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WELCOMING WORD You're Excellencies, It is for International Petroleum Services Group (IPSG) an honor and a privilege to convey this message to all the participants in the training course for API 510 INSPECTOR’S EXAMINATION. IPSG strongly commends the participants for having taking this initiative which will undoubtedly enhance the knowledge of essential to the professional practice of inspecting in-service pressure vessels and process piping.
During the next five days you will be called upon to covering all interesting facts and history regarding the evolution of the API Code, and it's close association with the ASME Code. Additionally, the "Special Notes" available in this training material offer some interesting information, particularly regarding the legalities of using the Code, and also that users of API-510 are cautioned to check the laws where the pressure vessel is installed to be sure API -510 is acceptable to the local and/or state jurisdictional authority. We are sure you will be most successful in this endeavor, on the one hand, on the basis of supporting your technical knowledge within the oil industry, on the other, in the perspective of enhanced standards of skillful employees who will be a value addition to KPC and it's subsidiaries.
IPSG is at your side as you embark the unlimited learning cycle of life for the cause enriching your technical skills. And we await with great expectation the results of your deliberations so as to strengthen the cooperation between Kuwaiti Petroleum Corporation (KPC) and International Petroleum Services Group (IPSG) with a view to contributing, as of now, to fulfill KPC's training demands.
Thank you very much.
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TABLE OF CONTENTS
Introduction ……………………………….…………………….…………………………….……….…….……………
3-8
ASME API History and Interrelationships ……………………….……….…..………………………
9 - 15
Review of API RP577 ………………………………………………………….……….…….………………….
16 - 35
ASME Section IX ……………………………………………………….…...……….………...……………...……..
36 - 102
ASME Section VIII ……………………………………………………….…..……....……….……………...……..
103 - 189
ASME VIII and API 510 Sample Calculations …………….…..……………..…………...……..
190 - 227
Review of API 510 ……………………………………………………….…..……..………….…………...……..
228 - 241
ASME Section V ………………………..……………………………….…..…...………………….………...……..
242 - 290
Review of API RP 571 ……………………………………………………….….………..……………...……..
291 - 331
API 510, 572, 576 Questions
………………………………………….…….………..……………...…….
332 - 365
External Pressure Charts ……………………………………………….……..….……..……………...……..
366 - 382
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INTRODUCTION
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TRAINING COURSE FOR
API 510 INSPECTOR’S EXAMINATION S PREPARATION COURSE FOR CERTIFICATION EXAMINATION T
DISCLAIMER: THE TRAINING MATERIAL HEREIN IS THE PROPERTY OF itcSkills ANY UNAUTHORIZED REPRODUCTION, COPYING, OR DISTRIBUTION WITHOUT THE EXPRESS WRITTEN CONSENT OF SCHINDLER & ASSOCIATES (LLC.) OR CODEWEST IS PROHIBITED AND WILL BE PROSECUTED TO THE FULLEST EXTENT ALLOWED BY THE LAW. All figures, sketches, and tables reproduced from ASME Code books and shown in this book are provided courtesy of the American Society of Mechanical Engineers in New York, New York. NOTE: The opinions and material presented here are solely those of itcSkills, and do not, in
any way, constitute an official interpretation or guidance to the user. As in all codes and standards, any official interpretation or guidance must be provided by the applicable committee of individual responsible for that code or standard.
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5 DAY TRAINING COURSE TENTATIVE COURSE OUTLINE FOR API 510 TRAINING SEMINAR (All times/dates are approximate)
Day 1 A.M. Instructor Introduction Introduction to Training Course and what will be covered Detailed coverage of what to expect on examination Introduction to ASME and API Organizations Review of RP 577 P.M. Review of ASME Section IX
Day 2 A.M. Commence review of ASME Section VIII Design P.M. Continue review of ASME VIII Design
Day 3 A.M. Complete Review of ASME VIII P.M. Commence Review of API 510
Day 4 A.M. Continue Review of API 510 P.M. Review of ASME Section V
Day 5 A.M. Review of RP 576 P.M. Review of RP 572 & 571
£ Timings Subject to Fluctuation
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INFORMATION FOR CANDIDATES API 510, PRESSURE VESSEL INSPECTOR CERTIFICATION EXAMINATION
FORMAT OF THE EXAMINATION The API 510 inspector certification examinations consist of objective multiple-choice questions covering knowledge essential to the professional practice of inspecting in-service pressure vessels and process piping. Each exam is constructed according to detailed test specifications. Each question has four alternative answers, only one of which is correct. The examinations contain 150 questions and are divided into two parts. Part 1 is open-book, and consists of 40 - 50 questions which can be answered using API and ASME reference material. Candidates will have 4 hours to complete Part 1. Part 2 is closed-book, and consists of 100 – 110 questions which must be answered without access to any reference material. Candidates will have 4 hours to complete Part 2. A total of 8 hours is allowed to complete each exam.
ADMISSION PROCEDURE If you application and fee is received before the deadline, and you meet the education and experience requirements set by API, you will be allowed to sit for the exam. You should receive notification of the test site from the jurisdiction prior to the exam date. Please be aware of any special instructions that may be included in the jurisdiction notification. Please report to the test site no later than 7:30 AM on the morning of the exam. Seating of candidates, distribution of test materials, and testing instructions will begin at 8:00 AM. Remember to allow adequate travel time to find the testing site on the morning of the exam. On the morning of the exam, candidates should bring an appropriate form of picture identification bearing their signature. Examples of acceptable forms of ID are a driver’s license, a passport, or an employee identification card. Social security cards are not acceptable. If you move or change your address, it is your responsibility to notify API and the jurisdiction of your new mailing address at least 4 weeks before the exam date so that your score report can reach you in a timely manner.
EXAMINATION PROCEDURES •
The testing time for each part of the exam is 4 hours. Additional time has been allowed for instructions. There is a one-hour lunch break scheduled after Part 1 of the exam, but if you complete Part 1 before time is called, you may leave the testing room. However, you may not re-enter the room until Part 2 of the exam is about to begin.
•
Candidates should bring some sharpened #2 pencils with erasers, a non-programmable calculator, and a set of API and ASME reference materials. Highlighting, underlining, page tabs, or written notes in the margins of the code books are acceptable. Note: API and ASME publications are copyrighted material. Photocopies of these reference documents are not permitted in the examination room.
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•
No loose notes, papers, or other books of any sort may be brought into the examination room.
•
No test materials, documents, notes or memoranda of any sort are to be taken from the examination room.
•
No questions concerning the content of the examination may be asked during the testing period. Candidates should listen carefully to instructions given by the proctor.
•
Candidates have the opportunity to comment on any question believed to be misleading or inaccurate at the end of the examination. A form for this purpose will be provided to candidates upon request. Be specific when commenting on a question as each comment will be individually reviewed by the Examination Committee. Individual responses to question comments will not be provided.
•
Proctors are authorized to maintain secure and proper test administration procedures, including relocation of candidates. Candidates may not communicate with each other during the examination.
SUGGESTIONS FOR TAKING THE EXAMINATION •
Answer the questions in order, but don’t waste time on questions containing unfamiliar or difficult material. You can come back to them later, time permitting.
•
Make educated guesses at correct answers rather than leaving the answer spaces blank. The score on the test will be based on only the number of correct responses, with no penalty for wrong answers.
•
Record your answers carefully on the separate answer sheet. The numbering of the questions in the test booklet should match the numbering of the responses on the answer sheet.
•
Should you change your mind on any answer, erase previously marked responses thoroughly. Multiple responses to a question will be scored as incorrect. Avoid making any stray marks on the answer sheet.
A criterion referenced passing score has been established by a panel of content experts using appropriate standard setting procedures. The passing score for each administration of the API 510 and 570 inspector certification examinations are based on a statistical equating process which adjusts for fluctuation in difficulty levels across different examinations. Equating ensures that candidates are evaluated according to the same competency standard from year to year. After each examination administration, individual test questions subject to comments from candidates are evaluated for their clarity and accuracy by the API Exam Construction Task Group prior to the grading process. Questions determined to be ambiguous may be scored with multiple correct answers at no penalty to the candidates. Exams are scored using an automated system. Any grievance or requests for manual scoring must be submitted in writing to API within 90 days after receipt of your score. Requests for manual scoring must include a viable reason why your exam should be re-graded. There is a $50 fee for manual scoring of exams. Requests should be submitted to: American Petroleum Institute Industry Services Dept. Inspector Certification Programs 1220 L Street, NM Washington, D.C. 20005-4070 202-962-4739 (Fax)
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AFTER THE EXAM Approximately 8 weeks after the examination, candidates will receive score reports. These reports will contain the date of the test administration, the title of the examination, the candidate’s name and address, the candidate’s identification number, the candidate’s total score, and the candidate’s subscores on each of the content areas covered in the test. Should you pass the exam, you will receive a wallet card and certificate approximately 6 weeks after notification of your score. Please do not call API for test results; these results will not be given over the telephone.
SPECIAL ACCOMMODATIONS Candidates with special needs may request special testing arrangements by submitting, with their application; (a) a letter describing the basis for the need, such as a physical disability or cognitive impairment; (b) a detailed description of the type of accommodation, such as large print or extended time; and (c) written verification of the need, such as a letter or report from a licensed health professional. The request and its accompanying documentation should be sent to API with the application. There is no additional charge for special accommodations. NOTES ON ROUNDING IN MATHEMATIC EQUATIONS API has not published a policy on rounding (either up or down) when calculations are performed as part of the examination, although they have been asked to publish this policy. The calculation answers are normally far enough apart so that rounding does not usually present a problem. However, we can only instruct based on (historically) what has worked best (so far). This is the rounding policy that will be used during this course (but may be modified on the exam by API): 1.)
Thickness Calculations: Round to the third decimal place, and don’t round-up/down. Example #1 - “.0075” - is “.007” - (same as on test) Example #2 - “.0993” - is “.099” - (may be shown as “0.100” on test) Example #3 - “.9998” - is “.999” - (may be shown as “1.00” on test)
2.)
Pressure Calculations: Round to whole single digit as psi: Example #1 - “239.3 psi” - is “239 psi” (same as test) Example #2 - “1007.9 psi” - is “1007 psi” - (may be shown as “1008 psi” on test) Example #3 - “999.99 psi” - is “999 psi” - (may be shown as “1,000 psi” on test)
3.)
Square Root - Do not round any number under a square root. Simply hit the square root button
(
)
on the calculator and utilize that full number.
REMEMBER: API may round up on their answer, but the detractors will (usually) be far enough apart from the right answer so as not to pose a problem!
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ASME API HISTORY & INTERRELATIONSHIPS
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AMERICAN SOCIETY OF MECHANICAL ENGINEERS (ASME) HISTORY OF THE ASME CODES •
1907
First legal code for Construction of Steam Boilers - Commonwealth of Massachusetts
•
1911
ASME established a committee to formulate standard specifications for the Construction of Steam Boilers and other Pressure Vessels
•
1914
First ASME B&PV Code - Section I (Power Boilers)
•
1921 Section III
Boilers for Locomotives (in 1962 this section was integrated into Section I and Section III designation was later assigned Nuclear Vessels).
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1922 Section V
Miniature Boilers (Section V, Miniature Boilers, was included in Section I in the 1962 edition and later assigned Non-destructive Testing).
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1923 Section IV
Low Pressure Heating Boilers
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1924 Section II
Materials (Previously, materials were included as a part of Section I).
•
1925 Section VIII
Unfired Pressure Vessels (In 1968, title was changed to Pressure Vessels).
•
1926 Section VII
Care of Power Boilers
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1937 Section IX
Welding Qualification (Requirements were originally a supplement to Section VIII, but in 1940 Welding Qualifications was published as a separate document).
•
1963 Section III
Nuclear Vessels
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1968 Section VIII Division 2
Alternative Rules for Pressure Vessels
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1969 Section X
Glass Reinforced Plastic Vessels
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1970 Section XI
Rules for Inservice Inspection of Nuclear Power Plant Components
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1971 Section VI
Recommended Rules for Care and Operation of Heating Boilers
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1975 Section III Division 2
Code for Concrete Reactor Vessels and Containments
•
1982 Section XI
The previous text was renumbered Division I. Division II Rules for Inspection and Testing of Components of Gas-Cooled Plants and Division III Rules for Inspection and Testing of Components of Liquid Metal Cooled Plants were added in the winter 1981 Addenda.
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2001 BOILER AND PRESSURE VESSEL CODE Section I
Power Boilers
Section II
Material Specifications Part A – Ferrous Material Part B – Nonferrous Materials Part C – Welding Rods, Electrodes, and Filler Metals Part D – Properties
Section III
General Requirements for Division 1 and Division 2 Division 1 Subsection NCA – General requirements Subsection NB – Class 1 components Subsection NC – Class 2 components Subsection ND – Class 3 components Subsection NE – Class MC components Subsection NF – Component Supports Subsection NG – Component Supports Appendices Division 2 Code for Concrete Reactor Vessels and Containments
Section IV
Heating Boilers
Section V
Nondestructive Examination
Section VI
Recommended Rules for Care and Operation of Heating Boilers
Section VII
Recommended Rules for Care of Power Boilers
Section VIII
Pressure Vessels Division 1 Division 2 – Alternative Rules Division 3 – High Pressure Vessel
Section IX
Welding and Brazing Qualifications
Section X
Fiberglass Reinforced Plastic Pressure Vessels
Section XI
Rules for Inservice Inspections of Nuclear Power Plant Components
Section XII
Transport Tanks
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ASME CODE ADDENDA A. B. C. D. E.
Color coded sheets Additions and revisions to each Section of the Code Published annually Sent out automatically to purchasers of Codes (through ASME) Available in loose format (same as Code)
ASME CODE INTERPRETATIONS A. B. C. D.
Specific answers to specific questions Published twice annually Loose format - sent out automatically (through ASME) Must follow Proposed Question - Proposed Reply format - (yes or no)
ASME CODE CASES A. B. C.
Proposals for new materials, alternatives to Code requirements Issued separately in a Code Case Book - updates sent automatically Code cases can be used by anyone, but (usually) must be shown on the Manufacturer’s Data Report.
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A. P. I. AMERICAN PETROLEUM INSTITUTE
A.
A voluntary organization comprised of petroleum producers, refiners, distributors, and associated equipment manufacturers/suppliers that exists to: •
Promote the petroleum industry
•
Promulgate standards and guidelines relative to the petroleum industry
•
Provide training, education, and dissemination of information
•
Provide certification to those who wish to use the API monogram
B.
API is headquartered in Washington D.C., with regional offices throughout the northern hemisphere.
C.
API 510, 653, and 570 are only three of the various codes, standards, or publications available to the petroleum and chemical industry (hereafter referred to generically as "Users" or "the User". A complete listing of available documents can be ordered through API Publications Department in Washington, D.C.
D.
API also issues interpretations that are published in a book. They are not sent out automatically to book holders.
P.E.S. PROFESSIONAL EXAMINATION SERVICES
A.
An organization that is contracted by API to prepare and promulgate the API certification examinations.
B.
PES coordinates questions from a “panel of content experts” to make up each examination.
C.
PES then grades the exams and provides the results to API. Challenged questions are forwarded back to the Testing Committee for review before final grading.
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INTER-RELATIONSHIPS
ASME
* Publishes Code of construction * Adopted by States, Governments as law * Used as a bsis for repairs, alterations on existing items
PES
API
Publishes Codes for inspection, repairs, alterations on existing equipment
Contracted by API to publish exam and grade results
Adopts ASME Codes through reference as a base standard
Utilizes ASME/API documents as a basis for examination
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Document Relationship.
‘RAGAGEPS’ Recognized And Generally Accepted Good Engineering Practices.
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REVIEW OF API RP 577
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SUBJECT:
API AUTHORIZED PRESSURE VESSEL & PIPING INSPECTOR CERTIFICATION EXAM
LESSON:
REVIEW OF RP 577 WELDING INSPECTION & METALLURGY
OBJECTIVE:
FAMILIARIZE CANDIDATES FOR THE API-510 & API 570 CERTIFICATION WITH RELEVANT REQUIREMENTS OF RP 577 WELDING INSPECTION
REFERENCE:
API RP 577
Module Objective:The API ICP Committee has deemed that inspectors shall demonstrate their knowledge and understanding of the information listed in API Recommended Practice 577.
The aim of this module is to review the text in such a way as to prepare candidates to correctly answer questions posed about topics within the document. This module is not an exhaustive review and great emphasis is placed on students studying and re-studying the document to commit essential information to memory.
Unlike other modules this material is new to the examination so experience on the type of question and answer sets is not available.
Document Status: Last Updated 11 August 2005 – Verified To API RP 577 First Edition
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1.0 SCOPE Provides guidance on welding inspection as encountered with fabrication and repair of refinery and chemical plant equipment and piping. This is not a replacement for training and experience required for a CWI. Does not require all welds to be inspected. Welds selected for inspection, and the appropriate inspection techniques should be determined by the welding inspectors and engineers.
2.0 REFERENCES Refer to the listed referenced publications in Section 2.
3.0 DEFINITIONS Refer to Section 3 for definitions related to this section.
4.0 WELDING INSPECTION 4.1 General Welding inspection is a critical part of an overall weld quality assurance program, including: -Review of specifications -Joint design -Cleaning procedures -Welding procedures -Welder qualifications Welding inspection activities can be separated into three stages. Inspectors should perform specific tasks: 1. Prior to welding 2. during welding 3. upon completion of welding Although it is not usually necessary to inspect every weld. 4.2 Tasks Prior to Welding Many welding problems can be avoided during this stage when it is easier to make changes and corrections. Such tasks may include review of: 4.2.1 Drawings, Codes and Standards 4.2.2 Welding Requirements 4.2.3 Procedures and Qualification Records
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4.2.4 NDE Information 4.2.5 Welding Equipment and Instruments 4.2.6 Heat Treatment and Pressure Testing 4.2.7 Materials 4.2.8 Weld Preparation 4.2.9 Preheat 4.2.10 Welding Consumables
4.3 Tasks During Welding Operations Should include audit parameters to verify the welding is performed to the procedure. Such tasks may include the following: 4.3.1 Quality Assurance 4.3.2 Welding Parameters and Techniques 4.3.3 Weldment Examination
4.4 Tasks Upon Completion of Welding Final tasks upon completion of the weldment and work should include those that assure final weld quality before placing the weldment in service, these include: 4.4.1 Appearance and Finish 4.4.2 NDE Review 4.4.3 Post-weld Heat Treatment 4.4.4 Pressure Testing 4.4.5 Documentation Audit
4.5 Non-Conformances and Defects If defects or non-conformances are identified, they should be brought to the attention of those responsible, or corrected. Defects should be completely removed and re-inspected.
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4.6 NDE Examiner Certification The referencing codes or standards may require the examiner be qualified in accordance with a specific code and certified as meeting the requirements. ASME Section V, Article 1, when specified by the referencing code, requires NDE personnel be qualified with one of the following: • •
ASNT SNT-TC-1A ANSI/ASNT CP-189
These references (SNT-TC-1A or CP-189) provide guidelines for the certification of NDE inspection personnel. They also require the employer to develop and establish a written practice or procedure detailing employer’s requirements for certification of inspection personnel. 4.7 Safety Precautions
5.0 WELDING PROCESSES 5.2 Shielded Metal Arc Welding (SMW) 5.3 Gas Tungsten Arc Welding (GTAW) 5.4 Gas Metal Arc Welding (GMAW) 5.5 Flux Cored Arc Welding (FCAW) 5.6 Submerged Arc Welding (SAW) 5.7 Stud Arc Welding (SW)
6.0 WELDING PROCEDURE Are required for welding fabrication and repair of pressure vessels, piping and tanks. They detail the steps necessary to make a specific weld and generally consists of a written description, details of the weld joint and welding process variables, and test data to demonstrate the procedure produces weldments that meet design requirements. This section reflects criteria described in ASME Section IX. Welding procedures required by ASME Section IX include: • •
A written welding procedure specification (WPS) A procedure qualification record (PQR)
The purpose of the PQR is to establish the properties of the weldment. The purpose of the WPQ (welder performance qualification – detailed in Section 7) is to establish the welder is capable of making a quality weld using the welding procedure. 6.2 Welding Procedure Specification (WPS) 6.3 Procedure Qualification Record (PQR) 6.4 Reviewing a WPS and PQR
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7.0 WELDING MATERIALS 7.1 General Welding materials refers to the many material involved in welding including the base metal, filler, metal, fluxes, and gases, if any. Each of these materials has an impact on the WPS and the weldment properties. 7.2 P-Number Assignment to Base Metals 7.3 F-Number Assignment to Filler Metals 7.4 AWS Classification of Filler Metals 7.5 A-Number 7.6 Filler Metal Selection 7.7 Consumable Storage and handling Welding consumable storage and handling guidelines should be in accordance with the consumable manufacturer’s instructions and guidelines and as given in the AWS A 5.XX series of filler metal specifications. Coatings on low-hydrogen electrodes and stainless steel electrodes are particularly susceptible to moisture pickup. Moisture can be a source of hydrogen.
8.0 WELDER QUALIFICATION 8.1 General Welder performance qualification is to establish the welder’s ability to deposit sound weld metal. 8.2 Welder Performance Qualification (WPQ) 8.3 Reviewing a WPQ
9.0 NON-DESTRUCTIVE EXAMINATION 9.2 Materials Identification 9.3 Visual Examination (VT) 9.3.2 Visual Inspection Tools 9.3.2.1 Optical Aids 9.3.2.2 Mechanical Aids 9.3.2.3 Weld Examination Devices 9.4 Magnetic Particle Examination (MT)
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9.5 Alternating Current Field Measurement (ACFM) The ACFM technique is an electromagnetic non-contacting technique that is able to detect and size surface breaking defects in a range of different materials and through coatings of varying thicknesses. Requires minimal surface preparation. Can be used at elevated temperatures up to 900°F (482°C). Uses a probe similar to an eddy current probe and introduces an alternating current in a think skin near to the surface of any conductor. When a uniform current is introduced into the area that is defect free, the current flows undisturbed. If the areas has a crack, the current flows around the ends and the faces of the crack. A magnetic field is present above the surface associated with this uniform alternating current and will be disturbed if a surface-breaking crack is present. Two components of the magnetic field are measured: BX along the length of the defect, which responds to changes in surface current density and gives an indication of depth when the reduction is the greatest; and BZ, which gives a negative and positive response at either end of the defect. During the application of the ACFM technique actual values of the magnetic field are being measured in real time. These are used with mathematical model look-up tables to eliminate the need for calibration of the ACFM instrument using a calibration piece with artificial defects such as slots. 9.6 Liquid Penetrant Examination (PT) 9.7 Eddy Current Inspection (ET) 9.8 Radiographic Inspection (RT) 9.8.2 Image Quality Indicators (Penetrameters) 9.8.3 Radiographic Film 9.8.4 Radioactive Source Selection 9.8.5 Film Processing 9.8.6 Surface Preparation 9.8.7 Radiographic Identification 9.8.8 Radiographic Techniques 9.8.8.1 Single-wall Technique 9.8.8.2 Single-wall Viewing
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9.8.8.3 Double-wall Technique 9.8.9 Evaluation of Radiographs 9.8.9.1 Facilities for Viewing Radiographs 9.8.9.2 Quality of Radiographs 9.8.9.3 Radiographic Density Exposed film that allows 10% of the incident light to pass through has a 1.0 film density. A film density of 2.0, 3.0, and 4.0 allows 1%, 0.1% and 0.01% of the incident light to pass through respectively. 9.8.9.4 Excessive Backscatter 9.8.9.5 Interpretation 9.8.10 Radiographic Examination Records 9.9 Ultrasonic Inspection (UT) 9.9.1 Ultrasonic Inspection System Calibration 9.9.1.1 Echo Evaluation with DAC 9.9.2 Surface Preparation 9.9.3 Examination Coverage 9.9.4 Straight Beam Examination 9.9.5 Angle Beam Examination 9.9.6 Automated Ultrasonic Testing ((AUT) a. Pulse Echo Raster Scanning b. Pulse Echo Zone Inspection c. Time of Flight Diffraction (TOFD) 9.9.7 Discontinuity Evaluation and Sizing 9.9.7.1 The ID Creeping Wave Method 9.9.7.2 The Tip Diffraction Method 9.9.7.3 The High Angle Longitudinal Method 9.9.7.4 The Bimodal Method
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9.10 Hardness Testing 9.11 Pressure and Leak Testing (LT) 9.12 Weld Inspection Data Recording 9.12.1 Reporting Details 9.12.1.1 General Information 9.12.1.2 Inspection Information 9.12.1.3 Inspection Results 9.12.2 Terminology
10.0 METALLURGY 10.2 The Structure of Metals and Alloys 10.2.1 The Structure of Castings 10.2.2 The Structure of Wrought Materials The vast majority of metallic materials used for the fabrication of refinery and chemical plant equipment are used in the wrought form rather than cast. 10.2.3 Welding Metallurgy 10.3 Physical Properties 10.3.1 Melting Temperature 10.3.2 Thermal Conductivity 10.3.3 Electrical Conductivity 10.3.4 Coefficient of Thermal Expansion 10.3.5 Density 10.4 Mechanical Properties 10.4.1 Tensile and Yield Strength 10.4.2 Ductility 10.4.3 Hardness 10.4.4 Toughness 10.5 Preheating 10.6 Post-Weld Heat Treatment
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10.7 Hardening 10.8 Material Test Reports 10.9 Weldability of Steels 10.9.1 Metallurgy and Weldability 10.9.2 Weldability Testing 10.10 Weldability of High-Alloys 10.10.1 Austenitic Stainless Steels 10.10.2 Nickel Alloys
11.0 REFINERY AND PETROCHEMICAL PLANT WELDING ISSUES 11.1 General 11.2 Hot Tapping and In-Service Welding 11.2.1 Electrode Considerations Hot tap and in-service welding operations should be carried out only with low-hydrogen consumables and electrodes (e.g., E7016, E7018 and E7048). Extra-low-hydrogen consumables such as Exxx-H4 should be used for welding carbon steels with CE greater than 0.43% or where there is potential for hydrogen assisted cracking (HAC) such as cold worked pieces, high strength, and highly constrained areas. Cellulosic type electrodes (e.g., E6010, E6011 or E7010) may be used for root and hot passes. 11.2.2 Flow Rates 11.2.3 Other Considerations 11.2.4 Inspection 11.3 Lack of Fusion with GMAW-S Welding Process
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Closed Book Practice Questions API RP 577 PRACTICE QUESTIONS
1. The level of learning and training offered by RP 577 is __________________. a. b. c. d.
consistent with an AWS CWI the same as required for an AWS CWI not a replacement for AWS CWI training automatically makes one a welding inspector
2. “DCEN” means. a. b. c. d.
direct current, electrode none direct current, electrode negative don’t come easy, Norman direct current, electrode normal
3. Another name or abbreviation for a penetrameter is: a. b. c. d.
O.C.T. D.E.Q. B.E.P. I.Q.I.
4. A theoretical throat dimension is based on the assumption that the root opening is equal to: a. b. c. d.
zero 1/16” 1/8” 1/32” – 1/16”
5. Welding inspection is a critical part of any ____________ program. a. b. c. d.
Quality Assurance Quality Process ISO 9000 ISO 11000
6. Welding inspection can be separated into 3 distinct stages: a. b. c. d.
welding, NDE, hardness testing pre-welding, NDE, heat treatment visual, NDE, RT before welding, during welding, after welding
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7. One of the items that should be checked prior to welding is: a. b. c. d.
confirm NDE examiners qualifications confirm acceptability of heat treatment procedures review WPS, PQR, and WPQ’s All of the above should be checked prior to welding
8. When discovered, welding defects should be: a. b. c. d.
radiographed to determine extent removed and re-inspected shearwave tested evaluated to API 580 acceptance criteria
9. NDE examiners should be qualified to ______ when specified by the referencing code. a. b. c. d.
ASME XII API 570 SNT-TC-1A API 510
10. As a minimum, each Inspector should review the ______________ prior to starting each job. a. b. c. d.
OSHA regulations EPA regulations site safety rules HAZWOPER Guidelines
11. An advantage of SMAW is: a. b. c. d.
equipment is very expensive slag must be removed from weld passes can be used on almost all commonly-used metal or alloy deposition rates are much higher than for other processes
12. GTAW and SMAW can be distinguished from other processes as they are both used with _______. a. b. c. d.
cc power supplies cv power supplies external gas shielding flux cored electrodes
13. When welding aluminum, and magnesium with GTAW, ______ is normally used. a. b. c. d.
DCEN CCPO DCEP AC
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14. GMAW can be used in 3 distinct modes of transfer. The coolest or fastest freezing of these transfers is: a. b. c. d.
spray short circuiting pulse-spray globular
15. A limitation of the FCAW process is: a. b. c. d.
slag removal slower than GTAW or SMAW lower deposition than GTAW lack of fusion problems because of short arcing
16. One of the unusual aspects of SAW is that: a. b. c. d.
it is not an arc welding process it can be automated the arc is not visible during welding a gas is used for shielding
17. The three welding documents required to make a production weld (as required by ASME IX) are: a. b. c. d.
WPS, PQR, WPL PSW, QPR, WPQ WPQ, PQR, WPS POR, PQR, WOR
18. F numbers are assigned to electrodes based on their ______________. a. b. c. d.
alloy chemistry usability characteristics flux coating
19. What type of electrodes should be stored in a heated oven after initial removal from the package? a. b. c. d.
low hydrogen cellulose coated GMAW rod high nickel
20. Slightly damp low hydrogen electrodes should be: a. b. c. d.
discarded rebaked in special ovens used “as is” rebaked in the storage oven
28
21. A welder continuity log should be maintained to allow verification that each welder has utilized each welding process within a _______ period. a. b. c. d.
one yea 3 month 2 year six month
22. Undercut is normally found_______________. a. b. c. d.
in the weld metal in the base metal at the weld interface at the root of the weld, only
23. Weld underbead cracking is normally found _______________________. a. b. c. d.
in the HAZ in the throat of the weld in the weld root in the weld face
24. The best NDE method used to inspect butt joints volumetrically (through the entire weld) would be: a. b. c. d.
PT VT RT LT
25. Hydrogen cracking may occur in all of the following welding processes, except: a. b. c. d.
SMAW FCAW SAW GMAW
26. In austenitic stainless steel, incomplete penetration is normally corrected by: a. b. c. d.
reducing travel speed proper heat input controlling ferrite content all of the above
27. “Optical aids” include which of the following: a. b. c. d.
levels thickness gauge mirrors fillet weld gauge
29
28. A typical fillet weld gauge would include which of the following: a. b. c. d.
skew-T Bridge Cam Hi-Lo Vernier Caliper
29. ACFM is an NDE technique that is applied to detect: a. b. c. d.
sub-surface indications, in carbon steel surface and sub-surface indications in stainless steel surface indications in carbon, alloy and stainless steel surface indications in carbon steel only
30. One of the best features of ACFM is that it: a. b. c. d.
requires not calibration standards does not require a skilled operator requires no electricity is a low temperature technique
31. Eddy Current (ET) has limited use in welding inspection, but is often used in____________. a. b. c. d.
heavy wall volumetric testing coating thickness measurement measuring cladding thickness both b and c, above
32. The NDE Examiner that performs the radiographic film interpretation should be qualified, as a minimum, to a _____. a. b. c. d.
ASNT Level I ASNT Level II ASNT Level III ASNT Level IV
33. Cobalt is normally used for radiographing thicknesses of _________. a. b. c. d.
0.25” – 3.0” 1.5” – 7.0” 8.0” – 10.0” 0.50” – 2.0”
34. A film density of 1.0 will allow _______% of light through to the film. a. b. c. d.
1% 10% 0.01% 0.001%
30
35. Ultrasonic examination that shows a plan view of the test object would be _____________. a. b. c. d.
A-scan B-scan C-scan D-scan
36. Each pass of the UT transducer should overlap the previous pass by _____% of the transducer dimension. a. b. c. d.
1% 5% 10% 15%
37. Because of the similarities in the shape of the grains and cooling characteristics, a weld can be considered to be a small_______________. a. b. c. d.
casting forging extrusion ingot
38. A defect is also considered to be a (an): a. b. c. d.
imperfection rejectable flaw acceptable flaw non-relevant indication
39. The vast majority of metallic materials used in refineries or chemical plants are ___________. a. b. c. d.
cast materials killed materials stainless steel materials wrought materials
40. Hydrogen in welding may come from various sources, such as: a. b. c. d.
lubricants moisture net electrodes all of the above
41. Materials with high thermal conductivity will require ___________________. a. b. c. d.
higher heat input to weld lower heat input to weld preheating post-weld heating
31
42. Metals with a high coefficient of thermal expansion are more susceptible to: a. b. c. d.
transverse cracking lack of fusion warpage and distortion linear porosity
43. The three hardness tests normally used are the: a. b. c. d.
Schindler, Johnson, Williams Rockwell, Vickes, Brinell Rockwell, UT, Shearwave Brinell, Vicky, Rockdale
44. In Rockwell hardness testing, the minor load is always____________________ a. b. c. d.
10 psi 150 psi 150 kg 10 kg
45. One of the most common types of fracture toughness tests is the _________ test. a. b. c. d.
Rockwell Tensile Charpy Stress-strain
46. How does preheating carbon steel tend to reduce hydrogen-induced delayed cracking? a. b. c. d.
eliminates SCC prevents carbon migration slows the cooling rate – prevents martensite formation makes the grains grow so they won’t crack
47. Preheat is usually monitored by________________ a. b. c. d.
thermocouples crayons contact pyrometer any or all of the above
48. The primary reason for PWHT is: a. b. c. d.
relieve residual stresses complete phase transformations de-sensitize steel drive off excess moisture
32
49. Hardness and hardenability are two terms that: a. b. c. d.
mean the same thing indicate the carbon content of a material mean two different properties indicate the alloying content of a material
50. A typical test for hardenability is the ___________. a. b. c. d.
bend test Rockwell test Jominy Bar test Charpy V-notch test
51. The general Brinell Hardness limit for 5CR-Mo steels is: a. b. c. d.
200 225 241 250
52. Which of the following elements influences the mechanical properties of weldments more than any other? a. b. c. d.
carbon silicon nitrogen nickel
53. OPEN BOOK QUESTION: A material Test Report shows the following chemistries: carbon – 0.15% manganese – 0.20% nickel – 0.35%
chrome – 1.25% molybdenum – 1.00% copper – 0.01%
vanadium – 0.02% silicon – 0.53%
What is the approximate CE of this material using the formula supplied in RP 577? a. b. c. d.
0.35 0.7 0.9 0.55
54. From the above CE number, what should typically be done after welding this steel? a. b. c. d.
no PWHT preheating PWHT preheat and PWHT
33
55. A very specialized external loading weld test is the _________ test. a. b. c. d.
bend Schindlerini gleeble rrc
56. Austenitic stainless steels typically contain chrome and nickel, and are used for: a. b. c. d.
corrosion resistance resistance to high temperature degradation sulfur resistance both a and b, above
57. The most common measure of weldability and hot cracking of stainless steel is the _________. a. b. c. d.
bend test ferrite number Charpy V-notch number hydrogen number
58. An extra-low hydrogen electrode (H4) should be used when hot tapping carbon steels with a CE greater than _____________(%) a. b. c. d.
0.50 0.43 0.25 0.35
59. To reduce burn-through potential, liquid flow rates should be between _________ and _________ when hot-tapping. a. b. c. d.
0.4 – 1.3 m/sec 1.5 – 4.0 ft/sec 0.4 – 1.2 m/sec 40 – 70 ft/sec
60. A common weld defect encountered with the GMAW-S welding process is: a. b. c. d.
LOP slag LOF cracking
34
ANSWER SHEET FOR API RP 577 PRACTICE QUESTIONS
1. c, Para. 1
31. d, 9.7
2. b, 3.17
32. b, 9.8.1
3. d, 3.33
33. b, 9.8.4
4. a, 3.58
34. b, 9.8.9.3
5. a, 4.1
35. c, 9.9
6. d, 4.1
36. c, 9.9.3
7. d, 4.2
37. a, 10.2
8. b, 4.5
38. b, Table 10
9. c, 4.6
39. d, 10.2.2
10. c, 4.7
40. d, 10.2.3
11. c, 5.2.2
41. a, 10.3.2
12. a, 5.2 and 5.3
42. c, 10.3.4
13. d, 5.3
43. b, 10.4.3
14. b, 5.4.1
44. d, 10.4.3
15. a, 5.5.2
45. c, 10.4.4
16. c, 5.6.2
46. c, 10.5
17. c, 6.1
47. d, 10.5
18. c, 7.3
48. a, 10.6
19. a, 7.7
49. c, 10.7
20. b, 7.7
50. c, 10.7
21. d, 8.2
51. c, 10.7
22. c, Table 2
52. a, 10.9.1
23. a, Table 2
53. b, Calculated 0.68 10.9.1
24. c, Table 4 – 5
54. d, 10.9.1
25. d, Table 6
55. a, Table 12
26. b, Table 6
56. d, 10.10.1
27. c, 9.3.2.1
57. b, 10.10.1
28. a, 9.3.2.3
58. b, 11.2.1
29. c, 9.5
59. c, 11.2.2
30. a, 9.5
60. c, 11.3
35
ASME SECTION IX
36
SUBJECT:
API AUTHORIZED PRESSURE VESSEL INSPECTOR CERTIFICATION EXAMINATION
LESSON:
INTRODUCTION
OBJECTIVE:
FAMILIARIZE 510 CANDIDATES WITH WELDING INFORMATION IN ASME SECTION IX IN WHICH THEY MUST BE KNOWLEDGEABLE
REFERENCES: ASME SECTION IX WELDING QUALIFICATION CODE
Module Objective:Currently most Pressure Vessels are made from a welded construction. The relevant design code ASME VIII whilst having specific welding requirements in general defers all welding, welder and welding operator qualification rules to the ASME Section IX document. The API Body Of Knowledge recognizes this and ASME IX is certain to appear on your exam and the open book part has always had a WPS & PQR with questions for candidates to review. This module is intended to provide you with a clear understanding of how to utilize the ASME Section IX document.
Foreword A section no one ever reads but does contain important information. Most significantly is when an edition of the codes becomes applicable. In general applicability occurs 6 months after date of issue except for Material Specifications where additional guidance may apply due to the interrelationship with ASTM. There are other useful pieces of guidance on tolerances and how and when to use metric versus US units. Stresses that converting between the two needs care.
37
INTRODUCTION Section IX relates to the qualification of: •
Welders
•
Welding Operators
•
Brazers
•
Brazing Operators
•
Welding/Brazing Procedures
who are employed in welding or brazing in accordance with the: •
ASME Boiler and Pressure Vessel Code and
•
ASME Piping Codes
PURPOSE The Welding Procedure Specification (WPS) and the Procedure Qualification Record (PQR) are used to determine that the weldment proposed for construction is capable of having the required properties. The procedure qualification test is to establish the properties of the weldment/brazement, NOT the skill of the welder /brazer.
ORGANIZATION Section IX is divided into two parts: •
Welding, Identified as QW
•
Brazing, identified as QB
These two parts are further divided into four Articles: •
General Requirements
•
Procedure Qualification
•
Performance Qualification
•
Data
38
PROCEDURE QUALIFICATION Each process is listed separately with the applicable essential and non-essential variables •
Change in an ESSENTIAL variable requires requalification
•
Change in a NON-ESSENTIAL variable requires a revision to WPS/BPS
•
Change in a SUPPLEMENTARY ESSENTIAL variable requires requalification
ADDITIONAL RULES In addition to covering various joining processes, rules also exist for special processes: •
Corrosion Resistance Weld Metal Overlay
•
Hard-Facing Weld Metal Overlay
•
Standard Welding procedure Specifications
•
Temper Bead Welding (New In 2004)
PERFORMANCE QUALIFICATION Each process is listed separately with the applicable essential variables •
Welder/Welding Operator can be qualified by: • • •
•
Mechanical Tests Radiography of the Test Plate/pipe Radiography of Initial Production Weld
Brazer/Brazing Operators CANNOT be qualified by radiography
39
ARTICLE I WELDING GENERAL REQUIREMENTS QW-100.1
A WPS is a written document that provides direction to the welder or operator for making production welds. The WPS must be qualified by the manufacturer or it shall be a Standard Welding Procedure Specification (SWPS) listed in Appendix E.
QW-100.2
The purpose of the performance test for a welder is to determine her ability to deposit sound weld metal. The purpose of the operator’s test is to determine her ability to operate the equipment.
QW-100.3
WPS, PQR, and Records of Performance Qualification can be used for construction built according to either the • •
ASME Boiler and Pressure Vessel Code -- or the -B31 Code for Pressure Piping
Providing it meets the requirements of either the • 1962, or later, editions of Section IX • Pre-1962 Edition of Section IX meeting ALL requirements of 1962, or later, editions Qualification/requalification of WPS MUST conform with the current Edition and Addenda of Section IX Scope
Rules in this section apply to
QW-101
Responsibility QW-103
•
preparation of WPS
•
qualification of welding procedures, welders, and welding operator for ALL manual/machine welding processes permitted in other sections
Manufacturer/contractor is responsible for welding •
MUST conduct tests to qualify Welding Procedure and Welders/Welders Operators Test results MUST be kept by manufacturer/contractor
•
MUST be certified by Manufacturer/contractor
Types and Purpose of Tests and Examinations QW-140
40
Mechanical Tests QW-141 Tension Tests QW-141.1
Determine the ultimate strength of groove-weld joints
Guided-Bend Tests QW-141.2
Determine the degree of soundness and ductility of groove-weld joints
Fillet-Weld Tests QW-141.3
Determine the size, contour, and degree of soundness of fillet welds
Notch-Toughness Tests QW-141.4
Determine the notch toughness of the weldment
Stud-Weld Tests QW-141.5
Determine the acceptability of stud welds
Tension Test QW-150
To determine the ultimate strength of a joint, expose sample to stress levels exceeding stated limitations
Tension Test Procedure QW-152
Sample shall be ruptured under tensile load •
Calculation:
Maximum Load Tensile Strength = Minimum Cross - Sectional Area
- Measurements MUST be taken before load is applied
41
5” SCHEDULE 80 3/8” SA-106 GR B W
t
A
LOAD
5
0.695
0.249
0.173
11,000
6
0.785
0.220
0.173
9,878
42
63,583
57,098
PSI
loc.
WM
BM
Acceptabl e Ref. QW153.1(d) Acceptabl e Ref. QW153.1(d)
Acceptance CriteriaTension Tests QW-153 Tensile Strength QW-153.1
Minimum tensile strength requirements: •
Stated base metal limitation, or
•
Stated base metal limitation of WEAKEST specimen when two different strength levels are present, or
•
Stated weld metal limitation when the applicable Section requires use of weld metal with a lower room temperature strength than the base metal
•
Strength is NOT MORE than 5% below the stated base metal limitation IF the specimen breaks outside the Fusion Zone and weld in the base material
Exercise Caution about notes at the bottom of 451.1. They relate to when you can use multiple specimens in lieu of a single specimen. They love to pose questions to see if you understand these rules. It can only be applied once the base metal is over 1.0” thick. Over being the critical word. These two specimens represent one specimen. Another set of two is needed to meet Procedure Qualifications Requirements.
43
2” SA-537 CLASS 2 (MIN. SPECIFIED TENSILE = 80,000) W t A 1b 1a 1.500 0.984 1.446 116,000
PSI 80,220
loc. WM
1b
1.490
0.997
1.486
114,000
76,720
PM
2a
1.197
0.950
1.137
91,200
80,000
WM
2b
1.250
0.981
1.226
98,000
79,934
WM
Acceptable Ref. QW153.1(a) Acceptable Ref. QW153.1(a) Acceptable Ref. QW153.1(a) Unacceptable Ref. QW153.1(a)
NOTE: Full set unacceptable because of 2b. Reference QW-151.1(c) SPECIAL NOTE: The math is incorrect on 1a. The area is 1.476 which makes the PSI 78,590 which is unacceptable. Reference QW-153.1 The alternative to a standard reduced section tensile is:
TENSILE TEST “TURNED SPECIMENS” “0.505”
44
EXAMPLE: Base Metal Tensile Strength = 75,000 NOTE: EACH PROCESS OR PROCEDURE SHALL BE INCLUDED IN THE TENSION, BEND OR IMPACT TEST SPECIMEN. REF. QW-200.4(a)
W 1 2
t 0.511D 0.501D
A 0.205 0.197
LOAD 15,570 14,520
PSI 75,950 73,750
Loc. BM WM
Results Fail* Fail**
NOTE: Turned Specimens(QW-151.3) *REF. QW-462.1(d)
**Ref. QW-153.1(a)
D = 0.500 + 0.010 In.
