NACE Internal Corrosion for Pipelines -Advanced Jan 2011

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 ( 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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•

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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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If Yes, How Bad Is It?

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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1

If Yes, How Bad Is It? Chapter 2

2

Determining Corrosion Severity • What is the corrosion rate? – Monitoring

• What is the extent of the corrosion damage? – Inspections – Assessments

3

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January 2011 1

Corrosion Rate Modeling • One tool for estimating corrosion rate and identifying monitoring locations • Types of models – Mechanistic models • Based on corrosion mechanism(s) • Corrosion rate determined by electrochemical reactions

– Empirical models • Corrosion rates based on correlations of experimental results

– Both 4

Corrosion Rate Modeling (cont.) • Inputs – Gas composition (CO2, H2S, O2, water vapor) – Liquid composition – Operating pressures – Operating temperatures – Flow rates

• Verify that model assumptions are valid 6

Monitoring Techniques • Factors in selecting a monitoring technique – – – – – – –

Corrosion forms that are reliably detected Media to be monitored Sensitivity and accuracy of technique Skills required by personnel Time requirements Placement, system modifications Data collection and analysis 7

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January 2011 2

Monitoring Techniques (cont.)

Intrusive

Direct

Indirect

Corrosion coupons

Hydrogen probes

Spool pieces

Water chemistry

Electric resistance (ER) probes

Solid analysis

Linear polarization resistance probes (LPR)

Gas analysis

Electrochemical Noise (ECN)

Nonintrusive

Ultrasonic testing (UT)

Hydrogen patch probes

Electrical Field Mapping (EFM)

Acoustic monitoring

8

Selection of Monitoring Locations • Area where corrosion is: – Most severe – Representative of pipeline

• Other considerations – – – –

Accessibility Circumferential location of monitoring device Need for multiple monitoring locations Alternative locations (not along pipeline) 9

Selection of Monitoring Locations Alternative Locations • Side streams – Bypass loops from process stream – Velocity, temperature, & pressure may differ – Turbulent conditions at beginning and end of stream

• Facilities – Separators – Slug catchers – Headers

10

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Selection of Monitoring Locations Alternative Locations (cont.) Separator

Slug catcher

11

Direct Intrusive Techniques • Insertion of device into pipe for exposure to the environment • Means of insertion – Retractable device – Plug fitting

12

Direct Intrusive Techniques (cont.)

13

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Corrosion Coupons • • • •

“Pipe” metal inserted into pipe Variety of shapes, sizes, and materials Pre-determined exposures General corrosion rate determined from weight loss

14

Corrosion Coupons (cont.)

15

Corrosion Coupons Monitoring Locations

16

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Corrosion Coupons Field Observations • Note – Damage on the coupon – Nature of any product films on coupon • Color • Presence of particulate • Thick / thin

17

Corrosion Coupons Field Observations (cont.)

18

Corrosion Coupons Laboratory Analysis • Determination of pit rate – Better assessment for localized corrosion

• SEM analysis – Corrosion severity – Corrosion morphology

• EDS analysis – Elemental make-up of associated scales

19

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Corrosion Coupon General Interpretations Average Corrosion Rate

Maximum Pitting Rate

(mm/y)

(mpy)

(mm/y)

(mpy)

Low

< 0.025

< 1.0

< 0.13

< 5.0

Moderate

0.025 - 0.12

1.0 - 4.9

0.13 - 0.20

5.0 - 7.9

High

0.13 - 0.25

5.0 -10

0.21 - 0.38

8.0 - 15

Severe

>0.25

> 10

> 0.38

> 15

NACE Standard RP0775

20

Spool Piece • Short section of pipe that can be installed and removed for inspection • Typically the same size & metal composition as system pipe • Exposure of 90 days-2 years • Provide 360º dynamic information • Successive measurements can be used to determine corrosion and pitting rates 21

Electrical Resistance (ER) Probes • Measures increase in probe element resistance in response to crosssectional area reductions • Rapid measurement • Operational in a variety of environments • Various element/electrode styles

22

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January 2011 7

ER Probes (cont.)

23

ER Probes (cont.) • Data collection methods – Handheld logger – Data recorder at probe location – Radio transmission of data – Hard wire to a SCADA system

24

ER Probes (cont.) • Probe element selection – Dictated by known or expected damage

• Element examples – Wire loop → highly sensitive, not suitable for high flow, erosive conditions – Cylindrical probes → suitable for harsh environments – Flush mounted → suitable for regularly pigged systems 25

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Other ER Probes • New generation high resolution ER probes – Quicker response – Enhanced compensation for temperature and noise reduction

• Erosion ER probes – CRA sensing elements – 45º angled element

26

Linear Polarization Resistance (LPR) Probes • Electrochemical technique – Require aqueous environment

• Instantaneous corrosion rates • Various electrode configurations • Electrode configuration allows for other electrochemical measurements

27

LPR Probes (cont.) I

Secondary Electrode

Reference Electrode

Working Electrode

E

28

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LPR Probes (cont.) • 10 mV above and below OCP applied to the electrodes • Resulting current measured • Rp value determined and converted to corrosion rate

29

LPR Probes (cont.)

Rp

30

LPR Probes (cont.) • Continuous immersion necessary for meaningful results • Oil, paraffin, iron sulfide or scale deposits can foul probe • Remain in service until probes need to be replaced or inspected

31

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Electrochemical Noise (ECN) • Electrochemical technique • Used with LPR probes • Measures the naturally occurring fluctuations (noise) in the potential and/or current generated by the corrosion at the metal-electrolyte interface • Data analysis is highly mathematical and time consuming 32

Electrochemical Noise (ECN) (cont.)

33

Electrochemical Noise (ECN) (cont.) ECN Scan 8.0E-06

7.0E-06

6.0E-06

Current (A)

5.0E-06

4.0E-06

3.0E-06

2.0E-06

1.0E-06

0.0E+00 0

200

400

600

800

1000

1200

Time (sec)

34

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Direct Non-Intrusive Techniques • Does not require insertion of device into pipe for corrosion rate estimation – Electrical Field Mapping (EFM) – Permanently mounted ultrasonic probes – Acoustic erosion monitoring

35

Electrical Field Mapping (EFM) • Uses induced current & array of sensing electrodes – Current induced directly to pipe – Potential difference between electrodes measured

• Defects identified by distortion within electric field • Sensitivity to general vs. localized corrosion dependent on pin spacing 36

Electrical Field Mapping (EFM) (cont.)

37

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Permanently Mounted UT Probes • Corrosion rate determined from successive measurements – Comparison of wall thickness over a given period of time

• Sensitivity of the probes limits the detectable minimum corrosion rate

38

Acoustic Erosion Monitoring • Measures acoustic noise generated by solids impacting pipe • Signals integrated over time and compared to pre-determined solid-free flow values • Information used to: – Determine produced solid rates – Correlate rates to flow regimes – Optimize rates 39

Indirect Techniques • Monitor parameters that can influence or are influenced by the corrosion severity of the environment – – – – –

Hydrogen monitoring Gas analysis Water analysis Solid analysis Microbiological analysis

40

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Hydrogen Monitoring • • • •

Intrusive & non-intrusive probes Monitors hydrogen absorption by steel Trends corrosion Used to monitor tendency for: – Hydrogen induced cracking (HIC) – Stress oriented hydrogen induced cracking (SOHIC) – Sulfide stress cracking (SSC) 41

Hydrogen Monitoring Intrusive Probes • Consists of: – Hollow steel sensing elements – Pressure-sensing device

• Rate of hydrogen pressure buildup ≈ hydrogen absorption

42

Hydrogen Monitoring Non-intrusive Patch Probes • Types – Pressure patch – Electrochemical patch

• Monitors rate of hydrogen egress from the outer surface of the steel

43

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Gas Sample Analysis • Methods – – – –

Gas chromatographs Dew point analyzers Stain tubes O2 and H2S monitors

• Data reviewed & interpreted on an ongoing basis

• Parameters of interest – – – –

H2S content CO2 content O2 content Water vapor content

44

Gas Sample Analysis Limitations • Stain tubes – Less accurate – Limited to certain range of testing – Dependent on exposure time and flow rate

• Laboratory collection – H2S can react with collection cylinders

45

Water Analysis • Dissolved gases – H2S, CO2, and O2

• pH • Alkalinity • Concentration of anions • Inhibitor residuals

• Concentration of metals/cations • Specific gravity • Total dissolved solids (TDS) • Organic acids

46

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Water Analysis Sample Collection • Allow sample to flow for short time prior to collection • Glass sample bottles recommended – Fill to top to eliminate air – Remain capped until analyzed

• Sample changes with time • Sample collection techniques can influence the quality of results 47

Water Analysis On-site Testing • Temperature • Dissolved gas contents (O2, CO2, and H2S) • Bacteria sample preservation • pH • Total alkalinity

48

Liquid Sample Analysis pH • pH levels change with time • Distinguish between field and lab measurement • Field techniques – Digital – pH paper

49

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Liquid Sample Analysis Alkalinity • Measurement of buffering capacity of water • pH dependent • Need to distinguish between field and lab measurement • Determined using acid titration – Uses color indicators – May be difficult to analyze dark colored samples 50

Liquid Sample Analysis • Anion Concentrations • Specific gravity – Laboratory measurements using ion chromatography

• Metal Concentrations – Inductively coupled plasma spectroscopy (ICP) – Atomic absorption spectroscopy (AAS)

– Ratio of the density of the liquid to the density of water – 0 > r* >1

Unfavorable 0.60%2

> 0.60%2

Copper (Cu)

0.40% - 0.60%

> 0.60%2

> 0.60%2

Other alloying elements3

Minimum not specified

Definite range or minimum quantity 4

Definite range or minimum quantity 5

Additional elemental limits 1

Maximum limits for Cr, Cu, Mo, and Ni when otherwise not specified6

Maximum limits for Cr, Cu, Mo, and Ni when otherwise not specified6

Typically < 0.8% for oil and gas industry

2

Aluminum (Al), boron (B), chromium (Cr), cobalt (Co), molybdenum (Mo), nickel (Ni), niobium (Nb), titanium (Ti), tungsten (W), vanadium (V), zirconium (Zr), etc.

3

One or more of the following elements must exceed the limits for plain carbon steel: Mn, Si, and/or Cu. 4

Alloying elemental content < 5%, 3.99% max Cr

5

Alloying elemental content > 5%, 3.99% max Cr

6

0.20% Cr max, 0.35% Cu max, 0.06% Mo max, and 0.25% Ni max

*

From Steel Products Manual, Section 6, American Iron and Steel Institute, August 1952, pp. 5 and 6. † From Steel Products Manual, Section 6, American Iron and Steel Institute, January 1952, pp. 6 and 7. Advanced Internal Corrosion for Pipelines ©NACE International 2009 May 2009 4

In contrast to plain carbon steels, alloy steels contain higher contents of elements such as manganese, silicon, and copper. Alloy steels may have a mixture of other elements to obtain various desired properties. A list of elements and their influence on steel is listed in Table C.4.

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Table C.4

List of Common Steel Alloying Elements and Their Impact on Final Properties

Alloying Element Silicon (Si)

Chromium (Cr)

Manganese (Mn) Titanium (Ti)

Impact on Steel Strengthens low-alloy steels Moderately improves hardenability Improves oxidation resistance Improves: • Corrosion and oxidation resistance • Hardenability • High temperature strength For high carbon compositions: • Improves abrasion resistance Improves hardenability at low cost; Combines with sulfur to form manganese sulfide stringers that improve machinability Strengthens through precipitation of carbides and nitrides Improves:

Molybdenum (Mo)

Nickel (Ni)

Tungsten (W)

Niobium (Nb)

Vanadium (V)

•

Hardenability • High temperature strength • Resistance to softening when tempered Improves toughness Combined with chromium, improves: Hardenability Impact strength Fatigue resistance Improves: • Strength by forming carbides • Resistance to softening when tempered, • Hardenability • High-temperature strength Improves: • Strength by forming carbides • Hardenability • Resistance to softening when tempered Improves: • Strength by forming carbides • Hardenability • Resistance to softening when tempered

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Changes in the carbon content of steel can alter the microstructure of the material and, thus, the properties of the material. Microstructures common to carbon steels include grain structures of austenite, ferrite, pearlite, and martensite. In general, steels with a fine (small) grain size, exhibit improved strength, ductility, and toughness. The microstructure of steel is established during the manufacturing process and is influenced by chemical composition, thermal treatment and mechanical forming. Typically, heat treatments involve heating steel into the austenite region, holding at temperature for a given amount of time, and cooling at a prescribed rate. Common heat treatments include annealing, normalizing, and quench and tempering. Annealing refers to heating steel into the austenite region followed by slow furnace cooling (approximately 8-10 hours). This treatment generally produces a coarse pearlitic microstructure. Normalizing refers to heating steel into the austenite region followed by cooling in still, ambient air. Unlike annealing, the cooling process occurs outside of the furnace and at a relatively faster rate (approximately 10-15 minutes). This treatment normally produces a fine pearlitic microstructure. Quenching and tempering is a two step process in which the steel is first heated into the austenite region. The steel is then rapidly cooled commonly by water, brine, or oil immersion. Alternatively, the steel can be cooled by forced air. The rapid cooling is collectively referred to as “quenching.” The next step called tempering refers to reheating the quenched steel to a temperature below the critical austenite temperature and maintaining that temperature for approximately 1 hour. Tempering reduces the hardness caused by quenching, and improves the ductility of the steel. Plain carbon and low alloy steels are generally used for low to moderate corrosive environments or low risk applications. Applications of plain and low alloy steels often will include some method of inhibition. Inhibition methods may involve use of inhibitors, biocides, or non-metallic liners. Typically, when plain carbon and low alloy steels are used with inhibition, corrosion monitoring will be essential to verify the efficacy of the inhibition method. Cast Irons Cast iron refers to the family of iron and carbon alloys containing silicon and more than 2% carbon. Free carbon is found in the microstructure of cast irons since their carbon contents exceed the solubility limit in iron. Advanced Internal Corrosion for Pipelines May 2009

©NACE International 2009 7

Cast irons are characterized by their low cost, low ductility, and low tensile strength. Four classes of cast iron exist and are identified as gray, white, malleable, and ductile. The differences between the classes relate to the composition, heat treatment, and microstructure of the alloys. These differences in turn alter the properties of the cast iron. Table C.5 list some of the properties associated with each class of cast iron. Table C.5

Cast Iron Class

List of Cast Iron Classes

Graphite Morphology

White

No graphite, carbides present

Gray

Flakes

Malleable

Irregularly shaped nodules

Ductile

Nodules / spheroids

Tensile Strength

Hardness

MPa (ksi)

(Brinell)

90 – 621 (13 – 90) 138 - 552 (20 – 80) 345 - 690 (50 – 100) 380 - 1208 (55 – 175)

Up to 600 140 – 350 110 – 270 130 – 300

Gray cast iron consists of flakes of graphite in a ferrite matrix. While the flakes enhance the machinability of the alloy, they also tend to decrease the ductility of the alloy. Gray cast iron is not particularly corrosion resistant, but is often used successfully in corrosive service. This is because the gray cast iron is typically thick enough that small amounts of corrosion damage have little effect on the service performance. Applications of gray cast iron include water and waste water lines that are often internally coated with a cement material to improve corrosion resistance. White cast iron is characterized by the absence of free carbon (i.e. graphite) and the presence of significant amounts of iron carbides. These alloys tend to be brittle, hard, and wear resistant, making them ideal for abrasive environments. White cast irons have the same corrosion resistance as the gray cast iron, but with improved ductility. Malleable cast iron refers to the class of cast irons characterized by irregularly shaped graphite nodules that form during heat treatment. Originally cast as white iron, the material is heat treated to convert the iron carbide to graphite nodules. These alloys are used in applications requiring both high strength and wear resistance. This class of cast iron is further divided into three separate types including ferritic, pearlitic (martensitic), Advanced Internal Corrosion for Pipelines May 2009

©NACE International 2009 8

and alloy. As implied by its name, ferritic cast iron has a ferritic microstructure, as well as contains nodular carbon. Pearlitic (martensitic) cast iron is characterized by the presence of nodular carbon in martensite or cementite. Finally, alloy cast iron is characterized by the presence of nodular carbon (graphite). Ductile (often termed ‘Nodular’) cast iron consists of nodular or spherodized graphite that forms during the solidification of the molten iron. This occurs due to additions of magnesium and cerium to the molten metal. These alloys are characterized by increased ductility and improved impact resistance. Compared to gray and malleable cast irons, ductile cast irons have relatively high strength and toughness. Similar to steel, these alloys can be strengthened through heat treatment. The application of cast iron in the oil and gas industry is limited. Some applications, however, include low pressure distribution pipes, pumps, valves, packers, and other components. The advantage of using these alloys is the ability to produce a variety of shapes at relatively low costs. Stainless steels Stainless steels are a group of steels that are alloyed with at least 12% chromium (Cr). The chromium promotes the formation of passive iron/chromium oxide films on steel, providing the steel with excellent corrosion resistance. In general, stainless steels have significantly better corrosion resistances than plain carbon steels. The corrosion resistance of stainless steels is not only attributed to chromium content. Corrosion resistance of these alloys is also related to the molybdenum (Mo), tungsten (W), and nitrogen (N), content and is typically expressed by the pitting resistance equivalent number (PREN). The PREN can be determined as follows: FPREN=wCr+3.3(wMo+0.5wW) +16wN Where: wCr = the mass fraction of chromium in the alloy wMo= the mass fraction of molybdenum in the alloy wW = the mass fraction of tungsten in the alloy wN = the mass fraction of nitrogen in the alloy

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For example, the PREN for 316 stainless steel containing 16% Cr and 3% Mo can be calculated as follows: 316SSPREN = 16 + 3.3(3 = 0.5(0)) + 0 = 25.9 ≈ 26 Chromium, molybdenum, tungsten, and nitrogen assist in imparting localized corrosion resistance. Higher PRENs, therefore, indicate increased resistance to uniform corrosion and localized corrosion. In general, Nickel assists in imparting resistance to chloride stress corrosion cracking, sulfuric acid corrosion, elemental sulfur and sulfide stress cracking. The corrosion properties of stainless steel alloys are not only defined by their compositions. Other factors that influence corrosion properties include grain size, inclusion distribution, precipitation of phases, surface quality, presence of crevices, and properties of welds. The higher initial cost of stainless steels due to alloy content, however, tends to limit their extensive use. Stainless steels are generally only used in situations where other corrosion mitigating techniques are not viable/cost effective. Stainless steels are not suitable for service in all environments. Stainless steels are subject to localized corrosion damage in the form of pitting in chloride environments, intergranular attack of sensitized welds, and hydrogen embrittlement, particularly at high temperatures. Stainless steels can become susceptible to corrosion of welds due to a microstructural condition termed “sensitization”. Sensitization occurs when the material is heated to a temperature high enough for chromium carbides to form at grain boundaries. The loss of chromium in the metal adjacent to the grain boundaries results in poor corrosion resistance, and can result in intergranular attack of welded areas. Stainless steels are divided into five different classes based strictly upon their metallurgical structures. The five classes include martensitic, ferritic, austenitic, precipitation hardened, and duplex stainless steel. Each class is described in more detail below along with their particular application in the oil and gas industry. See Table C.6 for a list of the classes of stainless steel and their properties.

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Table C.6

List of Stainless Steel Classes

Stainless Steel Class

Austenitic

Ferritic

Martensitic

Microstructure

Austenitic

Ferritic

Martensitic

18 – 25 % Cr 8 – 20 % Ni

13 - 27% Cr; < 0.08% C

Hardenable by Heat Treatment

No

Hardenable by Cold Work

Composition

Tensile Strength MPa (ksi)

12 – 18 % Cr

Precipitation Hardenable

Duplex Mixed austenitic & ferritic

17% Cr

0.08 – 1.10 %C

4% Ni

20 – 29% Cr; 3 – 7% Ni

No

Yes

Yes

No

Yes

No*

Yes*

Yes *

Yes*

520- 760 (75 – 110)

415 – 655 (60 – 95)

275 – 1900 (40 – 275)

896 – 1700 (125 – 250)

550 – 690 (80 – 100)

Martensitic Stainless Steels Martensitic stainless steels have the widest range of use of any corrosion resistant alloys (CRAs) in the petroleum industry. Containing 12% - 18% Cr, 0.08 – 1.10% C, and small amounts of other elements such as nickel (Ni), Niobium (Nb), Molybdenum (Mo), Selenium (Se), silicon (Si), and sulfur (S), these steels are characterized by tempered martensitic microstructure. This microstructure is achieved though a quenching and tempering heat treatment, similar to that described earlier in this chapter for carbon steel. Due to their high degree of hardenability, martensitic stainless steels are typically used in applications where strength and corrosion resistance are required. Martensitic steels are included in the AISI 400 series of stainless steels in which the primary types include 410 and 420 (UNS S41000 and S42000). Applications of these steels include tubing for corrosive well service and deep sweet gas wells. Particular care must be taken with regard to these alloys in sour services, as they may be susceptible to sulfide stress cracking (SSC). Higher strength martensitic stainless steels may be used in sweet service. However, their Advanced Internal Corrosion for Pipelines May 2009

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corrosion resistance and ductility may be adversely affected by increasing strength. Ferritic Stainless Steels In contrast to martensitic stainless steel, ferritic stainless steel cannot be hardened through heat treatment. These steels typically contain high Cr contents (13 – 27%) and lower C contents than martensitic stainless steels. High chromium containing alloys also tend to be susceptible to embrittlement if not properly heat treated. These steels are also included in the AISI 400 series of stainless steel in which the primary types include 405, 430, and 436 (UNS S40500, S43000, and S43600). Ferritic stainless steels are used for good corrosion resistance and high temperature properties. Type 439 exhibits good resistance to chloride SCC. As implied by their name, these steels have a ferritic microstructure and are strongly magnetic. The resistance of these steels to CO2 and H2S corrosion will vary and is dependent upon the chemical composition of the steel. Applications of ferritic stainless steels include heat exchangers and thin walled tubing products. Austenitic Stainless Steels Austenitic stainless steels are generally used in applications that do not require high strengths. Alloyed with Cr (18 – 25%) and Ni (8 – 20%), austenitic steels have a characteristic austenitic microstructure and are included in the “300” series of stainless steel. Austenitic stainless steels cannot be hardened through heat treatment, have high general corrosion resistance, and have lower strengths. Commonly used alloys in the oil and gas industry include 304, 316, 303, and 347 stainless steel. Annealed austenitic stainless steels are susceptible to stress corrosion cracking (SCC) when chlorides are present and temperatures are greater than approximately (60oC). Higher alloyed austenitic stainless steels such as 254 SMO (UNS S31254) and alloy AL6XN (UNS N08367) have higher strengths and increased corrosion resistance in comparison to the “300” series stainless steels. The higher strengths of these alloys are achieved through cold working.

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Precipitation Hardened (PH) Stainless Steels Precipitations hardening (PH) stainless steels are commonly used in corrosion/wear resistant equipment parts and have very limited applicability in H2S environments. Alloyed with varying amounts of Cr and Ni, these steels can be hardened using specific heat treatments at relatively low temperatures. Hardening can result from additions of elements such as Cu, Al, Ti, and Mo that promotes precipitation of separate phases which produce strengthening. The result is steel that has the corrosion resistance of austenitic steels with the strengths of martensitic steels. An example of a common PH stainless steel is 17-4PH that contains 17% Cr and 4% Ni (UNS S17400). PH stainless steels can be used for fasteners, springs, and valve components. Duplex Stainless Steels (DSS) Alloyed with Cr and Ni in the ranges of 20 – 29% and 3 – 7%, respectively, duplex stainless steels (DSS) are characterized by a mixed austenitic and ferritic microstructure that provides high corrosion resistance and strength. Some duplex stainless steels are strengthened through cold working, achieving yield strengths as high as 1100 MPa (160,000 psi). Cold worked DSS tends to be more corrosion resistant than martensitic stainless steel, but its resistance to SSC is similar. Annealed duplex stainless steels (DSS) tend to be more resistant to H2S and SSC in chloride environments than austenitic stainless steels. Consequently, duplex stainless steels have been used in line pipe and surface facility applications. It is important to note that duplex stainless steels can precipitate out detrimental phases (e.g. sigma phase) when improperly heat treated or otherwise thermally processed (e.g. welding). Application of duplex stainless steel is finding favor for components exposed to severely corrosive conditions (i.e. water wet CO2 environments) and/or high risk operations (i.e. pressure vessels, facility piping, down hole tubing). Duplex stainless steels are virtually immune to chloride SCC. They are susceptible to low pH corrosion in mineral acids. Nickel-based Alloys Nickel-based alloys are characterized by Ni contents that are > 30% and may contain significant amounts of chromium. These alloys exhibit excellent corrosion resistance, ductility, formability, and malleability. Nickel-based alloys are relatively expensive and are used when corrosive conditions are too extreme to be handled by stainless steels. The corrosion resistance of nickel alloys, similar to stainless steels, is related to the nickel (Ni), chromium (Cr), molybdenum (Mo), tungsten (W), and nitrogen (N) Advanced Internal Corrosion for Pipelines May 2009

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contents and is typically expressed by the pitting resistance equivalent number (PREN). Ni assists in imparting resistance to chloride stress corrosion cracking and sulfide stress cracking, while Cr, Mo, W, and N assist in imparting localized corrosion resistance. Higher PREN values indicate increased resistance to uniform corrosion and localized corrosion. The metallurgy of nickel-based alloys is complex due to the numerous phases that may form. Some phases that form, such as sigma phase, are detrimental to the corrosion resistance of nickel-based alloys. Therefore, processing is tailored specifically to produce optimum strength and toughness, while maintaining corrosion resistance. Further, many nickel alloys are not heat treatable and are strengthened by either cold working or aging. A range of nickel-based alloys has been developed for severe corrosive service, including both “sweet” and “sour” services for the oil and gas industries. The most common nickel alloys used in oil and gas applications include Alloy 625 (UNS N06625), Alloy 825 (UNS N08825), and Alloy C276 (UNS N10276). Both Alloys 625 and 825 have austenitic structures and contain high contents of Ni, Cr, and Mo. Alloy 825 has a lower Mo content than Alloy 625 and thus has lower protection from corrosion associated with chlorides. Consequently, alloy 625 is preferred in corrosive services with high chloride contents and high temperatures. Copper Alloys Copper alloys are used for various water handling applications, due to their good corrosion and fouling resistance. Typical copper alloys used include brasses (Cu-Zn alloys), aluminum bronze, and copper-nickel alloys. While brass is more susceptible to stress corrosion cracking and the selective removal of zinc from the alloy, copper-nickel alloys are more resistant to stress corrosion cracking. Thus, while the brasses and bronzes (UNS C61300 and UNS C61400) are utilized for injection water services, copper-nickel alloys (UNS C70600 and UNS C71500) are utilized for raw sea water piping for water floods. Copper based alloys suffer high corrosion rates in H2S environments. Aluminum Alloys A variety of aluminum alloys exist, as shown in Table C.7. As seen in this table, aluminum alloys are designated by their major alloying elements under the Unified Numbering System. Advanced Internal Corrosion for Pipelines May 2009

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Aluminum alloys are known for their light weight and high strength-toweight ratios. In addition, aluminum readily reacts with oxygen to form a thin oxide layer that resists progressive oxidation. When alloyed with the appropriate elements, aluminum alloys can resist corrosion associated with corrosive water and the presence of salts. Aluminum alloys are typically used in applications where the system pH is between 5 and 7, as they are susceptible to corrosion in highly acidic and high alkaline environments. Consequently, aluminum is used in aerated fresh water lines and heat transfer applications. Table C.7

Unified Numbering System Aluminum Alloy Designations

Alloy Group

Major Alloying Elements

A91XXX

None – 99+% Aluminum

A92XXX

Copper

A93XXX

Manganese

A94XXX

Silicon

A95XXX

Magnesium

A96XXX

Magnesium and Silicon

A97XXX

Zinc

Nonmetallic Materials Nonmetallic materials such as plastics and composites materials are also used throughout the oil and gas industry. Plastics are finding increased use in the oil and gas industry as their operating windows become better defined and expanded. Polymeric Materials Polymers, commonly referred to as plastics, are high molecular weight organic materials. Polymers are generally classified as either thermoplastic or thermosetting materials. Thermoplastics refer to materials that can soften and be reshaped when heated. This occurs with minimal or no change in their properties. In contrast, thermosetting materials are rigid, highly cross-linked polymers that cannot be heated and reshaped. Thus, thermosets can generally endure higher service temperatures than thermoplastic materials.

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Both thermoplastic and thermosetting materials are available in a wide variety of compositions, with a wide range of both mechanical properties and resistance to deterioration. Polymers are resistant to classical electrochemical corrosion but they are not totally inert. They can be adversely affected by such agents as ultraviolet light, heat, acids, bases, and many organic solvents. As such, the use of polymers is often limited by temperature. High temperatures can cause softening of thermoplastics or chemical degradation of thermosets. Their resistance to attack by UV light, heat, acids, bases and organic solvents depends on the specific polymeric material. Polymers can either be used for low pressure line pipe or as liners in a metallic pipe. The choice of how the polymer is used depends both on the cost and the performance necessary. In general, polymers do not have the strength to withstand high stresses. Typically, the higher the operating temperature, the lower the allowable working pressure for nonmetallic materials. Examples of thermoplastics currently used in the oil and gas industry include high and low density polyethylenes (PE), nylons, polyvinylchloride (PVC), polyvinylidene chloride (PVDC), polyvinyldene fluoride (PVDF), and polyphenylene sulfide (PPS). Table C.8 lists properties of some thermoplastic materials. Examples of thermosetting materials currently used in the oil and gas industry include polyester, vinyl ester, or epoxy resins.

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Table C.8

Properties of Some Thermoplastic Materials

Applications

Polyvinyl chloride (PVC)

Thermoplastics Polyethylene (PE)

Limitations

•

-17.8 to 60 ºC (0 – 140 ºF)

•

Prolonged high temperatures

•

Alkalis

•

Fatty acids

•

Oxidizing acids

•

Acetic acids

•

Aliphatic hydrocarbons

•

Solvents

•

Aromatic hydrocarbons

•

Hydrocarbons > 38 ºC (100 ºF)

•

Solvents > 49 ºC (120 ºF)

•

Oxidizing acids

•

Aromatic hydrocarbons

•

Waters & brines

•

-17.8 to 60 ºC (0 – 140 ºF)

•

Hydrocarbons < 38 ºC (100 ºF)

•

Acids

•

Alkalis

•

Waters & brines

•

-17.8 to 60 ºC (0 – 140 ºF)

•

Hydrocarbons < 38 ºC (100 ºF)

•

Acids

•

Alkalis

•

Waters & brines

Polypropylene (PP)

Same as PE

Composites 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. Advantages of composites include increased strength, increased wear resistance or weight savings. Limitations of composites include that their corrosion resistances are generally poor, and they tend to be of higher initial cost. Composites used in pipelines include fiberglass-reinforced plastic (FRP), graphite fiber reinforced plastic (GFRP), thermoplastic reinforced pipe, and Advanced Internal Corrosion for Pipelines May 2009

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metal matrix composites (MMCs). Each of these composites is discussed in more detail below. Fiberglass-Reinforced Plastic (FRP) Fiberglass-reinforced plastic (FRP) is a composite composed of inert chopped glass or high strength synthetic fibers embedded in a thermosetting resin (e.g., polyester or epoxy resin). The arrangement of fibers within the resin minimizes permeation of liquids and vapors through the coating, establishing a barrier to protect the substrate. FRP can be used for corrosion protection and is often a popular choice for repairing badly pitted and otherwise corroded vessels. FRP pipes can be installed very quickly, relative to steel, resulting in significant cost savings. One of the disadvantages of using FRPs for piping is that performance is dependant on the temperatures and pressures of operation. High temperatures (> 149 ºC [300 ºF]) can soften or degrade the polymer matrix. Graphite fiber reinforced plastic (GFRP) Graphite fiber reinforced plastic (GFRP) is a composite composed of continuous graphite fibers in a polymer matrix. Studies on graphite reinforced polymers have shown reduced corrosion resistance compared to other composites. The graphite phase is conductive and this can lead to increased damage. For example, stray currents from the external environment may be introduced to the electrolyte solution via the conductive graphite phase. This can lead to oxygen evolution at the anode. The accumulation of adsorbed oxygen is thought to lead to damage to the polymer matrix. Reinforced Thermoplastic Pipe (RTP) Reinforced thermoplastic pipe (RTP) is another family of composites available for the oil and gas industry. RTP incorporates thermoplastic liners (i.e. HDPE or PE), with continuous high-strength glass fiber reinforcements. This family of composites has much higher strengths, allowing for substantial increases in their pressure and temperature envelopes. Promoted as corrosion resistant, RTP has found application in production gathering, injection, and disposal applications where the transfer Advanced Internal Corrosion for Pipelines May 2009

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of corrosive gas or liquids is necessary. Other advantages of RTP include their flexibility, ease of installation, and improved flow characteristics. Metal Matrix Composites (MMC) Studies on MMCs composed of aluminum alloys with reinforcement of alumina, silicon carbide or titanium carbide have shown reduced corrosion resistance in salt solutions. In some cases, the reinforcement phase has been shown to cause preferential dissolution of the alloy at the interface, though this is not confirmed for all combinations of materials. The corrosion rate then becomes a function of the volume fraction and/or the surface area of the reinforcing phase. The mechanism in aerated solutions is galvanic corrosion, with oxygen reduction being the primary cathodic reaction. Galvanic corrosion does not appear to be prevalent in deaerated solutions.

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NACE GLOSSARY OF CORROSION-RELATED TERMS

A

AERATION CELL [See Differential Aeration Cell.]

AIR DRYING ABRASIVE Small particles of material that are propelled at high velocity to impact a surface during abrasive blast cleaning.

ABRASIVE BLAST CLEANING Cleaning and roughening of a surface produced by the highvelocity impact of an abrasive that is propelled by the discharge of pressurized fluid from a blast nozzle or by a mechanical device such as a centrifugal blasting wheel. (Also referred to as Abrasive Blasting.)

ACCELERATOR A chemical substance that increases the rate at which a chemical reaction (e.g., curing) would otherwise occur.

ACRYLIC

Process by which an applied wet coat converts to a dry coating film by evaporation of solvent or reaction with oxygen as a result of simple exposure to air without intentional addition of heat or a curing agent.

AIRLESS SPRAYING Process of spraying coating liquids using hydraulic pressure, not air pressure, to atomize.

ALKYD Type of resin formed by the reaction of polyhydric alcohols and polybasic acids, part of which is derived from saturated or unsaturated oils or fats.

ALLIGATORING Pronounced wide cracking over the surface of a coating, which has the appearance of alligator hide.

Type of resin polymerized from acrylic acid, methacrylic acid, esters of these acids, or acrylonitrile.

AMPHOTERIC METAL

ACTIVATOR

ANAEROBIC

A chemical substance that initiates and accelerates a chemical reaction (e.g., curing). Heat and radiation may also serve as activators for some chemical reactions.

ACTIVE (1) The negative direction of electrode potential. (2) A state of a metal that is corroding without significant influence of reaction product.

A metal that is susceptible to corrosion in both acid and alkaline environments.

Free of air or uncombined oxygen.

ANION A negatively charged ion that migrates through the electrolyte toward the anode under the influence of a potential gradient.

ANODE The electrode of an electrochemical cell at which oxidation occurs. Electrons flow away from the anode in the

external circuit. Corrosion usually occurs and metal ions enter the solution at the anode.

ANODE CAP An electrical insulating material placed over the end of the anode at the lead wire connection.

ANODE CORROSION EFFICIENCY The ratio of the actual corrosion (mass loss) of an anode to the theoretical corrosion (mass loss) calculated from the quantity of electricity that has passed between the anode and cathode using Faraday's law.

ANODIC INHIBITOR A chemical substance that prevents or reduces the rate of the anodic or oxidation reaction.

ANODIC POLARIZATION The change of the electrode potential in the noble (positive) direction caused by current across the electrode/electrolyte interface. [See Polarization.]

ANODIC PROTECTION Polarization to a more oxidizing potential to achieve a reduced corrosion rate by the promotion of passivity.

ANODIZING Oxide coating formed on a metal surface (generally aluminum) by an electrolytic process.

ANOLYTE The electrolyte adjacent to the anode of an electrochemical cell.

ANTIFOULING Preventing fouling. [See Fouling.]

© 2002, NACE International. This publication may not be reprinted without the written consent of NACE International. Page 1 of 18

NACE GLOSSARY OF CORROSION-RELATED TERMS ATTENUATION Electrical losses in a conductor caused by current flow in the conductor.

AUGER ELECTRON SPECTROSCOPY Analytical technique in which the sample surface is irradiated with low-energy electrons and the energy spectrum of electrons emitted from the surface is measured.

AUSTENITIC STEEL A steel whose microstructure at room temperature consists predominantly of austenite.

AUXILIARY ELECTRODE An electrode, usually made from a noncorroding material, which is commonly used in polarization studies to pass current to or from a test electrode.

B BACKFILL Material placed in a hole to fill the space around the anodes, vent pipe, and buried components of a cathodic protection system.

BARRIER COATING (1) A coating that has a high resistance to permeation of liquids and/or gases. (2) A coating that is applied over a previously coated surface to prevent damage to the underlying coating during subsequent handling

BEACH MARKS The characteristic markings on the fracture surfaces produced by fatigue crack propagation

(also known as clamshell marks, conchoidal marks, and arrest marks).

BETA CURVE A plot of dynamic (fluctuating) interference current or related proportional voltage (ordinate) versus the corresponding structure-to-electrolyte potentials at a selected location on the affected structure (abscissa).

BINDER

by moisture (also known as blooming).

BRACELET ANODES Galvanic anodes with geometry suitable for direct attachment around the circumference of a pipeline. These may be halfshell bracelets consisting of two semi-circular sections or segmented bracelets consisting of a large number of individual anodes.

The nonvolatile portion of the vehicle of a formulated coating material.

BRITTLE FRACTURE

BITUMINOUS COATING

BRUSH-OFF BLAST CLEANED SURFACE

An asphalt or coal-tar compound used to provide a protective coating for a surface.

BLAST ANGLE (1) The angle of the blast nozzle with reference to the surface during abrasive blast cleaning. (2) The angle of the abrasive particles propelled from a centrifugal blasting wheel with reference to the surface being abrasive blast cleaned.

BLOWDOWN (1) Injection of air or water under high pressure through a tube to the anode area for the purpose of purging the annular space and possibly correcting high resistance caused by gas blockage. (2) In conjunction with boilers or cooling towers, the process of discharging a significant portion of the aqueous solution in order to remove accumulated salts, deposits, and other impurities.

BLUSHING Whitening and loss of gloss of a coating, usually organic, caused

Fracture with little or no plastic deformation.

A brush-off blast cleaned surface, when viewed without magnification, shall be free of all visible oil, grease, dirt, dust, loose mill scale, loose rust, and loose coating. Tightly adherent mill scale, rust, and coating may remain on the surface. Mill scale, rust, and coating are considered tightly adherent if they cannot be removed by lifting with a dull putty knife. [See NACE No. 4/SSPC-SP 7.]

C CALCAREOUS COATING A layer consisting of calcium carbonate and other salts deposited on the surface. When the surface is cathodically polarized as in cathodic protection, this layer is the result of the increased pH adjacent to the protected surface.

CALCAREOUS DEPOSIT [See Calcareous Coating.]

© 2002, NACE International. This publication may not be reprinted without the written consent of NACE International. Page 2 of 18

NACE GLOSSARY OF CORROSION-RELATED TERMS CASE HARDENING Hardening a ferrous alloy so that the outer portion, or case, is made substantially harder than the inner portion, or core. Typical processes are carburizing, cyaniding, carbonitriding, nitriding, induction hardening, and flame hardening.

CASEIN PAINT Water-thinned paint with vehicle derived from milk.

CATHODIC POLARIZATION The change of the electrode potential in the active (negative) direction caused by current across the electrode/electrolyte interface. [See Polarization.]

CATHODIC PROTECTION A technique to reduce the corrosion of a metal surface by making that surface the cathode of an electrochemical cell.

CATHOLYTE CATALYST A chemical substance, usually present in small amounts relative to the reactants, that increases the rate at which a chemical reaction (e.g., curing) would otherwise occur, but is not consumed in the reaction.

CATHODE The electrode of an electrochemical cell at which reduction is the principal reaction. Electrons flow toward the cathode in the external circuit.

