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THIS MONTH: CORROSION AND THE ENVIRONMENT

CORROSION CONSIDERATIONS FOR CRUDE OIL TRANSPORT

CORROSION PREVENTION AND CONTROL WORLDWIDE

MATERIALS

PERFORMANCE

JANUARY 2014

VOL. 53, NO. 1

ADVANCEMENTS IN THE ABRASION RESISTANCE OF INTERNAL PLASTIC COATINGS

Special Feature: NACE International Roundtable:

A Closer Look at Microbiologically Infuenced Corrosion

Monitoring Cathodic Protection from Inside the Pipe

Metallurgical and Corrosion Assessment of a Submerged Tanker

Corrosion Inhibitors in Deep Oshore Catenary Risers

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1NACE INTERNATIONAL: VOL. 53, NO. 1 MATERIALS PERFORMANCE JANUARY 2014

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JANUARY 2014

VOL. 53, NO. 1IN THIS ISSUE

CORROSION PREVENTION AND CONTROL WORLDWIDE MATERIALS PERFORMANCE

With the editorial themes of “Corrosion and the Environment” and “Corrosion Considerations for Crude Oil Transport,” this issue features articles on preventing pipeline corrosion, a new approach to hydrogen sulfde limits in high-temperature petroleum production, advancements in internal plastic coatings, and other experiences and advice from our technical article authors. In this month’s special feature, a roundtable of NACE International experts in the feld of microbiologically infuenced corrosion (MIC) discuss such issues as how MIC impacts structures, vessels, and pipelines; the techniques being used to identify the mechanism; and the mitigating and monitoring strategies involved (p. 32).

SPECIAL FEATURE

32A Closer Look at Microbiologically Infuenced Corrosion Kathy Riggs Larsen

MATERIALS SELECTION & DESIGN

69New Approach to H

2S Limits for High-Pressure,

High-Temperature Petroleum Production WellsRussell D. Kane, Tanmay Anand, Avidipto Biswas, Peter F. Ellis, and

Sridhar Srinivasan

74Metallurgical and Corrosion Assessment of Submerged Tanker S.S. Montebello

Dana J. Medlin, James D. Carr, Donald L. Johnson, and David L. Conlin

CATHODIC PROTECTION

42Lessons Learned: Monitoring Cathodic Protection Current from Inside the Pipe Dennis Janda and David Williams

46CP Blog

COATINGS & LININGS

52Advancements in the Abrasion Resistance of Internal Plastic CoatingsRobert S. Lauer

57CL Blog

CHEMICAL TREATMENT

64Corrosion Inhibitors in Deep Offshore Catenary RisersCheolho Kang, Jesse Rhodes, Kavitha Tummala, and

Alvaro Augusto Oliveira Magalhae

About the Cover

22 NACE INTERNATIONAL: VOL. 53, NO. 1JANUARY 2014 MATERIALS PERFORMANCE

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JANUARY 2014

VOL. 53, NO. 1IN THIS ISSUE

CORROSION PREVENTION AND CONTROL WORLDWIDE MATERIALS PERFORMANCE

18DEPARTMENTS

6Up Front

10Viewpoint

11The MP Blog

14The Essential Fellow

18Material Matters 18. Robotic equipment cleans and coats pipeline’s internal feld joints 21. NACE task group report focuses on sustainability of wastewater systems 24. NDK explosion resulted from stress corrosion cracking of a high-pressure vessel 27. Company News

28Spotlight on NACE International Corporate Members

30Product Showcase

80I AM NACE

92Building Business Connections 92. Corrosion Engineering Directory 95. Advertisers Index 95. Classifed

96Corrosion Basics

96. Special Cathodic Protection Requirements for Specifc Pipeline Applications

NACE NEWS

82NACE Sponsors Seven Rising Stars at the Emerging Leaders Alliance Conference

83NACE Area & Section News

84NACE International Commences Global Study on Corrosion Costs and Preventive Strategies

85Corrosion Analysis Network Provides One-Stop Source for Corrosion Information

87 In Memoriam

88 NACE Corporate Members

89 Meetings and Events

90 NACE Course Schedule

22

MP (Materials Performance) is published monthly by NACE International

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UP FRONT

Cadets Study Cathodic Protection to Combat Bridge CorrosionSenior cadets at the U.S. Air Force

Academy (Colorado Springs, Colorado)

are working to significantly extend the

lifespan of bridges across the country as

part of a year-long project to develop

effective ways to control corrosion build-

up on concrete and steel bridges through

cathodic protection (CP). They are assess-

ing the use of sacrificial anodes to protect

the metal infrastructure. Because many

bridges are being retrofitted with embed-

ded sacrificial anodes that can’t be moni-

tored without tearing the bridge apart,

the cadets are also evaluating impressed

current CP powered by energy harvesters

such as a solar panel or wind turbine that

can be used in a remote area without

access to the power grid. For more infor-

mation, visit www.usafa.af.mil.

Sensor Belt Monitors Health of Undersea Pipelines

An entirely new concept for transmitting

pipeline data has been developed by

researchers with SINTEF (Trond heim,

Norway) as part of the SmartPipe project.

Belts containing a series of sensors

designed to measure pipeline wall thick-

ness, tension, temperature, vibration, and

acceleration are fitted on pipelines at

24-m intervals and encased in a thick,

insulating polypropylene jacket applied

around the outside of the steel pipe sec-

tions. Data are transmitted wirelessly to

either an offshore platform or onshore

facility. The new self-monitoring pipe-

lines provide a continuous data stream

and will allow operators to maintain the

condition of a pipeline and respond to

problems at an early stage. The new

system is being tested on 250 m of pipe

in Norway’s Orkanger Harbour. Visit

www.sintef.com for more information.

Report Addresses Biofuel Storage in Underground Storage TanksThe risk of biofuel releases can be mini-

mized by ensuring underground storage

tanks (USTs) incorporate materials that

are compatible with biofuel storage. To

help owners, operators, contractors, and

consultants evaluate UST compatibility,

the Association of State and Territorial

Solid Waste Management Officials

(ASTSWMO) Alternative Fuels Work-

group (Washington, DC) developed a doc-

ument, “Compatibility of UST Systems

with Biofuels.” In addition to information

on biofuels and their properties, the docu-

ment presents considerations for biofuel

storage, a compatibility evaluation check-

list, and specific case studies where stor-

age issues, including corrosion, were

identified. To download the report, visit

www.astswmo.org.

EPA Proposes 2014 Renewable Fuel Standards The 2014 levels of renewable fuels to be blended into U.S. gasoline and diesel have been

proposed by the U.S. Environmental Protection Agency (EPA) (Washington, DC). The

proposal discusses a variety of approaches for setting the 2014 standards and includes a

number of production and consumption ranges for key biofuel categories covered by

the Renewable Fuel Standard (RFS) program. The proposal seeks public comment on a

range of total renewable fuel volumes for 2014 and proposes a level within that range. In

a separate action, EPA is also seeking comment on petitions for a waiver of the renew-

able fuel standards that would apply in 2014. Nearly all gasoline sold in the United

States is now E10, which is fuel with up to 10% ethanol. Visit www.epa.gov for details.

Intelligent Robot to Conduct Tunnel InspectionsAn intelligent robotic system that will

inspect highway and railroad tunnels is

being developed by scientists from the

Universidad Carlos III of Madrid (Madrid,

Spain) as part of the Robotic System with

Intelligent Vision and Control for Tunnel

Structural Inspection and Evaluation

(ROBINSPECT) project funded by the

Seventh Framework Programme of the

European Union.

The system, which will permit inspec-

tion and structural assessment in one

pass, is comprised of three components: a

small, robust tractor-like vehicle; a crane

that will allow inspections from a dis-

tance of ~5 m; and a robotic arm equipped

with an extensive sensor system, includ-

ing visual, tactile, and ultrasound tech-

nologies, to provide the precise and intel-

ligent movement needed to carry out

tunnel inspections. The robotic system

will automatically scan the intrados for

potential surface defects and measure (in

millimeters) deformities that can impact

tunnel stability, such as tiny fissures,

cracks, open joints, and cross-sectional

radial deformation. For more informa-

tion, visit www.uc3m.es.

CategoryProposed Volume(A) gal (L)

Range gal (L)

Cellulosic biofuel 17 million (64 million) 8-30 million (30-113 million)

Biomass-based diesel 1.28 billion (4.84 billion) 1.28 billion (4.84 billion)

Advanced biofuel 2.20 billion (8.32 billion) 2.0-2.51 billion (7.5-9.5 billion)

Renewable fuel 15.21 billion (57.56 billion) 15.0-15.52 billion (56.77-58.74 billion)

(A)All volumes are ethanol-equivalent except for biomass-based diesel, which is actual.Source: U.S. EPA.

Photo: Thor Nielsen/SINTEF.

Continued on page 8


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http://www.sintef.com

http://www.astswmo.org

http://www.epa.gov

http://www.uc3m.es


UP FRONT

Smart Coatings Protect Vehicles from Corrosion

Innovative coatings, developed as part of

the European Union-funded Multi-Level

Protection of Materials for Vehicles by

Smart Nanocontainers (MUST) project,

will protect a vehicle’s structural metallic

materials against corrosion by releasing

healing agents in response to the environ-

ment. Nanocontainers capable of storing

and releasing active healing agents are

loaded and incorporated into multi-layer

coating systems. Changes in environmen-

tal factors, such as pH, temperature,

mechanical impact, water, and chlorides,

cause the controlled release of the healing

agents, which then migrate throughout

the coating and repair any damage so the

underlying metallic substrate is pro-

tected. Some of MUST’s top performers

include pretreatments and primers for

corrosion inhibition in automobile and

aircraft components. Learn more at

cordis.europa.eu.

Sensors Use Electrical Charge to Detect Corrosion By using embedded piezoelectric trans-

ducers, researchers with the University

at Buffalo (Buffalo, New York) are able to

detect reinforcing steel corrosion in

bridges. By monitoring an electrical

charge sent along opposite ends of a steel

cable, the researchers can determine

early signs of corrosion from inconsisten-

cies in the charge. In their experimental

work, transducers that convert a signal

into another form of energy are embedded

in each end of a wire. A volt of electricity

is generated at one end of the wire, which

travels through the metal without much

energy loss, and monitored at the other

end. When the charge was sent through

the same wire after it was corroded by a

saltwater mixture, most of the energy was

lost. The sensors would be attached per-

manently to reinforcing cable and tests

could be conducted remotely. Learn more

at www.buffalo.edu. Source: UB Reporter.

Internal Corrosion Leads as Cause of Home Heating Oil SpillsThe Maine Department of Environmental

Protection (Augusta, Maine) reports that

~400,000 of Maine’s households rely on

fuel oil for home heating, and the depart-

ment, on average, responds to one home

heating oil spill per day. The leading

cause of residential oil releases is internal

corrosion resulting from water and a

build-up of sludge in the home’s heating

oil tank. The corrosion destroys a tank

from the inside and the deterioration isn’t

visible to the homeowner until a cata-

strophic tank failure occurs. The state’s

clean-up costs from home heating oil

spills can add up to as much as $2 million

annually. Source: www.maine.gov.

Corrosion Closes Portion of Duluth, Minnesota Bridge

A deteriorated piling on Pier 32. Photo courtesy of Gary Elmquist, MnDOT D1 lead bridge inspector.

A portion of southbound Interstate 35

(I-35) that crosses bridge #69887 in

Duluth, Minnesota was closed by the

Minnesota Department of Transportation

(MnDOT) after corrosion and deteriora-

tion were discovered on the buried pilings

for Pier 32, which is located in a low-lying

section of the bridge. The cause of the

deterioration, found at the bottom of the

pier caps where the piling and the pier

cap join, is being investigated, but exces-

sive moisture is considered be a contrib-

uting factor. MnDOT reports that runoff

from I-35 f lowing through an expansion

joint located on top of Pier 32, along with

water from deck drains on the bridge,

runoff from the bluffs above the freeway,

and overf low from a nearby creek, con-

tributes to water-saturated soils beneath

the bridge that rarely dry out. Below-

ground pilings don’t normally deteriorate

when exposed to dry air or encased in

concrete, but corrosion typically will

occur when both water and oxygen are

present. A bridge preservation project is

planned, which includes reshaping the

soil to drain pooling water. Source:

www.dot.state.mn.us.

Self-Healing Mechanism Discovered in MetalResearchers with the Massachusetts

Institute of Technology (MIT) (Cam-

bridge, Massachusetts) discovered that

under certain conditions, putting a

cracked piece of metal under tension—

a force that would be expected to pull it

apart—has the reverse effect and causes

the crack to close and its edges to fuse

together. The reason is tied to the way

grain boundaries interact with cracks in

the crystalline microstructure of a metal,

which in this case is nickel—the basis for

superalloys used in extreme environ-

ments such as deep-sea oil wells. By mod-

eling the microstructure and studying its

response to various conditions, the

researchers found a mechanism that can,

in principle, close cracks under any

applied stress. The finding could lead to

self-healing materials that repair incipi-

ent damage before it has a chance to

spread. Learn more at www.mit.edu.

Continued from page 6

MP welcomes news submissions and leads

for the “Up Front” department. Contact

MP Associate Editor Kathy Riggs Larsen

at phone: +1 281-228-6281,

fax: +1 281-228-6381, or

e-mail: [email protected].


http://cordis.europa.eu

http://www.buffalo.edu

http://www.maine.gov

http://www.dot.state.mn.us

http://www.mit.edu


EDITORIAL

DIRECTOR, CONTENT DEVELOPMENT Gretchen A. Jacobson

MANAGING EDITOR

TECHNICAL EDITOR John H. Fitzgerald III, FNACE

ASSOCIATE EDITOR Kathy Riggs Larsen

EDITORIAL ASSISTANT Suzanne Moreno

CONTRIBUTOR Husna Miskinyar

GRAPHICS

ELECTRONIC PUBLISHING Teri J. Gilley

COORDINATOR

GRAPHICS DESIGNER Michele S. Jennings

ADMINISTRATION

NACE EXECUTIVE DIRECTOR Robert (Bob) H. Chalker

GROUP PUBLISHER William (Bill) Wageneck

ADVERTISING

SALES MANAGER Diane Gross

[email protected],

+1 281-228-6446

ASSISTANT SALES MANAGER Teresa Wright

[email protected],

+1 281-228-6472

ACCOUNT EXECUTIVES Brian Daley

[email protected],

+1 281-228-6455

Pam Golias

[email protected],

+1 281-228-6456

Jody Lovsness

[email protected],

+1 281-228-6257

Leslie Whiteman

[email protected],

+1 281-228-6248

ADVERTISING/BOOKS Brenda Nitz

COORDINATOR [email protected],

+1 281-228-6219

REGIONAL ADVERTISING SALES The Kingwill Co.

REPRESENTATIVES Chicago/Cleveland/

New York Area–

[email protected],

+1 847-537-9196

NACE International Contact Information

Phone: +1 281-228-6200 Fax: +1 281-228-6300

E-mail: [email protected] Web site: www.nace.org

EDITORIAL ADVISORY BOARD

John P. Broomfield, FNACE Broomfield Consultants

Raul A. Castillo Consultant

Irvin Cotton Arthur Freedman

Associates, Inc.

Arthur J. Freedman Arthur Freedman

Associates, Inc.

Orin Hollander Holland Technologies

W. Brian Holtsbaum Corsult Associates (1980),

Ltd.

Russ Kane iCorrosion, LLC

Ernest Klechka CITGO Petroleum Corp.

Kurt Lawson Mears Group, Inc.

Lee Machemer Jonas, Inc.

Norman J. Moriber Mears Group, Inc.

John S. Smart III Packer Engineering

L.D. “Lou” Vincent L.D. “Lou” Vincent PhD LLC

John H. Fitzgerald III, FNACEMP Technical Editor

MP Greets the

New Year with

a New LookFrom the minute you opened your first

Materials Performance magazine of the

year, I’m sure you noticed a fresh new look

that continues to unfold as you page

through the news sections, feature story,

technical articles, and departments. Our

NACE International graphics team came

together in 2013 with the goal of creating

a redesign of the magazine that is clean,

organized, and attractive. You will still

find the content you are used to seeing in

MP—corrosion control information

covering all industries and technologies

in 12 monthly issues throughout the year.

We do have a few additions, however.

First, starting in 2014 many of our

issues will have multiple editorial themes,

enabling readers to find more informa-

tion of interest in a variety of technical

areas. We continue to cover the four

primary areas of corrosion control

technologies—cathodic protection,

coatings and linings, chemical treatment,

and materials selection and design—

while focusing on current corrosion

issues and projects as they relate to

industry, government, and academia

worldwide. We are relaunching “The

Essential Fellow,” a column written by a

NACE International Fellow on a topic of

his or her choosing. See p. 14 for this

month’s installment by Bijan Kermani,

FNACE. I encourage NACE Fellows to

contact me and MP staff with topic ideas

and to schedule your column.

We are adding a new department

based on the recently launched I AM

NACE series of video interviews and

online profiles that highlight individuals

working in a variety of corrosion profes-

sions. Many of the stories include insight

into how NACE training, certification,

and membership activities have impacted

and supported individuals at various

stages of their careers. See p. 80 for our

first I AM NACE profile, and be sure to

visit www.nace.org/i-am-nace to view

the profile videos online.

The heart of MP continues to be the

technical articles that are submitted by

corrosion control professionals from all

over the world who provide experiences

and information that readers can learn

from and apply to their own corrosion

work. In just the last two years we have

received more manuscript submissions

than ever before. We look forward to

seeing this trend continue as the NACE

membership of more than 33,000 steadily

increases and awareness grows about the

critical importance of corrosion control.

Visit the MP area of the NACE Web

site at www.nace.org/publications/

materials-performance for complete

information and guidelines on how to

submit an article to the magazine. In

addition, MP editorial staff is always

interested in leads for articles that can be

written internally and shared with the

readership.

Ultimately, our goal is to provide the

latest and most useful information for MP

readers. Please contact us anytime with

your comments and suggestions to help

us best serve your needs in our 2014 issues

and beyond. On behalf of our staff, I wish

you all a wonderful, successful year in

your invaluable roles as corrosion control

professionals.

VIEW POINT












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THE BLOG

The following are excerpts from the NACE

International Corrosion Network (NCN)

and NACE Coatings Network. These are

e-mail-based discussion groups for corro-

sion 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 techni-

cal 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

“Corrosion Central” link and then “Online

Corrosion Community List Servers” on the

NACE Web site: www.nace.org.

Hydrocarbons in cooling water systems

Q: I need standards or references on the maximum advisable

content of hydrocarbons in cooling water systems, particularly closed systems. The f luid of the cooling system is potable water (with corrosion inhibitors, biocide, antifoam, etc.). It is not a glycol-water mix system. The only recommendation I encountered is that oil should never exceed 5 ppm (according to Colin Frayne, “Cooling Water Treatment Principles and Practice,” Chemical Pub., 1999, p. 406).

We routinely quantify the concentra-tion of total hydrocarbons using the EPA 418.1 method. Typical values are between 1 and 3 mg/L. The circuit has a persistent problem of high aerobic bacteria count, exceeding the specified maximum. As one of the causes may be the presence of hydrocarbons, we are looking for any standard or consensus about the recom-mended maximum content of hydrocar-bons in cooling water systems.

A: Any oil intrusion into closed cooling water systems will result

in a high risk of microbiological fouling of heat transfer surfaces. In open cooling

water systems, the risk of hydrocarbon intrusion is measured in several ways. For light hydrocarbons (e.g., volatile), the hydrocarbons are measured in the vapor space above the same, and the limit is 5% concentration of hydrocarbons in the

vapor evolved from a cooling water sample. Tis is an industry practice, not a published specifcation. Also, make sure that the risers that return cooling water to the top of the tower are vented, or you


Continued on page 12



http://www.matcor.com



http://www.nace.org

BLOG

can have structural failure of the pipe from the pressure of the accumulated volatile hydrocarbons.

By the way, Frayne’s recommenda-tions apply to open cooling water systems.

A: It is not easy to quantify oil intru-sion, but if you take a water

sample and it has an oil sheen, then you need to treat the system or fush and replace the water. Tere are no simple feld methods to detect oil dissolved in

water. You can try to measure total organic carbon (TOC), but if you have any other organic additives in the water, you must know the background TOC, and this is usually not known. Most of the time, you have to wait for the contamination to reach the point of immiscibility and form a sheen on the surface of the water sample.

A: You mention hydrocarbons; what type are they—black oil, lube oil?

Te ppm can be measured by obtaining a sample and then conducting an oil in water test. Te typical test method used is a solvent extraction-based test. Ten use infrared (IR) analysis for detection. Take a sample of clean solvent and add a known amount of your hydrocarbon to make a 1% or 10,000 ppm solution. Ten make serial dilutions of the 1% solution. Run the sample in the IR machine and draw a calibration curve. After you have a calibration curve, extract a cooling water sample with the same solvent and subject the solvent extract to IR to determine concentration. Picking the solvent depends on the type of hydrocarbon and potential health and disposal issues. Common solvents are n-hexane, TCE, chloroform, etc.

Metals to handle sodium bisulfite

Q: I am trying to find out what metallic materials are typically

used for the piping and storage of 20 to 50% sodium bisulfite (NaHSO

3) at

ambient temperatures and if Type 316L stainless steel (SS) (UNS S31603), for example, offers improved performance over Type 304L SS (UNS S30403).

Information has been hard to find. I was able to find that the Outokumpu Stainless Corrosion Handbook (9th ed.,

Picking the solvent

depends on the type of

hydrocarbon and

potential health and

disposal issues.




http://www.defelsko.com




2004) mentions the case where air is present with sodium bisulfite, Type 304 SS (UNS S30400) can be attacked by sulfurous and sulfuric acid (H

2SO

4) in the

gaseous (vapor) phase.What kind of penetration rates are

suggested in mils per year?

A: Type 316 SS (UNS S31600) has better performance than Type

304 SS in over 20% concentration of sodium bisulfte at ambient temperature. Te average penetration rate for Type 316 (<2 mils/y) is less than for Type 304 (<20 mils/y).

Corrosion of buried steel

Q: Is there a point (i.e., depth) where a buried steel object will

cease to corrode, presumably through lack of oxygen? If so, are we talking a meter, tens of meters, or greater? Would it depend on the position of the water table?

The reason for asking is that we are considering putting some steel piles into an area of reclaimed land where the fill material is sea-dredged. I am unsure how much of a corrosion problem there may be and how much of the pile will need some form of protection.

A: As a general rule, soil will become anaerobic below a certain depth,

but this depth will vary greatly according to the soil type and the water table (it is reasonably accurate to say that the soil will be aerated above the water table, as oxygen transport through the gas space in dry soil will be rapid). Te state of aeration will also be markedly afected by the disturbance of the soil associated with burying things. Te fnal problem is that deaerated does not necessarily imply no corrosion if sulfate-reducing bacteria (SRB) are active.

In your case, sea-dredged material is likely to be pretty good at supporting SRB activity, and I would suggest that all of the piles will need protection at a level appropriate to situations with a risk of microbiologically inf luenced corrosion (MIC).

A: If there is no risk of MIC, the normal corrosion allowance in

the design for the steel pile below the seabed level (or in your case, the reclaimed area) is 0.05 mm/y. However, allowance should be made for scouring, etc., if required.

As a general rule, soil will become anaerobic

below a certain depth, but this depth will vary

greatly according to the soil type and water table.



http://www.corrpro.com



N

THE ESSENTIAL FELLOW

This feature in MP highlights experiences, opinions, and advice from NACE

International’s Fellows, who are honored for their distinguished contributions

in the feld of corrosion and its prevention. NACE Fellows make up a broadly

based forum through which technical and professional leaders serve as

advisors to the association. This month, MP is pleased to publish the

contribution of Bijan Kermani, FNACE, who was named a NACE Fellow

in 2010.

Positive Corrosion

NACE international and the corrosion

community have contributed enormously

to the advances made in engineering and

science that have subsequently led to step

changes in material degradation mitiga-

tion practice. The global awareness of the

topic, including succinct communication,

education, and public awareness, has

come a long way since NACE was first

established in 1943.

The impact of such measures has

been felt across nations, governments,

communities, and cultures. Our profession

continues to have substantial impact with

encouraging progress. NACE has also been

instrumental in demonstrating the finan-

cial impact of corrosion to various industry

sectors through outlining the detrimental

effect of failures and shortfalls that may

occur if corrosion mitigation measures

are not administered correctly. This has

paved the way for better recognition of

the subject matter and increased the level

of interest in the corrosion theme and its

management.

Corrosion remains a very interesting,

challenging, exciting, and relevant subject

incorporating a diverse set of disciplines:

physics, metallurgy, chemistry, engineer-

ing, and art. The additional appeal of

corrosion discipline existing among the

most lucrative engineering careers is

still insufficient to attract high-caliber

intakes and retain them. This is a critical

loss to the industry and it is imperative

that the anticipated shortfall is addressed

effectively. Furthermore, the discipline

average age is increasing with the decreas-

ing number of youngsters entering our

community. According to NACE, more

than 60% of the members are older than 40

and more than 40% are above 50. I believe

this deficit is correlated to the current

image of corrosion within the society.

NACE activities have traditionally

portrayed the impact of corrosion by

outlining losses, costs, failures, leaks, and

degradation. Crucially, corrosion mitiga-

tion activities have been portrayed as

a sort of life insurance, a vital concept,

Bijan Kermani, FNACE, KeyTech, Camerley, Surrey, United Kingdom

but one which people are reluctantly

acquiescent to. This approach has been

extremely effective in convincing those

with vested interest in policy change to

take the subject seriously and has made

the necessary impact. However, it is

time to change this somewhat negative

perspective of corrosion, which may have

instigated the diversion of the attention of

young engineers and scientists away from

the subject area. I feel it is now time to

develop this perspective to encompass the

positive sentiment of the profession on a

global scale.

Reducing the number of dangerous

events, injuries, and undesirable releases

remains a top priority and key focus of

our profession’s commitment to continu-

ally improving industrial and social safety

standards. NACE has maintained a relent-

less effort in making certain that safety

performance is improved through facilitat-

ing leadership, communication, education,

and technology transfer. The constructive

nature of our activities needs to be exposed

in an attempt to portray a positive image of

corrosion within the society.

Therefore, the present viewpoint

attempts to demonstrate what we have

achieved and sets the scene for a focus

shift to a perspective of delivering a

brighter future for generations to come.

First, a few examples of positives and

then what we hope to achieve.

Positive ImpactsOur profession under the flagship

of NACE has been responsible for many

advances and many achievements. There

have been exceptional innovations in

developing new generations of corrosion-

resistant alloys, corrosion inhibitors, and

coating systems with outstanding perfor-

mances. The impact of our community

on public welfare in minimizing harmful

loss of containment to the environment

and the safety and security of people and

wealth are unparalleled and we have to

be proud of these achievements and flag

them more clearly.

Here I share with you a few examples

as a token of what we have been able to


Highlights experiences, opinions, and advice from NACE International’s Fellows


Pipeline safety has been

enhanced over the years by

NACE initiatives and

activities.



THE ESSENTIAL FELLOW


deliver. The examples are too numerous

to mention in this limited space and I only

highlight a few in an attempt to paint a

brief picture as a sample demonstration

of the effects of our role in societal protec-

tion. A number of statistics are worthy of

attention.

Pipeline Failures vs. Pipeline Length

An Institute of Energy publication on

the number of pipeline failures over the

total length of pipelines in use outlines

that the overall pipeline failure frequency

has dropped to some 0.028 incidents per

1,000 km each year of operation.1 This

is an impressive figure no matter what

the benchmark. Failure frequencies have

been decreasing regularly year by year,

as shown in Table 1, although the rate of

change has fallen in recent years.

In comparison with the above, it is

worth noting that the number of fatalities

per million flight hours is considered as

a measure of success in the aeronautical

industry.2 The fatalities range between 4 to

22 per million flight hours depending on

the type of flights, as shown in Table 2.

Another measure of safety of opera-

tions is in the nuclear industry, which has

long been held in high regard with respect

to safety. In 2012, the nuclear industry

posted its best industrial safety record

ever, with only 0.05 industrial safety

accidents per 200,000 worker-hours.3

It is interesting to compare these

figures: 28 failures per million km per

year, against four fatalities per million

flight hours and finally against 0.05 safety

incidents for 200,000 worker-hours! It’s

a good comparison albeit not directly

associated and a demonstration of what

our industry has achieved in minimizing

pipeline failures.

Worker SafetyA comparison of U.S. pipeline trans-

portation data vs. the U.S. transportation

and warehousing sector data shows that

precisely zero pipeline workers experi-

enced injuries and illnesses in 2011. This

accomplishment is all the more impres-

sive given that trillions of cubic feet of

natural gas and billions of gallons of oil

traverse U.S. pipelines every year.4 Federal

data also show improvements in leak

rates. A 2012 Interior Department report

examined leak records from 1996 through

2010 (the year of the Deepwater Horizon

incident). Researchers found that offshore

spill frequency was actually “relatively

low” despite the fact that Gulf of Mexico

deepwater oil production had risen

sharply over that time.4

Pipeline Release VolumeTypical release volume for pipelines

transporting petroleum products is

11,286 gal (42,717 L) per billion ton-miles.5

This figure decreases by approximately one

third if the high product recovery rate for

pipelines is considered. Again an impres-

sive figure.

Landfall Valve Installation Risk Level

DEN Quantified Risk Assessment

(QRA)6 of risk level associated with a

proposed pipeline and landfall valve

installation (LVI) showed that it poses

an extremely low risk to the occupants of

dwellings along the route of the pipeline.

The predicted level of individual risk of

receiving a dangerous dose or more at the

nearest dwelling to the pipeline is 1.8 x

10-11 per year (1.8 events in every 100 billion

years). The predicted level of individual

risk of receiving a dangerous dose or more

standing at the pipeline is 2.9 x 10-9 per

year (2.9 events in every 100 billion years).

These are extremely low values both due

to meticulous engineering and corrosion

design considerations.7

Number of Large SpillsWhile the amount of oil produced and

transported has increased as the world’s

economy has expanded, the overall number

of large spills has significantly decreased.8

This reduction is primarily due to efforts

by companies operating throughout the

oil supply chain to develop more effec-

tive preventive measures; particularly the

corrosion community. Overall hydrocarbon

release (discharge and spill) of >1 bbl over

2005 to 2011 covering both onshore and

offshore, was 7.9 tonnes per million tonnes

production. This is <0.001% or ~55,000

tonnes globally.9

The Way ForwardWhile not all is directly comparable, I

believe the previously mentioned figures are

TABLE 1. PIPELINE FAILURE DATA SUMMARY (INCIDENTS PER 1,000 KM/YEAR)1

European Gas Pipeline Incident

Data Group (EGIG)

U.K. Pipeline Operators

Association (UKOPA)

Conservation of Clean Air and

Water in Europe (CONCAWE)

U.S. Department of Transportation

(DOT)

Overall 0.36 0.25 0.56 0.33

Latest fve-year rolling average 0.14 0.028 0.34 N/A

TABLE 2. WHICH TYPE OF FLYING IS SAFER2

Type of Flight Fatalities Per Million Flight Hours

Airliner (Scheduled and Non-Scheduled Part 121) 4.03

Commuter Airline (Scheduled Part 135) 10.74

Commuter Plane (Non-Scheduled Part 135— Air Taxi on Demand)

12.24

General Aviation (Private Part 91) 22.43




a clear demonstration of what we as a com-

munity of corrosion experts have achieved

over the years and on a statistical basis

they are very positive figures. Nevertheless,

there is no place for complacency, albeit the

image needs a slight change of focus so that

a new chapter can start.