Guided Bend Tests QW-160
Using a test jig, bend the sample into a "U" shape
Types of Guided Bend Tests QW-161 Transverse Side Bend Weld is transverse to the longitudinal axis of the specimen QW-161.1 Side surface of the weld becomes the convex surface of the specimen Transverse Face Bend
Weld is transverse to the longitudinal axis of the specimen
QW 161.2
Face surface of the weld becomes the convex surface of the specimen
Transverse Root Bend QW-161.3
Weld is transverse to the longitudinal axis of the specimen Root surface of the weld becomes the convex surface of the specimen Longitudinal Face Bend Weld is parallel to the longitudinal axis of the Specimen
45
QW-462.2 SIDE BEND SIDE BENDS EXPOSE THE FULL CROSS SECTION OF THE WELD TO THE 180° BEND VERSUS THE FACE OR ROOT BENDS.
QW-161.6
Face surface of the weld becomes the convex surface of the specimen
Longitudinal Root Bend QW-161.7
Weld is parallel to the longitudinal axis of the specimen
Acceptance Criteria QW-163
Weld and heat affected zone SHALL BE ENTIRELY within the bent area of the specimen
Root surface of the weld becomes the convex surface of the specimen
Specimen MUST NOT have any defects greater than 1/8 inch •
Measurements taken anywhere on rounded surface
•
Corner cracks discounted unless evidence of internal defects are present
Corrosion Resistant Weld Overlay Cladding requirements: •
No defects greater than 1/16 inch (cladding)
•
No defects greater than 1/8 inch (approximate weld interface)
46
Notch Toughness Tests QW-170
When required by the Code, one of the following tests MUST be conducted: •
Charpy V-notch
•
Drop Weight Impact
Other Tests and Examinations QW-190
Visual examination of welder/operator qualification test is required
Radiographic Examination QW-191
May be substituted for mechanical testing for welders/welding operators
MUST meet requirements of Article 2, Section V – Except that a written RT procedure is not required. MUST meet acceptance criteria of QW-191.2 QW191.2.3
Acceptance standards for operators that qualify on production welds shall be the referencing code section. The acceptance standard for welders on production welds shall be QW 191.2.2.
ARTICLE II WELDING PROCEDURE QUALIFICATIONS General QW-200 Welding Procedure Specification (WPS) QW-200.1
Written directions for the welder/welding operator making production welds describing all variables involved •
ESSENTIAL VARIABLE Welding specification change affecting mechanical properties of the weldment Requires specification requalification
•
SUPPLEMENTARY ESSENTIAL VARIABLE Welding specification change affecting notch toughness properties of the weldment Requires specification requalification
•
NON-ESSENTIAL VARIABLE Welding specification change NOT affecting the mechanical or notch toughness properties of the weldment. Requalification NOT required providing WPS is amended Essential variable for one process may be non-essential for another or may not be required at all for a third process
47
Non-essential variables can be changed without requalification •
Procedure Qualification QW-200.2
Change MUST be documented by variable on either a new, or amended original, WPS
Tests to determine that the weld can provide the required (PQR) properties for the intended application All variables of the WPS MUST be followed Base metal of the specimen can be in any form •
Procedure qualification transferable between plate and pipe welding
PQR components: •
All essential and supplementary essential variables used during test coupon welding MUST be recorded
•
Any non-essential or other variables can be recorded at a later date
•
Any variables recorded MUST be the actual variable
•
Variables not monitored MUST NOT be recorded
•
If more than one process/filler metal is employed, RECORD the approximate deposit weld thickness of each
Changes:
Multiple WPS's with One PQR/Multiple PQR's with one
•
NOT allowed except as an editorial or addenda
•
REQUIRES recertification
Several WPS's may be prepared from data on one PQR One WPS may cover numerous essential variable changes providing a PQR WPS exists for all essential and supplementary essential variables
QW-200.4
Combination welding procedures (more than one process) are allowed; However ALL variables and ranges for each process shall be applied and identified. Note restriction on GMAW -SC arc.
QW-201
Manufacturers/Contractors responsibility to conduct tests, document results, and maintain records. NOT permissible to sub-contract welding of coupons, but all other work in preparing coupons and testing can be subcontracted.
QW-202.1
This sends you to QW-451 for type and number of tests required. This is one of the most important pages to mark or tab for the examination. We assure you that you will turn to this page on numerous occasions,
48
QW 252 -
Variable Tables Per Process These tables are very important and should be treated as your ‘road map’ to the use of ASME IX. Understand these and use them as your starting point and the document becomes relatively easy. Fail to understand these and you will be lost. We will conduct a detailed exercise on these tables and their application.
QW 290 -
This is a whole new section on TEMPER BEAD WELDING added in the 2004 edition. Temper bead welding gained prominence as a way of avoiding post weld heat treatment in repairs to low P No steels. This paragraph is only permitted when the referencing code allows it so be careful.
QW 290.1 -
You need to qualify you need to qualify a WPS and PQR.
QW 290.2 -
Limits the welding processes for temper bead welding, SMAW, GTAW, SAW, GMAW (FCAW) and PAW. However manual and semi automatic GMAW and PAW are prohibited except for root pass made from one side.
QW 290.3 -
List variables for this technique and references Table QW 290.4. This introduces the concept of hardness test variables.
QW 290.5 -
Details how to prepare test coupons.Very detailed procedure on how and where to make hardness measurements.
QW 290.6 -
In process repair welding. I.e. when a construction mistake is made this is how to rectify it. Special rules.
49
ARTICLE III WELDING PERFORMANCE QUALIFICATIONS
General QW-300 QW-300.1
Welder qualification is limited by the essential variables given for each process Welder/welding operator can be qualified by: •
Radiography of test coupon
•
Radiography of initial production welding
•
Bend tests taken from test coupon
Visual examination of all tests is required QW-300.2
Manufacturer/contractor MUST conduct tests to qualify welders/welding operators in accordance with a qualified WPS •
This is to ensure that welders /welding operators can develop the minimum requirements specified for an acceptable weldment
QW-301.1
Intent of Tests. Determine the ability of the welders/welding operators to make sound welds
QW-301.2
Qualification of Tests Performance qualification tests MUST be welded in accordance with qualified WPS Welder/Welding operator who prepares the WPS qualification test coupon is also qualified within the performance qualification range of the performance variables.
QW-301.3 Welders/Welding Operators
Must be assigned an individual identifying: • number, -- or -• symbol ALL work must be identified in this manner
Record of Tests QW-301.4
WPQ record MUST include: • Essential variables • Type of test • Test results • Qualified range of welder/welding operator
50
Welders QW-304
Use form QW-484 or equivalent Welders MUST pass the mechanical test prescribed in QW-302.1 •
Exception: special requirements
Welder making groove-welds using •
SMAW
•
SAW
•
GTAW
•
PAW
•
GMAW (except short-circuiting mode)
•
Or a combination of these
Can be qualified by radiographic examination - - Exception: P-21 - 25, P-51 - 53 and P-61 - 62 metals Welders making groove-welds in P-21 - 25 and P-51 - 53 metals using GTAW process may be qualified by radiographic examination Welders qualified with one WPS are likewise qualified with another WPS providing the same welding process is used within the applicable range of essential variables Examination QW-304.1
Shall be examined by either: •
Mechanical Tests (QW-302.1) - - or - -
•
Failure to Meet Radiographic Standards QW-304.2
Radiography (QW-302.2)
If the production weld selected for welder performance qualification DOES NOT meet the radiographic standards the welder has FAILED
If the entire production weld had been made by this welder, it MUST be radiographed and repaired by a qualified welder/welding operator Welding Operators QW-305
Same as QW-304
Examination QW-305.1
Same as QW-304.1 • Exception: for the production weld being radiographed, a three foot length MUST be examined
51
Failure to Meet Radiographic Standards QW-305.2 Combination of Welding Processes QW-306
Same as QW-304.2
Welder MUST be qualified for the welding process(es) used in production Welder can be qualified by making tests with the •
Individual welding process - - or - -
•
combination of welding processes in one test coupon(s)
Thickness limits of which the welder will be qualified depend upon the Thickness of the deposited weld metal of each welding process Failure of ANY portion of a combination test in a test coupon fails the entire combination Retests and Renewal of Qualifications QW-320 Retests QW-321
Welder/welding operator can be retested per the conditions of • QW-321.1 • QW-321.2
Immediate Retest QW-321.1
MUST make two consecutive test coupons for each Mechanical Testing position failed-All coupons must pass the required tests
Immediate Retest Using Radiography QW-321.2
Retest must be two 6 inch plate coupons or Pipe: • Two pipes, totaling 12 inches of welds, that MUST include the entire weld circumference Small Diameter Pipe: • Perform no more than eight consecutively made test coupons Production Welds: • Can be retested by an additional 12 inch length of the SAME weld - - If length PASSES, the welder is qualified - - If length FAILS, all production welds must be completely radiographed and repaired A welding operator who has failed can retest by submitting an additional six Foot length of the same production weld - - If length PASSES, the welding operator is qualified - - If length FAILS, all production welds must be completely radiographed and repaired
52
Renewal of Qualification QW-322
Welder/welding operator performance qualifications will be affected by these conditions • Not welding with a specific process during six month or greater period of time: - - Qualifications for that process have expired • Specific reason to doubt that the welds meet required specifications: - - Qualifications for those processes MUST be revoked When qualifications have expired it can be renewed by welding one test coupon and testing it as specified in QW-301 and QW-302 for each process qualified. •
Test coupon can be of either plate or pipe, of any material, thickness, or diameter, and in any position
•
This process renews the welder/welding operator's previous qualifications
When qualifications have been revoked a welder/welding operator can be requalified by welding and testing a test coupon representative of the work that person will be doing • •
Test MUST be in accordance with QW-301 and QW-302. Test MUST be completed prior to performing any work
Table QW-352-357
Variable tables for WELDERS - all essential variables
QW-360
Variables for machine/automatic OPERATORS -all essential variables
QW-380
Special process requirements for welders/operators - includes corrosionresistant weld metal overlay and hard facing weld metal overlay
53
ARTICLE IV WELDING DATA This Article contains many - Tables, Graphs, and other mandatory information that is referenced throughout Articles I, II, and III. Many of the Tables (such as QW 451.1, QW 452.1(a) and 452.1(b)) will be used to determine the allowable ranges for the WPS or WPQ, such as: • • • • • • •
Allowable Base Metal Ranges for WPS (QW 451.1) Allowable Deposited Weld Metal Ranges for WPS (QW 451.1) Allowable Deposited Weld Metal Ranges for Welders (QW 452.1(b)) Allowable Pipe Diameter Qualification Ranges for Welders (QW 452.3) Allowable Position Qualifications for Welders (QW 461.7) Allowable P# Qualification ranges for Welders and WPS (QW 423 and 424, respectively) The candidate must become familiar with the Tables, and know where to go to obtain the correct information. After several practice sessions these Tables become quite easy to master, and can be accessed rather quickly.
ARTICLE V STANDARD WELDING PROCEDURE SPECIFICATIONS (SWPS) QW-510
The SWP’s listed in Appendix E (approximately 17) are only allowed. Prior to use a laundry list of items must be completed by the user of the SWPs, including the following: a. Enter the name of the user (manufacturer); b. The SWPs must be certified; c. The applicable referencing code sections must be met; d. The user (manufacturer) must weld and test one groove weld using the SWPS and record 15 items. Then the coupon must be visually examined and bend tested or RT’d.
QW-520
Once the above coupon passes all similar SWP’s may be used without the demonstration in (d), above. The list of changes that will require additional discreet demonstrations are listed in this paragraph.
QW-540
All production welding must be done in strict accordance to the SWP’s, other rules for utilizing SWP’s are provided in the paragraph.
Document Status: Last Updated Jan 27 2006 Reviewed To ASME Section IX 2004 Edition
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Closed Book Practice Questions ASME SECTION IX PRACTICE QUESTIONS
1. The purpose of the WPS and PQR is to determine that: A. the welder is qualified B. the base metals are strong enough C. the weldment has the desired properties D. the skill of the welder 2. The WPS lists: A. nonessential variables B. essential variables C. ranges for 1 & 2 above D. all of the above 3. The PQR must list: A. essential variables B. qualification test & examination results C. supplementary essential variables (when notch toughness is required) D. all of the above 4. What is the earliest Edition of Section IX recognized by the current edition? A. 1958 B. 1992 C. 1987 D. 1962 5. New Welding Procedure Specifications must meet the ______________ Edition and Addenda of Section IX. A.1962 B. current C. 1986 D. 1995
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6. Each _________________ shall conduct the tests required by Section IX to qualify the WPS's used during the construction, alteration, or repair. A. Welder or welding operator B. Manufacturer or contractor C. Inspector D. All of the above 7. The records of procedure, welder and welding operator qualification must be available to the _______________ . A. Manufacturer B. Welder C. Authorized Inspector D. Foreman 8. A welder qualifying with a groove weld in plate in the 4G position is qualified to weld groove welds in plate and pipe over 24"O.D. in at least the _________ positions. A. Vertical B. Flat & horizontal C. Flat & overhead D. Horizontal 9. A welder qualifying with plate fillet welds in the 3F and 4F positions is qualified to weld groove welds in plate in the _______________ positions. A. Flat only B. Flat and horizontal C. Flat and vertical D. None of the above 10. A welder qualifying by making a groove weld on pipe with an O.D. of 3/4" in the 5G position is qualified to weld groove welds in: A. 1/2" O.D. Pipe in the overhead position B. 6" O.D. Pipe in the vertical position C. 3/4" O.D. pipe in the horizontal position D. None of the above 11. In general, qualification on groove welds also qualifies a welder to make: A. Stud welds B. Overhand welds C. Fillet welds D. All of the above 12. Charpy V-notch tests are performed to determine a weldment's A. Tensile strength B. Ductility C. Notch toughness D. All of above
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13. A welder making a groove weld using the SAW process on P1 materials may be qualified using radiography. A. True B. False 14. When a tensile specimen breaks in the base metal outside of the weld or fusion line, the strength recorded may be at most ___ below the specified tensile and be accepted. A. 3.5% B. .5% C. 5% D. All of the above 15.
Guided-bend specimens shall have no open defects in the weld or heat effected zone exceeding ________________ measured in any direction on the convex surface of the specimen after bending. A. 1/16" B. 3/32" C. 1/8" D. None of the above
16. When using radiographs to qualify welders, the acceptance standards used are found in A. ASME Section V B. ASME Section IX C. ASME Section VIII D. The referencing code 17. A WPS must describe: A. Essential variables B. Nonessential variables C. Supplementary essential variables when required for notch toughness D. All of the above 18. A PQR must describe A. Nonessential variables B. Essential variables C. Results of Welder Qualification tests D. Project description & NDE methods 19. The ______ must certify the PQR as accurate. A. Inspector B. Manufacturer or contractor C. Welder D. All of the above
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20. For the SMAW process ______________ is an essential variable for the WPS. A. Groove design B. Post Weld Heat Treatment C. Root spacing D. Method of cleaning
21. For the SAW process _____________ is an essential variable for the WPS. A. Supplemental powdered filler metal (if used) B. Filler metal diameter C. Preheat maintenance D. Addition or deletion of peening 22. The basic purpose of testing a welder is to establish the welder's ______________. A. Knowledge of welding requirements B. Ability to deposit sound weld metal C. mechanical ability to operate equipment D. General attitude toward welding inspectors 23. The record of a welder's performance test is called a ______________. A. PQR B. WQR C. WPS D. WPQ 24. If a welder qualified with the SMAW process on Jan. 1, 1994 and last welded with SMAW on March 15, 1994, would he still be qualified on October 7, 1994? A. Yes B. No 25. A welder qualifying with a groove weld welded from both sides is qualified to weld ________. A. Without backing B. With all base metals C. With backing only D. With P1 backing only 26. Immediate retests of welders qualifications coupons A. Must use the same method B. May use any method C. Are not allowed D. Require Inspector approval
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27. Welder performance qualification records must describe all the _____________ variables specified. A. Essential & nonessential B. Nonessential C. Essential D. Brazing 28. A welder depositing 1/2" of weld metal in a groove weld using 3 layers of weld metal with the SMAW process is qualified to deposit _________ of weld metal. A. 8" maximum B. an unlimited amount C. 1" maximum D. 1/2" maximum 29. "P" numbers are used to designate groups of A. Electrodes B. Flux C. Base metals D. Joints 30. A welder qualifying by welding P-No. 21 to P-No. 21 is qualified to weld A. P-1 - P-11 to P-1 - P-11 B. P-8 - P8 C. P-21 - P-25 to P-21 - P-25 D. P21 to P21 only 31. Welding electrodes are grouped in Section IX by A. AWS class B. ASME specification C. SFA D. "F" number 32. Ferrous weld metal chemical composition may be designated using A. "P" number B. Welder I.D. C. "A" number D. page number 33. For welder qualification with the SMAW process ________________ is an essential variable. A. Base metal thickness B. Peening C. P-number D. Electrode diameter
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34. Each welder must be assigned a(n) A. P number B. Unique identifier C. Hood & gloves D. Inspector 35. May a welder who qualified in the 2G position on 1/4 inch thick plate, weld a 1 inch outside diameter groove weld in pipe, 1/4 inch thick in the horizontal position without requalification? A. B. C. D.
Yes No Not enough information provided Yes, provided pipe is carbon steel, P#1
36. What is the basic difference between gas metal arc welding and gas tungsten arc welding processes? A. B. C. D.
GMAW uses a continuously fed filler metal and GTAW a tungsten electrode The SFA specification of the filler metal The F# of the filler metal GTAW is run with gas; gas is optional with GMAW
37. A welder has been tested in the 6-G position, using an E-7018 F-4 electrode, on 6” sch 160 (.718” nom) SA 106B pipe. Is this welder qualified to weld a 2” 300# ANSI schedule 80 bore flange to a 2” schedule 80 SA 106 B nozzle neck? A. B. C. D.
Yes No Not enough information provided Yes, provided a backing strip is provided in the 2” weld.
38. May a welder who is qualified using a double-groove weld, make a single V-groove weld without backing? A. B. C. D.
Yes No Not enough information provided Yes, because backing is not an essential variable for a welder
39. May a GTAW welder be qualified by radiography, in lieu of bend tests? The test coupon will be P-22 material and the production welds will be P-22 also. A. B. C. D.
Yes No Not enough information provided Yes, provided the P-22 is welded with F-22 fillers
40. Who is responsible for qualification of welding procedures, welders and welding operators? A. B. C. D.
The Inspector The A.I. The Shop Foreman The Manufacturer of Contractor
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41. A welding electrode has the marking E-6010. The “1” marking indicates: A. B. C. D.
Flat position only Horizontal position only All positions Only good for heat treated welds
42. May a FCAW welder, qualified using UT, be used to weld in production? A. B. C. D.
Yes, welder can be used No welder cannot be used Yes, if welder is using GMAW (Short Arc) Yes, if welder is qualified with backing
43. A welder may deviate from the parameters specified in a WPS if they are a (True or False)
nonessential variable.
A. True B. False 44. A repair organization has a WPS which states it is qualified for P-8 to P-8 material welded with either E308, E308L, E309, E316, electrodes (SMAW process). The PQR, supporting this WPS, states the weld test coupons were SA-240 Type 304L material, welded with E308 electrodes. Is the WPS properly qualified for the base material listed? A. B. C. D.
Yes No Not enough information given Yes, if properly heat treated
45. What positions are necessary to qualify a welder for all position pipe welding? A. B. C. D.
3G and 4G 2G and 5G 3G and 1G 4G and 5G
46. What ASME Code Section has welding electrode storage requirements? A. B. C. D.
ASME IX ASME VIII ASME B31.1 ASME II Part C
47. What are the number of transverse guided bend tests required for Performance Qualification in a 6G position? A. B. C. D.
2 4 6 3
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48. May a GMAW, short circuit transfer, welding procedure be qualified using real-time ultrasonics? A. B. C. D.
Yes No Not enough information given Yes, provided bend tests are done
49. Three arc welding processes are: A. B. C. D.
BMAW, SMAW, EFGAW FCAW, SAW, ESW SMAW, GTAW, PAW PTAW, SLAW, PEAW
50. You are reviewing a WPQ (QW-484) for a welder testing in the 2-G position; on SA-53 grade B pipe (TS-60,000 psi). The test results indicate the following: #1 #2 #1 #2
Tensile developed 51,000 psi, broke in the weld Tensile developed 56,900 psi, broke in base metal Transverse root bend satisfactory Transverse face bend satisfactory
Will these test qualify the welder? A. B. C. D.
Yes No Not enough information given Tension test is acceptable but #1 is unacceptable
51. Is a welding procedure qualified under the 1965 ASME Code Section IX still applicable? A. B. C. D.
Yes No, must be requalified Is only applicable for 1965 pressure vessels Cannot be used for new construction - repairs only
52. A nonessential variable must be documented on: A. B. C. D.
The WPQ The PQR The WPS All of the above
53. What are the various positions in which a welder may qualify for plate groove welds? A. B. C. D.
1G 3G 4G All of the above
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54. A welder was qualified with a P-1 test coupon using SMAW E7018 electrodes. May the welder weld P-4 material using E8028 electrodes in production? (Assume the P-4 procedure using E8028 electrodes has been qualified.) A. B. C. D.
Yes No Not enough information provided None of the above
55. What are the primary classifications of guided-bend tests permitted by the Code? A. Side and Transverse B. Face and Root C. Transverse and Longitudinal D. Side and Face 56. A welder qualified by welding in the 5G position is qualified for what position on plate? A. B. C. D.
F, H, OH F, V, OH V, OH, SP H, V, OH
57. Which of the following is a covered electrode? A. B. C. D.
E6010 E 7018 E 9028 All of the above
58. Applicable essential variables must be documented on which of the following? A. B. C. D.
The WPS The PQR The WPQ All of the above
59. In performance qualification of pipe welds to ASME Section IX, which positions require more than two guided bend specimens for qualification? A. B. C. D.
5G and 6G 2G and 4F 4G and 5G None of the above
60. Name two defects that would cause visual rejection of a welder’s test pipe or plate? A. B. C. D.
Porosity, underfill Lack of penetration/fusion Slag, overlap Any of the above
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61. A variable that,when changed will cause a change in the mechanical properties of the weldment is called a: A. B. C. D.
Essential variable Non-essential variable Supplementary essential variable All of the above
62. The test that determines the ultimate strength of groove-weld joints is a: A. B. C. D.
Notch Toughness Test Tension Test Fillet Weld Test Guided-Bend Test
63. The procedure qualification test is used to determine: A. B. C. D.
The skill of the welder That the proposed production weldment is capable of having the required properties The corrosion -resistance of the proposed weldment None of the above
64. A change in a supplementary essential variable requires requalification, when notch- toughness is a consideration. True
or
False
(circle one)
65. When using Macro-examination of fillet weld tests, the weld and the HAZ must not reveal cracks when magnified at: A. B. C. D.
5X 2X 10X No magnification is required - visual examination is required, only.
66. A non-essential variable may be changed without re-qualification because: A. B. C. D.
Nobody cares about non-essential variables The welder is allowed to change variables at his discretion Non-essential variables do not affect the mechanical or notch-toughness properties Non-essential variables cannot be changed without re-qualification
67. The data recorded on a PQR (non-editorial) may be changed provided: A. The AI approves B. The test data on a PQR is a record of what occurred and should never be changed. Only editorial information can be changed on a PQR. C. The API 510 Inspector approves D. The date of the WPS is changed
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68. A WPS must only address essential and, if applicable, supplementary essential variables. True
or
False
(circle one)
69. Tension tests may be used in lieu of bend tests to qualify welders or welding operators. True
or
False
(circle one)
70. A groove weld bend test reveals a linear indication on the face of the bend surface that measures exactly 1/8" long. No other indications are seen. Does this coupon pass or fail? A. B.
Pass Fail
71. Unless notch-toughness is a consideration, a qualification in any position qualifies a welding procedure for all positions. True
or
False
(circle one)
72. The purpose of a WPS and PQR is to determine if a welder has the skill necessary to make sound production welds. True
or
False
(circle one)
73. Welders can be qualified by radiograph when using P 6X materials? True
or
False
(circle one)
74. It is permissible to sub-contract welding of coupons as well as other work to prepare coupons. True
Or
False
(circle one)
75. Variable QW 402.4 for SMAW procedure qualification is a _____________variable A. B. C. D.
Essential Non-essential Supplemental essential None of the above
76. Variable QW 404.24 for SAW procedure qualification is an ___________ variable A. B. C. D.
Essential Non-essential Supplemental essential None of the above
77. Each manufacturer must certify the PQR (by signature) indicating that the information given is true and correct. True
Or
False
(circle one)
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78. Welder variable QW- 405.1 (for welders qualifying with the SMAW process) is a _________ variable. A. B. C. D.
Essential Non-essential Supplemental essential None of the above
79. The purpose of a WPS and PQR is to determine if a proposed weldment to be used in construction is capable of providing the required properties for the intended application. True
or
False
(circle one)
80. A qualification in a 4G position qualifies a welder for all groove weld positions. True
or
False
(circle one)
81. A WPS must address all applicable non-essential variables. True
or
False
(circle one)
82. Groove weld coupons shall be tested by macro-examination when qualifying a welding procedure. True
or
False
(circle one)
83. A welding procedure must be qualified with impact tests only when required by the applicable construction code, such as ASME VIII Div. 1. True
or
False
(circle one)
84. A welder qualified to weld in the 2G position on pipe would have to be qualified in which of the additional positions to qualify for all position groove welding on pipe? A. 1G B. 2G C. 5G D. 6G E All of the above 85. The maximum preheat temperature decrease allowed without requalification of a GMAW groove weld procedure is: A. 50°F B. 100°F C. 125°F D. 150°F E. None of the above
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86. A welder is qualified to weld all thicknesses of material when: A. B. C. D. E.
The test is any thickness above 3/8 inch The test thickness was ½ inch or over and a minimum of three passes are run. The test thickness was 3/4 inch or over The test pipe wall thickness was 5/8 inch and nominal pipe size was over ½ inches None of the above
87. What is the maximum defect permitted on the convex surface of a welder qualification bend test after bending , except for corner cracks and corrosion resistant weld overlay? A. B. C. D. E.
1/4 inch 1/8 inch 1/16 inch 3/16 inch No defects are allowed
88. What period of inactivity from a given welding process requires the welder to requalify in that process? A. B. C D. E.
3 months 6 months 9 months 12 months As stated by the AI
89. Notch-toughness requirements are mandatory A. B. C. D. E.
For heat treated metals For quenched and tempered metals For hardened and tempered metals For annealed and tempered metals When specified as required by the referencing Code section
90. A welder qualified for SMAW using an E7018 electrode is also qualified to weld with: A. B. C. D. E.
E7015 E6011 E6010 E7024 All of the above
91. Macro examination of an etched fillet weld section for performance qualification is acceptable if the examination shows: A. Complete fusion and freedom from cracks, excepting linear indications not exceeding 1/32 inch at the root. B. Concavity or convexity no greater than 1/16 inch C. Not more than 1/8 inch difference in leg lengths D. All of the above E. Both B and C above
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92. Each manufacturer or contractor is responsible for the welding or brazing done by his organization. Whenever these words are used in Section IX, they shall include: A. B. C. D. E.
Designer or architect Designer or installer Architect or installer Installer or assembler Assembler or designer
93. For P-11 materials, weld grooves for thicknesses_____________shall be prepared by thermal processes, when such processes are to be employed during fabrication. A. B. C. D. E.
Less than 5/8 inch 5/8 inch 1 inch 1-1/4 inches None of the above
94. A SWP’s may be used in lieu of a manufacturer-qualified WPS when_______________________. A. B. C. D.
approved by the Inspector’s Supervisor allowed by ASME V one test coupon is tension tested per Article V compliance to Article V and Appendix E of ASME IX is shown
95. A change in a non-essential variable requires re-certification of the PQR. True or False (circle one)
96. Reduced-section tensile test specimens conforming to QW-462.1 (b) may be used on all thicknesses of pipe having an outside diameter greater than: A. 2 inches B. 2-1/2 inches C. 3 inches D. 3-1/2 inches E. 4 inches 97. Groove weld tests may be used for qualification of welders. Which of the following shall be used for evaluation? A. Only bend tests B. Only radiography C. Both radiography and bend tests D. Either bend tests or radiography E. None of the above 98. Under which of the following conditions can a welder be qualified during production work? A. A 6" length of the first production groove weld may be qualified by radiography B. A bend test coupon may be cut from the first 12" length of weld C. A macro examination may be taken from the first 3" of weld length D. None of the above
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99.
Two plate tensile test specimens have been tested and found to be acceptable. The characteristics of each specimen are as follows: Specimen #1 has a width of .752”, thickness of .875” and an ultimate tensile value of 78,524 psi. Specimen #2 has a width of .702”, thickness of .852” and an ultimate tensile value of 77,654 psi. What is the ultimate load for each specimen that was reported on the laboratory report? A. B. C. D.
100.
51,668 & 46,445 67,453 & 56,443 78,524 & 77,654 None of the above
Which of the following welding processes are currently not permitted to be used with SWP’s as referenced in Appendix E of ASME IX? A. B. C. D.
GMAW SAW PAW All of the above
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ANSWER SHEET ASME SECTION IX PRACTICE QUESTIONS
1. C QW-100.1
26. A QW-321
51. A
76. A
2. D QW-100.1
27. C QW-301.4
52. C
77. True
3. D QW-100.1, QW-200.2
28. B QW-452.1(b)
53. D
78. A
4. D QW-100.3
29. C QW-421
54. A
79. True
5. B QW-100.3
30. C QW-423.1
55. C
80. False
6. B QW-103
31. D QW-431
56. B
81. True
7. C QW-103
32. C QW-442
57. D
82. False
8. C QW-461.9
33. C QW-353
58. D
83. True
9. D QW-461.9
34. B QW-301.3
59. A
84. C
10. B QW-461.9, QW-452.3
35. B
60. B
85. B
11. C QW-303
36. A
61. A
86. B
12. C QW-171
37. B
62. B
87. B
13. A QW-304
38. B
63. B
88. B
14. C QW-153
39. A
64. True
89. E
15. C QW-163
40. D
65. D
90. E
16. B QW-191
41. C
66. C
91. D
17. D QW-200.1
42. B
67. B
92. D
18. B QW-200.2
43. B
68. False
93. A
19. B QW-200.2
44. A
69. False
94. D
20. B QW-253
45. B
70. Pass
95. False
21. A QW-254
46. D
71. True
96. C
22. B QW-100.2, QW-301.1
47. B
72. False
97. D
23. D QW-301.4
48. B
73. False
98. A
24. B QW-322.1
49. C
74. False
99. A
25. C QW-310.2
50. A
75. B
100. D
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ASME Section IX Practice Reviews
Module Objective. The only way to grasp how to use the Tables Of variables of ‘road map’ concept explained in the previous module is to apply the technique. Reviewing welding documents is about method and accuracy. Remember: ¾ ¾
the WPS must list all variables the PQR must list all essential variables.
The ranges shown on a WPS must be supported by the actual value on the PQR plus within the rules allowed by ASME IX. As such the WPS values must be supported by both PQR and Code.
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PQR & WPS # SMAW-1-8, REV. 0 - PRACTICE QUESTIONS
1. Do the mechanical tests support qualification of this PQR? A. Yes B. No, one tensile test failed. C. Face Bends and root Bends should have been performed instead of side bends. D. The 3/32” defect in the heat effected zone on the side bend tests is over the acceptable limit. Note: .758 x ,752 = .570 sq. in. 37850/57 x 100 = 66403.5 70000 x .95 = 66500 66403.5 , 66500 so the tensile failed & the report is incorrect See QW-153.1 (d) (5% rule) 2. Is joint design fully addressed on the WPS? A. No, the sketch of the joint must also show weld layers & specify uphill or downhill. B. Yes C. No, root spacing is not addressed. D. No, spacing between backing strip & base metal must also be addressed. Note: If a sketch of the joint is not supplied and a note such as; “See drawings.” is entered in place of a sketch it is not acceptable unless the sketch is supplied with the WPS. The WPS is used to provide direction to the welder. It is not acceptable to allow the welder to choose the joint design or type he desires. 3. The full range qualified for the base metal thickness that may be welded with this WPS is: A. 1/16” to 1 1/2” B. 3/16” to 1 1/8” C. As shown on the WPS D. None of the above Note: See Table QW-451.1 4. The actual maximum throat dimension allowed for the weld metal thickness “t” for fillet welds: A. has been restricted by the WPS to 1” maximum throat. B. should be 0” to 8” C. is 1/16” to 3/4” D. is 3/16” to 1 1/2”
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5. If a joint was made using this WPS and the welder put in a single pass with a deposited weld metal thickness, “t”, of 9/16” : A. It would not make any difference. B. The welder would need to use a different electrode. C. The WPS would need to be requalified with a new PQR. D. Charpy production toughness tests would need to run. Note: 1/2” “t” rule 6. The minimum preheat temperature that this WPS could specify without requalification is: O A. 200 F B. 300O F C. 50O F D. 100O F
7. To increase the full range qualified for “T” on the WPS to 3/16” to 2”: A. The original coupon used for the PQR would have to have been 1” thick. B. The WPS only needs editorial revision to allow the welding the thicker material. C. The preheat temperature needs to be increased to 300O F. D. The method of back gouging must be restricted to grinding only.
8. The full range of A Number qualification which may be shown on the WPS is: A. A-1 through A-11, P-34 and P-4X B. As shown on the WPS C. A-1, Groups 1, 2 & 3 only D. Not covered by ASME Section IX.
73
74
75
76
77
WPS # GTAW - 1 REV. 0 and PQR # GTAW-2
1. The proper base metal thickness range shown on the WPS is: a. b. c. d.
Correct as shown 1/16” - 1” 3/16” - 1/2” 3/16” - 1/4”
2. The shielding gas shown on the WPS is: a. b. c. d.
Correct as shown Should be 75% AR 25% CO2 Should be shown as 20-30 CFH Both B & C above
3. The proper preheat temperature range that should be shown on the WPS is: a. b. c. d.
Correct as shown 100°F minimum 250° maximum 150° minimum
4. The PQR supporting this WPS: a. b. c. d. 5.
A drawing or sketch of the weld joint: a. b. c. d.
6.
is properly identified and traceable to the WPS is not properly identified and is not traceable to the WPS is not traceable to the WPS must be PWHT’d per ASME requirements
must be shown on the PQR must be shown on the WPS and PQR must be shown on the WPS but not the PQR none of the above
The tension tests shown on the PQR: a. b. c. d.
are acceptable as shown are unacceptable because of mathematical error are unacceptable due to the size of the specimen shown are unacceptable due to the strength of the specimens; shown
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7.
The tension tests shown on the PQR: a. b. c. d.
8.
The bend tests shown on the PQR: a. b. c. d.
9.
are acceptable as shown are insufficient in number are incorrect as to the type of bend test performed (i.e., side, face, root) Both B and C above
The bend tests shown on the PQR: a. b. c. d.
10.
are full size pipe specimens are full size reduced section specimens are reduced section turned specimens are not required for this PQR
are acceptable as shown do not meet the acceptance criteria of ASME IX should be listed with the length of each specimen need to be PWHT’d after bending
PQR #GTAW-2 is: a. unacceptable because it was run in the 1G position and the WPS states all positions are acceptable. b. unacceptable because it is not certified. c. unacceptable because it was run with backing gas and the WPS does not require backing gas. d. none of the above
11.
The filler metal shown on the WPS: a. b. c. d.
12.
The amperage and voltage ranges shown on the WPS: a. b. c. d.
13.
has been properly qualified by the PQR has not been properly qualified by the PQR is not necessary because GTAW can be run without filler metal will need to be peened after deposition, per the WPS
are acceptable as shown are unacceptable as qualified on the PQR must be higher to properly run this size of electrode none of the above
The best explanation for the problems observed on the PQR is: a. b. c. d.
Mr. Blow was insane at the time of preparation Mrs. Blow was distracting Mr. Blow at the time of preparation (New swimsuit) The test laboratory personnel just checked out of Betty Ford Clinic The front and back pages of the PQR have been copied from separate documents
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80
81
82
83
WPS # GMAW-1, REV. 0 AND PQR #GMAW-1
1.
The base material thickness range shown on the WPS: a. b. c. d.
2.
The deposited weld metal thickness range shown on the WPS: a. b. c. d.
3.
is unacceptable for that qualified on the PQR is acceptable as shown should be “pulsed” on the WPS none of the above
The gas shielding shown on the WPS is: a. b. c. d.
6.
is acceptable as shown is unacceptable because ER 70S-2 was qualified, and ER 70S-7 is shown on the WPS is incorrect for the SFA # correlating to the F # cannot be used with the GMAW process
The mode of transfer shown on the WPS: a. b. c. d.
5.
is acceptable as shown is beyond the range allowed by the Code is acceptable if impact tests are performed none of the above
The filler metal shown on the WPS: a. b. c. d.
4.
should be 3/16” - 4” maximum should be 3/16” - 2” maximum is proper as shown should be 3/16” - 8” maximum
acceptable as shown unacceptable, because the composition has changed not required because GMAW can be run without gas none of the above
The 3G position of the test coupon indicates that the plate: a. b. c. d.
was tested in the horizontal position was tested in the overhead position was tested in the 45° fixed position none of the above
84
7.
The tension test results shown on the PQR are: a. b. c. d.
8.
The bend test results shown on the PQR are: a. b. c. d.
9.
It is properly certified it does not list toughness tests it has the welder’s name and lab # listed the PQR is unacceptable because it has not been properly certified
A non-essential variable that has not been addressed on the PQR is: a. b. c. d.
11.
acceptable as shown unacceptable because of incorrect type of specimens tested unacceptable because results do not meet the Code unacceptable because not enough bend tests were taken
The PQR is acceptable because: a. b. c. d.
10.
acceptable as shown unacceptable because of insufficient strength unacceptable because an insufficient number of tests were taken for the thickness welded unacceptable because of errors in mathematical calculations
peening electrode spacing gas cup size not applicable - non-essential variables do not have to be addressed on the PQR
An essential variable (or variables) that has not been addressed on the PQR is: a. b. c. d.
QW 403.9 QW 404.24 - QW 404.27 QW-402.1 both a & b above
85
86
87
88
89
WPS #SAW-1, REV. O, PQR #SAW-1
1.
The deposited weld metal thickness range listed on the WPS: a. b. c. d.
2.
The joint design shown on the WPS: a. b. c. d.
3.
is acceptable as shown is incorrect - plate does not qualify for pipe should be >24” o.d. should be shown as > 2 7/8” o.d.
Post-weld heat treatment as shown on the WPS/PQR is: a. b. c. d.
6.
QW-404.36 QW-403.9 QW-403.13 all of the above
The pipe diameter range listed on the WPS: a. b. c. d.
5.
must be qualified by the PQR is acceptable as shown must be re-qualified if an open root joint will be used should be qualified with a backing strip instead of weld metal
An essential variable that has not been addressed on both the WPS and PQR is: a. b. c. d.
4.
is correct as shown is incorrect - should be 3/16” - 2” max. should be 4” max. none of the above
incorrect, as all codes require PWHT in this thickness incorrect, as the PQR should be PWHT’d incorrect as the WPS should specify required PWHT of production welds none of the above
The tension test results shown on the PQR are: a. b. c. d.
acceptable as shown unacceptable due to insufficient width of specimens unacceptable due to insufficient number of specimens unacceptable because multiple specimens cannot be used in this thickness of plate coupon
90
7.
The bend test results shown on the PQR are: a. b. c. d.
8.
The tension test results shown on the PQR are: a. b. c. d.
9.
sufficiently strong to meet the Code too weak to meet the Code 1.5% over the rated base metal tensile strength, and therefore, do not meet the Code unacceptable because the results look “bogus”
The PQR: a. b. c. d.
10.
acceptable as shown unacceptable due to insufficient number of specimens unacceptable due to wrong type of bend test specimen unacceptable due to wrong size of specimen
does not need to be signed must be signed to be “Code legal” must be signed by the President of the Company none of the above
An essential variable that is addressed on the WPS but not addressed on the PQR is: a. b. c. d.
QW 404.25 QW 406.1 QW 407 QW 404.34
91
92
93
94
95
WPS #SMAW-1, REV. 0 AND PQR # SMAW-1A
1.
The base metal thickness range shown on the WPS is: a. b. c. d.
2.
correct as shown incorrect - should be - 1/16” - 1 1/2” incorrect - should be - 3/16” - 2” incorrect - should be 3/8” - 1”
The deposited weld metal thickness range shown on the WPS is: a. correct as shown b. incorrect - should be “unlimited” c. incorrect - should be 8” maximum d. incorrect - should be 2” maximum
3.
The welding rod change (from 7018 on the PQR to 7016 on the WPS) is: a. b. c. d.
4.
The preheat temperature shown on the WPS should be: a. b. c. d.
5.
60° F minimum 100° F minimum 250° F minimum 300° F minimum
The tension test specimen results shown on the PQR are: a. b. c. d.
6.
acceptable as shown unacceptable - can only be 7018 on the WPS acceptable - provided the rod is 7016 A1 unacceptable - the rod on the WPS must be 6010 only
acceptable as shown unacceptable - not enough specimens unacceptable - ultimate stress does not meet ASME IX unacceptable - width of specimens are incorrect
The bend test results shown on the PQR are: a. b. c. d.
acceptable as shown unacceptable - defect greater than allowed unacceptable - wrong type and insufficient number of specimens unacceptable - incorrect Figure # - should be QW-463.2
96
7.
The PQR must be _________ to be “Code legal”. a. b. c. d.
8.
Essential variable # QW 403.9 has been: a. b. c. d.
9.
correctly addressed on the WPS incorrectly addressed on the WPS not addressed on the PQR both B & C above
The position of the groove on the PQR is: a. b. c. d.
