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MP_OLPage_Jan_14.indd 1 12/19/13 9:46 AM
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
January 2014 MP.indd 1 12/18/13 10:37 AM
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
7432
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3NACE 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
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
(ISSN 0094-1492; USPS No. 333-860). Mailing address and Editorial
Offces: 1440 South Creek Drive, Houston, TX 77084-4906; phone: +1
281-228-6200. Internet address: www.nace.org. Preferred periodicals
nonproft postage paid at Houston, TX and additional mailing offces.
Canada Post: Publications Mail Agreement #40612608. Canada Returns
to be sent to Pitney Bowes, PO Box 25542, London, ON N6C 6B2. Copyright
2014 by NACE International. Reproduction of the contents, either as a whole
or in part, is forbidden unless permission has been obtained from the
publisher. Articles and editorials herein represent the opinions of the authors
and not necessarily those of NACE. Advertising is included as an educational
service, and products and/or services mentioned carry no implied or real
endorsement or recommendation from NACE. NACE reserves the right to
prohibit any advertisement that is not consistent with the objectives of
NACE.
POSTMASTER: Forwarding charges guaranteed. Send address changes to
NACE FirstService, 1440 South Creek Drive, Houston, TX 77084-4906.
SUBSCRIPTION RATES: To members as part of annual dues $12; U.S.
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bers subject to change. Subscriptions must be prepaid. Claims made within
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228-6223 worldwide or e-mail: [email protected]). Cancellation must
be made in writing. Refunds will be prorated less a $20 processing fee.
Information on becoming a NACE member can be obtained from the NACE
Membership Services Department at the above phone number and e-mail
address. PRINTED IN THE U.S.A.
8
4 JANUARY 2014 MATERIALS PERFORMANCE NACE INTERNATIONAL: VOL. 53, NO. 1
83
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5NACE INTERNATIONAL: VOL. 53, NO. 1 MATERIALS PERFORMANCE JANUARY 2014
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6 JANUARY 2014 MATERIALS PERFORMANCE NACE INTERNATIONAL: VOL. 53, NO. 1
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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7NACE INTERNATIONAL: VOL. 53, NO. 1 MATERIALS PERFORMANCE JANUARY 2014
January 2014 MP.indd 7 12/18/13 10:38 AM
8 JANUARY 2014 MATERIALS PERFORMANCE NACE INTERNATIONAL: VOL. 53, NO. 1
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].
January 2014 MP.indd 8 12/18/13 10:38 AM
9NACE INTERNATIONAL: VOL. 53, NO. 1 MATERIALS PERFORMANCE JANUARY 2014
January 2014 MP.indd 9 12/18/13 10:38 AM
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
+1 281-228-6446
ASSISTANT SALES MANAGER Teresa Wright
+1 281-228-6472
ACCOUNT EXECUTIVES Brian Daley
+1 281-228-6455
Pam Golias
+1 281-228-6456
Jody Lovsness
+1 281-228-6257
Leslie Whiteman
+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–
+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
10 JANUARY 2014 MATERIALS PERFORMANCE NACE INTERNATIONAL: VOL. 53, NO. 110
January 2014 MP.indd 10 12/18/13 10:38 AM
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
11NACE INTERNATIONAL: VOL. 53, NO. 1 MATERIALS PERFORMANCE JANUARY 2014
Continued on page 12
January 2014 MP.indd 11 12/18/13 10:38 AM
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.
12 JANUARY 2014 MATERIALS PERFORMANCE NACE INTERNATIONAL: VOL. 53, NO. 1
Continued from page 11
January 2014 MP.indd 12 12/18/13 10:38 AM
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.
13NACE INTERNATIONAL: VOL. 53, NO. 1 MATERIALS PERFORMANCE JANUARY 2014
January 2014 MP.indd 13 12/18/13 10:38 AM
14 JANUARY 2014 MATERIALS PERFORMANCE NACE INTERNATIONAL: VOL. 53, NO. 1
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
January 2014 MP.indd 14 12/18/13 10:39 AM
Highlights experiences, opinions, and advice from NACE International’s Fellows
15NACE INTERNATIONAL: VOL. 53, NO. 1 MATERIALS PERFORMANCE JANUARY 2014
Pipeline safety has been
enhanced over the years by
NACE initiatives and
activities.
