NIST Special Publication 1044 

Advanced Coatings R&D for Pipelines and Related Facilities 

The proceedings of a workshop held 

June 9-10, 2005 at the 

National Institute of Standards and Technology,

Gaithersburg, MD 20899 USA 

Edited by: 

Richard E. Ricker

Sponsored by: 

The Office of Pipeline Safety

U.S. Department of Transportation 

Pipeline and Hazardous Materials Administration 

With support from: 

American Gas Association 

ASTM International 

CANMET, Minerals and Metals Sector, Natural Resources Canada 

Gas Technology Institute 

Minerals Management Service, U.S. Department of the Interior 

NACE International 

National Energy Board, Canada 

National Institute of Standards and Technology 

Pipeline Research Council International 

September 7, 2005 

U.S. Department of Commerce 

Carlos M. Gutierrez, Secretary 

Technology Administration 

Phillip J. Bond, Under Secretary for Technology 

National Institute of Standards and Technology 

William Jeffrey, Director 
Preface 

The first suggestion that a workshop be held at NIST on pipeline coatings was made 

at the February 2005 meeting of the Pipeline Safety Coordination Council. Since NIST is 

a popular location for meetings, reservations were made immediately for the only dates 

available for the summer of 2005. The normal delays in obtaining approvals prevented 

final approvals until mid April. A Steering and Advisory Committee, which was 

assembled immediately; deliberated and decided to hold this meeting on the originally 

scheduled dates of June 9-10, 2005. This was an ambitious goal, as it left the committee 

only a little over two months to organize the meeting. The contributions of the steering 

committee to the organization of this meeting cannot be over emphasized. The success of 

this meeting is largely due to the contributions of this committee. 

Preparing a successful meeting with little time requires three things. First, a steering 

committee is necessary to help organize the sessions, identify speakers, and promote 

attendance. Second, a good location and excellent support staff are vital. Knowledgeable 

attendees, insightful discussions, and considerate debate complete the third requirement. 

Fortunately, this meeting had all three. This meeting would not have happened without 

the efforts of the steering committee and I express my sincere gratitude to the members of 

this committee for their contributions. In addition, I thank Kathy Kilmer of the NIST 

Conference and Facilities Division who made dealing with the planning details a 

pleasure. I also thank all who attended for their contributions and their willingness to 

openly present and discuss their issues and opinions. Finally, I thank the Office of 

Pipeline Safety (OPS) for providing support for this meeting and to J. Merritt and R. 

Smith of OPS for serving on the Steering Committee and for their innumerable 

contributions to the success of this meeting. 

I dedicate this volume to my father, who became terminally ill shortly before this 

meeting. Harry H. Ricker, Jr. (May 13, 1917-Aug. 4, 2005) was one of the hundreds of 

NASA engineers who helped put man in space. According to the history of NASA 

website (www.hq.nasa.gov/office/pao/History), he was one of the 45 people transferred 

to the manned space program when it was founded in 1958. As Head of the On Board 

Systems Branch in 1959, he sat on NASA’s New Projects Panel, which proposed 

following the manned satellite program with a program to construct a three person 

spacecraft to travel to the moon and identified 1970 as a reasonable target date for a lunar 

landing. He spent most of his career studying reliability and safety; and while he worked 

on very different systems, he would have appreciated the subject and goals of this 

meeting. 

- Richard E. Ricker 

ii 
Table of Contents 

Preface........................................................................................ ii 

Table of Contents............................................................................ iii 

Steering Committee and Scientific Advisory Committee.............................. v 

Executive Summary......................................................................... vii 

Summary of Findings....................................................................... ix 

1. Workshop Objectives..................................................................... 1 

J. Merritt and R. W. Smith, Office of Pipeline Safety 

2. Report on Findings of MMS Offshore Coatings Workshop........................ 16 

D. Olson and B. Mishra, Colorado School of Mines 

3. Standards for Pipeline Coatings......................................................... 29 

S. Papavinasam and R. Winston Revie, CANMET Materials Tech. Lab. 

4. Standards for Evaluating Pipeline Coatings.......................................... 40 

S. Papavinasam and R. Winston Revie, CANMET Materials Tech. Lab. 

5. Current ASTM Standards Activities................................................... 92 

D. Kathrein, Tapecoat 

6. Current NACE Standards Activities................................................... 96 

C. Johnson, NACE Intl. 

7. Current CSA Standards Activities...................................................... 105 

F. Jeglic, National Energy Board, Canada 

8. Owner/Operator Viewpoint on Coatings Issues....................................... 111 

J. Didas, Colonial Pipeline 

9. PRCI Activities ........................................................................ 126 

G. Ruschau, CC Technologies 

10. Coatings Deterioration Studies ......................................................... 134 

J. Been, NOVA Chemicals Corporation 

11. GTI Activities and Preliminary Results from Coatings Test Program ............ 146 

P. Beckendorf, GTI 

12. Coatings Fabrication Issues (Field and Factory)................................... 166 

P. Singh, Bredero Shaw 

13. NDE and Eddy Current Methods for Pipeline Coating Inspection................ 185 

S. Babu and E. Todorov, Edison Welding Institute 

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14. Coatings Failure Modes............................................................... 196 

M. Dabiri, Williams Pipeline 

15. Report of the Working Group on Coating Test Methods and Materials

Development........................................................................... 245 

M. Dabiri (Williams) and B. Chang (Shell), Chairs 

16. Report of Working Group on Coating Mill Application Technologies and Quality

Control Issues........................................................................... 247 

P. Singh (Bredero Shaw) and R. Lewoniuk (NOVA Chem.), Chairs 

17. Report of the Working Group on Coating Identification, Inspection, and Evaluation 

Technologies.............................................................................. 250 

S. Babu (EWI) and R. W. Smith (OPS), Chairs 

18. Report of the Working Group on In-Field Technologies for Joints, Repairs, and 

Rehabilitation.............................................................................. 255 

J. Didas (Colonial Pipeline) and P. Nidd (PGNGroup L.P.), Chairs 

19. Closing Comments and Next Steps................................................... 258 

J. Merritt, Office of Pipeline Safety 

Appendixes 

A. Workshop and Laboratory Tour Agenda ............................................. 261 

B. Workshop Registration List ............................................................ 263 

iv 
Steering and

Scientific Advisory Committee

Rodney Anderson 

Technology Manager 

National Energy Technology Lab. 

U.S. Department of Energy 

rodney.anderson@netl.doe.gov 

Lisa Beal 

Director 

Environment and Construction Policy 

Interstate Natural Gas Association of 

America 

lbeal@ingaa.org 

Paul Beckendorf 

Executive Director 

Gas Operations Laboratory 

Gas Technology Institute 

paul.beckendorf@gastechnology.org 

Jenny Been 

Corrosion Research Engineer 

NOVA Chemicals Corporation 

beenj@novachem.com 

Tom Brooke 

Director 

Standards Development 

ASTM International 

tbrooke@astm.org 

Daniel Driscoll 

Senior Project Manager 

National Energy Technology Lab. 

U.S. Department of Energy 

Daniel.driscol@netl.doe.gov 

Michael Else 

Research Engineer 

Minerals Management Service 

U.S. Department of the Interior 

michael.else@mms.gov 

Steve Gauthier 

Executive Director 

Distribution and Pipeline Technology 

Gas Technology Institute 

steve.gauthier@gastechnology.org 

Franci Jeglic 

Technical Specialist 

National Energy Board (Canada) 

fjeglic@neb-one.gc.ca 

Cliff Johnson 

Public Affairs Director 

NACE International 

cliff.johnson@nace.org 

Don Kathrein 

Chair, ASTM Committee D 01.48 

Durability of Pipeline Coatings and 

Linings 

Tapecoat/Royston Coating Products 

Chase Specialty Coatings 

dkathrein@tapecoat.com 

Dave McColskey 

Materials Reliability Division 

Materials Science and Engineering Lab.

National Inst. of Standards and Tech.

mccolske@boulder.nist.gov

v 
James Merritt 

R&D Program Manager 

Office of Pipeline Safety 

U.S. Department of Transportation 

james.merritt@dot.gov 

Sankara Papavinasam 

Research Scientist 

CANMET Materials Tech. Lab. 

Natural Resources Canada 

spapavin@nrcan.gc.ca 

Winston Revie 

Program Manager 

Infrastructure Reliability Program 

CANMET Materials Tech. Lab. 

Natural Resources Canada 

wrevie@NRCan.gc.ca 

Richard E. Ricker 

Metallurgist 

Metallurgy Division 

Materials Science and Engineering Lab. 

National Inst. of Standards and Tech. 

richard.ricker@nist.gov 

Christina Sames 

Director, Engineering Services 

American Gas Association 

csames@aga.org 

Marina Q. Smith 

Program Manager 

Pipeline Research Council Intl., Inc. 

msmith@prci.org 

Robert W. Smith 

R&D Program Manager 

Office of Pipeline Safety 

U.S. Department of Transportation 

robert.w.smith@dot.gov 

Tom Siewert 

Acting Division Chief 

Materials Reliability Division 

Materials Science and Engineering Lab. 

National Inst. of Standards and Tech. 

siewert@boulder.nist.gov 

vi 
Executive Summary 

In the early 1920s, the National Bureau of Standards initiated a study into the 

underground corrosion of uncoated steel pipes. Very early in this study it became clear 

that coatings would be required for some environments, and a second study of coated 

pipes was initiated immediately. Pipeline coatings have been the subject of research and 

development ever since, and coatings, coating application methods, in-field application 

and repair technologies, and inspection technologies have evolved dramatically since 

these first studies. Today, a wide variety of high-quality coating systems are available for 

new pipeline construction, but the existing infrastructure of pipelines is protected with a 

wide range of coating types with varying ages. Therefore, the R&D needs of the pipeline 

community with respect to coatings ranges from testing protocols for evaluating new 

coatings and standards for quality control, to methods for evaluating of the performance 

and remaining life of coatings in service and remediation. The objective of this 

workshop was to bring the pipeline community together to discuss, identify, and 

prioritize coating R&D needs for improving the safety of pipelines. 

This workshop was held at the National Institute of Standards and Technology’s 

Gaithersburg Maryland campus June 9-10, 2005 with support from the Office of Pipeline 

Safety of the U.S. Department of Transportation. To organize this meeting, a steering 

committee was assembled that was composed of 20 representatives from the pipeline 

industry, industry consortia, pipeline standards developing organizations, government 

agencies, and regulatory agencies from the US and Canada. This committee planned the 

agenda, identified speakers, determined the number and nature of the working groups, 

and helped promote attendance. The workshop had 56 registered attendees representing 

pipeline operators, coatings manufacturers, pipeline fabricators, pipeline industry 

consortia, standards developing organizations, universities, government agencies, and 

regulatory agencies. The workshop consisted of 14 presentations on US and Canadian 

standards, current research, operating experience, and failure mechanisms followed by 

break out into four working groups to identify, discuss, and prioritize research needs. 

The working groups reported their findings. The workshop concluded with a summation 

and tours of laboratories at NIST conducting pipeline relevant research. 

The workshop started with a presentation of the workshop goals, followed by a 

report on the findings of the most recent related workshop on offshore coatings. These 

presentations were then followed by a review and summary of existing coating standards 

and standards under development including their status and utility. Presentations on 

ongoing research into coatings performance and test methods followed along with 

presentations on owner-operator experience and a survey of coating failure modes 

observed in the field. Three issues were frequently raised throughout during these 

presentations. First, coating performance depends on the environment. The optimum 

coating for one environment may perform unsatisfactorily in another environment. 

Therefore, understanding the service environment and the range of conditions that the 

coating will be exposed to; not just in service, but during shipping, storage, and handling, 

is a very important step in optimizing performance. Second, since accelerated laboratory 

vii 
tests are used for coating development and selection, the coatings are actually optimized 

for performance in these tests and not necessarily for performance in service. 

Performance in service is optimized only if these tests accurately represent conditions in 

service or otherwise allow evaluation of the relative rates of the processes that limit 

performance in service for different types of coatings. Therefore, the design, 

development, evaluation, and standardization of better test methods will yield 

improvements in performance. Third, actual in-service failures almost always occur at 

flaws in the coatings. This indicates that the failure rates are related to the coating flaw 

size distribution and the ability of the coating system to resist the propagation of 

corrosion at coating flaws instead of the inherent degradation mechanisms of the asdesigned coating system. As long as failures occur at preventable flaws, improvements 

in coating application technologies and quality control will yield improvements in 

performance. Comparisons were frequently made to welds, where recent developments 

in welding technology, standards, and practices have dramatically reduced failure rates. 

After the presentations, the workshop broke up into four working groups to 

discuss and evaluate R&D needs in different areas: 

(I) Coatings Test Methods and Materials Development, 

(II) Coating Application Technologies and Quality Control (Mill Applied), 

(III) Coating Identification, Inspection, and Evaluation Technologies, and 

(IV) In-Field Technologies for Joint, Repairs, and Rehabilitation. 

These working groups met in the afternoon of the first day to identify and discuss the 

issues and then in the morning of the second day to evaluate and rank the identified 

issues. Each group identified five critical issues: 

(I) Coatings Test Methods and Materials Development, 

1. Short Term Laboratory Tests to Determine Long Term Performance in the Field, 

2. Modeling Tools for Predicting Long Term Field Performance, 

3. Database of Coating Performance in the Field, 

4. Smart Coatings (Sensors for Detecting Coating Failure), and 

5. Mechanism of Cathodic Disbondment. 

(II) Coating Application Technologies and Quality Control (Mill Applied), 

1. Database of Coating Failures and Mechanisms, 

2. Effect of Coating Application Methods on Properties of Steels, 

3. Better Characterization of Service Conditions, 

4. Relationships Between Application Parameters and Performance, and 

5. Universally Accepted Standard(s) for Pipeline Coatings. 

(III) Coating Identification, Inspection, and Evaluation Technologies, 

1. NDE Tools and Models for Inspection and Characterization of Flaws, 

2. Coatings Life-Cycle Database (Exposure Conditions and Performance), 

3. Standardized Tools, Procedures, and Training, 

viii 
4. Better Understanding of Interactions between Welds and Coatings, and 

5. Smart Coatings (coatings designed to aid inspection and evaluation). 

(IV) In-Field Technologies for Joint, Repairs, and Rehabilitation, 

1. Database of Coatings Formulations, Technical Data, Procedures, and Expiration, 

2. Evaluations of Abrasive Blast Materials and Development of Selection Guides, 

3. Standardized Applicator and Inspector Certification and Training, 

4. Selection Guides for Coatings and Repairs, and 

5. NDE Tools for Coatings and Evaluation of Corrosion Under Coatings. 

The reports of the working groups are included in the workshop proceedings, and they 

contain more descriptive information on the nature of these issues, as well as other needs 

that were not ranked as highly. One should refer to these reports for more detailed 

information or description. 

After the working groups reported their findings, the workshop concluded with a 

brief summary of the objectives, purpose, and findings by J. Merritt of the Office of 

Pipeline Safety. Following the conclusion of the workshop, participants toured the NIST 

laboratories conducting research relevant to pipeline safety concerns. More details on the 

findings and conclusions of the working groups can be found in the working group 

reports sections of this proceedings (pages 239-251) or from the Office of Pipeline Safety 

website http://primis.phmsa.dot.gov/rd/mtg_060905.htm, where the sections of this 

proceedings are available for download. 

ix 
Summary of Findings 

The Chairs of the Working Groups reported the findings of each group, and the entire 

workshop discussed them. The workshop made no attempt to develop overall rankings of 

the individual issues or needs identified. Frequently, different groups identified similar 

or related R&D needs. These needs were rarely identical, and sometimes working groups 

combined similar or related topics while others did not. In addition, some working 

groups avoided discussing and ranking topics clearly in the area of other groups. For 

these reasons, and since the purpose of breaking the workshop up into smaller working 

groups was to identify specific needs, developing overall quantitative rankings on the 

basis of numerical analysis of the frequency of appearance or average ranking was 

inappropriate. Therefore, one should refer to the individual working group reports on 

pages 239-251 (also available at http://primis.phmsa.dot.gov/rd/mtg_060905.htm) for 

detailed analysis, description, comparison and ranking of the individual topics identified 

by the working groups. For this summary, the topics were sorted by the nature of the 

proposed R&D and then similar or related projects grouped until a relatively small 

number of categories could be identified for discussion. 

The working groups were instructed to identify the basic nature of the R&D need by 

classifying the type of work to be performed into one of three areas: 

(1) development of knowledge or scientific understanding, 

(2) development of new technology or tools using existing knowledge, and 

(3) development of standards and databases. 

Of course, most R&D projects will contain elements of all three types of work, but the 

working groups were asked to make this assessment based on the primary nature of the 

work performed in the project. The R&D needs identified by the working groups were 

sorted according to the type of work proposed and then grouped to form categories. 

These categories were then ranked based on the average rankings of the topics in the 

categories under each type of work. This created a crosscutting view of the workshop 

findings. 

1. Development of Knowledge or Scientific Understanding 

1.1 Methods for Testing and Prediction of Coating Performance in Service 

The objectives of the R&D topics in this category are to develop standardized and 

universally accepted testing methods that can be used to accurately predict the service life 

of different coatings or coating systems in the pipeline service environment. These test 

methods and subsequent laboratory measurement-based life-prediction models are needed 

to enable other R&D projects to be conducted in a reasonable time with reliable results. 

In addition to the development of better mill and field applied coatings, these test and life 

prediction methods are required to enable better coating selection and life cycle cost 

analysis. It was clear at this workshop that this community does not consider the existing 

test methods sufficient to meet their R&D needs. It is currently impossible to develop 

x 
reliable test methods because the understanding of the degradation mechanisms of 

coatings in service is insufficient. 

1.2 Evaluation of the Influence of Processing Variables on Performance 

Research topics were suggested that involved measuring and evaluating the influence 

of environmental and loading variables on coating performance. Loading variables 

included (a) soil stresses, (b) cyclic stresses, (c) thermal stresses, (d) residual stresses (e) 

stresses at welds, (f) residual stresses in the coating (curing stresses), (g) unusual event 

stresses, and (h) changes in stresses in the coating during aging of the coating or coating 

systems. The environmental variables included the normal range of pH, temperature, salt 

concentrations, found in ground waters. Extreme conditions could also be investigated, 

such as those encountered in mining or industrial by-products or the hydrocarbons that 

the coating might be exposed to if a leak occurred elsewhere and contaminated the back 

fill. 

1.3 Effects of Loading and Environmental Variables on Performance 

Research topics were suggested that involved measurement and evaluation of the 

influence of environmental and loading variables on coating performance. Loading 

variable suggested for study included (a) soil stresses, (b) cyclic stresses, (c) thermal 

stresses, (d) residual stresses (e) stresses at welds, (f) residual stresses in the coating 

(curing stresses), (g) unusual event stresses, and (h) changes in stresses in the coating 

during aging of the coating or coating systems. The environmental variables included the 

normal range of pH, temperature, salt concentrations, found in ground waters, but it was 

also suggested that extreme conditions be investigated such as one would encounter in 

mining or industrial by-products or the hydrocarbons that the coating might be exposed to 

if a leak occurred elsewhere and the back fill became contaminated. 

1.4 New Materials Research

 The working group discussions suggested that there was still considerable interest in 

developing new coating materials that resist degradation and failure better than existing 

coatings and coating systems. Concerns were expressed that coatings development 

research is limited by the available accelerated test methods. In addition to standard 

coating development, new materials research into (a) non-metallic pipes, (b) special 

coating or shielding materials for extreme conditions, (c) multilayer and multifunctional 

coatings, (d) improved materials for repairs (coatings, sleeves, and patches), and (e) 

improved materials for seams and welds. For in-field repairs and weld seam coatings, 

this area overlaps technology development as the objective shifts to developing in-field 

application techniques for coating materials that are essentially identical to those 

developed for mill application. 

xi 
2. Development of new technology or tools using existing knowledge 

2.1 Better NDE Tools and Techniques 

While this category did not dominate the discussion of any particular working group, 

all discussed it and raised NDE-related topics that fit into the knowledge, technology, and 

standards development areas. Some suggested development of standards for interpreting 

and guiding decision making based on NDE results. Others suggested developing new 

NDE tools and technologies or models for predicting signals from defects of known 

types. In addition to enabling better detection and identification of coating failures, NDE 

tools should be developed to (a) identify unknown coating materials, (b) assess the extent 

of coating degradation and estimate remaining service life, and (c) inspect multilayered 

coating systems. Inspecting the outside surface coating of a pipe from an NDE device 

mounted on a pig inside the pipe is extremely attractive. The suggestion with the greatest 

potential for wide ranging impact is that of developing a technique for non-intrusively 

assessing the extent of polymer degradation (as opposed to finding flaws or defects). This 

would enable estimation of remaining life of a coating and the development of reliable 

accelerated laboratory testing methods as discussed above in R&D category 1.1. 

2.2 Smart Coating Systems 

The importance of NDE to pipeline safety should not be understated. However, no 

one sets out to design a system that will require frequent or costly NDE inspections. One 

approach to reducing NDE inspection costs is to design a coating system that either 

enables easier, quicker, and cheaper inspection or continuous monitoring. These coatings 

could integrate sensors or be designed such that some property, which can be remotely 

monitored or periodically inspected, changes when failure initiates. A less ambitious 

approach is to design a coating system that assists or makes it easier for existing NDE 

techniques to find and identify flaws or regions of coating failure. 

2.3 New and Improved Repair Technologies 

In addition to materials development, the workshop participants identified new or 

improved technologies for in-field repairs for both newer and old coatings as R&D needs. 

Research topics included (a) techniques to remove old coatings, (b) in-field surface 

cleaning and preparation techniques, (c) sleeves and other innovative repair technologies, 

and (d) development of better procedures. 

2.4 New and Improved Coating Techniques for Weld Joints 

Welds represent discontinuities in the surface of the steel pipe. In-field joint welds 

being less consistent than seam welds they represent a greater challenge. The 

development of special coating techniques and procedures that ensure good quality, 

lasting coatings over these regions were deemed a special problem worthy of study 

separate from other coatings issues by many of the attendees. The larger stresses in the 

xii 
coatings and the irregularities in the coating to steel interface at these joints place greater 

demands on the coating system. 

3. Development of standards and data 

3.1 Coatings Databases 

Virtually every group suggested a coating database of one type or another at some 

point in their list of suggested R&D topics. Databases should be developed six areas: (a) 

coating technical data, (b) coating repair matrix of techniques for different situations and 

experience, (c) coating repair experience, (d) coating field performance (life-cycle data), 

(d) NDE analysis techniques, (e) failure analysis techniques (forensics) and identification 

of failure mechanisms, and (f) coating failures. 

3.2 Standardized Training 

The development of standardized training of mill and field applicators and inspectors 

is the topic area where investment will have the highest probability of positive benefit. 

However, the rate of return must not be attractive enough to prevent underinvestment in 

this area. Specialized and standardized training are necessary in (a) mill and field 

application of coatings, (b) handling of coated pipes, (c) coating of weld joints, (d) field 

repairs, (e) information resources on coatings and procedures (i.e. the coating repair 

technology matrix discussed above), and (f) safety in both the mill and the field. 

3.3 Improved Standards for Performance Testing and Life Prediction 

Development of a definitive accelerated laboratory test method may require 

considerable time. In addition, it will almost certainly take years of tests and field 

experience to prove the effectiveness of any new technique to the point of universal 

acceptance and standardization. Therefore, the community will continue to use the 

existing standardized test methods for the foreseeable future. A conservative industry will 

have considerable overlap when both new and old techniques are used. Continual 

evaluation and updating of the existing standards was suggested. The review presented 

by Papavinasam and Revie in this workshop illustrates this point. The pipeline industry 

will realize considerable benefit by improving these techniques and standards. 

3.4 Pipeline Coatings User Group and Data Sharing 

Workshop participants advocated forming a pipeline coatings users group to develop 

recommendations for recording pipeline handling and coating performance data. Many 

of the database and standardization suggestions require pipeline users to provide 

information on the performance of their pipelines. Clearly, many of the database 

suggestions will occur more easily if the pipeline operators take the initiative and 

formulate the approaches. At this meeting, representatives from NACE International 

offered to facilitate the organization of this users group. NACE International is a 

xiii 
Standards Developing Organization with a long history of working with and helping the 

pipeline industry. 

This workshop successfully identified and ranked R&D needs and challenges for 

improving the performance of pipeline coatings. The needs were identified and ranked 

by each working group according to the defined scope of their group. These needs were 

then gathered, sorted, combined, and ranked into the above crosscut according to nature 

of the work required to fulfill the need. This crosscut should enable the identification and 

description of programs without inhibiting creativity in the formulation of specific 

projects. The pipeline safety community should find this documentation of pipeline 

coatings R&D needs useful and a good source for helping prioritize R&D investment in 

this critical area. 

xiv 
Office of Pipeline Safety

Office of Hazardous Materials Safety

Pipeline and Hazardous 

Materials Safety Administration

Workshop on Advanced Coatings 

R&D for Pipelines and Related 

Facilities

June 9-10, 2005

Gaithersburg, MD - USA 

• ”

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Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

WELCOME

 WELCOME from “ Our Steering Committee

 First (on-shore) Advanced Coatings Workshop

 Building on Past workshop and forum success

 Consensus, Coordination & Collaboration

 Today’s Approach: Contest, Brainstorming, & 

Gap Analysis 

Safety and Comfort Announcements

 Fire Exits, Restrooms, Cell Phones

 Show of Hands Please

 Government, Industry, Vendors

Office of Pipeline Safety 

Office of Hazardous Materials Safety 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 USA Page 1
Office of Pipeline Safety

Office of Hazardous Materials Safety

Steering Committee

 Members

Government Organizations

• DOT Office of Pipeline Safety (OPS)

• DOC National Institute of Standards and Technology (NIST)

• DOI Minerals Management Service (MMS)

• DOE National Energy Technology Laboratory (NETL)

• National Energy Board of Canada

• CANMET Materials Technology Laboratory

Private Organizations

• American Gas Association (AGA)

• Pipeline Research Council International, Inc. (PRCI)

• National Association of Corrosion Engineers (NACE)

• Gas Technology Institute (GTI)

• Interstate Natural Gas Association of America (INGAA)

• ASTM

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Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

Why are we here?

 Corrosion still remains a major cause of accidents

 Coatings are important - Some consider coatings as the 

primary cathodic protection system

 Coating durability, application, and in-field assessment 

remains suspect

 Desire for solving coating issues usually ends up as low 

priority at larger events

 Problems with coatings are seen onshore, offshore & 

internationally 

Office of Pipeline Safety 

Office of Hazardous Materials Safety 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 USA Page 2
Office of Pipeline Safety

Office of Hazardous Materials Safety

Historical Accident Summary

Pipeline Incidents by Cause 

All Pipeline Types; 1994 - 2003

26 %

18 %

30 %

9 %

5 %

13 %

0

200

400

600

800

1000

1200

Corros on Excavation Damage Natura Force

Damage

Human Error Material Failure All Other Causes

Other

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Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

i l 

Office of Pipeline Safety 

Office of Hazardous Materials Safety 

37 Accidents 

37 Accidents 

3 Accidents 

Total Corrosion Accidents 

(External + Internal) 

Liquid 

Gas Transmission 

Gas Distribution 

Fast Facts 

1. Summary 1/1/2004 – 12/31/2004 

2. Corrosion – 18% of all accidents 

3. 3rd Party Damage 20% of all 

accidents 

4. Total No. of Accidents all causes 

is 429 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 USA Page 3
Office of Pipeline Safety

Office of Hazardous Materials Safety

15 Accidents

24 Accidents

3 Accidents

Total External Corrosion

Accidents

Liquid

Gas Transmission

Gas Distribution

Fast Facts

1. Summary 1/1/2004 – 12/31/2004

2. External Corrosion – 55% of all 

corrosion accidents 

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Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

Coating System Failures Are 

Not Totally Understood 

Some failures are caused by:

 Poor surface preparation

 Poor application

 Poor selection criteria

 Cathodic protection 

Office of Pipeline Safety 

Office of Hazardous Materials Safety 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 USA Page 4
Office of Pipeline Safety

Office of Hazardous Materials Safety

Various contaminates remaining on the metal 

surface such as salts, moisture, old coatings, 

hydro carbons and various other “dirt” on the surface, 

Inadequate profile or improper heating of the surface

Poor Surface Preparation

Office of Pipeline Safety

Office of Hazardous Materials Safety

Workshop on Advanced Coatings R&D for Pipelines and Related Facilities June 9-10, 2005 NIST, Gaithersburg, MD 20899 USA Page 5
Office of Pipeline Safety

Office of Hazardous Materials Safety

Office of Pipeline Safety

Office of Hazardous Materials Safety

Workshop on Advanced Coatings R&D for Pipelines and Related Facilities June 9-10, 2005 NIST, Gaithersburg, MD 20899 USA Page 6
Office of Pipeline Safety

Office of Hazardous Materials Safety

Poor Application

 Technologies

Different coating types have particular application 

methods that must be followed:

• FBE’s require several critical steps for proper 

 application to take place

• Liquid coatings must be mixed and applied 

 using the proper techniques 

• Use of the correct primer for a particular coating

 system is critical

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Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

Poor Application 

Technologies

 When using tape type coatings, proper tension and 

overlap are very critical

 Application of Shrink Sleeves must include proper 

heating of both the metal and the sleeve

 Proper curing is critical to many different types of 

coatings before handling or back filling 

Office of Pipeline Safety 

Office of Hazardous Materials Safety 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 USA Page 7
Office of Pipeline Safety

Office of Hazardous Materials Safety

Poor application techniques

•

•

Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

Office of Pipeline Safety 

Office of Hazardous Materials Safety

 Choosing high dielectric strength coatings that will shield 

CP currents if the coating fails may not always be 

the best choice

 Soil stress must be considered when choosing a coating 

system. Many types of coatings are affected by soil 

stress, especially coatings that stretch easily 

Poor Coating Selection 

Criteria 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 USA Page 8
Office of Pipeline Safety

Office of Hazardous Materials Safety

Coatings failure caused from 

soil stress

Office of Pipeline Safety

Office of Hazardous Materials Safety

Workshop on Advanced Coatings R&D for Pipelines and Related Facilities June 9-10, 2005 NIST, Gaithersburg, MD 20899 USA Page 9
Office of Pipeline Safety

Office of Hazardous Materials Safety

Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

Office of Pipeline Safety 

Office of Hazardous Materials Safety 

Some Coatings Crack & 

Move Because of Soil Stress 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 USA Page 10
Office of Pipeline Safety

Office of Hazardous Materials Safety

Mechanical damage may start the water

Penetration & the shielding process

•

•

” 

•

Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

Office of Pipeline Safety 

Office of Hazardous Materials Safety 

Cathodic Protection

 Cathodic protection is blamed for many coating failures 

(The real reason for coating failures are many 

times overlooked)

 Many think that a high pH under the coating indicates 

that coating has failed because of cathodic protection 

(This may simply mean that you have a “fail safe

 coating system)

 Too many worry over meeting certain criteria when 

failed coatings that shield CP are the main reason 

for corrosion problems 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 USA Page 11
Office of Pipeline Safety

Office of Hazardous Materials Safety

Cathodic Protection

• As CP increases, we may be causing more coating 

 damage, (CP interference with other systems and wasting

 money on excessive power use, extensive surveys and 

 equipment to meet this demand)

• If we use properly selected and applied coatings we will 

 start seeing that meeting a certain CP criteria is not the 

 most important issue in solving our corrosion problems

 on coated structures

• CP causes electrolyte around the protected structure to 

 become more alkaline and drives water toward the metal 

 being protected

•

• “ ”

” 

Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

Cathodic Protection

 CP will protect exposed substrate and will sometimes

 penetrate partially under disbonded coatings at an 

opening or holiday depending on many variables 

Fail Safe coatings allow some CP current to protect

 the substrate even if there is no opening or holiday. 

