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jpclPAINTSQUARE .COM JOURNAL OF PROTECT IVE COAT INGS & L IN INGS

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A JPCL eResource

CORROSION UNDER INSULATION

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Copyright 2005 byTechnology Publishing Company2100 Wharton Street, Suite 310Pittsburgh, PA 15203

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This eBook may not be copied or redistributedwithout the written permission of the publisher.

CORROSION UNDER INSULATION


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iv Introduction

1 Preventing CUI With Thermal-Spray Metal Coating By Peter Bock, Advanced Polymerics, LLC

6 When Undercover Agents are Tested to the Limit: Coatings in Action (CIA) and Corrosion Under Insulation (CUI) at High Temperature By Mike O’Donoghue, Ph.D., Vijay Datta, MS, Adrian Andrews, Ph.D., and Sean Adlem, International Paint LLC; Linda G. S. Gray, MSc, Coating Consultant; Tara Chahl and Nicole de Varennes, CET, RAE Engineering and Inspection Ltd.; and Bill Johnson, AScT, Acuren Group Inc.

24 When Undercover Agents Can’t Stand the Heat: Coatings in Action and the Netherworld of Corrosion Under Insulation By Dr. Mike O’Donoghue, Vijay Datta, MS Dr. Adrian Andrews, Sean Adlem and Matthew Giardina, International Paint LLC; Nicole de Varennes, CET, Linda G.S. Gray, MSc, and Damien Lachat, RAE Engineering and Inspection Ltd.; and Bill Johnson, AScT Acuren Group Inc.

32 The “No Big Bang” Theory: An Introduction to Risk-Based Inspection Systems for Mitigating CUI in Process Equipment and Piping By Peter Bock, Capital Inspectors

39 Corrosion under Insulation: Basics and Resources for Understanding By Brian Goldie and Karen Kapsanis, JPCL

47 Application of Thermal Spray Coating (webinar) Presented by John Kern, technical auditor, SSPC.

Contents

Sponsored by

http://www.thermioninc.com/

http://www.thermioninc.com/


IntroductionThis eBook features articles from the Journal of Protective Coatings & Linings (JPCL)

about corrosion under insulation and includes topics such as understanding the

basics, preventing CUI with thermal-spray metal coatings and more. All information

about the articles is based on the original dates of publication of these materials in

JPCL. Please visit www.paintsquare.com for more articles on these and other topics.

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Using thermal-spray metal coating on carbon steel to prevent corrosion is a process that has been around for most of a century. Under its traditional and more familiar name of “metalizing,” ther-mal-spray coating has prevented corrosion on

carbon steel lock gates, dam components and similar large marine-environment structures since the early 1900s. Today, thermal-spray coating is applied by arc spray or flame spray; flame spray is the older, more traditional applica-tion method, and — in appearance — seems similar to braz-ing, although in fact, the thermal spray coating process and the protective film it produces are closer to a liquid-applied coating system. Arc-spray application of thermal-spray metal coatings was a shop-bound process until the 1990s, when portable arc-spray equipment was developed and introduced into field maintenance coating procedures. For refining and petrochemical projects using ther-

mal-spray coating, arc spray is preferred for large, relatively smooth surfaces such as tank roofs or exteriors of large process vessels (Fig. 1). Smaller and more intricate surfaces, such as small-diameter piping, valves and flanges, are done with flame spray. Where a project is large enough, both pro-cesses are used to benefit from the advantages of each.

Metal TypesA wide variety of metals can be used for thermal spray coating; the author has watched bronze thermal spray being

Preventing CUI With Thermal-Spray Metal CoatingNew Use for a Traditional Process

Photo courtesy of Turner Industries Group. LLC. All other photos courtesy of the author unless otherwise specified.

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By Peter Bock, Advanced Polymerics, LLC


applied to bronze statues whose surfaces had deteriorated from long-term environmental exposure in a polluted urban environment on the U.S. Gulf Coast. Thermal-spray zinc was originally touted as a competitor to hot-dip galvanizing, al-though the two processes are significantly different in appli-cation and in the resulting corrosion-resistant film they form. Hot-dip galvanizing is most definitely a shop process, totally unsuitable for any sort of field or maintenance appli-cation. In times when environmental considerations were not as strict as they are today, a large-scale galvanizing facility, with huge open vats of strong acids or alkalis and an equally large vat of molten zinc at 700 F was perfectly acceptable; today it is not. Also back in those times, hot-dip galvanizing was considered a “quick” process, where flame-spray metal application was thought to be tedious and expensive.

The protective layer produced is significantly different be-tween the two processes. Because of the strong chemicals, high temperatures and molten zinc used in hot-dip galvaniz-ing, the galvanized steel surface actually has an alloy effect. A hot-dip galvanized surface has highly reactive, nearly pure zinc at the exposed surface, but going down toward the sub-strate, there are distinct layers of zinc-iron alloy, ending up with all iron at the bottom of the galvanizing layer. Thermal-spray metal-coated steel is different, whether the metal used is aluminum or zinc. The flame or arc melts the protective metal and the gas or air stream breaks the molten metal into tiny spheres, which are then deposited onto the steel to be protected. Molten metal oxidizes readily, so the tiny molten spheres have formed a thin layer of surface oxide by the time they land on the surface to be protected. They have also cooled significantly, so they do not form a continu-ous solid metal film, the way hot-dip galvanizing does, but the oxide layer of the metal droplets is in intimate contact with the oxide layer of surrounding droplets and any porosity be-tween droplets is quickly filled in by oxide formation. Think of the steel substrate covered with a thick layer of M&M candies — the candy shell is the oxide layer, and the chocolate inside is the aluminum or zinc metal. In a relatively short period after application of the thermal spray metal, the “candy coating” oozes together without the chocolate inside ever melting. The thermal-spray metal protective film is actually closer to a liquid-applied coating than to hot-dip galvanizing, except that there is no binder resin, as there would be in a liquid-ap-plied coating. From its first availability, thermal-spray application was use-ful for field work, for maintenance, and for the fact that ther-mal spray metal could be repaired in the field where hot-dip galvanizing could not. Another advantage of thermal-spray coating was the ability to use aluminum instead of zinc as the protective metal. Both aluminum and zinc are anodic, sacrifi-cial metals, but aluminum sacrifices much more slowly than zinc; thermal-spray aluminum (TSA)-coated structures were found to have much longer service life than hot-dip galva-nized structures. There was no “hot-dip aluminizing” process available, so taking advantage of aluminum’s lower sacrificial tendency coupled with the fact that the oxide layer formed during thermal-spray application slowed anodic metal sacri-fice even more, made TSA application a viable competitor of hot-dip galvanizing. Usable service life of 30 and 40 years in exposed severe marine environments became the accepted — and expected — norm for TSA-coated, exposed, carbon-steel structures. The mitigation of corrosion under insulation (CUI) has a much shorter history than thermal-spray metal coating of steel. Until fairly recently, the whole concept of preventing CUI in refineries and chemical plants was totally neglected. To quote the global nonmetallic coatings specifier for a major

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Fig. 1: Multi-story process vessels provide large relatively flat areas for arc-sprayed thermal spray aluminum. The high cost of lost pro-duction on such vessels offsets the higher application cost of thermal spray because of the shorter return-to-service time.


oil company in 2009, “…when our plants were built, industry did not understand that the environment under insulation was going to be almost like immersion conditions, so the correct type of coating (immersion grade) was not used. As a result, almost NONE of the surfaces under insulation in every single facility which is older than 15 years old are adequately protected from CUI. CUI is a phenomenon because of our ignorance.” Until the late 1970s, petrochemical equipment designers and maintenance managers worked under the incorrect assumptions that insulated, hot-operation carbon steel equipment stayed hot enough not to have water under the insulation, and that any corrosion which might occur could be offset by designing equipment with additional steel wall thickness as a “corrosion allowance.” Both of these concepts are partially incorrect. All hot operating equipment cycles hot to cold. Even a ves-sel or pipe which runs hot continuously until taken down for turnaround maintenance is cycling. The length of the cycle is equal to the operating time between turnarounds, and the vessel or pipe will corrode while shut down for turnaround. Additional steel wall thickness may provide some added ser-vice life, but corrosion is rarely flat and uniformly distributed across the surface of a pipe or vessel — pinholes or cracks at welds, corners or low spots in the insulation where water may gather under the insulation will eventually perforate the steel, and the results of the perforation can be catastrophic. Another reason for neglecting CUI was far more straightfor-ward. Until the 1980s, there were very few coatings suitable for use in hot service under insulation. The standard pro-cess operating temperature for hot-operation carbon steel equipment in the 1980s was quoted as 350 F. During turn-around steam-out work, this temperature could reach over 400 F. Only inorganic zinc and thin-film silicones had resins which could survive such temperatures. Inorganic zinc was a sacrificial coating; once the zinc had all sacrificed, there was no longer any protection. Silicones could not be built to sufficient thickness to prevent water permeation and even with lead and chromates in the silicone primer, they did not provide adequate corrosion resistance. A series of major CUI-related equipment failures in the early 1980s showed the problem with using inorganic zinc under insulation. As long as there was zinc left, the coating system protected. Once the zinc was completely sacrificed, active corrosion progressed rapidly. There was no cost-effective way of knowing or judging when the last bit of zinc was gone, and the concept of risk-based inspection had not yet been developed. There was an active search for relatively thick-film, stable, temperature-resistant, cyclic-service-tolerant protective coatings to be used under insulation. Attempts to formulate coatings using the ethyl silicate resin from inorganic zinc, but without the added zinc, were a complete failure. The introduc-

tion of polysiloxane-based elevated-temperature coatings in the early 1990s allowed thick-film build and temperature re-sistance, but the initial formulations could not tolerate cyclic service. Second-generation polysiloxane-silicone hybrid for-mulations resolved this problem and provided the necessary temperature tolerance, flexibility for cyclic service and film thickness to survive for years under insulation. TSA coating was suggested as a CUI coating at about the same time. Although thermal-spray application required an arc or flame, it was actually less hazardous than applying liquid paint. A “hot-work” permit similar to one issued for welding or cutting was obtained for thermal-spray application. Because the deposited metal was cool, the aluminum dust generated as overspray was less hazardous than the solvents released during liquid paint application and the dust could be easily gathered and removed, unlike paint overspray which stuck to everything it touched.

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Fig. 2: A large refinery or petrochemical plant will have hundreds of insulated process vessels and hundreds of miles of insulated pipe feeding those vessels.

Fig. 3: This coupon failed the thermal-spray bend test after testing as specified in SSPC-CS 23.00/AWS C2.23M/NACE No. 12.


When coatings contractors first offered thermal-spray application in the 1990s and early 2000s, the cost of field ap-plication was typically about 10 times as expensive as liquid coatings. These costs included the cost of surface prepara-tion, coating materials, application and inspection, but made no allowance for the amount of time actually required for application and drying, or for the cleanup and disposal costs at the end of the project. Liquid coatings intended for CUI service typically require two or three coats to achieve the specified 10-to-12 mils dry-film thickness (DFT). Applied DFT for each coat cannot be accurately checked until the coat of paint is dry, which may take 8-to-12 hours, depending on temperature, humidity and air circulation. If low DFT is found, additional paint must be applied, requiring another full coat’s drying time. In contrast, thermal-spray metal coating is a single-coat system; dry and ready to be checked for DFT within seconds of application; and any low-DFT areas that are found can be immediately touched up with additional thermal-spray metal (Fig. 4).

So Why is Thermal Spray More Expensive?The source of the extra costs is detailed in the joint SSPC/AWS/NACE standard for application of thermal spray coat-ings, SSPC-CS 23.00/AWS C2.23M/NACE No. 12, “Specifica-tion for the Application of Thermal Spray Coatings (Metalliz-ing) of Aluminum, Zinc, and Their Alloys and Composites for the Corrosion Protection of Steel” (Fig. 3, p. 64). This standard is used for thermal-spray coatings, whether intended for exposed or CUI service and the requirements in it are much stricter than requirements for application of liquid coatings in similar service.

The first bit of expensive news in this standard regards surface preparation. SSPC-SP 5, “White Metal Blast Cleaning” is required for thermal spray in marine or immersion service. Because CUI service is considered intermittent immersion, SSPC-SP 5 is mandatory for thermal spray in CUI service. Achieving a specified anchor profile is also critical for ther-mal-spray projects, since mechanical adhesion of the ther-mal-spray layer to the anchor profile of the steel substrate is the only thing keeping the thermal-spray layer attached to the substrate. Many CUI-rated liquid coatings may be applied over lesser surface preparation, or even on top of existing old coatings; the liquid resin in these provides an additional means of adhesion. Second is the requirement for qualified applicators and helpers. Improperly applied thermal spray may have holidays or poor cohesion. Improperly applied thermal-spray coat-ing which does not tie into the anchor profile may disbond from the substrate during thermal cycling under insulation. Thermal spray can only be applied by specialized arc-spray or flame-spray equipment; liquid coatings can be sprayed, rolled, brushed or even applied by a mitt or dauber, depend-ing on surfaces to be coated, product data sheet or specifi-cation. Third is the need for much more thorough inspection, before, during and after application of thermal spray, than would normally be done for liquid coatings. Properly applied TSA looks like “White Metal” blasted steel, so visual holiday inspection cannot be done as for liquid coatings (Fig. 5). DFT readings must be taken much more frequently than would normally be specified by SSPC-PA 2, and pull-off adhesion testing is mandatory according to SSPC-CS 23.00. As more and more contractors have become familiar with thermal-spray coating application, prices have come down, but they are still higher than coating the same project with liquid paint. However, thermal spray has two inherent advan-

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Fig 4: Despite the apparent fireworks, the arc-sprayed thermal-spray aluminum is dry and cool almost immediately after application and is ready for insulation and jacketing. Liquid coatings require additional coats and extended drying time after each coat. Photo courtesy of Turner Industries Group, LLC.

Fig. 5: Inspection of thermal-spray aluminum requires special care because the visual appearance of thermal spray is almost identical to the appearance of newly blasted steel.


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tages offsetting the restrictions from the SSPC/AWS/NACE standard. Unlike a contractor, who is bidding the time and materials his crews will actually use, the specification engi-neer or maintenance manager is also intimately concerned with the out-of-service time required to replace a CUI coating system on a vessel or pipe run. To him or her, “out of ser-vice” means “out of production.” “No production” equals “no income” for the affected unit — and possibly — other units upstream or downstream in the same train, which cannot operate when the affected unit is down. Scaffolding, tenting, removal of jacketing and insulation, surface preparation, and replacement of insulation and jack-eting are identical whether using thermal spray or liquid coat-ings, but where liquid coating application takes three days if drying time between coats is included, thermal spray is a one-day operation. The corrosion control manager at a major Gulf Coast refinery estimated that a 15- or 17-story contact process tower such as the ones shown in Figure 1, generates a million dollars in revenue per day of operation. Saving two days of downtime by applying thermal spray instead of liquid coating will save the owner $2 million which (the corrosion control manager estimated) is much more than the added cost of thermal spray instead of liquid coating. The second savings is length of service life. From a con-tractor’s viewpoint, the cost of a project is the cost of time and materials his crews and inspectors will require to com-plete a project. From the corrosion control manager’s point of view, the true cost of a project is the contractor’s invoice plus the cost of out-of-service time, divided by the number of years of service life expected from the corrosion-control project. Major U.S. oil company corrosion-control specifications rate thermal-spray aluminum in CUI service as an expect-ed service life of 20, 30, and in one specification, 40 years without replacement or major repair. These same specifica-tions rate the best liquid-applied coating systems as having expected service life of 8-to-15 years. From this perspective, the price of thermal-spray coating goes from being much more expensive than liquid-applied coatings to being much less expensive, since it is expected to last much longer.

Despite thermal-spray metal coating’s nearly a century of successful service on exposed steel in coastal, marine and similar severe environments, the longest properly recorded, properly monitored CUI service for TSA on U.S. refineries or chemical plants that the author can find records for is just short of 15 years. But after that service time, the applied TSA coating is in excellent shape and looks to be good for another ten or fifteen years, approaching the corrosion control manager’s dream of the CUI coating system having the same expected service life as the unit itself.

