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BASIC CORROSION Student Manual
July 2014 Version 2.01
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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.
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Acknowledgements The time and expertise of a many members of NACE International have gone into the development of this course. 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 under the auspices of the NACE Education Administrative Committee in cooperation with the NACE Certification Administrative Committee. It is the intention of this task group to continue toward development of additional NACE courses on integrity management. On behalf of NACE, we would like to thank the 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. Bopinder Phull, PhD
Consultant Corrosion & Cathodic Protection Specialist Wilmington, NC
Jerry Byrd
Byrd Coating Consultants Wellington, FL
Raul Castillo
Senior Metallurgical Specialist Dow Chemical Company Freeport, Texas
Dan Laury
Project Lead Vantage Force, Inc. Houston, TX
John P. Campbell
Head3 Interactive Project Manager/Coordinator The Woodlands, TX
Nina Pasini Deibler
Instruction Design Consultant Pittsburgh, PA
Scott Brady
Project Coordinator Vantage Force, Inc. Houston, TX
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Welcome to the Basic Corrosion Course Summary The goal of this course is to provide interested persons with a basic overview of corrosion including its causes, its impact of various materials, and measures used to inhibit, inspect, and monitor it. A person who successfully completes this course will know enough about corrosion to be able to pursue additional study and professional development through the NACE Certification Program.
Who Should Attend This course is for individuals interested in a basic survey of corrosion, including but not limited to: •
Engineers
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Managers
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Supervisors
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Technicians
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Salespersons
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Inspectors
Prerequisites An understanding of basic chemistry at the high-school level is highly recommended. Very little time will be spent reviewing general chemistry basics during the course. Learners include high school or technical school graduates through college educated businesspersons and scientists/engineers. The course materials will be written in plain language and all technical terms will be clearly and simply defined and stated. The course will not assume any existing scientific knowledge or education of the learners.
Length The course begins on Monday (or Day 1) at 8:00 AM and ends on Friday (or Day 5) at 1:00 PM.
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Delivery Media An instructor will present the course in-person to a classroom of attendees. Materials will include: •
Student manuals with images
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PowerPoint presentations with images
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Classroom delivery
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Quizzes (ungraded for practice)
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Practical exercises (to reinforce concepts)
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100 item assessment (graded exam)
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Reference materials
Quizzes and Examinations Each chapter will include self-test questions as a quiz for learners to complete as study aids. The final written exam, which will be given on Day 5, will consist of 100 true/ false and multiple-choice questions. The four-hour examination is open book and students may bring reference materials and notes into the examination room. Self-test and exam questions are drawn from the learning objectives and the material covered in the lectures and course manual. A score of 70% or greater is required to successfully complete the course and receive a course completion certificate and continuing education units (CEUs).
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DAILY SCHEDULE DAY ONE 8:00 AM–5:00 PM Morning Session
Chapter 1 Introduction to Basic Corrosion Chapter 2 Basics of Corrosion Electrochemistry
Afternoon Session
Chapter 2 Basics of Corrosion Electrochemistry (continued) Chapter 3 Corrosive Environments DAY TWO
8:00 AM–5:00 PM Morning Session
Chapter 4 Materials
Afternoon Session
Chapter 5 Forms of Corrosion DAY THREE
8:00 AM–5:00 PM Morning Session
Chapter 5 Forms of Corrosion (continued)
Afternoon Session
Chapter 6 Designing for Corrosion Control DAY FOUR
8:00 AM–5:00 PM Morning Session
Chapter 7 Corrosion Control Methods
Afternoon Session
Chapter 8 Inspection, Monitoring, and Testing DAY FIVE
9:00 AM–1:00 PM Morning Session
Exam Briefing and Final Written Exam (4 Hours)
*Schedule may vary based on individual instructor’s pace.
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Code of Conduct While on site at a NACE course, appropriate behavior towards instructors, NACE/ class location staff, and fellow students is required. If appropriate behavior is not maintained, NACE has the authority to take proper action against the student(s) in violation, which could result in revocation of one or more of the following: NACE Certification, Membership, and current/future classroom attendance.
Classroom Policies To provide the best environment for training, please observe and follow these requirements: •
No smoking or other tobacco products.
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Class starts at designated times.
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Participants are responsible for their own learning and timekeeping.
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Turn off mobile phone ring tones, and do not make or answer calls, text messages, or tweets while in the classroom.
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Mobile phones, smart phones, tablets, notebooks, cameras and any other devices containing cameras are not permitted during quizzes and exam.
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Observe designated times for lunch breaks, coffee breaks, and smoke breaks.
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Note location(s) of restrooms and smoking facilities.
Policy Regarding Use of Electronic Devices During Examinations (Classroom, Lab, or Field) This includes, but is not limited to, laptops, smart phones, cell phones, communication devices, and cameras. Non-communicating, battery-operated, silent, non-printing calculators, including calculators with alphanumeric keypads, are permitted. 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, organizers, smart phones, and cell phones. Also excluded are communication devices, such as pagers, cameras, and recorders of any type. All communication devices must be kept on silent mode and not answered during the exam(s). INSTRUCTIONS FOR ACCESSING SCORES ON-LINE
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Instructions for Completing the ParSCORETM Student Enrollment 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: √ PHONE:
Student ID, NACE ID or Temporary ID provided 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 fourdigit number in this space.) √ LAST NAME: Your last name (surname) √ FIRST NAME: Your first name (given name) √ M.I.: Middle initial (if applicable) √ TEST FORM: This is the version of the exam you are taking. √ SUBJ SCORE: This is the version of the exam you are taking. √ NAME: _______________ (fill in your entire name) √ SUBJECT: ____________ (fill in the type of exam you are taking, e.g., CIP Level 1) √ DATE: _______________ (date you are taking exam) 3. The next section of the form (1–200) is for the answers to your exam questions. x All answers MUST be bubbled in on the ParSCORETM Score Sheet. Answers recorded on the actual exam will NOT be counted. TM x If changing an answer on the ParSCORE sheet, be sure to erase completely. x Bubble only one answer per question and do not fill in more answers than the exam contains.
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It is NACE policy not to disclose student grades via the telephone, e-mail or fax. Students will receive a grade letter in approximately 6-8 weeks after the completion of the course by US mail or through their company representative. However, in most cases, within 7-10 business days of receipt of exams at NACE headquarters, the students may access their grades via the NACE web site. The following are step-by step instructions for this process. Spaces are provided below for you to fill in the information required to access grades. Please be sure to have this information filled in before leaving the course location. Keep this form with you upon leaving the course. You will not be able to access your grades without this information.
Go to the NACE Website at www.nace.org Under the Training & Education tab click on Check My Grades Then follow the 4 easy steps: Step 1: Find your Course Number in the drop-down list and click on it. COURSE NUMBER: ___________________ You may find your course number on your registration confirmation letter or it will be available from the instructor at the class. If your course number does not appear in the drop down list then grades have not yet been posted. Step 2: Enter your Student ID number
STUDENT ID:
____________________
This will be your 6-digit NACE ID number or membership number (example 123456) OR a 10-digit temporary ID number assigned at the course. The 6-digit number is printed on the roster provided to the instructor as well on your registration confirmation. For courses where no roster is provided, the instructor will assign a 10-digit temporary ID number used only for accessing scores on-line. Step 3: Enter your Password:
PASSWORD: ______________________
This should be the last four digits of the telephone number you completed on your ParSCORE exam form. You may choose an alternate number but it must be in the last four spaces provided for the telephone number on the Scantron exam form Step 4: Click on “SEARCH” If you have trouble accessing your grade, please contact NACE International by e-mail at
[email protected].
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NACE Corrosion Network (NCN) NACE has established the NACE Corrosion Network, an electronic list server that is free to the public. It facilitates communications among professionals who work in all facets of corrosion prevention and control. If you subscribe to the NACE Corrosion Network, you will be part of an e-mail driven open discussion forum on topics A–Z in the corrosion industry, or you can review and respond to relevant topics online. Got a question? Just ask! Got the answer? Share it! The discussions will sometimes be one-time questions, and other times there will be debates. What do you need to join? An e-mail address. That’s all! 1. To subscribe, fill out the form and select the lists you wish to join at: www.nace.org/ncn
2. You will receive a confirmation e-mail, which you will need to reply to in order to join the lists.
3. To unsubscribe, click Unsubscribe for the lists you wish to leave at: www.nacecorrosionnetwork.com/read/all_forums
Technical Committees More than 2,000 NACE members participate in technical committee activities. The committees are led by the Technical Coordination Committee (TCC), which serves as the administrative and policy-making body to the committees. The technical committees are organized by Specific Technology Groups (STGs). STGs are assigned specific technical areas within three administrative classes: Industry-Specific Technology (N), Cross-Industry Technology (C), and Science (S). Technology Management Groups (TMGs) are formed under the TCC to provide a structure and a conduit for communication between the TCC and the various STGs within their respective areas. They provide assistance, when necessary, to help STGs achieve their objectives.
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Standards and Reports NACE standards are prepared by the Association’s technical committees to serve as voluntary guidelines in the field of prevention and control of corrosion. These standards are prepared using consensus procedures. NACE offers its standards to the industrial and scientific communities as voluntary standards to be used by any person, company, or organization. Members may download PDF copies of standards at no charge. A technical committee report is a limited-life document developed by a technical committee. Typical categories for committee reports are 1) state-of-the-art reports that deal with the current science and technology of a method, technique, material, device, system, or other aspect of corrosion control work; or 2) informational reports that can be statements on a specific problem (summarizing its ramifications, controversial points, and possible solutions), surveys of common practices, bibliographies on special subjects, etc. Reports also may be downloaded at no cost by NACE members.
Certification Information Traditionally, NACE certification has been awarded to candidates who have met work and education requirements and have successfully completed an open book exam. “Parallel Path” is an alternative route to achieving certification. Under the Parallel Path, NACE certification is achieved by earning credits through successful completion of specified NACE training courses. Successful completion of the NACE Basic Corrosion course satisfies the examination requirement for Corrosion Technician Certification. To learn more about becoming certified or complete the application, 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.
List of References See these other resources for more information. The reference book, Corrosion and Its Control: An Introduction to the Subject, Second Edition by J.T.N. Atkinson and H. Van Droffelaar is provided.
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Basic Corrosion Table of Contents Chapter 1: Introduction to Basic Corrosion Definition of Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 Importance of Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 Direct Costs of Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 Excessive Maintenance, Repair, and Replacement . . . . . . . . . . . . . . . . . . . . . . . 2 Lost Production and Downtime . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 Product Contamination . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 Loss of Product . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 Loss of Efficiency: Oversizing and Excess Energy Costs . . . . . . . . . . . . . . . . 3 Accidents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 Increased Capital Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 Fines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 Indirect Consequences of Corrosion. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 Safety Risks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 Structural Collapse . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 Leaks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 Product Contamination . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 Consumer Confidence . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 Loss of Redundancy. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 Appearance. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 Increased Regulation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 Environment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 Changes in Engineering Practice . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 Forms of Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 List of Organizations Involved in Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
Chapter 2: Basics of Corrosion Electrochemistry Corrosion Occurs Through Electrochemical Reactions . . . . . . . . . . . . . . . . . . . . . . 1 Terms Used in Corrosion and Electrochemistry . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 Matter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 Element . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 Compound. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 Mixture . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 Atom . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 Molecule . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 Ion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
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Electrolyte . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 Oxidation/Reduction Reactions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 Corrosion as an Electrochemical Process . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 Corrosion Requires a Complete Circuit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 Thermodynamics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 Potential . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 Reference Electrodes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 Calomel Reference Electrode. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 Silver/Silver-Chloride Reference Electrode. . . . . . . . . . . . . . . . . . . . . . . . . . . 8 Copper/Copper-Sulfate Reference Electrode. . . . . . . . . . . . . . . . . . . . . . . . . . 9 Comparison of Potentials Measured Using Different Reference Electrodes . . 9 The Galvanic Series . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 Nernst Equation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 EMF Series. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 Pourbaix Diagrams . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 Kinetics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 Faraday’s Law. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 E log i Curves (Evans Diagrams) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 Area Effects . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16 Electrochemical Cells . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 Galvanic Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 Concentration Cell Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 Active/Passive Cells. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18 Thermogalvanic Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18 Passivity. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19 pH . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
Chapter 3: Corrosive Environments Atmospheric Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 Industrial . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 Marine . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 Rural . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 Indoor . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 Corrosion Under Insulation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 Water . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 Dissolved gases. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 Effects of Dissolved Salts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 pH . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 Effects of Mineral Deposits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 Effects of Liquid Velocity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 Effects of Temperature . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 Microbiologically-Influenced Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
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Soils . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 High-Temperature Environments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
Chapter 4: Materials Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 Metallurgy Fundamentals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 Crystal Structure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 Strengthening Methods . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 Mechanical Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 Forming Methods . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 Wrought vs. Cast Structures. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 Welding . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 Materials Specifications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 Metals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 Carbon Steel and Low Alloy Steels . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 Carbon Steel. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 Low-Alloy Steels . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 Cast Irons . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 Stainless Steels . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 Martensitic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 Ferritic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 Austenitic and Super-Austenitic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 Precipitation-Hardening . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 Duplex and Super Duplex . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15 Nickel-Based Alloys . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15 Copper Alloys . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 Characteristics of Copper Alloys . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18 Titanium Alloys . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19 Aluminum . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20 Zinc . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22 Non-Metallic Materials . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22 Polymers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22 Classification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22 Degradation Mechanisms. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25 Joining Polymers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25 Composites . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26 Concrete. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27 Components of Concrete . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28 Cement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28 Aggregate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28 Water . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29 Field Practice . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29
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Effects of Environment on Concrete . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29 Freezing and Thawing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29 Aggressive Chemical Exposure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30 Abrasion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30 Corrosion of Embedded Steel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30 Stray Electrical Currents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30 Corrosion Cells Within Concrete. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30 Chemical Reactions of Aggregate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31 Repair of Concrete . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31 Use of Protective Coatings. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31 Aqueous Environments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31 Underground Environments. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32 Composition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32 Degradation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33 Ceramics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34 Ceramic Materials vs. Metals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34
Chapter 5: Forms of Corrosion Forms of Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 Combination of Forms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 General Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 Definition and Description . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 Recognition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 Mechanism . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 Corrosion Rates. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 Predictability and Measurement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 Performance of Metals and Alloys . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 Control of General Attack Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 Localized Corrosion. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 Pitting Definition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 Pitting Mechanism . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 Pitting Rates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 Predictability/Measurement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 Performance of Metals and Alloys. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 Control of Pitting Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 Crevice Corrosion Definition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 Mechanism . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 Types . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 Performance of Metals and Alloys. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 Control of Crevice Corrosion. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 Filiform Corrosion Definition. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
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Mechanism . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 Performance of Metals and Alloys. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 Control of Filiform Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 Galvanic Corrosion Definition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 The Electrochemical Process . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 Galvanic Series . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15 Galvanic Corrosion Rates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15 Potential Difference . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15 Nature of Environment. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16 Polarization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16 Spatial Effects: Area, Distance, and Geometric Effects . . . . . . . . . . . . . . . . 16 Electrolyte Resistivity Effects . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 Predicting Galvanic Attack . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 Performance of Metals and Alloys . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18 Control of Galvanic Attack. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20 Design . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20 Materials Selection. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20 Electrical Isolation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20 Barrier Coatings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21 Cathodic Protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21 Modification of Environment. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21 Environmental Cracking Definition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21 Mechanism . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21 Recognition of Environmental Cracking . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21 Controlling Cracking Factors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22 Types of Environmental Cracking . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22 Stress Corrosion Cracking Definition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22 Hydrogen Induced Cracking and Sulfide Stress Cracking Description . . . . . . . 24 HIC Recognition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24 HIC Mechanism . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25 Sulfide Stress Cracking . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25 ANSI/NACE MR0175/ISO 15156, “Petroleum and Natural Gas Industries—Materials for Use in H2S-Containing Environments in Oil and Gas Production” . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26 Performance of Metals and Alloys. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26 Liquid Metal Embrittlement (LME) Definition . . . . . . . . . . . . . . . . . . . . . . . . . 27 Recognition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27 Mechanism . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27 Performance of Metals and Alloys. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27 Corrosion Fatigue Definition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28 Description . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28 Mechanism . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29 Performance of Metals and Alloys. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29
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Control of Environmental Cracking. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30 Flow Assisted Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32 Erosion-Corrosion Description . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32 Recognition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32 Mechanism . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33 Performance of Metals and Alloys . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33 Aluminum and Aluminum Alloys . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33 Carbon and Low-Alloy Steels . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33 Stainless Steels and Nickel-Based Alloys . . . . . . . . . . . . . . . . . . . . . . . . . . . 34 Copper Alloys . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34 Impingement Description . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34 Recognition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34 Mechanism . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34 Water Drop Impingement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34 Performance of Metals and Alloys. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35 Cavitation Description . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35 Recognition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35 Mechanism . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36 Performance of Metals and Alloys. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36 Control of Flow Assisted Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37 Intergranular Corrosion Definition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38 Description . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38 Recognition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38 Mechanism . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38 Performance of Materials . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38 Intergranular Corrosion of Stainless Steel . . . . . . . . . . . . . . . . . . . . . . . . . . . 38 Aluminum and Aluminum Alloys . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39 Copper and Copper Alloys. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40 Nickel and Nickel-Based Alloys . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40 Control of Intergranular Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40 Materials Selection. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40 Design/Fabrication . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40 Modification of Environment. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40 Use of Proper Welding Procedures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41 Heat Treatment. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41 Dealloying . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41 Definition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41 Description . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41 Recognition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41 Mechanism . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41 Performance of Metals and Alloys . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42 Copper Alloys . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42 Brasses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42
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Bronzes. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42 Cast Iron. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42 Control of Dealloying . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43 Materials Selection. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43 Control of Environment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43 Use of Protective Coatings. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43 Electrochemical Techniques . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43 Design . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43 Fretting Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44 Definition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44 Description . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44 Recognition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44 Mechanism . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44 Performance of Metals and Alloys . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45 Controls. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45 Materials Selection. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45 Design . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45 Use of Lubricants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45 High-Temperature Oxidation/Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45 Definition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46 Recognition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46 Mechanisms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46 Oxygen Reactions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47 Reaction Rates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47 Linear Behavior . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47 Parabolic Behavior . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47 Oxide Scale Characteristics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48 Scale Thickness . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48 Scale Adhesion. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48 Internal Oxidation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48 Sulfidation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49 Carburization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49 Decarburization (Hydrogen Effects) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50 Halide Effects. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50 Molten-Phases Formation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 51 Performance of Metals and Alloys . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 52 Carbon and Low-Alloy Steels . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 52 Alloy Additions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 52 Stainless Steels . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 52 Nickel-Based Alloys . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 52 Refractory Metals. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 53 Control of High-Temperature Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 53 Materials Selection. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 53
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Design . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 53 Modification of the Environment. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 53 Protective Coatings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 53
Chapter 6: Designing for Corrosion Control Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 Construction Parameters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 Welding. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 Accommodating Other Corrosion Control Measures . . . . . . . . . . . . . . . . . . . . . . 2 Process Parameters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 Temperature . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 Nominal Operating Temperature . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 Maximum Operating/Upset Temperature . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 Minimum Operating Temperatures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 Temperatures during Downtime . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 Velocity. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 Flow Rates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 Flow Regime . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 Pressure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 Pressure Variations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 Chemistry . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 Drainage. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 Dissimilar Metals. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 Crevices . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 Corrosion Allowance/Operating Lifetime . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 Maintenance and Inspection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
Chapter 7: Corrosion Control Methods Materials Selection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 Factors that Influence Materials Selection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 Corrosion Resistance in the Environment . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 Availability of Design and Test Data. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 Mechanical Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 Cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 Availability. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 Compatibility with Other System Components . . . . . . . . . . . . . . . . . . . . . . . . 3 Life Expectancy of Equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 Reliability. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 Appearance. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 Comparison with Other Corrosion Control Methods . . . . . . . . . . . . . . . . . . . . . . 3
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Candidate Materials . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 Metals. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 Nonmetals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 Modification of the Environment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 Corrosion Inhibitors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 Types of Inhibitors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 Common Corrosive Species that Affect Corrosion Inhibition. . . . . . . . . . . . . 8 Applications of Inhibitors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 Gaseous Environments. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 Inhibitor Application Techniques . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 Safety Considerations With Inhibitors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 Water Treatment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 Protective Coatings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 Coating Purposes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 Mechanisms of Protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15 Barrier . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15 Inhibitive Pigments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15 Cathodic Protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15 Desirable Properties of a Coating . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15 Chemical Resistance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15 Low-Moisture Permeability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16 Easy Application to Substrate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16 Adhesion to Substrate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16 Cohesive Strength . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16 Tensile Strength . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16 Flexibility/Elongation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16 Impact Resistance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16 Abrasion Resistance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16 Temperature Resistance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16 Resistance to Cold Flow . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16 Dielectric Strength . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16 Coating System Selection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 Types of Exposure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 Operating Conditions/Upset Conditions . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 Substrate. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 Ambient Conditions During Application. . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 Environmental Regulations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 Application of Coating During Operation or at Shutdown . . . . . . . . . . . . . . 18 Time Constraints . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18 New Construction/Maintenance. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18 Shop/Field Application . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18 Design/Fabrication Considerations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18 Surface Preparation. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
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Coating Application . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21 Manual . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21 Spray . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21 Production Techniques. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21 Inspection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21 Surface Preparation Inspection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21 Coating Application Inspection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22 Wraps and Tapes. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22 Insulation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22 Metallic Coatings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22 Coating Anodic to Base Metal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22 Coating Cathodic to Base Metal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23 Organic Coatings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23 Coating Degradation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23 Cathodic and Anodic Protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26 Principles . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26 How Cathodic Protection Works . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26 Galvanic (Sacrificial) Anode Cathodic Protection Systems . . . . . . . . . . . . . . . . 27 Impressed-Current Cathodic Protection (ICCP) Systems. . . . . . . . . . . . . . . . . . 29 Impressed Current System Anodes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30 Impressed-Current Cathodic Protection System Power Sources . . . . . . . . . . 31 Measurement of Cathodic Protection Effectiveness . . . . . . . . . . . . . . . . . . . . . . 32 Structure-to-Environment Potential . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32 Test Coupons . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33 Potential Change . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33 Design . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33 Regulatory Requirements. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33 Economics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33 Metal to be Protected . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33 Life Requirements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34 Total Current Requirements. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34 Variation in Environment. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34 Electrical Shielding . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34 Stray Current Effects . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34 Temperature . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34 Wire and Cable. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35 Anode Backfill . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35 Protective Coatings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35 Maintenance. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35 Anodic Protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35
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Introduction and Definitions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 Inspection. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 Inspection Methods. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 Visual . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 Radiography (X-Ray and Radioactive Isotopes) . . . . . . . . . . . . . . . . . . . . . . . 3 Ultrasonic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 Eddy Current Inspection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 Dye Penetrant Inspection (DPI) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 Magnetic Particle Inspection (MPI) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 Positive Materials Identification (PMI) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 Thermographic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 Significance of Inspections . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 Corrosion Monitoring . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 Corrosion Probes. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 Mass-Loss (Weight-Loss) Coupons . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 Electrical Resistance Probes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 Electrochemical Methods . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 Linear Polarization Resistance (LPR) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 Tafel Extrapolation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 Galvanic Monitoring. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 Hydrogen Probes. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15 Water Chemistry Monitoring . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15 Deposits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15 Suspended Solids . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15 Scale . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16 Microbiological Fouling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16 Cathodic Protection Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16 Inspection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16 Monitoring . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
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Basic Corrosion List of Figures Chapter 1: Introduction to Basic Corrosion Figure 1.1: Corrosion of Steel on an Offshore Platform . . . . . . . . . . . . . . . . . . . . . 1 Figure 1.2: Costs of Corrosion1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 Figure 1.3: Corrosion Allowance on an Offshore Platform Leg in Splash and Tidal Zone 2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 Figure 1.4: Structural Collapse, a Fatal Highway Bridge Collapse into the Ohio River . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 Figure 1.5: Parking Garage Collapse Due to Deicing Salt-Accelerated Corrosion of Reinforcing Steel3 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 Figure 1.6: Unsightly Corrosion on a Ship4 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 Figure 1.7: 1965 Pipeline Explosion in Natchitoches, Louisiana2 . . . . . . . . . . . . . 5 Figure 1.8: Oil Containment Boom and Oil-Absorbing Papers on the Surface of a River to Minimize the Spread of Crude Oil from a Corroded Pipeline2 . . . . . . . 6 Figure 1.9: Ruptured Pipeline Resulting in 12 Fatalities2 . . . . . . . . . . . . . . . . . . . . 6 Figure 1.10: Internal Surface of Corroded Pipeline . . . . . . . . . . . . . . . . . . . . . . . . . 6 Figure 1.11: Short Circuit in Microelectronics due to Corrosion and Dendritic Growth5 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 Chapter 2: Basics of Corrosion Electrochemistry Figure 2.1: Electron vs. Conventional Current Flow . . . . . . . . . . . . . . . . . . . . . . . . 6 Figure 2.2: Corrosion Cell . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 Figure 2.3: Nernst Equation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 Figure 2.4: Open-Circuit Potentials . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 Figure 2.5: Anode Polarization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 Figure 2.6: Cathode Polarization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15 Figure 2.7: Combined Polarization of Complete Corrosion Cell . . . . . . . . . . . . . 15 Figure 2.8: Equal Anode and Cathode Area . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16 Figure 2.9: Area Effects – Smaller Cathode . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16 Figure 2.10: Area Effects – Smaller Anode . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 Figure 2.11: Reversal of Zinc-Iron Potential . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18 Figure 2.12: Illustration of Passivity (Active-Passive Behavior) of Certain Materials . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19 Figure 2.13: pH Scale . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21 Chapter 3: Corrosive Environments Figure 3.1: Corrosion Environments on an AST1 . . . . . . . . . . . . . . . . . . . . . . . . . . 1 Figure 3.2: Corroded Fins on a Window-Mounted Air Conditioner . . . . . . . . . . . . 2
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Figure 3.3: Atmospheric Corrosion Testing at the NASA Kennedy Space Center Beachside Corrosion Site4 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 Figure 3.4: Simplified Diagram Showing the Effect of Relative Humidity and Pollution on the Corrosion of Carbon Steel 2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 Figure 3.5: Industrial Atmosphere Corrosion of a Sewage Digester1 . . . . . . . . . . . 3 Figure 3.6: Salt Shaker with Rice . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 Figure 3.7: Marine Corrosion on a Steel Ship . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 Figure 3.8: Marine Corrosion on Copper . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 Figure 3.9: Problem Locations for Insulated Aboveground Pipelines . . . . . . . . . . 5 Figure 3.10: External Jacketing on Insulated Piping and Process Equipment . . . . 5 Figure 3.11: Condensation Leading to Corrosion on Indoor Chilled-Water Pipe . . 6 Figure 3.12: Minimal Corrosion in the Exterior of Insulated Steam Line . . . . . . . . 6 Figure 3.13: Condensate Channeling Corrosion in Gathering Line6 . . . . . . . . . . . . 7 Figure 3.14: Effect of Dissolved Gases on the Corrosion of Carbon Steel7 . . . . . . 7 Figure 3.15: Corrosion Rate of Iron in Air-Exposed Water with Varying Salt (Sodium Chloride) Concentrations8,9 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 Figure 3.16: Zones of Corrosion for Steel Piling in Seawater10,11 . . . . . . . . . . . . . 8 Figure 3.17: Effect of pH on the Corrosion Rate of Iron in Water at Room Temperature2,8 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 Figure 3.18: Corrosion Rate of Zinc in Water at Different pHs10 . . . . . . . . . . . . . . 9 Figure 3.19: pH of Pure Water at Various Temperatures1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 Figure 3.20: Carbonic Acid, Bicarbonate Ion, and Carbonate Distribution as a Function of pH . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 Figure 3.21: Calcium Carbonate (Calcite) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 Figure 3.22: Calcium Sulfate (Gypsum) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 Figure 3.23: Boiler Scale in Steam Generating Piping . . . . . . . . . . . . . . . . . . . . . 11 Figure 3.24: Corrosion Due to Water Separation at the 6 o'clock Position on a Low-Velocity Crude Oil Gathering Line . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 Figure 3.25: Corrosion at the Bottom of an Aqueous Film-Forming Foam Piping System in an Aircraft Hangar . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 Figure 3.26: Changes in Oxygen Solubility in Water Exposed to Air at Various Temperatures10 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 Figure 3.27: Pitting Under Microbial Deposits . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 Figure 3.28: Corroded Pipeline at the Air-to-Soil Interface1 . . . . . . . . . . . . . . . . 13 Figure 3.29: Differing Soil Layers Leading to Differing Corrosive Environments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 Figure 3.30: Radial Locations Where Corrosion is Most Likely to Occur on Buried Pipelines1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 Chapter 4: Materials Figure 4.1: Body-Centered Cubic Crystal Structure1 . . . . . . . . . . . . . . . . . . . . . . . 2
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Figure 4.1: Face-Centered Cubic Crystal Structure . . . . . . . . . . . . . . . . . . . . . . . . . 2 Figure 4.2: Grain Boundaries in a Metal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 Figure 4.3: Substitutional Solid Solution in a Crystalline Solid 2 . . . . . . . . . . . . . . 3 Figure 4.4: Interstitial Solid Solution in a Crystalline Solid 2 . . . . . . . . . . . . . . . . . 3 Figure 4.5: The Collapse of the Point Pleasant Bridge Across the Ohio River in 1967 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 Figure 4.6: Welded Ship That Cracked Due to DBTT Problems During Fabrication . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 Figure 4.7: DBTT Cracking of an Interstate Highway Bridge in 2000 . . . . . . . . . . 4 Figure 4.8: Liquefied Hydrogen Storage Tank at the NASA Kennedy Space Center . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 Figure 4.9: Principal Directions of Rolled Plate . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 Figure 4.10: Defects Associated with Welding . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 Figure 4.11: Distortion of Exterior Plates Due to Weld Shrinkage . . . . . . . . . . . . . 7 Figure 4.12: Spiral-Welded Pipeline Under Construction . . . . . . . . . . . . . . . . . . . . 7 Figure 4.13: Weathering Steel Bridge Beams (Protective Rust Film Formed on Surface Indicated by Arrow) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 Figure 4.14: Brittle Fracture of a Cast Iron Water Pipe . . . . . . . . . . . . . . . . . . . . . 9 Figure 4.15: Flakes of Graphite in the Microstructure of Gray Cast Iron . . . . . . . 10 Figure 4.16: Rounded Nodules of Graphite in Ductile (Nodular) Cast Iron . . . . . 10 Figure 4.17: Stainless Steel Equipment Meter Runs in Wet CO2 Service . . . . . . 11 Figure 4.18: Stainless Steel Equipment Bubble Trays in Gas Stripping Tower . . 11 Figure 4.19: Cupronickel Seawater Piping . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18 Figure 4.20: Titanium Plates for Plate-and-Frame Heat Exchanger . . . . . . . . . . . 19 Figure 4.21: Titanium Alloys for Shell and Tube Heat Exchanger . . . . . . . . . . . . 19 Figure 4.22: Aluminum Coast Guard Cutter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21 Figure 4.23: Zinc Corrosion vs. pH of the Environment 9 . . . . . . . . . . . . . . . . . . 22 Figure 4.24: Rodent Bite Damage on Cathodic Protection Ground Bed Lead Wire . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25 Figure 4.25: UV Degradation of Polypropylene Rope After UV Exposure . . . . . 25 Figure 4.26: UV Degradation of New Polypropylene Rope . . . . . . . . . . . . . . . . . 25 Figure 4.27: Fiber-Reinforced Composite Walkway . . . . . . . . . . . . . . . . . . . . . . . 26 Figure 4.28: FRP Piping Underneath a Pier . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26 Figure 4.29: Solvent Dissolved the Matrix of this Glass-Reinforced Polymer Pipe.12 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27 Figure 4.30: Freeze-Thaw Damage on Concrete . . . . . . . . . . . . . . . . . . . . . . . . . . 33 Figure 4.31: Acid Attack Due to Spilled Chemicals on a Concrete Floor Slab . . 33 Figure 4.32: Rust Oozing From Cracks Formed in Concrete Due to Corrosion of Reinforced Steel in Sea Wall . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33 Figure 4.33: Reinforcing Steel on Highway Bridge Deck; Most of the Steel is in Good Condition Due to the Alkalinity (High pH) of the Concrete Environment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33 Figure 4.34: Pitting Corrosion of the Base of an Aluminum Guard Rail on a
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Causeway Near the Atlantic Ocean . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33 Chapter 5: Forms of Corrosion Figure 5.1: Cross-Section of a Carbon Steel Tray in an Amine-Sweetening Unit 1 2 Figure 5.2: General Corrosion Underneath Disbonded Coating; Note Rippled Surface1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 Figure 5.3: General corrosion along the bottom of a gas well flow line where acidic condensate thinned the bottom of this horizontal piping. 2 . . . . . . . . . . . . . 2 Figure 5.4: Corrosion Rates vs. Time . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 Figure 5.5: Pit with pH and Chloride Concentration Changes Indicated6 . . . . . . . . 5 Figure 5.6: Pit Morphology7 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 Figure 5.7: Pit Gauge for Measuring Pit Depth in the Field . . . . . . . . . . . . . . . . . . 6 Figure 5.8: Crevice Corrosion Locations on Joint and Fastener8 . . . . . . . . . . . . . . 9 Figure 5.9: Oxygen Concentration Cell Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . 9 Figure 5.10: Metal Ion Concentration Cell Corrosion . . . . . . . . . . . . . . . . . . . . . . 10 Figure 5.11: Crevice Corrosion of a Ten-Year-Old Bold on a Water-Control Valve9 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 Figure 5.12: Crevice Corrosion on a Heat Exchanger Header Plate1 . . . . . . . . . . 11 Figure 5.13: Underdeposit Corrosion of 90-10 Copper-Nickel Tubing at the 6 O’clock Position1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 Figure 5.14: Filiform Corrosion Underneath a Transparent Protective Coating . . 13 Figure 5.15: Filiform Corrosion Underneath Coating on the Skin of an Aircraft . 13 Figure 5.16: Galvanic Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 Figure 5.17: Galvanic Series . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15 Figure 5.18: Galvanic Corrosion of Carbon Steel Structure Connected to Stainless Steel Fasteners1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16 Figure 5.19: Effect of Electrolyte Resistivity on the Distribution of Galvanic Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 Figure 5.20: New Pipe Connected to Old Pipe Produces a Galvanic Corrosion Cell 2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18 Figure 5.21: Differential Aeration Cell on a Pipeline Beneath a Paved Road 4 . . 18 Figure 5.22: Electrically-Isolated Flange Assembly5 . . . . . . . . . . . . . . . . . . . . . . 20 Figure 5.23: Stress Corrosion Cracking of Brass Cartridge by Ammonia . . . . . . 22 Figure 5.24: HIC in a High Carbon Steel Bourdon Tube . . . . . . . . . . . . . . . . . . . 24 Figure 5.25: SSC in Drill Pipe . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25 Figure 5.26: LME of a Stressed Monel Distillation Column Caused by Mercury Exposure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27 Figure 5.27: Cracked Fuselage on Aloha Airlines Flight 243 in 198811 . . . . . . . . 29 Figure 5.28: Corrosion Fatigue of a Marine Propeller1 . . . . . . . . . . . . . . . . . . . . . 29 Figure 5.29: Collapsed Alexander Kielland Semi-Submersible Platform in the North Sea, 198012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30 Figure 5.30: Eroded Well-Head Component2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32
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Figure 5.31: Erosion Corrosion Due to Cavitation on Stainless-Steel Pump Impeller . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36 Figure 5.32: Intergranular Corrosion of an Aerospace Aluminum Alloy (UNS A97075) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38 Figure 5.33: Graphitic Corrosion (Dark Areas) on the Exterior of a Cast Iron Water Main1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43 Figure 5.34: Fretting Corrosion Due to Chain Vibrating Against a Stationary Fence Post . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44 Figure 5.35: Loose Fit Tubing in Heat Exchanger Baffle . . . . . . . . . . . . . . . . . . . 44 Figure 5.36: Fretting And Fatigue of Heat Exchanger Tube . . . . . . . . . . . . . . . . . 44 Figure 5.37: High Temperature Corrosion of Gas Turbine Vane10 . . . . . . . . . . . . 46 Figure 5.38: High Temperature Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47 Chapter 6: Designing for Corrosion Control Figure 6.1: Pipeline With Alternating Longitudinal Welds At 10 O’clock and 2 O’clock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 Figure 6.2: Structural Member Orientation for Drainage . . . . . . . . . . . . . . . . . . . . 5 Figure 6.3: Tank Outlet for Drainage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 Figure 6.4: Joining Details . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 Chapter 7: Corrosion Control Methods Figure 7.1: Polarization Diagram Illustrating Anodic Inhibition . . . . . . . . . . . . . . 5 Figure 7.2: Polarization Diagram Illustrating Cathodic Inhibition . . . . . . . . . . . . . 6 Figure 7.3: Corrosion Control Expenditures by Means of Control 1 . . . . . . . . . . . 12 Figure 7.4: Protective Coatings, Paint, And Internal Linings on a Large AboveGround Storage Tank . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 Figure 7.5: Breakdown of Costs of Applying a Protective Coating to an Existing Structure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 Figure 7.6: Marine Piling with Aging Coating . . . . . . . . . . . . . . . . . . . . . . . . . . . 24 Figure 7.7: Osmotic Blistering on a Pipeline Riser . . . . . . . . . . . . . . . . . . . . . . . . 24 Figure 7.8: Blisters on Fusion-Bonded Epoxy . . . . . . . . . . . . . . . . . . . . . . . . . . . 24 Figure 7.9: Cracking Due to Structural Motion on the Exterior Wall of a Ship . . 24 Figure 7.10: Abrasion from the Floating Roof Scraping on the Inside Wall of Aboveground Storage Tank Caused this Corrosion . . . . . . . . . . . . . . . . . . . . . 25 Figure 7.11: Impact Damage on the Front Hood of an Automobile Caused this Corrosion and Coating Blisters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25 Figure 7.12: Disbonded Pipeline Coating . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25 Figure 7.13: Corroded I-Beam Flange Where Debris Accumulated and Promoted Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25 Figure 7.14: Corrosion Cells on Unprotected Structure . . . . . . . . . . . . . . . . . . . . 26 Figure 7.15: Illustration of How Cathodic Protection Makes the Entire Surface
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Cathodic; i.e., Corrosion Cells on the Structure . . . . . . . . . . . . . . . . . . . . . . . . . 27 Figure 7.16: Principle of Galvanic (Sacrificial) Anode Cathodic Protection System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28 Figure 7.17: Examples of Galvanic (Sacrificial) Anodes; Magnesium (Left) and Zinc (Right) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29 Figure 7.18: Principle of Impressed Current Cathodic Protection (ICCP) System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30 Figure 7.19: Examples of ICCP Anodes; Silicon-Iron (Left) and Platinized Niobium (Right) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31 Figure 7.20: Example of ICCP Transformer-Rectifier (T/R) . . . . . . . . . . . . . . . . 32 Figure 7.21: Principle of Anodic Protection System . . . . . . . . . . . . . . . . . . . . . . . 36 Figure 7.22: Polarization Diagram Showing Anodic Protection Principle . . . . . . 36 Chapter 8: Inspection, Monitoring, and Testing Figure 8.1: Areas of increased corrosion susceptibility in a horizontal piping system1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 Figure 8.2: Manual Pit Gauge Measures the Depth of External Pitting on a Pipeline . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 Figure 8.3: Schematic of Film Radiography of a Metal With a Corrosion Pit, an Internal Crack, and Internal Porosity Defects . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 Figure 8.4: Radiograph Showing Erosion Corrosion at a Piping Bend Where Fluid Flows From Right to Left . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 Figure 8.5: Ultrasonic Inspection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 Figure 8.6: Inspection Port for Ultrasonic Equipment to Determine if ErosionCorrosion Has Occurred on a Piping System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 Figure 8.7: Ultrasonic Inspection of the Top (12 O’clock Position) of a Crude Oil Pipeline . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 Figure 8.8: Eddy Current Inspection Of Heat Exchanger Tubes . . . . . . . . . . . . . . . 7 Figure 8.9: Dye Penetrant Inspection for Surface Cracks on Non-Magnetic Piping . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 Figure 8.10: Magnetic Particle Crack Indications on the Exterior of a Pipeline . . . 8 Figure 8.11: Portable X-Ray Fluorescent Spectrometer Being Used for Positive Materials Identification3 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 Figure 8.12: Thermographic Image Showing Location Where Insulation Breakdown Leads to CUI . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 Figure 8.13: Slumping Acid Storage Tank Due to Excessive Wall Thinning4 . . . 10 Figure 8.14: Intrusive and Flush-Mounted Corrosion Probes Inserted into a Three-Phase Oilfield Production System2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 Figure 8.15: Mass Loss Coupons and Probes Used for Corrosion Monitoring . . . 11 Figure 8.16: Corrosion Rate Change vs. Time . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 Figure 8.17: Typical ER Probes2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 Figure 8.18: Voltage vs. Potential Plot at Potentials Near the Corrosion
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Potential . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 Figure 8.19: Applied Current Cathodic Polarization Curve of a Corroding Metal Showing Tafel Extrapolation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 Figure 8.20: Schematic of Hydrogen Pressure Probe . . . . . . . . . . . . . . . . . . . . . . 15 Figure 8.21: Measurement of Pipe-to-Soil Potential 4 . . . . . . . . . . . . . . . . . . . . . . 17 Figure 8.22: Typical At-Grade Test Station 4 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18
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Basic Corrosion List of Tables Chapter 1: Introduction to Basic Corrosion Chapter 2: Basics of Corrosion Electrochemistry Table 2.1: Characteristics of Ions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 Table 2.2: Examples of Ions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 Table 2.3: Characteristics of Oxidation and Reduction . . . . . . . . . . . . . . . . . . . . . . 3 Table 2.4: Examples of Oxidation and Reduction Reactions . . . . . . . . . . . . . . . . . . 3 Table 2.5: Characteristics of Anodic and Cathodic Reactions . . . . . . . . . . . . . . . . . 4 Table 2.6: Examples of Anodic and Cathodic Reactions . . . . . . . . . . . . . . . . . . . . . 5 Table 2.7: Reference Electrodes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 Table 2.8: Galvanic Series for Metals in Seawater. . . . . . . . . . . . . . . . . . . . . . . . . 10 Chapter 3: Corrosive Environments Chapter 4: Materials Table 4.1: The Unified Numbering System for Alloys . . . . . . . . . . . . . . . . . . . . . . 7 Table 4.2: Selected Martensitic Stainless Steels. . . . . . . . . . . . . . . . . . . . . . . . . . . 12 Table 4.3: Selected Ferritic Stainless Steels . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 Table 4.4: Selected Austenitic Stainless Steels* . . . . . . . . . . . . . . . . . . . . . . . . . . 13 Table 4.5: Nominal Composition of Selected Highly-Alloyed Austenitic Stainless Steels . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 Table 4.6: Nominal Composition of Selected Precipitation-Hardening Stainless Steels . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 Table 4.7: Nominal Composition of Selected Duplex and Super Duplex Stainless Steels . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15 Table 4.8: Nominal Composition of Some Nickel Alloys . . . . . . . . . . . . . . . . . . . 16 Table 4.9: Common Copper Alloys . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 Table 4.10: Nominal Composition and Mechanical Properties of Selected Titanium Alloys . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19 Table 4.11: Aluminum Alloys . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21 Chapter 5: Forms of Corrosion Chapter 6: . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Designing for Corrosion Control
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Chapter 7: Corrosion Control Methods Table 7.1: Surface Preparation Methods and Standards. . . . . . . . . . . . . . . . . . . . . 20 Table 7.2: Current Requirements for Steel in Various Environments . . . . . . . . . . 34 Chapter 8: . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Inspection, Monitoring, and Testing
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Introduction to Basic Corrosion
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Chapter 1: Introduction to Basic Corrosion Upon completion of this chapter, students will be able to: • Define corrosion •
Describe the economic, environmental, and safety significance of corrosion
1.1 Definition of Corrosion Corrosion is the deterioration of a material, usually a metal, or its properties because of a reaction with its environment. Figure 1.1 shows an example of corrosion of structural steel members in the splash and atmospheric zones of an offshore platform.
Figure 1.1 Corrosion of Steel on an Offshore Platform
1.2 Importance of Corrosion Corrosion is significant to the economy, in terms of financial costs for corrosion prevention and structural inspection and maintenance, and to society in terms of its environmental impact and potential safety issues.
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1.2.1 Direct Costs of Corrosion Based on the Federal Highway Administration (FHWA) study in 2001, direct loss due to corrosion is estimated at more than $276 billion annually or 3.1% of the Gross Domestic Product (GDP) in the United States1. Losses from corrosion include the corrosion of residential items like automobiles, water heaters, home plumbing, and exposed metal surfaces such as gutters and downspouts. It also includes the cost of corrosion to industry and loss due to the deterioration of public infrastructure including bridges, public buildings, water-supply and wastewater disposal systems, Figure 1.2 Costs of Corrosion1 and other utility systems. Figure 1.2 provides a comparative summary of corrosion costs of common economic sectors. If corrosion control technology could completely eliminate corrosion, the cost of the control measures themselves may not be economically feasible. It may be easier to control corrosion to a reasonable limit than to eliminate it completely.
1.2.2 Excessive Maintenance, Repair, and Replacement If corrosion is not properly considered and prepared for in the initial design of a system, it can lead to frequent breakdowns, and the need for excessive maintenance, repair, and replacement. The maintenance cost is more expensive than the cost to avoid corrosion at the design stage. Preparation during the design stage includes the substitution of more corrosion-resistant materials, changing the operating conditions of the system, or applying other corrosion control measures. 1.2.2.1 Lost Production and Downtime
When corrosion damage creates the need for maintenance or repair, it usually interrupts production. These interruptions result in reduced income for the plant creating an economic impact. In addition, system shutdown and startup costs can be substantial. 1.2.2.2 Product Contamination
In many industries, contamination of a product caused by corroded material entering the product stream can be harmful. This is particularly true for the food processing and pharmaceutical industries, but it also impacts other systems. The direct cost of such contamination is the product’s loss of value, but there may be other indirect costs too including public trust and perception.
