67014-APR_2011

Here is the rIn March 2011, MATCOR celebrate

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e is the real cover story...ted a new era and new brand identity.

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NACE International, Vol. 50, No. 4 April 2011 MATERIALS PERFORMANCE 1www.carboline.com

http://www.carboline.com

2 MATERIALS PERFORMANCE April 2011 NACE International, Vol. 50, No. 4

coatings & linings

Redefining Antifouling Coating Technology—Part 1

Diego Meseguer Yebra and Pere Català

CL Blog

cHEMical tREatMEnt

The Role of Water Chemistry in Preventing Silica Fouling in

Industrial Water Systems

Z. Amjad and R.W. Zuhl

CT Blog

MatERials sElEction & DEsign

Construction Materials for Acid Gas Pipelines and Injection Wells

S. Bhat, Bipin Kumar, Dipanka Baishya, and M.V. Katarki

Review of Caustic Soda Service Chart for Carbon Steel

Avtandil Khalil Bairamov

Temperature Effect on Hydrogen Permeation of X56 Steel

Chuanbo Zheng and Guo Yi

©2011 NACE International

42

48

54

60

62

68

72

catHoDic PRotEction

FEatURE

Improvements to the External Corrosion Direct Assessment Process—

Part 2

David H. Kroon, Olagoke Olabisi, Larry G. Rankin, James T. Carroll,

Dale D. Lindemuth, and Marlane L. Miller

CP Blog

Corrosion Under Insulation—The Hidden Threat to Piping and

Equipment Integrity

Kathy Riggs Larsen

30

38

24

coatings & linings

about the coverSteel equipment is frequently insulated for personnel protection, energy conservation, or process stabilization in refineries and chemical processing plants, and there is a risk that corrosion will occur under the insulation material. Known as corrosion under insulation (CUI), this corrosion mechanism occurs when water from the outside environment infiltrates an insulation system and comes into contact with the metal surface of a pipe or piece of equipment. Shown on the cover is a close-up view of the outside surface of a severely corroded chemical storage tank that was insulated. The black spots are areas where corrosion perforated the steel from the outside inward. See the article beginning on p. 24 for a discussion on the causes of and solutions for CUI. Photo courtesy of Hi-Temp Coatings Technology.

nacE intERnational aPRil 2011 Vol. 50 no. 4

www.globalcorrosion.com

[email protected]

[email protected]

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http://www.globalcorrosion.com

mailto:[email protected]





APRIL 2011 DEPARTMENTS

UP FRONT 6

GOVERNMENT NEWS 8

VIEWPOINT 10

MATERIAL MATTERS 16

PRODUCT SHOWCASE 22

CORROSION BASICS 88

BUILDING BUSINESS CONNECTIONS 84

NACE NEWS

77 The NACE Annual Career and Salary Survey Is Expanding to Europe

78 NACE Area & Section News

80 NACE International Corporate

Members

81 NACE Course Schedule

82 Meetings & Events

MP (Materials Performance) is published monthly by NACE International (ISSN 0094-1492;

USPS No. 333-860). Mailing address and Editorial Offices: 1440 South Creek Drive, Houston,

TX 77084-4906; phone: +1 281-228-6200. Internet address: www.nace.org. Preferred

periodicals nonprofit postage paid at Houston, TX and additional mailing offices.

Canada Post: Publications Mail Agreement #40612608. Canada Returns to be

sent to Bleuchip International, PO Box 25542, London, ON N6C 6B2. Copyright

2011 by NACE International. Reproduction of the contents, either as a whole

or in part, is forbidden unless permission has been obtained from the publisher.

Articles and editorials herein represent the opinions of the authors and not necessarily those

of NACE. Advertising is included as an educational service, and products and/or services men-

tioned carry no implied or real endorsement or recommendation from NACE. NACE reserves

the right to prohibit any advertisement that is not consistent with the objectives of NACE.

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be obtained from the NACE Membership Services Department at the above phone number

and e-mail address. PRINTED IN THE U.S.A.

16 Software tools predict corrosion on ship hulls

18 Stainless steel with a tantalum surface alloy resists corrosion

in an aggressive acid environment

20 Company News

84 corrosion engineering directory

87 advertisers index

88 high-temperature corrosion

THE MP BLOG 11

http://www.nace.org


www.elcometer.com

[email protected]

http://www.elcometer.com



U P F R O N T

n A report in the American Chemical Society (ACS)

journal, Environmental Science & Technology, says that

household sewage has far more promise as an alter-

native energy source than originally thought. The

discovery, which increases the estimated potential

energy in waste water by almost 20%, could stimulate

efforts to extract methane, hydrogen, and other fuels

from this vast resource. According to the scientists,

U.S. sewage treatment plants use about 1.3% of the

nation’s electrical energy to treat 12.5 trillion gal

(47.5 trillion L) of waste water a year. The research

indicates that 1 gal (3.8 L) of waste water contains

enough energy to power a 100-W light bulb for

5 min. To learn more, visit www.acs.org.

Waste Water Potentially a New Energy Source

n A new, independent non-profit

organization—the Institute for

Sustainable Infrastructure (ISI)—

was founded by the American

Council of Engineering Companies

(ACEC), the American Public

Works Association (APWA), and

the American Society of Civil Engineers (ASCE) to

develop and administer a sustainability rating for

North American infrastructure. The performance-

based rating system, to be launched in the summer

of 2011, will be a voluntary, Web-based product

applicable to a wide range of infrastructure projects,

including roads, bridges, and energy and water sys-

tems, and adaptable to project size and complexity.

To learn more, visit www.asce.org or www.acec.org.

n Teams from the Institut Charles Sadron in col-

laboration with researchers from the Laboratoire de

Biomatériaux et Ingénierie Tissulaire, both part of

the Université of Strasbourg (Strasbourg, France),

have improved and extended the technique of layer-

by-layer thin-film deposition, which has led to the

development of a wide range of nanocoatings, includ-

ing anti-corrosion coatings, with new and extremely

varied properties. The original deposition technique

required successive dipping and long deposition

times. The new technique uses two bottles to simul-

taneously spray two liquids onto the surface to be

coated. To learn more, visit www.cnrs.fr.

Thin-Film Deposition Technique Advances Nanocoatings

Advanced Microscope Aids Nanoscale Research

n A research team from the National Institute of

Standards and Technology, the University of Mary-

land, Janis Research Company, Inc., and Seoul

National University has designed and built the most

advanced ultra-low temperature scanning probe

microscope (ULTSPM) in the world, which operates

at lower temperatures and higher magnetic fields

than any other similar microscope and provides new

research opportunities in nanoscale physics. To

achieve the ultra-low operating temperature of

10 mK, the team designed a low noise dilution

refrigerator to supplement the ULTSPM’s 3-m deep,

250-L liquid helium bath. The microscope itself sits

on top of a 6-ton granite table. For more information,

visit www.nist.gov.

Guidance Developed for Offshore Gas Terminals

Organization to Develop Infrastructure Rating System

n To address the rising development of floating

offshore gas terminals as well as those currently in

operation, Det Norske Veritas (DNV) (Oslo, Norway)

has prepared a new Offshore Technical Guidance

(OTG-02) on gas terminals, which covers a broad

range of issues, including classification and regula-

tory compliance, conversion of gas ships, structural

design, sloshing assessment, fatigue assessment, cor-

rosion issues, assessment of novel concepts, and

qualification of technology. The guidance applies to

different types of floating units, but is specifically

directed toward floating ship-shaped designs. For

more information, visit www.dnv.com.

n A report, “Tar Sands Pipeline Safety Risks,”

released by the Natural Resources Defense Council,

Pipeline Safety Trust, National Wildlife Federation,

and Sierra Club, discusses the risk of pipeline spills

as a result of diluted bitumen, a raw form of tar

sands oil that is more acidic and corrosive than

standard oil, being delivered to the United States

using conventional pipeline technology. According

to the report, diluted bitumen pipelines require

higher operating temperatures and pressures to

move the thick material through a pipe, which pose

new and significant risks of pipeline leaks or ruptures

due to corrosion. To read the report, visit www.

nrdc.org.

Report Discusses Tar Sands Pipeline Corrosion

—K.R. Larsen

http://www.acs.org

http://www.asce.org

http://www.acec.org

http://www.cnrs.fr

http://www.nist.gov

http://www.dnv.com

http://www.nrdc.org

http://www.nrdc.org

NACE International, Vol. 50, No. 4 April 2011 MATERIALS PERFORMANCE 7

www.Loresco.com [email protected]

http://www.Loresco.com



G O V E R N M E N T N E W S

n The U.S. Nuclear Regulatory Commission

(NRC) (Washington, DC) issued an information

notice (2011-04) to inform operators of pressurized

water reactor (PWR) nuclear power plants of the

effects of contaminants and stagnant conditions on

the potential for stress corrosion cracking (SCC) in

stainless steel (SS) piping in PWRs. The operating

experiences of several nuclear generating stations,

which are described in the notice, indicate that SCC

can potentially become an emergent degradation

mechanism in aging PWRs. It also states that SCC

can be managed effectively through cleanliness con-

trol of SS piping. To learn more, visit www.nrc.gov.

NRC Warns of SCC in Nuclear Power Plants

n The U.S. Department of Energy (DOE) (Wash-

ington, DC) finalized a $96.8 million Recovery

Act-supported loan guarantee to U.S. Geothermal,

Inc. to construct a 23-MW (net) geothermal power

project in southeastern Oregon. The project uses an

improved technology, referred to as a supercritical

binary geothermal cycle, to extract energy from rock

and fluids in the Earth’s crust more efficiently than

traditional geothermal binary systems, which allows

lower-temperature geothermal resources to be used

for power generation. Unlike coal-fired and natural

gas-fired power generation plants, geothermal plants

produce virtually no greenhouse gas emissions. For

more information, visit www.eere.energy.gov.

n Engineers with the U.S. Army’s Armament Re-

search, Development, and Engineering Center

(ARDEC) (Picatinny Arsenal, New Jersey) are using

cobalt alloys to develop a machine gun barrel that

will retain high strength during long-term exposure

to high temperatures from sustained firing. At high

temperatures, steel barrels lose their strength proper-

ties, requiring soldiers to carry spare gun barrels into

battle. The proof-of-concept barrel, produced from

an alloy containing more than 50% cobalt, consis-

tently reached high temperatures without degrading.

Other benefits of the cobalt alloy barrel are corrosion

and erosion resistance. To learn more, visit www.

army.mil.

Cobalt Alloys Facilitate High-Strength Weapons

DOE Finalizes Loan for Geothermal Project

New Power Plant Approved for Wales

n U.K. Energy Minister Charles Hendry issued

consent for Scottish and Southern Energy plc to build

a new 870-MW gas-fired power station near Port

Talbot, Wales. The Abernedd Combined Cycle Gas

Turbine Plant will be built at the Baglan Bay Energy

Park, on the former site of a chemicals facility,

and will have the potential to provide electricity to

1.4 million homes. This station will be built

carbon-capture ready, which means that carbon

dioxide (CO2) produced by the plant eventually could

be captured and transported for storage offshore. For

more information, visit www.decc.gov.uk.

PHMSA Issues Safety Order Notice

n As a result of an investigation of the

January 2011 pipeline leak at the Trans-

Alaska Pipeline System (TAPS) Pump

Station #1 (PS-1), the Department of

Transportation (DOT) Pipeline and Haz-

ardous Materials Safety Administration’s

(PHMSA) (Washington, DC) Office of

Pipeline Safety issued a Notice of Pro-

posed Safety Order to TAPS operator

Alyeska Pipeline Service Co. (Anchorage,

Alaska). Among other things, the preliminary find-

ings state a history of internal and external corrosion

problems upstream of PS-1 and that the leak is be-

lieved to be the result of external or internal corro-

sion. To learn more, visit www.phmsa.dot.gov.

n The European Chemicals Agency (ECHA) (Hel-

sinki, Finland) published proposals to identify seven

additional chemicals as Substances of Very High

Concern (SVHC) and possible candidates for autho-

rization—where they cannot be placed on the mar-

ket or used unless granted an authorization. These

substances are proposed because of their potentially

serious effects on human health. Among the chemi-

cals on the list are strontium chromate (SrCrO4), a

corrosion-resistant pigment, and hydrazine (H4N

2),

a corrosion inhibitor. ECHA invites interested par-

ties to comment on the proposals by April 7, 2011.

For more information, visit www.echa.europa.eu.

More Chemicals Proposed for ‘Concern’ List

—K.R. Larsen

http://www.nrc.gov

http://www.eere.energy.gov

http://www.decc.gov.uk

http://www.phmsa.dot.gov

http://www.echa.europa.eu

http://www.army.mil

http://www.army.mil

www.metalsamples.com www.alabamalaser.com

http://www.metalsamples.com

http://www.alabamalaser.com


editoriald ire Ctor , PUB l i Cat io NS

Ma Nag i Ng ed i tor

Gretchen A. Jacobson

te ChNiCal ed i tor

John H. Fitzgerald III, FnAce

aSS oC iate ed i tor

Kathy Riggs Larsen

ed i tor ial a SS iSta Nt

Suzanne Moreno

graPhiCSele Ctro NiCS PUB l i Sh i Ng SP eC ial i St

Teri J. Gilley

Ma Nager

e. Michele Sandusky

adMiNiStratioNNaCe exe CU t ive d ire Ctor

Robert (Bob) H. chalker

advertiSiNgSale S Ma Nager

Tracy Sargent

aCC oUN t exe CU t ive S

Anastasia Bisson

Jody Lovsness

Leslie Whiteman

advert i S iNg/B oo KS C oord i N ator

Brenda nitz

reg io Nal adve rt i S iNg Sale S

re Pre SeNtat ive S

The Kingwill co.chicago/cleveland/new York Area–

+1 847-537-9196

nAce International contact InformationPhone: +1 281-228-6200 Fax: +1 281-228-6300

e-mail: [email protected] Site: www.nace.org

editorial adviSorY Board

John P. Broomfield Broomfield Consultants

raul a. Castillo the dow Chemical Co.

irvin Cotton arthur Freedman associates, inc.

arthur J. Freedman arthur Freedman associates, inc.

orin hollander holland technologies

W. Brian holtsbaum dNv

lee Machemer Jonas, inc.

ernest Klechka Schiff associates

george d. Mills george Mills & associates international, inc.

Norman J. Moriber Mears group, inc.

John S. Smart iii Packer engineering

l.d. “lou” vincent l.d. “lou” vincent Phd llC

v i e W P o i N t

rebuilding infrastructure through Better decisions

A roadmap to help federal, state, and local officials tackle infrastructure cor-

rosion is currently in place. But the process for implementing this model is very

different from the framework the U.S. Department of Defense (DoD) uses to fight

corrosion on our military weapon systems.

When I speak of infrastructure, I refer to our

highways, roads, and bridges, as well as our pipeline,

utility, and wastewater systems. By now, members of

NACE International are familiar with the seminal

NACE-sponsored study, which estimates that cor-

rosion of this infrastructure directly costs the United

States $276 billion annually. Moreover, we should

understand that within the myriad agencies compris-

ing the U.S. DoD, U.S. Department of Transporta-

tion, and our federal, state, and local governments,

there is no central process or mechanism for curb-

ing the cost of mitigating infrastructure corrosion.

Nonetheless, it is paramount that we follow certain

corrosion prevention and mitigation protocols as we

repair and rebuild our aging infrastructure.

First and foremost, potential corrosion concerns must be addressed as new sys-

tems are being designed, based on the availability of resources. At first blush, this

is easier said than done because the system designers and decision-makers don’t

fall under the auspices of a single entity. Our first key challenge is to educate the

decision-makers within DoD, local municipalities, cities, and state governments,

and to make them aware that there are corrosion challenges to be considered in

the design of our bridges, roads, water and sewer systems, and military installations.

Second, coordination among policy-makers, engineers, and contractors is para-

mount so the best possible coatings, metals, and cathodic protection (CP) systems

are used. Decision-makers should ensure that subject matter experts select materi-

als that are appropriate and properly employed. Organizations such as NACE,

above all, can lead the way toward our meeting this challenge by forming public

and private partnerships and engaging state and local governments to address

corrosion in the design phase at the federal, state, and county level.

If you examine any of our DoD-approved CP technologies reviewed by the

Government Accountability Office, you’ll find that the return on investment (ROI)

is worth every cent expended by taxpayers, because they ensure that the life of

our military installations are prolonged for as long as possible.

DoD has a model in place for tackling infrastructure corrosion. This model

can and must be adapted and transferred to the executive branch, states, coun-

ties, and municipalities. This framework consists of DoD instructions, corrosion

prevention projects with a high ROI, guidebooks and technical handbooks, and

myriad collaborative efforts among DoD, industry, and academia. We need public

administrators and subject matter experts to adopt the DoD model and adapt it

to their own needs and requirements.

Finally, I should point out that corrosion is not the most important issue that

must be considered in preserving infrastructure. The DoD Corrosion Office

recognizes that important trade-offs must often be made at the design level. But

corrosion must be appropriately considered because we cannot afford to ignore

it anymore.

The DoD models for tackling infrastructure corrosion can be found at the

CorrDefense Web site at www.corrdefense.org.

Daniel J. Dunmire, Director, DoD Office of Corrosion Policy and Oversight


http://www.nace.org

http://www.corrdefense.org


NEPTUNERESEARCH.COM

The MP BlogExperiences and opinions from readers on corrosion issues

The following are excerpts from the NACE International Corrosion Network (NCN) and NACE Coatings Network. These are e-mail-based discussion groups for corrosion professionals, with more than 3,000 participants.

The excerpts are selected for their potential interest to a large number of NACE members. They are edited for clarity and length. Authors are kept anonymous for publication.

Please be advised that the items are not peer-reviewed, and opinions and suggestions are entirely those of the inquirers and respondents. NACE does not guarantee the accuracy of the technical solutions discussed. MP welcomes additional responses to these items. They may be edited for clarity.

For information on how to subscribe to these free list servers, click on the “Resources” link and then “Online Community” on the NACE Web site: www.nace.org.

Continued on page 12

Alloy 400 for naphthenic acid in crude oil service

QHow resistant is Ni-Cu

alloy (UNS N04400) to

naphthenic acid and

related organic acids

at elevated temperatures?

AI’ve never seen Alloy 400 or 500

(UNS N05500) in crude oil ser-

vice at temperatures high enough

to experience naph thenic acid

corrosion (say, above 400 °F [200 °C]).

My guess is that there would be hydrogen

sulfide (H2S) present, and a Cr-free Ni-Cu

alloy will not have good sulfidation cor-

rosion resistance.

AI don’t think Alloy 400 would last

very long in a normal naphthenic

acid corrosion situation in a re-

finery crude distillation unit be-

cause the H2S normally present will

corrode it rapidly above ~400 to 450 °F

(200 to 230 °C) and faster at 600 to

700 °F (315 to 370 °C). I don’t have any

rates in front of me but would guess

up in the 1,000 mpy (25 mm/y) range

at the higher temperatures because of

sulfidation.

I also don’t have corrosion rates in

straight naphthenic acid but remember

we used to fractionate crude naphthenic

acid sprung from crude oil with caustic,

which formed sodium naphthenates and

the 125 and 250 “neut” number acids

ate up any alloys that didn’t have a lot of

molybdenum in them.

http://NEPTUNERESEARCH.COM

http://www.nace.org


[email protected]

www.defelsko.com

M P B L O G

Continued from page 11

Corrosiveness of

50% caustic soda

QA customer of ours

contends that 50%

caustic soda (NaOH) is

corrosive to carbon

steel (CS) at a rate <2.5 mpy

(64 µm/y) when shipped in

railcars and loaded between

70 and 100 °F (21 and 38 °C). My

resources and experience predict 2 to 20

mpy (51 to 508 µm/y) in these service

conditions, varying with aeration, con-

tamination, commodity movement, etc.

I appreciate any comments you may have

on your experiences with this service.

AI always prefer data to theory, but

I have no data under your condi-

tions. However, 50% caustic soda

will have a pH >12. Under these

conditions, one would expect sharply

higher steel corrosion rates because of the

formation of soluble ferrates. However,

one must also take into account aeration.

In a tank car, one can expect that when

the dissolved oxygen is consumed in the

initial reactions, there may not be enough

oxygen transport to maintain corrosion

rates at significant levels. So, initial cor-

rosion rates may be quite high but then

quickly decrease to negligible levels.

ACS is usually considered “accept-

able” up to 50% NaOH to –60 °C.

Steel tanks and steel heating coils

(freezing point is ~20 °C) are used

in these conditions, but one does get hot

wall effects in such circumstances—Type

304 stainless steel (UNS S30400) or Alloy

600 (UNS N06600) is preferred. Much

depends on the acceptable iron content.

LaQue and Copson indicate rates of not

more than 0.1 mpy (2.5 µm/y) in 10 to

50% NaOH at room temperature. Nelson

indicates <1 mpy (25.4 µm/y) in 50%

NaOH at 40 °C, 5 mpy (127 µm/y) at

60 °C, and 8 mpy (203 µm/y) at 55 to

75 °C (Table 37 in Volume 13 of ASM

Metals Handbook).

Also, having 0.5% chlorates (a very

common contaminant and one that

controls the corrosion rate for nickel stoi-

chiometrically), causes a tenfold increase

in corrosion of steel in 48% NaOH, ac-

cording to K. Hauffe in DAECHEMA

Werkstoffe tabelle, p. 84 (1986).

ACorrosion could be greatly in-

creased depending on what the

other 50% is made up of. Even

small amounts of other chemis-

tries can increase corrosion rates. An-

other situation we often encounter in

railcars is that the environmental condi-

tions can vary greatly after the car is

emptied. Residue often remains, and it

can be exposed to completely different

levels of temperature, humidity, and oxy-

gen. Of course this would not occur if the

rail car was constantly full of product.


http://www.defelsko.com


www.corrpro.com

AThe corrosion rate of CS in 50%

caustic at 70 to 100 °F will be in

the range of 2.5 mpy or less.

However, 50% caustic must usu-

ally be heated to maintain this tempera-

ture. Although this heating may keep the

caustic in the 70 to 100 °F range, it may

also raise the metal temperature well

above 100 °F. As the temperature in-

creases, especially if it increases above

120 °F (49 °C), the risk of excessive cor-

rosion and stress corrosion cracking will

increase as well.

AThe original query related spe-

cifically to corrosion rates of CS

in 50% caustic when shipped in

a tank car. Can we sort out the

effect of conditions? A tank car is likely to

be an oxygen-depleting environment af-

ter initial corrosion processes. What is the

corrosion rate of steel in well-mixed, aer-

ated 50% caustic in this temperature

range? What is the rate-determining

process? Corrosion products would not

be expected to be stable at the pH of 50%

caustic based on Pourbaix diagrams.

Without clearly stating the conditions

under which various reported measure-

ments were made, we may be left with an

erroneous understanding of what is going

on. One would expect pH increases to

retard cathodic reduction of oxygen, but

the formation of soluble iron hydroxides

would depolarize the anodic reaction. At

different pHs, these effects would exert

varying degrees of control. Furthermore,

there is probably a transition region in

which the effects are approximately equal

and opposite—surrounded by ranges

where one or the other dominates.

Erosion-corrosion: bronze seawater pump shaft

QWe have a high-lift

seawater inlet pump

with a Nitronic† 50

(austenitic Cr-Ni-Mn

stainless steel [SS]) pump

shaft and nickel-aluminum

bronze (NAB) column and

impeller. There is severe erosion-

corrosion with dealuminification in the

body of the column, plus severe pitting

on the crevice face at the flanged point.

The SS and NAB are very good

matches from a galvanic perspective,

provided the NAB is able to maintain an

oxide film. Our bench tests have shown

that NAB without oxide film to be very

anodic relative to the SS. We are consid-

ering controlling oxidation of the NAB

surface followed by coating and sacrificial

anodes. Has anyone experienced a simi-

lar problem and implemented a proven

solution?Continued on page 14

†Trade name.

http://www.corrpro.com


[email protected] www.thurmalox.com

M P B L O G


AWe had lots of problems with our

seawater pumps that were made

of NAB casing and austenitic SS

impellers. It too had cathodic

protection with impressed current, but

the system failed to protect the NAB.

After many trials, we finally came up

with a solution that is something totally

unorthodox. It consists of coating the

NAB (anode) with three layers of an

epoxy ceramic coating while leaving the

impeller (cathode) uncoated.

We first tried coating the impeller

only, but the coating always failed by

flaking off. Then we tried coating both

the pump casing and the impeller and

the corrosion in the pump casing finally

was controlled because of the effective

protection provided by the organic coat-

ing. Again, the coating on the impeller

always peeled off.

Finally, we decided not to coat the

impellers anymore. We have five years

of accumulated experience with this

solution. There are 12 pumps that are

working under these conditions.

AWe had an almost identical prob-

lem in a pump used in the Red

Sea. The problem was resolved

by proper heat treatment of the

SS alloy.

External corrosion of copper water systems

QWe are experiencing

external corrosion

problems on domestic

table water Cu ser-

vices that are failing after only

six to seven years of service in

the same city. The services are con-

nected to polyvinyl chloride (PVC) water

mains. At the house end, they are con-

nected to polybutylene tubing that runs

into the house. Therefore, each service is

electrically isolated.

The soils do not appear to be highly

corrosive, with resistivities in the 1,600

to 1,900 Ω-cm range and pH of ~8.

Chloride and sulfate ion contents are low

(<10 ppm). Soils appear to be silty clay.

AI believe you have lost the sacri-

ficial anode that used to protect

the Cu services (ductile iron and

cast iron). The soils you describe

are quite corrosive to steel, so I would

expect them to be similarly corrosive to

Cu. It probably is pointless to pinpoint

the cause when the solution simply is to

cathodically protect the copper pipe. This

can be achieved using a prepackaged zinc

anode of suitable size to protect the sur-

face area of bare Cu at each service.

Since the advent of building designs

whereby the mains are nonmetal and

the building entry also is nonmetal, there

have been failures of brass curb stops and

the Cu services.

Editor’s Note: Additional MP Blog items

appear in the individual technical sections: cathodic

& anodic protection (p. 38), coatings & linings

(p. 48), and chemical treatment (p. 60).

Join the NACE Corrosion and

Coatings List Servers!

More than 3,000 corrosion professionals from all over the world participate on the NACE International Corrosion Network and NACE Coatings Network. You can post your question and receive expert advice in a matter of minutes.

To join either or both of these free list servers, go to the NACE Web site: www.nace.org, click on the “Resources” link, and then “Online Community.”

The networks look forward to your participation!


http://www.thurmalox.com

http://www.nace.org

NACE International, Vol. 50, No. 4 April 2011 MATERIALS PERFORMANCE 15www.enduropls.com

http://www.enduropls.com


Material Matters

Software tools predict corrosion on ship hulls

Corrosion of a ship’s

hull structure is a

primary concern

for ship owners

and the classifica-

tion societies that establish

and maintain technical stan-

dards for ship construction

and operation. To address

this problem, FLAGSHIP-

HCA (hull condition assess-

ment), a subproject of the

Pan-European FLAGSHIP

maritime transport project

funded in part by the Euro-

Software tools developed by FLAGSHIP-

HCA were demonstrated on the bulk

carrier M/V ANGELA. Photo courtesy of

PORTLINE.

pean Union (EU), has success-

fully developed a set of inter-

related software tools that

assist in monitoring the struc-

ture of a ship’s hull. Designed

for ship owners and survey-

ors, the tools work together to

more accurately forecast the

condition of the components

and coating of a vessel’s hull

over time, which will assist

ship owners and operators in

scheduling maintenance in a

more efficient manner, reduc-

ing maintenance costs and

improving safety at sea. The principal economic objectives of

FLAGSHIP-HCA are to extend the life

of the existing fleet of tankers and bulk

carriers by up to five years, and reduce

service repair costs for ships throughout

their lifecycle by 10 to 20%.

