Corrosion Inhibitors NACE Publication

CORROSION INHIBITORS Edited by

c. C. NATHAN Betz Laboratories, Inc. Philadelphia, Pa.

NATIONAL ASSOCIATION of CORROSION Houston, Texas

ENGINEERS

CONTENTS

{

I

I

(

Page

Scope and Importance of Inhibitor Technology Norman E. Hamner

.........

1

Theoretical Aspects of Corrosion Inhibitors and Inhibition Olen L. Riggs, Jr Methods of Evaluation and Testing of Corrosion Inhibitors E. Schaschl .

7

. . . . . 28

Corrosion Inhibitors in Refineries and Petrochemical Plants Part I . Part 2-Control of Fouling C. C. Nathan Corrosion Inhibitors in Petroleum Production Primary Recovery Al Nestle Corrosion Inhibition in Secondary Recovery A. K. Dunlop i

i

Control of Internal Corrosion of Pipelines Carrying Refined Petroleum Products

.42

.55

61

76

89

Control of Internal Corrosion of Pipelines Carrying Crude Oil

.95

Inhibition of Natural Gas Pipelines

.96

,

I

J

J

Inhibition of Tanks and Other Structures Handling Crude Petroleum Ivy M. Parker Inhibition of Tankships Transporting Refined Petroleum Products Controlling Corrosion in Petroleum Drilling and in Packer Fluids H. E. Bush

98

100

102

Page

Inhibitors for Potable Water George B. Hatch

114

Inhibition of Cooling Water George B. Hatch

126

Inhibitors in Desalination Systems Billy D. Oakes

148

Inhibitors in Acid Systems George Gardner

..

156

Application of Inhibitors in Automobiles and Their Environment Leonard C. Rowe

173

Inhibitors in Organic Coatings Norman E. Hamner

190

.....

Inhibition and Corrosion Control Practices for Boiler Waters J. H. Metcalf .

. . . . 196

Inhibitors for Temporary Protection Part I-Oil and Grease Coatings Part 2- Vapor Phase Corrosion Inhibitors . D. F. Knaack and D. Brooks

220 224

Microbiological Corrosion and Its Control J. M. Sharpley

228

Controlling Corrosion in Pulp and Paper Mills A. J. Piluso

236

Inhibition of A1uminum A. H. Roebuck

240

Inhibition of Corrosion From Caustic Attack A. H. Roebuck

245

Application of Inhibitors in Miscellaneous Environments Norman E. Hamner

251

Index

261

Scope and Importance of Inhibitor Technology

NORMAN E. HAMNER*

Introduction

Contents of Predecessor Book By agreement with J. 1. Bregman, the National Associa-

Information about inhibitors is scattered throughout the corrosion literature and frequently is concealed under a poultice of semantics so thick that only the most vigorous digging brings it to light. Also, like many other technical words, "inhibitor" labors under the difficulty that not everyone agrees on exactly what an inhibitor is and few agree on all aspects of the manner in which inhibitors function. The definition of inhibitor favored by the National Association of Corrosion Engineers is:

tion of Corrosion Engineers has prepared a successor to his book for publication. The association's aims, set forth in greater detail later in this chapter, were to bring his book up to date with technology developed since its preparation and to increase the scope of this work to cover many areas of inhibitor importance that he did not cover. Dr. Bregman's book was limited intentionally to "problems caused by water in certain aqueous and petroleum systems." As a result, many of the industrial areas in which inhibitors are commonly used either are not mentioned or are discussed only superficially by him. Because the scope of the present work is broader, it is obvious that a number of persons must contribute to this volume because no one person could expect to have sufficient competence in the diverse areas in which inhibitors are used to do

A substance which retards corrosion when added to an environment in small concentrations.l While this is not a perfect definition, it will be one of the bases on which this book on inhibitors is oriented. There are temporary excursions around the limits of this description, but most discussions will center on this defmition. The subject of mechanisms by which inhibitors work will be discussed elsewhere in this work, but it is useful to paraphase a statement about the fundamentals of inhibitor mechanisms found in a recent publication.2 The statement is that inhibitors function:

justice to all of them. Active work on this book began late in 1969. Its comprehensiveness is a tribute to the editor and a credit to numerous collaborators, not all of whom are listed in the author index.

Objectives of This Edition The main objectives of this edition are, in approximately the order of their importance: 1. To produce a book essentially comprehensive of the whole field of inhibition.

I. By adsorption as a thin film onto the surface of a corroding material. 2. By inducing formation of a thick corrosion product. 3. By changing characteristics of the environment either by producing protective precipitates or removing or inactivating an aggressive constituent so that it does not corrode the material.

2. To bring up to date the excellent work of Dr. Bregman. 3. To provide a base on which improved editions of this book may be issued in the future. If these aims are met to a significant degree, it should be possible for both newcomers and experienced practitioners alike to use this edition to advantage. The opportunity has been taken to set down in one place a large volume of information which, although available elsewhere, is scattered among a large number of sources. Some of these sources are not readily available and others are available only at great expenditure of time, expense and effort. Not the least of the aims of NACE is the provide a good summary of the subject matter and a large number of references to other works for those who wish to go into a subject in greater depth. Even in this aim it will be necessary to limit the information given, because in NACE magazines alone, there are hundreds of references to inhibitors and inhibitor technology.

Sometimes more than one of these effects takes place. These mechanisms cover most of the observed effects and form the bases for experimental work leading to the development of inhibitors as well as schemes for their use. It also is the main premise of the book "Corrosion Inhibitors," by J. I. Bregman, which this volume attempts to succeed. It will be useful also to consider the contents of Dr. Bregman's book and to understand the philosophy of the present work. Because Dr. Bregman's book has been out of print for some time, there has been some urgency to get a successor volume into circulation for those involved in inhibitor technology. *Staff, National Association of Corrosion Engineers, Houston, Tx.

1

The numerous developments since 1963 in the technology of inhibitor related to the petroleum field will be considered under several headings. In some cases, such as in connection with oilwell sucker rods, existing information on inhibitor protection has been collected into a repore published by NACE. Other similar data will be included among the several chapters relating to petroleum. Among the references in this and other chapters and in the bibliography following this chapter, a considerable volume of additional information on many inhibitor applications will be found.

products used as inhibitors are not necessarily so classed, but also because financial information is not readily obtained from either producers or users. In some cases the dollar value of the material used as an inhibitor is unimportant, if not trivial, as is the case of 0.5 percent water that passivates titanium exposed to cWorine.7 Dr. Bregman estimated some large installations may spend as much as $100,000 annually for inhibitors. There is no reliable way to determine how accurate this is nor any way to extrapolate it to an overall figure for all industry today. It is sufficient and probably accurate to say that many millions of dollars are spent annually not only for the inhibitor materials themselves, but also for the equipment used to apply them and for the labor and supervision required for their successful use.

History of Inhibition As is the case with other technology, there is no certain way to determine exactly when inhibition began to be considered as a separate technology. It has been observed for many years that the calcareous coating formed inside pipes carrying certain natural waters is protective of the pipes. It is common practice for water supply operators to so adjust the mineral content of their water that this beneficial coating is deposited to protect them. This coating is so common in potable water piping that it and its benefits often are overlooked. This leads to such consequences as the multiple leaks that occurred in the water system of a city into whose mains the low solids water derived from a desalination plant was introduced. The high purity water dissolved the calcareous lining from the inside of the pipes, thus exposing numerous holes which previously had been blocked by the lining. It was necessary to treat the desalination plant water with calcium to protect the piping.4 Lime treatment was a well known practice over 65 years ago. Current practice is described in a book.s

To the extent that the statistics are significant, an examination of the abstract literatureS shows that there has been a gradual increase in the number of abstracts of articles and books on inhibition during the past eight years. In 1962 there were 38 abstracts and in 1969, 91. Total abstracts in the eight years was 647. By contrast, there were 29 abstracts in the 1945 Bibliographic Survey of Corrosion. If the NACE definition is accepted, the main types of inhibition may be, from one point of view, substantially as follows: 1. Adsorptive. 2. Bulk film formers. From another point of view, they can be classified as 1. Anodic. 2. Cathodic. 3. Mixed. In the latter schedule they are classed as to whether they interfere with the corrosion reaction by preferentially attaching themselves to anodic or cathodic areas or whether they attach to both.

H. E. Waldrip in an article in 1948 Corrosion6 referred to a 1943 report in his discussion of the inhibition of oilwells. Treatments using hexametaphosphates in water, inhibitors in coatings, in product pipelines, in acid systems and elsewhere were well established practices before NACE was founded in 1945.

There is no completely satisfactory way to categorize inhibitors. This is readily understood when one of the mechanisms for protection of steel is considered: Changing pH of the environment into the alkaline range in which steel does not corrode. The effect of alkaline media probably is to stifle the corrosion reaction because iron's lower oxides are sparingly soluble in alkaline solutions.9 Conversely, tungsten and molybdenum, whose oxides tend to be stable in acid, are active in alkaline solutions.9 Oxides of some metals such as zinc and aluminum are active over a wide range of pH. There is no unimpeachable classification for water as in the case of titanium cited except to say that oxygen in water apparently forms a stable layer on titanium which is protective against chlorine. Similarly, halides of fluorine, bromine, cWorine and iodine (usually corrosive1elsewhere, help to inhibit the corrosion of steel in sulfuric acid. 2 0

The lQ-Year Index to Corrosion covering 1945-54, contains references to inhibition in aircraft, aluminum process equipment, boilers, diesel engines, cooling water, street deicing salt, petroleum refineries, tankships and numerous others. The articles published during these years indica te a highly developed technology.

Extent to Which Inhibitors

Are Used

There is little question that inhibitors are widely used. There is some evidence that their use is growing and there is ample reason to believe that sophisticated methods are available for the evaluation, application and assessment of the merits of inhibitors in a wide range of environments. While the nature of inhibitors is such that they are far more common in aqeuous environments, extensive use in hydrocarbon, high temperature, gaseous, liquid metal and other environments is evident.

How Inhibitors

are Used

In liquid environments, inhibitors may be introduced: 1. In slugs (that is, large quantities at once). 2. Continuously (that is, in metered amounts). The choice of an application method usually is a function of one of the main parameters of inhibitor

As pointed out by Or. Bregman, it is difficult, if not impossible, to determine the dollar value of inhibitors used in the United States. This is so not only because many 2

performance, persistence. An inhibitor is said to be persistent when it tends to resist detachment from the surface it

Stainless Steel in Nuclear Ship Several analyses of stainless steel were used in the Nuclear Ship Savannah's main propulsion plant so that the volume of corrosion and other foreign matter circulating would be kept to a minimum. 11 Selection of these materials did not entirely eliminate the necessity for chemical treatment of the circulating water, however. Timer-actuated feeder pumps metered injections of morpholine, di and tri-sodium phosphate and sodium sulfite into the secondary water system to control corrosion there. The system was also charged with hydrazine to keep the pH at 8 to 9.5.

protects or to remain in the environment in sufficient concentration to be protective. Examples of slug treatment in oil wells, for example, include those in which a measured amount of inhibitor is forced by pressure (squeezed into an underground producing formation from which it gradually is released to maintain an effective film on surfaces subject to corrosion. Technique is important in the successful application of inhibitors. In many oilwells, the surfaces to be protected must be coated with an effective film of inhibitor before the "squeeze" into the formation. The squeezed inhibitor reemerges to replenish this film as it is gradually worn off by produced fluids. Continuous application is used frequently in such environments as those requiring large volumes of cooling water. The complex environment of cooling water systems, especially when open to the atmosphere, involves the use of biological agents (which may be corrosive); pH adjusting chemicals (sulfuric acid, for example) and other chemicals, such as flocculants. In such systems, not only is there a continuous application of the various chemicals, but often also a continuous monitoring system permitting operators to check on the water condition. Among books in the bibliographic references at the end of this chapter are several that discuss water inhibition skillfully and in. great depth.

Cupronickel (consisting essentially of copper and nickel) alloys selected for tubing in heat exchangers used to cool exhaust steam from power plant turbines using salt water contain a small percentage of iron (usually 0.40 to 1.75) because the iron significantly improves their corrosion resistance to salt water and boiler feedwater. 12

Chemical Treatment of Environment As is apparent from the preceding discussions, inhibition usually involves addition of chemicals to the environment. It is useful, however, to avoid the misconception that aqueous environments are the only ones in which inhibitors (or inhibiting practices) are employed. So, the following examples are in order. Hot Salt Corrosion of Titanium Various hot salts (sodium chlorides, sodium bromide, sodium iodide, among others at 650 to 750 F (343 to 399 C) cause stress corrosion c~acking of titanium alloys. 1 3 It was discovered that water is a prime factor in making these hot salts aggressive. Environments in which hot salt environments are found include gas turbines, especially those operating in aircraft over oceans where sodium chloride and bromine can be concentrated from the atmosphere. In this case, where it is feasible to do so, excluding water will prevent or reduce corrosion damage from these hot salts.

Materials Problems Associated With Inhibition Because there are three principal avenues to solution of a corrosion problem, or similarly three avenues to prevention of or control of corrosion before it occurs, it is desirable to consider them separately. Although these approaches will be detailed in succeeding chapters, a few observations about them are appropriate. The approaches are 1. Change the materials in the system. 2. Change the environment. 3. Put a barrier between the materials and the environ-

Vanadium Pentoxide as Corrodent Vanadium pentoxide, which by itself and in combination with other byproducts of the combustion of certain fuels, is aggressive at high temperatures, is amenable to treatment with certain chemicals (inhibition is one sense of the word) which limit its corrosivity. One method involves absorbing the pentoxide in a copper-magnesium oxide when the conditions are oxidizing and another involves using reducing agents, such as ammonium ions when the conditions are reducing (Le., non-oxidizing.)14

ment (a coating, for instance). One or more of the above can be combined.

Select Corrosion Resistant Materials Materials in a system are obviously of primary importance. Because of economics, however, freedom to select noncorrosive materials, or those which are sparingly corrosive, is limited. More often than not as a consequence, prevention of corrosion or solution of a corrosion problem involves alterations in the environment, or more specifically alteration of conditions at the interface between environment and material. It is at the interface-a zone of the infmitely small-that many studies of inhibitor reactions are made. These reactions are taken into account when selecting an inhibitor for a specific function. Nevertheless, in some circumstances, such as fO{ atomic reactors and as in heat exchangers in electric power'plants, selection of the proper materials is the best way to prevent corrosion. A few examples will illustrate why this is so.

Chemical Treatment in Aqueous Environments The subject of chemical treatment in aqueous environments will be covered in detail under numerous headings in other chapters. The environments considered range from the very simple (Le., very pure water such as that used in nuclear reactors) to heavily contaminated liquids, such as those found in solutions of hydrocWoric acid used to clean chemical equipment. Inhibitors markedly reduced the corrosion rate of steels cleaned by hydrochloric acid

3

solutions, but the inhibition rate is strongly influenced by corrosion products, such as hydrogen sulfide. 15 Because oxygen is the most common corrosive in aqueous environments, many inhibitors are designed to counteract its attack. In a similar manner, such elements as sulfur, because they combine readily with oxygen, are soluble in water and are aggressive also, frequently are targets for inhibitors. The Battersea and Bankside electric generating stations in England remove sulfur dioxide from stack gases in a water scrubber then neutralize (inhibit) the resulting sulfurous acid with chalk. 1 6 Succeeding chapters will discuss inhibition by chemicals in detail, so no further treatment is needed here.

While many effects at the metal-environment interface are comparatively stable, many others are not. Performance of inhibitors usually is affected adversely by high velocity. On the other hand, performance of certain inhibitors in some environments is adversely affected by low velocity. An example of adverse influence by increased velocity is seen in tests with hot carbonate systems used to remove carbon dioxide from natural gas. Tests showed that the metavanadate ion improved the passivation of mild steel in hot carbonates at 100 C, but that this ion was ineffective when the carbonate impinged on material at high velocity, as it did at an elbow.17 The reverse of this effect is reported in tests of a water system in which it was found that corrosion of copper tubing at 6 ft/sec was superficial, but that pitting and surface attack occurred when the same solutions moved at

Bamers to Separate Materials From Environments Although it is outside the scope of this book, barriers between the environment and the material are the third

only 2 ft/sec. This effect may be attributed to well known effect of the presence or absence of oxygen in the environmen t.

control method. An example is the use of coatings inside piping used to transport salt water, especially when the volume of water is great and when it contains large quantities of dissolved oxygen. In this case, when a non-corroding material (such as a fiber reinforced plastic) cannot be substituted for steel and when the volume of

Techniques for Inhibitor Testing Testing, to be considered in detail in a later chapter is important in inhibitor technology. Various means have been developed by NACE and other organizations to test the inhibitor efficiency before a selection is made. These are two main types of tests: Laboratory and on-site (or service). Laboratory tests usually involve screening inhibitors to weed out those obviously unsuited. Laboratory tests also permit a measure of judgment of relative merit when inhibitors are compared to others of known efficiency and performance. NACE has published reports concerning static testing of inhibitors for oilfield service.1S ,19 Other organizations, notably the American Society for Testing and Materials, have published others. A large volume of information about inhibitor testing will be found in the NACE magazine Materials Protection. An example of this is an article concerning inhibition of alkanolamine-carbon dioxide systems in which an effective inhibitor was reported to make substantial reduction in corrosion rates.2 0 Other reports concern special problems and merit study by those who have similar problems. The data are located readily thorugh the subject indexes in December issues in NACE journals.

inhibitor that would be required to effectively control corrosion is prohibitively expensive, then a coating on the pipe surface may be a remedy.

Other Influences on Performance In common

with

other

reactions

in the corrosion

process, the usefulness and efficiency of inhibitors is affected by numerous other conditions of the environment and of the materials. This discussion of these influences is introductory only. Each of them is treated fully in other chapters. The most common conditions are temperature and velocity. Conditions of pressure or vacuum are known to have some influence on inhibitor performance in some cases. Instances when this is true apparently are infrequent, l}owever, because they are rarely mentioned in the literature. Consequently, neither of these latter effects is mentioned to any significant extent in this book. Effect of Temperature It is generally conceded that the effectiveness of inhibitors usually is adversely influenced by increases in temperature. This is true in inhibited cleaning acids15 and is usually true in other environments. The extent to which temperature affects inhibitor efficiency often can be determined only after tests in the actual corrosive medium being studied. In some cases, the properties of organic inhibitors have been so fully explored that maximum operating temperature limits for their use are well known. The temperature factor is always important and always is a design consideration.

Scienfitic and Practical Inhibitor Development The development of scientific methods of inhibitor development have accelerated in recent years. These developments have been both by associations and scientific groups such as the American Chemical Society, NACE, ASTM and by individuals and companies. The scientific approach is exemplified by the work of electrochemists who pursue reactions at the materialenvironment interface with a number of sophisticated instruments, deriving data useful in the technology both directly and indirectly. An example of the scientific approach is found in an article recently published describing the concept of developing an inhibitor by designing the molecules of which it is composed.2 1 In these studies the

Effect of Velocity Because of the inherent properties of chemical compounds, velocity effects are important in inhibition, especially when they are considered in relation to performance. 4

of the total available. Because of membership is diverse industries, there is a useful interchange of information across traditional lines. This is beneficial not only to NACE members, but to industry as a whole, which has free access to N ACE technology.

kinetics of the reaction and electric double layer are evaluated. They also permit considering the principal types of inhibitor adsorption and the role of molecular architecture, nature of metal to be protected, corrosion solution compositon, mechanism of inhibitor action, molecular designing of corrosion inhibitors and other factors. Indicative of another type of approach is the recent NACE report surveying quality control practices of major oil field inhibitor manufacturers.2 2 This report is assumed to cover about 90 percent by volume of the inhibitors manufactured in the United States. The survey showed a high level of control over quality. Individual 'companies also issue reports on tests of inhibitors such as one recently published on the performance of 48 organic inhibitors designed for oilfield use.23 In this report the inhibitors are rated by one of three classifications: Superior, intermediate or dubious. Other similar developments are occurring continuously throughout industry. The fmdings in these studies permit a more precise choice of materials for specific conditions and selection of the best among several inhibitors recommended for a given use. The economics of inhibitor application are continuously improving as more is learned about initial choice, application techniques and testing for results.

References 1. NACE Glossary of Corrosion Terms. Mat. Pro., 4, No. 1, 79-80 (1965) Jan. 2. N. Hadarman. Chapter 9-Fundamentals of Inhibitors, NACE Basic Corrosion Course, NACE, Houston, Texas. 3. Recommendations for Corrosion Control of Sucker Rods by Chemical Treatments a Report of NACE T-ID, Mat. Pro., 6, No. 5, 85-88 (1967) May. 4. U. R. Evans. Metallic Corrosion, PaS'livity and Protection, Longmans, Green & Co. New York, N. Y. p323. 5. W. A. Parsons. Chemical Treatment of Sewage and Industrial Wastes, National Lime Assoc., Wash., D. C. 6. H. E. Waldrip. Present Day Aspects of Condensate Well Corrosion, Co"osion, 4,611-618 (1948) Dec. 7. E. E. Millaway. Titanium: Its Corrosion Behavior and PaS'livation, Mat. Pro., 4, No. 1, 16-21 (1965) Jan. 8. Corrosion Abstracts Yearbook, 1963-69 incL NACE, 2400 W. Loop S., Houston, Tx, 77027. 9. U. R. Evans. op. cit. p.30. 10. R. M. Hudson and C. J. Warning. Pickling Inhibitors in H2 S04 - Tests With Inorganic Halides and Their Mixtures, Mat. Pro., 6, No. 2,52-54 (1967) Feb. 11. F. J. Pocock, C. P. Patter son and R. A. Benedict. N. S. Savannah Water Chemistry, Proc. NACE 24th Conference, NACE, p474 (1969). 12. F. L. LaQue. Corrosion Resistance of Cupronickel Alloys Containing 10 to 30 Percent Nickel. Co"osion, 10, No. 11, 391-399 (1954) Nov. 13. S. P. Rideout, R. S. Ondrejcin, M. R. Louthan, Jr., and D. E. Rawl. Role of Moisture and Hydrogen in Hot Salt Cracking of Titanium Alloys, Proc. Fund. Aspects, Stress Corrosion Cracking, NACE, Houston, Tex, p650 (1969). 14. G. J. Kalkabadse, B. Manohin and E. Vassiliou. High Temperature Reactions Involving Vanadium Oxides and Certain Salts, The Mechanism of Corrosion by Fuel Impurities, Johnson and Littler, Butterworths, London, p254-260 (1963). 15. K. R. Walston and A. Dravnieks. Corrosion of .Refming Equipment During Acid Cleaning, Co"osion, 14, No. 12, 57 It-577t (1958) Dec. 16. A. C. Stern. Air Pollution Il, Academic Press, New York p395 (1962). 17. W. P. Banks. Corrosion in Hot Carbonate Systems, Mat. Pro., 6, No. 11,37-41 (1967) Nov. 18. Proposed Standarized Laboratory Procedure for Screening Corrosive Inhibitors for Oil and Gas Wells. NACE TlK 155. 19. Proposed Standarized Static Laboratory Screening Test for Materials Used as Inhibitors in Sour Oil and Gas Wells. NACE TlK 160. 20. B. D. Oakes and M. C. Hager. Corrosion Studies in Alkanolamine -C02 Systems, Mat. Pro., 5, No. 8, 25-27 (1966) Aug. 21. Z. A. Foroulis. Molecular Designing of Organic Corrosion Inhibitors, Symposium on Coupling of Basic and Applied Corrosion Research, NACE, Houston, p24-39 (1969). 22. Survey of Quality Control Procedures Used in the Manufacture of Oil Field Inhibitors, Mat. Pro., 6, No. 6, 82-84 (1967) June. 23. A. C. Nestle. Simulated Field Usage Testing-Organic Inhibitors for Oil and Gas Wells, Mat. Pro., 7, No. 1, 31-33 (1968) Jan. 24. Some Corrosion Inhibitors-A Reference List, NACE T3A-155.

Scope of This Book As has been indicated, the scope of this book has been expanded to cover essentially the whole field of inhibition. For the most part, the presentations will be industry oriented. In spite of the inevitable overlaps in such a scheme, it is believed that the method is useful and practical. Cross indexing permits locating information on subjects dispersed in a number of the chapters. Authors chosen for the chapters are among those known to be active in the specific fields on which they are writing. The editor of this book and the National Association of Corrosion Engineers believe that this method produces the greatest volume of useful information on the subject. Authors used their own sources of information both specified and otherwise. In addition, numerous references are listed for those who wish to pursue in greater depth some topic that is not fully treated in the text.

NACE Activities in Inhibition From its beginning NACE has had a deep and continuing interest in inhibition and inhibitors. Among the early technical committee reports published by NACE was a reference list of corrosion inhibitors.2 4 Technical committee activity has continued to be comprehensive, with attention given to acid cleaning solutions, cooling waters, hydrocarbon streams, high temperature, high purity water and numerous other environments. NACE members will be found working on inhibitor problems in many major industries, so their contributions make up the bulk of the literature published by NACE and a significant part of that published elsewhere. Inhibitor topics are a continuing feature of NACE meetings at every level and the data generated constitute a significant segment

Bibliography of Books on Inhibition P. Hamer, J. Jackson and E. F. Thruston. Industrial Treatment Practice, Butterworths, London (1961).

5

Water

L. I. Pincus. Practical Boiler Water Treatment-Including Air Conditioning Systems, Mc Graw-Hill Book, Co., Inc., New York (1962). G. V. lames. Water Treatment, Third Edition, Technical Press, Ltd., London (1965). 2nd European Symposium on Corrosion Inhibitors. Comptes Rendus, Ferrara, 1965, University Degli Studi di Ferrara, Ferrara, Italy.

M. L. RiehL Water Supply and Treatment, National Lime Assoc., Wash. D. C. (1962). Betz Handbook of Industrial Water Conditioning, Sixth Edition, Betz Laboratories, Inc., Philadelphia, Pa. (1962). I. N. Putilova, S. A. Balezin and V. P. Barannik. Metallic Corrosion Inhibitors, Pergamon Press, New York (1960).

6

l I

Theoretical Aspects .of Corrosion Inhibitors and Inhibition t OLEN L. RIGGS, JR.*

Introduction

f

r

.

or

external electrical currents, a change in free energy satisfies the requirements of Condition 1. Whether the metal's corrosion is controlled by the cathodic or anodic reaction, the rate, in most cases, is limited by the first transfer step. The discrete oxidation and reduction reactions, typified by Equations 1 and 2, are the charge transfer mechanisms. While other reactions can occur, they usually will satisfy Condition 2 also.

When metals are reduced from their ores, one of nature's fundamental reactions is reversed. In most environments, metals are not inherently stable, but tend to revert to compounds which are more stable; a process which is called corrosion. Corrosion is derived from the Latin "corrosus," meaning gnawed away. Corrosion may be further defined as a gradual destruction of a material, a substance, or an entity, usually by solution or other means attributed to a chemical process.! Metallic corrosion reactions are so extensive it is

Condition 3 is satisfied when metal ions discharged into an electrolyte provide a conductive path through it to complete the electrical circuit. Anodic and cathodic reactions occur as the result of

unlikely that a single set of mechanisms can explain all cases. Generally, the corrosion of metals in aqueous environments is caused by electrochemical processes. These processes occur on the metal surface and/or at the metal/solution interface. Organic corrosion inhibitors also may function by: 1. Chemisorption of the molecule on a metallic substrate; 2. Complexing of the molecule with the metal ion which remains in a solid lattice; 3. Neutralizing the corrodent; and 4. Absorbing the corrodent. Corrosion is a heterogeneous reaction which is often diffusion controlled. In order for the reaction to proceed electrochemically, there are three necessary conditions which must be met simultaneously: 1. There must be a potential difference; 2. Mechanisms for charge transfer between electronic and electrolytic conductors must exist; and 3. A continuous conduction path must be available. The corrosion reaction can be expressed as simply: (Reduction Processes) M + 2H +~ M ++ + H2

differences in free energy states between reacting sites when all other conditions essential for a corrosion reaction are met. This is typified by the situation created when a piece of iron is partially immersed in brine, for example, when differences in the surface states of zones at the gas-liquid interface and those deeper in the brine cause reactions between these zones. Corrosion usually is accelerated at the interface zone. Differences in the oxygen content of liquid in a crevice between two metals and the bulk electrolyte outside the crevice also can result in accelerated corrosion. An electrochemically identical reaction occurs when scale produced by reactions on a metal surface is broken or removed, thus exposing zones differing in free energy states from the remainder of the undisturbed surface.

The Electrical Double Layer Exhaustive electrochemists

the metal-electrolyte interface. While the complexities of these studies are such that a full exposition is outside the main objectives of this chapter, nevertheless, a general description of what is presumed to take place at the corroding interface is useful. Those who wish to investigate these phenomena in detail are referred to the several discussions about them, including the exhaustive treatment by Delahay.2 For the purposes of this discussion, it is sufficient to say that the reactions take place at what has been termed by Delahay and others as the "compact" double layer "comprised between the electrode and the plane of closest approach," and the "diffuse" double layer extending "from the plane of closest approach to the bulk of the solution." The double, or Helmholtz layer, and some of the other

(1)

and/or (Oxidation Processes) M+02 Because corrosion

+2H+~MO+H20 reactions

theoretical treatment has been given by and others to the reactions that occur at

(2)

result from the inherent

thermodynamic instability of most metals (gold, platinum, iridium and palladium excepted) or as the result of stray *Kerr-McGee Corp., Oklahoma City, Okla.

7

SOLUTION

SOLUTION

II , .•..,

~'-b \"-'\:!::I

(~ ....

11

~ 11'-'\

Q

~

11 \ •••• '

I' ...J

1I 11 11

f:i:\ \::..J

~

•.....

'

OUTER HELM HOLTZ PLANE PLANE INNER HELMHOLTZ

x-x-

L1JJI'

t0Cl.

FIGURE 1 - Schematic representation of the electrical double layer at the potential of the electro-capillary maximum. Small circles represent adsorbed ions. Dotted circles represent "ghosts", ions which would be present if the double layer were not there. (D. Grahame)

characteristics of this hypothesis in Figures 1,2 and 3.

...J et Z ,It-

FIGURE 2 - SchematiC representation of the electrical double layer with negative polarization. Note absence of adsorbed ions and increased concentration of positive ions as compared with Figure 1. The concentration of "ghosts" is also increased. (D. Grahame)

are graphically displayed

Fouroulis4 discussing surface phenomena related to inhibitor action.

A simplified explanation of what happens is that ions approaching or entering the Helmholtz layer participate in reactions with the electrons of metal exposed to the electrolyte. These concepts will be broadened by discussions of corrosion processes, inhibitors and inhibition in terms of the metal-solution interface, the inhibitor molecule, corrosion inhibition and measurement techniques. In Figures I through 3,3 the large circles represent an excess of solvated ions. The dotted circles represent deficiencies of an ion type. The small circles (Inner Helrnholtz Plane) represent the nonsolvated excess ions. The positive or negative signs on the metal represent either electron deficiencies or electrons. The change in potential as a function of distance is shown schematic ally in the boxes below each figure. Figure I diagrams the electrical double layer at zero charge potential of the metal surface. Figures 2 and 3 show schematic ally the double layer, with negative and positive polarization, respectively. This description of the composition of and states in or near the Helmholtz layer is more or less the same as that given by

These comparisons are schematically presented in Figure 4, illustrating the relationship of both potential position and structure for the negative and positive surfaces with respect to the zero charge potential surface. The processes (electron discharge and ionization) are related to the ion transition from a "hydrate" (aqua ion) to a surface adsorbed atom and the reverse. The electrical field within the double layer controls these directional processes. Levine5 gave a detailed review of the electrical double layer, with attention focused on the discreteness of charge, or discrete ion effect.

Free Energy All changes in the nature of materials are caused by their tendency to reach a state of maximum stability. Once this state of equilibrium has been reached, the tendency to change further is reduced and the system is said to be stable. The tendency towards change is greater, the greater the difference between the free energy state of the material and the equilibrium state.

8

SOLUTION

molecules, depending on the kind of solvent, i.e., hydroxyl, ammonia, sulfate hydrate, hypophosphite, cyano, and others. The compressed solvation sheath is rigidly oriented about the metal ion and in this manner tends to shield it from further complexing ions. This is the type of metal surface boundary that occurs during metallic corrosion and

e

a. I-

eII-z>.J.~JW 7 is a dangerous practice if copper alloys are present in the condensing system or downstream of it in the water drawoff. At pH values in excess of 7.0 to 8.5 (depending on the source quoted),

9.0

80

I

I

/

/

/ /'

I

/

/

I

I

I I

same and requires their adsorption onto the metal through their polar group or head. The nonpolar tail of the inhibitor molecule is oriented in a direction generally vertical to the metal surface. It is believed that the hydrocarbon tails mesh

/""/ //

5.0

4.0

/ /'

30

/

/

/

/

I

/

/

/

/

/

/

//

/

/

/

/ /

Intermediate Molecular Oil-Soluble Amine

Weight Neutralizing

with each other in a sort of "zipper" effect to form a tight film which repels aqueous fluids, establishing a barrier to the chemical and electrochemical attack of the fluids on the base metal. A secondary effect is the physical sorption of hydrocarbon molecules froin·· the process fluids by the hydrocarbon tails of the adsorbed inhibitor molecules. This increases both the thickness and effectiveness of the hydrophobic barrier to corrosion.

/,,/'

Based on the above explanation, it may be understood why such inhibitors are generally more effective in the presence of an oil phase. In fact, it is often difficult to use filming inhibitors effectively and economically in the absence of an oil phase. Selection of the proper inhibitor for a specific application is generally a practical rather than a theoretical problem. Inhibitors are available with a wide range of solubilities and other physical properties. The concentrations at which they are used generally is about ten

2.0

400

800

ppm

1200 Hel

1600

2000

Titrated

FIGURE 1 - Crude unit-atmosphere (Betz Laboratories)

sion can take place in the absence of an aqueous liquid phase, an unusual occurrence under refinery conditions. A recent article by Nathan19 describes the development and use of higher molecular weight amines, which do not form chloride deposits from either the hydrocarbon or water phase and which also have good buffering capacity compared to ammonia and morpholine. Such material permits easier pH control and largely eliminates the danger of copper corrosion at high pH (above 7.5 in presence of ammonia or amines). This is shown in Figure I.

Refineries and petrochemical processes employ a variety of film forming inhibitors under varying conditions. Bregman describes a number of inhibitors and others have been developed in the past ten years. The mechanism by which all materials function is the

I

60

Carlton's article, as does that of Backenstol8, points ou t an additional complication-corrosion of base metal under the deposits. Carlton also discusses how this corro-

Filming Inhibitors

/'

I

70

copper forms the soluble cuprammonium complex and deterioration of such materials as CDA 443-445 (Admiralty) can be expected. Similarly, some of the low molecular amines also can form soluble copper complexes. Control of pH is not an unusual industrial operation and can be effected with automated measuring, recording and feeding equipment now available. The expense of such equipment can often be justified to plant management by savings in chemicals injected and in increased efficiency of corrosion control. Alternative approaches to such close pH con trol are discussed in Reference 19. An additional drawback to the use of ammonia is the formation of ammonium chloride deposits, which cause fouling problems, resulting in reduced flow-rates and heat transfer. Intermittent or preferably continuous water washing can remove the deposits. The problem is described in a number of industrial case histories including that by Carlton.17

tower overhead water.

45

Obtaining a representative and reliable sample of the stream is difficult under such conditions. In addition, because of their detergent action, many inhibitors often cause an initial increase in the amount of sludges and scale going into the process stream as old deposits are loosened by the detergent-inhibitor and slough off equipment. This increase must be recognized for what it is and not be assumed to signify an increased corrosion rate.

parts per million (ppm) based on the hydrocarbon phase, so the economics is generally quite favorable. Although many polar types of inhibitors are described in the literature, those most widely used in petroleum refining contain nitrogen bases such as amines, diamines, imadazolines, pyrimidines and their salts or complexes with fatty acids, naphthenic acids and sulfonates. Inhibitors vary in solubility, etc., as mentioned above and also must be chosen in consonance with pH range and other fluid properties. In general, it is more economical to reduce all or a portion of the acid content of treated stream with ammonia or other neu tralizer and augment this by use of a film-forming inhibitor. As an example, five ppm of a filming inhibitor applied at pH of 5.5 is often an effective and economical treatment. At lower pH, several times as much inhibitor would be required, while at higher pH, the problems of ammonium chloride deposits would have to be considered. Specific applications are given in the case histories of various units.2 0 Film-forming inhibitors, as distinguished from ammonia and other volatile amines, are considered to be nonvolatile; accordingly, in any gas-liquid separation process, they remain with the liquid and so may be concentrated in the heavy fractions of a refinery process. This means that the inhibitors must be injected by suitable equipment at the point of use. If another corrosion problem occurs at a down-stream unit, it may be necessary to inject additional inhibitor to protect the second unit. The efficacy of an inhibitor treatment or other process changes in controlling corrosion is easily followed in refinery work by use of corrosion test coupons or spools, corrosion rate meters, corrosion resistance probes and by analysis of process streams for dissolved metal. While these methods are explained in more detail in this book in the chapter on Corrosion Measurements, a few general concepts applied to refineries will be given here.

Test Coupons Test coupons are the most widely used tool in monitoring refinery corrosion and its treatment because they may be easily prepared, inserted, removed and evaluated. Coupons are composed of metals similar to those of interest and exposed to conditions similar to those of interest. An exception is that "clean" coupons with reproducible surface characteristics are always used, while the surfaces being corroded are frequently dirty, scaled, or roughened in a manner difficult to categorize or reproduce. For this reason, corrosion rates on coupons often are high initially but drop off with time to a steady-state value as the coupon surface approaches the condition of the actual plant equipment surface. A fresh coupon placed in an inhibited system also will show a high corrosion rate initially until the inhibitor film has had time to build up on the coupon surface. Accordingly, coupon exposure times are generally 2 to 4 weeks for determination of "before" and "after" conditions. Exposure time will be limited and data questionable if process changes are made during the exposure period. Such variations as changes in feed stocks, processing charge rates, temperatures and the like may affect corrosion rates sufficiently to negate the effects caused by changes in the inhibitor program under investigation. Application Equipment The practical aspects of equipment used in inhibitor injection cannot be neglected. As previously emphasized, the inhibitor cannot be effective unless it is in intimate contact with the metal surface being attacked at the desired concentration and at the point(s) of attack. Because of the very small concentrations of inhibitor required, even streams of thousands of barrels per day require but a few gallons of inhibitor. The material, diluted with a suitable solvent, is injected into the stream at desired locations by a small chemical injector pump which can overcome the pressure of the operating unit. However, usually it is convenient to dilute the inhibitor with the product stream into which it is being injected. An adequate pump can be used, or a side stream from the operating unit is employed. Also, the larger the volume of inhibitor solution injected, the better its mixing efficiency in the process stream and the more uniform the treatment is. Special equipment such as "quills" also are obtainable for injection of the inhibitor as fine droplets or mist into a gas stream and for effecting more uniform distribution. This is necessary when it is desired to treat a gas rather than a liquid. In recent years the trend has been to purchase inhibitors in tank truck quantities. The inhibitors are put

Methods of Measurement Irrespective of the method, it should be remembered that the relative corrosion rate before and after treatment is used as a basis of comparison. This is generally easier to determine and of more use than the absolute rate. It is also important to consider that the build-up, breakdown and repair of films formed by adsorption-type inhibitors are not instantaneous processes but may require times of the order of several days. Accordingly, the limitations of spot readings as determined by electrical corrosion rate meters and "grab" samples of fluids for metal ion analysis must be considered. In addition, because a corrosion rate meter gives readings only in electrically conducting media, readings are dependent on the conductivity of the medium and suitable corrections must be made for stream composition and/ or conductivity. Process stream analyses for dissolved metals such as Fe2+, Cu2+ among others, can be carried out quickly and cheaply, but are of questionable value in streams containing hydrogen sulfide, because its corrosion products usually will be insoluble sulfide~.

46

effective levels. Nathan21 discusses the problem in some detail If iron content is used to measure results of inhibitor

into bulk storage tanks before use. This practice offers the advantages of savings from quantity buying and reduces labor costs for inhibitor storage, dilution and handling. Other recent innovations include formulation of neu-

treatment, the initial rise when treatment is begun, usually attributable to cleaning of scaled surfaces, will soon fall to a rate less than that before treatment. If it does not, then either too little inhibitor is being used, or the inhibitor is not being added in such a way that it reaches the corroding equipment. In actual plant practice, the inhibitor is normally added at concentrations of 5 to 10 times the final desired recommended value.(2) The high concentration reduces the time needed for sloughing of old deposits and also accelerates the attainment of a good film on the cleaned metal. The concentration is gradually reduced after this, until the desired inhibition level (as shown by coupons, resistance probes, water analyses) is attained at an economical cost.

tralizing and film-forming inhibitors in a single drum or tank and the combination of inhibitors and antifoulants. Antifoulants are discussed in a later section. Again, the purpose is to simplify treating programs by reducing costs of lab or, storage facilities and handling.

Special Concepts in Use of Corrosion Inhibitors to Refineries Film-forming and/or neutralizing inhibitors in refineries offer no panaceas. Chemical treatment for prevention of corrosion is one of several tools used by competent engineering and management personnel as approaches to corrosion control alternative to other measures such as special resistant materials, protective coatings, design changes and the like. Before discussing the relative advantages and disadvantages of the various protective and corrective measures, some limitations, as well as pitfalls to avoid in using inhibitors will be mentioned.

Surfactant Properties of Inhibitors The effectiveness of film-forming inhibitors, as already stated, depends upon strong adsorption of inhibitor molecules at the interface between the process liquid(s) and the metal surface to be protected. It is not at all unusual for materials active at a solid-liquid interface to be active also at a liquid-liquid and/or liquid/gas interface. The former may cause emulsification problems, the latter may result in foaming. (Foaming problems will be discussed in a later section on corrosion in gas processing units.) Emulsion problems are evidenced in water drawoffs in retlnery equipment and in petrochemical plants, e.g., separation of oils and tars from ethylene quench water systems. Of great importance when refining products such as jet fuels is emulsification of small quantities of water in to the product. The water may enter the system because of storage tanks which "breathe" humid atmospheres or carry water bottoms or by contamination or careless handling. Water that does get into the jet fuel storage system often is difficult to remove with settlers or coalescers when surfactants are present in the system. Because of the deleterious action of emulsified water in

Temperature Limitations Film-forming inhibitors contain organic molecules with carbon-carbon, carbon-hydrogen, carbon-nitrogen bonds and so on. In common with other organic molecules, they decompose at elevated temperatures. It was pointed out at the beginning of this chapter that inhibitors are recommended only for "low" temperatures, by which is meant corrosion in the presence of water. Furthermore, filmforming inhibitors act through an adsorption process, which generally becomes less effective at elevated temperatures, requiring larger treatment dosages to maintain effective fllms on metal surfaces. This increases expenditures for the treating chemicals. Above about 450 to 500 F (230 to 260 C) it may be said that film forming inhibitors have limited application, although they may be used at higher temperatures. Fouling reactions occurring in the range of about 300 to 700 F (ISO to 370 C) present problems, many of which art amenable to use of chemical antifoulants.( 1) Above about 700 to 800 F, there is little experience to draw on in use of either film-forming or neutralizing corrosion inhibitors or use of antifoulants, although some work along these lines is being pursued.

promoting bacterial growths in storage and in freezing and clogging of fuel injection nozzles during operation, jet fuel purchasers have strict requirements concerning such water as well as fuel response to it. This is usually determined by the ASTM Water Separometer Index, Modified or WSIM Test. 22 Essen tially the test correla tes the presence of emulsified and/or entrained water droplets injet fuels with turbidity of fuel measured under closely controlled and standardized conditions. The effect of various surfactants

Insufficient Concentration Many corrosion inhibitors of both the passivating and the film-forming types (as explained in the chapter on inhibitor types) are classified as "dangerous", because they actually may produce increased localized corrosion and pitting compared to untreated systems if they are used in quanti ties insufficient to form an effective corrosionresistant film. For this reason, it is not advisable to attempt reduction of inhibitor costs by reducing dosage below safe, (I )See

the

discussion

on antifouJants

in Part

such as corrosion inhibitors can be determined by this test. No generalizations can be given abou t the effect of a given (2)Start-up

Programs

dosage A - If dirty. B - If cleaned.

2 of this chapter.

47

le A

time

B

1\ time

Such failures can be very expensive and in many cases they are catastrophic, Le., give no warning of their imminence and result in heavy loss of products, equipment, production time and even of life.

material on a given fuel, because the fuels themselves often have traces of polar materials which may act as surfactants, such trace materials being present in the original crude feed stocks. Testing of emulsions and demulsifiers is a very empirical field and requires that the given emulsion be evaluated with specific materials of interest required to break and to make it. Because there are many commercial refinery inhibitors on the market, usually it is possible to find one which is effective as a corrosion inhibitor but produces minimal emulsification or which can be modified by a demulsifying agent without losing its corrosion inhibitive properties. The WSIM Test is involved and the equipment is fairly expensive. In addition, the procedure has poor (but predictable) reproducibility as pointed out by Nathan and Dulaney2 3,24 who discuss the test's limitations. Despite these limitations, the WSIM test is widely used and will probably be relied on for some time.

Co"osion Preventive Barriers Various protective coatings, linings, claddings and paints, all are examples of corrosion control by means of barriers separating the aggressive environment from the corrodible metal. While the cost of such systems is high (although rarely as high as resistant alloys) their life is limited. As with metals, coatings and linings are evaluated in the laboratory and~ field under conditions as close as possible to service conditions. A principal cause of barrier failures is not lack of innate resistance of the barrier itself, but defects in application, such as pinholes, holidays, or other discontinuities. These defects are caused by improper application or by unavoidable mechanical damage after application. They allow attack not only at the isolated spots on bare or unprotected metal, but also on the coating itself, by undercutting around the defects. Protective coatings are usually applied over external surfaces or to internal surfaces of vessels of such size that the condition of the coating can be observed visually at intervals and defects patched or replaced. Accordingly, coating failures rarely result in catastrophic failure in refmery applications. Furthermore, coatings, particularly organic-based, are not used under such extremes of temperature, pressure and chemical environment as are refmery alloys.

Economic Aspects of Chemical Inhibition And Other Measures for Corrosion Prevention In discussing various corrosion preventive measures, it is useful to consider that corrosion of the type described here, that is, attack by an aqueous liquid on a metal, has three prerequisites: 1. An aggressive or corrosive liquid, 2. An active or corrodible metal, and 3. Intimate contact between the metal and the liquid. Control measures available are altering the metal or the environment or placing a barrier between them to prevent their contact. Of course, combinations of two or more of these methods also may be applied for better results.

Alterations of Co"osive Environment The use of neutralizing amines for acid corrosion in refinery processing is an example of alteration of environment. The use of f1lming amines may be thought of as a combination of environmental alteration and protective barrier, for example, the adsorbed inhibitor film supplemented by the sorbed oil fIlm. Chemical treatments employing neutralizers and/or f1lming inhibitors are screened in the laboratory and tested in the plant to verify laboratory indications. Such tests are no more error-proof than are those on metals or coatings. In this respect, the advantage of chemical treatments is that efficacy of treatment may be followed easily and cheaply in the plant and modifications quickly made if the original treatment is inadequate. Because of the sensitivity, rapidity and ease of the methods used for monitoring inhibitor treatments in the field, there is a small likelihood of substantial loss of equipment, performance or of catastrophic failure. In general, all that is required is the use of a nominal volume of chemical, with appropriate feeding equipment and corrosion-measuring devices. Probably one of the greatest economic advantages of chemical treatment over other methods is that the costs of. chemicals which must be added continuously are treated for tax and accounting purposes as expensed items similar to maintenance and other operating coast. On the other hand, alloy and coatings systems usually call for capital outlays of considerable magnitude. These expenses are not

Altering the Metal The activity of a metal may be altered somewhat by variations in its heat treatment or slight changes in composition; however, for marked differences in corrosion resistance, a completely different metal generally will be required. Thus, carbon steel may be replaced by copper or one of its brass or bronze alloys or by one of several stainless steels or other alloys. Cost of such substitution is high. The least expensive stainless steel will be an order of magnitude more expensive than carbon steel. When the more "exotic" metals and alloys, such as titanium, tantalum and zirconium are considered, costs may be several orders of magnitude more than for carbon steel. Despite the higher costs of alloys and "exotic" metals, there are many conditions such as elevated or cryogenic temperatures, high pressure hydrogenation, high-temperature oxidation environments and others where the superiority of expensive materials is so great that the added costs are justifIed. Generally, expensive materials are not installed without thorough laboratory evaluation of chemical, physical and corrosion properties as well as field experience in pilot-plant units. Nevertheless, failures are known to occur usually because of inability to duplicate field exposure conditions in the laboratory and pilot-plant. 48

~ I' I:

failure, etc., due to the increased pressure resulting from its formation.

deducted directly from operating income and hence bear a less favorable tax position. Such generalizations, of course, may vary with individual companies and their accounting systems. Economic analyses such as discounted cash flow, present values, payout times and other ways to evaluate the economics of a system cannot be covered in this article; nevertheless, their importance should be emphasized, because the success or failure of a corrosion prevention program depends on economic feasibility as well as on technical performance. The plant engineer who recommends a preventive treatment to his management should be conversant with these methods of economic evaluation and

Under most conditions of acid corrosion, the equilibrium between atomic and molecular hydrogen is displaced essentially completely in the direction of molecular hydrogen .. However, in the presence of a number of catalytic agents, H atoms are kept from combining at the surface. Important catalysts are cyanides and sulfur compounds, including hydrogen sulfide. Experience in handling sour crudes and sour waters was described by Wachter and his colleagues28 and by Ehmke29 and others. An early paper by Effinger30 points out that high nitrogen content in the feedstock appears to increase the probability of hydrogen attack in gas plants following catalytic cracking because of CN increase brought about by hydrogenation of nitrogen compounds.

justification. (3) In modern refineries and chemical plants with highly complex and interrelated processes and equipment, downtime because of corrosion failure with concomitant loss in

In a recent paper describing corrosion in the hydrocracking of West Coast crudes, Piehl31 found that corrosion of aqueous effluents increased with the mathematical product of nitrogen and sulfur contents of the water, expressed as an equivalent content of ammonium sulfide. Total water volume as well as fluid velocity were also factors determining corrosion rates. Gutzeit32 has summarized the various parameters involved in corrosion in such systems and extended the earlier work of Wachter, et al. Gutzeit explains the effect of pH, sulfide content and cyanide content as competition between the formation of a protective iron sulfide film and its dissolution as soluble ferrocyanide. Figure 2 shows some of the results reported by Gutzeit.

production and product sales and profits, may be much more important than direct costs of equipment replacement or repair and labor to effect them. Such losses can easily exceed the cost of continuous treatment by corrosion inhibitors and antifoulants.

Special Refinery Processes Amenable to Corrosion Inhibitors The foregoing discussion has purposefully been kept as general as possible in order to illustrate the basic criteria of wet refinery corrosion and its solution by chemical treatment with neutralizers and film-forming inhibitors. Use of neutralizers and inhibitors has been described in the crude still and overheads. The same concepts are being applied in other systems where there is a hydrocarbon product in contact with liquid water containing corrosive constituents, usually hydrochloric acid and hydrogen sulfide. Corrosion by naphthenic acids is descirbed by Bregman, based on early references of Tandy2 5 and Derungs2 6 Naphthenic acids can be neutralized with NaOH to form oil-soluble salts and the acid number of a crude containing naphthenic acids often gives an indication of its corrosivity during processing. In a report by NACE Committee T_S27 (Refinery Corrosion) in 1963, it was concluded that the problem is no longer of major importance in refinery operations because of the widespread use of resistant alloys such as Type 316 stainless steel. However, further work on the problem was indicated.

This type of corrosion is becoming more common as hydrogen treating processes proliferate. It is noteworthy to point out that corrosion occurs at basic pH values, where it would be expected that iron and its alloys would be protected, as explained in the beginning of this chapter. A blue deposit of the ferro and ferricyanides of iron in fouled or corroded equipment often is evidence of this sort of corrosion. Gutzeit mentions the use of filming amines for amelioration of the problem. Recently, Nathan, et al33 have extended Gutzeit's work in systems containing an oil phase and filming inhibitors in additon to the corrosive hydrogen sulfide-ammonia-hydrocyanic acid constituen ts. They show that both overall attack and hydrogen blistering may be effectively reduced by the use of "proper" film-forming amines. These amines are similar to those used for other refinery corrosion prevention services. It is very important that the "proper" inhibitor be used, as determined by preliminary laboratory and plant evaluation. This is because overall attack may be reduced, while blistering or hydrogen embrittlement is not if an "improper" inhibitor is used. In fact, hydrogen adsorption problems may even increase, as is pointed out in an early paper by Zappfe34 on organic film-forming inhibitors and by many other authors since.35 Samans36 has recently mentioned the successful use of organic film-forming inhibitors for prevention of hydrogen blistering in refinery vessels.

Hydrogen Blistering Problems Hydrogen blistering problems are well known and several studies of this problem and its solution have been reported by Bregman. The basic cause of hydrogen blistering is the trapping of atomic hydrogen in the interstices between grains of metal or at inclusions or laminations where the atomic hydrogen combines to form molecular hydrogen. When the molecular hydrogen cannot escape through the metal surface, it causes blisters, cracking and (3)A collection of 15 articles on the economics of corrosion control is the NACE publication: Corrosion Control Makes Dollars and Sense.

49

failure, etc., due to the increased pressure resulting from its formation.

deducted directly from operating income and hence bear a less favorable tax position. Such generalizations, of course, may vary with individual companies and their accounting systems. Economic analyses such as discounted cash flow, present values, payout times and other ways to evaluate the economics of a system cannot be covered in this article; nevertheless, their importance should be emphasized, because the success or failure of a corrosion prevention program depends on economic feasibility as well as on technical performance. The plant engineer who recommends a preventive treatment to his management should be conversant with these methods of economic evaluation and

Under most conditions of acid corrosion, the equilibrium between atomic and molecular hydrogen is displaced essentially completely in the direction of molecular hydrogen .. However, in the presence of a number of catalytic agents, H atoms are kept from combining at the surface. Important catalysts are cyanides and sulfur compounds, including hydrogen sulfide. Experience in handling sour crudes and sour waters was described by Wachter and his colleagues28 and by Ehmke29 and others. An early paper by Effinger30 points out that high nitrogen content in the feedstock appears to increase the probability of hydrogen attack in gas plants following catalytic cracking because of CN increase brought about by hydrogenation of nitrogen compounds.

justification. (3) In modern refineries and chemical plants with highly complex and interrelated processes and equipment, downtime because of corrosion failure with concomitant loss in

In a recent paper describing corrosion in the hydrocracking of West Coast crudes, Piehl31 found that corrosion of aqueous effluents increased with the mathematical product of nitrogen and sulfur contents of the water, expressed as an equivalent content of ammonium sulfide. Total water volume as well as fluid velocity were also factors determining corrosion rates. Gutzeit32 has summarized the various parameters involved in corrosion in such systems and extended the earlier work of Wachter, et al. Gutzeit explains the effect of pH, sulfide content and cyanide content as competition between the formation of a protective iron sulfide film and its dissolution as soluble ferrocyanide. Figure 2 shows some of the results reported by Gutzeit.

production and product sales and profits, may be much more important than direct costs of equipment replacement or repair and labor to effect them. Such losses can easily exceed the cost of continuous treatment by corrosion inhibitors and antifoulants.

Special Refinery Processes Amenable to Corrosion Inhibitors The foregoing discussion has purposefully been kept as general as possible in order to illustrate the basic criteria of wet refinery corrosion and its solution by chemical treatment with neutralizers and film-forming inhibitors. Use of neutralizers and inhibitors has been described in the crude still and overheads. The same concepts are being applied in other systems where there is a hydrocarbon product in contact with liquid water containing corrosive constituents, usually hydrocWoric acid and hydrogen sulfide. Corrosion by naphthenic acids is descirbed by Bregman, based on early references of Tandy2s and Derungs2 6 Naphthenic acids can be neutralized with NaOH to form oil-soluble salts and the acid number of a crude containing naphthenic acids often gives an indication of its corrosivity during processing. In a report by NACE Committee T_827 (Refinery Corrosion) in 1963, it was concluded that the problem is no longer of major importance in refinery operations because of the widespread use of resistant alloys such as Type 316 stainless steel. However, further work on the problem was indicated.

This type of corrosion is becoming more common as hydrogen treating processes proliferate. It is noteworthy to point out that corrosion occurs at basic pH values, where it would be expected that iron and its alloys would be protected, as explained in the beginning of this chapter. A blue deposit of the ferro and ferricyanides of iron in fouled or corroded equipment often is evidence of this sort of corrosion. Gutzeit mentions the use of filming amines for amelioration of the problem. Recently, Nathan, et al33 have extended Gutzeit's work in systems con taining an oil phase and filming inhibitors in additon to the corrosive hydrogen sulfide-ammonia-hydrocyanic acid constituen ts. They show that both overall attack and hydrogen blistering may be effectively reduced by the use of "proper" film-forming amines. These amines are similar to those used for other refinery corrosion preven tion services. It is very important that the "proper" inhibitor be used, as determined by preliminary laboratory and plant evaluation. This is because overall attack may be reduced, while blistering or hydrogen embrittlement is not if an "improper" inhibitor is used. In fact, hydrogen adsorption problems may even increase, as is pointed out in an early paper by Zappfe34 on organic film-forming inhibitors and by many other authors since.3 5 Samans36 has recently mentioned the successful use of organic film-forming inhibitors for prevention of hydrogen blistering in refinery vessels.

Hydrogen Blistering Problems Hydrogen blistering problems are well known and several studies of this problem and its solution have been reported by Bregman. The basic cause of hydrogen blistering is the trapping of atomic hydrogen in the interstices between grains of metal or at inclusions or laminations where the atomic hydrogen combines to form molecular hydrogen. When the molecular hydrogen cannot escape through the metal surface, it causes blisters, cracking and (3)A collection of IS articles on the economics of corrosion control is the NACE publication: Corrosion Control Makes Dollars and Sense.

49

man. These various processes are claimed to have greater efficiency, economy, or versatility than the monoethanolamine and diethanolamine processes. The principle of all these processes is the same and involves the adsorptionextraction equilibria between the gases, carbon dioxide and hydrogen sulfide and the various treating liquids. Equilibrium favors the formation of a salt, or of increased solubility of gas in the liquid at low temperatures and high pressures. The salt is decomposed and/or the gas liberated from solution as pressure is lowered and/or temperature is raised. This renews the solvent-extractant for reuse and liberates

200 80 U a:0E'"c: 100 'e ~0

60 110 160 ii: 140 120

COI.IPONS

HS-/CN-

PROBES

o

V

1-10

o

••

o

••

10-100 100-1000 1000- 10.000

•

• ••

the gases for disposal, burning or further processing, e.g., sulfur manufacture. Gas treating plants have been bothered with corrosion problems from the beginning. These problems have been described in early papers by Polderman et al,37 Lang and Mason38 and Moore,39 as well as by others. Much of the trouble is caused by the breakdown of the solvents, e.g., monoethanolamine, at the elevated temperatures of the reboiler regenerator. It is postulated that the breakdown products can chelate with iron and prevent the formation of an insoluble protective ftlm at the high pHof operation, which pH should preclude corrosion of iron (according to fundamental electrochemical theory as previously described in the paper). In this respect, there is a similarity between the corrosion of iron in amine solutions in gas regereration, for example, and that in the effluents from hydrocracking plants described earlier. According to Butwell,40 corrosion and other operational problems can be greatly reduced by proper plant operation. He recommends that the gas loading (ratio of moles acid gases per mole of MEA) be kept to 0.45 or less, monoethanolamine concentration be kept at 20% and that degradation products be removed by use of a side-stream reclaimer. Most of the authors quoted recommend maintaining reboiler temperatures at the lowest practical values in order to reduce solvent degradation and subsequent corrosion of equipment.

.,

• o

20

86 o

-5

V

-4

-3

~ -2

Q

--T

Log Bisulfide Concentration

CD

0

•.I

-2

(g moles/I)

FIGURE 2 - Corrosion rates for test runs with cyanide plotted against the logarithm of bisulfide ion concentration. Three regions of attack can be identified: A region of sulfide corrosion (typical pH values below 8.01; a noncorrosive region because of formation of protective ferrous sulfide scale (typical pH values between 8.0 and 9.0); and a region of sulfide corrosion because of complete dissolution of the protective sulfide scale by cyanide ions at pH values above 9.0 (extreme rightl.32

Corrosion in Gas Processing Units

New Processes Developed Among the processes recently developed to compete with ethanolamines is the Sulfolane process (Shell Oil). The solvent is an aqueous solution of di-isopropylamine (DIPA) and sulfolane and is described in articles by Dunn et al41 by Goar42 and by McNab and Treseder.43 Holder44 discusses the use of "Diglycolamine" which consists of p, p' hydroxyaminoethyl ether and is purported to be comparable in performance to MEA but to require lower capital costs. Franckowiak and Nitscke45 discuss the Estosolvan

Corrosion in gas sweetening and other gas processing units has become of increasing importance with the growth of the natural gas industry and with the increase in volume of refinery and petrochemical plant off-gasses and light products such as ethylene and with the number of process for treating such gases. Acid constituents such as carbon dioxide and hydrogen sulfide ordinarily are removed from natural gas in central field treating plants before transmission of the gas for sale. Similarly, these constituents must be removed from plant gas streams, as in stream cracking of hydrocarbons for ethylene production, before the gases are subjected to low-temperature fractionation. In the production of synthesis gas for subsequent conversion to ammonia or methanol, for example, it is usually necessary to remove carbon dioxide formed either by partial combustion of hydrocarbons or by the water gas shift reactions. Many gas purification processes have been developed during the past ten years to compete with the older ethanolamine sweetening processes as described by Breg-

process, employing tri-n-butylamine phosphate as the solvent-extractant. This process is said to selectively remove hydrogen sulfide from carbon dioxide and to require a lower heat demand than MEA because of physical rather than chemical adsorption of the acid gases. Hegwer and Harris46 describe the Selexol process, employing as a solvent polyethylene glycol dimethyl ether, which is claimed to selectively remove carbon dioxide from hydrogen sulfide and to have low initial plant costs and reduced utility costs, with minimum maintenance. so

Comparison of the various gas treating processes include recent articles by Dingman and Moore,47 Maddox and Burns,48 and Blake.49

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,.,.,~.~

~\.i.:.'~ &,1.,.. ' .•"4.••. ./, ". ;Y; .

-er-",;,,f!..,,,, .&.. ,

AI'

Corrosion and its prevention and solution in gas treating plants are described in a number of articles. A staff report by the Natural Gasoline Producer's Association in 196750 is a good summary of the problem. Grafr 1 reports on the unsuccessful use of a number of a materials tested as corrosion inhibitors in MEA plants. Sudbury et al52 early recognized the corrosion problem in MEA plants and recommended an organic inhibitor known as T-52 (a reaction product of an acetylenic alcohol and polyamine) to deal with the problem. Mottley and Fincher53 successfully used this material in all but the "dead" areas of heat exchangers, etc., in a sour gas processing plant in East Texas. They said the material reduced foaming of the MEA solutions. They also reported on the use of sodium sulfite and hydrazine for removal of oxygen and reduction of the corrosion loading in the system. The inhibitor T-52 was subsequently licensed to a refinery service company and its use is described by Nathan.19 It is probably the most commonly used inhibitor for MEA and other gas sweetening processes and is formulated with antifoaming agents for optimum field utilization. Foaming, a common problem in many gas-liquid separation or extraction processes, may be aggravated by surfactants, particularly in MEA systems and by fme' particles, such as corrosion products, which act as foam nuclei or stabilizers. Use of a side-stream filter to remove these particles often is an effective supplement to the proper corrosion inhibition in solving such foaming problems.

FIGURE 3 - Exchanger tube from MEA plant showing corrosion attack near baffle. Failure occurred because inhibitor could not reach dead areas next to the tube sheet and baffles. 53

FIGURE 4 - Reboiler tube failure resulting from concentration of heat load at top section of tubes because steam traps were flooded with condensate and water was in the tubes.5 3

Oakes and Hager5 4 discuss laboratory corrosion studies in MEA systems and favorable results obtained by use of an experimental compound developed as a result of their study. They do not report on any field or plant results. The material was effective with carbon dioxide as the corrosive gas, but not with hydrogen sulfide. Williams and Leckie55 report on the use of sodium metavanadate as a successful corrosion inhibitor in an MEA system removing carbon dioxide from hydrogen streams. Use of the inhibitor above 225 F (108 C) is believed to produce a highly protective fIlm of Fe3 04, Hawkes and Mag056 have recently described a three component inorganic additive claimed to be highly effective in MEA systems for carbon dioxide absorption.

is low. The addition

of oxygen to the system increases

passivation of mild steel but increases corrosion of coppernickel alloys. The catalytic removal of carbon dioxide with potassium carbonate (Catacarb Process) is described by Eickmeyer61 and by Morse.62 Corrosion inhibition in this system by using soluble trivalent oxides of As, Sb and Bi has been patented by Negra.63 The toxic effect of these materials and the pollution problems encountered in the disposal of spillages and waste streams con taining them must be considered in evaluating their applicability. Similarly Fischer64 has patented the use of antimony tricholoride in conjunction with tartaric acid as an MEA

Use of hot potsssium carbonate for gas sweetening and corrosion problems encountered in these systems has been described in several articles by Bienstock and Field et al. 5 7-59 They found

that both potassium nitrite (0.5%) and potassium chromate (0.2%) were very effective in carbon dioxide systems but not with hydrogen sulfide. Various other organic and inorganic compounds were evaluated with negative or questionable results as corrosion inhibitors in these systems. Figures 3 and 4 show some consequences of corrosion in MEA units. Banks60 reports on the use of metavanadate in hot carbonate systems and states that metavanadate passivates steel in a carbonate solution only when bicarbonate content

inhibitor. The Giammarco process65,66 employs aqueous alkaline carbonates supplemen ted with amino acids for carbon dioxide adsorption and alkaline arseni te-arsenate solution for hydrogen sulfide absorption. Jenette67 has reviewed the performance of the process in practice, including the corrosion problems, which were stated to be minor. A recent

article

by Goar68

compares

the relative

advantages and disadvantages of currently used sweetening processes in the U.S. 51

Miscellaneous

Refinery Corrosion Problems

clude that low pH is very detrimental, with considerable increase in resistance to SCC as pH is raised from 2 to 5. Heller and Prescott 75 discuss refinery problems of SCC in hydrodesulfurizer units, etc., in presence of hydrogen sulfide and poly thionic acids formed by reaction between hydrogen sulfide and sulfur dioxide. They point out the effect of air in increasing susceptibility to SCC in these systems, as it is also known to do in systems where chloride is the principal causative factor. The above examples illustrate several ways that chemical agents can be used for prevention of stress cracking by alteration of the environment, e.g., by changing the pH or by use of antioxidants for removal of oxygen. Although the principal means of preventing SCC are by controlling the environment as described above or by alteration of the metal, protection by barriers can be used, provided they can be kept intact. As was discussed in a previous section, this is usually difficult with protective coatings; however, it may be effected by use of films formed by inhibitors, which are in dynamic equilibrium with liquids containing inhibitor and in contact with the metal to be protected. Hence, the film can be repaired continuously. Patton and Casad76 report on the use of film-forming inhibitors in reducing failure by corrosion fatigue, a phenomenon similar to stress corrosion cracking, in systems simulating corrosive oil field fluids and containing hydrogen sulfide. Fatigue life was increased by a factor of as much as ten, depending upon the inhibitor used and the conditions of filming. The efficacy of the various treatments described was attributed to the strength of the film and its insolubility in the filming and contacting fluids. This would appear to indicate the potential of applying film-forming inhibitors for prevention of stress cracking and corrosion fatigue in refinery as well as down-hole applications.

Many miscellaneous corrosion problems in refinery and petrochemical plants not discussed already involve metal contact with strong acids such a sulfuric used in alkylation and acid washing, hydrofluoric in alkylation, nitric from ammonia oxidation and so on. Generally these corrosion problems are solved by means other than the use of corrosion inhibitors, e.g., by changes in process design (such as assuring water-free systems, or by maintaining sulfuric acid at sufficiently high concentrations to be noncorrosive to steel); by metallurgical approaches and selection of resistant alloys; by use of protective coatings and linings; or by anodic protection. Thornton69 gives as keys to corrosion control for corrosion-free HF alkylation: "good engineering design, appropriate materials of construction, diligence in keeping equipment and feedstocks dry and careful and intellignet adherence to prescribed maintenance practices." Carvalho and Alvarenga 70 report on corrosion problems caused by sulfuric, hydrochloric and nitric acids in Brazilian refining and petrochemical operations. Geerlings and Jongebreuer 71 discuss the whole range of refinery corrosion problems and their solutions. Included are problems in handling strong caustic solu tions, phosphoric acid and the other mineral acids mentioned above. They also discuss corrosion problems in furfural units brought about by oxidation of the furfural to furoic acid, etc. Corrosion prevention by chemicals is not ordinarily practical in refinery work for acids which are either concentrated or strong. However, dilute acid streams often may be rendered noncorrosive by use of inexpensive neutralizers and/or filming inhibitors. Examples include the mixed condensate composed of water and hydrocarbon liquids from dehydrogenation of ethyl benzene to styrene in the presence of steam, various acidic wash streams, etc. In using inexpensive and easily available alkalies for neutralizing acidic streams, washing out vessels, etc., the chloride content of the commercially available soda ash or caustic must be carefully controlled, as also must the chloride content of the plant or source water used to make up the neutralizing and wash solutions. This is because of the deleterious effect of chloride ion in destroying passive films on normally corrosion-resistant alloys such as the various types of stainless steels, resulting in stress corrosion cracking (SCC) of these materials. A recent NACE publication 72 discusses this problem and gives detailed recommendations, which should be followed. With increasing use of stainless steels under a wide variety of services, the problem of stress cracking has received a great amount of deserved attention. The corrosion literature abounds with discussions of the problem and its solutions, both from the theoretical and the practical points of view. Various parameters influencing SCC have been reported by Kohut and McGuire 73 in systems where hydrogen sulfide is a principal causative factor. Other important factors in their systems were strength of steel, stress level and acidity or alkalinity of the environment. Treseder and Swanson 74 report on the SCC of high strength steels exposed to a wide range of hydrogen sulfide concentrations, chloride concentration and pH. They con-

References I. C. M. Huggins, Jr. A Review of Sulfide Corrosion Problems in the Petroleum Industry. Mat. Pro., 41, (1969) Jan. 2. A. S. Couper and A. Dravnieks. High Temperature Corrosion by Catalytically Formed Hydrogen Sulfide, Corrosion, 29 It, (1962) Aug. 3. A. S. Couper. High Temperature Mercaptan Corrosion of Steels, Corrosion, 396t, (1963) Nov. 4. C. L. Easton and B. G. Jameson. High Temperature Organic Sulfur Corrosion in Crude Processing Units, Proc. NACE 25th Cong, Houston, Tx. p.572-577,(l969). 5. J. D. McCoy and F. B. Hamel. Effect of Hydrodesulfurizing Process Variables on Corrosion Rates, Mat. Pro., 17 (1971) April. 6. A. S. Couper and J. W. Gorman. New Computer Correlations to Estimate Corrosion of Steels by Refinery Streams Containing Hydrogen Sulfide, Proc. NACE 26th Conf., Houston, Tx. p.431-437. 7. J. E. Guthrie and R. D. Merrick. Resistance of Furnace Reformer Tubes in a Sulfur Environment, Mat. Pro. 32 (1964) Nov. 8. D. M. McDowell, Jr. Refinery Reactor Design to Prevent High Temperature Corrosion, Mat. Pro., 45 (1966) Nov. 9. C. A. Robertson and Hugh L. Meyers. Application and Use of Aluminum Coatings in Oil Refinery Processes, Mat. Pro., 23 (1967) Sept. 10. 1. R. Schley and F. W. Bennett. Destructive Accumulation of

52

11.

12. 13. 14. 15. 16. 17. 18.

19. 20. 21.

22.

23. 24. 25. 26. 27. 28.

29.

30. 31.

32. 33.

34.

35. 36. 37.

38. 39.

Nitrogen in 30 Cr-20 Ni Cast Furnace Tubes in Hydrocarbon Cracking Service at 1100 C, Corrosion, 276 (1967) Sept. F. A. Hendershot and H. L. Valentine. Materials for Catalytic Cracking Equipment, (A survey of 20 petroleum refineries). Mat. Pro., 43 (1967) Oct. J. F. Kaufman. Sulfide Corrosion Attack on Heater Tubes, Chem. Pro., 29 (1971) April. G. J. Samuelson.Proc. Am. Pet. Inst., 34, III, 50 (1954). R. 1. Annessen and G. D. Gould. Sour-Water Processing Turns Problems into Payout, Chem. Eng., 67 (1971) March. Natural Petroleum Refiners Association. Phila. Meeting, Fall (1970). L. E. Fisher, G. C. Hall, R. W. Stenzel. Crude Oil Desalting to Reduce Refinery Corrosion Problems, Mat. Pro., 8 (1962) May. R. H. Carlton. Refinery Condenser and Exchanger Corrosion by Ammonium Chloride, Mat. Pro., 15 (1963) Jan. E. B. Backensto and A. N. Yurick. Chloride Corrosion and Fouling in Catalytic Reformers with Naphtha Preheaters, Corrosion, 17, 133t, (1961) March. C. C. Nathan. Use of Chemicals for Solution of Refinery Corrosion and Related Problems, Mat. Pro., 15 (1970) Nov. J. A. Biehl and E. A. Schnake. Corrosion in Crude-Oil Processing-Low pH vs. High pH, Oil Gas l., 57, 125-8 (1959). C. C. Nathan and C. L. Dulaney. How Statistical Concepts Facilitate Evaluation of Corrosion Inhibitors, Mat. Pro., 21 (1971) Feb. ASTM Method D-2550-66T, Water Separation Characteristics of Aviation Turbine Fuels, ASTM Standards, Part 17, p.965, American Society for Testing and Materials, Philadelphia, Penna. (1961). C. L. Dulaney and C. C. Nathan. Jet Fuel Tests Provoke Reevaluation, Oil Gas l., 68, 89 (1970) April. C. C. Nathan and C. L. Dulaney. Water Separometer Test is Tricky, Hydro. Proc., 50, 129 (1971) August. E. H. Tandy. Inspection of Petroleum Refinery Equipment. Corrosion, 10,160 (1954) May. W. A. Derungs. Naphthenic Acid Corrosion-An Old Enemy of the Petroleum Industry, Corrosion, 12, 617t (1956) Dec. NACE Technical Committee T-9, Task Group J-8-3, Mat. Pro.. J. J. Heller, et ai, 90 (1963) Sept. T. Skei, A. Wachter, W. A. Bonner, H. D. Burnham. Hydrogen Blistering of Steel in Hydrogen Sulfide Solutions, Corrosion, 9, 163 (1953) May. E. F. Ehmke. Hydrogen Diffusion Corrosion Problems in a Fluid Catalytic Cracker and Gas Plant, Corrosion, 16, 246 (1960) May. R. T. Effinger. Hydrogen Blistering in Cat Cracker Gas Plants, Oil Gas l., 41, 222 (1957) Oct. R. L. Piehl. Corrosion by Sulfide Containing Condensate in Hydrocracker Effluent Coolers, API-33rd Annual Midyear Meeting, Philadelphia, Penna., (1968) May. J. Gutzeit. Corrosion of Steel by Sulfides and Cyanides in Refinery Condensate Water, Mat. Pro., 17 (1968) Dec. C. C. Nathan, C. L. Dulaney and M. 1. Leary. Prevention of Hydrogen Blistering and Corrosion by Organic Inhibitors in Hydrocarbon-Aqueous Systems of Varying Composition, -74th Annual Meeting of ASTM, Atlantic City, N. J. (1971) June. C. A. Zapffe and M. E. Haslem. Evaluation of Pickling Inhibitors from the Standpoint of Hydrogen Embrittlement, Wire and Wire Prod., 23, (1948) Oct., Nov., and Dec. B. G. Goar. Today's Gas Treating Processes, Oil Gas l., 75 (1971) July. C. H. Samans. Hydrogen Blistering of Refinery Vessels, Presented to API Operating Practices Committee (1969) May. L. D. Polderman, C. P. Dillon, A. B. Steele. Degradation of Monoethanolamine in Natural Gas Treating Systems, Oil Gas l., (1955) May. F. S. Lang and J. F. Mason, Jr. Corrosion in Amine Gas Treating Solvents, Corrosion, 14, 105t (1958) Feb. K. L. Moore. Corrosion Products in a Refinery Diethanolamine System, Corrosion, 16, 503t (1960) Oct.

40. K. F. Butwell.Hydro. Proc., 47, III (1968) April. 41. C. L. Dunn, E. R. Freitas, E. S. Hill, J. E. R. Sheeler, Jr. Shell Records Commercial Data on Sulfolane Processing, Oil Gas l., 89, (1965) March 29. 42. B. G. Goar. Sulfinol Process Has Several Key Advantages, Oil GasJ., ll7 (1969) June 30. 43. A. J. McNab and R. S. Treseder. Materials Requirements for a Gas Treating Process, Mat. Pro. & Pert, 21 (1971) Jan. 44. H. L. Holder. Diglycolamine-A Promising New Acid Gas Remover, Oil Gas l., 83, (1966) May 2. 45. S. Francowiak and E. Nitsche. Estosolvan: A New Gas Treating Process, Hydro. Proc., 145, (1970) May. 46. A. M. Hegwer and R. A. Harris.Solexol Solves High H2S/C02 Problem, Hydro. Proc., 107, (1970) April. 47. J. C. Dingman and T. F. Moore. Compare DGA and MEA Sweetening Processes, Hydro. Proc., 138 (1968) July. 48. R. N. Maddox and M. D. Burns. How to Choose a Treating Process, Oil Gasl., 131 (1967)Aug 14. 49. R. J. Blake. How Acid-Gas Treating Process Compare, Oil Gas l., (1967) Jan. 9. 50. NGPA Staff Report. Where to Expect Processing Plant Corrosion, Oil Gas l., 74 (1967) July 17. 51. K. A. Graff. Corrosion in Amine Type Gas Processing Units, Refining Engineer, C-12, (1959) March. 52. J. D. Sudbury, O. L. Riggs and J. F. Leterle. Lab Inhibitor Stops DEA Corrosion, Petro. Ref, 37, 183 (1958) May. 53. J. R. Mottley and D. R. Fincher. Inhibition of MEA Solutions, Mat. Pro., 26 (1963) August. 54. B. D. Oakes and M. C. Hager. Corrosion Studies in Alkanolamine - CO2 Systems, Mat. Pro., 25, (1966) August. 55. E. Williams and H. P. Leckie. Corrosion and Its Prevention in a Monocthanolamine Gas Treating Plant, Mat. Pro., 21 (1968) July. 56. E. N. Hawkes and B. F. Mago. Stop MEA CO2 Corrosion, Hydro. Proc., 109 (1971) August. 57. D. Bicnstock and J. H. Field. Corrosion Inhibitors for HotCarbonate Systems, Corrosion, 571t (1961) Dec. 58. D. Bienstock, J. H. Field and J. G. Myers. Corrosion Study of the Hot Carbonate System, Bu Mines RI 5979, (1962). 59. D. Bienstock and J. H. Field. Corrosion of Steels in Boiling K2C03 Saturated with CO2 and H2S, Corrosion, 337t (1961) July. 60. W. P. Banks. Corrosion in Hot Carbonate Systems, Mat. Pro., 37 (1967) November. 61. A. G. Eickmeyer. Catalytic Removal of CO2, Chem. Eng. Progress, 89 (1969) April 22. 62. R. J. Morse. Catacarb C02 Cuts Cost, Enjoys Big Growth, Oil GasJ., 184 (1968) April. 63. J. S. Negra. Inhibiting Corrosion by Use of Soluble Trivalent Oxides of As, Sb, Bi, U.S. Patent No. 3,087,778 to Chemical Construction Comapny. 64. Paul W. Fisher. Method of Gas Purification Utilizing an Amine Solution and an Anti-Corrosion Agent, U.S. Patent 2,869,978. Assigned to Union Oil of California, L.A., Cal. 65. G. Giammarco. Method of Separating Carbon Dioxide from Gaseous Mixtures, U.S. Patent No. 2,993,750, Assigned to S.p.a. Vetrocoke, Turin, Italy. 66. G. Giammarco. Method of Removing Hydrogen Sulfide from Gaseous Mixtures, U.S, Patent No. 2,943,910. 67. E. Jenette. Six Cases Throw Light on the Giammarco Vetrocoke Process, Oil Gas l., 60,72 (1962) April 30. 68. B. G. Goar. Today's Gas Treating Processes, Oil and Gas l., (1971) July 12 and 19. 69. D. P. Thornton, Jr. Corrosion-Free HF Alkylation, Chem. Eng., 108 (1970) July. 70. P. de Cunha Cavalho and M. de Alvarenga. Corrosion Caused by Mineral Acid in Oil Refineries-Its Causes and Prevention, 2nd International Congress on Metallic Corrosion, NACE, Houston, Tx. 319 (1963). 71. H. C. Geerlings and J. C. Jongebrcur. Corrosion in Oil Refinery

53

Equipment, Proc. 1st International sion, 573 (1961).

Congress on Metallic Corro-

Cracking Causes Failure of Compressor Components in Refinery Services, Mat. Pro., 17 (1968) June. 74. R. S. Treseder and T. M. Swanson. Factors in Sulfide Corrosion Cracking of High Strength Steels, Corrosion, 31 (1968) Feb. 75. J. J. Helier and G. R. Prescott. Cracking of Stainless Steels, Mat. Pro., 14 (1965) Sept. 76. C. C. Patton and B. M. Casad. Tests Determine Effect of Organic Inhibitors on Corrosion Fatigue, Mat. Pro., 56 (1969) Sept.

72. L. T. Overstreet. Recommendations for the Use of Neutralizing Solutions to Protect Against Stress Corrosion Cracking of Austenitic Stainless Steels in Refineries, Report of NACE Committee T-8-6, Proc. NACE 25th ConL, NACE, Houston, TX.578-582 (1969). 73. G. B. Kohut and W. J. McGuire. Sulfide Stress Corrosion

S4

Part 2 - Control of Fouling

In 1963, Bregman1 stated "protection by inhibitors drops off rapidly and 450 F appears to be the limit of effective inhibitor usage. Corrosion, as apparent in intermediate temperature units, can drop off rapidly and be replaced by fouling of the equipment. The fouling due to product degradation becomes a very serious problem as it interferes markedly with heat transfer. In general, one may say that above 450 F, corrosion inhibitors are replaced by either antifouling agents or else by the use of special alloys." The correctness of Bregman's statement has been borne out to a large extent by the experience of petroleum and petrochemical processors. In the last two decades, an increasing variety of fouling problems has been encountered, many of which have been solved economically by the use of chemical antifoulants. Furthermore, corrosion inhibitors have been used under increasingly varied and severe conditions as explained in the previous section. Because of the close relation between fouling and corrosion problems in such processes, this section on antifoulants has been added.

an interdependence is indicated between fouling and corrosion in process equipment. Another common fouling problem due to inorganic deposits may occur when ammonia is used to neutralize HCI formed by hydrolysis of cWorides remaining after crude desalting. Increasing the pH in order to reduce corrosive potential results in formation of the oil-insoluble salt, N~ Cl. This may result in a fouling problem which can be alleviated by adding water either continuously or intermittently to affected units.(I) Another approach, as described by Biehl and Schnake3 is to reduce the amount of ammonia added for neutralization and operate at a lower pH and instead use organic film-forming inhibitors to control corrosion. Frequency of this approach has increased because of the development of inhibitors active over a wider pH range than those originally used in refinery work. A third solution to the problem employs neutralizers other than ammonia, e.g., morpholine, cyclohexylamine or other high molecular weight amines, which combine with mineral acids to give salts having higher oil solubility and/or dispersibility than does NH4 Cl.(2)

Scope of Fouling

Organic Fouling Deposits

Despite long use, the meaning of the word "fouling" remains nebulous. In the following discussion, fouling is considered to relate to the presence of solid materials, without respect to origin and nature, which are insoluble in the process streams of interest. These materials cause operating difficulties by deposition onto surfaces of equipment contacted by the process streams either in zones where the insolubles are formed and/or in downstream units. Such deposits interfere with mass and heat transfer, as evidenced by reduced heat transfer coefficients and flow rates and by increased pressure drops. Accordingly, throughputs are reduced, while pumping costs and heating or cooling requirements are increased. In extreme cases, fouling may result in complete plugging, or burning out or rupturing of critical process units. Thus, the scope of fouling problems is seen to be quite broad.

Organic fouling is much more prevalent but less well understood than inorganic fouling. Organic foulants usually are high molecular weight materials formed by oxidation, polymerization or other reactions of constituents in the process streams. These constituents may be the principal components of the streams or impurities in them. Deposits range in consistency from rubbery-like solids to "pop-corn" and coke. Deposit as well as stream analyses may be of value in determining the composition of the deposit to indicate its origin and remedy. However, sllch analyses are often time-consuming, expensive and do not yield a great deal of useful information. While it is desirable to predict the fouling potential of a stream from its analysis, this has been possible only in a few cases such as those reported by Taylor and Wallace.4 Nevertheless, some useful generalizations can be made on factors influencing fouling and possible methods of prevention as illustrated by Gonzalez.5 Several examples will be discussed below. It should be emphasized that although the term paraffin (low affinity) implies that such materials are nonreactive, this is not necessarily the case at the elevated temperatures and pressures involved in petroleum processing and in the presence of certain contaminants. Paraffins are relatively nonreactive, compared to other more active

Inorganic Fouling Deposits It is sometimes useful to classify fouling deposits as to their inorganic or organic nature, because such a classification may point to the cause of the fouling and indicate possible methods of prevention or alleviation. Weinland2 et al point out that corrosion products such as metallic oxides and sulfides may deposit on equipment downstream of the area of corrosive attack, causing fouling problems. Accordingly, use of corrosion inhibitors to solve the corrosion problem is a possible solution to the fouling problem and

(I )See References 17 and 18 in Part 1. (2)See Reference 21 in Part I.

55

the use of film-forming corrosion inhibitors. The dispersant molecule must possess a polar end which adsorbs onto the growing particles of coke and prevents their growing into larger precipitates. A nonpolar tail is also necessary and is oriented away from the growing nucleus. The nature of the polar end and the length and other properties of the non polar tail are important in determining the solubility of material in the process stream as well as its adsorption from the stream. Nathan and Dulaney! 0 have described a test for effectiveness of materials as antifoulants based on their

components such as olefins, aromatics and heterocyclic hydrocarbons encountered in petroleum refineries and particularly in petrochemical operations. The presence of such reactive materials, even in the range of parts per million (often beyond the scope of conventional stream analyses) can lead to severe fouling. Consideration must be given to the effect of concentrations of ppm multiplied by stream volumes of thousands of barrels per day and continuous operations of months to give large quantities of deposits from streams containing only minute concentrations of foulants.

ability to disperse carbon black in hydrocarbons. Commercial materials used as antifoulants in process industries contain combinations of dispersants, antioxidants, metal deactivators and/or corrosion inhibitors. The choice of the best material for a given application is determined by effectiveness and cost. Screening tests to differentiate between alternative materials have been

Operating parameters such as temperature, pressure and contact time, all of which increase fouling reaction rates, ordinarily are set by processing conditions. Additional factors are stream contamination effects, which mayor may not be amenable to process changes. Many fouling reactions proceed through free-radical oxidation and polymerization routes, so that the elimination of free-radicals or their precursors is desirable. Because oxygen is effective in many free-radical reactions, as described by Taylor, prevention of air contamina tion in a system is desirable. This is accomplished by "tightening up" the system, minimizing transfer and storage times and/or by such procedures as inert gas blanketing of storage vessels. Many materials are so sensi tive to traces of oxygen, however, that even these measures allow some fouling to occur. Consequently, antioxidants may be used to negate the effect of air as described by Gonzalez, by Nixon and Minor6 and by Mahoney.7 Another factor which increases fouling is the presence in the process streams of trace quantities of certain active metals such as iron, nickel, vanadium and particularly copper (Nixon and Minor). These metals are present because of original occurrence in the crude streams or from corrosion of process equipment constructed of the metals or their alloys. Surfaces of these metals are also active catalysts for fouling reactions. Here again, the interdependence of corrosion and fouling is illustrated, since metal contaminants resulting from corrosion in up-stream units may be reduced by use of corrosion inhibitors. An alternative and supplementary method of combatting metal contamination has been described by Luvisi and Chenicek8 and involves the use of chemicals effective

developed and will be described below. Because of the wide variety of streams requiring treatment, many commercial antifoulants have been developed for different applications. The situation is similar to that in corrosion inhibition and no universal remedy is available. An additional important property of antifoulants is high temperature stability. Temperatures above 400 F (200 C) are common and applications in the range of 600 to 650 F (315 to 345 C) are not unusual, as stated by Couper!! in the 1970 NACE T-8 Committee Report on Fouling. Higher temperatures also may be possible for very short contact times. Applications of antifoulants are being attempted under extreme conditions such as in ethylene steam-cracking pyrolysis units. Here it is postulated that the surface of the pyrolysis furnace tubes may be altered by the antifoulant so as to reduce the catalytic effect of the surface in promoting coke formation.

Use of Antifoulants The previous discussion has covered the rather limited theory involved in the development of antifoulants. During the past ten years, use of these materials has increased and many successful applications have been reported in the technical literature. Although the technological and economic aspects have been covered amply in the T-8 report just cited, several of the more important aspects brought out in that report as well as in a few other technical articles will be summarized.

in complexing the undesirable metal, either on the equipment surface or in the stream, to prevent acceleration of fouling reactions. Such chemicals may be formulated in combination with an antioxidant, corrosion inhibitors and/or dispersant as described by Gonzalez. Oil-soluble dispersants are widely used to alleviate both organic and inorganic fouling problems. The object is not to prevent the initial formation of coke nuclei and other insoluble particles in the stream, but to reduce their tendencies to agglomerate into larger precipitates which can settle out of the process stream and deposit on and in various places in the equipment. Numerous dispersants are described in the patent literature and a number of typical examples are included in the attached list of patents.9 The principles involved in development of surfactanttype materials or dispersants are similar to those relating to

Additional details in the form of case histories may be found in the T-8 Committee minutes for the past ten years and in the round table discussions on corrosion and fouling held by the National Petroleum Refiners' Association.! 2 Good summaries of plant experiences have been reported by Smith! 3 and Port.!4 Numerous additional case histories are available from service companies engaged in this field as well as from patent literature and other sources. Table 1 shows some results of pH control.! 4 Figure 1 shows fouling on a tube bundle.! 4 According to the T -8 report, principal uses of antifoulants are in hydrodesulfurizers (for naphthas, gas and lubricating oils), in naphtha reformers, in crude and catalytic cracking units. Other units include cokers, vis-

56

Selected List of Antifoulant Patents (Reference No. 9) U. S. Patent No.

breakers, alkylation units, ethylene units, deethanizers, solvent recovery units, etc. While fouled equipment consists primarily of heat exchangers, furnace tubes, piping and distillation towers also have been affected. Use of anti-

L. Chenicek G. E. KentNalco A. Gonzalez J. A. L. Pollitzer Nalco Co.Co. Godar R.L.Godar M. Colfer C. E. Johnson Universal Oil M. Miller etChemical Barnum etalCorp. al Lubrizol Betz Lab., Inc.Prod. R. B. Thompson Esso and Eng. Petrolite Patented by Res. Assigned to

foulants in gas compressors has also been mentioned by Moellerl5 et al in NACE Technical Group Committee T-8-1 (1968). The economic justification for using an antifoulant is usually based on how it increases on-stream time, improves heat transfer efficiency, reduces fuel costs, improves fluid throughputs and the like. Costs of cleaning, repairing and replacing fouled equipment are generally of secondary importance. 1 6 ,I 7 All direct and indirect costs must be balanced against the cost of the treatment program used for fouling prevention or alleviation. The economics are usually quite favorable. Smith described the use of an antifoulant in an ethylene unit depropanizer tower where the expenditure of $10,000 per year resulted in an annual saving of $150,000 from increased on-stream time and decreased maintenance. Nathanl 8 reported that the use of $44,000 of chemicals in a combination corrosion inhibitor and anti-

See also: NACE Standard RP-0l-70: Recommended Practices for the Protection of Austenitic Stainless Steels by Use of Neutralizing Solutions During Shutdown, NACE, Houston, Texas.

foulant treatment resulted in an increase of throughput equivalent to $351,000 additional revenue in a refinery catalytic hydrodesulfurizer unit. Other specific cases, sometimes with economic data, are given in the references cited above. The T-8 report lists chemical outlays of $0.28 to $37.50 per thousand barrels of fluid. In general, a payout of five to one can be considered as quite favorable when contemplating any type of ameliorative treatment. Table 2 presents some results reported after the use of antifoulants.

