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 thereof accept any responsibility for the use of the methods and materials discussed herein. No authorization is implied concerning the use of patented or copyrighted material. The information is advisory only and the use of the materials and methods is solely at the risk of the user. Printed in the United States. All rights reserved. Reproduction of contents in whole or part or transfer into electronic or photographic storage without permission of copyright owner is expressly forbidden.

Acknowledgements NACE International would like to extend a special thank you to BP Exploration Alaska for its contribution toward the development of this course. The time and expertise of many members of NACE International have gone into this material. Their dedication and efforts are greatly appreciated by the authors and by those who have assisted in making this work possible. The scope, desired learning outcomes and performance criteria of this course were developed by the Internal Corrosion Subcommittee under the auspices of the NACE Education Administrative Committee in cooperation with the NACE Certification Administrative Committee. On behalf of NACE, we would like to thank the Advanced Internal Corrosion for Pipelines task group for its work. Their efforts were extraordinary and their goal was in the best interest of public service — to develop and provide a much needed training program that would help improve corrosion control efforts industry-wide. We also wish to thank their employers for being generously supportive of the substantial 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, AB CANADA

Carlos Palacios

CIMA-TQ Edo Anzoategui VENEZUELA

Gerald Pogemiller

JP Consultants Inc. Hot Springs Village, Arkansas

Tim Zintel

ANR Pipeline Troy, Michigan

Drew Hevle

El Paso Corporation Houston, Texas

Pat Teevens

Broadsword Corrosion Eng Ltd Calgary, AB CANADA

Sankara Papavinasam

CANMET Materials Tech. Lab Ottawa, ON CANADA

Tom Pickthal

EnhanceCo Missouri City, Texas

Michael Brockman

El Paso Corporation Houston, Texas

Richard Eckert

BP Exploration Alaska Anchorage, Alaska

Bruce Cookingham

BP Exploration Alaska Anchorage, Alaska

This group of NACE members worked closely with the contracted course developers Oliver Moghissi, Kathy Krajewski and Lynsay Bensman of DNV Columbus, Inc. Thank you to the following companies for contributing photos and other images used to enhance the Advanced Internal Corrosion for Pipelines material: BP Exploration Alaska Nalco Energy Services In Line Services Inc. ARC Specialties El Paso

Welcome to the Internal Corrosion for Pipelines — Advanced Course Overview The Internal Corrosion for Pipelines —Advanced course focuses on the monitoring techniques and mitigation strategies required to assess internal corrosion and develop and manage internal corrosion control programs. Data interpretation, analysis and integration, as well as criteria for determining corrective action for high-level internal corrosion problems within a pipeline system, will be covered in detail. The course will be 5 days in length. Students successfully completing the course examination, and who meet the requirements, can apply for certification as a Senior Internal Corrosion Technologist.

Who Should Attend This course will provide in depth coverage of internal corrosion control and is targeted for individuals who are responsible for the implementation, maintenance and management of an internal corrosion control program for a pipeline system.

Prerequisites To attend this course, students should meet the requirements on one of the following paths: PATH 1 •

Hold Internal Corrosion Technologist Certification.

PATH 2 •

8 years internal corrosion work experience in a pipeline environment OR

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4 years internal corrosion work experience in a pipeline environment PLUS •Bachelor’s degree in one of the following disciplines: Chemistry, Microbiology, Biology, Chemical Engineering, Metallurgical Engineering

Length The course beings Monday and ends Friday with class starting at 8:00 am and ending at approximately 5:00 pm.

Quizzes and Examinations There will be quizzes distributed during the week and reviewed in class by the instructors. The final written exam, which will be given on Friday, will consist of 100 multiple-choice questions. The examination is open book and students may bring reference materials and notes into the examination room. Exam questions may come from text, powerpoints, appendices, case studies, group studies or any other material covered during the course. A score of 70% or greater is required for successful completion of the course. All questions are from the concepts discussed in this training manual. Noncommunicating, battery-operated, silent, non-printing calculators, including calculators with alphanumeric keypads, are permitted for use during the examination. Calculating and computing devices having a QWERTY keypad arrangement similar to a typewriter or keyboard are not permitted. Such devices include but are not limited to palmtop, laptop, handheld, and desktop computers, calculators, databanks, data collectors, and organizers. Also excluded for use during the examination are communication devices such as pagers and cell phones along 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 your password for accessing your grades on-line (for privacy issues, you may choose a different four-digit number in this space)

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LAST NAME:Your last name (surname)

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FIRST NAME: Your first name (given name)

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M.I.: Middle initial (if applicable)

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

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

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NAME: _______________ (fill in your entire name)

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

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DATE: _______________ (date you are taking exam)

3. The next section of the form (1 to 200) is for the answers to your exam questions. •

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

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If changing an answer on the ParSCORETM sheet, be sure to erase completely.

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Bubble only one answer per question and do not fill in more answers than the exam 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 company representative, 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 exams at 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 drop down menu. Type in your Student ID or Temporary Student ID (Example 123456 or 4240700217)*. 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:

STUDENT ID__________________COURSE CODE_________________ PASSWORD (Only Four Digits) ___________________ *Note that the Student ID number for NACE members will be the same as their NACE membership number unless a Temporary Student ID number is issued at the course. For those who register through NACE Headquarters, the Student ID will appear on their course confirmation form, student roster provided to the instructor, and/or students’ name badges. For In-House, Licensee, and Section-Registered courses, a Temporary ID number will be assigned at the course for the purposes of accessing scores online only.

For In-House courses, this information may not be posted until payment has been received from the hosting company. Information regarding the current shipment status of grade letters is available on the web upon completion of the course. Processing begins at the receipt of the paperwork at NACE headquarters. When the letters for the course are being processed, the “Status” column will indicate “Processing”. Once the letters are mailed, the status will be updated to say “Mailed” and the date mailed will be entered in the last column. Courses are listed in date order. Grade letter shipment status 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 posted “Mailed date” (6 weeks for international locations), or if you have trouble accessing 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/Courses and Programs. Certification candidates who do not meet the prerequisites at the time of course attendance will have five (5) years from the examination date to satisfy the course/ certification prerequisites and apply for certification.

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Internal Corrosion for Pipelines — Advanced Table of Contents

Chapter 1: Do I Have An Internal Corrosion Problem? What is Internal Corrosion?. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 Basic Corrosion Cell . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 Forms of Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 Uniform Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 Localized Corrosion. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 Pitting . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 Crevice Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 Mesa Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 Weld Zone Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 Environmentally Assisted Cracking (EAC) . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 Flow-Assisted Damage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 Corrosion Mechanisms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 Galvanic Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 Concentration Cells . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 Potentially Corrosive Species . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 Carbon Dioxide (CO2). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 Hydrogen Sulfide (H2S) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16 Oxygen . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 Microbiologically Influenced Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19 Environmentally Assisted Cracking Mechanisms . . . . . . . . . . . . . . . . . . . . . . . 21 Hydrogen Damage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21 Hydrogen Induced Cracking (HIC). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21 Hydrogen Embrittlement (HE) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23 Stress-Oriented Hydrogen Induced Cracking (SOHIC) . . . . . . . . . . . . . . 23 Sulfide Stress Cracking (SSC) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23 Stress Corrosion Cracking (SCC) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24 Liquid Metal Embrittlement (LME) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24 Flow-Assisted Damage Mechanisms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24 Erosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25 Impingement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25 Erosion-Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25 Cavitation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26 What Type of Pipeline Is It? . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27 Upstream Petroleum Production Pipelines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27 Crude Oil/ Multiphase High Vapor Pressure (HVP) Liquid . . . . . . . . . . . . . 28 Water Cut . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29 Natural Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29

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Water Services (Sea, Produced, Fresh) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30 Fresh Water . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31 Sea Water . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31 Produced Water . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32 Transmission Pipelines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32 Liquid Pipelines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32 Crude Oil (Low Vapor Pressure (LVP) Liquids) . . . . . . . . . . . . . . . . . . . 33 Sulfur Content. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34 Total Acid Number (TAN) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34 Basic (Bottom) Sediment and Water (BS&W). . . . . . . . . . . . . . . . . . . . 35 Product Pipelines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35 Anhydrous Ammonia (NH3). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36 Natural Gas Pipelines. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37 “Dry” Transmission Lines. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37 Distribution Pipelines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38 Pipeline Facilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39 Storage Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39 Other Service Pipelines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40 Slurry . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40 Sewage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41 High Pressure Steam . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41 Hydrogen . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41 Super Critical CO2. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41 Jet Fuel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42 Acid Gas Injection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42 Do I Have an IC problem?. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43 Failures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43 Number of Failures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44 Year When Failure(s) Occurred . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44 Location Along Pipeline . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45 Orientation of Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45 Form of Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45 Corrosion Mechanism or Potentially Corrosive Species . . . . . . . . . . . . . . . . 45 Inspections and Assessments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46 Inspection/Assessment Method . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47 Location of Inspection/Assessment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47 Date of Inspection/Assessment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47 Monitoring . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48 Corrosion Rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48 Detection of Localized Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49 Frequency . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49 Date of Monitoring . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49 Location . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49

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Water. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50 Samples . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50 Water Content and/or Dew Point . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 51 Removal of Water Following Hydrostatic Pressure Testing . . . . . . . . . . . . . 52 Water Composition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 53 pH. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 54 Scaling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 54 Alkalinity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 58 Chlorides . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 58 Corrosion Rate Modeling. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59 Corrosion Inhibitors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59 Acids . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59 Iron and Manganese . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59 Microorganisms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 60 Testing Results . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 60 Aerobic and Anaerobic Organisms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 61 Types of Bacteria . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 61 Conditions Conducive to Bacteria Growth . . . . . . . . . . . . . . . . . . . . . . . . . . 63 Biocides . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 63 Solids Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 63 Types of Solids. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 64 Accumulation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 64 Flow Modeling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 65 Flow Rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 65 Flow Velocity. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 66 Flow Regimes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 68 Wettability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 71 Flow . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 71 Low or Stagnant Flow . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 72 High Flow . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 72 Entrainment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 72 Operating Temperature and Pressure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 72 Temperature . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 72 Pressure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 73 System Design . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 74 Gas 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. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 Monitoring Techniques . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 Selection of Representative Monitoring Locations . . . . . . . . . . . . . . . . . . . . . . . 4 Side Streams and Bypass Loops . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 Monitoring Points at Facilities. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 Direct Intrusive Techniques . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 Corrosion Coupons . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 Spool Piece. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 Electrical Resistance (ER) Probes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 Linear Polarization Resistance (LPR) Probes . . . . . . . . . . . . . . . . . . . . . . . . 17 Electrochemical Noise (ECN) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20 Direct Non-Intrusive Techniques . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23 Electrical Field Mapping (EFM) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23 Permanently Mounted UT Probes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25 Acoustic Solids Monitoring . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26 Indirect Methods . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26 Hydrogen Monitoring . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27 Intrusive Hydrogen Probes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27 Non-intrusive Hydrogen Patch Probes . . . . . . . . . . . . . . . . . . . . . . . . . . . 28 Gas Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29 Water Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30 Sample Collection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31 pH . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32 Alkalinity. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32 Anion Concentrations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32 Metal (Cation) Concentrations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33 Specific Gravity. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33 Total Dissolved Solids (TDS) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33 Organic Acid . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33 Inhibitor Residuals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34 Solid Analyses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34 Sample Collection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35 Qualitative Spot Tests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35 Energy Dispersive Spectroscopy (EDS) . . . . . . . . . . . . . . . . . . . . . . . . . . 36 X-ray Fluorescence (XRF) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38 X-ray Diffraction (XRD). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38 Microbiological Monitoring. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39 Sample Collection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40 Planktonic Sampling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40 Sessile Sampling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40 Liquid Culture Media . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41

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Adenosine Triphosphate (ATP) Photometry. . . . . . . . . . . . . . . . . . . . . . . 43 Hydrogenase Measurements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44 Fluorescence Microscopy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45 Adenosine Phosphosulfate (APS) Reductase . . . . . . . . . . . . . . . . . . . . . . 46 Monitoring Technique Selection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47 Real Time Monitoring Required . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48 Environmentally Assisted Cracking (EAC) Expected . . . . . . . . . . . . . . . 48 Intrusive Monitoring is Not Possible . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48 Flow Assisted Damage is Expected . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48 Complimentary Testing. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49 Inspection Methods . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50 Selection of Representative Inspection Locations . . . . . . . . . . . . . . . . . . . . . . . 50 Visual Inspection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50 Magnetic Flux Leakage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 54 Ultrasonic Testing (UT) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55 Manual UT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55 Automated UT (AUT). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 57 Guided Wave Ultrasonic Testing Technology (GWUT) . . . . . . . . . . . . . . . . 58 Eddy Current (EC) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59 Radiographic Testing (RT) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 60 Inspection Method Selection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 62 Wall Thickness Measurements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 62 Screening Tool/Quick Inspection. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 62 Detection of Internal Cracking. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 62 Pipeline Replacement / Internal Surface Exposed . . . . . . . . . . . . . . . . . . . . . 62 Assessments. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 63 Direct Assessment Methodology . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 63 Dry Gas ICDA Methodology. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 64 Pre-Assessment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 64 Indirect Inspection. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 69 Detailed Examination . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 71 Post Assessment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 73 Wet Gas ICDA (WG-ICDA) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 75 Pre-Assessment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 75 Indirect Inspection. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 76 Detailed Examination . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 77 Post Assessment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 77 Liquid Petroleum ICDA. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 77 Pre-Assessment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 78 Indirect Inspection. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 78 Detailed Examination . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 80 Post Assessment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 80 Confirmatory Direct Assessment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 81

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Pressure Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 81 In-line Inspection (ILI) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 84 Assessment Method Selection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 86 Determining If Mitigation Is Required . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 87

Chapter 3: How Do I Stop It? Maintenance Pigging . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 Types of Maintenance Pigs. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 Mandrel Pigs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 Foam Pigs. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 Solid-Cast Pigs. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 Sphere Pigs. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 Gel Pigs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 Cleaning Frequency Schedule and Impacts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 Performance Confirmation. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 Chemical Treatment. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 Application Methods. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 Continuous Injection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 Batch Treatment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 Concentration and Injection Rate. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 Factors Influence Chemical Treatment Performance. . . . . . . . . . . . . . . . . . . 14 Temperature . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15 Velocity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15 Solubility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15 Compatibility with System Fluids and Other Chemicals . . . . . . . . . . . . . 15 Chemical Availability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16 Corrosion Inhibitors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16 Water Soluble Corrosion Inhibitors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18 Oil Soluble-Water Dispersible Corrosion Inhibitors . . . . . . . . . . . . . . . . . . . 18 Oil Soluble Corrosion Inhibitors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18 Inorganic Corrosion Inhibitors. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19 Biocides . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19 Resistance to Biocides . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21 Alternatives to Biocides . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22 Scavengers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22 Oxygen Scavengers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23 Hydrogen Sulfide (H2S) Scavengers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23 Chemical Cleaning . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24 Design and Operation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25 Water Removal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25 Removal of Potentially Corrosive Gases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25 Modifying Flow Characteristics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26

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

Chapter 4: How Do I Design To Prevent Corrosion? Define the Service Environment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 What is the Expected Product Quality . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 What are the Expected Operating Conditions?. . . . . . . . . . . . . . . . . . . . . . . . . . . 2 Corrosion Form/Rate Prediction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 Past Experiences . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 Non-Corrosive Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 Effectively Mitigated Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 Monitoring/Inspection Results. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 Internal Corrosion Failures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 Industry Guidance. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 Corrosion Modeling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 Design Features . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 Removal of Water . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 Separation. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 Dehydration/Dewatering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 Gas Dehydration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 Joule-Thompson Expansion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 Solid Desiccant . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 Liquid Desiccant . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 Liquid Dewatering. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 Electrostatic Treatment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 Heat Treatment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 Chemical Treatment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 Time/Gravity. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 Removal of Corrosive Gases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 Amine Scrubbers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 Membrane Units. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 H2S Scavenger Units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15 Catalytic Combustion. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15 Drips. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15 Geometry – Physical Design Changes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 Inspectability/Accessibility. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 Piggable Lines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 Monitoring Access Points . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18 Materials Selection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18 Is the Material Suited to the Environment? . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20 Can Carbon Steel Be Used? . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20

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Protective Coatings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20 Cement Mortar Lining (CML) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22 Elastomeric Liners . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22 Cladding . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23 Selecting and Implementing Appropriate Mitigation Methods . . . . . . . . . . . 24 Selection of Alternative Materials . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25 Corrosion Mitigation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26 Pitting . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26 Crevice Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26 Galvanic Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27 Weld Zone Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27 Microbiologically Influenced Corrosion (MIC) . . . . . . . . . . . . . . . . . . . . . . . . . 27 Stress Corrosion Cracking (SCC) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28 Hydrogen Induced Cracking (HIC) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28 Stress Oriented Hydrogen Induced Cracking (SOHIC) . . . . . . . . . . . . . . . . . . . 29 Sulfide Stress Cracking (SSC) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30 Erosion-Corrosion. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30 Cavitation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31

Chapter 5: How Do I Optimize An Internal Corrosion Program? What is Risk Management? . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 Risk Identification. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 Risk Evaluation. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 Risk Matrices . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 Bow-Tie Technique . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 Risk Based Decision Making. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 Risk Mitigation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 Risk Monitoring . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 Economics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 Accounting Methods. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 Rate of Return (ROR) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 Net Present Value (NPV) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 Profitability Index (PI) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 Profitability Decisions (NPV, ROR, PI) . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 Life-cycle costing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 Economic Maintenance Optimization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15 Internal Corrosion Management Program . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16 Internal Corrosion Management Plan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16 Roles and Responsibilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16 Monitoring . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 Mitigation. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 Data Management and Integration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18

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Continuous Improvement Options . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19 Management of Changes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20 Change of Product Mix . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20 Change of Flow or Flow Direction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20 Pressure and Temperature Changes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21

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Internal Corrosion for Pipelines — Advanced List of Figures Chapter 1: Do I Have An Internal Corrosion Problem? Figure 1.1: Uniform Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 Figure 1.2: Pits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 Figure 1.3: Schematics of Potential Pit Morphologies as Viewed in Cross Section . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 Figure 1.4: Metallurgical Mount Showing Elliptical Pit Morphology in Carbon Steel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 Figure 1.5: Metallurgical Mount Showing Shallow Parabolic Pit Morphology in Carbon Steel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 Figure 1.6: Metallurgical Mount Showing Undercut Pit Morphology in Carbon Steel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 Figure 1.7: Crevice Corrosion on a Corrosion Coupon . . . . . . . . . . . . . . . . . . . . . . 6 Figure 1.8: Mesa Attack . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 Figure 1.9: Localized Corrosion Attack at a Longitudinal Seam Weld . . . . . . . . . 8 Figure 1.10: Flow Assisted Damage Downstream of a Girth Weld . . . . . . . . . . . . 9 Figure 1.11: Galvanic Series in Sea Water . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 Figure 1.12: Example of Metal Ion Concentration Cell Corrosion . . . . . . . . . . . . 12 Figure 1.13: Corrosion Damage Associated with 400 mm Diameter (16 in) Multiphase Pipeline . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15 Figure 1.14: CO2 Corrosion Exacerbated by High Flow Rates . . . . . . . . . . . . . . 15 Figure 1.15: Pits Associated with Oxygen . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18 Figure 1.16: Corrosion Products Associated with Oxygen . . . . . . . . . . . . . . . . . . 19 Figure 1.17: Pits Attributed to MIC . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19 Figure 1.18: Hydrogen Induced Cracking (HIC) . . . . . . . . . . . . . . . . . . . . . . . . . . 22 Figure 1.19: Erosion on a Choke Insert and an Orifice Plate . . . . . . . . . . . . . . . . 26 Figure 1.20: Erosion-corrosion Resulting in a Through-wall Leak . . . . . . . . . . . 26 Figure 1.21: Pits From an Acid Gas Injection Line . . . . . . . . . . . . . . . . . . . . . . . . 43 Figure 1.22: Aftermath of an Internal Corrosion Failure Attributed to MIC . . . . 43 Figure 1.23: Internal Corrosion Failure Attributed to CO2 . . . . . . . . . . . . . . . . . . 44 Figure 1.24: Water Dew Point Chart (Metric Units) . . . . . . . . . . . . . . . . . . . . . . . 52 Figure 1.25: Water Dew Point Chart (Imperial Units) . . . . . . . . . . . . . . . . . . . . . 53 Figure 1.26: Scale Observed During Visual Inspection of the Internal Surface of a Pipe . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 58 Figure 1.27: Sludge Removed During Pigging . . . . . . . . . . . . . . . . . . . . . . . . . . . 65 Figure 1.28: Paraffin Removed During Pigging . . . . . . . . . . . . . . . . . . . . . . . . . . 65 Figure 1.29: Mahdhane et al. Horizontal Flow Regime Map . . . . . . . . . . . . . . . . 68 Figure 1.30: Schematic Showing Flow Regimes for Two Phase Flow . . . . . . . . . 69 Figure 1.31: Pipeline Drip Removed From Service . . . . . . . . . . . . . . . . . . . . . . . 75 Figure 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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 Figure 2.2: Retractable Device; Low Pressure System . . . . . . . . . . . . . . . . . . . . . 7 Figure 2.3: Retractable Device; High Pressure System . . . . . . . . . . . . . . . . . . . . . . 7 Figure 2.4: Assortment of Coupon Types; Coupons in Coupon Holders . . . . . . . . 8 Figure 2.5: Coupon Immediately After Removal From a Pipeline . . . . . . . . . . . . . 9 Figure 2.6: ER Probe and Data Collector . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 Figure 2.7: ER Probes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 Figure 2.8: ER Probe Elements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15 Figure 2.9: Flush and “Finger-type” LPR Probes . . . . . . . . . . . . . . . . . . . . . . . . . 17 Figure 2.10: Current Measured by an ECN Probe . . . . . . . . . . . . . . . . . . . . . . . . . 21 Figure 2.11: Pitting Potential Measured by an ECN Probe . . . . . . . . . . . . . . . . . . 22 Figure 2.12: EFM Used to Monitor Short Pipe Section . . . . . . . . . . . . . . . . . . . . 24 Figure 2.13: Hydrogen Patch Probe . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28 Figure 2.14: SEM Image Showing Elemental Mapping of Scale Removed From a Pipe . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37 Figure 2.15: Three Superimposed EDS Spectra Collected From Scale . . . . . . . . . 37 Figure 2.16: Quantitative Results for Spectrum 1, 2, and 3 . . . . . . . . . . . . . . . . . 37 Figure 2.17: Robbins Device . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41 Figure 2.18: Optical Photomicrograph Showing Bacteria Viewed Under Ultraviolet Light . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46 Figure 2.19: Field Personnel Performing Manual UT Inspection . . . . . . . . . . . . . 56 Figure 2.20: AUT Device on a Pipe . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 57 Figure 2.21: GWUT Collar on Pipe . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59 Figure 2.22: Radiographic Image Showing Areas of Metal Loss . . . . . . . . . . . . . 60 Figure 2.23: Examples of Region Identification . . . . . . . . . . . . . . . . . . . . . . . . . . 69 Figure 2.24: Pipeline Elevation and Inclination Profiles Showing Locations Exceeding the Critical Incliation Angle . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 72 Figure 2.25: In-line Inspection Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 84

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

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Figure 3.7: Sphere Pigs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 Figure 3.8: Gel Pig . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 Figure 3.9: Chemical Injection and Storage Facility . . . . . . . . . . . . . . . . . . . . . . . 12 Figure 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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 Figure 4.2: Horizontal Separators . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 Figure 4.3: Vertical Oilfield Separators . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 Figure 4.4: Slug Catcher . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 Figure 4.5: Glycol Dehydration Unit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 Figure 4.6: Pipeline Drip Installed at 6 o’clock Orientation . . . . . . . . . . . . . . . . . 16 Figure 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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 Figure 5.2: Risk Matrix . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 Figure 5.3: Hierarchy of Risk Mitigation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 Figure 5.4: Swiss Cheese Barrier Model . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 Figure 5.5: Example of a Monitoring Strategy Showing Monitoring Locations. . 17

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Internal Corrosion for Pipelines — Advanced List 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. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 Table 2.2: Categorization of Carbon Steel Corrosion Rates from NACE RP0775 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 Table 2.3: Summary of Monitoring Techniques and Their Applications. . . . . . . . 49 Table 2.4: Inspection Methods Comparison. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 63 Table 2.5: Essential Data for DG-ICDA per NACE SP0206 . . . . . . . . . . . . . . . . . 65 Table 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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 Table 4.2: Material Selection Comparison . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19 Table 4.3: Examples of Internal Coatings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22

Chapter 5: How Do I Optimize An Internal Corrosion Program? Table 5.1: NPV Company A. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 Table 5.2: NPV Company B. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 Table 5.3: Comparison of Investment Decisions . . . . . . . . . . . . . . . . . . . . . . . . . . 13 Table 5.4: Estimated Initial Investment Costs and Expect Cash Flows for Oil Plus Pipeline Company. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14

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Advanced Internal Corrosion for Pipelines Appendices and List of Standards

APPENDICES: Group Studies & Case Studies Appendix A Analysis Report Appendix B Laboratory and Field Testing of Candidate Chemical Treatments Appendix C Typical Properties of Materials

LIST OF STANDARDS: NACE Glossary of Corrosion-Related Terms Glossary for Internal Corrosion TM0194 Field Monitoring of Bacterial Growth in Oil and Gas Systems SP0102 In-Line Inspection of Pipelines RP0775 Preparation, Installation, Analysis and Interpretation of of Corrosion Coupons in Oilfield Operations SP0206 Internal Corrosion Direct Assessment Methodology for Pipelines Carrying Normally Dry Natural Gas (DG-ICDA) SP0108 Corrosion Control of Offshore Structures by Protective Coatings SP0106 Control of Internal Corrosion in Steel Pipelines and Piping systems

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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 a material and its environment that results in degradation of the material. Corrosion can be categorized either by the physical nature of the metal loss or damage, the mechanism by which the metal loss or damage occurred, or the environment in which it takes place. A pit, for example, is a form of corrosion damage that could be attributed to any of several possible mechanisms or combination of mechanisms. Therefore, when describing corrosion, it is important to clearly distinguish between the form of damage, the mechanism by which the damage occurred, and the environment that supported the mechanism.

1.1.1 Basic Corrosion Cell Corrosion reactions involve the transfer of a charge between the metal and the electrolyte, which is electrochemical in nature. In order for these corrosion reactions to occur, the following four components must be present: 1. Anode 2. Cathode 3. Metallic electrical connection between the anode and cathode 4. Electrolyte At the anode, oxidation (corrosion) occurs and cations enter the electrolyte. At the cathode, the electrons produced from the anodic reaction are consumed in reduction reactions. Below are equations showing the oxidation of iron and the reduction of water. The reduction is shown with and without the presence of oxygen.

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Fe → Fe2+ + 2e- (oxidation of iron)

[1.1]

2H2O + 2e- → H2 + 2OH- (hydrogen evolution)

[1.2]

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2H2O + O2 + 4e- → 4OH- (oxygen reduction)

[1.3]

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

1.1.2 Forms of Corrosion Materials are susceptible to various forms of physical degradation due to interactions between the material and the environment. The physical degradation may be in the form of uniform metal loss, isolated/localized metal loss, environmentally assisted cracking, or flow assisted damage.

1.1.2.1 Uniform Corrosion Uniform, or general corrosion, is metal loss that proceeds more or less evenly over the surface of a material, or a large fraction of the material. During uniform corrosion, local anodes and cathodes do not become fixed. An image of uniform corrosion is shown in Figure 1.1. This form of corrosion can be identified by visual examination and is recognized by an overall roughening of the surface. Because uniform corrosion occurs over a larger area, it is more easily detected from the outside of the pipe using ultrasonic measurements than isolated pitting. Uniform corrosion, can occur in isolated locations along a pipeline due to an isolated environment.

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Figure 1.1 Uniform Corrosion

1.1.2.2 Localized Corrosion Localized corrosion is identified by small, discrete sites of metal loss at fixed anodes. Metal surfaces surrounding areas of localized corrosion show minor or no apparent attack, although pitting can occur within areas of general corrosion as well. 1.1.2.2.1 Pitting Pitting is the most common form of localized corrosion. It can be identified by the presence of discrete cavities or craters called pits on the metal surface. Figure 1.2 show a sample of pits. The cavities correspond to areas where small volumes of metal were removed and may or may not be associated with corrosion products.

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Figure 1.2 Pits

Pitting is found in many different shapes (e.g. round, elliptical or irregular), sizes and depths. As viewed in cross section (see Figure 1.3 through Figure 1.6), pits occur in various aspect ratios. Aspect ratio 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

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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

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Pitting is more difficult to predict and detect than uniform corrosion. Although pitting is somewhat unpredictable, a great deal is known about environments that promote pitting. In particular, environments containing hydrogen sulfide (H2S), carbon dioxide (CO2), oxygen (O2), microorganisms, and chlorides have all experienced pitting. 1.1.2.2.2 Crevice Corrosion Crevice corrosion is a form of localized corrosion that occurs at, or immediately adjacent to, discrete sites where free access to the bulk environment is restricted (see Figure 1.7). This form of corrosion, normally, can be identified visually and is recognized by the pitting or etching near, or adjacent to, locations of restricted flow. Common sites for crevice corrosion are under loose fitting washers, flanges, or gaskets. This form of corrosion is not, however, limited to crevices formed by mated surfaces of metal assemblies. Crevice corrosion can also occur under scale and surface deposits (termed “under deposit” corrosion).

Figure 1.7 Crevice Corrosion on a Corrosion Coupon

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

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Figure 1.8 Mesa Attack

1.1.2.2.4 Weld Zone Corrosion Localized corrosion damage may also occur at welds. Under certain conditions, welds are particularly susceptible to corrosive attack as a result of minor metallurgical, chemical, and residual stress differences within the weld bead, heat affected zone (HAZ), and the parent metal. Weld zone damage may take the form of localized pitting or cracking. Electric resistance welded (ERW) longitudinal seam pipe is susceptible to selective seam corrosion (or grooving corrosion). Pitting occurs along the weld seam, aligning until the pits become one round-bottom groove. Figure 1.9 shows localized attack at a longitudinal seam.

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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 of cracking mechanisms that result from the combination of tensile stress and the environment. Environmental cracking may affect the mechanical strength or serviceability of a material with no visible signs of damage or metal loss. Some forms of EAC result in unanticipated brittle failure of an otherwise ductile material. EAC is a very environmentally/material specific form of corrosion. For example, a hot chloride environment may crack austenitic stainless steels, but have no such effect on carbon steels. The presence of environmental cracks may be difficult to detect without the use of specialized inspection methods (e.g., ultrasonic inspection using an angle beam technique). Microscopically, EAC is recognized by the presence of tight cracks at right angles to the direction of maximum tensile stress. EAC occurs at rates that are difficult to predict. In addition, EAC can occur at widely varied rates on the same pipeline. This complicates managing the threat because the extent of the pipeline to inspect and the required inspection intervals are not easily determined.