According to Ben Hodgson, project

manager at engineering consulting firm

BMT Group (Teddington, United King-

dom) and project leader for FLAGSHIP-

HCA, the software tools provide a process

for capturing information and formaliz-

ing the corrosion inspection process. The

set comprises a Survey Advisor Tool

(SAT), a Hull Health Advisor (HHA), and

a Corrosion Parameter Prediction Tool

(CPPT). The tools work together to im-

prove the effectiveness of surveys and

reduce the amount of time a ship is out

of service.


ww

w.F

arw

estC

orr

osio

n.c

omInformation on corrosion

control and prevention

The SAT is used to more easily and

efficiently plan and perform a hull survey.

It draws from a three-dimensional model

of the ship that contains information such

as measurements of the ship’s structural

elements, thickness and location of indi-

vidual plates and profiles, the type of

coatings that are used, and the environ-

mental conditions to which the coatings

are exposed (e.g., salt water, the spray

zone, or air). Theoretical hull corrosion

models are used to predict corrosion hot

spots and initially guide the surveying

process. To expand the data for the cor-

rosion models, information from other

similar structures and from other ships in

the fleet may be used, which can improve

corrosion predictions.

The interactive SAT displays the

ship’s structural elements, predicts spe-

cific areas where the ship may be the most

vulnerable to corrosion, and directs sur-

veyors to the most critical sections of the

ship with a ranked list of areas to be in-

spected. The survey route is planned to

optimize the surveyors’ time.

Once the inspection areas are identi-

fied, the HHA assists with performing

preventive hull assessments and mainte-

nance, and developing cost-effective

maintenance plans that best match the

operational plans for the ship. As a visual

inspection is conducted, this tool allows

the surveyor to record the results of the

inspection as well as the outcomes of any

maintenance actions. A database is then

updated with corrosion parameters as-

sociated with every aspect of the ship’s

hull based on observed rules and results.

Data from a hull thickness measurement

campaign to evaluate corrosion levels

can also be recorded. One of the main

goals of the HHA is to detect and present

abnormal occurrences, which include

corrosion and coating problems due to

excessive exposure to the environment,

and cracks and deformation due to

fatigue from excessive loads or weak

structures.

Once the data are inputted from the

HHA, the CCPT analyzes and uses them

to update and improve the parameters of

the theoretical corrosion models that are

utilized by the SAT to identify problem

areas in the ship. This helps the SAT to

provide a more accurate prediction of

specific areas where the ship may be the

most vulnerable to corrosion.

The tools provide a means for associat-

ing all the information for a particular

element of the hull, which can be used to

predict risk for other elements exposed to

the same conditions, explains Hodgson.

“The real benefit comes about when this

information is shared across multiple ships

in a fleet that have the same operational

characteristics. The pool of information

results in better estimates,” he says.

Initiated about three years ago, the

subproject was demonstrated on the

M/V ANGELA, a bulk carrier operated

by PORTLINE that was built in 2004

with an overall length of ~190 m and a

gross registered tonnage (NT) of 30,064.

The FLAGSHIP-HCA project, led by

the BMT Group, was supported, deliv-

ered, and trialed in conjunction with

MARINTEK (Norway), Bureau Veritas

and Sirehna (France), Germanischer

Lloyd (Germany), and PORTLINE—

Transportes Marítimos Internacionais

(Portugal).

Contact Benjamin Hodgson, BMT Group—

e-mail: [email protected].


http://www.farwestcorrosion.com


M A T E R I A L M A T T E R S

Stainless steel with a tantalum surface alloy resists corrosion in an aggressive acid environment

In oil well production, pumping

stimulation acids into an oil reservoir

through tubular piping, also known as

acidizing, is commonly used to clean tu-

bular deposits, remove formation dam-

age, and increase formation porosity. The

acidizing environments are aggressive

and almost every alloy used in the process

experiences high corrosion rates.

To evaluate the corrosion resistance

of several corrosion-resistant alloys

(CRAs) in these environments, research

laboratory Honeywell Corrosion Solu-

tions (Houston, Texas) conducted a study

in the laboratory that exposed samples of

various CRAs to two simulated deep well

acidizing environments. According to

NACE International member Brian

Chambers, the senior research engineer

with Honeywell Corrosion Solutions who

conducted the study, corrosion damage

is expected to occur in high-temperature

acidizing solutions, even with high doses

of the proper inhibitors. Because the tu-

bular piping is exposed to the acidizing

solutions for short periods of time, the

industry generally accepts corrosion rates

that are <2,000 mpy (<50.8 mm/y).

A view of the Ta-surface-alloyed specimen rack before

testing in the mild acidizing environment. Photo courtesy

of Honeywell Corrosion Solutions.

A view of the specimen rack following exposure to the

aggressive acidizing environment. The Type 316L SS

coupons on the upper right side of the rack and titanium

alloy coupons on the left side of the rack were completely

dissolved. Photo courtesy of Honeywell Corrosion Solutions.

Chambers explains that the study was

conducted to gain an understanding of

how these alloys would perform in the

acidizing environments and to determine

what the corrosion rates would be if the

materials were exposed to stimulation

acids for an ultra deep well. Both general

and localized corrosion were evaluated.

In the study, one test environment repre-

sented a mild acidizing condition with

10% acetic acid (C2H

4O

2) and the other

test environment corresponded to an ag-

gressive acidizing condition with 10%

hydrochloric acid (HCl), 10% C2H

4O

2,

and 0.1 MPa hydrogen sulfide (H2S).

Neither solution contained any corrosion

inhibitors; corrosion rates in uninhibited

acidizing solutions reflect a worst-case

scenario and are thought to better repre-

sent actual acidizing operations under

flow or conditions where inhibitors were

already consumed at shallower depths in

the well. The alloys tested were Type

316L stainless steel (SS) (UNS S31603),

nickel-based C276 (UNS N10276), tita-

nium alloys Ti 6-4 (UNS R56400) and Ti

6-2-4-6 (UNS R56260), and Type 316L

SS with a tantalum surface alloy.

Another goal of the study, Chambers

adds, was to prove a piece of equipment

that could withstand the acidizing envi-

ronments simulated in the tests. “Our

laboratory specializes in extreme environ-

ment exposure to test for corrosion and

cracking, so most of our equipment is

constructed of C276. We had already run

into a problem when we attempted tests

in these acidizing environments, and

caused damage to very expensive pieces

of equipment,” Chambers explains.

When the Honeywell researchers started

to experience degradation of their equip-

ment, they approached Tantaline

(Waltham, Massachusetts), a producer of

tantalum surface alloys, about treating

some of their lab equipment with its tan-

talum surface alloy process to determine

if the Ta surface alloy would hold up

under the corrosive acidizing environ-

ments when conducting tests.

Tantalum is known as one of the most

corrosion-resistant materials available,

explains Dean Gambale, president of

Tantaline. The problem with tantalum, he

says, is that it is very expensive, difficult to

machine, and difficult to fabricate into


TAbLE 1

Corrosion Rates in a Mild Acidizing Environment—

10% C2H

4O

2

Material

Weight Loss

mg

Corrosion Rate

mpy (mm/y)

Average Corrosion Rate

mpy (mm/y)

Type 316L SS 30.645.8

193 (4.9)291 (7.4)

242 (6.1)

C276 2.1 2.0

12.2 (0.3)11.6 (0.3)

11.9 (0.3)

Ti 6-4 0.3 0.1

3.3 (0.1)1.1 (0.0)

2.2 (0.1)

Ti 6-2-4-6 0.0–0.1

0.00.0

0.0

Ta-surface-alloyed Type 316L SS

–0.3–0.3

0.00.0

0.0

TAbLE 2

Corrosion Rates in an Aggressive Acidizing

Environment—10% HCl, 10% C2H

4O

2, and 0.1 MPa H

2S

Material

Weight Loss

mg

Corrosion Rate

mpy (mm/y)

Average Corrosion

Rate mpy (mm/y)

Type 316L SS >5,787 (dissolved)>5,747 (dissolved)

>36,506 (>927)>36,517 (>928)

>36,517 (>928)

C276 3,6043,589

20,901 (531)20,893 (531)

20,897 (531)

Ti 6-4 >3,733 (dissolved)>3,718 (dissolved)

>41,341 (>1,050)>41,312 (>1,049)

>41,341 (>1,050)

Ti 6-2-4-6 >1,260 (dissolved)>1,259 (dissolved)

>16,289 (>414)>16,231 (>412)

>16,289 (>414)

Ta-surface-alloyed Type 316L SS

–1.7 –1.7

0.0 0.0

0.0

parts. Tantaline has developed a propri-

etary vapor-deposition process where

commercially pure tantalum is chemically

reacted and vaporized in a furnace heated

to a temperature between 700 and 900 °C.

The high temperature provides conditions

suitable for diffusion and surface bonding

of the vaporized Ta to a fabricated metal

product at the atomic level. Gambale

emphasizes that the resulting surface alloy

is not a metallic coating with a distinct

interface between the two materials. The

interface or alloy zone between the Ta

surface alloy and the substrate is a metal-

lurgical bond that gradually blends the Ta

with the substrate metal until the surface

metal becomes pure Ta. The pure Ta

surface alloy is typically 50-µm thick.

All internal parts of the autoclave used

in the tests were constructed of alumina

ceramic or Ta-surface-alloyed Type 316L

SS. The specimen test rack was also made

of Type 316L SS with a Ta surface alloy.

The test coupons were stamped with

unique identification numbers, and the

location of each set of coupons on the

specimen rack was noted in the event that

identification numbers were illegible after

being exposed to the acid solutions.

The coupon exposure for each acidizing

environment was 8 h at 450 °F (232 °C),

after which the autoclave was quickly

cooled and the coupons were removed

and inspected.

In the test with the mild acidizing

condition (10% C2H

4O

2), all the alloys

exhibited corrosion rates well below

the 2,000 mpy acceptability criteria,

Chambers says. The results are shown in

Table 1. The corrosion rates in the test

with the aggressive acidizing condition

(10% HCl, 10% C2H

4O

2, and 0.1 MPa

H2S) were extremely high for all the alloys

evaluated except for the Ta-surface-

alloyed Type 316L SS, which exhibited

no corrosion. The Type 316L SS, Ti 6-4,

and Ti 6-2-4-6 coupons were all com-

pletely dissolved during the 8 h exposure.

Table 2 displays the results for this test.

“We were expecting the Type 316L

SS to be completely dissolved and were

anticipating extremely high corrosion

rates for C276,” Chambers comments.

“There weren’t many studies previously

done on the titanium alloys that would

tell us what would happen, so the test

results were interesting for certain, espe-

cially considering that the titanium alloys

were being considered for tubulars in

ultra deep wells because of their high

corrosion resistance in most cases, crack-

ing resistance, and the lightweight nature

of the alloy. It was enlightening,” he adds.

The results of the study also demon-

strated that the laboratory testing equip-

ment treated with the Ta surface alloy

process successfully withstood the highly

corrosive, high-temperature acidizing

environments, which is critical for the

lab’s equipment integrity.

More information on the Honeywell

study can be found in CORROSION

2011 paper no. 11106, “Performance of

Tantalum-Surface Alloy on Stainless

Steel and Multiple Corrosion Resistant

Alloys in Laboratory Evaluation of Deep

Well Acidizing Environments,” by Brian

Chambers, Anand Venkatesh, and Dean

Gambale.

Contact Brian Chambers, Honeywell Corro-

sion Solutions—e-mail: Brian.Chambers@

Honeywell.com; and Dean Gambale, Tanta-

line—e-mail: [email protected].

—K.R. Larsen





Plasticolors selects distributor for China

Shanghai Ji JingTrading and Developing Co.,

Ltd. was selected by Plasticolors, Inc. (Ashtabula,

Ohio) as its independent sales and distribution

representative. The company, which is a full-

service, fine chemicals distributor specializing in

the paint, printing ink, composite, and adhesive

markets, will distribute Plasticolors’ coatings

products in China. Plasticolors is a supplier of

advanced colorants and chemical dispersions for the

thermoset plastics, paint, and coatings industries.

Anerousis returns to Coastal Flow

John P. Anerousis rejoined Coastal Flow Gas

Measurement (Houston, Texas), part of the

Coastal Flow Measurement family of measurement

companies for natural gas and other hydrocarbon

fluids, as chief business development officer. A

former executive with Coastal Flow and the first

president of its subsidiary company, Physichem

Technologies, Inc., Anerousis will focus on the

continued advancement of the company’s BirdDog

Remote Data Retrieval System, as well as market-

ing and business development across all measure-

ment activities for the energy industries. He has

B.S. degrees in chemical engineering and chemical

engineering administration from the University of

Delaware, and an M.B.A. degree from Drexel

University.

Singleton receives Francis L. LaQue Award

ASTM International’s (West Conshohocken,

Pennsylvania) Committee G01 on Corrosion of

Metals presented Raymund Singleton, president of

Singleton Corp. (Cleveland, Ohio), with the Fran-

cis L. LaQue Memorial Award for his outstanding

contributions to the field of corrosion testing and

evaluation. Singleton serves as vice chair of mem-

bership on Committee G01 and vice chair of

Subcommittee G01.05 on laboratory corrosion

tests, as well as chair of Subcommittee G01.05.03

on cabinet corrosion tests. He is also a member of

the joint ASTM/NACE committee on corrosion.

American Innovations adds to management team

American Innovations (AI) (Austin, Texas),

a provider of products and services to automate

data collection, storage, and reporting for pipe-

lines, announced the addition of Michael Ray

and John Renfroe to its Compliance Technology

Division leadership team. Prior to joining AI,

Ray managed enterprise GIS implementations,

PODS data migrations, enterprise asset manage-

ment development, and executed integrity manage-

ment programs. He will utilize his diverse

pipeline industry experience to create and imple-

ment the strategic direction for AI’s Pipeline

Compliance Software, Risk Intelligence Platform,

System Analyzer, and the Allegro Field Data PC

product lines. Renfroe comes to AI from Affinis-

cape, where he served as the senior director of

engineering and led the Engineering, Quality

Assurance, and IT departments in the construc-

tion of three product lines. He will direct the

technology and employee resources needed for ef-

ficient delivery and growth of all product lines.

Colorado River Bridge honored with SSPC award

SSPC: The

Society for Protec-

t i v e C o a t i n g s

(Pittsburgh, Penn-

sylvania) awarded

its 2011 E. Crone

K n o y A w a r d ,

which recognizes a single, recent, outstanding

achievement in commercial coatings work that

demonstrates innovation, durability, or utility on a

commercial use structure, to the Hoover Dam

Bypass Project’s Colorado River Bridge, also

known as the Mike O’Callaghan-Pat Tillman

Memorial Bridge. Honored for their work on the

project were coating material suppliers PPG

Industries Protective and Marine Coatings (Pitts-

burgh, Pennsylvania) and Superior Products Inter-

national II, Inc. (Kansas City, Kansas), and

coatings contractor/applicator United/Anco

Services (Joliet, Illinois).

HALOX hires senior technical advisor

HALOX® (Hammond, Indiana), a provider

of corrosion inhibition services for the paint and

coatings industry, appointed Bodan Ma, president

of P.T. Hutchins China Co., as its senior techni-

cal advisor. Based in Shanghai, China, Ma will

work closely with the company’s distributor part-

ners in China and Taiwan, as well as focus on

developing and strengthening customer relationships

within the Asian marketplace. Ma holds a B.S.

degree in chemical engineering from the Tsinghua

University and a Ph.D. in polymer science and

engineering from the University of Massachusetts

at Amherst.

Curtiss-Wright to acquire BASF’s Surface Technologies business

Motion and flow control products manufacturer

Curtiss-Wright Corp. (Parsippany, New Jersey),

the parent firm of metal finishing services provider

Metal Improvement Co., signed a definitive pur-

chase agreement to acquire the assets of BASF

Corp.’s Surface Technologies business, which is a

supplier of metallic and ceramic thermal spray

coatings primarily for the aerospace and power

generation markets. The acquisition of BASF’s

Surface Technologies business adds a new offering

in the area of high technology coatings to Curtiss-

Wright’s existing portfolio of niche coating tech-

nologies.

Company news


Colorado River Bridge

MP welcomes news submissions

and leads for the “Material

Matters” and “Company News”

departments.

Contact MP Associate Editor

Kathy Riggs Larsen at:

Phone: +1 281-228-6281

Fax: +1 281-228-6381

E-mail:

[email protected]


NACE International, Vol. 50, No. 4 April 2011 MATERIALS PERFORMANCE 21NACE International, Vol. 50, No. 4 April 2011 MATERIALS PERFORMANCE 21


Product Showcase

PORTABLE POWDER

COAT ING SYSTEM

Resodyn Engineered Polymeric

Systems, Inc. (Butte, Montana)

has introduced its next genera-

tion high-output polymer thermal

spray (PTS) system. The PTS-

30TM system’s patent-pending

design incorporates the company’s

unique flameless heating technol-

ogy to gently process powdered

materials at high deposition rates

to create powder coatings of any

thickness, without the inclusion

of burned particles. The coatings

contain no volatile organic com-

pounds, require no post-baking or

cure, and are ready for immediate

use after application. Phone:

+1 406-497-5249, Web site:

www.resodyn.com.

Corrosion-resistant pump

CAT Pumps (Minneapolis, Minne-

sota) announces its new stainless steel

corrosion-resistant Triplex Plunger Pump

Model 1541, which is suitable for pump-

ing harsh and aggressive liquids such as

seawater, crude oil, waste water, deion-

ized water, and chemicals. The pump’s

design is energy efficient and enables

smooth, low-pulsation performance. The

stacked valve design facilitates servicing.

Rated at 18 gpm at 1,100 rpm with pres-

sures up to 1,200 psi, the pump weighs 55

lb (25 kg) and may be used in portable or

stationary installations. Phone: +1 763-

780-5440, Web site: www.catpumps.com.

Nondestructive test instrumentation

James Instruments, Inc. (Chicago,

Illinois) has released its 2011 catalog

featuring nondestructive test instrumen-

tation for construction materials and

structures. Products include handheld

equipment for the contractor, engineer,

material producer, and educator. The

instruments determine strength, locate

objects in structures, evaluate density

ultrasonically, analyze corrosion, and

determine moisture content in concrete,

mortar, brick, masonry, drywall, wood,

soil, and ceramics. The catalog features

products that evaluate a number of

parameters. Phone: 1 800-426-6500,

Web site: www.ndtjames.com.

Environmentally friendly antiscalants

BWA Water Additives (Tucker, Geor-

gia) has launched a new set of antiscalants

specifically designed for the environmen-

tally conscious customer. Designed for

cooling and process waters, the Belclene

800 family of products offers excellent

performance with low environmental

impact, based on biodegradability and

phosphorus content. Belclene 810’s bio-

degradability, effective calcium carbon-

ate scale inhibition, and chlorine stability

make it an ideal component of any green

cooling water treatment formulation.

Phone: 1 800-600-4523, Web site: www.

wateradditives.com.

http://www.resodyn.com

http://www.catpumps.com

http://www.ndtjames.com

http://www.wateradditives.com

http://www.wateradditives.com


The latest tools for fighting corrosion

Complementary Coatings Corp.

(Mont vale, New Jersey) has unveiled a

complete portfolio of industrial main-

tenance coating systems with the cre-

ation of Insl-x-branded CORTECH®

High Performance Coatings. Repre-

senting years of research, develop-

ment, and field experience, the new

line features more than 40 products

that include waterborne acrylics, ali-

phatic urethane, and an extensive

array of epoxies, enamels, and corro-

sion protection primers. A complete

selection of support materials is under

development, including new product

guides, ready-mix and custom color

cards, and custom fan decks. Phone:

1 800-225-5554, Web site: www.

corotechcoatings.com.

Ultimate Linings (Houston, Texas)

announces the availability of a spray

elastomer designed for demanding

applications against abrasion and cor-

rosion. Ultimate Linings Product UL

TK 22 is a fast-set, 100% solids, flex-

ible, two-component spray elastomer

made to deliver high performance

against tear and impact. It may be

applied in single or multiple applica-

tions without appreciable sagging and

can be applied in most temperatures.

Fast gel time makes the product

ideal for applications down to –20 °F

(–29 °C). Phone: +1 713-466-0302,

Web site: www.ultimatelinings.com.

MP welcomes submissions of product press releases and photos for Product Showcase. Please send them to the attention of Suzanne Moreno, NACE Inter-national, 1440 S. Creek Dr., Houston, TX 77084; phone: +1 281-228-6259; fax: +1 281-228-6359; e-mail: [email protected].

—S. Moreno

Solar-powered pumping system

Vanton Pump & Equipment Corp.

(Hillside, New Jersey) announces the

new Solar Powered Chemical Dosing

System, a nonmetallic, peristaltic pump

for corrosion-free transfer of caustic and

acidic treatment chemicals from an inte-

gral storage tank to water and wastewater

containment facilities in remote locations.

The pump, Flex-I-Liner® Model 12, uti-

lizes a rotor mounted on a shaft to push

fluid trapped between a flexible elastomer

liner and a solid plastic body block. The

self-priming design has no seals to leak

or valves to clog and can run dry without

damage. Phone: +1 908-688-4216, Web

site: www.vanton.com.

Safety gear for water jetting

Qualjet LLC (Seattle, Washington)

offers a complete line of protective cloth-

ing for ultrahigh-pressure water jetting

applications. Manufactured by TST®

Sweden AB, the clothing is made of

special fabrics containing the extremely

strong Dyneema fiber. Striped fabric

clearly identifies protected areas and

labels indicate the level of protection. Pro-

tective gear includes overalls, waistcoats,

trousers, jackets, aprons, hand protection,

boots, gaiters, and more. The large range

of products allows the user to choose the

ideal model appropriate for the work in

question. Phone: 1 866-782-5538, Web

site: www.qualjet.com.

Epoxy lining technology

Nu Flow America (San Diego, Cali-

fornia) and Nu Flow Canada (Oshawa,

Ontario) offer a trenchless technology to

protect pipes when traditional repair or

replacement methods are not economi-

cally or operationally feasible. Also used

to protect finished floors, walls, and ceil-

ings, the epoxy lining technology can

be used in situ to rehabilitate pipeline

interiors. The system is a cost-effective

solution for renewing and extending

the useful life of pipeline operations. It

is applied regularly in pipe diameters of

1/2 to 10 in (13 to 254 mm), and in spe-

cialty applications for diameters greater

than 10 in. Phone: 1 800-834-9597, Web

site: www.nuflowtech.com.

AbrASion-reSiStAnt

SprAy elAStoMer

induStriAl MAintenAnce

coAtingS

http://www.ultimatelinings.com


http://www.vanton.com

http://www.qualjet.com

http://www.nuflowtech.com

http://www.corotechcoatings.com

http://www.corotechcoatings.com


Corrosion Under Insulation— The Hidden Threat to Piping

and Equipment Integrity

Steel equipment in refineries and chemical processing plants, such as the vertical pipes (risers) on the front of the tower, is frequently insulated for personnel protection, energy conservation, or process stabilization. Photo courtesy of Hi-Temp Coatings Technology.

24 MATERIALS PERFORMANCE April 2011


S P E C I A L F E A T U R E

NACE Standard SP0198 Includes Revised Guidelines for Protective Coatings Under Insulation

Kathy Riggs LaRsen, associate editoR

In refineries and chemi-

cal processing plants, steel

equipment is frequently in-

sulated for personnel protec-

tion, energy conservation,

or process stabilization, and there

is a risk that corrosion will occur

under the insulation material. This

corrosion mechanism, known as

corrosion under insulation (CUI),

occurs when water from the out-

side environment infiltrates an

insulation system and comes into

contact with the metal surface of

a pipe or piece of equipment. The

water may contain contaminants

from the surrounding atmosphere

as well as the insulation. As a re-

sult, the environment under the

insulation may be very aggressive,

and subsequent surface corrosion

is hidden underneath the insula-

tion system and undetectable

through visual inspections. NACE SP01981 outlines the current

technology and industry practices for

mitigating corrosion under thermal insula-

tion and fireproofing materials. Originally

prepared in 1998 as RP0198, the standard

has been revisited several times and was

most recently revised and its designation

changed to SP0198 in June 2010. (All

NACE “recommended practices” are now

being called “standard practices.”) The

CUI prevention and mitigation experience

of many companies throughout the oil, gas,

and chemical industries is incorporated

into this new document.

“The recent changes we made to the

present document were not substantive to

the general structure of the standard, but

rather we were seeking to fine tune it and

add newer proven technologies that have

been developed recently,” says NACE

International member Murry Funderburg,

senior staff engineer with Shell Oil Prod-

ucts (Houston, Texas) and chair of NACE

Task Group (TG) 325—CUI: Revision of

NACE SP0198 (formerly RP0198), “The

Control of Corrosion Under Thermal

Insulation and Fireproofing Materials—A

Systems Approach.” While many aspects

of the standard remain virtually the same,

there are modifications to the document

that significantly impact the recommenda-

tions for protective coatings to mitigate

CUI. Some of these changes reflect tremen-

dous improvements made in the products

and systems available to mitigate CUI, and

the changes made to the document in 2010

bring the standard up to date.

“The problem with insulated equipment

is that you really have no idea of what is go-

ing on underneath the insulation and clad-

ding, and it is very expensive to find out,”

says NACE International member Peter

Bock, a NACE-certified Coating Inspector

Program (CIP) Level 1 Coating Inspector

and a CUI specialist for Hi-Temp Coat-

ings Technology (Houston, Texas). “There

is that moment in many under-insulation

repair projects when the maintenance per-

sonnel remove some insulation to complete

a minor repair job and find that the equip-

ment under the insulation is extremely cor-

roded. Quite often the degree of corrosion

under the insulation is a surprise. NACE

Standard SP0198 is the best guideline

we have for mitigating CUI for both new

construction projects and, to a very great

Severe corrosion was found under insulation that covered a vessel. Photo courtesy of Hi-Temp Coatings Technology.


S P E C I A L F E A T U R E Corrosion Under Insulation—The Hidden Threat to Piping and Equipment Integrity

extent, repairs on equipment that was insu-

lated eight, 10, 15, and sometimes 20 years

ago,” he adds. Bock, who is chair of NACE

TG 425—State of the Art in CUI Coating

Systems, was involved with updating NACE

Standard SP0198. He comments that part

of the evolution of controlling CUI is learn-

ing how well the protective coatings systems

applied in the past have survived and how

compatible they are with the better coatings

systems available today.

What is CUI?

Insulation can instigate severe corrosion

problems, such as general corrosion and pit-

ting in carbon steel (CS), and external stress

corrosion cracking (ESCC) in austenitic

and duplex stainless steel (SS). Insulation

wicks or absorbs water that enters through

breaks or degradation in the insulation

system’s weatherproofing. Once it is wet,

the insulation system’s weather barriers and

sealants trap the water inside, so the insula-

tion remains moist. Next to the equipment

surface, the insulation forms an annular

space or crevice that retains the water and

other corrosive media, conditions that are

conducive to corrosion. As corrosion occurs,

the insulation hides the resulting corrosion

damage from sight. Severe CUI has been

responsible for major equipment outages,

production losses, and unexpected mainte-

nance costs, which are reasons why CUI is

such a serious concern.