TABLE 1 - Bundle Life Comparisons of Distilling Unit at an Oil Refineryl4 densers Condensers Tops/Crude life, ConMonths Tops

48 No. 1140 40 115 28 37 48 Bundles Oper. High pH ~:rfM

Average Service

Evaluation of Antifoulants The two examples cited above illustrate magnitudes (which are by no means unusual) of losses caused by fouling and of costs for alleviation. Despite the effectiveness of antifoulants used in relatively small concentrations (5 to 20 ppm) and the modest unit cost of the chemicals, total costs can be appreciable because of the large volume of streams treated. It is desirable to optimize the cost versus

(I )Service life predicted on basis of four years of operation.

TABLE 2 - Effect on Corrosion in Using Antifoulantsl 21

No Change After Using Antifoulant Corrosion Increased After Using Antifoulant Corrosion Decreased After Using Antifoulant

I I

Method of Evaluating Corrosive Effect Corrosion

7

Probes

Visual Coupons Observation Calculated Corrosion Metallographic Radiography

2

16 Rates

8

Examination

2

After Antifoulant

None

4

4

Under Deposit Attack Pitting Stress Corrosion Cracking Furnace Tube Oxidation

8

8

13

13 2 1 2

By Antifoulant High Temperature Sulfur Corrosion

FIGURE 1 - Showing fouling of carbon steel heat exchanger bundle after operation at high pH.14

57

1 Before Antifoulant

Types of Corrosion

2

I

o

1

Porous Metal Filter

effectiveness of the treatment by selecting the additive(s) best for the specific application under consideration. Because of the wide diversity of refinery and various petrochemical streams, no single approach or chemical may be expected to be a universal solution to all fouling problems. Due to the cost as well as time involved in testing antifoulants in plant applications, considerable effort has been made by several refiners and service companies to develop laboratory test methods to determine the fouling potential of process streams and evaluate the effects of alternative additives and treatment levels. These laboratory tests are always of relatively short duration-from several minutes to several days-and require intensification of the causative factors to increase fouling rates and thus provide measurable changes in the system parameters during the test times which are short relative to the weeks or months

Rotameter 5 Micron /Prefilter

~

~/

Sample Flow Control Valve --. ~ubular Preheater

~~

) Receiver

& Scale

of actual field fouling problems. Temperatures may be higher, contact times longer, or contaminant levels greater (as by blowing air into the test fluids). Because of the more severe conditions of the tests, additive levels are usually higher than under plant conditions. Several screening tests described below illustrate these concepts. It is more important to remember that these tests are for screening rather than for prediction of additive performance under actual field conditions which may be very much different from the test conditions. Accordingly, the screening test· should be used only to obtain preliminary information on materials which appear promising on a cost-performance basis. Promising materials should then be evaluated in the field for optimization of the antifoulant treatment.

FIGURE frequently apparatus increases filter.11

2 - Schematic diagram of Erdco coker used to evaluate the coking tendencies of jet fuels. The can be modified to evaluate antifoulants from in the pressure drop across the heated porous

Waste Feed

Erdco CFR Coker Frazier19 et al described a modification of the Erdco jet fuel testing procedure (ASTM D-1660). In this unit, the test fuel is pumped at a controlled rate over a heated surface (400 F) which is designed to simulate feed preheat exchanger conditions. Decomposition of materials in the process stream on the hot surface causes deposition of polymers and coke, some of which adhere to the surface. However, some decomposition products also are carried in suspension by the fluid stream. The stream is then pumped through a metal filter having 2011 pores. These capture much of the suspended matter from the stream. Because suspended matter plugs the filter, the pressure across the filter rises exponentially with time. The slope of log pressure drop versus time is used as a measure of the fouling index which the authors have correlated with plant fouling conditions for both treated and untreated conditions. In ASTM D-1660, the physical appearance of the heat transfer surface, i.e., blackening and coking, is expressed in a quantitative manner to correlate with fouling tendencies of heated jet fuels, etc. Figure 2 shows a schematic of the Erdco coker.

Cooler

N

FIGURE 3 - Liquid-vapor phase fouling apparatus to select antifoulants, based on comparisons of the annular heater tube's condition after a specified test period.11

Jet Fuel Thermal Oxidation Tester (JFTOT) developed by a San Antonio, Texas firm. The device operates on the same principles as the Erdco coker developed in 1965 by Amoco and according to the Erdco Aviation Fuel Testing Procedure (ASTM D-1660). One of the main advantages of the JFTOT tester is that it uses only one quart of fuel. The device was developed after a 3-year competitive program. Because JFTOT and Erdco produce much the same sort of data, data from JFTOT can be posted on Erdco data sheets. Enjay's experience with the device is reported by Gillespie.20 In equipment described by Gonzalez, fluids flow inside

JFTOT Device Developed Better correlation between test results and refinery experience with antifoulants is claimed with data from the

58

flows and decreases heat transfer rates, but increases pressure drops and heating (or cooling) demands, all of these or the rates of their changes in the treated and untreated systems may be used as indications of the effectiveness of the treatment. However, it should be noted that many of these parameters also can be changed by process variations independent of fouling, e.g., changes in charge rates, cracking severities, feed stocks, etc. Accordingly, tests which are carried out for extended times require careful control and data interpretation if meaningful conclusions are to be developed. Other methods of rapid evaluation in laboratory and/or field are proposed from time to time. because of the need for a guide and accurate screening method for antifoulants. These methods should be considered as to their ability to measure true fouling rates or fouling potentials or some other physical or chemical property purported to be related to the desired property. When extrapolating the test conditions to the field conditions, it should be remembered that the dangers in such extrapolations increase as the conditions between actual and test conditions diverge. A summary of present day laboratory and field methods of evaluating antifoulants was presented during a round table discussion in a September, 1971 meeting of NACE T-8 (Refinery Corrosion) Committee in Chicago. An additional concept in the evaluation of antifoulants by laboratory screening devices has been pointed out by Nathan and Dulaney in the reference cited previously as well as in other articles relating to the problems of determining cost-effectiveness relations in surfactant applications. This concept considers the wide fluctuations in reproducibility of test data obtained at intermediate efficiency values of additive applications. At low efficiencies, such as those obtained at low treatment levels, or at high efficiencies, such as those obtained at high treatment levels, replicate tests have good reproducibility.

a tube which is weighed before and after the test to determine the amount of deposit in the presence and absence of various antifoulants being tested. An efficiency factor is calculated based on the relative reduction of the treated and untreated systems. Inlet and outlet fluid temperatures, as well as tube skin temperatures, are determined and the variation of overall heat transfer of "U" coefficient is calculated as a function of time. Relative merits of treatments are based on the rates of "U" drop under varying treatments. Plots of treatment efficiency versus treatment level usually give typical Langmuir adsorption isotherms, similar to those obtained with surfactanttype corrosion inhibitors. Figure 3 is a schematic of a test device using a comparison of a heated tube's condition before and after a test run. There are numerous variations on the above methods. The "hot wire" is a fairly simple and inexpensive test which employs heating of the test fluid by contact with a hot nichrome wire.21 The wire is heated by a current (about 5 to 10 amperes) sufficient to elevate the temperature to incipient redness. As the fluid decomposes on the hot metal surface, fouling may be observed by 1. An increase in the apparent diameter of the wire as coke covers the wire; 2. Discoloration of the liquids; 3. Changes in the current through the wire brought about by reduction of the wire's thermal and electrical conductivi ty . Normally, several determinations are carried out simultaneously with the test wires in series electrical connection. Thus, the treated and untreated systems can be compared visually and followed with time. Figure 4 shows some of the results of a series of hot wire tests. Field methods used to follow the course of fouling and its reduction by various treatments are based on changes in operating parameters. Because fouling usually reduces fluid

FIGURE 4 - Test solutions influenced by hot wire tests of antifoulants

S9

(Betz Laboratories).

However, poor reproducibility at intermediate concentrations and efficiencies limits the ability to differentiate between the cost-effectiveness of alternative additives.

12.

Similar difficulties have been reported with respect to the evaluation of corrosion inhibitors in refinery processes and other applications22 and in testing the effect of surfactants employed as corrosion inhibitors and/or antifoulants on the water tolerance of jet fuels (WSIM Test). The limitations of screening tests emphasize the inadvisability of undue reliance on them and the need for following such tests with careful plant studies to obtain reliable technical and economic data on antifoulant applications.

13. 14.

15.

References 16.

1. J. 1. Bregman. Corrosion Inhibitors, p. 257, The MacMillan Co., New York (1963). 2. B. W. Weinland, R. M. Miller, and A. J. Freedman. Reduce Refinery Fouling, Materials Protection, 6, 41-43 (1967) February. 3. J. A. Biehl and E. A. Schnake. What Ohio Oil Learned in 5 Years of Procession Crude Oil at Low pH, Oil and Gas J., 57, No. 23, 125 (1959). 4. W. F. Taylor and T. J. Wallace. Kinetics of Deposit Formation from Hydrocarbons, I & E.C. Prod. Res. Dev., 6, No. 4, 258 (1967) December and 7, No. 3, 198 (1968) September. 5. A. Gonzalez, D. 1. Hagney, and N. E. Sumner. The Evaluation and Application of Metal Coordinating Antifoulants, NACE South Central Region Conference, New Orleans, La., October 18-21,1965. 6. A. C. Nixon and H. B. Minor. Effect of Additives on Jet Fuel Stability and Filterability, Ind. and Eng. Chem., 48, 1909 (1956) October. 7. L. R. Mahoney. Antioxidants, Angew Chem. International Edition. 8, No. 8,547 ff (1969). 8. J. P. Luvisi and J. A. Chenicek. U. S. Patent No. 3,023,161. 9. See list hereunder. 10. C. C. Nathan and C. L. Dulaney. Statistical Concepts in Testing of Dispersants, I. & E.C. Prod. Res. and Dev. (1970) December. 11. A. S. Couper and F. B. Hamel. Process Side Antifoulants in

17. 18.

19.

20.

21. 22.

23.

60

Petroleum Refineries, Report of Work Group T-8-2a, Materials Protection, 9, 29-33 (1970) June. Oil and GasJ., 118 ff (1961) April 17; 115 ff (1967) March 13; 114 ff (1968) March 25; 77 ff (1969) February 17; 115 ff (1969) March 3; 69 ff (1970) February 16; 74 ff (1970) April 13; 67 ff (1970) March 9; 202 ff (1970) March 16. D. M. Smith. Antifouling Agents in Refinery Equipment, Materials Protection,S, 51-52 (1966) June. G. R. Port. Antifoulants and Inhibitors Reduce Fouling and Corrosion of Refinery Equipment, Materials Protection, 7, 29-32 (1968) September. See also: G. R. Port. Mitigation of Fouling and Corrosion in Refinery Processes Utilizing Antifoulants and Inhibition, Proc. NACE 24th Cont., pp. 653-659, National Association of Corrosion Engineers, Houston, Texas. Corrosion, Metallurgical and Mechanical Experiences of Petroleum Refinery Compressors. Interim Report of NACE Technical Group T-8-1, Proc. NACE 24th Cont., pp. 660-673, National Association of Corrosion Engineers, Houston, Texas. W. F. McFatter. Reliability Experiences in a Large Refmery, Chem. Eng. Prog., 68,52 (1972). K. E. Coulter and V. S. Morello. Improving Onstream Time in Process Plants, Chem. Eng. Prog., 68,56 (1962). C. C. Nathan. Use of Chemicals for Solution of Refmery Corrosion and Related Problems, Materials Protection, 9,15-18 (1970) November. A. W. Frazier, J. G. Huddle, and W. R. Power. New Fast Approach to Reduced Preheat Exchanger Fouling, Oil and Gas J., 117, (1965) May 3. B. G. Gillespie. A New Process AntifouIant Test Correlates Better with Refinery Experience, Paper 40, NACE 27th Conference, March, 1971. Sce also Mat. Pro. & Pert., 10, No. 8, 21-25 (1971) Aug. Anon. Simple Device Tests for Foulants, Oil and Gas J., 96 (1969) February 3. C. C. Nathan and C. L. Dulaney. How Statistical Concepts Facilitate Evaluation of Corrosion Inhibitors, Materials Protection, 10,21-25 (1971) February. C. C. Nathan and C. L. Dulaney. Statistical Aspects of Surfactant Evaluation Applied to Water Tolerance of Jet Fuels, AIChE 68th National Meeting and 6th Petroleum Conference, Houston, Texas, February 28-March 4, 1971. See also Water Separometer Test Is Tricky. Hydro. Proc., SO, No. 8, 129, (1971) Aug.

Corrosion Inhibitors in Petroleum Production Primary Recovery

AL NESTLE*

The discovery of the inhibitive properties of long chain, high molecular weight polar materials about 25 years ago dramatically altered the pattern of inhibition practices on primary production oilwells and gas wells. It permitted long term operation of wells which otherwise might not have been economical to keep in production. The inhibitors also helped to increase the percentage of the total fluids that could be taken from reservoirs.

acetic or other to a greater complicate the which they are

short-chain aliphatic acids may be produced or lesser extent. These gases and acids problem of inhibiting corrosion of wells in present.

Furthermore, because corrosivity frequently is proportional to the ratio of produced water to hydrocarbons, the volume and composition of produced water influence the performance of inhibitors. Another major influence is the production mode of the well, that is, whether it is flowing, pumped or produced by gas lift.

During the past decade, the principal improvements in inhibition practices have been in the refinement of formulations and the development of better ways to apply inhibitors and to evaluate their performance during use. A large share of the attention given to inhibitors used for primary production has been to determine with greater precision their probable effects when used in wells. The economics of inhibition have been materially improved by new methods of application. Benefits achieved have been especially important to the industry because of the increased costs of producing from offshore zones and the deeper drilling required to get production. Ecological considerations have emphasized the importance of maintaining the integrity of production equipment, especially that located in coastal waters and rivers.

Influence of Well Depth, Completion Method As well depth increases, bottom hole temperature rises. For this reason it has been necessary to develop inhibitors that will function at higher temperatures than were prevalent a decade ago. Other aspects of the cost of drilling, such as the technique of producing from more than one stratum in one casing also influence inhibitor practices. High labor and equipment costs offshore introduce a factor of economic risk in the application of inhibitors, making the effect of failure more important than heretofore. This had made it necessary to carefully screen inhibitors for anticipated performance and to select application methods with care. Increasing the duration of inhibition is important so that intervals between treatments can be lengthened.

Characteristics of Oil and Gas Wells While there are many other ways to categorize oil and gas wells, this chapter considers them in the following broad categories: 1. Oil-that is, producing mainly liquid hydrocarbons. 2. Gas-that is, producing mainly gaseous hydrocarbons.

Economics of Inhibition The economics of inhibition as discussed in J. I. Bregman's book1 are probably more favorable now than they were a decade ago when he said that inhibitors showed a 7 to I payout in oil wells and better than 4 to 1 in highly corrosive condensate wells, in spite of the increased cost of labor, equipment and taxes. The cost of inhibitors has not shown a marked increase.

3. Condensate-that is, producing significant quantities of liquid hydrocarbons along with gas at high pressures and temperatures. Each of these may be divided into "sweet" or "sour", designations which are a function of the amount of hydrogen sulfide produced. Because there is no unqualified dividing line between sweet and sour with respect to the quantity of hydrogen sulfide produced, there are some wells that may be classified in either category. lt is usually accepted that even a trace of hydrogen sulfide may be sufficien t to categorize a well as "sour". Other gases, including carbon dioxide, and formic,

An estimate by Phenicie2 of petroleum production corrosion costs in 1966 indicated that the oil industry in the United States spent 16 cents per barrel of produced crude for corrosion losses and control measures or about $450 millions a year. About $25 millions annually was spent for corrosion control chemicals. He estimated that $10 millions of the estimated $12 millions cost of condensate well corrosion (1951) could have been saved by proper corrosion control measures. There is reason to believe savings would be greater today than they were then.

*Houston, Tx. Formerly Corrosion Technologist, Production Chemistry Group, Texaco Research Laboratories, Houston, Tx.

61

and pressure are two significant possibilities. Pressures in wells may exceed 12,000 psi6 and temperatures may be over 400 F (200 C). Many corrosion inhibitors lose effectiveness at high temperatures.

Well pulling jobs of Huntington Beach, Ca!. wells were reduced from an average of 5.7 per well per year to 1.6 by an effective inhibitor, program.(1) Cost of the chemical control program was only 5 percent of subsurface maintenance costs for·these wells. Numerous other instances of substantial savings have been repeatedly reported in technical journals. Data on possible savingsin producing operations were given in a survey published by Robinson and Waldrip.3 The ratio of savingsfrom corrosion control varied from less than 4 to over 8 to one, both substantial benefits, although profit calculations may have been partial or incomplete in most of the cases reported. Continuing work by NACE T-IH Unit Committee on Economics of Corrosion Control resulted in an article titled "Economics of Petroleum Production," by Park and Roberson.4 The article covers the application of "time value of money" and "federal, state and local income taxes," to expenditures or income and makes it easier to compare cash outlays to extended payments. This material is scheduled to be used in forthcoming edition of a book on oil and gas well corrosion. To assist in the economic appraisal of corrosion control measures, NACE has published its Standard RP-02-72: Recommended Practice-Direct Calculation of Economic Appraisalsof Corrosion Control Measures.

Cyclic Loading, Stress, Wear

Corrosion inhibitors especially suited to control corrosion accelerated by stress, cyclic loading or hydrogen embrittlement have been reported in the literature by Chittum,7 Bates,8 Hudgins,9 and Patton.1 0 Control requires preliminary investigations of candidate materials in test simulating the environment created by the accelerants. The extra expense usually is more than repaid by the resulting safe operating conditions. Wear occurs in pumping wells and others in which conditions are conductive to rubbing contacts. These can occur at many places in the long "strings" which sometimes go down over 4 miles. Few wells are vertical throughout. Pumping rods moving vertically as many as 60 strokes a minute have sliding contacts at many places. Couplings that join the 25-foot segments rub against the tubing, so, if corrosion inhibitors are not also superior lubricants, metal loss can be seriOUs.Also, tubing strings in pumping wells often slide against the outer casing or other structures (for example, packers).ll Figure 1 illustrates the consequences of poor practices in a pumping well and benefits of good inhibition.

Factors Influencing Corrosivity of Produced Fluids

Ero~on,Abraswn,cavftanon

"Sand control" measures are designed to prevent f'me solids from being produced with the hydrocarbons and water. These measures reduce the harmful effect of these particles on moving parts. Cavitation effects may occur on the trailing surfaces of rapidly moving parts as the result of the formation and collapse of vacuum bubbles in the liquid at the metal-liquid interface. Inhibitors sometimes nelp reduce cavitation attack. Recommenaations are often made that corrosion control measures be used on all wells beginning with their initial production because it is more economical to treat initially and continue treating than to monitor and delay corrosion control until the need is positively demonstrated. Frequently, delay causes expensive failures which could have been prevented. These usually are followed by additional failures, no matter how effective the control measures initiated.

Characteristics of Fluids

Produced fluids vary from non-corrosive liquid or gaseous hydrocarbons to severely corrosive waters and brines. Produced mixtures of gas, liquid or solid hydrocarbons and waters also vary from non-corrosive to severely corrosive, not necessarily in proportion to the water fraction, which may vary from less than one to over 99 percent. Methods of monitoring the severity of corrosion are covered elsewhere in this book. Predictive methods based on information from produced fluids, samples, well tests, experience with similar wells are readily available in the literature. Some of the principles governing the corrosivity of produced fluids are discussed below. Temperature, Pressure Velocity

The effect of temperature on corrosion of petroleum production equipment is similar to its effect on other chemical reactions. Because rates of many corrosion reactions increase with temperature, doubling with each rise of 20 F (11 C), temperature effects should be taken into account.5 Secondary pressure effects may have more influence on corrosion reactions than primary effects of pressure or reaction rates. Acid gas solubility changeswith temperature

Determining Well Fluid Co"osivity

"It has been found that wells often become corrosion problems when total water cut passes 85 percent, although there seem to be occasional exceptions. Amount of emulsion carried in the well fluids will affect the fluid's resistivity and thereby the effectiveness of fluids as an electrolyte. In general, therefore, wells producing large volumes o~ water with little emulsion should be relatively more corrosive than lower-cut wells with emulsion pres· ent."12 Early studies made by the National Association of Corrosion Engineers and Natural Gas Producer's Associ-

(I)H. 1. Kipps. The Practice of Corrosion Control in a California Oil Field-Four Case Histories. Proc. 1971Western States Corrosion Seminar. NACE, Houston, Tx. (1972).

62

weight fatty acids. This situation results in an aggressive acid attack which may include severe pitting." The relationship of pressure and corrosion in gas condensate wells has been described in the NGPA condensate well corrosion book! 4 as follows: 1. A partial pressure of carbon dioxide in the gas above 30 psi usually indicates corrosion. 2. A partial pressure of carbon diodide between 7 and 30 psi may indicate corrosion. 3. A partial pressure of carbon dioxide below 7 psi is considered non-corrosive. This breakdown is widely accepted and is the only statement of its kind in the literature on corrosion. An examination by Shock and Sudbury!5 of the relative influence of carbon dioxide and the fatty acids on corrosion of gas condensate wells showed that carbon dioxide was the primary causative agent. Organic acids cause general, rather than a pitting type corrosion associated with carbon dioxide. The corrosion rate of steel due to organic acids decreases with time; the reaction is self· stifling. Fatty acids cause carbon dioxide attack to occur at lower concentrations than would be the case otherwise. Results of additional work on predicting corrosion are summed up as follows by Farrar!6: "Approximately 30 percent of the country's low-pressure, sweet-oil wells are "economically affected" (annual corrosion cost $200 or more) by water-dependent corrosion. The annual cost of corrosion is $960 per well, even with remedial measures. The average low-pressure well experiences 11 years of relatively trouble free operation before corrosion sets in. After corrosion starts, tubing life is reduced to an average of 3 years and may be as low as 6 months. The average low pressure corrosive well is produced from a depth of 5050 feet, with average bottom hole pressure of 2275 psi. Average bottom hole temperature is 160 F (70 C). Previous papers have summarized water-independent corrosion which occurs at high pressures, usually from the beginning of the well's production history.! 7-20 Relationship to water production ... only a small proportion of low-pressure wells producing less than 40 bbl of water a day are corrosive, while 75 percent of those making greater than 100 bbljday are corrosive. However, there is no direct relationship between volume of water produced and corrosion. "Wells making large amounts of water usually have high lifting costs and the added burden of corrosion expenditure can result in operation at a loss. Water-oil ratio has a primary influence on whether a given well in a corrosionsusceptible field is corrosive. Figures on a number of corrosive fields show: 0 to 20% water- 0% of wells corrosive; 20 to 40% water-O% of wells corrosive; 40 to 60% water-74% of wells corrosive; 60 to 80% water-I 00% corrosive and 80 to ] 00% water-l 00% corrosive."! 6 Similar information came from GreenweIl2!: "The

FIGURE 1 - (Top) Polished rod couplings after several months' service in a crooked holed well producing severely corrosive fluids shows the advantage of inhibitor treatment which reduced corrosion and wear. (Bottom) Corroded couplings from a well exposed to severely corrosive well fluids without proper inhibition. (Bottom: Figure 1 "Corrosion Control in the EastTexas Field. B. W. Cato. Mat. Pro., 1, No. 5, 58-67 (1962) May).

ation committees corrosion:

resulted

in designating

two types of

1. "Water-independent" corrosion that occurs in sweet or sour oil and gas wells when as low as 0.1 percent water is produced. Corrosion activity (severe) begins at initial water production in this class of well. 2. "Water-dependent" corrosion develops in oil and gas wells that produce high percentages of brine. Corrosion activity may not begin in this class of well until after several years of production.! 3 Bregman! summed up prediction of corrosivity in these wells: "Gas condensate wells are a major corrosion problem. These wells have high gas-to-oil ratios under very high pressure. The condensation of large volumes of hydrocarbons is accompanied by the formation of a small amount of water which contains carbon dioxide and low molecular

ratio of water in the produced fluids may vary from less than 1 to over 99 percent water. Corrosion in oil wells generally increases (with the water cut) according to field experience." Low pressure oil wells producing gas contain-

63

ing carbon dioxide were "corrosive" according to the percentage of water produced. The water is usually brine from less than 1% to over 10% sodium chloride. It is believed that characteristics of produced fluids affect corrosivity. However, estimates of the percentage of sour wells producing corrosive fluids varied widely and sour production was not necessarily corrosive in all cases. An NACE committee in 1952 surveyed over 8000 sour oil wells and found 44 percent to be economically affected by corrosion.22 This percentage undoubtedly has increased because of the growing use of secondary recovery methods. Bass23 said in an article that corrosion inhibitors were needed in 80 percent of all crude producing wells. Sour fluids may cause more severe corrosion than sweet, but there are exceptions. Organic inhibitors suitable for good continuous treating and good persistent filming appear to work better with sour fluids than with sweet. While percent protection obtained by these effective materials is higher in sour environments, this is due usually to the greater unprotected corrosion rates common in sour environments. Nevertheless, absolute corrosion rates with good inhibitors are as low as or lower in sour environments than they are in sweet environments. Some of the bad reputation sour fluids have for severe corrosion is justified because, without protection, more severe types of corrosion of the harder steels are possible in them. Accelerated and localized corrosion which occurs also in sweet fluids and especially in improperly or imperfectly inhibited sweet fluids, can be more severe than in similarly handled sour fluids. Sour fluids may cause hydrogen blistering and stress corrosion cracking but may or may not be worse than sweet fluids in causing accelerated wear or corrosion fatigue. An analysis of the facts might show that corrosion by sour fluids is not necessarily more difficult to control than is corrosion by sweet fluids. 2 4,25 Regardless of the merits of the various means to predict corrosivity, it is perhaps safer to agree with the following: "1t is good insurance to assume that corrosion conditions will exist ... and act to control them effectively by one or more of the excellent corrosion control methods available as applicable to the assumed corrosion conditions." Reference 6).

(page 3,

Hydrogen Sulfide Attack The solution of hydrogen sulfide stress corrosion cracking is mainly in metallurgy. Experimen tal and practical evidence shows that the tendency of steels to stress corrosion crack under the influence of hydrogen sulfide is related to alloying elements in the steel and to phase structures and hardness. The most recent guidance on the selection of materials for sour service is contained in NACE Publication 1 F 166 (1973 Revision): Sulfide Cracking Resistant Metallic Materials for Valves for Production and

FIGURE 2 - Typical electron micrographs of 4340 steel showing results of heat treatment to reduce stress cracking susceptible martensite. A = Treated 1 hr at 1400 F (760 Cl; B = Treeted 1 hr at 1400 F plus tempered at 1200 F (649 Cl. E. Snape. F. W. Schaller. R. M. Forbes-Jones. A Method of Improving Sulfide Cracking Resistance of Low Alloy Steels, Proc. NACE 25th Conf., NACE Houston, Tx. p116.

Pipeline Service. This is a report of NACE Unit Committee T-l F on Metallurgy of Oil Field Equipment. Inhibition has a secondary role in reducing the amount of corrosion and thereby reducing the quantity of hydrogen produced at the electrolyte-metal interface. This

64

hydrogen is usually assigned a major role in stress corrosion cracking due to hydrogen sulfide attack. Figure 2 shows the results of heat treatment of high strength steel to reduce marten site content. Martensite content is believed to be a factor in hydrogen sulfide attack. This is only one of the ways that metals can be adapted to corrosive oil well environments.

Methods of Inhibitor Application Continuous Treatment In the continuous treatment mode, inhibitors are applied in oil wells in the same way that demulsifiers are, by a chemical proportioning pump or by frequent batching. When continuous treatment is practiced, adsorption of the inhibitor is slow and desorption rapid whenever concentration in the well fluids drops to a level inadequate for protection. Treatment often is begun at high concentrations to produced a fast initial film. Continued treatment at high concentrations, however, may not improve results and may even reduce protection. Maintaining excessive protection may be prohibitively expensive. Protection obtained using continuous treatment may be over 95 percent and may reduce uniform corrosion rates to less than 1 mil a year. An inadequate inhibitor or insufficient concentration may increase average corrosion rates or change uniform corrosion to a pitting type. Inhibitors must mix or dissolve in well fluids, stay within defmite concentration limits and try to contact all metal surfaces to be protected.2 6 ,2 7 . Treatment levels usually vary from less than 25 to over 100 parts per million (0.0025 to 0.01 percent) based on the fluids carrying the treatment. At these low levels, solubility, dispersability or miscibility may be obtained easily. It is essential to check zones where stream velocity is low to be sure that concentrations of inhibitor in these

FIGURE 3 - Droplets of encapsulated amine inhibitor designed to be introduced into oil wells. The large black dot is an agglomeration of several capsules. X625. J. E. Haughn and B. Mosier. Micro-Encapsulation-A Method of Long Term Inhibition for Oil Wells. Mat. Pro., 3, No. 5, 42-50 (1964) May.

Essentially all the metal to be protected must be contacted. The inhibitor preferably should be a fast-filmer and be insoluble both in any diluent used to aid in injecting the mixture and also in produced fluids. Neither the treating mix nor the well fluids should dissolve the film. Retreat-

zones are sufficient to give adequate protection. Droplets of inhibitor in the 30 to 40 micron range as shown in Figure 3 have been prepared using weighted amines encapsulated in a water-soluble sheath. Their small size permits them to move freely through the producing system and their weight causes them to drop through the fluids to low levels. When the capsule is dissolved, the inhibitor is released into the fluids. Two tests with this material showed satisfactory results.

ment must be done at sufficiently frequent intervals to avoid overextended intervals between treatings. The penalty for delay may be accelerated and/or pitting corrosion.2 8 Economical use of inhibitors to produce longlasting and highly protective films depends upon infrequent batch treating, supplemented by interim applications to repair the film or protect untreated metal inserted into the system. Most corrosive wells are amenable to a regime based on early initial application, preferably long before critical need is manifest. Interim applications should follow at conservatively spaced intervals. Regular treating intervals under optimum conditions range from 3 to 6 and even as much as 12 months in some cases, not necessarily on low corrosivity systems. Application methods include all means of coating the metal to be protected. Concentrations range from undiluted to less than 0.2 volume percent dispersed into diluen ts. Contact with the metal may be assisted by pipeline scrapers, pigs or other devices.

Intermittent Treating Intermittent treating achieves persistent filming by infrequent batching of large quantities of inhibitor. Smaller quantities of chemicals may be used overall than in continuous treatment. More economical and better protection often is possible with intermittent treating than with continuous treating. The inhibitor may be used undiluted, as a uniform special mix with diluents or mixed with a portion of the well fluids. Treating mixes should quickly form protective and persistent films. Protection achieved may exceed 99 percent with uniform corrosion rates of less than 0.1 mil per year.

Weighting agents are used to get the inhibitor down to 65

the bottom of the well. Riggs and Shock29 describe a corrosion inhibitor heavy enough to sink through the liquid column in an oil well. The formulation consists of an

The economic hazard is considerable because costs are high and the operator runs the risk of losing a great deal of money at one time if something goes wrong or if bad weather causes operations to be delayed. The major concern is probably the possibility of the development of emulsion blocks or reverse-wetting in the formation which would reduce well production rates. This problem has not been as formidable as first anticipated, although "tight" formations are still considered risky. 33 The plugging effect of inhibitors on cores has been studied in the laboratory by Kerver and Morgan.3 5,36 Squeeze treatments often can be completed in a relatively short time. For example, 2 to 4 hours may be sufficient to treat a 10,000-ft gas condensate well at 5000 psi.34 Squeeze treatments usually can be repeated indefinitely and the consensus is that the second and succeeding treatments have longer lives than the first, 3 7 possibly because some of the chemical used in the first squeeze is trapped in the formation and cannot return to the well bore.

oil-soluble inhibitor, an immiscibilizing agent and a mutual solvent. The mixture has a specific gravity of 1.1 (9.2 Ib/gal ('" 1100 g/1). A typical example consists of a dimeric acid (polymerized linoleic acid), polyethoxylated sorbitan mono oleate and C6H4 Ch. These materials are now made without chlorinated hydrocarbons and use either inorganic or organic weighting agents to give densities of over 14 Ib/gal (1680 g/l). They are described in detail as to applications, fall rates and other attributes by Bundrant,30 Michnick, Annand and Farquhar31 and Patton, Deemer and Hilliard.32 It is evident that a great deal of trouble is taken to make certain that the inhibitor is available at needed locations. Dramatic results are obtained using stick-type inhibitors in wells not previously susceptible to protection by liquid inhibitors. Substitution of the same inhibitor in stick form often results in a sharp reduction of a well's corrosion rate and a considerable savings in maintenance costs.

During the treating process, some of the inhibitor can be squeezed into or adsorbed into low-permeability pores and fractures from which the fluid does not pass while the well is working. These pores are saturated during the first treatment. The initial treatment also can alter the wettabil-

Even weighted inhibitor sticks do not always reach bottom, so some operators have pushed them down with wire line tools. Others are trying bottom-hole injection, but, because of gelling of diluents in wells with high bottom hole temperatures, problems are being encountered.

ity of the formation to enhance adsorption on subsequent treatments. Poetker and Stone38 describe how treating costs in the Placedo Field in Victoria County, Texas were cut about 50 percent and treating efficiency increased about 17 percent. Squeeze treating was first tried in the mid fifties and rapidly gained widespread acceptance.3 9-4 5 Many inhibitors, undiluted or diluted with crude or rermed oils, lease condensate, produced brine or fresh water were pumped into wells. Difficulties encountered can be considered due

Squeeze Treating Techniques Squeeze treating is applicable to any well with sufficiently porous strata. It will result in essentially continuous treatment as inhibitor is slowly released with produced fluids from the strata. True intermittent treating can be achieved by using persistent ftlming inhibitors to ftlm the metal as they go toward or are removed from the porous strata. Film repair may be accomplished subsequently by a short-time application of high concentrations. Inhibitor return from porous strata probably does not occur at a uniform rate.

either to side effects or excess well pressures that prevented squeezing all of the desired volume into the formation. Success was reported and long-time, good corrosion control was achieved in most cases when the inhibitor was forced successfully into the formation.

In this widely favored technique, a drum (50 to 55 gal. 189 to 2661) or more of inhibitor is injected under pressure into the producing formation so that the chemical will penetrate and be adsorbed on the strata and then gradually desorb as fluids are produced. This procedure often leads to continuous feedbacks lasting anywhere from three months to a year. An "over flush" of oil or brine consisting of a few to more than 350 barrels is used to push the inhibitor further into the formation. 33,34 A primary advantage of this method is that it successfully treats many wells which are packed off or have high fluid levels are are therefore difficult to treat by other methods. In addition, treatment frequency is drastically reduced and a steady supply of inhibitor assured over a long time. The technique requires less manpower and is more reliable than other methods. The entire length of tubing is treated; treating and shut-in time are reduced and wear and tear on equipment minimized. These advantages are especially important in off· shore wells.34 The method is not without disadvantages, however.

Tubing Displacement Results Sometimes a squeeze treatment was successful when none of the inhibitor was forced into the formation. This "non-squeeze" variation came to be known as "tubing displacement." Based on later experience, it was claimed that success from tubing displacements resulted because the inhibitor ftlmed the metal sufficiently to give lasting protection. It is obviously impossible to obtain protection equivalent to continuous treatment from this procedure unless a tight persistent, protective film is formed on the metal surfaces of the well. This mm had to withstand the effects of flow, abrasion. contaminants and the corrosive environment for the times reported. which often approached those obtained from total squeezes. Kerver and Morgan35 ,36 showed that some formations resisted the flow of some types of squeeze mixtures. They also studied cores and found that adsorption characteristics 66

Importance of Inhibitor Properties When Treating Gas Wells

of various sandstones differed and that the adsorption characteristics of limestones differed markedly from those of sandstones. Their work was extended and reported later by Kerver and Hanson.46 Field studies with tracers were reported by Raifsnider, et al.47 Squeeze treatments have been successful with all kinds of wells. Pumping wells have been squeezed by injecting the inhibitor down the tubing after unseating the pump to permit fluids to pass the valves in the pump. Pumping wells also have been treated by injecting the inhibitor down the tubing-casing annulus. When using the latter method, a greater volume of fluid is required and the inside of tubing, rods and pump parts do not receive treatment initially but are filmed later by the inhibitor when it retums mixed with the production. Treatment durations effective for nine months have been reported.4 7

Information that should influence the choice between a heavy liquid inhibitor or an inhibitor-diluent mixture when treating gas wells is presented by Michnick, Annand and Farquhar,31 in "Batch Treatment of Gas Wells With Corrosion Inhibitors: Tracer Experiments." Some of their data should be helpful also in estimating treating considerations involved in controlling corrosion in other types of wells. Data in Table I on the fall rates of inhibitors in six wells can be used as a guide in selecting inhibitor type. Figure 4, from the same source, shows distribution of inhibitor on tubing walls and the effect of time and resumption of flow reflected by measurements of gamma rays from an isotope-tagged inhibitor. These data can be used as a guide to treatment selection.

Treatment of Pumping Wells Other treatments producing effects similar to the squeeze have been applied to pumping wells. They often require small volumes of fluid and less equipment than do squeeze treatments. They do not call for unseating the pump and are called by various terms including "slug, circulate and park." The procedure calls for an appropriate volume of chemical to be injected into the tubing-casing annulus instead of into the flowline. This causes the

o

2

3

-5 '"

Lf6 '0

b oo c:

8

0.9 '"

o

10

ments are described by Fincher44 and in a report by Park and Riley.47 Another method of treating pumping wells accomplishes approximately the same results as the slug-circulatepark treatment if the well has a high fluid level in the tubing-casing annulus. Called the "extended period batch treatment," it introduces or circulates a large inhibitor volume down the annulus at fixed intervals.

11 •..•._ •.•...• ~

_

02468

02468 Film Thickness

o

2

Jr., Oil Well Liquid

4

in Mils

FIGURE 4 - Gamma logs showing distribution of inhibitor on tubing wall. Log 1 - 5 hr after start of injection. Log 2 2-21 hr after injection, well shut in. Log 3 - 26 hr after injection, well flowing for 4 hr at 30 million cubic feet a day.31

1 - Fall Rate of Corrosion Inhibitors in Gas Wells31

(I )Five gal lease condensate and 8 gal water. D. A. Deemer, and H. M. Hilliard,

(2)C. C. Patton,

7

.c

repairing and refilrning, similar to the manner in which the squeeze treatment functions with its stored-in-theformation excess. Good results attained with these treat-

HeavyTABLE

LOG 3

4

chemical to be forced down the annulus into the pump inlet and up the tubing. When the residue reaches the surface, it is "parked" in the annulus and then the production is returned to the flow line. The residue reaches the surface as a high concentration band or slug in well fluids. Residual material is used to continue treatment by constant concentration simulation or intermittent film

Inhibitor Feet 378 0Type Diluent Fall Rate inOD Gallons Gallons 53 Normal 55 10 13(1 13 Inhibitor 0.5 1.1 27.5 27.5 35 265 1300 1100 265 105 600 2000 2900 23/8 23/8 4.3 3000 1.2 31/2 cps gpm 9,700 Viscosity Pumping fph) 11,600 H eavy 10,000 10,500 Heavy Tubing 30.5 10,000

LOG 1

Inhibitor

67

Effectiveness,

Materials Protection, 9, 37-41 (1970)

February.

mixture can be made compatible without harmful side effects.

It may be better from the standpoint of improving results and minimizing shutin time to use low viscosity inhibitor mixtures that have greater volume but do not necessarily cost more than heavy liquid inhibitors for treating gas wells that empty on shutin. Similar treatments might be used on other wells also except those which can be killed when excess amounts of fluid are injected into the tubing.

Heavy liquid inhibitors are used in treating pumping wells. Their non-miscibility with hydrocarbons enables them to fall more easily through static columns of hydrocarbons than most treating mixes. Less fluid volume per injection is required. Continuous treating can be effected by using frequent, small-volume batch additions. True intermittent treating using persistent fIlming requires larger volumes and reduced frequency. Additional information is in Bundrant's excellent article.3o Table 2 shows some of the results achieved in four fields.

Treatment With Heavy Liquid Inhibitors The problem of getting corrosion inhibitors to the metal surfaces by either constant concentration or persistent filming methods is comparatively easy to solve. Complications in addition to those resulting from mechanical operations include side effects such as formation of tight emulsions as thick as cold cream which may kill the well. A squeeze treatment, still the most successful and economical method, has similar problems in addition to complicated logistics involving large volumes to be pumped. This often requires waiting on weather in inland and offshore waters. Advantages of heavy liquid inhibitors offset some of these side effects by reducing the volume of fluid to be injected so that wells are seldom killed and thick emulsions formed less frequently. Twenty to fifty gallons of inhibitor dropped down into the well usually require longer shutin (production off) times than either the squeeze or tubing displacement methods. Treatment cannot be expected to be as effective or to last as long as either of these latter methods. Objections may be raised in some cases to the use of zinc chloride or other soluble zinc salts as weighting agents, reminiscent of the taboo on the use of chlorinated hydrocarbons, the original weighting agents. Glycol or other organic weighting agents also are well tested and probably more acceptable, provided a proper filming

Treating Special Types of Wells and Miscellaneous Types of Treatment Heavy liquid inhibitor slugs are not the only means that can be used on wells that are easily killed, that is, wells which will not resume flowing without being swabbed, having the column lightened, etc., if production is stopped. Treating these wells imposes extra requirements such as mixes which lighten the column, foams, gases and the like. The use of reeled "macaroni" tubing (or running a string of small diameter pipe to the bottom for treating pruposes) and/or gas lift to revive the well are some expedients. The small diameter strings can either be left in the well or pulled out between treatments. Wells that kill can be treated by forcing the inlubitor into the formation or positively forcing the fluids into contact with the metal and perhaps squeezing inhibitor into the formation in the process by gas pressure (for example, dry gas, plant gas), liquefied petroleum gas or an inert gas such as nitrogen. Then the well can easily be returned to production. Use of nitrogen to force fluids down and of atomized treating mixes is described by Nunn and Hami!ton.48

Summary of Oil and Gas Well Inhibition Practices

TABLE 2 - Effectiveness of Heavy Inhibitor Treatments as Reflected in Iron Contents of Produced Water3 0 40 5 6 4 19 3 Months 25 ppm

41 15 8 Weeks

After Treatment

with the well fluids and

250 87 185 162

68

Many methods are used to protect oil field metal with corrosion inhibitors including continuous or intermittent treating and other more specialized methods to produce a constant concentration or persistent inhibitor film. Application methods depend on the physical setup of the well, the availability of inhibitors, labor, services and other factors. For continuous treating, the inhibitor must be mixed into well fluids, often with chemical pumps to inject the required quantities. Maintenance problems have plagued these pumps, particularly when they are in locations visited infrequently, for example, once a day or less. Inhibitior mixtures have been forced (squeezed) into formations to feed back into produced fluids. Inhibitors formulated into slow-dissolving solids, sticks, pellets, encapsulated droplets and as weighted liquids and other configurations have been used successfully for continuous treating. Also, downhole dump bailers, chemical treatment valves in tubing to feed inhibitor into the production stream from annuli, concentric tubing of small diameter and special diffusing devices have been proposed or used.

Control of Acid Cleaning Solutions

Acid treatments downhole interrupt producing operations in several ways. Corrosion control programs, particularly those involving chemical corrosion inhibitors, may be disrupted. The treating program in effect has to be modified to accomodate the after-effects of acidizing. These modifications include stopgap treating with inhibitors to restore protective films removed by the acid. Standard inhibitors may not give good protection against acid treatment. A special post-acidizing program with the regular corrosion inhibitor should be planned to follow acidizing as soon as possible. A prerequisite is having all traces of acid removed from the system.

Acids and acid inhibitors may be used to clean lines and vessels in the oil field just as they are used in industry. They are described in this book in the chapter on acid inhibitors. Acids and acid inhibitors are used downhole in the oil field. Corrosion inhibitors for use with well stimulation acid treatments or formation cleanouts for restoring injectivity of disposal wells are specialized chemicals preferably chosen through simulated field operation tests. The specific metals, formations and contaminants should be tested under operating temperature ment times.

and pressure for the probable treat-

Bactericides as Inhibitors

Billings, Knox and Morris describe these tests.49 Figure 5 shows some of the equipment required for laboratory tests of inhibitors used to control corrosion by well acidizing fluids. (Work is under way on standards applying to the use of acid inhibitors by a joint NACE-American Petroleum Institute committee). An excellent treatment on well acid treatment mechanisms is found in Tedeschi, Natali and McMahon's article.49a

The life processes or the residues of the growth of living organisms may aggravate corrosion or produce corrodents. Bacteria and algae as well as other organisms often are found in produced fluids. Consequently germicides, bactericides, bacteriostats, algaecides and similar compounds may influence corrosion rates if they reduce effects of living matter. Physical conditions in a system may be changed by organic growths to aggravate corrosion. Sulfate reducing bacteria produce tubercles under which corrosion may be severe and highly localized and lead to pitting. They also produce hydrogen sulfide to make sweet systems sour. These examples and others are discussed by Jorda and Shearer,s 0 Baumgartners 1 and Sharpley.s2

Characteristics of Organic Inhibitors Most of the inhibitors used now are long chain nitrogeneous materials. The most common, all long chain hydrocarbons (usually Cl 8 ) include 1. Aliphatic fatty acid derivatives. 2. Imidazolines and derivatives. 3. Quarternaries. 4. Rosin derivatives. The first of these, aliphatic fatty acid derivatives can be further broken down into: 1. Primary, secondary and tertiary monoamines. 2. Diamines. 3. Amides.

4. Polyethoxylated

amines, diamines or amides. 5. Salts of these materials.

6. Amphoteric compounds. Commercially available inhibitors which fall into these various classifications are as follows, where R = C 18 H3 7 unless otherwise specified. 1. Monoamines: a. Primary: R-NH2. b. Secondary: R2-NH. c. Tertiary: R-N(CH3)2' 2. Diamines: R-NHCH2CH2CH2NH2. 3. Amides: R-CONH2. 4. Polyethoxylated materials: a. Amines (where x + y varies from 2 to 50):

FIGURE 5 - Top view of test unit to measure velocity and temperature effects on inhibitors. The three container jars can be rotated at speeds up to 190 rpm at temperatures up to 250 F (120 Cl. Tests with the device showed velocity had little or no effect if the inhibitor was arsenic compounds or propargyl alcohol.49

..•.. (CH2 CH2 O)xH

R-N,

(CH2 CH2 O)yH

69

b. Diamines (where x + y + Z varies from 3 to 10):

many investigations by laboratory workers. More than two decades ago varieties of test methods designed to discriminate among inhibitors were developed and reported in NACE journals. In 1960, a static test was formalized out of the work done by Spalding and Grec05 6 as a "Proposed Standardized Static Laboratory Screening Test for Materials to be Used as Inhibitors in Sour Oil and Gas Wells." This was identified as NACE Publication 60-2.57 It used chemicals at concen-

R-NCH2CH CH N.-CCH2CH20hH I 22, (CH2CH20)zH (CH2CH20)yH c. Amides (where x + y varies from 5 to 50):

o 11

R-C-N

.....(CH2CH20)XH

trations equivalent to cost of 100 ppm of $2 a gallon inhibitors, based on total fluids. Mild steel, cold rolled coupons were exposed for about a week and were evaluated on a weight loss basis. Static tests produce results applicable to static conditions and also are useful as a preliminary screening before the more time consuming and detailed dynamic tests. Dynamic testing reported by many workers involved a wide array of methods including rotated and tumbled bottles, coupons exposed on the perimeter of a rotating wheel, shaking machines, stirring devices and others. Various sizes and configurations of flat, rectangular or circular coupons as well as sections of rods and pipe were used. Evaluation was by weight loss, pitting, film persistence, fIlm resistivity, hydrogen evolution, drop-size ratio and electrical resistance. In 1970 NACE published Standard TM-02-70: Test Method-Method of Conducting Controlled Velocity Laboratory Corrosion Tests, which is applicable to inhibitor evaluation.

...... {CH2CH20)yH 5. Acetic, oleic, dimeric, naphthenic, salts.

or phosphate

acid

6. Amphoteric compounds: CH3 CHCH2 COOH. I

R-NH

PfoW and Gregory5 3 patented the diamines RHN (CH2 )xNH2 in which R is an aliphatic or alicyclic carbon chain of 8 to 22 atoms and x is 2 to 10. The alicyclic or aliphatic group is preferably a resin acid (or high fatty acid residue containing 18 carbon atoms) which can be obtained from resin or tall oils, soybean of coconut oil or tallow. In the same patent Pfohl and Gregory say that oleic acid salts of these diamines are still better inhibitors. The reaction of the diamines with acids obtained by partial oxidation of certain liquid hydrocarbons was patented by Jones.54,55 A typical example is the salt of Duomeen- T and Alox 425.(2 )

NACE also developed a standard coupon(3) which can be used in a wide variety of tests. Tables 3 and 4 show some of the results obtained by various companies making dynamic tests. Figure 6 is a diagram of the criteria applicable to the drop size ratio evaluation method. Figure 7 shows results of tests to evaluate the influence of temperature on inhibitor performance.

Laboratory Testing of Corrosion Inhibitors The litera ture on corrosion control in the petroleum industry has many references to testing methods designed to simulate field conditions. Ingenuous procedures attempt analog methods to study corrosion control with actual well fluids and metal, or the best available synthetic fluids. Variables encountered in the field are simulated within

(3)A standard coupon is available from NACE for use in monitoring inhibitor effectiveness or making screening tests. It allows replication studies in individual laboratorie.s and later comparisons of results among various laboratories. The coupon is made of 1020 steel, measures 4314 x 1/2 x 1/8-inch with a 5/16-inch hole on a 3/8-inch center from one end. It is normalized after cutting and stamping. Coupons can be obtained from Technical Committee Secretary, NACE, P. O. Box 1499, Houston, Tx. 77001.

practical limits by a variety of measures aimed at quantification of results. , Because corrosion fluids sometimes are quiescent, they can be simulated by static tests, without the necessity of correlating fluid flow effects. Oilfield examples of quiescent fluids are packer fluids and others left in tubing-casing or casing-formation annuli. Shut-in wells or intermittent flow conditions in producing wells impose static conditions also. Cooperative work done by NACE on testing is described below: B ,A C

TABLE 3 - Summary of Results of Multilaboratory Tests on Inhibitor Film Persistence(1)

Inhibitor

12(2) 0First 110 0Third 60Fourth 0 Second 50611 0

Effectiveness Ranking

NACE Static and Dynamic Test MethodsD Screening tests for both static and dynamic conditions have been documented by NACE as the culmination of »~ (1)Summary from Table 4. O. R. Fincher. Cooperative Evaluation of Film Persistency Tests.

(2)Ouomeem-T, A tradename belonging to Armour Chemical Co., Chicago, 111.(Amino Trimethylene Stearyl Amine). Alox 25, a tradename belonging to Alox Corp., Niagara Falls, N. Y. (Fatty acid prepared by oxidation of selected petroleum fractions).

( 2 )Mat. Pro.,of5,reporting No. 10,69-73 (1966) Oct. Number laboratories.

70

TABLE 4 - Description of Test Procedures of Various Companies(1) Rod Fixed strip Strip Strip Long strip RPM .... 41.0 250 33 42 Rod 175 15 9.2 ml Total ......... Short-arc 450 30 334 34 ·9.37 horizontal shaker 350 350 52.5 180 120 170(2) 26 55 10.4 10.9 11.7 30 45 Long Area, sq Type cm Fluid, Apparatus Coupons Rotating wheel Rotating Rotating mounting wheel coupon mounting onboard board plasticstrip 350

ype

Coupon

spindle

(1)C. C. Nathan. Correlations of Oil-Soluble, Water-Dispersible Corrosion Inhibitors inOil Field Fluids, Corrosion, 18, No. 8, 282t-28St (1962) Aug. (2)Shaker movement in cycles per minute.

I

I

~

•I

~

2

3

statistical nature of the protection obtained from continuous treating of oil field fluids with inhibitors was the subject of investigations reported by N athan and Eisner.2 6,58 They showed that some inhibitors give poor protection and even accelerate corrosion at low concentrations, but that data from replicate tests allow predictions of variations from the statistical mean. At optimum concentrations, the scatter is low when the protection is high. In the concentration region between too little and enough, the data are extremely variable, making it difficult to determine what protection can be obtained unless sufficient rcplicatc

4

FIGURE 6 - Configurations of drops used in evaluating the merits of oilwell inhibitors using the "drop size ratio" technique. Numbers 1 through 4 indicate order of increasing performance. Drop 1 produces no wetting; 2 and 3 have a 0.5 rating while 4 produces almost perfect wetting. (H. E. Waldrip and J. E. Rowe. Variables Influencing the Corrosivity of Oil and Gas Wells, Corrosion, 14. No. 2, 108-120 (1958) Feb.).

~ w >

U-l C w « I0 u i= z ~wIZ

60 80 20 100 40

...

0

I-

IIIII. IIIII

IIII

:I III

Cl::

I

I

II

2312312312312312 A

B

Applications of Statistics

.,.,.,.,.,."".,.,.,., "",.,., The

C

1 2 3 D

E

F

G

." ~NHIBITORS

2 3 H

23123123123 J

K

FIGURE 7 - Results of temperature on inhibitor performance. Numbers represent: Farenheit temperatures as follows: 1 = Room; 2 - 150; 3- 220. (Centigrade 21, 66, 1041. Figure 6. Corrosion inhibitor Evaluation at Elevated Temperatures. V. W. Maxwell, Corrosion, 16, No. 4, 201t-204t (1960) April.

71

L

coupon filming time is one hour. Bottles containing coupons and filming fluids were rotated on a wheel. The following combinations were used: a. Refined 300 oil containing 2.3 percent inhibitor (I gal inhibitor to I bbl oil). b. Fresh water containing 2.3 percent inhibitor. c. To simulate conditions after filming, coupons are transferred to fluids containing 10 percent 300 oil and 90 percent 10.5 percent brine. 2. To simulate conditions after filming, coupons are transferred to fluids containing 10 percent 300 oil and 90 percent brine (with no inhibitor) and run on a dynamic wheel for one hour. After this, coupons were transferred to fresh fluids consisting of 10 percent 300 oil and 90 percent 10.5 percent brine (no inhibitor) and returned to the dynamic wheel for a 72 hour run.

.30

::t

•

"

~

_ Inhibitor 1 •

~ .20

+

c

•

'"

Inhibitor Inhibitor Inhibitor

2 3 4

.~ et

o o

.20

.40 Fraction Inhibition'"

FIGURE 8 - Fraction inhibition inhibitors 1, 2, 3 and 4.26

.60

1.0

.80

f vs fraction

scatter for

Monitoring Results of Inhibition Radio tracer Methods

tests are carried out. This may mean that each separate concentration in any series of tests should have at least four duplicate tests. This should be kept in mind when working with this kind of laboratory testing. Figure 8 graphically illustrates some results of Nathan and Eisner, showing how the data deviate at different inhibitor efficiencies.

Notable work using radioactive tracers has been done by Raifsnider, et ai, in relating results from laboratory tests of the squeeze method to field results. Figure 9 shows their results. This study permitted identification of an application method Get stream) which produced benefits much greater than were achieved from dump bailer applications.

How to Make Simulated Field Tests

Iron Content Measurement

In a 1968 article, NestleS 9 reported on screening tests of 48 commercial organic inhibitors used to control corrosion in oil and gas wells. His methods were designed to simulate field use and to gather data permitting a reduction of the number of formulas in inventory. Inhibitors were evaluated in sweet and sour environments using simulations of continuous treatment and persistent filming application methods. Laboratory prepared fluids used were 300 oil( 4) with 10.5 percent brine and 300 oil with fresh water. Details of the tests follow:

Results of tests on squeeze treatment of two condensate wells and two oil wells in South Louisiana and a gas lift oil well in South Texas were reported by C. C. Nathan.26 Using iron content of produced fluids as a criterion for the Louisiana well squeezes, it was concluded that one condensate well had about six months' protection, but that protection of the others was questionable. The South Texas well was a gas lift well producing 300 barrels of gross fluid, 93 percent salt water. This well was squeezed with a drum of "oil soluble, water-dispersable" inhibitor mixed with three barrels of oil and overflushed

Colltinuous Treatment

with 8 barrels of oil. Success of the squeeze was measured using iron content.

I. An inhibitor concentration of 15 parts per million (ppm) was used. This is in the 10 to 100 ppm range (basis total fluids), consti tu ting a severe test for many inhibitors. 1. More than one concentration should be tested if possible. 3. The inhibitor was mixed in and tested in fluids

Coupons A Iso Exposed Downhole coupons were placed in this well prior to a squeeze and were removed at intervals until the last pair was removed after six months. Short-term down hole

consisting of ] 0 percent 300 oil and 90 percent 10.5 percent brine. Coupons were run on a dynamic wheel for 72 hours. Before and after weight differences were compared with weight losses for similar coupons run 72 hours in fluids containing no inhibitor. 4. Fluids from wells producing hydrocarbons and water should be used also when possible. Persistent FilminK TreatmCllt I. To simulate persistent filming intermittent ment, several coupon filming fluids were used.

coupons were those exposed for the short interval between pulling the long-term coupons. The long-term coupons indicated that a squeeze treatment was giving 98 percent protection; whereas, the short term coupons showed 98 percent protection for the tIrst three weeks only. After that the rate steadily decreased to 35 percent for the last period of exposure, which was 5 to 6 months after treatment. The other methods showed that no protection was being obtained by the squeeze after three weeks. It appeared that corrosion protection was being obtained as the result of persistence of the film on the tubing and/or from the initial slug of inhibitor that was produced when the well returned to production.

treatUsual

(4)"Refined Oil 300" is a high-flash, low viscosity (42 SUS at 30 C (100 F) paraffin distillate oil. Brine = 10 percent sodium chloride and 0.5 percent calcium chloride in distilled water.

72

30

300

----

Instantaneous Daily Corrosion Rate - Cumulative mils (Daily Sampling) Cumulative mils (Weekly Sampling) 1. 2. 3. 4.

"

5. 6. 7. 8.

1ii

~

Well Shut-in (Proration)

c

.s o

"

~

r-

8 100

-oil-

U

Installed Specimen Dump Bailed 5 qts. Diamine Salt Dump Bailed 5 qts. Diamine Salt Applied 30 qts. Imidazoline Salt with Jet Stream Ran Caliper Survey Dump Bailed 5 qts. Imidazoline Salt Commenced Sampling Weekly Ran Caliper Survey

i20

§ .;;;

o

rr-

o

U

~o

No

-"1-

Samples

~ H ~ o

50

100

150

200

250

300

350

400

Time. days

FIGURE 9 - Chart of corrosion data from 9600-ft gas lift well producing a mixture of 88 bbl oil and 110 bbl brine daily. Data were taken using a cobalt-60 isotope source located in the producing string of the well. Radioactivity of effluent was compared satisfactorily with concurrent weight loss data. Inhibitor was applied three times during 500 days by dump bailer and once'(70 days after start of test) by jet stream application. This method uses an applicstor which squirts inhibitor onto the walls of the tubing and wipes it over the surface with a felt pad. Low corrosion rates following this treatment lasted almost a year. (Figure 1-Corrosion Monitoring in Oil Wells With a Radioactive Specimen. B. E. Gordon, P. J. Raifsnider and D. L. Lilly, Mat. Pro., 5, No. 11,21-3 (1966) Nov.

Techniques Applying to Coupons Assessing the life of films produced by intermittent treating (persisting fIlming) requires special techniques. Unless coupons have the same treating history as the metal in the well and are materials the same or essentially similar to well metals, coupon corrosion rates will not be equivalent to metals in the system. Coupons must be in the system when it is fIlmed or must be given a treatment simulating the filming. Under the heading "New Idea Tried," Smith37 reported in an article titled "Corrosion Checked in West Texas by Inhibitor Squeeze," the following: "The probe installed on May 4, 1959 was submerged in a concentrated inhibitor solution before it was installed and

special types of monitoring to evaluate fully the results of these types of application. Continual monitoring of results is more difficult when the persistent film technique is used than it is with continuous treating. While coupons, dissolved iron analysis, hydrogen probes, electrical resistance and polarization instrumentation all can be used, a more reliable coupon or other device is needed than is presently in common use to follow the progress of intermitten t inhibitor effectiveness.

Quality Control and Specifications Oilfield inhibitors usually sell for about $2 a gallon. While there are many exceptions, in spite of inflation, the average price of most inhibitors will be close to this amount or even slightly less. Materials used in most inhibitors are by-products of petroleum refining and other industries. Although inhibitor formulators and vendors usually adhere to fairly rigid manufacturing specifications, most of them do not provide data from corrosion testing under field conditions. Quality variations from batch to batch have not been controlled carefully by some compounders. While the compounder relies on tests which may indicate significant differences in raw materials from batch to batch, these data have little or no bearing on the performance of the inhibitor in the field. Since inhibitors may contain three or more active ingredients in addition to solvents which can materially affect performance, considerable variations in field results can occur. Many inhibitors are odorous, dark-brown materials with color and/or odor caused by impurities not removed

the data are much more in line with what was expected from the treatment."

Inhibitor Optimizing Needed Even poor quality inhibitors sometimes give economical protection when used according to good application practices. This often confuses the issue to the extent that no effort is made to determine how much better results could have been obtained if better materials were employed with the same care and precision. Causes and effects in continuous treating are closely coupled, while in persistent filming the lag between cause and effect can be lengthy. Squeeze treatments with good inhibitors have been known to last for two years and are suspected of lasting much longer. This means that long exposure times and many wells are needed along with 73

when the inhibitors were synthesized and formulated. This makes it difficult to attach significance to what are called "active" materials. Even listing materials other than solvents or diluents does not help. A 1967 report of NACE Task Group T-ID-S6o on quality control procedures used in inhibitor manufacture revealed that less than half of the

References

1I. A. Lubinski and K. A. Blekharn. Buckling of Tubing in Pumping Wells, Its Effects and Means of Controlling It, AIME Trans., 210,73-88 (1957). 12. R. J. Villagrana and W. W. Messick. Economics of Oil Well Corrosion Control, Oil & Gas J., 48, No. 11,58-94 (1949) July. Also: APl Drilling and Production Practice, p391 (1949). 13. J. T. Martin. South Louisiana Operators Wage Fight on Four Types of Corrosion, Oil & Gas J., 52, No. 7, 308-20 (1953) June 22. 14. Condensate Well Corrosion. Natural Gasoline Association of America, Tulsa, Okla (1953). 15. D. A. Shock and J. D. Sudbury. Corrosion Control in Gas Lift Wells, Corrosion, 8, No. 9, 296-299 (1952) Sept. 16. G. L. Farrar. Combatting Corrosion in Oil and Gas Wells, Oil & GasJ., 51, No. 49,106-9, 111, 113 (1953) Apr. 13. 17. H. L. Bilhartz. Sweet Oil Well Corrosion, World 0iI,134, 208-16 (1952) Apr. 18. H. L. Billiartz. How to Predict and Control Sweet Oil Well Corrosion, Oil & Gas J., 50, No. 50,116-18,151,153 (1952) Apr. 21. 19. H. L. Bilhartz. Sweet Oil Well Corrosion, API Drilling and Production Practice, p54 (1952). 20. H. L. Bilhartz. High Pressure Sweet Oil Well Corrosion, Corrosion, 7, No. 8, 256-64 (1951) Aug. 21. H. E. GreenwelL Studies on Water-Dependent Corrosion in Sweet Oil Wells, Corrosion, 9, No. 9, 307-12 (1953) Sept. 22. J. A. CaldwelL Sour Oil Well Corrosion, Corrosion, 8, No. 8, 292-94 (1952) Aug. 23. D. Bass. Preventing Corrosion by Crude: The Use of SurfaceActive Agents, Petroleum, 20,139-42 (1957) Apr. 24. C. M. Hudgins. A Review of Sulfide Corrosion Problems in the Petroleum Industry,Mat. Pro., 8, No. 1, 41-7 (1969) Jan. 25. C. M. Hudgins. Hydrogen Sulfide Corrosion Can Be Controlled. Petro. Eng., 13, No. 13, 33-6 (1970) Dec. 26. C. C. Nathan and E. Eisner. Statistical Concepts in the Testing of Corrosion InhIbitors, Corrosion, 14, No. 4, 193t-20It (1958) Apr. 27. C. C. Nathan. Correlations of Oil-Soluble, Water-Dispersible Corrosion Inhibitors in Oil Field Fluids, Corrosion, 18, No. 8, 282t-285t (1962) Aug. 28. C. C. Nathan. Minutes of Record, NACE T-l Meeting, Oil and Gas Well Corrosion, Oklahoma City, Okla. (1957) Oct. 1, Summary Corrosion, 14, No. 4, 27-30 (1966) Nov.

1. J. I. Bregman. Corrosion Inhibitors, The MacMillan Company, New York, (1963). 2. J. W. Phenicie. Increased Petroleum Production Demands Increased Corrosion Control, Mat. Pro., 5, No. 3, 23-4 (1966) Mar. 3. R. M. Robinson and H. E. Waldrip. Review of Survey Made on Oil and Gas Well Corrosion Costs. NACE T-IH on Economics of Corrosion Control (1963) June. 4. B. D. Park and G. R. Roberson. Economics of Petroleum Production, Draft of chapter intended for Corrosion of Oil and Gas Well Equipment, Division of Production, American Petroleum Institute. 5. V. W. MaxwelI. Corrosion Inhibitor Evaluation at Elevated Temperatures, Corrosion, 16, No. 4, 20It-204t (1960) Jan. 6. D. R. Fincher, W. F. Oxford, Jr. and E. H. SulIivan. Well Completion and Corrosion Control of High Pressure Gas Wells, Status Report, NACE T-IB-l, Corrosion, 15, No. 2, 73t (1959). 7. J. F. Chittum. Corrosion Fatigue Cracking of Oilwell Sucker Rods, Mat. Pro., 7, No. 12, 37-8 (1968) Dec. 8. J. F. Bates. Sulfide Cracking of High Strength Steels in Sour Crude Oils, Mat. Pro.• 8, No. 1,33-9 (1969) Jan. 9. C. M. Hudgins. A Review of Sulfide Corrosion Problems in the Petroleum Industry, Mat. Pro., 8, No. 1,41-7 (1969) Jan. 10. C. C. Patton. Corrosion Fatigue Problems in Petroleum Production, Corrosion 71 Paper 61, Petroleum Production-Stringent Corrosion Control Procedures Key to Extended Fatigue Life, Mat. Pro. & Per!., 11, No. I, 17-8 (1972) June.

29. O. L. Riggs and D. A. Shock. Oil-Well Corrosion Inhibitor, U. S. 2,822,330, (1958) Feb. 4. 30. C. O. Bundrant. High Density Corrosion InhIbitors Simplify Oil Well Treatments, Mat. Pro., 8, No. 9, 53-5 (1969) Sept. 31. G. B. Farquhar, M. J. Michnick and R. R. Annand. Tracer Experiments During Batch Treatment of Gas Wells With Corrosion Inhibitors, Mat. Pro. & Per!., 10, No. 8,41-5 (1971) Aug. 32. C. C. Patton, D. A. Deemer and H. M. Hilliard, Jr. Field Study of Fall Rate-Oilwell Liquid Inhibitor Effectiveness, Mat. Pro., 9, No. 2, 37-41 (1970) Feb. 33. J. A. Stanton. A Digest of the Proceedings of the Corrosion Control Short Course, The University of Oklahoma, (1959) Mar. 31-Apr. 2. 34. R. H. Poetker, P. C. Brock and S. A. Huckleberry. Petro. Eng., (1957) Dec. 35. J. K. Kerver and F. A. Morgan, Ill. Corrosion Inhibitor Squeeze Technique-Laboratory Study of Formation Permeability Damage, Mat. Pro., 2, No. 4,10-20 (1963) Apr. 36. J. K. Kerver and F. A. Morgan, Ill. Corrosion Inhibitor Squeeze Technique-Laboratory Adsorption-Desorption Studies, Mat. Pro., 10, No. 4,10-20 (9163) April 37. R. L. Smith. Corrosion Checked in West Texas by InhIbitor Squeeze. Oil & Gas J., 57, No. 43, 117-20, 124-6 (1959) Oct. 19. 38. R. H. Poetker and J. D. Stone. Squeezing InhIbitor Into Formation, Petro. ElIg.• 28, B29-34 (1956) May.

27 manufacturers that supplied information regularly make composition analyses of raw materials going into their products, while 64 percent tested physical properties and only 18 percent checked performance. The survey also showed that with respect to finished products, 40 percent made composition analyses, 72 percent checked physical properties and 27 percent evaluated performance. The survey covered what was believed to be about 90 percent of the volume of inhibitors used in oil fields.

Computer Aids in Controls Computer oriented records permit faster, more accurate analysis of results from oilfield corrosion control programs. Some of the systems now in use are described in an article by Hamner.61 Detailed reporting of events, which include in some instances the exact identification of failed equipment, the kind and cost of repair parts and labor expense make it possible to closely monitor results of inhibitor programs. In another article by Bucuram and Sullivan,62 failure data entered into a computerized system have provided a means of predicting probable corrosion failures, thus permitting corrective measures to be taken in advance. Real time computer access makes machine evaluation of chemical treating programs economical. Treating many wells for corrosion and scale control requires constant updating of treatment quantities on an individual well basis. This technique is discussed by Frye and Canaday.6 3

74

50. R. M. Jordan and L. T. Shearer. Aqualin Biocide in Injection Waters. SPE Paper 280 (SPE of AIME) Research Meeting, Tulsa, Okla. (1962). 51. A. E. Baumgartner. Microbiological Corrosion-What Causes It and How It Can Be Controlled. 1. Petro. Tech., 14, No. 10, 1074 (1962) Oct. 52. J. M. Sharp1ey. Elementary Petroleum Microbiology. Buckman Lab., Inc., Short Course on Petroleum Microbiology. 53. F. W. Pfohl and V. P. Gregory. Corrosion Inhibitors, U. S. 2,736,658, (1956) Feb. 28. 54. L. W. Jones. Corrosion Inhibitors, Especially for Oil Wells, U. S. 2,840,525, (1958) June 24. 55. L. W. Jones. Corrosion Inhibitors for Oil Wells, U. S. 2,840,584, (1958) June 24. 56. NACE T-IK. A Proposed Standardized Laboratory Procedure for Screening Inhibitors for Use in Sour Oil and Gas Wells, Pub. 55-2, Corrosion, 11, No. 3, 143t (1955) Mar. 57. NACE T-IK. A Proposed Laboratory Screening Test for Materials to Be Used as Inhibitors in Sour Oil and Gas Wells, Pub. 60-2. Corrosion, 16, No. 2, 63-64t (1960) Feb. 58. C. C. Nathan. Statistical Aspects of the Corrosion Process and Its Inhibition, 3rd European Symp on Corrosion Inhibitors, Ferrara, Italy, Sept. 14-17, p829-850 (1970). 59. A. C. Nestle. Simulated Field Usage Testing-Organic Inhibitors for Oil and Gas Wells, Mat. Pro., 7, No. 1,31-3 (1968) Jan. 60. Survey of Quality Control Procedures Used in the Manufacture of Oil Field Inhibitors, Report of NACE T-ID-5, NACE Pub. ID267,Mat. Pro., 6, No. 6, 82-4 (1965) June. 61. N. E. Hamner. NACE Investigations Into Computerization of Corrosion Control Information, NACE W. Canadian Region Conf., Calgary, Alb., Canada (1971) Feb. 62. S. M. Bucuram and J. G. Sullivan. Data Gathering and Processing System to Optimize Producing Operations, J. Petro, Tech .. 24. No. 2, 185-192 (1972) Feb. 63. G. A. Frye and P. G. Canaday. Computation of Well Treating Programs Utilizing Time Sharing System, W. States NACE Regional Conf., San Diego, Ca., (1969) Sept. 26.

39. R. H. Poetker and J. D. Stone. Inhibition Improved 17 Percent While Cost Dropped 50 Percent. Oil & Gas 1., (1956) July 9. 40. R. H. Poetker. Inhibitor Squeeze Treatment. SPE Paper 1129-G, Houston, Tx. (1958) Oct. 5-8. 41. D. R. Fincher. Corrosion in Gas Wells and Gas Gathering Systems, 1. Petro. Tech., 13, No. 9, 847 (1961) Sept. SPE Paper 29. 42. W. B. Bleakley. Inhibitor Squeeze Treatment Is Promising, Oil & Gas 1., 57, No. 7, 114 (1959) Feb. 9. 43. E. B. Norwood. Corrosion Control by Inhibitor Squeeze. API Paper 925-4-A: Spring Meeting, (1959) Mar. 25-27, API Southern District, New Orleans, La. 44. D. R. Fincher. Special Techniques Cut Corrosion Costs, Petro. Eng., B-30, (1961) Feb. 45. W. B. Bleakley. Inhibitor Solves Corrosion Problem, Oil & Gas 1., 66, No. 52, 151 (1968) Dec. 30. 46. J. K. Kerver and H. R. Hanson. Corrosion Inhibitor Squeeze Technique-Field Evaluation of Engineered Squeezes, 1. Petro, Tech., 17,50 (1965) Jan. 47. B. D. Park and A. R. Riley. Recommendations for Corrosion Control of Sucker Rods by Chemical Treatment, Mat. Pro., 6, No. 5, 85-9 (1967) May. NACE Pub. 10167. NACE T-lD-3, Also Sec. 2, API Recommended Practice for Care and Handling of Sucker Rods, APR RP 11 BR, Fifth Edition, (1969) Mar, p5-7, 11, Corrosion Control by Chemical Treatment, Also API RP-ll-BR, 4th Ed., (1968) Apr., p4-7, Corrosion Control by Chemical Treatment. 48. G. L. Nunn and B. E. Hamilton. Well Treatment With Inert Gas-Inert Gas Squeeze for Corrosion Control, Mat. Pro., 6, No. 5, 37-40 (1967) May. 49. W. E. Billings, J. A. Knox and D. Morris. Laboratory Apparatus Tests Pressure and Velocity Effects in Inhibited Hydrochloric Acid, Mat. Pro., 2, No. 8, 59-62 (1963) Aug. 49a. R. J. Tedeschi, P. W. Natali and H. E. McMahon. The Role of the Triple Bond in Acid Corrosion Inhibition, Proc. NACE 25th Conference, 1969, NACE, Houston, Tx. pI73-9.

7S

Corrosion Inhibition in Secondary Recovery'"

A. K. DUNLOP*

Corrosion Problems in Water Floods

Introduction

The water flooding process entails a number of steps: 1. Locating a satisfactory source of water; 2. Treating it, if necessary, to prevent corrosion 1 or improve water quality; 3. Raising the pressure enough to overcome the formation pressure by use of either centrifugal or positive displacement pumps; and 4. Moving the high pressure water through distribution lines to wellheads of the injection wells; thence 5. Down the tubing to the formation. The volume of water handled (as much as ten times the oil produced) may be on the order of tens or hundreds of thousands of barrels a day. The cost of corrosion failures in repairs and lost production can be substantial. Corrosion encountered in water floods is due primarily to either oxygen contamination or acidity of the water. The oxygen causes pitting, while the acidity results in general attack. Oxygen may be present initially if the water comes from sources open to the atmosphere (rivers, lakes, the ocean,2 or even some source shallow wells) or it may enter the system through vents in storage tanks, along the shafts or the suction side of centrifugal pumps or even through such equipment as diatomaceous earth fIlters. Acidity in injection water is more likely when produced water (water produced from the formation along with the oil) is used for flooding. This acidity is generally caused by residual acidic gases (carbon dioxide or hydrogen sulfide), but also may be due in part to low molecular weight organic acids.3 If waters containing significant amounts of dissolved solids are to be transported through bare steel pipe, oxygen must be excluded (or removed).4 Inorganic inhibitors used in aerated water (as in cooling towers or radiators) are usually too expensive to be applied to waters on a once-through basis as would be the case in a water flood. Concentrations of the usual amine type organic inhibitors sufficient to prevent oxygen corrosion are too expensive also. However, successful inhibition of brines with up to 7800 parts per million chloride have been claimed recen tly by Hatch and Ralston,5 who used a newly introduced aminomethylenephosphonate-zinc sulfate formulation. Alternatives to oxygen removal are the use of organic inhibitors developed especially to control oxygen corrosion, internally coating steel piping with either an organic or

Primary oil production is not a very efficient process, even when aided by such techniques as pumping and gas lifting. Depending on viscosity, formation permeability, pressure, depth and numerous other factors, primary recovery can range from something on the order of 25 to 40 percent of the oil initially in a formation down to essentially zero. Because the cost of discovering the oil and developing the field has already been expended, there is a great economic incentive (and certainly a conservational one as well) to recover from the formation as high a percentage of the oil as possible. This incentive has led to development of secondary, tertiary and other methods of recovery. All of these will be discussed under the heading of secondary recovery. The principal secondary recovery methods are: 1. Water flood (ambient temperature), 2. Hot water flood, 3. Steam flood, 4. Miscible flood, and 5. Fire flood (in situ combustion). Each has its own sphere of greatest applicability. However, there is considerable overlap both in the utility of these methods and in the corrosion problems encountered in their utilization. The main hazard encountered in shifting from primary production to secondary recovery is in the possibility that foreign materials may be introduced into the production system. From the corrosion standpoint, the most important of these materials is oxygen. Oxygen is rarely present in primary production environments below a few hundred feet. Oxygen is a potent corrosive-even at very low concentrations. Furthermore, oxygen corrosion cannot normally be controlled by the 'inhibitors usually applied in primary production. Other materials with less significant influence on corrosion rates are incompatible brines which can cause scaling and bacteria, some of which can generate hydrogen sulfide or cause plugging. Another factor involved in floods injecting water in some form is an increase in the fraction of water in the produced fluids. This can aggravate corrosion problems, but does not really introduce any new features unique to secondary recovery. iI *Bellaire

, ,j

Researdl

Center

Publication

No. BRC·-CORP-15.

*Shell Development Company, Houston, Tx.

,

it.!' I

76

\ cement lining, or substituting nonmetals for the steel.

corrosion-resistant

alloys or

caused by increased temperature. the equilibrium

Oxygen removal and inhibition are discussed below but the other approaches to control are outside the scope of this chapter. Acid corrosion, as is true also in primary production, is usually controlled by filming amine or imidazoline inhibitors. In water floods, however, water soluble or dispersable modifications of these materials are employed.

As temperature increases,

(1) shifts to the right and the resultant carbon dioxide concentrates in the vapor phase if pressure, temperature and pH are such that one can form. If, as is taught by Wallace , Bradley, Holliday and Pryor, 7,8 the resultant carbon dioxide-containing steam and liquid phases are injected together into the formation, no difficulty will be expected. However, if the steam is separated from the basic blowdown and injected by itself, condensate corrosion due to carbon dioxide (as encountered in steam plant condensate return lines) can occur. (See further, the chapter on boiler corrosion.) Carbon dioxide corrosion (due in fact to acidity of carbonic acid formed when carbon dioxide partially hydrates during dissolution in water) can arise also in miscible floods using high pressure carbon dioxide to reduce the viscosity of the liquid phase to increase sweep efficiency.9 Inhibition may be used when carbon dioxide breaks through into producing wells, but drying below the dew point is being used to prevent corrosion in transmission and injection lines.

Co"osion in Other Fluid Flood Systems Hot Water and Steam-In hot water and steam floods, the potential for oxygen corrosion is even greater than in conventional water floods. For this reason, it is imperative to remove oxygen completely from the flood water before it is fed to the field heater or boiler. At higher temperatures, other approaches to corrosion control are ruled out by ineffectiveness or by scaling problems. A comprehensive discussion of corrosion problems in steam injection systems has been written by HaseItine and Beeson.6 Other problems which may occur in high temperature secondary recovery systems can arise from the presence of calcium and magnesium ion hardness and/or bicarbonate ions in the feed water. Hardness must be controlled to prevent precipitation of suifates and/or carbonates on heat exchanger surfaces. This is ordinarily accomplished by ion exchange in which resins give up sodium ions equivalent to the calcium and magnesium ions removed. However, because the ion exchange process is seldom 100 percent efficient under practical operating conditions, a small amount of a chelating agent such as ethylene diaminetetraacetic acid (EDT A) is often added. The EDT A complexes the residual hardness and lowers the concentration of

Co"osion in In Situ Combustion In situ combustion processes (or fire floods, as they are also called) face still other corrosion problems. These include the necessity of handling fluids containing the oxygen necessary to sustain the downhole combustion. Oxygen may also be found in the produced fluids, if it is not completely consumed in the combustion process. Carbon dioxide and organic acids also are produced and tend to complicate corrosion control in the production wells. High temperatures created when the combustion zone nears a producing well can further aggravate the situation.

"free" calcium and magnesium ions below the level where precipitation of solids can occur. While this takes care of the scaling problem, it can create two other quite different corrosion problems. If the chelating agent were added to the flood water before the oxygen scavenging step, the necessary catalyst (usually cobaltous ion) could be complexed and thus inactivated so that the scavenging reaction would not take place. As a consequence, unreacted oxygen could be fed to the field heater or boiler and cause severe corrosion there.

A recent general appraisal of in situ combustion field tests has been written by S. M. Farouq Ali;lo an extensive bibliography is included.

Fundamentals of Secondary Recovery Corrosion and Inhibition Essentially all corrosion problems encountered in secondary recovery systems are electrochemical in nature. As pointed out in Riggs' chapter on theoretical aspects and elsewhere,1 1 an electrical circuit must be established before electrochemical corrosion can take place. Thus, for such a corrosion cell to operate, the two locations of potential electrochemical reaction, the surface of the metal and the surface where the corrosive may be reduced, must be electrically connected by both an electronic and an ionic conductor. This is illustrated in Figure I where the electronic conductor transports the electrons released in the anodic dissolution reaction to the surface where the

Another problem may result from the use of excessive amounts of chelating agent. If chelant concentration is more than a few parts per million in excess of that required to complex the hardness leaking through the ion exchange beds, it may dissolve the protective layer of magnetite from the interior surfaces of the boiler or heater. Without this magnetite layer, the bare underlying metal of the water-side heat exchanger surfaces would be susceptible to rapid attack. The reaction would be simply that of iron with water to produce hydrogen and hydroxide and ferrous ions. Such attack, if encountered, would be expected to be most acute in regions where rates of mass transfer are high, as at return bends.

electrons are utilized in reduction of the corrosive, here, oxygen dissolved in an aqueous salt solution. Ionic conduction through this electrolyte completes the circuit.

The principal reaction due to the bicarbonate ion in heated water is the shift of the bicarbonate equilibrium 77

-

~..

-

_ •.•OH·-

CI--

Na + _

.Na

Cl

~ .~

When carbon steel is attacked by weak acids, mming amine· type inhibitors will affect both anodic and cathodic reactions. The only other alternative to the amines in this situation is the use of coatings (which may be unreliable) or expensive alloys in place of steel. When oxygen causes the attack, cathodic control by excluding or removing it is one of the most widely used techniques. In this situation also, the alternatives are coatings or alloys. , Acid Corrosion-When weak or, dilute acids (which would seldom give a pH below 3 or 4) are responsible for corrosion, neutralization is the most obvious and sometimes the simplest approach. However, a stoichiometric amount of caustic, ammonia or other base is required. In a well buffered water, this could be economically prohibitive. Furthermore, to prevent precipitation or other subsidiary effects, pH adjustment may be undesirable. Inhibition is then the most likely solution. The tWo steps in hydrogen ion reduction most amenable to inhibition are the adsorption and electron uptake reactions. Since the hydrogen ion must be adsorbed on the metal surface before the cathodic reaction can

-OH -••••••

++

- - Fe

"" _

l\

t•

------- /

'F:"~i Fe = Fe ++ + 2e -

-CI-_ +

0,+2H,0+4'

-40H

FIGURE 1 - Simple electrochemical cell. Proc. NACE W. States Corrosion Seminar (1970).

From the nature of this electrochemical circuit, it can be seen to consist of a chain of events in which all must go for anyone to go. This situation makes for flexibility in the application of inhibition. When any step in the reaction chain is stopped or drastically slowed, the whole corrosion reaction is stopped or slowed. Consequently, when a corrosion problem is approached, the basic steps should be kept in mind: The two electrochemical reactions (anodic and cathodic) and the two conduction processes (ionic and electronic). Anyone of the four can be controlling. The problems are to know under what circumstances the various possible steps are apt to be controlling and therefore vulnerable to inhibition and then what measures to take to inhibit the vulnerable steps. The first and most important step in seeking to control corrosion is to find out what the corrosive is. Despite the fact that only two corrosives cause nearly all the damage in secondary recovery systems, this task can often be a frustrating one. It is essential to know whether the cause is oxygen or acidity, because markedly different techniques are appropriate for each. Sometimes both corrosives are present, so a combination of measures is necessary.

occur, materials which compete effectively for adsorption sites on the surface can block out the hydrogen ions and thus preclude their reaction. Long chain amines and other similar compounds (described in detail later) can have a substantial effect on corrosion rates as a result of their ability to occupy adsorption sites on the surface. Materials used to influence the electron uptake reaction include arsenic compounds such as sodium arsenite. Under strongly acidic conditions, elemental arsenic, which is a very inefficient substrate for the electron uptake reaction, can be plated out on the metal surface to slow the reaction rate by several orders of magnitude. This method is,. however, seldom, if ever, used in secondary recovery operations. Plastic lined pipe is the principal alternative to cathodic control. This approach is effective as long as the lining is perfect and some satisfactory method is found to protect joints. In actual practice, it is difficult to maintain a perfect lining-particularly in injection tubing. When wireline tools are used, the coating can be damaged to expose bare metal which can then be rapidly attacked. Corrosion by Oxygen-In oxygen carrying waters en-· countered in secondary recovery systems, most control measures involve some form of cathodic control. Anodic

Parenthetically, for those new to this field, the general approach to uncovering the cause (or causes) of corrosion can be briefly stated. First, look at the pH of the aqueous phase. If the pH is 6 or above, there is little liklihood that acidic type corrosion is involved. However, one must guard against being mislead by nonrepresentative samples. Loss of acid gases from solution can easily give rise to a pH increase of several units. This can make a high pressure acidic environment appear nearly neutral when a sample is tested after standing at ambient conditions. Where appreciable bicarbonate or sulfide residuals are found, the presence of carbon dioxide or hydrogen sulfide can be suspected. If the possibility of acidic corrosion has been ruled out, oxygen will be the prime suspect. This can then be confirmed by analysis, use of "spark plug probes" ,38 or through examination of equipment for possible sources of oxygen entry.

control techniques are important below.

also, however, as detailed

Usually, when carbon or low alloy steels are exposed to neutral oxygenated water, the corrosion rate is limited by the rate of the cathodic reaction-the reduction of oxygen. Furthermore, in most practical situations, the oxygen reduction rate is limited by the rate of arrival of oxygen molecules at the electrolyte-cathode interface (i.e., the steel surface). This means that the corrosion rate is mass transfer limited and that any factor influencing the transfer of oxygen in the system will affect the corrosion rate also. Hence, changes in flow velocity and oxygen concentration affect the corrosion rate because both influence the mass transfer rate of oxygen.

Cathodic Reactions In most secondary recovery corrosion problems, control of metal loss (which is the result of the anodic reaction) is achieved, at least to some degree, by controlling the cathodic reaction.

78

On the other hand, filming amines have little effect at the concentrations normally used to control acid corrosion because the adsorption and electron exchange steps in oxygen corrosion are rapid and films of molecular dimensions do not significantly affect mass transfer of oxygen molecules. Thicker films approaching macroscopic dimensions, such as are produced by exceeding inhibitor solubility limits can, however, substantially reduce the rate of corrosion by oxygen.! 2 Normally, the concentrations required render this approach impractical. Oxygen Scavenging is the term used to describe oxygen removal by chemical reaction. Scavenging permits reducing oxygen concentrations to the parts per billion range, a level which is (with few exceptions) insignificant from the standpoint of practical corrosion problems. Only three different reactants are used to a significant extent for oxygen scavenging:

where M is the metal atom and R· is an organic radical. Chain propagation then proceeds in the following steps

1. The sulfitel ion (either from a salt such as sodium sulfite or from sulfur dioxide), 2. Hydrazine, or 3. Sodium hydrosulfite (dithionite).

Most practical problems with low scavenging rates involve the initiation step. Usually, a metallic ion catalyst is used in Reaction (4). However, all transition metal ions are not equally effective and pH affects the various possible ions differently. These effects are illustrated by Snavely and Blount' 4 in their work on the hydrazine scavenging reaction.

(6) (7)

I

Some step such as (9) is also needed to regenerate catalyst if step (4) is used for initiation

The two most common complications responsible for low scavenging rates arise from inactivation of the catalyst. This may be casued by its precipitation as an insoluble (and catalytically inactive) solid due to sulfide in the water,15 or by complexing with a chelating agent such as EDTA. This latter problem can arise if EDT A is added to the flood water before scavenging to handle residual hardness as might be required in a steam or hot water flood. A further possible source of difficulty can arise from the presence of readily oxidizable impurities in the water. Such materials as alcohols, phenols and/or amines'6 can slow the overall reaction by destruction of the reactive free radicals required to propagate the chain reaction involved in oxygen scavenging. Side reactions due to the presence of a mercaptan illustrate the point. First, the mercaptan readily undergoes hydrogen abstraction to destroy an active radical ion (10) Subsequently, two mercaptan radicals can dimerize to form a disulfide molecule which is thus formed at the expense of two of the radical ion chain propaga ting species. ' 7 2 RS'~ RSSR

(5)

(11)

Corrosion inhibitors also can interfere with rapid scavenging either by reactions such as (10) or by catalyst complexing. Hydrazine is a practical scavenging agent only at elevated temperatures such as in boilers. Only the cupric ion has been reported to have a significant catalytic activity in the hydrazine-oxygen reaction at ambient temperatures and near neutral pH, and even this activity is not great. Several parts per million of Cu2+ are required to achieve

does not proceed at a measurable rate at ambient temperatures. Rather, the reaction must be initiated by one of the following steps: ' 3 S03= + hv ~ 'S03- + e (3)

S03= + R· ~ 'S03- + R-

the

(9)

(2)

(4)

I

(8)

The reactions of all of these scavengers involve a free radical chain mechanism necessitating some form of initiating step. This need is usually met by adding a transition metal ion catalyst at concentration levels in the fraction of a part per million range. A wide range of variables affects the rate of oxygen scavenging, which is an important parameter in designing a water flood system. Fortunately, when sulfite, the most common scavenging agent, is used in conjunction with 0.1 ppm cobalt catalyst, a modest stoichiometric excess at ambient temperatures usually effects complete oxygen removal in minutes. However, when such a rate is not satisfactory or is unattainable, an investigation of the oxygen scavenging mechanism and the effects of variables thereon should uncover the source of the difficulty. To understand the possible complications which can lead to insufficient oxygen scavenging rates, it is important to appreciate the need for a reaction initiator. This will be discussed first in terms of the sulfite-oxygen reaction because it is by far the most widely used. Furthermore, it has been the most thoroughly studied technique and also typifies the considerations applicable to the hydrazineoxygen reaction. The hydrosulfite (dithionite) reaction is, on the other hand, quite different. Breakdown products of the unstable dithionite ion, itself, act as reaction chain initiators, so that hydrosulfite is the only one of the three common oxygen scavenging agents which is self-sufficient. As indicated, the overall reaction for sulfite scavenging, as written,

S03= + M3+ ~ 'S03- + M2+

I

and suIfate is formed by the reaction

79

I

'i

scavenging times approximating a few minutes. 1 4 Because of the possibility of copper plating out on steel lines (due to the replacement reaction) and leading to pitting, it is not an attractive catalyst. A possible, untried alternative for water flood use, is hydrazine "activated" by addition of a quinone as patented by H. Kallfass.1 8 Hydrosulfide (dithionite) is also recommended only for a specialized use. In polymer floods(1) it is said to scavenge oxygen with much less polymer degradation than is caused by sulfite. Phosphites are also possible oxygen scavengers. Their use in boilers is discussed on page 31 t of a bibliography on corrosion inhibitors for high purity water by NACE Committee T-3F/9 but no use in secondary recovery is known. Inhibition of Oyxgen Co"osion is different from inhibition of acid corrosion. This is true on a fundamental

producing passivation are much more critical than with-inherently corrosion resistant materials. Although inhibitors such as chromates and nitrites can greatly broaden the range over which passivation may be obtained, passivating inhibitors find little use now in water floods. Cathodic

basis as well as on a practical one. However, this is not surprising in view of the differences in the reactants (one is a neutral molecule, the other an ion), their redox potentials (oxygen is a much stronger oxidizing agent), their rate limiting steps (mass transfer vs adsorption or electron exchange) and the often marked differences in corrosion product solubility. The fact that the same operational term "inhibition" is used in describing techniques for impeding both types of corrosion should not lead to the misconception that what is good for treating one should suffice for the other also.