We need to evolve the image of our

role in a positive way, putting emphasis

on the benefits of our actions above the

consequence of hindsight failure to act.

In other words, we should emphasize

the positive effects that our discipline

enables in addition to the negative conse-

quences that it prevents. As the above

demonstrates, we have been instrumental

in enabling a better and safer quality of

life and increased availability of fuels for

transportation for goods and services,

which is the foundation for global trade,

energy provision for homes, etc.

Looking to the future, our disci-

pline enables a more efficient use of

resources, thus reducing the impact on

climate change; we are also instrumental

in the development and implementa-

tion of carbon capture, transportation,

and storage technologies that can help

reverse the effect of carbon dioxide (CO2)

emissions.10 By working together with

city planners and other engineering disci-

plines, corrosion mitigation can give rise

to new, more sustainable ways of urban

living. With increasing pressure on water

and food resources, we have a key role in

ensuring that clean water is available to

users and not lost to leaks or failures.

All these and NACE’s unrelenting

efforts have made the necessary impact by

outlining the significance of corrosion in

the industrial and social sense. While the

economic impact and the prevention of

failures are significant and major drivers,

they have over the years portrayed a

negative image of corrosion.

I believe it is now crucial to advance a

different image of our community—

a “positive image.” This is a move to under-

line what our community is capable of

doing and has done in facilitating environ-

mental benefits, provision of social welfare,

and safety and security of people. These

latter cases, which may fall into a category

of “positive corrosion,” are normally lost

in conversation and dialogue. I suspect

the public and those in the public domain

may be getting blasé about the protection

integrity management provides and the

acceptance of the inevitability of corrosion.

We must seek to change this.

Even statistics are on our side—how

many leaks do we face in the United States

bearing in mind thousands of miles of

pipeline? The ratio is impressive!

You may ask why we should start such

an initiative. This is due to the fact that

we want to feel even better about the

real contributions that our community

of corrosion makes to society, not just

the failures we avoid but also the good

things we produce. We want to attract

a new generation of young, enthusiastic

engineers to our discipline, and we will

be much more successful by presenting

a positive vision rather than a “life insur-

ance” perspective. And frankly, society

offers more rewards for creating wellbeing

than for preventing catastrophes.

“Positive corrosion” needs NACE

attention as a flagship and value-adding

theme. Within this context, the NACE

International Institute is a step in the right

direction and a very encouraging develop-

ment. We hope to move to the next chapter

and aspire to a corrosion-free world.

References1 Technical Guidance on Hazard Analysis for On-

shore Carbon Capture Installation and Onshore

Pipelines, A Guidance Document, 1st ed. (Lon-

don, U.K.: Energy Institute, September 2010).

2 NTSB Accidents and Accident Rates by NTSB

Classification 1998-2007.

3 “U.S. Total Industrial Safety Accident Rate,”

Nuclear Energy Institute, 2012.

4 R. Bradley, “Oil & Gas Isn’t Just One of the

Richest Industries, It’s Also One of the Safest”

Forbes (March 25, 2013).

5 Manhattan Institute for Policy Research, Issue

Brief no. 23, June 2013.

6 “Corrib Onshore Pipeline QRA,” Shell E&P Ire-

land, Ltd. DEN, Report no./DNV Reg no. 01/

12LKQW5-2, Rev 01, May 18, 2010.

7 “Risk Assessment Data Directory, Riser &

Pipeline Release Frequencies,” International

Association of Oil and Gas Producers, Report

no. 434-4, March 2010.

8 “Oil Tanker Spill Statistics,” ITOPF, 2012.

9 “Environmental Performance Indicators,”

2011 data, International Association of Oil

and Gas Producers, OGP Report no. 2011e,

October 2012.

10 Carbon Capture, Transportation and Storage

(CCTS), Aspects of Corrosion and Materials,

B. Kermani, ed. (Houston, TX: NACE Interna-

tional, in publication).

Bijan Kermani, FNACE, is the founder and

has been the managing director of KeyTech,

Camberley, Surrey, United Kingdom, since

1999. He has a B.Sc. in

metallurgy and a Ph.D.

in corrosion with more

than 35 years of experi

ence in oilfield corro

sion and materials. He

is a visiting professor at

Leeds University and

UCL. He worked for BP for 15 years, holding

the positions of team leader (Corrosion and

Mater ia ls ) and technology manager

(Corrosion Free BP). Kermani is a leading

authority on oilfield corrosion and materials

and has more than 60 publications in his field

of expertise. He has edited prominent publi

cations on CO2 corrosion and established a

new methodology in material design for sour

service duties that is now included in NACE

MR0175/ISO 15156. He recently published

“Recommended Practice on Pipeline Cor

rosion Management.” He received a NACE

Technical Achievement Award in 2007 and

was named a NACE Fellow in 2010.

We should emphasize the positive effects

that our discipline enables in addition

to the negative consequences that it

prevents.


MATERIAL MATTERS

Robotic equipment cleans and coats pipeline’s internal feld joints

Robotic inspection equipment uses high-voltage brushes to inspect the factory-applied internal

pipe coating and feld-applied internal feld joint coating. Photo courtesy of CRTS.

When water is scarce, every

drop counts, whether it is

quenching thirst or

fulfilling agricultural and

industrial needs. Preserving the integrity

of the scarce water supply at the

Candelaria open-pit copper mine near the

mining and agriculture town of Copiapo,

Chile was the primary goal of a project

that used a robotic corrosion prevention

system to apply an environmentally

friendly fusion-bonded epoxy (FBE)

coating to nearly 6,400 internal field

joints on a 85-km long, 24-in (700-mm)

diameter pipeline for process water. The

project was implemented by CRTS (Tulsa,

Oklahoma) in collaboration with its sister

company, United Sistema de Tuberias

Limitada, a Chilean subsidiary of Aegion

Co.’s United Pipeline Systems (UPS);

pipeline owner Freeport-McMoRan

because they have no volatile organic

compounds. The equipment is also envi-

ronmentally friendly—the vacuum robot

recycles and reuses the abrasive grit that

cleans each internal field joint.

The water in a desalination pipeline is

highly oxygenated, and steel pipes, gener-

ally used for their strength at higher pres-

sure, are highly susceptible to corrosion

due to bacterial activity3 and iron oxide.

Recent research emphasizes that pitting,

crevice, galvanic, and stress corrosion

can occur as well as mineral scaling and

biological fouling, which can alter the

performance of the equipment.1 To mini-

mize internal corrosion, the internal field

joints were cleaned, coated, and

inspected before any product was put

through the pipeline. Eight CRTS field

technicians and one CRTS supervisor

completed the eight-month job using two

robotic cleaning units, two robotic FBE

coating units, and one robotic inspection

machine. This process, partnered with

pipe that was internally coated at the fac-

tory, created a corrosion-resistant barrier

on the pipe’s internal surface.

The factory-coated pipes had an

uncoated cutback area (2-in [51-mm] of

bare steel) to accommodate welding, and

were delivered to the project site with end

caps intact to protect them from foreign

objects and dust. The robotic equipment

consisted of a crawler, cleaner, vacuum,

coater, and inspection machine. The

robots were set up in various configura-

tions (sets) and a crane was used to lower

each set of equipment into the pipe string.

After each pipe string was welded

together and x-rayed, the internal field

joint/parent coating interface was pre-

cleaned with the robotic cleaner-vacuum

that was powered by a battery-filled

robotic crawler. The steel grit was thrown

onto the field joint circumferentially for

cleaning and abrading the surface and

Mining Co.; and Hatch Engineering, the

project designer and manager.

Desalinating seawater is one alterna-

tive for mining companies to secure a

water supply without causing water

shortages to local residents and their

agricultural pursuits.1 Corrosion preven-

tion is vital to desalination plants

because of the inherent extreme condi-

tions that include “filtration, heat

exchange, distillation, evaporation…and

high f low velocities, often turbulent…

brines cause localized corrosion such as

pitting, crevice, galvanic and stress cor-

rosion.”2 To ensure a sufficient supply of

quality water in Copiapo, robotic machin-

ery developed by CRTS was used to coat

the internal field joints of the Candelaria

project’s desalination water pipeline with

FBE powder. FBE powders are environ-

mentally friendly barrier coatings



the internal field joint was blasted with

the abrasive to create an anchor profile

on the fresh weld metal for the coating.

The vacuum robot then filtered and recy-

cled the grit for application on the next

field joint. Onboard cameras allowed the

field technician, via monitors, to locate

the next weld ready for cleaning.

Next, another set of robots, the

crawler and FBE coater, were loaded into

the pipe. A field technician controlled the

external induction coil that heated the

pipe, a process required for both internal

and external FBE coating. When the pipe

reached the coating manufacturers’ rec-

ommended temperature, the FBE coating

cycle began. The coater’s powder head

rotated to disperse the coating in a fan-

like pattern, using a set number of revolu-

tions to meet the manufacturer’s/owner’s

recommended coating thickness. The

coater coated the bare steel plus 1 in (25

mm), which was directly deposited onto

the parent pipe coating on both sides of

the field joint. Each internal field joint

was then inspected visually with the

coater’s onboard camera. Live feedback

was displayed on the remote monitor for

the field technician to view and record.

The crawler and inspection machine

were then driven to each cleaned and

coated weld. The dry film thickness (DFT)

was measured in each quadrant to ensure

the coating met project requirements,

and a high-voltage holiday inspection was

performed on each internal field joint.

Using the onboard camera, a high-voltage

holiday detector was aligned over the

coated area to perform a 360-degree

sweep of the coated field joint. This

inspection allowed the operator to detect

any visible anomalies such as weld spat-

ter/slag, coating blisters, holidays, and

foreign objects. It also enabled welds to be

repaired before any product was put into

the pipe, which would minimize future

repairs and/or rehabilitation. Where any

anomalies or holidays were located, the

weld was repaired by re-abrading the FBE

coating, and then recoating. The cleaning

and coating cycles were adjusted to main-

tain the millage specifications.

The DFT probe and 360-degree rotating brass brush inspect coated internal feld joints.

Photo courtesy of CRTS.



Information on corrosion control and prevention

January 2014 MP.indd 19 12/18/13 12:41 PM



The focus and zoom capabilities of the robot’s

visual inspection camera detect minute details

and defects. Photo courtesy of CRTS.

The Candelaria coating project had

several challenges. Environmental chal-

lenges, such as the desert’s dust, required

every pipe string to be re-cleaned prior to

the actual cleaning/coating process. Most

significantly, the entire length of each

pipe string was inspected in addition to

the standard internal field joint inspec-

tion. Circumferential line-travel holiday

detecting equipment, located on the

inspection machine, was used to inspect

the lining of each pipe after the internal

field joints were completely cleaned,

coated, visually inspected, and holiday

inspected. Real-time feedback provided

the field technician with immediate veri-

fication of each pipe section’s quality sta-

tus, and detected any anomalies in the

factory-coated pipeline. Repairs were

made where holidays did occur.

Teamwork with the contractors and

the pipeline owner also contributed to the

success of this environmentally sensitive

project. On the most productive day, 115

internal field joints were cleaned, coated,

and inspected; and an average day

resulted in 41 cleaned, coated, and

inspected welds.

Source: Tis article was submitted by

James A. Huggins, co-founder and past

president, and Caroline A. Fisher, technical

writer, with CRTS, Inc. Contact Caroline

Fisher—e-mail: [email protected].

References1 Case Studies on Tailings Management (Nai-

robi, Kenya: United Nations Environmental

Programme, 1999).

2 M. Schorr, B. Valdez, J. Ocampo, A. Eliezer,

“Corrosion Control in the Desalination In-

dustry,” Desalination, Trends and Technologies

(Rijeka, Croatia: InTech, 2011).

3 F. Knops, M.G. de la Mata, C. Mendoza Fa-

jardo, E. Kahne, “Seawater desalination of the

Chilean coast for water supply to the mining

industry,” C.D. McCullough, M.A. Lund, L.

Wyse, eds., Proc. International Mine Water

Association Annual Conference, held Sep-

tember 30-October 4, 2012 (IMWA, 2012), pp.

697-703.


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MATERIAL MATTERS



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A pipe at an older wastewater pump station is

deteriorating. Photo courtesy of Southern

Trenchless Solutions.

NACE task group report focuses on sustainability of wastewater systems

An increasing number of water and

wastewater systems, structures, and

components in the United States are

being affected by corrosion and deteriora-

tion, which can shorten the life span of

the system and increase costs for the con-

sumer. To increase awareness of the cor-

rosion problems encountered by munici-

pal wastewater systems, members of

NACE Task Group (TG) 466 recently pub-

lished a report, “Corrosion Problems and

Renewal Technologies in Wastewater

Systems.”

The comprehensive report provides a

roadmap that can guide decision-makers

such as utility directors or operations

managers in understanding the types of

corrosion-control solutions available that

can help them achieve system sustain-

ability, says NACE International member

Eric Dupré, business manager with

Southern Trenchless Infrastructure

Rehab Co. (Houston, Texas) and chair of

TG 466. The report identifies materials of

construction and the corrosion mecha-

nisms that affect various components of a

municipal sewer system, and explains

repair, rehabilitation, and replacement

methods for these components. Addi-

tionally, the report describes several cur-

rent inspection technologies available for

asset assessment.

The TG 466 report notes that ~190

million people in the United States are

served by ~16,000 sewer systems compris-

ing ~740,000 miles (1.2 million km) of

public sewer mains—the publicly owned

collection lines that gather the sanitary

sewage from individual properties, con-

vey it to a treatment plant, and then

release it into a receiving body of water—

plus 500,000 miles (800,000 km) of private

lateral sewers, the portion of the collec-

tion system that connects a privately

owned structure to the sewer main.

These systems, however, are aging; 68%

are more than 25 years old and 2% are

more than 50 years old. Investment in

upgrades and repairs is needed to main-

tain the nation’s wastewater infrastruc-

ture and prolong its service life; but the






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need comes at a time when municipal and

state budgets are becoming more con-

strained and less able to maintain and

sustain these deteriorating wastewater

systems, and many asset management

programs are doing more with less.

In its 2013 Report Card for America’s

Infrastructure,1 the American Society of

Civil Engineers (ASCE) says capital

investment needs for U.S. wastewater and

storm water systems are estimated to

total $298 billion over the next 20 years,

with 80 to 85% of capital investments

addressing the country’s public sewer

mains. The report gives the nation’s

wastewater systems a “D” grade for infra-

structure because they are “in poor to fair

condition and mostly below standard,

with many elements approaching the end

of their service life.”

The costs to manage corrosion are also

high. The 2002 cost of corrosion study,2

published by the U.S. Federal Highway

Administration, reports the direct annual

cost of corrosion in drinking water and

sewer systems is $36 billion, which

includes the cost of replacing aging infra-

structure, lost water from leaks, corrosion

inhibitors, internal mortar linings, exter-

nal coatings, and cathodic protection.

This figure comprises 75% of the total cor-

rosion cost for all utilities—gas distribu-

tion, electricity, tele-

communications,

water, and waste water.

Wastewater pipe

corrosion leads to

untreated sewage

releases into the envi-

ronment that can

cause soil and ground-

water contamination.

Pipe defects (such as

holes, cracks, and

failed pipe joints) in

wastewater collection

systems can cause

blockages that lead to

sewage overf low and

backup into buildings.

Pipe leaks/breaks can

cause soil erosion and

roadway damage, and disrupt service to

customers.3 In the United States, there

are up to 75,000 sanitary sewer overf lows

per year, resulting in the discharge of 3 to

10 billion gal (11.3 to 37.8 billion L) of

untreated wastewater.4

According to the TG 466 report, a

variety of materials are used to construct

wastewater pipelines and structures,

including concrete, brick, iron, steel, vari-

ous plastics, and composites. Portland

cement-based unlined concrete is the

most widely used material in existing

wastewater systems in the United States,

with ferric metals (iron and steel) coming

in second. Corrosion of these materials in

wastewater systems is caused mainly by

hydrogen sulfide (H2S) corrosion and

microbiologically inf luenced corrosion

(MIC). Other corrosion deterioration

mechanisms found in typical wastewater

collection systems include hydraulic

abrasion from turbulent f lows and grit in

the wastewater stream, and stress result-

ing from hydrostatic pressures.

The report describes the basic mecha-

nisms of H2S corrosion, which can lead to

rapid, extensive damage of concrete and

metal sewer pipe and tanks, mechanical

equipment used for the transport and

treatment of wastewater, and electrical

control and instrumentation systems. This

type of corrosion occurs where biological

activity of anaerobic bacteria results in

the formation of sulfide. Under anaerobic

(septic) wastewater conditions, sulfides

cannot be oxidized. They combine with

hydrogen to produce H2S gas, which has

the characteristic “rotten egg” odor. When

a sewer is operating partially full and

exposed to air, the damp surface above the

water line is exposed to aerobic bacteria

that oxidize the H2S in the presence of

moisture and produce sulfuric acid

(H2SO

4). The H

2SO

4 attacks exposed con-

crete and unprotected iron, steel, and cop-

per surfaces. This results in corrosion of

the collection system pipes, manholes, lift

station wells, and other structures, with

the majority of corrosion occurring above

the water line in the headspace area of the

structure. Systems that are particularly

vulnerable to attack include electrical

components, instrumentation systems,

and ventilation units. Many variables,

which are summarized in the report,

directly or indirectly affect sulfide genera-

tion, H2S release, and H

2SO

4 corrosion.

The rate of H2S corrosion is dependent

on the construction materials used, the

features of the wastewater stream and the

collection system, and the type of trans-

port and treatment processes used.

Certain units and their processes are

more susceptible to corrosion damage

than others. The report describes the vari-

ous components of a wastewater collec-

tion and treatment system that are most

likely to promote the generation and re-

lease of H2S gas and reviews the basic

steps typically involved in identifying ex-

isting or potential corrosion problems. It

notes that system components experienc-

ing H2S corrosion often require renewal—

the application of a broad range of repair,

rehabilitation, and replacement technolo-

gies to pipes, manholes, tanks, pump sta-

tions, and other mechanical equipment—

to restore the functionality of the entire

wastewater collection system.

Factors that commonly affect renewal

planning include the ability to inspect

and assess the condition and deteriora-

tion rate of each component, the extent of

H2S corrosion caused deterioration and reinforcing steel failure of

this 4-in (102-mm) thick concrete manhole. Photo courtesy of

Southern Trenchless Solutions.



MATERIAL MATTERS


critical repair needs, and the availability

of funding for rehabilitation work. When

the pipe or structure is structurally sound

and provides acceptable f low capacity, a

repair technique is usually applied. A

rehabilitation technique is employed

when hydraulic conditions and structural

strength need to be improved. When a

pipe or structure is severely deteriorated,

and/or f low capacity needs to be

increased, a replacement technique is

normally used.

The report focuses on trenchless tech-

nologies, which are methods that can be

used to renew underground structures

without full excavation so surface disrup-

tions are minimal, and includes a descrip-

tion of typical repair, rehabilitation, and

replacement methods for the primary

components of a wastewater collection

system—namely sewer mains, sewer lat-

erals, manholes, force mains, and ancil-

lary structures (pump/lift stations, valve

or diversion structures, overf low struc-

tures, and drop shafts). H2S corrosion is

often controlled by protecting structures

with paint and other coatings and linings,

as well as constructing structures of

corrosion-resistant materials. The

renewal technologies discussed in the

report include sliplining, spiral-wound

liners, cured-in-place pipe (CIPP) liners,

close-fit liners, grout-in-place (GIP) lin-

ers, panel liner systems, sprayed coating

and liner systems, and f lood grouting.

The applicability of each technique is

based on the condition of the existing

asset, site circumstances, cost, track

record, local availability of the technique,

as well as its expected ability to meet per-

formance requirements over an extended

life cycle. The report contains several

tables that provide a comprehensive over-

view of these sewer pipe renewal meth-

ods, including their features, work

requirements, and applicable pipe param-

eters. According to the report, the perfor-

mance of these technologies to date indi-

cates that they do provide extended

service life to infrastructure.

Other issues associated with manag-

ing wastewater system corrosion are also

discussed in the report. These include

design considerations, long-term perfor-

mance and testing, and new materials, as

well as condition assessment and inspec-

tion technologies. Condition assessment

provides the critical information needed

to evaluate the physical condition and

functionality of a wastewater collection

system and estimate its remaining ser-

vice life and the value of its assets. The

report lists a variety of inspection tech-

nologies used to assess wastewater col-

lection systems, where they can be

applied, and the type of defects they can

detect. The technologies described

include closed-circuit television (CCTV),

acoustic technologies, electrical/electro-

magnetic current technologies, laser pro-

filing, and other technologies currently

under development.

This report is not intended to address

all types of activities used to develop and

implement a wastewater system renewal

construction project; however, says

Dupré, it does provide the reader with

valuable information that will guide them

when making corrosion management

decisions that affect the future sustain-

ability of their wastewater system.

Members of TG 466 include vice chair

Frank Madero with MADERO Engineers

& Architects; Erez Allouche with the

Trenchless Technology Center at

Louisiana Tech University; Alec B. Angus

and Ramon Pelaez with Greenman-

Pedersen, Inc.; Jason Iken with the City of

Houston PWE Wastewater; Jeffrey Maier

with the Metro Wastewater Reclamation

District in Denver, Colorado; Dan J.

Murray with the U.S. Environmental

Protection Agency; Mohammad Najafi

with the Center for Underground

Infrastructure Research and Education at

the University of Texas at Arlington; Jim

Sepowksi with International Paint, LLC;

and Cumaraswamy Vipulanandan with

the Center for Innovation Grouting

Materials and Technology at the

University of Houston. Dupré acknowl-

edges that a substantial amount time and

effort was donated by TG 466 members to

develop and publish this report.

Contact Eric Dupré, Southern Trenchless

Infrastructure Rehab Co.—e-mail: eric@

southerntrenchless.com.

References

1 “2013 Report Card for America’s Infrastruc-

ture,” American Society of Civil Engineers,

http://www.infrastructurereportcard.org

(November 25, 2013).

2 G.H. Koch, M.P.H. Brongers, N.G. Thompson,

Y.P. Virmani, J.H. Payer, “Corrosion Costs and

Preventive Strategies in the United States,”

FHWA-RD-01-156 (Washington, DC: FHWA,

2002).

3 “Aging Water Infrastructure Research: Sci-

ence and Engineering for a Sustainable Fu-

ture,” U.S. Environmental Protection Agency,

Publication No. EPA/600/F-11/010, 2011.

4 “Aging Water Infrastructure (AWI) Research,

System Rehabilitation,” U.S. Environmental

Protection Agency, October 30, 2012, http://

www.e p a .go v/aw i/sy st em-reh ab.html

(November 22, 2013).

— Next Month in MP —

Editorial Theme: Military Corrosion

Special Feature: CORROSION 2014 Program Preview

Chemical Agent-Resistant Coatings for Military Assets

Predicting Corrosion in Military Aircraft

Cathodic Protection of Tank Bottoms

Corrosion-Resistant Steel Fixtures for Masonry Walls

Green and Synthetic Polymer Clay Dispersants

Limiting Corrosion from Dust Control Agents




http://www.infrastructurereportcard.org



http://www.epa.gov/awi/system-rehab.html

http://www.epa.gov/awi/system-rehab.html

Vessel No. 2 is shown on the ground outside

the NDK manufacturing facility. Most of the

building’s exterior wall panels were blown

out due to the force of the explosion. Photo

courtesy of the CSB.


NDK explosion resulted from stress corrosion cracking of a high-pressure vessel

The U.S. Chemical Safety Board (CSB)

(Washington, DC) recently released the

investigation report1 on its findings on

the December 7, 2009 explosion of a steel

pressure vessel at the NDK Crystal manu-

facturing facility in Belvidere, Illinois.

According to the report, cracks in the

steel vessel wall, caused by stress corro-

sion cracking (SCC), reduced the tough-

ness of the vessel material, which eventu-

ally led to large f laws and catastrophic

failure. The CSB also released a safety

video, “Falling through the Cracks,” that

uses computer animation to illustrate the

accident’s sequence of events and investi-

gation findings.

The report states that the NDK

Crystal Belvidere facility, located in a

light industrial area next to Interstate 90

(I-90), was constructed in 2002 and put

into operation in 2003. The five-story

building accommodated eight vertical

steel pressure vessels used to simulate

geologic crystal growth through heat and

high pressure. Each 140,000-lb (63,504-

kg) vessel is comprised of a 48-ft (14.6-m)

tall, 8-in (203-mm) thick cylindrical shell

and a 2-ft (0.6-m) thick, 10,000-lb (4,536-

kg) closure head that is clamped to the

top by operators. The top and bottom of

the vessels are significantly thicker than

the vessel wall: ~18 in (463 mm) near the

lid and ~16 in (406 mm) at the base. The

vessels have a maximum allowable work-

ing pressure (MAWP) of ~30,000 psig

(206.8 MPa) and a maximum operating

temperature of 750 °F (399 °C). After each

crystal growing cycle (100 to 150 days),

the pressure relief device was replaced

due to the high operating pressure.

During the manufacturing process,

raw mined quartz is lowered into the bot-

tom of a vessel and 800 gal (3,028 L) of an

alkaline water and 4% sodium hydroxide

(NaOH) solution is added, along with a

small amount of lithium nitrate (LiNO3).

Seed crystals are hung at the top of the

vessel. The vessel is slowly heated to

700 °F (371 °C), which boils the caustic liq-

uid and increases the inside pressure to

~29,000 psig (200 MPa). During the pro-

cess, the caustic NaOH solution and silica

react with the iron in the steel vessel wall

and form a layer of iron silicate, known as

acmite, on the inner surface of the vessel

wall. According to the CSB report, the

acmite coating was intended to serve as a

protective coating to prevent corrosion of

the steel vessel and shield the final prod-

uct from iron contamination.

On December 7, 2009, Vessel No. 2

experienced a sudden rupture when it was

120 days into a 150-day operating cycle.

MATERIAL MATTERS



http://www.cortecvci.com



A micrograph of the vessel fragment shows

stress corrosion cracking on the fracture

surface about 0.75 in (19 mm) from the inner

diameter surface of the vessel fragment.

Photo courtesy of the CSB.



The report states that the rapid release of

superheated liquid from the failure

caused a 4- by 8-ft (1.2- by 2.4-m), 8,600-lb

(3,900-kg) steel fragment from the vessel

to burst through two concrete walls,

travel about 435 ft (132 m) away from the

NDK building, and slam into the wall of a

nearby office building. The thrust of the

escaping liquid sheared the base of the

vessel away from its foundation. Pieces of

structural steel that were blown out of the

building landed 650 ft (198 m) away in the

parking lot of a nearby gas station on I-90,

where one piece struck and killed a truck

driver at the gas station. NDK has not

resumed operations at the Belvidere facil-

ity since the accident.

As part of the subsequent CSB investi-

gation, process data for the vessel over the

120-day period prior to the incident were

reviewed by CSB investigators. Since evi-

dence of a process deviation that might

have caused the vessel failure was not

found, the 8,600-lb fragment was sub-

jected to metallurgical examination and

destructive and nondestructive testing.

The report says the resulting test data

showed strong evidence of cracking on

and near the inner diameter of the vessel

wall, and the fracture initiated at an

existing, surface-breaking crack in the

inner diameter of the lower portion of the

vessel near the base.

Microscopic examinations indicated

that SCC—where cracks form in the com-

bined presence of applied stresses and a

corrosive environment—was present in

many regions of the vessel fragment. The

SCC was likely caused by the corrosive

environment created inside the vessel

(particularly in small surface scratches)

by the caustic NaOH solution, which is

generally known to cause corrosion on

some steels.2 Additionally, the report says

temper embrittlement may have acceler-

ated SCC or contributed to the critical

crack formation.



http://www.monti-tools.com






Metallurgists also performed energy

dispersive spectroscopy (EDS) testing on

the fragment to assess the acmite coating

on the vessel’s inner surface. According to

the report, significant quantities of sili-

con, titanium, and aluminum were

observed, as well as smaller quantities of

sulfur and chloride. The presence of these

impurities implies that the process f luid

was able to penetrate the surface cracks

in the vessel because the acmite coating

provided inadequate protection.

During the investigation, the CSB

learned that the Illinois Board of Boiler

and Pressure Vessel Safety did not con-

duct internal inspections. Pressure ves-

sels subject to internal corrosion are

required by the Illinois Boiler and

Pressure Vessel Safety Act to receive a

certificate of inspection every three

years. When the state’s Board of Boiler

and Pressure Vessel Safety initially certi-

fied the NDK vessels, however, it approved

the vessels for non-corrosive service. As a

result, only accessible external surfaces

and pressure relief devices were

inspected by the state boiler and pressure

vessel inspector. In 2003, 2006, and 2009

(less than three months prior to the inci-

dent), the state conducted inspections of

Vessel No. 2, but these inspections

focused only on accessible external sur-

faces and did not examine the vessel for

internal corrosion. “Had NDK conducted

regular inspections, it would have discov-

ered that the acmite coating was not pro-

tecting the vessel walls,” comments CSB

Lead Investigator Johnnie Banks.

Additionally, the CSB investigation

determined that the vessels did not meet

requirements of the ASME Boiler and

Pressure Vessel Code,3 which provides

codes and standards that are adopted by

state and federal regulators, including

those in Illinois. The report says the NDK

vessels’ 8-in thick walls exceeded the rec-

ommended limits of 7 in (178 mm), possi-

bly making them too thick for proper heat

treatment during manufacturing.

According to CSB Investigator Lucy

Sciallo-Tyler, evidence from the accident

suggests that excessive wall thickness

resulted in improper manufacturing and

contributed to the metallurgical damage

mechanism that led to the catastrophic

rupture.

The report also notes a previous inci-

dent in January 2007, when the closure

head in Vessel No. 6 experienced an

uncontrolled leak while in service and hot

(400 °F [204 °C]) NaOH solution was

released through the threaded pressure

sensor connection at the top of the vessel.

During the following nondestructive

examination of the vessel lids, conducted

as part of an investigation by a consultant

hired by NDK, tiny cracks were found in

the closure heads for Vessels No. 1, 4, 6,

and 8, with the possibility of cracks

reported for the lid of Vessel No. 2. The

consultant attributed the leak in Vessel

No. 6 to SCC and reported that SCC was

present in the four vessel heads. The SCC

was thought to be caused by issues in the

design, material selection, and heat treat-

ment of the vessels and vessel lids, and the

consultant advised against returning any

of the facility’s eight vessels to service.

SCC on the lids was the first indica-

tion that the acmite coating did not pos-

sess adequate protective capabilities, the

report says, and there was a possibility

that SCC may have been evident through-

out the vessels. Because the vessels were

produced from the same ingot as the lids,

it was possible that the interior of the ves-

sels would be susceptible to a similar fail-

ure mechanism. The consultant investi-

gating the lid failure commented that

higher tensile hoop stresses down the

length of the cylinder made the inner

diameter susceptible to cracks where the

caustic solution could collect. After the

2007 investigation, a consultant hired by

NDK’s insurance company recommended

a thorough examination of the all the ves-

sels’ interiors to identify cracks. NDK,

however, continued operations without

addressing the origin of the SCC.