Highlights experiences, opinions, and advice from NACE International’s Fellows
January 2014 MP.indd 15 12/18/13 10:39 AM
THE ESSENTIAL FELLOW
16 JANUARY 2014 MATERIALS PERFORMANCE NACE INTERNATIONAL: VOL. 53, NO. 1
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
January 2014 MP.indd 16 12/18/13 10:39 AM
Highlights experiences, opinions, and advice from NACE International’s Fellows
17NACE INTERNATIONAL: VOL. 53, NO. 1 MATERIALS PERFORMANCE JANUARY 2014
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.
January 2014 MP.indd 17 12/18/13 10:39 AM
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
18 JANUARY 2014 MATERIALS PERFORMANCE NACE INTERNATIONAL: VOL. 53, NO. 1
January 2014 MP.indd 18 12/18/13 10:39 AM
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.
Continued on page 20
19NACE INTERNATIONAL: VOL. 53, NO. 1 MATERIALS PERFORMANCE JANUARY 2014
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.
Continued from page 19
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MATERIAL MATTERS
January 2014 MP.indd 20 12/18/13 10:39 AM
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
Continued on page 22
21NACE INTERNATIONAL: VOL. 53, NO. 1 MATERIALS PERFORMANCE JANUARY 2014
Information on corrosion control and prevention
January 2014 MP.indd 21 12/18/13 10:39 AM
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.
Continued from page 21
22 JANUARY 2014 MATERIALS PERFORMANCE NACE INTERNATIONAL: VOL. 53, NO. 1
MATERIAL MATTERS
January 2014 MP.indd 22 12/18/13 10:39 AM
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
23NACE INTERNATIONAL: VOL. 53, NO. 1 MATERIALS PERFORMANCE JANUARY 2014
Information on corrosion control and prevention
January 2014 MP.indd 23 12/18/13 12:18 PM
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.
24 JANUARY 2014 MATERIALS PERFORMANCE NACE INTERNATIONAL: VOL. 53, NO. 1
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
January 2014 MP.indd 24 12/18/13 12:20 PM
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.
Continued on page 26
25NACE INTERNATIONAL: VOL. 53, NO. 1 MATERIALS PERFORMANCE JANUARY 2014
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.
Information on corrosion control and prevention
January 2014 MP.indd 25 12/18/13 12:20 PM
Continued from page 25
26 JANUARY 2014 MATERIALS PERFORMANCE NACE INTERNATIONAL: VOL. 53, NO. 1
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
January 2014 MP.indd 26 12/18/13 12:18 PM
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.
27NACE INTERNATIONAL: VOL. 53, NO. 1 MATERIALS PERFORMANCE JANUARY 2014
January 2014 MP.indd 27 12/18/13 12:20 PM
28 JANUARY 2014 MATERIALS PERFORMANCE NACE INTERNATIONAL: VOL. 53, NO. 1
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
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.
January 2014 MP.indd 28 12/18/13 12:18 PM
Find a mentor. Be a mentor.
www.nace.org/mentors
January 2014 MP.indd 29 12/18/13 12:18 PM
30 JANUARY 2014 MATERIALS PERFORMANCE NACE INTERNATIONAL: VOL. 53, NO. 1
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.
January 2014 MP.indd 30 12/18/13 12:20 PM
31NACE INTERNATIONAL: VOL. 53, NO. 1 MATERIALS PERFORMANCE JANUARY 2014
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)
EHL-LED-7W-100-1523 explosion-proof
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-
cations. The two-component coating
can be used in applications that specify
either Grade A or Grade B finishes,
including Army or Navy equipment
requiring weather resistance, or for
interior surfaces. It offers superior
corrosion resistance and satisfies the
Army Research Lab’s stringent require-
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:
January 2014 MP.indd 31 12/18/13 12:20 PM
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
32 JANUARY 2014 MATERIALS PERFORMANCE NACE INTERNATIONAL: VOL. 53, NO. 1
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.
33NACE INTERNATIONAL: VOL. 53, NO. 1 MATERIALS PERFORMANCE JANUARY 2014
A Closer Look at Microbiologically Influenced Corrosion
Jan14_Feature.indd 33 12/18/13 3:54 PM
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.