About the AuthorPeter Bock is executive vice president of Advanced Poly-merics Inc. in Hooksett, New Hampshire. He is an Air Force veteran and holds degrees from Tulane University and the University of Northern Colorado. Bock has 37 years of sales,

management and technical service experience in oilfield and petrochem-ical heavy-duty coatings in the United States, Canada, Mexico, Venezuela, Indonesia and Taiwan. He has experience with on- and off-shore production, drilling and workover rigs, shipyard work, natural gas and LNG, pipelines, terminals, refineries and chemical plants. Bock is a specialist in

elevated temperature systems, corrosion under insulation and chemical passivation. He is a former president of NACE New Orleans Section and of the Houston Coating Society. Bock is a NACE-certified coating inspector and has presented papers and symposia at many na-tional, regional and local coatings and corrosion control events.JPCL


WHEN UNDERCOVER AGENTS CAN’T STAND THE HEAT:Coatings in Action (CIA) and the Netherworld of Corrosion Under Insulation

By Dr. Mike O’Donoghue, Vijay Datta, MSDr. Adrian Andrews, Sean Adlem and Matthew Giardina, International Paint LLC; Nicole de Varennes, CET, Linda G.S. Gray, MSc, and Damien Lachat, RAE Engineering and Inspection Ltd.; and Bill Johnson, AScTAcuren Group Inc.

OPERATION HIGH HEAT

Mission Impossible gave us a thrilling movie where the daring hero, a master of disguise, belonged to an unofficial

branch of the CIA. His prime directive was to prevent a secret list of covert eastern European CIA agents from falling into the wrong hands. Failure was not an option - countless lives were at stake; the balance of global power hung on a knife edge. Suc-cess depended on the courageous, quick thinking actions of our CIA agent and his team. Ominously, some CIA agents were not as they seemed. Who could be trusted? Who was friend? Who was foe? With a focus on intelligence collection for the oil and gas industry, Mission Possible: “Operation High Heat,” is our

high-tech adventure into a mysterious corner of the coatings world where specialty high heat coatings work undercover on corrosion under insulation (CUI) assignments. Under close scrutiny, a task force of the CIA (Coatings in Action), was poised to expose potential fault lines, misinformation, and hyperbole with respect to coatings performance. What was trustworthy? What was friend? What was foe? Would a post-reconnaissance of the mission prove revealing? Would some new technology CIA agents be able to stand the heat? Could the same new technology CIA agents throw light on other CIA activities? And how would an older, well-respected CIA agent perform under the same adversarial conditions as the newer generation opera-tives? This article will describe the importance of Coatings in Action (CIA) in the undercover realm of CUI. A suite of accel-erated laboratory tests was undertaken in part to evaluate the

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Fig. 2: Experimental set-up (Left to Right: TSA, Coating #1, Coating #2, and TMIC)

Fig. 1: Pipe sample schematicFigures courtesy of the authors

claims made for engineered coatings touted to possess ultra-high-heat resistance to 400 C and simultaneous anticorrosion properties, and to evaluate the coatings’ suitability for cyclic CUI use. The inspiration for Operation High Heat stemmed in part from facility owners’ requests to the authors to identify promis-ing new pipe and process vessel coatings that could be used in cyclic (rather than continuous) temperature CUI environments

that are more aggressive than those typical of CUI problems. The tests also continue earlier accelerated laboratory investiga-tions of the CUI cyclic performance of new generation coatings.

COLLATERAL DAMAGECorrosion under insulation (CUI) and its high associated costs have been the subject of considerable attention by facility own-ers for several decades. CUI processes themselves are gener-

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Increasing Corrosion Protection of Organic Coatings

Coating Impedance, Log z (Z in ohms•cm2 @ 0.1 Hz)

4 6 8 10

Poor Protection Good Excellent Begins

Fig. 3: Interpretation of EIS results21

Fig. 4: Overview of all samples after CUI cyclic testing

ally well understood.1,2 For CUI to occur, the usual actors must be in play: oxygen (a strong corrodent), water, a contaminant salt (the corrosive), a metallic pathway, and a suitable tempera-ture range. According to NACE SP0198, the critical corrosion temperature ranges that a high heat coating must withstand are -4 C to 175 C for carbon steel, and 50 C to 175 C for stainless steel.3 Typically, the most potentially menacing CUI environment for thermally insulated carbon steel piping spools will occur be-tween 60 C and 120 C. Factors such as dissolved oxygen, cor-rosive salts in the water or insulation, the type of insulation, and isothermal conditions or thermal cycling will be important. Rain leaking through damaged cladding and porous insulation can lead to moisture at the carbon steel-insulation interface. So too can condensation at that interface after a rapid cooling stage in the process cycle. When the system cools and if an absorbent insulation like calcium silicate is used, moisture will be retained. Therefore, insulation materials like expanded perlite or aerogels tend to be favored. A carefully designed facility and the use of high quality insu-lation materials and protective jacketing (e.g., aluminum clad-ding, multi-laminate tapes, and glass fiber lagging cloths) are important CUI deterrence strategies to prevent water reaching insulated carbon steel pipes.4 But as noted, if mechanical damage occurs, water can reach hot pipes, where evaporation results in deposition of soluble salts. A continued water supply and repetitive thermal cycles will concentrate the salts, raising the boiling point of the water. In an open system, as water nears its boiling point, the solubility of dissolved oxygen will plummet. However, in a closed CUI environment, water entering the insu-lation is continually replenishing oxygen to the steel-insulation interface. The net result is that CUI rates of 1.5 to 3.0 mm per year can occur, some 20 times greater than rates due to atmo-spheric corrosion alone.5 A clandestine and unpredictable enemy, CUI normally goes undetected until the damage is significant. Without warning, perforation of carbon steel can bring operations to a grinding

halt and may cause a catastrophe. Pipe maintenance repair costs from CUI alone have been reported to be 40-60% of a re-finery’s maintenance budget.6 Ancillary costs can be significant from lost production, chemical spills, environmental cleanup, and health and safety implications. Without the CUI countermeasures of judiciously selected materials, be they protective jacketing, thermal insulation, or specialty coatings, bare carbon steel pipe and vessels inevita-bly corrode undetected in water saturated-insulation. When the steel fails, the consequences can ultimately be dire.

COUNTERMEASURES TO CUIThermal Spray Aluminum (TSA)For over 30 years, a single coat application of ~10 mils of TSA has had an excellent track record of protecting carbon steel against atmospheric corrosion in many environments.7,8

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Fig. 5: Average rusting (left) and cracking (right) in the coatings after CUI cyclic testing

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Fig. 6: EIS results of tested and untested CUI pipes

Fig. 7: After cyclic immersion in salt solution with dry out

Pre

test

100

C20

0 C

300

C40

0 C

Pre

test

100

C20

0 C

300

C40

0 C

Pre

test

100

C20

0 C

300

C40

0 C

Pre

test

100

C20

0 C

300

C40

0 C

TSA #1 #2 TMIC

Log

Z Im

peda

nce

at 0

.1 H

z

12.0

10.0

8.0

6.0

4.0

2.0

0

Fig. 8 (below): After cyclic immersion in salt solution with dry out—average rusting

Although TSA is somewhat expensive to apply, requiring a min-imum SSPC-SP 5, White Metal abrasive blast with a profile of 3.5 to 5.5 mils, its life cycle costs are low and its performance is generally outstanding in the war on atmospheric corrosion.9 With respect to CUI mitigation, however, there appear to be relatively few case histories using TSA and the jury appears to be out regarding its efficacy for CUI service. It has been report-ed that TSA can provide 25 to 30 years of maintenance-free and inspection-free service.10 Indeed TSA has provided over 20 years of zero maintenance service life in some CUI pipe applications and its use in CUI environments continues to be the subject of investigation.11,12 In atmospheric service, TSA provides both galvanic and barrier protection to carbon steel and austenitic stainless steel. While TSA is known to be tolerant of continu-ous temperatures as high as 500 C, and elevated cyclic temperatures in wet and dry conditions, what is not so well known is that TSA corrodes on steel in hot salt solutions at ~80 C.13 So while a facility own-er’s expectation is that TSA should provide mark-edly superior performance in CUI service compared to liquid-applied coatings, this expectation may not always be well founded. With wet insulation on steel pipe, TSA does have a temperature limitation in hot salt solutions. Al-though metallic aluminum is anodic to carbon steel, in a saline environment

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Fig. 9: After cyclic immersion in salt solution with dry out—average cracking

Fig. 10: After cyclic immersion in salt solution with dry out—average flaking

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Fig. 11: TSA after CUI cyclic testing

Fig. 12: TSA with TMIC patch after CUI cyclic testing

Fig. 13: Coating # 1 after CUI cyclic testing

with the temperature close to 80 C, the efficiency of aluminum will be lowered. In contrast, barrier coatings, even if they contain aluminum pigments, do not behave as sacrificial anodes and thus can be more effective in hot brine. Also, TSA, with high porosity (e.g., 5 to 30%), will form insoluble aluminum salts in the pores over time. Sealers have been used to address the porosity.14 Typical sealers have been based on low viscosity coatings, although those based on vinyl coatings, and certain thin film inorganic copolymers have been shown to be more effective than those based on epoxy coat-ings.15

High-Performance Modified Silicone Polymer Coatings In contrast to the use of TSA, a particularly interesting approach to mitigating CUI would be for the coating formulator to develop

a high-heat and ultra-high-heat-resistant (up to 200 C and >200 C respectively) inorganic copolymer that contained leafing alu-minum flake pigmentation. Distributed throughout an otherwise brittle coating matrix, an overlapping array of aluminum flake pigments could be theorized to afford internal stress reduction to the coating when applied to carbon steel. In essence, the aluminum platelets would be envisioned to provide mechan-ical toughening of the coating and enable it to withstand the expansion and contraction of carbon steel pipe in elevated and fluctuating temperature service. More obviously, aluminum flake pigmentation would function as a tortuous diffusion path against the intrusion of water, oxygen, and dissolved salts, and as an anticorrosive pigment. When used in epoxy formulations, aluminum pigments have been noted for their abilities to func-tion as barrier pigments, and for their buffering reactions at the coating-steel interface.16 In CUI environments, such a system

could provide a much needed flexible and impermeable coating film on carbon steel or austenitic stainless steel. These considerations formed the basis of the development of the titanium modified inorganic copolymer (TMIC), a relatively new technology that consists of cross-linked inorganic film-formers with aluminum flake pigmentation. The TMIC network was designed to ensure that mechanical properties such as flexibility would accom-modate the stresses generated within the coating during high temperature cycling in the typical CUI temperature range (and cycling anywhere between 100 C and 400 C), through im-

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Fig. 14: Coating # 2 after CUI cyclic testing

Fig. 15: TMIC after CUI cyclic testing

Fig. 16: Overall view of uncoated pipe samples

Fig. 17: Close-up view of uncoated pipe samples

Fig. 18: SEM backscat-ter image of the TSA coating showing the coating with porosity present during coating application (100 x)

Fig. 19: SEM backscat-ter image of the TSA with TMIC repair patch at the 4 cm (400 C) location showing intact bond to substrate and between coatings (100 x)

proved network formation. TMIC technology has been de-scribed elsewhere for insulated and non-insulated pipe appli-cations, deployed either in stand-alone mode or in conjunction with TSA.15,17 Two other commercial inorganic copolymers of interest were investigated in the present work. Derived from advanced

silicone chemistry, they were expected to have thermal and thermo-oxidative stability through the resistance of their Si – O bonds to scission, and to be excellent potential CIA candidates. It is important to point out that the evolution of coatings technology for high temperature resistance and anticorrosive properties in CUI service has been through inorganic zinc sili-cates (400 C), early thin film multi-coat aluminum silicones (500 C), and immersion-grade epoxy novolac systems (230 C).18 The maximum service temperatures are in parentheses. First, the zinc silicates are no longer favored in CUI environments because of reactivity and inadequate performance. Second, the early thin film aluminum silicones have poor barrier properties in intermittent hot and wet service and poor resistance to thermal shock. Third, epoxy phenolics begin to thermally decompose, carbonize, and become ineffective at ~230 C.19 So coming to the fore in the present day are modified inor-ganic polymer coatings said to have attributes that may include the following.• Cyclic and continuous temperature resistance to 400 C• One coat, thick film applications at 7 to 8 mils DFT• Flexible at elevated temperatures • Barrier resistance and micro-crack resistance• Long service life

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Fig. 20: Metallographic image showing the bond location between the TSA and TMIC repair patch at the 4 cm (400 C) location (200 x)

Fig. 21: SEM - X-ray map-ping images showing the distribution of elemental constituents in the TMIC and TSA bond location (300 x)

Fig. 22: SEM image of Coating #1 after exposure to 100 C at interface with substrate, showing coarse filler material in a dense matrix (300 x)

Fig. 23: SEM image of Coating #1 at interface with substrate, after ex-posure at 400 C showing disbondment at coating to substrate interface(100 x)

• Ease of application• Application to SSPC-SP 6 and water blasted surfaces• Application to hot substrates up to 150 C • Minimal to zero porosity• Self repair and spot repair for TSA• Sealer utility for TSA Formulated to have enhanced barrier properties, some of these materials are said to have the added advantage of alumi-num flake or micaceous iron oxide (MIO) pigments in their resin matrix. Because of its ultra-high-temperature properties (>200 C), TSA was included as the benchmark for this study, and a new technology, titanium modified inorganic copolymer (TMIC), already demonstrated to be suitable for cyclic CUI service up to 400 C, was investigated as a repair patch on TSA in a laboratory simulation of a field touch-up.

Undercover Agents InvestigateIn the Mission Impossible movie, our hero dons one of his many clever disguises, preparing for the mission to find the elusive data so crucial to his investigation. But now he is alone. His re-sources are tested to the limit with so many forces against him. All his faculties are sharply attuned as he strives against almost

insurmountable odds. Will this testing time winnow the weak from the strong? All will be revealed.... And what did our own winnowing reveal about the four CIA coating technologies investigated here? • TSA: Thermal Spray Aluminum (1 coat @ 10 mils DFT).• Coating #1: Modified Silicone Copolymer (2 coats @ 10 to 12 mils TDFT). Stated temperature resistance up to 650 C in continuous service and suitable for CUI service. • Coating #2: Inorganic Polymer with MIO (2 coats @ 12 to 18 mils TDFT). Stated to withstand intermittent exposures up to 720 C and prevent CUI.• TMIC: Titanium Modified Inorganic Copolymer (1 coat 7 to 8 mils DFT). Stated to withstand cyclic CUI environments for pipes to 400 C and 650 C in continuous operation. The following tests were carried out.A. CUI cyclic testing. ASTM D2485, ASTM G189, and the mod-ified Houston Pipe test20 were considered for evaluating CUI coating performance. Instead, the CUI cyclic test employed in the previous research17 was used, as it provided an accelerat-ed, significantly more aggressive environment favored by some facility owners. Also, coating performance under CUI conditions

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Fig. 24: SEM image of Coating #2 at interface with substrate, after ex-posure at 100 C show-ing coarse filler material and intact matrix (300 x).

Fig. 25: SEM image of Coating #2 after exposure at 400 C showing coating matrix break-down and fracture (300 x)

Fig. 26: SEM image of Coating #2 after image analysis to evaluate coating porosity after exposure at 400 C showing porosity level of 9% in the matrix (200 x)

Fig. 27: SEM image of TMIC coating after exposure at 100 C showing interlacing of dense aluminum platelets in an inorganic matrix (1000 x)could be determined simultaneously over a wide range of tem-

peratures, from 95 C to 445 C. In the CUI cyclic test, insulated, coated steel pipe was positioned vertically on a hot plate, resulting in a temperature gradient along the length of the pipe. The insulation was cyclically saturated with sodium chloride solution, and the pipe was cyclically cooled. Calcium silicate was used as the insulation because it is known to absorb and wick moisture, and hold 20-40 times its weight in water. Uncoated steel pipe was prepared and subjected to CUI cyclic testing in exactly the same manner as the coated pipe to determine the corrosion occurring in the absence of a protec-tive coating.B. EIS testing. Electrochemical Impedance Spectroscopy analysis of the coatings was performed before and after CUI cyclic testing to assess changes in the barrier properties of the coatings.21C. Cyclic salt immersion and high heat dry out. After CUI cyclic testing the four coatings were submitted to six weeks of another aggressive round of corrosive testing in which they were exposed to cycles of sodium chloride solution immersion alternated with dry heat at 200 C.D. Adhesion,porosity,cracking,andflakingtests. After CUI cyclic testing, the four coatings were evaluated for adhesion loss, porosity, cracking, and flaking using optical and scanning electron microscopy (SEM).