CP requirements may increase for some “fail safe

 coatings systems, but the benefits usually 

OUTWEIGHS THE CORROSION PROBLEMS 

Office of Pipeline Safety 

Office of Hazardous Materials Safety 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 USA Page 12
Office of Pipeline Safety

Office of Hazardous Materials Safety

Future of Collaborative 

Research

• Plenty of incentives for any pipeline company 

• Collaboration Maximizes value of input

• Collaboration means targeting technology gaps

 knowledge, Tools and or Standards

• Industry determines needs

• Almost always needs are common

 (everyone has problems whether they admit to them or not)

• Collaboration provides new answers to old problems

•



•

•

•

•

Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

Future of Collaborative 

Research

 We must remind members of our industry (owners, consultants,

 contractors, service providers) that they must manage their risks

 Failure to supply, Public risk Litigation, Fines, 

Loss of revenue, Loss of share value

 Obligations to their shareholders and the public

 Collaboration research is the best way of mitigating risks

 Research is for the betterment of the industry

 Industry & Government Agencies must partner on research 

Office of Pipeline Safety 

Office of Hazardous Materials Safety 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 USA Page 13
Office of Pipeline Safety

Office of Hazardous Materials Safety

Incentives for Research

• We don’t want a catastrophe as a catalyst –but:

• Some failures or near misses concentrate the mind

• Research & its application to solving real world problems 

 provide best defence against:

 Failure to supply

 Public risk

 Litigation

 Fines

 Loss of revenue

 Loss of share value

•

–

•

•

Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

What did the recent 

R&D Forum report? 

2005 Government and Industry Pipeline R&D Forum 

Houston, Texas March 22-24, 2005 

http://primis.phmsa.dot.gov/rd/mtg_032305.htm 

Report-Out on Design/ Construction/ Materials/ Welding 

Issue Action Required 

Coatings are relied upon for Series of research programs 

corrosion protection of pipelines. relating to gaps in knowledge. 

There is a need for more effective 

short term testing methods to Intended out come of this predict long term performance Workshop is to establishing wear and penetration, coating soil specific project needs interactions, etc. 

Office of Pipeline Safety 

Office of Hazardous Materials Safety 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 USA Page 14
•

•

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Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

Conclusions

 Government supported Research is critical to 

filling the gaps in Knowledge, developing new 

industry Tools and improving Standards

 There must be a balance between a coatings

 overall performance and the CP system

 Continued government/industry partnership in 

evaluation and testing will provide the information 

needed to continue to make the best coating 

choices to protect the pipeline infrastructure 

Office of Pipeline Safety 

Office of Hazardous Materials Safety 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 USA Page 15
Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

Coatings for Corrosion Protection:

Offshore Oil and Gas Operation Facilities, Marine

Pipeline, and Ship Structures

April 14-16, 2004 Biloxi, Mississippi

NIST Publication 1035

Edited by: Charles Smith, Tom Siewert, Brajendra Mishra, David Olson, Angelique Lasseigne 

Coatings for Corrosion Protection: Offshore Oil and Gas

Operation Facilities, Marine Pipeline and Ship Structures

• This workshop of 150 attendees drew participation by internationally 

recognized: 

– Marine coating experts 

– Material specialists 

– Inspection specialists 

– Coatings manufacturers 

– Maintenance engineers 

– Designers 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 USA Page 16
Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

Coatings for Corrosion Protection: Offshore Oil and Gas

Operation Facilities, Marine Pipeline and Ship Structures

• This workshop was crafted to include multiple view points 

including: 

– Industrial 

– Academic 

– Environmental 

– Regulatory 

– Standardization 

– Certification 

Coatings for Corrosion Protection: Offshore Oil and Gas 

Operation Facilities, Marine Pipeline and Ship Structures 

• Workshop is to Assess 

Opportunities for Research 

and Development in: 

– Coating Practice 

– Coating Materials 

– Coating Application 

– Repair 

– Non-Destructive Evaluation 

– Extended Coating Life Prediction 

USS Ogden new technology tank coatings after 6 years 

USS Ogden old technology tank coatings after 3years 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 USA Page 17
Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

Coatings for Corrosion Protection: Offshore Oil and Gas 

Operation Facilities, Marine Pipeline and Ship Structures 

• Papers generated during this workshop include: 

– Keynote 

– Topical Information 

– Discussion Groups 

Coatings for Corrosion Protection: Offshore Oil and Gas

Operation Facilities, Marine Pipeline and Ship Structures

• Keynotes and Invited Topical Papers Define State of the Art 

– To assess current practices and their limitations 

– To discuss field experiences 

– To chart a course for the best corrosion protection methodology 

• Including serving and monitoring 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 USA Page 18
Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

Coatings for Corrosion Protection: Offshore Oil and Gas

Operation Facilities, Marine Pipeline and Ship Structures

• Keynotes and Invited Topical Papers 

– Research and Development of Coatings for 

Alaska Tanker Company 

– Practical Experience to Combat Corrosion on 

Floating Production Units (FSO/FPSO’s) 

– Inspection and Repair of Coatings 

– Past, Present, and Future “Smart” Protective 

Coatings 

– Risk Assessment and Economic Considerations 

When Coating Ballast Tanks 

Coatings for Corrosion Protection: Offshore Oil and Gas

Operation Facilities, Marine Pipeline and Ship Structures

• Keynotes and Invited Topical 

Papers 

– Decision Making in Coating Selection in 

Marine/Offshore Environments 

– Corrosion Protection for Offshore 

Pipelines 

– Experience with Coatings for Corrosion 

Protection from the Norwegian 

Continental Shelf 

– U.S. Navy Ships: Developments and 

Status 

– Single Coat and Rapid Cure Tank 

Coating Systems 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 USA Page 19
Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

Coatings for Corrosion Protection: Offshore Oil and Gas

Operation Facilities, Marine Pipeline and Ship Structures

• Six Discussion Groups: 

– To Address Specific Issues Identified 

– To Prioritize the Issues 

– To Recommend Specific Research and Development 

Topics for: 

• Government 

• Industry 

Coatings for Corrosion Protection: Offshore Oil and Gas

Operation Facilities, Marine Pipeline and Ship Structures

Discussion Groups “White Papers” 

1. U.S. Shipyard Paint Shops: Current Issues and Future Needs 

2. Rationalization and Optimization of Coatings Maintenance Programs 

for Corrosion Management on Offshore Platforms 

3. Coatings for Pipelines 

4. Coatings for Port Facilities 

5. Near 100 Percent Solids Tank Linings 

6. Evaluating the Current State of Inspection Practices for Protective 

Coatings (In Process and Continued Evaluation) and the Exploration of 

Opportunities for Improvement of these Practices 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 USA Page 20
Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

Recommendations from the Discussion Groups

• Research 

– Quantitative evaluation of the long-term field performance of 

pipeline coatings. One project should install coated pipe samples in 

the field at carefully selected locations representative of different 

environmental conditions. Several monitoring methods should be 

used. In addition, the coating performance evaluation should include 

both consistent and fluctuating temperatures with transient and cyclic 

temperature fluctuations. A one-day scoping meeting prior to this 

investigation should be held with good representation of the interested 

parties. 

– Development of practices for evaluating pipeline coatings for 

service under extreme conditions such as: Offshore-deep sea, 

Offshore-Arctic, Onshore-equator is recommended. These 

investigations should include three types of coatings: Anti-corrosion 

coatings, Abrasion-resistant coatings, and Insulation coatings. 

Recommendations from the Discussion Groups

• Research 

– Development of a non-destructive method of evaluating the 

application of coating systems. Programs need to explore the 

feasibility of thermography, magnetic flux leakage, electrical impedance, 

and eddy current phase array. Modeling using EIS is not reliable. 

– Development of specific advancements in coating materials. A 

project for non-skid deck coating systems that will last when applied 

over less than perfect surface preparations. Parameters that control 

coating performance. Modeling of performance of all coatings (not only 

FBE). A project should include the evaluation of coatings at higher 

temperature in the laboratory. Performance of insulation coating should 

be investigated. Research project to develop coating systems that 

respond to exposure stresses needs to be performed. 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 USA Page 21
Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

Recommendations from the Discussion Groups

• Development 

– Improvement in the effective use of coatings for port facilities and the development of 

the necessary performance-based specifications. The development of generally 

accepted design standards and practices for port authorities needs to be established. 

These standards and practices need to be beneficial to the owner. Also the program needs to 

develop generally accepted design standards and acceptances for port facilities. This 

development may need to be geographically specific such as: blue water specific or brown 

water specific. 

– Advanced methodologies for applications of coatings. A project needs to address paint 

application issues without the use of brushes and rollers to increase productivity, lower costs, 

and less personnel exposure. The proposed investigation should include concerns of issues 

such as: curing time compared to burial or immersion time and adhesion of field-applied 

coatings to mill-applied coatings. An investigation to assess the effects of stockpiling of 

coating products on pipeline coatings performance including the effect of temperature, ultraviolet light, and time needs to be established. Development of high solid products, which meet 

VOC requirements that have less tendency to embrittle over time. Develop a mechanism to 

aid the painter in being able to achieve more uniform film thicknesses with high solid coatings 

in the field. The use of a capture device at the spray gun versus total encapsulation of the 

space to be painted should be investigated. Evaluate the need to increase the investment in 

coating application technology R&D. Establishment of a welding procedure for welding on 

painted surfaces is recommended. 

Recommendations from the Discussion Groups

• Development 

– Assessment of new technologies for surface preparation before 

coating. This program should include projects on the feasibility of 

using microwave technology for surface preparation, hand-held x-ray 

fluorescence system to detect salts on the surface, and a project to 

improve the dissemination and clarity of information on allowable 

surface chlorides. Improvement of application equipment to facilitate 

applying high solid coatings in the field to inaccessible areas. A project 

investigating the effects of minor variations in surface preparation and 

effects of variation in composition of surface contamination, including 

mill scale, on long-term coatings performance is necessary. A project 

on secondary surface preparation critera / Standards (example: 

exceeding the recoat window of an epoxy- Methodology for evaluation) 

needs to be established. The cost of surface preparation and coating 

application for underwater hull areas is going up and the designs of 

coating technology for this area has not kept pace. 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 USA Page 22
Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

Recommendations from the Discussion Groups

• Administrative 

– Standardized methodology for data collection and management. An 

unbiased third party to compile an industry wide historical data base on 

pipeline coating performance and evaluate the data critically needs to be 

established and funded. A program to establish user-friendly 

standardization needs to be initiated and performed. The program would 

include a project on the standard/ recommended practices for 

implementation of inspection for protective coatings projects. 

– Formulation of a roadmap for coatings research and/or development 

that indicates the proper sequence of projects. The roadmap needs to 

be periodically updated by industrial organizations as well as government 

research agencies and industrial users of coated structures. Such a 

roadmap would be helpful in prioritizing national and international needs 

and to assist in obtaining the necessary funding. The roadmap program 

will need to be annually updated by NACE International and SSPC (The 

Society for Protective Coatings). 

Recommendations from the Discussion Groups

• Administrative 

– A working group, national or regional, to increase exchange of information 

on the performance of coating products and application. The working group 

can formulate through user conscience new performance based specifications, 

design standards, and practices for port facilities. There already exists the 

working structure for such a working group in the existing coating and corrosion 

societies. It needs an initiator. (Note: Loosely exists at SSPC). 

– Evaluation of the economic issues of coating materials, their application, 

and their service behavior. A specific project on the study of the measurable 

economic contribution of the inspection of coatings project successes and 

performance needs to be performed. A project to study economics of coating 

technology to suggest and recommend the most cost effective use of the present 

technology should be implemented. The issue is that use and deployment of 

new coating technology is hampered by high cost of new equipment. Look into 

what can be done to utilize existing equipment; lower the cost of new equipment; 

or provide the financial incentives needed. Consumer and coating industry 

feedback loop needs to be improved. Problems are generally reported and 

investigated; however, successful applications rarely are investigated to confirm 

good practice. 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 USA Page 23
Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

Recommendations from the Discussion Groups

• Operations 

– Advanced methods for coating repair. This program should include a 

project on standards for quantification of performance and repair criteria and a 

project to quantify the effect of "repairs" on newly installed coatings system's 

performance. 

– Training, education, and certification of painters, corrosion engineers, 

and inspectors in the marine and pipeline industry. Develop a certification 

and training program for painters in the marine industry. Help develop an 

engineering technologist degree / vocational training program for coating 

specification. Guidelines/Practices/Standards for evaluating In-Service 

Coatings and the training of Coating Survey Inspectors, with focus on 

Inspection and Evaluation of In-Service Coatings and tools for evaluation 

needs to be organized. A special program for educating Coast Guard and 

MMS inspectors to establish consistency with the offshore industrial 

standards. Development of a hiring program offering training and certification 

plus weekly pay, which would have an impact on safety, employee morale, 

and salary. 

Recommendations from the Discussion Groups

• Operations 

– Development of coating/corrosion assessment criteria and acceptable 

corrosion levels for use by corrosion engineers and regulators in the 

development and assessment of Asset Integrity Management Programs. 

Development of a criteria for determining the most cost effective 

maintenance effort and tools to quantify: coatings age and degradation, 

ability to apply over-coatings, and consistent evaluation needs to be 

established. 

– Address the environmental and health and safety issues regarding 

paint materials and their application. A project for the determination of 

the effects of environmental conditions and variations in coating procedures 

on the performance of field-applied pipeline coatings needs to be instituted. 

A project on the development and research of environment tolerant coatings 

that can be used year round with increased quality. The development of 

pipeline coatings with anti-microbial properties. This development must 

achieve coating acceptable ecological concerns. 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 USA Page 24
Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

Pipeline Papers

#1 Corrosion Protection for Offshore Pipelines 

By Ernest W. Klechka, Jr., P.E.

CC Technologies, Dublin, Ohio

• Corrosion Control - Integrity Management 

• Evaluation of Corrosion Potential 

• Coating Selection 

• Design Considerations 

• Cathodic Protection Design 

• Monitoring and Inspection 

Pipeline Papers: Discussion Group Paper

#2 Coatings for Pipelines 

By S. Paapavinasam and R. Winston Revie

CANMET Materials Technology Laboratory

Ottawa, Ontario, Canada

June 9-10, 2005 NIST, Gaithersburg, MD 20899 USA Page 25
Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

Pipelines Paper: “Coatings for Pipelines”

Identified Research Needs and Opportunities 

• Consolidation of laboratory methods to develop generic tests, leading 

to specific test methods for specific coatings, should be considered. 

• A comprehensive model to predict long-term performance of coatings 

should be developed based on carefully controlled laboratory 

experiments as well as from field experience with older coatings, such 

as coal tar and asphalt, and modern coatings, such as FBE and 

urethane, using the power of modern computers and intelligent 

systems, e.g., artificial neural networks. 

• Based on a systematic study, the temperature limits of existing tests 

should be explored, and tests to evaluate products for elevated 

temperature applications should be developed. 

Pipelines Paper: “Coatings for Pipelines”

Identified Research Needs and Opportunities 

• Whereas many of the issues of mainline coatings are well 

understood and standards for mainline coatings have been 

developed, there is now a need to focus on field applied coatings, 

both repair and joint coatings. 

• The effects of minor variations in surface preparation on long-term 

coatings performance need to be established. 

• Relationship between application temperature and coating 

performance needs to be established. 

• Influence of stockpiling on coating performance should be 

established. 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 USA Page 26
Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

Pipelines Paper: “Coatings for Pipelines”

Identified Research Needs and Opportunities 

• A systematic study on the effects of field conditions and variations 

of procedure during the application of joint coatings, including the 

field performance of the coating, is recommended. This study 

should include the cohesive and adhesive strength of joint coatings. 

• Realistic backfill impact testing that includes a method to evaluate 

the compaction produced by backfilling should be carried out to 

determine the effect of backfilling on coating performance. 

• Focused effort to understand soil forces (both physical and 

chemical) on coating performance will provide useful information for 

developing strategies to protect coatings. 

Pipelines Paper: “Coatings for Pipelines”

Identified Research Needs and Opportunities 

• Recommended practices for evaluating coatings for northern 

pipelines need to be developed and incorporated in standards. 

• Tests to evaluate repair coatings, including evaluation of 

cohesion within the repair coating and adhesion to the mainline 

coating and to steel pipe, should be developed. 

• Development of a remote, accurate monitoring technique to 

evaluate the status of the coating (including the shielding effect) 

will greatly enhance pipeline integrity and decrease the number 

of pipeline incidents caused by corrosion. 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 USA Page 27
Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

Pipelines Paper: “Coatings for Pipelines”

Identified Research Needs and Opportunities 

• Development of an industry-wide coating database to share the 

experience of older and modern coatings is an essential logical 

step to develop an integrity management program. Continuous 

updating and sharing of such a database will be very useful. 

• The performance of coatings should be compared at constant 

and fluctuating temperatures. 

• An objective study to develop a method that monitors microbial 

population and coating biodegradation will clarify the effects of 

microbes on coatings. 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 USA Page 28
a

Phone:

bPhone

Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

Natural Resources Ressources naturelles 

Canada Canada 

Canada

Standards for Pipeline Coatings 

S. Papavinasama and R.W. Revieb 

CANMET Materials Technology Laboratory

 Ottawa, Ontario, Canada K1A 0G1 

Fax: 613-992-8735

 613-947-3603, Email: spapavin@nrcan.gc.ca 

: 613-992-1703, Email: wrevie@nrcan.gc.ca 

Canada

Natural Resources Ressources naturelles 

Canada Canada 

2 

Outline 

Introduction 

Historical Perspective 

Standards for Coating Evaluation 

Summary 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 Page 29
Performance 

Evaluation of Pipeline

Coatings

Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

Canada

Natural Resources Ressources naturelles 

Canada Canada 

3 

Standard 

Tests 

Field 

Performance 

New 

Methodologies 

Laboratory 

Experiments 

Introduction 

Canada

Natural Resources Ressources naturelles 

Canada Canada 

4 

Historical Perspective 

 Procedures to Select Pipeline Coatings 

 Pipeline operating conditions and physical properties 

of the coating are identified 

 Tests or behavior of materials 

 Several coatings short listed 

 Compromise of factors, including cost and facilities 

 Most appropriate coating(s) selected 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 Page 30
Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

Canada

Natural Resources Ressources naturelles 

Canada Canada 

5 

Historical Perspective 

 10-Year Study in 1950s 

 Develop and devise laboratory procedures 

 Correlate laboratory and field performance data 

 Test new materials 

Canada

Natural Resources Ressources naturelles 

Canada Canada 

6 

Historical Perspective 

13 New ASTM Pipeline Coating 

Standards (1970s) 

 Physical and Mechanical Tests 

 Chemical and Atmospheric Exposure Tests 

 Electrical and Electrochemical Tests 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 Page 31
Canad Natural Resources Ressources naturelles

Canada Canada

8

Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

Canada

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7 

Historical Perspective 

Industry Surveys 

 PRCI/GRI Survey (1992) 

 PRCI/GRI/CANMET Survey (2002) 

 Biloxi Coating Workshop (2004) 

a

Pipeline Coatings in North America 

1930 1940 1950 1960 1970 1980 1990 2000 2010 

year 

Coal Tar 

Wax 

Asphalt 

Extruded Polyolefins 

Polyethylene Tape 

Fusion Bonded Epoxy 

3-Layer 

Composite 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 Page 32
Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

Canada

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9 

Standards for Pipeline Coatings 

General 

 NACE RP0169, NACE RP0190, & CSA Z662 

Specific Coatings 

 Coal Tar, Tape, FBE, Liquid Epoxy, Urethane, 

and Extruded Polyolefins 

Specific Properties 

 Adhesion, Cathodic Disbondment, etc. 

Canada

Natural Resources Ressources naturelles 

Canada Canada 

10 North American Standards-Making 

Organisations for Pipeline Coatings 

 ASTM 

 Specific Properties of Polymeric Coating 

 AWWA 

 Water Pipelines 

 CSA 

 Canadian Pipelines 

 NACE 

 Specific Coatings 

 SSPC 

 Surface Preparation 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 Page 33
Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

Canada

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11 

Influencing Factors 

Steel 

Coating 

Steel/ 

Coating 

Interface 

Coating/Soil 

Interface 

Steel/Soil Interface 

Canada

Natural Resources Ressources naturelles 

Canada Canada 

12 

Influencing Factors 

Coating 

Steel 

Steel-Coating Interface 

Coating-Soil Interface 

Steel-Soil Interface 

Manufacturing 

Application 

Transport 

Construction 

Operation 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 Page 34
Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

Canada

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13 

Standards: Steel 

 Cleaning 

 Surface profile 

 Chemical contamination 

 Visible and Non-visible 

Standards agree with each other 

with respect to the influence of steel 

Canada

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14 

Standards: Steel-Coating Interface 

 Adhesion 

 Hot-Water Soak 

 Peel 

 Sheer 

 Pull-off 

 Cathodic Disbondment 

 Bendability/Flexibility 

Harmonization of Standards by Various Organizations Useful 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 Page 35
Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

Canada

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15 

Standards: Coating (Common) 

• Thermal Conductivity 

• Dielectric Strengths 

• Electrical Conductivity 

• Hardness 

• Penetration Resistance 

• Water Permeation 

• Blistering 

• Chemical Resistance 

• Weathering 

• Cohesion 

• Stress-Cracking Resistance 

• Resistance to Oxidation 

• Compressive Properties 

• Thermal Expansion 

• Brittleness Temperature 

• Film Thickness 

Harmonization of Standards from Various Organizations to 

Evaluate Water Permeation and Blistering will be useful. 

Canada

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16 

Standards: Coating (Specific) 

 Composition 

 Gel Time (FBE) 

 Particle Size 

 Total Volatile Content 

 Porosity 

 Viscosity 

 Flow 

 Softening Point 

 Shelf Life 

 Filler Content 

 Tear Strength 

 Curing 

 Tensile Strength 

 Sag 

 Low-Temperature 

Cracking Test 

 Pliability 

 Breaking Strength 

 Insulation Resistance 

 Density/Specific Gravity 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 Page 36
Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

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17 

Standards: Coating-Soil Interface 

 Microbial Resistance 

 Abrasion Resistance 

 Impact Resistance 

 Freeze-Thaw Stability 

 Resistance to Elevated Temperature 

 Compatibility and Repairability 

Specifications included in the Coating-Standards 

Canada

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18 

Standards: Steel-Soil Interface 

Detection of Holidays and Disbondments 

Cathodic Protection Current 

 DC Potential (Soil) Gradient 

Close Interval Survey 

Coating Conductance 

 AC Voltage Gradient 

 Inline Inspection 

Bellhole Inspection 

Development of standards required 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 Page 37
Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

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19 

Summary Summary

 Good Understanding of Coating Properties 

 Several Standards Available 

 Several Standards have Similar Requirements 

 Some Standards have Different Requirements 

 Cathodic Disbondment and Adhesion 

Canada

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20 

Moving On Moving On

 Harmonization of Some Standards 

 Correlation between Laboratory and Field Data 

 Common Industry Database 

 Capability to Predict Long-Term Coating 

Performance using Short-Term Experiments 

Based on Standards 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 Page 38
Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

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21

Performance 

Evaluation of Pipeline 

Coatings 

Standard 

Tests 

Field 

Performance 

New 

Methodologies 

Laboratory 

Experiments 

Summary

1960-1980 

1980-

2000 

1940-

1960 

2000-2020 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 Page 39
Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

STANDARDS FOR EVALUATING PIPELINE COATINGS 

Sankara Papavinasama

 and R.Winston Revieb

CANMET Materials Technology Laboratory 

568 Booth Street

Ottawa, Ontario, Canada K1A 0G1P

a

Phone: 613-947-3603, Fax: 613-992-8735, Email: spapavin@nrcan.gc.ca 

b

Phone: 613-992-8735, Fax: 613-992-8735, Email: wrevie@nrcan.gc.ca 

EXECUTIVE SUMMARY 

A review of standards used in U.S.A. and Canada for evaluating pipeline protective coatings is 

presented. The standards covered in this review were developed by ASTM, AWWA, CSA, 

NACE, and SSPC. Limited information on standards used in Europe is also presented in this 

paper. Commonality and differences in these standards are discussed. Some important features 

are: 

• There is a good understanding in the industry of the important properties that are 

detrimental to pipeline coating behaviour. 

• Several standards are available to test those properties that are detrimental to pipeline 

coatings. 

• Standards developed by different organisations have essentially the same requirements 

for evaluating some properties of the coating (e.g., surface profile), but different 

requirements for evaluating other properties (e.g., cathodic disbondment and adhesion). 

• Properties for which standards from different organizations have different requirements 

are also properties considered important for the coating performance; i.e., cathodic 

disbondment and adhesion. Harmonization of standards to evaluate these properties will 

be very useful. 

• Correlation of performance of coatings in standard tests and in the field has not been well 

documented, nor is such a correlation a specified requirement in any of the standards. 

• To date, no studies have been successful in establishing a correlation between field 

performance and performance in standard tests. 

• No common industry database on the performance of coatings in the field is available. 

• Development of a capability to predict long-term coating performance from test data 

established in short-term standard tests is an industry priority. 

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1. INTRODUCTION 

Many test procedures have been developed and methods of using them have been described to 

evaluate pipeline protective coatings. Standards have been developed by various standardsmaking organisations for these tests. In this paper, historical perspective of coating evaluation, 

laboratory methodologies used over the years and their significance are discussed; standards 

from various standards-making organisations for testing a particular property are compared; 

opportunities for harmonizing standards are identified; and areas for developing new standards 

are identified. 

2. HISTORICAL PERSSPECTIVE 

The procedure to be followed in selecting a protective pipeline coating has remained essentially 

1 the same since the 1940s. Three steps are involved : 

• First, the requirements from the standpoints of pipeline operating conditions and physical 

properties of the coating are identified; 

• Second, from the tests or information based on similar tests or general background 

knowledge of the behaviour of materials, several coatings that will meet the 

requirements are placed on a “short list”; and 

• Finally, a compromise of all the related factors, including cost and available facilities, is 

made to select the most appropriate coating. 

In 1958, a 10-year coating evaluation testing program, involving experiments in the laboratory 

2 and in the field was completed . This test program consisted of three phases to: 

1: Develop and devise laboratory procedures and apparatus suitable for evaluation of pipe 

coatings; 

2: Evaluate commonly used coatings and to correlate laboratory evaluations with field 

performance data; and 

3: Test new materials with the techniques developed and evaluate their performance against 

coatings in common use. 

Field burial tests were lengthy, and because of the variable conditions, results could not be 

evaluated with any precision. On the other hand, laboratory tests were considered suitable for 

evaluating one property of the coating at a time. Correlation between laboratory results and field 

performance was not established in this study. 

In the laboratory program, the objectives were to develop methods to determine the performance 

characteristics of coatings under carefully controlled conditions. To do this, methods were 

devised so that each test would determine one coating property under controlled, reproducible 

conditions. It was also the intent to determine, as far as possible, the service performance 

characteristics on a completed coating structure. 