CUI of CS stems from wet metal expo-

sure over a period of time and is possible

under all types of insulation (calcium silicate

[Ca2O

4Si], expanded perlite, man-made

mineral fibers, cellular glass, organic foams,

and ceramic fiber). The corrosion rate is

affected mainly by contaminants present in

the water and the metal temperature of the

steel surface. Contaminants are generally

chlorides and sulfates from sources such as

cooling tower drift, acid rain, atmospheric

emissions that deposit on the exterior of the

insulation, and from the insulation itself.

When the insulation is wetted, contami-

nants are carried through the insulation by

the water and deposited onto the equip-

ment surface. As the water evaporates,

chloride concentrations on the CS surface

gradually increase. Industry recognizes that

CS piping or equipment operating with a

skin temperature within the range of 25 to

350 °F (–4 to 175 °C) are the most likely to

experience CUI.

In austenitic and duplex SS, ESCC

occurs when chlorides are transported by

external water through the insulation to

the hot surface of the SS, where they are

concentrated when the water evaporates.

The chloride concentration in the water

doesn’t have to be high. ESCC failures

occur when the metal skin temperature is

between 120 to 350 °F (50 to 175 °C). For

ESCC to develop, sufficient tensile stress

must be present. An increase in tempera-

ture increases the corrosion reaction and

shortens the time required for initiation

and propagation of ESCC. While ESCC

most commonly occurs beneath all types of

thermal insulation materials, the presence

of insulation is not required.

According to NACE member Tim

Hanratty, a NACE-certified CIP Level

1, Level 2, and Level 3—Peer Review

Coating Inspector and corrosion special-

ist and PetroChem business manager for

The Sherwin-Williams Co. (Cleveland,

Ohio), several factors over the years have

contributed to CUI, such as the wrong

coatings being specified, improper installa-

tion of the insulation system, and the use of

absorbent insulation materials. As water and

contaminants infiltrated the insulation, the

protective coating system was not capable

of protecting the equipment, and corrosion

and failure occurred.

The infiltration of external water can be

reduced by changes in the insulation materi-

als and the design of the equipment that is

insulated; however, some amount of water

ingress into the insulation system eventually

occurs. Also, condensation is a water source

on piping that operates below the atmo-

spheric dew point since insulation systems

aren’t vapor tight. Because attempts to pre-

vent water from entering insulated systems

are not sufficiently reliable to prevent CUI,

and corrosion protection techniques such

as inhibitors and cathodic protection have

been less effective than protective coatings

in mitigating CUI, NACE SP0198 recom-

mends the use of high-quality, immersion-

grade protective coatings as a highly effec-

tive method of protecting insulated CS and

austenitic and duplex SS from corrosion.

These barrier coatings prevent water and

contaminants from penetrating the CS or

SS substrate and initiating corrosion.

“Because water is trapped under the

insulation, CUI is treated as an immersion

condition. If the equipment is in a petro-

chemical plant, any contaminants in the

air will eventually get through the insula-

tion with the water,” Hanratty explains.

“So when we engineer a protective coating

system to solve this corrosion issue, we use

immersion-grade coatings as part of the

solution because they can withstand these

conditions. Since we can’t see CUI, it’s

critical to get the protective coating system

correct on the front end,” he emphasizes.

Hanratty, who writes specifications for

protective coatings that mitigate CUI and

participated in the NACE SP0198 review

and update process, comments that coatings

suppliers, owners, and engineering firms

in the petrochemical industry do refer to

NACE SP0198, specifically the coating

tables, when designing protective coating

systems to mitigate CUI.

Coating systems considered in the stan-

dard have a history of successful use and

include thin-film, liquid-applied coatings;

fusion-bonded coatings; metalizing or ther-

mal spray coatings; and wax-tape coatings.

Other systems also may be satisfactory. For

instance, aluminum foil wrapping may be

used to prevent ESCC of austenitic and

duplex SS under insulation.

A crucial consideration when determin-

ing the appropriate protective coating to use

under insulation is the service temperature

of the equipment or piping. The coating

should be selected based on the expected

Surface corrosion can be hidden underneath an insulation and cladding system and undetectable through visual inspections unless the insulation is removed. The exposed pipe section shows cor-rosion that occurred under the insulation. Photo courtesy of Hi-Temp Coatings Technology.


service temperature range if this range could

allow moisture to occur on the substrate

surface. This is especially true for processes

using intermittent thermal cycling. Nor-

mally the high end of a temperature range

for equipment or piping is determined

by the design temperature—the highest

possible temperature that the equipment/

piping is designed to withstand. Although

typical operating temperatures for a piece

of equipment may not run at the high end

of the temperature design, Bock explains,

spikes in temperatures due to process varia-

tions, maintenance cleaning during plant

turnarounds, etc. must be considered when

specifying a protective coating system. This

is important, he points out, because one

temperature excursion can damage a pro-

tective coating system if it is not designed to

withstand the higher temperature.

“A lot of coatings that we do use work

better at one temperature range than an-

other. One size doesn’t fit all,” Funderburg

comments.

When looking at the process tempera-

tures of insulated equipment, Hanratty

notes that 300 °F (150 °C) used to be the

norm for a process operating tempera-

ture, but new processes in refineries and

chemical plants are running at higher

TAbLE 1

Typical Protective Coating Systems for Austenitic and Duplex Stainless Steels Under Thermal

Insulation (Reprinted from NACE SP0198, pp. 22-23.)

System

Number

Temperature

Range(A),(B)

Surface

Preparation(C)

Surface Profile,

µm (mil)(D)

Prime Coat,

µm (mil)(E)

Finish Coat,

µm (mil)(E)

SS-1 –45 to 60 °C (–50 to 140 °F)

SSPC-SP 1 and abrasive blast

50–75 (2–3) High-build epoxy, 125–175 (5–7)

N/A

SS-2 –45 to 150 °C (–50 to 300 °F)


50–75 (2–3) Epoxy phenolic, 100–150 (4–6)

Epoxy phenolic, 100–150 (4–6)

SS-3 –45 to 205 °C (–50 to 400 °F)


50–75 (2–3) Epoxy novolac, 100–200 (4–8)

Epoxy novolac, 100–200 (4–8)

SS-4 –45 to 540 °C (–50 to 1,000 °F)


15–25 (0.5–1.0) Air-dried silicone or modified silicone, 37–50 (1.5–2.0)

Air-dried silicone or modified silicone, 37–50 (1.5–2.0)

SS-5 –45 to 650 °C (–50 to 1,200 °F)


40–65 (1.5–2.5) Inorganic copolymer or coatings with an inert multipolymeric matrix,(F) 100–150 (4–6)

Inorganic copolymer or coatings with an inert multipolymeric matrix,(F) 100–150 (4–6)

SS-6 –45 to 595 °C (–50 to 1,100 °F)


50–100 (2–4) Thermal-sprayed aluminum (TSA) with minimum of 99% aluminum, 250–375(10–15)

Optional: sealer with either thinned epoxy-based or silicone coating (depending on max. service temperature) at approximately 40 (1.5)

SS-7 –45 to 540 °C (–50 to 1,000 °F)

SSPC-SP 1 N/A Aluminum foil wrap with min. thickness of 64 (2.5)

N/A

(A) The temperature range shown for a coating system is that over which the coating system is designed to maintain its integrity and capability to perform as specified when correctly applied. However, the owner may determine whether any coating system is required, based on corrosion resistance of austenitic and duplex stainless steels at certain temperatures. Temperature ranges are typical for the coating system; however, specifications and coating manufacturer’s recommendations should be followed. SS-4, SS-5, SS-6, and SS-7 may be used under frequent thermal cyclic conditions in accordance with manufacturer’s recommendations.

(B) Temperature range refers to the allowable temperature capabilities of the coating system, not service temperatures. An expe-rienced metallurgist should be consulted before exposing duplex stainless steel to temperatures greater than 300 °C (572 °F).

(C) To avoid surface contamination, austenitic and duplex stainless steels shall be blasted with nonmetallic grit such as silicon carbide, garnet, or virgin aluminum oxide. Because there are no specifications for the degree of cleanliness of abrasive blasted austenitic and duplex stainless steels, the owner should state the degree of cleanliness required after abrasive blasting, if applicable, and whether existing coatings are to be totally removed or whether tightly adhering coatings are acceptable.

(D) Typical minimum and maximum surface profile is given for each substrate. Acceptable surface profile range may vary, depend-ing on substrate and type of coating. Coating manufacturer’s recommendations should be followed.

(E) Coating thicknesses are typical dry film thickness (DFT) values, but the user should always check the manufacturer’s product data sheet for recommended coating thicknesses.

(F) Consult with the coating manufacturer for actual temperature limits of these coatings.


temperatures, up to 400 °F (205 °C). “In

many specifications that we write today—

in comparison to 2004, 2005, or even

prior to that—we’re seeing that 400 °F is

more common. This higher temperature

has become the new benchmark versus

300 °F,” Hanratty says.

Changes in the

NACE CUI Standard

One of the key modifications made to

NACE SP0198 was an extensive revision

of the tables that recommend coatings

systems to protect the materials under the

insulation, says Funderburg.

These updated tables reflect the revi-

sions, which include the addition of new

protective coating system technologies,

the addition of metallic coating systems,

the elimination of outdated coating sys-

tems, and a modification of the recom-

mendation for new pipe that is primed

with an inorganic zinc (IOZ)-rich coating.

The standard recommends the surface

preparation, surface profile, and a coating

system for particular operating tempera-

ture ranges in Table 1, “Typical Protec-

tive Coating Systems for Austenitic and

Duplex Stainless Steels Under Thermal

Insulation,” and Table 2, “Typical Pro-

tective Coating Systems for Carbon Steels

Under Thermal Insulation and Fireproof-

ing,” which are reprinted in this article.

One significant change to the tables

is the addition of thermal-sprayed alu-

minum (TSA) (with a minimum of 99%

aluminum) to the coating choices, Fun-

derburg remarks. TSA coatings have per-

formed successfully in under-insulation

onshore and marine environments. “The

chemical process industries have found

that TSA gives significantly longer life

performance over traditional coatings,”

he comments.

Another significant change, observes

Bock, is the inclusion of high build, el-

evated temperature coatings introduced

in the 2000s—inorganic copolymers and

coatings with an inert multipolymeric

matrix—that can withstand higher op-

erating temperatures, up to 1,200 °F

(650 °C), depending on the product.

These coatings can be applied as very

thick films—typically 4 to 6 mils (100 to

150 µm) per coat. “These products allow

you to build a thicker barrier coat, which

provides longer life and better protec-

tion,” he notes.

Hanratty mentions that the recom-

mendation regarding bulk, shop-primed

CS pipe with an IOZ coating is another

important change to the standard. While

it is a good temporary coating for protec-

tion from mild atmospheric corrosion, an

IOZ coating is not a preferred system for

service temperatures in the CUI range

up to 350 °F. Zinc provides inadequate

corrosion resistance in closed, sometimes

wet, environments. At elevated tempera-

tures >~60 °C, the zinc may undergo a

galvanic reversal where the zinc becomes

cathodic to the CS.

“For a new project, it’s very common

in the petrochemical and refining indus-

tries to use a shop-applied IOZ coating

as a primer on all of the CS piping. It

dries extremely fast and is cost efficient,”

Hanratty comments. He explains that the

shop-primed pipe is typically purchased

in bulk for a project and then individual

pieces of pipe are finish coated at the job

site based on the service and operating

temperature where they will be used.

According to the revised standard, an

IOZ coating shall not be used by itself

under thermal insulation in a service

temperature range of 50 to 175 °C for

long-term or cyclic service. In cases where

pipe is previously primed with an IOZ

coating, it should be topcoated to extend

its life, and a coating manufacturer should

be consulted for coating thickness and

service temperature limits.

Hanratty says that industry has be-

come more aware of the underlying

causes of CUI and has taken steps to

successfully address them, such as design-

ing better insulation systems, noting the

operating temperatures of the piping and

equipment, and using NACE SP0198 as

a guide for selecting protective coating

systems. However, he adds, there are

still many pieces of equipment and pip-

ing that were insulated years ago that

may be experiencing CUI, and several

major companies have implemented a

CUI initiative within the last few years

to inspect equipment and pipe surfaces

under insulation and take any necessary

corrective action.

NACE SP0198 is available online for

downloading. For NACE members, stan-

dards can be downloaded at no cost. To

download the standard, visit the NACE

store at www.nace.org/store.

Reference

1 NACE SP0198-2010 (formerly RP0198),

“Control of Corrosion Under Thermal

Insulation and Fireproofing Materials—

A Systems Approach” (Houston, TX:

NACE International, 2010).

The thin lines of corrosion on the IOZ-coated pipe correspond to the spaces between the strips of insulation that provided a path for water to reach the equipment surface. Photo courtesy of Hi-Temp Coatings Technology.

S P E C I A L F E A T U R E Corrosion Under Insulation—The Hidden Threat to Piping and Equipment Integrity

http://www.nace.org/store


TAbLE 2

Typical Protective Coating Systems for Carbon Steels Under Thermal Insulation and Fireproofing

(Reprinted from NACE SP0198, pp. 25-26.)

System

Number

Temperature

Range(A),(B)

Surface

Preparation

Surface Profile,

µm (mil)(C)

Prime Coat,

µm (mil)(D)

Finish Coat,

µm (mil)(D)

CS-1 –45 to 60 °C (–50 to 140 °F)

NACE No. 2/ SSPC-SP 10

50–75 (2–3) High-build epoxy, 130 (5) Epoxy, 130 (5)

CS-2 (shop application only)

–45 to 60 °C (–50 to 140 °F)


50–75 (2–3) N/A Fusion-bonded epoxy (FBE), 300 (12)

CS-3 –45 to 150 °C (–50 to 300 °F)


50–75 (2–3) Epoxy phenolic, 100–150 (4–6)

Epoxy phenolic, 100–150 (4–6)

CS-4 –45 to 205 °C (–50 to 400 °F)


50–75 (2–3) Epoxy novolac or silicone hybrid, 100–200 (4–8)

Epoxy novolac or silicone hybrid, 100–200 (4–8)

CS-5 –45 to 595 °C (–50 to 1,100 °F)


50–100 (2–4) TSA, 250–375 (10–15) with minimum of 99% aluminum

Optional: Sealer with either a thinned epoxy-based or silicone coating (depending on maximum service temperature) at approximately 40 (1.5) thickness

CS-6 –45 to 650 °C (–50 to 1,200 °F)


40–65 (1.5–2.5) Inorganic copolymer or coatings with an inert multipolymeric matrix, 100–150 (4–6)

Inorganic copolymer or coatings with an inert multipolymeric matrix, 100–150 (4–6)

CS-7 60 °C (140 °F) maximum

SSPC-SP 216 or SSPC-SP 317

N/A Thin film of petrolatum or petroleum wax primer

Petrolatum or petroleum wax tape, 1–2 (40–80)

CS-8 Bulk or shop-primed pipe, coated with inorganic zinc

–45 to 400 °C (–50 to 750 °F)

Low-pressure water cleaning to 3,000 psi

(20 MPa) if necessary

N/A N/A Epoxy novolac, epoxy phenolic, silicone, modified silicone, in-organic copolymer, or a coating with an inert multipolymeric matrix, is typically applied in the field. Consult coat-ing manufacturer for thickness and service temperature limits(E)

CS-9 Carbon steel under fireproofing

Ambient NACE No. 2/ SSPC-SP 10

50–75 (2–3) Epoxy or epoxy pheno-lic, 100–150 (4–6)

Epoxy or epoxy pheno-lic, 100–150 (4–6)

CS-10 Galvanized steel under fireproofing

Ambient Galvanizing: sweep blast with fine, nonmetallic grit

25 (1) Epoxy or epoxy phenolic (for more informa-tion on coatings over galvanizing, see 4.3.3), 100–150 (4–6)

Epoxy or epoxy phenolic, 100–150 (4–6)

(A) The temperature range shown for a coating system (including thermal-cycling within this range) is that over which the coating system is designed to maintain its integrity and capability to perform as specified when correctly applied. However, the owner may determine whether any coating system is required, based on corrosion resistance of carbon steel at certain temperatures. Temperature ranges are typical for the coating system; however, not all coatings in a category are rated for the given minimum/maximum temperature. Specifications and coating manufacturer’s recommendations should be followed for a particular coating system.

(B) Temperature range refers to the allowable temperature capabilities of the coating system, not service temperatures. (C) Typical minimum and maximum surface profile is given for each substrate. Acceptable surface profile range may vary, depending

on substrate and type of coating. The coating manufacturer’s recommendations should be followed.(D) Coating thicknesses are typical DFT values, but the user should always check the manufacturer’s product data sheet for recom-

mended coating thicknesses. (E) If inorganic zinc-rich coating is applied in a shop and topcoat is applied in the field, proper cleaning of the inorganic zinc-rich

coating is required. The use of inorganic zinc-rich coating under insulation is not a preferred system for service temperatures in the CUI range up to approximately 175 °C (350 °F). However, bulk piping is often coated with inorganic zinc-rich coating in the shop and some owners purchase this piping for use under insulation. In these cases, the inorganic zinc-rich coating should be topcoated to extend its life.


Improvements to the External

Corrosion Direct Assessment

Process—Part 2DaviD H. Kroon, olagoKe olabisi, larry g. ranKin,

James T. Carroll, Dale D. linDemuTH, anD marlane l. miller,

Corrpro Companies, Inc., Houston, Texas

Te U.S. Department of Transportation Pipeline

& Hazardous Materials Safety Administration

sponsored a research project for the external

corrosion direct assessment process for buried

pipelines. Part 1 of this article (March 2011 MP)

addressed methodologies for cased pipe.

Part 2 covers severity ranking of indirect

inspection indications and potential

measurements in paved areas.

Astudy sponsored by the U.S.

Department of Transpor tation

Pipeline & Hazardous Materials

Safety Administration (PHMSA)

was conducted to determine the applica-

bility of existing and emerging technolo-

gies to assess buried pipelines for external

corrosion using external corrosion direct

assessment (ECDA). This included ex-

amination of existing ECDA processes,

best practices of pipeline operators, and

emerging technologies. The project find-

ings are significant for gas transmission

pipeline operators in the United States

because the integrity of all pipe in high-

consequence areas (HCAs) must be as-

sessed by December 17, 2012, including

those segments of pipe in casings. There

is an industry need for a methodology to

assess cased pipe where in-line inspection

(ILI) and pressure testing are either not

possible or not practical.

Severity RankingThe purpose of the severity ranking

portion of the study was to enhance the

existing Tables 3 and 4 in NACE SP0502-

2010.1 The existing tables in the standard

are very general, which result in varying

interpretations and inconsistencies in ap-

plication under the current practice. The

project goals were to identify improve-

ments that could be made and develop an

enhanced severity ranking methodology.

Data from five transmission and dis-

tribution system operators were com-

piled, sorted, and analyzed. This included

the results of 400 direct examinations

with complete, applicable data sets, in-

cluding soil analysis. Fifty percent (200)

of the data sets used in the study demon-

strated measurable external corrosion.

ILI data were also analyzed, which cov-

ered 14,000 joints of pipe where close

interval potential surveys (CIPS) and al-

ternating current attenuation (ACCA)

surveys had been performed. These data

included 4,000 joints of pipe with measur-

able corrosion and 100 excavations. To


C A T H O D I C P R O T E C T I O N

TAbLE 1

Enhanced severity classification criteria of indirect inspections (IDI)

(Modification of Table 3 in NACE SP0502-2010)

Measure Minor Moderate Severe

IDI Tool = Close Interval Potential Survey

A = Off (polarized) potential (mV)

–950 mV < A < –850 mV –850 mV < A < –650 mV –650 mV < A

OR OR AND

B = On potential (mV) –1,000 mV < B < –950 mV –950 mV < B < –850 mV –850 mV < B

AND AND AND

C = On/off convergence (mV) 50 mV < C < 70 mV 30 mV < C < 10 mV 10 mV < C

OR OR AND

D = On and/or off profile depression within 100 ft (30.5 m) (mV/span)

50 mV/span < D < 100 mg/span 100 mV/span < D < 200 mV/span 200 mV/span < D

IDI Tool = AC Current Attenuation

E = Current 98 Hz frequency signal loss (–)(mdB[mA]/ft)

7 mdb(mA)/ft < E < 3 mdb/ft 12 mdb(mA)/ft < E < 7 mdb(mA)/ft 12 mdb(mA)/ft < E

AND/OR AND/OR AND/OR

F = Current 4 Hz frequencysignal loss (–) (mdB[mA]/ft)

20 mdb(mA)/ft < F < 40 mdb(mA)/ft 40 mdb(mA)/ft < F < 60 mdb(mA)/ft 60 mdb(mA)/ft < F

AND AND OR

CP level modifier Adequate CP level Adequate to marginalCP level

All indications with inadequate CP level

IDI Tool = AC Voltage Gradient

G = Voltage signal loss (–)(dB[mV])

44 dB(mV) < G < 60 dB(mV) 60 dB(mV) < G < 78 dB(mV) 78 dB(mV) < G

AND AND OR

CP level modifier Adequate CP Adequate to marginal CP level All indications with inadequate CP

IDI Tool = DC Voltage Gradient

H = coating defect size (%IR) 5%IR < H < 20%IR 20%IR < H < 50%IR 50%IR < H

AND OR OR

I = Corrosion stateassessment (normaloperating conditions)

I = Cathodic/cathodic orcathodic/neutral

All indications 5%IR < H < 50%IRwhere I = cathodic/anodic

All indicationswhere I = anodic/anodic

AND AND OR

CP level modifier Adequate CP level Adequate to marginalCP level

All indications with inadequate CP level

IDI Tool Modifier—USDA Soils Data—Soil Texture Designation (Not an Independent Tool)

J = USDA soil texturedesignation (12 types)

J = Sand, loamy sand, sandy loam, loam, silt loam, or silt

J = Sandy clay loam, sandy clay, clay loam, silty clay loam

J = Clay and silty clay

AND AND OR

CP level modifier Adequate CP Adequate to marginal CP level All area with inadequate CP

IDI Classification


C A T H O D I C P R O T E C T I O N Improvements to the External Corrosion Direct Assessment Process—Part 2

the severity ranking as defined by the

numerical ranges. This, of course, is con-

sistent with what we have all observed,

but have only been loosely able to tie to

specific soil properties such as soil resistiv-

ity, pH, active ion concentration, and

moisture content. A broader character-

ization of soil “texture” was postulated to

provide a better indicator of corrosive

conditions. This correlation was investi-

gated using the U.S. Department of

Agriculture (USDA) Web Soil Survey,2

which provides significant detail regard-

ing soil texture and physical/chemical

properties across the United States. It has

the additional advantage of being easily

accessible on the Internet and free for

anyone to use. The investigation con-

cluded that percent clay content (ex-

pressed as a percentage of total composi-

tion) was a parameter that correlated with

the presence of external pipeline corro-

sion. Data from the 14,000 joints of pipe

(4,000 with measurable external corro-

sion) representing 188 soil types were

plotted (Figure 1).

The data were then further analyzed

by ranking the leak and rupture hazards

as a percent of clay for the data set. The

threat of leaks was indicated by wall loss

while the threat of rupture was expressed

as rupture pressure ratio. The data clearly

illustrated that as the percent clay in the

soil increases, so does the threat of both

rupture and leak. A soil modifier was then

applied to the Severity Classification

Criteria of Indirect Inspections and the

Prioritization Criteria for Indirect Inspec-

tion Indications as shown on the bottom

of Table 1 and on the left side of Table

2, respectively.

Conclusions Concerning Severity Ranking

Improved tables for Severity Classifi-

cation and Prioritization Criteria for In-

direct Inspection Indications were devel-

oped, which provide a more consistent

assessment of the external corrosion

threat.

Observed corrosion by soil texture.

capture best current industry practices,

this phase of the project was discussed

with 10 qualified and experienced opera-

tor and service provider professionals with

a total of over 300 years of experience.

In developing improvements to Tables

3 and 4 in NACE SP0502-2010, specific,

numerical criteria were developed, which

covered a wide range of definable condi-

tions. The work included analysis of

rupture pressure ratio (RPR) and percent

wall loss relative to abovegrade measure-

ments at individual IDI indications. The

enhancement of existing Tables 3 and 4

appear as Tables 1 and 2 herein.

During the course of evaluating soil

data at IDI indications, it was noticed that

soil conditions appeared to correlate with

FIguRE 1

TAbLE 2

Enhanced prioritization criteria for indirect inspection

indications (Modification of Table 4 in NACE SP0502-2010)

USDA Soil

Texture

Modifier

IDI Tool 2

Classification Severe Moderate Minor

Severe Severe Immediate Immediate Scheduled

Severe Moderate Immediate Scheduled Scheduled

Severe Minor Scheduled Scheduled Monitored

Moderate Severe Immediate Scheduled Scheduled

Moderate Moderate Scheduled Scheduled Monitored

Moderate Minor Monitored Monitored Monitored

Minor Severe Immediate Scheduled Monitored

Minor Moderate Scheduled Monitored Monitored

Minor Minor Monitored Monitored Monitored

Prioritization: Two Tools with Soil Modifier

IDI Tool 1 Classification



Methodologies developed represent

an enhancement to NACE SP0502-2010

for quantification and qualification of IDI

indications, effective use of available soils

data, and introduction of a soil texture

modifier.

The new methodologies quantified and

verified both the project research data and

industry knowledge and experience.

Potentials in Paved Areas

Current industry practices for collect-

ing potential measurements in paved

areas are to drill through the pavement,

collect potentials offset from the location

of the pipeline, surface wetting, or simply

skipping data collection in paved areas.

The purpose of the potentials in the

paved areas portion of the project was to

develop a methodology to collect more

FIguRE 2

FIguRE 3

Large-scale lab testing of potentials in paved areas: (a) steel plate electrode and (b) copper/copper sulfate (Cu/CuSO4)

electrode.

(a)

(b)

Asphalt resistance measurements.



P/S potential measurements on weathered asphalt.

reliable data in a more user friendly, ef-

ficient, and safe manner. The goal was

for the methodology to be applicable to

both transmission and distribution sys-

tems, and ultimately to provide for more

data collection in paved areas, thereby

enhancing pipeline integrity assessment.

We considered gravel, asphalt, and

concrete surfaces. Variability in thick-

ness, aggregate, sub-base, and construc-

tion yields a nearly infinite number of

conditions. If basic electrical measure-

ments could characterize a pavement,

then decisions and guidelines could be

developed regarding the validity of po-

tential measurements with reference

electrode placement on the pavement. As

the research progressed, this postulation

was tested and refined. The result was a

simple test procedure that can be used at

the onset of a potential survey to deter-

mine if on-paving measurements can be

made accurately.

The research approach consisted of

reviewing prior work, running large-scale

laboratory tests as illustrated in Figure 2,

and collecting field data on operating

distribution and transmission pipelines.

Resistance measurements to character-

ize the pavement were made using a digi-

tal meg-ohmmeter having a maximum

1,000-V direct current (DC) source spe-

cifically manufactured for high-resistance

circuits. Most measurements were made

with one terminal of the meg-ohmmeter

connected to an 8- by 8-in (203- by 203-

mm) metal plate electrode on the paved

surface and the other terminal connected

to a nearby electrical ground used as an

earth electrode. No surface wetting was

done for these measurements, other than

to use a damp towel directly under the

metal plate electrode. Figure 3 shows sur-

face resistance values for asphalt pavement

with and without visible cracking.