CIA RECONNAISSANCE: OPERATION HIGH HEAT Experimental So where is our agent now? To find the “mole,” he becomes a mole, delving deeply into convoluted terrain, finding false avenues of espionage and dangerous dead ends. Our hero, previously alone, now has other covert agents support and defend him. Yet his life is in danger. But he must carry on, for to step away is to admit defeat, and defeat would be catastrophic. What will he do next?. In the same vein, which CIA agent will act as a mole and survive the ravages of corrosion under insulation?

Pipe SamplesThe external surfaces of steel pipe (60 cm long, 5 cm inside diameter, 5 mm wall thickness) were abrasive blast cleaned to an SSPC-SP 10, Near White Metal, with a 2-3 mil profile using G40 steel grit. Each of the liquid coatings was applied to dupli-cate steel pipes by air spray and cured at 25 C for seven days. TSA was applied using flame spray. Other sections of prepared pipe were left uncoated to facilitate temperature determination under insulation and the corrosion behavior of bare steel under CUI cyclic test conditions.

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Fig. 31: Inspection of TMIC after 1 year in service showing no coating breakdown or rusting

Fig. 28: SEM image of TMIC coating after exposure at 400 C showing interlacing of aluminum platelets in the intact inorganic matrix (1000 x)

Fig. 29: Preparation of TSA weld joints Fig. 30: TMIC applied to protect TSA weld joints

Pre-formed calcium silicate insulation, 5 cm in thickness, was fastened around each pipe in clam-shell fashion. Aluminum foil was wrapped around the insulated pipe and secured, leaving both ends of the insulation open to facilitate the entry and drainage of the wetting solution (Fig. 1). One of the TSA-coated pipes was prepared with an inten-tional repair patch of TMIC. The repair area was abrasive blast cleaned to bare steel (silica sand) to an SSPC-SP 5, White Metal. TMIC was brushed on in two coats with a total DFT of 9 mils on the bare steel area, overlapping the adjacent featheredTSA. The patch extended over one side of the lower half of the pipe, which was the area subjected to the highest temperature.

CUI Cyclic Test DesignThe CUI cyclic test was run twice with each of the four coatings. Each weekday morning, one liter of 1% sodium chloride (NaCl) solution was poured slowly into the insulation at the top end of the pipe sample. The liquid was mostly absorbed by the insula-tion, with only a small amount of drainage from the bottom. The four pipe samples were placed on the hot plates (Fig. 2), and the hot plates were turned on, reaching 450 C within 30 minutes. After 8 hours, the four pipe samples were removed from the hot plates, and another liter of 1% NaCl was poured slowly into the insulation at the top of each pipe. The re-saturated pipe sam-ples remained off the hot plates overnight. This procedure was

repeated five days a week, for six weeks, for a total of 30 cycles. After 30 cycles, the insulation was removed from the pipes and the coating performance evaluated.

CUI Pipe Temperature GradientThe temperature of the pipe under the insulation was deter-mined by placing thermocouples between uncoated steel pipe and the insulation at 5-cm intervals. The assembly was other-wise identical to the coated samples. The instrumented pipe was placed on each of the hot plates, and the hot plate tem-perature was adjusted to achieve a temperature gradient from 445 C (bottom) to 95 C (top) as Table 1 shows. The insulation was not wetted with electrolyte in these measurements. The hot plate settings were maintained for the duration of the testing. The temperature profile measurement was repeated after each six-week test to confirm that it was unchanged.

Evaluation of Coating Performance after CUI Cyclic TestingCoating performance was evaluated based on visual examina-tion, including degree of rusting, blistering, flaking, and cracking (ISO 4628, Parts 2–5) and color change. Adhesion was evaluat-ed using an X-scribe knife method (ASTM D6677). EIS measurements (ISO 16773) were made before and after CUI cyclic testing, using the attached cell method in which acrylic tubes (2 cm in diameter) were cemented to the coating and filled with 5% NaCl solution at 23 C for 48 hours. Bode curves were run with Gamry EIS instrumentation, and coating impedance (Log Z) was read from each curve at 0.1 Hz. An interpretive guide for EIS is presented in Fig. 3. Attached cells were placed on the pipe where CUI temperatures were 100, 200, 300, and 400 C.

Cyclic Immersion in Salt SolutionThe effect of CUI cyclic test conditions on the four coatings was further evaluated by subjecting one set of tested coatings to a cyclic salt immersion/heat test (insulation removed). The bottom 30 cm of each coated pipe (190-445 C) was immersed in a 5% NaCl solution at 23 C for 48 hours, after which the pipes were transferred to a convection oven at 200 C for 48 hours.

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The pipe samples remained in the oven over the weekend. Three cycles of immersion and dry heat were conducted each week for 6 weeks, with visual inspections at 2-week intervals.

CIA RECONNAISSANCE: RESULTS AND DISCUSSIONFigure 4 shows the appearance of the coated pipe samples after CUI cyclic testing, and Fig. 5 graphically shows the degree of rusting and cracking. Table 2 and Fig. 6, respectively, give the adhesion and EIS results. Duplicate coated pipe samples performed almost identically. Figure 7 shows the coated pipe samples after subsequent cyclic salt immersion and heat, and Figs. 8 to 10, respectively, show the degree of rusting, cracking and flaking.

TSA in ActionCUI Cyclic Testing

The main effect of the CUI conditions was rusting in the hottest zone of the pipe (390 C to 445 C), presumably from corrosion of the steel substrate by sodium chloride solution that had pene-trated the porous TSA coating. The degree of rusting was Ri 2 (ISO 4628-2), or rusting over about 0.50% of the affected area. The TSA did not blister, flake, or crack. Except for rusting, the only visible changes were a slight loss of metallic luster above 250 C and patches of a thin white deposit, which was presum-ably residues of salt, insulation or aluminum oxide formation (Figs. 4 and 11). The TSA retained excellent adhesion to the steel substrate (Table 2), and no coating could be removed by prying with a stout knife. The TSA (pre-test) initially had very low impedance, Log Z = 2.6, consistent with the metallic nature of the coating. Exposure to CUI conditions resulted in a small increase in impedance that is attributed to the formation of oxides and/or insoluble salts. They add electrical resistance to the metallic coating by filling the pores of the coating.

Cyclic Immersion in Salt Solution and Dry HeatSubsequent exposure to cyclic salt immersion and dry heat produced little change in the TSA. It showed no significant increase in rusting and did not blister, flake or crack. Visually the TSA became more dulled and yellowed, but this appeared to be staining as a result of salt and rust deposits that accumulated in the immersion solution.

TMIC Repair Patch on TSA in ActionCUI Cyclic Testing

No deterioration or rusting was observed on the TMIC repair patch (Figs. 4 and 12) except for a longitudinal, hairline crack in the TMIC/TSA overlap area from 335 to 445 C. The crack contained no rust, indicating it did not penetrate to the steel substrate. The TMIC patch showed a slight to moderate loss of metallic luster and general dulling above 245 C, with only

a slight dulling elsewhere. Adhesion of the TMIC to the steel substrate and the TSA in the overlap area was excellent (Table 2) with cohesive separation only occurring during the prying action.

Coating#1(ModifiedSiliconeCopolymer)inActionCUI Cyclic Testing

Coating #1 deteriorated significantly more than TSA (Figs. 4 and 13). Moderate to severe rusting (ISO 4628-3 Ri 2 and Ri 3, Fig. 5) was observed above 250 C. Below 250 C, a small amount of pinpoint rusting occurred, with no rusting below 190 C. Most of the rusting was associated with cracking of the coating. The cracking consisted of crescent shaped cracks above 390 C (ISO 4628-4, Rating 2, Sigmoid), randomly orientated cracks between 390 and 250 C (ISO 4628-4 Rating 4 and 5, NP) and progressively fewer cracks below 250 C, with no cracks below 210 C. A small ring of coating around the pipe circumference at about 400 C was relatively crack-free. The coating did not blister or flake, and it darkened slightly above 250 C. Coating #1 retained relatively good adhesion (Table 2). Above 200 C, adhesion dropped from a pre-test rating of 10 to ratings of 7 and 8. Coating #1 (pre-test) initially had a relatively high impedance, Log Z = 10.4, indicative of excellent barrier properties. Exposure to CUI cyclic testing caused the impedance to drop by several Log Z units at 200 C and higher, consistent with cracking and physical breakdown in the coating. The impedance at 400 C (Log Z=7.3) was measurably higher because the coating was relatively free of cracks in this area.

CUI Immersion in Salt SolutionSubsequent exposure to cyclic salt immersion and dry heat resulted in further deterioration of Coating #1. The degree of rusting increased significantly above 190 C, with rusting now extending below 190 C into areas previously rust-free. The extent of cracking above 210 C also increased significantly, re-sulting in large areas of flaking where previously there had been none. The flaking was accompanied by large rusty patches of exposed substrate. The coating darkened and became severely dulled by rust above 250 C. It became moderately dulled and yellowed by the rust in the saline solution in the 190 C to 250 C region.

Coating #2 (Inorganic Polymer with MIO) in ActionCUI Cyclic Testing

Coating #2 deteriorated considerably more than Coating #1. Severe rusting (ISO 4628-3 Ratings 1 to 3) occurred above 290 C, and above 335 C, the coating looked swollen from corrosion product formation under the coating. Blistering, patches of severe flaking and severe cracking occurred above 390 C. The blisters were 2 to 4 mm in diameter (ISO 4628-2, size 4, den-sity 2) and occurred over half of the pipe circumference. The

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flaking had a rating 1 to 5 (ISO 4628-5) and included two large flakes ( 2.5 x 5 cm and 1.5 x 2 cm) that revealed a heavily rusted substrate. The cracking was longitudinal (ISO 4628-4, Rating 3), with some cracks continuing into areas of the pipe at lower temperature down to 335 C (Figs. 4 and 14). The degree of deterioration below 390 C progressively decreased, until no deterioration was visible below 250 C. The area of the coating above 190 C darkened moderately, whereas the area below 190 C lightened. Patches of a white deposit, presumably of salt or insulation, were present over the surface. The coating completely lost adhesion above 335 C (Table 2, ASTM D6677, Rating 0) and could be lifted from the substrate in large chips. Below 335 C, the adhesion improved, with excellent adhesion retained below 250 C (Ratings 8 and 9). Coating #2 (pre-test) initially had a relatively high impedance, Log Z = 10.4, indicative of excellent barrier properties. Exposure to CUI conditions produced little change in impedance at 100 C and 200 C, suggesting no deterioration had occurred. However at 300 C and 400 C the impedance dropped significantly, con-sistent with the visible coating degradation.

TMIC in ActionCUI Cyclic Testing

TMIC performed generally as well as the TSA (Figs. 4 and 15). A ring of light rust and pinpoints of rust occurred from 335 C to 445 C (ISO 4628-3 Ri 0 and Ri 1). However, the rust stain was easily removed by lightly abrading the coating surface, indi-cating the rust did not originate from the steel substrate, but instead from transfer of corrosion products from the uncoated end of the steel pipe. The TMIC had no blistering, flaking, or cracking. A slight loss of luster and general dulling occurred above 190 C. Adhesion to the substrate was excellent at 200 C and above, with no adhesive or cohesive separation observed during the prying action (Table 2). At 100 C, small (1 to 2 mm) chips could be pried cohesively from the pipe surface. The observations suggest that exposure to temperatures above 100 C improved the adhesion and toughness of the TMIC. The impedance of TMIC initially (pre-test) was Log Z=7.0. Ex-posure to CUI conditions at 100 C, 200 C, and 300 C produced a significant increase in impedance to Log Z=9.3 to 9.7. Expo-sure to higher temperature reduced the permeability of the coating by completing the curing and cross-linking processes of the polymeric structure of the coating that had been applied at ambient temperature. The high impedance was consistent with the visually excellent condition of the coating. At 400 C, the impedance dropped to Log Z=3.3, close to the values observed for TSA.

Cyclic Immersion in Salt SolutionPinpoint rusting increased somewhat in size and density above 335 C, with no rusting or any other type of degradation ob-

served below 335 C. One quadrant of the pipe above 390 C developed mild flaking associated with pinpoint rusting. The flaking occurred cohesively and did not extend to the substrate. The coating below 335 C remained free of flaking. A few hairline cracks developed around half of the pipe circumference above 390 C. The coating became duller with more staining as testing progressed, where staining was presumably from salt and rust in the immersion solution.

Corrosion Rate of Steel under CUI Cyclic Testing ConditionsUncoated steel pipe was subjected to the same CUI cyclic test as the four coatings. The steel pipe was covered with a thick layer of loose, red/black corrosion products at the end of the test (Fig. 16). The corrosion products were noticeably thinner and more adherent over the middle third of the pipe (160 C to 250 C). The corrosion products were removed by glass bead blast-ing (Fig. 17) to better determine the metal loss and the nature of the corrosion. Between 285 C and 445 C, the steel surface had a high density of very small pits, 0.4 mm to 0.6 mm in diameter. The pits appeared to be deep, but were too small in diameter to accurately measure with a pit gauge. From 190 C to 285 C, large pits 2 to 10 mm in diameter were visible, with depths of 0.5 mm to 1.25 mm (mechanical pit gauge measurement). The 95 C to 190 C area of the pipe showed a mixture of both types of pitting but at much lower density. Based on the deepest pit (1.25 mm) after 6 weeks of CUI cyclic testing, the pit corrosion rate was calculated as 10.8 mm/year. At this corrosion rate, perforation of the 5-mm pipe wall would occur in approximately 4.3 months.

Post Cia Reconnaissance: Microstructure, Porosity, CompositionOur Mission Impossible hero is shaken. Our hero finds that a friend can be foe after all, and conversely foe can inexplicably become friend. What was believed to be true is revealed to be false. What was once obvious and accepted is now in doubt. The tables have turned, a compromise reached, but what will be done with the secret data? Will the face of the future ultimately change? As did our hero, we too rely on computer science, high-tech gadgetry to reveal and confirm our findings. Let us see where our investigations have led. To complete the picture of how the four coatings reacted to the effect of heat, the microstructure and porosity of the coatings were examined at high magnification using optical microscopy, scanning electron microscopy (SEM), X-ray mapping, and EDXA.

General ObservationsOptical microscopy was first employed with the intention of estimating porosity based upon visual comparison to CSA Z245.20 (Canadian Standards Association). Early optical photo-

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micrographs suggested there was porosity in the liquid-applied coatings, in some instances similar to that in TSA. SEM was then used to afford a more quantitative value for porosity within the coating based on the cross section sur-face areas. This worked well for TSA and for Coating #1, where virtually no porosity was seen. However, it did not work well for TMIC because virtually all the dark areas in the TMIC’s optical and SEM images were subsequently shown not resulting from porosity. This led next to taking higher magnification images. Through the use of a fluorescent green epoxy mounting me-dium, and polishing the samples, the dark areas of TMIC at all temperatures were shown to be back reflection of pigment. In contrast, the dark areas seen in the images of Coating #2 were spaces arising from coating breakdown (not true porosity) when the temperature increased beyond 200 C. Selected areas near the coating-steel interface were exam-ined at high magnification using X-ray mapping techniques. Each coating cross-section was analyzed using EDXA at various locations in the coating matrix.

TSA in ActionInspection of the photomicrographs and SEM images showed that the porosity of the TSA according to the analysis from the Image Pro Plus software was approximately 12 to 20% (Fig. 18). This range is typical for TSA. As expected there was no evi-dence of structural changes in the TSA between 100 C and 400 C. The images also indicated excellent adhesion between the TSA and the abrasive blast cleaned steel substrate, in agree-ment with the knife adhesion tests previously discussed (ASTM D6677 adhesion Rating 10).

TSA with TMIC Patch in ActionThe integrity of the TMIC coating that was applied as a re-pair patch to TSA did not appear to change as the exposure temperature increased from 200 C to 400 C. Figures 19 and 20 show, respectively, SEM and optical images of the repair system at 400 C and the unbroken and tortuous path of the aluminum flake platelets. Figure 21 shows the X-ray map and distribution of the main elements in the TMIC sample exposed to 400 C, namely silicon, aluminum, and carbon (titanium, although vital to the efficiency of TMIC, was below the detection limit). It is inter-esting to see the widespread distribution of carbon from carbon compounds that will have been thermally decomposed.19

Coating #1 in ActionAs shown in Fig. 22, the coating was dense, and showed less than 1% porosity over the full test temperature range. The interface between the two coats during application was not visi-ble. The coating structure consisted of the polymer matrix with entrained fillers and pigments with a wide variety of shapes and sizes (rods, plates, blocks, irregular fractured shapes). The mor-phology, distribution, and volume of the solid phases in Coating

#1 would not be expected to present such a tortuous path for the ingress of water, oxygen, and deleterious salts compared to TMIC. It is noteworthy that at 400 C, the primer is cohesively stressed and shears, leaving a thin film of Coating #1 adhered to the carbon steel substrate (Fig. 23).