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1.2.2.3 Loss of Product
Losing a product due to leaks can have significant direct and indirect costs. The direct costs include the value of the product itself, the cost of repairs, the associated costs of downtime, including shutdown and startup, and the disposal costs of the contaminated products. However, corrosion leaks can have other implications and costs. For example, leaks in the plumbing of public and residential buildings often result in other water damage many times greater than the cost to repair or prevent the leak. 1.2.2.4 Loss of Efficiency: Oversizing and Excess Energy Costs
In many cases, when designers expect substantial corrosion, they may enlarge the system to accommodate the corrosion. In addition to the direct cost of excess material, oversizing can have other direct economic effects. For example, if heat exchanger tubes are made thicker than necessary, the extra thickness of the tube wall will reduce the efficiency of the heat exchanger, which can increase fuel costs or reduce output. Fouling of heat exchangers with corrosion products can have similar effects on fuel costs and productivity. Figure 1.3 shows an oversized offshore platform leg intended to provide a corrosion allowance for the portions of this leg that are exposed to tidal and Figure 1.3 Corrosion Allowance on an Offshore splash-zone conditions. Platform Leg in Splash and Tidal Zone 2 1.2.2.5 Accidents
Corrosion can and has caused severe accidents, resulting in personal injury or loss of life. Corrosion-related accidents have direct economic effects including medical bills, employee or plant downtime, investigations, and lawsuits. They also have other indirect economic and social implications. For example, if a plant or industry has a bad safety record because of corrosion, the cost of insurance will be higher than if they had maintained a good safety record. 1.2.2.6 Increased Capital Costs
The addition of extra material to a system for corrosion control can increase the capital cost for construction and maintenance. Capital costs include the initial costs of other corrosion control measures, such as protective coatings, cathodic protection systems, and equipment for the injection of corrosion inhibitors into the system. 1.2.2.7 Fines
The cost of environmental cleanup for product spills has increased greatly due to intensified awareness of the potential short- and long-term effects these spills can have on the environment. Laws now require the cleanup of most spills. Even if the company responsible for the spill is no longer the owner of the offending system, the company that owned the system at the time of the spill can be liable for the cost of cleanup. If the incident resulted from negligence, the fines can be imposed on the system owners or system operators. Recent spill fines have exceeded $1,000,000.
1.2.3 Indirect Consequences of Corrosion 1.2.3.1 Safety Risks
Corrosion can and has caused many accidents. Most accidents could have been avoided by the proper application of corrosion control measures. Others could have been predicted and corrected before injury or loss of life.
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1.2.3.2 Structural Collapse
Although complete structural collapse due to corrosion occurs infrequently, it does occur. Corrosion can also reduce the resistance of structures to natural forces, such as earthquakes. Figure 1.4 and Figure 1.5 show examples of structural collapse due to corrosion.
Figure 1.4 Structural Collapse, a Fatal Highway Bridge Collapse into the Ohio River
Figure 1.5 Parking Garage Collapse Due to Deicing Salt-Accelerated Corrosion of Reinforcing Steel3
1.2.3.3 Leaks
Leaks in systems carrying flammable or toxic materials are an obvious safety hazard. Fire and explosions from corrosion leaks in underground natural gas pipes are frequent, but avoidable, losses caused by corrosion. Although, in many cases, third-party damage, not corrosion, causes the leaks that result in fire and explosion. 1.2.3.4 Product Contamination
Product contamination can also affect safety, particularly if the contamination is not detected until after a product has been consumed. Corrosion can contaminate foods during both production and storage. Corrosion also frequently contaminates drinking water through the distribution lines and other plumbing-system components. The contamination may simply be unsightly, as in the case of “red water” where relatively harmless levels of iron from iron pipe corrosion causes unsightly staining in the water and on the visible surfaces of plumbing fixtures. Corrosion from lead solders on food cans and copper pipes and corrosion in lead pipes caused many illnesses and deaths before anyone identified the toxic properties of lead. In addition to the elimination of the lead through the replacement of the lead-containing materials, water treatment to reduce the corrosion of the lead and the subsequent release of lead into the water successfully reduced this problem in some cases. Pharmaceutical contamination can cause not only product loss during manufacture, but also premature deterioration and loss of potency during storage. 1.2.3.5 Consumer Confidence
Corrosion can impact the marketability of a product. Recent improvements in the corrosion resistance of automobiles, particularly with long-term guarantees against rust-through, are now a major selling feature. Even if the corrosion only results in unsightliness, a product that has a reputation of resisting corrosion will have greater sales appeal.
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1.2.3.6 Loss of Redundancy
When an organization requires continuous processing or product supply, redundant systems ensure continuous operation. These systems either operate in parallel or use one system as a spare. In the first case, corrosion in one of the parallel systems reduces production until repairs can be completed. In the second case, corrosion in the primary system causes a loss of redundancy until the primary system is repaired. The worst-case scenario is failure of the backup system before the first can be repaired and placed back in service. 1.2.3.7 Appearance
Corrosion, particularly the all-toofamiliar red rust from corroding iron and steel, is unsightly even if it does not interfere with system operation (see Figure 1.6). Industry spends a significant effort trying to eliminate such unsightly corrosion simply for the aesthetic benefits. This is particularly true when the appearance of a plant may be of considerable value to stockholders. 1.2.3.8 Increased Regulation
Many aspects of corrosion control are now regulated. For example, legislation regulates the corrosionrelated aspects for safe operation of pipelines carrying hazardous liquids Figure 1.6 Unsightly Corrosion on a Ship4 or flammable gases. Figure 1.7 shows images from the 1965 pipeline compressor station explosion that killed seventeen and led to the creation of the U.S. Office of Pipeline Safety, and, starting in 1975, Federal requirements for corrosion control on interstate pipelines. Due to recent failures, the Pipeline Hazardous Material Safety Administration (PHMSA), previously known as the “Office of Pipeline Safety,” has instituted new and more stringent regulations for all regulated pipeline systems.
Figure 1.7 1965 Pipeline Explosion in Natchitoches, Louisiana2
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1.2.4 Environment Environmental pollution is an increasing concern worldwide. Figure 1.8 shows an oil containment boom limiting the spread of oil leaking from a corroded pipeline. During the 1990s the United States and Canada required the replacement of all underground storage tanks (USTs) at filling stations and similar operations with double-hulled USTs due to repeated problems with ground water contamination from corroded leaking USTs.
Figure 1.8 Oil Containment Boom and Oil-Absorbing Papers on the Surface of a River to Minimize the Spread of Crude Oil from a Corroded Pipeline2
1.2.5 Changes in Engineering Practice Sometimes corrosion changes engineering practices. The internal corrosion shown in Figure 1.9 and Figure 1.10 led to industrial efforts to control internal corrosion including the development of Internal Corrosion Direct Assessment (ICDA) efforts.
Figure 1.9 Ruptured Pipeline Resulting in 12 Fatalities
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Figure 1.10 Internal Surface of Corroded Pipeline
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Modern electronics are exposed to a wide variety of environments and are made from increasingly complex microelectronic components and circuit boards. The corrosion shown in Figure 1.11 could be controlled by keeping the equipment in atmospherically-controlled environments, but the manufacturing facility cannot guarantee that the item would not encounter corrosion during shipping and storage prior to use. The most common approach to limiting corrosion is to coat the circuits.
1.3 Forms of Corrosion Corrosion is commonly classified in the following categories: • General Corrosion •
Figure 1.11 Short Circuit in Microelectronics due to Corrosion and Dendritic Growth5
Localized Corrosion –
Pitting
–
Crevice
–
Filiform
•
Galvanic Corrosion
•
Environmental Cracking
•
Flow-Assisted Corrosion
•
Intergranular Corrosion
•
Dealloying
•
Fretting Corrosion
•
High-Temperature Oxidation/Corrosion
1.4 List of Organizations Involved in Corrosion The list below only emphasizes sources likely to be used by North American organizations that publish in English. Many other worldwide organizations also publish useful corrosion information and guidelines. The Internet can be a resource, but some of the information may be incorrect. • NACE International •
American Gas Association
•
American National Standards Institute
•
American Petroleum Institute
•
American Society of Mechanical Engineers
•
American Society for Testing and Materials
•
ASM International
•
Materials Technology Institute
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SSPC-The Society for Protective Coatings
•
Steel Tank Institute
References: 1. Corrosion Cost and Preventative Strategies in the United States, September 2001, Federal Highway Administration Report, FHWA-RD-01-156. 2. R. Heidersbach, Metallurgy and Corrosion Control in Oil and Gas Production, John Wiley & Sons, New York, 2011. 3. NASA Kennedy Space Center, Fundamentals of Corrosion, http://corrosion.ksc.nasa.gov/ corr_fundamentals.htm, accessed March 2, 2012. 4. D. Ramirez, (2008), licensed as http://creativecommons.org/licenses/by/2.0/deed.en from http:// www.flickr.com/photos/danramarch/2873459569/, accessed April 30, 2012. 5. Matco, Inc., http://www.matcoinc.com/materials-engineering/environmental-testing-of-electronics.
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Basics of Corrosion Electrochemistry
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Chapter 2: Basics of Corrosion Electrochemistry Upon completion of this chapter, students should have an understanding of the: • Terms and definitions of basic electrochemistry •
Basic electrochemical processes and concepts
2.1 Corrosion Occurs Through Electrochemical Reactions Electrochemical reactions occur: • In electrolytes, which are liquids that can carry an electrical current •
Through the exchange of electrons
The exchange of electrons in electrochemical reactions occurs at separate sites. The electrons flow through the metal from one of these separate sites to another.
2.2 Terms Used in Corrosion and Electrochemistry 2.2.1 Matter Matter is anything that occupies space. Matter may be in the form of a solid, liquid, or gas. Matter may be formed from either elements, molecules, chemical compounds, or mixtures.
2.2.2 Element An element is a substance that cannot be broken down through chemical reactions. Elements are the basic building blocks of all matter. There are 92 naturally occurring elements, ranging from the lightest, hydrogen, to the heaviest, uranium. Iron, oxygen, and gold are also elements.
2.2.3 Compound A compound is a combination of two or more elements. A compound is a pure substance and has a fixed composition. Examples of chemical compounds and their chemical formulas are: • Carbon Dioxide – CO2 –
•
Salt – NaCl –
•
one atom of sodium (Na), one atom of chlorine (Cl)
Water – H2O –
•
one atom of carbon (C), two atoms of oxygen (O)
two atoms of hydrogen (H), one atom of oxygen (O)
Ferric Oxide – Fe2O3 –
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2.2.4 Mixture A mixture is a combination of elements, compounds, or both held together by physical (rather than chemical) forces. A mixture does not have a fixed composition. Air, for example, is roughly 20% oxygen and 78% nitrogen. It also contains other substances, such as argon (about 1%) and varying amounts of carbon dioxide and water vapor. Soil is a mixture of minerals formed from elements and compounds and contains varying amounts of these minerals and water. Most rocks contain one or more minerals that are either chemical compounds, elements, or mixtures.
2.2.5 Atom An atom is the smallest chemical unit of an element. An atom consists of a nucleus surrounded by electrons. The nucleus contains positively charged particles called protons and all but the lightest element (hydrogen) contain neutrally charged particles called neutrons as well. The electrons surround and orbit around the nucleus. The number of electrons in an atom always equals the number of protons in the nucleus. Thus, atoms have a net electrical charge of zero, and are therefore electrically neutral.
2.2.6 Molecule A molecule is the smallest particle of an element or compound that retains all the chemical properties of that compound or element.
2.2.7 Ion An ion is a charged atom or molecule. An ion may either be an anion (negatively charged) or a cation (positively charged). Some examples of ions are shown in Table 2.1.
2.2.8 Electrolyte An electrolyte is a liquid that contains ions. It can conduct electricity through the flow of ions. Anions flow toward the anode and cations flow toward the cathode. An electrolyte contains equal amounts of charge on the ions contained in it. An electrolyte may be highly conductive because of its high content of ions (seawater) or only mildly conductive because of its very low content of ions (pure water).
2.3 Oxidation/Reduction Reactions Most corrosion reactions are electrochemical reactions, called oxidation/reduction reactions (Table 2.3, Table 2.4). Oxidation/reduction reactions occur through an exchange of electrons. In corrosion reactions, these exchanges occur at specific sites. Oxidation occurs at sites called anodes and reduction occurs at sites called cathodes. The electrons given off at the anodes travel through the metal to the cathode, where they are consumed in a reduction reaction. Corrosion occurs in electrolytes that supply the reactants for these reactions.
Table 2.1: Characteristics of Ions Anion
Cation
Negative ion
Positive ion
Net negative charge
Net positive charge
Formed by addition of electrons
Formed by loss of electrons
Attracted to anode
Attracted to cathode
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Table 2.2: Examples of Ions Anion
Cation
Sulfate ion (SO42-)
Ferrous ion (Fe++)
Chloride ion (Cl–)
Ferric ion (Fe+++)
Hydroxyl ion (OH–)
Hydrogen ion (H+)
Table 2.3: Characteristics of Oxidation and Reduction Oxidation
Reduction
Loss of electrons
Gain of electrons
Increases positive charge
Increases negative charge
Decreases negative charge
Decreases positive charge
Occurs at anode
Occurs at cathode
Electrons remain in metal
Metal is electron source
Table 2.4: Examples of Oxidation and Reduction Reactions Oxidation
Reduction
Fe0 → Fe++ + 2e–
2H+ + 2e– → H2
Fe0 → Fe+++ + 3 e–
O2 + 2 H2O + 4 e– → 4(OH–)
Fe++ → Fe+++ + e–
O2 + 4 H+ + 4 e– → 2 H2O
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2.4 Corrosion as an Electrochemical Process Metals and alloys are generally good electron conductors; and aqueous electrolytes typically contain ions. Therefore, corrosion of metals and alloys in such environments is electrochemical in nature. This is known as “wet” corrosion. In contrast, since most non-metals (plastics, concrete, glass, ceramics, etc.) are poor electron conductors, their degradation (corrosion) mechanism is not electrochemical. Attack that occurs on metals and alloys in gaseous environments (i.e., when no aqueous phase is present) is called “dry” oxidation if it occurs near ambient temperatures; for example, tarnishing of copper and silver. When corrosion attack occurs at elevated temperatures (e.g. typically > 1/3 of the melting point of the metal or alloy) in gaseous environments where no moisture is present, the phenomenon is often called high-temperature oxidation. In environments containing gaseous sulfur compounds, high-temperature oxidation is referred to as sulfidation. In gaseous carbon-rich environments, it is called carburization or decarburization, depending on the gas-mixture composition. In reducing environments, the phenomenon may be called high-temperature reduction and so forth. Even though no water or moisture is present, the corrosion mechanism of dry corrosion and high-temperature oxidation is also electrochemical in nature. The oxide-scale acts as a “solid electrolyte” that has semiconducting properties; i.e., partial electron conduction, as well as some migration of ionic species. At the anode, oxidation occurs and metal atoms are dislocated from the metallic structure and enter the electrolyte as ions (Table 2.5). Note that reaction with oxygen is not required for oxidation to occur. In the terminology used for corrosion reactions, oxidation is simply the formation of positive ions through loss of electrons. Cathodic reactions can involve many compounds, but the reduction of hydrogen ions (2H+ + 2e– → H2) and the reduction of dissolved oxygen are very common ones in acidic electrolytes (O2 + 4 H+ + 4 e– → 2 H2O) and aerated neutral-pH electrolytes (O2 + 2 H2O + 4 e– → 4(OH–).
Table 2.5: Characteristics of Anodic and Cathodic Reactions Anodic Reactions
Cathodic Reactions
Loss of electrons
Gain of electrons
Increases positive charge
Increases negative charge
Decreases negative charge
Decreases positive charge
Oxidation
Reduction
Electrons remain in metal
Metal is electron source
Note that the characteristics of anodic and cathodic reactions are essentially the same as for oxidation/reduction reactions (Table 2.3).
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2.4.1 Corrosion Requires a Complete Circuit When an anodic reaction occurs, the electrons remain in the metal. Unless consumed in reactions at the cathode, they build up and tend to stifle the corrosion reaction. The reaction at the anode that results in the loss of metal can only proceed as fast as electrons are consumed at the cathode. The rate of any chemical reaction is slowed by the buildup of reaction products. In this case, the reaction products of the oxidation reaction are electrons that remain in the metal and metal ions that enter the solution. This type of reaction is written:
A buildup of either the metal ions in the electrolyte or of the electrons in the metal will tend to reduce the reaction rate. In many corrosion reactions, the metal ions are consumed by reacting with other molecules or compounds in the electrolyte. These reactions reduce the dissolved metal ion content and allow the electrochemical oxidation to proceed rapidly. The metal ions produced by oxidation at the anode combine with other substances in the electrolyte to form corrosion products. The formation of corrosion products is a side reaction that can affect the rate of corrosion, but is not directly involved in the present electrochemical oxidation/ reduction reactions. Cathodic reactions consume electrons. Three of the most common cathodic reactions that consume electrons are given in Table 2.6. Many other reactions are possible, depending on the chemical composition of the electrolyte and other conditions.
Table 2.6: Examples of Anodic and Cathodic Reactions Anodic Reactions
Cathodic Reactions
Fe0 → Fe++ + 2 e–
2H+ + 2e– → H2
Fe0 → Fe+++ + 3 e
O2 + 2 H2O + 4e– → 4 (OH–)
Fe++ → Fe+++ + e–
O2 + 4 H+ + 4 e– → 2 H2O
Metals are generally good conductors of electricity. Unlike electrolytes, which conduct electricity through the flow of ions, metals conduct electricity through the flow of electrons. Electrons flow in metals from areas with more negative charge (excess electrons) to areas with more positive charge (fewer electrons). One point of confusion is the difference between current flow and electron flow. When electricity was first being studied in the 1700s, the actual mechanism of electrical flow was not known. What was known was that something was flowing in both electrical (electrical flow through metals and other solid conductors) and electrolytic (electrical flow through electrolytes) circuits. Early scientists, such as Benjamin Franklin, established a convention for labeling electrical potentials and electrical flow. They arbitrarily assigned a positive charge to the carrier of electrical charge in a metal and, therefore, the flow of this charge was from the more positive areas to the more negative areas in a circuit. They were wrong. In the late 1800s, physicists discovered the electron and found that it was the movement of the negatively charged electron that was responsible for the flow of electricity in metals. However, the convention stuck and the flow of “conventional current” in an electrical circuit is still described as the flow of positive charge from the more positive areas of the circuit to the more negative areas. The electron flow in the metal is in the opposite direction. In a corrosion cell, electrons flow through the metal from sites where anodic reactions occur to where cathodic reactions occur (Figure 2.1).
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Electrical current also flows through the electrolyte to balance the flow of electrons in the metal. In this case, the carriers of the electrical current are ions in the electrolyte. Anions flow toward the anode and cations flow toward the cathode (Figure 2.2). The complete corrosion reaction requires all these components to be present and active. The required components and characteristics of a corrosion cell are: • Anode: Where metal is lost and electrons are produced •
Cathode: Where the electrons produced at the anode are consumed
•
Metallic path: Conducts electrons from the anodic sites to the cathodic sites.
•
Electrolyte: Provides reactants for the cathodic reactions and allows the flow of ions.
Note that if any of these processes can be slowed or stopped, corrosion can be slowed or eliminated.
2.5 Thermodynamics Thermodynamics is the science of the flow of energy. In some chemical reactions, such as in the burning of wood or oil, the energy is in the form of heat. Thus, the term is derived from “thermo” (heat) + “dynamics” (movement). In corrosion, the chemical reactions usually produce heat at such a slow rate that it is difficult to detect. However, energy flows in corrosion reactions, usually in the form of electrical energy.
Figure 2.1 Electron vs. Conventional Current Flow
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Figure 2.2 Corrosion Cell
The flow of energy determines the direction of all chemical reactions, including corrosion reactions. The energy content of metals is higher than the energy content of the corrosion products that result from corrosion reactions. Natural processes always tend to reduce the total energy content of a system. In this case the system is the metal and its environment. In nature, metallic elements are usually found in the form of chemical compounds, called ores. In refining these compounds into pure metals, energy is required either in the form of heat or electricity. The more reactive metals require more energy input to produce pure metals from their ores. From an energy standpoint, corrosion is simply the natural process of returning these high-energy forms of the metallic elements as pure metals, or as mixtures of metals called alloys, into a lower energy state, where they are combined with other elements to form chemical compounds. In fact, corrosion products are often the same compounds as ores. For instance, iron ore is primarily ferric oxide (Fe2O3), which is a common form of rust produced by the corrosion of iron and steel. Another interesting point is that the metals requiring little energy to produce pure metals from their ores are more corrosion resistant. Only gold, silver, and sometimes copper, are found as metallic elements in nature. Not surprisingly, their corrosion resistance in natural environments is generally very good. This energy difference is given off as heat (usually immeasurable) and electrical flow (easily measurable in many cases).
2.5.1 Potential Measurement of electrical potential is one way of measuring energy differences. In corrosion, the anode (negative electrode) is in a higher energy state than the cathode (positive electrode). The electrons flow from a high-energy area to one of lower energy. In electrochemistry, the usual symbol for potential is E; it is measured in volts or millivolts. The electron flow is dependent on the energy difference existing between the anode and the cathode. This amount of energy can be measured as a difference in potential between the anode and the cathode, providing that a voltmeter can be inserted between the anode and the cathode in the electrical circuit. This energy (potential) difference is normally on the order of a few volts or less. Measuring the potential difference between galvanized steel and copper in water is an example of such a potential measurement. The potential of the electrode connected to the common test lead is more negative than the potential of the electrode connected to the positive lead when the potential reading is positive. The potential of the galvanized steel is more negative than that of the copper by
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0.851 V. The potential of each metal in this case was not measured; the potential difference between them was. As in the case of measuring the heights of various points on the earth, it is necessary to establish a reference height in order to discuss the potential of individual electrodes (anodes or cathodes). In the case of measuring earth surface heights, a sea level reference height is given a value of zero. A point can be given in terms of feet above (or below) sea level. The height difference between two points can be determined by subtracting the height (as measured from sea level) of the higher point from the lower point. Sea level is useful as a reference height because it is approximately the same all over the earth. In the measurement of potentials, a reference electrode is frequently used. A reference electrode is constructed so that its potential will be reproducible. Many reference electrodes can be constructed, and each is particularly suited for its intended use. In laboratory use, the hydrogen reference electrode has been assigned the zero value for potential. Other reference electrodes that can be more conveniently used in the laboratory and in the field can be compared to the arbitrary zero potential of the hydrogen reference electrode. When potentials are measured with respect to these other reference electrodes that have a nonzero potential, it is necessary to indicate which reference electrode was used. In the case of measurement of the height of points on the earth, we could measure the heights of several mountain peaks above the level of a mountain lake, and then find the height of the peaks above sea level by adding the height of the lake above sea level to the heights of the peaks above the lake.
2.5.2 Reference Electrodes Calomel, silver, and copper reference electrodes are frequently used under laboratory or field conditions. To make a reference electrode with a reproducible potential, a metal is immersed in an electrolyte with a reproducible chemical composition, in particular, a specific content of ions. 2.5.2.1 Calomel Reference Electrode This reference electrode is primarily used under laboratory conditions. It consists of mercury as the metal and a solution of potassium chloride as the electrolyte with mercury chloride (calomel) as an intermediate compound. The potential of the calomel electrode is dependent on the concentration of potassium chloride used; saturated, normal, and one-tenth normal potassium chloride are commonly used. The electrolyte in the reference electrode and the electrolyte within which the electrode to be measured is immersed are brought into contact through a porous glass disk or a capillary tube. The electrode is usually constructed from glass and is not durable enough for field measurements. 2.5.2.2 Silver/Silver-Chloride Reference Electrode This reference electrode is used under both laboratory and field conditions. Silver is the metal; the silver is coated with silver chloride. In the “wet type” of silver electrode, a solution of potassium chloride is used as the electrolyte and the potential of the reference electrode is dependent on the concentration of potassium chloride. Either a normal or saturated solution is commonly used. The electrolyte in the reference electrode and the electrolyte within which the electrode to be measured is immersed are brought into contact through a porous glass disk or a capillary tube. In the “dry type” of silver/silver-chloride reference electrode, the silver chloride-coated silver is directly immersed in the electrolyte that contains the electrode to be measured. This type of reference electrode is most commonly used in seawater, where the concentration of chloride (the important ion with regard to the potential of this reference electrode) is reasonably constant. The dry type of silver chloride reference electrode is particularly rugged and is widely used to measure the potentials of metals in seawater.
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2.5.2.3 Copper/Copper-Sulfate Reference Electrode The copper/copper-sulfate reference electrode is very widely used as a reference electrode for measuring potentials in soils and fresh water. It consists of a copper metal wire or rod immersed in a saturated solution of copper sulfate. Contact between the copper sulfate electrolyte and the external electrolyte is made through a porous plug, usually made of ceramic or wood. The copper/copper-sulfate reference electrode is particularly rugged and inexpensive. When measuring potentials it is important to know and record the type of reference electrode that is used. In the slide, the potential of zinc is being measured using a copper/copper-sulfate reference electrode. In this case, the zinc is connected to the common (negative) terminal. The positive reading on the voltmeter indicates that the potential of the zinc is more negative than that of the copper/copper-sulfate reference electrode by 1.029 V. The potential should be reported as –1.029 V with respect to a copper/copper-sulfate reference. This is usually recorded as –1.029 V vs. Cu/CuSO4–. 2.5.2.4 Comparison of Potentials Measured Using Different Reference Electrodes The potentials of the following commonly used reference electrodes are measured with respect to the hydrogen reference electrode under laboratory conditions. The potentials are listed in Table 2.7.
Table 2.7: Reference Electrodes Reference Electrode
Potential (Volts)
Saturated Hydrogen Electrode (SHE)
0.000
Saturated Calomel Electrode (SCE)
+0.2415
Calomel (1N)
+0.2800
Calomel (0.1N)
+0.3337
Silver/Silver-Chloride (sat. KCl)
+0.2250
Silver/Silver-Chloride (1N)
+0.2222
Silver/Silver-Chloride (Dry in Seawater)
+0.2500
Copper/Copper-Sulfate (sat. CuSO4)
+0.3160
To compare reference electrodes to each other, simply subtract the potential of one reference electrode from that of the other to obtain the difference between them. For example the copper/copper-sulfate reference electrode is more positive than the dry-type silver/silver-chloride electrode in seawater by 0.066 V. For example, a potential of an electrode (metal pipe) immersed in an electrolyte (moist earth) measured using one reference electrode can be related to the potential of that same combination measured using any other reference electrode. It is useful to show the potentials on a chart so that it is clear whether to add or subtract the difference in potentials of the reference electrodes. In this case, the potential of the metal would be –0.850 V if measured using a copper/coppersulfate reference electrode and, all other things being equal, would be –0.775 V if measured using a saturated calomel reference electrode. In these cases, the potential of the metal would be reported as –0.850 V with respect to a copper/copper-sulfate reference electrode and –0.775 V with respect to a saturated calomel reference electrode.
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2.5.3 The Galvanic Series The galvanic series is a listing of metals in order of their potentials in one specific environment. The galvanic series is similar to, but significantly different from, the electromotive potential series, as we shall see later in this section. The galvanic series may be different for different environments. The most commonly seen galvanic series is for metals in seawater. A short galvanic series for metals in seawater is given in Table 2.8. If the potentials of metals are measured in other environments and listed in order of their potentials, a galvanic series for that specific environment can be developed. There may be shifts in the positions of various metals in galvanic series for different environments. The galvanic series is very useful for determining the interactions between metals when they are coupled together. More information on the use of the galvanic series will be given later in this course. Some metals, such as 13% chromium (Type 410) stainless steel and 18-8 (18% Cr-8% Ni) stainless steels are shown in two positions on the galvanic series. The importance of this will also be discussed later. There is a general tendency for the active metals to corrode more rapidly than the metals that are less active, but this is only a general trend and there are many exceptions. The galvanic series only considers corrosion potential. Many other factors affect actual corrosion rates.
Table 2.8: Galvanic Series for Metals in Seawater Active (More Electronegative) End Magnesium Zinc Aluminum Alloys Carbon Steel Cast Iron 13% Cr (Type 410) Stainless Steel (Active) 18-8 (Type 304) Stainless Steel (Active) Naval Brass Yellow Brass Copper 70-30 Copper-Nickel Alloy 13% Cr (Type 410) Stainless Steel (Passive) Titanium 18-8 (Type 304) Stainless Steel (Passive) Graphite Gold Platinum Noble (More Electropositive) End
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2.5.4 Nernst Equation The Nernst equation is an electrochemical equation that relates the potentials of pure metals in solutions containing various concentrations of ions. The Nernst equation is depicted in Figure 2.3.
Figure 2.3 Nernst Equation
Where: •
Eº = Standard state half-cell electrode potential
•
E = Electrode potential in existing solution
•
aMn+ = Activity of metal ions in solution
•
aM = Activity of the metal (aM = 1 for pure metal)
•
n = Number of electrons transferred
Activity: • 1 for metals in their metallic state •
1 for ions in 1 M concentration (1mol w/L) roughly equal to concentration of ions (in terms of molar concentration) in dilute solution
Using a standard temperature of 72°F (22.2ºC); using actual values for the constants R, T, and F; and converting from natural logarithms to normal base 10 logarithms, the Nernst equation becomes:
The Nernst equation applies to many corrosion reactions and to the potentials of reference electrodes. For example, if the potential of the reaction Fe0 → Fe++ + 2 e– is reported in volts (versus a hydrogen electrode) when the activity of the Fe++ ions is 1 (1 mol/L = 55.85 g/L) [this is an activity of 1 for the Fe++ ion]), then E0 is –0.44 V. The concentration of Fe++ is then changed and the resulting potential can be calculated. Say that the new concentration of Fe++ is reduced to 0.1 M (activity of 0.1); the new potential (E) is:
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The Nernst equation explains the difference between the potentials of the calomel reference electrodes with different concentrations of potassium chloride. The calomel reference electrode with a potassium chloride concentration of 1 M cell has the standard potential E0. When the concentration of potassium chloride is changed, the potential of the reference electrode changes. For example, when a calomel reference electrode has a potassium chloride concentration of 0.1 M, the Nernst equation can be used to compare the potential of this reference electrode to the standard one, potassium chloride concentration of 1 M. Note that in the reaction in the calomel reference electrode, only one electron is transferred.
The small difference (0.0053 V) in the calculated potential (0.3390 V) and the potential previously given for the 0.1 N calomel reference electrode (0.3337 V in Table 2.7) is due to the use of the concentration of potassium chloride rather than its activity. 2.5.4.1 EMF Series The electromotive force (EMF) series is similar to the galvanic series in that it lists metal oxidation potentials in order of their potential. However, the galvanic series lists the metals in the order of their potentials in a single environment. The EMF series lists the metals in order of their potentials in solutions of standard (1 M) ion concentrations. The EMF series is also called the standard oxidation-reduction (redox) Series. These are the E0 potentials for pure metals in solutions of their ions with an activity of 1. The EMF series can be used to determine whether or not a metal will corrode in a given environment. A metal with a more negative EMF will tend to be oxidized and a metal with a more positive EMF will tend to be reduced. In the case of zinc in water (water reacts at the hydrogen potential), the zinc has a more negative potential than the hydrogen and will tend to corrode. In the case of copper in water, the copper has a more positive EMF than hydrogen and will tend to be stable. It is important to remember that the EMF series is for pure metals in solutions of standard activity; reactions of impure engineering materials in other solutions can and will be different.
2.5.5 Pourbaix Diagrams Pourbaix diagrams are used to predict the stability of metals and corrosion products in environments of varying pH. pH is the relative acidity or alkalinity of a solution. A pH of 7 is neutral, a pH lower than 7 is acidic, and a pH greater than 7 is alkaline. pH will be discussed in more detail later in this course. Pourbaix diagrams are very useful for predicting whether or not corrosion can occur under certain conditions of pH and potential, for estimating the corrosion product composition, and for predicting what changes in pH and potential can increase, reduce, or eliminate corrosion.
2.6 Kinetics Kinetics is the study of speed. Applied to corrosion, kinetics determines the rates of the chemical processes responsible for corrosion. As current (actually, electron) flow is fairly easy to measure, we normally measure the rates of the electrochemical reactions responsible for corrosion by measuring current flow. The amount of current flowing can be used to determine the corrosion rate; the total amount of current flowing over a period of time can be used to calculate the total amount of material lost.
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2.6.1 Faraday’s Law Faraday’s law gives the relationship between the flow of current and the amount of material corroded. Faraday’s law is:
Key: • W = weight of material reacted •
M = atomic weight of material reacted
•
t = time in seconds
•
I = current flow in amperes
•
n = number of electrons exchanged
•
F = Faraday’s constant = 96,500 coulombs (Ampere Seconds)
For example, say that a current of 2 A flows in a corrosion cell for a period of 24 hours. If the anode in the cell is iron and is reacting to form Fe++, what is the weight of iron reacted?
Where: • M = 55.85 g/mol •
t = 86,400s
•
I = 2A
•
n = 2 electrons exchanged
•
F = 96,500 coul/g at. wt.
The same current flowing for a year would corrode 365 x 50 or 18,250 grams, or roughly 40 pounds of iron.
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2.6.2 E log i Curves (Evans Diagrams) Evans diagrams are useful for showing how electrochemical cells function. In an Evans diagram, the potential is typically plotted on the vertical axis and the logarithm of the current flow is plotted on the horizontal axis. The Evans diagram shows the effect of polarization on corrosion behavior. Polarization is the change in potential on a metal surface due to current flow. Both the anode and the cathode in a corrosion cell are subject to polarization of varying degrees. The polarization behaviors of the anodes and cathodes in a corrosion cell greatly affect the current flow in the cell and thus greatly affect the corrosion rate of the anode. In an Evans diagram, the open-circuit (uncoupled) potentials of the anode and the cathode are represented by points on the vertical axis, as shown in Figure 2.4.
Figure 2.4 Open-Circuit Potentials
As current is allowed to flow from the anode, the potential of the anode changes with increased current, as shown in Figure 2.5.
Figure 2.5 Anode Polarization
Note that the potential of the anode becomes less negative with current flow.
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Since current also flows from the cathode, the cathode also polarizes with increasing current, as shown below in Figure 2.6.
Figure 2.6 Cathode Polarization
When both the anodic and cathodic polarization is shown on the same Evans diagram, the corrosion current flowing in the cell can be determined as shown in Figure 2.7.
Figure 2.7 Combined Polarization of Complete Corrosion Cell
Evans diagrams will be used in this course to show the effects of changes in the characteristics of anode and cathode polarization on corrosion currents.
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2.6.3 Area Effects In corrosion reactions, the current density, measured in units of current per unit area, such as milliamperes per square centimeter, are used because current density rather than total current determines the intensity of an electrochemical reaction on a surface. For the same total amount of current, the effect of an electrochemical reaction will have a less intense effect on a large electrode than on a small one. The total amount of reaction will be the same in both cases, but in the case of the small electrode, the effect is concentrated over a smaller area. The effect of current density can be shown using an Evans diagram. In Figure 2.8, polarization of a cell with equal anodic and cathode areas is shown.
Figure 2.8 Equal Anode and Cathode Area
If the area of the cathode is reduced, the current will be more intense on the surface of the cathode and its polarization will increase, as shown in Figure 2.9.
Figure 2.9 Area Effects – Smaller Cathode
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In this example, the increased polarization of the cathode significantly decreases the corrosion current. As the area of the anode remains unchanged, the corrosion current is spread over the same anode area. This corresponds to a lower anodic current density. Therefore, the total amount of metal loss at any point is reduced. If, however, the area of the anode is reduced while the area of the cathode remains the same, a different effect is found. The total current flow is reduced, but the current is now concentrated on a smaller anode area. This corresponds to a higher current density, as shown in Figure 2.10. The metal loss is concentrated at the smaller anodic area, and the intensity of corrosion increases.
Figure 2.10 Area Effects – Smaller Anode
The effect of relative area ratios will be covered in more detail in the section on Galvanic Corrosion and other sections of this course.
2.6.4 Electrochemical Cells When there is a difference in potential between two electrodes in an electrochemical cell, and the electrodes are electrically connected and exposed to an electrolyte, corrosion can occur. 2.6.4.1 Galvanic Corrosion When the potential difference is created by a difference in the chemical compositions of the electrodes, the resulting corrosion is called galvanic corrosion. 2.6.4.2 Concentration Cell Corrosion When the potential difference is created by a difference in environment between different areas on the same metal, the resulting corrosion is called concentration cell corrosion. Crevices, either metal-to-metal or metal-to-nonmetal, that allow the electrolyte to enter the crevice but impede the circulation of the electrolyte can cause the differences in concentration responsible for concentration cell corrosion. The details of concentration cell corrosion will be covered in a separate section later in this course.
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2.6.4.3 Active/Passive Cells When a portion of the surface of a metal is covered with a film of corrosion products that inhibits corrosion, the potential difference between the portion of the metal covered with the film and the portion of the metal that is not covered can create a corrosion cell. In most cases, the area covered by the corrosion products is cathodic with respect to the uncovered areas. This is shown in the galvanic series, where stainless steels are shown in two positions. The “active” position represents the uncovered material and the “passive” position is that of the covered material. The potential difference between the active and passive areas can cause very rapid localized attack if the anode-to-cathode area ratio is small (i.e., small anode, large cathode). This will be discussed in greater detail in the section on pitting corrosion. 2.6.4.4 Thermogalvanic Corrosion Temperature can affect the corrosion potentials of metals. In most cases, a metal exposed to a higher temperature will have a more active (negative) potential than the same metal at a lower temperature. Thus, the metal at a higher temperature will become the anode if it is electrically connected to the same metal at a lower temperature. One result of this effect is the thermogalvanic corrosion between hot and cold domestic copper water pipes when both are buried in the soil under a house, or buried in the concrete slab foundation. In this case, the external surfaces of the hotwater pipes can corrode because of the difference in potential. Different metals show different degrees of change of potential with temperature. In some potable waters, for example, those containing bicarbonates and carbonates, the potential of iron becomes more negative than the potential of the zinc, and galvanized (zinc-coated) steel hot-water tanks do not perform well. This is shown in Figure 2.11.
Figure 2.11 Reversal of Zinc-Iron Potential
At lower temperatures, the iron is the cathode and the zinc corrodes preferentially, as intended. In hotter waters, the situation reverses and the iron corrodes preferentially, causing rust-contaminated “red” water and rapid corrosion of the tank wall. Potential reversal does not occur when appreciable chloride levels are present.
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2.7 Passivity Passivity is the reduction of chemical reactivity of a metal or alloy under certain circumstances. In some cases, film formation occurs naturally in air and can provide a very substantial reduction in the corrosion of these materials. Aluminum, with its very active position in the galvanic and EMF series, is expected to corrode rapidly. Because of the presence of a thin, tightly adherent film of aluminum oxide that forms on the aluminum upon exposure to air, aluminum alloys have good resistance to corrosion in many environments where the oxide film responsible for their passivity is stable. In some cases, such as in stainless steels, active metals, such as chromium are added to iron. The active chromium helps to form the tightly adherent film responsible for the corrosion resistance of stainless steels in many environments. The addition of other elements, such as nickel and molybdenum, to the chromium-iron alloys further improves the stability of this passive film and improves corrosion resistance in a wide variety of environments. An increase in the oxidizing strength of the environment can also improve the stability of passive films on some metals. This may occur when a strong oxidizing agent, such as nitric acid, is present in moderate quantities. The effect of the oxidizing agent increases the stability of the passive film and reduces the corrosion rates substantially. When the oxidizing strength of the electrolyte is increased too much in some alloys, the passive film is no longer stable and the corrosion rate increases. This phenomenon is called transpassive behavior. The behavior of a passive metal with respect to the increasing oxidizing power of the electrolyte is shown in Figure 2.12.
Figure 2.12 Illustration of Passivity (Active-Passive Behavior) of Certain Materials
A similar effect can be produced for some metals in certain environments if a current is applied to a metal surface to make it more negative. This has the same effect as increasing the oxidizing power of the electrolyte. If the potential is maintained so that the metal remains in the passive range, corrosion can be reduced to low levels. This is the basic principle of anodic protection, which will be discussed later in this course.
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2.7.1 pH One factor in the corrosivity of liquids is pH. pH has been mentioned before in this course, but not completely defined. pH is a measure of the acidity or alkalinity of an aqueous solution. Pure water is very slightly ionized by the breakdown of a few of the water molecules to form hydrogen ions (H+) and hydroxyl ions (OH–) through the reaction.
Very little of the water breaks down in this manner. In fact, only 1 in 10,000,000 water molecules are broken down. Scientists use the notation 10–7 to represent this small number (note that there are seven zeros in 1/10,000,000). Since there are equal numbers of H+ and OH– ions in pure water, each has a concentration of 10–7.
where H+ = hydrogen ion activity = the molar concentration of hydrogen ions multiplied by the mean ion-activity coefficient. pH is the negative of the concentration of H+ ions expressed as a power of 10. Thus, pure water with a hydrogen ion concentration of 10–7 has a pH of 7. This is considered neutral. Another important fact about pH is that the total concentration of H+ and OH– ions in a water-based solution is always 10–14.
Acidic solutions are solutions that contain a greater concentration of hydrogen ions (H+) than neutral solutions and alkaline solutions are solutions contain a greater concentration of hydroxyl ions (OH–) than neutral solutions. Thus, acidic solutions have a pH less than seven and alkaline or basic solutions have a pH greater than 7. In an acidic solution with a concentration of hydrogen ions of 10–4 (note that the smaller negative number for the power of 10 represents a larger number of hydrogen ions), the pH would be 4. For an alkaline solution with a concentration of hydroxyl ions of 10–4, the total concentration of hydrogen and hydroxyl ions will still be 10–14, so the concentration of hydrogen would be 10–10. The pH of this solution would be 10. It is important to remember that a change of one pH unit changes the concentration of both hydrogen ions and hydroxyl ions by a factor of 10. Seemingly small changes in pH can have very significant effects on corrosion, depending on the metal and the actual pH of the environment.
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Showing pH on a scale from very acidic to very alkaline, as in Figure 2.13, can help simplify the use of pH.
Figure 2.13 pH Scale
Other factors that have significant effects on the internal surfaces of systems carrying or storing liquids are the physical configuration of the system, the chemical makeup of the liquid, the flow rate of the liquid, the presence of solids in the system, the temperature of the liquid, the pressure of the liquid, and the presence of biological organisms.
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Chapter 3: Corrosive Environments Upon completion of this chapter, students should have a basic understanding of corrosion in: • Atmospheric environments •
Water and other electrolytes
•
Soil environments
•
High-temperature environments
3.1 Atmospheric Corrosion Like the other forms of corrosion, atmospheric corrosion requires the presence of condensed water on the metal surface. The only exception to this general rule is at very elevated temperatures, for example in combustion exhaust systems and flares, where corrosion can occur without liquid water. Natural atmospheric exposures are classified into four types for purposes of understanding their effect on corrosion: • Industrial atmospheres •
Marine atmospheres
•
Rural atmospheres
•
Indoor atmospheres
All of these atmospheres are primarily composed of a mixture of oxygen (about 20%) and nitrogen (about 78%). While the oxygen present in natural atmospheres is important in atmospheric corrosion, it remains fairly constant as far as corrosion reactions go. It is the other materials in the atmosphere that vary considerably and that must be identified properly to understand atmospheric corrosion. These materials include solids, liquids, and gases. It is also possible to have the combined effects of several of these classifications, e.g., marine industrial corrosion, but usually the effects of one or the other are the most important. Figure 3.1 shows how several environments can be encountered on one piece of equipment, an aboveground storage tank (AST). The corrosion control methods for each of these areas on the same tank are different. Studies have shown that atmospheric corrosion of carbon steel substantially increases above 60% relative humidity.2 At higher humidities, microscopic water layers form and start to cause corrosion. Sereda and other researchers showed the importance of time of wetness (time above a critical humidity).3 This is why protective coating Figure 3.1 Corrosion Environments on an AST1 site preparations usually require a 3ºC (5ºF) difference between wet-bulb and dry bulb temperatures. These differences correlate with the lack of microscopic water layers on metal surfaces and acceptably low relative humidities.
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Figure 3.2 shows corrosion on a window-mounted air conditioner in a location where it was only used for approximately half of each year. The corrosion of the aluminum fins occurred during the months when the equipment was not in use and during the hours, usually at night, when moisture condensed on the fins when the air conditioner was turned off. Corrosion under insulation is considered a special case of atmospheric corrosion, because the surfaces are usually not continuously wetted. Atmospheric corrosion testing has repeatedly shown that most of the corrosion on flat exposure samples happens on the bottom side of the panels, because the top sides of these panels are washed by periodic rainfall, which is less likely to wash the bottom. Figure 3.3 shows atmospheric corrosion test panels at the NASA Kennedy Space Center.4 Airborne particles on metal surfaces increase corrosion rates by increasing time of wetness. They can also release corrosive chemicals into condensation.
Figure 3.2 Corroded Fins on a WindowMounted Air Conditioner
Figure 3.3 Atmospheric Corrosion Testing at the NASA Kennedy Space Center Beachside Corrosion Site4
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3.1.1 Industrial Polluted industrial atmospheres can be very corrosive. Most of the corrosion can be attributed to the presence of sulfur and nitrogen oxides, although carbon oxides can also contribute as shown in Figure 3.4. All three of these oxides can have various oxidation levels producing acid condensates of varying corrosivity.
Figure 3.4 Simplified Diagram Showing the Effect of Relative Humidity and Pollution on the Corrosion of Carbon Steel 2
Condensation from unpolluted air has a pH of approximately 5.6, due to the effects of CO2. Additional lowering of the pH of condensation is caused by sulfur and nitrogen oxides, and pH levels between 2–3 have been noted for fogs in some large industrial cities.5 Figure 3.5 shows the corrosion on the inside of an aluminum sewage digester hatch. The acid fumes of the vapors have corroded the inside of this digester, but the external sides of the same metal, exposed to a marine atmosphere are relatively uncorroded.