CATHODIC CORROSION Corrosion resulting from a cathodic condition of a structure, usually caused by the reaction of an amphoteric metal with the alkaline products of electrolysis.

CATHODIC DISBONDMENT The destruction of adhesion between a coating and the coated surface caused by products of a cathodic reaction.

CATHODIC INHIBITOR A chemical substance that prevents or reduces the rate of the cathodic or reduction reaction.

The electrolyte adjacent to the cathode of an electrochemical cell.

CATION A positively charged ion that migrates through the electrolyte toward the cathode under the influence of a potential gradient.

CAVITATION The formation and rapid collapse of cavities or bubbles within a liquid which often results in damage to a material at the solid/liquid interface under conditions of severe turbulent flow.

CELL [See Electrochemical Cell.]

CEMENTATION The introduction of one or more elements into the surface layer of a metal by diffusion at high temperature. (Examples of cementation include carburizing [introduction of carbon], nitriding [introduction of nitrogen], and chromizing [introduction of chromium].)

CHALKING The development of loose, removable powder (pigment) at

the surface of an organic coating, usually caused by weathering.

CHECKING The development of slight breaks in a coating which do not penetrate to the underlying surface.

CHEMICAL CONVERSION COATING An adherent reaction product layer on a metal surface formed by reaction with a suitable chemical to provide greater corrosion resistance to the metal and increase adhesion of coatings applied to the metal. (Example is an iron phosphate coating on steel, developed by reaction with phosphoric acid.)

CHEVRON PATTERN A V-shaped pattern on a fatigue or brittle-fracture surface. The pattern can also be one of straight radial lines on cylindrical specimens.

CHLORIDE STRESS CORROSION CRACKING Cracking of a metal under the combined action of tensile stress and corrosion in the presence of chlorides and an electrolyte (usually water).

COAT One layer of a coating applied to a surface in a single continuous application to form a uniform film when dry.

COATING A liquid, liquefiable, or mastic composition that, after application to a surface, is converted into a solid protective, decorative, or functional adherent film.

© 2002, NACE International. This publication may not be reprinted without the written consent of NACE International. Page 3 of 18

NACE GLOSSARY OF CORROSION-RELATED TERMS COATING SYSTEM The complete number and types of coats applied to a substrate in a predetermined order. (When used in a broader sense, surface preparation, pretreatments, dry film thickness, and manner of application are included.)

COLD LAP (1) Discontinuity caused by solidification of the meniscus of a partially cast anode as a result of interrupted flow of the casting stream. The solidified meniscus is covered with metal when the flow resumes. Cold laps can occur along the length of an anode. (2) A protective film consisting of one or more coats, applied in a predetermined order by prescribed methods to an asspecified dry film thickness, including any reinforcing material that may be specified.

COLD SHUT Horizontal surface discontinuity caused by solidification of a portion of a meniscus during the progressive filling of a mold, which is later covered with more solidifying metal as the molten metal level rises. Cold shuts generally occur at corners remote from the point of pour.

COMMERCIAL BLAST CLEANED SURFACE A commercial blast cleaned surface, when viewed without magnification, shall be free of all visible oil, grease, dust, dirt, mill scale, rust, coating, oxides, corrosion products, and other foreign matter. Random staining shall be limited to no more than 33 percent of each unit area (approximately 58 cm2 [9.0 in.2]) of surface and may consist of light shadows, slight streaks, or

minor discolorations caused by stains of rust, stains of mill scale, or stains of previously applied coating. [See NACE No. 3/SSPC-SP 6.]

CONCENTRATION CELL An electrochemical cell, the electromotive force of which is caused by a difference in concentration of some component in the electrolyte. (This difference leads to the formation of discrete cathodic and anodic regions.)

CONCENTRATION POLARIZATION That portion of polarization of a cell produced by concentration changes resulting from passage of current though the electrolyte.

CONDUCTIVE COATING (1) A coating that conducts electricity. (2) An electrically conductive, mastic-like material used as an impressed current anode on reinforced concrete surfaces.

CONDUCTIVE CONCRETE A highly conductive cementbased mixture containing coarse and fine coke and other material used as an impressed current anode on reinforced concrete surfaces.

CONDUCTIVITY (1) A measure of the ability of a material to conduct an electric charge. It is the reciprocal of resistivity. (2) The current transferred across a material (e.g., coating) per unit potential gradient.

CONTACT CORROSION [See Galvanic Corrosion.]

CONTINUITY BOND A connection, usually metallic, that provides electrical continuity between structures that can conduct electricity.

CONTINUOUS ANODE A single anode with no electrical discontinuities.

CONVERSION COATING [See Chemical Conversion Coating.]

CORROSION The deterioration of a material, usually a metal, that results from a reaction with its environment.

CORROSION FATIGUE Fatigue-type cracking of metal caused by repeated or fluctuating stresses in a corrosive environment characterized by shorter life than would be encountered as a result of either the repeated or fluctuating stress alone or the corrosive environment alone.

CORROSION INHIBITOR A chemical substance or combination of substances that, when present in the environment, prevents or reduces corrosion.

CORROSION POTENTIAL (Ecorr) The potential of a corroding surface in an electrolyte relative to a reference electrode under open-circuit conditions (also known as rest potential, opencircuit potential, or freely corroding potential).

© 2002, NACE International. This publication may not be reprinted without the written consent of NACE International. Page 4 of 18

NACE GLOSSARY OF CORROSION-RELATED TERMS CORROSION RATE The rate at which corrosion proceeds.

CORROSION RESISTANCE Ability of a material, usually a metal, to withstand corrosion in a given system.

CORROSIVENESS The tendency of an environment to cause corrosion.

COUNTER ELECTRODE [See Auxiliary Electrode.]

COUNTERPOISE A conductor or system of conductors arranged beneath a power line, located on, above, or most frequently, below the surface of the earth and connected to the footings of the towers or poles supporting the power line.

COUPLE [See Galvanic Couple.]

CRACKING (OF COATING) Breaks in a coating that extend through to the substrate.

CRAZING A network of checks or cracks appearing on the surface of a coating.

CREEP Time-dependent strain occurring under stress.

CREVICE CORROSION Localized corrosion of a metal surface at, or immediately adjacent to, an area that is shielded from full exposure to the

environment because of close proximity of the metal to the surface of another material.

CRITICAL HUMIDITY The relative humidity above which the atmospheric corrosion rate of some metals increases sharply.

CRITICAL PITTING POTENTIAL (Ep, Epp)

The lowest value of oxidizing potential (voltage) at which pits nucleate and grow. The value depends on the test method used.

CURING Chemical process of developing the intended properties of a coating or other material (e.g., resin) over a period of time.

CURING AGENT A chemical substance used for curing a coating or other material (e.g., resin). [Also referred to as Hardener.]

CURRENT

D DC DECOUPLING DEVICE A device used in electrical circuits that allows the flow of alternating current (AC) in both directions and stops or substantially reduces the flow of direct current (DC).

DEALLOYING The selective corrosion of one or more components of a solid solution alloy (also known as parting or selective dissolution).

DECOMPOSITION POTENTIAL The potential (voltage) on a metal surface necessary to decompose the electrolyte of an electrochemical cell or a component thereof.

DECOMPOSITION VOLTAGE [See Decomposition Potential.]

(1) A flow of electric charge. (2) The amount of electric charge flowing past a specified circuit point per unit time, measured in the direction of net transport of positive charges. (In a metallic conductor, this is the opposite direction of the electron flow.)

DEEP GROUNDBED

CURRENT DENSITY The current to or from a unit area of an electrode surface.

The removal of factors resisting the current in an electrochemical cell.

CURRENT EFFICIENCY

DEPOSIT ATTACK

The ratio of the electrochemical equivalent current density for a specific reaction to the total applied current density.

One or more anodes installed vertically at a nominal depth of 15 m (50 ft) or more below the earth's surface in a drilled hole for the purpose of supplying cathodic protection.

DEPOLARIZATION

Corrosion occurring under or around a discontinuous deposit on a metallic surface (also known as poultice corrosion).

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NACE GLOSSARY OF CORROSION-RELATED TERMS DEZINCIFICATION A corrosion phenomenon resulting in the selective removal of zinc from copper-zinc alloys. (This phenomenon is one of the more common forms of dealloying.)

DIELECTRIC COATING A coating that does not conduct electricity.

DIELECTRIC SHIELD An electrically nonconductive material, such as a coating, sheet or pipe, that is placed between an anode and an adjacent cathode, usually on the cathode, to improve current distribution in a cathodic protection system.

DIFFERENTIAL AERATION CELL An electrochemical cell, the electromotive force of which is due to a difference in air (oxygen) concentration at one electrode as compared with that at another electrode of the same material.

DIFFUSION-LIMITED CURRENT DENSITY The current density that corresponds to the maximum transfer rate that a particular species can sustain because of the limitation of diffusion (often referred to as limiting current density).

DISBONDMENT The loss of adhesion between a coating and the substrate.

DISSIMILAR METALS Different metals that could form an anode-cathode relationship in an electrolyte when connected by

a metallic path.

DOUBLE LAYER The interface between an electrode or a suspended particle and an electrolyte created by charge-charge interaction leading to an alignment of oppositely charged ions at the surface of the electrode or particle. The simplest model is represented by a parallel plate condenser.

DOUBLER PLATE An additional plate or thickness of steel used to provide extra strength at the point of anode attachment to an offshore platform.

DRAINAGE Conduction of electric current from an underground or submerged metallic structure by means of a metallic conductor.

DRIVING POTENTIAL Difference in potential between the anode and the steel structure.

DRYING OIL An oil capable of conversion from a liquid to a solid by slow reaction with oxygen in the air.

E ELASTIC DEFORMATION Changes of dimensions of a material upon the application of a stress within the elastic range. Following the release of an elastic stress, the material returns to its original dimensions without any permanent deformation.

ELASTIC LIMIT The maximum stress to which a material may be subjected without retention of any permanent deformation after the stress is removed.

ELASTICITY The property of a material that allows it to recover its original dimensions following deformation by a stress below its elastic limit.

ELECTRICAL INTERFERENCE Any electrical disturbance on a metallic structure in contact with an electrolyte caused by stray current(s).

ELECTRICAL ISOLATION The condition of being electrically separated from other metallic structures or the environment.

ELECTRO-OSMOSIS The migration of water through a semipermeable membrane as a result of a potential difference caused by the flow of electric charge through the membrane.

ELECTROCHEMICAL CELL A system consisting of an anode and a cathode immersed in an electrolyte so as to create an electrical circuit. The anode and cathode may be different metals or dissimilar areas on the same metal surface.

ELECTROCHEMICAL EQUIVALENT The mass of an element or group of elements oxidized or reduced at 100% efficiency by the passage of a unit quantity of electricity.

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NACE GLOSSARY OF CORROSION-RELATED TERMS ELECTROCHEMICAL POTENTIAL The partial derivative of the total electrochemical free energy of a constituent with respect to the number of moles of this constituent where all other factors are kept constant. It is analogous to the chemical potential of a constituent except that it includes the electrical as well as chemical contributions to the free energy.

ELECTRODE A conductor used to establish contact with an electrolyte and through which current is transferred to or from an electrolyte.

ELECTRODE POTENTIAL The potential of an electrode in an electrolyte as measured against a reference electrode. (The electrode potential does not include any resistance losses in potential in either the electrolyte or the external circuit. It represents the reversible work to move a unit of charge from the electrode surface through the electrolyte to the reference electrode.)

ELECTROKINETIC POTENTIAL A potential difference in a solution caused by residual, unbalanced charge distribution in the adjoining solution, producing a double layer. The electrokinetic potential is different from the electrode potential in that it occurs exclusively in the solution phase. This potential represents the reversible work necessary to bring a unit charge from infinity in the solution up to the interface in question but not through the interface (also known

as zeta potential).

ELECTROLYTE A chemical substance containing ions that migrate in an electric field.

ELECTROLYTIC CLEANING

the anode, resulting from higher current density.

ENDURANCE LIMIT The maximum stress that a material can withstand for an infinitely large number of fatigue cycles.

A process for removing soil, scale, or corrosion products from a metal surface by subjecting the metal as an electrode to an electric current in an electrolytic bath.

ENVIRONMENT

ELECTROMOTIVE FORCE SERIES

Brittle fracture of a normally ductile material in which the corrosive effect of the environment is a causative factor.

A list of elements arranged according to their standard electrode potentials, the sign being positive for elements whose potentials are cathodic to hydrogen and negative for those anodic to hydrogen.

ELLIPSOMETRY An optical analytical technique employing plane-polarized light to study films.

EMBRITTLEMENT Loss of ductility of a material resulting from a chemical or physical change.

EMF SERIES [See Electromotive Force Series.]

ENAMEL (1) A paint that dries to a hard, glossy surface. (2) A coating that is characterized by an ability to form a smooth, durable film.

END EFFECT The more rapid loss of anode material at the end of an anode, compared with other surfaces of

The surroundings or conditions (physical, chemical, mechanical) in which a material exists.

ENVIRONMENTAL CRACKING

Environmental cracking is a general term that includes all of the terms listed below. The definitions of these terms are listed elsewhere in the Glossary: Corrosion Fatigue Hydrogen Embrittlement Hydrogen-Induced Cracking ⎯ (Stepwise Cracking) Hydrogen Stress Cracking Liquid Metal Cracking Stress Corrosion Cracking Sulfide Stress Cracking The following terms have been used in the past in connection with environmental cracking but are now obsolete and should not be used: Caustic Embrittlement Delayed Cracking Liquid Metal Embrittlement Season Cracking Static Fatigue Sulfide Corrosion Cracking Sulfide Stress Corrosion Cracking

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NACE GLOSSARY OF CORROSION-RELATED TERMS EPOXY

EXTERNAL CIRCUIT

FILM

Type of resin formed by the reaction of aliphatic or aromatic polyols (like bisphenol) with epichlorohydrin and characterized by the presence of reactive oxirane end groups.

The wires, connectors, measuring devices, current sources, etc., that are used to bring about or measure the desired electrical conditions within an electrochemical cell. It is this portion of the cell through which electrons travel.

A thin, not necessarily visible layer of material.

EQUILIBRIUM POTENTIAL The potential of an electrode in an electrolyte at which the forward rate of a given reaction is exactly equal to the reverse rate; the electrode potential with reference to a standard equilibrium, as defined by the Nernst equation.

EROSION 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 carried with the fluid.

EROSION-CORROSION A conjoint action involving corrosion and erosion in the presence of a moving corrosive fluid or a material moving through the fluid, leading to accelerated loss of material.

EXCHANGE CURRENT The rate at which either positive or negative charges are entering or leaving the surface when an electrode reaches dynamic equilibrium in an electrolyte.

EXFOLIATION CORROSION Localized subsurface corrosion in zones parallel to the surface that result in thin layers of uncorroded metal resembling the pages of a book.

F FATIGUE The phenomenon leading to fracture of a material under repeated or fluctuating stresses having a maximum value less than the tensile strength of the material.

FATIGUE STRENGTH The maximum stress that can be sustained for a specified number of cycles without failure.

FAULT CURRENT A current that flows from one conductor to ground or to another conductor due to an abnormal connection (including an arc) between the two. A fault current flowing to ground may be called a ground fault current.

FERRITE The body-centered cubic crystalline phase of iron-based alloys.

FERRITIC STEEL A steel whose microstructure at room temperature consists predominantly of ferrite.

FILIFORM CORROSION Corrosion that occurs under a coating in the form of randomly distributed thread-like filaments.

FINISH COAT [See Topcoat.]

FORCED DRAINAGE Drainage applied to underground or submerged metallic structures by means of an applied electromotive force or sacrificial anode.

FOREIGN STRUCTURE Any metallic structure that is not intended as a part of a system under cathodic protection.

FOULING An accumulation of deposits. This includes accumulation and growth of marine organisms on a submerged metal surface and the accumulation of deposits (usually inorganic) on heat exchanger tubing.

FRACTOGRAPHY Descriptive treatment of fracture, especially in metals, with specific reference to photographs of the fracture surface.

FRACTURE MECHANICS A quantitative analysis for evaluating structural reliability in terms of applied stress, crack length, and specimen geometry.

FREE MACHINING The machining characteristics of an alloy to which an ingredient has been introduced to give small broken chips, lower power consumption, better surface finish, and longer tool life.

FRETTING CORROSION Deterioration at the interface of

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NACE GLOSSARY OF CORROSION-RELATED TERMS two contacting surfaces under load which is accelerated by their relative motion.

technique whereby an electrode is maintained at a constant current in an electrolyte.

FURAN

GENERAL CORROSION

Type of resin formed by the polymerization or polycondensation of furfuryl, furfuryl alcohol, or other compounds containing a furan ring.

Corrosion that is distributed more or less uniformly over the surface of a material.

G GALVANIC ANODE A metal that provides sacrificial protection to another metal that is more noble when electrically coupled in an electrolyte. This type of anode is the electron source in one type of cathodic protection.

GALVANIC CORROSION Accelerated corrosion of a metal because of an electrical contact with a more noble metal or nonmetallic conductor in a corrosive electrolyte.

GALVANIC COUPLE A pair of dissimilar conductors, commonly metals, in electrical contact in an electrolyte.

GALVANIC CURRENT The electric current between metals or conductive nonmetals in a galvanic couple.

GALVANIC SERIES A list of metals and alloys arranged according to their corrosion potentials in a given environment.

GALVANOSTATIC Refers to an experimental

that is characteristic and reproducible; when coupled with another half-cell, an overall potential that is the sum of both half-cells develops.

HALF-CELL POTENTIAL

Deterioration of gray cast iron in which the metallic constituents are selectively leached or converted to corrosion products, leaving the graphite intact.

The potential in a given electrolyte of one electrode of a pair relative to a standard state or a reference state. Potentials can only be measured and expressed as the difference between the half-cell potentials of a pair of electrodes.

GRAPHITIZATION

HAND TOOL CLEANING

GRAPHITIC CORROSION

The formation of graphite in iron or steel, usually from decomposition of iron carbide at elevated temperatures. [Should not be used as a term to describe graphitic corrosion.]

Removal of loose rust, loose mill scale, and loose paint to degree specified, by hand chipping, scraping, sanding, and wire brushing. [See SSPC-SP 2.]

GRIT

[See Curing Agent.]

Small particles of hard material (e.g., iron, steel, or mineral) with irregular shapes that are commonly used as an abrasive in abrasive blast cleaning.

GRIT BLASTING Abrasive blast cleaning using grit as the abrasive.

GROUNDBED One or more anodes installed below the earth's surface for the purpose of supplying cathodic protection.

H

HARDENER HEAT-AFFECTED ZONE That portion of the base metal that is not melted during brazing, cutting, or welding, but whose microstructure and properties are altered by the heat of these processes.

HEAT TREATMENT Heating and cooling a solid metal or alloy in such a way as to obtain desired properties. Heating for the sole purpose of hot working is not considered heat treatment.

HIGH-PRESSURE WATER CLEANING

HALF-CELL A pure metal in contact with a solution of known concentration of its own ion, at a specific temperature, develops a potential

Water cleaning performed at pressures from 34 to 70 MPa (5,000 to 10,000 psig).

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NACE GLOSSARY OF CORROSION-RELATED TERMS HIGH-PRESSURE WATER JETTING

HYDROGEN STRESS CRACKING

Water jetting performed at pressures from 70 to 170 MPa (10,000 to 25,000 psig).

Cracking that results from the presence of hydrogen in a metal in combination with tensile stress. It occurs most frequently with high-strength alloys.

HIGH-TEMPERATURE HYDROGEN ATTACK A loss of strength and ductility of steel by high-temperature reaction of absorbed hydrogen with carbides in the steel, resulting in decarburization and internal fissuring.

HOLIDAY A discontinuity in a protective coating that exposes unprotected surface to the environment.

HYDROGEN BLISTERING The formation of subsurface planar cavities, called hydrogen blisters, in a metal resulting from excessive internal hydrogen pressure. Growth of nearsurface blisters in low-strength metals usually results in surface bulges.

HYDROGEN EMBRITTLEMENT A loss of ductility of a metal resulting from absorption of hydrogen.

HYDROGEN-INDUCED CRACKING Stepwise internal cracks that connect adjacent hydrogen blisters on different planes in the metal, or to the metal surface (also known as stepwise cracking).

HYDROGEN OVERVOLTAGE Overvoltage associated with the liberation of hydrogen gas.

I

oxide, sulfide, or silicate particle in a metal.

INORGANIC ZINC-RICH COATING Coating containing a metallic zinc pigment (typically 75 wt% zinc or more in the dry film) in an inorganic vehicle.

INSTANT-OFF POTENTIAL

IMPINGEMENT CORROSION A form of erosion-corrosion generally associated with the local impingement of a highvelocity, flowing fluid against a solid surface.

IMPRESSED CURRENT An electric current supplied by a device employing a power source that is external to the electrode system. (An example is direct current for cathodic protection.)

IMPRESSED CURRENT ANODE An electrode, suitable for use as an anode when connected to a source of impressed current, which is generally composed of a substantially inert material that conducts by oxidation of the electrolyte and, for this reason, is not corroded appreciably.

IMPULSE DIELECTRIC TEST A method of applying voltage to an insulated wire through the use of electric pulses (usually 170 to 250 pulses per second) to determine the integrity of the wire’s insulation.

INCLUSION A nonmetallic phase such as an

The polarized half-cell potential of an electrode taken immediately after the cathodic protection current is stopped, which closely approximates the potential without IR drop (i.e., the polarized potential) when the current was on.

INTERCRYSTALLINE CORROSION [See Intergranular Corrosion.]

INTERDENDRITIC CORROSION Corrosive attack of cast metals that progresses preferentially along paths between dendrites.

INTERFERENCE BOND An intentional metallic connection, between metallic systems in contact with a common electrolyte, designed to control electrical current interchange between the systems.

INTERFERENCE CURRENT [See Stray Current.]

INTERGRANULAR CORROSION Preferential corrosion at or along the grain boundaries of a metal (also known as intercrystalline

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NACE GLOSSARY OF CORROSION-RELATED TERMS corrosion).

INTERGRANULAR STRESS CORROSION CRACKING Stress corrosion cracking in which the cracking occurs along grain boundaries.

INTERNAL OXIDATION The formation of isolated particles of oxidation products beneath the metal surface.

INTUMESCENCE The swelling or bubbling of a coating usually caused by heating. [The term is commonly used in aerospace and fireprotection applications.]

ION An electrically charged atom or group of atoms.

IR DROP The voltage across a resistance in accordance with Ohm’s Law.

IRON ROT Deterioration of wood in contact with iron-based alloys.

K KNIFE-LINE ATTACK Intergranular corrosion of an alloy along a line adjoining or in contact with a weld after heating into the sensitization temperature range.

LOW-PRESSURE WATER CLEANING

L LAMELLAR CORROSION [See Exfoliation Corrosion.]

LANGELIER INDEX A calculated saturation index for calcium carbonate that is useful in predicting scaling behavior of natural water.

LINE CURRENT The direct current flowing on a pipeline.

LINING A coating or layer of sheet material adhered to or in intimate contact with the interior surface of a container used to protect the container against corrosion by its contents and/or to protect the contents of the container from contamination by the container material.

LIQUID METAL CRACKING Cracking of a metal caused by contact with a liquid metal.

LONG-LINE CURRENT Current though the earth between an anodic and a cathodic area that returns along an underground metallic structure.

LOW-CARBON STEEL Steel having less than 0.30% carbon and no intentional alloying additions.

Water cleaning performed at pressures less than 34 MPa (5,000 psig).

LUGGIN PROBE A small tube or capillary filled with electrolyte, terminating close to the metal surface of an electrode under study, which is used to provide an ionconducting path without diffusion between the electrode under study and a reference electrode.

M MARTENSITE A hard supersaturated solid solution of carbon in iron characterized by an acicular (needle-like) microstructure.

METAL DUSTING The catastrophic deterioration of a metal exposed to a carbonaceous gas at elevated temperature.

METALLIZING The coating of a surface with a thin metal layer by spraying, hot dipping, or vacuum deposition.

MILL SCALE The oxide layer formed during hot fabrication or heat treatment of metals.

MIXED POTENTIAL A potential resulting from two or more electrochemical reactions occurring simultaneously on one metal surface.

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NACE GLOSSARY OF CORROSION-RELATED TERMS MODULUS OF ELASTICITY A measure of the stiffness or rigidity of a material. It is actually the ratio of stress to strain in the elastic region of a material. If determined by a tension or compression test, it is also called Young’s Modulus or the coefficient of elasticity.

N NATURAL DRAINAGE Drainage from an underground or submerged metallic structure to a more negative (more anodic) structure, such as the negative bus of a trolley substation.

NEAR-WHITE BLAST CLEANED SURFACE A near-white blast cleaned surface, when viewed without magnification, shall be free of all visible oil, grease, dust, dirt, mill scale, rust, coating, oxides, corrosion products, and other foreign matter. Random staining shall be limited to not more than 5% of each unit area of surface (approximately 58 cm2 [9.0 in.2]), and may consist of light shadows, slight streaks, or minor discolorations caused by stains of rust, stains of mill scale, or stains of previously applied coating. [See NACE No. 2/SSPC-SP 10.]

NEGATIVE RETURN A point of connection between the cathodic protection negative cable and the protected structure.

exact electromotive force of an electrochemical cell in terms of the activities of products and reactants of the cell.

measured with respect to a reference electrode or another electrode in the absence of current.

NERNST LAYER

ORGANIC ZINC-RICH COATING

The diffusion layer at the surface of an electrode in which the concentration of a chemical species is assumed to vary linearly from the value in the bulk solution to the value at the electrode surface.

NOBLE The positive direction of electrode potential, thus resembling noble metals such as gold and platinum.

NOBLE METAL (1) A metal that occurs commonly in nature in the free state. (2) A metal or alloy whose corrosion products are formed with a small negative or a positive free-energy change.

NOBLE POTENTIAL A potential more cathodic (positive) than the standard hydrogen potential.

NORMALIZING Heating a ferrous alloy to a suitable temperature above the transformation range (austenitizing), holding at temperature for a suitable time, and then cooling in still air to a temperature substantially below the transformation range.

O

Coating containing a metallic zinc pigment (typically 75 wt% zinc or more in the dry film) in an organic resin.

OVERVOLTAGE The change in potential of an electrode from its equilibrium or steady-state value when current is applied.

OXIDATION (1) Loss of electrons by a constituent of a chemical reaction. (2) Corrosion of a metal that is exposed to an oxidizing gas at elevated temperatures.

OXIDATION-REDUCTION POTENTIAL The potential of a reversible oxidation-reduction electrode measured with respect to a reference electrode, corrected to the hydrogen electrode, in a given electrolyte.

OXYGEN CONCENTRATION CELL [See Differential Aeration Cell.]

P PAINT

NERNST EQUATION

OPEN-CIRCUIT POTENTIAL

An equation that expresses the

The potential of an electrode

A pigmented liquid or resin applied to a substrate as a thin layer that is converted to an opaque solid film after application. It is commonly used

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NACE GLOSSARY OF CORROSION-RELATED TERMS as a decorative or protective coating.

PAINT SYSTEM [See Coating System.]

PARTING [See Dealloying.]

PASSIVATION A reduction of the anodic reaction rate of an electrode involved in corrosion.

PASSIVATION POTENTIAL [See Primary Passive Potential.]

PASSIVE (1) The positive direction of electrode potential. (2) A state of a metal in which a surface reaction product causes a marked decrease in the corrosion rate relative to that in the absence of the product.

PASSIVE-ACTIVE CELL An electrochemical cell, the electromotive force of which is caused by the potential difference between a metal in an active state and the same metal in a passive state.

PASSIVITY The state of being passive.

PATINA A thin layer of corrosion product, usually green, that forms on the surface of metals such as copper and copper-based alloys exposed to the atmosphere.

pH The negative logarithm of the hydrogen ion activity written as: pH = -log10 (aH+)

where aH+ = hydrogen ion activity = the molar concentration of hydrogen ions multiplied by the mean ion-activity coefficient.

PLASTIC DEFORMATION

PICKLING

PLASTICITY

(1) Treating a metal in a chemical bath to remove scale and oxides (e.g., rust) from the surface. (2) Complete removal of rust and mill scale by acid pickling, duplex pickling, or electrolytic pickling. [See SSPC-SP 8.]

PICKLING SOLUTION A chemical bath, usually an acid solution, used for pickling.

PIGMENT A solid substance, generally in fine powder form, that is insoluble in the vehicle of a formulated coating material. It is used to impart color or other specific physical or chemical properties to the coating.

PIPE-TO-ELECTROLYTE POTENTIAL [See Structure-to-Electrolyte Potential.]

PIPE-TO-SOIL POTENTIAL

Permanent deformation caused by stressing beyond the elastic limit.

The ability of a material to deform permanently (nonelastically) without fracturing.

POLARIZATION The change from the open-circuit potential as a result of current across the electrode/electrolyte interface.

POLARIZATION ADMITTANCE The reciprocal of polarization resistance.

POLARIZATION CELL A DC decoupling device consisting of two or more pairs of inert metallic plates immersed in an aqueous electrolyte. The electrical characteristics of the polarization cell are high resistance to DC potentials and low impedance of AC.

POLARIZATION CURVE

[See Structure-to-Electrolyte Potential.]

A plot of current density versus electrode potential for a specific electrode/electrolyte combination.

PITTING

POLARIZATION DECAY

Localized corrosion of a metal surface that is confined to a small area and takes the form of cavities called pits.

The decrease in electrode potential with time resulting from the interruption of applied current.

PITTING FACTOR

POLARIZATION RESISTANCE

The ratio of the depth of the deepest pit resulting from corrosion divided by the average penetration as calculated from mass loss.

The slope (dE/di) at the corrosion potential of a potential (E)-current density (i) curve. (The measured slope is usually in good agreement with the true value of

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NACE GLOSSARY OF CORROSION-RELATED TERMS the polarization resistance when the scan rate is low and any uncompensated resistance is small relative to the polarization resistance.)

POLARIZED POTENTIAL The potential across the structure/electrolyte interface that is the sum of the corrosion potential and the cathodic polarization.

POLYESTER Type of resin formed by the condensation of polybasic and monobasic acids with polyhydric alcohols.

POSTWELD HEAT TREATMENT Heating and cooling a weldment in such a way as to obtain desired properties.

POTENTIAL-pH DIAGRAM A graphical method of representing the regions of thermodynamic stability of species for metal/electrolyte systems (also known as Pourbaix diagram).

POTENTIODYNAMIC Refers to a technique wherein the potential of an electrode with respect to a reference electrode is varied at a selected rate by application of a current through the electrolyte.

POTENTIOKINETIC [See Potentiodynamic.]

POTENTIOSTAT An instrument for automatically maintaining a constant electrode potential.

POTENTIOSTATIC Refers to a technique for maintaining a constant electrode potential.

POT LIFE The elapsed time within which a coating can be effectively applied after all components of the coating have been thoroughly mixed.

POULTICE CORROSION [See Deposit Attack.]

POURBAIX DIAGRAM

for subsequent coats. [Also referred to as Prime Coat.]

PROFILE Anchor pattern on a surface produced by abrasive blasting or acid treatment.

PROTECTIVE COATING A coating applied to a surface to protect the substrate from corrosion.

R

[See Potential-pH Diagram.]

POWER TOOL CLEANING Removal of loose rust, loose mill scale, and loose paint to degree specified by power tool chipping, descaling, sanding, wire brushing, and grinding. [See SSPC-SP 3.]

PRECIPITATION HARDENING Hardening caused by the precipitation of a constituent from a supersaturated solid solution.

PRIMARY PASSIVE POTENTIAL The potential corresponding to the maximum active current density (critical anodic current density) of an electrode that exhibits active-passive corrosion behavior.

PRIME COAT [See Primer.]

PRIMER A coating material intended to be applied as the first coat on an uncoated surface. The coating is specifically formulated to adhere to and protect the surface as well as to produce a suitable surface

REDUCTION Gain of electrons by a constituent of a chemical reaction.

REFERENCE ELECTRODE An electrode whose open-circuit potential is constant under similar conditions of measurement, which is used for measuring the relative potentials of other electrodes.

REFERENCE HALF-CELL [See Reference Electrode.]

RELATIVE HUMIDITY The ratio, expressed as a percentage, of the amount of water vapor present in a given volume of air at a given temperature to the amount required to saturate the air at that temperature.

REMOTE EARTH A location on the earth far enough from the affected structure that the soil potential gradients associated with currents entering the earth from the affected structure are

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NACE GLOSSARY OF CORROSION-RELATED TERMS insignificant.

using a cement sack, gunny sack, or sponge rubber float.

RESISTIVITY (1) The resistance per unit length of a substance with uniform cross section. (2) A measure of the ability of an electrolyte (e.g., soil) to resist the flow of electric charge (e.g., cathodic protection current). Resistivity data are used to design a groundbed for a cathodic protection system.

REST POTENTIAL

SACRIFICIAL ANODE [See Galvanic Anode.]

SHOP COAT

Reduction of corrosion of a metal in an electrolyte by galvanically coupling it to a more anodic metal (a form of cathodic protection).

SHOT BLASTING

SCALING

REVERSIBLE POTENTIAL

(1) The formation at high temperatures of thick corrosionproduct layers on a metal surface. (2) The deposition of water-insoluble constituents on a metal surface.

RIMMED STEEL An incompletely deoxidized steel. [Also called Rimming Steel.]

RISER (1) That section of pipeline extending from the ocean floor up to an offshore platform. (2) The vertical tube in a steam generator convection bank that circulates water and steam upward.

RUST Corrosion product consisting of various iron oxides and hydrated iron oxides. (This term properly applies only to iron and ferrous alloys.)

RUST BLOOM Discoloration indicating the beginning of rusting.

S SACKING Scrubbing a mixture of a cement mortar over the concrete surface

(1) Protecting; protective cover against mechanical damage. (2) Preventing or diverting cathodic protection current from its natural path.

SACRIFICIAL PROTECTION

[See Corrosion Potential.]

[See Equilibrium Potential.]

SHIELDING

SCANNING ELECTRON MICROSCOPE

One or more coats applied in a shop or plant prior to shipment to the site of erection or fabrication.

Abrasive blast cleaning using metallic (usually steel) shot as the abrasive.

SHOT PEENING Inducing compressive stresses in the surface layer of a material by bombarding it with a selected medium (usually steel shot) under controlled conditions.

An electron optical device that images topographical details with maximum contrast and depth of field by the detection, amplification, and display of secondary electrons.

SIGMA PHASE

SENSITIZING HEAT TREATMENT

A deformation process involving shear motion of a specific set of crystallographic planes.

A heat treatment, whether accidental, intentional, or incidental (as during welding), that causes precipitation of constituents (usually carbides) at grain boundaries, often causing the alloy to become susceptible to intergranular corrosion or intergranular stress corrosion cracking.

SHALLOW GROUNDBED One or more anodes installed either vertically or horizontally at a nominal depth of less than 15 m (50 ft) for the purpose of supplying cathodic protection.

An extremely brittle Fe-Cr phase that can form at elevated temperatures in Fe-Cr-Ni and NiCr-Fe alloys.

SLIP

SLOW STRAIN RATE TECHNIQUE An experimental technique for evaluating susceptibility to environmental cracking. It involves pulling the specimen to failure in uniaxial tension at a controlled slow strain rate while the specimen is in the test environment and examining the specimen for evidence of environmental cracking.

SLUSHING COMPOUND Oil or grease coatings used to

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NACE GLOSSARY OF CORROSION-RELATED TERMS provide temporary protection against atmospheric corrosion.

SOLUTION HEAT TREATMENT

abrasive blast cleaning or as a selected medium for shot peening.

STEP POTENTIAL

Heating a metal to a suitable temperature and holding at that temperature long enough for one or more constituents to enter into solid solution, then cooling rapidly enough to retain the constituents in solution.

The potential difference between two points on the earth’s surface separated by a distance of one human step, which is defined as one meter, determined in the direction of maximum potential gradient.

SOLVENT CLEANING

STEPWISE CRACKING

Removal of oil, grease, dirt, soil, salts, and contaminants by cleaning with solvent, vapor, alkali, emulsion, or steam. [See SSPC-SP 1.]

SPALLING The spontaneous chipping, fragmentation, or separation of a surface or surface coating.

STANDARD ELECTRODE POTENTIAL The reversible potential for an electrode process when all products and reactions are at unit activity on a scale in which the potential for the standard hydrogen reference electrode is zero.

STANDARD JETTING WATER Water of sufficient purity and quality that it does not impose additional contaminants on the surface being cleaned and does not contain sediments or other impurities that are destructive to the proper functioning of water jetting equipment.

[See Hydrogen-Induced Cracking.]

STRAY CURRENT Current through paths other than the intended circuit.

STRAY-CURRENT CORROSION Corrosion resulting from current through paths other than the intended circuit, e.g., by any extraneous current in the earth.

STRESS CORROSION CRACKING Cracking of a material produced by the combined action of corrosion and tensile stress (residual or applied).

STRESS RELIEVING (THERMAL) Heating a metal to a suitable temperature, holding at that temperature long enough to reduce residual stresses, and then cooling slowly enough to minimize the development of new residual stresses.

STRUCTURE-TOELECTROLYTE POTENTIAL The potential difference between the surface of a buried or submerged metallic structure and the electrolyte that is measured with reference to an electrode in contact with the electrolyte.

STRUCTURE-TO-SOIL POTENTIAL [See Structure-to-Electrolyte Potential.]

STRUCTURE-TOSTRUCTURE POTENTIAL The potential difference between metallic structures, or sections of the same structure, in a common electrolyte.

SUBSURFACE CORROSION [See Internal Oxidation.]

SULFIDATION The reaction of a metal or alloy with a sulfur-containing species to produce a sulfur compound that forms on or beneath the surface of the metal or alloy.

SULFIDE STRESS CRACKING Cracking of a metal under the combined action of tensile stress and corrosion in the presence of water and hydrogen sulfide (a form of hydrogen stress cracking).

SURFACE POTENTIAL GRADIENT Change in the potential on the surface of the ground with respect to distance.

STEEL SHOT Small particles of steel with spherical shape that are commonly used as an abrasive in

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NACE GLOSSARY OF CORROSION-RELATED TERMS

T TACK COAT A thin wet coat applied to the surface that is allowed to dry just until it is tacky before application of a thicker wet coat. (Use of a tack coat allows application of thicker coats without sagging or runs.)

TAFEL PLOT A plot of the relationship between the change in potential (E) and the logarithm of the current density (log i) of an electrode when it is polarized in both the anodic and cathodic directions from its open-circuit potential.

TAFEL SLOPE The slope of the straight-line portion of the E log i curve on a Tafel plot. (The straight-line portion usually occurs at more than 50 mV from the open-circuit potential.)

TARNISH Surface discoloration of a metal resulting from formation of a film of corrosion product.

THERMAL SPRAYING A group of processes by which finely divided metallic or nonmetallic materials are deposited in a molten or semimolten condition to form a coating.

THERMOGALVANIC CORROSION Corrosion resulting from an electrochemical cell caused by a thermal gradient.

THROWING POWER

UNDERFILM CORROSION

The relationship between the current density at a point on a surface and its distance from the counterelectrode. The greater the ratio of the surface resistivity shown by the electrode reaction to the volume resistivity of the electrolyte, the better is the throwing power of the process.

[See Filiform Corrosion.]

TOPCOAT The final coat of a coating system. [Also referred to as Finish Coat.]

TOUCH POTENTIAL The potential difference between a metallic structure and a point on the earth’s surface separated by a distance equal to the normal maximum horizontal reach of a human (approximately 1.0 m [3.3 ft]).

TRANSPASSIVE The noble region of potential where an electrode exhibits a higher-than-passive current density.

TUBERCULATION The formation of localized corrosion products scattered over the surface in the form of knoblike mounds called tubercles.

U-V-W ULTIMATE STRENGTH The maximum stress that a material can sustain.

ULTRAHIGH-PRESSURE WATER JETTING Water jetting performed at pressures above 170 MPa (25,000 psig.)

VEHICLE The liquid portion of a formulated coating material.

VOID (1) A holiday, hole, or skip in a coating. (2) A hole in a casting or weld deposit usually resulting from shrinkage during cooling.

WASH PRIMER A thin, inhibiting primer, usually chromate pigmented, with a polyvinyl butyral binder.

WATER CLEANING Use of pressurized water discharged from a nozzle to remove unwanted matter (e.g., dirt, scale, rust, coatings) from a surface.

WATER JETTING Use of standard jetting water discharged from a nozzle at pressures of 70 MPa (10,000 psig) or greater to prepare a surface for coating or inspection.