Coating #2 in ActionThe microstructure of Coating #2 was similar to Coating #1, but appeared to be simpler, with the larger particles dominating the morphology (Fig. 24). The coating retained good adhesion to the substrate with no corrosion products visible at the sub-strate. At 300 C, the onset of an intra-coat cohesive fracture line was discerned, where the MIO pigment in the primer was seen at the primer surface. By 400 C, the coating had lost integrity and fractured, which allowed the ingress of the hot salt solution to reach the carbon steel substrate. The resulting oxidation was confirmed by the SEM images and EDXA on the carbon steel substrate, where iron, oxygen (likely iron oxide), and chloride ions were detected. The cracks were filled with epoxy during sample preparation, helping to keep the coating sample intact during preparation (Fig. 25). These cracks served as a pathway for oxidation and corrosion on the substrate. Based on the space within the coat-ing filled with fluorescent green epoxy, at 400 C, the apparent porosity of Coating #2 was about 9% (Fig. 26).

TMIC in ActionThe SEM images showed that there was virtually no porosity in TMIC (less than 1%) and the coating microstructure did not appear to change as the temperature increased from 100 C to 400 C. With no cracking or disbonding, the microstructure of TMIC remained essentially unchanged over the full temperature range, as was also observed for TSA (Figs. 27 and 28). At 400 C, the TMIC microstructure was found to be fully intact with no evidence of degradation of the matrix (Fig. 28). The coating morphology consisted of a dense array of leafing aluminum platelets in a silicon-based resin system. Interestingly, TMIC had been applied at a lower film thickness than any other coating under test, and there was no evidence of separation or opening between the platelets. This may be in part due to the overlapping and interweaving nature of the aluminum platelets, thereby providing additional tensile strength in the circumferen-tial orientation. The aluminum flake may potentially further im-prove coating integrity and performance at high temperatures by producing a reduced thermal differential or insulating effect across the coating from better heat transfer characteristics.

General Discussion of the CIAPrevious work by the authors17 showed that TMIC technology was an excellent proposition for high heat and under-insulation service, and would make a perfect complementary product strategy for TSA. It was argued that TMIC could be used to

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repair and extend the life of TSA. In the present work, not only did TMIC perform almost as well as TSA in a stand-alone mode at 7-8 mils DFT, but it was virtually unaffected as a repair patch to TSA even at temperatures up to 400 C. More work needs to be undertaken, however, because of a hair line crack that developed at the transition between the TMIC and TSA at tem-peratures close to 400 C. More importantly, TMIC was shown to have heat resistance and corrosion resistance properties far superior to the other high-heat coatings investigated. As a CIA agent, TMIC ranked #1 among the liquid-applied coatings by a considerable margin. Its barrier properties based on the CUI experiments (including cyclic immersion and EIS studies) revealed superior performance. Examination of the TMIC microstructure using optical microscopy, SEM, and X-ray mapping all confirmed that TMIC performs as a flexible coating in the CUI range of 60 C to 120 C, and at elevated temperatures up to 400 C. In addition TMIC had superior post-test adhesion than either Coating #1 or Coating #2. It was particularly inter-esting to note that EIS confirmed what is known about TMIC technology in that the inorganic polymer does not achieve full cross-linking until heated beyond 100 C. Aside from the successful applications in the field, these studies strongly indicate that the specification of TMIC tech-nology for facility owners in the industrial, marine and offshore sectors could be a step forward for CUI mitigation, particularly if ultra high (>200 C) cyclic environments are involved. Depend-ing on the temperature, the application of the CIA agent TMIC should reduce the number of costly CUI inspections, cut the cost of pipe maintenance, lower life cycle costs, and markedly assist risk management practice.

Case HistoriesGoing Undercover with a TMIC AgentOur hero has prevailed! All his strivings, sacrifices, and tra-vails have been worth it. His has been a fact-finding journey of discovery into labyrinths of intrigue; a secret operation into untrammelled territory. The covert agent list was in safe hands once again; the lives of many were saved; the balance of power was assured, and our hero is ready to tackle the next assign-ment. We too, have been on a journey of discovery, albeit more of a technical kind with our own undercover agents. As you can see our travels inside the world of ‘coatings under insulation’ have been no less stimulating, no less revealing. And we too, are ready for the next exciting assignment in the realm of protective coatings. No matter how well it is designed, a laboratory simulation of a service environment will only approximate, or serve to indi-cate, what might be expected to happen in real life conditions. Accelerated performance will never fully reflect how a CIA agent will perform in real life service with all the attendant variables. That said, the following case histories outline the successful

performance of TMIC in actual service conditions, success which could reasonably be anticipated based upon Operation High Heat.

France–TMIC Protection of TSA Field JointsIn 2007, in a refinery in France, some piping that was coated with TSA was overlapped with TMIC technology on the welded field joints. Given that welded joints are particularly suscepti-ble to corrosion, TMIC technology was chosen for its barrier properties and high heat protection up to 400 C. Interestingly, a traditional thin film silicone aluminum had not met the facility owner’s expectations and was subsequently replaced with a TMIC coating (Figs. 29 and 30). Because of heat stresses created during welding, the welds are areas most at risk from corrosion. TMIC was applied on-site by roller and without involving hot work to protect field joints with TSA.

Texas Gas Dryer Unit Gas dryer units in a Texas refinery with a history of rapid deteri-oration of coatings under insulation were selected for the first industrial field trial of TMIC technology. The dryer units cycle between -20 and 230 C over a 4- to 5-day cycle. Previously, several different polymeric coating technologies had been used to protect the dryers, and, in all cases, the coatings had failed within 6 to 12 months of service. Because of the lack of success with other coatings, and the inability to apply TSA to the on-site structures, the refinery decided to try TMIC to solve the CUI problem. In 2004, the TMIC coating was applied to the dryers. Because of site safety and operational limitations, abrasive blasting was not possible, so the surface preparation consisted of SSPC-SP 2 and SP 3, hand and power tool cleaning, followed by two coats of the TMIC coating for a total DFT of 8-10 mils. One year later, the dryer units were inspected, showing no rusting or coating degradation (Fig. 31). At present, the dryers have operated for over 6 years without any indications of CUI.

CIA CONCLUSIONS TSATSA and TMIC both had similar performance and were the best of the four coatings during the CUI cyclic test runs. The majority of visible rusting was limited to the 390 C to 445 C section of the pipe. No blistering, flaking, or cracking was observed on the coating on either of the CUI test runs. However, minute pin-points of rust could be observed from 140 C to 390 C after CUI cyclic testing. During the cyclic immersion-heat testing, TSA performed the best, showing no signs of blistering, cracking, or flaking. While pinpoints of rust were visible from 135 C to 445 C along the pipe in some instances, they were minuscule, few in number, and appeared to have little effect on the surrounding coating.

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No significant increase in severity occurred to these pinpoints, even after 6 weeks of immersion and heating cycles. The low EIS values were representative of the coating’s me-tallic nature and hence low electrical resistance. The impedance of the coating increased over the course of CUI cyclic testing, implying porosity reduction, a desirable attribute of thermal spray coatings. As expected, the TSA coating exhibited significant true porosity, which did not appear to be a factor with performance because the steel substrate was free of any evidence of oxidation or corrosion beneath the TSA. The TSA coating also appeared to retain bond integrity along the fusion line between the TSA and the steel substrate at all locations, including the 400 C location.

Coating #1 Coating #1 performed relatively poorly, with a major loss in performance at temperature above 250 C. From 210 C to 250 C, Coating #1 performed better, with little deterioration observed below 190C. Coating #1 showed no signs of blistering or flaking during the CUI test, but consistently showed high amounts of non-preferentially oriented cracking from 250 C to 445 C. The cracking was tied to the development of flaking and loss of coating adhesion during immersion testing. EIS tests showed that the barrier properties of Coating #1 were very good at 100 C, but fell significantly, mostly as a result of cracking and physical deterioration, as the temperature increased. However, at about 400 C where a small ring of the coating was relatively crack-free, the barrier properties were higher than those of the coating at 300 C (where cracking was observed).

Coating #2Coating # 2 performed relatively poorly and saw a major loss in performance at temperatures from 290 C to 445 C as a result of rusting, blistering, cracking, and flaking, accompanied by corrosion of the steel substrate. From 250 C to 290 C, its per-formance was better, with little visible deterioration below 250 C. The deterioration became increasingly more severe during cyclic immersion testing, and after 6 weeks rusting and flaking were observed to temperatures as low as 210 C. The barrier properties of Coating #2 dropped significantly at temperatures above 200 C, which coincided visually with the performance of the coating in both CUI runs, and after immer-sion testing. SEM images, optical microscopy and X-ray maps showed the coating contained coarse MIO flakes within a silicon based binder matrix. The coating matrix appears to break down and fracture at higher temperatures resulting in coating integrity failure. The coating fractures allow for hot saline solutions to contact the carbon steel substrate and cause corrosion of the steel pipe.

TMICApplied to carbon steel pipes, and under repetitive cyclic thermal conditions, TMIC offers thermal resistance and corrosion resistance in the critical CUI temperature range of -4 C to 175 C. The performance of TMIC is equal to or better than the other coatings in this range. However TMIC outper-forms the other liquid coatings at temperatures from 175 C to 400 C. Both TMIC and TSA performed similarly, with both coatings sharing the best performance of the coatings during both CUI cyclic tests. The TMIC coating performed consistently well at temperatures below 335 C, with slight degradation occur-ring between 335 C and 445 C. This was also true of the TMIC brush-applied repair patch tested on the TSA coated pipe. TMIC did not have any blistering, flaking, or cracking under CUI cyclic temperature testing. After additional testing in cyclic immersion, hairline cracks, and flaking were observed around pinpoints of rust above 390 C, which seemed to indicate that the rust pinpoints had increased in severity due to the cyclic immersion testing. Below 390 C, TMIC performed consistently well. TMIC developed excellent barrier properties after CUI cyclic testing up to 300 C. However, at 400 C, the impedance plum-meted into the range observed for TSA while otherwise demon-strating excellent performance in visual, microscopic/SEM, and physical tests. It is speculated that the close packing of alumi-num flakes in the resin network may have resulted in initiation of fusion at 400 C. As a result, TMIC could have developed some of the metallic characteristics of TSA and thus exhibit reduced electrical resistance.

Operation High Heat Coatings in Action: RankingOverall, during CUI cyclic testing, the TSA and TMIC coatings provided the best performance for temperatures up to 445 C. Coating #1 had the next best performance, with varying degrees of deterioration beginning above 100 C. Coating #2 had the poorest performance, with degradation above 200 C being severe and significantly worse than that seen for Coating #1. So what is the final analysis? Mission Impossible? Or is it Mission Possible? The answer depends on the coating agent and the operation temperature. Before the mission, all undercover agents were said to be capable of effective CUI countermeasures in Operation High Heat. However, the mission exposed that some important claims derived from fine work of coating formulators and material scientists were found wanting. In the present investigation, the old benchmark agent TSA and the new technology agent TMIC could stand the heat. But the new technology Coating #1 and Coating #2 could not. As in the movie Mission Impossible, we must all wait for a new adventure. In the meantime, industrial, marine, and offshore facilities have two great coating agents to recruit for CUI.

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AcknowledgementsThe authors wish to acknowledge Mark Schilling of Corrosion Probe for his keen insights into the properties of thermal spray aluminum (TSA) and the CUI process. In addition, the authors wish to acknowledge Peter Salvati, art director, JPCL for the art-work; and Brian Goldie, technical editor of JPCL for his editing assistance with a large manuscript.

REFERENCES1. Goldie, B., Kapsanis K., “Corrosion Under Insulation: Basics and Resources or Understanding,” JPCL July 2009. p. 34.2. Bock, P.P., MeLampy, M.F., “Field Maintenance of Coating Systems,” JPCL April 2009. p. 44. 3. NACE Standard SP0198-2010, “Control of Corrosion Under Thermal Insulation and Fireproofing Materials – A Systems Approach,” (Houston, Texas; NACE 2010).4. Hart, Gordon, H., “The Toolbox for Prevention of Corrosion Under Insulation,” Insulation Outlook, March, 2008.5. “Uhlig’s Corrosion Handbook, 2nd Edition”, Review, R.W. Editor, p.566.6. Fitzgerald, B.J., Lazar, P. III, Kay, R.M., Winnik, D., “Strategies to Prevent Corrosion Under Insulation in Petrochemical Industry Piping,” Corrosion 2003, Paper No. 03029. 7. Cunningham, T., Avery, R., “Thermal Spray Aluminum for Corrosion Protection – Some Practical Experience in the Offshore Industry,” SSPC Orlando, Florida, 1998.8. Goulette, B., “TSA Coatings for Risers and Offshore Piping,” Presentation at Pipeline Coatings Seminar, NACE Fall Committee Week/2002, Dallas, TX, Sept. 8–13, 2002. The author reviews several researchers’ findings on the durability of TSA in corrosive atmospheric environments.9. Parks, A.R., “Aluminum Sprayed Coatings Onboard US Navy Ships – A Ten-Year Overview,” www.inmetl.com/OnNavy 10.10. Harrup, Eurocorr 2008, “Workshop on Corrosion Under Insulation Case Studies.”11. Mitschke, H., “Informal Technology Exchange” presentation of NACE Corrosion 2007.12. Kane, R.D., Chauviere, M., “Evaluation of Steel and TSA Coating in a Corrosion Under Insulation (CUI) Environment,” NACE Corrosion 2008, Paper No. 08036. 13. Schilling, M.S. – Personal Communication, November 2011.14. Thomason, W.H., Olsen, S., Haugen, T., Fischer, K., “Deterioration of Thermal Sprayed Aluminum Coatings on Hot Risers Due to Thermal Cycling,” Corrosion 2004.15. Halliday, M., “Preventing Corrosion Under Insulation – New Generation Solutions for an Age Old Problem,” Corrosion and Prevention 2006, Paper 014.16. Knudsen, O., Rogne, T., Rossland, T., “Rapid Degradation of Painted TSA,” NACE Paper No. 04023, 2004, p. 6.17. O’Donoghue, M., Datta, V.J., and Aben, T., “From Trauma to Transcendence: Corrosion Under Insulation,” NACE North Western Conference, February 15-18, 2010 Calgary, Alberta.

18. Brown, O., “High Heat Coatings: An Overview of Coating Performance and Product Characteristics,” JPCL March 2008. p. 10.19. Hare, C., “Paint Film Degradation – Mechanisms and Control,” SSPC 01-14, Thermal Degradation of Binders, Chap. 45, p. 379, 2001. 20. Betzig, D., “Qualification Testing of High Temperature Coatings,” 13th Middle East Conference and Exhibition, Paper No. 10136.21. Gray, Linda G. S. and Bernard R. Appleman. “EIS: Electrochemical Impedance Spectroscopy. A Tool To Predict Remaining Coating Life?” JPCL February 2003. p. 66.

Mike O’Donoghue, PhD, is the Director of Engineering and Technical Services for International Paint LLC. He has 30 years of experience in the protective coatings industry.

Vijay Datta, MS, is the Director of Industrial Maintenance for Interna-tional Paint LLC. He has more than 40 years of experience in the marine and protective coatings industry.

Adrian Andrews is the Technology Development Manager, International Paint LLC. He has 30 years of ex-perience in the protective coatings industry.

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Linda G. S. Gray, MSc, is a Senior Ma-terials Special- ist for RAE Engineer-ing and Inspection Ltd. and has over 20 years of experience with industrial coatings.

Damien Lachat is a Coatings Tech-nologist for RAE Engineering and In-spection Ltd., where he is involved in various aspects of industrial coatings testing and research.

Bill Johnson, AScT, is the Manager of Laboratory Services with Acuren Group Inc., in Richmond, BC. Bill has 20 years of experience in materials testing, failure analysis, scanning electron microscopy, and energy dispersive X-ray analysis.JPCL

Sean Adlem is the Sales Manager, Alberta Region Protective Coatings, International Paint LLC. Sean has over 20 years of experience in the protective coatings industry.