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1.1.2.4 Flow-Assisted Damage Flow-assisted damage encompasses metal damage that results from increased flow. Flow that removes a film can eliminate its protective effect. Normally, films are removed by purely physical/mechanical influences, but mass-transfer effects may cause the dissolution of a film. It is also possible for flow to damage the metal itself by purely physical/mechanical erosion. Flow-assisted damage can include pits, grooves, and/or roughened surfaces that correspond to the direction of flow. Figure 1.10 shows flow-assisted damage downstream 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 Corrosion Galvanic corrosion is a mechanism resulting from the metallic coupling of two dissimilar metals (galvanic coupling) exposed to an electrolyte. The mechanism is driven by the potential difference between the two dissimilar metals. When coupled electronically (e.g., hard metallic short), the material with the more negative potential acts as the anode and corrodes, while the material with the more positive potential acts as the cathode. The galvanic corrosion

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series, shown in Figure 1.11, can be used to determine which metal will act as the anode and which the cathode within a galvanic coupling. This corrosion mechanism is principally recognized by the presence of preferential attack on one material (the anode) at the junction between two dissimilar materials. Preferential attack of the anode may be localized pitting or corrosion dispersed over a large area. Galvanic corrosion is associated with the macroscopic coupling of two dissimilar metals (e.g., copper and steel). However, it can also arise from microscopic differences in a metal (i.e., different phases or microstructural features), or between two similar metals of different vintages. The latter case is important when repairs and replacements are considered, in which new components will be connected to older components of the same material. The older sections will most likely have formed scales or protective films that may be cathodic to the new section, until similar scales or films are formed on the new section. In some cases, the new section does not form a protective scale or film because operating conditions have changed. The result is that the new section experiences corrosion damage at a higher rate than the older section.

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Cathode (noble) Platinum Gold Graphite Titanium Silver Zirconium 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) Bronzes Copper Brasses Nickel (active) Naval brass Tin Lead AISI Type 316, 317 stainless steels (active) AISI Type 304 stainless steel (active) Cast iron Steel or iron Aluminum alloy 2024 Cadmium Aluminum alloy 1100 Zinc 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 of compositional differences between the weld filler material and the base metal. Potential differences can develop between the weld and base metal, resulting in preferential attack of the anodic metal. In carbon steels, potential differences between the weld metal and the 1.

Denny Jones, Principles and Prevention of Corrosion p. 14

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parent metal are generally negligible. The potential differences can be very significant, however, in highly conductive electrolytes and result in significant corrosion.

1.1.3.2 Concentration Cells Concentration cells refer to a corrosion mechanism that results from differences in the concentration of a chemical component of the electrolyte. Two of the main types of concentration cells are metal ion and oxygen. Because of the concentration differences in the electrolyte, discrete cathodic and anodic regions form on the metal surface. Metal ion and oxygen concentration cells are commonly associated with crevice corrosion, since concentrations of chemical species inside and outside of the crevice are often quite different. Metal ion concentration cells arise from differences in the metal ion concentrations between areas inside and outside of the crevice. As a result, a potential difference develops between the area inside and outside of the crevice. The tendency of a metal to go into solution will increase as the concentration of its ions in solution decreases. Therefore, the metal in contact with the lower concentration of ions will become the anode and corrode. The metal at the higher concentration of ions will serve as the cathode. Typically, corrosion associated with the metal ion concentration cell is most prevalent at the entrance of the crevice. (See Figure 1.12)

Figure 1.12 Example of Metal Ion Concentration Cell Corrosion

Oxygen concentration cells arise from oxygen concentration differences between the areas inside and outside of the crevice (also known as differential aeration). As a result, a potential difference develops between the areas inside and outside the crevice. The corrosion associated with the oxygen concentration cell usually

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

1.1.4 Potentially Corrosive Species Various chemical species present within pipelines can significantly affect internal corrosion in the system. The manifestation of corrosion damage associated with each species will vary with the operating conditions and the physical environment. For the oil and gas industry, the species of significance include: •

Carbon dioxide (CO2)

•

Hydrogen sulfide (H2S)

•

Oxygen (O2)

• Metabolic activity from some bacteria For 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 at varying levels in a pipeline. While present in producing formations to various degrees, CO2 may also be introduced during enhanced oil recovery methods. CO2 is only corrosive when dissolved in an electrolyte. Dissolved CO2 can cause corrosion due to the formation of carbonic acid as shown in the equation below. CO2  H 2 O  H 2 CO3

[1.4]

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

2.

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

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partial pressure 

mole %  total pressure  100

[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 damage associated with CO2. Figure 1.13 shows an example of localized corrosion associated with CO2. The specific forms of localized attack associated with carbon steels include: •

Pitting

•

Mesa attack

•

Flow-assisted damage

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

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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 in transmission lines, CO2 corrosion tends to occur at slower rates in transmission lines than in production lines. Corrosion product scales associated with CO2 systems tend to be dominated by iron carbonates (i.e., FeCO3). When iron carbonate

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precipitates at the steel surface, it can slow down the corrosion process by: •

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

•

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

These scales are characteristically thin, brittle, and poorly adherent. Thus, they are highly susceptible to flow damage, particularly turbulent and high velocity flow. The formation of these scales, and their influence on the corrosion, depends on environmental conditions in the pipeline. The effects of environmental conditions are discussed further in Section 1.3.10 Operating Temperature and Pressure.

1.1.4.2 Hydrogen Sulfide (H2S) Hydrogen sulfide is a colorless, poisonous gas with a rotten egg odor at low concentrations. Inherent to many producing formations, H2S may also be generated from the metabolic activities of sulfate reducing bacteria and/or introduced to the system through makeup water or well working fluids. H2S is only corrosive when dissolved in an electrolyte. Internal corrosion associated with H2S is governed by the production of a weak acid, the generation of hydrogen ions, and the formation of sulfide scales, which are slightly cathodic to steel. H2S readily dissociates in solution. H2S → H+ + HS-

[1.6]

The forms of corrosion associated with H2S include pitting, under deposit corrosion (crevice corrosion), and environmentally assisted cracking (EAC). EAC mechanisms associated with H2S include sulfide stress cracking (SSC), hydrogen induced cracking (HIC), and stress oriented hydrogen induced cracking (SOHIC). These mechanisms are discussed further in Section 1.1.5 Environmentally Assisted Cracking Mechanisms. Scales associated with H2S systems tend to be dominated by various iron sulfides (FexSy). These scales (usually black) are electrically semi-conductive and cathodic to iron. Compared to carbonate

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

1.1.4.3 Oxygen Oxygen (O2), when present in even minor concentrations (10 – 50 parts per billion [ppb]) in pipelines, can result in corrosion when an electrolyte is present. The corrosion severity depends upon the concentration 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 its presence is usually the result of contamination, which occurs when air enters the system. Sources of oxygen contamination include: • • •

Aerated fluids used in drilling maintenance and injection waters Leaks associated with pumps (suction) and other processing and 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 solubility of O2 at atmospheric pressure decreases as temperatures increase and as the dissolved solid content increases. Internal corrosion associated with O2 usually generates pitting, and crevice corrosion. Figure 1.15 is an example of pits associated with O2. As discussed in Section 1.1.3.2 Concentration Cells, differences in O2 transport/solubility may result in the formation of crevice corrosion conditions known as differential aeration. The regions of limited O2 transport/solubility tend to have higher corrosion rates. Examples of differential aeration include: • •

Crevices Water-air interfaces

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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 the presence 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 include turbulent or agitated systems. Not only can O2 accelerate corrosion reactions, it can also render previously protective scales nonprotective. Under specific circumstances, O2 can cause precipitation of oxides, hydroxides, and free sulfur. Figure 1.16 is an example of corrosion products associated with O2. Oxygenated systems may also allow growth of aerobic microorganisms that foul systems and/ or enhance pitting through under deposit corrosion.

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Figure 1.16 Corrosion Products Associated with Oxygen

1.1.4.4 Microbiologically Influenced Corrosion Microbiologically influenced corrosion (MIC) is the deterioration of a material, due to the presence and activities of microorganisms (bacteria, fungi, algae, and protozoa) and/or the products they produce. The corrosion associated with bacteria is usually pit corrosion. 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: • •

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

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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 Section 1.3.6 Microorganisms. The presence and activities of microorganisms on a metal surface may result in: • • • •

Destruction of the protective film on the metal surface Generation of a local acid environment (acid producing bacteria [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 be more prevalent in low flow or stagnant conditions. Surface conditions at welds (e.g., weld protrusions) can also create localized environments, conducive to biofilm establishment. Bacteria can produce polymeric material that: •

Creates a protective environment

•

Facilitates the flow of nutrients and removal of waste products

•

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

The polymeric material, therefore, helps create a localized corrosion environment and promotes bacteria growth, which could make it more difficult to mitigate the corrosion. Factors that promote the occurrence of MIC include: •

Low flow velocities

•

Deposit accumulations

•

High water cuts

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Increased bacteria levels

1.1.5 Environmentally Assisted Cracking Mechanisms Environmentally assisted cracking (EAC) encompasses a variety of cracking mechanisms that are driven by tensile stress and the environment. Compressive stresses will not lead to cracking. EAC mechanisms relevant to this course include hydrogen induced cracking (HIC), hydrogen embrittlement (HE), stress-oriented hydrogen 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 high residual stresses within the HAZ, microstructural heterogeneity, and the entrapment or absorption of atomic hydrogen resulting from the welding processes.

1.1.5.1 Hydrogen Damage Hydrogen damage is a term that collectively refers to various forms of EAC resulting from the diffusion of hydrogen into a metal. The forms include HIC, HE, SOHIC, and SSC. Each of the four forms require a susceptible material and a corrosive environment. While HIC and HE are usually the result of stresses developed from internal pressure due to the buildup of hydrogen (no external stresses), both SOHIC and SSC result from applied or residual stresses. Hydrogen sulfide (H2S), chloride (Cl-), cyanide (CN-), carbon dioxide (CO2), and ammonium ion (NH4+) have all been linked to the acceleration of hydrogen damage. 1.1.5.1.1 Hydrogen Induced Cracking (HIC) Hydrogen induced cracking (HIC) is a form of EAC that occurs when hydrogen atoms adsorbed to the metal surface do not combine to form hydrogen gas (H2). The hydrogen is inhibited from recombining to form H2 by the presence of certain environmental species at the metal interface, (e.g., sulfide or cyanide). Unable to recombine, the nascent hydrogen diffuses into the metal. The hydrogen then migrates and collects at internal discontinuities

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(voids, inclusions, laminations, etc.), forming pockets of molecular hydrogen. Buildup of the hydrogen leads to increased internal pressures that lead to crack initiation and propagation or blistering. Blistering associated with HIC is generally observed near the surface of the metal. HIC, often associated with gas or crude oil environments containing H2S, forms preferentially around elongated nonmetallic inclusions or laminations. Cracks associated with HIC are show as stepwise cracking resulting from the linking of parallel cracks. Figure 1.18 shows an example of HIC. This form of damage is more common to low strength steels (≤ 359 MPa [≤ 52,000 psi]).

Figure 1.18 Hydrogen Induced Cracking (HIC)

Sources of hydrogen leading to HIC include: •

Hydrogen entrapped during pouring of the molten metal

•

Hydrogen absorbed during electroplating or pickling

•

Hydrogen generated at cathodic sites during the corrosion processes

•

Hydrogen generated during welding

•

Hydrogen present due to the equilibrium between H2S, S and H in environments containing H2S

Factors influencing HIC include the microstructure and morphology of nonmetallic inclusions within the steel and the severity of the service environment.

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1.1.5.1.2 Hydrogen Embrittlement (HE) Hydrogen embrittlement (HE) is a form of hydrogen damage characterized by a significant reduction of ductility. This occurs from the diffusion of atomic hydrogen into the material. The sources of hydrogen leading to embrittlement are the same as those listed for HIC in Section 1.1.5.1.1 Hydrogen Induced Cracking (HIC). HE is commonly associated with high-strength steels (>359 MPa [>52,000 psi]), titanium alloys and aluminum alloys. 1.1.5.1.3 Stress-Oriented Hydrogen Induced Cracking (SOHIC) SOHIC is a variation of HIC that involves the propagation of cracking in the through-wall direction as a result of applied (or residual) stresses. Similar to HIC, SOHIC originates from the diffusion of nascent hydrogen into the metal and subsequent formation of molecular hydrogen at internal discontinuities. The buildup of molecular hydrogen within the metal produces minute cracks that align and become interconnected with the application of an external stress (applied or residual). The interconnected cracks are oriented in a direction perpendicular to the stress and in the plane of the internal discontinuity (i.e., inclusion). SOHIC is usually associated with low strength steels, occurring adjacent to areas of high hardness (i.e., welds) where cracking may originate. 1.1.5.1.4 Sulfide Stress Cracking (SSC) Sulfide stress cracking (SSC) is a form of HE that typically occurs in high strength steels, only under certain stress conditions. Unlike HE, SSC involves application of a stress (applied or residual). SSC typically occurs perpendicular to the applied stress and can occur at H2S partial pressures greater than 0.34 kPa (0.05 psia). This form of attack results from the adsorption of atomic hydrogen generated by the cathodic portion of the sulfide corrosion reaction on the metal surface. Typically, little metal loss or general corrosion is associated with SSC. The susceptibility of steel to SSC is related to the material strength, the tensile stress, and hydrogen permeation into the material. Higher hardness materials are more susceptible to SSC. Susceptible materials subjected to higher tensile and/or residual stresses are also more prone to SSC. Metallurgical and environmental limits for

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materials used in sour services can be found in NACE MR0175/ISO 15156, “Petroleum and natural gas industries—Materials for use in H2S-containing environments in oil and gas production” Parts 1, 2, and 3 and all associated Technical Corrigenda and Circulars.

1.1.5.2 Stress Corrosion Cracking (SCC) Stress corrosion cracking (SCC) results from exposure of a susceptible alloy to the combination of a specific corrosive environment and tensile stresses. No one corrosive environment causes stress corrosion cracking in all alloys. Rather, particular alloys are susceptible only to particular environments (i.e., caustic with carbon steel (CS), chlorides with stainless steel (SS), and ammonia (NH3) with copper alloys). Tensile stresses involved in SCC can either be directly applied or residual. There is little metal loss or general corrosion associated with SCC. Instead, SCC is seen as fine cracks that penetrate into the material. The cracking often originates at the base of pits and may be either transgranular or intergranular in nature. Cracking associated with SCC often exhibits branching when examined microscopically.

1.1.5.3 Liquid Metal Embrittlement (LME) LME is the embrittlement of a normally ductile solid or susceptible metal when it is in intimate contact with a liquid metal such as mercury (Hg). The embrittlement can cause failure when the metal is stressed in tension. Metals susceptible to liquid Hg include: aluminum (Al), tin (Sn), gold (Au), silver (Ag), and zinc (Zn). A susceptible alloy, such as stainless steel and brass, needs only minute amounts of liquid Hg for LME to occur. Areas of particular susceptibility include stress concentration points where protective films are compromised, plastically deformed surfaces with exposed bare metal, or abraded surfaces with exposed bare metal.

1.1.6 Flow-Assisted Damage Mechanisms Flow-assisted damage encompasses metal loss that results from a variety of purely physical/mechanical influences. Velocity/flowrelated damage arises when high surface fluid or particle velocities

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cause metal loss. Some flow assisted damage is not related to corrosion mechanisms although the appearance of pits and metal loss is often similar and easily confused with corrosion.

1.1.6.1 Erosion Erosion is the progressive loss of material from a solid surface due to mechanical interaction between that surface and a fluid, a multicomponent fluid, or solid particles (sand or metal oxide particles) carried with the fluid. The particles tend to abrade or impact the metal surface accelerating the damage to the surface. This form of attack occurs without electrochemical interaction. It is often difficult to distinguish between strict erosion and erosion-corrosion, and a careful examination of all operating conditions is warranted whenever erosion is suspected.

1.1.6.2 Impingement Impingement is flow-assisted damage that occurs when the flow is perpendicular to the metal surface. Entrained gas bubbles and suspended solids in the fluids tend to accelerate this form of attack. Impingement can cause damage to the pipe’s protective film resulting in corrosion. Impingement damage results in pits/grooves that exhibit undercutting on the end away from the source of the flow (i.e., downstream end). It is commonly seen in pumps, valves, orifices, and pipeline elbows and tees.

1.1.6.3 Erosion-Corrosion Erosion-corrosion is an accelerated attack of mechanical wear or abrasion of corrosion products from a metal surface, occuring at the same time the metal beneath corrodes. The high velocity or turbulent flow of the medium wears away or damages the protective scale/film on the metal, exposing fresh metal to the corrosive environment. Figure 1.19 is an image of erosion-corrosion on a choke insert and an orifice plate. This form of corrosion generally forms pits or grooves, which parallel the direction of the flow. Pit formation tends to increase the turbulence and increase the erosion rates, thus leading to leaks. Erosion-corrosion commonly occurs at bends, elbows, connections where there is turbulent flow, section changes, or other areas involving changes in the flow direction. Figure 1.20 shows erosion-

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corrosion results in a through-wall leak on a 90 degree elbow on a sour multiphase pipeline.

Figure 1.19 Erosion on a Choke Insert (left) and an Orifice Plate (right)

Figure 1.20 Erosion-corrosion Resulting in a Through-wall Leak on a 90 Degree Elbow on a Sour Multiphase Pipeline Where the Gas Volume was Approximately 50 E3m3/d (1.5 MMSCFD), 20 m3/d water (135 BBls/d), 15% H2S, 2 % CO2 at Approximately 2 MPa (280 psig) and 15 °C (59 °F)

1.1.6.4 Cavitation Cavitation is flow-assisted damage in which a metal surface deteriorates due to the sudden formation and rapid collapse of bubbles/voids in high-fluid velocity liquid or when there is vibration of components in liquid service. Voids within the liquid develop when the local pressure of the liquid falls below the vapor pressure.

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Turbulence or temperature change may trigger this process. Cavitation produces areas or patches of pitted or roughened surfaces on the metal at the downstream side of the turbulence. The extent of the damage may range from loss of material to surface deformation or changes in the properties of the metal. Locations where cavitation are most likely to occur include: •

At the discharge of a valve or regulator, especially when operating in a near-closed position

•

At the suction of a pump, especially if operating near the net positive suction head required

•

At geometry-affected flow areas such as pipe elbows and expansions

•

Areas where dramatic pressure drops can occur

1.2 What Type of Pipeline Is It? The potential for internal corrosion to occur can vary greatly, depending on the type of service. Various types of pipeline services are described below.

1.2.1 Upstream Petroleum Production Pipelines Upstream production pipelines include gathering lines, flow lines, well lines, trunk lines, common lines, etc. The environments in upstream production pipelines can be harsh and aggressive in promoting internal corrosion. Upstream production pipelines can have high pressures, high temperatures, and contain potentially corrosive species. In particular, production pipelines can contain naturally occurring species such as water, H2S, CO2, organic/ inorganic acids, elemental sulfur, polysulfides, and elemental mercury. Under the right conditions, any one of these species can create an environment that produces severe corrosion. Additional potentially corrosive species may be introduced into the production field through drilling and maintenance fluids (concentrated brines and acids). As production progresses, solids and sands may become entrained in the production fluids, further impacting the internal corrosion (and erosion) conditions in the system.

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Due to the presence of solids, liquids, and gases in production environments, multiphase flow in production pipelines can be complex. Multiphase flow is defined as more than one physical form or state. In production systems, three phases – crude oil, water, and gas – may be present. Although both water and crude oil are liquids, they are considered separate phases. Flow will be further discussed in Section 1.3.8 Flow Modeling. Collectively, the various species and conditions present in production pipelines make for a very aggressive corrosion environment.

1.2.1.1 Crude Oil/ Multiphase High Vapor Pressure (HVP) Liquid Crude oil recovered from oil fields is generally a multiphase liquid consisting of hydrocarbons, natural gas, brine, and other impurities (i.e., metallic compounds and sulfur). Crude oils vary considerably, depending upon the nature of the organic compounds they contain. Factors that have significant effects on the corrosion rate in production systems include: • Water content • Acid gases (CO2 and H2S) • Oxygen • Chlorides • Solids • Paraffin, waxes, and asphaltenes • Flow velocity • Temperature • Pressure • pH • Pipeline material The impact of water content is presented below; the other factors are addressed in subsequent sections.

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1.2.1.1.1 Water Cut As previously discussed, an electrolyte is necessary for corrosion to occur. Multiphase production systems are vulnerable to corrosion because of their water cut. Water cut is defined as the volume of water divided by the volume of water plus crude oil. As the water content increases, the potential for internal corrosion increases. Ultimately, there is no strict rule-of-thumb for determining the critical water cut at which a given system will corrode, (i.e., a low water cut is not the sole factor in eliminating the possibility of corrosion). Water cuts in crude oil formations will vary over the life of the reservoir. During the early stages of production, crude oil is the primary transported media. As the field ages, methods to enhance oil recovery are used and internal corrosion issues increase as potentially corrosive species are introduced into the formation. During secondary recovery, water is injected into the formation to maintain pressure and to facilitate production. The injected water may contain chlorides, dissolved acid gases, oxygen, organics, scaling minerals, and bacteria. Water injection is further discussed in Section 1.2.1.3 Water Services (Sea, Produced, Fresh). Tertiary recovery methods are also used and can include injecting steam into the formation. Thus, depending upon the conditions, the use of recovery methods may increase the corrosion severity in production pipelines.

1.2.1.2 Natural Gas In general, the natural gas initially recovered/produced from oil fields, natural gas fields, and coal beds, contain significant amounts of methane. Several species that affect the internal corrosion behavior of the system, however, may also be present. These potentially corrosive species include formation water, dissolved gases (CO2 and H2S), organic acids, solids (sand and/or elemental sulfur), and mercury. Wet gas pipelines in natural gas storage fields, although not part of a production system, have environments similar to natural gas production pipelines. Thus, this discussion is applicable to any “wet” gas pipeline where “wet” gas is defined as gas that typically contains free liquid and/or is saturated with water vapor.

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The severity of corrosion in natural gas production increases when dissolved acid gases, CO2 and H2S, or O2 are present along with formation or condensed water. Similarly, organic acids in the system can result in internal conditions that are more corrosive than those produced by dissolved acid gases. Corrosion in natural gas production systems can be more severe than in multiphase crude oil production pipelines. The increased corrosion severity is because of increased water wet surfaces versus the oil wet surfaces that are sometimes observed in multiphase crude oil pipelines. This tendency is applicable for crude oil and natural gas pipelines of similar pressures, but is not necessarily true for low pressure natural gas production pipelines. Additionally, systems containing condensed water can experience higher corrosion severity than systems containing produced water because condensed water does not have buffering capacity. The same increased corrosion severity, due to recovery methods that exists in multiphase crude oil production pipelines, can also exist in natural gas production pipelines. Although not common to all production fields, mercury (Hg) in the formation can result in liquid metal embrittlement. Corrosion may also occur when liquid mercury combines with aluminum and tin, resulting in the potential for galvanic corrosion in presence of an electrolyte.

1.2.1.3 Water Services (Sea, Produced, Fresh) Water service used in oil and gas production processes typically involves injecting water into formations for enhanced oil and gas recovery after primary recovery methods have been exhausted. The injected water not only enables further oil and gas production, but helps maintain well pressures in the formation. Waters used for injection include fresh, sea, and produced waters. Depending upon the type of water used, and the success of contaminant removal prior to injection, the impact on internal corrosion may vary. Oxygen and bacteria are the two most significant factors that affect the corrosion rate in water handling services. However, some exceptions do exist. These exceptions include: •

Areas where high chloride-containing produced waters and acid gases are the primary factor

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The formation of scales and deposits which can plug the system

The effects of oxygen and bacteria are discussed in Section 1.1.4.3 Oxygen and Section 1.1.4.4 Microbiologically Influenced Corrosion. The concentration of water constituents can be described in mg/L or ppm (parts per million) and both are used in this course. The units of mg/L represent the weight of the constituent in a liter of liquid (typically water). Assuming a specific gravity of 1 g/cm3 for water, mg/L and ppm are interchangeable, as shown below. Xppm 

X mg L  10 6 3 1 g cm  1000 mg g  1000cm L 3

[1.8]

Other methods of reporting constituent levels include volume ratios (e.g., mL/L) or mass/weight ratios (e.g., mg/g). These ratios can also be expressed in units of ppm; for mass/weight ratios this corresponds to units of mg/kg and for volume ratios this corresponds to units of μL/L. 1.2.1.3.1 Fresh Water Sources of fresh water include lakes, streams, and rivers. Fresh water is characterized by low salt contents ( ic). Following this relationship, the smaller the anode area (Aa), the greater the anodic corrosion current density (ia). Finally, if the area of the cathode is small with respect to the area of the anode (Ac < Aa), the corrosion current density anode will be less than that for the cathode (ic > ia). In summary, a small anode/cathode area ratio is highly undesirable as it results in more severe corrosion of the anode. Conversely, a large anode/cathode area ratio is desirable.

2.2 Monitoring Techniques Monitoring techniques can be described as: •

Direct methods — involve the measurement or quantification of metal loss, from which corrosion rates can be estimated

•

Indirect methods — monitor parameters that can influence, or are influenced by the corrosion severity of the pipeline contents

•

Intrusive methods — require penetration into the pipe or vessel to gain direct access to the interior of the equipment

•

Non-intrusive methods — can monitor internal pipe wall loss from the outside of the pipe or vessel wall

Sampling methods are considered intrusive methods because access to the interior environment is required to obtain a sample. Table 2.1 lists and describes the characteristics of monitoring techniques commonly used. It is important to note that no single corrosion monitoring technique will work in all applications. Multiple techniques may need to be used in combination to provide accurate and reliable data.

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Table 2.1: Types of Monitoring Techniques.

Intrusive

Non-intrusive

Direct Corrosion coupons Spool pieces Electric resistance (ER) probes Linear polarization resistance (LPR) probes Electrochemical Noise (ECN) Ultrasonic testing (UT) Electrical Field Mapping (EFM)

Indirect Hydrogen probes Water chemistry Solid analysis Gas analysis

Hydrogen patch probes Acoustic monitoring

2.2.1 Selection of Representative Monitoring Locations Corrosion monitoring devices only provide information about the specific location where they are installed. Therefore, carefully selecting representative locations to monitor internal corrosion is essential in order to collect data that is meaningful. Proper selection requires knowledge of the internal environment and the system design. Monitoring locations should be selected where corrosion is expected to be: •

The most severe

•

Representative of the pipeline

Locations where corrosion is expected to be the most severe include low spots, drips, and stagnant areas (e.g., dead legs). Locations for monitoring should take into account the circumferential orientation where corrosion might be expected. For example, if top-of-line corrosion is anticipated, a 12 o’clock monitoring position would be appropriate. Where water/solids accumulation is probable, corrosion monitoring should be at the bottom of the pipe. The accessibility of a potential monitoring position should be considered as well. This is especially true when the ideal monitoring location is at the 6 o’clock position in a buried pipeline. Pipelines are not always equipped for, (or conducive to) installing, monitoring, servicing or extracting monitoring devices. Sometimes,

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the system can be retrofitted to accommodate monitoring devices, but this can be extensive in scope and very time consuming in order to ensure personnel safety. When it is not feasible to install monitoring devices at ideal locations along the pipeline, monitoring is then often performed at separators or other locations in pipeline facilities. Side streams may be considered in order to monitor an environment that is representative of the pipeline. The use of side streams is further discussed below. Multiple monitoring locations may be needed to gain a complete profile of the corrosive environment of a given system. For instance, if multiple flow regimes are expected, monitoring should be performed in areas of each flow regime.

2.2.1.1 Side Streams and Bypass Loops Side streams are bypass loops that are created by tapping a line in two different spots to create a separate stream. Monitoring devices can be inserted into the side streams; gas, liquid, or solids may be collected. Side streams can be isolated, allowing easy installation and removal of monitoring devices without affecting the flow in the pipeline. Figure 2.1 is an example of a side stream.

Figure 2.1 Example of a Side Stream

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Side streams typically have a smaller diameter than the main line, so there is a different flow rate and velocity in the side stream than the pipeline. The difference in flow rate can have a large effect on the measurements that are being taken. For example, if erosion or erosion-corrosion is a concern, the flow in a side stream will have a higher velocity and, therefore, a higher propensity for erosion. Alternatively, if water separation due to low flow rates is the concern, the side stream is less likely to have corrosion due to water separation than the pipeline. Another factor to keep in mind when using side streams or by-pass loops is that there are highly turbulent flow regions at the beginning and end of the stream (and potentially throughout, depending on the flow rates, pipe diameter, and length of the stream/loop). Again, these conditions are not necessarily representative of the environment in the pipeline.

2.2.1.2 Monitoring Points at Facilities It is common for there to be access points at pipeline facilities for monitoring (including sample collection). Separators, slug catchers, or headers are places in pipeline facilities where the corrosion rate may be more severe than the pipeline itself due to the presence of water and stagnant conditions.

2.2.2 Direct Intrusive Techniques Direct intrusive methods insert a monitoring device through a fitting into the pipe for it to be exposed to the internal environment. This method may require modification of the pipe. Monitoring devices can be installed using either a retractable device or plug fitting. Retractable devices are available, which enable coupons and probes to be extracted and replaced without requiring depressurization or shut down of the system. Various types of retractable devices are available, tailored to the system pressure. Figure 2.2 and Figure 2.3 show low and high pressure retractable devices. Plug fittings inserted directly into the pipeline require isolation and depressurization at the monitoring location. The amount of product lost during isolation and depressurization depends on the distance between isolation points. Plug fittings may also be used in side streams or off of isolation valves.

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There are Health, Safety and Environment (HSE) issues associated with all intrusive techniques.

Figure 2.2 Retractable Device; Low Pressure System

Figure 2.3 Retractable Device; High Pressure System

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2.2.2.1 Corrosion Coupons A corrosion coupon is a carefully cleaned and weighed piece of metal that is used to monitor corrosion severity in the pipeline environment by being exposed to it. Coupons are manufactured in variety of shapes and from a variety of materials (e.g., low carbon steel, API grade steel, or actual pipe samples). Ideally, the coupon should be similar to the pipe material in terms of composition. Coupon holders hold the coupon in place in the pipeline environment. If the coupon holder is metallic, non-metallic (e.g., plastic) spacers should be used to electrically isolate the coupon from the holder so that galvanic corrosion cannot occur. Figure 2.4 illustrates coupon types and coupons in coupon holders. Once inserted into the pipeline, the coupon is exposed for a predetermined period of time that is based on past monitoring results, the expected corrosion rate, or other internal corrosion data.

Figure 2.4 Assortment of Coupon Types (left); Coupons in Coupon Holders (right)

The coupons should be visually examined when removed. Damage and the nature of any product films (i.e., color) should be documented. Figure 2.5 shows a coupon immediately after removal from a pipeline. The following are examples of observations from coupon removals: •

The coupon is encased in a salt product.

•

The coupon contains a thick or thin scale.

•

The coupon is covered in oil (in a gas system).

•

The coupon is covered in debris.

•

Solid particles appear embedded in coupon.

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•

The coupon is covered in slime.

•

The coupon was damaged during removal.

•

The coupon is bent.

It is important to note the color of any solids present on the coupon immediately after removal since the color of the solids may change with time. Information documented at the time of removal can help in describing and determining the corrosion environment. For example, the presence of brown film, rather than black or green film, in oilfield exposure may indicate the occurrence of oxygen ingress.

Figure 2.5 Coupon Immediately After Removal From a Pipeline

After exposure, the coupon is cleaned and weighed. The end weight of the coupon is compared to its initial weight when installed to determine what mass has been lost during the exposure period. The general corrosion rate is determined based on the mass loss, the time of exposure, and the surface area of the coupon, using Equation 2.4 from NACE RP0775 “Preparation, Installation, Analysis, and Interpretation of Corrosion Coupons in Oilfield Operations”.