“Our report lists eight key findings,

which in summary point to the results of

regulatory ambivalence and a culture of

not inspecting for problems in the face of

clear warnings,” says Banks. “NDK did

not verify the integrity of the vessel coat-

ing; regulators incorrectly designated

vessels as ‘non-corrosive;’ NDK did not

examine vessels even after being told of

corrosion; and the company didn’t per-

form inspections even after a recommen-

dation to do so by the vessels’ designer—

who knew the equipment better than

anyone else.”

The CSB report makes a total of eight

safety recommendations that are

directed to the pressure vessel code and

regulatory authorities and NDK. These

include a recommendation to the Boiler

and Pressure Vessel Safety Division of the

Office of the Illinois State Fire Marshal

that it develop and implement state

requirements and procedures to ensure

the pressure vessel approval process

accurately identifies vessels that may be

subject to corrosion or similar deteriora-

tion mechanisms, and ensure regular

inspections in accordance with these

state requirements. Also, the CSB recom-

mends that NDK implement a program to

ensure the ongoing integrity of any coat-

ing used on the new process vessels and

employ an expert (e.g., a coatings expert

certified by NACE International) to

design the program.

Source: Te U.S. Chemical Safety Board,

Web site: www.csb.gov.

References

1 “Case Study, NDK Crystal, Inc., Belvidere, IL,

High-Pressure Vessel Rupture,” U.S. Chemical

Safety Board, No. 2010-04-I-IL, November

2013.

2 NACE SP0403-2008, “Avoiding Caustic Stress

Corrosion Cracking of Carbon Steel Refinery

Equipment and Piping” (Houston, TX: NACE

International).

3 ASME Boiler and Pressure Vessel Code,

Section VIII, Division 3 (New York, NY:

ASME).

MP welcomes news submissions

and leads for the “Material Matters”

department. Contact MP Associate Editor

Kathy Riggs Larsen at phone:

+1 281-228-6281, fax: +1 281-228-6381,

or e-mail: [email protected].

MATERIAL MATTERS


http://www.csb.gov


COMPANY NEWS

New Laboratory Takes Fatigue Testing to New HeightsEnova’s new €2.8 million flagship site in

Toulouse, France will drive expansion in

its aerospace composites and metals test-

ing. The new facility will provide a 25%

increase in capacity with an additional

eight fatigue testing frames, a new milling

machine, and an increase in scanning elec-

tron microscope capability. The laboratory

specializes in fatigue testing, crack propa-

gation, and fracture toughness of airframe

and aircraft engine components and mate-

rials, as well as comprehensive testing

services for non-metallic composite

materials.

KTA Announces the Promotion of O’MalleyKTA-Tator, Inc. (Pittsburgh, Pennsylvania)

is pleased to announce the promotion of

Cindy O’Malley

to manager of

consulting and

laboratory ser-

vices. In her new

role, O’Malley

will oversee all

consulting ser-

vices, including

failure analysis,

system selection and specification devel-

opment services, and research projects.

She will continue to oversee the analytical

laboratory and the physical testing labora-

tory services. During her 18 years with

KTA, O’Malley has advanced her career

element for achieving our growth strategy

in the provision of environmentally

friendly completion fluids in the shale gas

market.”

Farwest Corrosion Relocates in Bakersfield, CaliforniaFarwest Corrosion Control Co. (Gardena,

California) is pleased to announce the

expansion and relocation of its Central

California operation in Bakersfield,

California. This new facility has 12,250 ft2

(1,138 m2) of warehouse and office space

to meet the products and service require-

ments of clients in the region and to accom-

modate continued growth. Farwest has

played a vital role in the Bakersfield oil,

gas, and water industries for more than

50 years and the new facility will allow it to

continue the tradition of service into the

future.

De Nora Strengthens its Partnership with ThyssenKrupp De Nora (Milan, Italy), in line with its stra-

tegic plan to focus on the electrode busi-

ness and develop new technologies, has

signed a joint venture agreement with

ThyssenKrupp Uhde, a 100% subsidiary of

ThyssenKrupp Industrial Solutions, the

plant engineering and construction special-

ist. The companies are planning to combine

their activities regarding engineering, pro-

curement, and construction (EPC) services

for electrolysis plants for the chlorine elec-

trolysis industry. This move will expand the

technological platforms and increase the

customer proximity, as well as the global

presence of both partners.

through department leadership initiatives

and dedicated involvement with industry

organizations.

DeLaney Joins Philpott Energy

The Philpott

Energy &

Transportation

Co., Ltd.

(Williamsport,

Pennsylvania)

announced that

Eric DeLaney has

joined the com-

pany. DeLaney

will manage the company’s sales and oper-

ations activities from Philpott’s new

Williamsport office. According to Philpott

Vice President Jeff Rog, “We are very

excited about Eric joining us as we launch

our shale gas service operations center in

Williamsport. His more than 10 years in

organizing and managing marketing, sales,

and field operations provide us a critical

LUX Assure Breaks New Ground in the Middle EastScotland-based LUX Assure has

announced the completion of its first

major work in the Middle East using its

corrosion management tool, CoMic. The

firm secured a contract with Kuwait Oil

Co. (KOC) Research and Technology divi-

sion in Ahmadi to provide support for a

seawater pipeline in North Kuwait. The scope of work involved LUX Assure’s senior

scientist Cameron Mackenzie working on site for several days using CoMic, to

evaluate the functional dosage of a corrosion inhibitor being applied in a transpor-

tation pipeline.

MMFX Steel Appoints New Sales ManagerMMFX Steel Corp. of America (Irvine, California) has

appointed Arthur Sakaev as a new regional sales manager to

support the growing demand of its reinforcing steel. With

experience in developing sales territories, Sakaev will be key

in the growth of the acceptance and use of MMFX uncoated

corrosion-resistant and high-strength reinforcing steel prod-

ucts in the southwestern United States. His abilities will be an

asset to engineers who are looking for solutions to extend the

life-cycle of their design projects or lower construction costs

through the use of Grade 100 reinforcing steel.




THIS MONTH: GOLD CORPORATE MEMBER NRI

For more than 31 years, NRI has revolu-

tionized and led the composites

industry in research and development,

engineering design, and manufacturing

of pre-impregnated and field-saturated

composite strengthening systems that

restore, protect, and reinforce pipes,

pipelines, and civil structures. NRI is

known for its cutting-edge solutions,

unparalleled customer support, and high-

strength, quality products that have

stood the test of time and environmental

elements. NRI has been distinguished as

the industry’s premier manufacturer of

composite reinforcement solutions.

IndustryNRI’s quality engineered solutions

have been used by leading oil and gas

companies, engineers, distributors,

contractors, and municipalities as well as

the U.S. and international militaries.

NRI’s product portfolio serves a broad

range of markets including construction,

industrial, marine, military, mining,

offshore, oil and gas distribution and

transmission, and refining and petro-

chemical. With a focus on developing and

engineering quality moisture-curable

carbon fiber, fiberglass, Kevlar®, and

other aramid composite solutions, NRI

can retrofit and reinforce defects and

anomalies to original specifications in

pipes, pipelines, and civil structures. NRI

is continuously researching and develop-

ing composite materials that will trans-

form the need for strong, quick-solving,

and corrosion-resistant solutions.

VisionNRI’s passion for providing composite

technology with quality, reliability, and

integrity was built on three fundamental

aspects: leading the industry with quality

composite solutions, fostering the

innovation and development of new

cutting-edge technology, and expanding

into new global markets. The company

has a single focus and commitment to be

the industry leader, offering the utmost in

credibility, knowledge, customer support,

and manufactured products for pipeline

and civil reinforcement.

NACE InvolvementNACE corporate membership enables

NRI to talk to a wider audience about its

solutions and engineering knowledge

within Materials Performance and the

NACE Web site and marketing literature,

which widens NRI’s network of customers

and collaboration with other industry

professionals. Another membership

benefit are the discounts on educational

courses and the technical resources for

NRI’s engineering and sales staff.

NRI has participated in the annual

NACE CORROSION Conference and Expo

for more than 10 years, along with other

local NACE events and seminars. These

events provide an excellent opportunity

to network and develop business relation-

ships with potential distributors,

vendors, customers, and other industry

professionals.

AccomplishmentsNRI has experienced many milestones

and accomplishments over the course of

31 years, beginning with its original

moisture-cured composite system,

Syntho-Glass®, which was accepted and

continues to be required onboard U.S.

Navy and Coast Guard vessels. Through

strategic research and innovative product

developments streaming from this origi-

nal product, NRI has vastly expanded its

product lines and capabilities, along with

application techniques and devices, and

created more robust composite products.

NRI has developed and patented

numerous products and application

devices such as The Resinator® and

ViperSkin® carbon composites. Within

the past five years, NRI has experienced

substantial growth as the demand for

composite solutions increases, and has

required a move to more than three facili-

ties. NRI is now headquartered in a 30,000

ft2 (2,787 m2) manufacturing facility in

Riviera Beach, Florida.

Learn more at www.neptuneresearch.

com.

NACE International’s Diamond, Gold,

and Silver Corporate Members receive a

“Spotlight” company profile in MP. For

more information about the NACE

Corporate Member Program or to schedule

your profile interview, please contact

[email protected].

NRI is known for its cutting-edge solutions,

unparalleled customer support, and

high-strength, quality products that have

stood the test of time and environmental

elements.



http://www.neptuneresearch.com

http://www.neptuneresearch.com

Find a mentor. Be a mentor.

www.nace.org/mentors


http://www.nace.org/mentors


PRODUCT SHOWCASE

Open Atmosphere Corrosion Inhibitor

Cortec Corp.’s (St. Paul, Minnesota)

new EcoLine 3680 is a certified

biobased, biodegradable, ready-to-

use temporary coating for multi-

metal protection. EcoLine 3680 is

formulated with U.S. Department of

Agriculture (USDA) renewable raw

materials, which allows use for corro-

sion protection of equipment where

incidental contact with food is possi-

ble. The product is HX-1 approval

pending. Metals protected with

EcoLine 3680 include carbon, galva-

nized, and stainless steels; copper;

brass; bronze; aluminum; and cast

iron. The product can be easily

applied by brushing or spraying.

Phone: 1 800-426-7832, Web site:

www.cortecvci.com.

Spill Kit in Truck-Mount ContainerNew Pig (Tipton, Pennsylvania) intro-

duces the Spill Kit in Truck-Mount

Container. The kit easily mounts on a

truck or trailer in preparation for leaks

and spills that can occur during trans-

portation. Available for universal,

oil-only, and hazmat applications, the

kit is pre-packed with enough PIG

Absorbents to absorb up to 14.8 gal

(56 L) of f luids, helping transporters

comply with the need to take prompt

actions to contain spills. In addition,

the kit contains PIG Repair Putty, a

containment pool, shovel, and basic

PPE to further assist with spill

containment efforts. Phone:

1 800-468-4647, Web site:

www.newpig.com.

New PosiTector RTR Replica Tape Reader

DeFelsko (Ogdensburg, New York) is

pleased to announce the PosiTector RTR

Replica Tape Reader, a new digital

spring micrometer that measures peak-

to-valley surface profile height using

TestexTM Press-O-FilmTM Replica Tape.

Advantages include the retention of a

digital record and a reduction in

measurement uncertainty, inspector

workload, the likelihood of error, and

the number of replicas needed to ensure

accuracy. The PosiTector RTR conforms

to all major international standards,

including NACE RP0287, ASTM D4417,

SSPC-PA-17, ISO 8503-5, and others.

Phone: 1 800-448-3835, Web site:

www.defelsko.com.

Ultra‐Low‐VOC Combination Metal DrierAllnex (Smyrna, Georgia) introduces

ADDITOL XW 6560, an ultra-low

volatile organic compound (VOC)

combination metal drier designed for

easy incorporation into low VOC water-

borne alkyd paints. “With much stricter

VOC regulations coming into force in

the U.S. in the near future, Allnex has

taken the initiative to develop a metal

drier that will not only help formulators

of alkyd coatings be compliant, but is

also easy to use and offers optimum

performance,” says Philippe De Micheli,

global marketing director, Liquid

Coating Resins and Additives. Phone:

1 800-433-2873, Web site: www.

allnex.com.

Flexible Spray Head and CAPS II Evacuation Sleeve ‘Duo’ AirVerter ( Jessup, Maryland) has

recently developed a combination of

two previously patented technologies.

Now painters everywhere can combine

the ergonomic convenience of

AirVerter’s MicroFlex f lexible spray

head with the environmental benefits of

the CAPS II evacuation system, which

are customizable to any spraying tool

including automatics and robotics. The

fitted CAPS II evacuation sleeve is

designed to be f lexible so that the duo

will still be able to access difficult-to-

reach areas. Phone: 1 800-937-4857,

Web site: www.airverter.com.



http://www.newpig.com


http://www.airverter.com

http://www.allnex.com

http://www.allnex.com


The Latest Tools forFighting Corrosion

New Data Retrieval SystemCoastal Flow Measurement (Houston,

Texas) announces the release of version

4.0 of the company’s BirdDog Remote

Data Retrieval System. All BirdDog

users automatically have access to this

newest system when logged into the

host Saas site. The system includes

enhanced security features, layered

administration, the ability for end-users

to perform ad hoc changes to alarm

settings, and fully customizable distri-

bution of BirdDog Morning Reports, all

with an even more streamlined and

intuitive user interface. Phone:

1 800-231-9741, Web site: www.

coastf low.com.

Monitoring Applications in Hazardous Locations

FreeWave Technologies, (Boulder,

Colorado) announces the release of its

WaveLine 10i a Class 1 Division 1 (C1D1)

certified high-performance wireless I/O

networking solution that is ideal for use

in oil and gas, water/waste water, and

other industrial settings with applica-

tions in hazardous environments. With

a C1D1 certification, operators can

achieve a safe operating environment

for a variety of monitoring applications,

including pressures, temperatures, and

liquid levels. In addition, it eliminates

the need for conduit and installation

outside of the C1D1 area for easier,

faster, and less expensive installations.

Phone: 1 866-923-6168, Web site:

www.freewave.com.

Remote Monitoring of Cathodic Protection

American Innovations (Austin, Texas)

has released the Bullhorn RM4150 for

accurate remote monitoring of assets

under cathodic protection. By collect-

ing and communicating rectifier

measurements using GSM networks,

operators can meet 49 CFR 192/195

regulations and protect their pipelines.

The unit features five analog channels

and two digital channels to monitor

rectifiers on pipelines, well casings,

tanks, and other assets. The Bullhorn

RM4150 also measures alternating and

direct current volts and amps, pipe-to-

soil potential, shunts, instant off, line

power presence, and more. Phone:

1 800-229-3404, Web site: www.

aiworldwide.com.

High-Performance LED Drop Light

Larson Electronics’ (Kemp, Texas)

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handheld LED features robust alumi-

num and steel construction, molded

rubber bumper guard, 10 W LED bulb,

100 ft (30 m) of SOOW cord, and a twist

lock explosion-proof plug. The high-

performance LED work light produces

far more lumens per watt than a 100-W

incandescent drop light, and produces

bright white light with better contrast-

ing and color quality. The LED bulb

produces 1,050 lumens and has a

50,000-h life rating. Phone: 1 800-369-

6671, Web site: www.magnalight.com.

Green High-Solids Epoxy Available for Military EquipmentSherwin-Williams (Cleveland, Ohio)

announces MIL-PRF-22750G Type III,

Grade A Seafoam Green high-solids

epoxy, which meets the military specifi-

cation for direct-to-metal (DTM) appli-

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ments of performance to a minimum

1,000 h of salt spray and 40 cycles of

cyclic corrosion. Phone: +1 216-298-

4653, Web site: oem.sherwin.com.

—H. Miskinyar

MP welcomes submissions of

product press releases and

photos for Product Showcase.

Please send them to the

attention of Husna Miskinyar,

NACE International; phone:

+1 858-768-0829; e-mail:

[email protected].


http://www.coastflow.com

http://www.freewave.com

http://www.magnalight.com

http://oem.sherwin.com


http://www.aiworldwide.com

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http://www.coastflow.com

M

FEATURE ARTICLE

A Closer Look at Microbiologically Infuenced CorrosionMaterials Performance Roundtable Q & A

Microbiologically influenced corrosion

(MIC) refers to corrosion caused by the

presence and activities of microorgan-

isms—microalgae, bacteria, and fungi.

While microorganisms do not produce

unique types of corrosion, they can

accelerate corrosion reactions or shift

corrosion mechanisms. Microbial action

has been identified as a contributor to

rapid corrosion of metals and alloys

exposed to soils; seawater, distilled water,

and freshwater; crude oil, hydrocarbon

fuels, and process chemicals; and sewage.

Many industries and infrastructure are

affected by MIC, including oil production,

power generation, transportation, and

water and waste water.1

To better understand MIC and the

corrosion threats it poses to pipelines,

vessels, and structures, Materials

Performance asked several NACE

International members and others from

industry, government, and academia

to comment on the impact of MIC and

challenges faced when identifying and

mitigating MIC. Panelists are Richard

Eckert and Torben Lund Skovhus with Det

Norske Veritas (DNV GL); Gary Jenneman

with ConocoPhillips; Sylvie Le Borgne

with the Metropolitan Autonomous

University at Mexico City; and Jason S.

Lee and Brenda J. Little, FNACE, with

the U.S. Naval Research Laboratory. (See

their biographies in the sidebar, “Meet the

Panelists.”)

MP: How does MIC impact structures,

vessels, and pipelines?

Le Borgne: The first reports of MIC are

from the nineteenth century. Most of the

studies have been in relation to metallic

materials. However, other materials such

as concrete, plastics, and new materials

or coatings increasingly used nowadays

should be included. MIC affects a variety

of structures, vessels, and pipelines by

directly or indirectly influencing the

overall corrosion process, and is usually

estimated to account for 20% of the total

cost of corrosion. Due to the complexity

Kathy Riggs Larsen, Associate Editor


Jan14_Feature.indd 32 12/18/13 3:30 PM

Many industries and infrastructure are affected by MIC, including

oil production, power generation, transportation, and water

and waste water.

MIC of pilings in the Duluth Superior Harbor in Duluth, Minnesota. Photo courtesy of Gene Clark, University of Wisconsin Sea Grant Institute.


A Closer Look at Microbiologically Influenced Corrosion


FEATURE ARTICLE

of systems involving microorganisms, it is

generally difficult to precisely quantify the

influence of MIC to the overall corrosion

process. Microbial ecology studies have

clearly demonstrated that microbes can

survive and be active in a wide variety of

environments including many man-made

structures and environments. Systems

where MIC is especially important include

hydrocarbon and fuel (gas and liquid)

transmission and storage systems, as well

as hazardous materials transport and

storage structures. These systems provide

adequate environmental conditions and

substrates for microbial development, and

the participation of microorganisms in

corrosion has been clearly demonstrated

and MIC failures documented. Utilities

such as drinking water and sewer systems

also provide adequate conditions for MIC

development. However in such systems,

MIC has often been underestimated, as

has been corrosion in general.

Eckert and Skovhus: MIC typically

manifests itself as localized (i.e., pitting)

corrosion—with wide variation in rate,

including rapid metal loss rates—both

internally and externally on pipelines,

vessels, tanks, and other fluid handling

equipment. Despite advances in the

understanding of MIC, it remains diffi-

cult to accurately predict where MIC will

occur and estimate the rate of degrada-

tion. MIC can occur as an independent

corrosion mechanism or in conjunction

with other corrosion mechanisms. These

characteristics present challenges to

implementing effective corrosion manage-

ment of engineered systems in which MIC

is an applicable threat.

Jenneman: Although the techniques

to identify MIC are nonstandard and

subject to interpretation, the places where

we suspect MIC to occur experience

rapid pitting, usually at interfaces where

solids such as scale, wax, and or other

solids can settle out or precipitate. Areas

downstream of welds, where cleaning

pigs have difficulty removing deposits, as

well as dead legs, low-velocity areas, and

tank bottoms where solids and bacteria/

biofilms can accumulate, are particularly

susceptible to attack. Often this pitting is

very isolated, with one hole surrounded by

a number of shallower pits. Pitting rates

range from a few mpy to >250 mpy.

Lee: MIC in itself is not a unique

corrosion mechanism; rather it produces

conditions that increase the susceptibility

of materials to corrosion processes such as

pitting, embrittlement, and underdeposit

corrosion (UDC). MIC can result in orders

of magnitude increases in corrosion rates.

Meet the PanelistsRichard Eckert is

a principal engi-

neer—corrosion

management at

Det Norske Veri-

tas (U.S.A.), Inc., in

Dublin, Ohio. He

has been involved

with pipeline cor-

rosion/failure investigation and forensic

corrosion engineering for over 30 years.

A NACE member for more than 20 years,

Eckert has a B.S. degree in engineering

metallurgy from Western Michigan Uni-

versity, is a NACE-certifed Senior Internal

Corrosion Technologist, and currently

serves as chair of the NACE Books Com-

mittee, vice chair of the NACE Publica-

tions Committee, and is a member of the

NACE Institute Certifcation Commission.

He is chair of NACE Task Group (TG) 254.

Eckert received the NACE Presidential

Achievement Award in 2004.

Gary Jenneman

is a principal sci-

entist within the

Global Production

Excellence group

of ConocoPhi l -

lips in Bartlesville,

Oklahoma, where

he has worked for

the past 26 years. Jenneman has held

various technical and supervisory posi-

tions in the areas of corrosion and oilfeld

microbiology. He holds a Ph.D. in micro-

biology from the University of Oklahoma

and has 12 U.S. patents and numerous

publications in the areas of microbiologi-

cally enhanced oil recovery, MIC, reser-

voir souring, and biodesulfurization. As a

NACE member, he has served on various

NACE technical committees and panels

over the past 15 years.

Sylvie Le Borgne

is a professor re-

searcher in the

Depar tment o f

Process and Tech-

n o l o g y a t t h e

Metropolitan Au-

tonomous Univer-

sity at Mexico City,

Mexico. Some of her research interests

are in environmental microbiology, bio-

corrosion, and biodeterioration, as well

as other topics in the area of biotechnol-

ogy. She has been directly involved in

petroleum biotechnology from 1999 to

2005. She was a recipient of the Carlos

Casas Campillo prize in 2004, given by

the Mexican Society of Biotechnology

and Bioengineering to young researchers

under 36 years old.



The most devastating issue regarding MIC

is its general lack of predictability—both

spatially and temporally.

Little: In almost all cases MIC produces

localized attack that reduces strength and/

or results in loss of containment.

MP: What are the current techniques

used to identify MIC?

Le Borgne: Current techniques to

identify MIC after it has occurred or when

it is suspected are based on detecting

and identifying the (causative/present)

microorganisms, examining the damaged

material (pit morphologies), and analyz-

ing the corrosion products in search of

biogenic structures. Concerning the detec-

tion and identification of microorganisms,

the traditionally used tests generally

involve culture techniques with already

prepared media tests kits to detect the

growth of specific microorganisms known

to participate in MIC in specific environ-

ments, such as sulfate-reducing bacteria

(SRB), acid-producing bacteria, nitrate-

reducing bacteria, or iron-reducing

bacteria. These kits are relatively easy to

use although they need some basic labora-

tory expertise; the samples are inoculated

directly in the field immediately after the

sample has been collected. These kits

also have the advantage of detecting only

active bacteria, even in very low numbers.

However, these kits can be rather unspe-

cific and allow the growth of other types of

microorganisms. Some years ago, genetic

techniques had been proposed to allow

a better detection and identification of

microorganisms in MIC. These techniques

need special expertise. Careful sampling is

needed to avoid contaminations as these

techniques are extremely sensitive and the

samples must be transported and stored

under special conditions to avoid degrada-

tion of the nucleic acids. Following total

DNA extraction from the samples, the

total content and identity of virtually all

the microorganisms present can be deter-

mined by different methods, from genetic

fingerprints to pyrosequencing. When

DNA is the starting material for these

analyses, all the microorganisms, whether

dead or alive, are detected. It cannot be

determined which microorganisms were

metabolically active when the sample was

taken. RNA extraction from environmental

samples is very challenging and is not a

routine technique.

Lee: Advancements in molecular

microbiology provide numerous methods

to determine which ones are there, how

many there are, and what they are doing.

Metallurgical sectioning and micro-

Jason S. Lee has

worked as a ma-

terials engineer

since 2001 at the

U.S. Naval Re-

search Laboratory

in Stennis Space

Center, Mississippi.

A NACE member

since 1999, Lee has chaired numerous

MIC technical symposia and is currently

vice chair of Technology Exchange Group

(TEG) 187X. His research for the Navy

focuses on the basic science aspects of

MIC, computational corrosion modeling,

improved fundamental understanding of

the localized corrosion, and electrochemis-

try of metals and alloys exposed to marine

environments. Lee received his B.S. degree

in chemistry and cellular/molecular biology

from the University of Michigan, and his

M.S. and his Ph.D. degrees in materials sci-

ence and engineering from the University

of Virginia.

Brenda J. Little,

FNACE, is a se-

nior scientist for

marine molecular

processes at the

Naval Research

L a b o r a t o r y i n

S t e n n i s S p a c e

Center, Mississip-

pi. She has worked on MIC projects for

the U.S. Department of Transportation

and the U.S. Army Corps of Engineers,

and has served as a consultant to NASA.

In addition to her accomplishments in

basic research, Little also works on U.S.

Navy assets to identify and control MIC.

Her research has been used to deter-

mine the cause of corrosion failures

in weapons systems, seawater piping

systems, storage tanks, and other U.S.

Navy equipment.

T o r b e n L u n d

Skovhus is project

manager at Det Nor-

ske Veritas (DNV GL)

in the Corrosion Man-

agement & Technical

Advisory Group in

Bergen, Norway. For

almost 10 years he

has been working with DTI Oil & Gas as a

consultant and oilfeld microbiologist for oil

and gas operators and chemical vendors

worldwide. He is an author of more than

30 technical and scientifc articles related

to molecular biology, oilfeld microbiology,

corrosion management, reservoir souring,

and MIC. He is the editor of three books and

the founder of the International Symposium

on Applied Microbiology and Molecular

Biology in Oil Systems (ISMOS). He has a

M.S. degree in biology and a Ph.D. from

the Microbiology Department at University

of Aarhus, Denmark. A NACE member, he

is the chair of NACE TEG 286X.




FEATURE ARTICLE

scopy provide information about material

composition, corrosion morphology, and

spatial relationships between micro-

organisms and sites of corrosion. Multiple

techniques are used to determine the

electrochemical properties of materi-

als exposed to biologically active media.

Surface science and crystallography

provide the chemical and structural

identity of corrosion products.

Jenneman: It is recommended when

trying to justify MIC as a contributing or

root cause of corrosion that the following

lines of evidence be examined:

1. Biological: In this case we will chemi-

cally characterize the water for

essential microbiological nutrients

(e.g., organics, nitrogen, phosphorus)

and perform microbiological testing, if

possible, to determine if the environ-

ment can support growth and activity.

We will use culture-based and molecu-

lar methods to determine the types/

numbers of microorganism present

if good samples are available. Other

physical properties (temperature, pH,

ionic strength) of the environment will

also be checked and evaluated.

2. Chemical: In this case we work with

corrosion engineers who will look at

water chemistry, gas analyses, corro-

sion models, etc. to determine if abiotic

mechanisms such as carbon dioxide

(CO2) corrosion can explain the corro-

sion.

3. Metallurgical: In this case both micro-

biologists and corrosion engineers will

examine corrosion products (using

x-ray fluorescence [XRF] and x-ray

diffraction [XRD]) and pit locations/

morphology, as well as determine

maximum pit depth using surface

profilometry to determine if param-

eters are consistent with MIC and/or

other mechanisms

4. Operational: Many operational condi-

tions and changes can influence the

likelihood for MIC, e.g., low-velocity/

stagnant conditions, pigging frequency,

types of pigs, biocide usage, rapid

failures, changes in temperature,

introduction of oxygen, and upward

trending of bacteria. All of these avail-

able lines of evidence and facts are then

weighed to determine if MIC is the root

cause or a contributing factor.

Eckert and Skovhus: MIC is identi-

fied by evaluating the physical conditions,

chemical composition, microbiology, and

metallurgy of the susceptible component

or system. The integration of this data is

what ultimately determines the extent

to which MIC may be contributing to

the observed corrosion. Therefore, the

techniques used to identify MIC are varied

and cross-disciplinary and require exper-

tise in materials, corrosion, microbiology,

chemical treatment, and asset operations.

Although microbiological conditions

are only one piece of the MIC puzzle, the

counting of viable bacteria has histori-

cally received the most emphasis. Serial

dilution using liquid culture media,

despite its limitations, has been the

predominant method used to identify

viable bacteria. The type (formulation)

of the culture medium and incubation

temperature determine the numbers and

types of microorganisms that will grow.

Since no culture medium can approximate

the complexity of a natural environment,

liquid culture provides favorable growth

conditions for only about 1 to 10% of the

natural microbiological population under

ideal circumstances. Further, some micro-

organisms are incapable of growth in

typical liquid media (e.g., some Archaea).

While these factors bias culture-based

results, serial dilution results are still

useful for monitoring general trends of

growth in some systems. Molecular micro-

biological methods (MMM), long used in

health care and forensics, have gained

popularity in the analysis of microbio-

logical corrosion and are now included

in a number of NACE standards and

publications, including TM0194-2004,2

3T199,3 TM0212-2012,4 and the forth-

coming revision of TM0106-2006.5 MMM

require only a small amount of sample

(liquid, biofilm, solid) with or without live

microorganisms. After genetic materi-

als are extracted from the sample, assays

are specific and render a more accurate

quantification of various types of micro-

organisms than culture tests. Molecular

techniques that are finding increased use

include quantitative polymerase chain

reaction (qPCR), denaturing gradient gel

electrophoresis (DGGE), and fluorescent

in situ hybridization (FISH).

Little: Despite the limitations of

liquid/solid culture techniques, it is my

opinion that most industries use some

form of culture to establish a most proba-

ble number (MPN) of viable organisms.

Relating MPN to the likelihood of MIC is

a questionable practice that can only be

reliable in limited applications. NACE

TM0212-2012 describes microscopic

analyses, chemical assays, and molecular

methods for evaluating MIC. Most of

the research in MIC testing is related to

molecular techniques that identify and

quantify microorganisms. It is not clear

that molecular techniques have provided

a more accurate tool for predicting the

likelihood of MIC. These techniques may

provide a tool for assessing mitigation

strategies. Microorganisms do produce

mineralogical fingerprints that can be

used to identify MIC. In many cases, MIC

is assumed when there is no obvious cause

of corrosion.

MP: What are the challenges faced when

establishing MIC as the probable cause

of corrosion?