Matt Giardina, Business Develop-ment Oil & Gas Market for Inter-national Paint LLC, has 7 years of experience in the coating industry.

Nicole de Varennes is Coatings Laboratory Manager for RAE Engi-neer- ing and Inspection Ltd. She has 7 years of experience in various aspects of industrial coatings.

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For industrial, marine, and offshore facility owners, the cost consequences of corrosion under insulation (CUI) can be intolerable in terms of lost production, chemical spills, environmental cleanup, and health and safety implications. Hence, it is very important to

implement carefully designed CUI mitigation strategies. Specialty coatings can be excellent tools for CUI mitigation strategies.1 The authors showed in previous laboratory inves-tigations using a CUI cyclic test, that coated carbon steel pipe insulated with Cal-Sil (calcium silicate) saturated with a 1% NaCl (sodium chloride) salt solution performed best with either ther-mal spray aluminum (TSA) or a spray-applied titanium modified inorganic copolymer (TMIC).2,3 The raison d’etre for the use of calcium silicate as an insulation material was because it readily absorbs and wicks moisture and can hold about 20–40 times its weight in water,4 thus representing a worst-case scenario. The cyclic temperature range used in the earlier work was 95

C to 445 C.2, 3 The temperature span was intended to ensure that the coated pipe test pieces were exposed to the NACE RP01985 critical corrosion temperature range (4 C to 175 C for carbon steel; 50 C to 175 C for stainless steel) and higher. Interestingly, an anomalous finding from the earlier work was that corrosion on wet and insulated bare steel pipe appeared to occur at temperatures higher than those known for the corro-sion of dry carbon steel.5, 6 This suggested that temperatures, measured by thermocouples on bare steel pipe encased in dry insulation, which were used to indicate temperatures of coated steel pipe encased in wet insulation, were incorrect and needed to be checked to provide greater accuracy. These new tem-perature measurements were carried out as part of this new CUI study.

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When Undercover Agents areTested to Coatings in Action (CIA) and Corrosion Under Insulation (CUI) at High Temperature ©iStockphoto/THEPALMER

By Mike O’Donoghue, Ph.D., Vijay Datta, MS, Adrian Andrews, Ph.D., and Sean Adlem, International Paint LLC; Linda G. S. Gray, MSc, Coating Consultant; Tara Chahl and Nicole de Varennes, CET, RAE Engineering and Inspection Ltd.; and Bill Johnson, AScT,Acuren Group Inc.

Editor’s Note: This article is the second part of a series on corrosion under insulation. The first part, “When Undercover Agents Can't Stand the Heat: Coatings in Action and the Netherworld of Corrosion Under Insulation,” appeared in the February 2012 JPCL. This article is based on a presentation given at SSPC 2013, the annual conference of SSPC: The So-ciety for Protective Coatings, held Jan. 14–17, 2013, in San Antonio, TX. It is available in the conference Proceedings (sspc.org).

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The primary aim of the current investigation was to evaluate coating performance on both carbon steel and stainless steel pipes in the temperature range for CUI and at elevated tempera-tures approaching 600 C. Utilizing the Cyclic Pipe test, the cy-clic temperature resistance of a new member of the TMIC class of coatings was compared and contrasted with one of the other specialty coatings studied in the previous work, an inorganic coating containing micaceous iron oxide (hereinafter Coating A and designated Coating #2 in the former study). Both the orig-inal TMIC coating tested and the new TMIC coating evaluated in this study were aluminum filled. They were formulated to pro-vide similar flexibility, be unaffected by intra-film stresses during high temperature cycling in the typical CUI temperature range, and withstand cycling and continuous operation between am-bient and elevated temperatures. In the present investigation, the new TMIC coating was touted to perform up to 600 C, much greater than the 450 C limit for the earlier version.

ExperimentalPartA:TemperatureProfileStudiesonBareSteelPipeIn the authors’ previous work, the temperature profile of the steel pipe under wet insulation was assumed not to be dissim-ilar to the temperature profile measured by thermocouples under dry insulation. This study was undertaken to characterize the temperature profile under wet conditions and determine what, if any, differences occurred compared to the dry condi-tion. The materials and procedures were identical to those used in the previous CUI cyclic test,2,3 except that under the dry condi-tion, only the temperature was cycled. Two duplicate, insulated, bare steel test pipes were prepared. The dry condition was run first (over a two-week duration), followed by the wet condition (two weeks) using the same duplicate pipes. The pipe was 60 cm long and 6 cm in outside diameter, with a 5-millimeter-thick wall. Thermocouples to measure the surface temperature of the pipe under the insulation were positioned at intervals varying from 20 mm to 50 mm, from the bottom (hot end) to the top (cold end) of the pipe, for a total of 18 thermo-

couples. Each pipe was en-cased in 5-centimeter-thick calcium silicate insulation sleeves. In this study, an additional eight thermocouples were added to the pipe to measure the temperature within the insulation as a function of dis-tance from the pipe surface. In this way, the temperature profile across the insulation was determined at 10, 20, 30 and 40 mm intervals from the pipe surface, at 150 mm and 450 mm from the bottom (hot end) of the pipe. The CUI cyclic test proce-dure was as follows. At the

beginning of the day, one liter of a 1% NaCl solution was poured slowly into the insulation surrounding the pipe at the top of the pipe. The pipe was then placed on a hot plate, which was immediately turned on. The hot end of the pipe reached approx-imately 600 C within two to three hours. After 8 hours on the hot plate, the insulated pipe was removed from the heat and placed in a shallow pan. One more liter of 1% NaCl solution was poured into the insulation, whereupon the insulated pipe was allowed to cool overnight. This procedure was repeated for five days a week (Monday through Friday), for two weeks. Almost all of the NaCl solution was absorbed by the insulation, with a minimal amount of solution flowing through the insulation, either to the pan or the hot plate. Each morning, after the first day, the pipe was weighed when it was cool, prior to starting the next day’s cycle. The temperature profile, determined under dry conditions, was determined using the same procedure, except that the brine was omitted. A stable, reproducible profile was achieved within 2 to 3 hours, and the measurements were deemed com-plete after two days.

Part B: High Temperature CUI Studies on Coated Carbon and Stainless Steel PipesThe CUI cyclic test previously employed by the authors was used again because it provided an accelerated and significantly more aggressive environment, which was favored by some facil-ity owners.2,3 A few modifications and changes were incorpo-rated, such as the addition of stainless steel pipe, application of a coating to each half of the pipe, and increasing the testing temperature. Sections of carbon steel and stainless steel pipe were abrasive blast cleaned to an SSPC-SP 10, Near-White Metal standard, using aluminum oxide grit. A 2–3 mil jagged profile

Fig. 1: Experimental set-up (left to right)Stainless steel pipe and carbon steel pipe

Fig. 2: Pipe sample schematic

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was obtained. The TMIC coating was applied to one half of the pipe (1 coat @ ca 8 mils’ DFT), and Coating A was applied to the other half (2 coats @ ca 6 mils’ DFT/coat), along the length of the pipe, respectively. The liquid coatings were applied by air spray and cured at 25 C for seven days. A pre-formed, 5-centimeter-thick calcium silicate pipe insula-tion was fastened around each pipe in a clam-shell fashion. Alu-minum foil was wrapped around the insulated pipe and secured with zip ties, as shown in Figure 1. Both ends of the insulation were left open to facilitate the entry and drainage of the NaCl wetting solution. Figure 2 shows the pipe sample schematic. The heat distribution on the hot plate was verified using temperature indicator crayons from 450 C to 750 C. The carbon steel and stainless steel temperature profiles were placed at the 650 C heat position. The CUI cyclic test procedure of heating and adding 1% NaCl solution to the porous calcium silicate insulation is documented above and in the authors’ previous work.2,3 The liquid was mostly absorbed by the insulation, with only a small amount of drainage from the bottom. The temperature profiles for the carbon and stainless steel pipes were slightly different. The procedure was repeated five days a week for six

weeks, for a total of 30 cycles, whereupon the insulation was removed from the pipes and the coating performance was eval-uated. The surface temperature of the pipes under dry insulation was determined with two pipe samples that were identical to the coated pipe samples, except that the carbon steel and stainless steel pipes were uncoated and thermocouples were placed between the insulation and the steel at 5 cm intervals. The temperature of the hot plate was adjusted such that the temperature gradient obtained along the pipe length with wet insulation was 72 C to 560 C for the carbon steel and 77 C to 600 C for the stainless steel pipe, as shown in Tables 1a and 1b. The hot plate settings were maintained for the duration of the testing with the coated and bare steel pipe samples. To facilitate detailed analysis of the coatings’ performance after CUI cyclic testing, each coated half of the pipe, as shown in Figure 3, was analyzed in 5 cm increments, moving from 0 mm (560 C) to 600 mm (72 C) for the carbon steel pipe and 0 mm (600 C) to 600 mm (77 C) for the stainless steel pipe. In the adhesion analysis, each area was divided into four test areas, with results reported based on the average temperature of that area. Coating performance was evaluated based on visual exam-ination and adhesion assessment (ASTM D6677). Visual ex-amination included color change, degree of rusting, blistering, flaking, and cracking (ISO 4628, Sections 2 through 5).

ResultsTemperatureProfileStudieson Bare Steel Pipes—Wet InsulationThe results for days 1, 3, and 5 are shown in Figures 4a, 4b, and 4c (pp. 36–37). Complete results for days 1, 3, 5, 7 and 10

Coating TMC

Coating A

0° to 180°

180° to 360°

Fig. 3: Diagram of pipe

Table 1a: Distance along Carbon Steel Pipe and Corresponding Temperature

Distance from Bottom (mm) 0–50 50–100 100–150 150–200 200–250 250–300 300–350 350–400 400–450 450–500 500–550 550–600Approx. Wet Temp Range (°C) 560–515 515–400 400–375 375–285 285–265 265–207 207–190 190–160 160–118 188–99 99–87 87–72Approx. Dry Temp Range (°C) 540–465 465–415 415–391 391–300 300–280 280–260 260–240 240–235 235–200 200–180 180–150 150–100

Table 1b: Distance along Stainless Steel Pipe and Corresponding Temperature

Distance from Bottom (mm) 0–50 50–100 100–150 150–200 200–250 250–300 300–350 350–400 400–450 450–500 500–550 550–600Approx. Wet Temp Range (°C) 600–536 536–460 460–365 365–305 305–250 250–120 120–112 112–102 102–98 98–95 95–92 92–77Approx. Dry Temp Range (°C) 600–520 520–450 450–370 370–325 325–275 275–195 195–180 180–170 170–150 150–125 125–110 110–95


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can be found in Appendix I, Figures 1a to 1e, available in full at paintsquare.com. Each figure shows the temperature profile of the pipe as a function of distance from the hot end (on the hot plate) at various time intervals during the daily heating cycle. Zero hours refers to the start of the day where 1 liter of 1% NaCl solution was poured into the insulation and into the pipe (at ambient temperature), immediately before the pipe was placed on the cold hot plate (which was then turned on.) Temperature profile curves were obtained at various intervals for the following 8 hours, after which the pipe was removed from the hot plate, another liter of 1% NaCl was poured into the insulation, and the pipe left overnight.

Weight Change of the PipeThe initial mass of the pipe with dry insulation was estimated to be 3.2 kg (7 lbs) made up of 2.7 kg (6 lbs) for the pipe and 0.45 kg (1 lb) for the insulation. After the first 5 days of cyclic wetting and heating, the pipe plus insulation had a mass of 13.4 kg (29.4 lbs), an increase of 10.2 kg (22.4 lbs). Over the 5 days, 10 liters of 1% NaCl had been added to the insulation. Therefore, very little water evapo-rated from the insulation during the first five days. After ten days, the pipe plus insulation had a mass of 14.0 kg (30.8 lbs), indicating that the pipe had reached a steady state. The insulation was presumably fully saturated, and the water loss by evaporative boiling was roughly equal to the amount of brine introduced. The rate of evaporation was presumably matched with the rate at which brine was introduced into the insulation at 5 days.

This was consistent with the observation of steaming (water vapor release) from the top of the pipe during the initial hours of heating.

TemperatureProfiles:Day1The pipe temperature increased rapidly as the heating cycle was applied. Over the 8-hour duration, the temperature profile curves tend toward the shape and values of that recorded for the dry pipe (Fig. 4a). The deviation from the dry curve is mini-mal at the high temperature end (bottom) of the pipe, presum-ably because the insulation is still dry, or has dried out from the heating. The deviation from the dry curve at the low tempera-ture end (top) of the pipe is considerably larger, presumably due to the loss of heat into the moisture present in the insulation.

TemperatureProfiles:Days2–5andDays6–10The temperature profile progressively changed from days 1 through 5, after which little further change was observed. The temperature profile at the high temperature end of the pipe was rather erratic from days 2 to 4, especially at the begin-ning of the heating cycle (Figure 4b). The behavior, consisting of high and low temperature variations along the length of the pipe was attributed to random “dry” and “wet” spots in the insulation. The erratic behavior stopped at day 5, presumably because the insulation became fully saturated with brine (Fig. 4c). The temperature of the pipe after 8 hours progressively decreased from days 2 to 5, particularly at the high temperature end of the pipe. After day 5, the portion of the pipe from 100 mm to 275 mm appeared to reach a limit of 100 C after 4 hours of heating. The heat supplied to the pipe resulted in evaporative

Fig. 4a: Day 1 of CUI cyclic testing with hydration

TEMPERATURE PROFILE OF PIPE SURFACE: DAY 1 TEMPERATURE PROFILE OF PIPE SURFACE: DAY 3

Fig. 4b: Day 3 of CUI cyclic testing with hydration


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boiling of the water saturated insulation, limiting the tempera-ture to 100 C. The bottom (hot end) 50 mm of the pipe reached temperatures up to 350 C, suggesting that it quickly dried out due to heat input from the hot plate. Nevertheless, the tempera-ture remained about 100 C less than the dry pipe. The top (cold end) of the pipe above 275 mm showed significantly less overall change in the 5 days, suggesting full saturation with brine had been achieved there first. The difference between the dry pipe temperature profile and the 8-hour wet pipe profile progressively increased from day 1 to 5, after which little further change was observed. After 5 days, the brine that had been introduced into the insulation de-pressed the temperature at the low and high temperature ends of the pipe by about 75 C and up to 200 C, respectively. In view of the water saturation, high rates of corrosion would be expected above 100 mm from the hot end. This was consis-tent visually with corrosion on the pipe, as previously docu-mented.2,3 The temperature profiles showed little further change after day 5, indicating a steady state had been achieved where evap-oration balanced the amount of brine poured into the insulation.

TemperatureProfileAcrosstheInsulationThe temperature profile results across the thickness of the insulation at 150 mm and 450 mm from the hot end of the pipe are shown in Appendix II, Figures 2a to 2e, available in full at paintsquare.com. In this article, Figures 5a, 5b, and 5c (p. 38) show results for days 1, 5, and 10, respectively.

150 mm from the Hot End of the PipeOn day 1, when the insulation was mostly dry, the tempera-ture across the insulation gradually increased over the 8-hour heating cycle. The pipe surface temperature was 265 C, and the temperature within the insulation was 160 C and 90 C, respectively, at 10 mm and 40 mm from the pipe surface. From days 2 to 5, the insulation gradually became saturated with brine and lost its insulating characteristics. The temperature gradient across the insulation decreased significantly, and little further change was observed after 5 days. After 2 hours into the heating cycle for the water saturated condition, the pipe surface temperature was 100 C, and the temperature across the insulation was relatively constant at about 95 C. The brine facilitated heat transfer within the insulation, resulting in both rapid heating and the absence of a temperature gradient across the insulation.

450 mm from the Hot End of the PipeThe temperature profile across the insulation at the cool end of the pipe was considerably different from the hot end. On day 1, the temperature profile across the insulation sta-bilized within about two hours. After 8 hours, the pipe surface temperature was 80 C, and the temperature in the insulation ranged from 62 C (10 mm from pipe surface) to 53 C (40 mm from the pipe surface). Between 2 hours and 8 hours, the temperature within the insulation dropped slightly, possibly the result of the brine gradually diffusing throughout the insulation in this area of the pipe. From day 2 to day 10, as the insulation became progressively more saturated with water, the temperature gradient across the insulation dropped and the overall temperature remained progressively closer to room temperature. After 4 to 8 hours of heating, the insulation temperature finally started to increase toward pipe temperature, but no significant temperature gra-dient developed, presumably due to the thermal conductivity of the brine. The pipe surface temperature dropped from 80 C on day 1, to 62 C on day 5, to 50 C on day 10. The difference between pipe surface temperature and insulation temperature gradually decreased over the 10-day interval from 20 C after 1 day to 6 C after 10 days (after 8 hours of heating).