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Coating characteristics tested in the laboratory were: 

1. electrical resistance; 

2. rate and amount of water adsorption; 

3. resistance to deformation under pressure; 

4. resistance to cracking and spalling under impact; 

5. resistance to cracking in bending; 

6. adhesion to pipe metal; 

7. deterioration in soil environment; 

8. deterioration in petroleum oils; and 

9. effects of cathodic protection. 

Since 1964, industry undertook to develop standardized tests for the evaluation of pipeline 

coatings. From 1964 to 1977, nearly 200 existing tests for non-metallic materials were reviewed 

for their potential value in the evaluation of pipeline coatings. Many tests could not be adapted to 

evaluate pipeline coatings and were, therefore, rejected. Others were dropped from further 

consideration because they produce data of marginal value. The tests retained for critical 

evaluation were those that would begin to yield definitive performance data within the first 90 

days of testing and not require more than 18 months to complete. Many methods selected could 

be completed in 30 days. The most promising of these tests were subjected to an intensive series 

of inter-laboratory, round robin testing for final verification. Additional rejections occurred at 

this level, principally due to lack of precision or undue complexity of the test apparatus and its 

associated method. 

By 1978, this systematic process had produced 13 ASTM standard test methods to determine 

3 properties of non-metallic coatings applied to steel pipe. These standard test methods are : 

Physical and Mechanical Tests 

1. Abrasion Resistance of Pipeline Coatings ASTM G 6 -77 

2. Bendability of Pipeline Coatings ASTM G 10-72 

3. Limestone Drop Test for Pipeline Coatings ASTM G 13-72 

4. Falling Weight Test for Pipeline Coatings ASTM G14-72 

5. Penetration Resistance of Pipe Coatings ASTM G 17-72 

Chemical and Atmospheric Exposure Tests 

6. Chemical Resistance ASTM G 20-72 

7. Effects of Outdoor Weathering on Pipeline Coatings ASTM G11-72 

Electrical and Electrochemical Tests 

8. Cathodic Disbondment of Pipeline Coatings ASTM G 8-72 

9. Disbondment of Pipeline Coatings by Direct Soil Burial ASTM G 19-72 

10. Water Penetration into Pipeline Coatings ASTM G 9-72 

11. Tests for Joints, Fittings, and Patches in Coated Pipelines ASTM G 18-72 

12. Cathodic Disbonding of Pipe Coatings Subjected to 

Elevated or Cyclic Temperatures ASTM G 42-75T 

13. Evaluating Pipeline Coating Patch Materials ASTM G 55-77 

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In the 1980s, a major transmission pipeline company evaluated predictability of long-term 

coating performance from laboratory tests. This study found that, at best, prediction is difficult 

4 and, at worst, is inaccurate and misleading . Properties of pipeline coatings most useful for 

comparing laboratory test results and field performance are: 

• adhesion, 

• resistance to soil stresses, 

• chemical and physical stability, 

• resistance to impact, and 

• resistance to cathodic disbonding 

Table 1 gives the qualitative correlation found between laboratory testing and field 

observations/testing of major coating systems. Data for laboratory testing was taken from 

manufacturers’ literature and testing by others for polyethylene tape, coal tar, and asphalt enamel 

and mastic. Laboratory data for epoxy and urethane is from the pipeline company’s own testing. 

Based on the general observations on field performance, asphalt enamel and mastic coatings had 

become very brittle and the soil stress resistance of tape was very poor. 

No relationship between degree of disbonding in laboratory testing and field performance over 

time could be established. It was observed that modifications to existing test procedures, 

apparatus, test electrolyte, and sample preparations are required to predict the long-term 

performance. 

Table 1: Correlation between laboratory evaluations and field performance of pipeline coatings. 

Coating Physical and 

chemical stability 

Resistance to 

soil stress 

Resistance to 

impact 

Adhesion Resistance to 

cathodic 

disbonding 

Polyethylene tape Good Poor Good Poor Good 

Asphalt enamel Fair Poor Good No lab. data Good 

Asphalt mastic Poor Poor Good No lab. data Good 

Epoxy Good Good Good Good Good 

Coal-tar enamel Good Fair Good No lab. data Fair 

Urethane Good Good Good Good Good 

In 1992, as part of a program to develop quantitative techniques for predicting the rate of 

disbonding of anti-corrosion coatings on buried natural gas pipelines, an assessment of the state- 5 of-the-art for the selection and use of pipeline coatings was performed . Information was 

gathered through questionnaires, interviews, and a review of the published literature. The results 

are summarized in Table 2 and Table 3. This study found that the three parameters most 

detrimental to the performance of pipeline coatings are: 

• adhesion 

• cathodic disbondment 

• water penetration. 

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Table 2: Criteria considered to be the most and least important during the selection of pipeline 

* coatings . 

Relative importance Avg. S. 

Field experience 1.82 0.91 

Laboratory test results 2.05 0.95 

Initial cost 2.06 1.17 

Applicator 2.45 1.11 

Soil stress resistance 2.46 1.31 

Service temperature 2.47 1.49 

Cost (operation and maintenance) 2.58 1.3 

Logistical convenience 2.61 1.17 

Ease of application 2.7 1.17 

Soil type 2.88 1.33 

Pipe diameter 3.05 1.17 

Ground water - fluctuation 3.12 1.35 

Repair methods available 3.13 1.08 

Ground water chemistry 3.25 1.33 

Pipeline class location 3.45 1.34 

Cathodic protection type 3.75 1.37 

* Respondents were asked to rank the importance of the various criteria from 1-5, with 1 being 

very important and 5 being not important. The “Avg.” refers to the average values of the 

responses and the values in the row labelled “S.” are the standard deviations of the responses. A 

criterion considered to be very important would have a low average. A low value for the 

standard deviation indicates good agreement among the respondents concerning the given 

importance of a criterion. 

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Table 3: Coating properties considered to be the most and least important to the performance of a 

pipe coating. 

Pipeline Companies Coating Applicators 

Properties Avg. S. Properties Avg. S. 

Adhesion/Peel strength 1.22 0.59 Adhesion/Peel strength 1.08 N/A 

Cathodic disbondment 1.45 0.77 Cathodic disbondment 1.38 N/A 

Water penetration 1.81 0.92 Soil stress-resistance 1.38 N/A 

Electrical resistivity 1.81 0.88 Handling damage resistance 1.46 N/A 

Penetration resistance 1.98 0.77 

Construction damage 2.02 0.85 

resistance 

Impact resistance 2.13 0.97 

Resistance to soil stress 2.15 1.23 

Tensile strength/elongation 2.48 1.05 

Biological resistance 2.62 1.19 

Ease of repair 2.63 0.93 

Ease of application 2.65 0.95 

Hardness 2.7 1 Hot-water resistance 2.77 N/A 

Weathering resistance 3.23 1.14 Tensile elongation 2.92 N/A 

UV resistance 3.37 1.06 Tensile strength 3 N/A 

Hot-water resistance 3.62 1.34 UV resistance 3.69 N/A 

A paper in 1993 reviewed the process of coating evaluation over 50 years and observed the 

6 following : 

$ Selection of appropriate coating and correct application are very important. 

$ CP must supplement the coating for 100% protection. 

$ Soil stress is one of the main problems. 

$ Pipeline coatings should have resistance to cathodic disbondment, soil stress, good 

adhesion, adequate thickness, low moisture absorption/transfer, chemical resistance 

(especially alkalis from CP), and flexibility. 

$ Field performance test are more reliable than laboratory tests. 

$ Cathodic disbondment tests are the most reliable tests to measure coating performance. 

$ The current required for CP is a good measure of coating performance. 

$ Results of adhesion tests do not correlate with those of cathodic disbondment tests. 

$ A test specifically to evaluate adhesion of the coating to the pipeline and cohesion within 

itself should be developed. 

$ A comprehensive model to predict long-term performance of coatings should be 

developed. 

$ Consolidation of laboratory methods to develop generic tests, leading to specific tests for 

specific coatings is recommended. 

In the late 1990s and early 2000s, attempts were made to predict long-term performance of 

7-9 coatings using kinetic and thermodynamic methods . Based on only one data parameter (e.g., 

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cathodic current demand) and/or one coating (e.g., FBE) these predictions would fail to predict 

the failures caused by other mechanisms and/or failures of other coatings. 

10 In 2002 , another study was undertaken to analyse the gaps in our knowledge to develop a 

reliable model to predict field performance from laboratory studies. Based on an online survey, 

literature survey and analysis, the following steps were recommended to fill the technical gaps. 

In this recommendation, items indicated with ***** are of highest priority and items indicated 

with * are of lowest priority. 

***** Whereas most of the issues of mainline coatings are well understood and the standards 

for mainline coatings are recognized, the focus should now be on field applied coatings, 

both repair and joint coatings. 

***** The effects of minor variations in surface preparation on long-term coating performance 

need to be established. 

***** The relationship between application temperature and coating performance needs to be 

established. 

***** Focused effort to understand soil forces (both physical and chemical) on coating 

performance will help develop strategies to protect the coatings. 

***** Development of an industry-wide coating database to share the experience of older and 

modern coatings is an essential logical step to develop an integrity management program. 

Continuous updating and sharing of such a database will be very useful. 

***** An objective study to develop a method that monitors microbial population and coating 

biodegradation will clarify the effects of microbes on coatings 

  A comprehensive model to predict long-term performance of coatings should be 

developed based on carefully controlled laboratory experiments as well as from field 

experience with older coatings, such as coal tar and asphalt, and modern coatings, such as 

FBE and urethane, using the computing power of modern computers and intelligent 

systems, e.g., artificial neural networks. 

** ** Development of a remote accurate monitoring technique to determine the status of the 

coating will greatly enhance pipeline integrity and decrease the number of pipeline 

corrosion incidents. 

*** Consolidation of laboratory methods to develop generic tests, leading to specific testing 

of specific coatings 

*** Based on a systematic study, the temperature limits of existing tests should be explored 

and products for elevated temperature applications should be developed. 

*** A systematic study on the effects of conditions and variations of procedure during the 

application of joint coatings and the performance is recommended. This study should 

include the cohesive and adhesive strength of joint coatings. 

** Influence of stockpiling on coating performance should be established. 

** The performance of coatings at constant and fluctuating temperatures should be 

compared. 

* The relationship between coating chemistry and corrosion protection is not clear. 

In 2004, at the workshop held in Biloxi, Mississippi, a white paper on pipeline coatings was 

11 developed . Following are the main R&D issues that were identified in the area of coatings for 

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pipelines, listed in decreasing order of priority; i.e., item 1 is the top priority item for R&D. 

Items with the same number were ranked equally in terms of relative priority. 

I. Database on Coating Performance 

An unbiased 3rd party will compile an industry-wide historical database on coating 

performance and evaluate the data critically. 

II. Performance of Field-Applied Coatings 

Effects of environmental conditions and variations in coating procedure on performance 

of field-applied coatings 

Curing time compared with time to burial or immersion 

Adhesion of field-applied coating and mill-applied coating 

II. Long-term field evaluation of pipeline coatings 

A national or international program. 

Coated pipe samples to be installed in the field at carefully selected locations 

representative of different environmental conditions. 

Several monitoring methods to be used. 

In addition, evaluate coating performance at constant and fluctuating temperatures with 

transient and cyclic temperature fluctuations. 

1-day scoping meeting to be held, most likely in the fall of 2004 

III. Effects of stockpiling on coating performance

 Temperature 

UV 

 Time 

III. Develop practices for evaluating coatings for service under extreme conditions 

Offshore, deep-sea 

Onshore Arctic 

Onshore Equator 

Include 3 types of coatings: 

Anti-corrosion coatings, 

Abrasion-resistant coatings, and 

Insulation coatings 

IV. Standardization of test methods for evaluating coatings 

IV. Development of coatings with anti-microbial properties 

3. PIPELINE COATINGS 

Over the past 50 years, several pipeline protective coatings have been used. Figure 1 presents 

the timeline of usage of the coatings. Standards that provide general guidelines to select and 

evaluate pipeline coatings are: 

NACE RP0169: Control of External Corrosion on Underground or Submerged 

Metallic Piping Systems 

NACE RP0190: External Protective Coatings for Joints, Fittings, and Valves on 

Metallic Underground or Submerged Pipelines and Piping Systems 

CSA Z662: Oil and Gas Pipeline Systems (Annex L: Test Methods for Coating 

Property Evaluation). 

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Specific standards to qualify the coatings are: 

Cold-tar 

ANACE RP0399 Plant-Applied External Coal Tar Enamel Pipe Coating Systems: 

Application, Performance, and Quality Control 

B

ANSI/AWWA C203 Coal-Tar Protective Coatings and Linings for Steel Water Pipelines 

– Enamel and Tape- Hot Applied 

C

NACE RP0602 Field-Applied Coal Tar Enamel Pipe Coating Systems: 

Applications, Performance, and Quality Control 

Tape 

DANSI/AWWA C214 Tape Coating Systems for the Exterior of Steel Water Pipelines 

E

ANSI/AWWA C209 Cold-Applied Tape Coatings for he Exterior of Special Sections, 

Connections, and Fittings for Steel Water Pipelines 

F

NACE MR0274 Material Requirements for Polyolefin Cold-Applied Tapes for 

Underground or Submerged Pipeline Coatings 

FBE 

GNACE RP0394 Application, Performance, and Quality Control of Plant-Applied, 

Fusion-Bonded Epoxy External Pipe Coating 

HCSA Z245-20 External Fusion Bond Epoxy Coating for Steel Pipe 

I

ANSI/AWWA C213 Fusion-Bonded Epoxy Coating for the Interior and Exterior of 

Steel Water Pipelines 

J

NACE RP0402 Field-Applied Fusion-Bonded Epoxy (FBE) Pipe Coating Systems 

for Girth Weld Joints: Application, Performance, and Quality 

Control 

Liquid Epoxy 

KANSI/AWWA C210 Liquid-Epoxy Coating Systems for the Interior and Exterior of 

Steel Water Pipelines 

Liquid Urethane 

L

ANSI/AWWA C222 Polyurethane coatings for the Interior and Exterior of Steel Water 

Pipe Fittings 

2-layer, 3-layer, and composite 

MDIN 30670 

NNACE RP0185 

OCSA Z245-20 

P

ANSI/AWWA C215 

Wax 

QNACE RP0375 

Polyethylene-Coatings for Steel Pipes and Fittings Requirements 

and Testing 

Extruded Polyolefin Resin Coating Systems with Soft Adhesives 

for Underground or Submerged Pipe 

External Polyethylene Coating for Pipe 

Extruded Polyolefin Coatings for the Exterior of Steel Water 

Pipelines 

Wax Coating Systems for Underground Piping Systems 

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4. REVIEW OF TESTS AND STANDARDS TO EVALUATE PIPELINE COATINGS 

In this section, the existing laboratory methodologies are described. Standards developed by 

various organisations are compared. These methodologies/standards are classified according to 

which properties are being evaluated. For each property, the background information of the tests 

was provided, general standards to evaluate the properties are listed, and finally the relevance of 

these standards for each coating system is presented. The standards are classified based on the 

properties that these standards are used to evaluate: 

• Steel 

• Steel/coating interface 

• Coating 

• Coating/soil interface 

• Steel/soil interface 

12 4.A: STEEL

The steel surface plays an important role in the performance of the coating. Surface 

imperfections can cause premature failure. Coatings tend to pull away from sharp edges and 

projections. Before the application of coatings, the steel surface is blast cleaned, the surface 

profile is established, and chemical contaminants, if any, e.g., chlorides, sulphates, and nitrates, 

are removed. The test methodologies and standards for determining steel properties are 

discussed in this section. 

4.A.1: Cleaning 

The primary functions of cleaning before coating are (a) to remove material from the surface that 

can cause early failure of the coating system, and (b) to obtain a suitable surface roughness and 

to enhance the adhesion of the coating. The steel surface is cleaned either by solvents or by 

tools. Blast cleaning is being increasingly used. The hierarchy of blast cleaning is as follows: 

• white metal blast cleaning 

• near-white metal blast cleaning 

• commercial blast cleaning 

• industrial blast cleaning 

• brush-off blast cleaning 

• water-jetting. 

4.A.1.a: Standards 

SSPC-SP 1: Solvent Cleaning 

SSPC-SP 2: Hand Tool Cleaning 

SSPC-SP 3: Power Tool Cleaning 

SSPC-SP COM: Surface Preparation Specifications Surface Preparation 

Commentary 

ISO 8504-1: Preparation of Steel Substrates Before Application of Paints and 

Related Products Surface Preparation Methods - Part 1: General 

Principals 

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ISO-8504-2: Preparation of Steel Substrates Before Application of Paints and 

Related Products Surface Preparation Methods - Part 2: Abrasive 

Blast-Cleaning 

ISO-8504-3: Preparation of Steel Substrates Before Application of Paints and 

Related Products Surface Preparation Methods – Part 3: Hand- and 

Power-tool cleaning. 

4.A.1.b: Coatings 

Surface preparation depends on the type of coating. Surface profile requirements for various 

coatings as recommended by various standards are presented in Table 4. 

Table 4: Requirements of surface preparation for various coatings. 

Coatings Surface Preparation Requirements 

As required by 

(Standards) 

NACE CSA AWWA 

Asphalt N/A N/A N/A 

Coal tar (plant)A, B (SSPC-SP1) 

SSPC SP6/NACE #3 

or ISO 8501-1 

 (SSPC-SP1) SSPC 

SP6/NACE #3/SSPC SP 

10/NACE #2 

Coat tar (field) C (SSPC-SP1) 

SSPC SP6/NACE #3 

or ISO 8501-1 

Tape D, F Not specified (SSPC-SP1) 

SSPC-SP 6/NACE #3 

Tape (for joints) E (SSPC-SP1) 

SSPC-SP 6/NACE#3 

FBE (plant) G, H, I SSPC-SP 10/NACE 

#2F or ISO 8501-1 

SSPC-SP 

10/NACE #2G 

(SSPC-SP1) 

SSPC-SP 10/NACE #2 

FBE (field) J (SSPC-SP1) 

SSPC-SP 10/NACE #2 

Liquid epoxy K Work in progress 

(NACE Committee TG 

247)

 (SSPC-SP1) 

SSPC-SP 10/NACE #2 

Liquid urethane L Work in progress 

(NACE Committee TG 

281)

 (SSPC-SP1) 

SSPC-SP 10/NACE #2 

2-layer N, O, P SSPC-SP 6/NACE#3L SSPC-SP 

6/NACE#3 

(SSPC-SP1) 

SSPC-SP 6/NACE#3 

3-layer O SSPC-SP 

10/NACE #2 

Composite O SSPC-SP 

10/NACE #2 

Wax Q (SSPC-SP 1) 

SSPC-SP 2 

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4.A.2: Surface Profile 

The allowable minimum/maximum height of profile usually depends on the thickness of the 

coating to be applied. Various methods for measuring surface profiles have been presented . 

4.A.2.a: Standards 

Visual 

SSPC-VIS 1: 

NACE RP0178 

Non-Visual 

ASTM D4417: 

NACE RP0287: 

ISO 8502-3: 

ISO 8503-1: 

ISO 8503-2: 

ISO 8503-4: 

4.A.2.b: Coatings 

Visual Standard for Abrasive Blast Cleaning Steel 

• Provides color photographs for various grades of surface 

preparation as a function of the initial condition of steel. 

Visual Comparator for Surface Finishing of Weld Prior to Coating” 

• It is a plastic weld replica that complements NACE Standard 

RP0178, “Fabrication Details, Surface Finish Requirements, and 

Proper Design Considerations for Tanks and Vessels to be Lined 

for Immersion Service.” 

Standard Test Methods for Field Measurement of Surface Profile of Blast 

Cleaned Steel 

Field Measurement of Surface Profile of Abrasive Blast Cleaned Steel 

Surfaces Using a Replica Tape 

• The measurement technique utilizes a tape that replicates the 

surface profile. The thickness of the tape (with the profile replicate) 

is then measured with a dial micrometer to determine the surface 

profile. 

Preparation of Steel Substrates Before Application of Paints and Related 

Products - Tests for the Assessment of Surface Cleanliness - Part 3: 

Assessment of Dust on Steel Surfaces Prepared for Painting (PressureSensitive Tape Method) 

Preparation of Steel Substrates Before Application of Paints and Related 

Products - Surface Roughness Characteristics of Blast - Cleaned Steel 

Substrates - Part 1: Specifications and Definitions for ISO Surface Profile 

Comparators for the Assessment of Abrasive Blast-Cleaned Surfaces 

Preparation of Steel Substrates Before Application of Paints and Related 

Products - Surface Roughness Characteristics of Blast - Cleaned Steel 

Substrates - Part 2: Method for the Grading of Surface Profile of Abrasive 

Blast-Cleaned Steel - Comparator Procedure 

Preparation of Steel Substrates Before Application of Paints and Related 

Products - Surface Roughness Characteristics of Blast - Cleaned Steel 

Substrates - Part 4: Method for the Calibration of ISO Surface Profile 

Comparators and for the Determination of Surface Profile - Stylus 

Instrument Procedure 

The minimum/maximum height of profile depends on the thickness of the coating. The surface 

profile requirements for various coatings are presented in Table 5 

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Table 5: Requirements for Surface Profiles for Various Coatings 

Coatings Surface Profile Requirements, mils (μm) 

As required by (Standards) NACE CSA AWWA 

Asphalt N/A N/A N/A 

Coal tar (plant) 1.5-3.5 (38-89) 1.5-3.5 

Coat tar (field) 1.5-3.5 (38-89) 

Tape Not specified 1-3 (25-75) 

Tape (for joints) Not specified 

FBE (plant) 1.5 (38) 1.5-4.5 (40-110) 1.5-4.0 (38-102) 

FBE (field) 2.5-4 (64-100) 

Liquid epoxy Not specified 

Liquid urethane 2 (50) 

2-layer 1.5 – 4.0 (38 – 102) 1.5-4.5 (40-110) 1.5-4.0 (38-102) 

3-layer 1.5-4.5 (40-110) 

Composite 1.5-4.5 (40-110) 

Wax Not specified 

4.A.3: Chemical Cleaning 

The steel surface may be contaminated with visual and non-visual contaminants. Steel 

contaminated with soluble salts (e.g., chlorides and sulfates) develops rust-back rapidly at 

intermediate and high levels of humidity. The presence of varnish or previous coating on the 

pipe, phosphoric acid treatment, water, and grit or shot quality all contribute to the interaction 

14-16 between the pipe and coating . The effects of surface contamination on FBE coatings have 

been widely studied. Based on field experience over the years, surface contamination affects all 

coatings17, 18 . 

4.A.3.a: Standards 

Visual Contaminants 

NACE RP 0394: Appendix P: Test for Interface Contamination of the Coating 

CSA Z.245.20: Section 12.9: Interface Contamination of the Coating 

Non-visual Contaminants 

SSPC-TU 4: Field Methods for Retrieval and Analysis of Soluble Salts on Substrates 

ASTM D4940: Standard Test Method for Conductometric Analysis of Water Soluble 

Ionic Contamination of Blasting Abrasives 

• This test method indicates the concentration of total watersoluble ions based on their electrolytic mobility. Thus it 

provides an indication of ionic corrosion potential. This 

method is used to determine contamination to the pipeline 

surface caused by abrasive blasting. 

ISO 8501-1-1988: Preparation of Steel Substrates Before Application of Paints and Related 

Products - Tests for the Assessment of Surface Cleanliness - Part 2: 

Laboratory Determination of Chloride on Cleaned Surfaces (1992) 

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ISO 8502-2-1992: Preparation of Steel Substrates Before Application of Paints and Related 

Products - Tests for the Assessment of Surface Cleanliness - Part 2: 

Laboratory Determination of Chloride on Cleaned Surfaces (1992) 

ISO 8502-6:1995: Preparation of Steel Substrates Before Application of Paints and Related 

Products - Tests for the Assessment of Surface Cleanliness - Part 6: 

Extraction of Soluble Contaminants for Analysis - The Bresle Method 

(1992) 

ISO 8502-9:1998: Preparation of Steel Substrates Before Application of Paints and Related 

Products - Tests for the Assessment of Surface Cleanliness - Part 9: Field 

Method for the Conductometric Determination of Water-Soluble Salts 

(1998) 

4.A.3.b: Coatings 

The importance of both visual and non-visual contamination is recognized in the standards. Only 

two standards for FBE specify maximum levels of visual contamination requirements (Table 6). 

Standards for non-visual contaminations are being developed (NACE TG259). 

Table 6: Specifications for Visual Interface Contamination of Various Coatings 

Coatings Maximum Interface contamination, % 

As required by (Standards) NACE CSA AWWA 

Asphalt N/A N/A N/A 

Coal tar (plant) Not specified Not specified 

Coat tar (field) Not specified 

Tape Not specified Not specified 

Tape (for joints) 

FBE (plant) 30 30 Not specified 

FBE (field) Not specified 

Liquid epoxy Not specified 

Liquid urethane Not specified 

2-layer Not specified Not specified Not specified 

3-layer Not specified 

Composite Not specified 

Wax Not specified 

4.B. STEEL-COATING INTERFACE 

4.B.1. Adhesion 

There is some evidence that good adhesion may be related in part to flexibility. This may 

account for the use of instruments that measure hardness to provide a measure of adhesion. It is 

evident that many adhesion tests are essentially subjective. This is not peculiar to adhesion tests, 

but may be more important than in other tests because of the absence of an absolute criterion 

against which a test value may be compared. It is also true that results of an adhesion test, 

subjective or otherwise, are not necessarily an unequivocal criterion of coating quality. This is 

true even at the laboratory level because of the largely uncontrollable variables that exist in the 

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preparation of test samples. When application under field conditions is considered, the value of 

adhesion tests may be even less significant. 

It is almost impossible to rate the various adhesion tests by their merits. It may be assumed that a 

test producing results in numerical values is more useful than a subjective test relying solely on 

19 the subjective assessment of the tester . 

Adhesion is a summation of a wide variety of forces that hold a coating to a substrate. Although 

adhesion is widely considered as a single property, it has not been identified as such, nor has it 

been measured directly. It is usually measured by the removal force, which combines many 

factors, including adhesion. 

Numerous test procedures have been developed specifically for evaluating the strength of 

adhesive joints. Many of these tests have been used for evaluating adhesive forces. It must be 

emphasized that the tests do not measure adhesive forces, but measure removal forces. Both 

adhesive and removal forces depend on the same forces, including surface conditions, surface 

geometry, wetting, and brittleness of the coating. 

4.B.1.a. Standards 

Hot-Water Sock

CSA.Z245.20: Section 12.14: Hot-Water Sock (75o

C, 24 hours)

NACE RP394: Appendix N: Hot-Water Sock (66 + 3 oC, 24 hours)

Peel Test 

• ASTM D1000: Standard Test Method for Pressure-Sensitive 

Adhesive-Coated Tapes Used for Electrical and Electronic 

Applications 

Shear Test 

ASTM D1002: Standard Test Method for Apparent Shear Strength of Single-Lap-Joint 

Adhesively Bonded Metal Specimens by Tension Loading (Metal-toMetal) 

Pull-Off Test 

ASTM D4541 Standard Test Method for Pull-Off Strength of Coatings Using Portable 

Adhesion Testers 

Others 

ASTM D2197: Standard Test Method for Adhesion of Organic Coatings by Scrape 

Adhesion 

• ASTM D3359: Standard Test Methods for Measuring 

Adhesion by Tape Test 

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4.B.1.b. Coatings 

Adhesion of coatings is measured differently for different coatings. The commonly used tests 

are hot-water sock, pull-off, shear, and peel. Because of the different types of tests, no 

meaningful comparison can be made either within the standards from one organisation or 

between various standards-making organisation (Table 7). 

Table 7: Specifications for Determining Adhesion of Various Coatings 

Coatings Minimum adhesion strength 

As required by 

(Standards) 

NACE CSA AWWA 

Asphalt N/A N/A N/A 

Coal tar (plant) (Pull) ASTM D 4541 

 2.4 MPa (350 psi) 

(Peel) AWWA C203 

(No peeling) 

Coat tar (field) (Pull) ASTM D 4541 

 2.4 MPa (350psi) 

Tape (Peel) ASTM D1000 

Inner layer: 

60-250 ozf/in. (6.6-27 

N/10-mm) width 

Outer layer: 

40-80 ozf/in. (4.4-8.9 

N/10-mm) width 

(Peel) ASTM D1000 

Inner layer: 

200 ozf/in. (2190 N/m) 

width 

Outer layer: 

20 ozf/in. (200 N/m) 

width 

Tape (for joints) (Peel) ASTM D1000 

20 ozf/in (220 g/cm) 

width 

FBE (plant) (Hot) NACE RP 394 

(Rating 1-3) 

(Hot) CSA Z245.20 

(Rating 1-3) 

(Shear) ASTM D1002 

3000 psi (20,685 kPa) 

FBE (field) (Peel) NACE RP 0402 

(No specification) 

Liquid epoxy (Pull) ASTM D4541 

400 lb/in (2,758 kPa) 

Liquid urethane (Pull) ASTM D4541 

1500 psi (10,350 kPa) 

2-layer Not specified (Peel) CSA Z245.21 

3.0 N 

Not specified 

3-layer (Peel) CSA Z245.21 

19.6 N 

Composite (Peel) CSA Z245.21 

150.0 N 

(Hot) CSA Z245.20 

(75o

C + 28 days) 

1-3 

Wax Not specified 

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Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

4.b.2. Cathodic Disbondment 

This test is an accelerated method for determining comparative characteristics of buried pipeline 

coatings that are designed to function as an electrical barrier. This test measures the coating 

disbondment caused by electrical stress during cathodic protection. The test evaluates the coating 

ability not to loosen or disbond in long-term underground use. The results of this test provide 

only a comparative indication, but no accurate assessment of the coating life in this respect in the 

field performance. The cathodic disbondment test was known in earlier days as the Salt Crock 

test . 