10.
certified notarized authorized witnessed
acceptable as shown unacceptable - essential variable not addressed unacceptable - position shown does not correlate to plate both B & C above
The PQR shows “string” beads. The WPS shows “both” string and weave beads. This condition is: a. b. c. d.
unacceptable - doesn’t meet Code acceptable - meets Code acceptable if “string” beads are in the root only acceptable if “weave” beads are in the cap pass only
97
98
99
100
101
ANSWER SHEET WELDING PROCEDURE REVIEW QUESTIONS
102
ASME SECTION VIII
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ASME SECTION VIII DIVISION 1 SUBSECTIONS - INFORMATION
INTRODUCTION
PART UG - GENERAL
PART UW - WELDING
• Scope • General • Standards
• Materials • Design • Openings and Reinforcements • Braced and Stayed Surfaces • Ligaments • Fabrication • Inspection and Tests • Marking and Reports • Pressure Relief Devices
• • • • •
General Materials Design Fabrication Inspection and Tests • Marking and Reports • Pressure Relief Devices
PART UCS - CARBON STEEL
PART UHA - HIGH ALLOY
• • • • • • • •
• • • • • • •
General Materials Design Low Temperature Operation Fabrication Inspection and Tests Marking and Reports Pressure Relief Devices
General Materials Design Fabrication Inspection and Tests Marking and Reports Pressure Relief Devices
SECTION VIII DIVISION 1 PRESSURE VESSELS Pressure Vessels = containers for the containment of internal or external pressure. Pressure sources
. external source . heat (direct or indirect) . combination
Structure of Division 1 Consists of: 3 subsections Mandatory Appendices Nonmandatory Appendices
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Subsections of Division 1 Subsection A Part UG
General Requirements General Requirements for all Methods of Construction and Materials
Subsection B
Requirements Pertaining to Methods of Fabrication
Part UW
Requirements for Pressure Vessels Fabricated by Welding
Part UF
Requirements for Pressure Vessels Fabricated by Forging
Part UB
Requirements for Pressure Vessels Fabricated by Brazing
Subsection C
Requirements Pertaining to Classes of Materials
Part UCS
Requirements for Pressure Vessels Constructed of Carbon and Low-Alloy Steels
Part UNF
Requirements for Pressure Vessels Constructed of Nonferrous Materials
Part UHA
Requirements for Pressure Vessels Constructed of High-Alloy Steel
Part UCI
Requirements for Pressure Vessels Constructed of Cast Iron
Part UCL
Requirements for Pressure Vessels Constructed of Material with Corrosion Resistant Integral Cladding, Weld Material Overlay Cladding, or with Applied Linings
Part UCD
Requirements for Pressure Vessels Constructed of Cast Ductile Iron
Part UHT
Requirements for Pressure Vessels Constructed of Ferritic Steels with Tensile Properties Enhanced by Heat Treatment
Part ULW
Requirements for Pressure Vessels Fabricated by Layered Construction
Part ULT
Alternative Rules for Pressure Vessels Constructed of Materials Having Higher Allowable Stresses at Low Temperature
Part UHX
New 2003 Addenda Rules For Shell & Tube Heat Exchangers
Mandatory Appendices
Address specific subjects NOT covered elsewhere in the Division Requirements are mandatory when the subject is included in CONSTRUCTION in this Division
Nonmandatory Appendices
Provide Information -- and -Suggested good practices
Vessels NOT Within
Those within the scope of other Sections
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the Scope of Section VIII, Division 1
Fired process tubular heaters Pressure containers which are integral components of rotating or reciprocating mechanical devices where the primary design considerations are drawn from the functional requirements of the device.
Piping systems Piping components (pipe, flanges, bolting, gaskets, valves, expansion joints, and fittings) and the pressure containing parts of other components (i.e., strainers, mixers, separators, snubbers, distribution devices, metering and flow controlling devices) which are generally recognized as piping components Water containing vessels with capacity of 120 gallons or less, and those which contain air (for cushioning) Hot water storage tank which is: - - indirectly heated - - LESS THAN 200,000 Btu/hour - - water temperature of 210 deg. F. or less - - capacity of 120 gallons or less Vessels with internal or external operating pressures of 15 psi or less regardless of their size Vessels with an inside diameter, width, height or cross section of 6 inches or less regardless of length Design Pressures
Rules based on vessels whose pressure does NOT exceed 3000 psi For pressures above 3000 psi, there are usually specific additions to, and deviations from, the rules of the Code. These special rules must be applied to all such higher pressure vessels, before it may be stamped (new ASME VIII Div. 3 to be developed).
Geometry of Pressure Parts
The scope of this division shall extend to: • Where external piping is connected - - the welding and connection for the first circumferential joint on welded connections - - the first threaded joint for screwed connections - - the face of the first flange for bolted, flanged, connections - - the first sealing surface for proprietary connections/fittings • The weld attaching a nonpressure part directly to the internal or external surface of a pressure vessel • Pressure retaining covers for vessel openings (manhole/handhold) • First sealing surface for proprietary fittings for which there are no rules in this division such as gauges/instruments
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Relief Devices and Unfired Steam Boilers
Scope includes those devices necessary to meet requirements of UG-125 through UG-136 and Appendix II Unfired Steam Boilers (defined in Section I) constructed according to rules in either Section 1 or this Division UG-125(b) and UW-2© Pressure vessels in which steam is generated shall be constructed in accordance with the rules of this Division. Evaporators or heat exchangers Where steam is generated by a processing system containing a number of pressure vessels, such as in the chemical or petroleum industries
Fired Vessels and Fired Jacketed Steam
Pressure vessels or parts which are DIRECT FIRED, and which are not within the scope of Sections I, III, or IV, may be built in Kettles accordance with the rules of this Division Gas fired jacketed steam kettles with operating pressures below 50 psi, may also be constructed in accordance with the rules of this Division.
SECTION VIII - DIVISION 1 INTRODUCTION AND SUBSECTION A U-1, Scope: The scope of Section VIII - Division 1 should be reviewed closely. It defines what constitutes a pressure vessel ( “containers for the containment of pressure, either internal or external”), and details the overall sections and subsections of the Code. In Paragraph (c), it states that the Code does not prohibit the use of the "U" Stamp on any type of pressure vessel, providing all of the rules are satisfied in the final construction. Paragraph (C) goes on to list 10 general classes of pressure vessels that are generally exempted from the Code. These should be watched closely, as many jurisdictions with pressure vessel laws adopt these exemptions as shown, and therefore, a particular vessel may not have to be inspected, stamped or registered if it falls under one of the exemptions shown. The reader should be cautioned, however, that it is the law at the point of installation that determines what pressure vessels must be constructed Code in order to be legally operated. Vessels requiring in-service inspection vary widely from jurisdiction to jurisdiction. U-1(d) is an important paragraph.. Contrary to what some believe, it does not limit the design of pressure vessel to 3,000 psi. However, for pressure vessels constructed over 3,000 psi, deviations from and additions to the rules may be necessary to satisfy the service conditions. If these deviations or additions (such as a complete stress analysis of each component) still show the vessel meets the Code, then the item may be Code stamped. U-1(e) is must be clearly understood to ensure a common understanding of where the “pressure vessel” ends and where the “piping” begins.
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manway
Denotes Code Scope Limitations U-1 (e) describes the minimum boundaries to establish a completed pressure vessel, but does not prohibit the Code application beyond the terminal points, provided all of the rules are satisfied in the extension and the materials are properly listed on the Manufacturer’s Data Report. For example, a nozzle boundary can be extended to any length, including all connecting piping many feet or meters away from the vessel. Conversely, a nozzle can be extended and be in place when the pressure vessel is tested but still be excluded from the Code construction by a proper entry on the Data Report. In this case, the nozzle does not have to meet Code requirements.
U-1(f) states that Section VIII - Division 1 includes provisions for pressure relief devices in UG-125 through UG136.
U-1(g) allows alternative construction of unfired steam boilers to Section VIII - Division 1, instead of ASME I, as some jurisdictions (such as Texas) classify these pressure vessels as boilers and require them to be constructed under Section VIII. U-1(h) covers direct fired pressure vessels NOT within the scope of ASME I, III, or IV, and U-1(I) covering gas fired jacketed steam kettles under 50 psi. Both of these classes of vessels may be constructed to Section VIII Division 1, provided it is allowed at the point of installation.
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U-1(j) provides for "UM" stamping of pressure vessels . Pressure vessels may be stamped "UM" provided full radiography is not a requirement, no quick-opening closures are employed, and provided the following volume and/or pressure limits are not exceeded: (1) 5 cu. ft. - 250 psi OR (2) 3 cu. ft. - 350 psi OR (3) 1-1/2 cu. ft. - 600 psi The primary difference between a pressure vessel stamped "UM" and a pressure vessel stamped "U" is that the pressure vessel stamped "UM" will not have been inspected during construction by an Authorized Inspector. Manufacturer’s Data Reports will not be furnished except upon specific request by the owner/user. See UG-120 for details.
U-2, GENERAL U-2 (a) states that the user and/or his designated agent shall establish design requirements for pressure vessels, taking into account startups, shutdowns, and upset conditions. Other design factors that the owner/user must convey to the fabricator are: * the need for corrosion allowance; * lethal service, if required * the need for PWHT if for service reasons (i.e., H2S service); * for unfired steam boilers, the need for fittings complying to ASME I.
U-2(b) covers responsibilities, and clearly states that the manufacturer of the completed pressure vessel has the total responsibility for Code compliance. The manufacturer of the pressure vessel may subcontract for parts and/or service to complete the pressure vessel; however, the Manufacturer that will apply the final “U” Code stamp to the item has the ultimate responsibility to ensure that the proper documentation is received and available for all work not done by him. ASME stamped parts with Partial Data Reports are usually the document used to allow manufacturers to accept welded parts from one another. The system of control of subcontracted services must be defined in each Manufacturers quality control system.
U-2 (C) and (d) are self explanatory. U-2 (e) requires the Authorized Inspector to make all inspections required by the rules, plus any other inspections he deems necessary to permit him to certify that, to the best of his knowledge, the pressure vessel meets the Code requirements. The Authorized Inspector is only required to verify that complete design calculations exist and that are on file at the time the Data Report is signed. Any questions raised by the Inspector must be resolved by the Manufacturer.
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U-2(g) states that Section VIII - Division 1 does not contain rules for all types of construction and states that, subject to the Inspector’s acceptance, other design rules may be used that will provide equivalent factors of safety.
U-2(h) describes the methods and means to perform field erection and completion of vessels in the field. Basically, this can occur in three ways: (1) The manufacturer completes the pressure vessel in the field; (2) The manufacturer receives Partial Data Reports for the individual parts, and then Code stamps and certifies the vessel on a master Data Report, using the partials as supporting evidence of Code compliance; (3) The field portion is completed by a sub-contractor and a partial Data Report is supplied. The Manufacturer, using the sub-contractor’s partial(s) prepares the master Data Report, and applies the full “U” Code stamp to the vessel.
U-3 and Table U-3 The Table shows the exact year or edition accepted by ASME VIII for reference standards used and specified throughout the book.
SUBSECTION A GENERAL REQUIREMENTS PART UG -GENERAL REQUIREMENTS FOR ALL METHODS OF CONSTRUCTION AND ALL MATERIALS UG - 1 SCOPE Part UG establishes general requirements applicable to all pressure vessels, and shall be used in conjunction with the specific requirements in Subsections B and C that pertain to the methods of fabrication and material. MATERIALS UG-4 GENERAL (a) -This paragraph requires that materials subject to stress due to pressure must be materials conforming to Section II - Materials Specifications and further limits these materials to materials listed in the applicable Part of Subsection C, except where allowed in Part UG. (b) -Non-pressure part materials attached to pressure parts do not have to conform to Section II, but if welded must be demonstrated to be of weldable quality. (e ) -Materials outside the limits of size and/or thickness established in a material specification may be used if the material is in compliance with the other requirements of the specification, and no size or thickness limitations are shown in the stress tables in Section II Part D. (f) - The selection of the right material for the intended service is very important, and is stressed here.
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UG-5 through UG-9 These paragraphs provide some general details on the different product forms. Particular attention should be given to UG-8, which discusses rules for integrally-finned tubes, and UG-9, which requires welding consumables to meet the requirements of Section VIII, Section IX, and the welding procedure to be used. UG-10 MATERIALS NOT FULLY IDENTIFIED TO AN ACCEPTABLE SPECIFICATION This paragraph provides for the use of materials that are not fully marked or traceable to Code requirements. It is only allowed to salvage materials that have lost their full identification, or for unacceptable materials that can be “dual qualified” to a material specification that is acceptable under the rules of the Code. UG-11 MISCELLANEOUS PRESSURE PARTS This paragraph provides for the use of pre-fabricated or pre-formed pressure parts made of Code materials and furnished under recognized standards that will normally not require Data Reports. Nearly all standard pressure parts used in Section VIII - Division 1 pressure vessels will be supplied under an ANSI or Manufacturer’s Standard. Manufacturer’s Standard pressure parts are acceptable only if the manufacturer has detailed literature which describes the parts, materials, forming, etc. All miscellaneous parts may be seamless or welded. Each part must have an applicable pressure rating, or it must be calculated under the Code rules using allowable stress values obtained from the applicable stress table in ASME II Part D. UG-12 - UG-14 Rules for bolts, studs, nuts, washers, and rods/bars are given, and are sometimes overlooked. These paragraphs should be watched closely, as some simple requirements are given, and must be followed. DESIGN UG-16 GENERAL (b) The minimum thickness of shells and heads, after forming and regardless of service shall be 1/16", exclusive of corrosion allowance. This rule does not apply to : * heat transfer plates * 6" NPS or less inner pipe of double pipe Heat Exchangers * Unfired steam boilers - 1/4" minimum * Compressed air, steam, water 3/32" minimum * tubes in heat exchangers (air cooled or cooling tower) provided conditions a – d are met. (c ) Plates are allowed an undertolerance of either .01" or 6% of ordered thickness, whichever is less. (d) Pipe undertolerance shall be per UG-40, which is specified as 12.5% of nominal thickness. This is VERY important when calculating shells or nozzles made from pipe, as this undertolerance must be considered and the next heavier schedule must be used to ensure adequate wall thickness for the pressure.
UG-19 SPECIAL CONSTRUCTIONS Combination units constructed of one or more independent chambers may be built under the rules. Each chamber of such construction must be designed and constructed as an independent pressure vessel. Where design rules are not given, a proof test in accordance with UG-101 may be done.
111
UG-20 DESIGN TEMPERATURE These paragraphs are often overlooked and are very important to know. The maximum and minimum metal temperatures MUST be established, and the minimum temperature may be based not only on operating conditions, but also atmospheric conditions at the point of installation. UG-20(f) This paragraph is very often overlooked when applying impact testing criteria from the other subsections. This paragraph provides for “blanket” exemptions to the impact testing rules, provided all the provisions listed (1-5) are complied with. UG-22 LOADINGS This paragraph requires that external loads from earthquakes and winds; reactions from piping supports and lugs; pressure vessel weight; superimposed loads from operating equipment, supports, effects of thermal reactions and abnormal pressures must be considered when designing a vessel. Specific rules for “considering” these loadings are not given in the Code, however, many designers use the Pressure Vessel Handbook or a computer program when confronted with these types of design details. UG-23 STRESS VALUES This paragraph guides the user to go to ASME Section II Part D for the allowable stress values for a given material when calculating any particular vessel. UG-24 CASTINGS Steel casting require supplementary inspections in order to use a 90% or 100% quality factor in the design calculations. The quality factor shall be 80% if only the basic material specification is satisfied. Castings of cast iron and cast ductile iron are prohibited. See Mandatory Appendix 7 for more requirements on castings. UG-25 CORROSION The user or designated agent must tell the vessel manufacturer if corrosion allowance will be needed above and beyond that required by the Code. This is a contractual matter, and one which the vessel manufacturer will, undoubtedly, charge more for than for not providing such allowance. The only mandatory requirement for corrosion allowance exists in Part UCS for pressure vessels used for air, steam, or water and this requirement may be waived depending on the design used. (e) Telltale holes are used in pressure vessels as an indicator that a vessel has corroded to a point of losing the corrosion allowance. They can not be used in pressure vessels containing toxic or flammable substances. UG25(e) provides information on size, depth, location, and spacing of telltale holes. UG-27 THICKNESS OF SHELLS UNDER INTERNAL PRESSURE These are the basic design formulas and nomenclature for calculating the thickness or maximum allowable working pressure of a cylindrical or spherical vessel shell. Note that these formulas only apply when the circumferential joint efficiency is less than ½ the longitudinal joint efficiency and the radius/pressure and pressure/stress ratios are in proportion to one another. Formulas are given in terms of inside radius. For outside radius/diameter, the alternative formulas in Appendix 1 may be used. UG-28 THICKNESS OF SHELLS AND TUBES UNDER EXTERNAL PRESSURE Rules are given for computing the allowable external pressure on a shell. Note that the applicable External Pressure Tables in ASME Section II Part D must be used to calculate these thicknesses. UG-32 FORMED HEADS, PRESSURE ON THE CONCAVE SIDE Rules for computing the thickness/MAWP of formed heads are provided. Four (4) types of head formulas are given: Ellipsoidal, Hemispherical, Torispherical, and Conical. Formulas are based on STANDARD shapes with INTERNAL dimensions (i.e. 2:1 Elliptical Heads). For heads with non-standard dimensions and/or for outside diameters, the alternative rules in Appendix 1 must be used.
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UG-33 AND UG-34, CONVEX PRESSURE HEADS AND FLAT HEADS Rules and formulas are given for calculating required thickness or MAWP are given. UG-35 OTHER TYPES OF CLOSURES Spherically dished heads attached by bolts are specified in Appendix 1. Quick-actuating closures (other than multibolted type) that provide quick access to a pressure vessel shall have the locking mechanism or locking device designed so that the failure of a single element or component in the locking mechanism cannot result in the failure of the elements and the release of the closure. UG-36 THROUGH UG-42 These paragraphs all deal with basically the same issues - making an opening in a pressure vessel, and then calculating the required reinforcement area to replace the area removed. UG-36 deals specifically with the opening, and specific attention should be directed towards (b), which discusses maximum sizes of openings, and (c ) (3) (a), which allows a blanket reinforcement exemption for certain openings in maximum thicknesses. Note that corrosion allowance is never included in adding reinforcing strength. UG-37 provides rules and a figure, UG-37.1, for calculating the required reinforcement of any given nozzle not exempted by UG-36. UG-38 and UG-39 give rules for openings in formed and flat heads. UG-40 provides narrative follow-up to the pictorial requirements of Figure UG-37.1, by establishing the maximum dimensions that can be considered for reinforcement on both planes of the opening (parallel and perpendicular). UG-41 discusses the required strength of reinforcing material, and stipulates that the material must be as strong as the vessel material, or the thickness of the reinforcement must be increased proportionally. UG-42 The strength of the weld metal, particularly the attachment fillet welds must be calculated when the standard weld details shown in UW-16 are not applied. Several Figures and formulas are given to allow this computation to be performed. Reinforcement of multiple openings spaced closely together are covered in UG-42. UG-43 METHODS OF ATTACHING NOZZLES TO VESSEL WALLS Welded connections must meet the design details given in UW-15 and UW-16. Rules are given and a Table is provided that details the requirements for threaded connections to a vessel wall. Note that this is not intended for pipe-to-pipe connections.
UG-44 FLANGES AND PIPE FITTINGS The acceptable ANSI standards for flanges and pipe fittings are specified.
UG-45 NOZZLE NECK THICKNESS This paragraph is commonly misunderstood by many users. Basically, what the paragraph is trying to state is that the thickness of a nozzle must be designed per UG-27, and additionally, cannot be less than the SMALLEST of several given values: * The thickness of the shell or head plus corrosion allowance; * The minimum (not nominal) thickness of standard wall pipe, plus corrosion allowance. UG-46 INSPECTION OPENINGS All vessels subject to corrosion, erosion , or for compressed air shall have inspection openings as outlined or exempted in this paragraph. Note that vessels with removable heads or covers (such as heat exchangers) do not require inspection openings. Tell-tale holes complying with UG-25 may be used in lieu of inspection openings. Also note that vessels over 36" i.d. shall be fitted with manways, or if impractical, at least two 4"x 6" handholes or equivalent. Minimum manway dimensions are 12” x 16” or 16” circular.
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UG-47 TO UG-50 BRACED AND STAYED SURFACES AND STAYBOLTS Rules and design formulas are given for these types of vessels. This is a relatively unused section of the Code, as not many pressure vessels are made, routinely, with stayed surfaces. The most likely usage would be for flat heads or tubesheets that are high pressure and would require the extra bracing for strength purposes. UG-53 LIGAMENTS Ligaments are those spaces between multiple small openings (such as heat exchanger tubesheets) that must be calculated to ensure that enough material is left to withstand the expected pressure. Again, this paragraph is used basically for heat exchangers and unfired steam boilers that will be subject to multiple small openings.
FABRICATION UG-76 CUTTING PLATES AND OTHER STOCK Materials may be separated by mechanical means such as machining, shearing, grinding, or by oxygen or arc cutting. If gas or arc cut, the slag and detrimental discoloration must be removed by mechanical means before further fabrication. Exposed inside edges of cut materials (such as nozzles) must be chamfered or rounded. UG-77 MATERIAL IDENTIFICATION (SEE ALSO UG-85) This paragraph is another commonly overlooked or misunderstood passage. The manufacturer MUST maintain traceability of ALL pressure retaining parts while the vessel is being fabricated (it is the “ALL” part that most fabricators don’t understand or appreciate). How each manufacturer accomplishes this is up to him, but it must be done. If material is to be separated or markings are to obliterated, the transfer of markings may occur either before or after the operation, provided positive identity can be established to the satisfaction of the Authorized Inspector. Each manufacturer’s accepted quality control system must establish the details for control of materials and the transfer of markings during fabrication. The use of coded markings must be described and available for review. All new materials supplied must include the full marking as required by the applicable material specification. Except for pressure parts furnished under an acceptable standard such as ANSI, non-welded material formed by a subcontractor (such as heads must have the full identification as required by the applicable material specification and must be supported by a Material Test Report. UG-78 REPAIR OF DEFECTS IN MATERIALS Repairs to material by the manufacturer are permitted provided acceptance of the Authorized Inspector is obtained.
UG-80 PERMISSIBLE OUT-OF-ROUNDNESS It is nearly impossible to make a perfectly round cylinder or sphere, especially when dealing with steel that has a tendency to “stretch and relax”. The Code recognizes this fact, and allows some out-of-roundness when rolling plate into these shapes: • 1% of inside diameter maximum at no openings; • 2% of inside diameter maximum when passing through an opening; • 3% maximum (and recalculation for lower pressure) for enamel lined vessels; • As calculated by (b) and Figure UG-80.1 for external pressure vessels
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UG-84 CHARPY IMPACT TESTS This is an extremely long and rather complicated paragraph that provides rules for HOW AND WHERE to conduct Charpy Impact Tests when required by Subsection C for each class of material. Most importantly, it also gives the ACCEPTANCE CRITERIA for each material based on the specific minimum yield strength. UG-85 HEAT TREATMENT Contrary to some beliefs, these provisions exist for heat treatment of materials to be carried out by other than the material manufacturer (such as a subcontractor or the vessel manufacturer). If heat treatment is carried out by anyone other than the material manufacturer, the pressure vessel manufacturer must maintain control over this operation, and must ensure the markings described in this paragraph are included. INSPECTIONS AND TESTS
UG-90 GENERAL Examination (QC) requirements are established for the manufacturer and Inspection (QA) requirements are established for the Authorized Inspector. The specific examinations required for each vessel are spelled out in (b) (1) through (19), with appropriate references to other paragraphs which contain further information about the subject. The vessel manufacturer must complete these examinations and provide some kind of objective evidence (as detailed in the written QC Program) that these examinations have been successfully applied. The Authorized Inspectors assigned duties are also spelled out in (c)(1) and (c)(2). The (c)(2) duties only apply in a very special circumstance for multiple, duplicate pressure vessel manufacturers that may produce hundreds of vessels per day at the same location (such as propane tank manufacturers). The note under UG-92 explains that an Authorized Inspection Agency or AIA means an accredited inspection agency in accordance with ASME QAI-1. UG-93 INSPECTION OF MATERIALS The manufacturer must obtain Material test reports for all plate and items made from plate (such as heads), except for those items furnished under an ANSI or Manufacturer’s Standard per UG-11. For all other products, the material can be accepted without MTR’S, provided it is properly marked in accordance with the applicable markings required by ASME Section II. (d) - All materials must be examined prior to examination. When a corner joint is made from flat plate, the joint must be examined prior to welding (and sometimes after welding) by PT or MT to ensure freedom from laminations. UG-96 AND UG-97 DIMENSIONAL CHECK/ INSPECTION DURING FABRICATION The manufacturer has the responsibility of making dimensional checks to ensure that the shape and thickness is acceptable as the vessel progresses through fabrication. The manufacturer shall furnish accurately formed templates if required by the AI. An internal inspection by the AI must be done prior to closure, where possible. An internal inspection is required in all lead-lined vessels.
UG-98 MAXIMUM ALLOWABLE WORKING PRESSURE The terms maximum allowable working pressure (MAWP), design pressure, operating pressure, and working pressure cause a lot of confusion. Basically, the terms “operating pressure” and “working pressure” are the same and they relate to the pressure at which the item will actually run, not counting upsets or abnormal conditions. These pressures are usually substantially less than the design pressure or maximum allowable pressure. The design pressure is the target pressure of the pressure vessel designer, and can be the same pressure that will be shown on the vessel stamping and in the Manufacturers Data Report as the maximum
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allowable working pressure. The maximum allowable working pressure for a pressure vessel is the maximum pressure permissible at the top of the pressure vessel in its normal operating position and at the operating temperature specified for that pressure. This is the ABSOLUTE top end that the vessel can experience, and is the pressure that the relieving devices should be based on. UG-99 STANDARD HYDROSTATIC TEST All completed pressure vessels, except for those pneumatically or proof tested in accordance with UG-100 or UG-101 shall be hydrostatically tested to the requirements of this paragraph. Many believe that the test pressure will always be 1.3 X MAWP. This is incorrect. This paragraph states that the ratio of the test temperature to the design temperature must be considered, and therefore, the stress value of ALL materials used in the vessel must be analyzed to ascertain if the test pressure must be increased to account for this transition in temperature. It is important to note that pneumatic testing cannot be arbitrarily substituted for the hydrostatic test. The possibility of brittle fracture at the time of the hydrostatic test must be considered. Therefore, the Code recommends the temperature of the test water be at least 30 degrees above the MDMT. The 120 degree maximum is intended as a safety measure to ensure personnel do not get burned. The weight of the liquid must also be considered by the designer, for the acceptability and strength of the supports. UG-100 PNEUMATIC TEST UG-100 provides for a pneumatic (air or gas) test when the physical size of the pressure vessel and/or the design is such that it will not support the fluid or the service condition is such that moisture residue is unacceptable. Safety is the primary consideration when conducting a pneumatic test, and therefore, the rules differ from the hydrostatic test rules given in UG-99. This is the reason that pneumatic testing is 1.1 X maximum allowable working pressure and extreme care should be taken to not exceed that pressure. Pressure increments are specified and must be closely followed to ensure the highest degree of safety. Also see UW-50 for additional NDE that must be conducted when pneumatically testing a vessel. UG-101 PROOF TESTS TO ESTABLISH MAWP This paragraph contains provisions for proof testing when design formulas do not exist in the rules. Proof testing can only be used to establish an allowable working pressure if the Code does not provide a design formula to calculate the part. Proof testing is very expensive, and usually results in the test vessel being discarded. The 4 types of proof tests are: 1. Brittle coating 2. Burst test 3. Strain measurement test 4. Displacement measurement test A procedure must be developed for each test and that acceptance of the procedure must be obtained from the Authorized Inspector before conducting the test. The proof test shall also be witnessed by and the test results accepted by the Authorized Inspector.
UG-102 TEST GAUGES Must have a test indicating gauge, visible to pump operator. Dial gauges must have a range not less than 1 ½ nor more than 4 times the test pressure. All gauges must be calibrated against a calibrated dead weight tester or master gauge, anytime there is reason to suspect error.
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MARKING AND REPORTS UG-116 REQUIRED MARKING Section VIII - Division 1 requires all vessels to be marked (either by direct stamping or nameplate) to identify the vessel and the basic design conditions relative to the vessel. This information is then traceable to the Manufacturer’s Data Report, which can be used for further defining the criteria and materials used in constructing the vessel. (e) - Note the “RT-1" , “RT-2", “RT-3" and “RT-4" stamping requirements to indicate the extent of radiography performed. This stamping is directly related to the design joint efficiencies used which also correlates to UW-3, UW-11, and UW-12. These paragraphs will be discussed in more detail in that section. (f) - Note also the heat treatment designations - “HT” when the entire vessel has been stress relieved; “PHT” when only part of the vessel has been stress relieved.
UG-117 CERTIFICATES OF AUTHORIZATION AND CODE STAMPS This paragraph details how to obtain a Code stamp, and the pre-requisites that must be met prior to applying for the stamp. The manufacturer must have a contract in force at all times with an Authorized Inspection Agency, and must have and implement a quality control program in compliance with Appendix 10 requirements. A Joint Review will be conducted by an ASME Designee (usually a Jurisdictional Representative) and the Inspection Agency Supervisor to ascertain the acceptability of the quality control program. If acceptable the Team will submit a recommendation to ASME, and the stamp(s) and certificate(s) will be issued for a 3 year period. Every 3 years, the process is repeated. UG-118 AND UG-119 These paragraphs are self-explanatory. UG-120 DATA REPORTS All ASME Code pressure vessels must be certified by use of a Manufacturer’s Data Report (“MDR”). There are several kinds and types of data reports, and familiarity with each one is essential not only for new construction, but also for field verifications, inspections, and repairs/alterations to existing vessels. Basically, there are 6 types of MDR’s (see non-Mandatory Appendix W: • U-1 Form - For multi-chamber vessels, such as exchangers • U-1A Form - For single-chamber, completely shop-fabricated vessels • U-2 Form - Partial Data Report for U-1 type vessels • U-2A Form - Partial Data Report for U-1A type vessels • U-3 Form - For miniature vessels (UM Vessels) • U-4 Form - For supplement to all other forms, in case lack-of-space is a problem PRESSURE RELIEF DEVICES UG-125 THROUGH UG-136 These paragraphs all deal with pressure relief devices, and in particular, are aimed at manufacturers and assemblers of relieving devices (UV Stamp holders). The key to remember is that these manufacturers and assemblers all have the same basic kinds of requirements and restrictions imposed on them as for the pressure vessel manufacturer (QC system requirements, design, test, material requirements, etc.), but are not subject to the scrutiny of an Authorized Inspector, nor are they required to have MDR’s for each valve produced. These paragraphs are all fairly straightforward, and will not be covered in detail in this course handout.
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SECTION VIII - DIVISION 1 SUBSECTION B PART UW REQUIREMENTS FOR PRESSURE VESSELS FABRICATED BY WELDING UW-1 SCOPE These rules apply ONLY when producing welded pressure vessels, and should be used as supplemental requirements to the applicable paragraphs in the Introduction and in Subsection A, Part UG. UW-2 SERVICE RESTRICTIONS There are several restrictions placed on welded vessels due to service requirements, such as lethal service, unfired steam boilers, and direct fired vessels. Most of the restrictions have to do with joint design limitations and additional radiography requirements. UW-3 WELDED JOINT CATEGORY Weld joint categories are basically LOCATIONS on the vessel that are subject to differing degrees or criticality of stress when pressurized. They are also used by designers to assist the designer in selecting the proper type of joint and the method of joint examination to satisfy Code requirements. Joint category designations should not be confused with the TYPE of joint required or the AMOUNT of examination of the joint that must be done to satisfy the rules of the Code. For example, a Category A weld may be of Type 1 or 2 or 3, and may have full radiography or no radiography. This will be explained further as we go along. There are 4 basic joint categories - A, B, C, and D. Category A joints are usually the most critical, as they usually require the greatest degree of examination for the efficiency allowed. This follows the basic theory of hoop stress which provides that on any given cylinder, the forces trying to open the vessel longitudinally will be twice as strong as those trying to separate the vessel circumferentially. Therefore, the next category is B, and those welds are usually the circumferential joints. Category C welds connect flanges to nozzles, tubesheets, and flat heads, etc. Category D welds connect nozzles or chambers to the main shell, and, if the Code is properly followed, will usually see the least amount of examination (usually only visual). See the following sketch for a further depiction of weld joint categories and where they are applied.
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UW-5 MATERIALS States that materials are to comply with the UG section of the Code. Non pressure parts welded to a pressure part do not have to be fully identified, provided a satisfactory welding procedure using that material has been tested and qualified. UW-9 DESIGN OF WELDED JOINTS Discusses rules for providing a 3:1 tapered transition between surfaces of butt welds when the offset differs by more than 1/4 of the thickness of the thinner section or 1/8", whichever is less. If formed by weld metal buildup the taper must be checked by PT/MT per UW-42. Longitudinal joints must be staggered by at least 5 times the thickness of the thinner plate, unless RT is applied 4" on each side of the circumferential joint. UW-11 RADIOGRAPHIC AND ULTRASONIC EXAMINATION Now that weld joint Categories and weld joint types are understood, the degree of examination will be discussed. (a) - “full” radiography is discussed in this paragraph. As previously shown, full radiography must be employed if a joint efficiency penalty is to be avoided. This paragraph is saying that all of the following must be Radiographically examined over their full length: ¾
All butt welds in shell and heads of vessel defined as lethal service. Plus nozzles over 10” NPS or 11/8 inch wall.
¾
All butt-welds over 11/2 inch thick or less as defined in UCS 57 etc. Note@ P5 materials it may be all thicknesses.
¾
All butt welds in steam boilers exceeding 50 psi. Plus all nozzles over 10” NPS or 11/8” Wall.
¾
Additionally, other situations may require full radiography for service or excessive thickness that are irrespective of the designers wishes, such as lethal service, unfired steam boilers or butt welds exceeding 1.5".
Note that RT is not normally required for nozzle butt welds that neither exceed NPS 10 nor 1 1/8" wall thickness. (a) (5) (b) - this paragraph gives a lot of people fits. In a nutshell, it really only matters when calculating seamless vessel sections and heads or when the vessel will be stamped “RT-2”. ¾
The paragraph says that all category A and D welds must be fully radiographed along their full length.
¾
All Category A and B welds must be Type 1 or Type 2
¾
Category B and C welds must at least have spot radiography.
If you meet these requirements then what UW-12 (a) says later on is that you select the joint efficiency from Column (a) of Table UW-12 even though you have not done full radiography on all welds. You only use the efficiency in Column 9 (b) of Table UW012 when the requirements have not been met.
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(a) (7) - allows UT to be used for the final closure seam on vessels where entry cannot be made. Absence of RT equipment is not justification for using UT.
CAUTION: There is an ASME Code Case in existence that overrides this rule when applied for thicknesses over 0.5” but does not permit manual ultrasonics. (b) - discusses “spot” radiography, and references UW-52 (c) - discusses “no” radiography (d), (e), and (f) - discuss RT rules for electroslag, electrogas, and inertia/friction drive welding processes. Of course everyone spends so much time trying to understand UW-11 (a) they forget to look at UW-11 (b). For many people working backwards helps clarify the point. UW-11 (b) discusses and defines ‘spot’ radiography. It is clear you may use ‘spot’ (defined in UW-51 as a six inch area of weld) to check the weld quality and when you do the penalty is that it drops you into column (b) of Table UW-12 for Joint Efficiency. In this case the vessel will be stamped RT-3. UW-11 © tells you when no radiography is required and if it is required and you do not do any then it drops you in column 9c) of Table UW-12 for joint efficiency. In this case the vessel would be stamdped RT-4.
UW-12 JOINT EFFICIENCIES UW-3 discussed the CATEGORY of joints that may be used in the vessel. Now we will discuss the TYPE of joint that can be used for each category. Joint types are listed as 1, 2, 3, 4, 5, or 6 in Table UW-12 (shown on a following page). As you can see from this Table, the joint types are listed in the far left hand side with a narrative description of the joint in the next column to the right. The next column lists whatever limitations there are on using that particular type of joint (if any), and the next column states which joint categories that the joint type can be used with. The final 3 columns are the ones that give everyone the most problems - degree of radiographic examination. These are the columns that are used to find the applicable joint efficiency in the formulas in Part UG (remember UG-27, and the formula for shells, which had a factor “E” that had to be found?). This is how to arrive at that number, and will also dictate what stamping will be applied to the vessel (remember UG-116 and the RT-1, 2 , 3 & 4 stamping?). “Full” radiography means that the weld joint has been completely radiographed for it’s full length per UW-51 rules. “Spot” radiography means that only a portion of the weld may be radiographed to assure quality and acceptability of the welder’s production work. “No” radiography means just that - no radiography of the joint has been performed. The tricky part of using this table is that different types of joints and different degrees of radiography may exist on the same vessel, and therefore, several calculations may have to be done using the correct efficiency for the same part of one vessel. Also, most confusing is the fact that the Code Committees state that the design philosophy used is “consider each joint separately”, but “spot” RT requirements are based on cumulative length of welds on the entire vessel. This has always been a little inconsistent in some people’s minds. (Note: In 1986, the Code changed from a “whole vessel” design approach to the current philosophy of “consider each welded joint separately” - some like it, some don’t).
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The degree of radiographic examination of butt welds, the credit given for radiography, and the stress reductions for not radiographing and/or using butt welds is an area greatly misunderstood by many designers. If other than butt welds are used in the pressure vessel or if butt welds are not radiographed the penalty is an increase in the required wall thickness by decreasing the allowable joint efficiency. However, depending upon the service, the kind of material, or thickness of the material butt welds, radiography may become a requirement regardless of the efficiency used in the design calculations. The Table has been previously discussed, and requires very little further explanation, except to state that the “limitations” and “joint category” columns are oftentimes overlooked, and must be consulted when finding the appropriate joint efficiency to be used. Additionally, many people still cannot accept the fact that pressure vessels can be joined with fillet welds, but as this Table states, the restrictions and efficiencies allow their use within limitation. As previously stated, UW-12 (d) is a “tie-in” to UW-11 (a)(5)(b), and pertains to seamless vessel sections and heads that are not radiographed. This is an area NOT listed on the UW-12 Table, and therefore, gives many people headaches. Just remember this - only two efficiencies apply for seamless vessels and heads joined by Category B and C butt welds, either 1.0 for welds that meet the spot RT requirements or 0.85 for those welds that are NOT Radiographed. Easy way to remember any Radiography E = 1.0 No Radiography E = 0.85
UW-12 (f) - requires an efficiency of .80 for the pressure welding processes, except ERW. Separate production weld joint test plates must be made for these processes. (See UW-28).
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UW-13 ATTACHMENT DETAILS Provides rules and sketches for attachment of heads to shells. Discusses tapered transitions in Para (b)(3), and requires their use when joining abutting sections differing greatly in thickness. Requirements for “offset heads” (pressed on heads used primarily in propane tanks) are given, with mandatory PT/MT of the offset prior to attachment of the head (Sketch UW-13.1 (k)).
UW- 14 OPENINGS IN OR ADJACENT TO WELDS Any opening meeting the reinforcement rules can be located in a weld joint; but non-reinforced openings require special radiography rules and requirements, particularly when multiple non-reinforced openings are located in line in a welded joint.
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UW-15 WELDED CONNECTIONS This paragraph basically states that if you comply with one of the full penetration weld sketches shown in UW16, strength calculations are not required. For all other designs, the weld strength must be computed. Telltale holes are required in reinforcing plates, per this paragraph.
UW-16 ATTACHMENT WELDS AT OPENINGS Various Figures are shown and nomenclature is given describing the basic requirements for fillet welds and other weld SIZES (not strength - this was given in UW-15). Many vessel designers have overlooked these requirements and later had to re-weld the fillet welds because of insufficient size. UW-21 FLANGE TO NOZZLE NECK WELDS Minimum dimensions for socket welds (smaller of tn or .7 th ) and slip on flange welds (.7 tn ) are given. FABRICATION UW-26 GENERAL UW-26 through UW-42 cover welding requirements. It is required to use an accepted welding process and to qualify the welding procedure and welder and/or welding operator to the requirements of Section IX - Welding Qualifications - prior to production welding. However, welders not in the employ of the manufacturer can be used, but the manufacturer must add a list of controls to his QC Manual and he must still qualify them per ASME IX, so it really doesn’t matter who pays them. UW-27 WELDING PROCESSES The acceptable welding processes are given, with the arc/gas processes listed in (a) and the pressure processes listed (b). Stud welds can only be used for non-load bearing attachments except for ultra-high strength materials in UHT. Electroslag and electro gas processes can be used with full radiography. UW-28 QUALIFICATION OF WELDING PROCEDURES All pressure parts and non-pressure parts must be joined using a welding procedure qualified in accordance with ASME IX. Non-load bearing attachments using automatic welding do not require procedure qualification. Standard Welding Procedure (SWP’s) as allowed in ASME IX are specifically allowed here. UW-29 TEST OF WELDERS AND WELDING OPERATORS ASME Section IX performance qualification requirements for welders and welding operators are covered in this paragraph for all pressure boundary welds and the attachment of load and non-load carrying attachments to pressure boundary parts. Each manufacturer shall maintain a list of qualified welders showing the date and result of tests, and the letter or number symbol assigned which the welder identifies his work. UW-30 LOWEST TEMPERATURE No welding below 0 degrees F is permitted. Between 0 and 32, the weld area should be heated warm to the hand approximately 60 degrees F. UW-31 CUTTING, FITTING, ALIGNMENT Rules for fit-ups, clamps and tackwelds are given. Tackwelds must be properly prepared or must be removed. If left in the weld, they must be made by a qualified welder. Tack welds made by a subcontractor do not require a partial data report, but must provide certification for such welds. Joint mismatch tolerances are given in Table UW-33, and cannot be exceeded
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UW-33 ALIGNMENT TOLERANCE The alignment tolerances established in Table UW-33 must be followed. Any mismatch WITHIN the tolerance must be faired at a 3:1 taper. If weld metal is used to taper, the PT/MT requirements of UW-42 must also be met. UW-34 SPIN HOLES – Treat as buttwelds. Must be PT/MT tested after completion. UW-35 FINISHED LONGITUDINAL AND CIRCUMFERENTIAL JOINTS Butt welds shall have full fusion and penetration. Surfaces must be relatively free of coarse ripples and valleys that may mask radiography. The term “undercut” is not used - “reduction in thickness due to the welding process” is the term used, and 1/32" or 10% of nominal thickness is the allowable reduction. The footnote clearly states that the intent is NOT to measure this, but if disagreements arise, then its acceptable to measure. Maximum reinforcement of welds is given in a table in UW-35. UW-37 MISCELLANEOUS WELDING REQUIREMENTS Each welder must stamp an identifying number, letter, or symbol at intervals not more than 3 ft. along each completed weld in ferrous materials 1/4" and over or in non-ferrous materials ½" and over, or a record must be kept. UW-39 PEENING Peening is not prohibited, but can’t be used on the root or cap pass of welds unless subsequently PWHT’d. Peening cannot be done in lieu of PWHT. Shot peening must be done after any required NDE and pressure test. UW- 40 PROCEDURES FOR POSTWELD HEAT TREATMENT This paragraph gives basic procedures for conducting PWHT, when required by the various material requirements in Subsection C. Basically, there are 8 ways to conduct PWHT: 1. Heating the whole vessel 2. Heating portions of the vessel in overlap stages 3. Heating Longitudinal joints and then circ. joints locally 4. Heating the vessel internally 5. Heating a band around the vessel containing nozzles 6. Heating the circ. joints in pipe or tube 7. Heating a local area around nozzles or welded attachments 8. Heating of other configurations than those about in (1) - (7) This paragraph also contains the definition for “nominal thickness” as used in UCS-56.
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UW-42 SURFACE WELD METAL BUILDUP Salvaging material by weld build-up to restore metal thickness and for using deposited weld metal to obtain the transition between transition in thicknesses is described in this section. MT or PT is required in these areas. Appendix 6 - Magnetic Particle, Appendix 8 - Liquid Penetrant, both of these appendices reference ASME Section V for procedural details, and both contain acceptance criteria when conducting the examinations. UW-50 NDE OF PNEUMATICALLY TESTED VESSELS All welds around openings and attachment welds greater than 1/4" shall be MT/PT examined prior to air/gas testing vessels. UW-51 RADIOGRAPHIC EXAMINATION OF WELDED JOINTS This section pertains to “full” RT. requirements, as discussed in earlier sections. Section V, Article 2, is required for technique, and personnel must be qualified to a program that is in compliance to SNT-TC-1A. Alternatively, personnel may be qualified and certified to the provisions contained in the ASNT Central Certification Program or in CP-189. The final acceptance of a radiograph is based on meeting the density requirements and the ability to show outline and the applicable hole or wire in the required IQI. A radiography written procedure is not required, as specified in ASME V. The acceptance criteria is set forth in UW-51(b). UW-51(c) discusses rules for Real Time Radioscopic Examination. UW-52 SPOT RADIOGRAPHY Spot RT is only a quality tool based on a random sample, and may allow defective welding to exist that will be in accordance to code rules. This is very hard for people to understand, particularly when the vessel is radiographed 10 years later in the field, and this “bad” welding is found. The rules state that :
• One spot for each 50 ft. of weld • One spot for each welder or operator • Locations to be chosen by the Inspector, except when he cannot make the choice due to absence • Acceptance standards different than UW-51 UW-53 ULTRASONIC EXAMINATION Ultrasonic examination can be used as a substitute for radiography to examine closure seams where meaningful radiographs cannot be obtained. UT is also required as a supplement to radiography for some electroslag and electrogas welds. Appendix 12 establishes the acceptance criteria for ultrasonic examinations and references Section V, Article 5, for technique. Written procedures are required for ultrasonic examinations.