Results Part BCUI Studies on Coated Carbon and Stainless Steel PipesThe appearance of the coated pipe samples after CUI cyclic testing at high temperature is shown in Fig. 6 and the degree of rusting is shown graphically in Fig. 7 (p. 42). Blistering and flaking are not graphically presented, as they occurred under only specific conditions. The adhesion results are presented in Table 2.

Coating A In ActionDetailed pictures of Coating A after exposure to CUI cyclic test

TEMPERATURE PROFILE OF PIPE SURFACE: DAY 5

Fig. 4c: Day 5 of CUI cyclic testing with hydration


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conditions are shown in Figs. 8 and 9 (p. 42).

Carbon Steel PipeSmall rust pinpoints (ISO 4628-3 Rating 1) (Fig. 7, p. 42) oc-curred over the 100 C to 215 C temperature range. Also, a small amount of rust stains were evident on the pipe exposed to the 450 C to 560 C temperature range (0 mm to 100 mm). The rust stains from the 450 C to 560 C range were easily removed by lightly abrading the coating surface, indicating the rust did not originate from the steel substrate, but presumably came from corrosion at the end of the steel pipe. The adhesion of Coating A to the steel substrate was excel-lent (Table 2). Virtually no coating could be removed by prying with a stout knife except for a few tiny coating chips (~1 mm in length), which disbonded cohesively at the region of the pipe exposed to 240 C. Coating A showed no visible signs of blis-tering, flaking, or cracking. Excluding rusting, Coating A had no other visible changes except for moderate dulling above 375 C.

Stainless Steel PipeThere was no evidence of rusting (ISO 4628-3 Rating 0), (Fig. 7, p. 42) or blistering (ISO 4628-2) of Coating A along the entire length of the pipe. However, cracking (ISO 4628-4) and flaking of large coating chips (5 mm to 20 mm in length) occurred from the pipe’s surface from 0 mm (600 C) to 100 mm (460 C). With the exception of the flaking, the adhesion of Coating A to the steel substrate was excellent (Table 2), and no coating could be removed by prying with a stout knife.

TMIC In ActionDetailed pictures of TMIC after exposure to CUI in cyclic test conditions are shown in Figs. 10 and 11 (p. 44).

Carbon Steel PipeNo rusting occurred along the length of the pipe other than a small amount of rust stain over the 450 C to 560 C temperature range. The rust stains were easily removed by lightly abrading the coating surface, indicating that the rust presumably came from corrosion at the end of the steel pipe. The TMIC showed no evidence of any blistering, flaking, or cracking. The adhesion to the substrate of TMIC was very good (Table 2). A very small amount of coating chips (1–2 mm in length) disbonded cohesively and adhesively over the 75 C to 240 C temperature range when the coating was pried with a stout knife. A slight loss of luster and moderate dulling of TMIC was most pronounced in the 450 C to 500 C temperature range.

Stainless Steel PipeThere was no evidence of rusting (ISO 4628-3 Rating 0, Fig. 7), or blistering (ISO 4628-2) of TMIC along the entire length of the pipe. However, cracking (ISO 4628-4) and flaking of large

coating chips (5 mm to 20 mm in length) occurred from the pipe’s surface from 0 mm (600 C) to 100 mm (460 C). The TMIC disbonded adhesively and cohesively even though one coat was applied. The adhesion to the substrate of the TMIC was very good (Table 2, p. 40). A very small amount of coating chips (1–3 mm in length) cohesively and adhesively disbonded over the 75 C to 175 C temperature range area when pried with a stout knife. A slight loss of luster and dulling of TMIC was most pronounced in the 320 C to 460 C temperature range.

General DiscussionPartA:TemperatureProfileStudieson Bare Steel PipesWhen the insulation was dry, the temperature gradually de-creased from the hot end of the pipe to the cold end; when the insulation was water saturated, the temperature did not change gradually, but instead was arrested at 100 C between 100 mm and 300 mm from the hot end. The arrest was speculated to result from evaporative boiling of water from water saturated in-sulation, which did not dry out during the heat cycle in this area. Measurements of temperature through the thickness of the insulation suggested that the insulation became water satu-rated at the top of the pipe after about 2 days, and towards the bottom of the pipe after 5 days. After water saturation, the temperature within the insulation was similar to the pipe surface temperature, and no significant temperature gradient occurred across the insulation. High rates of corrosion of bare steel pipe would be expected over most of the pipe where the insulation remained wet and the temperature was ≤ 100 C. The results indicated the temperatures to which the CUI coatings were subjected were considerably lower than predict-ed from the temperature measurement profile on the pipe with dry insulation. In the authors’ previous studies of the CUI cyclic testing performance of TSA, a TMIC coating, and two inorganic silicone polymer coatings, a temperature range of 95 C to 445 C was cited for the test pipes. Differences of coating performance were generally observed at the reported ranges of 210–190 C, 245–210 C, 285–245 C, 335–285 C, 390–335 C, and 445–390 C. The best of the four coatings during the CUI cyclic test runs were TSA and TMIC. Furthermore, both were markedly superior in performance to Coating #1 and Coating #2 in that study. To reiterate, Coating #2 in the previous study is Coating A in the present study. Also in the earlier work, corrosion was evidenced on bare steel pipe subjected to the same CUI conditions as coated pipes. In that case, a high density of small pits were seen at a reported temperature of 445–285 C, large pits at 285–190 C, and both small and large pits at 190–95 C. First and foremost, this new work shows that the introduc-


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tion of brine into the insulation significantly reduces the pipe surface temperature and insulating properties. In particular, if the saturation is sufficient that dry-out cannot occur, the steel pipe surface remains wetted by NaCl brine at elevated tempera-ture, a condition producing high rates of corrosion. The earlier reported temperatures were lower in reality. This explains why corrosion on bare steel apparently seemed to occur on carbon steel at temperatures higher than expected according to the re-ceived wisdom.5, 6 Table 3 (p. 42) shows the temperature range corrections based on the current investigations.Notwithstanding the temperature corrections in Table 3, it is important to note that the ranking of coating performance of the four coatings remains unchanged. Applied to carbon steel pipes, and under repetitive cyclic thermal conditions, other than TSA, the TMIC coating rated to ca 400 C provided the best thermal resistance and corrosion resistance in the critical CUI temperature range of -4 C to 175 C.2, 3

Part B: CUI Studies On Coated Carbon Stainless Steel PipesIt is interesting to note the compositional differences between carbon steel and stainless steel, the effect of temperature on these steels, and what influence, if any, might result from re-ex-posing coated carbon and steel pipes to the highest tempera-tures sustained in the present CUI studies.

Carbon Steel SubstrateThe pipe material used for the CUI investigation was reported to be ASTM A513 (grade not reported), low carbon steel welded pipe. This pipe is generally produced in the hot or cold rolled condition. The microstructure of low carbon piping such as this generally consists of ferrite and pearlite. The upper temperature of the CUI studies was 600 C (1,113 F), below the transformation temperature of 723 C (1,333 F) for steel. Below the transformation temperature, the phases pres-ent at room temperature will remain stable, and not transform to austenite. Some alteration of the microstructure in the form of grain growth and spheroidization of pearlite may occur over long-term exposure at high temperatures, but in general, the properties of the steel will remain relatively consistent. In general, the coefficient of thermal expansion for carbon steel is 13.0 x 10-6 cm/cm C from 0 C (32 F) to 600 C (1,113 F). For a 25 cm length of pipe, the total linear expansion expected from room temperature to 600 C is 0.19 cm in length.

Stainless Steel SubstrateThe stainless steel pipe used was reported to be a Type 304 austenitic stainless steel with a nominal composition of 8–12 weight percent nickel, 18–20 weight percent chromium, and 0.08 weight percent carbon maximum, with the balance iron. The microstructure of this material will be predominately aus-tenite with some ferrite islands possibly present. The stainless

property is achieved by the tenacious surface oxide layer that is formed due to the alloying of chromium and nickel. This layer may be damaged in the presence of chloride solutions, result-ing in pitting attack. Type 304 stainless steels may be susceptible to sensitization at temperatures from 550 C to 800 C. At this temperature range, chromium may migrate to austenite grain boundaries, result-ing in a thin zone of chromium depletion adjacent to the grain boundaries. This chromium-depleted zone is susceptible to intergranular stress corrosion cracking in aggressive environ-ments, including chloride solutions. In general, the coefficient of thermal expansion for stainless steel is 17.3 x 10-6 cm/cm C from 0 C (32 F) to 600 C (1,113 F). For a 25 cm length of pipe, the total linear expansion expected from room temperature to 600 C is 0.26 cm in length. This will remain more linear from room temperature due to the austenitic matrix present.

Coatings on Carbon SteelTesting showed that TMIC was virtually unaffected by the high-temperature heating and water saturation under insulation. There was no evidence of blistering, rusting, adhesion loss, or flaking of TMIC. TMIC contains aluminum flake pigmentation and is a very flexible coating. While Coating A also performed well and did not suffer any blistering or flaking, it did sustain a small amount adhesion loss at 240 C and some pin point rusting occurred where the coating was exposed to the 100 C to 215 C temperature range. Coating A contains MIO pigmentation and is not as flexible as TMIC.2, 3 As seen in the earlier studies, TMIC somewhat out-performed Coating A in the high temperature microenvironment of the CUI cyclic test.

Coatings on Stainless SteelUp to a temperature of 460 C, testing showed that TMIC and Coating A performed almost as well on stainless steel as they did on carbon steel pipes. Indeed, there were no observations of blistering, rusting, adhesion loss, or flaking in the tempera-ture range of 70 C to 460 C for either coating. However, severe flaking occurred with both TMIC and Coating A due to exposure to the temperature range of 460 C to 600 C. An investigation of this phenomenon using metallographic and other analysis will be undertaken to fully understand the mechanism present. Some possible scenarios for the coating disbondment are significant sensitization and intergranular attack of the stainless steel during the cooler temperature cycles in the presence of the chloride solution. The higher thermal expansion coefficient may also contribute to the coating bond degradation at the elevated temperature. TMIC also showed some separation in the coating at the temperature range of 460 C to 500 C. Overall, TMIC performed as well as it did in previous studies


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at lower temperatures.2, 3 Coating A performed better than it did in previous studies at lower temperatures.2, 3 At the time of writing, the authors’ CUI research is continu-ing. Shorter carbon steel and stainless steel pipes have been coated with TMIC and Coating A and are being subjected to the same CUI test regimen as presented here. The dimensions of the pipes are 6 cm in diameter and 30 cm in length with a 5 mm thick wall. The results of that work will be presented at a later date together with any optical microscopy and SEM investiga-tions.

ConclusionsOne coat of TMIC and a two-coat system of Coating A showed similar performance under the applied CUI test conditions on both carbon and stainless steel pipes. On carbon steel pipes, TMIC was marginally better in that there was no evidence of blistering, rusting, cracking, flaking, or adhesion loss, whereas Coating A exhibited some pinhole rusting over the 100 C to 215 C temperature range. When TMIC and Coating A were exposed to higher tempera-tures on carbon and stainless steel pipes, there appeared to be more compositional changes in stainless steel than in carbon steel at higher temperatures. This resulted in both coatings disbonding when applied to stainless steel. The undercover agent TMIC performed as well as it did in previous studies at lower temperatures. The undercover agent Coating A performed better than it did in previous studies at lower temperatures. The temperatures to which the CUI coatings were subjected were considerably lower than initially predicted from a tem-perature measurement profile on pipe with dry conditions. The introduction of water and or brine into the insulation material significantly reduces the pipe surface temperature and insulat-ing characteristics. The insulation type also plays a role in determining the corro-sion resistance and performance of CUI coatings and therefore any prediction of coating lifetimes from short term aggressive testing methodologies is difficult. (Although accepted as true, this is not a conclusion of this study.) The overall performance of a CUI coating is most likely insu-lation-type specific. Further work is underway to evaluate these coatings under a range of insulation types.

References1. Goldie, B., Kapsanis K., “Corrosion Under Insulation: Basics and Resources for Understanding,” JPCL, July 2009, p. 34.2. O’Donoghue, M., Datta, V.J., Andrews, A., Giardina, M., de Varennes, N., Gray, L.G.S., Lachat, D., and Johnson, B., “When Undercover Agents Can’t Stand the Heat: Coatings in Action (CIA) and the Netherworld of Corrosion Under Insulation,” JPCL, February 2012, pp. 24–43. 3. O’Donoghue, M., Datta, V.J., Andrews, A., Giardina, M.,

de Varennes, N., Gray, L.G.S., Lachat, D., and Johnson, B., “When Undercover Agents Can’t Stand the Heat: The CIA and the Netherworld of Corrosion Under Insulation,” SSPC 2012. The International Protective Coatings Conference and Exhibition. New Orleans, LA, February 2012.4. O’Donoghue, M., Datta, V.J., “From Trauma to Transcendence: Corrosion Under Insulation,” NACE North Western Conference, Calgary, Alberta, Feb. 15–18, 2010.5. NACE Standard RP0198-2004, “Control of Corrosion Under Thermal Insulation and Fireproofing Materials – A Systems Approach,” NACE International, Houston, TX, 2004.6. Chustz, K., Personal Communication. March 2012.

About the AuthorsMike O’Donoghue, Ph.D., is the Director of Engineering and Technical Services for International Paint LLC. He has more than 30 years of experience in the protective coatings industry.Vijay Datta, MS, is the Director of Industrial Maintenance for International Paint LLC. He has more than 40 years of experience in the marine and protective coatings industry.Adrian Andrews is the Technology Development Manager, International Paint LLC. He has more than 30 years of experience in the protective coatings industry.Sean Adlem is the Sales Manager, Alberta Region Protective Coatings, International Paint LLC. Sean has over 20 years of experience in the protective coatings industry.Linda G. S. Gray, MSc, is a Senior Materials Specialist for RAE Engineering and Inspection Ltd. and has over 20 years of experience with industrial coatings.Tara Chahl, CET, is a Chemical Technologist for RAE Engineer-ing and Inspection Ltd. She has three years of experience in industrial coatings. Nicole de Varennes is Coatings LaboratoryManager for RAE Engineering and Inspection Ltd. She has 8 years of experience in various aspects of industrial coatings. Bill Johnson, AScT, is the Manager of Laboratory Services with Acuren Group Inc., in Richmond, BC. Bill has 20 years of ex-perience in materials testing, failure analysis, scanning electron microscopy, and energy dispersive X-ray analysis. JPCL


The ”No Big Bang Theory”An Introduction To Risk-Based Inspection Systems for Mitigating CUI in Process Equipment and Piping

Fig. 1a: (Left) Vertical process vessel after complete reblast and recoat with thermal spray aluminum. Thermal spray is used under insulation on large, flat, easy-to-access surfaces.Fig. 1b: (Right) Vertical process vessel coated with thermal spray aluminum after insulation and cladding have been replaced, and before removal of scaffolding.Photos courtesy of The Dow Chemical Company, St. Charles Operations, Hahnville, LA 70057

By Peter Bock, Capital Inspectors

Steelwork at all levels of industry in the United States is corroding despite our best efforts to stop it.1 Un-expected atmospheric corrosion damage (including corrosion under insulation—CUI) causes tens of billions of dollars in losses annually from unantici-

pated shutdowns of equipment; loss of production; unplanned maintenance; unexpected cleanup costs; and, in more severe cases, damage to adjacent equipment, injuries to operating personnel or surrounding residents, toxic chemical releases, environmental damage, and other long-term effects. Moreover, this unexpected corrosion damage affects everything from the largest and most sophisticated refineries down to small local waterworks and sewage plants. While the damage can take many forms, one of the most challenging is CUI, the focus of

this article. Our news media regularly report “big bangs”—fires, explosions, chemical spills, toxic releases and other similar “events.” Many of these are caused by CUI. CUI is as likely to be found on the boiler feed lines in a local hospital or food processing plant as in a coal-fired electrical generating plant or a major petrochemical facility, where hot process equipment and pipeline are common. The larger and more complex a manufacturing facility is, the more likely it is to suffer from CUI and unexpected atmospheric corrosion damage. In addition, the larger and more complex a plant is, the more likely it is that a corrosion-related failure during operation will have major consequences. Chemical and petrochemical plants can be quite complex, and the damage to them (and the surrounding area) from CUI can be quite severe because CUI is

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usually well under way before it is detected. Unfortunately, it is often “detected” after it has caused significant damage. Finding CUI before the damage occurs is challenging. This article de-scribes using risk-based inspection (RBI) to detect and mitigate CUI in chemical and petrochemical process equipment and pipeline before severe damage is done. The article also illus-trates a successful in-house CUI-RBI program in Figs. 1a and 1b; Figs. 2a, 2b, 2c, and 2d; and Fig. 3.