During the CD test carried out over a one-year period, a continuous increase in the disbonded 

area with time was observed. The data were scattered, but suggested a linear time dependence 

after an initial period with a higher disbondment rate. The disbondment rate, or time dependence, 

varies with coating systems. This study suggests that an exposure time of ~ 250 days was 

21 necessary to evaluate the coatings . The results from long-term exposure do not correlate with 

those from short-term experiments. 

22 Table 8 shows that increased negative potential does not increase the disbonded area . The 

differences between the individual results for all types of coating are not significant and are 

within the range of accuracy of the method. The current, both initial and final, increased 

significantly with increased potential on all types of coating. Irrespective of the applied potential, 

in no case was the polarized potential lower than -1.2 V vs. CCS. 

The standard electrode potential for hydrogen evolution is -1.15 V vs. CCS. At and more 

negative then this potential, the reaction kinetics is governed by diffusion control (when gas 

evaluation occurs), not charge control. Increasing the applied potential beyond a certain negative 

potential does not result in any acceleration. As a consequence, there is nothing to be gained by 

23 using applied potentials more negative than -1.15 V vs. CCS in cathodic disbondment tests . 

Cathodic disbondment test results depend on the soil pressure, resistivity, temperature, and 

experiment duration. The cathodic disbondment test results may be misleading if these effects 

24 are not considered . 

A direct method for determining the area of disbondment during a CD test is the measurement of 

double layer capacitance. Since the disbonded area is in contact with the electrolyte, the 

disbonded area is directly related to the double layer capacitance. This technique is 

nondestructive, in situ, and determines the area disbonded automatically. This technique has 

25 been successfully tested in the laboratory . 

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Table 8: Area disbonded vs. applied potential in a cathodic-disbondment test. 

Disbonded Area, mm2 

Coating No 

applied 

Applied Potential (V) vs. Cu/CuSO4 Magnesium 

anode 

Mean 

potential -1 -1.5 -3 -6 

A 520 910 380 440 345 430 501 

B 37 95 100 120 115 56 97 

C 260 230 110 240 105 145 166 

D 65 130 150 150 285 330 209 

E 60 200 180 160 175 185 180 

F 230 550 430 360 465 250 411 

G 128 290 387 300 85 505 313 

Mean 186 344 248 253 225 272 268 

4.B.2.a. Standards 

A comparison of cathodic disbondment standards is presented in Table 9. 

ASTM G8: Standard Test Methods for Cathodic Disbonding of Pipeline Coatings 

ASTM G19: Standard Test Method for Disbonding Characteristics of Pipeline Coatings 

by Direct Soil Burial 

ASTM G42: Standard Test Method for Cathodic Disbonding of Pipeline Coatings 

Subjected to Elevated Temperature 

ASTM G80: Standard Test Method for Specific Cathodic Disbonding of Pipeline 

Coatings 

ASTM G95: Standard Test Method for Cathodic Disbondment Test of Pipeline 

Coatings (Attached Cell Method) 

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Table 9: Comparison of CD standards Std. Dev. Org. 

Std. Coating 

Thickness 

Holiday # and size 

Potential, Cu/CuSO4 

Minimum Surface Area 

Temp. °C (°F) 

Electrolyte Duration, 

days 

Current Meas. 

ASTM G8 Not 

specified 

3, Not less than 3 times the coating thickness, min. 6.35 mm (0.250 in) 

-1.45 to – 1.55 

Not specified 

Room 1% NaCl 30 Not required 

in Method A, Required in Method B 

ASTM G19 Not 

specified 

3 holidays (304.8 mm (12 in); 457.2 mm (18 in.); and 609.6 mm (24 in.)). 

-1.45 Not 

specified 

Room Soil 30 to 18 

months 

Current and pipe-to-soil potential at 0 and 30 days. 

ASTM G42 Not 

specified 

1 Holiday, diameter 3 times thickness of coating (min. 6.35 mm (0.25 in.) 

-1.5 23200 mm2 

(36 in2) 

60 (min) 

Distilled water with 1 wt% ea NaCl, Na2SO4, Na2CO3 

30 Current 

requirement in uA 

ASTM G80 Not 

specified 

3, Not less than 3 times the coating thickness, min. 6.35 mm (0.250 in) 

-1.45 to – 1.55 

92,900 mm2 

(1 sq.ft) 

Room Pot. tap water 

with 1 wt% ea NaCl, Na2SO4, 

Na2CO3 

60 Not reported. 

ASTM G95 Not 

specified 

1, 3.2 mm (0.125 in) 

3 76.2 mm (3 

inch) 

Room Distilled 

water with 3% NaCl 

90 Not reported 

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Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

CSA Z245.20 

(Sec.12.8) 

300 um 1, 3.0 or 3.2 

mm 

-1.5 6.4 (pipe 

wall thickness) x100x100 mm 

20 Distilled 

water with 3% NaCl 

28 Not reported 

-3.0 65 1 

CSA Z245.20 

(Sec. 12.13 (strained at –30oC) 

300 um 1, 3.0 or 3.2 

mm 

-1.5 6.4 20 Distilled 

water with 3% NaCl 

28 Not reported 

CSA Z245.21 

(sec.12.3) 

Varies 6.4 mm -1.5 pipe wall 

thickness x100x100 mm 

20 Distilled 

water with 3% NaCl 

28 Not reported 

CSA Z245.21 

(sec.12.3) 

Varies 6.4 mm -1.5 pipe wall 

thickness x100x100 mm 

Max. design temp. 

Distilled water with 3% NaCl 

28 Not reported 

CSA Z245.21 

(sec.12.3) 

Varies 6.4 mm -3.5 pipe wall 

thickness x100x100 mm 

65 Distilled 

water with 3% NaCl 

1 Not reported 

NACE RP0394 

(Sec.H) 

360 + 50 um 

3 mm -3.5 100 mm sq. 

x 6 mm thick 

66 (150 F) 

Distilled water with 3% NaCl 

28 Not reported 

NACE RP0394 

(Sec.H) 

360 + 50 um 

3 mm -1.5 100 mm sq. 

x 6 mm thick 

66 (150 F) 

Distilled water with 3% NaCl 

1 Not reported 

NACE RP0394 

(Sec.M) (Strained at –18oC) 

360 + 50 um 

3 mm -3.5 100 mm sq. 

x 6 mm thick 

66 (150 F) 

Distilled water with 3% NaCl 

28 Not reported 

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4.B.2.b. Coatings 

All coatings are evaluated for their cathodic disbondment resistance. Although Standards 

standards developed in various organisations have almost similaressentially the same procedure, 

but the conditions of the experiments and the criteria for coating selection differ vastly so much 

that precludes meaningful comparison of the coatings with respect to their cathodic disbondment 

resistance is not possible (Table 10). 

Table 10: Requirements of Cathodic Disbondment Resistance of Various Coatings 

Coatings Maximum Disbonded Area Radius, mm (inch) 

As required by 

(Standards) 

NACE CSA AWWA 

Asphalt 

Coal tar (plant) ASTM G8 

8 (0.3), 60 days

 Not 

specified 

Coat tar (field) ASTM G8 

8 (0.3), 60 days 

Tape ASTM G8 

50 (2), 30 days

 Not 

specified 

Tape (for joints) Not 

specified 

FBE (plant) RP0394 (Appn. H) 

12 

CSA Z245.20 (12.8) 6.5 in 

24 hour or 8.5 in 28 day or 

11.5 in 24 hour for 

production 

Not 

specified 

FBE (field) RP0394 (Appn. H) 

12 

Liquid epoxy Not 

specified 

Liquid urethane Not 

specified 

2-layer ASTM G8 & ASTM 

G42 

Not specified. 

CSA Z245.21 (12.3) 

12 in 28 d at 20o

C 

or max.design temp. or 

12 in 24 h (production) 

Not 

specified 

3-layer CSA Z245.21 (12.3) 

12 in 28 d at 20o

C 

or max.design temp. or 

7 in 24 h (production) 

Composite CSA Z245.21 (12.3) 

12 in 28 d at 20o

C 

or max.design temp. or 

7 in 24 h (production) 

Wax Not specified. 

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4.B.3. Bendability/Flexibility 

Because pipelines expand or contract in response to temperature changes, it is desirable that 

coatings have some flexibility. The methods to assess bendability involve bending a coated 

substrate over a mandrel and determining the amount of bending that takes place before the 

coating cracks. 

The effects of short-radius bends on coating on small-diameter pipe are determined, which 

reflects on the ability of coatings to resist cracking, disbonding, or other mechanical damage. 

Coating failures are detected visually and electrically. This method is useful in coating selection 

and quality control needs. 

Flexibility is also measured in terms of elongation, and the breaking point of the coating. 

4.B.3.a. Standards 

Bendability 

ASTM G10: Standard Test Method for Specific Bendability of Pipeline Coatings 

ASTM G70: Standard Method for Ring Bendability of Pipeline Coatings (Squeeze 

Test) 

Elongation 

• ASTM D522: Standard Test Method for Elongation 

of Attached Organic Coatings with Conical Mandrel Apparatus 

• ASTM D638: Standard Test Method for Tensile 

Properties of Plastics 

• ASTM D1000: Standard Test Method for Pressure-Sensitive 

Adhesive-Coated Tapes Used for Electrical and Electronic 

Applications 

• ASTM D1737: Standard Test Method for Elongation of 

Attached Organic Coatings With Cylindrical Mandrel 

Apparatus 

Breaking point 

• ASTM D882: Standard Test Method for Tensile 

Properties of This Plastic Sheeting 

ASTM D146: Standard Test Methods for Sampling and Testing Bitumen-Saturated Felts 

and Woven Fabrics for Roofing and Waterproofing 

Others 

• ASTM D790: Standard Test Methods for Flexural 

Properties of Unreinforced and Reinforced Plastics and 

Electrical Insulating Materials 

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4.B.3.b. Coatings 

For all coatings, flexibility/bendability is determined. But the testing to determine this 

property differs considerably. In general, flexibility testing includes determining flexibility, 

bendability, elongation, and breaking point of the coatings (Table 11). 

Table 11: Requirements of Flexibility of Various Coatings 

Coatings Flexibility 

As required by (Standards) NACE CSA AWWA 

Asphalt Not available Not available Not available 

Coal tar (plant) 

Coat tar (field) Not specified 

Tape 100 – 400 % 

(ASTM D1000) 

Tape (for joints) 

FBE (plant) NACE RP0394 

(App.K) 

(2o

/PD at –18oC) 

Or 

(1.5o

/PD permanent 

strain, for production 

rings) 

No cracks, tears or 

delamination 

FBE (field) Not specified 

Liquid epoxy 

Liquid urethane 

2-layer ASTM D 638 

Min. 100% 

3-layer ASTM D 638 

Min. 300% 

Composite 

Wax Not specified 

4.C. COATING 

Both the properties of the coating material and the quality control during the application of 

coating determine the reliability of the coating. Several tests are performed to evaluate the 

properties of the raw materials and of the coating material. These tests are classified as common 

(to all coatings) and specific (to a particular coating) tests and are discussed in the following 

paragraphs. 

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Common Tests 

4.C.1. Thermal Conductivity 

During pipeline operations, the temperature of the pipe varies, depending on weather conditions 

and on operating requirements. The measure of thermal conductivity provides information on the 

performance of the coating at different temperatures. 

4.C.1.a. Standards 

ASTM C611: Standard Test Method for Electrical Resistivity of Manufactured Carbon 

and Graphite Articles at Room Temperature 

ASTM E1225: Standard Test Method for Thermal Conductivity of Solids by Means of the 

Guarded-Comparative-Longitudinal Heat Flow Technique 

4.C.1.b. Coatings 

The requirements of thermal conductivity for various coatings are presented in Table 12. 

Table 12: Requirements of Thermal Conductivity for Various Coatings 

Coatings Thermal Conductivity 

As required by (Standards) NACE CSA AWWA 

Asphalt N/A N/A N/A 

Coal tar (plant) 0.16 W/M-K (1.1 

BTU/ft2

/n/F/in) 

(ASTM E1225) 

Not specified 

Coat tar (field) 0.16 W/M-K (1.1 

BTU/ft2

/n/F/in) 

(ASTM E1225) 

Tape Not specified Not specified 

Tape (for joints) Not specified 

FBE (plant) Not specified Not specified Not specified 

FBE (field) Not specified 

Liquid epoxy Not specified 

Liquid urethane Not specified 

2-layer Not specified Not specified 

3-layer Not specified 

Composite Not specified 

Wax Not specified 

4.C.2. Dielectric Strength 

Polymeric coatings are insulators and should have high dielectric strength. 

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4.C.2.a. Standards 

ASTM D149: Standard Test Method for Dielectric Breakdown Voltage and 

Dielectric Strength of Solid Electrical Insulating Materials at Commercial 

Power Frequencies 

ASTM D495: Standard Test Method for High-Voltage, Low-Current, Dry Arc 

Resistance of Solid Electrical Insulation 

4.C.2.b. Coatings 

The requirements of dielectric strength for various coatings are presented in Table 13. 

Table 13: Requirements of Dielectric Strength for Various Coatings 

Coatings Dielectric Strength 

As required by (Standards) NACE CSA AWWA 

Asphalt N/A N/A N/A 

Coal tar (plant) >10 V/um (250 V/mil) 

(ASTM D495)

 Not specified 

Coat tar (field) >10 V/um (250 V/mil) 

(ASTM D495) 

Tape 18,000-22,000 V/mm 

(450 to 550 V/mil) 

(ASTM D1000)

 400 V/mil (15 

V/um) 

Tape (for joints) 6,000 V/single 

thickness & 12,000 

V total system 

FBE (plant) Not specified Not specified 

FBE (field) Not specified 1,000 V/mil (39.4 

V/mm) (ASTM 

D149) 

Liquid epoxy Not specified 

Liquid urethane Not specified 

2-layer 20 kV/mm (500V/mil) 

(ASTM D149) 

Not specified (500 V/mil) 

3-layer Not specified 

Composite Not specified 

Wax 14-79 V/um (350-2000 

V/mil) 

(ASTM D149) 

4.C.3. Electrical Conductivity/Insulation Resistance 

The value of electrical resistivity data in studying the properties of polymers has long been 

recognized. Accordingly, it is useful in studies of pipeline coatings. Electrical resistivity 

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measurements are used to study rates and extent of polymerization, glass transition temperature, 

solid state and dielectric properties, degradation, and related properties. 

14 The resistance of polymeric coatings is high (10 ohms). This high resistance protects the 

pipeline from corrosion. Sophisticated equipment is needed to obtain accurate measurements at 

high resistance. However, the resistance decreases as ground water containing ionic species 

enters into the coating. The ion transport of a freestanding coating can be monitored by using the 

polymeric coating as a diaphragm in an electrolysis cell and by monitoring the electrolysis that 

takes place through, and in spite of, the polymeric coating. 

4.C.3.a. Standards 

ASTM D257: DC Resistance or Conductance of Insulating Materials 

ASTM C611: Standard Test Method for Electrical Resistivity of Manufactured Carbon 

and Graphite Articles at Room Temperature 

ASTM D1000: Standard Test Methods for Pressure-Sensitive Adhesive-Coated Tapes 

Used for Electrical and Electronic Applications 

4.C.3.b. Coatings 

The requirements of electrical resistance for various coatings are presented in Table 14. 

Table 14: Requirements of Insulation/Electrical Resistance for Various Coatings 

Coatings Insulation Resistance 

As required by (Standards) NACE CSA AWWA 

Asphalt N/A N/A N/A 

Coal tar (plant) 1 x 1014 ohm-cm 

(ASTM C611)

 Not specified 

Coat tar (field) 1 x 1014 ohm-cm 

(ASTM C611) 

Tape 450,000 – 550,000 

Megohms

 500,000 megohms 

Tape (for joints) 500,000 megohms 

FBE (plant) Not specified 1.1 x1015 

(ASTM D257) 

FBE (field) 

Liquid epoxy Not specified 

Liquid urethane Not specified 

2-layer Not specified Not specified Not specified 

3-layer Not specified 

Composite Not specified 

Wax 

4.C.4. Indentation/Hardness 

Hardness measurements reflect the resistance of coatings to damage from loads during yard life 

and backfilling. During the service life, the hardness of a pencil needed to rupture a coating is 

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recorded and termed the “pencil hardness.” Since the technician uses hand pressure on the 

pencil, the result of the test is somewhat subjective and can vary from technician to 

technician. Nevertheless, a trained technician can obtain fairly consistent results. Hardness of the 

thick film products should be tested using indentation testers. The resistance of the coating to 

penetration by an indenter is measured using the Knoop or Pfund indentation hardness for 

coatings applied on rigid substrates. 

4.C.4.a. Standards 

ASTM D1474: Standard Test Methods for Indentation Hardness of Organic Coatings 

ASTM D2240: Standard Test Method for Rubber Property—Durometer Hardness 

ASTM D2583: Standard Test Method for Indentation Hardness of Rigid Plastics by 

Means of a Barcol Impressor 

ASTM D785: Standard Test Method for Rockwell Hardness of Plastics and Electrical 

Insulating Materials 

ASTM D3363: Standard Test Method for Film Hardness by Pencil Test 

4.C.4.b. Coatings 

The requirements of hardness for various coatings are presented in Table 15.

Table 15: Requirements of Indentation/Hardness for Various Coatings

Coatings Indentation/Hardness 

As required by (Standards) NACE CSA AWWA 

Asphalt N/A N/A N/A 

Coal tar (plant) Not specified Not specified 

Coat tar (field) Not specified 

Tape Not specified Not specified 

Tape (for joints) Not specified 

FBE (plant) Not specified Not specified 

FBE (field) Not specified 

Liquid epoxy 

Liquid urethane 

2-layer Min. 60 Shore D 

(ASTM D2240) 

Min. 45 Shore D 

(ASTM D2240) 

3-layer Min. 50 Shore D 

(ASTM D2240) 

Composite Min. 60 Shore D 

(ASTM D2240) 

Wax Not specified. 

4.C.5. Penetration Resistance 

This method determines the penetration or deformation resistance of a coating under blunt rod 

loading. The depth or penetration as a result of the blunt rod load is measured with a micrometer 

depth gauge. The result indicates the effects on coatings of concentrated loading from soil and 

other buried objects. 

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4.C.5.a Standards 

ASTM D5: Standard Test Method for Penetration of Bituminous Materials 

ASTM G17: Standard Test Method for Penetration Resistance of Pipeline Coatings 

(Blunt Rod) 

ASTM D937 Standard Test Method for Congealing Point of Petroleum Waxes, 

Including petrolatum 

4.C.5.b. Coatings 

The requirements of thermal conductivity for various coatings are presented in Table 16. 

Table 16: Requirements of Penetration Resistance for Various Coatings 

Coatings Penetration Resistance 

As required by 

(Standards) 

NACE CSA AWWA 

Asphalt N/A N/A N/A 

Coal tar (plant) 2-55 at 50-100 g/s (or 

1.8-3.53 oz/s) 

(ASTM D5) 

5-55 at 50-100 g 

weight per sec (or 1.8-

3.53 oz/s) at 25-46oC 

(ASTM D5) 

Coat tar (field) 2-55 at 50-100 g 

weight per sec (or 1.8-

3.53 oz/s) at 25-46oC 

(ASTM D5) 

Tape 20% (or 30%) with no 

holiday at 22o

C (60oC) 

(ASTM G17) 

25% with no holiday 

at 22oC 

(ASTM G17) 

Tape (for joints) Not specified 

FBE (plant) <10% at 93o

C 

(ASTM G17) 

Not specified <10% at 60oC 

(ASTM G17) 

FBE (field) Not specified 

Liquid epoxy Not specified 

Liquid urethane Not specified 

2-layer 3.0-12.0 mm (0.12 to 

0.47 in) (ASTM D5) 

Not specified 2.5-12 mm at 25o

C, 

100 g/5 s (ASTM G5) 

3-layer Not specified 

Composite Not specified 

Wax 160-290 at 25o

C 

(ASTM D937) 

4.C.6. Water Permeation 

Coatings function as a barrier by physically isolating the substrate from moisture. Entry of water 

is the first step in the development of corrosion cells. It is important to detect the permeation of 

water. 

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Coated samples are immersed and suspended in an aqueous electrolyte for the test duration. 

Electrical measurements (coating capacitance and dissipation factor) are used to measure water 

absorption rate into the material. 

The water vapour sorption isotherms on freestanding coatings are measured in an apparatus that 

26 consists of a Cahn Electrobalance in a high-vacuum environment. The free film is weighed and 

hung on the electrobalance. The initial weight of the sample is recorded before evacuation. The 

evacuation is continued until no further weight loss is observed, at which point the water vapour 

(~ 10% relative humidity) is introduced. The weight increase is recorded and the measurement 

continued until little or no further weight increase is observed. 

4.C.6.a. Standards 

Water Absorption 

ASTM D570: Standard Test Method for Water Absorption of Plastics 

Water Permeability 

ASTM D163: Test Method for Water Vapour Permeability of Organic Coating Films 

ASTM D1434: Standard Test Method for Determining Gas Permeability Characteristics 

of Plastic Film and Sheeting 

ASTM G9: Standard Test Method for Water Penetration into Pipeline Coatings 

Water Transmission 

ASTM D3985: Oxygen Gas Transmission Rate Through Plastic Film and Sheeting Using 

a Coulometric Sensor 

ASTM E96: Standard Test Methods for Water Vapor Transmission of Materials 

ASTM F 372: Standard Test Method for Water Vapour Transmission Rate of Flexible 

Barrier Materials Using an Infrared Detection Technique 

Moisture Content 

ASTM D95: Standard Test Method for Water in Petroleum Products and Bituminous 

Materials by Distillation 

ASTM D2247: Standard Practice for Testing Water Resistance of Coatings in 100% 

Relative Humidity 

4.C.6.b Coatings 

The requirements of water permeation for various coatings are presented in Table 17. 

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Table 17: Requirements of Water Permeation for Various Coatings 

Coatings Water Permeation 

As required 

by (Standards) 

NACE CSA AWWA 

Asphalt N/A N/A N/A 

Coal tar 

(plant) 

0.2% or 0.3 g/30 cm2

 (0.1 

oz/50 in.2) (ASTM D95) 

6.5 x 103 perms (ASTM E96) 

 Not specified 

Coat tar 

(field) 

0.2% or 0.3 g/30 cm2

 (0.1 

oz/50 in.2

) (ASTM D95) 

6.5 x 103 perms (ASTM E96) 

Tape 0.025 to 0.035 g/24 h/100 cm2 

(0.15 to 0.25 g/24 h/100 in.2) 

(ASTM E96) 

0.2% by wt. (ASTM D570) 

0.2% perm (1.15 x10-11 kg 

(pascal.sec.metre2

) max. 

(ASTM E96) 

Tape (for 

joints) 

0.25 perm (1.44 

ng[Pa.s.m2]), max. (ASTM 

E96) 

FBE (plant) 0.5% max. & 

Rating 1-3 

1-3 pass 4-5 Fail 

(AWWA C213) 

FBE (field) Rating 1-3 0.5%-0.6% max 

(CSA 245.20) 

Liquid epoxy Not specified 

Liquid 

urethane 

 3% max 

(ASTM D570) 

2-layer 0.02 wt % 

(ASTM D570) 

Wt % 0.1 max 

(ASTM D570) 

0.2% max. (ASTM D570) 

0.2% perm (1.1 x10-11 kg 

(pascal.sec.metre2

) max. 

(ASTM E96) 

3-layer Wt % 0.1 max 

(ASTM D570) 

Composite Wt % 0.1 max 

(ASTM D570) 

Wax Not specified. 

4.C.7. Chemical Resistance 

Pipeline coatings should be resistant to soil contaminants. The resistance of polymeric coatings 

to the liquid and vapour phases is determined by visible examination and by tests for any loss of 

mechanical or bonding properties. 

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4.C.7.a. Standards 

ASTM G20: Standard Test Method for Chemical Resistance of Pipeline Coatings 

ASTM D543: Standard Practices for Evaluating the Resistance of Plastics to Chemical 

Reagents 

4.C.7.b. Coatings 

The requirements of chemical resistance for various coatings are presented in Table 18. 

Table 18: Requirements of Chemical Resistance for Various Coatings 

Coatings Chemical Resistance 

As required by 

(Standards) 

NACE CSA AWWA 

Asphalt N/A N/A N/A 

Coal tar (plant) Not specified Not specified. 

Coat tar (field) Not specified 

Tape Not specified Not specified 

Tape (for joints) Not specified 

FBE (plant) No blistering 

(HCl, HNO3, NaCl+H2SO4, 

NaCl, distilled water, NaOH) 

(CSA 245.20.Appendix I) 

Not specified. 

FBE (field) Not specified 

Liquid epoxy Immersion for 30 days 

at 24o

C Deionized 

water, Sulphuric acid, 

1%; & NaOH, 1% 

No blistering, peeling, 

and disbondment 

Liquid urethane 10% H2SO4, 30% 

NaCl, 30% NaOH and 

#2 Diesel fuel (5% 

change after 30 days, 

max) (ASTM D543) 

2-layer ASTM G20 – no 

specification 

Not specified 

3-layer Not specified 

Composite Not specified 

Wax Not specified. 

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4.C.8. Blistering 

Blister formation is one of the common modes of failure of FBE coatings when immersed in 

water. The blister formation tendency is evaluated by immersing the coated samples in hot water. 

The temperature should be less than the glass transition temperature of the coating. The 

processes of formation and growth of blisters (including chemical and/or physical breaking of 

bonds between the metal and the film) can be detected by monitoring acoustic emission signals. 

The delaminated areas and the blisters can be detected because of the differences in light 

reflection through the coating27, 28 . 

4.C.8.a. Standards 

ASTM D714: Standard Test Method for Evaluating Degree of Blistering of Paints 

4.C.8.b. Coatings 

No specific coating standards require evaluation of blister formation. 

4.C.9. Weathering 

Effects of outdoor exposure are determined by parallel sets of samples that are aged indoors and 

outdoors. The coatings deteriorate due to atmospheric corrosion. 

4.C.9.a. Standards 

ASTM G11: Standard Test Method for Effects of Outdoor Weathering on Pipeline Coatings 

4.C.9.b. Coatings 

Except for NACE document (RP0185) on extruded polyolefin (which refers to ASTM G11), no 

other standard specifies this test. 

4.C.10 Cohesion 

Cohesion tests are similar to adhesion tests except that the specimen plates are designed so that 

the adhesion area is greater than the specimen cross-sectional area, thus assuring a cohesion 

29 failure within the coating rather than an adhesion failure at the steel-coating interface . 

When bonds between the metal and the coating break or when hydrogen gas evolves, measurable 

acoustic emission signals are emitted. 

4.C.10.a. Standards 

ASTM D879: Specification for Communication and Signal Pin-Type Lime-Glass 

Windows (withdrawn in 1981; there is no replacement) 

ASTM D1000: Standard Test Method for Pressure-Sensitive Adhesive-Coated Tapes 

Used for Electrical and Electronic Applications 

ASTM D1002: Standard Test Method for Apparent Shear Strength of Single-Lap-Joint 

Adhesively Bonded Metal Specimens by Tension Loading (Metal-toMetal) 

ASTM D2197: Standard Test Method for Adhesion of Organic Coatings by Scrape 

Adhesion 

ASTM D3359: Standard Test Methods for Measuring Adhesion by Tape Test 

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ASTM D4541: Standard Test Method for Pull-Off Strength of Coatings Using 

Portable Adhesion Testers 

4.C.10.b. Coatings 

Same as for adhesion. 

4.C.11. Environmental Stress-Cracking Resistance 

Computerized visual imaging based on high-resolution colour image processing is used in 

highway coating inspection. The usefulness of this technique for underground pipelines is not 

30 known . Due to soil stress and wet-dry cycles, the coatings may crack during pipeline corrosion. 

Internal stresses in coatings can be determined by the cantilever and strain gauge methods. A 

coated panel will curve or bend due to forces exerted at the substrate-coating interface as a result 

of stress in the coating. The curvature (deflection) can be measured using an optical microscope 

31 (cantilever method) or using a strain gauge . 

4.C.11.a. Standards 

ASTM D1693: Environmental Stress-Cracking of Ethylene Plastics 

4.C.11.b. Coatings 

The requirements of environmental stress-cracking for various coatings are presented in Table 

19. 

Table 19: Requirements of Environmental Stress-Cracking for Various Coatings 

Coatings Environmental Stress-Cracking 

As required by 

(Standards) 

NACE CSA AWWA 

Asphalt N/A N/A N/A 

Coal tar (plant) Not specified Not specified. 