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(Initial Weight - Final Weight) x Unit Factor Corrosion Rate = ----------------------------------------------------------------------------------------------------------Area x Density x Exposure Period Variable

[2.4]

SI units

Imperial units

millimeters per year (mm/y)

mils per year (mpy)

Weights:

grams (g)

grams (g)

Density:

grams/cubic centimeter (g/cm3)

grams/cubic centimeter (g/cm3)

days (d)

days (d)

millimeters squared (mm2)

inches squared (in2)

365,000

22,300

Corrosion Rate

Exposure period: Area: Unit Factor:

General corrosion rate assumes that mass loss occurred uniformly over the surface of the coupon. Mass loss resulting from localized damaged (such as pitting, edge erosion, or mechanical damage) is not properly reflected in the general corrosion rate value. Additional analysis of the coupon can be performed to characterize this type of damage. One example of additional analysis is an examination to determine a pit rate. The coupon can be examined using an optical microscope (stereomicroscope) to determine if pitting is present. The pit density and maximum pit diameter can be determined easily using an optical microscope equipped with a measuring reticule. Pit depth can be measured using a metallograph. Alternatively, surface profilometry can be used to characterize the surface. Maximum pit depth can then be used to calculate a pitting rate equivalent, as shown in the equation below from NACE RP0775 “Preparation, Installation, Analysis, and Interpretation of Corrosion Coupons in Oilfield Operations”.  days   mils   Max pit depth microns * 0.03937   * 365   micron   year  Pitting Rate Equivalent mpy  exposure period days

[2.5]

The pitting rate must be calculated in order to properly interpret the results and determine the appropriate mitigation methods. If localized corrosion is the predominant form of corrosion in a

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pipeline (vs. general corrosion), general corrosion rates will not accurately characterize the corrosion severity. Additional methods of analysis include scanning electron microscopy (SEM) and energy dispersive spectroscopy (EDS). SEM analysis can determine corrosion severity and morphology on a microscopic scale using 500X to 1000X (or higher) magnifications. EDS determines the qualitative chemical makeup of scale or deposits associated with corrosion features on the coupon. Table 2.2 provides general interpretations that can be made from coupon monitoring results. The table should not be taken as a strict guideline. Table 2.2: Categorization of Carbon Steel Corrosion Rates from NACE RP0775 Average Corrosion Rate mm/y (1) mpy (2) Low 10 (1) mm/y = millimeters per year (2) mpy = mils per year

Maximum Pitting Rate mm/y mpy 15

Advantages •

Low material cost per coupon

•

Simple direct analysis in most cases

•

No electronic or complex instrumentation is necessary

•

Can be used in almost any environment

•

Not constrained by temperature

•

Additional analysis can provide information on pitting rates

Limitations •

Each analysis cycle requires insertion into pipeline, exposing personnel to potential hazards (HSE considerations)

•

Does not provide real time corrosion rates

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•

Intrusive coupons can prevent passage of pigs

•

Does not detect short duration upsets or variations in the corrosion rate during the period of exposure

2.2.2.2 Spool Piece A spool piece is a relatively short 300 to 900 mm (1-3 ft) long section of pipe that can be installed and periodically removed for inspection. The spool should be the same size and metal composition as the material used in the system. If the composition of the spool piece and piping are different, electrical isolation should be used to avoid galvanic corrosion. Spools are usually exposed for longer periods of time than coupons (90 days to 2 years). Visual inspection is used to determine the presence of corrosion and solids. Measurements from successive installations can be used to determine corrosion and pitting rates. However, if protective scales are disrupted or removed during spool inspection, subsequent corrosion and pitting rates may be effected. Spool pieces may also contain corrosion monitoring devices that can be removed and examined in a laboratory. Advantages •

Allows visual inspection of pipe

Limitations •

Requires extensive fabrication for installation

•

Requires taking the line out of service to remove/install the spool

•

Corrosion measurement may require the use of additional inspection techniques depending on length and diameter of pipe

2.2.2.3 Electrical Resistance (ER) Probes An ER probe consists of a sensing (exposed) metal element and a reference metal element. The exposed element is placed in the pipeline environment while the reference element is sealed within the probe body (i.e., not exposed to the pipeline environment). Since sensing elements come in a variety of materials, use one that matches the pipe material. Data is collected either by a handheld logger, a data recorder at probe location, a radio transmission of data, or a hard wire to a Supervisory Control and Data Acquisition

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system (SCADA). Figure 2.6 shows a schematic and a photograph of an ER probe with its associated data collector.

Figure 2.6 ER Probe and Data Collector

Once ER probes are installed, they remain in service unless the probes need to be replaced or inspected (versus coupons, which require removal from the system on a routine basis). ER probes may need be replaced for a variety of reasons, such as corrosion, mechanical damage, etc. ER probes determine metal loss by measuring the increase in electrical resistance of the probe element as its cross-sectional area is reduced by corrosion. The relationship between the probe’s resistance and cross-sectional area is given in the equation below: R

l A

[2.6]

Where: ρ = the resistivity of the probe material l = probe length A = the probe cross-sectional area

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As the cross-sectional area of the sensing probe decreases due to corrosion, its resistance increases proportionally. In general, ER probes are not appropriate for monitoring pitting corrosion. Temperature changes can affect ER probes by altering the probe resistance. Measurements of the resistance ratio between the sensing element and the reference element are used to account for resistance changes attributable to temperature. ER probes do not need to be submerged in an electrolyte, so they are operational in a variety of environments (e.g., normally “dry” gas pipelines). The usefulness of ER is very limited in environments where conductive scales or products precipitate onto the electrode elements. Scales or corrosion products can cause underestimation of the associated metal loss by dampening the probe response (i.e., change in resistance ratio is less than it should be). For some designs, bridging may occur when semi-conductive FexSy scales form. Various probe sensing element designs are available and include wires, strips/plates, or tubes. Figure 2.7 shows various ER probe element designs. Sensing elements can either protrude into the process stream or remain flush with the internal surface of the pipe. The sensitivity of the probe can be adjusted by varying the thickness of the wire, or wall thickness of the plate, tube, or strip. Increased sensitivities can be achieved through reduction of element thickness. However, this decreases the service life of the probe. In general, the useful life of strip and tube-type element is compromised once the element has been reduced to half of its original thickness, while wire probe elements are compromised once the element is reduced to a quarter of its original thickness. Figure 2.8 shows a close-up example of ER probe elements.

Figure 2.7 ER Probes

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Figure 2.8 ER Probe Elements

Proper selection of the probe element (e.g., wire vs. tube) is often dictated by the known or expected corrosion damage. For example, while wire loop probes tend to be highly sensitive, they are unsuitable for high flow rate applications in which erosive conditions exist. Cylindrical probe elements are often used for harsh environments including high temperatures and high velocities. Flush mounted probes are designed to be placed into pipes without protruding beyond the wall thickness, making them the optimum choice for systems requiring regular pigging. Data from the ER probes can be obtained periodically or continuously depending on the method of data collection. Readings taken on a continuous basis are either radio transmitted or hard wired into the SCADA system and provide real-time, on-line measurement of general corrosion rates. Readings taken on a periodic basis (e.g., using a portable data logger) provide a general corrosion rate for the time period between measurements. During the initial installation, obtain a baseline reading only after the probe reaches steady state with the system. Depending upon the environment, it may take hours or days before the probe reaches a steady state. Probe manufacturers provide conversion factors and/or formulas to convert the meter readings to a corrosion rate. A plot of corrosion meter readings vs. time is another method to determine the associated corrosion rates. From this method, readings from the

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meter are converted to corrosion rates (in mpy) using slopes and according to the following equation: mpy 

d ( K ) t

[2.7]

Where: ∆d = the change in meter reading K

= probe factor supplied by manufacturer

∆t = time between readings New generation high resolution ER probes are available and provide enhanced compensation for temperature and electronic noise reduction. Compared to other ER probes, high resolution ER probes tend to have quicker response times. Thus, they have been used in pipelines with highly active corrosion. Erosion ER probes are also available and use corrosion resistant alloys (CRAs), such as stainless steel for the sensing elements. Erosion ER probes monitor changes in resistance due to solids impacting the sensing elements. Due to the severity of the potential damage, the sensing elements are either in thin-walled tubes or embedded in 45o angled probes. For optimum results, the probes are located either within two pipe diameters from an elbow or in areas of high turbulence. Advantages •

Can be used to determine general corrosion rates in any corrosive environment

•

Data can be remotely monitored or accessed

•

Continuous corrosion monitoring is possible

•

Can detect upsets or periods of increased or decreased corrosion rates

•

Can be used to determine optimum chemical usage to control general corrosion

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Limitations •

Requires insertion into pipeline, exposing personnel to potential hazards

•

Not sensitive to localized corrosion (pitting)

•

Deposits/corrosion products on the element can cause false readings

•

Limited element life based on corrosion rate

•

Can prevent passage of pigs unless flush mounted probes are used

•

Temperature fluctuations can cause erroneous readings

2.2.2.4 Linear Polarization Resistance (LPR) Probes An LPR probe consists of two or three electrodes that are electrically isolated from each other. Electrodes come in a variety of materials and only those composed of the same material as the pipe should be used. All electrodes are exposed to the pipeline environment. LPR probes can have electrodes that are either flush to the surface or protruding (“finger-like”) into the system. LPR probes with flush mounted electrodes can be used at locations where pigging is required. Figure 2.9 is a schematic showing flush and “finger-type” LPR probes.

Figure 2.9 Flush and “Finger-type” LPR Probes

Three-electrode probes can measure solution resistance (Rs) or environmental IR drop, and account for the resistance in the corrosion rate. Rs values are critical for high resistance (low

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conductivity) environments because the solution resistance can significantly impact the corrosion rate. If the resistance of the environment is low, the Rs value may be considered negligible. LPR probes can also provide information about general corrosion rates in aqueous environments. Continuous immersion of the probe elements in the electrolyte is necessary to obtain meaningful results. Fouling of the LPR probe elements by oil, paraffin, iron sulfide or scale deposits can result in bad data and require the probe to be removed and cleaned. Consequently, the application of LPR probes in oil and gas operations has been limited. Data can be collected using a handheld logger, data recorder at probe location, radio transmission of data, or using a hard wire to a SCADA system. Once LPR probes are installed, they remain in service unless the probes need to be replaced or inspected, contrary to coupons which require removal from the system on a routine basis. LPR probes use electrochemical techniques to determine corrosion rates. A small potential is applied to polarize the electrodes to approximately 10 mV below (more negative) and above (more positive) the open circuit potential (OCP). The OCP refers to the steady state potential between two electrodes in the absence of an external current. The resulting current is measured, assumingly without significantly disturbing the rate or nature of the corrosion reactions. The linear polarization technique uses Faraday’s Law, mixed potential theory, and the Butler-Volmer equation to derive an inverse relationship between polarization resistance (Rp) and the corrosion current density. The linear polarization resistance is the ratio of the change of potential (∆E) to the change of current density ∆Iapp). Graphically, the Rp is the slope of a linear plot of potential versus current density at the open circuit potential. Mathematically, the corrosion current density can be determined using the Stern-Geary relationship below: Rp 

a c E  I app 2.3 icorr (  a   c )

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[2.8]

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Where: Rp = the polarization resistance (Ω) ∆E = the change in corrosion potential (V) ∆iapp= the change in corrosion current density (A/cm2) βa

= the estimated or measured Tafel slope for the anodic reaction (V/decade) βc = the estimated or measured Tafel slope for the cathodic reaction (V/decade) icorr = the corrosion current density at the free-corroding potential (A/cm2)

Using the Stern-Geary equation above, the icorr can be determined and then used to calculate a corrosion rate (CR) from the following equation: CR 

icorr M FZD

[2.9]

Where: M=

molecular weight of the metal (g)

F =

Faraday’s constant = 96,485.339 C/mol

Z =

metal valence

D =

density of the metal (g/cm3)

The electrode configuration of LPR probes allows for combination with other electrochemical measurements, such as electrochemical noise (ECN). Advantages •

Can provide an instantaneous corrosion rate

•

Data can be remotely monitored or accessed

•

Does not require any corrosion to occur on the probe

•

Can detect process upsets or other short-term corrosion conditions

•

Can be used for quick comparisons of corrosion inhibitors

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Limitations •

Requires insertion into pipeline, exposing personnel to potential hazards

•

Not sensitive to localized corrosion (pitting)

•

Works best when water phase is continuous, precluding use of the technique for many applications in oil and gas industry

•

Cannot be used in sour systems (H2S) since conductive iron sulfide deposits can short circuit the electrodes

•

Electrodes can be fouled by surface deposits and condensates/oil

2.2.2.5 Electrochemical Noise (ECN) Electrochemical noise probes are similar LPR probes in that they consist of two or three electrodes that are electrically isolated from each other. Electrodes come in a variety of materials; only the same material as the pipe should be used. All electrodes are exposed to the pipeline environment. ECN probes can have electrodes that are either flush to the surface or protruding (“finger-like”) into the system. The ECN technique measures the naturally occurring fluctuations (noise) in the potential and/or current generated by the corrosion at the metal (electrode)-electrolyte interface (i.e., without any external influence). These fluctuations are on the order of 10-3 to 1 Hz. The technique can also measure the: •

Noise in the current based on an applied potential

•

Noise in the potential based on an applied current

Figure 2.10 shows an example of current measured by an ECN probe.

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Figure 2.10 Current Measured by an ECN Probe

Current noise fluctuations are commonly measured between two nominally identical electrodes, while potential noise fluctuations are commonly measured using an electrode and a reference electrode or using two nominally identical electrodes. For most applications, a zero-resistance ammeter is coupled to the electrodes so that no signal is applied to the sample by the device itself. A three electrode system is commonly used since it allows for simultaneous measurement of both the electrochemical current noise and the electrochemical potential noise. For most industrial monitoring, corrosion probes comprised of three identical (i.e., same material) sensing probes are used for ECN measurements. Current noise measurements use two of the sensing elements while potential noise measurements use all three elements. The potential benefit of the ECN technique is its ability to distinguish between general and localized corrosion through their distinct noise signatures. Specifically, the ECN technique can identify the onset of localized corrosion (i.e., pitting) before it is visually evident. Noise measurements are related to electrochemical activity. The greater the noise level, the more active the

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electrochemical corrosion at the electrode-electrolyte interface. Figure 2.11 shows plot of the localized corrosion index as determined using measurements obtained by an ECN probe.

Figure 2.11 Pitting Potential Measured by an ECN Probe

The noise is then analyzed using various algorithms to determine a corrosion rate. ECN data analysis can be labor intensive and requires a skilled expert to properly analyze the signal. Advantages •

Data can be remotely monitored or accessed

•

Does not affect natural corrosion reactions

•

Data has the potential to provide information about corrosion mechanisms, i.e., can detect non-uniform corrosion resulting from pitting, stress corrosion cracking (SCC) and crevice corrosion

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Can provide corrosion rate determinations, particularly at low corrosion rates

Limitations •

Requires insertion into pipeline, exposing personnel to potential hazards

•

Limited, well documented examples for CO2 corrosion in the oil and gas industry

•

Works best when the water phase is continuous

•

Electrodes can be fouled by surface deposits and condensates/oil

•

Data analysis is highly mathematical and time consuming

2.2.3 Direct Non-Intrusive Techniques Direct non-intrusive techniques measure metal loss from which a corrosion rate can be estimated without inserting a device through the pipe or vessel wall.

2.2.3.1 Electrical Field Mapping (EFM) Electrical Field Mapping (EFM) involves permanently attaching a series of sensing pins to the external surface of the pipeline. These pins are arranged in a geometric array or matrix and may be welded, glued, or spring-loaded to the pipe. When measurement is performed, a current is applied to the pipeline at the location of the pins. When applied, the current is efficiently spread out across the monitored area. For a pipeline with an even wall thickness, a uniform electrical field is set up. However, the presence of general corrosion, localized corrosion, and cracks can distort this electrical field. The voltage between the pins, which results from the distortion of the electric field, is measured. When the voltage measurements are compared with the original measurements, they reflect wall thickness loss, resulting in a “map” of the monitored area. EFM is used to monitor short sections of pipe (e.g., a meter/a few feet long); see Figure 2.12. EFM must have a continuous power source if monitoring is continuous.

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Figure 2.12 EFM Used to Monitor Short Pipe Section

The sensitivity of EFM in identifying general or localized corrosion (pitting or cracking) depends on the pin spacing. As the pin spacing increases, the resolution for general corrosion increases and the resolution for localized corrosion decreases. EFM can be applied to new pipelines or old pipelines with existing internal or external corrosion features. Baseline wall thickness measurements (for new and corroded pipelines) are needed before the monitoring device is installed. Data can be recorded at a remote monitoring station, but there are limitations on the distance the station can be located from the monitoring point. Data interpretation requires the use of analysis software. Advantages •

Made directly on structure, pipe, or vessel

•

Does not alter the flow conditions or the corrosion process in the pipe

•

Generally, no access is required after initial installation; does not require insertion into pipeline and limits exposure of personnel to potential hazards.

•

Provides monitoring in locations that are inaccessible for regular inspection.

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Limitations •

Does not distinguish between internal flaws, external flaws, or material loss

•

Discrimination between individual pits is sometimes difficult

•

Battery replacement is necessary if portable battery source is used

•

Requires baseline wall thickness data and results of previous inspection measurements

•

Interpretation is sometimes impaired by conductive scales and depositions

2.2.3.2 Permanently Mounted UT Probes Ultrasonic testing probes can be permanently mounted to the pipe to provide continuous monitoring. Ultrasonic testing is described later in Section 2.3.4 Ultrasonic Testing (UT). Similar to successive UT measurements, a corrosion rate is determined by comparing the change of wall thickness over a given period of time. Permanently attached UT probes provide more accurate data than successive UT measurements because the exact location of the measurement remains constant. The sensitivity of the probes limits the minimum corrosion rate or change in wall loss that can be detected. Advantages •

Direct measurement of remaining wall thickness

•

Does not require insertion into pipeline and exposure of personnel to potential hazards

Limitations •

Adversely affected by variations in temperature of the pipe wall and by erroneous sound reflections

•

Presence of rust, scales, and heavily corroded surfaces can reduce the accuracy of the measurements

•

Monitoring is limited to a very local area

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2.2.3.3 Acoustic Solids Monitoring Special acoustic ER probes and acoustic techniques can be used to monitor for solids. Erosion monitoring ER probes were already discussed in Section 2.2.2.3 Electrical Resistance (ER) Probes. Non-intrusive acoustic solid monitoring involves measuring acoustic noise generated by solids impacting pipe walls. An acoustic monitor is attached on the external surface of the pipe/component and sensors contained in a weatherproof housing produce a signal in response to solid impact noise. The signals are integrated over time and compared to pre-determined solid-free flow values. Signals not associated with solid-free flow are then converted to solid rates through internal calibrations. This information allows operators to quantify produced solid rates, correlate the rates with flow regimes, and optimize the rates to reduce/prevent further formation and erosion damage. It is important to note that the technique does not directly monitor damage to the pipe from erosion. Other techniques such as UT inspection and electric field monitoring (EFM) can be used to determine the extent of damage due to erosion. The limitation of UT and ERM is that it is very difficult to distinguish between metal loss due to erosion and that due to corrosion. Advantages •

Can provide produced solid rates

•

Does not require insertion into pipeline and exposure of personnel to potential hazards

Limitations •

Does not directly monitor the amount of erosion damage

•

Requires baseline solid-free data to determine solid rates

•

False positives created by other impinging components of the product stream e.g., bubbles or droplets

2.2.4 Indirect Methods Indirect methods monitor parameters that can influence or are influenced by the corrosion severity of the pipeline environment.

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2.2.4.1 Hydrogen Monitoring As previously discussed, corrosion commonly produces atomic hydrogen (Ho). Hydrogen monitoring involves the use of intrusive or non-intrusive hydrogen probes to monitor hydrogen absorption by steel. These devices can be used to monitor the potential for: •

Hydrogen induced cracking (HIC)

•

Stress oriented hydrogen induced cracking (SOHIC)

•

Sulfide stress cracking (SSC)

A baseline must be developed for hydrogen monitoring probes to make sense of the data. Hydrogen probes do not provide a method for predicting the exact corrosion rate occurring, but do present a good measure of hydrogen activity. The hydrogen activity can be extrapolated to hydrogen related problems, such as corrosion, hydrogen embrittlement, or hydrogen blistering. 2.2.4.1.1 Intrusive Hydrogen Probes Intrusive hydrogen probes consist of steel sensing elements, which have a hollow space inside, connected to a pressure-sensing device that monitors the buildup of hydrogen pressure. The rate of hydrogen pressure buildup is proportional to the severity of hydrogen absorption. Advantages •

Can respond quickly to changes in the transport rate of atomic hydrogen

•

Can detect very small amounts of atomic hydrogen

Limitations •

Requires insertion into pipeline, exposing personnel to potential hazards

•

Results only apply to the area being monitored

•

Erroneous results can be caused by temperature fluctuations

•

There is no definite correlation between the rate of atomic hydrogen transport through the pipe wall and corrosion rate

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If probes are not checked, pressure can build up and rupture the gauge

2.2.4.1.2 Non-intrusive Hydrogen Patch Probes Non-intrusive hydrogen probes consist of an externally applied patch or cell that monitors the rate of hydrogen egress from the outer surface of the steel. Figure 2.13 shows an example of a hydrogen patch probe. Hydrogen patch probes include pressure patch probes and electrochemical patch probes. Hydrogen pressure probes act as artificial voids on the surface of the pipe, trapping hydrogen atoms as they diffuse through the pipe wall. The change in pressure measured in the probe chamber gives a good indication of the rate of diffusion. Electrochemical hydrogen probes measure hydrogen diffusion directly by creating an electrochemical cell on the pipe surface. As hydrogen atoms diffuse to the external pipe surface, they are ionized to H+ ions. The ions then enter the solution and are reduced to hydrogen gas (H2). The current flowing in the cell is proportional to the amount of hydrogen diffusing through the steel.

Figure 2.13 Hydrogen Patch Probe

Advantages •

Can respond quickly to changes in the transport rate of atomic hydrogen

•

Can detect very small amounts of atomic hydrogen

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Does not require insertion into pipeline and exposure of personnel to potential hazards

Limitations •

Results only apply to the area being monitored

•

Erroneous results can be caused by temperature fluctuations

•

There is no definite correlation between the rate of atomic hydrogen transport through the pipe wall and corrosion rate

2.2.4.2 Gas Analysis Gas samples can be measured using on-line monitoring devices such as gas chromatographs, dew point analyzers, O2 monitors, or H2S monitors. Additionally, stain tubes can be used in the field to determine concentrations of various gases or samples can be collected and sent to a laboratory for analysis. Although stain tubes provide less accurate information than an on-line gas chromatograph, where on-line instrumentation is not available, stain tubes may be preferable to sample collection and subsequent analysis. For example, water content is more accurately measured in the field than by laboratory analysis. Additionally, laboratory collection of H2S is difficult because the H2S can react with the sample cylinders, causing H2S levels to drop. Gas chromatography can be used to analyze CO2 content. When sampling, it is important that the sampling port or sampling collection bottle is purged of any air present. Stain tubes are limited to a certain range of testing. Therefore, it is important that the appropriate stain tube is chosen based on known system conditions. Measurements on stain tubes are dependent upon exposure time and flow rate through the tube, which makes them susceptible to error. Gas analysis results may be used with corrosion rate modeling to estimate a corrosion rate. Advantages •

Can be used to determine potential for water vapor condensation

•

Can be used to indicate acid gas concentrations

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Stain tubes are a relatively inexpensive way to perform measurements at multiple locations

Limitations •

Requires exposure of personnel to pipeline environment

•

Error associated with stain tubes or laboratory samples containing H2S

•

Corrosion rates determined from modeling using gas analysis results assume that water is present

•

Provides information on potential for corrosion to occur, but does not provide information that corrosion has occurred

2.2.4.3 Water Analysis If water is present in a liquid sample, analysis can be used to determine the concentrations of potentially corrosive constituents and corrosion products in a pipeline system. Some chemical constituents of water can be monitored using online devices. A full chemical analysis involves determination of the following: •

Dissolved gases (H2S, CO2, and O2)

•

pH

•

Alkalinity

•

Concentration of anions (chloride, sulfate, bicarbonate, and carbonate)

•

Concentration of metals/cations (calcium, magnesium, barium, strontium, sodium, potassium, iron, and manganese)

•

Specific gravity

•

Total dissolved solids (TDS)

•

Organic acids

•

Inhibitor residuals

Examples of water sample analysis reports can be found in Appendix A.

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Advantages •

Can be used to determine the presence of potentially corrosive species

•

Can be used to determine the potential for scaling

Limitations •

Requires exposure of personnel to pipeline environment

•

Improper sampling and preservation will affect results

•

Provides information on potential for corrosion to occur, but does not provide information that corrosion has occurred

2.2.4.3.1 Sample Collection Where water is continuously present or present in a large volume, the sample point should be allowed to flow for a short period of time prior to sample collection in order to collect a sample representative of the bulk liquid. However, for locations where a limited amount of water is available, this may not be possible. The volume of sample required for a water analysis depends upon the type of analysis to be performed. To prevent gas permeation, glass sample bottles are recommended. Sample bottles should be filled to the top, eliminating any excess air. The bottle should remain capped, except to remove samples for on-site testing. This is necessary to avoid contamination and minimize escape of dissolved gases. Samples should be collected in clean, new bottles. Care should be taken to avoid touching the inside of the bottle with anything that could contaminate the sample. Samples should be properly labeled including the time and date of collection. Samples change the instant they leave the pipe. Many chemical and biological parameters are profoundly affected during sample collection and handling. It is imperative that on-site testing be performed without delay in order to accurately portray the system conditions. On-site testing includes: •

Temperature

•

Dissolved gas contents (O2, CO2, and H2S)

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•

Bacteria sample preservation

•

pH

•

Total alkalinity

If Yes, How Bad Is It?

The following tests require proper handling, sampling and preservation. 2.2.4.3.2 pH After a water sample is collected, pH levels can change rapidly as a result of dissolved gas egress due to depressurization. Therefore, it is important to know if the pH value reported is a field or laboratory measurement. In the field, digital meters provide more reliable measurements than pH paper because interpretation of results using pH paper is subjective. 2.2.4.3.3 Alkalinity As previously stated, pH levels are expected to change with time due to dissolved gas egress. These changes in pH will in turn affect total alkalinity measurements which are pH dependent. Therefore, alkalinity measurements obtained during on-site testing are more reliable than those obtained from laboratory analysis. Alkalinity is determined based on acid titration. Acid titration involves adding acid (e.g., sulfuric acid or hydrochloric) to a water sample containing a color indicator (e.g., phenolphthalein or bromcresol green) until the end point (color change) is reached. It may be difficult to identify the color change in samples that are dark in color. 2.2.4.3.4 Anion Concentrations Anion concentrations are determined in laboratories using ion chromatography. Discussion of how ion chromatography works is outside the scope of this course. However, it is important to realize that there is a minimum detection limit for each ion which may vary from instrument to instrument. Field kits are available for determining some anion concentrations. Some kits use color comparative test strips (similar to pH strips), while others use portable spectrophotometers. Field testing of anions is more prevalent for water pipelines than for the oil and gas industry.

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2.2.4.3.5 Metal (Cation) Concentrations Metal concentrations are determined in laboratories using inductively coupled plasma spectroscopy (ICP) or atomic absorption spectroscopy (AAS). ICP allows for analysis of multiple elements simultaneously, allowing for shorter analysis times compared to AAS. Discussion of how ICP and AAS work is outside the scope of this course. However, it is important to realize that there is a minimum detection limit for each metal ion which may vary from instrument to instrument. Similar to the kits listed for determining anion concentrations, field kits are available for determining metal ion concentrations. 2.2.4.3.6 Specific Gravity Specific gravity is the ratio of the density of the liquid to the density of water. Specific gravity measurements can provide an indication of the total dissolved solid (TDS) content in a sample. Samples with a specific gravity greater than 1 suggest the presence of TDS. Specific gravities less than 1 may indicate that the sample contains liquids other than water (e.g., methanol). Specific gravity is a laboratory analysis that can be performed using a hydrometer. 2.2.4.3.7 Total Dissolved Solids (TDS) Total dissolved solids (TDS) are a combination of all inorganic and non-volatile organic substances in a water sample that would be left after drying. The determination of TDS is often used to check the completeness of a water analysis. The TDS should be roughly equivalent to the sum of all metal and anion concentrations. If major discrepancies exist, further investigation may be warranted to determine if additional constituents (not analyzed) are present in the sample. Note: Sometimes instead of analyzing for sodium and/or potassium, their concentrations are determined by finding the difference between the TDS content and the sum of other individual constituents. 2.2.4.3.8 Organic Acid Organic acid concentrations are determined in laboratories using ion chromatography. Since organic acids in samples can degrade, it is

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important to use proper sampling and preservation methods to prevent degradation. Discussion of how ion chromatography works is outside the scope of this course. However, it is important to realize that there is a minimum detection limit for each organic acid which may vary from instrument to instrument. 2.2.4.3.9 Inhibitor Residuals Inhibitor residuals are used to determine the efficacy and performance of a mitigation treatment when combined with monitoring data from coupons, probes, and inspection Residuals analyses are commonly performed by measuring one or more constituent in the inhibitor (e.g., amines). Additionally, chemical suppliers should be able to identify specific tests to determine residual values, i.e., UV fluorescence or liquid chromatography, that may be used to analyze inhibitor constituents. Inhibitor residuals can only be used to determine if the chemical has reached the bulk liquid at a given location. The residual levels do not provide any information regarding the effectiveness of the treatment. Therefore, the use of inhibitor residuals alone (without supporting corrosion monitoring data) is not a technically sound practice. It is possible for upstream chemicals to carry over and interfere with accurate determination of downstream treatments.

2.2.4.4 Solid Analyses Solid samples may be collected from pig receivers and exposed pipes. Solids may also be present in liquid samples. Analyses of solid samples include both on-site and laboratory testing. Critical testing for solid samples that should be performed on-site include: •

pH testing

•

Bacterial culturing

•

Sulfide/carbonate spot tests

Additional solid analyses performed in a laboratory include: •

Qualitative Spot Tests

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•

Energy Dispersive Spectroscopy (EDS)

•

X-ray Fluorescence (XRF)

•

X-ray diffraction (XRD)

Examples of solid analysis reports can be found in Appendix A. Advantages •

Can be used to determine the presence of potentially corrosive species

•

Can be used to determine the potential for scaling

Limitations •

Requires exposure of personnel to pipeline environment

•

Improper sampling and preservation will affect results

•

Provides information on potential for corrosion to occur, but does not provide information that corrosion has occurred

2.2.4.4.1 Sample Collection Solid samples are typically collected in plastic bags using clean, sterile equipment. Air should be evacuated from the bag prior to sealing. If possible, samples should be double bagged to reduce the potential for damage. Sludge samples are typically collected in clean, new polyethylene bottles similar to that used for liquids. The color and smell of any solids collected should be recorded at the time of removal since these may change with time. Properly labeling of the sample should include the contents, date of sampling, and time of sampling. Samples should be kept in a cool, dark place if possible. Sludge samples typically require drying prior to laboratory analysis. 2.2.4.4.2 Qualitative Spot Tests Field spot tests can be performed to potentially identify the presence of various scales or compounds (e.g., carbonates and sulfides). The majority of the tests involve the reaction of the tested solid with an acid. The intensity of the reaction, smell, and color are all used to determine the presence of various compounds. Lead acetate paper may also be used to determine the presence of H2S released during

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the reaction with the acid. Kit instructions should be used to determine results. 2.2.4.4.3 Energy Dispersive Spectroscopy (EDS) Energy Dispersive Spectroscopy (EDS) is a non-destructive technique that uses a scanning electron microscope (SEM). EDS provides elemental composition information of a solid. EDS operates by bombarding the sample with an electron beam and measuring the resultant emission of x-rays. For each element, the emitted x-rays correspond to characteristic energy levels, allowing elemental identification. EDS analysis can also provide semi-quantitative elemental information using standards or standard-less analysis. A standardless analysis quantifies the elements by calculating the area under the peak of each identified element, and then performs calculations to convert the area under the peak into weight or atomic percent. It is also possible to map the elements in a sample. The locations of various elements are identified using color coated dots. Figure 2.14 is an example of an elemental map for scale removed from a pipeline. Figure 2.15 and Figure 2.16 are the associated EDS spectra and quantitative results for analyses performed on areas 1, 2, and 3 identified on Figure 2.14. The location of various elements in relation to one another can indicate the underlying chemistry. For example, the presence of iron and sulfur at the same location in the absence of oxygen would be indicative of iron sulfide. EDS can also be used to determine regional variations on a corrosion sample (e.g., a pipe sample containing a pit). The size of the sample will be dictated by the size of the SEM chamber.