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SECTION VIII DIVISION 1 SUBSECTION C-REQUIREMENTS PERTAINING TO CLASSES OF MATERIALS PART UCS-REQUIREMENTS FOR PRESSURE VESSELS CONSTRUCTED OF CARBON AND LOW-ALLOY STEELS GENERAL UCS-1 SCOPE The rules in PART UCS are applicable to pressure vessels and pressure vessel parts constructed of carbon and low-alloy steels. It is to be noted that the materials shall be limited to those listed in Table UCS-23 of ASME Section II Part D. Part UCS should be used in combination with other materials covered in other sections of Section VIII - Division 1. PART UCS is relatively straightforward (except for impact testing) and does not usually create many problems for the reader. MATERIALS UCS-5 GENERAL Carbon or low alloy steel having a carbon content greater than .35% shall not be welded or be oxygen cut. UCS-6 STEEL PLATES Structural steels can be used for pressure retaining materials, but are limited to SA-36, SA/CSA G40.21 38W and SA-283 Grades A, B, C, and D with the following restrictions: 1. The vessel can not contain a lethal substance; 2. Not allowed in unfired steam boilers; 3. Shells, heads, and nozzles the plate thickness for high-strength welding is limited to 5/8”. UCS-11 NUTS AND WASHERS These are very simple, straightforward requirements, but are oftentimes overlooked by Code users. Note the threading requirements in (c). UCS-27 SHELLS MADE FROM PIPE Seamless pipe may be used for shells and/or nozzles in a pressure vessel. ERW pipe is limited in diameter to 30 inches, if the material is produced by the open-hearth, basic oxygen, or electric-furnace methods. UCS-56 REQUIREMENTS FOR POSTWELD HEAT TREATMENT Welding procedures must be qualified with the correct PWHT time/temperature per ASME IX before applying these requirements. The Tables shown provide EXEMPTIONS to mandatory PWHT - unless exempted, ALL carbon/low alloy vessels shall be PWHT’d. If PWHT is a service requirement, the exemptions do not apply. Table UCS-56.1 allows an increase in holding time for a reduction in temperature. Provides clear rules for the initial temperature, the up/down heating rates, and the allowed cooling after PWHT. Allows some limited base metal repairs after PWHT, but contractual arrangements usually preclude this from happening.
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UCS-57 RADIOGRAPHIC EXAMINATION Table UCS-57 is an overriding requirement that mandates full radiography of butt welds based on thickness and material REGARDLESS of service or joint efficiency. Again, this paragraph takes precedence over the other requirements, and must be consulted when constructing carbon/low alloy vessels.
TABLE UCS-57 THICKNESS ABOVE WHICH FULL RADIOGRAPHIC EXAMINATION OF BUTT WELDED JOINTS IS MANDATORY
___________________________________________________________________________________ P-NO. & GR. NO. NOMINAL THICKNESS ABOVE CLASSIFICATION WHICH BUTT WELDED JOINTS OF MATERIAL SHALL BE FULLY RADIOGRAPHED, IN. ___________________________________________________________________________________ 1 GR. 1, 2, 3 1 1/4 3 GR. 1, 2, 3 3/4 4 GR. 1, 2 5/8 5 GR. 1, 2 0 9A GR. 1 5/8 9B GR. 1 5/8 10A GR. 1 3/4 10B GR. 2 5/8 10C GR. 1 5/8 10F GR. 6 3/4 ___________________________________________________________________________________
LOW TEMPERATURE OPERATION UCS-66 MATERIALS This paragraph deals and the accompanying Tables are probably the most misunderstood and hardest to apply. Basically, the idea here is not about when you MUST impact test your materials, but how to GET OUT OF impact testing your materials. This is reasonable, because if your base metal must be impact tested, then: • • •
the weld metal must be impact tested (or be bought with results listed) the welding procedures must be impact tested upon qualification the production welds must be impact tested
As one can imagine, this is quite a lengthy and involved process, and can be quite expensive if not performed correctly. Therefore, it is in the fabricator’s best interest NOT to run impact tests if it can be avoided. Fig UCS-66 lists exemptions for various grades and types of materials. The key to using this chart is to find the Curve assigned to the specific material in question. If the material thickness and corresponding temperature are ON or ABOVE the assigned curve, the material is exempted from impact testing. If the point of intersection falls below the curve, the material must be impact tested.
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If the material must be impact tested per Fig. UCS-66 then another “out” is provided in Fig. UCS-66.1. This graph allows the designer to “over design” the vessel by making it more thick, and thereby increasing the safety factor. This then allows for a reduction in the minimum design metal temperature without having to perform impact testing. The flow chart provided in Fig. UCS-66.2 explains all this in a more clear-cut fashion. UCS-67 As previously stated, if the base metal requires impact tests, then so too does the welding procedure. Additionally, rules are given for welds made without the use of filler metal. UCS-79 FORMING SHELL SECTIONS AND HEADS When rolling or forming metal, the fibers will expand as the metal is formed, but residual stresses will be “locked in” if PWHT is not performed. This is especially critical on items rolled from thick materials into a small radius. Therefore, this paragraph gives rules for when PWHT will be required. UCS-85 HEAT TREATMENT Contrary to some beliefs, this paragraph only applies when the vessel manufacturer completes the material specification heat treatments. It does not apply to regular PWHT requirements.
MANDATORY APPENDICES The Mandatory Appendices are VERY important and should not be overlooked. In particular, the appendices that will usually be consulted most often are: • • • • • •
App. 1 - Supplemental Design Formulas App. 3 - Definitions App. 4 - Rounded Indication Charts (porosity) for RT acceptance App. 6 - Magnetic Particle methods App. 8 - Liquid Penetrant methods App. 12 - Ultrasonic examination of welds
Remember, all of these appendices are MANDATORY, and must be applied when referenced by the main body of the Code. Many times users forget about these requirements stuck “way in the back”, but they must still be followed, obscure as they are.
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Open Book Practice Questions ASME SECTION VIII, DIV. 1 PRACTICE QUESTIONS
1.
An item, which can not be found on a mill test report for material, is: A. B. C. D.
2.
What is the minimum thickness of plate that can be used in the shell or head of a pressure vessel? A. B. C. D.
3.
ASME Section I ASME Section VIII Engineering Guides and General Specifications API – Pressure Vessels
Which of the following types of heads will normally require the greatest wall thickness? A. B. C. D.
6.
Approved by the Inspector Accepted by the engineering department Approved by the pressure vessel engineer Less than 2” in depth
Design and fabrication of power boilers is in accordance with which of the following: A. B. C. D.
5.
1/4” 3/16” 1/16” There is no minimum thickness
Surface defects in materials may be repaired when: A. B. C. D.
4.
SA Specification number Heat number Allowable stress value Chemical composition
2:1 elliptical head Dished torispherical Hemispherical head Flat head
Design and fabrication of pressure vessels shall be in accordance with which of the following: A. B. C. D.
ASME Section I ASME Section VIII Engineering Guides and General Specifications API – Pressure Vessels Section IV
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7.
A nozzle was originally PWHT when the vessel was constructed because of lethal service application. The material was SA-516 Gr 70 with a thickness of 1/8 in. A full thickness repair is made. The minimum holding time is _____ hours. A. B. C. D.
8.
1/2 hour 1/4 hour 1 hour 4 hours
The maximum deviation from the true circular form of a vessel shall not exceed: A. B. C. D.
2% 1% 10 % of the nominal inside diameter 5%
9.
DELETED
10.
For non-ferrous and ductile cast iron, a casting quality factor of _________ maximum should be applied. A. B. C. D.
11.
Which of the following liquid penetrant indications would be unacceptable? A. B. C. D.
12.
Relevant linear indications Relevant rounded indications greater than 3/16” Four or more relevant rounded indications in a line separated by 1/16” or less All of the above
According to the ASME Code, Section VIII, the metal temperature during pneumatic test shall be at least _____ above the minimum design metal temperature to minimize the risk of brittle fracture. A. B. C. D.
13.
80% 90% 100% 70%
20°F 30°F 40°F 50°F
The maximum postweld heat treatment cooling rate required for a 1 1/2inch, SA-516 Gr. 70 material, flush patch installed as part of a repair to a pressure vessel is: A. B. C. D.
333°F/hr 500°F/hr 267°F/hr 400°F/hr
130
14.
Ultrasonic examination may be substituted for radiography when: A. B. C. D.
15.
Radiographic equipment is not available Final closure seam of a vessel does not permit interpretable radiographs Required by the designer Final closure seam exceeds 2-in. thickness
If a vessel is so large that it must be PWHT in more than one heat, what is the minimum overlap in the furnace? A. B. C. D.
5’ 10’ 15’ 50’
16.
What documentation is required for a plate of SA-516 Gr. 70 material to be used in a repair procedure? A. A certified material test report B. A certificate of conformity C. A material test report D. A certified certificate of compliance
17.
A vessel nameplate is stamped RT 4 this indicates that: A. B. C. D.
18.
What is the maximum allowable working pressure of a vessel? A. B. C. D.
19.
The vessel’s design pressure The vessel’s design pressure plus the static head The maximum gauge pressure permitted at the bottom of the vessel, which includes hydrostatic head The maximum gauge pressure permitted at the top of the vessel
The symbol “HT” on a pressure vessel nameplate indicates: A. B. C. D.
20.
Only part of the complete vessel has satisfied the radiographic requirements of UW-11(a) The complete vessel satisfies the requirements of UW-11(a)(5) and the spot radiography requirements of UW-11(a)(5)(b) have been applied All butt welds have been 100% radiographed All butt welds have been spot radiographed per UW-52
Vessel was hammer tested Whole vessel was Post Weld Heat Treated Vessel is good for high temperature Vessel was hydrotested
If an additional ASME Code nameplate (in addition to the original nameplate) is installed on the skirt, jacket or other permanent attachment to the vessel, how should the nameplate be marked? A. B. C. D.
SAMPLE DUPLICATE ADDITIONAL EXTRA
131
21.
A welded carbon steel joint has an MDMT that is colder than 120°F, at what governing thickness must impact tested materials always be used? A. B. C. D.
22
The Manufacturer’s Data report for a shop fabricated single chamber pressure vessel is: A. B. C. D.
23.
> 4 in. < 2 in. 6 in. 3 in.
U-1 U-3 U-1A U-2
An isolated rounded indication is found in a 3/4 inch thick weld. The maximum acceptable size is: A. B. C. D.
0.250 in. 0.156 in. 0.031 in. 0.568 in.
24.
What is the minimum size for a liquid pressure relief valve? A. NPS 3/4 B. NPS 1/4 C. NPS 1/2 D. NPS 1 1/2
25.
If a user signs a contract to build a pressure vessel on May 1, 1997, what edition and addenda of the Code would be mandatory? A. B. C. D.
26.
Which of the following is not considered a piping component and therefore not exempt from the scope of the Code? A. B. C. D.
27.
1995 Edition, Addenda 1996 1995 Edition, Addenda 1995 1995 Edition, No Addenda The date of the edition when the vessel is completed
Pipe Fittings Valves Product storage vessel
Which of the following pressure vessel categories are exempt from inspection by an Authorized Inspector during construction? A. B. C. D.
Those having a volume of 5 cu ft and design pressure of 250 PSI Those having a volume of 3 cu ft and design pressure of 400 PSI Those having a volume of 1.2 cu ft and design pressure of 900 PSI Those having a volume of 1.5 cu ft and design pressure of 605 PSI
132
28. 29.
Deleted Who establishes the design requirements for a new pressure vessel? A. B. C. D.
30.
Which of the following are classified as service restrictions under Section VIII, Division 1? A. B. C. D.
31.
3 4 1 None of the above
Longitudinal welded joints within the main shell or nozzles are Category _____. A. B. C. D.
35.
Spot Fully Partially None of the above
Pressure vessels subject to direct firing do not permit what type weld joints for Category A and B joints? A. B. C. D.
34.
All Above 5/8 in. Above 1 1/4 in. Above 1 in.
Butt welds in vessels that contain lethal substances are required to be _____ radiographed. A. B. C. D.
33.
Lethal Vessels operating below certain temperatures Unfired steam boilers exceeding 50 PSI All of the above
Vessels containing lethal substances are required to be postweld heat treated in what thicknesses? A. B. C. D.
32.
Manufacturer Design firm The user or his designated agent ASME
C D A B
The temperature used when calculating the required thickness of a shell or head is known as the _____ design temperature. A. B. C. D.
Marginal Minimum Maximum Optimal
133
36.
The acronym MDMT stands for _____. A. B. C. D.
37.
Which carbon low-alloy material listed below can be exempted from impact testing per UG-84? A. B. C. D.
38.
P-No. 8, 1/2 in. P-No. 1, Group 3, Curve E, 1 in. P-No. 1, Group 1 or 2, Curve C, not exceeding 2 in. P-No. 1, Group 1 or 2, Curve D, not exceeding 1 in.
P-No. 1, Group 1 or 2 material listed on Curve A is exempted from impact testing if it does not exceed _____. A. B. C. D.
39.
Major Design Method Theory Minimum Design Metal Temperature Maximum Design Metal Temperature Minimum Design Material Temperature
1 in. 2 in. 1/2 in. 9/16 in.
Loadings to be considered in designing a pressure vessel are: A. B. C. D.
Internal and external pressure Wind Snow All of the above
40.
If a steel casting has a weld seam with a joint efficiency of 0.70 and is examined in accordance with the minimum requirements of the material specification, what would be the appropriate “E” value to use when calculating the required thickness of the casting? A. 0.70 B. 1.00 C. 0.80 D. 1.00
41.
You are calculating the required thickness of a cylindrical shell under internal pressure. The inside radius including corrosion allowance is 24 in. The corrosion allowance is 0.125 in. What inside radius would you use? A. B. C. D.
42.
24 in. 24.125 in. 48.50 in. 26 in.
A full size Charpy impact test specimen has a dimension of _____. A. B. C. D.
10 mm x 11 mm 0.394 in. x 0.394 in. 0.394 in. x 0.393 in. 0.262 in. x 0.394
134
43.
What is done when full size impact test specimens cannot be obtained? A. B. C. D.
44.
You are to impact test a material, which is 1 in. thick, and has a minimum specified yield strength of 55 ksi. What is the required average for the 3 specimens? A. B. C. D.
45.
Full radiography in accordance with UW-51 Spot radiography in accordance with UW-52 Partial radiography in accordance with UW-53 Spot radiography in accordance with UW-51
Ultrasonic examination in accordance with UW-53 may be substituted for radiography for what condition? A. B. C. D.
47.
20 ft-lbf 15 ft-lbf 30 ft-lbf 50 ft-lbf
When full radiography is required of the Category A and D butt welds, the Category B and C butt welds shall as a minimum meet the requirements for _____. A. B. C. D.
46.
Estimate the ft-lbf that could be obtained Refer to standard tables Subsize specimens are to be used Use a drop weight test as an alternative
It is never permitted When radiographic equipment is not available For the final closure seam if the construction does not permit interpretable radiographs For longitudinal welded seams when they are in excess of 1 1/4 in.
Joint efficiencies for welded joints shall be in accordance with _____. A. B. C. D.
Subsection C UW-11(a)(5)(b) Paragraph UW-12(d) Table UW-12
48.
When a value of E is taken from column (a) of Table UW-12 what are the values for Type 1 and Type 2 welded joints? A. 1.00 & 0.90 B. 1.00 & 0.85 C. 0.85 & 0.70 D. 0.85 & 0.65
49.
What would be the value of E for a butt-welded longitudinal joint welded from both sides on pipe? A. B. C. D.
1.00 0.85 0.45 0.60
135
50.
Material for pressure parts shall comply with the requirements for materials given in ___. A. B. C. D.
UG-4 thru UG-15 UG-93 UW-15 UG-15 thru UG-27
51.
Material for non-pressure parts, which are welded to the vessel _____ prior to being used in the vessel. A. Must be tested using PT or MT B. Must be proven of weldable quality C. Must be ultrasonic thickness tested D. Must be pressure tested
52.
For material which is not identifiable in accordance with UG-10, UG-11, UG-15, or UG-93, proof of weldable quality can be demonstrated by: A. B. C. D.
53.
When adjacent abutting sections differ in thickness by more than the lesser of one-fourth the thickness of the thinner section of 1/8 in. what must be done? A. B. C. D.
54.
Five times the minimum thickness of the plate Five times the thickness of the thicker plate Six inches Four times the thickness of the thicker plate
Full radiography is required for which of the following butt welds: A. B. C. D.
56.
Provide a tapered transition of at least 3:1 Make six inch radiograph Nothing Provide a tapered transition of at least 4:1
Longitudinal welded joints of adjacent courses shall be separated by at least _____ to avoid additional radiographic requirements. A. B. C. D.
55.
Using weld material which meets the requirements of an SFA specification Preparing a butt joint test coupon from each piece of non-identified material and making guided bend tests Satisfactory qualification of the welding procedure Both 2 and 3 above
In shells and heads of vessels containing lethal substances In shells and heads of unfired steam boilers having design pressures less than 50 PSI In all vessels where the least nominal thickness exceeds 1 in. None of the above
Category B and C butt welds in nozzles and communicating chambers never require radiographic examination provided they neither exceed: A. B. C. D.
NPS 10 1 1/8 in. NPS 6 NPS 10 nor 1 1/8 in.
136
57.
What formula would be used to determine the internal design pressure for a circular unstayed flat cover? A. B. C. D.
58.
The maximum inside diameter of a welded opening in a vessel head of 1/2 in. thickness, which does not require a reinforcement calculation, is _____. A. B. C. D.
59.
UG-34, (1) UG-34, (3) UG-32 (e) UG-34, (7)
3 1/2 in. 6 in. 3tr 2 3/8 in.
No two isolated unreinforced openings shall have their centers closer to each other than: A. B. C. D.
Five times their radii The sum of their diameters 3d 12 in.
60.
When calculating the required thickness of a seamless nozzle for a reinforcement problem and the nozzle is made from ERW pipe what efficiency would be used? A. 0.65 B. 0.90 C. 1.00 D. 0.85
61.
The allowable stresses of the nozzle and shell are 17500 and 13800 respectively, what would be the maximum strength reduction factor? A. B. C. D.
62.
What happens to the formula for A in Figure UG-37.1 when fr1 = 1.0? A. B. C. D.
63.
1.00 1.268 0.788 0.60
Nothing Everything after the plus (+) sign is equal to 0 (1 – fr1) = 1 F becomes 0.5
When calculating the limits of reinforcement normal to the surface and there is no reinforcing element installed the value of _____ is used for te. A. B. C. D.
1.0 0.5 0 32
137
64.
The governing limit of reinforcement parallel to the vessel surface is the larger of: A. B. C. D.
65.
What is the set pressure tolerance for a pressure relief device set at 350 PSI? A. B. C. D.
66.
R or Dn + t D or Rn + tn + t d or Rn + tn + t 1 or 3 above
+/- 2 PSI +/- 30 PSI +/- 10.5 PSI +/- 15%
A pressure vessel, which is 50 in. inside diameter, has a flat spot. What is the maximum permitted out of roundness at this location? A. B. C. D.
2.00 in. 1.00 in. 0.750 in. 0.500 in.
67.
The formula that is to be used calculating thickness and pressure for cylindrical shells subject to circumferential stress is found in Appendix _____. A. 1-1, formula 2 B. 1-1, formula 1 C. 1-4, formula 3 D. 1-8, formula 1
68.
When calculating the required thickness for external pressure of a shell factor B must be determined. Considering the Do / t ratio what are the three parameters required to determine the factor? A. Material, stress, temperature B. Factor A, modulus of elasticity, material C. Factor A, material, and the design temperature D. Thickness, factor A, design temperature
69.
A nozzle similar to Figure UW-16.1, sketch (e) has a shell thickness of 9/16 in. and a nozzle thickness of 3/4 in., what is the value of tmin? A. B. C. D.
70
9/16 in. 1/2 in. 1 1/2 in. 1 in.
Two shells are to be butt welded together to form a circumferential joint. Each shell is 1” thick. What is the maximum permitted offset? A. B. C. D.
3/16 in. 1/4 t 1/8 in. 3/4 in.
138
71.
Pressure vessels with a volume of 1 1/2 cu ft and 600 PSI design pressure can be exempted from Authorized Inspection provided they are not to be _____. A. B. C. D.
72.
If a head is formed with a flattened spot what is the C factor that must be used? A. B. C. D.
73.
981 818 1730 1308
The temperature of the furnace shall not exceed _____ oF at the time the vessel or part is placed in it. A. B. C. D.
77.
Maximum NPS 1/4 tap Maximum NPS 2 Maximum NPS 1/2 tap 2 in.
A pressure vessel is to be hydrostatically tested in accordance with the ASME Code. The MAWP is 654 PSI. Sd = 8600 PSI and St = 17500 PSI. What is the minimum required test pressure? A. B. C. D.
76.
L / Do ratio D / D ratio Do / t ratio t / Do ratio
Reinforcing plates and saddles of nozzles attached to the outside of a vessel shall be provided with at least one telltale hole _____ in size. A. B. C. D.
75.
0.33m 0.25 1.2 0.17
When performing thickness calculations for shells and tubes under external pressure what value must first be determined? A. B. C. D.
74.
Provided with quick actuating closures Used for water service only Used for steam service less than 400oF Used for noncorrosive service
600 500 800 300
Ultrasonic examination of welds shall be performed using methods described in _____ of ASME Code Section V. A. B. C. D.
Article 1 Article 4 Article 5 Article 23
139
78.
Ellipsoidal heads of what ratio are calculated using the formula in UG-32? A. B. C. D.
79.
3:1 2:1.2 4:1 2:1
It is recommended that no welding be performed when the metal temperature is lower than _____oF. A. B. C. D.
32 60 0 5
SECTION VIII, SUBSECTION A QUESTIONS 80.
If a user signs a contract to build a pressure vessel on January 1, 1997, what edition of the Code would be applicable as a minimum? A. B. C. D.
81.
Which of the following is not considered a piping component and therefore not exempt from the scope of the Code? A. B. C. D.
82.
Those having a volume of 5 cu ft and design pressure of 250 PSI Those having a volume of 3 cu ft and design pressure of 400 PSI Those having a volume of 1.2 cu ft and design pressure of 900 PSI Those having a volume of 1.5 cu ft and design pressure of 605 PSI
Pressure vessels with a volume of 1 1/2 cu ft and 600 PSI design pressure can be exempted from Authorized Inspection provided they are not required by the rules to be _______. A. B. C. D.
84.
Pipe Fittings Valves Product storage vessel
Which of the following pressure vessel categories are exempt from inspection by an Authorized Inspector during construction? A. B. C. D.
83.
1995 Edition, Addenda 1996 1995 Edition, Addenda 1995 1995 Edition, no Addenda The date of the edition when the vessel is completed
Provided with quick actuating closures Used for water service only Used for steam service less than 400oF Used for noncorrosive service
Who establishes the design requirements for a new pressure vessel? A. B. C. D.
Manufacturer Design firm The user or his designated agent ASME
140
85.
What is the date of the acceptable edition of SNT-TC-1A to be used for new construction? A. B. C. D.
86.
1992 1984 1996 1975
Material subject to stress due to pressure shall conform to _____. A. B. C. D.
ASTM, latest edition Section VIII, Division 1, Subsection B Section VIII, Division 1, Subsection C Section II
87.
Which of the following parts are not considered to be subject to stress due to pressure? A. Reinforcing pads B. Legs of the vessel C. Shells D. Stiffening rings
88.
The term plate is considered to also include: A. B. C. D.
89.
Welding materials only have to comply with the requirements for _____ to be used in the manufacture of a pressure vessel. A. B. C. D.
90.
Carbon content Proper chemistry Correct length Marking or tagging
The Code paragraph that allows using of a material that is not fully identified with a specification permitted by the Code is _____. A. B. C. D.
91.
Strip and sheet Lugs Skirts Baffles
UG-77 UG-10 Appendix 3 UG-11
When no specific exceptions apply, the minimum thickness of the heat transfer plates of plate type heat exchangers is _____. A. B. C. D.
1/4 in. No minimum 1/16 in. 3/8 in.
141
92.
Plate material may be used at full design pressure when the mill undertolerance does not exceed _____. A. B. C. D.
93.
Pipe is ordered by its nominal thickness, where would this manufacturing undertolerance limits be found? A. B. C. D.
94.
12 1/2% 18% The value established by the owner The smaller of 0.01 in. or 6% of the ordered thickness
In the owners purchasing specification In Section VIII, Division 1 In Section II, Part D In the pipe and tube specifications listed in Subsection C
The dimensional symbols used in the design formulas throughout the Code represent dimensions in the _____ condition. A. B. C. D.
Corroded As built As designed Normally desirable
95.
The temperature used when calculating the required thickness of a shell or head is known as the _____ design temperature. A. Marginal B. Minimum C. Maximum D. Optimal
96.
The acronym MDMT stands for _____. A. B. C. D.
97.
Which carbon low-alloy material listed below can be exempted from impact testing per UG-84? A. B. C. D.
98.
Major Design Method Theory Minimum Design Metal Temperature Maximum Design Metal Temperature Minimum Design Material Temperature
P-No. 8, 1/2 in. P-No. 1, Group 3, Curve E, 1 in. P-No. 1, Group 1 or 2, Curve C, not exceeding 2 in. P-No. 1, Group 1 or 2, Curve D, not exceeding 1 in.
P-No. 1, Group 1 or 2 material listed on Curve A is exempted from impact testing if it does not exceed _____. A. 1 in. B. 2 in. C. 1/2 in. D. 9/16 in.
142
99.
Loadings to be considered in designing a pressure vessel are: A. B. C. D.
100.
If a steel casting has a weld seam with a joint efficiency of 0.70 and is examined in accordance with the minimum requirements of the material specification what would be the appropriate “E” value to use when calculating the required thickness of the casting? A. B. C. D.
101.
0.85 0.60 1.00 0.80
When performing thickness calculations for shells and tubes under external pressure what value must first be determined? A. B. C. D.
104.
24 in. 24.125 in. 48.50 in. 26 in.
What is the weld joint efficiency to be used on an NPS 12 nozzle of P-No. 1 material butt welded to a 3/4 in. shell, which has a backing strip, left in place and is spot radiographed? A. B. C. D.
103.
0.70 1.00 0.80 1.00
You are calculating the required thickness of a cylindrical shell under internal pressure. The inside radius including corrosion allowance is 24 in. The corrosion allowance is 0.125 in. What inside radius would you use? A. B. C. D.
102.
Internal and external pressure Wind Snow All of the above
L / Do ratio D / D ratio Do / t ratio t / Do ratio
You are calculating the required thickness for external pressure of a shell having a Do / t ratio of 66. The actual L / Do ratio is 75. At what value would you enter Figure G on the L / Do ordinate? A. B. C. D.
50 75 0.50 0.20
143
105.
When calculating the required thickness for external pressure of a shell factor B must be determined. Considering the Do / t ratio what are the three parameters required to determine the factor? A. B. C. D.
106.
The minimum required thickness of a formed head with pressure on the concave side is the thinnest point after _____. A. B. C. D.
107.
D.
10% of outside crown radius 6% of the inside crown radius 2.88 in. 6% of the inside head diameter
If a head is formed with a flattened spot what is the C factor that must be used? A. B. C. D.
111.
The minor axis equals one-half the inside head diameter Half a sphere Half the minor axis (inside depth of the head minus the skirt) equals one-fourth of the outside head diameter Half the minor axis (inside depth of the head minus the skirt) equals one-fourth of the inside head diameter
The UG-32 formula for determining minimum thickness of a torispherical head considers what specific knuckle radius? A. B. C. D.
110.
3:1 2:1.2 4:1 2:1
The semiellipsoidal form is defined as: A. B. C.
109.
Cutting the plate Forming Heat treating Welding
Ellipsoidal heads of what ratio are calculated using the formula in UG-32? A. B. C. D.
108.
Material, stress, temperature Factor A, modulus of elasticity, material Factor A, material, and the design temperature Thickness, factor A, design temperature
0.33m 0.25 1.2 0.17
An unstayed flat head similar to Figure UG-34(f) is made up of two pieces welded together using a Type 2 butt joint, which is only visually examined. What joint efficiency would be applicable? A. B. C. D.
0.65 0.80 0.90 1.00
144
112.
A seamless unstayed flat head similar to Figure UG-34 (b)(1) is welded to a shell using a butt weld. What efficiency would be used to calculate required thickness if there was no radiography performed on the circumferential weld? A. B. C. D.
113.
What formula would be used to determine the internal design pressure for a circular unstayed flat cover? A. B. C. D.
114.
Five times their radii The sum of their diameters 3d 12 in.
When calculating the required thickness of a seamless nozzle for a reinforcement problem and the nozzle is made from ERW pipe what efficiency would be used? A. B. C. D.
117.
3 1/2 in. 6 in. 3tr 2 3/8 in.
No two isolated unreinforced openings shall have their centers closer to each other than: A. B. C. D.
116.
UG-34, (1) UG-34, (3) UG-32,(e) UG-34, (7)
The maximum inside diameter of a welded opening in a vessel head of 1/2 in. thickness, which does not require a reinforcement calculation, is _____. A. B. C. D.
115.
1.00 0.55 0.85 0.90
0.65 0.90 1.00 0.85
The allowable stresses of the nozzle and shell are 17500 and 13800 respectively, what would be the maximum strength reduction factor? A. B. C. D.
1.00 1.268 0.788 0.60
145
118.
119.
What happens to the formula for A in Figure UG-37.1 when fr1 = 1.0? A. Nothing B. Everything after the plus (+) sign is equal to 0 C. (1 – fr1) = 1 D. F becomes 0.5 When calculating the limits of reinforcement normal to the surface and there is no reinforcing element installed the value of _____ is used for te. A. B. C. D.
120.
The governing limit of reinforcement parallel to the vessel surface is the larger of: A. B. C. D.
121.
Machined, chamfered Chamfered, rounded Avoided, rounded Tapered, rounded
Material traceability can be maintained by several methods. One of those is: A. B. C. D.
124.
Bolted flange material Split reinforcing elements Bolting Stiffener
Exposed inside edges shall be _____ or _____. A. B. C. D.
123.
R or Dn + t D or Rn + tn + t d or Rn + tn + t 1 or 3 above
With the exception of studding outlet flanges _____ within the limits of reinforcement shall not be considered to have reinforcing value. A. B. C. D.
122.
1.0 0.5 0 32
Transfer of the original identification markings Tell the QC Inspector A coded marking Marking the ASTM material specification on the material
Where service conditions prohibit the use of die-stamping for material identification, which of the following is a substitute? A. B. C. D.
Magic marker vibro etching color coding All of the above
146
125.
When plates are rolled to form a longitudinal joint for a cylindrical shell they are first _____ to avoid flat spots along the finished joint. A. B. C. D.
126.
When a shell section is welded into a vessel operating under internal pressure the difference between the maximum and minimum inside diameters at any cross section shall not exceed _____ of the nominal diameter at the cross section being considered. A. B. C. D.
127.
Crimped Beveled Radiographed Visually inspected
2% Square root of Rt 5/8% 1%
When pressure parts extend over pressure retaining welds the welds shall be _____ for the portion of the weld to be covered. A. B. C. D.
Left as is Ground flush Notched Radiographed
128.
Non pressure parts extending over pressure retaining welds shall be _____ or _____ to clear those welds A. Ground flush, notched or coped B. Machined, beveled C. Radiographed, MT D. MT, PT
129.
Each set of impact test specimens shall consist of _____ specimens. A. B. C. D.
130.
A full size Charpy impact test specimen has a dimension of _____. A. B. C. D.
131.
One Two sets of three Four Three
10 mm x 11 mm 0.394 in. x 0.394 in. 0.394 in. x 0.393 in. 0.262 in. x 0.394 in.
What is done when full size impact test specimens cannot be obtained? A. B. C. D.
Estimate the ft-lbf that could be obtained Refer to standard tables Subsize specimens are to be used Use a drop weight test as an alternative
147
132.
You are to impact test a material, which is 1 in. thick, and has a minimum specified yield strength of 55 ksi. What is the ft-lbf requirement? A. B. C. D.
133.
The acceptance criteria for materials having a specified minimum tensile strength of 95,000 PSI or greater is based on the _____. A. B. C. D.
134.
25oF 15oF 0oF 10oF
T G NPT N
Duties of the Inspector include which of the following: A. B. C. D.
138.
A _____
When the plate material manufacturer does not performed the heat treatments required by the material specification a letter _____ is marked next to the material specification designation on the plate. A. B. C. D.
137.
30oF 40oF 80oF 15oF
The material being impact tested has a minimum specified yield strength of 35 ksi. temperature difference is permitted. A. B. C. D.
136.
The ratio of stresses to the ft-lbf value Maximum lateral expansion opposite the notch Minimum lateral expansion opposite the notch Charpy V Notch values taken
A subsize impact test specimen must be used which is 0.118 in. thick. What temperature reduction would be taken? A. B. C. D.
135.
20 ft-lbf 15 ft-lbf 30 ft-lbf 50 ft-lbf
Verifying that welding procedures and welders have been qualified Verifying that heat treatments have been properly performed Verifying that required nondestructive examinations have been performed All of the above.
_____ materials are the only product form that must have a material test report provided. A. B. C. D.
Plate Pipe Casting Forging
148
139.
A 1 in. shell is to be welded to a tube sheet 3 in. thick using a corner joint per Figure UW-13.2. What must be done to the weld preparation in the flat plate prior to welding? A. B. C. D.
140.
Before welding a nozzle into a shell the Inspector must: A. B. C. D.
141.
P = 1.5 x MAWP P = 1.25 x MAWP x St /Sd P = 1.3 x MAWP x St / Sd P = 3 x Design Pressure
A special hydrostatic pressure test is permissible which utilizes the _____ thickness including corrosion allowance and the allowable stress at _____ temperature multiplied by 1 1/2. A. B. C. D.
145.
Maximum internal or external pressure including static head Maximum internal or external pressure excluding static head Maximum pressure at the bottom of the part Average maximum pressure between the top and bottom of the vessel
The formula for hydrostatic testing is: A. B. C. D.
144.
Maximum internal or external pressure including static head Maximum internal or external pressure excluding static head Maximum pressure at the top of the vessel excluding any static head Average maximum pressure between the top and bottom of the vessel
The maximum allowable working pressure for a vessel part is: A. B. C. D.
143.
Make certain the nozzle fits the vessel curvature Verify the identification markings Examine the material for imperfections All of the above
The maximum allowable working pressure for a complete vessel is: A. B. C. D.
142.
Visually examine the entire surface UT 10% of the circumference Examined by either MT or PT Examined by random radiography
Nominal, test Minimum, design Postulated, 100oF Assumed, test
When a hydrostatic test exceeds the test pressure either accidentally or intentionally what must be done? A. B. C. D.
The vessel is rejected Have an engineer perform a stress analysis Stop the test and repeat Must be inspected by the Inspector for visible distortion
149
146.
When hydrostatic testing a pressure vessel which has more than one chamber, each chamber _____. A. B. C. D.
147.
Single wall pressure vessels designed for vacuum service only shall be hydrostatic pressure tested at not less than _____. A. B. C. D.
148.
Shall be tested using the differential in any adjacent chamber Shall be tested without pressure in any adjacent chamber Shall be tested with the full test pressure in all other chambers Shall be tested using a combined hydrostatic pneumatic test
1.3 times the difference between normal atmospheric pressure and the minimum design internal absolute pressure 30” of water gage Two times the difference between normal atmospheric pressure and the minimum design internal absolute pressure 15 PSI
The required visual inspection after application of the hydrostatic test pressure is conducted at not less than _____. A. B. C. D.
Four-fifths the test pressure The MAWP to be stamped on the vessel The test pressure divided by 1.3 Ten percent above operating pressure
149.
What type liquids may be used for hydrostatic testing? A. Water B. Any nonhazardous liquid if below its boiling point o C. Combustible liquids having a flash point less than 110 F D. All of the above
150.
The recommended test temperature above the MDMT for hydrostatic testing in accordance with the ASME Code is _____. A. B. C. D.
10oF 30oF 20oF 50oF
151.
The hydrostatic test pressure shall be applied to a filled pressure vessel when _____. A. The vessel and its contents are at about the same temperature B. The Inspector believes it should be applied C. Required by the test procedure D. All personnel are at a safe distance from the test site
152.
What is the maximum metal temperature that need not be exceeded during a hydrostatic pressure test? A. B. C. D.
70oF 30oF above the MDMT 120oF 10oF above the Design temperature
150
153.
A small liquid relief valve installed on the vessel set to _____ times the hydrostatic test pressure is a recommended precaution to prevent overpressure and damage A. B. C. D.
154.
Except for lethal service a vessel _____ be painted, coated or internally lined prior to the hydrostatic pressure test. A. B. C. D.
155.
3 2 1 1/2 1 1/3
May May not Should Must
The formula for determining the pneumatic test pressure is: A. B. C. D.
P = 1.25 x Maximum Operating Pressure P = 1.5 x MAWP x St / Sd P = 1.1 x MAWP x St / Sd P = 3 x Minimum Operating Pressure
156.
The metal temperature during ASME pneumatic test shall be maintained at least _____ above the MDMT. A. 10oF B. 20oF C. 60oF D. 30oF
157.
The two steps in pressurizing a vessel for the pneumatic test are: A. B. C. D.
158.
The required visual inspection after application of the pneumatic test pressure is conducted at a pressure equal to _____ of test pressure. A. B. C. D.
159.
Increase to one-half test pressure then in steps of one-tenth test pressure until test pressure is reached Rapidly raise to one-third test pressure then raise slowly to test pressure Increase to one-third test pressure then in steps of one-twentieth test pressure Raise to one-half test pressure then to full test pressure in equal steps
Two-thirds Four-fifths One-half One-tenth
Except for lethal service a vessel _____ be painted, coated or internally lined prior to the pneumatic pressure test. A. May B. May not C. Should D. Must
151
160.
Indicating test gages shall be connected _____. A. B. C. D.
161.
When the operator controlling a pressure test cannot see the pressure gage _____. A. B. C. D.
162.
Any range A range specified by the Inspector A very narrow range A range of only 0.5 to 6 times the test pressure
Pressure test gages shall be calibrated against _____. A. B. C. D.
166.
2, 4 3, 4 1 1/2, 4 3, 5
A digital pressure gage having _____ may be used for pressure tests. A. B. C. D.
165.
About double the test pressure About 1 1/2 times the test pressure About three times the test pressure About 1 1/3 times the test pressure
In no case shall indicating pressure gages have a range of neither less than _____ nor more than _____ times the test pressure. A. B. C. D.
164.
A telephone system shall be installed between the test gage observer and test controller A second gage shall be installed that can be observed by the test pressure controller They estimate when the test pressure is reached Visual communication between pressure gage observer and pressure test controller must be established
An indicating pressure gage, which has a range _____, should be used for pressure tests. A. B. C. D.
163.
Directly to the vessel Within 30 feet of the bottom of the vessel In sets of three to the vessel Always with a recording gage to the vessel
A calibrated master gage A standard deadweight tester A deadweight test gage Either 1 or 2 above
When magnetic particle examinations are prescribed they shall be done in accordance with Appendix _____, A. B. C. D.
12 6 8 7
152
167.
When liquid penetrant examinations are prescribed they shall be done in accordance with Appendix _____, A. 12 B. 6 C. 8 D. 7
168.
The units of measurement that are mandatory for Manufacturer’s Data Reports and markings on pressure vessels is: A. U.S. Customary and metric B. U.S. Customary C. English D. Metric
169.
Which of the following can be found on the required marking for a pressure vessel? A. B. C. D.
170.
A vessel is constructed by arc or gas welding, what symbol would appear under the Code symbol stamp to denote this type of construction? A. B. C. D.
171.
UB DF W HT
A vessel has been radiographed in accordance with UW-11 where the complete vessel satisfies the requirements of UW-11(a)(5) and the spot radiography requirements of UW-11 (a)(5)(b) have been applied, what marking would appear under the Code symbol stamp? A. B. C. D.
173.
A L P W
A vessel is constructed for special service as an unfired steam boiler, what symbol would appear under the Code symbol stamp to denote this service condition? A. B. C. D.
172.
The name of the manufacturer preceded by the words “made by” The MAWP _____PSI at _____oF The month and year built The minimum design product temperature
None RT 2 RT 3 SR
A vessel has been radiographed in accordance with UW-11 where the complete vessel satisfies the spot radiography requirements of UW-11(b), what marking would appear under the Code symbol stamp? A. None B. SR 3 C. RT 3 D. RT 4
153
174.
A vessel has been radiographed in accordance with UW-11 where only part of the vessel has satisfied the radiographic requirements of UW-11(a) and none of the markings RT 1, RT 2 or RT 3 apply, what marking would appear under the Code symbol stamp? A. None B. SR 3 C. RT 3 D. RT 4
175.
A vessel has been radiographed in accordance with UW-11 where the complete vessel has had all butt welds radiographically examined for their full length, what marking would appear under the Code symbol stamp? A. B. C. D.
176.
A vessel has been designed with only visual examination required of the butt welded joints. What marking would appear under the Code symbol stamp for this condition? A. B. C. D.
177.
Partially hydrogen tested Partially head tested Partially heat treated Pneumatically tested
A pressure vessel is a single chamber and has been completely shop fabricated what Manufacturer's Data Report form would be used? A. B. C. D.
180.
Fully heat treated Partially heat treated Hydrostatically tested Hydrogen tested
The marking PHT is used for vessels that have been _____. A. B. C. D.
179.
RT 4 None RT 3 NR
The marking HT is used for vessels that have been _____. A. B. C. D.
178.
None SR 2 RT 1 RT 2
U-1 P-4 P-1 U-1A
What Manufacturer’s Data Report form would be used for a pressure vessel part? A. B. C. D.
P-3 U-1 U-2 P-4A
154
181.
All pressure vessels other than unfired steam boilers shall be protected by a pressure relieving device that shall prevent the pressure from rising more than the greater of _____% or _____ PSI above the MAWP. A. B. C. D.
182.
What is the minimum size of liquid relief valve permitted by Section VIII, Division 1? A. B. C. D.
183.
10, 3 15, 5 25, 10 40, 3
NPS 10 NPS 24 NPS 1 NPS 1/2
When a single pressure relief device is used on a pressure vessel it shall be set to operate at a pressure not exceeding _____. A. B. C. D.
The MAWP The operating pressure The design pressure The mean design pressure
SECTION VIII, SUBSECTION B QUESTIONS 184.
Which of the following are classified as service restrictions under Section VIII, Division 1? A. B. C. D.
185.
Vessels containing lethal substances are required to be postweld heat treated in what thickness? A. B. C. D.
186.
Lethal Vessels operating below certain temperatures Unfired steam boilers exceeding 50 PSI All of the above
All Above 5/8 in. Above 1 1/4 in. Above 1 in.
Butt welds in vessels that contain lethal substances are required to be _____ radiographed. A. B. C. D.
Spot Fully Partially None of the above
155
187.
Pressure vessels subject to direct firing do not permit what type weld joints for Category A and B joints? A. B. C. D.
188.
Longitudinal welded joints within the main shell or nozzles are Category _____. A. B. C. D.
189.
B A C D
Welded joints connecting communicating chambers or nozzles to main shells or heads are Category _____. A. B. C. D.
193.
B A C D
Welded joints connecting flanges, tubesheets or flat heads to main shell or formed heads are Category _____. A. B. C. D.