Figure 3.5 Industrial Atmosphere Corrosion of a Sewage Digester1
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3.1.2 Marine Marine atmospheres have high concentrations of wind-borne salt that may be carried many miles (km) inland. While ordinary table salt (sodium chloride) is the primary constituent of sea salt by weight, other salts have important corrosive effects. Some of the compounds in sea salt, such as sodium and magnesium chlorides, are hygroscopic. Figure 3.6 shows a salt shaker with rice. The hygroscopic nature of salt would plug the holes in the shaker, but the rice preferentially absorbs the moisture and keeps the salt relatively moisture free. Hygroscopic materials tend to absorb water and release the water only during conditions of very low relative humidity. Surfaces contaminated with sea salts will remain wet much Figure 3.6 Salt Shaker with Rice longer than uncontaminated surfaces. Figure 3.7 and Figure 3.8 show atmospheric corrosion in a marine environment. The minimal corrosion of the copper Statue of Liberty emphasizes the differences in corrosion resistance between carbon steel (Figure 3.7) and copper (Figure 3.8).
Figure 3.7 Marine Corrosion on a Steel Ship
Figure 3.8 Marine Corrosion on Copper
3.1.3 Rural Rural environments are often benign, but ammonia from fertilizers and animal urine can cause stress corrosion cracking of copper-based electrical contacts, e.g., in cathodic protection rectifiers.
3.1.4 Indoor Indoor environments can be controlled and are generally less corrosive. Indoor corrosion is usually minimal provided the air is kept above the dew point. Electronics processing and control rooms on offshore platforms often use positive pressures to limit the ingress of outside, moist and contaminated air. Vapor-phase corrosion inhibitors prevent corrosion during shipping and storage in warehouses that are protected from rain but are not heated.
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3.1.5 Corrosion Under Insulation Corrosion under insulation (CUI) is often considered to be a special case of atmospheric corrosion. NACE SP0198 provides guidance on the control of CUI. Figure 3.9 shows typical locations where you would expect corrosion to occur on outdoor insulated piping systems.
Figure 3.9 Problem Locations for Insulated Aboveground Pipelines
Many repairs and alterations to piping result in situations where the external moisture barriers (usually aluminum sheet metal) (Figure 3.10) are not repaired.
Figure 3.10 External Jacketing on Insulated Piping and Process Equipment
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Figure 3.11 and Figure 3.12 compares corroding wetted piping on an indoor chilled water pipe with the lack of corrosion on an outdoor steam system where the insulation was also removed. The differences between the chilled water system that is corroding and the steam system with minimal corrosion emphasize the importance of time of wetness.
Figure 3.11 Condensation Leading to Corrosion on Indoor Chilled-Water Pipe
Figure 3.12 Minimal Corrosion in the Exterior of Insulated Steam Line
Many organizations treat CUI by specifying the coating of carrier pipe with immersion-grade protective coatings qualified for the temperature of the service. Flame-sprayed aluminum is often specified for heated lines, but organic coatings are more common on chilled water systems.
3.2 Water All corrosion in water depends on water coming in contact with the containing metal surfaces. If the metal surfaces are hydrocarbon wetted, little or no corrosion will occur. This is why the inside walls of many crude oil storage tanks are not coated and do not corrode. Organic liquids can dissolve polymers (plastics), but they are generally benign to metals, except when they contain corrosive dissolved components. H2S gas dissolved in hydrocarbons can produce hydrogen embrittlement, but this is normally worse if water is also available.
3.2.1 Dissolved gases Corrosion cannot occur if some other chemical is not available to be reduced. The reducible species often comes from dissolved gases.
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Hot water condensate return lines in power plants are made from carbon steel. They only corrode if air, containing CO2 and oxygen enters the system, e.g., through defective seals or valves. Because these lines need to handle differing amounts of liquid depending on the power load, they are only wetted along the bottom (6 o'clock position). This corrosion is sometimes called condensate channeling in the power-generation business. A similar pattern occurs in horizontal gathering lines in oil production. Most wells produce a combination of oil and water. The water may separate to the bottom of the lines and cause corrosion if CO2 or oxygen enters the system. This produces the same pattern of channeling along the bottom of the line. Note that Figure 3.13 shows that the corrosive water level has varied to produce channeling at two different levels. Figure 3.14 shows common gases that accelerate corrosion: • Oxygen—most corrosive of the common gases, because it can be directly reduced, which allows corrosion to proceed •
CO2—dissociates to produce a weak mineral acid containing some reducible hydrogen ions
•
H2S—dissociates to produce a weak mineral acid; can also lead to hydrogen embrittlement
Figure 3.13 Condensate Channeling Corrosion in Gathering Line6
Figure 3.14 Effect of Dissolved Gases on the Corrosion of Carbon Steel7
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3.2.2 Effects of Dissolved Salts Pure water (pH=7) is essentially non-ionic and is a very good insulator. Pure water is non-corrosive. Salt water is more corrosive than fresh water. Figure 3.15 shows the combined effects of dissolved air and salt concentration on the corrosivity of water. As increasing amounts of salt are added to water, the electrical conductivity increases and so does the corrosion rate. At the same time, the oxygen solubility decreases with Figure 3.15 Corrosion Rate of Iron in Air-Exposed Water with additional salt concentrations, Varying Salt (Sodium Chloride) Concentrations8,9 and this limits the corrosion rate, because reduction of oxygen is the rate-controlling chemical reaction.8 Figure 3.15 also helps explain why salt water is more corrosive than fresh water. However, the most important point of Figure 3.15 is that, even at its most corrosive content (approximately 3%), depending on which salt is involved), only about one-third of the corrosion in salt water is due to salt—most of the corrosion would occur anyway due to the presence of oxygen. Figure 3.16 shows the corrosion rates of steel piling in seawater.10,11 The highest corrosion rates are in the splash zone, where the metal is frequently covered with air-saturated water. The relatively low corrosion rates in the tidal region are due to oxygen concentration cells between the air-saturated water in the tidal zone and the lower concentrations in the fully submerged zone below it. The tidal zone, high in oxygen, is cathodic to the fully submerged zone just below, which is anodic. As the water deepens, the oxygen concentrations decrease and so does the corrosion rate. Figure 3.16 Zones of Corrosion for Steel Piling in Seawater10,11
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3.2.3 pH Figure 3.17 shows the effects of pH on the corrosion rate of iron and steel. In the pH range from 4–10, the metal surface is covered with rust, a partially protective passive film, but the corrosion rate is still high enough that corrosion control efforts such as protective coatings, cathodic protection, or corrosion inhibitors are often necessary. At higher pHs, the metal becomes covered with mineral scales which cover the surface and provide increasing protection. At low pHs, the acidic environment dissolves any protective films and exposes bare metal to corrosion.2,8
Figure 3.17 Effect of pH on the Corrosion Rate of Iron in Water at Room Temperature2,8
Figure 3.18 shows a similar plot of the corrosion rate of zinc in water with different pHs. Zinc, aluminum, and cadmium are sometimes called the amphoteric coating metals. They all have the same amphoteric properties of corroding at low rates (below carbon steel) in neutral environments and at higher rates in both acids and bases. Pure water becomes more ionic at elevated temperatures. Pure water becomes more ionic at elevated temperatures. Figure 3.19 shows how neutral pH—the pH at which equal concentrations of H+ and OH– ions are in solution—decreases with increasing temperature. Organizations that need to determine pH at elevated temperatures usually use software calculations to determine the in situ pH. This is common for steam generation, chemical processing, and downhole oil and gas pH determinations.
Figure 3.18 Corrosion Rate of Zinc in Water at Different pHs10
Figure 3.19 pH of Pure Water at Various Temperatures1
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3.2.4 Effects of Mineral Deposits The chemical species that form with CO2 depend on the pH of the system as shown in Figure 3.21. The solubility of CO2 varies with both temperature and pressure. As both temperature and pressure change in oil wells, calcium-rich mineral deposits may form on the inside of the upward-flowing production tubing, which frequently produce more salty water than oil. Figure 3.21 shows calcium carbonate scale on the inside of oil-well tubing. Figure 3.22 shows similar scale, gypsum— calcium sulfate, that formed in a different well. Both of these scales protect the underlying metal from corrosion, but they also restrict fluid Figure 3.20 Carbonic Acid, Bicarbonate Ion, and Carbonate flow. Distribution as a Function of pH
Figure 3.21 Calcium Carbonate (Calcite)
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Figure 3.22 Calcium Sulfate (Gypsum)
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Figure 3.23 shows similar deposits in low-quality steam piping. In the watertreatment business, low-quality steam is a term for water that is mostly vapor (steam) but also has microscopic liquid water droplets. Calcium- and magnesium-rich minerals can form from virtually any natural water. Drinking water suppliers deliberately send their water from the treatment plant slightly “hard,” which means they are oversaturated in calcium and magnesium, which causes the water to deposit thin mineral scales on metal surfaces.
3.2.5 Effects of Liquid Velocity Fluid velocities can affect corrosion rates: • Excess velocity can lead to increased corrosion (erosion corrosion), which is discussed in Chapter 5.
Figure 3.23 Boiler Scale in Steam Generating Piping
•
Emulsions, mixtures of immiscible liquids, can be noncorrosive if a hydrocarbon continuous phase surrounds a dispersed water phase. If the water phase is continuous, then corrosion will occur.
•
If liquids become stagnant, then phase separation can occur and water will wet the surrounding metal container. Corrosion caused by phase separation is shown in Figure 3.24 and Figure 3.25.
•
In low flow areas, solids or sediment can drop out, causing under-deposit corrosion.
•
Microbiologically influenced corrosion (MIC) is most often found in stagnant or low-flowrate liquid systems.
Figure 3.24 Corrosion Due to Water Separation at the 6 o'clock Position on a Low-Velocity Crude Oil Gathering Line
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Figure 3.25 Corrosion at the Bottom of an Aqueous Film-Forming Foam Piping System in an Aircraft Hangar
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3.2.6 Effects of Temperature •
High temperatures generally increase chemical reactions, including corrosion reactions.
•
High temperatures lower the solubility of dissolved gases as shown in Figure 3.26.
•
Pressure alters boiling points. Pressure vessels and downhole environments often have liquid water up to 250°C (400+°F).
•
The degree of ionization of water depends on temperature, and this alters the pH as previously noted in Figure 3.19. Figure 3.26 Changes in Oxygen Solubility in Water Exposed to Air at Various Temperatures10
3.2.7 Microbiologically-Influenced Corrosion Microbiologically-influenced corrosion (MIC) is a phenomenon that has been recognized for many years and is the subject of numerous books (see Figure 3.27). MIC and the bacteria that can produce MIC are classified in many ways. Bacteria can be classified as: • Planktonic bacteria that freely float or “swim” in a body of water •
Sessile bacteria that are attached to surfaces and become motionless
Many organizations collect water samples and determine the presence or absence of planktonic bacteria without recognizing that sessile bacteria, sampled by the use of insertion coupons or probes, is more important. Some of the most important types of bacteria associated with MIC are:12 • Sulfate-reducing bacteria (SRB) •
Iron-oxidizing bacteria (IOB)
•
Acid-producing bacteria (APB)
•
Sulfur-oxidizing bacteria (SOB)
•
Slime-forming bacteria
Figure 3.27 Pitting Under Microbial Deposits
MIC is usually controlled by a combination of mechanical cleaning to remove surface biofilms followed by injection of biocides on a continuous or batch basis depending on the system in question. MIC is often associated with pitting corrosion, but it can be found in conjunction with virtually any corrosion form.
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3.3 Soils Water and gas occupy much of the space between solid particles of soil, and these are important in determining the corrosivity of soils. The air-soil interface (Figure 3.28) is the most corrosive location for buried materials. Cathodic protection does not work on the loosely consolidated surface soil and corrosion control requires special attention—additional coatings and frequent inspections. Underground corrosion varies with soil types. The physical characteristics of soils affecting corrosion are primarily related to grain size and distribution, and moisture retention and aeration. In a soil that contains an Figure 3.28 Corroded Pipeline at the uneven distribution of particle sizes or large rocks, differential environment corrosion cells can be created. Air-to-Soil Interface1 Soils with otherwise benign characteristics can become very corrosive. Notice the discoloration in Figure 3.29, which may indicate different soil types that could cause corrosive conditions. Soil moisture and access to air frequently determine how much corrosion occurs on buried structures. Figure 3.30 shows the radial locations where corrosion is most likely to occur on buried pipe. The loose soil and air pockets at approximately 4 o'clock and 8 o'clock are the locations where air-saturated water will cause corrosion. Anaerobic bacteria are associated with stagnant water conditions, which are likely to occur in association with buried structures. Figure 3.29 Differing Soil Layers Leading to Differing Corrosive Environments
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Figure 3.30 Radial Locations Where Corrosion is Most Likely to Occur on Buried Pipelines1
3.4 High-Temperature Environments High-temperature gases can react directly with metals and cause corrosion, even in the absence of an electrolyte. This type of corrosion, sometimes also referred to as dry corrosion, is discussed in Chapter 5. • High-temperature corrosion does not require aqueous environments. •
High-temperature corrosion typically occurs in gaseous environments.
•
High-temperature environments can react directly with metals and cause corrosion.
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References: 1.
R. Heidersbach, Metallurgy and Corrosion in Oil and Gas Production, John Wiley & Sons, 2011.
2.
W. R. Revie and H. H. Uhlig, Corrosion and Corrosion Control, 4th Ed., Wiley-Interscience, New York, 2008.
3.
P. J. Sereda, S. G. Croll, and H. F. Slade, “Measurement of the Time-of-Wetness by Moisture Sensors and Their Calibration,” in Atmospheric Corrosion of Metals, ASTM STP 767, S. W. Dean and E. C.Rhea, eds., American Society for Testing and Materials, 1982, pp. 267-285.
4.
http://corrosion.ksc.nasa.gov/PAbeach.htm, March 5, 2012
5.
M. Hoffman, “Acid Fog,” Engineering Science, Vol. 48 (September 1984), pp. 5-11, http:// calteches.library.caltech.edu/3438/1/Hoffmann.pdf March 5, 2012
6.
H. Byars, Corrosion Control in Petroleum Production, NACE TPC Publication 5 (2nd Edition), 1999.
7.
A. Shankardass. Corrosion control in pipelines using oxygen stripping, OIlsands water usage workshop. 2004, Edmonton, Alberta, Canada, 2004.
8.
H. Uhlig, The Corrosion Handbook, John Wiley and Sons, New York, 1948, p. 131.
9.
B. Heidersbach, “What NACE Can Do for You,” Materials Performance, October 2009, pp. 9-11.
10. R. Baboian and R. Treseder, eds, NACE Corrosion Engineer's Reference Book, 3rd Ed., NACE, Houston, 2002. 11. F. LaQue, Marine Corrosion: Causes and Prevention, John Wiley & Sons, 1975. 12. NACE Report 31205, Selection, Application, and Evaluation of Biocides in the Oil and Gas Industry, 2006
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Chapter 4: Materials Upon completion of this chapter, students should be able to recognize the properties of and classify types of: • Metals •
Non-metals
•
Composites
•
Concrete
•
Ceramics
The most important materials for most engineering applications are metals, especially carbon steels. This chapter emphasizes the properties of carbon steels, but you can apply the principles associated with these alloys to most other materials used in corrosive environments.
4.1 Properties Materials are chosen for a number of reasons, and corrosion-resistance is often less important than strength, formability, cost, etc.
4.1.1 Metallurgy Fundamentals Virtually all metals used for engineering applications are alloys. Pure metals are used for electrical conductivity and for some corrosion-resistance applications, but whenever mechanical properties become important, designers choose alloys because they are stronger than pure metals. 4.1.1.1 Crystal Structure
Most solids, with the exception of glasses and organic materials, are crystalline in nature. This means that the atoms in the crystal are oriented in one of seven orientations, only three of which are common in metals. Figure 4.1 shows the two crystal structures found in most metals—body-centered cubic (Figure 4.1a) and face-centered cubic (Figure 4.1b). Zinc and titanium are the only commonly used metals that have the hexagonal-close packed crystal structure not shown in Figure 4.1. The body-centered cubic (BCC) structure (Figure 4.1a) found in room-temperature iron is stronger and less ductile than the face-centered cubic structure (FCC) that is found in high-temperature iron and in austenitic stainless steels, aluminum, copper, and other ductile metals. This is one reason why steel mills heat steel to high temperatures before many forming operations (e.g. hot rolling of plate to make large-diameter pipe or pressure vessels). Steel mills do not have equipment that can deform large steel structures when they are at ambient temperatures.
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Figure 4.1a Body-Centered Cubic 1
Crystal Structure
Figure 4.1b Face-Centered Cubic Crystal Structure
A solid metal contains many crystals. A typical crystal has millions of atoms, and defects in the structure are common. The combination of alloying additions, crystal size, and different crystal structures determines the mechanical and corrosion resistance properties of metals. Figure 4.2 shows how three crystals, with different orientations but the same chemistry, join and form grain boundaries. The grain boundaries, indicated by the dotted lines in Figure 4.2, have larger spaces between the atoms. Impurity atoms are most likely to be in these spaces. Unwanted segregation of impurity atoms to grain boundaries can cause major problems with corrosion resistance. Most metals are alloys. Alloying affects mechanical Figure 4.2 Grain Boundaries in a Metal properties and corrosion resistance. The effects of alloying on the metal microstructure can result in: • Atoms of similar size to the base metal fitting into the base-metal crystal structure, forming substitutional solid solutions as shown in Figure 4.3. •
Small atoms fitting between the larger atoms forming interstitial solid solutions as shown in Figure 4.4.
•
Carbon, oxygen, boron, and nitrogen may be used for interstitial case hardening of steel.
•
Hydrogen and helium are even smaller—too small to be controlled—and they can cause hydrogen or helium embrittlement.
•
New crystals, having different compositions and crystal structures than the base metal.
As an example, carbon steel usually has almost pure iron crystals plus a compound having the chemical formula Fe3C. This iron carbide phase gives steel greatly increased strength compared to pure iron. Two-phased metals are usually stronger than single-phased metals.
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Figure 4.3 Substitutional Solid Solution in a Crystalline Solid
2
Figure 4.4 Interstitial Solid Solution in a Crystalline Solid 2
4.1.1.2 Strengthening Methods
Metals are strengthened by: • Alloying—All metals used for strength are alloys of two or more different elements. •
Precipitation hardening—The metal is heat treated to produce crystals that would not form without special heat treatment.
•
Work hardening—The metals are deformed at low temperatures producing hardening due to deformation.
•
Grain size refinement—Metals with small crystals are stronger than metals with larger crystals.
•
Second-phase hardening—Steel is a good example of this.
4.1.1.3 Mechanical Properties
Metals are chosen for their strength and related mechanical properties, including: •
Tensile and yield strength
•
Toughness
•
Ductility
•
Fracture
•
Hardness
•
Stress concentrations
Strength Most metals are specified based on their strength. Most industrial specifications define strength targets for yield. Hardness Hardness is a material property that may be important for materials that will have wearing surfaces. Hardness testing is also used for field checking of mechanical strength, because tensile strength and hardness can be correlated. Ductility Ductility is the ability of a metal to be stretched in tension before it fractures. API Specification 5CT for oilfield tubing and casing requires a minimum elongation, depending on sample thickness, of between 8% and 30%.4 In addition to elongation before breaking, some definitions of ductility specify the reduction of cross section area before breaking as a measure of ductility. The opposite of ductility is brittleness. Some authorities consider any metal to be brittle if it has less than 5% elongation before breaking.
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Toughness Toughness is a measure of the resistance of a material to a propagating crack during impact loading. The opposite of ductility is brittleness. Toughness, as property, has gained importance in recent years, and has been added to many materials specifications. Toughness is a measure of the resistance of a material to a propagating crack during impact. Figure 4.5 shows the collapsed Point Pleasant Bridge that connected Point Pleasant, West Virginia with Kanauga, Ohio across the Ohio River. On a cold December day in 1967, a stress corrosion cracking failure caused the bridge to collapse in rush hour traffic, killing 46 commuters.
Figure 4.5 The Collapse of the Point Pleasant Bridge Across the Ohio River in 1967
Figure 4.6 Welded Ship That Cracked Due to DBTT Problems During Fabrication
A number of industrial failures resulted in the creation of impact testing, including the fracture of welded ships built during World War II as shown in Figure 4.6. Nonetheless, brittle failures still occur. Many engineers do not understand the concepts associated with ductile-brittle transition temperature (DBTT) failure. The structures shown in Figure 4.5 and Figure 4.6 were developed before engineers fully understood brittle failure. Figure 4.7 shows an interstate highway bridge that fractured due to ductile-brittle transition temperature problems in December 2000. Toughness depends on temperature. The refining and Figure 4.7 DBTT Cracking of an Interstate Highway Bridge in chemical-process industries have 2000 specified toughness for many years, because of concerns with expansive cooling associated with gas leaks. In 2000 API specifications for line pipe added nil-ductility temperature requirements to the line pipe specifications. This means that many miles (km) of high-pressure transmission piping have never been tested for toughness.
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DBTT concerns are important to corrosion because expansive cooling made several gas pipeline incidents worse (Joule-Thompson effect), leading to changes in API line pipe specifications in 2000. Before 2000 there were usually no controls on DBTT for upstream oil and gas line pipe, even though it was standard for many years in downstream (refinery) operations. Pipelines built prior to 2000 may have steel subject to brittle behavior if used in gas transmission service. While thus emphasizes high-pressure gas pipelines, the list is applicable to any gas-pressurized system. For many low-temperature applications, carbon steel may be inappropriate. Austenitic (FCC) stainless steel and aluminum are the preferred materials for cryogenic piping, storage and process vessels like the liquefied hydrogen tank shown in Figure 4.8. This is because face-centered cubic structure (FCC) alloys do not undergo a ductile-brittle transition, but rather remain tough regardless of temperature. Large stationary liquefied natural gas (LNG) storage tanks are often made from iron-9 nickel alloys. The nickel ensures toughness in these steels at LNG temperatures, but the DBTT is too high for use in liquefied hydrogen storage. Fracture Figure 4.8 Liquefied Hydrogen Storage Tank at the NASA Kennedy Space Center The forms of fracture for many metals are: • Overload (ductile) fracture •
Brittle fracture
•
Creep
•
Fatigue
Stress Concentrations Modern engineering designs have adopted the practice of avoiding sharp details (e.g. 90 degree angles with no rounding) on hatch covers and other procedures to limit the effects of stress concentrations. Stress concentrators raise the effective stress on a part and can cause brittle failures like those shown in Figure 4.5 and Figure 4.6. Examples of stress concentrators due to corrosion include stress corrosion cracks and corrosion pits.
4.1.2 Forming Methods Just like wood has different strength properties in different directions, metals reflect their forming properties. This results in different mechanical and corrosion resistance properties depending on how a metal is formed. 4.1.2.1 Wrought vs. Cast Structures
•
Wrought is defined as material structure altered by thermo-mechanical processes, e.g. rolling, extrusion, forging, drawing. –
•
Cast is defined as material structure achieved by solidification from the molten metal. –
•
Typically small grain size Typically large grain size
Cast metals typically have larger crystals and are weaker than wrought products.
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All wrought (deformed after solidification) metals have crystal structures that reflect their forming process. Rolled plate, which is used to manufacture large diameter pipe and pressure vessels, will have different microstructures and different mechanical properties in all three principal directions shown in Figure 4.9. The increased number of exposed grain boundaries on the shorttransverse direction usually leads to lower corrosion resistance than for the other directions. Castings tend to be weaker than wrought Figure 4.9 Principal Directions of Rolled Plate products, because their crystals are larger. They may also have porosity that would be eliminated by rolling or other deformation processes in wrought products. Typically, applications where complex shapes are more economical use castings instead of forming, machining, or welding wrought products into the desired shape. Many castings have thick cross sections that make them less subject to failure by localized corrosion, e.g. pitting corrosion. 4.1.2.2 Welding
Welding is the preferred joining method for many structures; especially those intended for immersion or buried service. Figure 4.10 shows typical defects in welds. Problems associated with welds that may affect their corrosion resistance include: • Heat-affected zones (HAZs)—The microstructures in HAZs can produce phase changes that may lead to HAZ corrosion. HAZs can also be harder than the weld metal or base metal, thus making it more prone to hydrogen embrittlement if not post-weld heat-treated.
Figure 4.10 Defects Associated with Welding
•
Porosity —This may provide stress concentrations.
•
Hard spots—These are martensitic inclusions caused by rapid cooling of the metal which doesn’t allow the more ductile ferrite-plus-cementite structure to form.
•
Cold cracking—Hydrogen cracking is the principle cause of this problem. Trapped hydrogen from the weld pool before solidification can cause hydrogen embrittlement.
•
Hot cracking—Also called sulfur cracking.
•
Lack of fusion—Sometimes the base metal does not melt, and the weld bead and the base metal do not join together in a continuous metal structure.
•
Incomplete penetration—The weld bead does not go deep enough into the surface of the parent metal.
•
Striking marks—These can cause hard spots.
•
Distortion of weld structures—This leads to the problems discussed in the following paragraph and is shown in Figure 4.11.
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Stresses caused by shrinkage of high-temperature welds adjacent to relatively low-temperature base metals can cause distortions like those shown in Figure 4.11. This can cause “wrinkling” of the bottoms of large tanks, leading to improper drainage.
Figure 4.11 Distortion of Exterior Plates Due to Weld Shrinkage
Figure 4.12 Spiral-Welded Pipeline Under Construction
Figure 4.12 shows a spiral-welded pipeline under construction. The possibility of defects in the welding process is higher in spiral-welded pipe because welding on a curve is harder than welding in a straight line, even in a factory. Many organizations try to avoid the use of spiral-welded pipe for hydrocarbon pipelines. The white markings in Figure 4.12 show where this pipe is also harder to coat and field-applied coating repairs were needed. Spiral welding is necessary for large diameter water pipes, which are 2 m (7 ft) or more in diameter. Steel mills cannot roll plate wide enough for longitudinally welded pipe of this diameter, and shipping by rail or highway would also prove difficult.
4.1.3 Materials Specifications Many organizations provide specifications for materials, and as a best practice you should order materials based on standardized materials specifications. Some specifications, e.g. the API specifications for oil-country-tubular goods (OCTGs), are performance specifications and define several options for how to achieve the desired mechanical properties.4 Table 4.1 shows the Unified Numbering System (UNS) for alloys.
Table 4.1: The Unified Numbering System for Alloys UNS Designation
Alloy System
Axxxxx
Aluminum Alloys
Cxxxxx
Copper Alloys, Including Brass And Bronze
Fxxxxx
Cast Iron
Gxxxxx
Carbon And Alloy Steels
Hxxxxx
Steels - Aisi H Steels
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Table 4.1: The Unified Numbering System for Alloys Jxxxxx
Steels - Cast
Kxxxxx
Steels, Including Maraging, Stainless Steel, Hsla, Iron-base Superalloys
M1xxxx
Magnesium Alloys
Nxxxxx
Nickel Alloys
Rxxxxx
Refractory Alloys
R03xxx
Molybdenum Alloys
R04xxx
Niobium (Columbium) Alloys
R05xxx
Tantalum Alloys
R3xxxx
Cobalt Alloys
R5xxxx
Titanium Alloys
R6xxxx
Zirconium Alloys
Sxxxxx
Stainless Steels, Including Precipitation Hardening Stainless Steel And Iron-based Superalloys
Txxxxx
Tool Steels
Zxxxxx
Zinc Alloys
NACE and other standards frequently refer to API, UNS, or other standardized alloy designation systems.
4.2 Metals 4.2.1 Carbon Steel and Low Alloy Steels 4.2.1.1 Carbon Steel
Carbon steel is the most commonly used metal in industry. Depending on the chemistry, primarily carbon content, and the heat treatment history, carbon steel can vary in yield strength from about 250 MPa (36 ksi) for structural steel to over 1380 MPa (200 ksi) for wire line. These materials normally contain approximately 0.2% carbon, although this varies widely. 4.2.1.2 Low-Alloy Steels
A common definition of low-alloy steel is steels with alloying contents of 8% or 9%. Most authorities consider low-alloy steels as alternatives to carbon steels. They are usually specified for their improved mechanical properties, e.g. in pressure-vessels, boiler, and other high-temperature applications. They are usually cathodic to carbon steels, but, like carbon steels, they normally have insufficient corrosion resistance to be used without corrosion protection in the form of cathodic protection, protective coatings, or corrosion inhibitors.
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Weathering Steels Weathering steels contain trace amounts of copper and can develop protective corrosion product films in certain atmospheric environments. They are typically not painted and are used when no painting is required for atmospheric exposure. The have been marketed under names such as Cor Ten, Mayari, etc. and are available in accordance with several different ASTM specifications.5, 6 Construction and shipping containers are the primary applications of weathering steels. They are stronger than ordinary carbon steels. Typical applications include highway bridge beams (Figure 4.13) and guardrails and high-voltage transmission poles. These metals are no better than conventional carbon steels in buried or immersion service, and they require protective coatings (sometimes supplemented by cathodic protection) when used for these applications.
Figure 4.13 Weathering Steel Bridge Beams (Protective Rust Film Formed on Surface Indicated by Arrow)
4.2.2 Cast Irons Cast irons are alloys of iron and carbon having approximately ten times the carbon content of typical carbon steels. The carbon is usually in the form of graphite flakes (gray iron) or spherical nodules (ductile iron) (except in white cast irons, where it is cementite, Fe3C). They are brittle materials (Figure 4.14). Cast iron classifications include: • Gray cast iron is the original cast iron shown in Figure 4.15. It has long flakes of graphite as the non-metallic phase, and has been replaced for most corrosion service (e.g. water and drain pipes) by modern cast irons—either nodular or malleable cast iron.
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Figure 4.14 Brittle Fracture of a Cast Iron Water Pipe
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•
White cast iron has less silicon than grey cast iron, which causes the microstructure to form as iron carbide instead of the iron-plus-graphite structures found in most other cast irons. The same microstructure can be produced by quickly chilling the surface of the casting, but this usually results in a “chill layer” of white cast iron on the surface with the interior of the casting being grey cast iron. Applications where extreme surface hardness is advantageous, such as slurry pumps requiring wear resistance, use white cast iron.
•
Nodular cast iron is often called ductile cast iron, even though the ductility is much lower than carbon steel. Nodular cast iron has rounded graphite nodules, produced by adding either magnesium or cerium to the melted metal, instead of the flakes found in grey cast iron as shown in Figure 4.16. This makes the material less brittle.
•
Malleable cast iron is produced by heat-treating white cast iron, which causes the iron carbide to transform into rounded graphite. Its properties are similar to nodular cast iron.
•
High silicon (typically 14% Si) is brittle and used extensively for impressed current cathodic protection anodes. These anodes are resistant in many corrosive environments.
Figure 4.15 Flakes of Graphite in the Microstructure of Gray Cast Iron
Figure 4.16 Rounded Nodules of Graphite in Ductile (Nodular) Cast Iron
4.2.3 Stainless Steels Stainless steels are the most commonly used corrosion resistant alloys (CRAs). NACE defines CRAs as alloys whose mass loss rate in produced fluids is at least an order of magnitude less than that of carbon and low alloy steel.7 Stainless steels are normally classified based on their microstructure, and usually are defined as iron-based alloys having at least 11% chromium by weight. Figure 4.17 and Figure 4.18 show two applications of austenitic stainless steel from the oil and gas processing industry. The major classes of stainless steels are: martensitic, ferritic, austenitic (and superaustenitic), duplex (and superduplex), and precipitation hardening. The corrosion resistance of stainless steels depends on many factors which include alloy composition and environmental parameters such as chloride content, pH, temperature, etc. The Pitting Resistance Equivalent Number (PREN) is sometimes used to provide a qualitative indication of corrosion resistance of stainless steels. It is based on an empirical formula such as:
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PREN = wt% Cr + 3.3 x wt% Mo + 16 x wt% N A higher PREN value generally indicates greater resistance. However, there is no threshold PREN which indicates complete corrosion resistance in all environments.
Figure 4.17 Stainless Steel Equipment Meter Runs in Wet CO2 Service
Figure 4.18 Stainless Steel Equipment Bubble Trays in Gas Stripping Tower
4.2.3.1 Martensitic
The major alloying addition in martensitic stainless steels is chromium in the range of 11%–17%. The carbon levels can vary from 0.10%–0.65% in these alloys. The high carbon enables the material to be hardened by heating to a high temperature, followed by rapid cooling (quenching). Martensitic types offer a good combination of moderate corrosion resistance and superior mechanical properties, as produced by heat treatment to develop maximum hardness, strength, and resistance to abrasion and erosion. End uses include cutlery, scissors, surgical instruments, wear plates, garbage disposal shredder lugs, industrial knives, and steam turbine blades. Martensitic stainless steels are magnetic. Table 4.2 lists some selected martensitic stainless steels including API and UNS specifications. Upstream oil and gas production uses martensitic stainless steels, commonly called 13Cr alloys. They are used as oil-country-tubular goods (OCTGs) and in well-head and other applications where their increased corrosion resistance over carbon steels is an advantage in hydrocarbon service. These alloys require protective coatings and cathodic protection when used for pipelines—they are not adequately corrosion resistant for direct burial or long-term immersion service.2 Cathodic over-protection can lead to hydrogen embrittlement.
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Table 4.2: Selected Martensitic Stainless Steels UNS Designation
Common Name
C max
Fe
Cr
Ni
Mo
Other
S41000
410
0.15
bal
12.5
S41425
Super 13Cr
0.05
bal
13.5
5.5
1.75
Cu 0.3
S41426
Super 13Cr
0.03
bal
12.5
5.5
2.25
Ti 0.01, V 0.5
S41427
Super 13Cr
0.03
bal
12.5
5.3
2
Ti 0.01, V 0.3
S42000
420
0.15
bal
13
K90941
9Cr 1Mo
0.15
bal
9
J91150
CA 15
0.15
bal
12.75
API L80 9Cr
0.15
bal
9
0.5 max
1
API L80 13Cr
0.15–0.22
bal
13
0.5 max
4.2.3.2 Ferritic
Ferritic stainless steels have higher chromium levels than martensitic stainless steels. This makes them more corrosion resistant in some environments. Ferritic stainless steels are magnetic, generally have good ductility, and can be welded and/or fabricated without difficulty. These grades can be processed to develop an aesthetically pleasing, bright finish, so they are sometimes used for automotive trim and appliance molding. Functional applications in which cost is a major factor, such as automotive exhaust systems, catalytic converters, radiator caps, and chimney liners use ferritic stainless steel. Ferritic stainless steel can be hardened by cold rolling, but cannot be hardened as much as the austenitic alloys. Table 4.3 lists some common ferritic stainless steels.
Table 4.3: Selected Ferritic Stainless Steels UNS Designation
Common Name
C max
Fe
Cr
S40500
405 SS
0.08
bal
11.5–14.5
S43000
430 SS
0.12
bal
16.0–18.0
S44635
26-1 Cb
0.10
bal
25.0–27.0
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Mo
Other Al 0.10–0.30
0.75–2.50
Nb 0.05–0.20
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4.2.3.3 Austenitic and Super-Austenitic
The majority of stainless steel used worldwide is austenitic stainless steels. These alloys are ductile because of their FCC structure, which also means they cannot be heat-treated for strength. Austenitic stainless steel includes both the 200- and 300-series alloys, which can be hardened by cold working. The 300-series alloys contain chromium and nickel as their major alloying additions. Type 304, also known as 18-8, is the most widely used of all stainless steel alloys. Table 4.4 shows the composition of selected austenitic stainless steels.
Table 4.4: Selected Austenitic Stainless Steels* UNS Designation
Common Name
C max
Cr
Ni
Mo
Other
S30400
304SS
0.08
19
9.25
S30403
304L
0.03
19
9.25
S31600
316SS
0.08
17
12
2.5
S31603
316L SS
0.03
17
12
2.5
S31700
317 SS
0.08
19
13
3.5
S32100
321 SS
0.08
18
10.5
Timin = 5x %C
S34700
347 SS
0.08
18
11
(Nb+Ta)min = 10x %C
* The compositions shown in this table are the averages between the minimum and maximum levels.
The 304 stainless is the “standard” austenitic stainless steel. Type 316 has Mo additions to limit pitting and crevice corrosion resistance. Austenitic stainless steels are subject to sensitization— the formation of unwanted chromium carbides in grain boundaries leading to accelerated corrosion due to chromium depletion in grain boundaries. Sensitization can be caused by the heat input of welding, for example in heat-affected zones (HAZs), or by long-term exposure to elevated temperature. Limiting the carbon content of the alloy can minimize sensitization due to welding, but is not effective for mitigating sensitization when caused by long-term elevated temperature exposure. Types 304L and 316L stainless steel have lower maximum allowable carbon contents than 304 and 316 (0.03 C vs. 0.08 C max). Type 317 SS has a higher Mo content requirement than 316. Many organizations that used 316 SS have switched to 317 SS whenever products in this alloy are available. This is predicted to produce greater pitting and crevice corrosion resistance. The higher Mo content is also required for adequate corrosion resistance to naphthenic acid in petroleum refinery crude distillation units. The 200 series alloys possess mechanical and corrosion resisting properties similar to 300 series materials. They also exhibit high hardness and yield strength as well as excellent ductility and are usually non-magnetic. The 200 series alloys were originally developed to conserve nickel by replacing it with manganese at a ratio of 2% manganese for each 1% of nickel replaced. This reduced nickel content results in the 200 series alloys having a lower and more stable cost than the 300 series materials.
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Super-Austenitic Highly-alloyed FCC alloys often are called super-austenitic stainless steels. Table 4.5 lists several of these alloys. The UNS designations for the alloys indicate they are either stainless or nickel alloys (S or N designation in UNS). Pure nickel is FCC, so the crystal structure of these alloys is FCC if iron or nickel is the predominant component. All of these alloys are called highly-alloyed austenitic stainless steels in NACE MR0175/ISO 15156.8 Many of these alloys contain less than 50% iron. They contain 4–6% molybdenum to improve resistance to chloride environments. They are about 50% stronger than austenitic stainless steels.
Table 4.5: Nominal Composition of Selected Highly-Alloyed Austenitic Stainless Steels UNS Designation
Common Name
C max
Cr
Ni
Mo
Cu
S31254
254SMO
0.02
20
18
6.25
0.75
N08029
20Cb3
0.07
20
35
2.5
3.5
N08367
AL6XN
0.03
21
24.5
6.5
N08904
904L
0.02
21
25.5
4.5
1.5
4.2.3.4 Precipitation-Hardening
Precipitation-hardening (PH) stainless steels are based on the general composition of 17 Cr-4 Ni, and this nickel content is lower than the 18-8 austenitic alloys listed in Table 4.6. These alloys are often specified when close dimensional tolerances are needed. The alloys can be machined in the soft state, and then heat treated to improved mechanical properties. These materials can be hardened to a strength up to 200 ksi (1350 MPa). Austenitic stainless steels, which are intended to be single-phased FCC metals cannot be heat treated for this purpose. Table 4.6 shows selected precipitation hardening alloys.
Table 4.6: Nominal Composition of Selected Precipitation-Hardening Stainless Steels UNS Designation
Common Name
C max
Fe
Cr
Ni
Mo
Other
S66286
A286
0.08
bal
14.75
25.5
1.25
Ti = 2.12, B 0.001–0.01, V 0.10–0.50
S17400
17-4 PH
0.07
bal
16.25
4.0
S15500
15-5 PH
0.07
bal
14.75
4.5
S15700
PH 15-7 Mo
0.09
bal
15
7
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Comments Austenitic
Martensitic Cu = 3.5 2.5
Martensitic Martensitic
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4.2.3.5 Duplex and Super Duplex
Duplex stainless steels have a combination of ferrite and austenite (approximately 50/50) in their microstructure. Ferrite is the continuous phase while austenite is the discontinuous phase. Duplex stainless steels have similar pitting resistance to austenitic stainless steels, but their chloride stresscorrosion-cracking resistance is superior due to ferrite being the continuous phase. (Austenite is susceptible to chloride SCC, and ferrite is susceptible to H2S.) These materials are about twice as strong as commonly-used austenitic stainless steels. Table 4.7 shows selected duplex stainless steel compositions.
Table 4.7: Nominal Composition of Selected Duplex and Super Duplex Stainless Steels UNS Designation
Common Name
Type
C max
Cr
Ni
Mo
Fe
N
S31803
2205
Duplex stainless steel
0.03
22
5
3
bal
0.15
S32750
2507
Super duplex stainless steel
0.03
25
7
4
bal
0.28
4.2.3.6 Nickel-Based Alloys
Nickel alloys generally provide a good combination of corrosion resistance, mechanical properties (especially ductility) and fabricability. The ability of nickel to contain greater amounts of alloying additions (such as Cr, Mo, W) enhances corrosion resistance compared to stainless steels in many environments. Even highly alloyed stainless steels (e.g. superaustenitics) with Fe content of < 50% can almost be considered as “borderline” nickel alloys in terms of their structure and corrosion behavior. In fact, some highly alloyed stainless steels have been designated as Nxxxxx in lieu of Sxxxxx in the UNS system. Compositions of typical nickel alloys are given in Table 4.8. Alloy Ni-200 exhibits high corrosion resistance in uncontaminated caustic (NaOH and KOH) environments over a wide range of concentrations and temperatures (including molten state). However, alloy Ni-200 is not resistant to NH4OH solutions. Ni-Cr-Fe alloy-600 and Fe-Ni-Cr alloy-800 find utility in nuclear steam generator service. Alloy690 is a newer alloy with significantly more resistance to corrosion in this application. It is also more resistant to SCC by caustic which can form and concentrate at tubesheets. Ni-Mo alloy B-3 is highly resistant to pure, deaerated HCl and H2SO4 acids but may be rapidly attacked by oxidizing impurities such as O2 and Fe3+ ions. In contrast, these impurities can be beneficial in imparting passivity for Ni-Cr-Mo alloys such as alloys G3, G30, 825, 625, C276, C22. However, chlorides can accelerate attack, the degree of acceleration depending on the specific alloy, environment composition, pH and temperature. In general, the higher Cr-containing alloys aid resistance in oxidizing acids (e.g. conc. HNO3, conc. H2SO4) while the higher-Mo content is detrimental. In reducing acids (e.g. HCl, dil. H2SO4, H3PO4) the influence of these alloying additions is typically opposite. Nickel alloys are quite resistant to organic acids in the absence of contaminants. Alloys such as 825, 925, G-3, C-276 are used in sour gas (H2S) and refinery applications. Ni-Cu alloy-400 is resistant to deaerated HF acid; but may be susceptible to SCC in HF vapor environments. Alloy-400 is used in seawater applications for fasteners and pump and propeller shafts. Alloy K-500 is the age hardened version of alloy 400 where higher strength is required. Both alloys are resistant to corrosion in fast flowing seawater and where crevices are absent. They do pit under fouling deposit in quiescent seawater but the pit depth rarely exceeds ~ 1 mm. Unlike
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CuNi alloys such as 90/10 and 70/30, alloy-400 and K-500 are not antifouling toward marine macro-organisms such as barnacles, clams, oysters, etc. Alloy 400 because of its high resistance to natural atmospheres is also used for outdoor architectural applications, e.g. roofs, flashing, gutters and sculptures. Since SCC resistance, in general, increases at higher Ni and Mo contents, nickel alloys are often used where stainless steels have failed by this corrosion mechanism. However, Ni-based alloys are not immune to attack under any conditions. They can suffer from SCC at higher temperatures (e.g. >200ºC[392ºF]), higher chloride levels (e.g. >50,000 ppm), acidic pH (e.g. 0.5 V) can result in very high corrosion rates. The high electrical resistivity of sound concrete reduces the intensity of this attack, but the electrical resistivity of concrete is reduced by many of the same factors that allow corrosion of the embedded steel.
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4.5.2.8 Chemical Reactions of Aggregate
The alkalinity inherent in Portland cement concrete can cause chemical attack of some aggregates, particularly those high in silica. The reaction commonly causes expansion of the aggregate, with resultant cracking and spalling of the concrete. Expansive aggregates should be tested for and avoided. Be sure that the aggregates to be used have been tested and have been found to be nonreactive. Many structures, including dams and buildings, have been torn down because the use of reactive aggregates made the structures unsafe.
4.5.3 Repair of Concrete Damage to concrete structures can be repaired in many ways. • The damaged concrete must be removed and the exposed concrete surfaces must be properly prepared to accept the repair. •
Bonding agents to improve the adhesion of the new concrete to the old concrete are often used.
•
Corroded reinforcing steel must be replaced by splicing new bars to sound stubs of the reinforcement in the structure.
•
New concrete can be added using several methods: –
Forms can be erected and the new concrete placed in a manner similar to new construction. In the dry-pack system, blended fine aggregate and cement with a minimum of water is used. Water from the surrounding environment, or an applied spray, provides additional water. In some cases, particularly for underwater repairs, the coarse aggregate is pre-placed in forms and the fine aggregate-cement mixture is pumped into the voids between the coarse aggregate.
–
Shotcrete, where cement and fine aggregate are sprayed using compressed air and a special gun, is widely used when the thickness of the repair is not too great.
–
Toppings of fine aggregate and cement are also commonly used to repair surface damage from abrasion or limited chemical attack.
One factor frequently overlooked in repair of reinforced concrete is that the steel exposed to the fresh sound concrete in the repaired area is usually very passive. Electrical contact between the reinforcement in the repaired area and the less passive reinforcement in the original structure can result in a corrosion cell. The zone at the interface between the original structure and the repair is particularly vulnerable. This effect can be counteracted by coating the reinforcement in the repair area, thus effectively reducing the exposed cathodic area. 4.5.3.1 Use of Protective Coatings
Coatings may be used on concrete to increase its resistance to deterioration. Most coatings are intended to reduce the intrusion of water into the concrete. This can improve freeze-thaw performance, protect the substrate from aggressive environments, and reduce the corrosion of embedded reinforcement. The surface of concrete is alkaline, and many coating materials do not bond well to alkaline surfaces. Coatings compatible with alkaline environments must be used. The coatings must be abrasion-resistant and resistant to the environment. 4.5.3.2 Aqueous Environments
Soft water tends to leach calcium from the cement paste and can rapidly attack Portland cement concrete. This frequently occurs in tanks, dams, and intake structures. Acidic waters can also attack the cement pastes, aggregates, and reinforcing steel as described above. Sulfates, particularly in seawater, can attack concrete unless Type V Portland cement is used.
