NACE Internal Corrosion for Pipelines Advanced.pdf

INTERNAL CORROSION FOR PIPELINES ADVANCED

JANUARY 2011

IMPORTANT NOTICE:

Neither the NACE International, its officers, directors, nor members thereofaccept any responsibility for the use of the methods and materials discussedherein. No authorization is implied concerning the use of patented or copyrightedmaterial. The information is advisory only and the use of the materials andmethods is solely at the risk of the user.

Printed in the United States. All rights reserved. Reproduction of contents inwhole or part or transfer into electronic or photographic storage withoutpermission of copyright owner is expressly forbidden.

Acknowledgements

NACE International would like to extend a special thank you to BP ExplorationAlaska for its contribution toward the development of this course. The time andexpertise of many members of NACE International have gone into this material.Their dedication and efforts are greatly appreciated by the authors and by thosewho have assisted in making this work possible.

The scope, desired learning outcomes and performance criteria of this course weredeveloped by the Internal Corrosion Subcommittee under the auspices of theNACE Education Administrative Committee in cooperation with the NACECertification Administrative Committee.

On behalf of NACE, we would like to thank the Advanced Internal Corrosion forPipelines task group for its work. Their efforts were extraordinary and their goalwas in the best interest of public service to develop and provide a much neededtraining program that would help improve corrosion control efforts industry-wide.We also wish to thank their employers for being generously supportive of thesubstantial work and personal time that the members dedicated to this program.

Advanced Internal Corrosion for Pipelines Course Development Task Group

Laurie Perry, Chair Southern California Gas Co. Los Angeles, California

Garry Matocha, Vice-Chair Spectra Energy Houston, Texas

Tim Bieri BP Exploration Alaska Anchorage, Alaska

Jerry Bauman Cimarron Engineering Ltd.Calgary, ABCANADA

Carlos Palacios CIMA-TQEdo AnzoateguiVENEZUELA

Gerald Pogemiller JP Consultants Inc.Hot Springs Village, Arkansas

Tim Zintel ANR PipelineTroy, Michigan

Drew Hevle El Paso CorporationHouston, Texas

Pat Teevens Broadsword Corrosion Eng LtdCalgary, ABCANADA

Sankara Papavinasam CANMET Materials Tech. LabOttawa, ONCANADA

Tom Pickthal EnhanceCoMissouri City, Texas

Michael Brockman El Paso CorporationHouston, Texas

Richard Eckert BP Exploration AlaskaAnchorage, Alaska

Bruce Cookingham BP Exploration AlaskaAnchorage, Alaska

This group of NACE members worked closely with the contracted coursedevelopers Oliver Moghissi, Kathy Krajewski and Lynsay Bensman of DNVColumbus, Inc.Thank you to the following companies for contributing photos and other imagesused to enhance the Advanced Internal Corrosion for Pipelines material:

BP Exploration AlaskaNalco Energy ServicesIn Line Services Inc.

ARC SpecialtiesEl Paso

Welcome to the Internal Corrosion for

Pipelines Advanced Course

OverviewThe Internal Corrosion for Pipelines Advanced course focuses on themonitoring techniques and mitigation strategies required to assess internalcorrosion and develop and manage internal corrosion control programs. Datainterpretation, analysis and integration, as well as criteria for determiningcorrective action for high-level internal corrosion problems within a pipelinesystem, will be covered in detail. The course will be 5 days in length. Studentssuccessfully completing the course examination, and who meet the requirements,can apply for certification as a Senior Internal Corrosion Technologist.

Who Should AttendThis course will provide in depth coverage of internal corrosion control and istargeted for individuals who are responsible for the implementation, maintenanceand management of an internal corrosion control program for a pipeline system.

PrerequisitesTo attend this course, students should meet the requirements on one of thefollowing paths:

PATH 1

Hold Internal Corrosion Technologist Certification.

PATH 2

8 years internal corrosion work experience in a pipeline environment OR

4 years internal corrosion work experience in a pipeline environment

PLUS

Bachelors degree in one of the following disciplines:

Chemistry, Microbiology, Biology, Chemical Engineering, Metallurgical Engineering

LengthThe course beings Monday and ends Friday with class starting at 8:00 am andending at approximately 5:00 pm.

Quizzes and ExaminationsThere will be quizzes distributed during the week and reviewed in class by theinstructors.

The final written exam, which will be given on Friday, will consist of 100multiple-choice questions. The examination is open book and students may bringreference materials and notes into the examination room. Exam questions maycome from text, powerpoints, appendices, case studies, group studies or anyother material covered during the course.

A score of 70% or greater is required for successful completion of the course. Allquestions are from the concepts discussed in this training manual. Non-communicating, battery-operated, silent, non-printing calculators, includingcalculators with alphanumeric keypads, are permitted for use during theexamination. Calculating and computing devices having a QWERTY keypadarrangement similar to a typewriter or keyboard are not permitted. Such devicesinclude but are not limited to palmtop, laptop, handheld, and desktop computers,calculators, databanks, data collectors, and organizers. Also excluded for useduring the examination are communication devices such as pagers and cell phonesalong with cameras and recorders.

Instructions for Completing the ParSCORETM Student Enrollment Sheet/Score Sheet

1. Use a Number 2 (or dark lead) pencil.2. Fill in all of the following information and the corresponding bubbles for each

category: ID Number: Student ID, NACE ID or Temporary ID provided

PHONE: Your phone number. The last four digits of this number will be yourpassword for accessing your grades on-line (for privacy issues, you maychoose a different four-digit number in this space)

LAST NAME:Your last name (surname)

FIRST NAME: Your first name (given name)

M.I.: Middle initial (if applicable)

TEST FORM: This is the version of the exam you are taking

SUBJ SCORE: This is the version of the exam you are taking

NAME: _______________ (fill in your entire name)

SUBJECT: ____________ (fill in the type of exam you are taking, e.g., CIPLevel 1)

DATE: _______________ (date you are taking exam)

3. The next section of the form (1 to 200) is for the answers to your exam ques-tions.

All answers MUST be bubbled in on the ParSCORETM Score Sheet.Answers recorded on the actual exam will NOT be counted.

If changing an answer on the ParSCORETM sheet, be sure to erase com-pletely.

Bubble only one answer per question and do not fill in more answers than theexam contains.

EXAMINATION RESULTS POLICY AND PROCEDURES

It is NACE policy to not disclose student grades via the telephone, e-mail, or fax.Students will receive a grade letter, by regular mail or through a companyrepresentative, in approximately 6 to 8 weeks after the completion of the course.However, in most cases, within 7 to 10 business days following receipt of examsat NACE Headquarters, students may access their grades via the NACE Web site.

Web instructions for accessing student grades on-line:

Go to: www.nace.org

Choose: Education

Grades

Access Scores Online

Find your Course ID Number (Example 07C44222 or 42407002) in the dropdown menu.