WEIGHT COATING An external coating applied to a pipeline to counteract buoyancy.

WHITE METAL BLAST CLEANED SURFACE A white metal blast cleaned surface, when viewed without magnification, shall be free of all visible oil, grease, dust, dirt, mill scale, rust, coating, oxides, corrosion products, and other foreign matter. [See NACE No. 1/SSPC-SP 5.]

WELD DECAY Intergranular corrosion, usually of

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NACE GLOSSARY OF CORROSION-RELATED TERMS stainless steel or certain nickelbase alloys, that occurs as the result of sensitization in the heataffected zone during the welding operation. [This is not a preferred term.]

WET FILM GAUGE Device for measuring wet film thickness of a coating.

WORKING ELECTRODE The test or specimen electrode in an electrochemical cell.

WROUGHT Metal in the solid condition that is formed to a desired shape by working (rolling, extruding, forging, etc.), usually at an elevated temperature.

X-Y-Z YIELD POINT The stress on a material at which the first significant permanent or plastic deformation occurs without an increase in stress. In some materials, particularly annealed low-carbon steels, there is a well-defined yield point from the straight line defining the modulus of elasticity.

YIELD STRENGTH The stress at which a material exhibits a specified deviation from the proportionality of stress to strain. The deviation is expressed in terms of strain by either the offset method (usually at a strain of 0.2%) or the totalextension-under-load method (usually at a strain of 0.5%.)

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Glossary for Internal Corrosion

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Glossary for Internal Corrosion Acid-Producing Bacteria (APB):

Bacteria that produce Organic Acids as an end product of their metabolism, which may be aerobic or anaerobic

Aerobic:

Containing or utilizing air or oxygen.

Aerobic Bacteria:

Bacteria that require oxygen for metabolism and growth.

Alkalinity:

A measure of water’s ability to neutralize acids.

Anaerobic:

Free of air or oxygen.

Anaerobic Bacteria:

Bacteria able to grow without free oxygen; oxygen is toxic to many of these organisms.

Anion:

A negatively charged ion (e.g., chloride–Cl-, sulfate–SO4-, etc) that reacts with positively charged ion species (see “Cation”) to form salts or other compounds, which can form scale deposits, and may promote or inhibit corrosion

Anode:

The electrode of an electrochemical cell at which oxidation is the principal reaction and corrosion occurs

Aqueous:

A liquid containing water.

Average Pit Density:

The average number of pits per square centimeter (cm2) located on any side of an Electron Microscope Coupon as observed through a light microscope at a magnification of 10x. This measurement may range from 0 to 99, with a default value of 100 (the maximum detection value) indicating when 100 pits/cm2 or greater are counted.

Batch Treatment:

Sometimes known as slug treatment, performed by injecting corrosion inhibitor or biocide at one location or various selected points on a system. Generally used in conjunction with pigging operations. Normally works best where no free liquids are transported with the gas.

Bicarbonate (HCO3-) Ion:

Is naturally occurring in some oilfield waters and can act as a buffer and prevent the acidity in the water from increasing (see “Alkalinity”) and may also promote scale formation

Biocides:

An additive used to kill or control bacteria. Some biocides also have inhibiting powers in certain corrosive environments.

Calcium (Ca++) Ion:

Calcium is an “active metal” cation that is a common dissolved constituent of most waters that represents a percentage of the total dissolved solids and is a hardness component of water. Calcium ions can combine with sulfate or carbonate ions to form insoluble compounds, which may in turn form deposits and scales that may be protective. Excessive and uncontrolled formation of scale deposits can decrease the diameter of the pipe and create flow problems. Naturally occurring ions in some oilfield waters that participate in the buffering of acids and in the formation of scales.

Carbonate (CO3=) Ion:

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Carbon Dioxide (CO2):

A colorless odorless gas that is present at varying levels in natural gas. When dissolved in soft water, CO2 forms carbonic acid (H2CO3), which is corrosive to iron and steel. When hard water is present, the CO2 will form carbonates (CO32-) and/or bicarbonates (HCO3-).

Cathode:

The electrode of an electrolytic cell at which reduction is the principal reaction.

Cathodic Protection (CP):

A technique to reduce the corrosion rate of a metal surface by making it the cathode of an electrochemical cell. The corrosion rate can be reduced by shifting the corrosion potential of the electrode toward a less oxidizing potential by applying an external Electromotive Force or by using a sacrificial anode.

Cation:

A positively charged ion (e.g., sodium-Na+, iron–Fe2+ or Fe3+) that reacts with negatively charged ion species (see “Anion”) to form salts or other compounds, which can form scales and deposits

Cavitation:

It is the erosion of a surface due to the sudden formation and collapse of bubbles that contain vapor, gas, or both resulting from liquids moving at high velocities. As the bubbles collapse and the surrounding liquid surfaces meet, a great deal of kinetic energy is released and may break a protective surface film on the metal and lead to the beginnings of metal loss/corrosion.

Check Reading:

A reading to test an ER probe using the electronic meter’s two internal references, where the difference of the two should remain constant (relative to temperature).

Chloride (Cl-) Ion:

An anion that is a very common dissolved constituent of most waters and is known to promote corrosion, particularly localized (pitting, crevice, etc.) corrosion. Chloride typically represents the most significant percentage of the total dissolved solids in many water samples because it is the chief component of most brines.

Coating:

A material (usually organic) applied to a structure to separate it from the environment.

Concentration Cell:

An electrolytic cell, the EMF of which is caused by a difference in concentration of some component in the electrolyte. This difference leads to the formation of discrete cathode and anode regions.

Conductivity:

The ability of a substance (measured in ohm-cm) to conduct an electric charge or current due to the presence of positively or negatively charged ions. Theoretically, the higher the conductivity of an electrolyte the greater the chance for corrosion to occur.

Continuous Injection:

A method of applying corrosion inhibitors or biocides by continuous injection of chemical. Can be used in either stratified or annular flows. Generally recommended when the free liquids are transported in the gas stream.

Corrosion:

The chemical or electrochemical reaction between a material, usually a metal, and its environment that produces a deterioration of the material and its properties.

Corrosion Potential (Ecorr):

The potential of a corroding surface in an electrolyte relative to a reference electrode measured under open-circuit conditions. Also called: native potential, rest potential, open-circuit potential, or freely corroding potential.

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Corrosion Coupon:

A small, carefully weighed and measured specimen of metal that is used to determine metal loss caused by corrosion over a specified period of time. Coupons are generally made of the same metal composition as the structure in which they are installed.

Corrosion Rate:

The amount of corrosion occurring in unit time. Generally expressed in mils per year (mpy) for uniform thickness changes or metal loss. A mil is 0.001 inch, or one one-thousandth of an inch. Coupon corrosion rates may help to indicate the severity of corrosion in a system and are calculated using the known values of: W = weight loss/gain (mg--milligrams), D = density of specimen material (g/cm3 grams per cubic centimeter), A = area of coupon specimen (in2 - inches squared), and T = exposure time (days) by the following equation: mpy = W x 365 / D* x 16.4 x A x T *Density of carbon steel = 7.85

Crevice (Contact) Corrosion:

Localized corrosion (similar to pitting) of a metal surface at, or immediately adjacent to, an area that is shielded from full exposure to the environment resulting in an area where flow is stagnated. Shielding may result under washers, flange gaskets, and sediments

Critical Velocity:

The velocity at which erosion-corrosion begins in a pipeline.

Culture Bottles:

Bottles/vials of liquid media formulated to cultivate and quantitate different groups of bacteria found in oilfield/pipeline environments.

Dry System:

A pipeline transporting an acceptable dew point gas, which will not condense free water into the gas stream.

Electrical Isolation:

The condition of being electrically separated from other conductors (e.g., metals).

Electrolyte:

The soil or liquid adjacent to and in contact with a buried or submerged system, including the moisture and other chemicals contained therein. In the electrolyte, the ions present will migrate in an electric field.

Electromotive Force Series (EMF Series):

A list of elements arranged according to their standard electrode potentials, with “noble” metals such as gold being positive and “active” metals such as zinc being negative.

End Weight:

The final weight, in grams (g), of a corrosion coupon after exposing it to pipeline conditions and cleaning. This value is used with the “Start Weight” to determine weight loss (or gain). This weight difference (typically converted to milligrams, mg) is used to calculate the corrosion rate. Note that the end weight may be affected by things other than metal corrosion, including the presence of remaining scale or the removal of metal from the coupon as a result of cleaning or mechanical damage.

Energy-Dispersive Spectroscopy (EDS):

When an electron beam (i.e., SEM) is used to bombard the metal surface or solid sample, x-rays are emitted with a characteristic energy. The characteristic energy peaks emitted then are used to identify individual elements on a qualitative (i.e., not quantitative) basis.

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Erosion:

The progressive loss of material from a solid surface due to mechanical interaction between that surface and a fluid, a multi-component fluid, or solid particles carried with the fluid. In simple erosion, corrosion makes no contribution to the metal loss. Erosion may appear as elongated pits or channels parallel to the flow direction or general metal loss at section changes, bends or elbows. Damage due to erosion generally has a smooth appearance.

Erosion Corrosion:

A conjoint action, involving corrosion and erosion in the presence of a moving corrosive fluid, leading to the accelerated loss of material. In this mechanism, erosion serves to prevent protective scales or films from forming over actively corroding areas. It may occur where changes in a section of pipe cause turbulence, or at bends and elbows. Erosion-corrosion is closely related to impingement corrosion.

Electrical Resistance (ER) Probes:

An electronic probe that can be used in systems where gas or liquids (including hydrocarbons) are present to determine metal loss over time by measuring the increase in the resistance of the electrode as its cross-sectional area is reduced by corrosion. The resistance of the electrode is then compared with the resistance of a standard, non-exposed electrode. The severe loss of ductility or toughness - or both - of a material, usually a metal or alloy.

Embrittlement: Exposure Period:

The number of days a coupon is exposed to system conditions. This value is used to calculate the general corrosion rate and pitting rate.

Facultative Bacteria:

Microorganisms that are capable of growing with or without the presence of a specific environmental factor (e.g., facultative aerobic). When no oxygen is available, such as in natural gas systems or in the anaerobic zone of a biofilm, facultative aerobic organisms utilize sulfates or nitrates as electron acceptors in lieu of O2. A calculation of the speed a gas or liquid moves through a pipe of a specific side diameter.

Flow Velocity: Free Liquids:

Liquids (hydrocarbon or water) that are not vaporized or entrained in the gas phase.

Galvanic Anode:

A metal that preferentially corrodes and provides protection to another metal, as in a sacrificial anode. Also applies to metals that are more noble in the series when coupled in an electrolyte because of its relative position in the galvanic series.

Galvanic Corrosion:

Accelerated corrosion of a metal because of an electrical contact with a more noble metal or nonmetallic conductor in a corrosive electrolyte. Also known as dissimilar metal corrosion.

Galvanic Series:

A list of metals and alloys arranged according to their relative corrosion potentials in a given environment.

Gas Flow:

Stratified Flow - Low gas velocity (liquid concentration on bottom of pipe) Wave Mist – Intermediate gas velocity (liquid concentration partially entrained in the gas flow) Annular Mist – High gas velocity (liquid concentration around circumference of pipe and entrained in the gas flow)

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Grind out (shake out):

To spin a sample of oil at high speed to determine its basic sediment and water content.

Holiday:

Any discontinuity or bare spot in a coated surface.

Hydrogen Sulfide (H2S):

A colorless, poisonous, and flammable gas that has a characteristic rotten egg odor at low concentrations. H2S is very soluble in water. When dissolved it behaves as a weak acid and usually causes pitting of carbon steel, depending on the type of film formed on the metal surface.

Hydroxide (OH-) Ion:

A dissolved constituent of water that has the ability to neutralize acids and act as an anionic inhibitor. OH- ions also make up a component in water’s calculated alkalinity.

Impingement Corrosion:

A form of erosion-corrosion generally associated with the local impingement of a high-velocity, flowing fluid against a solid surface. This type of attack occurs when a liquid stream collides with a metal surface and breaks down protective films in very small areas. Impingement is very similar to erosion-corrosion; but it is usually considered to be due to more direct blasting of the surface by a fluid, which is often the result of turbulence surrounding small particles adhering to the metal surface.

Impressed Current:

An electric current supplied by a device employing a power source that is external to the electrode system. An example is direct current for CP.

Inhibitors:

A chemical substance or combination of substances that, when present in the proper concentration and forms in the environment, prevents or reduces corrosion. Inhibitors have solubility and dispersability characteristics, and some are pH-activated. Depending on the product, concentration levels of 50 to 250 ppm are desired residuals in the appropriate liquid phase.

In-Line Inspection (“Smart Pigging”):

The inspection of a steel pipeline using an electronic instrument or tool that travels along the interior of the pipeline in order to locate corrosion and/or material defects.

In situ:

A Latin phrase meaning "in place." Any process that occurs in the field as opposed to the factory. Internal coating of pipe after installation is called in situ coating.

Intergranular Corrosion:

Preferential corrosion at or adjacent to the grain boundaries of a metal or alloy, with relatively little corrosion of the grains. This occurs when there are dissimilarities in the activities between the grain boundaries and the grain that can be caused by impurities at the grain boundary, enrichment of one of the alloying elements, or depletion of one of these elements in the grain boundary areas.

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Glossary for Internal Corrosion

Iron (Fe++/Fe+++) Ion:

6

Iron is a metallic cation that is a common dissolved constituent of most waters (generally in the oxidized ferric–Fe3+ form) and the chief indicator of corrosion of carbon steel. In anaerobic environments such as natural gas systems, iron may also be present as the reduced ferrous (Fe2+) form. Dissolved iron: Generally determined in the field on untreated aqueous samples using colorimetric methods, it indicates all iron species in solution. Total iron: Generally determined in the laboratory on acidified samples, which solubilize any undissolved iron in the sample for detection of all iron present.

Iron Carbonate (FeCO3):

A corrosion product of iron and steel. FeCO3 scale deposits often form when dissolved iron in water reacts with carbonates and precipitate on metal surfaces. Iron carbonate on the external portion of the pipe is an indicator that CP is reaching that area.

Iron Oxide (Fe2O3):

A very common corrosion product of iron and steels (i.e., “rust”). Fe2O3 scale deposits form when dissolved iron ions in water react with air and precipitate on metal surfaces.

Iron Sulfide (FeS):

A black corrosion product of iron and steel that is corrosive itself. Originates from reactions between dissolved iron and sulfide (S--) ions that may be present from hydrogen sulfide (H2S) in the gas or produced by bacteria

Linear Polarization Resistance (LPR): Probe:

A linear polarization resistance (LPR) probe measures corrosion rates instantaneously by utilizing an electrochemical method known as linear polarization in which the potential of the probe is polarized (changed) from its inherent corrosion potential and the resulting current is measured. This resulting current can then be used to estimate the corrosion rate. Magnesium is a very reactive, divalent metal cation. It is a common dissolved constituent of most waters that represents a percentage of the total dissolved solids and is a major hardness component of water. Magnesium ions can combine with sulfate or carbonate ions to form insoluble compounds, which may in turn form deposits and scales that may be protective. Excessive and uncontrolled formation of scale deposits can decrease the diameter of the pipe and create flow problems. Manganese is a metallic cation that has multiple oxidation states and is a common dissolved constituent of most waters - but usually at relatively low concentrations. Mn is also a constituent of carbon steel. Its presence within liquid samples may not only indicate whether corrosion is occurring within the system but also can be used to follow the corrosion process. Chemical reactions in all living organisms that are responsible for growth and survival. In many microorganisms for example, these reactions are oxidationreduction reactions that are accompanied by a release of energy. Because microbes may act as electron donors or electron acceptors, microorganisms attached to metal surfaces are capable of producing electrochemical reactions that can drive a corrosion cell. Generally used as a freeze-protectant, as a carrier in corrosion inhibitors or biocides, and in dewatering pipelines following hydrotesting.

Magnesium (Mg++) Ion:

Manganese (Mnn+):

Metabolism:

Methanol (CH3OH):

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Microbiologically Influenced Corrosion (MIC):

Corrosion inhibited or accelerated by the presence or activity, or both, of microorganisms, including the effects resulting from metabolic processes. Two groups of bacteria often identified in MIC of natural gas systems are: AcidProducing Bacteria (APB) and Sulfate-Reducing Bacteria (SRB).

Milligrams Per Liter (mg/L):

A weight-volume relationship that is a commonly used unit of measurement for expressing the dissolved constituents detected in water samples. Milligrams per liter (mg/L) is sometimes incorrectly used interchangeably with parts per million (ppm). To convert mg/L to ppm, the following equation can be used: (mg/L) / (specific gravity) = ppm

Mixed Potential:

The potential of a specimen (or specimens in a galvanic couple) when two or more electrochemical reactions are occurring simultaneously (e.g., corrosion of iron as the anodic reaction and reduction of oxygen as the cathodic reaction).

Mole Percent

The percentage of a compound or moles in a sample.

(mol. %):

To convert partial pressure to mol. %, use the following equation: [partial pressure (psia) x 100%] / [pressure (psig) + atmospheric pressure (psi)] For example, if the CO2 partial pressure in natural gas was 5 psia and the pipeline operating pressure was 1,000 psig, the CO2 mol. % would be calculated as follows: [(5) x (100)] / (1,000 + 1 atmosphere*) (500) / (1,014.7) = 0.49 mol. % *1 atmosphere (sea level) = 14.7 psi

Obligate Anaerobes:

Anaerobic bacteria that cannot grow in the presence of free oxygen or for which oxygen is toxic.

Organic Acids:

Weak acids that are the end product of metabolism by a variety of microorganisms, which are corrosive to carbon steel and other metals. These acids are correctly classified as carboxylic acids (contain a carboxyl groupCOOH) and are also known as short-chain fatty acids.

Oxidation:

Loss of electrons by a constituent of an electrochemical reaction.

Oxygen (O2):

A colorless, odorless gas that, when dissolved in water, can serve as a cathodic reactant promoting corrosion. Although well known for its role in the corrosion of iron and steel when available (i.e., certain external environments), oxygen generally is not a factor in most internal corrosion of natural gas systems because it is not usually present in produced gas and its ingress is minimized.

pH:

The negative logarithm of the hydrogen-ion concentration in a substance. A pH of 7.0 is neutral. A pH lower than 7.0 is acidic while a pH greater than 7.0 is alkaline.

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Glossary for Internal Corrosion

Partial Pressure:

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The pressure, in pounds per square inch atmospheric (psia), of a component gas in a pipeline or vessel. The partial pressure of a gas represents the pressure that a gas would exert on a system if it were the only gas present. The partial pressure of a gas can be computed using the following equation (assuming ideal gas): partial pressure = [fractional mole % x total pressure] where:

fractional mol. % = [(mol. %) / (100)] total pressure (psia) = [pressure (psig) + atmospheric pressure

(psi)] For example, if a gas sample has 0.5 mol. % of CO2 and the pipeline operating pressure was 1,000 psig, the CO2 partial pressure would be calculated as follows: [(0.5) / (100)] (1,000 + 1 atmosphere*) (0.005) (1,014.7) = 5.07 psia *1 atmosphere (sea level) = 14.7 psi Parts Per Million (ppm):

One of the commonly used units for reporting water analysis data. The part per million (ppm) is a measure of proportion by weight, equivalent to a unit weight of dissolved substance per million unit weights of solution. The unit used in water analysis is the milligram (mg), so 1 ppm is equivalent to 1 mg of solute per 1,000 grams of solution.

Pitting:

Corrosion of a metal surface, confined to a point or small area, that takes the form of cavities. The metal undergoing corrosion suffers localized metal loss, rather than over the entire surface. In general, a pit may be described as a cavity or hole where the surface diameter is about the same size or less than its depth.

Pitting Rate:

The rate of penetration calculated using the maximum pit depth measured on a coupon. This penetration is extrapolated over a 1-year period and expressed in mils per year (mpy). The following equation is used to find the pitting rate: mpy = max. pit depth (microns) x 0.03937 (mils/micron) x 365 (days/year) exposure period (days)

Planktonic Bacteria: +

Free-floating or free-swimming bacteria in bulk fluids.

Potassium (K ) Ion:

A monovalent metallic cation that is a common dissolved constituent of most waters and formation brines.

Pressure:

The force exerted or applied over a surface, expressed in pounds per square inch gauge (psig). Pressure affects the rates of most chemical reactions, including corrosion reactions. The primary importance of pressure is its effect on dissolved gases; i.e., more gas goes into solution as the pressure is increased. This may in turn increase the corrosiveness of the solution.

Reduction:

The gain of electrons by a constituent of an electrochemical reaction.

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Scaling Tendency:

Describes a water’s potential for scale formation (see “Stability Index”). The tendency for scaling in a system is influenced by temperature, pressure, concentration of different ions, and amount of dissolved gases. A strongly positive stability index suggests a potential for scaling, whereas a very negative stability index predicts no scale precipitation and that there is a potential for corrosion. Values in between are generally considered inconclusive with regard to scaling or corrosion.

Sessile Bacteria:

Bacteria attached to a surface.

Sodium (Na+) Ion:

A monovalent metallic cation that is a common dissolved constituent of water, brines, and scales. Sodium commonly forms salts with anions such as chloride. The addition of salts to water increases its conductivity and possibly its corrosiveness.

Specific Gravity:

The ratio of the weight of a given volume of a substance at a given temperature (60o F [15.6 o C] is often used) to the weight of a standard substance at the same temperature. Specific gravity of a solution can be used as an indication of the amount of salts dissolved in water. As the specific gravity increases, the density and therefore the amount of dissolved salts - also increases.

Stability Index:

An empirical expression that indicates the scaling and corrosion tendencies of water samples. The stability index provides a somewhat quantitative value for whether calcium carbonate scale will be deposited within a pipeline, as well as potential seriousness of any scaling or corrosion that might occur. In general, more positive numbers indicate a greater likelihood of scale formation and more negative numbers indicate an increased possibility for corrosion. The stability index is accurate when calculated using field measured pH and alkalinity.

Start Weight:

This is the initial weight, in grams (g), of a corrosion coupon before exposing it to pipeline conditions (also known as “Begin Weight”). This value is used with the “End Weight” to determine weight loss (or gain). This weight difference (typically converted to milligrams, mg) is used to calculate the corrosion rate.

Sulfate (SO4=):

A non-metallic, anionic divalent compound that is a common dissolved constituent of most waters. SO4= can combine with calcium or magnesium ions to form insoluble compounds, which may in turn form deposits that may serve as a protective scale. However, if the formations of these deposits are excessive and uncontrolled, their build-up can decrease the diameter of the pipe and create flow problems. Sulfate is also important because it is reduced by sulfate-reducing bacteria (SRB) to sulfide (highly corrosive) and oxygen.

Sulfate Reducing Bacteria (SRB):

A group of anaerobic bacteria that reduce sulfate to sulfide (see “Microbiologically Influenced Corrosion”). Considered by many to be the chief causative agent of MIC.

Sulfur:

An element that has multiple possible forms. The relevant forms that may be present in a natural gas system include H2S, elemental sulfur, dissolved sulfide, and oxyanions of sulfur (e.g., sulfate – SO42-).

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Temperature:

Temperature, in degrees Fahrenheit (o F), or degrees Celsius (o C) is a measure of the heat present in a substance or its environment. Because temperature changes rapidly, it must be measured at the time of sample collection. All chemical reactions are affected by temperature either directly or as a result of its effect on reaction rates, solubility, phase change, etc. Some of these effects are complex; however, in general, an increase in temperature increases the corrosion rate. A rough “rule of thumb” suggests that the reaction rate doubles for every 10o C rise in temperature. To convert degrees Celsius into Fahrenheit, the formula is as follows: o F = [o C x 1.8] + 32

Total Alkalinity:

Alkalinity is a measure of a liquid’s ability to neutralize acids. Total alkalinity is the sum effect of all the major sources of alkalinity, such as carbonate (CO3=), bicarbonate (HCO3-), and hydroxide (OH-) alkalinity. Total alkalinity measurements should be performed in the field immediately following sample collection because the value is pH-dependent and capable of changing over time.

Total Dissolved Solids (TDS):

The sum of all dissolved ions, both cations and anions, measured in the analysis of an aqueous liquid. This value can be used to predict a water’s conductivity and whether a water is composed chiefly of brine or condensed water. This value can also be used as a check to verify the completeness of an analysis with the sum of each of the individual constituents of the sample being approximately equal to the total dissolved solids value. Localized corrosion under or around a deposit or collection of material on a metal surface. The deposit(s) may be due to corrosion product accumulation, precipitation of solids from the water, or microbiological activity. Corrosion that proceeds at about the same rate over a large area of a metal surface.

Under-Deposit Corrosion: Uniform Corrosion: Upset Conditions:

Abnormal operating conditions. With respect to internal corrosion, the concern is when corrosive constituents are temporarily introduced to the gas stream.

Water Dewpoint:

The point at which gas is saturated with water vapor and begins to condense liquid water. The water content in lb/mmscf determines the temperature and pressure at which liquid condenses.

Wet System:

A pipeline transporting gas saturated with water.

Internal Corrosion for Pipelines Course Manual © NACE International, 2003 October 2003

NACE Standard TM0194-2004 Item No. 21224

Standard Test Method Field Monitoring of Bacterial Growth in Oil and Gas Systems This NACE International (NACE) standard represents a consensus of those individual members who have reviewed this document, its scope, and provisions. Its acceptance does not in any respect preclude anyone, whether he has adopted the standard or not, from manufacturing, marketing, purchasing, or using products, processes, or procedures not in conformance with this standard. Nothing contained in this NACE standard is to be construed as granting any right, by implication or otherwise, to manufacture, sell, or use in connection with any method, apparatus, or product covered by Letters Patent, or as indemnifying or protecting anyone against liability for infringement of Letters Patent. This standard represents minimum requirements and should in no way be interpreted as a restriction on the use of better procedures or materials. Neither is this standard intended to apply in all cases relating to the subject. Unpredictable circumstances may negate the usefulness of this standard in specific instances. NACE assumes no responsibility for the interpretation or use of this standard by other parties and accepts responsibility for only those official NACE interpretations issued by NACE in accordance with its governing procedures and policies which preclude the issuance of interpretations by individual volunteers. Users of this NACE standard are responsible for reviewing appropriate health, safety, environmental, and regulatory documents and for determining their applicability in relation to this standard prior to its use. This NACE standard may not necessarily address all potential health and safety problems or environmental hazards associated with the use of materials, equipment, and/or operations detailed or referred to within this standard. Users of this NACE standard are also responsible for establishing appropriate health, safety, and environmental protection practices, in consultation with appropriate regulatory authorities if necessary, to achieve compliance with any existing applicable regulatory requirements prior to the use of this standard. CAUTIONARY NOTICE: NACE standards are subject to periodic review, and may be revised or withdrawn at any time without prior notice. NACE requires that action be taken to reaffirm, revise, or withdraw this standard no later than five years from the date of initial publication. The user is cautioned to obtain the latest edition. Purchasers of NACE standards may receive current information on all standards and other NACE publications by contacting the NACE Membership Services Department, 1440 South Creek Drive, Houston, Texas 77084-4906 (telephone +1 [281] 228-6200).

Revised 2004-11-15 Approved 1994 NACE International 1440 South Creek Dr. Houston, Texas 77084-4906 +1 281/228-6200 ISBN 1-57590-197-7 © 2004, NACE International

TM0194-2004

________________________________________________________________________ Foreword This standard describes field test methods that are useful for estimating bacterial populations, including sessile bacterial populations, commonly found in oilfield systems. The described test methods are those that can be done on site and that require a minimum of laboratory equipment or supplies. The described test methods are not the only methods that can be used, but they are methods that have been proved to be useful in oilfield situations. This standard is intended to be used by technical field and service personnel, including those who do not necessarily have extensive or specific training in microbiology. However, because microbiology is a specialized field, some pertinent and specific technical information and explanation are provided to the user. Finally, the implications of the results obtained by these test methods are beyond the scope of this standard. The interpretation of the results is site- and system-specific and may require more expertise than can be provided by this standard. This standard is loosely based on a document produced by the former Corrosion Engineering Association (CEA). CEA operated in the United Kingdom under the auspices of NACE and the (1) Institute of Corrosion (Icorr). This NACE International standard was originally prepared in 1994 by NACE Task Group T-1C-21 under the direction of Unit Committee T-1C on Corrosion Monitoring in Petroleum Production. It was revised in 2004 by Task Group 214 on Bacterial Growth in Oilfield Systems—Field Monitoring: Review of NACE Standard TM0194, which is administered by Specific Technology Group (STG) 31 on Oil and Gas Production—Corrosion and Scale Inhibition and by STG 60 on Corrosion Mechanisms. It is issued by NACE under the auspices of STG 31. _________________ (1)

Institute of Corrosion (Icorr), P.O. Box 253, Leighton, Buzzard Beds, LU7 7WB, England.

In NACE standards, the terms shall, must, should, and may are used in accordance with the definitions of these terms in the NACE Publications Style Manual, 4th ed., Paragraph 7.4.1.9. Shall and must are used to state mandatory requirements. The term should is used to state something good and is recommended but is not mandatory. The term may is used to state something considered optional.

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TM0194-2004

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Standard Test Method Field Monitoring of Bacterial Growth in Oilfield Systems Contents 1. General.......................................................................................................................... 1 2. Sampling Procedures for Planktonic Bacteria............................................................... 1 3. Culture Techniques ....................................................................................................... 3 4. Evaluation of Chemicals for Control of Planktonic Bacteria.......................................... 7 5. Assessment of Sessile Bacteria.................................................................................... 8 References.......................................................................................................................... 9 Appendix A: Glossary....................................................................................................... 10 Appendix B: Rapid Methods for Assessing Bacterial Populations ................................... 13 Appendix C: Membrane Filtration-Aided Bacterial Analyses ........................................... 14 Appendix D: Bacterial Culturing by Serial Dilution ........................................................... 15 Appendix E: Alternative SRB Growth Medium Formulation............................................. 17 Table 1: Results Interpretation Table................................................................................. 5 Table D1: Single Serial Dilution ....................................................................................... 16 Table D2: Duplicate Serial Dilution .................................................................................. 17 Table D3: Five Replicate Serial Dilution........................................................................... 17 ________________________________________________________________________

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TM0194-2004 ________________________________________________________________________ Section 1: General 1.1 Scope 1.1.1 This standard describes field test methods for estimating bacterial populations commonly found in oil and gas systems. Although these techniques have been successful in the oil field, they are not the only methods that are used. It is not the intent of this standard to exclude additional techniques that can be proved useful. However, caution should be exercised with any technique that is at variance from those outlined here. 1.1.2 A glossary of terms used in this standard is provided is Appendix A. 1.1.3 This standard deals only with bacteria and does not consider other organisms that may be found in oilfield fluids, such as archaebacteria, phytoplankton (algae), protozoa, or fungi. In addition, these methods are not applicable to marine organisms such as zooplankton (copepods). 1.1.4 Because effective sampling is essential to any successful analysis, emphasis is given to sampling methods that are suitable for use in oilfield conditions. 1.1.5 Media formulations for enumerating common oilfield bacteria are given. 1.1.6 This standard describes dose-response (timekill) testing for evaluating biocides used in oilfield applications.

1.1.7 Methods for evaluating surface attached (sessile) bacteria are addressed. The importance of these bacteria in oilfield problems is usually not adequately considered. Attached bacterial populations are often the most important component of a system’s 1 microbial ecology. 1.1.8 Emerging technologies for the rapid determination of bacterial populations and bacterial activity are addressed (See Appendix B). While these technologies are not specifically recommended, it is not the intent of this standard to prevent the use of any technology that can be useful. However, the user must determine the applicability of these new methods to the site/system. Similarly, there are a number of commercially available “test kits” for detecting various types of microorganisms; these are not discussed in this standard. However, the user could use this standard to evaluate the suitability of these test kits for any particular situation. 1.1.9 The simple presence of bacteria in a system does not necessarily indicate that they are causing a problem. In addition, bacterial populations causing problems in one situation, or system, may be harmless in another. Therefore, “action” concentrations for bacterial contamination cannot be given. Rather, bacterial population determinations are one more diagnostic tool useful in assessing oilfield problems. 1.1.10 Further information on the corrosion problems associated with bacterial growth in oilfield systems is 2 given in NACE Publication TPC #3.

________________________________________________________________________ Section 2: Sampling Procedures for Planktonic Bacteria 2.1 Baseline Sampling 2.1.1 Natural bacterial population fluctuation and uneven bacterial distribution within water systems may hamper accurate assessment of bacteria numbers. If baseline studies described here show a large variation in reported bacterial populations, several samples should be taken on each occasion and combined (bulked). However, this procedure may mask fluctuations in population profiles, if determining such profiles is a goal of the work. 2.1.2 Field operators should be solicited for valuable information. These operators can often provide, or obtain, critical past biological monitoring (background) data taken from the system. Communication with operators can also ensure that baseline sampling occurs during normal operations and not during excursions (pigging, shut-ins, biocide treatments, etc.).

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In addition, selection of proper sample sites can best be made in cooperation with operators. 2.1.3 Sampling Frequency 2.1.3.1 Sampling frequency depends on how the field system operates and should encompass the various stages of its operation. 2.1.3.2 Some systems may exhibit large population variations over a short time. To establish the natural variation in bacteria numbers, samples (bulked or otherwise) should normally be taken randomly over several days to establish a baseline. This work should also establish the sample points that are representative of the system. As an example of what sample frequency might be required, twice-daily sampling over three to five days is often used. In other cases, greater

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TM0194-2004 sample frequencies over longer time periods may be required. 2.1.3.3 If the evaluation spans several months, it is important to account for any system variables that are related to seasonal changes. Usually, these variables can only be established with extensive background monitoring. 2.1.3.4 During biocide treatments, additional samples should normally be taken immediately prior to treatment and at random intervals over several days after each treatment. A good procedure would be to match the sampling schedule used with the baseline sampling for the system. 2.1.3.5 To fully understand the ecology of a system, the entire system should be surveyed rather than only areas where elevated bacterial populations are expected or where obvious bacterial problems are occurring. 2.2 Sampling Bottles 2.2.1 It should be assumed that bacterial populations undergo both qualitative and quantitative changes with time while being held in any sample container. Sample containers should be made of sterile glass, polyethylene, or polypropylene. Sterile containers are obviously preferred, but any new containers usually suffice. In the latter case, the samples that were collected in nonsterile containers should be so noted. 2.2.2 To minimize changes, the sample should be analyzed without delay, preferably on site. If a delay of more than one hour is unavoidable, a glass container should be used; however, it should be noted that errors in bacterial population estimates still could result. The time delay occurring between sampling and analysis should be held constant for all testing. For example, if some samples are normally analyzed four hours after collection, all samples should be held for four hours before testing. This practice helps minimize population variability caused by the sample handling procedure. Samples to be held more than four hours should be refrigerated (4°C [40°F]). For handling thermophilic bacteria, special precautions may need to be observed. Samples held for longer than 48 hours, even under refrigeration, are of dubious value. 2.2.3 The sample container should be rinsed with the system water, then completely filled to flush out air, and then closed with a screw cap (preferably with an airtight liner). The cap should only be removed just prior to sampling and replaced immediately afterwards. Touching the internal surfaces of the container neck and cap should be avoided. 2.3 Possible Sampling Problems

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2.3.1 These sampling procedures pertain only to planktonic bacteria. Special procedures are required for sampling sessile bacteria (See Section 5). Relying on only planktonic bacterial testing for problem solving may lead to serious misunderstanding of the extent or nature of bacterial activity in the system. 2.3.2 The available sampling points may not be suitable for identifying a microbiological problem (i.e., at or close to the suspected location of the problem). Prior consultation with operators may identify alternatives to avoid some sampling problems. Ideally, consultation on sample point location should take place during the design and construction phase of the facility. 2.3.3 Samples may be taken from either flowing (e.g., pipeline) or static (e.g., storage tank) systems. Usually, samples should be obtained by cracking a valve and allowing the fluids to flow for several minutes (to thoroughly flush out dead-space fluids) before collecting the sample. In some instances (such as with tank bottoms or when sampling from open waters), a specially designed sampling apparatus, e.g., a sampling bomb, a sample thief, or a pumped line, is required. 2.3.4 During sampling of systems containing both oil and water, phase separation should be permitted to occur before the water is used. Samples with low water cuts (i.e., low percentage of water) or those with tight emulsions may not contain enough water for testing. If an additional sample is necessary to obtain enough water for a particular test, caution should be exercised to prevent contamination during sample bulking. It is usually satisfactory to directly use an emulsion for bacterial isolation. The recorded water cut may be used to estimate the water volume used in the culturing procedure (for those workers who feel more accurate bacterial population estimates will result). 2.3.5 If the detection of very low bacterial populations is required (i.e., less than one viable cell per mL), special means to increase the bacteria numbers must be used. One common method for doing this is the membrane filtration technique. See Appendix C for more detail. Sterile sample containers must be used with the membrane filtration technique. 2.4 The following information should be recorded when taking samples: 2.4.1 Date, time, and location of the sample. 2.4.2 Sample temperature and pH. 2.4.3 Dissolved oxygen and hydrogen sulfide (H2S) content. 2.4.4 Any production concentration noted.

chemicals

present,

with

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TM0194-2004 2.4.5 Observations on color (particularly suspended metallic sulfide or black water), turbidity, odor (particularly H2S), and the presence of slime and deposits.

2.4.6 Other relevant information pertaining to the sample.

________________________________________________________________________ Section 3: Culture Techniques 3.1 General 3.1.1 Bacterial culturing in artificial growth media is accepted as the standard technique for the estimation of bacteria numbers. However, users should be aware of the limitations of the culture technique: 3.1.1.1 Any culture medium grows only those bacteria able to use the nutrients provided.

3.2 Bacteria Testing: Media and Determinations 3.2.1 Heterotrophic Bacteria (Aerobic and Facultative Anaerobic Bacteria) Testing: Several different liquid bacterial culture media are widely used for enumerating heterotrophic bacteria in oilfield waters. Examples are: 3.2.1.1 Phenol Red Dextrose Broth:

3.1.1.2 Culture medium conditions (pH, osmotic balance, redox potential, etc.) prevent the growth of some bacteria and enhance the growth of others. 3.1.1.3 Conditions induced by sampling and culturing procedures, such as exposure to oxygen, may hamper the growth of strict anaerobes.

Beef extract Peptone Phenol Red Dextrose NaCl Distilled water

1.0 g 10.0 g 0.018 g 5.0 g 5.0 g 1,000 mL

The pH should be adjusted to 7.0 with NaOH. 3.1.1.4 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.

The broth should be distributed to tubes or vials and autoclaved for 15 min at 121°C (250°F). 3.2.1.2 Standard Bacteriological Nutrient Broth:

3.1.1.5 Some bacteria cannot be grown on culture media at all. 3.1.2 A test for hydrocarbon-oxidizing organisms should be used in the rare instance when such organisms are important to a particular situation. 3 These test methods are described elsewhere. Otherwise, the methods detailed here are usually sufficient. 3.1.3 Procedures for the detection or enumeration of 4,5 6 sulfur-oxidizing bacteria and iron bacteria are not described here.

Beef extract Peptone Distilled water

3.0 g 5.0 g 1,000 mL

The pH should be adjusted to 7.0 with NaOH. The broth should be distributed to tubes or vials and autoclaved for 15 min at 121°C (250°F). 3.2.2 Anaerobic and Facultative Anaerobic Bacteria Testing: 3.2.2.1 Thioglycolate Broth:

3.1.4 Only liquid culture methods are described herein. Classical methods using agar-solidified media 7 can be found elsewhere. Such methods are impractical for routine field use. In addition, because only population estimates to the nearest order of magnitude are required, duplicate culturing in liquid media provides sufficient accuracy. For those occasions when estimates of greater precision are needed, such as for finished water quality testing, the 7 most probable number (MPN) method can be used. However, the large amount of bench space, glassware, incubator space, and operator time required for this 1 method also makes it impractical for routine field work.

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Yeast extract Casitone Sodium chloride L-cystine Thioglycolic acid Agar Dextrose Distilled water

5.0 g 15.0 g 2.5 g 0.25 g 0.3 mL 0.75 g 5.0 g 1,000 mL

The pH should be adjusted to 7.0 with NaOH.