Eckert and Skovhus: Since micro-

organisms are ubiquitous, and some are

capable of life in even the most extreme

environments, the greatest challenge is

determining the degree to which MIC

contributes to corrosion in conjunction

with other relevant corrosion mecha-

nisms. For example, biofilms that increase

MIC susceptibility in pipelines often occur

where the fluid velocity is continuously

low enough to promote water accumula-

tion and solid particle deposition. Deposit

or sediment buildup may also allow

UDC mechanisms, such as concentra-

tion cells, to occur. Distinguishing the



relative contributions of the biofilm and

concentration cells, for example, may be

difficult depending on the information

available to the investigator. The second

challenge is effectively collecting and

integrating corrosion, microbiological,

chemical, operational, design, mitigation,

and metallurgical data to determine the

predominant corrosion mechanisms that

are present. Corrosion threat assessment

for MIC should be conducted in view of all

other applicable corrosion mechanisms

for the asset. Identifying the predomi-

nant corrosion mechanisms supports the

establishment of mitigation measures

that are likely to have the greatest benefit.

Finally, establishing MIC as the probable

cause of corrosion in a failed component

may be particularly difficult since the

failure event itself is likely to have altered

the conditions that caused the corrosion

damage. Careful sample preservation

and field sample collection from repre-

sentative undamaged areas can aid in

forensic corrosion investigations. The

identification of MIC as a damage mecha-

nism should not be based solely on the

presence, number, or type of microorgan-

isms on a corroded component.

Lee: MIC is a very subtle study. Rarely

can a case of suspected MIC be confirmed

without evidence from multiple analysis

techniques and sciences. The presence

of microbes alone does not prove the

existence of MIC. Microorganisms exist

throughout the environment. The greatest

challenge is proving that microorganisms

actually influenced the electrochemi-

cal properties of the system. In addition,

higher numbers of microorganisms do

not necessarily mean increased likeli-

hood of MIC. Molecular techniques are

required to detect the individual activities

of each microbe species. A system baseline

of normal operating conditions, where

predictable corrosion occurs (e.g., uniform

corrosion of carbon steel [CS] in fresh-

water), is required for comparison with

suspected MIC cases.

Jenneman: There are really no

definitive tests or accepted standard-

ized methodologies that can be applied

to directly implicate MIC as the probable

cause. It is often determined through

a process of deduction of the facts

and elimination of other mechanisms.

Therefore, a challenge is to develop

standardized tests and approaches that

can be widely accepted by the industry.

However, MIC is a complex problem

involving various aspects of materials

science, electrochemistry, and microbiol-

ogy that necessitates the involvement

of scientists and engineers from various

disciplines to take on this challenge. Also,

the potentially large number of microbial

types and activities involved challenges us

to develop better mechanistic understand-

ings of how these microorganisms and

activities influence corrosion processes.

Little: MIC does not produce a unique

corrosion morphology, making it impos-

sible to identify MIC without specific

testing.

Le Borgne: Challenges include the

nature of the collected samples and

whether they are from biofilms or bulk

water. Only microorganisms in biofilms

influence the corrosion process, although

these microorganisms proceed from

the surrounding bulk liquid phase. The

number of corrosive or potentially corro-

sive microorganisms detected in the

bulk water is not related to the intensity

of the attack. Live microorganisms may

not be detected in the samples, but dead

organisms that participated in the attack

or influenced the corrosion process are

present on the surface of the material and

in the corrosion products. The microor-

ganisms may act as consortia and not as

isolated organisms, which may complicate

the diagnosis and interpretation of the

data.

Different techniques are available

for studying and diagnosing MIC. These

analyses are generally performed in paral-

lel and a multidisciplinary approach is

necessary and might not always be easy to

manage. There must be a link between the

microbiological studies, the pit morpholo-

gies, and the composition of the corrosion

products in order to clearly establish MIC

as a corrosion mechanism, which may

contribute from 0 to 100% in a corrosion

process.

MP: Are current identification technol-

ogies adequate or is additional research

necessary to develop more effective

methods to identify MIC?

Little: The identification tools that can

be used to determine that MIC has taken

place appear to be adequate. There are

recent refinements in sample preparation

and fixation for more accurate molecular

analyses. However, there are few tools/

technologies for predicting MIC before it

occurs.

Eckert and Skovhus: Current technol-

ogies, when used in combination with each

other, can usually provide adequate infor-

mation to assess and characterize MIC.

Since MIC must typically be diagnosed

using a combination of data (chemical,

microbiological, metallurgical, opera-

tional, etc.), no single technology or tool

can reliably identify MIC in all cases. Many

operators have used extended coupon

analysis to collect chemical, microbiologi-

cal, and corrosion data from one sample

point with much success. The integration

of results from MMM with other corrosion

information is one area where additional

research is needed to take advantage of

the vast amount of information provided

by genetic technologies.

Researchers and asset owners are both

continuing to find new insights resulting

from collaboration between corrosion/

materials professionals and microbiolo-

gists. Distinguishing the effect of MIC in

combination with other abiotic exter-

nal corrosion mechanisms on buried

metallic structures and the influence

of cathodic protection (CP) potentials

more negative than –850 mV are other

areas that deserve further attention and

additional research—the pipeline industry

would benefit from additional engineering

guidance in this area.

Lee: Additional research is needed in

development of a link between biologi-




FEATURE ARTICLE

cal activity and corrosion rate. Real-time

monitoring of corrosion rate and

microbiology currently is not available.

Lab-on-chip devices being developed

are promising for use in microbiologi-

cal monitoring programs, but academic

disagreements still exist on which

microbial markers are most important.

Corrosion sensors have also become more

sophisticated, but still lack the ability to

be used in prediction of long-term corro-

sion susceptibility.

Le Borgne: Many identification

technologies are available to provide a

complete description of systems where

MIC might have occurred. Some of these

techniques require specific expertise

and do not give an immediate response.

However, more research is required in

order to develop portable devices or

online/remote sensors to detect MIC. The

development of international standards

and actualized protocols and programs

that take the peculiarities of each system

into account and allow the determination

of risk factors is also needed to prevent

MIC before it occurs in different facilities.

Jenneman: Better methods are

definitely required to identify MIC. The

traditional culture testing is very slow and

does not give a very complete picture of

the microbial communities involved in the

corrosion. The newer molecular methods

(e.g., DGGE, qPCR, and metagenomic

sequencing) are gaining more widespread

use and may eventually replace culture

testing as costs decrease and availability

of these technologies to oilfield end users

increases. They do have the advantage

of providing a faster and more complete

picture of the microbial communities,

but they currently require highly skilled

professionals to perform the testing and

interpret the results. There are currently

no accepted standards by which these

tests are performed and no accepted

models to help the end user interpret the

results.

These tests are typically outsourced

to specialized laboratories and require

the end user to understand the poten-

tial pitfalls of sampling, preservation,

procedural nuances, and interpretation

of results. There are currently industry-

sponsored programs aimed at applying

genomic technologies to better under-

stand and identify MIC.

MP: When MIC is established as the

corrosion mechanism, what are the

mitigation and monitoring strategies

typically used? Are these strategies

effective?

Eckert and Skovhus: Common strate-

gies for internal MIC mitigation in oil and

gas pipelines include maintenance pigging

and chemical treatment. Depending upon

the pigging frequency and pig design,

maintenance pigging can be effective in

removing deposits/biofilm that promote

MIC. A further benefit of removing

deposits is increasing the effectiveness of

chemical treatment by allowing the chemi-

cal to reach the exposed metal surface.

Chemical treatment is typically

performed using corrosion inhibitors

(some with the added benefit of a biocidal

tendency), biocides, and combinations of

these chemicals. External MIC on buried

structures and pipelines is more challeng-

ing to diagnose and mitigate properly,

since nearly all soils are naturally rich with

microbiological activity. Furthermore, CP

and an external coating are essentially the

only mitigation options for external corro-

sion (including MIC) on direct buried pipe.

Pipeline industry guidelines often call for

applied potentials more negative than

–850 mV when MIC is suspected; however,

additional research is needed in this

area to validate the effectiveness of more

negative potentials in consideration of

other parameters that influence external

corrosion of buried structures.

Regardless of the type of system,

monitoring the effectiveness of MIC

mitigation measures must include

corrosion monitoring in addition to

any microbiological monitoring that is

performed, since ultimately the goal of

mitigation is to control corrosion. Often

MIC mitigation programs are focused on

measuring microbial numbers, types, or

activity, which can be helpful in optimiz-

ing mitigation but is not a replacement for

corrosion monitoring.

Little: Accelerated low water corro-

sion (ALWC) of CS in saline waters is a

form of MIC most often attributed to

microorganisms in the sulfur cycle (i.e.,

SRB and sulfur-oxidizing bacteria). Both

CP and coatings have been effective in

preventing ALWC.

Jenneman: Biocides are still the

chemicals of choice when mitigating

MIC; however, biocides usually need to be

combined with a mechanical or chemi-

cal cleaning program to enhance their

effectiveness, especially if the biofilms and

corrosion are already firmly established.

Biocides are comprised of both oxidizing

and non-oxidizing chemicals. Both can be

effective, but the environment and metal-

lurgy will often dictate the choice.

Other strategies are possible, including

the injection of biostats or inhibitors. We

have found that some low-toxicity film-

forming corrosion inhibitors can inhibit

MIC development in model laboratory

flow cells. Other tactics include develop-

ing new chemicals and surfaces (e.g.,

nanomaterials) that will not allow bacteria

to attach and form biofilms, or destroy

microorganisms on contact. In addition,

application of natural chemicals can inter-

fere with the quorum sensing capacity that

microbial communities rely on to form

mature biofilms, potentially rendering

them less corrosive.

Unfortunately, much of the testing to

evaluate these techniques is targeted at

controlling the microbes themselves and

not the corrosion. Testing that simply

addresses the reduction of microbial

populations without addressing the

changes in corrosiveness is insufficient.

To determine the effectiveness of these

strategies, it is necessary to have effec-

tive monitoring and inspection strategies.

Monitoring can be used to examine the

effectiveness of the mitigation strategy to

deliver the chemicals, control microbio-

logical growth, and reduce corrosiveness



of the environment; however, monitoring

is only as good as the locations selected

and samples collected, as well as the

analyses performed.

Le Borgne: The main problem associ-

ated with the use of chemicals is the

adaptation capacity of microorganisms

that allow them to develop resistance

mechanisms and, in some cases, the ability

to biodegrade these products. Constant

injection of chemical products is neces-

sary. Recently, the injection of nitrate in

oilfields has been described as an effective

technique to control MIC by SRB; however,

the long-term effects of this manipula-

tion of the environment have not been

evaluated. Strategies based on the use of

bacteriophage to control specific bacte-

rial populations have also been proposed.

These strategies, as well as their long-term

effects, have to be tested.

MP: When selecting materials for new

construction and/or predicting material

lifetime, is MIC a consideration?

Lee: In my experience, often times MIC

is not a consideration in materials selec-

tion. Certain materials have been shown

to not be susceptible to MIC (e.g., titanium

and high Ni-Cr alloys), but these alloys are

often cost prohibitive. In the last 20 years,

MIC has gained traction in industrial,

commercial, and military sectors. The

result of unexpected failures due to MIC

has increased the attention of MIC and its

consideration in material selection. While

many sectors are hiring corrosion scien-

tists and engineers to deal with increased

failure concerns, MIC still lags behind in

consideration in the field of corrosion.

Le Borgne: To my knowledge, it is

rarely considered, at least in the systems I

have been involved in. MIC is not usually

taken into account until it occurs and

few reports deal with prevention and

the assessment of risk factors associated

with MIC. If such information could be

systematized and proper documentation

of MIC failures cases organized, then MIC

could be taken into account in materials

selection. Standardized protocols and test

methods are also needed to test for MIC of

materials under laboratory conditions and

norms must be established.

Jenneman: Yes. In some cases, partic-

ularly where the risks (e.g., dead legs and

low-velocity sections) and consequences

are high (e.g., oil and gas lines), we have

changed from CS to corrosion resistant

alloys (typically duplex stainless steels

[SS]) as a means to mitigate the impact

of MIC. I cannot say this will be effec-

tive in all cases, but we have seen good

results in some instances thus far. Also,

the application of fusion-bonded epoxies

to tank bottoms and the use of non-metals

(e.g., glass-reinforced epoxy [GRE] or

high-density polyethylene [HDPE]) for

low-pressure water lines can be effective

strategies to combat MIC. More research is

needed on the effect of MIC in non-austen-

itic, high-alloyed SS and non-metallic

coatings to qualify them for use in various

MIC environments. Unfortunately, to my

knowledge, there are currently no reliable

mechanistic MIC models that can be used

to predict material lifetimes in CS or SS.

Little: Certainly, reports of ALWC as a

global problem in saline waters has forced

design engineers and insurers to question

the probability of MIC in specific locations

and to plan accordingly.

Eckert and Skovhus: The threat of

MIC needs to be considered in the design

of new projects to enable monitoring and

mitigation for managing MIC during the

operational stage of the asset. More impor-

tantly, designing to reduce the potential

for conditions that would promote MIC

(e.g., dead legs, low velocity) should be

part of the development process. Materials

selection should be based upon the antici-

pated operating conditions through the

life of the asset and the intended design

life.

Few metallic materials commonly used

for engineered structures exhibit complete

resistance to MIC, therefore material

selection is usually based primarily on

other engineering requirements for the

project. While a number of models have

been proposed to rank the susceptibility of

a system to MIC, widely accepted models

for reliable prediction of MIC corrosion

rates have yet to be developed, and in fact

may remain elusive due to the vast range

of conditions under which MIC can occur.

MP: Recent research has demonstrated

new MIC-based corrosion mechanisms.

Has this new information changed the

approach to managing MIC?

Lee: The traditional understanding of

MIC involves the formation of a biofilm

that provides a niche for corrosive micro-

organisms to proliferate. Recent research

has demonstrated that metal surfaces

alone can produce redox, oxygen, and

nutrient gradients without an established

biofilm. Many mitigation and monitoring

strategies operate under the assumption

of a substantial biofilm presence and treat

accordingly.

Little: The list of microorganisms

that can influence corrosion and the

causative mechanisms is constantly

growing. Recent research has, in general,

demonstrated the metabolic flexibility of

causative organisms. Most recently it has

been demonstrated that some bacteria

can accept electrons for iron (iron is the

electron donor). However, it is not clear

that increased understanding has trans-

lated into increased predictability.

Eckert and Skovhus: Research contin-

ues to confirm that MIC does not occur

by any single, exclusive mechanism, and

that various microbial consortia in differ-

ent environments have established novel

ways to use the energy sources available to

them. The increased knowledge of micro-

organisms in industrial systems brought

about by application of genetic methods

has resulted in new understanding, and at

the same time raised new questions about

how the activities of specific microorgan-

isms contribute to corrosion. Increased

knowledge of the ways in which microor-

ganisms influence corrosion through both

biotic and abiotic processes will ultimately

lead to improved mitigation and monitor-

ing strategies and technologies. However,

even with improved understanding of MIC




FEATURE ARTICLE

mechanisms, development and implemen-

tation of innovative MIC management

technologies will take time.

Jenneman: The recent revelations

of the ability of certain SRB and metha-

nogens to directly use electrons from

metallic iron prior to the formation of

molecular hydrogen is indeed opening

our eyes to the different ways in which

microorganisms can influence corrosion

and to the need to expand our approaches

and methods when looking for these

causative agents of MIC. We need to better

understand how these microorganisms

accomplish this and how to detect their

presence and control their activity. Their

presence and potential activity can also

impact how we currently manage and

formulate the risks to our pipelines and

facilities.

Le Borgne: To my knowledge it has

not changed the approach yet, at least in

the systems I have been involved in. It will

probably take some time until this new

knowledge is incorporated and taken into

account in the field.

References

1 B.J. Little, J.S. Lee, Microbiologically

Influenced Corrosion (Hoboken, NJ: John

Wiley & Sons, 2007).

2 NACE Standard TM0194-2004, “Field

Monitoring of Bacterial Growth in Oilfield

Systems” (Houston, TX: NACE International,

2004).

3 NACE Publication 3T199, “Techniques

for Monitoring Corrosion and Related

Parameters in Field Applications” (Houston,

TX: NACE, 2013).

4 NACE Standard TM0212-2012, “Detection,

Testing, and Evaluation of Microbiologically

Influenced Corrosion on Internal Surfaces of

Pipelines” (Houston, TX: NACE, 2012).

5 NACE Standard TM0106-2006, “Detection,

Testing, and Evaluation of Microbiologically

Influenced Corrosion (MIC) on External

Surfaces of Buried Pipelines” (Houston, TX:

NACE, 2006).

Bibliography

A Practical Evaluation of 21st Century

Microbiological Techniques for the

Upstream Oil and Gas Industry, 1st Edition

(London, U.K.: Energy Institute, 2012).

H.A. Videla, Manual of Biocorrosion

(Boca Raton, FL: CRC Press, 1996).

S.W. Borenstein, Microbiologically Influenced

Corrosion Handbook (Cambridge, U.K.:

Woodhead Publishing Ltd, 1994).







http://jotun.com

http://jotun.com

CATHODIC PROTECTION

I

Inline cathodic protection (CP) in-

spection was frst announced in Mate-

rials Performance in June 2008 and

has been commercially available since

then. Since its introduction, more than

3,000 miles (4,800 km) of hydrocarbon

pipelines have been inspected using

this relatively new technol ogy, which

reveals issues with a pipeline’s CP sys-

tem that often go undiscovered using

conventional technologies.

In the early 2000s, Shell Global Solutions

and Shell Pipeline Co. began testing the

feasibility of an inline current measuring

tool. There was a clear need in the industry

for a more efficient and reliable means of

evaluating pipelines, particularly those

that were difficult to access with conven-

tional assessment techniques such as

close-interval survey (CIS) or direct

current voltage gradient (DCVG) methods.

This need led to the development and

subsequent patent of the inline cathodic

protection (CP) current measurement tool

in 2006. Baker Hughes licensed and

commercialized this technology in 2008.

Today, inline CP current measurement

tools have been used by numerous opera-

tors worldwide to provide insight into CP

current distribution on pipelines. This

article outlines the lessons learned in using

inline CP inspections.

Lesson One— Internal Cleanliness

Not all pipelines are good candidates for

inline CP inspections. Inline CP tools are

direct measurement tools requiring good

electrical contact to the internal pipe wall

to be able to measure the small voltage

drops created by CP current f low. This

requires the candidate pipeline to be quite

clean to allow for good tool-to-pipe contact.

Crude oil pipelines typically present the

least amount of contact problems. They are

usually cleaned on a fairly frequent basis

and do not usually require a great deal of

pre-inspection cleaning to gather good

inline CP inspection data.

Refined products pipelines are generally

thought of as “clean” pipelines as long as the

end product shows little contamination.

While they may usually deliver “on-spec”

product and do not commonly have debris

issues, refined products pipelines are typi-

cally cleaned less frequently than their crude

oil counterparts. Experience has shown that

these pipelines are often problematic from

an electrical contact standpoint when con-

ducting CP inspections. They generally

require a higher level of pre-inspection

cleaning to ensure successful inline CP

inspections. There are simple, low-cost tools

available to clean these refined products

pipelines in one or two passes. These tools

also have the ability to gauge the level of

cleanliness and the probability of sufficient

contact for a successful inline CP inspection.

Lessons Learned: Monitoring Cathodic Protection Current from Inside the Pipe

Dennis JanDa anD DaviD Williams,

Baker Hughes, Inc., Houston, Texas



Figure 1 shows raw inline CP voltage

plots from two inspections of the same

refined products pipeline made roughly

one year apart. The top graph shows exces-

sive noise from insufficient cleaning and

poor electrical contact. Data in the lower

graph were obtained after two passes with

a cleaning and contact-verification tool.

Data quality was improved dramatically.

Natural gas pipelines present a signifi-

cant challenge for inline CP inspections.

They are difficult to clean because the

oxides and debris scraped off the pipe wall

in the cleaning process are not suspended

in a liquid and carried out with the flow of

product. Electrical contact is usually spo-

radic at best. While contact is usually not

sufficient to return good direct current

(DC) data in gas pipelines, alternating cur-

rent (AC) data do not seem to be affected as

much and are often suitable for analysis.

Speed excursions in gas pipelines can be

problematic because of the light weight of

the inline CP tools and their low-friction

design.

Newer pipelines that still retain a good

deal of internal mill scale on the inner pipe

wall make contact and voltage drop mea-

surement difficult. This is often com-

pounded by the fact that newer pipelines

typically have very good coating systems,

and therefore, low current requirements.

Less-than-perfect contact can be tolerated

much more in older high-current lines, but

it can be problematic in newer, low-current

pipelines.

Due to the reasons stated above, inline

CP inspections are usually reserved for

older liquid lines. At the moment, natural

gas pipelines are considered for inline CP

inspection only if the primary corrosion

threat is induced AC.

Lesson Two—

Documentation of

Current Sources

Inline CP tools excel at locating all cur-

rent sources on the pipeline, as well as

undocumented bonds/drains/shorts. If an

interrupted CIS plays a large role in the

integrity management plan, the data must

be reliable. All current sources and drains

FIGURE 1 The effect of internal cleaning on inline CP data.

FIGURE 2 Locating current sources with the inline CP tool.

on the pipeline must be accounted for and

interrupted for the CIS data to be accurate.

Figure 2 presents a few examples of undoc-

umented current sources and drains that

were discovered during an inline CP

inspection.

The undocumented bonds in Figure 2

were underground bonds to an abandoned

pipeline. Multiple pipelines in this right-of-

way had been protected by a common CP

system in the past. The location of the

underground bonds had been lost over the

years.

Occasionally, inline CP inspection tools

do not find CP features that the pipeline

operator expects to see. One particular

inspection did not indicate a rectifier

where expected. This rectifier had been

associated with this particular pipeline for

years. The operator’s first response to these

data was to question the accuracy of the

tool. Excavation of the negative drain cable,

however, revealed that this rectifier was

connected to a different pipeline.

In another case, an inline CP inspection

of an offshore pipeline in the Gulf of Mexico

indicated that six recently installed anode

sleds were not operating. Diver inspection

revealed that the “missing” anode sleds

were either installed incorrectly, never con-

nected to the pipeline, or damaged by a hur-

ricane. The CP tool proved the assumptions



CATHODIC PROTECTION

cient to measure the cumulative effect of

several holidays or the current coming to

the pipe at an uncoated girth weld. Figure

3 shows an example of how these tools

respond to various coatings.

Figure 3 is the current plot from an 8-in

(203-mm) diameter refined products pipe-

line. Approximately 6 miles (9.7 km) of

pipeline are shown in this graph, which

clearly indicates the distinction between

the fusion-bonded epoxy (FBE) coating

( flat slopes) and the 1950s coal tar (steep

slopes). The coal tar areas exhibit very

similar CDs in the 2 to 5 mA/ft2 (22 to 54

mA/m2) range, while the FBE-coated areas

have a CD of 0.013 to 0.015 mA/ft2 (0.14 to

0.16 mA/m2). This line is actually overpro-

tected because the CDs in the FBE-coated

pipe are more than double what is nor-

mally seen on well-protected pipelines

with FBE coating.

In the analysis of inline CP current data,

the pipeline is segmented into discreet

areas that exhibit linear CD. In other words,

each time the slope of the current plot

changes, a new pipe segment is identified.

These segments are tabulated in a CD

report. This makes it quite easy to scan

down the report and highlight areas of high

or low CD.

Lesson Four— Finding Cathodic

Protection MalfunctionsWhat you don’t know about your pipe-

line can hurt you. Figure 4 is a good exam-

ple of two conditions on a pipeline that

could have caused serious problems had

they not been discovered. In this graph at

312 ft (95 m) from the launch, a 3.8-A loss to

an abandoned pipeline was discovered.

This correlated with a “close metal object”

call in the previous metal-loss inspection.

At 12,000 ft (3.6 km) from the launch, a 73-A

rectifier can be seen. It protects only ~2,000

ft (609 m) upstream to a block valve. There

is no current on the line upstream of this

valve. It was determined that inline isola-

tion must exist at the valve, thus blocking

protection upstream . The operator

reported good historic pipe-to-soil poten-

tials at this valve and felt the call must have

FIGURE 3 Determination of coating quality.

FIGURE 4 Locating CP malfunctions.

used in the design of the anode sled system,

and also was a good quality assurance/qual-

ity control (QA/QC) tool to confirm proper

installation by the diving contractor.

Inline CP tools also excel at locating

shorts in casings. The tools do not have the

ability to detect casings, but when data

from previous magnetic f lux leakage

(MFL) inspections are imported into the

inline CP database and properly aligned,

the casing starts and ends are identified.

The CP tool not only detects the current

passing from the casing to the pipeline

through the short, it also pinpoints the

location of the short.

Lesson Three— Inline Cathodic Protection Data and Coating QualityThe very nature of the data that inline

CP tools gather makes these tools excel-

lent for coating evaluation. Since the tools

are measuring the CP current that has

been received by the pipeline and is flow-

ing back to its source, it is quite simple to

calculate how much current any given

area has received. There is a direct corre-

lation between current density (CD) and

coating quality, which can be easily seen in

inline CP current plots. Steep slopes in the

current plot indicate high CD, while flatter

slopes indicate lower CD.

It is important to understand that

these tools are measuring the voltage drop

in the pipe wall over a fixed distance of

6 to 9 ft (1.8 to 2.7 m) (the distance

between the front and rear contacts on the

tools); therefore, they should be consid-

ered macro tools rather than micro tools.

They do not have the resolution to detect

how much current a small coating defect

is picking up, but the resolution is suffi-



been in error. Excavation of the buried

valve revealed an isolator on the upstream

flange with a broken bond wire across it.

The short to the abandoned pipeline along

with the inline isolator were preventing

protective current from reaching a 10,000-

ft (3-km) long section of this pipeline.

Proximity to a large rectifier and high

potentials at the valve gave the operator a

false sense of security about the protection

across this pipe segment; this section of

pipeline was under a major waterway.

Lesson Five— Effects of Inconsistent

Flow RatesSpeed and internal pipe conditions can

have an impact on inline CP data, but this

depends heavily upon the internal rough-

ness of the pipeline being inspected. In gen-

eral, electric resistance welded (ERW) pipe-

lines can tolerate higher speeds than

seamless or spirally welded pipelines. It

must be remembered that these CP tools

are measuring very small voltages—usually

microvolts. Excessive speed in rough pipe

can have a negative impact on the data.

Speeds of ~2 mph (3.2 km/h) are usually

ideal in most pipelines. Figure 5 shows

the effect of inconsistent flow rates (slack

line conditions) in a spirally welded 24-in

(610-mm) pipeline.

Lesson Six— Locating Interference

Interference is often a much misunder-

stood phenomenon. Many technicians

often think that their pipeline is experienc-

ing interference from a foreign source be-

cause they see potentials change when the

foreign source is cycled. True interference

occurs only when current is ex changed

through the electrolyte from one structure

to the other. As part of a 2010 Pipeline

Research Council International (PRCI)

project, inline CP tools proved they can lo-

cate and quantify interference currents. In

more than 3,000 miles (4,827 km) of inspec-

tions, however, this phenomenon has rarely

been seen. Potential shifts observed during

foreign rectifier cycling are often mistaken

for interference.

ConclusionsInline CP current measurement tech-

nology is gaining use and acceptance

worldwide as a valid inspection technique.

It has a good record of success in liquid

pipelines. While it may not be the right tool

for every pipeline, when it is used in the

right pipeline under favorable conditions,

it continues to reveal information that can

be overlooked by other technologies. Better

understanding of a pipeline’s CP system

will lead to improved integrity of pipeline

assets.

DENNIS JANDA is a business development manager for Baker Hughes, Inc., Process and Pipeline Services, 2301 Oil Center Ct., Houston, TX 77073, e-mail: [email protected]. Janda has been a member of NACE International since 1983.

DAVID WILLIAMS is a cathodic protection specialist for Baker Hughes, Inc., Process and Pipeline Services, e-mail: [email protected]. Williams has been a member of NACE International since 1976.

FIGURE 5 Effect of inconsistent fow rates on tool data.


Lessons Learned: Monitoring Cathodic Protection Current from Inside the Pipe


http://www.anotec.com





BLOG

Continued from The MP Blog, p. 13.

The following items relate to cathodic

protection.



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.

Performing DCVG survey on a pipeline close to a power line

Q: I came across a problem when surveying a pipeline close to an

overhead power line. Induced alternating current (AC) voltage on the line is about 1 V. The impressed direct current voltage gradient (DCVG) signal on the pipe is ~750 mV. When surveying the line, the needle (analog display) on the DCVG meter (input impedance 1 MΩ) stays to one side and cannot be centered using bias handles. I believe it is because of the induced AC in the DCVG meter circuit (DCVG probes and connecting leads). With the same set of equipment we are able to locate coating anomalies on other pipelines. Also, we are able to move the needle of the DCVG meter using bias handles once the surveyor is ~100 to 200 ft (30 to 61 m) away from the power line. Has anyone had a similar situation and found a solution for it?

A: Have you tried reading the over-the-ground voltage DC using two

reference cells and a common voltmeter? If there is a strong gradient, this may cause you problems but I think that the AC induced voltage won’t disturb your DC readings.

A: I have observed the analog meter needle oscillating at a very high

frequency in the presence of AC. Te span of the needle movement may be 1 mm or a little more. Tis was right underneath a 400-kW power line. But I could move the oscillating needle from left to right using a bias probe.

Installation of horizontal anodes

Q: I am considering a horizontal groundbed design. I propose

making a continuous trench 200 ft (61 m) long and 1 ft (0.3 m) wide with 10 mixed metal oxide (MMO) anodes equally spaced along the trench. In the area of the anodes, I propose to have 6 in (152 mm) of backfill (calcined petroleum coke) around each anode, making it nominally 1 ft thick. I would maintain this thickness 1 ft off each end of the anode. In between the anode areas, I would only use 6 in of coke.

Is it reasonable to consider this a single horizontal anode 200 ft long and nominally 6 in in diameter? It seems this would be a conservative assumption, and



http://www.densona.com



it would only be slightly non-conservative to assume a 12-in diameter. For 20,000 Ω-cm soil, this would keep the system under 5 Ω. What standard shows a diagram of horizontal anodes with backfill, vent, and their specification?

A: A horizontal groundbed is a simple installation. It does not

require vent pipes. A.W. Peabody’s book, Peabody’s Control of Pipeline Corrosion, discusses it in detail and also shows equations to calculate anode-to-ground resistance, which depends on anode diameter, length, and the soil resistivity. Peabody’s second edition comes with a CD containing programs to calculate the resistance.

A: Horizontal anodes are normally buried ~1.5 m deep; the anodes

are made of various materials (MMO is my preferred choice). Te backfll surface area and type are the critical factors in calculating the size of the groundbed. Te backfll should be 99% carbon, 1 mm nominal grain size. Te anode should be placed in the center of a 300- or 200-mm carbon column. Te modifed Dwight formula should be used to estimate the circuit resistance of the groundbed. Te consumption rate of the carbon will determine the surface area required; vent pipes are not required for such installa-tions. Some users have codes of practice but these codes can quite often be rigid and out of date.

A: You can’t consider this a truly continuous bed. With a center-to-

center anode spacing of ~20 ft (6 m), you will get an uneven anode-to-ground resis-tance along the length of the groundbed because of the alternating surface area of the coke breeze and the distance between the anodes. You have a coke perimeter of 4 ft (1.2 m) around the anodes and ~20 ft between them; the perimeter of the coke between anodes is 2 ft (0.6 m). Tis is not like a deep anode bed where the coke column is of uniform diameter and the anodes are 1 or 2 ft apart. Te anode length is the length of the anode itself

plus 2 ft of coke and the anode diameter is equivalent to the 1-ft square surrounding coke, or 1.27 ft (0.39 m).

