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CHEMICAL & PETROCHEMICALPLANT COATING SYSTEMS:SELECTING AND SOURCING

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Chemical & PetrochemicalPlant Coating Systems: Selecting and Sourcing

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Introduction

The “No Big Bang” Theory: An Introduction to Risk-Based Inspec-tion Systems for Mitigating CUI in Process Equipment and Pipingby Peter Bock, Capital Inspectors

Coating System Guide for Chemical & Petrochemical Plants

Coating Company Profiles

Contents

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Protective CoatingsYour Strategic Partner helping you minimize Corrosion and Cost

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IntroductionThis eBook consists of a Journal of Protective Coatings and

Linings (JPCL) article about inspecting corrosion under insulation at Chemical and Petrochemical Plants as well asJPCL Buying Guide material on selecting and specifyingcoatings for Chemical and Petrochemical Plants in variousexposure environments. All information about the article,products, and companies is based on the original dates ofpublication of the materials in JPCL.

The Buying Guide is organized, first, by exposure type, suchas “Exterior Plant Exposure, Moderate to Severe ChemicalWeathering, & UV,” then by substrate type, first steel, thenconcrete. Then, coating manufacturers are listed in alphabetical order, with each company’s preferred systemsnamed in both proprietary and generic terms. Finally, contact

details are given for allthe companies.

This collection is designed to provide general guidance on selecting and specifyingcoatings for Chemicaland PetrochemicalPlants, and then to givesources for acquiring theappropriate systems.

Introduction

iStockphoto

Editor’s Note: This article first appearedin JPCL in August 2013.

By Peter Bock,Capital Inspectors

T H E “ N O B I G B A N G ” T H E O R YAn Introduction to Risk-Based Inspection Systems for Mitigating CUI in Process Equipment and Piping

Fig. 1a: (left) Vertical processvessel after complete reblastand recoat with thermalspray aluminum. Thermalspray is used under insulation on large, flat,easy-to-access surfaces.Fig. 1b: (below) Verticalprocess vessel coated withthermal spray aluminumafter insulation and claddinghave been replaced, and before removal of scaffolding.Photos courtesy of The DowChemical Company, St. Charles Operations, Hahnville, LA 70057

Fig. 2a: Sphere being abrasiveblasted prior to recoating and re-insulation. Maximum operating temperatures are lowenough that an epoxy system canbe used.

S teelwork at all levels of industry in the United States is corroding

despite our best efforts to stop it.1 Unexpected atmospheric corrosion

damage (including corrosion under insulation—CUI) causes tens of

billions of dollars in losses annually from unanticipated 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, environ-

mental damage, and other long-term effects. Moreover, this unexpected

corrosion damage affects everything from the largest and most sophisticated re-

fineries 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 un-

expected atmospheric corrosion damage. In ad-

dition, the larger and more complex a plant is,

the more likely it is that a corrosion-related fail-

ure during operation will have major conse-

quences. 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 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 describes 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 illustrates 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 manufac-

turing processes are simply advanced forms of

cooking—crude oil or intermediate chemicals

are “cooked,” heated under specific conditions

or in specific temperature and pressure envi-

ronments, to produce more desirable end prod-

ucts. Process vessels and piping are usually

insulated to conserve process heat and reduce

the fuel required, to reduce process tempera-

ture variations, to stabilize stored intermediates

or end products, and to protect workers from

exposure to hot equipment. Insulation is nor-

mally covered with unpainted aluminum or

stainless steel sheet metal “cladding” to protect

the fragile insulation.

It is this sheet metal cladding over insulated

piping and vessels that gives a refinery or chem-

ical plant’s process units a shiny, misleading

“good-to-go” appearance. But don’t be fooled—

beneath that shiny exterior cladding and the in-

sulation 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 thick-

ness is lost, and the vessel or pipe is no longer

capable of resisting the temperature and pres-

sure it was originally rated for. Normally, there

is a “corrosion allowance” of extra thickness in

the steel. When the thickness of corrosion ex-

ceeds this allowance, the pipe or vessel becomes

unsafe. If corrosion continues, cracking, leakage,

or catastrophic failure during operation be-

comes more and more likely.