Many CIS surveys were performed in

the field that compared current on and

instant-off pipe-to-soil (P/S) potential

measurements with the cell placed on dry

pavement, wet pavement, or in drilled

holes through the pavement. Figure 4

contains results from a survey on weath-

ered asphalt where the pavement contact

resistance was 2 × 108 Ω{ft2 measured as

described above. The data on drilled

holes are consistently accurate, whereas

there are great inaccuracies in the data

on the asphalt surface as evidenced by the

extreme data scatter in both the positive

and negative directions.

Figure 5 shows data collected on con-

crete pavement. Using the data from the

drilled holes as the basis, potentials on

FIguRE 4


pavement were first more positive and

then became more negative as the survey

progressed down the pipeline. This was

the case even though the pavement con-

tact resistance was a very low 100 Ω{ft2.

For gravel and asphalt, a procedure

has been developed for measurement of

the resistance through the pavement us-

ing a metallic electrode on the paved

surface and a MΩ resistance meter. Fig-

ure 6 shows the correlation between ac-

curate P/S potential data and the surface

resistance measurement for 61 surveys on

asphalt pavement. Based on analysis of

the data collected, a threshold normalized

resistance of 2 × 105 Ω{ft2 has been estab-

lished. That is, when gravel or asphalt

paving exhibits a resistance of 200,000

Ω{ft2 or less, a reliable potential measure-

ment can be made with the reference

electrode on the pavement.

For concrete pavement, the research

concludes there is no clear, consistent

method for making reliable P/S potential

measurements without placing the refer-

ence electrode in direct contact with the

underlying soil (e.g., by drilling holes

through the pavement). P/S potentials

with the reference electrode on a concrete

surface are either more negative or more

positive than when in contact with the

underlying soil. While P/S potential

measurements are not valid with a refer-

ence electrode on the concrete pavement,

DCVG measurements may be.

Conclusions Concerning Potentials in Paved Areas

• For gravel and asphalt pavement:

C A simple, straightforward, pre-

survey surface resistance mea-

surement can be used to deter-

mine if potentials recorded with

the reference electrode placed on

the pavement will provide accu-

rate data.

C A threshold of 200,000 Ω{ft2 has

been identified, below which

potentials on pavement demon-

strated accuracy.

C A standard, 3-in (76-mm) diam-

eter reference electrode with

a wetted towel or sponge is

adequate to minimize contact

resistance.

• For concrete pavement:

C No clear, consistent method for

recording accurate potential mea-

surements on concrete pavement

was identified except by drilling

holes through the pavement to

facilitate reference electrode con-

tact with the underlying soil.

P/S potential measurements on weathered concrete.


FIguRE 5


Surface resistance threshold for asphalt.


FIguRE 6

AcknowledgmentsWe would like to acknowledge the

PHMSA funding and support for this

work, and the contribution of time and

effort from our team members El Paso,

ExxonMobil, Southern Union, and the

Texas Gas Association.

References

1 NACE SP0502-2010, “Pipeline External Corrosion Direct Assessment Methodology” (Houston, TX: NACE International, 2010).

2 U.S. Department of Agriculture Web Soil Survey, http://websoilsurvey.nrcs.usda.gov/app/HomePage.htm.

Bibliography

Carroll, J., D. Kroon, D. Lindemuth, M. Miller, O. Olabisi, L. Rankin. “PHMSA-Sponsored Research: Improvements to ECDA Process— Severity Ranking.” CORROSION 2010, paper no. 10054. Houston, TX: NACE, 2010.

“External Corrosion Probability Assessment for Carrier Pipes Inside Casings (Casing Corrosion Direct Assessment—CCDA).” GRI-05/0020. Des Plaines, IL: Gas Technology Institute.

Lindemuth, D., D. Kroon, J. Carroll, M. Miller, O. Olabisi, L. Rankin. “PHMSA-Sponsored Research: Improvements to ECDA Process— Potential Measurements in Paved Areas.” CORROSION 2010, paper no. 10055. Houston, TX: NACE, 2010.

NACE SP0200-2008. “Steel-Cased Pipeline Practices.” Houston, TX: NACE 2008.

Rankin, L., J. Carroll, D. Kroon, D. Lindemuth, M. Miller, O. Olabisi. “PHMSA-Sponsored Research: Improvements to ECDA Process— Cased Pipes.” CORROSION 2010, paper no. 10056. Houston, TX: NACE, 2010.

USDA Natural Resources Conservation Service. http://websoilsurvey.nrcs.usda.gov/app/HomePage.htm., 2009.

DAVID H. KROON is executive vice president and chief engineer at Corrpro Companies, Inc., 7000B Hollister, Houston, TX 77040. He graduated from Yale University with a B.S. degree in chemistry and is a registered Professional Engineer in 10 states. He has 40 years of experience in corrosion prevention, including materials performance, protective coatings, pipeline integrity, CP, and AC/DC interference mitigation. Over his entire career, he has been actively engaged in pipeline assessments for energy companies. He is a 39-year member of NACE.

OLAGOKE OLABISI is the director of Internal Corrosion Engineering at Corrpro Companies, Inc., e-mail: [email protected]. He is a NACE- certified Chemical Treatment Specialist and is experienced in materials engineering, corrosion control, root cause analysis, materials selection, nonmetallic materials, CP, specifications, and standards. He has worked in the Consulting Services Department at Saudi Aramco, Research and Development Department at Union Carbide Corp., and the Ceramics Division at Oak Ridge National Laboratory. He also has academic experience as a professor of chemical engineering and dean of engineering prior to joining Corrpro.

http://websoilsurvey.nrcs.usda.gov/app/HomePage.htm





www.tinker-rasor.com

[email protected]

www.edi-cp.com

LARRY G. RANKIN is director, Pipeline Integrity at Corrpro Companies, Inc., e-mail: [email protected]. He has 35 years of experience in the pipeline and corrosion control industries, including pipeline integrity management, operational reliability assessment, rehabilitation and service conver-sions, inline inspection, and direct assessment. He has a B.S.E.E. degree from Louisiana Tech University and is a NACE-certified CP Specialist. He is a 35-year member of NACE.

JAMES T. CARROLL is a project manager at Corrpro Companies, Inc., e-mail: [email protected]. A 10-year member of NACE, he has worked in the CP and pipeline integrity fields for 30 years with both service providers and operators.


DALE D. LINDEMUTH is the director of engineering at Corrpro Companies, Inc., e-mail: [email protected]. He has a B.S. degree in electrical engineering and is a NACE-certified Corrosion Specialist and CP Specialist. He has 32 years of corrosion control experience with emphasis in the regulated pipeline and water/wastewater industries, including AC and DC interference mitigation, CP, and integrity assessments. He is a 32-year member of NACE.

MARLANE L. MILLER is an engineer at Corrpro Companies, Inc. She is a 2005 graduate of Texas A&M University with a B.S. degree in industrial distribution. She has five years of experience in the corrosion prevention industry, primarily with pipeline integrity, CP, and AC and DC interference mitigation. A five-year member of NACE, she is a NACE-certified CP Technician.

http://www.tinker-rasor.com


http://www.edi-cp.com





www.irtrectifier.com

Continued from The MP Blog, p. 11.

The following items relate to cathodic &

anodic protection.

Please be advised that the items are

not peer-reviewed, and opinions and

suggestions are entirely those of the in-

quirers and respondents. NACE Interna-

tional does not guarantee the accuracy

of the technical solutions discussed.

MP welcomes additional responses to

these items. They may be edited for

clarity.

Offshore structure cathodic protection

QWhat surface area al-

lowance or current

a l lowance do you

make in your cathodic

protection (CP) design calcu-

lation for driven steel piles on

offshore structures? Can you also

provide the basis of your allowance?

AI use 0.025 A/m2 for the buried

portion down to a maximum

depth of 30 m below the mud

line. I don’t know the basis for

this figure. Well casings get a blanket 3 A

per well.

AIt depends on the type of sheet

piling. For Larssen Type 4 piles,

I normally use a surface factor

of 1.6. This corresponds very

well with the real geometry of the pile.

Morgan states: “The actual area of the

metal is 50% or more greater than the

frontal area.” In general, I think that a

factor between 1.5 and 1.7 should cover

any additional surface area because of

geometry.

AUse NACE standard SP0176-

2007, “Corrosion Control of

Submerged Areas of Perma-

nently Installed Steel Offshore

Structures Associated with Petroleum

Production.”

AMy experience with offshore

structures has been designing the

systems based on 0.1 mA/ft2

(1.1 mA/m2). This design basis is

adequate once your structure has been

polarized. If you are considering an im-

pressed current system, applying the

initial high current density should not be

a problem. For galvanic systems such as

zinc or aluminum anodes, I strongly rec-

ommend the use of magnesium ribbon

anodes (for rapid polarization)—which of

course will deplete in a short time and

then your designed galvanic system will

take over.

Breakdown voltage in mixed metal oxide anode

QIt has been reported

that breakdown of

mixed metal oxide

(MMO) anodes may

occur at 50 to 60 V in low-

chloride concentration water

but at only 10 V in chloride-

rich environments. What is the

meaning of the voltage here? Does any-

one have experience in breakdown and

failure of a MMO anode system for this

reason?

AI don’t think you mean break

down the voltage of MMO, but

its substrate. In a chloride envi-

ronment, titanium oxide film

breaks down between 8 to 12 V measured

at the interface of anode to electrolyte

while the nobium substrate can be oper-

ated at 100 V without breakdown of

nobium oxide film.

AI have seen platinized titanium

anode fai lure in seawater.

Whether MMO or platinum, the

breakdown voltage that we refer

to is the oxide coating on the base metal.

Titanium or nobium, when used as base

metal, forms an oxide coating where the

base metal gets exposed. This coating

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mesaproducts.com


prevents current discharge from the base

metal and prevents anode failure. If you

are using a MMO anode with a titanium

base metal, the oxide protective film that

forms on the titanium will remain intact

as long as the voltage between the anode

and the electrolyte is kept under 12 V.

When the titanium oxide film breaks

down, the base metal begins to corrode

and the anode fails, not because the

MMO has been consumed but because

of the failure of the titanium base metal.

If the base metal is nobium instead of ti-

tanium, the nobium oxide film can with-

stand up to 100 V across the anode-

electrolyte interface before the oxide film

breaks down.

Titanium ribbon anodes

in reinforced concrete

QI am installing ca-

thodic protection (CP)

on new concrete struc-

tures. We are using

mixed metal oxide (MMO)

coated titanium ribbons as

anodes. We utilize plastic spacer clips

to fasten the ribbon that is spaced ~20 to

50 mm from the rebar. There is a sepa-

rate anode ribbon system designed for

each rebar layer. For example, on a 1-m

thick wall, there are two layers of anodes

installed—one on each face of the rebar

layer. The structure has state-of-the-art

monitoring and a distributed current

system installed with alarms, etc.

Is it better to install the anode ribbon

on the outside or inside the rebar cage?

It’s easier to handle such an installation

if installed within the rebar cage because

the concrete placement poses lesser threat

to the anode ribbons. Also, form work can

be conducted without taking extensive

precautions because heavy form work has

the potential of damaging the ribbons.

The contractor is happy with the contract

specifications that do not specify the loca-

tion of the ribbons. But I wonder if it will

work the same either way.

Because the rebars are bare steel

placed in the electrolyte (concrete), which

will be exposed to seawater on one side

and a chloride-rich, wet and sandy envi-

ronment on the other, the protective cur-

rent will be absorbed by the rebar. Upon

energizing the impressed current CP

(ICCP) system, more current will head

to the face of the rebar directly in front

of the ribbons. Eventually, this would

change when polarization is achieved at

those particular areas and more current

flow gradually would divert to areas away

from the ribbons (i.e., the outer surface

of the rebar).

All rebars are tested and verified

for electrical continuity. Silver/silver

chloride (Ag/AgCl) reference electrodes

are installed on the outer side of the

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[email protected]

C P B L O G


rebar cage as a permanent installation

with their own instrument negative con-

nections. The design allows 5 mA/m2

for atmospheric zones. The number of

ribbons depends on the current require-

ment of the substrate (rebar); the ribbons

therefore are placed 250 mm apart in this

particular example. Electrical isolation of

these ribbons from the rebar is a priority

before and during concrete placement.

The term “rebar cage” is for two layers

of reinforcement placed ~1 m apart and

thus forming a cage, while the wall is

~1.6 m.

AI’m not a CP practitioner, so

can’t speak from experience, but

on a “first principles” analysis I

would try to avoid having the

anodes inside the cage. As well as supply-

ing the protective current to the rebar,

the anode is attracting chloride and gen-

erating acidity. With the anode outside

the cage, this moves chloride back toward

the surface of the slab, where it will come

into equilibrium with the chloride diffus-

ing in from the seawater or ground water,

and then chloride content next to the

rebar will stay relatively low. If the anode

is inside the rebar cage, the chloride will

be pulled into the slab (in the same direc-

tion as the inward diffusion); it will ac-

cumulate in the center of the slab and

could get relatively high next to the rebar.

AMany ICCP systems are built

into new structures in Italy

(where it was named cathodic

prevention), some are in the

United States, and increasing numbers

are in the Middle East. Most install rib-

bon anodes behind the outer steel for

practical reasons, even though this at-

tracts chlorides into the concrete to the

anodes. European standard EN 12696

Annex B, paragraph 4 states that the cur-

rent density needed for “cathodic preven-

tion” is 0.2 to 2 mA/m2, with “post cor-

rosion” CP requiring 20 mA/m2 (of steel

surface in both cases). Therefore, assum-

ing your new structure starts with passive

steel in a nonchloride environment, you

are merely setting up an electric field to

stop the chlorides from “touching” the

steel.

There was a case given in a paper by

Chaudhary at the 2003 NACE annual

conference, however, where higher cur-

rents were required. During discussions

it became apparent that the concrete

mix and steel surface may have started

with chloride contamination, but this

was not confirmed. At the 2004 NACE

conference, Glass gave a paper on how

little current is required to cathodically

protect steel and why. The current may

flow initially to the side of the bar away

from the chlorides and toward the anode,

but that side will polarize, increasing the

resistance. The current will flow on the

areas under chloride attack because the

interface has a lower resistance. It is this

electrochemical effect that allows us to

protect large areas from small anodes

without all the current being consumed

close to the anode.

One last point: I do hope your rigorous

checking includes ensuring no electrical

contact between anode and steel before,

during, and after pouring—and not just

continuity between rebars. My experi-

ence is that it is very difficult to ensure

separation in practice, and anode and

rebar must not touch or it is all a waste of

time and money. So to summarize:

• The ideal location for the anodes is

on the surface, drawing chlorides

out, not in.

• The practicalities of construction

are that it is easier to have them

behind the steel.

• Assuming reasonable construction

practices (negligible chloride con-

tamination), the current should be

low so that the amount of chloride

drawn in should be modest but will

accumulate with time.

• It is important that the system is

adequately maintained through-

out its life because, if the current

stops, chlorides will accumulate at

the anode and diffuse toward the

rebar.

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http://www.anotec.com



Redefining Antifouling

Coating Technology—

Part 1Diego Meseguer Yebra, Fouling Control Denmark, Lyngby, Denmark

Pere CatalÀ, Fouling Control Spain, Polinyà, Spain

After tin-based technology was abandoned in 2001,

economic and environmental factors have

necessitated higher energy efficiency in marine

transportation, much of which depends on the

performance of antifouling coatings. Tis three-part

article lists some of these factors and presents the

most recent antifouling products. Part 1 introduces

the subject; further details will be covered in Parts 2

and 3 (May and June 2011 MP).

Excluding ship and propulsion

system design, few other param-

eters influence a ship’s overall

energy efficiency as much as anti

fouling (AF) systems for the underwater

hull. The colonization of ship bottoms by

sessile species has a widely acknowledged

negative impact on the vessel’s hydrody-

namics.12 In this respect, AF coatings

have a major role in keeping the frictional

resistance of vessels as close as possible to

newly built levels.2 Frictional resistance

dramatically impacts the vessel’s fuel

consumption (Table 1) as well as its ex-

haust gas (carbon dioxide [CO2], nitro-

gen oxide [NOx], and sulfur oxide [SO

x],

and particulate matter) emissions to the

atmosphere

The equivalent average hull roughness

values (Rt50

) for different fouling scenarios

provided by Schultz1 were converted into

friction coefficient values using the Inter-

national Towing Tank Conference equa-

tions, extrapolated into estimated in-

creases in fullscale powering based on

proprietary data from extensive ship

model testing. As Table 1 indicates, the

presence of seaweed on a ship’s hull may

increase the fuel consumption by up to

50%, significantly more than the benefits

offered by optimization of rudder or

propeller designs or even over the use of

propulsion aid systems such as towing

kites. In spite of this, it is surprising to note

that AF coatings and their influence on

ship performance have attracted very

limited attention in past decades. Evi-

dence of this statement is that topper-

forming tinfree selfpolishing copolymer

(SPC) AF paints are not dominating the

market, with a significant amount of own-

ers preferring to cut down on dry docking

costs by choosing less expensive AF prod-

ucts. According to a press release in June

2010,3 this decision could mean over 5%

increased fuel costs. This scenario is prob-

ably the result of several historical factors:

• The traditional use of lowpriced,

highly efficient and toxic organotin


C O A T I N G S & L I N I N G S

based coatings, which largely dom-

inated the market until their aban-

donment by the major marine paint

producers in 20014

• The lack of biocide registration

schemes, which has allowed eco-

nomical biocides to be placed in the

market worldwide without extensive

studies about their environmental

profile and effectiveness5

• Lack of reliable studies linking AF

performance to fuel consumption

• The scarcity of reliable performance

monitoring systems, which can be

used to assess the value of investing

in high-performance AF systems2

• The relatively low cost of heavy

bunker fuel

The increase in crude oil prices in

2004-2009 and more recently, the global

financial crisis, has triggered alarms in the

maritime industry. Ship owners and op-

erators have been forced to maximize

profitability by setting up strict fuel-saving

policies (e.g., slow steaming), reevaluating

the choice of AF products and suppliers

and, when necessary, laying up vessels.

Such an alarm coincided with the rising

concern about the climate change, which

also hit the maritime industry, as demon-

strated by the MEPC 60/4/21 document

and by International Marine Organiza-

tion (IMO) guides to set up Ship Energy

Efficiency Management Plans.6 In addi-

tion to greenhouse gases, other harmful

emissions from low-grade bunker fuel are

also in the spotlight. The MEPC.176(58)7

resolution highlights the need to reduce

SOx, NO

x, and particulate matter, which

will certainly result in increased operating

costs for the maritime industry.

It is unarguable that using improved

AF systems strongly contributes to mini-

mizing fuel costs and exhaust gas emission

rates. Furthermore, a shift to high-perfor-

mance AF products would also mitigate

the risk of introducing invasive species into

sensitive ecosystems,8 an escalating prob-

lem already acknowledged by IMO. Tak-

ing these facts into consideration, it seems

clear that as the marine market progres-

sively recovers from the economic down-

turn, optimized efficiency and minimized

environmental impact will remain a top

concern to a much larger extent than ever

before in the history of shipping.

Self-Polishing, Biocide-Based Paint Technologies

Many tin-free technologies commer-

cially available today were already avail-

able before the review by Yebra, et al.,4

and they have been optimized in cost and

performance since then. Table 2 reviews

new high-performance products; those

systems that have been launched (or re-

launched with significant improvements)

since 2004 are marked in bold. Products

represented from six companies and

designated Products A through N include

(in order) the SeaQuantum† range,

Seamate†, Intersmooth 460-465†, Inter-

smooth 7460HS †, Sea Grandprix

1000/2000†, Sea Grandprix 660 HS CF-

10† (copper free), SylAdvance 800†, Eco-

Fleet 530†, Alphagen 230/240†, SeaCare

Plus A/F 850†, SeaCare A/F 795†,

Dynamic†, Globic NCT†, and Oceanic†.

Note that some of them can also be

specified for dry-docking intervals of up

to 90 months.

Table 2 shows that silylated acrylate

(SA)-based products are already being

offered by most paint manufacturers,

with several new products launched in

recent years. Two companies already had

SA products at the time of the organotin

abandonment by the major paint suppli-

ers in 2001, but have enlarged their lines

with new products over the past years. In

the early 2000s, one company developed

TAbLE 1

Hull condition effects

Hull Condition %∆ST

Newly applied applied AF coating —

Old system or thin slime 9.4

Thick slime 26.8

Algae and small-size shell fouling 50.7

Medium-size shell fouling 82.3

Estimated effect of different hull conditions on the total shaft power (ST) for the case of a 7,000 TEU container ship.

†Trade name.

TAbLE 2

AF paint systems

Product(A) Description Global Launch Date

A SA 2000

B SA 2008

C Copper acrylate First versions 1994

D Higher solids version 2008

E SA(B) 1995

F Advanced fusion zinc acrylate ionomer 1995

G SA 2009

H Unknown 2009

I Pure organic SA 2009

J SA

K SA

L Fiber-reinforced SA 2002 (first version)

M Fiber-reinforced NanoCapsule Technology 2006

N Fiber-reinforced zinc carboxylate 2000

(A)Products are defined in the article text.(B)Different SA polymer from other suppliers. Review of the most important 60-month AF paint systems on the market together with the binder technology and the launch date (when known).Note: Systems that have been launched or relaunched with significant improvements are marked in bold.


Redefining Antifouling Coating Technology—Part 1C O A T I N G S & L I N I N G S

a new binder (nanocapsule) technology9

as an improvement to its first 60-month

tin-free product family. This product of-

fers excellent fouling protection for dry-

docking periods of up to 60 months. To

meet the rising demand for products

reaching the 90-month dry-docking in-

terval, this company has recently rede-

signed its silylated acrylate assortment

including new product features and re-

launched it.

The clear trend toward the expansion

of SA products may be partly encouraged †Trade name.

Polishing effects on SA technology, (a) stable dry film thickness (DFT) decreases (polishing) during testing; (b) the paint condition on a container ship after two years in operation; (c) cross-section of a three-year-old paint system taken from a ship showing a very even polishing pattern and almost no leached layer.4,10,14

(a)(b)

(c)

TAbLE 3

Results of dynamic exposure test

Handysurf, Rz (µm) Interferometry, R

a (µm)

SA 5.82 ± 0.08 0.92 ± 0.1

Cu-acrylate 12.45 ± 0.60 1.88 ± 0.2

Relative increase 114.0% 104.3%

Ten-point roughness (Rz) and the arithmetical mean roughness (R

a) values for commercial SA

(left) and pure copper acrylate (right) after the dynamic exposure test.10 The copper acrylate surface is >100% more rough than the SA one.

by the decision of some major perfor-

mance-oriented customers to shift to SA

products aimed at optimized and reliable

performance and reduced fuel bills, espe-

cially for those vessels that are permitted

to trade for up to 90 months without dry-

docking. This conclusion was reached

after analyzing hundreds of tin-free per-

formance (torsiometer) data gathered

throughout their fleets, showing that SA

products comprised the tin-free technol-

ogy best suited to work beyond 60-month

dry-docking intervals. The SA technology

definitely shows a very constant and pre-

dictable polishing rate and very thin

leached layers.

In Figure 1(b), the second AF layer

(brown) is starting to show up from polishing

through of the first layer (red), which re-

mains only at high paint thickness areas

(spray overlapping) and on areas that are

frequently out of the water (vessel unloaded).

SA paints also show a smoother sur-

face during service. Panels coated with a

commercial SA paint and with a pure

copper acrylate-based product were ex-

posed to dynamic testing in natural

seawater as described by Sanchez and

Yebra.10 After more than 20,000 NM

(peripheral speed), the panels were with-

drawn and slime was carefully removed

by freshwater rinsing to ensure no ero-

sion of the paint. The micro-roughness

of the panels was analyzed by means of

a Handysurf E-3509†,11 and also by 3D

White Light Interferometry (MicroXAM

100HR ex. ADE Phase Shift Technol-

ogy/KLA Tencor†). Table 3 shows the

results.

It is not clear whether the SA technol-

ogy will achieve the same levels of market

share as tin-based coatings, even though

its advantages compared to some other

advanced tin-free technologies are obvi-

ous only after long operating periods. In

spite of this, one company still questions

whether the SA technology should right-

eously be termed “self-polishing,” a term

usually linked to top performance. Ac-

cording to Yebra, et al.,4 the discussion

on what a “true self-polishing” copolymer

paint is should be based on the final paint

performance and not so much on the

binder chemistry. In this respect, it would

not be surprising if all major marine paint

manufacturers will soon position a SA

product at the top of their lines. Other

authors, such as Finnie and Williams,12

prefer to classify the different technolo-

gies based on some chemical and formu-

lation criteria, largely regardless of the

FIguRE 1


C O A T I N G S & L I N I N G S

paint performance. If we follow their

definition strictly, a SPC could very well

perform worse than what they called

“controlled depletion polymer” (CDP)

technology.

An example of the chemistry-perfor-

mance mismatch is the well-known sen-

sitivity of copper acrylate technology with

respect to immersion in fresh water,

compared to the stability of TBT-SPCs

and SA products (Risberg, et al.13).

Table 4 reviews the chemistry of the

main candidates to the “true self-polish-

ing” position. All resins have both strong

similarities and significant differences to

the TBT-SPC chemistry. Note that no

matter how simple this classification is

made, it would be a mistake to forget that

the main SP resin is only part of the full

formulation, and that other co-binders,

Panel condition after cyclic blister box test. No failures were observed in the fiber-reinforced coating, whereas comparable commercial products showed severe cracking.

TAbLE 4

Chemistry of primary antifouling technologies

Technology Name Initial Chemistry Final Chemistry Notes

Tributyltin methacrylatecopolymer

TBT-SPC Sodium acrylate copolymer

Covalent bond. Kinetically controlled hydrolysis. Biocidal pendant group. Can be formulated without rosin-derivatives.

Triisopropyl SA SA Sodium acrylate copolymer

Covalent bond. Kinetically controlled hydrolysis. Non-biocidal pendant group. Poor properties without rosin-derivatives.

Non-aqueous methacrylicacid copolymer dispersion

Nanocapsule Sodium acrylate copolymer

Diffusion controlled hydrolysis. Non-biocidal pendant group. Poor properties without rosin-derivatives.

Acrylate bearing a coppersalt of a monobasic organic acid

Copper acrylate

Sodium acrylate copolymer

Ionic bond. Ion exchange-type reaction. Non-biocidal pendant group. Can be formulated without rosin-derivatives.

Main 60-month antifouling technologies with their initial chemistry and description. This table highlights that all these chemistries lead to the formation of sodium acrylate salts attained through different reaction mechanisms and kinetics.

FIguRE 2


Redefining Antifouling Coating Technology—Part 1C O A T I N G S & L I N I N G S

pigments, and biocide packages also play

a key role in the final performance.

The fiber-reinforced silylated coating

series can be used as another example of

the compositional differences within the

SA family. Compared to products based

on the same technology (and often re-

garded as equivalent), the patented use

of mineral microfibers provides this coat-

ing with excellent mechanical properties

(Figure 2). As pointed out by Finnie and

Williams,12 SA products achieve peak

performance when blended with con-

trolled amounts of rosin derivatives.

Fiber-reinforced silylated coating does

not use natural gum rosin, but rather the

zinc salt of a synthetic derivative, which

has been shown to provide a more

predicable behavior in seawater (Yebra,

et al.,4 Figure 3).

Fiber-reinforced silylated coating has

low solvent content. This feature facili-

tates the application of high film thick-

nesses in fewer coats, and lowers the risk

of solvent retention, which could affect

the paint performance if the application

takes place at low temperatures or if short

recoating intervals are used.