Preparation of deep anode groundbed

Q: After drilling a deep groundbed and putting in the anodes, the

next step is to fill the active area with carbonaceous coke. The type of coke that I am concerned about is granular coke. Should I pour this coke directly into the hole or first mix it with water? Also, how should I increase the contact of the anode with the granular coke? Should I add water after loading the coke? Does adding water cause a gas trap?

A: Tere are a number of ways to do it. If your hole was drilled with a

rotary mud drilling rig, it will be full of water and drilling fuid and the coke breeze may or may not freefall to the bottom, depending on the viscosity of the fuid. Te viscosity depends on whether or not your driller “thinned” the fuid before loading the anodes. Some people use powdered coke breeze mixed with water to fuidize it. Ten they pump it from the bottom of the hole upward using a tremie pipe. Tis method will sometimes take a day for the coke to fully settle and compact around the anodes. Be sure to withdraw the tremie pipe as you pump or else it will get locked in under the weight of the coke.

If it is a dry hole, top-loading is possi-ble, but you must be careful that the coke doesn’t “bridge” from loading it too rapidly, or from large angular coke breeze. Granular coke f lows best. Monitor your anode-to-earth resistance during the loading process. When you see a significant drop in resistance, you can assume that particular anode is covered. Successfully loading deep anode wells is an art and will depend a lot on the geology and drilling method. A good, experienced anode well driller is key.

A: Refer to NACE RP0572, “Design, Installation, Operation, and

The backfill surface area and type are the

critical factors in calculating the size of the

groundbed.



http://www.tinker-rasor.com






Maintenance of Impressed Current Deep Groundbeds.” Pouring is not the best way to fll in the active area. A water/coke mix is advisable but not always economical if your anode bed is not very deep.

Aluminum anodes

Q: Could you tell me in what resis-tivities aluminum anodes work

efficiently? Is there any standard stipulat-ing the water resistivity values? For example, NACE standards state that zinc with gypsum and bentonite backfill are used in soils having relatively low resis-tivity (<2,000 Ω-cm).

A: Normally aluminum anodes are used only in seawater, which has

a resistivity of ~25 Ω-cm. Even then they have a small amount of alloying to prevent passivation. Aluminum anodes generally require chloride ions in the electrolyte to function properly. As the quantity of chloride ions decreases below normal seawater concentrations (3.5%, or 35,000 ppm), the current capacity of the anode decreases, and the anode potential becomes more noble. Refer to the NACE

Corrosion Engineer’s Reference Book, Tird Edition, in the chapter “Design Criteria for Ofshore Cathodic Protection Systems” (p. 163).

A: Aluminum alloy anodes require the presence of chloride ions to

prevent passivation. Obviously, an environment with a sufcient amount of chlorides to operate the anodes will have a low resistivity, but resistivity is not the key factor. We could have a medium with low resistivity, but if there are no chlorides, the anodes will not work. According to S.N. Smith, et al. (MP 17, 3 [1978], p. 32), the minimum required chloride concentration in waters is ~1,800 to 2,000 ppm.

C.F. Schrieber and R.N. Murray (MP 27, 7 [1988], p. 70) found that Al-Zn-In-Si anodes in brackish waters >12% seawater strength exhibit current capacities (A-h/kg) equal to those observed in full-strength seawater. At saline strength <12%, severe capacity scatter was observed. Anode potentials show accept-able values (–1.07 to –1.10 V vs. silver/silver chloride [Ag/AgCl]) through 33% strength seawater. At ~20% seawater strength and less, noticeable potential variance will occur.

Aluminum alloy anodes require the

presence of chloride ions to prevent

passivation.


BLOG


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Fax: 562-438-7151

E-mail: [email protected]

Who doesn’t have

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corrosion around

hand holes?You clean the hole. You coat the hole.

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You install the hand hole cover.

The gasket invariably sticks to the tacky coating.

Now, you need to take a potential reading, so you must remove the

hand hold cover.

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You damage the coating getting it off.

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The Hand Hole Liner Grommet

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Cathodic protection for tank bottom

Q: What is the best system for protecting a coated tank bottom

on the soil side with a high-density polyethylene (HDPE) liner present? The system will be installed between the HDPE liner and tank bottom. Should we use mixed metal oxide (MMO) strips or wire in a grid or polymer anodes?

Our experience shows that MMO strip anodes in a grid is the best system based on the past eight years of use. Will gases be generated at the anode surface due to anodic reactions? How will these be dissi-pated? Or will they get entrapped under the steel tank bottom?

A: In your case, I would prefer the cathodic protection (CP) grid

system with MMO strip anodes and conductor bars. You can also consider other alternatives.

A: I have never heard those concerns, but I also realize that

the tanks are not always full. Emptying and flling the tank causes the tank bottom to fex and separate from the soil surface. Tis phenomenon might also help release any gas trapped in the inter-face due to the anodic reaction.

One way to prove that this situation is not happening is to measure the circuit resistance after the system is working. If gases are generated during the anodic reaction and cannot be released, it is most likely that the circuit resistance will increase. I do not remember seeing this change in the circuit resistance in regular aboveground tank CP systems. Of course, you have to be sure that you are taking the measurements with all other condi-tions remaining the same; for example, measure the tank liquid level every time you are inspecting the tank CP system.

A: I prefer the MMO grid system, mostly because I believe the resis-

tance will be quite low and the installa-tion is really fast. Any good design with other systems might work as well or in some cases even better depending on the conditions and workmanship. You can design with MMO using a spiral or several concentric circles.



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COATINGS & LININGS

I

For more than 60 years, internal plas-

tic coatings have been used for corro-

sion protection on tubing, casing, line

pipe, and drill pipe. One of the histo-

ried concerns with the use of these

coatings is the threat of mechanical

damage and subsequent corrosion.

Applicators have relied solely on en-

hanced surface preparation and ad-

hesion to ensure minimal exposure of

the substrate. Several materials have

been developed that offer abrasion

resistances up to 20 times greater

than what has previously been avail-

able. This article outlines the devel-

opment of these products including

the different chem istries used and the

material’s abrasion resistance.

In the development of abrasion-resistant

internal plastic coatings, one must first

identify the possible abrasion mechanisms

that could occur for these applications.

Three main types of abrasion are found on

the internally coated tubular surface:

wireline abrasion, flowing solids abrasion,

and large body abrasion.

Interaction between a wireline and a

coated surface leads to a cutting action.

Film penetration can be quick, exposing the

steel to the well environment. It has long

been understood that this minimal area of

exposed steel would not lead to accelerated

corrosion because the surface area ratio of

the anode to cathode is very small.1

A second type of abrasion is from the

erosive effects from flowing solids interact-

ing with the pipe wall. Solids contained in

process flow will cause impact as well as

general abrasion. The internal coatings can

possess a surface finish much smoother

than either carbon steel (CS) or 13%

chrome. This lower surface roughness will

reduce the turbulence (shear) at the sur-

face, reducing small particle interaction

and impact.

A third type of abrasion is large body

abrasion, in which wear is associated with

a coiled tubing run or rod or beam pump-

ing production. The abrasive force from

this interaction tends to be spread over a

much larger area and, therefore, the rate of

penetration tends to be much slower than

wireline abrasion. In sucker rod pumping

wells, in conjunction with the direct wear

abrasion from the constant cycling of the

rods up and down the well, there will also

be impact on the coated surface from the

impact of the rod against the pipe wall. A

coating material used in this application

will achieve a higher level of success if it

possesses both abrasion resistance and

impact resistance.

Measurement of Abrasion Resistance

Several laboratory tests were used to

determine the abrasion resistance of poly-

meric coating systems. In one test, ASTM

D4060,2 a flat coated panel of known weight

is rotated under CS-17 abrasive wheels

with a 1-kg load for 5,000 to 10,000 cycles.

Advancements in the Abrasion Resistance of Internal Plastic Coatings

RobeRt S. LaueR, NOV Tuboscope, Houston, Texas



The coated panel is then reweighed to

determine how many grams of coated

material were abraded away every 1,000

cycles. While this provides a comparable

value, the fact that different coating mate-

rials have different densities can yield erro-

neous comparisons. A second allowable

recording method is to measure the thick-

ness of coating material, in mils or microns

(10–6 m), that is lost for every 1,000 cycles.

This method provides for a comparison of

different coating materials and their abra-

sion resistance.

Previous work compared two coating

materials, an older epoxy phenolic coating

and a modified epoxy phenolic coating.3

The modified epoxy phenolic coating con-

tains an inorganic filler package to enhance

the abrasion resistance. During this com-

pletion work, there were a total of 17 frack-

pack completions in which hydraulic frac-

turing ( frack) fluid (viscous fluid containing

either sand or manufactured solids) was

pumped through the internally coated pipe

at velocities approaching 17.07 m/s (56

ft/s). More than 907,184.7 kg (2,000,000 lb)

of frack f luid were pumped and over

41,452.4 m (136,000 ft) of wireline run

through this string. As can be seen in Figure

1, the original epoxy-phenolic coating

(greenish-brown in color) was abraded

down to bare metal in a high erosion zone.

The modified epoxy phenolic coating

(blue-green in color) lost ~12% of its total

film thickness in the same area.

These field results indicate that positive

results with the Tabor Abraser3 testing

yielded positive results regarding the mate-

rials’ ability to reduce the effect of abrasion

in the field (Table 1).

ASTM D9684 has also been utilized to

quantify the abrasion resistance of various

oilfield coatings. In this test, silicon carbide

(SiC) is used to test the erosion/small-body

FIGURE 1 Sections of pipe utilized in SPE 77687 comparing abrasion resistance in the same

completion environment.

TABLE 1. SOURCE COMPANY-GENERATED TABER ABRASER VALUES FOR COATINGS TESTED IN SPE 776873

Coating

Taber Wheels Used

Taber Abrasermg/1,000 Cycles

Magnitude ofImprovement

Taber Abrasermils/1,000 Cycles

Magnitude ofImprovement

Epoxy phenolic CS-17 67 — 0.6 —

Modifed epoxy phenolic CS-17 9 7.4X 0.18 3.3X

impact resistance of the coating system.

The abrasive is allowed to free-fall onto the

coated surface of a metal coupon that has

been secured at a 45-degree angle. The test

determines how many liters of abrasive it

will require to completely penetrate the

coating surface and expose the substrate.

Results are reported in liters of abrasive per

mil of coating removed.

It is important also to understand the

flexibility and impact resistance of the

material to determine how it will handle

large body impact in the presence of abra-

sion, such as in rod pumping applications.

When considering the impact related to

rod pumping applications, current tests do

not generate relevant results. Instead, the

flexibility of the coating has been shown to

be a better indicator of performance in

these applications.

By comparing these test results for dif-

ferent coating systems, it can be deter-

mined which one will have the greatest

level of success in the various types of abra-

sive environments. Table 2 shows the

parameters for each of these systems

including the applications in which they

are historically used. Table 3 outlines and

compares the results for popular internal

coating systems vs. the recently developed

materials that have been designed for

greater abrasion resistance.

Field Performance

Case History 1In this case, an operator completed its

production wells utilizing Grade L-80 CS6

on the bottom half of the well and 13%

chrome on the upper half. The bottom hole



temperature for these wells averages

215.5 °C (420 °F) with a flowing tubing pres-

sure of ~2,000 psi (13.8 MPa). The carbon

dioxide (CO2) concentration ranged from

18 to 22%. At this temperature, there was

insufficient liquid water to cause corrosion

in the bottom section of the well. The tem-

perature at the metallurgy transition depth

is ~160 °C (320 °F). A phenolic novolac

coating system was used in an L-80 CS tub-

ing string in place of the 13% chrome tub-

ing. The wells in this field required numer-

ous wireline interventions. Through Well

#1, there were 18 wireline runs and through

Well #2, there were 33. At the time of this

writing, the phenolic novolac coating sys-

tem is still performing in the well.

Case History 2Rod or beam pumping wells offer a

unique challenge to providing adequate

corrosion protection because of the

dynamics of the system. Abrasive wear cou-

pled with impact can make many standard

corrosion treatment methods ineffective. A

highly deviated rod pumping well experi-

enced premature tubing failures from

excessive rod wear. This was a Christmas

tree well producing ~30 to 35 bbls (4,770 to

5,565 L) of oil and 820 to 840 bbls (130,380

to 133,560 L) of water per day. Rod guides

were not employed to minimize wear. A

variety of coating systems (including

ceramic-filled coatings, nanocoatings,

nylon coating, and penetrants) had been

field trialed in this well and yielded a maxi-

mum tubing life of less than six months.

A modified epoxy coated tubing string

was installed in November 2009 and has

TABLE 2. COATING SYSTEM PARAMETERS

Coating System Maximum Temperature (°F/°C) Applied Thickness (μm) Primary Usage

Phenolic 400/204 127-203 High-temperature/pressure production

Epoxy novolac 400/204 152-330 Product/injection tubing

Epoxy phenolic 400/204 127-229 Drilling/completions

Epoxy 225/107 254-508 Product/injection tubing and line pipe

Modifed epoxy phenolic 400/204 127-229 Drilling/completions

Novolac 300/149 254-457 Production/injection tubing

Phenolic novolac 350/177 152-330 High-temperature/pressure production/injection tubing

Modifed epoxy 225/107 254-508 Product/Injection tubing and line pipe

Modifed novolac 300/149 178-381 Production/injection tubing

TABLE 3. LABORATORY RESULTS FOR COATING MECHANICAL PROPERTIES

Tabor Abraser Test Values

Coating System Mg Lost /1,000 Cycles Mils Lost /1,000 Cycles(A)

Falling SiC L/mil of Coating(B)

Flexibility (%) Elongation

Phenolic 57 0.5 3.4 1

Epoxy novolac 36 0.5 6.8 1

Epoxy phenolic 67 0.6 6 1

Epoxy 53 0.7 14.9 >6

Modifed epoxy phenolic 11 0.18 6 1

Novolac 28 0.38 12 1.5

Phenolic novolac 7 0.065 7.2 1

Modifed epoxy 5 0.025 14.9 >6

Modifed novolac 2.5 0.01 N/A 1

(A)Allows for comparison between materials with different densities.(B)A higher number indicates an improved ability to withstand erosion/impact abrasion.


COATINGS & LININGS


been successful in dramatically extending

the life of the tubing string without the use

of rod guides. The tubing and coating

lasted 22 months in this application before

being pulled and rerun in another applica-

tion, where it continues to provide corro-

sion and abrasion protection.

Conclusions

Internal tubular coatings have been

susceptible to mechanical damage that

could expose the substrate to the corrosive

nature of the production or injection fluids.

Advancements have been made in both

filler materials as well as resin chemistries

that have been shown to increase the abra-

sion resistance of these coating systems by

as much as 50 times. These abrasion-resis-

tant systems have proven themselves to

perform well when subjected to mechani-

cal intervention such as wireline and coiled

tubing, abrasive solids flow such as frack-

ing or the production of sand, and abrasive

wear in conjunction with impact forces

typically seen in rod-pumping applications.

These new coating systems can reduce well

construction costs when compared to

exotic alloys, as well as reduce production/

injection downtime.

References

1 H.G. Byars, “Phorgotten Phenomena: Posi-

tive Effect of Anode-to-Cathode Ratio in

Damaged Coated Tubing,” MP 38, 1 (1999):

p. 51.

2 ASTM D4060-10, “Standard Test Method for

Abrasion Resistance of Organic Coatings by

the Taber Abraser” (West Conshohocken, PA:

ASTM Inter na tional, 2010).

3 R.D. Pourciau, “Case History : Internally

Coated Completion Workstring Successes,”

SPE Annual Technical Conference 2002, SPE

77687 (Richardson, TX: SPE, 2002).

4 ASTM D968-05 “Standard Test Methods for

Abrasion Resistance of Organic Coatings by

Falling Abrasive” (West Conshohocken, PA:

ASTM, 2010).

5 R.S. Lauer, “New Advancements in the Abra-

sion Resistance of Internal Plastic Coatings,”

Abu Dhabi International Petroleum Exhibi-

tion and Conference 2012, SPE 162182 (Rich-

ardson, TX: SPE, 2012).

6 API Spec 5CT, “Specification for Casing and

Tubing” (Washington, D.C.: API, 2012).

This article is based on CORROSION 2013

paper no. 2208, presented in Orlando, Florida.

ROBERT S. LAUER is the director of Co rrosion Control Solutions at NOV Tuboscope, 2835 Holmes Rd., Houston, TX 77051, e-mail: [email protected]. He has worked with internal tubular coatings

for the company for 13 years in both research and technical support. He pub-lished an article in World Pipelines and has presented papers for NACE, SPE, and IADC conferences. He received three U.S. pat-ents for developed materials. A 12-year member of NACE, Lauer is chair of NACE Task Groups 486 and 488.


Advancements in the Abrasion Resistance of Internal Plastic Coatings


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Continued from The MP Blog, p. 13.

The following items relate to coatings

& linings.



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.

Copper slag embedded in blasted surface

Q: The external side of a ship hull

was blasted with copper slag to

SA Standard 2.5. During the visual

inspection, we found that the copper slag

was embedded in the surface and could

not be removed with high-pressure

compressed air. We need to ensure the

quality of paint work to achieve a dock-

free life of 20 years. The coating to be

applied is solvent-free surface-tolerant

epoxy. What are the causes for the

contamination? Is there any guideline or

standard to refer to? What will be the

consequences if the coating is applied

over the existing blasted surface?

A: As a contractor, we used copper

slag when it was not feasible to

use chilled iron. Copper slag is a nonfer-

rous abrasive, so attempts should be

made to remove it where possible.

Overcoating should not cause a problem,

although it is not very satisfactory

visually. Te usual cause for contamina-

tion would be excess abrasive being

blown onto the surface in the vicinity of

sprayed work.

A: Your SA standard covers the

surface, which should be free of

contaminants and near-white where

almost all mill scale rust and foreign

matter are removed to the extent that

only traces remain in the form of spots or

stripes. Te copper slag you are using is

fracturing when it hits the surface,

embedding itself in the steel. One cause of

this may be too high an air pressure or

poor-quality slag. I recommend changing

your abrasive to garnet, which will not

give you this problem. Another solution is

to brush-blast the area with ilmenite to

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remove the slag. Tese alternatives are

expensive but much cheaper than a

repaint.

A: Garnet has a blocky, sub-rounded

shape, which reduces embedment

signifcantly compared to some slags.

Clearly, the energy requirement for clean-

ing is lower compared to the energy

requirement for the abrasive blast that is

causing high embedment. Tis would be a

problem in a case where the application is








critical and has a high expected service life. Copper slag to SA 2.5 has been used for a very long time quite successfully. Personally, I like to have a surface as well-prepared as possible and would not like to compromise in this critical area.

Coatings for pipelines near cooling towers

Q: High-build epoxy paint is being used to paint pipelines in the

vicinity of cooling towers. Within five to six months, the paint is peeling off and the carbon steel pipes are nesting. The most likely reason is the chlorination unit near the cooling tower that probably gives rise to acid formation. Can anyone suggest a suitable coating system (includ-ing surface preparation) for such an application?

The second problem is discoloration of the paint where it has not peeled off. White water marks appear from water drips/splashes. Apart from preventing the dripping or splashing on the pipeline to prevent discoloring, what else can be done to avoid the problem?

A: Te surface preparation methods should include a process of

contamination analysis including salts such as chlorides and sulfates. Use of chloride and sulfate testing followed by decontamination is advisable. After decontamination, blast clean to the Swedish Standard Sa 2.5 cleanliness with a 2- to 3-mil profle.

Concerning a coating system, I have seen a multi-coat high-solids (90%+) high-build polyamide epoxy (7 to 12 mils) provide 10+ years of service life on this level of cleanliness to a steel surface when protected from ultraviolet (UV) light exposure. Use a UV topcoat of an acrylic or urethane/acrylic type to provide good atmospheric UV resistance. Industry still looks positively on zinc-rich primers with subsequent barrier films as well.

The cause of the spotting is likely evaporation of water and residual salt deposits. Solving this problem may require looking at the source of the water, which is probably “blow-by” related. If the problem is basically aesthetic, select a light color topcoat to minimize the appearance of light water spotting.

A: Your discoloration problem is probably just a continuation of

Check your wash water. It is not unusual in

many parts of the world to find that the

available water is high in chlorides.


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http://www.tuboscope.com



the contaminant fallout from the cooling tower. Te diference is that the reaction is with the epoxy topcoat that has begun to chalk from the UV rays of the sun.

This chalky deposit contains mostly pigments that are no longer bound by the epoxy resin that has degraded from UV exposure. Thus, the fallout has a nice soft layer to land on and react with, causing the spots.

You could reduce this considerably by applying a high-gloss acrylic polyure-thane topcoat over the epoxy system. You will have to use a surfactant-type cleaner and power wash the epoxy topcoat before applying the polyurethane.

One more word of caution: check your wash water. It is not unusual in many parts of the world to find that the avail-able water is high in chlorides. If so, you will have to use demineralized or deion-ized water for your final wash to avoid leaving a film of chlorides on the substrate.

A: If the problem with the short life of the paint is contamination of

the surface, then care must be taken to prevent recontamination between clean-ing and applying the primer coat. Tis may require containment to prevent infl-tration of the airborne contaminants onto the surface (the opposite reason than for lead abatement).

The final coat to alleviate the runny appearance and provide further protec-tion could include a “graffiti guard” type coating. It has a variegated appearance of multiple colors and a very slippery surface that allows easy washing of almost any substance with a high-pressure water washer or steam cleaner.

A: Te chlorination process has most likely left high levels of

chlorides in the pores of the carbon steel. It is also likely that previous surface preparation attempts, such as sandblast-ing, have impinged chlorides into the steel itself, like the pits. Tese salts are extremely hygroscopic. Left on the steel under any coating system, they will suck moisture into the steel, where the chlorides are entrapped. Te chlorides will expand, causing the flm to swell, crack, and fnally peel.

Using reinforcing particles such as glass f lake doesn’t help because, as the moisture is drawn into the film, it has to

weave in around the f lakes. This works like a filter to purify the water to some extent. Mixing pure water with chlorides creates a mild form of hydrochloric acid (HCl). This will cause the coating to peel dramatically.

The discoloring is typical of epoxy coatings exposed to UV but is most likely not limited to epoxies as far as the water spotting is concerned. The effect of salts on the surface from the cooling water and








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er guidelines for developing a MSD. The minimum and optional information to be included on the MSD

are defned. Guidance is also provided on key issues that arise when materials are selected.

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tion (QA/QC) and conforming work is placed upon the contractor rather than upon owner inspection,

which is currently the most prevalent practice. The webinar also contends that the owner must provide

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chlorides will naturally cause such discoloring.

I would suggest starting over with a wet abrasive blast using a liquid-soluble salt remover that has the ability to break the bond on electrochemically bonded salts and put it back into suspension so the salts can become soluble and be removed with the wet abrasive blasting process. Alternatively, try hydroblasting with the same salt remover added to the process.

Finally, if sandblasting is the preferred method, try pressure washing first with the liquid soluble salt added at a ratio of 1:50 or 1:100 (50 to 100 parts tap water) to remove the surface chlorides before impingement can occur from blasting them into the steel. Follow this with sandblasting (or mechanical methods of removal), then a final repeat pressure that includes the salt remover. The successful removal of the chlorides will minimize any rust-back from occur-ring, although I would expect some reblooming.

With a surface-tolerant primer, I would rather use a prime salt-free, rebloomed steel (tightly adhered) vs. freshly blasted white metal that is high in salts. Priming the white metal that is high in salts before it has a chance to rebloom is only asking for repeat trouble. In this case, you have only masked the salts. They are still there and you have already seen the results.

As for the coating system I have used successfully, consider a surface-tolerant, zinc-rich, moisture-cure urethane at 3 mils dry film thickness (DFT) covered with a coal tar moisture-cure urethane, at two coats of 6 to 8 mils DFT each. I know it sounds strange to use a zinc-rich primer in areas that could be deemed acidic, but it works. If you know for a fact that the pH is lower than 3, however, I wouldn’t suggest using the zinc primer.

A: I should add a few points of general background. Many

people think chlorine does not contribute to chloride formation under such circum-stances, but it may if high-breakpoint chlorination levels are necessary to overcome any organics present.

Further, some “common” salts are hygroscopic, while others are not. Pure sodium sulfate (Na

2SO

4) and sodium

chloride (NaCl) are not particularly hygro-

scopic. Potassium chloride (KCl) is reasonably hydroscopic. Calcium chloride (CaCl

2), on the other hand, is extremely

hygroscopic and deliquescent. Generally, mixtures of salts are more hygroscopic than their components taken in isolation. Mixtures of salts are probably the most common outcome in the field.

With chlorides present, pitting and crevice corrosion are driven by low pH in the pit or crevice. Under these conditions, it is reasonable to say that mild HCl is being formed.

Zinc load

Q: I have a contractor who was using an organic zinc-rich

coating. The engineer questioned whether the correct amount of zinc had been used with the product. We made samples and were able to look at the applied coating and see that it was the right color compared to the samples. We also looked at the empty cans and found no sludge at the bottom, which indicated neither zinc loss nor improper mixing. Essentially, the job looked good and subsequent coats are being applied.

Other than a visual comparison to standard panels, does anyone know if there is some chemical that would change color when applied to the coated surface (like a titrator strip) depending upon the concentration of zinc? It seems this might offer a better quantitative measurement. I am looking for a quick and easy test in the field.

A: Why not centrifuge a well-mixed sample? Te metallic zinc will be

at the bottom and lighter resin will be easy to pour of. Simply weighing before and after you pour the resin of could give you a good indication.

A: One would have to be very careful with respect to visual compari-

son and/or a surface colorimetric test. Te particle size distribution and morphology of zinc powder varies signif-cantly between manufacturers.

A: I would perform sample tests by energy dispersive spectroscopy

(EDS) to be sure that the red color is caused by iron and by x-ray difraction (XRD) to check the iron oxides present. I once had the good luck to observe spots of grease with rust color upon a coated surface.



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A: Nothing like that exists for metal-lic zinc content. Weight-per-

gallon is a fair indicator.

A: It sounds like there is no conve-nient feld test for you to use. I

would ask why the engineer was question-ing the application. Perhaps he or she saw something out of the ordinary during painting, or perhaps he or she isn’t famil-iar with the process and is asking out of curiosity. Either way, explaining the process and equipment might answer the question.

Cadmium in paint?

Q: We have been refurbishing some old equipment (i.e., removing

coatings by sandblasting) and we are noticing some significant levels of cadmium in our sandblast media. Could the cadmium have originated from the old paint that is on the equipment?

A: Cadmium can sometimes be found in steel structures. I think

it was used on bolts and nuts as well as a corrosion control device. I, too, have found cadmium in blast residue that was generated from barges.

A: Cadmium is used sparingly as a pigment and drier (cadmium

naphthenate) in coatings. It is relatively expensive and generally used only in specialty items such as artist paints (cadmium yellow). It is more often used in alloys that are electrodeposited or hot-dip applied.

A: It could be from the paint (some yellows are cadmium based) or, if

it’s a galvanized surface, it could come from the zinc. Some zinc grades contain up to 0.1% cadmium.

A: Many cabinets for inside use have cadmium-plated hardware for

their connections. Additionally, cadmium was routinely used to protect electrical parts in electrical and electronic equip-ment. These are possible sources, but I don’t know what type of cabinets you are cleaning.

A: We encountered a tank project that contained a verbally

reported cadmium level of 22,000 ppm in the paint! After some investigation, I was informed by a coating specialist that there is a family of cadmium pigments that is referred to as mercadmium, which contains elevated levels of mercury and cadmium.


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C

Multiphase fow characteristics can be

altered with a change of pipeline to-

pography in deep offshore oil and

gas production. Increasing corrosion

rate and decreasing inhibitor perfor-

mance in the risers can occur from

changes of multiphase fow charac-

teristics. To simulate offshore fow

lines and risers, experiments were

carried out in a 44-m long industrial

scale multiphase fow loop equipped

with three different pipeline inclina-

tions. The effectiveness of three com-

mercial corrosion inhibitors was ana-

lyzed. The effect of inclination on the

fow characteristics and their subse-

quent effect on corrosion rates are

described. In most testing conditions,

high inhibitor concentration was re-

quired to achieve the target corrosion

rate.

Corrosion of carbon steel (CS) pipelines

is of great concern because of the risk of

accidents, lost product, and down time.

These pipelines often face very corrosive

conditions due to seawater, carbon dioxide

(CO2), high pressure, high temperature,

high liquid and gas velocities, and other

factors. Risers have different inclinations,

which change the f low patterns and

pressure drops and affect corrosion rates.

Corrosion mitigation includes internal

coatings, chemical inhibitors, and corro-

sion-resistant alloys. Chemical inhibitors

are often the main method to reduce corro-

sion rates.

The effect of multiphase flow at the

inclinations typical of flow lines (0 degrees),

touch down point (3 degrees), and risers

(45 degrees) were evaluated in a large-scale

4-in (102-mm) diameter loop. The relevant

testing parameters included CO2 partial

pressure, temperature, superficial liquid

velocity, superficial gas velocity, f low

regime, water cut, water chemistry, and oil

viscosity to determine the optimal chemi-

cal product (corrosion inhibitor) and inhib-

itor concentration.

In 2001, T.-W. Cheng, et al.1 confirmed

that the gas slug velocity in an inclined tube

is higher than that in a horizontal tube. In

1997, W.P. Jepson, et al.2 noted that field

data suggested the slug frequency for hori-

zontal pipelines is usually in the range of 1

to 20 slugs/min, depending on the liquid

velocity. If the pipe is inclined, however, the

slug frequency can increase to values much

greater than these, which may lead to

higher levels of corrosion.

C. De Waard, et al.3 proposed that no

corrosion occurs if the water cut is less

than 30%. Corrosion rates depend not only

on water cut, but also on superficial gas

and liquid velocity and inclination angles.

In 2002, C. Kang, et al.4 studied corrosion

for high-pressure, large-diameter pipelines

under horizontal and 2-degree oil/water/

gas multiphase flow conditions. The water

cuts studied were 10, 20, and 30% ASTM

salt water. The superficial gas velocities

Corrosion Inhibitors in Deep Offshore Catenary Risers

Cheolho Kang, DYCE USA, Plain City, OhioJesse P. Rhodes and Kavitha tummala,

Det Norske Veritas U.S.A., Inc., Dublin, OhioalvaRo augusto oliveiRa magalhaes,

Petrobras, Rio de Janeiro, Brazil

64 JANUARY 2014 MATERIALS PERFORMANCE NACE INTERNATIONAL: VOL. 53, NO. 164 JANUARY 2014 MATERIALS PERFORMANCE NACE INTERNATIONAL: VOL. 53, NO. 1

CHEMICAL TREATMENT


ranged from 1 to 9 m/s under pressures of

0.27, 0.45, and 0.79 MPa. The predominant

flow was found to be slug flow, and all cor-

rosion experiments were carried out in this

regime. The results showed that measur-

able corrosion still occurs even at these low

water cuts. The corrosion rate increases

with an increase in slug frequency at the

same Froude number.