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Figure 2.14 SEM Image Showing Elemental Mapping of Scale Removed From a Pipe 140

cps/eV

120 100 80

Ca

O

60 40 C 20

Fe 0

S

Na Mg 1

Cl

2

Mn 3

keV

4

5

Fe

6

7

Figure 2.15 Three Superimposed EDS Spectra Collected From Scale Sample Shown in Figure 2.14 Individual Spectrums Are Color Coded (Spectrum 1 – Blue, Spectrum 2 – Green, and Spectrum 3 – Brown)

Spectrum

C

O

Na

Mg

S

Cl

Ca

Mn

Fe

1

8.57

53.03

–

0.26

0.36

0.25

31.21

–

6.32

2

7.28

47.75

0.97

0.51

0.63

2.03

3.89

–

36.9

3

3.11

24.09

–

–

–

–

0.46

1.02

71.31

Figure 2.16 Quantitative Results for Spectrum 1, 2, and 3 from Figure 2.15. Refer to Figure 2.14 for Sampling Locations

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EDS is more commonly used than x-ray fluorescence spectrometry (XRF) to identify elemental compositions. Hydrocarbons cannot be analyzed using EDS and, if present, they must be removed from the sample prior to analysis. 2.2.4.4.4 X-ray Fluorescence (XRF) Wavelength-dispersive x-ray fluorescence spectrometry (XRF) is a non-destructive analytical technique used to identify and determine the concentrations of the elements present in solids, powders, and some liquids. XRF is capable of measuring all elements from beryllium (atomic number 4) to uranium (atomic number 92). XRF operates by irradiating a sample with high energy primary xray photons and measuring the resultant emission of secondary xray photons (fluorescence). For each element, the emitted electrons correspond to characteristic energy levels, allowing elemental identification. The number of photons emitted (emission intensity) is proportional to the concentration of the responsible element in a sample. XRF analysis is comparable to EDS systems equipped with software that allows for quantitative analyses. Similar to EDS, XRD is necessary to provide compound identification. XRF is less commonly used than EDS or XRD. 2.2.4.4.5 X-ray Diffraction (XRD) XRD makes a qualitative determination of the crystalline compounds, known as ‘phases,’ present in solid materials recovered from pipelines. Qualitative analyses identify the type of constituents present but not the amount. These are identified by comparing the x-ray diffraction pattern of an unknown sample with an internationally recognized database of reference patterns. Modern computer-controlled diffractometer systems use automatic routines to measure, record, and interpret the unique patterns produced by individual constituents in even highly complex mixtures. This method can be used on samples as small as a pea (1 cm2). Generally, compounds present in concentrations greater than 5% of the total can be identified. XRD is used when it is necessary to identify specific compounds. For example, EDS or XRF may identify the presence of iron and

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sulfur in a sample. These elements may be present as iron sulfide, but it is possible that the sulfur could be elemental or part of a sulfate compound. In this example, XRD would confirm the presence of iron sulfide. XRD analysis cannot be used to determine the composition of amorphous (non-crystalline) or organic materials. It is critical to preserve the sample so that oxygen exposure is minimized. Oxygen could react with the iron to form iron oxides that were not present in the pipeline.

2.2.4.5 Microbiological Monitoring Microbiological monitoring involves identification and enumeration of the bacterial populations and/or measurement of the chemical and physical parameters that indicate elevated bacterial activity. Bacterial sampling involves sampling the water phase and deposits at various locations to enumerate the planktonic and sessile bacteria. It is important to note that detecting bacteria within a sample does not mean microbiologically influenced corrosion (MIC) has occurred. Microbiological monitoring should not be taken as an independent diagnosis, but rather as a tool for trending microbiological activity. Advantages •

Can be used to identify and quantify bacterial populations

•

Measurements of sessile bacteria can indicate potential for MIC

•

Measurements can indicate the effectiveness of biocide treatments

Limitations •

Requires exposure of personnel to pipeline environment

•

Improper sampling and preservation will affect results

•

Presence of bacteria does not mean MIC is occurring

•

Culture techniques are slow, requiring up to 28 days for analysis

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2.2.4.5.1 Sample Collection Samples, both liquid and solid, collected for bacterial testing should be collected using sterile instruments and containers. To further avoid sample contamination, those collecting the samples should wear latex gloves. Since samples can change over time and biological parameters can be affected during sample collection and handling, on-site testing should be done without delay in order to properly assess system conditions. When on-site testing is not possible, preserve the samples by refrigeration if testing is delayed more than 4 hours. 2.2.4.5.1.1 Planktonic Sampling Planktonic sampling is used as a diagnostic tool to trend microbiological activity. To properly trend microbiological activity, take an initial baseline sampling of the system. Communicate clearly with field operators to ensure that baseline sampling takes place during normal operations and not during process excursions. Excursions that can affect baseline data include pigging, shut-ins, biocide treatments, etc. It is essential to note that natural planktonic bacterial populations fluctuate and the repeatability of testing is 1-2 orders of magnitude. Therefore, multiple samples per occasion are typically necessary. To establish natural variations in bacteria numbers, samples should be taken over an extended period of time (days, months) to establish a baseline. 2.2.4.5.1.2 Sessile Sampling In terms of corrosion, attached microbes (sessile bacteria) are more important than planktonic bacteria. Since sessile bacteria are in intimate contact with system components, they can directly influence corrosion. Any removable field system component can potentially be used to sample for sessile bacteria (e.g., corrosion coupons and removed pipe sections). Removed pipe sections cannot always be sampled immediately for sessile bacteria which may affect sample results. Devices, such as the Robbins device (see Figure 2.17), can also be used to collect sessile bacteria samples. Sampling devices must be located such that they are representative of sessile bacterial growth.

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Figure 2.17 Robbins Device

2.2.4.5.2 Liquid Culture Media Liquid culture media testing done using the serial dilution method is the most common field test used to enumerate broad classes of viable bacteria. A variety of liquid media culture test kits are commercially available with formulations specific to oil and gas industry needs. The most widely used standard liquid culture media are specifically formulated to grow: •

General Heterotrophic Bacteria (Aerobic and Facultative Anaerobic Bacteria)

•

Anaerobic Heterotrophic Bacteria

•

Acid Producing Heterotrophic Bacteria

•

Sulfate Reducing Bacteria

•

Nitrate Reducing Bacteria

•

Iron Related Bacteria

The serial dilution technique uses a series of sealed vials that each contain 9 mL of sterilized nutrient media for growing bacteria. The first media vial is inoculated with 1 mL of the field sample. After thorough mixing, 1 mL is withdrawn from the first vial and added to the second vial. This sequential dilution process is repeated with the remaining vials in the series. This method results in the original sample being diluted by a factor of ten in each successive vial, from which the approximate number of viable cells in the sample is estimated. A total of five to eight media vials are usually sufficient to enumerate bacteria. The complete series of media vials is

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incubated for seven days (aerobic and facultative anaerobic bacteria) or 14 to 28 days (SRB), depending on the type of media. Following the incubation period, the number of positive vials provide an estimate of the number of bacteria in the original sample. For statistical validity, this test can be done with replicates and the population estimate derived from a statistical table. It should be noted that serial dilution testing has the following limitations: 1. Any culture medium grows only those bacteria able to use the nutrients provided. 2. Culture medium conditions (pH, osmostic balance, redox potential) prevent the growth of some bacteria and enhance the growth of others. 3. Conditions induced by sampling and culturing procedures, such as exposure to oxygen, may hamper the growth of strict anarobes. 4. Only a small percentage of the viable bacteria in a sample can be recovered by any single medium (i.e., culture media methods may underestimate the number of bacteria in a sample. 5. Some bacteria cannot be grown in culture media at all. The proper incubation temperature is essential to grow bacteria removed from the field system. Therefore, the incubation temperature should be within + 5oC (+ 9oF) of the typical operating temperature of the system. Because oilfield bacteria can grow in produced fluids at temperatures of 80oC (176oF) or higher, special incubation procedures may be required for high-temperature fluids. Common problems associated interpretation include:

with

liquid

culture

media

1. No detectable growth in the first vial, but detectable growth in subsequent vials 2. Gaps between sequential positive vials Problem 1 is often related to the presence of treatment chemicals. Residual biocide, inhibitor, methanol or other chemicals in the sample can inhibit bacterial growth. However, as the sample

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becomes sequentially more diluted, the treatment chemicals are removed, thus, any viable bacteria may thrive in successive bottles. Problem 2 may have several possible explanations including: •

Accidental contamination (i.e., via the syringe)

•

Bacteria in the non-detected vial may not have survived or thrived in the environment

•

Any viable bacteria introduced into the non-detected vial may have been transferred during subsequent dilution

Assessments of sulfate reducing bacteria (SRB) vials may also be inaccurate when a sample contains H2S. In such a situation, the first inoculated vial may turn positive instantaneously. This result, however, is due to excessive H2S levels and not due to SRBs. If succeeding vials do not turn after 28 days of incubation, then the vial most likely does not correspond to bacterial growth. It is imperative that the investigator note any immediate changes observed during serial dilution. Advantages •

Most commonly used technique

•

Does not require a skilled operator to perform the inoculation

•

Possible to discriminate between different classifications of bacteria (SRB vs. APB)

Limitations •

Requires exposure of personnel to pipeline environment

•

Improper sampling and incubation will affect results

•

No single media can be used for all bacteria

•

The presence of chemicals from mitigation treatments may affect results

2.2.4.5.3 Adenosine Triphosphate (ATP) Photometry Adenosine triphosphate (ATP) is present in all living cells. Therefore, the quantity of ATP in field samples is approximately proportional to the number of living bacteria in a sample. Several

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commercial kits are available for ATP quantification. When cells die, however, ATP rapidly degrades. Quantification of ATP relies upon photometers that measure the amount of light emitted when the ATP in the sample is allowed to react with an enzyme. Prior to the reaction, the sample is filtered and treated with gold buffers. These buffers assist in releasing the ATP from the organisms. It is important to note that ATP testing should only be considered as an estimation of bacterial numbers in a sample. The minimum detection limit using ATP photometry is 1,000 organisms/mL. Advantages •

Testing is rapid and fairly easy to perform

•

Test is sensitive to bacterial numbers as low as 1,000 organisms/ mL

Limitations •

Subject to interference from chemicals (e.g., biocides, H2S, oxygen scavengers)

•

Does not discriminate between classifications of bacteria (SRB vs. APB)

2.2.4.5.4 Hydrogenase Measurements Hydrogenase is an enzyme produced by bacteria that use hydrogen as an energy source. Testing for the presence of the hydrogenase is one technique utilized to enumerate bacteria populations in samples. Quantification of bacteria populations using this method first involves adding an enzyme extracting solution to the sample. The extracted hydrogenase is preserved in a solution that maintains enzyme activity and then placed in a reaction chamber where hydrogen is introduced. The hydrogen oxidation is identified using a color indicator (refer to NACE TM0194). The reaction can take anywhere from 30 minutes to 4 hours. The reaction time and developed color intensity together are used to measure the relative activity of the enzyme.

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Advantages •

Testing is fairly simple to perform

•

Detects wide range of organisms

•

Can be used on both water and deposit samples

Limitations •

Subject to interference from slimes formed by bacteria

•

Does not discriminate between classifications of bacteria

2.2.4.5.5 Fluorescence Microscopy Fluorescence microscopy is a direct enumeration laboratory technique that involves visually counting the number of bacteria in a sample using a specialized microscope. Bacteria samples are placed in a formalin solution that “fixes” or kills bacteria. The samples are then stained using a dye, e.g., fluorescein isothiocyanate (FITC), that fluoresces when irradiated with ultraviolet light. Using an epifluorescence microscope, a skilled analyst counts the total number of bacterial cells in a known volume of the sample. As with ATP photometry, this technique does not distinguish between bacteria types. While most of the fluorescent dyes do not clearly distinguish between living and dead cells, recent advances in fluorescent stains often enable direct enumeration of living and dead cells. Since hydrocarbons also fluoresce under the ultraviolet light, oilfield samples are often difficult to examine using this technique. (see Figure 2.18). The minimum detection limit using fluorescence microscopy is 1,000 organisms/mL. It is possible to characterize the shape of bacteria (e.g., rods).

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Figure 2.18 Optical Photomicrograph Showing Bacteria Viewed Under Ultraviolet Light. Green Cells Detected With a Florescent Stain (FITC)

Advantages •

Detects wide range of organisms

•

Test is sensitive to bacterial numbers as low as 1,000 organisms/ mL

Limitations •

Does not discriminate between classifications of bacteria (SRB vs. APB)

•

Does not distinguish between living and dead organisms

•

Requires skilled technician

•

Some hydrocarbon samples may be difficult to analyze

2.2.4.5.6 Adenosine Phosphosulfate (APS) Reductase APS reductase is an enzyme specifically associated with sulfate reducing bacteria (SRB). Measurement of the APS reductase provides an indication of the viable SRB concentration.

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Detection and measurement are based on immunological methods and can be performed using a simple field kit. The test involves exposure of the sample to small particles containing antibodies. These particles specifically capture the APS reductase enzyme. The particles, now mixed with APS reductase, are subsequently isolated on a porous membrane and exposed to specific indicator chemicals. Reaction between the particles and chemicals result in a color change that is proportional to the concentration of the APS reductase in the sample. It is important to note that APS reductase testing should only be considered as an estimation of the number of SRB present in a sample. The test does not detect bacteria other than SRB. The test is used on liquid samples and special techniques are used to analyze solid samples. Advantages •

Specific to SRB

•

Simple test to perform

•

Disposable field test kits available for rapid detection

•

Does not require specialized training

Limitations •

Does not detect bacteria other than SRB

•

Freshly killed bacteria may still react with APS reductase

•

Method is several orders of magnitude less sensitive than culture techniques

•

Special techniques necessary to handle deposits and corrosion products

•

Test kits have short shelf lives, especially in warm climates

2.2.4.6 Monitoring Technique Selection A summary table of the monitoring techniques is presented in Table 2.3.

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Corrosion coupons are the most commonly used monitoring technique. An alternative technique may be preferred if one or more of the following situations exist. 2.2.4.6.1 Real Time Monitoring Required If monitoring is required to detect short upsets or changes in corrosion rate (i.e., real time monitoring), ER probes, LPR probes, or ECN may be used. Examples of situations where real time monitoring may be required include: •

Testing new chemical treatments

•

Systems where highly corrosive liquids may be present for short periods of time

•

Operating conditions change on a frequent basis

ER probes can be used in any environment. LPR and ECN probes require a continuous aqueous environment and are susceptible to hydrocarbon fouling. 2.2.4.6.2 Environmentally Assisted Cracking (EAC) Expected If EAC is identified as a potential form of corrosion, hydrogen probes or hydrogen patch probes may be used. If direct access to the internal pipe environment is not possible, non-intrusive hydrogen patch probes may be used. 2.2.4.6.3 Intrusive Monitoring is Not Possible When access to the internal pipeline environment is difficult or unfeasible, electrical field mapping (EFM) or permanent ultrasonic testing (UT) probes may be used. This may be necessary to monitor buried locations. 2.2.4.6.4 Flow Assisted Damage is Expected When flow assisted damage (e.g., erosion) is occurring on a line, ER probes with corrosion resistant alloy (CRA) sensors, angled (45º) ER probes, or acoustic solid monitoring may be used. Acoustic solid monitoring can be used where access to the internal pipeline environments is difficult or unfeasible.

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2.2.4.6.5 Complimentary Testing Gas, liquid, and solid analysis (including bacteria testing) should be used as complimentary techniques and not used as stand alone methods. Table 2.3: Summary of Monitoring Techniques and Their Applications

Corrosion

Localized Corrosion

Environmentally Assisted Cracking Flow Assisted Damage

Crude Oil / Multiphase Crude Oil Coupons Coupons Spool piece Spool piece ER probe ER probe UT UT EFM EFM Gas + Liquid*

Water Coupons Spool piece ER probe LPR probe ECN UT EFM Coupons Spool piece UT** ECN EFM Hydrogen probes & patches Coupons ER erosion probes Acoustic emission monitoring

Gas + Water

Coupons Spool piece UT* EFM

Coupons Spool piece UT* EFM

Hydrogen probes & patches

Hydrogen probes & patches

Coupons Spool piece ER probe LPR probe ECN UT EFM Coupons Spool piece ECN UT* EFM Hydrogen probes & patches

Coupons ER erosion probes Acoustic emission monitoring

Coupon ER erosion probes Acoustic emission monitoring

Coupon ER erosion probes Acoustic emission monitoring

* Where condensate or other crude oil may be present ** If localized corrosion is occurring, the wall loss/corrosion rate from pitting will be measured; however, the technique will not distinguish whether the damage is localized or general.

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2.3 Inspection Methods Inspection methods are used to detect and evaluate damaged areas. Inspection techniques provide information on the extent of corrosion damage. However, they do not provide information on the time period over which the corrosion occurred. When inspection methods are performed at regular intervals, they can be used as a monitoring technique.

2.3.1 Selection of Representative Inspection Locations Inspections can provide information about the presence and extent of corrosion damage at a specific location. Therefore, the selection of representative locations for corrosion inspection is essential to collecting data that provides meaningful information. Proper selection requires knowledge of the internal environment and the system design. Inspection locations should be selected that represent locations where corrosion is expected to be: 1. The most severe 2. Representative of the pipeline Examples of locations where corrosion is expected to be the most severe include low spots, drips and stagnant areas (e.g., dead legs); drips are not typically selected for inspection as they are difficult to inspect. The locations of low spots can be determined by creating pipeline elevation profiles as described in the internal corrosion direct assessment section below. Low spots can also be determined based on knowledge of the pipeline terrain or as-built drawings. Inspection at multiple locations may be necessary to gain a more thorough understanding of the extent of the corrosion damage. For instance, if multiple flow regimes are expected, inspections should be performed in areas of each flow regime.

2.3.2 Visual Inspection Visual inspection is often used to detect surface corrosion and pitting on an exposed pipe/vessel. While visual inspection and measurement of corrosion damage is desirable, it is frequently not

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possible without a system shutdown. In some instances it may be possible to use borescopes or video cameras inserted in the pipeline without shutting down the system. Since corrosion involves the interaction between a material and its environment, it is essential that the environmental conditions at and surrounding the corrosion site be accurately and thoroughly documented. This information, when combined with field and laboratory testing, will assist the inspector to determine the cause of the corrosion. Any time a pipe or vessel is removed from service, a visual inspection of the internal surfaces for evidence of corrosion should be conducted. The inspection may involve the use of devices such as borescopes or video cameras in remote areas or areas inaccessible to the naked eye. As visual evidence may change with time, it is imperative that a visual inspection be conducted as soon as possible. At a minimum, the inspection should include written and photographic documentation, sketches, and simple measurements. The reliability of the information gathered during any visual inspection is dependent on the skill of the inspector. The inspector should be thorough, identifying all critical flaws, and recognizing all areas where failure could occur. A proper visual inspection will not disturb or alter the sample (i.e., probing, cleaning) as this can remove or compromise valuable information. Similarly, if the inspector finds evidence that the pipe/vessel was cleaned or altered prior to his/her examination, this should be noted. When utilized correctly, this method may be the most informative technique at an investigators disposal. When documenting internal corrosion features, the investigator should attempt to identify the following parameters for each feature: •

Location of the corrosion (both physical and in relation to other features)

•

Form of the corrosion damage

•

Severity of the damage

•

Pipe/vessel internal conditions at the time of inspection

Documentation of the physical location associated with a corrosion feature should include the circumferential position in the pipe, the

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external climate/environment to which the pipe is exposed and for how long, and the pipe orientation (i.e., vertical or horizontal). Together, this documentation should provide insight into the operating conditions, internal pipe temperature, and potential for solid/liquid accumulation. Each identified corrosion feature should also be related to the location of any distinct feature associated with the particular line or system. These facets include: •

System designs (drips, dead legs, valves, etc.)

•

Pipeline elevations

•

Girth welds, mechanical joints, or longitudinal welds

•

Areas of directional flow changes

•

Sources of corrosive materials (i.e., inlets, outlets, taps, fittings)

•

Heat sources or temperature changes

•

Historical liquid levels

•

Deposits, coatings, debris, nodules, scale, or biological materials (i.e., slimes or biomass)

•

Chemical injection equipment

•

Processing equipment

•

Construction/materials changes

•

Pipe mill defects

Again, this documentation may provide insight into whether the location promotes accumulation of solids/liquids due to low flow or stagnant conditions, abrupt changes in flow patterns, and/or the formation of crevices, galvanic and/or turbulent conditions. Additionally, the documentation may provide insight into possible sources of corrosive species and operating parameters that tend to accelerate corrosion attack. The form of corrosion damage is also essential to document. This assessment involves identifying the manifestation of the corrosion damage and should not be confused with determination of a corrosion mechanism. Forms of corrosion include: •

Pitting

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•

General/uniform corrosion

•

Crevice corrosion

•

Flow-assisted damage

•

Environmentally assisted cracking

When documenting corrosion forms identified during an inspection, the inspector should also note whether the form was isolated or associated with other forms of corrosion (e.g., isolated pit(s) vs. isolated pit(s) in areas of general corrosion). Documenting the severity of any identified corrosion features is also essential. Assessment of corrosion severities should address: •

Longitudinal and circumferential damage extents

•

Maximum wall loss

•

Profile wall loss

•

Maximum/average pit depths

•

Maximum/average pit diameters

•

Pit lengths vs. pit widths

•

Depth/diameter ratio

This documentation is critical to evaluating the integrity of the pipe/ vessel and determining the component’s fitness for service. Finally, the internal conditions of the pipe or vessel should be documented. Conditions of interest include: •

Whether the environment is wet or dry

•

Presence of debris, scale, or deposits

•

Color of any debris, scale, or deposits present

•

Smell of the environment

Advantages •

Potentially large areas of pipe can be inspected for the presence of internal corrosion

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•

The scale of the inspection is dependent upon accessibility and line of visibility

•

Potential to accurately measure pit depths, when accessible, using a pit gauge

•

Areas of pitting or corrosion can be associated with the presence of solids, scale or liquids

Limitations •

Surface should be cleaned in order to fully determine extent of corrosion

•

Often requires shut down of pipeline

•

May require the removal and replacement of a section of pipe

•

Area may not be accessible for direct inspection

•

Sensitivity of technique limited to surface corrosion evaluation

2.3.3 Magnetic Flux Leakage Magnetic flux leakage (MFL) uses permanent magnets and sensor coils to identify corrosion in a pipeline. The permanent magnets are used to induce a magnetic field on the pipe and the sensor coils detect “leaks” (or disturbances) in the resulting field. The “leaks” in the magnetic field result from defects in the metal. The amplitude of the leaking field is measured by the sensor coils and compared to known defects to predict/infer wall losses. MFL methods are used for in-line inspection tools which will be discussed further in the assessment section. Advantages •

Can be used to detect volumetric wall losses

•

Can inspect long sections of pipe relatively quickly

•

Inspection devices are portable

Limitations •

Requires exposure of personnel to pipeline environment

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•

The presence of rust, scales, and heavily corroded surfaces can reduce the accuracy of the measurements

•

MFL provides an inferred wall thickness measurement

•

Seamless pipe can produce more noise due to wall thickness variations

2.3.4 Ultrasonic Testing (UT) Ultrasonic testing is used to detect cracks, wall thinning, and pitting associated with corrosion. The method uses a highly sensitive probe to transmit ultrasonic waves through the object being inspected. A high frequency ultrasonic sound wave enters the material and travels to the back wall of the material. The wave then reflects off the back wall and returns to the transducer. The reflected waves are picked up by the sensing probe and are interpreted in terms of thickness of the pipe and types of defects. Angle beam or shear wave transducers are used to detect cracks. Variations in temperature of the pipe wall and erroneous sound reflections can adversely affect results. Surface preparation of the pipe and proper coupling is also important. Manual, automated, and guided wave UT inspections are discussed in the following sections. The use of fixed permanent transducers is discussed in Section 2.2.3.2 Permanently Mounted UT Probes. UT methods are used for in-line inspection tools, which will be discussed further in the assessment section.

2.3.4.1 Manual UT Various types of probes can be used for manual UT inspection. Several frequencies and diameters are available. The frequency affects the sound transmission characteristics and proper selection improves echo strength. Probe diameters are generally between 10 and 25 mm. Smaller probe diameters have higher signal attenuation and lower penetration power versus larger probe diameters. Proper selection of the probe improves the probability of finding localized corrosion. Two types of probes used are the twin crystal probe and the single crystal probe. The twin crystal probe is used when additional signal strength is needed to overcome the loss of signal strength caused by surface roughness scattering the sound energy.

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Manual UT can involve individual spot measurements or B-scan techniques. Figure 2.19 shows field personnel performing a manual UT inspection on a pipe. B-scan is a presentation of UT data where the time-of-flight diffraction (TFD) is displayed on the vertical axis and the longitudinal position of the transducer is displayed on the horizontal axis. Grids may be drawn on the pipe as a guide for individual spot measurements. Since wall thickness measurements are only known where spot measurements are performed, the grid spacing along with probe diameter will dictate the maximum diameter of localized corrosion that may remain undetected by the inspection.

Figure 2.19 Field Personnel Performing Manual UT Inspection

Advantages •

Allows numerous thickness measurements to be performed over a short period of time

•

Direct measurement of remaining wall thickness

Limitations •

Results may be dependent upon the inspector

•

Adversely affected by variations in temperature of the pipe wall and by erroneous sound reflections

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•

The presence of rust, scales, and heavily corroded surfaces can reduce the accuracy of the measurements

•

Surface area inspected with each UT measurement is relatively small, limiting monitoring to a very local area

•

The use of manual spot measurements can be time intensive for large inspection areas

2.3.4.1.1 Automated UT (AUT) AUT involves use of a multi-channel imaging system and a 2 axis robotic scanner in order to perform ultrasonic mapping. The data is provided in either a B-scan presentation or a C-scan presentation. A C-scan shows a plane type view of the location and size of detected anomalies. Figure 2.20 shows an AUT device on a pipe. Advantages •

Allows inspection of a large area over a short period of time (vs. manual UT)

•

Direct measurement of remaining wall thickness

Limitations •

Adversely affected by variations in temperature of the pipe wall and by erroneous sound reflections

•

The presence of rust, scales, and heavily corroded surfaces can reduce the accuracy of the measurements

Figure 2.20 AUT Device on a Pipe

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2.3.4.2 Guided Wave Ultrasonic Testing Technology (GWUT) GWUT sends waves longitudinally down the length of the pipe. The waves are reflected back from features such as corrosion, welds, etc. The reach of the sound wave depends on the type of fluid in the pipeline, the type of coating, and whether the line is buried. The waves are transmitted and received using a collar of transducers that is placed around the pipe. Waves are typically transmitted in both directions from the collar. Figure 2.21 shows a GWUT collar on a pipe in the field. Peaks or spikes in the received signal are used to determine where corrosion may be present. The amplitude of these signals can be used to estimate the percentage of the cross-sectional area that has been lost. The estimated percentage of area loss is divided by the pipe circumference over which the corrosion is expected to have occurred in order to estimate a percent depth. The signal does not differentiate between internal and external defects. Reflections from welds and other features at known distances from the collar are used to calibrate the axial length at which signal amplitudes are observed. Locations where corrosion defects are identified using GWUT, AUT or manual UT can be used to measure the extent of the corrosion (i.e., size and depth).

Advantages •

Can inspect a long length of pipe from a single location

•

Allows for inspection of inaccessible areas

Limitations •

Does not quantify the amount of damage

•

Cannot distinguish between internal and external metal loss

•

Cannot identify small areas of localized corrosion or pitting

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Figure 2.21 GWUT Collar on Pipe

2.3.5 Eddy Current (EC) Eddy current uses an alternating magnetic field to induce a circulating electrical current. Eddy current requires a signal generator and a probe containing a coil. Defects are identified by a change in the balance between the electrical fields in the generator and the sensing coil. The signal can be analyzed in real-time or post inspection. Defects that can be detected include: •

Pitting

•

General corrosion

•

Erosion

•

Cracks

Eddy current can only be used on conductive materials. The sensitivity of the technique decreases with depth into the material. Eddy current is not sensitive to defects in magnetic material (e.g., carbon steel) because the magnetic permeability limits the depth of penetration of the eddy currents. An external magnetic field can be applied by the probe to suppress the magnetic characteristics and allow examination. Robotic probes can be used to inspect areas that are difficult to access. Advantages •

Can detect a wide variety of defects

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•

Can be used in areas that are difficult to access

•

Results can be analyzed on-site

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Limitations •

Not sensitive to internal surface defects for carbon pipe without applying an external magnetic field

•

Not sensitive to thick wall pipe

2.3.6 Radiographic Testing (RT) Radiographic testing (RT) uses ionizing radiation produced from machines or chemical substances (isotopes) that emit “X” or gamma rays which are directed through components to create an image (radiograph) on film or digital media. Like medical x-rays, industrial radiography shows changes in density and component geometry. Thin areas or voids in material are indicated by darker areas because more energy is able to penetrate the piece during the exposure period; thicker or denser areas are indicated by lighter areas because less energy was able to penetrate the piece during the exposure. Figure 2.22 is a radiographic image showing areas (dark regions) of metal loss near a weld.

Figure 2.22 Radiographic Image Showing Areas of Metal Loss (darker regions)

Optical film densities corresponding to non-corroded areas of the pipe or equipment will differ from those associated with pitting.

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Absolute thickness of inspected objects is not normally discernable in a radiographic image. From differential optical density of the film, a difference in thickness can be calculated. However, the remaining wall thickness may be assumed based on other information, such as the nominal wall thickness of piping. A reference marker can also be included in the image to measure thickness. Scale or other debris in the area of corrosion can significantly affect the accuracy of the calculated pit depths. Radiographic testing is particularly useful for inspecting welds and complex pipe geometries where UT would prove difficult. Radiographic testing is not well suited for liquid lines. Unless the diameter of a liquid pipeline is small (< 102 mm [4 in]), the volume of liquid will prohibit clear radiographic images. Digital radiography is also available. This method uses digital gamma ray sensors and requires less radiation and no chemical processing to produce digital images. The data can be stored electronically and inspections performed at various times can be superimposed.

Advantages •

Useful for inspection of welds and complex geometries

•

Can identify both internal and external defects

•

Digital radiography provides digital records

Limitations •

Health, Safety, and Environmental (HSE) concern because of exposure to radiation (gamma/x-rays)

•

Difficult to perform for liquid lines

•

Absolute thickness of inspected object is not normally discernable from the radiographic image

•

Scale or other debris in the area of corrosion can significantly affect the accuracy of the calculated pit depths

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2.3.7 Inspection Method Selection A summary of the inspection methods is presented in Table 2.4 Selection of an appropriate inspection method can be determined based on the topics discussed below. Magnetic flux leakage (MFL) will be discussed with in-line inspection (ILI) in the assessment method selection section.

2.3.7.1 Wall Thickness Measurements Manual UT or AUT should be selected as the inspection method if detailed wall thickness measurements are required or desired. AUT equipment is typically more expensive than manual UT, however, manual UT is more labor intensive. Extended areas of corrosion may, therefore, result in AUT being more economical.