Acids normally encountered in secondary recovery systems are usually weak. In injection facilities, hydrogen sulfide and carbon dioxide predominate. Both acid gases may be brought into the system in produced water used for flooding. Hydrogen sulfide also may be formed in the system itself, by sulfate-reducing bacteria growing there. Pure carbon dioxide or a carbon dioxide-water mixture9 may also be used for miscible flooding. Combustion gases containing carbon dioxide can be similarly used. Other acids may be encountered in producing wells. In in situ combustion projects, significant amounts of carboxylic acids or even strong acids can be produced. If significant amounts of nitrous or sulfurous oxides are formed, nitric and sulfurous or sulfuric acids can be produced. Acid corrosion problems of producing wells in secondary recovery systems are substantially like those of wells in primary production discussed in the chapter on primary production inhibition. Hence, attention will be focused on injection facility corrosion. Furthermore, because water floods presently account for the greatest use of inhibitors in secondary recovery production, discussion will cent er on inhibition of water floods.

control by oxygen scavenging is usually a superior method. Anodic stifling, whereby corrosion products or byproducts build up on the metal surface and interfere with the dissolution process, also can produce a measure of corrosion control. When filming amines are used to inhibit corrosion of steel by weak acids, the anodic effects appear to be the most significant ones. However, the cathodic reaction is affected also. The relative influence of the two effects changes with the degree of inhibitor adsorption?

0

Inhibition of Corrosion by Acids

Effective inhibition of oxygen corrosion usually involves passivating inhibitors such as chromates or nitrites (really anodic inhibitors), or inorganic barrier formers such as calcium plus bicarbonate, zinc salt phosphate combinations or the silicates. For water floods, however, these materials are not usually satisfactory. The concentrations required for passivating inhibitors-particularly in the presence of a significant chloride content-tend to be prohibitive for once-through use. The controlled scaling technique whereby a calcium carbonate precipitate is formed at the more alkaline cathodic areas is reliable only in potable waters and potable waters are not normally used in flooding. The straight zinc-salt phosphate combinations do not seem to be economical either in once-through applications even though they are effective in brines. Current interest in oxygen corrosion inhibition appears to be centered on variations of the zinc phosphate approach involving organic components and in other materials of a completely organic nature.

Generally, techniques applicable to water flood corrosion inhibition are the same as those for primary production-to establish, on the metal surfaces, an adsorbed film of an organic compound or compounds which will moderate the attack. In addition, because the same weak acids are found in both environments, it is logical to assume that the same kinds of compounds should be effective in both applications. To a degree, this is true. However, absence of an oil phase in waterfloods introduces two significant differences. In a water flood, the most persistent inhibitors (high molecular weight, oil-soluble, filming, polar organics) cannot be used because they are insoluble in the flood water. Secondly, the effectiveness of the inhibitor film cannot be augmented by formation of an overlying oil layer as is the case when an oil phase is present.(2) Both of

Anodic Reactions In anodic control of corrosion, passivation is by far the most important phenomenon. It is this phenomenon that is responsible for the corrosion resistance of stainless steels and innumerable other alloys. While metals such as iron and steel may also be passivated, the conditions required for

(1)rnjection of water containing a few percent weight of a high molecular weight polyacrylamide which alters the viscosity properties is used with the intent of creating a more effective distribution of flood water into the formation.

(2)For instance, Briggs and Radd60 found that the addition of a hydrocarbon phase to sour brine lowered the required inhibitor concentration from 25 to 5 ppm.

80

these factors tend to reduce inhibitor effectiveness in the

The tendency of an inhibitor to adsorb is affected by the nature of its polar group21 or groups,23 but not as much as might be expected. Thus, in IN sulfuric acid, adsorption of C6 amines > C6 carboxylic acids> C6 alcohols at low degrees of coverage. However, at higher coverages and with higher molecular weight homologues, no consistent pattern is maintained?4 For a more detailed discussion of these effects, the reader is referred to the chapter on fundamentals. Inhibitor film stability is determined by the interplay of a number of factors involving both the hydrophobic hydrocarbon chain and the polar portion or portions of the inhibitor molecule. In general, changes in the hydrophobic portion of the molecule that promote water solubility, tend to decrease film stability also. Thus, branching25 and reducing chain lengths20,2 4,26 reduce inhibitor effectiveness. This conflict between solubility and film stability is one of the basic obstacles to be overcome in formulating an effective water soluble inhibitor. On the other hand, use of a strongly adsorbing polar group or more than one such group per molecule, tends to promote inhibitor film stability. So does polymerization of an inhibitor molecule.2 7-2 9 Hydrogen bonding or other interactions among adjacent adsorbed molecules also can be used to enhance film stability. Water compatibility problems arise when ions in the flood water combine with the inhibitor to form inactive

single phase aqueous systems of water floods. These effects, however, tend to be offset by the lower temperatures and generally lower acid concentrations prevailing in water floods. Acid concentrations are usually reduced by venting acid gases before produced water is fed into the repressuring system. The net effect is that inhibitor concentrations in water floods often are lower than those in producing wells. A review of recommendations by a number of suppliers of inhibitors shows that recommended inhibitor concentrations for water floods range from 5 ppm, or more generally, 10 to 25 parts per million. Recommendations for oil production inhibitors range from about 5 or 10 ppm to as much as 50 to 60 ppm. One supplier recommends two inhibitors for both oil production and water floods. This manufacturer suggests that either material should be used in water floods at concentrations of 10 to 20 ppm and for oil production, at 5 to 40 ppm. these recommendations are, of course, based on total handled. To put on the basis of oil produced, flood efficiency or gas oil ratio and other factors discussed C. Nathan22 would have to be taken into account.

All of fluids sweep by C.

In an inhibitor to be used in aqueous systems to control attack by weak acids, a balance must be reached among a number of competing influences. These include solubility-or at least dispersibility-so that the inhibitor can be effectively transported from injection points to the surfaces needing protection. On the other hand, many techniques used to achieve good transport properties tend to lessen inhibitor effectiveness and/or persistence. For instance, use of shorter alkyl chain lengt11s:2

% by Gas Chromatographic

-8 a08u

u

u

'Qj

Tall Oil

Analysis(1)

60-70% Fatty Acids,

30-40% Rosin Acids

Rosin ACids(2)

Abietic

Acid 25-35%

Remaining

Resin Acids are Abietic

x x xtionion 2-12 7-13 1 Isomerizat tion % 12-17 3-13 2-12 10-14 MethylaHydrogenation

x

Dehydrogena-

Acid Derivatives x

Shown

Below

Modification

Bond

(I)Emery industries, Specifications and Characteristics of Fatty Acids. (2)See Reference 63.

The polyamines in these mixtures patented by P. W. Wolk and F. T. Bobalek36 are N, N"-(hexachlorobisphenylene) bis(diethylenediamine) and I, I' -(hexachlorobiphenylene) -bis(diethylenetriamine). In an 18 hour test at 80 C (175 F), 20 ppm of a 5 to 20 percent bis-amine content mixture gave 70 percent inhibition in a sour 5 percent sodium chloride brine containing 0.25 percent acetic acid. In a German patent by E. Haarer, E, Fuerst and G. Nottes,37 two partially amidized polyamines are used. One,

corrosion inhibitor which can be represented schematically as follows:

R-O-I LC-?-OH C-NR'R" J 1-5 The primary inhibitor was effective when used alone in a rotating bottle test in a sour 5 percent sodium chloride brine. Ten parts per million gave 80 to 85 percent inhibition in a 24 hour test at 38 C (100 F). To match this performance in a sweet brine, it was necessary to add a polyethoxylated carboxylic acid (Tall oil acids with 10 to 25 ethoxy groups per molecule are an example). A small amount (I to 10 percent) of free fatty acids (C 16 -C 18 preferably) was added to complete the final formulation. Substitu ted polyamines have been used in synergistic mixtures with compounds of the formula

the diamide from oleic acid and methyldipropylenetriamine, is ethoxylated (30 to 60 ethoxy units per mole of amide) and then neutralized with phthalic anhydride. The other, from sperm oil acid and diethylene triamine, is neutralized with propionic acid. The ethoxylated product with an oil-soluble acetylenic compound(e.g., ethynylcyc1ohexanol) inhibits acid corrosion, but in the preferred embodiment, the diamide propionate accounts for about 90 percent of the active ingredients.

CH3(CH2)n X (CH2)mNH2 where n = 7 to 13 X = S or 0 and m = 2 or 3.

Imidazolines with both straight and branched alkyl chains are usually employed as their acetate salts. Often the R' group (see Table I) is C2H4NH2. 83

Quaternaries appear in a variety of guises in waterflood inhibitor formulations. Common combinations are dicoco-

barrier, only a modest amount of mixing is required to assure that the oxygen concentration at the membrane exterior is representative of that in the bulk solu tion. 4, Thus, the electrical current required to reduce the oxygen on the inert electrode is proportional to the bulk oxygen concentration.

dimethyl quaternary ammonium chlorides mixed with soya or tallow trim ethyl quaternaries. In another Instance, a benzyl-containing quaternary chloride is mixed with a nonionic dispersant and a polyethoxylated isooctyl phenol type of surfactant. Quaternaries of partially amidized polyamines have been discussed previously where these compounds appear as a part of formulations containing other types of nitrogen compounds.

Calibration by measuring the current at a known oxygen concentration (usually achieved by saturation with air) can then be used to put the readings on an absolute basis. Probes of this type are usually rugged and reliable but do require a certain amount of care such as periodic renewal of electrolyte and intelligent application. With respect to application precautions, it is necessary to make sure that the principles involved in the operation of these instruments are not being interfered with in some manner. Thus, traces of residual oil or sludge can build up on probe membranes, blocking oxygen diffusion and causing erroneously low readings. Also, exposure to a sulfide environment can lead to such a reduction in sensitivity that grossly low readings will result in a matter of hours.

Oxygen Corrosion Control As discussed earlier, prevention of oxygen corrosion of steel lines carrying flood waters is usually effected by removing the oxygen. When oxygen levels are low, as can be the case when produced water is imperfectly protected, a simple oxygen scavenging step will usually be the most economic route. However, when surface or other waters with oxygen concentrations approaching saturation (6 to 8 mg/I) are used, it is often advantageous to reduce the oxygen concentration to 0.3 to 0.5 mg/l by gas stripping before the oxygen scavenging step. Inhibition is a competing technique for controlling oxygen corrosion. It was investigated at length in early waterfloods bu t was generally eclipsed by oxygen scavenging alternatives. However, interest in inhibition has been renewed recen tly. In analyzing a corrosion problem where oxygen is suspected, a reliable analytical technique is necessary. Tests for traces of oxygen can be made by something as simple as a partially shielded wire in an electrical circuit used to detect crevice corrosion.38 However, diagnostic work and oxygen monitoring usually call for something more sophistica ted. Polarographic type probes widely used for these tests have a number of advantages over chemical analyses such as the Winkler method. First, errors due to leakage during sampling can be avoided by putting the probe directly in the flowing stream or in a sidestream. When dealing with fractions of a part per million, in situ measurement is almost mandatory. Secondly, response of polarographic type oxygen probes is essentially instantaneous and, being electrical, it can be readily observed and converted into a permanent record. Finally, sensitivity in the range of a few parts per billion can be achieved; however, 10 ppb (0.01 ppm) is more normal. Oxygen probes available from a number of manufacturers(7) operate according to a common set of principles: I. Oxygen diffusing through an inert membrane is reduced electrochemically as fast as it arrives at an inert electrode.

Gas Stripping

Gas stripping is a simple operation wherein the flood water is brought into intimate contact with an oxygen-free gas in such a way that most of the oxygen is removed with the exit gas stream.39,40 Countercurrent contacting (usually in a packed column of rubber lined steel) is the most efficient way to use the stripping gas. However, concurrent contacting has also been used.41 Using this method, Lake Maraicaibo, Venezuela water was stripped to about 0.5 mg/l in gas lifting. 4 2 Gas stripping can also be used to reduce the concentration of dissolved acid gases and their precursors. Doscher and Tuttle43 have discussed removal of hydrogen sulfide from sour brine. Slight acidification will convert the ionic sulfide and carbonate species into their respective molecular forms which then can be readily stripped from the solution. Neutralization is then normally used to prevent subsequent acid corrosion. The two commonly used stripping gases are natural gas and its combustion products. The latter, made either by a special burner arrangement leaving no residual oxygen or in an inert gas generator, has the advantage of providing about nine times the volume of stripping gas as its natural gas precursor. The reaction is

2. With the oxygen concentration thus kept at zero inside the membrane, the rate of oxygen diffusion is proportional to its concentration outside the membrane. 3. Because the membrane is a considerable diffusion

A further advantage of the combustion product gas over natural gas is that natural gas purchased from a transmission line may contain air. Such air is sometimes added to natural gas before delivery to gain maximum volume while maintaining the minimum fuel value specified in sales contracts.

(7)EqUipment manufactured by Magna Corp., Santa Fe Springs, Ca!.; Petrolite Corp., SI. Louis, Mo.; Beckman Instruments, Inc., Fullerton, CaI.; and possibly others.

Oxygen Scavenging Sulfite is presently the most common oxygen scavenging agent for water and stream floods. It is available in a 84

some cases, sufficient catalytic metallic ions are present initially in the brine, but more typically, a catalyst must be added to achieve a satisfactory scavenging rate. Normally, 0.1 mg/l of cobaltous ion derived from either the sulfate or chloride salt is adequate. The ion may be incorporated conveniently into the concentrated sulfite scavenging solution either by addition of the appropriate salt or by using a proprietary product that includes the catalyst. If a nominal 0.1 mg/l Co2+ does not provide complete oxygen scavenging in a few minutes, some interfering factor undoubtedly is present. In a location such as Cook Inlet, Alaska this interference could be nothing more than slowing of the reaction by low temperatures. More typically, the interference could be due to sulfide present in the water initially or produced by the growth of sulfate reducing bacteria. Control of sulfate-reducing bacteria is discussed elsewhere (see in this book, Sharpley, Piluso) and scavenging in sour waters is discussed below.

number of chemical forms that may be used interchangeably if their differences in equivalent weight and solution pH are taken into account. A choice among the three most common forms-sodium sulfite, sodium metabisulfite (Na2S2 05) and sulfur dioxide-is usually based on cost and availability. However, other considerations do enter into the decision. Sulfur dioxide may be fed directly into the flood water while with the salts, concentrated solutions must be made up and metered in. These sulfite solutions must be isolated from the atmosphere to prevent their being depleted before use. When using metabisulfite, a further precaution is necessary. When it is dissolved in water as indicated in the following reaction,

S20t

+ H20 = 2HS03- = 2H+ + 2S03=

(13)

it hydrolyzes to bisulfite ion, a relatively strong acid. An organic coating is usually used to prevent acid attack on bisulfite storage tanks. The stoichiometry of the overall scavenging reaction with anhydrous sodium sulfite Na2S03 + 1/2 O2

(aq) = Na2S04

Other possible interferences with scavenging such as catalyst complexing and free radical chain terminating agents were discussed previously. Cobalt can also be made less effective by low pH environments such as might arise when sulfur dioxide is used as a source of sulfite. This results from cobalt's decreasing catalytic effectiveness (in the sulfite-oxygen reaction) with decreasing pH. Filtration before complete scavenging or air leakage downstream of filters can also lead to incomplete oxygen removal, even when an adequate surplus of sulfite is present. Both observations, plus the pH effect, indicate that scavenging catalysis by cobalt is heterogeneous, i.e., due to a colloidal hydroxide. Complications Encountered in Sour Systems are due primarily to catalyst inactivation by sulfide precipitation. This complicates the normally straightforward scavenging step to such an extent that all alternative approaches should be examined seriously: Can gas blanketing and proper pump maintenance64 adequately exclude oxygen? Can an alternative source of water be found?

(14)

shows 8 parts by weight of sodium sulfite are needed per part of oxygen. However, an excess is needed to aid in removing the last traces of oxygen at a practical rate, to compensate for fluctuations in flow rates and reactant concentrations and to take care of oxygen leakage subsequent to the initial scavenging. Because of these effects, the recommended sulfite excess varies with initial oxygen concentration. With a fully saturated brine that could have on the order of 8 mg/l of oxygen, 80 mg/l of sodium sulfite (an excess of 25 percent) would normally suffice. On the other hand, waters with oxygen concentrations on the order of 0.5 mg/l could easily require 10 mg/l of sulfite, or a 150 percent excess. Normal oil field practice is to maintain an excess of 10 ppm sodium sulfite. In instances when both general corrosion due to acid and pitting due to oxygen are simultaneously encountered, both a filming amine inhibitor and an oxygen scavenger may be required. One approach is to utilize an amine (or imadazoline) salt of sulfurous acid to do both jobs. Such a material may be formed in situ by adding the basic nitrogen inhibitor and sulfite to the flood water separately as recommended by P. J. Raifsnider and L. K. Gatzke44 who suggest 10 to 100 ppm inhibitor plus 5 to 150 ppm of alkali metal sulfite. AIternatively, a concentrate may be prepared from a cyclic amidine(imidazoline or pyrimidine4S)or from a straight chain polyamine46 prepared in an alcohol solvent and conveniently added as a single, easily handled solution. Successful application of such a material compounded from oleyl diamine to brine disposal wells has been reported by Dunlop, Raifsnider and Howard.3 0 Catalysts required for the oxygen·sulfite reaction may vary considerably from flood to flood. In any case, some form of catalyst is necessary at ambient temperatures.(8) In

Can the one being used be freed of hydrogen sulfide by gas stripping or through use of biocides active against suifate reducing bacteria? Another alternative is the use of corrosion resistant materials in pumps, valves and other mechanical equipment, cement-lined distribution lines and coated tubing. Mechanical damage leading to rapid pitting of tubing is the greatest drawback to the latter alternative. Another possible alternative, which to the author's knowledge has not yet been adequately assessed, is use of an oxygen corrosion inhibitor in a sour system along with (if necessary) an acid inhibitor to handle the direct effects of hydrogen sulfide. However, due to the reaction between hydrogen sulfide and oxygen which produces elemental sulfur (which is still a corrosive and difficult to inhibit), this may not be a fruitful line of attack. See discussion of catalysis of hydrogen sulfide-oxygen reaction, herein. Scavenging Oxygen from Sour Water-A number of techniques are available to scavenge oxygen from sour

(8)This can be demonstrated easily by adding EDT A to a naturally catalyzed water; this chelant will tie up the catalytic ions and halt the reaction.

; ;

i

8S

~

floods by inhibition-in contrast to physical or chemical removal of the oxygen-drew directly on typical cooling water treatment techniques. Using a soluble zinc salt and a glassy phosphate, Hatch and Ralston49 achieved effective inhibition in laboratory tests at the 10 to 20 ppm level in fresh water and dilute brines. Requirements increased to 25 ppm in 5 percent brine and to 50 ppm in 10 percent brine. In field tests with potable or nearly potable water, 6 to 12 ppm of inhibitor sufficed. Inhibitive action in this technique relies on deposition of a film formed from calcium originally in the water and the added glassy phosphate. Zinc enhances this film-forming tendency so that less phosphate is required for a given level of inhibition. Another approach patented by Farriss50 calls for the use of 13 ppm of zinc chromate in a 5 percent sodium chloride brine containing oxygen. Sulfide in the water interferes with both of the two

water. If only a trace of hydrogen sulfide is present, a stoichiometric excess of cobalt ion can be used to precipitate the sulfide and leave enough excess to catalyze the scavenging reaction.! 5 For example, 0.25 mgfl of hydrogen sulfide would require about 0.5 mg/l of cobaltour ion to leave 0.1 mg/l as a catalyst. The added cost of cobalt and solids introduced into the system are obvious disadvantages of this approach. Alternatively, catalytic ions such as those of iron or manganese which have more soluble sulfides can be used. However, the catalytic effectiveness of these ions in the sulfite-oxygen reaction is much less than that of cobalt, so both higher concentrations and longer reaction times may be required. A new approach is the use of a reaction initiation mechanism which does not depend on catalytic metal ions. In this technique,47 patented by the author, a peroxide such as tertiary butyl hydroperoxide (TBHP) is used to initiate scavenging via Reaction (5), where, in this instance, R· repres~nts t-BuO' or 'OH, probably formed by thermal fission of the peroxide bond. At modest sulfide concentrations, this technique works quite well. In an air saturated water with 10 ppm sulfide, an initial scavenging rate of about 65 percentfminute can be achieved at ambient temperatures with 125 mg/l of sodium sulfite and 25 mgfl of TBHP or with 250 mg/l of sodium sulfite and 5 mg/l of TBHP.

preceding inhibition schemes (it precipitates the zinc ion) and, in addition, organics can interfere with the zinc chromate method by reducing the chromate to noninhibitive chromic ions. Organic Inhibitors-Two organic inhibitors for oxygen corrosion in flood waters have been reported recently. One, by Hatch and Ralston,S is logical successor to their inorganic zinc-phosphate treatment. An aminomethylenephosphonate (AMP) replaces the glassy phosphate of their earlier inhibitor combination. The simplest member of the series

At higher sulfide concentrations, however, another factor enters. Sulfide itself becomes significant as a free radical chain stopper via Reaction (10), and reagent requirements increase. With 100 ppm sulfide, a comparable scavenging rate requires the use of higher concentrations in each case, e.g., 250 mgfl sodium sulfite coupled with 25 mg/l TBHP. Still another approach is the use of sodium hydrosulfite (dithionite). Because dithionite provides its own chain reaction initiators, it appears highly likely that it, too, can be used in sulfide systems. Thus, dissociation to give two radical ions

performed as well as higher homologues. These organic phosphonates share many of the properties of the inorganic polyphosphates but are more resistant to hydrolysis (reversion to monomeric phosphates) and retain their effectiveness as inhibitors at pH levels up to 8.5, whereas the polyphosphates falter at pH levels appreciably above seven. Field tests with a 40:60 aminomethylphosphonate-zinc ratio achieved corrosion control with very low treatment levels. Two to three mg/l of AMP-zinc sufficed in both a hard bicarbonate water containing 6 mgfl oxygen and in a high carbon dioxide water (160 mg/I) containing 2 mgfl oxygen. In a hard, brackish water (7800 mg/I CI-) containing 7 mg/I oxygen, 4 to 5 mgfl of AMP-zinc were required. The AMP-zinc treatment is also reported to be useful for scale control. 5 I Patents underlying the work reported have been issued variously to Hatch, Ralston, and Park.5 2-5 4

(15) is consistent with the kinetic study of the air oxidation of dithionite described by R. G. Rinker et al. 4 8 The work of Snavely and BlountI4 opens up yet another possible approach, namely that of using hydrogen sulfide as the scavenging agent. They found that oxygen in an approximately neutral 3.5 percent sodium chloride brine is almost completely consumed according to Equation (16)

The other newly reported material is entirely organic. Martin, Annand, Wilson and Abrahamson55 indicate that

(16) in about 200 ppm elemental produce refrained

application of an "organic sulfophosphate" to sour gas gathering systems contaminated with oxygen can markedly lower corrosion rates. In the four years before treatment was started in one system, average corrosion rates measured by Corrosometer(9) probes installed in a line carrying 0.2 to 0.6 percent oxygen along with about 1 percent hydrogen sulfide and 0.25 percent carbon dioxide were 15 to 35 mils

a minute in the presence of 5 ppm nickel ion and hydrogen sulfide. However, as mentioned before, sulfur is itself corrosive, so this approach may not a satisfactory solution. The authors, themselves, from a positive recommendation of the technique.

Inhibition of Oxygen Co"osion Early approaches to oxygen corrosion control in water

(9) A tradename of the Magna Corp., Santa Fe Springs, Cal.

86

a year when conventional inhibition methods were being used. Injection of 0.5 gal/day of the sulfophosphate inhibitor lowered the average rate during the next year to about 5 mlls a year. Short term rates with no inhibition were as high as ISO mlls a year. This organic sulfophosphate has the advantage of being primarily an anodic inhibitor so that it does not tend to aggravate pitting if used too sparingly. Successful use in waterfloods at about 15 ppm is reported, but it is most effective in the presence of some hydrocarbons. Thus, in a laboratory test in an air saturated 5.8 percent mixed brine at 77 C (170 F), 1000 ppm of organic sulfophosphate dropped the corrosion rate from 120 to 12 mlls a year. On the other hand, 70 ppm of the inhibitor plus 2 percent mineral spirits brought the rate down to about 2 mils a year. Alone, 70 ppm of sulfophosphate only dropped the rate to about 70 mlls a year. This material is dispersible rather than soluble in water and is said to inhibit better

to be taken into account in assessing the practicality of the various alternatives. For corrosion caused by CO2 and H2S, inhibitors of the filming type are normally the best choice. In this application, the inhibitors are usually water soluble or water dispersible. For strong acids such as might be produced by in situ combustion, neutralization, corrosion resistant materials or use of pickling or other strong acid inhibitors should prove to be effective. When both acids and oxygen are present, measures appropriate for the control of each type of corrosive are needed; and care should be taken to assure that the measure used are compatible.

References 1. C. C. Wright. Corrosion Control in Large Volume Pumping Brine Wells, Mat. Pro. & Prot., 11, No. 1,23 (1972) Jan. 2. 1. D. Sudbury et al. Conditioning of Pacific Ocean Water for Waterflood Injection,Petro. Trans. A/ME, 207,322 (1956). 3. Kinney Handcock and L. H. Lochte. Acidic Constituents of a California Straight Run Gasoline Distillate, JACS, 61, 2448 (1939). 4. R. F. Weeter. Dissolved Oxygen Control in Injection Water, Mat. Pro., 11, No. 8,29 (1972) Aug. 5. G. B. Hatch and P. H. Ralston. Aminomethylenephosphona'tezinc Mixtures Control Oxygen Corrosion, Mat. Pro. & Pert, 11, No. 1, 39 (1972) Jan. 6. N. G. Haseltine and C. M. Beeson. Steam Injection Systems and Their Corrosion Problems, Mat. Pro., 4, No. 10,57 (1965). 7. E. W. Wallace, J. A. Pryor, B. W. Bradley and G. H. Holliday. Use of Low-Grade Steam and (Unseparated) Blowdown in an Oil Production Method, U.S. Patent 3,193,009, July 6, 1965. 8. E. W. Wallace, et al. Use of Recombined Steam Plus Blowdown in an Oil Production Method, U.S. Patent 3,237,692, March I, 1966. 9. Noel De Nevers. Carbonated Water Flooding-Is It a Laboratory Success and a Field Failure? World Oil, 163, No. 4,93 (1966). 10. S. M. Faroug AIL A Current Appraisal of In-Situ Combustion Field Tests, J. Petro. Tech., 24,477 (1972). 11. A. K. Dunlop. Using Corrosion Inhibitors, Chem. Eng., p. 108 et seq., October 5, 1970. Theory and Use of Inhibitors, Proc. W. States Corrosion Seminar, W. Reg. NACE, Sept., 1970. 12. G. Kar, I. Cornet and D. W. Fuerstenenau. Effects of Alkyl Amine Surfactants on Mass Transfer Controlled Corrosion Reactions,J. Electrochem. Soc., 119,33 (1972). 13. K. J. Laidler. Chemical Kinetics, McGraw-Hill Book Co., N.Y., p 339-341 (1950). 14. E. S. Snavely and F. E. Blount. Rates of Reaction of Dissolved Oxygen with Scavengers in Sweet and Sour Brines, Co"osion, 25, 397 (1969). 15. C. C. Templeton, S. S. Rushing and Jane C. Rogers. Solubility Factors Accompanying Oxygen Scavenging with Sulfite in Oil Field Brines, Mat. Pro., 2, No. 8,42 (1963) Aug. 16. Ref. 13,p. 338. 17. W. A. Pryor. Mechanisms of Sulfur Reactions, McGraw·Hill Book Co., N.Y., p. 90, Eq. (3-129) (1962). 18. H. Kallfass. Inhibiting Oxygen Corrosion with Hydrazine plus a Quinone, U.S. Patent 3,551,349, December 29, 1970. 19. Anonymous. T-3F (NACE) Bibliography on Corrosion Inhibitors for High Purity Water, Co"osion, 19, 26t (1963). 20. R. J. Meakins. Alkyl Quaternary Ammonium Compounds as Inhibitors of Acid Corrosion of Steel, J. Applied Chem., 13, 339 (1963). 21. P. F. Cox, R. L. Every and O. L. Riggs, Jr. Study of Aromatic Amine Inhibitors by Nuclear Magnetic Resonance, Co"osion, 20, 299t (1964). 22. C. C. Nathan. Correlations of Oil-Soluble, Water-Dispersible

when hydrogen sulfide is present in addition to oxygen. 1t is interesting to note two other types of organic corrosion inhibitor of oxygen corrosion-even though they have apparently not been applied to secondary recovery systems. L. W. Jones and J. P. Barrett,S 6 while seeking a remedy for combined oxygen-hydrogen sulfide corrosion, developed amine-"oxygenated petroleum acid" complexes which were effective at 50 to 100 ppm concentrations in laboratory tests. Successful field tests also were made in rod-pumped wells and in a wet (25 percent air contaminated) gas gathering line. The diamine used in the final formulation undoubtedly supplied acid inhibition and the organic petroleum acids (pure long-chain carboxylic acids were effective also) were the effective agents in combatting oxygen corrosion. A mode of operation similar to that of "soluble oils"s 7,58 (petroleum sulfonates in oil) is probably involved. Chelating agents form another class of compounds which could give rise to inhibitors useful for combatting oxygen corrosion. Such complexing agents can accelerate corrosion under some conditions, but recent work by Weisstuch, Carter and Nathans9 has shown that other less common chelating agents such as long chain pyrocatechols and sarcosines can give over 90 percent inhibition in laboratory cooling water tests when used at a concentration of 100 ppm. Further development could possibly lower the treatment level to one which would be practical for waterflood use.

Summary The first step, as in attempting the solution of any corrosion problem, is to identify the corrosive, or corrosives, responsible. Normally, either oxygen or weak acids will be the causative agent. Occasionally, elemental sulfur or strong acids might also be found. If oxygen is the corrosive, exclusion should be the first consideration. If this is impractical, the alternatives are removal by stripping and/or scavenging, use of corrosion resistant materials including coatings and linings and use of inhibitors expressly for oxygen caused corrosion. If hydrogen sulfide is also present, the attendent complication~ need

87

23.

24.

25.

26.

27.

28. 29.

30.

31.

32.

33.

34.

35. 36.

37.

38. 39. 40.

41.

42. Personal Communication, 1. N. Klinge, CSV. 43. T. M. Doscher and R. N. Tuttle. Preparation of a Subsurface Injection Water from a Sour Brine, World Oil, 160, March 1, 1955. 44. P. J. Raifsnider and 1. K. Gatzke. Amine Plus Sulfite for Inhibition of Acid and Oxygen Corrosion in Water Floods, V.S. Patent 3,119,447. 45. P. J. Raifsnider. Alkylcyc1ic Amidine-S02 Adducts for Acid-02 Corrosion Inhibition, V.S. Patent 3,502,579, March 24, 1970. 46. P. J. Raifsnider. Polyamine-S02 Adduct for Acid-02 Corrosion Inhibition, V.S. Patent 3,412,157. 47. A. K. Dunlop. Peroxide Initiation of Sulfite Scavenging in Sour Waters, V.S. Patent 3,634,232, January 11, 1972. 48. R. G. Rinker, et al. Kinetics and Mechanism of the Air Oxidation of the Dithionite Ion (S204=) in Aqueous Solutions, J. Phys. Chem., 64,573 (1960). 49. G. B. Hatch and P. H. Ralston. Oxygen Corrosion Control in Flood Waters, Mat. Pro., 3, No. 8, 35 (1964) August. 50. R. E. Farriss. Prevention of Corrosion of Iron by Aqueous Brines (by Vse of ZnCr04), V.S. Patent 2,695,876, November 30, 1954. 51. P. H. Ralston. Scale Control with Aminomethylenephosphonates,J. Petro. Tech., 21, 1029 (1969). 52. G. B. Hatch. Inhibiting (Oxygen) Corrosion with Zinc SaltMethanol Phosphonic Acid Derivative Combinations, U. S. Patent 3,532,639, October 6, 1970. 53. P. H. Ralston. Amine Phosphonate Scale Inhibitor, V.S. Patent 3,393,150, July 16, 1968. 54. G. B. Hatch, A. Park and P. H. Ralston. Method of Inhibiting Corrosion with Aminomethylenephosphonic Acid Compounds, V.S. Patent 3,483,133, December 9,1969. 55. R. 1. Martin, R. R. Annand, Dale Wilson and W. E. Abrahamson. Inhibitor Control of Oxygen Corrosion: Application to a Sour Gas Gathering System, Mat. Pro. and Perf, 10, No. 12,33 (1971) December. 56. 1. W. Jones and 1. P. Barrett. Laboratory Development of Corrosion Inhibitors, Corrosion, 11, 217t (1955).

Corrosion Inhibitors in Oil Field Fluids, Corrosion, 18, 282t (1962). F. M. Donahue and K. Nobe. Theory of Organic Corrosion Inhibitors-Adsorption and Linear Free Energy Relationships, J. Electrochem. Soc., 112,886 (1965). Z. Szklarska-Smialowska and G. Wieczorek. Adsorption Isotherms of Mild Steel in H2S04 Solutions for Primary Aliphatic Compounds Differing: in Length of Chain, Cor. Se., 11, 843 (1971). V. 1. Stromberg. Effects of Structural Change on the Inhibitor Effectiveness of Amido Acids, Mat. Pro., 4, No. 4, 60 (1965) April. N. Hackerman, R. M. Hurd and R. R. Annand. Some Structural Effects of Organic N.containing Compounds on Corrosion Inhibition, Corrosion, 18, 37t (1962). R. R. Annand, R. M. Hurd and N. Hackerman. Adsorption of Monomeric and Polymeric Amino Corrosion Inhibitors on Steel,!. Electrochem. Soc., 112,138 (1965). Op. cit., p. 144. Inhibition of Acid Corrosion by Soluble Monomer and Polymer Nitrogen Containing Inhibitors. R. R. Annand, D. Redmore and B. M. Rushton. Vse of Heterocyclic Polymers as Corrosion Inhibitors. V.S. Patent 3,514,251, May 26, 1970. A. K. Dunlop, R. 1. Howard and P. J. Raifsnider. ODASA: Oxygen Scavenger and Inhibitor, Mat. Pro., 8, No. 3, 27 (1969) March. A. G. Ostroff. Polyphosphate-ethoxylated Amine Mixture for Scale and Corrosion Inhibition, V.S. Patent 3,412,025, November 19, 1968. W. M. Budde, Jr. and J. W. Sigan. Salts of Ether Diamine for Corrosion Inhibition in Oil-Water and Aqueous Systems, V.S. Patent 3,404,165, October 1, 1968. 1. P. Barrett and E. E. Clay tor, Jr. Laboratory Flow Test for Evaluation of Oil Well Corrosion Inhibitors, Corrosion, 18, 277t (1962). 1. W. Jones. Amine Salts of Boric Acid-polyol Complexes for Oxygen and Acid Inhibition and Biocide, V.S. Patent 3,373,170. James R. Stanford. Inhibitor for Oxygen-free Flood Waters, V.S. Patent 3,424,681, January 28, 1969. P. A. Wolf and F. J. Bobalek. Synergistic Amine Mixtures for Inhibition of (Acid) Corrosion in Aqueous Systems, V.S. Patent 3,524,719, August 18, 1970. E. Haarer, E. Fuerst and G. Nottes. Inhibitor for Oil Field Brine and Water Flooding, Ger. Pat. 1,192,905; CA., 63,9629 b (1965). P. J. Raifsnider and A. Wachter. Pitting Corrosion by Water Flood Brines, Corrosion, 17, 325t (1961). F. M. Brewster, Jr. et al. The Deaeration of Water with Natural Gas, Prod. Mo., 18, July, 1955. R. F. Weeter. Desorption of Oxygen from Water Vsing Natural Gas for Countercurrent Stripping, J. Petro. Tech., 17, 515 (1965) May. H. G. Bosma. Petro. Eng., 41,64, Dec. 1969.(10)

57. J. I. Bregman. Corrosion Inhibitors, McGraw-HiIl Book Co., N.Y., p. 143. 58. V. R. Evans. The Corrosion and Oxidation of Metals, Edw. Arnold, Ltd., London, 1960; St. Martin's Press, Inc., N.Y., p. 169 (1960). 59. A. Weisstuch, D. A. Carter and C. C. Nathan. Chelation Compounds as Cooling Water Corrosion Inhibitors, Mat. Pro. and Perf, 10, 11 (1971). 60. O. 1. Riggs, Jr. and F. 1. Radd. Physical and Chemical Study of an Organic Inhibitor for Hydrogen Sulfide Attack. Corrosion, 19, It (1963) January. 61. G. J. Pierotti, C. A. Deal and E. L. Derr. Activity Coefficients and Molecular Structure, [nd. and Eng. Chem., 51,95 (1959). 62. Lewis and Randall. Thermodynamics. Revised by K. S. Pitzer and Leo Brewer, 2nd Ed. McGraw-Hill Book Co., Inc., N.Y. (1961) page 227. 63. T. Lloyd-Jones. Corrosion Inhibitors, Cor. Prev. and Control, p. 11, (1966) August. 64. L. C. Case. Oxygen Traces May be Corroding Your Waterflood Piping, Oil and GasJ., (1964) January 13.

(10)Readers are cautioned against taking advice to inject floodwater containing about 0.5 ppm oxygen; serious corrosion ~roblems were encountered soon after publication of this article. 2

88

Control of Internal Corrosion of Pipelines Carrying Refined Petroleum Products*

IVY M. PARKER*

Introduction

contemplating use of an inhibitor. One operator 7,8 reported that sodium sulfite had been used as an oxygen scavenger from 1936 to 1941 and then an inhibitor was applied. In the late forties, an interest began to develop in use of oil soluble polar compounds as adsorption corrosion inhibitors in products pipelines. The first to be employed was a sulfonated mahogany oil.9 Then followed complex carboxylic acids, amines, etc. The sulfonic, carboxyl or amine group makes the compound polar and provides for selective adsorption on the steel. Such materials must have a high molecular weight and proper molecular structure to function as inhibitors. (See chapter on theoretical aspects.) A surveylO of inhibitor practices made in 1954

History The first products pipeline was operated in 1893,1 but the industry really began to develop in 1929 when Tuscarora Pipe Line Company, Ltd., converted a crude line to product service. In the next two years, Great Lakes Pipe Line Company, Atlantic Refining Company, Phillips Petroleum Company, So cony Mobil Oil Company, Inc. and Sun Oil Company placed many miles of pipeline in product service. By 1934, the problem of internal corrosion was recognized as a serious factor in causing roughness of internal surface and reducing capacity of these pipelines. An informal meeting to discuss internal corrosion was held by pipeline operators in St. Louis in the summer of 1935. Research and development programs were started to develop means for controlling internal corrosion. Scraper programs were started to remove the encrustations and to partially restore capacity. Atlantic Refining Company2 began experimentally injecting a water solution of sodium chromate in the Keystone-Buffalo system as a corrosion inhibitor in 1935; Socony Vacuum Oil Company3 built its first dehydrator in 1936; Phillips Petroleum Company4 reported on use of an oil soluble inhibitor, mercaptobenzothiazole, in 1939. Shell Oil CompanyS followed with use of buffered sodium nitrite. An API Subcommittee on Internal Corrosion of

TABLE 1 - Solubility of Water in Gasoline! 2 Solubility Gal/1000 Bbl

Products Pipe Lines was organized in May, 1941. A survey6 made that year showed thirteen companies operating products pipelines each of which was over 200 miles long. One pipeline was using dehydration, three were using Benzene Butene-l mercaptobenzothiazole, two 24.8 were experimenting with n-Pentane n-Hexane n-Octane Isobutane Cyclohexane Heptene-l Isopentane n-Heptane Hydrocarbon addition of sodium sulfite n-Butaneas an oxygen scavenger and four were using scraper programs to control internal corrosion. A survey of industry practices made in 19467 covering eighteen companies which were operating products pipelines showed that two pipelines were using mercaptobenzothiazole, four were using sodium chromate, six were using sodium nitrite and seven were not using any inhibitor. One of the latter dehydrated its products and three were

*

Tx., formerly Co., Atlanta, Ga.

Corrosion

Engineer,

Plantation

2.1 2.4

2.7

3.0 3.3 3.6 4.0

,

68.06.5 1IGal/1000 1.1 11.1 66.26.9 68.0 68.09.4 0.0 3.3 20 20.5 19 15 Bbl 312.0 9.7 4.2 68.9 2.6 1.6 3.2 30.8 3.6 20 4.2 3.1 76.6 1.7 16.1 °c mg/100g I 2.4 OF104.7 TABLE 259.06.1 -43.5 Solubility of Water in Specific Hydrocarbons!

I

Portions of this chapter reproduced by permISSIOn from Petroleum Transportation Handbook. Bell, editor. Sec. 8-Control of Internal Corrosion of Pipelines. Copyrighted 1963, McGraw-Hill Book Co., a Division of McGraw-Hill, Inc., New York, N. Y.

* Austin,

1.8

40 50 60 70 80 90 100 110

Pipe Line

89

Solubility

3

covering twenty-eight operators and some sixty individual pipeline systems showed 20% using dehydration, 33% using water soluble inhibitor (seven, sodium chromate and thirteen, sodium nitrite), 42% using oil soluble inhibitors (six different ones) and 5% using neither inhibitor nor dehydration.

at the lowest temperature of the line. The towers are switched when a specified dissolved water content is reached. The water content of the product is usually determined by titration with the Karl Fischer reagent. 1 5 Various techniques have been developed to reduce contamination of activated alumina and to decrease frequency of regeneration. Water separators are installed ahead of dehydrators to remove free water and fine mesh screen ftlters are often installed to trap fme solids which would tend to coat the alumina and decrease its activity. In spite of protective devices employed, the absorption capacity of the activated alumina decreases with repeated regenerations which necessitates its periodic renewal. Pipelines handling liquefied petroleum gas, propane and butane lend themselves to dehydration because of absence of any additives which may be removed by the alurnina. The Mid-America system was put into operation in 1960 with provisions to dehydrate all products injected into the pipeline by using activated alumina, regenerative-type dehydrators.16,17 The towers are regenerated when the dew point of the product reaches -15 F (-26 C). They employ self-regenerative type, activated alumina dehydrators on loading docks at terminals. 1 7 Ten years of successful operation has been achieved. Dehydration is an effective way to control internal corrosion of a products pipeline. Activated alumina systems require availability of low cost steam, butane, propane or natural gas for regeneration. Dehydration cannot be used on products carrying certain additives such as alcohols or surface active detergents for prevention of icing in carburators. Such materials would be adsorbed by the activated alumina.

Causes of Internal Corrosion Dry refined products with normal additives are noncorrosive to steel pipelines. The products are corrosive because of associated water and air. A film of liquid water adheres to the pipeline surface and oxygen is available from dissolved air in the product. The solubility of air in products varies, but there seems little doubt that refined products carry sufficient oxygen to support corrosion.11 Air is introduced into the products by tank mixers, turbulence, normal tank breathing, etc. Even though the product is clear, indicating absence of free water when it is placed in the pipeline, a temperature drop may occur during transit and cause water to separate. Table 1 shows increasing solubility of water in a gasoline 1 2 as temperature increases. Table 2 indicates the range of solubility 1 3 of water in some pure hydrocarbons. The important factor is the change in solubility per increment of temperature change. From Table 2, a 17 F increase in temperature doubles solubility of water in n-pentane. Other data by Black and co-workers 1 3 indicate a similar change in solubility for other saturated hydrocarbons such as butanes, hexanes, heptanes, etc. The change in solubility of water per degree temperature change is greater for aromatics such as benzene and toluene than for the saturated hydrocarbons. Water is often carried into the pipeline as a separate phase. For example, where conventional floating roof tanks are used, during heavy rains it is difficult to keep water from entering the product while it is being pumped to the pipeline. Covered floating roof tanks practically eliminate rain as a source of water.

Water Soluble Inhibitors Sodium chromate and sodium nitrite are inorganic water soluble salts which act as metal passivators when used in proper concentration in slightly alkaline solutions. All active metals have a natural oxide mm which is more or less protective. Aluminum oxide is especially resistant under many conditions. The oxide f1lm on iron or steel is weak. The chromates and nitrites act to reinforce this ftlm by reacting with exposed bare metal at the breaks in the f1lm. This may be considered a stifling action, since they are anodic inhibitors. Therefore, if insufficient inhibitor is used, corrosion may be intensified in small areas and produce pitting. The maintenance of the reinforced ftlms produced by chromate or nitrite requires a continuous supply of the inhibitor. This is proved by the fact that when completely passivated steel coupons are transferred to inhibitor-free solutions, rusting will start immediately. Experience indicates that much heavier treatment is required to develop a protective f1lm than is required to maintain it. In the case of nitrite, ammonia is produced as a by-product of reaction between the steel and the inhibitor. The consumption rate of nitrite18 is dependent on the amount of corrosion taking place. Thus, a well protected system actually consumes a small amount of nitrite. Many pipelines provide some type of scale and water traps upstream of pumps on lines which have multiple

Methods of Control In ternal corrosion can be controlled by removing one of the active ingredients, water or air; by adding an inhibitor which will make the steel inactive; or using a barrier coa ting on the steel. Dehydration: Processes for Removing Water Water is removed by adsorption on a solid, such as activated alumina, which can be regenerated with heat, or by a disposable, deliquescent material, such as calcium chloride, which liquefies as it absorbs water. Towers packed with activated alumina were first used by Socony-Vacuum Oil Company.3 These were regenerated with superheated steam. Where superheated steam is not available, hot butane or natural gas is employed.14 It is necessary to raise the temperature of the absorption bed well above the boiling point of water to obtain efficient regeneration. A dehydration system is operated to maintain the concentration of the dissolved water below the dew point

90

Washington, D. C. 20025, Attention: PP 4. A list of currently approved inhibitors is available from the same source. At present, the commercial airlines in this country discourage use of any inhibitor in aviation kerosene because of restrictions by at least one engine manufacturer. The general practice for pipelines carrying products with restricted inhibitor requirements is to cut off the injector while these products are passing. There are data22,23 to indicate that the chemisorbed portion of the oil soluble inhibitors maintains protection of the steel for a time even when the products being pumped do not contain the inhibitor. This is not expected with water soluble inhibitors. As noted in the first section, a survey' 0 made in 1954 showed that 42% of sixty pipelines were using oil soluble inhibitors. Some of these operators have published papers The detailing their experience and operation.9,Z4-Z7 general dosage ranges from three to six pounds per 1000 barrels in motor gasolines. A number of inhibitors are effective at a two pound level. Although no new survey has been made, practically all products pipelines, excluding LPG, now use oil soluble inhibitors. Some pipelines carrying LPG are using oil soluble inhibitors in special situations.

pumping stations. These provide for decreasing velocity and some water drop-out. Usually, where water soluble inhibitors are used, additional inhibitor is injected at every 50 to 100 miles at pumping stations where a part of the water is withdrawn. The amount added is scheduled on basis of analyses of water effluent from water drop-outs. In aqueous solutions, both sodium nitrite and sodium chromate completely passivate steel in slightly alkaline solutions at concentrations of 0.1 %. Experience has shown that in pipelines where water is a very minor phase, it is necessary to inject sufficient nitrite or chromate to give 2% concentration in water samples withdrawn at downstream water drop-outs. Sodium chromate is sufficiently alkaline to maintain pH of 8 to 9. However, it is necessary to add a buffering agent to sodium nitrite, usually a small amount of caustic soda or soda ash. Soda ash is preferable because of ease of handling. The caustic or soda ash absorbs carbon dioxide from the products and is converted to bicarbonate of soda. Oil Soluble Inhibitors The recognition of absorption and chemisorption properties of polar compounds'9-ZZ in very dilute solutions increased interest in their possible application as inhibitors in products pipelines in the late forties. Sinclair Pipe Line9 pioneered in this field, using a sulfonated mahogany oil in which the sulfonic acid group is the polar portion of the molecule. A number of patented polar compounds which are good inhibitors are on the market. Not all oil soluble polar compounds with good steel inhibiting properties can be used in refined products. Some polar compounds are basic ingredients of emulsifying agents, an undesirable property in a products pipeline system. The material must be essentially nonemulsifying, readily soluble in the products and effective as a corrosion inhibitor in low concentrations-less than five pounds per 1000 barrels. The inhibitor should not be extracted readily from the fuel by water. It must not alter, at effective concentrations, the performance or the ASTM specifications of the product, Le. existing gum test (ASTM D 381-58T), oxidation stability (ASTM D 525-55). It must be compatible with standard additives in the products, such as antiknock agents, metal de activators and antioxidants in gasolines, other additives in fuels and with other corrosion inhibitors. If it is to be added to aviation fuels, it should also be non-ash forming and should not affect the water tolerance test or severely downgrade the WISM( 1) of the product at the maximum allowable concentration of inhibitor.

The oil soluble inhibitors have the advantage that they may be injected at the refinery during the normal blending operation and will protect the refinery piping, the pipeline, the gasoline station tanks and the tank on the automobile. This advantage is fully realized when a company operates its own pipeline and handles its own products. Similarly, common product pipelines can inject inhibitor at source points only, or can require shippers to supply inhibited product.

Mechanics of Inhibitor Application Addition of oil soluble inhibitors in the refinery blending process is simply a matter of using the proper size blending pump. Additions to pipelines are made with chemical proportioning pumps. Water solutions of chromate or nitrite are either injected with a chemical feeder pump or dripped into the line by gravity feeders. When beginning inhibition of a new pipeline, the initial inhibitor dosage should be high and then should taper off to required maintenance dosage. For example, with an oil soluble inhibitor that will require three pounds per 1000 barrels, the dosage should be about six pounds for the first month and then gradually be decreased to three pounds. Similarly, the dosage of water soluble inhibitor must be high at the beginning. Before initiating an inhibitor program, it is necessary to run scrapers to remove construction sediment and loose mill scale. After a line is cleaned and inhibited, running of scrapers can be reduced to a minimum so long as proper inhibitor concentration is maintained. Caution must be exercised when starting to inhibit a line which has operated without either an inhibitor or dehydration. Either water or oil soluble inhibitors will loosen rust, so when beginning inhibition of such a line, the

Handling aviation products is a special problem because present specifications will not permit use of water soluble inhibitors and only a limited number of oil soluble inhibitors are approved for military fuels. To obtain approval, the qualification tests described in Military Specification: "Inhibitor, Corrosion, Fuel Soluble," MIL-I-25017C, must be carried out and the results approved by the Bureau of Aeronautics, Navy Department, (1) ASTM Water Separometer

Index,

Modified,

or WSIM test.

91

TABLE 3 - Specific Gravity

treatment should start low and be coupled with frequent scraper runs. If this is not done, sufficient sediment may collect to stop the scraper and require removal of a section of pipe. Over a period of time the treatment is brought up to the required amount.

vs Viscosity2 Specific Gravity(s)

0.80 0.74 0.72 0.70 0.68

Use of Protective Coatings Many miles of large diameter gas transmission lines have been installed with an internal epoxy coating. The coating facilitates the clean-up of the line after construction and offers some corrosion protection. The use of internal coatings has been limited in products pipelines. One company coated a 60-mile section of 16-in line with inorganic zinc.28 Several companies have applied epoxy coatings to lines devoted exclusively to uninhibited aviation turbine fuel. In all of the above cases, the coating was applied at a coating yard after sandblasting and no attempt was made to protect the weld area after laying the pipe. A small mileage of pipeline has been chemically cleaned and coated in place.

Coupons for Control Tests Two types of polished steel coupons are used in testing corrosivity of products or efficiency of inhibitor. One is the round rod used in the modified turbine oil test (ASTM Designation: 0-665-54) MIL-1-25017C and NACE Standard TM-01-7231 procedure, and the other is a flat coupon which is installed in the pipeline stream. Selection and Preparation of Coupons - To obtain reproducible and reliable results, special care is required in choosing the proper steel stock for making the coupons. Also, rigid control of surface preparation, handling and storing of coupons must be exercised. A group of coupons should be cut from stock from one heat of steel. Before

162.04 QSO.54 C = pO.54 D2.63 where Q = Barrels per hour P = Pressure drop per mile, psi S = Specific gravity at operating temperature 0= Internal diameter of pipe, in.

using the coupons for evaluation, they should be tested in uninhibited product or even in tap water to determine that they give an even and reproducible rusting. Flat coupons should be annealed after shearing to size, stamping identification number and cutting a one-quarter inch hole near one end of coupon. ASTM Designation: D-665-54 gives details for preparing the round specimens from cold finished carbon steel bars and shafting (ASTM Designation: A-I08). Some petroleum research laboratories have experienced difficulty in making coupons which give reproducible results in testing gasolines. Deverter32 found tha t rods prepared from concrete reinforcing rods (ASTM Designation: 0-15) gave more reproducible results than those cut from SAE 10:20 mild steel which comes under ASTM Designation: A-I08. Meyer and SheldaW33 made an extensive study of coupon stock material for round specimens and effect of type of finish. They found that banded SAE 1020 steel did not give reproducible results. They recommend uniform, nonbanded, cold rolled SAE 1020 steel finished to thirtyfive microinches with one-hundred grit silicon carbide

or

162.04

efficiency

Factor2

(S/p)O.54

9

B e=

4.06 (d5 I/sf'

0.46

0.38 0.31

Miller29 states that the generalized values shown in Table 3 can be used for absolute viscosity without introducing too much error. The range covers API gravities from 45.4 to 76.6 degrees. A pipeline constructed of new pipe and one which has been efficiently inhibited or dehydrated will have C factors of 155 to 160 or efficiency factors of 96 to 99%.

C Factor

X

2.0 0.65

F).

C Factor or Efficiency The ultimate criterion of control is securing the maximum volume per horsepower unit. This is accomplished by obtaining the smoothest possible internal pipe surface; that is, the least possible friction. The friction factor is expressed as the modified Hazen-Williams C Factor or as efficiency:

D2.63

Viscosity(s)

Rea30 gives a graph showing viscosities for gasolines having the following specific gravities: 0.74,0.72,0.70 and 0.68 in the temperature range from -1.1 to 39 C (30 to 100

Criteria for Control

C=Q

9

(log d3 S I/z2 + 4.35) ,

where e = Line efficiency B = Barrels per day d = Internal diameter of pipe, in I = Pressure drop per mile, psi s = Specific gravity of product at operating temperature z = Absolute viscosity in centipoises at operating temperature. 92

abrasive cloth. Details are available in the paper. The same general procedure is followed for flat coupons. MIL-I-250-17C calls for SAE 1020 hot rolled steel with

TABLE 4 - Rating Schedule for In-Line Corrosion Coupons

final polish using 400 grit aluminurn oxide abrasive cloth. E C B2+ B+ Rating It is important that coupons are not handled with bare B A0 hands after starting the finishing operation. Perspiration from the skin can disqualify a coupon. Finished coupons should be stored in paper envelopes or wrappings which contain a vapor phase inhibitor. Modified Turbine Oil Test - ASTM Designation: D665-54, Corrosion Test for Turbine Oil is the basis for rust test procedures. This test specified 60 C (140 F) for 24 hours. To adapt the test to gasolines and JP-4, the temperature had to be lowered and the time reduced. Tests in different laboratories publishing data vary from one hour32 at room temperature to three and one-half hours3 3 at 38 C (100 F). These laboratories use Procedure A for distilled water from the ASTM test. Unit Committee T-3P

Rust

I

No rust00.1 Description Trace rust

PerCf'"lt 75-100 5-25 50-75 25-50 5.0

In-line corrosion coupons may be used to monitor any section of the pipeline, such as beginnings and ends of various line sections. Coupons prepared according to the above discussion are probably more sensitive to corrosion than is the pipeline surface; therefore a high rating on the coupons gives assurance that the internal surface of the pipe is not corroding. The rating scale shown in Table 4 is commonly used. The in-line coupon is equally useful in pipelines inhibited with either water or oil soluble inhibitors or in

of Group Committee T-3 of the National Association of Corrosion Engineers developed a Standard Test Method "Antirust Properties of Products Pipeline Cargoes" which was issued March, 1972 as NACE Standard TM-01-72.31 This test specified three and one-half hours at 100 Fusing distilled water. This test applies to gasolines and distillate fuels. Military specification, MIL-I-25017 A, for qualification of oil soluble inhibitors required twenty hours at 38 C (100 F) using Procedure B for sea water. A new specification, MIL-I-25017C, was issued on March 8,1971 which calls for five hours at 100 F using a synthetic, moderately hard water. This test also requires a higher polish of the test specimens than does the NACE test. These changes were found to be necessary to give the type of reproducibility desired. The modified turbine oil test is used to determine in

systems protected by dehydration. Electrical Resistance Probes The successful use of electrical resistance probes for monitoring corrosion in refining and chemical industries has led to the development of probes which show promise in products pipelines. The corrosion rate is proportional to the decrease in resistance of the probe with time. Where the corrosion rate is relatively low, the probe is made with small diameter wire.

the laboratory the amount of oil soluble inhibitor required to inhibit a product and to check inhibitor effectiveness in product removed from the pipeline. It is assumed, if the proper amount of inhibitor is injected and the product removed from the pipeline shows little, if any, rusting, that the pipeline is properly inhibited. In-Line Corrosion Coupons - These are flat coupons which are inserted in the pipeline stream. The same care in selection of stock, finish and checking of reproducibility is needed as in the modified turbine oil test. It is necessary to be able to insert and remove the coupons without interrupting operation of the pipeline. A section of pipeline must be chosen where the coupon will not interfere with scrapers.

At least one pipeline has data covering several years of operation which indicate a good correlation with experience.

Summary Internal corrosion of refined petroleum products pipelines varies from very severe to sufficiently small that a few operators do not need to provide any protection against it. Relatively few pipeline leaks are caused by internal corrosion. Sediment produced by internal corrosion is abrasive and can damage pipeline equipment such as pump seals and meters. Excessive volume of sediment overloads protective fIltering equipment and may degrade the products. Preventive measures practiced by the majority of the industry to insure low pipeline friction and to prevent damage resulting from internal corrosion are discussed.

NACE T-3P Unit Committee is developing a recommended practice on use of in-line corrosion coupons in refined petroleum products pipelines. NACE in-line coupons have been available to the industry since 1956.(2)

References 1. Products Pipelining. Oil Gas J., 57, £6-£9 (1959) January 28. 2. H. G. Schad. Symposium on Combatting Internal Corrosion of Products Pipe Lines: Keystone-ButTalo Pipe Line System. Proc. Am. Petr. Inst., 24, (IV), 44-55 (1943). 3. Harry K. Phipps. Use of Dehydration in Combatting Internal Corrosion in Products Pipeline Systems. Proc. Am. Petr. Inst.,

(2)Unbanded 1020 steel or bar stock all of same heat. Analysis reported on each lot of metal spectrographically and for rust sensitivity. Measurements 4.75 x 0.5 x 0.12S-inch. Coupons are pre-stamped with numbers. Surface finish, edge finish, inhibited packaging specified. Per coupon, $4, plus postage. Order from NACE, Houston, Texas.

93

4.

5. 6.

7.

8.

9. 10. 11. 12.

13.

14. 15.

16. 17. 18.

26, (V), 37-40 (1946); Corrosion, 3,458-465 (1947) September. L. C. Morris and W. A. Schulze. Internal Corrosion of Gasoline Pipe tines. Proc. Am. Petr. Inst., 20, (IV), 14-24 (1939); Oil Gas 1., 38, 205 (1939) November 17. S. S. Smith. Results of Corrosion Inhibitor Demonstrated in Products tine. Oil GasJ., 41, 85-87 (1942) September 24. W. A. Schulze, L. C. Morris, and R. C. Alden. A Review of Methods Used to Reduce Internal Corrosion of Gasoline Pipe tines. Proc. Am. Petr. Inst., 22, (IV), 22-29 (1941). Ivy M. Parker. Use of Corrosion Inhibitors in Products Pipe tines. Proc. Am. Petr. Inst., 26, (V), 26-36 (1946); Corrosion, 3,157-168 (1947) April. C. C. Keane. Internal Corrosion of Products Pipe tines-Great Lakes Pipe tine Company. Proc. Am. Petr. Inst., 24, (IV), 102-135 (1943). E. W. Umuh and F. Me Watkins. Rust Prevention in Products Pipe tines. Oil GasJ., 47,63-64 (1948) June 17. W. G. Horstman and Ivy M. Parker. Filtering Practices. Paper API Transportation Division, Chicago, November 9, 1954. John M. Pearson. Combatting Internal Corrosion. Proc. Am. Petr. Inst., 24, (IV), 66-68 (1943). A. Wachter and S. S. Smith. Preventing Internal Corrosion of Pipe Lines-Sodium Nitrite Treatment for Gasoline tines. Ind. Eng. Chem" 35,358-367 (1943). Cline Black, George C. Joris, and Hugh S. Taylor. The Solubility of Water in Hydrocarbons. 1. Chem. Phys., 16, 537-543 (1948) May. R. P. Dougherty. Dehydration on Products Pipe tine. Petr. Eng., 24, D-I0 (1952) June. John Mitchell, Jr. and Donald Milton Smith. Aquametry; Application of the Karl Fischer Reagent to Quantitative Analyses Involving Water. Interscience Publishers, Inc., New York, N. Y., 1948, pp. 162-168. Melvin A. Judah. How New Mid-America LPG tine will be Operated. Pipe Line Ind., 13,36-41 (1960) November. Private Communication. April 14, 1971. Rowena Pyke and Morris Cohen. Rate of Breakdown and Mechanism of Nitrite Inhibitor of Steel Corrosion. J. Electro· chem. Soc., 93,63-78 (1948) March.

19. W. C. Bigelow, D. L. Pickett, and N. A. Zisman. Oleophobic Monolayers. Part 1, Films Absorbed from Solution in Nonpolar tiquid. J. of Coli. Sei., 1,513-538 (1946) December. 20. H. R. Baker and W. A. Zisman. Polar Type Rust Inhibitors: I Theory and Properties. Ind. Eng. Chem., 40, 2338-2347 (1948) December. 21. Norman Hackerman and H. R. Schmidt. Adsorption of Organic Inhibitors on Iron and Steel Surfaces-Electron Diffraction Studies. J. Phys. and Colloid. Chem., 53, No. 5, 629-638 (1949). 22. N. Hackerman and H. R. Schmidt. The Role of Adsorption from Solution in Corrosion Inhibitor Action. Corrosion,S, 237-243 (1949) July. 23. M. R. Barusch, L. G. Haskell, and R. L. Piehl. Control of Internal Corrosion of Petroleum Products Pipelines with Oil Soluble Inhibitors. Corrosion, 15, 158t-166t (1959) March. 24. K. T. Feldman and F. M. Watkins. New Corrosion Inhibitor Gets Job Done. Oil Gas J., 49, 340-344 (1950) November 16. 25. P. S. DeVerter and A. W. Jasek. Control of Internal Corrosion of a Products Pipe Line System. Corrosion, I I, 261 t-266t (1955) June. 26. R. H. Meyer. Corrosion Inhibitor Testing Inside a Products Pipe tine. Corrosion, IS, 131t-134t (1959) March. 27. W. S. Quimby. Oil Soluble Inhibitors for Controlling Corrosion in Tankers and Pipe Lines. Corrosion, 16, 9- IQ (1960) March. 28. Melvin A. Judah. Louisiana Products tine Coated with Zinc Silicate System. Pipe Line Ind., 13, (1967) March. 29. Benjamin Miller. Application of Pipe tine Efficiency Concept to Gasoline Pipe lines. Oil Gas J., 41,122-123 (1943) January 7. 30. W. E. Rea. A. Discussion of Flow Formulas Used for Design of Gasoline Pipe Lines. Oil GasJ., 39,40 (1941) January 23. 31. Test Method: Antirust Properties of Petroleum Products Pipeline Cargoes. NACE Standard TM-OI-72, National Association of Corrosion Engineers, Houston, Texas. 32. P. S. DeVerter. Test for Presence and Evaluation of Product Soluble Rust Inhibitors. Petr. Eng.. 25, C-35 (1953) September. 33. R. H. Meyer and D. B. Sheldahl. Is Your Inhibitor Doing Its Job? Oil Gas J., 54, 224-228; 231-232 (1956) September 17.

94

Control of Internal Corrosion of Pipelines Carrying Crude Oil

Introduction

Because the corrosion is concentrated

There is a wide variety of experience with corrosion in pipelines carrying crude oil. Most crude oils contain oil well brine, which is an excellent electrolyte to promote corrosion. Some oils are paraffinic and deposit a protective layer of paraffin on the pipe wall, while others appear noncorrosive because of chemical composition. The amount of corrosion is often related to the amount

at the bottom of the

pipe, it was once a common practice to take up the pipe, turn it over and re-lay it. There has been considerable interest in in-place coating! of lines suffering severe internal corrosion. There is also interest in plastic pipe for low pressure systems. Because of its resistance to hydrogen sulfide attack, aluminum pipe has been used. However, Ellis2 reported attack by iron sulfide similar to that experienced with steel. Successful use of aluminum pipe for a gathering line has been reported. 3 NACE Technical Practices Unit Committee T-lOE is

and composition of sediment. High velocity flow tends to sweep sediment out of the pipeline, while low velocity allows it to settle on the bottom of the pipe. When the sediment settles, it shields the pipe and pitting tends to take place beneath the sediment. When the crude oil is sour, the sediment contains iron sulfide. This aggravates the corrosion because, in addition to the shielding effect, the iron sulfide is strongly cathodic to steel. Thus, the iron sulfide and steel produce a battery-type action which destroys the steel at a rapid rate.

developing recommended procedures for monitoring internal corrosion of pipelines carrying crude oil, natural gas and refined products.

Summary Severe internal

corrosion

occurs in crude oil lines

carrying sour crudes. Operating techniques which reduce the amount of sediment in the pipeline are the primary ways to control it. Internal coatings and aluminum pipe have proved useful.

Methods of Control Specifications on BS & W content of oil entering the pipeline limit the amount of sediment and water available to cause corrosion. Most cross country pipelines operate at sufficient velocity to keep a moderate amount of sediment in suspension, and furthermore many operators carry out regular scraper programs to dislodge scale and traps to collect sediment from the stream. Low velocity gathering lines may give a great deal of trouble, especially when they are collecting sour crudes.

References 1. M. B. Grove. Internal Coating of Pipe in Place, Corrosion, 10, 142-146 (1954). 2. Almont Ellis. Some Corrosion Experiences with Aluminum Crude Oil lines, Corrosion, 8,289-291 (1952). 3. R. W. Flournoy. Underground Aluminum Pipe line for a Sour Gas Gathering System, Corrosion, 16, 419t-420t (1960).

95

Inhibition of Natural Gas Pipelines

160

Oxygen, carbon dioxide and hydrogen sulfide are the main corrosives in natural gas pipelines and they are aggressive only when they are absorbed into water or moisture in the lines. Most pipeline gas has been desulfurized and desiccated as well as treated otherwise before it is pumped into transmission lines. Consequently, most of the corrosion problems in gas systems occur in the various gathering lines and in the piping and equipment used for removing liquid hydrocarbons and sulfur . While inhibitors may be slugged, injected or sprayed into a gas stream, they function only to the extent that they are adsorbed on or react with the steel to set up a barrier between it and the aggressive agents.

•

120 Cl:

~

w

>-

0.25 gal/day

Cl:

:f

80

en

...J ::2'

40

o

Inhibition of Oxygen, Carbon Dioxide and Hydrogen Sulfide

NOVEMBER

Martin, Annand, Wilson and Abrahamson1 gave details of the corrosion problems caused by oxygen and hydrogen sulfide and of an effective solution of corrosion problems by using an inhibitor. Their report concerned a gathering system handling about 600,000 standard cubic feet of gas a day. The gas was collected from five pumping wells operating at up to 5 inches of vacuum and it contained 1 percent or more oxygen during upset conditions, 1 percent hydrogen sulfide and 0.25 percent carbon dioxide. These gases, dissolved in precipitated water, corroded a groove along the bottom of the pipe. Drip pots were installed along the line to trap accumulated liquid. An organic sulfophosphate inhibitor (Tol-Aeromer A(1 » was used after several others had produced only limited benefits. As shown in Figure 1, there was a dramatic drop in the corrosion rate (as reflected by test probes) when the inhibitor was first injected into the line. Reduction of corrosion from an uncontrolled 160 mpy to less than 1 mpy was achieved eventually while the injection rate was being increased to 0.5 gallons a day. Corrosion rates, leak frequency and replacement of corroded pipe all were reduced by the inhIbitor. Tests and operation experience show that the inhibitor has a good mm life and that it can be effective in treating extremely corrosive mixtures of hydrogen sulfide and air in the presence of carbon dioxide if inhibitor concentrations are adequate.

DECEMBER MONTHS

JANUARY

FIGURE 1 - Showing reduction in corrosion rate following iniection of an organic sulfophosphate inhibitor. I (1) = Tol-Aeromer-AQ1.

TABLE 1 - Comparison of Slug vs Fogging of 10-1nch Meter Run Gas Transmission Line2 (Coupon Rates av. mpy) Type of Treatment Slug

Line

None

Fog

A

-

1.6

0.3

B

-

3.8

0.4

Sullivan2 to be the principal causative agents in corrosion damage to a natural gas gathering piping system. Numerous fittings and 12,900 feet of corroded pipe were removed from the line after an extensive corrosion survey. Water condensed from the gas absorbed carbon dioxide and ran down the pipeline bottom to lowest points. An oil soluble amine type inhibitor was selected for application to the line. It was mixed with kerosene in the ratio of one part inhibitor to three parts kerosene and was found to be sufficiently soluble in the pipeline water to be effective at low pH. The ratio was changed later to 1:4 inhibitor to kerosene to improve performance. Treatments were adjusted annually to conform to production rates, but were one pint per million cubic feet of gas initially.

Carbon Dioxide and Water Corrosion Is Controlled Carbon dioxide and water were found by Graves and (1 > A tradename of the Tretolite Co., St. Louis, Mo.

96

Hydrogen sulfide can be converted to free sulfur as an end product. Monoethanolamine (MEA) is an agent which will absorb hydrogen sulfide and carbon dioxide. It is regenerated by heating it to drive off the acid gases. Mottley and Fincher4 detail some of the corrosion problems and design factors experienced in an MEA cycling plant used to absorb acid gases from natural gas. Gas contained about 13 percent hydrogen sulfide and 5 percent carbon dioxide. It was necessary to inject inhibitors at several points and use an oxygen scavenger to obtain reasonable control of corrosion in the system. In addition, design changes were necessary to eliminate dead spots in heat exchangers, reduce velocities to a reasonable rate of less than 20 fps, to provide a means of keeping the steam reboilers free of collected condensate and other modifica. tions.

As shown in Table I fog treatment proved much more beneficial than slug applications of inhibitor. Contrary to earlier studies which indicated that corrosion was negligible in sweet natural gas containing less than 10 psi partial pressure of carbon dioxide, Graves and Sullivan2 found serious corrosion at partial pressures of carbon dioxide as low as 4 to 5 psi. Cost of inhibition for the system was estimated (1966) to be 50 to 60 cents per million cubic feet of gas produced. Average uncontrolled corrosion cost of the system was estimated at about $42,000 a year over nine years. Annual cost of inhibitor treatment was about $15,000.

Spray Injection Into a High Pressure Gas System Injection of an inhibitor as a fine mist into a 26 mile, 4-inch, 600 psig, natural gas transmission line was effected by a by-pass arrangement as reported by Blount and Anthony.3 An atomizing nozzle is positioned in the center of the gas line so that the nozzle will spray in the same direction as the gas flow. An orifice plate is placed in the line immediately upstream of the nozzle. The arrangement requires a minimum of 10 and a maximum of 20 psig pressure drop across the orifice. The gas is tapped on the high pressure side of the orifice and passed through a filter to the atomizer and into the top of the chemical feed tank. The chemical is fed to the atomizer from the feed tank. Except for valves, there are no moving parts to the system. The same arrangement can be used to spray inhibitor into gas being used for gas lift operation of wells.

Summary Natural gas is a complex system as it comes from producing wells. It contains varying amounts of water, carbon dioxide, hydrogen sulfide and possibly other corrosives such as formic acid. It may not be possible to relate its corrosiveness to a single major contaminant. Examples cited above show that inhibitors are valuable in controlling corrosion associated with natural gas.

References 1. R. 1. Martin, R. R. Annand, Dale Wilson and W. E. Abrahamson. Inhibition Control of Oxygen Corrosion: Application to a Sour Gas Gathering System, Mat. Pro., 10, No. 12, 33-37 (1971) Dec. 2. J. W. Graves and E. H. Sullivan. Internal Corrosion in Gas Gathering Systems and Transmission Lines, Mat. Pro., 5, No. 6, 33-37 (1966) June. 3. F. E. Blount and J. W. Anthony. Spray Injection of Liquids Into High Pressure Gas Lines, Corrosion, 13, No. 12, 127-128 (1957) Dec. 4. J. R. Mottley and D. R. Fincher. Inhibition of Monoethanolamine Solutions, Mat. Pro., 2, No. 8,26-30 (1963) Aug.

Inhibiting a System for Removing SuIfur Sour gas must be sweetened before it can be sold as pipeline gas. That is, hydrogen sulfide must be removed.

97

Inhibition of Tanks and Other Structures Handling Crude Petroleum

Introduction

foot per year (1955). In this line an inhibitor batched behind scrapers once a week produced a reduction in leaks from seven in one month before inhibition was started to only four during 14 months of treatment. Cost of maintaining the line, including leak repairs, rotation of the pipe, reconditioning and lost oil averaged 24 cents per foot per year during 10 years. Cost of the inhibitor was estimated to be 1 to 3 mils per barrel of crude. As shown in Table 1, a comparison of several alternative methods of controlling corrosion of a hypothetical pipeline showed inhibition to be the most economical. Sharpe also reported that treatment with zinc dust or a soluble zinc salt gave good results.

Crude petroleum ordinarily is considered much less corrosive than refined products of petroleum. This difference is mainly the result of the tendency of oil to plate out on metal surfaces, on the protective properties of the scale and deposits formed on surfaces contacted by crude oil and to the inhibitive properties of some of the constituents found in the oil. However, sour crudes such as those from the Middle East and some from the Permian Basin may be very corrosive. There are, however, environments in which crude oil becomes corrosive and inhibition is necessary. There also are related environments, such as tankships, in which the corrosion damage occurs as a result of the necessity to clean cargo space and from the alternate ladings, such as when sea water is used as ballast. Most of the corrosion suffered by tankships, however, occurs in tanks carrying "clean", that is, refined petroleum products.

Inhibition

Vapor Space Corrosion in Tanks There is conflicting information on the effectiveness of using ammonia to control corrosion in the vapor space of tanks holding crude petroleum. Gardner, Clothier and Corye112 reported as the result of using ammonia reductions up to 99 percent in corrosion rates of oil storage tanks handling crude containing hydrogen sulfide. Ammonium carbonate and anyhdrous ammonia both produced good results in tankage when metered into the vapor space at a

of a Crude Oil Pipeline

In one of the infrequent references in the literature to inhibition in a crude oil pipeline, Sharpe 1 gave the cost of inhibiting 30 miles of 6-inch pipeline as about 1.5 cents per

TABLE 1 - Cost Comparison for Various Methods of Controlling Internal Corrosion in a Hypothetical Fifty-Mile 12-lnch Discharge. Required Life Thirty Years. 3. Concrete-Lined Pipe: Second Class pipe; more than 30 years' service; no leaks.

1. Unprotected Pipe: New PE pipe; 15 years service until replacement is necessary. 300 leaks occur during first 15 years and additional 300 leaks during second 15 years.

4. Plastic Coating: Second Class pipe; life of coating 10 years, line re-coated in place at 10-year intervals; service life of pipe more than 30 years; 10 leaks.

2. Inhibitor Program: Second Class pipe; inhibitor batched weekly; more than 30 years' service; 10 leaks occur during 30 years.

(1) 0.02 0.40 Inhibitor Concrete $0.13 Unprotected $3.44 Steel Pipe

-

I

$3.86

$ 4.78

C.pital Investment-Line in Place-Cost per ft. Maintenance Cost for 30 year period, cost per ft. Replacement of Line Leaks ($400 each) . Recoating line . Inhibitor cost. batch treatment Total 30- Year Cost, including original investment but excluding salvage value. Cost per Foot, per Year .

$ 4.78 0.91

$10.47 $ 0.35

Note: Pressure requirements preclude use of plastic pipe or asbestos cement pipe.

98

-

1.40 Plastic $0.14 Coating $4.23 (4) $0.19 $4.14 Lining I 0.02

(2) (3) $5.56

Exposure ate h

TABLE 2 - Results of Anhydrous Ammonia Treatment of 55,OOO-Barrel Sour Crude Storage Tank2 Days

I

(2) 45 11 Reduction 99 15 30 96 85 90 3Rate, Corrosion Mdd 96 7 Lb/Day

30 62 57 28 31 32

Injection

Percent(l)

(l)Referred to yearly average corrosion rate of 289 mdd determined in this area prior to the start of routine inhibitor treatment. (2)Not determined. Weights lost.

rate of about 12 pounds a day for 55,000 barrel cone roof tank. At the time (1950) the cost of this treatment was about $372 a year for ammonia. Total materials cost for application tanks and piping was $412 annually over 15 years. In locations where only 4 Ib of ammonia a day was needed, annual cost of ammonia and facilities was $164 a year. These figures, when contrasted to an estimated $17,000 cost of replacing corroded tank members in the same period, show the value of protection. The safety factor also is important. It is estimated that on some tanks, an unprotected, roof will be unsafe in four years. The cost of an unprotected roof in sour crude service is about $3400 a year. Ammonia protection for the same tank costs $412 a year. Table 2 shows the record on a 55,000 barrel tank protected with anhydrous ammonia.

treatments with ammonia of a tank having an already developed iron sulfide surface would not reduce appreciably the corrosion rate. 3

Inhibition of Crude Oil Tanker According to Quimby,4 marked benefits were obtained when a polar type oil inhibitor was metered at a rate of 24 Ib per 1000 barrels into crude oil being loaded into a tank. The three year old ships had suffered significant pitting corrosion damage on bottom plates, cargo piping and hea ting coils. Annual inspection for six years after the inhibition program started showed marked improvement and much better conditions compared to ships without the inhibitor program. Pitting rate was reduced. Most pits ranged from 3 to 6 tenths of an inch deep in upward facing horizontal surfaces. There was little or no bulkhead pitting. Relatively little rust was removed from the tanks, the residue being mainly waxy material that tended to settle from the crude oil. While pitting was reduced, it was not brought to an acceptably low value because the pits tended to be filled with water and were not affected by the inhibitor in the oil.

Only Temporary Results Reported Rogers,3 discussed tests made by his company involving injection of anhydrous ammonia into the vapor spaces of 13 tanks with capacities from 55,000 to 80,000 barrels. Protection in the vapor space from attack by hydrogen sulfide was only temporary. When coupons and new steel were exposed to vapors containing hydrogen sulfide and ammonia, protection lasted four to eight months. After this period, the corrosion rate increased to about the same as that for unprotected steel. The pH of water collected on the decks of tanks was in the 10 to 11.5 range at all times during the tests. But because iron sulfide surfaces are cathodic to steel and

References 1. 1. G. Sharpe. Economic Considerations in Pipe Line Corrosion Control, Co"osion, 11, No. 5, 227t-240t (1955) May. 2. F. T. Gardner, A. T. Clothier and F. CoryelL The Use of Ammonia in Control of Vapor Space Corrosion of Storage Tanks, Co"osion, 6, No. 2, 58-65 (1950) Mar. 3. W. F. Rogers. A Note on the Value of Ammonia Treatment for Tank and Casing Annulus Corrosion by Hydrogen Sulfide, Corrosion, 11, No. 11, 488t-490t (1955) Nov. 4. W. S. Quimby. Oil Soluble Inhibitors for Controlling Corrosion in Tankers and Pipe Lines, Co"osion. 16, No. 3, 9, 10, 12, 14, 16, 18 (1960) Mar.

difficult to polarize, the result is high corrosion rates in hydrogen sulfide environments. Changes in fluid pH from 4.5 to 9.5 such as result from ammonia treatment do not greatly change the polarization characteristics of an iron sulfide cathode. These data support the conclusion that

99

Inhibition of Tankships Transporting Refined Petroleum Products

Introduction Tankships carrying refined petroleum products can enjoy marked benefits from effective inhibition practices in their cargo tanks. As is the case with other hydrocarbon environments, major corrosion damage occurs in the vapor phase or as the result of a water phase developed from water absorbed in and/or aspirated into the hydrocarbons from the environment. The high initial cost and usual long service life of tankships, added to the expense involved in tieing up a ship to make repairs of corrosion damage, make inhibitors attractive. Because sides of cargo tanks of tankships also make up the hull and decks, the consequences of catastrophic corrosion attack are too serious to be ignored.

Use of Oil-Soluble Inhibitors As reported by Quimby· a five-year test of several ships engaged in coastwise clean cargo service revealed that approximately 241b/ 1000 barrels of an oil soluble inhibitor was effective in reducing corrosion of tank surfaces to reasonable limits. Micrometer thickness measurements, as shown in Table I, showed an indicated rate of 6.6 mils a year over the five years. This was a considerable reduction from the estimated 14 to 16 mpy that would have been suffered if the inhibitor had not been used. Published

FIGURE 1 - Thick layer of hard corrosion product on the surface of a tank in clean cargo service. (Protection Against Tanker Corrosion. C. G. Munger. Mat Pro.• 5. No. 3.8-13 (1966) Apr.l.

TABLE 2 - Two Year Corrosion Rates on Coupons Exposed to Flotation Inhibitors·

industry figures of 23 to 25.6 mpy indicate that the saving may have been even greater. Weights of rust removed from tanks in these ships was significantly less than those from similar ships operated without inhibition. The annual average rust weight from the four ships tested was 52,000 lb while uninhibited ships in the same trade between 5th and 10th years of service would have 150,000 to 200,000 lb of rust a year removed from

Tank Corrosion Ballast-Average ... Ballast + Flotation-Average

TABLE 1 - Five Year Corrosion Rates on Inhibited Tanks· Member Shell Longitudinals Transverse Wet Frames Vertical Keels Bulkhead Stiffeners Stri ngers ... Bulkheads Shell Stringers Average of members below cargo level .

Corrosion Rates (mpy) Center Wing Tanks Tanks 20 4

8.5 2

tanks. Figure 1 shows the appearance of rust layers in a clean cargo tank.

Average Rate. mpy

Vapor Space Corrosion There is about 18 inches of space between the top of lading and the bottoms of decks. Condensation in these spaces can result in corrosion at rates up to 40 mpy. When an inhibitor was brushed or sprayed on the exposed areas, corrosion was substantially reduced in five year tests.

5.4

4.5 1.8 8.3 7.6 9.3

9.2

Flotation and Fogging Techniques Because of large volumes of fluids handled, every effort must be made to find techniques of inhibitor application that economize on the quantities necessary. Oosterhout,

6.6

100

TABLE 3 - Two Year Corrosion Rates

When about 2 gallons of inhibitor per 1000 barrels capacity was poured onto the rising surface of water in a tank being filled to the top with ballast water, a layer of inhibitor was deposited on the sides of the tank and on all areas of the vapor space. l,2 Table 2 shows corrosion data.

on Coupons Exposed to Fogging Inhibitorsl Corrosion Rates (mpy) Tank Condition

Empty-Average .. Empty + FoggingAverage .....

Center Tanks 23

4.2

I

Fogging Technique Empty tanks (non-ballast) were protected by "fogging" the inhibitors into them. A finely atomized spray or fog of the inhibitor concentrate in air or steam covered all of the

Tanks Wing

6 6

underside area.2 The injection rate was 2 gallons per 1000 barrels of tank capacity in about 10 minutes. Injection was done as soon as practical after cargo was discharged. Inspection and corrosion data showed protection comparable to that achieved with the flotation treatment. Table 3 shows results.

Stanley and Quimby2 discuss the flotation and fogging techniques for applying inhibitors in tankships.

Oil-soluble polar compounds used as inhibitors in refined products cargoes are applicable to flotation and fogging techniques. Oosterhout, Stanley and Quimby2 reported tests of tankship fogging inhibitors using a 300 barrel tank in which the coupons to be tested were suspended from the top in such a way that the fogging spray impinged on them.

Flotation Techni£[ue Flotation inhibitors are applied in an oil solution which is floated on top of water in a relatively thin layer. The exposed steel makes contact with the inhibitor both when the tank is being filled with water and when the water is pumped out. The effect of flotation inhibitors can be demonstrated by the following procedure, as reported by Oosterhout, Stanley and Quimby2; 1. A layer of inhibitor is deposited on water in ajar. 2. Coupons are suspended in the jar. 3. The amount of water in the jar is increased until the tops of the coupons are covered. 4. The coupons are withdrawn and then suspended in salt water for varying periods to determine the effectiveness of the adsorbed layer.

References 1. W. S. Quimby. Oil Soluble Inhibitors for Controlling Corrosion in Tankers and Pipe Lines, Corrosion, 16, No. 3, 9, 10, 12, 14, 16,18 (1960) Mar. 2. J. C. D. Oosterhout, M. E. Stanley and W. S. Quimby. Corrosion Prevention in Tankers and Storage Tanks by Fogging or Flotation With an Inhibitor Solution, Corrosion, 15, No. 5, 241t-244t (1959) May.

101

Controlling Corrosion in Petroleum Drilling and in Packer Fluids

H.E.BUSH*

Corrosion is one of the problems that must be reckoned with in the successful drilling and completing of an oil or gas well. Recognition of the causes of corrosion in this environment, as in others, has led to the development of numerous corrosion control techniques. It is well known that environmental components such as oxygen, carbon dioxide, hydrogen sulfide and dissolved salts accelerate corrosion attack. These corrosion accelerators are commonly encountered in drilling and completion fluids and in many instances all are present. To offset their corrosive effect several techniques are used, including dilution, concentration, precipitation, neutralization and chemical inhibition. Living organisms are not usually classified as corrosion contaminants, but they have the ability to produce corrosives to the extent that they, too, are an important consideration in corrosion control.

for corrosion fatigue cracks which are the major cause of drill pipe failure. It is easily understood that corrosion problems become more critical as well depth increases, because among other things, high temperature becomes one of the more critical problems faced in many deep drilling projects. Effect of High Temperatures There are two generally accepted high temperature corrosion effects in drilling and packer fluid environments. As temperature increases corrosion attack increases expotentially and high temperature degradation products of chemical additives increase environmental corrosiveness. Thermal stability is a primary prerequisite for materials involved in chemical corrosion control under high temperature conditions. Dilution, precipitation and corrosion inhibition are also used to combat this problem.

Factors Important in Corrosion Attack During Drilling and Completion

Time Factors Time also is always an important factor in corrosion control. The current trend in oil well drilling which requires probing deeper strata of the earth increases equipment exposure time under the critical conditions. Good practice involves decreasing the area of equipment surface exposed, the exposure time and the critical conditions. Drill pipe internally plastic coated and sealed bearing bits are two examples of decreased surface equipment exposure. Increasing penetration rates by optimizing drilling conditions has played an important role in reducing equipment exposure time. Use of temperature-stable materials, corrosion inhibitors or converting to noncorrosive oil systems also changes conditions. Not all practices can be considered beneficial even though they improve one or more of the detrimental conditions. As an example, air or mist drilling greatly increases the penetration rate and therefore decreases equipment exposure time. Although this technique is often considered economical, corrosive conditions are almost always severe and require correction. The relationship between the chemical, mechanical and time factors involved in controlling corrosion caused by drilling and packer fluids has been recognized for many years. Early recognition of corrosion problems in the drilling industry led to the development of some of the technology used in current exploration and production practices.

Microorganisms Microorganisms are common to drilling and completion fluids and can produce hydrogen sulfide, carbon dioxide or organic acids. Some bacterial species, including Desulfovibrio desulfuricans, also increase corrosion by metabolically depolarizing the cathode. Because of the prolific nature of bacteria in these environments, both biostats and biocides are often used for their control. (See chapter on biological influences.) Mechanical and Metallurgical Factors Corrosion due to mechanical and metallurgical problems also exist. Metal tools used in drilling wells are often softer than the formation being penetrated. The abrasiveness of formation solids can easily erode protective films from drilling equipment, leaving metal exposed to corrosion-erosion attack. Mechanical and chemical separation of abrasive solids helps control this attack. It is difficult, however, to control stress concentrations in a string of drill pipe that may reach miles into the earth. Stress increases corrosion attack "and must be controlled through proper design and use of equipment, as well as by reduction of environmental corrosives. For example, corrosion pits concentrate stress and are prime initiation points *Section Leader, Baroid Division, National Lead Co., Houston, Tx.

102

History of Drilling

Historically, control of drilling corrosion was primarily concerned with oxygen contamination. Chemical treatments were used to scavenge oxygen, interfere with oxygen diffusion or passivate the metal by using oxidizing materials.

Metal tools were used in drilling operations as early as 256 B.C.1 Ancient well drillers were interested in obtaining fresh water or brine and would have considered oil seeping into the well bore highly annoying. Although little has been recorded about corrosion problems in the early days of the petroleum industry, the existence of this problem is certainly indicated by records showing that as early as 1825 special fishing tools were used to retrieve drilling equipment that broke off in the hole. Equipment failures were once generally regarded as purely mechanical problems. Today corrosion is clearly understood as a major cause of drilling equipment failure. More than fifty years ago, serious attention was given to mitigating corrosion in drilling and packer fluids. Swan2 was granted a patent in 1919 on the use of an anti-corrosive, viscous, tar oil for drilling and packer fluids. This simple approach was the predecessor of the highly efficient oil-base and oil-emulsion fluids in use today. One of the first studies on the use of corrosion inhibitors in drilling fluid was published by Speller. 3,4 Speller's approach was unique in that he determined that suspended colloids (bentonite) would reduce oxygen corrosion. His celebrated article has become known as "Speller's Obstacle Course Effect". Colloidal particles were used to interfere with the diffusion of oxygen to the metal surface. Information also was presented in this study on sodium sulfite as an oxygen scavenger. A laboratory studyS in 1936 evaluated sodium sulfite and quebracho extract as oxygen scavengers in drilling fluid. The two materials were reported to be substantially equal in removing oxygen, but the quebracho had other beneficial effects on mud properties. Quebracho has been extensively used in drilling fluids for rheological control with little attention to its oxygen scavenging ability. The speed with which oxygen was removed was not considered in these early tests. There is evidence now that catalyzed sodium sulfite will remove oxygen at a much faster rate than will quebracho.

Failures Are Analyzed Early investigators also discussed various types of corrosion failures. Thomas9 and Grant10 published excellent papers on the cause and prevention of drill-pipe and tool-joint troubles. More recently Maradudin11 described failure modes, including sulfide stress corrosion cracking of drill pipe and tubular goods. Current practice in drillingfluid corrosion control considers all the known contaminants and types of equipment failure. Bush 12 outlined current methods to detect corrosion contaminants and described techniques using cationic, amine inhibitors. Extreme-pressure lubricants consisting of sulfurized organic acids and metal soaps also are used to inhibit drilling-fluid corrosion. Behrens1 3 reported on a technique employing a downhole corrosion coupon to estimate the corrosion rate of drill pipe. Bush14 developed a test to evaluate hydrogen embrittlement tendencies. These tools are frequently used to estimate the rate and type of corrosion attack and evaluate the effectiveness of inhibition techniques. Corrosion mitigation during drilling has been the object of contributions from many sources, but corrosion problems do not stop when the total depth of the well is reached. Problems Related to Packer Fluids Drilling fluids are often left as packer fluids in the tubing and casing annuli. The packer of "fill-in fluid" must function in a way different from the drilling fluid, because dynamic circulating drilling conditions are changed to a static fluid column. While drilling, the fluid must remove from the bore hole tremendous quantities of formation debris, some of which is trapped in the circulating fluid and may present a corrosion problem when the mud is left as a packer fluid. One function of the packer fluid is to stabilize and maintain the entrained materials in suspension. This fluid must be of sufficient density to contain the well pressure in the event of a pipe failure. Under long-term, static conditions, detrimental changes may take place that cannot be rectified easily. Packer fluids must be conditioned to function for years, because no opportunity is afforded for correction without great expense. Corrosive contaminants, such as carbon dioxide and hydrogen sulfide are produced by bacterial action, thermal degradation or electrochemical

Early Organized Studies One of the first corrosion studies organized by a professional society was sponsored by the American Association of Oil Well Drilling Contractors in 1946. In this study McMaster6 tested sodium chromate and sodium hydroxide as inhibitors. Betz 7 also proposed the use of sodium chromate to inhibit drill pipe corrosion and suggested the possible use of sodium nitrite for the same purpose. Because chromium was a vital material and in limited supply during the Second World War, sodium nitrite was then investigated8 and used in the field. It is interesting that inadequate packaging of this material had much to do with discontinuing its use. The sodium nitrite was packaged in wooden drums and upon exposure to a humid atmosphere, it would absorb water and become a hard cake. It has been said that the drums would start growing white whiskers and appear to be frosty after a few days of atmospheric exposure at the rig, an effect that bothered the drillers.

reduction. Johnston and Cowan,1 5 and Simpson,1 6 Barbee,17 Simpson and Andrews,18 Simpson and Barbee,19 Skelly and Kjellstrand20 and Chesser2 1 have contributed information on the cause and effect of contaminants in packer fluids. These authors present both laboratory and field data and clearly show that the fluid placed in the annular space of the well requires careful selection if successful and economical completions are to be assured. 103

Economic Factors in Drilling Practice

Group Survey.23 All of the various mud types cannot be considered separately in this chapter, so water and oil mud types generally will be considered with respect to special corrosion problems of specific types.