In 2008, C. Kang, et al.5 studied the

effect of 20% water cut on the corrosion

rates in inhibited simulated seawater/2.5

cP oil mixes and found that as much as 125

ppm of inhibitor was needed to mitigate

corrosion to acceptable levels (<4 mpy or

0.10 mm/y). Therefore, the question arose:

What would be the effect of a more viscous

oil (25 cP) and how would it affect the con-

centrations of inhibitor that would be

needed to mitigate corrosion to acceptable

levels?

Experimental Facility and Procedure

The experiments were carried out in a

high-pressure system. The flow loop is a

44-m long, 102-mm diameter, high-temper-

ature system (Figure 1). The entire loop is

made from AISI 316L stainless steel (SS)

(UNS S31603). A specified amount of oil

and salt water mixture was stored within a

1.9 m3 SS storage tank. This tank is

equipped with a 40-KW immersion heater.

A specially designed cooling jacket was

installed at two locations on the loop to

maintain system temperature. The temper-

ature settings are controlled through a con-

trol panel.

CO2 gas was introduced into the system

at an inlet pressure of 2.1 MPa (300 psi)

from the 6-ton capacity storage tank. The

flow rate of the CO2 gas was measured

using a variable f low meter, located

between two ball valves, that has an operat-

ing range from 3 to 30 standard m3/min.

Once the system has reached the desired

pressure, a 93-KW (125-hp) low-shear pro-

gressive cavity multiphase pump was used

to recirculate the gas phase throughout the

system. At the start of the experiments, the

system was pressurized using the CO2 gas

to the necessary level. The lubrication

FIGURE 1 Experimental layout of the inclined high-pressure multiphase fow loop.

TABLE 1. SUMMARY OF TEST CONDITIONS

Parameters Test Conditions

Superfcial liquid velocity (Vsl) 1.5 m/s

Superfcial gas velocity (Vsg) 0.7, 3, and 6 m/s

Pressure (P) 600 kPa

Temperature (T) 50 °C

Oil tested 25 cP at 50 °C

Water cut (WC) 20%

Inclination 0, 3, and 45 degrees

Brine concentration 150,000 ppm of chloride 55 ppm of bicarbonate

Corrosion inhibitor G, Y (oil soluble), and K (water soluble)

pump and the liquid low-shear progressing

cavity pump were turned on and set at a

required flow rate. The gas pump was then

turned on and the gas flow rate was fixed.

The high-pressure system had been

mo dif i ed to ac c ommo d at e 3- and

45-degree inclined segments to study the

various f low patterns and the effect of

inclination on corrosion. Each of these

three segments contained a 2-m long test

section with eight ports for taking mea-

surements of the flow characteristics and

corrosion and a 1.2-m long transparent

pipe for flow visualization. Table 1 summa-

rizes the test conditions.

Results and Discussion

Metal Loss Rates and Inhibitor Performance

High-sensitivity electrical resistance

(ER) probes located at the bottom of line

(BOL) were used to measure the corrosion

rate. Also, AISI 1018 (UNS G10180) CS

weight-loss coupons were utilized to gain

additional data at the BOL sections. The

baseline corrosion data were recorded until

steady state conditions were reached.

Bottom of Line Corrosion Rates

• Baseline corrosion rates at superfi-

65NACE INTERNATIONAL: VOL. 53, NO. 1 MATERIALS PERFORMANCE JANUARY 2014 65NACE INTERNATIONAL: VOL. 53, NO. 1 MATERIALS PERFORMANCE JANUARY 2014


cial liquid velocity (Vsl) = 1.5 m/s;

superficial gas velocity (Vsg) = 0.7

m/s for 0- and 3-degree inclinations

• Baseline corrosion rates at Vsl = 1.5

m/s; Vsg = 3 m/s for 3- and 45-degree

inclinations



inclinations

• Prescreening with Inhibitor G at

varying superficial gas velocities

(0.7, 3, and 6 m/s); inclinations (0, 3,

FIGURE 2 Baseline corrosion rates, 20% WC, 25cP BOL, Vsl = 1.5 m/s, Vsg = 0.7 m/s, P = 600 kPa,

T = 50 °C.


T = 50 °C.

and 45 degrees); and inhibitor

concentrations

• Prescreening with Inhibitor Y at


(0.7, 3, and 6 m/s); inclinations (0, 3,

and 45 degrees); and inhibitor

concentrations

• Prescreening with Inhibitor K at


(0.7, 3, and 6 m/s); inclinations (0,

3, and 45 degrees); and inhibitor

concentrations

Top of Line Corrosion Rates• Baseline corrosion rates at Vsl = 1.5

m/s; Vsg = 0.7 m/s for 0- and 3-degree

inclinations



inclinations



inclinations

Baseline Corrosion Results

Figure 2 shows the effect of inclination

on corrosion rates at superficial liquid and

gas velocities of 1.5 and 0.7 m/s using two

different measurement techniques (weight-

loss coupons and ER probes) at the 0- and

3-degree inclinations. Figure 3 shows the

corrosion rates at superficial liquid and gas

velocities of 1.5 and 3.0 m/s. Corrosion

rates obtained using weight-loss coupons

were slightly higher than those measured

by ER probes.

The effect of an increase in the superfi-

cial gas velocity is evident when comparing

Figures 2 and 3. The corrosion rate for the

3-degree inclination at 3 m/s was almost 1.5

times higher than that obtained at 0.7 m/s.

This is attributed to the change in the flow

pattern that occurs from an increase in

superficial gas velocity. The corrosion rates

for weight-loss coupons are higher than

those for the ER probes, but follow the

same trend as the ER probe. Also, the ratio

between ER corrosion rates and weight-loss

corrosion rates obtained at a 3-degree incli-

nation for 0.7 and 3 m/s superficial gas

velocity are similar, which indicates consis-

tency in the data.

Figure 4 shows baseline corrosion rates

at 3- and 45-degree inclinations for a super-

ficial gas velocity of 6 m/s and superficial

liquid velocity of 1.5 m/s. At a 45-degree

inclination, the ER corrosion rates are ~1.4

times higher and weight-loss corrosion

rates were ~1.2 times higher than the corro-

sion rates at the 3-degree inclination

because the slug intensity (Froude number)

increases with an increase in the inclina-

tion of the pipe.

Figure 5 presents the influence of super-

ficial gas velocities on corrosion rates for


CHEMICAL TREATMENT


top of line (TOL) and can be compared to

BOL corrosion rates from Figures 2 through

4. Lower corrosion rates were observed for

the TOL section when compared to the

BOL section because of the turbulence and

impact caused by the entrained gas bubbles

moving toward the bottom of the pipe.

Corrosion Inhibitor Pre-Screening Results

The candidate corrosion inhibitors,

Inhibitor G (oil-soluble), Inhibitor Y (oil-

soluble), and Inhibitor K (water-soluble),

were tested to determine their perfor-

mance at 20% water cut and 25 cP oil. The

corrosion inhibitor volume was calculated

based on total liquid volume in the system.

Measurements with ER probes were taken

every two minutes, and each test was per-

formed until the corrosion rate reached a

nominal steady state value.

Inhibitor G succeeded in mitigating

corrosion to a desired level (50 ppm). At a

superficial gas velocity of 0.7 m/s, the ini-

tial concentration (20 ppm) of Inhibitor G

for 0- and 3-degree inclinations was unable

to lower the corrosion rates to below the

target corrosion rate (0.1 mm/y). Inhibitor

concentration of 35 ppm achieved the tar-

get corrosion rate for all superficial gas

velocities at the 0- and 3-degree inclina-

tions. At 50 ppm concentration, desired

corrosion rates were obtained even at a

superficial gas velocity of 6 m/s and a

45-degree inclination.

Inhibitor Y was the most successful of

the three inhibitors tested in mitigating

corrosion and achieving the target corro-

sion rate for the 20% test conditions. At the

initial dosage of 20 ppm, significant reduc-

tions of corrosion rates was achieved in all

conditions, and the target corrosion rates

were achieved in all conditions except for a

superficial gas velocity of 6 m/s and a

45-degree inclination. When an additional

15 ppm of inhibitor (total: 35 ppm) was

added, corrosion rates decreased to the tar-

get rate.

Inhibitor K did not perform well com-

pared to Inhibitors G and Y for mitigating

corrosion in the 20% water cut test condi-

tions. At high gas velocities (slug flow con-


T = 50 °C.

FIGURE 5 Baseline corrosion rates, 20% WC, 25cP TOL, Vsl = 1.5 m/s, P = 600 kPa, T = 50 °C.

dition), the target corrosion rates were

obtained with 175 ppm of Inhibitor K.

Conclusions

• At all inclinations, slug flow was the

dominant flow regime observed at a

superficial gas velocity of 0.7 m/s and

superficial liquid velocity of 1.5 m/s.

• At higher gas flow rates (3 and 6 m/s)

and a superficial liquid velocity of 1.5

m/s, slug flow existed at all pipe incli-

nations.

• The baseline corrosion rates at the

BOL were higher than that at the TOL.

• The weight-loss coupon results

generally were higher than the ER

corrosion rates in all conditions.

• The corrosion rate generally in-

creased with the increase in the pipe-

line inclination.


Corrosion Inhibitors in Deep Offshore Catenary Risers


• For all test conditions, the corrosion

rate decreased significantly within

the first 30 to 40 min after the initial

addition of an inhibitor.

• For the pre-screening tests at 20%

water cut, Inhibitor Y exhibited the

best performance. The target corro-

sion rate (<4 mpy or 0.1 mm/y) was

achieved with the total dosage of 35

ppm, and in all but one case (Vsl = 1.5

m/s and Vsg = 6 m/s, 45-degree incli-

nation) was achieved at 20 ppm of

inhibitor. For Inhibitor G, the target

corrosion rate in 20% water cut was

achieved in all conditions with 50

ppm.

• Inhibitor K exhibited the worst

performance and is not suitable for

corrosion inhibition in these condi-

tions. The target corrosion rate was

not achieved until a total dosage of

175 ppm was added.

AcknowledgmentsThe authors would like to thank

Petrobras for sponsoring this work and

allowing its publication. The authors would

like to acknowledge Mark Landers in help-

ing complete this work.

References1 T.-W. Cheng, T.-L. Lin, “Characteristics of

Gas-Liquid Two Phase Flow in Small Diame-

ter Inclined Tubes,” Chemical Eng. Sci. 56

(2001): pp. 6,393-6,398.

2 W.P. Jepson, S. Stitzel, C. Kang, M. Gopal,

“Model for Sweet Corrosion in Horizontal

Multiphase Slug Flow,” CORROSION/97,

paper no. 97011 (Houston, TX: NACE Inter-

national, 1997).

3 C. de Waard, “Prediction of CO2 Corrosion of

Carbon Steel,” CORROSION/93, paper no.

93039 (Houston, TX: NACE, 1993).

4 C. Kang, W.P. Jepson, H. Wang, “Flow Regime

Transitions in Large Diameter Inclined

Multi phase Pipelines,” CORROSION 2002,

paper no. 02243 (Houston, TX: NACE, 2002).

5 C. Kang, P.P. More, J. Vera, P.A. Ferreir,

E.C. Bastos, M. Arauj, “Effect of Flow on Cor-

rosion and its Inhibition in Riser Pipeline,”

CORROSION 2008, paper no. 08562 (Hous-

ton, TX: NACE, 2008).

This article is based on CORROSION 2013

paper no. 2595, presented in Orlando, Florida.

CHEOLHO KANG is the senior vice presi-dent of DYCE USA, 8059 Corporate Blvd., Ste. A, Plain City, OH 43064, e-mail: [email protected]. He has worked in the oil and gas industry in the areas of multiflow, corro-sion, erosion, inhibitors, drag-reducing agents, and pipeline integrity management for more than 22 years. He has been a member of NACE International for 18 years.

JESSE P. RHODES is a staff engineer at DNV GL, 5777 Franz Rd., Dublin, OH 43017, e-mail: [email protected]. He is experi-enced in the design and operation of corro-sion research related to flow environments, sweet and sour high-pressure and high-temperature conditions, inhibitors, coat-ings, electrochemistry, material selection, and mechanical testing. He has been a co-author of several NACE conference papers and received a certification of appreciation for Outstanding Contributions as a Reviewer of the CORROSION 2013 sympo-sium, Pipe Coatings, Corrosion Control, and Cathodic Protection Shielding. He is a six-year member of NACE.

KAVITHA TUMMALA is an engineer at DNV GL, e-mail: [email protected]. She is experienced in projects related to corro-sion and corrosion inhibitor performance, coating evaluation using flow loops, rotat-ing cylinder electrodes, and various types of bench top setups and corrosion monitor-ing techniques. She has been a co-author of several NACE conference papers and is a five-year member of NACE.

ALVARO AUGUSTO OLIVEIRA MAGALHAES is a technical consultant in corrosion engineering at Petrobras, Avenida Horacio Macedo, 950-Ilha do Fundao, Rio de Janeiro, Brazil, e-mail: [email protected]. He has been with the company since 2001, working on research projects and providing technical assistance related to corrosion monitoring and CO

2/

H2S corrosion process control using chemi-

cals. He has Ph.D. degrees in metallurgical and materials engineering from the Federal University of Rio de Janeiro and electro-chemistry from the Université Pierre et Marie Curie in Paris, France. He has published more than 30 papers in corrosion and electrochemistry journals and for national and international conferences. He taught two courses at ABRACO, the Brazilian Association of Corrosion, from 2003 to 2006: Corrosion Monitoring and Corrosive Process Control and Qualification of Professionals for Corrosion Monitoring. He has taught courses on corrosion for pipeline engineers at Petrobras University since 2006.


CHEMICAL TREATMENT








http://www.gmcelectrical.net

D

In high-pressure, high-temperature

(HPHT) wells, mere ppm-level hydro-

gen sulfde (H2S) can cause H

2S partial

pressures (PH2S

) over the limits for many

high-strength steels and corrosion-

resistant alloys (CRAs) currently al-

lowed by NACE MR0175/ISO 15156.

Such situations create design and eco-

nomic challenges by limiting the use of

these cost-effective materials required

for HPHT completions. This article cov-

ers new methodologies that may ex-

pand the range of HPHT well condi-

tions where high-strength materials

and CRAs can be used.

During the past 50 years, the oil and gas

industry has witnessed a significant transi-

tion to more severe downhole operating

conditions and environments that involve

higher pressures and temperatures along

with increased well depths. These high-

pressure, high-temperature wells are

commonly referred to by the abbreviation

HPHT. As shown in Figure 1, there are now

various regimes of HPHT well formations

that can exhibit extreme conditions that

approach and even exceed pressures of

20,000 psi (138 MPa) and temperatures of

400 °F (204 °C).

In HPHT wells, a mere ppm level of

hydrogen sulfide (H2S) can cause H

2S partial

pressures (PH2S

) over 0.05 psia (0.3 kPa), a

sour (H2S-containing) condition. This is

where NACE MR0175/ISO 151561 imposes

significant metallurgical and use restric-

tions on high-strength steels (>80 ksi [551

MPa] specified minimum yield strength

[SMYS]) to prevent sulfide stress cracking

(SSC), a form of environmental cracking

caused by hydrogen produced by the sulfide

corrosion reaction.2 These restrictions

require the use of special C-Cr-Mo steels and

mandatory quenching and tempering for

near 100% martensitic transformation. They

also mandate yield strength and hardness

limits as a means to qualify SSC resistance. If

still higher strength steels (non-sour service

steels with 80 to 125 ksi [862 MPa] SMYS) are

required, they can be utilized only if required

minimum use temperatures are met.

Even at low to moderate H2S concentra-

tions, HPHT conditions often yield PH2S

that

exceed the 1.5 to 3 psia (10 to 20 kPa) limits

defined by NACE MR0175/ISO 15156 Part 3

for many stainless steels (SS) and enter into

the range where nickel-based alloys

become mandatory. Such situations create

HPHT well design and economic chal-

lenges by greatly limiting the use of cost-

effective high-strength carbon/low-alloy

steels and corrosion-resistant alloys

(CRAs).

New Approach to H2S Limits for High-Pressure, High-Temperature Petroleum Production Wells

Russell D. Kane, Honeywell Consultant, Houston, Texas Tanmay ananD, aviDipTo Biswas,

peTeR F. ellis, anD sRiDhaR sRinivasan,

Honeywell Process Solutions, Houston, Texas




Development of Current Industry Requirements

NACE MR0175/ISO 15156 is the pri-

mary industry standard for materials selec-

tion in sour upstream oil and gas opera-

tions. This best-practice document has its

roots in empirical knowledge gained from

over 50 years of field experience with high-

strength steels that started in the 1940s to

the 1960s in Texas and Canada, and later

gained a scientific basis through laboratory

testing and research.

During much of the early history of this

standard, the focus was primarily on SSC

and its prevention through the selection of

H2S-resistant materials derived primarily

on the basis of hardness and metallurgical

requirements. The H2S limit that defined

sour service conditions was initially

defined in terms of concentration (i.e., 50

ppm H2S in the gas phase). Subsequently,

with the advent of the original version of

NACE MR0175 in 1975, the sour service

threshold limit was changed to PH2S

of 0.05

psia (0.3 kPa). This change acknowledged

the contribution of total system pressure

in determining sour service limits through

the concept of defining H2S partial pres-

sure as the product of total system pres-

sure and the mole fraction of H2S in the

vapor phase.

The advent of new higher alloy and

higher strength CRA materials in petro-

leum production applications led to the

recognition that other forms of environ-

mental cracking, such as anodic stress cor-

rosion cracking (SCC) and galvanic hydro-

gen stress cracking (GHSC), required

consideration in NACE MR0175 in addition

to SSC. This led to the inclusion of new ser-

vice limits to handle the new forms of

cracking and new CRA materials. As new

CRAs were brought into petroleum opera-

tions, most of these limits for environmen-

tal cracking in NACE MR0175 were identi-

fied through laboratory testing. In 2003,

through a collaborative effort between

NACE and ISO, MR0175 progressed further

into its present form as a joint NACE/ISO

document.

Consequences of Deviation from Ideal Gas BehaviorGuidelines for selection of many mate-

rials for sour service as found in NACE

MR0175/ISO 15156 are based on PH2S

and

chloride concentration in the brine, along

with in situ pH determined by the dissolved

H2S and CO

2 in the brine that per Henry’s

Law are directly proportional to PH2S

and

PCO2

. An inherent assumption of Henry’s

Law is that the aqueous phase solubilities

of H2S and carbon dioxide (CO

2) exhibit

ideal gas behavior and are directly related

to the partial pressures of acid gases in the

vapor phase in contact with the liquid

phase.

The potential shortcoming of the prac-

tice of defining materials’ suitability for

sour service in terms of PH2S

and PCO2

stems

from the notion that PH2S

and PCO2

are prox-

ies for dissolved H2S and CO

2 in the aque-

ous phase. Further, Henry’s law operates on

the assumption that any interactions

between the gas molecules and the ions in

the brine have no effect on gas solubility, as

shown in Equation (1):

mH2S

= PH2S

/KH2S

(1)

where the dissolved concentration (m)

equals the partial pressure (P) divided by

the strict (ideal) Henry’s Law constant for

the gas.

The pitfall in the logic utilized herein,

especially in the context of HPHT environ-

ments, is that the behaviors of H2S and CO

2

at high pressures do not generally obey the

ideal gas law and hence the corresponding

partial pressure-based solubility assump-

tions may be inaccurate. For example, large

differences exist in dissolved H2S and CO

2

concentrations in the aqueous phase when

total pressure is low (as is often used in

laboratory fitness-for-purpose [FFP] test-

ing used for SSC/SCC evaluation) vs. when

the pressure is high (as in HPHT well envi-

ronments).

Nelson and Reddy3 compared the dis-

solved H2S concentrations for a well envi-

ronment at 10,000 psi (68.9 MPa) total pres-

sure and 10% H2S (P

H2S = 100 psia [689 kPa])

with a laboratory FFP test at 100 psi (689

kPa) H2S (with no additional nitrogen or

methane added). At the same value of PH2S

,

they found that the dissolved H2S in the

aqueous phase in the low-pressure FFP test

was more than 10 times the aqueous phase

H2S concentration under the actual well

conditions.

FIGURE 1 Regimes of HPHT well conditions in the petroleum industry.




Further, in a recent effort to predict the

in situ pH under HPHT conditions more

accurately, Plennevaux, et al. outlined the

importance of considering the Poynting cor-

rection when assessing high-pressure sys-

tems containing H2S and CO

2.6 It was shown

that predictions on thermodynamic vari-

ables made by equilibrium thermodynamic

models based on the ensemble Henry’s Law

equation were in better agreement with

experimental data as compared with predic-

tions based on simple Henry’s Law or even

fugacity/activity corrected models.

Thermodynamic Modeling Study: H

2S

Limits for Martensitic Stainless UNS S41426

Over 100 materials, along with their

respective sour service limits, are cited in

NACE MR0175/ISO 15156. One example is

the case for a martensitic SS, UNS S41426

(13Cr-5Ni-2Mo), as listed in Table A.19 of

the standard. This material was approved

for use up to PH2S

of 1.5 psia where in situ pH

is >3.5. This case was included in the

NACE/ISO standard based on passing SSC

test results for the following conditions:

Solution—5 wt% sodium chloride (NaCl)

with an addition of acetic acid (CH3COOH)

FIGURE 2 SSC results plotted vs. H2S fugacity with 95% confdence limits for low- and

high-pressure tests.4 1 psi = 6.9 kPa; 1,000 psia = 6.9 MPa.

It appears likely that the FFP test in the

above scenario could be unrealistically

harsh vs. the actual well condition because

of its higher level of dissolved H2S. This is a

situation now referred to as “over-evalua-

tion,” which could potentially disqualify

many candidate high-strength materials

that presumably could provide reliable ser-

vice under the actual well condition. This

scenario leads to a factor of conservatism

left in existing designs for HPHT wells. Since

high-strength materials are often required

for HPHT well completions, however, it puts

engineers in the position of being between “a

rock and a hard place.” It may be time for the

petroleum industry to reconsider FFP test-

ing parameters and sour service limits used

for selecting sour service materials.

A Conceptual Step Forward: Ensemble Henry’s Law

The corrosion and surface chemistry

effects responsible for environmental

cracking under sour service conditions are

generally considered to occur in the aque-

ous phase. From a thermodynamic and sys-

tem kinetics standpoint, these reactions

are a function of the solution activities of

relevant species, including H2S and CO

2 or

their gas phase counterparts (i.e., fugacity

and not the partial pressure).

Applying Equation (1) to oil and gas well

environments requires significant correc-

tions for the non-ideal behavior of the gases,

interactions between the gas molecules

under pressure, the non-ideal solute-solute

ion interactions in the solvent, and the

effect of overall system pressure. The equa-

tion resulting from the application of these

correction factors to the simple Henry’s

Law equation are referred to as the “ensem-

ble Henry’s Law equation.”3 For H2S, this

equation may be expressed as Equation (2):

aH2S

= γH2S

mH2S

= φH2S

PH2S

/KH2S

exp[ξ] (2)

where: aH2S

= the activity of H2S in the solu-

tion; γH2S

= molal activity coefficient of H2S;

mH2S

= molal concentration (in units of

mole solute/kg H2O) of H

2S in solution; K

H2S

= ideal gas law Henry’s constant for H2S;

φH2S

= fugacity coefficient of H2S; P

H2S = par-

tial pressure of H2S; and exp[ξ] = Poynting

correction for total pressure. The ensemble

Henry’s Law equation is written for H2S, but

similar equations exist for CO2. The correc-

tions to Henry’s Law are generally close to

unity at low to moderate pressures but

become quite significant at HPHT well

pressures.

Recently, Grimes, Miglin, French, and

Coleman4 described data/results from a

study of the physical chemistry of H2S and

its impact on the SSC crack arrest proper-

ties of a low-alloy steel using NACE

TM01775 (Method D) fracture tests. This

study examined the influence of PH2S

, H2S

gas fugacity, H2S solubility, and H

2S aque-

ous activity (that is related to gas fugacity).

Their findings showed that: (a) KISSC

(crack

arrest fracture toughness for SSC) at con-

stant PH2S

varied for high and low total pres-

sure conditions, indicating that the use of

H2S partial pressure alone did not fully

characterize the SSC behavior; (b) the vari-

ations in KISSC

between the low- and high-

pressure environments were not totally

accounted for by variations in the soluble

H2S concentration; and (c) SSC susceptibil-

ity varied according to H2S fugacity, and it

sufficiently describes the SSC behavior of

the steel (Figure 2).


New Approach to H2S Limits for High-Pressure, High-Temperature Petroleum

Production Wells


to pH 3.5; gas—10% H2S—90% N

2 mixture

yielding PH2S

of 1.5 psia; temperature—75 °F

(24 °C); test pressure—14.7 psia (100 kPa).

The traditional approach utilized to

apply such sour service limits for UNS

S41426 (determined with low-pressure FFP

tests) would be to simply match these limit-

ing conditions to prospective use condi-

tions in actual high-pressure well environ-

ments using the simple concept of PH2S

limits. Based on the concepts of ensemble

Henry’s Law and H2S fugacity, however, it

may be possible to translate the H2S limits

in NACE MR0175/ISO 15156 for UNS

S41426 determined at low pressure to a

range of HPHT service conditions where

the H2S fugacity is used in the FFP test as

the scalable parameter for determining

condition severity.

Figure 3 shows the results of thermody-

namic modeling that produced conditions

of constant PH2S

of 1.5 psia. H2S fugacity

decreased with increasing total pressure, a

trend that suggests that the severity of SSC

in this material at PH2S

of 1.5 psia may

decrease as the total pressure increases.

Figure 4 examines an alternative and

perhaps more meaning ful case where,

through ionic modeling, the H2S fugacity is

held constant for conditions of increasing

total pressure. This case suggests that if H2S

fugacity is the scalable parameter control-

ling SSC for UNS S42416, then, as the total

pressure increases, the PH2S

limit (derived

from the low-pressure laboratory FFP test)

may actually increase above PH2S

of 1.5 psia

as HPHT well conditions are attained. It

must be noted that the possible effects of

chloride activity on localized corrosion and

environmental cracking of CRAs have not

yet been examined, however.

Need for Further ResearchThe analytical, experimental, and com-

putational methods described in this article

appear to offer the potential for significant

changes and evolution in the application of

NACE MR0175/ISO 15156, with the possibil-

ity for extending the use of higher strength

alloys to higher PH2S

for HPHT applications.

It must be acknowledged that the experi-

mental data and verification for application

of these alternative methods are still limited

for both steels and CRAs.

The authors are actively involved in

joint industry research aimed at enhancing

the applicability and verification of the

methodologies detailed herein. Such

efforts include evaluation of applicability of

fugacity, solubility, and aqueous compo-

nent activity to: (a) SSC initiation vs. crack

propagation and arrest, (b) higher strength

steels (and their SSC minimum tempera-

ture limits), and (c) CRAs that demonstrate

active/passive behavior, pitting, and sus-

ceptibility to other environmental cracking

mechanisms such as anodic SCC.

References

1 NACE MR0175/ISO 15156, “Petroleum and

natural gas industries—Materials for use in

H2S-containing environments in oil and gas

production” (Houston, TX: NACE Interna-

tional, 2009).

2 R.D. Kane, M.S. Cayard, “Roles of H2S in the

Behavior of Engineering Alloys: A Review of

Literature and Experience,” CORROSION/98,

paper no. 274 (Houston, TX: NACE, 1998).

FIGURE 3 Decreasing H2S fugacity vs. total pressure for fxed P

H2S service limits for UNS S41426

(1.5 psia). 1 psi = 6.9 kPa; 1,000 psia = 6.9 MPa.

FIGURE 4 Increasing PH2S

service limits for UNS S41426 with increasing total pressure for fxed H2S

fugacity (1.5 psia). 1 psi = 6.9 kPa; 1,000 psia = 6.9 MPa.




3 J.C. Nelson, R.V. Reddy, “Selecting Represen-

tative Laboratory Test Conditions for Fit-

For-Purpose OCTG Materials Evaluations,”

SPE High Pressure/High Temperature Sour

Well Design Applied Technology Workshop

2005, MS-97576 (Richardson, TX: SPE, 2005).

4 W.D. Grimes, B.P. Miglin, R .N. French,

A.T. Coleman, “Physical Chemistry Tests of

Hydrogen Sulfide Gas and Sulfide Stress

Cracking Results at Elevated Pressure,”

Eurocorr/2013, paper no. 1587 (London,

U.K.: EFC, 2013).

5 NACE Standard TM0177-2005, “Laboratory

Testing of Metals for Resistance to Sulfide

Stress Cracking and Stress Corrosion Crack-

ing in H2S Environments” (Houston, TX:

NACE, 2005)

6 C. Plennevaux, T. Cassagne, M. Bonis, et al.,

“Improving pH Prediction for HPHT Applica-

tions in Oil and Gas Production,” CORRO-

SION 2013, paper no. 2843 (Houston, TX:

NACE, 2013).

RUSSELL D. KANE is a Honeywell consul-tant, iCorrosion LLC, PO Box 27868, Houston, TX 77227, e-mail: [email protected]. He is a corrosion and materials consultant and expert in environmental cracking, applying his expertise to indus-trial research, laboratory evaluation, corro-sion modeling and prediction, and failure analysis. He has a Ph.D. in metallurgy and materials science from Case Western Reserve University. A 38-year member of NACE International, Kane received the A.B. Campbell Young Authors Award, was the CORROSION/96 plenary lecturer, and received a NACE Technical Achievement Award and ASTM Sam Tour Award.

TANMAY ANAND works as a corrosion research engineer at Honeywell Inter-national. His current work focuses on experimental evaluation of the perfor-mance of a variety of materials (metals and nonmetals) for oil and gas and refining applications. He has a B.S. degree in met-allurgical engineering from NIT, India, and an M.S. degree in materials engineering from Colorado School of Mines. He is an active member of NACE and has authored several conference publications related to oilfield corrosion and metallurgy.

AVIDIPTO BISWAS is a research scientist at Honeywell Corrosion Solutions, 11201 Greens Crossing Blvd., Ste. 700, Houston, TX 77067, e-mail: [email protected]. He studies the mechanical behavior of metallic systems in corrosive environments relevant to the oil and gas industries. His areas of expertise include materials characterization—surface and bulk, surface engineering of metallic

materials, and physical and mechanical metallurgy. He has a Ph.D. in materials science and engineering from Case Western Reserve University (2013). He is a member of NACE.

PETER F. ELLIS II is the engineering team leader, corrosion, at Honeywell Corrosion Solutions, e-mail: [email protected]. With more than 30 years of experi-ence in machinery corrosion failure analy-ses, he has been responsible for more than 400 failure analyses. He has seven years of experience designing and operating materials testing programs under sour HTHP conditions. He is a 34-year member of NACE.

SRIDHAR SRINIVASAN is the global business leader, corrosion/asset integrity solutions at Honeywell International, Inc. In his current role he manages all aspects of the company’s corrosion business, including real-time modeling and monitor-ing systems/services, as well as consulting and laboratory services. He is also the program leader for Honeywell’s corrosion joint industry projects. He has more than

23 years of experience developing solutions for corrosion and asset integrity across multiple industry verticals. He has a B.S. degree in mechanical engineering from Bangalore University and an M.S. degree in mechanical engineering from the University of Houston. A 19-year member of NACE, Srinivasan is chair of the NACE task group on smart monitoring sensors. He is widely published, with more than 80 journal and conference publica-tions to his credit, as well as book chapters and articles related to corrosion, model-ing, asset integrity solutions, and risk-based asset management methodologies.