34 JANUARY 2014 MATERIALS PERFORMANCE NACE INTERNATIONAL: VOL. 53, NO. 1
Jan14_Feature.indd 34 12/18/13 3:30 PM
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.
A Closer Look at Microbiologically Influenced Corrosion
35NACE INTERNATIONAL: VOL. 53, NO. 1 MATERIALS PERFORMANCE JANUARY 2014
Jan14_Feature.indd 35 12/18/13 3:30 PM
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
36 JANUARY 2014 MATERIALS PERFORMANCE NACE INTERNATIONAL: VOL. 53, NO. 1
Jan14_Feature.indd 36 12/18/13 3:30 PM
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-
A Closer Look at Microbiologically Influenced Corrosion
37NACE INTERNATIONAL: VOL. 53, NO. 1 MATERIALS PERFORMANCE JANUARY 2014
Jan14_Feature.indd 37 12/18/13 3:31 PM
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
38 JANUARY 2014 MATERIALS PERFORMANCE NACE INTERNATIONAL: VOL. 53, NO. 1
Jan14_Feature.indd 38 12/18/13 3:32 PM
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
A Closer Look at Microbiologically Influenced Corrosion
39NACE INTERNATIONAL: VOL. 53, NO. 1 MATERIALS PERFORMANCE JANUARY 2014
Jan14_Feature.indd 39 12/18/13 3:32 PM
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).
40 JANUARY 2014 MATERIALS PERFORMANCE NACE INTERNATIONAL: VOL. 53, NO. 1
Jan14_Feature.indd 40 12/18/13 3:32 PM
41NACE INTERNATIONAL: VOL. 53, NO. 1 MATERIALS PERFORMANCE JANUARY 2014
January 2014 MP.indd 41 12/18/13 12:29 PM
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
42 JANUARY 2014 MATERIALS PERFORMANCE NACE INTERNATIONAL: VOL. 53, NO. 1
January 2014 MP.indd 42 12/18/13 12:28 PM
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
43NACE INTERNATIONAL: VOL. 53, NO. 1 MATERIALS PERFORMANCE JANUARY 2014
January 2014 MP.indd 43 12/18/13 12:29 PM
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-
44 JANUARY 2014 MATERIALS PERFORMANCE NACE INTERNATIONAL: VOL. 53, NO. 1
January 2014 MP.indd 44 12/18/13 12:29 PM
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.
45NACE INTERNATIONAL: VOL. 53, NO. 1 MATERIALS PERFORMANCE JANUARY 2014
Lessons Learned: Monitoring Cathodic Protection Current from Inside the Pipe
January 2014 MP.indd 45 12/18/13 12:29 PM
BLOG
Continued from The MP Blog, p. 13.
The following items relate to cathodic
protection.
Please be advised that the items are
not peer-reviewed, and opinions and
suggestions are entirely those of the in-
quirers and respondents. NACE Interna-
tional does not guarantee the accuracy
of the technical solutions discussed.
MP welcomes additional responses to
these items. They may be edited for
clarity.
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
46 JANUARY 2014 MATERIALS PERFORMANCE NACE INTERNATIONAL: VOL. 53, NO. 1
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Continued on page 48
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.
47NACE INTERNATIONAL: VOL. 53, NO. 1 MATERIALS PERFORMANCE JANUARY 2014
January 2014 MP.indd 47 12/18/13 12:41 PM
Continued from page 47
Continued on page 51
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.
48 JANUARY 2014 MATERIALS PERFORMANCE NACE INTERNATIONAL: VOL. 53, NO. 1
BLOG
January 2014 MP.indd 48 12/18/13 12:29 PM
49NACE INTERNATIONAL: VOL. 53, NO. 1 MATERIALS PERFORMANCE JANUARY 2014
January 2014 MP.indd 49 12/18/13 12:29 PM
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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.