Type in your Student ID or Temporary Student ID (Example 123456 or4240700217)*.

Type in your 4-digit Password

(the last four digits of the telephone number entered on your Scantron exam form)

Click on Search

Use the spaces provided below to document your access information:

*Note that the Student ID number for NACE members will be the same as theirNACE membership number unless a Temporary Student ID number is issued atthe course. For those who register through NACE Headquarters, the Student IDwill appear on their course confirmation form, student roster provided to theinstructor, and/or students name badges.

For In-House, Licensee, and Section-Registered courses, a Temporary ID numberwill be assigned at the course for the purposes of accessing scores online only.

STUDENT ID__________________COURSE CODE_________________

PASSWORD (Only Four Digits) ___________________

For In-House courses, this information may not be posted until payment has beenreceived from the hosting company.

Information regarding the current shipment status of grade letters is available onthe web upon completion of the course. Processing begins at the receipt of thepaperwork at NACE headquarters. When the letters for the course are beingprocessed, the Status column will indicate Processing. Once the letters aremailed, the status will be updated to say Mailed and the date mailed will beentered in the last column. Courses are listed in date order. Grade letter shipmentstatus can be found at the following link:

http://web.nace.org/Departments/Education/Grades/GradeStatus.aspx

If you have not received your grade letter within 2-3 weeks after the postedMailed date (6 weeks for international locations), or if you have troubleaccessing your scores on-line, you may contact us at [email protected].

Certification To qualify for certification as an Senior Internal Corrosion Technologist,candidates must:

1) successfully complete the written exam

2) satisfy the course prerequisites

3) submit the Senior Internal Corrosion Technologist certification application.

For more certification information, please visit www.nace.org/Education/Coursesand Programs.

Certification candidates who do not meet the prerequisites at the time of courseattendance will have five (5) years from the examination date to satisfy the course/certification prerequisites and apply for certification.

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NACE International 2009 Internal Corrosion for Pipelines Advanced Course Manual September 2009

Internal Corrosion for Pipelines AdvancedTable of Contents

Chapter 1: Do I Have An Internal Corrosion Problem?What is Internal Corrosion?. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

Basic Corrosion Cell . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1Forms of Corrosion. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2

Uniform Corrosion. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2Localized Corrosion. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3

Pitting . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3Crevice Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6Mesa Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6Weld Zone Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7

Environmentally Assisted Cracking (EAC). . . . . . . . . . . . . . . . . . . . . . . . . . . 8Flow-Assisted Damage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9

Corrosion Mechanisms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9Galvanic Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9Concentration Cells . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12

Potentially Corrosive Species . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13Carbon Dioxide (CO2). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13Hydrogen Sulfide (H2S) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16Oxygen . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17Microbiologically Influenced Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19

Environmentally Assisted Cracking Mechanisms . . . . . . . . . . . . . . . . . . . . . . . 21Hydrogen Damage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21

Hydrogen Induced Cracking (HIC). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21Hydrogen Embrittlement (HE) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23Stress-Oriented Hydrogen Induced Cracking (SOHIC) . . . . . . . . . . . . . . 23Sulfide Stress Cracking (SSC) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23

Stress Corrosion Cracking (SCC) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24Liquid Metal Embrittlement (LME) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24

Flow-Assisted Damage Mechanisms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24Erosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25 Impingement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25Erosion-Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25Cavitation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26

What Type of Pipeline Is It? . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27Upstream Petroleum Production Pipelines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27

Crude Oil/ Multiphase High Vapor Pressure (HVP) Liquid . . . . . . . . . . . . . 28Water Cut . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29

Natural Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29

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Internal Corrosion for Pipelines Advanced Course Manual NACE International 2009September 2009

Water Services (Sea, Produced, Fresh) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30Fresh Water . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31Sea Water . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31Produced Water . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32

Transmission Pipelines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32Liquid Pipelines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32

Crude Oil (Low Vapor Pressure (LVP) Liquids) . . . . . . . . . . . . . . . . . . . 33Sulfur Content. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34Total Acid Number (TAN) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34Basic (Bottom) Sediment and Water (BS&W). . . . . . . . . . . . . . . . . . . . 35

Product Pipelines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35Anhydrous Ammonia (NH3). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36

Natural Gas Pipelines. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37Dry Transmission Lines. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37

Distribution Pipelines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38Pipeline Facilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39

Storage Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39 Other Service Pipelines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40

Slurry . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40Sewage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41High Pressure Steam . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41Hydrogen . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41Super Critical CO2. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41Jet Fuel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42Acid Gas Injection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42

Do I Have an IC problem?. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43Failures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43

Number of Failures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44Year When Failure(s) Occurred. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44Location Along Pipeline . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45Orientation of Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45Form of Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45Corrosion Mechanism or Potentially Corrosive Species . . . . . . . . . . . . . . . . 45

Inspections and Assessments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46Inspection/Assessment Method . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47Location of Inspection/Assessment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47 Date of Inspection/Assessment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47

Monitoring . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48Corrosion Rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48 Detection of Localized Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49 Frequency . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49 Date of Monitoring . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49 Location . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49

iii


Water. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50Samples . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50Water Content and/or Dew Point . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 51Removal of Water Following Hydrostatic Pressure Testing . . . . . . . . . . . . . 52

Water Composition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 53pH. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 54Scaling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 54Alkalinity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 58Chlorides . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 58Corrosion Rate Modeling. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59Corrosion Inhibitors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59Acids . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59Iron and Manganese . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59

Microorganisms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 60Testing Results . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 60

Aerobic and Anaerobic Organisms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 61Types of Bacteria . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 61

Conditions Conducive to Bacteria Growth . . . . . . . . . . . . . . . . . . . . . . . . . . 63Biocides . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 63

Solids Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 63Types of Solids. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 64Accumulation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 64

Flow Modeling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 65Flow Rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 65Flow Velocity. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 66Flow Regimes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 68Wettability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 71

Flow . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 71Low or Stagnant Flow . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 72High Flow . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 72Entrainment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 72

Operating Temperature and Pressure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 72Temperature . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 72Pressure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 73

System Design . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 74Gas Transmission Pipeline Drips. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 74 Dead Legs/Ends . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 76 Pipeline Fittings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 77 Compressor Stations and Associated Piping. . . . . . . . . . . . . . . . . . . . . . . . . 78

Pig Launchers/Receivers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 79 Expansion Loops. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 80

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Chapter 2: If Yes, How Bad Is It?Corrosion Rate Modeling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

Anode/Cathode Area. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2Monitoring Techniques . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3

Selection of Representative Monitoring Locations . . . . . . . . . . . . . . . . . . . . . . . 4Side Streams and Bypass Loops . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5Monitoring Points at Facilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6