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TM0194-2004 The medium should be heated to boiling, distributed to tubes or vials, and autoclaved for 15 min at 121°C (250°F). 3.2.3 Salt composition and concentration should be formulated to approximate that of the field water being tested. The salinity should be approximated within 10%. 3.2.4 Fill serum vials, 10-mL nominal capacity, with 9 mL of media. Stopper the vials with butyl or natural latex rubber stoppers. Protect and seal the rubber stopper with a disposable metallic cap. Steam sterilize the filled and sealed vials in accordance with the media formulations in Paragraph 3.2.1. Some workers prefer to bottle and cap these media under reduced-oxygen conditions (See Paragraph 3.3.3). 3.2.4.1 These media can be obtained ready made (to any salinity requirement) from biological supply houses. All media should be marked with the medium preparation date and stored at 4°C (40°F) unless stated otherwise. 3.2.4.2 Arrange media vials into a “dilution series.” The media temperature should approximate the temperature of the sample to avoid “shock” effects on the microbes in the sample. Inoculate the first dilution vial with a sterile disposable syringe containing 1 mL of sample collected as described in Section 2; discard the syringe. Then complete the serial dilution with one of the following procedures. All work must be done in duplicate. NOTE: Disposable 3-mL plastic syringes with 25-mm (1.0-in.) 22-gauge needles are convenient. 3.2.4.2.1 Classical Procedure: Vigorously agitate the inoculated vial and, using another sterile syringe, withdraw 1 mL of the inoculated broth. Inject this 1 mL of inoculated broth into the second dilution vial. Vigorously agitate this vial; then use another sterile syringe to transfer 1 mL to the third dilution vial. Repeat this procedure in the same manner until an appropriate dilution factor is reached. The appropriate dilution factor depends on the expected bacterial population. More detail can be found in Appendix D. NOTE: In cases of severe bacterial contamination, the user may wish to periodically determine the bacterial population by a complete dilution-to-extinction procedure. This may require a 109 dilution factor (or greater). 3.2.4.2.2 Alternative Procedure (widely practiced): Vigorously agitate the initially inoculated vial as before. Using another sterile syringe, withdraw 1 mL from this vial and inject it into the second vial of the dilution series. Keeping that syringe needle in this

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vial, invert the vial, and rinse the syringe thoroughly by drawing up and expelling several milliliters of broth three times. Then withdraw 1 mL of this well-mixed broth and inject it into the third vial of the dilution series. Cleanse the syringe again by rinsing three times (in the inverted third dilution vial) before using it to transfer 1 mL to the next dilution vial. Repeat this procedure for each dilution desired. NOTE: The occasional spurious result is more likely when using this method. However, because of inherent inaccuracies of culturing, an occasional spurious result is usually acceptable. If this is not felt to be the case or spurious results are common, then the previous (i.e., classical) dilution method should be used. As with the classical procedure outlined in Paragraph 3.2.4.2.1, normally a 106 dilution factor is sufficient. Complete dilution-to-extinction determinations are not usually necessary, but may be done in special cases. 3.2.5 Incubation 3.2.5.1 The proper incubation temperature is critical to growing bacteria removed from the field system. Therefore, the incubation temperature must be within ±5°C (±9°F) of the recorded temperature of the water when sampled. This incubation temperature must be recorded. Because oilfield bacteria can grow in produced fluids at temperatures of 80°C (176°F) or higher, special incubation procedures may be required when high-temperature fluids are encountered. 3.2.5.2 Vials that become turbid in between 1 and 14 days shall be scored as positive. With phenol red dextrose media, a color change from red to yellow accompanying the turbidity is a positive for acid-producing bacteria. These vials may be discarded after 14 days’ incubation. 3.2.5.3 Estimate bacteria numbers using Table 1. However, it must be noted that using this table is simplistic. Estimating bacterial populations by the serial dilution method is a subject for statistical analysis. The more replicate samples done, the tighter the statistical distribution, and the more precise the estimate. With the duplicate testing prescribed in this standard, the ranges of bacterial populations shown in Table 1 are actually too narrow. Adding to the confusion is the fact that bacterial media inherently underestimate bacterial populations. However, by convention, the values reported in Table 1 are considered acceptable for oilfield situations. For more details, see Appendix D. The bacterial estimate reported is the one shown in the fourth column. If all the serial dilution vials used are positive, then report the results as

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TM0194-2004 “equal to or greater than” (≥) the highest dilution used in the testing.

TABLE 1 RESULTS INTERPRETATION TABLE Number of Positive Vials 1

Actual Dilution of Sample 1:10

Growth (+) Indicates Bacteria per mL 1 to 9

Reported Bacteria per mL 10

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1:100

10 to 99

100

3

1:1,000

100 to 999

1,000

4

1:10,000

1,000 to 9,999

10,000

5

1:100,000

10,000 to 99,999

100,000

6

1:1,000,000

100,000 to 999,999

1,000,000

3.3 Sulfate-Reducing Bacteria (SRB) Testing: Media and Determination 3.3.1 SRB testing should be conducted in association with other analyses, such as pH, redox potential, oxygen content, total dissolved solids, and whenever possible, sulfide and sulfate content.6 Also, general heterotrophic bacterial population evaluations (Paragraph 3.2) should be conducted simultaneously. Without such information, it may be difficult to estimate the contributions of SRB to the problems found. 3.3.2 Media As with heterotrophic bacterial culturing, serial dilution in a liquid medium should be used to estimate SRB to the nearest order of magnitude. Many different media may be used. Two widely used media formulations for SRB estimation are given below: 3.3.2.1 Sodium Lactate SRB Medium Sodium lactate solution (60 to 70%) Yeast extract Ascorbic acid MgSO4.7H2O K2HPO4 (anhydrous) Fe(SO4)2(NH4)2.6H2O NaCl Distilled water

4.0 mL 1.0 g 0.1 g 0.2 g 0.01 g 0.2 g 10.0 g 1,000 mL

(2),8,9

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3.3.2.2 Postgate Medium B KH2PO4 NH4Cl CaSO4 MgSO4.7H2O Sodium lactate Yeast extract Thioglycolic acid Ascorbic acid FeSO4.7H2O Distilled water

0.5 g 1.0 g 1.0 g 2.0 g 2.8 g 1.0 g 0.1 g 0.1 g 0.5 g 1,000 mL

3.3.2.3 Preparation of SRB Media 3.3.2.3.1 Dissolve the ingredients with gentle heating and adjust the pH to 7.3 ±0.3 with NaOH solution. 3.3.2.3.2 Because of the difficulty in growing some field strains of SRB, one of the following may be added to this medium: (1) 0.05 mL thioglycolic acid for additional redox reduction, (2) an acidetched iron nail to provide adequate iron concentrations, and/or (3) 2.5 g sodium acetate. 3.3.2.3.3 All vials should be marked with the date that the medium was prepared and then examined periodically for deterioration. They should be stored at 4°C (40°F).

___________________________ (2)

Formerly referred to as API(3) RP 388 Medium. The RP 38 standard that previously served as a reference for this medium was not reauthorized for publication by API. Therefore, to avoid referring to a publication that is no longer in print, the medium is referred to in this standard as Sodium Lactate SRB Medium. (3) American Petroleum Institute (API), 1220 L St. NW, Washington, DC 20005.

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TM0194-2004 3.3.2.3.4 Salt composition and concentrations should be formulated to approximate that of the field water being tested. The salinity should be approximated within 10%. 3.3.2.3.5 The medium may be made up in source water, i.e., substituting filtered source water for distilled water in the medium formula. Some source waters may contain sulfide concentrations that make them inappropriate for use in medium preparation (because the medium is black on initial preparation). In such cases, the H2S may be removed by boiling the water prior to medium preparation. Likewise, other source waters may contain high levels of CO2 that may lead to pH instability. Buffering may be needed. 3.3.2.3.6 Adding sulfur-containing compounds other than sulfate (i.e., sulfite, bisulfite, thiosulfate, etc.) should be avoided. These compounds can allow non-SRB to grow in these media and be reported as SRB rather than more appropriately as “sulfide-producing bacteria.” 3.3.2.3.7 Some workers report that the addition of 20 to 30% melted SRB agar to a sample of field water improves SRB recovery from the water. This method should be considered qualitative. The SRB agar is a commercial product similar to the medium described in Paragraph 3.3.2.1 with 15 g/L agar added. 3.3.2.4 There are SRB that use carbon sources other than lactate, specifically acetate, propionate, and butyrate. These nonlactate-utilizing SRB may be present in some oilfield systems and may not grow in media containing only lactate. In these cases, SRB culturing in traditional media can seriously underestimate the total SRB population present. If lactate-based media invariably and unexpectedly yield low SRB populations in situations in which high SRB populations are expected (as indicated by sulfide production, microbiologically influenced corrosion, etc.), other media options should be screened to determine the most appropriate one for a particular system. Appendix E lists an alternative SRB growth medium that has given improved SRB recovery in some situations. In addition, several rapid methods are available (one commercially) for estimating SRB populations (see Appendix B). 3.3.3 Medium Bottling Procedure

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3.3.3.1 To limit oxygen contamination, fill serum vials (nominal 10-mL capacity) with 9 mL of hot bacterial growth medium while maintaining an inert gas atmosphere (e.g., nitrogen or argon). Seal the vials with stoppers made of butyl or natural latex rubber and cap them with disposable metallic covers. After sealing, sterilize the filled vials at 100 kPa (15 psig) steam pressure for 15 minutes. 3.3.3.2 If iron nails are used, they should be added prior to filling and stoppering. The nails should be prepared by degreasing in acetone, soaking in 2 N HCl for 0.5 hours, water rinsing to remove all acid, and then transferring into a container of acetone for storage. Iron wire or reduced iron powder, reagent grade, may be substituted for the iron nail. 3.3.4 Inoculation 3.3.4.1 Collect water samples according to the technique described in Section 2. Make serial dilutions according to Paragraph 3.2.4.2. 3.3.5 Incubation 3.3.5.1 Proper incubation temperature is critical for growing the bacteria present in the field system. Incubation must be within ±5°C (9°F) of the recorded temperature of the water when sampled. The incubation temperature must be recorded. Because oilfield bacteria can grow in produced fluids at temperatures of 80°C (176°F) or higher, special incubation procedures may be required when high-temperature fluids are encountered. 3.3.5.2 Vials that turn black shall be scored as positive. Vials shall not be scored as negative until 28 days. Vials that turn black within two hours are discounted (i.e., not scored) because the blackening is caused by the presence of sulfide in the water sample. If these vials are the only ones blackening after 28 days, subcultures shall be made into fresh medium to serve as a check. (NOTE: It is acceptable to make these subcultures after only 7 days to reduce the turnaround time for obtaining results. However, backup subcultures must be made after 28 days to confirm these results in case they are negative.) The time that it takes each vial to blacken shall be noted because this can be used as an indication of the “strength” (i.e., activity) of the growing culture. 11 Other bacteria (e.g., Shewanella putrefaciens ) can produce sulfide (and cause media blackening) in some cases, especially when sulfur sources other than sulfate are present. 3.3.5.3 Estimate bacteria numbers using Table 1 (also See Paragraph 3.2.5.3).

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TM0194-2004 ________________________________________________________________________ Section 4: Evaluation of Chemicals for Control of Planktonic Bacteria 4.1 When a chemical inhibitor (biocide) is desired to control microbial activity in a system, it is necessary to select an effective chemical agent that is compatible with the fluids and components in the system. On-site doseresponse (time-kill) testing is often used as a guide for selecting biocides. 4.2 Biocide Time-Kill Testing for Planktonic Bacteria 4.2.1 To assess a potential biocide application, adapt the following basic test procedure. A goal is to match test conditions to those prevailing in the system under scrutiny. It is unrealistic to describe a single, standard procedure for biocide testing; therefore only the basic test design is outlined. These biocide tests must be done in duplicate, as a minimum. 4.2.2 Basic Test Procedure

application) to make this determination. Septum seals should be used to limit oxygen ingress into the test systems. 4.2.2.5 Choose biocide exposure times (test system holding times) to match the likely contact times for the biocide within the field system. At the end of these times, withdraw 1-mL samples from each dilution of each biocide being tested (and the controls) and determine viable bacterial populations, as described in Paragraph 4.2.2.4. 4.2.2.6 Following growth medium incubation, tabulate the surviving bacterial populations for each biocide dose rate and each exposure time. Use this tabulation to determine the minimum effective biocide dose rate. Use this dose rate and the biocide unit cost to calculate the most costeffective biocide.

4.2.2.1 Obtain field water samples as previously described (See Section 2). Begin testing immediately after sample collection. Make testing conditions as similar as possible to those prevailing in the system. For example, for anaerobic systems (typical), the tests should be performed in nitrogen- or argon-purged bottles.

4.2.2.7 Examine the test systems for evidence of biocide/water incompatibilities. However, the lack of apparent incompatibilities in these systems does not preclude compatibility problems in the field system.

4.2.2.2 The organisms used to challenge the test biocides should be the population normally found in the test fluid. Alternatively, up to a 1% inoculum of a fully grown culture originating from the field system may be used. Use no more than 1% inoculum to prevent the undue addition of organic material to the test systems.

4.2.2.8 Field experience shows that time-kill testing can only serve as a guide for the field application of the biocide. Therefore, biocide effectiveness must be confirmed once the chemical is added to the actual field system. Some fine adjustment of biocide dose rates is almost always required. In addition, biocide/system compatibility problems may not become apparent until field trials are performed.

4.2.2.3 Add distilled water-based biocide stock solutions (10,000 mg/L recommended) to small sterile bottles (30 to 200 mL). The stock solution volume added to each bottle (test system) should be the amount calculated to provide one of the dose rates expected to be useful in the system (once the bottle is filled with field water). The total biocide stock solution added should not exceed 1% of the final volume. Add distilled water instead of biocide stock solution to several bottles to serve as controls for the field water. 4.2.2.4 Fill the above test bottles, both those containing the biocide dilutions and the control bottles, with the test fluid (containing bacteria). Mix thoroughly and immediately withdraw 1-mL samples from the control bottles to determine the number of viable bacteria initially present in the test bottles. Use the methods described previously for general heterotrophic bacteria (see Paragraph 3.2), for SRB (see Paragraph 3.3), or both (depending on the objectives of the biocide

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4.2.2.9 Notes 4.2.2.9.1 This testing is most reliable when the test procedure most closely matches the normal operating condition of the field system, including the presence of normal amounts of production chemicals. Therefore, the user must modify the procedure to suit a particular system. 4.2.2.9.2 False results may be encountered in the first or second serial dilutions with the higher biocide concentrations used because of the transfer of significant biocide concentrations from the test fluid to the growth medium. 4.2.2.9.3 The tests described here are only for planktonic organisms. The ability of biocides to control sessile bacteria in the system cannot be determined by this

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TM0194-2004 technique. See Section 5 for more detail. In general, biocides are much less effective

against sessile bacteria planktonic bacteria.

than

against

________________________________________________________________________ Section 5: Assessment of Sessile Bacteria 5.1 Attached microbes (sessile bacteria) are normally the most important biological component of the bacterial ecology of an oilfield system. The previously discussed planktonic techniques are of limited value for assaying these bacteria. Techniques for sessile bacterial study produce variable results. Consequently, few routine procedures can be described. However, the following guidelines should provide a basis for analytical work that yields valuable information about sessile bacteria within an oilfield system. 5.2 Sampling Biofilms 5.2.1 Any removable field system component can potentially be used to sample for sessile bacteria. These removable components are referred to as “coupons” in this standard. Standard corrosion coupons are a good example. Another alternative is 12 the use of removed pipe sections (spools). Alternatively, coupons specially designed for microbiological use are available from suppliers of corrosion-monitoring systems, as well as service companies. 5.2.2 The coupons may be located in suitably designed side streams or they may be placed within actual system flow paths by employing properly designed coupons and access fittings. The coupons must be located such that they are representative of sessile bacterial growth. For example, coupons are often located at the “6 o’clock” position in oil and gas piping. 5.2.3 When metal coupons are used, they must be similar in composition to the pipework of the system and electrically isolated to prevent galvanic effects. 5.2.4 During any baseline or investigation survey, sessile samples should always be collected. Good sources are filter backwashes, pig runs, pipe walls at unions, etc. Corrosion failures should always be tested for sessile bacterial populations. 5.2.5 While clean coupons inserted in the system may be rapidly colonized by bacteria, the time taken for the development of a dense biofilm is variable and depends on the system. A major obstacle in working with sessile bacteria samples is the uneven nature of sessile growth within the system (patchiness). For this reason, multiple sessile samples (or large surface areas) should be removed during each sampling episode. 5.3 Monitoring of Sessile Bacteria

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5.3.1 The above sampling devices can be used to monitor biofilm development by periodically removing them and then applying the techniques described earlier to count the bacteria (Section 3). However, with sessile bacteria, the bacteria shall be removed from the coupon by scraping with a sterile scalpel, swabbing, shaking with glass beads, or using ultrasonic devices. If scalpels or swabs are used, the biofilm and associated products must be completely dispersed using a vortex mixer with glass beads or by a sonic bath. In each case, sterile phosphate-buffered saline (or ultra-filtered field water) shall be used to collect the removed bacteria. It is necessary to establish that the collecting method used is effective and that the assay methods allow efficient recovery of the bacteria being analyzed. 5.3.1.1 Phosphate-buffered saline (PBS) solution is commonly used to process sessile samples. This solution can also be used to suspend deposits from corrosion failures, coupons, pig run specimens, or biofilm probes. The PBS solution provides an environment for maintaining viable bacteria without providing nutrients for growth. Furthermore, some investigators have reported benefits from using anaerobic PBS solutions in processing sessile specimens from gas or oil pipelines. 5.3.1.1.1 PBS Solution NaCl KH2PO4 K2HPO4 Distilled water

8.7 g 0.4 g 1.23 g 1,000 mL

Bottle and autoclave (100 kPa [15 psig]/20 minutes) (for brines, greater amounts of NaCl should be added to avoid osmotic shock effects). 5.3.1.1.2 Anaerobic PBS Solution Prepare as above and add: 20 mL of 2.5% cysteine-HCl and/or 20 mL of 5% ascorbic acid 1 mL of 0.1% Resazurin indicator (optional) 5.4 Assessment of Biocide Efficiency 5.4.1 Coupons bearing biofilms can be used to assess the efficiency of biocide treatments against sessile

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TM0194-2004 bacteria. Coupon-based biofilm samples should be removed before, during, and after biocide treatment. Surviving bacteria should be assayed as above. For time-kill testing, sessile bacteria on coupons should be exposed to biocides either under static conditions or by 13,14 being placed in dynamic flow loops.

5.4.2 In recognition of the importance of biofilm growth, many different test methods to evaluate biocide effectiveness are under development. Such tests will undoubtedly become more widely used in the future, but no single recommended procedure can be given at this time.

________________________________________________________________________ References 1. B. Little, P. Wagener, F. Mansfeld, “Microbiologically Influenced Corrosion of Metals and Alloys,” International Materials Reviews 36, 6 (1991): pp. 253-272.

“Mitigation Strategies for Microbiologically Influenced Corrosion in Gas Industrial Facilities,” CORROSION/89, paper no. 192 (Houston, TX: NACE, 1989).

2. NACE Publication TPC #3, “Microbiologically Influenced Corrosion and Biofouling in Oilfield Equipment” (Houston, TX: NACE, 1990).

13. I. Ruseska, J.W. Costerton, E.S. Lashen, “Biocide Testing Against Corrosion Causing Bacteria Helps Control Plugging,” Oil and Gas Journal 4 (1982): pp. 253-264.

3. L.D. Bushnell, H.F. Haas, “Utilization of Certain Hydrocarbons by Microorganisms,” Journal of Bacteriology 41 (1941): pp. 653-673.

14. D.H. Pope, T.P. Zintel, H. Aldrich, D. Duquette, “Laboratory and Field Tests of Efficiency to Biocides at Corrosion Inhibiting in the Control of Microbiologically Influenced Corrosion,” CORROSION/90, paper no. 34 (Houston, TX: NACE, 1990).

4. R.L. Starkey, “Isolation of Some Bacteria Which Oxidize Thiosulphate,” Soil Science 39 (1935): pp. 197-219. 5. J.G. Kuenen, O.H. Tuovinen, The Procaryotes, eds. M.P. Starr, H. Stolp, H.G. Truper, A. Balos, H.G. Schlegel (Berlin: Springer Verlag, 1981): pp. 1023-1036. 6. E.G. Mulder, “Iron Bacteria, Particularly Those of the Sphaerotilus-Leptothrix Group, and Industrial Problems,” Journal of Applied Bacteriology 27, 1 (1964): pp. 151-173. 7. W.F. Harrigan, M.E. McCance, Laboratory Methods in Food and Dairy Microbiology (New York: Academic Press, 1976). 8. API RP 38, “Recommended Practice for Biological Analysis of Waterflood Injection Waters,” 3rd ed. (Washington, DC: API, 1975) (out of print). 9. NACE Publication TPC #17, “Corrosion Failures in Boilers” (Houston, TX: NACE, 1996). 10. J.R. Postgate, The Sulphate-Reducing Bacteria, 2nd ed. (Cambridge, England: Cambridge University Press, 1984). 11. K.A. Perry, J.E. Kostka, G.W. Luther III, K.H. Nealson, “Mediation of Sulfur Speciation by a Black Sea Facultative Anaerobe,” Science 259 (1993): pp. 801-803.

15. R. Prasad, “Pros and Cons of ATP Measurement in Oil Field Waters,” CORROSION/88, paper no. 87 (Houston, TX: NACE, 1988). 16. E.S. Littmann, “Oilfield Bactericide Parameters As Measured by ATP Analysis,” International Symposium of (4) Oilfield Chemistry, paper no. 5312 (Richardson, TX: SPE, 1975). 17. J.G. Jones, B.M. Simon, “An Investigation of Errors in Direct Counts of Aquatic Bacteria by Epifluorescence Microscopy, with Reference to a New Method for Dyeing Membrane Filters,” Journal of Applied Bacteriology 39, 1 (1975): pp. 317-329. 18. J. Boivin, “The Influence of Enzyme Systems on MIC,” CORROSION/90, paper no. 128 (Houston, TX: NACE, 1990). 19. H.R. Rosser, W.A. Hamilton, “Simple Assay for Accurate Determination of (35S)Sulfate Reduction Activity,” Applied and Environmental Microbiology 6, 45 (1983): pp. 1956-1959. 20. J.A. Hardy, K.R. Syrett, “A Radiorespirometric Method for Evaluating Inhibitors of Sulfate-Reducing Bacteria,” European Journal of Applied Microbiology and Biotechnology 17 (1983): pp. 49-51.

12. D.H. Pope, T.P. Zintel, B.A. Cookingham, R.G. Morris, D. Howard, R.A. Day, J.R. Frank, G.E. Pogemiller,

___________________________ (4)

Society of Petroleum Engineers (SPE), P.O. Box 833836, Richardson, TX 75083-3836.

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TM0194-2004 21. D.H. Pope, T.P. Zintel, “Methods for the Investigation of Under-Deposit Microbiologically Influenced Corrosion,” CORROSION/88, paper no. 249 (Houston, TX: NACE, 1988). 22. G.L. Horacek, L.J. Gawel, “New Test Kit for Rapid Detection of SRB in the Oil Field,” paper no. SPE 18199, 63rd Annual Technical Conference of the Society of Petroleum Engineers (Richardson, TX: SPE, 1988).

23. “Standard Methods for the Examination of Water and Wastewater,” 17th ed. (Washington, DC: American Public Health Association, 1989). 24. NACE Standard TM0173 (latest revision), “Methods for Determining Quality of Subsurface Injection Water Using Membrane Filters” (Houston, TX: NACE).

________________________________________________________________________ Appendix A GLOSSARY 4-6-diamidino-pheynylindole hydrochloride (DAPI): A DNA-binding molecule that will fluoresce when illuminated with appropriate excitation wavelength of light, allowing visualization and enumeration of bacterial cells in a sample. Compare acridine orange.

Autoclave: A chamber that utilizes pressure and heat to sterilize solutions, media, instruments, and glassware by killing all microorganisms present. See sterilize. Bacteria: Prokaryotic microorganisms enclosed by a cell membrane without a fully differentiated nucleus.

Acridine orange: A fluorochome that binds to DNA and RNA and fluoresces when excited with UV light. This reagent can be used to stain bacterial cells for enumeration by fluorescence microscopy.

Bacterial culturing: Techniques used to grow bacteria present in a sample inoculum in select growth media in the laboratory. See culture medium.

Adenosine triphosphate (ATP): A molecule that provides energy to living cells via hydrolysis of the high energy bond to the terminal phosphate.

Biocide: A chemical product that is intended to kill or render harmless biological organisms. Also termed antimicrobial pesticide.

Aerobic bacteria: Bacteria that grow and reproduce in the presence of oxygen.

Biocide efficacy: The degree of performance a biocide exhibits in killing bacteria. This is usually based on concentration and contact time relative to other biocides being screened.

Agar: A dried polysaccharide extract of red algae used as a solidifying agent in microbiological media. Algae: Unicellular to multi-cellular plants that occur in fresh water, marine water, and damp terrestrial environments. All algae possess chlorophyll for photosynthesis.

Biofilm: A matrix of bacteria, exopolymer, debris, and particulate matter that adheres to a surface.

Anaerobic bacteria: Bacteria that grow and reproduce in the absence of oxygen.

Biomass: The mass per sample volume of microorganisms present. When referring to sessile biofilms, this term may also include the solids formed by bacterial growth such as exopolymer.

APS-reductase: An enzyme specific to sulfate-reducing bacteria that is involved in the reduction of sulfate to sulfide.

Broth: An alternative term for liquid medium used to culture bacteria in the laboratory. See culture medium.

Archaebacteria: The kingdom of monerans that consists of methanogenic bacteria, halophilic bacteria, and thermoacidophilic bacteria. These bacteria evolved over 3.5 billion years ago and exist in extreme environments, are anaerobic, and derive energy from inorganic molecules or light. Compare Eubacteria.

Copepods: Aquatic crustaceans comprising the most numerous group of metazoans in the water community. Adults average 1 to 2 mm in size. They represent an important link between phytoplankton and fish in the food chain.

ATP photometry: A method of bacterial enumeration that quantifies the amount of ATP present in a sample and thereby provides an estimate of bacteria present based on the assumption that the concentration of ATP is proportional to number of bacterial cells.

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Cost-effective biocide: A biocide that provides superior kill of microorganisms based on cost per gallon or pound. Coupon: A removable system component used to sample sessile bacteria growth. Standard corrosion coupons are an example.

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TM0194-2004 Culture medium: Formulated solution of organic and inorganic nutrients that facilitate bacterial growth in the laboratory.

Heterotrophic bacteria: Bacteria that are unable to use carbon dioxide as their sole source of carbon and require one or more organic compounds.

Dilution-to-extinction method: During microbial enumeration using the serial dilution method, dilution-toextinction refers to continuing the serial dilutions to a point at which no growth will be encountered, i.e., to a point at which no microorganisms are transferred in the final dilution. This ensures that a full estimate of the original population in the sample can be determined. See serial dilution method.

Hydrocarbon oxidizing organisms: Heterotrophic microorganisms capable of using hydrocarbons as their energy source as well as a carbon source for growth. This metabolic process is generally aerobic, requiring the presence of oxygen.

Dose-response test: Biocide screening test to establish concentration and contact time for effective bacterial kill. See time-kill test. Duplicate culturing: Performing replicate cultures, for instance with the serial dilution method, in order to obtain more reliable interpretation of the results. Emulsion: A mixture in which one liquid, termed the dispersed phase, is uniformly distributed (usually as minute globules) in another liquid, called the continuous phase or dispersion medium. In the oil field, typically water is dispersed as droplets in oil (water-in-oil emulsion). A reverse emulsion refers to oil dispersed in water (oil-inwater emulsion). Facultative anaerobic bacteria: Bacteria that are able to carry out both aerobic and anaerobic metabolism and therefore are able to grow and reproduce in both the presence and absence of oxygen. Filter backwash: A process of forcing a water stream back through a filter in order to dislodge particles from the filter media. Oftentimes biocide may be introduced during this cycle to treat sessile bacteria buildup on the filter media. Fluorescence microscopy: A microscopic method that utilizes a specific illuminating wavelength of light to excite a fluorescent stain or probe added to a sample for specific detection of cells, structures, or molecules present in the sample. Specific filters are used to select for proper emission spectra of the illuminated probe. Fluorescent antibody: An antibody or immunoglobulin that has been raised against a specific antigen being investigated, such as a protein or cell component, and is coupled to a fluorescein molecule to allow its detection. Fluorescein isothiocyanate: A very common fluorochome that is excited at 420 to 480 nm and fluorescesces at 530 to 540 nm. This protein dye is often used in fluorescence microscopy and can be conjugated with an antibody for use in immunofluorescence methods. Fungi: A group of plants that lacks chlorophyll and includes molds, rusts, mildews, smuts, and mushrooms.

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Hydrogenase: An enzyme that catalyzes the oxidation of hydrogen and is possibly involved in cathodic depolarization by sulfate-reducing bacteria. Immunoassay: A detection method that takes advantage of antibody specificity to a protein or cell component being analyzed. The antibody is usually conjugated to a fluorescein dye or chomogenic substrate, which allows quantification of the molecule being investigated. Inoculum: A medium or sample containing microorganisms that is introduced into a culture. Iron bacteria: The so-called iron-oxidizing bacteria. These 2+ 3+ bacteria oxidize ferrous iron (Fe ) to ferric iron (Fe ), which generally precipitates as iron hydroxide. Membrane filter technique: An enumeration technique for waters with low bacterial concentrations in which a volume of sample is passed through a 0.45-µm filter using a filter funnel and vacuum system. Any organisms in the sample are concentrated on the surface of the membrane. The filter is then placed in nutrient medium. The passage of nutrients through the filter facilitates the growth of organisms on the upper surface of the membrane. The discrete colonies that form on the surface of the membrane can be easily transferred to confirmation media. Microbial ecology: Encompasses a wide range of disciplines and focuses on the interactions of microorganisms with one another and with their environment. Microorganisms: Common term used for unicellular organisms of the plant or animal kingdoms that are structurally related. These cannot be seen without magnification and generally range from 0.2 to 200 µm in size. Most probable number (MPN) method: The essence of this method is the dilution of a sample to such a degree that inocula will sometimes but not always contain viable organisms. The "outcome," i.e., the numbers of inocula producing growth at each dilution, will imply an estimate of the original, undiluted concentration of bacteria in the sample. In order to obtain estimates over a broad range of possible concentrations, microbiologists use serial dilutions, incubating several tubes or plates (replicates) at each dilution.

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TM0194-2004 Osmotic balance: In the context used here, the proper salt concentration of a medium required for the bacteria being cultured to be able to maintain proper osmoregulation. pH: The negative logarithm of the hydrogen ion activitiy written as: + pH = -log10 (aH ) +

Where aH = hydrogen ion activity = the molar concentration of hydrogen ions multiplied by the mean ion-activity coefficient. Phase separation: Specifically used here to refer to the macroscopic separation of oil and water in a sample into the two respective fluids by a allowing time for the fluids to “settle.” Phenol red dextrose broth: Culture medium used to grow heterotrophic bacteria. Phytoplankton: A collective term for free-floating aquatic plants and plant-like organisms. Compare zooplankton. Pig run: The process of launching a pig device in a pipeline segment for the purpose of cleaning or to monitor pipeline integrity. Pigging: A procedure used for cleaning pipeline scale, deposits, and solids or to monitor pipeline integrity. The pig consists of a cylindrical device that forms a seal with the inner pipe surface and is launched through a segment of the pipeline using differential pressure. Pigs can be equipped with brushes or various adaptations to facilitate cleaning or permit inspection of the pipe wall. Planktonic bacteria: Bacteria that are freely floating in brine. Planktonic bacteria can become sessile bacteria by adhering to a surface. Postgate medium B: Specific medium designed for culturing sulfate-reducing bacteria characterized by lactate that is used as a carbon source and sulfate to provide the terminal electron acceptor required for SRB metabolism. Protozoa: Single-celled eukaryotic microorganisms that feed heterotrophically and exhibit diverse forms of motility. Radiorespirometry: Sensitive method for bacterial enumeration whereby radioactive nutrients are metabolized by bacteria in a sample and the amount of radiolabeled gases that are generated are measured to give an estimate of the number of viable bacteria in the sample. Redox potential: A measure of the relative oxidationreduction potential of an environment. Aerobic bacteria grow best in systems with highly positive redox potentials (oxidizing environments) while anaerobic bacteria, including SRB, will grow much better in reducing environments where the redox potential is less than -100 mV.

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Salinity: The measure of dissolved salts in the system water, usually reported as total dissolved salts (TDS) or chlorides. The salinity should be approximated when media for culturing microorganisms from the system water are prepared. Sampling bomb: A sample device that can be used to take liquid samples at discrete depths in drums, tanks, and surface water bodies. Sampling thief: Another term used for a liquid sampling device used to take samples at discrete depths. See sampling bomb. Serial dilution method: Method of enumerating bacteria in a sample via transfer to a series of growth media vials using successive 1:10 dilutions in each successive vial. Following an incubation period, the number of positive cultures provides an estimate of the number of bacteria in the original sample. For statistical validity this test is done with replicates and the population estimate is derived from a statistical table. See Most Probable Number method. Serum vial: A glass vial used for culturing bacteria. It contains a septum that can be sealed with a metal ring. The septum can be accessed with a syringe needle for inoculating bacteria. The vial assembly can be filled with culture media and autoclaved for sterilization. Sessile bacteria: Bacteria that are attached to surfaces. Bacteria that live in biofilms are sessile bacteria. Shewanella putrefaciens: Although not true SRB, these sulfidogenic bacteria exist in biofilms and can act synergistically with SRB to facilitate MIC and hydrogen sulfide formation. Shut-in: In general, refers to closing the valves to a well to shut off production. The term also refers to closing down a segment of a system, vessels, piping, or injection wells. During the shut-in period, the fluids in that part of the system are stagnant and amenable to increased bacterial growth. Sodium lactate SRB medium: Medium for culturing SRB. It is derived from the original Postgate B medium and provides similar nutrients and salts but in a slightly different formulation. See Postgate B medium. Spool: A monitoring device for obtaining sessile bacterial samples that often consists of a removable pipe section inserted in a side-stream flow loop, whereby a representative sample of sessile biofilm growth can be acquired. Standard bacteriological nutrient broth: Basic culture medium for heterotrophic bacteria containing beef extract and peptone.

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TM0194-2004 Sterile: Free of living organisms. To sterilize a medium or material is to kill all microorganisms that are present. See autoclave.

Sulfate-reducing bacteria: A diverse variety heterotrophic microorganisms characterized by metabolism of sulfate to sulfide.

Strict anaerobe: A microorganism that grows only in the absence of oxygen.

Thermophilic bacteria: Bacteria that grow and reproduce in high temperature environments, above 113°F (45°C).

Subculture: For the purposes of this standard, used to evaluate false positives for the presence of SRB in the first two vials of a dilution series that have turned black within two hours due to the presence of hydrogen sulfide. After the 28-day incubation period, a 1-mL aliquot can be taken from these vials and re-tested by serial dilution into SRB media (subculturing) to determine whether SRB are present.

Thioglycolate broth: A culture medium used to grow anaerobic bacteria in the laboratory.

Sulfur oxidizing organisms: A broad group of aerobic bacteria that derives energy from the oxidation of sulfide or elemental sulfur to sulfate.

of its

Time-kill test: A biocide screening test that determines the efficacy of a biocide against microorganisms cultured from the system and identifies optimum contact times and concentrations for effective bacterial kill. Zooplankton: Collective term organisms present in plankton.

for

nonphotosynthetic

________________________________________________________________________ APPENDIX B RAPID METHODS FOR ASSESSING BACTERIAL POPULATIONS The procedures for bacterial analysis outlined in the main body of this standard rely on growth of bacteria in nutrient media. Such techniques generally do not allow rapid evaluation of bacterial contamination. Many techniques have been used to obtain rapid information about microbial populations in oilfield systems. These include measurement of adenosine triphosphate (ATP), general fluorescent microscopy, and measurement of hydrogenase. Methods specific for SRB are as follows: radiorespirometry, fluorescent antibody microscopy, and measurement of APS-reductase. These techniques are outlined below, together with literature references to specific applications. Users are responsible for determining the appropriateness of any of these methods for their needs. GENERAL BACTERIA ATP Photometry. ATP is present in all living cells and is involved in energy metabolism. Because it rapidly disappears on cell death, ATP can give an indication of the viable biomass present in a sample. ATP can be measured using an enzymatic reaction that generates flashes of light when ATP is present. These flashes are detected in a photomultiplier, the output being proportional to the amount of ATP. Many analytical kits are currently available. Disadvantages of ATP photometry include the following: (1) sulfide, chloride, and chemical additives interfere with the reaction; (2) the results exhibit unacceptable scatter with low bacteria numbers; (3) the method does not differentiate between the various types of organisms; and (4) the 15 method requires a sensitive instrument. In view of these disadvantages, ATP photometry is not used for routine monitoring. It has been used successfully, however, to 16 monitor trends, particularly following biocide treatments.

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Fluorescence Microscopy. The total number of bacteria in the sample can be determined, and live and dead cells can be distinguished, by fluorescence microscopy. Specific stains that fluoresce when irradiated with ultraviolet light are used. Stains such as acridine orange, fluorescein isothiocyanate (FITC), and 4, 6- diamidino-2-phenylindole hydrochloride (DAPI) are used for total bacteria counts because they stain both the live and the dead cells. Recent developments in fluorescence stain technology have resulted in methods using a combination of dual fluorescent dyes, with different emission spectra, that can distinguish between live and dead bacteria. A fluorescence 17 microscope is used to allow cells to be counted. As with ATP photometry, this method requires a delicate instrument and is best suited for the laboratory. Only total bacteria counts can be determined. Some interferences can result from organic and inorganic material suspended in the sample. Hydrogenase Measurement. The hydrogenase test analyzes for the hydrogenase enzyme that is produced by bacteria able to use hydrogen as an energy source. Because it is believed that the use of cathodic hydrogen is an important factor in microbiologically influenced corrosion, the presence of hydrogenase may indicate a potential for this corrosion. A strong hydrogenase activity can also 18 indicate the presence of a microbial biofilm community. Hydrogenase testing is best performed on sessile samples. Hydrogenase should be measured by first collecting the bacteria in a sample (e.g., by filtration), exposing to an enzyme-extracting solution, then noting the degree of hydrogen oxidation in an oxygen-free atmosphere (as evidenced by a color reaction with a dye). A response can be expected in 0.5 to 4 hours; a 12-hour exposure is

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TM0194-2004 generally used to allow the system to equilibrate for comparison purposes. SRB TESTS 19

Radiorespirometry. This method, as currently proposed, is specific to SRB. Like the culture methods described elsewhere in this standard, it requires bacterial growth for detection. Unlike other culture methods for SRB, however, it produces results in one to two days of total testing time. The sample should first be incubated with a known trace amount of 35S-labeled sulfate. After incubation, the reaction should be terminated with acid to kill the cells and to release any 35S-sulfide produced by SRB. Such sulfides should be fixed in zinc acetate prior to quantification, using a liquid scintillation counter. Once the 35S-sulfides are fixed, they can be quantified in laboratories away from the site. When the natural concentration of sulfate is known, the overall activity of the SRB population can be calculated. Radiorespirometry has been applied to quantify SRB in the 20 field and for testing biocide efficiency in the laboratory. However, it is a highly specialized technique involving expensive laboratory equipment. Also, the handling of radioactive substances is strictly regulated. Fluorescent Antibody Microscopy. This method is similar to the general fluorescent microscopy described above, except that FITC (the fluorescent dye used) is bound to antibodies specific to SRB cells; consequently, only those bacteria recognized by the antibodies fluoresce under the 21 microscope. The major advantage is speed, because

results are obtained within two hours. The major limitation of this method is that, because the antibodies are developed against whole SRB cells, they are specific only to the type of SRB used in their manufacture. While a large number of SRB antibodies can be combined to make the test fairly general, there is always the possibility that new strains that are not detected will be encountered. Other than that, the disadvantages are similar to those for other microscope techniques: a high degree of training required, difficulty in dealing with samples containing a lot of debris, the need for a laboratory facility, and the detection of nonviable as well as viable SRB. NOTE: While this method, as cited, is used to detect SRB, it can be used for other microbes as well. However, separate antibody “pools” must be developed for each microbe to be tested. APS-Reductase Measurement. This immunoassay takes advantage of the functional definition of SRB, which is “any bacteria capable of anaerobically reducing sulfate to sulfide.” A unique requirement for this process is the presence of an enzyme, APS-reductase. Measurement of the amount of APS-reductase in a sample, therefore, gives an estimation of the total number of SRB present. The test does not require bacterial growth to occur (no medium is used) and is independent of sample temperature, salinity, and redox condition. The test should be carried out using disposable “kits” that are fully contained and usable either in the field or the laboratory. The entire test takes 15 to 20 22 minutes.