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New Approach to H2S Limits for High-Pressure, High-Temperature Petroleum

Production Wells


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Y

The Union Oil tanker S.S. Montebello

was torpedoed and sunk six miles

(9.7 km) off the coast of Cambria, Cali-

fornia by a Japanese submarine on

December 23, 1941, two weeks after

the attack on Pearl Harbor. With close

proximity to the National Monterey Bay

Marine Sanctuary, concern about pos-

sible crude oil contamination led to the

most recent expedition to the site in

October 2011. Assessment of the shell

plate found that the average corrosion

rate was very low and the structure will

remain stable for many decades.

“Yesterday, December 7, 1941, a date

that will live in infamy, the United States of

America was suddenly and deliberately

attacked by naval and air forces of the

Empire of Japan.” This statement rang out

in histor y as President Franklin D.

Roosevelt declared war against Japan on

December 8, 1941, the day after the Pearl

Harbor attack. The attack was one of many

planned for the same day at British and

American military installations throughout

the Pacific, including Guam, Wake Island,

Singapore, Brit i sh Malaya , Burma ,

Thailand, the Dutch East Indies, and the

Philippine Islands.1 On December 23, 1941,

two weeks after the Pearl Harbor attack,

Japanese submarine I-21 sighted and

followed the tanker S.S. Montebello. The

tanker had departed Port San Luis,

California on December 22 and was on its

way to Vancouver, British Columbia when it

was fired on by two torpedoes. One struck

and exploded midship, sinking the ship

within an hour. The tanker contained

73,500 bbl (11.7 million L) of crude oil, 2,470

bbl (392,730 L) of Bunker-C fuel oil, and an

unknown amount of lubricating oil.

For more than 72 years, the tanker has

rested upright on the bottom in ~900 ft (275

m) of water, ~6 miles (9.7 km) off the coast

of Cambria, California. Because of the ship’s

close proximity to the Monterey Bay

National Marine Sanctuary, a marine habi-

tat, discovery dives in 1996 and subsequent

reconnaissance dives in 1996 and 2003

employed still photography and video tap-

ing to document the integrity of the hull

and general site conditions for potential oil

contamination.2 In October 2011, an expe-

dition to the site was conducted to assess

corrosion directly from samples recovered

robotically and to determine if crude oil

remained on board. This article presents

the results of the metallurgical/corrosion

study and shows how the data are incorpo-

rated into a universal corrosion prediction

model. Unexpected difficulties in robotic

acquisition of metal and concretion sam-

ples from a comparatively deep sea envi-

ronment are also discussed.3

The Ship

Structural

The shelter deck tanker was built in

1921 by the Southwest Shipbuilding Co.

(San Pedro, California). Figure 1 shows a

Metallurgical and Corrosion Assessment of Submerged Tanker S.S. Montebello

Dana J. MeDlin, Engineering Systems, Inc., Omaha, NebraskaJaMes D. Carr, University of Nebraska-Lincoln, Lincoln, NebraskaDonalD l. Johnson, National Park Service Submerged Resources Center, Sun City West, ArizonaDaviD l. Conlin, National Park Service Submerged Resources Center, Lakewood, Colorado



rare photograph.4 Historic structural draw-

ings could not be found; however, the origi-

nal plate thickness (TL) [Equation (1)] the

basis for determining the corrosion rate, was

evaluated from the American Bureau of

Shipping Rules.5 To properly interpret the

rules for the shell steel plate used to con-

struct the Montebello, Naval Architect

Zachary Malinoski was consulted.6 For a

total ship length of 440 ft (134 m), and side

shell stiffeners on 30-in (762-mm) spacing,

plate thicknesses were variable depending

upon horizontal positions as follows:

• Sides, midships section of length 0.4L

(176 ft [53.6 m]): TL = 0.68 in (17 mm)

• Ends extend inwards 0.1L (44 ft [13.4

m]) from bow and stern: TL = 0.46 in

(12 mm)

• Taper fore and aft extends 0.2L (88 ft

[27 m]) from ends: TL = 0.46 in; to sides:

TL = 0.68 in

A shear strake plate runs longitudinally at

the shelter deck at the height of the summer

tanks. The thickness is 0.16 to 0.25 in (4.0 to

6.35 mm) greater than the shell plate thick-

ness. Whether the strake plate is an addi-

tional plate overlying the hull plate is

unknown, although local doubling plates “can

be fitted as necessary” according to the rules.

Coupon Analysis

Metal Coupon ChemistrySamples MB-1, 3, 5, and 8 are typical of

steel manufactured in 1921 when the

Montebello was under construction. Table 1

indicates that %C, %P, and %S are somewhat

higher for the Montebello than modern Grade

A36 steel (UNS K02600). More precise control

is the reason for the difference, although

such differences have no measureable effect

on corrosion of the Montebello hull.

Metallographic ExaminationThe samples were prepared by traditional

metallographic techniques as described in

ASTM E3-11.7 The microstructures are domi-

nant in ferrite (light, >99% iron) due to the

low carbon content and heat-treatment his-

tory (Figure 2). The darker areas are pearlite,

a layered mixture of ferrite and iron carbide

(Fe3C), which is an intermediate compound

FIGURE 1 The S.S. Montebello. Photo courtesy of the Vancouver Maritime Museum.

TABLE 1. CHEMISTRY OF MONTEBELLO STEEL

Sample No. %C %P %S %Mn %Si %Cr %Ni

MB-1 0.289 0.0147 0.0567 0.399 0.011 0.019 0.011

MB-3 0.216 0.0180 0.0820 0.329 0.012 0.011 0.024

MB-5 0.292 0.0460 0.1270 0.376 0.009 0.013 0.017

MB-8 0.235 0.0200 0.0650 0.368 0.013 0.013 0.009

Modern

Grade A36

0.200 0.0120 0.0370 0.550 — — —

of iron. Inclusions are in the form of manga-

nese (II) sulfide (MnS) stringers, a form of

sulfur common in carbon steels, particu-

larly those manufactured early in the twen-

tieth century. The average hardness of the

coupons varied from 64 to 76 Rockwell B

hardness. The hardness is slightly low com-

pared to modern low-carbon steels but is

not a significant issue with regard to corro-

sion performance.

Corrosion Rate ExpressionsEquation (1) is an expression for the

corrosion rate in terms of direct thickness

measurement:8

icorr

= ½ (TL – T

m)/t (1)

where TL is original shell plate thickness

(1,000 × in = mil, mil × 25.4 = µm), Tm

is mea-

sured post exposure thickness, t = 70 is sub-

mergence time (years), and icorr

is corrosion

rate in mils per year (mpy) or micrometers

per year (µm/y). Since corrosion occurs on

both sides, a factor of one half is applied.

Equation (2) is an expression for corro-

sion rate in terms of data extracted from

collected marine concretions, concretion

equivalent corrosion rate (CECR):8

icorr

= icecr

= 0.8ρd%Fe/t (2)

where: ρ is density (g/cm3), d is concretion

thickness (cm), %Fe is iron content in wt%,

and t is defined above.

Equation (3) is an expression for the

Weins number (Wn) given by:9

Wn = icorr

/iaocr

= k0 exp(–∆Ha/RT) (3)

where iaocr

(available oxygen corrosion

rate) is calculated from the expression



iaocr

= kC(O2)/(100 d), C(O

2) is per-

cent dissolved oxygen (DO), d is

concretion thickness (cm), k0 is

pre-exponential constant, –∆Ha is

activation energy (Kcal/mole/°K or

KJ/mole/°K), R is the gas constant,

and T is absolute temperature.

Corrosion Rate

Core metal thickness mea-

surements were conducted on

seven metal coupon samples at

E S I l a b o r a t o r i e s (O m a h a ,

Nebraska). From four to eight

measurements were taken around

the circumference of each sample

in the “as-received” condition.

Figure 3 shows the recovered

robotic hole saw shipside core

sample. Figure 4 shows the hole

saw cutting into the hull. Figure 5

shows the sample “as received.”

Table 2 gives original thickness,

average core thickness, and corre-

sponding corrosion rates for each

sample.3

From Table 2, column 4, corro-

sion rate per side, average icorr

=

0.4 mpy (10.16 um/y) or 0.8 mpy

( 2 0 . 3 2 u m / y) b o t h s i d e s .

Neglecting Sample MB-3 because

of uncertainty in original thick-

FIGURE 2 Microstructure consists of ferrite, F, pearlite, P, and inclusions (MnS). Etched with 2% nital.

FIGURE 3 Robert Schwemmer, NOAA/ONMS, recovers

the hole saw aboard support vessel OSRV Nanuq. Photo

courtesy of Kerry Walsh, Global Diving and Salvage.

ness at the strake, the average corrosion

rate is given by Equation (4):

icorr

≈ 0.2 mpy (5.08 µm/y) ±

0.15 mpy (3.81 µm/y) (4)

From published data,10 corrosion rates

are reported to be significantly higher at

~2.5 mpy (63 um/y) per side at a depth of

1,000 ft (305 m) near Port Hueneme,

California on the Pacific coast. With sam-

ple exposure times at Port Hueneme of

three years or less, the difference between

reported results at Port Hueneme and the

Montebello is likely related to the protec-

tion afforded by concretion over a 70-year

period. All of the Montebello samples were

taken either above the summer tanks

located just below the shelter deck or in

boiler spaces. None of these spaces held oil

before the attack.

Concretion Measurements Concretion measurements on seven

samples were completed in chemistry labo-

ratories at the University of Nebraska-

Lincoln. Enough material in small pieces

was available to obtain the iron content of

all the samples. Only one sample, MB-7c

(c for concretion), however, was sufficient

in size to measure density and thickness

between shipside and seaside (the side

exposed to the open water). Equation (5)

applies criteria developed from environ-

mental scanning electron microscopy

(ESEM) characterization studies11 and

CECR Equation (2):

icecr

= 0.7 mpy (17.78 µm/y) (5)

where ρ = 2.24 g/cm3, %Fe = 45.3, and d = 0.6

cm. The average would likely have been

lower if additional samples could have

been acquired that provided continuity

between the hull and seaside. Some loss of

sample was encountered during acquisi-

tion, however, and concretion was broken

up after removal from the hole saw.

Application of Weins Number Profile

The Wn was developed as a method to

correlate long-term marine corrosion




under widely variable environmental sea-

water conditions from 2 °C to >30 °C.11 The

Wn is defined by the ratio of the actual

corrosion rate to a corrosion rate deter-

mined from environmental parameters

including the thickness of the accumu-

lated concretion (Equation [3]). Based on

site percent DO, %DO = 17, temperature =

8 °C, salinity = 34 PSU, and corrosion rate

from Equation (4), a new data point with

point spread, is added to the Wn profile

Figure 6.

With the profile modified slightly after

inclusion of the Montebello data points,

Equation (6) illustrates how the Wn ( from

the definition of the Wn, Equation [3])

could be used to estimate the corrosion

rate of the Montebello shell plate knowing

three variables: 1) concretion thickness d =

0.6 cm, 2) temperature = 8 °C, and 3) %DO =

17. The temperature, 8 °C, converts to T =

8+273 = 281 °K. The reciprocal is 1/T (K-1 )

× 1,000 ≈ 3.56. In Figure 6, 3.56 on the x-axis

intersection with the profile line corre-

sponds to a y-axis reading of Wn = 0.4.

icorr

= 0.901 Wn (%DO)d/100 = 0.901(0.4)(17)

(0.6)/100 ≈ 0.05 mpy (1.27 µm/y) (6)

DiscussionBased on metal core thickness differ-

ence, Equation (1), the corrosion rate was

estimated to be icorr

= 0.2 ± 0.15 mpy (5.08 ±

3.8 um/y). Based on Equation (2), the CECR

method estimated the corrosion rate to be

icorr

= 0.70 mpy (17.78 um/y). As mentioned

earlier, the latter would likely have been

lower if sufficient concretion had been

available. Montebello data are consistent

with the existing Wn profile, supporting the

conclusion that the Wn remains a potential

methodology to correlate and predict long-

term marine corrosion at widely diverse

sites. This is especially important at deep-

water sites where core samples are difficult

or impossible to obtain.

Unofficial reports after the latest expe-

dition indicate that no crude remains in the

cargo tanks today although the smell of oil

is noted on at least one of the core samples.

The expertise of the research group does

not include prediction of structural integ-

rity; it is the collective opinion of the group,

FIGURE 4 The robotic hole saw cutting into the hull. Photo courtesy of Kerry Walsh, Global Diving

and Salvage.

FIGURE 5 Sample received at ESI Omaha. The

sample is ~4 in (100 mm) in diameter.

however, that the S.S. Montebello will main-

tain on-site integrity for many decades to

come. In future operations, it is highly rec-

ommended that a metallurgist/corrosion

scientist be on board to monitor sample

acquisition.

Acknowledgments Funding for the metallurgical/corro-

sion assessment of the S.S. Montebello shell

plate was provided by a combination of the

Na tional Oceanic and Atmospheric

Ad ministration, National Marine Sanc-

tuaries, and the National Park Service

Submerged Resources Center.

References 1 D.L. Gause, The War Journal of Major Damon

“Rocky” Gause (New York, NY: Hyperion,

1999).

2 The Attacks on the SS Montebello and the

SS Idaho, The California State Military Mu-

seum, http://www.militarymuseum.org/

Montebello.html (Nov. 20, 2013).

3 Report submitted by D.L. Medlin with D.

Johnson, J. Carr, J. Wagner, “Montebello

Corrosion Assessment Report,” ESI File

No. 37081M, Office of Marine Sanctuaries,

NOAA, June 14, 2012.

4 D. Krieger, “Times Past: Montebello sinking

was denied, then covered up,” The Tribune,

December 19, 2011, http://www.sanluisobispo.

com/2011/12/19/1877032/times-past-

montebello-sinking.html (Nov. 20, 2013).

5 Rules for the Classification and Construction

of Steel Ships (New York, NY: American

Bureau of Shipping, American Lloyds, 1862-

1917) p. 74.

6 Z. Malinoski, T&T Bisco LLC, correspon-

dence to author, April 17, 2011.

7 ASTM E3-11, “Standard Guide for Prepara-

tion of Metallographic Specimens” (West

Conshohocken, PA: ASTM, 2003).


Metallurgical and Corrosion Assessment of Submerged Tanker S.S. Montebello


http://www.militarymuseum.org/Montebello.html

http://www.militarymuseum.org/Montebello.html

http://www.sanluisobispo.com/2011/12/19/1877032/times-pastmontebello-sinking.html



TABLE 2. CORROSION RATE AND SUPPORTING THICKNESS

MEASUREMENTS

Sample Location

Average Final Thickness (in) Original Thickness (in)

Corrosion Rate per Side (i

corr) (mpy)

Equation (1)

MB-1m (Port) Taper region(A) 0.674

0.680 – 0.080 = 0.600 Taper correction = –0.08

(0.600 – 0.674) × (1,000/70) × 0.5 ≈ 0.0

MB-2m (Stbd) End 0.460

0.460 + 0.052 = 0.512 Taper correction = 0.052

(0.512 – 0.460) × (1,000/70) × 0.5 ≈ 0.4

MB-3m (Stbd) Strake plate 0.550

0.680 + 0.160 = 0.840 Taper correction = 0.16

(0.840 – 0.550) × (1,000/70) × 0.5 ≈ 2.0

MB-4m (Port) Taper(A) 0.620

0.680 – 0.090 = 0.590 Taper correction = –0.09

(0.590 – 0.620) × (1,000/70) × 0.5 ≈ 0.0

MB-5m (Port) Side 0.677 0.680

(0.680 – 0.677) × (1,000/70) × 0.5 ≈ 0.02

MB-6m (Port) Side

0.673 0.680 (0.680 – 0.673) × (1,000/70) × 0.5 ≈ 0.05

MB-7c ———————Concretion Only———————

MB-8m (Stbd) Taper(A)

0.543 0.680 – 0.080 = 0.600 Taper correction = –0.08

(0.600 – 0.543) × (1,000/70) × 0.5 ≈ 0.4

(A)Taper shell plate thickness determined by linear extrapolation between 0.46 and 0.68 in.

FIGURE 6 Wn plot as a function of reciprocal absolute temperature. The Montebello estimate is

depicted in red.

8 M.A. Russell , D.J. Conlin, L.M. Murphy,

D.L. Johnson, B.M. Wilson, J.D. Carr, “A Mini-

mum-Impact Method for Measuring Corro-

sion Rate of Steel-Hulled Shipwrecks in Sea-

water,” The International Journal of Nautical

Archaeology, 35.2 (2006): pp. 310-318.

9 D.L. Johnson, D.J. Medlin, L.E. Murphy,

J.D. Carr, D.L. Conlin, “Corrosion Rate Trajec-

tories of Concreted Iron and Steel Ship-

wrecks in Seawater—The Weins Number,”

Corrosion 67, 12 (2011): pp. 125005-1 to

25005-9.

10 M. Schumacher, ed., Sea Water Corrosion

Handbook (Park Ridge, NJ: Noyes Data Corp.,

1979), p. 121.

11 D.L. Johnson, R.J. DeAngelis, D.J. Medlin,

J.D. Carr, D.L. Conlin, “Advances in Chemical

and Structural Characterization of Concre-

tion with Implications for Modeling Marine

Corrosion,” Springer.com, link JOM, Nov. 28,

2013, in JOM, May 2014 issue.

DANA J. MEDLIN is a senior consultant at Engineering Systems, Inc., 5697 N. 13th St., Omaha, NE 68154, e-mail: [email protected]. He has more than 25 years of experience in the fields of metallurgical, corrosion, and biomedical engineering. He was the NUCOR Professor of Metallurgy and director of the Biomedical Engineering Program at the South Dakota School of Mines and Technology. He is a Fellow of ASM International, as well as the author of numerous publications, books, and patents.

JAMES D. CARR is an emeritus professor of chemistry at the University of Nebraska, 317 Hamilton Hall, Lincoln, NE 68588, e-mail: [email protected]. He has taught at every level, from freshmen to graduate students, and has done research on many systems involving dilute solutes in water.

DONALD L. JOHNSON is a staff metallur-gist at the Submerged Resources Center, National Park Service, 14709 W. Via Manana, Sun City West, AZ 85375. He is a professor emeritus with the Department of Mechanical and Materials Engineering, University of Nebraska-Lincoln, with publi-cations in the areas of corrosion and metal chemistry. A member of NACE Inter-national since 1964, Johnson received the George B. Hartzog National Park Service Individual Volunteer of the Year Award in 2005.

DAVID L. CONLIN is an underwater arche-ologist and the current chief of the National Park Service’s Submerged Resources Center in Lakewood, Colorado. He has worked on marine corrosion as applied to shipwrecks worldwide since early work on the Confederate submarine HL Hunley in 1996.




http://Springer.com





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www.nace.org/traindubai

4,000 sq. ft. of

training space

2 dedicated training

& exam rooms

Entire suite of NACE courses

will be offered

New Training Center Features:

DIAC is located on an 18 million sq. ft. campus dedicated to Higher Education. This state-of-the-

art campus offers a full range of facilities including restaurants, news agents, bookstores, retail

shops, and a student recreational center.

Located in the Dubai International Academic City (DIAC) Campus


http://www.nace.org/traindubai


Meet Benny Abbott, a coatings

professional with 26 years of

experience in the industry. Abbott

is NACE-certified CIP Level 3 and

CIP Level 3 Nuclear. He shared

his career story in the I AM NACE

career story sharing project. To see

Abbott’s video interview and full

Q&A—and to explore the careers of

other corrosion professionals—

visit www.nace.org/i-am-nace.

Q: When did you start working

in the coatings field?

A: I was sort of born and raised

into the field. My father was

an industrial coatings contractor for 47

years. He started out up on an old water

tank. We did a lot of water tanks, bridges,

and steel mills in the Birmingham area.

My dad instilled in me the importance of

doing the job right the first time, following

the specifications, making the customer

happy, and learning the equipment that

you’re working with so that when it breaks

you can repair it and get the job done.

Q: What are some challenges

you see in the field?

A: People wanting a quick job and

taking short cuts. If you take

shortcuts you’re looking for a failure. It’s

not going to last. Do it right the first time.

Surface prep is key. I don’t care what type

of coatings system it is. If you don’t do the

correct surface preparation, it’s going to

fail.

Q: What do you like to do for

fun?

A: I dabble with playing drums.

Since the early 1990s, I’ve been

building custom drums and do custom

finishes. Most of the shells I build are out

of maple. The drummer for Leon Russell

is playing my drums and I’ve got a good

friend in Birmingham who is the world’s

largest drum collector. He’s got several

of my snares in his collection.

BENNY “BENJY” ABBOTT

Career: Business owner

Abbott Consulting and Coating

Inspections

NACE Certifcations: CIP Level 3

CIP Level 3 Nuclear

Quote: “If you stop learning, you’ve

basically just stopped your

whole career.”

Would you like to share your corrosion story?

E-mail us at [email protected]


http://www.nace.org/i-am-nace


2014

Collaborate. Educate. Innovate. Mitigate.

www.nacecorrosion.org

Ofcial Publications of CORROSION 2014

March 9-13, 2014Henry B. Gonzalez Convention Center

San Antonio, Texas

6000+ Attendees

380+ Exhibitors

14 Industry Tracks

Vast Networking Opportunities

Hours of Technical Education

Register Today for the World’s Largest Corrosion Conference & Expo

Registration has Never Been Faster or Easier!


http://www.nacecorrosion.org

Your Association

in ActionNACE NEWS


NACE Sponsors Seven Rising Stars at the Emerging Leaders Alliance Conference

The corrosion industry is facing

what some have called a “silver

tsunami;” a wave of retirements

expected to leave many job

openings and leadership

positions in its wake. If the NACE Inter

national members who attended the 2013

Emerging Leaders Alliance (ELA) Con

ference are any indication of the future,

soontoberetirees can rest assured know

ing the industry is in good hands.

The ELA is a partnership of

engineering, research, and scientific

organizations—including NACE—focused

on fostering leadership among promising

young members. Held November 11 to 13

in Reston, Virginia, the conference was

attended by seven accomplished young

members of NACE, who joined 77 of their

peers for the intensive threeday program

designed to provide attendees with

valuable leadership skills they can apply

immediately.

“We received several applications for

this program and each applicant was very

impressive,” says NACE Executive Director

Bob Chalker. “I’m proud to have all of these

young professionals among our member

ship; they bring so much to the industry

and I believe they will continue to be

valuable members of the organization, and

hopefully future NACE leaders.”

Leadership training is not a typical

requisite in an engineering curriculum,

but as young professionals advance at

work, strong management skills become

a necessity. “I was looking to gain tips for

more effective communication and ways to

inspire a team,” says Kathleen Armistead,

refinery technical advisor at Athlon

Solutions. “I was also very interested to

learn about how to leverage different gener

ations working together.” The conference

NACE International’s 2013 ELA participants (left to right): Kathleen Armistead, refnery technical advisor

at Athlon Solutions; Eric Shoyer, engineer at Elzley Technology Corp.; Brittney Taylor, specialty engineer

at Xcel Energy; Dana Lipfert, corrosion engineer at QEP Field Services; Keith Redmond, co-owner and

pipeline consultant at BR&A Pipeline Solutions, Inc.; Sam Zelinka, materials research engineer at U.S.

Forest Service; and Abirami Krishnan, corrosion engineer at Chevron.

covered those topics and more, including

leading innovation, resolving team conflict,

and making the transition from a technical

position to a management position.

One of the most popular topics at the

conference was social styles and behavioral

intelligence. “I really enjoyed the social

skills session,” says Eric Shoyer, an engineer

with Elzley Technology Corp. “It showed

how different people behave and react

to certain things. It was eyeopening and

made me realize things I hadn’t considered

before.” Sam Zelinka, materials research

engineer at the U.S. Forest Service, says he’s

already begun to put what he learned into

practice by working on interactions with

his coworkers.

Keith Redmond, coowner and pipeline

consultant at BR&A Pipeline Solutions,

expected to hear from excellent speakers

and learn how to implement structure

in the workplace among the oil and gas

workforce. He says, “The conference

exceeded my expectations. What I learned

can be applied not only at work, but also in

everyday situations, with anyone.”

When asked about advice for other

NACE members who may wish to attend

the ELA Conference in the future, Shoyer

says, “If you get the opportunity to go, don’t

miss it. It’s very beneficial to your work and

it’s also a great networking opportunity for

you and for your employer.”

The application process for the 2014

ELA Conference will begin in March 2014.

Applications are reviewed by a member

volunteer group from the NACE Area

Coordination Committee. The group selects

the top applicants and NACE sponsors their

full registration for the event. For more infor

mation about the program, please contact

Cassie Dieudonne at +1 2812286200.

For more information about the ELA, visit

http://emergingleadersalliance.org.

Jan14_NACEnews.indd 82 12/18/13 3:38 PM

http://emergingleadersalliance.org


Atotal of 56 individuals in the

corrosion field successfully

completed state-of-the-art

training at the annual fall

Rectifier School, conducted

at Seaward County Community College/

Area Technical School (SCCC/ATS) on

October 22 to 24, 2013 in Liberal, Kansas.

The participants devoted 2½ days to the

hands-on training, hosted in partnership

with the NACE International Gas Capital

Section, the Gas Capital Rectifier School

Committee, and SCCC/ATS.

The students accomplished the follow-

ing during the course:

¥ Mastered a basic understanding of a

typical cathodic protection rectifier

¥ Learned how to read and safely adjust

the rectifier

¥ Developed a basic understanding of a

typical rectifier

NACE Area & Section News

Central Area

Northern Area

The NACE International Northern

Area held its eastern confer-

ence October 20 to 22 in Halifax,

Nova Scotia. Hosted by the NACE

Atlantic Canada Section, the

conference featured presentations and open

forums with industry leaders in the areas of

corrosion in transportation and municipal

infrastructure, the oil and gas industry, and

marine and seawater environments.

In addition to the technical program,

participants enjoyed several social and

networking events, including two receptions

and an evening cruise in Halifax Harbor

aboard the sailing vessel Silva.

The Northern Area Western Conference will

be held January 27 to 30, 2014, in Edmonton,

Alberta, Canada. (—Bob Horne)

Nearly 60 people attended the annual Rectifer School in Liberal, Kansas.

¥ Discovered how a rectifier works

¥ Picked up basic troubleshooting

techniques

Bob Speck (Universal Rectifiers)

shared his 56 years of experience during

the instruction. In addition, six students

in the corrosion technology program at

SCCC/ATS earned scholarships totaling

$3,000 from the college and the NACE Gas

Capital Section.

The next corrosion school is scheduled

for March 11 to 13, 2014. Information and

registration for that session are available

by contacting the SCCC/ATS Business

and Industry Office at b&[email protected] or

+1 620-417-1170. (—Norma Jean Dodge)

Left to right: Dennis Dutton; Bob Horne, past

Northern Area chair and current Atlantic Canada

Section trustee; and Debra Boisvert.

Attendees of the NACE Northern Area Eastern

Conference enjoyed an evening cruise in Halifax

Harbor. Left to right: Debra Boisvert, Northern

Area chair; Laura Hack, NACE frst lady; Harvey

Hack, NACE president; and Dennis Dutton,

Northern Area secretary/treasurer.

NACE

Area & Section News


http://sccc.edu


NACE NEWS

NACE International Commences Global Study on Corrosion Costs and Preventive Strategies

Administration (FHWA) and support from

NACE provided broad research on direct

and indirect costs for U.S. industry sectors.1

The results of the study indicated the

annual estimated direct cost of corrosion

in the United States was $276 billion. The

study led Congress to develop a Corrosion

Policy and Oversight (CPO) office within

the Department of Defense (DoD); the CPO

has demonstrated up to a 40:1 return on

investment for corrosion control programs

implemented by DoD. The study also

resulted in Congressional support for the

launch of the world’s first undergraduate

degree in corrosion at the University of

Akron in Ohio.

“This is an essential study for industry

stakeholders and government world-

wide,” says NACE Executive Director Bob

Chalker. “It will be the most comprehen-

sive study to look at costs associated with

the impact of corrosion and the result-

ing data will contribute to future project

plans, regulations, education, and more.”

NACE will provide updates on the

progress of the study periodically in NACE

publications, press releases, and at www.

nace.org.

Reference1 G.H. Koch, M.P.H. Brongers, N.G. Thompson,

V.P. Virmani, J.H. Payer, “Corrosion Costs

and Preventive Strategies in the United

States,” Publication no. FHWA-RD-01-156

(Washington, DC: FHWA, 2002).

NACE Past President Elaine Bowman is

leading the new global cost of corrosion

study.

A free publication summarizing the results

of the 2002 cost of corrosion study is

available from the Publications area of the

NACE Web site: www.nace.org.

The new study will examine corrosion costs in several industry sectors and provide cost comparisons for repairs, replacement, prevention, and control.

NACE International has

announced the commencement

of its new global study on costs

related to corrosion, an initia-

tive to determine the financial and societal

impact of corrosion on industry sectors

including infrastructure, manufacturing,

utilities, transportation, and govern-

ment. The two-year study, led by NACE

with participation from industry partners

worldwide, is now underway and is being

managed by longtime corrosion industry

advocate and NACE Past President Elaine

Bowman.

The study will integrate research based

on international, regional, and academic

participation and will focus on economic data

to provide statistics and models that asset

owners can use to implement asset preserva-

tion, management, and/or replacement.

“Corrosion is an inevitable, but control-

lable process that can result in destructive,

even catastrophic incidents when not

properly prevented and managed,” says

Bowman. “Costs associated with corro-

sion control include direct expenses like

repair and replacement of assets, or the

environmental and physical impact of

corrosion-related failures. This study will

explore direct and indirect costs of corro-

sion to several industry sectors around the

world and identify ways to save as much as

30% of those costs.”

A 2002 study funded by the U.S. Congress

with oversight by the Federal Highway


http://www.nace.org

http://www.nace.org

http://www.nace.org

Your Association in Action


Corrosion Analysis Network Provides One-Stop Source for Corrosion Information

The Corrosion Analysis Network,

a joint project between founding

partners NACE International and

ASM International and content

partners ASTM and SSPC, is a comprehen-

sive and authoritative online source for

researching, understanding, preventing,

and solving corrosion-related problems.

The site includes three main content

areas—Publications & Standards,

Corrosion Performance Data, and News

& Resources—offering materials profes-

sionals and emerging professionals a

single point of access to content and

data from multiple published sources.

The home page features a simple search

function for quick access to publications

and standards information, and provides

one-click access to the other content

areas.

Vilupanur Ravi, a professor and

department chair at Cal Poly Pomona

in California, says, “I recently provided

access to the Corrosion Analysis Network

to the students in my corrosion and degra-

dation of materials class, and asked them

to provide feedback. They have found it

to be a valuable resource for corrosion-

related research and investigation. The

Publications & Standards section provides

a nice, diverse set of articles—for instance,

more than 1,200 documents pertaining

to cathodic protection, including infor-

mation from ASM, ASTM, and SSPC, in

addition to NACE. Another content area

within the Corrosion Analysis Network,

the Corrosion Performance Database,

currently includes metallic and ceramic

materials, and associated corrosion

behavior in different environments. Given

the growing interest in polymers such as

PVC and polypropylene, I would like to

It is possible to determine a material’s performance qualities by performing a search or drilling down

into the database material data content tree.