Direct Intrusive Techniques . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6Corrosion Coupons . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8Spool Piece. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12Electrical Resistance (ER) Probes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12Linear Polarization Resistance (LPR) Probes . . . . . . . . . . . . . . . . . . . . . . . . 17Electrochemical Noise (ECN) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20

Direct Non-Intrusive Techniques . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23Electrical Field Mapping (EFM) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23Permanently Mounted UT Probes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25Acoustic Solids Monitoring . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26

Indirect Methods . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26Hydrogen Monitoring . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27

Intrusive Hydrogen Probes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27Non-intrusive Hydrogen Patch Probes . . . . . . . . . . . . . . . . . . . . . . . . . . . 28

Gas Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29 Water Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30

Sample Collection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31pH . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32Alkalinity. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32Anion Concentrations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32Metal (Cation) Concentrations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33Specific Gravity. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33Total Dissolved Solids (TDS) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33Organic Acid . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33Inhibitor Residuals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34

Solid Analyses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34Sample Collection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35Qualitative Spot Tests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35Energy Dispersive Spectroscopy (EDS) . . . . . . . . . . . . . . . . . . . . . . . . . . 36X-ray Fluorescence (XRF) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38X-ray Diffraction (XRD). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38

Microbiological Monitoring. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39Sample Collection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40

Planktonic Sampling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40Sessile Sampling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40

Liquid Culture Media . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41

v


Adenosine Triphosphate (ATP) Photometry. . . . . . . . . . . . . . . . . . . . . . . 43Hydrogenase Measurements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44Fluorescence Microscopy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45Adenosine Phosphosulfate (APS) Reductase . . . . . . . . . . . . . . . . . . . . . . 46

Monitoring Technique Selection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47Real Time Monitoring Required . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48Environmentally Assisted Cracking (EAC) Expected . . . . . . . . . . . . . . . 48Intrusive Monitoring is Not Possible . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48Flow Assisted Damage is Expected . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48Complimentary Testing. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49

Inspection Methods . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50Selection of Representative Inspection Locations . . . . . . . . . . . . . . . . . . . . . . . 50Visual Inspection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50Magnetic Flux Leakage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 54Ultrasonic Testing (UT) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55

Manual UT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55Automated UT (AUT). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 57

Guided Wave Ultrasonic Testing Technology (GWUT) . . . . . . . . . . . . . . . . 58Eddy Current (EC) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59Radiographic Testing (RT) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 60Inspection Method Selection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 62

Wall Thickness Measurements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 62Screening Tool/Quick Inspection. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 62Detection of Internal Cracking. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 62Pipeline Replacement / Internal Surface Exposed . . . . . . . . . . . . . . . . . . . . . 62

Assessments. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 63Direct Assessment Methodology . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 63

Dry Gas ICDA Methodology. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 64Pre-Assessment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 64Indirect Inspection. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 69Detailed Examination . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 71Post Assessment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 73

Wet Gas ICDA (WG-ICDA) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 75Pre-Assessment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 75Indirect Inspection. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 76Detailed Examination . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 77Post Assessment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 77

Liquid Petroleum ICDA. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 77Pre-Assessment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 78Indirect Inspection. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 78Detailed Examination . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 80Post Assessment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 80

Confirmatory Direct Assessment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 81

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Pressure Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 81In-line Inspection (ILI) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 84Assessment Method Selection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 86

Determining If Mitigation Is Required . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 87

Chapter 3: How Do I Stop It?Maintenance Pigging . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

Types of Maintenance Pigs. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2Mandrel Pigs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2Foam Pigs. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4Solid-Cast Pigs. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5Sphere Pigs. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6Gel Pigs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7

Cleaning Frequency Schedule and Impacts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7Performance Confirmation. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9

Chemical Treatment. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11Application Methods. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11

Continuous Injection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11Batch Treatment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13Concentration and Injection Rate. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14Factors Influence Chemical Treatment Performance. . . . . . . . . . . . . . . . . . . 14

Temperature . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15Velocity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15Solubility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15Compatibility with System Fluids and Other Chemicals . . . . . . . . . . . . . 15Chemical Availability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16

Corrosion Inhibitors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16Water Soluble Corrosion Inhibitors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18Oil Soluble-Water Dispersible Corrosion Inhibitors . . . . . . . . . . . . . . . . . . . 18Oil Soluble Corrosion Inhibitors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18Inorganic Corrosion Inhibitors. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19

Biocides . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19Resistance to Biocides . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21Alternatives to Biocides . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22

Scavengers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22Oxygen Scavengers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23Hydrogen Sulfide (H2S) Scavengers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23

Chemical Cleaning . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24Design and Operation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25

Water Removal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25Removal of Potentially Corrosive Gases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25Modifying Flow Characteristics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26

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Physical Design Changes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26Selecting and Implementing Appropriate Methods. . . . . . . . . . . . . . . . . . . . . . . . . 28Effectiveness of Mitigation Method . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29

Chapter 4: How Do I Design To Prevent Corrosion?Define the Service Environment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

What is the Expected Product Quality . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1What are the Expected Operating Conditions?. . . . . . . . . . . . . . . . . . . . . . . . . . . 2

Corrosion Form/Rate Prediction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2Past Experiences . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2

Non-Corrosive Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3Effectively Mitigated Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3Monitoring/Inspection Results . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3Internal Corrosion Failures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3

Industry Guidance. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4Corrosion Modeling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4

Design Features . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5Removal of Water . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5

Separation. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5Dehydration/Dewatering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8

Gas Dehydration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9Joule-Thompson Expansion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9Solid Desiccant . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10Liquid Desiccant . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10

Liquid Dewatering. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11Electrostatic Treatment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12Heat Treatment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12Chemical Treatment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12Time/Gravity. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13

Removal of Corrosive Gases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13Amine Scrubbers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14Membrane Units. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14H2S Scavenger Units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15Catalytic Combustion. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15Drips. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

Geometry Physical Design Changes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17Inspectability/Accessibility. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17

Piggable Lines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17Monitoring Access Points . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18

Materials Selection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18Is the Material Suited to the Environment? . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20Can Carbon Steel Be Used? . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20

viii


Protective Coatings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20 Cement Mortar Lining (CML) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22Elastomeric Liners . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22Cladding . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23Selecting and Implementing Appropriate Mitigation Methods . . . . . . . . . . . 24

Selection of Alternative Materials . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25Corrosion Mitigation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26

Pitting . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26Crevice Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26Galvanic Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27Weld Zone Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27Microbiologically Influenced Corrosion (MIC) . . . . . . . . . . . . . . . . . . . . . . . . . 27Stress Corrosion Cracking (SCC) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28Hydrogen Induced Cracking (HIC) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28Stress Oriented Hydrogen Induced Cracking (SOHIC) . . . . . . . . . . . . . . . . . . . 29Sulfide Stress Cracking (SSC) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30Erosion-Corrosion. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30Cavitation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31