________________________________________________________________________ APPENDIX C MEMBRANE FILTRATION-AIDED BACTERIAL ANALYSES Occasionally, it is desirable to test for microbial contamination in waters that contain very low bacterial populations (N)

10 (6.2)

15 (9.3) Distance, km (mi)

Critical Angle (S->N) degrees

20 (12)

Critical Angle (N->S) degrees

E le v a tio n , m (ft)

I n c l in a t io n , d e g r e e s

60.0

25 (16)

-100 (-328)

Elevation

OVERVIEW - Elevation and Inclination vs. Stationing

Figure A1: Example inclination and elevation profiles, with critical inclination angles. Screen capture of spreadsheet. (1 ft = 0.3048 m, 1 mile = 1.609 km) 18 NACE International

SP0206-2006

Table A2: Example—Inspection Results Inspection Region Subregion Stationing, Number km (mi) 1 I 0.08 (0.05) 2 I 0.88 (0.547) 3 I 1.03 (0.640) 4 I 1.22 (0.758) 5 I 2.89 (1.80) 6 I 1 0.84 (0.52) 7 I 1 0.66 (0.41) 8 I 1 0.27 (0.17) II II II II II

28.839 (17.92) 28.035 (17.42) 26.63 (16.55) 25.798 (16.03) 24.72 (15.36)

In c lin a tio n , d e g r e e s

For Region 1, the uphill inclination data are shown in Figure A2, with the critical inclination angle for south to north represented by the dashed line at 6 degrees. In this example, corrosion was found at the first two inclines examined (Digs #1 and #2); therefore, the search for corrosion continued downstream. No additional corrosion was found downstream (Digs #3, #4, and #5). As a result, two subregions were defined: Subregion 0 from 0 km to 0.08 km (0 to 0.05 mile) (i.e., from 0 km to Dig #1), and Subregion 1 from 0.08 km to 0.88 km (0.05 to 0.55 mile) (i.e., from Dig #1 to Dig #2). There were no additional

Internal Corrosion Present? Yes Yes No No No Yes No No

7 14 4 6 18

Yes Yes No No No

upstream sites in Subregion 0; however, there were additional potential liquid holdup locations in Subregion 1. The next highest inclination in Subregion 1 was 5 degrees, at 0.84 km (0.52 mile) (i.e., Dig #6). Corrosion was found at this location. The search for internal corrosion continued upstream in the subregion. The next highest inclination upstream was 3 degrees, at 0.66 km (0.41 mile) (i.e., Dig #7); no corrosion was found. No corrosion was found at the last site upstream in the subregion, 2 degrees at 0.274 km (0.17 mile) (i.e., Dig #8). The detailed examination process was complete for Region 1.

100.0

200 (660)

80.0

150 (490)

60.0

100 (330)

40.0

50 (160)

Moving North

2 20.0

1

8

6

3

7

0 (0)

5

4

0.0

-50 (-160)

-20.0 0.0 (0)

E l e v a ti o n , m ( ft)

9 10 11 12 13

Inclination Angle, degrees 9 16 9 8 7 5 3 2

1.0 (0.6)

2.0 (1.2)

3.0 (1.9)

4.0 (2.5)

5.0 (3.1)

6.0 (3.7)

-100 (-330)

Distance, km (mi)

Inclination (S->N)

Critical Angle (S->N) degrees

Critical Angle (N->S) degrees

Elevation

Figure A2: Example inclination profile, gas flowing south to north (first 6.4 km [4 miles]). Elevation is shown for reference. Screen capture of spreadsheet. (1 ft = 0.3048 m, 1 mile = 1.609 km) The numbers on Figure A2 indicate the order of excavation. NACE International

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SP0206-2006 The uphill inclination data for Region 2 are shown in Figure A3, with the critical inclination angle for north to south represented by the solid line at -4 degrees. Internal corrosion was found at both of the first sites inspected, 28.839 km (17.92 miles) and 28.035 km (17.42 miles) (i.e., Digs #9 and #10). Therefore, the search for internal corrosion continued downstream. No corrosion was found at the next two sites examined (Digs #11 and #12), nor at the validation site at 24.72 km (15.36 miles) (i.e., Dig #13). Subregions were defined as follows: Subregion 0 between 29.3 km (18.2 miles) and 28.839 km (17.92 miles), and Subregion 1 between 28.839 km (17.92 miles) and 28.035 km (17.42 miles). There were no additional potential liquid

holdup locations in either region; therefore, the detailed examination process was complete for Region 2. Note that an adjacent inclination must be associated with a unique low point to be considered a separate liquid holdup location. The benefit of the DG-ICDA approach is that an assessment may be performed on a pipe segment for which it is not practical to perform ILI. Examination of a limited portion of the line provides information about the remaining length. Internal corrosion is identified but is limited to a few locations. Repairs can be made, possible process problems investigated, and integrity is similarly assured.

-120.0

200 (660)

-100.0

150 (490)

E le v a tio n , m (ft)

-60.0 50 (160)

-40.0

9

10

Moving South

11

13

12

0 (0)

In c lin a tio n , d e g r e e s

-80.0 100 (330)

-20.0

-50 (-160)

0.0

-100 (-330)29.0 (18.0)

28.0 (17.4)

27.0 (16.8)

26.0 (16.2)

20.0 24.0 (14.9)

25.0 (15.5)

Distance, km (mi)

Inclination (S->N)

Critical Angle (S->N)

Critical Angle (N->S)

Elevation

Figure A3: Example inclination profile, gas flowing north to south (first 6.2 km [3.9 miles]). Elevation is shown for reference. Screen capture of spreadsheet. (1 ft = 0.3048 m, 1 mile = 1.609 km)

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SP0206-2006 ________________________________________________________________________ Appendix B: Example Region Definition (Nonmandatory) Figure B1 is an example of DG-ICDA region definitions for a given pipeline. All historic outlets and inlets are shown (Location A, Location B, end, and beginning of the line). There was suspected backflow at the outlet of Location A between 1978 and 1988, so this location has also been used in the region definitions. From this information, the pipeline operator defined three distinct DG-ICDA regions.

The example shown in Appendix A would correspond with the pipe length contained in Region 3, between location B and the receiver; however, only flow in the north-to-south direction (designated Region 2 in Appendix A) is shown in Figure B1.

Years: 1993 to 2002 NORTH Launcher

5 MPag (725 psig), Low 7 MPag (1,015 psig), High Max Flow = 329 kNm3/h (295 million scf/d)

Location A 19.3 km (Output Not Active)

3.45 MPag (500 psig), Low, 5.9 MPag (850 psig), High

Location B 29 km (Input Not Active)

Max Flow = 329 kNm3/h (295 million scf/d)

3.45 MPag (500 psig), Low, 5.9 MPag (850 psig), High

SOUTH Receiver

Max Flow = 329 kNm3/h (295 million scf/d)

Years: 1988 to 1993 Launcher

5.9 MPag (850 psig) No Gas Flow

X

Location A 19.3 km

5.9 MPag (850 psig) No Gas Flow

Location B 29 km

5.9 MPag (850 psig) No Gas Flow

X

(Input Not Active)

(Output Not Active)

Receiver

Years: 1978 to 1988 (Pipeline Installed in 1978)

Launcher

3.45 MPag (500 psig), Low, 5.9 MPag, (850 psig), High Max Flow = 303 kNm3/h (271.5 million scf/d)

REGION 1

Location A 19.3 km

Max Flow = 47.3 kNm3/h (42.4 million scf/d)

3.45 MPag (500 psig), Low, 5.9 MPag, (850 psig), High Max Flow = 303 kNm3/h (271.5 million scf/d)

REGION 2

Location B 29 km

3.45 MPag (500 psig), Low, 5.9 MPag (850 psig), High

Receiver

Max Flow = 329 kNm3/h Max Flow = 26.5 kNm3/h (23.7 million scf/d)

REGION 3

Figure B1: Illustration of ICDA Region Definitions

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NACE SP0208-2008 Item No. 21127

Standard Practice Internal Corrosion Direct Assessment Methodology for Liquid Petroleum Pipelines This NACE International standard represents a consensus of those individual members who have reviewed this document, its scope, and provisions. Its acceptance does not in any respect preclude anyone, whether he or she has adopted the standard or not, from manufacturing, marketing, purchasing, or using products, processes, or procedures not in conformance with this standard. Nothing contained in this NACE International standard is to be construed as granting any right, by implication or otherwise, to manufacture, sell, or use in connection with any method, apparatus, or product covered by Letters Patent, or as indemnifying or protecting anyone against liability for infringement of Letters Patent. This standard represents minimum requirements and should in no way be interpreted as a restriction on the use of better procedures or materials. Neither is this standard intended to apply in all cases relating to the subject. Unpredictable circumstances may negate the usefulness of this standard in specific instances. NACE International assumes no responsibility for the interpretation or use of this standard by other parties and accepts responsibility for only those official NACE International interpretations issued by NACE International in accordance with its governing procedures and policies which preclude the issuance of interpretations by individual volunteers. Users of this NACE International standard are responsible for reviewing appropriate health, safety, environmental, and regulatory documents and for determining their applicability in relation to this standard prior to its use. This NACE International standard may not necessarily address all potential health and safety problems or environmental hazards associated with the use of materials, equipment, and/or operations detailed or referred to within this standard. Users of this NACE International standard are also responsible for establishing appropriate health, safety, and environmental protection practices, in consultation with appropriate regulatory authorities if necessary, to achieve compliance with any existing applicable regulatory requirements prior to the use of this standard. CAUTIONARY NOTICE: NACE International standards are subject to periodic review, and may be revised or withdrawn at any time in accordance with NACE technical committee procedures. NACE International requires that action be taken to reaffirm, revise, or withdraw this standard no later than five years from the date of initial publication and subsequently from the date of each reaffirmation or revision. The user is cautioned to obtain the latest edition. Purchasers of NACE International standards may receive current information on all standards and other NACE International publications by contacting the NACE International First Service Department, 1440 South Creek Dr., Houston, Texas 77084-4906 (telephone +1 281-228-6200).

Approved 2008-11-07 NACE International 1440 South Creek Dr. Houston, Texas 77084-4906 +1 281-228-6200 ISBN 1-57590-221-4 © 2008, NACE International

SP0208-2008

____________________________________________________________________ Foreword This standard practice formalizes a methodology termed liquid petroleum internal corrosion direct assessment (LP-ICDA) that can be used to help ensure pipeline integrity. The methodology is applicable to pipelines that are normally fully packed with petroleum compound(s) existing in an incompressible liquid state under normal pipeline operating conditions, with basic (or bottom) sediment and water (BS&W) contamination normally lower than 5% by volume. This standard is intended for use by pipeline operators and others who manage pipeline integrity. The basis of LP-ICDA is identification and detailed examination of locations along a pipeline in which water or solids can accumulate for extended periods, allowing informed conclusions to be made about the integrity of the nonexamined pipeline. If the locations determined to have the highest susceptibility for long-term internally corrosive conditions are examined and found to be free of significant corrosion, other less susceptible locations may be considered to be free of corrosion. This standard is not applicable to pipelines in which corrosion or leaks have occurred at unpredictable locations, and it may not present an economical alternative to in-line inspection for pipelines found to have moderate or higher rates of internal corrosion. LP-ICDA methodology for liquid petroleum systems is described in terms of a four-step process: (1) pre-assessment, (2) indirect inspection, (3) detailed examination, and (4) post assessment. The LP-ICDA method provides the greatest benefit for pipelines that cannot be in-line inspected; however, the method is not limited to unpiggable pipelines. This standard was prepared by Task Group (TG) 315 on Pipelines (Liquid Petroleum): Internal Corrosion—Direct Assessment. TG 315 is administered by Specific Technology Group (STG) 35 on Pipelines, Tanks, and Well Casings. This standard is issued by NACE International under the auspices of STG 35.

In NACE standards, the terms shall, must, should, and may are used in accordance with the definitions of these terms in the NACE Publications Style Manual. The terms shall and must are used to state a requirement, and are considered mandatory. The term should is used to state something good and is recommended, but is not considered mandatory. The term may is used to state something considered optional.

_____________________________________________________________________

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NACE International Standard Practice Internal Corrosion Direct Assessment Methodology for Liquid Petroleum Pipelines Contents 1. General ........................................................................................................................... 1 2. Definitions ....................................................................................................................... 8 3. Pre-Assessment ............................................................................................................. 9 4. Indirect Inspection ......................................................................................................... 11 5. Detailed Examinations .................................................................................................. 16 6. Post Assessment .......................................................................................................... 18 7. LP-ICDA Records ......................................................................................................... 18 References........................................................................................................................ 19 Appendix A: Determination of Water Accumulation (Nonmandatory) .............................. 22 Appendix B: Determination of Wettability (Nonmandatory) .............................................. 28 Appendix C: Determination of Solids Accumulation (Nonmandatory) .............................. 28 Appendix D: Corrosion Rate Models (Nonmandatory) ..................................................... 31 FIGURES Figure 1: Pre-Assessment Step .......................................................................................... 3 Figure 2: Indirect Inspection Step ....................................................................................... 4 Figure 3: Detailed Examination—Site Selection ................................................................. 5 Figure 4: Detailed Examination Step .................................................................................. 6 Figure 5: Post-Assessment Step ........................................................................................ 7 Figure A1: Schematic representation of the stratified oil-water flow ................................ 25 Figure C1: Schematic presentation of three-layer model and forces acting on a representative particle at the interface between the two bed layers ........................... 29 TABLES Table 1: Typical Data for Use of LP-ICDA Methodology .................................................. 10 ________________________________________________________________________

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SP0208-2008 ____________________________________________________________________________ Section 1: General 1.1 Introduction 1.1.1 This standard is intended to serve as a guide for applying the NACE LP-ICDA process to liquid petroleum pipeline systems. 1.1.2 The primary purposes of the LP-ICDA method are (1) to enhance the assessment of internal corrosion in liquid petroleum pipelines, and (2) to improve pipeline integrity. 1.1.3 The LP-ICDA methodology assesses the likelihood of internal corrosion and includes existing methods of examination available to a pipeline operator to determine whether internal corrosion is actually present or may occur. This methodology may be incorporated into corrosion integrity and risk management plans. 1.1.4 LP-ICDA uses flow modeling results provides a framework to utilize those methods.

and

1.1.5 LP-ICDA was developed for pipelines that are normally fully packed with petroleum compound(s) that exists in an incompressible liquid state under normal pipeline operating conditions, with BS&W contaminations that are normally less than 5% by volume. 1.1.6 One benefit of the LP-ICDA approach is that an assessment can be performed on a pipe segment for which alternative methods (e.g., in-line inspection [ILI], hydrostatic testing, etc.) may not be practical. 1.1.7 LP-ICDA has limitations, and not all pipelines can be successfully assessed with LP-ICDA. These limitations are identified in the pre-assessment step. 1.1.8 The provisions of this standard shall be applied by or under the direction of competent persons who, by reason of knowledge of the physical sciences and the principles of engineering and mathematics, acquired by education or related practical experience, are qualified to engage in the practice of corrosion control and risk assessment on pipeline systems. Such persons may be (1) registered professional engineers, (2) recognized as corrosion specialists by organizations such

as NACE, or (3) professionals (i.e., engineers or technicians) with professional experience, including detection/mitigation of internal corrosion and evaluation of internal corrosion on pipelines. 1.1.9 For accurate and correct application of this standard, it shall be used in its entirety. Using or referring to only specific paragraphs or sections can lead to misinterpretation or misapplication of the recommendations and practices contained herein. 1.1.10 This standard does not designate practices for every specific situation because of the complexity of internal conditions that may be present in various pipeline systems. 1.1.11 In the process of applying LP-ICDA, other pipeline integrity threats, such as external corrosion, mechanical damage, stress corrosion cracking (SCC), etc., may be detected. When such threats are detected, additional assessments, inspections, or both must be performed. The pipeline operator should utilize appropriate methods to address risks other than internal corrosion, such as those described in NACE 1 (1) (2) 2 B31.4, standards (e.g., SP0204), ANSI /ASME 3 (3) 4 5 ANSI/ASME B31.8, API 1160, ANSI/API 579, and (4) 6 (5) BSI 7910, international standards (e.g., DnV RP7 F101), and other documents. 1.1.12 This standard does not address specific remedial actions that may be taken when corrosion is 2 found; however, the reader is referred to ASME B31.4 8 and other relevant documents (e.g., API 2200) for guidance. 1.2 Four-Step Process 1.2.1 LP-ICDA requires the integration of data from multiple field examinations and pipe surface evaluations, including the pipeline’s physical characteristics and operating history. 1.2.2 LP-ICDA includes the following four steps, as shown in Figures 1 through 5.

__________________________________________ (1)

American National Standards Institute (ANSI), 11 W. 42nd St., New York, NY 10036. ASME International (ASME), Three Park Ave., New York, NY 10016-5990. (3) American Petroleum Institute (API), 1220 L St. NW, Washington, DC 2000-4070. (4) British Standards Institute (BSI), 389 Chiswick High Rd., London, United Kingdom W4 4AL. (5) Det Norske Veritas (DnV), Veritasveien 1, 1322, Høvik, Oslo, Norway. (2)

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SP0208-2008 1.2.2.1 Pre-Assessment. The pre-assessment step collects essential historic and present operating data about the pipeline, determines whether LP-ICDA is feasible, and then defines LPICDA regions. The types of data to be collected are typically available in design and construction records, operating and maintenance histories, alignment sheets, corrosion survey records, liquid analysis reports, and inspection reports from prior integrity evaluations or maintenance actions. 1.2.2.2 Indirect Inspection. The indirect inspection step covers flow predictions, developing a pipeline elevation profile, and identifying sites along a pipeline segment most likely to have corrosion damage caused by water, solids accumulation, or

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both, and other factors affecting distribution within a LP-ICDA region.

corrosion

1.2.2.3 Detailed Examination. The detailed examination step includes performing excavations and conducting detailed examinations of the pipe to determine whether metal loss from internal corrosion has occurred. 1.2.2.4 Post Assessment. The post-assessment step is an analysis of the data collected from the three previous steps to assess the effectiveness of the LP-ICDA process, to develop conclusions about the integrity of nonexamined pipe, and to determine reassessment intervals.

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SP0208-2008 Figure 1

Step 1: Pre-Assessment

Yes

Pre-Assessment Step Numbers refer to paragraph numbers in this standard.

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SP0208-2008 Figure 2 From Step 1: Pre-Assessment

For each LP-ICDA region

Indirect Inspection Step Numbers refer to paragraph numbers in this standard.

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SP0208-2008 Figure 3

—

Detailed Examination—Site Selection Numbers refer to paragraph numbers in this standard.

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5

SP0208-2008 Figure 4

Select dig sites (go to Step 3a: Figure 3)

Detailed Examination Step Numbers refer for paragraph numbers in this standard.

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SP0208-2008 Figure 5

-

Post-Assessment Step Numbers refer to paragraph numbers in this standard.

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SP0208-2008 ______________________________________________________________________ Section 2: Definitions Anomalies: See Indication. Cleaning Pig: A device inserted in a pipeline for the purpose of dislodging and removing accumulated corrodents such as solids or water. Corrosion: The deterioration of a material, usually a metal, that results from a reaction with its environment. Creaming: The separation of the phases of an emulsion due to deformation of the dispersed droplets and migration to pipe walls in vertical and near-vertical flows. Critical Droplet Size (dcrit): The largest size of water droplet that can be maintained as a water-in-oil dispersion in horizontal or near-horizontal flow without settling due to gravitational forces causing stratified oil/water flow. Critical Inclination Angle: An angle determined by LPICDA flow modeling; the lowest angle at which water accumulation or solids accumulation is expected to occur.

it until the nominal hoop stresses in the pipeline reach a specified value. Inclination Angle: An angle resulting from a change in elevation between two points on a pipeline, in degrees. Indication: Any measured deviation from the norm. Indirect Inspection: The use of tools, methods, or procedures to evaluate a pipeline indirectly. For LP-ICDA, this consists of calculating and comparing flow modeling results and probability of corrosion distribution with an inclination profile. In-Line Inspection (ILI): The inspection of a pipeline from the interior of the pipe using an ILI tool. The tools used to conduct ILI are known as pigs, smart pigs, or intelligent pigs. In Situ Water Velocity: The average velocity of the bottom layer of water in stratified oil-water flow.

Critical Velocity (Vcrit): The velocity of a water-in-oil dispersion in which the maximum water droplet size (dmax) is smaller than the dcrit. Flow velocity greater than Vcrit significantly reduces the possibility of water accumulation by preventing the separation of oil and water into distinct phases.

Liquid: A substance that tends to maintain a fixed volume, but not a fixed shape.

Dry Gas Internal Corrosion Direct Assessment (DGICDA): A four-step direct assessment (DA) process to evaluate the impact of corrosion occurring on the inside wall of a pipe normally carrying dry natural gas, but may suffer from infrequent upsets of water.

Liquid Petroleum Internal Corrosion Direct Assessment (LP-ICDA): The internal corrosion direct assessment process as defined in this standard applicable to liquid petroleum systems.

Direct Assessment (DA): A structured process that combines pre-assessment, indirect inspections, direct examination, and post assessment to evaluate the impact of predictable pipeline integrity threats such as corrosion. Detailed Examination: The examination of the pipe wall at a specific location to determine whether metal loss from internal corrosion has occurred. This may be performed using any industry-accepted technology, such as visual, ultrasonic, radiographic means, etc.

Liquid Petroleum: Petroleum compound(s) that exists as an incompressible fluid at every point in the pipeline system of interest.

Low Point: A location having higher elevations immediately adjacent upstream and downstream. LP-ICDA Region: A continuous length of pipe (including weld joints) exhibiting a uniform set of operating parameters including the following as a minimum: (1) fluid characteristics (e.g., liquid petroleum, including contaminants), (2) flow characteristics (e.g., diameter and flow rate), and (3) mitigative activities (e.g., pigging and chemical treatment).

Electrolyte: A chemical substance containing ions that migrate in an electric field.

Maximum Droplet Size (dmax): The largest size of water droplet that can be sustained by a flow in a water-in-oil dispersion without further breakup due to turbulent forces.

External Corrosion Direct Assessment (ECDA): A fourstep DA process to evaluate the impact of corrosion occurring on the outside wall of a pipe on the integrity of a pipeline.

Microbiologically Influenced Corrosion (MIC): Corrosion processes that have been made more aggressive through environmental changes brought about by microbiological activity on or near the metal surface.

Hydrostatic Testing: The testing of sections of a pipeline performed by filling the pipeline with water and pressurizing

Overbend: Any vertical change in pipe direction that results in a negative change in slope.

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SP0208-2008

Region: See LP-ICDA Region.

Stratified Flow: A multiphase flow regime in which fluids are separated into layers, with lighter fluids flowing above heavier (i.e., higher-density) fluids.

Segment: A portion of a pipeline that is assessed using LPICDA. A segment may consist of one or more ICDA regions.

Superficial Liquid Velocity: The volumetric flow rate of liquid (at system temperature and pressure) divided by the cross-sectional area of the pipe.

Pigging: See In-Line Inspection or Cleaning Pig.

________________________________________________________________________ Section 3: Pre-Assessment 3.1 Introduction 3.1.1 The objective of the pre-assessment step is to determine whether LP-ICDA is an appropriate integrity assessment method for the selected pipeline segment. It must be perfomed in a comprehensive and thorough manner. This step includes evaluating the potential internal corrosion mechanisms that may have been present in the pipeline during its history. 3.1.2 The pre-assessment step includes the following activities: 3.1.2.1 Data collection;

and maintenance activities related to internal corrosion is essential in determining the probability of significant internal corrosion damage. 3.2.2 At a minimum, the pipeline operator shall collect essential data from the following categories, as shown in Table 1. In addition, a pipeline operator may determine that items not included in Table 1 are necessary. 3.2.2.1 Operating history; 3.2.2.2 System design information (grade, wall thickness of pipe, maximum operating pressure [MOP], etc.);

3.1.2.2 Assessment of LP-ICDA feasibility; and 3.1.2.3 Identification of LP-ICDA regions. 3.2 Data Collection 3.2.1 The pipeline operator shall collect both historical (i.e., throughout the life of the pipeline) and current data, along with physical information for each segment to be evaluated. 3.2.1.1 The pipeline operator shall define minimum data requirements based on the history and condition of the pipeline segment. In addition, the pipeline operator shall identify data elements that are critical to the success of the LP-ICDA process (see Table 1 for typical information to be considered). 3.2.1.2 All parameters that impact the LP-ICDA region definition (see Paragraph 3.4) shall be considered for initial LP-ICDA process applications on a pipeline segment. 3.2.1.3 Accurate and complete elevation profile and flow rate data are essential for predicting the locations of water and solids accumulation. Accurate information regarding pipeline operating

NACE International

3.2.2.3 Presence upsets);

of

liquid

water

(including

3.2.2.4 Water and solids content in the liquid petroleum; 3.2.2.5 Composition of liquid petroleum; 3.2.2.6 Presence of hydrogen sulfide (H2S), carbon dioxide (CO2), and oxygen (O2); 3.2.2.7 Maximum and minimum flow rates; 3.2.2.8 Pipeline elevation profiles; 3.2.2.9 Internal corrosion leak or failure history; 3.2.2.10 Internal corrosion using in-line inspection (ILI) or visual inspection; 3.2.2.11 Mitigation currently being applied to control internal corrosion; and 3.2.2.12 Other known and documented causes of internal corrosion such as microbiologically influenced corrosion (MIC).

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SP0208-2008 Table 1: Typical Data for Use of LP-ICDA Methodology

CATEGORY Operating history Diameter and wall thickness Presence of liquid water (including upsets) Water and solids content in the liquid petroleum Composition of the liquid petroleum Presence of hydrogen sulfide (H2S), carbon dioxide (CO2), or oxygen (O2) Maximum and minimum flow rates Elevation profile

Temperature Inputs/outputs (Injection/delivery points) Corrosion inhibitor Pigging operations Internal corrosion using ILI or visual inspection Other documented internal corrosion Internal corrosion leaks/failures Corrosion monitoring

Internal coatings Other chemical treatment

Other internal corrosion data

DATA TO COLLECT Changes in flow direction, type of service, year of installation, etc. Nominal pipe diameter and wall thickness. Any locations in which liquid water has been identified. Frequency, nature of any liquid water upsets (intermittent or chronic), including volume, if known. Typical BS&W content of liquid petroleum. Results from any laboratory analysis of liquid petroleum. Typical quality specifications. Relationship of crude analyses to pipe location. Typical H2S, CO2, and O2 content of liquid petroleum. Relationship of chemical analysis to pipe location. Maximum and minimum flow rates for all inlets and outlets. Significant periods of low/no flow. (6) Topographical data (e.g., USGS data), including consideration of a pipeline depth of cover. Care must be taken to select instruments that ensure sufficient accuracy and precision may be achieved. Typical operating temperature, unless a special environment exists (e.g., river crossing or aerial pipeline). Identify all locations of current and historic inputs and outputs to the pipeline. Information about injection location, chemical type, batch/continuous, and dose. Types of pigs used, frequency of pigging, and volumes of solids or liquid water recovered from pigging operations. Location and severity of any internal corrosion identified through ILI or visual inspection. Location and severity, as well as potential cause (e.g., CO2) of any other known occurrences of internal corrosion. Locations of internal corrosion-related leaks/failures. 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 (e.g., NACE 9 3T199). Any available nondestructive inspection results. Existence and location(s) of internal coatings. Information about injection location, chemical type, and application method of fluid property modifiers such as drag-reducing agents (DRA), emulsifiers, and demulsifiers. As defined by the pipeline operator.

3.2.3 The data collected in the pre-assessment step often include the same data typically considered in an overall pipeline risk (threat) assessment. Depending on the pipeline operator’s integrity management plan and its implementation, the operator may conduct the pre-assessment step in conjunction with other riskassessment efforts.

3.2.4 When data for a particular category are not available, conservative assumptions shall be used based on the operator’s experience and information about similar systems. The basis for these assumptions shall be documented. 3.2.5 When data regarding liquid petroleum composition (BS&W, CO2 content, H2S content, O2

___________________________ (6)

U.S. Geological Survey (USGS), 12201 Sunrise Valley Drive, Reston, VA 20192.

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SP0208-2008 content, etc.) are unknown, a sample shall be collected and analyzed to gain an understanding of current operations. Note: Samples collected do not provide any information regarding historical operating conditions, but rather are a snapshot of the location and the time that the sample was collected. The operator’s experience and information about similar systems may predicate more conservative assumptions regarding historical liquid petroleum composition, as required (see Paragraph 3.2.4). 3.2.6 In the event the pipeline operator determines that sufficient data are not available or cannot be collected for some LP-ICDA regions comprising a segment to support the pre-assessment step, LP-ICDA shall not be used for those regions until the appropriate data can be obtained. 3.3 LP-ICDA Feasibility Assessment The pipeline operator shall examine the data collected in Paragraph 3.2 to determine whether conditions exist that would preclude this LP-ICDA application or for which indirect inspection tools, methods, or procedures cannot be used. The following conditions preclude the application of this LPICDA standard: 3.3.1 Indirect inspection cannot determine locations in which internal corrosion is most probable; 3.3.2 The pipeline is expected to have a continuous water phase during normal operation; 3.3.3 The pipeline has a continuous internal coating for the entire length of the line;

3.3.4 The pipeline cannot be made accessible for detailed examinations; and 3.3.5 A reliable (or conservative) interval cannot be determined.

reassessment

3.4 Identification of LP-ICDA Regions The pipeline operator shall define LP-ICDA regions from the data collected in the pre-assessment step. 3.4.1 A LP-ICDA region is a portion of pipeline that has at least one distinguishing characteristic to describe it. A distinguishing characteristic is any parameter relating to liquid petroleum constituents, flow patterns, operating conditions, or mitigative actions that may affect the location of corrosion initiation, corrosion mechanism, or anticipated corrosion rate. At a minimum, new LP-ICDA regions should be determined by: 3.4.1.1 Historical and present injection points; 3.4.1.2 Historical and present delivery points; 3.4.1.3 Historical and present chemical injection points; and 3.4.1.4 Historical and present pigging operations (send/receive points). 3.4.2 Region designations shall also consider changes in flow direction. In the case of bidirectional flow history, LP-ICDA regions shall be identified for each flow direction, and each flow direction shall be treated separately.

________________________________________________________________________ Section 4: Indirect Inspection 4.1 Introduction 4.1.1 The objective of the LP-ICDA indirect inspection step is to evaluate the likelihood of internal corrosion as a function of distance within each LP-ICDA region using flow modeling analysis and detailed pipe elevation profiles. 4.1.2 The indirect inspection step requires the comparison of critical velocities and inclination angles for water and solids accumulation with pipeline inclination profiles. Locations that are predicted to have the highest susceptibility to corrodent accumulation for the longest duration of time are assessed the highest likelihood of experiencing significant internal corrosion. The indirect inspection step utilizes this analysis to select sites for detailed examination. Note: Inclination angle is not the only factor that causes water and solids

NACE International

accumulation; therefore, accumulation may be identified as occurring in a horizontal pipe segment. 4.1.3 The LP-ICDA indirect inspection step shall include each of the following activities, for each LPICDA region: 4.1.3.1 Performing multiphase flow calculations using collected data to determine the critical velocities and inclination angles for water and solids accumulation; 4.1.3.2 Identifying other factors for the pipeline system that might influence internal corrosion or corrosion location—such as non-stready flow, temperature profile, or historical pigging operations;

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SP0208-2008 4.1.3.3 Producing a pipeline inclination profile; 4.1.3.4 Identifying sites in which water accumulation, solids accumulation, or both may occur, integrating the flow calculation results with the pipeline inclination profile; and 4.1.3.5 Assessing the probability of internal corrosion at sites in which internal corrosion is most likely to have occurred using corrosion models or sound engineering judgment. 4.2 Water Accumulation 4.2.1 The internal corrosion threat in liquid petroleum systems is based on the assumption that corrosion only occurs when water drops out of the hydrocarbon phase and wets the steel surface of the pipe. Therefore, the operator shall predict critical parameters for water dropout and accumulation using flow modeling calculations for each identified LP-ICDA region. 4.2.2 One model for identifying the minimal velocity for water entrainment and the critical inclination angle for water accumulation is shown in Appendix A (Nonmandatory). For the purpose of providing an example, Paragraphs 4.2.3 and 4.2.5 through 4.2.8 describe the parameters and methodology used in this model. Several other valid models are also identified in Appendix A. Any valid multiphase flow-modeling approach that considers stratified flow, semistratified flow, and water-in-oil dispersion flow is acceptable. The operator shall consider the system operating conditions (i.e., liquid petroleum composition, pressure, temperature, flow rate, etc.) and select a model that is applicable to those conditions. The rationale for selecting the model shall be documented. 4.2.3 A parameter known as Vcrit is used to determine the oil-water flow pattern. If the input velocity is smaller than Vcrit, the flow pattern is stratified for a given flow condition. If the input velocity is equal to or greater than Vcrit, the flow pattern is water-in-oil dispersion for horizontal and downward inclined pipelines. 4.2.4 Accumulation of water does not necessarily lead to corrosion. Under this condition, wettability of the hydrocarbon on the steel determines corrosiveness. Based on the wettability, hydrocarbons can be classified into three categories: 4.2.4.1 Oil-wet surface: On an oil-wet surface, the oil has a strong affinity to be in contact with carbon steel. Oil-wet surfaces physically isolate the pipe from the corrosive environment and, under such conditions, corrosion does not occur. 4.2.4.2 Water-wet surface: On a water-wet surface, the oil does not have an affinity to be in contact with carbon steel; in fact, the oil may not be in contact with the carbon steel at all, even

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when it is the only phase. A water-wet surface (in the presence of oil) is highly susceptible to corrosion. 4.2.4.3 Neutral-wet surface: On a neutral-wet surface, the oil does not have any preference to be in contact with carbon steel. The oil may be in contact with the carbon steel surface as long as there is no competing phase (e.g., water) present. 4.2.4.4 All locations should be assumed to have the same wettability (whether it is oil-wet or waterwet), unless evidence suggests otherwise. Appendix B (Nonmandatory) contains references for laboratory tests that can be performed to determine wettability. 4.2.5 In order for water-in-oil dispersion flow to occur, dmax must be less than dcrit for water entrainment. 4.2.5.1 The dcrit is the water droplet size above which the droplet separates from the oil-water dispersion either as a result of gravity forces, which are predominant in horizontal flow, or deformation and creaming, which is typical of vertical flow. 4.2.5.2 The dcrit is dependent on the pipeline inclination angle. 4.2.6 Determination of dmax for dilute dispersions and dense dispersions is discussed in Appendix A. 4.2.6.1 A dilute dispersion exists when water droplets entrained in the oil phase act independently, fully suspended in the continuous hydrocarbon phase. 4.2.6.2 A dense dispersion exists when droplets of water entrained in the hydrocarbon phase are not fully suspended and there is significant interaction between them. 4.2.7 If water is not entrained in the hydrocarbon phase (i.e., dmax > dcrit), the probability of water/oil phase separation and internal corrosion is increased. Further analysis is then needed to estimate whether water accumulation is expected to occur. 4.2.8 The critical inclination angle is not necessarily constant within an LP-ICDA region (e.g., changes in internal diameter) and is usually plotted against distance. 4.3 Solids Accumulation 4.3.1 Corrosion in locations in which water accumulates may be significantly affected by organic or inorganic solids that may coprecipitate from the liquid, grow on the pipeline surface, or both.

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SP0208-2008 4.3.2 Solid particles within liquid petroleum systems are subject to gravitational forces (which tend to deposit them) and turbulent forces (which tend to keep them in suspension).

sediment. Operations cleared through this method do not require solids accumulation analysis using flow models. 4.4 Other Influencing Factors

4.3.3 Various flow patterns may be observed, depending on the mixture flow rate. If the flow rate is high enough, all the solid particles are suspended because of the high level of turbulence. When the flow rate is reduced, the solid particles with density higher than that of the carrier fluid tend to settle and agglomerate at the bottom of the pipe, forming a moving sediment bed. 4.3.4 The minimal settling bed velocity can be calculated to determine whether or not solids accumulate, and it is based on the balance of driving and opposing torques acting on solid particles. It is influenced by the pipeline inclination angle, as discussed in Appendix C (Nonmandatory). Several other valid models for determining solids accumulation are also identified in Appendix C. The operator shall consider the system operating conditions (i.e., liquid petroleum composition, pressure, temperature, flow rate, BS&W, etc.) and select a model that is applicable to those conditions. The rationale for selecting a model shall be documented. 4.3.5 The inclination angle at which the in situ water velocity is equal to the minimal particle settling velocity is defined as the solids critical inclination angle. 4.3.6 Local variations in turbulence caused by changing pipe direction, fittings, or pipeline diameter changes can cause deposition of sediment and resulting corrosive conditions at locations that are not predicted by the analysis presented in Appendix A. Additional direct examinations at the following locations known to cause local sedimentation may be required to compensate for uncertainties regarding the sedimentation process: 4.3.6.1 Overbends associated with changes in topographical profile and pipe direction (excavate and examine pipe immediately downstream from overbend); 4.3.6.2 Isolation valves (examine entire joint downstream from valve); 4.3.6.3 Pipeline diameter increases (spot check several joints downstream from diameter increases); and 4.3.6.4 Liquid petroleum injection points (spot check several joints downstream from new injection points).

4.4.1 In addition to the primary factors of water and solids accumulation that affect where internal corrosion may occur, the following additional factors should be considered in determining the probability of internal corrosion distribution within a LP-ICDA region: 4.4.2 Emulsion Breaking If sufficient mixing or shear stress is applied to two immiscible liquids such as oil and water, one liquid becomes dispersed in the form of droplets entrained in the other liquid. Once the agitation in the system ceases, the dispersion tends to separate into distinct phases over time. The stability of the dispersion is usually determined by the time required for separation. More stable emulsions require more time for separation. 4.4.2.1 For the same Vcrit, a more stable emulsion may require a longer incline to produce water separation. 4.4.3 Corrosion Inhibition The use of corrosion inhibitors may affect corrosion distribution along a pipeline segment because inhibition effectiveness is usually affected by distance from the injection point. The dependence is different for batch and continuously treated systems and is further influenced by the frequency of pigging. 4.4.3.1 For batch treatment, corrosion may be more likely upstream than downstream. This is especially true for systems whose batch frequency is determined by downstream monitoring (e.g., coupons). Downstream pipe can remain inhibited longer than upstream portions because of readsorption of inhibitor that desorbed from upstream locations. 4.4.3.2 For continuous inhibitors, corrosion may be more likely downstream than upstream. Downstream piping can receive less protection because the residual concentration of the inhibitor decreases with length as the inhibitor adsorbs in upstream locations. This is especially true for systems with long distances between injection point and with corrosion monitoring solely located in upstream portions of pipe.

4.3.7 Nonsedimenting pipeline operations may be demonstrated through the use of mechanical cleaning runs that do not produce accumulated sand or

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SP0208-2008 4.4.4 Water Chemistry

4.4.7 Hysteresis in Wettability

Water chemistry is expected to remain relatively constant throughout the length of pipeline. However, the following changes should be considered:

The amount of time required for the pipeline surface properties to change from hydrophobic (oil-wet) to hydrophilic (water-wet) may be very long, depending on hydrocarbon properties, the presence of surfactants, and flow and operating conditions.

4.4.4.1 Increased dissolved iron with distance (e.g., from internal corrosion) may affect the pH of the water, and 4.4.4.2 If trace amounts of oxygen enter the system, the oxygen may be consumed at upstream locations, leaving downstream locations free from oxygen. 4.4.5 Bacteria and Biocides A pipeline known to suffer from MIC is expected to have a large uncertainty with respect to predicted corrosion severity over distance. Additional direct examinations may be required in systems in which MIC is expected to be the primary internal corrosion mechanism. It has been recognized that even though MIC can occur in unexpected places, it is more prevalent in the following locations: 4.4.5.1 At locations where water is allowed to accumulate; 4.4.5.2 At locations where solid materials are allowed to accumulate; 4.4.5.3. At low point in long-distance pipes; and 4.4.5.4 In stagnant areas or fittings that rarely or never experience flow (i.e., dead legs).