Coat tar (field) Not specified 

Tape Not specified Not specified 

Tape (for joints) Not specified 

FBE (plant) Not specified. 

FBE (field) 

Liquid epoxy 

Liquid urethane 

2-layer 300 minimum 

for 100% lgepal 

(ASTM D746) 

300 minimum 

for 100% lgepal 

(ASTM D746) 

3-layer 300 minimum 

for 100% lgepal 

(ASTM D746) 

Composite 300 minimum 

for 100% lgepal 

(ASTM D746) 

Wax Not specified. 

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4.C.12. Resistance to Oxidation 

The environment surrounding a pipeline coating can range from a relatively inert environment 

(for example, sandy soil) to a more hostile environment (for example, acidic marsh). When a 

pipeline is operated at elevated temperature (up to 85o

C) in hostile environmental conditions, 

anti-oxidants are incorporated into the coatings. It is advantageous to have a rapid and reliable 

laboratory method to determine the resistance of anti-oxidative additives to degradation. One 

such method is the measure of oxidative induction time. The OIT is the time required for 

oxidation of the coating (for example, polyethylene) to begin. 

Chemiluminescence is a measure of the light given off in the normal oxidation of organic 

materials. In the oxidation sequence, activated peroxides are generated which give off light when 

they fall to their ground state. Chemiluminescence is a measure of that light. 

4.C.12.a Standards 

No standard available 

4.C.12.b. Coatings 

No coating requirement specifies this property. 

4.C.13. Compressive Properties 

The change in mechanical properties, including modulus, should be determined under various 

loading conditions. 

4.C.13.a. Standards 

ASTM D695: Standard Test Method for Compressive Properties of Rigid Plastics 

4.C.13.b. Coatings 

No coating requirement specifies this property. 

4.C.14. Thermal Expansion 

The coating material should have very low thermal expansion 

4.C.14.a. Standards 

ASTM D696: Standard Test Method for Coefficient of Linear Thermal Expansion of Plastics 

Between -30�C and 30�C With a Vitreous Silica Dilatometer 

4.C.14.b. Coatings 

No coating requirement specifies this property. 

4.C.15. Brittleness Temperature 

The temperature and impact conditions at which pipeline coatings exhibit brittle failure should 

be determined. 

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4.C.15.a. Standards 

ASTM D746: Standard Test Method for Brittleness Temperature of Plastics and Elastomers by 

Impact 

4.C.15.b. Coatings 

The requirements of brittleness temperature for various coatings are presented in Table 20. 

Table 20: Requirements of Brittleness Temperature of Various Coatings 

Coatings Brittleness Temperature 

As required by 

(Standards) 

NACE CSA AWWA 

Asphalt N/A N/A N/A 

Coal tar (plant) -29oC (-20oF) 

(AWWA C203)

 -29oC (-20oF) 

(AWWA C203) 

(No cracking) 

Coat tar (field) -29oC (-20oF) 

(AWWA C203) 

Tape Not specified Not specified 

Tape (for joints) Not specified 

FBE (plant) Not specified 

FBE (field) Not specified 

Liquid epoxy Not specified 

Liquid urethane Not specified 

2-layer -70oC or lower 

for F20 

(ASTM D746) 

3-layer -70oC or lower 

for F20 

(ASTM D746) 

Composite -70oC or lower 

for F20 

(ASTM D746) 

Wax Not specified 

4.C.16. Film Thickness 

Coating thickness is an important factor in determining the coating service life and cost. 

Nondestructive measurement of the dry film thickness of coatings on an external steel pipe 

surface is important. Variation in magnetic flux or magnetic attraction due to the presence of 

coating can be calibrated into a thickness measurement. 

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4.C.16.a. Standards 

ASTM G12: Standard Test Method for Nondestructive Measurement of Film Thickness 

of Pipeline Coatings on Steel 

ASTM D4138: Standard Test Methods for Measurement of Dry Film Thickness of 

Protective Coatings Systems by Destructive Means 

ASTM D4414: Standard Practice for Measurement of Wet Film Thickness by Notch 

Gages 

TAPPI T414 Thickness (Calliper) of Paper, Paperboard, and Combined Board 

(Technical Association of the Pulp and Paper Industry) 

4.C.16.b. Coatings 

The requirements of film thickness for various coatings are presented in Table 21. 

Table 21: Requirements of Thickness of Various Coatings 

Coatings Thickness, mm (mil) 

As required by 

(Standards) 

NACE CSA AWWA 

Asphalt N/A N/A N/A 

Coal tar (plant) 3.0-3.6 (120-140) 1.1 (43) (inner + outer 

wrap) 

1.2 (TAPPI T 411) 

Coat tar (field) 3.0 (120) 

Tape 1.250 (50) 0.75 (30) 

Tape (for joints) 1.2-2.2 (46-88) 

FBE (plant) 0.3(12) 0.3 (12) 0.406(16) 

FBE (field) 0.64 (25) 

Liquid epoxy 0.406 (16) 

Liquid urethane 0.5(20) 

2-layer (varies with pipe 

diameter, for CSA&AWWA) 

0.78 (31) 0.7 – 1.25 0.789 (31) – 1.7 (69) 

3-layer (varies with pipe 

diameter, for CSA)

 2-3.22 

Composite 0.67 

Wax 0.15 – 0.36 (6-14) 

(ASTM D1000) 

Specific Tests 

4.C.17. Low-Temperature Cracking Test 

Below certain temperatures, polymer coatings lose elasticity due to solidification and crack. 

4.C.17.a. Standards 

ANSI/AWWA C203 Section 5.3.5: Laboratory Low-Temperature cracking Test 

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4.C.17.b. Coatings 

This is a good Q.C. test for coal tar coatings. 

4.C.18. Composition 

This test provides documentation of the general composition of the coating material. The 

attenuated total reflectance (ATR)-IR technique is an excellent analytical tool and can be used to 

determine if changes are occurring at the metal-coating interface as the system ages. This 

technique detects changes in the spectra due to aging. The main difficulty with this system is the 

requirement of coating onto the ATR cell (cured to the surface). Difficulties are also encountered 

in duplicating the curing conditions that are observed on real pipe and on test panels. The initial 

cure conditions should have a significant effect on the type and amount of bonds formed at the 

interface. A technique needs to be developed to coat the whole cell without coating the end 

surfaces. 

4.C.18.a. Standards 

ASTM D1652: Standard Test Methods for Epoxy Content of Epoxy Resins 

4.C.18.b. Coatings 

This is a good QC test for FBE and epoxy coatings. 

4.C.19. Sag 

As the pipeline coating ages, it will sag (that is, stretch and droop). To simulate the effect of 

aging, the sag test is conducted at higher temperatures than the operating temperature of the 

pipeline. 

4.C.19.a. Standards 

ANSI/AWWA C203 Section 5.3.4: Laboratory High-Temperature Sag Test 

4.C.19.b. Coatings 

This is a good QC test for coat tar coatings. 

4.C.20. Pliability 

Pliability is a measure of the strength of the external layer of a protective coating. 

4.C.20.a. Standards 

ANSI/AWWA C203: Section 5.3.9: Outerwrap Pliability Tests and Section 5.3.14.3: Pliability 

Test 

4.C.20.b. Coatings 

This is a good QC test for coal tar coatings. 

4.C.21. Gel Time 

Measurement of gel time of a coating material provides information on the duration of coating 

application. 

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4.C.21.a. Standards 

CSA Z245.20: Section 12.2: Gel Time of the Epoxy Powder 

NACE RP0394: Appendix D: Gel Time Determination 

AWWA C213: Section 5.3.2.3: Gel Time - Hot Steel Plate 

4.C.21.b. Coatings 

This is a good QC test for FBE and epoxy coatings. 

4.C.22. Particle Size 

The size of the raw material determines the density of the finished coatings. The particle size is 

controlled carefully during the application of the coating. 

4.C.22.a. Standards 

CSA Z245.20: Section 12.5: Particle Size of the Epoxy Powder 

4.C.22.b. Coatings 

This is a good QC test for FBE coating. 

4.C.23. Total Volatile Content 

Release of volatile contents from a coating leads to the formation of voids. 

4.C.23.a. Standards 

NACE RP0394: Appendix G: Determination of Total Volatiles 

4.C.23.b. Coatings 

This is a good QC test for FBE coating. 

4.C.24. Porosity 

To maintain integrity, the coating must be as non-porous as possible. 

4.C.24.a Standards 

CSA Z245: Section 12.10: Porosity of the Coating 

ANSI/AWWA C203: Section 5.3.14.4: Porosity test 

• Refers to ASTM D737 

ASTM D737: Test Method for Air Permeability of Textile Fabrics 

NACE RP0394: Appendix J: Test for Porosity of the Coating 

4.C.24.b. Coatings 

This is a good QC test for FBE coating. 

4.C.25. Viscosity 

The viscosity determines the flow, wetting and spreading during application of the coating. 

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4.C.25.a. Standards CSA Z245.21: Section 12.1: Viscosity 

ASTM D4212: Standard Test Method for Viscosity by Dip-Type Viscosity Cups 

4.C.25.b. Coatings 

This is a good QC test for 2-layer, 3-layer and composite coatings. 

4.C.26. Flow 

To apply the coating uniformly at different locations and to maintain the efficiency of the spray 

gun, the flow should be maintained. In the flow test, the rate of extrusion of molten resins 

through a die of a specified length and diameter is measured under prescribed conditions of 

temperature, load, and piston position in the barrel. 

4.C.26.a. Standards 

ASTM D1238: Standard Test Method for Melt Flow Rates of Thermoplastics by 

Extrusion Plastometer 

AWWA C215: Section 5.3.1.4: Melt-Flow Rate, Type B Adhesive (Refers to ASTM 

D1238) 

CSA Z245.21: Section 12.2: Flow Test 

4.C.26.b. Coatings 

This is a good QC test for 2-layer, 3-layer and Composite coatings. 

4.C.27. Softening Point 

This is a measure of the fluid property of the coating. 

4.C.27.a. Standards 

ANSI/AWWA C203: Section 5.3.13.4: Softening Point Test (Refers to ASTM D36) 

ANSI/AWWA C215: Section 5.3.1.1: Softening Point Type A Adhesive (Refers to ASTM E28) 

ASTM D36: Standard Test Method for Softening Point of Bitumen (Ring-and-Ball 

Apparatus) 

ASTM E28: Standard Test Methods for Softening Point of Resins Derived from Naval 

Stores by Ring-and-Ball Apparatus 

ASTM 1525: Standard Test Method for Vicat Softening Temperature of Plastics 

4.C.27.b. Coatings 

This is a good QC test for coal tar coating. 

4.C.28. Shelf Life 

This test is used to estimate the shelf life of coating materials. 

4.C.28.a. Standards 

NACE RP0394: Appendix C: Shelf Life Determination 

4.C.28.b. Coatings 

This is a good QC test for FBE coating. 

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4.C.29. Filler Content 

This test is used to estimate the filler content 

4.C.29.a. Standards 

AWWA C203: Section 5.3.13.6: Filler Content Test (Refers to ASTM D2415) 

ASTM D2415: Standard Test Method for Ash in Coal Tar and Pitch 

4.C.29.b. Coatings 

This is a good QC test for coal tar coating. 

4.C.30. Density/Specific Gravity 

The weights of free coating in air and water are measured. The loss in weight in water is due to 

the displaced volume of water. The weight in air divided by this volume is the density. An 

analytical balance is used for all weighing. 

4.C.30.a. Standards 

CSA Z245.20: Section 12.6: Density of the epoxy powder 

AWWA C215: Section 5.3.1.3: Specific Gravity, Type A Adhesive (refers to ASTM D71) 

AWWA C215: Section 5.3.1.5: Density, Type B Adhesive (Refers to ASTM D1505) and 

Section 5.3.1.6: Density of Polyolefin resin 

NACE RP0394: Appendix B: Specific Gravity Determination 

ASTM D71: Standard Test Method for Relative Density of Solid Pitch and Asphalt 

(Displacement Method) 

ASTM D 792: Standard Test Methods for Density and Specific Gravity (Relative 

Density) of Plastics by Displacement 

ASTM D1505: Standard Test Method for Density of Plastics by the Density-Gradient 

Technique 

4.C.30.b. Coatings 

This is a good QC test for all powder coatings. 

4.C.31. Tear Strength 

This test is used to determine the tear strength in both the longitudinal direction and in the 

transverse direction. 

4.C.31.a. Standards 

AWWA C203: Section 5.3.14.1: Elmendorf Tear-Strength Test 

4.C.31.b. Coating 

This is a good QC test for coal tar coating. 

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4.C.32. Curing 

32- The extent of curing determines the strength of the coating, whether it is sprayed or brushed

. Shear rheology measurement is extremely useful in determining the rate of build-up of 

physical properties as the curing process proceeds. The measurement is performed by pressing 

the epoxy powder between two flat parallel plates. One plate is oscillated at a constant amplitude 

while the force due to the rheological property of the sample is measured on the other. The plate 

arrangement is surrounded by an environmental chamber providing temperature control. It 

demonstrated that the rheology method provides information on processes occurring in the final 

34 stages of cure . 

The strength of curing is determined by Differential Scanning Calorimetry (DSC) and 

Differential Thermal Analysis (DTA) or by solvent extraction methods37, 38 . 

4.C.32.a. Standards 

CSA Z245.20: Section 12.1: Cure Time of the Epoxy Powder 

CSA Z234.20: Section 12.7: Thermal Characteristics of the Epoxy Powder and Coating 

(This test is used to determine the glass transition temperature and the 

exothermic heat of reaction of epoxy powders and coating and the 

percentage conversion of coatings). 

NACE RP0394: Appendix E: Glass Transition and Heat of Reaction Determination (Glass 

transition temperature by DSC). Round-robin comparisons between 

laboratories have resulted in significant variations in all parameters 

measured. Achieving comparable results between laboratories will require 

strict compliance with this test procedure followed by laboratory 

comparison testing. 

AWWA C210: Section 5.2.2. Refers to ASTM D4752 (Solvent rub test) and ASTM D 

3363 (Pencil hardness) or both. A coating system that has not been cured 

in accordance with the manufacturer’s written instructions may be rejected 

AWWA C222: Section 5.5.1: The coating manufacturer shall be consulted to ascertain the 

proper cure time of the coating prior to inspection and testing. 

4.C.32.b. Coatings 

This is a good QC test for liquid epoxy, FBE, and urethane coatings. 

4.D. COATING-SOIL INTERFACE 

4.D.1. Microbial Resistance 

Microbial degradation of coating materials is well known because the coating components can 

feed microbes. A mixed population of microorganisms, including sulphate-reducing bacteria 

(SRB) and acid-producing bacteria (APB), may be involved in coating degradation. Sandy soils 

favour APB and high-clay soils support populations of both kinds of organisms. Fungi also alters 

optical, mechanical, and electrical properties of polymeric coatings. The resin portion of the 

coating is generally fungus-resistant. Other components such as plasticizers, stabilizers, and 

39 colouring agents may be susceptible to microbial attack . 

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Despite these indications, a quantitative relationship between bacteria and coating damage has 

been difficult to establish. Large samples of most coating materials will sustain extensive 

microbial growth under realistic field conditions for many months without apparent damage to 

the coating. Exposing very small coating samples to large volumes of bacterial culture leads to 

mixed effects. For most coatings, loss of components through water dissolution is the primary 

effect. Bacteria grow through the use of dissolved extracts rather than direct attack on the 

coating. Further, the physical and chemical changes that can be specifically attributed to 

biodegradation are difficult to relate to field performance. 

Generally, the test protocol to evaluate resistance of coatings to microbes involves exposure to a 

naturally occurring microbial environment, followed by performance tests (for example, the CD 

test). 

4.D.1.a. Standards 

ASTM G21: Standard Practice for Determining Resistance of Synthetic Polymeric Materials 

to Fungi 

ASTM G22: Standard Practice for Determining Resistance of Synthetic Polymeric Materials 

to Bacteria 

ASTM E2180: Standard Test Method for Determining the Activity of Incorporated 

Antimicrobial Agent(s) in Polymeric or Hydrophobic Materials 

4.D.1.b. Coatings 

No specification 

4.D.2. Abrasion Resistance 

The relative resistance of steel pipeline coatings to abrasion by a slurry of coarse abrasive and 

water during construction should be evaluated. Information on abrasion resistance can be used 

to specify optimum coating thickness. 

4.D.2.a. Standards 

ASTM G6: Standard Test Method for Abrasion Resistance of Pipeline 

Coatings 

ASTM D968: Standard Test Methods for Abrasion Resistance of Organic 

Coatings by Falling Abrasive 

ASTM D1044: Standard Test Method for Resistance of Transparent Plastics to 

Surface Abrasion 

ASTM D4060: Standard Test Method for Abrasion Resistance of Organic 

Coatings by the Taber Abraser 

4.D.2.b. Coatings 

The requirements of resistance to abrasion for various coatings are presented in Table 22. 

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Table 22: Requirements for Abrasion Resistance of Various Coatings 

Coatings Thickness, mm (mil) 

As required by 

(Standards) 

NACE CSA AWWA 

Asphalt N/A N/A N/A 

Coal tar (plant) Not specified Not specified 

Coat tar (field) Not specified 

Tape Not specified 

Tape (for joints) 

FBE (plant) 300 mg per 5000 

cycles 

(ASTM D4060) 

Not specified 0.3 (5000 cycles-gm 

loss) 

(ASTM D1044) 

FBE (field) Same as FBE Plant 

Liquid epoxy Not specified 

Liquid urethane 100 mg loss per 

1000 cycles 

(ASTM D4060) 

2-layer Requirement not 

specified 

(ASTM G6) 

Not specified Not specified 

3-layer Not specified 

Composite Not specified 

Wax Not specified 

4.D.3. Impact Resistance 

The resistance of pipeline coatings to mechanical damage during shipping, handling, installation 

and impacts from backfilling should be determined. The effects of backfilling rocks in damaging 

the coatings are determined visually, or electrically, by measuring the amount of dropped 

material required to pierce through the coating to bare metal. 

4.D.3.a. Standard 

ASTM G13: Standard Test Method for Impact Resistance of Pipeline Coatings 

(Limestone Drop Test) 

ASTM G14: Standard Test Method for Impact Resistance of Pipeline Coatings (Falling 

Weight Test) 

ASTM D256: Standard Test Methods for Determining the Izod Pendulum Impact 

Resistance of Plastics 

ASTM D2794: Test Method for Resistance of Organic Coatings to the Effects of Rapid 

Deformation (Impact) 

4.D.3.b. Coatings 

The requirements of impact resistance for various coatings are presented in Table 23. 

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Table 23: Requirements for Impact Resistance of Various Coatings 

Coatings Impact Resistance 

As required by 

(Standards) 

NACE CSA AWWA 

Asphalt N/A N/A N/A 

Coal tar (plant) Not specified 650 g ball, 8-ft drop 

(25oC) 

(AWWA C203) 

1016 in2

 (6,452 – 

10,323 mm2) – max. 

Coat tar (field) Not specified 

Tape 30 lbf.in. (3.4 J) 

(ASTM G14) 

No holidays after 30 

drops 

(ASTM G13) 

25 lbf.in. (2.8 N.m) 

(ASTM G14) 

Tape (for joints) Not specified 

FBE (plant) 1.5 J (13 in.-lb) min 

(ASTM G14) 

1.5 J 100 in-lbf (11.3 Nm) 

FBE (field) 1.5 J (13 in.-lb) min 

(ASTM G14) 

Liquid epoxy Not specified 

Liquid urethane 40 in.lbs (0.46 kg.m). 

minimum 

(ASTM D2794) 

2-layer (ASTM G14) 

No specification 

3.0 J/mm of 

actual total 

coating thickness 

25 lbf.in (2.8 N.m) min. 

(ASTM G14) 

3-layer 3.0 J/mm of 

actual total 

coating thickness 

Composite 3.0 J/mm of 

actual total 

coating thickness 

Wax Not specified. 

4.D.4. Freeze-Thaw Stability 

This test determines the effect of freezing and thawing on coating adhesion. This test is 

important for operation in low-temperature climates. A freeze-thaw test can be performed by 

changing either the frequency of the freeze/thaw conditions or the temperature differential. 

Coating properties (usually adhesion) are determined before and after the freeze-thaw test. 

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4.D.4.a. Standards 

ASTM D2243: Test Method for Freeze-Thaw Resistance of Waterborne Paints 

ASTM D2337: Test Method for Freeze-Thaw Stability of Multicolour Lacquers 

4.D.4.b. Coatings 

No coating standard specifies this requirement. 

4.D.5. Resistance to Elevated Temperature 

Operating temperatures of pipelines continue to increase; =e.g., pipelines carrying oils and 

operate at temperatures up to 150oC. The performance of coatings should, therefore, be evaluated 

at operating temperatures. 

4.D.5.a. Standards 

ASTM D2485: Standard Test Methods for Evaluating Coatings for High Temperature Service 

ASTM D3012: Standard Test Method for Thermal-Oxidative Stability of Propylene Plastics 

Using a Specimen Rotator Within an Oven 

4.D.5.b. Coatings 

The requirements of minimum operational temperature requirements of various coatings are 

presented in Table 24. 

Table 24: Requirements of Maximum Operational Temperature of Various Coatings 

Coatings Temperature, max, o

C (oF) 

As required by 

(Standards) 

NACE CSA AWWA 

Asphalt N/A N/A N/A 

Coal tar (plant) 71-110(160-230) Not specified. 

Coat tar (field) 71-110(160-230) 

Tape -30-90 (-22-194) Not specified 

Tape (for joints) Not specified. 

FBE (plant) Not specified Not specified 

FBE (field) 

Liquid epoxy Not specified 

Liquid urethane Not specified 

2-layer Not specified 

3-layer Not specified 

Composite Not specified 

Wax 

4.D.6. Compatibility and Repairability 

Coating materials used on joints, couplings, irregular fittings and patched areas should be 

compatible with main-line coatings. The performance of joint and repair coatings depends on the 

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bond to the substrate and to the original coating, the moisture seal at the joints, and water 

absorption. 

4.D.6.a. Standard 

ASTM G18: Standard Test Method for Joints, Fittings, and Patches in Coated Pipelines 

ASTM G55: Standard Test Method for Evaluating Pipeline Coating Patch Materials 

4.D.6.b. Coatings 

Specific standards to qualify joint/repair/rehabilitation coatings are available. Standards to 

determine compatibility of mainline and joint coatings are not available. 

4.E. PIPE-SOIL INTERFACE (PRESENCE AND/OR FORMATION OF HOLIDAYS) 

4.E.1. Holiday Detection 

Discontinuities or thin spots in dielectric pipeline coatings are determined by an impressed 

voltage. Electrical leakage paths indicate coating discontinuity holidays such as uncoated 

regions, bubbles, voids, cracks, thin spots, metallic inclusions or contaminants. With over 

10,000 km of pipelines buried in widely varying soil types, environments, and terrain conditions, 

pipeline companies rely on the corrosion protection of coatings as a primary method for 

maintaining the integrity of their pipelines. More than 150 years ago, in his book Two Years 

Before the Mast, Richard Henry Dana Jr. wrote of the “holyday,” a reference to the application 

of tar to the ship’s rigging as a protection against the sea water. The term “holiday” has carried 

over to general use in the pipeline industry, retaining its original meaning, as a defect in the 

40 coating . One of the major concerns of using polymer coatings to protect pipelines is the 

presence or development of holidays. Various electrical methods have been developed for 

detecting coating faults before installation of the pipe. The most common method uses an 

electrical probe energized by alternating or pulsating high voltage. Such devices are commonly 

41 referred to as “jeepers” or “holiday detectors” . Any holidays detected at the time of installation 

are repaired. 

During operation, some coatings lose their integrity and ultimately fail to provide the service for 

which they were intended to perform according to the specifications. When a coating fails, the 

problems can be more serious than just a failed coating. Therefore, a failed coating may be more 

harmful and costly than a bare pipeline. For example, when shielding occurs, increased current 

is required. . But, very little, if any, of this increased current reaches the steel surface. The 

investment made in the coating and their applications are lost. Therefore, it is not only important 

to choose and apply the best coating, but also to monitor the performance of the coating on a 

buried pipeline continuously. Most of the techniques for monitoring the coating quality are 

electrical in nature. The techniques can be divided into DC (direct current) methods and AC 

(alternating current) methods. 

Because the techniques are electrical in nature, calcareous deposits resulting from the application 

of cathodic protection or large accumulations of loose corrosion products may increase the 

electrical resistance of a coating defect, making detection of defects difficult. Some techniques 

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that monitor pipeline capacitance may be used to detect coating damage even if the bare 

pipe is not directly contacting the soil. 

The four DC methods all involve the application of cathodic protection current to the pipeline, 

the cyclical interruption of this current, and the measurement of the resulting “on” and “off” DC 

potentials. 

The measurement of pipe-to-soil potentials is a common component of all four DC techniques. 

The success of the DC method depends on the ability to measure both the on-potential and the 

off-potential, and to interrupt cathodic protection synchronously. 

All DC methods are susceptible to errors resulting from stray DC current interference. Wherever 

practical, sources of such interference, such as foreign cathodic protection rectifiers and DC 

welding generators, should be de-energized during the test period. 

The close-interval survey (CIS) and the DC voltage gradient (DCVG) methods are very similar, 

and can be conducted using standard instrumentation (reference electrodes, voltmeter, current 

interrupter). Both methods involve the evaluation of DC voltages in the vicinity of coating 

defects; the only difference between them is that the CIS method uses pipe-to-soil potential 

measurements, whereas the DCVG method uses voltage gradients measured in the soil between 

two reference electrodes. 

Since the CIS method requires that the trailing pipe lead wire be picked up following the test, it 

is the more laborious of the two methods, but it has the added benefit of providing cathodic 

protection potential data. 

Both methods produce a fault severity rating, which can be correlated with pipe depth and soil 

resistivity to provide an indication of percent coating damage. Both methods require complete 

access to the pipeline, and become less sensitive to coating defects as pipe depth increases. 

The cathodic protection current requirements (CPCR) and the coating conductance (CC) 

methods are also similar, and can be conducted using standard instrumentation. Both require the 

measurement of CP currents at each of the pipe sections, so that the CP current density being 

applied to that pipe section can be determined. This determination requires a magnetometer or 

clamp-on ammeter, or IR drop test lead (that is, as a voltage drop over that pipe section). 

Although it is preferable to monitor potentials at several locations along the pipe, potentials 

measured at each end of the pipe may be sufficient. Both tests are applicable regardless of pipe 

depth. 

The CPCR technique requires that cathodic polarization (that is, polarized off potential minus 

static potential) be determined, whereas the CC technique requires the measurement of the 

voltage drop across the coating. The CPCR technique provides information on the polarization 

2 occurring per unit of applied current density (in mV/mA/ft ), whereas the CC technique provides 

2 coating conductance (in siemens/ft ). 

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The polarization per unit of current density determined using the CPCR technique is generally 

indicative of the quality of the coating. Polarization also depends on soil moisture, temperature, 

and aeration. As a result, it would be difficult to correlate the results with percent coating 

damage consistently for a wide range of soil conditions. Furthermore, this technique requires 

that static potentials be measured prior to the application of cathodic protection current, and that 

a sufficient amount of time be allowed for polarized potentials to reach a steady state. 

The CC technique can be conducted without any knowledge of static potentials and requires only 

that the polarized potentials be at a steady state. Since coating conductance depends primarily on 

defect size and soil resistivity, an index could be formulated relating percent bare area with 

coating conductance over a range of soil resistivities. 

AC methods all require the use of special equipment. The AC voltage gradient (ACVG) 

technique, more commonly known as the Pearson method, involves the detection and 

measurement of voltage gradients at coating defects resulting from the application of an AC 

signal to the pipeline. Since it is similar to the DCVG and CIS techniques, it is subject to the 

same limitations of access required to the entire pipeline. The other two AC methods, current 

attenuation (CAT), and transwave system (TS), do not share these limitations, but require more 

technical sophistication. 

Electrochemical impedance spectroscopy (EIS) is a technique that has been used to conduct 

laboratory evaluations of coatings, but has seen limited field use due to the complexity of the 

instrumentation and analysis. The required equipment is expensive and analysis procedures are 

complex. As a result, EIS is not widely used to monitor pipeline coatings in the field. 

The TS technique involves the analysis of waveforms generated by CP rectifiers. Attenuation of 

these waveforms along the pipelines is a function of the characteristics of the pipe, soil, and 

waveform frequency, as well as the quality of the coating. Waveform readers at each end of the 

pipe section record information that is subsequently analyzed to provide attenuation data, which 

can then be correlated with coating quality. The measurement and analysis of the TS technique 

is complex. 

The DC techniques are susceptible to stray current, whereas the AC techniques are susceptible to 

induced AC, although electronic filtering can be used to minimize the effects of induced AC. All 

eight techniques were evaluated for their ability to monitor coatings on a bored crossing. The 

techniques were scored based on their accuracy, applicability, efficiency, equipment availability 

and on the ease of use42,43 . 

The CC technique evaluating coating quality received the highest score in this assessment, and is 

the only DC method that can practically be considered for use on pipelines. It can be conducted 

by a single corrosion technician with no special training, using only standard equipment, except 

for some means of measuring pipe current. It does not require complete access to the pipeline, 

and it is applicable regardless of pipe depth. 