Chapter 5: How Do I Optimize An Internal Corrosion Program?What is Risk Management? . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

Risk Identification. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2Risk Evaluation. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4

Risk Matrices . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5Bow-Tie Technique . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5Risk Based Decision Making. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6

Risk Mitigation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6Risk Monitoring. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8

Economics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8Accounting Methods. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9

Rate of Return (ROR) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9Net Present Value (NPV). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10Profitability Index (PI) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12Profitability Decisions (NPV, ROR, PI) . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13

Life-cycle costing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14Economic Maintenance Optimization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

Internal Corrosion Management Program . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16Internal Corrosion Management Plan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16

Roles and Responsibilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16Monitoring . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17Mitigation. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17

Data Management and Integration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18

ix


Continuous Improvement Options . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19Management of Changes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20

Change of Product Mix . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20Change of Flow or Flow Direction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20Pressure and Temperature Changes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21

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Internal Corrosion for Pipelines Advanced NACE International 2009September 2009

Internal Corrosion for Pipelines AdvancedList of Figures

Chapter 1: Do I Have An Internal Corrosion Problem?Figure 1.1: Uniform Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3Figure 1.2: Pits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4Figure 1.3: Schematics of Potential Pit Morphologies as Viewed

in Cross Section . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4Figure 1.4: Metallurgical Mount Showing Elliptical Pit Morphology

in Carbon Steel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5Figure 1.5: Metallurgical Mount Showing Shallow Parabolic Pit Morphology

in Carbon Steel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5Figure 1.6: Metallurgical Mount Showing Undercut Pit Morphology

in Carbon Steel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5Figure 1.7: Crevice Corrosion on a Corrosion Coupon . . . . . . . . . . . . . . . . . . . . . . 6Figure 1.8: Mesa Attack . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7Figure 1.9: Localized Corrosion Attack at a Longitudinal Seam Weld . . . . . . . . . 8Figure 1.10: Flow Assisted Damage Downstream of a Girth Weld . . . . . . . . . . . . 9Figure 1.11: Galvanic Series in Sea Water . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11Figure 1.12: Example of Metal Ion Concentration Cell Corrosion . . . . . . . . . . . . 12Figure 1.13: Corrosion Damage Associated with 400 mm Diameter (16 in)

Multiphase Pipeline . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15Figure 1.14: CO2 Corrosion Exacerbated by High Flow Rates . . . . . . . . . . . . . . 15Figure 1.15: Pits Associated with Oxygen . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18Figure 1.16: Corrosion Products Associated with Oxygen . . . . . . . . . . . . . . . . . . 19Figure 1.17: Pits Attributed to MIC . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19Figure 1.18: Hydrogen Induced Cracking (HIC) . . . . . . . . . . . . . . . . . . . . . . . . . . 22Figure 1.19: Erosion on a Choke Insert and an Orifice Plate . . . . . . . . . . . . . . . . 26Figure 1.20: Erosion-corrosion Resulting in a Through-wall Leak . . . . . . . . . . . 26Figure 1.21: Pits From an Acid Gas Injection Line . . . . . . . . . . . . . . . . . . . . . . . . 43Figure 1.22: Aftermath of an Internal Corrosion Failure Attributed to MIC . . . . 43Figure 1.23: Internal Corrosion Failure Attributed to CO2 . . . . . . . . . . . . . . . . . . 44Figure 1.24: Water Dew Point Chart (Metric Units) . . . . . . . . . . . . . . . . . . . . . . . 52Figure 1.25: Water Dew Point Chart (Imperial Units) . . . . . . . . . . . . . . . . . . . . . 53Figure 1.26: Scale Observed During Visual Inspection of the Internal

Surface of a Pipe . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 58Figure 1.27: Sludge Removed During Pigging . . . . . . . . . . . . . . . . . . . . . . . . . . . 65Figure 1.28: Paraffin Removed During Pigging . . . . . . . . . . . . . . . . . . . . . . . . . . 65Figure 1.29: Mahdhane et al. Horizontal Flow Regime Map . . . . . . . . . . . . . . . . 68Figure 1.30: Schematic Showing Flow Regimes for Two Phase Flow . . . . . . . . . 69Figure 1.31: Pipeline Drip Removed From Service . . . . . . . . . . . . . . . . . . . . . . . 75Figure 1.32: Solid Accumulation in a Pipeline Drip . . . . . . . . . . . . . . . . . . . . . . . 76

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Figure 1.33: Corrosion at a Flange Face Resulting FromFlow Assisted Damage Due to Misalignment of a Gasket . . . . . . . . . . . . . . . . . . . . . . . . . . . . 78

Figure 1.34: Pig Launcher / Receiver . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 80

Chapter 2: If Yes, How Bad Is It?Figure 2.1: Example of a Side Stream . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5Figure 2.2: Retractable Device; Low Pressure System . . . . . . . . . . . . . . . . . . . . . 7Figure 2.3: Retractable Device; High Pressure System . . . . . . . . . . . . . . . . . . . . . . 7Figure 2.4: Assortment of Coupon Types; Coupons in Coupon Holders . . . . . . . . 8Figure 2.5: Coupon Immediately After Removal From a Pipeline . . . . . . . . . . . . . 9Figure 2.6: ER Probe and Data Collector . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13Figure 2.7: ER Probes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14Figure 2.8: ER Probe Elements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15Figure 2.9: Flush and Finger-type LPR Probes . . . . . . . . . . . . . . . . . . . . . . . . . 17Figure 2.10: Current Measured by an ECN Probe . . . . . . . . . . . . . . . . . . . . . . . . . 21Figure 2.11: Pitting Potential Measured by an ECN Probe . . . . . . . . . . . . . . . . . . 22Figure 2.12: EFM Used to Monitor Short Pipe Section . . . . . . . . . . . . . . . . . . . . 24Figure 2.13: Hydrogen Patch Probe . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28Figure 2.14: SEM Image Showing Elemental Mapping of Scale Removed

From a Pipe . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37Figure 2.15: Three Superimposed EDS Spectra Collected From Scale . . . . . . . . . 37Figure 2.16: Quantitative Results for Spectrum 1, 2, and 3 . . . . . . . . . . . . . . . . . 37Figure 2.17: Robbins Device . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41Figure 2.18: Optical Photomicrograph Showing Bacteria Viewed Under

Ultraviolet Light . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46Figure 2.19: Field Personnel Performing Manual UT Inspection . . . . . . . . . . . . . 56Figure 2.20: AUT Device on a Pipe . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 57Figure 2.21: GWUT Collar on Pipe . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59Figure 2.22: Radiographic Image Showing Areas of Metal Loss . . . . . . . . . . . . . 60Figure 2.23: Examples of Region Identification . . . . . . . . . . . . . . . . . . . . . . . . . . 69Figure 2.24: Pipeline Elevation and Inclination Profiles Showing Locations