CUI: The Back StoryMost oil refining and petrochemical manufacturing processes are simply advanced forms of cooking—crude oil or intermedi-ate chemicals are “cooked,” heated under specific conditions or in specific temperature and pressure environments, to produce more desirable end products. Process vessels and piping are usually insulated to conserve process heat and reduce the fuel required, to reduce process temperature variations, to stabilize stored intermediates or end products, and to protect workers from exposure to hot equipment. Insulation is normally covered with unpainted aluminum or stainless steel sheet metal “clad-ding” to protect the fragile insulation. It is this sheet metal cladding over insulated piping and vessels that gives a refinery or chemical plant’s process units a shiny, misleading “good-to-go” appearance. But don’t be fooled—beneath that shiny exterior cladding and the insulation it covers, there usually beats a hidden heart of rusty steel. And in many cases, no one has any idea of how rusty the steel really is. Once corrosion eats into the steel, wall thickness is lost, and the vessel or pipe is no longer capable of resisting the tempera-ture and pressure it was originally rated for. Normally, there is a “corrosion allowance” of extra thickness in the steel. When the thickness of corrosion exceeds this allowance, the pipe or

vessel becomes unsafe. If corrosion continues, cracking, leak-age, or catastrophic failure during operation becomes more and more likely. Until the 1970s, carbon steel under insulation for elevated temperature service was often left unpainted. It was thought that the high operating temperatures would keep the steel from rusting, and there were no effective paints for high tempera-tures. There were two major problems with this concept. 1. Nothing stays hot forever—most elevated temperature equipment actually cycles hot-cold fairly frequently. Even equipment that runs hot almost continuously is cooled down for maintenance turnarounds and corrodes during those “cool” times if not protected.2. CUI is normally invisible. The insulation and cladding hide the steel, and even if it was properly painted with a temperature-re-sistant coating, there is usually no quick and inexpensive way to check that the coating is protecting the steel. To make matters worse, most cladding leaks, and most insulation holds water to some degree, so the steel under insulation is exposed to a se-vere immersion corrosion environment whenever it is operating below the boiling point of water. Today, there are effective coating systems available for ele-vated temperature CUI service, but problems 1 and 2 continue.2 Corrosion under insulation tends to be invisible, and no coating system gives 100% protection for tens of years under such severe conditions. The cost of removing cladding and insulation is time con-suming and very expensive; replacing cladding and insulation is even more expensive. Most insulated equipment receives only periodic spot checks of tiny areas during normal operation. Most of the steel under insulation is not seen for the expected life of the coating system or the expected life of the uncoated

Fig. 2a: Sphere being abrasive blasted prior to recoating and re-insulation. Maximum operating temperatures are low enough that an epoxy system can be used.

Fig. 2b: Newly applied epoxy primer and stripe coats on the sphere. Each step of the coating application process is closely inspected before the next step is allowed to start.


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steel. When the “expected life” matches real life, cladding and insulation are removed, and the steel beneath is inspected, re-prepared, re-coated, re-insulated, and re-clad. But real life becomes much shorter than “expected life” and catastrophes can occur when unexpected moisture or chemical contami-nants get beneath the insulation; when the steel is damaged; or when operating conditions change, allowing increased corro-sion under the insulation. The currently circulating draft of API RP 583, “Corrosion Under Insulation and Fireproofing,” lists nearly a dozen differ-ent electronic methods of checking remaining wall thickness of insulated and clad steel pipe or vessels.3 These methods range from simple X-rays to complex real-time systems using the latest nuclear technology. Many of these methods do not require the insulation and cladding to be removed while doing the electronic testing, but none has been found reliable enough to completely eliminate removal of insulation and cladding and visual inspection of the surface at problem areas indicated by the electronic test.

Risk-Based Inspection Systems for CUI Other than the expense of removing and replacing cladding and insulation, a large part of the reason for unexpected atmo-spheric corrosion damage from CUI or other sources is a lack of qualified plant inspection personnel and a lack of planning. All U.S. industries now run with extremely lean staffs of qualified personnel. Even some major refineries and chemical plants may have only one corrosion manager or corrosion engineer, and a few technicians at most. Moreover, the corrosion engineer is usually in charge of all types of corrosion mitigation, not just atmospheric corrosion or CUI and not just mitigation through protective coatings. Mid-sized facilities may have only a maintenance manager

or maintenance engineer, for whom corrosion mitigation is only a secondary duty. Very few successful, cost-effective facilities have enough people, time, and money in their maintenance budget to do thorough, complete CUI inspections regularly without outside help. Because of their limited staffing and bud-gets, smaller plants may actually operate on an “inspection by perforation” philosophy, which can be costly and dangerous. One effective (and cost-effective) method of CUI mitigation that has been known and used successfully for a couple of de-cades is a Risk-Based Inspection (RBI) Program. Unfortunately, RBI is a complex program that requires support and coopera-tion of the entire company, from top-level management to field-unit operators. Initial setup of an RBI program requires extensive in-house work, a fairly generous budget, and lots of time even for just the insulated piping and equipment in a plant.4 Operation of a successful RBI program also requires a multi-year commitment. For CUI-RBI, a successful program may require a multi-decade commitment because scheduled major maintenance programs on insulated piping and equipment can be at 10- to 15-year intervals. Many companies shy away from setting up meaningful RBI programs because the programs seem too complicated and too costly, the time horizons are beyond the companies’ normal planning ranges, and the com-panies’ plants do not have skilled people or budgets big enough to do the required initial baseline surveys.

Setting Up an RBI ProgramSetting up an RBI program requires an initial investment of time and thought by the company’s top management, who need to identify their company’s concept of “risk” and to rank their com-pany’s sensitivity (and aversion) to the different types and levels of risk they may encounter in operating their plants. Fortunately, this type of assessment needs to be done only once for the en-tire company, or, at most, once for each type of operating unit and possibly each country the company operates in. The Exploration and Production, Americas, division of one global oil and petrochemical producer has worked with the RBI concept for more than two decades. On the one hand, the divi-sion has distilled the basic concept and philosophy of RBI into a simplified matrix printed on two sides of one sheet of paper. On the other hand, the petrochemical division of the same compa-ny has expanded it to a level where, for some process units in its South Louisiana petrochemical plants, every valve, every flange, and sometimes even every set of bolts and nuts have been analyzed and given an individual “criticality” rating and inspec-tion frequency requirement. We can draw on both divisions’ use of the matrix to amplify our discussion of setting up an RBI program. Producing a Risk Assessment Evaluation requires identifi-cation of potential events and their potential consequences, estimating their potential severity and likelihood, and then estimating the level of risk based on the combination of severity and likelihood of the event happening. A Risk Assessment

Fig. 2c: Epoxy topcoat of the sphere. After the epoxy had passed inspection and was fully cured to accept insulation, the sphere was insulated and cladding was installed.


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Evaluation is required for every location. For the exploration and production division of our model company, “location” is defined as the smallest individual unit assessed, down to each production platform offshore or each flow station onshore. For a refinery or petrochemical plant, a “location” may be defined as one production unit within a larger plant, or even one special-ized portion of the plant (such as “raw materials storage and handling”). A simplified typical Risk Assessment Evaluation Chart (Table 1) examines possible consequences of an unexpected event and their effect on the following.• Neighbors: People, buildings, and land in the area of the affected plant • Equipment in the plant itself

• Environment both in the immediate area and in general • Reputation of the owner or parent company, locally and worldwide Severity of consequences is rated from Zero—No injuries, no damage, no environmental or reputation effect—to Five—Multiple fatalities, massive damage to the facility, and a huge long-term impact on the environment and on the company’s reputation. A “Serious” effect, Three on the consequences scale, would be an event that produces many days of absence from work for affected employees, or that results in long-term disabilities; a release of large amounts of crude oil or of any reportable quan-tity of a hazardous chemical; an event that triggers an environ-mental fine; an event that incurs very high repair and mitigation

Fig. 2d: After work is complete and scaffolding has been removed, the newly recoated, insulated and clad sphere is seen at the left of the picture in the plant’s sphere tank area

Table 1: Risk Assessment Evaluation Chart


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costs; or an event that causes partial shutdown of a facility and generates extensive regional media coverage. The likelihood of such an event occurring is also rated in five steps, from “Possible but unlikely,” as the lowest rating to “Occurs Frequently” for the most likely to occur. A simple chart of severity versus likelihood of an event produces the risk rating for that particular event. The higher the likelihood of an event is and the more serious its consequences are, the more closely and more frequently the equipment involved must be monitored to keep the potential event from happening. The purpose of the RBI program is to reduce all such risks to a minimum “ALAP” (“As Low As Practical”), that is, to a level at which the cost and effort of further risk reduction are unafford-able or disproportionate to the risk reduction achieved. Once the Risk Assessment for all potential events has been com-pleted, the actual evaluation of operating equipment begins in order to determine the required Risk Based Inspection process for assuring that operation of the equipment will not produce negative events beyond the “ALAP” level. The second half of an initial RBI assessment involves person-nel actually operating and maintaining the equipment being rat-ed. These are the people who actually live with the equipment day-in and day-out; they are most qualified to identify portions of the unit or piece of equipment most likely to fail, and whose failure is most likely to cause damage. They also are most likely to know what coincidental or collateral damage one failure might cause to other parts of the plant. This process allows a whole series of possible “events” to be evaluated from each potential failure. Plant maintenance records and equipment design blueprints are analyzed to determine the portions or pieces of equipment most likely to corrode and cause an “event.” Then, potential events are rated for their effect on plant operation and pro-duction, and the same potential events are rated against the company’s Risk Assessment charts. This initial survey can be done by outside consultants, but, ultimately, it is the plant operating personnel who are familiar enough with plant components to know which are the most like-

ly to fail, and local plant management who are best able to determine what and how severe damage such a failure will cause.

Commitment to an RBI ProgramThe engineer or manager chosen to design and implement a CUI-RBI program faces a daunting task. First, he or she must be assured of buy-in from upper manage-ment and from the field people who will be doing the site evaluation. After every-one understands and agrees that an RBI program is a multi-year, continuing effort,

not a one-time inspection, there comes the question of return on investment (ROI). On the one hand, the initial survey and risk assessment are expensive and time-consuming. On the other hand, preventing one “Moderate” event from the Risk Evaluation chart can mean a savings of $1,000,000; preventing a “Major” event can save ten times as much. In comparison, the cost of the initial plant RBI survey may seem reasonable. For a refinery or oil production facilities, and for many pet-rochemical plants, the in-plant risks—such as a vapor cloud explosion, petroleum jet fire, petroleum pool fire, or major toxics release—can all do grievous harm to the plant, to the surround-ing environment, and to the company’s bottom line as well as to its reputation. The in-plant survey needs to identify specific high-risk areas or pieces of equipment whose failure might raise the severity of consequences on the “Equipment” column of the risk chart. Of course, such equipment should already be closely monitored as part of the plant maintenance program, but iden-tifying (or re-identifying) key high-risk items helps the RBI initial survey become a defined risk-mitigation process. Existing plant data on performance of unit vessels, piping, operating equipment, controls, and even electrical and elec-tronic sub-systems can be used to develop an RBI continuing inspection schedule and calculate its expected cost in terms

Table 2: Expected Service Life Performance of Typical CUI Systems

Fig. 3: Five-year-old liquid-applied elevated temperature coating exposed for RBI inspection. Liquid-applied coating is used under insulation on complex or hard-to-reach surfaces


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of dollars per square foot or dollars per linear foot of pipe per year of the RBI program. Remaining service life of an older unit, expected upgrades or replacement, and the part one unit plays in the overall operation of the plant all need to be evaluated against the risk evaluation for that particular unit. Once data is collected, the proposed RBI program needs to be prioritized, based on highest possible event consequences, age and replacement cost of equipment, turnaround schedules, and the ability to incorporate the RBI program into existing in-spection procedures (if any exist). Because there is not enough budget for 100% frequent inspection of all insulated areas, a priority ranking program is set up, with the “riskiest” vessels, piping, and equipment receiving the most frequent and most thorough spot inspections, and lower-risk equipment being inspected less often, or with less of the insulation and cladding actually removed as part of the scheduled inspection. Low-est-risk or no-risk equipment may receive only the minimum required electronic wall thickness tests annually. Some critical refinery areas may require 100% removal of cladding and insu-lation and 100% visual inspection. A key factor in the frequency of visual inspections is the equipment owner’s confidence in the CUI coating systems used on equipment included in the CUI RBI program. Where quality surface preparation, a suitable proven coating system, good application, and thorough inspection have been done on equip-ment under insulation, the number of inspection spots may be reduced to areas of known breakdown, and the inspection intervals may be extended. Table 2 shows a major global pet-rochemical company’s “confidence level” for length of service life of coatings under insulation, where operating temperatures never exceed the maximum service temperature of the applied coating system.5

Continuing the RBI ProgramAfter the base plant (or unit) RBI survey has been done, and the risks and hazards have been agreed upon, quantified, and ranked by plant personnel, then the actual annual (or otherwise recurrent) field surveys can be done by an outside survey firm that has experienced, qualified inspectors, and follows the base survey. Many existing RBI programs actually combine electronic non-destructive testing (NDT) with insulation and cladding re-moval and visual inspection of selected small areas. Both parts of the survey may be done by the same firm, or NDT can be done by a specialist, and the results can be verified by a paint inspection company. The findings of these recurrent surveys are summarized in electronic format, incorporating electronic testing results, digital photographs, and the field contract inspector’s “eyeball on the steel” evaluations. The plant’s corrosion engineer or maintenance manager now can examine the corrosion state of his facility on a computer monitor in his or her office, at his or her convenience. Management personnel can review the survey

results, match them against expected results based on the initial RBI survey, and decide on an appropriate course of action. In simplified form, the recurrent RBI survey can have four possible results for a particular unit or piece of equipment.• Less corrosion is found than was expected. This result is noted in the survey. If the result is found to repeat in the next scheduled survey of this unit, the unit or piece of equipment may be re-evaluated for lower risk or less frequent inspection. Some owners also use such a finding to re-evaluate related equipment, working on the sound theory that if one unit or piece of equipment is rusting less than expected, something else related to the equipment may be acting as an anode and rusting more than expected.• Corrosion is as expected. The survey is submitted and repeat-ed as scheduled.• A small increase in corrosion is noted over expectation. Additional portions of the unit are inspected at the same time to confirm the increase in corrosion. For CUI work, inspecting additional portions means removing additional small areas of cladding and insulation. The unit or area is marked, and the next scheduled re-inspection will determine whether unscheduled corrosion-preventive maintenance may be necessary.• A large or unexpected increase in corrosion is noted. Addition-al portions of the unit are inspected at the same time to confirm the increase in corrosion, and plant personnel are brought in to try to determine a cause. Budget and scheduling are rearranged to give priority to corrosion-preventive maintenance on this unit or piece of equipment. The recurrent survey schedule is rearranged to closely monitor this problem until corrosion-pre-ventive maintenance is done, and then afterward to determine whether the maintenance resolved the problem. RBI programs for plants with large amounts of insulated piping and equipment require additional input during the initial set-up of the program to assure that the spots selected for recurrent survey are actually representative of the “worst case” areas of each unit or piece of equipment. The first few recurrent surveys done by a contract inspection or survey firm may actu-ally include additional, redundant spot inspection points, which can be phased out later if survey results are as expected. Where electronic testing or thermal imaging produces reliable results and matches destructive spot testing over several recurrent survey cycles, the destructive testing spots may be reduced, thereby reducing the overall survey costs without affecting reliability. Figures 1-3 that accompany this article show an in-house RBI program in action at a petrochemical plant in South Louisi-ana. The facility is an older plant, but equipment is meticulously maintained, and a very thorough RBI program is in place. Sec-tions of insulated piping, vessels, and equipment are inspected annually on a rotating basis, with a typical section being re-in-spected every three years on average. The plant uses a combi-nation of organic coatings and thermal spray aluminum for CUI


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work; annual survey results tend to confirm the plant’s RBI base surveys and the service life expectations for the systems used. Confidence is high that the CUI-RBI program is working as it should. A Houston-area industrial gas facility, which produces vari-ous gases by cryogenically refrigerating air and then separating its components, has an entirely different approach to RBI for the company’s piping for transfer, storage, and loading. The facility doesn’t do any RBI. Analysis of maintenance and operating records on these low-temperature piping systems in the plant has shown that failures are always due to cracking of piping in cyclic service from cryogenic to ambient temperatures. A failed pipe is quickly discovered through unexpected pressure loss; the insulation and cladding over the pipe act as an effective containment over the ruptured pipe; and the only loss is of the product in the pipe, which, as a gas component of air, is inher-ently non-polluting. The plant has been designed to allow effective isolation of failed pipe run sections, so when such a failure occurs, the af-fected pipe run is shut in, insulation and cladding are removed, and the failed pipe section is replaced. Loss of product and loss of productivity are minimal. The plant runs several parallel air separation trains, so the downtime required to replace a frac-tured length of pipe in the transfer, storage, and loading piping produces only a small reduction in plant output and does not require other shutdowns. Corporate management has deter-mined that for these portions of the plant, this policy of neglect presents low enough risk and is more cost effective than an intense RBI program.