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Of the four AC techniques, the SA technique received the highest score, and is the only AC 

technique that could be considered for this application. It too can be conducted by a single 

corrosion technician. It does not require complete access to the pipeline, and it is applicable 

regardless of pipe depth. However, this technique was rated slightly lower than the CC 

technique because of the special equipment and training requirements. 

The EIS and TS techniques were reported to be accurate, and are applicable to bored crossings, 

but the special expertise and equipment required for these techniques prohibits their use for 

pipeline coating monitoring. 

4.E.1.a. Standards 

ASTM G62: Standard Test Methods for Holiday Detection in Pipeline Coatings 

4.E.1.b. Coatings 

No specific standard is available either for above ground or for in-the-ditch techniques to 

monitor underground coating deterioration. 

5. SUMMARY 

• There is a good understanding in the industry of the important properties that are 

detrimental to pipeline coating behaviour. 

• Several standards are available to test those properties that are detrimental to pipeline 

coatings. 

• Standards developed by different organisations have essentially the same requirements 

for evaluating some properties of the coating (e.g., surface profile), but different 

requirements for evaluating other properties (e.g., cathodic disbondment and adhesion). 

• Properties for which standards from different organizations have different requirements 

are also properties considered important for the coating performance; i.e., cathodic 

disbondment and adhesion. Harmonization of standards to evaluate these properties will 

be very useful. 

• Correlation of performance of coatings in standard tests and in the field has not been well 

documented, nor is such a correlation a specified requirement in any of the standards. 

• To date, no studies have been successful in establishing a correlation between field 

performance and performance in standard testsNo common industry database on the 

performance of coatings in the field is available. 

• Development of a capability to predict long-term coating performance from test data 

established in short-term standard tests is an industry priority. 

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6. REFERENCES 

1 K.G. Compton, “Selection of Protective Coatings for Metals,” Corrosion 4(3) (1948), 

p.112. 

2 E.R. Allen, “A Coating Evaluation Testing Program,” Corrosion 14(12) (1958), p.546t. 

3 E.Senkowski, “Standard Laboratory Tests for Pipeline Coatings,” Materials 

Performance,” 18 (8) (1979), p.23. 

4 J.L.Banach, “Evaluating Design and Cost of Pipe Line Coatings, Pipe Line Industry, (4) 

(1988), p.37) and Pipeline Coaings - Evaluation, Repair, and Impact on Corrosion 

Protection Design and Cost, NACE 87/Paper #29. 

5 S.J. Lukezich, J.R. Hancock, B.C.Yen, and P.Werner, “Prediction of the Field 

Performance of Anti-Corrosion Coatings for Buried Steel Pipelines,” 1992 International 

Gas Research Conference, p.512. S.J. Lukezich, J.R. Hancock, B.C.Yen, “State-of-theArt for Use of Anti-Corrosion Coatings on Buried Pipelines in the Natural Gas Industry,” 

Gas Research Institute, GRI-92/0004, April 1992. Werner, S.J. Lukezich, “Selection and 

Use of Anti-Corrosion Coatings for Corrosion Control of Buried Natural Gas Pipelines,” 

92-DT-63. 

6 R.N.Sloan, “50 Years of Pipe Coatings We Have Come a Longway, NACE

CORROSION 1993, Paper # 17 (1993), Houston, Texas.

7 N. Sridhar, S.Dunn, and M.Seth, “Application of a General Reactive Transport Model to 

Predict Environment Under Disbonded Coatings, Corrosion, 57 (7), 2001, p.598. 

8 M.E.Orazem, J.M.Esteban, K.J.Kennelley, and R.M.Degerstedt, “Mathematical Models 

for Cathodic Protection of an Underground Pipeline with Coating Holidays: Part 1­

Theoretical Development, Corrosion 53(4), 1997, p.264 

9 F.M.Song, D.W.Kirk, J.W.Graydon, and D.E.Cormack, “Steel Corrosion Under a 

Disbonded Coating with a Holiday – Part 2: Corrosion Behavior” Corrosion 59(1), 2003, 

p.42. 

10 S.Papavinasam and R.W.Revie, “Coating Gap Analysis”, PRCI Report #L51971. 

11 S. Papavinasam and R.W.Revie, “Coatings for Pipelines”, in “Coatings for Corrosion 

Protection: Offshore Oil and Gas Operation Facilities, Marine Pipelines, and Ship 

Structures, Ed. C.Smith, T.Siewert, B.Mishra, D.Olson, and A.Lassiegne, NIST Special 

Publication 1035, p. 178. 

12 A.N. McKelvie, “Can Coatings Successfully Protect Steel? What Are the Ingredients of 

Success?” MP 19(5) (1980), p.9. 

13 T. Svartdal and W.H. Thomason, “Qualitative Versus Quantitative Assessment of 

Coating Quality in CP/Coating Applications, NACE CORROSION Conference 93, Paper 

# 447, 1993, Houston, Texas. 

14 Rodríguez,V.; Castaiieda,L.; Luciani,B., “Effect of Contaminants on FBE Performance” 

NACE Corrosion 98, Paper #612, 1998, Houston, Texas. 

15 P.E.Partridge, “Effects of Phosphoric Acid Treatment on the Performance of FBE

Coatings”, PR247-9511, October 1997.

16 C.C.Chappelow, G.R.Cooper, C.S.Pinzino, B.LaRue, Rose, and S.R.Spurlin, “Effect of 

Substrate Contaminants on the Performance of Fusion-Bonded Epoxy Pipeline Coatings”, 

AGA Project #. Pr-138-907, January 1992. 

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17 Vincent,L.; “Surface Preparation Standards”, NACE Corrosion 

conference 2001, Paper # 1659, Houston, Texas. 

18 J.A.Beavers, “Assessment of the Effects of Surface Preparation and Coatings on the 

Susceptibility of Line Pipe to Stress-Corrosion Cracking”, PR186-917, February 1992. 

19 Adhesion Fundamentals and Methods of Testing Organic Coatings. N. Hamner, MP, 9 

(5) (1970), p.31 and Line Pipe Coating Analysis Volume II: Topical Report on Adhesion, 

November 1978, AGA Catalog # LOOO37.

20 L.R. Shepperd, “Determining the Effect of Formulation on Physical Properties of Asphalt 

Mastic Coatings,” Corrosion 17 (4), (1961), p.157t. 

21 Laboratory Evaluation of Coatings, MP 1 (6) (1962), p.10. 

22 H.M. Smith, M.F. Bird, and R.H. Penna, “Examination of Tests for Buried-Pipe 

Coatings” MP 30 (1) (1991), p.18. 

23 NACE CORROSION 2000/Paper #758. 

24 J. Kellner, “Laboratory Evaluation of In-Ground Cathodic Disbondment of Pipeline 

Coatings” MP 25 (9) (1986), p.20 

25 J. Kellner, “Nondestructive Evaluation of Cathodic Disbondment. MP 22 (7) (1983), 

p.25. 

26 Line Pipe Coating Analysis Volume 1: Laboratory Studies and Results. (Appendix A: 

Background and Data for the Characterisation of Basic Coating Materials and Free 

Films), November 1978, American Gas Association, A.G.A. Catalog # L00036. 

27 T. Tsuru, A. Sagara, and S. Haruyama, “Acoustic Emission Measurements to Evaluate 

the Degradation of Coating Films,” Corrosion 43 (11) (1987), p.703. 

28 J. Kellner and J.M. Serra, “Recent Developments in Polymer Pipeline Coatings,” Pipes 

and Pipelines International, November-December, 1995. 

29 L.R. Shepperd, “Determining the Effect of Formulation on Physical Properties of Asphalt 

Mastic Coatings,” Corrosion 17 (4), (1961), p.157t. 

30 A. Zdunek, G. Shubinsky, K.H. Jan, “Inspection and Evaluation of Protective Coatings 

by Visual Imaging Techniques,” NACE CORROSION 95/Paper # 592, Houston, Texas. 

31 Y. Korobov and L. Salem, “Stress Analysis as a Tool in Coatings Research,” MP 29 (4) 

(1990), p.30. 

32 P.E. Partridge, “Maximizing the Accuracy and Precision of Cure Determination of Fusion 

Bonded Epoxy by Differential Scanning Calorimetry, NACE CORROSION 2000/Paper # 

0770. 

33 G. Temple and K.E.W. Coulson, “The Use of Differential Scanning Calorimetry to 

Determine Coating Cure,” MP 24 (11) (1985), p.17. 

34 Gray, W.H. Lunn, and O. Mcardle, “Evaluation of Epoxy Pipeline Coatings,” MP 22 (7) 

(1983), p.9. 

35 Neal, “Fusion-Bonded Epoxy Coatings-Cure and Glass Transition Temperatures,” MP 32 

(2) (1993), p.49. 

36 G. Mills, “Interpretation of Differential Thermal Data Analysis for Fusion Bonded Epoxy 

Powder Coatings,” MP 23 (6) (1984), p.45. 

37 Neal, “Fusion-Bonded Epoxy Coatings-Cure and Glass Transition Temperatures,” MP 32 

(2) (1993), p.49. 

38 Neal, “Fusion-Bonded Epoxy Cure by solvent Extraction,” MP 33 (11) (1994), p.26. 

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39 T.R. Jack, G.V. Boven, M.Wilmott, and R.G. Worthingham, “Evaluating Performance of 

Coatings Exposed to Biologically Active Soils” MP 35 (3) (1996), p.39. 

40 D.E. Stearns, M.W. Belson, and R.H. Lee, “Technical Factors in Testing Pipe Line 

Coatings”, Corrosion 5 (10) (1949), p.342 

41 M. Olyphant, “Corona Breakdown Jeeping as a Factor in Pipeline Coatings”, Materials 

Performance 4 (9) (1965), p.8. 

42 R.G. Wakelin, “In-Situ Evaluation of Directional Drill/Bore Coating Quality Directional 

Drill/Bore Coating Quality”, PRCI Contract PR-262-9738, Report - October 1998, 

Appendix G, (Interim Report Sept./97). 

43 R.W. Gummow, S.M.Segall, and R.G.Wakelin, “Coating Quality Testing of Directionally 

Drilled Pipe Sections”, CORROSION2000/Paper 764, NACE CORROSION 

CONFERENCE (2002), Houston, Texas. 

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ASTM D 01.48 

Durability of Pipeline Coatings and Linings

Committee Chair, Don Kathrein, Tapecoat/Royston,

Sub-committee of ASTM D 01, Paints and Related Coatings, Materials and Applications

 Staff Manager, Timothy Brooke, ASTM

Scope: ASTM D 01.48 Committee creates, approves fox ballot, rejects, reviews, 

modifies and ballots the ASTM standards that directly relate to pipeline coatings and 

linings. All new standards, standard renewals and non-editorial changes are re-balloted. 

Membership: Open to members of ASTM (annual fee required). Committee normally consists 

of volunteer members representing pipeline owners and operators, steel pipe manufacturers, 

pipeline coating manufacturers, pipeline;lining manufacturers, testing laboratories, contractors, 

academics, government agency members and interested individuals. 

Meeting: Traditionally, twice per year (Jan. & Jun.). Extra meetings if necessary. All 

standards are reviewed at least every five years. Task groups may be formed to deal with special 

issues regarding standards or standards themselves. 

Standards: ASTM D 01.48 is currently responsible for 18 standards. These are well 

established pipeline coating industry, minimum testing standards for: 

• abrasion resistance 

• cathodic disbondment resistance (6 standards) 

• water penetration resistance

• outdoor weathering resistance 

• impact resistance 

• blunt rod penetration resistance 

• chemical resistance 

• bendability (2 standards) 

• holiday detection 

• non-destructive thickness determination 

• joints, fittings and patching materials evaluation (2 standards) 

These ASTM standards are widely referenced in other organization's standards or recommended 

procedures (ANSI/AWWA, NACE, etc.) 

Status: Eight standards have been reviewed, re-balloted and re-approved since 2001. Seven 

additional standards have been reviewed and will be re-balloted this summer. The remaining three 

standards in the five year cycle will be reviewed at the Jun 2005 meeting in Pittsburgh, PA. 

The most common revision is the addition of Precision and Bias statements to standards that 

have not previously addressed Precision and Bias. 

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One standard, ASTM G l3, the impact resistance by limestone drop standard, was reviewed and 

removed from the list of standards. Reasons for the removal of the standard included: 

1. lack of use by testing laboratories contacted 

2. lack of use by coating manufacturers contacted 

3. lack of correlation to actual field conditions (improper design of test apparatus) 

4. availability of ASTM G 14 impact resistance standard 

5. possible OSHA concerns with dust generated in the laboratory from the numerous 

limestone drops. 

Task Group: A task group has been formed to investigate and resolve the controversy between 

the "current divider" school and the "voltage divider" school of circuit design for cathodic 

disbondment testing. 

Trends: ASTM D 01 meetings with ISO counterparts to harmonize individual standards 

between ASTM and the international standards community. 

Challenges: Keeping ASTM D 01.48 committee membership and attendance at a sufficient 

level to prevent being absorbed into a committee with a larger scope and membership that could 

switch the control of the pipeline industry standards away from the Pipeline industry 

community. 

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ASTM D 01.48 

Sub-Committee on Durability of Pipeline Coating and Linings 

18 ACTIVE standards and 9 WORK ITEMS in progress (May 2005) 

18 ACTIVE standards under the jurisdiction of D01.48: 

D6676-01e1 Standard Test Method for Cathodic Disbonding of Exterior Pipeline Coatings 

at Elevated Temperatures Using Interior Heating 

G6-88(1998) Standard Test Method for Abrasion Resistance of Pipeline Coatings. See also 

WK2881 for information on a proposed revision to this standard. 

G8-96(2003) Standard Test Methods for Cathodic Disbonding of Pipeline Coatings 

G9-87(1998) Standard Test Method for Water Penetration into Pipeline Coatings. See also 

WK2882 for information on a proposed revision to this standard. 

G10-83(2002) Standard Test Method for Specific Bendability of Pipeline Coatings 

G11-04 Standard Test Method for Effects of Outdoor Weathering on Pipeline 

Coatings. See also WK5645 for information on a proposed revision to this 

standard. 

G12-83(1998) Standard Test Method for Nondestructive Measurement of Film Thickness of 

Pipeline Coatings on Steel See also WK2883 for information on a proposed 

revision to this standard. 

G14-04 Standard Test Method for Impact Resistance of Pipeline Coatings (Falling 

Weight Test) See also WK5646 for information on a proposed revision to this 

standard. 

G17-88(1998) Standard Test Method for Penetration Resistance of Pipeline Coatings (Blunt 

Rod) 

G18-88(1998) Standard Test Method for Joints, Fittings, and Patches in Coated Pipelines. 

See also WK2884 for information on a proposed revision to this standard. 

G19-04 Standard Test Method for Disbonding Characteristics of Pipeline Coatings by 

Direct Soil Burial. See also WK5647 for information on a proposed revision to 

this standard. 

G20-88(2002) Standard Test Method for Chemical Resistance of Pipeline Coatings 

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G42-96(2003) Standard Test Method for Cathodic Disbonding of Pipeline Coatings 

Subjected to Elevated Temperatures 

G55-88(1998) Standard Test Method for Evaluating Pipeline Coating Patch Materials 

G62-87(1998)e1 Standard Test Methods for Holiday Detection in Pipeline Coatings 

G70-81(1998) Standard Test Method for Ring Bendability of Pipeline Coatings (Squeeze 

Test) 

G80-88(1998) Standard Test Method for Specific Cathodic Disbonding of Pipeline Coatings. 

See also WK2885 for information on a proposed revision to this standard. 

G95-87(1998)e1 Standard Test Method for Cathodic Disbondment Test of Pipeline Coatings 

(Attached Cell Method). See also WK2886 for information on a proposed 

revision to this standard. 

9 WORK ITEMS in progress under the jurisdiction of D01.48: 

WK2881 Proposed Revision of G6-88(1998) 

WK2882 Proposed Revision of G9-87(1998) 

WK2883 Proposed Revision of G12-83(1998) 

WK2884 Proposed Revision of G18-88(1998) 

WK2885 Proposed Revision of G80-88(1998) 

WK2886 Proposed Revision of G95-87(1998)e1 

WK5645 Proposed Revision of G11-88(1996)e1 

WK5646 Proposed Revision of G14-88(1996)e1 

WK5647 Proposed Revision of G19-88(1996)e1 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 USA Page 95
Leaders in Corrosion Control Technology

Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

NACE International & Pipeline Coatings

Cliff Johnson 

Director, Education 

Larry Christie 

Coatings Market Manager 

Presentation Overview 

Who is NACE International 

How Standards are Developed 

External Coating Standards for Pipelines 

Test Methods & Technical Committee Reports for Pipeline Coatings 

NACE Committee Listings for Pipeline Coatings 

Coating Applicator Training Program 

NACE Legislative Efforts 

Leaders in Corrosion Control Technology 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 USA Page 96
Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

NACE International 

About us 

History 

Founded in 1943 

Began with the Oil & Gas Industry 

Goals – Protect the environment, public safety, and reduce the 

economic impact of corrosion 

Since 1943 NACE International has: 

Produced over 100 standards

Developed numerous training and certification courses

Grown to almost 15,000 members worldwide

Leaders in Corrosion Control Technology 

How NACE Standards 

Are Developed 

More than 300 NACE technical committees 

The committees serve as the technical arm of the association 

Committee members develop NACE standards, reports, and 

conduct informative meetings, symposia, and open forums to 

exchange state-of-the-art technical information. 

NACE International publishes 3 classes of standards: material 

requirements (MR), recommended practices (RP), and test 

methods (TM). 

Leaders in Corrosion Control Technology 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 USA Page 97
Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

Committee Listings for 

Pipeline Coatings 

Specific Technology Group (STG 03) “Coatings and Linings, 

Protective: Immersion and Buried Service” 

• Task Group (TG 247) Coatings, Liquid Epoxy for External Repair, 

Rehabilitations, and Weld Joints on Buried Steel Pipelines 

• Task Group (TG 251) Coatings, Tape for External Repair, 

Rehabilitations, and Weld Joints on Pipelines 

• Task Group (TG 265) Coating Systems, Polyolefin Resin: Review 

of NACE Standard RP0185-96 

Leaders in Corrosion Control Technology 

Committee Listings for 

Pipeline Coatings 

Task Group (TG 281) Coatings, Polyurethane for Field Repair, 

Rehabilitation, and Girth Weld Joints on Pipelines 

Task Group (TG 294) Above Ground Techniques for the Evaluation of 

Underground Pipeline Coating Condition 

Task Group (TG 296) Coating Systems, Wax for Underground Piping 

Systems: Review of NACE Standard RP0375 

Leaders in Corrosion Control Technology 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 USA Page 98
Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

Committee Listings for 

Pipeline Coatings 

Specific Technology Group (STG 35) - “Pipelines, Tanks, Well Casings” 

• Task Group (TG034) Pipeline Coatings, External : Gouge Test 

• Technology Exchange Group (TEG) 033X Pipeline Rehabilitation

Coatings

Leaders in Corrosion Control Technology 

NACE External Coating

Standards for Pipelines

RP0399-2004 Plant-Applied, External Coal Tar Enamel Pipe 

Coating Systems: Application, Performance, and Quality Control 

RP0602-2002 Field-Applied External Coal Tar Enamel Pipe 

Coating Systems: Application, Performance, and Quality Control 

RP0394-2002 Application, Performance, and Quality Control of 

Plant-Applied Fusion-Bonded Epoxy (FBE) External Pipe Coating 

RP0402-2002 Field-Applied Fusion-Bonded Epoxy (FBE) Pipe 

Coating Systems for Girth Weld Joints: Application, Performance, 

and Quality Control 

Leaders in Corrosion Control Technology 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 USA Page 99
Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

NACE External Coating 

Standards for Pipelines 

RP0303-2003 Field-Applied Heat-Shrinkable Sleeves for Pipelines:

Application, Performance, and Quality Control

RP0490-2001 Holiday Detection of Fusion-Bonded Epoxy External

Pipeline Coatings of 250 to 760 m ( 10 to 30 mils )

RP0185-96 Extruded Polyolefin Resin Coating Systems with Soft

Adhesives for Underground or Submerged Pipe

RP0375-99 Wax Coating Systems for Underground Pipeline

Systems

Leaders in Corrosion Control Technology 

Test Methods for Coatings 

TM0102-2002 - Measurement of Protective Coating Electrical 

Conductance on Underground Pipelines 

TM0174-2002 - Laboratory Methods for the Evaluation of 

Protective Coatings and Lining Materials for Immersion Service 

NACE Technical Committee Reports on Pipeline Coatings 

NACE Publication 10D199 - Coatings for the Repair and 

Rehabilitation of the External Coatings of Buried Steel Pipelines 

Leaders in Corrosion Control Technology 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 USA Page 100
Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

Standards Under 

Development 

Committee 

Number 

Document 

Type 

Title Status Expected 

Publication Date 

TG 247 Standard Coatings, Liquid Epoxy for External Repair 

Rehabilitations, and Weld Joints on Buried Pipelines 

Re-balloted October 2005 

TG 251 Standard Tape Coatings for External Repair, Rehabilitations, 

and Weld Joints on Pipelines 

Completing 

Draft 

October 2005 

TG 265 Revision 

of NACE 

Standard 

RP0185-96 

Review of NACE Standard RP0185-96 “Extruded 

Polyolefin Resin Coating Systems with Soft 

Adhesives for Underground or Submerged Pipe” 

Ballot 

closed 

08/2002; 

Open 

review held 

October 2005 

at C/2003 

Leaders in Corrosion Control Technology 

Leaders in Corrosion Control Technology 

Re-Ballot October 2005 

closed 

3/9/05 

Wax Coating System for Underground Piping 

Systems 

Revision 

of NACE 

Standard 

RP0375-99 

TG 296 

Just June 2006 

received 

draft from 

committee 

Aboveground Techniques for the Evaluation of 

Underground Pipeline Coating Condition 

TG 294 Standard 

Ballot January 2006 

closed 

01/2003 

Open 

Review 

held at 

CTW/2003 

Field-Applied Polyurethane Coatings for Field 

Repair, Rehabilitation, and Girth Weld Joints on 

Pipelines: Application, Performance, and Quality 

Control 

TG 281 Standard 

Expected 

Publication Date 

Document Title Status 

Type 

Committee 

Number 

Standards Under 

Development 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 USA Page 101
Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

Coating Applicator 

Training Program 

Action spurred by the U.S. Navy and the International Union of

Paint and Allied Trades (IUPAT)

NACE International and SSPC are co-developing a comprehensive 

credentialing program for coating applicators that includes a 

standard on performance qualifications, training & certification 

Leaders in Corrosion Control Technology 

Coating Applicator

Training Program

Task groups have been established to work on the standard and 

the training and certification programs. 

Tentative plan is to offer four levels of training ranging from the 

“helper” level to the “master” level. 

Plan to publish standard in January 2006. Training and

certification will follow.

Approaching development stages 

Hands-on training + lecture 

Leaders in Corrosion Control Technology 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 USA Page 102
Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

Invest in the Future 

“Request to Congress” 

Corrosion Prevention Tax Credit 

Propose a 15% Tax Credit on Implementation of Corrosion

Prevention Strategies and Methodologies

Tax Credit to all businesses and in all industries based on new

initiatives

Leaders in Corrosion Control Technology 

Questions?

Leaders in Corrosion Control Technology 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 USA Page 103
Leaders in Corrosion Control Technology

Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

Cliff Johnson Office of Pipeline Safety Workshop on 

Director, Education Advanced Coatings R&D for Pipelines and 

Larry Christie Related Facilities 

Coatings Market Manager June 9, 2005 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 USA Page 104
National Energy

Board

Office national

de l’énergie

Slide Number 1

Advanced Coatings R & D for Pipelines

PHMSA Workshop Gaithersburg

9 June 2005

Canadian Standards Association

Standards on Pipeline Coatings

Dr. Franci Jeglic

National Energy Board

Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

Slide Number 2 

CSA – Z662 – 03 

Oil and Gas Pipeline Systems 

Design 

Assessment for the selection of coatings – 

Factors to be considered: 

 Pipe diameter, soil type and instability, depth of 

cover, cathodic protection potentials, type of fluid 

to be transported, coating resistivity; 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 USA Page 105












Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

Slide Number 3 

Design (continued) 

Pipe bending and backfilling; 

Maximum, minimum and cyclic temperatures, 

excursions, and durations; 

Coating application and ambient conditions; 

Service changes; 

Interaction of dissimilar coatings; and 

Duration and method of coated pipe storage. 

Slide Number 4 

CSA – Z662 - 03 

Materials 

Plant Applied External Protective Pipe Coatings. 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 USA Page 106




Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

Slide Number 5 

CSA Z662 - 03 

Non-mandatory Annex L 

Test Methods for Coatings Property Evaluation 

Test Methods for: 

Volume resistivity; 

Cathodic disbondment; 

Slide Number 6 

 Adhesion; 

 Water absorption; 

 Water vapour transmission; 

 Coating flexibility; 

 Peel adhesion; 

 Shear adhesion; 

 Pull off adhesion; 

 Impact resistance; 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 USA Page 107
















Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

Slide Number 7 

Wear abrasion; 

UV stability; 

Penetration; 

Temperature resistance; 

Chemical resistance; 

Microbial resistance; 

Oxidative stability; and 

Heat aging. 

Slide Number 8 

CAN / CSA Z245.20 - 02 

External Fusion Bond Epoxy Coating for Steel 

Pipe 

Standard covers: 

 Qualification; 

 Application; 

 Inspection; 

 Testing; 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 USA Page 108




of 

Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

Slide Number 9 

CSAN / CSA Z245.20 – 02 

(Continued) 

Handling; and 

Storage 

materials required for plant-applied fusion bond 

epoxy coating applied externally to bare pipe. 

Slide Number 10 

CAN /CSA Z245.21 - 02 

External Polyethylene Coating 

Scope: qualification, application, inspection, testing, 

handling, and storage. 

An adhesive is interposed between bare or epoxyprimed pipe and polyethylene. 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 USA Page 109
Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

A1 and A2 – adhesive and polyethylene outer sheath. 

B1 – liquid or powdered epoxy primer, a 

polymeric adhesive and polyethylene 

outer sheath. 

B2 – powdered epoxy primer, a 

powdered copolymer adhesive, and a 

powdered polyethylene outer layer. 

Slide Number 11 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 USA Page 110
Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

A Pipeline Operators Viewpoint 

on Underground Coatings Issues 

Jeff Didas

Colonial Pipeline Company

Major Issues 

• Existing Pipeline Coatings 

• Coatings for New Construction 

• Coatings for Pipeline Rehabilitation 

• Coatings for Pipeline Repairs 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 Page 111
Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

Existing Pipeline Coatings 

• Coal Tar Enamel 

• Asphalt Enamel 

• Extruded Polyethylene 

• Fusion Bonded Epoxy 

• Somastic 

• Pritec 

• Liquid Epoxy 

• 3 Layer 

• Tape 

• Wax 

What is the issue with existing 

coatings? 

• Age 

• Condition 

• Failure Mode 

• Reparability 

• Compatibility with Repair Coatings 

• Hazards & Toxicity 

• Transition Zones 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 Page 112
Workshop on Advanced Coatings R&D for Pipelines and Related Facilities June 9-10, 2005 NIST, Gaithersburg, MD 20899 Page 113
Workshop on Advanced Coatings R&D for Pipelines and Related Facilities June 9-10, 2005 NIST, Gaithersburg, MD 20899 Page 114
Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

Transition Zones 

Issues 

• CP Shielding 

• Increased CP Levels 

• Recoating 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 Page 115
Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

Coatings for New Construction 

• Most common is Fusion Bonded Epoxy – 

FBE 

• Multi – Layer Systems Gaining in 

Popularity 

• Issues are Coating the Weld Joints, 

Handling Damage, Flexibility and Coating 

Repair Methods – Quality Control & 

Inspector Standards. 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 Page 116
Weld Joint 

Flexibility 

Workshop on Advanced Coatings R&D for Pipelines and Related Facilities June 9-10, 2005 NIST, Gaithersburg, MD 20899 Page 117
Handling Damage 

Handling Damage 

Workshop on Advanced Coatings R&D for Pipelines and Related Facilities June 9-10, 2005 NIST, Gaithersburg, MD 20899 Page 118
Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

Coatings for Pipeline 

Rehabilitation Issues 

• Compatibility with Existing Coatings 

• Cure/Dry Time 

• Performance 

• Application 

• Ambient Conditions 

• Quality Control 

• Inspector Standards 

Weather 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 Page 119
Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

Job Site 

Abrasive Blasting 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 Page 120
Holiday Testing 

Workshop on Advanced Coatings R&D for Pipelines and Related Facilities June 9-10, 2005 NIST, Gaithersburg, MD 20899 Page 121
Workshop on Advanced Coatings R&D for Pipelines and Related Facilities June 9-10, 2005 NIST, Gaithersburg, MD 20899 Page 122
Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

Coatings for Pipeline Repairs 

• Keyhole Coatings 

• Wet ditch/hole Coatings 

• Winter Grade/Summer Grade Coatings 

• Cure/Dry Time 

Repair Coatings 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 Page 123
Repair Coatings 

Keyhole Coating 

Workshop on Advanced Coatings R&D for Pipelines and Related Facilities June 9-10, 2005 NIST, Gaithersburg, MD 20899 Page 124
Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

Summary of Issues 

• Repair & Rehabilitation Coatings are the major 

issue for pipeline operators. 