4.4.7.1 Locations predicted to be water-wet under normal operating conditions may have a higher likelihood of internal corrosion than those predicted to be water-wet only during upsets. 4.4.8 Hysteresis in Water and Solids Transport The velocity required to re-entrain settled water and solid materials is higher than the velocity required to maintain entrainment under steady state operation. The impact of short term shutdown or flow rate reductions must be considered as a risk factor. 4.4.9 Effect of Turbulence and Flow Disturbances The effect of turbulence and flow disturbances is dependent on flow rates, flow pattern, liquid petroleum properties, and BS&W content. 4.4.9.1 Additional turbulence at bends or welds may induce entrainment of the water phase, reducing the internal corrosion rate. 4.4.9.2 Turbulence may facilitate water droplets to break through the thin oil film, wetting the pipe surface and inducing localized corrosion. 4.4.9.3 Inertial forces in a bend may also induce additional water/oil separation.

4.4.6 Solids Composition 4.5 Inclination Profile Calculation Internal corrosion caused by solids accumulation may be significantly affected by the presence of different organic and inorganic materials that may be present from corrosion products, scales, and carryover of solids into the pipeline segment. 4.4.6.1 The effectiveness of cleaning pigs over distance should be considered. 4.4.6.2 The composition of solids may provide information on potential internal corrosion mechanisms.

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4.5.1 The operator shall calculate the inclination profile or change in elevation over the defined length. The accuracy of the inclination profile is critical to the success of LP-ICDA, and the accuracy of methods to measure the profile must be documented (including consideration of pipeline depth-of-cover). 4.5.2 The inclination profile shall be composed of multiple sets of data points for each LP-ICDA region examined and is calculated by Equation (1): ⎛ ∆(elevatio n) ⎞ ⎟⎟ θ = arcsin ⎜⎜ ⎝ ∆(distance ) ⎠

(1)

4.4.6.3 The presence of corrosion products or other adherent scale or organic deposits can reduce the internal corrosion rate. A system with a changing scaling tendency may have less internal corrosion where a protective scale has formed.

Where:

4.4.6.4 The deposition of wax or formation of a stable asphaltenic layer on the surface can effectively inhibit corrosion.

4.5.3 Elevation measurements must be taken at intervals that capture all relevant changes in the inclination profile. The minimum interval depends on

θ is the inclination angle at that location.

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SP0208-2008 the specific pipeline being evaluated, the terrain, and other features. Uncertainty in the inclination profile must be estimated based on the accuracy of elevation data. 4.5.4 The operator shall document the procedure for collecting the elevation data, the elevation data obtained, the assumptions made in this process, the method of determining uncertainty of the inclination profile, and this uncertainty.

4.6.1 The probability of corrosion distribution is calculated based on the primary locations in which internal corrosion is expected and the relative influence of other factors, which are identified in Paragraph 4.4. 4.6.2 Primary locations shall be selected based on a comparison of the critical inclination angle for water accumulation and the critical inclination for solids accumulation with the pipeline inclination profile. 4.6.2.1 All locations with inclinations greater than either the water critical inclination angle or the solids critical inclination angle shall be identified as primary locations. 4.6.3 If internal corrosion has been previously identified in the pipeline, locations that have similar characteristics to those in which internal corrosion was identified before may be considered primary locations. 4.6.4 All locations that have been identified as primary locations for internal corrosion shall be arranged in order of priority based on a calculated distribution of corrosion which considers the effects of influencing parameters discussed in Paragraph 4.4. The distribution of corrosion shall be determined based on Equation (2):

Region

= ∏ f i (x) i

(2)

Where: Pc is the probability of corrosion, which can be normalized by dividing Pc(x) over the maximum probability, Pcmax.

f i(x) is a series of corrosion-influencing factors. The range of values for each factor, f (x) must never include zero and always include 1: 0 < f i(x) ≤ 1. 4.6.5 The range of values for f i(x) is dependent on the magnitude of the influence of the factor and the confidence in its accuracy.

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4.6.5.2 Factors that have a low confidence but a large influence shall be assigned values ranging between 0.5 and 1, depending on location. 4.6.5.3 Factors with high confidence but a small influence shall be assigned values ranging between 0.9 and 1, depending on location.

4.6 Probability of Corrosion Distribution

Pc (x)

4.6.5.1 Factors with a high confidence and a large influence shall be assigned values ranging between 0.1 and 1, depending on location. Water and solids accumulation are factors in this category.

4.6.5.4 Factors with low confidence and a small influence shall be assigned a value of 1 at all locations. 4.6.6 The basis for assigning the range of values for each factor shall be documented. 4.6.7 As an alternative to calculating the probability of corrosion distribution, a corrosion rate model may be used to determine which primary locations are most likely to contain internal corrosion. Appendix D (nonmandatory) contains a number of models to determine corrosion rate. Any corrosion rate model that considers multiphase flow may be used. The operator shall consider the system operating conditions (i.e., liquid petroleum composition, pressure, temperature, flow rate, BS&W, etc.) and select a corrosion model that is applicable to those conditions. The rationale for selecting a model shall be documented. 4.7 Site Selection 4.7.1 At a minimum, the two locations with the greatest probability of internal corrosion within each LP-ICDA region shall be selected for detailed examination. 4.7.1.1 Consideration shall be given to the possibility of long-distance stratification of pipeline fluids and dispersed solids. For regions longer than 5 km (3 mi), the ICDA region should be segregated into subregions corresponding to first, second, and third equal lineal portions; the two locations with the greatest probability of internal corrosion within each subregion shall be selected for detailed examination. 4.7.2 If there has been bidirectional flow through the pipeline, flow in the opposite direction shall be considered as a separate LP-ICDA region, and each direction shall be treated separately. 4.7.3 The two locations with the highest probability of internal corrosion based on water accumulation modeling within each LP-ICDA region shall be identified for detailed examination.

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SP0208-2008 4.7.3.1 If a region or subregion contains more than two sites with a similar highest probability of internal corrosion, additional sites shall be selected. 4.7.4 For pipelines susceptible to solids accumulation due to flow disturbance effects, two locations with the highest probability of internal corrosion within each LPICDA region or subregion shall be identified for detailed examination.

4.7.5.2 Locations selected for detailed examination should be compared to repair records and history in order to identify any steel/composite repair sleeves that may exist that would make inspections difficult. Also, because internal corrosion is a time-dependent threat, if the location selected is in an area of replacement pipe, consideration should be given to selecting another site with a similar probability of internal corrosion. 4.8 Comparison and Analysis

4.7.4.1 Solids accumulation resulting from flow disturbance effects is exacerbated by increasing pipe diameter and increasing hydrocarbon density. 4.7.5 Site accessibility, repair history/records, and any internal leak/rupture history should be considered during site selection. 4.7.5.1 If multiple sites have the same probability for the same internal corrosion mechanism, it may be prudent to perform the first inspection at the site that is most easily accessible.

4.8.1 To check for consistency, the results of the indirect inspection shall be compared to the data collected in the pre-assessment step as well as any locations in which internal corrosion is known to have occurred. The values assigned to each factor shall be reevaluated in selected sites that are not consistent with the known location of internal corrosion or preassessment data.

________________________________________________________________________ Section 5: Detailed Examinations 5.1 Introduction 5.1.1 The objectives of the LP-ICDA detailed examination are (1) to determine whether internal corrosion exists at locations selected in the indirect assessment step, and (2) to use the findings to assess the overall condition of the LP-ICDA region. 5.1.2 The detailed examination step focuses examination efforts on identified sites and features most likely to experience internal corrosion. 5.1.3 Excavation and subsequent inspection sufficient to identify and characterize internal corrosion features in the pipe must be used. 5.1.4 Procedures for nondestructive inspection techniques (NDT) and action as a result of identifying defects during the inspection are not included in the scope of this standard. The operator must follow the appropriate guidelines located in related NACE and ASME standards for evaluating and responding to the presence and extent of corrosion at each site examined. 5.1.5 During the detailed examination step, defects other than internal corrosion, such as external corrosion, mechanical damage, and SCC, may be found. If this occurs, alternative methods must be considered for assessing the impact of such defect types.

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5.1.6 Alternative methods are given in ASME B31.4, 4 5 6 API 1160, ANSI/API 579, BS 7910, NACE standards, international standards, and other documents. 5.1.7 The priority in which excavations and detailed examinations are made shall be determined through comparison of flow modeling results with the pipe inclination profile. 5.2 Performing the Detailed Examination Process 5.2.1 Selection and examination of sites for detailed examination shall be based on the diagrams shown in Figures 3 and 4. Any deviation from this process must be technically justified by the operator, and the reasons must be documented. 5.2.2 An alternative to the deterministic detailed examination process as described in Figures 1 through 5 is to optimize the number of excavations required for LP-ICDA assessment by engineering analysis (including probabilistic methods). The use of an alternative approach shall be technically justified, and the methodology and assumptions documented. 5.2.3 In addition, detailed examination shall be conducted in one location not identified as susceptible for internal corrosion. 5.2.4 In summary, locations with the greatest probability of internal corrosion must be examined in

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SP0208-2008 each LP-ICDA region or subregion. The two locations with the highest priority shall be examined. Two consecutive locations must be found free of internal corrosion to complete the assessment. 5.2.5 One of the following criteria shall be used for measurements to determine the presence of internal corrosion. These criteria are the basis for determining the number of required detailed examinations as described in Paragraph 5.2.4. 5.2.5.1 Internal corrosion metal loss is considered present if the wall thickness is less than minimum specified nominal (compensation for metal loss from external corrosion can be made).

5.3 Other Facility Components 5.3.1 Even in the absence of a critical incline, facility components that rarely or never experience flow (i.e., dead legs) may represent worst-case conditions for water and solids accumulation. Examples of such locations include tee fittings where the direction of pipe flow (under normal operating conditions) makes an abrupt turn, allowing water and solids to accumulate in the full bore pipe immediately past the tee. 5.3.2 The pipeline operator shall examine at least one fixture in which flow effects can be expected to preferentially deposit water or solids. 5.4 Excavation and Inspection

5.2.5.2 A pipeline-specific analysis may be performed to develop criteria for internal corrosion. The analysis might include consideration of previous metal loss and years of pipeline service. 5.2.5.3 Other technical criteria for internal corrosion may be used with documented technical justification. 5.2.6 Operators may perform additional validation examinations at their discretion on regions for which the detailed examination process has been completed. 5.2.7 When the detailed examination process identifies the existence of extensive severe internal corrosion, the operator shall return to pre-assessment because the applicability of LP-ICDA is in question (significant continuous water phase). 5.2.8 When performing the detailed examination step, the operator shall conduct detailed, accurate measurements of the wall thickness and determine the axial length of any wall loss indications present. The length of the pipeline affected by water accumulation may be large in some situations, and care should be taken in selecting the proper NDT technique. Remaining wall thickness values must be identified. 5.2.9 NDT methods used to determine the remaining wall of the pipe in corroded areas shall be performed in accordance with qualified written procedures and applicable industry standards by individuals qualified by training and experience.

5.4.1 Corrosion detection and mitigation are not included in the scope of the LP-ICDA standard. However, improvements for real-time monitoring and future site accessibility for LP-ICDA, to be installed concurrently with excavations/inspections, are recommended. 5.4.2 Once a site has been exposed, the operator may install a corrosion monitoring device to assist in determining assessment intervals and benefit from monitoring in the locations most susceptible to 13 corrosion. Various monitoring devices are discussed 9 in NACE Publication 3T199. 5.4.2.1 Coupons installed at arbitrary locations (e.g., end of pipeline) are not expected to represent a pipeline with corrosion that varies with location. 5.4.2.2 Monitoring equipment must be selected based on the appropriate corrosion threat mechanism. 5.4.3 ILI tools (or other assessment) results for a portion of pipe within a LP-ICDA region may provide information that can be used to help assess the condition of the pipeline in areas where a pig cannot be run. 5.4.3.1 ILI results showing extensive significant corrosion demonstrate that the LP-ICDA process is not feasible for that region.

5.2.10 The pipeline operator shall evaluate or calculate the remaining strength of locations in which corrosion is found. Example methods of calculating the remaining 10 11,12 and strength include RSTRENG, ASME B31G, 7 DnV RP-F101.

5.4.3.2 ILI results showing sporadic locations of corrosion damage may be used to refine the susceptibility analysis used to select direct examination sites.

5.2.11 The inspection procedures, detailed wallthickness data, and strength calculations must be retained with the LP-ICDA records for the pipeline.

5.4.3.3 ILI results showing negligible corrosion damage allow a reduction in the number of direct examination sites required to demonstrate the integrity of that region.

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SP0208-2008 ________________________________________________________________________ Section 6: Post Assessment 6.1 Introduction 6.1.1 The objectives of the post-assessment step are to assess the effectiveness of LP-ICDA and to determine reassessment intervals. 6.1.2 If the operator utilizing LP-ICDA determines that the locations most susceptible to internal corrosion are free from metal loss, the integrity of a large portion of pipeline mileage has been assured relative to this corrosion threat, and resources can be focused on pipelines on which corrosion is determined to be more likely. 6.2 Assessment of LP-ICDA Effectiveness 6.2.1 Effectiveness of the LP-ICDA process is determined by the correlation between detected corrosion and the LP-ICDA predicted locations. 6.2.1.1 Operators must evaluate the effectiveness of LP-ICDA, and the process shall be documented. 6.2.2 The operator shall establish additional criteria for assessing the long-term effectiveness of the LP-ICDA process. 6.2.2.1 An operator may choose to establish criteria that track the reliability or repeatability with which the LP-ICDA process is applied. 6.2.3 If extensive corrosion is found throughout the pipeline, the assumption that water and solid corrodents are predictably being transported in the liquid petroleum shall be reevaluated. 6.3 Remaining Life Calculations 6.3.1 If no internal corrosion defects are found, no remaining life calculation is needed. The remaining life can be taken as the same for a new pipeline.

6.3.2.1 The remaining life of the maximum remaining flaw shall be estimated using sound engineering analysis. 6.3.3 The corrosion growth rate shall be determined by one of the following methods: 6.3.3.1 Reexamine the site at a prescribed frequency to determine or assess growth rate (i.e., monitor site for corrosion growth on the actual pipe); 6.3.3.2 Install one or more corrosion monitoring devices at sites of predicted liquid accumulation and at other representative locations, based on flow modeling results; 6.3.3.3 Apply a corrosion rate model based on operating conditions, liquid composition, and other key factors; or 6.3.3.4 Perform laboratory testing on fluids (i.e., liquid water composition) to determine corrosiveness. 6.4 Determination of Reassessment Intervals 6.4.1 When internal corrosion is identified during detailed examinations, the maximum reassessment interval for each LP-ICDA region shall be taken as onehalf of the calculated remaining life. The maximum reassessment interval may be further limited by 2 3 documents such as ASME B31.4 and ASME B31.8. 6.4.2 Different LP-ICDA regions may have different reassessment intervals based on variation in expected internal corrosion growth rates. 6.5 Feedback and Continuous Improvement 6.5.1 Improvements as a result of this assessment are to be incorporated into future LP-ICDA projects.

6.3.2 The maximum remaining flaw size at all detailed examination locations shall be used in the remaining life calculations.

________________________________________________________________________ Section 7: LP-ICDA Records 7.1 Introduction 7.1.1 This section describes LP-ICDA records that document data pertinent to pre-assessment, indirect inspection, detailed examination, and post assessment

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in a clear, concise, and workable manner. All decisions and supporting assessments must be documented. The records required by the standard must be kept for the life of the pipeline.

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SP0208-2008 7.2 Pre-Assessment Documentation

7.4.1.1.2 Data used to identify other areas that may be susceptible to corrosion; and

7.2.1 All pre-assessment step actions and decisions shall be recorded. These may include, but are not limited to, the following:

7.4.1.1.3 Results calculations.

strength

7.4.1.3 Descriptions of and reasons for any selections of additional sites. 7.5 Post Assessment 7.5.1 All post-assessment actions and decisions shall be recorded. These may include, but are not limited to, the following:

7.2.1.3 Boundaries of LP-ICDA regions. 7.3 Indirect Inspection

7.5.1.1 Remaining-life calculation results;

7.3.1 All indirect inspection actions and decisions shall be recorded. These may include, but are not limited to, the following: 7.3.1.1 Flow models used to determine critical angles for solids and water accumulation, as well as the rationale for selecting each model;

7.5.1.1.1 Maximum determinations;

remaining

7.5.1.1.2 Corrosion minations; and

growth

flaw

rate

size

deter-

7.5.1.1.3 Method of estimating remaining life.

7.3.1.2 Method for determining the accuracy of inclination profiles; and

7.5.1.2 Reassessment intervals, including technical justification and operator’s validation of selected method of reassessment;

7.3.1.3 Method used for determining the probability of corrosion distribution (or, alternatively, identifying the corrosion model used), as well as the rationale for selecting a given corrosion rate model, if used.

7.5.1.3 Criteria used to assess LP-ICDA effectiveness and results from assessments;

7.4 Detailed Examinations

7.5.1.3.1 Criteria and metrics; and 7.5.1.3.2 Data from periodic assessments.

7.4.1 All detailed examination actions and decisions shall be recorded. These may include, but are not limited to, the following:

7.5.1.4 Monitoring records; and 7.5.1.5 Feedback.

7.4.1.1 Data collected before and after the excavation; 7.4.1.1.1 Measured geometries;

remaining

7.4.1.2 Planned mitigation activities; and

7.2.1.1 Data elements collected for the segment to be evaluated, in accordance with Table 1; 7.2.1.2 Methods and procedures used to integrate the data collected to determine when LP-ICDA is not feasible; and

of

metal

loss

corrosion

________________________________________________________________________ References 1. NACE SP0204 (latest revision), “Stress Corrosion Cracking (SCC) Direct Assessment Methodology” (Houston, TX: NACE). 2. ANSI/ASME B31.4 (latest revision), “Pipeline Transportation Systems for Liquid Hydrocarbons and Other Liquids” (New York, NY: ASME). 3. ANSI/ASME B31.8 (latest revision), “Gas Transmission and Distribution Piping Systems” (New York, NY: ASME).

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4. API 1160 (latest revision), “Managing System Integrity for Hazardous Liquid Pipelines” (Washington, DC: API). 5. ANSI/API 579 (latest revision), “Recommended Practice for Fitness-for-Service and Continued Operation of Equipment” (Washington, DC: API). 6. BS 7910 (latest revision), “Guide to methods for assessing the acceptability of flaws in metallic structures” (London, England: BSI).

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SP0208-2008 7. DnV-RP-F101 (latest revision), “Corroded Pipelines” (Oslo, Norway: DnV). 8. API 2200 (latest revision), “Repairing Crude Oil, Liquified Petroleum Gas, and Product Pipelines” (Washington, DC: API). 9. NACE Publication 3T199 (latest revision), “Techniques for Monitoring Corrosion and Related Parameters in Field Applications” (Houston, TX: NACE). 10. P.H. Vieth, J.F. Kiefner, RSTRENG2 (DOS Version) User’s Manual and Software (Includes L51688B, Modified Criterion for Evaluating the Remaining Strength of Corroded (7) Pipe) (Washington, DC: PRCI, 1993). 11. ANSI/ASME B31G (latest revision), “Manual for Determining the Remaining Strength of Corroded Pipelines: A Supplement to B31, Code for Pressure Piping” (New York, NY: ASME). 12. P.H. Vieth, J.F. Kiefner, “A Modified Criterion for Evaluating the Remaining Strength of Corroded Pipelines: A Supplement to B31, Code for Pressure Pipe,” PRCI, PR-3805, Final Report, December 22, 1989. 13. API Specification 5L (latest revision), “Specification for Line Pipe” (Washington, DC: API). 14. O. Moghissi, W. Sun, C. Mendez, J. Vera, S. Brossia, "Development of ICDA for Liquid Petroleum Pipelines," PHMSA Report DTRS56-05-T-0005, 2006. 15. N. Brauner, D. Maron, “Two-Phase Liquid-Liquid Stratified Flow,” Physico Chemical Hydrodynamics 11, 4 (1989): pp. 487-506. 16. R.S. Brodkey, The Phenomena of Fluid Motions (New York, NY: Dover Publications, 1995). 17. D. Barnea, “A Unified Model for Predicting Flow-Pattern Transitions for the Whole Range of Pipe Inclinations,” International Journal Multiphase Flow 13, 1 (1987): pp. 112. 18. Y. Taitel, A.E. Dukler, “A Model for Predicting Flow Regime Transitions in Horizontal and Near Horizontal Gas(8) Liquid Flow,” AIChE Journal 22, 1 (1976): pp. 47-55.

19. B.F.M. Pots, “Prediction of Corrosion Rates of the Main Corrosion Mechanisms in Upstream Applications,” CORROSION/2005, paper no. 550 (Houston, TX: NACE, 2005). 20. J.T. Davies, “Calculation of Critical Velocities to Maintain Solids in Suspension in Horizontal Pipes,” Chemical Engineering Science 42, 7 (1987). 21. J.F. Hollenberg, R.V.A. Olimens, “Prediction of Flow Conditions to Minimize Corrosion,” Shell Report, 1992. 22. A.J. Karabelas, “Vertical Distribution of Dilute Suspensions in Turbulent Pipe Flow,” AIChE Journal 23, 4 (1977): p. 426. 23. A. Segev, “Mechanistic Model for Estimating Water Dispersion in Crude Oil Flow,” 90th Annual AIChE meeting, held November 25-30, 1984 (New York, NY: AIChE, 1984). 24. B.F.M. Pots, J.F. Hollenberg, E.L.J.A. Hendriksen, “What Are the Real Influences of Flow on Corrosion?” CORROSION/2006, paper no. 591 (Houston, TX: NACE, 2006). 25. S. Papavinasam, A. Doiron, T. Panneerselvam, R.W. Revie, “Predicting Internal Pitting Corrosion of Oil and Gas Pipelines: Hydrocarbon-Wet to Water-Wet Transition,” CORROSION/2006, paper no. 641 (Houston, TX: NACE, 2006). 26. U. Lotz, “Velocity Effects in Flow-Induced Corrosion,” CORROSION/90, paper no. 27 (Houston, TX: NACE, 1990). 27. H. Snuverrink, O. Lansink, P.E.M. Duijvestijn, “Liquid/Liquid Oil/Water Flow in Pipes: Entrainment of Settled Water by Flowing Oil in Pipes,” Shell Report, 1987. 28. D.T. Tsahalis, “Conditions for the Entrainment of Settled Water in Crude Oil and Product Pipelines,” 83rd Annual AIChE Meeting, held March 21-24, 1977 (New York, NY: AIChE, 1977). 29. C. Deng, K. Sand, P. Teevens, “A Web Based Software for Prediction of the Internal Corrosion of Sweet and Sour Multiphase Pipelines,” CORROSION/2006, paper no. 565 (Houston, TX: NACE, 2006). 30. K. Sand, C. Deng, P. Teevens, D. Robertson, T. Smyth, “Corrosion Engineering Assessments via a Predictive Tool,” presented at the Tri-Service Corrosion Conference, held November 14-18, 2005 (sponsored by the

___________________________ (7) (8)

Pipeline Research Council International, Inc. (PRCI), 1401 Wilson Blvd., Suite 1101, Arlington, VA 22209. American Institute of Chemical Engineers (AIChE), Three Park Avenue, New York, NY 10016-5991.

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United States Department of Defense Corrosion Policy and Oversight Office, the Office Under Secretary of Defense for Acquisition, Technology, and Logistics, and NACE International, 2005).

41. A. Anderko, “Simulation of FeCO3/FeS Scale Formation Using Thermodynamic and Electrochemical Models,” CORROSION/2000, paper no. 102 (Houston, TX: NACE, 2000).

31. P. Teevens, “Sour Pipeline Production Operations: 27 Years of Failure-Free Engineering Strategies for the Detection, Mitigation and Prevention of Internal Corrosion,” CORROSION/2005, paper no. 647 (Houston, TX: NACE, 2005).

42. A. Anderko, P. McKenzie, R.D. Young, “Computation of Rates of General Corrosion Using Electrochemical and Thermodynamic Models,” Corrosion 57, 3 (2001): pp. 202213.

32. M. Wicks, J.P.Fraser, “Entrainment of Water by Flowing Oil,” Materials Performance 14, 5 (1975): p. 9. 33. J.O. Hinze, “Fundamentals of the Hydrodynamic Mechanism of Splitting in Dispersion Processes,” AIChE Journal 1, 3 (1955): p. 289. (10)

34. ISO 6614 (latest revision), “Petroleum Products— Determination of Water Separability of Petroleum Oils and Synthetic Fluids” (Geneva, Switzerland: ISO). 35. W.G. Anderson, “Wettability Literature Survey - Part 2: Wettability Measurement,” Journal of Petroleum Technology 38, 12 (1986): pp. 1246-1262. 36. S. Papavinasam, A. Doiron, R.W. Revie, “Determine Inhibitory and/or Corrosive Properties of Condensates,” PRCI, GRI-8705, 2005. 37. P. Doiron, D. Barnea, “Flow Pattern Maps for SolidLiquid Flow in Pipes,” International Journal of Multiphase Flow 22, 2 (1996): pp. 273-283. 38. J.R. Shadley, S.A. Shirazi, E. Dayalan, E.F. Rybicki, “Velocity Guidelines for Preventing Pitting of Carbon Steel Piping when the Flowing Medium Contains CO2 and Sand,” CORROSION/96, paper no. 15 (Houston, TX: NACE, 1996). 39. C.D. Adams, J.D. Garber, R.K. Sing, V.R. Jangama, “Computer Modeling to Predict Corrosion Rates in Gas Condensate Wells Containing CO2,” CORROSION/96, paper no. 31 (Houston, TX: NACE, 1996). 40. A. Anderko, R.D. Young, “Simulation of CO2/H2S Corrosion Using Thermodynamic and Electrochemical Models,” CORROSION/99, paper no. 31 (Houston, TX: NACE, 1999).

43. M.R. Bonis, J.L. Crolet, “Basics of the Prediction of the Risks of CO2 Corrosion in Oil and Gas Wells,” CORROSION/89, paper no. 466 (Houston, TX: NACE, 1989). 44. J.L. Crolet, N. Thevenot, A. Dugstad, “Role of Free Acetic Acid on the CO2 Corrosion of Steels,” CORROSION/99, paper no. 24 (Houston, TX: NACE, 1999). 45. E. Dayalan, F.D. de Moraes, S.A. Shirazi, E.F. Rybicki, “CO2 Corrosion Prediction in Pipe Flow Under FeCO2 Scale-Forming Conditions,” CORROSION/98, paper no. 51 (Houston, TX: NACE, 1998). 46. C. de Waard, D.E. Milliams, “Carbonic Acid Corrosion of Steel,” Corrosion 31, 5 (1975): pp. 177-181. 47. C. de Waard, U. Lotz, “Prediction of CO2 Corrosion of Carbon Steel,” CORROSION/93, paper no. 69 (Houston, TX: NACE, 1993). 48. C. de Waard, U. Lotz, A. Dugstad, “Influence of Liquid Flow Velocity on CO2 Corrosion: A Semi-Empirical Model,” CORROSION/95, paper no. 128 (Houston, TX: NACE, 1995). 49. B. Mishra, S. Al-Hassan, D.L. Olson, M.M. Salama, “Development of a Predictive Model for ActivationControlled Corrosion of Steel in Solutions Containing Carbon Dioxide,” Corrosion 53, 11 (1997): pp. 852-859. 50. S. Nesic, J. Postlethwaite, S. Olsen, “An Electrochemical Model for Prediction of Corrosion in Mild Steel in Aqueous Carbon Dioxide Solutions,” Corrosion 52, 4 (1996): p. 280. 51. S. Nesic, J. Postlethwaite, S. Olsen, “An Electrochemical Model for Prediction of CO2 Corrosion,” CORROSION/95, paper no. 131 (Houston, TX, 1995). 52. S. Nesic, M. Nordsveen, R. Nyborg, A. Stangeland, “A Mechanistic Model for CO2 Corrosion with Protective Iron Carbonate Films,” CORROSION/2001, paper no. 40 (Houston, TX: NACE, 2001).

___________________________ (9)

Department of Defense (DoD), 1400 Defense Pentagon, Washington, DC 20310-1400.

(10)

International Standards Organization (ISO), 1, ch. de la Voie-Creuse, Case postale 56,CH-1211 Geneva 20, Switzerland. NACE International

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SP0208-2008 53. R. Nyborg, P. Andersson, M. Nordsveen, “Implementation of CO2 Corrosion Models in a Three-Phase Fluid Flow Model,” CORROSION/2000, paper no. 48 (Houston, TX: NACE, 2000). (11)

Standard M-506 (latest revision), “CO2 54. NORSOK Corrosion Rate Calculation Model” (Lysaker, Norway: NORSOK). 55. A.M.K. Halvorsen, T. Santvedt, “CO2 Corrosion Model for Carbon Steel Including a Wall Shear Stress Model for Multiphase Flow and Limits for Production Rate to Avoid Mesa Attack,” CORROSION/99, paper no. 42 (Houston, TX: NACE, 1999). 56. J.E. Oddo, M.B. Tomson, “The Prediction of Scale and CO2 Corrosion in Oil Field Systems,” CORROSION/99, paper no. 41 (Houston, TX: NACE, 1999). 57. S. Papavinasam, R.W. Revie, V. Sizov, “Predicting Internal Pitting Corrosion of Oil and Gas Pipelines: Model Preduction vs. Field Experience,” CORROSION 2007, paper no. 658 (Houston, TX: NACE, 2007). 58. S. Papavinasam, R.W. Revie, W.I. Friesen, A. Doiron, T. Panneerselvam, “Review of Models to Predict Internal

Pitting Corrosion of Oil and Gas Pipelines,” Corrosion Reviews 24, 3-4 (2006): pp. 173-230. 59. B.F.M. Pots, “Mechanistic Models for the Prediction of CO2 Corrosion Rates under Multi-Phase Flow Conditions,” CORROSION/95, paper no.137 (Houston, TX: NACE, 1995). 60. S. Srinivasan, R.D. Kane, “Prediction of Corrosivity of CO2/H2S Production Environments,” CORROSION/96, paper no. 11 (Houston, TX: NACE, 1996). 61. M.B. Kermani, L.M. Smith, eds., “CO2 Corrosion Control in Oil and Gas Production, Design Considerations,” (12) European Federation of Corrosion Publications, Number 23, Chapter 6 (London, England: Maney Publishing, 1997), pp. 18-23. 62. N. Petalas, K. Aziz, “A Mechanistic Model for Multiphase Flow in Pipes,” Journal of Canadian Petroleum Technology 39, 6 (2000): pp. 43-55. 63. E. Adsani, S.A. Shirazi, J.R. Shadley, E.F. Rybicki, “Mass Transfer and CO2 Corrosion in Multiphase Flow,” CORROSION/2002, paper no. 492 (Houston, TX: NACE, 2002).

________________________________________________________________________ Appendix A: Determination of Water Accumulation (Nonmandatory) This appendix is considered nonmandatory, although it may contain mandatory language. It is intended only to provide supplementary information or guidance. The user of this standard is not required to follow, but may choose to follow, any or all of the provisions herein. Example of an Oil-Water Flow Model (excerpt from 14 PHMSA DTRS56-050T-0005) This model is not intended to bind the user of this direct assessment standard practice to a particular modeling approach, but rather to demonstrate the level of sophistication required to predict water accumulation in liquid-packed hydrocarbon pipelines with reasonable rigor. This model has been peer reviewed (through PHMSA) and is in reasonable agreement with other flow models and published flow loop data. The operator shall consider the system operating conditions (i.e., liquid petroleum composition, pressure, temperature, flow rate, BS&W, etc.) and select a model that is applicable to those conditions. Under a given set of flow conditions, there is a maximum size of water droplet that can exist without being broken down into smaller pieces by the forces of turbulence. Similarly, there is a maximum water droplet size that can be

sustained without settling under the forces of gravity. The point at which these two values are equal is known as the critical velocity for a water-in-oil dispersion, and comparison of the actual pipe flow to this critical velocity determines whether a stable water-in-oil dispersion will persist, or whether the flow will separate into stratified layers of oil on water (stratified flow). Factors governing formation of water droplets and their sizes are oil- and water-specific gravities, interfacial tension between the oil and water, oil viscosity, oil velocity, pipe diameter, and pipeline inclination. The critical velocity can be calculated at different pipeline inclinations for a certain test condition, and eventually the critical pipeline inclination for water entrainment can be deduced. The sets of equations proposed for these calculations are described in the paragraphs following.

_______________________________ Norsk Sokkels Konkuranseposisjon (NORSOK), P.O. Box 242, NO-1326 Lysaker, Norway. (12) European Federation of Corrosion (EFC), 1 Carlton House Terrace, London SW 1Y 5DB, UK. (11)

22

NACE International

SP0208-2008 U o = U sw + U so

Maximum Droplet Size Two sets of equations (see Equations [A.1] through [A.15]) are used to determine the maximum droplet size, depending on the characteristics of the water dispersion in the oil phase. The first set of equations described in this appendix apply to dilute dispersions.

(A.7)

Where (units are dimensionless unless otherwise stated): U o is the oil velocity (the continuous phase, in this case),

m/s U sw

is the superficial water velocity, m/s, ( U sw = Qw

For dilute dispersions: Under dilute flow conditions, the water droplets entrained in the oil phase act independently, fully suspended in the continuous hydrocarbon phase, and fluid-droplet forces dominate.

(1 - ε w )

ρm ≈1 ρo

),

Where: 3

is the volume flow of water, m /s 2 and A is the cross-sectional area of pipe, m Q Uso is the superficial oil velocity, m/s ( Uso = o ), Q o is the QW

3

(A.1)

A

A

volume flow of oil, m /s η is the oil viscosity, Pa-s σ is the surface tension of the water, N/m o

Where (units are dimensionless unless otherwise stated): ε w is the in situ water cut (i.e., fractional flow that is water— the disperse phase, in this case) 3 ρm is the density of the oil-water mixture, kg/m ρo is the density of the continuous phase (in this case, oil), 3 kg/m d max , the maximum droplet size, in m, for pipe flow, can be 15

expressed according to Brauner as: ⎛ d max ⎜⎜ ⎝ D

⎡ ρ (1 - ε w ) ⎤ ⎞ ⎟⎟ = 1.88 ⎢ o ⎥ ρm ⎦ ⎠ dilute ⎣

- 0.4 - 0.6

We o Reo

0.08

(A.2)

The Weber number represents the ratio between the external force that tends to deform the drop and the counteracting surface tension force (see Equation A.8). Although the turbulent field in pipe flow is not homogeneous and isotropic, Equation (A.2) has been proven to yield a good prediction of dmax in the flow of dilute dispersions for a variety of two-liquid systems, as long as dmax < 0.1 D. For liquid systems, where the density of the continuous and disperse phases is approximately the same, this approximation is valid for εw< 1.

If:

Wecrit = τ ⋅ d max /σ

1.8Re o

0.7

⎛d < ⎜⎜ max ⎝ D

⎞ < 0.1 ⎟⎟ ⎠ dilute

(A.3)

(A.8)

Where:

τ = shear stress, N/m2

Note that the subscript refers to dilute dispersion.

The following input parameters are required for the calculation of dmax:

Where (units are dimensionless unless otherwise stated): Fluid parameters: D is the pipe diameter, m ε w is the in situ water cut

3

Water phase: Qw (m /s) 3 Mixture oil-water: ρm (kg/m ) 3 Hydrocarbon or oil phase: Qo (m /s), η o (Pa-s), σ (N/m), 3 ρ o (kg/m )

Weo is Weber number of the oil phase Reo is Reynolds number of the oil phase

εw =

U sw U sw + U so

Weo =

Reo =

ρo DU o2 σ

ρo DUo ηo

NACE International

(A.4)

Geometric Parameters: Pipe diameter: D (m) 2 Cross-sectional area: A (m )

(A.5)

(A.6)

For dense dispersions: When the dispersion cannot be considered dilute, which means droplets of water entrained in the hydrocarbon phase are not fully suspended and there is much interaction

23

SP0208-2008 between them, a dense dispersion approach should be considered. This approach may apply if there is an eventual increase in the water cut for any reason or if there is a large difference between the oil-water mixture density and the oil density. Under such conditions, the flow rate of oil phase, Qo, should carry sufficient turbulent energy to disrupt the tendency of the water droplets, flowing at a rate Qw, to coalesce. 15 Brauner noted that the rate of surface energy production in the coalescing water phase is proportional to the rate of turbulent energy supply by the flowing oil phase (see Equations [A.9] to [A.12]): ⎛ ρo U '2 ⎜ ⎜ 2 ⎝

⎞ 4σ ⎟Qo = C H Qw ⎟ d max ⎠ Qo =

(A.9)

π 2 D U so 4

(A.10)

π Qw = D 2 U sw 4

(A.11)

U '2 = 2 (ed max )

2/3

(A.12)

Where:

⎧⎛ d ⎞ ⎫ ⎛ d max ⎞ ⎛d ⎞ ,⎜ max ⎟ ⎜ ⎟ = Max ⎨⎜ max ⎟ ⎬ ⎝ D ⎠ ⎩⎝ D ⎠ dilute ⎝ D ⎠ dense ⎭

(A.15)

Gravity Effect The gravity effect is the critical droplet diameter above which separation of droplets due to gravity, dcd, takes place. This can be found by a balance of gravity and turbulent forces, as shown in Equation (A.16):

fU o2 3 ρ ⎛ d cd ⎞ 3 ρo = f 0 Fro ⎜ ⎟= ⎝ D ⎠ 8 ∆ρ Dg ⋅ cos (θ ) 8 ∆ρ Where Froude number (Fro) is defined Equations (A.17), (A.18), and (A.19) as: Fr o =

U o2 Dg ⋅ cos (β )

(A.16)

in

(A.17)

∆ρ = ρ o - ρw

(A.18)

Where (units are dimensionless unless otherwise stated):

CH is a constant of the order of 1, and

U ' (m/s) denotes the

turbulent kinetic energy. In the isotropic and homogeneous turbulence, the turbulent kinetic energy can be related to the rate of turbulent energy dissipation, e, as shown in Equation (A.13) (turbulent 2 3 energy dissipation rate is in units of m /s ): e=

2U 4τU o ρm = Dρo (1 − εw ) D ρo (1 − εw ) 3 o

(A.13)

Substituting Equations (A.11) and (A.13) into (A.9) yields Equation (A.14): ⎛ ρ U 2D ⎞ ⎛ d max ⎞ = 2.22C H0.6 ⎜⎜ o o ⎟⎟ ⎜ ⎟ ⎝ D ⎠ dense ⎝ σ ⎠

- 0.6

⎛ εw ⎜ ⎜1 - ε w ⎝

⎞ ⎟ ⎟ ⎠

-0.6

⎡ ⎤ ρm f⎥ ⎢ ( ) ρ 1 ε o w ⎣ ⎦

- 0.4

(A.14)

The subscript dense denotes the dense oil-water dispersion and f is the Fanning friction factor, see Equation (A.19). For the dense dispersion analysis, the same parameters used for the dilute dispersion analysis are needed. Given a water-oil fluid system and operational conditions, the largest droplet size that can be sustained is the larger of the two values obtained via the dilute or the dense dispersion approach (Equations [A.2] and [A.14]), which can

24

be considered as the worst case for a given oil-water system (see Equation [A.15]):

β : inclination of the pipeline, degrees g : gravity constant, 2 9.81 m/s f : turbulent flow friction factor f = 0.046/Reo0.2

(A.19)

This effect is predominant at low pipe inclinations, i.e., in horizontal and near-horizontal flows. The critical droplet diameter, above which drops are deformed and creamed (dcσ), leads to the migration of the droplets toward the pipe walls in vertical and near-vertical 16 flows, as calculated in Equations (A.20) through (A.22):

⎤ 0.4σ ⎛ d cσ ⎞ ⎡ ⎟=⎢ ⎜ ⎥ 2 − ⋅ D ρ ρ gD cos ( θ ) ⎠ ⎣⎢ o ⎝ w ⎦⎥ θ = β if β < 45 o θ = 90 − β if β > 45 o

0.5

(A.20)

(A.21) (A.22)

Dcrit can then be conservatively estimated for any pipe inclination according to the suggestion made by Barnea 17 (see Equation [A.23]):

NACE International

SP0208-2008 ⎧⎛ d d crit = Min ⎨⎜⎜ cd D ⎩⎝ D

⎞ ⎛ d cσ ⎟⎟, ⎜⎜ ⎠⎝ D

⎞⎫ ⎟⎟⎬ ⎠⎭

locations, the in situ water velocity approaches zero, accumulation occurs, and the likelihood of internal corrosion is increased.