192.
A B C None of the above
Circumferential welded joints connecting hemispherical heads to main shells, to nozzles are Category _____. A. B. C. D.
191.
C D A B
Circumferential welded joints within the main shell or transitions in diameter are Category _____. A. B. C. D.
190.
3 4 1 None of the above
A B C D
o When a Circumferential welded joint connecting a transition in diameter exceeds 30 it is not considered a _____.
A. B. C. D.
Butt weld Groove weld Fillet weld Full penetration weld
156
194.
Material for pressure parts shall comply with the requirements for materials given in _____. A. B. C. D.
195.
UG-4 thru UG-15 UG-93 UW-15 UG-15 thru UG-27
Material for nonpressure parts which are welded to the vessel _____ prior to being used in the vessel. A. B. C. D.
Must be tested using PT or MT Must be proven of weldable quality Must be ultrasonic thickness tested Must be pressure tested
196.
For material which is not identifiable in accordance with UG-10, UG-11, UG-15, or UG-93 proof of weldable quality can be demonstrated by: A. Using weld material which meets the requirements of an SFA specification B. Preparing a butt joint test coupon from each piece of nonidentified material and making guided bend tests C. Satisfactory qualification of the welding procedure D. Both 2 and 3 above
197.
When adjacent abutting sections differ in thickness by more than the lesser of one-fourth the thickness of the thinner section or 1/8 in. what must be done? A. Provide a tapered transition of at least 3:1 B. Make a six inch radiograph C. Nothing D. Provide a tapered transition of at least 4:1
198.
Longitudinal welded joints of adjacent courses shall be separated by at least _____ to avoid the radiographic requirement. A. B. C. D.
199.
Full radiography is required for which of the following butt welds? A. B. C. D.
200.
Five times the minimum thickness of the plate Five times the thickness of the thicker plate Six inches Four times the thickness of the thicker plate
In shells and heads of vessels containing lethal substances In shells and heads of unfired steam boilers having design pressure less than 50 PSI In all vessels where the least nominal thickness exceeds 1 in. None of the above
Category B and C butt welds in nozzles and communicating chambers never require radiographic examination provided they neither exceed: A. B. C. D.
NPS 10 1 1/8 in. NPS 6 NPS 10 nor 1 1/8 in.
157
201.
When full radiography is required of the Category A and D butt welds, the Category B and C butt welds shall as a minimum meet the requirements for _____. A. B. C. D.
202.
203.
Ultrasonic examination in accordance with UW-53 may be substituted for radiography for what condition? A. It is never permitted B. When radiographic equipment is not available C. For the final closure seam if the construction does not permit interpretable radiographs D. For longitudinal welded seams when they are in excess of 1 1/4 in. Joint efficiencies for welded joints shall be in accordance with _____. A. B. C. D.
204.
1.00 0.85 0.45 0.60
A seamless vessel section is welded into a vessel with the requirements of UW-11(a)(5)(b) spot radiography requirements met. What value of E would be used in the calculation for the shell? A. B. C. D.
207.
1.00 & 0.90 1.00 & 0.85 0.85 & 0.70 0.85 & 0.65
What would be the value of E for a butt welded longitudinal joint welded from one side? A. B. C. D.
206.
Subsection C UW-11(a)(5)(b) Paragraph UW-12(d) Table UW-12
When a value of E is taken from column (a) of Table UW-12 what are the values for Type 1 and Type 2 welded joints? A. B. C. D.
205.
Full radiography in accordance with UW-51 Spot radiography in accordance with UW-52 Partial radiography in accordance with UW-53 Spot radiography in accordance with UW-51
0.85 0.65 0.90 1.00
A seamless head is welded to a vessel shell using a Type 4 joint. What value of E would be used in the calculation for the head? A. B. C. D.
0.55 0.45 0.85 1.00
158
208.
An ERW pipe is being used as the shell of a vessel, what E value would be used in the calculation of the shell if the requirements of UW-11(a)(5)(b) were met? A. B. C. D.
209.
210.
A single unreinforced opening meeting the requirements of UG-36(c)(3) is located in a Category B weld joint. What radiographic requirements must be met? A. A radiograph must be taken that is two times the diameter of the hole in length B. A six inch radiograph must be taken which is centered over where the hole will be placed C. A twenty inch radiograph must be taken which is centered over the hole area D. A radiograph must be taken that is three times the diameter of the hole in length Strength calculations are required for which of the following nozzle configurations? A. B. C. D.
211.
1.00 0.85 0.45 0.60
Figure UW-13.2, sketch h Figure UW-16.1, sketch a-1 Figure UW-16.1, sketch b Figure UW-13.1, sketch d
Reinforcing plates and saddles of nozzles attached to the outside of a vessel shall be provided with at least one telltale hole _____ in size. A. B. C. D.
Maximum NPS 1/4 tap Maximum NPS 2 Maximum NPS 1/2 tap 2 in.
212.
The largest throat size required for a tc fillet weld when only pressure loading is being considered is: A. 3/4 in. B. 1/3 the thickness of the nozzle C. 3/16 in. D. 1/4 in.
213.
A nozzle similar to Figure UW-16.1, sketch (e) has a shell thickness of 9/16 in. and a nozzle thickness of 3/4 in., what is the value of tmin? A. 9/16 in. B. 1/2 in. C. 1 1/2 in. D. 1 in.
214.
When calculating the allowable load on fillet welds a joint efficiency of _____% is used. A. B. C. D.
60 55 1.0 85
159
215.
Welding procedures used in welding pressure parts and in joining load-carrying nonpressure parts shall be qualified in accordance with: A. B. C. D.
216.
When welding nonpressure-bearing attachments, which have no load-carrying function, is made by any automatic welding process procedure qualification testing is: A. B. C. D.
217.
Removed completely Ground on the starting and stopping ends Examined with the PT method Either 1 or 2
Surfaces to be welded shall be cleaned within what distance from the weld joint? A. B. C. D.
221.
32 60 0 5
Tack welds used to secure alignment shall be: A. B. C. D.
220.
Clock number Welding helmet Blue uniform Identifying number, letter or symbol
o It is recommended that no welding be performed when the metal is lower than _____ F.
A. B. C. D. 219.
Required when thickness exceeds 1/2” Required for pressure parts only Not required Not required unless requested by the inspector
Each welder and welding operator shall be assigned a/an _____ by the manufacturer/repair firm. A. B. C. D.
218.
AWS B1 ASME Section IX ASME Section VIII Company engineering specifications
1” Two times the plate thickness There is no mandatory distance As required by the inspector
Two shells are to be butt welded together to form a circumferential joint. Each shell is 1” thick. What is the maximum permitted offset? A. B. C. D.
3/16 in. 1/4 t 1/8 in. 3/4 in.
160
222.
What is the maximum permitted weld reinforcement for a butt in a pressure vessel shell that is 1 1/2 in. thick? A. B. C. D.
223.
224.
When welds are identified by stamping, each welder or welding operator shall stamp their identification at what intervals for steel fabrications? A. 6 ft. B. 2 ft. C. 10 ft. D. 3 ft. Peening shall not be used on which of the following welds if the vessel is not subsequently post weld heat treated? A. B. C. D.
225.
Either before or after the hydrostatic test Prior to minor repairs Before hydrostatic test After hydrostatic test
An example of nominal thickness for the purpose of determining heat treatment time is: A. B. C. D.
228.
10 ft. 5 ft. No minimum specified 15 ft.
Postweld heat treatment when required shall be done _____. A. B. C. D.
227.
Initial (root layer) Intermediate layers Final face layer 1 and 3
What is the minimum overlap that must be provided when a vessel is heat treated in more than one heat in a furnace? A. B. C. D.
226.
1/2 in. 3/32 in. 1/8 in. 1/4 in.
The depth of a repair weld The thickness of the attachment when a nonpressure part is welded to a pressure part The thickness of the tubesheet in shell to tubesheet connections The thicker of the two adjacent welded butt welded parts
Surface weld metal buildup is required to be examined over the full surface of the deposit by which of the following? A. B. C. D.
Radiographic Ultrasonic Magnetic Particle Acid etching
161
229.
The Inspector shall assure that which of the following has been accomplished? A. B. C. D.
230.
When pneumatic testing is used instead of hydrostatic testing which of the following welds must be examined with MT or PT? A. B. C. D.
231.
50 ft. 25 ft. 60 ft. 10%
The minimum length of a spot radiograph shall be _____. A. B. C. D.
235.
3/16 in. 1/4 in. 3/4 in. 1/2 t
For spot radiography, one spot shall be examined on each vessel for each _____ of length. A. B. C. D.
234.
SNT-TC-1A ACCP CP-189 Any of the above
A longitudinal butt weld is being fully examined. The weld is 3/4 in. thick which includes a 1/16 in. reinforcement. What is the longest elongated inclusion permitted? A. B. C. D.
233.
All welds around openings Welds around openings over 12 in. OD Attachment welds with throat thickness exceeding 3/8 in. None of the above
When full radiography is required the radiographic personnel shall be qualified to which standard? A. B. C. D.
232.
Welding procedures used have been qualified Welders used have been qualified Postweld heat treatments have been correctly performed All of the above
24 in. No minimum specified 12 in. 6 in.
When a spot radiograph does not meet Code requirements _____. A. B. C. D.
The entire increment will be acceptable if the weld is repaired at the failed spot Two additional spots shall be examined One additional spot shall be examined The entire increment must be rewelded and a new spot examined
162
236.
Ultrasonic examination when required is performed in accordance with _____. A. B. C. D.
Section V, Article 5 Appendix 8 Appendix 12 Appendix 7
SECTION VIII, SUBSECTION C QUESTIONS 237.
238.
For welded construction the carbon content for carbon and low alloy steels shall not exceed _____%. A. 0.035 B. 0.35 C. 3.5 D. 10 SA-36 SA-283 Grades A, B, C, and D and G 40.21 38W steel plates may be used as pressure parts for which of the following applications? A. B. C. D.
239.
The term nominal thickness for determination of postweld heat treatment holding time is defined as: A. B. C. D.
240.
UCS-66 or UHT-56 UCS-56 or UHA-32 UHT-56 or UHA-32 UNF-56 or UCS-56
o The temperature of the furnace shall not exceed _____ F at the time the vessel or part is placed in it.
A. B. C. D. 242.
Thickness of the weld including corrosion allowance Thickness of the base metal Thickness of the weld excluding corrosion allowance Thickness of the base metal plus one-half the corrosion allowance
When pressure parts of two different P-Number groups are joined by welding the postweld heat treatment shall be that specified in: A. B. C. D.
241.
Unfired steam boilers not exceeding 50 PSI Vessels containing lethal substances Vessels processing gasoline None of the above
600 500 800 300
Above 800oF the heating rate shall not be more than _____. A. B. C. D.
500oF/hour divided by the maximum metal thickness 400oF/hour divided by the maximum metal thickness 900oF/hour divided by the maximum metal thickness 200oF/hour divided by the maximum metal thickness
163
243.
During the postweld heat treatment holding period there shall be no greater difference than _____oF between the highest and lowest temperature throughout the portion of the vessel being heat treated. A. B. C. D.
244.
150 200 300 250
During the heating and cooling periods, the furnace atmosphere shall be controlled as to avoid _____. A. B. C. D.
Excessive corrosion Excessive bending Excessive stress Excessive oxidation
245.
o Above 800 F cooling shall be done in _____. A. A furnace B. A furnace or cooling chamber C. A cooling chamber D. Still air
246.
Above 800oF the cooling rate shall not be more than _____. A. B. C. D.
247.
What is the normal holding temperature for a P-No. 1 Group 3? A. B. C. D.
248.
1100oF 1200oF 900oF 600oF
What is the minimum holding time for a P-No. 1 Group 2 welded joint 2 in. thick? A. B. C. D.
249.
500oF/hour divided by the maximum metal thickness 400oF/hour divided by the maximum metal thickness 900oF/hour divided by the maximum metal thickness 200oF/hour divided by the maximum metal thickness
4 hours 2 hours 15 minutes 2 hours 3 hours
What is the minimum holding time for a P-No. 1 Group 3 welded joint 1/8 in. thick? A. B. C. D.
1 hour 12.5 minutes 15 minutes None of the above
164
250.
What is the minimum holding time for a P-No. 3 Group 2 welded joint 6 in. thick? A. B. C. D.
251.
A welded joint in a P-No. 1 Group 1 material is 1 3/16 in. thick. No special service requirements apply. What would the minimum holding time be? 1. 2. 3. 4.
252.
2 in. 1 1/4 in. 1 1/2 in. 5/8 in.
After completing all welding, the repair area shall be maintained at a temperature of _____ for a minimum period of _____ hours. A. B. C. D.
255.
Groove welds not over 1/2 in. that attach nozzles with an inside diameter of 2 in. Fillet welds with a throat thickness of 3/4 in. that attach nonpressure parts to pressure parts Any weld less than 1 1/2 in. Any weld not over 1 1/4 in.
The maximum depth of a repair weld using the temper bead process that does not require a repostweld heat treatment for a P-No. 1 Group 2 material is _____. A. B. C. D.
254.
1 hour 11.25 minutes No PWHT required 2 hours None of the above
The special service conditions of UW-2 apply to a P-No. 1 Group 3 material. Which of the following can o be exempted from PWHT if a minimum 200 F preheat is applied? A. B. C. D.
253.
3 hours 3 hours 30 minutes 2 hours 5 hours
o 300-400 F 5 hours 400-500oF 5 hours 450-550oF 4 hours 400-500oF 4 hours
The alternative postweld heat treatment temperate of 950oF is to be used for a P-No. 1 Group 2 weld joint of 4 in. thick. What would the minimum holding time be? A. B. C. D.
10 hours 45 minutes 10 hours 4 hours 2 hours 30 minutes
165
256.
For P-No. 1 Group 1 material full radiography is required when the thicknesses exceeds _____ in. A. B. C. D.
257.
Unless otherwise exempted impact testing is required for a combination of thickness and _____. A. B. C. D.
258.
0 1 1/2 1 1/4 5/8
Minimum design metal temperature Maximum design temperature Specification and grade of material Allowable stress
Components, which are to be evaluated to establish impact test exemptions, are: A. B. C.
259.
Shells Heads Attachments, which are essential to the structural integrity of the vessel when, welded to pressure retaining components D. All of the above The governing thickness tg for a corner, fillet or lap welded joint is defined as: A. B. C. D.
260.
When the governing thickness for a welded joint exceeds _____ in. and is colder than _____oF impact tested material shall be used. A. B. C. D.
261.
4, -50 4, 120 6, 120 2, -50
The governing thickness of a flat nonwelded tubesheet of 16 in. thickness is: A. B. C. D.
262.
The throat thickness of the attaching weld The thinner of the two parts joined The nominal thickness of the thickest welded joint The thickness of the thicker member divided by 4
4 in. 16 in. Dependent on the attaching shell thickness 6 in.
If the governing thickness of a nonwelded part exceeds 6 in., below what MDMT must the material be impact tested? A. B. C. D.
100oF 60oF 120oF None of the above
166
263.
What is the basic minimum design metal temperature for a SA-216 Grade WCB casting which is produced to a fine grain practice and water quenched and tempered with the largest nominal thickness 1 1/2 in.? A. B. C. D.
264.
When the coincident ratio as defined in Figure UCS-66.1 is 0.70 what is the further reduction in the MDMT of the material? A. B. C. D.
265.
266.
20oF 30oF 40oF 110oF
No impact testing is required for B16.5 steel flanges used at design metal temperatures no colder than _____oF. A. 120oF B. -20oF C. -50oF D. 20oF No impact testing is required for UCS materials less than _____ in. thick. A. B. C. D.
267.
88oF 14oF 43oF 51oF
1.000 0.099 0.100 0.250
If postweld heat treating is performed on a weld joint joining P-No. 1 materials when not otherwise required by Section VIII an additional _____oF in impact testing exemption temperature may be given to the minimum permissible temperature from Figure UCS-66. A. B. C. D.
30 35 50 70
SECTION VIII, APPENDICES QUESTIONS 268.
The formula that is to be used calculating thickness and pressure for cylindrical shells subject to circumferential stress is found in Appendix _____. A. B. C. D.
1-1, formula 2 1-4, formula 3 1-1, formula 1 1-8, formula 1
167
269.
When evaluating rounded indications thickness “t” is the thickness of the weld _____. A. B. C. D.
270.
A butt weld is 1/2 in. thick with the maximum weld reinforcement on each side. acceptable size of a random rounded indication is _____ in. A. B. C. D.
271.
Including the reinforcement on the pressure side only Including any allowable reinforcement Excluding a maximum of 1/32 in. allowable reinforcement on each side Excluding any allowable reinforcement The maximum
0.168 0.125 0.250 0.063
For magnetic particle examinations, only indications that are greater than _____ in. shall be considered relevant. A. B. C. D.
1/8 1/32 1/16 1
272.
Which of the following are acceptance standards for liquid penetrant examination? A. Relevant linear indications B. Relevant rounded indications greater than 3/16 in. C. Four or more relevant rounded indications in a line separated by 1/16 in., or less D. All of the above
273.
Liquid penetrant examiners are certified by the manufacturer with a _____. A. NDE examiners certification B. Certificate of Competency C. SNT-TC-1A certification D. None of the above
274.
Ultrasonic examination of welds shall be performed using methods described in _____ of ASME Code Section V. A. Article 1 B. Article 4 C. Article 5 D. Article 23
275.
Personnel performing examinations of welds shall be qualified in accordance with _____. A. SNT-TC-1A B. PCS-185 C. PAAC D. Manufacturer’s standard
168
276.
For UT, other than cracks, lack of fusion and incomplete penetration, other imperfections are unacceptable if the indications exceed the reference level and have lengths, which exceed: A. B. C. D.
277.
The manufacturer shall maintain a record of all UT reflections from uncorrected areas that exceed _____% of the reference level. A. B. C. D.
278.
60 50 100 20
The Manufacturer’s Data Report form used for a single chamber, completely shop fabricated vessel is: A. B. C. D.
279.
1/4 in. for t up to 3/4 in. 1/3 t for t from 3/4 in. to 2 1/4 in. 3/4 in. for t over 2 1/4 in. All of the above
U-3 U-1 U-1A U-4
The Manufacturer’s Data Report form used for a part of a vessel is: A. B. C. D.
U-2 U-1A U-3 U-4
169
ANSWER SHEET ASME QUESTIONS
Section VIII General Questions
1. 2. 3. 4. 5. 6. 7. 8. 9. 10. 11. 12. 13. 14. 15. 16. 17. 18. 19. 20.
C C A A D B B B DELETED B D B B B A C A D B B
21. 22. 23. 24. 25. 26. 27. 28. 29. 30. 31. 32. 33. 34. 35. 36. 37. 38. 39. 40.
A C A C B D A DELETED C D A B A C C B D C D A
41. 42. 43. 44. 45. 46. 47. 48. 49. 50. 51. 52. 53. 54. 55. 56. 57. 58. 59. 60.
170
B B C A B C D A A A B D A B A D A D B C
61. 62. 63. 64. 65. 66. 67. 68. 69. 70. 71. 72. 73. 74. 75. 76. 77. 78. 79.
A B C C C D B C A A A B C A C C C D C
Subsection A
80. 81. 82. 83. 84. 85. 86. 87. 88. 89. 90. 91. 92. 93. 94. 95. 96. 97. 98. 99. 100. 101. 102. 103. 104. 105. 106. 107. 108. 109. 110. 111. 112. 113. 114.
B, Foreword D, U-1(e) A, U-1(j) A, U-1(j) C, U-(2) C, Table U-3 D, UG-4(a) B, UG-4(b) A, UG-5, Note 2 D, UG-9 B, UG-10 B, UG-16(b)(1) D, UG-16(c) D, UG-16(d) A, UG-16(e) C, UG-20(a) B, Figure UCS-66.2 D, UG-20(f)(1)(b) C, UG-20(f)(1)(a) D, UG-22 A, UG-24(a) B, UG-27(c) & UG-16(e) D, Table UW-12 C, UG-28 A, UG-28(c)(1) Step 2 C, UG-28(c)(1) Step 4 B, UG-32(a) D, UG-32(d) D, UG-32(d) B, UG-32(e) B, UG-32(o) A, UG-34 C, UG-34(c)(2) & UW-12 A, UG-34(c)(2) D, UG-36(c)(3)(a)
115. 116. 117. 118. 119. 120. 121. 122. 123. 124. 125. 126. 127. 128. 129. 130. 131. 132. 133. 134. 135. 136. 137. 138. 139. 140. 141. 142. 143. 144. 145. 146. 147. 148. 149.
B, UG-36(c)(3)(c) C, UG-37(a) A, UG-37(a) B, Figure UG-37.1 C, UG-37(a) C, Figure UG-37.1 & UG-40(b)(1)&(2) A, UG-40(e) B, UG-76(c) A, UG-77(a) D, UG-77(b) A, UG-79(b) D, UG-80(a) B, UG-82(a) A, UG-82(b) D, UG-84(c)(1) B, UG-84(c)(2) C, UG-84(c)(3) A, Figure UG-84.1b C, UG-84(c)(4)(b) B, Table UG-84.2 D, Table UG-84.4 B, UG-85 D, UG-90(c)(1) A, UG-93(a)(1) C, UG-93(d) A, UG-96 C, UG-98(a) A, UG-98(b) C, UG-99(b) A, UG-99(c) D, UG-99(d) B, UG-99(e) A, UG-99(f) C, UG-99(g) B, UG-99(h)
171
150. 151. 152. 153. 154. 155. 156. 157. 158. 159. 160. 161. 162. 163. 164. 165. 166. 167. 168. 169. 170. 171. 172. 173. 174. 175. 176. 177. 178. 179. 180. 181. 182. 183.
B, UG-99(h) A, UG-99(h) C, UG-99(h) D, UG-99(h) A, UG-99(k) C, UG-100(b) D, UG-100(c) A, UG-100(d) D, UG-100(d) A, UG-100(e) A, UG-102(a) B, UG-102(a) A, UG-102(b) C, UG-102(b) A, UG-102(b) D, UG-102(c) B, UG-103 C, UG-103 B, UG-115(b) B, UG-116(a)(3) D, UG-116(b)(1) A, UG-116(c) B, UG-116(e)(2) C, UG-116(e)(3) D, UG-116(e)(4) C, UG-116(e)(1) B, UG-116(e) A, UG-116(f)(1) C, UG-116(f)(2) D, UG-120 & Appendix W C, UG-120(c) A, UG-125(c) D, UG-128 A, UG-134(a)
Subsection B
184. 185. 186. 187. 188. 189. 190. 191. 192. 193. 194. 195. 196. 197. 198. 199. 200. 201. 202. 203. 204. 205. 206. 207. 208. 209. 210. 211. 212. 213. 214. 215. 216. 217. 218.
D, UW-2 A, UW-2(a) B, UW-2(a) A, UW-2(d)(2) C, UW-3(a)(1) B, UW-3(a)(2) B, UW-3(a)(1) C, UW-3(a)(3) D, UW-3(a)(4) A, UW-3(b) A, UW-5(a) B, UW-5(b) D, UW-5(b)(3) A, UW-9(c) B, UW-9(d) A, UW-11(a)(1) D, UW-11(a)(2) & (4) B, UW-11(a)(5)(b) C, UW-11(a)(7) D, UW-12 A, Table UW-12 Column (a) D, Table UW-12 Column (c) D, UW-12(d) C, UW-12(d) A, UW-12(e) D, UW-14(b) B, UW-15(b) A, UW-15(d) D, UW-16(b) A, UW-16(b) B, UW-18(d) B, UW-28(b) C, UW-28(c)(2) D, UW-29(c) C, UW-30
219. 220. 221. 222. 223. 224. 225. 226. 227. 228. 229. 230. 231. 232. 233. 234. 235. 236.
172
D, UW-31(c) C, UW-32(a) A, Table UW-33 C, Table UW-35 D, UW-35 D, UW-39(a) B, UW-40(a)(2) C, UW-40(e) A, UW-40(f)(6) C, UW-42(b)(2) D, UW-47, 48, 49 A, UW-50 D, UW-51(a)(2) B, UW-51(b)(2) A, UW-52(b)(1) D, UW-52(c) B, UW-52(d)(2) C, UW-53
Subsection C
237. 238. 239. 240. 241. 242. 243. 244. 245. 246. 247. 248. 249. 250. 251. 252. 253. 254.
B, UCS-5(b) C, UCS-6(b) A, UCS-56(a) B, UCS-56(c) C, UCS-56(d)(1) B, UCS-56(d)(2) A, UCS-56(d)(3) D, UCS-56(d)(4) B, UCS-56(d)(5) A, UCS-56(d)(5) A, Table UCS-56, P-No. 1 material C, Table UCS-56, P-No. 1 material C, Table UCS-56, P-No. 1 material A, Table UCS-56, P-No. 3 material B, Table UCS-56, P-No. 1 material A, Table UCS-56, P-No. 1 material C, UCS-56(f)(2) D, UCS-56(f)(4)(c)
255. 256. 257. 258. 259. 260. 261. 262. 263. 264. 265. 266. 267.
APPENDICES
268. 269. 270. 271. 272. 273. 274. 275. 276. 277. 278. 279.
C, Appendix 1-1, Formula 1 D, Appendix 4-2(c) B, Appendix 4, Table 4-1 C, Appendix 6-3 D, Appendix 8-4 B, Appendix 8-2 C, Appendix 12-1(b) A, Appendix 12-2 D, Appendix 12-3(b) B, Appendix 12-4 C, Appendix W, Form U-1A A, Appendix W, Form U-2
173
A, Table UCS-56.1 C, Table UCS-57 A, UCS-66(a) D, UCS-66(a) B, UCS-66(a)(1)(b) B, UCS-66(a) A, UCS-66(a)(3) C, UCS-66(a)(5) D, Figure UCS-66 & Table UCS-66.1 B, Figure UCS-66.1 B, UCS-66(c) C, UCS-66(d) A, UCS-68(c)
API 510 CALCULATIONS SUMMARY SHEET CATEGORY Min. Thickness of Shells (Cylinders) (“Required” Thickness from API 510, Para. 6.4) Design Pressure on Shells (Cylinders) External Pressure on Cylinders
CODE ASME VIII
PARA. UG-27 - I.R. APP1 - O.R.
CALCULATION/FORMULA t =
ASME VIII
UG-27 - I.R. APP1 - O.R.
ASME VIII & Charts provided with test
UG-28 and External Pressure Charts
P= 1. 2. 3. 4.
PR SE −.6 P or t =
SEt or P = SEt R +.6t Ro −.4 t
L/D o and D o /t Go to Fig G, find “A” Go to Material Chart Find “B” 4B 3( Do / t )
calculate PA = Min. Thickness of Formed Heads (“Required” Thickness from API 510, Para. 6.4)
ASME VIII
UG-32 (d) (e) (f)
PRo SE +.4 P
Ellip. - t =
PD 2 SE −.2 P
Torispherical - t =
.885PL SE −.1P
PL 2 SE −.2 P 2 SEt Ellip. - P = D+.2 t
Hemi. - t = Design Pressure/MAWP Formed Heads
ASME VIII
UG-32 (d) (e) (f)
of
Hemi. - P =
Toris. - P =
SEt .885L+.1t
2 SEt L+.2 t
Min. Thickness of Flat Heads
ASME VIII
UG-34 (C) (2) Formula 1
t = d CP
Nozzle Reinforcement
ASME VIII
UG-37, Fig. UG37
Impact Testing
ASME VIII
Hydro/Pneumatic Tests
ASME VIII
UG-20(f), UG-84 UCS-66, 67, 68 UG-99, UG-100
A 1 , A 2 , A 41 must be greater than A for Nozzles with no repad; A 1 , A 2 , A 41 , A 42 and A 5 must be greater than A for Nozzles with repad UG-20(f) for blanket exceptions, UCS - 66, 67, 68 for requirements, UG-84 for acceptance criteria 13 . xPxStress@ TestTemp Hydro - P = Stress@ DesignTemp
SE
Pneumatic - P =
174
11 . xPxStress@ TestTemp Stress@ DesignTemp
Weld Efficiencies
Joint
ASME VIII
UW-11, UW-12 Table UW-12
CATEGORY Nozzle Weld Sizes
CODE ASME VIII
PARA. UW-16 Fig. UW-16
Corrosion Rate/Remaining Life
API 510 and Body of Knowledge
6.4
RT-1 - Full - 1.0 or .90 RT-2 - Full on Cat A - Spot on Cat B (UW11(a)(5)(b) 1.0 or .90 RT-3 - Spot - 1 -50 foot weld -1 for each welder .85 or .80 RT-4 - Combination of above No RT - .70 or .65 Seamless - .85 if UW-11(a)(5)(b) is not met 1.0 is UW-11(a)(5)(b) is met
CALCULATION/FORMULA t c = smaller of 1/4” or .7t min t min = smaller of 3/4” or thickness of parts t 1 , t 2 = smaller of 1/4” or .7 t min Leg = 1.414 x throat - Throat = .707 x Leg Corrosion Rate - Metal Loss Time t actual − t required Remaining Life = CorrosionRate * *either short or long term, normally whichever is greater (Long Term CR) LTCR =
(Short Term CR) STCR =
Hydrostatic Head
Head Depth (Dish) MAWP on Current Vessels (Corrosive Service)
tinitial − t actual TimeBetween Re adings t previous − t actual
TimeBetween Re adings Hydrostatic Head = .433 psi x each (1) foot of height
ASME VIII & API 510 Body of Knowledge ASME VIII
UG-99
UG-32
Head Depth = 1/4 x D – Elliptical Heads Head Depth = 1/2 x D – Hemispherical Heads
API 510
6.4
Shells - P = SE(t – corrosion rate x yrs next inspection) R + 0.6 (t – corrosion rate x yrs next inspection) Heads – Applicable formula from UG-32 utilizing (t – corrosion rate x yrs next inspection)
175
FUNDAMENTALS OF ASME VIII PRESSURE VESSEL DESIGN The API inspector will have to be knowledgeable in the fundamentals of the design requirements of the ASME Boiler and Pressure Vessel Code in order to know what he is looking at and what he must look for when doing inservice inspection of pressure vessels, and to help satisfy himself that the vessel is being operated under the proper conditions. In this section we will review some of the parameters that must be addressed in design calculations for pressure vessels being built in accordance with the requirements of ASME Section VIII. As we know ASME Section VIII, Div.1 is divided into three subsections, a general subsection, a method of fabrication subsection, and material class subsection. No matter the fabrication process not the class of material used, the requirements for design in the general subsection apply in addition to the specific design criteria given in the other applicable subsections. Such things as minimum thickness of shells and heads, mill undertolerances, pipe undertolerances, and corrosion allowance must be taken into consideration when designing pressure vessels. A combination of construction techniques may be used in a single pressure vessel, provided the rules applying to the respective methods of fabrication are followed and the vessel is limited to the service permitted by the method of fabrication having the most restrictive requirements. Any combination of materials may be used provided the applicable rules are followed and the requirements in ASME Section IX for welding dissimilar metals are met. Paragraph UG-19 addresses special constructions, such things as combination units, special shapes, and the situation where no design rules are given. Design temperatures are addressed in Paragraph UG-20. Stipulations must be made for both maximum and minimum design temperature. Normally the maximum design temperature will not be less than the mean metal temperature expected under normal operating conditions. Normally the minimum metal design temperature shall be the lowest expected in service. The design maximum metal temperature cannot exceed the temperatures listed in the tables of Subsection C and for pressure vessels under external pressure, the temperature shall not exceed the maximum temperature given on the external pressure charts. The design pressure of a vessel covered by ASME Section VIII, Div. 1; shall be the most severe condition of coincident pressure and temperature expected in normal operation. For this condition and for test conditions, the maximum difference in pressure between the inside and outside of the vessel, or between any two chambers of a combination unit shall be considered. UG-22 addresses loading. It states that the loading to be considered in the designing of a pressure vessel shall include internal and external design pressure, the weight of the vessel, and any of its normal contents, either during operation or during testing, and superimposed static reactions from weight that is attached to the vessel, any loads due to attachment of items, and any cyclic and dynamic reactions. It is also stated that wind, snow, and seismic reactions will be considered. Any impact reactions due to fluid shock and any temperature gradients and differential thermal expansion must be considered.
176
Maximum allowable stress values are considered in UG-23. Each class of material has its own maximum allowable stress value and the reader should become familiar with the stress tables referenced in each subcategory of material class. UG-24 contains requirements for specifying quality factors for castings. A casting that has no nondestructive examination performed on it will have a lower quality factor than will a casting that has been examined using a nondestructive examination method. Regarding corrosion, the user or his designated agent shall specify corrosion allowances other than those required by the rules of Section VIII, Div. 1. If corrosion allowance is not provided for, this fact must be indicated on the data report. When making allowance for corrosion, erosion and mechanical abrasion factors must also be taken into consideration for the desired life of the vessel. Any material added for these purposes does not have to be the same thickness for all parts of the vessel. The rate of deterioration will determine the added thickness requirements. Any vessel subject to corrosion must have a suitable drain opening at the lowest point practical in the vessel. A pipe may be used extending inward from any other location to within a quarter inch of the lowest point of the vessel. Paragraph UG-27 addresses thickness of shells under internal pressure. Formulas are given for calculating minimum thicknesses and maximum pressure for cylindrical and spherical shells. Special attention must be paid to circumferential stresses and longitudinal stresses within cylindrical shells. These different stress categories will determine the minimum thickness or maximum working pressure of the vessel. The API inspector should be aware of the limitations of both of these calculations and the applicability of each. Paragraph UG-28 addresses the thickness of shells and tubes under external pressure. A figure is supplied in ASME II Part D to make the determination if the chosen shell thickness value will withstand the maximum allowable working pressure. Using this procedure involves the process of assuming an outside diameter to thickness ratio and using this value and the charts provided, to determine the maximum allowable pressure. This procedure is applicable to cylinders having an outside diameter to thickness ratio value of equal to or greater than ten. When the outside diameter to thickness ratio is less than ten, other formulas are used for determining the maximum pressure allowable. Three configurations are addressed in paragraph UG-28. The two that we have mentioned are the cylindrical shells and tubes with diameter to thickness values of greater than 10 and cylindrical shells and tubes with a diameter to thickness ratio of less than ten. The third configuration is spherical shells. The API certified inspector should be familiar with the method used for determining pressure and thickness in this paragraph and be able to apply these Code rules in any given situation. The inspector should be familiar with the requirements of paragraph UG-31 regarding tubes and pipes when used as tubes or shells. This paragraph stipulates that the rules of UG-27 or UG-28 shall be applied depending if the tube or shell is to experience internal or external pressure and further that corrosion and erosion allowances must be taken into consideration. Threaded tube ends are also a consideration. Formulas and rules for using formed heads with pressure on the concave side are given in Paragraph UG-32. The inspector should be familiar with these formulas and their applicability. Definitions of ellipsoidal, torispherical, hemispherical, and toriconical heads should also be understood by the inspector. UG-32 presents similar formulas when using formed heads with pressure on the convex side.
177
Unstayed flat heads and covers are discussed in Paragraph UG-34. Figure UG-34 presents some of the acceptable types of unstaying flat heads. The inspector should be aware of this figure and know how to recognize the configurations that are exemplified. The formulas given in Paragraph UG-34 must be understood by the inspector. Since the inspector may be in the situation where he would have to verify design calculations, his working knowledge of these formulas and the applicability of these formulas must be well understood. Normally in the construction of an ASME Section VIII pressure vessel, it will be necessary to have openings through the pressure retaining shell. As most everyone knows, when a hole is made in a pressure vessel, it weakens the vessel and therefore it will not withstand the same stresses as a vessel without openings. Paragraph UG-36 addresses openings that must be made in a pressure vessel. The shape of openings and size of openings are discussed along with any combination of openings and spacing of openings. Paragraph UG-37 gives the requirements for reinforcement around any openings in a pressure vessel. A formula is given for the determination of the total cross sectional area of reinforcement as well as rules for vessels that experience external pressure and vessels that experience both internal and external pressure. Limits of reinforcement are discussed in Paragraph UG-40. This paragraph stipulates the boundaries of crosssectional area in any plane and the physical location of the reinforcement with respect to the opening. Material used for reinforcement shall have an allowable stress value equal to or greater than that of the vessel wall material. Requirements for the strength of the reinforcement are discussed in UG-41 and the inspector should be able to understand that the strength of the material used for reinforcement must be at least equivalent to that of the pressure vessel. Questions may arise during construction as to what to do about the reinforcement for vessels that have multiple openings that are near to one another. Paragraph UG-42 tells the manufacturer how this situation is to be dealt with. The overlap of reinforcement areas is taken into consideration and the total area of reinforcement is stipulated. Another area that the certified inspector should be very familiar with is how pipe and nozzle necks are attached to the vessel. The ASME Code gives restrictions regarding material and the design of the joint that makes the attachment. Paragraphs UG-45 and UG-46 discuss nozzle neck thicknesses and inspection openings. The inspector should be familiar with both of these paragraphs, because in UG-45 the required wall thickness for inspection openings with weld-on necks is discussed. UG-46 discusses in particular the requirements for inspection openings and the circumstances in which inspection openings may be omitted. Sizes of manholes, numbers of telltale drains, are also discussed.
178
UW-12 JOINT EFFICIENCIES Table UW-12 gives the joint efficiencies E to be used in the formulas of this division for welded joints. Except as required by UW-11 (a)(5), a joint efficiency depends only on the type of joint and on the degree of examination of the joint and does not depend on the degree of examination of any other joint.
•
A value of E not greater than that given in column (a) of Table UW-12 shall be used in the design calculations for fully radiographed butt joints (see UW-11 (a)), except that when the requirements of UW-11 (a)(5) are not met, a value of E not greater than that given in column (b) of Table UW-12 shall be used.
•
A value of E not greater than that given in column (b) of Table UW-12 shall be used in the design calculations for spot radiographed butt welded joints (see UW-11(b)).
•
A value of E not greater than that given in column (c ) of Table UW-12 shall be used in the design calculations for welded joints that are neither fully radiographed nor spot radiographed (see UW-11(c)).
•
For calculations involving circumferential stress in seamless vessel sections or for thickness of seamless heads, E = 1.0 when the spot radiography requirements of UW-11 (a)(5)(b) are met. E = 0.85 when the spot radiography requirements of UW-11(a)(5)(b) are not met, or when the category A or B welds connecting seamless vessel sections or heads are type no. 3,4,5 or 6 of Table UW-12.
•
ERW welded pipe or tubing shall be treated in the same manner as seamless, but with allowable tensile stress taken from the welded product values of the stress tables, and the requirements of UW-12(d) applied.
NOTE: Circumferential stress is the stress exerted on the longitudinal seam while the longitudinal stress is the stress exerted on the circumferential seams.
179
REMEMBER: Hydrostatic Head must be accounted for on any vessel designed for fluid service, per UG-98 and 3-2. If “T” = X MAWP at the top of the vessel, then T must = X MAWP + .433 psi per linear column height (L.C.H.) of water at the bottom. Example 1:
t=
PR SE −.6P
Where P = MAWP + .433 psi X L.C.H.
So if P = 150 and height is 100 ft.,
P = 150 + (100 X .433) = 150 + 43.3 OR 193.3 WITH HYDROSTATIC HEAD!
Solve formula with this value Example 2:
P=
Set R +.6t
Where P = -.433 psi X L.C.H. If P = 150 and height is 100 ft, then final adjusted pressure becomes 150 - (.433 X 100) or 150 - 43.3, or 106.7 psig allowed on vessel. Do this after solving for “P”.
•
HYDROSTATIC HEAD = .433 psi x EACH 1 FT. COLUMN HEIGHT OF WATER
•
ALSO, MAWP IS EXCLUSIVE OF CORROSION ALLOWANCE
NOTES ON ROUNDING IN MATHEMATIC EQUATIONS API has not published a policy on rounding (either up or down) when calculations are performed as part of the examination, although they have been asked to publish this policy. The calculation answers are normally far enough apart so that rounding does not usually present a problem. However, we can only instruct based on (historically) what has worked best (so far). This is the rounding policy that will be used during this course (but may be modified on the exam by API): 1.)
Thickness Calculations: Round to the third decimal place, and don’t round-up/down. Example #1 - “.0075” - is “.007” - (same as on test) Example #2 - “.0993” - is “.099” - (may be shown as “.010” on test) Example #3 - “.9998” - is “.999” - (may be shown as “1.00” on test)
180
2.
Pressure Calculations: Round to whole single digit as psi: Example #1 - “239.3 psi” - is “239 psi” (same as test) Example #2 - “1007.9 psi” - is “1007 psi” - (may be shown as “1008 psi” on test) Example #3 - “999.99 psi” - is “999 psi” - (may be shown as “1,000 psi” on test)
3.
Square Root - Do not round any number under a square root. Simply hit the square root button
(
)
on the calculator and utilize that full number.
SOLVING SHELL CALCULATIONS Step 1 - Determine what question is asked - minimum thickness or maximum allowed pressure? Step 2 - Go to UG-27 for IR. Formula - Appendix 1 for O.S.R. formula. Step 3 - Determine values for nomenclature necessary to solve formula. (REMEMBER -only ONE unknown can be solved - either T or P!) Write these values down in tabular form: EXAMPLE: t = ? S = 15,000 (given in problem or stress value from tables for material) E = 1.0 (Joint efficiency from UW-12 for long seam) P = 250 (given in problem) + Hydrostatic Head, if details given. R= 30 (given in problem) Step 4 - Plug in values in formula from UG27 or Appendix 1 (NOTE: When solving for "t" Hydrostatic Head must always be considered!) Step 5 - Solve mathematically - (watch numbers carefully!) Work in descending order and BE NEAT! (for Thickness) t =
PR SE −.06P
t=
250x 30 15,000x1−.6x 250
t=
7500 15,000 − 150
or
t = 7500 14,850
t = .505”
181
P=
SEt (for Pressure) R +.6t
Step 6 - Answer multiple choice question - EXAMPLE: A. "No; Shell doesn't meet Code requirements because required thickness is .505" and available thickness is .480" OR A. "Maximum pressure allowed is (x) psig.” Step 7 - Circle Answer
SOLVING HEAD PROBLEMS Step 1 - Determine what question is asked - minimum thickness or maximum allowable pressure? Step 2 - GO TO UG-32 for INSIDE dimensions of: A. 2:1 elliptical heads B. 6% knuckle radius torispherical heads C. All I.D. hemispherical heads Step 3 - Determine values for nomenclature necessary to solve formula (REMEMBER - only one unknown can be solved - either T or P) write these values down in tabular form: EXAMPLE (from UG32 -- 2:1 elliptical head): t=? P = 250 (given in problem) + H.H. D= 60 inside diameter (given in problem) E = 1.0 joint efficiency from Table UW-12 (REMEMBER; UW 11 (A)(5)(b)) S= 15,000 Stress value (given in problem or in stress tables)
Step 4 - Plug in values in formula from UG32 (NOTE: when solving for "t" hydrostatic head must always be considered) EXAMPLE: t =
PD (for Thickness) 2SE − 0.2 P
or
P=
2SEt (for Pressure) D+.2 t
Step 5 - Solve mathematically - (WATCH NUMBERS CAREFULLY!) t=
250x 60 2 x15,000x1−.2 x 250
t=
15,000 30,000 − 50
t = .500”
182
Step 6 - Answer Question - EXAMPLE: "No, head does not meet code requirements because required thickness is .500" and available thickness is .480" OR "Maximum pressure allowed in head is x PSIG - This condition is acceptable because MAWP on vessel is y PSIG." Step 7 - Circle answer
SOLVING NOZZLE WELD SIZE PROBLEMS STEP 1 - Determine what question is asked - Allowable throat or allowable leg. STEP 2 - From description in problem, determine applicable sketch from Figure UW-16 (may be provided in problem) EXAMPLE: "A nozzle conforming to sketch UW-16.1(K) has a ½" fillet weld on the inside and a 1/4" fillet weld on the outside. The nozzle is .280" wall thickness and the shell is .375" thick. Does this condition comply with the Code? STEP 3 - From UW-16, determine what requirements are: t 1 = t 2 > 1 1/4t min and t 1 or t 2 not less than the smaller of 1/4" or .7t min . STEP 4 - Set up problem and nomenclature EXAMPLE: t min = 3/4" or thickness of thinner parts - .375" or .280" (smaller) Therefore: t min = .280" t 1 = 1/4" leg = .707 X .250" = .176 throat (actual) t 2 = ½" leg = .707 X .500" = .353 throat (actual) STEP 5 - Plug in values (WATCH MATH ERRORS!) t 1 + t 2 = .176 + .353 = .529 1 1/4 t min = 1.25 X .280 = .350" .529 > .350" OK t 1 = .176, smaller than .250, (.7t min = .196) smaller than .7t min - Doesn’t meet Code t 2 = .353, larger than .250, larger than .7t min - Does meet Code STEP 6 - Answer question EXAMPLE: "Outside fillet weld does not meet Code requirements because it is smaller than that allowed by Code rules."