51NACE INTERNATIONAL: VOL. 53, NO. 1 MATERIALS PERFORMANCE JANUARY 2014
Continued from page 48
BLOG
January 2014 MP.indd 51 12/18/13 12:29 PM
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
52 JANUARY 2014 MATERIALS PERFORMANCE NACE INTERNATIONAL: VOL. 53, NO. 1
January 2014 MP.indd 52 12/18/13 12:29 PM
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
53NACE INTERNATIONAL: VOL. 53, NO. 1 MATERIALS PERFORMANCE JANUARY 2014
January 2014 MP.indd 53 12/18/13 12:29 PM
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.
54 JANUARY 2014 MATERIALS PERFORMANCE NACE INTERNATIONAL: VOL. 53, NO. 1
COATINGS & LININGS
January 2014 MP.indd 54 12/18/13 12:29 PM
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.
55NACE INTERNATIONAL: VOL. 53, NO. 1 MATERIALS PERFORMANCE JANUARY 2014
Advancements in the Abrasion Resistance of Internal Plastic Coatings
January 2014 MP.indd 55 12/18/13 12:29 PM
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January 2014 MP.indd 56 12/18/13 12:29 PM
Continued from The MP Blog, p. 13.
The following items relate to coatings
& linings.
Please be advised that the items are
not peer-reviewed, and opinions and
suggestions are entirely those of the in-
quirers and respondents. NACE Interna-
tional does not guarantee the accuracy
of the technical solutions discussed.
MP welcomes additional responses to
these items. They may be edited for
clarity.
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
BLOG
Continued on page 58
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
57NACE INTERNATIONAL: VOL. 53, NO. 1 MATERIALS PERFORMANCE JANUARY 2014
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Continued from page 57
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.
58 JANUARY 2014 MATERIALS PERFORMANCE NACE INTERNATIONAL: VOL. 53, NO. 1
BLOG
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Continued on page 61
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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January 2014 MP.indd 59 12/18/13 12:30 PM
60 JANUARY 2014 MATERIALS PERFORMANCE NACE INTERNATIONAL: VOL. 53, NO. 1
To learn more or to register, visit www.nace.org/knowledgenow
Upcoming Webinars
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Tuesday, February 6, 2014
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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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Using Procedural Conformity as a Better Way to Administer a Contract
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11:00 a.m. Central
This webinar focuses on the idea that contracting practices can be improved if responsibility for inspec-
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
well-written contract documents for this to occur and that those documents are the basis for Procedural
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January 2014 MP.indd 60 12/18/13 12:30 PM
Continued from page 59
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.
Continued on page 63
61NACE INTERNATIONAL: VOL. 53, NO. 1 MATERIALS PERFORMANCE JANUARY 2014
BLOG
January 2014 MP.indd 61 12/18/13 12:41 PM
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January 2014 MP.indd 62 12/18/13 12:30 PM
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.
63NACE INTERNATIONAL: VOL. 53, NO. 1 MATERIALS PERFORMANCE JANUARY 2014
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BLOG
January 2014 MP.indd 63 12/18/13 12:30 PM
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
January 2014 MP.indd 64 12/18/13 12:30 PM
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
January 2014 MP.indd 65 12/18/13 12:30 PM
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
• Baseline corrosion rates at Vsl = 1.5
m/s; Vsg = 6 m/s for 3- and 45-degree
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.
FIGURE 3 Baseline corrosion rates, 20% WC, 25cP BOL, Vsl = 1.5 m/s, Vsg = 3.0 m/s, P = 600 kPa,
T = 50 °C.
and 45 degrees); and inhibitor
concentrations
• Prescreening with Inhibitor Y at
varying superficial gas velocities
(0.7, 3, and 6 m/s); inclinations (0, 3,
and 45 degrees); and inhibitor
concentrations
• Prescreening with Inhibitor K at
varying superficial gas velocities
(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
• Baseline corrosion rates at Vsl = 1.5
m/s; Vsg = 3 m/s for 3- and 45-degree
inclinations
• Baseline corrosion rates at Vsl = 1.5
m/s; Vsg = 6 m/s for 3- and 45-degree
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
66 JANUARY 2014 MATERIALS PERFORMANCE NACE INTERNATIONAL: VOL. 53, NO. 1
CHEMICAL TREATMENT
January 2014 MP.indd 66 12/18/13 12:30 PM
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-
FIGURE 4 Baseline corrosion rates, 20% WC, 25cP BOL, Vsl = 1.5 m/s, Vsg = 6.0 m/s, P = 600 kPa,
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.