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4.5.3.3 Underground Environments
Concrete is frequently used in contact with soil. It may be on the surface or buried in such structures as footings, piers, tanks, and pipes. Soil environments may attack aggressively if the pH is less than 6; if the pH is neutral but hydrogen ions are available; if there is a high sulfate, sulfide, or chloride content; or if there is a high content of magnesia (MgO) content. Type V cements should be used where sulfate attack is possible. Concrete is the most widely used ceramic construction material. Many ceramic materials are acidic (e.g. silicon glasses, quartz, etc.), but concrete is a base with a pH of approximately 12.8 according to many estimates. This means that concrete will deposit protective scales (mineral deposits) on embedded metal surfaces (these surface deposits are often termed passive films). Concrete is a widely used structural material that is frequently reinforced with carbon steel reinforcing rods, post tensioning cable, or pre stressing wires. The steel maintains the strength of the structure, but it is subject to corrosion. The cracking associated with corrosion in concrete is a major concern in marine environments and in areas that use deicing salts. There are two theories on how corrosion in concrete occurs: • Salts and other chemicals enter the concrete and cause corrosion. Corrosion of the metal leads to expansive forces that cause cracking of the concrete structure. •
Cracks in the concrete allow moisture and salts to reach the metal surface and cause corrosion of the steel rebar.
In new construction, concrete corrosion usually is controlled by embedding the steel deep enough so that chemicals from the surface don't reach the steel (adequate depth of cover). Other controls include keeping the water/cement ratio below 0.4, having a high cement factor, proper detailing to prevent cracking and ponding, and the use of chemical admixtures. These methods are very effective, and most concrete structures, even in marine environments, do not corrode. Unfortunately, some concrete structures do corrode. When this happens, remedial action can include repairing the cracked and spalled concrete, coating the surface to prevent further entry of corrosive chemicals into the structure, and cathodic protection, an electrical means of corrosion control. 4.5.3.4 Composition
Concrete is a composite construction material composed primarily of: • Aggregate
•
–
Coarse aggregate (rocks)
–
Fine aggregate (sand)
Cement paste –
Cement plus water → cement paste
–
Portland cement, based on calcium, silicon, and aluminum oxides, is the most commonly used cement, but specialty cements, e.g. for high temperature refractories or for exposure to acids are also available.
–
The water/cement ratio determines the strength of the cement paste, which acts as a binder for aggregates and reinforcement. Low water/cement ratios lead to stronger, less permeable, more durable concrete.
•
Reinforcement: Steel reinforcement provides minimal tensile strength (concrete is usually loaded in compression) and also stops cracking.
•
Chemical admixtures
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4.5.3.5 Degradation
Concrete has a number of degradation mechanisms including: • Freeze thaw damage (Figure 4.30) •
Acid base reactions (Figure 4.31)
•
Shear cracking
•
Vibration induced cracking
•
Corrosion of embedded steel (Figure 4.32, Figure 4.33, and Figure 4.34) Figure 4.30 Freeze-Thaw Damage on Concrete
Figure 4.31 Acid Attack Due to Spilled Chemicals on a Concrete Floor Slab
Figure 4.32 Rust Oozing From Cracks Formed in Concrete Due to Corrosion of Reinforced Steel in Sea Wall
Figure 4.33 Reinforcing Steel on Highway Bridge Deck; Most of the Steel is in Good Condition Due to the Alkalinity (High pH) of the Concrete Environment
Figure 4.34 Pitting Corrosion of the Base of an Aluminum Guard Rail on a Causeway Near the Atlantic Ocean
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Materials
Most steel embedded in concrete is protected by the high pH environment. Most of the exposed steel in Figure 4.33 is uncorroded, because steel corrosion rates are low in strongly alkaline environments, and concrete has a pH of nearly 13. This is in contrast with the overall roughening and deep pitting incurred by aluminum as shown in Figure 4.34. Unlike steel, aluminum is an amphoteric metal with high corrosion rates in alkaline environments.
4.6 Ceramics Ceramic materials are inorganic, non-metallic materials. Many ceramics are crystalline, but glass, a common ceramic material, is amorphous. Most ceramics are compounds or metals with non-metals (usually oxides), but diamond, which has all of the other properties of ceramics, is also considered a ceramic. Porcelain and glass linings are often used for corrosion control. Ceramic linings are brittle and subject to mechanical cracking, but they are chemically resistant to many environments. Ceramic materials are widely used for specific applications where their brittleness (lack of ductility) is acceptable. Ceramic materials include: • Ceramics •
Acid brick
•
Stoneware and porcelain
•
Glass
•
Vitreous silica
Some of these materials, particularly ceramics and glass, may be used as a fused coating over steel or other metals.
4.6.1 Ceramic Materials vs. Metals In general, ceramic materials: • Are more resistant to high temperatures (below their melting points) •
Have better erosion and erosion-corrosion resistance
•
Have better corrosion resistance (except to hydrofluoric acid and caustics)
•
Are better electrical insulators
•
Are more brittle
•
Are weaker in tension
•
Are more susceptible to thermal shock
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References: 1. W. D. Callister and D. G. Renthwisch, Fundamentals of Materials Science and Engineering: An Integrated Approach, John Wiley & Sons, Hoboken, NJ, 2008. 2. R. Heidersbach, Metallurgy and Corrosion Control in Oil and Gas Production, John Wiley and Sons, Hoboken, NJ, 2011. 3. API 5CT/ISO 11960, “Specification for Casing and Tubing.” 4. SAE E527/ASTM DS-561, “Numbering Metals & Alloys in the Unified Numbering System.” 5. ASTM A242/A242M, “Standard Specification for High-Strength Low-Alloy Structural Steel.” 6. ASTM A606, “Standard Specification for Steel, Sheet and Strip, High-Strength, Low-Alloy, HotRolled and Cold-Rolled, with Improved Atmospheric Corrosion Resistance Steel.” 7. NACE 1F192, “Use of Corrosion-Resistant Alloys in Oilfield Environments.” 8. ANSI/NACE MRO175/ISO15156-1, “Materials for use in H2S-containing Environments in Oil and Gas Production—Part 3: Cracking-Resistant CRAs and Other Alloys.” 9. R. Baboian and R. S. Treseder, NACE Corrosion Engineer’s Reference Book, NACE, Houston, TX, 2002. 10. S. Dexter, “Microbiologically Influenced Corrosion,” in Metals Handbook, Volume 13A—Corrosion Fundamentals, Testing, and Protection, Environments and Industries, S. D.Cramer and B. S. Covino, eds., ASM International, Materials Park, OH, 2003, pp. 399-416. 11. API RP 14G, Recommended Practice for Fire Prevention and Control on Fixed Open-Type Offshore Production Platforms. 12. W. Bogaerts and K. S. Agema, Active Library® on Corrosion, NACE-Elsevier, Houston, TX, 1991.
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Chapter 5: Forms of Corrosion Upon completion of this chapter, students will have an understanding of: • Forms of corrosion •
How to recognize each form
•
Materials subject to each form
•
Environments that promote each form
•
Control of each form
This chapter discusses the various forms of corrosion. Along with describing each type of corrosion, this chapter will discuss specific mechanisms that result in corrosion. Rates of attack and ways of measuring and predicting each form of corrosion will be discussed. Finally, methods that can be used to control each type of corrosion will be detailed. Only through a thorough understanding of the mechanisms responsible for each form of corrosion can appropriate control measures be identified and implemented.
5.1 Forms of Corrosion The following forms of corrosion will be discussed: • General Corrosion •
Localized Corrosion –
Pitting
–
Crevice
–
Filiform
•
Galvanic Corrosion
•
Environmental Cracking
•
–
Stress corrosion cracking
–
Hydrogen-induced cracking and sulfide stress cracking
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Liquid metal embrittlement
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Corrosion fatigue
Flow-Assisted Corrosion –
Erosion-corrosion
–
Impingement
–
Cavitation
•
Intergranular Corrosion
•
Dealloying
•
Fretting Corrosion
•
High-Temperature Oxidation/Corrosion
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5.1.1 Combination of Forms In most cases, the combination of the metals used in structures and equipment, coupled with the wide range of environments encountered, will result in more than one form of corrosion within a system. Even a single alloy, exposed to different environments at different points within the system, can undergo more than one type of attack.
5.2 General Corrosion 5.2.1 Definition and Description General corrosion is attack that proceeds more or less uniformly over the exposed surface without appreciable localization of attack (Figure 5.1, Figure 5.2, Figure 5.3). General attack corrosion is also called general corrosion, or uniform corrosion. For sheet or plate materials, this leads to relatively uniform thinning. For round bars or wires, corrosion proceeds radially inward at essentially a uniform rate around the entire circumference. The result is the production of a bar or wire of progressively smaller diameter. Pipe and tubing that suffer general corrosion are thinned from one side or the other (or both), depending on the nature of the exposure to the corrosive environment. Misapplying materials in corrosive environments often results in severe general corrosion.
Figure 5.1 Cross-Section of a Carbon Steel Tray in an Amine-Sweetening Unit 1
Figure 5.2 General Corrosion Underneath Disbonded Coating; Note Rippled Surface
1
Figure 5.3 General corrosion along the bottom of a gas well flow line where acidic condensate thinned the bottom of this horizontal piping. The two sets of corrosion grooves show that the acidic water flowed at two different levels during the lifetime of this equipment.2
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5.2.2 Recognition General attack corrosion can be recognized by a roughening of the surface and by the presence of corrosion products. In some cases, however, the corrosion products may not be present, as they can be soluble or can be removed by the action of wind, rain or other forces.
5.2.3 Mechanism The mechanism of general attack is typically an electrochemical process taking place on the surface of the material. The anodes and cathodes are caused by minor differences in composition or orientation between small areas on the metal surface. These sites change their potential with respect to surrounding areas, and the corrosion proceeds more or less uniformly over the surface. Of the many forms of corrosion, general attack is perhaps the least insidious, since the life of a part that is subject only to truly general attack may be readily predictable.
5.2.4 Corrosion Rates Depending on the specific material and environment, the rate of general corrosion (Figure 5.4) may be: • Linear •
Decreasing with time
•
Increasing with time
5.2.5 Predictability and Measurement When corrosion rates are linear or decrease with time, long-term projections of corrosion damage are possible. When corrosion rates increase with time, it is Figure 5.4 Corrosion Rates vs. Time much more difficult to predict long-term corrosion damage. General attack corrosion is usually measured in terms of penetration rates per unit of time in millimeters per year or mils per year. Experimental measurement of general attack corrosion is usually made by measuring weight loss and calculating the equivalent loss of metal thickness. Both in experimental measurements and in the field, loss of thickness can be measured directly using a micrometer-caliper or ultrasonic thickness measurement instrument.
5.2.6 Performance of Metals and Alloys Carbon and low-alloy steels perform well in a wide variety of environments, including atmospheric exposure, immersion in natural waters and many chemicals, and underground. Copper and copper alloys also perform well in a wide variety of environments. Aluminum and aluminum alloys may be used where localized corrosion does not occur. Rates of uniform corrosion of aluminum can be very high in alkaline environments.
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5.2.7 Control of General Attack Corrosion When corrosion rates are low and are either linear or decrease with time, uniform corrosion can be tolerated without the need to control it. The effect of the corrosion loss is relatively easy to assess, and allowances can be made in the initial design for the anticipated loss in thickness. If the rate of attack is unacceptable (when it cannot reasonably be handled by a corrosion allowance, or where metal contamination cannot be tolerated), it may be necessary to modify the original design, either at the initial design stage or through modification after construction. In some cases, a more corrosion-resistant material can be used. The design can be changed to eliminate the corrosive condition. This may involve anything from a simple reorientation of surfaces to avoid features that trap and hold water to significant changes in operating conditions. If the environment can be controlled, such as by dehumidification of interior spaces or the addition of corrosion inhibitors to liquid environments, corrosion may be reduced to acceptable levels. Protective coatings are particularly effective in controlling uniform corrosion. When the coating is defective, or fails due to environmental exposure, only relatively slow uniform attack occurs. Recoating or local coating repair can stop the attack before it progresses far enough to cause a significant loss of material. Cathodic protection, a method which interferes with the flow of the current in the electrochemical cell, can be used in underground or immersion situations. We will cover cathodic protection in more detail later in this course. Some low-alloy steels have been formulated specifically to form tightly adherent, dense corrosion products that inhibit corrosion in some atmospheric environments. In environments where these protective corrosion products form, these “weathering steels” show low rates of corrosion, usually at a rate that decreases with time. These alloys are useful for many structural and architectural applications. In some environments, the corrosion products are not protective, and there is little or no reduction in corrosion over that of ordinary carbon and low-alloy steels.
5.3 Localized Corrosion Localized corrosion, unlike general attack corrosion, occurs at discrete sites on a metal surface. While corrosion activity at these sites may start and stop with changes in the environment and new sites may start corroding, corrosion is concentrated at these sites. The areas surrounding the sites where localized corrosion occurs are corroded to a lesser extent, or may be essentially unattacked. Three forms of localized attack will be described in this section: • Pitting corrosion •
Crevice corrosion
•
Filiform corrosion
5.3.1 Pitting Definition Pitting is a deep, narrow corrosive attack which often causes rapid penetration of the substrate thickness. Pitting corrosion is characterized by corrosive attack in a localized region surrounded by corrosion free surfaces, or surfaces that are attacked to a much lesser extent. Pitting corrosion can initiate in some statistical manner on an open, freely-exposed surface, or at random imperfections where protective surface films or coatings have broken down.
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5.3.1.1 Pitting Mechanism
Very often, a local cell is set up between the interior of the pit and the external surface. The interior contains acidic, hydrolyzed salts that are quite corrosive compared with the bulk solution. An anode is established within the pit, and the surrounding surfaces act as cathodes. This is particularly the case for alloys that rely on a resistant, passive film for protection (such as with stainless steels, titanium, and aluminum). It also may occur on iron, steel, lead, and other metals. Pits develop at weak spots in the surface film and at sites where the film is damaged mechanically under conditions where self repair will not occur.
Figure 5.5 Pit with pH and Chloride Concentration Changes Indicated6
5.3.1.2 Pitting Rates
The practical importance of pitting depends on the thickness of the metal and on the penetration rate. The rate usually decreases with time. Thus, on thin sections pitting may be serious, while on a thick section it may be less important. In general, the rate of penetration decreases if the number of pits increases. This is because adjacent pits have to share the available adjacent cathodic area, which controls the corrosion current that can flow. Movement of the solution over a metal surface often reduces and even may prevent pitting that otherwise would occur if the liquid were stagnant (such as with some austenitic stainless steels in seawater). Pitting corrosion usually occurs in the following stages. Initiation Pits initiate at defects or imperfections in a protective or passive film. The defects may either be randomly distributed, or caused by mechanical damage to the films. In some alloys, it may take a considerable amount of time for the passive films to break down. Pitting may not initiate for long periods, but once it initiates, the pitting can propagate rapidly. Propagation In the propagation stage, corrosion is driven by the potential difference between the anodic area inside the pit and the surrounding cathodic area. In addition, the environment within the pit can become more aggressive and further accelerate corrosion within it. Termination A pit may terminate because of increased internal resistance of the local cell (caused by filling with corrosion products, filming of the cathode, etc.). If a pitted surface is dried out, of course, the pits will terminate. Reinitiation When re-wetted, some of the pits may reinitiate. This may be due to the re-establishment of the conditions, or to the differential aeration between the solution in the main pit cavity and solutions in some of the cracks that emanate from deeper into the metal. In structural members where strength alone is the concern, pitting may not be as important as in a service of containing fluid.
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5.3.1.3 Predictability/Measurement
Pitting corrosion is measured by measuring the depth of the pits below the surrounding surface. This may be accomplished by using such instruments and methods as: Pitting Resistance Equivalent The pitting resistance equivalent number (PREN) is a “rule of thumb” guide to the pitting resistance of a metal. The PREN is often defined as PREN = %Cr + 3.3 x Mo% + 16-30 x % N. Examples of PREN values should be included for various metals; suggest UNS S30400, S31600 and a high alloyed material such as 6% molybdenum superaustenitic steel. Pitting Corrosion Morphology Pits can vary in depth, size and orientation as shown in Figure 5.6. Calibrated Microscopy In measuring pits with a calibrated microscope, the microscope is first focused on the surface surrounding the pit, then on the bottom of the pit. The difference in focusing distance read from a scale on the microscope represents the depth of the pit. Pit Depth Gauge When using a pit gauge (Figure 5.7) with a needle probe, the gauge is zeroed on a flat surface, then the needle is inserted into the pit and the pit depth is read. It is important that the needle reach the deepest part of the pit. This can be a problem with deep, narrow pitting.
Figure 5.6 Pit Morphology7
Figure 5.7 Pit Gauge for Measuring Pit Depth in the Field
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Metallographic Sectioning Metallographic measurement of pits requires sectioning the sample at pit sites. It is often difficult to ensure that the section is at the deepest point of the pit. Routing Routing removes material from the surface until no further pits are evident. This method is the most accurate because, even in metallographic sectioning, it is difficult to find the location of the deepest penetration. A variation of the routing method, which can be used to measure the maximum pit depth on the outside of a pipe, is to place a sample length in a lathe and machine it until no further corrosion is evident. In most cases, the deepest pit and the average depth of a number of pits (commonly the ten deepest pits) are reported. Another measurement of pitting is the pitting frequency, which is the number of pits per unit area (usually pits per square centimeter). The effect of pitting corrosion is more difficult to apply than the effect of uniform corrosion, because the exact location of the pits cannot be predicted. In addition, the depth of pitting is statistically distributed. It is not possible, based on limited corrosion testing, to be sure the deepest pit measured on a small area in a test will predict or portray the deepest pit that actually occurs over a large area in a service exposure. 5.3.1.4 Performance of Metals and Alloys
Aluminum Alloys The introduction of small amounts of ions of metals such as copper, lead, or mercury may cause severe corrosion of aluminum equipment. For example, corrosion of upstream copper alloy equipment can cause contamination of cooling water. Under these circumstances, copper can plate out (cathodic reaction) on downstream equipment and pipe, setting up local galvanic cells that can result in severe pitting and perhaps perforation. Mercury causes severe pitting and stress cracking of aluminum. Common sources of mercury contamination include blown manometers, broken thermometers, broken seals, and mercurycontaining biocides. Aluminum alloys may also pit in seawater or other environments containing chlorides or other halide salts, such as bromides or iodides. Stainless Steels and Nickel Based Alloys The resistance of stainless steels and nickel-based alloys depends on the specific alloy used and the environment. Pitting should always be a concern when selecting stainless steels and nickel alloys. Stainless steels are notoriously susceptible to chloride pitting. Surface films of either organic or inorganic origin may occlude and concentrate chlorides to cause widespread pitting over a surface area. Except for localized attack under marine deposits in seawater, pitting of pure nickel is rare. The nickel-copper alloys (alloy-400 and K-500) are also subject to pitting corrosion in seawater; however, the occurrence of such pitting is rare. These alloys are often used as fastener materials or for other small parts. These small parts usually receive sufficient cathodic protection from more active surrounding materials to eliminate pitting in most marine immersion applications. The basic Ni Cr Fe alloys are subject to pitting in a manner similar to austenitic stainless steels. The molybdenum bearing varieties are markedly more resistant and distinctly superior to the stainless steels in this regard, but even the highly resistant alloys may be attacked under severe conditions. Copper Alloys Copper alloys are used extensively in various water handling systems because of their good corrosion behavior and resistance to pitting. Copper alloys are attacked by ammonia, which can cause both pitting and stress corrosion cracking. Hot oxygenated water can also cause pitting of many copper alloys.
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Very soft fresh waters can promote some pitting of copper, particularly if CO2 levels are high. Carbonaceous films present from lubricants used in the forming of copper tubing can also promote pitting. Steam with sufficiently high quantities of CO2, O2, or NH3 can be corrosive and lead to pitting of some copper alloys. Deposits of iron oxide resulting from upstream iron corrosion or other sources can also cause pitting corrosion of copper alloys. Sulfides in waters, including seawater, lead to severe pitting of most copper alloys. Copper alloys are not recommended for handling oxidizing acids or acids with oxidizing agents (such as oxygen or ferric ions) since high rates of pitting can occur. Lead Lead is frequently used as an external shield in underground electrical and communication cables. Lead may pit in these underground environments, aggravated by stray electrical currents. 5.3.1.5 Control of Pitting Corrosion
Pitting corrosion can be controlled in several ways. Materials Selection This approach is broadly applicable. The use of a more pit resistant material, on a partial basis, is also employed (e.g., use of weld overlays to improve resistance of flange faces). Modification of Environment The propensity of an environment to induce pitting sometimes can be modified by deaeration, elimination of certain species, inhibition, etc. Keeping the surface clean can help to control pitting. Protective Coatings Coatings can be effectively used in specific instances, such as on threaded fasteners. On boldly exposed surfaces, there is always the possibility of concentrating attack at imperfections in the coating, unless the coating is a metallic film sacrificial to the substrate. Electrochemical Techniques Cathodic protection has been used effectively to control pitting on boldly exposed surfaces. Anodic protection is generally not recommended where pitting attack may occur. Design Increased cross section or corrosion allowances are not a practical measure against pitting attack or severe localized corrosion.
5.3.2 Crevice Corrosion Definition Crevice corrosion is a form of localized attack in which the site of attack is an area where free access to the surrounding environment is restricted. As crevice corrosion is caused by differences in the concentrations of materials inside and outside the crevice, crevice corrosion is also called concentration cell corrosion. This form of localized attack can occur at crevices where materials meet in such a way that the environment can enter the joint between them but the flow of material into and out of the joint is restricted. These crevices may either be metal to metal or metal to nonmetal. Crevices can also be formed under deposits of debris or corrosion products. Crevice corrosion can be recognized by the localization of attack either at the entrance to a crevice or deep within the crevice. When corrosion occurs deep within a crevice, it is often revealed only after a failure has occurred.
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5.3.2.1 Mechanism
There are two basic mechanisms of crevice corrosion: • Oxygen concentration cell corrosion •
Metal ion concentration cell corrosion
Figure 5.8 is a schematic diagram showing typical crevice locations at a bolted joint. In oxygen concentration cell crevice corrosion, the difference in oxygen concentration between the areas inside and outside the crevice causes a potential difference between these areas. Oxygen concentration primarily affects the activity of the cathodic reactions involved in corrosion. Where the cathodic activity is high, the area will act as a cathode with respect to areas where the cathodic activity is low. In many natural environments, the most common cathodic reactions are the reduction of oxygen or water.
Figure 5.8 Crevice Corrosion Locations on Joint and Fastener8
•
Oxygen reduction:
O2 + 2H2O + 4e– → 4(OH–)
•
Water reduction:
2H2O + 2e– → H2 + 2OH–
A basic principle in chemistry is the law of mass action, which says that an increase in the concentration of reactants will increase the reaction. The law also states that a build up of reaction products will tend to stifle the reaction. The Nernst equation is a mathematical expression of this basic concept. In both of the above cases, an increase in oxygen content will tend to increase the cathodic reaction, whereas a decrease in oxygen will tend to reduce the cathodic reaction. An area with a more active cathodic reaction will tend to act as a cathode with respect to an area with a less active cathodic reaction. The area within a crevice will become quickly depleted quickly of oxygen because of corrosion reactions and other reactions that consume oxygen. Thus, the area within a crevice will become anodic with respect to the outside area, where the high oxygen content drives the cathodic reaction. As a result, concentration cell corrosion from oxygen concentration results in corrosion concentrated deep within the crevice, as shown in Figure 5.9.
Figure 5.9 Oxygen Concentration Cell Corrosion
As with pitting, the initial driving force of an oxygen concentration cell causes corrosion to initiate, but that corrosion can be further accelerated by the accumulation of acidic hydrolyzed salts within the crevice.
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In metal ion concentration cell corrosion, the difference in potential between the inside and the outside of the crevice is caused by a difference in metal ion concentration. The Nernst equation can be used to better understand concentration cell corrosion. By comparing the potentials at high and low concentrations with the standard potentials, the potential difference between these areas can be calculated. Say that the reaction is CuO → Cu++ + 2 e– and the low concentration of Cu++ is 0.01 and the high concentration of Cu++ is 0.1. The potential of the cell created between these areas is:
In this case, the positive potential indicates that the potential of the surface in contact with the high concentration of metal ions is more positive than the surface in contact with the low concentration of metal ions. In an electrochemical cell, the surface with the more positive potential will act as a cathode. The area of the cell exposed to the high metal ion concentration that exists inside the crevice will act as a cathode with respect to the area with low metal ion concentration outside the crevice. In metal ion concentration cell crevice corrosion, the corrosion is usually concentrated at the entrance to the crevice, as shown in Figure 5.10.
Figure 5.10 Metal Ion Concentration Cell Corrosion
Localized corrosion, similar in appearance to crevice corrosion, can occur because of restricted access of corrosive solutions to certain areas of the surface. For example, in structures exposed to the atmosphere, the surfaces within the crevices may be subjected to considerably longer periods of wetting than boldly exposed surfaces, which tend to dry more easily. The mechanism of this attack is not concentration cell corrosion; the attack occurs primarily because of differences in duration of wetness. 5.3.2.2 Types
Crevice corrosion can occur under many circumstances such as: • In metal-to-metal crevices, such as threaded fasteners, couplings, or joints (Figure 5.11) •
In metal-to-nonmetal crevices under gaskets or wet insulation (the latter is sometimes called “poultice” attack) (Figure 5.12)
•
Under deposits of debris or corrosion products (Figure 5.13)
Figure 5.11 Crevice Corrosion of a TenYear-Old Bold on a Water-Control Valve9
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Metal ion or oxygen concentration cell corrosion can occur in both metal-to-metal and metal-tononmetal crevices.
Figure 5.12 Crevice Corrosion on a Heat Exchanger Header Plate
1
Figure 5.13 Underdeposit Corrosion of 90-10 Copper-Nickel Tubing at the 6 O’clock Position1
In the case of corrosion under debris or corrosion products, the deposit can either be inert (e.g., sand) or electrochemically active (e.g., carbonaceous material or magnetite). In the case of electrochemically active debris, the crevice attack is further accelerated by the difference in potential between the deposit and the underlying metal. 5.3.2.3 Performance of Metals and Alloys
Crevice corrosion occurs most commonly on passive film protected metals, such as the following. Aluminum and Aluminum Alloys Aluminum and aluminum alloys are attacked by crevice corrosion in many environments. Crevice corrosion of aluminum alloys in marine environments is particularly common. The most common form of crevice corrosion on aluminum alloys is due to oxygen concentration cells. Stainless Steels and Nickel Based Alloys Although resistance varies with composition, many stainless steels are susceptible to crevice corrosion. Crevice corrosion of stainless steels in marine environments is particularly common. Crevice corrosion on stainless steels is caused most commonly by oxygen concentration cells. Molybdenum additions increase the resistance of stainless steels to crevice corrosion in many environments. Many nickel alloys are subject to crevice corrosion in a manner analogous to austenitic stainless steel. The molybdenum bearing varieties seem to be markedly more resistant and distinctly superior to the stainless steels, but even the highly resistant alloys may be attacked under severe conditions. Titanium and Titanium Alloys Titanium depends on a passive film for its resistance. It can suffer severe crevice corrosion in hot brines and other environments where conditions inside a crevice area allow breakdown of the passive film. Zirconium and Zirconium Alloys Zirconium and zirconium alloys are reactive metals similar to titanium. They can corrode in crevices where corrosive species such as Fe+3 or Cu++ accumulate or concentrate.
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Copper Alloys Copper alloys are subject to metal ion concentration cell corrosion in many environments. This form of crevice corrosion is often not a significant problem as it occurs at the entrance to the crevice, where some corrosion damage is acceptable. Crevice corrosion deep within crevices is usually a greater problem, particularly in the case of seals, where corrosion inside the crevice can cause leaks. 5.3.2.4 Control of Crevice Corrosion
The control of crevice corrosion is complicated by the difficulty of effectively reaching the environment within the crevice. The principal options for control of crevice corrosion are: Materials Selection Materials selection is an obvious way to control crevice corrosion. Simply use materials less subject to this problem. However, this means of control is often made difficult because it is nearly impossible to predict the severity of the crevices that will actually be created in the service environment. To determine which alloys are resistant, some type of testing is required. To be valid, the tests must reproduce the actual service environment, including the depth and tightness of the crevice. Many test crevices tend to be more severe than those actually encountered in field application. As a result, alloys that are more resistant than required are selected for use. While this is a conservative practice, the more resistant materials are usually more expensive and the extra expense may not be justified. Design Design is used to control crevice corrosion, primarily by eliminating crevices. Ways to eliminate crevices will be covered in detail later in this course. Some of the ways in which design can eliminate crevices are: • Using butt-welded joints instead of lap-welded or bolted joints •
Sealing of lap joints where they cannot be avoided
•
Avoiding skip welds
•
Providing complete drainage
•
Avoiding materials that can hold moisture in contact with substrate
•
Providing surfaces that can be kept clean easily and kept free of debris
Cathodic Protection Cathodic protection is surprisingly effective in controlling crevice corrosion. While the exact mechanism of cathodic protection in controlling crevice corrosion is not well understood, several factors are usually considered important. Cathodic protection makes the potential of the outside of the crevice more negative; thus, the difference in potential between the inside and the outside of the crevice is reduced. Cathodic protection also produces alkalinity on the protected surfaces outside of the crevices. This alkalinity can diffuse into the crevice and reduce the acidic effects of hydrolyzed salts inside the crevice.
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5.3.3 Filiform Corrosion Definition Filiform corrosion (Figure 5.14 and Figure 5.15) is a special form of oxygen cell corrosion occurring beneath organic or metallic coatings on materials. The attack results in a fine network of random “threads” of corrosion product developed beneath the coating material. Such attack can develop beneath coatings in an environment of humidity higher than 60% relative humidity. Such items may include coated cans, office furniture, cameras, aircraft structures, auto interiors and exteriors, and a host of other common products.
Figure 5.14 Filiform Corrosion Underneath a Transparent Protective Coating
Figure 5.15 Filiform Corrosion Underneath Coating on the Skin of an Aircraft
5.3.3.1 Mechanism
The mechanism of filiform corrosion is similar to that of crevice corrosion in that it is driven by the potential difference between the advancing head of the attack and the area behind the head of the advancing attack. In filiform corrosion, the head of the advancing filament (about 0.1 mm [0.04 in] wide) becomes anodic, with a low pH and a lack of oxygen, as compared with the cathodic area immediately behind the head, where oxygen is available through the semipermeable film. Corrosion proceeds as the cathode follows behind the anodic head. Water and oxygen in the cathodic area convert the anodic products to the usual oxides of the metal. The cause of filiform corrosion appears to be associated with mild surface contamination of solid particles deposited from the atmosphere or residue on the metal surface after processing. Such surfaces exposed to humid atmospheres will often suffer filiform corrosion. Filiform corrosion does not normally result in significant corrosion of the metal surface. It can delay the adhesion of a paint film, resulting in the eventual attack of the metal. 5.3.3.2 Performance of Metals and Alloys
Filiform corrosion can occur under semipermeable coatings on steel, zinc, aluminum, and magnesium alloys exposed to humidity greater than 60% relative humidity 5.3.3.3 Control of Filiform Corrosion
This type of corrosion, particularly on painted surfaces, can be prevented by proper cleaning and preparation of the metallic surface, and then applying the coating only to a thoroughly-cleaned and dried surface.
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5.4 Galvanic Corrosion Definition Galvanic corrosion is a form of corrosion which occurs because of the potential differences between metals. Galvanic corrosion occurs through the action of the electrochemical cell. Galvanic corrosion is defined as corrosion accelerated by the potential differences between different metals when they are in electrical contact and exposed to an electrolyte. Galvanic corrosion can also occur between a metal and an electrically conductive nonmetal such as graphite. Carbon in plastics and elastomers may also be electrochemically active and can cause galvanic corrosion. Such corrosion products as magnetite (Fe3O4) and sulfides can also be electrochemically active and are cathodic with respect to most metals. Ions of a more noble metal may be reduced on the surface of a more active metal (e.g., copper on aluminum). The resulting metallic deposit provides cathodic sites for further galvanic corrosion of the more active metal. The electrical contact between the dissimilar materials may be through either direct contact, or an external conductive path. In galvanic corrosion, the rate of attack of one metal or alloy is usually accelerated, while the corrosion rate of the other is usually decreased. Galvanic corrosion can be recognized by either increased corrosion of the anodic material, or decreased corrosion of the cathodic material. Galvanic corrosion is often pronounced, where the dissimilar materials are immediately adjacent to each other and at sharp edges or corners.
5.4.1 The Electrochemical Process The mechanism of galvanic corrosion is the classical electrochemical cell. As discussed previously, the electrochemical cell requires four factors to be present: • The anode is the place where metal is lost and electrons are produced. •
The cathode is the place where electrons produced at the anode are consumed.
•
The metallic path conducts electrons from the anodic sites to the cathodic sites.
•
The electrolyte provides reactants for the cathodic reactions and allows the flow of ions.
For galvanic corrosion to occur, all these components must be present and active. In galvanic corrosion, electrons flow through a metallic path from sites where anodic reactions are occurring to sites where they allow cathodic reactions to occur. Electrical current flows through the electrolyte to balance the flow of electrons in the metallic path as shown in Figure 5.16. Galvanic corrosion is driven by the potential differences between metals or electrically conductive nonmetals when exposed to an electrolyte. Nonmetals include such electrically conductive materials as graphite. In some cases, the cathodic member of a galvanic couple can be a deposit formed by the deposition of metal ions from solution onto the anodic metal surface. Figure 5.16 Galvanic Corrosion
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5.4.2 Galvanic Series A galvanic series is simply a listing of metals in the order of their potential in a specific electrolyte (Figure 5.17). A galvanic series for seawater was shown in Chapter 2. Galvanic corrosion affects the anode of the couple by increasing its corrosion rate (e.g., see Figure 5.18). The results of this corrosive attack may be by general attack, pitting, or some other form of corrosion. Galvanic activity does not control the form of corrosion, which occurs at the anode; it only increases the rate of attack. Galvanic corrosion affects the cathode of the couple in several ways. In general, the corrosion that would normally occur if the cathode were exposed to the environment by itself will decrease when it is coupled to a more active material. In some cases, however, the cathode can be adversely affected. Hydrogen embrittlement, a form of corrosion that will be discussed later in this section, can result. In addition, the alkaline cathodic reaction products formed in a galvanic cell can adversely affect some materials such as aluminum. Metals that are chemically vulnerable in both acidic and alkaline environments, known as amphoteric materials, can be affected at the cathode in a galvanic corrosion cell. Such attacks are called amphoteric effects.
5.4.3 Galvanic Corrosion Rates The extent of accelerated corrosion resulting from galvanic coupling is affected by the following factors: • The potential difference between the metals or alloys •
The specific nature of the environment
•
The polarization behavior of the coupled materials
•
Spatial effects, such as area, distance, and cell geometry
•
Resistivity of the electrolyte
Figure 5.17 Galvanic Series
5.4.3.1 Potential Difference
The potential difference between materials causes current flow when dissimilar materials are coupled in a suitable electrolyte. The direction of current flow depends on which metal is more active. The more active metal becomes the anode, while the less active metal becomes the cathode. The magnitude of the driving force for galvanic attack in this couple is the difference in potential between these electrodes. To determine the specific effects between specific materials in a specific environment, it is necessary to know the galvanic series for those materials in the environment of interest. Such an empirically-developed galvanic series of metals and alloys may be useful for predicting galvanic relationships of metals and alloys according to their potentials, measured in a specific electrolyte. It allows one to determine which metal or alloy in a galvanic couple is more active in the
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environment of interest. The difference in measured potential between two metals or alloys in this galvanic series can give a prediction of the probable magnitude of corrosive effects. Most commonly when someone mentions the galvanic series, they are referring to a table which has been constructed from measurements in seawater. With certain exceptions, this series is broadly applicable in other natural waters and in uncontaminated atmospheres. In general, electrode potentials are sensitive to the following factors: • Electrode composition •
Electrolyte composition
•
Temperature
•
Degree of agitation
•
Presence of depolarizers, inhibitors, or both
•
Surface condition of electrodes
•
Metallurgical condition of the electrodes
Any differences in these factors between the environments for which a galvanic series was developed and the intended service environment can cause a reordering of materials in the series.
Figure 5.18 Galvanic Corrosion of Carbon Steel Structure Connected to Stainless Steel Fasteners1
5.4.3.2 Nature of Environment
Galvanic corrosion can occur under either immersion or atmospheric conditions. Under immersion conditions, galvanic effects cover essentially the exposed surfaces of the anode and cathode. Because of effects of electrolyte resistance, galvanic effects are usually concentrated where the anode and cathode are closest together. In atmospheric exposures, the resistance effects in the electrolyte limit the range of galvanic effects to the area where the two electrodes are in contact (when this area is filled with electrolyte) and for a very short distance around the contact area. This distance is usually on the order of 1–2 mm (0.04–0.08 in). 5.4.3.3 Polarization
As shown in Chapter 2, Electrochemistry, polarization of the anodic and cathodic areas can have a very large effect on the intensity of the anode’s corrosion. If neither the anode nor the cathode polarizes significantly, the amount of current flow will be large, and the resulting galvanic corrosion will also be large. 5.4.3.4 Spatial Effects: Area, Distance, and Geometric Effects
Area Effects Area effects in galvanic corrosion involve the ratio of surface areas of the cathode to the surface areas of the anode. As discussed in Chapter 2, the galvanic corrosion which occurs when the exposed area of the anode is small with respect to the exposed area of the cathode under immersion conditions, the intensity of attack on the anode can be very high. Conversely, if the exposed area of the anode is large with respect to the exposed area of the cathode, the acceleration of corrosion at the anode may be negligible. In atmospheric environments, since the affected area is only the wetted contact area and a few millimeters beyond, the effective area ratio is effectively 1 to 1. Distance Effects In a galvanic couple under immersion conditions, most of the corrosion occurs near the junction because of the effects of the electrolyte’s resistivity. In high-resistivity electrolytes, this effect at the junction between the anode and the cathode is more pronounced than in low-resistivity electrolytes.
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Geometric Effects Cell geometry exerts an effect to the extent that current will not readily flow around obstacles. For example, the interior of a pipe cannot be protected by application of an external current. At the anode, because of current gradient effects, galvanic corrosion tends to be concentrated at sharp points or edges. 5.4.3.5 Electrolyte Resistivity Effects
Since the electrolyte is the element in the circuit which allows galvanic current flow, the resistivity of the electrolyte will affect the flow of current in the cell. All other things being equal, less corrosion current will flow in a cell that has a high-resistivity electrolyte than in one with lowelectrolyte resistivity. Because the corrosion of the anode is a direct function of this current, galvanic corrosion is usually less intense in electrolytes with higher resistivity.
Figure 5.19 Effect of Electrolyte Resistivity on the Distribution of Galvanic Corrosion
5.4.4 Predicting Galvanic Attack While it is fairly easy to predict the likelihood of galvanic attack and to identify which metal is likely to suffer increased attack as an anode, exact predictions of changes in corrosion rates are difficult. Potential measurements can be used to develop a galvanic series for a specific environment if one is not available. Only those metals that are candidates for evaluation need to be included in this series. It should be pointed out that metals and alloys forming passive films will exhibit varying potentials with time; therefore, it will be difficult to position them in the series with certainty. It is possible to predict galvanic corrosion rates by measuring the current flow in a model couple that reproduces the relative area and other important factors in the proposed application. It is important to remember that the rates may change with time, so long-term current flow must be evaluated to make a good prediction of actual service performance. In performing these tests, a specialized ammeter with “zero effective” resistance is used to measure the current flow between the anode and the cathode in the external circuit. It is important that a zero-resistance ammeter be used for these measurements, because even a small resistance inserted into the circuit can significantly reduce the current flow. Measurements of the polarization characteristics of the candidate materials in the service environment can also be used to predict galvanic corrosion rates. The polarization curves are plotted on Evans diagrams that predict total current flow, and the current density on the anode can be calculated.
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In most cases, these methods can be used to predict galvanic corrosion tendencies (i.e., to identify anode and cathode) relatively well. They also give good relative predictions of galvanic corrosion rates. There can be significant differences between the predicted rates using these methods and the actual rates experienced in service. The best method for predicting galvanic corrosion rates is to expose model couples of the candidate materials in the intended service environment and compare the galvanic corrosion rates with the rates of the uncoupled materials. Other examples of galvanic corrosion are found in Figure 5.20 and Figure 5.21.
Figure 5.20 New Pipe Connected to Old Pipe Produces a Galvanic Corrosion Cell 2
Figure 5.21 Differential Aeration Cell on a Pipeline Beneath a Paved Road 4
5.4.5 Performance of Metals and Alloys The performance of specific metals and alloys can be estimated from their position on the galvanic series. In general, metals higher (i.e., more active) in the galvanic series will be affected by contact with a wider variety of materials than those low in the galvanic series. Of course, it is the relative position of the materials making up a specific couple that must be evaluated for each application where galvanic corrosion is a concern. Magnesium and magnesium alloys occupy an extremely active position in most galvanic series and, therefore, are highly susceptible to galvanic attack. Magnesium is widely used as a sacrificial anode in cathodic protection.
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Aluminum and aluminum alloys also occupy active positions in the galvanic series. In “chloridebearing” solutions, aluminum alloys are susceptible to “galvanically-induced” localized corrosion, especially dissimilar-metal crevices. In this type of environment, severe galvanic effects are observed when aluminum alloys are coupled with more noble metals and alloys. Galvanic effects are also observed in the presence of deposited heavy metals such as copper, mercury, or lead. Some aluminum alloys are used for sacrificial anodes in seawater. An active aluminum alloy is used to “clad” aluminum, protecting it against pitting in some applications. Zinc is an active metal, susceptible to galvanic attack. It is widely used for galvanic anodes in cathodic protection as a sacrificial coating applied by hot-dip galvanizing or electroplating and as a pigment in certain types of coatings. Carbon and low-alloy steels are fairly active materials and require protection against galvanic attack by more noble materials. Galvanic attack on carbon and low-alloy steels when anodic in a galvanic corrosion cell, is usually in the form of general attack. Galvanic attack of stainless steels is difficult to predict because of the influence of passivity. In the common galvanic series, a noble position is assumed by stainless steels when in the passive state, while they assume a less noble position in the active state. This dual position in chloride bearing aqueous environments has been the cause of some serious design errors. More precise information on the galvanic behavior of stainless steels can be obtained by using polarization curves, critical potentials, and the mixed potential of the galvanic couple. In chloride bearing environments, “galvanically-induced” localized corrosion of some stainless steels occurs in couples with copper or nickel (and their alloys) and other more noble materials. Couples of stainless steel and copper alloys are often used with impunity in freshwater cooling systems. Iron and steel tend to protect stainless steel in aqueous environments when galvanically coupled. The passive behavior of stainless steels makes them easy to polarize, so that galvanic effects on other metals or alloys tend to be minimized. Because of the passive films on both alloys, galvanic corrosion between stainless steel and aluminum alloys in seawater is much less severe than would be anticipated by their difference in position on the galvanic series, particularly if the anode/cathode area is favorable. Nickel and its alloys are not readily polarized and, therefore, will cause accelerated corrosion of more active materials such as aluminum and ferrous alloys. In chloride bearing solutions, nickel is somewhat more noble than copper, and the cupronickels lie somewhere in between. Nickel and its alloys are similar to copper alloys in their effects on stainless steels. In some environments, the cast structure of a nickel weld may be anodic to the parent metal. With the chromium nickel alloys, the combination of a passive surface with the inherent resistance of the nickel based alloys (e.g., Alloys 600, 625, C276) places them in more noble positions in the traditional galvanic series. In chloride bearing solutions, Alloy 600 is reported to occupy two positions because of the existence of active and passive states similar to the stainless steels. These alloys are readily polarized, and galvanic effects on other, less noble metals and alloys tend to be minimized. Lead and tin form oxide films that can shift their potentials to more noble values. In some environments, they may occupy more noble positions than one might otherwise expect. For example, the tin coating in tin cans is anodic to steel under the anaerobic conditions within the sealed container, but it becomes cathodic when the can is opened and exposed to air. Copper and its alloys occupy an intermediate position in the galvanic series. They are not readily polarized in chloride bearing aqueous solutions and, therefore, may cause severe accelerated corrosion of more active metals such as aluminum, its alloys, and the ferrous metals. Titanium, zirconium, and tantalum are extremely noble because of their passive films. In general, these alloys are not susceptible to galvanic attack, and their ease of polarization tends to minimize adverse galvanic effects on other metals or alloys. Because of the ease with which they pick up hydrogen in the atomic state, they may themselves become embrittled in galvanic couples if the anodic member corrodes rapidly, with H2 evolution proceeding at a very rapid rate. Tantalum repair patches in glass-lined vessels have been destroyed by contact with cooling coils or agitators made of less noble alloys.
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“Noble metals” such as gold and silver do not cathodically polarize readily and, therefore, can have a marked effect in galvanic couples with other metals or alloys. This effect is observed with gold and silver coatings on copper, nickel, aluminum, and their alloys. Graphite, either in pure form or as an additive to plastics and elastomers, can have an adverse effect on most other materials when they are galvanically coupled. Graphite has a very low position on the galvanic series and does not polarize readily. Thus, its effect on other materials can be severe.
5.4.6 Control of Galvanic Attack Galvanic corrosion can be controlled in several ways, including: 5.4.6.1 Design
Unfavorable area ratios should be avoided. Use metal combinations in which the more active metal or alloy surface is relatively large. Rivets, bolts, and other fasteners should be of a more noble metal than the material to be fastened. Avoid dissimilar-metal crevices such as those that occur at threaded connections. Crevices should be sealed, preferably by welding or brazing, although putties are sometimes used effectively. Provide an appropriate corrosion allowance of the more active member. 5.4.6.2 Materials Selection
Combinations of metals or alloys widely separated in the relevant galvanic series should be avoided, unless the more noble material is easily polarized. Metallic coatings can be used to reduce the separation in the galvanic series. 5.4.6.3 Electrical Isolation
The joint between dissimilar metals can be insulated to break the electrical continuity. Use of nonmetallic inserts, washers, fittings, and coatings at the joint between the materials will provide sufficient electrical resistance to eliminate galvanic corrosion (Figure 5.22). When electrical isolation is used to control galvanic corrosion, it is important to verify that isolation has actually been achieved. In atmospheric exposures, this can be verified using a simple ohmmeter. When both members of the couple are exposed to such an electrolyte as liquid or soil, resistance tests are not useful because low resistances will be read through the electrolyte even if the metals are effectively isolated (i.e., the electron flow path is not continuous). In these cases, more Figure 5.22 Electrically-Isolated Flange Assembly5 sophisticated instruments that discriminate between electrical metallic conductivity and electrolytic conductivity, must be used.