Until the 1970s, carbon steel under insula-

tion for elevated temperature service was often

left unpainted. It was thought that the high op-

erating temperatures would keep the steel from

rusting, and there were no effective paints for

high temperatures. There were two major prob-

lems 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 prop-

erly painted with a temperature-resistant

coating, there is usually no quick and inex-

pensive way to check that the coating is pro-

tecting the steel. To make matters worse, most

cladding leaks, and most insulation holds

water to some degree, so the steel under insu-

lation is exposed to a severe immersion cor-

rosion environment whenever it is operating

below the boiling point of water.

Today, there are effective coating systems

available for elevated 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.

Fig. 2b: Newly applied epoxy primerand stripe coats on the sphere. Each

step of the coating applicationprocess is closely inspected before

the next step is allowed to start.

The cost of removing cladding and insula-

tion is time consuming and very expensive; re-

placing 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 in-

sulation is not seen for the expected life of the

coating system or the expected life of the un-

coated 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 con-

taminants get beneath the insulation; when

the steel is damaged; or when operating con-

ditions change, allowing increased corrosion

under the insulation.

The currently circulating draft of API RP

583, “Corrosion Under Insulation and Fire-

proofing,” lists nearly a dozen different elec-

tronic 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 elec-

tronic testing, but none has been found reli-

able enough to completely eliminate removal

of insulation and cladding and visual inspec-

tion of the surface at problem areas indicated

by the electronic test.

Risk-Based Inspection Systems for CUI Other than the expense of removing and re-

placing cladding and insulation, a large part of

the reason for unexpected atmospheric corro-

sion 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 per-

sonnel. Even some major refineries and chem-

ical plants may have only one corrosion man-

ager or corrosion engineer, and a few

technicians at most. Moreover, the corrosion

engineer is usually in charge of all types of cor-

rosion mitigation, not just atmospheric corro-

sion or CUI and not just mitigation through

protective coatings.

Mid-sized facilities may have only a mainte-

nance manager or maintenance engineer, for

whom corrosion mitigation is only a secondary

duty. Very few successful, cost-effective facili-

ties have enough people, time, and money in

their maintenance budget to do thorough, com-

plete CUI inspections regularly without outside

help. Because of their limited staffing and budg-

ets, 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 decades is a Risk-

Based Inspection (RBI) Program. Unfortunately,

RBI is a complex program that requires support

and cooperation of the entire company, from

top-level management to field-unit operators.

Initial setup of an RBI program requires exten-

sive in-house work, a fairly generous budget,

and lots of time even for just the insulated pip-

ing 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 com-

panies’ 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 com-

pany’s top management, who need to identify

their company’s concept of “risk” and to rank

their company’s sensitivity (and aversion) to the

different types and levels of risk they may en-

counter in operating their plants. Fortunately,

this type of assessment needs to be done only

once for the entire 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 pro-

ducer has worked with the RBI concept for

more than two decades. On the one hand, the

division has distilled the basic concept and phi-

losophy 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

company has expanded it to a level where, for

some process units in its South Louisiana petro-

chemical plants, every valve, every flange, and

sometimes even every set of bolts and nuts

have been analyzed and given an individual

“criticality” rating and inspection frequency re-

quirement. We can draw on both divisions’ use

of the matrix to amplify our discussion of set-

ting up an RBI program.

Producing a Risk Assessment Evaluation re-

quires identification of potential events and their

potential consequences, estimating their poten-

tial 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 Evaluation is required for

every location. For the exploration and produc-

tion 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 specialized portion of the plant (such

as “raw materials storage and handling”).

A simplified typical Risk Assessment Evalu-

ation Chart (Table 1) examines possible conse-

quences 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 environmen-

tal or reputation effect—to Five—Multiple fa-

talities, massive damage to the facility, and a

huge long-term impact on the environment and

on the company’s reputation.