67NACE INTERNATIONAL: VOL. 53, NO. 1 MATERIALS PERFORMANCE JANUARY 2014
Corrosion Inhibitors in Deep Offshore Catenary Risers
January 2014 MP.indd 67 12/18/13 12:30 PM
• 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.
68 JANUARY 2014 MATERIALS PERFORMANCE NACE INTERNATIONAL: VOL. 53, NO. 1
CHEMICAL TREATMENT
January 2014 MP.indd 68 12/18/13 3:06 PM
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
MATERIALS SELECTION & DESIGN
69NACE INTERNATIONAL: VOL. 53, NO. 1 MATERIALS PERFORMANCE JANUARY 2014
January 2014 MP.indd 69 12/18/13 2:22 PM
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.
70 JANUARY 2014 MATERIALS PERFORMANCE NACE INTERNATIONAL: VOL. 53, NO. 1
MATERIALS SELECTION & DESIGN
January 2014 MP.indd 70 12/18/13 2:22 PM
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).
71NACE INTERNATIONAL: VOL. 53, NO. 1 MATERIALS PERFORMANCE JANUARY 2014
New Approach to H2S Limits for High-Pressure, High-Temperature Petroleum
Production Wells
January 2014 MP.indd 71 12/18/13 3:08 PM
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.
72 JANUARY 2014 MATERIALS PERFORMANCE NACE INTERNATIONAL: VOL. 53, NO. 1
MATERIALS SELECTION & DESIGN
January 2014 MP.indd 72 12/18/13 2:22 PM
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
January 2014 MP.indd 73 12/18/13 3:09 PM
MATERIALS SELECTION & DESIGN
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
74 JANUARY 2014 MATERIALS PERFORMANCE NACE INTERNATIONAL: VOL. 53, NO. 1
January 2014 MP.indd 74 12/18/13 2:23 PM
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
75NACE INTERNATIONAL: VOL. 53, NO. 1 MATERIALS PERFORMANCE JANUARY 2014
January 2014 MP.indd 75 12/18/13 2:23 PM
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
76 JANUARY 2014 MATERIALS PERFORMANCE NACE INTERNATIONAL: VOL. 53, NO. 1
MATERIALS SELECTION & DESIGN
January 2014 MP.indd 76 12/18/13 2:23 PM
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).
77NACE INTERNATIONAL: VOL. 53, NO. 1 MATERIALS PERFORMANCE JANUARY 2014
Metallurgical and Corrosion Assessment of Submerged Tanker S.S. Montebello
January 2014 MP.indd 77 12/18/13 2:23 PM
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.
78 JANUARY 2014 MATERIALS PERFORMANCE NACE INTERNATIONAL: VOL. 53, NO. 1
MATERIALS SELECTION & DESIGN
January 2014 MP.indd 78 12/18/13 2:23 PM
79NACE INTERNATIONAL: VOL. 53, NO. 1 MATERIALS PERFORMANCE JANUARY 2014
NACE International Training Center - Dubai
Coming Spring 2014
13_1025
Announcing the Opening of the NEW
To learn more, visit
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
January 2014 MP.indd 79 12/18/13 2:23 PM
80 JANUARY 2014 MATERIALS PERFORMANCE NACE INTERNATIONAL: VOL. 53, NO. 1
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]
January 2014 MP.indd 80 12/18/13 2:23 PM
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!
January 2014 MP.indd 81 12/18/13 2:23 PM
Your Association
in ActionNACE NEWS
82 JANUARY 2014 MATERIALS PERFORMANCE NACE INTERNATIONAL: VOL. 53, NO. 1
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
83NACE INTERNATIONAL: VOL. 53, NO. 1 MATERIALS PERFORMANCE JANUARY 2014
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
Jan14_NACEnews.indd 83 12/18/13 3:38 PM
84 JANUARY 2014 MATERIALS PERFORMANCE NACE INTERNATIONAL: VOL. 53, NO. 1
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
Jan14_NACEnews.indd 84 12/18/13 3:38 PM
Your Association in Action
85NACE INTERNATIONAL: VOL. 53, NO. 1 MATERIALS PERFORMANCE JANUARY 2014
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
Jan14_NACEnews.indd 85 12/18/13 3:38 PM
86 JANUARY 2014 MATERIALS PERFORMANCE NACE INTERNATIONAL: VOL. 53, NO. 1
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
• 105 technical book chapters
• 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
• 306 technical book chapters
• 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.