2.3.7.2 Screening Tool/Quick Inspection RT, GWUT, or EC can be used as screening tools to quickly identify where damage exists. GWUT inspects the largest area in a set period of time and it can be used to inspect inaccessible areas (e.g., stream crossings), however, the technique does not distinguish between internal and external defects. RT is the most reliable of the three methods, although it has limited applicability for liquid pipelines. Eddy current has limited use on magnetic surfaces.

2.3.7.3 Detection of Internal Cracking RT, EC, or angle beam UT can be used to inspect for internal cracking. Angle beam UT is the more commonly used method. EAC can be difficult to detect with RT. Limitations of the techniques have already been discussed.

2.3.7.4 Pipeline Replacement / Internal Surface Exposed Visual inspection is the easiest and most reliable method when pipe replacements occur or the internal surface of the pipe is exposed.

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Table 2.4: Inspection Methods Comparison

*

For exposed internal surfaces

2.4 Assessments 2.4.1 Direct Assessment Methodology The direct assessment methodology has been developed for the threats of external corrosion, internal corrosion, and stress corrosion cracking. The direct assessment methodology is comprised of four steps: 1. Pre-Assessment 2. Indirect Inspection 3. Direct/Detailed Examination 4. Post Assessment NACE International currently has standard practices published for: •

ECDA (NACE SP0502)

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•

DG-ICDA (NACE SP0206

•

LP-ICDA (NACE SP0208)

•

SCCDA (NACE SP0204)

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The methodology for wet gas ICDA (WG-ICDA) is currently being developed by a NACE task group. Each of these methods relies on data integration and indirect inspection results to select locations for examination where corrosion is most likely to exist.

2.4.1.1 Dry Gas ICDA Methodology Dry Gas Internal Corrosion Direct Assessment is applicable to pipelines that transport gas that is normally dry, but may suffer infrequent upsets, which may introduce water to the pipeline. Dry gas is defined as gas that is above its dewpoint and does not normally contain liquids. The methodology is based on looking for areas where water may accumulate, as these are the locations where corrosion is most likely to occur. 2.4.1.1.1 Pre-Assessment The purpose of the Pre-Assessment step is to collect data regarding the pipeline that is being assessed, to determine if DG-ICDA is feasible for the pipeline that is to be evaluated, and to identify DGICDA regions. The goal is to understand the likely corrosion mechanism(s) for the pipeline being analyzed and a basis to identify susceptible locations. Feasibility assessment and region identification is supported by data collection. Data are collected regarding: •

Pipe specifications

•

Pipe construction

•

Topography

•

Operations and maintenance

•

Corrosion monitoring

•

Inspection and repair history

NACE SP0206 identifies data elements that are essential to performed DG-ICDA (see Table 2.5). Additional data may be required by government regulations, or company procedures.

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Table 2.5: Essential Data for DG-ICDA per NACE SP0206 Category

Data to Collect

Operating history?

Change in gas flow direction, type of service, removed taps, year of installation, etc. Has the line ever been used previously for crude oil or other liquid products?

Defined length

Length between inputs/outputs.

Elevation profile

Topographical data (e.g., USGS data), including consideration of pipeline depth of cover. Take care in instrument selection that sufficient accuracy and precision may be achieved.

Features with inclination

Roads, rivers, drains, valves, drips, etc.

Diameter and wall thickness

Nominal pipe diameter and wall thickness.

Pressure

Typical minimum and maximum operating pressures.

Flow rate

Flow rates—maximum and minimum flow rates at minimum and maximum operating pressures for all inlets and outlets. Significant periods of low/ no flow.

Temperature

For example, ambient soil temperature up to 54 ˚C (130 ˚F) at compressor discharge unless a special environment exists (e.g., river crossing, aerial pipeline).

Water vapor

Information about water vapor dew point.

Inputs/outputs

Must identify all locations of current and historic inputs and outputs to the pipeline.

Corrosion inhibitor

Information about injection, chemical type, and dose.

Upsets

Frequency, nature of upset (intermittent or chronic), volume if known, and nature of liquid.

Type of dehydration

Is dehydration carried out using glycols (yes/ no)?

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Table 2.5: Essential Data for DG-ICDA per NACE SP0206 Category

Data to Collect

Hydrotest information

Past presence of water, hydrotest water quality data.

Repair/maintenance data

Presence of solids, anomalies; pipe section repair and replacement; prior inspections; NDE data. Any cleaning pig locations, frequencies, and dates. Analytical data of all removed sludge, liquids when cleaning pigs were employed or from liquid separators, hydrators, etc. and the analysis performed to determine the chemical properties and corrosion severity, including the presence of bacteria, of the removed products.

Leaks/failures

Locations and nature of leaks/ failures.

Gas quality

Gas and liquid analyses, and any bacteria testing results for the pipeline and on shipper and delivery laterals. Relationship of gas analyses to pipe location.

Corrosion monitoring

Corrosion monitoring data including type of monitoring [e.g., coupons, electric resistance (ER)/linear polarization resistance (LPR) probes], dates and relationship of monitoring to pipe location, corrosion rate recorded/ calculated, and accuracy of data. Any available non-destructive inspection results.

Flow coatings

Existence and location(s) of internal coatings.

Other internal corrosion data

As defined by the pipeline operator.

According to NACE SP0206, the following conditions are required in order to perform DG-ICDA: •

Liquids, including glycols, are not normally present in the pipeline.

•

The pipeline has not been converted from a service for which DG-ICDA is not applicable (transportation of crude oil or products) unless it is shown that internal corrosion did not occur in the previous service, or if previous damage has been assessed separately.

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•

The pipe does not have a continuous internal coating that provides protection from corrosion. The internal coating may either be applied at the pipe mill, during construction, or after commencement of operation through the use of a pig. Internal coatings designed to improve flow efficiency are not considered protective coatings. If a discontinuous internal coating is present, examinations shall be performed at non-protective locations.

•

The pipe does not have a history of top of the line corrosion (i.e. corrosion caused by condensing water).

•

The use of corrosion inhibitor may prevent the use of DG-ICDA because the inhibitor may not have been uniformly effective along the length of the pipeline. Data that has been collected are considered when determining whether the use of corrosion inhibitors precludes the application of DG-ICDA. While the use of a scale inhibitor or biocide does not specifically preclude the use of DG-ICDA (according to SP0206), these chemicals may also impact the distribution of corrosion if they are not uniformly effective. An engineering analysis can be performed to determine whether the use of chemical treatment has affected the distribution of corrosion in the pipeline.

•

The pipeline has not been pigged. Pigging can affect the distribution of liquids and solids on the pipeline and may result in areas of internal corrosion that cannot be predicted by DG-ICDA. Technical justification is required in order for DG-ICDA to be performed on pipelines that have been pigged.

•

The pipeline should not have accumulations of solids, sludge, biofilm or biomass, or scale. If accumulations of solids, sludge, biofilm or biomass, or scale are present, the impact of these materials on internal corrosion is considered prior to performing DG-ICDA. The presence of solids, sludge and scale may affect the validity of the DG-ICDA process by:

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•

Increasing corrosion by retaining water inside a porous matrix or under a solid layer

•

Increasing corrosion by attracting water through hygroscopic properties or deliquescence

•

Increasing corrosion through the formation of a concentration cell (i.e., under-deposit corrosion)

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•

Decreasing corrosion through the formation of a protective layer

•

Changing corrosion rates due to the influence of bacteria

Accumulations may be identified by the presence of large amounts of solids in upstream filters, separators, etc. An increase in pressure drop may be evidence of the accumulation of solids or deposits. Historical visual inspections of pipe may have identified the presence of solid accumulations. Inspection of downstream locations such as separator filters or orifice plates may also identify the presence of solids. If solids are found downstream, further analysis can be performed to identify whether solids have accumulated within the pipeline. In addition to the conditions listed above, the feasibility assessment considers whether indirect inspection tools (flow modeling) can be used. The critical angle equation contained within NACE SP0206 can be applied to systems with stratified flow. Supporting calculations exist for use of the model for pipelines with a nominal diameter between 0.1 and 1.2 meters (4 and 48 inches) and pressures less than 7.6 MPa (1,100 psi). Technical support or calculations are required to show that this model is valid for pipelines operating outside of these conditions. DG-ICDA regions are identified based on the presence of current and historical inputs. A new region is identified for each current and historical input. If bi-directional flow has ever occurred, each flow direction is considered its own region. The presence of compressor stations, valves, or other equipment that can change the pressure or temperature of the gas is also considered when determining DGICDA regions. New regions are identified any time that the pressure or temperature changes associated with this equipment may result in the introduction of liquid to the pipeline. Figure 2.23 shows two stick drawings depicting region identification, one for a pipeline with two inputs and flow in one direction and the other for a pipeline with bi-directional flow.

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Region 1

Inlet 1

Region 2

Inlet 2

Region 1

Region 2

Inlet 2

Inlet 1

Figure 2.23 Examples of Region Identification

2.4.1.1.2 Indirect Inspection The Indirect Inspection step of DG-ICDA is used to identify locations where internal corrosion is most likely to occur. The process used to select these locations consists of: •

Using multiphase flow modeling to determine critical inclination angles for each region

•

Determining the pipeline elevation and inclination profile for each region

•

Using the critical inclination angles in conjunction with the pipeline elevation and inclination profile to select locations of potential water accumulation for each region.

The following flow modeling equation is used in NACE SP0206 to determine the critical inclination angle. However, any multiphase flow model for small liquid volumes can be used in place of this equation.

 g Vg2   arcsin 0.675      g * d id l g 

1.091

   

[2.10]

Where: θ = ρl = ρg = g =

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critical inclination angle, in degrees density of liquid (water) (1,000 kg/m3 [62.43 lbs/ft3]) density of gas, determined by total pressure and temperature (kg/m3, lbs/ft3) acceleration due to gravity (9.81 m/s2 [32.17 ft/s2])

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did = internal diameter of pipeline (m, ft) linear gas velocity (m/s, ft/s) Vg = The density of water is assumed to be 1000 kg/m3 (62.43 lbs/ft3). The density of the gas is calculated based on the pressure and temperature of the pipeline as shown in the equation below.

g 

P  MW Z  R T

[2.11]

Where: P

=

pressure (kPa, psi)

MW =

molecular weight (16 g/gmol, methane)

Z

=

gas compressibility (unitless)

R

=

universal gas constant (8.314 kPa*m3/kg-mol*K, 10.73 psi*ft3/lb-mol*R)

T

=

temperature (k, ºR)

Values for Z for various operating conditions can be found in texts such as Perry’s Chemical Engineering Handbook and The Properties of Gases and Liquids. Alternatively, Van der Waal’s equation can be used to simulate the behavior of non-ideal gases. The highest calculated critical inclination angle (based on the combination of pressure, temperature and superficial gas velocity) is used in selecting locations for detailed examinations. Both current and historical operating conditions are considered when determining the highest critical inclination angle. As much historical information as available should be considered when identifying the critical angle. The critical angle is not necessarily constant within a region. Local changes in pressure and temperature, or changes in flow rate at delivery points, will affect the critical inclination angle. Therefore, the critical inclination angle is typically plotted versus distance. The pipeline elevation and inclination profile can be created from a variety of data sources. Some examples of data sources include: •

global positioning system (GPS) survey data

•

Light image detection and ranging (LIDAR) data

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•

Digital elevation mapping

•

Transit and level surveys

All of these techniques measure the elevation of the land, not the pipe (if the pipe is buried). For buried pipes, the depth of cover of the pipeline is subtracted from the land elevation in order to determine the pipeline elevation. The pipeline inclination angles are determined by taking the arcsine of the change in pipeline elevation over the change in distance (stationing).

θ  arcsin(

Δelevation ) Δdistance

[2.12]

Locations for detailed examination are selected by overlaying the flow modeling results with the elevation and inclination profiles of the pipeline and determining where the pipeline inclination angle exceeds the critical inclination. The first location where the pipeline inclination angle exceeds the largest critical inclination angle is the first site that is selected for detailed examination. If there are not any locations where the pipeline inclination angle exceeds the largest critical angle (i.e., there are not any locations that meet the condition identified in the previous statement), the largest inclination angle is selected for detailed examination. 2.4.1.1.3 Detailed Examination The Detailed Examination step consists of examining locations based on the results of the Indirect Inspection step for the presence of internal corrosion. The first location selected for detailed examination is the first site where the pipeline inclination angle exceeds the critical angle. The second inspection location is the next site downstream where the pipeline inclination angle exceeds the critical angle. Detailed examinations are continued at downstream locations that exceed the critical angle until two consecutive sites have been found free from internal corrosion. Once two consecutive sites have been determined to be free from internal corrosion, a location where the pipeline inclination angle exceeds the critical angle that is downstream from all of the sites previously examined is inspected as a validation site. Figure 2.24 shows an example of a pipeline inclination profile with critical inclination angle.

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Figure 2.24 Pipeline Elevation and Inclination Profiles Showing Locations Exceeding the Critical Incliation Angle

Detailed examinations are also performed at locations upstream from the first location that exceeds the critical inclination angle in order to account for periods of low flow. If steady flow can be demonstrated for the life of the pipeline, no additional examinations are required. Sub-region n=’0’ is the length of pipe between the beginning of the region and the first location that was examined. The first examination in sub-region n=’0’ is performed at the site with the largest inclination angle within the sub-region. If internal corrosion is not found at this site, a validation examination is performed at the site with the largest inclination angle upstream of the first sub-region examination. If internal corrosion is found during the first sub-region examination, additional examinations are performed upstream of the first site until a location is found free of corrosion (after which a validation examination is also performed) or the beginning of the sub-region is reached. Sub-regions n=’1,2,etc.’ are defined between region inspection sites where internal corrosion is found.

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Examinations in each of these sub-regions are selected in the same manner as for sub-region n=’0’. The presence of water trapping features (e.g., drips) may affect the number and location of examinations necessary. Water trapping features may be used as detailed examination locations if they are demonstrated to effectively trap liquids and they have an environment that represents or is more severe than that the general pipeline. If water trapping features are not used as detailed examination locations, they should be assessed separately. During detailed examinations, the pipe is inspected for the presence of corrosion. The internal pipe surface cannot typically be visually inspected; most inspections rely on non-destructive testing (NDT) techniques, as described in Section 2.3 Inspection Methods. It is important that the inspection be sufficiently detailed to detect internal corrosion present at the location. Internal corrosion may be present anywhere that electrolyte has been present. Because the volume of upsets (water) is not normally known, consideration should be given to inspecting a sufficient portion of the pipe so that the entire area where water may have accumulated is inspected. In particular, corrosion may be the most severe at the gasliquid interface. The anticipated corrosion mechanism(s) should be well understood to ensure that the proper inspection techniques are employed to detect possible damage. Understanding the corrosion mechanism will ensure that the proper areas of the pipe are inspected. 2.4.1.1.4 Post Assessment The purpose of the Post Assessment is to review the results of the Detailed Examination step and evaluate the performance of the DGICDA process. The Post Assessment consists of the following steps: 1. Determine the effectiveness of DG-ICDA. The effectiveness of DG-ICDA is determined by comparing the locations where internal corrosion is found to the locations identified during the Indirect Inspection step. If corrosion is found only at locations of expected liquid accumulation, DG-ICDA can be considered effective. If no corrosion is found, DG-ICDA can be considered effective. If corrosion is found at locations

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that were not expected to have liquid accumulation, the DGICDA is not considered effective. 2. Re-evaluate the feasibility of DG-ICDA for the pipeline. The feasibility of DG-ICDA is re-evaluated if extensive corrosion or corrosion at the top of the pipe is found. These findings can be an indication that some assumptions made during the Pre-Assessment step are not valid and that DG-ICDA is not feasible. 3. Remediate any internal corrosion discovered. Any internal corrosion that is identified during the Detailed Examination step is remediated according to company policies or government regulations. 4. Determine re-assessment intervals. Re-assessment intervals are determined based on the remaining life that is calculated based on the defect that was found during the Detailed Examination step. Remaining life is calculated based on the remaining strength of the corroded areas (e.g., RSTRENG) as well as the estimated corrosion growth rate for the defect. The corrosion growth rate can be determined using monitoring methods (as previously described in this chapter) or by using corrosion rates modeling. Re-assessment intervals depend on pipe operating stress level as well as government regulations or company policies. When internal corrosion is discovered during the ICDA process, monitoring and mitigation needs to continue after the assessment. Information regarding the location and form of corrosion determined during the Detailed Examination step can be useful in selecting appropriate monitoring techniques. Re-assessment intervals can be adjusted if monitoring results indicate corrosion rates different than those used to determine the remaining life.

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Resources NACE SP0106 “Internal Corrosion Direct Assessment Methodology for Pipelines Carrying Normally Dry Natural Gas (DG-ICDA)” Perry’s Chemical Engineering Handbook The Properties of Gases and Liquids

2.4.1.2 Wet Gas ICDA (WG-ICDA) (Wet Gas ICDA does not yet exist as a standard. Therefore, the following text is considered an example only.) The key difference between WG-ICDA and DG-ICDA is that the WG-ICDA process assumes that water, or a combination of water and hydrocarbons can be present throughout the pipeline. For the purpose of applying ICDA, wet gas is defined as gas that does not meet the requirements for DG-ICDA. WG-ICDA is intended for onshore and offshore systems where the liquid to gas ratio is small (less than 10% in volume). The lines may be water-saturated, hydrocarbon-saturated, or multiphase streams containing gas, liquid, water, and/or liquid hydrocarbons. WG-ICDA works to identify locations in the pipeline where corrosion is expected to be the most severe. 2.4.1.2.1 Pre-Assessment The goal of the Pre-Assessment step is to understand the likely corrosion mechanism(s) for the pipeline being analyzed and a basis to identify susceptible locations. Interviews and discussions with company personnel may be utilized to gain a thorough and accurate understanding of the pipeline. During the Pre-Assessment step, historical and current data, along with physical information regarding the pipeline are collected. Data are collected from the following categories: •

Operating history

•

System design information (grade, wall thickness, maximum operating pressure, etc.)

•

Presence of liquid water (including upsets)

•

Water and solids content

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•

Presence of H2S, CO2, and O2

•

Maximum and minimum flow rates

•

Pipeline elevation profiles

•

Internal corrosion failure history

•

Internal corrosion identified using visual inspection, in-line inspection or other non-destructive testing method

•

Mitigation currently being applied to control internal corrosion

•

Known and documented causes of internal corrosion (e.g., MIC)

The feasibility assessment for WG-ICDA considers whether conditions exist that would preclude the use of WG-ICDA or for which indirect examination tools cannot be used. In order to apply WG-ICDA, all required data must be collected, unless a SME has made a technically supported assumption. The pipeline must be expected to be wet (i.e., a continuous water phase is present at some point along the pipeline or throughout the whole pipeline during normal operation). Additionally, the pipeline has to be accessible to perform detailed examinations. The pipeline is divided into regions based on the data collected. A WG-ICDA region is a portion of a pipeline that has at least one distinguishing characteristic to describe it. A distinguishing characteristic is defined as any parameter relating to wet gas constituents, flow patterns, operating conditions, flow rate additions/reductions, or mitigation that may affect the location of corrosion, corrosion mechanism or anticipated corrosion rate. 2.4.1.2.2 Indirect Inspection The objective of the WG-ICDA Indirect Inspection step is to identify the locations in the region where corrosion damage is expected to be the most severe. These sites may be candidates for detailed examination. The locations where corrosion damage is expected to be most severe are determined by performing corrosion rate modeling. Risk methodologies may be used as appropriate. Locations which are predicted to have the highest internal corrosion rates are assessed the highest likelihood of experiencing significant internal corrosion and are high priority. It must be kept in mind that

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the historical operation of the pipeline may require several corrosion rate modeling assessments be conducted as operating conditions may have changed over time. The corrosion rates are multiplied by the length of time over which that rate is expected and then summed in order to estimate a cumulative amount of damage. 2.4.1.2.3 Detailed Examination The objectives of detailed examination include performing excavations and conducting detailed examinations at locations where they have been prioritized to have the highest corrosion severity. Examinations are also performed at locations expected to have lower corrosion severity, in order to verify that the corrosion model used was capable of identify the locations of most severe corrosion. The pipe examination must have sufficient detail to determine the existence, extent, and severity of corrosion. Examination of the pipe involves the uses of inspection methods described in Section 2.3 Inspection Methods to identify and characterize internal defects. Incorporation of inspection data to update the indirect inspection results may help reprioritize the examination sites. 2.4.1.2.4 Post Assessment The objectives of Post Assessment are to validate the process, assess the effectiveness of WG-ICDA, and to determine reassessment intervals. It covers the analysis of data collected from the previous three steps to assess the effectiveness of the WG-ICDA process, activate and prioritize mitigation, control and maintenance strategies, and determine reassessment intervals. If the results of examinations do not match the results from the corrosion rate modeling, the modeling is updated and additional examinations performed.

2.4.1.3 Liquid Petroleum ICDA The Liquid Petroleum Internal Corrosion Direct Assessment (LPICDA) methodology is designed to assess the likelihood of internal corrosion on pipelines that transport incompressible liquid hydrocarbons that normally contain less than 5% BS&W (base sediment and water). LP-ICDA works to identify locations on the

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pipeline that have the highest probability of having experienced internal corrosion. 2.4.1.3.1 Pre-Assessment The objectives of the Pre-Assessment step are to collect the data required to perform LP-ICDA, determine the feasibility of LPICDA for the pipeline being assessed, and identify LP-ICDA regions. The data that is required to perform LP-ICDA includes pipeline construction and operational data, compositional data on the liquid petroleum that is transported, including BS&W composition, presence of H2S, CO2 and O2, maximum and minimum flow rates for all inlets and outlets, periods of low or no flow, operating temperature ranges, use of corrosion inhibitors and biocides, pigging operations (maintenance and ILI), presence of internal corrosion through ILI results, visual inspection or other methods, and any leaks or failures due to internal corrosion. LP-ICDA is not applicable to pipelines where indirect inspection cannot determine locations in which internal corrosion is most probable, where the pipeline is expected to have a continuous water phase during normal operation, where the pipeline has a continuous coating for the entire length of the line, or where the pipeline cannot be made accessible for detailed examination. The pipeline is divided into regions based on the presence of historical and current injection and delivery points, chemical injection locations, and pigging operations. Additional LP-ICDA regions are required if the pipeline has experienced bi-directional flow. 2.4.1.3.2 Indirect Inspection The Indirect Inspection step consists of performing multiphase flow modeling to identify the locations where water and solids could accumulate. Critical velocities and inclination angles for water and solids accumulation are compared to the pipeline inclination profiles in order to identify the location where water and solid could accumulate. Any valid multiphase flow modeling approach that considers stratified flow, semi-stratified flow, and water-in-oil dispersion can be used during the Indirect Inspection step. The pipe elevation profile is used with flow modeling results and other factors that may affect corrosion distribution to identify

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locations which have the highest potential for internal corrosion. Other factors that are considered include: •

Emulsion stability

•

Corrosion inhibition

•

Water chemistry

•

Bacteria and biocides

•

Solids composition

•

Hysteresis in wettability

•

Hysteresis in water and solids transport

•

The effect of turbulence and flow disturbances

Hysteresis in wettability is the amount of time required for the pipeline surface properties to change from oil-wet to water-wet once water is present. Hysteresis in water and solids transport considers that the velocity required to re-entrain settled water and solids is greater than the velocity required to maintain entrainment in steady state conditions. The probability of corrosion is calculated for all locations where water or solids accumulation is expected. For each location, values are assigned for each of the factors (e.g., water chemistry) identified above based on confidence and influence. The confidence and influence of each factor are determined by subject matter experts. Factors assigned a ‘high’ confidence are those for which the data or method used to differentiate different locations is considered reliable. Factors assigned a ‘low’ confidence are those for which the data or method used to differentiate different locations involved a large amount of uncertainty. Factors assigned a ‘large’ influence are those which play the most influential role in the overall corrosion rate. Factors assigned a ‘low’ confidence are those which play the least influential role in the overall corrosion rate. •

Factors with a high confidence and a large influence are assigned values ranging between 0.1 and 1.

•

Factors that have a low confidence but a large influence are assigned values ranging between 0.5 and 1.

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•

Factors with a high confidence but a small influence are assigned values ranging between 0.9 and 1.

•

Factors with low confidence and small influence are assigned 1 for all locations.

As an alternative to calculating the probability of corrosion, corrosion rate modeling can be used to determine the locations most likely to contain internal corrosion. Corrosion rate models should be applicable to the operating conditions (i.e., liquid petroleum composition, pressure, temperature, flow rate, etc.) of the pipeline that is being analyzed. The two (2) locations with the highest probability of internal corrosion, based on water accumulation within each region, are identified for detailed examination. For pipelines susceptible to solids accumulation, two additional locations are selected at locations with the highest probability of internal corrosion based on solids accumulation. If an LP-ICDA region is greater than 3 miles in length, the region is typically split into three equal length subregions to assess for the possibility of flow stratification. The sites with the highest probability of internal corrosion in each sub-region are identified for inspection in the Detailed Examination step. 2.4.1.3.3 Detailed Examination In the Detailed Examination step, the selected sites in each LPICDA region are examined for the presence of internal corrosion. If internal corrosion is found at any of the sites, the next highest probability locations are examined until two consecutive locations are free from internal corrosion. A validation examination is also performed at a location that is expected to have a low probability of internal corrosion. The examinations are performed using inspection methods described in Section 2.3 Inspection Methods. 2.4.1.3.4 Post Assessment The purpose of the Post Assessment is to determine the remaining life of any defects that were found, evaluate the effectiveness of the LP-ICDA process, and determine the re-assessment interval. The remaining life of defects can be determined based on remaining strength calculations for internal corrosion identified in the Detailed Examination step and corrosion rates determined for defect growth. Corrosion growth rates can be determined using monitoring devices

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as described in Section 2.2 Monitoring Techniques, or using corrosion rate modeling. The effectiveness of the LP-ICDA process is determined by correlating any corrosion that is found with the locations that were predicted during the Indirect Inspection step.

2.4.2 Confirmatory Direct Assessment Confirmatory Direct Assessment (CDA) can be used to verify the corrosion rate that was determined during a DA process before the re-assessment interval is complete. There is currently no standard for CDA for internal corrosion.

2.4.3 Pressure Testing Pressure testing is based on the premise that once defects that fail at the test pressure are removed, the line is safe to operate at the MOP or below. While pressure testing can be performed using an inert gas, the majority of pressure testing is performed using water. Hydrostatic testing is a relatively simple, low-technology method to assess pipeline integrity. Hydrostatic pressure testing is performed by filling the pipeline with water and increasing the pressure to an established test pressure. Generally, both pressure testing for strength and leaks are done. The test pressure and duration of the test is determined by applicable codes or government regulations. For example, ASME B31.8 requires a test pressure which will cause a hoop stress of 90% of the specified minimum yield stress (SMYS) in the tested segment with the lowest design or rated pressure. If the hoop stress percent of SMYS cannot be determined, the strength test can be performed at 1.1 times the maximum allowable operating pressure (MAOP). The strength test pressure is held for a minimum of one half hour. Following the strength test, a leak test is performed at 1.1 times the MAOP for as long as necessary to detect or locate any leaks. ASME B31.4 requires a test pressure of 1.25 times the internal design pressure for a minimum of four hours. If the pipeline is not visually inspected during the test, it must be followed by a second test at 1.1 times the internal design pressure for a minimum of four hours.

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Hydrostatic pressure testing only provides information about the integrity of the pipeline at the time of the test. Additionally, only flaws that fail at the hydrostatic test pressure are identified; no information is provided regarding the presence of sub-critical flaws. The identification of the presence of internal corrosion is, therefore, limited to areas that fail at the hydrostatic test pressure. However, the higher the hydrostatic test pressure (as a percentage of specified minimum yield stress [SMYS]), the smaller the defect that can remain in the pipeline after testing. Hydrostatic pressure testing cannot be used to determine corrosion activity or growth (i.e., there is no way to compare successive hydrostatic pressure tests in order to determine corrosion activity). To perform a hydrostatic test, the pipeline must be taken out of service. The line is then filled with water. Water used for hydrostatic testing can be taken from potable sources (e.g., city water) or nonpotable sources (e.g., river or lake). The source of the water is dependent on what water supplies are readily available. Non-potable water can have a larger impact on internal corrosion based on the introduction of potentially corrosive constituents such as bacteria. Biocides and or corrosion inhibitors can be used to reduce this impact. The discharge of test water may be governed by applicable environmental regulations. The addition of mitigation chemicals such as corrosion inhibitors or biocides may influence the ability to dispose of water. Once the water is in the pipeline, the pressure is increased to a level specified by applicable regulations and/or company procedures. The pressure is held for a set period of time, which is again specified by applicable regulations and/or company procedures. After the pressure test has been completed, the water must be removed from the line. Before the pipeline is returned to service, it should be completely de-watered. Any water that does remain can result in increased corrosion rates at locations where it has accumulated. Pigs are commonly used to remove water from the line. Types of pigs that are used for de-watering include foam, spherical, mandrel (with cups/seals) or solid cast. Running multiple pigs through the pipeline until no water emerges with the pig helps to ensure that all water has been removed and has

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not been temporarily displaced into laterals. The number of pigs required depends on the length of the line, the number of laterals, and the number of low spots or other locations where water could settle after the hydrostatic test. Nitrogen or de-hydrated air/gas can be used to dry the line after water has been removed. Monitoring the humidity or dew point of the gas exiting the pipeline helps to identify when the pipeline is dry. Methanol slugs in between pigs can also be used to swab the lines and help remove any remaining water. Assessment intervals for hydrostatic pressure tests may be determined by company policy, standards such as ASME B31.8S, or government regulations. Assessment intervals defined by ASME B31.8S are shown below (ASME B31.8S Table 3 Integrity Assessment Intervals: Time-Dependent Threats, Prescriptive Integrity Management Plan). Table 2.6: Assessment Intervals for Hydrostatic Testing and In-Line Inspection per ASME B31.8S Criteria Inspection Technique Hydrostatic Testing

In-line Inspection

Interval (Years)1

At or Above 50% SMYS

At or Above 30% up to 50% SMYS

Less than 30% SMYS

5

Test pressue at 1.25 times MAOP

Test pressure at 1.4 times MAOP

Test pressure at 1.7 times MAOP

10

Test pressure at 1.39 times MAOP

Test pressure at 1.7 times MAOP

Test pressure at 2.2 times MAOP

15

Not allowed

Test pressure at 2.0 times MAOP

Test pressure at 2.8 times MAOP

20

Not allowed

Not allowed

Test pressure at 3.3 times MAOP

5

Pf above 1.25 times MAOP

Pf above 1.4 times MAOP

Pf above 1.7 times MAOP

Pf above 1.39 times MAOP

Pf above 1.7 times MAOP

Pf above 2.2 times MAOP

Not allowed

Pf above 2.0 times MAOP

Pf above 2.8 times MAOP

Not allowed

Not allowed

Pf above 3.3 times MAOP

1

Intervals are maximum and may be less, depending on repairs made and prevention activities instituted. In addition, certain threats can be extremely aggressive and may significantly reduce the interval between inspections. Occurrence of a time-dependent failure requires immediate reassessment of the interval.

Pf

the predicted failure pressure as determined from ASME B31G or equivalent.

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2.4.4 In-line Inspection (ILI) In-line inspection (ILI) is a method of non-destructive integrity assessment. ILI of long pipe sections normally uses instrumented pig-type equipment. Gas or liquid propelled ILI tools are moved through the pipeline by controlling the gas pressure differential across the tool once it is inserted into the pipe. Tethered ILI tools are moved from a cable passed through the inspection segment, connected to the tool, and pulled back through the segment at a controlled rate. There are three basic types of ILI tools that are used to measure wall loss: low-resolution and high-resolution magnetic flux leakage (MFL) tools, and ultrasonic tools. Figure 2.25 shows an example of an in-line inspection tool.