(A.23)

In addition to the parameters needed to estimate dmax, the calculation of dcrit requires the inclination angle of pipeline. The final criterion for water entrainment into the 15 hydrocarbon or oil phase is established by Brauner. The transition from stratified flow to stable water-in-oil dispersion occurs, when the oil phase turbulence is intense enough to maintain the water phase broken up into droplets not larger than dmax, which must be smaller than dcrit, causing droplet separation (dmax ≤ dcrit). In situ water velocity estimation

The objective is to identify local examination points in which water that is not entrained in the hydrocarbon can locally accumulate (i.e., upstream from inclines). In these

The two-phase segregated flow model is selected because liquid petroleum transmission pipelines are fully packed witha liquid phase (i.e., no significant gas phase), and the water content in crude oil is typically specified by BS&W of less than 1%. Two-phase stratified model

In the two-phase segregated flow model, the phases are assumed to be totally separated, with one phase flowing at the top of the pipe and the other at the bottom of the pipe. Two sets of conservation equations, one for oil phase and the other for water phase, are used to describe the momentum balance, mass balance, and energy balance in the two-phase segregated flow model. The schematic of a two-phase stratified flow of oil and water in a circular pipe is shown in Figure A1.

Figure A1

si

τo

Ao

uo

τi Aw

−

τi

uw

τi

h

τw

Schematic representation of the stratified oil-water flow.

Based on the figure, both mass balance and momentum balance conservation equations are written for each phase. A mass balance includes Equations (A.24) to (A.26): Qo = U o Ao = U so A

(A.24)

Qw = U w Aw = U sw A

(A.25)

Qo + Qw = U o Ao + U w Aw = (U so + U sw )A

Aw =

(A.26)

⎛ 2 ⎛ − ⎞ ⎛ − ⎞ D2 ⎜ ⎛ − ⎞ π − acos⎜⎜ 2 h −1 ⎟⎟ + ⎜⎜ 2 h −1 ⎟⎟ 1 − ⎜ 2 h − 1 ⎟ ⎜ 4 ⎜ ⎜ ⎟ ⎜ ⎟ ⎝ ⎠ ⎝ ⎠ ⎝ ⎠ ⎝

⎞ ⎟ ⎟ ⎟ ⎠

(A.27)

−

Where: 2

A is the pipe cross-sectional area, m 3 Qo is the volumetric flow rate of the oil phase, m /s 3 Qw is the volumetric flow rate of the water phase, m /s 2 Ao is the cross-sectional area occupied by the oil layer, m Aw is the cross-sectional area occupied by the water layer, 2 m Uo is the in situ velocity of the oil layer, m/s

NACE International

Uw is the in situ velocity of the water layer, m/s Uso is the superficial velocity of the oil layer, m/s Usw is the superficial velocity of the water layer, m/s If the height of the oil-water interface is h from the bottom of the pipe, then the cross-sectional area occupied by the water phase is given by Equation (A.27):

Where the dimensionless film height, h , is calculated in Equation (A.28): −

h=

h D

(A.28)

and

D is the diameter of the pipe, m

25

SP0208-2008 A momentum balance is carried out for the oil and water layers in Equations (A.29) and (A.30):

⎛D U f o = Co ⎜⎜ o o ⎝ υo

⎞ ⎟ ⎟ ⎠

− no

(A.34)

For the water phase: ⎛ dp ⎞ Aw ⎜ ⎟ − τ w Sw − τ i1Si1 − ρw Aw gsinβ = 0 ⎝ dx ⎠

(A.29)

− nw

(A.35)

υw is the water viscosity in m2/s υ o is the oil viscosity in m2/s

⎛ dp ⎞ Ao ⎜ ⎟ − τ oSo + τ i Si − ρo Ao gsinβ = 0 ⎝ dx ⎠

(A.30)

Where:

τ o is the shear stress at wall for oil, N/m2 τ w is the shear stress at wall for water, N/m2 τ i is the interfacial shear stress, N/m2 β is the pipe inclination, (β is positive for upward flow), degrees So is the portion of pipe circumference in contact with the oil phase, m Sw is the portion of pipe circumference in contact with the water phase, m Si is the width of the interface, m 3 (dp/dx) is the pressure gradient, N/m 3 is the density of the oil phase, kg/m ρo 3 ρ w is the density of the water phase, kg/m The pressure drop is the same in both the phases. The pressure drop term is eliminated in Equation (A.31): ⎛S So S S ⎞ − τ w w − τ i ⎜⎜ i + i ⎟⎟ + (ρ o − ρ w )gsinβ = 0 Ao Aw A A w ⎠ ⎝ o

The constants C and n are given the following values: for laminar flow, C = 16 and n = 1 and for turbulent flow, C = 0.046 and n = 0.2. It should be noted that the Reynolds numbers for the two fluids are based on the equivalent hydraulic diameters. These are defined according to 15 whether the upper layer is the faster one, or vice-versa. The interface is considered a free surface when the velocities of the phases on each side of the interface are of comparable levels. When the velocities are different, the interfacial surface must be added to the wetted perimeter of the faster phase. In contrast to gas-liquid flow, the velocities of the two phases in liquid-liquid systems may be similar, and alternatively, one phase velocity exceeds the other (see Equations [A.36] to [A.41]). For Uo > Uw:

ρ oU o2 2

τ w = fw

ρ w Uw2 2

(A.36)

Dw =

4 Aw Sw

(A.37)

Do =

4Ao So

(A.38)

4Aw Sw + Si

(A.39)

For Uo < Uw

18

τ o = fo

4Ao So + Si

Do =

(A.31)

Following Taitel and Dukler, the shear stresses are evaluated by using a Blasius-type equation, as shown in Equations (A.32) and (A.33):

Dw = For Uo = Uw

(A.32)

Do =

4Ao So

(A.40)

(A.33)

Dw =

4Aw Sw

(A.41)

Where: f is a Fanning friction factor that depends on the Reynolds number.

The friction factors are defined in Equations (A.34) and (A.35):

26

⎞ ⎟ ⎟ ⎠

Where:

For the oil phase:

τo

⎛D U f w = Cw ⎜⎜ w w ⎝ υw

The interfacial shear stress between the two layers, defined in Equation (A.42):

τ i = fi

ρ(U w − U o )(U w − U o ) 2

τi,

is

(A.42)

NACE International

SP0208-2008 Where (units are dimensionless unless otherwise stated): 3

ρ is the density of the faster layer, kg/m

f i is the friction factor of the faster layer

assumptions: homogeneous dispersion, single droplet size, drops act as solid particles, smooth pipe wall, and horizontal line. 22,23,24

Karabelas/Segev (K/S) Model

All parameters shown in the momentum balance (Equation [A.31]) can be expressed as a function of interface height. Hence, solving Equation (A.31) for a given oil and water flow rate, the height of the interface can be predicted. The holdup and pressure drop can then be evaluated.

This model provides critical flow velocity for water settling. This velocity is assumed to be the flow velocity at which 60% of water accumulates at the bottom.

Other models can be used to calculate water accumulation. For example, a simple calculation for predicting water entrainment in oil under turbulent flow (Reynolds number of 19 liquid phase > 2,100) has been proposed based on two critical Froude numbers, as indicated in Equation (A.43):

There are two kinds of emulsions: oil-in-water and water-inoil. An oil-in-water emulsion has high conductivity and is corrosive. In an operating pipeline, initially, the amount of water carried is lower and the amount of oil carried is higher, and the water content progressively increases. The percentage of water at which water-in-oil converts to oil-inwater is known as the emulsion inversion point (EIP). Laboratory and field probes are available to identify the type of emulsion under pipeline operating conditions.

F=

ρo VL ∆ρgD

(A.43)

F > 0.67 ⇒No water accumulation at bottom of pipe F > 2 ⇒ Water entrainment into the oil phase Where (units are dimensionless unless otherwise stated): 3

ρo is the oil density, kg/m 3 ∆ρ the oil-water density difference, kg/m 2 g is the acceleration due to gravity, 9.81 m/s D is the hydraulic diameter of the liquid phase (oil + water), m VL is the liquid phase velocity, m/s

At a Froude number of 0.67, water is predicted to be swept from a low point over a hill by the oil flow. This rule is based on flow loop tests and considered conservative for inclinations less than 5 degrees. At a Froude number of about 2, water is predicted to be entrained into the oil phase. The critical value is obtained from modeling of the breakup of water droplets and found to be within 20% of field and laboratory cases studied. Alternative Flow Models

A number of additional rules and models are available to describe the likelihood of water dropout of oil, leading to establishment of corrosion conditions. Every model has its limitations; therefore, when a particular model is used, its characteristics and limitations should be understood. Only some simple models are described in this appendix; more complex models are not necessarily better. 20,21

Hollenberg and Oliemans Model

Hollenberg and Oliemans describe a model that establishes the Vcrit, at which sufficient turbulence is created to break up large water droplets and to maintain them in dispersion against sedimentation. It is based on the following

NACE International

24,25

Papavinasam Model

24,26

Pots Model

In the past, a minimum mixture velocity of 1 m/s and a maximum water cut of 20% was used for a safe and corrosion-free operation. However, based on a combination of laboratory and field experiments, it was found that water dropout and water-film thickness depend on the nature of the oil, and that no single Vcrit can be used in all circumstances. 24,27

Snuverink et al. Model

Snuverink et al. correlated Vcrit for moving water over a hill with a Froude number. This rule is conservative for inclinations less than 5 degrees. It applies only when the flow is turbulent. This model was developed by determining the sweeping of water from the lowest point of an inclined pipe section in laboratory experiments using various pipe diameters, inclinations, and model fluids. 28

Tsahalis Model

The Tsahalis model was developed to predict the minimum flow velocity at which the water is entrained into the oil phase. This model gives typical critical flow velocities as low as 0.5 m/s. 29,30,31

Teevens Model

The Teevens model predicts both the liquid holdup and the internal corrosion rate in two- and three-phase oil and gas production pipelines. It is able predict both the location and liquid hold-up cross-sectional area as a function of distance and elevation change over discrete distances as dictated by global positioning system (GPS) interval data collected and inputted into the model.

27

SP0208-2008 32,33

Wicks and Fraser Model

The model developed by Wicks and Fraser refers to the pickup of water by flowing oil from low points. The model is based on a combination of two correlations: one for the minimum velocity for the net axial transport of sand particles

and one for water dropout size. It is assumed that the correlation for the sand particles is equally applied to rigid dropouts of the same size. The droplet size is taken from a different study, which refers to dmax in a turbulent flow. The sand transport correlation is derived from experimental data for transport of sand in various liquids.

________________________________________________________________________ Appendix B: Determination of Wettability (Nonmandatory) This appendix is considered nonmandatory, although it may contain mandatory language. It is intended only to provide supplementary information or guidance. The user of this standard is not required to follow, but may choose to follow, any or all of the provisions herein. Emulsion and wettability are two different properties. A hydrocarbon may hold a lot of water, but as soon as the inversion point occurs, the surface may become water-wet immediately. On the other hand, an inversion point may occur at a very low water cut, but the surface may not become water-wet until a very high water cut is reached. The difference in behavior is because the emulsion depends on liquid-liquid (oil-water) interaction, whereas wettability depends on the balance between two solid-liquid (steel-oil and steel-water) interactions.

Laboratory setup: Steel samples are polished (600 grit). The samples are then placed in a beaker containing distilled water, and the oil is injected through a syringe into the water so that it adheres to the sample surface. A photograph from which the contact angle is measured is taken.

Contact Angle Method

Spreading Method

The tendency of water to displace hydrocarbon from steel can be estimated by considering the relative surface energies of all the interfaces involved. A hydrocarbon-steel interface is replaced by a water-steel interface if the energy of the system decreases as a result of this action.

In this method, the conductivity of the emulsion is measured between two probes placed at various distances apart. In the presence of oil with no affinity toward steel (water-wet), good conductivity (typically between 1 and 2 kΩ) is measured between all probes. On the other hand, in the presence of oil with an affinity toward steel (oil-wet), no conductivity is measured between any of the probes. In the presence of oil with no particular affinity (mixed-wet), conductivity is measured between some probes.

On the other hand, displacement of water by hydrocarbon is expected when θ, measured through the oil, is between 0° and 90°.

25,34,35,36

Displacement of water by hydrocarbon should be expected when the contact angle (θ), measured through the water, is between 90° and 180°, and displacement of hydrocarbon by water should be expected when θ is between 0° and 90°.

______________________________________________________________________ Appendix C: Determination of Solids Accumulation (Nonmandatory) This appendix is considered nonmandatory, although it may contain mandatory language. It is intended only to provide supplementary information or guidance. The user of this standard is not required to follow, but may choose to follow, any or all of the provisions herein. Example of Solids Accumulation Model (excerpt from 14 PRCI PR-186-04305)

This model is not intended to bind the user of this direct assessment standard practice to a particular modeling approach, but rather to demonstrate the level of sophistication required to predict solids accumulation in liquid-packed hydrocarbon pipelines with reasonable rigor. This model has been peer reviewed (through PRCI) and is

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in reasonable agreement with other models. The operator shall consider the system operating conditions (i.e., liquid petroleum composition, pressure, temperature, flow rate, BS&W, etc.) and select a model that is applicable to those conditions. Settled-out solids often contain high concentrations of contaminants such as bacteria and organic chlorides that may benignly persist on the bottom of a pipeline until a

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SP0208-2008 significant water upset activates the electrochemical process. Some solid materials are known to transport a certain amount of attached water that is adsorbed onto their hydrophilic surfaces, and hence are innately corrosive even in the absence of a discrete water phase. Hence, some understanding of the mechanisms leading to the accumulation of solid materials is warranted. An understanding of solid contaminant transportation can be considered under two general categories: (1) continuous flow analysis, and (2) flow disturbance effects. Continuous flow analysis can be used to evaluate the relative susceptibility of a pipeline to accumulating sediment under idealized pipe flow conditions, but some susceptible pipelines manifest a higher degree of internal corrosion damage due to flow disturbances. These are discussed separately. Continuous Flow Analysis

Various flow patterns are observed, depending on the mixture flow rate. If the flow rate is high enough, all the solid particles are suspended because of the high level of

turbulence. When the flow rate is reduced, the solid particles whose density is higher than that of the carrier fluid tend to settle and agglomerate at the bottom of the pipe, forming a moving deposit. When the sum of the driving forces acting on the particle is lower than the sum of the forces opposing the particle motion, the particle becomes stationary. To determine whether solids settle at the bottom of the pipe or move away, it is important to calculate the minimal settling bed velocity. The minimal bed velocity is obtained from the balance of driving and opposing torques acting on the solid particles in the lowermost stratum of the moving layer. A typical particle, which rests between adjacent particles of the upper part of the stationary bed and is at the verge of rolling, is shown schematically in Figure C1. In this situation, the driving torque (which arises from the drag exerted by the moving bed layer on the particle) and the opposing torque (which arises from the submerged weight of the particle and the moving bed particles, which lie on top of it) must balance.

Figure C1

Schematic presentation of three-layer model and forces acting on a representative particle at the interface 37 between the two bed layers. 1 2 C D AP (C.1) F D = ρ L U bc The driving torque is FDLD, where FD is the drag exerted by 2 the surrounding medium, and LD is the perpendicular distance from the center of rotation (O in Figure C1), to the line of action of the driving force. The drag is calculated Where (units are dimensionless unless otherwise stated): using Equation (C.1):

ρ L is the density of the carrier liquid, kg/m3 NACE International

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SP0208-2008 Where (units are dimensionless unless otherwise stated):

U bc is the minimal settling velocity, m/s

AP is the projection of the particle’s exposed area on a 2 plane normal to the flow direction, m C D is the drag coefficient for the particle. C D depends on the particle Reynolds number, Rep (see Equations [C.2] to [C.4]). Re P = ρL ω o d P /µ L C D = 18.5Re P−0.6 C D = 0.44

(C.2)

0.1 < Re P L < 500

500 < Re P L < 2 ×10 5

(C.3) (C.4)

LD passes through the centroid of Ap, as shown in Equation (C.5): d ⎛ π ⎞ L D = P ⎜ sin + 0.0137 ⎟ 3 2 ⎝ ⎠

(C.5)

N is the average number of particles in the column y mb is the height of the moving bed layer, m Cmb is the moving bed concentration (assumed to be 0.52 for cubic packing)

The distance (L2) between the line of action of this force to the centre of rotation, “O,” is found using Equation (C.9): d ⎛π ⎞ (C.9) L 2 = P sin⎜ ⎟ 2 ⎝6 ⎠ The minimal settling bed velocity is then extracted by equating the driving torque and the opposing torques (see Equation C.10):

U bc

⎡ ⎛π ⎛y ⎞⎤ ⎞ cos β 1.559 (ρ S − ρ L )gd P ⎢sin ⎜ + β ⎟ + C mb ⎜⎜ mb − 1 ⎟⎟ ⎥ d 6 2 ⎠ ⎝ ⎝ P ⎠ ⎦⎥ (C.10) ⎣⎢ = ρ LC D

Where: Flow Disturbance Effects

wo is the fluid velocity, m/s µL is the viscosity of the liquid, Pa-s dp is the particle’s diameter, m The opposing torque is composed of the effect of the submerged weight of the particle (WpL1) and the effect of the solid particles in the moving bed layer pressing on it (FNL2). The particle’s submerged weight, Wp, is found using Equation (C.6): WP =

1 π (ρS − ρ L )gd P3 6

(C.6)

Where:

Such disturbances in susceptible pipelines may precipitate sudden changes in the ability of the working fluid to maintain uniform transport of the moving sediment bed on the pipe floor, and severely accelerated settling of solid materials may result; thus, accelerated corrosion is possible. Common characteristics of most susceptible pipelines are identified below:

• Large diameter (> 0.4 m)

Wp is the particle’s submerged weight, N ρ S is the density of the solids, kg/m3 2 g is the gravitational acceleration, 9.81 m/s The perpendicular distance (L1) from the line of action of this force to the center of rotation, “O,” is found using Equation (C.7): L1 =

dP ⎛π ⎞ sin⎜ + β ⎟ 2 ⎝6 ⎠

(C.7)

Where:

The normal force exerted by the column of particles lying above the particle under consideration is found using Equation (C.8): FN = W P Ncosβ = W P C mb

3

• Higher-density petroleums (> 900 kg/m ) • Moderate-low flow rates (< 1.2 m/s) • Measurable base sediment load (even as low as ~ 0.05%) Pipelines exhibiting these characteristics should have a selection of direct examination sites based on the following flow disturbance creating fittings:

• Valves (downstream joint or 5 m minimum)

β is the pipe’s angle, radians

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Flow disturbances caused by pipeline fittings, valves, diameter changes, direction changes, and injection locations create unpredictable turbulence variations within an operating pipeline.

y mb − d P cosβ dP

(C.8)

• Diameter increases (downstream joint or 5 m minimum) • Overbends (5 m downstream, beginning at overbend) • Injection points (5 m downstream, beginning at injection point)

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SP0208-2008 29,30

Alternative Models

Teevens Model

A number of additional rules or models to describe the likelihood of solids accumulation in oil-packed pipelines are available. Every model has its limitations; therefore, when a particular model is used, its characteristics and limitations should be understood. Only some simple models are described; more complex models are not necessarily better.

This model predicts where solids deposition locations are most likely to occur by calculating the solids depositional velocity of the material being accumulated. It predicts solids accumulation as a function of distance and elevation change over discrete distances, as dictated by global positioning satellite (GPS) interval data collected and input into the model. The model does not predict the cumulative amount of the material, nor does it attempt to predict underdeposit corrosion rate behavior at this time.

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Shadley Model

The Shadley model is based on the analysis of corrosion pattern to provide guidelines for flow rates below which solids are expected to accumulate.

________________________________________________________________________ Appendix D: Corrosion Rate Models (Nonmandatory) This appendix is considered nonmandatory, although it may contain mandatory language. It is intended only to provide supplementary information or guidance. The user of this standard is not required to follow, but may choose to follow, any or all of the provisions herein. A corrosion rate model may be used to identify locations for detailed examination instead of determining the probability of corrosion distribution. Several models to predict internal corrosion of oil and gas pipelines are presented in this appendix. This list is not exhaustive. In addition, several commercial software packages that are largely based on these models are available. 39

Adams Model

The Adams model, developed from the operating conditions of condensate wells, can be used to predict corrosion rates in gas condensate wells based on operating conditions, temperatures, and flow rates. 40,41,42

Anderko Model

This comprehensive model has been developed to calculate the corrosion rates of carbon steels in the presence of CO2, H2S, and brine. It combines a thermodynamic model (that provides realistic speciation of aqueous systems) with an electrochemical model (based on partial cathodic and anodic processes on the metal surface). The partial processes taken into account by this model include the oxidation of iron and reduction of hydrogen ions, water, carbonic acid, and hydrogen sulfide. 43,44

45

Dayalan Model

This model consists of a computational procedure and a computer program to predict the corrosion rates of carbon steel pipeline caused by CO2-containing flowing fluids in oil and gas field conditions. The computational procedure is based on a mechanistic model for CO2 corrosion and is developed from basic principles. The model takes into account the CO2 corrosion mechanism and the kinetics of electrochemical reactions, chemical equilibrium reactions, and mass transfer. 46,47,48

De Waard and Milliams Model

The model developed by de Waard and Milliams is the most frequently cited model for evaluating internal corrosion. The first version of this model was published in 1975, and it has been revised three times since then. In the earlier versions of the model, there was no significant consideration of the effects of liquid flow velocity on the CO2 corrosion rate. The corrosion reaction was assumed to be activation controlled, although the observed corrosion rates were, in some cases, about twice the rate predicted. Therefore, a somewhat empirical equation was developed to describe and predict the effect of the flow rate. In 1995, the effect of carbides on the CO2 corrosion rate was addressed. 49

Crolet Model

Mishra Model

The Crolet model predicts the probability of corrosion in oil wells. It is based on a detailed analysis of field data on CO2 corrosion from two oilfield operations. In the Crolet model, the parameters that influence potential corrosiveness are pH level, carbonic acid (H2CO3), CO2, acetic acid, temperature, and flow rate.

Corrosion of steel in CO2 solutions is considered to be a chemical-reaction-controlled process. In the Mishra model, a corrosion rate equation was derived on the basis of fundamental reaction rate theory and was then compared with empirically determined relationships reported in the literature. The prediction of this model is similar to the

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SP0208-2008 empirically developed models; the model, however, accounts for the effects of steel microstructure and the flow velocity of the solution on the corrosion rate. The application limit for this model occurs when the corrosion process begins to be diffusion controlled, usually after the formation of a stable corrosion-product scale on the steel surface. 50,51,52

Nesic Model

Nesic uses a theoretical approach by modeling individual electrochemical reactions occurring in a water-CO2 system. The processes modeled in this system are the electrochemical reactions at the metal surface and the transport processes of all the species in the system, + 2+ including H , CO2, H2CO3, and Fe . The Nesic model requires the following inputs: temperature, pH, CO2 partial pressure, oxygen concentration, steel, and flow geometry. Version 2 of the Nesic model also predicts the equivalent of a scaling tendency (that is, the ratio between the precipitation rate and the corrosion rate). 53,54,55

Nyborg Model

Nyborg integrated the 1993 and 1995 versions of the de Waard and Milliams model with a commonly used threephase fluid-flow model. The temperature, pressure, and liquid flow velocity profiles derived from this fluid-flow model are used to calculate CO2 partial pressure, pH, and corrosion rate profiles along the pipeline. 56

Oddo Model

The Oddo model uses an iterative approach to predict the corrosion rate. The model accounts for protective films formed by the deposition of mineral scales. Initially, the program calculates the corrosion rate, assuming that there is no scale on the metal surface. 57,58

Papavinasam, et al. Model

The Papavinasam, et al. model predicts internal pitting corrosion of oil and gas pipelines. The model accounts for the statistical nature of the pitting corrosion, predicts the growth of internal pits based on the readily available operational parameters from the field, and includes the pit

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growth rate driven by variables that are not included in the model. It also considers the variation of the pitting corrosion rate as a function of time and determines the error in the prediction. 59

Pots Model

This mechanistic model predicts the CO2 corrosion rate and the effects of fluid flow. The model, also referred to as the Limiting Corrosion Rate (LCR) model, provides a theoretical upper limit for the corrosion rate based on the assumption that the rate determining steps are the transport and production of protons and carbonic acid in the diffusion and reaction boundary layers. 60

Srinivasan Model

The basis of the Srinivasan model is the de Waard and Milliams relationship between CO2 and corrosion rate, but additional correction factors are introduced. The first step in this approach is a computation of the system pH. The dissolved CO2 (or H2S) that contributes to pH is determined as a function of acid gas partial pressures, bicarbonates, and temperature. In addition to pH reduction, the Srinivasan model takes into account the role of H2S as a general corrodent, as a protective film former, and as a pit initiator. 61

SSH Model

The SSH model is a worst-case scenario model, derived mainly from laboratory data below 100 °C and from a combination of laboratory and field data at temperatures above 100 °C. 30,31,32,62,63

Teevens Model

This mass-transfer model is capable of yielding a general corrosion rate for uninhibited corroding multiphase or twophase pipeline systems, in which O2, CO2, and H2S contribute to corrosion of carbon steel pipes. The gas-liquid flow model was updated mainly from the work of Petalas and Aziz, Taitel and Dukler, and Barnea. The flow model predicts the flow pattern, liquid holdup, pressure drop, and friction losses, and it calculates gas and liquid velocities.

NACE International NACE International ISBN 1-57590-221-4

NACE SP0106-2006 Item No. 21111

Standard Practice Control of Internal Corrosion in Steel Pipelines and Piping Systems This NACE International (NACE) standard represents a consensus of those individual members who have reviewed this document, its scope, and provisions. Its acceptance does not in any respect preclude anyone, whether he or she has adopted the standard or not, from manufacturing, marketing, purchasing, or using products, processes, or procedures not in conformance with this standard. Nothing contained in this NACE standard is to be construed as granting any right, by implication or otherwise, to manufacture, sell, or use in connection with any method, apparatus, or product covered by Letters Patent, or as indemnifying or protecting anyone against liability for infringement of Letters Patent. This standard represents minimum requirements and should in no way be interpreted as a restriction on the use of better procedures or materials. Neither is this standard intended to apply in all cases relating to the subject. Unpredictable circumstances may negate the usefulness of this standard in specific instances. NACE assumes no responsibility for the interpretation or use of this standard by other parties and accepts responsibility for only those official NACE interpretations issued by NACE in accordance with its governing procedures and policies which preclude the issuance of interpretations by individual volunteers. Users of this NACE standard are responsible for reviewing appropriate health, safety, environmental, and regulatory documents, and for determining their applicability in relation to this standard prior to its use. This NACE standard may not necessarily address all potential health and safety problems or environmental hazards associated with the use of materials, equipment, and/or operations detailed or referred to within this standard. Users of this NACE International standard are also responsible for establishing appropriate health, safety, and environmental protection practices, in consultation with appropriate regulatory authorities if necessary, to achieve compliance with any existing applicable regulatory requirements prior to the use of this standard. CAUTIONARY NOTICE: NACE standards are subject to periodic review, and may be revised or withdrawn at any time in accordance with NACE technical committee procedures. NACE International requires that action be taken to reaffirm, revise, or withdraw this standard no later than five years from the date of initial publication. The user is cautioned to obtain the latest edition. Purchasers of NACE International standards may receive current information on all standards and other NACE International publications by contacting the NACE International FirstService Department, 1440 South Creek Drive, Houston, Texas 77084-4906 (telephone +1 [281] 228-6200).

Approved 2006-12-01 NACE International 1440 South Creek Drive Houston, TX 77084-4906 +1 281/228-6200 ISBN 1-57590-208-7 ©2006, NACE International

SP0106-2006

________________________________________________________________________ Foreword The purpose of this NACE standard practice is to describe procedures and practices for achieving effective control of internal corrosion in steel pipe and piping systems in crude oil, refined products, and gas service. Because of the complex nature and interaction between constituents that are found in gas and liquid (e.g., oxygen, carbon dioxide, hydrogen sulfide, chloride, bacteria, etc.), certain combinations of these impurities being transported in the pipeline may affect whether a corrosive condition exists. Identification of corrosive gas and liquid in a pipeline can only be achieved by analysis of operating conditions, impurity content, physical monitoring, or other considerations. Therefore, gas, liquids, and operating conditions must be monitored and evaluated on an individual basis in order to accurately assess the effects of their presence or absence in the pipeline. This standard presents general practices and preferences in regard to control of internal corrosion in steel piping systems. This standard is intended for use by pipeline operators, pipeline service providers, government agencies, and any other persons or companies involved in planning, designing, or managing pipeline integrity. This standard was prepared by Task Group (TG) 038 on Control of Internal Corrosion in Steel Pipelines and Piping Systems. TG 038 is administered by Specific Technology Group (STG) 35 on Pipeline, Tanks, and Well Casings. This standard is issued by NACE International under the auspices of STG 35.

In NACE standards, the terms shall, must, should, and may are used in accordance with the th definitions of these terms in the NACE Publications Style Manual, 4 ed., Paragraph 7.4.1.9. Shall and must are used to state mandatory requirements. The term should is used to state something good and is recommended but is not mandatory. The term may is used to state something considered optional.

________________________________________________________________________

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SP0106-2006

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NACE International Standard Practice Control of Internal Corrosion in Steel Pipelines and Piping Systems Contents 1. General.......................................................................................................................... 1 2. Definitions...................................................................................................................... 1 3. Structure Design ........................................................................................................... 2 4. Corrosion Detection and Measurement ........................................................................ 4 5. Methods for Controlling Corrosion ................................................................................ 5 6. Evaluating the Effectiveness of Corrosion Control Methods ......................................... 7 7. Operation and Maintenance of Internal Corrosion Control Systems............................. 7 8. Corrosion Control Records............................................................................................ 9 References.......................................................................................................................... 9 Appendix A: Typical Gas Quality Specification (Nonmandatory) ..................................... 11 Appendix B: Publications Providing Information Necessary for Determining the Quantity of Impurities (Nonmandatory)...................................................................................... 12 Appendix C: Impacts of Common Impurities (Nonmandatory) ........................................ 13 ________________________________________________________________________

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SP0106-2006 ________________________________________________________________________ Section 1: General 1.1 This standard presents recommended practices for the control of internal corrosion in steel pipelines and piping systems used to gather, transport, or distribute crude oil, petroleum products, or gas. 1.2 This standard serves as a guide for establishing minimum requirements for control of internal corrosion in the following systems: (a) Crude oil gathering and flow lines (b) Crude oil transmission (c) Hydrocarbon products (d) Gas gathering and flow lines (e) Gas transmission (f)

Gas distribution

(g) Storage systems 1.3 This standard does not designate practices for every specific situation because the complexity of pipeline inputs and configurations precludes standardizing all internal corrosion control practices. 1.4 The provisions of this standard should be applied under the direction of competent persons who, by reason of knowledge of the physical sciences and the principles of engineering and mathematics acquired by education or related practical experience, are qualified to engage in the practice of corrosion control and risk assessment on carbon steel piping systems. Such persons may be registered professional engineers or persons recognized as corrosion specialists by organizations such as NACE, or engineers or technicians with suitable levels of experience, if their professional activities include internal corrosion control of buried carbon steel piping systems.

________________________________________________________________________ Section 2: Definitions Coating: A liquid, liquefiable, or mastic composition that, after application to a surface, is converted into a solid protective, decorative, or functional adherent film. Corrosion: The deterioration of a material, usually a metal, that results from a reaction with its environment. Corrosion Inhibitor: A chemical substance or combination of substances that, when present in the environment, prevents or reduces corrosion. Erosion-Corrosion: A conjoint action involving corrosion and erosion in the presence of a moving corrosive fluid or a material moving through the fluid, leading to accelerated loss of material. Gas or Liquid: The material being transported through a pipeline. Holiday: A discontinuity in a protective coating that exposes unprotected surface to the environment.

waters contain naturally occurring dissolved iron. This iron is detected when running iron counts in production systems can be mistaken for iron produced by corrosion. The presence of iron in produced water must be viewed along with the other indicators of corrosion to determine whether iron count values are significant. The probable occurrence of corrosion should always be confirmed by equipment inspection, downhole caliper surveys, and review of failure records before parameters for using iron counts as an indicator of corrosion are established. Manganese Count: The concentration of manganese in iron alloys used in oilfield downhole equipment is typically 0.5 to 1.5%. Therefore, the supposition is that the ratio of manganese to iron in produced water should be about 1:100 if all the iron and manganese result from corrosion and no precipitation has occurred from the water. Pigging: The operation of transporting a device or combination of devices (scraper, sphere, or flexible or rigid plastic) through a pipeline for the purpose of cleaning, chemical application, inspection, or measurement.

Iron Count: The quantity of iron, usually expressed in parts per million or milligrams per liter, contained in a sample of the liquid that may be indicative of corrosive activity within the equipment that contained the liquid. Some produced

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SP0106-2006 ________________________________________________________________________ Section 3: Structure Design 3.1 Introduction 3.1.1 The purpose of this section is to provide design considerations that apply to pipelines made of steel used to transport natural and manufactured gas, crude oil, and refined products for the control of internal corrosion. A corrosion specialist should be consulted during pipeline design and construction. 3.2 Pipeline Design 3.2.1 Gas or Liquid Quality Quality specifications for gas or liquids transported are individually negotiated in contracts between purchasers or pipeline companies and processors/producers. The specification limits can range over wide limits, depending on climatological conditions, end use, and 1 other factors. The amount of each of the components in the gas or liquid stream can significantly affect measurement, operation, pipeline efficiency, and potentially corrosion. Gas or liquid quality standards are set, in part, to minimize internal corrosion. However, gas or liquid corrosiveness cannot be determined from these standards alone. Industry experience has shown that water and corrosive impurities can unintentionally enter the pipeline due to operational upsets, or accumulate in low spots despite gas or liquid quality monitoring that shows adherence to quality standards. Because of the complex nature and interaction between constituents that are found in gas or liquid (e.g., oxygen, carbon dioxide, hydrogen sulfide, chloride, bacteria, etc.), certain combinations of these impurities being transported in the pipeline may affect whether a corrosive condition exists. Identification of corrosive gas or liquid in a pipeline is achieved by analysis of operating conditions, impurity content, monitoring data, mitigation schemes, and other considerations. For companies that use many different quality specifications—typically gas and condensate—quality specifications are listed in Appendix A (nonmandatory). Appendix A is described as a typical gas and condensate quality specification. 3.2.1.1 The quality of the gas or liquid to be transported should be determined. Examples of impurities from a corrosion standpoint are: (a) Bacteria (b) Carbon dioxide (CO2) (c) Chloride (Cl)

2

(d) Hydrogen sulfide (H2S) (e) Organic acids (f)

Oxygen (O2)

(g) Solids or precipitates (h) Sulfur-bearing compounds (i)

Water (H2O)

See Appendix B (nonmandatory) for a list of standards and other publications that provide information on how to determine the quantity of impurity present. 3.2.1.2 Knowledge of the impurity content and gas or liquid composition allows predictions of the magnitude of harmful effects that might result from their presence. See Appendix C (nonmandatory), “Impacts of Common Impurities.” Principal harmful effects that should be considered are: 3.2.1.2.1 Physical deterioration of the pipe as a result of thinning, pitting, hydrogen blistering, hydrogen embrittlement, or stress corrosion cracking (SCC). 3.2.1.2.2 Contamination of gas or liquid by corrosion product. 3.2.1.3 If the specified quality of the gas or liquid is such that transportation will result in harmful corrosion of the pipeline system, coordination should be established with the supplier to provide for additional treatment that may reduce the gas or liquid corrosiveness. 3.2.1.4 The designer should consider the cost of additional treatment to reduce corrosiveness of the gas or liquid in relation to the cost of other corrosion mitigation methods such as increased pigging, use of corrosion inhibitors, internal coating of the pipeline, or a combination of these methods. 3.2.1.5 Satisfactory performance of the design requires that the specified quality be maintained and that internal corrosion of the pipeline is minimal. 3.2.2 Flow Velocity 3.2.2.1 Design consideration shall be given to control of flow velocity within a range that minimizes corrosion. The lower limit of the flow velocity range should be that velocity that will keep impurities suspended in the gas or liquids, thereby

NACE International

SP0106-2006 minimizing accumulation of corrosive matter within 2 the pipeline. The upper limit of the velocity range shall be such that erosion-corrosion, cavitation, or (1) impingement attacks are minimal. API 14E includes a section for calculation of erosional 3 velocity in gas/liquid two-phase lines. 3.2.3 Intermittent Flow 3.2.3.1 Intermittent flow conditions should be avoided when possible. If operating criteria dictate the need for intermittent flow, design consideration should be given to obtaining an operating velocity that will pick up and sweep away water or sediment that accumulates in lower places in the line during periods of no flow or low flow. 3.2.3.2 If water, sediment, or other corrosive contaminants are expected to accumulate in the pipeline, pigs should be used to clean the line. The design should include pig loading and receiving traps. Operating procedures for adequate cleaning shall be developed and implemented. 3.2.4 Line Size Changes 3.2.4.1 Changes in line size diameter should be designed to provide a smooth hydraulic transition, thereby eliminating pockets of altered flow velocity, where corrosive contaminants can collect. 3.2.4.2 Dead ends associated with blind flanges, stubs, laterals, or tie-ins shall be avoided in design. If they are necessary, blow-offs, traps, or drains shall be included in the design so that all accumulated contaminants, including sand, can be periodically removed. 3.2.5 Dehydration and Dewpoint Control 3.2.5.1 If there is no water present on a steel surface, no corrosion should occur, even in the presence of corrosive gases (H2S, CO2, and O2). Hygroscopic salt deposits on the steel surface can cause the formation of an invisible water film on the surface below dewpoint conditions that can cause corrosive attack. When the presence of water in a gas or liquid could cause harmful corrosion during transportation in the pipeline, dehydration should be considered. Dehydration to reduce the dewpoint is often the only measure needed for corrosion control in gas pipelines. The line should be monitored using probes or coupons to detect the presence of corrosive attack (see Paragraph 4.3). If reductions of the water content alone will not control the expected corrosion, other mitigation methods—such as pigging, internal coating, and chemical inhibition—may be used in ___________________________ (1)

conjunction with dehydration to provide adequate corrosion control. 3.2.6 Deaeration 3.2.6.1 The pipeline system should be designed to eliminate any air entry. The presence of oxygen in a gas or liquid can cause corrosion during transportation in the pipeline. Deaeration of gas or liquid to reduce its oxygen content to an acceptable level shall be considered (see Paragraph 5.3.2). If removal or reduction of oxygen alone does not control the corrosion, other mitigation methods such as use of corrosion inhibitor or internal coatings (see Paragraph 5.5) may be used in conjunction with deaeration to provide adequate corrosion control. 3.2.7 Chemicals 3.2.7.1 When the addition of chemicals such as corrosion inhibitors, oxygen scavengers, or biocides are used to mitigate corrosion, design shall include facilities adequate for treatment of the pipeline or facility (see Paragraph 5.4). 3.2.7.2 The following information chemical used shall be on hand:

for

each

(a) Material safety data sheet (MSDS), (b) Technical data sheet, and (c) Data on corrosiveness of the chemical toward materials of construction and sealing materials. 3.2.8 Internal Coatings 3.2.8.1 When a corrosion problem is anticipated, internal coatings may be considered (see Paragraph 5.5). In some cases, such applications leave the circumferential weld area bare. Additional corrosion mitigation methods such as chemical inhibitors should be used for protection of these areas, as well as bare areas resulting from coating holidays. 3.2.9 Monitoring Facilities 3.2.9.1 In design of pipelines handling corrosive commodities, and especially when chemicals will be used for purposes of corrosion control, strategically located corrosion monitoring facilities should be installed for determining gas or liquid corrosiveness and evaluating effectiveness of 4,5 corrosion mitigation methods. Monitoring facilities may include pipe spools, gas or liquid perturbation methods (field signature), or hydrogen probes. Details of various monitoring methods are

American Petroleum Institute (API), 1220 L St. NW, Washington, DC 20005.

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SP0106-2006 samplers, weight loss corrosion coupons, corrosion rate measuring probes, potential 6 presented in NACE Publication 3T199. Designs may include provisions for monitoring corrosion through the use of in-line inspection (ILI) tools, and the pipeline should be designed to permit free passage of these ILI tools. Design features that should be considered include pipeline bends, 7 valves, and traps. See NACE Standard RP0102 for information on design considerations.