Jan14_NACEnews.indd 86 12/18/13 3:39 PM
Your Association in Action
87NACE INTERNATIONAL: VOL. 53, NO. 1 MATERIALS PERFORMANCE JANUARY 2014
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
Jan14_NACEnews.indd 87 12/18/13 3:39 PM
88 JANUARY 2014 MATERIALS PERFORMANCE NACE INTERNATIONAL: VOL. 53, NO. 1
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.
Jan14_NACEnews.indd 88 12/18/13 3:39 PM
Meetings & Events
89NACE INTERNATIONAL: VOL. 53, NO. 1 MATERIALS PERFORMANCE JANUARY 2014
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
Jan14_NACEnews.indd 89 12/18/13 3:39 PM
NACE Course Schedule
90 JANUARY 2014 MATERIALS PERFORMANCE NACE INTERNATIONAL: VOL. 53, NO. 1
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
Houston, TX 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
Houston, TX February 16-21, 2014
Houston, TX February 23-28, 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
Houston, TX March 9-14, 2014
Aberdeen, U.K. March 10-15, 2014
Houston, TX March 16-21, 2014
Newcastle-upon-Tyne, U.K. March 17-22, 2014
Melbourne, VIC, Australia March 17-22, 2014
Quito, Ecuador March 17-22, 2014
Houston, TX March 23-28, 2014
Newcastle-upon-Tyne, U.K. March 24-29, 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
Houston, TX April 6-11, 2014
Houston, TX April 7-12, 2014
Sydney, NSW, Australia April 7-12, 2014
Houston, TX April 12-17, 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
Houston, TX February 9-11, 2014
Ulsan, Korea March 24-26, 2014
Houston, TX April 2-4, 2014
CIP Level 2
Mumbai, India February 3-8, 2014
Houston, TX February 3-8, 2014
Perth, WA, Australia February 10-15, 2014
Montreal, QC, Canada February 16-21, 2014
Mobile, AL February 16-21, 2014
Houston, TX 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
Baton Rouge, LA March 9-14, 2014
Brisbane, QLD, Australia March 10-15, 2014
Newcastle-upon-Tyne, U.K. March 17-22, 2014
Kansas City, MO March 23-28, 2014
Houston, TX March 23-28, 2014
Newcastle-upon-Tyne, U.K. March 24-29, 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
Houston, TX April 21-26, 2014
Dammam, Saudi Arabia April 26-May 1, 2014
CIP Exam Course 2
Houston, TX February 12-14, 2014
Ulsan, Korea March 27-29, 2014
Houston, TX April 6-8, 2014
CIP One-Day Bridge
Houston, TX March 8, 2014
Virginia Beach, VA April 5, 2014
CIP Peer Review
Mobile, AL February 21-23, 2014
Montreal, QC, Canada February 21-23, 2014
Houston, TX February 21-23, 2014
Kuala Lumpur, Malaysia March 2-4, 2014
Baton Rouge, LA March 14-16, 2014
Kansas City, MO March 28-30, 2014
Houston, TX March 28-30, 2014
Jan14_NACEnews.indd 90 12/18/13 3:39 PM
NACE Course Schedule
91NACE INTERNATIONAL: VOL. 53, NO. 1 MATERIALS PERFORMANCE JANUARY 2014
Newcastle-upon-Tyne, U.K. March 29-31, 2014
Virginia Beach, VA April 11-13, 2014
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
Houston, TX April 26-28, 2014
Coatings in Conjunction with Cathodic Protection
Houston, TX February 23-28, 2014
Houston, TX April 21-26, 2014
Corrosion Control in the Refning Industry
Fahaheel, Kuwait February 2-6, 2014
Cairo, Egypt February 15-19, 2014
San Antonio, TX March 3-7, 2014
Houston, TX April 28-May 2, 2014
CP Interference
Bogota, Colombia March 31-April 5, 2014
CP 1–Cathodic Protection Tester
Mumbai, India February 10-15, 2014
Houston, TX March 2-7, 2014
Houston, TX March 16-21, 2014
Dammam, Saudi Arabia March 29-April 3, 2014
Houston, TX April 12-17, 2014