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5.4.6.4 Barrier Coatings
Barrier coatings of a metallic nature have already been discussed. Inert barrier coatings, organic or vitreous, can effectively isolate the metals from the environment. Note that it is potentially dangerous to coat only the anodic member of a couple. This reduces its area and severely accelerated attack can occur at the holidays, or imperfections in the protective coating. When using barrier coatings to control galvanic corrosion, always coat the cathode. Further protection may also be achieved by coating the anode. 5.4.6.5 Cathodic Protection
Metals, such as magnesium or zinc, may be introduced into the galvanic assembly. The most active member will corrode, while providing cathodic protection to the other metals even when the other metals are electrically coupled. Impressed-current systems provide the same effect. 5.4.6.6 Modification of Environment
In particular cases, it is possible to greatly reduce galvanic attack between widely dissimilar metals or alloys. Use of corrosion inhibitors is effective in some instances. Elimination of cathodic depolarizers (e.g., deaeration of water by thermomechanical means, plus the use of oxygen scavengers such as sodium sulfite) can be effective in some aqueous systems.
5.5 Environmental Cracking Definition Environmental cracking is an important form of corrosion. Unlike many other forms of corrosion, where the corrosion occurs over long periods of time, and such failures as leakage and structural collapse can be prevented through inspection, environmental cracking can occur very rapidly and result in a failure before inspection can identify damage. Environmental cracking is the brittle failure of an otherwise ductile material, resulting from the combined action of corrosion and tensile stress.
5.5.1 Mechanism The combined action of a tensile stress and a corrosion reaction is the principle characteristic of the environmental cracking phenomenon. In the absence of either the tensile stress or the corrosive environment, cracking will not occur. Failures resulting from this localized form of corrosion can be unanticipated and catastrophic because they occur in metals selected for their general corrosion resistance (e.g., stainless steels).
5.5.2 Recognition of Environmental Cracking In environmental cracking, tight cracks are at right angles to the direction of maximum tensile stress. Single and multiple cracks can occur. A group of multiple cracks on the metal surface is commonly observed. Corrosion products can be found in the cracks, but the metal surface is usually clean, with no evidence of corrosion except for the fine network of cracks. Environmental cracks other than corrosion fatigue are often generally branched. They can either be intergranular and propagate along the metal grain boundaries, or transgranular and propagate across the grains.
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5.5.3 Controlling Cracking Factors Many factors control whether or not a material will be susceptible to environmental cracking in a given situation. These factors include: • Tensile stress •
Alloy composition and structure
•
Corrosion environment
•
Corrosion potential
•
Temperature
5.5.4 Types of Environmental Cracking The following types of environmental cracking will be described: • Stress corrosion cracking (SCC) •
Hydrogen induced cracking (HIC)
•
Liquid metal embrittlement (LME)
•
Corrosion fatigue (CF)
5.5.4.1 Stress Corrosion Cracking Definition
SCC is a brittle failure in an otherwise ductile metal, resulting from the combined action of tensile stress and a specific corrosive environment. Note that only specific corrosive media promote stress corrosion cracking of an alloy system (e.g., caustic with carbon steel, chlorides with stainless steel, and ammonia with copper alloys). An example is shown in Figure 5.23. Recognition Figure 5.23 Stress Corrosion Cracking of Brass SCC can be recognized by the brittle failure of Cartridge by Ammonia an otherwise ductile material when exposed to a specific environment. Mechanism Stress corrosion cracking is an anodic process, a fact which is verified by the applicability of cathodic protection as an effective remedial measure. Usually there is an incubation period, during which time cracking originates at a microscopic level. This is followed by actual propagation. Eventually, the cracks may be self arresting to a large extent, as in the typical multibranched transcrystalline SCC, apparently because of the localized mechanical relief of stresses. We can say that SCC occurs in metals exposed in an environment where, if the stresses were nonexistent or even much lower, there would be no damage. Likewise, SCC would not occur if the structure, subject to the same stresses, were in an environment that did not contain the specific corrodent for that material. The term stress corrosion cracking implies the formation of cracks and, as indicated above, usually little metal loss or general corrosion is associated with it. If there is severe general corrosion, SCC usually will not occur. The failure of a stress bolt rusted away until it eventually cannot sustain the applied load is not classified as being due to stress corrosion. However, if products from general corrosion are trapped so as to cause stress in a structure, they can cause SCC.
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Performance of Metals and Alloys We will now discuss the susceptibility of various alloy groupings to stress corrosion cracking. These metal-environment combinations are illustrative only, and this must not be considered a final or comprehensive listing. Carbon and Low-Alloy Steels Carbon steels containing sufficient residual or applied tensile stress are susceptible to stress corrosion cracking by caustics, anhydrous ammonia, nitrates, cyanides, bicarbonates, mixtures of carbon monoxide-carbon dioxide-water, and many other corrosive species. Both intergranular and transgranular modes of cracking are encountered. High-strength steels (e.g., those with strengths above about 900 MPa [130 kSi]) are susceptible to SCC in the same environments as carbon steel, as well as some others. As the material strength increases, so does its susceptibility to cracking. Stainless Steels • Martensitic Grades Stress corrosion cracking of martensitic stainless steels has been reported in hot concentrated caustic solutions. SCC has been reported in hardened martensitic stainless steels in some salt atmospheres. In the latter case, the cracking was transgranular; and hydrogen effects were reportedly not involved. •
Ferritic Grades The ferritic grades tend to be resistant to chloride stress corrosion cracking, although they will suffer environmental cracking in hot concentrated caustic. The superferritics are resistant in caustic evaporators, but their performance is probably strongly influenced by oxidizing contaminants in the caustic.
•
Austenitic Grades Transcrystalline stress corrosion cracking is induced in 18 8-type austenitic grades and related alloys by chlorides especially, and by hot concentrated caustic. The more highly-alloyed grades of higher nickel content have increasing resistance to chlorides, but not to caustic. Cracking may be intergranular if the metal has been sensitized in an environment which would otherwise cause transcrystalline cracking (such as in chloride contaminated dilute acetic acid, or hot caustic).
•
Precipitation-Hardened Grades Depending on the heat treatment, precipitation hardened grades may or may not be resistant to chloride stress corrosion cracking. In general, the heat treatments that give alloys a very high strength cause a susceptibility to chloride stress corrosion cracking.
•
Superaustenitic Grades
•
There are a number of more highly-alloyed austenitic grades, often proprietary, that have improved resistance to chloride stress corrosion cracking, but that remain susceptible to SCC in caustic and other corrosive species.
Nickel and Chromium Nickel Alloys Certain nickel alloys are subject to stress corrosion cracking by hydrofluoric acid vapors in the presence of oxygen and by hydrofluorosilicic acid.
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Chromium nickel alloys are subject to stress corrosion cracking by concentrated caustics and acid chlorides (e.g., aluminum chloride) at high temperatures when stressed above the yield point. Intergranular cracking of sensitized material (e.g., oxygen SCC) has been observed at stresses near the yield point in supercritical water. Titanium and Titanium Alloys Commercial titanium alloys are subject to stress corrosion cracking in hot salt (sodium chloride above 275°C [527°F]), 10% hydrochloric acid at slightly above room temperature, and in nitrogen tetroxide or red fuming nitric acid. Cracking can be controlled by changing the environmental composition in the latter two cases. Various chlorinated and fluorinated organic solvents have been reported to cause stress corrosion cracking, but methanol (methyl alcohol) has been the prime problem. Stress corrosion cracking by methanol can be inhibited by adding small amounts of water (2,000 ppm), but is dependent on the level of chloride contamination. The mode of cracking is predominantly intergranular. Aluminum and Aluminum Alloys High-strength aluminum alloys are susceptible to stress corrosion cracking in the presence of moisture, particularly if chlorides are present. The most susceptible grades are the copper bearing, magnesium bearing, and zinc bearing alloys. Cracking is typically intergranular and is characteristically directional, with the short transverse orientation being the most susceptible in the grain structure. Proper thermal treatment or tempering can lessen susceptibility. There appears to be no threshold stress level for the susceptible combinations of alloys and environments. Copper Alloys High-strength copper alloys (e.g., brasses hardened by cold work, welded silicon, or aluminum bronzes) are susceptible to stress corrosion cracking by ammonia (season cracking), sulfur dioxide, and nitric acid or other nitrogen-containing compounds. Cupronickels appear to be practically immune to ammonia cracking. Pure steam can cause cracking of silicon bronzes.
5.5.5 Hydrogen Induced Cracking and Sulfide Stress Cracking Description HIC results from the combined action of a tensile stress and hydrogen in the metal. Atomic hydrogen produced on the metal surface by a corrosion reaction (“nascent hydrogen”) can be absorbed by the metal and can promote environmental cracking. Higher strength alloys (i.e., those of a tensile strength of 1,034 MPa/ [150,000 psi] or greater) are more susceptible to this mode of cracking than are lower strength alloys. Sulfide stress cracking is a specific form of HIC wherein the presence of sulfides suppresses the evolution of hydrogen. 5.5.5.1 HIC Recognition
HIC results in the brittle failure of otherwise ductile materials when exposed to an environment where hydrogen can enter the metal. Figure 5.24 shows an example of HIC. Figure 5.24 HIC in a High Carbon Steel Bourdon Tube
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5.5.5.2 HIC Mechanism
HIC is a cathodic phenomenon wherein the normal evolution of hydrogen at cathodic sites is inhibited, and the atomic hydrogen (H0) in the cathodic reaction enters the metal. Formation and evolution of molecular hydrogen (H2) at cathodic sites can be inhibited by “poisons” in the environment such as sulfides or arsenides. Atomic hydrogen on the metal surface (nascent hydrogen) can diffuse into the metal instead of evolving as a gaseous cathodic reaction product. Anodic protection lessens and cathodic protection aggravates the cracking. Field applications of cathodic protection have been responsible for cracking failures in pipelines and ship propellers. In cases of ordinary environmental cracking and under the aforementioned conditions, it is usually from the ordinary corrosion process that nascent atomic hydrogen is produced at the local cathodes if, in a highly stressed condition, these cathodes are subject to HIC. The situation is aggravated in the presence of certain chemical species which act as negative catalysts (poisons) for conversion of atomic to molecular hydrogen. The normal formation and evolution of molecular hydrogen is suppressed; and the nascent atomic hydrogen diffuses into the interstices of the metal, instead of being evolved as a gaseous cathodic reaction product. The conversion of atomic to molecular hydrogen is poisoned by: • Cyanides •
Arsenides
•
Antimonides
•
Phosphides
•
Sulfides
Many chemical species poison the conversion of atomic to molecular hydrogen (e.g., cyanides, arsenides, antimonides, phosphides, and sulfides). One commonly-encountered species is hydrogen sulfide (H2S), which is formed in many natural decompositions (e.g., rotten eggs, sewer gas) and petrochemical processes. 5.5.5.3 Sulfide Stress Cracking
Sulfide stress cracking (SSC) is a type of HIC in which sulfide is the primary poison for hydrogen evolution. Processes or conditions involving wet hydrogen sulfide are called sour services, and the high incidence of sulfide induced HIC has resulted in the term sulfide stress cracking (see Figure 5.25). Whether or not the “poison” on the metal surface is a sulfide, the presence of hydrogen in the metal creates the conditions for cracking under stress. The presence of the sulfide, or any other inhibiting ion, simply implies that a greater volume of hydrogen will penetrate the metal during a given time, producing more rapid cracking of the steel. The result is the same: HIC. Sulfide stress cracking of medium-strength steels has been a continuing source of trouble in oil fields. Similar problems are encountered wherever wet hydrogen sulfide is encountered (e.g., acid gas scrubbing systems, heavy water plants, wastewater treatment). Figure 5.25 SSC in Drill Pipe
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5.5.5.4 ANSI/NACE MR0175/ISO 15156, “Petroleum and Natural Gas Industries—Materials for Use in H2S-Containing Environments in Oil and Gas Production”
In the field failures have occurred when storage tank roofs, saturated with hydrogen from corrosion are subjected to a surge in pressure, resulting in brittle failure of the circumferential welds. Factors affecting HIC Include: • Temperature •
Hydrogen concentration
•
Strength level
•
Cold work
Maximum susceptibility to HIC occurs near room temperature, while increasing temperatures cause a reduction in susceptibility. Generally, as the tensile strength of the alloy is increased, the HIC susceptibility also increases. In addition, cold work can cause increased susceptibility. This pattern is that of common hydrogen embrittlement, a temporary loss of ductility when steel becomes saturated with atomic hydrogen (as in pickling or electroplating). Ductility may be restored, without permanent damage to the alloy, by heating for a short time at about 200ºC (400ºF) to drive out the hydrogen. 5.5.5.5 Performance of Metals and Alloys
HIC performance of various alloy groupings is discussed below. This discussion must be considered illustrative, not final or comprehensive. Aluminum Some aluminum alloys are susceptible to HIC. Carbon and Low Alloy Steels If sufficiently hardened by cold work, heat treatment, or welding (e.g., of a massive item in which the cold parent metal effectively quenches the weldment), HIC can occur from nascent hydrogen. This type of cracking is fostered by the presence of specific poisons from the dimerization of atomic hydrogen (sulfides, arsenic, selenium compounds, antimony compounds, etc.). Hot hydrogen attack (decarburization) can also occur in steel exposed to hydrocarbons or hydrogen-rich environments at high temperatures [approximately 260ºC (500ºF)]. In this form of attack, the hydrocarbon breaks down on the metal surface and the hydrogen enters the steel. Methane forms by reacting with the carbon of metastable carbides. Pressure builds up and causes cracking. The main weakness of the high-strength steels, such as low-alloy martensite-forming grades, is susceptibility to cracking by atomic hydrogen. The hydrogen may be nascent, as in corrosion by moist environments contaminated with salts or cathodic poisons, or atomic, as in the case of galvanic couples or impressed-current cathodic protection. Stainless Steels Martensitic Grades In the hardened condition, these alloys are subject to HIC, including SSC, in a manner similar to other high-strength steels. Ferritic Grades Cracking by atomic hydrogen has been reported in cathodic protection installations with a driven impressed-current potential in excess of –850 mV versus a copper-copper sulfate electrode.
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Austenitic Grades HIC in the austenitic grades is observed primarily in severely cold-worked material in marine atmospheres. Precipitation-Hardened Grades Precipitation-hardened stainless steels are cracked by nascent or atomic hydrogen, particularly in sour (hydrogen sulfide) service. Their susceptibility is determined by the steel's specific thermal history and resultant hardness. Nickel Based Alloys Severely cold-worked nickel alloys have failed by HIC when in a galvanic couple, with steel in the presence of small amounts of hydrogen sulfide. Chromium nickel alloys can suffer HIC, but generally only under severe conditions, such as in the presence of a combination of severe cold work, high stress, and galvanic coupling in the presence of hydrogen sulfide and chlorides. Copper Alloys It is possible for atomic hydrogen which has resulted from impressed currents to cause HIC (e.g., in cathodic protection of manganese bronze ship propellers). Titanium/Zirconium/Tantalum Titanium, zirconium, and tantalum can be functionally destroyed by the formation of hydrides caused by absorption of atomic hydrogen. These metals are subject to HIC.
5.5.6 Liquid Metal Embrittlement (LME) Definition Liquid metal embrittlement (LME) is defined as the decrease in strength or ductility of a metal or alloy as a result of contact with a liquid metal. Figure 5.26 shows an example of LME. 5.5.6.1 Recognition
A normally ductile material which is under tensile stress while in contact with a liquid metal may exhibit brittle fracture at low-stress levels. 5.5.6.2 Mechanism
Unlike fracture by stress corrosion cracking, initiation of a failure by LME is not time dependent. Cracking begins immediately upon the application of stress if the solid material has been wetted by the liquid metal. Crack growth will continue as long as Figure 5.26 LME of a Stressed Monel Distillation Column sufficient liquid metal covers at least Caused by Mercury Exposure part of the fracture surface and some vapor reaches the apex of the crack. 5.5.6.3 Performance of Metals and Alloys
LME may be encountered in most common structural metals and alloys. Given the right combination of liquid metal, stress level, and temperature, most alloys exhibit some degree of susceptibility to LME. One fascinating aspect of LME is the specificity of the embrittling agent. For example, gallium, which causes severe embrittlement of aluminum and its alloys, has no significant effect on other materials such as low carbon steels, stainless steels, and copper alloy.
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Stainless steels, in general, are quite resistant to degradation when contacted by liquid metal, while materials such as plain carbon steels and copper-based alloys are severely embrittled. Carbon and Low-Alloy Steels Carbon and low-alloy steels are susceptible to LME in a number of environments in addition to those containing zinc. Research conducted in the temperature range between 450°–1600°F (approximately 230°–875°C) showed that such steels can suffer embrittlement when in contact with the following liquid metal systems: copper, zinc, cadmium, lead tin solders, brass, and indium. The embrittling effect of lithium is also well known. Additionally, the higher the strength of the steel, the greater the degree of embrittlement. For example, high-strength steels are embrittled at room temperature by mercury sodium amalgams. Such amalgams have no effect on a low-strength carbon steel, such as 1010 carbon steel. Stainless Steels The family of stainless steels, including martensitic, ferritic, duplex, precipitation-hardening, and austenitic stainless steel, is quite resistant to LME. Only molten zinc, aluminum, and cadmium produce adverse effects. Aluminum and Aluminum Alloys Aluminum alloys can fail rapidly by LME in the presence of mercury, gallium, indium, tin, and alkali metals (with the exception of lithium). As with low-alloy steels, the higher the strength, the more severe the embrittlement. Copper and Copper Alloys Mercury causes severe LME of brasses and bronzes; tin, lead and alloys of tin and lead also embrittle brasses. Copper and copper-base alloys other than brasses are also embrittled by mercury, bismuth, and lithium. Nickel and Nickel Based Alloys Mercury and liquid lead rapidly corrode nickel base alloys, but do not cause embrittlement. Nickel base alloys, however, may be severely embrittled by sulfur diffusing along grain boundaries from a nickel, nickel sulfite eutectic. Titanium and Titanium Alloys The deformation of titanium and titanium alloys in contact with mercury will result in severe embrittlement. Molten cadmium may also cause embrittlement. In addition, several titanium alloys have been found to suffer brittle fracture at room temperature when in intimate contact with solid cadmium. In all cases, the protective oxide film must be ruptured before embrittlement will occur. Magnesium Alloys Liquid sodium and liquid zinc are the only low melting point metals known to cause LME of magnesium alloys.
5.5.7 Corrosion Fatigue Definition Corrosion fatigue results from the combined action of a cyclic tensile stress and a corrosive environment. A tensile component of cyclic stress is required. This form of cracking lacks the specificity of the corrosive environments which are associated with the types of environmental cracking we have discussed previously. 5.5.7.1 Description
Corrosion fatigue is characterized by the premature failure of a cyclically-loaded part. This failure may occur at a lower stress, or in a fewer number of cycles in the corrosion environment than it would in an inert environment.
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5.5.7.2 Mechanism
The phenomenon covers a broad spectrum, bounded on one side by fatigue with no contribution by corrosion, and on the other side, by stress corrosion cracking under static tensile stress. In this discussion, only cases that have a clearly definable corrosion contribution are considered, as opposed to those cases attributed primarily to mechanical fatigue. Corrosion fatigue continues to be a serious cause of failure and necessitates major expenditures by industry for repair. For example, the petroleum industry encounters major trouble with corrosion fatigue in the production of oil. The exposure of drill pipes and sucker rods to brines and sour crudes results in failures that are expensive both from the standpoint of replacing equipment, as well as from the loss of production during the time required for “fishing” and rerigging. 5.5.7.3 Performance of Metals and Alloys
Aluminum Alloys Fatigue strengths of most aluminum alloys are lower in corrosive environments such as salt waters than in air. The more corrosion-resistant alloys, like 5XXX and 6XXX alloys, lose less fatigue strength than do the less resistant alloys, like the 2XXX and 7XXX series. Figure 5.27 shows a twenty-year-old airplane Boeing 737 that had over 75,000 take offs and landings. The pressure differences caused by the pressurized cabin caused corrosion fatigue cracks that eventually led to the incident resulting in one fatality. Following this incident, airlines began devoting more time to inspection for fatigue cracks, but another Boeing 737 experienced in-flight fatigue cracking of the fuselage in 2011.13 Figure 5.27 Cracked Fuselage on Aloha Airlines Flight 243 in 198811
Copper Alloys Copper alloys are often used in applications where repeated stresses are encountered. Combinations of high fatigue limits and high corrosion resistance in the service environment enhance corrosion resistance. Beryllium coppers, phosphor bronzes, aluminum bronzes, and copper nickels find applications as springs, switches, diaphragms, bellows, aircraft and automobile gasoline and oil lines, and tubes for condensers and heat exchangers. Figure 5.28 Corrosion Fatigue of a Marine Propeller1
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Carbon and Low-Alloy Steels The corrosion fatigue resistance of steels is greatly influenced by the corrosion behavior of the steel in the service environment. Time, stress intensity, number of cycles, and rate of cyclic stress will significantly affect corrosion fatigue. The rate of damage tends to increase if any of these conditions increases. Higher strength steels do not necessarily exhibit higher corrosion fatigue tendencies, even if the service environment is corrosive. More corrosive environments, such as brackish water, have been shown to reduce apparent corrosion fatigue limits. Figure 5.29 Collapsed Alexander Kielland SemiThe use of inhibitors and zinc-plated steels can Submersible Platform in the North Sea, 198012 improve corrosion fatigue resistance. Figure 5.29 shows the collapsed semi-submersible oil platform, Alexander Kielland, that capsized during a storm in the North Sea. The incident investigation revealed that a welded connection broke, leading to the collapse and the loss of 123 lives. This incident led to increased inspection procedures in fabrication yards worldwide. Stainless Steels and Nickel Alloys These materials have inherently higher corrosion fatigue limits than ordinary steels, with chromium and molybdenum a significant contributors to this resistance. Generally, the resistance to corrosion fatigue will parallel the relative resistance to such localized corrosion as pitting or crevice corrosion, because localized breakdown of the passive film prompts the failure in both cases. In many instances, corrosion fatigue cracks will emanate from the bases of pits initiated in the corrosive environment. Titanium Alloys Corrosion fatigue of titanium alloys is not considered common. Fatigue in fretted areas has been documented in some rotating aircraft components. 5.5.7.4 Control of Environmental Cracking
Environmental cracking can be controlled in many ways, including the following. Design The design can be changed to lower the tensile stresses to below the threshold level that helps to control stress corrosion cracking, or to a level significantly less conducive to cracking, to control other environmental cracking phenomena. If an alloy is susceptible to cracking in a given environment, the tensile stresses must be reduced. The total resultant stress from residual stresses, thermal stresses, and stresses from operating loads and pressure must be considered. A second design consideration to control environmental cracking is to avoid geometries in which solutions can become concentrated, or in which critical species can accumulate. Dead spaces where steam blanketing or water evaporation can occur are potential failure sites. Solutions with bulk chloride concentrations of 1 ppm can become concentrated to high chloride levels in crevices and other restricted geometries. The compatibility of materials throughout the system is a third design consideration. Contact of dissimilar metals can polarize one metal into the potential range for environmental cracking. Chlorides leached from insulation, or formed by hydrolysis of organic chlorides in elastomeric seals or plastic devices, can cause stress corrosion cracking of austenitic 18 8-type stainless steels. Ammonia introduced to control pH and minimize the corrosion of steel can promote stress corrosion cracking of copper alloys in adjacent equipment.
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The overall design should be reviewed for materials compatibility. A fix for corrosion in one part of the process must not cause environmental cracking elsewhere in the system. Materials Selection A common fix for an environmental cracking problem is to substitute a more resistant alloy for the one that has failed. It is important to identify the critical species causing the environmental cracking. Recall that specific alloy systems are subject to specific types of attack in specific environments. Another example of changing materials to control cracking is the substitution of lower strength steels for higher strength steels when hydrogen-induced cracking causes a failure. In addition to complete shifts from one alloy system to another, minor compositional changes within the alloy system may help control environmental cracking. Modification of Environment Environmental cracking sometimes can be controlled by eliminating the critical species from the environment, or by lowering its concentration to levels which will not promote cracking. Unfortunately, the concentration that will promote SCC depends on the alloy and the temperature, and experimental data are often required to identify safe concentration limits. When the concentration of critical species needs to be controlled, take care to ensure that species are not increased in concentration during service by evaporation or by localized boiling. In some environment-alloy combinations, it is possible to reduce environmental cracking by eliminating oxygen or oxidizing agents. Oxygen removal can be accomplished by reducing dissolved oxygen with a scavenging agent such as sodium sulfite. Minor constituents in the solution can also affect the concentration and temperature ranges in which cracking is observed. These minor constituents can be beneficial or detrimental. Another approach to modifying the environment is to prevent an aqueous solution from contacting the alloy. Stress corrosion cracking in gas storage and transmission service is controlled by dehumidifying the gases. If the water concentration is decreased and the dew point lowered sufficiently, no condensation will occur and environmental cracking is thus prevented. Carbon steel may successfully contain a dry mixture of carbon dioxide and carbon monoxide. In a wet mixture of these gases, carbon steel will fail rapidly by stress corrosion cracking. In duct work and other high-temperature systems, the temperature is purposely maintained above the dew point of the gas mixture to prevent condensation and, thus, cracking is controlled. Electrochemical Techniques Cathodic protection can be used to control some forms of environmental cracking; however, cathodic protection can contribute to hydrogen-induced cracking and must be used with care. Both anodic and cathodic protection have been used to polarize an alloy to a potential out of the range that will promote stress corrosion cracking. In anodic protection, the alloy is polarized to a potential more oxidizing than the stress corrosion cracking range. Steel in caustic solution may be protected by anodic protection. In cathodic protection, the metal is polarized to a potential more reducing than the cracking potential range. Polarization can be controlled either by galvanic action of dissimilar metals or by impressed currents. Conversely, changing the potential can be detrimental and can promote environmental cracking. A common instance of this is in cathodic protection of high-strength steels for corrosion control. Because hydrogen is generated on the steel surface, the cathodic protection may induce hydrogen embrittlement. Polarization to more reducing potentials by cathodic protection results in greater concentrations of hydrogen in the steel and greater susceptibility to cracking. Failures of galvanized high-strength bolts have resulted from this effect.
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Protective Coatings Coatings have been used to control environmental cracking, although the protection afforded is only as good as the integrity of the coating. Barrier coatings that effectively isolate the metal from an aqueous environment can help control environmental cracking. Metallic coatings also have been used to control environmental cracking. An outer layer of a resistant alloy may be clad to a high strength alloy substrate. The alloy surface effectively prevents contact of the aggressive environment with the high strength substrate which is susceptible to cracking. A combination of control techniques is illustrated by the application of primer systems that contain environmental cracking inhibitors to buried gas transmission pipe lines. Environmental cracking is controlled both by isolation of the steel from ground waters by the coating system and by the inhibitor, which leaches from the primer into the environment at flaws in the coating. Reduction in Residual Surface Stress Residual stresses from metal fabrication and unit construction are reduced by two principal methods: stress-relieving heat treatment or shot-peening, sometimes referred to as mechanical stress relief. In the first case, a fabricated item is heated to a temperature high enough for the residual stresses to relax. In the second case, the metal surface is mechanically peened at an intensity sufficient to cause residual compressive stresses at the surface. Both of these methods can effectively reduce surface stresses. In some cases, the residual surface stress can be reduced below the level required for environmental cracking.
5.6 Flow Assisted Corrosion In this section, we consider principal varieties of related attack due to flow of a substance across a surface. The surface may be either stationary (e.g., a valve seat) or moving (e.g., a pump impeller or propeller). Flow assisted corrosion is defined as the combined action of corrosion and fluid flow. The types of velocity phenomena we will discuss are: • Erosion-corrosion •
Impingement
•
Cavitation
5.6.1 Erosion-Corrosion Description Erosion-corrosion occurs when the velocity of the fluid is sufficient to remove protective films from the metal surface. Figure 5.30 shows eroded well-head equipment from an oil and gas well.
5.6.2 Recognition Erosion-corrosion often causes localized attack where surface discontinuities cause flow aberrations and turbulence. This phenomenon often occurs at weld beads. Figure 5.30 Eroded Well-Head Component2
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5.6.3 Mechanism Erosion-corrosion can occur in flowing liquids or gases with or without abrasive particles. In this form of attack, the velocity of the flow is sufficient to remove weakly adhered corrosion products from the surface, reducing their protective effect, and may also remove substrate. This results in an acceleration of the corrosion process. The fluid dynamics in erosion-corrosion by liquids can be an important factor in determining the rate of material removal. Turbulence of flow is also important. Velocity alone can explain a sudden increase in surface damage. When erosion-corrosion occurs, the effect of velocity on the corrosion rate usually exhibits a breakaway phenomenon, wherein a maximum velocity can be withstood without removal of the protective films. Above this limiting breakaway velocity, the corrosion rates increase very rapidly. The resistance to removal of protective films plays a significant role in determining the breakaway velocity for a given alloy-environment system. Erosion by particles in a corrosive medium may not proceed by complete removal of the corrosion product. At elevated temperatures (e.g., coal gasification environments), the corrosion product may be ductile and may flow with the particle impact. This results in the removal of a good deal of corrosion product and little base metal. The erosion debris, if collected and examined, will show characteristic rounded particles rather than the flakes characteristic of metal debris. Although not necessarily an electrochemical corrosion mechanism, elements of mechanical erosion are often encountered and the recognizable features should be defined. Mechanical erosion is caused by hard particles impacting on the surface and results in cratering of the metal surface. The plastic deformation at each impact extrudes metal around the particles, and the extrusions are broken off by later impacts. Erosion by particle impact is influenced by the angle of impact. For ductile metals, the removal rate maximizes at an impingement angle of about 20° to 30°. Other factors contributing to erosion rate are particle velocity, hardness and angularity as well as the temperature of the environment. The sensitivity of ductile materials to the angle of impingement causes localized erosion damage along the flow path. As material is removed from the surface, the impingement angle changes locally, and small areas in which the erosion efficiency is highest erode faster than other areas. A characteristic ripple pattern is shown. In some cases, it is difficult to discriminate between erosion-corrosion and velocity effect corrosion resulting from non-uniform mass transfer effects due simply to the greater availability of reactive material, and the reduction in dissolved metal ion concentration because of flow. If erosion-corrosion can be identified and there is no evidence of particle impingement, one possible solution is to reduce the flow rate, or remove flow-disturbing surface discontinuities.
5.6.4 Performance of Metals and Alloys Almost any material will be affected by the combined effects of velocity and corrosion if the velocity is high enough. The discussion that follows concentrates on the performance of metals at velocities typically found in piping and heat exchanger tube environments. 5.6.4.1 Aluminum and Aluminum Alloys
Aluminum and aluminum alloys, in general, are not very resistant to erosion-corrosion in environments where they are subject to corrosion, such as in potable water and seawater. Limiting velocities are usually on the order of 0.75 m/s (2 ft/s) or less. 5.6.4.2 Carbon and Low-Alloy Steels
Carbon and low-alloy steels, in general, are not very resistant to erosion-corrosion in environments where they are subject to corrosion, such as in potable water and seawater. Limiting velocities are usually on the order of 1 m/s (3 ft/s) or less.
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5.6.4.3 Stainless Steels and Nickel-Based Alloys
Stainless steels and nickel-based alloys generally show good resistance to erosion-corrosion. It should be remembered, however, that some alloys, particularly those in the stainless steel group, are not very resistant under stagnant conditions. All flow conditions must be considered when selecting materials for velocity service. 5.6.4.4 Copper Alloys
Generally, copper alloys are fairly resistant to erosion-corrosion attack. They are widely used for piping systems and heat exchanger tubes. They do have limiting velocities which must not be exceeded. These velocities are usually on the order of 2–4 m/s (6–12 ft/s).
5.6.5 Impingement Description Impingement is localized erosion-corrosion caused by turbulence or impinging flow. Entrained air bubbles tend to accelerate this action, as do suspended solids. This type of corrosion occurs in pumps, valves, and orifices, on heat exchanger tubes, and at elbows and tees in pipelines. 5.6.5.1 Recognition
Impingement corrosion usually produces a pattern of localized attack with directional features. The pits or grooves tend to be undercut on the side away from the source of flow, in the same way that a sandy river bank at a bend in the river is undercut by the oncoming water. 5.6.5.2 Mechanism
The mechanism of impingement is similar to that of erosion-corrosion, as flow removes the protective films responsible for the corrosion resistance of the material. In impingement, however, the flow is either turbulent or directed at roughly right angles to the materials, whereas, in erosioncorrosion, the flow is roughly parallel to the surface. When a liquid is flowing over a surface (e.g., in a pipe), there is usually a critical velocity below which impingement does not occur and above which it increases rapidly. Impingement attack first received attention because of the poor behavior of some copper alloys in seawater. In practice, impingement and cavitation may occur together, and the resulting damage can be the result of both. Impingement may damage a protective oxide film and cause corrosion, or it may mechanically wear away the surface film to produce a deep groove. 5.6.5.3 Water Drop Impingement
Water drop impingement is a form of mechanical erosion in which the eroding medium is highvelocity water drops. Analogous effects can be produced by any liquid drops at high velocity. Usually, the source of the drops is condensate, as is the case with steam turbines. Drops also occur in natural atmospheres, such as by rain. Raindrop erosion is a practical problem associated with high-speed jets, re entry vehicles, and helicopter rotor blades. Some similarities exist between solid-particle and water drop impact damage. The impact creates sufficient contact stress to cause the surface to yield and create craters. Impact can also cause disintegration and lateral jetting of fragments of the impacting particle, whether drop or solid. Solid particles will tend to cut the surface and, therefore, are more sensitive to impingement angle than are water drops. Water drop impact causes damage by the momentary high-pressure pulse induced during collision. This pressure, known as water hammer pressure, is a function of the drop velocity relative to the surface, the density of the liquid, and the velocity of sound in the material being eroded.
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Water drop impingement damage on a ductile material produces rounded craters of fairly uniform size and often craters within craters. The surface often looks something like a fracture surface, since it has ductile, dimpled characteristics. Solid particle impingement causes angular pits, conforming to the shape of the particle and imbedded particles may be found in the surface. This is a positive way to distinguish between water drop erosion and hard particle erosion. Identifying differences between water drop impingement damage and cavitation erosion is very difficult; it is often impossible to distinguish between the two. 5.6.5.4 Performance of Metals and Alloys
The interaction between the medium and the surface produces a film which either protects the surface from the material removal process, or is vulnerable to fracture and chipping from impact particles or liquid drops. Removal of protective or passivating films by shear forces from highvelocity flowing liquid or turbulence can accelerate galvanic action, especially when only a small area of substrate is exposed. When this is the case, the corrosion resistance of alloys will be similar to that of alloys experiencing film free liquid immersion corrosion. The rate of corrosion may be accelerated by the flow, but the resistance to the specific corrosive environment will be the same for each metal or alloy. Aluminum and Aluminum Alloys Aluminum alloys, in general, are not very resistant to impingement in environments where they are subject to corrosion (e.g., in potable water and seawater). Carbon and Low-Alloy Steels Carbon and low-alloy steels, in general, are not very resistant to impingement in environments where they are subject to corrosion (e.g., potable water and seawater). Stainless Steels and Nickel-Based Alloys Stainless steels and nickel-based alloys, in general, show good resistance to impingement. Copper Alloys Copper alloys, in general, are not very resistant to impingement in environments where they may corrode, such as in potable water and seawater. Otherwise, they are fairly resistant to velocity attack. These alloys are widely used for piping systems and heat exchanger tubes, where impingement effects can be reduced through design. Titanium, Zirconium, Tantalum Titanium, zirconium, and tantalum have good resistance to velocity effects in general.
5.6.6 Cavitation Description Cavitation is a mechanical damage process caused by collapsing bubbles in a flowing liquid. See Figure 5.31 for an example of corrosion due to cavitation. 5.6.6.1 Recognition
Cavitation usually results in the formation of deep aligned pits in areas of turbulent flow.
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5.6.6.2 Mechanism
Cavitation is caused when protective films are removed from a metal surface by the high pressures generated by the collapse of gas or vapor bubbles in a liquid. When the energy input to produce cavitation is sufficiently high, neither will significantly contribute hard particle impact or corrosion to the process. The necessary high-energy inputs can be duplicated in the laboratory with suitably-powered ultrasonic transducers. Under these conditions, extreme turbulence can cause the collapsing voids in the liquid to disappear in about a microsecond (one millionth of a second) and can generate forces on the order of about Figure 5.31 Erosion Corrosion Due to Cavitation on 700MPa (100 ksi) as the bubbles collapse. Stainless-Steel Pump Impeller This process can literally tear the surface apart. The action is somewhat similar to the water hammer effect in pipes when a valve is closed suddenly. The steps through which this process is thought to occur are: 1. Bubbles form in an area of low pressure. 2. Bubbles move to higher pressure areas. 3. Bubbles collapse, forming high-pressure waves in the liquid. 4. Pressure waves impinge on the surface, removing the protective film. 5. Corrosion occurs at the bare area (may or may not occur). 6. Process repeats. 5.6.6.3 Performance of Metals and Alloys
In general, higher-strength alloys are more resistant to cavitation corrosion than lower-strength materials. Cavitation damage should be considered as two separate phenomena. When cavitation damage is caused primarily by corrosion following the removal of protective films, the corrosion portion of the damage may predominate. The cavitation itself is incapable of mechanically damaging and removing the underlying metal. Under these conditions, the corrosion behavior of the material is important. Under extreme cavitation conditions, the cavitation itself is capable of damaging and removing the metal directly, and corrosion effects are insignificant. Aluminum Alloys Aluminum alloys, in general, are not very resistant to cavitation damage because of their low strength. Carbon and Low-Alloy Steels Carbon and low-alloy steels, in general, are not very resistant to cavitation damage unless the cavitation is incapable of directly damaging and removing the steel. In this case cathodic protection or the use of corrosion inhibitors, can reduce the effects of cavitation.
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Stainless Steels and Nickel-Based Alloys Generally, stainless steels and nickel-based alloys show better resistance to cavitation than many materials because of their relative high strength and resistance of their protective films to mechanical damage. However, they are susceptible to cavitation under extreme conditions. Copper Alloys Copper alloys, in general, are not very resistant to cavitation because of their low strength. Impingement is more likely to occur in environments corrosive to them such as potable water and seawater. Otherwise, these materials are fairly resistant to velocity attack. They are widely used for piping systems and heat exchanger tubes, where impingement effects can be reduced through design. Titanium, Zirconium, and Tantalum Titanium, zirconium, and tantalum have good resistance to velocity effects in general. 5.6.6.4 Control of Flow Assisted Corrosion
Flow assisted corrosion can be controlled in many ways, including the following. Design Velocity effects can be controlled through design, primarily by controlling the flow velocity and flow patterns. Flow velocities should not exceed the limiting velocities of the materials selected. Smooth flow is always preferable to turbulent flow from the standpoint of velocity effect corrosion. Entrained gases and solids should be eliminated from flow whenever possible. Pressures should be considered when cavitation damage is possible. Materials Selection Selecting a material because of its resistance to the expected flow velocity and flow regime is widely used to control velocity effect corrosion. As mentioned above, all conditions within the system (e.g., periods of stagnation) must be considered when selecting materials. Modification of Environment In some cases, corrosion inhibitors can effectively control velocity effect corrosion. Some inhibitors can reduce the corrosion rate of the areas from which the protective films have been removed. Another beneficial effect of some inhibitors is that they can increase the resistance of the protective film to velocity effects. Protective Coatings Protective coatings can be used to control velocity effects. Rubber linings are particularly effective in reducing erosion-corrosion effects when solid materials are contained within the flow stream. Of course, the bond of the protective coatings to the materials is an important factor in their use to control velocity effects. Metal coatings, applied by cladding or weld overlay, are widely used to control velocity effect corrosion. Cathodic Protection Cathodic protection can effectively control corrosion of metal even when the metal is not covered with protective films. Thus, velocity effect corrosion can be controlled by cathodic protection. The required electrical current for cathodic protection in high-velocity flow is usually much greater than the current required for low velocity flow.
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5.7 Intergranular Corrosion Definition Intergranular corrosion is preferential attack at or adjacent to the grain boundaries of a metal.
5.7.1 Description As described previously in this course, almost all engineering metals are composed of individual crystals (or grains) which meet at areas of relative impurity and misalignment called grain boundaries. The corrosion that occurs preferentially at or adjacent to these grain boundaries results in a very large corrosive effect compared to the actual amount of metal removed at the grain boundaries. In some cases, individual grains are loosened and lost from the material. In other cases, the localized loss of grain boundary material results in localized attack similar in appearance to cracking.
5.7.2 Recognition Intergranular corrosion usually produces surfaces that are granular in appearance. It may also take the form of localized areas with an appearance similar to cracking. See Figure 5.32 for an example of intergranular corrosion.
5.7.3 Mechanism Intergranular corrosion occurs when the grain boundaries or the areas directly adjacent to the grain boundaries are anodic to the surrounding grain materials. Grain boundaries may be anodic to the surrounding metal through many mechanisms. They may be anodic because of differences in impurity levels between the grains and the grain boundaries. They may be anodic because of the effective strain energy of misaligned atoms in the grain boundaries. The grain boundaries, or adjacent areas, may be anodic because of the formation of precipitates due to improper heat treatment.
Figure 5.32 Intergranular Corrosion of an Aerospace Aluminum Alloy (UNS A97075)
5.7.4 Performance of Materials Although several metals and alloy systems are subject to intergranular corrosion, we will concern ourselves primarily with stainless steels and aluminum alloys. 5.7.4.1 Intergranular Corrosion of Stainless Steel
Intergranular corrosion of stainless steels is caused most frequently by three types of metallurgical effects that cause the grain boundaries or areas adjacent to the grain boundaries to become anodic relative to the surrounding material. The three types of effects are: • General sensitization •
Weld decay
•
Knife line attack
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General Sensitization Austenitic stainless steels, either when they are cooled slowly through a temperature range of approximately 500ºC–850ºC (932ºF–1,562ºF), or are otherwise maintained for some time in that range, can become susceptible to intergranular attack if subjected to specific corrodents. The grain boundaries are said to be “sensitized.” This sensitization is caused by the formation of chromium carbides, depleted chromium from the grain boundaries and the adjacent areas. A very small weight percentage of carbon combines with a relatively large weight percent of chromium. The sensitized areas do not have sufficient chromium content to produce a stable passive film. They become anodic with respect to the surrounding passive material. As will be described later in more detail, sensitization of stainless steels can be prevented by the following methods: • Avoid heating the metal in the sensitizing temperature range •
Heat treatment to eliminate chromium carbides
•
Use of a material with very low carbon content
•
Use of “stabilized” material, which contains alloy additions that preferentially combine with carbon rather than combine carbon with chromium
If ferritic stainless steels are quenched rapidly they can also become sensitized. Weld Decay Weld decay occurs in the heat affected zone about 6 mm (0.24 in) from the actual weld and parallel to it. Weld decay is the same as sensitization, except it occurs locally from welding effects rather than over the entire substrate. Weld decay results in uniform thinning adjacent to the weld, where grains of metal have been removed because of intergranular attack. Knife Line Attack Knife line attack occurs in a narrow zone near the interface of the weld pool and the base metal. Knife line attacks occur only in certain grades of stainless steel stabilized at the weld temperature, which is higher than the temperature at which sensitization occurs. In general sensitization and weld decay, chromium has a higher affinity for carbon than for the titanium or niobium which has been added to stabilize the material. Therefore, when the weld cools in the narrow weld zone, chromium carbide precipitates in the fusion line. Thus, resistance to corrosion is lowered adjacent to the weld. 5.7.4.2 Aluminum and Aluminum Alloys
The chemical composition, mechanical working, and heat treatment of aluminum alloys have been developed to minimize intergranular corrosion. During welding this careful balance can be easily upset, and the alloys can become susceptible to intergranular attack. Both the weld filler materials and the welding process, particularly the control of heat input, must be controlled carefully to minimize the adverse effects welding has on aluminum alloys with respect to intergranular corrosion. Certain aluminum alloys are subject to a form of intergranular attack known as exfoliation. Exfoliation looks layered or leafed in character, and consists of alternating strata of corroded and corrosion free metal. Corrosion products that result from the attack force the uncorroded layers upward from the surface, thus giving it the characteristic appearance of exfoliation. Typically, the corrosive attack is parallel to the plane of maximum reduction, such as the rolling plane in sheet and plate. Although many aluminum alloys are resistant to intergranular corrosion, others are not-particularly aluminum alloy systems containing magnesium, copper, or both. Aluminum can develop intergranular corrosion in an aqueous environment if chloride is present. Such conditions are a concern in seawater and other chloride-containing environments.
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Intergranular corrosion of aluminum is believed to occur in susceptible aluminum alloys as a result of the formation of precipitates along grain boundaries. For example, aluminum copper alloys (the 2XXX series), contain about 4% copper, and exhibit intergranular attack under certain circumstances. After fabrication (welding) of these alloys, it is customary to solution heat treat the piece at approximately 490ºC (920ºF) and water quench it. This class of alloys will age harden at room temperature. If, however, the quench is incorrectly performed, CuAl2 can precipitate along grain boundaries, leaving a zone adjacent to the grain boundaries that is depleted of copper. 5.7.4.3 Copper and Copper Alloys
Copper and many copper alloys are susceptible to intergranular corrosion in environments containing amines or ammonia. Copper-nickel alloys are more resistant than other copper alloys in these environments. 5.7.4.4 Nickel and Nickel-Based Alloys
Commercially-pure nickel is subject to intergranular oxidation at elevated temperatures. Nickel copper alloys have reportedly suffered intergranular corrosion in certain hydrofluoric acid and chromic acid solutions. The exact sensitization mechanism has not been determined. Intergranular corrosion can also occur in the nickel molybdenum alloys in hot hydrochloric acid and sulfuric acid, especially (due to precipitates of molybdenum-rich constituents) because these acids precipitate molybdenum-rich constituents. Nickel-chromium alloys of the Inconel variety are subject to intergranular corrosion because of Cr7C3 precipitation and are not intended for service where this could be a problem. Some nickelchromium alloys have been stabilized against this type of attack and are effective in normal welding-type construction for corrosive service. These alloys, however, are potentially subject to knife line attack (in the case of titanium stabilized alloys) or to attack of intermetallic phases in highly oxidizing acid solutions. In the molybdenum-bearing grades, intergranular corrosion is caused by molybdenum carbides and by molybdenum-rich intermetallic compounds, rather than by chromium carbides. This problem has been countered by stabilization and by reduction of carbon content. These types of alloys have also experienced problems oxidizing chloride solutions (e.g., ferric chloride, hypochlorites) and in oxidizing and reducing acids.