Figure 2.25 In-line Inspection Tool

Launchers and receivers, either permanent or temporary, are required to perform a traditional ILI (where the tool is transported by liquid or gas that is normally present in the pipe) on a pipeline. The flow rate of the gas or liquid may need to be decreased in order for the ILI tool to run at the desired speed. If launchers and receivers are not present, or only one launcher/receiver is able to be used, a tethered ILI tool can be employed. The tethered tool is inserted through a tap in the pipeline and can be driven by product, compressed nitrogen, compressed air, or wireline. Pipeline lengths of up to five (5) miles can be inspected using a tethered tool,

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depending on pipe configuration, the topography of the pipeline, pipeline construction and the type of equipment being used to perform the ILI run. In-line inspection can be used to assess long lengths of pipe in a relatively short period of time. If the proper tool type is used, both the internal and external condition of the pipe can be evaluated. Subsequent inspection logs can be compared to determine the growth rate of anomalies. Inertial navigation systems can be used to add pipe location data to a geographical information system (GIS). Not all pipelines can be inspected using ILI without modification. Changing diameters, tight bends or turns (such as offsets), valve types, wall thickness, and small diameter lines may prohibit the use of ILI. Some tools may be capable of inspecting multiple diameter pipelines. Low resolution MFL tools generally do not distinguish between internal and external indications. Therefore, the type of wall loss that is shown from a low resolution MFL tool cannot be known until the pipe is physically examined. The use of an ultrasonic tool requires that a liquid be present around the tool to provide coupling between the transducers and the pipe wall. Typically, this means that ultrasonic ILI tools are used only in liquid pipelines. However, an ultrasonic tool may be used in a gas pipeline if it is run in a slug of liquid that is contained between two additional pigs. Consideration must be given to the benefits of running an ultrasonic versus the impact of introducing a liquid into the pipeline. It is very important to have the pipeline interior as clean as possible before an ILI run to ensure that the most accurate data can be collected and to limit the possibility that a re-run will be required. Caliper and sizing tools are often used prior to the first ILI run on a line to ensure that the instrumented tool can safely pass through any dents, bends, wall thickness changes, valves, or other pipeline features which could damage the tool or cause it to hold up. A “dummy” tool of similar size to the actual ILI tool may also be run immediately before the ILI run to verify that the ILI tool will be able to pass through the pipeline undamaged. Inspection at selected anomaly locations can be used to validate the ILI log. In order to validate the internal indications, it is helpful if at

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least one validation location be located at an internal anomaly (i.e., not all validation locations correspond to external anomalies). ILI does not assess the condition of crossovers, drips, bypass sections, etc. Assessment intervals for in-line inspection may be based on company procedures, standards such as ASME B31.8S, or government regulations. Assessment intervals based on ASMEB31.8S are shown above in Table 2.6. Resources •

NACE Technical Committee Report 35100, “In-Line Nondestructive Testing of Pipelines”

•

NACE standard Recommended Practice SP0102, “In-Line Inspections of Pipelines”

•

API 1163

2.4.5 Assessment Method Selection Selection of an appropriate assessment method can be determined based on the topics discussed below. ILI is a popular assessment method because it provides detailed information regarding corrosion anomalies along the entire length of the pipe inspected. Pipelines that are piggable are almost always assessed using ILI. Modifications to make a pipeline piggable should be considered when: •

The pipeline can be made piggable with minor modifications

•

Corrosion monitoring has shown high corrosion rates

•

Previous inspections have identified the presence of corrosion

•

The use of tethered ILI inspection can be considered as an alternative to making a pipeline piggable

ICDA is typically selected for pipelines for which ILI, including tethered pigging, is not performed. ICDA is best suited for pipelines that span long distances with limited inputs. ICDA can be performed on systems that form networks and/or systems for which hydrostatic pressured testing is unfeasible. Where ICDA is selected, the appropriate ICDA type (e.g., dry gas, wet gas, or liquid petroleum) is chosen based on the service condition.

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Hydrostatic pressure testing is generally the least popular method because it does not provide any information regarding remaining corrosion features and increases the potential for future corrosion, due to the introduction of water. Hydrostatic pressure testing may be the only option for unpiggable lines for which ICDA is not applicable (e.g., multiphase production lines with > 5% water content, water pipelines, slurries, etc.).

2.5 Determining If Mitigation Is Required Once monitoring, inspections, and/or assessments have been performed, it is time to determine where mitigation is necessary. If inspections and/or assessments show corrosion but monitoring has not been performed, monitoring can be used to determine if corrosion is active. When inspections and/or assessments identify the presence of internal corrosion damage, but monitoring indicates a ‘low’ corrosion rate, the corrosion damage may be historical and thus mitigation is not required. Specific corrosion rates at which mitigation is necessary are determined individually by companies. However, the need for mitigation depends on the amount of corrosion damage that already exists, the remaining life/operation of the pipeline, and the feasibility of pipe replacements. The severity of existing corrosion damage and the corrosion rate can be used to estimate the remaining life of the pipeline. The remaining life can then be compared to the expected remaining operation of the pipeline. The more severe or extensive the internal corrosion that already exists in a pipeline, the lower corrosion rate that can be tolerated.

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Chapter 3: How Do I Stop It? Overview Internal corrosion mitigation is done to reduce the impact of a corrosive environment to an acceptable level. It can also be implemented to comply with regulations or company policies. Corrosion can be mitigated in the following ways: •

Reduce the amount of time that corrosive species are in contact with the pipeline

•

Reduce the impact of corrosive species that are present

•

Prevent corrosive species from entering the line

•

Prevent corrosive species from contacting the metal surface of the pipeline

Mitigation methods should be selected based on the corrosive species present in the line and the operating conditions of the pipeline. Mitigation strategies may rely on multiple mitigation methods to effectively control internal corrosion.

3.1 Maintenance Pigging Maintenance (or cleaning) pigging is used to remove accumulated water and/or solids in a pipeline. To perform pigging on a routine basis, launchers and receivers must be present on the line. For lines that do not have launchers and receivers, factors that should be considered to determine if a line can be made piggable are: •

The presence of changing diameters

•

Valves that prevent the passage of pigs

•

Tight bends or turns

Maintenance pigging is also done for operational purposes. For example, pigs are used to separate different batches of products for liquid petroleum lines. The use of pigs for operational purposes is not covered in this course.

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3.1.1 Types of Maintenance Pigs There are various types of maintenance pigs, each of which has a different application and performance capability. Therefore, the type of pig used is specifically selected based on the objective of the pigging. Pigs can be used in ‘trains’ (multiple pigs of the same type or different types) to achieve the desired effect. A train consists of multiple pigs that are run through the pipeline at the same time. Maintenance pigs should be the proper size for the pipeline being pigged. They need to be checked for damage or wear prior to use and need to be cleaned prior to launching. Figure 3.1 shows an example of a dirty pig. Pigs should be maintained and replaced when they are worn down or damaged to keep them functioning properly.

Figure 3.1 Dirty Pig

3.1.1.1 Mandrel Pigs Mandrel pigs have a metal body (steel or aluminum) and are equipped with scraper cups or discs that seal to the pipe wall. Figure 3.2 shows examples of a mandrel pig equipped with scraper cups (left) and a mandrel pig equipped with discs (right). Cups are used for uni-directional flow. Discs can be used for lines that have unidirectional or bi-directional flow. Conical cups are also available for pipelines with varying internal diameters or deformations. The outer

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diameter of the pig is slightly larger than the internal diameter of the pipe (generally 1% to 5%) to ensure that a proper seal is achieved. Mandrel pigs can be used to remove liquids, sludge, or paraffin from a pipeline.

Figure 3.2 Mandrels Pigs Equipped with Scraper, Discs or Cups (left) and Discs (right)

Mandrel pigs can be equipped with brushes or blades to remove solids. Figure 3.3 shows mandrel pigs equipped with blades and brushes and Figure 3.4 shows a mandrel pig with brushes after removal from a pipeline. Brushes can be metallic or non-metallic and can cover the entire circumference of the pig or be segmented. The brushes and blades can be spring mounted to ensure constant contact with the pipe surface. Mandrel pigs can also be equipped with magnets to help remove magnetic debris such as iron oxides. The cups, discs, brushes and blades on a mandrel pig are removable so the entire pig does not need to be replaced when these parts become unusable.

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Figure 3.3 Mandrel Pigs Equipped with Blades (left) and Brushes (right)

Figure 3.4 Mandrel Pig with Brushes After Removal From a Pipeline

3.1.1.2 Foam Pigs Foam pigs are manufactured from polyurethane foam, which is available in various densities. Foam pigs can be coated in an elastomer (generally not over the entire surface) and can have plastic bristle straps, steel wire brush straps, or silicon carbide attached to the elastomer. Foam pigs are normally used for drying or

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wiping to remove paraffins or other soft deposits. The ability of the foam pig to remove solids depends on the density of the foam and the outer material. Figure 3.5 shows examples of sealing and disc foam pigs.

Figure 3.5 Foam Pigs - Sealing Type (left) and Disc Type (right)

The advantages of foam pigs are that they are: •

Compressible

•

Expandable

•

Lightweight

•

Flexible

These characteristics allow them to be used in lower pressure systems and in systems with short radius bends, tees, valves, and other constrictions that may prevent other types of pigs from being used. Foam pigs can be used as sacrificial pigs when pigging branch lines without a pig receiver, especially when the branched line is barred (i.e., there are bars at the tee into the other line). A sacrificial pig is one that is not expected to be re-used because it will be destroyed or otherwise deformed going through the system. Foam pigs may also be used the first time that maintenance pigging is performed to determine if other pig types will be able to pass through the line.

3.1.1.3 Solid-Cast Pigs Solid-cast pigs are similar to cup or disc mandrel pigs except that the entire pig is made of polyurethane plastic (see Figure 3.6). Solidcast pigs are lighter than mandrel pigs, allowing them to be used in

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lower pressure systems than mandrel pigs. They can be used to remove liquid in a gas system, water in a liquid product system, or debris or other solid accumulation in any type of system. As the cups or discs wear down, the entire pig needs to be replaced.

Figure 3.6 Solid-cast Pig

3.1.1.4 Sphere Pigs Sphere pigs may be solid-cast, inflatable, or foam (see Figure 3.7). They can be used to remove liquids from gas systems and water from liquid products lines. They can negotiate short-radius 90degree turns, irregular turns, and bends.

Figure 3.7 Sphere Pigs

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3.1.1.5 Gel Pigs Gel pigs are highly viscous fluids that are used to suspend deposits and debris. They are generally used in conjunction with other pigs. For example, a gel pig may be run in front of a scraper pig. They can be formulated for various pipeline environments (e.g., gas, water, crude, etc.). Gel pigs can be used without a launcher or receiver by pumping into the line. Figure 3.8 shows an example of a gel pig.

Figure 3.8 Gel Pig

3.1.2 Cleaning Frequency Schedule and Impacts The frequency at which maintenance pigging is performed depends on the type of pipeline operation and the volume of liquids or solids that need to be removed from the line. For some systems it may be sufficient to pig on an annual basis, whereas for others more frequent pigging is required. Pigging needs to be performed on a frequent enough basis to manage corrosion and ensure the pig does not get stuck in the pipe due to the volume of accumulated liquids or solids. The initial pigging schedule should be selected based on known or suspected accumulation rates. Subsequent pigging is then determined based on what is discovered during the previous pig run(s). The volume of liquids and solids recovered during pigging should be quantified to determine if additional runs are needed and

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to help determine the frequency of future runs. Where no information is known regarding potential accumulation rates, an arbitrary pigging frequency (such as monthly or semi-annually) may be selected as a starting point. A pressure drop in a pipeline segment is one way to determine pigging frequency in gas lines where pigging removes accumulated liquids or in lines with high solid production. The pressure drop used to trigger pigging depends on the operating pressure of the line, the length of the line, and historical knowledge of pigging for the line. Often, several cleaning pigs need to be run because there can be a large amount of bypass during the pigging process (i.e., the pig is able to pass by solids or water without removing them). Therefore, a pig run containing a minimal amount of solids or sludge does not necessarily indicate that the line is clean. It is also important that there be some means of handling the total volume of liquids or solids that are removed. For example, if there is a 10 barrel capacity separator at the end of a piggable line and a 50 barrel slug of water is removed during pigging, the water exceeds the volume of the separator and will end up being transported downstream. In such a case, pigging needs to be performed on a more frequent basis or another vessel capable of holding larger volumes of liquids needs to be installed. Pig cleaning schedules may have an impact on pipeline operations. For most pigs, there is an optimum velocity range in which they should be run. For systems where the typical operating velocity is greater than what is recommended for the pig type, the gas or liquid flow rate may need to be reduced. The impact of flow reduction on downstream delivery needs to be taken into consideration when scheduling the pig cleaning. For systems with relatively steady flow, it may be possible to perform pigging operations at any time. For systems with low pressure or low flow, pressure may need to be built up (if possible) or the flow increased in order to move the pig through the line. For systems that have periods of low or stagnant flow, it is important that the pigging operations be scheduled prior to these periods to remove water and solids. Additionally, although most pigging is

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performed on-line, there may be some instances where pigging is performed off-line. When pigging is being performed off-line, downstream customers need to be considered during scheduling. For pipelines where hydrates are a problem, methanol (or a hydrate inhibitor) can be run in front of the pig to prevent hydrate formation during pigging. Alternatively, pigging may need to be performed off-line. For branched systems, lateral lines should be pigged prior to pigging the main line. If possible, the isolation valves (if present) where the laterals tie in to the main line should be closed to prevent liquids and solids from entering the laterals during pigging of the main line. The presence of barred tees on the lateral lines is also helpful during the pigging process to ensure the pig does not attempt to go down the lateral line.

3.1.2.1 Performance Confirmation A methodical approach should be used when implementing a new pigging program or when evaluating the effectiveness of an existing program. Trials of different pig types and pigging schedules may need to be performed in conjunction with internal corrosion monitoring to determine the optimal mitigation schedule. An example of a process to follow in selecting and evaluating a pigging program includes: 1. Determine the potentially corrosive species present in the pipeline (see Chapter 1). 2. Determine the severity of corrosion (see Chapter 2). 3. Select the appropriate pig type for the objectives and identify performance metrics. 4. Evaluate the results of the pigging. 5. Adjust the pigging program as necessary to optimize corrosion control.

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Flush-mounted corrosion coupons can be used to help determine the effect of pigging on the internal pipe wall. If multiple coupons are used, one can be removed and examined before a pig run and another can be examined after a pig run. The two coupons can be compared to determine the effectiveness of the pig run on removing solids, scale, or biofilm from the pipe surface. It is important to note that the internal surface of the pipe is curved, whereas most coupons are flat. This can affect the effect of pigging observed on the coupon versus the actual pipe wall. This effect is more pronounced in smaller diameter pipelines. In pipelines with diameters larger than 600 mm (24 inches), the curvature in the area of the coupon becomes less noticeable. Additionally, it is important that the coupon be at the appropriate elevation relative to the pipe wall (i.e., flush) to experience the same cleaning action as the pipe surface. Performance confirmation may also be done by comparing the results of monitoring upstream with the results of flush mounted monitoring devices within the pigged section. Pigging envelope sampling can also be used to evaluate the returns that are being pushed through by the pig. Advantages • Corrosive species are physically removed from the line •

When effective, it removes scales, biofilms, solids, liquids, and other materials that can promote internal corrosion

•

Can be used to remove solids prior to chemical treatment; thus enabling the chemical treatment to reach the pipe surface

•

Can be used prior to biocide applications to improve efficency of biocide treatment

•

More effective at removing liquids than line sweeping1, and one of few options for removing tenacious solids

•

There are many different types (with different functions)

•

They can be run in trains to achieve multiple goals

1. Line sweeping is defined as increasing flow velocity in an attempt to remove accumulated solids and liquids.

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•

Flexible mitigation technique that can be easily varied as operating conditions change on a line

Limitations • For lines with multiple branches, liquids, solids, or sludge may be pushed into the branches during line pigging (depending on the line configurations and the location of valves), promoting corrosion •

Protective scale can be removed at the same time as non-protective scale, exposing the pipe surface to a corrosive environment and potentially resulting in a temporary increase in corrosion rate

•

Potential for the pig to become stuck behind accumulated debris

•

Pig may pass over debris accumulation

•

It may be difficult to pig at the desired frequency or time due to operational considerations

•

Manpower considerations associated with performing pigging may limit the frequency at which pigging can be performed

•

HSE considerations

3.2 Chemical Treatment Chemical treatment involves the planned addition of a site-specific combination of chemicals. The treatment may include chemicals designed to inhibit corrosion, control microbial activity, scavenge oxygen, control scaling, and/or clean the pipeline. The performance of chemical treatment programs must be verified.

3.2.1 Application Methods The two most common application methods used for chemical treatments are continuous injection and batch treatment.

3.2.1.1 Continuous Injection Treatment chemicals are injected continuously when a specified concentration of chemical is desired in the fluids being transported. Chemicals can be delivered in a variety of ways including drip tanks, chemical pump injection, etc.

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Continuous injection requires the installation of chemical pumps and other equipment including a chemical holding tank, a control unit, control interface, and potentially a mixer and flow meter. Figure 3.9 shows a chemical injection and storage facility. Multiple pump heads can be necessary where there are multiple injection points along the same line.

Figure 3.9 Chemical Injection and Storage Facility

Chemical injection can be performed through an open tube or quill or using an atomizing nozzle. Atomizing nozzles are used to disperse a chemical into the gas phase. Where top-of-line corrosion is occurring, it may be necessary to inject the treatment chemical into the gas phase. If chemicals are added directly to the line (i.e., not using a tube or quill), corrosion may occur at the site of chemical injection. Figure 3.10 shows corrosion at a chemical injection point without a quill.

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Figure 3.10 Corrosion Occurring at a Chemical Injection Point

The materials within the injection system should be compatible with the product (e.g., storage tanks, elastomers, tubing, etc.) The most effective position for chemical injection is the center of the pipe or vessel. However, this prevents the section where the chemical is being injected from being pigged. Where pigging operations need to be performed, the injection point must be upstream of the piggable section, flush mounted, or the injection tubes removed prior to pigging. Pumps used to inject chemicals can be set at a fixed rate. The volume (injection rate) of chemical can be based on the amount of water that is transported, instead of the flow rate of oil or gas. Injection rates can also be set based on chemical residual values or monitoring data. It is also possible for the chemical injection rate to vary with the product flow. In such cases, the water production is assumed to change proportionally with the change in product flow. This allows the concentration of the chemical in the water phase to remain constant as the product flow rate changes.

3.2.1.2 Batch Treatment Batch treatments are designed to lay down an inhibition film to provide protection between treatments. Chemicals are typically pumped into the pipeline at a high concentration (generally, tens of thousands of parts per million) for a brief period of time (minutes).

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The volume of chemical injected during batch treatment is determined based on the surface area of the pipe to be treated or contact time of the chemical batch. The desired film thickness of the chemical depends on the chemical being applied. The volume of chemical that reaches the end of the line can be used to help determine whether chemical was applied throughout the entire line at the desired thickness. Batch treatment can be accomplished using either slugs of chemical or transporting the chemical using pigs. Slug treatments are used on lines that are not piggable and result in a less uniform film thickness application than batch treatment using pigs. When performing batch treatment using pigs, a tight seal between the pig and the pipe wall is undesirable because it can result in the application of an insufficient film thickness. Batch treatments can be used at locations where continuous treatments are not possible (e.g., remote locations where it is difficult to install continuous injection equipment). Batch treatment using pigs may be preferable to disrupt solids or biofilms prior to chemical treatments. The leading pig removes solids and biofilms that would otherwise prevent the chemical from reaching the pipe wall. Additionally, batch treatment may be preferred where top-ofline corrosion is occurring.

3.2.1.3 Concentration and Injection Rate Prior to application of treatment, the desired chemical concentration must be determined. Laboratory testing or field trials as described in Appendix B can be used to determine expected chemical concentrations at which treatment is expected to be effective. The concentration of the chemical prior to application, flow rate, and desired applied concentration can be used to determine the required injection rate for the system. If the product is waterdispersible/soluble, the injection rate is usually based on water volume.

3.2.1.4 Factors Influence Chemical Treatment Performance The performance of a chemical treatment can be affected by temperature, velocity, solubility, compatibility with other chemicals,

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and chemical availability. Consistency in the quality of the chemical over time can also affect the treatment performance. 3.2.1.4.1 Temperature The effectiveness of treatment chemicals is dependent on the system operating temperature. Generally, increases in temperature have an adverse effect on the performance of treatment chemicals. This is the result of the breakdown of chemical and increase in corrosion rate. Decreases in temperature may affect the ability to deliver the chemical. Chemical treatments should only be applied if their performance capabilities are known at the system operating temperature. Testing as described in Appendix B can be used to determine the performance of the chemical treatment at various temperatures. 3.2.1.4.2 Velocity The effectiveness of treatment chemicals is dependent on the system velocities and flow regimes. Shear stress from high velocities can have an adverse effect on the performance of treatment chemicals. Low velocities can prevent effective deliverability of the chemical. Chemical treatments should only be applied if their performance capabilities are known at the system velocities. 3.2.1.4.3 Solubility All treatment chemicals can be classified according to their water and oil solubility and dispersibility characteristics. Solubility is a measure of a treatment chemical’s ability to dissolve in a given medium (e.g., water or oil). Dispersibility is a measure of the chemical treatment’s ability to be separated into particles in a given medium. Solubility and dispersibility are discussed further with each treatment chemical below. 3.2.1.4.4 Compatibility with System Fluids and Other Chemicals Chemical treatments must be compatible with the system fluids and other chemicals being added to the system (e.g., scale inhibitors, demulsifiers, methanol, etc.). It is possible for two or more chemicals to react with each other, nullifying their effectiveness and/or causing operational problems. The compatibility of

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chemicals may be tested in a laboratory prior to their use. Compatibility of chemicals for reservoirs may need to be evaluated. 3.2.1.4.5 Chemical Availability Chemical treatment delivery cannot be guaranteed 100% of the time over the life of the system. Rather, the availability of a chemical treatment will vary over time due to various interruptions. Examples of interruptions that can affect the chemical availability include: •

Blockage of injection valves and associated piping

•

Leaks on injection valves and associated piping

•

Pump failures

•

Incorrect pump settings

•

Solid deposition (preventing chemicals from reaching pipe surface)

•

Changes in production rates or water cuts (preventing chemicals from reaching pipe surface)

•

Disruption to chemical supply

Over the course of a chemical treatment, it may be necessary to consider potential interruptions to the system that could prevent the correct dosage of chemical treatment from reaching the pipe.

3.2.2 Corrosion Inhibitors Corrosion inhibitors are substances that are added to a pipeline to reduce the corrosion rate. The most common components of corrosion inhibitors include: •

Amides/imidazolines

•

Salts of nitrogen containing molecules with carboxylic acids

•

Nitrogen quaternaries

•

Filming oxyalkylated amines, amides, and imidazolines

•

Nitrogen heterocyclics and compounds containing phosphorus, sulfur, and oxygen

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Corrosion inhibitors are commonly used with carbon and low alloy steel systems. Most corrosion inhibitors work by adsorbing to a metal surface and forming a protective film. Corrosion inhibitors can also adsorb to solids or scale present in the system. The effectiveness of a corrosion inhibitor depends on the pipeline material, the inhibitor composition, corrosion mechanisms, fluid composition, and the type of flow. It is necessary to introduce the inhibitor into the phase in contact with the pipe wall. This can be accomplished only if flow patterns and phase distributions under different conditions are known. Selection of the appropriate inhibitor should include laboratory performance testing (refer to Appendix B for laboratory inhibitor tests). As previously discussed, corrosion inhibitors are characterized by their solubility and dispersibility. Corrosion inhibitors may be water soluble, oil soluble, or oil soluble water dispersible. Each type of solubility is discussed on the following pages. Even though a corrosion inhibitor is soluble in one medium, a portion of it may still be present (or partition) into the other phase. Partitioning between oil and water can be characterized by the partition coefficient. P  CI oil /CI water

[3.1]

Where: P

= partition coefficient

[CI]oil

= concentration of corrosion inhibitor in oil phase

[CI]water = concentration of corrosion inhibitor in water phase Advantages • Can be applied continuously in non-piggable systems •

Useful when pigging and prevention of potentially corrosive species is ineffective at reducing corrosion rates to an acceptable level

Limitations • Environmental regulations may limit their use and disposal

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•

There is not one corrosion inhibitor that can be used for all operating systems

•

Some corrosion inhibitors can be corrosive in a concentrated form

3.2.2.1 Water Soluble Corrosion Inhibitors Water soluble corrosion inhibitors dissolve in the aqueous phase and then diffuse to the pipe surface, forming a barrier between the aqueous phase and the pipe surface. They are used in systems where water is the only liquid phase, regardless of the actual volume of water. Water soluble corrosion inhibitors can also be used in liquid multiphase systems provided that there is a sufficient volume of water present for the corrosion inhibitor to be injected into and transported throughout the line by the water phase.

3.2.2.2 Oil Soluble-Water Dispersible Corrosion Inhibitors Oil soluble–water dispersible corrosion inhibitors are transported in the hydrocarbon phase and are dispersed into the water phase as a result of turbulence in the transported fluids. They are used for continuous injection predominantly in crude oil lines where water is either not present or water cuts are relatively low. Oil soluble–water dispersible corrosion inhibitors are also sometimes used for batch treatments. Where they are being used, it is important that there is sufficient mixing for the inhibitor to be dispersed into the water phase. Oil soluble–water dispersible corrosion inhibitors can cause problems with emulsion formation and foaming.

3.2.2.3 Oil Soluble Corrosion Inhibitors Oil soluble corrosion inhibitors dissolve in crude oil. They can be used during batch treatment to lay down a persistent film. They can also be used to lay down a film in vessels such as slug catchers. Oil soluble inhibitors are most applicable in systems where water is the only liquid phase. Once they have been applied to the pipe surface, they generally have a greater film persistency than water soluble or oil soluble–water dispersible inhibitors. Film persistency is a measure of a corrosion inhibitor film’s stability (i.e., ability to remain undisturbed) once it has been applied.

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3.2.2.4 Inorganic Corrosion Inhibitors Corrosion inhibitors may be either organic or inorganic. While organic inhibitors operate by affecting the entire metal surface, inorganic inhibitors operate by affecting just the anodic or cathodic sites. In the oil and gas industry, organic inhibitors that contain amines tend to be the most commonly used. Inorganic corrosion inhibitors are generally metal salts that function by forming a passive layer on the surface of a metal. Inorganic corrosion inhibitors have strict pH and concentration dependencies. In addition, the presence of chlorides tends to disrupt the ability of inorganic inhibitors to function. The two classes of inorganic inhibitors are: •

Anodic

•

Cathodic

Anodic inhibitors cause a shift in the corrosion potential by coating anodic areas of the metal. Anodic inhibitors are further classified as either passivators or non-passivators, depending upon their oxygen requirements. Passivators (chromates and nitrites) do not require oxygen, while the non-passivators (polyphosphates) require oxygen for their reaction. If the concentration of anodic inhibitors is insufficient to cover the anodic regions, severe pitting may form due to the large cathode and small anode areas. Cathodic inhibitors precipitate on cathodic areas, increasing circuit resistance and reducing corrosion rates by restricting diffusion of reactants. Cathodic inhibitors are least effective in chloride containing solutions. One example of a cathodic inhibitor is zinc oxide.

3.2.3 Biocides Biocides are used to mitigate various microbiological problems. Biocides include strong oxidants (such as chlorine), reactive aldehydes (such as glutaraldehyde), quaternary ammonium salts, amines (such as cocodiamine), tetrakis hydroxymethyl phosphonium sulfate (THPS), and acrolein. Some biocides are administered in pure form (e.g., injection of gaseous chlorine), while others are formulated in a solution or carrier (e.g., alcohol and

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diesel). Surfactants or emulsifiers may be added to penetrate or disperse deposits and bio-films. Surfactants (surface-active agents) modify surface properties of liquids and solids by reducing surface tension. This allows penetration of solids by liquids. Most biocides reduce the overall microbial population with little specificity regarding which organisms are targeted. Side effects of biocide treatments include foaming and emulsions. In concentrated form, some biocides have a low pH, making them corrosive. Because of this, applying biocides at improper concentrations can increase corrosion rates. For biocides to be effective, they must come in contact with the bacteria present in the pipeline. Biofilms and solids may provide a layer of protection to bacteria. Therefore, biocide applications are often combined with maintenance pigging. Pigging disrupts surface deposits and biofilms allowing the biocide to reach the pipe surface. Biocides may be injected using batch or continuous methods as described under Section 3.2.1 Application Methods. Additionally, dosing may be used to treat a system. Dosing involves continuous injection of a chemical for a discrete, intermittent time period. For example, a biocide may be injected continuously for 24 hours once a week. The concentration of injected biocide is greater than that used for continuous treatments, but less than that used for batch treatments. Biocides are usually injected as close to the bacteria source as possible. Killing bacteria at their source can prevent the need to treat downstream portions of the system. Different biocides may be example, biocides may be bacterium, but ineffective populations can change and and nutrient availability.

better for different applications. For particularly effective on one type of on another. In addition, bacterial adapt to changes in system conditions

Bio-stats may also be used to limit the growth of microorganisms without killing them. One example of a biostat is anthraquinone. Bio-stats can be used in conjunction with biocides. For example, a biocide applied followed by the application of a bio-stat to inhibit the growth of any remaining bacteria. Using bio-stats in conjunction

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with biocides can reduce the volume of chemical required to treat the system. Corrosion monitoring is performed to verify the effectiveness of biocide treatments. Monitoring of bacteria levels alone is not sufficient; corrosion rates are monitored using coupons, probes, or other techniques. Planktonic bacteria levels do not provide adequate information regarding the biocide’s ability to kill bacteria in contact with the pipe wall. It is, therefore, possible for planktonic levels to be reduced while corrosion rates remain constant. The monitoring program typically includes both sessile and planktonic bacteria analysis. If sessile analyses are not performed, there will be no opportunity to confirm the biocide’s effectiveness. Advantages • Most common mitigation method for MIC •

Can kill the bacteria that are present, whereas other mitigation techniques only try to limit growth

Limitations • Environmental regulations may limit their use and disposal •

Different biocides can be used for different operating conditions and systems

•

Biocides can be corrosive in a concentrated form

3.2.3.1 Resistance to Biocides The concentrations necessary to mitigate sessile bacteria (corrosion associated bacteria) tend to be much higher than for planktonic bacteria. Consequently, the use of higher biocide concentrations and prolonged treatments has resulted in the apparent resistance of bacteria to biocide. Bacteria that have had prolonged exposures to a specific biocide may develop this apparent resistance because of the changes in the biofilm structure and predominant species. Consequently, the efficacy of the biocide treatment diminishes. Methods that may be used to prevent bacteria from developing an apparent resistance to a particular biocide treatment include altering the method of injection or using multiple biocides. Bacteria have been found to develop apparent resistances more rapidly when injection of biocides is at a low continuous rate. Thus, altering the

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injection method may reduce the potential for a decrease in biocide efficacy over time. Switching biocide products periodically can restore effective control in a system developing an apparent resistance to the continuous use of one product. Higherconcentration scheduled batch treatments tend to be more effective in the long term and can be more cost effective.

3.2.3.2 Alternatives to Biocides Alternatives to chemical biocide treatments include changing the environment so that it is not conducive to bacterial growth and biocompetitive exclusion. The first alternative involves changing the environment so that it is not conducive to bacterial growth. This can be achieved by: •

Increasing velocities such that biofilm formation is minimized

•

Removing solids, sludges, and other deposits (mechanically cleaning with pigs)

•

Keeping systems free of suspended solids

The other alternative is biocompetitive exclusion which is based upon the inhibition of SRB through bacterial culture (mostly nitratereducing bacteria), nitrate, or nitrite injection. The basis for biocompetitive exclusion is that microorganisms such as nitratereducing bacteria (NRB) flourish at the expense of SRB.