Tulsa, OK April 27-May 2, 2014
CP 2–Cathodic Protection Technician
Houston, TX February 10-15, 2014
Houston, TX February 16-21, 2014
Chicago, IL February 16-21, 2014
Mumbai, India February 17-22, 2014
Houston, TX March 17-22, 2014
Dammam, Saudi Arabia April 5-10, 2014
Bogota, Colombia April 21-26, 2014
Houston, TX April 21-26, 2014
CP 2–Cathodic Protection Technician—Maritime
Houston, TX April 27-May 2, 2014
CP 3–Cathodic Protection Technologist
Cairo, Egypt February 1-6, 2014
Houston, TX March 30-April 4, 2014
Fahaheel, Kuwait April 5-10, 2014
CP 4–Cathodic Protection Specialist
Houston, TX February 23-28, 2014
Fahaheel, Kuwait April 12-17, 2014
Houston, TX April 27-May 2, 2014
Designing for Corrosion Control
Edmonton, AB, Canada February 3-7, 2014
Dammam, Saudi Arabia February 15-19, 2014
Houston, TX April 21-25, 2014
In-Line Inspection
Houston, TX February 24-28, 2014
Internal Corrosion for Pipelines—Basic
Dammam, Saudi Arabia February 22-26, 2014
Cairo, Egypt March 1-5, 2014
Houston, TX March 17-21, 2014
Internal Corrosion for Pipelines—Advanced
Dammam, Saudi Arabia March 29-April 3, 2014
Cairo, Egypt March 8-12, 2014
Houston, TX March 24-28, 2014
Marine Coating Technology
Houston, TX March 10-13, 2014
San Antonio, TX March 13-16, 2014
Nuclear Power Plant Training for Coating Inspectors
San Antonio, TX March 13-17, 2014
Offshore Corrosion Assessment Training (O-CAT)
Houston, TX March 24-28, 2014
PCS 1 Basic Principles
Houston, TX March 30-April 1, 2014
PCS 2 Advanced
Houston, TX April 2-4, 2014
PCS 3 Management
Houston, TX March 10-14, 2014
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)
Houston, TX February 17-21, 2014
Houston, TX April 13-17, 2014
Pipeline Corrosion Integrity Management (PCIM)
Fahaheel, Kuwait February 2-6, 2014
Houston, TX April 6-10, 2014
Shipboard Corrosion Assessment Training (S-CAT)
Houston, TX February 3-7, 2014
San Antonio, TX March 3-7, 2014
Virginia Beach, VA April 13-17, 2014
For the most up-to-date course
schedules and course information,
visit www.nace.org/eduschedule.
Jan14_NACEnews.indd 91 12/18/13 3:39 PM
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
92 JANUARY 2014 MATERIALS PERFORMANCE NACE INTERNATIONAL: VOL. 53, NO. 1
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
E-mail: [email protected]
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
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
93NACE INTERNATIONAL: VOL. 53, NO. 1 MATERIALS PERFORMANCE JANUARY 2014
We have a space reserved for
your business card.
Call the Advertising Department
at +1 281-228-6219.
Phone/fax: 210/923-5999
E-mail: [email protected]
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
CEDs_FINAL FILE_USETHIS NEW.indd 93 12/18/13 4:21 PM
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
94 JANUARY 2014 MATERIALS PERFORMANCE NACE INTERNATIONAL: VOL. 53, NO. 1
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
• Confdential OFC staff recruitment service
• Confdential OFC job search
CEDs_FINAL FILE_USETHIS NEW.indd 94 12/18/13 4:21 PM
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
95NACE INTERNATIONAL: VOL. 53, NO. 1 MATERIALS PERFORMANCE JANUARY 2014
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96 JANUARY 2014 MATERIALS PERFORMANCE NACE INTERNATIONAL: VOL. 53, NO. 1
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.
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