STEP 7 - Circle answer
183
SOLVING HYDROSTATIC/PNEUMATIC TEST PROBLEMS
STEP 1 - Determine what question is asked - "What is the hydrostatic test pressure required? What is the pneumatic test pressure required? What is the minimum temperature for pneumatic testing? Does the condition shown comply with the Code?" STEP 2 - From description in problem go to UG-99 for hydrostatic test or UG-100 for pneumatic test. UG-99 states hydropressure is 1.3 X MAWP (May be design pressure) marked on vessel times the lowest ratio of stresses for materials used in vessel, with hydrostatic head considered. Pneumatic testing is 1.1 X MAWP X lowest ratio of stresses for materials used. STEP 3 - REMEMBER: For hydrotest the recommended minimum temperature is 30 deg. F. above minimum design metal temperature. For pneumatic tests the temperature shall be at least 30 deg. F. above the minimum design metal temperature. (Also for pneumatic tests see NDE requirements of UW-50) STEP 4 - EXAMPLE: For a 30' tall vessel with an MAWP of 200 psig @ 700 deg. and material of SA516 GR70, what is minimum hydropressure on bottom head? 200 X 1.3 X 17,500@ ambient
+ (30 X .433 H.H.)
14 ,800@ 700 deg.
= 200 X 1.3 X 1.18 + 12.99 = 319.79 psig EXAMPLE: Same problem as above, only a pneumatic test is applied. 200 X 1.1 X 1.18 + 0(HH) = 259.6 psig STEP 5 - Answer the question EXAMPLE: "Yes this hydrostatic test meets Code requirements" or "The minimum hydrostatic/pneumatic pressure to be applied to this vessel is 319.79/259.6 psig." STEP 6 - Circle answer
184
SOLVING NOZZLE REINFORCEMENT PROBLEMS
STEP 1 - Determine what question is asked - "Is reinforcement necessary? Does the condition described conform to Code requirements?" STEP 2 - From description in problem, determine which sketch in Table UW-16 is applicable and sketch out on paper. If no sketch is shown in book, sketch out and determine which UW-16 sketch is closest to the one described. STEP 3 - Check fillet weld sizes, if nozzle has fillet welds (REMEMBER - leg = 1.414 X throat dimension) (throat = .707 X leg dimension) EXAMPLE: Nozzle configuration is as shown in UW-16 sketch (C). Fillet weld size is .375", and shell thickness is 1", and nozzle thickness is .500". From UW-16 throat must be tc where tc = not less than the smaller of 1/4 or .7t min . t min = smaller of 3/4" or thickness of thinner parts joined (.500") Therefore, t min = .500" and .7t min = .350" tc = smaller of .250" or .350" -- tc = .250" Actual: .375" leg weld = .375 X .707 = .265 actual throat .265 is larger than .250, therefore, fillet weld is acceptable. STEP 4 - Set up windows of reinforcement per Fig. UG-37.1 Parallel plane is the larger of the finished diameter of the opening or the inside radius of the nozzle plus the nominal thickness of the nozzle wall, plus nominal thickness of the vessel wall. Perpendicular plane is smaller of 2.5 X the nominal shell thickness or 2.5 X the nominal nozzle thickness. EXAMPLE: An 8" I.D. .500" wall nozzle is inserted into a 1" thick shell. Parallel plane is larger of 8" or (4" + 1" + .500") - Therefore, 8" on each side from the centerline of the nozzle is the parallel limits. Perpendicular limit is smaller of 2.5 X 1" = 2.5 or 2.5 X .500 = 1.25 -- Therefore, perpendicular limit is 1.25" from each surface of the shell. STEP 5 - Determine values for nomenclature in math formulas given for A, A 1 , A 2 , ETC. in Fig. UG-37.1. REMEMBER: All “Fr” = 1.0, All “F” = 1.0, and all E = 1.0. Therefore, the back half of the A and A 1 formulas becomes 0, always! STEP 6 - Plug in values in formula and work accordingly. WATCH MATH VERY CAREFULLY HERE - MISTAKES ARE EASY TO MAKE! (REMEMBER: short cuts such as "If frl=1 the back end of A and A 1 calculations becomes zero")
185
STEP 7 - Compare A 1 + A 2 + A 3 + A 41 + A 43 to value for A. If A is greater, nozzle is adequately reinforced. If A is smaller, nozzle needs reinforcement. STEP 8 - Answer Question EXAMPLE: "Nozzle is adequately reinforced per ASME Requirements" or "Nozzle is not adequately reinforced per ASME requirements and will require additional reinforcement." STEP 9 - Circle answer
SOLVING EXTERNAL PRESSURE PROBLEMS STEP 1 - Determine what question in being asked - "What is the maximum allowable external pressure for a given condition? Does the condition given meet the Code?" (A given pressure compared to MAWP) STEP 2 - Go to UG-28 and determine values for nomenclature. EXAMPLE: A 60" OD vessel is 25' long and is supported at 5' intervals. The stamped MAWP (external) is 20 psig @ 500 deg. F and the vessel is made from 1/2" thick SA516 GR70 plate. Does this condition comply with the Code? NOMENCLATURE VALUES: PA = ? D o = 60" L = 5' or 60" P = 20 psig external tS or t = 1/2" or .5 temp = 500 deg. F. STEP 3 - Fig UG-28, follow directions as stated EXAMPLE: Ratio of D o /t = 60/.5 = 120 Ratio of l/ D o = 60/60 = 1 STEP 4 - Enter external pressure chart, Figure G, at value of 1.0. On left hand side of chart. Move right to intersection of angled Dot value of 120 (between 100 and close to 125 lines). At intersection, read straight down to factor A value at bottom of page approximately .001 = factor A. STEP 5 - Using .001 (Factor A) go to chart CS1 or CS2 on next page (CS1 for material with yield strength of 24- up to 30,000 PSI, CS2 for 30,000 and over) SA516 GR70 yield strength is 38,000 psi, so use table CS2. STEP 6 - From CS2 enter table at bottom at Factor A (.001) - read up to where curved lines for temperature intersects line at .001. Read temperature @ 500 deg. F intersecting .001, and then read to right hand side of chart = 10,000 (Factor B)
186
STEP 7 - From UG-28 (Step 6) using value of B, compute formula given: Pa =
4B ⎛ Do ⎞ 3⎜ ⎟ ⎝ t ⎠
Pa =
40,000 360
=
=
Pa
=
4 x10,000 3x120
111.11 MAWP
STEP 8 - Answer the question - "Yes condition complies with Code because shell is good for 111 psig MAWP and stamped pressure is limited to 20 psig." STEP 9 - Circle answer
SOLVING IMPACT TESTING PROBLEMS STEP 1 - Determine what question is asked - "Does the condition comply with Code? What is the minimum temperature allowed for the material given? Does this material require impact tests?" EXAMPLE: "An existing pressure vessel made of SA516 GR70 material (normalized) is moved into a service where the lowest-expected operating temperature is -30 deg. F. If the material is 2" thick, 60" I.D., and is spot radiographed with Type 1 joints, can this vessel be operated at the temperature given without impact tests, with a 250 psig MAWP at 90°F?" (1/2" corrosion allowance is provided) STEP 2 - Determine if material is automatically exempted by UG-20(f) or UCS 66(b)(3). Not exempt per UG-20 (i.e. 2" thick and colder than -20)? Not exempt per UCS-66? STEP 3 - Go to Fig. UCS-66. Determine what curve SA516 GR70 is on curve D for normalized SA516 material. This is the most important step! Find the right material on the right curve! STEP 4 - Enter bottom of chart at thickness 2" - intersect curve D material at 2" - Read left to min design temperature - Approximately -5 deg. This is warmer than allowed so we must see if we can reduce this temperature further as allowed by UCS-68(c). STEP 5 - If voluntary PWHT has been conducted, a 30°F temperature reduction from the MDMT (at the intersection of the curve and thickness) may be taken. Since our example does not state whether PWHT has been done, we cannot take this allowance. STEP 6 - Answer the question - "No vessel cannot be operated at -30 deg. F per requirements of UCS-66 without impact tests. STEP 7 - Circle answer
187
SOLVING FLAT HEAD CALCULATIONS
STEP 1 - Define what question is being asked - "What is the minimum thickness of the head in question? Does the condition given comply with Code requirements?" STEP 2 - Go to UG-34 and Fig. UG-34 and determine which picture applies to the condition given in the problem: EXAMPLE: "A flat circular head of 24" I.D. is attached by inside and outside fillet welds as shown in UG-34 sketch f. The head is made from SA516 GR70 material, and the MAWP is 200 psig @ 500 deg. Assuming the fillet welds comply with the Code and a "C" factor of .20, what is the minimum thickness required for this head?" STEP 3 - Go to applicable paragraph in UG-34, and solve accordingly t = d
t = 24
CP
SE
.20x 200 17 ,500x1
t = 24 X .047
t=? d = 24" C = .20 P = 200 S = 17,500 E = 1 (no welds specified assume seamless)
t = 1.14 STEP 4 - Answer the question - "The minimum thickness required is 1.14." STEP 5 - Circle answer
NOTE:
The only hard thing about these calculations is finding the correct C factor and determining fillet weld size. So far this information has always been given, but there's always a first time!!!!
188
SOLVING API 510 CORROSION PROBLEMS
STEP 1 - Determine what question is being asked - “What is allowable internal inspection interval for conditions noted? What is corrosion allowance? How many more years may vessel operate within principals of ASME Code?” EXAMPLE: A 60” i.d. pressure vessel in caustic service is measured at .375 thickness one year. At the next inspection 5 years later the vessel has thinned to .200”. 5 years later, the vessel has thinned to .150”. From the above information when should the next internal inspection be scheduled per API 510 if the minimum thickness per ASME is .100”? STEP 2 - From API 510 – SHORT TERM CORROSION = .200 - .150 = .05” SHORT TERM CORROSION RATE =
.05" = .010” Per Year 5
CORROSION ALLOWANCE = .150 - .100 = .050” REMAINING LIFE BASED ON SHORT TERM CORROSION RATE =
.100 = 5 Years .010
STEP 3 - From API 510 LONG TERM CORROSION = .375 - .150 = .225 LONG TERM CORROSION RATE =
.225 = .0225 10
CORROSION ALLOWANCE = .150 - .100 = .050 REMAINING LIFE BASED ON LONG TERM CORROSION RATE =
.050 = 2.22 Years .0225
STEP 4 From API 510 - Where remaining safe life is less than 4 years, the inspection internal may be the remaining life up to a maximum of 2 years. STEP 5 - Answer the question - “Internal inspection must be done at 2.2 years from the last internal inspection”. STEP 6 - Circle answer
189
REVIEW OF ASME SECTION VIII AND API 510 SAMPLE CALCULATIONS
190
1.
A horizontal deaerator has been in-service for approximately 10 years. An onstream inspection shows that the vessel shell thickness is .275" (uniform) and that the heads have both pitted, reducing the thickness at the crown radius to .300. The MDR for this vessel reflects that the shell is made from SA 414 GR E plate with Type #2 longitudinal joints in all three courses, with an I.D. of 66". The heads are made from SA 285 GR C material, and are full hemispherical, with weld seams (Type 1) with an I.D. of 66" The nameplate stamping shows that the original MAWP is 280 psig @ 650°F, and complies with the rules for spot radiography (RT-3) with no static head considered, can this vessel be allowed to continue to operate at this pressure and temperature? If it should be reduced, what is the MAWP that can safely be applied to this vessel? (shell S = 16,200, Head S = 13,800) a. b. c. d.
2.
A tubular heat exchanger is constructed with a flat, unstayed, seamless circular head, welded to the shell with inside and outside fillet welds as shown in Fig. UG-34, Sketch (F) (C=.20) The measured thickness of the head is 1", and is corroding approximately 1/32" (uniform) every year. The thickness of the shell has not corroded, and an onstream inspection shows the shell to be .375" thick. There are Type #1 joints in the shell, with full RT, and a vessel I.D. of 30". The fillet welds are in good condition, and are measured at .375" on both the inside and outside welds. The diameter of the head is 30", and the vessel is stamped for an MAWP of 90 psig @ 500°F. The head is constructed of SA-516 GR 70 material, and the shell is constructed of SA 285 GR C material. Assuming that the corrosion rate of 1/32" per year will continue, how many more years may this vessel be allowed to operate within the principles of the ASME Code? (head S = 17,500) a. b. c. d.
3.
No - allowable pressure should be reduced to approximately 212 psig. No - allowable pressure should be reduced to approximately 107 psig. Yes - vessel is acceptable for operation at 280 psig. Yes - vessel is acceptable for operation at 280 psig, if impact tests are conducted.
1.96 years 3.42 years 9.62 years 1.21 years
A new pressure vessel has been received from a manufacturer with the following information available to the Inspector about the shell:
made
MAWP 500 psig @ 780°F MDMT 10°F 200 psig Spot RT, 60" I.D. Hydro pressure 750 psig @ 70°F (material stress is 18,100 psi @ 70ºF) Material: SA 387 GR 21, CL 1 Thickness: .350" (P# 5 material, Stress = 14,000) Type 1 Category A welds Vertical height: 140 feet No impact tests performed No heat treatment performed Material not normalized From the above given information, how many individual Code violations can you, as the Inspector, find as reason for not accepting this replacement part? a. b. c. d.
No violations - This part meets all Code requirements. 3 Code violations 5 Code violations 10 Code violations
191
4.
A fractionating tower is 14' I.D. X 21' long, bend line to bend line, and is fitted with fractionating trays. The tower is designed for an external design pressure of 15 psig @ 700°F. The tower is constructed of SA-285 GR C carbon steel, yield strength 30,000 psi, and the design length is 39" between the fractionating trays, which are adding support to the vessel. Does this construction comply with ASME VIII requirements (assuming a designed thickness of ½")? a. b. c. d.
5.
An ASME-stamped pressure vessel has been altered and now requires a hydrostatic pressure test to be applied. The vessel is 175' tall and has a pressure gauge at the top of the vessel and another gauge 25' up from the bottom of the vessel for the Inspector to look at. The MAWP is 125 psig. The ratio of design to material test stress = 1. What pressure should be shown on the gauge at the 25' level to meet API 510 requirements? a. b. c. d.
6.
approximately 275 psig approximately 185 psig approximately 125 psig approximately 228 psig
An existing carbon steel pressure vessel is stamped for lethal vapor service, and has an elliptical 2:1 head. The head is measured at 60.25" I.D. in the corroded condition. The head, when new, was 1.375" thick and 60" I.D. The stress value is 13,800, the MAWP is 300 psig, and the head is attached to the shell with a Type 1 Category B weld. Assuming a corrosion rate of 1/8" per year, answer the following questions:
•
What are the radiography requirements for the head-to-shell joint?
•
Does the head, in its corroded condition, meet ASME Code requirements?
•
If the answer to B is yes, how many more years can the vessel operate within the parameters of ASME Code requirements?
a. b. c. d. 7.
Yes, meets Code requirements No - does not meet Code - pressure should be increased to 30 psig No - does not meet Code - pressure should be decreased to 10 psig No - does not meet Code - thickness should be increased to 3.6”
full, yes, 4.75 years spot, yes, 8.95 years partial, no, 10.65 years none of the above
A torispherical head is connected to a seamless vessel with a single welded butt joint with backing. The seam has been welded by a single welder, and is spot radiographed per UW11(a)(5)(b).
• a. b. c. d.
What is the type of joint, joint category, and joint efficiency factor? Type 1, Cat. D, E = .85 Type 2, Cat. B, E = 1.0 Type 3, Cat. A, E = 1.0 Type 2, Cat. B, E = .85
192
8.
A 60" I.D. pressure vessel will require a fillet welded (temporary) patch plate. The patch and the shell are both SA 515-60 material (S = 15,000). The patch is .375" thick and the vessel is .622" thick with no corrosion allowance. The vessel has Type 1 Category A welds, and is stamped for RT-2, 200 psig @ 500°F, and an MDMT of -15°F. From the information given, will this repair require the use of a welding procedure that has been impact tested? a. b. c. d.
9.
A nozzle is installed in a vessel shell, as illustrated in Fig. UW-16.1(i), using two equal size fillet welds. The minimum shell thickness is 3/4 inch and the nozzle wall is 7/16 inch minimum thickness. Using equal leg fillet welds, what is the leg dimension of the welds rounded up to the next larger 1/16 inch? a. b. c. d.
10.
yes, impact tests are required on the welding procedure no, impact tests are not required on the welding procedure yes, impact tests are required on both the base metal and welding procedure no, impact tests are only required on the base metal
7/16” 3/16” 9/16” 11/16”
A vertical vessel is to be rerated to a new Maximum Allowable Working Pressure based on calculations of the vessel parts. The top of the vessel is located at an elevation of 75 feet. The following calculated values (P) have been determined by the Engineer (elevations are given to the bottom of the item being considered, (static head of water equals 0.433 psi per vertical foot): 1. 2. 3. 4. 5.
top head, elevation 72.5 feet, P-351.3 psi top shell section, elevation 65 feet, P - 352.6 psi manway connection, elevation 50 feet, P = 360 psi reducer section, elevation 30 feet, P = 372.5 psi bottom head, elevation 6 feet, P = 425 psi
What is the maximum value of MAWP which can be applied to this vessel? a. b. c. d. 11.
450 psig 360 psig 395 psig 348 psig
During the inspection of a horizontal pressure vessel, a torispherical head is measured and found to have the following dimensions: Thickness equals 1.25 inches. Inside diameter of skirt = 48 inches. The distance from the bottom of the head to the top of the vessel is 5 ft 6 in. The weight of water equals 0.433 psi/ft. From the vessel data report S = 15000 psi, and “RT-2” has been met. At what Maximum Allowable Working Pressure can this head be used with no corrosion allowance? a. b. c. d.
490 psig 390 psig 416 psig 426 psig
193
12.
A lap patch is to be installed on a pressure vessel built to ASME Code, Section VIII, Div. 1 as part of a repair of the vessel. The patch is made of SA-515 Gr. 70 material (P-No. 1), 1-1/8 inch thickness without normalization. The owner’s engineer has determined the ratio of the allowable stress to the actual stress to be 1.0. The vessel nameplate lists the MDMT as 50°F with “HT” for the heat treatment, therefore, the patch will be voluntarily heat treated. Will the patch plate require impact testing? a. yes b. no c. no, if welding procedure is impact tested d. none of the above
13.
A pressure vessel cylindrical shell is measured and found to be 1.36 inches thickness at its thinnest point. The inside radius was measured at 28.625 inches. Plant records provide the following information: 1. 2. 3. 4. 5.
•
Based on the above, how much material thickness is available as remaining corrosion allowance?
•
What is the remaining life of the vessel?
a. b. c. d. 14.
.111”/10.61 years .250”/3.6 years .101”/5.31 years .202”/4.1 years
A vessel’s cylindrical shell has corroded down to .25” in thickness. The cylinder is 40” o.d. with an unsupported length of 10’. Design temperature is 300°F, and the material yield strength is 30,000 psi. What is the allowable external pressure allowed on this vessel? a. b. c. d.
15.
The vessel has been in service for 4 years The original vessel thickness was 1.4375 inches minimum The allowable stress of the vessel material is 17500 psi at design temperature The weld seam efficiency is 1 The maximum allowable working pressure is 745 psi with a static head of water equal to 5 psi
38 psi (approximately) 45 psi (approximately) 12 psi (approximately) 23 psi (approximately)
During the inspection of an existing pressure vessel you find it necessary to determine the weld seam efficiency of several joints on a vessel. The vessel nameplate shows RT-4. The joint type and degree of RT we read from ASME data reports for the vessel. What are the joint efficiencies for the following? Type 1. Type 1 2. Type 3 3. Type 2 a. b. c. d.
1., .85 1., .90 1., 1.00 1., .85
Category Cat A Cat B Cat C 2., .60 2., .90 2., 1.00 2., .80
RT spot Full RT Full RT 3., .90 3., 1.00 3., 1.00 3., .80
194
Joint Efficiency 1. ______________ 2. ______________ 3. ______________
16.
A vessel cylindrical shell is measured today and found to be 1.0625” at the thinnest point. The inside radius is 24”. Plant records provide the following: 1. Vessel has been in service 64 years. 2. Original t was 1.1875” min. 3. SV = 15000 at design 4. Efficiency = .85 5. MAWP = 500 psi with a static head of water equal to 6 psi 6. Previous (last) inspection was completed 8 years ago and the wall thickness was 1.087
• • a. b. c. d. 17.
.065”/40.6 years .0868”/29.93 years .001”/32 years .862”/15.6 years
no, head must be replaced no, head must be repaired yes, head can continue in service no, head thickness must be 2.5” to be acceptable
A vessel owner is to repair a pressure vessel by replacing one of the vessels seamless ellipsoidal heads with a duplicate head, but welded to the shell. The original vessel name plate is stamped “W” “RT-2” and “HT”.
•
What type or types welded joints may be used in the repair?
•
What Radiographic Testing of the joint is required?
a. b. c. d. 19.
What is the remaining life of the vessel?
A flat unstayed circular head with a diameter of 14” is operating at 350 psi at 500°F. The SV = 17500 with an efficiency of 1.0 the C factor = .33. Can this head continue in service in its present state or would a repair be necessary, if the present thicknesses is 1.25”? a. b. c. d.
18.
Based on the above information, how much material t is available as remaining corrosion allowance?
Type 1/full RT Type 2/spot RT Type 3/full RT Type 1 or 2/spot RT
A vertical pressure vessel in water service with Type 1 Category "A" long seam welds is 10' seam/seam, is made from 1/2" thick SA516 GR70 material (S = 17,500), is stamped for an MAWP of 100 psig @ 650°F, and is also stamped as "RT-3" (satisfies spot radiography rules) with an I.D. of 60". What is the actual minimum thickness of this vessel, including hydrostatic head. a. b. c. d.
.211” .250” .350” .360”
195
20.
The heads on the vessel in #19 are 2:1 elliptical heads, are seamless, and are made from the same material, same diameter, same thickness, and are welded to the vessel with Category "B" Type 1 circumferential welds. What is the minimum thickness of the bottom head if the extra radiograph required by UW-11(a)(5)(b) is taken on each head-to-shell weld? (Remember static head) a. b. c. d.
21.
Assuming the same parameters for the above pressure vessel in # 19, but the heads are seamless hemispherical heads with a 30" spherical radius attached with a Category "A" Type 1 full penetration weld, what is the minimum thickness of the bottomhead? a. b. c. d.
22.
25 psig 31 psig 17 psig 50 psig
What is the required thickness of a seamless flat, unstayed circular head with a diameter (or SA105 short span) of 24", an internal design pressure of 250 psig @ 650° F, with material of (S = 17,500)? Attachment is as shown in Fig. UG-34(A), and the inside corner radius is not less than three times the required head thickness. a. b. c. d.
24.
.250 .220” .179 .105”
An 8 feet I.D. horizontal pressure vessel with Type 1 weld joints is constructed totally of SA285 GR C (S = 12,100) plate with two courses (one circumferential seam joining two cylinders.) The original thickness is .375" uncorroded (new and cold) and the vessel is stamped for full radiography (RT-1). The MAWP is 50 psig @ 750° F. The heads are torispherical, 6% knuckle, 96.75" O.D. skirt, and were .375" thick also when new. An onstream inspection shows the vessel has corroded evenly over the head and shell with a uniform 1/4" external corrosion. What MAWP can this vessel be operated at, assuming no static head? a. b. c. d.
23.
.250” .200” .179” .105”
1.1” 1.9” 2.3” 1.66”
Given the parameters of the above flat head in #23, assume the head is not circular but elliptical with the same short span and a long span of 36". What is the required thickness of this head? (NOTE: This question is not supposed to be in the test, but a similar question has been asked previously.) a. b. c. d.
1.9” 1.5” 2.1” 1.66”
196
25. A 60" I.D., 1" thick pressure vessel constructed of SA442 GR60 material is stamped RT-3, and is also stamped for an MAWP of 70 psig @ 650° F. A nozzle is located in the shell and doesn't pass through a welded joint. Details of the attachment are as follows: Nozzle material - SA106 GR B Nozzle I.D. - 16" Nozzle thickness - .375" Nozzle attached to shell by full penetration weld into shell and a cover fillet weld on the outside of the shell only. Fillet weld leg lengths are 1/2" X 1/2". Attachment detail is as shown in Fig. UW 16.1 sketch (C). Does this construction need a repad? Assuming Fr, F and E= 1.0 and t R = .890" and t RN = .290". a. b. c. d. 26.
27.
no yes not enough information given none of the above
What are the parallel and perpendicular (or normal) limits of reinforcement for the nozzle in #25, above? a.
parallel - 16” normal - 2.5”
b.
parallel - 9.375” normal - .9375”
c.
parallel - 9.375” normal - 2.5”
d.
parallel - 16” normal .9375”
A pressure vessel has a new 18" ID manway installed in the shell, with a configuration similar to Fig. UW - 16(a-1). The shell thickness is .350", the manway is .280" thick, and the repad is .375" thick. The cover weld attaching the pad to the shell is .300" in size, and the cover weld attaching the pad to the nozzle is .300" in size. The nozzle is SA 516 70 rolled and welded plate (17,500 stress) fully RT’d, and the vessel is also SA 516-70 (fully RT’d. The vessel is 50" ID, and is constructed for 200 psig @ 500°F. The od of the repad is 24", and the ID of the hole in the pad is 19". The repad is also SA 516-70 material. Is this manway properly reinforced? (All Fr, E, and F = 1.0, t R = .287" and t RN = .103"). a. b. c. d.
yes no not enough information given none of the above
197
28.
A vertical one course pressure vessel in vapor service is 12' tall is made of .300" nominal wall seamless pipe, SA106 Gr B (S = 15,000). Design pressure is 250 psig @ 500° F. The outside radius of the shell is 18". The vessel is stamped RT-3 (spot RT) attached to the shell are two seamless torispherical heads made from SA516 Gr 70 plate (S = 17,500). The inside crown radius of the heads is also 18". The heads are also .300" thick. What is the MAWP of this vessel, based on the shell and heads? a. b. c. d.
29.
A 20' tall pressure vessel is stamped for 1000 psig MAWP @ 900° F. The hydrostatic test is to be applied at 70° F. Materials are SA516 GR70 and SA240 Type 302 S.S. plate. What is the minimum hydrostatic test pressure that should be applied at the bottom of the vessel to satisfy ASME Code requirements? (Stress value for SA240 Type 304 is 14,700 at 900° and 18,800 at 70°. – Stress values for SA-516-70 is 17,500 psi @ 70° F and 6,500 @ 900° F.) a. b. c. d.
30.
250 psig 279 psig 220 psig 246 psig
4038 psig 1500 psig 2000 psig 1659.66
What is the maximum allowable external pressure allowed on the following pressure vessel: O.D. = 24" Material = SA106 GR C (yield strength = 40,000 psi) Nominal thickness = .500" Total length between lines of support = 48" Design temperature = 500° F a. b. c. d.
31.
A stationary vessel is made from SA516 GR70 plate that has been normalized. The MDMT is 30°F @ 470 psig. The actual material thickness is 3.0" thick, and the vessel id is 48" and the joint efficiency is 1.0. Does this material require impact testing? a. b. c. d.
32.
327 psig 390 psig 456 psig 512 psig
yes no not enough information none of the above
A vessel is ultrasonically checked on the shell in 1990 and is .637” thick. This same spot is checked again in 1996 and is .607” thick. It is on-stream inspected again in 1999 and is .509” thick. What is the remaining life of this vessel if the maximum thickness is .411” thick? a. b. c. d.
1.5 years 2.7 years 3.2 years 6.4 years
198
33.
A pressure vessel has been inspected and found to be thinned over a 20" long area, parallel with the long seam. Thickness readings in this area are .275", .279", .280", .290" and .295". Original thickness is .375". The vessel is now 11 years old. MAWP is 80 psig @ 100°F, 24" ID and material stress is 16,800. Joint efficiency is .85. 1. What is the minimum shell thickness? 2. What is the longest dimension that can be corrosion averaged per API 510? 3. What is the internal or onstream inspection interval for the vessel based on the above? a. b. c. d.
34.
3., 10 years 3., 10 years 3., 10 years 3., 10 years
Metal loss = Corrosion rate = Corrosion allowance = Remaining life = Inspection interval =
A pressure vessel made of SA 285 GR B (12,100 = stress) material has been in service 10 years. It has a measured shell thickness of ½" at the thinnest section. If this vessel is to be operated with a stamping that indicates an internal MAWP of 300 psig @ 700 Deg. F, RT-2, Type 1 joints, and an ID of 80", what will the minimum thickness of the shell be to support this pressure? a. b. c. d.
36.
2., 12” 2., 6” 2., 2.44” 2., 2.14”
An existing pressure vessel material thickness is measured at .500" on an inspection. 4 years later, this same thickness is measured at .250" at the same location. Required thickness (by calculation) shows that the vessel must be .125" thick to withstand the given pressure. Per API 510, and from this information, what is the: a. b. c. d. e.
35.
1., .067” 1., .100” 1., .500” 1., .050”
approximately 1.200” approximately 1.00” approximately .750” approximately .890”
What is the minimum thickness required for a pressure vessel that is stamped with a 600 psig @ 500° MAWP, is 70" OD, complies with the rules for spot radiography, has Type 2 joints, is made from SA 515 GR 60 (S = 15,000) material, and is 25' high in water service? a. b. c. d.
1.950” 1.074” 1.560” 1.746”
199
37.
A pressure vessel head is thinned at the knuckle radius to .250" thick. The head is attached to the vessel with a Type 1 joint that is fully radiographed and operated at 600° F. The head is a 2:1 elliptical head with an ID of 45" and is made from SA 285 GR C (S = 13,800) material. What MAWP can be operated on this head, with no static head considered? a. b. c. d.
38.
A pressure vessel shell is 80" ID, .375" thick and the heads are torispherical (6% knuckle radius) and are also 80" ID and .375" thick. Both shell and heads are made from SA 36 plate (14,500 stress), and the shell complies with spot radiography. The heads are spliced (welded) and comply with spot radiography. Assuming all joints are Type 1, what is the MAWP allowed on this vessel based on the heads assuming a 500° temperature and vapor pressure only? a. b. c. d.
39.
403 psi 425 psi 387 psi 415 psi
An 8" nozzle on a vessel is replaced with an identical nozzle with an attachment similar to UW 16.1 Sketch C. If the nozzle thickness is .500" and the vessel shell thickness is 1". What is the minimum size of throat and leg dimensions for the attachment fillet welds? a. b. c. d.
41
70 psi 85 psi 64 psi 110 psi
If a vessel is built from SA 106 GR B (S = 15,000) seamless pipe, is .375" nominal wall thickness and has one circumferential weld joint and is 24" ID, what is the MAWP allowed if the temperature is 500° F, and the vessel is stamped “RT-2”? a. b. c. d.
40.
175 psi 153 psi 190 psi 142 psi
.170” throat/.250 leg .750” throat/1.00” leg .250” throat/.353” leg .250” throat/.250” leg
A vessel nozzle has corroded around the attachment fillet welds, reducing them to a .125 throat thickness. With a nozzle wall thickness of .350" and a shell thickness of .500" and, assuming a joint configuration in compliance with UW 16.1 Sketch (i), will this condition meet ASME Code? a. b. c. d.
yes no fillet welds not required for this nozzle not enough information given
200
42.
A 8" nozzle in a pressure vessel is to be replaced with a 10" ID SA 106 B nozzle that is .280" thick. The vessel is .75" thick and is stamped for an MAWP of 350 psig @ 600°F. The vessel ID is 60", and the vessel complies with the rules for spot RT (Type #1 joints). The installation is similar to UW-16.1 Sketch (c) with a .750” throat fillet weld. Does this nozzle require a reinforcing pad? The S.V. for the shell is 15,000 psi. The required thickness of the shell is .490” and the required thickness of the nozzle is .160” (All E, F, FR= 1.0) a. b. c. d.
43.
yes no not enough information given no reinforcement calculations required per UG-36 (c)(3)(a)
A 50' high Amine Tower has been altered and requires a hydrostatic test. The MAWP is 350 psig @ 750° F. The vessel materials are SA 516 GR 70, SA 285 GR A, and SA 53 GR B (seamless) pipe. If the test is to be conducted to ASME VIII requirements, what is the minimum hydrostatic pressure required on the bottom head if the test will be conducted at 70°F? The stress values are as follows:
70°F 750°F a. b. c. d. 44.
SA53-B
17,500 14,800
11,300 10,300
15,000 13,000
455 psi 546 psi 518 psi 670 psi
231 psi 220 psi 300 psi 425 psi
A circular flat head is seamless and is 20" diameter and is attached similar to Figure UG 34, (b-1). If the MAWP of the vessel is 300 psig @ 500 Deg F and the material is SA 105 (S = 17,500), what is the minimum required thickness of this head? a. b. c. d.
46.
SA285-A
A vessel is to pneumatically tested @ 70°F per the Code. The MAWP is 200 psig @ 700 Deg F. The materials are SA 240 Type 304 stainless steel and SA 515 GR 65. What is the minimum pneumatic pressure required on this vessel? The S.V. for SA 240 Type 304 @ 700°F is 16,800 psi, and 18,000 psi @ 70°F. The S.V. for SA515-65 @ 700°F is 15,500 and 18,000 @ 70°F. a. b. c. d.
45.
SA516-70
.894” .970” .900” 1.07”
A circular flat head is 30" in diameter and is attached to the shell with a weld similar to Fig. UG 34, (h). The head is splice-welded (seamed) with a Type 1 joint and has been spot radiographed. The head is made from SA 515 GR 60 (S = 15,000). What is the minimum thickness required on this head, assuming a temperature of 650° F and an MAWP of 375 psig? a. 1.677” b. 2.09” c. 2.955” d. 3.650”
201
47.
A vessel is constructed for external pressure and is supported at 7' intervals. The OD is 48", the thickness is .500" and the temperature is 600°F. What is the approximate maximum external pressure allowed on this vessel? The material yield strength is 28,000 psi. a. 97 psi b. 160 psi c. 181 psi d. 195 psi
48.
A vessel is made from SA 662 GR A material, SA 182 GR 21 normalized and tempered material, and SA 516 GR 70 material. All materials are .375" nominal thickness and the vessel is made for a design temperature of -30° F. Which materials, if any, will require impact testing? a. all materials b. only the SA 662 and SA 182 materials c. only the SA 182 and SA 516-70 d. only the SA 516-70
49.
A 30" ID vessel is fully radiographed, has Type 1 joints, is .500" thick and is stamped for an MAWP of 100 psig @ 300 Deg F; with a corrosion allowance of 1/16”, and a minimum temperature of -40° F. If the material is SA 516 GR 70 (not normalized), does this vessel require impact testing? (A reduction stress ratio of 1.0 will be used, per UCS 66.1). a. yes, requires impact testing b. no, does not require impact testing c. exempted from impacts per UG-20(f) d. not enough information provided
50.
A vessel is checked during an internal inspection and is found to be .753 inches thick. 5 years later the vessel is shown to be .500" thick. With a minimum thickness required of .350", determine the following: a. b. c. d. e.
51.
An 80" ID vessel is fully radiographed, is 1" thick and is made from SA 516 GR 70 (S = 17,500) material with Type #1 joints with an MAWP of 150 psig @ 600° F. If this vessel corrodes at an even rate of 1/8" per year, how many years may the vessel operate within the principals of the ASME Code? a. b. c. d.
52.
Metal loss = Corrosion rate = Corrosion allowance = Remaining service life = Inspection interval per API 510 =
5.24 years 2.62 years 10.48 years 3.15 years
A pressure vessel is 175' tall and is stamped with an MAWP of 150 psig. What is the minimum hydrostatic test pressure that should be shown on a pressure gauge that is placed 25' up from the bottom of the vessel, assuming the ratio of design stress to test stress is 1.0, and all other rules of ASME have been met? a. b. c. d.
225 psi 235 psi 250 psi 260 psi
202
53.
An elliptical head (2:1 ratio) is attached to an existing pressure vessel. The head has internally corroded around the skirt and is measured at 1/8" uniform corrosion. The original inside diameter of the head was 60", and the MAWP of the vessel is 150 psig @ 650°F allowable stress value is 17,500. With a stamping of RT-2 applied to the vessel using a Type 2 weld what is the minimum thickness required for this head? a. b. c. d.
54.
A seamless ellipsoidal head is attached to a pressure vessel using a single “Vee” groove weld with a backing strip. If spot radiography per RT-2 is conducted on this vessel, determine the following and the applicable ASME Code paragraph? A. B. C.
55.
.208” .258” .312” .335”
Para. Para. Para.
Head Efficiency Joint Category Joint Type
A pressure vessel has the following measurements (averaged) at the below locations on one year. The same readings are taken 5 years later at the same locations. With a minimum thickness of .125" at all locations, determine the remaining life of each component:
1st year
5th year
Top Head
Bottom Head
Shell # 1
Shell #2
Nozzle #1
Nozzle #2
.350
.300
.285
.275
.265
.250
.300
.270
.270
.200
.150
.230
Remaining Life
56.
A vessel is stamped for 400 psig design pressure and is currently measured to be .788” thick. The shell material stress value is 16,800, and the joint efficiency is .85. The i.d. of the vessel is 47.5”. If the corrosion rate is known to be .012” per year, and the next inspection is scheduled for 6 years from the current inspection, per API 510 PARA. 6.4 this vessel: a. b. c. d.
may continue to be operated for 6 years at the current design pressure should be reduced in pressure or inspection interval should be allowed to operate at 550 psi should be immediately removed from service
203
57.
A 60 KSI tensile strength weld metal is used to repair a 75 KSI tensile strength base metal. Total base metal thickness is .390”, and the depth of the repair is .195”. What is the required total thickness of this weld deposit, per API 510? a. b. c. d.
58.
.195” .390” .520” .243”
A pressure vessel is currently .370” thick. 10 years from now the vessel is scheduled to be inspected again. The stress is 17,100 psi and the vessel is stamped RT-2 with Type 2 longitudinal weld seams. The last thickness measurements (5 years ago) reflected that the vessel was .407” thick. If the vessel is 72” I.D. and the corrosion rate is expected to continue, what MAWP should be allowed on the vessel per API 510 Para. 6.4? a. b. c. d.
98 psi 150 psi 180 psi 200 psi
204
ANSWER KEY 1.
Shell:
P=? t = .275 E = .80 R = 33 S = 16,200 P=
16,200x.80x.275 33+.6x.275
P=
3564 33165 .
P = 107.462 psig (No H.H.)
P=
7038 33.06
P = 212.88 psig (No H.H.)
Heads: P = ? t = .300 L = 33 E = .85 S = 13,800 P=
2 x13,800x.85x.300 33+.2 x.300
ANSWER: B
2.
t=? d = 30 P = 90 S = 17,500 E = 1.0 C = .20 t = 30 .20x 90
t = .962
1 - .962 =
17 ,500
ANSWER: D
3.
1. Pressure not to Code for thickness 2. Impacts required 3. Hydro pressure insufficient 4. Heat treatment required 5. Full Radiography required ANSWER: C
4.
L = 39 D o = 169” t = .5 L/D o = .230
A = .001 B = 8,000
205
.038CA .03125CR
= 1.21 years
D o /t = 338 yield = 30,000 PA =
4 x8000 3x 338
ANSWER: A.
5.
PA =
32 ,000 1014
PA = 31.55 psig
Yes, meets Code
175' tall with a gauge at 25' = 150 ft of head pressure acting on gauge MAWP = 125 DS/MS = 1.0 1.3 X MAWP X (1.0) + (H.H.) = 1.3 X 125 + (.433 X 150) = 162.5 + 64.95 = 227.45 PSIG ANSWER ANSWER: D
6.
A. FULL, Per UW-11(a)(1) B.
t = 1.25" P = 300 (No H.H.) S = 13,800 E = 1.0 D = 60.25
From UG-32
t =
t=
300x 60.25 2 x13,800x1−.2 x 300
t=
18.075 27 ,600 − 60
PD 2 SE −.2 P
=
18,075 27 ,540
=
.656 REQUIRED
ANSWER B - YES .656 REQUIRED < 1.25 ACTUAL
C. CA = RL 1.25 CR - .656 ANSWER: A 7.
8.
=
.594 .125
=
4.75 YEARS
Type 2, Category B weld, with a joint efficiency of or 1.0 per UW-11(A)(5)(b) . ANSWER: B S = 15,000 E = 1.0 R = 30 t = .622” P = 200
206
t=
200x 30 15,000x1−.6x 200
t = 6,000 14,880
t = .403 From Fig. UCS-66 - Curve B @ .622 = 5°F. From Fig. UCS-66.1 -
.403x1.0 = .64 .622 − 0
Allowable Reduction = 35°F Allowable = + 5 - 35°F = -30°F, which is lower than -15°F. ANSWER: B. No, impact tests not required. 9.
UW-16.1 Sketch (I):
t
1
t min = .4375”
375" .7 t.4 min = .306” 1 1/4 t min = .54
.7 5 0 "
t2 FromUW-16.1, Sketch (I), welds must be: (a) t 1 + t 2 > 1 1/4 t min (b) t 1 or t 2 not less than smaller of 1/4” or ,7t min
Step 1: .546/2 = .273 + .273 = 1 1/4 t min - “a” is satisfied Step 2: .273 is greater than .250” - “b” is satisfied Step 3: Convert Throat to Leg - .273 x 1.414 = .386” Rounding up to next larger 1/16” = 7/16”10. ANSWER: A = 7/16”
207
10.
a) Top head elev. 72.5’ @ 351.3 psi = 75’ - 72.5’ =
2.5’ x.433 1.082
351.3 - 1.082 = 350.218
b) Top shell elev. 65’ @ 352.6 psi = 75’ - 65’ =
10’ x .433 4.33
352.6 - 4.33 = 348.27 c) Manway elev. 50’ @ 360 psi = 75’ - 50’ =
25’ x .433 10.825
360 - 10.825 = 349.175 d) Reducer elev. 30’ @ 372.5 = 75’ - 30’ =
40 x .433 17.32
372.5 - 17.32 = 355.18 e) Bottom head elev. 6’ @ 425 psi = 75’ - 6’ = 69’ x .433 = 29.877 425 - 29.877 = 395.123 Question: What is the max. value of MAWP which can be applied to this vessel? 348.27 psig ANSWER: D
208
11.
Torispherical head - given:
t = 1.25 skirt i.d. = 48 L = skirt OD = 50.5 S = 15,000 E = 1.0 (UW-11 (A)(5)(b) has been met) H.H. = 5.5 x .433 = 2.381 psig
From UG-32 P =
SEt .885L + −01 .t
P =
15,000 x1x125 . .885x50.5+.1x125 .
P =
18,750 44.69+.125
P = 418.3 psig - 2.3 psig (H.H.) = 416 psig ANSWER: C
12.