Co"osion Losses in Drill Pipe The variable nature of each drilling operation makes an evaluation of economics difficult. The characteristic

Some Problems Related to Water Base Fluids

operating techniques of drilling companies over a large area have been used to arrive at cost figures for drill pipe. Drill pipe alone does not represent the total economic picture, but it is considered a reliable indication of the whole

Water base drilling fluids present corrosion problems primarily because they are subject to contamination from corrosion accelerators such as oxygen, carbon dioxide, hydrogen sulfide or salts that are always present in varying quantitites. The sources and effects of these contaminants have been the subjects of numerous investigations. Early investigators were primarily concerned with oxygen, which is still a major problem today. A recent study by Bradley24 presents data correlating pitting attack with oxygen contamination. Functional oxygen meters described by Blount and Snavely2S and downhole corrosion coupons described by Wattman26 are helpful tools to evaluate the potential effect of oxygen and other contaminants in various systems. More recently electrical probes that make corrosion measurements are being used. Important tools such as these can often prcvide needed information on the cause of corrosion and also help evaluate the effectiveness of corrective treatments.

problem. Cost figures may be generally applicable when reduced to percentages of drill pipe loss. Published information by Clark and Sheridan22 provide such information. Clark shows that 23 percent of pipe was downgraded to restricted service at each 42,500 foot inspection interval in West Texas service. Sixty-four percent of the pipe was downgraded due to pitting corrosion. Sheridan shows that a 75 percent drill pipe loss was experienced due to corrosion in the Gulf Coast area. The authors'! 2 interpretation of drill pipe records from West Texas also indicates that 75 percent of drill pipe loss is due to corrosion. A recent estimate by a large drilling contractor was that drill pipe loss amounted to $120 a day per rig. Based on 75 percent of this as a corrosion loss, the direct cost of corrosion is seen to be about $90 a day per rig. This information clearly shows that the economic loss due to corrosion of drill pipe alone is significant. To this must also be added the cost of pump parts, bits and casing in addition to lost time for fishing jobs and washouts. The latter consideration quite often exceeds the cost of an entire string of pipe.

For example, oxygen scavenger treatments are being adjusted through measurements with an oxygen meter and electrical corrosion probes. The quick response of these instruments is an important benefit in controlling corrosion during drilling. They permit measurements at pump suction and flow line. Oxygen scavenger treatments are adjusted to keep suction readings the same as or less than those of the flowline. This procedure is based on the fact that oxygen enters the pump suction and is consumed in reactions on the drill string while circulating back through the hole to the flow line. Experience has shown that a sulfite residual in the drilling fluid is necessary to take care of oxygen pickup during "trips", chemical or water additions and mud pit cleaning.

Effect of Packer Fluids Packer fluid corrosion problems also constitute a significant economic problem. Workover cost can vary from a few hundred dollars for a simple cement squeeze operation or tubing replacement to possibly millions of dollars lost as the result of a high pressure well failure. It has been estimated that on the average a well will require working over every six years. Of approximately 700,000 producing wells in the United States, 96,000 require some form of workover annually. Packer fluid corrosion, of course, does not cause all of the workovers but it is recognized as a significant contributing cause. Current opinion indicates that packer fluid corrosion problems are increasing because of high temperature, formation contaminants, mud additive contaminants, tubing leaks and increased use of high strength steels. For additional related information on the significance of packer fluid corrosion, the reader is referred to the economic section under "Petroleum-Primary Production" in this book. The functional differences between drilling and packer fluids requires that each be treated in this chapter as a separate environment. Further separation into the various types of fluids presents a problem. There is an abundant variety of drilling and packer fluid types. Many of the types were listed as to their relative corrosivity by a NACE Task

Oxygen Exclusion Important The most effective control for oxygen corrosion is to keep oxygen out of the system. This is difficult, because the drilling fluid is exposed to the atmosphere as it circulates through the pits. However, carelessness is often the cause of excessive oxygen pickup. For example, the improper use of mud guns or mud hoppers is a common occurrence and results in added oxygen contamination. Aerated muds, oxygen contaminated make-up water and oxidizing chemicals all are sources of this environmental corrosion accelerator. In the case of air or aerated driliing, corrosion is a most serious problem. In aerated sea water, corrosion rates of more than 450 mpy (18 lbjsq-ftjyr) have been measured with downhole coupons. In drilling fluids the control of corrosion rates below 50 mpy (2 lbjsq ftjyr) with uniform corrosion is considered a practical objective. A ttack from oxygen in this environment is almost always in the form of pitting, which 104

in a short time can produce irreversible damage to drilling equipment. Sharp-bottomed pits are especially damaging to drill pipe because they cause stress concentrations that increase susceptibility to fatigue failure. Pitting is one of the most deceiving forms of corrosion under drilling conditions. Severe pitting will not always result in the expected associated failures. Pits with round bottoms do not cause failures as often as do those with sharp profiles. Longer exposure and higher stresses are required to produce failures when pits have wide-angled geometry. What makes a pit round or sharp bottomed is not clearly, understood but the grade of steel, environment and stress conditions are all thought to be important factors. Proper environment control has a strong influence on both the form and rate of corrosion attack. When pitting occurs, mitigation techniques should strive to lower the corrosion rate to less than 50 mpy and make the attack uniform. A rate expressed in mils per year has little meaning unless corrosion is uniform, because pits concentrate stress and lead to premature fatigue failures of drilling equipment. Effect of Concentration Cells In drilling fluid environments, pits which often are the result of corrosion concentration cells, affect stress and fatigue life. It is beyond the scope of this chapter to describe thoroughly concentration cells, information on which is covered in many reference and textbooks on corrosion. Briefly, concentration cells are caused by a difference in the concentration of ions on the affected

FIGURE 2 - Results of periodically pumping an amine inhibitor down the drill string exposed to aerated sea water drilling mud. Corrosion attack on the ring was reduced but was still too high to be acceptable.

metal surfaces. Conditions for this to occur in drilling fluids are most often caused by incomplete barriers such as mud solids, scale and corrosion by-product deposits on the exposed drilling equipment. Since ion concentration under-

FIGURE 3 - Appearance of a corrosion test ring exposed to aerated sea water drilling mud after application of 4 gal amine inhibitor every 30 minutes while drilling. Generalized corrosion, rate: 88 mpy (3.6 Ib/sq ft/yr).

neath the barrier is different from that on clean metal. an active corrosion cell can exist. In oxygen-contaminated fluid, concentration cells are serious pitting accelerators. Elimination of the barrier or difference in ion concentra-

FIGURE 1 - Severe pitting on a corrosion ring exposed to aerated sea water drilling fluid in a drill string. Rate: 455 mpy (18.5Ib/sq ft/yr).

tion is needed to control this cause of pitting.

105

:-1

in small quantities as a thinning agent in drilling fluids. An increase in corrosion (pitting) has frequently been experienced following chromate additions. Additions both of oxygen contaminated water and oxidizing chemicals will continue because they are useful and necessary in drilling operations. This is an important, point because corrosion is only one of the factors involved in a complex mixture of mechanical and chemical considerations. The primary objective is to drill a well safely and economically, so consideration must be given to methods that permit this to be done most efficiently. If the use of materials that cause an undesirable increase in corrosion cannot be avoided, then adequate inhibitor treatments should be used to control corrosion.

Sand blasting has been used to clean drill pipe and remove the barriers and scale from the metal. Control methods most often used on operating equipment include frequent treatments with oil soluble, organic, amine inhibitors applied directly to the affected metal surface. Oilsoluble, organic inhibitors must penetrate and cover either the anodic or cathodic areas (or both) of the corrosion cell in order to stifle the cell. Thick scale or corrosion by-products that prevent the inhibitor from reaching the base metal interfere with protection. Mechanical removal of the barrier is necessary under these conditions. Controlling concentration cell corrosion by the removal of an offending ion, such as oxygen, would be impractical in aerated drilling systems. However, the reduction of oxygen is often achieved in normal drilling by additions of tannates, quebracho, or lignosulfonates. Sodium sulfite is now being used in the nondispersed, low-solids polymer muds. These chemicals, along with organic amine treatments, can provide significant protection against oxygen corrosion (concentration cell).

Useful Techniques to Control Corrosion in Drilling Operations Acid-forming gases, carbon dioxide and hydrogen sulfide are serious environmental corrosion accelerators that must be dealt with in drilling fluids. These are often associated with the hydrocarbons of the produced crude oil or gas as well as in formation water and are a major cause of corrosion in the petroleum industry. Both general attack and stress corrosion are caused by them and they produce highly insoluble corrosion products that often are detected in pits and fatigue cracks of drilling equipment, clearly indicating the strong role of hydrogen sulfide and carbon dioxide in the corrosion process. Protecting metal with filming type inhibitors is more difficult due to the shielding effect of these corrosion products, such as iron carbonate and iron sulfide. Because filming amine inhibitors normally form strong bonds only on active clean metal surfaces, barriers such as these interfere. Generally, a clean metal surface is more easily protected by inhibitors than is an unclean surface.

How A mines Are Used There is some discussion under way how on the merits of amine inhibitors for controlling oxygen corrosion. Experience shows that they are ineffective at low concentrations, but work better if applied directly to the affected metal as mixtures of 5 to 20 percent inhibitor in oil or water. Figures I, 2 and 3 show the effect of corrosion from aerated sea water drilling fluid and the results of successive inhibitor treatments on corrosion rings exposed in the drill string. The corrosion attack shown in Figure 1 consists of severe pitting at a rate of 455 mpy (18.5 lb/sq ft/yr). Figure 2 shows reduced attack but a still unacceptable rate. Figure 3 shows benefits from addition of 4 gallons of amine inhibitor pumped down the drill string every 30 minutes while drilling. The rate on this coupon was 88 mpy (3.6 lb/sq ft/yr) and a generalized type of attack was developed in contrast to the pitting in untreated systems. Oxygen corrosion in drilling is not limited to aerated systems, however. Make-up water contaminated with oxygen has a strong influence on corrosion of drilling equipment. In some drilling operations, over 1000 barrels of water per day are used. In one case, approximately 20 percent of the drill pipe wall was penetrated by pitting in three days' exposure. Approximately 2000 barrels of fresh water were added during this period. Corrosion by-products from the pits were identified as oxides of iron, evidence clearly pointing to oxygen as the major cause of corrosion and providing an indication of the damage that can result from simple make-up water additions. Polymer type drilling fluids are susceptible to strong oxygen corrosion attack because they normally do not contain thinners and are generally of a low pH. These fluids tend to foam and entrap air. Oxygen scavengers, organic inhibitors and defoamers are commonly required in these systems. Oxidizing chemicals, such as chromates are often used

Influence of Gas Contamination Contamination by carbon dioxide or hydrogen sulfide from the formation can be quite serious if large volumes of gas are allowed to enter the fluid column. This is best prevented by properly controlling the hydrostatic pressure. When drilling operations are at a pressure near that of the formation or at underpressure, larger quantities of formation gas can enter the mud and more acid contamination will occur. Comtamination can occur while drilling either gas or water-bearing formations, so it is customary to provide an alkaline buffer to help neutralize them. In most cases the alkaline buffer is used to preserve drilling fluid properties as well as to reduce corrosion problems. Alkaline materials have limitations and may be insufficient to neutralize the acid gases if serious contamination is occurring. Under these conditions much of the gas may be vented to the atmosphere from the surface pits or disposed of even more efficiently by de-gassing equipment. In addition, drilling fluid properties can be adjusted to facilitate the escape of the gas. Hydrogen sulfide in sufficient quantities is poisonous if uncontrolled and will be dangerous to rig crews. When 106

control is necessary, metallic salts can be added to the fluid to precipitate the sulfides and reduce the danger. Compounds such as zinc oxide or zinc carbonate are used to combine with sulfide ions to form highly insoluble precipitates in strongly basic muds. This reaction reduces the harmful effects of the sulfide from a health standpoint and possibly aids in mitigating corrosion. However, the long term effects of a continuous buildup of a zinc sulfide precipitate in the drilling fluid is unknown and may become a problem. For example, if pH is lowered, hydrogen sulfide can be regenerated. While this reaction can be controlled in drilling fluids, the pH is naturally reduced under packer fluid conditions. Some caution should be exercised in the use of a packer fluid in which a semi-stable sulfide compound is present. Current practice when high-strength tubing and casing are used calls for a packer fluid free of sulfide precipitate. Zinc oxide and carbonate compounds are only sparingly water-soluble, but the solids still react with the sulfide ion. The insoluble character of the zinc materials allows for this addition to the drilling fluid as a pre-treatment buffer against sulfide contamination.

materials containing carbonyl or sulfur-oxygen groups into carbon dioxide or hydrogen sulfide begins at approximately 150 C (300 F). Thermally stable materials should be used when well temperatures are expected to exceed the 300 F range for extended periods because thermal degradation tends to destroy drilling fluid properties. Water dilution or small additions of sodium chromate are often used together with other additives to keep thermally degraded mud fluids. Both alternatives add oxygen and accelerate corrosion. During drilling operations, organic amine corrosion inhibitor treatments applied to the drill string and alkaline materials in the drilling fluid are usually effective in offsetting the corrosive effects of thermally degraded muds fluid. Both alternatives add dation of drilling fluid additIves is a serious problem in packer fluids.

Biological Effects Microorganisms readily attack drilling resulting in their chemical breakdown to hydrogen sulfide and other degradation breakdown of these additives can result

and

fluid additives, carbon dioxide, products. The in detrimental

changes which are significant in controlling fluid properties and corrosion. Alkaline materials are considered biostats in drilling fluids, but for efficient microorganism kill, biocides are used. The most readily measurable effect of microorganisms in drilling fluid is their consumption of chemicals that results in the loss of desired f1ltration control and rheological properties. These properties are rigidly controlled and their alteration can. result in serious drilling problems. Bacterial cultures can be made from the drilling fluid to determine their presence and populations so that pH adjustments and/or biocide treatments can be regulated. There is little understanding of the scope of the corrosion problem caused by microorganisms under drilling conditions. Investigations have generally been made on packer fluids. Current thinking tends to favor the premise that if physical properties are not harmed, the microorganisms are not a problem while drilling. Consequently, it is not unusual to find active microorganisms in drilling fluids.

Copper Is a Corrosion Hazard Copper compounds also are used as sulfide ion precipitators. The copper compounds are efficient in precipitating sulfide, but can cause accelerated corrosion of steel. Accelerated corrosion associated with copper compounds in drilling fluids was observed early in the history of their use and more recently was demonstrated in laboratory tests by Perricone and Chesser?' Basic copper carbonate is used to combat the sulfide ion problem. Copper carbonate has very limited solubility in water and, as with zinc compounds, the solids react with sulfide ions. The limited solubility of copper carbonate in drilling fluids becomes a corrosion problem as the result of an electrochemical reaction whereby the copper ion is displaced from solution by iron going into solution, causing metallic copper to be plated on the steel equipment. This copper plating on steel equipment results in accelerated galvanic corrosion. Copper plating has been observed on steel drilling equipmen t after only a few hours' exposure to copper carbonate treatments. Laboratory tests have supported field observations showing the copper plating and its accelerated attack on steel coupons. It is clear that some drilling fluid chemicals such as lignosulfonates and tannates aid in the ionization of the copper carbonate which increases copper plating on steel and thus causes galvanic corrosion. Corrosion of iron in an iron-copper couple will continue at an accelerated rate until the copper is removed. For this reason, copper compounds are not generally recommended in drilling fluids.

Drilling fluids also contain materials that can be biodegraded into corrosion accelerators with little. effect on hydraulic properties. Plant and wood fibers are prime examples. It is reasonable to assume that corrosion probably is caused by microorganism by-products in some drilling wells and that their control is desirable. Practical control of microorganisms can be accomplished if pH can be maintained above 10, or if the fluid is saturated with a salt such as sodium chloride. However, because of the proliferous nature of microorganisms in certain drilling fluids, biocides are needed for control. Chlorinated phenols or paraformaldehyde at concentrations up to 2 Ib/bbl are used in drilling fluids. These treatments can vary because solids in drilling fluid usually favor the growth of microorganisms and tend to reduce biocidal efficiency.

Influence of Temperature Acid gas contamination has resulted from drilling fluid materials that have been altered by temperature, 1 2 ,20 microbiological activity! 5 or electrochemical effects.! 9 Contamination originating from thermal breakdown of drilling fluid additives is conditioned by time and temperature. Serious breakdown of many commonly used organic 107

Electrochemical Factors to

potentially damaging hydrogen from the interior of the steel. Purging requires that hydrogen must be allowed to diffuse to the surface. Increased temperature is considered beneficial in facilitating movement of the entrained hydrogen through the steel lattice. Heat seems to have a dispersing effect and enhances hydrogen's escape from the metal matrix, a beneficial effect that may be linked to the relaxation of bonds between metal atoms as the result of

One form of corrosion by-product has been attributed the flow of direct current in the corrosion cell.

Electrochemical reduction of sulfur~oxygen groups results in hydrogen sulfide being formed at the cathode.19 This well-known corrosion cell reaction provides reactive hydrogen near the metal cathode surface. The hydrogen combines with the ever-present suifur-containing compounds in drilling fluid to form hydrogen sulfide, which in turn may attack the steel. These reactions have been demonstrated in

increased temperature. Entrained hydrogen atoms produce microstresses in the metal lattice. With time and increased hydrogen pressure, macrostresses result that often lead to embrittlement

the laboratory and are strongly suspected in field observations where other sources of iron sulfide deposits are not apparent. The consequences of this source of contamination is not clearly understood but is significant primarily in packer fluids and in hydrogen embrittlement problems.

cracking. Some cracks tend to relieve local stresses and may not cause total or visible failure. Once cracks are formed, permanent damage has been done, but final failure may be due to fatigue or some other effect induced by the initial cracks caused by the hydrogen. Present knowledge of this type of failure does not define a functional time limit during which equipment can be used with no hydrogen embrittlement damage. Experience simply teaches that the higher the strength of steel or the stress, the shorter the time required for failure to occur in an embrittling environment.

Effects of Hydrogen Hydrogen embrittlement resulting from exposure of steel to a wet environment at a moderate temperature has been a problem for many years. Surface corrosion initiates the attack which is accompanied by the absorption of nascent hydrogen into the interior of the steel. This results in a reduction of strength and toughness of the structure (Johnson28). The rate of hydrogen absorption is influence by such environmental factors as contaminants, pH and temperature, (McGlasson2 9). Steel hardness (strength) determines the type of failure or damage to a given structure. Spontaneous brittle failure occurs in high-strength steel and blistering occurs in low-strength steels. Hydrogen embrittlement, recognized as a special problem, has resulted in limited use of highstrength steels in the petroleum industry.

Effect of Acid Gases The acid gas contaminants (carbon dioxid-:: and in particular, hydrogen sulfide) increase environmental embrittlement tendencies. Their effect is to increase the volume of hydrogen entering the steel by causing corrosion which supplies hydrogen ions and by interfering with cathodic reactions. Chemical treatments can be utilized to overcome some of these effects. Chemical control of hydrogen embrittlement is usually difficult because environmental alterations will affect only one of the four basic conditions leading to this form of corrosion. However, wells are currently being drilled and successfully completed under embrittling conditions.

Embrittlement by Hydrogen An understanding of the hydrogen embrittlement phenomenon will be useful in reaching a practical solution of the problems it creates. Preconditions for hydrogen embrittlement are high-strength steel, stress, exposure time and environmental factors. Steels with yield strengths greater than approximately 80,000 psi and hardness exceeding Rc20 are susceptible to spontaneous brittle fracture. It is common to find steels of this strength and hardness in drilling and producing equipment. For example, rock bit bearings and bearing races have hardness levels of 55 Rc or greater and this equipment may fail from hydrogen embrittlement in less than five hours while drilling in hydrogen sulfide contaminated fluid. Experience has also shown that amine treatments and pH adjustments may permit bits to be used under similar conditions without premature embrittlement failures. Tool joints, high-strength drill-pipe tubes, drill collars and various drill string tools also are susceptible to failure from hydrogen embrittlement.

Effect of Alkaline Additions Alkaline materials neutralize the acid formed by the gases and thus reduce the hydrogen gradient into steel. Sodium or calcium hydroxide or sodium carbonate are the primary materials used to increase and maintain a basic pH in drilling fluid. Film-forming amine-type inhibitors also are used as inhibitors against hydrogen embrittlement. These materials are known to affect the cathodic sites and tend to offset the detrimental effects of sulfide or other cathodic poisons. Amine-type salts that contain sulfur groups or triplebonded components tend to be effective against embrittlement in drilling fluid environments. Oil muds (water in oil emulsion systems) are clearly recognized as a most effective defense against hydrogen embrittlement as well as other forms of corrosion attack. Both laboratory and field experience have shown that these systems can be contaminated with high concentrations of carbon dioxide or hydrogen sulfide and remain free of corrosion or of embrittling tendencies. Saturated salt water tends to be less conducive to embrittlement than fresh water. It is thought

Influence of Stress Both residual and applied stresses increase embrittling tendencies. It is interesting that a continuous stress for a given time is required for this form of failure to occur and that under some conditions the metal may be purged of 108

that this is due to the decreased solubility of gases in the salt-saturated fluid.

organic material to the exposed metals. This avoids mixing the inhibitor with the bulk of the drilling fluid. Film forming inhibitors tend to be adsorbed on the solids in drilling fluids and thereby lose their effectiveness. For this and other obvious economic reasons, the batch method is recommended over continuous concentration type treatments. Because some organic inhibitors are compatible with certain types of drilling fluids, a fixed concentration can be established for corrosion control. Such materials are

Use of Saturated Salt Solutions Saturated salt solutions are commonly used both as drilling and as packer fluids. Unsaturated salt solutions are believed to cause more severe corrosion than saturated fluids. Increased solubility of acid gases in the dilute solutions is the basic cause. Inhibitors are commonly recommended for these solutions because corrosion is

primarily long chain organic acids soaps useful as torque reducers and extreme pressure lubricants. Their dual usefulness tends to justify the extra cost of continuous concentration type treatment. Organic inhibitors used to protect drill pipe in weighted as well as in low-solids muds are effective when proper attention is given to the application method. Every effort should be made to apply the inhibitor to the drill pipe rather than to mix it in the drilling fluids. This permits better control of drilling fluid properties and avoids excessive corrosion inhibitor costs.

clearly a problem in highly conductive salt environments. Oil Mud Drilling Fluids Oil mud drilling fluids have been in wide use for a number of years. These fluids are composed of a continuous oil phase in which water has been emulsified. The emulsifying agents consist of organic soaps and aminereacted compounds and are not only strong emulsifiers but also are excellent corrosion inhibitors. The water that is emulsified into the oil contains various salts, including alkaline materials. In a properly prepared oil mud, the water phase does not contact the drilling equipment. This type of drilling fluid is stable to extreme pressures and temperatures encountered. Due to their electrical nonconductive properties corrosion is not a problem. Oil mud drilling fluids have many useful properties and experience has shown that they function efficiently even under severe conditions. They are the most effective answer to corrosion problems.

Steps in the Procedure follow: 1. Establish corrosion rate and identify type of corrosion attack with drill string corrosion coupons prior to treatment. Each well should be evaluated individually and inhibitor treatments based on evaluation of the corrosion coupons. 2. Prepare a mixture of organic inhibitor with diesel oil or sweet crude oil in a separate mixing tank. The inhibitor-oil mixture can be varied from 1 to 6 to 1 to 13. Example: For 100 gallons of a·l to 13 mixture: 7 gallons of inhibitor to 93 gallons of oil. Because concentration and frequency of treatment will vary, better results will be obtained by establishing the proper treatment for each well. When the inhibitor cannot be diluted with oil, it can be used in its concentrated form. Some organic materials are dispersible in water, which may be substituted for the oil. 3. Drill pipe in the hole should be mmed initially by adding 1 to 2 barrels (42-84 gallons) of inhibitor-oil mixture at the pump suction and pumping the batch around. 4. For maintenance treatment, batch 5 to 15 gallons of inhibitor-oil mixture through the pump suction every 2 to 4 hours. If the corrosion rate is reduced and pitting or localized corrosion attack is not occurring, treatment frequency usually can be reduced. 5. After completion of the well, the drill pipe should be washed inside and out to remove all the drilling fluid and drilled solids. It should then be treated with inhibitor-oil

Drilling Fluid Inhibitors Inhibitors are used most often to remove or neutralize contaminants or to form a film with relatively high dielectric strength on the equipment. Oxygen scavengers, such as sodium sulfite are currently used in both water and oil muds. Calcium or zinc compounds are used to precipitate carbon dioxide or hydrogen sulfide. Alkaline materials are used in drilling fluids for both rhelogical control and corrosion inhibi~ion. Generally, pH is increased above that normally required for good fluid properties when corrosion inhibition is needed. Although this can be done with most alkaline materials, sodium hydroxide is the main chemical used for this purpose. As a rule when corrosion rates are below 2 lb/sq ft/yr and uniform corrosion attack is occurring, pH control is all that is needed for effective inhibition. If corrosion attack is localized or of the pitting type, then organic, film forming inhibitors such as cationic amine salts are strongly recommended. Some judgment is required in these inhibitor treatments. For example, previous pitting damage of the drilling equipment (drill pipe) should be taken into account.

mixture by spraying inside and out or dipping prior to storage on the rack. 6. Where corrosive conditions are severe, the inhibitoroil mixture can be batched down the drill pipe during connections and poured into the annulus to mm the drill pipe while making a trip. This type of batch treatment is usually based on tlle rule of thumb: 1.5 gallons of inhibitor-oil mixture for each 1000 feet of drill pipe in the hole. Spray equipment has been designed to treat the O.D. of the drill pipe while making trips. This technique is preferred in coating the outside of the drill string.

How Film Forming Amines Are Used Film-forming organic inhibitors are most effective when applied directly to the metal surface. Because they have the ability to displace water in surface pits and fatigue cracks, they are extremely useful in drilling fluid environments. Batch type treatments are used to deliver the

109

operations, for proper displacement into the annular space and to permit moving to overcome well pressure if necessary. To serve these useful purposes the packer fluid must have good hydraulic properties (density, rheology, gellation. Simpson30). The packer fluid also should protect against corrosion. Materials commonly used to produce the required hydraulic properties are often unstable at some specific temperature and pressure and can produce corrosion contaminants when altered by bacterial, thermal or electrochemical effects. These effects are more critical under

A weighted (high-solids) drilling fluid is more abrasive than a low-solids fluid and the solids will tend to erode the inhibitor/oil film from the drill pipe. In this case, more frequent treatments are required. In a high-solids or viscous drilling fluid" the use of a water cushion directly ahead of the inhibitor/oil mixture can be beneficial. This cushion tends to clean the drill pipe to allow the inhibitor-oil mixture to reach and adhere to the metal surface more readily.

Use of Drill String Corrosion Coupons One of the most widely used techniques in drilling fluid corrosion control employs drill string corrosion coupons used to study the corrosive effects of a drilling fluid, to determine the need for a corrosion inhibitor treating program and to evaluate its effectiveness. Following are suggestions for using drill string corrosion coupons. I. Drill string corrosion coupons should be exposed to the drill string for approximately 50 hours. A variation of plus or minus 10 hours is not critical. Short times (10 hours) should not be used because initial corrosion rates are usually high and can give misleading data. The coupon is usually placed in the first tool joint above the drill collars and can be left in the drill string for more than one bit run. 2. After exposure, coupons can be cleaned with soapy water, using fine steel wool and alcohol for drying prior to weighing. 3. The type of corrosion attack is as important as the corrosion rate and should be noted when a coupon is removed from the drill string. The different types of corrosion attack can be described as pitting, localized or generalized. Pitting is the most serious and potentially destructive form of corrosion in drilling fluids. 4. After a pre-weighed drill string corrosion coupon has been cleaned properly and the corrosion film and type of attack noted, the coupon should be reweighed and the corrosion rate calculated. The corrosion rate for steel is

packer fluid conditions due to time factors and inaccessibility for correction. Materials to combat these bad effects must be utilized in a preventive as well as corrective sense. Potential corrosion problems as well as initial corrosion must be considered in packer fluid treatments. Problems of settling, gellation, solidification and corrosion are regarded as inherent in many packer fluids. More often than not, the mud used for drilling will be used subsequently as a packer fluid. Contaminants entrained in the mud while drilling may continue to cause corrosion problems in the packer fluids. Examples are bacteria, mineral salts, carbon dioxide and hydrogen sulfide and possibly oxygen. Biocides, corrosion inhibitors and specially prepared fluids are used to overcome the various packer fluid problems. When packer fluids are placed in the annuli of wells it is assumed that they are set apart from outside contamination. Unfortunately this is not always the case, because of leaky packers or couplings. Very small leaks into the tubing-casing annulus may not be noticed or not regarded as important as a production problem and are corrected by bleeding the pressure from the annuli. However, these leaks often result in packer fluid-side corrosion failures. Contamination from the produced fluid side and less frequently from the formation side are contingencies that experience has shown should be considered in packer fluid corrosion control. Additional chemicals to help consume or buffer these outside influence should delay serious attack in the event of a small leak. Every care should be exercised to prevent leaks from occurring and causing corrosion problems in the annular spaces.

reported as mpy (mils per year) or lb/sq ft/yr mpy = lh/sq ft/yr x 24.5 Corrosion rates are usually lower when proper inhibitor treatments are used but even then a coupon may show a few deep pits. This indicates a more serious corrosion problem than does a coupon showing a high corrosion rate but with generalized corrosion only. For this reason, microscopic examination of corrosion coupons is desirable for full evaluation.

Hydrogen Embrittlement Effects Environment caused hydrogen embrittlement is a serious and difficult problem to control in packer fluids. All conditions conducive to this form of corrosion occur in most packer environments. Tubing failures caused by hydrogen embrittlement have been described in the literature.1 6,19 It was determined that these failures were the

Packer Fluid Corrosion Control The primary function of a packer fluid is to contain a well safely in the event of a downhole equipment failure. To do this, the weight of the fluid must be sufficient to balance the well pressure. The packer fluid should also protect pipe against burst or collapse and should be reasonably uniform in density throughout the fluid column. To achieve this, gravitational force must be overcome and this requires stable suspension and gelling properties. Good fluid properties are needed for completion and workover

result of reactions from the packer fluid side. Environment originated hydrogen embrittlement also has affected casing strings. One example (Figure 4) shows a casing collar that failed in less than a year's exposure to a water-base lignosulfonate treated mud. Collars were made of 125,000 psi quenched and tempered steel with proper metallurgical composition and tensile strength. Iron sulfide detected on the fracture face clearly showed hydrogen sulfide to be the 110

packer fluid. This nonconductive environment has advantages over water when treated with an inhibitor and functions well as a packer fluid. Corrosion problems exist, however, because it is highly unlikely that the system will be entirely free of water. Laboratory corrosion tests have shown that both surface corrosion and hydrogen embrittlement can occur in oil when free water is present. Strong corrosion cells can exist when there is an interface between water, oil and metal. The common contaminants should be considered also as possible trouble makers in this environment. Organic amines or amine-salts are effective in most oils. Good inhibitor solubility in the oil and dispersion in water has proved best. While low inhibitor concentrations are effective, it is desirable to use relatively high concentrations to take care of possible leaks or other unforeseen problems. Concentrations of 0.5 to 1.0 volume percent inhibitor are commonly used for an oil packer fluid. Fresh and Salt Water Packer Fluids Either fresh water or saturated salt solutions are preferred. Salt solutions considered here include sodium or calcium chloride whose saturated solutions have the advantage of lower solubility to corrosive gases and a reduced possibility of bacterial problems.' 5 The high conductivity of the salt solutions is, of course, a disadvantage. Less than saturated solutions offer fewer advantages, but fresh water is less conductive. Water soluble organic inhibitors in the concentration range of I to 3 percent are recommended. Where applicable, inhibitors should have biocidal properties or a compatible biocide should be included. In additions, the pH should be increased with an alkali such as sodium hydroxide. A P-alkalinity of 0.5 or greater is suggested, if compatible with the subject fluid and inhibitors.

FIGURE 4 - This 125,000 psi casing collar failed after less than a year's exposure to a water base lignosulfonate treated mud. Hydrogen sulfide was believed to be the primary cause of failure.

primary environmental cause of failure. It was determined that high temperatures caused degradation of mud chemicals and formation of hydrogen sulfides. Bottom hole temperature was about 300 F.2 Under critical conditions involving high pressures and temperatures such that high strength pipe is required, oil type packer muds or casing packs are strongly recommended.

Note: Every precaution should be taken to maintain a clear fluid. Solids have no redeeming qualities in unweighted packer fluids and when practical should be avoided. Brines should be tested for scaling tendencies at bottom hole temperatures. Some of the mud used in drilling the well will no doubt remain in or on the casing. Where fresh water or brine is used, some corrosion will probably take place and some hydrogen sulfide or carbon dioxide may be formed. High strength pipe should not be used under these conditions.

has traced the development of packer fluid technology and made recommendations for corrosion control under a variety of conditions. His work'8 includes the requirements of packer fluids and casing packs. Some of the conclusions from his work are presented in Appendices I and 2. Simpson3o

Medium Density Packer Fluids

Both surface corrosion and hydrogen embrittlement problems are found in packer fluid environments and high temperature and high pressure also must be considered. The location of a well may be such that extra precautions are essential to prevent equipment failures as would be the case when located in cities or on offshore platforms. Recommendations listed below begin with the low priority and less critical problems and proceed through the more difficult situa tions.

Packer fluid densities of not more than 11.5 pounds per gallon are considered here. Where low strength materials are used, no danger of spontaneous brittle type failures is expected. Well temperatures below the thermal degradation point of materials in the packer fluid will result in fewer corrosion problems, so tests may be required to establish the thermal resistance of the drilling fluid to bottom hole temperature. Sulfide or carbon dioxide may be generated by bacterial action on mud products and should be controlled.

Refined or Crude Oil Packer Fluid Under low pressure well conditions oil can be used as a

Economics of workovers must be considered, but in locations where there have been little expense and few 111

TABLE

1 - Summary of Inhibition

Recommendations

for Drilling and Packer Fluid Corrosion

gelation of the mud or settling of solids may eventually occur, necessitating a wash-over operation. Where high risk is involved, or workover expense has been high in instances when water base packer fluids are used, a properly formulated oil mud should be substituted. As packer fluid density requirements are increased, larger amounts of suspended solids are needed. Under these conditions it is more difficult to maintain the previously cited desirable properties in water base muds. However, hydraulic and corrosion resistant characteristics of oil muds are easily controlled when higher density is required. Properly prepared oil mud can be made stable to temperatures in the 260 C (500 F) range. Hydrogen embrittlement is not considered a problem in properly formulated oil mud systems.

Problems

Treat the Cause of the Problem Problem

Material

Treatment

Oxygen

Sodium sulfite Tannates

Oxygen scavenger

Lignosulfonates Carbon dioxide

Neutral ization

Sodium hydroxide Calcium hydroxide

Precipitation Neutralization

Hydrogen sulfide

Sodium hydroxide Sodium carbonate Zinc oxide Zinc carbonate

Precipitation

Salts

Concentration Dilution

Same salt Water

Microorganisms

Biocides

Chlorinated phenols Paraformaldehyde

As conditions become more critical, water-base packer fluids become less dependable; therefore, when temperatures approach 300 F, or if high strength pipe is used, oil mud packer fluids or casing packs are recommended.

Summary

Treat the Effect of the Problem All contaminants

Organic film formers

Corrosion control in drilling and packer fluids requires various techniques, some of which are summarized in Table

Organic amines, Amine salts of

1.

long chai n fatty acids. Long chain fatty acid soaps

References 1. J. W. Pennington. History of Drilling Technology and Its Prospects, The Drilling Contractor. December, 1949. 2. J. C. Swan. Method of Drilling Wells, U. S. Patent Records No. 1,455,010, October 29,1919. 3. F. N. SpeIler. Corrosion Fatigue of Drill Pipe is Cut by the Chemical Treatment of Mud, Oil and Gas J.. November 14, 1935. 4. F. N. SpeIler. Prevention of Corrosion Fatigue Failures, March 24,1937, U. S. Patent Records No. 2,132,586. 5. Private communication. 6. R. C. McMaster .BatteIle Reports on Field Survey, The Drillinf( Contractor, April 15, 1947. 7. W. H. Betz and L. D. Betz. Inhibition of Drill Pipe Corrosion, Drilling, (1946) May. 8. Private communication. 9. P. D. Thomas. Straight and Corrosion Fatigue, Dri/linf( (1939). 10. R. S. Grant and H. G. Texter. Causes and Prevention of Drill Pipe and Tool-Joint Failures, API Drilling and Production Practice, p 9-48 (1941). 1I. A. P. Maradudin. Drill Pipe, Casing, Tubing, Sucker Rods~Corrosion Failures and Methods of Combating Corrosion, Reprints of Symposium on Sulfide Stress Corrosion Cracking, NACE, Houston, Tx. 12. H. E. Bush, R. D. Barbee and J. P. Simpson. Current Techniques for Combating Drill-Pipe Corrosion, API Drilling and Production Practice, pp 59-69 (1966). 13. Behrens, Holman and Cizek. Technique of Evaluation of Corrosion of Drilling Fluids, Paper presented at the Southern District API Meeting, March 1962. 14. H. E. Bush. Embrittlement Test, U. S. Patent Records No. 3,468,160 and 3,585,852. 15. Johnston and Cowan. Recent Developments in the Microbiology of Drilling and Completion Fluids, Developments in Industrial Microbiology, Volume 6. American Institute of Biological Sciences, Washington, D. C. (1964). 16. J. P. Simpson. Corrosivity of Drilling and Completion Fluids, NACE Houston Section Short Course, Houston, Texas. January, 1966.

Change the Environment

All problems

1

1 Oil mud systems

problems, a water-base mud treated with a biocide may be satisfactory. Biocide treatments that are effective against both aerobic and anaerobic bacteria should be used and should be compatible with the packer fluid. Anionic or nonionic materials that are judged effective and compatible with the strongly anionic mud solids should be used if they do not cause health problems to rig personnel. Cationic materials are notably ineffective in muds with suspended solids because they react with and are deactivated by the anionic mud materials. Chlorinated phenol type biocides have been found effective under a wide variety of packer fluid conditions. The commonly used paraformaldehyde is considered effective but has a short life. Biocide treatments of 0.5 to 1.0 Ib per barrel are usual, but sometimes higher concentrations are required. For complete sterilization, treatment recommendations should be based on tests of the packer fluid. It also is well to be sure that the mud does not contain soluble sulfides. The interval over which the mud remains relatively noncorrosive may be extended if pH can be increased and maintained at about 11.5 for a few days prior to completion, but solids should be kept at a minimum to avoid excessive gelation if the pH is increased to this range. Severe 112

Be noncorrosive, Le., resist corrosion from oxygen, carbon dioxide, hydrogen sulfide, organic acids or bacteria that might be present. Because the packer fluid is designed as a non-communicating system, the primary consideration is to formulate a fluid that is functional under the conditions listed.

17. Barbee. Corrosion Control Important in Packer Fluids: Casing Packs, Petroleum Equipment. March-April, 1966. 18. J. P. Simpson and R. S. Andrews. Oil Mud Packs for Combatting Casing Corrosion, Mat. Pro.,' 5, No. 6 (1966) June. 19. Simpson and Barbee. Corrosivity of Water Base Completion Fluids, Mat. Pro., 6, No. 12 (1967) December. 20. W. C. Skelly and Kjellstrand. The Thermal Degradation of Modified Lignosulfonates in Drilling Mud, The A.P.I. Div. Prod., Houston, Texas, March 1966. 21. B. G. Chesser. Corrosivity of Chrome Treated Sodium Lignosulfonate Packer Fluid Systems, A.P.I. Div. Prod., Tyler, Texas, March 1968. 22. J. A. Clark and H. Sheridan. Experience with Plastic Coated Drill Pipe, The Drilling Contractor, November-December, 1965. 23. A Survey of Corrosion Control in Drilling and Annular Fluids, NACE Publication 10168, NACE, Houston, Texas. 24. B. W. Bradley. Oxygen, Cause of Drill Pipe Corrosion, The Petroleum Engineer, December, 1970. 25. F. E. Blount and E. S. Snavely. Use of High-Capability Oxygen Meter in Corrosion Control, Proceedings NACE 25th Conference, 1969. NACE, Houston, Texas, pp 193-208. 26. K. E. Wattman. New Weapon Joins Battle to Extend Drill Pipe Life, Drilling, August, 1963. 27. A. C. Perricone and B. G. Chesser. The Corrosive Aspects of Copper Carbonate in Drilling Muds, Milchem Research Technical Bulletin. 28. William H. Johnston, Memoranda. The Action of Nascent Hydrogen on Iron, Scribner's Monthly Magazine, May to October, 1874. 29. R. 1. McGlasson. Special Metallurgical Problems, Proc. U of Okla. Corrosion Control Course, Norman, Okla. 1970. NACE, Houston, Texas. 30. J. P. Simpson. Stability and Corrosivity of Packer Fluids, Presented in a panel discussion on packer fluids at the 1968 API Southwestern District Meeting, Tyler, Texas, March, 1968.

The casing pack is defined as the fluid left in the casing formation annulus.

APPENDIX 2 Characteristics of Packer Fluids for External Casing (in Addition to Those for Casing-Tubing Annulus) Have very low filtration rate to avoid significant loss of volume or change in composition of the pack. Be sufficiently gelled to prevent migration of fluids within the annulus. Protect casing from corrosion by formation fluids. (Provide physical barrier and/or chemical resistance.)

BIBLIOGRAPHY Symposium on Sulfide Stress Corrosion. Corrosion, 8, No. 10, 325-360 (1952) Oct. D. R. Fincher. Corrosion Problems Associated With Sour Gas Condensate Production, Corrosion, 15, No. 8, 413t-416t (1959) Aug. D. W. Shannon and J. E. Boggs. Factors Affecting the Corrosion of Steel by Oil-Brine-Hydrogen Sulfide Mixtures, Corrosion, IS, No. 6, 299t-302t (1959) Nov. C. M. Hudgins, J. E. Landers and W. D. Greathouse. Corrosion Problems in the Use of Dense Salt Solutions as Packer Fluids, Corrosion, 16, No. 11, 535t-538t (1960) Nov. R. S. Ladley. Stress-Corrosion Cracking of High Strength Oil Country Tubular Goods, Corrosion, 16, No. 11, 539t-542t (1960) Nov. M. F. Baldy. Sulfide Stress Cracking of Steels for API N-80 Tubular Products, Corrosion, 17, No. 11, 509t-513t (1961) Nov. 1. P. Simpson and R. S. Andrews. Oil Mud Packs for Combating Casing Corrosion, Mat. Pro., 5, No. 6, 21-25 (1966) June. B. J. Ramey and B. G. Price. Causes, Detection, Prevention: Drill Pipe Corrosion Fatigue Failure, Mat. Pro., 5, No. 6, 86-88 (1966) June. B. W. Bradley. Oxygen-A Major Element in Drill Pipe Corrosion, Mat. Pro., 6, No. 12,40-43 (1967) Dec. G. 1. Nunn and O. H. Haveman. Getty Oil's Experience With Packer Fluids, Mat. Pro., 7, No. 12,37-38 (1968) Dec.

APPENDIX I Characteristics of Packer Fluids for Casing-Casing or Casing-Tubing Annuli Provide density as required to assist in maintaining the packer seal and in preventing bursting or collapse of pipe. There should be no compacted settling of solids and sludging and top separation of liquid should be minimal. Be fluid enough to permit placement in a small annulus or a good displacement in a large annulus. Be stable at downhole conditions of temperature and pressure.

113

Inhibitors for Potable Water

GEORGE B. HATCH*

Potable waters vary widely in composition and corrosivity. Some are extremely aggressive, while others cause neglible attack, unfortunately the latter are a rather small minority. Surface supplies generally approach saturation with respect to dissolved oxygen. As a result, they usually are quite corrosive unless the water lays down a protective film or deposit (i.e., unless it is naturally inhibitive). Deep well supplies generally are essentially devoid of dissolved oxygen and as a result practically noncorrosive. Unfortunately, absorption of oxygen is difficult to prevent, particularly when appreciable treatment (e.g., clarification, settling, etc.) is required prior to introduction into the distribution system. It follows that many potable water supplies require treatment in order to alleviate problems raised by corrosion of the distribution system. The number of inhibitors available for treatment of

tion system. Increased pumping costs of $40 million a year have been estimated to result from obstruction of flow by corrosion products. 1 The problem becomes increasingly acute as increases in water consumption tax existing distribution facilities. Failure of piping as a result of corrosion on the water side seldom is a problem in potable distribution systems. This contrasts with the situation encountered on most other inhibitor applications where internal failures are perhaps the most serious manifestations of corrosion. Dearth of internal failures probably is a consequence of the rather extensive use of heavy-wall, cast-iron pipe in municipal distribution service. Corrosion of water heaters poses a much more expensive problem. Replacement costs have been estimated at $300 million a year.1 This problem generally is considered to be one to be passed on to the individual consumer. Inhibitor levels are chosen for protection of the major distribution system and treatment of the entire system at an inhibitor level sufficient to protect the individual consumer's system-either hot or cold-seldom has been

drinking water is drastically limited by potability considerations. Moderate pH elevation, calcium carbonate scale and limited concentrations of silicates, polyphosphates and zinc salts are about the only inhibitors permissible for potable service at this time. All of these have been known for a number of years and have been investigated quite extensively, both alone and in combination. Levels of the permissible inhibitors are considerably restricted by potability requirements.

Economics of Treatment Economic considerations frequently lead to even more drastic limitation of treatment levels. The beneficial effects of the treatment on the distribution system and the quality of its effluent must be balanced against its cost. Carrying capacity falls off long before corrosion products reduce the cross-sectional area of a water line appreciably. Increased surface roughness, such as produced by relatively small scattered tubercules, suffices to interfere with flow quite markedly. Tuberculation which sufficed to lower the Williams-Hazen Friction Coefficient of a cast iron main from 128 to 110 is shown in Figure 1. This photograph shows a section of the line removed for inspection prior to recleaning to restore the needed carrying capacity. From an economic point of view, obstruction to flow is the major problem raised by corrosion in a water distribu-

FIGURE 1 - Tuberculation of cast iron water main which reduced the WilliamlYHazen Friction Coefficient from 128 to 110.

*Deceased. Formerly with Calgon Corp., Pittsburgh, Pa.

114

20

10 Cl Cl

~

l,,/ ,

systems usually leads the individual home owner to select the alternative of more resistant and more expensive materials. Some larger cities require that any auxiliary treatment system be supervised and the levels thereof periodically checked by qualified personnel. Thus, there are two more or less discrete aspects of the problem: Inhibitor treatment for the distribution system and auxiliary protective measures for the consumer systems.

~~-------~------------,~ ALUMINUM (3003-H14)

I'

Characteristics

I (J) (J)

g

of Potable Water

Potable waters of the United States vary quite widely in composition. Dissolved solids range from about 20 mg/l to over 2 g/l. Over 100 public supplies exceeded 2 g/l total solids in 1962.2

0

I- 100

::r:

t:}

w

Analyses of some of the different types of waters which serve as potable supplies in the United States are included in Table 1. These data were chosen from the compilations of Lohr and Love.3 The first column of the table gives the composition of a very soft water of low dissolved solids content, a type quite common along the Northwestern and Eastern seacosts. Natural soft supplies are not limited to low solids waters. For example, the water in Column 2, although low in hardness contains quite high levels of alkali metal, bicarbonates, sulfates and chlorides. Data for a lime-soda softened effluent are given in Column 3. The pH of this particular supply is higher than usual because the softener effluent was not recarbonated.

s: 50

o 0.5

COPPER CONC. Mg/I FIGURE 2 - Influence of dissolved copper on corrosion of aluminum and zinc by Pittsburgh tap water.

attempted. Protection the owners.

Potable waters also include hard waters of high electrolyte content as shown in Column 4, for example. The hard, acid-supply shown in Column 5 reflects contamination from coal mine drainage. It is rather unusual in that the pH generally is raised to at least five, even where no other measures are taken to alleviate attack.

of these individual systems is left to

Corrosion Products are the Problem in Potable Water Systems

The recommended maxima for drinking water2 are shown in the last column. When these values are exceeded, another supply, if available, is recommended. Unfortunately, these recommended maxima are quite frequently exceeded and even the mandatory limits occasionally are exceeded (e.g., the fluoride contents of the waters in Columns 2 and 4).

Deterioration of water quality is an additional major consequence of corrosion in a potable distribution system. Although essentially a problem of consumer relations, it generally has priority over strictly economic considerations. En trainmen t of corrosion products with the result red and turbid water is a sure source of consumer complaints. Occasionally, the red water problem has been alleviated by moderate elevation of pH. This tends to precipitate the hydrous ferric oxide before it can reach the consumer. Frequently this practice has been unsuccessful and even where it has controlled red water successfully, it obviously has been of no help in maintaining the carrying capacities of the mains. The products of corrosion attack are the most troublesome aspect of corrosion in the distribu tion system. They obstruct flow when they remain in the lines and cause red water when they do not. The only satisfactory solution is to inhibit the attack. The consumer, in an effort to control corrosion of his piping, may use an auxiliary inhibitor feed or may substitute more resistant materials than iron to handle the

Influence of Dissolved Oxygen Unfortunately, the values for dissolved oxygenprobably the most important constituent from the corrosion standpoint-are not included among the data in Table 1. Potable supplies generally fall in or are adjusted to a pH range (i.e. 5-11), where depolarization of the cathodically liberated hydrogen is required to sustain appreciable corrosion. Even in oxygen saturated supplies, the corrosivity of a water cannot be calculated from its analysis. A rather rough qualitative estimate is about the best that can be made. Dissolved oxygen does not render pure water particularly corrosive, at least at normal temperatures (i.e., 0-4OC). However, additions of traces of sulfate or chloride (e.g., 0.55 mg/I) suffice to make it highly aggressive.4 Larson and coworkerss-7 have found that chlorides, sulfates and nitrates stimulate corrosion of iron in oxygen-

water. Large installations such as apartments, office buildings, etc. generally find inhibition more economical. The cost and attention required to maintain auxiliary inhibitor

115

TABLE 1 - Compositions of Various Domestic Water Supplies

----- - -

(1)

-

00.1 0.00 3.6 -94.0 -250.0 -244.0 -520.0 0.3 USPHS 540.0 Hard 00 S0.2 oft 7.0 Effluent Acid 33.0 0170.0 10.0 0(4) 45.0 53 6-1.7( 74.0 01.8 462.0 10 22 086.0 4.0 06.0 1.6 1.8 4.6 Maxima lime-Soda 500.0 3.9 10.6 7.4 0.07 306.0 8.2 0.05 .38 7.8 250.0 344.02.6 768.0 167.0 228.0 16.0 0.0 67.0 0156.0 288.0 5.8 Solids22.0 Hard Soft 233.0 0.7 7.6 13.2 00.1 0.8 5.7 02.7 1.4 1550.0 0.08 1210.0 0.5 8.0 0.4 2.5 2.2 7.0 153.020.0 19.0 2.0 (2) Electrolyte (6) (5) (3) Electrolyte High High Bicarbonate (HC03)

(Concentrations in mg/I)

l)

(l)Limit is temperature dependent.

nonmetallic materials in this service is included in the paper by Wilson. 1 0 Copper and lead (in some of the older system s) serve as lead-ins to the consumer systems. Thus, they can affect the quality of the water delivered to the consumer.

bearing water, while calcium, bicarbonate and hydroxide were inhibitive. They suggested that the corrosivity of air-saturated domestic waters depends on the ratio of aggressive to inhibitive ions. Examination of Table 1 from this standpoint suggests pronounced differences in the corrosivity of these domestic supplies.

Toxicity of Dissolved Lead Dissolved lead is highly toxic. Consequen tly, it is of concern to the supplier even when restricted to the consumer's system. Although, lead is not commonly used nor should it be used-in modern water piping, it still may be encountered in some older systems. The magnitude of the dissolved lead problem is brought out in a recent report of the Bureau of Water Hygeine, V.S. Public Health Servicell which covered 989 supplies that serviced 18.2 million people. Roughly 2% of these were found to be consuming water with excessive concentrations of lead (Le., over the U .S. Public Health Service's mandatory limitsl2) the source of which was attributed to lead pipes in the home or supply systems.

Influence of pH The pH affects both the type and velocity of the attack. It also influences the performance of inhibitors against the attack as well as affecting deposit formation. Differences of pH in the range of 5 to about 9.5 do not significantly affect the rate of attack of iron and steel by nonscaling, oxygen and calcium-bearing waters.8,9 Corrosivity with respect to ferrous metals falls off quite rapidly with further elevation of the pH.

Materials Used in Water Systems Distribution Systems Although gray cast iron long has been the principal material used for distribution lines, steel and ductile iron are used to a lesser though growing extent. Protection of these ferrous metals is the primary aim of corrosion control in the distribution system. Lines fabricated from nonmetallic materials such as

Consumer Systems A rather wide range of metals is used in consumer's water systems. Steel, galvanized iron, copper, bronze and red and yellow brass are among the more common. Lead, aluminum, monel and both ferritic and austenitic stainless steels also may be encountered occasionally. Each of these metals, to a greater or lesser degree, adds its own particular corrosion problems. The manner in which the system is fabricated greatly

concrete, asbestos cement and plastic are being used to an increasing degree in distribution systems but they will be excluded from the present discussion because they are not subject to electrochemical corrosion. Further information concerning the current use of both the metallic and

116

affects its susceptibility to attack. Care should be taken to avoid crevices, deposits, thread cuttings and miscellaneous debris which can obstruct access of dissolved oxygen to the metal surface and thereby set up differential aeration cells. The latter are detrimental to all of the metals involved, but especially to aluminum, monel and stainless ste~ls. Frequently, unfortunate combinations of different metals in a single system cause severe galvanic corrosion. Direct couples of some of these different metals are a rather obvious source of trouble and are particularly destructive where the area of the cathodic metal is large compared to that of the anodic component. Couples also may develop during operation of the system. Traces of metal dissolved from upstream portions of the system frequently deposit on contact with more active components. The resultant couples can lead to serious attack of the more active metals. Relatively insignificant corrosion of the cathodic metal can dissolve amounts sufficient to accelerate attack of the active component to a pronounced degree. For example, even 0.1 mg/l of dissolved copper markedly accelerated attack on zinc1 2 and aluminum as illustrated by the data in Figure 2. Impingement attack of copper is a rather common source of trouble in some of the larger consumer systems (e.g., apartment and institutional buildings, hospitals, etc.). Among the more recent discussions of the problem are those of Obrecht13 and Hatch 14. The difficulty often stems from an unfortunate choice of materials, because copper is particularly susceptible to attack of this nature. Even under optimum conditions, flow velocities over 5 ft/sec should be avoided where copper is used. The presence of an entrained second phase (e.g., air bubbles, suspended solids, etc.) reduces the allowable velocity even further. Copper portions of circulating hot water systems adjacent to the suction side of the circulating pump are particularly susceptible to impingement attack because dissolved air can separate from the water if pressure reduction is excessive. Air also may be pulled in through leaky faucets. In either case it tends to promote impingement attack.

FIGURE 3 - Copper tubing sections from circulating hot water system which suffered severe impingement attack.

Figure 3 shows two sections of copper tubing from a circulating hot water system of a hospital which have suffered severe impingement attack. Tubing was undersized and the susultant excessive flow velocity led to the attack. Copper also may suffer localized attack (Le., pitting) which does not involve excessive flow velocities. It is fortunate that pitting of this type seldom is encountered because its causes are not fully understood. Figure 4 shows an example of such attack. The bright spots in the pit at the left are caused by reflections from relatively large crystals of cuprous oxide at the bottom of the pit. Well formed crystals of cuprous oxide such as this generally are associated with this type of localized attack on copper. Influence of Temperature Water temperatures in the distribution system may range from just above freezing to around 30 C. Temperatures of almost 100 C frequently are encountered in domestic hot water service despite admonitions to limit

FIGURE 4 - Pitting of copper tubing in domestic service.

117

essentially a dilute solution of calcium sulfate which contained a moderate amount of chloride and was rather low in bicarbonate. The hardness showed a seasonal variation from about 35 to 200 mg CaC03/1 while the pH averaged 6.7.

Inhibition of Potable Water pH Elevation pH elevation alone is not frequently relied on for corrosion protection. Yet, its inhibitive action is pertinent, because its properties frequently persist and substantially alter the nature of the protection obtained from other inhibitors. A sufficient increase in pH (e .g., 10 to 11) will inhibit the corrosion of iron and steel quite effectively. However, use of this method is restricted to relatively soft waters where excessive depostion of calcium carbonate scale does not pose a problem. Effluents of lime-soda softeners are inherently well adapted for corrosion control by this means. Calcium carbonate depositon from such an effluent (i.e., afterprecipitation) can be prevented quite simply by treatment with 0.25 to 0.5 mg/l polyphosphate. The lime-soda softened supply depicted in Column 3 of Table I is an example of water where this type of corrosion control is involved. Harder waters (Le., 100 mg/l CaC03) cannot be stabilized at such elevated pH levels (i.e., 10 to 11) by the polyphosphates. Thus, pH elevation for corrosion control is not applicable to waters of this type. The chief inhibitive function of elevated pH is its maintenance of a protective oxide film. Ferrous ions formed during incipient stages of attack are oxidized rapidly and precipitated in situ by the high pH, oxygenbearing medium. Increasing the pH to intermediate levels (e.g., 7.2 to 9.5) serves primarily to localize attack. Corrosion of steel is essentially uniformly distributed in oxygen bearing potable waters at pH levels of 7 or less. As the pH rises appreciably above this level however, more of the corrosion products adhere to the metal surface and the attack begins to localize. While localized corrosion alleviates red water

FIGURE 5 - Pitted galvanized hot water tank which failed weeks' service in Pittsburgh water at 82 C (180 F).

temperatures to 60 C to avoid excessive corrosion. The influence of operating conditions of the corrosion in hot water systems has been discussed by Shuldener.1 5 In domestic service the corrosion rate increases steadily as the temperature is raised. The maximum in the corrosion rate-vs-temperature curve is displaced at higher temperatures as a result of higher oxygen solubility levels in these pressurized systems. Excessive temperatures are particularly detrimental to galvanized hot water tanks where potential reversals between zinc and steel may occur at temperatures above 60 C to aggravate localized attack on the stee1.16 Actually, galvanically accelerated attack on the steel base can even occur in cold water. The intermediate zinc-iron alloy layer formed during hot galvanizing is reported to be cathodic to both zinc and steel in either hot or cold oxygen-bearing water. 1 7 Pits revealed after wire brushing to remove tubercules in a bottom-fired galvanized hot water tank which failed after 81 weeks of a test in Pittsburgh tap water at 82 C (180 F) are shown in Figure 5. The water involved was

somewhat, it aggravates obstruction of flow considerably. No pronounced drop in volume of metal consumed accompanies the early stages of pH elevation because the increased attack on the anodes roughly balances the reduction of the anodic area. Not until the pH reaches about 9.5 does this balance tip appreciably and the total attack start to fall off significantly. A pH of 10 or above usually is required before a satisfactory degree of inhibition is attained. The most serious objection to control by pH elevation is localization of attack produced at intermediate levels which is characterized by severe tuberculation. While pH levels required for adequate protection frequently are considered excessive for human consumption, this objection, though perhaps more valid from an aesthetic than a physiological point of view, is none the less generally decisive.

118

Inhibition is often sensitive to electrolyte concentration, a characteristic common to most passivators. pH levels sufficiently high to afford adequate protection for iron and steel are excessive for galvanizing, aluminum and yellow brass.

"egg-shell" coating of calcium carbonate to isolate the metal surface effectively from the corrosive action of the water. The illusory simplicity of the process and its apparent basis in elementary physical chemical principles renders it expecially attractive. Means for the attainment and maintenance of the desired uniform "egg-shell" coating have provided a subject for continual research for the past 50 years.

Controlled Scale Elevation of the pH of a hard bicarbonate water will convert the problem from one of the corrosion to one of scale. If proper control can be established so that these two tendencies can be balanced, corrosion can be controlled satisfactorily without excessive deposition of calcium carbonate scale. Most natural or lime-soda softened supplies contain sufficient calcium to make scale control feasible. Baylis pioneered this system of corrosion control over 50 years ago at J ackson, Mississippi 18 and developed it further at Baltimore, Maryland.19,2 0 His aim was to adjust the pH to a point at which the tendencies to corrode and to encrust were at a minimum. This generally requires the water to be very slightly encrustant-just sufficiently supersaturated to lay down and maintain a uniform, thin,

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_~~:~f .--rackish, water service. It has the distinction of being almost the pnly inhibitor to enjoy appreciable application in once-through cooling systems. Applications of ferrous sulfate to power plant condensers cooled by brackish water was described by Bostwick.107 He found that daily treatment for 45 min with ferrous sulfate at a rate of I mg Fe/l practically eliminated failures of aluminum brass tubes from impingement attack. The treatment has since been extended to other copper alloy tubes. A tightly adherent mm of hydrous ferric oxide -apparently is responsible for the protective action of the ferrous sulfate. The mm is sufficiently thick (i.e., approx. 3 rnils) to impart a dark reddish color to the metal surface. The treatment appears to serve a function somewhat analogous to that of the iron in alloys such as the cupronickels. In each case the production of a mm of hydrous ferric oxide is relied on for protection.

Analytical Procedures

Analytical procedures for most inhibitor constituents

TABLE 3 - Analytical Controls for Monitoring levels of Inhibitive Mixtures in Recirculating Cooling Water Systems Analytical Control Secondary Primary

I

Inhibitive Mixture Chromate-poly

phosphate

Chromate and/or

Chromate-polyphosphate-zi

polyphosphate Polyphosphate Chromate and/or

Chromate-zinc nc

Zinc Zinc

polyphosphate Polyphosphate-zinc Polyphosphate-ferrocyan Lignin sulfonate-zinc NTMp(1)-zinc EDP(2)-zinc EDP(2)-chromate

Control of Inhibitor Levels

ide

Polyphosphate Polyphosphonate Zinc

Zinc

Phosphonate Phosphonate Phosphonate and/or chromate

Zinc Zinc

Ferrocyanide

(1)Nitrolitris/meth ylenephosphonate. (2)Ethanoldiphosphonate.

Maintenance of a sufficient concentration of inhibitor 143

/~.

chromate should not be discharged into streams or other waterways. More recently, discharge of phosphate has been criticized but for a different reason. Phosphates are an effective nutrient for biological growths. In addition zinc is toxic to some fish at levels of 1 mg/I/08 although the limit for drinking water is 5 mg/1.1 09 Chromate can be removed by reduction-for example, with ferrous sulfate, sulfurous acid and its salts, etc.followed by separation of the resultant chromic hydroxide. Mracek110 has discussed the factors involved in its reduc-

are available in the literature and additional procedures often can be obtained from suppliers of the mixtures. Colorimetric methods generally are preferred because they are relatively quick and amenable to automation. However, atomic absorption, if available, frequently is preferred for zinc. Procedures for the newer inhibitive ingredients, the phosphonates AMP and EDP, are generally less familar and warrant additional consideration. Phosphonates cannot be converted to P04 by simple hydrolysis, such as suffices for the polyphosphates, but require strong oxidation (e.g., persulfate) to break the Cop bond and accomplish the conversion. The strong chelating action of these phosphonates also requires their destruction prior to colorimetric determination of the zinc. Inhibitor feed is not as critical as is acid addition for pH control because the protective film can withstand temporary fluctuations of inhibitor levels. As a result, rapid response of the inhibitor feed is not essential. This permits use of relatively simple feed systems, one of which is shown diagramatically in Figure 13.

tion by sulfur dioxide. Chromate also can be removed by ion exchange as described by Hessler and Oberhoferl 11 and by Kelly.1 12 Chromate is selectively removed by the chloride form of a strong-base resin, preferably from a slightly acid solution (e.g., pH 4.5). The chromate is released for reuse and the resin regenerated by a caustic solution of sodium chloride. The caustic soda converts the dichromate to chromate and the chloride exchanges for the latter. Eliassen and Tchobanoglousl 13 recently have reviewed the procedures for removal of phosphates from waste water. Polyphosphates readily revert to orthophosphate in the conventional sewage plant. The phosphate can be removed by adsorption on activated sludge floc, precipitated with lime, alum or iron salts or adsorbed on activated alumina. The latter has been discussed by Yee.l 14 Precipitation with lime was discussed in conjunction with the use of sewage plant effluent for makeup.2 6 The extent to which phosphates are removed in conventional sewage plants varies from 20 to 90%, depending on the degree of aeration of the activated sludge and pH. Menar and Jenkinsl 15 note that aeration removes carbon dioxide and raises pH, thus favoring calcium phosphate precipitation. Apparently, methods for phosphate removal are still in such a preliminary state of development that optimum procedures have yet to be established. Zinc is readily adsorbed by calcium carbonate 108 and silt, so its removal does not appear too difficult. Little information is available at this time regarding either the necessity or the means for removal of the newer inhibitors NTMP and EDP.

Blowdown Disposal Recent emphasis on environmental protection requires a closer look at blowdown disposal practices than has been taken in the past. Few corrosion inhibitors now in use are completely unobjectionable from the standpoint of environmental contamination. This definitely applies to the three most common inhibitive ingredients, chromates, polyphosphates and zinc. It has long been recognized that because of their toxicity, effluents containing appreciable concentrations of

HAKE-UP WATER

Newer Inhibitor Treatments to Meet Pollution Controls CHEIIICAL PUr.lP

Editor's Note: The following death of Or. Hatch in order

FEED

disposal methods

SHUT OFF VALVE

and related topics for cooling water.

sections have been added since the to update his section on blow down

involved

in more

recent

water

treating

CONDENSER

Donohue and Sarnol 16 recently described treatments containing very low concentrations of chromate, e.g., 5 ppm. These "ultralow" chromate treatments arc used at pH values of 8.0 or even above. At a high pH, corrosivity of the system is reduced and acid feed for pH control usually is not required. In order to prevent scaling problems which would normally be encountered at high pH values, it is necessary to augment chromate with scale-preventing materials such as phosphonates and/or various organic polymers

CNElII CAL SOLUTlOtl TANK CDNDEtlSER WATER PU~IP

FIGURE 13 - Schematic of proportional feed system using a water meter-timer combination. Increments of inhibitor solution are injected at a frequency proportional to the makeup volume. (Figure 6, SeeReferenceto Figure 3) 144

References

which act as scale dispersants. Phosphonates used include nitrilotris (methylenephosphonate) and I-hydroxyethylidene 1, I-diphosphonate, which have. been described by Ralston.11 7 Carter et a/118 recommend that for consistently good results with these treatments, the systems be subjected to a pretreatment at a substantially higher chromate level and that the Langelier Index be maintained at + 1.0 to 2.5 during the uItralow chromate treatment. Treatments in which chromate is eliminated completely are described in a recent work by Carter and Donohue.119 These treatments employ a mixture of phosphate (properly balanced between polyphosphate and orthophosphate), phosphonates such as described above and/or organic polymeric dispersants. A typical program calls for 3-10 ppm total phosphate, 2-5 ppm orthophosphate and pH in the range of 7.0 to 9.0. A high positive Langelier Index of I to 2.5 is required and this necessitates at least 25 ppm of calcium (as CaC03). However, lOO ppm or more are preferred values. Weisstuch and Schell120 report that both the low chromate treatments and those containing no chromate described above are also effective in stifling galvaniccorrosion caused by contacts of dissimilar metals in industrial cooling systems. At the higher pH values of the low chromate or non-chromate treatments, the biocidal effectiveness of chlorine is reduced, so larger quantities of chlorine .are required or alternatively, non-oxidizing biocides such as chlorophenates, quaternary nitrogen compounds, etc., are employed. Donohue and Sarno discuss the pollution aspects of these materials and of the corrosion inhibitors and suggest the use of biocides such as acrolein, tertiary butyl hydrogen peroxide and bromo-nitrostyrene. These materials have the advantage of being easily detoxified by addition of stoichiometric quantities of sodium sulfite. In his discussion, Hatch stresses the need for close maintenance of inhibitor levels and other operating parameters. One of the most important of these is pH. In the newer treatments which employ low chromates or no chromates, the establishment and maintenance of protective fIlms is even more sensitive to changes in pH and inhibitor concentration than are those formed with conventional high-chromate treatments. Schieber12 1 discusses factors involved in obtaining effective protection and describes the principles of operation and advantages of automatic control devices used in industrial cooling water systems. The entire field of cooling water treatment is presently in a state of flux of increasingly stringent requirements on pollution control being promulgated by Federal, state and municipal authorities. A considerable amount of work is being carried out by water service companies, universities, governmental agencies, etc., to solve these pollution problems in an economical as well as efficient and safe manner. The technical literature adquately covers current work and the reader is referred to the publications of the National Association of Corrosion Engineers, to the journals of other technical societies and to government reports for the latest developments in this important field.

1. C. H. Kline. Water Otemical Sales are High, but Profits Scarce, Paper presented at meeting of European Otemical Marketing Research Assoc., Sept. 2, 1971, Summary in Mat. Pro. Perf., 10,41-43 (1971). 2. NACE Recirculating Cooling Water Sub-committee. Some Economic Data on Otemical Treatment of Gulf Coast Cooling Waters, Co"osion, 11,61-62 (1965) Nov. 3. Staff Feature Industrial Water Corrosion Control and Costs. Mat. Pro., 5,8-13 (1966) July. 4. O. W. Siebert and W. C. Engman. Case History on Economics of Otemical Treatment of a Recirculating Water Cooling Tower, Mat. Pro., 3,20-25 (1964) Oct. 5. D. B. Jones. Can You Afford Your Cooling Water Treatment Program, Mat. Pro., 4,62-67 (1965) March. 6. C. P. Dillon. Economic Evaluation of Corrosion Control Measures, Mat. Pro., 4, 38-45 (1965) May. 7. M. Brooke. Dollars and Sense in Cooling Water Treatment,Mat. Pro., 4,53-55 (1966) July. 8. B. Berg, R. W. Lane and T. E. Larson. Water Use and Related Costs with Cooling Towers, Circular 86, Illinois State Water Survey, Urbana, Ill. (1963). 9. C. S. Cone. A Guide for Selection of Cooling Water Corrosion Inhibitors, Mat. Pro. Perf., 9, 32-34 (1970) July. 10. NACE Unit Committee T-7A. Cooling Water Treatment Manual, NACE, Houston, Texas (1971). 11. Selected Papers on Cooling Tower Water Treatment. Circular 91, Illinois State Water Survey, Urbana, Ill. (1966). 12. Standard Heat Exchanger for Cooling Water Tests. A Report of NACE Technical Unit Committee T-5C on Corrosion by Cooling Water, Mat. Pro., 4, 70-72 (1965) Aug. 13. A. S. Krisher. NACE Standard Heat Exchanger Monitors Cooling Tower Water Corrosion, Mat. Pro., 4,73-79 (1965) Aug. 14. H. F. McConomy. literature Survey of Corrosion in Cooling Water Systems1 1940-1953, Proc. Am. Petro. Inst. Ill, 35, 32-79 (1955). 15. J. K. Rice. Treatment of Recirculating Cooling Water, CO"Qsion, 8,375-380 (1952) Nov. 16. G. B. Hatch and O. Rice. Surface Active Properties of Hexametaphosphate,Ind. Eng. Chem .. 31,51-57 (1939) Jan. 17. O. Rice and E. P, Partridge. Threshold Treatment: Elimination of Calcium Carbonate Deposits from Industrial Waters, Ind. Eng. Chem., 31,58-63 (1939) Jan. 18. P. H. Ralston. Scale Control with Aminomethylenephosphonates, J. Petro. Tech., 1029-1036 (1969) Aug. 19. G. H. Sanders and H. R. Newsom. Device that Permits Feeding Sulfuric Acid to Cooling Towers at Rates Proportional to Makeup Flow, Mat. Pro., 1,95-96 (1962) Oct. 20. J. M. Donohue, A. J. Piluso and J. R. Schieber. Acrolein-A Biocide for Slime Control in Cooling Water Systems, Mat. Pro., 5,22-24 (1966) July. 21. S. Kaye and P. G. Bird. Stop Silt Settling in Exchangers, Hydro. Proc. Petro. Ref., 44, 149-152 (1965) Aug. 22. A. Sherry and E. R. Gill. Current Trends in Corrosion Control at West Thurrock Power Station, Chem. & Ind., 102-106 (1964) Jan. 23. G. W. Schweitzer. Silt Control Treatment in Cooling Water Systems, Proc. Int. Water Conf. (W. Penna. Engrs. Soc.) 26, 74-76 (1965). 24. T. W. Zierden. Methods and Compositions for Removing Alluvium and Other Deposits in Water Systems, U.S.Pat. 3,503,879 (March 31, 1970). 25. A. Wolman. Industrial Water Supply from Processes Sewage Treatment Plant Effluent at Baltimore, Maryland, Sewage Works J., 20,15-21 (1948) Jan. 26. S. L. Terry. Use of Sewage Plant Effluent as Cooling Tower Makeup, Selected Papers on Cooling Water Treatment, Circular 91, Illinois State Water Survey Urbana, Ill. (1966). 27. E. F. Mohler. Extended Experience in Biological Treatment

145

28. 29. 30.

31.

32. 33. 34.

35. 36. 37.

38. 39. 40.

41.

42. 43. 44.

45.

46.

and Reuse of Refmery Waste Water in Cooling Towers, Int. Water Conf Proc. (W. Penna. Engrs. Soc.) 26, 21-37 (1965). G. D. Bengough and R. May. Seventh Report to the Corrosion Research Committee,./. Inst. Metals (Brit.), 32, 81 (1924). D. B. Bird and K. L. Moore. Brackish Cooling Water vs Refinery Heat Exchangers, Mat. Pro., 1,71-77 (1962) Oct. D. R. Baker. Controlling Deterioration of Cooling Tower Lumber, Presented at 7th Annual Conf., Petroleum Div. Am. Soc. Mech. Engrs. (1952). Report of Study of Wood Maintenance for Water Cooling Towers. Cooling Tower Institute, Houston, Texas, June 1959, Resume: Mat. Pro., 1,32-39 (1962) Oct. W. Yoel. Determination and Prevention of Fungal Deterioration of Cooling Towers, Mat. Pro., 2,64-69 (1963) April. S. Kaye and P. G. Bird. Measuring the Progress of Wood Rot in Cooling Towers, Mat. Pro., 3,46-50 (1964) Oct. C. W. Regutti and T. H. Power. Cooling Tower Preservation by Steam Sterilization and Chemical Distillation-A Progress Report, Inter. Water Conf Proc. (W. Penna. Engrs. Soc.) 22, 27-34 (1961). T. A. McConomy. Cooling Tower Steam Sterilization: Four Years Progress, Mat. Pro., 5,51-53 (1966) Sept. T. Palen. Reduce Cooling System Corrosion, Petro. Ref, 38, 239-242 (1959) May. P. R. Puckorius. Pretreatment-The Key to Effective Protection of Cooling Water Systems, Proc. Am. Water Conf (W. Penna. Engrs. Soc.) 21, 23-33 (1960). P. R. Puckorius and W. J. Ryznar. Cooling Water Inhibitor Performance, Corrosion, 16, 473t-478t (1960) Oct. W. S. Janssen. Corrosion Control in a Refinery Salt Water Cooling System, Mat. Pro., 1,42-53 (1962) Oct. J. F. Conoby and T. M. Swain. Nitrite as a Corrosion Inhibitor. Controlling Depletion of Sodium Nitrite, Mat. Pro., 6,55-58 (1967) April. S. Sussman, O. Nowakowski and J. J. Constantino. Experiences With Sodium Nitrite, Unpredictable Corrosion Inhibitor, Ind. Eng. Chem., 51,581-583 (1959). T. P. Hoar. Nitrite Inhibition of Corrosion: Some Practical Cases, Corrosion, 14, 103t-104t (1958) Feb. O. G. Lundgren and A. Krikszens. U.S.Pat. 3,087,777 (April 30, 1963). M. Darrin. Corrosion Inhibition with Chromate.3- GasProcessing Plants and Refineries, Oil & Gas./., 85-88 (1949) Feb. S. Matsuda and H. H. Uhlig. Effect of pH, Sulfates, and Chlorides on Behavior of Sodium Chromate and Nitrite as Passivators for Steel, J. Electrochem. Soc., 111, 156-161 (1964) Feb. A. D. Mercer and I. R. Jenkins. Comparative Study of Factors Influencing the Action of Corrosion Inhibitors for Mild Steel in Neutral Solution ll. Potassium Chromate, Brit. Corrosion J., 3,130-135 (1968) May.

52.

53. 54. SS. 56.

57. 58. 59.

60. 61.

62. 63. 64.

65.

66.

as a Corrosion Inhibitor in Water Piping, Ind. Eng. Chem.,44, 1765-1769 (1952) Aug. J. W. Wood, J. S. Beecher and P. S. Laurence. Some Experiences with Sodium Silicate as a Corrosion Inhibitor in Industrial Cooling Waters, Corrosion, 13, 719t-724t (1957) Nov. S. Sussman. Silicates in Water Treatment, Ind. Water Eng. (1966) March. J. C. Thresh. Analyst, 47,459-468,500-505 (1922). F. N. Speller. J. Franklin Inst., 193,519-520 (1922). G. B. Hatch. Inhibition of Galvanic Attack of Steel with Phosphate Glasses, Ind. Eng. Chem., 44, 1780-1786 (1952) Aug. G. B. Hatch. Control of Couples Developed in Water Systems, Corrosion, 11,461 t-468t (1955) Nov. G. B. Hatch. Corrosion Inhibiting Composition and Method of Using Same, U.S.Pat. 2,742,369 (August 17, 1956). G. B. Hatch. Method of Inhibiting Corrosion of Copper and Cuprous Alloys in Contact with Water, U.S.Pat. 2,941,953 (June 21, 1960). G. B. Hatch and O. Rice. Corrosion Control with Threshold Treatment,lnd. Eng. Chem., 37,752-759 (1945) Aug. H. L. Kahler, C. A. Bishof and W. A. Tanzola. Corrosion Inhibition in Water Systems, U.S.Pat. 2,848,299 (August 19, 1958). G. B. Hatch. Protective Film Formation with Phosphate Glasses, Ind. Eng. Chem., 44, 1775-1786 (1952) Aug. G. B. Hatch. Poly phosphate Inhibitors in Potable Water, Mat. Pro., 8,31-35 (1969) Nov. J. C. Lamb, III and R. Eliassen. Mechanism of Corrosion Inhibition by Sodium Metaphosphate Glass, JA WWA, 46, 445-460 (1954) May. J. L. Mansa and W. Szybalski. Corrosion Due to Tuberculation in Water Systems, Acta Chem. Scand., 4, 1275-1292 (1950); Corrosion, 8,381-388 (1952) Nov. B. Raistrick. Condensed Phosphates and Corrosion Control, Chem. & Ind., 408-414 (1952).

67. B. Raistrick. The Influence of Foreign Ions on Crystal Growth from Solution. I-The Stabilization of the Supersaturation of Calcium Carbonate Solutions by Anions Possessing o-P-o-P-o Chains, Disc. Faraday Soc., No. 5, 234-237 (1949). 68. Z. Szklarska-Smialowska and J. Mankowski. Mechanism of the Action of Polyphosphates as Inhibitors of the Corrosion of Steel by Water, Centre Beige D'Etude et de Doc. des Eaux, No. 288,474-482 (1967) Nov. 69. S. T. Powell, H. E. Bacon and J. R. Lill. Corrosion Prevention by Controlled Calcium Carbonate Scale, Ind. Eng. Chem., 37, 842-846 (1945) Sept. 70. S. T. Powell, H. E. Bacon and E. L. Knowdler. Corrosion Prevention by Controlled Calcium Carbonate Scale, Ind. Eng. Chem., 40,453-457 (1948) March. 71. G. B. Hatch. Influence of Inhibitors on the Differential Aeration Attack of Steel, Corrosion, 21, 179-187 (1965),June; Methods of Inhibiting the Pitting of Iron and Steel. U.S.Pat. 3,022,133 (February 20, 1962). 72. R. S. Thornhill. Zinc, Manganese and Chromic Salts as Corrosion Inhibitors, Ind. Eng. Chem., 37, 706-708 (1945) Aug. 73. F. N. Speller. Discussion, Proc. ASTM, 36, (Part 2), 695-696 (1936). 74. W. G. Palmer. Corrosion Inhibitors for Steel, J. Iron & Steel Inst. (Brit.), 421-431 (1949) Dec.; Corrosion, 7, 10-19 (1951) Jan. 75. H. L. Kahler. Phosphate-Chromate Protection in Water Systems, U.S.Pat. 2,711,391 (June 21, 1955). 76. H. L. Kahler and C. George. A New Method for the Protection of Metals Against Pitting, Tuberculation and General Corrosion, Corrosion, 6, 331-340 (1950) Jan. 77. W. A. Hess. Refinery Corrosion Rates Below 5 mpy Achieved

47. W. D. Robertson. Molybdate and Tungstate as Corrosion Inhibitors and the Mechanism of Inhibition, J. Electrochem. Soc., 98,94 (1951). 48. G. B. Hatch. Influence of Inhibitors on Differential Aeration Attack of Steel. ll-Dichromate and Orthophosphate, Paper presented at 1964 NACE National Conference. 49. U. R. Evans. Inhibitors-Safe and Dangerous, Trans. Electroch em. Soc., 69, 213-231 (1936). 50. M. Cohen and A. F. Beck. Passivity of Iron in Chromate Solutions I-Structure and Composition of the Film, Z. Elektrochem., 62, 696 (1958). J. E. O. Mayne and M. J. J. Pryor. The Mechanism of Inhibition of Corrosion of Iron by Chromic Acid and Potassium Chromate,./. Chem. Soc., 1831-1835 (1949). U. R. Evans. The Corrosion and Oxidation of Metals, Edw. Arnold Ltd. (London) p. 151-157 (1960). 51. L. Lehrman and H. L. Shuldener. Action of Sodium Silicate 146

by Chromate Water Treatment, Corrosion, 16, 18-21 (1960) July. 78. M. C. Forbes. Approaching Problems of Cooling Water Corrosion,Petro. Ref, 36,164-165,216(1957) April. 79. G. B. Hatch. Low Level Dichromate-Zinc Inhibition in Recirculating Cooling Water Systems, Mat. Pro., 4, 52-56 (1965) July. 80. G. B. Hatch. Controlling Aluminum Attack in Recirculating Cooling Systems, Mat. Pro., 5,46-52 (1966) July. 81. H. L. Kahler and W. A. Tanzola. Inhibiting Corrosion in Industrial Water Systems, U.S.Pat. 2,900,222 (August 18, 1959). 82. H. L. Kahler and C. George. Decreasing Cooling Water Corrosion,Petro. Ref, 34,144-148 (1955) July. 83. R. V. Comeaux. Basic Cooling Water Guide, Hydro. Proc., 46, 129-132 (1967) Dec. 84. G. B. Hatch and P. H. Ralston. Oxygen Corrosion Control in Flood Waters, Mat. Pro., 3, 35-41 (1964) Aug. 85. G. B. Hatch. Phosphate Glass Composition. U.S.Pat. 3,284,368 (November 8, 1966). 86. R. T. Halon, A. J. Steffen, G. A. Rohlich and L. H. Kessler. Scale and Corrosion Control in Potable Water Supplies at Army Posts,lnd. Eng. Chem., 37,724-735 (1945) Aug. 87 F. N. Speller. Hot and Cold Water Systems, Corrosion Handbook (Uhlig) John Wiley & Sons, New York, p. 496-506 (1948). 88. R. C. Ulmer and J. W. Wood. Prevention of Corrosion in Cooling Water, Corrosion, 8,402-406 (1952) Dec. 89. J. W. Ryznar and M. A. Peich. Corrosion Inhibiting Compositions and Method. U.S.Pat. 2,515,529 (July 18, 1959). 90. J. I. Bregman and T. R. Newman. Developments in Cooling Tower System Treatments. Part I-Polyvalent lon-Polyphos. phate Inhibitors, Corrosion, 15, 97t-l00t (1959) Feb. 91. J. L. Powell. Corrosion of Copper in Open Recirculating Water . , Systems,lnd. Eng. Chem., 51, 75A-76A (1959) March. 92. R. R. Irani. Sequestration of Metal Ions. U.S.Pat. 3,234,124 (February 8, 1966). 93. P. H. Ralston. Method of Inhibiting Precipitation and Scale Formation, U.S.Pat. 3,336,221 (August 15, 1967). 94. P. H. Ralston. Scale Control with Aminomethylenephosphonates,J. Pet. Tech., 1029-36 (1969) Aug. 95. G. B. Hatch and P. H. Ralston. Method of Inhibiting Corrosion with Aminomethylenephosphonic Acid Compositions, U.S.Pat. 3,483,133 (December 9,1969). 96. G. B. Hatch and P. H. Ralston. AminomethylenephosphonateZinc Mixtures Control Oxygen Corrosion, Mat. Pro. Perf, 11, 39-42 (1972) Jan. 97. G. W. Schweitzer. Aminomethylenephosphonates Control Scale and Corrosion in Cooling Water Systems, Proc. Int. Water Conf (W. Penna. Engrs. Soc.) 30, 131-138 (1969). C. M. Hwa. Organic Phosphorous Acid Compound-Chromate Corrosion Protection in Aqueous Systems. U.S.Pat. 3,431,217 (March 4, 1969). 98. C. M. Hwa. Use of Phosphonates for Treating Cooling Water Systems, Proc. Int. Water Conf (W. Penna. Engrs. Soc.) 30, 138-141 (1969). 99. G. B. Hatch. Corrosion Inhibiting with Combinations of Zinc Salts and Derivatives of Methanolphosphonic Acid, U.S.Pat. 3,532,639 (October 6, 1970).

100. D. W. Haering. Film Inhibitors in Industrial Aqueous Systems, Ind. Eng. Chem., 30, 1356-61 (1938) Dec. 101. R. S. Robertson and W. J. Ryznar. Cooling Water Treatment and Compositions Useful Therein. U.S.Pat. 3,256,203 (June 14,1966). 102. W. S. Calcott. U.S.Pat. 1,797,401 (March 24, 1931). 103. A. Weisstuch, D. A. Carter and C. C. Nathan. Chelation Compounds as Cooling Water Corrosion Inhibitors, Mat. Pro. Perf, 10,11-15 (1971). 104. J. B. Cotton. Control of Surface Reactions of Copper by Means of Organic Compounds, Proc. 2nd Int. Congress Metallic Corrosion, New York 1963, p 590, NACE (1966). 105. I. Dugdale and J. B. Cotton. Corrosion Sci., 3,69 (1963). 106. J. B. Cotton and I. R. Scholes. Benzotriazole and Related Compounds as Corrosion Inhibitors for Copper, Brit. CO"os. J., 2, 1-5 (1967) Jan. 107. T. W. Bostwick.· Reducing Corrosion of Power Plant Condenser Tubing with Ferrous Sulfate, Co"osion, 17, 12-19 (1961) Aug. 108. J. Finn. Saving Fish from Metal Poisons, Eng. News Record, 125,9(1940). 109. Public Health Service Drinking Water Standards'-1962. Public Health Service Pub!. No. 956, U.S. Gov. Printing Office, Washington, D.C. 1l0. W. A. Mracek. Control and Automation of Chromate Was~e Reduction Plants, Proc. I;u. Water Conf (W. Penna. EngIs. Soc.) 30, 91-9 (1969). Ill. J. c. Hesler and A. W. Oberhofer. Recovery and Reuse of Chromates in Cooling Tower Discharge, Mat. Pro., 3, 8-22 (1964) Dec. Il2. B. J. Kelly. Cooling Tower Chromates-Recovery or Disposal, Mat. Pro., 8,23-5 (1969) March. 113. R. Eliassen and G. Tchobanoglous. Removal of Nitrogen and Phosphorous from Waste Water, Envir. Sci. Tech., 3,536-541 (1969) June. Il4. W. C. Yee. Selective Removal of Mixed Phosphates from Water Streams by Activated Alumina, JA WWA, 58, 239-247 (1966) Feb. 115. A. B. Menar and D. Jenkins. Fate of Phosphorous in Waste Treatment Processes: Enhanced Removal of Phosphate by Activated Sludge/Envir. Sei. Tech., 4, 1115-1121 (1970) Dec. 116. J. M. Donohue and C. V. Sarno. Pollution Abatement Pressures Influence Cooling Water Conditioning, Mat. Pro. & Pert, 10,19-21 (1971) December. 117. P. H. Rlilston. Inhibiting Water Formed Deposits with Threshold Compositions, Mat. Pro. & Pert, 11,39-44 (1972) June. 118. D. A. Carter, A. Weisstuch and W. L. Harpe!. Technical Aspects of Modern Cooling Water Treatment. 1972 North Central-Northeast NACE Meeting, Chicago, Ill., October 16-18, 1972. 119. D. A. Carter and J. M. Donohue. New Protective Measures for Cooling Systems, Mat. Pro. & Pert, 11, 35-38 (1972) June. 120. A, Weisstuch and C. E. Schell. Effectiveness of Cooling Water Treatments as Galvanic Corrosion Inhibitors, Mat. Pro. & Pert, 11,23-26 (1972) November. 121. J. R. Schieber. Control of Cooling Water Treatments: A Statistical Study. Ninth Annual Liberty Bell Corrosion Course, Philadelphia, Pa., Sept. 13-15, 1971. Also available as Technical Paper, 218A, Betz Laboratories, Inc., Trevose, Pa. 19047.

147

,I

Inhibitors in Desalination Systems

BILLY D. OAKES*

Most of the effort in desalination plants to cope with corrosion problems has been expended in seeking metallurgical solutions. To a significant degree, this effort has produced valuable results and has substantially reduced corrosion rates of materials in the plants. This work is outside the scope of this book and will not be reported. Application of inhibitors to desalination systems reported here has been mostly experimental in nature, usually in the laboratory and has not been followed up with extensive field or pilot plant testing. There is, however, considerable interest in the application of inhibitors in desalination environments and some research work is' underway with them. Some test results will be reported in the near future.

Magnitude of Desalination

TABLE 1 - Desalting Plants in Operation or Under Construction - January 1, 1969( I)

307 15 12 26 21

43.2 10.2 8.5 18.5

Europe (Continental)

88

England & Ireland Austral ia Asia Middle East

63 6 24 74

29.6 15.9 1.3 3.2 62.9

Africa USSR

43

U.S.A U.S.A. Territories North America (Except U.S.A.) Caribbean South America

Activity

In the next 10 years, the use of water will increase 20% in the United States. Greater rates may be reached elsewhere (Table 1).1 Because of the importance of adequate supplies of fresh water for human, animal and industrial use, investigation of new de salting methods and improvement of existing systems continues at an accelerated rate. In addition to the three main de salting methods listed in Table 1, there are others including solvent extraction, which showed some advantages from a cost standpoint as shown in Figure 1.2 This process, which has not had full-scale tests, has the advantage of offering very low corrosion rates on materials. Table 2 shows some of the corrosion rates found in tests.

Total

3.8

7

12.9 37.2

686

247.2

By Size, 103 gpd 25-99 100-299 300-499 500-999 1000-4999 5000-7499 7500

>

Total

351 218 34 31 46 3 3

17.8 35.3 13.0 21.3 95.4 17.5 46.9

686

247.2

646

241.6 146.3 38.7 54.4

By Process

Other de salting methods that have either been suggested or tested include ion exchange, biological separation through the use of algae, precipitation by additions to the saline solution, recompressive freezing and electrodialysis using the principles of the fuel cell to conserve energy. 3 Also considered are systems involving deposition of troublesome scales on surfaces outside the heat exchanger.

Economics

Plants

By Geographic Area

Distillation Multi-Stage Flash Submerged Tube Long Tube Vertical Vapor Compression

229 302 96 19

Membrane Electrodialysis Reverse Osmosis

2.2

37

5.3

34 3

0.2

3 3

0.3 0.3

686

247.2

5.1

Influences Operations

As in other processes involving expenditure of energy, economics is a ruling constraint. Present costs of potable water are variously given as 40 cents to $2 a thousand gallons (Figure ]), depending on the desalination method. The economics of size are important in establishing costs

Crystallization Vacuum Freezing Vapor Compression

'Dow Chemical Company, heeport,

(I)Office

Total Note: Includes plants producing

Tx.