Table 1: Risk Assessment Evaluation Chart INCREASING LIKELIHOOD OF AN EVENT >>>>

EFFECTS OF AN EVENT ON: A B C D EPossible Possible Has Occasionally Frequently

NEIGHBORS EQUIPMENT ENVIRONMENT REPUTATION But Unlikely Occurred Occurs Occurs

(0) No Injuries No Damage No Effect No Effect

(1) Minimal Injuries Minimal Damage Detectable Effect Short-Term Local Effect RISK >

(2) Few minor injuries Easily Repaired Damage Measurable Effect Short-Term Regional Effect >>>

(3) Hospitalizations Serious Damage Slight Short-Term Effect Longer, Regional Effect >>>>>

(4) Death Long-Term Damage Serious Short-Term Effect National Effect >>>>>>>

(5) Multiple Deaths Total Loss Long-Term Effect Long-Term National Effect >>>>>>>>>

INCREASES

A “Serious” effect, Three on the consequences

scale, would be an event that produces many

days of absence from work for affected em-

ployees, or that results in long-term disabilities;

a release of large amounts of crude oil or of any

reportable quantity of a hazardous chemical; an

event that triggers an environmental fine; an

event that incurs very high repair and mitiga-

tion costs; or an event that causes partial shut-

down 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 un-

likely,” as the lowest rating to “Occurs Fre-

quently” 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 equip-

ment 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 un-

affordable or disproportionate to the risk re-

duction achieved. Once the Risk Assessment

for all potential events has been completed, 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 personnel actually operating and

maintaining the equipment being rated. These

are the people who actually live with the equip-

ment day-in and day-out; they are most quali-

fied 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 col-

lateral 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 de-

sign blueprints are analyzed to determine the

portions or pieces of equipment most likely to

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.

corrode and cause an “event.” Then, potential

events are rated for their effect on plant opera-

tion and production, and the same potential

events are rated against the company’s Risk As-

sessment charts.

This initial survey can be done by outside

consultants, but, ultimately, it is the plant oper-

ating personnel who are familiar enough with

plant components to know which are the most

likely 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 management and from the field peo-

ple who will be doing the site evaluation. After

everyone 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, pre-

venting 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 petrochemical plants, the in-plant

risks—such as a vapor cloud explosion, petro-

leum jet fire, petroleum pool fire, or major toxics

release—can all do grievous harm to the plant,

to the surrounding environment, and to the com-

pany’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 mainte-

nance program, but identifying (or re-identify-

ing) 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 electronic sub-systems

can be used to develop an RBI continuing in-

spection schedule and calculate its expected

cost in terms of dollars per square foot or dol-

lars per linear foot of pipe per year of the RBI

program. Remaining service life of an older unit,

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

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 pro-

gram needs to be prioritized, based on highest

possible event consequences, age and replace-

ment cost of equipment, turnaround schedules,

and the ability to incorporate the RBI program

into existing inspection 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 re-

ceiving the most frequent and most thorough

spot inspections, and lower-risk equipment

being inspected less often, or with less of the in-

sulation and cladding actually removed as part

of the scheduled inspection. Lowest-risk or no-

risk equipment may receive only the minimum

required electronic wall thickness tests annu-

ally. Some critical refinery areas may require

100% removal of cladding and insulation and

100% visual inspection.

A key factor in the frequency of visual in-

spections 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 inspec-

tion have been done on equipment under insu-

lation, 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 petrochemical company’s

“confidence level” for length of service life of

coatings under insulation, where operating tem-

peratures 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 out-

side survey firm that has experienced, qualified

inspectors, and follows the base survey. Many

existing RBI programs actually combine elec-

tronic non-destructive testing (NDT) with insu-

lation and cladding removal 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 engi-

Service LifeSystem Required Repair

Clad, insulated, uncoated bare steel(Lose entire wall thickness corrosion allowance) 6 years; 100% re-do

Clad, insulated, organic coating without abrasive blast(Lose entire coating system, portion of wall thickness) 12 years; 100% re-do

Clad, insulated, organic coating with SSPC-SP 10 abrasive blast(Lose portion of coating system, portion of wall thickness) 16 years; 100% re-do

Clad, insulated, thermal spray aluminum with SSPC-SP 5 abrasive blast(Lose small portion of TSA, small portion of wall thickness) 40 years; 25% re-do

Table 2: Expected Service Life Performance of Typical CUI Systems

neer or maintenance manager now can exam-

ine the corrosion state of his facility on a com-

puter monitor in his or her office, at his or her

convenience. Management personnel can re-

view the survey results, match them against ex-

pected 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 in-

spection. 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, some-

thing else related to the equipment may be act-

ing as an anode and rusting more than expected.

• Corrosion is as expected. The survey is sub-

mitted and repeated 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, inspect-

ing additional portions means removing addi-

tional small areas of cladding and insulation.