Strong evidence exists pointing to SA

as an increasingly important technology.

Not all “silylated” products necessarily

perform at the same level, even if they use

exactly the same polymer chemistry; only

experience and complex performance

analysis can tell which formulation yields

the best cost-efficient balance.

Part 1 has presented an introduction

to SA coatings. Parts 2 and 3 (May and

April 2011 MP) will describe non-stick

Comparison between synthetic rosin derivatives and natural gum rosin.4

fouling technology, tie-coat and topcoat

parameters, sealing of antifouling coat-

ings, and coating touch-up and repair.

References

1 M.P. Schultz, “Effects of Coating Roughness and Biofouling on Ship Resistance and Powering,” Biofouling 23, 2 (2007): pp. 331-341.

2 T. Munk, D. Kane, D.M. Yebra, “The Effects of Corrosion and Fouling on the Performance of Ocean-Going Vessels: A Naval Architecture Perspective,” C. Hellio, D.M. Yebra, eds., Advances in Marine Antifouling Coatings and Technologies (Cambridge, U.K.: Woodhead Publishing, Ltd., 2009).

3 Press release, A.P. Moller-Maersk (June 21, 2010).

4 D.M. Yebra, S. Kiil, K. Dam-Johansen, “Antifouling Technology: Past, Present, and Future Steps Towards Efficient and Environmentally Friendly Antifouling Coatings,” Progress in Organic Coatings 50 (2004): pp. 70-104.

5 M.B. Pereira, C. Ankjaegard, “Legislation Affecting Antifouling Products,” C. Hellio, D.M. Yebra, eds., Advances in Marine Antifouling Coatings and Technologies (Cambridge, U.K.: Woodhead Publishing, Ltd., 2009).

6 IMO MEPC.1/Circ. 683, “Guidance for the Development of a Ship Energy Efficiency Management Plan (SEEMP)” (London, U.K.: IMO, 2009).

7 IMO MEPC 58/123 Annex 13, Resolution MEPC.176 (58), “Amendments to the Annex of the Protocol of 1997 to Amend the Interna-tional Convention for the Prevention of Pollution from Ships, 1973, as Modified by the Protocol of 1978 Relating Thereto” (London, U.K.: IMO, 2008).

8 R.F. Piola, K.A. Dafforn, E.L. Johnson, “The Influence of Antifouling Practices on Marine Invasions,” Biofouling 25, 7 (2009): pp. 633-644.

9 C. Bressy, A. Margaillan, F. Fay, I. Linossier, K. Vallee-Rehel, “Tin-Free Self-Polishing Marine Antifouling Coatings,” C. Hellio, D.M. Yebra, eds., Advances in Marine Antifouling Coatings and Technologies (Cambridge, U.K.: Woodhead Publishing, Ltd., 2009).

10 A. Sanchez, D.M. Yebra, “Ageing Tests and Long-Term Performance of Marine Antifouling Coatings,” C. Hellio, D.M. Yebra, eds., Advances in Marine Antifouling Coatings and Technologies (Cam-bridge, U.K.: Woodhead Publishing, Ltd., 2009).

11 C.E. Weinell, K.N. Olsen, M.W. Christoffersen, S. Kiil, “Experimental Study of Drag Resistance Using a Labo-ratory Scale Rotary Set-up,” Biofouling, Vol. 19 (supplement) (2003): pp. 45-51.

12 A.A. Finnie, D.N. Williams, “Paint and Coatings Technology for the Control of Marine Fouling,” S. Durr, J.C. Thomason, eds., Biofouling (Hoboken, NJ: Blackwell Publishing, Ltd., 2010).

13 E. Risberg, A. Koop, K. Dahl, R. Hem, “Water Uptake of Commercial Antifouling Coatings with Binders Based on Trialkyl Silylated Acrylates or Metal Acrylates/Carboxylates,” 15th Interna-tional Congress on Marine Corrosion and Fouling, Newcastle Gateshead, U.K., July 25-29, 2010.

14 D.M. Yebra, C. Weinell, “Key Issues in the Formulation of Marine Antifouling Paints,” C. Hellio, D.M. Yebra, eds., Advances in Marine Antifouling Coatings and Technologies (Cambridge, U.K.: Woodhead Publishing, Ltd., 2009).

Parts 1 through 3 of this article were originally

published in the November 2010 and January 2011

issues of The Naval Architect.

DIEGO MESEGUER YEBRA is manager of Fouling Control Denmark, Research & Development, Hempel A/S, Lundtoftevej 150, Kgs. Lyngby, 2800, Denmark, e-mail: [email protected]. He has a Ph.D. in chemical engineering, specifically in the field of chemical product design, and is co-editor of “Advances in Marine Antifouling Coatings and Technology.”

PERE CATALÀ is manager of Fouling Control ES, Hempel A/S, Carretera de Sentmenat 108, 08213 Polinya, Spain. During his 20 years with the company, he has led the launch of several new antifouling products for yachts and the marine industry and established technology roadmaps for long-term project development. He has also contributed to the development of new and more efficient test methods for antifouling coatings.

FIguRE 3



MCMILLER.COM

http://MCMILLER.COM


[email protected]

www.defelsko.com


The following items relate to coatings

& linings.









clarity.

IOZ under foam glass insulation

QCan inorganic zinc

(IOZ) be used success-

fully under foam glass

insulation for normal

operating temperatures in the

70 to 80 °F (21 to 27 °C) range? What if there is an upset in the operation

temperatures that could get as high as

150 °F (66 °C) for a short period of time?

There is no cyclic operation; the unit runs

24 h each day, seven days a week, and is

only shut down during planned (or un-

planned) maintenance outages.

AIn my opinion, there should be

little difficulty in using IOZ under

foam glass at 70 to 80 °F. The

problem most people talk about

is the galvanic reversal between zinc and

iron at about 140 °F (60 °C). Short peri-

ods of exposure above 140 °F during

upsets should not result in severe or un-

usual corrosion. During shutdowns at

ambient temperatures, the IOZ should

protect the steel piping.

IOZ is a tough wear-resistant coating

and should not be adversely affected by

foam glass.

AI believe that IOZ under insula-

tion is okay except if the insula-

tion gets wet. A prolonged expo-

sure to wet insulation could result

in the steel rusting. An epoxy coating may

be more in order under the circum-

stances.

At temperatures higher than the

boiling point of water, this wetness factor

evaporates! IOZs can handle up to 750 °F

(400 °C) under dry conditions.

ATemperature-wise, there is no

problem. I have not seen IOZs

used underneath glass insulation

but I would be wary of any wet-

ting problems during shutdowns. If you

get condensation or water ingression

during shutdowns, you could get some

pretty aggressive conditions underneath

your insulation.

Take a look at NACE SP0198, “The

Control of Corrosion Under Thermal

Insulation and Fireproofing Materials—

A Systems Approach.” It has a whole

bunch of interesting information. IOZ is

in there for situations in which tempera-

tures go up to 1,000 °F (540 °C).




www.roxar.com


AFor your temperature range,

there is no specific need for IOZ.

You’ll have better luck and

equally good protection using an

epoxy coating. Also, if your substrate is

stainless steel, forget about the IOZ.

Masking off galvanizing

QDoes anyone have ex-

perience with prevent-

ing galvanizing from

adhering to surfaces? We have a job coming up that requires

bridge beams to be hot-dip galvanized,

but the top flanges must have no galvaniz-

ing on them. This is to allow welding of

grating and shear connectors. Some ad-

vice we have received is to apply “two

coats of good epoxy and the coating will

scrape off.” Frankly, I’m skeptical.

AThe advice given is correct. At

the galvanizing temperature,

epoxy would decompose to form

carbon. Carbon paste is a very

effective means of preventing zinc adhe-

sion. Alternatively, water glass (sodium

silicate) also would act as a stop-off.

After applying the stop-off, you would

have to remove both galvanizing and

stop-off residue before the zinc-rich

primer could be applied. Otherwise it

probably will fall off as well.

AUsing an epoxy may be valid. My

experience is that any paint left

on the steel will not be removed

during the pickling process, un-

less the steel is left in the pickling tanks

for an extended period of time. Even

then, the paint is not always removed.

If the epoxy was confined to the area

you want to mask only and the steel was

left in the pickling tank only for the period

of time required to prepare the bare steel,

it very well may come out of the galva-

nizing tank with the flange uncoated or

coated but not bonded to the steel. This

is because the remaining epoxy would

prevent the molten zinc from wetting out

the surface, thus preventing the normal

coating reactions. In the American Hot

Dip Galvanizers Association’s Inspection

Hand Book, one of the causes given for

bare spots is paint on the steel surface.

AInstead of using an epoxy mask-

ing coating, you may just as easily

apply a graphite-rich (carbon)

coating to the flanges—and the

cost wouldn’t be as great.

AHere in the United Kingdom, we

sometimes mask off small areas

of galvanizing with heat-resistant

sticky tape. You stick it on before

dipping and then peel it off afterward. It

works well for small areas but it might be

more of a pain with whole flanges.

http://www.roxar.com


www.densona.com [email protected]

C L B L O G


Bubbles in epoxy liner over concrete

QA three-coat epoxy

monolithic liner system

was applied to walls

and floors in a facility

that is not yet in production.

The concrete substrate at the new facility

had cured more than six months and had

received a sweep blast to provide the

necessary surface profile (which was a

medium grade 40 to 60 grit sandpaper

texture) and to remove the concrete cur-

ing agents. The primer was mixed with a

paint mixer and applied using a brush

and roller.

The liner was mixed and applied by

hand trowel to a film thickness of 1/8 in

(3 mm). A gel coat was mixed with a paint

mixer and applied using a brush and

roller. The time period for the complete

system application was ~6 h. Ambient

conditions were in the 60 to 70 °C (15 to

20 °C) range during application and rose

above 70 °F during the curing process.

Bubbles and white patches showed up

in the gel coat within 24 h of application

and continued to show up after three

days. The coating system was still soft

enough to penetrate the bubble areas

after three to four days. Manufacturer

representatives explain these areas as an

aesthetic condition resulting from “amine

blush.” Comments?

ARising temperatures immediately

after a thick film coating system

is applied frequently result in

blisters, not bubbles, in the entire

coating system. So I don’t think that’s

the cause.

Concerning white spots, my experi-

ence is they are caused by the intro-

duction of moisture (whether or not in

conjunction with amine blush). If pin-

hole-free integrity is required, I suggest

performing a holiday test. Normally the

gel coat’s function is to seal minor trowel

imperfections and to provide an easy-to-

clean surface where required.

AThe partial pore pressures of

water in the concrete trying to get

to the surface in a concrete that

is either moist itself or on a damp

subgrade will always bring moisture to

the surface and cause even minute

“bubbles” to form.

If this is the cause, the only way to cor-

rect it is expensive: remove it and let the

concrete dry—which is not always pos-

sible if the subgrade is in a permanently

damp area. Since the bubbles continue

and they still are forming after three days,

it sounds like there is an uninterrupted

source of moisture available to the con-

crete. If so, it cannot be stopped and the

indicated gel for all intents and purposes

will never be able to set.

http://www.densona.com




[email protected]


Since I work with concrete frequently,

I almost always attempt to separate it

from any source of moisture. If it requires

coating, wait until the afternoon prior to

starting the coating.

Blisters from sulfur aggregates in epoxy over concrete

QA recent problem

arose in a basement

floor coating applica-

tion that was applied

to concrete made of Type 3

Portland cement, sand, and

mine aggregates that had high

levels of sulfur present. The

flooring system used was a high-build

aggregate-filled epoxy system that was

applied to an epoxy primer. The concrete

had been cured for two to three months

and had never been exposed to any

chemical attack. There was no curing

membrane used and there was a vapor

barrier installed prior to placing the con-

crete. Could the sulfur-containing ag-

gregates, when mixed with the cement,

sand, and water mixture, have a reaction

with the amine curing agents? After ap-

proximately 18 months, large blisters

appeared and the floor system is heaving.

Prior examinations had shown small 1/4-

to 1/2- in (6- to 13-mm) blisters randomly

spaced and with low frequency. Previ-

ously these were attributed to overwork-

ing the product during installation.

The floor is a basement in a copper

refinery under the electrolytic cells. Ex-

posure is limited to 20 to 25% copper

sulfate (CuSO4) solutions at 50 to 60 °C

(120 to 140 °F) with frequent warm water

rinses (60 °C).

Would a cured and rigid coating soften

and deform into a blister if acidic leachate

permeated the coating, reacted with the

alkaline concrete surface, and formed off

gas? I would have thought that the cured,

high modulus coating would not deform

to this extent but I may be wrong.

ACuSO

4 is quite acidic. One pos-

sibility is permeation of the epoxy

by the solution, resulting in blis-

ters underneath when the acidic

liquor reacts with sulfur-containing ag-

gregate (forming hydrogen sulfide [H2S])

or concrete (forming carbon dioxide

[CO2]).

Another is that reaction of sulfur-

containing aggregate with amines does

not appear to hold up because 1) the reac-

tion does not have a plausible gas product

(that I can think of), and 2) I’d expect a

reaction over the first three months, not

after 18 months. Eighteen months is more

consistent with a permeation mechanism.

I’d suggest mixing CuSO4 solution

with some of this aggregate to see if you

get gas production. Do it carefully, be-

cause not many people realize H2S is as

toxic as hydrogen cyanide (HCN).

AIf the concrete pad still isn’t

sound, you may have cracks in

the concrete that have propa-

gated through the coating and

allowed the CuSO4 through. The reac-

tion products from acidic media with

concrete can be voluminous and easily lift

a coating. We have seen numerous in-

stances where this has happened. Expan-

sion joints are also critical areas, and if

they are not prepared suitably prior to

coating, the coating above the joint will

crack.

100% epoxy vs. 100% polyurethane

QDoes anybody have

experience comparing

100% epoxy coatings

to 100% elastomeric

polyurethanes (PURs) for po-

table water storage tanks?

AThe 100% solids epoxies and

100% solids elastomeric PURs

are very different beasts and are

really meant for different appli-

cations. The elastomer is, by definition,




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C L B L O G


a rubbery and/or stretchy material

much like that of the sole of your run-

ning shoes. The epoxy will be much

more rigid (perhaps even brittle) by

comparison.

Tests have been conducted to compare

100% solids elastomeric PUR, 100% sol-

ids epoxy, 100% solids rigid PUR, and an

amine-based epoxy (containing solvents).

The details were presented in a paper for

the NACE Northern Area Conference in

Toronto in November 1997. Most of the

data were with reference to steel. In sum-

mary, the elastomeric PUR had much

better impact resistance, flexibility, and

abrasion resistance than the 100% solids

epoxy. The 100% solids epoxy had bet-

ter current density (CD) resistance. The

permeability and adhesion of the two

coatings were similar.

One important note, which you may

want to consider, is that the 100% solids,

rigid PUR significantly outperformed

both the 100% solids epoxy and the

elastomeric PUR in the areas of adhe-

sion, CD resistance, and permeability.

The rigid PUR was better than the epoxy

but not as good as the elastomeric PUR

in the areas of impact strength and abra-

sion resistance.

Please keep in mind that these com-

parisons are generic in nature. You

should look at the data on the specific

coating material in question to get a truly

accurate comparison.

Join the NACE Corrosion and

Coatings List Servers!

More than 3,000 corrosion

professionals from all over the world

participate on the NACE International

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question and receive expert advice in

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http://www.sauereisen.com



The Role of Water Chemistry

in Preventing Silica Fouling in Industrial Water

SystemsZ. AmjAd And R.W. Zuhl, Lubrizol Advanced Materials, Inc., Cleveland, Ohio

Deposition of silica and silicate-based foulants in

industrial water systems is a difficult challenge for

water technologists because of the limited solubility

of both amorphous (polymerized) silica and metal

silicates. Once formed, silica scale is extremely

difficult to remove. Tis article describes the

influence of water chemistry on the performance of

polymeric additives to inhibit silica polymerization.

Silica and metal silicate-based salts

have been described as the most

problematic foulants in industrial

water systems operating with

silica-laden feedwater.1-3 In desalination

of brackish water by reverse osmosis

(RO), silica-based fouling problems cause

reduced permeate production rates, in-

creased energy costs, poor permeate

quality, and more frequent membrane

cleaning. In evaporative cooling systems,

water technologists must maintain silica

at acceptable levels (usually <180 mg/L

in absence of silica/silicate control agents)

to avoid silica-based deposits. This re-

quires operating systems at low cycles of

concentration, which increases water

consumption or the incorporation of sil-

ica/silicate control agents in the water

treatment.

In geothermal applications, factors

such as variable fluid compositions, fluc-

tuating plant operating conditions, and

the complex nature of silica polymeriza-

tion reaction contribute to silica-silicate

fouling problems. The composition and

the amount of silica scale as well as the

rate at which it forms is dependent on

silica supersaturation, pH, temperature,

hardness ion concentration, and system

impurities.

Over the years, a variety of approaches

has been proposed to combat silica/sili-

cate fouling in industrial water systems.

These methods fall into five categories: (a)

operating system at low silica-silicate

supersaturation, (b) reducing silica con-

centration by precipitation process in

feed water, (c) using an additive to prevent

silica polymerization, (d) creating and

inhibiting metal-silicate compound pre-

cipitation, and (e) incorporating polymer(s)

into water treatment formulations to dis-

perse silica/silicate deposits.

The type and extent of impurities such

as aluminum, iron, manganese, zinc, and

suspended matter present in recirculating

cooling water exhibit antagonistic effects


C H E M I C A L T R E A T M E N T

on the performance of deposit control

polymers used in cooling water treatment

formulations.4 The effectiveness of the

surface water treatments in reducing sus-

pended solids is dependent on the proper

selection and feed rate of coagulants or

flocculants, pH, mixing time, and resi-

dence time. Chemicals commonly used in

a coagulating or flocculating capacity in-

clude alum, ferric chloride (FeCl3), and

cationic polymer such as diallyldimethyl

ammonium chloride (NH2Cl). These

chemicals are known to “carry over” and

have been reported to decrease the per-

formance of calcium phosphate5 and cal-

cium phosphonate inhibitors.6 Low levels

(0.1 to 1.0 ppm) of flocculants or coagu-

lants exhibit an antagonistic influence on

the efficacy of iron oxide dispersants.7 The

present work focuses on the impact of

various system impurities such as Al(III),

Fe(III), hardness ions, and cationic floc-

culants on the performance of silica po-

lymerization inhibitors.

Experimental

ProceduresReagent-grade chemicals and distilled

water were used throughout the study.

Silica stock solutions were prepared from

sodium metasilicate, standardized spec-

trophotometrically, and stored in poly-

ethylene (PE) bottles. Stock solutions of

calcium chloride (CaCl2) and magnesium

chloride (MgCl2) were standardized by

titrating with standard EDTA solution.

Standard solutions of Fe(III) and Al(III)

were purchased from Fisher Scientific.

The inhibitors used in this study were two

Carbosperse† K-700 polymers and two

other commercially available materials as

listed in Table 1. All experimental results

are reported on a 100% active inhibitor

basis for comparative purposes. The ex-

perimental set-up used in the present

investigation was described in an earlier

article.2

Silica polymerization experiments

were performed in a PE container placed

in a double-walled Pyrex† cell maintained

at 40 °C. The silica supersaturated solu-

tions were prepared by adding a known

volume of water. After allowing the tem-

perature to equilibrate, the silicate solu-

tion was quickly adjusted to pH 7.0 using

hydrochloric acid (HCl). The pH

was monitored using a Brinkmann/

Metrohm† pH meter equipped with a

combination electrode. After pH adjust-

ment, a known volume of a CaCl2 and

MgCl2 stock solution was added to the

silicate solution. The silicate supersatu-

rated solution was readjusted to pH 7.0

with dilute sodium hydroxide (NaOH) or

HCl and was maintained constant

through out the silica polymerization ex-

periment. Experiments involving inhibi-

tors, Fe(III), Al(III), and cationic polymer

were performed by adding inhibitor solu-

tions to the silicate solution before adding

the CaCl2 and MgCl

2 solution. The reac-

tion containers were capped and kept at

constant temperature and pH during the

experiments.

Silica polymerization in these super-

saturated solutions was monitored by

analyzing the aliquots of the filtrate from

0.22-µm filter paper for the soluble silica

using the standard colorimetric method

as described previously.2 The silica poly-

merization inhibition values were calcu-

lated according to Equation (1):

(1)

where SI = silica inhibition (%) or %SI,

[SiO2]

sample = silica concentration in the

presence of inhibitor at 22 h, [SiO2]

blank

= silica concentration in the absence of

inhibitor at 22 h, and [SiO2]

initial = silica

concentration at the beginning of the

experiment. †Trademark of The Lubrizol Corporation. †Trade name.

TAbLE 1

Polymeric inhibitors evaluated

Inhibitor Composition Acronym

CCP-D(A) Poly(acrylic acid:2-acrylamido-2-methylpropane sulfonic acid:non-ionic)

CP3

CCP-A(A) Proprietary acrylic copolymer CP4

K-XP212 Proprietary copolymer blend CP5

K-XP229 New proprietary copolymer blend CP6

(A)Polymer containing >50% carboxylic monomers.

Silica polymerization inhibition as a function of CP5 dosage.

FIguRE 1


C H E M I C A L T R E A T M E N T The Role of Water Chemistry in Preventing Silica Fouling in Industrial Water Systems

Results and

Discussion

Effect of Polymer Dosage

Assessments of polymer effectiveness

as a silica polymerization inhibitor were

done at similar initial silica super-satura-

tion (550 mg/L silica, 200 mg/L Ca,

120 mg/L Mg, pH 7.0, 40 °C) and in the

presence of various polymer dosages.

Figure 1 details the silica concentrations

vs. time profiles in the absence and in the

presence of varying copolymer (CP5) dos-

ages. The results suggest that silica con-

centrations decrease with increasing time

(thereby indicating silica polymerization

is occurring) and that silica concentration

at a given time increases with increasing

polymer dosage. For example, silica con-

centrations in the absence of polymer at

time equal to 0, 1, and 3 h are 560, 458,

and 299 mg/L, respectively. Figure 1 also

presents silica inhibition as a function of

CP5 dosage. At 22 h in the presence of 15

ppm CP5, the silica concentration in solu-

tion is 230 mg/L compared to 177 mg/L

in the absence of CP5. At 25 and 50 ppm

CP5 dosages, the silica concentrations are

370 and 495 mg/L, respectively.

Figure 2 shows silica inhibition data

calculated according to Equation (1) for

CP3, CP4, CP5, and CP6. Compared to

CP5, CP6 exhibits excellent silica polym-

erization inhibitor performance, espe-

cially at low dosages. The %SI value

obtained in the presence of 25 ppm of

polymers at 22 h for CP5 is 12% com-

pared to 56% for CP6. Figure 2 also in-

dicates that the competitive commercial

polymers (CP3 and CP4) perform poorly

(<20% SI) even at 350 ppm dosages (not

shown) as silica polymerization inhibitors

compared to CP5 and CP6. The data

presented in Figure 2 clearly show that

polymer architecture plays an important

role in inhibiting scale formation in in-

dustrial water systems.

Silica polymerization inhibition as a function of polymer dosage.

Effect of Fe(III) concentration on silica polymerization inhibition by polymers (50 ppm).

Effect of Al(III) concentration on silica polymerization inhibition by polymers (50 ppm).

FIguRE 2

FIguRE 3

FIguRE 4


C H E M I C A L T R E A T M E N T

Effect of Coagulating/Flocculating Agents

The use of flocculating agents (inor-

ganic and organic types) to flocculate/

coagulate suspended matter in feedwater

and wastewater streams is well known.

The suspended solids commonly present

in feedwaters include metal oxides, clays,

microorganisms, organic debris, etc.

Commonly used inorganic salts to induce

flocculation and coagulation include

aluminum chloride (AlCl3), aluminum

sulfate [Al2(SO

4)3], and FeCl

3. Although

these chemicals are effective in coagulat-

ing/flocculating colloidal particles, they

are corrosive and generate large sludge

volumes. The metal salts treatment can

be augmented, however, by the use of

cationic polymer such as diallyldimethyl

ammonium chloride.

Inorganic Metal Salts

To understand the role of both inor-

ganic and organic coagulants/flocculants

on the performance of silica polymeriza-

tion inhibitors (i.e., CP5 and CP6), a se-

ries of experiments was carried out in the

presence of varying Fe(III) dosages. Low

Fe(III) levels (e.g., 0.25 ppm) exhibit a

negative or antagonistic influence on the

silica polymerization inhibition by CP5

and CP6 (Figure 3). Incrementally in-

creasing Fe(III) levels to 1.0 ppm further

decreases silica inhibition (%SI) values.

For example, the %SI values obtained in

the presence of 0.50 ppm Fe(III) are 59%

for CP5 and 70% for CP6. Figure 3 shows

that CP6 is more tolerant to Fe(III) than

is CP5. Similar antagonistic effects by

Fe(III) have been reported in studies in-

volving calcium phosphate inhibition by

anionic polymers.

The influence of low Al(III) levels was

also investigated by conducting a series

of silica polymerization experiments in

the presence of 50 ppm of CP5 and CP6.

Results presented in Figure 4 clearly show

that silica polymerization inhibitor per-

formance is strongly impacted by the

presence of Al(III), and that silica poly

merization inhibition values for both

polymers decreased 20 to 30% by adding

0.10 ppm Al(III) and more pronounced

antagonistic effects occurred when add-

ing 0.25 ppm Al(III). By comparing the

silica polymerization inhibition of CP5

and CP6 in the presence of metal ions

(Figures 3 and 4), it is evident that Al(III)

exhibits a more antagonistic effect than

Fe(III). The markedly greater antagonism

on silica inhibition values caused by

Al(III) compared to Fe(III) may be at-

tributed to the different cationic charge

density present on metal hydroxides.

Cationic Polymer

Figure 5 presents silica polymerization

inhibition data for CP5 and CP6 in the

presence of varying dosages of a cationic

polymer (diallyldimethyl ammonium

chloride or DADMAC). The data indi-

cate that DADMAC dosages up to 3.0

ppm cause a slightly antagonistic effect

on the silica polymerization inhibition

performance of CP5 and CP6. This is

very interesting, because cationic poly-

mers such as DADMAC have previously

been shown to exhibit strong antagonistic

effects on the performance of calcium

phosphate and calcium phosphonate4

inhibitors.

Effect of Hardness Ions

It is generally known that the presence

of metal ions affects both the rate of pre-

cipitation and crystal morphology for

scaleforming salts. Metal ions are also

known to form insoluble salts with silicate

ions in aqueous solution. To understand

the role of metal ions (i.e., Ca2+ and Mg2+)

on silica polymerization inhibition in the

presence of CP6, a series of experiments

was carried out at similar initial silica

concentration and varying concentra-

tions of CaCl2/MgCl

2 solution.

Figure 6 illustrates silica concentra-

tions as a function of time for experiments

in the presence of 50 ppm CP6 and vary-

ing total hardness (TH or Ca2+/Mg2+)

concentrations. The data indicate that

silica polymerization inhibition increases

as a function of TH concentration.

The influence of total dissolved solids

(TDS) on silica polymerization inhibition

in the presence of 50 ppm CP6 was also

investigated. The experimental data

(omitted herein) included silica polymer-

ization inhibition values at 22 h in the

presence of 50 ppm CP6 and various

TDS levels (either Ca2/Mg2+ [2:1] as

described above or NaCl). The data in-

dicate that silica polymerization inhibi-

tion strongly depends on the Ca2+/Mg2+

concentration present in the silica super-

saturated solutions. Furthermore, diva-

lent metal ions (i.e., Ca2+, Mg2+) in the

presence of constant ionic strength ex-

hibit a greater effect on silica polymeriza-

tion inhibition than monovalent cations

(i.e., Na+). Specifically, %SI values ob-

tained using 50 ppm CP6 in the presence

of similar ionic strength but different TDS

Effect of cationic polymer on silica polymerization inhibition by polymers (50 ppm).