5.7.5 Control of Intergranular Corrosion Intergranular corrosion can be controlled in several ways, including the following. 5.7.5.1 Materials Selection
Alloys can be selected for their resistance to intergranular corrosion in a specific service environment. For the stainless steels, alloy variations low in carbon content (the “L” grades) can be used, as well as grades containing additions stabilizing of such elements as titanium and niobium. 5.7.5.2 Design/Fabrication
If the material is not resistant to intergranular corrosion from the effects of welding, the welds may be eliminated by using another joining technique. In some cases, the joints themselves can be eliminated in the design. Other fabrication processes requiring heating of the metal must be properly controlled. 5.7.5.3 Modification of Environment
In some cases, the environment can be modified so that the affected grain boundaries are no longer anodic with respect to the adjacent material. This may be accomplished by adding corrosion inhibitors, or by removing aggressive ions (such as chlorides) where aluminum alloys are used.
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5.7.5.4 Use of Proper Welding Procedures
Proper welding procedures can minimize or eliminate the effects at grain boundaries that lead to intergranular corrosion. Welding procedures which minimize intergranular corrosion, once developed, must be followed carefully to obtain the desired effects. 5.7.5.5 Heat Treatment
Proper heat treatment can eliminate intergranular corrosion either by preventing grain boundary effects in the first place, or by removing the adverse effects of improper heat treatment or welding. This commonly consists of a heat treatment called a “solution heat treatment,” which dissolves the undesirable constituents at the grain boundaries. This heating is usually followed by a rapid cooling to prevent reformation of undesirable precipitates at the grain boundaries.
5.8 Dealloying 5.8.1 Definition Dealloying is a corrosion process in which one constituent of an alloy is removed preferentially, leaving an altered residual structure.
5.8.2 Description Most engineering metals are alloys that consist of mixtures of elements. In some cases, such as in the case of zinc and copper alloyed to produce a brass, one element used is anodic with respect to the other elements in the alloy and can selectively corrode by galvanic action. The phenomenon was first reported in 1866 on brass (i.e., copper zinc) alloys. It has been reported since in virtually all copper-based alloy systems, as well as in cast iron and other alloy systems.
5.8.3 Recognition Dealloying is commonly detectable as a color change or a drastic change in mechanical strength. Brasses will turn from yellow to red, and cast irons from silvery gray to dark gray. Gray iron that has suffered graphitic corrosion can be cut with a pen knife. Recognizing dealloying may be difficult where deposits, colored environments, or accessibility make inspection complicated. Detecting dealloying may be difficult with most methods of automated inspection because no volume change occurs and because the density difference can be masked by precipitated salts, corrosion products, etc., within the dealloyed region. Various laboratory techniques, such as cross-sectioning the part in question, will normally provide evidence of color changes. Metallographic examination at high magnification and x-ray spectroscopy (normally performed with a specially-equipped scanning electron microscope or with an electron microprobe) can also provide positive identification.
5.8.4 Mechanism The dealloying mechanism can be either a selective removal of one or more alloy constituents, leaving a residual substrate, or dissolution of the entire alloy, with one or more constituents redeposited. Laboratory investigations have shown that both processes can occur simultaneously under certain conditions. In either case, the corrosion results in a residual metal with essentially the same surface profile and volume as the parent metal. This is sometimes referred to as a “pseudomorph” of the original artifact. Typically, up to 30% or more of the original metal will have corroded away, and the residual “sponge” or “plug” will have virtually no mechanical strength.
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5.8.5 Performance of Metals and Alloys 5.8.5.1 Copper Alloys
Dealloying was originally observed in brasses and termed “dezincification” to connote the loss of zinc from the original copper zinc alloy. Other terms, such as “destanification,” “denickelification,” and “dealuminification,” have been used to indicate the loss of other alloying constituents. 5.8.5.2 Brasses
Red brasses composed of 15% zinc or less are usually resistant in conventional applications in aqueous or atmospheric service. Yellow brasses, including inhibited “aluminum brass” and admiralty brass, are resistant in such moderate environments as potable or fresh cooling waters if they contain tin, plus arsenic, antimony, or phosphorus. 5.8.5.3 Bronzes
Phosphor (tin) bronzes have been subject to destanification (i.e., dealloying of tin from the alloy) in severe chemical environments. Aluminum bronzes (copper-aluminum alloys) are sometimes subject to dealuminification. Compositions are available that minimize this problem by avoiding the formation of a metastable high-temperature phase, which is particularly vulnerable to this form of corrosion. These alloys are normally used as castings, which makes precise microstructural control difficult. Nonetheless, heat treatments have been suggested to minimize the problem. The wrought alloys seem to be resistant except in certain severe chemical environments, such as phosphoric acid at elevated temperature. Silicon bronzes have been subject to desiliconification in isolated cases involving high-temperature steam plus acidic species. Cupronickels have occasionally been reported to suffer dealloying under conditions of localized corrosion. 5.8.5.4 Cast Iron
Dealloying of gray cast irons usually proceeds uniformly inward from the surface, leaving a porous matrix of carbon. Graphitic corrosion, or graphitization, is a form of dealloying caused by the selective dissolution of iron from some cast irons, usually gray cast iron. See Figure 5.33 for an example of graphitic corrosion on cast iron. In the dealloying of gray cast iron, the iron corrodes, leaving the graphite matrix. In this instance more than 90% of the original alloy can be lost due to corrosion, with no apparent change in volume or thickness. There is no outward appearance of damage, but the effected metal loses weight and becomes porous and brittle. Depending on alloy composition, the porous residue may retain some appreciable tensile strength and have moderate resistance to erosion. For example, a completely graphitized buried cast iron pipe may continue to hold water under pressure until jarred by a workman's shovel. Graphitization occurs in salt waters, acidic mine waters, dilute acids, and soils, particularly those containing sulfates and sulfate reducing bacteria. The presence of sulfates and sulfate reducing bacteria in soil stimulates this form of attack. The addition of several percent of nickel to cast iron greatly reduces susceptibility to graphitization. It is possible to produce graphitization in the laboratory by immersing gray cast iron in very dilute sulfuric acid.
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Figure 5.33 Graphitic Corrosion (Dark Areas) on the Exterior of a Cast Iron Water Main1
5.8.6 Control of Dealloying Control of dealloying can be accomplished in several ways, including: 5.8.6.1 Materials Selection
Control of dealloying is normally achieved by using an alloy that is more resistant to this form of corrosion, such as: • Inhibited brasses instead of ordinary brasses •
Ni-resistant cast iron instead of gray cast iron
•
Nodular or malleable cast iron instead of gray cast iron
5.8.6.2 Control of Environment
It is sometimes possible to control dealloying corrosion by changing the environment, especially in regard to acidity/alkalinity. For example, acidic waste waters that cause graphitic corrosion of cast iron can be controlled by proper treatment. Corrosion inhibitors can also control dealloying in some metal environment systems. 5.8.6.3 Use of Protective Coatings
Protective coatings may be useful in some instances. 5.8.6.4 Electrochemical Techniques
Cathodic protection has been shown to control dealloying.
5.8.7 Design Temperature is often used to control dealloying. Minimizing hot-wall effects in heat exchangers can be beneficial in controlling dealloying of some materials.
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5.9 Fretting Corrosion 5.9.1 Definition Fretting corrosion is defined as metal deterioration caused by repetitive slip at the interface between two surfaces in contact.
5.9.2 Description Fretting usually involves the relative motion of two surfaces that were not intended to move in that fashion.
5.9.3 Recognition Fretting corrosion occurs at the interface between two surfaces which can move with respect to each other. Surfaces affected by fretting corrosion are often free of corrosion products and show a burnished appearance.
Figure 5.35 Loose Fit Tubing in Heat Exchanger Baffle
Figure 5.34 Fretting Corrosion Due to Chain Vibrating Against a Stationary Fence Post
Figure 5.36 Fretting And Fatigue of Heat Exchanger Tube
5.9.4 Mechanism Fretting corrosion occurs when motion between surfaces either removes protective films, or, combined with the abrasive action of corrosion products, mechanically removes material from surfaces in relative motion. For fretting corrosion to occur, the interface must be under load and the motion (usually of small amplitude) must be sufficient for the surfaces to strike or rub together. Results of fretting include: • Metal loss in the area of contact •
Production of oxide and metal debris
•
Galling, seizing, fatiguing, or cracking of the metal
•
Loss of dimensional tolerances
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•
Loosening of bolted or riveted parts
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Destruction of bearing surfaces
The wear process in fretting is not well understood. It is known that the debris produced can be either an oxide, if oxidation conditions exist, or very fine metal particles, if no corrosive medium invades the contact region. The debris can be abrasive and exacerbate in the fretting wear process.
5.9.5 Performance of Metals and Alloys Virtually all materials are subject to fretting corrosion if the correct conditions are present.
5.9.6 Controls Techniques for control of fretting corrosion include: 5.9.6.1 Materials Selection
To control fretting corrosion when the motion between the surfaces cannot be eliminated, use mating surfaces of different materials, e.g., soft metal against harder metal. 5.9.6.2 Design
In system design, avoid situations in which there can be small relative motion between surfaces. This can be accomplished by roughening the interface, increasing the load, or greatly increasing the relative motion between the surfaces. The environment between the surfaces can be controlled by the use of cements or sealants. These materials can also reduce or eliminate abrasive scrubbing between the surfaces. 5.9.6.3 Use of Lubricants
Lubricants, such as molybdenum sulfide at the faying surfaces, can be used to control fretting corrosion. The use of such low friction materials as fluorocarbons, either as one surface in the system or as a lubricant, can also be effective in controlling fretting corrosion.
5.10 High-Temperature Oxidation/Corrosion High-temperature corrosion is a form of material degradation that occurs at elevated temperatures. Direct chemical reactions, rather than reactions of the electrochemical cell, are responsible for the deterioration of metals by high-temperature corrosion. The basis of high-temperature corrosion resistance stems from considerations of thermodynamics and kinetics of reactions at elevated temperatures. Thermodynamics determines the tendency of metals to react in specific environments, considering both the temperature and species present in the environment (oxygen, water, sulfides, hydrogen, etc.). In the case of kinetics, whether or not a metal is considered corrosion-resistant is dependent not on whether it corrodes, rather, how fast it corrodes. To determine what factors cause whether a hightemperature corrosion reaction to occur slowly or rapidly, we must consider the characteristics of the corrosion product layer which forms. The behavior of metals at elevated temperatures, and especially their corrosion behavior, is a detailed and complex subject. Our discussion of high-temperature corrosion will focus on its practical aspects.
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5.10.1 Definition High-temperature corrosion is the deterioration of a metal at temperatures where direct chemical reactions between the metal and the environment cause the material to degrade. The actual temperature at which high-temperature corrosion becomes important depends upon the material and the environment, but the corrosion usually begins to occur when the temperature is about 30%–40% of the melting point of the alloy. It is usually in this range that mechanical properties are governed by creep strength, and here the first evidence of what we consider to be high-temperature corrosion characteristics appear. • Magnesium and aluminum alloys are in high-temperature modes at temperatures as low as 204°C (400°F), iron and steel at temperatures as low as 426°C (800°F). •
Stainless steels in the range of 425°–870°C (800°–1,600°F)
•
Titanium, on the other hand, loses strength at temperatures as low as 315°C (600°F), despite its high melting point, 1,815°C (3,300°F).
5.10.2 Recognition High-temperature corrosion (Figure 5.37) is usually associated with the formation of thick oxide or sulfide scales, or with internal reactions that cause internal swelling of the metal at elevated temperatures.
Figure 5.37 High Temperature Corrosion of Gas Turbine Vane10
5.10.3 Mechanisms High-temperature corrosion is dependent on several reactions, including: • Oxygen reactions •
Sulfidation
•
Carburization
•
Decarburization (hydrogen effects)
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•
Halide effects
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Molten-phase formation
5.10.3.1 Oxygen Reactions
Oxygen reactions are the most common and most widely studied high-temperature corrosion reactions. Oxygen reaction concepts are directly applicable to most other gas metal, high-temperature reactions in which a scale is formed. In fact, almost all high-temperature corrosion reactions can be classified as oxidation, whether the scale is an oxide, a sulfide, or a halide, because the valence charge of the metal has been increased. Most metals will react directly with oxygen at high temperatures. When a metal is oxidized at elevated temperatures, an oxide or other compound may form. This corrosion product layer may act as a barrier between the substrate and the corrosive environment (air, flue gas, molten salt, or any other corrodent). To be effective in controlling the rate of oxidation, oxide scales must: • Be physically stable •
Maintain good mechanical integrity
•
Adherent to substrate
•
Possess slow-growth kinetics
•
Have low volatility
5.10.3.2 Reaction Rates
Depending on the degree to which the scale formed prevents attack on the base metal, the corrosion reaction can be either a linear or a parabolic function of time (Figure 5.38). Other rate behaviors with respect to time are also possible. 5.10.3.3 Linear Behavior
If the oxide film or scale cracks or is porous and the corrosive environment continues to penetrate Figure 5.38 High Temperature Corrosion readily and react with the base metal, protection will be limited and attack will proceed at a rate determined essentially by the availability of the corrosive species. In this case, the rate will be linear. 5.10.3.4 Parabolic Behavior
If the scale formed is continuous, adherent, and prevents easy access of the corrosive gas to the underlying base metal, a considerable measure of protection may occur and the extent of protection will increase as the scale thickens. In this case, the availability of the corrosive gas will not determine the reaction rate. Diffusion through the scale will be the slowest and, hence, the rate controlling factor. The diffusing element that controls the reaction rate may be either the oxygen moving inward or the metal
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moving outward. The latter is more likely in alloys possessing good corrosion resistance. As the scale thickens, if everything else remains the same, the diffusion rate will decrease, so the rate of scale growth will decrease and be inversely proportional to its thickness at any point in time. 5.10.3.5 Oxide Scale Characteristics
As briefly mentioned, important characteristics of scales with respect to their ability to control high-temperature corrosion include scale thickness and scale adhesion. 5.10.3.6 Scale Thickness
Scale thickness can be an important factor. In early stages, the scale is thin and comparatively elastic. At this stage it has little intrinsic strength and usually will remain tightly adhered to the base metal. As it thickens however, its less desirable properties may become manifest. Heavy scales tend to be brittle and so tend to rupture and spall from the surface. The volume of scale formed, relative to the volume of the metal reacting, often has been cited as a principal factor controlling scale continuity. It has been postulated that for maximum performance, the scale volume should exceed that of the metal consumed. In this case, the surface scale is under some compressive stress, which is desirable for most brittle materials, and the tendency to crack is minimized. Certainly, if the scale volume was considerably less and tensile stresses existed, susceptibility to rupture would be much greater. 5.10.3.7 Scale Adhesion
The matter of scale adhesion is important, particularly if temperature variations occur. A weakly adhered scale is likely to separate locally from the base metal, a phenomenon sometimes termed blistering. Scales will eventually rupture and spall because they have little intrinsic strength. Adhesion may be affected by differences in the thermal coefficients of expansion between scale and base metal. The nature of the interface between the scale and base metal also affects scale adhesion. If the interface is smooth, it is easy to conceive of a shear crack initiating at the interface and propagating rapidly across the surface. If the interface is rough and incipient grain boundary attack occurs beneath the scale, a keying action may prevent rapid crack propagation and thus may improve scale adherence. It is thought by some that reactive rare earth additions to heat resistant alloys exert their armor effect not by entering the scale and lowering diffusion rates, but by accumulating in grain boundaries, thus ensuring a small amount of grain boundary attack to provide the keying action. 5.10.3.8 Internal Oxidation
It is also possible for oxidation to proceed without external scale, provided certain conditions exist. The alloy must contain, as a minor ingredient, an element that is considerably more reactive than the major constituent. Silicon in copper is one example; chromium in nickel is another. The concentration of the minor element must be less than a certain critical value. The rate at which the minor element diffuses toward the surface must be less than that at which the corrosive species diffuses inward. Internal oxidation is controlled by the concentration of oxygen in surface layers. This quantity must be insufficient to oxidize the nobler major constituent, but sufficient to oxidize the reactive minor constituent. External scale will form only when the effective pressure of oxygen at the metal gas interface exceeds this range for the more noble component, or when the concentration of the less noble component exceeds some critical value. Conversely, failure of surface scale to form can indicate that the oxygen partial pressure at the interface is at such a level that the oxygen will not react with the major constituent.
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An early example of destructive internal oxidation was found in failures of the chromel alumel thermocouples used to measure the temperature of a hydrogen rich gas. The hydrogen was able to penetrate the protection tube and set up an atmosphere of 90% nickel 10% chromium-chromel alloy within the tube; this atmosphere was reducing to the nickel, but oxidizing to the chromium. Thus, no nickel oxide surface scale formed, and the chromium concentration was not sufficient to form an external chromium oxide scale. Instead, islands of Cr2O3 formed within the alloy, giving the fracture surfaces their characteristic green color “green rot”. One method to correct situations of this sort is to include in the assembly an active “getter” for oxygen, such as a strip of titanium, which by removing the oxygen will leave an atmosphere that is reducing to both constituents of the alloy. 5.10.3.9 Sulfidation
When the sulfur activity (partial pressure, concentration) of the environment is sufficiently high, sulfide phases (in addition to oxide phases) can be formed. In the majority of environments encountered, alumina or chromium sesquioxide generally form in preference to any sulfides, and destructive sulfidation attack occurs mainly at sites where the protective oxide has broken down. Sulfur can be transported through scales. Once it has entered the alloy, sulfur appears to tie up the chromium and aluminum as sulfides, effectively redistributing the protective scale-forming elements near the alloy surface, thus interfering with the process of scale formation or reformation. If sufficient sulfur enters the alloy so that all immediately-available chromium or aluminum is converted to sulfides, the less stable sulfides of the base metal can then form. It is these base metal sulfides that are often responsible for the accelerated attack observed because they grow much faster than the oxides or sulfides of chromium or aluminum. They have relatively low melting points, so molten slag phases are often possible. Sulfur can be transported across continuous protective scales of alumina and chromium sesquioxide under certain conditions, with the result being that discrete sulfide precipitates can be observed immediately beneath the scales on alloys behaving in a protective manner. For reasons indicated above, as long as the amount of sulfur present as sulfides is small, there is little danger of accelerated attack. However, once sulfides have formed in the alloy, there is a tendency for the sulfide phases to be preferentially oxidized by the encroaching reaction front (oxides are more stable than sulfides) and for the sulfur to be displaced inward. This process prompts the formation of new sulfides deeper in the alloy, often in grain boundaries or at the sites of other chromium- or aluminum-rich phases, such as carbides. In this way, finger like protrusions of oxide/sulfide can be formed from the alloy surface inward, which may act to localize stress or otherwise reduce the load-bearing section. 5.10.3.10 Carburization
Metals such as steel, when exposed to a suitable carbonaceous gas or liquid at high temperature, may absorb some of the carbon atoms that reach the metal surface. The surface, because of its higher carbon content, will respond better to heat treatment and develop a higher surface hardness, while the interior will be softer but tougher, a desirable characteristic for many applications. Most metals have a significant solubility for carbon, that is, they can absorb large amounts of carbon without undergoing any drastic physical change, although some properties, e.g., response to heat treatment, may be altered measurably. If carbon continues to be driven into the metal, its solubility can be exceeded and more dramatic changes will occur. In pure nickel, which forms no stable carbide at high temperatures, embrittlement from graphite precipitation may occur, and in the more commonly used heat resistant alloys of the iron nickel chromium system, precipitation of chromium rich carbides will occur.
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Initially, such carbides will have little effect on the chemical or physical behavior of the alloy. In fact, most commercial chromium containing alloys, such as the stainless steels, have a small quantity of chromium carbides present. However, as carburization continues and the quantity of carbides increases, the situation will change. Because chromium forms carbides more readily than the other constituents of stainless steels, the matrix of the alloy will be depleted of chromium. As discussed previously, chromium is the element that contributes most to resistance to oxidation and sulfidation. The chromium depleted matrix will be unable to develop adequate protective scales and will become quite susceptible to these and other types of attack.14 Furthermore, the presence of continuous grain boundary carbides will both increase the rate of intergranular attack (because the carbides are more reactive than the matrix) and deteriorate mechanical properties (because cracks can propagate more readily). Another possible effect of carburization is metal dusting. This phenomenon occurs in process operations where oxidizing and reducing conditions alternate. When the environment is on the reducing side (CO predominant), shallow carburization of the metal can occur at breaks in the protective oxide film. When the exposure then changes to oxidizing, the high-carbon area of the metal is burned out and the underlying metal reacts to become new oxide. A depression is left in the metal surface where the carburized area existed, and the metal oxide is swept downstream as metal dust. 5.10.3.11 Decarburization (Hydrogen Effects)
Decarburization attack, or high-temperature hydrogen effect, is also a high-temperature phenomenon. It should be clearly distinguished from hydrogen-induced cracking, which occurs at near-ambient temperatures and is usually associated with an aqueous environment as the source of the hydrogen. At temperatures above dew point, high-pressure hydrogen is the usual source. The attack relates to the reaction of hydrogen, with readily reducible carbides, or in some cases oxides, within the alloy to form methane or steam. Under high pressure, these gaseous products will cause small local ruptures which will impair the structural integrity of the metal and lead to early failure. Hydrogen is a difficult gas to cope with at elevated temperatures because of its ability to diffuse rapidly through metals in atomic form and because of its extreme reactivity. If the hydrogen, during its passage through the metal, encounters such readily-reducible compounds as the carbides previously mentioned, an irreversible reaction will occur. Because the movement of hydrogen through metals cannot be prevented, the principal means of control is to ensure that the carbides formed are sufficiently stable to resist reaction with hydrogen. Such elements as chromium and molybdenum form carbides considerably more stable than iron carbides, so steels containing additions of these elements have been quite successful in resisting hydrogen attack. Note, however, that blistering can be caused by such defects as seams and inclusions and will not be eliminated merely by selecting a stabilized alloy. Remember, atomic hydrogen penetrates through common metals. In a clad vessel (e.g., copper-nickel, or stainless clad steel), the substrate steel must be alloyed to resist the process side conditions of temperature and partial pressure of hydrogen. Otherwise, the steel substrate will be attacked by atomic hydrogen passing through the corrosion-resistant cladding. 5.10.3.12 Halide Effects
Halogen gas can form volatile halide layers on metal substrates. When a critical temperature is reached, the halide layer evaporates, leaving the metal substrate exposed to further rapid reaction. In industrial service the principle halides of interest are chlorine and fluorine, together with hydrochloric and hydrofluoric acid vapors. Bromine and iodine are of secondary importance, but relatively little data exist even for the gases of major significance.
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Despite the small amount of data, it is interesting to consider halide attack because it introduces a new mode of scale breakdown. In principle, corrosion by halogens proceeds in essentially the same fashion as corrosion by oxygen, sulfur, or nitrogen. The gas, upon contacting the surface, will oxidize the metal atoms there and form a halide layer. The halide scale, while it remains in place, will offer some measure of protection against continuing attack. The major difference is that metal halide compounds all have very high vapor pressures, so that when some critical temperature is exceeded, the scale will volatize and leave the metal surface exposed for further rapid reaction. Although a few oxides (e.g., MoO3) are volatile at relatively low temperatures and others (e.g., Cr2O3) may reach significant vapor pressures at very high temperatures, volatization of oxides can be ignored in most cases; it cannot for halides. Many metal halides, such as chlorides, fluorides, and bromides, have high vapor pressures; scales formed by these halides vaporize quickly above a certain critical temperature, leaving the metal exposed for continuing attack. 5.10.3.13 Molten-Phases Formation
In all environments considered up to this point, we have ignored the possibility of corrosion product fusion and have limited the discussion to gas metal reactions with solid, or in the case of halides, gaseous reaction products. In many situations, a clear distinction cannot be made. The corrosion product itself may melt, or contaminants may lower the melting point into the service temperature range. The reaction products or harmful contaminants have one thing in common: whether they themselves are solid, liquid, or gaseous, they react with the metal or corrosion products to form a fused phase. This phase will destroy the integrity of the protective scale by fluxing or dissolving it and leaving the underlying metal available for further corrosion. Frequently the fused phase will attract and concentrate potent corrodents at the place where they do the maximum amount of damage: where the scale is disrupted. Ideally, the contaminating phase is removed and the problem is eliminated. However, this remedy is frequently not possible. Because of the numbers of contaminants which may interfere with the normal development of a protective scale during high-temperature service, it is virtually impossible to present a complete list. Some familiar examples include: • Leaded gasoline (lead oxide) •
Residual oils
•
Sea salt
•
Welding slag
The combustion of leaded gasoline leaves deposits of lead oxide and other compounds on exhaust valves that can shorten their lives. Due to the introduction of unleaded gasolines, it was discovered that lead oxide coating has a beneficial effect in reducing valve wear; valve and valve seat materials with improved wear resistance are now required. Combustion of residual oils may interfere with the normal development of a protective scale because the ash contains, among other things, vanadium pentoxide. This compound, in pure form, melts at 690°C (1,274°F), but its melting temperature may be lowered further by the presence of other compounds. The small amount of sea salt that may enter a reactor or gas turbine with the combustion air can initiate a sequence of events culminating in catastrophically high corrosion rates. Welding slag, improperly or incompletely removed, also may cause difficulty and, frequently premature failure. However, no attempt will be made to discuss even a representative sampling of such contaminants. We shall merely try to show how they affect corrosion behavior.
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5.10.4 Performance of Metals and Alloys 5.10.4.1 Carbon and Low-Alloy Steels
Ordinary carbon and low-alloy steels have been used successfully from room temperature up to temperatures of about 480°C (900°F) and for short periods of time up to 590°C (1,100°F). At temperatures beyond this, ordinary steels tend to corrode rather heavily. There is a trend to resort to cementation (surface diffusion treatments) on carbon and low alloy steels to render them more resistant to corrosion. Depending on the corrosiveness of the medium involved and the exposure temperature one or several of the following may be used: siliconizing, aluminizing, chromizing, or special treatments such as plating, plasma spraying, or cladding. 5.10.4.2 Alloy Additions
Additions of alloying elements to steels can greatly increase their resistance to some hightemperature environments. Additions of chromium to steel can cause a sharp decrease in iron corrosion (oxidation) by air at elevated temperatures. However, additions of chromium beyond 20% have little effect, particularly at the lower temperatures. On the negative side, chromium additions can make iron less resistant to halide attack. Nickel additions to iron chromium alloys not only improve their corrosion resistance, as described in the following section, but their mechanical strength as well. Nickel is not alloyed to ordinary iron to improve high-temperature corrosion properties. It is effective, however, in alloys containing 11% chromium. Its beneficial effects, like those of chromium, tend to become less effective after reaching some specific amount. The amount of nickel required to achieve a low-corrosion rate is greater than that of chromium, and the amount needed also increases for higher exposure temperatures. The beneficial effect of aluminum additions in suppressing high-temperature corrosion of iron alloys is surprisingly strong. When amounts of up to 12% aluminum are added, a considerable reduction in high-temperature corrosion is achieved. However, mechanical properties suffer, thus making this approach to corrosion resistance less attractive. Where lower mechanical properties can be tolerated, the use of limited amounts of aluminum can be considered. One approach to simulating aluminum-alloying while causing relatively little effect on mechanical properties is spray metallizing or aluminizing. This high-temperature cementation process diffuses aluminum into iron and produces an effective surface for exposure in air, or sulfur dioxide fumes, to temperatures in the neighborhood of 1,095°C (2,000°F). 5.10.4.3 Stainless Steels
The most common alloys used for exposure at high temperatures are the stainless steels. If medium or high alloy steels are used, chromium bearing stainless steels are generally recommended. Both straight chromium steels and chromium-nickel stainless steels are used up to approximately 870°C (1,600°F). At still higher temperatures, higher nickel and higher chromium alloys are used. At temperatures somewhat in excess of 1,093°C (2,000°F), only alloys with more than 20% Cr can be used. These alloys are relatively safe for short or intermediate periods of time. During long-term use at high temperatures, a phenomenon known as creep is experienced, during which relatively low loads may cause a metal to deform very slowly and possibly fail. This is a factor that must be considered by anyone considering or recommending alloys for use at very high temperatures. 5.10.4.4 Nickel-Based Alloys
Many nickel-based alloys have excellent resistance to high-temperature corrosion, and many have been specifically developed for high-temperature applications such as blades for gas turbine engines.
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5.10.4.5 Refractory Metals
At temperatures higher than can be tolerated by other alloys, it may be necessary to use refractory metals—those that have good high-temperature mechanical properties and melting temperatures well above 1,650°C (3,000°F). Thus, alloys of chromium, niobium, molybdenum, tantalum, rhenium, or tungsten are usually considered for very high temperature service. Although titanium and zirconium melt above 1,650°C (3,000°F), their high-temperature mechanical properties are rather unsatisfactory, so they are not generally considered in the category of refractory metals. Similarly, vanadium is not a popular contender for high-temperature applications. Unfortunately, all the above-named refractory metals, with the exception of chromium, have poor high-temperature corrosion resistance in air or other oxidizing atmospheres. Some success has been obtained in developing useful life at high temperatures by using protective coatings on the other refractory metals. In a few cases, corrosion resistance has been improved by alloying.
5.10.5 Control of High-Temperature Corrosion Methods of corrosion control in high-temperature applications are largely confined to materials selection and design, although limited modification of the environment can be achieved and the use of protective coatings can be effective. 5.10.5.1 Materials Selection
The selection of materials compatible with the chemical makeup of the environment at the specific service temperature conditions is the most commonly used method for controlling hightemperature corrosion. Because of the complex nature of high-temperature corrosion, materials selection usually requires the services of an expert in high-temperature corrosion. 5.10.5.2 Design
Design can be used to reduce some factors related to high-temperature corrosion. Stress reduction can reduce the creep that affects the scale adhesion and dimensional stability of the metal itself. Good design can also reduce the effect of the high-temperature corrosion in a manner similar to the use of a corrosion allowance. Reduction of thermal cycling and thermal differentials can also be used to control high-temperature corrosion. 5.10.5.3 Modification of the Environment
In some cases, environmental contaminants can be controlled to reduce high-temperature corrosion. In other cases, materials such as oxygen can be added to improve scale formation (e.g., oxygen can be added) when the scales are more stable in high-oxygen environments). 5.10.5.4 Protective Coatings
Protective coatings of high-temperature-resistant metals and alloys applied by weld overlay or electroplating, as well as ceramic coatings, have been successfully used to control high-temperature corrosion in some cases.
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References 1.
R. Heidersbach, Metallurgy and Corrosion Control in Oil and Gas Production, John Wiley & Sons, 2011.
2.
H. G. Byars, Corrosion Control in Petroleum Production, TPC Publication, 2nd Edition, NACE, Houston, 1999.
3.
P. Roberge, Corrosion Basics: An Introduction, NACE, Houston, 2006.
4.
J. A. Beavers, “Fundamentals of Corrosion,” in Peabody’s Control of Pipeline Corrosion, 2nd Ed., R. L. Bianchetti, ed., NACE, Houston, 2001, pp. 297-317.
5.
R. Bianchetti, “Construction practices,” in Peabody’s Control of Pipeline Corrosion, 2nd Ed., R. L. Bianchetti, ed., NACE, Houston, 2001, pp. 237-259.
6.
J. Martin, R. Heidersbach, and L. MacDowell, Pitting corrosion. http://corrosion.ksc.nasa.gov/pittcor.htm, Accessed February 22, 2012.
7.
NACE TM0106. Detection, testing and evaluation of microbiologically influenced corrosion (MIC) on external surfaces of buried pipelines.
8.
E. D. Verink, “Designing to Prevent Corrosion,” Chapter 5 in R. W. Revie, Uhlig’s Corrosion Handbook, 2nd Edition, John Wiley & Sons, Inc., 2000. pp. 95-109. Figure 6, page 102.
9.
Courtesy of D. Raymond.
10. W. Bogaerts and K. S. Agema, Active Library on Corrosion, NACE-Elsevier, Houston, TX, 1991. 11. 1988—The Aloha Incident, http://corrosion-doctors.org/Aircraft/Aloha.htm Accessed February 25, 2012. 12. Alexander L. Kielland Capsize - Oil Rig Disasters - Offshore Drilling Accidents, http://home.versatel.nl/the_sims/rig/alk.htm Accessed February 25, 2012. 13. C. Rivera, Fatigue cracks found in Southwest plane, Los Angeles Times, April 4, 2011, http://articles.latimes.com/2011/apr/04/nation/la-na-southwest-20110404 Accessed February 25, 2012. 14. Alley, D. W., Mucek, M. W., and Bradley, S. A., “Failure Analysis of a CA6NM Plug and Cage Control Valve in Hydroprocessing Service,” National Association of Corrosion Engineers, Corrosion/2005, Paper No. 05562.
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Chapter 6: Designing for Corrosion Control Upon completion of this chapter, students will have an understanding of corrosion control by design.
6.1 Introduction Corrosion control at the design stage does not just happen—it must be planned. For a major project, as much lead time will be required for the corrosion aspects of the design as for other considerations. If the technology of the application is established, there must be careful selection of a known solution, with meticulous attention to those details that are new. If new corrosion technology must be developed, testing will be necessary so that reasonable choices can be made. Design includes consideration of many factors, such as: • Materials selection •
Construction parameters
•
Process parameters
•
Geometry for drainage
•
Dissimilar metals
•
Crevices
•
Corrosion allowance
•
Operating lifetime
•
Ease of access for maintenance and inspection
Materials selection, because of its importance as a corrosion control method, will be considered as a separate topic in Chapter 7.
6.2 Construction Parameters The locations of specific structures and processes within a facility should be considered. For example, if several buildings are to be constructed, a building that will contain processes that produce corrosive fumes should be located downwind from the others. The locations of specific structures and processes within a facility should be considered. For example, if several buildings are to be constructed, a building that will contain processes that produce corrosive fumes should be located downwind from the others. In many cases, systems are constructed or assembled under field conditions rather than under controlled shop conditions. Control of field conditions is particularly important with regard to welding and applying of protective coatings. In the field, it may be necessary to weld or apply protective coatings under unusual or awkward conditions (e.g., overhead welding). These conditions must be considered in design. Welding and application of protective coatings may require special field precautions, such as the erection of temporary protective enclosures. Failure to properly control conditions can result in a system that is not as corrosion resistant as intended.
6.2.1 Welding Welding is one of the most important parts of fabrication. Too often, rigid material specifications based on optimum performance of the equipment are voided by mistakes in welding. There must be an inviolable conviction that no shortcut can be taken on welding integrity and quality. Strict adherence to fabrication codes, joint preparation, welder qualification, selection of compatible
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welding technique and electrodes, thermal pre- or post-treatment, and inspection is mandatory. Welding has become a field of considerable specialization. Techniques may range from gas welding to electron beam welding, with an array of possibilities in between. The appropriate selection of joining methods is a must to ensure optimum performance. The possibility of weld defects is much higher than in wrought metal, so specifications commonly require longitudinally welded pipe joints to be placed with their longitudinal welds alternating at the 2 o’clock and 10 o’clock positions as shown in Figure 6.1. In some cases, post-weld heat treatment may be required to restore mechanical properties of the weldment, to improve strength and corrosion resistant properties in weld and heateffected zones, and to reduce residual stresses. When required, these treatments must be carefully specified and carried out. Post-weld heat treatment is particularly difficult in field Figure 6.1 Pipeline With Alternating Longitudinal conditions, and most welding requiring postWelds At 10 O’clock and 2 O’clock weld heat treatment is done in shop conditions. Some basic rules apply to most welding: • Keep the weld design simple. •
Insist on approved shop drawings.
•
Conform to code regulations.
•
Specify inspection requirements.
•
Specify “pass/fail” limits for inspection results.
•
Specify welding procedures in detail.
•
Specify procedures for storage and handling of welding materials.
•
Specify the proper filler metal.
•
Make an inspection agreement with the fabricator.
•
Ensure fabricator’s capability to do the job.
•
Ensure qualifications of welders.
•
Specify post-weld heat treatment, if necessary.
•
Consider post-weld shipping of equipment.
6.2.2 Accommodating Other Corrosion Control Measures The overall system design can affect such corrosion control measures as protective coatings and cathodic protection. An example of such a design feature is sufficient clearance around, over, and under components that are to be coated. The clearance must be sufficient for surface preparation and coating application as well as clearance for scaffolding, if required. A surface that is easily accessible will receive a better coating than one that is not. Access for repair of coatings and recoating must also be considered. Cathodic protection systems must also be considered in the overall design, rather than as an afterthought. Locations of anodes, rectifiers, and other system components should be included as well as ample access for installation and maintenance.
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6.3 Process Parameters In designing equipment and facilities, it is important to consider the various factors that make up the service conditions, including: • Temperature •
Velocity
•
Pressure
•
Chemistry
6.3.1 Temperature Temperature factors to be considered include the nominal operating temperature, the maximum operating or upset temperature, the minimum operating temperature, and temperatures during downtime. In most corrosion reactions, an increase in temperature is accompanied by an increase in reaction rate. A rule of thumb suggests that the reaction rate doubles for each 10°C (18°F) rise in temperature. Although there are numerous exceptions to this rule, it is important to consider temperature when analyzing why materials fail, and in designing to prevent corrosion. 6.3.1.1 Nominal Operating Temperature
The nominal design temperature, or more properly stated, the nominal design temperature range, is usually the primary concern with regard to corrosion resistance because it is the temperature range that will occur most of the time. Materials used for construction are normally selected on the basis of the nominal operating temperature. 6.3.1.2 Maximum Operating/Upset Temperature
The design engineer must consider the maximum operating temperature to which equipment may be exposed in cases of malfunction. For example, a car radiator operates at temperatures of 80°C–90°C (176°F–194°F), but in the event that some fluid is lost, the temperature may go well in excess of 100°C (212°F). As a result the radiator or coupling hoses may blow out. In the same sense, if a large steam boiler loses its water or steam content, the boiler tubes are no longer cooled by the water or the steam, and the steel tubes may be severely damaged. The maximum operating temperature must be considered, along with the normal operating temperature. In some cases, corrosion rates can be very high at the maximum operating temperature, and significant corrosion can occur during these short periods. Also, corrosion can initiate at elevated temperatures when it would not initiate at normal operating temperatures, and this temperature-initiated corrosion sometimes continues at the normal operating temperature. Materials that develop passive films are subject to the initiation of such corrosion. Protective coatings selected to withstand normal operating temperatures can be damaged during periods of higher temperature and may not provide protection during subsequent operation at lower temperatures. 6.3.1.3 Minimum Operating Temperatures
In some cases, particularly when there are condensable gases in the system, the system can be damaged at temperatures lower than the nominal operating temperature. Flue stacks and engine exhaust systems are systems that are designed to operate hot without the presence of liquid water. If operated below the dew point, where water can condense, corrosion can occur. 6.3.1.4 Temperatures during Downtime
Temperatures during downtime must also be considered. Although these temperatures are usually lower than the operating temperature, effects such as condensation must be considered during design.
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6.3.2 Velocity 6.3.2.1 Flow Rates
As discussed previously in this course, velocity and fluid flow can have a great effect on corrosion. Systems should be designed to limit fluid flow velocities to levels that can be tolerated by the materials. Fluid flow velocities are most commonly controlled by the proper selection of pipe sizes. In many cases, systems have devices to measure and control fluid flow so that the maximum allowable fluid velocity is not exceeded. Even short periods of high flow can remove protective surface films and initiate corrosion that continues during periods of normal flow. Low-flow conditions should also be considered, particularly when using stainless steel and other alloys that require oxygen to maintain their passive films. In most cases, entrapment of air or other gases and solid particles in the fluid flow should be avoided due to abrasive tendencies. 6.3.2.2 Flow Regime
Turbulence greatly increases the effects of fluid flow. Systems should be designed to minimize turbulence. The use of wide-radius elbows (also called sweeps) is a common method to avoid turbulence in piping systems. The systems must be installed carefully to ensure that no conditions cause turbulence. Using improperly-fitted gaskets or the failure to remove burrs from inside cut pipes frequently causes turbulence.
6.3.3 Pressure In systems that are completely filled with liquid, pressure usually has little effect on corrosion reactions. However, pressure has a great effect on the consequences of corrosion. High-pressure equipment must be carefully designed to prevent catastrophic failures, and corrosion of such equipment is a very important aspect of design. Pressure also is a major factor in the stresses on the system; the effect of these stresses on corrosion, particularly on environmental corrosion cracking, must be considered during design. If both gases and liquids are in a system, the solubility of the gas in the liquid is a function of the pressure in the system. The corrosivity of the liquid and the increased levels of dissolved gas that will be created in a high pressure environment must be considered. 6.3.3.1 Pressure Variations
Pressure variations not only affect the range of environments that must be considered in design, but they can induce cyclic stresses that cause corrosion fatigue.
6.3.4 Chemistry The chemistry of the environment is an important factor in system design. In some cases, wide chemistry ranges will be encountered; the system must be designed with consideration of all possible environments. These include normal operating conditions, excursions, and downtime conditions. As discussed previously, a large number of chemical factors influence corrosion, including: • pH •
Major species
•
Minor species
•
Nature of environment (atmospheric vs. immersion)
All of these, and other factors in the chemical makeup of the environment, must be considered during design.
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6.4 Drainage Design should ensure water or corrodents cannot be trapped. There are innumerable ways to design systems poorly so that water and debris are trapped and held in contact with surfaces. This greatly increases surface corrosion that is due to increased time of wetness. Figure 6.2 and Figure 6.3 show two common drainage problems.
Figure 6.2 Structural Member Orientation for Drainage
Figure 6.3 Tank Outlet for Drainage
6.5 Dissimilar Metals Design team members should ensure that dissimilar metals do not have contact unless a galvanic effect is desired (as in cathodic protection). Otherwise an unwanted galvanic process will initiate corrosion. If, for example, a copper or brass valve were installed in a plain carbon steel system, the copper would be cathodic with respect to the steel, and the steel adjacent to the valve would corrode more rapidly. As described previously, the area effect in this type of corrosion may be quite pronounced. If galvanic corrosion is a problem, consider employing the following remedial measures: • Use compatible metals in galvanic contact. This means using metals close together in the galvanic series for the service environment, or using materials with desirable polarization characteristics (e.g., stainless steels or titanium) for the cathodic member of the couple. •
Avoid unfavorable cathode/anode ratios. A large cathode area adjacent to a small anode region can greatly accelerate the intensity of the corrosive attack at the anodic metal location. Cathode/anode ratios are often more important than the position of the metals in the galvanic series. Insulate (break the circuit between the two metals) to ensure contact is not restored during service.
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Maintain coatings; it is important for the cathode to be coated and carefully maintained to avoid an unfavorable cathode/anode area effect.
6.6 Crevices Wherever possible, crevices should be minimized. As with drainage, there are innumerable ways to create crevices and innumerable illustrations of ways to avoid crevices. Like many other corrosion-related design aspects, attention to crevices is an important part of designing a corrosion-resistant system. One of the best ways to avoid crevices is to join parts by welding rather than by bolting or riveting. A full-penetration butt weld is the type of welded joint that best eliminates crevices (Figure 6.4).
Figure 6.4 Joining Details
6.7 Corrosion Allowance/Operating Lifetime In some cases, it may be more economical to use a less corrosion-resistant material and compensate for the rate of attack. In most cases, additional material, or corrosion allowance, is added to the system to make up for the corrosion likely to occur over the life of the system. This approach assumes that the corrosion is not unacceptable from the standpoint of contamination or appearance and that it is predictable. Using corrosion allowance is normally only applicable to metal-environment combinations in which uniform corrosion occurs at either a linear rate or a rate that decreases with time. Corrosion allowance is normally used when a specific lifetime for the component can be defined, and the component can be replaced easily if a longer system-operating life is desired.
6.8 Maintenance and Inspection A good design should provide ease of maintenance and inspection by providing adequate access to components. This access may require specific items such as access ports and manholes, or may simply involve proper equipment location. It is important that the designer prepare detailed inspection and maintenance manuals and instructions. The designer normally assumes the system will be periodically inspected and maintained, but he or she needs to provide instructions so that the assumed actions can be performed on a scheduled basis.
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Chapter 7: Corrosion Control Methods Upon completion of this chapter, students should have an understanding of corrosion control by: • Materials selection •
Modification of environment
•
Protective coatings
•
Cathodic and anodic protection
•
Design
Principles of corrosion control by design are discussed in detail in Chapter 6.
7.1 Materials Selection One answer to corrosion control is to use a more resistant material. As previously discussed, there is no such thing as a material resistant in all corrosive situations. First define the required properties of the material, then choose one with as many suitable characteristics as possible. If no materials meet all the requirements then establish the best method of corrosion control or adjust the service environment.