148

25,000 gpd or more.

of Saline Waler, U.S. Depl. Inlerior.

ferrous and nonferrous materials in various configurations and combinations have been explored at length. A comprehensive survey of materials data up to the time of its publication is included in an article by Fink.s

1.60

•••• •••••••

'"

c

••• ••• •• ••

.2

~ 1.20

oo o

Reports on Scale and Corrosion Control Following establishment of the Office of Saline Water in 1952, numerous projects were proposed for desalination plants. These included the first plant, which began producing about 1,000,000 gallons a day in 1961, half for the city of Freeport, Texas and the other for Dow Chemical Company, which is located nearby. Indicative of the problems that beset desalination plants was the galvanic corrosion in this plant of 1700 carbon steel plugs in the seven exchangers tubed with copper alloys. The plant was shut down after only 60 days' operation to repair the damage.6 Incoming water at the Freeport plant was deaerated to limit iron corrosion in steam condensate up to 400 F.7 ,8 Following is a description of the method used for treatment of feed water from the article by Schrieber, Osborn and Coley: 9 Figure 2 is the Figure I referred 'to in the quotation. "Figure I is a simplified flow sheet of the unit used to treat the sea water prior to corrosion testing. Raw sea water is picked up by a titanium pump, pushed through polypropylene filters (rubber-lined) and warmed to approximately 110 F. Sea water pH is then lowered to 3.7 by the controlled addition of 98% sulfuric acid. High velocity circulation assists in the release of carbon dioxide at this

~~

Q.) .!!! '"Cl. :5 •...

()'0 ~ 80 "C

40

--.J

o 20,000 10,000 Feed concentration

35,000

FIGURE 1 - The effect of feed concentration on the cost of product water at various heat costs as compared to membrane and freezing processes for feed water at 25 C, in 10,OOO,OOO-gallon-per-dayplant - Ethyl sec-butylamine - - 1-2 mixture of triethylamine and methyldiethylamine • Ionic membranes o Freezing process2

and the fortuitious availability of heat which otherwise would be wasted often dictates final decisions.

point. The acidified, partially decarbonated sea water is then pumped to the top of a packed deaerator tower (Saran lined with polypropylene pall rings) and allowed to fall countercurrent to a low steam flow. The tower is held at a

Second only in importance to removal of oxygen from feed water is the control of scale on heat exchanger surfaces. Because most of the existing (and all full-scale) plants involve evaporation, attention has focused on scale control.4 Voluminous studies have been made on materials and

vacuum of 27 inches of mercury. Dissolved oxygen and the remaining carbon dioxide are removed at this point. A centrifugal pump pulls the water from the tower and places it under pressure. At this point, the water is neutralized to a given pH by introduction of 10% NaOH at the pump suction. The treated water is then forwarded to contact the

design problems. To a significant extent, the attributes

metal specimens. It is to be noted that the trea ting plan t is

of

TABLE 2 - Corrosion of Mild Steel in Amine Water Solutions(l) 30 C, Specimen Area 16.3 cm2

Solutions

Grams Lost 64 Days Sq Cm Specimen

I

Mils Lost 64 Days Per Year

I

5% NaCI +

2% diisopropylamine in water

0.0585

2% diisopropylamine in water

0.0015

30% water in diisopropylamine

0.0054

(I )Table

J,

3.6 X 10-3

3.3x 10-4

ReI'. 2.

149

0.11

0.62

0.003

0.017

0.012

0.064

TABLE 3 - Analyses of Sea Water at Guantanamo Bay and Kuwait( I) Parts per Million Guantanamo Kuwait

I

Item Steam

6350

Hardness (CaC03) 114 0 3.0 2910 1315 415 19600 Calcium35400 (Ca) Magnesium (Mg) 7.8

Filter

Acid mixer

I Deaerator

8.3 23100 3100 8200 5.0 500 4 42000 1665 135

P - Alk (CaC03) M - Alk (CaC03) Sutfate (S04) Chloride (Cl)

To testing systems

Silica (Si02) Total solids

Raw, sea water intake pH FIGURE facility.9

2 -

Simplified

flow

sheet

of sea water

treating

(I )Table

constructed entirely of material that will not allow metal ions to enter the sea water stream."

10.

Scale formation is partially controlled by the addition of 3 to 5 ppm polyphosph,ate at brine concentration factors of 1.5 to 2. An adherent sludge forms on heat transfer surfaces, however.

Other Evaporative Plants The plant at Point Loma (San Diego, California) was operated for 26 months at 200 F10 with polyphosphate treatment and at temperatures up to 250 F with acid treatment. In February, 1964, 28 stages of the Point Loma plant were shipped to Guantanamo Bay, Cuba, to supply water to the D.S. garrison there after Cuba threatened to cut off its water supply. The eight stages (25 to 32) not sent to Cuba had steel tubing that showed signs of corrosion, while the cupronickel and aluminum brass tubing of the other stages had performed satisfactorily. The three evaporators at Guantanamo Bay had an output rating of 2,250,000 gpd. Three 650 psi, 850 F boilers supply steam for two condensing 7500 KW turbogenerators equipped with ftxed extraction bleed points. Turbine extraction steam supplemented by boiler steam is used for the brine heaters. Approximately 2 to 3 ppm of a polyphosphate is used for sea water treatment for the evaporators and sulfuric acid is added continuously for cleaning purposes. In spite of the inhibitor treatment, an adherent sludge forms. At Guantanamo Bay, the sludge is removed about once a week from heat transfer surfaces by acid cleaning while the plant is operating. At Point Loma, cleaning is done about once a month. Occasionally sulfamic acid is used but ordinarily sulfuric acid is fed continuously to the evaporator makeup to lower the pH of recycled brine to about 5 or 5.5. After three of the steel water boxes at Guantanamo

I, Reference

Inhibition

of Kuwait Evaporator

Polyphosphate treatment of Caribbean or Mediterranean sea water is not as effective as it is in ocean waters of the temperate zone. The Kuwait 1,200.000 gpd multi. stage evaporators are operated at ] 94 F with a brine concentration of 2 and polyphosphate feed at :; ppnl.! () This treatment results in a brine heater cleaning interval of 8000 to 10,000 hours. Inhibited hydrochloric acid is used for cleaning. Although salt concentratj~n and alkalinity of the Red Sea water is less than that at Guantanamo, the Kuwait evaporators operate at higher brine concentrations and have less sludge formation. Effectiveness of treatment at Kuwait is attributed to absence of iron in evaporator makeup water. Table 3 shows compositions of water from tile two sites.

Corrosion Problems at

110,

Peru

Heavy chlorination at 1.5 ppm of feed water at the 110, Peru, plant built there in I%6 for the Peru Copper Company caused corrosion problems. I 1 The chlorination was done to offset the effects of pollu tion effluen t from a fish meal plant, bird sanctuary wastes as well as frequent "red tides" and other marine growth. Reduced concen tration of chlorine and chlorination at intervals instead of continuously decreased corrosion.

Inhibition

developed leaks, they were re-installed after a stainless steel liner was applied over their exposed surfaces. Sulfuric acid is introduced into the sea water' makeup at the Lanzarote, Canary Islands evaporator to help control scale. 1 0 Carbon dioxide and air are removed in the last

of Mild Steel Corrosion

Phosphate-chromate mixtures were tested to limit corrosion of mild steel under desalination conditions at 250 F (121 C). When sea 'water was deaerated and at nearly neutral pH, mild steel had acceptably low corrosion rates using chromate or dichromate plus phosphate inhibitors. 12

stage by a steam jet vacuum system and pH of recycled sea water is controlled to a range of 7.6 to is. A concentration factor of 2 is maintained.

During two week tests at 250 F using various coneen-

150

sufficient to cause a localized attack that is prohibitive even at low overall corrosion rates. Three inorganic inhibitor systems described provide effective corrosion control in oxygen saturated sea water at 250F. 1. A dichromate-phosphate used at a concentration of 50 ppm, 2. A chromate-phosphate used at a concentration of 50 ppm and 3. A chromate-phosphate-zinc-iodide system used at a concentration of 100 ppm. Later results obtained in the Dow program14 designed to modify the sea water environment revealed that low levels of dissolved oxygen plus low levels of chromate plus phosphate inhibitor offer excellent promise of controlling mild steel corrosion in a hot sea water environment. Chromate may be supplied with equal effectiveness as either sodium chromate or sodium dichromate. Of commercial phosphates tested, only NaH2P04 (sodium dihydrogen phosphate) and Na2HP04 (disodium hydrogen phosphate) were acceptable sources of phosphate anion in the chromate-phosphate inhibitor. Na2HP04 is preferred because it did not cause pitting. Specific commercial phosphate compounds that were not acceptable as sources of phosphate ion included trisodium phosphate, sodium tripolyphosphate, sodium hexametaphosphate, sodium pyrophosphate, sodium metaphosphate. Some of these materials were acceptable when tested as reagent grade chemicals, but Na2HP04 is always the preferred source. Dynamic loop tests with 1 ppm chromate plus 9 ppm phosphate without oxygen addition, but also without deaeration, indicate that even this low concentration may be effective. Even lower concentrations may be satisfactory in an effectively deaerated system.

trations and proportions, chromate-phosphate inhibitors reduced corrosion rates from 49 mils per year to 4 or 5 in some tests. Figure 3 shows some of the r~sults. Best results were obtained with 5 ppm chromate plus 30 to 45 ppm phosphate as monosodium dihydrogen phosphate. It was recognized that this method creates the problem of disposal of the poisonous wastes or their neutralization before returning residual water to the ocean. Another way to decrease the cost of desalination is to modify sea water so that it no longer is highly corrosive to inexpensive materials of construction such as mild steel or even aluminum. W. H. McCoy13 said that in 1965, corrosion control in sea water had been achieved by the use of organic monolayers and controlled multilayers. Longchain, branched and unbranched amines and long-chain acids are representative of materials tried. The best inhibitor tested was a mixture of stearic acid and n-octadecylamine. The Dow Chemical Company, under Office of Saline Water sponsorship, initiated in its laboratories in 1967, a program designed to explore the possibility of employing environmental changes to permit the economic use of mild steel or aluminum as materials of construction for heat exchanger surfaces in desalination plants. The first report on this program pointed out that efficient exclusion of dissolved oxygen from sea water will permit the use of mild steel at temperatures up to 250 F. Contamination of the water with even traces of dissolved oxygen, however, is

60

Inhibition of Aluminum Alloys Dissolved oxygen was found not to exert a pronounced effect on the corrosion of aluminum alloys in sea water at 250 F. Of five aluminum alloys tested, only one, 5052, demonstrated a high level of resistance when no inhibitor was used. Other alloys tested were 1l00, 3003, 5554, and 6061. Bicarbonate ion at 50 ppm concentration permits the use of 1100 alloy in desalination applications when the pH is adequately controlled. Chromate ion at 100 ppm concentration confers excellent corrosion resistance to alloys 1100, 3003, and 5554 in sea water at 250 F. Portions of this report covering mild steel results were published in 1970.15 All early results were obtained in laboratory tests. Data only recently available from the Aluminum Association test unit at OSWFreeport Test Facility indicate that certain aluminum alloys may be perfectly acceptable for use in desalination plants without the use of any inhibitor. Later Dow work14 reported that a chromatebicarbonate inhibitor controlled corrosion and pitting of 1l00, 3003, 5052, 5554 and 6061 aluminum alloys. In most cases, this meant low rates were decreased to even lower values. In a dynamic test involving the 1100 alloy, the corrosion rate decreased from 100 to 1 mpy. The

40

30 >Q.

E

(Figure 1, Reference 12)

20

10

o

100

200

Total chromate-phosphate

300

400

(1:1) concentration

500 (ppm)

FIGURE 3 - Corrosion rate of mild steel versus chromat.phosphate ion concentration after two weeks' exposure in oxygen seturated see water at 250 F (121 Cl.

151

mpy

It

-- • I

•-- ••• -BLANK

cO

0cO

function without serious scaling at temperatures up to 260 to 270 F. The next generation of plants is planned for operation at temperatures of 325 to 350 F because a production plant that operates at these higher temperatures would have much lower costs due to improved thermodynamic performance. Operation at these temperatures will require removal of significant percentages of the calcium and magnesium ions from sea water to prevent sulfate scaling. Three methods are currently under investigation for conditioning feed water so that distillation temperatures can be increased without serious scale problems. The Mason-Rust Company, at the Wrightsville Beach Test Facility, is treating decarbonated sea water with a barium type cation-exchange resin both to absorb Na, Ca and Mg cations and to precipitate sulfate as barium sulfate.I8 This allows a multi-stage flash evaporator unit to operate up to 335 F. The San Diego Test Facility is using a limemagnesium-carbonate scale control pilot plant to condition feed water for higher temperature operations. 1 9 The Materials Test Center of Freeport Test Facility will soon have on stream a cation-exchange facility for removing significant portions of the calcium and magnesium from the water, thus allowing the use of higher temperatures. A similar process is described in the 1969-1970 Saline Water Conversion Report by Chemical Separations Corporation.20

"" LC'l

5

STATIC DEAERATED 4

-.

-

STATIC O2 SATURATED

111I111I1 DYNAMIC

3

SCALE

2 CHANGE XO.5

I• - -- I• - -

-

•

5/50

;;;;

50/50

o Use of Chelating Agents Another method of control is to add chemicals that

ppm Ratio: Cr04'/HCO;

prevent scale deposition on heat exchange surfaces. This can be done using "seed crystals" that cause precipitation of the scale-forming compounds in the brine and cause the insoluble precipitant to go out with the effluent rather than deposit in unwanted places. This also can be done with chelating agents that hold the troublesome ions in solution. An excellent review of materials tried in various desalting plants to control scale formation by addition of various chemicals is presented in a 1969 OSW report2 1 and will not be repeated here. Several articles on scale control methods of various kinds were presented to the First International Symposium on Water Desalination.1 3 Other methods that have been investigated for controlling scale include utilization of graphite heat transfer tubes of controlled permeability to steam22 ,23 to keep the solution adjacent to the tube wall below the saturation or supersaturation temperature and concentration limits required for scale formation. Another method is to determine the effect of surface potential on the formation of calcium sulfate scale.24 The latter work was done on a

FIGURE 4 - Comparison of static and dynamic corrosion rates of AI in treated 250 F sea water. 1 7

mixture of chromate and bicarbonate is definitely superior as a corrosion inhibitor to either used alone. Most of the later Dow work has been presented at various national NACE meetingsI ',16,1 7 (Figure 4). If the bicarbonate naturally present in sea water is active as the bicarbonate source in the chromate-bicarbonate inhibitor and if the concentration of bicarbonate required for inhibition does not cause scaling, the cost of inhibitor addition can be extremely low (on the order of one cent per thousand gallons of water. produced). This could be inexpensive if it would truly guarantee against failure of aluminum components in desalination processes. It should be emphasized that only additional testing will determine if these inhibitor systems actually will function under real desalination conditions. They have just passed from the research stage, so time will be required to ascertain if the inhibitor approach will make a significant contribution to decreasing the cost of desalinated water by permitting the use of less costly materials. If inhibitors continue to show progress, ecological considerations may require development of methods for their removal from the brine concentrate leaving the desalination plant or ideally permit their re-use.

research basis utilizing controlled potentials on platinum electrode surfaces where it was found that surface potential does affect nucleation of calcium sulfate scale.

Miscellaneous

Other corrosion problems, solutions for some of which are still lacking, include attacks by residual ammonia. Because ammonia is in an ionized, chemically bound state,

Removal of Carbonates Removal

of carbonates

Corrosion Problems

would allow the systems to 152

it is difficult to remove completely even by the best . deaeration methods. 1 1 Iron or copper may be removed by forced aeration followed by settling or filtration. Chelation or sequestration of trace elements can be used also. Techniques involving chlorine used to limit biological fouling might produce excess gaseous halides in ventilating systems. Various metals choices are available to solve some of

again the value of the chromate-phosphate solution. Local action was stifled and inhibition somewhat improved. Effect of chromate ion concentration is given in Table

4.

Summary A wide range of operating procedures is used in desalting plants to reduce corrosion and scale deposition. Standard vacuum degassing techniques are commonly used to remove oxygen. The main scale deposition control method usually involves adjusting pH of incoming feed water to reduce the tendency of minerals to precipitate on heat exchanger surfaces. Problems are encountered in connection with marine

these problems.

Tests with Other Inorganic Salts In another series of tests with 1020 steel, this time in aerated solutions, it was learned that various concentrations and combinations of other inorganic salts failed to give satisfactory results in sea water at 250 F.' 2 The inhibitors tested included sodium salts of dichromate, nitrite, phosphate and vanadate at 50 ppm. Localized attack was increased. Also tested were sodium arsenite, zinc ion and sodium silicate. The chromate ion reduced attack but did not limit localized corrosion, reacting in much the same way that it does in fresh water systems. Binary combinations of zinc ion and iodide ion, zinc with sodium arsenite, the phosphate ion in combination with vanadate. nitrite and dichromate ions were tested.

fouling, including the deleterious effect of poisons. Poisoning schedules must be compatible with scale and corrosion control effects. Various phosphate formulations have been tried and are being used with varying degrees of success. Experimental combinations of inhibitors show promise, including binary combinations of sodium chromate and phosphates and ternary combinations involving sodium chromates, phosphates and various other ions, including iodates and vanadates. Various filming organics have been investigated as corrosion inhibitors but none has progressed beyond the early testing stages (Tables 5 and 6).

Only the phosphate-dichromate combination reduced corrosion significantly. At 50 ppm, both localized and general attack were stifled.

References

Ternary systems involving chromate and dichromate ions were made with 25 ppm zinc ion. These demonstrated

1. A. Cohen and L. Rice. Recent

Experience

TABLE 4 - Effect of Chromate Ion Concentration on Corrosion of 1020 Steel in Hot Aerated Sea Water at 250 F 14 Chromate

Corrosion

(ppm)

Rate (mpy)

Blank{ I)

97.8 7.6

50 100

4.1

Inhibitor Efficiency

o 92.1 95.8

(%)

Mode of Attack General Localized

I

Very Severe Slight Slight

{I )No inhibilor.

TABLE 5 - Summary of Inhibiting Systems Used in Flash Distillation Units Name Scale Control Sulfamic acid or2 2pH F3.7 Medium 194 250 250 7.6-8.2 5HCI Cone. Factor Inhibitor NaOH 5-5.5 195 Polyphosphate Polyphosphate ppm H2S04 H2S04 Location

250

H2S04 Kuwait

153

Moderate Moderate Moderate

with Copper

Alloys

TABLE 6 - Experimental Inhibitor Systems Used in Flash Distillation and Other Desalination Units Inhibitors

F

ppm

Comments

Aluminum Stearic acid plus n"octa decylamine Bicarbonate ion

Experimental .

50

pH must be controlled

Chromatebicarbonate

Corrosion reduced from> 100 to 1 mpy.

<

Steel. Mild Chromate plus phosphate Dichromate-phosphate Chromate-phosphate Chromate-phosphatezinc-iodide

5 30-45

. .

50 50

.

100

I

250

Oxygen saturated sea water

Oxygen saturated sea water

9

Oxygen saturated sea water

1

Copper Alloys

2.

3.

4.

5. 6. 7. 8. 9.

10.

11.

Barium cation exchange

Allows operation to 335 F; removes Na, Ca. Mg.

Cation exchange

Removes Ca, Mg

12. B. D. Oakes, J. S. Wilson and W. J. Bettin. Inhibition of Mild Steel Corrosion Under Desalination Conditions. 2-PhosphateChromate Mixtures, Proc. NACE 26th Conf, pp. 549-556, National Association of Corrosion Engineers, Houston, Texas. 13. W. H. McCoy. Research Program of the Office of Saline Water. Proc. of the First International Symposium on Water Desalination, I, p. 345, Washington, D. C., October 3-9, 1965. 14. The Dow Chemical Company. Sea Water Corrosion Control by Environment Modification. Part Two. Office of Saline Water. Res. & Dev.Prog. Rept. 649. May, 1971. 15. R. A. Legault and W. J. Bettin. Inhibition of Mild Steel Corrosion Under Desalination Conditions, Materiols Protection and Performance. 9, 35-39 (1970) September. 16. B. D. Oakes and J. S. Wilson. The Inhibition of Mild Steel Corrosion Under Desalination Conditions, Part 3-Dynarnic Studies in a Recirculating System. Paper No. 63, presented to CORROSION/71 the Annual NACE Conference, Chicago, Ill., March,1971. 17. J. S. Wilson and B. D. Oakes. The Inhibition of Aluminum Alloy Corrosion Under Desalination Conditions. Further Studies on Candidate Inhibitors. Paper No. 64, presented to CORROSION/71, Annual NACE Conference, Chicago, Ill., March,1971. 18. 1969-1970 Saline Water Conversion Report, Executive Summary, p. 8, Office of Saline Water, US Dept. of the Interior. 19. 1969-1970 Saline Water Conversion Report, Executive Summary, p.15, Office of Saline Water, US Dept. of the Interior. 20. 1969-1970 Saline Water Conversion Report, p. 360, Office of Saline Water, US Dept. of the 'Interior. 21. Office of Saline Water. Scale Control in Saline Water Evaporators-A Review of Current Status. Office of Saline Water Research and Development Progress Report No. 411, April, 1969. 22. Union Carbide Corp. Scale Control with Graphite Heat Transfer

in Desalting Plant Environments, Proc. NACE 25th Conf, pp. 342-345, National Association of Corrosion Engineers, Houston, Texas. '; D. W. Hood and R. R. Davison. The Place 'of Solvent Extraction in Saline Water Conversion. Saline Water Conversion, 1960. Advances in Chemistry Series, No. 27. Amer. Chem. Soc., Washington, D. c., pp. 40-49. A. Rose, R. F. Sweeny, T. B. Hoover and V. N. Schrodt. Exploratory Research on Demineralization. Saline Water Conversion, 1960. Advances in Chemistry Series, No. 27. AIDer. Chem. Soc., Washington, D. C., pp. 50-55. J. T. Banchero and K. F. Gordon. Scale Deposition on a Heated Surface, Saline Water Conversion, 1960. Advances in Chemistry Series, No. 27. Amer. Chem. Soc., Washington, D. C., pp. 105-114. F. W. Fink. Alloys for Sea Water Conversion, Materials Protection. 6,41-43 (1967) July. Galvanic Corrosion Shuts Down Freeport's Salt Water Plant. Corrosion, 17,37 (1961) September. F. H. Speller. Corrosion Causes and Prevention. McGraw-Hill Book Co., New York, N. Y. (1951). H. H. Uhlig. The Corrosion Handbook. John Wiley & Sons, Inc., New York, N. Y. (1948). C. F. Schrieber, O. Osborn and F. H. Coley. The Behavior of Metals in Desalination Environments-First Interim Report, Proceedings NACE 24th Conf. pp. 334-338, National Association of Corrosion Engineers, Houston, Texas. A. Checkovitch and J. Brodsky. Operating Experiences with Commercial Flash Evaporator Plants, Proe. NACE 24th Conf. pp. 339-345, National Association of Corrosion Engineers, Houston, Texas. R. M. Ahlgren. Desalination Plant Design and Operation for Corrosion Control, Proc. NACE 24th Conf, pp. 346-349, National Association of Corrosion Engineers, Houston, Texas.

154

Desalination Environments, Materials Protection, 7, 20 (1968) October. The Dow Chemical Co. Sea Water Corrosion Test Program, Office of Saline Water Research and Development Progress Report No. 417, March, 1969. A. Cohen and L. Rice. Recent Experience with Copper Alloys in Desalting Environments, Materials Protection, 8, 67 (1969) December. The Dow Chemical Co. Sea Water Corrosion Control by Environment Modification. Office of Saline Water Research and Development Progress Report No. 438, April, 1969. A. Cohen and L. Rice. Experience with Copper Alloys in the Desalting Environment, Materials Protection and Performance, 9, 29 (1970) November. A. Cohen and L. Rice. Copper and Its Alloys in the Desalting Environment- Third Progress Report. Paper No. 57 presented to CORROSION/71, Annual NACE Conference, March, 1971. The Dow Chemical Co. Sea Water Corrosion Test Program: Part Two. Office of Saline Water Research and Development Progress Report. No. 623. Dec., 1970. E. D. Verink, Jr. Aluminum Alloys for Desalination Service, Materials Protection, 8, 13 (1969) November. E. D. Verink, Jr. Performance of Aluminum Alloys in Desalination Service-A Progress Report. Paper No. 60 presented to CORROSION/71, Annual NACE Conference, Chicago, Ill., March, 1971. T. R. Harkins and H. H. Lawson. Evaluating the Performance of Stainless Steels in Desalination Plant Environments, Proc. 25th NACE Conference, p. 600, Philadelphia, Pa., March, 1970. T. R. Harkins and H. H. Lawson. Performance of Stainless Steels in Desalination Plants, Water and Wastes Eng. (1970) January. T. R. Harkins and H. H. Lawson. Evaluating Material Performance in 3000 gpd Stainless Steel Desalination Test Plant-One Year Operation. Paper No. 58 presented to CORROSION/71, Annual NACE Conference, Chicago, Ill., March, 1971. Westinghouse Electric Corp. Development of a Low-Cost Iron-Base Alloy to Resist Corrosion in Hot Sea Water. Office of Saline Water Research and Development Progress Report No. 394, January, 1969. Westinghouse Electric Corp. Development of a Low-

gal aCid

of oil well acidizing

Gal inh/1000 inhibitor

in

FIGURE

28 wlo

3 - Performance hydrochloric acid.

gal acid

of oil well acidizing

inhibitors

in

b. Scale constituents are dissolved and added to the bath as metal salts; c. Acid used up is replenished; d. Acid, inhibitor and salts are removed by "drag"out" from the solution when metal is removed;

Streicher believes the ferric and other ions cause rapid formation of mms on anodic areas and reduce ferric ions to ferrous ions on cathodic areas to reduce corrosion rates.

e. Inhibitor can be decomposed or salted out; f. Inhibitor isadded a~ required. The effect of exposure time on the systems I and 2 will be materially differen t.

Differences in Rates in Two Systems Considering System I: While it is difficult to assess accurately the effect of the various changes in the system on the rate of corrosion loss, it is nearly always the case that the corrosion loss per unit time will increase with the time that the metal is exposed to the acid. This puzzling effect has been ascribed to changes occurring in the inhibitor and to build-up of metal salts in solution. However, a study of the work of Nathan49 and McDougall,6 and the performance of some rather simple corrosion experiments, points rather strongly to the fact that the rate increase is caused largely by the increase in active surface area as the metal is attacked. In System 2, represente~ by a commercial acid pickling line, the tendency is to approach a steady state by additions of acid and inhibitor, with overflowing to keep down concentrations of metal salts. This condition usually continues until events require the renewal of the bath. Influence of Lead Ion Deleterious effect

of the lead ion from lead-lined

pickling baths is reported by Edwards et als 7 in tests involving propargyl alcohol and butynediol, frequently used acetylenic alcohol inhibitors. Corrosion resistance of panels 164

coated with an epoxy-phenolic coating was better when propargyl alcohol was the inhibitor in sohltions without the lead ion. Butynediol, on the other hand, inhibited solutions with lead ion to such an extentth:it performance was superior to that in solutions that did not contain the lead ion. The reaction postulated by Edwards et al for the inhibition, of steel by the two inhibitors is that the unsaturated alcohols polymerize through the acetylenic bond or add to the acetylenic linkage, yielding a polymeric unsaturated ether.

liable to attack than is qubon steel, especially if its area is small compared to the carbon steel surface to which it is attached.

Procedures fur Chemical Cleaning Procedures for chemical cleaning in petroleum and petrochemical plants are well established. Among preliminaries suggested by Klinge and Selman58 is analysis of the deposits to be renfoved. Tests can show what cleaning compounds are required and whether or not they can be removed by chemicals. Mixtures of inorganic and organic deposits require careful selection and sequence in the application of cleaning agents. Klingc and Selman list cleaning agents most often uscd and indicate their suitability when contacting various mctals.

shown in Figures 4 and 5. Figure 4 shows the relation between inhibitor concentration arid weight loss, and Figure 5 shows the relation between inhibitor concentration and degree of inhibition. These relations were first investigated by Sieverts and Lueg,55 who showed that Figure 5 has the form of an adsorption isotherm and that Figure 4 haso the form of an adsorption isotherm turned ' through 180 . This typical performance of acid inhibitors led Sieverts and Lueg to suggest an adsorption mechanism for the action of organic inhibitors in acids. Many later workers have supported this hypothesis. Practically all organic and many inorganic inhibitors in small concentrations in acid solutions affect corrosion in a way shown by these curves. Mann1 3 ,14 suggested that inhibitors are effective because of their adsorption on cathodes. More recent investigators, such as Fink,59 Machu,6o Hackerman and Sudbury,61 Hackerman and Schmidt,6Z Hoar,63 Hackerman and Makrides64 and Gardner,65 believe that adsorption is general and further that it is both physical and chemical in nature. The classical relation between the concentration of an

The Effect of Concentration of Inhibitor Investigators of acid corrosion soon learn that there is a characteristic relation between inhibitor concentration and loss in weight of the metal specimen. As the concentration of inhibitor increases, the weight loss decreases and tends to approach a low, constant value, which depends' on the properties of the particular inhibitor. This typical'relation between concentration of inhibitor and corrosion'rate is

Corrosion damage to 12-14 chrome steel in one clcaning opera tion was reported by Klinge and Selman.5 8 Thc damaged metal was in contact with large areas of carbon stccl and because the mono-orthotolylthiourea inhibitor apparcntly was ineffective in preventing the corrosion. laboratory tests were made. These tests showed that neither the inhibitor actually used or any of four other commcrcial inhibitors could have protected the steel at the tempcratures and concentrations that were used. It was Icarncd also that 12-14 chrome steel is more

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Concentration of inhibitor

Concentration of inhibitor FIGU.RE 5 - Typical curve showing drop in corrosion rate as a function of, inhibitor concentration.

FIGURE 4 - Typical curve showing increased inhibitor efficiency as a function of concentration of inhibitor.

165

TABLE 5 - Immersion Testing of Inhibitors in Hydrochloric Acid Solutions

adsorbate and the amount of adsorption, has been given by Langmuir.66 He showed that the fractional surface, s, covered by adsorption, is related to the concentration, c, of the adsorbed species in solution by the relation

Experiment No. 1 Experimental Conditions Temperature, F 180 Duration of immersion of test specimens,min 30 FeCI2·4H20 in solution 42.7 g/l 00 ml (no FeH) HCI, w/o 6 Inhibitor Experimental A c = % by volume of inhibitor w = loss in weight, Ib/ft2/24 hr

ac

(1)

s = 1 + abc '

where a is a characteristic constant for the specific adsorbate. This equation can be put into a form useful in corrosion research as follows: Let a metal specimen be immersed in a solution of constant acid concentration, at temperature T and for time 0.0336 0.0672 0.084 0.0504 0.0168 t, where 0.0000 Experiment No. 2 Wo

--

l/e 0.234 e wO-w w 0.076 0.137 0.107 0.083 3.456 3.583 3.614 3.553 59.52 19.84 11.90 1.068 1.039 1.023 1.021 w 3.69 3.607 29.76 14.88 1.030 wO/wOExperimental Conditions

= The loss in weight per unit area per unit time in the absence of an inhibitor.

w = The loss in weight per unit' area, in unit time, in the presence of an inhibitor, and c = The inhibitor concentration, expressed in any convenient unit. In order to relate these values to Equation write:

s=k

Wo

Temperature, F 180 Duration of immersion of test specimen. min 30 FeCI2·4H20 in solution none added initially HCI, w/o 6 Inhibitor Experimental A c = % by volume of inhibitor w = loss in weight, Ib/ft2/24 hr

(1), we can

-w

Wo

(2)

in which we postulate a direct relation between the amount of metal dissolved, and the free surface available. Substituting in Equation (1), and introducing new constants A and B, Wo Wo

-w

=A(I/c)+B.

Table 5 and Figure 6 show how this equation applied to an actual inhibitor problem.

Influence

(3)

e

l/e

w

0.0000 0.0168 0.036 0.0504 0.0672 0.084

59.52 29.76 19.84 14.88 11.90

1.92 0.077 0.042 0.029 0.023 0.022

wo-w

1.843 1.878 1.891 1.897 1.898

wo/wo-

w

1.042 1.023 1.016 1.012 1.011

Experiment No. 3

can be

of Synergism

No discussion of the use of inhibitors in acid solutions can be complete without some mention of the remarkable phenomenon of synergism. This effect has been observed since the earliest days of inhibitor technology and continues to be a potent tool in the development of acid 0.120 0.080 0.040 0.100 0.060 0.020 inhibitors for specialized 0.0000 uses. e One example of this effect has been reported by Foley,67 who says that in experiments with iron in 4N sulfuric acid, it was discovered that "in the absence of halide ions, organic cations such as tetraisoamyl-ammonium sulfate had no influence on the electrode processes on the iron." However, when O.005N potassium iodide was added, Foley reported the mechanism as "the organic cation is adsorbed, leading to a considerable decrease in double layer capacity, a retardation of both cathodic and anodic processes and a decrease in the iron dissolu tion by a factor of some hundreds." Neither of the additives alone would produce reductions of corrosion of this magnitude.

166

Experimental Conditions Temperature, F 180 Duration of immersion of test specimen, min 30 FeCI2-4H20 in solution 42.7 g/100 ml (also containing the amount of Fe3+ that was present in the ferrous chloride. HCI, w/o 6 Inhibitor Experimental A l/e wO-w w 0.143 50.0 0.215 3.555 3.475 3.515 25.0 10.0 1.050 1.038 0.288 3.402 3.547 12.5 1.085 1.040 0.175 0.138 3.552 16.7 1.062 1.039 wO/wOw 3.69 c0.135 = %8.33 by volume of inhibitor w = loss in weight, Ib/ft2/24 hr

For perhaps 25 years, acetylenic alcohols havc bccn used as acid inhibitors. When combined with amincs, however, they are grcatly improved. Thc modcrn combina-

Wo-W 1.08

.'

Expt. No. 3

,.

.'"

In many corrosion reactions-and this includes most of the readily corrodible metals-the fundamental corrosion reaction is so rapid that the rate of transfer of corrodent to the metal surface is the slow process. In these cases, mass transfer processes are controlling with respect to the rate of corrosion .

.~

••

Some phenomena, it is true, are difficult to classify and chief among these little-understood processes are the phenomena of passivity. Passivation of metals does change electrode potentials and in that way, it is activational in nature. However, the oxide mm of passivity seems at times to indicate that the mm is a mass transfer resistance. Again, when inhibitors are present in corroding solutions, the actual mechanism is frequently obscure. Usually, it is believed that inhibitors are adsorbed on the surface, thus changing the surface area accessible to the corrodent. On this basis, corrosion in the presence of an inhibitor is controlled by a mass transfer process. This cannot be a general explanation of the behavior of inhibitors in a flow system, however, because so many types of effects are observed.

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Diffusion and Fluid Flow70 If a fluid in turbulent flow moves past a metal surface, the velocity of the fluid particles at various distances from the surface is not uniform, but varies from zero at the surface to relatively large values at positions far removed from the surface. Immediately adjacent to the interface, there isa thin mm in laminar or viscous flow, moving in orderly streamlines parallel to the contours of the surface, the velocity within the mm increasing linearly with the distance from the metal surface. In the outer regions of the fluid, on the other hand, the flow is turbulent. Relatively large portions of the fluid (eddies) move from one position in the fluid to another, causing considerable mixing. The transition from laminar flow near the wall to turbulent flow

1.00 10

20

30

FIGURE 6 - Graphical representation Experiments 1. 2 and 3 from Table 5.

40

50

1/e

of data developed in

tion of an acetylenic compound, an amine and an oxyalkylated naphthenic acid68 is a case in point. Again, acetylenic compounds are improved by using them with thio-compounds, as in the use of a thio or sulfoxide compound, a sulfonated laurylamine and an acetylenic alcohol,69 the combination showing unexpectedly high inhibiting efficiency.

in the outer fluid regions is gradual, giving rise to an intermediate buffer zone between the two principal zones. The relative thickness of the various zones depends upon the degree of turbulence existing, as measured by the Reynolds number,7! for example. This is the modem view of the Nemst mm. As pointed out by Van Name and Hill,72 it is not necessary to assume that a layer of solution next to the solid surface remains quite stationary with respect to the surface. It is sufficient that the fluid motion normal to the surface becomes small

Acid Corrosion in Flow Systems Velocity Effects in Corrosion and Inhibition Activational and mass transfer processes significant in the corrosion of metals, in the absence or presence of inhibitors, indicate that the observed overall reaction rate is the result of a number of partial processes, physical and chemical and that this overall reaction rate is always controlled by the rate of the slowest of the partial processes. The processes involved in metal corrosion and in fact in any heterogeneous process, can be classed under two general headings: 1. Activational processes, and 2. Mass transfer processes. Activational processes are usually considered under the heading of those fundamental processes related to the actual chemical reaction involved. The inertness of the

and does not affect materially the rate at which dissolved substances are transported to and from the surface.73-76

Fluid Velocity, the Diffusional Boundary Layer and Reaction Rate Considering then, corrosion reactions of the common metals, in many cases these rates do seem to be controlled by mass transport processes. Among these processes, diffusion through a boundary layer (the Nemst mm) seems to be the slow process-and the controlling one-from the point of view of overall corrosion reactions. The variation with fluid velocity of the boundary layer in thickness and

noble metals is a specific example, where the fundamental chemical reaction is the sluw process. 167

in effectiveness as a diffusional resistance is of extreme interest. Actual measurements of the boundary layer have been made by Fageand Townsend77 and their results have been rela.ted to· actual corrosion by King,76 who studied the solution rate of a magnesium cylinder in acetic acid at 25 C, at different rotational rates. King wrote the Nemst equation as - (dx/dt)=

(D/o) (A)(a-x)/Y

16.0

o N/5 H2S04 • •

•. 0~0'"> Qi Sl > et:

>c:

' chromate benzoate > phosphate > hydroxide - carbonate > bicarbonate> nitrate.

Chromate Inhibitors for Cooling System It is apparent that a single chemical seldom provides complete protection to an engine cooling system because of the varied service conditions that can be encountered, but it has taken many years of testing to reach this conclusion. Chromate was one of the earliest inhibitors suggested for use in engine cooling systems. Darrin36,3 7 discussed its use in diesel engine cooling systems or in automotive cooling systems during the summer months when water alone was used. Nitrates, borates and carbonates have been used in combination with chromates to provide added protection and better pH control. Best and Roche38 found satisfactory protection in field tests with the use of chromates in methanol antifreeze.

Levy32 investigated the anodic and cathodic behavior of steel in inhibited 30% ethylene glycol-water solutions by applying an external electromotive force to a copper-steel couple. He found that borate, nitrite, chromate, silicate, benzoate and triethanolamine functioned as anodic polarizers;whereas, mercaptobenzothiazole was a cathodic polarizer. Northan and Boies33 tested 68 different chemicals for effective inhibition of aluminum by measuring the volume of hydrogen released by the corrosion reaction. It was concluded that effective inhibitors were those that prevented a pH rise, formed insoluble aluminum compounds, or formed adsorbed films because of their semi-polar characteristics. Cessna34 emphasized the significance of surface conditions and he found that precorroded steel was more difficult to inhibit again~t further corrosion than a clean, polished metal surface. Using a change in metal conductivity to shbw inhibitor effectiveness in glycol-water solutions containing cWoride, suifate and bicarbonate salts,

However, they cautioned that hexavalent chromium is susceptible to reduction to trivalent chromium (which forms insoluble Cr203) by substances in the solution and by light. Rowe39 studied the use of sodium chromate with ethylene glycol in considerable detail. Qualitative tests showed that the reaction between chromate and ethylene glycol is dependent upon temperature, pH and the catalyzing effect of light. Degradation began within a few hours in the presence of light but only slight breakdown occurred in a four-month storage period in the absence of light. Car tests were run with 2000 ppm chromate in ethylene glycol solutions, but when chromate was added once only, it was soon depleted. When chromate was added continuously by means of a by-pass filter, a concentra tion of 450 ppm was maintained. 1t was concluded that under certain conditions and with the exclusion of light, chromates could be used with ethylene glycol solutions. However, they are used infrequently in automotive engine cooling systems today to avoid the possible formation of insoluble chromium oxide. Chromates are still used

he f~und that borax at a concentration of 0.18% by weight was the least effective inhibitor orseveral for the protection of steel. Bop!,x, IIletasilicate and polar oil protected alumirium,'but benzoate and nitrite did not. Borax, nitrite, and polar ,p\I were ~ffecti.ve inhibitors for copper and brass corrosion .... I . '. Rowe35 . con~ucted a series of evaluation tests on a number oC metali using 1% solutions of sodium borate, sodium ben~of~e'~' ~Qqi~m nitrite, potassium dichromate, emulsifiable oil and the sodium salt of mercaptobenzothiazole (MBT). Each test.was run on a single metal at 77 C (170 F) for 14 50% solution of salts added in inhibitors were

days. ~9I,lftioris were either tap water or a glycol-tllp: water 1 wi~h chloride and sulfate some cases to' Increase corrosivity. All fairly effective in the absence of the

in commercial by-pass filters for heavy-duty vehicles and even somewhat successfully with ethylene glycol coolants. Some antifreeze products are more compatible than others 178

'I

with chromates and the antifreezes to be used are selected on the basis of compatibility tests.

aluminum was reported by Collins and Glover46 in boraxinhibited water than in borax-inhibited glycol solutions, presumably because of the formation of acid products in the glycol solutions. Bregman and Boies47 in their investigation found borate-nitrite to be an effective combination. Although borates have definite inhibitive qualities under certain environmental conditions and reinforce the effect of other inhibitors, one of their principal functions is to provide reserve alkalinity and buffering action against acids. Reserve alkalinity is a term that is used to define the capability of a solution to neutralize acids. It is given a numerical value in terms of tl1enumber of milliliters of O.IN HCl required to titrate 10 ml of concentrated antifreeze to a pH of 5.s.4 8

Advantages of By-Pass Filter

The concept of adding an inhibitor to the cooling system by the use of a by-pass filter has some merit for vehicles that are on a maintenance schedule because filters are easily replaced, which ensures an appropriate level of inhibitor. However, if a well-inhibited antifreeze is used, maintained and replaced at proper intervals, .there is little need for this approach. Because of the inherent vulnerability of chromate to reduction in organic fluids and because of the difficulties that can arise if large amounts of precipitates are formed, it appears reasonable to exclude chromates from the system. In recent years, other inhibitors, such as borates and nitrites, have been used in by-pass filters and this approach would appear to be safer. Chromates may still be used successfully in water systems, such as diesel engine cooling systems and optimum efficiency under recirculating and cavitating conditions can be obtained at a concentration of 500 ppm.40-42 The consumption of chromate is high during the first few days but stabilizes within three months. Chloride ions can accelerate consumption so an increased concentration of chromate is required in the presence of chloride.

Inhibitors for Copper Alloy Mercaptobenzothiazole (MBT) and benzotriazole49 (more recently tolyltriazole has been proposed as an alternative) are two inhibitors that have contributed much to the success of formulated antifreezes because of their specific inhibition of copper and its alloys. By preventing the corrosion of copper, these inhibitors have the added effect of reducing the corrosion of iron and aluminum since fewer copper ions are available to migrate to those metal surfaces to deposit and cause galvanic effects. MBT is subject to degradation from heat and light and sodium sulfite is added to the commercial product (a water solution of the sodium salt of MBT) to prevent its oxidation to benzothiazyl disulfide. Because of this instability, antifreeze with MBT as an inhibitor should be'stored in the dark or in opaque containers. MBT is also pH dependent and it is necessary to maintain the ,pH on the alkaline side. SquiresS0 claims that copper corrosion products in the system consume MBT. The lowest effective concentration was found to be about 0.01%. At an initial concentration of 0.1%, it took 8 to 16 months in car tests to reach the low' level of 0.01%. Benzotriazole is reported to be more stable than MBT to light and to high coolant temperatures and to provide equivalent inhibition at lower concentrations. There is less information in the literature on its evaluation than on MBT, but it is known to be used in a number of formulations.

,Borate Inhibitors A good share of the inhibitor formulations in the United States contain. borate. Several of these formulas from the patent literature have been listed by Jackson et al.28 Borates are used as either the tetraborate (borax) or the metaborate. Because of their solubility in ethylene glycol, they are ideal for formulating antifreeze products. However, borates alone seldom provide adequate metal protection in the variety of waters that are used in engine cooling systems.43 Dulat44 stated that while borax preserves the protective oxide film on iron, it does not become part of the film. A concentration above 0.6% is required for protection. It also protects copper and is satisfactory for aluminum but not when aluminum is coupled to iron or copper. Dulat4S ran a five-year service test on a borax-based antifreeze with an inhibitor concentration in the glycol of 3.3 borax, 0.11 MBT, 0.11 Na2Si03 . 5H20 and 0.04 Ca(OH)2 in percent by weight. He reported excellent corrosion inhibition with about a 33% glycol solution. No depletion of borax occurred in 6 months, but over 50% of the MBT and silicate was depleted. These results should be viewed with some caution, because only one test car was used and because total accumulated mileage in five years was only 48,000, which is considered light-duty operation. Furthermore, the coolant was replaced at six-month intervals and a relatively mild water containing 20 ppm chloride ion was used for dilution of the glycol. As mentioned previously, both Cessna34 and Rowe3s found reduced effectiveness of borax with increases in chloride or sulfate ion concentrations.

Emulsif13ble Oils Emulsifiable oils ("soluble oils") are another category of corrosion inhibitors that have been used in the automotive engine cooling systems. They consist of a combination of a mineral oil base and one or more polar organic materials, such as fatty acids or their salts, petroleum sulfonates, or sulfated vegetable oils, along with emulsifying agents. Evanss 1 says that the oil particles carry a negative charge and are deposited at the anodic points in the corrosion process. Powers and Cessnas2 say that polar oil molecules are adsorbed onto metal surfaces and provide a thin layer of the carrier oil. It was claimed on the basis of change in potential that the higher absorption of oxygen by the oil film leads to passivation of the metal surface and that the barrier action of the oil allows passivity to be

Weibu1l43 found that borax alone did not provide satisfactory protection in car tests. Less corrosion of 179

maintained under unfavorable conditions. Neither the oil base nor the additive was effective alone. Emulsifiable oils are not added normally to antifreeze concentrates, although a polar type of oil was used for many years in one major antifreeze product. The use of emulsifiableoil has been restricted to additions to water coolants during the summer months and for many years a few ounces of emulsifiable oil was added to production-car cooling systems as a pump lubricant. Sealers that are added to cooling systems to reduce leakage contain oil in some cases. There are some disadvantages to the use of emulsifiable oils. They will contribute to the growth and stability of foam if there is a condition in the cooling system that encourages its formation. If the emulsion breaks, the separated oil floats on the surface of the coolant and coats metal surfaces, affecting the transfer of heat from the metal to the coolant. Oil can cause degradation of some polymeric materials used for hoses. Finally, there are variations in the inhibitive qualities of emulsifiable oils, even in the same brand, because of variations in composition or differences in manufacturing processes.

and Glover57 suggested that this combination of inhibitor may damage rubber and benzoate-nitrite-borax may cause solder corrosion. Benzoate in another test was found to creep and cause etching of aluminum above the liquid level.9 Another formulation that has been evaluated extensivelyby the British is one containing 0.4% triethanolamine (TEA), 0.19% phosphoric acid and 0.041% of the sodium salt of MBT. Triethanolamine phosphate (TEP) when used without MBT in glycol-water solutions causes accelerated corrosion of copper alloys by complexing the copper cations, allowing them to migrate through the solution and deposit on aluminum or steel.58 Squires50 found that TEP does not prevent the oxidation of glycol to form acids, but it does provide a weak buffering action that might be more preferable than the effect of more alkaline buffers that can attack some metals. In a simulated service test, the acidic oxidation products rose from 0 to 0.3 gram equivalents per liter, with most of the products being formic acid.56 TEP has some softening effect on hard waters, but the quantity of insoluble phosphates that are formed has little effect on the function of the cooling system. Weibu1l43reported that TEP-MBT formulated antifreeze gave good protection in a car test until the inhibitors were depleted. Collins and Higginsl3 ran car tests with this formula and found that most of the phosphate and MBT werelost in two months or 4000 miles and they associated the increased corrosion to the formation of acids from glycol breakdown. Collins and Glover55 ran simulated service tests at 80 C, using a 20% glycol solution and the TEP-MBT inhibitor system. A marked decrease in the concentration of MBT (0.035 to 0.005%) occurred in the first 100 hours, followed by a slow decline to almost zero in 900 hours. There was a steady decline in phosphoric acid and TEA content over a 600-hour period and at this point the phosphoric acid content was almost zero and the copper in solution rose from 40 to 150 ppm. A drop in pH and a rise in acidic products caused increased corrosion of aluminum, cast .iron and bronze. In water alone, adequate protection was maintained even though the MBT was partially depleted. There has been a definite trend in recent years in the United States to include phosphate in inhibitor formulations. Phosphate has buffering action and increases the reserve alkalinity. Furthermore, it has been found to be very effective in reducing cavitation of aluminum pumps. The antifreeze for military use in the United States for many years is identified as Type I antifreeze and it contains 2.5% borax in the concentrate.59 In order to improve the inhibitive quality of the coolant, it is recommended now that other inhibitors be added to the cooling system from a separate packaged product. A 170 g (6 oz) package contains approximately 26 g of mercaptobenzothiazole, 65 g of anhydrous Na2B407, and 16 g of anhydrous Na2HP04.6o The inhibitor is added to either water or a Type I antifreeze-water system at a concentration of 28 g (1 oz) inhibitor to 1.9 g (2 qts) of water. Conley,61 who reported on the development and evaluation of this inhibitor system, found satisfactory corrosion protection in both hard and corrosive water in vehicle tests which accumulated 34,000

Mixed Inhibitor Systems One of the inhibitor formulations that has received considerable attention, particularly by the British, is the benzoate-nitrite combination. Mercer and Wormwell12,53,54 reported their findings with this formulation in a number of publications in the literature. Five percent sodium benzoate and 0.3% sodium nitrite in a 25% ethylene glycol solution protected cast iron and solder as well as other metals at room temperature for five years. The nitrite concentration can be reduced to 0.1% under conditions of intermittent heating. Sodium benzoate alone is less effective for cast iron than steel. Sodium nitrite alone is very effective for ferrous metals but attacks solder. The combination of the two prevents corrosion of cast iron, solder, brass and copper in 20% glycol solution with intermittent heating. In low mileage (2500 miles) car tests, 1.5% benzoate did not prevent corrosion of cast iron in new engines but arrested corrosion in used engines; whereas, 1.5%benzoate and 0.1% nitrite were effective in both cases. Corrosion of aluminum was not completely pre~ented in either case. The pH was found to rise as high as 10.0 and the concentration of inhibitors dropped. Based on recirculating tests run at 80 C (176 F) for a minimum of 1000 hours, Collins and Glover55 found that a 20% glycol solution containing 1.2% benzoate and 0.1% nitrite showed a steady decline in nitrite over the first 800 hours while the benzoate remained constant. In water alone, the benzoate showed some decline after 500 hours. In a simulated aluminum-alloy-engine test, the nitrite concentration dropped to zero in 1000 hours,56 and the solution became corrosive to aluminum as the inhibitor depleted and oxidation products were formed. Aluminum alloys were pitted under conditions of low coolant flow. Weibu1l43found the benzoate-nitrite combination to be the most stable of four antifreeze formulations tested. Collins 180

liquid and the condition of the metal surface have a determining effect on the severity of the cavitation. Inhibitors in coolants can either reduce or increase cavitation, depending on their effect upon the physical characteristics of the coolant and the formation of vapor bubbles and their effect upon the characteristics of the metal surface. In the latter case, the inhibitors must have good stability at the metal surface. Wilson64 gives an excellent review of the effect of physical characteristics of the solution on cavitation. He found in his experimental work that there was no difference between the cavitation damage produced in water alone or in a 20% glycol solution at 60 C (140 F). The damage in the glycol solution was fourfold greater than that in water at 80 C, partly because the decrease from the maximum at 60 C was more precipitous in water than in glycol solution. In a comparison of commercial antifreezes, cavitation damage decreased with an increase in antifreeze concentrations over a broad temperature range. Clark6s also found a dependence on antifreeze concentration, with maximum damage at a concentration of about 20%. He also showed a considerable variation in the degree of cavitation caused by different antifreeze products when tested under the same conditions.

miles over a 13-month period. (A new Military Specification, MIL-A-46153(MR), dated October 19, 1970, covers an antifreeze compound that includes all of these inhibitors in a single package.) New Formulation Developed A formulated antifreeze product was developed recently by the General Motors Corporation.6Z This product contains the following concentration of inhibitors by weight percent in the antifreeze concentrate: 0.21 NaN03; 0.98 Naz B407 . 5Hz 0; 0.17 Naz Si03 . 5Hz 0; 0.43 Na3 P04 . 12Hz 0; 0.55 ofa 50% water solution of the sodium salt of MBT and 0.19 NaOH. This combination of inhibitors was selected after evaluating a large number of candidate formulas. Each chemical serves a particular purpose: 1. Nitrate for protection of aluminum and solder, 2. Borate for its buffering action, reserve alkalinity and protection of ferrous metals, 3. Silicate for general protection of all metals, 4. Phosphate for protection of ferrous metals and aluminum and its buffering action, 5. MBT for protection of copper and brass. 6. NaOH for additional reserve alkalinity. Furthermore, cavitation.

silicate and phosphate

The effectiveness of specific inhibitors in preventing cavitation has not been publicized greatly. Chromates and emulsifiable oil have been reported as having a significant effect on the reduction of cylinder liner cavitation in diesel systems. Wa1l66 postulated that vibration at the metal surface was beneficial to chromate inhibition because it increased the movement of oxygen to the surface. The ASTM Pump Cavitation TestZ4 or a similar test has been used extensively in the automotive industry67,6 8 and by antifreeze producers to evaluate inhibited antifreezes. Significant differences have been found in the results obtained from different products, but these results have not been published. Phosphate and silicate inhibitors have been found generally to be the most effective deterrents to cavitation of aluminum water pumps. Phosphates are used more often in current antifreeze products because they are more stable than silicates at higher concentrations in the antifreeze concentrate. However, antifreezes that contain borates as essentially the only inhibitor appear to cause more cavitation damage than do glycol-water solutions without an inhibitor. This effect is more pronounced under accelerated conditions and there is supporting evidence from service tests. There is some indication that if a

are effective against

This type of formulated antifreeze provided excellent corrosion protection at a 44% concentration, using corrosive water for dilution in 10 test cars for a two-year period, with an accumulated mileage in each car of 20 to 25,000 miles. Normal depletion of silicate, MBT and phosphate occurred, but the pH and reserve alkalinity of the coolant solutions showed only a nominal change in two years. The product has reasonably good storage stability, good compatibility with other antifreezes, good high temperature stability and good protection against cavitation. Cavitation ofAluminum Cavitation-erosion generally has not been a major problem in the au tomotive engine cooling system. However, there has been considerable research associated with the cavitation of aluminum pumps and timing chain covers. Because of the advantages in being able to use die cast aluminum components rather than cast iron, there was a trend in this direction until tests and service experience indicated the susceptibility of this material to cavitation damage under some operating conditions. Under severe cavitating conditions, the metal can be perforated, leading to loss of coolant or entry of the coolant into the oil system. The subject of cavitation has had extensive coverage in the literature, and a general review has been given by Godfrey.63 Much of the information has been related to cavitation of diesel cylinder liners rather than that of automotive components. Because cavitation damage results from the formation of vapor bubbles under differential pressure conditions and the subsequent implosion of these bubbles on the metal surface, the physical properties of the

borate-inhibited antifreeze is allowed to form a protective film on the metal surface before the surface is exposed to cavitating conditions, there will be less damage than when bright metal is exposed immediately to cavitating conditions. In summary. inhibition of corrosion in an engine cooling system is not an easy task. A thorough knowledge of the system and its environmen tal variations is necessary to develop formulations that will provide adequate protection. Good test procedures must be followed to ensure that results are indicative of service perfonn'lI1ce. Even the best product has a limited life and the cooling system must be 181

TABLE 1 - Consumption of Deicing Salts in the United States and Canada for 1960-70

maintained properly and the inhibitor content kept at an adequate concentration to ensure good cooling performance.

Millions of Tons Calcium Rock Salt Chloride Abrasives

Exterior Metal Surfaces The environmental

conditions

to which automobiles

United States

are exposed have a determining effect upon the destructiveness of the corrosion that occurs. Although corrosion can occur in the presence of moisture and air alone, the severity of corrosion is determined largely by the species of salts or gases that are dissolved in the moisture and by conditions that increase the time of exposure to these corrosive environments. Sui fur dioxide is one of the gases found in fairly high concentrations in the atmosphere. It forms either sulfurous or sulfuric acid in combination with water and oxygen. Nitrous, nitric, hydrochloric, formic and acetic acids have been identified in the environment and can be expected to accelerate corrosion. Organic substances and aerosols in the atmosphere may not make a direct contribution to corrosion, but they may have an indirect effect. They can react chemically with another species to produce a new species that is more corrosive, or they can cause particles· of material to adhere to the metal surface' be'Cause they function as an adhesive or have a particle charge. Particulate"matter, such as carbonaceous material, can fall ori a metal surface and can cleaie high concentrations of acid through gas absorption, in the pres.ence of moisture. Particles of iron,eopperand -other solids can produce differential-aeration cells ona metal surface or cause

Canada

9.00 1.75

0.28 0.02

10.42 3.62

improved driving conditions during the winter months.70 The most commonly used chemicals are sodium chloride (rock salt) and calcium chloride. The Salt Institu te 71 in a recently published survey gave the estimated use of these chemicals and abrasives in the United States and Canada for 1969-70 as shown in Table 1. Wood 72 made a projected estimate for deicing salt consumption in the United States for 1974-75 of ten million tons and this estimate has been revised by the Salt Institute 71 to eleven to fifteen million tons. Much of this usage is restricted to only a portion of the country, but Weigand and Schrock73 stated that approximately 40% of the cars in the United States are in deicing salt areas. Calcium chloride depresses the freezing point of water more than rock salt, but it is used to a lesser extent because of cost. When used, it is often combined with rock salt at a ratio of one part calcium chloride to three parts rock salt, with the prevailing tendency to use it on expressways or freeways rather than on city streets. The corrosivity of solutions of these salts has been compared and it has generally been concluded that at equal chloride concentrations there is little difference in their effects on the corrosion of ferrous metals, although less is known about their effects on other metals. The difference

galvanic effects, which often lead to local high corrosion rates and severe pitting. Deicing salts, because of their nalidecontent, increase the conductivity of moisture and contribute to the breakdown of protective films. Recognizing the significance of the environment on the corrosion of :external components of the automobile, car manufacturers have used many different preventive measures to minimize corrosion. An SAE Committee

in corrosivity of the two salts lies in the difference in their hygroscopicity when on a metal surface. Preston and Sanyal74 compared the weight gain of a number of salts over a seven-day period at varying relative humidities. Calcium chloride gained 139% weight at 58% relative humidity, which increased to 465% at 94% relative humidity; whereas, potassium chloride, which should react somewhat like sodium chloride, showed no appreciable gain until a relative humidity of 94%, where the gain was 198%. Thus, surfaces coated with calcium chloride will be wet for longer times than those coated with sodmm chloride because calcium chloride will absorb and retain moisture

published a report69 in 1964 in which some of these preventive methods are discussed. They include design features that should minimize exposure to corrosive conditions and the use of: 1. Corrosion resistant metals and polymeric materials, 2. Coatings and protective treatments, and 3. Inhibitors. The barrier effect of coatings, the sacrificial protection of a metallic coating such as zinc galvanizing and the protective quality of electroplated coatings are utilized to a great extent. Although inhibitors are used in paints, sealers and undercoating rust preventives to supplement the protection provided by the coating, a more direct application of an inhibitor and one that has received considerable attention, is the addition of inhibitors to deicing salts.

over a greater range of relative humidities. Damage from Deicing Salts There can be little doubt that deicing salts contribute to the corrosion of automobiles. The deleterious effect of deicing chemicals on automobile corrosion has been discussed in an excellent report by the O.E.C.D. Road Research Group.7S Surveys have consistently shown that more corrosion occurs in cities using deicing salts than in those that do not. 76 Laboratory tests support these findings in that salt solutions are more corrosive than plain water; maximum corrosion occurs in salt solutions at a concentration between 3 and 4'fr,. Even though deicing salts

Deicing Salt Inhibitors Chemicals which are spread on the streets to lower the freezing point of snow and ice are referred to as deicing salts. They are used along with abrasives to provide 182

-

made in the Civic Affairs Committee Repore 7 that inhibitors in deicing salts have doubtful value in preventing corrosion that affects the exterior appearance of cars, but they might reduce the effect of corrosion on unprotected metal surfaces.

increase the corrosivity of the environment, the average . motorist recognizes their value in providing increased safety. This was expressed very aptly in a report from the Civic Affairs Committee of the Engirieering Society of Detroit 77 where the statement was made that "public safety through the safe movement of traffic should be the paramount compelling force in any choice of deicing method or material." Wirshing 76 mentioned that, without the use of salt, losses in Detroit could reach $100 million per year in lost work, lost customers to businesses, lost transportation income, and lost business to cartage and trucking companies. A number of less corrosive substitute materials have

NACE Committee Investigates NACE Technical Unit Committee T-3N (formerly T-4D), Corrosion by Deicing Salts, has followed closely the controversial aspects associated with the use of de icing salt inhibitors. The question of the effectiveness of inhibitors has been asked periodically at committee meetings. Laboratory test results would usually show that inhibitors produce a substantial reduction in corrosion, but field test results were less obvious. As pointed out by LaQue,8 3 it is difficult to obtain quantitative data to substantiate a reduction in corrosion by the use of inhibitors in the field. NACE sections in New York State ran a joint test in 1958 to compare corrosion rates in Buffalo, Syracuse and Rochester, where the latter city was the only one to be using an inhibitor. 84 Fifty steel coupons were attached to vehicles in each city. The average corrosion rate was essentially the same in each city. Corrosion rate per 1000 miles of vehicle operation was lowest in Syracuse. By adding the factor of tons of salt used, Rochester showed the lowest rate. Uncontrolled variables, such as humidity, driver habits, car storage and the number of times cars were washed affect results and were not taken into consider-

been suggested to replace rock salt and calcium chloride. Boies and Bortz 78 proposed the use of urea, calcium formate and formamide. Waindle 79 mentioned the use of ammonium sulfate and magnesium, lithium or aluminum chlorides. These substitute materials are not as effective as the rock salt or the calcium chloride and their cost is usually higher. In an effort to decrease the corrosivity of deicing salts, inhibitors have been considered. Because of its known inhibitive qualities, a chromate salt was one of the first materials considered for this purpose. Sodium dichromate was used at a 1% concentration in the city of Akron, Ohio during the winter of 1947-48.80 From a comparison of cars from areas using inhibited salt with those from areas using salt alone, the inhibition was considered satisfactory.81 There was an apparent psychological value in the use of a yellow inhibitor because the color made people aware that an inhibitor was being used. However, the continued use of chromates was questioned because of their toxicity and irritant effect on the skin. Therefore, glassy metaphosphates were used in 1948-49, with a green dye added to show the presence of an inhibitor. The city authorities in Rochester, N. Y., where more salt was being used than in cities of comparable size, became interested in the use of inhibitors at this time and it was decided that an inhibitor must be nontoxic, nonstaining and nonirritating to the skin. The inhibitor that was selected for use during the winter of 1948-49 was a polyphosphate-nitrite chemical containing a strontium salt. Temmerman and Sterlin82 reported wide variations in weight losses within groups of test coupons that were attached to passenger cars, trucks and snow plows, but the average weight loss showed less corrosion in areas where the inhibited salt was used than in areas where salt alone was

ation. The inhibitor concentration of salt samples in Rochester was found to be one-third of the intended 1% concentration. Because of these many variations, the results were considered inconclusive and inhibitors have not been added to deicing salts in Rochester since 1958 despite the favorable reaction of the public.8s The city of Akron cOl).tinued to show an interest in the use of inhibitors and an ordnance was passed in 1961 that required the addition of an inhibitor to de icing salts.8 6 An effort was made to have surrounding cities do the same thing, with the possibility of eventual state-wide use. However, a subsequent vote in Akron to approve the funds for this endeavor failed to carry, 87 and the city has added only a nominal but itu:ffective concentration of inhibitor to meet the requirements of the ordinance.

Testing of Salt Inhibitors Because of the difficulty associated with the interpretation of field test results, there was a strong incentive to develop a laboratory or simulated field test that would be more indicative of the effectiveness of inhibitors. A test was designed at the Ontario Research Foundation88,89 that consisted of three small circular tracks on which four

used. The inhibitor was tested again the following winter, with one of the major benefits being a reduction in complaints from the citizens in the city. Based on the inspection of exterior surfaces of thousands of cars in various cities in the United States, Wirshing76 reported that corrosion was always greater in those cities using deicing salts. However, a comparison of corrosion in Rochester and Akron, where inhibited salts were used, with that in Detroit, where uninhibited salts were used, showed no essential difference in the severity of corrosion. These surveys provided no information about underbody or internal corrosion and the conclusion was

separate hooded wheels could be operated on each track (Figure 1). All tracks were run with snow and soil added to the track; salt was also added to one track and salt plus inhibitor to another. Salt was used in an amount that would give a concentration of 4 to 7% in water formed from melted snow and sodium hexametaphosphate inhibitor was used at a concentration of 2% by weight of the dry salt. Test panels of various shapes were fitted to the underside of 183

..

controlled. Palmer92 determined the average reduction in corrosion as a result of the inhibitors on the basis of that portion of the corrosion caused by the salt addition alone (difference between corrosion in salt water and water alone). On this basis, he found that Carguard was 69 to 78% effective on flat panels and 57% on v-shaped panels. However, the actual reduction in corrosion rates between that in the salt solution and that in the Carguard salt solution was only about 16%. An extensive field test program was run using treated salt in Minneapolis, Minnesota and untreated salt in Milwaukee, Wisconsin. Scribed painted panels, plain carbon steel and stainless steel panels and plated and anodized panels were attached to racks on the front ends of test vehicles. As a result of these tests, J ameston and Ireland93 found that panels exposed to inhibited salt on the streets showed consistently less corrosion than those exposed to uninhibited salt. On the basis of weight loss, corrosion of steel panels over a I4-week test period was 52% less in the inhibited salt area than in the uninhibited salt area. Although test conditions in the two cities were about the same, the weather was less severe than in previous years and salt was not used as frequently as expected. This may have had some effect on the results. Zaremski94 was interested in the corrosion of stainless

FIGURE 1 - Testing setup to evaluate merits of inhibition in street deicing salts.

fenders or hoods and the wheels were operated at an average speed of 25 mph. The results after 91 days showed that the inhibitor caused a reduction in salt corrosion ranging from 10.5% to 77%, depending on the shape and position of the panel. Based on an extrapolation of results to a year, it was estimated that the inhibitor would reduce corrosion by about 25%. A recent entry into the inhibitor field has been a material sold under the tradename of Carguard.(I) This product has the rock salt and inhibitors already mixed before it is distributed for use. This procedure assures uniform distribution of inhibitor in the salt and at a proper concentration. Carguard contains four inhibitors plus sodium ferrocyanide (a chemical added to reduce caking during stock piling).90 The exact composition of the inhibitor system has not been published, but one inhibitor is apparently a chromate and some of the others have been referred to as a long chain organic compound and an additive that catalyzes the conversion of Fe(OH)2 to gamma ferric oxide. Cost of the product was originally estimated to be about $4 more per ton than rock salt. This product has been subjected to one of the most extensive testing programs of all inhibitors. One of the early tests was run in a park at Davenport, Iowa,91 where a number of areas were set aside for different salt treatments.

steel and its galvanic effect on mild steel in these tests. To obtain additional information, tests were run in Pittsburgh where uninhibited salt was used, and the results were compared with those from its suburbs where inhibited salt was used. Galvanic corrosion was reduced by over 90% as the result of the use of inhibitors in the MinneapolisMilwaukee test, but only 60% in the Pittsburgh test. Surface corrosion of Type 430 stainless steel and muffler grade stainless steel showed significant benefit from the use of an inhibitor in Minneapolis the first year but less benefit the second year; there was essentially no benefit in the Pittsburgh area. Differences in salt usage and exposure conditions were assumed to have affected the latter results. Where corrosion by industrial pollutants was a factor, the effectiveness of the inhibitor was less pronounced. Black and Lherbier9s in some previous studies found that corrosion results from service exposure may be conflicting because of the unpredictability of the weather and the nature of the corrosive conditions; thus, correlation between corrosion resistance and the use of inhibited or uninhibited deicing salts is not always clear. Because one of the inhibitors in Carguard was a chromate, this test program provided an opportunity to determine whether the effluent from city streets, where this inhibited salt was being used, might seriously affect lakes and streams. Samples of effluent, taken at several points where it entered the lakes, were analyzed for chromate content. The concentration of chromate was determined to

A single car was used in each area and test coupons were exposed under fenders. As a result of this test, the inhibitor was said to provide over 80% protection. In a test program at the Ontario Research Foundation, a test cabinet was constructed with three compartments; each compartment contained an automobile snow tire and facilities for mounting an array of flat and v-shaped steel panels in selected positions. Wheels were revolved at a speed of 10 mph for two IS-minute periods each day. Plain water was used in one compartment, 3% road salt in another, and 3% Carguard in the last one. Humidity and temperature were (l)Product

be sufficiently low that it did not appear to constitute a problem. An independent report from West96 on the toxicity of Carguard showed it to be comparable to sodium chloride; therefore, it is not a health hazard under ordinary conditions.

of Cargill, Inc., Minneapolis, Minnesota.

One of the most comprehensive 184

series of tests was

less than the minimum concentration of 0.5% found to be necessary in the laboratory. The Research Foundation of the American Public Works Association initiated a series of car tests in Minne-

conducted by Fromm97 of the Department of Highways in Ontario, Canada. Vehicle corrosion tests were run in a variety of different environments and. test coupons were exposed on racks at the same time to these same environmental conditions. He also tested inhibitors in a Traffic Simulator Test, similar to that used by Palmer.89 Three inhibitors were evaluated in this test, including impure hexametaphosphate, a finely divided metal powder and a proprietary product with general inhibiting properties. Coupons were removed periodically from all tests to determine the corrosion rate at different intervals of time.

apolis in 1967 to investigate the effectiveness of deicing salt inhibitors. 1 00 Three cars were driven over each of three test areas-one site treated with sand, one with rock salt and the other with inhibited salt. Cars were dismantled at the conclusion of the test for inspection and rating of parts, while interim information was provided during the test by exposed panels. It was concluded that deicing salt contributed to as much as 50% of the corrosion. Inhibitors

The atmospheric corrosion rates varied from location to location; vehicle corrosion rates tended to follow the same pattern unless deicing salts were used, in which case there was an increase in rate. Test coupons in the Simulator Test had corrosion rates that were comparable to those from vehicle tests; in the absence of salt, the corrosion rate was about one-half that of coupons exposed only to atmospheric conditions. By carefully comparing these different corrosion rates under several different exposure conditions, it was concluded that the decrease in corrosion brought about by the use of inhibitors was not sufficient to warrant the extra cost involved in their use.

caused some reduction in corrosion of bright metal parts but had little effect on corrosion of major vehicle parts. Inhibitor Effectiveness Evaluated Although other tests will probably be run in the future, some tentative conclusions can be drawn about the effectiveness of inhibitors in de icing salts on the basis of results that have been provided to date. Assuming that results indicate that an adequate concentration of some inhibitors will decrease the corrosion of bare metal when exposed to deicing salts, what then are the problems associated with the use of these inhibitors? One of the problems is to ensure that an effective concentration of inhibitor reaches

Bishop and Steed98 ran a series of laboratory tests using bare steel panels and scribed painted panels. Corrosion rates of the bare steel panels were determined at intervals over a six-week period. Panels were exposed at 25 C (77 F) to an intermittent fog from a 3% salt solutionfour hours of fog and 20 hours without fog. Tests were run using an addition of 0.1% emulsifier STH (sodium salt of N-alkylsulphonyl-glycine) to the salt, 1% STH, 1% sodium hexametaphosphate and 3% Carguard. The reduction in corrosion rate was only 20% for both concentrations of STH, 10% for hexametaphosphate and less than 10% for Carguard. Hexametaphosphate provided the best protection to scribed painted panels on the basis of rust creepage from the scribe mark on the panels.

the metal surface. The first requirement is a homogeneous mixture of inhibitor and deicing salt. This is seldom attained when the inhibitor is added to stockpiled salt or to a truck load of salt; therefore, the inhibitor and salt have to be premixed before use. Even the use of a premixed material does not ensure a proper inhibitor concentration after the salt is spread on the street. Since the inhibitor usually coats the outside of the salt, the dissolution of the salt and the melting of the ice is delayed if the inhibitor dissolves slowly. 1 00 If the inhibitor dissolves first, it may be splashed to the side of the road, leaving the salt behind with a reduced concentration of inhibitor. Rain and snow may also wash the inhibitor from the surface of the salt. Even with an

Asanti99 studied a number of inhibitors in an alternate immersion test. These inhibitors included sodium nitrite, sodium chromate, sodium hexametaphosphate, sodium zinc metaphosphate, water glass and stearylamine. Chromate and nitrite were not given .serious consideration because of their toxicity; some inhibitors were impractical to use; and the sodium zinc metaphosphate was not effective. Sodium hexametaphosphate was the most effective inhibitor in 3% solutions of both sodium chloride and calcium chloride when the inhibitor concentration in the solution was

adequate concentration of inhibitor in the salt, there is still the problem of distribution to and retention at the metal surfaces. Distribution is provided by direct splash from the wheels of the vehicle or by spray from other vehicles, but this does not guarantee uniform distribution of inhibitor and salt. Shielded areas that are not directly exposed to the spray may receive less inhibitor, or the inhibitor may be leached faster than the salt from surfaces packed with mud and snow. In some cases, a uniform mixture of inhibitor and salt may not reach the metal surface because they do not penetrate debris on the surface at the same rate. Aside from the difficulties associated with assuring an adequate concentration of inhibitor at the metal surfaces, the other deterring factor is the cost of adding an inhibitor to salt. At a minimum additional cost of three dollars per ton, a city the size of Detroit, which uses over 90,000 tons of salt per year, 71 would have to spend over $300,000 additional per year. Although the average car owner would probably pay very willingly the unit cost per vehicle of a few cents, there is less support for the use of municipal

greater than 0.015% (0.5% of the salt concentration). Road tests showed a decrease in phosphate inhibitor concentration in solutions from salt-sand mixtures because the inhibitor tended to be adsorbed by the sand; a 1% inhibitor addition to a salt-sand mixture was insufficient to provide the proper concentration to a solution from the mixture. An analysis of splash samples in the winter showed further evidence that the inhibitor had concentrated in the sand rather than in the salt; the inhibitor concentration in the solution portion of the samples was always less than 0.3% of the salt content and usually less than 0.1%, which was 185

3. Resin emulsion, 4. Metallo-organic,and 5. Asphaltic.

taxes for this purpose so the city usually has to assume the burden of cost. There is less actual benefit to the car owner from this additional expenditure than presumed. Air pollutants, soils and moisture from rain or condensation contribute to corrosion over the whole year; whereas, deicing salts are only used for about three months. Thus, if corrosion is reduced by as much as 50% by the addition of inhibitors to salt, this may represent only a reduction of abou t 12% in the total yearly corrosion. Palmer89 conjectured an extension of vehicle service life of one-half year in ten years at a potential cost to some cities during this period of two million dollars. Although the use of inhibitors is most desirable if it accomplishes a reasonable reduction in corrosion, it appears to fall short of the mark. It becomes apparent that the best approach to a solution of the problem is the protection of the vehicle by the use of protective coatings, sacrificial metal coatings, more resistant materials, or added surface protection, such as the use of rust preventive oils or greases. These types of protection are available for the entire year rather than just a few months during the winter.

The finished product that is applied is a blend of resin and film formers, petroleum solvent, rust inhibitors and insoluble fillers. Inhibitors enhance the protection provided by the barrier effect of the film. Typical inhibitors are metal soaps, fatty acids, phosphonates, sulfonates and carboxylates.1 05 As many as six inhibitors may be used in a single formulation and the content of the inhibitors in the dried film may approach 15% by weight. Fillers are often asbestos, calcium carbonate, bentonite clay or powdered silicate. Rust preventives are being used more extensively for automotive applications because they fill a need that cannot be met always by other methods of protection. Some typical uses are the protection of leaf springs, rear axle spindle housing assemblies, fasteners, sea t springs, crankshafts, engine components and a host of other parts. A recent application has been the protection of metal surfaces under the rear window moldings where moisture tends to accumulate and is not readily dried because of limited air flow. The most extensive application of rust preventives has been for the protection of underbody surfaces and enclosed areas, such as rocker panels. door panels and front end assemblies. Although it is difficult for the car manufacturer to use this method of treatment on an

Rust Preventive Compounds Petroleum-based materials have been used successfully for many years to prevent the corrosion of metal parts in storage. These materials are applied by spraying, dipping, or brushing and the protection provided varies with the composition of the material and the coating thickness. Compounds are frequently referred to in terms of the film that is produced-thick films with greases, thin films with oils and dry films with waxes. Several types of rust preventives are listed by their characteristics and use in the SAE Handbook Supplement 1447a.69 It was only natural that the use of these materials should be extended to the protection of metal surfaces on automobiles. However, the environmental exposure of automobiles is much more severe than that of parts in storage, so rust preventives are required that will retain film stability and provide protection over a broad range of conditions. A desirable material must have good flow characteristics when applied at normal application temperatures, must possess polar or chemical bonding qualities for good adhesion to metal and must be able to seep into cracks. The rust preventive coating must be nonflammable after application, maintain flexibility and adhesion at temperatures below freezing, must not sag at engine compartment temperatures, must resist creep back of corrosion at scratches or be self-healing and must dry to the touch in four hours and become firm and tack free in 24

assembled vehicle because of the drying time involved and the extensive cleaning required after application, the pretreatment of some parts before assembly is being given careful consideration. The method has been used more predominantly by field specialists who treat both new and used cars. Impetus was given to the application of rust proofing compounds by organizations with fleets of vehicles. The military, for example, uses many vehicles in coastal areas or on islands where salt water corrosion is a problem and a rather extensive procedure that often involves the dissassembly of component parts to ensure the coaling of hidden surfaces has been developed. along with specifica tion s to ensure that adeq ua te corrosion preven tive compounds are used. 106 There has been increased interest in the past decade in the application of rust preventives to vehicles to reduce maintenance and extend vehicle life. The Bell Telephone Compani 0 I ,107 ini tiated a test program in the early sixties and a large percentage of its vehicles is now receiving began this treatment. The United States Post Office1ox treating its vehicles in 1964. Several European countries make extensive use of rust preventives for the protection of vehicles. Asanti99 claimed that 70 to 80% of the cars imported in Finland in 1966 were treated wi th a rust preventive oil by the dealer or the owner and Ulfvarson and J ohansson 109 estimated that 70% of all new cars sold in Sweden in 1964 were treated by the ML-Method that was developed in that country.

hours.79 ,1 0 I-I 03 Furthermore, the rust preventive coating must provide protection against salt solutions and acid or alkaline environmental conditions. Selkel 0 I maintained

that the material also should stop corrosion that had already started. Higginsl04 classified petroleum-base rust proofing compounds into five categories:

Much of the published literature on this subject deals with the characteristics and application of materials rather

I. Grease, 2. Wax resin, 186

than results of tests to show effectiveness. This is probably because of the special equipment that is required to apply the materials and the necessity to be familiar with the techniques of application and the structural design of the vehicles. Holes are drilled in closed sections to allow the rust preventive to be sprayed on inner surfaces as well as exterior surfaces. Special spray nozzles are used to ensure complete coverage. Airless spray units appear to give less overspray, although conventional high pressure air units can be used. 103,110 The holes are filled with plastic caps after application of the rust preventive.

surfaces coated and the other half was left uncoated

for

comparison. Results after 18 months' exposure supported the results of the earlier specimen tests. The rust preventive not only protected bare metal but supplemented the protection provided by other coatings. The effectiveness of rust preventives on galvanic couples of metals was checked in the laboratory by exposing steel-galvanized steel and steel-aluminum couples to a wet-dry cycle consisting of five days in salt fog and two days in air at room temperature. Results showed that rust proofing compounds were comparable in effectiveness to a complete spray-applied paint finishing system. The results from the few tests that have been run, along with service experience, indicate that properly inhibited and properly applied rust preventive compounds are a valuable adjunct to the present protective coating system on automobiles. However, the need to apply a rust preventive coating will depend on the severity of the corrosive environment and on whether the economic gain from the additional protection offsets the cost of application.

Accelerated Tests Popular Much of the testing of these products has been limited to the exposure of coated panels to salt fog or to humidity. Muffleyl 0 3 considered the salt fog test to be significant because vehicles are exposed to salt solutions on highways. He tested over 30 different compounds and many of them failed to pass a SOO-hour minimum requirement in salt fog. A number of other requirements were taken into consideration, such as the prevention of undercutting at a scratch and the creepage of material between two metal riveted plates. Waindle79,102 placed a higher requirement on a good material and said that it should pass 2000 hours in salt spray and 60 days in 100% relative humidity at 38 C (100

References 1. L. McKilwin. Harper's Weekly, Harper and Brothers, New York, January 2 (1909). 2. H. R. Wolf. Effect of Antifreeze Solutions on Engine Parts, Report No. 234393, Research Laboratories, General Motors Corp., November, 1926. 3. R. J. Agnew, J. K. Truitt, and W. D. Robertson. Corrosion of Metals in Ethylene Glycol Solutions, Ind. & Eng. Chem., SO, 649 (1958).

F). Ulfvarson and 1ohansson 1 09 used several different approaches to the evaluation of rust prevel1tives. Panels were sprayed three minutes every hour with a S% salt solution in one test and in another they were partially immersed in a 3% salt solution. They also exposed box-shaped specimens that were attached to the underside of freight cars on trains for five months. The cars operated on roads where sodium cWoride was used and abrasives were present. On the basis of rather limited results, it could not be concluded that there was a correlation between laboratory and field test results and the lack of correlation was attributed to the erosive factor of the abrasives in the field test.

4. E. Gehres. An Analysis of Engine Cooling in Modern Passenger Cars, SAE Preprint 660C, National Meeting, Detroit, Mich., March,1963. 5. T. K. Ross. Corrosion and Heat Transfer-A Review, Brit. Corr. J., 2, 131 (1967). 6. J. C. Cessna. Problems in the Use of Corrosion Inhibitors in Automobile Engine Cooling Systems, Interim Report of Committee T-3A, Materials Protection, 3, No. 5, 37 (1964). 7. H. J. Hannigan. Coolant Performance at Higher Temperatures, SAE Preprint 680497, Mid-Year Meeting, Detroit, Mich., May, 1968. 8. M. A. Boehmer and J. W. Compton. Effects of Water Quality in Auto Cooling System Corrosion in Glycol Antifreeze Solutions, Soap and Chemical Spec., 35, No. 6, 93 and No. 7, 85 (1959). 9. N. S. Dempster. Corrosion of Aluminum Alloy in GlycolWater Cooling System, Corrosion, IS, 395t (1959). 10. L. C. Rowe and M. S. Walker. Effect of Mineral Impurities in Water on the Corrosion of Aluminum and Steel, Corrosion, 17, 353t (1961). 11. D. H. Green, J. C. Kratzer, and P. I. Emch. Requirements of an Engine Antifreeze and Methods of Evaluation, ASTM Bulletin 154, 57 (1948). 12. A. D. Mercer and F. Wormwell. Research and Experience with Sodium Benzoate and Sodium Nitrite Mixtures as Corrosion Inhibitors in Engine Coolants, SCI Monograph No. 4, The Protection of Motor Vehicles from Corrosion. Soc. Chem. Ind., Belgrave Square, London, p. 69 (1958). 13. H. H. Collins and R. I. Higgins. The Corrosion of Road Vehicle Engines by Antifreeze Solutions, Corr. Prel'. and COlltr., 7, No. 2, 36 and No. 3,41 (1960). 14. Maintenance of Automotive Engine Cooling Systems. Information Report HS40, Society of Automotive Engineers, New York, N. Y. (1965). 15. Selection and Use of Engine Coolants. ASTM Special Technical Publication No. 120-A, ASTM, Phila .• Pa.• Sept.. 1963.

Higgins104 lists ten different test procedures in the appendix of a publication. These tests cover fluidity of the compound, resistance to solvent wash, creep capability, adhesion, abrasion resistance and corrosion protection. About 12 different compounds were tested in the Cleveland area where both road salt and cinders were used during the winter months. Box-shaped specimens of cold-rolled steel, with one end open, were coated and attached to the undersides of vehicles. The test was run for 18 months, ~vering two winter seasons. A comparison of ratings after vehicle exposure with those after 1000 hours of salt fog, which was considered to be a minimum requirement, showed the relative order of material performance in the two tests to be about the same. Only about one-third of the materials were considered satisfactory. It was concluded that a material based on a metalloorganic compound combined with a phosphate resin would provide effective protection. Higgins111 also reported the results of full-scale automotive tests in which half of the vehicles had underbody 187

16. M. S. Walker and W. D. France, Jr. New Method Developed for Monitoring Automotive Cooling System Corrosion, Materials Protection, 8, No. 9,47 (1969). 17. 1. C. Rowe. Methods of Testing Automotive Engine Coolant for Corrosion Inhibition, Research Publication GMR-972, Research Laboratories, General Motors Corp., May, 1970; and Chapter in Handbook on Corrosion Testing and Evaluation, W. H. Ailor, John WHey & Sons, Inc., New York, N. Y. (1971). 18. Corrosion Test for Engine Antifreezes in Glassware (D 1384), 1972 Book of ASTM Standards, Part 22. 19. Simulated Service Corrosion Testing of Engine Antifreezes (D 2570),1972 '/Jook of ASTM Standards, Part 22. 20. R. J. Foley, E. Beynon, and A. C. Bato. Service Performance of Factory Installed Antifreezes with Extended Use Recommendations, SAE Preprint 826B, National Meeting, Detroit, Mich., March, 1964. 21. Testing Engine Antifreezes by Engine Dynamometer. (D 2758),1972 Book of ASTM Standards, Part 22. 22. H. J. Hannigan and D. H. Hultgren. Engine Dynamometer Evaluation of Automotive Antifreeze, SAE Preprint 660A, National Meeting, Detroit, Mich., March, 1963. 23. Testing Engine Coolants in Vehicle Service (D 2847), 1972 Book of ASTM Standards, Part 22. 24. Cavitation-Erosion Corrosion Characteristics of Aluminum Automotive Water Pumps with Coolants (D 2809), 1972 Book of ASTM Standards, Part 22. 25. Anon. Soap and Chemical Spec., 46, No. 6,110 (1970). 26. J. E. Miller. Methoxyl Propanol Automotive Antifreeze, Soap and Chemical Spec., 43, No. 10,69 (1967). 27. Automotive Antifreezes. NBS Circular 576, United States Dept. of Commerce, July 26, 1956. 28. J. D. Jackson, P. D. Miller, F. W. Fink, and W. K. Boyd. Corrosion of Materials by Ethylene Glycol-Water, DMIC Report 216, Battelle Memorial Institute, Columbus, Ohio, 1965. 29. E. Beynon. Antifreezes and Automotive Chemical Specialities, Encyclopedia of Industrial Chemical Analysis, 6, Edited by F. D. Snell and C. 1. Hilton, Interscience Publishers, a division of John Wiley & Sons, Inc., New York, N. Y., pp. 9-17, 351, 357, and 358 (1968). 30. J. G. N. Thomas and T. J. Nurse. The Anodic Passivation of Iron in Solutions of Inhibitive Ions, Brit. Corr. J., 2, No. 1, 13 (1967).

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31. D. M. Brasher. Stability of the Oxide Film on Metals in Relation to Inhibition of Corrosion, Part n. Dual Role of the Anion on the Inhibition of the Corrosion of Mild Steel, Brit. Corr. J., 4, No. 5, 122 (1969). 32. M. Levy. Corrosion Inhibitors in Automotive Coolant Media, Ind. & Eng. Chem., 50,657 (1958). 33. B. J. Northan and D. B. Boies. Inhibition of Corrosion of Aluminum in Ethylene Glycol-Water Systems, Proc. NACE 24th Conference, p. 287, Houston, Texas (1968). 34. J. C. Cessna. Electrical Resistance Method for Studying Corrosion Inhibitors in Automotive Antifreezes, Corrosion, 15, 607t (1959). 35. 1. C. Rowe. An Evaluation of Inhibitors for Corrosion Prevention in an Engine Cooling System, Corrosion, 13, 750t (1957). 36. M. Darrin. Chromate Corrosion Inhibitors in Bimetallic Systems,lnd. & Eng. Chem., 37,741 (1945). 37. M. Darrin. Chromate Corrosion Control for Engine-Jacket Water, Corrosion and Materials Protection, 4, No. 3,6 (1947). 38. G. E. Best and E. A. Roche. Chromate for Corrosion Control in Methanol Antifreeze, Corrosion, 10, No. 7, 217 (1954).

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66. R. Wall. The Effect of Vibration on Aqueous Corrosion, Symposium on Cavitation Corrosion and Its Prevention in Diesel Engines, British Rail Chemical Res. Div., London (1965). 67. Cavitation Corrosion Characteristics of Long-Life Coolant. Method MB BL3-!, Manufacturing Staff, Ford Motor Co., Dearborn, Mich., September, 1964. 68. Automotive Engine Coolant. Engineering Standard GM 1899M, Appendix (Water Pump Cavitation-Erosion Test), General Motors Corp., Warren, Mich., July, 1965. 69. Prevention of Corrosion of Metals. SAE Handbook Supplement J447A, Society of Automotive Engineers, New York, N. Y. (1964). 70. Snow and Ice Control with Chemicals and Abrasives, Bulletin 152, Highway Research Board, Washington, D. C., 1960. 71. Survey of Salt, Calcium Chloride and Abrasive Use in the United States and in Canada for 1969-70, Salt Institute, Alexandria, Va 1971. 72. F. O. Wood. The Role of Deicing Salts in the Total Environment of the Automobile, Proc. 26th Annual NACE Conference, p. 106, Philadelphia, Pa. (1970). 73. R. S. Weigand and R. E. Schrock. Analysis and Control of Automobile Body Corrosion, Proc. NACE 24th Cont., p. 21, NACE, Houston, Texas (1968). 74. R. S1. 1. Preston and B. Sanyal. Atmospheric Corrosion by Nuclei,J. Appl. Chem., 6,26 (1956). 75. Motor Vehicle Corrosion and Influence of De-icing Chemicals, Road Research Group Report, Organization for Economic Co-operation and Development, Paris, France 1969. 76. R. J. Wirshing. Effect of Deicing Salts on the Corrosion of Automobiles, Bulletin ISO, Highway Research Board, Washington, D. C., p. 14 (1957).

91. Anon. Road Test of Cargill Salt with Carguard Corrosion Inhibitor, 1964-65, Research Dept., Cargill, Inc., Davenport, Iowa, 1965. 92. J. D. Palmer. Effect of an Inhibitor on the Corrosion of Auto

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66. R. Wall. The Effect of Vibration on Aqueous Corrosion, Symposium on Cavitation Corrosion and Its Prevention in Diesel Engines, British Rail Chemical Res. Div., London (1965). 67. Cavitation Corrosion Characteristics of Long-Life Coolant. Method MB BL3-1, Manufacturing Staff, Ford Motor Co., Dearborn, Mich., September, 1964. 68. Automotive Engine Coolant. Engineering Standard GM 1899M, Appendix (Water Pump Cavitation-Erosion Test), General Motors Corp., Warren, Mich., July, 1965. 69. Prevention of Corrosion of Metals. SAE Handbook Supplement J447A, Society of Automotive Engineers, New York, N. Y. (1964). 70. Snow and Ice Control with Chemicals and Abrasives, Bulletin 152, Highway Research Board, Washington, D. C., 1960. 71. Survey of Salt, Calcium Chloride and Abrasive Use in the United States and in Canada for 1969-70, Salt Institute, Alexandria, Va 1971. 72. F. O. Wood. The Role of Deicing Salts in the Total Environment of the Automobile, Proc. 26th Annual NA CE Conference, p. 106, Philadelphia, Pa. (1970). 73. R. S. Weigand and R. E. Schrock. Analysis and Control of Automobile Body Corrosion, Proc. NACE 24th Cont, p. 21, NACE, Houston, Texas (1968). 74. R. St. 1. Preston and B. Sanyal. Atmospheric Corrosion by Nuclei, J. Appl. Chem., 6, 26 (1956). 75. Motor Vehicle Corrosion and Influence of De-icing Chemicals, Road Research Group Report, Organization for Economic Co-operation and Development, Paris, France 1969. 76. R. J. Wirshing. Effect of Deicing Salts on the Corrosion of Automobiles, Bulletin 150, Highway Research Board, Washington, D. C., p. 14 (1957).