FIguRE 5


C H E M I C A L T R E A T M E N T The Role of Water Chemistry in Preventing Silica Fouling in Industrial Water Systems

levels (Na+ [1,755 mg/L NaCl]) and

Ca2+/Mg2+ [320 mg/L total hardness]) at

similar ionic strength are 16 and 92%,

respectively. The performance variations

caused by TDS (Na+ and total hardness

[either Ca2+ or Mg2+]) on silica polymer-

ization may be attributed to the different

charge density of these metal ions.

Silica Precipitates—Characterization and

Composition

X-ray dispersive (XRD) spectra were

used to evaluate the precipitates formed

both in the absence and presence of CP5

or CP6 at 50 ppm. It is evident from the

XRD spectra that the silica precipitates

formed both in the absence and presence

of inhibitors are amorphous. Energy

dispersive x-ray spectrometry (EDS) was

used to evaluate the precipitates and

indicate the compositions are essentially

silicon and oxygen with only trace

amounts of Ca and Mg present in the

filtered solid. This observation was con-

firmed by analyzing Ca and Mg ions

before and after filtration wherein

there was no significant concentration

difference. The trace levels of Ca and

Mg shown in the EDS spectra may be

the result of surface adsorption of

Ca and Mg on the unwashed precipi-

tated silica.

Conclusions

Results presented herein indicate that

silica polymerization strongly depends on

water chemistry (i.e., type and concentra-

tion of mono-, di-, and tri-valant ions). It

has been found that low levels (≤1 ppm)

of Al(III) and Fe(III) exhibit antagonistic

effects on the performance of silica po-

lymerization inhibitors. However, the

presence of up to 3 ppm of cationic floc-

culant (DADMAC) has minimal (<5%)

antagonistic effects on the performance

of both CP5 and CP6.

The data presented in this article also

show that Ca2+ and Mg2+ present in the

silica supersaturated solution exhibits a

synergistic effect on the performance of

CP6 whereas the presence of Na+ has an

insignificant influence on silica polymer-

ization. In addition, EDX spectra of silica

samples collected in the presence and

absence of CP5 or CP6 show that the

silica precipitates formed are amorphous

in nature with essentially no incorpora-

tion of hardness ions.

References

1 R. Sheikholeslami, I.S. Al-Mutaz, T. Koo, A. Young, “Pretreatment and the Effect of Cations and Anions on Prevention of Silica Fouling,” Desalination 139 (2001): pp. 83-95.

2 P.P. Nicholas, Z. Amjad, “Method for Inhibiting and Deposition of Silica and Silicate Compounds in Water Systems,” U.S. Patent No. 5,658,465 (1997).

3 K.D. Demadis, A. Stathoulopoulou, A. Ketsetzi, “Inhibition and Control of Colloidal Silica: Can Chemical Additives Untie the Gordian Knot of Scale Inhibi-tion?,” CORROSION 2007, paper no. 07058 (Houston, TX: NACE Interna-tional, 2007).

4 Z. Amjad, J.F. Zibrida, R.W. Zuhl, “Polymer Performance in Cooling Water—Influence of Process Variables,” MP 36, 1 (1997): pp. 32-38.

5 Z. Amjad, R.W. Zuhl, “The Influence of Water Clarification Chemicals on Deposit Control Polymer Performance in Cooling Water Applications,” Associ-ation of Water Technologies Annual Convention, Orlando, FL (2002).

6 Z. Amjad, R.W. Zuhl, J.A. Thomas-Wohlever, “Performance of Anionic Polymers as Precipitation Inhibitors for Calcium Phosphonates: The Influence of Cationic Polyelectrolytes,” Advances in Crystal Growth Inhibition Technologies, Z. Amjad, ed. (New York, NY: Kluwer Academic Publishers, 2000).

7 Z. Amjad, R.W. Zuhl, J.F. Zibrida, “The Effect of Biocides on Deposit Control Polymer Performance,” Associa-tion of Water Technologies Annual Convention, Honolulu, HI (2000).

This article is based on CORROSION 2010

paper no. 10048, presented in San Antonio, Texas.

The paper contains additional figures not included in

this article.

ZAHID AMJAD is a technical consultant at Lubrizol Advanced Materials, Inc., 9911 Brecksville Rd., Cleveland, OH 44141, e-mail: [email protected]. He has an M.S. degree from Punjab University, Pakistan; a Ph.D. from Glasgow University, U.K.; and is a post-doctoral fellow at the State University of New York at Buffalo. A member of NACE International for more than 20 years, Amjad is also a member of the American Chemical Society, was inducted in the National Hall of Corporate Inventors, and is listed in American Men and Women of Sciences and Who’s Who of American Inventors. He received the Association of Water Technologies’ 2002 Ray Baum Memorial Water Technologist of the Year. He holds 29 U.S. patents, has published more than 100 technical papers and articles, and has edited five books.

BOB ZUHL is the global business manager, Water Treatment Chemicals, at Lubrizol Advanced Materials, Inc., e-mail: [email protected]. He has a B.S. degree in civil engineering and an M.S. degree in environmental engineering from Michigan State University, and an M.B.A. from Baldwin Wallace College. A member of NACE for more than 20 years, Zuhl is a registered Professional Engineer (Michigan and Indiana) and has published more than 20 technical papers and articles.

Silica concentration vs. time in presence of 50 ppm CP6 and varying TH levels.

FIguRE 6




www.corcon.org

www.naceindia.org

[email protected] [email protected]

http://www.corcon.org

http://www.naceindia.org





The following items relate to chemical

treatment.









clarity.

Tubercles all MIC-related?

QAre tubercles manifes-

tations of microbial

activity? Are there tubercles

that are not fully explained by

microbiologically influenced corrosion

(MIC)? What would you see in the shape

of the underlying pit that would provide

more information on the root cause of

such problems?

AI would say that tubercles are the

result of plain old corrosion.

AI have found tuberculation on

seawater cooling systems (piping,

coolers, cooling towers, etc.) that

were not related to MIC.

ALook at the tubercle to determine

the cause. Microbial analysis will

determine if it contains the types

of microbes that are associated

with MIC. Mineral analysis tells you if

there are byproducts of electrochemical

corrosion. A look in the underlying pit

provides additional information to sup-

port your conclusion as to the cause(s) of

the tubercle/pit.

AMIC often has crater-like pits

with something that looks like

tide lines inside the crater. The

tide lines represent the changing

size of the bacterial colony as the environ-

ment changes.

AThere are many references that

show photographs that allegedly

represent MIC damage. In my

experience, the photograph ref-

erences are good “pointers.” However,

proof for MIC requires more rigorous

evidence than the photographs to sup-

port MIC as a significant cause of the

tubercle/pit.

AWe do scanning electron micros-

copy for the mineral in the de-

posit to look for corrosion and

MIC byproducts and do elemen-

tal mapping to look for selective leaching

of the metal. Both of these are “pointers”

to the cause(s) of corrosion. However,

don’t confuse the appearance of the pit

with the more detailed analytical work.

The appearance of MIC is widely recog-

nized, but appearance in and of itself is

not sufficient to claim MIC as a signifi-

cant cause of the corrosion. You should

remember that the microbes can move

into the pit after the corrosion started.

Pigging frequency

QWe have just finished

pigging a 30-km sweet

gas pipeline. The pig

brought out ~3 to 4 kg of black

iron product mixed with various sub-

stances (glycol, inhibitor, and heavy hy-

drocarbons). No iron sulfide (FeS) was

present and we guessed the black color

was due to mixing of these substances.

The line had not been pigged since

construction 10 years ago. The oxides

that formed on the internal surface were

still present. Pigging removed these ox-

ides and left the steel directly exposed

to gas. Another oxide layer will now be

formed. We need this layer to protect

the line.

The line transports gas from a com-

pressor station to a main process plant.

The compressor station has only gas

compressors and a glycol unit, to mini-

mize water content. What is the standard

pigging interval in such a case to keep the

protective layer and still clean the line?

AThere is a concern about oxides

in natural gas plugging down-

stream equipment, such as burn-

ers, etc., and also about the effi-

ciency of cleaning the pipes. There is an

in-line continuous monitor that measures

the mass and number of particles flowing

through the pipe and can also take a

sample for analysis. That would give you

good information on when to clean.

AIn this case, you need not worry

much about the pipeline construc-

tion residuals and possible “oxide

layers” inside the pipe. I presume

the pipe carries dry natural gas, and the

possibility of oxygen ingress is remote.

The 4 to 5 kg of black pigging debris

after a period of 10 years looks quite all

right to me. Better check that compres-

sor station and glycol unit personnel are

adhering to proper procedures.

APigging frequency depends on

your gas analysis, composition of

the shipping material, pressure of

your system, and types of pigs.

More pigging is better than less for your

pipeline protection.

Heat exchanger cleaning methods

QWe are a chemical pro-

duction facility seek-

ing economical meth-

ods for cleaning the

shell side of a fixed tube sheet

heat exchanger that is fouled

with tar. We have tried to develop a

chemical solution for dissolving the tar,

but have been unsuccessful. The heat

exchanger is carbon steel consisting of

~1,500 tubes welded on each tube sheet.

We will likely scrap the equipment, but

need to clean it prior to disposal.


[email protected]

www.defelsko.com

[email protected]

www.CortecVCI.com

Is anyone aware of unique economical

cleaning methods that may be used for

this situation?

AMTI Publication 51, “Cleaning

of Process Equipment and Pip-

ing” (1997), is a useful reference

and has some details on organic

solvents and safe ways of cleaning. The

main issues seem to be cacogenic and

flash point properties. For a flash point

>65 °C, heavy naphthas and aromatic

distillates are recommended. For a flash

point <65 °C, heptane [CH3(CH

2)5CH

3],

light naphthas, and chlorinated hydro-

carbon solvents such as trichloroethylene

(CHCl:CCl2) can be used.

ATars are usually tough because

they frequently are polymeric

substances formed by heat. I

would suggest analyzing the tar

first to determine the functional groups

present, as this can provide clues to effec-

tive dispersion. Hot chlorinated solvents

can work quite well if polymerization is

not too advanced. However, there are

occupational health and safety issues to

be taken into account. If there is ester

present, recirculating hot, reasonably

concentrated alkali could kick-start suf-

ficient saponification to disperse the tar.

I have heard of ammoniated citric acid

(C6H

8O

7{H

2O) being used to clean steel

electrical transformers, although not with

tar contamination.

As a last resort, cold commercial grade

concentrated sulfuric acid (H2SO

4), con-

centrated phosphoric acid (H3PO

4), and

potassium dichromate (K2Cr

2O

7) is be-

loved by chemists wanting to clean badly

contaminated glass. Attack on the steel

should only occur in the rinsing phase,

but could be overcome by passivation to

alkaline pH with nitrite.

AI think, as a very first step, you

need the composition of what you

want to dissolve. Many organic

solvents (light naphtha, gasoline,

chlorinated solvents, light oils, etc.) exist

in tar.




http://www.CortecVCI.com

62 MATERIALS PERFORMANCE April 2011 NACE International, Vol. 50, No. 462 MATERIALS PERFORMANCE April 2011 NACE International, Vol. 50, No. 4

Construction Materials

for Acid Gas Pipelines and

Injection WellsS. Bhat, Bipin Kumar, DipanKa BaiShya, anD m.V. KatarKi,

Institute of Engineering and Ocean Technology, Navi Mumbai, India

Sweetening highly sour gas and disposing of it

through injection into reservoirs prevents acid gas

emissions to the atmosphere. Wet acid gas is

corrosive to steel pipelines and equipment. Any

leakage of the gas can be catastrophic as it is severely

toxic. Dehydration of acid gas can be achieved

through proper compression. Suitable construction

materials for associated pipelines and equipment

and typical injector well design are discussed.

The marginal field in western off-

shore India produces highly sour

hydrocarbons with hydrogen

sulfide (H2S) and carbon dioxide

(CO2) content of 4 and 11%, respectively.

These gases are called acid gases because

they can form acidic compounds when in

contact with water. CO2 is considered a

“greenhouse” gas, and efforts to limit

venting to the atmosphere are widely

encouraged. H2S is normally removed

from the gas with a sweetening process,

and then flared.

The sulfur dioxide (SO2) product of

combustion can cause acid rain when

combined with moisture in the atmo-

sphere. If acid gas flaring is done off-

shore, the cities on the western coast are

likely to face the brunt of acid rain. The

gas sweetening process and disposal of

acid gas through injection into a forma-

tion is an alternative to flaring. The

severe corrosiveness of the acid gas

has been assessed and suitable materials

of construction (MOC) have been identi-

fied for equipment and piping for in

jection and handling of acid gas injec-

tion (AGI). The findings are discussed in

this article.

Acid Gas Injection AGI involves compression of the gas

from the sweetening process and injection

into a suitable underground formation,

and is essentially a zero emission pro-

cess.1-3 Figure 1 shows the schematic of

the AGI process. The flow rate of the gas

from the sweetening plant is 38,100

m3/day, the pressure is 41.2 psia, and the

temperature is 45 °C. The gas composi-

tion is 27.7% CO2, 66.58% H

2S, and

5.23% water (H2O). The gas is pumped

through a 6in (152mm) pipeline and

compressed in a four-stage compressor to

a design pressure of 2,133 psia. It is in-

jected into the wellhead through a 4.156

in (105.56mm) pipeline. The injector

well has 2 7/8in (73mm) tubing.


M A T E R I A L S S E L E C T I O N & D E S I G N

Corrosion Susceptibility and Identification of Suitable Materials of Construction

The corrosion severity has been evalu-

ated by considering the partial pressure

of CO2, H

2S, the temperature, and liquid

water wetting conditions. The worst pre-

dicted corrosion rate has been calculated

from software analysis. Considering the

severe impact of H2S, a conservative ap-

proach has been adopted in deciding on

the MOCs for piping and various equip-

ment handling the AGI process.

Pipeline from Sweetening Process to Compressor

The 6-in carbon steel (CS) wet acid gas

pipeline from the gas sweetening plant is

highly vulnerable to corrosion as the

partial pressures of CO2 and H

2S are

11.4 psi and 27.4 psi, respectively, with a

P-CO2/P-H

2S ratio of 0.4. The predicted

corrosion rate for CS is 2.2 mm/y. The

operating temperature is much less than

60 ºC and hence susceptibility to sulfide

stress cracking (SSC) is also high. The

salinity in the marginal field wells is sig-

nificantly high (2%) and with H2S at 27.4

psi, alloys like 13Cr steel, Type 316 stain-

less steel (SS) (UNS S31600), Type 304

SS (UNS S30400), and duplex and super

duplex steel do not have adequate corro-

sion resistance. The guidelines of The

Nickel Institute4 indicate that the suitable

MOC for these operating conditions

should be 20Cr-25Ni-4Mo. Alloy 28†

(UNS N08028) conforms to the required

composition.

Compressor Components, Discharge Line, and Injection Well

The compressor components in direct

contact with the acid gas are exposed to

partial pressures of CO2 and H

2S in the

ranges of 11.4 to 640 psi and 27.2 to

1,493 psi, respectively, at various stages

of the compression. Hence, in the pres-

ence of liquid water either at any stage of

the compressor or discharge pipeline, the

predicted corrosion rate would be very

high. The predicted corrosion rate for CS

wellhead components, downhole tubu-

lars, and other components of the injector

well would be extremely high in the event

of wetting by liquid water. Thus, assess-

ment of the presence of liquid water in

the acid gas medium helps in predicting

the severity of corrosion. The water con-

tent in the acid gas is predicted by using

the software AQUAlibrium†.5 The results

are given in Table 1.

It can be seen that for the acid gas

composition, its water-holding capacity

would be minimum at ~600 psi pressure.

Above 700 psi pressure, acid gas begins

to transform from the gaseous state to the

liquid phase, and finally at 900 psi, it

changes over to the liquid state almost

completely. Figure 2 shows the graphical

representation of the water-holding ca-

pacity of acid gas. Over each compression

stage, the pressure and temperature in-

creases and after each compression stage

the gas is cooled. The water-holding ca-

pability of the gas decreases from stage to

stage, until the minimum water-holding

capacity is reached. If the condensed

water is removed at this point, the gas †Trade name.

Schematic of AGI process.

FIguRE 1

TAbLE 1

Effect of pressure on water content of acid gas

Pressure (psia)

Water in Gas

(lb/MMSCF)

Water in Condensate

(lb/MMSCF)

27 2,485.0 —

100 703.4 —

200 375.9 —

300 268.9 —

400 217.6 —

500 189.0 —

600 172.9 —

700 163.5 807.8

800 158.4 698.1

1,000 — 664.3

1,600 — 714.8

2,200 — 747.9


M A T E R I A L S S E L E C T I O N & D E S I G N Construction Materials for Acid Gas Pipelines and Injection Wells

will be undersaturated with water

throughout the rest of the compression

process. A corrosion-resistant alloy

(CRA) will not be required in the com-

pressors or coolers after this point. If the

temperature of the compressed gas does

not drop to the new water saturation

temperature in the pipeline or well bore,

dehydration can be eliminated and a

CRA and methanol injection will not be

necessary.

Suggested pressures at various stages

of compression should be ~600 to 700

psi to take advantage of the thermody-

namics of the gas wherein water content

of acid gas is a minimum. This design

facilitates auto-dehydration of gas during

compression. The design of the compres-

sor stages is such that dehydration of the

gas takes place before the third stage of

compression.

Suction at the first stage is 41 psia,

suction at the second stage is 41 × 2.6 =

106 psia, suction at the third stage is 106

× 2.6 =275 psia, and suction at the fourth

stage is 275 × 2.4 = 660 psia. At this

pressure, the acid gas will be in a gaseous

state and has the least water-holding

capacity. Hence, the maximum possible

water present in the gas is separated at

air cooling, and the suction gas for the

fourth stage has the least water-holding

capacity. Discharge line pressure is 660

× 3.25 = 2,145 psia.

Material of Construction for Compressor Components in Contact with Acid Gas

In the inter-stage coolers, water will

condense and could pose a corrosion

problem. Downstream of the coolers, the

lines to the inter-stage scrubbers and the

scrubbers themselves will be exposed to

the corrosive acid gas and condensed

water mixture. The sour water that is

condensed at intercoolers at the first,

second, third, and fourth stages of com-

pression is very corrosive. The CRA

suitable for compressor components is

Type 316L SS (UNS S31603) per NACE

MR0175/ISO15156 standard.6 Type

316L SS has a maximum hardness of 22

HRC and can be used for compressor

components without restriction on tem-

perature, partial pressure of H2S, chloride

content, or in situ pH conditions. Thus,

the inlet and outlet manifold, inter-stage

coolers, lines to the inter-stage scrubbers,

scrubbers, drain line from the compres-

sor, cooler headers, bundles, tubes, con-

nections, valves, thermowells, instrument

lines, manifolds, etc. can be made of Type

316L SS. The compressor seal rings and

gasket are austenitic J92600 or J92900

SS, which is applicable to any combina-

tion of H2S, temperature, partial pres-

sure, chloride concentration, and in situ

pH. J92600 or J92900 API compression

seal rings and gaskets made of wrought

or centrifugally cast materials in the as-

cast or solution-annealed condition need

a hardness of 160 HBW (83 HRB) maxi-

mum. The compressor cylinder material

can be ion nitrided CS. The compressor

suction and discharge valves are Type

316L SS. The piston rod is Type 316L

SS, coated with a tungsten carbide over-

lay having a maximum hardness of RC

22. The valves are Type 316L SS.

Material of Construction for the Discharge Line from Compressor to Injector Well

After the fourth stage compression, the

gas is in the liquid phase, which is a non-

aqueous liquid form of acid gas. The re-

sidual water content, if any, held by the

acid gas will be within the liquid H2S and

will not be available for any electro-

chemical reaction of steel. The non-

aqueous liquid form of acid gas is inert

with respect to electrochemical reactions

and hence does not facilitate anodic-

cathodic reactions. Therefore, CS can be

used as the MOC. An acid gas injection

process is not the place to save a little

money, however, when leaks can be

catastrophic because H2S is a lethal gas.

At equipment failure, liquid acid gas

changes its phase from liquid to gaseous

with the falling pressure and increasing

temperature and hence the CS pipeline

would be highly vulnerable to severe cor-

rosion, leading to unpredictable prema-

ture failure. As a conservative approach,

Type 316L SS is recommended.

Well Completion Design and Material of Construction for Injector Well

The flow profile of the acid gas in the

injector well has been derived by using

the software GLEWpro Version 1.1†.7-9 It

Graphical representation of water-holding capacity of acid gas.

FIguRE 2



estimates the phase, property, and flow-

ing profiles of acid gas along the well

bore. The software analysis shows that

the phase behavior is single phase (liquid)

from wellhead to well bottom. The phase

is a nonaqueous form of gas and is highly

unsaturated with water. The separation

of water in this condition is ruled out. The

wellhead and Christmas tree are Material

Class HH-Sour Service, with body, bon-

net, end, and outlet connections; pressure

controlling parts; and stems. The man-

drel hangers are a CRA. The surfaces in

these components directly exposed to gas

are Incoloy 825† (UNS N08825). The gas

after the fourth stage is highly unsatu-

rated with water and the condensation of

any water held by acid gas is unlikely at

the injector well operating pressure and

temperature.

The thermodynamics of the injected

acid gas is such that it will be a nonaque-

ous liquid state and the water held will be

within this nonaqueous phase, thereby

not facilitating any electrochemical reac-

tion on the tubing surface. The predicted

corrosion rate for CS tubing in the event

of thermodynamics favoring the formation

of liquid water and bubbling out acid gas

would be extremely high. This can happen

only if the acid gas injection operation

(compression, etc.) fails. As a conservative

approach, however, it is recommended to

use NACE CS for tubing.

The bottom hole portion, with the

bottom hole temperature being the high-

est in the whole path of gas flow, may

experience corrosion first in the event of

any upset in the thermodynamics of gas

compression and discharge. Such an

event, though unlikely in normal opera-

tions, cannot be ruled out, especially in

case there is any accidental shutdown of

the compressor, followed by decreasing

bottom hole pressure. The fall in pressure

may lead to water phase separation and

accumulation in the bottom hole, causing

electrochemical corrosion at the well bot-

tom. Hence, as a conservative approach,

bottom hole assembly of the tubing is

suggested to be a CRA. The suitable

CRA for the bottom hole assembly is

N08825. Further, to ensure any future

well control operation, a N08825 pup

joint is installed between the packer and

the nonselective profile nipple in the tub-

ing tail, both constructed of N08825. At

the bottom, above the packer, there is a

N08825 pup joint connected to the on-off

connector and further joined to CS L-80

tubing up to the wellhead. At the bottom

hole assembly, below the profile nipple,

perforated N08825 tubing pup and a no-

go re-entry guide is to be assembled.

Figure 3 illustrates a typical well comple-

tion diagram. In this diagram, only pro-

duction casing is shown, which requires

special attention on material selection.

The remaining surface and intermediate

casing can be CS, API 5CT L80 Type I.

There is a combination of N08825

and CS. Bimetallic galvanic corrosion

occurs when two dissimilar alloys with

different potentials are in electrical con-

tact while immersed in an electrically

conducting corrosive liquid. In the injec-

tor well, the acid gas profile is a nonaque-

ous liquid and is nonconducting and

hence will not facilitate galvanic corro-

sion on the internal surface of the tubing.

Further, on the external surface of the

tubing and the internal surface of the

casing, galvanic corrosion can be pre-

vented by nonaqueous well completion

fluids such as stabilized crude oil or diesel

oil. The casing for the injector well can

be CS conforming to API 5CT L80 Type

I, having additional characteristics as

recommended by an Alberta Energy

Utility Board directive.10

To have a trouble-free bottom hole

assembly for longevity, it is suggested to

have the CRA bottom hole component †Trade name.

FIguRE 3

Well completion design for AGI injector well.


M A T E R I A L S S E L E C T I O N & D E S I G N Construction Materials for Acid Gas Pipelines and Injection Wells

of casing joined to the CS string above up

to the wellhead. The CRA for the bottom

portion of the casing string should be

N08825. The casing is set at the top of

the gas injection zone. The injection zone

is open hole. Packers and their associated

equipment have to be chosen for longev-

ity. Inner mandrels are N08825, as are

the packer bodies below the packer seal-

ing element. Packer elements are specially

formulated nitrile rubber and seal assem-

blies are acid-resistant materials.

For facilitating well maintenance in

the future, a wire line retrievable subsur-

face safety valve may have to be installed

at the time of initial well construction.

The wire line retrievable subsurface

safety valve, its landing nipple, and selec-

tive lock mandrels should be N08825.

Acid-resistant seals can be used in the

safety valve and lock. The control line

termination should be through the bon-

net, not the tubing head side outlets, to

ensure safer completion and work-over

operations. Cement behind the casing

can be attacked by acid gas; therefore,

acid-resistant cement is suggested in the

lower portion of the well bore.

ConclusionsDisposal of acid gas through injection

to a reservoir prevents its emission to the

atmosphere. The wet acid gas is highly

corrosive to steel pipelines and equipment.

The advantage of the auto-dehydration of

acid gas during compression can be

achieved through proper design of com-

pression stages and use of suitable MOCs.

Materials have been identified for piping,

equipment, and well tubulars for AGI in-

jector wells, and a typical well completion

design has been incorporated.

AcknowledgmentsThe authors thank the ONGC man-

agement for providing the necessary

study infrastructure and its gracious ap-

proval for publication of this article.

References

1 G.J. Duncan, C.A. Hartford, Petro-Canada Oil & Gas, “Get Rid of Greenhouse Gases by Downhole Disposal-Guidelines for Acid Gas Injection Wells,” SPE paper no. 48923 (Dallas, TX: SPE, 1998).

2 E. Wichart, T. Rouan, “Acid Gas Injec-tion Eliminates Sulphur Recovery Ex-pense,” Oil and Gas J. (April 28, 1997).

3 S.G. Jones, D.R. Rosa, J.E. Johson, “Lisbon Gas Plant Installs Acid Gas Enrichment, Injection Facility,” Oil and Gas J. (March 1, 2004).

4 C.M. Schillmoller, “Selection of Corro-sion Resistant Alloy Tubulars for Off-shore Applications,” NiDI Technical Series No. 10035 (Toronto, ON, Can-ada: Nickel Development Institute).

5 J.J. Carroll, “Water Content of Acid Gas and Sour Gas from 100 to 220 °F and Pressures to 10,000 psia,” 81st Annual GPA Convention proc., Dallas, TX, March 11-13, 2002.

6 NACE MR0175/ISO 15156, “Petroleum and natural gas industries—Materials for use in H

2S-containing

environments in oil and gas production (Houston, TX: NACE International).

7 J.J. Carroll, S. Wang, “Model Calculates Acid Gas Injection Profiles,” Oil and Gas J. 104, 33 (Sept. 2004).

8 J.J. Carroll, “Phase Equilibria Relevant to Acid Gas Injection: Part 1— Nonaqueous Phase Behaviour,” JCPT 41, 6 (2002).