7.1.1 Factors that Influence Materials Selection Selecting an appropriate material involves balancing a large number of factors such as: • Corrosion resistance in the environment •
Availability of design and test data
•
Mechanical properties
•
Cost
•
Availability
•
Maintainability
•
Compatibility with other system components
•
Life expectancy of equipment
•
Reliability
•
Appearance
7.1.1.1 Corrosion Resistance in the Environment
The particular chemical and physical characteristics of a service environment can have a substantial effect on the corrosion resistance. Before materials are selected, the environment must be defined. Some of the environmental characteristics that need to be defined are: • Main constituents (identity and amount) •
Impurities (identity and amount)
•
Temperature
•
pH
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•
Degree of aeration
•
Velocity or agitation
•
Pressure
•
Estimated range of each variable
Only after all the pertinent environmental characteristics have been defined can the most appropriate materials be selected. 7.1.1.2 Availability of Design and Test Data
Performance data of candidate materials in the specific service environment must be available for appropriate materials to be selected. Performance data about materials in identical service environments is always best, but often the data is unavailable. Service data from similar service environments is usually the next best choice, as long as enough is understood about the differences between the present environment and the previous service environment. Laboratory test data can be used as the basis for material selection in applications where the service environment is not too complex and can be reproduced in the laboratory easily. Laboratory tests, however, are usually of short duration. It is often difficult to get reliable laboratory data about changes in corrosion rates over long periods of time, and short-duration laboratory tests can fail to identify corrosion mechanisms with long-reaction times. Laboratory tests are frequently used as screening tests to eliminate materials with undesirable characteristics. The candidate materials are then tested for longer periods under conditions that more closely match the anticipated service conditions. Published corrosion data contains information on material performance in both laboratory and service conditions. These data must be used carefully. It is particularly important that the reported corrosion measurement was appropriate for the type of corrosion that occurred. For example, using corrosion rates based on weight loss is inappropriate when corrosion is localized. Data on the performance of a wide variety of metals and nonmetals is available in NACE International’s COR•SUR software. This extensive database can be searched to identify candidate materials for a wide variety of environments. 7.1.1.3 Mechanical Properties
Mechanical properties, such as strength and ductility, are important in the selection of materials for any application. These data are widely available. Loss of ductility due to environmental cracking is one important consideration that often must be addressed. 7.1.1.4 Cost
Cost is, of course, a consideration in materials selection. Simple cost considerations such as the cost per kilogram of material are not usually sufficient to make a good estimate of the actual installed cost. Fabrication costs often outweigh the actual cost of the material. It is often less expensive to use a material that is easy to fabricate than one that is difficult to fabricate, even if the easy material costs more per kilogram. Not only material costs should be considered, but also annual costs for maintenance, replacement, and repair are important. To properly assess these costs, calculations need to assess the time value of money. These economic analyses must be performed to determine the actual cost of material selection options over the life of the system. 7.1.1.5 Availability
The material should be readily available in the form required. Many materials are available as plate and sheet, but not as pipe or castings, and vice versa. It is sometimes practical to make use of an available form of the material (e.g., to fabricate welded pipe from sheet material), but the cost of fabrication and the effect of fabrication on the material properties must be considered.
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7.1.1.6 Compatibility with Other System Components
Materials selected must be compatible with the entire system. Incompatibilities, such as those that might cause galvanic corrosion problems, are fairly easy to identify and correct. Other problems, such as corrosion due to contamination by metal ions from other parts of the system, are much more difficult to identify at the design stage. One common problem of this type is when different parts of the system are designed by different groups. Each portion of the system might be well designed, but they may not be compatible with each other. Design, particularly from the standpoint of corrosion, must always have a system focus. 7.1.1.7 Life Expectancy of Equipment
In some cases, it is less expensive and more practical to design specific system components for a short life with frequent replacements during the overall life of the system. If this is the case, it is important that inspections and replacement of these components are included in the system operation and maintenance manuals. Sometimes it is difficult to establish the actual required life of equipment. Frequently the actual service life of the equipment exceeds the nominal “design life” originally assumed. This can lead to situations in which maintenance and repair costs due to corrosion become excessive, or much worse, result in service failures. 7.1.1.8 Reliability
Reliability is also central to material selection, particularly when failure is a safety or environmental issue (e.g., in high-pressure piping carrying hazardous materials). Reliability outweighs cost and expense, and using corrosion resistant materials may be justified. 7.1.1.9 Appearance
Appearance can also be an important design factor. A clean and pleasant environment not only affects the quality of life for workers, but can play a big role in positive community relations.
7.1.2 Comparison with Other Corrosion Control Methods Materials selection is an important consideration in the design of corrosion-resistant systems; however, it is only one possible option for controlling corrosion. The iron and steel used for the vast majority of structural applications are not corrosion-resistant in many environments and must be protected. In atmospheric environments, coatings are used to protect many materials against corrosion. In underground and immersion conditions, a combination of coatings and cathodic protection is commonly used to augment the resistance of materials that are not inherently corrosion-resistant. Many liquid-handling systems rely on corrosion inhibitors. Of course, these means of augmenting the corrosion resistance of materials has associated costs, and the overall cost and other factors must be considered.
7.1.3 Candidate Materials The performance of materials and their resistance to many forms of corrosion has been discussed previously in this course. Metals and nonmetals are candidates for a wide variety of applications. 7.1.3.1 Metals
Metallurgy When selecting metals, the details of the structure of the metal are often as important as the chemical composition of the metal. Proper heat treatment and surface treatments to obtain the desired properties must be specified. Candidate metals are commonly classified into the following groups: • Carbon and low-alloy steels •
Stainless steels
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•
Nickel and nickel-based alloys
•
Copper and copper alloys
•
Aluminum and aluminum alloys
•
Titanium and titanium alloys
7.1.3.2 Nonmetals
The properties and performance of many nonmetals have also been described previously in this course. Candidate nonmetals are commonly classified into the following groups: • Plastics •
Composites
•
Elastomers
•
Concrete
•
Vitreous materials
7.2 Modification of the Environment Modification of the environment is widely used to enhance the inherent corrosion resistance of materials. In liquid-handling systems, the three principal methods of environmental modification are the use of corrosion inhibitors, deaeration, and pH control.
7.2.1 Corrosion Inhibitors A corrosion inhibitor is a substance which, when added to an environment, decreases the rate of attack by the environment. Corrosion inhibitors are commonly added in small amounts to acids, cooling waters, steam, and other environments, either continuously or intermittently, to control corrosion. Corrosion inhibitors generally control corrosion by forming thin films that modify the environment at the metal surface. Inhibitors form films in several ways: by adsorption, the formation of bulky precipitates, or the formation of a passive layer on the metal surface. Some inhibitors retard corrosion by adsorption to form a thin, invisible film only a few molecules thick. Others form bulky precipitates that coat the metal and protect it from attack. A third mechanism consists of causing the metal to corrode in such a way that a combination of adsorption and corrosion product forms a passive layer. 7.2.1.1 Types of Inhibitors
Types of corrosion inhibitors include: • Anodic (passivating) •
Cathodic
•
Ohmic
•
Organic
•
Precipitation-inducing
•
Vapor phase
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Anodic (Passivating) Inhibitors Anodic inhibition is illustrated in Figure 7.1. The increase in anodic polarization decreases the corrosion current and the rate of corrosion of the anode.
Figure 7.1 Polarization Diagram Illustrating Anodic Inhibition
Anodic inhibitors must be used with caution because they can cause increased localized corrosion if they do not cover the entire anodic surface. There are two types of anodic inhibitors: • Oxidizing •
Nonoxidizing
Oxidizing anodic inhibitors such as chromate and nitrite can passivate steel even in the absence of oxygen. Nonoxidizing anodic inhibitors, such as phosphate, tungstate, and molybdate, require the presence of oxygen to passivate steel.
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Cathodic Inhibitors Cathodic inhibitors cause cathodic polarization. As shown in Figure 7.2, the Evans diagram, this decreases the corrosion current and the corrosion rate of the anode.
Figure 7.2 Polarization Diagram Illustrating Cathodic Inhibition
There are two main types of cathodic corrosion inhibitors, cathodic poisons and cathodic precipitates. Cathodic inhibitors either slow the cathodic reaction itself, or cause selective precipitation in the cathodic area. The latter method increases the circuit resistance and restricts diffusion of reducible species to cathodic areas. Where the anodic polarization is unaffected, the corrosion potential is shifted to more negative values. Cathodic poisons interfere with cathodic reduction reactions, such as hydrogen atom formation or hydrogen gas evolution. The rate of the cathodic reaction is slowed; and because anodic and cathodic reactions must proceed at the same rate, the whole corrosion process is slowed. Examples of cathodic poisons include arsenic, bismuth, and antimony compounds. A serious drawback in the use of cathodic poisons is that they sometimes cause hydrogen blistering of steel and increase its susceptibility to hydrogen embrittlement. Because the recombination of hydrogen atoms is inhibited the surface concentration of hydrogen atoms is increased; and a greater fraction of the hydrogen produced by the corrosion reaction is absorbed into the steel. Blisters are formed when hydrogen atoms combine to form hydrogen molecules inside the steel. Molecular hydrogen does not diffuse through steel; it collects at defects or voids to create pressures which may reach 7,000 MPa (1 million psi) or more. Cathodic precipitates deposit because of increased pH caused by the cathodic reaction. The most widely used cathodic precipitation inhibitors are carbonates of calcium and magnesium because they occur in natural waters. Their use as inhibitors usually requires only a pH adjustment. Zinc sulfate (ZnSO4) precipitates as zinc hydroxide Zn(OH)2 on cathodic areas and so is also considered an inhibitor.
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Ohmic Inhibitors Ohmic inhibitors increase resistance of the electrolyte circuit by forming a film on the metal surface. We have already discussed inhibitors that increase the electrical resistance of the electrolyte circuit to some extent in the section about anodic and cathodic film forming inhibitors. Because it is usually impractical to increase the resistance of the bulk electrolyte, increased resistance is achieved more practically by the formation of a film on the metal surface. If the film is deposited selectively on anodic areas, the corrosion potential shifts to more positive values; if it is deposited on cathodic areas, the shift is to more negative values; and if the film covers both anodic and cathodic areas, there may be only a slight shift in either direction. Organic Inhibitors Organic inhibitors affect the entire surface of the metal. They are adsorbed according to their electrical charge. Cationic organic inhibitors carry a net positive charge and anionic organic inhibitors a net negative charge. Organic compounds constitute a broad class of corrosion inhibitors designated specifically as anodic, cathodic, or ohmic. Anodic or cathodic effects alone are sometimes observed in the presence of organic inhibitors, but generally organic inhibitors affect the entire surface when present in sufficient concentration. Both anodic and cathodic areas probably are inhibited, but to various degrees (depending on the potential of the metal, the chemical structure of the inhibitor, and the size of the inhibitor molecule). The film formed by adsorption of soluble organic inhibitors is only a few molecules thick and is invisible. Organic inhibitors will be adsorbed according to the ionic charge of the inhibitor and the charge on the metal surface. Cationic inhibitors (positively charged, +), such as amines, or anionic inhibitors (negatively charged, –), such as sulfonates, will be adsorbed preferentially, depending on whether the metal is charged negatively or positively. Precipitation Inhibitors Precipitate-inducing inhibitors are film forming compounds that have a general action over the metal surface, interfering with both anodic and cathodic reactions. Common precipitation inhibitors include silicates and phosphates. In waters with a pH near 7.0, a low concentration of chlorides, silicates, or phosphates causes steel to passivate when oxygen is present, hence, these molecules behave as anodic inhibitors. Another anodic characteristic is that corrosion is localized in the form of pitting when insufficient amounts of phosphate or silicate are added as inhibitors to saline water. Both silicates and phosphates form deposits on steel that increase cathodic polarization. Their action is a combination of both anodic and cathodic effects. Vapor Phase Inhibitors Vapor phase inhibitors (VPI), also called volatile corrosion inhibitors (VCI), are compounds in a closed system transported to the site of corrosion by volatilization. In boilers, volatile basic compounds are transported with steam to prevent corrosion in condenser tubes. Compounds of this type inhibit corrosion by making the environment alkaline or by forming hydrophobic films. In closed vapor spaces, such as shipping containers, volatile solids are used. The mechanism of inhibition by these compounds is not entirely clear, but it appears that the organic portion of the molecules provides volatility. On contact with a metal surface, the inhibitor vapor condenses and is hydrolyzed by any moisture present to liberate nitrite, benzoate, or bicarbonate ions. Since ample oxygen is present, nitrite and benzoate ions are capable of passivating steel, as they do in aqueous solution. The mechanism for carbonate may not be the same, and here the organic amine portion of the vapor-phase inhibitor may serve to aid inhibition by adsorption and by providing alkalinity. It is desirable for a vapor-phase inhibitor to provide inhibition rapidly and to have a lasting effect. The
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compound should have a high volatility to saturate all the accessible vapor space as quickly as possible. At the same time it should not be too volatile; it would be lost rapidly through any leaks in the package or container in which it is used. The optimum vapor pressure of vapor-phase inhibition is sufficient enough to maintain an inhibiting concentration on all exposed metal surfaces. Vapor phase inhibitors may attack some nonferrous metals. 7.2.1.2 Common Corrosive Species that Affect Corrosion Inhibition
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Oxygen (O2)—Dissolved oxygen promotes corrosion. However, if its presence is reduced to very low levels (less than -0.01 ppm) by scavenging compounds or by stripping, sufficient control is provided for some systems (e.g., in boilers and hot water supplies). In cooling water systems, oxygen can be used to passivate steel—when adding a passivating inhibitor like nitrite.
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Chloride ions (Cl–)—Steel is more difficult to passivate in the presence of the chloride ion; therefore, a higher concentration of passivating inhibitor is required if chlorides are present. Nonpassivating inhibitors also must be used in higher concentrations because chloride ions are readily adsorbed by steel.
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Sulfate ions (SO4–)—Sulfates effect passivity similar to chloride, but to a lesser degree. Sulfates or chlorides must not be allowed to concentrate in a system because depassivation may occur.
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Bicarbonate Ions (HCO3–)— Calcium (Ca++) and magnesium (Mg++) bicarbonates can be used to form protective precipitates, but at high concentrations they can interfere with inhibitors by precipitating non-protective deposits. Small concentrations of heavy metal ions such as copper or mercury may cause severe interference with inhibitors.
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Hydrogen Ions (H+)—Hydrogen ions increase corrosion rates and increase the difficulty of passivating steel. Non-passivating organic or cathodic inhibitors are preferred in pickling acids to avoid the consequences of depassivation.
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Hydroxyl Ions (OH–)—In alkaline solutions, steel corrosion is controlled by the rate of oxygen diffusion through the precipitated corrosion product, usually ferrous hydroxide, Fe(OH)2. Steel is passivated in alkaline solutions. Amphoteric metals, such as aluminum, zinc, and lead, corrode in alkaline environments and inhibitors may be required.
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7.2.1.3 Applications of Inhibitors
Inhibitors can be used in both aqueous and non-aqueous liquid systems, and in gaseous environments. Aqueous Liquid Systems Aqueous systems are the most common corrosive environments to which inhibitors are applied. Water is a powerful solvent capable of carrying many different ions at the same time. Requirements for corrosion inhibition can vary greatly, depending on the type and amount of dissolved species present. Because there is no universal inhibitor for water systems, an inhibitor satisfactory for one system may be ineffective or even harmful in another. Non-Aqueous Liquid Systems Corrosion in nonaqueous liquids, such as fuels, lubricants, and edible oils, may be caused by small amounts of water, if present. Water is slightly soluble in petroleum products, and its solubility increases with temperature. If a nonaqueous medium is saturated with water and the temperature is lowered, then some of the water will separate to attack the steel it contacts. Oils that have been subjected to high temperatures in air may contain organic acid that will be extracted by any water present, thus increasing the rate of attack. Solubility is significant in evaluating corrosion inhibitors for nonaqueous fluids, because they do not have the same solvent effects as water. Because an inhibitor must be transported through the environment to corrosion sites it must be either soluble in the environment or sufficiently dispersed in fine droplets so that settling does not occur. Additionally, it is essential the inhibitor does not form filter plugging, insoluble products by reaction with metals or components of the nonaqueous fluid. 7.2.1.4 Gaseous Environments
Gaseous environments include open atmosphere, the vapor phase (head space) in tanks, natural gas in wells, and the empty space in packaging containers. Again, water and oxygen are the principal corrosive agents, but the fundamental necessity in providing inhibition is to transport the inhibitor from a source to the sites where corrosion may occur. • Open Atmosphere—Corrosion inhibitors for corrosion in an open atmosphere are applied directly to the metal surfaces to be protected. The most common method is using inhibitive pigments in protective coatings. •
Vapor Phase in Tanks—The walls of tanks above a water line are subject to extensive corrosion because the relative humidity is always high and oxygen is plentiful if the tank is vented to the atmosphere. If water contamination is not a factor, a layer of oil on the surface helps to maintain a low humidity and as the level rises and lowers the walls become coated. The oil may contain an organic inhibitor and an agent (usually an amine) to cause the oil to spread on the metal surface. Oil layers containing about 15% lanolin have been used in ship ballast tanks to control corrosion.
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Natural Gas in Wells—Gas wells corrode mostly in the reflux zone, which is a specific area of the well between the bottom and the wellhead, where condensation occurs. As the gas flows up the well, its temperature drops due to expansion; and this causes condensation when the temperature reaches the water dew point of the gas. Volatile inhibitors injected into gas wells have been used successfully to inhibit corrosion. Many gas wells today are protected by continuously injecting amine inhibitors either in slugs or by squeeze, which means they coat the well when injected and also enter the gas stream partially by vaporization and partially by entrainment.
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Empty Space in Packaging Containers—Packaged materials may be protected from corrosion in several ways. Packages that contain parts which cannot be coated with an inhibitor or exposed to volatile inhibitors (e.g., electronic parts), are protected by placing a desiccant (such as silica gel) in the package to maintain low humidity. Vapor-phase inhibitors can be placed in a package in bulk; alternatively, the article to be protected can be wrapped in paper impregnated with a VPI. These compounds are volatile organics, so the package in which they are used must be well sealed.
7.2.1.5 Inhibitor Application Techniques
Commonly encountered methods of inhibitor application include continuous injection, batch treatment, squeeze treatment, and coating. Continuous Injection Continuous injection of corrosion inhibitors is used in once-through systems, when slugs or batch treatments cannot be distributed evenly through the fluid. This method is used for water supplies, oil field injection water, once through cooling water, open-annulus oil or gas wells, and gas lift wells. Liquid inhibitors are injected using a chemical injection pump. Most chemical injection pumps can be adjusted to deliver at a desired injection rate. Another form of continuous application is by the use of slightly soluble forms of solid inhibitors. The inhibitor (e.g., a glassy phosphate or silicate in the form of a cartridge) is installed in a flow line where the inhibitor is continuously leached out by passing fluid through the cartridge. Inhibitor sticks or pellets are used in oil and gas wells to supply the inhibitor continuously by natural slow dissolution. Batch Treatment In batch treatment, a quantity of inhibitor is added to a closed system to provide protection for an extended period. A familiar example of batch treatment is an automobile cooling system. A quantity of inhibitor is added to provide protection for an extended period. Additional inhibitor may be added periodically, or the fluid may be drained and replaced with a new supply. In most aerated, closed loop cooling systems, it is important that the inhibitor concentration is measured occasionally to ensure that a safe level is maintained. Batch treatment is also used to treat oil and gas wells. An inhibitor is diluted with an appropriate solvent and injected into the annulus of open-hole wells or into the tubing of gas wells that have a packer. In these applications it is important that the inhibitor contact all surfaces and that it have good persistence. Most wells require treatment about every two weeks. Squeeze Treatment The squeeze treatment is a method of continuously feeding an inhibitor into an oil well. A quantity of inhibitor is pumped into a well, and then sufficient solvent is added to force the inhibitor into the formation. The inhibitor is adsorbed by the formation, from which it slowly escapes to inhibit the produced fluids. Protection applied in this manner has been known to last for up to one year. Coatings Inhibitors may be used in coatings. When moisture contacts the coating, the inhibitor is leached out to protect the metal. It must be soluble enough to be leached out in sufficient quantities to protect the metal, but not so soluble that it will be lost rapidly. One common coating inhibitor is zinc chromate, which passivates steel by providing chromate ions.
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7.2.1.6 Safety Considerations With Inhibitors
Handling The toxic effects of inhibitors must be dealt with in processes where the compounds may be inhaled or contacted. Extreme care must be taken to avoid using toxic compounds in or near food-processing equipment, ice plants, and potable water supplies. When inhibitor solutions are prepared for injection, care must be taken to follow label instructions regarding skin contact, eye contact, ingestion, and inhalation. Read all safety information before opening containers of inhibitors. Disposal Because a number of inhibitors contain ions and compounds that are toxic, it can be quite difficult to dispose of inhibitor fluids that have been drained, dumped, or leaked from systems. Chromates are a prime example. In fact, the use of chromate containing inhibitors has been severely reduced or banned in recent years because of the disposal problem. Disposal must be considered during inhibitor selection. Heat Transfer Heat transfer must be taken into account applying corrosion inhibitors. Scaling of heat transfer surfaces, which can reduce heat transfer, should be avoided or held to a minimum. Excessive deposits of phosphates, silicates, or sulfates should be avoided; the latter in particular because they are difficult to remove by chemical means.
7.2.2 Water Treatment Water treatment is frequently used for corrosion control in water facilities. Water treatment may be accomplished by physical or chemical methods. Physical water treatment methods include removal of the following: • Solids •
Gases
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Non-aqueous liquids
Removal of solids is normally accomplished by settling or filtration. Removal of undesirable gases is normally accomplished by deaeration, or in some cases by aeration. Removal of air by deaeration can be accomplished by gas stripping towers, or in boiler systems by steam stripping in a deaerator unit. Aeration is used to remove hydrogen sulfide and other dissolved gases that can be displaced by air. Removal of non-aqueous liquids (such as oils/greases) is accomplished through the use of skimmers and separators. Chemical water treatment methods include: • Softening •
pH adjustment
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Demineralization
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Desalinization
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Oxygen scavenging
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Chlorination (biocide)
Softening may be performed using lime softening, or sodium zeolite ion exchange methods. Softening is frequently required to prevent scaling by calcium and magnesium salts. It should be
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noted that even short term upsets in softener operation can cause severe scaling under heat transfer conditions, such as waterside boiler fouling; resulting in failure from under-deposit corrosion or boiler tube overheating. pH adjustment is commonly performed to cause calcium carbonate precipitation. Many natural waters and municipal water supplies contain calcium carbonate (CaCO3) in solution. This can be made to precipitate by adding more calcium, by heating (the higher the temperature, the less soluble the calcium carbonate), or by adjusting pH to make the solution more alkaline. The objective is to increase the alkalinity of the municipal water to a pH at which calcium carbonate precipitation is just about to occur. At the correct pH, the deposit will be firm and smooth and similar to an eggshell. Once a protective deposit is formed, the pH of the water must be maintained at the equilibrium level; if allowed to become acidic, it will redissolve the protective deposit. If the appropriate pH is exceeded, calcium carbonate will precipitate to form a slimy, porous deposit that does not provide corrosion protection and in fact may increase corrosion by creating concentration cells involving dissolved oxygen or other corrosive anions. In addition, excessive calcium carbonate precipitation can build up to block water flow in piping and foul heat transfer surfaces, causing failure in boilers and heat exchangers. Demineralization removes dissolved minerals from water. It may be accomplished by deionization using ion exchange resins, by reverse osmosis, or by distillation. Desalination is accomplished by reverse osmosis or distillation, primarily to remove dissolved salts. Oxygen scavengers reduce depolarization by dissolved oxygen, and find principle use in boiler systems. Oxygen scavengers are compounds such as sulfites or hydrazine that react with oxygen in a solution and thus reduce the availability of oxygen for corrosion reactions. They may be added alone or combined with other inhibitors. Care must be taken to maintain sufficient oxygen scavenger residuals, especially during outage periods when the ingress of air can consume available scavenger chemical, and create a dissolved oxygen pitting corrosion risk. Use of chlorination and/or biocide chemical additions in cooling water systems is usually required to reduce the likelihood of microbiological fouling, and/or microbiologically influenced corrosion (MIC). Maintenance of a chlorine residual (or appropriate biocide residual) reduces the possibility of corrosion during hydro-testing of new equipment, storage, and system operation.
7.3 Protective Coatings Figure 7.3 shows the most common means of corrosion control. Protective coatings are the most commonly used means of corrosion control. Between organic and metallic coatings, protective coatings account for over 90% of corrosion control expenditures. Protective coatings control corrosion on many carbon steel and other structures. Linings, which are generally thicker and often applied as flexible solid sheets of material, also serve as protective coatings. Typically in NACE usages, the term paint applies to color-coding and decorative, rather than protective, coatings. The term “coatings” will refer to corrosion control uses unless stated otherwise. Figure 7.4 shows the role of paint, protective coatings, and linings on a storage tank.
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Figure 7.3 Corrosion Control Expenditures by Means of Control 1
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Figure 7.4 Protective Coatings, Paint, And Internal Linings on a Large Above-Ground Storage Tank
NACE defines several terms related to protective coatings: • Coating: A liquid, liquefiable, or mastic composition that, after application to a surface, is converted into a solid protective, decorative, or functional adherent film. •
Protective coating: A coating applied to a surface to protect the substrate from corrosion.
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Coating to an Existing Structure 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.
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Linings: Coatings or layers 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.
Figure 7.5 Breakdown of Costs of Applying a Protective
Protective coating systems must be compatible with their substrates, with the intended application method, and with cathodic protection, if they are used in immersion or buried service with cathodic protection as a secondary means of corrosion control.
7.3.1 Coating Purposes Putting a barrier between a corrosive environment and the material to be protected is a fundamental method of corrosion control. It is arguably the most widely used method of protecting metals and other substrates. A protective coating is any material that, when applied to a surface, will resist the service environment and prevent serious breakdown of the substrate.
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Coatings may be used for a variety of reasons: • Corrosion control—Protective coatings may be used as a corrosion control measure. •
Waterproofing—Coatings may be used to prevent the transmission of liquid, or reduce the transmission of water vapor.
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Weatherproofing/weather protection—Weatherproofing would include, of course, waterproofing. Other examples would include use of coatings to provide resistance to ultraviolet rays of the sun.
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Biocide application—Wood may be coated to enhance its resistance to attack by insects, fungus and rot, etc.
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Marine fouling—In the marine industry, antifouling coatings may be used to reduce the attachment of marine organisms to the hulls of ships and other submerged structures when such protection is desired. Current marine coating may also simply serve as corrosion protection and not as biocides.
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Fireproofing/fire retardancy—Fire-resistant and fire-retardant coatings are available.
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Appearance—All other things being equal, most people prefer clean, attractive surroundings. Coatings may be used to help attain and maintain the appearance of industrial, commercial, and residential locations.
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Color Coding—Even substrates that might not be coated for corrosion control reasons, such as stainless steel or plastic piping, may be coated as part of a color-code scheme.
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Sanitation/decontamination—Coatings may be applied to porous substrates, such as concrete, wood, and plaster, to allow for easier cleaning. “Sanitation” is important in food processing plants. “Decontamination” is important in nuclear power plants, where there are millions of square yards of surface area which must be coated to provide surface that is easy to decontaminate in case of an accident.
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Safety—Coatings may be applied for reasons of safety, including: –
To make hazards more visible
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To symbolize the presence of certain types of hazardous substances, processes, or equipment
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Because of safety marking requirements and color coding requirements may be mandated by local regulations
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Prevention of product contamination—Coatings may be applied to prevent contamination of the product contained to preserve, taste, or to prevent odor pickup.
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Friction reduction (increased throughput)—A surface may be coated to reduce friction. An example would be coating the interior of pipelines to decrease resistance to flow.
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Wear resistance—Certain high wear areas (e.g., slurry pipelines, hoppers) may be coated with abrasion-resistant coatings to reduce wear of the substrate.
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Heat transfer—Coatings may be used to increase heat transfer (e.g., the use of black paints in solar heating application) or to cut heat transfer (e.g., the use of white and reflective paints on buildings and other structures).
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Electrical insulation—Coatings may be used to provide electrical insulation, as in the case of coating transformer wire.
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Sound deadening (acoustical control)—Foam insulation is an example of a coating material that may also be used for sound deadening.
7.3.2 Mechanisms of Protection Three basic mechanisms by which a coating may provide corrosion protection are: • Barrier •
Inhibitive pigments
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Cathodic protection
7.3.2.1 Barrier
A major purpose of a coating is to protect a substrate from the effects of its environment. One way in which the coating may do this is by acting as a physical barrier between the substrate and its environment. 7.3.2.2 Inhibitive Pigments
Inhibitive coatings contain pigments that react with absorbed moisture vapor within the coating and then react with the steel surface to passivate it and decrease its corrosive characteristics. 7.3.2.3 Cathodic Protection
Coatings can contain active metals (usually zinc) as pigments. These active metals are anodic to steel. In areas where the barrier coating is damaged and an electrolyte is present, a galvanic cell is set up and the metallic coating corrodes preferentially; thus, providing protection to the metal structure.
7.3.3 Desirable Properties of a Coating The following are generally considered to be desirable properties in a coating: • Chemical resistance •
Low-moisture permeability
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Easy application to substrate
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Adhesion to substrate
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Cohesive strength
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Tensile strength
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Flexibility/elongation
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Impact resistance
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Abrasion resistance
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Temperature resistance
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Resistance to cold flow
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Dielectric strength
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Resistance to cathodic disbondment
7.3.3.1 Chemical Resistance
Chemical resistance is the ability of a coating to resist deterioration of its properties due to chemicals present within the intended exposure environment.
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7.3.3.2 Low-Moisture Permeability
One of the primary barrier functions of a coating is to keep moisture away from the substrate. Low-moisture permeability is resistance to moisture vapor absorption and moisture vapor transmission. 7.3.3.3 Easy Application to Substrate
The coating must be easily applied to the substrate by methods which will not affect the properties of the substrate. Ease of application is an important property of a coating, especially for critical exposures where the structure may be intricate, with many corners, edges, recesses, or similar areas. 7.3.3.4 Adhesion to Substrate
Adhesion is created by the physical and chemical forces that interact at the interface of the coating and the substrate. Adhesion to the substrate is greatly enhanced by good surface preparation and correct application of the coating. 7.3.3.5 Cohesive Strength
Cohesive strength is the ability of a coating to resist internal stress due to curing, thermal, expansion/contraction, cold working (forming), etc. It is a measure of the internal strength of a coating and is usually a good indicator of toughness. 7.3.3.6 Tensile Strength
Tensile strength is the ability of a coating to resist breaking/cracking under linear stress. For example, when the substrate heats/cools, the coating can move with it. 7.3.3.7 Flexibility/Elongation
Flexibility is the ability of a coating to withstand deformation of the substrate. 7.3.3.8 Impact Resistance
Impact resistance is the ability of a coating to withstand sudden mechanical shock. Impact resistance is closely related to abrasion resistance. 7.3.3.9 Abrasion Resistance
Abrasion resistance is essential in areas of hard service where damage due to scraping and other abrading actions can occur. 7.3.3.10 Temperature Resistance
Temperature resistance is the ability of a coating to resist deterioration of its properties due to extremes of temperature within the intended exposure conditions. 7.3.3.11 Resistance to Cold Flow
Resistance to cold flow (creep) is an important property in high-build thermoplastic coatings, some of which tend to cold flow (flow down, or slump) with age. 7.3.3.12 Dielectric Strength
The electric field intensity at which coating breakdown occurs is known as the “dielectric strength.” A higher dielectric strength will result in a higher breakdown voltage. The need for a high dielectric strength relates to a corrosion cell that consisting of an anode, a cathode, connected to the anode by a conductive path and the presence of an electrolyte. A coating with a relatively high dielectric strength placed on the cathode will prevent the electrochemical “reduction” reaction while an effective coating on the anode will prevent the “oxidation” reaction thus corrosion in this cell would be stopped. Unfortunately the dielectric strength of coating once applied to the structure is reduced due to coating “holidays” (coating damage or failure) or in some cases due to moisture intrusion into pores or cracks. Cathodic protection can then be applied. Even
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an imperfect highly dielectric coating is desired as it will reduce the cathodic protection current requirement.
7.3.4 Coating System Selection Coating system selection is similar to the selection of any material. Many factors need to be considered, including: • Types of exposure •
Operating conditions/upset conditions
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Substrate
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Ambient conditions during application
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Environmental regulations
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Cost
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Application of coating during operation or at shutdown
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Time constraints
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New construction/maintenance
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Shop/field application
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Design/fabrication considerations
7.3.4.1 Types of Exposure
The type of exposure is an important consideration in coating selection. Coatings should be selected with regard to the service environment. 7.3.4.2 Operating Conditions/Upset Conditions
The specific operating condition may be the chief factor in coating selection. For example, if a coating is to be applied to a structure operating at high temperature and exposed to acid fumes, the coating selected will be limited to one that can withstand these conditions. Upset conditions refer operations that are outside design limits. In some cases, this may cause damage to the coating. For example, a tank properly protected on its interior and containing an acid or alkali might be coated on its exterior with a mildly resistant coating. As long as the contents stay in the tank, no harm may come to the coating. If the tank were to overflow, the exterior coating could fail. If this type of upset condition can occur, then the coating selected for the exterior should be highly resistant to the tank’s contents. 7.3.4.3 Substrate
The substrate affects chemical compatibility, thermal compatibility, flexing, and adhesion of the coating. A reaction between the coating and the substrate could be harmful if it lessens adhesion or leads to corrosion spotting. 7.3.4.4 Ambient Conditions During Application
Anticipated ambient conditions during application, such as temperature, relative humidity, and dew point, can affect how well the coating cures. The selected coating must be one that can be applied successfully in the anticipated ambient conditions. 7.3.4.5 Environmental Regulations
In most locations, governmental regulations restrict the use of certain techniques or materials, such as abrasive blasting and solvent emission. Regulations also restrict coatings to be used in contact with potable water or foodstuffs.
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Cost for a given coating project can influence coating selection. The cost of the coating material itself is frequently only a small portion of the overall cost of coating, which includes surface preparation, coating application, inspection, scaffolding, etc. It is usually most economical in the long term to use the best coating. 7.3.4.6 Application of Coating During Operation or at Shutdown
If coating application is to proceed when a unit is in operation, various factors may influence the coating selection, including: • Metal temperature during operation •
Application methods permissible during operation
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Plant personnel who will be present during operation
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Safety
7.3.4.7 Time Constraints
The time allowed to work on or to complete the job can affect coating selection. 7.3.4.8 New Construction/Maintenance
Generally, new construction projects allow for or require a complete coating system. With maintenance work, surface preparation efforts may not be as effective or the coating may be only require touch up. Coatings compatible with the existing coating system to be maintained must be chosen, and a coating that can tolerate less than perfect surface preparation may also be desirable. 7.3.4.9 Shop/Field Application
Available surface preparation, application equipment, and techniques vary between shop and field application, affecting the types of coatings which may be selected. In many cases, steel is primed in the shop and topcoated in the field. This avoids field surface preparation, which is often difficult and can yield inferior results and prevents mechanical damage to the top coat during transportation and assembly. 7.3.4.10 Design/Fabrication Considerations
The design of the structure should facilitate coating operations and strive to minimize fabrication defects that may hinder corrosion protection. To the greatest extent possible, a structure to be coated should be designed so that it will facilitate the coating. The design should also minimize details that could limit accessibility for future maintenance painting. Common Design Defects Common design defects or details that make coating difficult include: • Inaccessible areas—Inaccessible areas are difficult to coat properly. Special attention is required to ensure proper coating. •
Fasteners—Riveted and bolted construction can leave gaps and areas that are difficult to coat. Riveted and bolted construction should be replaced by welding whenever possible.
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Welding—Welding can produce rough welds and weld spatter which must be removed, ground or requires additional coating thickness.
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Gaps
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Angles
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Threaded areas—Threaded fittings should be replaced, when possible, by the more easily accessible and treated weld pad-type fittings, as threads are very difficult to coat properly.
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Dissimilar metals—Where dissimilar metals are electrically connected by a metallic path, the possibility for severe corrosion exists. Once corrosion starts, it can spread rapidly because of the large exposed cathodic area relative to the small anodic areas present at breaks in the coating. One way to avoid the occurrence of a large cathode/anode ratio is to coat the entire surface.
Common Fabrication Defects Common fabrication defects include imperfect welds and weld spatter, both of which are difficult to completely coat; and are highly vulnerable to corrosion. Breakdown of the coating at a deposit of weld spatter can quickly spread over a large area. Weld spatter is similar to rough welding surfaces and must be removed prior to coating. Proper welding technique is also important. Welds should be continuous rather than skip welds, spot welds, or intermittent welds. Rough welding surfaces should be avoided. Grinding is necessary to make them smooth. Tiny voids in the weld may be bridged over by a coating. Sharp ridges and spikes are difficult to coat, the coating pulls back from the edge of the ridge and is much thinner at that point. Rough welds must be repaired to remove sharp edges and other irregularities. Laminations, scabs, rollovers, and other defects of this type must be corrected to avoid any areas inaccessible to coating. Gouges and other sharp indentations make coating difficult. These indentations should be rounded so that the entire surface can be coated evenly and completely. Coatings applied to gouges may bridge over a gouge, creating a void where corrosion can occur. Coatings tend to pull back from sharp edges. Sharp edges should be rounded. Coatings can bridge over the base of a sharp bend or angle, creating a void that can trap moisture.
7.3.5 Surface Preparation The majority of coating failures are caused either completely or partially by poor or inadequate surface preparation. For this reason, it is highly critical that the correct surface preparation quality for the selected coating be attained. Many factors in surface preparation affect the life of a coating, including: • Residues of oil, grease, and soil, which weaken adhesion or mechanical bonding of paint to the surface •
Residues of various chemicals that can induce corrosion
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Rust on the surface; rust scale cannot be protected by any coating and cannot maintain adhesion to steel
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Presence of loose or broken mill scale which can cause early coating failure. Tightly adherent mill scale may cause later failure
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A surface profile, which may be so rough that it contains peaks impossible to adequately protect with paint, or may not be rough enough, causing coating failure from loss of adhesion
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Sharp ridges, burrs, edges, or cuts from mechanical cleaning equipment, preventing adequate thickness of coatings over irregularities
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Surface moisture which, if painted over, may cause blistering and delamination failure
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Old coatings which may have poor adhesion may be incompatible, or may be too deteriorated for recoating
Generally, these conditions should be remedied by appropriate means of surface preparation prior to any coating application. Many tools, techniques, and methods can be used to prepare a surface for coating. A number of standards exist for various types and degrees of surface preparation, including those described in Table 7.1.
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Table 7.1: Surface Preparation Methods and Standards Joint NACE/SSPC and ISO Standards NACE WJ-1/SSPC-SP WJ-1
Clean to Bare Substrate
NACE WJ-2/SSPC-SP WJ-2
Very Thorough Cleaning
NACE WJ-3/SSPC-SP WJ-3
Thorough Cleaning
NACE WJ-4/SSPC-SP WJ-4
Light Cleaning
NACE No. 6/SSPC-SP 13
Surface Preparation of Concrete
NACE No. 8/SSPC-SP 14
Industrial Blast Cleaning
ADDITIONAL SSPC STANDARDS SSPC SP1 82
Solvent Cleaning
SSPC SP2 82
Hand-Tool Cleaning
SSPC SP3 82
Power-Tool Cleaning
SSPC SP 5 82
White-Metal Blast Cleaning
SSPC SP6 82
Commercial Blast Cleaning
SSPC SP7 82
Brush Off Blast Cleaning
SSPC SP8 82
Pickling
International Standards Organization (ISO) STANDARDS FOUR GRADES OF ABRASIVE BLAST CLEANING Sa1
Brush-Off Blast
Sa2
Commercial
Sa2 ½
Near White
Sa3
White Metal TWO GRADES OF POWER TOOL CLEANING (ISO)
St2
Thorough
St3
Very Thorough FOUR SURFACE CONDITIONS (ISO)
A
Adherent Mill Scale
B
Rusting Mill Scale
C
Rusted
D
Pitted and Rusted
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7.3.6 Coating Application Many methods of applying a coating have been developed. These methods include brush, roller, and spray applications, and specialized methods such as dipping (used in production facilities). 7.3.6.1 Manual
Brushing and rolling rank as the easiest application techniques. Palming is an application method whereby the coating is “gloved” on. This has application on cables and other hard-to- cover items where appearance is not critical. Concrete, mortars, epoxy, polyester, furan, and other materials may be applied as heavy coatings by hand troweling. 7.3.6.2 Spray
Spray application of coating may be accomplished using either conventional air spray, airless spray, electrostatic spray or flame spray. Conventional air spray is a technique in which an air stream is used to atomize the coating and propel it onto the work piece. Airless spray is a technique in which the coating is pressurized and the tip of the gun is designed to atomize the coating. With electrostatic spray, electrically-charged particles of coating are directed through the air toward a surface whose charge is opposite that of the particles. Thus, the coating is attracted to the surface and will tend to deposit with little overspray. It is mainly used on production lines, although some field use occurs. In the flame spray method, thermoplastic powders or rods are fed into a suitable flame and impelled toward the surface to be coated. The particles coalesce and solidify to form the coating. Metals are applied in the same manner at much higher temperatures. 7.3.6.3 Production Techniques
In hot dipping, the work piece is dipped into a bath of molten metal. When zinc is the material applied, the process is called hot-dip galvanizing. When using the fluidized bed technique, thermoplastic polymer powder is suspended in a tank through which air is pumped so that the particles behave like a liquid. Surfaces to be coated are preheated and run through the bed. The hot surface melts the thermoplastic and fuses the coating, and subsequent cooling produces a uniform plastic sheathing. The coating thickness depends on the temperature of the substrate and the time of exposure. Parts to be coated by the powder spray method are heated to the appropriate temperature and then moved to an area where a fusible coating powder is sprayed onto the surface. Powder spray is a production line technique that can produce very uniform coatings.
7.3.7 Inspection Inspection should be conducted before, during, and after each step of the coating operation. A wide array of tests and equipment is available for coating inspection. NACE has a training and certification program devoted solely to coating inspection. 7.3.7.1 Surface Preparation Inspection
Surface preparation inspection includes inspection for such factors as surface cleanliness, anchor profile, and removal of chemicals and other material that may affect coating performance. Assessment of the cleanliness of the surface with regard to removal of rust and old coating is usually performed using visual standards. Anchor profile inspection can be performed in several ways. One of the most common is to use a special conforming tape that is pressed into the surface to be inspected and then measured with a micrometer to determine the anchor profile height. One
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common test for removal of undesirable chemicals is a chemical spot test for soluble iron compounds. 7.3.7.2 Coating Application Inspection
Inspection during coating application involves verification that such conditions as temperature and relative humidity are within the proper limits and that the proper application techniques are used. Wet-film thickness of the coating may be measured during coating application, if required. Inspection after coating may include tests for complete curing of the coating, usually by measuring the hardness of the coating; tests for coating adhesion, and dry-film coating thickness. Coating continuity may also be measured using high- or low-voltage electrical “holiday detectors.”
7.3.8 Wraps and Tapes Protective wraps and tapes are frequently used as protective coatings. While very durable, they must be applied carefully to achieve good performance. They may either be hand-applied to small areas or applied mechanically to large structures, such as pipes for underground service. Some tape systems require the use of a liquid-applied primer for proper adhesion and performance. Some tapes and wraps are loosely applied and then “heat shrunk” to give a tightly fitting covering.
7.3.9 Insulation Some coatings are applied as thermal insulation. When applied directly over a substrate, it is important that these coatings do not absorb moisture and do not contain chemicals that may react with the substrate. If the insulating coating does absorb moisture, either a coating on the surface prior to application of the insulation, or sealing of the insulation to prevent moisture absorption must be used. If the insulation contains materials that may react with the substrate, either an alternative insulation material must be used, or the substrate must be coated prior to the insulation application.
7.3.10 Metallic Coatings Metallic coatings can be applied to other metals, or to nonmetallic substrates in many ways, including by weld overlaying, hot dipping, electroplating, and cladding and thermal spraying. Mechanical damage and corrosion of the coating may expose the substrate. Where the substrate is exposed, the galvanic relationship between the coating and the substrate is very important in the protection of the substrate.
7.3.11 Coating Anodic to Base Metal When the coating is anodic to the base metal, the coating will serve as an anode with respect to the substrate at areas of substrate exposure. The coating can protect the substrate even at defects or damage areas. In immersion or underground service, the size of the defect protected can be large because of the ability of the protective current to flow through the electrolyte. In immersion service, the ratio of exposed areas is favorable when the majority of the surface is anodic and the exposed cathodic area is relatively small. In atmospheric service, the size of exposed substrate that can be protected is limited, usually to 1–2 mm (0.04–0.08 in). In atmospheric service, the effective anode/cathode area ratio is less favorable, but at worst, it is about 1 to 1 and is not unfavorable. Anodic coatings, of course, will be slowly consumed in protecting the substrate, and their life span is dependent upon their thickness. The thick coatings obtained by hot dipping will usually give longer life than the thinner coatings applied by electroplating.
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7.3.12 Coating Cathodic to Base Metal If the coating is cathodic to the base metal, the coating will act as a cathode and the substrate will act as an anode whenever the substrate is exposed. Thus, the substrate will corrode to protect the coating. This is usually not desirable. This effect is accelerated by the relative anode/cathode area ratio. In immersion or underground service, the anode/cathode area ratio can be especially severe. Although less severe in atmospheric service, the area ratio remains unfavorable in most cases.
7.3.13 Organic Coatings Organic coatings are very widely used as protective coatings. They consist of an organic filmforming material called a resin. This resin may be dissolved in a solvent, or may be the primary constituent of the vehicle (the liquid part of the coating). Most coatings also contain pigments to improve the performance of the coating and provide color and opacity.
7.3.14 Coating Degradation All coatings eventually fail. Understanding why coatings failures have occurred will sometimes allow the coatings professional to justify more stringent surface preparation procedures or different coatings for remedial application. The primary reasons for coating failures, in their approximate order of importance are: 2 1. Poor surface preparation and cleanliness 2. Poor coating application 3. Poor or inadequate inspection 4. Poor specifications (both construction and coating) 5. Poor component design Normal ageing phenomena include: • Blistering •
Checking, alligatoring, or cracking
•
Chalking and discoloration
•
Lifting or undercutting the paint film
Figure 7.6 shows a marine piling with typical aging of the protective coating. Several different degradation processes are apparent. The blistering shown in Figure 7.6 is an indication that the lifting due to corrosion undercutting is about to approach these blisters. The blisters shown in Figure 7.6 and Figure 7.7 show osmotic blistering, but the metal underneath the blister is still uncorroded (at the arrow). The arrow indicates a blister that was deliberately broken to determine the condition of the underlying metal. As long as these blisters remain intact, they will serve as permeation barriers and prevent corrosion on buried structures.
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Figure 7.6 Marine Piling with Aging Coating
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Figure 7.7 Osmotic Blistering on a Pipeline Riser
Figure 7.8 shows a similar blister on a buried pipeline coated with fusion-bonded epoxy. The pH of the water bleeding from the deliberately-broken blister was more than 10, indicating that cathodic protection had been able to reach the metal beneath the blister. Figure 7.9 shows corrosion starting at cracks in the protective coating on the inside of a ship’s hull. Hull flexing during storms broke the coating at high-stress areas and led to the corrosion pattern in the picture.
Figure 7.8 Blisters on Fusion-Bonded Epoxy
Figure 7.9 Cracking Due to Structural Motion on the Exterior Wall of a Ship
Abrasion can wear away coatings leading to bare areas producing corrosion patterns like the corrosion shown on the inside of wall of the floating-roof above-ground storage tank shown in Figure 7.10. Impact damage leads to corrosion undercutting and blistering as shown in Figure 7.11 from the front hood of an automobile.