3.2.4 Scavengers Scavengers are used to react with a particular potentially corrosive species making it unavailable to participate in corrosion reactions. The two most commonly used scavengers in the oil and gas industry are oxygen and H2S scavengers. The scavengers will react with the species in the phase in which the scavenger is soluble. Therefore, it is important that the scavenger be selected for the phase in which species removal is desired. Unlike some potentially corrosive gas removal units, scavengers can be used in systems which contain liquids (crude oil and water). Unused chemical scavengers and/or the products produced by scavenging may have compatibility issues with other chemicals added to the system. The scavengers and/or products produced by

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scavenging may also cause operational issues with downstream equipment (e.g., dehydrators). The concentration and injection rate for scavengers depends on the concentration of the potentially corrosive species to be removed. The reaction time of the scavenger is also considered when determining the injection rate.

3.2.4.1 Oxygen Scavengers Scavengers remove oxygen by a reaction with an oxidizable substance. Sulfites (e.g., sodium sulfite and sodium bisulfite) are commonly-used oxygen scavengers. Equation 3.2 shows the reaction of dissolved oxygen with sodium sulfite to create a sodium sulfate. O2 + 2 Na2SO3 → 2Na2SO4

[3.2]

Oxygen scavenger effectiveness depends on pH. The effective pH range may vary from scavenger to scavenger. Catalysts may be included with the oxygen scavenger to increase the reaction rate. Common catalysts include cobalt and nickel. Manganese, copper and iron ions are also used. Where sulfites are used as scavengers, they can react with other species in the water. For example, sulfites can react with corrosion inhibitors or calcium present in the water. In addition, the catalyst can react with the sulfides present in the water to create insoluble sulfide products. Oxygen scavengers can be corrosive in concentrated form. Scavengers can be incompatible with biocides (e.g. glutaraldehyde).

3.2.4.2 Hydrogen Sulfide (H2S) Scavengers Scavengers remove H2S by a reaction to form a soluble liquid or solid. Triazines and ammonia are commonly used H2S scavengers. Reactions of triazines with H2S can result in an increase in pH, which may impact the scaling tendency. Triazines and ammonias are water soluble; however, oil soluble H2S scavengers are also available. H2S scavenger performance may depend on the concentration of CO2.

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Advantages

•

Can remove potentially corrosive species without the installation of vessels required for other gas removal treatments

Limitations • May be incompatible with other chemicals present or added the pipeline environment, rendering them ineffective •

Can have an impact on water chemistry–changing pH and scaling tendencies

•

Reaction rates can vary between types of scavengers and with temperature and pressure

•

May require additive or catalyst for reaction to proceed

3.2.5 Chemical Cleaning Chemical cleaning involves injecting a chemical into a pipeline system for the purpose of deposit or sludge dissolution. Subsequent removal of the solution containing the dissolved material results in a clean pipe surface. There are generally three main reasons for cleaning an active pipeline: 1. Improving line flow efficiency 2. Improving data quality from in-line inspection tools 3. Improving results of inhibitor/biocide programs Chemical cleaning is sometimes performed as a batch application between pigs. Pigs are often used to remove the solution from the line after the dissolution is complete. Condensate film and foreign particles can interfere with the action of cleaning chemicals, thus reducing the effectiveness of the cleaning chemical. Maintenance pigging prior to the application of a cleaning chemicals helps to ensure that the chemicals reach the area/solids of interest (i.e., solids that are not easily removed by mechanical means). Cleaning chemicals can be corrosive to carbon steel, so precautions should be taken to ensure that corrosion is not accelerated by the cleaning chemicals. Advantages

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•

They can improve the effectiveness of other chemical treatments

•

They can also improve the quality of inspection data

Limitations • They can be potentially corrosive •

They can pose compatibility issues with other chemicals added to the pipeline environment

3.3 Design and Operation 3.3.1 Water Removal There are several methods of water removal prior to it entering a pipeline including: •

Separation

•

Dehydration

•

Coalescence

Separation is done as a first stage process to remove free water from the product stream. Dehydration and/or coalescence are then used to remove water vapor and water droplets from the stream. Separation, dehydration, and coalescence units are generally considered during the design phase of a pipeline project. However, it is possible to add these units to an existing pipeline. Separation, dehydration, and coalescence units are detailed in Chapter 4.

3.3.2 Removal of Potentially Corrosive Gases Potentially corrosive gases can be removed using: •

Amine scrubbers (remove CO2 and H2S)

•

Membrane units (remove CO2)

•

H2S scavenger units (remove H2S)

•

Catalytic combustion processes (remove O2)

Gas removal units are normally considered during the design phase of a pipeline project. However, it is possible to add these units to an

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existing pipeline. Amine scrubbers, membrane units, H2S scavenger units, and catalytic combustion processes are discussed further in Chapter 4.

3.3.3 Modifying Flow Characteristics Flow modifications include increasing or decreasing the flow rate. Stagnant conditions result in water and solids separation and accumulation. Where pipeline operations can be modified to prevent no-flow conditions from occurring (or reduce that amount of time that no-flow conditions exist), the potential for internal corrosion is reduced. For liquid petroleum lines with low water cuts, increasing the flow rate can entrain water creating a water-in-oil dispersion, which decreases the potential for corrosion to occur. Flow modeling can be performed to determine the flow rate at which entrainment will occur. For systems with multiphase flow, there may be locations along the pipeline (e.g., inclines) where water and solids accumulate. Where accumulation is occurring, the flow rate can be increased to sweep water (and potentially solids) through the line. Flow modeling can be used in order to determine a sufficient flow rate to prevent water accumulation. Often, the flow rate cannot be increased on a permanent basis, but can be increased occasionally. In such cases, line sweeping acts in a similar fashion as pigging. In general, pigging is a more effective means to remove accumulated liquids and solids. However, the volume of water and ability to pig the line should be considered when selecting between pigging and line sweeping. For pipelines that experience erosion-corrosion, decreasing flow rates can lead to a decrease in corrosion rate by reducing the removal of protective films. In systems where solids are present, the flow rate is usually maintained at a level where solid deposition does not occur.

3.3.4 Physical Design Changes In some cases, there are physical design changes that can be made to help prevent internal corrosion from occurring. These changes typically involve reducing or eliminating the potential for water

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accumulation to occur. Examples of common design changes include: •

Removing low spots

•

Removing dead legs

•

Removing couplings or other features that create crevices

•

Replacing existing pipe with smaller diameter pipe to increase fluid velocity to aid in sweeping liquids, or prevent coalescence of water

•

Installing drips (gas lines)

•

Making the pipeline piggable

Low spots can be removed during pipeline replacements or reroutes. For localized low spots, it may be possible to fill in the low spot or re-route the pipeline around the low spot. This becomes impractical for steep, lengthy inclines and locations where water crossings are present. Aerial crossings or spans can also be considered where corrosion is known to occur at low spots associated with water crossings. Dead legs created by flanged or capped tees can be removed by replacing the tee with a straight section of pipe. Weld caps on headers may be replaced by flanges or hinged covers which can allow for the headers to be cleaned and/or inspected. Couplings used to join two sections or joints of pipe create crevices in the pipeline. Water and solids can settle in the crevices and create corrosive environments. Couplings can be replaced with welded joints to reduce the potential for crevice corrosion to occur. Pipe replacement can be used to aid in-line sweeping in systems where water accumulation occurs and the flow rate cannot be adjusted. Decreasing the pipe diameter is most likely to be a viable option when pipe replacement is already being performed for other reasons. The diameters of isolated sections such as low points can be reduced; however, changing the diameter of isolated section may make the line unpiggable. Drips can be installed on gas lines to help remove water in the pipeline. Drips are typically installed on lines where water is known to exist (or upsets can possibly occur) but where there is no other

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means for water removal. Drips are installed at low points or other locations where liquids are likely to accumulate. If installed, drips must be properly maintained to remove liquids. Solids can accumulate in drips creating an increased potential for corrosion to occur. Some new drip designs allow for pigging or cleaning the drip. Drip installation is normally considered during the design stage and is further discussed in Chapter 4. Pipelines can be made piggable by removing: •

Sections of pipe with changing diameters

•

Valves that prevent the passage of pigs

•

Tight bends or turns (e.g., offsets at roads)

If pigging is going to be done on a routine basis, launchers and receivers must be added.

3.4 Selecting and Implementing Appropriate Methods Selection of the appropriate mitigation method(s) should be based on the corrosion mechanisms affecting the system, system design, expected corrosion severity, cost, risk, and company preference. Pigging is frequently selected as a mitigation method, either as a stand alone technique or in conjunction with chemical treatment. For existing systems, the presence of numerous offsets, tight bends or turns, or changing diameters can make it potentially unfeasible to make a pipeline piggable. The ability to effectively apply chemical treatment should also be considered before eliminating pigging as a mitigation option. For some pipeline systems such as upstream lines, chemical treatment using an inhibitor or biocide may be the preferred means to mitigate internal corrosion. However, for downstream systems where design methods or mechanical means can be used for corrosion mitigation, chemical treatment may be a company’s last choice.

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3.5 Effectiveness of Mitigation Method The effectiveness of mitigation is determined by monitoring or inspection. Various monitoring and inspection methods were discussed under Section 3.2 Chemical Treatment and Section 3.3 Design and Operation. Monitoring and inspection results obtained prior to implementation of mitigation (i.e., uninhibited system), can be compared to results obtained during mitigation to verify that corrosion rates are reduced to an acceptable level. For systems where baseline data (i.e., monitoring and inspection results of uninhibited systems) are unavailable, monitoring and/or inspection results may be used to verify that corrosion rates are acceptable. However, the monitoring and/or inspection results cannot be used to assess the reduction of corrosion rates achieved by the current mitigation method(s). When applying chemical treatment, monitoring and/or inspection results from both upstream and downstream of the chemical injection point can be used to determine the effectiveness of the mitigation method.

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Chapter 4: How Do I Design To Prevent Corrosion? Overview In the previous chapters, discussion focused on the identification, assessment, and mitigation of internal corrosion on in-service pipelines. However, internal corrosion can also be minimized and/or prevented, during the design stage. When designing a new pipeline, internal corrosion control measures may include: •

Materials selection

•

Modification of the environment

•

Elimination of features that can lead to corrosion

•

System configuration

•

Operating parameters

•

Mitigation methods

It is important to note that once a pipeline is designed and constructed, the options for controlling internal corrosion listed above are usually significantly curtailed. Therefore, prior to the selection and implementation of any of the above methods, it is important to characterize the “anticipated” environment.

4.1 Define the Service Environment Various types of pipeline services were discussed in Chapter 1. The type of pipeline must be known to appropriately assess the corrosion environment with respect to the following topics.

4.1.1 What is the Expected Product Quality Whether or not water is expected to exist in the product stream is crucial to determining what, if any, action(s) should be taken to prevent corrosion. For pipelines where water is expected to be present and can not be prevented from entering the system, the anticipated volume and water chemistry should be predicted based

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upon past experiences and/or industry guidance. Potential changes in volume over time should also be considered — especially for production systems. The type (e.g., produced sand, paraffins, asphaltenes, etc.) and amount of solids expected should be estimated. For systems where sand production is expected, the potential for erosion or erosioncorrosion should be considered (see Section 1.3.9.2 High Flow). Microorganisms and their source should also be anticipated. Finally, the gas quality should be considered. This involves anticipating the typical and maximum CO2, H2S, O2, and water vapor contents.

4.1.2 What are the Expected Operating Conditions? When predicting the impact of operating conditions on internal corrosion, it is important to consider both normal and abnormal conditions. Abnormal conditions include periods of upsets or shutdowns where temperatures, pressures, and flow may deviate significantly from that observed during normal operations. Although variations from the normal operating conditions may be brief in duration, they can impact the corrosion severity of the environment. For example, temperatures below the normal operating conditions may result in top-of-line (TOL) corrosion in the presence of acid gases.

4.2 Corrosion Form/Rate Prediction Corrosion type and rate predictions are often based upon past experiences. When past experiences are not applicable, industry guidance and corrosion modeling may be required.

4.2.1 Past Experiences When using past experiences to predict corrosion forms and rates, it is important to have complete knowledge of the pipeline (i.e., the existing pipeline). This should include: •

Service conditions

•

Material selection

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•

Equipment

•

Design geometries

•

Type and frequency of maintenance

•

Repairs and replacements

•

Type and frequency of mitigation methods

•

Any maintenance deviations from original specifications

The new pipeline should be similar to the pipeline to which it is compared. Where differences exist in service conditions, the potential impact on internal corrosion should be considered.

4.2.1.1 Non-Corrosive Systems Similar systems, where it has been established that internal corrosion is not a problem (in the absence of mitigation), can be used to help establish that internal corrosion is not expected to be a problem.

4.2.1.2 Effectively Mitigated Systems Similar systems, where it has been established that the mitigation strategies have been implemented to reduce or prevent corrosion, do not necessarily provide information regarding unmitigated corrosion rates. However, the mitigation strategies may be applied to the new system.

4.2.1.3 Monitoring/Inspection Results Monitoring results for similar systems can be used to estimate corrosion rates. It is important to consider what, if any, mitigation methods were being applied at the time of monitoring. This includes chemical concentration and pigging frequency. Inspection results for similar systems can be used to predict expected forms of corrosion. It is important to consider what, if any, mitigation methods were applied over the life of the pipeline.

4.2.1.4 Internal Corrosion Failures Visual examinations, chemical analysis, and metallurgical analysis associated with past internal corrosion failures can provide information on the conditions that lead to a particular failure.

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Figure 4.1 shows a failure associated with a pipeline drip. Information can also be ascertained on the form and mechanism of corrosion attributed to the failure. Metallurgical analysis can provide information on the influence of design (e.g., crevices, high stresses), material deficiencies, fabrication (e.g., machining, assembly, welding, etc.), and the environment on the failure.

Figure 4.1 Results of a Drip Failure

4.2.2 Industry Guidance Industry guidance in the form of recommended practices, technical reports, handbooks, and computerized reference databases can be used to predict corrosion rates or estimate the corrosion severity for particular service conditions. When possible, the information should be based on in-service experience.

4.2.3 Corrosion Modeling Corrosion rate modeling can be performed using anticipated water chemistry, gas quality, temperature, and pressure to estimate corrosion rates. Some corrosion rate models may be able to predict corrosion rates for multiple materials.

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4.3 Design Features It may be possible to prevent potentially corrosive species (e.g., water, H2S, and CO2) from entering the pipeline. This is often accomplished by incorporating units that remove water and potentially corrosive gases prior to entering the pipeline.

4.3.1 Removal of Water Water removal is the first design mitigation technique that is considered. The potential for internal corrosion is greatly reduced if water can be prevented from entering the system. The various methods for removing water are described in the following sections.

4.3.1.1 Separation Separation often involves multiple stages. Separation vessels can be incorporated into a pipeline to remove one or more fluids from the product being transported. Separation is often performed as a first stage process to remove free water from the product stream. Separation vessels may be horizontal or vertical, the operation and design of which is very similar. Figure 4.2 and Figure 4.3 show horizontal and vertical separators. The main differences are in designed pressure drop, residence time required for desired separation, and processing capacity for a given separator volume. Separation vessels need to be sized based on the anticipated maximum flow of each fluid.

Figure 4.2 Horizontal Separators

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Figure 4.3 Vertical Oilfield Separators

Centrifugal or cyclone separators use centrifugal forces to separate solids or liquids from gas. They are typically used in situations where the volume of solid or liquid is small compared to the volume of gas or where the size of the solid particles or water droplets is small. Types of separation include: •

Liquid-gas

•

solid-gas

•

Liquid-liquid

•

Liquid-liquid-gas

Liquid-gas separation is used to remove liquids from natural gas. Examples of liquid-gas separation equipment include scrubbers, separators, and slug catchers. Figure 4.4 shows an example of a slug catcher. A mist extractor, comprised of wire mesh or vanes, can be present inside the separator. Liquid droplets impinge on the mesh or vane, coalesce and drop out of the gas stream. Droplets greater than 10 microns are typically removed when mist extractors are present. It is critical to note that the gas leaving these types of equipment is

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still saturated with water and any pressure and/or temperature drop can result in condensation.

Figure 4.4 Slug Catcher

Solid-gas separation is used to remove solid particles that may be present in the gas stream. Solid particles can be removed through the use of a filter within a separator. Solid separation may occur at the same time as liquid separation. Liquid-liquid separation can be used to remove water from crude oil. This is done by the use of internal baffles. The crude oil enters the first “chamber” of the separator and is retained through the use of an internal baffle. Water settles to the bottom of the chamber and is removed. Oil floats to the top of the water and is allowed to spill over the internal baffle. Liquid-liquid separation can be accomplished in both horizontal and vertical separators, although it is primarily performed using horizontal separators. The water separation is gravity driven; therefore, residence time is an important consideration during separator design. Demulsifiers and/ or temperature can significantly reduce resident time requirements. Liquid-liquid-gas separation is similar to liquid-liquid separation, with an additional outlet for gas. Normally, an internal mist extractor is used to reduce the amount of liquid droplets present in the exiting gas stream.

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Factors to consider when determining whether the application of separators is feasible include: •

Location – Can a separator be installed at the inlet of the pipeline?

•

Product volume – Can the appropriate size and/or number of vessels be installed to handle the anticipated volume of product?

•

Liquid removal – How will liquid be removed from the vessel (e.g., manual or automated)?

•

Frequency of liquid removal – How frequently does the vessel need to be drained based upon anticipated liquid volumes?

•

Liquid disposal – How will collected liquids be disposed?

4.3.1.2 Dehydration/Dewatering Dehydration is the process of removing water vapor from a gas stream. Dewatering is the process of removing water from liquid hydrocarbons. Dehydration is generally done following separation unless there are not any free water or solids present in the product stream. Table 4.1 lists the primary dehydration/dewatering methods for natural gas and crude oil. Table 4.1: Primary Water Removal Methods for Natural Gas and Liquid Hydrocarbon Pipelines Gas Dehydration

Liquid Hydrocarbon Dewatering

Joule-Thompson expansion Solid desiccant Liquid desiccant

Electrostatic Heat Chemicals Time (gravity)

Factors to consider when determining whether the application of dehydration is feasible include: •

Location – Can a dehydrator be installed at the inlet of the pipeline?

•

Product volume – Can the appropriate size and/or number of dehydrators be installed to handle the anticipated volume of product?

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•

Water content – Can the inlet water vapor content be reduced to the desired content of the outlet stream?

•

Regeneration – How frequently will units need to be regenerated?

•

Presence of liquids (gas only) – Are liquids present in the stream or can upsets occur?

4.3.1.2.1 Gas Dehydration Dehydration of natural gas is typically done so the gas will meet pipeline specifications (which are not necessarily corrosion related). Typical specifications for water content are a maximum of 64 - 112 kg/MMSCM (4-7 lbs/MMSCF). There are three primary methods of dehydration for natural gas: 1. Joule-Thompson expansion 2. Solid desiccant 3. Liquid desiccant 4.3.1.2.1.1 Joule-Thompson Expansion Although not commonly used, dehydration by Joule-Thompson expansion involves expansion of the gas (i.e., pressure is reduced), using a choke valve. This results in temperature decreases, causing moisture to condense. The amount of water removed depends on the temperature of the gas upstream of the choke and the pressure differential across the choke valve. The lower the gas temperature upstream of the choke valve, the more water can be removed for the same starting water content and pressure differential. Hydrate inhibitors may be used to prevent the formation of hydrates as the temperature of the gas is reduced. Natural gas liquids can also be produced during Joule-Thompson expansion. Because a large pressure drop is needed to cool the gas enough to remove water, the line must either operate at a much lower pressure than the input line or the gas must be compressed after the expansion process. Additionally, there must be a means (e.g., a separator) to remove the water and natural gas liquids that are produced.

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4.3.1.2.1.2 Solid Desiccant Solid desiccant dehydration is achieved by passing gas through a bed of solid desiccant such as silica gel, activated alumina, or a molecular sieve (zeolite). The moisture in the gas is adsorbed into the solid desiccant. The moisture evaporates from the desiccant and enters the regeneration gas stream. This gas stream is then either burned or cooled and passed through a separator to remove the water. It is then dehydrated and added to the normal gas stream. Typically, at least two solid desiccant adsorption towers are required because of the need to regenerate the desiccant. Solid desiccant units can result in pressure drops ranging from 0.07 – 0.35 MPa (10 – 50 psi). Disadvantages of solid desiccant dehydration are that the desiccant is susceptible to fouling from heavy hydrocarbons, poisoning from corrosive constituents such as H2S and CO2, or physical degradation. The solid desiccant is regenerated by passing heated gas through the bed. 4.3.1.2.1.3 Liquid Desiccant Liquid desiccant dehydration is the most commonly used dehydration method. Liquid desiccant dehydration is achieved by passing gas through a glycol contactor. Diethylene and triethylene glycol (DEG and TEG, respectively) are typical liquid desiccants. The gas is passed through a counter current liquid contactor; normally a bubble cap tray column or a packed bed. As the glycol absorbs water, it becomes water-rich. The water-rich glycol is removed from the bottom of the dehydrator and fed into a reboiler, where the water is boiled off. The water vapor and any natural gas that was absorbed by the glycol are vented off the top of the reboiler. The regenerated glycol is recycled back to the top of the dehydration column. Glycol dehydration only results in a small pressure drop of 0.03 – 0.07 MPa (5 – 10 psi). This is an advantage when the input line is the same or similar pressure to the operating pressure of the line. Another advantage to this method is that, in general, less heat per pound of water removed is required for glycol than for solid desiccant. One disadvantage of glycol dehydration is that glycol is corrosive when contaminated or decomposed. Common contaminants in glycol dehydration units include:

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•

Free water (including brine)

•

Liquid hydrocarbons

•

Corrosion inhibitors

•

Biocides

•

Other treatment chemicals

•

Solids

These contaminants can enter the dehydration unit if there is not a separator prior to the dehydrator or if inadequate separation occurs. If a glycol upset occurs, potentially corrosive species can then be introduced into the pipeline. A pipeline system design consideration would be to install a separator, or other vessel ,downstream from a glycol dehydrator, to prevent any glycol upsets from entering the line. Figure 4.5 shows a glycol dehydration unit.

Figure 4.5 Glycol Dehydration Unit

4.3.1.2.2 Liquid Dewatering After primary separation, hydrocarbon liquids with less than 10% water (generally in an emulsion) can be dewatered via four methods: 1. Electrostatic treatment

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2. Heat 3. Chemicals 4. Time (gravity) 4.3.1.2.2.1 Electrostatic Treatment Electrostatic treatment uses an applied voltage to polarize water droplets within a crude oil emulsion. The polarized water droplets elongate, become attracted to one another, and coalesce. The coalesced droplets then settle out to the bottom of the vessel by gravity. Historically, alternating current (AC) was used for electrostatic treatment. However, newer designs can utilize either alternating or direct current. 4.3.1.2.2.2 Heat Treatment Heat treatment consists of using a heater or treater to increase the temperature of the crude oil. Heating results in a decrease in the crude oil viscosity. As a result, there are more collisions between water droplets. These increased collisions allow more droplets to coalesce and drop out. Heating the crude oil can vaporize some of the more volatile hydrocarbons. If these volatilized hydrocarbons can not be returned to the liquid state, loss of product due to heat treatment must be considered. High temperatures within the heater may cause coke deposits to form on the fire tubes within the heater. The coke deposits can decrease the efficiency of the heater and may result in failure of the heater tubes. 4.3.1.2.2.3 Chemical Treatment Chemical treatment consists of using a demulsifier (e.g., emulsion breaker), which destabilizes the emulsion. The amount of time required for the separation of the water and crude oil to occur, as well as the completeness of the separation, depend on the selected demulsifier. A separation vessel is required downstream from the addition of the demulsifier to remove the water that separates from the crude oil.

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Demulsifiers are surface-active agents which have properties making them effective in disrupting the effect of the natural emulsifiers present in the oil. Their initial action is at the water-oil interface. The “skin” surrounding the water droplets in the emulsion prevents the water droplets from uniting. Demulsifiers work to join water droplets together and then disrupt the skin surrounding individual droplets allowing the droplets to coalesce. 4.3.1.2.2.4 Time/Gravity Liquid hydrocarbon can be dewatered by gravity over a period of time. Liquid hydrocarbon is allowed to remain stagnant in a separation vessel or other unit. Water droplets that will not settle out of the liquid hydrocarbon while the product stream is flowing are allowed to separate from the crude oil. The use of time as a dehydration method may be used in conjunction with other dehydration methods.

4.3.2 Removal of Corrosive Gases Various scrubbers and units may be installed at the design stage to remove or reduce the amount of potentially corrosive gas that enters a pipeline. Units include: •

Amine scrubbers

•

Membrane units

•

H2S scavenger units

•

Catalytic combustion processes

Each unit is described in detail below. Questions to consider when determining whether or not to install units to remove potentially corrosive gases include: •

Sales requirement – Is removal of potentially corrosive gases required to make gas saleable?

•

Location – Can the unit be installed at the inlet of the pipeline?

•

Gas volume – Can the appropriate size and/or number of units be installed to handle the anticipated volume of gas?

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•

Potentially corrosive gas concentration – Can a unit reduce the concentration of the potentially corrosive gas to a level to which internal corrosion is not a problem?

•

Corrosion inhibitor – Can a corrosion inhibitor be used to effectively mitigate corrosion?

•

H2S and CO2 gas disposal – How will removed gases be disposed?

4.3.2.1 Amine Scrubbers Amine scrubbers can be used to remove carbon dioxide and hydrogen sulfide from the natural gas phase. Amine scrubbers normally use an aqueous amine (alkonalamine) or other solvents, such as diethanolamine (DEA) or methyldiethanolamine (MDEA), to absorb any CO2 and H2S present. Solvent selection is critical, as different types of amines have varying selectivity to CO2 or H2S. Therefore, solvent selection is usually based on whether CO2, H2S, or both need to be removed from the gas stream. It is important to note that the presence of oxygen in the gas stream can have an adverse effect on the amine. Also, environmental regulations may limit the emission of CO2 and H2S into the atmosphere during the regeneration process.

4.3.2.2 Membrane Units Membrane units use polymer based membranes (e.g., cellulose acetate) to remove CO2 from a gas stream via selective permeation. Membrane units operate by allowing gases to permeate and diffuse through the membrane. Different gases will have different solubility and diffusion rates. Therefore, gas removal is governed by the solubility of the gas in the membrane and its diffusion rate through the membrane. Since CO2 permeates and diffuses through the membrane at a faster rate than methane and other hydrocarbons, CO2 can be separated from the hydrocarbons. Complete separation of the CO2 and hydrocarbons is not always achieved, so some hydrocarbon gas can be lost in the stream of CO2 that is removed. To reduce hydrocarbon losses, a multiple stage unit can be used.

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4.3.2.3 H2S Scavenger Units In addition to amine scrubbers, H2S scavenger units can be used to remove H2S from the gas stream. The units can be used to reduce the H2S content of the gas to less than 1 ppm. H2S scavenger units are generally only used if the inlet concentration of H2S is very low. Otherwise, this technique becomes cost-prohibitive. H2S scavengers can be liquids, solids, or catalysts. The scavengers remove H2S by reacting with H2S. Most solid scavengers use a reaction with some form of iron to remove the H2S, producing iron sulfide (FexSy). Iron “sponges” have also been used to remove H2S. The “sponges” are composed of wood shavings that are saturated with iron oxide powder. The H2S in the gas reacts with the iron oxide and produces ferric sulfide. Generally, a wet gas is required or the sponge loses its reactivity. Sponges must be replaced periodically.

4.3.2.4 Catalytic Combustion Catalytic combustion can be used to remove oxygen from natural gas. Prior to the combustion, the gas stream is passed through a filter separator to remove any solid particles that could foul the catalyst used in the combustion process. The combustion process results in the production of water and CO2. Therefore, water separation and CO2 removal may be required downstream of the combustion. The life span of the catalyst depends on the gas flow rate and the oxygen content of the gas. Oxygen scavengers can also be used to remove oxygen, as discussed in the Section 3.2.4.1 Oxygen Scavengers.

4.3.2.5 Drips Drips can be installed on gas lines to help capture and remove liquids in the pipeline, thus reducing internal corrosion. Available in a variety of designs, drips can range from a short pipe section that is tied into the pipeline to larger configurations that are fully incorporated into the mainline. Figure 4.6 shows a pipeline drip installed at the 6 o’clock orientation. In order to capture any “free” liquids, drips should be installed at the 6 o’clock orientation (bottom of the pipe). As previously stated, drips are generally installed at low point areas or other locations where liquids are likely to accumulate.

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If drips are installed, they need to be inspected regularly and properly maintained to remove liquids. Solids can accumulate in drips, creating an increased potential for corrosion to occur. Figure 4.7 shows solids that have accumulated in a pipeline drip. Some new drip designs allow for pigging or cleaning of the drip.

Figure 4.6 Pipeline Drip Installed at 6 o’clock Orientation

Figure 4.7 Solids That Have Accumulated in a Pipeline Drip

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4.3.3 Geometry – Physical Design Changes In some cases, there are physical design changes that can be made to help prevent internal corrosion from occurring. These changes involve reducing or eliminating the potential for trapped water to accumulate. Design methods used to reduce water accumulation include minimizing low points and crevices. Often, it is easier to minimize low points within the system than crevices, as joints and connections that form crevices are inevitable in a pipeline system. Where crevices cannot be eliminated, steps to minimize the potential for corrosion at crevice locations should be employed. These steps include ensuring that the material matches the service conditions and preventing the ingress of potentially corrosive species into the crevice. Factors to consider when determining the feasibility of physical design changes include: •

Crossings – Are there water, rail, or major road crossings?

•

Dead legs – Do any dead legs exist on the pipeline?

•

Major low points – Are there major low points that can not be avoided?

4.3.4 Inspectability/Accessibility Frequently overlooked, access for inspection and maintenance tools should be considered during the design stage.

4.3.4.1 Piggable Lines If possible, pipelines should be designed to be piggable. There are some exceptions, including distribution systems. Pig launchers and receivers are required to pig the system (whether permanent or temporary). Pig launchers and receivers are pressurized vessels, installed at the beginning and end of pipelines to facilitate cleaning and inspection. These vessels are used to introduce and retrieve pigs (intelligent or maintenance) from the pipeline. Although launchers and receivers may be added to an existing pipeline, it is more economical to install them during the original construction. Additional items that should be considered when designing a piggable line:

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•

Full bore valves and adequately sized fittings (to allow passage of pigs) should be used

•

Bends should be no less than 1.5 times the pipe diameter

•

Multiple pipe diameters should not be used

•

Valves should be the same size as the pipe, e.g., 508 mm (20 in) valves should not be used on a 610 mm (24 in ) diameter pipeline

•

All tees into which a pig may fit should be barred

When pipelines cannot be designed to be piggable, consideration should be given to installation of ports/taps that allow tethered tools entry into the piggable sections of the line.

4.3.4.2 Monitoring Access Points As discussed in Section 1.3.3 Monitoring and Section 2.2 Monitoring Techniques, corrosion monitoring is a key component in determining the existence and severity of internal corrosion within a pipeline. In addition, monitoring is an integral component when assessing the effectiveness of mitigation methods. Thus, it is useful to ensure that a pipeline can accommodate monitoring devices during the design stage.

4.4 Materials Selection Once the service environment and material performance requirements have been defined, candidate materials (metallic or non-metallic) can be identified. Metallic materials generally consist of specific combinations of elements (alloys) that, when combined, yield improved properties such as strength and corrosion resistance. Non-metallic materials generally refer to materials such as plastics, ceramics, or composites. Refer to Appendix C for material properties. Pipeline environments are rarely free of corrosion. Thus, during the design stage, acceptable levels of corrosion performance should be established and defined. An acceptable level of corrosion is defined as corrosion that has minimal impact on system performance. Acceptable corrosion limits are defined by the operating company and may vary between companies.