91. Anon. Road Test of Cargill Salt with Carguard Corrosion Inhibitor, 1964-65, Research Dept., Cargill, Inc., Davenport, Iowa, 1965. 92. J. D. Palmer. Effect of an Inhibitor on the Corrosion of Auto

93.

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95.

96. 97.

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77. The Use of Salt for Deicing Streets. A Report by the Civic Affairs Committee, p. 8, The Engineering Society of Detroit (1956). 78. D. B. Boies and S. Bortz. Economical and Effective Deicing Agents for Use on Highway Structures, Report 19, National Co-Operative Highway Research Program, Highway Research Board (1965). 79. R. F. Waindle. Automobile Corrosion Problems-Causes and Prevention, Materials Protection, 6, No. 12, 30 (1967).

102.

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105. 106.

84. Meeting of NACE Technical Unit Committee T-4D, Corrosion by Deicing Salts, Chicago, Ill., March 19, 1959. 85. C. E. MacKinnon. Salt as a Factor in Automotive Corrosion, Presented at a meeting of the Salt Institute in February, 1967.

107.

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109.

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89. J. D. Palmer. Inhibitors Unjustified for Controlling Automobile Corrosion from Deicing Salts, Materials Protection, 19, No. 8, 31 (1963). 90. Anon. Treated Salt Removes Snow While Reducing Auto Corrosion, C&E News, 43, No. 10, 70 (1965).

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111.

189

Body Steel by Deicing Salts, Report No. M-6440, Ontario Research Foundation, January 21, 1965. R. A. Jameston and D. T. Ireland. Field Test Evaluation of an Inhibited Deicing Salt, SAE Preprint 680441, Mid-Year Meeting, Detroit, Mich., May, 1968. D. R. Zaremski. Inhibited Deicing Salt and Stainless Steel Automotive Trim, SAE Preprint 680442, Mid-Year Meeting, Detroit, Mich., May, 1968. H. L. Black and L. W. Lherbier. A Statistical Evaluation of Atmospheric, In-Service and Accelerated Corrosion of Stainless Steel Automotive Trim Materials, Paper No. 22, 70th Annual ASTM Meeting, Boston, Mass., 1967. R. West. The Toxicology of Carguard. Report No. PT66-64, Rosner-Hixson Laboratory, Chicago, Ill. (1966). H. J. Fromm. Corrosion of Autobody Steel and the Effect of Inhibited Deicing Salt, Proc. NACE 24th Cont, p. 50, NACE, Houston, Texas (1968). R. R. Bishop and D. E. Steed. Corrosion Inhibitors as Additives to Highway Deicing Salts-Laboratory Tests, Proc. Inst. Mech. Engrs., 182, Part 3J (1967-68). P. Asanti. Investigation of Motor Car Corrosion in Finland, Proc. Inst. Mech. Engrs., 182, Part 3J (1967-68). J. D. Palmer. The Environment-Its Effect on Inhibition Economics, SAE Preprint 680439, Mid-Year Meeting, Detroit, Mich., May 1968 and Vehicle Corrosion Caused by Deicing Salts-Evaluation of the Effects of Regular vs Inlubited Salt on Motor Vehicles, Special Report No. 34, American Public Works Association, Chicago, Illinois, September, 1970. G. H. Selke. Operation Antirust, SAE Paper 535E, Atlantic City, N. J., June, 1962. R. T. Waindle. Post Assembly Rust Proof'mg-A Systematic Approach to Prevention of Premature Rust Destruction of Automotive Bodies, Proc. 26th Annual NACE Conference, p. 68, NACE, Houston, Texas (1970). H. C. Muffley. Evaluation of Vehicle Corrosion Preventives, Lubrication Engineering, 21, No. 12,506 (1965). W. A. Higgins. Automotive Rustproof'mg Compounds, NLGI Spokesman, 29, No. 12, 381 (1966). Anon. Interest in Car Under coatings Sharpens, C&E News, 40, No. 26,50 (1965). Corrosion Preventive Compound, Cold Application (for Motor Vehicles), Rock Island Arsenal Purchase Description RIAPD-687, September 1965; Corrosion Preventive Compound, Cold-Application (for Motor Vehicles), MIL-C0083933A (MR) 5 October 1970, Adminstrative Wheeled Vehicles Treatment, Painting, Undercoating, Identification Marking, Data Plates and Warranty Notice Standards, MILSTD-1223M, 15 August 1970. Anon. Fleet Vehicles Protected Against Rust by Inhibited Grease Pipeline Coating, Materials Protection, 2, No. 3, 71 (1963). Automotive Vehicle Corrosion Preventive Compound, Solvent Cutback, Cold Application, Post Office Department, Bureau of Facilities, Maintenance Division, POD Specification VB-65-1 Maintenance Bulletin V-5-65, October, 1964. U. Ulfvarson and K. Johansson. Determining a Standardized Procedure for Evaluation of Automotive Rustproof'mg Compounds, Materials Protection, 8, No. 6, 43 (1969). R. R. Tisdall. Application of Corrosion Preventive Compounds to Automotive Underbodies, SAE Paper No. 535G, Atlantic City, N. J., June, 1962. W. A. Higgins. Corrosion Prevention in Automotive Vehicle Bodies, Proc. Inst. Mech. Engrs., 182, Part 3J (1967-68).

Inhibitors in Organic Coatings

NORMAN E. HAMNER*

Introduction

resistance to p\:netration of the environment by creating a devious path limiting movement of corrosives through the coating layer. Because of the manner in which they are used, the so-called "temporary" coatings based on oil or grease will not be covered. They are discussed in another chapter. Many temporary coatings contain inhibitive materials that markedly improve performance of the coatings in aggressive environments.

The main function of an organic coating on a metal surface is to be a barrier between the metal and the external environment. Other characteristics also contribute to the effectiveness with which a coating protects the substrate to which it is applied. Traditional nomenclature applied to paint, sanctioned in some cases by centuries of use, implies that additions to the vehicle are added for cosmetic reasons, as "pigments", to confer col or. While the exact definition of the word "pigment" does not necessarily cover properties other than color, it has long been recognized that the word covers other functions, including inhibition. It is obvious now and it has been a major factor in coatings technology from the earliest times, that inhibitive values are an important reason for adding "pigments" and that inhibition may, in many cases, be the only reason for so doing. The tendency to add substances to coatings for the purpose of inhibiting corrosion has accelerated so much in recent years that the word "inhibitor" when related to coatings no longer is challenged as improper. Inhibitors are usually incorporated into primers. Although it may not be technically correct to do so, this discussion of inhibitive properties of coatings will not cover additives which, because of their gross electrochemical activity protect the substrate by altering its electrical relationship to the environment. It is acknowledged that the protection conferred by a chemical inhibitor has many similarities to barriers produced by electrically reactive materials. The function of anodic coatings is more intimately related to cathodic protection technology than it is to coatings technology. Accordingly, studies of the function of such anodic additions as zinc and its compounds can be understood better in the context of cathodic protection theory and practice than they can in the context of coatings barrier technology. Likewise, additions of relatively inert substances, including glass, aluminum, stainless steel, mica, sand and the like will not be considered here. It is usually conceded that these materials are added to improve the barrier effect or to increase thickness such as might be required when a coating is subjected to abrasion. Inert metal often is added to confer reflectivity, to improve heat or radiation resistance, resist the influence of actinic rays or to improve

Function of Inhibitors in Coatings There are two bonding modes between inhibitive substances and substrates. These are usually described as chemisorption and physical adsorbtion. The distinctions between these two bonding modes have been clarified and some of the scientific aspects of the bonding forces described by Burns and Bradley,1 among others. While it is not essential that all the details about bonding forces be understood, it is important to know that coatings often may succeed or fail in proportion to their ability to bond themselves to the substrate to which they are applied. There is a singular relationship between the molecular structure of coatings vehicles and their additives and pigments. Henry F. Payne2 points out that inhibitive pigments usually are finely divided solids added to oils or resins, volatile solvents and driers or catalysts. He says further that the association forces between molecules of polar compounds are always stronger than those between non-polar compounds and that the basic properties of coating molecules determine their good or bad performance. When molecules of a coating contain ester groups, for example, limited resistance to alkalies can be expected and soaps may be formed. Soap formation may indicate deterioration of a coating's ability to resist the environment. While there is no consensus, the mechanism proposed for some polar compounds is like that advanced for sodium, barium, or strontium oleates and petroleum sulfonates. It is postulated that these compounds wet metal surfaces, preferentially displacing water already there and orient themselves so their hydrophobic ends face the environment and thus repel moisture. 3 Furthermore, apparent anomalies exist, such as the superior passivating ability of coatings with 5 to 15% zinc chromate as compared to those with greater percentages.4 This illustrates the complexity of the functions among

.Staff, National Association of Corrosion Engineers, Houston, Tx.

190

components of coatings and explains in part why many discoveries in new coatings seem to be empirical rather than the result of scientific investigation. It is convenient, if not entirely accurate from a scientific point of view, to consider also that an inhibitor must have another property if it is to function properly. This property involves its capacity to reject, or hold away from the substrate surface, ions or other substances that may attack the substrate . Thus, effective inhibitors in coatings, like inhibitors elsewhere, must have the ability to bond themselves to a substrate while at the same time rejecting, repelling or neu tralizing corrosives which otherwise would attack the coating-substrate interface.

> 2 en •... .J:: ~ J: ::l '5 •0 0'"...l:::l 0 5e'E '0 ?fl Ql Ql Ql

E

2

2

6

10

18 20

14

Months

Anodic and Cathodic Inhibitors

FIGURE 1 - Protective properties of coatings at 100% humidity and 20 C and in unheated storerooms (time to appearance of the first corrosion centers) 1-acrylic latex without inhibitor; 2-acrylic latex with inhibitor.S

Both anodic and cathodic inhibitors may be used in coatings. These designations refer to the property whereby inhibitors preferentially affect either anodic or cathodic sites in a corroding system. Some inhibitors affect sites of both types. If anodic inhibitors are not present in sufficient quantity to cover anodic areas adequately, they may accelerate rather than reduce corrosion. Burns and Bradley· point out that inorganic (anodic) inhibitors rarely achieve more than 80 to 95% protection. It is also important to note that the beneficial effect of red lead (Pb3 04) is assumed to be the result of its combination with the primary corrosion products of iron.s In additon, red lead deters formation oflocal cells and thus helps preserve the physical properties of a coating. Another view of the mechanism of protection by lead has been advanced by Mayne6, who, while discussing the inhibitive properties of red lead, zinc oxide and calcium carbonate pointed out that investigations have shown that these additives form soaps with linseed oil. In the presence of water and oxygen, they break down into "a range of inhibitive products, the most important being the salts of azelaic acid."

'-PmV -600 1

2

-100

o 1.0 +100

2.0 Hours 3.0

3

FIGURE 2 - Steel potential vs coating corrosion in 0.001 N Na2S04 solution. 1-Uncoated metal; 2-Metal coated with acrylic varnish without inhibitor; 3-Metal coated with acrylic varnish with inhibitor. S

Lead azelate inhibits at 20 to 60 ppm and it has been suggested that small quantities of metallic lead are deposited on the surface of the steel and that at these points, "cathodic reduction of oxygen can proceed more readily. Consequently, the potential of the specimen is maintained in the region of ferric oxide stability and the air-formed film is reinforced and thickened by material of similar composition."

coatings based on acrylic latexes, a marked improvement in protection from inhibitors was noted.s As shown in Figure 1, the protection lasted more than 10 times longer with an inhibitor than without. The potential of a metal under an inhibited coating may be displaced as much as 0.5 v positive, as shown in Figure 2. This potential displacement accounts in large part for the benefits conferred by inhibitors in coatings.

Calcium plumbate, according to Mayne6 inhibits by raising pH into the alkaline range where steel tends not to corrode and creates calcium soaps when ground with linseed oil. Lead sub oxide consists of a core of metallic lead

Types and Attributes of Inhibitors Commonly Found in Coatings

surrounded by a layer of lead monoxide (PbO) or litharge. In oleoresinous coatings and in other vapor permeable vehicles, the lead changes into lead soaps at the metal surface, where by adsorption or reaction it blocks the anode areas.? From 4 to 18 Ib of pigment per gallon is required. On rusted steel the linseed oil-lead sub oxide primer is said to penetrate thin rust and into crevices. In an evaluation of the performance of temporary

While it is true that a complex relationship exists between the vehicle in which an inhibitor is used and the effectiveness of the inhibitor in reducing corrosion, this discussion will be concerned more with the inhibitors themselves and witll practical aspects of their use. Figure 3 shows some of tlle differences observed anlOng various vehicles with and without inhibitive pigmentation. 191

TABLE 1 - Some Inhibitors Used in Protective Coatings 2

Compounds

3

Calcium Carbonate MolYbdate Plumbate

4

Chromium Barium potassium chromate Basic lead silicochromate ... Cadmium chromate Oxide ..... Strontium chromate Zinc chromate

6

8

Sources of Information*

.5,(1),(4) .5

.1,5

.5,(1),(4)

.10 .1,12 ,1

.12,(1 ),(4) .1,10,12

Lead

o

6

12

18

Basic silicoplumbate . Blue ..... Calcium plumbate Carbonate (white)

24

Months

FIGURE 3 - Protective properties of various coatings at 100% humidity at 18 to 25 C. 1-Natural drying oil; 2-Natural drying oil with inhibitor; 3-Alkyd varnish; 4-Alkyd varnish with inhibitor; 5-Alkyd styrene varnish; 6-Alkyd-styrene varnish with inhibitor; 7-Alkyd-nitrocellulose varnish; 8-Alkyd-nitrocellulose varnish withinhibitor.8

Numbers of Inhibitors

The number of materials that may be added to a coatings formulation is too numerous to be itemized. Many manuals give detailed information on formulations so it would be redundant to duplicate here that has been done elsewhere. Among publications with detailed information is the book edited by C. R. Martens which covers the technology of paint and siillilar materials.9 Insofar as coatings for steel are concerned, it is interesting to look at some of the pigments contained in the formulations recommended for steel by the Steel Structures Painting Council.! 0 These inhibitors and those from other organizations and publications are listed in Table 1. Six of the 21 compounds listed in Table I contain chromium. Some materials listed in Table 1, while presumably somewhat effective as inhibitors, are used mainly as fillers or extenders. Zinc and calcium molybdates are said to be nontoxic in a variety of vehicles and effective in concentrations as low as 3% by volume.

Inhibitors

in Coatings for Nonferrous

.5,(1),(4) .1

Red

.10

Titanate

.1

Zinc Chromate MolYbdate Oxide .. Tetroxychromate

.5,( 1),(4)

Miscellaneous Antimony oxide Carbon black Chalk .. China clay Iron oxide Strontium chromate Talcum Titanium dioxide

Used

.1,10 .1

.10,12

.10 .5,(1),(4)

.13 .(11 .(11

.14 .10 .12,( 1),(4) .( 1)

.10

*Superior numbers refer to references at end of article. Numbers in parenthesis refer to references below: (l)W. Von Fischer and E. G. Bobalek. Organic Protective Coatings, Reinhold, New York, 1953. (2)J. RuC. Pigments Containing Chromates or Phosphate, Werkstoffe und Korrosion, 20, 861-869 (1969). (3)Protective Coatings Containing Molybdates. Climax Molybdenum Co., p 4,1969. (4)M. Rajamaki. Calcium Plumbate as a Protective Pigment Against Corrosion and a Covering Pigment for Galvanized Surfaces, Kern. teoU., 25, No. 2,170-181 (1968). In Finnish. Corrosion Abstracts, p 369-355, September, 1960.

Metals

The exposed area of steel and iron alloys far exceeds that of all other structural metals. Because nonferrous

of these metals exposed in industry are relatively small compared to those of steel or aluminum. Most of the formulations for use on aluminum include

metals exposed to the atmosphere often require no coating, the instances in which inhibitors are used to protect them are less common than they are for ferrous metals. The structural nonferrous alloy most often coated is aluminum. Magnesium and zinc also are frequently coated but cadmium, lead, tin, and copper seldom require coating and areas

chromates, which are widely incorporated in both standardized and empirical formulations. Burns and Bradley! cite the diversity of chromate compounds which are available in combination with both acids and alkalis and which in 192

.,

· addition may contain silicates, phosphates or fluorides. These coatings are believed to form compounds consisting of various aluminum oxides by reaction with the aluminum surface layer. Surfaces that have been treated with a chromate formulation usually are readily topcoated with other materials. Magnesium and cadmium are not top coated as often as is aluminum. The inhibitive properties of the chromate are valuable under the topcoat. Durability is a function of thickness and to some extent of the composition of the base metal.

in the tests. Tests by the same agency revealed that primers containing arsenic can be substituted effectively for those containing antimony. Paint containing finely dispersed metalloids and low solubility compounds such as antimony trioxide can be used in place of plating. Antimony-plated magnesium primed with zinc chro· mate corroded slowly and increased chromate concentration was measured at the metal-coating boundary. Similarly, antimony was superior to both tin and cadmium when plated on magnesium and tested by salt spray.

Other Inhibitive Practices Related to Coatings Practical Applications of Chromates

Among numerous other practices designed to improve the performance of coatings but not strictly involving inhibitors are the well known and often used zinc and/or iron phosphate conversion systems which form a base for primers or topcoats. Tannin is also used on the surfaces of freshly shot-abraded shipbuilding steel'4 as a preliminary application in a formulation consisting of 10 to 12%tannin along with ethyl alcohol and phosphoric acid. Soon after the tannin is applied, various synthetic resins (polyvinyl butyral, vinyl copolymer, chlorinated rubber, alkyds, etc.) are applied. After nine months in an industrial and in a semi-industrial atmosphere with high humidity, about 20% of the surfaces so prepared were covered with rust. Samples with tannin and up to 30% iron oxide, performed better, having only 1 to 5% of surfaces rusted. The particular advantage of this coating system is that it neither interferes with welding nor produces toxic fumes when on a welded surface.

Among practical applications of chromates to protect aluminum and reasonably typical of aggressive environments in which it is desirable to protect them are recommendations applicable to naval aircraft." After surfaces of corroded aluminum in aircraft have been cleaned of corrosion products, they can be washed with a solution consisting of 10% by weight chromic acid plus a small amount (about I teaspoonful) of sulfuric acid battery solution to a gallon of water. This liquid should be left on the surface for 15 to 30 minutes after which the surface is flushed with water. After this treatment, topcoating of the resulting surface should be completed as soon as possible. Similarly, a 10% solution of sodium dichromate with 1/2 to I % chromic acid can be applied to corroded aluminum surfaces at 150 F (66 C) and allowed to remain for at least 20 minutes before flushing. Potassium dichromate crystals may be suspended in bags in low spots in the bilges of seaplanes where the chromate leachp.!linto the bilge water."

Effect of Surfactants Certain surfactants, particularly alkyl benzyl dimethylammonium chloride

Zinc, Cadmium and Strontium Chromates Because of problems encountered with chromate compounds used to protect aluminum aircraft components, tests were made with zinc, cadmium and strontium chromates to determine their usefulness in instances when trapped in crevices or pinholes. All three proved effective in the tests. ' 2 This study indicated that chromate-based compounds were effective because they are reduced at the cathodic sites and prevent hydrogen evolution. Evolution of hydrogen was cited by the authors as a reason for disbonding of coatings on aluminum. The usefulness of the inhibited materials was improved by the addition of an anodic inhibitor, such as cadmium phosphate-chromate. Alizarin, among other materials that form insoluble aluminum compounds was found to be beneficial. 1 2 Table 2 (Table 6 of Reference 12) lists some of the results achieved with inhibitors added to epoxies on aluminum exposed in accelerated screening splash tests. More information on inhibition of aluminum surfaces can be located in the subject index of this book.

confer marked advantages when incorporated into coal tar, epoxy or polystyrene coatings, natural varnish and phenoloil primers.' 5 This additive in concentrations of 0.25 to 1% not only permitted the modified coatings to retain high hnpact strength, plasticity, hardness and adhesion but also reduced their permeability to moisture. The additive is also credited by the researchers with forming a hydrophobic layer on the steel substrate underneath the coating. This was said to improve inhibition of the surfaces 2 to 4 times more than was achieved with the same formualtion without the surfactant.

Widespread Investigations Made into Inhibitor Functions in Coatings Interest in the inhibitive properties of substances added to coatings has been continuous for many decades and in recent years has attracted the attention of numerous scientific investigators seeking fundamental reasons for good performance. Benefits of understanding the inhibitor

Anomalous Behavior of Magnesium Primers containing antimony oxide applied to carbon steel, aluminum and a magnesium alloy provided coatings which had electrical resistances in sea water of at least one or two megohms per sq in.' 3 There was no visible corrosion 193

TABLE 2 - Effect of Additives to Epoxy Primers on Aluminum in Screening Splash Tests

Good Corrosion Protection and Film Integrity

Poor Film Integrity (continued) Blistered

Alizarin

OH

Pyrocatechol Picrolonic acid

OOH

Iminodiacetic aciddi sodium salt

Isatin

Nitrilotriacetic

0

o

+ _11 H 11_ + Na 0 CCH2NCH2CO Na • ~O

acid N(C H2COO H))

o

2,4-Pentanedione

0

11

11

CH)CCH2CCH)

4-Hydroxybenzophenone

1,3-Diphenyl-l,

o

3-propanedione'

0

;=\11 ~CCH2CV

2,4-Hexanedione Antimony trimethoxide

o 11

11;=\

0

11

CH)CCH2C CH2CH)

4,4,5,5,6,6,6-Heptafluoro1-(2-thienyl)-1,3hexanedione 3,5-Heptanedione

Triphenyl antimony p-Tolylarsonic acid

I-Arginine

Bis (l, 2-diphenylarsine) ethane

O~CH2~

o 11

C ••+)

Tributyl antimony Triphenyl arsine

(6§CH))

CF2CF2CF)

0

11

C H~ H:zCCH2CCH2CH)

I

HN -~H2)) H2NC=NH

Tris (2-hydroxyacetophenono) chromium

0

o

I

-CH-C~~_ NH)+

Sb(C4H~)

(C6H~)As

Zinc acetylacetonate Toluenechromium

tricarbonyl

Soft, nonadherent

Chromium acetylacetonate

Oleoyl sarcosine Zinc cyc10hexanebutyrate

O{} 11

zn;i OC(CHU

Natural sodium

Poor Film Integrity

petroleum sulfonate

Cracked

Sorbitan fatty ester

Maleic acid

Barium salts of complex organic phosphate esters

H'c-c.~OOH HOOC - H

OH

Salicylic acid

Alkylaminoalkyl phosphate

VCOOH

Phosphated fatty alcohols

o-Aminobenzoic acid

Anionic fatty amido phosphate Hexafluoroacetyl

acetone

4,4,4- Trifluoro-l-(2thienyl)-I,3-butanedione

2,6-Dimethyl-3, 5heptanedione

194

~ ~H) ~ CnHnC-N-CH2COH

Summary

function in protective coatings include the possibility of developing useful films by applying scientific principles to formulations, defining more precisely. the relationships between good performance and the environments to which coatings are exposed and more exactly proportioning coatings components to product best results at least expense. Because organic coatings are complex mixtures and compounds, there is an almost infinite number of possible combinations of materials, percentages and compounding practices. To explore all of these by trial and error is imposssibly expensive and time consuming, so scientific analysis of formulations is the rule rather than the exception in companies producting high performance industrial coatings. As pointed out by Rozenfeld et al,l 6 while the idea that inhibitors can confer benefits on organic coatings was logical, it has proved difficult to find additives which will not adversely affect other properties. These researchers discovered that the addition of guanidine chromate to natural or glyptal varnishes protected for over a year at 100% relative humidity the metal substrate to which they were applied while the same coatings without the inhibitor protected the metal under the same conditions for only three or four hours. It is useful also to understand the function of such

Many additives, including the so-called pigments used in modern protective coatings have been found to confer useful properties to coatings. In some cases the additives are specific with respect to environments and applications in which they are used. In contrast to what often has been the case, modern coatings investigations involve the application of inhibitor theory and the use of sophisticated equipment. Many inhibitive materials are listed, together with references to additional information. Results of some recent laboratory investigations into the reactions of inhibitors at the coatings-environment interface are described and some comparisons of performance are made between fomulations that include inhibitors and those that do not.

References 1. R. M. Burns and W. W. Bradley. Protective Coatings for Metals. Third Edition, Reinhold, N. Y. p674. 2. H. F. Payne. Corrosion, 16, 32-38 (1960) June. 3. N. B. PlOmisel and G. S. Mustin. Prevention of CorlOsion in Naval Aircraft. Part 1. Corrosion, 7,339-352 (1951) October. 4. 1. V. Nitsberg, 1. A. Bobina and O. Y. Khenven. Interdependence Between Passivating and Diffuse Properties of Varnish and Painting Coatings. Proc. Third International Congress on Metallic Corrosion, English Edition, Swetz & Zeitlinger, Amsterdam (1969). 5. T. Rossel. Corrosion Protection by Red Lead Priming Coats. Werkstoffe u. Korrosion, 20, 854-860 (1969). 6. J. E. O. Mayne. Protection by Metallic and Nonmetallic Coatings. Proc. 4th Int. Congo on Met. Cor., NACE, 2400 West Loop South, Houston, Texas, 77027, pp. 8-14. 7. H. S. Bennet. Lead Suboxide Pigment is Important Ingredient in Paint. Materials Protection, S, 77-78 (1966) April. 8. I. 1. Rosenfeld, F. I. Rubenstein, and S. V. Yakubovich. Inhibited Polymer Coatings for Corrosion Protection of Metals, Proc. Third International Congress on Metallic Corrosion, English Edition, Swetz & Zeitlinger, Amsterdam, Vol. 3, p. 212 (1969). 9. C. R. Martens. Technology of Paints, Varnishes and Lacquers. Reinhold Book Corp., New York, (1968). 10. Steel Structures Painting Manual. Vol. 2, System s and Specifications, Steel Structures Painting Council, 4400 Fifth Avenue, Pittsburgh, Pennsylvania. 11. Corrosion Control for Aircraft. NAVWEPS-OI-IA-509. p.18,19. (1961) Dec. 12. D. B. Boles, B. J. Northan and W. P. McDonald. Chromate Based Pigments. Proc. NACE 25th Conference, pp. 180-189. NACE, Houston, Texas. 13. S. 1. Chisholm. Some Factors Involved in Corrosion of Light Alloys in Naval Aircraft. Mat. Pro., 3,52-64 (1964) May. 14. S. Cristea and P. Marcu. Contribution to !lIe Study of Anticorrosive Protection of Rolled Sheets Used in Shipbuilding. Pro. Third International Congress for Metallic Corrosion. 1966. Swets & Zeitlinger, Amsterdam, English Edition. NACE. Houston, Texas. 15. R. G. Gadjieva. Influence of Polar Additives on Anticorrosion Properties of Coatings Intended for Protecting a Wet Steel Swface, Proc. Fourth Intemational Congress on Metallic Corrosion. 1972, NACE Houston, Texas, pp 725-730. 16. I. L. Rosenfeld, F. I. Rubenstein. V. P. Persiantseva, and S. V. Yakubovich. Modification of Polymer Coatings by Inhibitors, 2nd European Sl'Inposiul/l on Corrosion Inhibitors, 2, University di Ferrara, Italy, 1965, pp 751-763.

additions to coatings as ferric oxide and various lead soaps since they are still widely used. Both of these are among the earliest known additions to organic vehicles and are more or less protective, the le:ld compounds especially so because of numerous possible combinations between lead and other metals and materials. Lead itself, being relatively inert, oxidizes or hydrolyzes slowly to form protective corrosion products which have some degree of chemical or electrochemical affinity for metal substrates. Useful discoveries are being made constantly about the advantages of inhibitors in coatings. One example of the careful analysis made of reactions is the work of Boies et al12 who pointed out, when discussing the effects of zinc, cadmium and strontium chromate on the corrosion of aluminum by sodium chloride: " ... zinc and cadmium precipitates as the pH is raised but the strontium does not." This observation related to the formation of corrosion products that sealed an intentional pinhole. They also pointed out that all three inhibitors performed well in an epoxy vehicle, indicating that the "primary mechanism of the corrosion inhibition must be the precipitation of salts or oxides of trivalent chromium at the active cathodic site, since the strontium chromate pigment, which does not form a precipitate at alkaline pH, was as effective as the zinc and cadmium pigments which do form such precipitates. " Application of the common theories of inhibitor function as described in an earlier chapter permit researchers to evaluate past experience and anticipate good performance. Expenditure of research funds to explore inhibitor reactions in coatings is justif1ed by the enormous magnitude of industrial investment in coatin~s.

195

Inhibition and Corrosion Control Practices for Boiler Waters

J. H. METCALF* Introduction The prevention of corrosion in boilers and in feedwater and return lines associated with them has been a major problem for several decades. The literature is replete with hundreds of papers on the subject. A few general review articles are listed in References 1 through 13. Reviews on specific topics included package boilers, 1 4 low pressure heating boilers, 1 5 ,I 6 high pressure boilersl 7-2 1 and nuclear power plant experience.2 2,23 Among a large number of articles and reports about inhibitors used in nuclear reactors are those which have

saving of $100,000 has turned into an expense of at least $300,000. As a result of this experience the plant adopted an optimum treatment program. The use of chemical water treatment inhibitors for the modern large to medium size boiler system will range between $2 to $10 per million pounds of steam generated. This figure is considerably higher for smaller plants and may range upward to $15 to $20 or more per million pounds of steam. The higher costs of the smaller plant are usually due to considerably increased treating chemical requirements as a result of using a lower quality feedwater.

appeared from time to time in NACE literature.24-27 A substantially complete summary of nuclear reactor steam cycle inhibition practices and results will be found in the 1971 book by Berry.28 Among the 180 references to the data in this chapter will be found most of the significant information concerning inhibitors in these environments.

Isolating the Boiler Corrosion Problem Corrosion in boiler systems cannot be isolated entirely from a number of other concomitant problems which have a direct effect on the type, amount and location of corrosion and the functioning of the boiler. These problems will be considered along with corrosion problems because they are all inter-related and because the corrosion inhibitors used are usually a part of a "package water treatment" containing additives for the solution of other problems. For simplicity, these additional problems can be identified as scale, sludge and carry over. Another complication arises in that there are a number of locations in a boiler system where various types and amounts of corrosion can occur. In this discussion, the boiler system will be investigated in three generalized locations-preboiler, boiler, and post-boiler-and the problems associated with each will be considered separately.

Economics of Boiler Inhibition There is no short cut to good corrosion control. Temporary gains may produce long term liabilities. The economic loss due to corrosion of boilers may be broken down into two categories: I. Direct replacement and repair costs and 2. Indirect losses due to downtime. The former costs have been estimated to run from $50 to 100 million a year in the United States alone, while the latter are incalculable but are probably more costly than replacement and repair outlays because of lost production. As an example of the high return that may be produced by the dollars invested in a well designed water treatment program, consider the case of a large refinery operating a modern boiler plant on minimum water treatment program at minimum cost. The cost differential between this

Preboiler Corrosion Problems The preboiler system is defined here to include feedwater pumps and lines and auxiliary equipment through which the feedwater is pumped prior to actually reaching the boiler. If not restricted, one could include a vast variety of units in which the makeup water is conditioned but which in themselves are essentially not a part of the boiler system. This definition then includes such equipment as stage heaters and economizers. Using this definition, one finds both corrosion and deposit problems in the preboiler system which can manifest themselves as general corrosion, pitting, or erosioncorrosion. The deposit problem can result from either deposition of suspended solids which should have been

minimum program and an optimum program was approximately $10,000 a year. After 10 years' operation and a "so-called" saving of $100,000 during that period, the plant experienced a serious corrosion problem resulting in an unscheduled outage of a number of critical units in the boiler plant. It has been estimated that this unscheduled outage cost this refinery a minimum of $400,000 in lost production. Some estimates place lost production costs as high as $1,000,000. Thus, it can be seen that this supposed

-Betz Laboratories, Trevose, Pa.

196

removed earlier in the clarifier unit or else it may be caused by formation of adherent calcium, magnesium or iron scales.

The other major source-dissolved solids-is common to practically all aqueous systems and will result in the formation of calcium, magnesium or iron scales. Tightly adherent calcium carbonate or phosphate, magnesium hydroxide or silicate or deposits of iron compounds are laid down on the metal surface, impede water flow, interfere with heat transfer and set the stage for localized pitting. Deposit composition varies widely and is a function of the water constituents and temperature. Deposits of calcium carbonate result when the solubility of that salt is exceeded, and, as with magnesium salts, the solubility of scale-forming calcium salts decreases with increased temperature. Thus, if calcium is not reduced to a sufficiently low level in the external treatment program, calcium deposits may be encountered. The presence of excess alkalinity in the water also contributes to carbonate scale formation.

Corrosion Effects Corrosion can attack iron, copper or nickel. General corrosion or pitting may occur for conventional reasons, e.g., dissolved oxygen, low pH, presence of deposits, stagnant areas, stress in the metals, defects in metal composition or surface conditions. Dissolved oxygen often will cause pitting attack when coupled with certain other conditions such as deposits on the metal surfaces or metal defects. The oxygen will oxidize ferrous hydroxide fIlm to magnetite (Fe3 04) or to hydrated ferric oxide. This oxidation will occur at a finite distance from the metal, allowing more iron to dissolve at the surface under this somewhat porous corrosion product. Acidic pH values will lead to general corrosion. The other factors will generally favor localized attack. Cavitation-corrosion can be en-

Magnesium hydroxide formation can occur for the same basic reasons-Le., an excess of magnesium with respect to temperature and alkalinity. Various iron compounds, such as oxides, phosphates or carbonates can result from either too much iron in the makeup water or else result from incorporation of corrosion products in the deposits. Phosphate deposits present a real anomaly. On one hand, polyphosphates are deliberately added (as will be shown later) to prevent adherent deposits and on the other hand, their reversion product, orthophosphate, can cause undesirable deposits. For this reason, temperature and pH conditions which accelerate reversion of polyphosphates must be considered carefully. Green30 discusses these factors in some detail.

countered in the pumps or at other locations where turbulent or high velocity flow may OCCUr.29Stage heaters and economizers are designed to increase the feedwater temperature which will increase the operating efficiency of the entire system and, as the temperature is increased, susceptibility to corrosion is greatly increased also. The composition of water going through feed lines may vary from distilled or demineralized water to softened water or tap water with either acidic or alkaline pH values. Temperatures can vary from ambient to close to boiler temperatures. Contaminants can include corrosion products, dissolved gases or oil. Furthermore, there is greater emphasis on water reuse and because this trend is expected to continue, it is significant to the corrosion engineer. He must become skilled in coping with the myriad process contaminants that may present a greater corrosion potential than the "fresh", distilled or softened water.

Economizers can present additional deposit problems. These units are designed to take boiler stack gases at about 900 F (480 C) and reduce them to temperatures approaching the dew point. In most cases, temperatures are in the range of 280 to 400 F (138 to 204 C). Since relatively low temperature gases are involved, it is necessary to design the economizer with a relatively large heating surface and this usually results in low feedwater flow rates in the units. The low rate of flow combined with the increase in feedwater

Sources of Deposits There are two major sources of deposits in the preboiler system. These are identified as (1) suspended or (2) dissolved. Suspended solids are the mud or silt commonly found in surface water such as that from lakes or streams. These suspended solids are generally removed from the water by the clarification equipment before it enters the preboiler system. However, improper operation of such equipment may result in suspended solids entering the system. The standard coagulation process may employ lime, which removes some of the hardness and changes the alkalinity balance of the water. Additionally, suspended turbidity, such as clay particles, is removed from the system. Additional coagulants, such as high molecular weight polymeric materials are frequently used, as are alum, iron salts or sodium aluminate. Frequently, residence time in the clarifiers is not sufficient or the fIlters do not

temperature-sometimes approaching boiler water temperature-can lead to severe deposition problems.

Boiler Water Corrosion There has probably been more literature written about and more man hours expended on the solution of boilerwater problems than on any other single water-treatment area. The problem is very significant historically. One phenomenon, embrittlement, was the subject of an excellent treatise by Straub31 in 1930. The growth in variety and pressure ranges of boilers is such that new problems arise as rapidly as old ones are solved. The present discussion makes no effort to treat specific boiler systems in detail, but instead, it concentrates on the general problems of deposits, carryover and corrosion, which are common to most or all systems.

function properly allowing fine floc particles to be carried through to the preboiler system where some grow, settle out there and cover the lines with deposits. The particles that do not settle out in the lines go to the boiler system and cause trouble there.

Deposits in Boilers Deposits in boilers can be considered in two major categories: Sludge and scale. The usual way to tell the 197

'I'

difference between them is by the nature of their adherence. Scale is commonly thought of as being tightly adherent to the metal while sludge may be dispersed in the boiler water, can be spread on the metal surface from which it is easily removable or else it can possibly serve as a binding agent for scale. Sludge is often created deliberately. For example, orthophosphate is added to boilers as an "internal treatment" with the objective of precipitating all the calcium and magnesium in the form of easily removable sludge. An example of sludges which are not desirable, on the other hand, is given by Andrews,3' who found that some failures in steam locomotive boilers in Ontario were caused by

bicarbonate, driving off carbon dioxide and leaving insoluble calcium carbonate behind. While calcium sulfate is readily soluble at room temperatures, its solubility drops off sharply to about 84 ppm at 360 F (182 C).37 Calcium silicate will form a very adherent glassy scale which has high heat insulating properties. Magnesium hydroxide is formed between 350 and 800 F (177 and 427 C) and has strong insulating properties. In high-pressure boilers, iron compounds are prevalent29 and complex silicon compounds are frequently found with the "hardness" (calcium and magnesium) compounds. It is difficult to arbitrarily assign specific compounds to scale or sludge, because many of them may deposit in either form, depending on operating conditions. For example, Clarke and Hopkins33 point out that silica may enter the boiler in as particulate matter and then deposit as sand sludge or it may enter as soluble silicate and deposit as silicate scale.

organic compounds, such as terpenes, which resulted from contamination of feedwater during passage through areas planted with conifers. Oil contamination of feedwater causes a sludge which adheres to the boiler walls and is difficult to remove. The formation of sludge balls can be encountered when the binder is a corrosion inhibitor, a paint residue, a fuel oil or a lubricant.32 These sludge balls can become very large under some turbulent conditions.

A study of scale formation in boilers and adhesive properties of scale leads to many interesting observations. Scale forms directly in place on heated metal surfaces and usually consists of columnar crystals33 growing at right angles to the surface, whereas sludge lacks crystallinity. Analcite, magnetite and magnesium phosphate deposits are among the densest deposits38 and show the greatest reduction in heat transfer. Samilov and Smirnov39 show

An interesting study has recently been reported33 of the corrosion effects of a sludge accumulation in various tubing alloys used in pressurized water nuclear power plants. Under the specific test conditions, severe attack resulted on carbon steel and even on Monel.

that there appears to be a critical temperature of about 470 F (243 C) where calcium hydroxide is converted to calcium oxide regardless of pressure. At this temperature, the amount of calcium which is carried away in generated steam drops markedly in accordance with the creation of its new state. Gerke and Tebenikhin40 studied scale formation on

Analyses of the components of sludges vary widely depending upon the particular system involved.' 9,33-35 An excellent discussion of this subject is in the Symposium on Boiler Water Chemistry ,10 wherein it is shown that almost any feedwater component or its contaminants can be found in the sludge in ratios varying according to peculiarities of the system involved. Zenekevich and Karasik35 found that chemical analyses of a large number of sludges in boilers at 185 atmospheres indicated that they were mixtures of crystalline hemitite, magnetite, cupric oxide and phosphorite. The composition of deposits taken from different sections of the boiler were similar, which indicated that they were all formed under identical thermodynamic conditions. Deev et al3 6 found that calcium phosphates and serpentine are sludge formers, although phosphorite, hemitite, magnetite and metallic copper also might be present. Clarke and Hopkins33 give detailed analyses of various sludges, which clearly related sludge compositions to the peculiarities of the particular systems.

b oiler

plate

samples

in

solutions

of

Ca(HC03

TABLE 1 - Crystalline Scale Constituents Identified by X-ray Diffraction Name

Complex scales are found frequently, particularly at high operating pressures now commonly encountered. A chemical analysis of these scales will only identify the chemical composition so, for positive identification of the crystalline nature of constituents, X-ray diffraction must bp employed. Table 1 shows scale constituents of deposits that have been i4entified by X-ray diffraction.2 Scales in low-pressure boilers commonly consist primarily of very adherent deposits of calcium carbonate, sulfate or silicate; magnesium hydroxide or analcite (sodium aluminosilicate). Calcium carbonate generally is formed when heat in the boiler decomposes the soluble calcium 198

Formula

Acmite Analcite Anhydrite Aragonite Brucite

Na20 . F~ 03 • 4Si02 Na20' AI203 . 4Si02 • 2H20 CaS04 CaC03 MgIOH)2

Calcite Cancrinite Hematite Hydroxyapatite Magnetite

CaC03 4Na20' CaO' 4AI203 . 2C02 • 9Si02 . 3H20 Fe203 Cal010Hh1P04)6 Fe304

Noselite Pectolite Quartz Serpentine Thenardite

4Na20 . 3AI203 . 6Si02 • S04 Na20' 4CaO' 6Si02 . H20 Si02 3MgO' 2Si02 • 2H20 Na2S04

Wallastonite Xonotlite

CaSi03 5CaO' 5Si02 . H20

)2 ,

-

TABLE 2 - Steam Purity29

Mg(HC03)2, and CaS04' They found that scale formed preferentially on roughened surfaces, that it varied according to the material of2001 composition 301-450 601-750 451-600 1501-2000 1001-1500 751-900 901-1000 Pressure, psi the substrate and that and higher of it was related directly to 0-300 the potential of the metal. More scale formed on zinc and aluminum than on boiler plate, while less formed on nickel, copper, brass and glass. Peters and Enge1l41 were able to relate scale adhesion on steel to scale thickness, steel composition and the oxidation temperature.

Operating Boiler 300 400 Solids 150 100 10 53500 500 Total ppm 20020 30060 250 600 250 150 100 40 3000 2500 2000 1500 Solids 750 700 1000 500 1250 Alkalinity Suspended

Problems From Carryover Carry over from boilers can be defined as the presence of water in the steam leaving the boiler. This water contains solids which cause deposit and corrosion problems in the post boiler system, one of the more serious of which is the rapid build-up of silica deposits on turbine blades. The silica concentrations are so critical that Kot42,4 3 states that saturated steam is not safe for turbine vanes unless it

in boilers of 7 ppm or less than 1% of the suspended solids. Tatarinov46 showed that at constant loading of a boiler the height of the foam rises with the salt content of the boiler water. The nature of the salt is important: Na2C03 has a greater effect than NaCl or Na2 S04. Villar47 showed that foam can be caused by solid carbonates which are present due to evaporation of feedwater or dislodged incrustants. Styrikovich48 presented a detailed mathematical analysis of contamination of saturated vapor by impurities which are present in the boiler water in high-pressure boilers due to both mechanical carry over and steam solubility. He showed that stable deposits formed only when there is a significant mechanical transfer, so that the contamination of the steam by any substance expeeds the solvation capacity of the steam.

contains less than 10 to 15 ppb Si03 =. The problem of silica deposits on turbine blades is primarily present under high pressure conditions, whereas at lower pressures a considerable amount of Si02 can be tolerated in the boiler water. At pressures over about 400 to 600 psig, boiler water silica will vaporize and contaminate the steam. As pressure is reduced as steam passes through the turbine, the silica begins to deposit, causing reduced turbine efficiency. If salt mixtures such as sodium chloride, sodium sulfate or sodium hydroxide are carried out and form deposits, then corrosion occurs, especially if the melting point of the mixture is lower than the steam temperature.44 Copper and its oxides deposits also can cause corrosion. Wickert44 showed that hydrogen sulfide can be formed from sodium sulfate and Fe in the presence of water vapor at temperatures over 300 C, while at 440 C, sodium chloride reacts with the vapor to form hydrochloric acid and sodium hydroxide. The sodium hydroxide is retained by the sodium chloride, while the hydrochloric acid lowers the pH of the condensate in which it gathers. Catalysts of the reaction are silicon dioxide, copper and especially cuprous chloride. The American Boiler Manufacturers Association has established standards for boiler water balances in its

Corrosion Reactions The electrochemical

where H20 may be liquid or gas. The protective f1lrn.is magnetic iron oxide, Fe304 and the major inhibitor approach is to maintain this mm as a continuous, very adherent, very thin layer. In a properly treated boiler, this isolation of steel from boiler water can be maintained for many years of service. Conversely, rupture of the mm by either mechanical or chemical means will promote the solution of iron.

standard steam purity guarantees. These are identified as "ABMA Limits" and are listed in Table 2. The carry over can occur as a result of mechanical or chemical causes. Carryover is generally classified as foaming, priming or general entrainment in the steam. Some of the mechanical factors that influence boiler water carryover are: (1) boiler design, (2) severe steam load swings and (3) high water level. The foamimg problem is the most difficult to control and can be caused by a number of factors. Some of the major ones follow: 1. Oil contamination, 2. Other organic or colloidal contamination, 3. High total dissolved solids content, 4. High alkalinities, and 5. Suspended solids. Schudlick et al4

5

corrosion reaction for iron boiler

metal surfaces is generally acknowledged12,4 8 to be:

The corrosive factors in a boiler vary, but in a broad sense, they can include dissolved oxygen, high temperatures and pressures, high salt concentrations, high-heat transfer conditions, stresses, localized concentrations of caustic (boilers are purposely operated at high pH values), erosion, peculiar localized flow conditions, deposits of salts, metals and metallic oxides and scales and sludges with localized overheating. The materials of construction are invariably carbon steel or low-alloy iron and steel except in nuclear boilers where alloys may be used. Various types of corrosion which can be encountered include pitting, concentration corrosion, caustic embrittlement, stress corrosion, erosion-corrosion and in nuclear installations, mass transfer.

have established maximum limits for oil

This list shows that major corrosion problems in the 199

Corrosion due to local concentration

boiler are local in nature. General corrosion of boiler tubes is not of much concern as a rule. Failures occur at specific sites and are associated with unique factors, such as deposits, crevices and stagnation. A brief survey of some of the more common types follows.

cells as a result of

stagnant conditions, deposits or overheating manifests itself in the form of isolated zones which can be either in the shape of saucers or in the form of elongated bands. The point of attack is frequently related to minor mechanical irregularities in the tube wall and is frequently found on the downstream side of a weld zone. The corroded area is

Pitting of Boiler Materials Pitting is frequently associated with attack by dissolved oxygen and is manifested throughout the boiler system. The oxygen causes the formation of Fe203 instead of the desired Fe304 and causes rapid tube failure. Conditions in the boiler are such that the development of oxygen concentration cells under scale or sludge deposits is favored. The last traces of oxygen must be removed to prevent this type of attack. Even then the oxygen in water can react with steel to cause pitting, especially in localized concentrated NaOH.4 9

generally covered with a voluminous corrosion product which is primarily Fe2 03, although considerable quantities of copper may also be present. Excess NaOH concentration is caused primarily by concentration of boiler water. HallS 2 points out that bubbles of steam formed at the surface of a boiler tube result in a localized temperature increase, which in turn, concentrates the boiler water at the interface between the bubble and the heat transfer surface. The result is a rapid increase in caustic content at that point.

Deposits, such as those caused by scale, sludge or mill scale, promote pitting. The deposits are cathodic to iron and intensify local attack, while at the same time they contribute to overheating in the deposit zones due to their heat insulating properties. Metal precipitation, especially of copper, is generally believed to accelerate pitting. The copper originates from copper or its alloys used in the preboiler and postboiler systems. Copper oxide which comes into the system from this source reacts with the metal surfaces to form iron

Caustic Embrittlement Caustic embrittlement can be considered a special manifestation of the caustic-concentration problem. The major corrosive factor here is an abnormally high concentration of caustic in contact with steel under relatively high tensile-stress. Crevices in the system, especially at rivet holes, present ideal conditions for embrittlement and the bulk of cracking of this type has been associated with the presence of rivets. It is interesting to note that the cracking tendency of steel is not necessarily related to its corrosion resistance. Tseitlin et als 3 showed that corrosion-resistant Cr-Ni and

oxide and spongy copper.so More copper oxide is then entrapped by the resulting deposit and gradually a large deposit builds up. A strong galvanic cell results. In addition, the pH of the water near the tube wall drops, loses part of its ability to maintain the desired Fe304 film and contributes further to the action of the corrosion cell. Copper precipitation may occur during acid cleaning under certain conditions unless specific measures are taken to avoid it. Stresses or solid impurities in the steel promote pitting! 3 Anodic areas are formed and the pits are found to be aligned with the stress, such as in fin tubes at the point where the fin has cracked and in the expanded zones of boiler tubes.

Cr-Ni-Mo steels have a strong tendency to crack under stress in the presence of hot alkali solutions, while carbon steel, which is more easily corroded, has a lesser tendency to crack under these conditions. PodgornyiS4 subjected steel samples to a pressure of 40 atm at 225 C in a solution containing 20% NaOH, 20% NaCl and a trace of Na2 Si03. He found that the resultant caustic embrittlement could be related directly to the cathodic polarization. He found further that correct mechanical and thermal pretreatment of metals minimized cathodic potentials and cracking. Embrittlement was found to be related to the strain produced by the curvature of the metal, to the chemical composition of the steel and to the concentration of the alkali solution. Caustic embrittlement increased with increasing boiler-water concentration. Hydrogen atoms were formed in localized areas and migrated through the intercrystalline interstices. The mechanism of embrittlement cracking is generally believed to be dependent on happenings at grain boundary atoms. Parkin SSS states that it is based on the distorted

Concentration Corrosion A number of forms of localized corrosion problems can be grouped under the general term concentration corrosion. This corrosion is essentially the result of high concentrations of chemicals in specific locations, brought about by deposits and/or stagnant flow conditions, crevices and localized overheating. The most common causative agent is a high sodium hydroxide concentration. Partridge and Hall I 3 showed how the attack on steel at 310 C is a function of pH and that maximum protection is achieved at pH 11 to 12. As the concentration of NaOH rises to give pH values above 12, the attack becomes rapidly aggravated by the formation of soluble Na2 F e02 instead of the protective Fe304. Corrosion rates also increase as the pH drops below 11, but the NaOH attack is by far the more common occurrence. Attack by concentrated NaOH proceeds more intensively in high-pressure boilers than in medium-pressure boilers. S I

nature of ferrite in the region of grain boundaries. Hecht, Partridge, Schroeder and Whirl in their section in UWig's Corrosion Handbookl3 say that grain boundary atoms are attached to crystals of different orientation and can be maintained in position by atomic force lines distorted from their normal position. Removal of such atoms from their strained position therefore is much easier than from the body of a crystal. Concentrated alkaline solutions can cause 200

published reports of cracking of stainless steel in high temperature water or steam and in each case found high concentrations of chlorides in the region where the cracking occurred. Both mild steel and austenitic stainless steel are

these intercrystalline cracks. A number of other theories including hydrogen,S 6,S 7 precipitation,S 6 oxide film,s 6 colloidal phenomena,s 8 and mechanical and boundary distortion theoriess 6 also have been suggested. Oxides are usually found in the cracks and precipitated salts also may be present. Silicates are reported to accelerate cracking. Akimovs 8 postulates that alkali acts upon iron to form sodium ferrate, Na2 Fe02 and hydrogen. Corrosion then proceeds along the grain boundaries where it is accelerated by internal stresses which separate the grains along the weakened ·boundaries. A crack forms, water penetrates into the weakened metal and intercrystalline corrosion spreads still further. In addition, the adsorption of the evolving hydrogen by the metal can add to the deterioration. Nitrate cracking also can cause localized corrosion problems. Parkinss S compared nitrate cracking with caustic cracking and said that nitrate cracks are intergranular, while caustic cracks are intercrystalline, although a certain amount of transcrystalline cracks also can be present. However, such problems are not normally encountered in boilers.

involved, with primary interest centering around the latter. Recent literature on this subject includes articles by Clarke and Ristaino,6! Phillips and Singlel4 and Edeleanu and Snowden.6s The most likely place for cracking to occur is in a stainl~ss steel tubed steam generator where high chloride concentrations and steam-blanketed areas develop.64 In addition, considerable free oxygen is likely to be present. The adverse effect of oxygen on chloride stress corrosion is pointed out by Williams62 who shows that oxygen and chloride both must be present for stress corrosion to occur. Temperature and time are both important factors here. Cracking can occur at the boiling point of water62 but it will be accelerated by increased temperatures. Time is important because of the possible need for an inductive period, although failure can be very rapid under highly conducive conditions. The problem of stress corrosion cracking becomes especially severe for those stainless steel parts which are intermittently exposed to boiler water. Both Clarke and Ristain06! and Williams62 point out that this exposure represents a much more severe condition for inhibition than in the case of the parts that are submerged in water continually. The cracking in the parts that are in the vapor phase does not occur if the water which contains chloride does not come in contact with them by splashing or by some other mechanism.

Stress Corrosion Caustic embrittlement is actually only one type of stress corrosion cracking. It is the one most frequently found in boilers and for that reason merits special consideration. A theory of the more general phenomenon of stress corrosion cracking was advanced by Dixs 9 and extended by Waber, McDonald and Longtin.6o This theory holds that the metal must have an inherent susceptibility to selective corrosion along a continuous path, such as along a grain boundary. This corrosion will occur when the structure is microscopically heterogeneous and the continuous phase is anodic to the rest of the metal in the particular corrosive medium under consideration. There also must be a high tensile-stress along this continuous phase. Corrosion then will proceed along the anodic path. A self-accelerating reaction is initiated in which the corrosion produces more stresses which in turn open up easier paths for the corrosion. The development of protective films is thus minimized and fresh anodic material is continually

Erosion-Corrosion On occasion, failures which occur in boiler tubes can be attributed to an erosion mechanism. They generally occur at areas in the tubes where the normal direction of flow has been altered abruptly, a condition of turbulence created and a new flow path followed. The resultant corrosion is similar to that found in some feedline systems. Here again a situation exists where the primary cause of the failure is a physical one, i.e .. the flow pattern while the resultant chemical corrosion causes the damage. An example of this type of attack is cited by Schoofs66 who describes the erosion-corrosion of brass

being exposed to the corrosive medium. In addition, precipitation of materials, such as iron nitride (in the case of mild steel), is hastened by high local stresses. Nitrides in turn cause the development of galvanic cells in which they dissolve to form cracks. The picture of stress corrosion thus presented is one of a catastrophic chain reaction inwhich physical stresses and electrochemical corrosive reactions are mutually accelerating. Concern has become quite prevalent during recent years over the stress cracking of steels by chlorides. This interest has come about because of the increasing work in

tubes in a reheater of a power station boiler. The attack took place where the direction of flow changed. Overheating and local boiling took place with a disruptive effect on protective films. particularly at the exit and the entry where turbulence was the greatest. Another example of the relation of corrosion to turbulence is the situation where copper pitting may be the causative effect but the corrosion is found downstream of a

pressurized water nuclear power plants. The United States Navy has been especially interested in connection with the Submarine Thermal Reactor Boiler6! and nuclear propulsion systems, nonmagnetic auxiliary boilers for mine sweepers and superheaters in general. 62,63 Identification of chloride as a major causative agent has been made by Williams62 who reviewed a number of

weld zone. The mixture of spongy. deposited copper and iron oxide acts as a barrier to flow of boiler water and entraps more copper oxide. The water reaching the tube walls is no longer agitated vigorously and a localized corrosive condition is created.5 0 201

Postboiler

Corrosion Phenomena

analogous to that of steam condensate systems. The condensed water contains oxygen and carbon dioxide, which result in an aggressive solution. The dissolved oxygen is an active depolarizer and if oxygen concentration cells develop under corrosion or salt deposits, it promotes rapid pitting. The dissolved carbon dioxide renders the water weakly acidic and promotes both general and localized attack.

The post boiler system is broken down into two areas: (1) the superheater and (2) the condensation and return system. Each will be considered separately. Superheater The allocation of the superheater to the postboiler group rather than to the boiler itself is purely arbitrary. Problems in the superheater are somewhat similar to both those of the boiler and those of the return and condensate system. For that reason it serves as an effective transition problem between the two. The attack on superheater tubes can be attributed to three corrosive factors:

Steam Condensate and Return Systems Corrosion of steam condensate and return systems presents a twofold problem to power-generating and steamheating plants. Equipment damage and frequent replacement of lines, valves and traps result in a serious maintenance problem. In addition, corrosion products frequently formed are carried back into the steam-generating equipment and deposits there. The result is plugging of lines, localized overheating and promotion of corrosion in the boiler system itself. Examples of these failures are cited by Ulmer and Wood7! and Straub.7z Since preventive treatments for condensate systems frequently are injected into the boiler itself, these combinations prove the need for an overall approach to the boiler-water problem rather than its isolation by sections. Corrosion in the condensate system manifests itself in certain typical forms, depending upon the corrosive factors involved. These factors are basically oxygen, carbon dioxide and condensed water. The attack due to dissolved oxygen is characterized by tuberculation, pitting and build-up of iron oxide deposits. The mechanism involved is thought to be one of depolarization of the cathodic areas on the metal surface. Collins and Henderson 73 made a detailed study of oxygen attack and arrived at the following condusions:

1. The reaction between steam and metal at high temperatures, 2. The carry over by steam of salts which are then deposited on the metal surfaces, and 3. Condensation that occurs when the system is banked or is temporarily out of service. Corrosion of metal by steam at very high temperatures is a serious problem but it will not be treated here since it is not amenable to solution by use of corrosion inhibitors. It must be minimized by the choice of suitable alloying materials. The reader is referred to reviews by Kovacs67 and Grobner and Bret68 and to excellent detailed discussions in UWig's Corrosion Handbook.! 3 Carryover by steam of salts which deposit on the metal surface and cause corrosion is a very serious problem in superheaters. Wickert44 showed that deposited NaCI could react with steam at440 Cto form NaOH which would be retained by the NaCl. The direct reaction between deposited NaCl and the metal is the subject of much controversy but there is little doubt that NaOH, whether it be from the reaction postulated above or whether it is present due to entrainment in the steam, will lead to severe local attack under the deposits. Wickert points out that this is especially true if the melting point of the deposited salt mixture is lower than the steam temperature. He also states that copper and its oxides, if deposited, also can be corrosive if electron acceptors like oxygen or hydrogen ions are present. Hass69 showed that deposited calcium salts, especially CaClz, also can decompose to form hydroxides at boiler temperatures. It was shown that the reaction of CaClz

1. Oxygen concentrations below 0.5 ppm cause negligible corrosion when the temperature is less than 70 C and the pH of the condensate is 6 or higher. 2. In the pH range 6 to 8 and at oxygen concentrations of 0.5 to 4 ppm, the rate of attack for general corrosion is given by the equation R = 24(C-0.4)0.9, where R is the average rate of penetration in mdd and C is the oxygen concentration in ppm.73 Collins and Henderson 73 say that this equation is not valid for pitting corrosion and does not take into account the accelerating effect of temperature.

with water vapor was accelerated by the presence of silica. Styrikovich 7 ° studied phase diagrams for water with SiOz , NaCl, Naz S04 and CaS04, respectively, at both subcritical and supercritical pressures and he detected the hydrolysis of salts by superheated steam at temperatures as low as 550 to 600 F. He also studied the distribution of a number of substances between water and steam phases and found that most carryover was caused by weak acids (silicic, boric); less for cWorides and hydroxides and least for sulfates, silicates, carbonates and phosphates.

Skaperdas and Uhlig 74 showed that an increase in temperature from 60 to 90 C will double the rate of oxygen corrosion. Normally, one would expect a dual effect due to oxygen as a function of increasing temperature. On one hand, the corrosion rate should increase rapidly with temperature in accordance with normal kinetic considerations while on the other hand, the decreasing solubility of oxygen with temperature should decrease the attack. In this particular closed system, however, the oxygen cannot escape and consequently the normal increase in reaction

Steam condenses readily in superheaters after a boiler is banked or shut down where the corrosive system becomes 202

Inhibition Practices in Boilers

rate with temperature is to be expected and does in fact occur. Carbon dioxide attack manifests itself by thinning and

Discussion

of chemical

inhibition

of the corrosion

problems previously mentioned will be given in the same order as were the problems. Solutions of scale, sludge and carry over problems also will be discussed because they were shown to be linked intimately to the corrosion problems and also because corrosion inhibitors are rarely used alone in boilers systems. The addition of chemicals or the use of other treatment

grooving the metal walls with failure occurring most readily at threaded connections. The walls are relatively clean, in contrast to the masses of corrosion products which cover the areas of oxygen attack. CoBins 75 also studied the corrosion rate of carbon dioxide and developed the equation

techniques as applied to boiler systems is generally known either as external or internal treatment. The term external

R = 5.7Wo.6, where R is the rate in mdd and W is the concentration of carbon dioxide in condensate in

treatment is usually applied to clarification, softening or demineralizing equipment, whereas the term internal treatment usually refers to treatment injected into the deaerator, feedlines, boiler or steam-condensate systems. The term pretreatment is synonymous with external treatment.

ppm multiplied by 0.1. Here again the temperature effect is not considered. Skaperdas and Uhlig74 found that an increase in temperature from 60 to 90 C raised the rate of attack of carbonic acid on low carbon steel by a factor of 2.6. The absolute magnitude of the corrosion will, of course, vary from system to system. Osmond and Welder 76 describe a system where the corrosion rate of steel panels in the de superheating condensate system was 1285 mdd prior to treatment. It is interesting to note that steam, which usually is thought of as being pure distilled water and relatively inoffensive, is instead highly corrosive and contains considerable quantities of CO2 and O2 . The principal source of these two gases is the boiler feedwater, although some gases may enter as a result of leaks or return-tank breathing. Efforts are usually made to eliminate oxygen from the boiler water, as will be discussed later, but these efforts are not always successful. The carbon dioxide results mainly from decomposition of bicarbonates and carbonates in the boiler, with the resultant liberation of free CO2, Collins et al13 ,75 ,77 point out that a peculiar equilibrium exists between gases in the vapor and those in the condensate. Normally, the amounts of O2 and CO2 in the condensate could be predicted readily from their partial vapor pressures, which decrease with increasing condensate temperature. When steam consumption of pressure equipment is very high, however, large concentrations of noncondensabJe gases accumulate in the vapor space of the unit. A gradient mixture of steam and noncondensable gases occurs, with the highest concentration of gas present at the vapor-condensate interface. This partial pressure at the interface determines the amount of gas dissolved in the condensate and the result is that larger quantities are dissolved than would be expected normally. Collinsl 3 also explains the diminishing corrosion rate as one proceeds downstream in the system as being due to a progressive increase in iron content, which raises the pH and makes the system less corrosive. The nature of the condensed water also affects the type and amount of corrosion. The presence of droplets leads to localized pitting attack. A uniform film, on the other hand, causes more general corrosion. Rozenfeld and Zhigalova 78 report this phenomenon in some detail.

Preboiler Inhibitor Practices External treatment is generally intended to solve both corrosion and scale problems in preboiler and boiler systems. Pretreatment Pretreatment of feedwater is designed to render it as noncorrosive or non scale-forming as possible. Corrosioncontrol methods include various ion-exchange techniques designed to remove dissolved ionized solids from raw water which is blended with the condensate makeup to compose the feedwater. The ion-exchange materials most commonly used now for this purpose are synthetic organic exchangers, rather than the naturally occurring zeolites or their synthetic analogues which at one time were in wide use. An ion-exchange resin can be considered to be a solid polyelectrolyte with a fIxed charge and a movable (in water) countercharge or "gegenion". Cation-exchange resins have fIxed anionic groups and exchangeable cations. The fixed anionic group can be sulfonic, carboxylic, phenolic or phosphonic. "Strong base" anion exchange resins have fIxed, positive, quarternary ammonium cations and exchangeable anions. "Weak base" anion exchange resins have fIxed primary, secondary, or tertiary amines and can take up acid molecules from water. The exchange reactions for these resins can be written as follows: 1. Cation exchanger: RS03-H++ Na+Cl- = RS03-Na+ +H+CI2. Strong base anion exchange:

3. Weak base anion exchange: RNH2 + HCI --* RNH2

•

HCl

In all cases R represents all of the resins except the functional group. Most of the resins commercially available are polystyrene-divinylbenzene copolymers which have been treated to develop the desired functional group.

203

promotes the formation of a protective mm. Ferrous oxide or hydroxide are formed initially and their transformation to magnetite can take place readily if nickel or copper are present as catalysts. There are some inherent disadvantages to this approach, however.4 8 Sufficient re circulation of the alkaline boiler water may be impractical or may lead to deposit problems as precipitate formation proceeds with the lowering of temperature. Use of NaOH can cause increased blowdown requirements in the boiler system. Two interesting points in this regard are made by Potter. 20 He noted that

As can be seen from these equations, an equilibrium is set up between the competing ions. This equilibrium can be driven in one direction by passing a solution containing one ion through a fixed bed of resin in another ionic form. Each resin particle acts as an equilibrating system and by the time the solution comes out of the bottom of the column, all of the unwanted ion originally present in the solution has been replaced by the exchangeable ion of similar charge on the resin. Thus, for instance, NaCl in solution can be completely converted to HCl or vice versa. It is apparent that resins can be used to soften water by removing the hardness ions, i.e., Ca ++ or Mg ++ and replacing them with sodium. Similarly, use of a cation resin in the hydrogen form produces an acid. Passage of the produced acid through an anion-resin bed in the hydroxide form results in pure demineralized water. This process can be carried out either by having one resin bed immediately after the other or by mixing the two resin types in one column. Similarly, alkalinity content and type of feedwater can be controlled by a suitable exchange of ions. Deaeration to remove oxygen from feedwater must be provided if oxygen corrosion is to be avoided. Deaeration is generally accomplished through a combination of mechanical and chemical means, a combination which is the most effective and economical available. A number of different mechanical systems, wherein water is heated to drive our dissolved gases have been devised for this purpose. A detailed discussion of their use is beyond the scope of this book. However, the principle of the most commonly employed equipment is that of stripping dissolved oxygen from the water by using steam as a stripping medium. The equipment is designed to break the water into small droplets and to bring them into intimate contact with steam. The water is formed into small droplets by using sprays or overflowing trays, or a combination of these means. The water flows downward while the steam moves

1. Alkalinity arising from massive dissolution of iron is no substitute for the addition of alkali, and 2. In view of the temperature involved, measurement of p OH would be of more value than measurement of pH since the former is much less temperature-dependent. A more recent approach to pH control in preboiler systems involves the use of ammonia or other . 49 "82 83Th IS .... IS necessary m systems operatmg ammes. above the 900 to 1200 psig range with high purity water. These weak bases permit a more closely controlled regulation of pH. Andres49 gives the following values in ppm for the amount of material necessary to give pure water a pH of 9.0.: 1. Ammonia-less than 0.5 2. Cyclohexylamine-2.0 3. Morpholine-4.0. One obvious concern relating to this approach is the effect of amines on the corrosion inhibition of nonferrous metals and especially copper. Decker and Marsh83 evaluated the above amines and NaOH for control of erosioncorrosion on a number of ferrous and nonferrous alloys and found that cyclohexylamine and ammonia were effective for ferrous metals but not for nonferrous. Sodium hydroxide was effective for all metals and morpholine was ineffective for all metals. Tash and KleinZ3 on the other hand, found morpholine to be an effective inhibitor, provided hydrazine was also used. Grabowski82 found that the volatile amines can be effective and claimed that NH3 in the pH range of 8.5 to 9.5 reduced the corrosion of copper. He states that to keep the copper and iron surfaces from corroding, the O2, CO2 and S02 gases must be kept at a low value while the proper pH is being maintained. Homig and Richter81 found that morpholine was superior to ammonia or cyclohexylamine for iron inhibition, but here again it was essential that the O2 and CO2 content be kept at a minimum. The primary problem appears to be oxygen and it is generally believed that use of ammonia or amines for pH control is satisfactory provided the oxygen content is carefully controlled also. Control of dissolved oxygen in the boiler water is accomplished chemically by the use of either sodium sulfite or hydrazine. Sodium sulfite or preferably catalyzed sodium sulfite has been used for many years, while hydrazine has become prominent for this purpose only during the past decade. The level to which it is necessary to remove the dissolved oxygen to prevent corrosion varies as a function

countercurrent to the water flow. Oxygen and other noncondensable gases are removed through a vent at the top of the unit. The entire unit is identified as a deaerating heater. It consists of two sections, a deaerating section (top) and a storage section. Oxygen removal down to 0.03 ccll (21 pp b) is common when the unit is operated at saturated conditions although some units are designed to remove more oxygen. Corrosion Control Practices General corrosion is frequently prevented by pH control. Maintenance of 9.0 pH reduces general corrosion appreciably.79,8o There have been two approaches to raising feedwater pH to this value.4 9 The earlier one consisted of either adding NaOH or recirculating alkaline boiler water and aimed at the protection of all metals generally found in these systems.8 1,82 Evans5 postulated that the mechanism of inhibition is as follows: As the (OH -) activity is raised, the solubility of all oxides and hydroxides is reduced and the degree of supersaturation set up in the liquid very close to the metal is raised. This situation favors production of closely spaced nuclei of ferrous hydroxide, ferrous oxide or magnetite and

204

-,

extent that all oxygen can be substantially removed at 400 F with reasonable values of reaction times and Nz ~ concentration. At feedwater temperatures normally encountered in most industrial boiler systems (220 to 235 F), the reaction rate of hydrazine is considerably slower than the sulfite-dissolved oxygen reaction rate. Leicester98 feels that the mechanism of the Nz H4 -Oz reaction has not yet been fully established, but that it is a surface reaction, is heterogeneous and does not always involve quantitative reaction with dissolved oxygen. Zimmerman and Brinkman in their patent9 9 show that Ag, Cu or activated carbon are catalysts for the Nz ~ -Oz reaction. Oertel8s also shows the advantages of using activated carbon.

'of temperature. Speller, in UWig's Corrosion Handbookl3 cites 0.30 ppm of oxygen in cold water, 0.10 ppm in hot water (70 C), 0.03 ppm in low-pressure boilers under 250 psi without economizers and less than 0.005 ppm in high-pressure boilers or when economizers are used. In practice, it is generally attempted to keep oxygen concentration at zero regardless of the system. Sodium sulfite is used alone or as a catalyzed formulation. The catalysts ordinarily used are very small amounts of copper or cobalt. At very high temperatures sulfite alone is effective in removing oxygen from water rapidly. Varying amounts are recommended. Speller I 3 states that about 8 Ib of sodium sulfate is required to remove I Ib of oxygen and recommends that an excess of about 30 ppm be maintained to insure complete oxygen removal. Deev84 describes cases supporting the need for an excess of sulfite and tells how even when the excess is 2.6 ppm of Naz S03, there is still some oxygen left dissolved in water. Typical dosage values recommended by suppliers for scavenging oxygen are 20 to 40 ppm excess. Tash and Kieinz 3 used 25 to 100 ppm of sodium sulfite in their boiler water at the Shippingport nuclear power station, while Arthurs et all 7 specified 100 to 140 ppm Naz S03 for their high-pressure boiler-water composition. In the case of 1700 psi boiler, they used both vacuum and pressure deaeration to reduce dissolved oxygen in the feedwater to 0.005 ppm. Catalyzed sulfite is used in the same range as uncatalyzed sulfite but is more rapid and more effective. Activated carbon, as an additive to sulfite, functions by adsorption and concentration of the oxygen. An increase in temperature is advantageous. A detailed description of the use of activated carbon is given in a German patent by Oerte1.8S

A competing reaction which can cause the formation of undesirable products is the catalytic or thermal decomposition of hydrazine. The resulting ammonia may attack nonferrous metals. Dickinson et al9 7 believe the reaction is as follows:

Hartmann and Resch9s say that at pH 8 the reaction is the following:

They made a very thorough study of the decomposition of hydrazine hydrate under high-pressure boiler conditions. It was found that when the log of the ratio of the concentration of Nz H4 after a given time to the initial concentration, C, is plotted against time, t, a straight line results. The half-period (50% decomposition) is given by the following equation:

Certain disadvantages are implicit in the use of sodium sulfite. One is that it can decompose to form SOz or Hz S in high-pressure, steam-generating equipment, thus appreciably increasing corrosion rates in the steam-fed water cycle: 86 Fiss87 found that above a limiting concentration of 10 ppm, sulfite decomposition occurred in 900 psi boilers. Another disadvantage is increased total dissolved solids in the boiler water which requires more blowdown. The catalysts can plate out in boiler tubes and promote pitting. For these reasons, there has been a considerable interest in another chemical additive for deoxygenation: Hydrazine. There is much recent literature on the use ofhydrazine. For some of the more thorough studies the reader is referred to papers by Woodward,88-41 Zanchi,92,93 Zimmerman94 and Hartmann and Resch.9s

0.301t t 1/2= [-log (C/Co)] The equation was found to decrease with increasing pH, presumably owing to the formation of N~ OH and its ionization at the higher pH values. The nature of the contact surface affects decomposition. Thus Hartmann and Resch9s found that when the surface was quartz, the decomposition rate was exceedingly slow with only slight thermal decomposition. On the other hand, metallic copper or Fe304 accelerated the reaction and copper resulted in production of Nz O. In a quantitative measurement of the decomposition reaction, Leicester98 found that if the residual hydrazine content of the boiler is kept below 0.2 ppm, the NH3 content of the steam will not be greater than 0.3 to 0.5 ppm. In actual plant operation88 it was shown that feeding hydrazine at three to five times the theoretical amount required to react with the dissolved oxygen left a residue in the boiler water and produced an NH3 content in the feedwater of 0.05 to 0.15 ppm. StoneslOO found that addition of hydrazine to 100'70 in excess of the oxygen requirement resulted in a rapid rise in NH3 and pH values

The reaction between hydrazine and oxygen has been described as follows: 89,9 I ,9 Z

with further hydrazine then reducing ever, Nissen96 said that hydrazine protective FeO layer. Dickinson et reaction rate increases rapidly with

metal oxides. Howwill not attack the al97 state that the temperature to the 205

from time to time. Therefore, coagulation equipment is almost always followed by filtration. The problem of flock carry over frequently can be resolved by closer attention to operating practices, redesign of the clarification system so that more residence time is provided for the floc to settle out, or changing the chemical coagulation procedure. Efficient operation of the coagulation and/ or softening process is essential for proper feedwater maintenance. Details of clarification or softening procedures will not be discussed here because they are beyond the scope of this book. Recently, there have been several exciting developments involving high molecular weight polymeric materials which markedly improve clarification procedures. Polymers used in the clarification process are generally required at low feed rates, usually in the range of I to 20 ppm. Their function is to agglomerate particles which otherwise would remain small (and become floc carry over) into larger particles heavy enough to settle ou t of the water. The three broad classes of these polymers are: (I) cationic, Effectiveness of each (2) anionic and (3) nonionic.102 varies, depending upon the charge on the suspended solids and molecular weight of the polymer. Further, some of the polymers may be used as a primary or secondary coagulants. Some are of such high efficiency that they may be useo. )ust pr10l to '3. f1\ter without the i\\s\'a\btion of clarification equipment. This latter application is referred to as "in-line" clarification.

with a resultant corrosion of copper-nickel and brass tubes. If the concentration of hydrazine is regulated carefully to prevent breakdown of the excess to ammonia, its use instead of sodium sulfite has a number of advantages. Salt content does not increase as it does when sulfite is added. Another advantage is that alkalinity can be controlled with proper excess of hydrazine. Maintenance of a hydrazine residual in the water protects the boiler against occasional increases in dissolved oxygen content which result from variations in operating conditions. Finally, much smaller dosage levels are required. A number of comparisons of the use of sodium sulfate and hydrazine have been published. Massart and Missa 101 compared them. They found that although sodium sulfate was more reactive than hydrazine, the latter was advantageous when air was admitted accidentally. Vapor pH was less than 7 with sodium sulfate compared to a desirable value of 9 for hydrazine. The amount of dissolved Fe decreased with hydrazine, but the amount of Cu in solution was unaffected. Hydrazine was superior economically despite higher initial chemical cost. Woodward88,8 9 also showed hydrazine to be more efficient than sodium sulfate, while Fiss89 substituted hydrazine for sulfite in a 1500 psi boiler that had experienced a series of tube failures. The hydrazine stopped tube failures. It was also effect1'le 1n 1850 psi boilers. Hydrazine is now being used in boilers with a wide spectrum of pressures ranging from 400 to 2500 psi.8 8 It is easy to apply and can be controlled readily. Because it is toxic, due care must be exercised in handling. Another disadvantage is that control testing is more complex, usually requiring photometric procedures for greatest accuracy. Some variations of hydrazine are now being examined. Dihydrazine phosphate is now being used in England to treat idle boilers.8 8,98 A new salt of dinaphthylmethanedisu1fonic acid containing 11 to 15% hydrazine is said to have promise.97 In addition to corrosion inhibition, this latter material is a good dispersant and assists in fluidizing solids in the boiler.

An example of the utility of polymeric coagulan t aids is cited 103 in a case where river water was being treated with extremely poor results for high-pressure boiler feed in a high-rate solids contact reactor. At times, chemical loadings as high as 120 ppm alum and 20 ppm activated silica were used, but still they did not provide proper clarification. The use of 0.5 ppm of new polymeric coagulant (a high molecular weight polyacrylamide. possibly very slightly hydrolyzed) during a period of extremely difficult operation enabled this plant to cut the alum loading in half, eliminate activated silica and achieve the desired clarity. It also improved the operation of the ion-exchange beds used for water softening. Feedline deposition problems from dissolved solids were encountered frequently prior to the currently common practice of softening makeup water. Where hard water is used, calcium, magnesium or iron scales may deposit in the preboiler circuit as a result of a temperature increase. Molecularly dehydrated phosphates (polyphosphates) are commonly used to prevent such deposits. Very low concentrations of poly phosphates will reduce the deposition of calcium carbonate upon moderate application of alkali or heat to hard bicarbonate water. An in teresting aspect of such a treatment program is that it appears to function in a twofold manner by reducing the build-up of scale deposits and also by minimizing corrosion. In the boiler-feed application, it is used primarily for the former purpose.

Deposits As indicated earlier, deposit problems in preboiler systems can be divided into two categories based upon their origin. The first is deposition of suspended solids which may be carried into the system with the makeup water, while the second is from dissolved solids such as calcium, magnesium or iron. The first problem, deposition of suspended solids, is attacked by filtration and/or clarification of the makeup. Filters can be of either the gravity or pressure type. Pressure filters are usually favored in industrial plants because of their relatively small space requirements. Filtration without clarification (coagulation and sedimentation) will commonly remove only the largest particles of the suspended solids and, therefore, often will prove unsatisfactory. Coagulation for suspended solids removal is not practiced alone as a rule because floc can be carried over

It was suggested 104-106 that the prevention of calcium carbonate deposition by molecularly dehydrated phosphates apparently results from the stabilization of a 206

condition of supersaturation with respect to calcium carbonate. Adsorption of the phosphate upon initially present or subsequently formed nuclei for crystallization appears to prevent CaC03 deposition; in the case of foreign materials which do not adsorb the phosphate but which can act as nuclei for crystallization, adsorption will occur as soon as CaC03 is deposited, with a subsequent inactivation of the surface as a nucleus for crystallization. A possible explanation of the effect of molecularly dehydrated polyphosphates on calcium carbonate was given by Buehrer and Reitemeier.! 07 They show that adsorption of phosphates results in gross deformation of calcium carbonate crystals formed when phosphates were present in quantities insufficient to inhibit deposition completely by complexing the calcium. Reference was made earlier to the reversion of molecu-

treatment which refers to mechanical processes (coagulation, softening, etc.) treating makeup water prior to the makeup water's entrance into the preboiler system. Internal treatment for prevention of deposits can be divided into two techniques: (I) precipitating treatment and (2) solubilizing treatment. Each control method will be reviewed separately. Precipitation treatments have been standard practice at boiler pressures up to the range of 900 to 1000 psig. The two common techniques use phosphate control or carbonate control. These treatments involve the formation principally of calcium phosphate or carbonate sludges, their dispersion by various organic chemicals and finally, their removal by blowdown. Phosphate control involves tying up all of the calcium in the boiler in the form of a calcium phosphate sludge. Calcium phosphate readily forms a finely divided sludge in contrast to other calcium salts which form scales. Both poly and orthophosphates can be used because the polyphosphates will revert to the ortho form very rapidly under boiler conditions and it is the ortho form which reacts with

larly dehydrated phosphates to produce orthophosphates. While this reversion is desirable in the boiler itself, it is very undesirable in the feedlines because of the build-up of calcium phosphate deposits, which can be as serious as the original feedline deposit problem. Users of polyphosphates in the preboiler system must consider this problem. Polyphosphates added to feedlines for deposit control also function as corrosion inhibitors. The mechanism of

the calcium. In practice, all commercially phates are used.

available phos-

Sufficient alkalinity must be used with phosphate control because at low alkalinity values calcium phosphate becomes more soluble and tends to form a sticky adherent sludge. Adequate alkalinity for complete reaction with calcium requires a minimum pH of 9.6 in a steaming boiler,37 a figure comparable to 10.5 at room temperature. The "phenolphthalein alkalinity" must be greater than one half of the "methyl orange alkalinity" and the latter value should be at least 200 ppm. Brooke2 favors a pH of 11.0 to 11.5 for scale prevention and advocates its maintenance by use of NaOH or Na3 P04. It must be recognized, however, that while this is a very desirable range, all makeup water do not have the same characteristics. Frequently, where external treatment has not been provided, it is necessary or desirable because of economics to operate with much higher phenolphthalein and methyl orange alkalinities, resulting in much higher boiler water pH values. Since the mechanism involved here is one of actually reacting with the calcium on a stoichiometric basis, it is apparent that an excess of phosphate must be maintained. This excess will vary from 10 to 100 ppm of phosphate, depending on the plant operating conditions and the efficiency of the feedwater hardness control. Because many feed waters contain magnesium in addition to calcium, it is necessary to consider the proper proper internal treatment of this feedwater component. The upper limit of 100 ppm for phosphate excess is used because above this value magnesium phosphate can begin to precipitate. Magnesium phosphate deposition has been encountered even at lower phosphate values. This is an undesirable precipitate since it is very adherent to boiler surfaces. Additionally, it will tend to cause greater volumes of hydroxyapatite and other precipitates to deposit on the boiler surfaces because of its adherent characteristics. Therefore, precipitation of magnesium in this form is to be avoided. This can be accomplished by maintaining the

protection is described elsewhere in this book in connection with cooling-water corrosion control. Poly phosphate also can prevent precipitation of hydrous ferric oxide if the water contains soluble iron. The injection of ortho or polyphosphate into feedwater in a preboiler system which contains an economizer will invariably lead to serious economizer deposits when calcium is present. The physical condition of flow rates and water-metal interface temperature combined with the usual chemical environment will result in deposits which will be predominantly tricalcium phosphate. Economizer deposits are commonly composed of tricalcium phosphate, magnesium silicate and iron oxide. Until recent years, the preferred method to reduce deposits was to eliminate phosphates from the preboiler system and add organic dispersants. These dispersants include tannins and lignins as well as synthetic polymers and their function will be discussed in the subsequent section. While the use of organic dispersants reduces economizer deposit problems considerably, they are not the preferred treatment method. With the advent in the last decade of chelant applications to boiler systems, true deposit control in economizer (and preboiler systems in general) has been achieved. As discussed later, chelants solubilize polyvalent metallic ions such as calcium, magnesium, iron etc. In the chelated form, such ions will not drop out of solution. Many corrosion engineers plagued with preboiler deposit problems have turned to the use of chelants.

Inhibition Procedures for Boilers Deposits The term internal treatment is used for the direct addition of chemicals to the boiler, in contrast to external 207

materials commonly used do not promote foaming and are not corrosive. The range of organic materials used for this purpose prior to 19511 13 included tannins, lignins, sulfite liquors, alginates, glucosates and starches. Materials which have been patented since that time include alkaline tannin extracts,1 14 vegetable derivatives,1 15 polymeric compounds containing adjacent carboxy groups such as a methylstyrene-maleic anhydride copolymer,1 10 carboxy me thyl cellulose,1 1 7 pOlyacrylates,1 18 o-nitrophenol dimers, 119 colloidal peatl20 and a wood-fat-molasses-coal mixture. 12 1 Control of magnetic iron oxide deposits has been achieved by using sodium nitrite 122 or an organic nitrite derivative21 to convert it to ferric oxide. Kahlerl 23 has

proper silica and hydroxide concentrations. Many feedwaters do not contain sufficient silica to react with most or all of the magnesium to form the magnesium silicate precipitate identified as serpentine (3MgO' 2Si02 . 2H20) and some will precipitate as the hydroxide. While both are desirable, internal conditions frequently can be dramatically improved by adding sufficient silica as internal treatment to precipitate the magnesium as serpentine. 108 Carbonate control is not practiced as widely as phosphate control. Not only is the calcium carbonate precipitate more difficult to control (Le., remove from the boiler) but an excessive amount of soda ash must be fed to maintain an adequate amount of carbonate. Grayl09 in an empirical survey of 101 low-pressure boilers, found that successful sludge and scale control could be maintained by observing only two conditions: 1. The Mg hardness of the feedwater must be kept above a certain minimum value which is a function of the Ca hardness and the Si02 content and

claimed that water-soluble lignins are more efficient in preventing Fe precipitation from water supplies than are molecularly dehydrated phosphates. Solubilizing Treatments Many problems still exist with the precipitating type treatment programs previously outlined, even where the guidelines set forth are closely followed. Modern boilers are very demanding with respect to feedwater quality and the amount of suspended solids that they will tolerate. Steaming rates per square foot of space occupied are far greater for today's units than they were 10 or 20 years ago. This then correctly implies that heat transfer rates have been greatly increased in modern boilers, which in turn, requires improved treatment programs. This has led to the common use of solubilizing treatments employing chelants. The first use of chelan ts in industrial water trea tmen t

2. The total carbonate alkalinity in the boiler should be between 200 and 300 ppm as CaC03 (i.e., sufficient to restrict the total hardness in the boiler water to 5 ppm). Gerard110 disagrees with Gray's suggestion, because of the difficulty in maintaining the 200 to 300 ppm of carbonate alkalinity. He points out that the decomposition of Na2 C03 to form NaOH would lead to caustic cracking: the added CO2 would increase condensate corrosion. In addition, the MgS04 and Na2S04 can lead to more deposits in the feedlines. Anchevll 1 describes the successful use of both the NaOH plus Na2C03 and the Na2P04 plus Na2 HP04 approaches to combat boiler scale in an electric power plant. Iron or copper may be present in the feedwater in an ionic form or may be present as a metal oxide. With precipitating type treatments, regardless of the original state, iron and copper will end up as a precipitate to increase the amount of sludge. After formation of the above described precipitates, whether they be phosphates, carbonates, silicates, hydroxides or metal oxides, they must be conditioned so that they remain suspended in the boiler water as free-flowing sludge. Unconditioned or improperly conditioned sludges tend to collect in locations where circulation rates are low and form

began in the textile industry about 1935 with the use of materials to control water hardness. 124 Chelants were applied to boiler systems in foreign countries about the middle 1950's and in the USA about 1960. The word chelate was coined from the Greek word "chela" which means the nipperlike organ or claw terminating the limbs of certain crustaceans such as the lobster. Thus, the word chelate was used to describe the grip of a class of amines and organic acids on metal ions, while the word chelation describes the reaction between these materials and the metal ions. Deposit control with chelants involves the use of this class of chemicals to react with metallic ions in the feedwater or boiler water. The resultant chelant-metal ion

packed layers of deposit on metal surfaces which can interfere with circulation and heat transfer. 112 A variety of organic dispersants have therefore been developed to keep this sludge in the free-flowing state.

complex is soluble. While chelant programs were developed initially to control calcium and magnesium deposits through improved technology and application techniques, their usefulness has been extended to systems where iron deposits have been troublesome. 125 Obviously, chelant treatments are far more effective than precipitating treatments for deposit control, since no precipitate is purposely formed.

Organic dispersing agents function not only by dispersing the sludge, but also by adsorption and crystal distortion. Crystal distortion is very important because it lessens the possibility that large crystals will form during the precipitation process and thus limits the potential for the development of a dense sludge deposit. Further, adsorption of the precipitates provides for a fluid sludge which is less adherent to boiler internal surfaces. And, finally, their dispersing characteristics tend to keep the precipitates in a finely divided state, in which form they are readily removed from the boiler by blowdown. The

Many chelating agents are available commercially. The two which have come into common use for boiler deposit control are ethylenediaminetetraacetic acid (EDT A) and nitrilotriacetic acid (NT A). In practice, the tetrasodium salt of EDT A and the trisodium salt of NT A are used, rather 208

than the acid. Both of thses materials chelate bivalent and trivalent metallic ions on a mol for mol basis. The reaction rates for technical grades of EDT A and NT A are listed in Table 3:126 The choice between these two chelants will depend upon many factors, such as concentration of the various metallic ions to be chelated, the concentration of the chelant which can be employed economically, the degree of reactivity required in the particular application and the chemical characteristics of the boiler water. 1 26 The

TABLE 3 - Reaction Rates of Technical Grades of Two Chelates ppm/ppm Metal Ion Metal Ions Calcium Magnesium

Iron Copper Aluminum

chelation reaction, while very energetic, is reversible under some conditions. Where high alkalinities are encountered or the feedwater contains phosphate, there is competition between the hydroxide and/or phosphate and the chelant for the metal ion. This may cause some precipitation in the boiler which might not be expected otherwise. A case in point is the chelation of iron. If boiler alkalinities are allowed to overconcentrate, the high hydroxide levels may cause the iron to precipitate. This can result in iron deposits. Since EDTA is a stronger chelant than NTA, this problem is more likely to occur in an NT A treated system. Because chelants are organic compounds, consideration must be given to temperature or pressure stability of these treatment materials. It has been reported that NT A should not be used in excess of 900 psig, while the upper pressure level for EDT A is about 1200 psig/ 25 Corrosivity of both EDT A and NT A treated boiler water have been investi-

EDTA

I

NTA

4.67 4.67 8.35 7.35

2.75 2.75 4.90 4.30

17.30

10.00

small steam bubbles are present and that they remain in intimate contact without coalescing. The photographs show also that after a polyamide antifoam agent is added, the small steam bubbles rapidly coalesce into large steam bubbles. This coalecing occurs both at the heating surface and in the body of the boiling water. The large steam bubbles are irregular in shape because of disstortion during movement in the boiling water and in many cases the nonspherical bubbles formed by coalescence do not have time to round out. An excellent review of antifoam development is also given by Denman, and the reader is referred to his paper for details. Early antifoams were based upon crudely refined mineral oils such as castor oil. These materials were not very effective and were prone to rapid hydrolysis in the hot alkaline boiler water to form soaps which promoted foaming. The result was an intensive search for more effective synthetic products. From this search have come the two major classes Qf antifoams used in boiler waters today-polyamides and polyoxy antifoams. A number of excellent polyamides are made from polyamines and carboxylic acids. For any given amine there will be a limited range of carbon atoms in the carboxylic acid for maximum effectiveness. Similarly, for a given acid the range of amines is limited. Denman gives examples of the most effective diamides that can be made from ethylenediamine or diethylenetriamine, the most effective triamides from diethylenetriamine and the distearoyl amides of dibasic acids and of alkylenediamines. Polyoxy antifoams are polyoxyalkyleneglycols and derivatives. They are made by taking a hydrophobic material and increasing its water solubility by ethoxylating it. One member of the more important groups in this series is the high molecular weigllt diether of polyoxyalkleneglycol. Some typical patents on antifoams for boiler water include the following:

gated, with the conclusion that both materials are no more corrosive than phosphates in properly controlled boiler applications. 1 2 5,128 The solubilization characteristics of both EDT A and NT A, particularly the former, have been used to remove boiler deposits. The chelant is fed to the system at a concentration in excess of that required to chelate the metal ions in the feedwater. The excess chelant will enter the boiler and react with deposits such as tricalcium phosphate and magnesium hydroxide. The calcium and magnesium will be chelated or solubilized. The sodium phosphate and sodium hydroxide, also formed, are soluble and all may then be removed by boiler blowdown. As is the case with precipitating type treatments, dispersants and polymeric materials are employed with the chelants. As previously pointed out, competing ions such as hydroxides and phosphates may cause precipitation to occur to some degree in the presence of the chelant. In such cases, the polymer is used to insure that precipitate deposition will be held to a minimum. Treatment for Carryover Carry over of boiler water with steam is often minimized by proper boiler design. Close attention to operating practices including restricting load swings, carrying proper water level, etc. also will reduce susceptibility to carry over problems. The major approach to be discussed here, however, will be the use of antifoams because their use is common in the control of chemical carry over problems.