Exceeding the Critical Incliation Angle . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 72Figure 2.25: In-line Inspection Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 84

Chapter 3: How Do I Stop It?Figure 3.1: Dirty Pig . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2Figure 3.2: Mandrels Pigs Equipped with Scraper, Discs or Cups and Discs . . . . . 3Figure 3.3: Mandrel Pigs Equipped with Blades and Brushes . . . . . . . . . . . . . . . . 4Figure 3.4: Mandrel Pig with Brushes After Removal From a Pipeline . . . . . . . . . 4Figure 3.5: Foam Pigs - Sealing Type and Disc Type . . . . . . . . . . . . . . . . . . . . . . 5Figure 3.6: Solid-cast Pig . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6

iii


Figure 3.7: Sphere Pigs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6Figure 3.8: Gel Pig . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7Figure 3.9: Chemical Injection and Storage Facility . . . . . . . . . . . . . . . . . . . . . . . 12Figure 3.10: Corrosion Occurring at a Chemical Injection Point . . . . . . . . . . . . . 13

Chapter 4: How Do I Design To Prevent Corrosion?Figure 4.1: Results of a Drip Failure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4Figure 4.2: Horizontal Separators . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5Figure 4.3: Vertical Oilfield Separators . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6Figure 4.4: Slug Catcher . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7Figure 4.5: Glycol Dehydration Unit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11Figure 4.6: Pipeline Drip Installed at 6 oclock Orientation . . . . . . . . . . . . . . . . . 16Figure 4.7: Solids That Have Accumulated in a Pipeline Drip . . . . . . . . . . . . . . . 16

Chapter 5: How Do I Optimize An Internal Corrosion Program?Figure 5.1: Bow-tie Diagram . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2Figure 5.2: Risk Matrix . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5Figure 5.3: Hierarchy of Risk Mitigation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7Figure 5.4: Swiss Cheese Barrier Model . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8Figure 5.5: Example of a Monitoring Strategy Showing Monitoring Locations. . 17

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Internal Corrosion for Pipelines AdvancedList of Tables

Chapter 1: Do I Have An Internal Corrosion Problem?Table 1.1: Effect of Increasing Parameters on the Potential for Scaling . . . . . . . . 55

Chapter 2: If Yes, How Bad Is It?Table 2.1: Types of Monitoring Techniques. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4Table 2.2: Categorization of Carbon Steel Corrosion Rates from

NACE RP0775 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11Table 2.3: Summary of Monitoring Techniques and Their Applications. . . . . . . . 49Table 2.4: Inspection Methods Comparison. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 63Table 2.5: Essential Data for DG-ICDA per NACE SP0206 . . . . . . . . . . . . . . . . . 65Table 2.6: Assessment Intervals for Hydrostatic Testing and In-Line

Inspection per ASME B31.8S. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 83

Chapter 3: How Do I Stop It?

Chapter 4: How Do I Design To Prevent Corrosion?Table 4.1: Primary Water Removal Methods for Natural Gas and Liquid

Hydrocarbon Pipelines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8Table 4.2: Material Selection Comparison . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19Table 4.3: Examples of Internal Coatings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22

Chapter 5: How Do I Optimize An Internal Corrosion Program?Table 5.1: NPV Company A. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11Table 5.2: NPV Company B. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12Table 5.3: Comparison of Investment Decisions . . . . . . . . . . . . . . . . . . . . . . . . . . 13Table 5.4: Estimated Initial Investment Costs and Expect Cash Flows for

Oil Plus Pipeline Company. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14

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Internal Corrosion for Pipelines - Advanced Course Manual NACE International 2009January 2011

Advanced Internal Corrosion for PipelinesAppendices and List of Standards

APPENDICES:Group Studies & Case StudiesAppendix A Analysis ReportAppendix B Laboratory and Field Testing of Candidate

Chemical TreatmentsAppendix C Typical Properties of Materials

LIST OF STANDARDS:NACE Glossary of Corrosion-Related TermsGlossary for Internal CorrosionTM0194 Field Monitoring of Bacterial Growth in Oil and Gas

SystemsSP0102 In-Line Inspection of PipelinesRP0775 Preparation, Installation, Analysis and Interpretation of

of Corrosion Coupons in Oilfield OperationsSP0206 Internal Corrosion Direct Assessment Methodology for

Pipelines Carrying Normally Dry Natural Gas (DG-ICDA)SP0108 Corrosion Control of Offshore Structures by Protective

CoatingsSP0106 Control of Internal Corrosion in Steel Pipelines and

Piping systems

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Internal Corrosion for Pipelines - Advanced Course Manual NACE International 2009January 2011

Do I Have An Internal Corrosion Problem? 1-1

NACE International 2009 Internal Corrosion for Pipelines Advanced Course ManualJanuary 2010

Chapter 1: Do I Have An Internal Corrosion Problem?

1.1 What is Internal Corrosion?Internal corrosion is corrosion that occurs inside a pipe or structure.The process of corrosion can be viewed as the interaction between amaterial and its environment that results in degradation of thematerial. Corrosion can be categorized either by the physical natureof the metal loss or damage, the mechanism by which the metal lossor damage occurred, or the environment in which it takes place. Apit, for example, is a form of corrosion damage that could beattributed to any of several possible mechanisms or combination ofmechanisms. Therefore, when describing corrosion, it is importantto clearly distinguish between the form of damage, the mechanismby which the damage occurred, and the environment that supportedthe mechanism.

1.1.1 Basic Corrosion CellCorrosion reactions involve the transfer of a charge between themetal and the electrolyte, which is electrochemical in nature. Inorder for these corrosion reactions to occur, the following fourcomponents must be present:

1. Anode 2. Cathode 3. Metallic electrical connection between the anode and cathode4. Electrolyte

At the anode, oxidation (corrosion) occurs and cations enter theelectrolyte. At the cathode, the electrons produced from the anodicreaction are consumed in reduction reactions. Below are equationsshowing the oxidation of iron and the reduction of water. Thereduction is shown with and without the presence of oxygen.

Fe Fe2+ + 2e- (oxidation of iron) [1.1]

2H2O + 2e- H2 + 2OH- (hydrogen evolution) [1.2]

1-2 Do I Have An Internal Corrosion Problem?

Internal Corrosion for Pipelines Advanced Course Manual NACE International 2009January 2010

2H2O + O2 + 4e- 4OH- (oxygen reduction) [1.3]

For the reaction to proceed, the anode and cathode must beelectronically connected (e.g., pipe wall) and in contact with anelectrolyte. It is important to note that the electrolyte associated withthese corrosion reactions need not be a bulk solution. Often only athin condensed film of moisture is sufficient for the corrosionreaction to proceed.