9 J.J. Carroll, “Phase Equilibria Relevant to Acid Gas Injection: Part 2—Aqueous Phase Behaviour,” JCPT 41, 7 (2002).

10 Alberta Energy Utility Board, Canada, Directive 010, “Minimum Casing Re-quirement,” June 2008.

SubRAhMANyA bhAT is chief chemist and in charge

of the Materials & Corrosion Laboratory, Oil and

Natural Gas Corp., Ltd. (ONGC), Materials &

Corrosion Section, IEOT, Panvel, Navi Mumbai,

Maharashtra 410221, India, e-mail: subrahmanya.

[email protected]. A postgraduate in analytical

chemistry, he has worked for the past 27 years in

hydrocarbon exploration and production activities

in India, with more than 17 years in materials and

corrosion studies. he has executed 65 projects

pertaining to MOCs for oilfield installations, failure

analysis, corrosion audits of subsea pipelines, and

corrosion inhibitor studies. his major contributions

are in the area of identifying suitable MOCs for

well completion, flow lines, process vessels, and

trunk lines for extremely severe sour gas field

developments. his innovative use of CRA bottom

portions with top CS casings and a couple in

between to prevent galvanic corrosion for in situ

combustion injector wells has been implemented

successfully in heavy oil fields in western India. he

formulated a noncarcinogenic corrosion inhibitor

for high-density well completion brines, and filed

for a patent in 2007. he has published more than a

dozen papers and presented papers in conferences.

A member of NACE, he is the recipient of the

prestigious NACE International India Section

National Award for Excellence in Corrosion Science

(2005).

bIPIN KuMAR is a mechanical engineer at ONGC.

he worked at the company for 17 years in various

capacities as I/C of mechanical maintenance,

operations, and planning and provisioning parts for

rig equipment. he has been involved in various

aspects of corrosion and its control, particularly

failure analysis and material selection. his

significant contributions are in material selection

for sour gas field development, marginal field

developments, and gas sweetening plants. he is

credited with a certificate course on advanced

pipeline engineering from the Indian Institute of

Technology in Mumbai.

DIPANKA bAIShyA is an electrical engineer at ONGC.

he has worked for the company for 17 years in

various capacities as I/C of electrical maintenance,

safety, and planning and provisioning parts for

onshore drilling rigs. he worked as a project

engineer in offshore engineering for five years and

was involved in the execution of two large offshore

projects. he has been involved in various aspects

of corrosion and its control, particularly failure

analysis and material selection, as well as

designing cathodic protection (CP) systems for

enhancing the life of old offshore jackets. he is

trained in pipeline corrosion control by CECRI and

Karaikudi and in CP systems by NACE.

M.V. KATARKI is general manager and head of the

Materials & Corrosion Section at ONGC. he started

with the company in 1973 and was responsible for

the construction of installations and pipelines for

various onshore and offshore oil and gas fields. he

is experienced in CP of long-distance cross-country

oil and gas trunk pipelines and maintenance of

infield pipelines and installations. he was the

group head involved in materials selection

for a wide range of operating conditions, failure

analysis, and various aspects of corrosion

problems in oilfield equipment, piping, and

pipelines. he retired from ONGC in May 2010.



www.nace.org

www.nace.org/education

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Review of Caustic Soda Service Chart

for Carbon Steel

AvtAndil KhAlil BAirAmov, SABIC Technology Center-Jubail, Saudi Arabia

A NACE International standard practice that

provides guidance for the design, fabrication, and

maintenance of carbon steel equipment and piping

exposed to caustic environments features a chart well-

known in the industry. If the user of the standard

does not review the supporting verbiage, the chart

may be misunderstood regarding material selection

below 5 wt%. Recommendations are made for

modifications to the chart to avoid this confusion.

It has become very clear over the

years, after numerous discussions

with industry, that the well-known

chart for carbon steel (CS) in caustic

service (Figure 1)1-3 can cause some con-

fusion during material selection and

application at lower concentrations

(<5 wt%). Furthermore, it appears that

most plant personnel do not always find

the time to read the details in the accom-

panying write-up and that they simply

refer to the chart as if it were a stand-

alone document. Moreover, plant person-

nel do not often consult corrosion experts

for interpretation, so the ease of interpre-

tation and clarity of this chart become

crucial. As a result, the chart is mostly

interpreted at face value.

Recommendations

We propose that this chart requires

some further clarification and modifica-

tion as follows:

• Earlier4-5 and in NACE SP0403,3

mention is made that CS could be

used in Area C if the concentration

of the caustic soda is below 5 wt%.

The chart (Figure 1) does not reflect

this, however. Furthermore, from

literature it is clear that if CS is used

in Area C, it must be in the stress-

relieved condition, as is required in

Area B. It is therefore proposed that

the upper curve that separates Area

B and Area C be modified to end at

5 wt% and to continue upward to

300 °F (149 °C),4-5 parallel to the

temperature axis (Figure 2), rather

than the way it is at present (Figure

1). Furthermore, the chart should

have a 5% entry included on the

sodium hydroxide (NaOH) concen-

tration axis for clarity purposes

(Figure 2).

• There are times when a concentra-

tion mechanism is at work and a

bulk solution below 5 wt% can lead

to stress corrosion cracking (SCC);

this is also pointed out in NACE



SP0403.3 API 571,6 however, gives

a more detailed coverage where it is

stated that only caustic solutions

<50 ppm are safe when this concen-

tration mechanism is expected. It is

therefore recommended to include

this in the existing chart (Figure 2).

However, practically, SCC can oc-

cur even below 50 ppm if localized

disturbance in normal environment

flow or localized high heat flow hap-

pen, resulting in very high concentra-

tion of caustic due to the departure

from nucleate boiling mechanism.

At present, the chart curves (Figure 1)

are drawn to include 0% caustic concen-

tration. Zero concentration of NaOH

implies a neutral medium with pH 7,

where actually plain CS with/without

postweld heat treatment (PWHT) can be

used at much higher temperatures, par-

ticularly in boiler feedwater (with a pH

range of 9.5 to 9.8) where there is a high-

temperature inhibitor present. CS with/

without PWHT normally operates at

temperatures up to 446 °F (230 °C) for

over 30 years. Generally, the allowable

temperature for CS is 750 °F (399 °C).7

For this reason it is also recommended to

modify the existing chart as explained

above (Figure 2).

The exact upper temperature limit for

the curves (related to 50 ppm and 5%,

Figure 2) that run parallel to the tem-

perature axis should not be specified

unless research work has been performed

to verify such a limit and probable slope.

From a practical point of view it should

be below the creep temperature limit for

CS (800 °F [427 °C]).8-10 Without the

expected concentration mechanism, no

PWHT is required in Area D.

AcknowledgmentThe author acknowledges the

contribution from Christian van der

Westhuizen, SABIC Manufacturing

Competence Center.

Caustic soda service chart.2

FIguRE 1

References

1 N.E. Hamner, ed., Corrosion Data Survey (Houston, TX: NACE International, 1974).

2 R.S. Treseder, ed., NACE Corrosion Engineer’s Reference Book (Houston, TX: NACE, 1980).

3 NACE SP0403, “Avoiding Caustic Stress Corrosion Cracking of Carbon Steel Refinery Equipment and Piping” (Houston, TX: NACE, 2003 and 2008).

4 A.A. Berk, W.F. Waldeck, “Caustic Danger Zone,” Chemical Engineering 57, 6 (1950): pp. 235-237.

5 H.W. Shmidt, P.J. Gegner, G. Heinemann, C.F. Pogacar, E.H. Wyche, “Stress Corrosion Cracking in Alkaline Solutions,” Corrosion 7, 9 (1951): pp. 295-302.

6 API 571, “Caustic Stress Corrosion Cracking (Caustic Embrittlement)” (Washington, DC: API, 2003).

7 E.S. Beardwood, “Operational Control and Maintenance Integrity of Typical and Atypical Coil Tube Steam Generat-ing Systems,” CORROSION/99, paper no. 338 (Houston, TX: NACE, 1999).

8 F.N. Kemmer, ed., The NALCO Water Handbook, 2nd Ed. (New York, NY: McGraw-Hill, Inc., 1988).




Review of Caustic Soda Service Chart for Carbon Steel


Materials in caustic soda service—applicability modified chart.

FIguRE 2

9 S.C. Stultz, J.B. Kitto, eds., Steam, Its Generation and Use, 40th Ed. (Charlotte, NC: Babcock and Wilcox, 1992).

10 Metals Handbook, Failure Analysis and Prevention, 9th Ed., Vol. 11 (Materials Park, OH: ASM, 1995).

AVTANDIL KHALIL BAIRAMOV is a consultant at Saudi Basic Industries Corp. (SABIC), PO Box 11669, Al-Jubail Indstrial City, 31961, Saudi Arabia, e-mail: [email protected]. He has worked at the company since 1995 and has 45 years of experience in corrosion prevention of metals. He has a B.S. degree from the Moscow Institute of Petrochemical and Gas Industry and a Ph.D. in

chemical resistance of materials and protection from corrosion from Azerbaijan Academy of Sciences in Baku, where he was manager of corrosion in the Electrochemistry Department. He has also conducted research at UMIST in the United Kingdom, the Swedish Corrosion Institute, and Brussels University. Bairamov has published more than 100 technical papers, holds 15 patents, and has authored brochures, book chapters, and numerous failure analyses and materials selection projects implemented in the petrochemical industry, with significant economic impact. A member of NACE since 2005 and a member of the Institute of Corrosion, he received a 2010 NACE Technical Achievement Award.



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72 MATERIALS PERFORMANCE April 2011 NACE International, Vol. 50, No. 472 MATERIALS PERFORMANCE April 2011 NACE International, Vol. 50, No. 4

Temperature Effect on

Hydrogen Permeation of

X56 SteelChuanbo Zheng and guo Yi,

Jiangsu University of Science & Technology, Jiangsu, China

Hydrogen permeation behavior of X56 steel under

different temperatures was investigated. Two

methods were used to calculate hydrogen diffusivity

(D) and subsurface hydrogen concentration (C0).

Results showed that hydrogen permeation current

density increases with temperature. Hydrogen

desorption rate and total hydrogen contents decrease

when the charging temperature increases.

Hydrogen entry into steel is af-

fected by many factors, such as

metal surface roughness,1 mi-

crostructure, traps in steel,2

thickness of specimen, and temperature.

The diffusion of hydrogen in steels has

been widely studied.3-5 Susceptibility of

steels to hydrogen-induced cracking

(HIC) is closely related to metallurgical

parameters, especially distribution of

defects such as nonmetallic inclusions and

secondary phases. Another important

parameter affecting HIC is the environ-

ment to which steels are exposed.

Hydrogen permeation in steels in-

volves several steps: adsorption, dissocia-

tion, dissolution, diffusion, recombina-

tion, and desorption. Since 1962, when

the double cell electrochemical method

was developed by Devanathan and Sta-

churski,6 many researchers have studied

the hydrogen diffusion coefficient of dif-

ferent steels at different conditions.7-9

Hydrogen permeation through a metallic

membrane by an electrochemical tech-

nique is a widely used method for study-

ing hydrogen diffusivity and metallic

embrittlement phenomenon.10-11 The

mechanism behaves as follows:

• Hydrogen atoms are first absorbed

at the entry surface.

• Hydrogen atoms diffuse through the

metallic membrane.

• Finally, they are desorbed from the

exit surface.

In this work, the temperature effect on

hydrogen permeation of X56 steels was

studied by the D-S double cell method.

Thermal desorption spectroscopy (TDS)

was done to measure the hydrogen con-

tent in the specimen. Two methods are

used to calculate the hydrogen diffusivity

(D) and the subsurface hydrogen concen-

tration (C0), and the contributions of D

and C0 to the hydrogen permeation under

different temperatures were determined.



Experimental Procedures

Specimens

The material used for the study was a

commercial X56 grade steel with a

chemical composition (wt%) as shown in

Table 1.

Experimental Setup

The D-S double cell was used to test

the hydrogen diffusivity at different tem-

peratures (Figure 1). A specimen 40 mm

in diameter and 0.7-mm thick was used

as the working electrode. One side of the

specimen was coated with a thin layer of

palladium (Pd). Before the test, the

specimens were carefully cleaned with

alcohol and acetone using an ultrasonic

bath and then dried with cold air.

The two cells were filled with 0.1 M

sodium hydroxide (NaOH), and one was

used as the cathodic charging cell, which

was polarized at a constant current den-

sity (CD) of 2 mA/cm2. The other one

was used as an anodic cell and was kept

at a constant potential vs. Hg/mercuric

oxide (HgO)/0.1 M NaOH. The hydro-

gen content in the specimen was mea-

sured by TDS.

Results and DiscussionFigure 2 gives the permeation curves

at different temperatures. The hydrogen

permeation CD increased temperature,

and the time for hydrogen permeation in

the anodic cell became shorter with in-

creasing temperature.

Two methods are used to calculate the

hydrogen diffusivity D. Table 2 shows the

calculated value.

Equation (1) shows the time to break-

through method tb:

TAbLE 1

Chemical composition (wt%) and mechanical properties of the tested line pipe steel

Steel C Mn P S

Yield Strength

s (MPa)

Ultimate Tensile

Strength sb (MPa)

X56 0.22 1.4 0.025 0.015 386 490

The experimental setup.

Permeation curves of X56 at different temperatures.

FIguRE 1

FIguRE 2


M A T E R I A L S S E L E C T I O N & D E S I G N Temperature Effect on Hydrogen Permeation of X56 Steel

Figure 3 shows the log(D) vs. 1/T and

linear regression fits for the sample, and

the activation energy was calculated.

Equation (4) shows the time to break-

through method:

Q = 36.8 kJ/mol (4)

The time lag method is:

Q = 25.6 kJ/mol (5)

The calculated activation energy

shows accordance with H. Addach.12 The

energy is not high, so the temperature

effect on hydrogen diffusivity should be

strong.

Ferro13 assumed that the energy of

activation for diffusion was the energy

required to accommodate a diffusing

hydrogen atom arriving from a neighbor-

ing site. And he considered the rate-

determining step in the diffusion of hy-

drogen in the creation of sites (distorted

octahedral holes) into which hydrogen

can enter. W. Beck14 considered that dif-

fusion is the rate-determining step of the

permeation of hydrogen. In this work, the

passivation current of X56 steel was mea-

sured. The results show that passivation

CD increases with temperature. This

indicates that more hydrogen atoms were

leaving the metal crystal lattices and were

detected by the anodic cell.

For the determined hydrogen diffusiv-

ity, the subsurface hydrogen concentra-

tion C0 is calculated by the following

equation:

(6)

where F is Faraday’s constant, I∞ is the

steady-state CD, and L is the specimen

thickness.

Figure 4 shows the calculated C0

change trends with temperature change.

TAbLE 2

“D” values calculated by two methods

25 30 35 40 45

D (tb method) 1.78 × 10–10 2.39 × 10–10 2.65 × 10–10 3.05 × 10–10 3.66 × 10–10

D (tL method) 3.12 × 10–10 4.71 × 10–10 5.61 × 10–10 7.12 × 10–10 8.53 × 10–10

Log(D) vs. 1/T and linear regression.

FIguRE 3

(1)

where tb is found by extrapolating the

linear portion of the initial hydrogen

permeation current transient to it = 0.

L is the specimen thickness.

Equation (2) shows the time-lag

method, tL:

(2)

The time of tL corresponds to the point

on the permeation curve at which it =

0.63 i∞. L is the specimen thickness.

In Table 2, the D values calculated by

two methods also show an increasing

trend with temperature increasing.

Molecular motion increases with in-

creased temperature. At higher tempera-

ture, diffusion of hydrogen was acceler-

ated, so hydrogen diffusivity increased

with temperature.

Hydrogen entry into steel and subse-

quent permeation through steel needs

energy. Using the diffusivity data, the

temperature dependence of diffusivity

was fitted to the Arrhenius relationship:

D = D0 exp(–Q/RT) (3)

where D0 is a temperature-independent

constant, Q (J/mol) is the activation en-

ergy for diffusion, R (J/mol K) is the gas

constant, and T (K) is the temperature.

Temperature (°C)



FIguRE 4

FIguRE 5

Calculated C0 change trends with temperature change.

The hydrogen desorption rate at different charging temperatures.

The C0 has an increasing trend with

temperature increase. When the tem-

perature reached 35 °C, the C0 increased

sharply.

The hydrogen content in the specimen

was measured by TDS. Figure 5 shows

the hydrogen desorption rate at different

charging temperatures. The hydrogen

desorption rate decreases with the charg-

ing temperature increases. The calculated

total hydrogen content is 1.22, 1.04, and

0.76 ppm at 25, 35, and 55 °C. This may

be because the solubility of hydrogen in

steel decreases with temperature increase.

Compared with the calculated C0, the

surface hydrogen concentration increases

with temperature, and the total hydrogen

content in the metal decreases as tem-

perature increases. Adsorption and de-

sorption effects are enhanced with tem-

perature, the concentration difference

becomes bigger, and the hydrogen per-

meation current increases.

Table 3 lists the contribution of hydro-

gen diffusivity D to hydrogen permeation

CD. According to the relationship:

I∞ = C0DF/L (7)

where L is the specimen thickness, which

is a constant value. So the hydrogen per-

meation current increase may be the re-

sult of the increase of D or C0 or both.

Table 3 shows that the contribution of D

is more than 60%, calculated by the two

methods. So with temperature increase,

the contribution of D to the hydrogen

permeation current is larger than C0.

Conclusions

Experimental results show that hydro-

gen permeation CD increases with tem-

perature because the two factors D and

C0 increase with temperature, and the

contribution to the hydrogen permeation

CD of D is more than that of C0. The

activation energy is not very high, so the

temperature effect in hydrogen perme-

ation current is strong. Adsorption and


www.nace.org/nacestore

TAbLE 3

“D” contribution to hydrogen permeation current

25-30 (%) 30-35 (%) 35-40 (%) 40-45 (%)

D (tb method) 89 90 65 78

D (tL method) 91 94 70 79


Temperature Effect on Hydrogen Permeation of X56 Steel

desorption effects are enhanced with

temperature increase; the hydrogen per-

meation current increases with tempera-

ture because the concentration difference

becomes larger.

AcknowledgmentThis work was financially supported

by the Natural Science Foundation of

China (No. 51001055).

References

1 R. Requiz, N. Vera, S. Camero, Revista de Metalurgia 40, 1 (2004): pp. 30-38.

2 J. O’M. Bockris, P.K. Subramanyan, J. Electrochem. Soc. 118, 7 (1971): pp. 1,114-1,119.

3 A.M. Brass, J.R. Collet-Lacoste, Acta Mater. 46 (1998): pp. 869-875.

4 Y.F. Cheng, Corros. Sci. 32 (2007): pp. 1,269-1,276.

5 A. Turnbull, M.W. Carroll, Corros. Sci. 30 (1990): pp. 667-679.

6 M. Devanathan, Z. Stachurski, Proc. R. Soc. 270A (1962): p. 90.

7 S.Wach, Br. Corros. J. 6 (1966): pp. 271-279.

8 A.J. Kumnick, H.H. Johnson, Metall. Trans. 5A (1974): pp. 621-622.

9 F.H. Heubaum, B.J. Berkowitz, Scr. Metall. 16 (1982): pp. 659-664.

10 M. Devanathan, Z.J. Stachurski, Electrochem Soc. 111 (1964): pp. 619-626.

11 R.A. Oriani, Acta Metall. 18 (1970): pp. 147-153.

12 H. Addach, P. Bercot, et al., Materials Letters 59 (2005): pp. 1,347-1,351.

13 A. Ferro, 1957, J. Appl. Phys. 28, 895.

14 W. Beck, J.O’M. Bockris, et al., Mathematical, Physical & Engineering Sciences 290 (1966): pp. 220-235.

CHUANBO ZHENG is a researcher at the Jiangsu

University of Science and Technology, No. 2,

Mengxi Rd., Zhenjiang, Jiangsu 212003, China,

e-mail: [email protected].

GUO YI is a researcher at the Jiangsu University of

Science and Technology.

NACE Releases SP0199-2009

Revised Standard

NACE Members: Download this standard for free at www.nace.org/nacestore!

Can you afford $17.3 billion? Following technical specifications and practices that prevent corrosion in air pollution control equipment is critical to reducing this cost.NACE SP0199-2009, “Installation of Stainless Chromium-Nickel Steel and Nickel-

Alloy Roll-Bonded and Explosion-Bonded Clad Plate in Air Pollution Control

Equipment,” provides design, fabrication, and installation personnel with a basis for

contract specifications when using these alloys, including:

• Material specifications• Weld joint design• Welding and installation practices• Inspection and repair of welds

List: $37NACE Member: $28 (for a printed copy of the standard)Item # 21087

Temperature (°C)

— Next Month in MP —

Editorial Focus:

Pipeline Corrosion

Premature Failure of a

New Gathering Station Pipeline

Microstructural Analysis of

Ethylene Furnace Steel

Alloy Tubes

Applications for Battery-Powered

Cathodic Protection

Remote Monitoring

Redefining Antifouling

Coating Technology

Brass Dezinctification

Performance Testing in

Potable Water

Special Feature:

Solar-Powered Cathodic

Protection of Fuel and

Water Pipelines at a

U.S. Naval Station

http://www.nace.org/nacestorewww.nace.org/nacestore



NACE NewsYour Association in Action

The NACE Annual Career and Salary Survey Is Expanding to Europe

Materials Perfor-

mance maga-

zine is expand-

ing its annual

career and sal-

ary survey in 2011 to include

NACE International mem-

bers in Europe as well as the

United States and Canada.

Starting this year, the survey

questionnaire will be sent

to NACE members in the 17

European Union countries

that use the Euro as their

currency—Austria, Belgium,

Cyprus, Estonia, Finland,

France, Germany, Greece,

Ireland, Italy, Luxembourg,

Malta, The Netherlands,

Portugal, Slovakia, Slovenia,

and Spain.Within the next few weeks, NACE

members in the United States, Canada,

and the aforementioned European coun-

tries who have provided NACE with a

valid e-mail address will receive a link to

the 2011 annual career and salary sur-

vey questionnaire via e-mail. If a survey

questionnaire link is e-mailed to you, the

MP staff asks that you please take a few

moments to fill out the form and return

it. The questionnaires are supported

with online survey software and responses

are anonymous.

Results of the career and salary sur-

vey are extremely valuable to NACE

members and the corrosion control com-

munity at large. They provide NACE

members with the opportunity to share

the latest information on their educa-

tion, work experience, job duties, and

annual compensation and gain insight

on career trends in the corrosion control

industry.

Last year, a record number of mem-

bers participated in the survey—2,186

from the United States and 314 from

Canada. So that the survey results rep-

resent an even larger base of corrosion

professionals in 2011, the MP staff would

like to see more members participate.

Results will be published in the July 2011

issue of MP. (—Kathy Larsen)

MP welcomes submissions of

NACE News. Please send articles

and photos to Gretchen Jacobson,

MP Managing Editor,

1440 South Creek Dr.,

Houston, TX 77084-4906, e-mail:

[email protected].



N A C E N E W S The Association in ActionNACE OFFICERS

PRES IDENTO.C. Moghissi*

DNV Dublin, OH

V ICE PRES IDENTK.C. Garrity*Mears Group Plain City, OH

TREASURERJ.L. Didas*

Colonial Pipeline Co. Richmond, VA

PAST PRES IDENTC.M. Fowler* Exova Group

Dudley, West Midlands, U.K.

EXECUT IVE D IR ECTORR.H. Chalker*

NACE InternationalHouston, TX

D IRECTORSM.K. Baach/2009-2012 The Philpott Rubber Co.

Brunswick, OH

G.E.C. Bell/2009-2012 HDR|Schiff

Claremont, CA

A.I. Williamson/2009-2012 Ammonite Corrosion Engineering, Inc.

Calgary, AB, Canada

A.M. Al-Zahrani/2010-2013 Saudi Aramco

Dhahran, Saudi Arabia

M. Ames/2010-2013 SAE, Inc.

Humble, TX

J.E. Feather/2010-2013ExxonMobil Research & Engineering

Fairfax, VA

S. Olsen/2010-2013 Statoil Hydro

Trondheim, Norway

J.M. Sapp/2010-2013 Mesa Products, Inc.

Tallahassee, FL

L. Uller/2010-2013 SURPLUS

Rio de Janeiro, RJ, Brazil

S. Degan/2011-2014Osnar Paints and Contracts Private, Ltd.

Mumbai, India

W.G. Mueller/2011-2014Allied Corrosion Industries, Inc.

Marietta, GA

D.A. Schramm/2011-2014EN Engineering, LLC

Woodridge, IL

*Executive Committee members

NACE Area and Section News

Members of the Texas-Louisiana Gulf

Section listen to a talk during the February

2011 meeting.

Central Area

The NACE International Hous-

ton Section and the Texas-

Louisiana Gulf Section based

in Beaumont, Texas, both had record

attendance in February: 96 attendees in

Houston and 55 attendees in Beaumont.

East Asia & Pacific Area

The NACE International Gate-

way India Section (NIGIS) is

organizing the CORCON 2011

Corrosion Conference and Expo, to be

held September 28 to October 1, 2011,

at the Hotel Intercontinental–The Lalit in

Mumbai, India. NIGIS organized its first

corrosion conference in 1994 and started

the CORCON series of conferences in

1997. CORCON 2011 will include:

■■ Technical Symposia for the

presentation of papers, including

keynote talks

■■ Open sessions for discussions of

corrosion-related issues

■■ Talks by eminent scientists and

professionals

Strong speakers, great networking op-

portunities, and steadily growing num-

bers are responsible for the success. The

volunteerism of section board members

in putting together section activities has

given both sections and their members

new opportunities for learning, meeting

their peers, and getting involved with

NACE. Both sections now offer members

an opportunity to pay for meetings online,

sponsor section activities, and post their

ideas and comments to the section Web

sites. The Houston Section meets the sec-

ond Tuesday of each month (www.nace-

houston.org) and the Texas-Louisiana Gulf

Section meets the third Tuesday of each

month (www.nace-txlagulfsection.org).

Congratulations on the growth of both

sections’ meetings! (—Jane Brown)

■■ An expo for display of products and

services

■■ Celebration of Corrosion Awareness

Day and the presentation of

annual awards to individuals and

organizations for their contributions in

the field of corrosion and its control.

Held in Goa, India, last year, COR-

CON attracted 650 delegates, 26 sup-

porters, 58 exhibitors, several keynote

talks, and more than 110 technical

papers. The annual event provides an

excellent opportunity for sharing knowl-

edge and experiences related to the sci-

ence of corrosion and the technologies to

control it and for developing a network of

contacts contributing to the growth and

development of the corrosion field. It is a

unique opportunity for meaningful inter-

actions between owners, suppliers, service

providers, consultants, and academics.

For more information on CORCON

2011, please e-mail [email protected]

or see the Web site: www.corcon.org.

(—Manoj Mishra)

http://www.nace-houston.org

http://www.nace-txlagulfsection.org



http://www.nace-houston.org


Northern Area

Kevin Reaville (Conoco Phillips), Doug

Kellow (Weatherford International),

and Den Dutton (Anotec) enjoying the

conference.

Mario Moreno of Carboline Co. and NACE

Conferences & Exhibits Associate Allison

Polka at the NACE booth.

Usually when one thinks of Re-

gina, Canada, in winter, heat

really does not come to one’s

mind. But the NACE International

Northern Area Western Conference

brought the heat to Saskatchewan with

its first ever conference dedicated to cor-

rosion issues in carbon capture and stor-

age projects. Each registrant was given a

NACE “tuque” to “Capture the Heat”

and help combat the –29 °C ambient

temperatures.