ConclusionUnfortunately, a great deal of corrosion-mitigation plant main-tenance, both for CUI and for atmospheric corrosion damage, is done reactively, rather than proactively. There is an “Oh Sh**” moment that comes in almost every unscheduled CUI inspec-tion. That’s when the plant corrosion engineer or maintenance manager looks at the large area of newly exposed corroding steel where insulation and cladding were removed after serious corrosion was seen in a smaller exposed area, and the engineer says “Oh Sh**. Fixing this is going to take my entire maintenance budget for the year.” For these plants, CUI repair work is scheduled and done only after a serious problem is unexpectedly found. This work often involves unscheduled shutdowns; loss of production; manufacturing bottlenecks or backlogs; and, occasionally, even fires, explosions, or toxic product releases. This maintenance process is unnecessarily costly and can be easily improved. Improvement requires only a small increase in budgets and no long-term increase in plant personnel, using RBI with an initial survey by plant personnel and recurrent inspections by outside contract inspectors or surveyors. Although commitment to a CUI-RBI program requires a

substantial initial investment of time and effort, and a multi-year continuing commitment, the relative security, peace of mind, and confidence in the plant corrosion state offer a positive re-turn on investment even before factoring in the cost savings of not having an unexpected event that might shut down the plant, pollute the neighborhood, and irreparably injure the company’s reputation.

References1. George F. Hays, P. E., “Now is the Time,” White Paper, World Corrosion Organization, Houston, TX, corrosion.org, 2007.2. “Control of Corrosion Under Thermal Insulation and Fireproofing Materials, a Systems Approach,” NACE SP 0198- 2010, NACE International, Houston, TX, nace.org, 2010.3. “Corrosion Under insulation and Fireproofing,” Currently circulating draft of API RP583, First Edition, First Ballot, American Petroleum Institute, Washington, DC, api.org, 2012.4. Keith E. McKinney, Fred J. M. Busch, Andre Blaauw, Andrea M. Etheridge, “Development of Risk Assessment and Inspection Strategies For External Corrosion Management,” Paper No. 05557, NACE Corrosion 2005, NACE International, Houston, TX, nace.org, 2005.5. William C. McRae and Nalton Thompson, “CUI Project Development,” Bring on the Heat 2013, NACE International, Houston, TX, nace.org, 2013.

Peter Bock is Inspection Sales Manager for Capital Inspectors, The Woodlands, TX. He is an Air Force veteran and has degrees from Tulane and the University of Northern Colorado. Bock has 36 years of experience with sales, management, and techni-

cal service in oilfield and petrochemical heavy-duty coatings in the U.S., Canada, Mexico, Venezuela, Indonesia, and Taiwan. He has experience with on- and offshore production, drilling and workover rigs, ship-yard work, natural gas and LNG, pipelines, terminals, refineries, and chemical plants. He is a specialist in elevated temperature systems and CUI mitigation.

The author gives special thanks for the photographs to Mr. Lawrence “Joe” Bordelon, Senior Coatings & Linings Technol-ogist, Site SME/Technical Support/Paint Operations, Global Paint/ Linings TRN Member, The Dow Chemical Company, St. Charles Operations. JPCL


Over the past 25 years or so, problems with cor-rosion under thermal insulation (CUI) have been recognized by the chemical and petrochemical industries, leading to the need for effective corrosion protection for piping, vessels, and

equipment encased in thermal insulation. The first part of this article briefly reviews how the environment for CUI is created. The review also explains how piping, vessels, and equipment are typically insulated and notes the historical circumstances that contributed to CUI. The second part of the article describes two recently published consensus documents about CUI and reports on three recent studies on CUI. The article is not intended to be a comprehensive discussion of CUI. Previous articles have addressed in varying detail many issues associated with CUI, including approaches to preventing it, performance of various coatings under insulation, and when coatings are needed under insulation (see examples, Referenc-es 1–8). An upcoming article will address the issue of deciding when to coat before insulating, taking into account more than the operating conditions.

Creating the Corrosive Environment under InsulationCorrosion of steel occurs when steel is in direct contact with water and oxygen. In most atmospheric services, corrosion occurs at such a rate that application of a protective barrier in the form of a coating system significantly extends the life of exposed piping, vessels, and equipment. The environment cre-ated when a steel surface is encased under thermal insulation is often more conducive to corrosion, resulting in significantly higher corrosion rates, than an analogous uninsulated surface. Corrosion under insulation is of particular concern because many insulating materials trap and hold moisture against the steel so that insulated surfaces are subject to a wetted envi-ronment for greater lengths of time than uninsulated surfaces, which more readily dry out. Many surfaces are insulated to retain heat, so the time in the wetted environment is also at an elevated temperature, resulting in an increased corrosion rate. Because the progressive corrosion of insulated surfaces is not readily observed, and therefore not allowing for regular mainte-nance when corrosion is minor, CUI often proceeds unnoticed until consequences are severe.

The Insulation SystemInsulation is typically applied to piping, vessels, and equipment in the petrochemical industry to maintain process tempera-tures. (In some facilities, insulation is also used to protect

Corrosion under Insulation:Basics and Resources for Understanding

By Brian Goldie and Karen Kapsanis, JPCL

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personnel from hot surfaces, but this topic is beyond the scope of this article.) Thermal insulation materials are generally porous materials (capable of absorbing moisture), including mineral wool, foam glass, aerogels, and polymeric foams. Insulation is clad or jacketed to prevent physical damage. Insulating and cladding materials are selected based on performance versus cost. The insulation system (insulation and cladding) must per-form so that its cost at an effective thickness is more than off-set by the savings resulting from maintaining process tempera-tures. The economics do not allow for systems with insulating materials that are highly impermeable to moisture ingress and with cladding that is moisture tight. Additionally, damage to the external cladding on the insulation can be caused at installation, over time as personnel walk on the insulation or drop heavy objects, or through deterioration with time. Therefore, most thermal insulation systems are subject to moisture ingress, and CUI is a possibility. Common external sources of moisture are humidity, fog, rain, testing of fire safety deluge systems, and washing down of equipment and facilities. Salt and chemical contamination from industrial pollution and coastal proximity can also be present in the water, further increasing its corrosivity to carbon and stain-less steels.

A Historical Note on CUIUp until the 1970s, CUI was not generally a problem. Economics at that time were such that piping, vessels, and equipment were not insulated unless the operating temperature was above 150 C (302 F). Insulated steel surfaces that were 150 C or higher much of the time remained dry, so significant amounts of corro-sion did not occur. The oil shortage of the 1970s changed industrial insulation practices. Escalating energy prices changed the economics such that efforts to retain heat in processes operating be-low 150 C were now beneficial. At these lower temperatures, insulated surfaces were wetted more often and subject to corrosion. Coating systems that had been used successfully on uninsulated surfaces were subsequently used under insulation. These systems performed poorly in the hot, wetted environ-ment created under thermal insulation below 150 C; problems with CUI started to emerge; and their significance increased. The fact that a hot aqueous environment was present under the insulation (due to water penetration, as described above) was not originally appreciated. The conventional atmospher-ic coating systems of the day could not protect adequately against corrosion in what are essentially immersion conditions. Corrosion under insulation continued unobserved until the steel was so seriously damaged that it became evident by leaks or structural failure. These problems led to the use of immersion-grade coating systems capable of providing effective corrosion protection in a hot, wetted environment and resisting maximum operating

temperatures up to approximately 220 C (425 F). Mitigating CUI became the subject of a NACE International guideline, pub-lished over a decade ago and updated in 2004 (Recommended Practice RP0198, “The Control of Corrosion Under Thermal Insulation and Fireproofing Materials - A Systems Approach”).

The Problem PersistsDespite advances in understanding the corrosive nature of the environment associated with an insulated structure and the kinds of coatings that can withstand the exposure, the problem persists, as evidenced by the issuance in 2007 of an ASTM guide to laboratory tests for CUI; by the publication of a 176-page guidance document on CUI from the European Federation of Corrosion (EFC); and by some of the types of research into protection against CUI.

ASTM Issues CUI Lab Testing GuideFrom ASTM Subcommittee G01.11 on Electrochemical Mea-surements in Corrosion Testing came the 2007 consensus document, ASTM G189, “Standard Guide for Laboratory Simula-tion of Corrosion under Insulation.” As noted in the Scope, the Guide addresses laboratory simulation of general and localized CUI. It calls for test specimens to be insulated sections cut from pipe and exposed to a corrosive environment that includes elevated temperature. Described in the standard are a testing apparatus for CUI exposure, specimen preparation, procedures for simulating temperatures, as well as wet and dry conditions of a CUI environment. While the guide is intended mainly to help establish acceptable approaches to simulating CUI on carbon steel or low alloy steel for pipe, the Scope states that the test procedures might be useful for assessing other metals, an-ti-corrosion materials on pipeline, and other aspects of CUI, as long as the samples are suitable for the test apparatus.

EFC GuidelineThe EFC Working Parties WP13 and WP15 issued Corrosion under Insulation (CUI) Guidelines: (EFC 55) in March 2008. Edit-ed by Stefan Winnik of ExxonMobil Chemical and published by Woodhead Publishing, the volume represents the work not only of the working parties but also of major European oil refining, petrochemical, and offshore companies that collaborated with WP13 and WP15. The volume covers everything from economics to materials, practices, inspection, testing, and more. Among the chapters are the following.• “Economic consideration”• “Ownership and responsibility”• “The risk-based inspection (RBI) methodology for CUI”• “Inspection activities/strategy” • “NDE/NDT screening techniques for CUI”• “Recommended best practice to mitigate CUI” A wealth of appendices to the document amplify topics such


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as cost analysis, quality assurance, types of insulation, suitable coatings, including thermal spray, application methods, clad-ding, protection guards, and inspection techniques.Industry ResearchSeveral industry research studies from petrochemical, pipeline, and other interested companies were presented at NACE Interna-tional’s Corrosion 2008 Conference and Expo (New Orleans, LA). Researchers from ExxonMobil and Honeywell Process Solutions conducted a laboratory investigation of CUI on steel in three conditions: uncoated, coated with thermal sprayed aluminium (TSA), and coated with TSA but with defects that exposed the steel. Two types of insulation were also tested over the coated and uncoated steel: mineral wool and calcium silicates. Researchers followed ASTM G189 to approximate field conditions of cycling temperatures and alternating wet and dry conditions. Of the three types of steel samples, specimens protected with TSA (with no coating defects) showed the lowest corrosion rates under each type of insulation tested. The test methods, specimens, procedures, and results are detailed in “Evaluation of Steel and TSA Coating in a Corrosion under Insu-lation (CUI) Environment,” by Russell D. Kane, Monica Chauviere, and Keith Chustz, and published in the NACE Corrosion 2008 proceedings (Paper No. 08036). A study conducted by Shaw Pipe Protection Limited looked at an epoxy coating for its suitability for use under insulating foam with resistance to high heat, at or above 150 C. The struc-ture studied was buried pipeline. The high service temperature is needed for moving bitumen extracted via thermal recovery from the oil sands in Alberta, Canada. M. Batallas and P. Singh reported on the methods they used to test the epoxy and their results in “Evaluation of Anticorrosion Coatings for High-Tem-perature Service,” Paper No. 08039 NACE Corrosion 2008 proceedings. Because CUI can be hidden for a long time beneath cladding and insulation, it often is not recognized until damage to a pipe or vessel is dramatic. Systematic inspection of insulated equip-ment is an approach to reducing damage from CUI by catching it sooner, before the damage is dramatic, extensive, and expen-sive. Two approaches to inspecting equipment and structures for CUI were the subject of a study that two ConocoPhillips refineries undertook. One approach involved direct initial and then thorough inspection and maintenance as needed of insu-lated equipment. The initial inspection helped isolate equipment that needed refurbishment. The second approach omitted a direct initial inspection and instead used a software program to identify insulated equipment for inspection and maintenance as needed to prevent or mitigate CUI. Authors Rob Scanlan, Ricardo Valbuena, Ian Harrison, and Rafael Rengifo report on the differences in the effectiveness of the methods in identify-ing and remedying or preventing CUI (“A Refinery Approach to Address Corrosion under Insulation and External Corrosion,” NACE Corrosion 2008 Paper No. 08558.

Futher InformationFor information about ASTM G189, visit www.astm.org. For information about the EFC Guide, visit www.efcweb.org. For in-formation about the NACE RP0198 and the three NACE papers and discussed above, visit www.nace.org.

References1. John Montle, Thomas Sikes, William Ashbaugh, John F. Delahunt, and Debbie C. Maatsch, “Using Inorganic Zinc Primers Under Insulation,” Problem Solving Forum, JPCL, January 1985, pp. 10–11.2. Brian Goldie, “Tips on Using Coatings under Thermal Insulation: A UK Viewpoint” JPCL, July 1995, pp. 85–89.3. Mike Mitchell and Chris Birkert, “Corrosion Protection Under Thermal Insulation: Current Studies and Potential Solutions,” Protective Coatings Europe, July 1997, pp. 12–15, 61–62.4. Bruce Rutherford, “Preventing Corrosion under Insulation in Chemical Manufacturing Facilities,” JPCL, July 1998, pp. 40–49.5. Martyn Wilmott, John Highams, Richard Ross, and Adam Kopystinski, “Coating and Thermal Insulation of Subsea or Buried Pipelines,” Protective Coatings Europe, April 2000, pp. 53–60.6. Brian J. Fitzgerald and Dr. Stefan Winnik, “A Strategy for Preventing Corrosion Under Insulation on Pipeline in the Petrochemical Industry,” JPCL/PCE, April 2005, pp. 52–57.7. M. Halliday, “New Generation Solutions for an Age-Old Problem—Preventing Corrosion under Insulation,” JPCL, February 2007, pp. 24–36.8. Peter P. Bock and Michael F. Melampy, “Field Maintenance of Coating Systems under Insulation,” JPCL, April 2009, pp. 44–48.

Brian Goldie, JPCL’s Technical Editor, worked in the oil industry for many years. Karen Kapsanis is the Editor of JPCL.


This webinar explains the proper procedure for applying metallic thermal spray coatings (TSCs) of aluminum, zinc and their alloys and composites to protect steel from corrosion. Standards, required equipment, application procedures, and in-process

quality control checkpoints are discussed. Participants will be eligible to receive credit from SSPC.

John Kern is a technical auditor for SSPC. He has over 40 years of experience in the industrial coatings industry and over 30 years of experience in the corrosion industry. He has experi-ence as a Coatings Chemist Tech for New Jersey Department of Transportation, a Corrosion Chemist for the U.S. Navy, and a Coatings Program Engineer for the U.S. Coast Guard. He is a NACE CIP Level 3 #135, an instructor for multiple training cours-es for SSPC and a prior vice chair for the National Ship Research Program. He is the president, consultant and chief engineer for Virginia Coatings Inspections and a Consultant at ADA Technol-ogies.

Application of Thermal Spray CoatingPresented by John Kern, technical auditor, SSPC.

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Photo courtesy of Thermion

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