The unit or area is marked, and the next sched-

uled re-inspection will determine whether un-

scheduled corrosion-preventive maintenance

may be necessary.

• A large or unexpected increase in corrosion is

noted. Additional portions of the unit are in-

spected at the same time to confirm the increase

in corrosion, and plant personnel are brought in

to try to determine a cause. Budget and schedul-

ing are rearranged to give priority to corrosion-

preventive maintenance on this unit or piece of

equipment. The recurrent survey schedule is re-

arranged to closely monitor this problem until

corrosion-preventive maintenance is done, and

then afterward to determine whether the main-

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

tenance resolved the problem.

RBI programs for plants with large amounts

of insulated piping and equipment require ad-

ditional input during the initial set-up of the

program to assure that the spots selected for re-

current 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 actually include additional, redundant spot

inspection points, which can be phased out later

if survey results are as expected. Where elec-

tronic testing or thermal imaging produces reli-

able results and matches destructive spot

testing over several recurrent survey cycles,

the destructive testing spots may be reduced,

thereby reducing the overall survey costs with-

out affecting reliability.

Figures 1-3 that accompany this article show

an in-house RBI program in action at a petro-

chemical plant in South Louisiana. The facility is

an older plant, but equipment is meticulously

maintained, and a very thorough RBI program

is in place. Sections of insulated piping, vessels,

and equipment are inspected annually on a ro-

tating basis, with a typical section being re-in-

spected every three years on average. The plant

uses a combination of organic coatings and ther-

mal spray aluminum for CUI work; annual sur-

vey 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 various gases by cryogenically refrig-

erating 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. Analy-

sis 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 cryo-

genic to ambient temperatures. A failed pipe is

quickly discovered through unexpected pres-

sure loss; the insulation and cladding over the

pipe act as an effective containment over the

ruptured pipe; and the only loss is of the prod-

uct in the pipe, which, as a gas component of air,

is inherently non-polluting.

The plant has been designed to allow effective

isolation of failed pipe run sections, so when such

a failure occurs, the affected 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 fractured length

of pipe in the transfer, storage, and loading piping

produces only a small reduction in plant output

and does not require other shutdowns. Corpo-

rate management has determined that for these

portions of the plant, this policy of neglect pres-

ents low enough risk and is more cost effective

than an intense RBI program.

ConclusionUnfortunately, a great deal of corrosion-mitiga-

tion plant maintenance, both for CUI and for at-

mospheric corrosion damage, is done reactively,

rather than proactively. There is an “Oh Sh**”

moment that comes in almost every unsched-

uled CUI inspection. That’s when the plant cor-

rosion engineer or maintenance manager looks

at the large area of newly exposed corroding

steel where insulation and cladding were re-

moved 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 unex-

pectedly found. This work often involves un-

scheduled shutdowns; loss of production;

manufacturing bottlenecks or backlogs; and, oc-

casionally, even fires, explosions, or toxic prod-

uct releases. This maintenance process is

unnecessarily costly and can be easily im-

proved. Improvement requires only a small in-

crease 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 commit-

ment, the relative security, peace of mind, and

confidence in the plant corrosion state offer a

positive return on investment even before fac-

toring in the cost savings of not having an un-

expected event that might shut down the plant,

pollute the neighborhood, and irreparably in-

jure 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 In-

sulation and Fireproofing Materials, a Sys-

tems Approach,” NACE SP 0198-2010,

NACE International, Houston, TX,

nace.org, 2010.

3. “Corrosion Under insulation and Fireproof-

ing,” 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 In-

ternational, 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.

About the authorPeter Bock is InspectionSales Manager for Capi-tal Inspectors, TheWoodlands, TX. He isan Air Force veteranand has degrees fromTulane and the Univer-sity of Northern Col-orado. Bock has 36years of experiencewith sales, management, and technical service inoilfield and petrochemical heavy-duty coatings inthe U.S., Canada, Mexico, Venezuela, Indonesia,and Taiwan. He has experience with on- and off-shore production, drilling and workover rigs, ship-yard work, natural gas and LNG, pipelines,terminals, refineries, and chemical plants. He is aspecialist in elevated temperature systems andCUI mitigation.The author gives special thanks for the photo-

graphs to Mr. Lawrence "Joe" Bordelon, SeniorCoatings & Linings Technologist, Site SME/Tech-nical Support/Paint Operations, Global Paint/Linings TRN Member, The Dow Chemical Com-pany, St. Charles Operations.