SA 515 Gr 70 not normalized, 1 1/8” thick Allowable Stress Ratio = 1, MDMT -10°F a) UG - 20 (f) - Not exempt b) UCS 66 (Figure) General notes - curve A material c) UCS 66 (Figure) - Requires impacts @ 75° for 1.25” material d) UCS 66 (b) Figure - Allows reduction of 0 for 1.0 ratio e) UCS 68(c) - 30° reduction allowed for voluntary PWHT, 75°F - 30°F = 45°F < 50°F. Therefore, vessel is exempt from impact testing ANSWER: B. Per UCS 66 (a) and (b) this material will not require impact testing
13.
Measured t = 1.36” Inside Radius = 28.625” S = 17,500 E = 1.0 P = 745 psi H.H. = 5 psi t=
PR SE −.6 P
Original t = 1.4375” 4 years in service
t=
750x 28.625 17,500x1−.6x 750
t = 21,468.75 17,050
t= 1.259”
209
13. continued A. 1.36” - 1.259 = .101” Corrosion Allowance B. 1.4375 - 1.36 = .07 metal loss 4 years
- ANSWER
= .019 per year corrosion rate
B. .101/.019 = 5.31 years Remaining Life --ANSWER ANSWER: C
14.
t = .25” o.d. = 40” (D.O.) L = 10’ or 120” D o /t = 160 L/ D o = 3.0 Factor A = .0002 Factor B = 2,800
From UG-28(C): Step 1: • D o /t = 40/.25 = 160 > 10 (use Path (1)) • L/ D o = 120/40 = 3.0
Step 2 and 3 • Fig G determine “A”
• Enter Chart at 3.0 - over to 160 intersects at approximately .0002 = Factor “A” Step 4 and 5 • Using Figure CS-2 (provided @ test location): Enter bottom @ .0002 up to 300° line - read right approximately 2,800 = Factor B Step 6:
• PA =
4B 3( Do / t )
• PA = 4 x 2800 3(160)
• PA =
11200 480
NOTE: Step 7 is n/a for this problem
• PA = 23.333 psi allowed Step 8: ANSWER: D.
210
15.
• RT-4 stamping,
• degree of RT from Data Report
• Efficiencies obtained from Table UW-12 A. Type 1 B. Type 3 C. Type 2
Cat.A Cat B Cat C
Spot RT No RT Full RT
ANSWER: 1:
.85 Joint Efficiency
ANSWER: 2:
.60 Joint Efficiency
Efficiency .85 Efficiency .60 Efficiency .90
ANSWER: 3: .90 Joint Efficiency ANSWER: A
16.
1.062” = t (corroded), 1.1875” original 24” = R 15,000 = S .85 = E (6+) 500 = P + H.H. = 506 A. From UG-27
•t=
PR SE −.6 P
• t=
506x 24 15,000x.85−.6x506
•
12 ,144 12 ,750 − 303.6
•
12,144 12446.4
t = .9757” required thickness 1.0625” (present “t”) - .9757” (required “t”) = .0868” ANSWER: - A: .0868” Remaining Material for Corrosion Allowance B.
Remaining Life = Corrosion Allowance/Corrosion Rate (from API 510) Corrosion Rate = 1.087 (8 years ago) - 1.0625 (present thickness) 1.087 - 1.0625 = .0245 in 8 years .0245/8 = .003 per year .0868/.003 = 28.933 Remaining Years
ANSWER B - Remaining Life = 28.933 years ANSWER: B
211
17.
From UG-34(c)(2): Editor’s Note: Questionable Values Provided!
t=d
t = 14
CP
→ → →
t = 1.25” d = 14 P = 350 C = .33 S = 17,500 E=1
SE
.33x 350 17 ,500x1
t = 14
1155 . 17 ,500
t = 14
.0066
t = 14 x .081240384 1.13” < 1.25” t = 1.13 ANSWER:
18.
C. Yes, this Head can continue to operate at the pressure shown
From UG-116: HT = Heat Treated W = Welded RT2 = Full (per UW 11(A)(5) and (A)(5)(b)) ANSWER A - Type 1 or Type 2 Per UW 12(d) ANSWER B - One Spot Radiograph in accordance with UW-52 for each seam. This Radiograph would be required over and above any other RT requirements. Para. UW 11(a)(5)(b) ANSWER: D
19.
t = .5 P = 100 + 4.33 HH = 104.33 E = .85 S = 17,500 ID = 60" IR = 30
t=
104.33 X 30 17,500 X .85 - .6 X 104.33 ANSWER: A
From UG-27: t = PR SE - 0.6P
=
3,129.9 14,875 - 62.598
212
=
3,129.9 = .211 14812.402
20.
t = .5 P = 100 + 4.33 E = 1.0 S = 17,500 ID = 60 IR = 30
HH = 104.33
From UG - 32: t = PD 2SE - 0.2P
=
t = 104.33 X 60 2 X 17,500 X 1.0 - .2 X 104.33 ANSWER: C
21.
t = .5 P = 100 + 4.33 HH = 104.33 S = 17,500 E = .85 L = 30" ID = 60"
t = 104.33 X 30 2 X 17,500 X .85 - .2 X 104.33 ANSWER: D
22.
6,259.8 = 35,000 - 20,866
6,259.8 34,979.134
= .179
From UG-32(f) t = PL 2SE - 0.2P
=
3,129.9 29,750 - 20.866
= 3,129.9 29,729.134
= .105"
Shell t = .375 - .250 = .125 ID = 96" IR = 48" S = 12,100 P=? E = 1.0
Heads t = .375" - .250 = .125 P=? S = 12,100 L = ICR = OD of skirt = 96.75" - .500 = 96.25 E = 1.0
Shell:
From UG-27
Heads: From UG-32
Shell:
P =
12 ,100x1x.125 48+.6x.125
P =
1512.5 48.075
Heads: P =
P =
P = 31.46 psig
12 ,100x1x.125 .885x 96.25+.1x.125 1512.5 85.301
P = 17.731
Answer = 17.731 psig ANSWER: C
213
23.
t=? D = 24 P = 250 S = 17,500 E = 1.0 C = .17
From UG-34
t = d CP / SE
t=
24
.17 X 250 17,500 X 1
t=
24
42.5 17,500
t=
24
.0024285
t=
24 X .04592
t=
1.182" ANSWER
ANSWER: A
24.
t=? d = 24 D =36 S = 17,500 E = 1.0 Z = 1.8 C = .17 P = 250
From UG-34 t=d
ZCP / SE
Z = 3.4 - 2.4 X 24 36 Z = 3.4 - 1.6 Z = 1.8 t = 24
t = 24
1.8 X .17 X 250 17,500 X 1 76.5 17,500
t = 24 X .0661 t = 1.586 ANSWER ANSWER: B
214
25.
d = 16 + 0.375 – 0.290 = 0.085 tr = .890 trn = .290 tn = .375 t = 1.0
0.085 x 2 = 0.170 = 16 + 0.170 = 16.170
From UG-36 A = 16.170 x .890 x 1 + 0 A = 14.39 ← A 1 = 16.170 X (1-.890) - 0 A 1 = 1.77 ← or A 1 = 2(1.375)(.11) = .302 A 2 = 5(.085) x 1 = .425 or A 2 = 5(.085) x .375 = .159 ← A3 = 0 A 41 = .5 2 = .25 ← A 43 = 0 A 1 = 1.77 + A 2 = .159 + A3 = 0 + A 41 = .25 + A 43 = 0 __________ 2.169 < 14.39 Yes need repad ANSWER: B
26.
Parallel = 16’ or 8 + .375” + 1” Larger value - use 16” Perpendicular = 2.5 x 1 or 2.5 x .375 + 0 Use smaller value - use .9375 ANSWER: D
215
27.
1. Set Nomenclature and compute “tr” and “trn”: d = 18 tr = .287 trn = .103 tn = .280" t = .350 f = 1.0 E1 = 1.0 fr1 = fr4 = 1.0 te = .375 Dp = 24 tr =
200x 25 47500x1−.6x 200
tr = 5000 17 ,380
tr = .287 trn =
200x 9 17,500x1−.6x 200
trn =
1800 17380
trn = .103
2.Compute “A”: A = 18 X .287 X 1 + 0 A = 5.166 3.Compute A1: A1 = 18 (1 X .350 - 1 X .287) - 0 A1 = 1.13 OR A1 = 2 (.350 + .280)(.350 - .287) -0 = 2 X .63 X .063 - 0 = .079
USE LARGER VALUE
4.Compute A2: A2 = 5(.280 - .103) X 1 X .350 A2 = .309 OR A2 = 2(.280 - .103) X (2.5 X .280 + .375) X 1 = .885 X 1.075 A2 = .380
USE SMALLER VALUE
216
27. continued 5.Compute A3 A3 = 0 6.Compute A41 = .300² = .09 7.Compute A42 = .300² = .09
8.Compute A43 = 0 9.Compute A5 = (24 - 18 - 2 X .280) X .375/1 A5 = 5.44 X .375 A5 = 2.04 10.Add values and compare to “A” A = 5.166
ANSWER:
28.
A1 = 1.13 A2 = .309 A3 = 0 A41 = .09 A42 = .09 A5 = 2.04 TOTAL = 3.659 < 5.166 B. Opening is not properly reinforced
From Appendix 1
From UG-32
Shell OR = 18" S = 15,000 E=1 t = .300 x .875 = .2675
Head S = 17,500 E = .85 L = 18 t = .300
P=
15,000x1x.2625 18−.4 x.2625
P=
17,500x.85x.300 .885x18+.1x.300
P=
3937.5 17.895
P=
4462.5 15.96
P = 220 psig
P = 279.60
Answer: 220 psig ANSWER: C
217
29.
UG-99 Stress value of SA516 70 @ 70° = 17,500 @ 900° = 6,500
= 2.6
OR Stress value of SA 240 type 304 18,800 @ 70° 14,700 @ 900°
=
1.27 use lowest value
1.3 X 1000 X 1.27 = 1,651 + HH 8.66 1,659.66 psig on bottom head ANSWER: D
30.
From UG-28
DO = 24" t = .500 L = 48" Dot = 48 L/Do =2 Temp - 500 °F Yield = 40,000
From Fig. G
=
.002 (Factor A)
From Fig. CS-2 = 11,800
(Factor B)
From UG-28
4B 3(Do/t)
=
= 47,200 144
= 4 X 11,800 3 X 48
Pa
=
=
372.77
Pa = 327.77 psig ANSWER: A
31.
SA 516 GR 70 is Curve “D” material Curve D 3.0" thick material is good for +10° per UGS-66(figure) + 10°F < 30°F, which is vessel rating Answer: No, does not require impact tests ANSWER: B
32.
LTCR =
.637 −.509 9
LTCR = .014” Year STCR =
.607−.509 3
STCR = .030” Year .509−.411 = 3.26 years .030 ANSWER: C
RL =
218
33.
t = 80 X 12 16,800 X .85 - .6 X 80
1. 2. 3.
t = 960 14.280 - 48 t = .067
Corrosion Rate = .008 per year Avg. = .283 - .067 = .216 Corrosion Allowance = .216 Remaining Life = 27 years - default to 10 years per API 510 ANSWER: A
34.
A. B. C. D. E.
Metal Loss = .250 Corrosion Rate = .0625 per year Corrosion Allowance = .125 Remaining Life = 2 yrs Inspection Interval = 2 yrs per API 510
35.
From UG-27 t=? P = 300 R = 40 E=1 S = 12,100 t=
300x 40 12,100x1−.6x 300
t=
12 ,000 12 ,100 − 180
t = 12 ,000 11,920
t = 1.006” required ANSWER: B
219
.067" 12" 10YEARS
36.
From Appendix 1 P = 600 + HH HH = 25 x .433 = 10.825 P = 610.825 E = .80 R o = 35 S = 15,000 t=
610.825x 35 15,000x.80+.4 x 610.825
t=
21378.875 12,000 + 244.33
t=
21378.875 12244.33
t = 1.746” ANSWER: D 37.
From UG-32 P =? t = .250 D = 45 S = 13,800 E = 1.0 P =
2 x13,800x1x.250 45+.2 x.250
P =
6900 45.05
P = 153.16 psig ANSWER: B
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38.
From UG-32 P = ? t = .375” S = 14,500 L = 80.75 (L= O.D. @ skirt) E = .85 P =
14,500 x.85x.375 .885x80.75+.1x.375
P =
4621875 . 72.463+ .0375
P = 64 PSI ANSWER: C
39.
From UG-27 P = ? t = .375 X .875 = .328 S = 15,000 E = 1.0 R = 12 P =
15,000x1x.328 12+.6x.328
P =
4920 12.196
P = 403 psi ANSWER: A
40.
From UW-16(b) tc = 1/4” or .7t min (smaller) t min = 3/4” or .500”/1.00” smaller - use .500 .7 x .500 = .350” or .250” - use .250” throat .250 x 1.414 = .353” leg ANSWER: C
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41.
From Fig. UW-16.1 Sketch (I) t 1 = .125 t 2 = .125 t 1 + t 2 = .250” t min = 3/4” or .350/.500” (smaller) t min = .350” 1.25 x .350” = .4375” required, .250” actual t 1 or t 2 not less than smaller of .250” or (.7 x .350) = .245” → .125 < .245 ANSWER: B
42.
From UG-37 d = 10 tr = .490 t = .750 tn = .280 trn = .160 A = 10 x .490 = 4.9 A 1 = 10(.750 - .490) = 2.6 or 2(.750 + .280)(.75 - .49) = .53 A 2 = 5(.280 - .160).750 = .45 0r 5(.280 - .160).280 = .168 A 3 =0 A 41 = (.75 x 1.414). 2 = 1.124 A 43 = 0 2.6 + .168 + 1.124 = 3.892” 4.9” required > 3.892” actual Reinforcement is required. ANSWER: A
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43.
From UG-99 P = 350 HH = 21.65 St/SD = 1.09 1.3 x MAWP x ⎛⎜ St ⎞⎟ + H.H. = ⎝ SD ⎠
H.H. = 50 x .433 = 21.65 SA 516 70 @ 750°F = 14,800 @ 70°F = 17,500
SA285 A @ 750°F = 10.300 @ 70°F = 11,300
SA53 B @ 750°F = 13,000 @ 70°F = 15,000
17,500 = 1.18 14,800
11,300 = 1.09 10,300
15,000 = 1.15 13,000
Use lowest ratio - use 1.09 1.3 x 350 x 1.09 + 21.65 = 517.6 or 518 psig ANSWER: C
44.
From UG-100 1.1 x MAWP x St
SD
P = 200 St = 1.05 SD
SA 515-65 @ 700°F = 15,500 @ 70°F = 16,300
SA 240 T 304 @ 700°F = 16,800 @ 70°F = 18,000
16,300 = 1.05 15,500
18,000 = 1.07 16,800
1.1 x 200 x 1.05 = 231 ANSWER: A
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45.
From UG-34 d = 20 C = .17 P = 300 S = 17,500 E=1 t = 20
.17 x 300 17 ,500x1
t = 20 .002914286 t = 1.07 ANSWER: D
46.
From UG-34 t=? C = .33 d = 30 E = .85 S = 15,000 P = 375 t = 30
.33x 375 15,000x.85
t = 30
123.75 12750
t = 30 x .098518437 t = 2.955” ANSWER: C
47.
From UG -28 and External Pressure Charts: D o =48” t = .500” L = 84” y = 28,000 T = 600°F D o /t = 96 L/ D o =1.75
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47.continued From Fig. G (External Pressure Charts): Factor A = .0008 From Fig. CS-1 (External Pressure Charts): Factor B = 7,000 From UG-28 Pa = 4 x 7000 3 x 96 ANSWER: A
48.
= 28000 288
= 97.2 psi
From UG-20(f) and UCS-66:
• •
Not exempt per UG-20(f) From UCS-66 SA 662 Grade A - Curve C @ -30°F (.375”) = -50°F SA 182 GR. 21 (Norm) - Curve C @ -30°F (.375”) = -50°F SA 516 - 70 - Curve B @ -30°F (.375”) = -20°F ANSWER: D
49.
From UG-20(f) - not exempted @ -40°F From UCS-66 SA 516-70 - Curve B @ .500” thick = -7°F > -40°F. Vessel requires impact testing ANSWER: A
50.
A. B. C. D. E.
.753 - .500 = .253” .253”/5 = .050” per year .500” - .350” = .150” .150”/.050” = 3 2 years per API 510
51.
From UG-27 tr = ? P = 150 S = 17,500 E = 1.0 R = 40 t=
150x 40 17,500x1−.6x150
t=
6000 17410
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51.continued t = .344” 1.0” - .344” = .656 .656/.125 = 5.24 years ANSWER: A
52.
From UG-99
1.3 x MAWP x St + H.H. SD
H.H. = 150 x .433 = 64.95
or 65
1.3 x 150 x 1 + 65 = 260 psi ANSWER: D
53.
From UG-32 P = 150 S = 17,500 E = 1.0 D = 60 + (1/4”) = 60.25 t=
150x 60.25 2 x17 ,500x1−.2 x150
t=
9037.5 35000 − 30
t = .258” ANSWER: B
54.
A. E = 1.0, UW-11(a)(5)(b) and UW-12(d) B. Category B, UW-3 C. Type 2, UW-12 Table
55.
Top Head
Bottom Head
Shell #1
Shell #2
Nozzle #1
Nozzle #2
.300−.125 .01
.270−.125 .006
.270−.125 .003
.200−.125 .015
.150−.125 .023
.230−.125 .004
17.5 years
24.16 years
48.33 years
5 years
1 year
26.85 years
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56.
From API 510 C/R = .012” per year x 2 = .144 metal loss at next inspection (twice). .788 - .144 = .688” remaining thickness at next inspection. From UG-27 P=
16,800 X 8.5 X .688 9824.64 = = 406.6 psi 23.75 + 0.6 x.688 24.162
P = 406.6 - Pressure or Inspection Interval is acceptable for conditions indicated. ANSWER: A
57.
58.
From API 510 Para. 7.2.11 - 75/60 = 1.25, 1.25 x (.195) = .243” ANSWER: D
.407 −.370 = .007” per year 5 .007 x 10 x 2 = .14” metal loss at next inspection (twice). .370 - .14 = .23” remaining thickness at next inspection.
From API 510 –
From UG-27 - P =
C/R =
17,100 x.90 x.23 3539.7 = = 97.9 or 98 psi 36 + 0.6 x.23 36138 .
ANSWER: A
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REVIEW OF API 510
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A. P. I. AMERICAN PETROLEUM INSTITUTE A voluntary organization comprised of petroleum producers, refiners, distributors, and associated equipment manufacturers/suppliers that exists to:
•
Promote the petroleum industry
•
Promulgate standards and guidelines relative to the petroleum industry
•
Provide training, education, and dissemination of information
•
Provide certification to those who wish to use the API monogram
API is headquartered in Washington D.C., with regional offices throughout the northern hemisphere. API 510, 653, and 570 are only three of the various codes, standards, or publications available to the petroleum and chemical industry (hereafter referred to generically as “Users” or “the User”. A complete listing of available documents can be ordered through API Publications Department in Washington, D.C..
API 510 REVIEW - 8TH EDITION – ADDENDUM 1, 2 3 & 4, AUGUST 2003 FOREWORD OF API 510 The Foreword contains some interesting facts and history regarding the evolution of the Code, and it's close association with the ASME Code. Additionally, the "Special Notes" on the preceding page offer some interesting information, particularly regarding the legalities of using the Code, and also that users of API-510 are cautioned to check the laws where the pressure vessel is installed to be sure API -510 is acceptable to the local and/or state jurisdictional authority (if one exists). It should be noted that OSHA 1910.119 (regarding Mechanical Integrity of Petrochemical facilities) has accepted API 510 as an acceptable document. API 510 has been accepted as an ANSI standard. However, at this date, approximately 16 jurisdictions recognize the document as an alternate set of rules to the National Board Inspection Code (it is rumored that more are on the way). However, API 510 is in common use by petroleum and chemical plants that do not have state or local laws specific to pressure vessels, mainly because of insurance liabilities, and as mentioned, the ever-present threat of the Feds (OSHA 1910)! Note that this edition supercedes all previous editions. Each edition, revision, or addenda becomes effective 6 months after the date of issuance. During the 6 month lag between issuance and effectivity, the user shall specify which document to use. SECTION 1 - GENERAL
Para.1.1 - This paragraph should be read thoroughly to understand what the document applies to, and where it should and should not be applied.
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NOTE: API 510 is RESTRICTED to organizations that employ or have access to an Authorized Inspection Agency and Engineering personnel! Also 510 is ONLY applicable to vessels that have been placed inservice. General Application states that the document covers maintenance, inspection, repair, alteration and rerating procedures for process vessels used in the petroleum and chemical process industries. API 510 limits the use of the document to those organizations that have access to an authorized inspection agency (as defined in the Glossary of Terms), and, further, to organizations that have qualified engineering and inspection personnel or arrangements with such organizations. 2003 Addenda introduced new guidance on coverage of vessels that have lost their nameplates and those not meeting a recognized standard. These are generically covered as non-standard vessels. These organizations must be technically qualified to maintain, inspect, repair, alter and/or rerate pressure vessels. API 510 is not intended to cover inspections, re-ratings, repairs/alterations to anything other than pressure vessels; however, an addenda covering unfired steam boiler will be out in the near future. The paragraph cautions that adoption of the standard does not permit its use in conflict with any prevailing regulatory requirement. However, API-510 can always be used to supplement other documents and/or requirements.
Para. 1.2.1 - Specific Applications outlines the fact that the scope of the Code also encompasses natural resource vessels ("oil patch" or drilling vessels), and that API 510 is intended to satisfy the concerns of a bunch of Federal Regulatory folks that oversee the "oil patch".
Para 1.2.2 - Specifically defines EXCLUSIONS to the Code: a.) Vessels on moveable structures (cargo trucks, etc.) b). Everything exempted by ASME VIII ( SEE U-1 SCOPE of ASME VIII) c). Miniature Vessels ("UM") that ARE included in ASME VIII.
Para 1.3 - API 510 recognizes fitness-for-service concepts and RP 579 for assessment of degradation of pressurized components.
SECTION 3 - DEFINITIONS Definitions are given and should be closely reviewed by each candidate. Examples of some of the definitions frequently asked on the test, or that have a high probability of being on the test:
Alteration- a physical change in the vessel beyond the scope of the original data report. Any nozzle added that does not require reinforcement is a repair, regardless of size, and the addition of reinforced nozzles less than or equal to existing reinforced nozzles are repairs, not alterations.
ASME Code - note the emphasis on complying not with the absolute letter of the ASME Code, but with the " applicable requirements of the Code".
Authorized Inspection Agency – four entities may qualify including recognition of Third-party Inspection (contract) Agencies that are not Insurance companies.
On-stream Inspection - NDE must be used to establish the suitability of the vessel, and essentially, the vessel is not entered for inspection even though it may or may not be in operation.
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Pressure Vessel Engineer - ...persons or organizations acceptable to the owner/user...knowledgeable and experienced in engineering disciplines which affect integrity and reliability of pressure vessels. This person should be regarded as a composite of all entities needed to assess technical requirements (NOTE: This does NOT say “Degreed” anywhere).
Pressure Vessel - includes: “unfired steam boilers and other vapor-generating vessels which use heat from the operation of a processing system or other indirect source of heat”
Quality Assurance - defines what the term means, and refers to the required QA Manual.
Repair Organization – 4 entities, all of which should be memorized.
Examiner - A person who assists the API 510 Inspector (such as an NDE Level II or CWI), but does not have to be certified as API 510 to conduct the examination.
Controlled-deposition Welding – used to control grain refinement and tempering of the weld HAZ – includes temper-bead and half-bead techniques.
Industry-Qualified UT Shearwave Examiner – An API qualified individual or an individual qualified to an equivalent program approved by the owner/user.
Fitness-For-Service – A methodology to assess equipment for continued use when it has demonstrated flaws.
SECTION 4- OWNER/USER INSPECTION ORGANIZATION This section is straight forward, and really needs no additional commentary; however, the prospective API 510 candidate should know what the minimum requirements are to be an Inspector and should remember and memorize:
Para. 4.1 – Owner/user shall exercise control of the inspection program, frequencies, and maintenance. The owner/user inspection organization shall control the actual inspections conducted.
Para. 4.2 – Appendix B lists criteria to become an API 510 Inspector, Remember: API is the certifying body!
Para. 4.3 - 15 criteria for owner/user Quality Assurance Inspection Manual, these should be remembered.
Para. 4.4 - Responsibilities for an API Authorized Pressure Vessel Inspector.
Para 4.5 New In 2003 Addenda. Deals with the requirements for a repair organization. Cleaning up the standard and making clear responsibilities.
SECTION 5- INSPECTION PRACTICES
Para 5.1 - provides guidelines for preparing a pressure vessel for inspection, information on safety practices, and basic equipment considerations to conduct an inspection.
Para. 5.2 - The various modes of deterioration and failure are covered, with specific emphasis on high temperature creep and low temperature embrittlement. The API 510 candidate should be familiar with these mechanisms and understand how they occur and some of the things than can be done to prevent them.
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Further, each Inspector should be able to recognize these types of failures, and be able to identify them when encountered in an actual vessel inspection. Further information on this should be read in the API Chapter II Guide for Inspection of Refinery Equipment, or in RP 579 for assessment of these applicable degradation mechanisms. Note that creep is dependent on 4 things – time, temperature, stress, and material creep strength. An inspection plan should be developed for items operating in the range of 750º - 1000ºF. It should take into account: a. b. c. d. e.
Creep and stress rupture Creep crack growth Effect of hydrogen interaction between creep and fatigue metallurgical considerations
The inspection plan should be reviewed by an engineer that has a good background in temperature effect on metallurgy. (NOTE: API RP 571 replaced Chapter II, but a limited version is being sold specifically for the API 510 Inspector's examination).
Para. 5.3- Corrosion Rate Determination. The API 510 candidate should be able to calculate corrosion rates given values of corrosion and period of time between inspections. The candidate should also understand that the corrosion rate value can be changed at any time depending upon what is discovered during any particular inspection. Three methods of computing corrosion rates are given: a. b. c.
vessels in same or similar service. experience or published data (such as NACE) on-stream inspection after 1000 hours of service, and subsequent intervals thereafter.
REMEMBER: Corrosion Rate = Metal Loss/Time!
Para. 5.4 - discusses maximum allowable working pressure, or MAWP.
Each API 510 candidate should CLEARLY understand the ASME VIII definition of MAWP, and should be aware that computations may be made only if all essential details such as upper and/or lower temperature limits for specific materials, quality of materials and workmanship, head design, inspection requirements, reinforcement of openings, and other design detail, are known to comply with the requirements of the original construction code or with API 510. The thickness measurement procedure shall be approved by the API Inspector. Confusing!!: Note that, in corrosive service, the wall thickness "t" used in MAWP calculations shall be the actual measured wall thickness, but this thickness can't be greater than the original "t" minus twice the estimated corrosion loss before the next inspection, unless modified by Para 6.4. (Don’t let this confusing language bother you - on the test you will know what they are looking for by the information given.)
Para. 5.5 - Defect Inspection. This paragraph details the primary considerations when making an inspection of a pressure vessel. Appropriate reference is made to API RP 572, which should be read several times by the API 510 Candidate.
Visual examination is the primary method specified, however other methods of examination may be used to supplement visual examination. Specifically, magnetic particle, liquid penetrant, ultrasonic, and radiographic
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examination are mentioned. The API 510 candidate must understand the basic principles of these nondestructive testing methods. Each Inspector should be familiar with the advantages and limitations of each one of these methods to allow the Inspector to require the appropriate nondestructive testing method to be use, if further investigation is needed in the field. Further in this paragraph, there is discussion of inspecting under insulation and coverings, both internal and external, and the necessity for removing the insulation or covering if it is suspected that there might be corrosion occurring that is not in a visible and accessible location. The API 510 candidate should understand that he has the option, and sometimes the obligation, to have these insulating materials removed so that a thorough examination may be performed. The owner/user shall specify the use of industry qualified shearwave operators when detailed flaw information is needed (i.e. RP 579 assessments). This requirement becomes effective 2 years after publication of this addendum.
Para. 5.6 - Inspection of Parts. This is a "tag-on " to Para 5.5. This paragraph gives guidance as to what types of defects to inspect for.
CAUTION: This is not a complete list of inspection items! The inspector will likely need to supplement this list depending on the particular installation and service. However, this paragraph is very important, and should be remembered as a good "starting point" for all inspections.
Para. 5.7 - Corrosion and minimum thickness evaluation. This paragraph informs the Inspector that actual measurement of wall thickness will be necessary and that there is more than digital ultrasonic thickness measurement to perform this measurement, such as A-scan, B-scan, C-scan or profile radiography. Further, it gives rules on how to handle corroded areas of considerable size. In 2003 Addenda this paragraph has been expanded to include assessment of damage which was previously in Para 5.8 – Assessment of Inspection Findings.
"Corrosion Averaging" and "Ignoring of Pits" are important concepts, and must be learned. One way to remember the allowed length of averaging is this way: "60 or less =1/2D or 20” (lowest) "More than 60 =1/3D or 40” (Lowest) Widely scattered pits may be ignored provided: • No pit depth over ½ trequired. • Total Area < 7 sq." in an 8 sq." area • Sum on along any straight line < 2"
WHATEVER WORKS FOR YOU TO REMEMBER THIS INFORMATION - USE IT! As an alternative to the above, a stress analysis of EACH component using ASME VIII Div 2 may be employed. If evaluating the base metal away from a weld with an efficiency less than 1.0, an E of 1.0 may be used, if the area is 1” away or 2x the BM thickness away from the weld, which ever is greater. Note that in Addenda 2003 they clarified this to mean as measured form the toe of the weld.
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Para 5.8 – this is where all the Fitness For Service Guidance now resides. It is simply a listing of the various flaw damage sections listed in API RP 579.
General Metal Loss Local Metal Loss Pitting Corrosion Blisters & laminations Misalignment Crack Like Flaws Fire Damage
SECTION 6-INSPECTION AND TESTING OF PRESSURE VESSELS AND PRESSURE RELIEF DEVICES
Para. 6.1 - provides general requirements and instructions for internal and external inspections. Note that on-stream inspections CAN be used to satisfy inspection interval requirements.
Para. 6.2 – RBI
This paragraph was cleaned up in 2003 Addenda in particular to reference and harmonise with API RP 580 the base rules document on RBI. Important points to remember from this paragraph: • RBI combines assessment of likelihood and consequence of failure • Likelihood assessment – based on all forms of degradation expected – should be repeated each time any changes are made that could affect the vessel. • Consequence assessment – considers the effects of releases, explosions, fires, environmental impacts, and other health effects. • RBI assessments must be thoroughly documented, and include all factors. • RBI can be used to develop a vessel inspection strategy which includes: A. appropriate methods, scope, techniques; B. frequency of inspections; C. need for pressure testing; D. steps to lower the likelihood/consequence of a failure • RBI can be used to increase/decrease inspection intervals. When used to increase the 10 year limit, RBI assessments shall be reviewed by an engineer and inspector at maximum 10 year intervals, or more often if warranted. The final paragraph has been clarified in Addenda 2003 to use the words appropriate inspection interval. The base guidance that use of RBI may change time based rules elsewhere in 510 has not altered.
Para 6.3 - External inspections must be done every 5 years or at the same required interval as the internal or on-stream inspection, whichever is less. Inspection for CUI - shall be considered for vessels externally insulated and operating between 25°F and 250°F (-4°C to 120°C) or in intermittent service. Buried vessels shall be inspected at intervals determined from known information about corrosion from underground piping or other vessels, or through test coupons or exposure of a part of the vessel. Vessels with a remaining life of over 10 years that are protected against moisture ingress do not need to have insulation removed.
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Para. 6.4 – Internal and On-Stream Inspections.
NOTE: THIS IS A VERY IMPORTANT PARAGRAPH AND MUST BE REMEMBERED!! Para 6.4 establishes Internal or on-stream inspection intervals at 10 years or ½ the corrosion rate life of the vessel. Note 6.4 b) 4. Amended Addenda 2003 to highlight consideration of risk associated with environmental cracking or hydrogen damage plus adding item 5) dealing with strip lining or plate lining. Be clear to apply this paragraph all of items 1-5 must apply. Confusing: Where the life is less than 4 years, the full life can be taken (Not broken in half) up to a maximum of 2 years. Example: Maximum remaining corrosion rate life = 3 years. Next on stream or internal is due in 2 years. This paragraph also addresses inspection intervals for “idle” or “non-continuous service” vessels, which is 10 years of actual service exposed life for protected vessels (nitrogen purged or isolated while not in service) or 10 linear years or ½ CRL for non-protected vessels. External inspection interval remains the same. At the discretion of the AI, when the corrosion rate life of a vessel is known to be less than .005" per year and remaining life is greater than 10 years, internal Inspections don't have to be done provided 1- 5 are complied with. A decision on the number and locations of Thickness Measurement Locations (TML’s) should consider results from previous inspections. Higher corrosion rates require higher numbers of TML’s. Statistical analysis (such as that used in Risk Based Inspection) may be used to establish remaining life and inspection intervals. Statistical analysis is N/A for vessels with extensive localized corrosion. Long-term or short-term corrosion rates may be used, as determined by the A.I. The Inspector shall consult a corrosion specialist to select the corrosion rate that best suits the process. Remember the formula for Remaining Life - RL= t actual - t required corrosion rate
LTCR = t initial – t actual years between readings
STCR = t previous – t actual years between readings For multi-chamber or multi-zone vessels, each is treated separately. As an alternative, MAWP can be calculated using a projected corrosion loss over the inspection interval. The resulting MAWP must be at least as high as the nameplate rating, with a maximum of 10 years for the inspection interval. Also, if vessel ownership AND location change, the vessel shall be inspected.
Para 6.5 - Pressure Tests - Required hydrostatic test temperature is 30°F above MDMT for vessels over 2" (5cm) thick, or 10°F above MDMT for vessels 2" (5cm) or under in thickness. 120°F remains the recommended maximum temperature for test. For vessels without an MDMT, the minimum operating temperature should be used.
COMMON MISTAKE - Everyone ASSUMES a pressure test is REQUIRED after a repair, alteration or re-rating. Read this and Para. 7.2.10 closely. You may be surprised!
Para. 6.6 - discusses pressure -relieving devices and who can repair them. Note that an ASME or National Board stamp-holder is not specifically called out, but each repair firm must have a documented QC system and training program. Remember (memorize) these QC requirements for the examination!
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(Editor’s Note: It is ironic that the Code would specify these QC Manual requirements for pressure relief device repair firms, but the vessel repair firms don't have to have anything!!) Test or inspections on relieving devices should not exceed 5 years, unless documented service experience indicates a longer interval is acceptable. Non-corrosive, non-fouling services, this interval may be increased to a maximum of 10 years. Other devices are inspected at intervals determined by the service. Note: Addenda 2003 added the word documented to force owner/users to demonstrate the basis of their decisions.
Para. 6.7 -Requires vessel owner/users to maintain permanent records (non-changing historical documents) and progressive records (documents that are updated). Four distinct types of information are required: a). Construction and design information; b). Operating and Inspection history; c). Repair, alteration, and re-rating information. d.) Fitness-For-Service assessment documentation.
For unidentified vessel with no nameplate and/or minimal/non-existent design information, the following should be used to verify operating integrity: o o o o o o
perform inspections – document, make repairs as necessary prepare drawings (calculations – 3.5 design factor may not be used) identify material based on UG-10(c) in ASME VIII or use SA-283C for default stress values. For alloy material alloy analysis should be used. use default of .70 or increase factor by additional RT attach a nameplate to vessel with new parameters perform a pressure test per Code requirements
SECTION 7, REPAIRS, ALTERATIONS, AND RERATING (RAR'S) OF PRESSURE VESSELS.
Para. 7.1 - The applicable ASME Code, or other specified Code, used in the original construction is recommended for use when making repairs/alterations or reratings. All repair/alteration work must be authorized by the Inspector. It is important to note that all alterations require prior approval by an Engineer experienced in pressure vessel design.
Para 7.1.1 - All RAR's must be authorized and approved by an API 510 Inspector. The "Engineer" has to approve repairs and alterations to ASME VIII Div 2 vessels, and only alterations on ASME Div. 1 vessels. (Re-ratings are handled in Para 7.3)
Par 7.1.2 - The API Inspector shall approve all repairs and alterations after an inspection of the work has shown it to be satisfactory.
Para. 7.1.3 - Cracks cannot be repaired without approval from the Inspector. Repairing a crack at a discontinuity with high stress concentrations should only be done with the consent of the Engineer.
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Para 7.2 - Welding procedure specifications and welders are to be qualified to the requirements of the ASME Code, Section IX.
Note: This is the "tie-in to ASME IX, and why the candidate must be tested on welding procedures.
Para. 7.2.3 - allows alternatives to required PWHT after a repair or alteration. Two methods of alternatives are allowed: Preheat or controlled deposition welding. Prior to using these methods, a metallurgical review by a P.V. Engineer must be conducted to assure the alternative is acceptable. Materials are limited to those specified; other materials must be PWHT’d to the original construction code.
Para. 7.2.3.1 – Preheat Method (Impact Testing not required); o limited to P1, and P3 (except MN – MO materials) o SMAW, GMAW, GTAW, only; o preheat to 300°F – 4” or 4xT (greater) – max interpass 600°F; o for partial penetration weld repairs – 4” or 4 x depth of repair weld should be maintained.
Para 7.2.3.2 – Controlled Deposition Method (Impact Testing required); o this method only used when notch toughness testing was required by the original code of construction; o P1, 3, 4 steel only – GMAW, SMAW, GTAW welding processes only; o qualified welding procedure developed with thicknesses per Table 7-1 – test material to be the same as that welded in the repair; o PQR shall be impact tested in weld/HAZ, if hardness tests are required, they shall also be performed; o items (f) (1) – (9) shall be addressed on the WPS or followed during the repair.
Para 7.2.4 – NDE of welds – requires MT/PT to ensure no defect is welded-over, and after welding is completed, Radiography of repair welds to be performed per original construction code requirements. If RT is not practical, repair welds shall be NDE’d using appropriate methods.
Para 7.2.5 - specifies rules for partial PWHT when a complete PWHT can't be performed.
Para 7.2.6- repairs to stainless steel weld overlay and cladding rules are given. Hydrogen service at elevated temperature service should receive additional considerations because of atomic hydrogen migration into the base metal. These considerations should include: a. b. c. d.
outgassing base metal hardening preheat and interpass temperature control PWHT
All repairs to overlay/cladding shall be inspected by PT to ASME VIII Appendix 8 requirements. P-3, P-4 or P-5 base materials should be examined by UT to ASME V Article 5, T-543, after a minimum of 24 hours, to ensure an absence or delayed cracking in chrome-moly materials.
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Para. 7.2.7 - addresses that fabricated parts should be constructed to the applicable original code.
Fillet welded patches welded from the outside of the vessel are allowed in API 510. Special rules concerning these patches are given, such as safety equivalent to a reinforced opening, designed to absorb membrane stress, and the strain does not exceed the fillet weld stress. Patches with rounded corners are required. Fillet welded patches require the approval of the inspector and engineer. A full encirclement lap band repair may be a long-seam repair provided the following are met: o documented and approved by the Engineer and Inspector; o no cracks; o full penetration butt welds in the band – longitudinal weld joint efficiency per acceptable code; o fillet welds sized on a J.E. of .45 – eccentricity f vessel to be considered; o fatigue of attachment welds considered; o C/A is provided in the band, and materials are compatible with fluids handled; o degradation mechanisms causing the repair shall be considered in future inspections of the repair. Non-penetrating nozzles and pipe caps can be welded over leaks/holes, when attachments comply with the referencing code. Repair bands/nozzles may need to be considered separate inspection zones during subsequent inspections.
Para. 7.2.8 - addresses material requirements, and basically specifies that the material used in making repairs or alterations shall conform to the applicable section of the ASME Code. Carbon or alloy steel having a carbon content over 0.35% shall not be welded.
Para. 7.2.9 - states that appropriate NDE, as necessary for the original construction shall be applied to all RAR's.
NOTE: This is the "tie-in" to ASME V, and why the candidate must be familiar with this Code section.
Para 7.2.10 - As stated before, watch this paragraph closely. If you read this the way it is written, a full hydrostatic test may not have to be performed, unless the API 510 inspector deems it necessary. It further specifies that pressure tests are normally required after alterations. However, the need for a test should be based on the brittle fracture characteristics of the metal, the possibility of meaningful NDE in lieu of hydro, etc. NDE may be done in lieu of test; however, the substitution of NDE for the pressure test after an alteration may be done only after consultation with an engineer experienced in pressure vessel design.
This Paragraph was substantially re-written in Addenda 2003 adding the formula for Hydrotest and recognizing the ASME Safety Factor Change in 1999.
Para. 7.2.11 - If filler metal is used that has a lower tensile strength than the base metal, the degradation mechanism should be considered, and also: a. Repair thickness not allowed greater than 50% of required B. M. thickness, minus any corrosion allowance. BMTS . b. Thickness of repair weld must be increased by ratio of DWMTS c. Increased thickness shall have rounded corners and 3:1 taper. d. Minimum of two passes shall be used.
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Para. 7.3 – Reratings. Calculations must be performed by either the manufacturer or the owner/user Engineer, rerating shall be established in accordance with the requirements of the Code to which the pressure vessel was built. If the vessel was designed earlier than 1999, and does not meet Code Case 2290 or 2278 it may be re-rated to the current code as allowed by Figure 7-1. The API inspector must be very familiar with the formulas found in ASME Section VIII. Before rerating can be finalized the pressure vessel has to be inspected, and must have been pressure tested (at some time) in accordance with the new service conditions, OR the vessel must have been evaluated by suitable NDE and inspection techniques. If a pressure test, at a higher pressure than required for the re-rating, has been performed, a new test is not required. The pressure vessel rerating has to be acceptable to the Inspector.
When the API inspector accepts the rerating he must oversee the
attachment of an additional nameplate or stamping. Paragraph 7.3 also indicates the information that must be contained in this stamping or on the new nameplate. The API candidate should be familiar with this required information.
NOTE: This is the ONLY stamping requirement contained in his Code. Repairs and alterations do not require a stamping, but must be documented per 4.6.
SECTION 8 -ALTERNATIVE RULES FOR NATURAL RESOURCE VESSELS. (Excluded from Examination) Appendix A This Appendix lists the ASME Code exemptions and the specific items exempted from API 510. Appendix B This Appendix describes the API 510 Inspector Certification Program. Many questions come from this section. You are expected to know the rules by which you are certified. 2003 Addenda Para B5.3 was added as new to recognize new rules of recertification every six years and a requirement to demonstrate knowledge of changes to the code since you initially sat the examination. Appendix C and D These Appendices show sample forms that can be used for documenting inspections or acceptance of repairs or alterations/reratings.
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Appendix E Appendix E provides guidance on how to submit inquiries to the Committee. Editor’s Note: RP 572, 576, and IRE are straight forward, self-explanatory, and require very little explanation. Most of the questions from these books are “Closed Book”, and therefore, repetition in reading is the key to understanding and remembering each document. API RP-572, Inspection of Pressure Vessels 1. Scope (API RP-572, Section 1) 2. References (API RP-572, Section 2) 3. Definitions (API RP-572, Section 3) 4. Types of Pressure Vessels (API RP-572, Section 4) 5. Construction Standards (API RP-572, Section 5) 6. Maintenance Inspection (API RP-572, Section 6) 7. Reasons for Inspection (API RP-572, Section 7) 8. Causes of Deterioration (API RP-572, Section 8) 9. Frequency and Time of Inspection (API RP-572, Section 9) 10. Inspection Methods and Limitations (API RP-572, Section 10) 11. Methods of Repair (API RP-572, Section 11) 12. Records and Reports (API RP-572, Section 12) Appendix A – Exchangers Appendix B – Sample Forms API RP 576, Inspection of Pressure-Relieving Devices: 1. Relief Devices a. Scope – Section 1, RP 576 b. References – Section 2 RP 576 c. Definitions – Section 3 – RP 576 d. Pressure Relieving Devices – Section 4 – RP 576 e. Causes of Improper Performance – Section 5 – RP 576 f. Inspection and Testing – Section 6 – RP 576 g. Records and Reports – Section 7 – RP 576 h. Appendix A – Sample Records and Report Forms i. Appendix B – Pressure Relief Valve Testing
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Chapter II, API Guide for Inspection of Refinery Equipment (IRE), Conditions Causing Deterioration or Failures Note: The above reference applies to refinery equipment other than pressure vessels (e.g., piping, heaters, and tanks). Only portions applicable to pressure vessels will be covered on the examination. 1. Types of Process Corrosion and Deterioration a. Corrosive Components of Crude Oils (API IRE, Chapter II, Section 202.02) b. Corrosion By Other Process Fluids (API IRE, Chapter II, Section 202.03) c.