1.1.2 Forms of CorrosionMaterials are susceptible to various forms of physical degradationdue to interactions between the material and the environment. Thephysical degradation may be in the form of uniform metal loss,isolated/localized metal loss, environmentally assisted cracking, orflow assisted damage.

1.1.2.1 Uniform CorrosionUniform, or general corrosion, is metal loss that proceeds more orless evenly over the surface of a material, or a large fraction of thematerial. During uniform corrosion, local anodes and cathodes donot become fixed. An image of uniform corrosion is shown inFigure 1.1. This form of corrosion can be identified by visualexamination and is recognized by an overall roughening of thesurface. Because uniform corrosion occurs over a larger area, it ismore easily detected from the outside of the pipe using ultrasonicmeasurements than isolated pitting.

Uniform corrosion, can occur in isolated locations along a pipelinedue to an isolated environment.



Figure 1.1 Uniform Corrosion

1.1.2.2 Localized CorrosionLocalized corrosion is identified by small, discrete sites of metalloss at fixed anodes. Metal surfaces surrounding areas of localizedcorrosion show minor or no apparent attack, although pitting canoccur within areas of general corrosion as well.

1.1.2.2.1 PittingPitting is the most common form of localized corrosion. It can beidentified by the presence of discrete cavities or craters called pitson the metal surface. Figure 1.2 show a sample of pits. The cavitiescorrespond to areas where small volumes of metal were removedand may or may not be associated with corrosion products.



Figure 1.2 Pits

Pitting is found in many different shapes (e.g. round, elliptical orirregular), sizes and depths. As viewed in cross section (see Figure1.3 through Figure 1.6), pits occur in various aspect ratios. Aspectratio is the width of the pit divided by the depth of the pit.

Figure 1.3 Schematics of Potential Pit Morphologies as Viewed in Cross Section



Figure 1.4 Metallurgical Mount Showing Elliptical Pit Morphology in Carbon Steel

Figure 1.5 Metallurgical Mount Showing Shallow Parabolic Pit Morphology in Carbon Steel

Figure 1.6 Metallurgical Mount Showing Undercut Pit Morphology in Carbon Steel



Pitting is more difficult to predict and detect than uniform corrosion.Although pitting is somewhat unpredictable, a great deal is knownabout environments that promote pitting. In particular, environmentscontaining hydrogen sulfide (H2S), carbon dioxide (CO2), oxygen(O2), microorganisms, and chlorides have all experienced pitting.

1.1.2.2.2 Crevice CorrosionCrevice corrosion is a form of localized corrosion that occurs at, orimmediately adjacent to, discrete sites where free access to the bulkenvironment is restricted (see Figure 1.7). This form of corrosion,normally, can be identified visually and is recognized by the pittingor etching near, or adjacent to, locations of restricted flow. Commonsites for crevice corrosion are under loose fitting washers, flanges,or gaskets. This form of corrosion is not, however, limited tocrevices formed by mated surfaces of metal assemblies. Crevicecorrosion can also occur under scale and surface deposits (termedunder deposit corrosion).

Figure 1.7 Crevice Corrosion on a Corrosion Coupon

1.1.2.2.3 Mesa CorrosionMesa corrosion is a form of localized corrosion recognized by large,flat bottom formations with sharp edges. Figure 1.8 shows a sampleof mesa corrosion.



Figure 1.8 Mesa Attack

1.1.2.2.4 Weld Zone CorrosionLocalized corrosion damage may also occur at welds. Under certainconditions, welds are particularly susceptible to corrosive attack as aresult of minor metallurgical, chemical, and residual stressdifferences within the weld bead, heat affected zone (HAZ), and theparent metal. Weld zone damage may take the form of localizedpitting or cracking.

Electric resistance welded (ERW) longitudinal seam pipe issusceptible to selective seam corrosion (or grooving corrosion).Pitting occurs along the weld seam, aligning until the pits becomeone round-bottom groove. Figure 1.9 shows localized attack at alongitudinal seam.



Figure 1.9 Localized Corrosion Attack at a Longitudinal Seam Weld

1.1.2.3 Environmentally Assisted Cracking (EAC)Environmentally assisted cracking (EAC) refers to a variety ofcracking mechanisms that result from the combination of tensilestress and the environment. Environmental cracking may affect themechanical strength or serviceability of a material with no visiblesigns of damage or metal loss. Some forms of EAC result inunanticipated brittle failure of an otherwise ductile material. EAC isa very environmentally/material specific form of corrosion. Forexample, a hot chloride environment may crack austenitic stainlesssteels, but have no such effect on carbon steels.

The presence of environmental cracks may be difficult to detectwithout the use of specialized inspection methods (e.g., ultrasonicinspection using an angle beam technique). Microscopically, EAC isrecognized by the presence of tight cracks at right angles to thedirection of maximum tensile stress.

EAC occurs at rates that are difficult to predict. In addition, EACcan occur at widely varied rates on the same pipeline. Thiscomplicates managing the threat because the extent of the pipelineto inspect and the required inspection intervals are not easilydetermined.



1.1.2.4 Flow-Assisted DamageFlow-assisted damage encompasses metal damage that results fromincreased flow. Flow that removes a film can eliminate its protectiveeffect. Normally, films are removed by purely physical/mechanicalinfluences, but mass-transfer effects may cause the dissolution of afilm. It is also possible for flow to damage the metal itself by purelyphysical/mechanical erosion. Flow-assisted damage can includepits, grooves, and/or roughened surfaces that correspond to thedirection of flow. Figure 1.10 shows flow-assisted damagedownstream of a girth weld.

Figure 1.10 Flow Assisted Damage Downstream of a Girth Weld

1.1.3 Corrosion Mechanisms

1.1.3.1 Galvanic CorrosionGalvanic corrosion is a mechanism resulting from the metalliccoupling of two dissimilar metals (galvanic coupling) exposed to anelectrolyte. The mechanism is driven by the potential differencebetween the two dissimilar metals. When coupled electronically(e.g., hard metallic short), the material with the more negativepotential acts as the anode and corrodes, while the material with themore positive potential acts as the cathode. The galvanic corrosion



series, shown in Figure 1.11, can be used to determine which metalwill act as the anode and which the cathode within a galvaniccoupling.

This corrosion mechanism is principally recognized by the presenceof preferential attack on one material (the anode) at the junctionbetween two dissimilar materials. Preferential attack of the anodemay be localized pitting or corrosion dispersed over a large area.

Galvanic corrosion is associated with the macroscopic coupling oftwo dissimilar metals (e.g., copper and steel). However, it can alsoarise from microscopic differences in a metal (i.e., different phasesor microstructural features), or between two similar metals ofdifferent vintages. The latter case is important when repairs andreplacements are considered, in which new components will beconnected to older components of the same material. The oldersections will most likely have formed scales or protective films thatmay be cathodic to the new section, until similar scales or films areformed on the new section. In some cases, the new section does notform a protective scale or film because operating conditions havechanged. The result is that the new section experiences corrosiondamage at a higher rate than the older section.