ABRI IndustriesIronBond 111Inorganic Zinc/Epoxy/Urethane

Alwan Paints and CoatingsAlwanInorganic Zinc/Epoxy/Urethane

ARC Composites, Div. of A.W. ChestertonARC S7Vinyl Ester (3 Coats)

Atlas Minerals & Chemicals, Inc.RezkladEpoxy 100% Solids (1 or 2 Coats)

Avilion Inc.PPG/PSX 700Organic Zinc/Siloxane

Bowers IndustrialGulf CoastEpoxy (1-2 Coats)/Urethane

Carboline CompanyCarbozincInorganic Zinc/Epoxy/Urethane

Ceilcote (International Paint LLC)CeilcoteVinyl Ester (3 Coats)

CIM IndustriesCIMUrethane Elastomeric (1 Coat)

Cloverdale Paint Inc.ArmourshieldEpoxy (1-2 Coats)/Urethane

Coatings For Industry, Inc.UrethabondEpoxy (1-2 Coats)/Urethane

Copolymer Protection SystemsChemProof Polymers/PermaTecEpoxy/Epoxy 100% Solids

Corotech High Performance CoatingsCorotechEpoxy (1-2 Coats)/Urethane

Corporacion Mara SASigma CoatingsInorganic Zinc/Epoxy/Urethane

Corrocoat USA Inc.Polyglass VEFVinyl Ester (3 Coats)

Cote-L Industries Inc.Durabak 18Urethane/Urethane

CSL Silicones Inc.Si-Coat 580Siloxane/Siloxane

Dampney Co., Inc.ThurmaloxOther

Denso North AmericaDensoTape Wraps

Devoe HPC (International Paint LLC)Devoe High Performance CoatingsOrganic Zinc/Epoxy/Urethane

Diamond Vogel Paint CompanyMult-E-Prime 500/Multi-Thane 330 or 340Epoxy (1-2 Coats)/Urethane

Duromar, Inc.HPL-1110/HPL-1110Epoxy/Epoxy 100% Solids

ENECON CorporationChemclad XCEpoxy Novolac (1 or 2 Coats)

Eoncoat LLCEoncoat 0 VOCOther

EPDM CoatingsLiquid EPDMOther

FLOROCK, Crawford Labs, Inc.Florock CR 250Urethane/Urethane

FSC Coatings Inc.Rustop/SP-X Silicone Poly PlusAlkyd/Alkyd/Silicone Alkyd

Gemite Products Inc.Gem-Cote EP 100Epoxy 100% Solids (1 or 2 Coats)

Global EcoTechnologiesEndura-FlexUrethane Elastomeric (1 Coat)

Goodwest Linings and CoatingsCarboline, Sherwin-Williams, Devoe, InternationalOrganic Zinc/Epoxy/Urethane

Gulf Coast Paint Mfg., Inc.GCPEpoxy (1-2 Coats)/Urethane

Hempel (USA) Inc.17360/17630-3/5595UEpoxy (1-2 Coats)/Urethane

Heresite Protective Coatings, LLCHeresite CSE 6200/UC5500Epoxy (1-2 Coats)/Urethane

Highland International, Inc.475R Dry-Fall/68-R Dry-FallEpoxy (1-2 Coats)/Urethane

HJ3 Composite TechnologiesHJ3 CarbonSeal Industrial SystemsEpoxy/Epoxy Novolac (2 Coats)

Induron Coatings, Inc.Perma-GlossOrganic Zinc/Epoxy/Fluoropolymer

Industrial Coatings & SealantsPolycoatPolyurea Hybrid (1, 2, or 3 Coats)

Industrial Nanotech Inc.Nansulate PTThermal Spray

International Paint LLCInternationalInorganic Zinc/Epoxy/Siloxane

Isolatek InternationalFendolite M-IIThermal Spray

ITW Polymers Coatings North AmericaAS-250Epoxy/Epoxy/Epoxy

Photos courtesy Hempel

Exterior Plant ExposureModerate to Severe Chemical, Weathering, & UVSteel

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