1. Johnson: Diether of a polyoxyalkyleneglycoll 2. Denman: ene oxide.! 3!

30

"Pluronics" -polypropyleneglycol-ethyl-

3. Ryznar: Amine-ethylene oxide additon product! 32 4. Johnson: Triliydroxpolyalkylene ethers of alkylenetriols and their reaction products with propylene or ethylene oxides 5.Bird and Jocoby: Symmetrically unsaturated diacylated polyamines! 34

Denman! 29 used high-speed photography to illustrate his theory of the mechanism by which antifoams function. His photographs of a foaming boiler show that numerous 209

'I

will cause cracking. As Evans points out, an adequate hydroxyl reserve is not necessarily the same thing as high pH value, since a good buffer system can maintain a supply of hydroxyl ions, replenishing those used up in film formation without giving a high pH. The problem then is to use a system which substitutes something else for most or all of the NaOH as a source of alkalinity. The coordinated pH approach rests upon the premise that the alkaline pH should come from trisodium phosphate as much as possible rather than from NaOH. The amount of phosphate which may be present should be compatible, however, with the need for a boiler-water content oflow dissolved solids. Pincus' b found that corrosion and scale formation in

6. French Railroad: Formaldehyde-amide condensation product'3S 7. Villar: Wetting agents plus isomyl alcohol47 While certain waters appear to require a particular type of antifoam, there are a number of factors which have an effect on antifoam efficiency. Sampling of steam for purity determination can be an important part of an inhibitor program.' 36 Periodic samples are taken to screen the antifoam program for assurance that high quality steam is being produced. Frequently, in-plant steam studies are utilized to evaluate antifoam effectiveness.' 37 Since carryover in the range of only 60 to 100 ppb can cause serious turbine blade deposits, steam purity measuring techniques are of prime importance. Metcalf' 36 reports that the sodium tracer technique is the preferred method of testing. Most commercial antifoams sold today are blends of several materials. The additon of other materials, such as powdered tannin, desulfonated lignin, Na2C03, polyphosphates,' 32 humates or starches,' 29 appears to improve the overall performance. It is likely that these other materials act as dispersants for the antifoams. Selective ion vaporization or carryover also can be a severe problem. Silica deposits on turbine blades are a frequent problem because of this selective characteristic. Severe problems also have been experienced with aluminum deposits. ' 39 Such selective carry over is attacked by removing the ions from the makeup or feedwater, or in some cases, by limiting concentrations in the boiler water. Boiler water silica concentration is usually regulated to assure less than 0.02 ppm silica in the steam.

low-pressure boilers could be held to a minimum by maintaining the boiler water at a hydroxide alkalinity of 100 to 350 ppm and a total alkalinity of 300 to 500 ppm, both expressed as CaC03. He used silicates, carbonates, phosphates and chromates to make up his nonhydroxide alkalinities. Alkalinities up to 1000 ppm did no harm. Hamer6 controlled corrosion of boilers operating below 200 psi by keeping total alkalinity at 10 to 15% of the total dissolved solids. When the boilers went over this pressure, he also deoxygenated the water. Clarke and Ristain06' used the coordinated phosphate-pH control for the Submarine Thermal Reactor Boiler with considerable success when the metal surfaces were immersed in water. Rath' 40 found that alkaline phosphates protected boiler steels subjected to a substantial amount of stress and the combined action of caustic soda and silica. A ratio of Na3P04 to NaOH equal to or greater than one was necessary to prevent caustic cracking. Akolzin, Kagan and Kot'4' in a study of drum-type boilers w.!!hout stages of evaporation, found that the excess P04 = concentration should be maintained below 40 ppm and NaOH alkalinity at 9 ppm minimum. For boilers with stages of evaporation, the last stage should show a maximum of 100 ppm P04 and a minimum in the boiler of 5 to 7 ppm, with the water tinged by phenolphthalein. Schroeder, Berk and Partridge'4 2 said that a ratio of Na3P04 to NaOH equal to or greater than one was necessary to prevent cracking. They postulated that the protective mechanism was the precipitation of phosphate in capillary crevices before NaOH therein would attain the dangerous concentration of about 4%. Data developed by a number of water-treatment companies over a period of many years have shown that phosphated waters which produced cracking invariably had more NaOH than P04. Brooke3, on the other hand, presented data which he interprets as meaning that the use of an Na3P04 to NaOH ratio is without merit and that Na3 P04 functions well only in the absence of hydroxide ions, a situation which occurs only infrequently in boilers.

Corrosion Reactions in the Boiler It has been said many times that the way to prevent corrosion in boilers is to keep oxygen out, maintain proper alkalinity and keep the surfaces clean. While this explanation obviously understates the ease of inhibiting corrosion, the basic principles are sound and their utility becomes apparent in this chapter. The problem of pitting was shown to be directly associated with the presence of dissolved oxygen and the development of deposits. The use of hydrazine or sodium sulfite together with the prevention of scaling are optimum means of minimizing this type of attack. The other corrosive agent, copper deposition, must be prevented by proper treatment of the feedlines and return lines. It should be noted that oxygen can enter the system by leakage, so it is essential to insure that an excess of sodium sulfite or hydrazine is present in the boiler. One method of insuring this excess is to add some of the oxygen scavenger directly to the boiler on a continuous basis. The problem of corrosion, because of high localized NaOH concentrations, is generally attacked by one of a number of methods, all of which rely on proper ratios of various salts and alkalinity in the boiler-water. Thus, the need for close control of boiler-water composition and frequent analysis to verify the control becomes apparent. The pH control situation is very complicated because while the hydroxyl ion will passivate the surface, too much

Evanss says that if the water contains sodium phosphate with a ratio of Na2 0 to P20S slightly lower than that corresponding to a solution of pure Na3P04, then in the body of the water, a concentration of hydroxide ion can be maintained by hydrolysis which is sufficient to prevent ordinary corrosion, but not to cause an excessive 210

hydroxide-ion concentration in the seams or recesses. Once the concentration has reached the level at which solid Na3 P04 is thrown out, the concentration of hydroxide ion cannot rise further. He further says that Na3P04 generally need not be added, but that if the water is already alkaline, Na2HP04 or (NaP03) which reverts in the boiler can be used.

11.5

11.0

10.5

Whirl and Purcelll 4 3 presented the curve shown in Figure 1. This curve, which has frequently been used by proponents of the phosphate approach, gives the relationship between pH and phosphate concentration and shows the areas in which caustic or phosphate will occur on evaporating surfaces. When pH and phosphate values intersect below the curve, the residue will be phosphate. Above the curve, free caustic will be present.62 Boiler water conditioned so its characteristics are represented in the area below the curve can be concentrated without

J:

a. , Maintain pH Below This Line To Avoid Excess Caustic

10.0

9.5

raising the hydroxyl ion concentration appreciably. I 2 Another approach to the prevention of caustic cracking involves the maintenance above a certain value of the ratio

9.0 o

of sodium sulfate to alkalinity in the boiler water. This method is subject to considerable dispute and there are two schools of thought as to its value. Akimovs 8 says that this approach is satisfactory. He says that the mechanism functions when the concentration of alkali in the joints and seams becomes dangerous and sulfate precipitates and protects the metal from the action of the alkali. In an examination of the basic soundness of the sulfate treatment, Weir and Hamerl44 state that the mechanism is either the deposition of solid Na2 S04 or CaS04 on the highly stressed parts of the boiler plate or the plugging of a seam. Stanisavlievici 14sand Hamer 7 in more recent publications state that Na2 S04 has an inhibitive action. The American Society of Mechanical Engineers Boiler Code of 1940 recommended maintenance of a high sulfate to hydroxide ratio for prevention of embrittlement, although more recently the American Railway Engineers Association 146 recommended that this procedure be disregarded on the basis that operating experience showed it to be without merit.

50

100

150 P04 Concentration - ppm

200

250

FIGURE 1 - Relationship between pH and P04 concentration in terms of prevention of excess caustic. (Figure courtesy of S. F. Whirl. Trans. ASME, (1942).

alkalinity by replacing Na ion with H ion. Both of these approaches appear to indicate that the SO" ion itself is not an inhibitor. The neutral salt approach is suggested by Hall.S2 It advocates maintaining in the boiler water a high concentration of neutral salt, such as sodium sulfate, relative to the amount of hydroxyl ion present. This approach is similar to the method proposed by Kagan and his co-workers. Straubl48 also recommends this approach, which reduces the effect of the caustic through the dilution effect of added salt on the boiler water concentrates. The most widely accepted chemicals for the prevention of caustic embrittlement are the nitrate ion and quebracho extract. Andres,49 Brooke,3 Podgornyi,S4 Akolzinl49 and many others show that nitrate is very effective for this purpose, while Parkins,s S Hecht et ai, 13 Andres49 and others describe the successful use of the quebracho extract. The amount of nitrate used is critical and Brooke3

Evanss makes a detailed analysis of the sulfate-ratio controversy. He points out that any beneficial effects might be attributed to keeping tlle hydroxyl-ion concentration low, rather than to keeping the sulfate-ion concentration high. The former can be defended on sound theoretical grounds, whereas the latter is a matter of conjecture. He studied results of this treatment in England and concludes that the value of tlle sulfate is doubtful. Hecht, Partridge, Schroeder and Whirl in tlleir chapter on boiler corrosion in Uhlig's Corrosion Handbookl3 go even further and make the flat statement that "sodium sulfate does not prevent cracking embrittlement of detector specimens." Kagan et ai, 19,14 I state that if chemically treated water is used along with condensate as the feedwater, then the ratio of (CI-) plus (SO,,) to NaOH should be no less than 5. Akolzin and Ratnels I ,147 recommend that exces-

states that tllis must be 4Q'fo of tlle total alkalinity calculated as NaOH. PodgornyiS 4 found tllat 35% gave the best results. Hecht et all 3 say that sodium nitrate has been used at pressures up to 750 psi and tllat concentrations

TABLE 4 - U.S. Bureau of Mines Ratios of Sodium Nitrate/Sodium Hydroxide to Boiler Pressure

Up

to

psi

250.

400. 700.

sive alkalinity be reduced by neutralizing with H2 S04 and then using an ion-exchange resin to free the water of excess 211

Ratio NaN03/NaOH 0.20 0.25 0.40

should be maintained

at about 20 or 30% of the NaOH

alloys. Sodium sulfite can be added to the condensate system when oxygen cannot be eliminated in any other manner. A preferred approach is to increase condensate pH with volatile amines. Raising the pH of the condensate will minimize oxygen attack. A very successful approach to the problem of acidic corrosion caused by carbon dioxide cal1s for using volatile amines. They are added to the boiler water, volatilize along with the steam, condense with it, neutralize the carbon dioxide and produce a condensate having a neutral or alkaline pH. Alternately, they can be added to the steam lines. In either event, they stay with the steam and condense with it, thus providing alkaline material at the places it is needed. A number or amines have been employed for this purpose. The most obvious one and the first studied was ammonia. Some of the earliest demonstrations of the effectiveness of ammonia were reported by Straub 7 and Leick. 150 The material is generally added as ammonium hydroxide or ammonium sulfate to the boiler feedwater with the resultant liberation of ammonia in the boiler. The major use of ammonia is in central stations with low percentage makeup and low carbon dioxide concentrations in the steam. I 5 I When carbon dioxide concentrations are

alkalinity. The V.S. Bureau of Mines recommends using ratios depending on boiler operating pressure as given in Table 4. Potassium nitrate functions as wel1 as the sodium saltl 45 and waste sulfite liquors containing NaN03 are also effective.47 ,13 6 Tanninsl45 and butyric acid (in the amounts of 0.5% of the amount of alkali present)54 are also effective in preventing caustic embrittlement. Phillips and Singlel4 present a very interesting study of methods of preventing chloride stress-corrosion attack of austenitic stainless-steel-tubed steam generators in nuclear power plants. They used an alkaline-phosphate boiler water containing up to 500 ppm chloride and found that sodium nitrate and sodium sulfite were effective inhibitors. The combination of the two was superior to either inhibitor alone or to any other inhibitor or combination. The erosion-corrosion problem in boiler tubes is attacked by 1. Redesigning the system to avoid turbulent flow, 2. Eliminating deposits and keeping the tubes clean, 3. Preventing corrosion of the copper in the preboiler and post boiler systems, and 4. Maintaining proper dosages of the corrosion inhibitors previously mentioned, especial1y the oxygen scavengers. The solution thus becomes a combination chemical approach.

quite high, as they tend to be in industrial plants, the required ammonia level for neutralization becomes high and this treatment runs into the disadvantage of serious corrosion of copper and zinc-bearing metals. I 5 I ,152 For this reason, other neutralizing amines have been developed which are not corrosive to copper at the dosages requircd for carbon dioxide neutralization. An instance of the

physical and

Controlling Post Boiler Corrosion Superheater It was pointed out earlier that the corrosion of metal by steam at very high temperatures is not readily prevented by the use of corrosion inhibitors. The most satisfactory preventive technique involves the choice of suitable al1oys, a procedure beyond the scope of this book. Carryover of salts by steam is best attacked by preventing carryover. This is usually accomplished in the boiler by using properly designed steam separators and anitfoam agents. Corrosion due to condensation of steam in superheaters is treated in the same manner as corrosion of steam condensate and return systems. This subject discussed in detail in the fol1owing section.

ineffectiveness of ammonia is described by Sperry I 53 who was attempting to protect turbines in generating stations from corrosion. He found that when ammonium compounds were added to the boilers, the resulting ammonia was largely lost in the steam and resulted in a lowcondensate pH and serious corrosion of condensatc pumps. The two neutralizing amines used most frcqucntly today are morpholine (C4 Hg NO) and cyclohexylamine (C6 HII NH2). Both chemicals are being sold in considerablc Liuantities under different trade names by inhibitor manufacturers. Jacklinl54 states that the vapor pressure of morpholine is such that even at low concentrations in boiler water it vaporizes and the proper proportion condenses with the first droplets of condensate which form in the system. Most other amines have vapor pressures which are too high or too low and consequently do not condense in the first-formed droplets, leaving a critically important part of the cycle unprotected. Maguire I 5 1 also poin ts ou t that this feature (prevention of acidic corrosion at the point of initial condensation) is valuable in large central-station turbines and that this is an example in which morpholine provides better control of corrosion than is possible with ammonia.

will be

Steam Condensate and Return Systems The earlier discussion of the causes of corrosion in the steam condensate and return systems indicates that the corrosion agents are oxygen and carbon dioxide. The development of corrosion inhibitors for these systems should therefore bear these two factors in mind. The first problem, corrosion due to oxygen, is general1y attacked by techniques described for eliminating the oxygen content of boiler water. This method usually insures that oxygen present in condensate will be derived essential1y from leaks in the return systems. When oxygen leakage into the return system becomes sufficient to promote corrosion, then the preferred solution is a mechanical one designed to eliminate the leaks or else a metal1urgical one calling for using proper

Patzeltl 55 calculated that at 25 C, the pH at which carbonic acid is completely converted to morpholine bicarbonate is 7.3. He found that in actual experimental work, a slightly higher pH value was desirable because of slower inhibition at the lower pH value. He also found that contamination of the condensate by ] % of a synthetic 212

concentrations of carbon dioxide make the use of neutralizing amines uneconomical. Early unsuccessful attempts to accomplish inhibition by film forming techniques involved materials such as sodium silicate, oils or polyphosphates. Sodium silicate I 3 reduced corrosion but could not prevent it entirely. It was postulatedl3 that the protective mechanism might involve the formation of a silicon dioxide film on the metal surface, the neutralization of carbon dioxide by the alkali, or both. Addition of oil to condensate showed that inadequate quantities might accelerate rather than decelerate corrosion on those surfaces not covered by the oil. 73 Polyphosphate treatments have been added to return lines in a number of steam-generating plants with some experiments by degree of success. I 55 Laboratory Patzeltl55 showed, however, that long times are necessary to allow the development of a protective film on the metal surface. This development time is a considerable disadvantage, because during the interval, corrosion may have proceeded to such an extent that it no longer can be treated. Hanlonl61 notes the impermanence of such phosphate films and Ulmer and Wood71 point out that it is necessary to maintain the dosages of these materials at their original values to prevent dissolution of the ftlms. Further, condensate returned to the boiler would contain the

boiler water raised the pH from 7.3 to 8.0 and lowered the untreated corrosion rate. This latter phenomenon was said to agree with field observations that plants having trouble with boiler-water carry over in the steam usually do not have condensate corrosion problems as serious as those where there is no carry over. Sperryl 52, in the case of volatile amines for turbine protection cited previously, found that morpholine was much more effective than ammonia. 1t is stable at high temperatures and pressures and is evenly distributed. For effective corrosion control, a pH of 8.8 to 9.0 and a morpholine residual of 3 to 4 ppm are maintained. Mondoux and Jacklinl 57 state that morpholine is stable up to a boiler pressure of 2500 psi and to 1200 F in superheated steam. A number of articles have appeared in the literaturel 58-160 reviewing the advantages of cyclohexylamine and dicyclohexylamine as inhibitors for the prevention of the corrosion of iron by steam condensate containing oxygen and carbon dioxide. Several other volatile amines have been evaluated for this purpose. Included among them are benzylamine, 16 I 2-diethylamineothanol, 15 7 ethylene diamine, 13 and amine alcohols. 16 I The concentration of an amine at any location in a steam-condensate system is dependent on the distribution ratio. This ratio is a comparison of the amount of amine in the steam versus the amount present in the condensate. The ratio for cyclohexylamine is 3 whereas that for morpholine is only 0.4. This would indicate that the greater concentration of morpholine will be found in the condensate. This characteristic makes it well suited for applications in central stations where protection is required in the wet end of high pressure turbines. The relatively high distribution ratio of cyclohexylamine makes it more applicable in extensive steam-condensate systems found in industrial plants. The differing distribution ratios of the volatile amines have been used in commercial return line corrosion inhibi-

additives. Silicates and phosphates could upset boiler water balances, causing extremely high concentrations of these salts, resulting in deposit formation, while the return of oil to the boiler could cause carryover and/or the accumulation of objectionable oily deposits. The earliest record of successful application of filming amines to steam-condensate systems was disclosed by Kahler.1 62 The use of long-chain nitrogenous compounds as film-formers for condensate and return lines has been very successful. They do not normally accumulate in the boiler because they either are eliminated at the vent of the deaerating heater or steam distill from the boiler water. While a number of materials are now being employed, octadecylamine (Cl 8 H3 7NH2) and its salts are most frequently used and typify this class. The following discussion as to the possible protective mechaanism will therefore revolve around octadecylamine. Octadecylamine does not function by neutralizing carbon dioxide in the system. There is usually too much carbon dioxide present in relation to the amount of amine for any stoichiometric reaction to occur. In addition, because the amine is not volatile and adheres to all metal surfaces, not just spots at which condensation occurs, even less amine is available as a neutralizing agent. The inhibitor is fixed to the metal surface and thus the amine portion is not sufficiently mobile for neutralizing purposes. It is obvious, then, that another mechanism, most likely that of a protective-film formation, must be involved. An observation of the physical appearance of a metal surface treated with octadecylamine gives a clue to the inhibitory mechanism. Water condenses on such a surface in the form of droplets rather than as a uniform film. Surface

tors. These inhibitors are generally combinations of morpholine and cyclohexylamine so blended as to obtain the benefits of the differing distribution ratios. Amine requirements are approximately 3.6 ppm morpholine (40%) or 3.0 ppm cyclohexylamine (40%) per ppm of carbon dioxide to elevate condensate pH to 7.0. The volatile amines can be added to the steam condensate system by additon to the feedwater, boiler, or return lines. Ulmer and Wood71 discuss the advantages and disadvantages of each approach in some detail. They prefer direct addition to the boiler or else the feedwater. Hanlonl61 points out one objection to this method in that it becomes necessary to treat the entire system to obtain adequate protection in a desired localized section. In the latter case, the preferred method is direct injection of the inhibitor into the steam or condensate lines by means of a chemical feed pump.7 I Another approach to prevention of steam condensate and return line corrosion is that of using "film-forming" chemicals to lay down a protective film on surfaces. This approach has come into widespread use with the development foe this purpose of suitable long-chain nitrogenous materials. It is especially effective in systems where high

wetting is minimized because the protective hydrophobic organic film which is already present repels water and acts 213

as a barrier between the metal and the corrosive condensate, thus protecting it against both oxygen and carbon dioxide attack. The result is a much better transfer of heat from the steam through the metal and a minimum formation of heat-insulating corrosion products. This dropwise condensation effect has been shown by a number of authors, including Cannon! 63 and Maguire.! 51

The "wetting" or degree of coverage of metal surface by inhibitor is really a function of two factors: 1. The strength of the chemical bond and 2. The orientation, shape and size of the long-chain portion of the molecule. The orientation of the nonpolar portion of the molecule will determine directly the fraction of metal surface it covers and this amount, in turn, will determine directly the effectiveness of the protective film. Nathan! 67 shows that branching of the alkyl chain decreases inhibitor efficiency. He postulates that the geometrical nature of the nonpolar radical should be such that a close interlocking of the hydrocarbon chains is possible. Molecular models show that such interlocking is impossible when the chains are branched as is shown by Bigelow, et al. ! 68 The length of the carbon chain appears to have a direct bearing on the effectiveness of the inhibitor. In the case of straight-chain primary aliphatic amines, Wilkes, Denman and Obrecht! 69 state that the carbon chain must be in the C! 0 to Cl 8 range for maximum effectiveness. Denman 170 in a patent of a formulation based on octadecylamine says that the Cl 2 -20 chains are preferred and Osipowel 71 requires Cl 3-2! for his long-chain amide-alcohol mixture. Mann et all 63 found that the efficiency increased as a direct function of chain length. They also contend that the efficiency of an amine inhibitor is related directly to the surface area it covers. Octadecylamine frequently is formulated so as to improve its feeding characteristics and also to aid the inhibitor in wetting sufaces rapidly. It is generally used as the acetate salt for easier feeding. Wetting characteristics are improved by blending or emulsifying it with suitable wetting agent. Thus Denman,170 for example. has blended octadecylamine with a nonionic surfactant and a small amount of cyclohexylamine in the ratios of 90 to ') to I and treated the mixture in a colloid mill to make a stable

The adsorbed film on the metal surface is believed to be substantially of monomolecular thickness that does not increase with continued treatment. 1S! No study has been reported in the literature on the mechanism by which the long-chain amine is bound to the metal surface in this specific system. A review of general theories developed for film-formers, taking into account the particular conditions involved here, can serve a worthwhile purpose, however.

Theoretical Aspects of Long-Chain Organic Nitrogenous Inhibitor Mechanisms There is no accepted theory for the exact mechanism by which long-chain organic nitrogenous inhibitors function. The division of materials into cathodic and anodic inhibitors which serves for many inorganic materials cannot be employed here, although many believe that there is some degree of inhibitor-ion orientation at the cathodes on the metal surface in the case of nitrogen derivatives. Thus, Mann, Lauer, and Hutlin16 3 conclude that amine cations are adsorbed on the cathodic regions of the metal surface in such a manner that the nitrogen atom is linked directly to the metal. The result is a monomolecular layer of amine ions on the surface. Hackerman and Sudbury!64 on the other hand, in studying the polarization phenomena of amine additives in water and sulfuric acid, found indications that both anodic and cathodic areas might be affected by the inhibitor. Anodic inhibition is explained on the basis of migration of electrons from the metal to the positively charged inhibitor rather than toward the cathodic areas within the metal.

emulsion. This mixture also has the advantage of eliminating corrosion which frequently occurs with the acetate salt at the point of introduction. Maguire found that this problem can be overcome by proper blending of octadecylamine and octadecylamine acetate. 172 Sato and Kato! 73 evaluated salts of octadecylamine with (I) "maleinated methyloleate;" (2) octadecanol and (3) oleic acid and they found the degree of effectiveness as rust inhibitors was in the same order.

Kuznetsov and lofa 165 also note that nitrogenous inhibitors produced anodic as well as cathodic inhibition. They explained the reactions by postulating that the adsorbed layer of positively charged inhibitor ions retards the transfer of metal cations from the surface into the solution and thus slows down the anodic reaction. There is no question, however, that the polar end of the molecule is the active participant in the adsorption process. Whether the initial adsorption is really chemisorption or physical adsorption by van der Waals forces followed by chemisorption has not been satisfactory resolved. Breston 166 states that both reactions probably occur simultaneously, chemisorption taking place at the "active spots" and the remainder of the surface being covered by the balance of the inhibitor held by physical forces. However, after a short period there does exist a strong covalent bond between the polar group of the inhibitor and the metal surface. The literature is replete with examples showing a direct relationship between the strength of this bond and the effectiveness of an inhibitor.

Other film-forming inhibitors reported in the patent literature include the following: 1. Ryznar and Kirkpatrick: Reaction product of an organic carboxy acid and a polyamine; e.g., amide mixture from reacting oleic acid, tall oil and diethylenetriamine.! 74 2. Osipowe: Mixture of high molecular weight primary aliphatic amides and alcohols of the general formulas CnH2n+1CH20H and CnH2n+1CONH2 where n = 13 to 21.17! An example is a mixture of octadecyl alcohol and stearamide. 3. Denman and Hwa: Imidazolines with side chains from Cl 2 to C! 8 and pyrimidines with similar side chains.! 75 214

attack can occur. Patzeltl 55 investigated octadecylamine acetate at 10 ppm and an unidentified proprietary material at the same level. He found that corrosion continued over a

The film-forming inhibitors, as well as the emulsifying or dispersing materials that may be used with them, have strong surface active properties. Consequently, their introduction into the system can result in the loosening of previously formed deposits and clogging of the lines by these materials. For that reason it may be better to clean the lines before starting to use the inhibitor or alternately to clean out the system after the loosened deposits have begun to accumulate. This cleaning will improve heat transfer as well as corrosion inhibition.

long time, although at reduced rates. It would thus appear to be desirable to start treatment at a high dosage level to lay down the protective film rapidly and then to reduce the treatment level to that necessary to maintain and repair the film. There is some disagreement as to the desirable feeding point for film-forming inhibitors. All inhibitor suppliers say that the materials can be fed directly to the steam and condensate systems. Some suppliers recommend adding the inhibitor to the feedwater or directly to the boiler and say that the inhibitor will evaporate with the steam and condensate in a thin, continuous film. However, most of the commercially available filming inhibitors are formulated products, each component having a somewhat different volatility (and solubility) and, therefore, the preferred point of addition should be the steam header. In some cases, the use of mming amines has led to deposit formation, particularly following the use of the first developed inhibitor, octadecylamine acetate. These deposits were polymerized amine and oil-oxide combinations. It was originally thought that overfeed of the inhibitor was the only cause of these accumulations, but investigation led to the conclusion that the octadecylamine acetate had polymerized with iron oxide and/or oxygen. Improved formulations were developed to eliminate this problem. Current commercial inhibitors have stabilizing agents which inhibit polymerization and thus deposit formation. I 79 An outgrowth of the search for increased corrosion control in condensate systems was the blending of neutralizing amines with filming amines. Experience with these newer inhibitors has shown a more even distribution of

The use of film-forming inhibitors becomes economical when the carbon dioxide content of the steam is so high that the cost of using sufficient neutralizing amine is excessive. By contrast, the dosage of mming amines is independent of dissolved gas concentration. Typical dosage levels are given by Denmanl70 to be 0.5 to 10 ppm with 2 ppm as the recommended level. Kahler and Brown,1 52 on the other hand, recommend levels of 15 to 30 ppm of a commercially dispersed filming amine to establish and maintain the desired corrosion resistant mm on the metal surfaces. By using a treatment level of 3 to 4 ppm of octadecylamine, Akolzin, Zaitseva, and Lazareval76 achieved satisfactory inhibition of corrosion of the distribution system of a large process steam plant caused by 2 ppm oxygen and 4 to 5 ppm carbon dioxide in the condensate and makeup. Interruption of treatment for a few hours could be tolerated because of the film that had been built up. Osmond and Welder76 investigated corrosion in a desuperheating condensate system where low pressure shells were badly corroded and fittings in the spillover system and piping from the condensate storage were severely attacked. They used a commercially available formulation based on octadecylamine with 2 ppm of inhibitor and reduced the corrosion rate of steel panels in the desuperheating condensate system from 1285 mg/dm2 / day to less than 1 mg/dm2/day. Ryznar and Kirkpatrickl 74 recommend the use of 10 ppm of their inhibitor, while Denman and Hwa I 75 use I to 10 ppm of their imidazolines and pyrimidines. Osipowel71 cut the corrosion rates of steel panels exposed to water and steam in half by using 25 ppm of his alcohol-amide mixture. Elliott and Gaughan I 77 claimed to have saved $14,200 per year in corrosion costs at one plant by the use of octadecylamine. Other savings in dollar figures cited for the use of film-forming amines include those of Maguire,1 5 1 who quotes a yearly reduction of $8000 maintenance costs by a small industrial plant producing 300,000 pounds of steam daily and a reduction of $40,000 by a plant generating 5,000,000 pounds of steam daily. The rate at which the protective film builds up is quite important. Ulmer and WOOd71 ran time studies on two proprietary film-formers. One was the "octadecylamine type" at 30 ppm and the other was a "quaternary ammonium salt type" at a dosage of 20 ppm. They found that the corrosion rate decreased as a function of time, but there was still considerable attack even after 28 days. They point ol1t that the film-forming inhibitors can be classified as "dangerous." If enough inhibitor to form a continuous film is not used, then anodic action leading to severe local

amines in complex steam condensate systems, resulting in improved overall corrosion protection. The combined amines are usually fed at rates sufficient to develop a continuous film throughout the entire system. Most of the increased benefits of the combination amines are thought to be a result of synergistic action of the amines, since the concentration of neutralizing amines is generally insufficient to provide protection from carbon dioxide corrosion.

High Temperature Hot Water Systems A high temperature hot water system is usually defined as a system operating above 300 F (149 C). The corrosion problems associated with such systems were summarized by Hayman. I 8 0 These factors are as follows: 1. Acidity (low pH due to carbon dioxide and/or decomposition of organic matter). 2. Dissolved gases (primarily oxygen). 3. Galvanic action (due to contacts among dissimilar metals). In a properly designed system there is little opportunity for scale formation. because there is no evaporation within tlle system and thus little makeup water is needed. Therefore, solids in makeup water do not concentrate and saturation values are not exceeded. However, when de· 215

signing such a system, it is a good practice to include the use of pretreatment such as zeolite softening. Demineralized water also is used sometimes as makeup. Characteristics of makeup water are important with respect to corrosion in high temperature hot water systems. If the circulating water pH is properly adjusted, much of the corrosion potential can be minimized. In all-steel systems, the pH can be adjusted to 11.0 to minimize corrosion. However, in bimetallic systems, pH values should not be allowed to reach this level because of possible reaction of the alkalinity with brass, bronze, copper and/or aluminum. Before a new hot water system is put into operation, it should be cleaned of all pipe dope, grease or cutting oils, dirt, sand and soldering flux. If these substances are not removed, they may result in the formation of concentration cells and greatly increase the corrosion load. Phosphates are most commonly used for cleaning. A satisfactory cleaning solution is a 2% solution of sodium hexametaphosphate or sodium tripolyphosphate. Chromates, nitrates, nitrites, boratils and silicates have been employed as corrosion inhibitors in hot water circulating systems. However, their use must be carefully controlled because they can cause problems in mechanical or patent circulating pump seals. Evaporation can occur, resulting in crystallization of the 'inhibitor with resulting wear on moving parts. Buffered chromates at 150 to 250 ppm concentrations have been employed successfully.

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109. J. A. Gray. Boiler-Water Treatment: A Formula for the Control of Sludge and Scale in Internal (Carbonate) Treatment., J. Inst. Fuel, 30, 577-91 (1957).

218

161. R. T. Hanlon. Causes and Prevention of Condensate Return Line Corrosion, Proc. Midwest Power Cont., 10, 134-40 (1948). 162. H. L. Kahler. Method of Protecting Systems for Transporting Media Corrosive to Metal, V.S. 2,460,259, Jan. 25, 1949. 163. D. R. Cannon. More Heat Less Corrosion. Chemicals and Raw Materials, Chem. Eng., 62, 140-2 (1955) April. 164. C. Mann, B. Lauer and C. Hutlin. Organic Inhibitors of Corrosion-Aliphatic Amines, Ind. Eng. Chem., 38, No. 9, 1049 (1936) Sept. 165. N. Hackerman and J. D. Sudbury. Effect of Amines on the Electrode Potential of Mild Steel in Tap Water and Acid Solutions,J. Electrochem. Soc., 97, 109 (1950). 166. V. A. Kuznetsov and Z. A. Iofa. Inhibitor Action on Solu ion of Iron in Acids, Zhur. Fiz. Khim., 21, 201 (1947). 167. 1. N. Breston. Corrosion Control With Organic Inhibitors,lnd. Eng. Chem., 44, No. 8, 1755-61 (1952) Aug. 168. C. C. Nathan. Studies on the Inhibition by Amines of the Corrosion of Iron by Solutions of High Acidity, Corrosion, 9, No. 6, 199-202 (1953) June. 169. W. C. Bigelow, S. C. Pickett and W. A. Zisman. 01eophobic Mono1ayers. I-Film Adsorbed from Solution in Nonpo1ar Liquids,J. Coli. Sci., 1, 513 (1946). 170. J. F. Wilkes, W. L. Denman and M. F. Obrecht. Filming Amines. Vse and Misuse in Power Plant Water-Steam Cycles, Natl. Eng., 59, No. 6, 20-3,42 (1955). 171. W. L. Denman. Corrosion Inhibitors, V.S. 2,882,171, Apr. 14, 1959. 172. L. 1. Osipowe. Corrosion Inhibition in Steam and Water Systems, V.S. 2,890,928, June 16, 1959. 173. 1. J. Maguire. Octadecylamine Materials and Process, V.S. 2,712,531, July 5, 1955. 174. S. Sato and Y. Kato. Rust-Preventive Additives. Salts of Some Organic Acids With Octadecylamine, Kogyo Kagaku Zasshi, 61,69-72 (1958). 175. J. W. Ryznar and W. H. Kirkpatrick. Inhibition of Corrosion in Steam-{:ondensate Lines, V.S. 2,771,417, Nov. 20, 1956. 176. W. L. Denman and C. M. Hwa. Corrosion Inhibitors for Steam and Condensate Lines, V.S. 2,998,193, June 2,1959. 177. P. A. Akolzin, Z. 1. Zaitseva and L. 1. Lazareva. The Prevention of Oxygen and Carbon Dioxide Corrosion With the Vse of Octadecy1amine, Teploenergetica, 5, No. 10, 54-5 (1958). 178. E. Elliott and P. 1. Gaughan. Plant Stops Return-Line Corrosion-:-Saves $14,200 a Year, Power Plant Eng., 55, No. 8, 104-9 (1951) Aug. 179. 1. R. Metcalf. Return Line Corrosion Control, The Betz Indicator, 35, No. 11 (1966) November. 180. R. H. Hayman. Corrosion Control in Hot Water Heating Systems, Heating, Piping and Air Cond., March, 1961.

141. P. A. Akolzin, D. Y. Kagan, and A. A. Kot. Safe Regimes for Alkaline Boiler Waters, Teploenergetika, 4, No. 6, 32-5 (1957). 142. W. C. Schroeder, A. A. Berk and E. P. Partridge. Proc. ASTM, 36, Part 2 (1936). 143. T. E. Purcell and S. F. Whirl. Protection Against Caustic Embrittlement by Coordinated Phosphate-pH Control, Trans. Am. Soc. Mech. Engrs., 64, 397-402 (1942). 144. C. D. Weir and P. Hamer. Caustic Cracking in Boilers: Prevention by Chemical Methods, Chem. and Ind., No. 43, 1040-9, Oct. 25, 1952. 145. L. Stanisavlievici. Prevention of Caustic Corrosion in Steam Boilers, Energetic, 4, 269-72 (1956). 146. American Railway Engineers Society. Amer. Ry. Eng. Soc. Bull. 490, Chicago: Amer. Ry. Eng. Soc., 1950. 147. P. A. Akolzin and A. V. Ratner. Intercrystallite Corrosion of the Metal of Cylinders and Pipes of High-Pressure Boilers, Vnutrikotlovye Fiz.-Khim. Protsessy, Akad. Nauk S.S.S.R., Energet. Inst. im. G. M. Krzhizhanovskogo, 384-95 (1957). 148. F. G. Straub.Mech. Eng., 61, 199-202 (1939). 149. P. A. Akolzin. The Role of the Boiler-Water Components in the Development of Intergranular Cracks in Boiler's Metal, Metody Borbys Neyo Sbornik, 71-86 Korroziya Metal. (1955); Referat. Zhur. Khim. 1956, Abstr. No. 41943. ISO. J. Leick. Arch. Metallkunde, 3, 100-5 (1959). 151. 1. J. Maguire. After Boiler Corrosion,lnd. Eng. Chem., 46, No. 5,994-7 (1954) May. 152. H. L. Kah1er and 1. K. Brown. Experiences with Filming Amines in Control of Condensate Line Corrosion, Combustion. 25, No. 7, 55-8 (1954). 153. S. M. Sperry. Reduction of Iron and Copper Corrosion in Steam and Water Cycle With Amines, Combustion, 27, No. 5, 65-71 (1955). 154. C. Jacklin. Amines for Corrosion Prevention in Steam Condensate Systems, Corrosion, 9, No. 7,1 (1953) July. 155. H. A. Patzelt. Laboratory Method for the Study of Steam Condensate Corrosion Inhibitors, Corrosion, 9, No. 1, 19-24 (1953) Jan. 156. R. G. Mondoux. Reduce Corrosion in Your Return System, Modern Power and Eng., 48, No. 9, 84-86,154-6 (1954) Sept. 157. C. Jacklin. Experimental Boiler Studies of the Breakdown of Amines, Trans. Am. Soc. Mech. Eng., 77,449-53 (1955). 158. W. K. Ashcroft and P. N. Heron. Cyclohexylamine in Water Treatment, Eng. and Boiler House Rev., 74,51-3 (1959). 159. Anon. Good Capacity for Absorbing Carbon Dioxide Makes Amine Vseful in Corrosion Inhibiting Formulations,- Chem. Processing, 14, No. 1,20 (1951) Jan. 160. W. K. Ashcroft and P. N. Heron. Cyclohexylamine for Corrosion Prevention in Steam-Raising Equipment, Corrosion Tech., 6, No. 3, 85-8 (1959) Mar.

i

219

Inhibitors for Temporary Protection

D. F. KNAACK and D. BROOKS*

Part 1 - Oil and Grease Coatings Because these polar compounds have a greater tendency than does water to be adsorbed on a metal surface, they are extremely effective in preventing corrosion. In fact, a number of special rust preventives with this property will disperse a film of water on a metal surface; accordingly, in some cases they are applied immediately after a final, water-rinse cycle. To be effective, polar materials must form a flexible, oriented, tightly held layer which has to be at least six molecules thick. Oil is retained in the interstices of this

Identification of oil and grease coatings as "temporary" is not strictly accurate in terms of length of time protection is provided. In fact, protection times afforded by some oil and grease coatings are counted in years, thus making the term "temporary" ambiguous. Nevertheless, the term is useful in helping users distinguish among the various kinds of coatings available and it is further sanctioned because it has been employed for a long time by persons experienced in the technology. In any case, the term is more acceptable than the expression "slushing oils", which is sometimes applied to characterize certain types of these materials. The wide variety of types, basic materials, thicknesses and modes of application of oil and grease coatings produces an extensive array of properties and efficiencies and makes possible their use over a broad range of applications. Some tests indicate that thin-film oil coatings do not confer lasting protection. Test data and experience, on the other hand, show that solvent-dispersed or thermoplastic materials have long-term protective capabilities even in aggressive environments.

layer, resulting in a film more impervious to water than either the additive or the oil alone.3 Rust preventives containing a polar compound protect more by electrochemical than by mechanical means. They are also much thinner than are types functioning only as barriers.

Types of Temporary Corrosion Preventive Films Conventional temporary corrosion preventive films may be classified into three major groups according to their bulk appearance: 1. Grease or petrolatum types 2. Oil types 3. Solvent types.

Mechanism of Protection Protection from oil or grease coatings is produced by either mechanical means, polar attraction or by both. Mechanically, the compounds interpose a barrier between the substrate and the environment; polar protection is conferred by the chemical or other bonding forces which 'produce an electrochemical interface between the substrate and the corrosive. Since there is usually little or no attraction between a metal surface and a mechanical film, the film thickness determines the degree of protection. True mechanical films usually are quite thick. One of the best known products of this type is Cosmoline! which was invented in 1869; however, modern modifications of the original material have been such that it now protects by a combination of mechanical and polar effects. As the need for protection increased with America's industrialization, special polar additives were developed for use in preservatives. There is a wide variety of these compounds, including metallic soaps of long chain fa tty acids, alkali and alkaline earth metal salts of petroleum sulfonates and oxidized petroleum residues.2 The exact composition of the polar additives and their derivatives is usually proprietary .information.

Grease or Petrolatum Types Grease or petrolatum types are probably the oldest rust preveQtives in use today. They usually contain inhibitors and an antioxidant. Softer, low-melting types are designed for moderate shipping and storage temperatures and mildly corrosive conditions. The harder, high-melting materials are designed for higher temperatures and more severe conditions. They are generally applied by hot dipping, spraying or brushing. Lubrication may be an important property, especially in the softer grades used to protect bearings. Solvent-cutback, emulsifiable, hot dip and oil-type petroleum base rust preventives may or may not contain additives designed to confer protection to surfaces from such corrosives as fingerprints.4 Thin mm coatings, mostly from solvent cutback formulations, are most popular, usually being deposited in thicknesses of about 0.2 mil. Medium thickness films are in the 0.6 to 0.8 mil 'range, while heavy films are from 2 to 3.5 mils.4 Although there is little choice between asphalt and. petroleum based products, asphalt base materials tend to be thinner and more easily sprayed. Because they are not compatible with conventional lubricants, asphalt coatings

*E. F. Houghton Co., Philadelphia, Pa.

220

must be removed in some cases before machinery can be used.4

3. Drywax, 4. Grease o~ petrolatum, 5. Oil, a. Conventional

Oil Type Protectives Oil types are slightly more complicated, depending on intended use. They may range from simple slushing oils based on an inexpensive mineral oil which contains appropriate inhibitors to relatively expensive oils based on synthetic fluids such as esters or silicones which also contain appropriate inhibitors. Oil-type coatings are available in all the desired viscosity grades. Some contain inhibitors and other chemicals to provide protection against high humidity, salt water and acidic fumes. They may have water-displacing and acid-neutralizing properties. Some may contain volatile corrosion inhibitors. In most cases, good lubricity is a

b. Fingerprint removing. Solvents are used to facilitate formation of films, for water displacement and to make application easier. Petroleum fractions or coal tar derivatives are customary, but water is being used with increasing frequency. Dry, asphaltic films are used mainly to protect noncritical surfaces, such as castings exposed to outdoor conditions. Dry clear resin and wax films may be used on both critical and non-critical surfaces. Depending on film thickness and consistency, they may protect under both indoor and outdoor weathering conditions. Petrolatum and oil films are used mostly on critical surfaces such as intricate pump parts, servo-valves, and bearings. The films are not always as neat to handle as are dry mms, but they impart lubricity and are easier to remove. Ordinarily, they are used for indoor protection and also, in many cases, in combination with barrier wrappings and packaging. Compositions of the fIlms are much the same as those of grease or petrolatum and oil-type rust preventitives described earlier.

requirement as well. Tests using a pulse polarizer demonstrated that a protective oil containing an inhibitor had the ability to restore a film after it had been broken down at the oil-metal interface by a pulse discharge. 5 Oils without inhibitors permit adsorption of oxygen or water on the surface, while rust preventive oils prevent this adsorption. It was also shown that good, rust preventive oils exhibit an oriented structure, while an oil without protective properties has random distribution. Uninhibited films will not prevent corrosion by moisture of a surface on which they are deposited because the films are easily displaced by water. Rust preventive oils, on the other hand, resist penetration by ions.s

Fingerprint Removers Fingerprint removers have been listed as a subdivision of oil film, solvent-type coatings. Because they serve to clean as well as to prevent corrosion, they require special comment. Fingerprint removers are used to clean fmgerprint residues from metallic surfaces. These residues are bodily excretions consisting principally of urea, salts, acids, water and natural body oils. This composition indicates that they are corrosive to most metals and should be removed from any critical surface being prepared for use, shipment or storage. Fingerprint removers are intended also as temporary corrosion preventives. This means that, following limited plant storage, they should be cleaned off and replaced with proper long term rust preventives.

Concentrates and Water Emulsions Concentrates and water-emulsifiable products are probably the latest developments in oil-type coatings. As implied, concentrates contain large percentages of inhibitors in the base oil and are suitable for dilution by the user with oil, solvents, petrolatum, or sometimes by water. The advantage of concentrates lies in their economy and lower plant inventories. Water-emulsifiable products resemble soluble cutting oils and sometimes are mistaken for them. However, this resemblance ends with the water emulsification. These oils

Synthetic fingerprint solutions have been formulated to provide a medium for testing removers and inhibitors. Natural fingerprint corrosivity varies not only from individual to individual but also from time to time for the same individual. 6

are designed to offer long term protection with minimal effect on nonferrous metals, performance not ordinarily found in soluble cutting oils. Their properties of fire resistance and low toxicity, along with low cost, have increased their popularity. These advantages are especially evident when they are compared to solvent-type mms. Emulsifiable coatings give reasonably good protection against fingerprints and absorb cutting oil and water from surfaces. Their drying time is longer than that of most solvent-type oils.4

Fingerprint removers contain water, chemicals for cleaning action, inhibitors, mineral oil and volatile solvents. They are usually tested in the laboratory for: 7 1. Stability over a wide temperature range. 2. Physical properties (e.g., flash point, viscosity, etc.) 3. Removing capacity. A test method involves using a synthetic fingerprint solution to print a test panel which is then treated with the product, rinsed with clean solvent, exposed to 100 percent static humidity and then examined for corrosion in the printed area. 4. Fingerprint suppression. This test measures the ability of a product to suppress corrosion that may occur

Solvent Type Oils Solvent type rust preventives may be classified with respect to the type of protective film formed: 1. Dry asphaltic, 2. Dry, clear resin, 221

from a fmgerprint under a film of the product if cleaning was not thorough prior to application. 5. Fingerprint handling. This measures the ability of a product, after application, to prevent fingerprint corrosion during further handling. 6. Protection tests, usually run in a humidity cabinet, determine the effectiveness of the product as a rust

5. Water Displacement. 11 Specimens are wet completely with water and immersed in the rust preventive. After exposure in a humidity cabinet, the specimens are examined for corrosion caused by undisplaced water. 6. Acid Neutralization. 12,13 Specimens are wet completely with dilute hydrobromic acid solutions or oil emulsions and immersed in the rust preventive. They are then removed and allowed to stand at room temperature or are placed in a humidity cabinet. Subsequently, the specimens are examined for corrosion caused by acid which was not neutralized.

preventive. 7. Corrosivity, or effect on metals test. This shows the effect of the product on both ferrous and non-ferrous metals. 8. Removability. Because it is advisable to clean off fmgerprint removers before application of a conventional rust preventive, it is important that they be easily removable.

7. Acid Fume Resistance. Coated specimens are placed in a closed chamber containing humidified acid fumes. Hydrochloric, sulfuric, sulfurous or acetic acids are most frequently used to produce these corrosive fumes. 8. Corrosivity or Effect on Metals. Specimens of different metals are coated individually or immersed in the rust preventive for specified times at elevated temperatures. Effect of rust preventive is measured visually or by weight change per unit area or both. The real significance of accelerated corrosion testing lies in the comparative evaluation of rust preventive films in specific environments. There are no positive time factors relating these tests to actual shipping and storage conditions. However, correct interpretation of accelerated corrosion test data will expedite the proper choice of a rust preventive. Laboratory and field tests of thin and thick film rustproofing compounds to be used on the exterior surfaces of motor vehicles cannot be correlated with marked

Methods of Testing Rust Preventives The ideal method of testing oil and grease coatings is to expose treated specimens in the environment that will be encountered. Unfortunately, the time factor makes this procedure impractical, so various accelerated tests must be relied upon. Accelerated tests selected should be closely related to the anticipated corrosive environment. For example, the Weatherometer(1) tests should be used to evaluate rust preventives intended for direct outdoor exposure. If possible, data from at least two different types of accelerated tests should be considered. Ideally, metal specimens and type of fmish should duplicate as closely as possible the metallic composition and finish of the work to be protected. Unfortunately, this would result in an insurmountable inventory problem in the laboratory. Therefore, most accelerated corrosion tests are run on plain low-carbon steel specimens with ground or smooth sandblasted surfaces. Commonly Used Accelerated Tfsts Descriptions of some of the commonly ated tests follow:

reliability. For example, salt spray (ASTM B 117-64) and immersion in 3 percent sodium cWoride solutions both produced results which could not be satisfactorily correlated with on-site exposures. 1 4

Practical Applications used acceler

To take full advantage of the protection available from rust preventives, their application should be handled in the following manner. First, the object to be protected should be considered with respect to its metallic composition, construction and surface finish. Secondly, the storage, shipping and operating conditions with respect to time, temperature and corrosive environment must be determined.

1. Humidity Cabinet.s Coated panels are subjected to elevated temperature and humidity on either a continuous or cyclic basis. Conditions normally used are: 100 percent relative humidity and 44 C (120 F). A rust preventive fails or passes according to the size and number of rust spots on the specimen. 2. Salt Spray.9 Coated test specimens are subjected to continuous 5 or 20 percent spray at 33 to 36 C (92 to 97 F). Variations include spraying synthetic sea water, acidifying the salt solution with acetic acid, or raising the temperature. 3. Weatherometer.1o Coated test specimens revolve around a source of ultraviolet light with or without water spray. Both corrosion of the specimen and deterioration of the film are usually observed. 4. Immersion. Coated test specimens are completely immersed in salt water, dilute acid, or dilute alkaline solutions.

Considering the above criteria, the proper rust preventive for the job should: 1. Be easily applied; 2. Be non-toxic to workmen; 3. Afford protection within the specified environmental parameters; 4. Form a stable, adhesive protective film; 5. For some uses, such as hydraulic systems, be compatible with the operating lubricant used; 6. Furnish lubrication, if necessary; 7. Be easily removable, if necessary. The surface of the part or object must be prepared for application of the rust preventive. Thorough cleaning of all surfaces is absolutely essential for greatest efficiency in

(I)Tradename of Atlas Electric Devices Co., Chicago, 111.

222

protection. Surface contamination will not only interfere with application but it may also cause corrosion. Some common contaminants are:

and lubricating properties which is particularly useful for deep drawing of steel plates consists of a base oil, sorbitan monooleate and special alkyl sulfonamides. The synergistic action of the sorbitan monooleate and certain alkyl sulfonamides such as dodecylbenzene or cetyl sulfonamide in combination with the base oil gives excellent rust preventive and lubricating properties. The rust preventive properties of such an oil were determined by placing polished steel plates in a humidity cabinet (standard JAN-H-792) at 88 F and 98 to 100 percent humidity. Steel plates coated with the base oil alone showed rusting over the entire surface in 24 hours. Plates coated with the above mentioned rust preventive drawing oil withstood 400 to 480 hours in the humidity cabinet before rusting occurred. 1 7 Water Displacing Rust Preventive Composition. This type of rust preventive is effective for displacement of water from surfaces in the reconditioning of water-wet apparatus such as in the salvaging of flooded electrical equipment. It is useful also in rust protection of mechanical equipment in daily operation at machine shops and factories.

1. Oil, grease, and other organic compounds; 2. Inorganic materials such as residual heat treating salts, soldering or welding fluxes, marking ink, metal fines and etching solutions; 3. Fingerprint and perspiration residues; 4. Water; 5. Dust and dirt. Intricate machinery with critical surfaces, such as machine tools, hydraulic equipment and internal combustion engines may require partial disassembly before cleaning and preservation. Procedures usually are recommended in government regulations15 by manufacturers of the machinery and by suppliers of rust preventives.16 Metal surfaces should be cleaned with inert solvents, avoiding chlorinated types, alkaline and emulsion cleaners. Fingerprint removers should be used where needed. Water displacing rust preventives and dry compressed air should be used to ensure that all rinsed surfaces are free of water. Less intricate parts and objects with non-critical surfaces may be cleaned by mechanical methods such as grit blasting or ultrasonics. Chemical methods such as solvent, alkaline, emulsion, or electrolytic cleaning may be used. Fingerprint removers and water displacing rust preventives also may be put to good use. Following surface preparation, the coatings are applied by brushing, spraying or hot or cold dipping. When critical surfaces are involved, reapplication of the rust preventive may be carried out during the storage period if necessary. Certain types of barrier wrappings, such as paper treated with vapor phase inhibitors or plastic sheets may be used to supplement protection. A word of caution is required concerning the use of solvent and water based rust preventives. The protective film must be absolutely free of water and solvent before packaging or plugging of parts is carried out. If solvent or water is present in a sealed part, the protective film will not form properly and corrosion probably will result.

This particular water-displacing rust preventive composition is nonflammable and has a low odor. It consists of 10 to 15 percent by weight of aliphatic ketones, 30 to 45 percent isopropyl alcohol, 2 to 3 percent of a polar rust inhibitor such as basic barium dinonyl naphthalene sulfonate and 50 percent water.18 Internal Combustion Engines. A compound of heavy engine oil, petroleum sulfonates and an acid neutralizing amine with suitable proportions of microcrystalline wax will, after being cooled through its transition temperature of about 49 C (120 F), coalesce into a gel with almost no draining rate. Under shear, however, it reverts to a liquid. This material is used as a preservative inside reciprocating aircraft engines for storage periods exceeding 60 days. No dehydration or sealing of the engine is necessary when the preservative is applied properly. 19 Vehicle Underbodies. Hard drying bituminous coatings are applied to undersides of Air Force motor vehicles for use in tropical exposures. The MIL-P-116, Type P-l material is applied, along with other protectives, at a cost of $150 to $300 per vehicle.2 0

Post-Protection Procedure After storage, it often is necessary to remove the rust preventive film before using the machinery or part. Critical surfaces should be solvent cleaned and dried. Ordinarily, soft oily or greasy films which are readily solvent-soluble will be on these surfaces. Non-critical surfaces can be cleaned with solvents, alkaline or emulsion cleaners. In some cases, steam cleaning and hot water flushing are acceptable. Sometimes, the protective film need not be removed. For example, in most internal combustion engines, hydraulic systems and precision bearings, the rust preventive films are initially chosen to be compatible with the operating lubricant or fluid. In these cases, equipment may be put to use immediately after servicing.

Protection of Firearms. Cleaners with temporary rust protective properties containing oil soluble inhibitors, solubilizing agents, chelating agents and water in colloidal form, along with other constituents, were tested for their protective properties on firearms components by the Swedish Research Institute for National Defense. The inhibitor was a sodium petroleum sulfonate. The chelating agent was trisodium salts of ethylene diamine tetraacetic acid.21 Accelerated tests were conducted at 60 to 100 C under controlled atmospheres in moving air to which oxygen was added at a concentration of 25 vol percent. At low oxygen concentrations, the inhibited grease did not prevent corrosion, but tended to increase it. Higher oxygen concentrations resulted in reduced attack.

Some bxamples of Applications Rust Preventive Drawing Oil. An oil having anti-rust 223

19. S. L. Chisholm and H. N. Rudd. Progress in Prevention of Corrosion in Naval Aircraft, Corrosion. 13, No. 7, 473t-480t (1957) July. 20. R. F. Conner. Protection of Motor Vehicles Against Tropical Corrosion, Mat. Pro., 2, No. 4, 60-3 (1963) Apr. 21. P. Atterby. Temporary Corrosion Prevention of Firearms, Corrosion Research in Scandinavia, IVth Scandinavian Corrosion Congress, Helsinki p290-6 (1964). 22. P. D. Donovan and J. Stringer. The Corrosion of Metals by Organic Acid Vapors, Proc. 4th Int. Congo Met Cor., Amsterdam, 1969, NACE, Houston, Tx., p537-44.

Corrosion of steel bolts was increased by the chelating agents. Flotation Type Coatings. Flotation type rust retarders are applied to the inside surfaces of tanks by depositing a layer of inhibited oil on the bottom of empty tanks. Water is introduced from the bottom so that the oil film floats on top. As the water level rises and falls, a layer of the coating is deposited on the sides of the tank.4 Protection from Vapor. Petroleum grease and strippable coatings have been used with some success to protect steel, lead, aluminum, magnesium, cadmium and other metals exposed to vapors emanating from various woods, plastic materials and papers. Corrosives include acetic acid, formic acid, hydrogen sulfide, sulfur dioxide, and hydrogen chloride.22

Part 2 - Vapor Phase Corrosion Inhibitors Although practical application of vapor phase inhibitors, also known as volatile corrosion inhibitors, became common only in recent years, as long as 100 years ago it was a practice in Sweden to put a piece of camphor in the case where a gun was kept.1 In the last 25 years, however, there has been a rapid growth of inhibitor applications in the vapor space about metals subject to corrosive attack. Formulations have been developed which will protect ferrous and nonferrous metals.

Summary Rust preventives cover the gamut from mechanical barrier to the more complex polar types. Within this range are grease, oil, solvent and water-based classifications. The recent development of specially designed additives allow thin film protection. Accordingly, film thickness is not as critical as it once was. By careful selection of suitable rust preventives metallic substrates can be protected from short to extremely long times.

When Wachter, Skei and Stillman2 published the results of Shell Development Co. tests on dicyclohexylammonium nitrite in 1951, they had accumulated data on exposures to 12 years. Concerning Dichan,(2) the Shell inhibitor, they said: "In contrast to the alkali metal nitrites, this solid amine nitrite differs in being slightly volatile at atmospheric temperatures. This property gives it special industrial importance because it makes possible the prevention of atmospheric corrosion of steel articles in packages or containers without the necessity of coating the steel with the inhibitor." They postulated that the Dichan molecule functioned by contributing its nitrite ion to condensed or absorbed moisture on a metal surface and that its volatility was merely a means of transport. Dicyclohexylammonium nitrite is a white crystalline solid melting at about 154 C (310 F) with decomposition. It is practically odorless. The pH of aqueous solutions is about 7.2.

References 1. Registered trademark, E. F. Houghton & Co., Philadelphia, Pa. 2. W. E. Campbell. Temporary Corrosion Preventive Coatings, The Corrosion Handbook, H. H. Uhlig, editor, John Wiley & Sons, Inc., New York, p916-23. 3. E. R. Barnum, R. G. Larsen and A. Wachter. Corrosion, 4, 423 (1948). 4. H. B. Carpenter. Characteristics and Uses of Petroleum Base Rust Preventives, Mat. Pro., 2, No. 3,28-32 (1963) Mar. 5. M. Kashima and Y. Nose. Physico-Chemical Investigation of Rust Preventive Oil, Proc. 2nd Int. Congo Met. Cor., New York, 1963, NACE, Houston, Tx., p612-23 (1966). 6. S. J. Eisler and H. L. Faigen. Investigation of Synthetic Fingerprint Solutions, Corrosion, 10, No. 8, 237-42 (1954) Aug. 7. Military Specification. Corrosion Preventive, Fingerprint Remover, MIL-C-15074C. 8. Rust Protection by Metal Preservatives in the Humidity Cabinet. ASTM Method No. D 1748-62T. 9. Corrosion Protection by Coatings: Salt Spray Test, Fed. Test Meth. No. 791 B. Meth. No. 4001.2. 10. Accelerated Weathering (Enclosed Arc Apparatus) ASTM Method No. D 822. 11. Military Specification. Corrosion Preventive Compound, Solvent Cutback, Cold Application. MIL-C-16173D. 12. Military Specification. Corrosion Preventive, Aircraft Engine. MIL-C-6529C. 13. Military Specification. Lubricating Oil, Internal Combustion Engine Preservative. MIL-L-21260. 14. U. Ulfvarson and K. Johansson. Determining a Standarized Procedure for Evaluation of Auto-Motive Rustproofing Compounds, Mat. Pro.• 8, No. 6,43-4 (1969) June. 15. Military Specification. Methods of Preservation, MIL-P-1l6E. 16. Preparation for Storage of Machine Tools and Production Equipment. E. F. Houghton & Co. (1954). 17. S. Yonezaki and S. Shimada. U. S. Patent 3,287,267 (1966). 18. H. R. Baker and C. R. Sing1eterry. U. S. Patent 3,138,558 (1964).

Table I from the Shell Development study2 gives some results of exposure tests using Dichan. Other Types Developed Other types and variations of inhibitors for vapor space applications have been developed. Using an adsorption microcelI, Mindowicz3 made tests to determine the protective properties of seven inhibitor formulations as shown in Figure I. This test method, by comparing the potentials of films produced on metal surfaces, permitted evaluation of the inhibitors as to their probable efficiency in reducing corrosion. Mindowicz concluded that vapors of the substances imparted a more or less alkaline reaction to the adsorption layer and that dicyclohexylamine chromate and nitrite and dibenzylamine nitrite vapors consist exclusively of undissolved molecules. The rest of the substances are presumed (2)Tradename of Shell Dev. Co., Houston, Texas.

224

to consist of amine molecules and acid radicals. He also said that monocyclohexylamine benzoate, dicyclohexylamine benzoate and monocyclohexylamine carbonate appear to have non-molecular modes of evaporation and sorption.

INHIBITOR

25 Dicyc10hexylamine

ferrous

metals

benzoate

Dibenzylamine

nitrite

Dicyclohexylamine

-

100

chromate

Monocyc1ohexylamine

carbonate nitrite

FIGURE 1 - Efficiency of the protective tile corrosion inhibitors under investigation.

action of the vola-

atmospheric corrosion are unable to protect non-ferrous metals.4 Among materials that protect nonferrous metals, the salts of nitrobenzoic acid function by depolarizing the surface so that anodic current density increases, leading to passivation of the metal. Levin et al4 also report that the protective action of esters of chromic acid and t-butyl alcohol is based on the hydrolysis of the ester and the subsequent passivation of the metal by Cr04 -2. Experiments with cyclohexylamine chromate (a yellow powder containing 5 to 10 percent water, with a pH of 7.5 to 8.5 in a 1 percent solution in water) showed it to have desirable properties when used with nonferrous metals.

from

Machined bars of SAE 1020 steel (l-inch diameter by 5-inchl, solvent cleaned, stored with and without protective oil treatment, in packages composed of inner wrap of plain kraft or of kraft impregnated with 2 to 3 g Oichan per sq ft and outer wrap of water-proof barrier laminates. Package edges stapled and sealed with wax. Packages exposed outdoors without shelter in industrial-marine atmosphere in Oakland, California. Composition 0.0755 0.6 15 AI foil-wax trace 14 1.1 K-A-K(l) 0.23 K-A-K~l) 60 0.7 10 85 Kraft 85 520trace Yr 3Inner Yr K Outer Wrap g/sq ft Oichan paper trace Kraft 620503raft Oichan paper at Wrap 5paper Yr. Remaining

75

(neutral)

TABLE 1 - Package Exposure Tests Unsheltered Outdoors2

paper ::lil paper paper ::lilYY X ..... .....

Percent

benzoate

Dibenzylamine

DicyclohexyJamine

EFFECT.

50

benzoate

Monocyclohexylamine

Mechanism of Cyclohexylamine Carbamate Protection Lund,1 reporting on studies at the Norwegian Defense Establishment, discussed properties of cyclohexylamine carbamate (CHC) whose mechanism was deduced to involve the following reactions in a sodium chloride environment: 1. Settling of the amine part of the molecule on the Cl ion, and 2. Settling of the carbon dioxide fraction on the Na ion. These activities were checked through the use of sodium and chlorine isotopes and making radiograms of the surface after adsorption of the tagged molecules. CHC proved effective in protecting antique firearms in the Norwegian Army Museum against corrosion in storage where relative humidity was 80 percent or more. The process of application included cleaning the weapons, after which they were placed in plastic bags containing 2 grams of inhibitor. This was effective for periods up to 10 years at a cost of 20 cents per weapon protected. Fire engines and other machinery under lubricated conditions has been kept with corrosion-free vapor spaces for 5 years using this inhibitor. Protection for Nonferrous Metals Most inhibitors that protect

PROTECTIVE

ofPercent Package

Surface

(1)60Ib kraft-60 Ib asphaIt-60 Ib kraft laminated (2 )Commercial rust-preventive oils.

225

Rusted

paper.

Oichan

Accelerated tests were made under the following conditions: 1. 94 to 98 percent relative humidity, 2. 0.01 mg/l sulfur dioxide, 3. Temperature cycles every 3 hours, from 45 C to room temperature. Microscopic examination of the surfaces gave the results shown in Table 2.

Practical Applications of Vapor Phase Corrosion Inhibitors Vapor phase inhibitors may be used to impregnate wrapping paper, or placed loosely inside a closed container. Either method has many applications for storage of small, large, or oddly shaped metal parts. The slow vaporization of the inhibitor furnishes protection against the air and moisture which ordinarily will penetrate the package or enclosure. This technique is particularly effective when the item is enclosed within a plastic "bubble".

Synthesized Inhibitors Rosenfeld, Persiantseva and Polteva,s synthesized a new class of vapor space inhibitors capable of protecting both ferrous and nonferrous metals. Hexamethyleneimine m-nitrobenzoate, one of the synthesized materials, is widely used. They made additional tests which showed that other amines such as dicyclohexylamine, butylamine, propylamine, monoethanolamine and diethanolamine can take the place of hexamethyleneimine forming m-nitrobenzoates to protect both ferrous and nonferrous metals.

Protection of Weapons and Engines Naval small arms and 50 mm cannon did not corrode after 10 years 7 outdoors when wrapped in vapor phase inhibitor impregnated paper and then sealed in a dipped plastic envelope. Reciprocating aircraft engines were protected by injection of about 75 grams of vapor phase inhibitor powder into engine cavities. Test engines were deployed for storage over a wide range of environments. In comparison with similar engines protected by other preservative methods, the vapor phase inhibited specimens were in acceptable condition after 18 months of outdoor storage while some of the others were not. During additional exposures up to three years, samples of test engines were found to be in good condition. After this time, however, cylinder walls began to show corrosion damage. Additional benefits are expected from improved inhibitors incorporating hydrobromic acid neutralizing additives and small additions of more volatile compounds to give early protection.

By testing the saturated vapor pressures of these materials, they discovered that in concentrated sodium sulfate solutions, aminobenzoates affect iron only slightly. The aminobenzoates are believed to passivate iron mainly by increasing the cathodic reduction reaction of the nitro groups. In dilute electrolytes they inhibit the anodic process. Investigations by Agarwala and Tripath6 showed that phenylthiourea gave four months' protection to steel, copper, brass and aluminum exposed to 100 percent humidity under stagnant conditions. Mild steel was protected best by allyl thiourea; copper and brass by phenylthiourea. Aluminum was protected best by tetramethylthiourea monosulfide.

Staining of Nonferrous Metals One percent aqueous solutions of alkali bichromate or

TABLE 2 - Results of Accelerated Tests

with Cyclohexylamine Chromate4 (21 g/m2

1616 301 01488 10248 2010.008% 368 10.018% 3 iren

of wrapping paper) 128010 0 Degree of Corrosion

After Cycles No.

Metals or Their Combinations

(I)Note:

The corrosion scale for nonferrous metals is: O-Without change. 1~Light tarnish, disappearing after wiping or washing. 2-Tarnish that can be washed, or light interference calor. 3-Stains or strips without distinct corrosion products. 226

chromate will confer resistance to tarnishing of copper and brass sheets after immersion for 10 seconds to 2 minutes. The sheets must be washed after dipping and then force-dried. 8 While mechanism of the protection is not fully understood, it is postulated that the treatment forms a layer of chromate about 2 x 10-4 mm thick on the surface. Others believe chromate ions are responsible for the protection. Slushing compounds with or without volatile solvents or inhibitors also are used. As shown in Figure 2, sodium chromate successfully protected aluminum sheets subject to attack by vapors from the atmosphere.9

Summary Substantial success in the vapor phase protection of ferrous metals has been achieved using volatile amines and other polar substances. Proper care must be taken in packaging to prevent the inhibitor from being lost to the outside atmosphere. Inhibitors for nonferrous metals with vapor space exposures have provided some degree of protection, but in many cases were not as effective as the inhibitors ll~ed with ferrous metals.

References 1. L. Lund. Practical Uses of Vapor Phase Inhibitors, 3rd Europ. Symp. on Cor. Inh., Ferrara, p875-9 (1970). 2. A. Wachter, T. Skei and N. Stillm an. Corrosion Preventive Packaging, Corrosion. 7, No. 9, 284-94 (1951) Sept. 3. J. Mindowicz. An Investigation of the Mechanism of the Effect of Certain Volatile Inhibitors on Corrosion, Proc. 3rd Int. Congo Met. Cor., Moscow, Vo!. 2, pi 70-7 (1966). 4. S. Z. Levin, S. A. Gintzberg, I. S. Dinner, and V. N. Kuchinsky. Synthesis and Protective Action of Some Inhibitors on the Basis of Cyclohexylamine and Dicylcohexylamine, Proc. 2nd Europ. Symp. on Cor. Inh., Ferrara, p765-6 (1965). 5. I. L. Rosenfeld, V. P. Persiantseva, and M. N. Polteva. Some Theoretical Aspects of Metal Protection Against Corrosion by Volatile Inhibitors, Proc. 4th Int. Congo Met. Cor., Amsterdam, NACE, Houston, Tx., p606-9 (1969). 6. V. S. Agarwala and K. C. Tripathi. Some Vapor Phase Inhibitor Experiments, Mat. Pro .• 5, No. 12,26-7 (1966) Dec. 7. S. L. Chisholm and H. N. Rudd. Progress in Prevention of Corrosion in Naval Aircraft, Corrosion, 13, No. 7, 47 3t-480t (1957) July.

FIGURE 2 - Panels from test racks in which aluminum sheets were exposed to a 30 day high humidity test. Top: No protection. Center: Interleaved with untreated tissue paper. Bottom: Interleaved with tissue paper containing 1.5 to 3 percent sodium chromate. Sheets were unoiled.8 8. E. Mattsson. Staining of Copper and Brass, Corrosion, 14, No. 2, 88t-92t (1958) Feb. 9. C. C. Lacy and E. W. Everhart. Inhibited Interleaving Tissue Prevents Water Staining of Aluminum, Corrosion, 9, No. 8, 295 (1953) Aug.

227

Microbiological

Corrosion and Its Control

J. M. SHARPLEY*

Introduction

tected pipeline-will be attacked promptly as the result of microbial activity. Although, microbiological corrosion is important economically, the exact dollar value of the loss must await precise quantification of biologically induced corrosion. A number of estimates of economic loss have been made.

Corrosion induced or accelerated by bacteria, fungi, or assorted higher invertebrates, is a recognized process. The process is well established in the literature, as its aspects have been reviewed by a number of authors. However, it is probable that microbiological corrosion rarely occurs as an isolated phenomenon but, rather, is coupled with some type of electrochemical corrosion. For example, corrosion induced by sulfate-reducing bacteria usually is complicated by the chemical action of sulfides. Corrosion by an aerobic organism, by definition, always occurs in the presence of oxygen. To further confound the problem, microbiocidal chemicals also may have some conventional properties as corrosion inhibitors (e.g.; filmforming). There does not seem to be a published record of a practical corrosion problem that has been treated with a biocide that did not also have some physicochemical action. The history of research on microbiological corrosion is informative and reflects the degree of pragmatism found in research in that area. A few investigators have been interested in microbiological corrosion for about 30 years. In 1958 an informal survey indicated that throughout the world there were about 20 people actually working and publishing in the field. In 1962 there was a conference in Washington concerning microbiological corrosion and about 250 persons indicated their interest and expertise. The change in interest level reflects the aircraft fuel corrosion problem in 1961-1966 and the large amount of Federal monies allocated to a solution of the problem. Microbiological corrosion in aircraft, with some major exceptions, is now controlled by fuel additives, coatings and good housekeeping. Little research money is now available in this specific area and the literature shows a major decrease in publications. If one accepts the most general definition of corrosion, then microbiological corrosion has existed since man first recovered metals from their ores. Microbiological corrosion was suggested in 18911 and 1910.2 It is an exceedingly common process. The mud of a marsh is very deficient in oxygen and anaerobic bacteria will convert the available sulfates to hydrogen sulfide. This, combined with other sulfur compounds, accounts for the typical odor found in such areas. Any scrap ferrous metal present-or an unpro-

Greathouse and Wessel3 estimated that biological corrosion of pipelines cost between $500 and $2000 million a year. In 1964 Booth4 estimated that at least 50 percent of the failures of all buried metal was due to biological corrosion. So far as is known, no public figures are available concerning the loss from aircraft corrosion but they must be very large.

Organisms Involved in Corrosion Processes Twenty years ago, the author would have written a section under this heading that contained a definitive list of "corrosion-causing bacteria", but this no longer is possible. Experience has shown that the basic knowledge concerning the organisms is lacking. It can be said that when certain types of bacteria and fungi are found, biological corrosion is probable, but, at best, this is a rather negative statement. As a result of this uncertainty, few positive statements may be made with scientific accuracy. However, it is known that biological corrosion is nearly always present where large numbers of bacteria exist; i.e., a dirty or slimed system. The implication of such a system is that a large variety of bacteria are present. The number of microorganisms, the variety of species and the substra te provided for additional species all statistically increase the possibility of strains occurring with corrosion inducing mechanisms. An excellent in-depth discussion of the taxonomy of organisms involved in corrosion processes has been provided recently by Iverson.s His paper is strongly recommended to the professional microbiologist. In general, both fungi and bacteria have been implicated by many authors in microbiological corrosion. The bulk of the publications probably concern the anaerobic sulfate-reducing bacteria; second, the aerobic, iron bacteria and last, the fungi. Most microbiologists will readily agree that in addition to those described in the literature, many unrecognized microorganisms probably are involved in corrosion processes.

Theory of Biological Corrosion *Virginia Commonweal1h University, Fredericksburg, Va.

Many investigators 228

regard microbial

corrosion

as a

contact with sulfate-reducing galvanic cell is formed thus:

specialized form of electrochemical corrosion. Unfortunately, some investigators without backgrounds in the biological sciences have not recognized the dynamic systems that are always inherent with a living population. For sake of convenience, the theories of biological corrosion are divided into aerobic and anaerobic systems.

bacteria, the cathode of the

The loss of electrons from the metal makes it anodic, with the iron going into solution:

Anaerobic Co"osion The fundamental paper concerning corrosion by sulfate-reducing bacteria is that of von Wolzogen Kuhr and L. S. van der Vlugt. 6 Although this remarkable paper was published in 1934, 35-odd years of examination have not shaken the foundation of the work.

Fe -+ Fe

2+

+ 2e -

The free electrons thus formed migrate to the cathode and react with hydrogen ions to form gaseous hydrogen:

In general the mechanism is as follows: When sulfate-reducing bacteria are present, the anode of a galvanic cell may be formed thus: Fe -+ Fe

2+

The free ferrous ions then react with hydrogen sulfide formed at the anode to form free hydrogen ions and ferrous sulfide. The hydrogen ions thus formed may either migrate to the cathode or react with hydroxyl groups to form water. The free ions must react because they cannot remain in a free state. The ferrous sulfide formed at the anode also will act

+ 2e-

Figure 1 is a diagram showing some of the possible reactions incident to the metabolism of sulfate reducing bacteria as they influence the corrosion of metals. On metal surfaces such as ordinary iron or steel not in

,--

3F~ 2+ _

Ir-Fe2+

~

3Fe(OH

)2

cathodically and release more ferrous ions, thus complicating the reaction. Occasionally, chemical analyses of such systems do not show the presence of sulfide but do identify other materials

~

60~_ S=

__

~

---

FeS

S04= -+ S= + 40-+

Su Ifate Reducing Bacteria

8H + 40 -+ 4H20

t 8H

.:;:..-------------Medium Metal

Anode +8(-)

~

8H-....J

/

/

,~-------------~--------~ FIGURE 1 - A diagram of the reactions incident to microbial corrosion caused by sulfate reducing bacteria.28 229

such as oxides. If a water system contains free carbon dioxide, then iron carbonate may form thus:

This reaction is preceded by a reaction dioxide and water to form carbonic acid.

could not confirm a direct 1: 1 relationship between hydrogenase and rate of corrosion but did confirm a much higher rate in the presence of hydrogenase. Horvath and Novae established polarization curves showing the changes in potential caused by sulfate-reducing bacteria. The changes of potential in sterile and inoculated culture solutions were plotted against time. In a sterile solution there was little change except a drift to the positive. The slopes of the polarization curves indicate verification of the cathodic depolarization theory proposed by von Wolzogen Kuhr.

of the carbon

It is interesting that the formation of iron hydroxide also can be postulated in this system by the reaction of ferrous sulfide and hydroxyl ions thus:

The influence of incubation time on cathode polarization of specimens inoculated with bacteria is illustrated in Figure 2. The publications of Booth, et al,12 confirm the conclusions above. However, this work is on much sounder foundation in respect to microbial biochemistry; a significant weakness in the Horvath work. Booth and Tiller used two strains of Desuifovibrio in their work. Both strains are sulfate-reducing bacteria, i.e., obligate anaerobes obtaining energy from the non assimilatory reduction of sulfates. However, D. desuifuricans (Hildenborough) contains a hydrogenase which permits it to utilize elementary hydrogen for the reduction of sulfate. D. orientis (Singapore) is a sulfate-reducing bacterium with no hydrogenase. Experimentally this is an important difference, since it is known that D. orientis (Singapore) cannot utilize elementary hydrogen whereas D. desulfuricans does. In

The cathodic depolarization step postulated in the original work was based on the important series of papers by Stephenson and Strickland,7 who were the first to report that hydrogen could be oxidized to water by bacteria. The enzymes involved in these reactions are hydrogenases. A simple example of the action is shown by Hydrogenomonas facilis in the reaction

2H2 + O2

hydrogenase • 2H20 + energy

Other common mechnisms bacteria are as follows:

of hydrogen

utilization

by

Mechanisms of Hydrogen Utilization by Bacteria 4H2 + 2C02-CH3COOClostridium aceticum

+ H20 + H30+ + energy

(1)

4H2 + CO2 -+ C~ + 2H20 + energy Methanobacterium omelianskii

(2)

4H2 + CO2 -+ NH3 + 2H2 0 + OH- + energy Micrococcus denitrificans

(3)

2H2 + O2 -+ 2H20 + energy Hydrogenomonas facilis

(4)

4H2 + 804= -+ S= + 4H20 + energy Desulfovibrio desulfuricans

(5)

-0.7

w

U (J)

:> '" .;:;

c Ql

•...

o

a.. Ql

Much controversy has been centered around this mechanism of bacterial depolarization, since it is the basis of the theory of microbial corrosion. In 1952, data published by Wanklyn and Spruil8,9 proved most damaging to the theory. It was shown that significant anodic depolarization occurred in the early stages of corrosion. This was caused by sulfide ions produced by the reduction of sulfate. Wanklyn and Spruit concluded that the anodic process rather than the cathodic depolarization is the rate determining step. However, Horvath and Novacl 0,11 in 1960 and 1962 published data substantiating cathodic depolarization. At the same time and independently, Booth and Tillerl2 published data that in turn substantiated the HorvathNovae paper. Subsequently Booth, Shinn and Wakelyl3

-0 •9

"'C

o...

•... (.) Ql

W

6 Days 18 Days 25 Days

-1.0

1.0

2.0

Current density MA/dm2 FIGURE 2 - Cathode polarization effects of increasing incubation.28

230

curves illustrating the

addition it is known that the Hildenborough strain will utilize elemental hydrogen preferentially even if an organic hydrogen donor is present. Thus, Booth and Tiller were able to demonstrate that the variations in polarization curves correspond with the single factor of hydrogenase present or absent. Figures 3 and 4 illustrate the differences in the reactions of these strains. The strongly anodic reaction attributed to D. Desulfuricans is readily apparent in Figure 4. Polarization curves prepared with the organisms described are quite significant. Anodic and cathodic curves for D. orientis (Singapore) show no cathodic depolarization. These results are related to the absence of a hydrogenase. The depolarization exhibited when the organism is able to utilize hydrogen is clearly shown by strong cathodic depolarization at 2 days, when the organism is growing well. After la days, when the activity of the bacteria has slowed through exhaustion of the nutrient, the curve returns to much the same form as in the newly inoculated culture. Iverson14,15 obtained additional data indicating that sulfate-reducing bacteria are directly involved in the corrosion rate reaction. Much of his work has been directly confirmed by the present author and indirectly confirmed by Booth and Tiller. 16 There is no doubt that sulfate-reducing bacteria containing a hydrogenase constitute an active mechanism of corrosion, removing hydrogen and thus increasing current flow in a corrosion cell. However, this is not the sole mechanism. The depolarizing effect of iron sulfide accounts for some of the high corrosion rates observed in the field. It is important to remember that the original causative hydrogen sulfide may be produced microbially. This point probably is important when working with corrosion engineers whose background would tend to bias them towards a purely chemical corrosion mechanism. The problem is not solved so simply.

Anodic

·0.4

w

() en en .±::

o

>c

·0.6

ca

c

'';::; Q)

•...

o

c..

·0.8

Cathodic o

50

100

Current density, MA/CM-z FIGURE 3 - Polarization curves for mild steel at 30 C. Cathode compartment inoculated with D. Orientis. 0--0 •• Initial curve. _ •• After 2 days. ••••• " After 10 days.28

-0.4 w

() en

en.±::

>o

.S -0.6 ca '';::;

c Q)

•...

o

c..

Aerobic Co"osion Mechanisms

The volume of literature concerning the sulfatereducing bacteria has tended to obscure the role of microorganisms in aerobic corrosion even though the number of oxygen-free aqueous environments in industry is comparatively small. Conversely, because aerated aqueous systems are common, aerobic bacteria may be involved frequently in microbial corrosion. The theories of aerobic microbial corrosion are mostly centered around the formation of concentration cells showing differential aeration. Olsen and Szybalski17 made use of this theory in explaining the pitting corrosion caused by iron bacteria. Sharpley extended the observations to salt water where a modified Gallionella was described and this organism is reasonably well established as the cause of pitting corrosion in waters where iron bacteria occur. 18 One modification suggested by Olsen and Szybalski and confirmed by Oppenheimer19 is the occurrence of sulfatereducing bacteria under the dense mats of Gallionella. This would, of course, cause a type of anaerobic corrosion in a well aerated system.

-0.8 Cathodic o

50

100

Current density IJ.A/cm-2 FIGURE 4 - Polarization curves for mild steel at 30 C. Anode inoculated with D. Desulfuricans. 0-0 •• Initial curve. _ •• After 2 days. -- •• After 7 days. -- •• After 10 days. 28

It seems apparent that if it is accepted that a dense mat of Gallionella can cause a differential aeration cell with consequent pitting corrosion, the same effect could be expected from any microorganism forming a dense growth. This was demonstrated by Sharpley20 working with Sphaerotilus, a slime-formingiron bacterium and with other slime-forming bacteria in water. Figure 5 illustrates the effect of a differential oxygen cell created as the result of a mat of biological depris deposited on steel. 231

reported corrosion by this mechanism in beet sugar mills in 1948 and Appllng and Sharpley observed the same phenomenon in 1957 in Cuban cane mills. The work previously discussed all has pertained to microbial corrosion of ferrous metals. In recent years the corrosion of aluminum has received a great deal of attention by the Air Force and its contractors. The problem at one time involved the structural integrity of aircraft and was an important specialized problem although, from an overall economic viewpoint, the corrosion of ferrous metals is far more important. From a corrosion viewpoint, this problem is considerably confused by the involved microorganisms utilizing jet fuel as a carbon source. Bacterial products are produced in the form of sludge and this further confused the issue. Water must be present in the aircraft fuel for the microorganisms to proliferate. Henrick, et ai,24 hypothesized that the bacteria in fuel tanks obtain their metal requirement directly from the aluminum. In tests using deionized water, fuel and bacteria show a large increase in corrosion compared to the same system when uninoculated., It is known that pure water is quite aggressive so, if one assumes that water present in aircraft results from vapor condensation, the water may indeed cause corrosion. However, water can be introduced into fuel from other sources and this water is far from pure. Hydraulic transfer of fuel by sea water displacement is a classic example. However, Hendrick's data do not seem to be incompatible with simple bacterial concentration cell corrosion and appear reasonably applicable to some problems observed in practice. Blanchard, et ai,2 5 have published data indicating that nitrate was an inhibitor of aluminum corrosion in much the same manner as discussed by Uhlig26 on 18-8 steel. However, in retrospect it appears that the obvious possibility of simple concentration cell corrosion appears to be the most logical cause of microbial aluminum corrosion. Iverson27 has demonstrated the presence of sulfate-reducing bacteria in the depths of tubercles on aluminum.14 Corrosion by metabolic by-products is certainly a possibility on both ferrous and nonferrous metals, but more experimental data are required to present a convincing case in the face of other evidence.

FIGURE 5 - Effects of microbiological corrosion of 1010 steel.

Corrosion under aerobic conditions is also caused by members of the genus Thiobacillus. Damage caused by these organisms is not common, but may be spectacular. Microbiologically, their growth may be quite complicated,21 but the corrosion mechanism is simple. They form sulfuric acid in their metabolism and the end concentration may lie between 5 and 10%. Any material attacked by dilute sulfuric acid may be damaged. Concrete sewer pipes are frequently damaged as the result of Thiobadllus activity. Thiobacillus fe"o"()xidans will oxidize natural pyrite deposits to produce high concentrations of sulfuric acid. Because pyrite deposits are often found in coal and gold mine tailings, the drainage from such deposits accounts for pollution known as acid mine drainage. For example Sirnmons and Reed22 have reported pH levels at 3.0 in Contrary Creek in Virginia as a result of the action of T. fe"ooxidans on mine tailings. Bacteria and fungi produce a large number of organic acids through their metabolisms. The accumulation of such acids would reasonably be expected to be corrosive and this effect has been reported several times. AlIen, et ai,2 3

Recognition of Microbial Corrosion Problems It seems safe to say that microbiologists generally feel that many cases of microbial corrosion in industry go unrecognized. At the current state of knowledge it is reasonable to suspect microbial corrosion in the presence of large masses of microbial slime and probably in the presence of large microbial populations. However, these parameters are often unknown. Microbial corrosion rarely occurs without at least some degree of conventional corrosion. It is very difficult to separate the two. The current state of knowledge necessi· tates the expediency of controlling or killing the microbiological growth and arbitrarily assuming the degree of 232

improvement gained was due to nullifying the action of the microorganisms. In general, it is not difficult to identify microbiological slime masses, but this can also prove to be a trap for the unwary. Bacteria and fungi often are sticky and act as a binder for inorganic material. Thus, a microscopic examination of the slime mass may reveal only a minor portion to be microbial in nature. Yet when these 1ivin~organisms are removed, the slime mass breaks up.

possibility of cell formation at every mesh. In addition, the wire is strongly flexed and abraded on one side. However, to the mill manager, the picture is quite different. He has years of records showing the length of time his wire has remained useful. If the average time has been 14 days and a change in operations now provides 16 days, he is convinced. Interestingly enough, one often fmds specific cases where one is convinced that corrosion is mitigated by bactericides but there is insufficient evidence to prove conclusively the microbial corrosion is involved at all.

Value of Coupon Tests In the author's laboratories over the past 25 years, thousands of corrosion coupons have been exposed to corrosive microbial environments. This has been a standard technique for years and, as is equally true for other common methods, has its advocates and critics. An impartial attitude toward coupon test techniques supports the contention that this test method must be handled very carefully when used for studies of microbial corrosion. Simple duplication of samples is almost a waste of time; replication of samples 12 or 20 fold is not excessive in borderline cases and some statistical method must be used for data evaluation. It will be remembered that microbial

Large number of field tests have been conducted by the author's laboratory to determine the degree of microbial corrosion. These tests were all made on 1010 mild steel and involved both large coupons and 1 cu ft welded 1010 steel boxes. No difficulty was experienced demonstrating microbial corrosion by weight loss and pit formation. In general, the degree of corrosion correlated well with the degree of slime accumulation but not at all with the numbers of bacteria counted by conventional techniques. In summary, microbial corrosion may be recognized or confirmed by some or a combination of the following observations: 1. Pitting type corrosion. 2. The presence of microbial slime masses. 3. Hydrogen sulfide in anaerobic systems. 4. Ferric(ous) hydroxide in aerobic systems. 5. Large bacterial or fungal populations. 6. Either an aqueous system or a nonaqueous system that allows the accumulation of water in some areas. 7. The temperature of the system must be below about 65 C at some intervals and below 125 C at all times. 8. The pH of the system is an unreliable indicator, but most microorganisms will not grow in strongly acidic or basic environments; i.e., below pH 4.0 and above 9.0. There are numerous exceptions. 9. Light is not necessary for the growth of most bacteria and fungi. It is necessary for the growth of algae. "Algae" growing in a light tight water tank is not algae at all; the growth must be either bacteria or fungi.

corrosion is nearly always evidenced by pitting and that the quantitative estimation of pitting corrosion from any source is difficult. Determination of corrosion by resistance techniques has been extensively used in the author's laboratory and elsewhere. This is believed to be a good method but also subject to the statistical limitations inherent in evaluating the consequences of pit formation. Large numbers of tests may make a testing program very expensive. Polarization curves are very useful, particularly for research studies, but are subject to much the same limitations as resistance probes. Field or Simulated Field Tests Field or simulated field observations

are somewhat

easier to observe than laboratory observations. There seem to be several reasons for this. First, excessive microbial slime formation is operationally undesirable in many industrial systems. Thus, it is simple to justify control of the microorganisms which indirectly controls the microbial corrosion. Second, the surface area of metal involved in industrial environments simplifies the observation of pitting corrosion. A statistically random process that is dependent on the surface area available is very difficult to simulate adequately in the laboratory. This necessitates the replicated tests now used. There is a third major reason, partially pragmatic and partially psychological. Most practicing engineers know their industrial system quite well. A change in operating conditions that provides increased life is not likely to be overlooked.

microbial populations 4. Reversal of the corrosion current. Illustrative of the fact that there is no doubt in the

Example of Pragmatic Evaluation Corrosion of Fourdrinier wire in a paper mill is an excellent example of an exceeding difficult process to duplicate in the laboratory. The copper wire is very reactive, the surface area is enormous and there is the

writer's mirid that good housekeeping is the most important of all measures used to prevent microbial corrosion, he once said28 that "slime problems may occur in a clean system, they will occur in a dirty one" and further experience has only confirmed the observation. Good housekeeping removes accumulated foreign matter and old slime masses

Prevention of Microbial Corrosion Microbial corrosion may be prevented or mitigated by several methods. These may be convenien tly grouped as follows: 1. Good housekeeping. 2. Protection of the metal surface a. Coatings b. Chemical absorption 3. Destruction or control

233

of the bacteria

or other

that not only cause problems in themselves but provide an excellent breeding place for future generations of microorganisms. Although good h6usekeeping may be accomplished by a detergent, hot water and a scrub brush, it is a rare system that is accessible to this treatment. More frequently hot solutions of detergents, with or without bactericides or other additives, are circulated through a system. Parenthetically, there is ample reason to suspect that several well known industrial biocides are primarily effective because of their surface-active characteristics and only secondarily because of their anti-microbial activity. Again, however, the pragmatist says "what difference, they work!" There are some situations where it is impossible to practice good housekeeping. For example, the writer once worked in Southern Illinois on a shallow buried water line

that showing the greatest biocidal activity. Thus, one often fmds mixtures in use to accomplish both purposes. Organic sulfur compounds, in addition to their biocidal activity, also apparently provide some physical cleaning. Since biocides are so rarely used solely for the control of microbial corrosion, it is often difficult to evaluate them properly. Cathodic protection is difficult to evaluate for much the same reasons. Corrosion is often quite severe before such a system is employed and it is difficult to distinguish among the initial forms of pitting corrosion. If the theories of microbial corrosion are correct, the imposition of a neutralizing current certainly should be effective. In conclusion, it does not appear to the writer that aggregate knowledge has advanced rapidly concerning practical controls of microbial corrosion. All remedial tech-

that was run through a large pig lot. Because the microbial population and moisture level was such that any chemical treatment was impractical, it seemed to be an ideal place for a coating to protect the exterior of the line. Such coatings are widely used and may consist either of the older asphaltic types or of newer synthetics and although they are subject to failure, as shown by Harris29 in a number of publications, they do indeed mitigate corrosion. The interior surfaces of lines may be protected by a physical coating such as asphalt, epoxy resins or cement. Although these coatings perform adequately when intact, they subject the underlying metal to accelerated pitting corrosion at the sites of flaws and holidays. Consequently, protection of metal surfaces by a chemical barrier such as that provided by the filming amines is a common practice. The carbon chain length of materials used in this fashion is important and a straight chain of 10 to 18 carbon atoms is most effective. Octyldecylamine (with 18 carbons) is frequently used. Such filming amines are effective but occasionally have caused difficulties by forming sludge. Other compounds are used to protect the surface from chemical corrosion. Sodium silicate, polyphosphates, organic gums and chromate have been used, as have sulfur compounds such as 2-mercaptobenzothiazol. From a microbiological point of view, these various compounds may show unexpected activities. Sodium silicate is probably inert, but the addition of phosphates to a water system may enhance microbial growth. Chromate may be quite undesirable. Contrary to popular opinion, chromate is generally ineffective as a bactericide and because of its high ion charge density, it coagulates individual bacteria into large slime masses. The alkali metal salts of 2-mercaptobenzothiazole are weak bactericides and seem especially active only with copper. More information on the effect of bacteria will be found in the chapter in this book on cooling water. Control of the microorganisms in a system is rarely used alone for microbial corrosion control. Consequently mixtures of compounds are commonly used to control bacterial growth as well as corrosion caused by other reactions. For example, filming amines are most effective as corrosion inhibitors at a chain length slightly greater than

niques used in aqueous systems are troublesome, expensive, only partially effective, or all three. Better methods for rapidly identifying microbial corrosion in industry are needed as badly as effective treatments are.