Cathode (noble)

PlatinumGold

GraphiteTitanium

SilverZirconium

AISI Type 316, 317 stainless steels (passive)AISI Type 304 stainless steel (passive)AISI Type 430 stainless steel (passive)

Nickel (passive)Copper-nickel (70-30)

BronzesCopperBrasses

Nickel (active)Naval brass

TinLead

AISI Type 316, 317 stainless steels (active)AISI Type 304 stainless steel (active)

Cast ironSteel or iron

Aluminum alloy 2024Cadmium

Aluminum alloy 1100Zinc

Magnesium and magnesium alloys

Anodic (active)

Figure 1.11 Galvanic Series in Sea Water1

The potential for galvanic corrosion can exist at welds as a result ofcompositional differences between the weld filler material and thebase metal. Potential differences can develop between the weld andbase metal, resulting in preferential attack of the anodic metal. Incarbon steels, potential differences between the weld metal and the

1. Denny Jones, Principles and Prevention of Corrosion p. 14



parent metal are generally negligible. The potential differences canbe very significant, however, in highly conductive electrolytes andresult in significant corrosion.

1.1.3.2 Concentration CellsConcentration cells refer to a corrosion mechanism that results fromdifferences in the concentration of a chemical component of theelectrolyte. Two of the main types of concentration cells are metalion and oxygen. Because of the concentration differences in theelectrolyte, discrete cathodic and anodic regions form on the metalsurface. Metal ion and oxygen concentration cells are commonlyassociated with crevice corrosion, since concentrations of chemicalspecies inside and outside of the crevice are often quite different.

Metal ion concentration cells arise from differences in the metal ionconcentrations between areas inside and outside of the crevice. As aresult, a potential difference develops between the area inside andoutside of the crevice. The tendency of a metal to go into solutionwill increase as the concentration of its ions in solution decreases.Therefore, the metal in contact with the lower concentration of ionswill become the anode and corrode. The metal at the higherconcentration of ions will serve as the cathode. Typically, corrosionassociated with the metal ion concentration cell is most prevalent atthe entrance of the crevice. (See Figure 1.12)

Figure 1.12 Example of Metal Ion Concentration Cell Corrosion

Oxygen concentration cells arise from oxygen concentrationdifferences between the areas inside and outside of the crevice (alsoknown as differential aeration). As a result, a potential differencedevelops between the areas inside and outside the crevice. Thecorrosion associated with the oxygen concentration cell usually



occurs within the crevice where the concentration of oxygen is low(anode).

1.1.4 Potentially Corrosive SpeciesVarious chemical species present within pipelines can significantlyaffect internal corrosion in the system. The manifestation ofcorrosion damage associated with each species will vary with theoperating conditions and the physical environment. For the oil andgas industry, the species of significance include:

Carbon dioxide (CO2)

Hydrogen sulfide (H2S)

Oxygen (O2)

Metabolic activity from some bacteriaFor these species to cause corrosion, water must be present.

1.1.4.1 Carbon Dioxide (CO2)Carbon dioxide is an odorless, colorless gas that may be present atvarying levels in a pipeline. While present in producing formationsto various degrees, CO2 may also be introduced during enhanced oilrecovery methods. CO2 is only corrosive when dissolved in anelectrolyte. Dissolved CO2 can cause corrosion due to the formationof carbonic acid as shown in the equation below.

[1.4]

The resulting corrosion rate depends on the water chemistry, theeffects of which are described in Section 1.3.5 Water Composition.Often the dominating factor to determine the corrosion severity isthe partial pressure of CO2. The partial pressure of CO2 (or anyother gas component) is found by analyzing a gas sample for itscontent and performing the calculation shown in Equation 1.5. Themole % (volume %2) of CO2 gas, in relationship to the entire gassample, is multiplied by the total pressure to calculate CO2 partialpressure.

2. Volume percent is equal to mole percent when assuming an ideal gas.

3222COHOHCO



[1.5]

Where:Total pressure = [gauge pressure + atmospheric pressure]

Atmospheric pressure = 0.101MPa (14.7 psi)

General and localized corrosion are both forms of corrosion damageassociated with CO2. Figure 1.13 shows an example of localizedcorrosion associated with CO2. The specific forms of localizedattack associated with carbon steels include:

Pitting

Mesa attack

Flow-assisted damage

CO2 pitting is usually present in low velocity conditions; thesusceptibility to pitting increases with increasing temperature andCO2 partial pressures. Mesa attack generally occurs under low tomoderate flow conditions where protective scales (iron carbonates)are worn away. Finally, turbulent, flow-assisted damage with CO2generally has areas of both pitting and mesa corrosion. Damageunder these conditions occurs as existing scales are destroyed,subsequent scale formation is prevented, and corrosive speciestransport to the metal surface is enhanced. Figure 1.14 is an imageof CO2 corrosion exacerbated by high flow rates.

100

% pressuretotalmolepressurepartial



Figure 1.13 Corrosion Damage Associated with 400 mm Diameter (16 in) Multiphase Pipeline Containing 5 mol % CO2 at a System Pressure of 1.7 MPa (250 psig) Which is

Equal to a Partial Pressure of 0.09 MPa (13 psia)

Figure 1.14 CO2 Corrosion Exacerbated by High Flow Rates

Since CO2 is usually removed prior to being transported intransmission lines, CO2 corrosion tends to occur at slower rates intransmission lines than in production lines.

Corrosion product scales associated with CO2 systems tend to bedominated by iron carbonates (i.e., FeCO3). When iron carbonate



precipitates at the steel surface, it can slow down the corrosionprocess by:

Presenting a diffusion barrier for the species involved in thecorrosion process, i.e., by reducing the flux of species

Blocking (covering) a portion of the steel surface and prevent-ing electrochemical reactions by excluding the electrolyte

These scales are characteristically thin, brittle, and poorly adherent.Thus, they are highly susceptible to flow damage, particularlyturbulent and high velocity flow. The formation of these scales, andtheir influence on the corrosion, depends on environmentalconditions in the pipeline. The effects of environmental conditionsare discussed further in Section 1.3.10 Operating Temperature andPressure.

1.1.4.2 Hydrogen Sulfide (H2S)Hydrogen sulfide is a colorless, poisonous gas with a rotten eggodor at low concentrations. Inherent to many producing formations,H2S may also be generated from the metabolic activities of sulfatereducing bacteria and/or introduced to the system through makeupwater or well working fluids. H2S is only corrosive when dissolvedin an electrolyte.

Internal corrosion associated with H2S is governed by theproduction of a weak acid, the generation of hydrogen ions, and theformation of sulfide scales, which are slightly cathodic to steel. H2Sreadily dissociates in solution.