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Figure 7.10 Abrasion from the Floating Roof Scraping on the Inside Wall of Aboveground Storage Tank Caused this Corrosion
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Figure 7.11 Impact Damage on the Front Hood of an Automobile Caused this Corrosion and Coating Blisters
Disbonded coatings, like the pipeline coating in Figure 7.12, allow moisture between the disbonded coating and the underlying substrate. This frequently leads to corrosion. Unlike the fusion-bonded pipeline coating shown in Figure 7.8, many older pipeline coatings, like the coal-tar enamel shown in Figure 7.12 serve as dielectric shields and prevent cathodic protection from reaching the exposed metal surface.
Figure 7.12 Disbonded Pipeline Coating
Figure 7.13 Corroded I-Beam Flange Where Debris Accumulated and Promoted Corrosion
Sheltered areas often accumulate debris and this can lead to corrosion problems. The flange shown in Figure 7.13 corroded on the horizontal surfaces due to the lack of runoff, which removed debris from the exterior surface.
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7.4 Cathodic and Anodic Protection Cathodic and anodic protection are electrochemical techniques used for corrosion control. Cathodic protection has wide use in a variety of environments, including liquid immersion and soil. Anodic protection has very limited, but important, application for a few materials in certain chemical environments.
7.4.1 Principles Cathodic protection reduces or eliminates corrosion by making the metal a cathode by means of an impressed current or attachment to a galvanic anode (usually magnesium, aluminum, or zinc). The cathode in an electrochemical cell is the electrode where reduction (and no corrosion) occurs. Before cathodic protection is applied, corroding structures will have both cathodic areas and anodic areas (those areas where corrosion is occurring). If all anodic areas can be converted to cathodic areas, the entire structure will become a cathode and corrosion will be eliminated.
7.4.2 How Cathodic Protection Works Figure 7.14 illustrates that small direct currents are generated between local anodic and cathodic areas on an unprotected buried or immersed structure.
Figure 7.14 Corrosion Cells on Unprotected Structure, Where A and C Represent Local Anodic and Cathodic Areas, Respectively, on the Structure Surface; Corrosion Attack Occurs at Anodic Areas
Corrosion occurs where the current discharges from metal into the electrolyte (soil) at anodic areas. Where current flows from the environment onto the pipe (cathodic areas), there is no corrosion. In applying cathodic protection to a structure, the objective is to force the entire surface exposed to the environment (soil or water) to be cathodic. This condition is attained by applying sufficient DC current from an external source connected to the structure. This is illustrated in Figure 7.15. The source of this externally-supplied current can be either galvanic (sacrificial)
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anodes and/or impressed current, as described below
Figure 7.15 Illustration of How Cathodic Protection Makes the Entire Surface Cathodic; i.e., Corrosion Cells on the Structure (Shown in Figure 7.14) are Eliminated
7.4.3 Galvanic (Sacrificial) Anode Cathodic Protection Systems In the galvanic anode system, pieces of an active metal, such as zinc or magnesium, are placed in contact with the corrosive environment and are electrically connected to the structure to be protected. The galvanic anodes corrode preferentially, providing protection to the structure. A galvanic (sacrificial) anode can be described as a metal that will have a voltage difference with respect to the corroding structure and will discharge (positive) current that will flow through the environment to the structure. The basic configuration of a galvanic cathodic protection system is shown in Figure 7.16.
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Figure 7.16 Principle of Galvanic (Sacrificial) Anode Cathodic Protection System
Requirements for a metal to be a practical anode material include: • Potential •
Long life
•
Efficiency
Materials that are commonly used as galvanic anodes are: • Aluminum •
Magnesium
•
Zinc
The potential between the anode and the corroding structure must be sufficient enough to overcome the anode cathode cells on the corroding structure. The anode material must have sufficient electrical energy to permit reasonably long life using a practical amount of anode material. Anodes must have good efficiency, meaning that a high percentage of the electrical energy content of the anode should be available for useful cathodic protection current output. The balance of the energy that is consumed in self corrosion of the anode itself should be very small. Anode materials are cast in numerous weights and shapes to meet cathodic protection design requirements. Data on available anodes can be obtained from suppliers of cathodic protection materials. Figure 7.17 shows some examples of galvanic anodes.
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Figure 7.17 Examples of Galvanic (Sacrificial) Anodes; Magnesium (Left) and Zinc (Right)
7.4.4 Impressed-Current Cathodic Protection (ICCP) Systems ICCP is more complicated than galvanic anode cathodic protection. In an ICCP system, external DC power is necessary to drive current from the anode groundbed, through the soil or water, to the structure requiring protection. This is illustrated in Figure 7.18.
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Figure 7.18 Principle of Impressed Current Cathodic Protection (ICCP) System
CAUTION: Anode groundbed must be connected to the positive terminal of rectifier, and the structure to be protected must be connected to the negative terminal of the rectifier. The positive terminal of the power source must always be connected to the anode groundbed, which is then forced to discharge as much cathodic protection current as is desirable. If a mistake is made and the positive terminal is connected to the structure to be protected, the structure will become an anode instead of a cathode and will corrode actively and usually very rapidly. 7.4.4.1 Impressed Current System Anodes
Examples of ICCP anode materials include: • High-silicon cast iron (14.5% Si) •
Graphite
•
Mixed-Metal Oxide (MMO)
•
Precious-metal clad (platinized titanium or platinized niobium)
•
Magnetite (Fe3O4)
•
Conductive polymer
Although scrap steel has been used as an ICCP anode material, its high consumption rate usually makes is very uneconomical in most applications. Figure 7.19 shows some common ICCP anodes.
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Figure 7.19 Examples of ICCP Anodes; Silicon-Iron (Left) and Platinized Niobium (Right) 7.4.4.2 Impressed-Current Cathodic Protection System Power Sources
When an impressed-current system is used, a current supply is necessary. Common current sources are rectifiers and solar cells. Rectifiers A rectifier is provided with power from electric utility system lines. It converts alternating current to a lower voltage direct current by means of a stepdown transformer and a rectifying device. Figure 7.20 shows a typical transformer-rectifier (T/R).
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Figure 7.20 Example of ICCP Transformer-Rectifier (T/R)
Solar Cells Solar panels used with and without battery storage facilities have been most successful and can be considered for use in locations where electric power is not available. Engine generators, fuel cells, wind-powered cells, thermo-electric cells, and other sources may also be encountered.
7.4.5 Measurement of Cathodic Protection Effectiveness Various techniques may be used to determine the degree to which a structure, supposedly under cathodic protection, is actually protected against corrosion. 7.4.5.1 Structure-to-Environment Potential
Potential measurements are a common means for determining whether protection is in effect. If current is flowing onto a protected structure, there must be a change in the potential of the structure with respect to the environment. This is because the current flow causes a potential change, which is a combination of the voltage drop across the resistance between the protected structure and the environment and the polarization potential developed at the structure surface. Reference electrodes such as those discussed earlier in this course may be used to measure the potential to the environment.
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7.4.5.2 Test Coupons
Evidence that cathodic protection is working can be obtained by using coupons of the same metal as that in the protected structure. These coupons may be weighed before they are electrically connected to the protected structure via test stations. Coupons represent holidays in the structure coating. 7.4.5.3 Potential Change
Potential measurements typically contain IR (ohmic) drop errors. These errors are associated with voltage drop between the position of the reference electrode and the structure. The IR drop error is usually corrected by turning the rectifier off and on. Where the cathodic protection system cannot be turned off, disconnecting the coupons at the test stations provides a convenient means for taking on and off potential measurements.
7.4.6 Design Design of an effective cathodic protection system is a complex task requiring experience, knowledge, and judgment. In this course we will briefly mention some of the factors which must be taken into consideration when developing a cathodic protection system, including: • Regulatory requirements •
Economics
•
Metal to be protected
•
Life requirements
•
Total current requirements
•
Variation in environment
•
Electrical shielding
•
Stray-current effects
•
Temperature
•
Wire and cable
•
Anode backfill
•
Protective coatings
7.4.6.1 Regulatory Requirements
Cathodic protection may be required by law for some systems, particularly when corrosion could endanger public safety or the environment. Metallic underground storage tanks and pipes handling hazardous materials are examples of systems where cathodic protection may be required by law. 7.4.6.2 Economics
Compared to the cost of the protected structure, cathodic protection is low. Costs of cathodic protection include the initial cost of design and installation, the cost of power in impressed-current systems, and the cost of inspecting and maintaining the system. 7.4.6.3 Metal to be Protected
The nature of the metal to be protected is a factor in cathodic protection systems. Steel is most commonly the metal protected, but other metals can be protected as well. Amphoteric materials, such as zinc, aluminum, and lead, can be protected under some circumstances, but these metals must be protected very carefully to avoid adverse effects.
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7.4.6.4 Life Requirements
Because of the consumption of anodes, cathodic protection systems have a finite life. Impressedcurrent systems usually have a longer life because of the slow consumption of the anodes. When the anodes are consumed, they can be replaced and the effective protection of the structure can continue. 7.4.6.5 Total Current Requirements
The total amount of current required must be determined during system design. In general, galvanic systems are used when total current requirements are small, and impressed-current systems are used when total current requirements are large. 7.4.6.6 Variation in Environment
The electrical resistivity of the environment is an important factor in the design of cathodic protection systems. Resistivity is a primary factor in the amount of current required and in the design of the ground beds for both galvanic and impressed- current systems. Approximate current requirements (for illustration, not for design) for steel in various environments are given in Table 7.2.
Table 7.2: Current Requirements for Steel in Various Environments Environment
Current Density Required (mA/m2)
Bare steel in moving seawater
100–160
Bare steel in quiet seawater
55–85
Bare steel in earth
10–30
Very well coated steel in earth or water
0.003 or less
7.4.6.7 Electrical Shielding
When the structure to be protected is in an environment with other metallic structures, the other structures can effectively shield the structure to be protected from the cathodic protection current. Design of cathodic protection systems in environments congested with other metallic structures often requires placement of anodes between the structures to ensure proper distribution of current. 7.4.6.8 Stray Current Effects
Currents from nearby electrical systems, such as electric rail systems, can interfere with the current flow in a cathodic protection system. When present, the cathodic protection system must be designed and adjusted to compensate for these currents. Cathodic protection systems themselves are also a source of these currents. All cathodic protection systems in a given locality must be adjusted to minimize interaction and possible damage to other buried metal structures that are not cathodically protected. 7.4.6.9 Temperature
Temperature of the environment can also affect cathodic protection systems by changing the electrical resistivity of the environment or changing the current required for protection.
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7.4.6.10 Wire and Cable
In galvanic systems, the wire connecting the anodes to the structure is not critical. If there is damage to the insulation on these wires, the anode will cathodically protect the exposed metal. In impressed-current systems, the wire connecting the structure to the power source is similarly protected. However, the wire connecting the positive terminal of the power source to the anode bed and interconnecting wires in the anode bed are corroded severely at any break in the insulation on these wires. The anode lead wire on these systems is critical. Specially insulated wires must be used and carefully placed to avoid system failure. 7.4.6.11 Anode Backfill
Backfill is the material placed around the anodes in both galvanic and impressed-current systems. In galvanic anode systems, these materials provide an environment for maximum efficiency, and the low-resistivity environment around the anodes ensures adequate current output. In impressedcurrent systems, anode backfill is used to reduce the resistivity of the environment around the anodes and to increase the effective area of the anode. The proper backfill must be used for each system, and the backfill must be properly placed to ensure maximum anode performance. 7.4.6.12 Protective Coatings
As shown in Table 7.2, a well-coated structure requires much less current than a bare or poorly coated structure. As the coatings on a system deteriorate, additional current must be supplied to ensure adequate protection. Criteria for protection are discussed in detail in NACE SP0169, “Control of External Corrosion on Underground or Submerged Metallic Piping Systems.”
7.4.7 Maintenance Cathodic protection systems require periodic inspection and maintenance. In galvanic anode systems, the two most common problems are the consumption of anodes and damage to connecting wires from digging in the area or from earth movements. Inspection of galvanic cathodic protection usually consists of periodic measurement of the structure-toelectrolyte potentials to ensure adequate protection and measurement of the current output of the galvanic anodes. These measurements are commonly performed at permanently placed test stations, an integral part of the system. Potential measurements and protection criteria are discussed under monitoring in Chapter 8. Inspection of galvanic anode systems is usually performed on a semi-annual or annual basis, but the frequency will vary depending on the system, the material contained in the system, and regulatory requirements. In impressed-current systems, failure of the power source and damage to the electrical connections are the most common problems. As noted above, damage to the wire between the rectifier and the ground bed is a common problem. It is common to require monthly inspection of the power sources in impressed-current cathodic protection systems. Structure-to-electrolyte potential measurements to ensure adequate protection are usually performed on a less frequent basis. As in the case of galvanic systems, impressed-current systems use permanent test stations for most of these measurements.
7.4.8 Anodic Protection Anodic protection is corrosion protection achieved by maintaining an active passive metal or alloy in the passive region by an externally applied anodic current. The basis for this type of protection is shown in Figure 7.21 and Figure 7.22.
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Figure 7.21 Principle of Anodic Protection System
Figure 7.22 Polarization Diagram Showing Anodic Protection Principle
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Solution oxidizing power and corrosion potential are equivalent; therefore, it is possible to achieve passivity by altering the potential of the metal using an appropriate external power supply to apply an anodic current. Anodic protection should not be confused with cathodic protection. In fact, it is quite the opposite. Anodic protection can be applied only to metals and alloys exhibiting active passive characteristics and can be used only for a very limited number of materials in certain environments because electrolyte composition strongly influences passivity. Anodic protection is not a generally applicable method of corrosion control but has been used successfully in the following limited applications: • Steel storage tanks for sulfuric acid •
Steel in ammonium nitrate fertilizer solutions
•
Stainless steel coolers in strong sulfuric acid
•
Steel in sodium hydroxide solutions
•
Steel in alkaline sulfide solutions (pulp and paper industry)
•
Titanium in hydrochloric acid
CAUTION: A very important caution with respect to anodic protection is that if the anodic protection current fails for some reason, the protective article could be very rapidly attacked by the corrosive environment. References 1. P. Roberge, Corrosion Basics: An Introduction, NACE, Houston, 2006 2. R. Heidersbach, Metallurgy and Corrosion Control in Oil and Gas Production, John Wiley & Sons, 2011
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Chapter 8: Inspection and Monitoring Upon completion of this chapter, students will be able to: • Describe the differences between inspection and monitoring •
Identify common techniques for: –
Inspection
–
Monitoring
8.1 Introduction and Definitions Many systems are so complex that it is impossible to inspect or monitor every component before or during operation. Organizations often identify the components that are either most likely to result in failure or those components whose failure is most likely to result in significant damage or losses. This is the basis for risk-based inspection, a concept that has been used for many years in the refining industry and is now being applied to many other industries. It is easy to confuse the purposes of inspection and monitoring, but they are distinct processes that cannot be substituted for one another. This chapter uses these definitions: • Inspection: Used to determine the condition of a system at the time of inspection. •
Monitoring: Used either periodically or continuously as a tool for assessing the need for corrosion control or of the effectiveness of corrosion control methods.
•
Hydrostatic testing: Involves filling a system with liquid to determine if it has adequate strength to withstand the desired stresses, which often include code-mandated safety factors.
•
Other tests: Evaluate products to determine their suitability for use in a system, e.g., oil field compatibility testing to determine if scale, hydrate, and corrosion inhibitors will work effectively together.
This chapter does not discuss testing in detail, but you can apply the principles of inspection and monitoring to testing. A number of NACE standards, technical manuals, and other publications discuss testing in detail.
8.2 Inspection Inspections determine whether equipment or structures exposed to the environment still conform to the safe parameters of the original design. The inspection must establish whether corrosion has consumed the “corrosion allowance.” The “corrosion allowance” is added to the required wall thickness of equipment or structures on which defects, such as cracking or corrosion may occur. Corrosion to a depth below the corrosion allowance will result in replacement of the component or a rigorous fitness-for-service evaluation in accordance with API/ASME 579. Inspections must be conducted in an organized and systematic manner. A number of industries now have computerized programs that help them assess the frequency, timing, and recording of equipment conditions. Inspections can be scheduled or unscheduled. Scheduled inspections are planned in advance and, when possible, conducted during scheduled downtime. Much of the information is obtained prior to a plant shutdown using techniques such as ultrasonic monitoring and radiography to determine the equipment condition in advance. Reliability engineers review past inspections, deficiencies not corrected, value of proposed inspection, and if adequate resources are available to complete planned inspection. Unscheduled inspections usually occur because of a failure and may result in expensive shutdowns. The main purpose of an unscheduled inspection is to determine what needs to be done
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to resume safe operations. Unscheduled inspections provide opportunities to inspect support equipment forced out of service by shutdown of primary equipment. You can sometimes predict the most probable sites of first failure, particularly when fluid flow is a factor. Inspectors must have access to the equipment history or the history of similar units that were replaced. Figure 8.1 shows an example of how corrosion can accelerate at joints or bends.
Figure 8.1 Areas of increased corrosion susceptibility in a horizontal piping system1
Inspection groups include a variety of skilled persons: • Reliability engineers •
Chemists and microbiologists
•
Metallurgical, mechanical, or chemical engineers
•
Mechanical inspectors
•
Corrosion technicians
The inspection technique you select depends on the type of corrosion you can expect. Inspection techniques include: • Visual (VI) •
Radiography (RT)
•
Ultrasonic (UT)
•
Eddy-current (ET)
•
Dye (liquid) penetrant (DPI)
•
Magnetic particle (MT)
•
Positive material identification (PMI)
•
Thermographic
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8.2.1 Inspection Methods 8.2.1.1 Visual
Visual examination is one of the oldest, simplest, and least expensive nondestructive test methods (Figure 8.2). Inspectors examine the object visually or with the aid of a magnifying glass or discreet probing with a penknife. Experienced inspectors can determine a great deal from surface appearance. Inspectors use borescopes and remote television cameras to visually examine inaccessible areas. While many visual inspections follow a programmed schedule and checklist, inspectors should look for any unexpected signs of deterioration. A skilled inspector Figure 8.2 Manual Pit Gauge Measures the Depth helps ensure continued reliable service. Visual of External Pitting on a Pipeline inspections do not require extensive training or equipment and have several benefits and limitations. Benefits of visual inspection include the ability to:2 • Scan large areas quickly •
Identify some forms of corrosion
•
Identify pit depths and pitting rates
•
Use video techniques can be used in areas where personnel access is restricted, such as inside reactor cooling jackets
Limitations of visual inspection include:2 • Must shutdown during internal inspection •
Coatings or deposits may need to be removed
•
Can only identify surface defects
8.2.1.2 Radiography (X-Ray and Radioactive Isotopes)
Radiography inspection uses penetrating radiation from either an X-ray tube or radioactive source to detect surface and subsurface flaws. It measures the amounts and absorptive characteristics of the materials between the radiation source and the detector, usually a film or fluorescent screen. Radiography inspection is useful for detecting voids, inclusions, and pit depths, but is less effective in locating cracks unless the orientation of the crack is known. Radiography inspection works well for inspecting inaccessible areas, such as the insides of valves and pipes. In many cases, inspectors can perform radiography without removing coatings and insulation. The radiograph also has the advantage of creating a permanent record. Figure 8.3 and Figure 8.4 illustrate the principles of radiography and show the kind of defects that can be detected using this technique. Radiography inspection can miss cracks if the cracks are not perpendicular to the plane of the film, so other inspection techniques may be necessary.
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Figure 8.3 Schematic of Film Radiography of a Metal With a Corrosion Pit, an Internal Crack, and Internal Porosity Defects
Figure 8.4 Radiograph Showing Erosion Corrosion at a Piping Bend Where Fluid Flows From Right to Left
Benefits of radiography inspection include:2 • Can use either electronic cameras or film •
Creates permanent record of defects
•
Requires minimal surface preparation since coatings and thin surface deposits are transparent to x-rays
•
Works on most materials
•
Can show fabrication errors, such as incomplete weld penetration
Limitations of radiography inspection include:2 • Allows inspection of local areas only •
Does not provide depth of defect information with 2D images
•
Requires access to both sides of inspected equipment
•
Requires radiation safety measures
•
Needs free access for placement of radiation source
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Misses crack-like defects if not oriented favorably
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Expensive
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8.2.1.3 Ultrasonic
Ultrasonic equipment can gauge the nondestructive thickness of in service equipment subject to corrosive attack. Ultrasonic equipment can detect laminar discontinuities and cracks. The accuracy and smaller equipment size, in addition to continuing improvements in operation, have made ultrasonic inspection equipment more suitable for field inspection. There are two main types of ultrasonic inspection: compression wave for thickness measurements (D-meter), and shear wave for flaw detection. This section only addresses compression wave ultrasonic inspection. Ultrasonic techniques include pulse-echo, transmission, and resonance. With the pulse-echo technique, inspectors only need access to one side of the part they are inspecting. A single transducer sends sound waves into the material and receives the returning echo. Echoes are produced by internal discontinuities from the back of the part. The echo from the back of the part reveals the material thickness. The transmission method uses transducers on both sides of the material to detect internal discontinuities. The resonance method uses a single transducer and is primarily used to measure thickness. All ultrasonic methods, except for thickness measurements, require a skilled operator. Figure 8.5 shows how ultrasonic inspection works.
Figure 8.5 Ultrasonic Inspection a) Sound Waves Detecting Different Pattens in the Part
b) Pulse-Echo Display Results from Readings Taken
As a best practice, inspectors should repeat ultrasonic inspections at the same location on a regular basis to ensure that they monitor changes in wall thickness at the same spot on subsequent inspections. The position of the inspection port shown in Figure 8.6 indicates fluid is flowing from the rear, towards the inspection port, and then up. The bend shown in Figure 8.6 is a likely location for erosion corrosion.
Figure 8.6 Inspection Port for Ultrasonic Equipment to Determine if Erosion-Corrosion Has Occurred on a Piping System
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In Figure 8.7, an inspector is conducting an ultrasonic inspection on the top (12 o’clock position) of a crude oil pipeline. Most internal corrosion of crude oil pipelines occurs near the bottom of a pipeline (6 o’clock position). Most external corrosion also occurs in the lower quadrants (typically between the 4 o’clock and 8 o’clock positions). Benefits of ultrasonic inspection include:2 • Requires direct access to only one side of the inspected material •
Can be used online
•
Provides accurate measurement of thickness and flaw depth
•
Can penetrate thick materials
•
Permits estimation of maximum allowable pressures based on measurements and ANSI/ASME B31G, API 653, API 510, API/ ASME 579, and similar codes
Figure 8.7 Ultrasonic Inspection of the Top (12 O’clock Position) of a Crude Oil Pipeline
Limitations of ultrasonic inspection include:2 • Usually requires direct access to material surface •
Requires extensive training and experience
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Many inspections are performed at easily-accessible locations, rather than likely areas of corrosion, e.g., pipe bottom
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Less accurate on non-metals
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Limited use on thin materials
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May not be suitable for online inspection of hot equipment due to temperature limitations
8.2.1.4 Eddy Current Inspection
Inspectors can perform eddy-current inspection (ET) on any electrically conductive material. Defects such as cracks, bulges, or corrosion pits alter the flow of electrical current and produce signals that inspectors can analyze and correlate with flaws. The basic equipment consists of an alternating electrical current source, a connected coil (probe) that inspectors pass near the part they are inspecting, and a voltmeter to measure the voltage across the coil. Inspectors move the probe across the surface and note any current changes. Figure 8.8 shows eddy current inspection of heat exchanger tubing. Eddy-current inspection is the most common method of checking for fatigue cracks and fretting at intermediate support baffles on heat exchangers. For eddy-current inspections, inspectors commonly draw the probe through the tubing and note horizontal locations where indications are noted. Further inspections, like ultrasonic, can determine the type of flaw noted during eddy-current inspection. It is common to block any tubes with eddy current indications until the number of blocked tubes affects equipment performance.
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Benefits of eddy-current inspection include:2 • Relatively simple and rapid method •
Makes surface defects easier to detect
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Works on all nonporous materials
Limitations of eddy-current inspection include:2 • Requires extensive training •
Complex analysis
•
Is limited to conductive materials
•
Has limited penetration depth Figure 8.8 Eddy Current Inspection Of Heat Exchanger Tubes
8.2.1.5 Dye Penetrant Inspection (DPI)
Dye penetrant inspection is also called liquid penetrant inspection. Inspectors use DPI to locate crack-like surface defects on a variety of non-porous materials (metals, polymers, and even concrete). Sometimes, flaws are open to the surface, but are impossible to find visually without aid. These include fine cracks caused by stress corrosion, fatigue, grinding, galling, etc. Flaws of this type may be found more easily by applying a liquid dye penetrant that becomes visible when a thin layer of absorptive material called a developer, is applied and wicks the penetrant out of the flaws making them more visible. Figure 8.9 shows a dye penetrant inspection for stress corrosion cracking in a stainless steel component of a chemical plant piping system. Benefits of DPI include:2 • Is a relatively simple and rapid method •
Makes surface defects easier to see
•
Works on all nonporous materials
Limitations of DPI include:2 • Requires skilled inspectors •
Is limited to surface defects
•
Requires direct access to surface being inspected
•
Requires chemical cleaning and disposal of dyes and Figure 8.9 Dye Penetrant Inspection developers
•
Paint and other coatings can mask defects
for Surface Cracks on Non-Magnetic Piping
8.2.1.6 Magnetic Particle Inspection (MPI)
Magnetic particle inspection has two principle advantages over dye penetrant inspection since it can: • Detect near-surface flaws (e.g., hydrogen blisters or weld defects) that would be missed by penetrant inspection. •
Sometimes detect smaller flaws than would be detected with penetrant inspection.
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The process involves applying a magnetic field, typically with an AC coil or DC “prods,” to the area to be inspected. Inspectors then spray fine iron powder (dry MPI) or iron powder suspended in a liquid (wet MPI) onto the surface. In wet MPI, the solution can be non-fluorescing (visible to the naked eye) or fluorescing (visible only under black light). The particles “decorate” flaws due to residual magnetic fields in the structure’s surface. Figure 8.10 shows surface crack indications on the exterior of a pipeline. Benefits of magnetic particle inspection include:2 • Relatively simple and rapid method •
May detect fine cracks missed by visual and dye penetrant inspection
•
May reveal shallow subsurface flaws
Limitations of magnetic particle inspection include:2 • Requires extensive training of inspectors •
For ferromagnetic material inspection only
•
Requires clean, smooth surfaces
•
Coatings may interfere
Figure 8.10 Magnetic Particle Crack Indications on the Exterior of a Pipeline
8.2.1.7 Positive Materials Identification (PMI)
Inspectors use portable X-ray fluorescence spectrometers to identify and confirm the composition of corrosion-resistant alloys during delivery from suppliers. They also confirm that as-built records on alloy composition are correct. Inspectors place a radiation probe on the part. This produces an X-ray spectrum that inspectors use to identify the elements on the metal surface and the specific alloy. Most commercial instruments are pre-programmed to identify dozens of alloys and the typical readout tells the inspector which of the pre-programmed alloy compositions most closely matches the detected X-rays. Figure 8.11 shows one of these spectrometers in use. Before beginning, inspectors clean the surface so that the bare metal is exposed and then place the detector on the surface they are inspecting. The machine analyzes the surface in seconds and compares it with the preloaded spectrum providing the nearest match. Portable spectrometers cannot detect light elements and cannot be used to distinguish between carbon steels. Inspectors typically perform field identification/sorting of carbon and low-alloy steels with hardness testing. PMI analyzers will easily differentiate between carbon steel, 1 ¼ Cr – ½ Mo steel, 2 ¼ Cr – 1 Mo steel, etc. Figure 8.11 Portable X-Ray Fluorescent Spectrometer Being Used for Positive Materials Identification3
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Benefits of PMI include:4 • Identifies many alloys quickly and accurately Limitations of PMI include:4 • Cannot differentiate between carbon steels •
Will not detect Al, Si, C, and other light elements
•
May get false results from surface contamination
•
Requires direct access to cleaned surface for analysis
•
Has a high initial equipment cost
8.2.1.8 Thermographic
Thermographic inspection (also called thermography) uses infrared cameras to detect temperature differences in equipment. Thermography will detect temperature variations due to fouling in shell and tube heat exchangers, maldistribution of flow in air coolers, settling of sediment or other debris in the bottom heads of vessels or along the bottom of horizontal piping, and loss of internal refractory lining. It is used as a remote inspection technique to determine fluid levels in storage tanks and for a variety of other purposes.5 Inspectors use advanced camera systems to detect temperature changes across the surface of structural components. Thermography can detect hidden corrosion, water, solids buildup, and composite delamination. Figure 8.12 shows a thermographic image used to detect leaks and corrosion underneath insulation (CUI). Thermography cannot identify the reason for temperature differences in a system, but it is used as a quick means of determining where closer inspections are warranted. Benefits of thermographic inspection include:5 • Is a nonintrusive remote technique • Can detect temperature changes as low as 3°C (5°F) • Allows identification of hot or cold spots due to fouling, maldistribution of flow, settling of sediment or other debris, and loss of internal refractory lining
Figure 8.12 Thermographic Image Showing Location Where Insulation Breakdown Leads to CUI
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Limitations of thermographic inspection include:5 • Cannot determine corrosion or wall thinning quantitatively
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8.2.2 Significance of Inspections Inspectors need guidance on how to collect and analyze surface deposits and biological samples, and protect them for shipment to analytical laboratories. Inspections can become so routine that decision makers are not notified when important changes occur. Figure 8.13 shows a sulfuric acid storage tank made from carbon steel, an accepted industrial practice. The tank experienced gradual wall thinning due to general attack corrosion. Inspectors performed ultrasonic inspection on a regular basis, and the original design called for replacement when the thinning reached a specific point. However, the inspection reports were filed, but were not brought to the attention of the proper decision makers. The tank was not replaced on time, and a subsequent filling of the tank produced the slumping shown by the arrow in this picture. Fortunately for the chemical plant where this happened, the steel bent under Figure 8.13 Slumping Acid Storage Tank Due to excessive loading and did not leak. Excessive Wall Thinning4 Many maintenance and inspection organizations have budgets related to production volumes. As equipment ages and systems become less profitable, inspection and maintenance budgets are reduced when inspection and maintenance are the most important. Corrosion-related incidents in recent years have led to the introduction of internal corrosion direct assessment (ICDA) and external corrosion direct assessment (ECDA) programs, currently under development. In addition, the refining and chemical process industries have introduced risk-based inspection protocols.
8.3 Corrosion Monitoring Inspection determines the condition of equipment at the time of inspection, while monitoring allows operators to determine if corrosive conditions and corrosion rates are changing. Both procedures are necessary. Corrosion monitoring determines the effectiveness of corrosion control methods, such as chemical inhibitor injection. As process conditions change, monitoring can be used to determine if environments are becoming more or less corrosive. Corrosion monitoring cannot always accurately identify the extent of corrosion in the most corrosion susceptible parts of complicated systems.
8.3.1 Corrosion Probes Most corrosion monitoring techniques require the insertion of intrusive metal samples of some type into the corrosive fluids. Figure 8.14 shows two Figure 8.14 Intrusive and Flush-Mounted typical arrangements. The corrosion coupon on the Corrosion Probes Inserted into a Three-Phase left is exposed into the process piping where it is Oilfield Production System2 exposed to produced water, oil, and natural gas. The probe on the right is flush-mounted with the piping wall, so it is only exposed to the produced water layer on the bottom of the pipe.
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8.3.2 Mass-Loss (Weight-Loss) Coupons Mass-loss coupons, which are also know as weight-loss coupons, are the most commonly used devices for monitoring corrosion. They come in a variety of shapes and different mounting methods (Figure 8.15).
Figure 8.15 Mass Loss Coupons and Probes Used for Corrosion Monitoring
NACE and other standards suggest methods of analyzing coupons after exposure for average (weight loss) corrosion rates and pitting rates, based on the deepest pits on the coupon.1, 5 Figure 8.16 shows how corrosion rates vary with time. Some corrosive environments produce linear corrosion rates (linear rate law), because the reaction products in these environments are soluble and removed from the metal surface. Most corrosion rates decrease with time (parabolic rate law). This means that the analysis of weight-loss data from short-term exposures may overestimate the true corrosion rates of equipment. Pitting and other corrosion mechanisms may not be detected from short-term exposures that are too short for corrosion initiation to be detected. Figure 8.16 Corrosion Rate Change vs. Time Benefits of mass-loss coupons include:1, 5 • Can be used in any corrosive environment •
Are a relatively simple procedure which is easily understood and widely accepted
•
Used to assess general attack and localized corrosion
•
Are relatively inexpensive
Limitations of mass-loss coupons include:5 • Must be inserted into fluid, which exposes personnel to potential hazards •
May create localized corrosion from turbulence with the projection of the coupon rack into the flow
•
Data is only available for time of exposure; multiple exposures are usually required
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Cannot be automated
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•
Determine only average corrosion rates, not effects of upsets or unusual occurrences
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May overestimate general corrosion rates and underestimate pitting or microbial activity due to short duration
•
Is a labor-intensive technique
8.3.3 Electrical Resistance Probes Electrical resistance (ER) probes contain a sensing element which is exposed to the process stream. The sensing element is made from the material of interest. The electrical resistance of the sensing element is measured either continuously or periodically. As the cross-sectional area of the sample is reduced by corrosion, the electrical resistance increases. Recent improvements in ER probe design have resulted in probes that can detect changes in corrosivity relatively rapidly, within hours instead of days. This means the probes can be used to remotely monitor corrosion at multiple locations and determine where if the location needs closer inspection or if there have been process upsets like air and oxygen intrusion. Figure 8.17 shows typical ER probes. Many of these probe designs allow for flush-mounted corrosion rate detection.
Figure 8.17 Typical ER Probes2
Benefits of ER probes include:5 • Allow continuous online corrosion monitoring •
Can be used in almost any environment
•
Can be directly connected to cathodically-protected structure to monitor corrosion-control effectiveness
Limitations of ER probes include:5 • Provide results indicative of general corrosion or erosion •
Cannot detect pitting and crevice corrosion—they only measure average loss of sensor cross-section
•
Require insertion of probes into the corrosive fluid
•
Have slower response (hours to days) than other electrochemical monitoring techniques
•
Can produce misleading results in the presence of electrically-conductive deposits (e.g., iron sulfide)
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Are not sensitive to rapid temperature changes
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8.3.4 Electrochemical Methods Electrochemical techniques measure the propensity of metal ions in a metal or alloy to pass into solution, by measurement of potentials and current density, on a corroding electrode system introduced into the process fluid to be monitored. For electrochemical measurements, the process fluid needs to be sufficiently conductive. In multiphase conditions or dew point/condensation conditions, the electrodes are positioned in such a way that the conductive phase completely covers the electrodes and interconnects the electrodes for quantitative measurements. Several electrochemical test methods were adapted to field-test procedures that are useful in corrosion monitoring. These include: • Linear polarization resistance (LPR) •
Tafel extrapolation
•
Galvanic monitoring
•
Electrochemical noise (EN)
•
Electrochemical impedance spectroscopy (EIS)
The first three techniques are suitable for field use in conductive fluids. Electrochemical noise and AC impedance spectroscopy, while popular in research laboratories, currently cannot produce better results than LPR and Tafel extrapolation. They require more expensive, delicate equipment, and are not discussed in this course. Electrochemical corrosion monitoring techniques have an almost instantaneous response (seconds or minutes) to changes in fluid corrosivity. This may be useful in identifying what process changes have produced changes in fluid corrosivity. 8.3.4.1 Linear Polarization Resistance (LPR)
LPR probes are sold with electrodes made of the material being monitored, typically carbon steel. The probes are small and may be inserted into fluids in the same manner as ER probes. The technique is based on the observation that, for many metals in many environments at potentials near the corrosion potential (±20 mV), the potential versus current plot is frequently linear. Figure 8.18 shows this relationship. The LPR technique is used to determine general corrosion rates in conductive electrolytes. LPR cannot measure localized (e.g., pitting) corrosion rates. LPR can be used to determine corrosion rates only for freely-corroding electrodes. LPR cannot be used if the probe is connected to, for example, a dissimilar metal or subjected to impressed current cathodic protection. Figure 8.18 Voltage vs. Potential Plot at Potentials Near the Corrosion Potential Instrumentation sold for LPR corrosion rate monitoring converts the slope of the voltage versus potential plot into average corrosion rates based on assumptions first described by Stern and Geary.2 The instruments are normally calibrated based on the assumptions that the “average” Stern-Geary constants apply and that the corroding metal is carbon steel corroding to produce Fe+2 ions (instead of Fe+3 ions). These assumptions and other limitations mean that the true corrosion rate cannot be determined within 50%.2, 4, 6 This limitation is not important for most LPR applications, because the purpose of on-line corrosion monitoring is to detect changes in corrosion rates and not true corrosion rates.
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Like all electrochemical monitoring techniques, the electrodes must be free of fouling caused by oily deposits. This is a major limitation in some industries, and it is the reason why more organizations use ER techniques. 8.3.4.2 Tafel Extrapolation
The Tafel extrapolation technique uses the same equipment as LPR monitoring, and most instruments are sold with the option of operating in either the LPR or Tafel extrapolation mode. At potentials greater than a few millivolts from the corrosion potential, potential-current plots may become linear on log-linear plots (Figure 8.19). Before the application of an applied current, the voltmeter reads the corrosion potential relative to a reference electrode. The current due to corrosion is unknown. As the inspector applies current, the applied current versus potential Figure 8.19 Applied Current Cathodic curve shows no change in potential when most Polarization Curve of a Corroding Metal of the reduction current on the structure Showing Tafel Extrapolation (working electrode) is due to the corrosion reaction. Eventually, the effects of the applied current cause the potential to shift in the cathodic direction and the curve slopes downward. After most of the current is due to applied current, the slope become linear and the original current becomes negligible. The log-linear portion of the polarization curve is called the “Tafel region,” in recognition of the German chemist who first described this behavior. The Tafel slope is then extrapolated back to the original corrosion potential to determine the original oxidation and reduction equilibrium currents before external cathodic current was applied. This technique can measure low corrosion rates at equal or greater accuracy than weight loss measurements. It is possible to measure extremely low corrosion rates with this technique, provided only one reduction reaction is involved over the potential range of the survey.6
8.3.5 Galvanic Monitoring Galvanic monitoring is a simple technique that involves placing electrodes of two dissimilar metals (usually carbon steel and a more corrosion-resistant, therefore cathodic, metal) in the same electrolyte. A zero-resistance ammeter (ZRA) measures the galvanic current between the two electrodes. If the environment becomes more aggressive, the current increases, indicating that something has occurred to change the corrosion rates. The technique is used to monitor corrosion rates in any water system where air leaks (and increased oxygen reduction reactions) or bacteria increase the corrosivity of the fluid. The instrumentation is simple and, like other electrochemical techniques, the results of many electrodes can be monitored at a central location. The response time is equal to LPR probes.
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8.3.6 Hydrogen Probes The reduction reaction associated with corrosion in acid environments produces hydrogen gas on the metal surface. While most of the hydrogen atoms almost immediately form hydrogen gas molecules and are evolved as hydrogen gas, some of the hydrogen atoms will migrate into the metal. There are three types of hydrogen probes: • Hydrogen pressure (or vacuum) probes • Electrochemical hydrogen patch probes • Hydrogen fuel cell probes
Figure 8.20 Schematic of Hydrogen Pressure Probe
Figure 8.20 is a schematic of a hydrogen pressure probe that can be externally mounted on the exterior of pipelines or storage tanks. The seal between the probe and the structure must be gas tight. This may require welded patches or temporary probes. Probes of this type can be used to monitor the effectiveness of internal corrosion inhibitor programs for mitigating hydrogen assisted cracking.
8.3.7 Water Chemistry Monitoring For water or process streams, chemistry monitoring may detect changes in the environment that may affect corrosion on a periodic basis by the collection and laboratory analysis of samples, or through the continuous use of measurement probes, such as pH electrodes or oxygen probes. Tests frequently analyze pH, oxygen content, carbon dioxide content, inhibitor concentration, and metal ions in solution. Metal ion content can measure the amount of metal loss within the system and indicate the overall corrosion performance of the various metals in the system. It cannot determine where the corrosion is occurring or the form of attack. 8.3.7.1 Deposits
By determining the chemical composition of corrosion product residue within deposits, organizations can obtain significant information regarding the cause of the corrosion. For example, the detection of copper within an aluminum corrosion product/deposit that has formed on top of a corrosion pit in an aluminum alloy may suggest that the pit growth was stimulated by aqueous copper ions dissolved in the water system. Another common example is the detection of chlorides within a water-formed deposit present on a pitted area on austenitic stainless steel. 8.3.7.2 Suspended Solids
The amount of suspended corrosion product can be used to determine the amount of metal corroding within the system. Suspended solids can be evaluated for chemical composition. They may be corrosion products or precipitates from reactions within the system or thermally deposited scales.
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8.3.7.3 Scale
Scale and corrosion products may remain in place within the system and can be removed and analyzed to determine their chemical makeup. The chemical composition of corrosion product scales, as well as their adherence, thickness, and continuity, can be useful in determining corrosion performance and the cause of corrosion failures.
8.3.8 Microbiological Fouling Microbiological activity can have a significant effect on corrosion (i.e., Microbiologically Influenced Corrosion, MIC), as well as on other system functions, such as heat transfer. The presence of microorganisms within the system may be monitored directly to count microbes using growth or culture-based methods. Examples of such methods include plate counts, dipslides, or serial dilution vials. Levels of bioactivity can also be monitored indirectly using specific biochemical markers (e.g., ATP). Planktonic counts refer to monitoring free-floating organisms in bulk water. This information is not as useful for understanding a system’s biological cleanliness as the results of monitoring the numbers of organisms colonizing wetted surfaces in the system, also known as sessile counts. Corrosion coupons provide a convenient sampling surface for monitoring such populations whether by direct culture-based counts or ATP-based bio-monitoring. In addition, organizations can also monitor the presence of microorganisms within the system indirectly by measuring the loss of nutrient materials (nutrients for the organisms may be significantly different from food products). By-products of microorganisms include hydrogen sulfide, (which can be very corrosive and hazardous to personnel) and strongly acidic corrosion product residue which can cause intense localized pitting underneath the biofilm. Microorganisms influence corrosion in several ways. The simple presence of a biofilm (a complex community of microorganisms growing on wetted or submerged surfaces) can block corrosion inhibitors from reaching the surface. Some microbes in biofilms produce waste products such as organic acids and hydrogen sulfide that are directly aggressive to metal surfaces. In addition, the biofilm is a deposit that creates a crevice on the metal surface. This can lead to concentration cell corrosion through effects on oxygen and chloride levels. Finally, microbial activity can remove reaction products at either the anode or cathode of the corrosion cell. These accumulated reaction products slow corrosion rates but when removed, corrosion rates once again increase (so-called, “depolarization”).
8.4 Cathodic Protection Systems The continued operation of cathodic protection requires inspection to ensure that the system is working properly and monitoring to assure that proper protection is being achieved (which may be a regulatory requirement mandated for certain applications handling hazardous products, such as high pressure gas and oil pipelines, petroleum storage tanks, etc.).
8.4.1 Inspection For impressed current cathodic protection (ICCP) systems, rectifiers should be inspected at least annually, to ensure that they are operational and repairs and adjustments made, as needed (e.g., current output), to maintain protection. The accessible electrical cable connections associated with the anode groundbeds, structures, and test stations should be clean and properly secured to their respective terminals to maintain low electrical resistance paths. Oil in oil-filled rectifiers should be replaced if discolored or contaminated with water. Inspection of buried anodes is usually not possible, except during replacements. Immersed anodes may be amenable to inspection if the anodes can be lifted out of the water (e.g., in storage tanks); using divers to inspect fixed anodes (e.g., on offshore structures or ships); or during dry-docking (e.g., for ships and boats). For ICCP systems, proper electrical safety procedures and precautions must be followed during inspections.
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8.4.2 Monitoring The effectiveness of cathodic protection in controlling corrosion is usually determined by appropriate monitoring of the structure being protected. The most common monitoring method involves measurement of structure potentials with the aid of a high-impedance DC voltmeter and a suitable reference electrode (also known as a half cell; e.g., copper/copper-sulfate, silver/ silver-chloride, etc.). The structure-to-electrolyte potential (known as pipe-to-soil potential in the case of buried pipelines) is measured as illustrated schematically in Figure 8.21. The potential measurements can be performed using either portable or stationary reference electrodes; stationary reference electrodes should be compared against portable for indications of drift. Such potential measurements or surveys are performed periodically to determine protection levels being achieved. Portable data-loggers, carried in backpacks, are now routinely used during such surveys to record data over the structures. Cathodic protection criteria, discussed in NACE SP0169, are listed below: • –850 mV polarized potential vs. Cu/CuSO4 (CSE) reference electrode •
100 mV polarization
•
E log i
•
Net protective current
•
Coupons attached to the structure
Figure 8.21 Measurement of Pipe-to-Soil Potential 4
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Corrections of the measured potentials for ohmic drop (IR-drop) errors are discussed in NACE SP0169. For large-diameter, long pipelines, smart pigs (in-line inspection tools) that travel inside the pipeline can indirectly monitor cathodic protection levels on the pipeline exterior surface. Figure 8.22 shows a convenient test station for making electrical connection to a buried pipeline for monitoring or troubleshooting the cathodic protection system. Where possible, such test stations can be located at regular intervals (e.g., every mile) along the pipeline right-of-way for performing the potential surveys.
Figure 8.22 Typical At-Grade Test Station 4
References 1. NACE RP0775, “Preparation, Installation, Analysis, and Interpretation of Corrosion Coupons in Oilfield Operations.” 2. B. Hedges, H. J. Chen, T. H. Bieri, and K. Sprague, “A Review of Monitoring and Inspection Techniques for CO2 and H2S Corrosion in Oil & Gas Production Facilities: Location, Location, Location,” NACE 06120. 3. Thermo Fisher Scientific and Niton Instruments. 4. R. Heidersbach, Metallurgy and Corrosion Control in Oil and Gas Production, John Wiley & Sons, 2011. 5. NACE 3T199, “Techniques for Monitoring Corrosion and Related Parameters in Field Applications.” 6. M. Fontana, Corrosion Engineering, McGraw-Hill, 1986.
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