References 1. J. H. Garrett. The Action of Water on Lead, H. K. Lewis, London (1891). 2. R. H. Gaines. Bacterial Activity as a Corrosion Influence in the Soil, Jour. Engl. fnd. Chem., 2,128-30 (1910). 3. G. A. Greathouse and C. J. Wessel. Deterioration of Materials, Reinhold Publishers, New York (1954). 4. G. H. Booth. Sulfur Bacteria in Relationship to Corrosion, Jour. Appl. Bacteriol., 27, No. I, 174-81 (1964). 5. W. P. Iverson. Biological Corrosion, In press (1972). 6. C. A. H. von Wolzogen Kuhr and L. S. van der Vlugt. Graphitization of Cast Iron as an Electro-biochemical Process in Anaerobic Soils, Water (Dutch) 18, No. 16, 147-65 (1934). C. A. H. von Wolzogen Kuhr. Unity of Anaerobic and Aerobic Iron Corrosion Process in the Soil, Corrosion, 17, No. 6, 293t-299t (1961) June. 7. M. Stephenson and L. H. Strickland. Hydrogenase: A Bacterial Enzyme Activating Molecular Hydrogen, I. Properties of the Enzyme, Biochemical Journa~ 25,206-14 (1931). 8. J. N. Wanklyn and C. J. P. Spruit. Iron/Sulfide Ratios in Corrosion by Sulfate-Reducing Bacteria, Nature (London), 168, 951 (1951). 9. Influence of Sulphate-Reducing Bacteria on the Corrosion Potential of Iron. Nature (London), 169, 928 (1952). 10. J. Horvath. Contributions to the Mechanisms of Anaerobic Microbiological Corrosion I. Acta Chemica, (Academiae Scientianum Hungaricae), 25, 65-79 (1960). H. J. Horvath and M. Novac. Contributions to the Mechanism of Anaerobic Microbiological Corrosion 11.,33,221-34 (1962). 12. G. H. Booth and A. K. Tiller. Polarization Studies of Mild Steel in Cultures of Sulphate-reducing Bacteria, Trans. Faraday Soc., 56, No. 11,1689-99 (1960). 13. G. H. Booth, P. M. Shinn and D. G. Wakerly. Congress International de la Corrosion Marine et de Salissures, (C.R.E.O.) Paris 363-71 (1964). 14. W. P. Iverson. Direct Evidence for the Cathodic Depolarization Theory of Bacterial Corrosion, Science, 151, (3713), 986-88 (1966). 15. W. P. Iverson. Corrosion of Iron and Formation of Iron Phosphide by Desulfovibrio Desulfuricans, Nature, 217, 1265-67 (1968). 16. G. H. Booth and A. K. Tiller. Cathodic Characteristics of Mild Steel in Suspensions of Sulfate-Reducing Bacteria, Corros. Sci., 8,583-600 (1968). 17. E. Olsen and W. Szybalski. Aerobic Microbiological Corrosion

234

18. 19. 20. 21. 22.

23.

24.

25.

26.

27.

of Water Pipes, Co"osion, 6, No. 12,405-14 (1960), Reprinted from Acta Chemica Scandinavia, 3,1094-1116 (1946). J. M. Sharpley. Occurrence of Gallionella in Salt Water, Applied Microbiology, 9,380-2 (1961). C. H. Oppenheimer. How to Detect and Control Corrosion Causing Bacteria, World Oi~ 147, No. 7,144-7 (1958). J. M. Sharpley. Microbiological Corrosion in Waterfloods, Co"osion, 17,92-6 (1961). C. D. Parker. Species of SulCur Bacteria Associated With the Corrosion of Concrete, Nature, 159,439 (1947). G. M. Simmons, Jr. and J. R. Reed, Jr. The Ecological Significance of Locating a Nuclear Powered Electrical Generating Facility on the North Anna River, Virginia, Proc. Thrid National Symposium on Radioecology, Oak Ridge, (In press). 1. A. Allen. et al. Microbiological Problems in the Manufacture of Sugar From Beet. Pt. 1. Corrosion in the Diffusion Battery and Recirculating Systems, Jour. Soc. Chem. loo., 67, 70-7 (1948). H. G. Hedrick, M. G. Crum, R. J. Reynolds, and S. C. Culver. Mechanism of Microbilogical Corrosion of Aluminum Alloys, Electrochem. Tech., 5, No. 3 & 4, 75-7 (1967). G. C. Blanchard and C. R. Goucher. The Corrosion of Aluminum by Microbial Cultures, Dev. in Ind. Microbiol., 6, 95-104 (1964). H. H. Uhlig and J. R. Gilman. Pitting of 18-8 Stainless Steel in Ferric Chloride Inhibited by Nitrates, Co"osion, 20, No. 9, 289~292t(1964)SepL W. P. Iverson. A Possible Role for SulCate Reducers in the Corrosion of Aluminum Alloys, Electrochem. Tech., 5, No. 384 77-9 (1967).

28. J. M. Sharpley. Elementary Petroleum Microbiology, Gulf Publishing Company, Houston, Texas (1966). 29. J. O. Harris. Bacterial Activity at the Bottom of Back-Filled Pipe Line Ditches, Co"osion, 16, No. 3 149-54 (1960) Mar.

Bibliography G. A. Trautenberg. SulCate Reduction in Bacterial Corrosion, Mat. Pro., 3, No. 2, 3134 (1964) Feb. R. N. Miller, W. C. Herron, A. G. Krigrens, J. 1. Cameron and B. M. Terry. Research Program Shows Microorganisms Cause Corrosion in Aircraft Fuel Tanks, Mat. Pro., 3, No. 9, 60-7 (1964) Sept. G. A. Trautenberg and A. C. Askew, Jr. Microbiological Control to Prevent Corrosion in Recirculating Water Systems, Mat. Pro., 3, No. 10,26-31 (1964) Oct. S. Kaye and P. G. Bird. Measuring the Progress of Wood Rot in Cooling Towers, Mat. Pro., 3, No. 10,46-50 (1964) Oct. W. R. Scott. Bacterial Corrosion in a Waterflood System, Mat. Pro., 4, No. 2,57-62 (1965) Feb. Y. Kunimoto. Sewer Corrosion Problems-The Honolulu System, Mat. Pro., 5, No. 11,8-11 (1966) Nov. E. Tehle, Jr. SulCate Reducing Bacteria in Water Cooling Systems, Mat. Pro., 5, No. 12,21-2 (1966) Dec. J. F. Conoby and T. M. Swan. Nitrite as a Corrosion InhibitorControlling Depletion of Sodium Nitrite, Mat. Pro., 6, No. 4, 55-8 (1967) Apr. D. R. Sexsmith and E. Q. PetreY. Laboratory Evaluation and Application of On Stream Cleaning in Open Recirculating Water Cooling Systems, Mat. Pro., 10, No. 6, 13-8 (1971) June.

235

Controlling Corrosion in Pulp and Paper Mills

A.

J. PI LUSO*

In every industrial process plant, corrosion is a big factor and often represents the difference between trouble-free operation, costly downtime and high capital expenditures for replacement. The corrosion that occurs in pulp and paper mill systems is caused by a variety of factors and chemicals and isl especially prevalent in older systems. The paper industry has been cognizant of high replacement costs and has knade significant strides in using more resistant materials of construction. Such materials as stainless steel (300 to 400 Series), and aluminum have gained widespread use because they are resistant to corrosive attack in many of the environments encountered in the manufacture of pulp and paper. These materials are also beneficial because· they lessen contamination and discoloration of the product. However, the problems of corrosion are still evident in pulp and paper mills and will significantly increase as mills tend to close up their water systems. Reduction of water losses due to governmental restriction of mill effluents, recirculation of high-solid, "white" waters, increases in temperatures and velocities of these waters and greater machine speeds all will contribute to the corrosivity of the systems. Published reports (Britt & Casey)I ,2 indicate that digesters in pulp mills corrode in varying degrees and that the attack is generally dependent on the corrosiveness of the liquor and/or varying operating conditions. The presence of chlorides, sulfates and carbonates in the kraft "white" liquors can accelerate corrosion under certain conditions. Alkaline digesters are usually constructed of carbon steel because it is economical; however, stainless steel liners or overlays are in widespread use. It is often found that corrosion is practically negligible in digesters operating continuously. However, recent data compiled by Canavan and Blanchard 3 show that average maintenance cost per unit year for both inclined and horizontal digesters is approximately $25,000. Evidence of corrosion and/or erosion is indicated by slight pitting at welds at the outlet nozzles, wasting of the mid-feather and wear caused by the flights. They also state that the areas most frequently attacked are welds, top head of cones, bottom shell section and internal piping. In neutral sulfite semi-chemical (NSSC) pulping operations corrosion is evident in digesters, conveyors, presses,

vacuum washers and other equipment servicing the system. Most of these units use stainless steel. In multiple-effect evaporators, corrosion problems occur primarily in the first effect, due to the highly concentrated liquors and high temperatures in this effect. In storage tanks of the turpentine and tall oil recovery systems, corrosion is caused primarily by hydrogen sulfide. The mechanism of corrosion in certain stainless steel alloys involves electrochemical reactions with anodic and cathodic areas. Each reaction is considered to be an oxidation-reduction system. The electrolyte may vary from moist air to strong acid.

Pitting Most Prevalent Problem Pitting-type corrosion is probably the most prevalent type found in pulp and paper mill systems. Impingement attack, caused by a steady stream of solution impacting on a surface also is commonly found in these systems. High suspended solids and high temperatures aggravate this type of attack. The abrasive action of the stream can remove the oxide film on the surface, which causes the area to become anodic and corrosion to continue. Galvanic corrosion occurs when dissimilar metals are in electrical contact while immersed in an electrolyte. Stainless steel coupled with other metals will not corrode as long as the surface film of oxides on the stainless remains unbroken and passive. If the stainless loses its passivity, due to abrasion or scraping, severe attack can occur. In many systems there is a defmite relationship between pit formation and the location of deposits. In areas where the surface is relatively smooth, deposition seldom occurs and usually there is no pit formation. However, where imperfections in the surface exist, such as at scratches, crevices, etc., nucleated pits are often observed. Build-up of fibrous deposits, slime and other material occurs on these imperfect surfaces in stagnant and slow-flow areas. This build-up results in and contributes to corrosion. A section of stainless steel plate taken from a large, white-water, collecting tank (Figure 1) shows characteristic corrosion due to both concentration cell activity and microbiological corrosion. Salts, particularly chlorides and sulfates contributed to the corrosivity of the system. The incidence of sulfate-reducing bacteria was extremely high. The raised weld areas and the abrasions on the metal surface indicate concentration

*Betz Laboratories, Philadelphia, Pa.

236

cell activity. The areas under

trations less than normal saturation, as in dense slime masses or stagnant areas) ~e sulfate ion can serve as the cathodic depolarizer. The sulfate-reducing bacteria consume hydmgen in their metabolic reduction of sulfate. This bacterial action, which reduces the sulfate to sulfides, is !Jfought about the catalytic action of the enzyme hydrogenase present in the bacterial cell. The sulfide reacts with the hydrogen to form hydrogen sulfide. Hydrogen sulfide will then react with iron to form ferrous sulfide. Oxygen from the sulfate is made available for cathodic depolarization and corrosion continues. The occurence of microbiological corrosion has been observed in low-flow areas, stagnant chests, headboxes, save-all, press sections and other areas associated with slime, pitch, fatty acids and fibrous deposits. The details of microbiological corrosion of iron and steel have been reviewed by Cruickshank4 and the electrochemical reactions of anaerobic corrosion in the presence of sulfate reducing bacteria described by Von Wolzogen Kuhr.s Briefly, the electrochernical

l-

FIGURE Attack in zones beside weld bead accelerated by bacterial factors. This section, taken from a large tank, shows characteristic corrosion due to concentration cells and microbiological· activity.

the deposits become anodic because of lack of oxygen. If the corrosion products remain in the pits, attack can be accelera ted.

Fe~Fe+++2(e) 2H+ + 2(e)~

Attack Resulting From Microbiological

reactions associated with

corrosion by sulfate-reducing bacteria can be explained by the following equations. I. Anodic dissolution leads to polarization of the dissolving steel, while the neutralization of hydrogen ions depolarizes the steel.

2H

Activity

These deposits also contribute to microbiological corrosion problems in the presence of sulfate-reducing, iron and sulfur-oxidizing bacteria which will intensify the attack at the metal interface through the formation of hydrogen sulfide and other corrosive acids and gases. The sulfate-reducers play a dual role in causing corrosion. First, they act as cathodic depolarizers and secondly, they produce hydrogen sulfide, which is corrosive. In the process of corrosion by these organisms, iron loses electrons and enters the electrolyte as ferrous ion at the anode. The electrons flow through the metal to the cathodic areas, where hydrogen gas is discharged, the hydrogen ions gaining an electron each and becoming neutral hydrogen atoms and eventually gaseous hydrogen molecules. If hydrogen is not removed, the cell becomes polarized and corrosion ceases. In acidic solutions, depolarization takes place by the evolution of hydrogen gas. In neutral or alkaline systems, oxygen can act as a cathodic depolarizer. In the case of slime and deposit accumulations, aerobic organisms on the suface of the slime masses utilize the oxygen and release by-products which create an anaerobic state at the metal interface. Thus, both aerobic and anaerobic organisms benefit by this association and/or contribution. This type of union is known as commensalism. When oxygen is absent (or present in concen-

2. In the presence of hydrogenase (bacterial enzyme), hydrogen adsorbed on steel surfaces reduces sulfates to sulfides. 8H + S04= ~ S= + 4H20 3. The dissolved iron may be hydrolyzed Fe ++ + 60H- ~ 3Fe (OHh 4. The sulfide ion reacts with iron to form a sulfide deposit

Iron sulfide deposits are characteristic of microbiological corrosion in the presence of sulfate-reducing bacteria. The overall reaction may be expressed as: 4Fe + 2H+ + S04 = + 2H2 0 ~ FeS + 3Fe (OHh

Microbiological

Control Measures

There is a lack of correlation between bacteriological examination and actual damage to a system resulting from microbiological corrosion. Although cultural techniques used in the field and laboratories are extremely helpful, 237

1. Chlorophenates, 2. Organic Nitrogen-base, 3. Carbamates, 4. Diamines, 5. Heavy metal oxides, 6. Sulfones, 7. Thiocyanate-base, 8. Acrolein, 9. Copper salt complexes, and 10. Organic sulfur-based compounds. In any dynamic system, there are no simple single foolproof tests. Usually, many indicators must be watched and frequently evaluated to determine if a given treatment program is effective. The seriousness of microbiological corrosion in paper mill systems is often relegated to a secondary role in importance, but a brief resume of a typical investigation and solution of the problem should be of interest.

they identify only the organisms that are present in the stream sample. These organisms can and often do, have a completely different and unknown relationship to other microorganisms deposited on the sides of lines, pipes and equipment. It is these latter organisms that are the cause of microbiological corrosion. Electrical resistance probes, such as the Corrosometer, (1 ) redox potential determination, mineral analysis and corrosion test coupons are very helpful in determining corrosion probabilities. However, results of these test methods cannot be correlated with the number of sulfate-reducing bacteria that will create a corrosion problem in a given system. The significant fact when these organisms are present is that the possibility for microbiological corrosion is developed. Cultural, direct microscopic and visual examination of these systems and deposits must be relied on to ascertain if bacterial corrosion is occuring. Microbiological Treatment Once the cause of the problem is ascertained, it becomes necessary to determine the most effective and economical solution. Treating chemicals are available that will kill or inhibit the growth of harmful bacteria. Generally, it is much more desirable to treat with an effective bactericide than with a bacteriostat, since the probability that a resistant strain of microbiological growth will develop is greater with bacteriostatic agents. It is possible to test microbiocides in the laboratory to identify the most effective compound that will effectively control the organisms. The use of dispersants and corrosion inhibitory chemicals is quite effective, but economics usually favor the use of biocides for control. Good housekeeping methods dictate that before treatment, the system be cleansed of old corrosive films, scale deposits and debris. Laboratory testing on one particular species of sulfatereducing bacteria has demonstrated the inhibiting and/or killing ability of several bactericides in the following descending order of effectiveness for various compounds:

Case History of Biological Attack The mill in question was experiencing failure in less than three months of lines of the glands of Nash vacuum pumps, as well as of clarified water lines. The slime control program in effect at the time was considered by operating personnel to be adequate, in that few operational problems attributable to slime were reported. Because slime was practically nonexistent, the possibility of microbiological corrosion was not considered. An immediate investigation of the chemical and microbiological factors was undertaken. Corrosion rates in the mill system were determined, not only to assess the severity of the problem, but also to serve as a reference point. The corrosion rate for the fresh water make-up pit is considered normal for this supply. The beater water pit showed an excessive corrosion rate. Samples obtained from various points in the mill system were checked for bacterial population levels, pH and acid production. The correlation of the chemical factors and the

(1)A trade name of the Magna Corp., Santa Fe Springs, Ca!.

TABLE

microbiological

1 - Summary of Conditions

Microbiological

Corrosion

Biocide +pH 700 5.1 4.7 5500 3420500 1000 825 800 4.8 Aerobe Count Acid 4.8 22.5 21.0 Production 1000 5.1 39.9 1X000 70 5.5 0 60 Corrosion 1500 25 1000 17.0 20.0 (Sulfate Reducers) (ppm) (mils/yr) Pit (2) (1) Makeup

and Results

in a Paper Mill

Anaerobe Count

238

data led to the conclusion

that micro-

biological corrosion was a contributing factor to this corrosion problem. An economical and effective biocide program was initiated in the system. Synergestic blends of chlorophenate-base compounds were added at a concentration of 25 ppm at the beater water pit. Sufficient time was allowed for equilibrium conditions to be established and a second corrosion study was conducted.

A summary of the conditions Table 1.

and results is given in

Treatment concentrations of effective biocides, points of addition and methods of feeding applications depend on many factors, all of which should be carefully investigated to achieve maximum effectiveness. The paper industry as a whole experiences corrosion throughout the entire process. The above are but a few of the types of corrosion that occur in pulp and paper mill systems. All types are governed by operating conditions, chemical and water characteristics and other factors. Each problem has to be individually evaluated as to cause and to the most economical approach to a solution.

This program showed considerable promise, since the corrosion rates remained unchanged for the fresh water make-up and significantly decreased in the beater water pit. Microbiological population levels also showed some improvement. Confirmation of the effectiveness of this program resulted in the increase in the biocide feed rate to achieve a 60 ppm concentration level. Periodic reports and examination of mill records have confirmed the protection secured by the treatment program, in addition to a more effective slime control program. This program has resulted in greater machine runnability and less down time for clean-up and repairs. The mill is still experiencing some degree of corrosion of piping, pump housings, etc. However, reduced replacement expenditures have more than justified the increased biocide addition costs.

References 1. K. W. Britt. Handbook of Pulp and Paper Technology, Second Edition. 2. Casey. Pulp and Paper, Vo!. 1,2, and 3. 3. H. M. Canavan and Z. S. Blanchard. Tappi, 1972. 4. G. A. Cruickshank. Monograph Series, No. 15, Tappi, 1955. 5. C. A. H. von Wolzogen Kuhr. Unity of Anaerobic and Aerobic Iron Corrosion Process in the Soil, Corrosion, 17, 293t-299t (1961) June.

239

Inhibition of Aluminum

A.H. ROEBUCK*

Protection of Aluminum by Inhibitors

3000 Series Alloys: Manganese-containing alloys. This series generally cannot be heat-treated. One of the most widely used alloys, 3003, has moderate strength, good workability and can be inhibited in certain media.

Aluminum, an amphoteric metal, is subject to attack in both strongly acid and strongly alkaline solutions. In the "essentially neutral range (pH 4.5 to 8.5) little, if any, attack occurs in the absence of 'heavy metal contamination' or galvanic effects. Outside this range, attack may occur depending more on the specific ions which are present than on the absolute value of pH." 1 Under essentially neutral conditions, Al can suffer localized pitting which may be observed on articles such as aluminum window casements and similar items where surface oxide breakdown has

4000 Series Alloys: for welding because have been in greater of the color effects

Silicon-containing alloys, used mainly of their lower melting points. Recently demand for architectural uses because which can be obtained when anodic

coatings are applied. This alloy series has good corrosion resistance and can be inhibited.

occurred. Such attack is more prevalent along the seacoasts or in other areas with high humidity. Chromates, silicates, polyphosphates, soluble oils and other inhibitors are commonly used to protect aluminum. Aluminum is concentration-sensitive to chromate solutions as well as to other anodic inhibitors. Combinations of

5000 Series Alloys: Magnesium-containing alloys. They are corrosion-resistant alloys which can be inhibited and are widely used in marine atmospheres, where they exhibit good resistance to attack. However, under certain conditions of loading, they are subject to stress corrosion cracking.

polyphosphates, nitrites, nitrates, borates, silicates and mercaptobenzothiazole are used in systems that include aluminum and other metals. 1

6000 Series Alloys: Silicon and magnesium-containing alloys. The silicon and magnesium are present in the approximate ratio to form magnesium silicide, which is heat-treatable. A major alloy in this series is 6061. These alloys have good corrosion resistance and may be inhibited effectively.

Aluminum Alloy Composition Aluminum alloys containing copper (2000 series) and zinc (7000 series) as major alloying elements are generally less corrosion-resistant than those without these elements. For this reason, these two series are usually more difficult to inhibit. Both are high-strength and widely used. Attack can be prevented or reduced by cladding with a more corrosion-resistant alloy such as high purity aluminum, a low magnesium-silicon alloy or an alloy of I % zinc. All of these cladding materials are frequently employed to give added corrosion protection to the 2000 and 7000 series alloys. The cladding on each side is 2 to 5% of the total thickness.

7000 Series Alloys: Zinc-containing alloys. Also may contain smaller percentages of magnesium, copper and chromium. They are heat treatable and can have very high strengths, e.g., 7075, which is one of the highest-strength aluminum alloys. Inhibitors may be used with the 7000 series. The solution heat treated tempers are usually more corrosion resistant and more amenable to corrosion inhibition than are the hardened alloys. The strain or work-hardened alloys are somewhat more readily inhibited than are the alloys hardened by aging treatments. Generally, the more homogeneous the alloy, the more readily it can be inhibited and the higher its corrosion resistance. Temper treatments which promote homogeneity for an alloying system enhance corrosion resistance and the alloys' ability to be effectively inhibited. Conversely, temper treatments which promote segregation, precipitation and non-homogeneity detract from the alloys' corrosion resistance and the ease with which it can be inhibited.

1000 Series Alloys: 99 percent pure aluminum or higher. This series has excellent resistance to corrosion and high electrical and thermal conductivities, but poor mechanical properties. 2000 Series Alloys: Copper-containing alloys. This series is high-strength and heat-treatable, but has generally low corrosion resistance, is subject to intergranular attack and is difficult to inhibit. The 2024 alloy is widely used in the aircraft industry. • FuJlerton, Ca.

240

TABLE

1- Classification of Inhibitor

TABLE 2 - Protection by Inhibitors in Antifreeze Solutions(1)3

Types for Aluminum Inhibitor Soluble oil and TSP, 3.0 percent Sodium hydrogen phosphate, 0.625 percent Sodium dichromate, Inorganic

..

I

Water

03030 60 00 . J 4(2) Alcohol .......... 17 Ethylene Glycol Isopropyl Alone 0.03and percent Water I Water and

.

801

mg Loss

Oxidizi ng: Chromate, nitrite, permanganate .... 1 Sodium silicate, 3.0 percent Cationic: Mg2+,Ca2+, Ni2+ Anionic: Molybdate, Si03-, W04-' Te04Organic Macromolecules-Proteins: Agar-agar, albumin, casein, glucose Amines: Acridine, hexamethylene tetramine, alkyl amines Acids: Stearic acid, nicotinic acid, sulfonic acid Others: Thiourea, nitrochlorobenzene

(I)Test Solution-Royal Oak tap water; Length of Test-SOO hours; Velocity-2000 rpm; Temperature-ISO F. (2)Inhibitor not compatible with alcohol solution.

Inhibitors Tested for Performance at High Fluid Velocities

Aluminum Inhibitor Types Inhibitors for aluminum may be classified chemically as I. Inorganic, or 2. Organic, They may also be classified by surface reactivity as 1. Adsorptive, or 2. Surface-reactive (where a precipitated mm is formed to provide a barrier between the corrosive agent and the aluminum surface). For purposes of this discussion the first classification system will be used, inhibitors being divided into inorganic and organic types as shown in Table 1.

Accelerated tests of aluminum-clad sheet, similar to sheet used in fabrication of automobile radiators, were made in natural waters and in automotive antifreezes3 at velocities up to 4700 fpm. Materials tested were sodium pyrophosphate, tartaric acid, sodium borate, sodium benzoate, sodium nitrite, disodium hydrogen phosphate, sodium silicate; an unidentified inhibitor containing sodium and chromium; an oil emulsion consisting of 25 percent trisodium phosphate and 25 percent oil in water; sodium dichromate; buffer consisting of 2 M potassium dihydrogen phosphate, 55 percent and 2 M sodium hydroxide, 45 percent; soluble oil, 33 percent and buffer (as shown above), 67 percent. Table 2 shows results using four inhibitive solutions selected by screening tests. Disodium hydrogen phosphate apparently promoted pitting of the clad aluminum in alcohol solutions. Sodium silicate proved to be incompatible. Tests with soluble-oil solutions showed it to be very effective in high velocity water, less so in lower velocity and deleterious in static water. In 1: I water-ethylene glycol, however, the soluble oil-buffer inhibitor reduced corrosion to zero. Soluble-oil solutions proved effective at pH 6; satisfactory at pH 8, but ineffective at pH 10. It was concluded that a buffer to adjust pH would be helpful when this solution was used.

Film Destruction is Corrosion Reaction A mechanism of aluminum corrosion deduced by Boies and Northan2 from tests made in wjo 62.5 ethylene glycol and 37.5 distilled water involves: 1. A period during which surface oxides are destroyed, hydrogen is evolved and an alkaline environment formed. 2. Film repair by oxygen in the solution until it is exhausted. They concluded that under the test conditions, the anodic reaction of metal dissolution to form aluminum ions occurs at the interface between the metal and an amorphous oxide layer; that aluminum ions diffuse outward because of the concentration gradient; and also that electrons flow outward because of the potential difference between anodic and cathodic reacting sites. "In any case, reaction of aluminum with water to form non protective oxide and hydrogen proceeds rapidly once this barrier layer is destroyed", they said, discussing the thin amorphous barrier layer next to the aluminum. In giving the results from tests with many inhibitors, Boies and Northan concluded:

Inhibitors Listed for Wide Range of Corrosive Solutions Roebuck and Pritchett,4 in citing their conclusions on a large volume of data concerning inhibition of aluminum said that gel-type inhibitors, such as agar-agar block cathodic reactions, causing marked cathodic polarization. Amine inhibitors also influence cathodic reactions and

1. Simple buffering is not the entire solution. 2. Inclusion of ions from the inhibitor in the protective mm on the aluminum is important. 3. Steric configuration of the inhibitor ions is important.

probably are useful in acid media. They pointed out also that nickel chromates (NiCr04) are more effective than potassium chromates, an indication that the effectiveness of chromates was due to the Ni2 + ion and the geometry of the NiCr04 molecule and not due solely to their oxidizing ability. Data are given in Table 3 from a large number of inhibitor tests and applications.

4. Structures capable of forming chelate-type, ring configurations are more effective than those that cannot. Good performance was obtained using non-ionic sorbitan fatty esters, 241

I

.,1

When the results were projected into estimates of the service life of aluminum underground, best performance was recorded by a treatment involving a chromate conversion coating plus application of petroleum jelly containing 1 percent Na2 Cr04' Projected life of this treatment in acid media was 76.9 years; in neutral media, 400 years and in alkaline media 166.7 years. Tests made of galvanic couples between steel and aluminum in the same media indicated that 40-year corrosion rates for steel coupled to aluminum coated with petroleum jelly containing 1 percent Na2 Cr04 were as follows: pH 3, 0.38; pH 6.4, 0.19; pH 10, 0.05 mils per year.

15

10

"0 "0

E III III

.2 •... ..r::.

Cl

'Q)

:s:

5

Inhibition in Hydrochloric Acid As reported by Unni and Rama Char,? aluminum, which ordinarily corrodes at rates in excess of 0.05 ipy in both aerated and unaerated hydrochloric acid at 24 C from 10 to 40 percent concentrations in waterS can be protected up to 98 percent under some conditions. Inhibitor efficiency with no, Di-ni- and Tri-n-Butylamines increased with acid concentration up to 1.25 or 1.5 N, depending on the inhibitor and was essentially constant at greater concentrations.

o o

1.5

0.5

Percent Sodium Chromate

FIGURE 1 - Inhibiting 7075 aluminum percent sodium chloride concentrations. 5

corrosion

in 5

Figure 2 shows efficiencies achieved using the three inhibitors.

100

Unni and Rama Char theorized that protection by the amines was due to their adsorption on cathodic areas .

•...

c:

Other Environments

Ql

tJ

~

Hydrofluoric acid is an effective inhibitor for aluminum in concentrated nitric or sulfuric acid at high temperatures.9 Silicates with a high ratio of silicate to soda are used in alkaline cleaners, soaps and dentifrices containing amines, carbonates and phosphates.

80

>tJ

c: Ql

'u

~ .•.. w

dium salts, naphthenic acids for Al in, 249 Tribasic sod. phos. vs Al pitting in, 249 Alkaline cleaners, sodium disilicate as Al inh. in, 249 A lk aline arsenite-arsenate vs hydrogen sulfide, 51 Alkaline earth sulfonates, 19 Alkalinity range for low pressure boilers, 210 Alkalinity, potable water, 116 Alkalinity, auto cooling system, 35 Alkenyl succinic acid structure, 21 Alkyd coatings, 192 Alkyl chain length, infl. of, 214 n-Alkyl quaternary ammonium, 16 Alkyl benzyl dimethyl-ammonium chloride in coatings, 193 Allenic a1cohols vs acids, 158 Allylamine structure, 22 Allylthiourea as steel VPI, 226 Allylthiourea structure, 26 Alox 425 for petr. wells, 70 Alum, boiler deposits vs, 197 Alum, treatment of sewage effluent, 130 Alumina, activated, dehydration of products , pipelines, 90 ALUMINUM Acids vs, 162 Agar-agar for, 241 Amides for, 249 Amines vs acids contacting, 241 Antifreeze solutions, inh. in, 241 Alkalis, inh. for, 248, 249

A ALUMINUM (Cont'd.) Auto engines, inhibited in, 174, 175 Bacterial attack on, 232 Boilers, deposits in, 210 Brine, inhibited in, 258 Borates in ethylene glycol vs, 179 Butylamines for, 242 Cavitation, phosphates vs pumps in auto cooling systems, 180, 181 Chloride vs deicing salts, 183 Coatings for, 192 Copper vs, 115, 132 Desalination, use in, 151 Glycol water, protection in, 178 Heat exchanger tubing, 132 Hydroxide, inh. for reinforcing steel in concrete, 259 Inhibitors, characteristics of, 178, 240, 241 Mechanism of corrosion, 241 Nickel chromates for, 241 Oil emulsions vs antifreeze sol., 241 Oils with adsorption inh. for, 245 Oxides vs vanadium pentoxide attack, 252 Pipelines for crude petroleum, 95 Salt water in, 154 Sodium chromate for, 242 Static vs dynamic rates in sea water, 250 F, 152 TCA, Dalapon vs, 255 VPI for, 225, 226, 227 Water cooling, dichromate zinc protective in, 138 Water cooling, polyphosphates in, 136 Ambiodic function, 14 Amchem,168 American Boiler Manufacturers' Assoc. Standards for steam purity, 199 American Petro. Inst. gravities, 45.4 to 76.6 degrees, 92 AMERICAN SOCIETY FOR TESTING and MATERIALS A u to engine cooling system test method, 176 Coupon designation, D-665-54, 92 Gum test, 91 Inhibitor test methods, 40 Laboratory tests, 34 Oxygen stability test, 91 Pump cavitation test, 181 Turbine oil test, D-665-54, 93 Water separometer index, [WSIM] test, 91 Amides in steam condensate, 214 Amides for petro. wells, 69 AMINE Ethylene oxide antifoams for boilers, 209 Nitrite, vapor phase inhibitors, 224 Oxygenated petroleum acid vs oxygen, 87 Water solutions, corrosion in salt, 149

2

A AMINES Bacterial attack, vs, 234 Boilers in, 204, 215 Carbon dioxide in boilers vs, 215 Cyanides in petro. ref., vs, 49 Packer fluids, used in oil, III Petro. drilling, in, 108, 109 Petro. ref., in, 45 Water floods, in, 80-82

I I

I 1 i i

4I Aminoazophenylene, 16 Aminobenzoates, VPI, 206 Aminobenzoic acid in coatings, 194 Aminoethylethanolamine structure, 23 Aminoethylene phosphonate-zinc sulfate for water floods, 76 Aminomethylene phosphonates + Zn vs oxygen in water floods, 86 Aminophenol (M&P) structure, 24 Aminophenol in alkalis vs Cu alloys, 248 Aminophenol derivatives vs acids, 158 AMMONIA Boilers in, 204 Cu alloys vs, 212 Desalination, control in, 152 Hydrazine reaction, 205 Inorganic deposits, infl. on petro. ref., 55

Organics vs petro. ref. inorganic deposits containing, 55 Petroleum, crude in tanks, 98 Petro. ref. in condensate, 45 Process streams in, 46 Steam condensate, use in, 212 Zinc alloys vs, 212 AMMONIUM Bifluoride in citric acid cleaners, 156 Chloride deposits, 45 Cyanate vs amm. nitrate, 255 Hexafluorophosphate for AI, 243 Nitrate, amm. thiocyanate inhibitors in, 255 " mercaptobenzothiazole, inh. of, 255 " thiourea inh. for, 255 " sod. chromate vs, 255 " urea vs, 255 Oxalate, inh. for Zn, 162 Phosphate, inh. for Zn in acids, 162 Sulfate vs deicing salt, 183 Amphoteric compounds for petro. wells, 70 AMP-zinc, 86 Anaerobic organisms, mechanism, 229 Aniline structure, 23 Anilines vs acids, 158 Anodic, inhibitors, 87 Anodic inhibitors for reinforcing steel in concrete, 259 Antifoams in boiler water, 209 Antifoulants, economics, 57 Antifoulants in petro. ref., 57 Antifoulant patent list, 57 Antifreeze in auto engines, 177 Antimony trichloride in MEA systems, 51

I

1

A

B

A AUTOMOBILES (Cont'd.)

Antimony trimethoxide in coatings, 194 Antimony vs vanadium pentoxide in turbines, 254 Aphenylacridine for AI, 243 Area, surface infl. on corrosion rates, 164 Arginine (I) in coatings, 194 Arsine gas, IS 8 Arsenic vs acids, IS 8 Arsenic, vs dealloying of Cu-Zn tubes, 131 Arsenic in water floods, 78 Aryl and alkyl sulfoxides vs acids, 158 Asphalt coatings, 220 Atlas Electric Devices Co., 222 AUTOMOBILES Al in cooling system, 175 Antifreeze inhibition, 35,175,180,241 Benzoate-nitrite for engine cooling, 180 Benzotriazole in cooling system, 179 Bicarbonate ion in cooling systems, 175 Body, accelerated tests for, 187 Borates in cooling systems, 179, 181 Borax, metasilicate, polar oil for Al in glycol-water, 178 By-pass filter in cooling systems, 179 Chlorides in cooling water, 174 Copper and brass, inh. in glycol-water, 178 Cooling systems, chromates in, 178 " cleaning with oxalic acid, 175 " methoxy propanol antifreeze, 177 " mixed inhibitor systems for, 180 " GM formulation of inhibitors for, 181 " nit'rites, nitrates in, 177 " triethanolamine, phosphoric acid and sodium salt of MBT, 180 Diesel engine cooling systems, 179 Deicing salts vs, 182 Emulsifiable oils in cooling systems, 177,179 Galvanic tests in glycol-water solutions, 178 Inhibitor tests, 34, 173, 176 Light, infl. on chromates in methanol, 178 Mercaptobenzothiazolti, sodium salt in glycol-water, 178 Methyl alcohol antifreeze in cooling systems, 177 Nucleate boiling in engines, 174 Oil and grease coatings for, 223 Oxygen in engine cooling systems, 174 Phosphates in cooling system inhibitors, 180 Potassium dichromate in glycol and/or tap water, 178 Pressure, infl. in cooling systems, 174 Rust preventive maintenance, 186 Sodium borate, benzoate, nitrite in glycol and/or tap water, 178 Solder, in cooling systems, 174 Sodium sulfite in cooling systems, 179 Sulfates in cooling systems, 174 Temperatures, engine, 174

BOILERS (Cont'd.)

Water impurities, corrosion prod. infl. in cooling systems, 174 Azelaic acid salts in coatings, 191

B BACTERIA Jet fuel, in, 232 Petroleum wells, in, 69 Sulfate reducing in cooling water, 129 Sulfide producing in water floods, 80, 85 Bactericices, 234, 238 Barriers, 4, 48 Barium sulfate vs vanadium pentoxide, 252 Batch treating, petro. wells, 65, 67 BIOLOGICAL ATTACK Bactericides, 238 Chlorophenate compounds vs, 239 Chromates vs, 234 Cleaning vs, 234 Organic sulfur compounds vs, 234 Octyldecylamines vs, 234 Phosphates, infl. on, 234 Sulfate reducing bacteria in paper mills, 236 Benzene, water sol. in, 89 Benzimidazole structure, 24 Benzoate nitrites for AI in glycol-water sol., 178,180 3-Benzylamino-I-butyne structure, 21 Benzylmercaptan structure, 25 Beta-naphthol in alkalis in Cu alloys, 248

BENZOTRIAZOLE Auto cooling systems, 179 Cooling water, in, 143 + Sodium molybdate or arsenate arsenite + buffer for AI, 243 Structure, 23

or

Blowdown disposal, cooling water, 127 BOILERS Alcohol-amides vs steam attack, 215 Alkalinity, 207, 210 Aluminum deposits in, 210 Amines in, 204, 212, 215 Ammonia hydrazine reactions, 205 Ammonia-oxygen reaction with Ag, Cu as catalysts, 205 Antifoams in, 209, 210 Brass tubes, erosion corrosion, 201 Butyric acid vs caustic embrittlement, 212 Calcium carbonate scale, polyphosphates vs, 206 Calcium chloride in, 202 Calcium soap vs residual oil in, 254 Carbon dioxide in, 203, 215 Carryover problems, 199,202,213

3

Catalysts of HCI, NaOH formation in, 199 Caustic embrittlement, 200, 211 Cavitation in, 197 Chelants, use in, 208 Chlorides infl. on SCC in, 201, 212 Concentration effects in, 200 Condensate, amides, imidazolines, pyramidines in, 214 Condensate, film formers in, 213 Condensate, octadecylamine, in, 213 Condensate, volatile amines in, 212 Cu precip. in, 200 Cyclohexylamine in nuclear systems, 247 Deposits from amines, 215 " coagulation, fIltration of, 206 " film formers, infl. on, 215 " pitting, infl. on, 200 " sources of, 197 Dicyclohexylamine in condensate, 213 Dihydrazine phosphate vs scale, 206 Dispersants, organic vs sludge and scale, 208 Economics of inh., 196 Economizer deposits, 197, 207 Electrochemical factors of corrosion, 199 Erosion corrosion in, 201,212 Ethylenediamine tetra acetic acid as chelant in, 208 Feed water clarification, 206 " magnesium infl., 207 " phosphate reversion, 207 " pretreatment, 203 Floc removal, 206 Foaming, causes of, 199 Hydrazine in, 205, 247 Hydrochloric acid formation in, 199 Hydrogen sulfide in, 199 Hydroxide concentrations vs magnesium, 208 Idle, dihydrazine for, 206 Ion exchange water pretreatment, 203 Low pressure, 198,208 Magnetic iron oxide, control of deposits in, 199,208 Makeup water, softening of, 206 Morpholine and cyclohexylamine in condensate, 212 Nitrates and q uebracho extract vs caustic embrittlement, 211 Nitrilotriacetic acid as chelant in, 208 Nuclear primary, boron in, 247 Nuclear reactor, SCC due to chlorides, 201 Oil contamination of, 198. 199 Oleic acid in steam condensate, 214 Oxygen, infl., 201, 204 pH control in, 204, 210 Phosphates in, 197, 207 Pitting, causes of, 200 Polyphosphates in makeup water, 206 Potassium nitrate vs caustic cracking of, 212 Precipitation treatment, 207

B BOILERS (Cont'd.) Preboiler problems, 196 Pressure, table of sodium nitrate/sodium hydroxide ratios, 211 Salt mixtures, corrosion by, 199 Scale, characteristics of, 197, 198 Shutdown, problems in, 202 Silica concentration vs magnesium, 208 Sludge, calcium phosphate in, 207 Sludge, content analysis, 198 Sodium hydroxide formation in, 199 Sodium phosphate-sodium hydroxide ratio in, 210 Sodium sulfa te-alkalinity ratio, importance in, 211 Sodium sulfate vs hydrazine in water, 206 Sodium sulfate vS' hydroxyl ion vs caustic cracking in, 211 Softening of water by ion exchange, 204 Solubilizing treatment, 207 Steam condensate, infl. of oxygen in, 202,212 Steam locomotive, terpenes in, 198 Steam purity tests, 210 Stresses in, 200, 201, 212 Supercritical, inh. of, 247 Superheater problems, 202, 212 Tannin vs caustic embrittIement, 212 Trisodium phosphate for pH control, 210 Tube, erosion corrosion prevention in, 212 Tubes, hydrazine vs CuNi brass in, 206 Tube pitting by sulfite catalysts, 205 Turbulence vs Cu in, 201 Water, Ag, Cu as catalysts in, ammonia-oxygen reaction, 205 Water carryover, control, 209 Water, dissolved oxygen in, 204 Waste sulfite liquors vs caustic embrittlement,212

Borates, in auto cooling systems, 179, 181 Borates, pumps vs seals in, 216 Borax, inh. of Al, Cu alloys in glycol-water sol., 178 Boron, nuclear primary boilers in, 247 Boundary layer phenomena, 167 Bicarbonate ion in auto cooling systems, 175 Bicarbonate, in desalination, 152 Bicarbonate, potable water, cone. in, 116 BIOLOGICAL FACTORS Algae in cooling water, 129 Petro. drilling fluids, in, 107 Petro. refining, bacteria in, 47 Nitrite, decomposition by bacteria, 133 Polyphosphates vs, 135 Water, cooling, biocides with low chromates in, 145 Wood, treatment for, 132 Brass, erosion-corrosion of boiler tubes, 201

c

B

CARBON DIOXIDE (Cont'd.) Brass, silicate vs dealloying, 135 Brines, inhibition of, 76 Brines, refrigeration, 258 Bromine vs acids, 161 Butane, water solubility, of, 89 Butene, water solubility of, 89 Butylamines for Al vs acids, 242 2-Butyne-l,4-Diol structure, 20 n-Butylamine structure, 22 Butyl mercaptan structure, 25 Butyl nitrite structure, 25 Butyl sulfide (di-sec) structure, 25 n-Butyric acid structure, 21 Butyric acid vs caustic embrittIement boilers, 212

Condensate gas wells, in, 63 Catacarb process removal of, 51 Film formers vs, in steam, 215 Hydrogen sulfide removed from, 50 Petro. drilling, infl. in, 106, 108 Potassium nitrite, chromate vs, 51 Pipelines, in natural gas, 96 Sodiummetavanadate to remove from hydrogen streams, 51 Steam condensate, in, 212 Tests, influence on, 32 Waterfloods, in, 76 Velocity effect, 4 of

c CALCIUM Desalination, removal during, 152 Formate in deicing salt, 183, 251 Molybdate in coatings, 192 Orthophosphate deposition, in cooling water, 135 Phosphate and methylene phosphonate zinc in cooling water, 141 Phosphate sludge in boilers, 207 Plumbate in coatings, 192 Potable water, conc. in, 116 Salts, infl. in boilers, 202 Soap vs residual oil in boilers, 254 Silicate in boilers, 198 Sulfate control in cooling water, 128 Sulfate scale, surface potential in desalination, 152 Sulfates vs vanadium pentoxide, 252 Water floods, in, 77 CALCIUM CARBONATE Boilers, in, 197 Coatings, in, 191 Polyphosphate in potable water, 118 Scale vs polyphosphate, silicate in booling water, 140 Scale in boilers, polyphosphates vs, 206 Steel reinforcing in concrete, as inhibitor, 259 Water, cooling, in, 128, 136 CALCIUM CHLORIDE Automobiles, vs, 182 Inhibitors vs, 185, 251 Calgon,260 Canadian Tests of deicing salt inhibition, 183, 184, 185 n-Caproic acid structure, 21 n-Caprylic acid structure, 21 Carbamates, bactericides, 238 Carbon, activated, additive to sulfite in boiler water, 205 Carbonate saturation, in potable water, test for, 119 CARBON DIOXIDE Boilers, attack on, 203

4

Carboxy methyl cellulose as boiler scale dispersant, 208 Cargill, Inc., 184 Carguard, 184, 185 Catacarb process, 51 CATALYSTS Boilers, Ag-Cu in ammonia-oxygen reaction, 205 Boilers, HCI, NaOH formed by, 199 Boiler pitting by plating on tubes, 205 Cobaltous ion for sodium scavenging in water floods, 85 Catalysis, hydrazine by Cu ions, 79 Catalyzed sodium sulfite in boiler water, 205 Catalyst, for water flood oxygen scavenging, 79 Cation exchange in desalination, 152 Cations, metal, infl., 13 Cathodic depolarization by bacteria, 230 Cathodic depolarization by chromates, 134 Cathodic inhibitor functions, 14 Cathodic, polarization by polyphosphate in cooling water, 136 Cathodic protection, bacterial attack, vs, 234 Cathodic, water floods, reaction in, 78 Caustic, Cr-Ni, Cr-Ni-Mo, attacks by, 200 CAUSTIC EMBRITTLEMENT Butyric acid vs, 212 Nitrates and quebracho in boilers vs, 211 Potassium nitrate vs, 212 Steel, causes, prevention, 201, 211 Tannins vs, 212 Waste sulfite liq uors vs, 212

Caustic Soda-See Sodium Hydroxide CAVITATION Al pumps in auto cooling systems, 181 Diesel engine liners, chroma tes vs, 181 Petroleum wells, infl., 62 Pumps for boilers, 197 Ceric sulfate vs boiling acids, 163 Cerium vs vanadium pentoxide in turbines, 254

I

~

I I

c

c

c COATINGS (Cont'd.)

C-factor , calculation of, 92 Chain lengths, alkyl significance of, 81 CHC,225 Chelants, boilers, in, 208 Chelants, coatings, trisodium salts of ethylene diamine tetra acetic acid in, 223 Chelants, desalination, in, 152 Chloramines in cooling water, 129 CHLORIDES Auto engine cooling system, in, 174 Boilers, SCC of, 201, 212 Dye baths, hot, 257 Influence of, 13 Petroleum refinery waters, control in, 52 Water, conc. in potable, 116 Chlorinated amines vs acids, 158 Chlorinated hydrocarbon weighting agents, 68 Chlorinated phenols vs microorganisms, 107 CHLORINE Acids, vs, 161 Benzotriazole in cooling water vs, 143 Ethanoldiphosphonate demand in cooling water, 142 Mercaptobenzothiazole vs, 142 Titanium, vs, 163 Water, cooling in, 129 Chlorophenates, bactericides, 238 Chlorophenates in cooling water, 129 CHROMATES Aluminum vs acid attack on, 241 Auto cooling systems, in, 178 Barium potassium in coatings, 192 Basic lead silico, in coatings, 192 Bicarbonates in desalination, 151 Biological attack, vs, 234 Cathodic depolarization by, 134 Coatings, used in, 193 Deicing salt, in, 183, 184,252 Light, influence on, in methanol, 178 Passivation, critical, in cooling water, 133 Petroleum drilling fluids, in, 106 Petroleum refineries, in, 43 Pitting due to low concentrations, 134 Poly phosphates and zinc in cooling water, 137, 139 Phosphate-zinc-iodide in desalination, 151 Pumps, hot water, vs seals, 216 Strontium, in coatings, 192 Water, cooling, in, 133, 144 Water floods vs oxygen, 80 Zinc in coatings, 192 Zinc in cooling water, 138 Chromium, acetyl acetonate in coatings, 194 Chromium oxide in coatings, 192

Chromium, hexava1ent in coal slurry pipeline, 256 Chromoglucosates in cooling water, 142 Cinnamic aldehyde, structure, 21 Citric acid in boilers, 156 COATINGS Acrylic latexes, inhibition in, 191 Alizarin in, 194 Alkyl aminoalky1 phosphate, in, 194 Alkyds with inhibitors, 192 Alkyl benzyl dimethyl-ammonium chloride, in, 193 o-Aminobenzoic acid in, 194 Anodic inhibitors in, 190 Anionic fatty amido phosphate, in, 194 Antimony oxide in, 192 Antimony trimethoxide in, 194 I-Arginine in, 194 Azelaic acid salts in, 191 Barium potassium chromate in, 192 Barium salts of organic phosphate esters, in, 194 Basic lead silico chromate in, 192 Cadmium chromate in, 192 Calcium carbonate in, 191 Calcium molybdate in, 192 Calcium p1umbate in, 191 Carbon black in, 192 Cathodic inhibitors in, 191 Chalk in, 192 China clay in, 192 Chromium oxide in, 192 Chromium acetyl acetonate in, 194 Chromium, tris (2-hydroxyacetophenono) in, 194 Crevices, for use in, 193 2,6-Dimethyl-3,5- heptanedione in, 194 Emulsifiable, oil type, 221 Esters, 221 Ethane, Bis (1,2-{!ipheny1arsine) in, 194 Guanidine chromate, in, 195 3,5 Heptanedione in, 194 Heptafluoro-1(2-thienyl)-1, 3-hexanedione,194 2,4-Hexanedione in, 194 Hexafluoroacety1 acetone in, 194 4-Hydroxybenzophenone in, 194 Humidity, infl. on, 191 Inhibitors used in, 190 (table), 192 Iminodiacetic acid, disodium salt in, 194 Inert material in, 190 Iron oxide in, 192 lsatin in, 194 Lead, blue in, 192 " carbonate in, 192 " red in, 192 "suboxide in, 191 " titanate in, 192 Linseed oil soaps in, 191 Litharge in, 191 Magnesium, for, 193 Maleic acid, in, 194 Mechanism of bonding to substrate, 190 Moisture displacing, 221 Nitrilo triacetic acid in, 194

5

Oil and grease, application, 222 " flotation, 224 " mineral, 221 " post-protective procedures, 223 " solvent type, 221 " vs vapor, 224 Oleoyl sarcosine in, 194 2,4-Pentanedione in, 194 Picrolonic acid in, 194 Pigments in, 190 Phosphated fatty alcohols, in, 194 Preferential wetting by, 190 Pyrocatechol in, 194 'Red lead in, 191 Resin, 221 Salicylic acid in 194 Silicones, 221 Silico plumbate in, 192 Sodium petroleum sulfonate in, 194 Sodium su1fate vs, 191 Sorbitan fatty ester in, 194 Strontium chromate in, 192 Surfactants in, 193 Talcum, in, 192 Tannin after abrasive blasting, 193 Titanium dioxide in, 192 Toluenechromium tricarbonyl in, 194 p-To1ylarsonic acid in, 194 Tributyl antimony in, 194 4,4,4-Trifluoro-1(2-thienyl) -1,3-butanedione in, 194 Triphenyl arsine in, 194 Wax, 221 Zinc acetylacetonate in, 194 Zinc chromates in, 190, 192 Zinc cyclohexane butyrate in, 194 Zinc molybdate in, 192 Zinc oxide in, 191 Zinc tetroxychromate in, 192 Clarification of boiler feed water, 206 CLEANING Acids, using, 165 Auto cooling systems, 175 Bacterial attack, to avoid, 233 Surfaces prior to oil and grease coatings, 223 Coagulation of boiler deposits, 197 Cobalt, catalyst \vith sod. sulfite in boiler water vs oxygen, 205 Cobaltous ion scavenging of oxygen from water floods, 85 Coke nuclei, inhibition in process streams, 56 Colloidal peat as boiler scale dispersant, 208 Computer analysis of petroleum production inhibitor result s, 74 Concentration cells, in boilers, 200 Condensate, boiler, HCl in, 199 Condensate, gas, NGPA classification, 63 Condensate, petro. ref., ammonia in, 45 Continuous treating petro. wells, 65, 72 Controlled scaling, water floods, 86 Cooling towers, absorption of air contaminants in, 128

c

c COPPER AND ALLOYS (Cont'd.)

Cooling towers, tests for, 37 Cooling water, chlor amines in, 129 Cooling water, chlorine in, 129 Cooling water, chlorophenates in, 129 Corrater, 31, 37 Corrosometer, 30, 37, 86, 238 COPPER Catalyst in ammonia-xygen reaction in boiler water, 205 Catalyst with sod. sulfite in boiler water vs oxygen, 205 Ion displacement test, 32 Salt bactericides, 238 Sulfate vs boiling acids, 163 Water in cooling, 129 Water, infl. in potable, 117 Water, vs salt, 154 COPPER AND ALLOYS Acid cleaning of, 156 Acids, inhibitors vs, 161 Alkalis vs, 248 Aluminum, effect on, 115, 132 m-Amino phenol in alkalis vs, 248 Ammonia vs, 45, 212 Auto cooling systems, ,infl. on Al in, 175 Beta napthol in alkalis vs, 248 Boilers, effect on, 199 Borates in ethylene glycol vs, 179 Brass vs TCA, Dalapon, 255 Catechol in alkalis vs, 248 Cresol in alkalis vs, 248 Dezincification of brass in alkalis w/glucose, 248 Ethanoldiphosphonate dichromate or zinc in cooling water, vs, 141 Furfuraldehyde in alkalis vs, 248 Gallocyanine in alkalis vs, 248 Glucose in alkalis vs, 248 Glycol-water, inh. in., 178 Hydroxy quinoline in alkalis vs, 248 Hydrazine, catalytic infl. with, 79 Impingement attack, 117, 131 Mercaptobenzothiazoles as bactericides, with,234 Methylenephosphonate-zinc in cooling water vs, 141 Petro drilling, vs hydrogen sulfide, 107 Petro. ref., in, 44, 56 Phloroglucinol in alkalis vs, 248 Pipe, flow velocities for, 117 Pitting in potable water piping, 117 Pitting by polypohsphate-ferrocyanide, in cooling water, 140 Pyrogallol in alkalis vs, 248 Quinalizarin in alkalis vs, 248 Resorcinol in alkalis vs, 248 Salicylaldehyde in alkalis vs, 248 Sodium diethyl dithiocarbamate in alkalis vs, 248 Sodium rhodizonate in alkalis vs, 248 Tannin in alkalis vs, 248 Thiourea in alkalis vs, 248 Velocity effects, 4

Water cooling vs chromate, polyphosphate in, 137 Water cooling, mercaptobenzothiazole protects in, 142 Water, cooling, pH vs pickup in, 136 Coal, slurry pipeline, hexametaphosphates in, 256 Coal, slurry pipeline, hexavalent chromium, 256 Concrete, steel reinforcing bars, inh. of, 259 COUPONS ASTM D-665-54 designation, 92 MIL-I-25017C,93 NACE Standard test, 30, 70 Petrol. well, monitoring results with, 72,103,110 Product pipeline tests with, 92 Crevices, boiler, infl. on caustic embrittlement, 200 Crevices, inhibited coatings for, 193 Crevices, phosphate benefits in boiler, 210 Cronox, 168 Crude oil pipelines, 95 Cupronickel tubing vs sea water, 131 Current-voltage measurements, 31 Cyanide as hydrogen blistering catalyst, 49 Cyano-ethylated amines vs acids, 158 Cyclic and heterocyclic keto amines vs acids, 158 Cyclic loading, infl. in petrol. wells, 62 Cyclohexane, water solubility of, 89 CYCLOHEXYLAMINE Boiler condensate, in, 212, 213 Boiler water, in, 204 Carbamate, 225 Chromate, VPI for nonferrous metals, 225 Nuclear system boiler, in, 247 Neutralizer in petro. ref., 55 Structure, 25

o Dalapon, 255 Deaeration of boiler water, 204 Deaeration, desalination plant, 149 Dealloying of brass in cooling water, 131 Decam ethy lene-b is-dimethyl hexadecyl ammonium bromide structure, 23 Decamethyleneimine structure, 24 n-Decylamine structure, 22 Degassing to remove oxygen, 153 Dehydration products pipelines, 90

DElCING SALTS Canadian tests, 183-185 Carguard vs, 184 Chromates vs, 183,252 Economics of inhibition, 185 Inhibitor evaluation, 185 Metaphosphates vs, 183

6

o DEICING SALTS (Cont'd.) NACE report, 183 Phosphates, urea, formamide, calcium formate vs, 251 Polyphosphate-nitrate vs, 183 Sodium hexametaphosphate vs, 185 Sodium salt or N-alkyl-sulfonyl-glycine vs, 185 Sodium zinc metaphosphate vs, 185 Strontium salt vs, 183 Testing inhibitors for, 183 Density tests, 38 DEPOSITS Amines causing boiler, 215 Boiler, coagulation, 206 Boiler, filtration, 206 Diesel engines, gas turbines from V20S additives, 253 Dry, attacks under, 45 Paper mills, accumulation, 236 DESALINATION Aluminum for, 151 Amine-water solutions, 149 Ammonia in, IS 2 Calcium, magnesium, removal, during, 152 Carbonates, removal of, 152 Cation exchange resins, 152 Chelating agents in, IS 2 Chromate-bicarbonate in, 151 Chromate-phosphate-zinc-iodides in 151 Copper removal during, IS 3 Dichromate with C steel, in, IS 3 Degassing techniques, IS 3 Flash distillation, summary of inhibitors, IS 3, 154 Graphite tubes used in, 152 Guantanamo, Cuba plant, ISO 110,Peru plant, ISO Iron removal during, IS 3 Kuwait plant, 150 Lanzarote, C.1. plant, 150 Materials, 149 Oxygen control in, 151 Nitrites with C steel in, IS 3 Phosphates with C steel in, 153 Point Lama plant, 150 Polyphosphates in, 150 Scale control, 149 Sodium arsenite in, 153 Sodium silicate with C steel in, 153 Steel, carbon in, IS 3 Vanadates with C steel, 153 Zinc ion with C steel, 153 Desalters, pH control, 44 Detergency, 38 Dextrin, inh. for AI, 162 N ,N-Dialkylaniline R=methyl or ethyl i>tructures, 25 Diamines, bactericides, 238 Diamines, molecular structures, 82 Diamines, petroleum wells, in, 69 Diamines, water floods, in, 81 3,5-Diaminobenzoic acid vs hydrochloric acid,20

o 3,5-Diaminobenzoic acid structure, 24 Diaminoethanolamine structure, 23 Diamylamine structure, 22 Dianodic, 137 Diba~ic amm. phosphate for steel in amm. nitrate-amm. sol., 255 Dibenzyl sulfide structure, 26 Dibenzyl sulfoxide structure, 26 Dibenzyl sulfoxide vs acids, 158 Dibutyl amine structures, 22 Di-n-Butyl sulfoxide structure, 26 Dichan, 224 Dichromate, active region dosages in cooling water, 134 Dichromate for steel in hot sea water, 152 Dicyclohexylamine chromate structure, 25 Dicyclohexylamine nitrite structure, 25 Dicyclohexylamine in steam condensate, 213 Dicyclohexylammonium nitrite, 224 Didecylsulfide structure, 25 Diesel engine cooling system, 179 Diethyl am'ine structure, 22 Diethanolamine structure, 23 5-Diethylamino-4-pentyne 2001-structure, 20 Diethylenetriamine structure, 23 Diethyl sulfide structure, 25 Diethylthiophosphate structure, 26 Diffusion phenomena in acids, 167 Diglycolamine process, 50 Dihydrazine phosphate for idle boilers, 206 Diisopropylamine + 5% NaG, 149 Dilinoleic acid + Na(CHME2) + mercaptobenzothiazole, 243 Dim e thyloctadecylphosphonium bromide structure, 26 2,6-Dimethylquinoline structure, 24 Dimethylsulfoxide structure, 26 Di-n-Octylamine structure, 22 Dioctylthiophosphate structure, 26 4,5-Diphenylimidazole structure, 24 1,3-Diphenyl-l-, 3-Propanedione in coatings, 194 Diphenylsulfide structure, 25 Diphenylsulfoxide structure, 26 1,3-Diphenylthiourea structure, 26 Dipropargyl ether structure, 21 Dipropargyl thioether structure, 21 Di-p-Tolyl sulfoxide structure, 26 Disodium hydrogen phosphate for Al in antifreeze, 241 Disodium phosphate in brines, 258 Dithionite, 79, 80 Dodecylbenzyl aromatic amines vs hydrochloric acid, 18 ,D 0 d e cy I ben z yldimethyl-ammonium chloride structure, 23 Dodecylbenzyl q uinolinium bromide structure, 23 N-Dodecyl B-Methylene diamine structure, 22

Dodecyl pyridinium xanthate, 158 Drawing oil, rust preventive for, 223 Duomeen-T for petro. wells, 70

E ECOLOGICAL FACTORS Blowdown disposal, cooling water, 127 Chromates in cooling water, 135 Phosphates in potable water, 124 Sulfonated tannins, sugar acids, blowdown problem, 142 Thermal contamination, 126 Tests, laboratory, 39 Water, cooling, blowdown, phosphate removal, 144 Water, cooling, blowdown, zinc removal, 144 Water cooling, chromate removal from blowdown, 144 Zinc in potable water, 124 EDT A, 77, 208 ECONOMICS Antifoulants in petr. ref., 57 Boron salvage at nuclear plant, 247 Chromate-polyphosphate-zinc in cooling water, 139 Coal slurry pipeline, 256 Digesters in paper mills, 236 Deicing salt inhibition, 184 Desalination, 148 Dichromate zinc in cooling water, 138 Natural gas pipelines, 97 Octadecylamine in boilers, 215 Petroleum, crude tanks and pipelines, 98 Petro drilling, 104 Petroleum production, 61 Petroleum ref., 48 Petrol, sweet oil wells, 63 Street deicing salts, 251 Polyphosphates in cooling water, 136 Polyphosphate, polyphosphate-zinc in potable water, 123 Value of inhibition, 2 Vehicles, oil and grease coatings, 223 Economizers, boiler deposits, 197 Economizers, polyphosphates, in boiler, 207 Electrical resistance measurements in water floods, 84 Electrical resistance probes, 238 Electron acceptors, 13 Embrittlement cracking, 108 Emulsifiable coatings, 220 Emulsifiable oils for auto engines, 177, 179 Emulsification problem, products pipelines, 91 . Emulsification. WSIM test for, 47 EMULSIONS Blocks, squeeze treating, 66 Petro wells, in, 62 Petro wells, with heavy liquids, 68 Problems with, 37 Engines, automobile, 173 Engines, oil and grease coatings for, 223 Environment, alterations of, 48 Erdco CFR device, 58 Erosion, corrosion in boilers, 201, 212 Erosion, petro wells, in, 62

7

E

Estosolvan process, 50 Ethane (bis (1,2-diphenylarsine) in coatings, 194 Ethanolamine, petro. ref., 44 Ethanolamine, sulfur removal, 50 Ethanoldiphosphonate mixtures in cooling water, 141 Ethoxylation, significance of, 81 Ethylamine structure, 22 l-Ethylamino-20ctadecylimidazoline structure, 23 Ethylenediamine tetracetic acid as boiler cheland, 208 Ethylene glycol, in auto radiators, 173, 177 Ethylene glycol, borates in, 179 Ethylene diaminetetraacetic acid in water floods, 77 Ethylene glycol, chromates in, 178 Ethyleneglycol bis-dibenzylxanthate structure, 26 Ethylene oxide adducts of abietyl amines vs acids, 158 Ethyl sec-butylamine desalination, 149 Ethyl-noOctyl sulfide structure, 25 6-N-Ethylpurine structure, 23 4-Ethylpyridine structure, 24

F Field tests, See Testing, on site FILM

Formers, concentration, 47 Measurements, 32 Moisture, displaced by coatings, 221 Persistency, 36 Water floods, stability in, 81 Filming inh. vs 230-260 C, 47 Filming inhibitors for petro. ref., 45 Filter, by-pass, in auto cooling systems, 179 Filtration of boiler deposits, 206 Fatigue, film formers vs, 52 Fatty acids in auto cooling systems, 179 Fatty acids, composition, 83 Fatty acids in petro. ref., 43 Ferric bromide vs boiling oxalic acid, 163 Ferric chloride vs boiling oxalic acid, 163 Ferric ions, infl. on acid cleaning, 157 Ferric oxalate vs boiling oxalic acid, 163 Ferrocyanide-polyphosphate in cooling water, 140 Ferrocyanide in hydrogen treating, 49 Ferrous metals, acids vs, 156 Fingerprints, oil and grease vs, 220 Fingerprints, removers, 221 Fingerprints, water emulsifiable coatings vs, 221 Firearms, oil and grease coatings, 223 Fire floods, organic acids in, 77 Fire floods, secondary recovery, 76 Floc, boiler, removal of, 206 Flotation application in tankships, 100 Flotation type coatings, 224 Fluorides, fluorosilicates vs Al in cooling water, 136

F

G

H

GALVANIC COUPLES (Cont'd.) Fluorides, potable water, conc. in, 116 FOAMING Boilers, 199, 209 Desalters, in, 44 General, 35, 39 MEA systems, 51 Fogging in tankships, lOO Fog treatment, natural gas pipelines, 97 Formaldehyde-amide condensate as boiler antifoams, 210 Formamide for AI, 243 Formamide in deicing salt, 183, 251 FOUUNG Aromatics, infl. on, 56 Erdco CFR coker test device,S 8 Dispersants vs, 56 Heterocyclic hydrocarbons, infl. on, 56 Hot wire test, 59 JFTOT test device for, 58 Olefins, infl., 56 Paraffin infl. in, 55 Petro ref., Cu, V, Ni infl. on, 56 Petro ref., free radicals infl. 56 Petro ref., organic,S 5 Prediction by tests, 55 Surfactants vs,S 6 Temp. stability of compounds vs, 56 Fourdrinier wire attack by bacteria, 233 Freeport, Tx desalination, 149 Free radicals' infl. on petro. ref. fouling, 56 Freezing process, desalination, 149 Freundlich isotherms, 17 Friction, products pipelines, calculating C factor, efficiency, 92 Fuel, aircraft, MIL test for inhibitors, 91 FUEL OIL Borax vs, 256 Chromates vs, 256 Domestic tanks, inh., 256 Sodium nitrite, alkaline buffer vs, 256 Fungi,228 Fungicide treatment of wood cooling towers, 132 Furfuraldehyde structure, 21 Furfuraldehyde in alkalis vs Cu alloys, 248 Furfural units, control in, 52

G Gallocyanine in alkalis vs Cu alloys, 248 Galvanic attack, copper in drilling fluids, , 107 Galvanic attack, polyphosphates in cooling water vs, 135 Galvanic attack, water, potable in, 117 GALVANIC COUPLES Al-Cu, borates vs in ethylene glycol, vs, 179 Acid cleaning, during, 157

Auto cooling systems, 34 AI-steel, inh. vs, 242 Boilers, Cu-Fe, in, 200 Measurements, 32 Oil and grease compounds vs, 187 Galvanic tests in glycol-water sol., 178 GASES Air-contaminated, amine oxygenated petroleum acid in, 87 Equilibrium in steam, 203 Explosive, during acid cleaning, 157 Natural, mono ethanolamine desulfurizer of, 97 Petro. ref., phase in, 43 Poison, generated during acid cleaning, 157 Potassium carbonate, hot, sweetening of,51 Processing, 50 Stripping oxygen from water floods, 84 Treatment modes, 46, 51 Venting in water floods, 81 Well characteristics, 61 Well packer fluid tests, 35 Gasoline, rust test, turbine oil, 93 Gasoline, water solubility in, table, 89 Glassy polyphosphate for water floods, 82 Glucose for AI, 243 Glucose in alkalis vs Cu alloy, 248 Glucosates as dispersants in boilers, 208 Glycol weighting agents, 68 Graphite, tubes in desalination, 152 Graphitization, cast iron during acid cleaning, IS 7 Grease coatings, 220 Guantanamo, Cuba, desalination plant, 150 Guanidine chromate in coatings, 195

H Halides vs acids, 161 Halogenated aromatics vs acids, 158 Halogen ions vs boiling oxalic acid, 163 Hardness, potable water criterion, 116 Heat exchangers, antifoulants for, 57 Heat exchangers cleaning with acids, 157 Heat exchangers in cooling water systems, 133 Heaters, potable water, liS Helmholtz layer, 7 N-Hexadecyl propylene diamino salicylate, 19 N-Hexadecyl propylene diamine structure, 22 N-Hexadecyl propylene, vs hydrogen sulfide, 18 Hexafluoroacetyl acetone in coatings, 194 Hexametaphosphates in coal slurry pipeline, 256 Hexametaphosphates vs deicing salt, 185 Hexamethyleneimine benzoate structure, 24 Hexamethyleneimine structure, 22

8

He xamethyleneimine-3, 5-dinitrobenzoate structure, 24 Hexamethyleneimine m-nitrobenzoate, VPI, 226 Hexamethylene tetramine for AI, 243 Hexamethylene tetramine structure, 22 Hexamme inh. vs aC1Qsfor Zn, Ib2 Hexane, water solubility in, 89 HF alkylation, 52 Hot dip petrolatum coatings, 220 Hot wire fouling test, 59 Humidity cabinet, 222 Humidity, infl. on coatings, 191 HYDRAZINE Ammonia reaction, 205 Boilers, CuNi, brass tubes, vs, 206 Boilers, in, 205 Nuclear systems, in, 247 Oxygen, control of dissolved in boilers, 204 Quinone catalyst for, 80 Sulfate in alkalis vs Cu alloys, 248 Hydrobromic acid, 161 Heptafluoro 1-(2-thienyl) -1,3-Hexanedione in coatings, 194 Heptane, water sol. in, 89 Heptene, water sol. in, 89 Hydrocarbons, petro ref., liquid in, 43 Hydrocarbons, specific gravity vs viscosity, (table),92 Hydrocarbon tests, 34 Hydrochloric acid cleaning, 156 Hydro desulfurizers, 52 Hydrodesulfurizers, antifoulants in, 56 Hydroiodic acid, 161 Hydrocracking, 44 HYDROGEN Catalysts in blistering, 49 Embrittlement in oil base muds, 112 Embrittlement in petro. drilling, 108 Embrittlement from petro. well packer fluids, 110 Evolution measurements, 31 Gas generated during acid cleaning, 157 Sodium met a vanadate vs CO2 in, 51 Temperature, attack at high, 42 Hydrogenase, infl. of, 230 HYDROGEN SULFIDE Alkaline arsenite-arsenate solution to absorb, 51 Al in condensate with ammonia, vs, 243 Bacteria produced in c!Joling water, 129 Boilers formed in, 199 Carbon dioxide removed from, 50 Catalyst in hydrogen blistering, 49 Copper carbonate vs in petro. drilling, 107 Crude petroleum, infl. on pipelines, 95 Electrochemical reduction in drilling fluids, 108 Embrittlement of oil well casing collar, 110

H HYDROGEN SULFIDE (Cont'd.) Heat exchangers, inh. in, 51 N-Hexadecyl propylene vs, 18 Hydrodesulfurizer units, infl. in, 52 NACE report on petro. wells, 64 Oxygen scavenging, infl. on, 85, 86 Petro wells, solutions for attack, 64 Petro drilling, control in, 103, 106 Petro drilling, metal salts vs, 107 Pipelines, in natural gas, 96 Process stream analysis, infl. on, 46 Stainless steels vs,S 2 Tests, infl. on, 32 Water floods, gas stripping from, 84 Water floods, inhibition in, 76, 80 Water floods, oxygen scavenging, initiation by tertiary butyl hydro peroxide, 86 Hydrosulfite, 79, 80 Hydroxyquinoline in alkalis vs Cu alloys, 248 Hydroxyquinoline structure, 24 Hydroxides, calcium chloride, formation in boilers from 202 Tris. (2-Hydroxyacetophenone) chromium in coatings, 194 4-Hydroxybenzophenone in coatings, 194 I-Hydro xy ethyl-2- octadecylimidazoline structure, 23

110, Peru desalination plant, 150 Imidazole, structure, 24 Imidazolines, molecular structure, 82 Imidazolines in steam condensate, 214 Imidazolines in water floods, 81,83 Iminodiacetic acid disodium salt in coatings, 194 Impingement attack on copper piping, 117, 131 Inorganic fouling in petro. ref., 55

INHIBITORS Acid systems, for, 156 Adsorbent, evaluation of, 16 Alkaline earth sulfonates, 19 Aluminum, for, 178,240 Anodic function, 14 Application, 2, 65 Cooling water analysis, 144 Batch, extended period treatment, 67 Books on, 5 Boilers, practices in, 203 Classes of, 11, 12 Coal slurry, 256 Concentration effects, 165 Definition, 1 Deicing salts, evaluation for, 185 Design principles, 13 Economics, 2 Effectiveness, theoretical aspects, 12 Efficiences of various in auto antifreeze, 178 Film persistence, 36, 81 Galvanic couples, vs, 34

INHIBITORS (Cont'd.) High density, 40 History, 2 Manufacturers, report on, 5 Materials problems with, 3 Mechanism, 28 Measurement techniques, 20 Microorganisms vs, 228 NACE activities, 5 Navy Dept., approved list, 91 Nitrates in aircraft fuel, 232 Nitrogenous, long chain in boilers, 214 Oil & grease coatings, in, 220 Oil soluble for refined products tankships, 100 Organic for oxygen in water floods, 86 Organic, types for petro wells, 69 Organizations involved with, 4 Petro. wells, concentrations used in, 65 Petroleum wells, economics, 61 Petro. well drilling and packer fluids, for, 112 Polymethyleneimines, 15 Polyphosphates in boiler feedlines, 207 Properties, 28, 37, 38 Screening by electrochemical techniques, 20 Sea water, 250 F, 148 Ships, nuclear propulsion systems, used in,3 Slug, circulate and park technique, 67 Sodium chromate and nitrite in products pipelines, 91 Solubility tests, 37 Squeeze application in petro. wells, 66 Structures of some, 20 Synergism, 166 Thiobenzene, 14 Tubing displacement technique, 66 Vanadium pentoxide, sodium sulfate vs, 252 Vapor phase, 224 Viscosity measurements, 37 Water, 149 C, for, 216 Water flood, organics, good for, 81 Water flood, vs oxygen attack in, 86 Weighting agents, 65 Intermittent treating, petro. wells, 65 Iodine vs acids, 161 Ion exchange, boiler feed water pretreatment by, 203 Ion exchange in water floods, 77 IRON Cast, graphitization during acid cleaning, 157 Ca talyst for water flood oxygen scavenging, 86 Content measurements, 47, 72 Magnetic, control in boilers, 208 Oxide + tannin in coatings for steel, 193 Petro. ref. infl. on fouling, 56 pH elevation in potable water, 118 Polyphosphate stabilization in potable water, 124 Salts vs acids, 161 Salts as boiler deposit coagulant, 197

9

IRON (Cont'd.) Water, conc. in potable, 116 lsatin in coatings, 194 lsomyl alcohol + wetting agents as boiler antifoams,210 lsobutane water solubility in, 89 lsopentane, water sol. in, 89 3-lsopropyl arnino-1-Butyne structure, 21 Isotopes, tests using, 32, 67

Jet fuel oxidatIon tester, 58 Jet fuel water tolerance, 39 JFTOT device, 58 JP-4, ASTM rust test, 93

K Kaolin vs vanadium pentoxide-sodium sulfate attack, 252 Keiselguhr vs vanadium pentoxide-sodium sulf'Ide attack, 252 Kuwait desalination plant, 150

L Langelier's formula, 119 Langmuir adsorption calculations, 166 Langmuir isotherms, 17 Lanthanum vs V20S, attack in turbines, 254 Lanzarote, Cl desalination plant, 150 Laurates for Al, 243 Laurylmercaptan structure, 25 LEAD Acetate vs acid cleaners, 157 Azelate in coatings, 191 Blue in coatings, 192 Calcium plumbate in coatings, 192 Carbonate in coatings, 192 Nitrate vs acids, 157 Red, in coatings, 191 Silicates to control pickup in cooling water, 135 Silicop1umbate in coatings, 192 Suboxide in coatings, 191 Titanate in coatings, 192 Water, potable, dissolved in, 116 Light, bacterial attack, infl. on, 233 Light, chromates in methanol, infl., 178 Lignins as dispersants in boilers, 208 Lime treatment of sewage effluent, 130 Linoleates for AI, 243 Linoleic acid, dimer of, structure, 21 Linseed oil soaps in coatings, 191 Liquids, use of heavy in petro. wells, 68 Liquefied petroleum gas pipelines, 91 Litharge in coatings, 191 Lithium chloride vs deicing salt, 183 LPG pipelines, 91 Lubricants, coatings compatible with, 221 Lubricants, petro. drilling, in, 103 2,4-Lutidine structure, 24

I M

M

M

MECHANISM (Cont'd.) Macaroni tubing, 68 Machinery, oil and grease coatings on, 223 Magna Corp., 30, 238 MAGNESIUM Boiler feedwater, infl. on, 207 Desalination, removal during, 152 Hydroxide in boilers, 197 Hydroxide inh. for reinforcing steel in concrete, 259 Lithium, aluminum chlorides vs deicing salt, 183 Silicates in cooling water, infl. of, 135 Water floods, in, 77 Water, conc. in potable, 116 Magnetite in boilers, 199 Maleic acid in coatings, 194 Maleic acid structure, 21 Manganese, catalyst for water flood oxygen scavenging, 86 Manganese naphthenate vs V20S in turbines, 254 Manganese, conc. in potable water, 116 MBT-See Mercaptobenzothiazole MEA- See Monoethanolamine Measurements-See Tests Membrane method, desalination, 149 Materials selection, alternate to inhibition, 3 MECHANISM Adsorption, 12 Aerobic bacteria, 231 Alkali bichromate VPI, 227 Alkalis, metal protection against, 248 Alkyl chain length, infl., 16 Ambiodic function, 14 Amines, adsorption, 81 Aminobenzoates, 226 Anions, effect on passivation, 178 Benzotriazole in cooling water, 143 Biological attack, 228, 237 Cathodic functions, 14 Calcium carbonate scale protection in potable water systems, 120 Caustic attack, 201, 246 Chromate orthophosphate in cooling water, 137 Chromate polyphosphate, zinc in cooling water, 138 Coatings bond to substrate, 190 Complexing with metal atom, 19 Cyclohexylamine chromate, 225 Electrical double layer, 7 EmulsiIiable oils in auto cooling system, 179 Ferrous sulfate protection, AI-brass in sea water, 143 Filming inhibitors, 45,214 Free energy, 8 Helmholtz layer, 7 Hydrogen blisters, 49 Ion exchange boiler water pretreatment, 204 Octydecylamine in boilers, 213 Oil and grease coatings, 220

Metal corrosion, 7 Metavanadate vs C02, 51 Methylenephosphonate-zinc in cooling water, 141 Mixed molecules, 14 Passivation by chromates, 134 Passivity in acid environments, 167 Polyphosphates vs calcium carbonate scale in boilers, 207 Polyphosphates, vs Cu pickup, cooling water, 136 Polyphosphate function, in cooling water, 136 Polyphosphate-zinc in cooling water, 139 Phosphonates in cooling water, 140 Polarization diagrams, 10 Sodium chromate, nitrate on steel, 90 Sodium hydroxide inhibition of boiler corrosion, 204 Structures, influence of molecular, 19 Structure, infl. of oil coatings, 221 Sulfide Itlms vs pH, cyanides, 49 Surfactants vs fouling in petro. ref., 156 Temperature influence, 13 Vanadium pentoxide attack, 252 Vapor phase inhibition, 224 Zinc, cadmium and strontium chromate in coatings, 195 M er c apto benzothiazole application techniques, 142 Mercaptobenzothiazole in glycol and/or tap water, 178 Mercaptobenzothiazole, ammonium nitrate, vs, 255 Mercaptobenzothiazole, in auto cooling systems, 181 Mercaptobenzothiazole, in cooling water, 142 Mercaptobenzothiazole, sod. salt in glycol and/or tap water, 178 2-Mercaptothiobenzole structure, 26 Milchem, 168 Mill scale, removal by pickling, 18 Miscible flood, secondary recovery, 76 Mercury, in cooling water, 129

Metal salts, infl. on acid attack, 164 Metallurgical factors, AI, related to inhibition, 240 Metaphosphates vs deicing salts, 183 Metasilicate for Al in glycol-w~ter sol., 178 Methoxy propanol as auto engine antifreeze, 177 Methyl alcohol antifreeze in auto cooling systems, 177 Methylamine structure, 22 2,2-Methylene bis (4-chlorophenol) vs nitrate reducing bacteria, 133 Methylenephosphonate-zinc or dichromate in cooling water, 140 Methylpropylamine structure, 22 Methyl styrene-maleic anhydride as boiler dispersant, 208 Monoamine, molecular structures, 82 Monoamines for petro. wells, 69 Monoethanolamine, antimony chI. as inhib. for, 51 Monoethanolamine, desulfurization of natural gas, 97 Monoethanolamine, structure, 23 Monoethanolamine, sulfur removal with, 51 MORPHOLINE 500 C, 4410 psi, stability in Water at, 247 Structure, 23 Boiler water, in, 204 Petro. ref., neutralization, 55 Steam condensate, in, 212

N NACE Cooling water inhibitor manual, T7B, 127 Coupons, standard l]1etal test, 30, 70

attack,

Deicing salt corrosion report, 183 Economics of cooling water corrosion control, T7 A, 127 Petro. inh., static and dynamic tcsts, 70 Petro. well acid cleaning standard, 69 Products pipeline in-line recommended practice, 93 Sulfide cracking resistant materials for valves for production and pipeline service, 64 Test, inhibitor methods, 40 Testing reports and standards, 4

METALS, NONFERROUS Amines vs in boiler water, 204 Chromic acid, n-butyl alcohol as vapor phase inhibitors, 225 Cyclohexylamine chromate, vapor phase inhibition, 225 Polyphosphates with, 122 Vapor phase inhibitors for, 225, 226 Staining, VPl vs, 226 Water, cooling, silicate protection, 135 Water, potable, silicate protection, 121

Naphthoquinone for AI, 243 Naphthenic acids, 49 Natural Gasoline Producer's Association classification of gas condensate wells, 63 Neodymium vs V20S in turbines, 254 Nernst equation, 168 Neutralization of acids, 44 Neutralizers other than ammonia in petro. ref., 55 Nickel, acids vs, 163 Nickel, chromates as Al inh., 241 Nickel, petro. ref., infl. on fouling in, 56

METALS Alkalis, attacked by, 245 Cations, infl., 12 Corrosion mechanism, 7 Oxides vs vanadium pentoxide 252

10

.~

o

N OXYGEN Nickel, water floods, oxygen scavenging using Ni ion catalyst, 86 Nicotinic acid for AI, 243 Nicotinic acid structure, 24 Nitrates, aircraft fuel, vs bacteria in, 232 Nitrates, auto cooling systems, in, 181 Nitrates, potable wattr, conc. in, 116 Nitrides, infl. in SCC, 201 Nitrilotriacetic acid as boiler chelant, 208 Nitrilotriacetic acid in coatings, 194 Nitrilotris, 140 NITRITES AI, for in glycol-water sol., 178 Cu, brass inh. in glycol-water, 178 Desalination, with C steel in, 153 Pump, hot water, vs seals in, 216 Water floods, vs oxygen in, 80 Nitrogen, corrosion, infl. on, 49 Nitrogen, in petro. ref. streams, 43 Nitrogen, sewage effluent, in, 131 o-Nitrophenol dimers as boiler dispersants, 208 NTA,208 NTMP-See Methylenephosphonate Nuclear reactor, boilers, treatment, 201, 212,247

o 9,1 I-Octadecadienoic acid (dimer of linoleic acid) structure, 21 Octadecylamine acetate, 214 Octadecylamine bacterial attack, vs, 234 Octadecylamine, steam condensate, in, 213 Octadecylamine, structure, 22 Octane, water sol. in, 89 n-Qctylamine structure, 22 OIL Boilers, max. limits in, 199 Coatings, 220 Contamination of boiler water, 198 Films, on pumps, valves. 221 Grease rust preventive, SAE data on, 186 Phase, infl. on performance, 45 Soluble inhibitors, for products pipelines, 91 Soluble, with adsorption inh. for AI, 245 Vapor space in tanks containing TCA, prot. by, 254 Wells-See Petroleum Olefinic polymers vs acids, 158 Oleyldiamine for salt water disposal wells, , 85 Onium ions vs acids, 158 Organic acids vs acids, 158 Organic sulfides vs acids, 158 Organic Thiocyanates vs acids, 158 Organic sulfur-based bactericides, 238 Oxalic acid for zinc, 162 d-Qximino-{3' vinyl quinuclidine structure, 22

Amines, boiler water, infl., 204 Amine oxygenated petroleum acids vs, 87

Ammonia reaction in boilers, Ag, Cu as catalysts, 205 Auto cooling systems, in, 174 Benzotriazole resistance to in cooling water, 143 Boiler feed water, control of dissolved in, 204 Boilers, pitting by, 200 Boiler, stress corrosion cracking, infl. on,201 Carbon, activated, sulfite additive to remove from boilers, 205 Catalysts for scavenging by sulfite, 85, 205 Caustic attack on C steel, vs polysulfides, 246 Chelants vs, 87 Coal slurry, in pipeline, 257 Desalination, control in, 151 Hydrogen sulfide infl. on water flood scavenging, 80, 85 Oil and grease coatings, vs, 223 Petro. drilling, scavenging from fluids, 104,106 Petro. ref. infl. on, 43, 56 Pipelines, natural gas in, 96 Pyrocatechols vs, 87 Sodium sulfite, metabisulfite and sulfur dioxide scavengers in water floods, 85 Sarcosines vs, 87 Scavengers in petro. drilling, 103 Scavenging from water floods, 84 Secondary recovery, infl. in, 76 Steam condensate, in, 202, 212 Steam stripping from boiler feedwater, 204 Sulfite scavenging from water floods, 84 Sulfur dioxide scavenging, cobaltous ion catalyst, 85 Temp. infl. on attack, 202, 205 Vanadium pent oxide-sodium sulfide, absorption of, 252 Water floods, cobaltous ion catalyst for scavenging, 85 "catalyst for scavenging with sulfite, 85 " chromate vs, 80 " hydrogen sulfide scavenger, 86 " inhibition, 80, 86 " measurement, in 84 " scavenging in, 77, 79, 86 " stripping with gas, 84 Water, potable, infl., 115

p Packaging VPI tests outdoors, 225 Pairmeter, 31 Paper, for VPI packaging test, 225 ,Paper miiIs, biological attack in, 238

11

Paraformaldehydt.' Vs microorganisms, 107 Passivators, concentta:tion, 4', Passivity, mech. in acids, 167 Pectin for AI, 245 2,4-Pentanedione in coMing$', 194 Pentane, water solubility in, 89 Persistent filming, petrolet>rn wells, te sts, 72 Perspiration attack on coupons, 93 Petrolatum coatings, 220 Petrolite Corp., 31 Petrochemical vessels, cleaning with acids, 156 PETROLEUM Fluids, characteristics, 62 Limestone, adsorption properties, 67 Sandstone, adsorption properties, 67 Sour oil or gas-See Hydrogen Sulfide Sulfide cracking, NACE report on materials, 64 Sulfonates in auto cooling systems, 179 Tanks, crude, protection, 98 Tankships, crude, prot., 99

PETROLEUM DRILLING Acid gases infl., 108 Alkalies used in, 106-108 Amines, in, 106-109 Application inhibitors, 109 Biological efrects, 107 Carbon dioxide effects, 106 Causative factors in, 102 Concentration cells, 105 Chlorinated phenols vg microorganisms, 107 Chromates in fluids, 106 Copper influence, 107 Coupons, down-hole, 110 Economics, 104 Failure analysis, 103 History, 103 Hydrogen in, 108 Hydrogen sulfide control, 106 Lubricants, 103 Mechanical factor, 102 Metallurgical factors, 102 Metal salh vs hydrogen sulfide, 107 Microorganisms, 102, 107 Mud, oil, 109 Mu550 C, 202 Steam, saturated vs turbines, 199 Steam, sodium tracer tests for purity; 210

SODIUM SULFITE Activated carbon additive in boiler water, 205 Auto cooling systems, in, 179 Boilers vs chloride SCC in, 212 Boilers, vs dissolved oxygen in, 204 Boiler water, decomp. >10 ppm in >900 psi, 205 Copper, cobalt catalysts, infl., 205 Oxygen scavengers, 85 Petroleum drilling, in, 103,106

STEEL CARBON Allylthiourea as VPI for, 226 Ammonium nitrate, sod. chromate vs, 255 Brine, inh. for, 258 Carbon content infl., 163 Caustic cracking in boilers, 200 Coupon, SAE 1020 for, 92 Cracking, quinoline vs, 17 Desalination, use in, 151 Diaminobenzoic (3,5-) acid vs hydrochloric acid, 20 Galvanic couples with 304 in acids, 157 Glycol-water, tests for inhibitors in, 178 n-Hexadecylpropylene vs hydrogen sulfide, 18 Hydrochloric acid vs, 17 Microbiological attack, 229 Nitrites for 250 F se~ water, 153 Phenylthiourea as VPI, 226 Phosphates for 250 F sea water, 153 Polysulfides vs caustic attack on, 246 Reinforcing in concrete, inhibitors for, 259 Salt water vs, 154 Sodium arsenite for 250 F sea water, 153 Sodium silicate for 250 F sea water, 153 Tannin for abrasive blasted, 193 TCA, Dalapon vs, 255 Vanadates for desalination, IS 3 Vapor phase inhibitors for, 224 Water floods, oxygen attack in, 78 Zinc ion for 250 F sea water, 153

Sodium tracer test for steam purity, 210 Sodium tungstate for AI, 243 Sodium zinc meta phosphate vs deicing salt, 185 Solder, in auto engine cooling system, 174 Solids, total dissolved in potable water, 116 Solubility-See Tests Solubilizing treatment of boilers, 207 Solvent cutback coatings, 220 Sour oil, gas-See Hydrogen Sulfide Specific gravity vs viscosity, hydrocarbons, 92 Squeeze application, petroleum wells, 66 Stannic sulfate vs boiling acids, 163 Stannous chlorides in acid cleaning solution, 157 Starches as dispersants in boilers, 208 Stearyl amines vs acids,-15 8 Steam, ammonia in condensate, 212 STEAM CONDENSATE Amides, imidazolines, pyrimidines, in, 214 Boilers, in shut down, 202 Boiler water carryover, infl., 213 Cyclohexylamine in, 212 Morpholine in, 212 Octydecylamine in, 213 Oils in, 213 Oleic acid in, 214 Oxygen in, 202 Oxygen and carbon dioxide in, 212 Polyphosphate in, 213 Sodium silicates, oils, polyphosphates in, 213 Volatile amines in, 212 Steam, corrosivity of, 203 St'1lm, equipment for cleaning, 156 Steam, film formers vs carbon dioxide in, 215 Steam floods, secondary recovery, 76, 77 Steam, gas equilibrium in, 203 Steam, locomotives, terpenes in, 198 Steam, morpholine stability, 2500 psi,