H2S H+ + HS- [1.6]

The forms of corrosion associated with H2S include pitting, underdeposit corrosion (crevice corrosion), and environmentally assistedcracking (EAC). EAC mechanisms associated with H2S includesulfide stress cracking (SSC), hydrogen induced cracking (HIC),and stress oriented hydrogen induced cracking (SOHIC). Thesemechanisms are discussed further in Section 1.1.5 EnvironmentallyAssisted Cracking Mechanisms.

Scales associated with H2S systems tend to be dominated by variousiron sulfides (FexSy). These scales (usually black) are electricallysemi-conductive and cathodic to iron. Compared to carbonate



scales, iron sulfide scales are generally less susceptible to velocityeffects. This is due to the rapid precipitation, mechanical properties,and low solubility of iron sulfide. The formation of sulfide scalesand their influence on the corrosion behavior of the pipelinedepends on environmental conditions in the pipeline; environmentaleffects are discussed in more detail in Section 1.3.10 OperatingTemperature and Pressure.

1.1.4.3 OxygenOxygen (O2), when present in even minor concentrations (10 50parts per billion [ppb]) in pipelines, can result in corrosion when anelectrolyte is present. The corrosion severity depends upon theconcentration of O2 and other corrosive species in the system.Oxygen affects the reaction at the cathode.

2H2O + O2 + 4e 4(OH) [1.7]

Oxygen is not naturally present in producing formations so itspresence is usually the result of contamination, which occurs whenair enters the system. Sources of oxygen contamination include:

Aerated fluids used in drilling maintenance and injectionwaters

Leaks associated with pumps (suction) and other processingand handling equipment

Failure of O2 removal systems

The solubility of O2 in water is a function of the pressure,temperature, and dissolved solids (mainly chlorides). The solubilityof O2 at atmospheric pressure decreases as temperatures increaseand as the dissolved solid content increases.

Internal corrosion associated with O2 usually generates pitting, andcrevice corrosion. Figure 1.15 is an example of pits associated withO2. As discussed in Section 1.1.3.2 Concentration Cells, differencesin O2 transport/solubility may result in the formation of crevicecorrosion conditions known as differential aeration. The regions oflimited O2 transport/solubility tend to have higher corrosion rates.Examples of differential aeration include:

Crevices Water-air interfaces



Areas beneath debris or corrosion deposits

Figure 1.15 Pits Associated with Oxygen

In many instances, O2 acts as a corrosion accelerator. For example,corrosion associated with CO2 and H2S can be more severe in thepresence of O2. The rate at which O2 accelerates the reaction,however, is limited by the mass transport of oxygen to the cathode.Situations that tend to enhance the effects of oxygen includeturbulent or agitated systems. Not only can O2 accelerate corrosionreactions, it can also render previously protective scales non-protective. Under specific circumstances, O2 can cause precipitationof oxides, hydroxides, and free sulfur. Figure 1.16 is an example ofcorrosion products associated with O2. Oxygenated systems mayalso allow growth of aerobic microorganisms that foul systems and/or enhance pitting through under deposit corrosion.



Figure 1.16 Corrosion Products Associated with Oxygen

1.1.4.4 Microbiologically Influenced CorrosionMicrobiologically influenced corrosion (MIC) is the deterioration ofa material, due to the presence and activities of microorganisms(bacteria, fungi, algae, and protozoa) and/or the products theyproduce. The corrosion associated with bacteria is usually pitcorrosion. Figure 1.17 shows pits attributed to MIC.

Figure 1.17 Pits Attributed to MIC

The types of bacteria common to the oil and gas industry include:

Sulfate-reducing bacteria (SRB) Iron-oxidizing bacteria (IOB)



Acid-producing bacteria (APB) Sulfur-oxidizing bacteria (SOB) Manganese-oxidizing bacteria (MOB) Slime-forming bacteria

Each of these bacteria types will be discussed in detail in Section1.3.6 Microorganisms.

The presence and activities of microorganisms on a metal surfacemay result in:

Destruction of the protective film on the metal surface Generation of a local acid environment (acid producing bac-

teria [APB]) Creation of corrosive deposits Modification of the anodic and cathodic reactions

Aside from acids, the microorganisms may also produce alcohols,ammonia, CO2, or H2S (sulfate-reducing bacteria).

Microorganisms can accumulate anywhere. However, they may bemore prevalent in low flow or stagnant conditions. Surfaceconditions at welds (e.g., weld protrusions) can also create localizedenvironments, conducive to biofilm establishment. Bacteria canproduce polymeric material that:

Creates a protective environment

Facilitates the flow of nutrients and removal of waste products

Sometimes functions to enable symbiotic relationshipsbetween the different types of bacteria in the biofilm

The polymeric material, therefore, helps create a localized corrosionenvironment and promotes bacteria growth, which could make it moredifficult to mitigate the corrosion.

Factors that promote the occurrence of MIC include:

Low flow velocities

Deposit accumulations

High water cuts



Increased bacteria levels

1.1.5 Environmentally Assisted Cracking Mechanisms

Environmentally assisted cracking (EAC) encompasses a variety ofcracking mechanisms that are driven by tensile stress and theenvironment. Compressive stresses will not lead to cracking. EACmechanisms relevant to this course include hydrogen inducedcracking (HIC), hydrogen embrittlement (HE), stress-orientedhydrogen induced cracking (SOHIC), sulfide stress cracking (SSC),stress corrosion cracking (SCC), and liquid metal embrittlement(LME).

Welds can be more susceptible to EAC mechanisms, due to highresidual stresses within the HAZ, microstructural heterogeneity, andthe entrapment or absorption of atomic hydrogen resulting from thewelding processes.

1.1.5.1 Hydrogen DamageHydrogen damage is a term that collectively refers to various formsof EAC resulting from the diffusion of hydrogen into a metal. Theforms include HIC, HE, SOHIC, and SSC. Each of the four formsrequire a susceptible material and a corrosive environment. WhileHIC and HE are usually the result of stresses developed frominternal pressure due to the buildup of hydrogen (no externalstresses), both SOHIC and SSC result from applied or residualstresses.

Hydrogen sulfide (H2S), chloride (Cl-), cyanide (CN-), carbondioxide (CO2), and ammonium ion (NH4+) have all been linked tothe acceleration of hydrogen damage.

1.1.5.1.1 Hydrogen Induced Cracking (HIC)Hydrogen induced cracking (HIC) is a form of EAC that occurswhen hydrogen atoms adsorbed to the metal surface do not combineto form hydrogen gas (H2). The hydrogen is inhibited fromrecombining to form H2 by the presence of certain environmentalspecies at the metal interface, (e.g., sulfide or cyanide). Unable torecombine, the nascent hydrogen diffuses into the metal. Thehydrogen then migrates and collects at internal discontinuities



(voids, inclusions, laminations, etc.), forming pockets of molecularhydrogen. Buildup

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