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Carbon steel is the predominant material of choice for pipelines, with two main exceptions. For distribution systems, cast iron, plastic, or other materials may be used due to the low pressures. Alternative materials should be considered for systems such as multiphase production pipelines where corrosion rates are expected to be high. For these systems, two options for material selection generally exist. The first option is to use carbon steel with some means of corrosion control (e.g., chemical treatment, internal coatings, liners, cladding). When the corrosion rates of carbon steel can not be acceptably reduced with some means of mitigation, the second option typically is to use a corrosion resistant alloy. Table 4.2 provides a comparison of some material selection options. Table 4.2: Material Selection Comparison Carbon Steel

Strength Ductility/ Toughness Weldability Corrosion resistance Resistance to EAC Manufacture and Installation Costs Availability Costs of operation

CRA Clad Carbon Steel

CRA

SMYS 175 – 830 MPa (25.4 – 120.4 ksi)

SMYS 290 – 552 MPa (42 – 80 ksi)

SMYS 207 – 448 MPa (30 – 65 ksi)

Very good

Marginal/good

Good/very good

Good/very good

Fair/Good

Fair/good

Marginal

Very good

Very good

Good/very good

Very good

Marginal

Fair

High/very high

High/very high

Good High for corrosive fluids

Fair

Poor/fair

Low

Low

When selecting a material for a particular application, it is important to consider the most cost effective solution that meets the defined corrosion performance and environmental and safety requirements. Life cycle costing, as described in this chapter, should be used when identifying cost effective solutions. The process for selecting the appropriate material for a specific application can be determined based on the questions listed in the sections below.

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4.4.1 Is the Material Suited to the Environment? Often, once the service environment and operating conditions are defined, materials can be excluded as candidate materials. For example, some thermoplastics are not suited for applications that exceed 60ºC (140ºF). Similar exclusions can be made based upon a material’s incompatibility with the media transported.

4.4.2 Can Carbon Steel Be Used? When considering the use of carbon steel, it is important to determine if the expected corrosion rates of carbon steel are acceptable or if mitigation measures would be needed to reduce corrosion rates to an acceptable level. Mitigation involving the application of internal coatings, liners, and cladding can be used to reduce corrosion rates of carbon steel when deemed necessary. Internal coatings, liners, and cladding are discussed below.

4.4.2.1 Protective Coatings Internal coatings are organic or inorganic materials that are applied over a carbon steel substrate to minimize corrosion attack. Internal coatings mitigate corrosion by providing a protective barrier between the environment and the metal surface. In addition, internal coatings can also impact product throughput by reducing friction loss. Finally, the presesnce of internal coatings may assist in controlling corrosion deposit formation (e.g., iron carbonate). Internal coatings will not prevent the deposition of such things as paraffins. Generally, internal coatings are composed of organic materials, but they may also be composed of inorganic materials. Organic coatings contain carbon to carbon bonding. Internal coatings are classified as thin films (< 0.25 mm thick [< 10 mils]) or medium films (0.25 – 0.41 mm thick [10 – 16 mils]). The use of thin or medium films will depend on the coating type and application. Table 4.3 lists the materials, applications, and limitations of each class of internal coating.

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The following steps can be taken to help ensure a good internal coating: •

Selection of the appropriate coating

•

Proper surface preparation (cleaning and blasting)

•

Coating of girth welds or joints

•

Proper coating application

•

Proper cure

•

Timely inspections

•

Proper handling of coated equipment

•

On site inspection prior to installation

Not following these steps may result in a coating failure. For example, improper material selection for the environment can lead to attack of the coating by acids and SCC of the underlying metal. Excessive coating thicknesses can lead to blistering, delamination, or cracking of the coating due to internal stresses. Similarly, inadequate coating thicknesses can result in holidays (areas of bare metal) where corrosion can occur. Finally, improper cures can result in loss of adhesion, blistering and disbonding (solvent entrapment), poor chemical resistance, or contamination of the transported media. Special consideration is necessary for coating girth welds or joints. Coatings in these areas are often applied in the field, so surface preparation is critical. Internal coatings are typically used when other control methods are either not economical or practical and when internal corrosion is expected to exist within the system. The decision to use an internal coating is usually based on economics and the ability to coat the pipe material. From an economics standpoint, internal coatings can add 17 - 21% to the initial cost of the pipe. Pigging, especially using scraper pigs, can cause damage to internal coatings. These coating holidays can result in the formation of localized corrosion cells depending on the environment.

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Table 4.3: Examples of Internal Coatings

Thickness mm (mils)

Material

0.25 (< 10 mils)

High bake phenolics and its modifications

0.25 – 0.41 (10 – 16 mils)

Powdered epoxies Modified urethanes Epoxies

Inhibition

Best controlled in combination with inhibition.

Seldom used in conjunction with inhibition

Applications

Limitations

Oil and gas service Water injection when CO2 or other corrosive gases also injected

Subject to abrasive damage

Water production environments Many oil and gas environments

Better impact and abrasion resistance than thin coatings

4.4.2.2 Cement Mortar Lining (CML) Cement Mortar Lining (CML) is a centrifugally applied continuous lining of dense Portland cement mortar with a smooth and uniform finish. The primary application is for produced water pipelines; both disposal and high-pressure injection situations. The operating temperature ranges between -40ºC and +300ºC (-40ºF to +572ºF). However, normal operating temperatures are usually limited by the external pipeline coating. It can be applied to pipe diameters ranging from nominal pipeline size NPS 2 through NPS 24 sizes in lengths between 10 and 25 m (33-80 feet). As with any internally coated pipe, care in handling is mandatory to ensure no damage to the coating is incurred prior to introduction of corrosive fluids.

4.4.2.3 Elastomeric Liners Similar to coatings, liners mitigate internal corrosion by providing a protective barrier between the susceptible pipe material and the produced corrosive fluids. In contrast to internal coatings, liners consist of sheets of thermoplastics or elastomers that are applied or bonded to a substrate. Liners may be employed for short-term corrosion protection, long-term corrosion protection, or friction reduction. When used for corrosion protection, liners should be

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continuous and physically intact. This includes covering weld areas and areas of repair. When application of a continuous, intact liner for corrosion protection is not feasible, inhibitors commonly supplement the mitigation technique. Materials used as liners are generally semi-crystalline and thermoplastic. The liners are mechanically fit to the pipe via expansion of the liner or compression of the pipe. Liners can be as much as 2,000 meters long, depending on diameter and topography. Pipeline construction is such that flanges are installed and the liners are pulled between the flanged sections. For polyethylene liners, a polyethylene flange is “welded” onto the liner and then allowed to collapse against the steel flange, ensuring that no metal is directly exposed to the pipeline environment. Prior to employing liners, the environmental conditions must be assessed, since liner materials may be susceptible to failure by collapse or buckling under certain conditions. Ideally, these materials should have excellent chemical resistance and stability, tear strength, temperature resistance, and elastic modulus. They should also be economical, widely available, and easily installed. Further considerations during material selection should include common cleaning practices. The liner should be able to withstand any chemical or mechanical (pigging) methods of cleaning. High density polyethylene (HDPE) is one such material that is used in gathering and transmission pipelines. This material has proven to have long term chemical resistance to various oilfield environments, including sour brine. Liners should be vented on a regular interval to prevent collapse, should pipeline pressure drop, or to prevent corrosion between the liner and pipe wall.

4.4.2.4 Cladding Cladding is a mitigation method that involves bonding different metallic materials together to form an inseparable composite. Cladding is used as a means to achieve acceptable corrosion rates at an economical cost. For example, plain carbon steel can be bonded to a corrosion resistant alloy (e.g., 316 stainless steel, Alloy 825, or Alloy 625). In this case, the carbon steel provides the mechanical strength and is cost effective, while the CRA provides the corrosion resistance. In addition, cladding is also designed to resist wear and abrasion.

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During the cladding process, materials may be bonded mechanically or metallurgically. Mechanical bonding is done by hydraulic shrink fitting or explosively bonding the CRA to the base metal. Metallurgical bonding is achieved through co-extrusion, roll bonding, weld-overlay, or centrifugal casting. For both mechanical and metallurgical joining techniques, bonding is achieved by some means of deformation that breaks up surface oxides and creates metal-to-metal contact. The heat associated with the deformation assists with the bonding between the materials, as none of the materials are molten during the bonding. The techniques differ in the amount of deformation and heat used to form the bond and in the manner in which the metals are brought into contact. Cladding thicknesses will vary according to the joining technique used. For example, roll bonding typically produces sheet-type products less than 5 mm (0.02 in) thick. In contrast, explosion bonding is used for thicker products up to 510 mm (20 in). It is important to note that some materials are more difficult to bond. For example, metals such as chromium are difficult to bond due to its low ductility. Stainless steels and aluminum alloys can also be difficult to bond due to their adhesive oxide films.

4.4.2.5 Selecting and Implementing Appropriate Mitigation Methods Mitigation using internal coatings, liners, or corrosion resistant alloys (CRA) can be selected when the expected corrosion rate cannot be appropriately controlled using other means (chemical or mechanical), or when their use is preferred by the company. Internal coatings, liners, and CRAs are normally selected during pipeline design. Although it is possible to install a lining once a line is already in service, any water or solids that are not removed from the pipeline service can become trapped on the pipeline surface below the lining. The cost of internal coatings, liners, and CRAs should be compared to the cost of mitigating through mechanical or chemical means during the process of selecting the appropriate mitigation measures. It is important to note that if the coating or liner is not continuous, or a CRA is not used for all components within the pipeline, additional mitigation methods (i.e., chemical treatment) may still be required to achieve corrosion protection for the entire pipeline. In such cases, the benefits of using coatings,

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liners, or CRAs are not considered significant because of the additional costs for chemical treatment.

4.4.3 Selection of Alternative Materials When it has been determined that the corrosion rates for carbon steel are unacceptable, other measures of mitigation are unfeasible, and/ or the consequence of failure is unacceptable, alternative materials can be considered. Candidate materials can be determined by first identifying a single property (i.e., strength or corrosion resistance) that is required for the application. Materials that fit the criteria should be identified and evaluated. Evaluations may be based upon laboratory testing and/or industry guidance. When selecting a material for a particular environment, it is important to consider its interaction with other materials in the system. If a metallic material is selected, the potential for galvanic corrosion exists when in contact with other metals. The potential severity of the corrosion will be related to where the metals fall in the galvanic series (Section 1.1.3.1 Galvanic Corrosion), as well as the anode/cathode area (Section 2.1.1 Anode/Cathode Area). Composites pipelines are one alternative to metallic pipelines. Composites are engineered materials that combine two or more materials (e.g. metal, polymer, or ceramic) with distinctly different properties. Generally, one of the materials acts as a reinforcing phase and is embedded in a matrix of the second phase. The reinforcing phase material may be present as sheets, fibers, or particles. Composites used in pipelines include: •

Fiberglass-reinforced plastic (FRP)

•

Graphite fiber reinforced plastic (GFRP)

•

Thermoplastic reinforced pipe

•

Metal matrix composites (MMCs)

Refer to Appendix C for descriptions of each of these composites.

Advantages •

strength

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•

wear resistance

•

weight savings

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Limitations •

higher initial cost

•

susceptibility to fire and third party damage

4.5 Corrosion Mitigation The following is a list of corrosion forms, mechanisms, and the potential methods used to mitigate their effects. A number of these are design-related mitigation methods. In some instances, it may be necessary or beneficial to use more than one method to mitigate an internal corrosion form or mechanism.

4.5.1 Pitting The following is a list of the common methods used to control internal pitting: •

Use of pit-resistant materials (e.g., avoid stainless steel in environments containing chlorides) where oxygen is present

•

Use of protective coatings or linings

•

Modification of the environment (e.g., inhibitors)

4.5.2 Crevice Corrosion Crevice corrosion can be minimized to some extent through careful design and fabrication (e.g., eliminating or sealing off crevices). Common design methods used to mitigate crevice corrosion include: •

Use of welded joints and junctions

•

Properly sizing gaskets

•

Coating/sealing flange faces

While design methods can help to minimize crevice corrosion, additional means may be necessary.

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4.5.3 Galvanic Corrosion The best means of controlling galvanic corrosion is to eliminate the galvanic couple by design. Common design methods used to control galvanic corrosion include: •

Selection of materials near one another in the Galvanic Series

•

Use of insulated connectors

•

Incorporation of large anode areas

•

Coat judiciously (e.g., coating cathode)

When utilizing coatings to control galvanic corrosion, both the anode and cathode are usually coated. Never just coat the anode as defects within the coating can result in severe localized attack at these locations. The localized attack occurs due to the large cathode to anode ratio.

4.5.4 Weld Zone Corrosion Methods used to control weld corrosion include: •

Proper welding procedures

•

Alloying additions to the weld metal such that the weld is cathodic to the base metal (minimize the potential for galvanic corrosion)

•

Stress-relieving heat treatments to minimize residual stresses (minimize potential for EAC)

•

Minimize weld protrusions to minimize accumulation of liquids, solids, and bacteria at the location

4.5.5 Microbiologically Influenced Corrosion (MIC) Common methods used to control MIC include: •

Use of routine cleaning to remove accumulating deposits (i.e., pigging)

•

Biocide treatments

•

Complete drying/drainage of liquids (i.e., after hydrotests)

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Control of flow rates (i.e., avoid stagnant to low flow conditions)

4.5.6 Stress Corrosion Cracking (SCC) SCC can be controlled by eliminating one of the following three factors: 1. Susceptible alloy 2. Tensile stress 3. Corrosive environmental species (hydroxides, chlorides, oxygen) At the design stage, SCC can be prevented by: •

Selecting the proper material for the environment

•

Minimizing tensile stresses by inducing compressive stresses (through peening, burnishing, or rolling surfaces)

•

Minimizing of areas of localized stress

Finally, SCC can be minimized by avoiding stagnant areas and crevices that can concentrate corrosive species.

4.5.7 Hydrogen Induced Cracking (HIC) Mitigating HIC first requires an understanding of the features in steel that permit its development (refer to Section 1.1.5.1.1 Hydrogen Induced Cracking (HIC)). In soft, low strength steels, hydrogen blistering is often observed. In stronger steels, the problem develops as HIC, or a combination of HIC and hydrogen blistering. If hydrogen blistering is noted, it should be taken as a warning that HIC may also be present. However, the absence of blisters does not indicate an absence of HIC. In petroleum production operations, HIC is almost exclusively a problem associated with systems containing H2S. Further, system pH has also been found to have a strong effect on HIC, with low pH values (acidic) promoting cracking. Thus, exposure of systems in sour service to very low pH conditions (e.g., acid cleaning, or by flow-back of downhole acid stimulation fluids) should be avoided as rapid crack development could be induced. Common design methods to control HIC include:

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•

Reduction of sulfur in the alloy to very low levels (i.e., reduce formation of elongated MnS inclusions)

•

Addition of alloying elements such as calcium or rare earths to modify the shape of inclusions (i.e., spheroid vs. elongated ellipse) forms in the rolled product

•

Use of fine grain steels that are often less susceptible than coarser steels

•

Control of casting and rolling processes to minimize segregation through the cross

•

Use of inherently resistant product forms such as seamless pipe rather than products derived from plate or strip

For non-sour service (H2S < 345 Pa [0.05 psia]), no measures are normally required. For sour service H2S exposure (above 345 Pa H2S [0.05 psia]), vendors are required to provide material designed for HIC resistance, and to verify that resistance by testing the heat of each material in accordance with NACE TM0284. Pipes should be HIC tested after forming. Use internally clad or weld overlaid carbon steel in severe cases. Note: HIC does not require residual or applied stress, and control of alloy hardness is not relevant to HIC prevention. HIC is, therefore, not controlled by the measures outlined in NACE MR0175/ ISO15156 for control of SSC. Soft low strength steels can be susceptible to HIC.

4.5.8 Stress Oriented Hydrogen Induced Cracking (SOHIC) Methods used to control and minimize HIC are also commonly used to avoid SOHIC. In addition, SOHIC resistance can be enhanced by post weld heat treatment (PWHT) for relief of residual stresses.

4.5.9 Sulfide Stress Cracking (SSC) Unlike HIC, SSC is more prevalent in high strength, high hardness steels. Thus, SSC is commonly controlled by limiting the hardness of components in accordance with the requirements of NACE

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MR0175/ISO15156. Ways to ensure that hardness limits are met include: •

Weld piping systems using only materials and procedures that limit the hardness in the weld deposit, heat affected zone and parent material

•

Ensure that specifications spell out the requirements for welds and define how the fabricator will achieve compliance

•

Ensure that welding specifications require hardness testing during the weld procedure qualification process

•

Ensure that the Procedure Qualification Record (PQR) must document the results of this testing

Note that measures designed to prevent HIC are irrelevant in the prevention of SSC. SSC susceptibility depends largely on the composition, strength and hardness of the material. Higher strength and higher hardness materials are more susceptible than lower strength, softer materials.

4.5.10 Erosion-Corrosion The following is a list of the common methods used to control erosion-corrosion: •

Reduce fluid velocity

•

Avoid abrupt changes in flow direction (eliminate right-angle T junctions when possible, use maximum radius elbows)

•

Avoid rough surfaces (i.e., prevent weld bead penetrations that disrupt flow)

•

Filtration of abrasive particles

•

Use of ceramic coatings

•

Increased thickness of vulnerable areas

4.5.11 Cavitation Cavitation may be controlled to some extent at the design stage. Common designs used to mitigate cavitation involve: •

Reduction of hydrodynamic pressure gradients

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•

Avoidance of pressure drops below the vapor pressure of the liquid

•

Avoidance of air ingress

While design methods can help to minimize cavitation, additional means may be necessary. Additional methods commonly used to control cavitation include: •

Removal of dissolved gases that allow for easy nucleation of bubbles

•

Proper operation of pumping equipment

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Chapter 5: How Do I Optimize An Internal Corrosion Program? Overview Internal corrosion management programs can be optimized through risk management, economic evaluations, and continuous improvement opportunities.

5.1 What is Risk Management? Risk is defined as “the combination of the probability of an event and its consequence” (ISO/IEC Guide 73). Risk = probability of failure x consequence Prior to discussing risk, it is important to understand the terms associated with risk. The following definitions will be used throughout this chapter: •

Hazard: A condition or practice with the potential for accidental loss.

•

Threat: A possible cause that will potentially release a hazard and produce an event.

•

Opportunity: A possible action with the potential to produce an event with positive consequences.

•

Accident: An event which results in unintended harm or damage.

•

Risk: The combination of the probability of an event and its consequence.

•

Risk management: A process to ensure that all significant risks are identified, prioritized, and managed effectively.

•

Likelihood: The expectation, possibility, or chance of an event happening, expressed as a frequency (i.e., once every 10 years) or probability (i.e., 0.2, 40%, etc.). Probability and likelihood are commonly interchanged in the dicussion of risk.

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Consequence: A measure of the level of harm or damage that the accident could cause.

Figure 5.1 is a bow-tie diagram that illustrates how causes, events, and consequences relate to each other. For example, the event could be a leak on a pipeline. This bow-tie diagram is further discussed in 5.1.2.2.

Causes

Consequences

Major

Event Event

Basic causes

Immediate causes

Immediate consequences

Ultimate consequences

Figure 5.1 Bow-tie Diagram

Risk management is a process used to identify, prioritize, and manage risks. The four steps of risk management are: 1. Identification 2. Evaluation 3. Mitigation 4. Monitoring

5.1.1 Risk Identification This step in the risk management process requires identifying hazards, threats, and opportunities associated with the process under evaluation. For the purpose of this course, the “process under evaluation” is the operation of a pipeline. It is the overall goal of the risk identification process to identify ALL hazards, threats and opportunities associated with the process; however, this is generally not possible.

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Hazard Identification (HAZID) and Hazard and Operability (HAZOP) processes are systematic processes to identify hazards for specific locations, tasks, or processes. HAZID and HAZOP processes can be completed using a structured brainstorming activity with a group of people knowledgeable about the system and its operation. When identifying risks, it is important to remember that people, equipment, material, and the environment are not isolated from each other. All four of these components must interact properly to prevent an event (accident) from occurring. The people component includes: •

Employees

•

Contractors

•

Suppliers

•

The public

The equipment component includes: •

All the tools and machines - Vehicles - Hand tools - Personal protective equipment (PPE)

The materials component includes: •

Raw materials

•

Chemicals

•

Other substances people use - For the oil and gas industry this would include the product being transported and any chemical treatment applied to the pipeline

The environmental component involves the physical environment surrounding the process or operation including: •

Air

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•

Water

•

Soil

•

Plants

•

Animals

5.1.2 Risk Evaluation Risk evaluation is the process by which risk information is considered and compared to standards to ensure that adequate controls are in place to reduce risk to an acceptable level. Risk evaluation answers the following questions: •

What can go wrong?

•

What will happen if something goes wrong?

•

How serious would it be?

•

How likely is it?

•

What should we do about it?

There are several different risk evaluation tools that can be utilized. Selection of the appropriate risk evaluation tool depends on: •

The amount of background information that is known regarding the process or equipment

•

Anticipated risk level (high or low)

•

Available resources (time, personnel, and money)

•

Competencies of people involved

Risk analysis is a component of risk evaluation that is the process used to determine the likelihood of an event and the potential consequences. Risk analysis may be quantitative or qualitative and simple or complex. Qualitative analyses involve analyzing risks based on judgment against set criteria, typically using a risk matrix. The bow tie technique can also be used to perform the analysis.

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5.1.2.1 Risk Matrices A risk matrix shows the consequence on one axis and the probability or likelihood on the other axis. The following steps describe the risk matrix methodology: 1. Identify the hazards and/or threats associated with a given event or accident. 2. Identify the categories for consequence evaluation. These categories can include safety, health, environment, legal/regulatory, financial, major accident, etc. 3. Establish the criteria for analysis of each consequence category. 4. Identify the consequence for each hazard and/or threat (using criteria established in Step 3). 5. Determine the likelihood of each consequence. The likelihood categories can be numeric or qualitative. For the example below (Figure 5.2), the likelihood categories may be established as: 1 = improbable, 2 = remote, 3 = occasional and 4 = frequent. Risk categories and descriptions will vary from organization to organization.

Figure 5.2 Risk Matrix

5.1.2.2 Bow-Tie Technique The bow-tie technique (shown in Figure 5.1) is a structured means to identify hazards and consequences associated with an event. On

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the left side of the bow-tie, the possible causes of an event as well as the controls which are in place to prevent the event from occurring are identified. On the right side of the bow-tie, the consequences of the event as well as the controls or barriers that are in place to limit the consequences are identified. Probabilities of various causes and consequences occurring can be assigned based on subject matter expert input or standard industry data.

5.1.2.3 Risk Based Decision Making The final step of risk evaluation is to make decisions based on the risk analysis that was performed. In routine situations where the risks are familiar, risk analysis may be less important than following relevant codes and standards and using competent technical judgment. As more uncertainty is involved, risk analysis and risk evaluation becomes more important. Risk-based decision making should identify tolerable versus intolerable hazards or threats. Cost benefit analysis can be used to help make risk based decisions. This involves determining the financial risk benefit and comparing that financial benefit with the cost of the proposed control method (e.g., monitoring or mitigation). Cost benefit analysis relies on the economic principles discussed in Section 5.2 Economics. Economic maintenance optimization (see 5.2.3) is a type of cost benefit analysis.

5.1.3 Risk Mitigation Once the risks have been evaluated, risk mitigation is used to manage the risks. There are four primary means to mitigate risk: 1. Terminate 2. Treat 3. Tolerate 4. Transfer Terminating risk involves avoiding or eliminating the hazard. For pipelines, it is not possible to eliminate all risks (short of stopping pipeline operations). Treating risk involves preventing, detecting, controlling, mitigating, and/or recovering (each of which is described further below).

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Tolerating risk is when a risk is occurring at an acceptable level; no specific action is taken to reduce the risk. Transfer of risk involves transferring of financial or legal liabilities (e.g., insurance). When risk is transferred, the overall risk does not decrease; the risk is simply assumed by another entity. Typically, the majority of risk mitigation is done within the “treat” category. When it comes to treating a risk, there is a preferred sequence in which actions are performed. This hierarchy is shown on the pyramid in Figure 5.3. The majority of the focus should be placed on preventing risks, and the least focus placed on recovering.

Figure 5.3 Hierarchy of Risk Mitigation

The barrier or “Swiss Cheese” model is a pictorial way in which to view risk mitigation. Each barrier that is put in place can be thought of as a slice of Swiss cheese as shown in Figure 5.4. During the course of normal operation, the holes in the Swiss cheese do not line up. When an event occurs, all of the holes in the cheese align (i.e., all of the barriers fail). Having multiple barriers in place reduces the likelihood that an event will occur. Additionally, some barriers are better than others at preventing a failure; those barriers can be thought of as having smaller holes.

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Figure 5.4 Swiss Cheese Barrier Model

5.1.4 Risk Monitoring Risk monitoring is done to ensure that planned mitigation measures have been implemented and to review the effectiveness of the mitigation measures. Monitoring methods will vary depending on the type of risk being monitored. For risks associated with pipeline failures, monitoring is generally the same type of monitoring discussed in Chapter 2.

5.2 Economics Economics are often used, both in conjunction with, and independent of, risk management, to make decisions regarding pipeline operations with respect to internal corrosion. Economic impact decisions relate to the design of the pipeline, monitoring/ inspection/assessment, and mitigation. Ultimately, the goal of the pipeline operation is to maximize the return on investment for the pipeline and increase the total worth of the company. Thus, the optimum internal corrosion management program assists the company in maintaining optimum production levels while conducting operations in a safe, efficient, reliable, and economical manner. Various accounting calculations can be used when evaluating and deciding whether to proceed with a specific monitoring technique, inspection, assessment method, or mitigation option. The economic impact of any internal corrosion-related activity can be calculated. Financial assessments involve addressing the associated direct and indirect costs. Direct costs include cost of equipment, chemicals, manpower and testing/analysis. Indirect costs are those that cannot be directly attributed to a project or function. Indirect costs include taxes, administration, electricity and

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gas costs, and security costs. Economic assessment should consider the entire life cycle and, therefore, include: 1. Capital costs 2. Operation and maintenance costs 3. Risk factors 4. Repair and replacement costs 5. Revenues 6. Competition 7. Profits 8. Economic regulations Initially, capital, operational, and maintenance costs may appear substantial. However, these costs must be weighed against the cost of a failure resulting from not taking proper action to prevent or mitigate internal corrosion. Costs associated with failures not only include material and personnel costs, but also include lost revenue from downtime, and lost production. Additional costs may result from lawsuits, governmental penalties, or other economic regulations. Volumes, tariffs, seasonal production variations, and rate of returns must also be considered.

5.2.1 Accounting Methods A few of the accounting methods that can be utilized include: •

rate of return (ROR)

•

net present values (NPV)

•

profitability index (PI)

While the processes available to operators are similar, the available tools, assumptions, and judgments may vary.

5.2.1.1 Rate of Return (ROR) Rate of Return (ROR) is one means of calculating the profitability of an investment. ROR is defined as the net income generated during a certain time period divided by the book value of the investment at the start of the specific time period.

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ROR 

Net Income Net Investment (book value)

[5.1]

While ROR calculations are very simple, they are extremely subjective as they may vary considerably between time periods. Although averaging ROR values for consecutive time periods may eliminate fluctuations, this method does not account for the time value of money. Ultimately, ROR calculations are best employed for evaluating the performance of individual techniques and making comparisons. Example ROR Calculation A pipeline company invested $600,000 on an internal corrosion monitoring program (monitoring equipment) 5 years ago. After year 4, the financial statements reveal that the value of the equipment has depreciated by $150,000 and has a listed value of $450,000. The pipeline company has a net income of $75,000 during its fifth year of operation. The ROR for the fifth year is: ROR 

75,000  0.166 (~ 17%) 450,000

[5.2]

5.2.1.2 Net Present Value (NPV) NPV is a summation of the present value of all cash inflows and outflows minus the initial project cost (C0). n

NPV  C 0   i 1

Where: C0

Ci (1  r ) i

[5.3]

= Initial cash flow (negative for a cash

Ci

“outflow”) = Cash flow in time period i

n r

= Number of time periods = Opportunity cost of capital/discount rate

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NPV is a good means for evaluating internal corrosion management projects and, from a financial standpoint, the best means for deciding whether to proceed with a project. This is because NPV calculates the amount that an investment exceeds, fails, or meets an expected rate of return. A positive NPV value indicates that the investment would exceed the expected rate of return (i.e., generate revenue equal to positive present value). A negative NPV value indicates that the investment would result in an opportunity loss (i.e., the earnings generated are not better than the alternative use of the funds). Generally, operators will tend to be indifferent to investments in which the calculated NPV value is equal to zero. This is because the investment yields the same return as the alternative use of the funds. Example NPV Calculation 1 A pipeline company must select between two alternative internal corrosion management plans. Each plan requires a different capital investment and has different cash flows. The opportunity costs of capital for the techniques have identical risks of 17%. Based upon the information in Table 5.1, identify which plan the company should choose. Table 5.1: NPV Company A

Plan 1 2

C0

C1

C2

C3

C4

-$175,000 -$240,000

$50,000 $85,000

$53,000 $88,000

$57,000 $89,000

$61,000 $91,000

NPV (1) = -$175,000 + $42,735 + $38,717 + $35,589 + $32,553 = -$25,406 NPV (2) = -$240,000 + $72,650 + $64,285 + $55,569 + $48,562 = $1,066

Example NPV Calculation 2 Calculate NPV for Pipeline Company B in Table 5.2 using a 15% discount rate and mid-year cash flow assumption.

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Table 5.2: NPV Company B

Year 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012

Time period (i) 0.5 1.5 2.5 3.5 4.5 5.5 6.5 7.5 8.5 9.5 10.5 11.5 12.5 13.5 14.5

Cash Flow - 205.00 175.90 71.43 46.33 25.44 18.90 12.75 10.50 7.04 5.75 4.30 4.10 3.66 3.33 3.14

NPV (B) = -$191.16 + $142.63 + $50.37 + $28.41 + $13.56 + $8.76+ $5.14+ $3.68 + $2.15 + $1.52 + $0.99 + $0.82 + $0.64 + $0.50 + $0.41

Answer: $68.43

5.2.1.3 Profitability Index (PI) Profitability Index (PI) is a dimensionless ratio that is used as a criterion for profitability. While NPV calculations are used for deciding whether to proceed with a project, they do not measure the efficiency of the investment. Consequently, PI is used to determine profitability. PI is defined as the ratio of the present value of future operating cash flows to the present value of the investment. Calculation of PI allows a company to determine the profitability of an investment. The higher the PI value, the better the investment.

PI  1  PVR  1 

NPV PV of capital investment

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Where: PVR is the present value ratio = NPV/PV of capital investment Example PI Calculation Two investment options are available to Pipeline Company Z. The present value of investment for option A is $200, and the net present value is $200. The present value of investment for option B is $2,500, and the net present value is $300. Of the two options available, which one is more profitable?

PI for option A  1 

PI for option B  1 

$200 2 $200

$300  1.12 $2500

Comparison of the PI values for Options A and B reveal that Option A is the better investment choice.

5.2.1.4 Profitability Decisions (NPV, ROR, PI) Table 5.3 summarizes how investment decisions are made based on NPV, ROR, and PI calculations. Table 5.3: Comparison of Investment Decisions

Profitability Measure Net present value (NPV) Rate of return (ROR) Profitability Index (PI)

Favorable >0 > r* >1

Unfavorable