The two-day technical program

focused on carbon dioxide (CO2) corro-

sion considerations for carbon capture

and storage projects with speakers from

a number of countries. There was also a

second technical track covering conven-

tional oil and gas corrosion topics in wells,

pipelines, and facilities.

The event began with an opening

reception and a viewing of the Super

Bowl XLV game between the Pittsburgh

Steelers and the Green Bay Packers. A

great game and atmosphere contributed

to a relaxing evening for colleagues and

peers. Greeting and opening remarks

were given by conference Chair and

Northern Area Director Sandy William-

son, NACE President Chris Fowler, and

NACE Executive Director Bob Chalker.

The exhibit hall was sold out and

buzzing with activity and valuable

exchanges of information. A student

poster session included participants

from Calgary, Alberta, and Regina Uni-

versities. The first-place winners were

Ameerudeen Najumudeen, Amornvadee

Veawab, and Adisorn Aroonwilas of the

University of Regina with a poster on

“Mechanistic Corrosion Model for CO2

Capture Plants Using Aqueous MEA

Solutions.” Prize money was presented

by Sandy Williamson on behalf of the

NACE Foundation of Canada.

Thank you once again to all confer-

ence sponsors, exhibitors, conference

organizers, and NACE staff members

Left to right: Northern Area Western

Conference Chair Sandy Williamson;

Student Poster Judge Sankara

Papavinisam; Student Poster winners

Ameerudeen Najumudeen, Qing Xun Low,

and Prakaspathi Gunasekaran; Judge

Jenny Been; and NACE President Chris

Fowler.

Renata Briscoe and Allison Polka for

contributing to such a successful event.

(—Laura Cardenas)

The Northern Area thanks the

following sponsors and exhibitors for

their support of the conference:

SPONSORS

■■ Ammonite

■■ Anotec

■■ Baker Hughes/Baker Petrolite

Canada

■■ Champion Technologies

■■ Commercial Sandblasting &

Painting

■■ Corrosion Technologies, Ltd.

■■ Deepwater Corrosion Services

■■ DENSO

■■ Enerclear

■■ Fibreglass Solutions, Inc.

■■ HTC Purenergy

■■ International Paint/Devoe Coatings

■■ Multichem

■■ Pipe Tech

■■ Prairie Petro-Chem

■■ Ranger Inspection

■■ Target Products

EXHIBITORS

■■ Advance Product Systems

■■ Alta West Cathodic/Anotec

Industries

■■ Carboline

■■ Champion Technologies

■■ CriticalControl Energy Services,

Inc.

■■ Corrosion Service Co., Ltd.

■■ Deepwater Corrosion

■■ Denso North America

■■ Droycon Bioconcepts

■■ Elecsys Pipeline Watchdog

■■ Fibreglass Solutions, Inc.

■■ General Paint/Amercoat Canada

■■ General Sandblasting & Painting

■■ Interprovincial Corrosion Control

■■ Nilex

■■ Pikotek

■■ Pipetech Corp., Ltd.

■■ Rolled Alloys Canada

■■ Sapphire Technologies

■■ Specialty Polymer Coatings, Inc.

■■ Stone Tucker Instruments

■■ The Sherwin Williams Co.

■■ TISI Canada, Inc.

■■ Weatherford


NACE International Corporate MembersMP publishes the names of all Platinum and Gold Corporate Members in each issue, in addition to that month’s new

corporate members of all levels. Following are the companies that are in these categories as of February 15, 2011:

Platinum

■■ BP Exploration & Production

Operating Co., Ltd., Sumbry-

on-Thames, Middlesex, United

Kingdom

■■ Carboline Co., St. Louis, Missouri

■■ Champion Technologies, Ltd.,

Houston, Texas

■■ Corrpro Companies, Inc.,

Houston, Texas

■■ Deepwater Corrosion Services,

Inc., Houston, Texas

■■ Denso, Houston, Texas

■■ DNV, Dublin, Ohio

■■ EMS Group, Houston, Texas

■■ Exova, Dudley, West Midlands,

United Kingdom

■■ Greenman-Pedersen, Inc., Port St.

Lucie, Florida

■■ International Paint, LLC,

Strongsville, Ohio

■■ MATCOR, Inc., Doylestown,

Pennsylvania

■■ MESA Products, Inc., Tulsa,

Oklahoma

■■ National Grid, Waltham,

Massachusetts

■■ RINA SpA, Ltd., Portsmouth,

United Kingdom

■■ Saipem SpA, San Donato

Milanese, Italy

Gold

■■ Alpha Leak Detection & Pipeline

Services, Kemah, Texas

■■ APAVE International, Artigues

Pres Bordeaux, France

■■ Atmos Energy, Jackson, Mississippi

■■ Baker Hughes, Sugar Land, Texas

■■ Bechtel Group, Inc., Houston,

Texas

■■ Corrosion Technology Services,

LLC, Sharjah, United Arab

Emirates

■■ El Paso Pipeline Group, Houston,

Texas

■■ Enerplus Resources Fund, Calgary,

Alberta, Canada

■■ E-Tech Oilfield Technology

Development Co., Ltd., Tianjin

City, Tianjin, China

■■ Evraz, Inc., Regina, Saskatchewan,

Canada

■■ Galvotec Alloys, Inc., Harvey,

Louisiana

■■ GL Noble Denton, Houston, Texas

■■ Haynes International, Kokomo,

Indiana

■■ High Performance Alloys, Inc.,

Tipton, Indiana

■■ Interprovincial Corrosion Control,

Burlington, Ontario, Canada

■■ Kuwait Pipe Industries and Oil

Services, Safat, Kuwait

■■ NICOR Gas, Naperville, Illinois

■■ Polyguard Products, Inc., Ennis,

Texas

■■ RASCO International, Ltd.,

Rassouli-elchin, Mustafa E., Baku,

Azerbaijan

■■ RK&K, LLP, Concord, North

Carolina

■■ Rosen Group, Stans, NW,

Switzerland

■■ Sherwin-Williams Co., The,

Cleveland, Ohio

■■ Sui Northern Gas Pipelines, Inc.,

Lahore, Pakistan

New Corporate Members

■■ Cascade Natural Gas Corp.,

Kennewick, Washington—Silver

■■ Unique Corrintec, Sharjah, United

Arab Emirates—Silver

■■ Corrodys, Cherbourg-Octeville,

France—Bronze

■■ John D. Mercer & Associates, Inc.,

Galveston, Texas—Bronze

■■ Alpaccess, Ploiesti, Romania—

Nickel

■■ Aztech Training & Consultancy,

Dubai, United Arab Emirates—

Nickel

■■ Bunduq Oil Co., Ltd., Abu Dhabi,

United Arab Emirates—Nickel

■■ Chemsain Konsultant Sdn Bhd,

Kuching, Malaysia—Nickel

■■ Forrest Services, La Porte, Texas—

Nickel

■■ KPS Technology & Engineering

LLC, Overland Park, Kansas—

Nickel

■■ Silvion, Ltd., Grantham, United

Kingdom—Nickel

Total NACE membership was

25,723 as of February 15, 2011—the

highest in NACE history. For more

information about NACE corporate

membership levels and individual

member benefits, contact the First-

Service department at phone: +1

281-228-6223 or e-mail: firstservice@

nace.org.

N A C E N E W S The Association in Action




NACE COURSE SCHEDULE APRIL–JUNE 2011

CIP Level 1April 11-16, 2011Lima, Peru

April 16-21, 2011Al-Khobar, Saudi Arabia

April 17-22, 2011Houston, TX

April 17-22, 2011Shanghai, China

April 23-28, 2011Jeddah, Saudi Arabia

April 25-30, 2011Chennai, India

April 25-30, 2011Uraga, Japan

May 1-6, 2011Houston, TX

May 1-6, 2011Virginia Beach, VA

May 2-7, 2011Kochi, India

May 2-7, 2011Perth, WA, Australia


May 9-14, 2011Mumbai, India

May 9-14, 2011Rio de Janeiro, Brazil

May 14-19, 2011Doha, Qatar


May 22-27, 2011Dubai, U.A.E.

May 23-28, 2011Kuala Lumpur, Malaysia

May 26-31, 2011Imabari, Japan June 4-9, 2011Abu Dhabi, U.A.E.

June 5-10, 2011Houston, TX

June 5-10, 2011Norfolk, VA

June 5-10, 2011Marabella, Trinidad


June 6-11, 2011Chennai, India

June 6-11, 2011Jakarta, Indonesia

June 6-11, 2011Brisbane, QLD, Australia

June 12-17, 2011Amherst, NY

June 12-17, 2011Shanghai, China

June 13-18, 2011Cuernavaca, Mexico



June 20-25, 2011Beijing, China

June 20-25, 2011Auckland, New Zealand

June 20-25, 2011Makati City, Philippines

June 22-27, 2011Uraga, Japan


June 26-July 1, 2011Houston, TX

June 27-July 2, 2011Mumbai, India

CIP Exam Course 1April 11-13, 2011Newcastle-upon-Tyne, U.K.


June 20-22, 2011Daejeon, Korea

CIP Level 2April 11-16, 2011Newcastle-upon-Tyne, U.K.

April 11-16, 2011Sydney, NSW, Australia

April 14-19, 2011Uraga, Japan

April 17-22, 2011Anchorage, AK

April 24-29, 2011Shanghai, China

May 1-6, 2011Genoa, Italy

May 2-7, 2011Makati City, Philippines



May 9-14, 2011Perth, WA, Australia

May 16-21, 2011Mumbai, India

May 28-June 2, 2011Dubai, U.A.E.

May 30-June 4, 2011Kuala Lumpur, Malaysia

June 11-16, 2011Abu Dhabi, U.A.E.


June 12-17, 2011Marabella, Trinidad

June 13-18, 2011Chennai, India

June 13-18, 2011Jakarta, Indonesia

June 13-18, 2011Brisbane, QLD, Australia




June 27-July 2, 2011Beijing, China CIP Exam Course 2April 14-16, 2011Newcastle-upon-Tyne, U.K.


June 23-25, 2011Daejeon, Korea

CIP Level 2, Marine Emphasis May 22-27, 2011Houston, TX

May 28-June 2, 2011Dubai, U.A.E.

CIP Peer ReviewApril 15-17, 2011Houston, TX

April 15-17, 2011St. Louis, MO

April 15-17, 2011Vallejo, CA

April 15-17, 2011Anaheim, CA

April 15-17, 2011Newcastle-upon-Tyne, U.K.

April 22-24, 2011Anchorage, AK



June 2-4, 2011 Dubai, U.A.E.



CIP 1 Day Bridge CourseMay 7, 2011Virginia Beach, VA

June 11, 2011Houston, TX

Coatings in Conjunction with Cathodic ProtectionMay 8-13, 2011Amarillo, TX


CP Interference June 19-24, 2011Downey, CA

CP1—Cathodic Protection Tester April 11-16, 2011Johannesburg, South Africa

April 30-May 5, 2011Jeddah, Saudi Arabia

May 2-7, 2011Lima, Peru

May 21-26, 2011Doha, Qatar



CP2—Cathodic Protection Technician April 18-23, 2011Beijing, China

May 7-12, 2011Jeddah, Saudi Arabia

May 9-14, 2011Lima, Peru

May 22-27, 2011Tulsa, OK

May 22-27, 2011Claysville, PA

May 22-27, 2011Kilgore, TX


June 12-17, 2011Downey, CA


CP3—Cathodic Protection TechnologistApril 16-21, 2011Fahaheel, Kuwait


May 16-21, 2011Beijing, China


CP4—Cathodic Protection SpecialistApril 23-28, 2011Fahaheel, Kuwait


June 13-18, 2011Beijing, China


Offshore Corrosion Assessment Training (O-CAT)June 6-10, 2011Houston, TX


Shipboard Corrosion Assessment Training (S-CAT)May 16-20, 2011Houston, TX



Basic CorrosionApril 18-22, 2011Houston, TX

May 9-13, 2011Amarillo, TX

May 9-13, 2011Beaumont, TX

May 16-20, 2011London, U.K.




Designing for Corrosion ControlApril 18-22, 2011Dartmouth, NS, Canada

April 30-May 4, 2011Al-Khobar, Saudi Arabia


May 23-27, 2011London, U.K.

Corrosion Control in the Refining IndustryApril 11-15, 2011Houston, TX

Internal Corrosion for Pipelines—BasicMay 7-11, 2011Al-Khobar, Saudi Arabia


May 9-13, 2011Makati City, Philippines


Pipeline Corrosion Integrity ManagementMay 16-20, 2011Houston, TX


Meetings & EventsN A C E N E W S The Association in Action

EVENT DATE/LOCATION CONTACT NACE

EVENT

MAY 2011

45th Annual Western States Corrosion

Seminar

May 3-5, 2011

Pomona, CA

Sylvia Hall, phone: +1 323-564-6626, e-mail:

[email protected], Web site: www.

westernstatescorrosion.org/registration.html

l

SF EXPO CHINA 2011 (The 9th Guangzhou

International Surface Finishing,

Electroplating and Coating Exhibition)

May 11-13, 2011

Guangzhou, China

Rita Lee, Wise Exhibition (Guangdong)

Co., Ltd., phone: +86-20-87350040, e-mail:

[email protected], Web site: sf-expo.cn/

en

Appalachian Underground Corrosion Short

Course

May 17-19, 2011

Morgantown, WV

Danielle Petrak, AUCSC Committee, phone:

+1 304-293-4307, e-mail: danielle.petrak@

mail.wvu.edu, Web site: www.aucsc.com

Sustainability of Materials Symposium May 18-19, 2011

Niskayuna, NY

Raul Rebak, phone: +1 518-387-4311,

Web site: www.asmeasternny.org/spring-

symposium.html

JUNE 2011

58th Annual Corrosion Course June 8-10, 2011

Norman, OK

Betty Kettman, phone: +1 405-325-3891,

fax: +1 405-325-7329, e-mail: bettyk@

ou.edu, Web site: www.engr.outreach.ou.edu/

corrosion/registration.html

l

JULY 2011

DoD Corrosion Conference 2011 July 31-August 5, 2011

La Quinta, CA

CaLae McDermott, phone: +1 281-228-6263,

e-mail: [email protected], Web site:

www.nace.org/DoD2011

l

AUGUST 2011

NACE Northern Area Eastern Conference

2011

August 14-17, 2011

Ottawa, ON, Canada

Renata Briscoe, phone: +1 281-228-6217,


www.nace.org/northernareaeastern

l

NACE Central Area Conference 2011 August 28-31, 2011

Grapevine, TX



www.nace.org/centralarea

l

SEPTEMBER 2011

EUROCORR 2011 September 5-8, 2011

Stockholm, Sweden

Web site: www.eurocorr.org

Corrosion Technology Week 2011 September 18-22, 2011

Las Vegas, NV


e-mail: [email protected]

CORCON Corrosion Conference & Expo

2011

September 28-October

1, 2011

Mumbai, India

Phone: +91-22-25797354, e-mail: info@

corcon.org, Web site: http://events.nace.org/

images/corcon2011.pdf

l

OCTOBER 2011

NAI Coating Show 2011 October 4-6, 2011

Cincinnati, OH



www.naicoatingshow.com

l

Materials Science & Technology (MS&T)

2011 Conference

October 16-20, 2011

Columbus, OH

Co-Sponsored by NACE, ASM, American

Ceramic Society, Association for Iron & Steel

Technology, and The Minerals, Metals &

Materials Society, e-mail: customerservice@

ceramics.org, Web site: ceramics.org

l

MARCH 2012

CORROSION 2012 Conference & Expo—

Call for Papers Opens January 2011

March 11-15, 2012

Salt Lake City, UT

NACE International, phone: +1 281-228-

6200, e-mail: [email protected]

MARCH 2013

CORROSION 2013 Conference & Expo—

Call for Papers Opens January 2012

March 17-21, 2013

Orlando, FL

NACE International, phone: +1 281-228-

6200, e-mail: [email protected]



http://www.aucsc.com

http://www.asmeasternny.org/spring-symposium.html


http://www.nace.org/DoD2011


http://www.nace.org/northernareaeastern


http://www.nace.org/centralarea

http://www.eurocorr.org



http://www.naicoatingshow.com

http://ceramics.org



http://www.westernstatescorrosion.org/registration.html

http://www.westernstatescorrosion.org/registration.html

http://sf-expo.cn/en

http://sf-expo.cn/en





http://www.engr.outreach.ou.edu/corrosion/registration.html

http://www.engr.outreach.ou.edu/corrosion/registration.html



http://events.nace.org/images/corcon2011.pdf

http://events.nace.org/images/corcon2011.pdf




www.nace.org/awards

http://www.nace.org/awards

C O R R O S I O N E N G I N E E R I N G D I R E C T O R Y


3N International, Inc.

Magnesium Anodes, Aluminum

Anodes, Zinc Anodes, MMO

Prepackaged Magnesium anodes

stocked in multiple locations

Phone: (330) 665-3821 Fax: (330) 665-3823

Web: www.3ninc.com Email: [email protected]

Engineering – Construction – Materials Corrosion Specialists & Professional Engineers

Houston, Texas Mobile, Alabama

Tel (713) 467-6003 Tel 800-241-0809

Fax (713) 467-1174 Fax (770) 425-1354

1550 Cobb Industrial Drive, N.E. Marietta, GA 30066-6611

(770) 425-1355 FAX (770) 425-1354 www.alliedcorrosion.com

A FULL SERVICE CORROSION CONTROL COMPANY SINCE 1984

SURVEYS ● ENGINEERING ● MATERIALS ● CONSULTING ● MAINTENANCE

MAIN OFFICE 10487 North 91st Avenue, #6

Peoria, Arizona 85345 Bus. 623-486-7800 Fax. 623-486-7827

Arizona ● California ● Nevada ● New Mexico ● Texas ● Utah

www.accuratecorrosion.com

CP Technical Services...including D.O.T. Compliance

CP Installations...Deep Wells, Conventional, Tanks Sys

Full Line of CP Materials, Instruments and Accessories

Guthrie, OK

405-293-9777

E-mail: [email protected]

www.cpmasters.com

CORROSION AND MATERIALS TECHNOLOGY, INC.

WILLIAM (BILL) J. NEILL JR., FNACE

PRESIDENT

CORROSION AND MATERIALS ENGINEERING

CONSULTING SERVICES

23 Manchester Drive nace international WestfielD, n.J. 07090-2255 certifieD corrosion (908) 233-3509 specialist no. 622 fax: (908) 233-8966 E-MAIL: [email protected]

ONSHORE/OFFSHORE CATHODIC PROTECTION

SERVICES

10172 Mammoth avenue (225) 275-6131

Baton rouge, la 70814 fax (225) 275-6134

e-mail: [email protected]

Website: www.coastalcorrosion.com

P.O. Box 425 · Medina, OH 44258 Phone: 330/769-3694

Fax: 330/769-2197 Web site: www.bushman.cc


n Corrosion Studies n CP Design & Inspection

n Cost Analysis n Specification Writing

n Training Seminars n Coatings Evaluations

n Expert Witness n Research & Development

BUSHMAN & Associates, Inc.C O R R O S I O N C O N S U L T A N T S

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A D I N D E X

Anotec Industries, British Columbia, Canada ...................................... 41

Phone: +1 604-514-1544, Web site: www.anotec.com

Borin Manufacturing, Culver City, California ...................................... BC

Phone: +1 310-822-1000, Web site: www.borin.com

Carboline, St. Louis, Missouri ................................................................... 1

Phone: +1 314-644-1000, Web site: www.carboline.com

CerAnode Technologies International, Dayton, Ohio ..................... 3

Phone: +1 937-278-6547,

Web site: www.apsmaterials.com or www.ceranode.com

Corrpro, Houston, Texas .......................................................................... 13

Phone: 1 866-CORRPRO, Web site: www.corrpro.com

Cortec Corp., St. Paul, Minnesota ......................................................... 61

Phone: 1 800-426-7832, Web site: www.cortecvci.com

Dampney Co., Inc., Everett, Massachusetts ........................................ 14

Phone: 1 800-537-7023, Web site: www.thurmalox.com

DeFelsko Corp., Ogdensburg, New York ..................................12, 48, 61

Phone: 1 800-448-3835, Web site: www.defelsko.com

Denso North America, Houston, Texas .............................................. 50

Phone: +1 281-821-3355, Web site: www.densona.com

D. E. Stearns Co., The, Shreveport, Louisiana .................................... 53

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Elcometer, Rochester Hills, Michigan ........................................................ 5

Phone: +1 248-650-0500, Web site: www.elcometer.com

Electrochemical Devices, Inc., Albion, Rhode Island ....................... 37

Phone: +1 401-333-6112, Web site: www.edi-cp.com

Enduro Pipeline Services, Inc., Tulsa, Oklahoma ............................ 15

Phone: 1 800-752-1628, Web site: www.enduropipelines.com

Farwest Corrosion Control Co., Gardena, California ...................... 17

Phone: 1 888-532-7937, Web site: www.farwestcorrosion.com

GMC Electrical, Inc., Ontario, California .............................................. 41

Phone: +1 909-947-6016, Web site: www.gmcelectrical.net

Hi-Temp Coatings, Acton, Massachusetts ........................................... 21

Phone: +1 978-635-1110, Web site: www.hitempcoatings.com

IRT Integrated Rectifier Technologies, Inc., Alberta, Canada ..... 38

Phone: +1 780-447-1114, Web site: www.irtrectifier.com

LISTING OF ADVERTISER CONTACT INFORMATION

Advertiser ............................Page No. Advertiser ............................Page No.

Loresco International, Hattiesburg, Mississippi .................................... 7

Phone: +1 601-544-7490, Web site: www.loresco.com

MATCOR, Inc., Houston, Texas ............................................... Split Cover

Phone: 1 800-523-6692, Web site: www.matcor.com

M.C. Miller Co., Sebastian, Florida ........................................................ 47

Phone: +1 772-794-9448, Web site: www.mcmiller.com

MESA, Tulsa, Oklahoma ........................................................................... 39

Phone: 1 888-800-6372, Web site: www.mesaproducts.com

Metal Samples, Munford, Alabama ......................................................... 9

Phone: +1 256-358-4202, Web site: www.metalsamples.com

NACE Gateway India Section, Mumbai, India .................................. 59

Web site: www.naceindia.org, www.corcon.org

Neptune Research, Inc., Lake Park, Florida ....................................... 11

Phone: +1 561-683-6992, Web site: www.neptuneresearch.com

Polyguard Products, Ennis, Texas ......................................................IFC

Phone: 1 800-541-4994, Web site: www.polyguardproducts.com

Roxar, Stavanger, Norway ........................................................................ 49

Phone: +1 47 51 81 8800, Web site: www.roxar.com

Sauereisen, Pittsburgh, Pennsylvania ..................................................... 53

Phone: +1 412-963-0303, Web site: www.sauereisen.com

Sumitomo Metals, Houston, Texas ..................................................... IBC

Phone: +1 713-654-7111, Web site: www.sumitomo-tubulars.com

Tinker & Rasor, San Bernardino, California .....................................37, 51

Phone: +1 909-890-0700, Web site: www.tinker-rasor.com

NACE International

Phone: +1 281/228-6223, Web site: www.nace.org

2011 NAI Coating Show ............................................................................. 52

DoD $22.5 Billion ........................................................................................ 40

Internal Corrosion for Pipelines—Basic Course ......................................... 67

NACE SP0199-2009................................................................................... 76

New Report ................................................................................................. 71

Nominations for Association Awards .......................................................... 83

http://www.anotec.com

http://www.borin.com

http://www.carboline.com

http://www.apsmaterials.com

http://www.ceranode.com

http://www.corrpro.com

http://www.cortecvci.com

http://www.thurmalox.com


http://www.densona.com

http://www.destearns.com

http://www.elcometer.com

http://www.edi-cp.com

http://www.enduropipelines.com

http://www.farwestcorrosion.com

http://www.gmcelectrical.net

http://www.hitempcoatings.com

http://www.irtrectifier.com

http://www.loresco.com

http://www.matcor.com

http://www.mcmiller.com

http://www.mesaproducts.com

http://www.metalsamples.com

http://www.naceindia.org


http://www.neptuneresearch.com

http://www.polyguardproducts.com

http://www.roxar.com

http://www.sauereisen.com

http://www.sumitomo-tubulars.com


http://www.nace.org


Corrosion BasicsUnderstanding the basic principles and causes of corrosion

High-temperature

corrosion is a form

of corrosion that

does not require

the presence of a

liquid electrolyte. In this cor-

rosion mechanism, metals

react directly with gaseous at-

oms in the atmosphere rather

than ions in solution. Some-

times, this type of damage

is called “dry corrosion” or

“scaling.” The first quantita-

tive analysis to oxidation be-

havior was made in the early

1920s with the postulation of

the parabolic-rate theory of

oxidation by Tammann and,

independently, by Pilling and

Bedworth.

Although temperatures greater than

approximately 90 or 150 °C are some-

times considered “high temperature”

(e.g., for heated oil pipelines), this article

is concerned primarily with temperatures

greater than the “red-hot range,” primar-

ily 650 °C and greater.

Alloys often rely upon the oxidation

reaction to develop a stable protective

scale that resists further corrosion, such

as sulfidation, carburization, and other

forms of high-temperature attack. In

general, the names of the corrosion

mechanisms are determined by the domi-

Corrosion resistance at high tempera-

tures stems from a combination of two

basic factors: thermodynamics, which

determines whether a corrosive reaction

will proceed, and kinetics, which deter-

mines the rate at which the reaction may

proceed. The rate of the reaction may be

reduced by careful selection of alloying

components, such as inclusion of a multi-

valent metal that can react with a greater

number of oxidizing atoms.

The need for a careful study of the

properties of a heat-resistant alloy and its

behavior in the anticipated environment

is of considerable importance in the se-

lection of a suitable alloy for a particular

service application. New alloys and non-

metallic materials that are continually be-

ing made available to industry are making

it possible to make better selections and to

establish safe working limits within which

the material can be expected to give sat-

isfactory performance over a reasonable

length of time.

Reference

1. R.C. John, “Compilation and Use of

Corrosion Data for Alloys in Various

High-Temperature Gases,” CORRO-

SION/99, paper no. 73 (Houston, TX:

NACE International, 1999).

This article is adapted by MP

Editorial Advisory Board Member

Norm Moriber from Corrosion

Basics—An Introduction, Second

Edition, Pierre R. Roberge, ed.

(Houston, TX: NACE International,

2006), pp. 217-218.

High-Temperature Corrosionnant corrosion product(s). For example,

oxidation (the general term for a variety

of reactions) implies oxides, sulfidation

indicates sulfides, sulfidation/oxida-

tion indicates a combination of sulfides

plus oxides, and carburization indicates

carbides.1

Oxidizing environments refer to high-

oxygen activities (concentrations) with

excess oxygen. Reducing environments

are characterized by low-oxygen ac-

tivities, with no excess oxygen available.

Clearly, oxide-scale formation is more

limited under such reducing condi-

tions. It is for this reason that reducing

industrial environments are generally

considered to be more corrosive than the

oxidizing variety.

The properties of high-temperature

oxide films, such as their thermodynamic

stability, ionic-defect structure, and de-

tailed morphology, play a crucial role

in determining the oxidation resistance

of a metal or alloy in a specific environ-

ment. High-temperature corrosion is a

widespread problem in various industries,

including:

n Refining and petrochemical

n Power generation (nuclear and fossil

fuel)

n Aerospace and gas turbine

n Heat treating

n Mineral and metallurgical processing

n Chemical processing

n Automotive

n Pulp and paper

n Waste incineration

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