• Deterioration & Aging of Existing Coatings are 

an ongoing issue for pipeline operators. 

• Improving handling properties for new pipeline 

coatings, flexibility of new coatings, as well as 

weld joint coatings (quality) and in field repairs 

(quality) for the coating are major issues for 

pipeline operators. 

Additional Issues 

• Development of new or standardization of 

existing short term testing methods to 

reliably predict long term coating 

performance. 

• Investigate the effects of pipeline 

preheating or thermal treatment used in 

the application of new coatings may affect 

the strain aging in steel substrates. 

Thank You 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 Page 125
GREG RUSCHAU

CC TECHNOLOGIES

DUBLIN, OH

•

•

•

•

–

Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

PRCI COATINGS 

RESEARCH 

PRCI RECENT STRATEGY 

HAS SHIFTED FROM MAINLINE COATINGS 

TO REPAIR/REHAB COATINGS 

FIELD-APPLIED COATINGS ARE CURRENT 

FOCUS OF “PURE” COATINGS RESEARCH 

ASSESSMENT OF IN-SERVICE CONDITION 

VERY IMPORTANT 

VERY LITTLE FOCUS ON FUNDAMENTALS 

OF HOW, WHY COATINGS PERFORM 

ALWAYS HAS BEEN FOCUSED ON RESULTS 

WHICH OPERATORS CAN USE 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 Page 126
WHY THE STRATEGY 

SHIFT? 

• OPERATORS FEEL THEY KNOW HOW TO

SELECT PLANT-APPLIED COATINGS

• MOST ARE DEALING WITH OLD

SYSTEMS OF COAL TAR AND ASPHALT

ENAMELS WHICH NEED REPAIR OR

REHABILITATION

• NO QA/QC STANDARDS FOR REPAIR

COATINGS – UNCERTAIN INTEGRITY

•

•

•

•

Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

RECENTLY COMPLETED (SINCE 2000) 

PRCI PROJECTS RELATED TO COATINGS 

Performance of Blistered FBE Coating

(2000)

Development of Predictive Accelerated

Test Methods for Pipeline Coatings (2002)

Compatibility of Repair Coatings to

Existing Below Grade Pipeline Coatings

(2002)

Coating Repairs for Thermite Welds and

Keyhole Excavations (2003)

June 9-10, 2005 NIST, Gaithersburg, MD 20899 Page 127
PERFORMANCE OF 

BLISTERED FBE COATED PIPE 

•WHEN FBE COATED PIPE IS

UNCOVERED AND THERE ARE

BLISTERS, WHAT SHOULD BE

THE REMEDIAL ACTION?

RECOAT, INCREASE CP, LEAVE

ALONE?

•DOES FBE COATING REALLY

ALLOW CP TO PENETRATE?

•

•

Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

RESULTS/CONCLUSIONS

BLISTERS FORMED AT 

HIGH TEMPERATURES 

(>Tg) DID NOT PASS CP 

CURRENT 

BLISTERS FORMED AT 

LOW TEMPERATURES 

WILL ALLOW CP 

CURRENT, BUT LIKELY 

BECAUSE OF 

MICROCRACKS 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 Page 128
DEVELOPING ACCELERATED 

PREDICTIVE TEST METHODS FOR 

EXTERNAL PIPELINE COATINGS 

Develop laboratory testing for FBE pipeline

coatings which is:

–Accelerated to provide answers in a short

time frame

–Predictive of future performance

–Realistic in that it accentuates the

degradation of properties which are likely to

degrade in service

Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

APPROACH

• CATALOGUE FIELD FAILURES AND 

FOCUS ON TESTS WHICH PRODUCE 

THESE FAILURES 

• USE SUITE OF TESTS RATHER THAN 

SEARCH FOR “MAGIC” ANSWER 

• INVESTIGATE ANALYTICAL 

TECHNIQUES FOR POTENTIAL 

BREAKTHROUGHS 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 Page 129
• Field failure pattern was common: Isolated

pockets of blisters and adhesion loss

– Blisters associated with cathodic disbondment

– Localized failures from damage and/or poor surface

prep/application

• Scatter in test results from differently prepared

FBE samples was greater than between

different products

– true comparative performance testing can only be

done on samples with identical surface preparation

• For coating selection, several accelerated test

techniques provide “scoring system” type

protocol

•

•

Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

RESULTS / CONCLUSIONS 

COMPATIBILITY OF REPAIR 

COATINGS TO EXISTING BELOW 

GRADE PIPELINE COATINGS 

Determine chemical compatibility of selected

repair coatings to mainline coating 

Describe general chemical compatibility of 

different chemistries of coating systems 

Coal Tar Asphalt FBE Extruded PE Tape Wrap 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 Page 130
• Epoxy mainline coatings provide best

chemical surface for bonding – epoxy

and epoxy polyurethane repairs both

excellent

• Thermoplastic coatings (asphalt, coal tar

enamel, PE tapes, extruded PE) provide

only physical surface for bonding

– Only in a molten state can the repair coatings bond

with the mainline coatings

• Short term chemical aging failed to

significantly affect performance ranking

in any systems

•

•

Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

CONCLUSIONS FROM PROJECT 

COATING COMPATIBILITY AT THERMITE 

WELDS AND FOR KEYHOLE EXCAVATIONS 

For special pipeline excavations involving thermite 

welds and other anode connections 

The requirements for achieving an acceptable coating 

repair at these excavations differ from standard 

bellhole survey repairs 

SOIL BOX 

PVC “BLIND” PIPE 

WORKING 

PLATFORM 

2 M EXCAVATION 

TRUCK 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 Page 131
APPROACH 

• Lab – look at adhesion to different components

• Simulation of keyhole application

•Adhesion to insulation is weakest link – PVC

insulation better than Polyethylene for this application

•Epoxies have superior compatibility and adhesion,

most also apply easy

•For application ease, best combination is a

moderately thick viscosity and rapid drying time (not

necessarily rapid cure time)

RESULTS/CONCLUSIONS 

•

•

•

•

•

Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

CURRENT PRCI COATING PROJECTS 

AT CC TECHNOLOGIES 

Cathodic Protection Shielding of Girth Weld Coatings 

Effects of Surface Preparation on the Performance of 

Repair and Rehabilitation Coatings 

Performance of Coatings Applied to Wet Surfaces 

Effective Methods of Coating Removal During 

Investigative Excavations 

Assessment of Aboveground Techniques for 

Locating Coating Defects (OPS co-funding) 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 Page 132
•

•

•

– “ ”

Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

COMMENTS ON CURRENT

STATE OF PIPELINE COATING

TECHNOLOGY

PIPELINE INDUSTRY HAS VERY LIMITED 

FUNDAMENTAL UNDERSTANDING OF THE 

TECHNICAL ISSUES WITH COATINGS 

COATINGS ARE FORMULATED TO PASS 

PERFORMANCE TESTS RATHER THAN TO PERFORM 

IN THE FIELD (IS IT THE SAME?) 

COATINGS ARE CONSIDERED A COMMODITY 

PRODUCT, NOT MATERIALS SCIENCE 

NOT AS COMPLEX AS ALLOYS, SMART PIGS, INSPECTION TOOLS 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 Page 133
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Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

The GLOBAL LEADER in Pipe Coating Solutions 

Coating Fabrication Issues 

Peter Singh

Presented to: Presented to:

Office of Pipeline Safety Workshop on

 Advanced Coatings R&D for Pipelines and Related Facilities Advanced Coatings R&D for Pipelines and Related Facilities

June 9-10, 2005

National Institute of Standards and Technology National Institute of Standards and Technology

Gaithersburg, MD USA

The GLOBAL LEADER in Pipe Coating Solutions 

Pipeline Coatings 

The role of external pipeline coatings is to

complement complement cathodic cathodic protection systems in

protecting pipelines from corrosion and subsequent protecting pipelines from corrosion and subsequent

failure

June 9-10, 2005 NIST, Gaithersburg, MD 20899 Page 166
Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

The GLOBAL LEADER in Pipe Coating Solutions 

Demands 

• Improved pipeline integrity

• Improved coating performance.

– increased reliability

– less risk of failures

– longer expected lifetime

– less maintenance

• Improved quality

• Increased capabilities

– higher pipeline operating temperatures

– low temperature construction in arctic regions

• Environmental concerns Environmental concerns

• Improved life cycle economics Improved life cycle economics

– material costs

– construction & operating costs

The GLOBAL LEADER in Pipe Coating Solutions 

Strategy for Achieving Pipeline Integrity 

• Develop understanding of coating performance 

requirements 

• Design and select coatings properly 

• Ensure meaningful specifications are written 

• Apply coating under optimum process with adequate 

quality control 

• Carry out construction according to plan 

• Operate system within specification 

• Periodic monitoring and feedback on performance 

• Research & Development of new technologies 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 Page 167
Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

The GLOBAL LEADER in Pipe Coating Solutions 

Requirements 

CSA Z662: 

• 9.2.7.1 properties: coating shall 

• a) electrically isolate the external surface of the piping from the 

environment; 

• b) have sufficient adhesion to effectively resist underfilm migration of 

moisture; 

• c) be sufficiently ductile to resist cracking; 

• d) have sufficient strength and adhesion - to resist damage due to soil 

stress and normal handling (including bending, concrete coating 

application, river/swamp weight installation, and anode bracelet 

installation, where applicable); 

• e) be compatible with cathodic protection; 

• f) resist degradation of the coating properties throughout - conditions 

and temperatures encountered during storage, shipping, construction, 

and operation; 

• g) where plant-applied and applicable to the coating system to be 

used, be in accordance with CSA standard Z245.20 or Z245.21 

The GLOBAL LEADER in Pipe Coating Solutions 

Matching Coating Properties to Integrity 

Issues 

HANDLING INSTALLATION TESTING OPERATION

Loading/Stacking

Transportation

Environmental

Exposure

Stringing

Bending

Burial

Hydrostatic

expansion

Temperature

Environment

Cathodic

Protection

Impact strength

Abrasion

resistance

Compressive

strength

Penetration

resistance

U.V. Resistance

Wet-dry cycling

resistance

Abrasion

resistance

Impact strength

Extensibility

Compressive

strength

Shear adhesion

Notch

sensitivity

Penetration

resistance

Tensile strength

Extensibility

Penetration

resistance

Adhesion

strength

Tensile

strength

Notch

sensitivity

Oxidative

stability

Tensile strength

Compressive Compressiv

strength

Shear strength

Adhesive

strength

Penetration

resistance

Cathodic

disbondment

Transport Transpor

properties,

water, oxygen water, oxyge

and ionic

species

June 9-10, 2005 NIST, Gaithersburg, MD 20899 Page 168
Workshop on Advanced Coatings R&D for Pipelines and Related Facilities June 9-10, 2005 NIST, Gaithersburg, MD 20899 Page 169

Plant Coating Technologies 

• Powder Applied Coatings 

– FBE 

• Single layer: corrosion and specialty 

• Multi-layer: abrasion, anti-slip, protective topcoat 

– HPCC 

• Multi-component: FBE, adhesive, PE or PP topcoat 

• Extrusion Applied Coatings 

– 2 layer PE/PP 

• Mastic adhesive, butyl, hot melt 

– 3 layer PE/PP 

• FBE, adhesive, PE or PP topcoat 

• Liquid Applied Coatings 

– Polyurethane, epoxy, coal tar enamel, asphalt enamel 

The GLOBAL LEADER in Pipe Coating Solutions 

Fusion Bonded Epoxy 

FBE

Top

Powdered Coat

Epoxy 

FBE

Steel Pipe FBE Base

 Coat

Steel Steel

FBE DPS FBE

The GLOBAL LEADER in Pipe Coating Solutions 
Workshop on Advanced Coatings R&D for Pipelines and Related Facilities June 9-10, 2005 NIST, Gaithersburg, MD 20899 Page 170

HPCC

2

3

4 

4 Material Standard Thickness andard Thickness

Black MPDE 500 micron (20 mils) 

topcoat 

1 Black MPDE Topcoat FBE/Adhesive 125 microns (5 mils) 

Interlayer 2 FBE/Adhesive Interlayer 

FBE 125 microns (5 mils) 3 FBE Primer 

TOTAL750 microns (30 mils) 4 Steel Pipe 

The GLOBAL LEADER in Pipe Coating Solutions 

2 Layer PE/PP 

Adhesive

Top Coat 

Steel Pipe 

The GLOBAL LEADER in Pipe Coating Solutions 
Workshop on Advanced Coatings R&D for Pipelines and Related Facilities June 9-10, 2005 NIST, Gaithersburg, MD 20899 Page 171

3 Layer PE/PP 

Topcoat 

Epoxy 

Primer 

Steel Pipe 

Copolymer

Adhesive

The GLOBAL LEADER in Pipe Coating Solutions 

Field Coating Technologies 

• Powder Applied Coatings 

– FBE 

• Single layer 

• Multi-layer 

– Multi-component 

• FBE, adhesive, PE or PP topcoat 

• Liquid Applied Coatings 

– Polyurethane, epoxy 

• Heat Shrink Sleeves 

– Crosslinked PE/PP with/out liquid epoxy 

• Others 

– Tapes, sleeves, etc. 

The GLOBAL LEADER in Pipe Coating Solutions 
Workshop on Advanced Coatings R&D for Pipelines and Related Facilities June 9-10, 2005 NIST, Gaithersburg, MD 20899 Page 172

Heat Shrink Sleeve 

Adhesive Directly To Line Coating Pre-attached Closure System 

CrossLinked Backing “Open” Adhesive Technology 

Force Cured Epoxy System Epoxy On Steel Only 

The GLOBAL LEADER in Pipe Coating Solutions 

Typical Process

PIPE IN

PREHEAT SURFACE INSPEC TION ADDIT ONAL I

PREPARATION Verify pipe suitable SURFACE for coating TREATMENT Removes mill Ensure there are no Establishes scale slivers, mill scale or Promotes coating 

uniform initial cracks adhesion to steel 

pipe temperature Establishes Inspect weld profile 

anchor pattern Remove surface Removes soluble 

imperfections salts i.e: chlorides 

Perform Quality 

control tests for 

anchor pattern 

HOLIDAY COOLING COAT NG I PR EAT E-H

INSPECTION/ AP L ATION PLICATION

STENCILING ENCILING Pre -heats pipe to Remove water from Removes heat from Electrostatic application pipe interior pipe and coating powder Spraying temperature Holiday detection 

Coating thickness Extrusion 

measurement 

Apply stencil Liquid Spraying 

Tally pipe 

Smooth cutbacks 

and bevels 

PIPE OUT

The GLOBAL LEADER in Pipe Coating Solutions 
Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

The GLOBAL LEADER in Pipe Coating Solutions 

FBE Coating Process 

The GLOBAL LEADER in Pipe Coating Solutions 

Design & Selection 

Need better understanding of performance requirements 

to quantify and select 

Many studies on various properties, for example: 

• Impact 

• Shear adhesion 

• Thermal aging 

• UV degradation 

• Cathodic disbondment 

• Cathodic protection 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 Page 173
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The GLOBAL LEADER in Pipe Coating Solutions 

Indentation Resistance 

HPCC-h 

DPS-FBE 

HPCC-s 

FBE 

0 

2 

4 

6 

8 

10 

12 

14 

16 

18 

0 0.2 0.4 0.6 0.8 1 1.2 1.4 1.6 

Average Coating Thickness (mm) 

Holidays/sq. m 

minus 50mm 

minus 25mm 

14mm 

Backfill Rock

Size Classification

The GLOBAL LEADER in Pipe Coating Solutions 

0.00 

5.00 

10.00 

15.00 

20.00 

25.00 

-40 -30 -20 -10 0 10 20 30 

Temperature (C) 

Impact Resistance (J) 

FBE DPS FBE HPCC -h 3LPE 

Impact 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 Page 174
Workshop on Advanced Coatings R&D for Pipelines and Related Facilities June 9-10, 2005 NIST, Gaithersburg, MD 20899 Page 175

Buried Pipeline Stress Analysis 

Pipeline Stress Analysis 

OD 762mm wt 16.4mm - Burial Depth 2m - Gas filled 

20 

17.5 

15 

12.5 

10 

7.5 

5 

2.5 

0 

Compressive Stress (psi) Vertical Shear Stress (psi) Pipe 

The GLOBAL LEADER in Pipe Coating Solutions 

Coating thickness remaining (microns) 

FBE thickness vs Stockpile time 

440.00 

420.00 

400.00 

380.00 

360.00 

340.00 

320.00 

300.00 

0 5 10 15 20 25 

Outdoor exposure time (months) 

FBE A FBE B 

The GLOBAL LEADER in Pipe Coating Solutions 
Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

The GLOBAL LEADER in Pipe Coating Solutions 

Specifications 

• Need for standardization 

– Proliferation of company exclusive specifications 

– Many differences, some good, some bad 

– ISO standards being developed 

• Need for performance based specifications 

– Define performance requirements not 

manufacturing process 

– End result can be to stifle innovation, build in 

mediocrity with poor specifications 

• Need for meaningful specification 

– More requirements, tighter criteria not often better 

– Focus on important properties and limits 

– Can deteriorate into testing project 

The GLOBAL LEADER in Pipe Coating Solutions 

Manufacturing Issues 

• Complex application process 

– Many diverse processes to apply coatings: from 

heating, surface preparation, materials application 

• Little consensus on best process/parameters 

– Some research on various parameters such as 

profile, contamination, surface treatments 

– Studies often not very conclusive 

• Realistic expectations 

– Large heavy part/surface area to be coated 

– Process time limitations (delivery schedules) 

– Cost limitations as % of steel cost 

– Cannot treat in same manner as small components 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 Page 176
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The GLOBAL LEADER in Pipe Coating Solutions 

Surface Preparation 

• Most important process in determining coating quality 

• Need to determine optimum parameters and how to 

measure during process 

• Many companies do not understand importance 

• Some coatings are more sensitive to level of preparation 

The GLOBAL LEADER in Pipe Coating Solutions 

Optimum Blast Profile? 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 Page 177
Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

The GLOBAL LEADER in Pipe Coating Solutions 

Cross-head/side extrusion? 

The GLOBAL LEADER in Pipe Coating Solutions 

Manufacturing Issues 

• Not ideal manufacturing process 

– Cannot schedule, inventory management, etc) 

• More similar to project driven business 

– Customer supplied pipe 

– Wait for pipe to be delivered and then coat 

• Problems inherent to project driven industries 

– Inefficient if work is not steady 

– Issues on maintenance of skilled labour 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 Page 178
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The GLOBAL LEADER in Pipe Coating Solutions 

Incoming Pipe Quality 

• May not be critical for pipeline itself but important for 

processing and coating application 

• Condition of pipe on delivery 

– Wall thickness 

– Roundness 

– Camber 

– Weld profile 

– Steel cleanliness 

– Contamination 

– Joint length 

• Steel pipe specification 

– Need to address not only pipeline design issues but 

also subsequent ability to process for coating 

The GLOBAL LEADER in Pipe Coating Solutions 

Quality Assurance 

• Should be internally driven by coating applicator 

– customer should expect a high level QA program 

• Quality improvement programs 

– awareness 

– preventative 

– inspection and audit 

• Use of ISO 9001 

– Program regularly audited by third party 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 Page 179
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The GLOBAL LEADER in Pipe Coating Solutions 

Industry Feedback is Important 

• Assessment of coating performance in independent digs 

• Confirmation of predictive analysis on long term 

coating properties 

– Adhesion 

– Permeability 

– Material properties 

• Joint development of corrective strategies 

• Operators, contractors, coaters, regulators, and 

engineering companies need to work as a team 

The GLOBAL LEADER in Pipe Coating Solutions 

Failure Modes 

• Damaged Coating 

• Impact damage 

• Cracking 

• Deterioration 

• Shielding Disbondment 

• Over the ditch tapes 

• Permeable Coating 

• Asphalts and to some extent FBE 

• Blistered Coating 

• Has been observed with FBE 

• Disbondment 

• Has been observed with 3 layer PE and PP 

coatings 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 Page 180
Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

The GLOBAL LEADER in Pipe Coating Solutions 

Blistered FBE 

Photograph 3: Disbonded coating around holiday. 

The GLOBAL LEADER in Pipe Coating Solutions 

3LPE Disbondment 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 Page 181
Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

The GLOBAL LEADER in Pipe Coating Solutions 

2LPE Cracking 

The GLOBAL LEADER in Pipe Coating Solutions 

Tape Disbondment & Wrinkling 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 Page 182
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The GLOBAL LEADER in Pipe Coating Solutions 

Research 

• Predictive studies 

– Predictive analysis of properties (long term) 

– Relation of lab measured properties to field performance 

– Development of models to use in design & selection of 

coatings 

• Product/process development 

– New products to reduce failures, increase performance, 

increase reliability, lower cost 

– Standards need to be flexible to allow new developments 

• Failure Analysis 

– Understanding coating failures 

• Blistering 

• Disbondment 

• Cracking 

The GLOBAL LEADER in Pipe Coating Solutions 

Competitive Issues 

• Protection of innovative technologies 

– Patents, secrecy agreements 

• Limits to access 

– Conflicts with end users specifying full access 

• Intentional and accidental sharing of technologies 

• Protection of R&D investment 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 Page 183
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The GLOBAL LEADER in Pipe Coating Solutions 

Summary 

• Design & selection of coatings 

• Specification changes 

– ensure steel pipe is compatible to coating process 

– performance based 

• Research 

– Develop design & predictive methodologies 

– Feedback of actual coating performance in service 

– New materials and processes to increase 

performance, reliability and reduce life cycle cost 

• Competitive industry 

– Protection of innovative technologies 

– Payback of R&D investment 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 Page 184
Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

THE MATERIALS JOINING EXPERTS 

NDE AND EDDY CURRENT 

METHODS FOR PIPELINE 

COATING INSPECTION 

NIST Workshop on 

Advanced Coatings R&D 

for Pipelines and Related 

Facilities June 05 

Evgueni Todorov, Ph.D. 

Engineering and NDE 

EWI 

PH. 614-688-5268, FAX 614-688-5001 

THE MATERIALS JOINING EXPERTS 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 Page 185
Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

Contents 

• NDE of coatings 

– General 

– Coating failures 

– Ultrasonics (UT) 

– Magnetic method 

– Infrared thermography 

• Eddy current (EC) method 

– Definitions 

– Tasks 

– Typical probes and equipment 

– Examples of current procedures 

• EC magnetic winding magnetometer (MWM) 

– General 

– Typical equipment and grids 

– Aluminum over carbon steel 

– Stainless steel over carbon steel 

• EC computer modeling (ECCM) 

– Coating thinning at different frequencies 

– Substrate inspections 

• Advantages and disadvantages of EC 

• Conclusions and recommendations 

NDE of Coatings - General 

• Most ASTM standards address the use of Eddy Current 

and Magnetic methods for thin coating thickness 

measurement (ASTM E 376, G12) 

• Except visual inspection technique, few examples if any 

are available for characterization of thick coatings on the 

pipelines 

• Typical tasks 

– Coating (or substrate) thickness measurement 

– Quality of coating (or substrate) material –

degradation, porosity, voids, cracks

– Adhesion of coating to the substrate – quality of bond, 

disbond areas, undercutting 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 Page 186
Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

NDE of Coatings - Coating Failures 

Undercutting 

and Corrosion 

Undercutting 

Blistering 

Scaling 

Corrosion 

under Coating 

NDE of Coatings - Ultrasonics (UT) 

• General description and areas of application 

– Time-of-flight technique usually used for coating thickness 

measurements 

– Well established acoustically reflective interface between the 

coating and the substrate required 

– UT method C-Scan used for disbonds and voids detection and 

sizing 

• Limitations 

– Organic or other highly attenuative coatings difficult or impossible 

to examine 

– If the interface is not acoustically reflective, the UT inspection is 

impossible 

– Small porosity or coating property variations that do not affect 

significantly the velocity of sound propagation are not detectable 

– In general, coating thickness has to be larger than 1-2 mm 

– Couplant is required 

– Multiple coating layers are difficult to evaluate 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 Page 187
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NDE of Coatings - Magnetic Method 

• General description and areas of application 

– Magnetic attraction or magnetic flux measurements 

usually used for coating thickness inspection 

– Ferromagnetic substrate or coating is required 

– Coating thickness may range from 0 to 2 mm 

• Limitations 

– The substrate or coating has to be ferromagnetic 

– Coating properties such as porosity, degradation, and 

flaws are not measured 

– Disbond between the coating and the substrate cannot 

be detected with magnetic methods 

– The method is not used for multiple coating layers 

NDE of Coatings - Infrared Thermography 

• General description and areas of application 

– Heat distribution in substrate-coating

combination is studied under pulse or

continuous heating

– The method can potentially be used for 

evaluation of disbonds and coating degradation 

• Limitations 

– Coating thickness may be difficult to assess 

– Thin metal coatings may be difficult to inspect 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 Page 188
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Eddy Current (EC) - Definitions 

LO - lift off

TC – coating thickness

TS – substrate thickness

LO f – current frequency

S, S – magnetic

permeability and electrical TC conductivity of substrate

C, C – magnetic

permeability and electrical

conductivity of coating

Probe Coating 

C, C 

Substrate 

S, S 

TS 

RULES OF THUMB 3 μ  >1.5μ 

> T C C S S To detect any coating changes C

fμCC μ S S >1.5μ C C

To eliminate substrate thickness 3

changes on coating thickness < TS

measurements fμS S 

EC - Tasks 

• Parameters to be measured 

– Coating (or substrate) thickness 

– Coating (or substrate) properties – e.g., degradation that affects C and 

C (S and S) 

– Coating (or substrate) cracks, corrosion, and other flaws 

• Coating-substrate combinations regarding EC 

– Metal coating on non-conductive and non-ferromagnetic substrate – 

metallic film on glass, ceramics or plastics 

– Non-ferromagnetic and non-conductive coating on metal non- or 

ferromagnetic substrate – paint, cement, rubber, other insulation organic 

coatings 

NOTE: Major case for pipelines 

– Non-ferromagnetic and conductive coating on metal non- or 

ferromagnetic substrate – aluminum, copper, cadmium, or zinc on carbon 

steel, pure aluminum on aluminum alloy 

– Ferromagnetic and conductive coating on metal ferromagnetic substrate 

– cobalt or nickel on carbon steel 

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EC - Typical Probes and Equipment 

Impedance Plane

Screen Of Typical

ET Instrument

Spot Pencil

Probe Probe

EC - Examples of Current Procedures 

Aluminum coating 

over carbon steel 

Paint coating over 

aluminum and carbon 

steel 

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EC Magnetic Winding Magnetometer (MWM) - Principle 

Substrate 

Coating 

TS 

TC 

LO 

MWM - Typical Equipment and Grids 

MWM 

Conformable 

Probe 

Conductivity-Lift-Off Grids 

MWM 

Instrument 

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Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

MWM - Aluminum over Carbon Steel 

Aluminum Coating Thickness Measurements (calibration using AL-TH-1, 24 mil coating) 

0 

5 

10 

15 

20 

25 

30 

35 

0 5 10 15 20 25 30 35 

Nom inal Thickness (m ils) 

Measured Thickness (mils)

Jentek AL-TH 1 

Jentek AL-TH 2 

Jentek AL-TH 3 

EWI AL-TH-1 

EWI AL-TH-2 

EWI AL-TH-3 

One set of 3 

specimens 

measured at 

2 locations 

MWM - Stainless Steel over Carbon Steel 

Stainless Steel Coating Thickness Measurements (calibration using SS-TH-1, 24 mil coating) 

0 

5 

10 

15 

20 

25 

30 

35 

0 5 10 15 20 25 30 35 

Nom inal Thickness (m ils) 

Measured Thickness (mils)

Jentek SS-TH 1 

Jentek SS-TH 2 

Jentek SS-TH 3 

EWI SS-TH-1 

EWI SS-TH-2 

EWI SS-TH-3 

One set of 3 

specimens 

measured at 

2 locations 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 Page 192
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Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

EC Computer Modeling (ECCM) 

ECCM - Coating Thinning at Different Frequencies 

• Coating 

thickness and 

property (e.g., 

conductivity) 

variations can 

be assessed 

in advance 

Simulation of Coating Thinning Signal 

IVD Aluminum Coating Spot 

Depth 0.0005 inch, Width 0.23 inch 

Resistance, Ohm 

-4 -2 0 

0 

2 

4 

Lift off 400 kHz 

IVD Spot 400 kHz 

Lift off 100 kHz 

IVD Spot 100 kHz 

Lift off 25 kHz 

IVD Spot 25 kHz 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 Page 193
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Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

ECCM - Substrate Inspections 

Simulation of Coating Thinning Signals and 

Steel Notch under Coating Signals at 

Lower Frequencies 

Resistance, Ohm 

-1.6 -1.2 -0.8 -0.4 0.0 0.4 

0.0 

0.4 

0.8 

1.2 

1.6 

Lift off 100 kHz 

Coating Thinning Spot 100 kHz 

Steel Notch under Coating 100 kHz 

Lift off 25 kHz 

Coating Thinning Spot 25 kHz 

Steel Notch under Coating 25 kHz 

100 kHz 

Large cracks in the substrate 

may be completely masked by 

coating thickness variations 

Simulation of Steel Notch Signals without IVD Coating 

Resistance, Ohm 

-1.6 -1.2 -0.8 -0.4 0.0 0.4 0.8 1.2 1.6

Reactance, Ohm

0.0 

0.4 

0.8 

1.2 

1.6 

Lift off 100 kHz 

Steel Notch 100 kHz 

Lift off 25 kHz 

Steel Notch 25 kHz 

100 kHz 

Advantages and Disadvantages of EC 

• Advantages 

– Does not require couplant 

– Very accurate for thin layers 

– Capable of examining multiple layers when aided with modeling and 

advanced technologies 

– Fast and easy to set up for field inspections 

– One instrument can perform thickness and flaw inspections on both 

coating and substrate 

– Change of coating properties (degradation, porosity, corrosion) that affect 

coating conductivity and/or magnetic permeability can be detected 

• Disadvantages 

– Disbond between coating and substrate is difficult or impossible to detect 

– Depending on the application, one or several layers have to be

conductive and/or ferromagnetic

– Only thickness (to certain range) is measured if the coating is non- conductive and non-ferromagnetic (paint, organic insulation, others) 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 Page 194
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Conclusions and Recommendations 

• New technologies and modeling approach allow development of new 

techniques for problems that have been outside of the scope of 

current procedures 

• Computer modeling especially for complex cases brings the following 

benefits: 

– Significantly reduced time for development and validation of 

procedures used for inspection of complex geometry structures 

where NDT technique performance is unknown 

– Significant cost benefits due to elimination and reduction of 

experimental specimens and mock-ups needed for technique and 

procedure validation 

– Increased inspection reliability and repeatability 

– Fast interpretation of field NDE data and reduction of unnecessary 

repairs 

– Quick customer support turnaround 

• Several NDE techniques may be required to fully characterize the 

coating-substrate structure on the pipelines 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 Page 195
Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

Failure Modes of Pipeline

Coatings

Matt Dabiri

Williams Gas Pipeline

Houston, TX

Commercial products may be included in this presentation. This does not imply 

endorsement or criticism of these particular products or services by the speaker 

or any workshop participant. 