The Corrosion Analysis Network provides a single point of access to corrosion-related content from

multiple sources.

see the corrosion performance database

expanded to include polymer data. Overall,

the Corrosion Analysis Network provides

a great deal of valuable information acces-

sible from a single site—serving both

academic and commercial user needs.”

Cal Poly Pomona chemical engineering

student Justin Soodjinda says, “The organi-

zation of the Web site and the ability to

access literature documents based on any



NACE NEWS

combination of subjects, sources, publish-

ers, or even years is great.” Adds Raul Rebak

of GE Global Research, “I really enjoy using

CAN since it is like a superstore for corro-

sion papers, a one-stop shop, and you get

all your groceries. I only need to click three

times and I have the paper I am looking

for—I don’t need to go in and out of different

society sites or databases. I like that CAN

has Corrosion journal articles and NACE

annual conference papers in one spot. CAN

also has ‘old’ ASTM papers that I cannot find

anywhere else!”

Case ExamplesConsider a simple example that

illustrates how the Corrosion Analysis

Network could help a design engineer or

failure analyst research ship hull coatings.

A quick search for key words “boat”

and “ship” returns nearly 2,400 results.

Choosing “Protection and Mitigation

>Protective Coatings” from a set of

predefined subject filters reduces the

result set down to 185 documents, includ-

ing conference proceedings, handbooks,

journals, magazine articles, reports,

standards, technical book chapters, and

technical papers. Additional filters by

content type, publisher, and publica-

tion year allow the user to hone in on the

most relevant information for the specific

project or task at hand.

Consider another use case—a researcher

or consultant investigating oil and gas

pipeline failures. A key word search for

“pipeline” with a filter of “Testing and

Monitoring>Failure Analysis” finds 56 publi-

cations from multiple sources, including

ASM failure analysis case histories, ASTM

STP technical papers, and NACE confer-

ence papers and Materials Performance

magazine articles. In investigating a particu-

lar material’s performance within a given

environment, for instance API N-80 steel in

petroleum oils, it may be useful to review the

data found within the Corrosion Analysis

Network Performance Database. Here, a user

can perform a simple search for “n-80” to

find the desired material, or alternatively can

drill down into the database’s material data

content tree.

The Corrosion Analysis Network

helps reduce the time it takes to solve a

particular corrosion engineering problem

by providing a central repository of

peer-reviewed research literature and real-

world examples.

Publications & StandardsThe Publications & Standards content

area combines corrosion mitigation infor-

mation from NACE, ASM, ASTM, SSPC,

the U.S. government, and other authorita-

tive sources. As described in the previous

examples, users can find information

pertaining to desired topics using a combi-

nation of key word and faceted (filtering)

searches. Since its initial launch in 2010,

the total number of documents in the

Corrosion Analysis Network has grown by

52%, from 13,700 to 20,800. Counts (as of

November 18, 2013) were:

n ASM (6,479 documents)

• 504 ASM Handbook articles

• 421 technical book chapters

• 3,840 conference proceedings articles

from conferences such as MS&T and

ISTFA

• 446 Alloy Digest datasheets

• 1,165 data book datasheets

• 28 articles from the Journal of

Thermal Spray Technology

• 75 other magazine articles

n ASTM (1,734 documents)

• 1,357 STP (peer-reviewed) technical

papers

• 186 standards


• 86 journal articles from the Journal of

ASTM International and the Journal of

Testing and Evaluation

n NACE (10,754 documents)

• 7,909 NACE conference proceedings

articles (1996-2013)

• 1,895 Corrosion journal articles

(1992-2009)

• 770 Materials Performance magazine

articles (2004-2013)

• 117 standards (2009-2013)

• 63 reports (2009-2013)

n SSPC (1,452 documents)

• 1,021 conference proceedings articles


• 116 standards

n U.S. Government & Other Sources (436

documents)

• 436 reports (1977-2013)

Corrosion Performance DataThe Corrosion Performance Data

content area, a separate component of

the Corrosion Analysis Network, is a fully

searchable database of corrosion data

for specific materials in specific environ-

ments, based on laboratory, sample, and

field testing. Consisting of nearly 9,000

metallic and ceramic material-environ-

ment records, it provides nearly 25,000

combinations of corrosion behavior.

Here, users can investigate questions

like:

n Which materials are resistant to corro-

sion in a particular environment?

n What is the corrosion rate for a certain

material in a specific environment?

n Where did the data come from? How

was the test or measurement made?

As an example, a design engineer might

want to compare the corrodibility of Type

304 stainless steel (UNS S30400) in various

common acids (e.g., hydrochloric acid

[HCl], hydrobromic acid [HBr]) at room

temperature. Using the left navigation tree,

the user can drill down and select the ma-

terials to be compared, and create a report.

Reports such as materials comparisons can be generated through the site.


Your Association in Action


News and Resources

Additional Corrosion Analysis Network

site content includes:

n News

n Glossary

n Videos and events information

n Education links—programs and other

resources

For additional information includ-

ing how to subscribe, contact Denise

In Memoriam

NACE International Past

President John D. Trim

passed away on September 25,

2013 following a long illness.

He was 83.

Trim was born in Montreal Quebec,

Canada and later moved to Toronto

Ontario, Canada following his marriage

to his wife, Joyce. He spent his career

in the field of corrosion control and

was a member of NACE for more than

50 years. He first became a member of

NACE technical committees on coatings

in 1969, serving as T-6A chair from 1970

to 1971 and T-6 chair from 1972 to 1977.

He was chair of the Technical Practices

Committee from 1979 to 1981. He served

on the NACE Board of Directors for 10

years and was elected president for the

1988-1989 term. Trim became a Reference

Publications Committee reviewer in 1992

and a document review coordinator in

1996. He also chaired the Committee on

Operating Procedures in 1993, which was

charged with

looking at

the Board

structure

and making a

report to the

Board. The

current Board

structure

came out of

the recom-

mendations of this committee. Trim

received the R.A. Brannon Award in 1998.

Outside of his career and NACE activi-

ties, Trim enjoyed spending time at the

family’s farm in Heathcote. He was an

avid gardener and fly fisherman. He and

Joyce traveled extensively, and he used

his multilingual skills to meet and get to

know new people.

Trim is survived by his wife Joyce,

children Heather (Stew) and David

(Joanna), and grandchildren Nicole, Kate,

Courtney, and Stephen.

Sirochman at denise.sirochman@

asminternational.org or +1 440-338-5409.

NACE International Gold and Diamond-

level corporate members receive a

subscription to the Corrosion Analysis

Network as one of their membership

benefits. For more information on the NACE

Corporate Member program, please contact

Cassie Dieudonne at cassie.dieudonne@

nace.org or +1 281-228-6282.

NACE OFFICERS

P RE S I DE NTTushar Jhaveri*

Vasu Chemicals

V ICE PR ES ID EN THarvey P. Hack*

Northrup Grumman Corp.

Annapolis, MD

T RE A S URE RKeith Perkins*

Williams Gas Pipeline Transco

Houston, TX

P AST PR ES IDE NTKevin C. Garrity*

Mears Group

Plain City, OH

E XEC U T IV E D IR E CT ORRobert H. Chalker*

NACE International

Houston, TX

D IR ECT O RSSamir Degan/2011-2014

William G. Mueller/2011-2014

Marietta, GA

EN Engineering, L.L.C.

Jenny Been/2012-2015

Timothy Bieri/2012-2015

BP America, Inc.

Houston, TX

Sylvia Hall/2012-2015

National Oilwell Varco

South Gate, CA

Jane Brown/2013-2016

Brown Corrosion Services

Houston, TX

Steven Hoff/2013-2016

University of Akron

Akron, OH

Shell

Fabian Sanchez/2013-2016

E X O FF I C IO D IRE CTORSNeil G. Thompson

Chris Fowler

*Executive Committee members







NACE NEWS

NACE Corporate MembersMP publishes the names of all Diamond 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 November 15, 2013:

DIAMOND

Asian Petroleum FMC, Shuaiba Industrial Area, Kuwait

Carboline Company, St. Louis, Missouri

Corrpro, Houston, Texas

Denso North America, Houston, Texas

DNV, Dublin, Ohio

Elcometer, Rochester Hills, Michigan

Exova, West Midlands, United Kingdom

International Paint, LLC, Strongsville, Ohio

MESA, Tulsa, Oklahoma

NALCO Champion, an Ecolab company, Houston, Texas

National Grid, Waltham, Massachusetts

ONEOK, Inc., Oklahoma City, Oklahoma

PMAC Group, Aberdeen, United Kingdom

Polyguard Products, Inc., Ennis, Texas

Research Institute of Lanzhou Petrochemical Co., Lanzhou, China

Saipem SpA, Milanese, Italy

Southern California Gas Co., Los Angeles, California

U.S. Department of Defense Corrosion Prevention and Control Integrated Product Team, Arlington, Virginia

GOLD

Alpha Pipeline Integrity Services, Kemah, Texas

APAVE International, Bordeaux, France

Atmos Energy, Jackson, Mississippi

Baker Hughes, Sugar Land, Texas

Bechtel Group, Inc., Houston, Texas

BP US Pipeline, Naperville, Illinois

ConocoPhillips Co., Bartlesville, Oklahoma

Corrosion Technology Services, LLC, Sharjah, United Arab Emirates

Corrosion Testing Services, Taft, Tennessee

Crompion International, Baton Rouge, Louisiana

Deepwater Corrosion Services, Houston, Texas

E-TECH Energy Technology Development Corp., Tianjin, China

Evraz, Inc., Regina, Saskatchewan, Canada

Galvotec Companies, McAllen, Texas

Haynes International, Inc., Kokomo, Indiana

High Performance Alloys, Inc., Windfall, Indiana

Integrated Global Services, Midlothian, Virginia

Interprovincial/International Corrosion Control, Inc., Burlington, Ontario, Canada

Kuwait Pipe Industries and Oil Services Co., Safat, Kuwait

MATCOR, Inc., Chalfont, Pennsylvania

NICOR Gas, Sycamore, Illinois

NRI, Lake Park, Florida

Oceaneering International, Inc., Houston, Texas

Pacific Gas & Electric Co., Walnut Creek, California

RK&K, Charlotte, North Carolina

Rosen Group, Stans, NW, Switzerland

Sherwin-Williams Co., The, Cleveland, Ohio

TGI SA ESP, Bucaramanga, Colombia

TransCanada Pipelines, Calgary, Alberta, Canada

United States Coast Guard, Baltimore, Maryland

Williams, Tulsa, Oklahoma

Wood Group Integrity Management, Perth, WA, Australia

Xodus Group, Houston, Texas

NEW CORPORATE MEMBERS

Research Institute of Lanzhou Petrochemical Co., Lanzhou, China—Diamond

Sulzer Mixpac USA, Inc., Salem, New Hampshire—Silver

AUGE Industrial Fasteners, LLC, Houston, Texas—Iron

BAE Systems Maritime, Cumbria, United Kingdom—Iron

CCB International, Houston, Texas—Iron

INRES, Ltd., Tema, Ghana—Iron

Total NACE membership was 33,317

as of November 15, 2013. For more

information about NACE corporate

membership levels and individual

member benefits, contact the

FirstService department at phone:

+1 281-228-6223 or e-mail: firstservice@

nace.org.




Meetings & Events


FEBRUARY 2014

15TH MIDDLE EAST CORROSION CONFERENCE

(MECCE)

February 2-5, 2014More Info: Mohammed Barot, NACE Dhahran Saudi Arabia Section, e-mail: [email protected], Web site: www.mecconline.org

LIBERTY BELL CORROSION COURSE

February 12-13, 2014Horsham, PA

More Info: David Krause, phone: +1 610-344-7002, e-mail: [email protected], Web site: www.nace-philapa.org

PURDUE CORROSION SHORT COURSE

February 25-27, 2014West Lafayette, IN

More Info: Josh Brewer, phone: +1 517-230-2435, e-mail: [email protected], Web site: www.corrosionshortcourse.com

MARCH 2014

CORROSION 2014

March 9-13, 2014San Antonio, TX

More Info: CaLae McDermott, phone: +1 281-228-6263, e-mail: [email protected], Web site: www.nacecorrosion.org

APRIL 2014

PIPELINE INTEGRITY MANAGEMENT

SEMINAR 2014

April 23-25, 2014Mexico City, Mexico

More Info: Lesley Williams, phone: +1 281-228-6413, e-mail: [email protected], Web site: www.nace.org/pimsmexico

MAY 2014

48TH ANNUAL WESTERN STATES

CORROSION SEMINAR

May 6-8, 2014Pomona, CA

More Info: Jamal Safa, phone: +1 312-367-6903, e-mail: [email protected], Web site: www.westernstatescorrosion.org

CONCRETE COATINGS CONFERENCE 2014

May 7-8, 2014Philadelphia, PA

More Info: Katie Flynn, phone: +1 281-228-6210, e-mail: [email protected], Web site: www.nace.org/concretecoatings

APPALACHIAN UNDERGROUND CORROSION SHORT COURSE

May 13-15, 2014Morgantown, WV

More Info: Danielle Petrak, phone: +1 304-293-4307, e-mail: [email protected], Web site: [email protected]

EUROPEAN CORROSION CONFERENCE & EXPO 2014

May 14-16, 2014Madrid, Spain

More Info: Medy Ilona Ghita, e-mail: [email protected], Web site: naceespanaevents.wordpress.com

SINOCORR 2014

May 19-22, 2014Beijing, China

More Info: NACE Shanghai China Section, phone: +86 21 5012 4418, e-mail: [email protected], Web site: www.sinocorr.org

JUNE 2014

BRING ON THE HEAT 2014

June 17-19, 2014Houston, TX

More Info: Katie Flynn, phone: +1 281-228-6210, e-mail: [email protected], Web site: www.nace.org/both2014

AUGUST 2014

NACE CENTRAL AREA CONFERENCE 2014

August 25-27, 2014Tulsa, OK

More Info: CaLae McDermott, phone: +1 281-228-6263, e-mail: [email protected]

SEPTEMBER 2014

CORROSION TECHNOLOGY WEEK 2014

September 21-25, 2014Alexandria, VA

More Info: Lesley Williams, phone: +1 281-228-6413, e-mail: [email protected]

Denotes NACE International event



http://www.mecconline.org


http://www.nace-philapa.org


http://www.corrosionshortcourse.com


http://www.nacecorrosion.org


http://www.nace.org/pimsmexico



http://www.nace.org/concretecoatings



http://naceespanaevents.wordpress.com



http://www.nace.org/both2014



http://www.westernstatescorrosion.org

http://www.westernstatescorrosion.org



http://www.sinocorr.org

http://www.sinocorr.org

NACE Course Schedule


NACE NEWS

Basic Corrosion

San Antonio, TX March 3-7, 2014

Houston, TX April 13-17, 2014

CIP Level 1

Houston, TX February 3-8, 2014

Perth, WA, Australia February 3-8, 2014

Mobile, AL February 9-14, 2014


Cape Canaveral, FL February 9-14, 2014

Milan, Italy February 9-14, 2014

Manchester, U.K. February 10-15, 2014

Vadodara, India February 10-15, 2014

Dubai, U.A.E. February 16-21, 2014

Shanghai, China February 16-21, 2014



Baton Rouge, LA March 2-7, 2014

Brisbane, QLD, Australia March 3-8, 2014

Houston, TX March 3-8, 2014

Spijkenisse, The Netherlands March 3-8, 2014


Aberdeen, U.K. March 10-15, 2014


Newcastle-upon-Tyne, U.K. March 17-22, 2014

Melbourne, VIC, Australia March 17-22, 2014

Quito, Ecuador March 17-22, 2014



Kuala Lumpur, Malaysia March 24-29, 2014

Virginia Beach, VA March 30-April 4, 2014

Anaheim, CA March 30-April 4, 2014

Seattle, WA March 30-April 4, 2014

Albuquerque, NM March 30-April 4, 2014

Cape Canaveral, FL March 30-April 4, 2014

Denver, CO March 30-April 4, 2014

Houston, TX March 30-April 4, 2014

Bogota, Colombia March 31-April 5, 2014

St. Louis, MO March 31-April 5, 2014



Sydney, NSW, Australia April 7-12, 2014


Shanghai, China April 13-18, 2014

Dammam, Saudi Arabia April 19-24, 2014

Houston, TX April 27-May 2, 2014

Harrogate, U.K. April 28-May 3, 2014

Mumbai, India April 28-May 3, 2014

CIP Exam Course 1


Ulsan, Korea March 24-26, 2014


CIP Level 2

Mumbai, India February 3-8, 2014


Perth, WA, Australia February 10-15, 2014

Montreal, QC, Canada February 16-21, 2014



Manchester, U.K. February 17-22, 2014

Dubai, U.A.E. February 22-27, 2014

Shanghai, China February 23-28, 2014


Brisbane, QLD, Australia March 10-15, 2014


Kansas City, MO March 23-28, 2014



Melbourne, VIC, Australia March 24-29, 2014

Kuala Lumpur, Malaysia March 31-April 5, 2014

Denver, CO April 6-11, 2014

Cape Canaveral, FL April 6-11, 2014

Seattle, WA April 6-11, 2014

Anaheim, CA April 6-11, 2014

Virginia Beach, VA April 6-11, 2014

St. Louis, MO April 7-12, 2014

Spijkenisse, The Netherlands April 7-12, 2014

Shanghai, China April 20-25, 2014


Dammam, Saudi Arabia April 26-May 1, 2014

CIP Exam Course 2


Ulsan, Korea March 27-29, 2014


CIP One-Day Bridge

Houston, TX March 8, 2014

Virginia Beach, VA April 5, 2014

CIP Peer Review


Montreal, QC, Canada February 21-23, 2014


Kuala Lumpur, Malaysia March 2-4, 2014


Kansas City, MO March 28-30, 2014



NACE Course Schedule




Seattle, WA April 11-13, 2014

Cape Canaveral, FL April 11-13, 2014

Denver, CO April 11-13, 2014

St. Louis, MO April 12-14, 2014


Coatings in Conjunction with Cathodic Protection



Corrosion Control in the Refning Industry

Fahaheel, Kuwait February 2-6, 2014

Cairo, Egypt February 15-19, 2014



CP Interference

Bogota, Colombia March 31-April 5, 2014

CP 1–Cathodic Protection Tester




Dammam, Saudi Arabia March 29-April 3, 2014


Tulsa, OK April 27-May 2, 2014

CP 2–Cathodic Protection Technician



Chicago, IL February 16-21, 2014



Dammam, Saudi Arabia April 5-10, 2014

Bogota, Colombia April 21-26, 2014


CP 2–Cathodic Protection Technician—Maritime


CP 3–Cathodic Protection Technologist

Cairo, Egypt February 1-6, 2014


Fahaheel, Kuwait April 5-10, 2014

CP 4–Cathodic Protection Specialist


Fahaheel, Kuwait April 12-17, 2014


Designing for Corrosion Control

Edmonton, AB, Canada February 3-7, 2014

Dammam, Saudi Arabia February 15-19, 2014


In-Line Inspection


Internal Corrosion for Pipelines—Basic

Dammam, Saudi Arabia February 22-26, 2014

Cairo, Egypt March 1-5, 2014


Internal Corrosion for Pipelines—Advanced

Dammam, Saudi Arabia March 29-April 3, 2014

Cairo, Egypt March 8-12, 2014


Marine Coating Technology



Nuclear Power Plant Training for Coating Inspectors


Offshore Corrosion Assessment Training (O-CAT)


PCS 1 Basic Principles


PCS 2 Advanced


PCS 3 Management


Pipeline Coating Applicator Training

Edmonton, AB, Canada March 31-April 4, 2014

Edmonton, AB, Canada April 14-18, 2014

Pipeline Corrosion Assessment Field Techniques (P-CAFT)



Pipeline Corrosion Integrity Management (PCIM)

Fahaheel, Kuwait February 2-6, 2014


Shipboard Corrosion Assessment Training (S-CAT)




For the most up-to-date course

schedules and course information,

visit www.nace.org/eduschedule.


http://www.nace.org/eduschedule

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


Cathodic Protection for Offshore Platforms, Pipelines,

Docks, Petrochemical Plants, Tanks, Vessels

Pin Brazing, Lockheed Marine VTA’s & ECDA Surveys

Engineering, Inspection, Installation & Materials

300 Bark Dr. Ph: 504-362-7373

Harvey, LA 70058 FX: 504-362-7331

Email: [email protected]

Galvotec Corrosion

Services, LLC

Sales Office

181 Grefer Lane

Harvey, LA 70058

Tel.: (504) 362-7776

Fax: (504) 269-1418

Headquarters-

6712 S. 36th Street

Mc Allen, Texas 78503

Tel.: (956) 630-3500

Fax: (956) 630-3595

ANODES

ISO-9001 Certifed

Aluminum-Magnesium-Zinc/Retroft-Platform-Bracelet/Hull-Tank

Onshore/Offshore

QUALITY-PERFORMANCE-RELIABILITY

Email: [email protected]

www.galvotec.com

Complete Corrosion Control SystemsACCESS FITTINGS•ER PROBES•LPR PROBES•COUPONS COUPON HOLDERS•CHEMICAL INJECTION•INSTRUMENTS

SOFTWARE•ANALYSIS•ISO 9001:2000 CERTIFIED

Manufacturing & Installation4815 Elenlak Road, Edmonton, Alberta, T6B 2N1

Tel (780) 465-1187 E-mail [email protected] Fax (780) 466-4632 Web Site www.caproco.com

Exclusive Authorized Distributor

Belzona Western Ltd.Calgary, Alberta Canada Phone: 1-800-249-7197 Fax: 403-278-8898Web site: www.belzona.caE-mail: [email protected] Belzona Polymeric Coatings combat erosion, corrosion and abrasion in high temperature immersed conditions. Rebuild and line tanks, process vessels and plant equipment.

and Procedures.

ISO 9001-2000 certifed

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]

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 Specifcation 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

THE D.E. STEARNS COMPANY

Manufacturers of Worry-Free Holiday

Detectors Since 1941

www.destearns.com

For over 25 years, Coastal Corrosion Control has been the Gulf South’s leader in cathodic protection

We offer services nationwide including:

• Construction/Installations • Pipeline - Integrity - ECDA• Engineering & Design • Right-of-Way Maintenance• Material Sales • Survey• Offshore

COASTAL CORROSION CONTROL, INC.800-894-2120

www.coastalcorrosion.com

CEDs_FINAL FILE_USETHIS NEW.indd 92 12/18/13 4:21 PM



We have a space reserved for

your business card.

Call the Advertising Department

at +1 281-228-6219.

Phone/fax: 210/923-5999


METASPEC Co.

METAL TEST SPECIMEN, COUPONS, PANELS

RODS, FIXTURES, RACKS AND HOLDERS

P.O. BOX 240898 r SAN ANTONIO, TEXAS 78224

Pin BrazingEasybond equipment & consumables available in the USA through sole importers Galvotec Corrosion Services and GMC Electrical

Contact Dave Johnson on (504) 362 7373

or Gary Matlack on (909) 947 6016

Phone: (256) 358-4202 Fax: (256) 358-4515 E-mail: [email protected]

www.metalsamples.com

Corrosion Monitoring Systems

• ER-LPR Instruments• Corrosion Probes

• Coupons & Racks • Coupon Holders

• Access Fittings • Retrieval Systems

ISO 9001 Certified




We have a space reserved for

your business card.

Call the Advertising Department

at +1 281-228-6219.

TRI-STAR INDUSTRIES PTE LTD

Website: www.tristar.com.sgEmail: [email protected]: Fax:

Specialist Manufacturer of Aluminum & Zinc

Anodes. We also provide full CP surveys, installations &

commissioning, including ICCP systems.

Plated and PTFE Coated Fasteners.

ZINGA Film Galvanizing System.

www.tinker-rasor.com

www.teststations.com

• Independent advice on Oilfeld Chemicals programs

[email protected]

• Confdential OFC staff recruitment service

[email protected]

• Confdential OFC job search

[email protected]



http://www.nace.org/nacestore

AD INDEX Listing of Advertiser Contact Information

C L A S S I F I E D

Anotec Industries, British Columbia, Canada ..................................... 45

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

Sugar Land, Texas ........................................................ 49

Phone: +1 281-275-7253, Web site: www.bakerhughes.com/inspection

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

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

Clemco Industries Corp., Washington, Missouri .............................. 48

Phone: +1 636-239-0300, Web site: www.clemcoindustries.com/pipetools

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

Phone: 1 800-443-3516, Web site: www.corrpro.com

Cortec Corp., St. Paul, Minnesota ........................................................ 24

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

DeFelsko Corp., Ogdensburg, New York .................................12, 57, 59

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

Houston, Texas ............................................. 46

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

Shreveport, Louisiana. .................................. 63

Phone: +1 318-635-5351, Web site: www.destearns.com

Dive Corr, Inc., Long Beach, California. ............................................... 51

Phone: +1 562-439-8287, Email: [email protected]

Elcometer, Rochester Hills, Michigan ..........................................IFC, 7, 40

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

Albion, Rhode Island ...................... 51

Phone: +1 617-484-9085, Web site: www.edi-cp.com

Gardena, California ..................... 19

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

GMA Garnet Group, Houston, Texas .....................................................3

Phone: +1 832-243-9300, Web site: www.garnetsales.com

GMC Electrical, Inc., Ontario, California ............................................. 68

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

HoldT Houston, Texas ........................................ 20

Phone: 1 800-319-8802, Web site: www.holdtight.com

Jotun Paints, Belle Chasse, Louisiana .................................................. 41

Phone: 1 800-229-3538, Web site: www.jotun.com

Loresco International, Hattiesburg, Mississippi ....................................5

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

MATCOR, Inc., Chalfont, Pennsylvania ................................................ 11

Phone: 1 800-769-5669, Web site: www.matcor.com

MESA, Tulsa, Oklahoma ...................................................................... Tip-In

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

MONTI Tools, Inc., Houston, Texas .................................................... 25

Phone: +1 832-623-7970, Web site: www.monti-tools.com

MSES Corrosion Products Division, Clarksburg, West Virginia ......9

Phone: 1 877-624-9700, Web site: www.msesproducts.com

NOV Tuboscope, Houston, Texas ........................................................ 58

Phone: 1 888-262-8645, Web site: www.tuboscope.com

Polyguard Products, Ennis, Texas .................................................... IBC

Phone: +1 214-515-5000, Web site: www.polyguardproducts.com

Sauereisen, Pittsburgh, Pennsylvania .................................................... 21

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

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

Cleveland, Ohio .................................... 55

Phone: 1 800-524-5979, Web site: www.sherwin-williams.com/protective

Tinker & Rasor, San Bernardino, California .............................47, 61, BC

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

NACE International

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

Concrete Coatings Conference ................................................................. 56

CORROSION 2014 ................................................................................... 81

Knowledge Now Webinars ........................................................................ 60

Marine Coating Technology ....................................................................... 62

NACE Mentor Program .............................................................................. 29

NACE Standard SP0210 ........................................................................... 94

New NACE International Training Center—Dubai ...................................... 79

Pipeline Integrity Management Seminar ..................................................... 50

The Marine Coatings User’s Handbook ..................................................... 63

Why Become a NACE Instructor ............................................................... 73






http://www.clemcoindustries.com/pipetools





http://www.destearns.com




http://www.farwestcorrosion.com


http://www.gmcelectrical.net



http://www.loresco.com


http://www.mesaproducts.com




http://www.polyguardproducts.com


http://www.sherwin-williams.com/protective


http://www.nace.org

http://www.corrosionjobs.com


CORROSION BASICSUnderstanding the basic principles

and causes of corrosion

Most pipeline cathodic

protection (CP) appli-

cations involve either

galvanic anode or

impressed current

systems installed in earth for protection

of external surfaces. Of the galvanic anode

installations, most use magnesium as the

anode material. Rectifiers are the most

common source of direct current power

for impressed current systems.

For pipelines installed in the ocean

bed (as for long harbor crossings and lines

to offshore drilling operations), consider-

able use has been made of galvanic anode

bracelets. These are essentially a ring of

specially cast anodes encircling the pipe

and attached directly to it. This permits

having the anodes already attached to the

pipe as it is laid. By doing so, the pipeline

will be cathodically protected as soon as

it becomes submerged. Used in conjunc-

tion with a good coating, sufficient anode

material may be provided for long useful

life. Zinc has been used most frequently

for this type of installation.

Where surface soil conditions for

pipelines on land are not suitable for

groundbeds installed near the surface,

deep groundbeds (vertical) may be

installed if underlying earth resistivity is

more favorable. With impressed current

systems, such groundbeds usually are

installed in a single hole. Particular care

must be exercised during installation to

avoid premature failures of anodes or

anode leads that may not be repairable

and may necessitate the installation of a

complete new groundbed.

of current may be needed. In this case, an

impressed current system may be used

with platinum-coated anodes penetrating

the pipe walls at intervals.

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. 513-514.

Other instances where deep ground-

beds are necessary include sites where

right-of-way for surface groundbeds

cannot be obtained. For example, a deep

bed can be installed on a pipeline right-

of-way. They also are used in congested

distribution systems where remote

groundbeds are needed, but where avail-

able sites for surface groundbeds are not

sufficiently remote from the pipes to be

protected or from structures owned by

others.

In some congested areas, anodes

(galvanic or impressed current) are

distributed along the length of pipe to

be protected. This permits placing the

anodes close to the pipe, with each anode

protecting a short length. The effect on

other structures also may be controlled

more readily. This type of installation may

be more expensive than remote ground-

beds placed at much longer intervals but

may, nevertheless, be the best solution in

some instances.

Where pipelines are banked, giving

rise to severe shielding, a continuous

ribbon anode may be used within the bank

and parallel to the pipelines to provide

protective current within the bank. Such

material is available in zinc or magnesium.

For impressed current systems, platinum-

coated wire or rod anodes are available if

required.

The interiors of large pipelines carry-

ing corrosive liquids (such as seawater

or industrial waste) may be lined with a

suitable coating and protected with strip-

type galvanic anode material. If the pipe

interior is bare, relatively large amounts

Special Cathodic Protection Requirements for Specifc Pipeline Applications

See the Corrosion Innovation

Award Nominations for 2014

Nominations for MP’s third annual

Corrosion Innovation of the Year

Awards are now available for

viewing. A panel of leading

corrosion experts will chose this

year’s award-winning corrosion-

control innovations, which will be

announced at CORROSION 2014

in San Antonio, Texas. To read the

nominations, visit www.nace.org/

MPInnovationAwards.

Innovation: In-place lining of small

diameter pressurized pipes.


http://www.nace.org/MPInnovationAwards

http://www.nace.org/MPInnovationAwards


http://www.PolyguardProducts.com/pad

http://www.PolyguardProducts.com

http://www.PolyguardProducts.com/pad

http://www.PolyguardProducts.com


http://www.tinker-rasor.com/APW


http://www.tinker-rasor.com/APW


233799-jan 2014

Documents

pipeline corrosion

corrosion engin

infuenced corrosion

nace international roundtable

editorial themes of

stress corrosion cracking

cover22 nace international

pm1nace international