3.2.9.2 Differences in pressure, temperature, and the concentration of water and other corrosives between the monitoring location and other locations of interest in the pipeline must be considered in locating monitoring facilities and evaluating their results. In-line filters should be installed in front of pressure control and measurement equipment to protect them from solid particles transported in the gas or liquid.

________________________________________________________________________ Section 4: Corrosion Detection and Measurement 4.1 Introduction 4.1.1 This section describes methods of determining the presence of internal corrosion in piping systems, the degree to which it has progressed, and the cause of the corrosive condition. 4.1.2 For pipelines that normally carry dry products but may suffer from short-term upsets of liquid water (or other electrolyte), internal corrosion is most likely to occur where water accumulates (e.g., at the bottom of inclines). Predicting locations of water accumulation may serve as a method for targeting local examinations 8 (e.g., inspection, monitoring, and sampling). 4.2 Visual Inspection 4.2.1 If a piping system is opened to allow visual access to the inside of the system, observations shall be conducted by qualified personnel to determine the following: 4.2.1.1 Evidence of corrosion on internal pipe surfaces. Types of damage should be identified (e.g., etching, pitting, and elongation of attack) to characterize the type of corrosion. 4.2.1.2 Measurement of wall thickness in the most deeply corroded areas if corrosion damage does exist. 4.2.1.3 Circumferential and longitudinal extent of corrosion on the pipe surface or any discernible pattern of attack. 4.2.1.4 Position of attack with respect to the horizontal at the corroded section and with respect to the elevation of adjacent pipe sections. 4.2.1.5 Existence of deposits and corrosion under the deposits. A sample of the deposit shall be obtained for analysis.

4.3 Coupons and Probes (see also Paragraph 6.2) 4.3.1 The use of properly located coupons and probes can be an effective method for determining the existence, rate, and type of internal corrosion. Procedures for preparing, installing, and analyzing metallic corrosion coupons or other monitoring devices 4 (2) can be found in NACE Standard RP0775 and ASTM 9 G 1. 4.3.1.1 Coupons and probes are installed in the gas or liquid to simulate the internal surface exposed. 4.3.1.2 The exposure time for coupons and probes in the stream is based on the type of gas or liquid, velocity of its flow, objective of the survey, and the expected corrosion rates. Part 192-477 of the U.S. Code of Federal Regulations, Title 49 states, “If corrosive gas is being transported, coupons or other suitable means must be used to determine the effectiveness of the steps taken to minimize internal corrosion. Each coupon or other means of monitoring internal corrosion must be checked two times each calendar year, but with intervals not exceeding seven and a half 10 months.” 4.3.1.3 Coupon or probe results may be more difficult to interpret when coupons or probes are installed in systems in which the gas or liquid contains sufficient amounts of paraffin or other insoluble materials that may deposit on the coupon. 4.3.1.4 Coupons or probes using various 6 techniques (NACE Publication 3T199 ) of operation and installation are used for periodic and continuous results. 4.3.1.5 Intrusive coupons or probes prevent pigging of a pipeline segment.

would

___________________________ (2)

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ASTM International (ASTM), 100 Barr Harbor Dr., West Conshohocken, PA 19428-2959.

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SP0106-2006 4.4.1.5 The frequency and comprehensiveness of chemical analysis of any gas or liquid should be determined by the variations and quantities of the gases or liquids in the pipeline system.

4.4 Sampling and Chemical Analysis 4.4.1 Representative samples should be taken when they can be used to determine the iron count, manganese count, pH, and concentrations of significant corrosive constituents in the gas or liquid and for performance tests. 4.4.1.1 Samples shall be taken only by experienced personnel or by those who have been instructed in the proper procedures.

4.5 ILI Tools 4.5.1 ILI tools may be employed for detecting 7 corrosion damage. Refer to NACE Standard RP0102 for information on these tools. 4.5.1.1 Correlation between corrosion indications on the log and actual distances on the ground is vital to enable exact determination of corrosion sites.

4.4.1.2 Clean valves, spigots, containers, and sampling environment are necessary for taking dependable samples. 4.4.1.3 If liquid water is present in the system, analyses may be made for CO2, H2S, bacteria, 11,12 acids, and other corrosive constituents. Analysis of CO2 and H2S should be made in the gaseous phase. See Appendix B for methods of analysis for each of the preceding. 4.4.1.4 Analyses to determine other undesirable compounds in the gas or liquid, such as those that cause scaling and plugging, may be made periodically.

4.5.1.2 Verification is necessary to confirm the accuracy of the inspection. 4.6 Pressure Drop Measurements 4.6.1 Changes in pressure drop measurements across a given segment of a pipeline can be indications of corrosion or deposit accumulations and shall be investigated.

________________________________________________________________________ Section 5: Methods for Controlling Internal Corrosion formation of local corrosion cells on the pipe's bottom quadrant, especially in conjunction with conditions in Paragraph 5.2.1.1.

5.1 Introduction 5.1.1 This section describes accepted practices for the control of internal corrosion in steel pipelines and piping systems. 5.1.2 If past experience has shown that the products being transported, particularly in distribution piping, are not corrosive to the system, some or all of these considerations may be rejected. 5.2 Line Cleaning 5.2.1 Cleaning pigs are used to improve and maintain internal pipe cleanliness by removing contaminants and deposits within the pipe. Periodic line cleaning with pigs can be used in conjunction with other corrosion mitigation measures such as chemical inhibition or dehydration. Some corrosive situations that can be remedied at least in part by pigging include: 5.2.1.1 Water and other fluids that settle out of the transported gas or liquid due to insufficient flow velocity for entrainment, intermittent flow, or pressure/temperature-related solubility changes. These fluids can contain oxygen, H2S, CO2, salts, acids, and other corrosives. 5.2.1.2 Loose sediment, including corrosion products, scale, sand, and dirt, that may promote

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5.2.1.3 Corrosion products, wax, or other solid deposits adhering to the pipe wall that can shield actively corroding areas, thereby limiting effectiveness of other corrosion mitigation measures, such as chemical inhibition. 5.2.2 A variety of pig designs with differing degrees of line cleaning capability are available. Some have spring-loaded steel knives, wire brushes, or abrasive grit surfaces for removal of adhering contaminants. Others are semi-rigid, nonmetallic spheres. In addition, flexible foam pigs can traverse line pipe of different sizes and can pass through short radius bends. 5.2.3 The choice of pig type depends on the following: (a)

Ability of pig to remove contaminants present

(b)

Ability to traverse pipe segment

(c) Compatibility of materials of construction with gas or liquid (d) Feasibility of its use from an operations standpoint. Possible problems may exist when a pig is run in a line that has any quill, probe, coupon, or

5

SP0106-2006 anything that protrudes into the line that could interfere with the pig. (e) Presence of corrosion inhibitor films or plastic coatings 5.3 Removal of Corrosive Constituents from the Gas or Liquid 5.3.1 Dehydration of the gas or liquid being transported can be used when water is present in amounts sufficient to cause corrosion problems. 5.3.1.1 Free water associated with crude oil and products may be removed by settling out at storage locations or by using water separators, coalescers, or sand filters. 5.3.1.2 Water associated with gas can be removed at various locations in the system by water separators, refrigeration, or dehydrators of various types (glycol or dry desiccant). Dewpoint control can be used to prevent the formation of free water in the system. 5.3.2 Deaeration can be used to remove oxygen in the commodity. In conjunction with deaeration, the entire pipeline system should be searched for points at which air may enter or otherwise contact the liquid. Careful equipment design is important to ensure that air does not enter the system. 5.3.2.1 Oxygen-scavenging chemicals such as alkaline sulfites or vacuum deaeration can be used to lower the oxygen content of the commodity to 13,14 suitable levels. Effectiveness of oxygenscavenging chemicals is often limited in the presence of H2S. 5.3.3 Other corrosive constituents, such as acid gases (H2S, CO2, and low-molecular-weight organic acids, e.g., acetic and propionic acids) can be removed from the gas or liquid by acid gas strippers and scrubbers. 5.4 Corrosion Inhibition 5.4.1 Addition of corrosion inhibitors should be considered a corrosion mitigation measure when corrosive gases or liquids are transported. 5.4.2 Numerous types and formulations of corrosion inhibitors—each with various chemical, physical, and handling characteristics—are commercially available. A corrosion inhibitor package contains one or more inhibitors, surfactants, and solvents. The inhibitor can 15,16 be classified as anodic, cathodic, or both. Inhibitors containing phosphorous (e.g., phosphate esters or phosphonates) are anionic and used to mitigate corrosiveness of low ppm levels of oxygen. Cationic inhibitors containing nitrogen and carrying a positive charge (e.g., amine-containing compounds) are used to mitigate H2S and CO2 corrosion. Nitrogen-

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containing compounds with long carbon chains (e.g., imidazolines) can act as a cathodic and anodic inhibitor. The inhibitor should be soluble in the liquid being transported to ensure the inhibitor can get to the area where it is needed. In predominantly dry gas systems, the inhibitor should be applied as a batch treatment between two pigs. 5.4.3 Of foremost importance in choosing a corrosion inhibitor is a firm understanding of the corrosion problem and its cause. The choice further depends on compatibility with the gas or liquid and other additives, ease of handling and injection, and possible adverse effects on downstream processes. 5.4.4 Laboratory tests, field tests, industry experience, and inhibitor manufacturer's recommendations can be useful for screening inhibitors as to their effectiveness, degree of solubility, compatibility, or required injection 17,18,19,20,21 rates. 5.4.5 To increase inhibitor effectiveness, consideration should be given to the use of other corrosion mitigation procedures, such as line cleaning or dehydration, in conjunction with the inhibition program. 5.5 Internal Coating or Lining 5.5.1 Internal coating of pipelines should be considered as an internal corrosion control measure. Internal coatings should also be considered for selected areas, such as in-station manifold piping or small-diameter gathering lines, where it is not feasible or economical to use other corrosion control measures. 5.5.2 The coating should have suitable resistance to attack by the gas or liquid being transported, as well as by any contaminants, corrosives, or additives contained in it. The quality of the transported gas or liquid should not be compromised. 5.5.3 Coatings and linings such as epoxies, cement or concrete, plastics, or metallic compounds can be used for selected applications. 5.5.4 Internal coating can be accomplished joint-byjoint at a coating plant, or by coating entire line segments in place. Regardless of where coating takes place, coating performance is dependent on suitable pipe cleaning and surface preparation as well as use of 22,23 proper application procedures. 5.5.5 Plant-applied internal coatings can be electrically inspected; however, verification of in-place coating integrity is not usually feasible. Spot checks by cutting coupons or removing test spools are often used for this 24 purpose. When a holiday-free coating cannot be guaranteed and aggressive corrosive service is anticipated, additional corrosion mitigation measures, such as chemical inhibition, may be required to control internal corrosion adequately.

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SP0106-2006 ________________________________________________________________________ Section 6: Evaluating the Effectiveness of Corrosion Control Methods 6.1 Introduction 6.1.1 This section recommends multiple techniques to be used to evaluate the effectiveness of corrosion control methods in a pipeline system. Some of the methods used to evaluate the effectiveness of corrosion control measures may be the same methods used for corrosion detection (see Section 4). 6.2 Coupons and Probes (see also Paragraphs 4.3 and 3.3.9.1) 6.2.1 Coupons and probes can be used to determine the effectiveness of corrosion control methods employed. 6.2.2 Coupons and probes should be positioned at points within the system to provide meaningful corrosion-related measurements. 6.2.3 Coupons and probes that are used should provide representative and reproducible measurements for the particular application. 6.2.4 Coupon or probe results can be useful for determining time-related changes in corrosive conditions. The results can be used to identify changes in the corrosiveness of gas or liquid due to changes in operating parameters or chemical treatment programs. Procedures for preparing, installing, and analyzing metallic corrosion coupons or other monitoring devices can be found in NACE Standard RP0775.4 6.2.5 The exposure time for coupons and probes is based on the type of gas or liquid, velocity of its flow, and the expected corrosion rates. Part 192-477 of the U.S. Code of Federal Regulations, Title 49 states, “If corrosive gas is being transported, coupons or suitable means must be used to determine the effectiveness of the steps taken to minimize internal corrosion. Each coupon or other means of monitoring internal corrosion

must be checked two times each calendar year, but with intervals not exceeding seven and a half 10 months.” 6.3 Sampling and Chemical Analysis (see also Paragraph 4.4 for additional direction regarding sampling and analysis) 6.3.1 Gas or liquid sampling can be used to determine a change in the corrosive medium being transported in the pipeline system. 6.3.1.1 Gas or liquid sampling performed at regular periods.

should

be

6.4 Visual Inspection (see also Paragraph 4.2) 6.4.1 Visual inspection of solid contaminants may be used to monitor protection effectiveness. 6.4.2 Changes in volume or weight of corrosion products removed from filters and traps can indicate variations in corrosion prevention. 6.5 Physical Methods 6.5.1 Periodic monitoring (magnetic, electronic, ultrasonic, or radiographic) may be helpful on some pipeline systems. 6.5.1.1 Adequate knowledge of the diameter, length, joint type, age, and location of the pipeline system is necessary to determine the appropriate method to be used. 6.5.1.2 Subsequent measurements shall be made at the same location. This does not preclude the incorporation of additional locations where future periodic measurements may be made. 6.5.2 Pressure-drop measurements on the same segment of pipeline can be used to monitor the effectiveness of the corrosion control program.

________________________________________________________________________ Section 7: Operation and Maintenance of Internal Corrosion Control Systems 7.1 Introduction 7.1.1 This section provides practices for operation and maintenance of internal corrosion prevention systems. 7.2 Line Cleaning (see Paragraph 5.2) 7.2.1 Any pig inserted into a pipeline shall be clean and in good repair.

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7.2.2 Pigging frequency should be adequate to remove contaminants before internal pipe damage occurs due to corrosion. 7.2.3 Routine observations of type and amount of contaminants removed shall be made to evaluate efficiency of pigging. Changes in pig type and frequency used shall be made to accomplish desired pipe cleanliness.

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SP0106-2006 7.2.4 Seasonal changes may require a change in pigging frequency or type of pigs used. Lower temperatures during winter months may require removal of water or wax that might result in freezing, plugging, or corrosion problems. 7.3 Inhibitor Treatment or Injection (see also Paragraph 5.4) 7.3.1 Inhibition can usually be accomplished by one of two general methods: batch (intermittent) treatment or continuous injection, or a combination of the two methods. 7.3.1.1 The preferred batch treatment method normally entails pumping a slug of inhibitor solution through the line between two pigs. Frequency of the treatment is governed by the remaining effectiveness of the inhibitor after a specified amount of gas or liquid has been moved through the line. 7.3.1.2 Continuous injection consists of constant addition of a specific proportion of inhibitor to the gas or liquid being transported through the pipeline. 7.3.2 Injection facilities vary in design and operation. In general, the installation includes the following: (a)

Inhibitor storage vessel

(b)

Injector (pump or nozzle)

(c) Measurement device (meter or calibrated sight glass) (d) Flow controller (needle or valve—the control can be built into the injector) (e)

Connection to the pipeline

(f) Associated piping and electrical and control hook-ups 7.3.2.1 Injector designs as simple as gravity feed injectors, as well as the more complex proportioning chemical injection pumps and venturi injectors, can be used successfully. Adjustable-capacity positive-displacement chemical pumps are widely used in liquid pipeline systems. 7.3.2.2 Atomization of inhibitor to produce a fine mist or fog in gas pipelines can be achieved by properly designed injection quill or venturis. The venturi throat should be sized to attain gas movement at the highest practical (sonic) velocity.

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7.3.2.3 Care must be exercised in location of such systems, particularly in distribution piping, so that flow-borne mist will not adversely affect the operations of pilot operated regulatory systems. 7.3.2.4 Materials of construction for the equipment should be suitable for continuous service in contact with the inhibitor. The chemical supplier’s recommended materials of construction should be used. Stainless steel should be considered for small-diameter piping or tubing in which even minor rusting could cause plugging or make pumping of more viscous liquids difficult. When nitrogen-based inhibitors (amines, amides, and nitrites) are handled, copper or copper-based alloys shall be avoided because SCC might result. Nonmetallic seal and packing materials shall be checked for compatibility with the inhibitor formulation. 7.3.3 Points of injection shall be chosen to provide maximum benefit in the pipeline system. Injection on the suction side of pumps takes advantage of pump turbulence to promote mixing of inhibitor with fluid. Injection through a tube into the center of the pipeline also aids mixing. When a venturi is used as an injection device, installation in a smaller-diameter bypass is preferred because gas flow at high velocity can be maintained more easily. 7.3.4 Premixing or dilution of the inhibitor can improve handling and promote more rapid dissolution, especially between immiscible phases. Injection point damage can occur due to low pH of the additive or flashing of solvents leaving a solid deposit. Viscous inhibitors can be diluted with a compatible, miscible hydrocarbon carrier to decrease viscosity, making pumping easier and metering more accurate, especially at low usage rates. Premixing water before injection greatly facilitates mixing of inhibitor with line water. 7.3.5 Premixing and dilution of inhibitor should be performed only if the supplier indicates no adverse impacts on the handling or performance of the inhibitor will result. Impacts can include emulsification, separation, or the formation of solids. 7.4 Internal Coating 7.4.1 If an internally coated pipeline is opened, the coating shall be inspected. Damaged areas shall be suitably repaired, if at all feasible, to maintain overall coating integrity. If coating damage is too widespread or repair is otherwise not feasible, supplemental mitigation measures shall be considered.

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SP0106-2006 _______________________________________________________________________________ Section 8: Corrosion Control Records 8.1 Introduction 8.1.1 This section describes a system of corrosion control records that can be used to document data pertinent to the design, installation, operation, maintenance, and effectiveness of internal corrosion control measures.

8.3 Relative to detecting, controlling, and evaluating corrosion problems and operations maintenance, the following shall be recorded: 8.3.1 Visual inspections by qualified personnel, including a consideration of the elements in Paragraph 4.2 whenever a piping system is opened. 8.3.2 Inspection and tests of probes, coupons, and other monitoring devices such as samples, chemical analysis, bacteria results, and internal inspection tool runs.

8.2 Relative to design considerations, the following shall be recorded: 8.2.1 Analysis of gas or liquid, including impurity content.

8.3.3 In-line inspection and line cleaning pig runs including date, type of pig, and amounts of water and solids removed by locations.

8.2.2 Physical design consideration including pipe size, wall thickness, grade, flow velocity, line size changes, internal coating, and type.

8.3.4 Name and quantity of inhibitor, biocide, and other chemicals used.

8.2.3 Considerations for treatment such as dehydration, deaeration, chemicals, internal coatings, and monitoring facilities.

8.3.5 Leak and failure records.

________________________________________________________________________ References (3)

2. M. Wicks, J.P. Fraser, “Entrainment of Water in Flowing Oil,” Materials Performance 14, 5 (1975): p. 9.

8. O. Moghissi, B. Cookingham, L. Perry, N. Sridhar, “Internal Corrosion Direct Assessment of Gas Transmission Pipelines—Application,” CORROSION/2003, paper no. 03204 (Houston, TX: NACE, 2003).

3. API RP 14E (latest revision), “Recommended Practice for Design and Installation of Offshore Production Platform Piping Systems” (Washington, D.C.: API).

9. ASTM G 1 (latest revision), “Preparing, Cleaning and Evaluating Corrosion Test Specimens” (West Conshohocken, PA: ASTM).

4. NACE Standard RP0775 (latest revision), “Preparation, Installation, Analysis, and Interpretation of Corrosion Coupons in Oilfield Operations” (Houston, TX: NACE).

10. U.S. Code of Federal Regulations (CFR) Title 49, “Internal Corrosion Control; Monitoring,” Part 192.477 (4) (Washington, DC: Office of the Federal Register, 1995).

5. T.G. Braga, R.G. Asperger, “Engineering Considerations for Corrosion Monitoring of Gas Gathering Pipeline Systems,” CORROSION/87, paper no. 48 (Houston, TX: NACE, 1987).

11. ASTM D 3370 (latest revision), “Sampling Water from Closed Conduits” (West Conshohocken, PA).

1.

Engineering Data Book, 11th ed., (Tulsa, OK: GPSA ).

6. NACE Publication 3T199 (latest revision), “Techniques for Monitoring Corrosion Related Parameters in Field Application” (Houston, TX: NACE). 7. NACE Standard RP0102 (latest revision), “In-Line Inspection of Pipelines” (Houston, TX: NACE).

12. ASTM D 4515 (latest revision), “Estimation of Holding Time for Water Samples Containing Organic Constituents” (West Conshohocken, PA: ASTM). 13. B.L. Carlberg, “Vacuum Deareration–A New Unit (5) Operation for Water Flood by Vacuum Deaeration,” SPE (6) AIME Meeting, paper no. SPE-6096 (Richardson, TX: SPE, 1976).

___________________________ (3)

Gas Processors Supplier Association (GPSA), 6526 East 60th St., Tulsa, OK 74145. The National Archives and Records Administration (NARA), 8601 Adelphi Rd., College Park, MD 20740-6001. (5) Society of Petroleum Engineers (SPE), 222 Palisades Creek Dr., Richardson, TX 75080. (6) American Institute of Mining, Metallurgical, and Petroleum Engineers (AIME), Three Park Ave., 17th Floor, New York, NY 10016-5998. (4)

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SP0106-2006 14. NACE Standard RP0278 (withdrawn), “Design and Operation of Stripping Columns for Removal of Oxygen from Water” (Houston, TX: NACE). 15. S. Papavinasam, “Corrosion Inhibitor,” in Uhlig’s nd Corrosion Handbook, 2 ed., R.W. Revie, ed. (New York, NY: John Wiley and Sons Inc., 2000), p. 1089. 16. V.S. Sastri, Corrosion Inhibitors, Principles and Applications (New York, NY: John Wiley and Sons, 1998). 17. NACE Publication 5A195 (latest revision), “State-ofthe-Art Report on Controlled-Flow Laboratory Corrosion Test” (Houston, TX: NACE). 18. NACE Publication ID196 (latest revision), “Laboratory Test Methods for Evaluating Oilfield Corrosion Inhibitors” (Houston, TX: NACE). 19. ASTM G 170.01a (latest revision), “Evaluating and Qualifying Oilfield and Refinery Corrosion Inhibitors in the Laboratory” (West Conshocken, PA: ASTM). 20. ASTM G 184 (latest revision), “Standard Practice for Evaluating and Qualifying Oil Field and Corrosion Inhibitors Using Rotating Cage” (West Conshohocken, PA: ASTM). 21. ASTM G 185 (latest revision), “Standard Practice for Evaluating and Qualifying Oil Field and Corrosion Inhibitors Using the Rotating Cylinder Electrode” (West Conshohocken, PA: ASTM).

29. ASTM D 512 (latest revision), “Chloride Iron in Water” (West Conshohocken, PA: ASTM). 30. ASTM D 4658 (latest revision), “Standard Test Method for Sulfide Ion in Water” (West Conshohocken, PA: ASTM). 31. ASTM D 4810 (latest revision), “Standard Test Method for Hydrogen Sulfide in Natural Gas Using Length-of-Stain Detector Tubes” (West Conshohocken, PA: ASTM). 32. B. Hedges, L. McVeigh, “The Role of Acetate in CO2 Corrosion: The Double Whammy,” CORROSION/99, paper no. 21 (Houston, TX: NACE, 1999). 33. J. Crolet, N. Thevenot, A. Dugstad, “Role of Free Acetic Acid on the CO2 Corrosion of Steels,” CORROSION/99, paper no. 24 (Houston, TX: NACE, 1999). 34. ASTM D 888 (latest revision), “Standard Test Methods for Dissolved Oxygen in Water” (West Conshohocken, PA: ASTM). 35. ASTM D 1796 (latest revision), “Standard Test Method for Water and Sediment in Fuel Oils by the Centrifuge Method (Laboratory Procedure)” (West Conshohocken, PA: ASTM). 36. ASTM D 5907 (latest revision), “Standard Test Method for Filterable and Nonfilterable Matter in Water” (West Conshohocken, PA: ASTM).

22. NACE Standard RP0191 (latest revision), “The Application of Internal Plastic Coatings for Oilfield Tubular Goods and Accessories” (Houston, TX: NACE).

37. ASTM D 5504 (latest revision), “Standard Test Method for Determination of Sulfur Compounds in Natural Gas and Gaseous Fuels by Gas Chromatography and Chemiluminescence” (West Conshohocken, PA: ASTM).

23. NACE Standard RP0291 (latest revision), “Care, Handling, and Installation of Internally Plastic-Coated Oilfield Tubular Goods and Accessories” (Houston, TX: NACE).

38. ASTM D 3227 (latest revision), “Standard Test Method for (Thiol Mercaptan) Sulfur in Gasoline, Kerosene, Aviation Turbine, and Distillate Fuels (Potentiometric Method)” (West Conshohocken, PA: ASTM).

24. NACE Standard TM0186 (latest revision), “Holiday Detection of Internal Tubular Coatings of 250 to 760 µm (10 to 30 mils) Dry-Film Thickness” (Houston, TX: NACE).

39. ASTM D 6304 (latest revision), “Standard Test Method for Determination of Water in Petroleum Products, Lubricating Oils, and Additives by Coulometric Karl Fisher Titration” (West Conshohocken, PA: ASTM).

25. API 2544 (latest revision), “Method of Test for API Gravity of Crude Petroleum and Petroleum Products— Hydrometer Method” (Washington, DC: API).

40. H. Byars, Corrosion Control in Petroleum Production, 2nd ed. (Houston, TX: NACE, 1999).

26. NACE Standard TM0194 (latest revision), “Field Monitoring of Bacterial Growth in Oilfield Systems” (Houston, TX: NACE).

41. C. de Waard, U. Lotz, “Prediction of CO2 Corrosion of Carbon Steel,” CORROSION/93, paper no. 69 (Houston, TX: NACE, 1993).

27. ASTM D 1945 (latest revision), “Standard Test Method for Analysis of Natural Gas by Gas Chromatography” (West Conshohocken, PA: ASTM).

42. C. de Waard, U. Lotz, A. Dugstad, “Influence of Liquid Flow Velocity on CO2 Corrosion—A Semi-Empirical Model,” CORROSION/95, paper no. 128 (Houston, TX: NACE, 1995).

28. ASTM D 513 (latest revision), “Standard Test Method for Total and Dissolved Carbon Dioxide in Water” (West Conshohocken, PA: ASTM).

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43. A. Anderko, R.D. Young, “A Model for Calculating Rates of General Corrosion of Carbon Steel and 13% Cr Stainless Steel in CO2/H2S Environments,”

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SP0106-2006 CORROSION/2001, paper no. 86 (Houston, TX: NACE, 2001). 44. S. Nesic, M. Nordsveen, R. Nyborg, A. Strangeland, “A Mechanistic Model for CO2 Corrosion with Protective Iron Carbonate Films,” CORROSION/2001, paper no. 40 (Houston, TX: NACE, 2001). 45. NACE MR0175/ISO 15156 (latest revision), “Petroleum and natural gas industries—Materials for use in H2Scontaining environments in oil and gas production” (Houston, TX: NACE).

46. A.K. Dunlop, “Stress Corrosion Cracking of Low Strength, Low Alloy Nickel Steels in Sulfide Environments,” Corrosion 34, 88 (1978): p. 88. 47. L.W. Jones, Corrosion and Water Technology (Tulsa, (7) OK: OGCI, 1992), p. 20. 48. R.A. Pisigan Jr, J.E. Singley, “Evaluation of Water Corrosivity Using the Langelier Index and Relative Corrosion Rate Models,” Materials Performance 24, 4 (1985): p. 26.

________________________________________________________________________ Appendix A: Typical Gas Quality Specification (Nonmandatory) Oxygen: The oxygen content shall not exceed 0.1 vol% of the gas, and the parties shall make reasonable efforts to maintain the gas or liquid free from oxygen. Hydrogen sulfide (H2S): The H2S content shall not exceed 3 3 5.7 mg/m (0.25 grains/100 ft ). 3

3

3

3

Temperature: The gas shall not be delivered at a temperature of less than 4.4°C (40°F), and not more than 49°C (120°F). Nitrogen: The nitrogen content shall not exceed 3 vol% of the gas.

NOTE: 1 grain/100 ft = 22.88 mg/m . Mercaptans: The gas shall not contain more than 5.7 3 3 mg/m (0.25 grains/100 ft ) of gas. Total sulfur: The total sulfur content, including mercaptans 3 3 and H2S, shall not exceed 46 mglm (2 grains/100 ft ). Carbon dioxide (CO2): The CO2 content shall not exceed 2 vol.% of the gas. Liquids: The gas shall be free of water and other objectionable liquids at the temperature and pressure at which the gas is delivered, and the gas shall not contain any hydrocarbons that might condense to free liquids in the pipeline under normal conditions and shall, in no event, 3 contain water vapor in excess of 112 kg/million (7 lb/million 3 ft ). 3

3

36 MJ/m (975 BTU/ft ) and not more than 44 MJ/m (1,175 3 BTU/ft ) on a dry basis.

3

NOTE: 1 lb/million ft = 16 kg/million m . Dust/gums/solid matter: The gas shall be commercially free of dust, gum-forming constituents, and other solid matter.

Hydrogen: The gas shall contain no carbon monoxide, halogens, or unsaturated hydrocarbon and no more than 400 ppm of hydrogen in the gas. Isopentane and Heavier: The gas shall not contain more 3 3 than 27 L/1,000 m (0.2 gal/1,000 ft ) of isopentane or heavier hydrocarbons. 3

3

NOTE: 1 gal/1,000 ft = 134 L/1,000 m . Condensate quality specification: Sulfur content: condensate.

Less than 0.05% by weight of the

Asphaltenes:

Trace

API gravity:

Minimum 35° API 25

B.S.&W. (The quanity of “basic sediment and water” contained in a liquid) and other impurities: Less than 0.5% of the condensate.

Heating value: The gas delivered shall contain a daily, monthly, or yearly average heating content of not less than

___________________________ (7)

Oil & Gas Consultants International (OGCI), 2930 S. Yale, Tulsa, OK 74114.

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SP0106-2006 ________________________________________________________________________ Appendix B: Publications Providing Information Necessary for Determining the Quantity of Impurities (Nonmandatory) (a)

Bacteria

NACE Standard TM0194 (latest revision), “Field Monitoring of Bacterial Growth in Oilfield 26 Systems”

(b)

CO2

ASTM D 1945 (latest revision), “Standard Test Method for Analysis of Natural Gas by Gas 27 Chromatography” ASTM D 513 (latest revision), “Standard Test Methods for Total and Dissolved Carbon 28 Dioxide in Water”

(c)

Chloride

ASTM D 512 (latest revision), “Standard Test Methods for Chloride Ion in Water”

(d)

H2S

ASTM D 4658 (latest revision), “Standard Test Method for Sulfide Ion in Water”

29

30

ASTM D 4810 (latest revision), “Standard Test Method for Hydrogen Sulfide in Natural Gas 31 Using Length-of-Stain Detector Tubes” ASTM D 1945 (latest revision), “Standard Test Method for Analysis of Natural Gas by Gas 27 Chromatography” (e)

Organic acids

B. Hedges, L. McVeigh, “The Role of Acetate in CO2 Corrosion: The Double Whammy,” 32 CORROSION/99, paper no. 21 J. Crolet, N. Thevenot, A. Dugstad, “Role of Free Acetic Acid on the CO2 Corrosion of 33 Steels,” CORROSION/99, paper no. 24

(f)

Oxygen

ASTM D 888 (latest revision), “Standard Test Methods for Dissolved Oxygen in Water”

34

ASTM D 1945 (latest revision), “Standard Test Method for Analysis of Natural Gas by Gas 27 Chromatography” (g)

Solids or precipitates

ASTM D 1796 (latest revision), “Standard Test Method for Water and Sediment in Fuel Oils 35 by Centrifuge Method (Laboratory Procedure)” ASTM D 5907 (latest revision), “Filterable and Non-Filterable Matter in Water”

(h)

Sulfur-bearing compound

36

ASTM D 5504 (latest revision), “Standard Test Method for Determination of Sulfur Compounds in Natural Gas and Gaseous Fuels by Gas Chromatography and 37 Chemiluminescence” ASTM D 3227 (latest revision), “Standard Test Method for (Thiol Mercaptan) Sulfur in 38 Gasoline, Kerosene, Aviation Turbine, and Distillate Fuels (Potentiometric Method)”

(i)

Water

ASTM D 6304 (latest revision), “Standard Test Method for Determination of Water in 39 Petroleum Products, Lubricating Oils, and Additives by Coulometric Karl Fisher Titration” ASTM D 1796 (latest revision), “Standard Test Method for Water and Sediment in Fuel Oils 35 by Centrifuge Method (Laboratory Procedure)”

12

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SP0106-2006 ________________________________________________________________________ Appendix C: Impacts of Common Impurities (Nonmandatory) (a)

Bacteria

Microbes commonly found in oil and gas systems are sulfate-reducing bacteria (SRB) and acid-producing bacteria (APB). Some of the bacteria are planktonic, free floating in the liquids; others are sessile and are attached to the surfaces in the system. Samples of the liquids indicate the presence of the planktonic bacteria; however, their presence does not necessarily indicate that microbiologically influenced corrosion (MIC) has or will occur. Coupons placed in the system must be used for detection of the sessile bacteria. See 26 NACE Standard TM0194 for details on monitoring to determine the presence, location, and severity of bacterial contamination. See chemical vendor for biocide recommendation and treatment concentration level.

(b)

CO2

If no liquid water is present, carbon dioxide (CO2) is noncorrosive. In the presence of liquid water, the partial pressure of CO2 (mole percent of CO2 × system pressure in kPa [psi]) is used as a guideline to determine the corrosiveness of CO2. See Corrosion Control in 40 Petroleum Production. 1. A partial pressure of CO2 above 207 kPa (30 psi) is usually corrosive in the presence of water. 2. A partial pressure of CO2 between 21 kPa (3 psi) and 207 kPa (30 psi) may be corrosive in the presence of water. 3. A partial pressure of CO2 below 21 kPa (3 psi) is generally considered noncorrosive. Caution should be used with the above guidelines in the presence of low molecular weight organic acids (acetic, propionic, etc.) or H2S that will interfere. A large number of predicative models have been developed for CO2 corrosion. The rate of 41,42 CO2 can be calculated using the deWaard, et.al. model. The corrosion rate is calculated using the partial pressure of CO2, temperature, and pressure of the system. Corrosion 43 44 models by A. Anderko, et al. and S. Nesic, et al. take organic acids into account.

(c)

Chloride

Steel must have a conductive solution on its surface to form a cell for corrosive attack to occur. The addition of salts containing chloride, commonly found in gas and oil production, increases the conductivity and corrosiveness of water, resulting in pitting or general corrosion. Chloride stress corrosion cracking (SCC) results from the interaction of chloride and mechanical tensile stresses. UNS S30400 cracks in the presence of parts per million (ppm) 40 chloride. Pages 21-22 of Corrosion Control in Petroleum Production include a table listing the susceptibility of metal to SCC.

(d)

H2S

H2S is very soluble in water. It is 200 times more soluble than oxygen and 3 times more soluble than CO2 in water at atmospheric pressure and temperature. H2S corrodes steel forming various forms of iron sulfide, which result in pitting corrosion. Hydrogen blistering may occur in some steels in the presence of H2S. Hydrogen atoms are sufficiently small to allow entry into and migration within the steel structural lattice. Some of the hydrogen atoms enter structural defects within the steel, such as voids, where they quickly react with other hydrogen atoms to form molecular hydrogen. This molecular hydrogen occupies a greater space and can no longer migrate through steel. Trapped hydrogen gas exerts pressure and can cause blister formation within the steel. If the blisters are sufficiently large, they can be detected by external deformation of the steel surface. Hydrogen gas trapped within higher-strength steels can lead to stepwise cracking (also called hydrogen-induced cracking [HIC]) within the steel. The hydrogen atoms in the metal migrate into a void and form hydrogen gas, eventually developing a blister on the 40 surface of the steel. See pp. 17-18 of Corrosion Control in Petroleum Production.

NACE International

13

SP0106-2006 Sulfide stress cracking (SSC) occurs in high-strength steels exposed to moist H2S conditions. Four conditions are required for SSC to occur. 1.

Presence of H2S

2.

Presence of water—trace amount is sufficient

3.

High-strength materials

4. Steel must be under tensile stress or loading (stress may be residual or applied). Plain carbon steels with strength below 620 MPa (90,000 psi) and Rockwell hardness below 43 73.0 HR 15 or 22 HRC are not affected. See NACE MR0175/ISO 15156 for detailed hardness requirements. Steels with yield strengths above this level are susceptible to cracking. The time to failure increases as the H2S concentration decreases. Cracking can 40,46 occur at 0.1 ppm levels of H2S in water with a very long time to failure. (e) Organic acids

Low-molecular-weight organic acids (acetic, propionic, etc.) can cause severe corrosion 32,33 when present in the gas phase at ppm levels. The presence of low-molecular-weight organic acids, which will partition into the water, are often not detected in the water analysis due to the interference of bicarbonate present in the water.

(f)

If water saturated with air, containing 7 to 8 ppm oxygen, is used to hydrotest a pipeline, little corrosion of the pipeline results. The oxygen immediately interacts with steel and is removed from solution, resulting in very little corrosion loss. However, if a constant supply of water containing oxygen flows through the line, severe pitting of the pipeline results. When large quantities of water flow through steel pipelines, the oxygen content should be 47 less than 1 ppm.

Oxygen

An equation to estimate the corrosion due to oxygen relates the corrosion rate to total 48 dissolved oxygen concentration, mineral saturation index, and exposure time. (g)

14

Water

If liquid water is not present in a steel pipeline, corrosion does not occur. The presence of oxygen, CO2, or H2S in a steel pipeline in the absence of liquid water does not cause 48 corrosion at temperatures below 200°C (390°F). Hygroscopic salt deposits on the steel surface can cause the formation of an invisible water film on the surface below dewpoint conditions, which can cause corrosive attack.

NACE International

NACE International Instructor Evaluation Survey NACE International takes the quality of instruction offered by its instructors seriously. NACE has a policy that requires that all instructors and courses be evaluated by their students, and that the evaluations be considered by the NACE Instructor/Peer and Course Quality Committees. The results of these evaluations are important to provide feedback to instructors on how their performance can be improved and to provide NACE with information to advance and revise it's training programs.

Course Title: ______________________________Date: __________________ Course Code: ______________ Location: ____________________ Instructor:___________________________ Agree (5)

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(2)

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Instructor Evaluation The instructor demonstrated a thorough understanding of the subject matter and showed enthusiasm for the subject matter.

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The instructor presented the material according to the course outline.

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The instructor came to class well prepared and organized. The instructor is a positive representative for NACE INTERNATIONAL. The instructor generally was available to consult with and assist students. The instructor encouraged student participation. The instructor answered my questions to my satisfaction. The instructor's presentation was interesting and kept my attention. The instructor spoke audibly and clearly. The instructor should continue to teach this course for NACE.

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ONLY COURSE ORGANIZERS AT NACE HEADQUARTERS SEE COMPLETED EVALUATION FORM.S

NACE International Evaluation Survey NACE International takes the quality of instruction offered by its instructors seriously. NACE has a policy that requires that all instructors and courses be evaluated by their students, and that the evaluations be considered by the NACE Instructor/Peer and Course Quality Committee. The results of these evaluations are important to provide feedback to instructors on how their performance can be improved and to provide NACE with information to advance and revise it's training programs.

Course Title: ______________________________Date:___________________ Location: ______________________________ Course Code: ___________________ Agree (5)

(4)

Attending this course has improved my knowledge and understanding of the subject matter of this course.

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I found the course to be generally interesting and informative.

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Course Evaluation

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This course was what I expected from its description in NACE Literature.

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This course was a worthwhile use of my time.

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Materials Evaluation I was completely satisfied with the COURSE MANUAL used in this class.

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I was completely satisfied with the DAILY QUIZZES used in this class. I was completely satisfied with the SLIDES/VIDEOS used in this class. I was completely satisfied with the CASE STUDIES used in this class. I was completely satisfied with the CLASS DISCUSSION encountered in this class.

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My Company or division can best be described as: (Please choose one of the following)

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Aerospace Bridges & Highways Chemical Processing/Process Industries Coating & Lining Application Coating & Lining Mfg/Distributor Construction Engineering/Architecture/Consulting Firms

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