The materials presented are for use and distribution as part of OPS/NIST 

Advanced Coatings for Pipelines Workshop only. The author’s permission is 

required for any other subsequent use. 

Today’s Discussion 

• Why Coatings Fail 

• What is the Life of a 

Coating 

• Failures 

• Lessons Learned 

• Wrap Up 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 USA Page 196
Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

Why Coatings Fail 

• Age 

• Selection 

• Application 

What is the Life of a Coating? 

• Determined by design 

• Determined by use 

• Determined by 

selection 

• Determined by 

application 

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Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

Lessons Learned 

• Select Coatings by 

Service Conditions 

• Do not select 

coatings by price 

• Use a Quality 

Specification 

• Use a Quality 

Applicator 

• Use a Qualified 

Inspector 

93 

Three players 

• Coating manufacturer 

“We have the very best materials – no 

second-best here! ” 

• Coating applicator 

“We’re the best and the greatest coating 

applicators – no improper coating jobs! ” 

• Customer 

... is left holding the bag when the coating 

fails 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 USA Page 242
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95

96

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97 

98 

Wrap Up 

• Any more discussion? 

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Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

Coating Identification, 

Inspection, and Evaluation 

Technologies 

Group 3

Robert (Bob) Smith (DOT)

Suresh Babu (EWI)

Participants (Government & Industry

Researchers)

Three major topics are defined as 

following. 

• Identification: Define the problem 

– Making sure that there is a coating problem as

opposed to assuming that there is a coating

performance problem.

• Inspection: Characterize the problem 

– Techniques to characterize the problem, where, when 

• Evaluation: Evaluate the impact of the problem 

– Make sure that what we detect is a problem 

– Now what do we do about it? 

– Solution is not covered here – hand off to Group 4. 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 Page 250
Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

Identification: Priorities 

• How big is the problem that coating failure leads to 

pipeline performance? (Knowledge) 

– Economics

– Risk

– Statistics 

• Collection of lice-cycle data (Knowledge and Standards) 

– Material 

– Construction 

– Transportation 

– Operational 

– Environmental 

• Techniques to identify of disbonded and shielding 

locations (Tools) 

– New and existing pipes 

Inspection: Priorities 

• Better techniques characterize flaws (Tools) 

• Modeling the inspection techniques (Knowledge 

and Tools) 

– Optimization of inspection 

• Training to prevent damage (Knowledge and 

Standards) 

– Matt’s pictures on failures 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 Page 251
Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

Evaluation & Assessment Priorities 

• Establish evaluation standard (Knowledge, Tools and 

Standards): 

– How to evaluate what is a good coating? 

– Validate the evaluation 

– Validate manufacturer claims 

• Re-evaluate the minimum standards (Knowledge and 

Standards) 

– Is the current minimum standard good enough? 

– Documentation of the life-cycle data 

• Welding and coatings communications (Knowledge, 

Standard) 

– Implication of interactions needs to be understood 

• Develop Smart coatings (Tools) 

– May be the focus of group 1; but the coating should be designed 

so that it will aid in the identification, inspection and evaluation 

easily. 

Summary

• How big is the problem? 

– We need to make a convincing case. 

• We need to make sure that “best” coating goes 

into specific application which minimizes repair. 

– Pro-active design for specific environment 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 Page 252
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Identification: All issues 

• Training – Standards 

• Poor Records 

– Basic Parameters of Coatings 

– Basic Parameters of defects 

• Reducing Digs or minimize dig size (size, key hole) 

• Minimize damage during 

• Disbond – defects and no defects 

• Failure modes 

• Modeling life cycle of coating integrity 

• Improve the detection of disbond and shielding 

– Sometimes lack of cathodic protection may be the problem 

• Information sharing 

– Data structure, fields of data 

– Standard 

Inspection – All issues 

• Modeling 

• Improve GUT / Emag 

• Training 

• Limiting Digs 

• Preventing damage while inspection 

• Data 

– Standardization, collection, sharing, flaw sizing and 

bond strength 

• Develop / improve infield bond assessment and 

technology (real time) 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 Page 253
Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

Evaluation and Assessment: All issues 

• How good is the standard? 

– Is it very discriminative or strict? 

– Are standards use in beginning, good enough – 

minimum standard? 

• Data 

– Define/standards 

• Risk 

• Economic 

• Validating manufacturing application claims 

• Smart coatings 

Identification, Inspection, Evaluation and

Assessment must be integral part of life-cycle.

• List of Issues 

were identified 

• Nature of Issues 

were identified 

Coating 

Property 

Pipe-System 

Property 

In-service 

Monitoring 

Pipe Laying 

Down 

Backfill 

Operation 

Steel 

Property 

Girth 

Welding 

In-field 

Coating 

Coating 

Property 

Pipe 

Transport 

Pipe 

Storage 

Coating 

Property 

Coating Design 

Application 

Seam 

Welding 

Steel 

Property 

– Knowledge 

– Tools 

– Standards 

• Urgency of 

issues were 

discussed 

• Ranking was 

done in each 

category. 

Repair & 

Rejuvenation 

Evaluate the 

Repairs 

In-service 

Monitoring 

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Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

Rank Nature 

(K,T,S) 

Description Priority 

(1) 

Priority 

(2) 

Comments / 

Benefits 

1 K/T Data base of coating technical data sheets, 

coating formulation history, testing results 

(based on accepted standard) & MSDS sheets. 

Technical data sheets – standard formats. 

Updating technical data sheets for reformulated 

coatings for all customers. Automatic updates – 

time limit for coating validity. 

Materials storage standards. Expiration dates for 

coating materials. 

Minimum third party evaluation of new or 

reformulated coatings. 

9 10 Knowledge 

sharing/ 

Development 

of up to date 

standards 

2 S Applicator & Inspector certification / Training 

Outcome – develop standards for applicators & 

inspectors. 

9 9 Provide 

standardized 

application & 

QC 

3 K/S Repair coating matrix – based on pipe diameter 

& temperature & soil stress. 

Coating Selection & Risk Assessment Profile & 

Results of Improper Selection 

8 8 Provide 

coating 

selection tool 

for operators 

4 R&D Perform performance testing & environmental 

assessment of abrasive blasting materials. 

4 Separated 

out/ no initial 

vote 

5 NACE Pipeline Coatings Industry Users Group Agreed to let 

NACE TEG to 

initiate 

6 R&D NDE & guided wave through coating corrosion 

evaluation- How accurate - assess existing 

techniques – develop new techniques. 

6 4 Provide 

operator 

knowledge 

regarding 

defect 

detection 

techniques. 

7 R&D Non intrusive disbondment testing – adhesion 

testing, wet film & dry film, hardness & % cure 

new & existing coatings. 

4 No damage to 

coating during 

testing. 

8 R&D Repair Sleeves – Composite & Steel - Field 

Applied Repairs. 

Required to coat. Coating of transition bridge. 

Compatibility issues. Setup and curing issues. 

3 Provide 

operator 

knowledge re 

sleeve 

reapairs 

9 R&D Research more effective coating removal 

methods. Technology transfer from DOE or NSF. 

4 Cost savings 

for operators/ 

efficiencies 

10 R&D Wet surface coatings operated at high 

temperatures – R&D for new materials. 

1 Problem 

solution 

11 R&D Repair coatings used in high or low pH 

environments. Mine run off – flue ash. 

2 Problem 

solution 

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Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

12 R&D Alternative methods of concrete removal for 

marsh areas 

1 Problem 

solution 

13 R&D Backfill – pipe support after backfill – piers – 

breakers – sand bags – research technologies. 

1 Problem 

solution 

14 R&D Time dependent coating compatability testing & 

minimum level requirements. 

1 Increased 

information 

regarding 

coating 

durability. 

Notes: 

1 Number of votes: Approach involved open 

discussion & selection of possible projects 

followed by initial vote (Show Of Hands) 

2 Number of votes: Second vote & Discussion of 

top 4 items 

Natue 

K= Knowledge, Scientific Understanding 

T= Technology or tool development 

S= Standardization of tools or procedures 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 USA Page 257
Office of Pipeline Safety

Office of Hazardous Materials Safety

Pipeline and Hazardous 

Materials Safety Administration 

Workshop on Advanced Coatings 

R&D for Pipelines and Related 

Facilities

June 9-10, 2005

Gaithersburg, MD - USA 

•

•

–

• –

•

•



Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

General Discussion

Next Steps

Post all presentations on the Web and send attendees CD -2 weeks

 Review the Working Groups recommendations and prepare an

 Advance Coatings workshop Report findings July 15

Send report out for comments to the Steering Committee. August 1 

(Once comments are back & incorporated, post the report on the OPS

 web site: http://primis.rspa.dot.gov/rd/

 Notify all attendees of the posting by e-mail 

Prepare and issue a Coatings focused Solicitation 

Knowledge Tools or Standards –September 1 

Office of Pipeline Safety 

Office of Hazardous Materials Safety 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 USA Page 258
Office of Pipeline Safety

Office of Hazardous Materials Safety

Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

http://primis.rspa.dot.gov/rd

OPS R&D Website 

Office of Pipeline Safety 

Office of Hazardous Materials Safety 

Jim Merritt 

Department of Transportation 

Research & Special Programs Administration 

Office of Pipeline Safety 

P(303) 683-3117 

mobile (303) 638-4758 

F(303) 346-9192 

Email james.merritt@dot.gov 

Robert Smith 

Department of Transportation 

Research & Special Programs Administration 

Office of Pipeline Safety 

P(202) 366-3814 

F(202) 366-4566 

Email robert.smith@dot.gov 

Jeff Wiese 

Department of Transportation 

Research & Special Programs Administration 

Office of Pipeline Safety 

P(202) 366-2036 

F(202) 366-4566 

Email jeff.wiese@dot.gov 

OPS R&D Program Contacts OPS R&D Program Contacts

Visit us at http://primis.rspa.dot.gov/rd 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 USA Page 259
Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

Office of Pipeline Safety 

Office of Hazardous Materials Safety 

Thank You 

for Attending 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 USA Page 260
Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

Appendix A - Meeting Agenda 

Advanced Coatings for Pipelines and Related Facilites Workshop 

National Institute of Standards and Technology 

Gaithersburg, MD 20899 USA 

Thursday June 9, 2005 

7:30 Bus from Hotel to NIST 

7:45 On-site registration - Lecture Room A 

8:00 Welcome - Richard Ricker, NIST 

8:05 Workshop Objectives - Jim Merritt/Bob Smith, OPS 

8:15 Report on Findings of MMS Offshore Coatings Workshop 

D. Olson and B. Mishra, Colorado School of Mines 

8:45 Review of Existing Pipeline Coatings Standards 

Sankara Papavinasam and R. Winston Revie, CANMET, Natural 

Resources, Canada 

9:15 Update on Current Standards Activities 

ASTM - R. Ricker for Don Kathrein, Tapecoat and Chair ASTM D01.48 

NACE - Cliff Johnson, NACE 

CSA - Franci Jeglic, National Energy Board, Canada 

9:45 Break 

10:00 Keynote Overviews 

1. Owner/Operator Viewpoint on Coatings Issues 

- Jeff Didas, Colonial Pipeline 

2. PRCI Activities and Coatings Deterioration Studies 

- Greg Ruschau, CC Technologies 

- Jenny Been, NOVA Chemicals Corporation 

3. GTI Activities and Preliminary Results from Coatings Test Program - Paul Beckendorf, GTI 

11:30 Lunch - NIST cafeteria (at attendees expense) 

12:30 Keynotes (cont.) 

4. Coatings Fabrication Issues (Field and Factory)

 - Peter Singh, Bredero Shaw 

5. NDE and Eddy Current Methods for Pipeline Coating Inspection 

- S. Babu and E. Todorov, Edison Welding Institute 

6. Coatings Failure Modes 

- M. Dabiri, Williams Pipeline 

2:00 Break 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 USA Page 261
Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

2:30 Working Groups Convene 

1) Coating Test Methods and Materials Development 

- Admin Bldg (#101) Lecture Room A 

2) Coating Application Technologies and Quality Control (Mill Applied) 

- Materials Bldg (#223), Rm. A250 

3) Coating Identification, Inspection, and Evaluation Technologies 

- Materials Bldg (#223), Rm. B307 

4) In-Field Technologies for Joints, Repairs, and Rehabilitation 

- Materials Bldg (#223), Rm. B307 

5:00 Adjourn for the Day 

5:10 Bus from NIST to Hotel 

Reception and Cook/Out at the Home of R. E. Ricker 12809 Talley Lane 

Friday June 10, 2005 

7:30 Bus from Hotel to NIST 

8:00 Working Groups Reconvene - Various Meeting Rooms (TBD) 

10:00 Break 

10:15 Working Group Reports (20 minutes each) 

1) Coating Test Methods and Materials Development 

- Admin Bldg (#101) Lecture Room A 

2) Coating Application Technologies and Quality Control (Mill Applied) - Materials Bldg (#223), Rm. A250 

3) Coating Identification, Inspection, and Evaluation Technologies 

- Admin Bldg (#101) Lecture Room D 

4) In-Field Technologies for Joints, Repairs, and Rehabilitation 

- Admin Bldg (#101) Lecture Room E 

11:35 General Discussion / Next Steps - Jim Merritt/Bob Smith, OPS 

12:00 Adjourn Workshop / Lunch - NIST cafeteria (at own expense) 

1:00 Tours of NIST Laboratories – Admin Lecture Rm A 

1:15 Residual Stress Measurements in Pipeline Steels 

- M. Law , T. Gnaeupel-Herold, and H. Prask (NCNR) 

2:00 High Speed Deformation Lab (Kolsky Bar) 

- S. Mates and S. Ridder (Metallurgy Div.) 

2:45 Coatings Adhesion and Appearance Labs

 - T. Nguyen (BFRL, Building Materials Div.) 

3:30 Corrosion, SCC, and CF Labs 

- R. E. Ricker and D. Pitchure (Metallurgy Div.) 

4:00 Conclude 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 USA Page 262
Appendix B - Registration List

Advanced Coatings for Pipelines and Related Facilites Workshop

National Institute of Standards and Technology

Gaithersburg, MD 20899 USA

June 9-10, 2005

Rodney Anderson

Technology Manager

US Department of Energy

PO Box 880 

Morgantown, WV 26507 USA

Phone: (304) 285-4709

Fax: (304) 285-4216

rodney.anderson@netl.doe.gov

Sudarsanam Babu

Technology Leader

Edison Welding Institute

1250 Arthur E Adams Drive

Columbus, OH 43221 USA

Phone: (614) 688-5206

suresh_babu@ewi.org

Paul Beckendorf

Executive Director

Distribution & PL Tech Ctr

Gas Technology Institute

1700 South Mount Prospect Rd.

Des Plaines, IL 60018 USA

Phone: (847) 768-0889

Fax: (847) 768-0569

paul.beckendorf@gastechnology.org

Jenny Been

Corrosion Research Engineer

NOVA Chemicals Corporation

2928 - 16 Street N.E.

Calgary, Alberta 1 T2E 7K7 CANADA

Phone: (403) 250-4750

Fax: (403) 250-0633

beenj@novachem.com

Allan Beshore

Senior General Engineer

US DOT/PHMSA/OPS

901 Locust St., Rm 462

Kansas City MO 64106 USA

Phone: (816) 329-3811

allan.beshore@dot.gov

Sean Brossia

Director of Research

CC Technologies

5777 Frantz Road 

Dublin OH 43017 USA

Phone: (614) 761-1214

Fax: (614) 761-1633

sbrossia@cctechnologies.com

Benjamin Chang

Staff Research Engineer

Shell Global Solutions

14742 Oak Bend Dr.

Houston TX 77079 USA

Phone: (281) 636-7794

Fax: (281) 544-6060

BTACHANG@Gmail.COM

Larry Christie

Coatings Market Manager

NACE International

1440 South Creek Dr.

Houston TX 77084-4906 USA

Phone: (281) 228-6202

Fax: (281) 228-6302

larry.christie@nace.org

Workshop on Advanced Coatings R&D for Pipelines and Related Facilities June 9-10, 2005 NIST, Gaithersburg, MD 20899 USA Page 263
Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

David Cope 

Corrosion Specialist 

Washington Gas 

6801 Industrial Road 

Springfield VA 22556 USA 

Phone: (703) 750-5853 

Fax: (703) 750-4447 

dcope@washgas.com 

Matt Dabiri 

Principal Engineer 

Williams 

P O Box 1396 

Houston TX 77251-1396 USA 

Phone: (713) 215-2714 

Fax: (713) 215-2222 

matt.dabiri@williams.com 

Jeffrey Didas 

Corrosion Program Manager 

Colonial Pipeline Company 

2607 Willard Road 

Richmond VA 23294 USA 

Phone: (804) 672-2718 

Fax: (804) 672-3080 

jdidas@colpipe.com 

Daniel Driscoll 

Senior Project Manager 

U.S. Department of Energy, NETL 

P.O. Box 880 

3610 Collins Ferry Road 

Morgantowm WV 26507-0880 USA 

Phone: (304) 285-4717 

Fax: (304) 285-4403 

daniel.driscoll@netl.doe.gov 

Michael Durbin 

Corrosion Specification Specialist 

Sherwin Williams Company 

201 Riverview Road 

Stevensville MD 21666 USA 

Phone: (443) 801-8776 

Fax: (410) 604-0816 

mike.c.durbin@sherwin.com 

Michael Else 

Research Engineer 

Minerals Management Service 

381 Elden Street 

Mail Stop 4021 

Herndon VA 20170-4817 USA 

Phone: (703) 787-1769 

Fax: (703) 787-1549 

michael.else@mms.gov 

Richard Espiner 

Pipeline Engineer 

BP 

Chertsey Road 

Sunbury on Thames 

1 TW16 7LN UNITED KINGDOM 

Phone: +44 1932 762295 

Fax: +44 1932 738414 

richard.espiner@uk.bp.com 

Steven Gauthier 

Gas Technology Institute 

1700 South Mount Prospect Rd. 

Des Plaines IL 60018 USA 

Phone: (847) 768-0805 

Fax: (847) 768-0569 

steve.gauthier@gastechnology.org 

Michael Hagan 

Senior Corrosion Specialist 

Washington Gas 

6801 Industrial Rd. 

Springfield VA 20601 USA 

Phone: (703) 750-7563 

Fax: (703) 750-4447 

mhagan@washgas.com 

Harvey Haines 

Senior Program Manager 

PRCI 

1401 Wilson Blvd. 

Arlington VA 22031 USA 

Phone: (703) 387-0190 

hhaines@prci.org 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 USA Page 264
Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

Gregory Hindman 

General Engineer 

Department of Transportation 

233 Peachtree St, Suite 600 

Atlanta GA 30303 USA 

Phone: (404) 832-1154 

Fax: (404) 832-1169 

gregory.c.hindman@dot.gov 

Stephen Horvath 

General Engineer 

DOT/OPS 

409 3RD ST., S.W.- SUITE 300 

WASHINGTON, D.C. DC 20024 USA 

Phone: (202) 260-8506 

Fax: (202) 260-8530 

stephen.horvath@dot.gov 

Robert House 

Metallurgical Inspection Coordinator 

Unocal 76 

14141 Southwest Freeway 

Sugar Land TX 77478 USA 

Phone: (281) 287-7423 

Fax: (281) 274-9737 

Houserw@unocal.com 

Franci Jeglic 

Technical Specialist 

National Energy Board 

444 7th Ave. SW 

1424 Joliet Ave. 

Calgary 1 T2P 0X8 CANADA 

Phone: (403) 299-2774 

Fax: (403) 292-5875 

fjeglic@neb-one.gc.ca 

Andrea Johnson 

American Petroleum Institute 

1220 L street NW 

Washington DC 20005 USA 

Phone: (202) 682-8107 

johnsona@api.org 

Cliff Johnson 

Public Affairs Director 

NACE International 

1440 South Creek Drive 

Houston TX 77084 USA 

Phone: (281) 228-6213 

Fax: (281) 228-6313 

cliff.johnson@nace.org 

Mobeen Khan 

Manager 

New Jersey Natural Gas Company 

1415 Wyckoff Rd. 

PO Box 1464 

Wall NJ 7719 USA 

Phone: (732) 919-8035 

Fax: (732) 919-0735 

mukhan@njng.com 

Brian Leis 

senior research leader 

Battelle 

505 king ave 

columbus OH 43201 USA 

Phone: (614) 424-4421 

leis@battelle.org 

James Levers 

Supervisor - Pipeline Integrity 

New Jersey Natural Gas Co. 

1415 Wyckoff Rd 

PO Box 1464 

Wall NJ 7719 USA 

Phone: (732) 938-7880 

Fax: (732) 919-0735 

jwlevers@njng.com 

Ronald Lewoniuk 

Technical Service Specialist 

NOVA Chemicals Corporation 

3620 - 32 street NE 

Calgary, Alberta 1 T1Y 6G7 CANADA 

Phone: (403) 291-8431 

Fax: (403) 291-0493 

lewoniur@novachem.com 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 USA Page 265
Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

Wei Luo J. Bruce Nestleroth 

Graduate Assistant Senior Research Scientist 

Penn State University Battelle 

212 Earth-Engineering Sci. Bldg. 505 King Ave 

University Park, PA 16802 USA Columbus OH 43201 USA 

Phone: (814) 863-1852 Phone: (614) 424-3181 

Fax: (814) 863-8164 Fax: (614) 458-3181 

wxl168@psu.edu nestlero@battelle.org 

Garry Matocha Phillip Nidd 

Principal Engineer Principal 

Duke Energy Gas Transmission PGNGroup Consulting L.P. 

P. O. Box 1642 1003 Redcedar Lnane 

Houston TX 77251 USA Houston TX 77094 USA 

Phone: (713) 627-4894 Phone: (713) 562-3702 

Fax: (713) 627-5490 Fax: (832) 201-9401 

gmmatocha@duke-energy.com phillip.nidd@pgngroup.com 

Donald McCoy David L. Olson 

Pipeline Safety Specialist Professor 

PHMSA/Transportation Safety Institute Colorado School of Mines 

P.O. Box 25082 PHP-70 1500 Illinois Street 

Oklahoma City OK 73125 USA Metall & Mater Engineering 

Phone: (405) 954-7306 Golden CO 80401 USA 

Fax: (405) 954-0206 Phone: (303) 273-3955 

dmccoy@tsi.jccbi.gov Fax: (303) 384-2189 

dolson@mines.edu 

James Merritt 

R&D Program Manager Sankara Papavinasam 

U.S. DOT Office of Pipeline Safety Research Scientist 

793 Countrybriar Lane CANMET Materials Technology 

Denver CO 80129 USA Laboratory 

Phone: (303) 683-3117 568 Booth Street 

Fax: (303) 346-9192 Ottawa 1 K1A 0G1 CANADA 

james.merritt@dot.gov Phone: (613) 947-3603 

Fax: (613) 992-8735 

Brajendra Mishra spapavin@nrcan.gc.ca 

Professor 

Colorado School of Mines Neil Pittman 

1500 Illinois Street Sr. Engineer 

Metall & Mater Engineering El Paso Corporation 

Golden 15170 Commerce Drive North 

CO 80401 USA Dearborn MI 48120 USA 

Phone: (303) 273-3893 Phone: (313) 240-7211 

Fax: (303) 384-2189 Fax: (313) 271-0047 

bmishra@mines.edu neil.pittman@elpaso.com 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 USA Page 266
Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

Robert Winston Revie 

Program Manager, Infrastructure 

Reliability 

CANMET Materials Technology 

Laboratory 

568 Booth Street 

Ottawa 1 K1A 0G1 CANADA 

Phone: (613) 992-1703 

Fax: (613) 992-8735 

wrevie@nrcan.gc.ca 

Bob Rogers 

ExxonMobil Development Company 

17001 Northchase Drive 

Mail Code: DEV-GP5-584 

Houston TX 77060 USA 

Phone: (281) 654-0483 

robert.h.rogers@exxonmobil.com 

Joseph Rose 

FBS, Inc. 

2134 Sandy Drive Suite #14 

State College PA 16803 USA 

Phone: (814) 234-3437 

Fax: (814) 234-3457 

jrose@fbsworldwide.com 

Gregory Ruschau 

Testing Manager 

CC Technologies 

5777 Frantz Rd. 

Dublin OH 43017 USA 

Phone: (614) 761-1214 

Fax: (614) 761-1633 

gruschau@cctechnologies.com 

Christina Sames 

Director, Engineering Services 

American Gas Association 

400 N Capitol St NW 

Washington DC 20001 USA 

csames@aga.org 

Buddy Secor 

Mgr - Engineering Technical Services 

Washington Gas 

6801 Industrial Road 

Springfield VA 22151 USA 

Phone: (703) 750-5939 

Fax: (703) 750-4447 

bsecor@washgas.com 

Tom Siewert 

Acting Chief 

NIST 

325 Broadway 

Boulder CO 80305 USA 

Phone: (303) 497-3523 

siewert@boulder.nist.gov 

Robert Sillers 

Integrity Engineer, E.I.T. 

Enbridge Pipelines Inc. 

10201 Jasper Avenue 

Edmonton, AB 1 T5J 3N7 CANADA 

Phone: (780) 420-8172 

Fax: (780) 420-5234 

rob.sillers@enbridge.com 

Peter Singh 

Manager, Global Coating Technology 

Bredero Shaw 

1200 630 3rd Ave SW 

Calgary 1 T2L 4L4 CANADA 

Phone: (403) 218 8229 

Fax: (403) 261-9078 

psingh@brederoshaw.shawcor.com 

Elizabeth Skalnek 

Senior Engineer 

USDOT/PHMSA/OPS 

400 7th St, SW Room 2103 

Washington DC 20590 USA 

Phone: (202) 366-2694 

Fax: (202) 366-4566 

elizabeth.skalnek@dot.gov 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 USA Page 267
Workshop on Advanced Coatings R&D for Pipelines and Related Facilities

Robert Smith 

R&D Manager DOT/OPS 

400 7th Street, S.W. 

Washington DC 20590 USA 

Phone: (202) 366-3814 

 robert.w.smith@dot.gov 

Frank Song 

Research Engineer 

Southwest Research Institute 

6220 Culebra Road 

San Antonio TX 78238 USA 

fsong@swri.org 

Mike Surkein 

ExxonMobil Development Company 

17001 Northchase Drive 

Mail Code: DEV-GP5-584 

Houston TX 77060 USA 

Phone: (281) 654-4821 

William Tao 

The Sherwin-Williams Co. 

549 E. 115th St. 

Chicago IL 60628 USA 

william.w.tao@sherwin.com 

George Tenley 

President 

PRCI 

1401 Wilson Blvd. 

Arlington VA 22031 USA 

Phone: (703) 387-0190 

Evgueni Todorov 

Senior NDE Engineer 

Edison Welding Institute 

1250 Arthur E. Adams Drive 

Columbus OH 43016 USA 

Phone: (614) 688-5268 

Fax: (614) 688-5001 

evgueni_todorov@ewi.org 

Stephen Urban 

Corrosion Engineer 

New Jersey Natural Gas Co. 

1415 Wyckoff Rd 

Wall NJ 7719 USA 

Phone: (732) 938-7091 

Fax: (732) 919-0735 

srurban@njng,com 

Robert Worthingham 

Senior Corrosion Engineer 

TransCanada PipeLines 

450 1st Street SW 

Calgary 1 T2P 5H1 CANADA 

Phone: (403) 920-6033 

Fax: (403) 920-2393 

robert_worthingham@transcanada.com 

June 9-10, 2005 NIST, Gaithersburg, MD 20899 USA Page 268