Deterioration Due To Hydrogen (API IRE, Chapter II, 202.023)
d. Stress Corrosion Cracking (API IRE, Chapter II, 202.064) e. Atmospheric Corrosion and Corrosion Under Insulation (API IRE, Chapter II, 202.04) f.
Erosion and Erosion-Corrosion (API IRE, Chapter II, 203)
g. Corrosion by Waters (API IRE, Chapter II, 202.025) h. Other Types of Corrosion (API IRE, Chapter II, Section 202.06) 2. Modes of Mechanical, Thermal, and High Temperature Deterioration a. Mechanical and Thermal Problems (API IRE, Chapter II, 205-209) b. High Temperature Problems (API IRE, Chapter II, Section 210) 3. Pressure Vessel Materials and Fabrication Problems a. Faulty Material and Equipment (API IRE, Chapter II, Section 210) b. Known Problems Associated With Design and Fabrication (API IRE, Chapter II, 210.02)
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ASME SECTION V
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SUBJECT:
API AUTHORIZED PRESSURE VESSEL INSPECTOR CERTIFICATION EXAM
LESSON:
REVIEW GENERAL REQUIREMENTS FOR NDE
OBJECTIVE:
FAMILIARIZE CANDIDATES FOR THE API-653 CERTIFICATION WITH RELEVANT GENERAL REQUIREMENTS FOR NDE.
REFERENCE: ASME SECTION V 2004, ARTICLE 1
T-110 SCOPE A) General requirements for NDE when referenced by other Codes B) General NDE terms are defined in the Mandatory Appendix I. We will cover these in the review of Article 2. T-120 GENERAL A) Subsection A describes methods of NDE to be used B) Subsection B lists NDE Standards - Standards are Mandatory when referenced by Subsection A C) Reference to a paragraph in Subsection A or referencing Code includes all applicable rules in the paragraph D) Standards in Subsection B are mandatory only to the extent specified when referenced E) When qualification is required per this Article then it must be in accordance with the employers written practice as per: SNT-TC-1A (2001) ANSI CP-189 ACCP or International Equivalent. Basically ISO 9712 – be careful although Article 1 has changed some of the referencing codes have not look out for conflicts. G) Performance demonstration permitted when allowed by referencing code – this is common for MT and PT in ASME Codes.
I) Limited certification is permitted Big Note: The term Code User is now adopted meaning anyone who uses the code. This changes emphasis in many subsequent paragraphs.
T-130 EQUIPMENT The CODE USER is responsible for equipment compliance. This is a change in 2003.
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T-150 PROCEDURE A) Special conditions such as part geometry or materials may require special procedures - If required they shall: - be equivalent or superior to the methods and techniques described in Section V - produce interpretable examination results - be capable of detecting discontinuities - be submitted to the Inspector for approval B) The manufacturer, fabricator or installer is responsible for establishing: - examination procedures - personnel certification procedures C) All NDE required by referencing code shall be done in accordance with a written procedure: Demonstrated to the satisfaction of the Inspector In compliance with the applicable Article of Section V Made available to the Inspector on request At least one copy available to the NDE personnel performing the examinations
T-160 CALIBRATION A) The manufacturer, installer or fabricator shall assure that all required calibrations are performed B) The manufacturer, installed or fabricator shall specify what calibrations are needed when using special procedures; if required
T-170 EXAMINATIONS AND INSPECTIONS A) The Inspector is responsible for: - verifying that all examinations meet all requirements of Section V and referencing Code - witness any examinations to the extent stated in the referencing Code - Inspector means the Authorized Inspector as defined in the referencing Code B) Inspection: - Refers to the functions of the Authorized Inspector - Examination: - Refers to the functions of the NDE personnel - There are some minor conflicts in these definitions in the ASTM documents
T-180 EVALUATION Acceptance standards are as stated in the referencing Code
T-190 RECORDS/DOCUMENTATION - Records shall be in compliance with: The referencing Code and Section V The CODE USER shall be responsible for all records and documentation
Document Status: Last Updated 27 January 2006 – Verified To ASME V Article 1 2004 Addenda
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SUBJECT:
API AUTHORIZED PRESSURE VESSEL INSPECTOR CERTIFICATION EXAM
LESSON:
REVIEW OF RADIOGRAPHIC EXAMINATION METHOD
OBJECTIVE:
FAMILIARIZE CANDIDATES FOR THE API-653 CERTIFICATION WITH THE REQUIREMENTS FOR RADIOGRAPHY.
REFERENCE:
ASME SECTION V 2004, ARTICLE 2 - RADIOGRAPHIC EXAMINATION
Module Objective:This module is not designed to qualify you to produce or interpret radiographic images. The intent is to provide those becoming API Inspectors with the required knowledge to identify that radiography has been performed in accordance with the requirements of the ASME Code and that all the quality requirements have been met. Remember it is the Inspectors responsibility to accept radiographic examinations so you must be in a position to verify they are correct.
T-210-SCOPE When the referencing Code Section specifies this Article, the radiographic method described in this Article shall be used together with Article 1, General Requirements. Definitions Definitions of terms used in Article 2 are found in Mandatory Appendix V, Standard Definition of Terms and SE-1316. Some important definitions are: -Defect -- a flaw (imperfection or unintentional discontinuity) of such size, shape, orientation, location, or properties as to be rejectable. -Discontinuity -- a lack of continuity or cohesion; an interruption in the normal physical structure of material or a product. -Evaluation of indications -- The process of deciding the severity of the condition after the indication has been interpreted. Evaluation leads to the decision as to whether the part must be rejected, salvaged, or may be accepted for use.
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-Flaw -- an imperfection or unintentional discontinuity which is detectable by NDE. imperfection -- a condition of being imperfect; a departure of a quality characteristic from its intended condition. -Indication -- the response or evidence from the application of a NDE. limited certification -- Limited certification within a given method or technique is defined as accreditation of an individual's qualification to perform a limited scope of work. -IQI -- Image Quality Indicator (used to be known as a Penetrameter) – a device used to indicate whether the required sensitivity of the radiographic technique is satisfactory. Two types of IQI’s are permitted in ASME V – Hole type or wire type. -Method -- A method is the utilization of a physical principle in non-destructive examination (NDE). -Procedure -- In NDE a procedure is an orderly sequence of rules that describes how a specific technique will be applied. -Source side -- that surface of an area of interest being radiographed for evaluation nearest the source of radiation. -Technique -- A technique is a specific way of utilizing a particular NDE method. Each technique is identified by at least one important variable from another technique within the method (Example: RT -- method -- XRay/Gamma Ray Techniques).
T-220 GENERAL REQUIREMENTS T-221 Procedure Requirements T-221.1 A written procedure is required for radiography. The variables that must be addressed are listed as follows: (a) (b) (c) (d) (e) (f) (g)
material & thickness range isotope used or maximum X-ray voltage used source-to-object distance distance from source side of object to the film source size film brand and designation screens used
T-221.2 Demonstration of the density and IQI image requirements of the written procedure on production or technique radiographs shall be considered satisfactory evidence of compliance with that procedure T-222 Surface Preparation T-222.1 Materials Surfaces shall satisfy the requirements of the applicable materials specification. Additional conditioning may be required (grinding, etc.), if necessary, by any suitable process to a degree that surface irregularities cannot mask or be confused with surface discontinuities.
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T-222.2 Welds Weld ripples or weld surface irregularities on both the inside and outside shall be removed by any suitable process to such a degree that the resulting radiographic image due to any irregularities cannot mask or be confused with the image of any discontinuity. T-222.3 Surface Finish The finished surface of all butt-welded joints may be flush with the base material or may be reasonably uniform crowns, with reinforcement not to exceed that specified in the referenced Code Section. (API 650 and/or API 653 in the case of Tanks) T-223 Backscatter Radiation A lead symbol "B" with minimum dimensions of 1/2" in height and 1/16" in thickness, shall be attached to the back of each film holder during each exposure to determine if backscatter radiation is exposing the film. T-224 System of Identification Permanent identification system shall be established to trace radiograph to the contract, component, weld or weld seam, or part numbers, as appropriate. In addition: - Manufacturer's symbol or name and the date of the radiograph shall be plainly and permanently included on the radiograph - I. D. system does not require that the information appear as radiographic image - the information shall not obscure the area of interest. T-225 Monitoring Density Limitations of Radiographs Either a Densitometer or step wedge comparison film shall be used for judging film density.
T-230 EQUIPMENT AND MATERIALS T-231 Film T-231.1 Radiographs shall be made using industrial radiographic film. T-231.2 SE-999 or paragraphs 23 through 26 of Standard Guide for Radiographic Examination SE-94 shall be used as a guide for processing film.
T-232 Intensifying Screens May be used when performing radiographic examination in accordance with this Article.
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T-233 Image Quality Indicator (IQI) Design T-233.1 - IQIs shall be either hole type or wire type - Manufactured and identified in accordance with: SE-1025 (for hole type) SE-747 (for wire type) - ASME standard IQIs shall consist of those in: Table T-233.1 for hole type (See table in Section V) Table 233.2 for wire type (See table in Section V) T-233.2 Alternative IQI Design IQI’s designed in accordance with other national or internal standards may be used provided: a.) Hole Type IQI’s – The calculated equivalent IQI sensitivity (EPS), per SE 1025, Appendix XI, is equal or better than the required standard hole type. b.) Wire type IQI’s – The alternative wire IQI essential wire diameter is equal to or less than the required standard IQI essential wire. T-234 Facilities for Viewing Radiographs - Viewing Facilities shall provide subdued background of an intensity that will not cause troublesome reflections, shadows, or glow on the radiograph. - Equipment used for viewing shall provide a variable light source sufficient for essential IQI hole or designated wire to be visible for the specified density range. - Viewing conditions shall be such that light from around the outer edge of the radiograph or coming through low-density portions of the radiograph does not interfere with interpretation.
T-260 CALIBRATION T-261 Source Size T-261.1 Verification of Source Size - follow manufacturer's or supplier's publications, technical manuals, or written statements documenting the actual or maximum source size or focal spots. T-261.2 Determination of Source Size - X-ray 320 kV or less, use pinhole method - For IR-192, determine by ASTM E 1114-86 T- 262 Densitometer and Step Wedge Comparison Film T-262.1 Densitometers – calibrated at least every 90 days during use: National Standard Step Tablet or step wedge film strip – 5 steps minimum (1.0 – 4.0), step wedge verified within last year. Densitometer Mfg. instructions followed Density steps closest to 1.0, 2.0, 3.0, and 4.0 are to be read Densitometer is acceptable if densities are within + .05 from tablet/wedge
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T-262.2 Step wedge comparison films verified prior to first use by calibrated densitometer, unless performed by manufacturer. Acceptable if density readings are within + .01. T-262.3 Periodic accuracy verifications of densitometers shall be performed each shift, after 8 hours of use, or after change of apertures, whichever comes first. Step wedge comparison films checked annually. T-262.4 Documentation -
densitometer calibration (not periodic verification) must be recorded in a calibration log. step wedge/tablet calibrations/verifications do not have to be documented.
T-270 EXAMINATION T-271 Radiographic Technique T-271.1 Single-Wall Technique -Use whenever practical -Radiation passes through only one wall of the weld (material) -Adequate number of exposures shall be made to demonstrate required coverage T-271.2 Double-Wall Technique -Use when a single-wall technique is not practical -Radiation passes through two walls of the weld (material) -Adequate number of exposures shall be made to demonstrate required coverage A) Single-Wall Viewing via Double-Wall Technique -for materials and for welds in components -weld (material) on the film side is viewed for acceptance on the radiograph. -when complete coverage is required for circumferential welds, a minimum of 3 exposures taken 120 degrees to each other shall be made. b) Double-Wall Viewing via Double-Wall Technique for materials and for welds in components 3.5-inches or less in nominal OD the radiation passes through two walls/weld in both walls is viewed for acceptance only a source side IQI shall be used - If the geometric unsharpness requirement cannot be met use single-wall viewing
T-272 Selection of Radiation Energy The radiation energy employed for any radiographic technique shall achieve the density and IQI image requirements of this Article.
T-273 Direction of Radiation - centered on the area of interest whenever practical.
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T-274 Geometric Unsharpness Geometric unsharpness of the radiograph shall be determined in accordance with: Ug = Fd/D where: Ug = geometric unsharpness. F = source size; the maximum projected dimension of the radiating source (or effective focal spot) in the plane perpendicular to the distance D from the weld or object being radiographed, inches. D = distance from source of radiation to weld or object being radiographed, inches. d = distance from source side of weld or object being radiographed, inches. T- 275 Location Markers (See Fig. T-275) - to appear as radiographic images on the film - shall be placed on the part, not on the exposure holder / cassette. - Their locations are to be permanently marked on surface of part being radiographed - or on a map in a manner permitting the area of interest to be accurately traceable - Locations shall be available for the required retention period of the radiograph - Evidence provided on the radiograph that the required coverage has been obtained T-275.1 Single-Wall Viewing A) Source Side Markers: Location markers shall be placed on the source side when radiographing the following: -flat components or longitudinal joints in cylindrical or conical components -curved or spherical components whose concave side is toward the source and the "source-to-material" distance is less than the inside radius of the component -curved or spherical components whose convex side is toward the source B) Film Side Markers: Location markers shall be placed on the film side when: - radiographing either curved or spherical components/concave side toward the source and the "source-tomaterial" distance is greater than the inside radius As an alternative to source side placement, location markers may be placed on the film side when the radiograph shows coverage beyond the location markers to the extent demonstrated in Fig. T-275 (e) and is documented in the radiographic report. C) Either Side Markers: Location markers may be placed on either the source side or film side when:
radiographing either curved or spherical components/concave side is toward the source and the "source-to-material" distance equals the inside radius of the component. T-275.2 Double-Wall Viewing: - For double wall viewing, at least one location marker shall be placed on the source side surface adjacent to the weld for each radiograph. T-275.3 Mapping the Placement of Location Markers: When inaccessibility or other limitations prevent the placement of markers as stipulated in "Single-Wall Viewing" and "Double-Wall Viewing", a dimensioned map of the actual marker placement shall accompany the radiographs to show that full coverage has been obtained.
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T-276 IQI Selection T-276.1 IQI’s shall be of the same alloy groups as shown in SE-1025, or SE-747, or an alloy of lower radiation absorption than the material being radiographed T-276.2 The designated hole IQI designated wire shall be as specified in ASME Code, Section V, Article 2, Table 276 (See table in Section V) - a smaller hole in a thicker IQI - or a larger hole in a thinner IQI may be substituted for any section thickness listed in Table 276 provided equivalent IQI sensitivity is maintained as shown in Table T-283. A) Welds With Reinforcements Selection of IQI based on: - nominal single wall thickness + the estimated weld reinforcement - Backing rings or strips are not considered as part of the thickness - Actual measurement of the weld reinforcement is not required. B) Welds Without Reinforcement Thickness of IQI based on: - nominal single wall thickness - Backing rings or strips are not considered as part of the thickness T-277 Use of IQI to Monitor Radiographic Examination
T-277.1 PLACEMENT OF IQIS A) Source Side IQIs - Place on the source side except for the condition described under T-277.1(b). - Place on a separate block when size or configuration prevents placing on the part or weld: - Blocks shall be made of the same or radiographically similar materials. - No restriction on the separate block thickness provided the IQI/area-of-interest density tolerance requirements of Paragraph T-282.2 are met.
B) Film Side IQIs Where inaccessibility prevents hand placing the IQI(s) on the source side, the IQI(s) shall be placed: - on the film side in contact with the part - separate block or “shim” placed as close to part as possible - block shall be larger than the IQI/3 sides of IQI must be visible on film - lead letter “F” placed next to or on the IQI - “F” may not mask the essential hole in the IQI
C) IQI Location for Welds -- Hole IQIs - Place IQI(s) adjacent to or on the weld. - ID numbers, lead letter "F", shall not be in the area of interest except when geometric configuration makes it impractical.
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D) IQI Location for Welds -- Wire IQIs - on the weld so that the length of wires is perpendicular to the length of the weld ID numbers, lead letter "F", shall not be in the area of interest except as in (1) and (2). 1) configuration makes it impractical to place the IQIs as outlined above 2) when weld metal is not radiographically similar to the base material ( See SE-142) E) IQI Location for Materials other than Welds -The IQI(s) with the IQI ID number(s), and, lead letter "F", may be placed in the area of interest T-277.2 Number Of IQIs - For components where one or more film holders are used, at least one IQI image shall appear on each radiograph except as outlined in "Special Cases". A) Multiple IQIs - One shall be representative of the lightest area of interest and the other the darkest area of interest; intervening densities on the radiograph shall be considered as having acceptable density. B) Special Cases 1) Cylindrical vessels where source is placed on axis of the object and one or more film holders used for single exposure of a complete circumference Three IQIs shall be spaced approximately 120 degrees apart. Where sections of longitudinal welds adjoin circumferential welds and are radiographed simultaneously with circumferential weld, an additional IQI shall be placed on each longitudinal weld at the end of each section most remote from the junction with the circumferential weld being radiographed. 2) Cylindrical vessels where source is placed on the axis of the object and four or more film holders are used for single exposure of a section of the circumference: - At least three IQIs shall be used - One shall be in the approximate center of the section exposed and one at each end - if the section exceeds 240 degrees, the rule for cylindrical vessels applies and additional film locations may be required to obtain necessary IQI spacing; otherwise at least one IQI shall appear on each film 3) Spherical vessels where source is located at the center of the vessel and one or more film holders used for single exposure of a complete circumference: - Three IQIs shall be spaced approximately 120 degrees apart - One additional IQI shall be placed on each other weld 4) Segments of spherical vessels where source is located at the center of the vessel and four or more film holders are used for single exposure of a section of the circumference: - At least three IQIs shall be used - One IQI shall be in the approximate center and one at each end - When the portion exceeds 240 degrees, the rule for spherical vessels applies and additional film locations may be required to obtain necessary IQI spacing; otherwise at least one IQI shall appear on each film 5) When an array of objects in a circle is radiographed, at least one IQI shall show on each object image. 6) In order to maintain the continuity of records involving subsequent exposures, all radiographs exhibiting IQIs which qualify the techniques permitted above must be retained.
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T-277.3 Shims Under Hole IQIs - material radiographically similar to the weld metal shall be placed between the part and the IQI if needed - the radiographic density throughout the area of interest shall be no more than minus 15% from (lighter than) the radiographic density through the IQI. - the shim dimensions shall exceed the IQI dimensions such that the outline of at least three sides of the IQI image shall be visible in the radiograph.
Note- the term ‘SHIM’ is also used in Magnetic Particle Examination know how to discriminate they love to try and confuse you in examinations.
T-280 EVALUATION T-281 Quality of Radiographs All radiographs must be free from mechanical, chemical, or other blemishes to the extent that they do not mask and are not confused with the image of any discontinuity in the area of interest of the object being radiographed. Such blemishes include, but are not limited to: fogging processing defects such as streaks, watermarks, or chemical stains scratches, finger marks, crimps, dirtiness, static marks, smudges, or tears false indications due to defective screens T-282 Radiographic Density "T-282.1 Density Limitations. The transmitted film density through the radiographic image of the body of the appropriate hole IQI or adjacent to the designated wire of a wire IQI and the area of interest shall be: - 1.8 minimum for single film viewing for radiographs made with an X-ray source - 2.0 minimum for radiographs made with a gamma ray source - For composite viewing of multiple film exposures, each film of the composite set shall have a minimum density of 1.3 - The maximum density shall be 4.0 for either single or composite viewing - A tolerance of 0.05 in density is allowed for variations between Densitometer readings T-282.2 Density Variation A) If the density of the radiograph anywhere through the area of interest varies by more than minus 15% or plus 30% from the density through the body of the hole IQI or adjacent to the designated wire of the wire IQI, within the minimum / maximum allowable density ranges specified in T-282.1: - an additional IQI shall be used for each exceptional area and the radiograph retaken - when calculating the allowable variation in density, the calculation may be rounded to the nearest 0.1 within the range specified in T-282.1. B) when shims are used the plus 30% density restriction of (a) above may be exceeded: - provided the required IQI sensitivity is displayed and the density limitations of T-282.1 are not exceeded.
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T-283
IQI
Sensitivity
Radiography shall be performed with a technique of sufficient sensitivity to display - the designated hole IQI image and the 2T hole - or the designated wire of a wire IQI - the radiographs shall display the ID numbers and letters. - If the required hole IQI image and specified hole, or designated wire, do not show on any film in multiple film technique, but do show in composite film viewing, interpretation shall be permitted only by composite film viewing T-284 Excessive Backscatter - If a light image of the "B" appears on a darker background of the radiograph, protection from backscatter is insufficient and the radiograph shall be considered unacceptable - A dark image of the "B" on a lighter background is not cause for rejection.
T-285 EVALUATION BY MANUFACTURER This paragraph was added in the 1998 Addenda to clearly reflect that film review consists of two separate and distinct elements -1.) A Technique Review 2.) Evaluation and Interpretations of the indications present on the film. The review form documenting the acceptability of the technique must be completed prior to the evaluation on the film. Both sheets must be completed and accepted prior to submittal to the Inspector.
T-290 DOCUMENTATION T-291 Radiographic Technique Details Details of the radiographic examination technique used shall be documented. As a minimum the information shall include:
identification, per T-224 data specified in T-275.3 when applicable (dimensioned or ID marker map) number of exposures or radiographs isotope or maximum X-ray voltage used source size material type and thickness, weld thickness, weld reinforcement thickness source-to-object distance distance from source side of object to the film film designation and manufacturer number of films per cassette single- or double-wall exposure single- or double-wall viewing
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T-292 Radiographic Review Form Manufacturer shall prepare a radiographic review form. This form must contain at least: a.) b.) c.) d.) e.)
A listing of each film location. The information in T-291 or by reference. Evaluation and disposition of each weld or material. Name of the Mfg.’s representative that accepted the film. Date
Document Status: Last Updated 27 January 2006 – Verified To ASME V Article 2 2004 Addenda
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SUBJECT:
API AUTHORIZED PRESSURE VESSEL INSPECTOR CERTIFICATION EXAM
LESSON:
REVIEW REQUIREMENTS FOR LIQUID PENETRANT EXAMINATION
OBJECTIVE:
FAMILIARIZE CANDIDATES FOR THE API-653 CERTIFICATION WITH RELEVANT REQUIREMENTS FOR LIQUID PENETRANT EXAMINATION.
REFERENCE:
ASME SECTION V 2004, ARTICLE 6
T-610 SCOPE Liquid penetrant examination techniques describe in Article 6 shall be used when specified by the referencing Code Section. Listed SE Standards (ASTM) Provide details which may be considered in specific procedures - SE-165, Standard Practice for Liquid Penetrant Inspection Method - Use PT method as described in Article 6 together with Article 1, General Requirements Definition of terms - Found in Mandatory Appendix I of this Article, which will send you to SE-1316.
T-620 GENERAL - PT is effective method for detecting discontinuities open to the surface of nonporous metals - Typical detectable discontinuities: cracks seams laps cold shuts laminations porosity Principles - penetrant applied to surface and allowed to enter discontinuity - excess penetrant removed - part is dried - developer applied - developer acts as blotter to absorb penetrant and as contrasting background
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T-621 Written Procedure T-621.1 Requirements A written procedure shall be developed and include items listed as essential and non-essential in Table T-621. Lets Review Those Items Now As They Are ideal For Closed Book Questions. T-621.2 Procedure Qualification Revision of procedure shall be required when: A change in an essential variable is made; changing a non-essential variable only means correcting the document.
T-630 EQUIPMENT Penetrant Materials - Include all penetrants, solvents, cleaning agents, developers, etc. used in the process
T-640 MISCELLANEOUS REQUIREMENTS T-641 Control of Contaminants required for penetrant materials when used on: - nickel based alloys, low sulphur, 1% residue by weight - austenitic stainless steel and titanium – low chlorine/fluorine, 1% residue by weight Certification is required – what constitutes certification? Documentation stated on the cans is not enough.
T-642 SURFACE PREPARATION A) When as welded, as cast, or as rolled condition is not satisfactory preparation by grinding, matching or other methods may be required B) Prior to examination the area to be examined and all adjacent areas within at least 1 inch shall be free of matter that can interfere with the examination C) Cleaning agents may be used to remove matter that will interfere with the examination D) Cleaning agents must meet the requirements of T641 if applicable
T-643 DRYING AFTER PREPARATION - after cleaning drying may be accomplished by evaporation or forced hot or cold air - minimum time must be established to assure cleaning agents dry prior to applying penetrant
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T-650 TECHNIQUES T-651 Techniques Six liquid penetrant techniques: - color contrast (visible) penetrant water washable post-emulsifying solvent removable - fluorescent penetrant: water washable post-emulsifying solvent removable T-652 TECHNIQUES FOR STANDARD TEMPERATURES -
-
0 0 standard temperature range: 50 F to 125 F
local heating and cooling is permitted
Outside these ranges procedure must be qualified. Be careful 1250F is not very high. T-653 TECHNIQUES FOR NON STANDARD TEMPERATURES Outside temperature ranges in T-652 require qualification per Mandatory Appendix III. This is the Liquid Penetrant Comparator requirement. T-654 TECHNIQUE RESTRICTIONS fluorescent penetrant shall not follow a color contrast examination Intermixing of penetrant materials from different families or manufacturers not permitted retest with water washable penetrants may cause loss of marginal indications T-660 CALIBRATION Lights meters both visible and black light must be calibrated: Annually After repair T-670 EXAMINATION T-671 PENETRANT APPLICATION by any suitable means dipping, Spraying, or Brushing compressed-air-type spray requires air be filtered to keep out contaminants T-672 PENETRATION TIME Critical. minimum time as shown in Table T-672 or as qualified by demonstration
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T-673 EXCESS PENETRANT REMOVAL T-673.1 Water Washable Penetrants remove with water spray pressure 50 PSI or less temperature 1100F or less T-673.2 Post-Emulsifying Penetrants Lipophilic Emulsification After dwell time emulsify excess by immersing or flooding component with emulsifier Time shall be determined experimentally. Following emulsification remove by rinsing with water at a temperature and pressure recommended by manufacturer.
Hydrophilic Emulsification After dwell time and prior to emulsification pre-rinse with water spray using the same procedure as for water washable for a time not to exceed 1 minute. Emulsify by spraying or immersion in hydrophilic emulsion. Following emulsification remove mixture by immersing or rinsing with water at a pressure and temperature recommended by manufacturer.
T-673.3 Solvent Removable Penetrants remove by wiping with cloth or absorbent paper traces removed by cloth or absorbent paper moistened with solvent FLUSHING SURFACE WITH SOLVENT IS PROHIBITED T-674 DRYING AFTER EXCESS PENETRANT REMOVAL A) Water washable or post-emulsifying technique: - Blot with clean materials or by circulating air - Air to not raise surface temperature above 125F B) Solvent Removable Technique: - Dry by normal evaporation, blotting, wiping, or forced air T-675 DEVELOPING - apply as soon as possible after penetrant removed - time interval to not exceed time per procedure - insufficient coating thickness may not draw out penetrant - excess coating thickness may mask indications - use only wet developer with color contrast penetrants - wet or dry may be used with fluorescent penetrants. T-675.1 Dry Developer Application - powder dusted evenly over entire surface to be examined. - apply to dry surface only. - apply by soft brush, hand powder bulb, powder gun, or other means.
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T-675.2 Wet Developer Application Must agitate suspension type prior to application. Ensure adequate dispersion of suspended particles. A) Aqueous Developer Application - apply to either wet or dry surface - apply by dipping, brushing, spraying, or other means - thin coating needed over entire surface - dry time may be reduced using warm air so long as surface does not exceed 125F - blotting not permitted B) Nonaqueous Developer Application - apply only to dry surface - apply by spraying - can apply by brushing where safety or access preclude spraying - dry by normal evaporation T-675.3 Developing Time for Final Interpretation - begins immediately after application of dry developer - begins as soon as wet developer coating is dry T-676 INTERPRETATION T-676.1 Final Interpretation - make within 10 to 60 minutes after developing time - longer periods permitted if bleed-out does not alter examination results - examine in increments if entire surface (large area) can not be done within prescribed time T-676.2 Characterizing Indication(s) If penetrant diffuses excessively into developer and discontinuities difficult to evaluate, close observation of formation of indications should be done. T-676.3 Color Contrast Penetrants Developer forms uniform white coating Bleed-out indicate discontinuities - usually deep red color Light pink color indicates excessive cleaning Inadequate cleaning may leave excess background Adequate illumination is required to insure adequate sensitivity ( 100 ft. candles/ 1000 Lux minimum) T-676.4 Fluorescent Penetrants Essentially same as Color Contrast process above except examination is by using Ultraviolet Light (black light). Perform examination as follows: In darkened area Examiner in darkened area 5 minute prior to performing examination Glasses or lenses worn by examiner shall not be photosensitive Black-light shall be warmed up minimum of 5 minutes before use or measurement of the intensity of the UV light emitted Measure black-light with black light meter Minimum of 1000 µW/sq. cm on surface of part required Measure intensity at least once every 8 hours
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T-677 POST EXAMINATION CLEANING
When required by procedure should be conducted as soon as possible after evaluation and documentation.
T-680 EVALUATION A) All indications shall be evaluated in terms of acceptance standards B) Discontinuities at surface will be indicated by bleed-out of penetrant - Surface irregularities may produce false indications C) Broad areas of fluorescence or pigmentation can mask indications - Such areas must be cleaned and reexamined.
T-690 DOCUMENTATION T-691.1 Nonrejectable Indications - Shall be recorded in accordance with Referencing Code Section T-691.2 Rejectable Indications - Shall be recorded in accordance with Referencing Code Section as a minimum type rounded or linear and extent shall be recorded. T-692 Examination Records For each examination you shall record
Procedure Identification and revision Visible or Fluorescent Type of materials Examination personnel and if required qualification level Map or record of indications Material and thickness Lighting equipment Date and time of examinations.
Note this list calls up a number of items on light intensity – it is important.
T-693 PERFORMANCE DEMONSTRATION When required by Referencing Code Section shall be documented.
Document Status: Last Updated 27 January 2006 – Verified To ASME V Article 6 2004 Addenda
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SUBJECT:
API AUTHORIZED PRESSURE VESSEL INSPECTOR CERTIFICATION EXAM
LESSON:
REVIEW REQUIREMENTS FOR MAGNETIC PARTICLE EXAMINATION
OBJECTIVE:
FAMILIARIZE CANDIDATES FOR THE API-653 CERTIFICATION WITH RELEVANT REQUIREMENTS FOR MAGNETIC PARTICLE EXAMINATION.
REFERENCE:
ASME SECTION V 2004, ARTICLE 7
Module Objective:There is no intent to produce personnel qualified to perform Magnetic Particle Examinations. This module is designed to familiarize candidates with the Quality requirements outlined in ASME Section V Article 7 in order that Inspectors can assure themselves that MT examinations have been correctly conducted and that the results will therefore be valid. Upon completion of this module and in-depth review of the Code document candidates should be able to identify and utilise the correct sections of the Code related to MT examination and to successfully answer examination questions on the subject matter.
T-710 SCOPE - When specified by referencing Code Section, the MT techniques of this Article shall be used - This Article generally in conformance with ASTM SE-709, Standard Recommended Practice for Magnetic Particle Examination. - SE-709 provides additional details to be considered in the procedures used - Article 7 shall be used together with Article 1, General Requirements - Definition of terms used found in Mandatory Appendix II, which will send you to SE-1316.
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T-72O GENERAL The magnetic particle method is applied to detect cracks and other discontinuities on or near the surfaces of ferromagnetic materials. Sensitivity greatest for surface discontinuities Sensitivity decreases rapidly with increasing depth of discontinuity Discontinuities detected typically are: cracks laps seams cold shuts laminations Principle: - Magnetizing an area to be examined - Applying ferromagnetic particles to the surface - Particles form patterns on surface/ discontinuities cause distortions in normal magnetic field - Patterns are usually characteristic of type of discontinuity detected - Maximum sensitivity is to linear discontinuities oriented perpendicular to the lines of flux - Examine each area twice for optimum effectiveness in detecting all types of discontinuities
- Lines of flux during one examination to be perpendicular to lines of flux during the other T-721 WRITTEN PROCEDURE REQUIREMENTS. T-721.1 Requirements
MT shall be performed in accordance with a written procedure, which shall as a minimum contain the variables listed as essential and non-essential in Table T-721. Lets review, as these are ideal for closed book exam questions.
T-721.2 Procedure Qualification When required a change in an essential variable requires requalification. A change in a non-essential variable requires documentation updates only. T-730 EQUIPMENT - Suitable and appropriate means used to produce the necessary magnetic flux - Use techniques listed in and described in T-750 T-731 EXAMINATION MEDIUM Ferromagnetic particles shall meet the following requirements: Treated with coloring agents to ensure adequate contrast with surface specific requirements given in SE-709 particles shall be used within temperature ranges set by the manufacturer
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T-741.1 PREPARATION A) Results usually satisfactory when surfaces are in the as-welded, as-rolled, as-cast, or as-forged condition - Grinding or machining may be necessary where surface irregularities could mask indications due to discontinuities B) Prior to examination: examine surface and all adjacent areas within 1 inch shall be dry, free of dirt, grease, lint, scale, welding flux, weld spatter, paint, oil, and other extraneous matter that could interfere with the examination C) Typical cleaning agents: detergents, organic solvents, descaling operations, and paint removers, degreasing, sand or grit blasting, or ultrasonic cleaning methods also may used D) If coatings left on part, it must be demonstrated that indications can be detected through the maximum coating thickness -- When temporary coatings are used to enhance particle contrast it must be demonstrated that indications can be detected through the enhancement coating T-741.2 SURFACE CONTRAST ENHANCEMENT
Where temporary non-magnetic coatings are utilized to provide particle contrast it shall be demonstrated that indications can be detected through the coating. T-750 TECHNIQUE - One or more of five magnetization techniques shall be used: prod technique longitudinal magnetization technique circular magnetization technique yoke technique multidirectional magnetization technique T-752 PROD TECHNIQUE T-752.1 Magnetizing Procedure - Magnetize by portable prod type electrical contacts pressed against area to be examined - Avoid arcing via remote switch that is operated only after prods have been properly positioned T-752.2 Magnetizing Current Direct or rectified magnetizing current shall be used Current shall be 100 (min) amp/in. to 125 (max) amp/in. of prod spacing for sections > 3/4” Current shall be 90 amp/in. to 110 amp/in. of prod spacing for sections < 3/4”. For Example: When testing a 1.0” thick section using prods 6” apart the current range shall be: 1.0” is greater than ¾” so range is 100-125 amps per inch 6 x 100 = 600 6 x 125 = 750 Range Is Therefore: 600-750 amps
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T-752.3 Prod Spacing
Space shall not exceed 8 in Shorter space to accommodate geometric limitations or to increase sensitivity Prod spacing less than 3 in. usually not practical. Particles band around prods Keep prod tips clean and dressed If open circuit voltage is greater than 25 volts, lead, steel, or aluminium (rather than copper) tipped prods are recommended to avoid copper deposits on parts being examined.
T-753 LONGITUDNAL MAGNETIZATION TECHNIQUE
Not part of current Body Of Knowledge T-754 CIRCULAR MAGNETIZATION TECHNIQUE
Not part of current Body Of Knowledge T-755 YOKE TECHNIQUE T-755.1 Application - Shall only be applied to detect discontinuities that are open to the surface of the part T-755.2 Magnetizing Procedure - Alternating or direct current electromagnetic yokes, or permanent magnet yokes, shall be used There is a note that states for material ¼” (6mm) or less AC Yokes are superior for detection of surface discontinuities for equivalent lifting power DC Yokes or Permanent magnets. T-756 MULTIDIRECTIONAL MAGNETIZATION TECHNIQUE
Not currently part of the Body Of Knowledge. T-760 CALIBRATION T-761 Frequency of Calibration T-761.1 Magnetizing Equipment A) Frequency: Equipment equipped with an ammeter Calibrate each piece of equipment at least once per year Calibrate prior to first use after major electrical repair, periodic overhaul, or damage B) Procedure: accuracy of meter verified annually by equipment traceable to a national standard Take readings at 3 different current out put levels encompassing the usable range
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C) Tolerance: -
Unit's meter reading shall not deviate more than ±10% full scale, relative to value shown by the test meter.
the actual current
T-761.2 Light Meters Both visible and black light meters shall be calibrated Annually Following repair T-762 LIFTING POWER OF YOKES A) - Check magnetizing force prior to use, at least once per year - whenever a yoke has been damaged - DC yokes checked daily prior to use B) - Alternating current yoke shall have a lifting power of at least 10 LB at the maximum pole spacing to be used C) - Direct current yoke or permanent magnet yoke shall have a lifting power of at least 40 LB at the maximum pole spacing to be used D) - Test weights to be weighed with a scale from a reputable manufacturer and stencilled With the applicable nominal weight prior to its first use.
- Verify weight only if damaged in a manner that could have caused potential weight loss
T-763 GAUSSMETERS Gaussmeters shall be calibrated Annually Following repair
T-764 MAGNETIC FIELD ADEQUECY T-764.1.1 Pie –Shaped Gauges - Place gage on part surface - Clearly defined line across copper face of indicator indicates suitable flux or field strength - When clearly defined line not present, the magnetizing technique shall be changed or adjusted -best used with dry particles T-764.1.2 Artificial Flaw Shims Understand what these are they are similar to ‘CASTROL Indicators or Strips’.
Be cautious about the word ‘SHIM’ it is also use din Radiography and is often used in examination questions to determine if you know the difference.
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T-764.1.3 Hall Effect Tangential Probes Not current part of Body Of Knowledge
T-753.3 Magnetic Field Direction Adequacy and Direction of the field shall be verified using indicators or shims. A clear line of direction shall be identified. T-765 WET PARTICLE CONCENTRATION AND CONTAMINATION. Not currently part of Body Of Knowledge T-766 SYSTEM PERFORMANCE OF HORIZONTAL UNITS. Not currently part of Body Of Knowledge T-770 EXAMINATION T-771 PRELIMINARY EXAMINATION
Visual examination prior to MT examination is required to identify and flaws that are obvious. T-772 DIRECTION OF EXAMINATION - Perform 2 separate examinations on each area - During 2nd examination, lines of magnetic flux shall be approximately perpendicular to those used during 1st examination - A different technique may be used for 2nd examination
T-773 METHOD OF EXAMINATION Examination shall be done by the continuous method. a) Dry Particles - the magnetizing current remaining on while the examination medium is being applied and while the excess of the examination medium is being removed. b) Wet Particles – the magnetizing current shall be turned on after particle applied. Wet particles applied by aerosol cans may be applied at any time. Wet particles applied while current is on should be applied adjacent to area of interest and allowed to flow over the examined area. T-774 EXAMINATION COVERAGE - Conduct with sufficient overlap to assure 100% coverage at required sensitivity (SEE T-764)
T-775 RECTIFIED CURRENT A) When direct current is required rectified current may be used. Rectified current shall be either 3-phase or single-phase B) Amperage required with 3-phase, full rectified current / verified by measuring average current. C) Amperage required with single-phase current / verified by measuring the average current during the conducting half cycle only.
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T-776 EXCESS PARTICLE REMOVAL Excess of dry particles remove by light air stream or low pressure dry air. Current or power shall remain on during removal of excess particles.
T-777 INTERPRETATION Indications shall be classed as False, Nonrelevant or Relevant. T-777.1 Non-fluorescent examinations must have a minimum of 100 fc (1000 lx) light intensity at the surface. This must be demonstrated one time, documented, and retained on file. T-778.2 Fluorescent Particles: Examination performed using ultraviolet or “black light” as follows: in a darkened area examiner shall be in darkened area for 5 minutes prior to exam examiners glasses or lenses shall not be photosensitive “black light” warmed up for min of 5 minutes or intensity measured “black light” intensity shall be a minimum of 1000 μ W / cm2 on the part surface intensity measured every 8 hours or when work station changed
T-778 DEMAGNETIZATION -
Do any time after completion of examination if residual magnetism in the part could interfere with subsequent processing.
T-779 POST EXAM CLEANING If required should be conducted as soon as possible using a process that does not affected the part.
T-780 EVALUATION A) - Evaluate all indications in terms of acceptance standards of the referencing Code Section B) - Discontinuities on or near surface indicated by retention of the examination medium - False indications may exist because of localized surface irregularities due to machining marks or other surface conditions C) - Particle accumulations in broad areas might mask indications and are prohibited - Such areas must be cleaned and re-examined
T-790 DOCUMENTATION T-791 Multidirectional Magnetization Technique Sketch - Technique sketch shall be prepared for each different geometry examined - Sketch to show the part geometry, cable arrangement and connections, magnetizing current for each circuit, and the areas of examination where adequate field strengths are obtained
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- Parts with repetitive geometry's but different sizes can be examined using one sketch, provided the magnetic field strength is adequate when demonstrated using the magnetic particle field strength indicator. (SEE T755.2)
T-792 RECORDING OF INDICATIONS T-792.1 Nonrejectable Indications. Shall be recorded as per referencing code. T-792.2 Rejectable Indications. Shall be recorded and identified as linear or rounded with their extent and alignment.
T-793 EXAMINATION RECORDS. Each examination shall record the following as a minimum:
Procedure identification and revision. MT equipment and type of current. Particle type. Examination personnel identity and if required qualifications. Map of indications per T-792. Material and thickness. Lighting equipment. Date and time examinations performed.
T-794 PERFORMANCE DEMONSTRATION. When required by referencing code will be performed and documented.
Document Status: Last Updated 27 January 2006 – Verified To ASME V Article 7 2004 Addenda
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ASME SECTION V - NDE - PRACTICE QUESTIONS Module Objective:This section provides API exam style questions for you to test your knowledge absorption. The answers are provided at the end of the section. Try the questions then verify your answers, if wrong then go back to course module of code book to find answer.
1. The ______________________ is responsible for examination equipment calibration records. 1. manufacturer 2. NDE technician calibrates his own equipment and 3. company that manufactures the NDE equipment 4. Authorized Inspector 2. At least _____________ copy(ies) of an NDE procedure must be available to the Manufacturers Nondestructive Examination Personnel at the work site. 1. two 2. one 3. none 4. there is no requirement 3. The difference between an inspection and an examination per Section V of the ASME Code is: 1. Inspections are NDE functions performed by contractors 2. “examinations” are QC functions performed by the manufacturer’s employees 3. “inspections” are performed by the Authorized Inspector 4. 2 & 3 above 4. How must all Nondestructive Examination Personnel be qualified? 1. per the manufacturer’s PQR’s 2. per the requirements of the referencing code or standard 3. The AI will specify the requirements for each job 4. they are always qualified per ASNT SNT-TC-1A 5. Which of the following is not part of the minimum content of a written radiographic procedure? 1. type of screens used if any 2. type of emulsion used 3. film brand & designation 4. maximum X-ray voltage or isotope used
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6. How can compliance with a written radiographic procedure be demonstrated? 1. by showing the film to the A.I. 2. by confirming the accuracy of the radiographs with a welder or welding foreman 3. by verifying the proper density and demonstrating the IQI image requirements 4. by demonstrating the required sensitivity by showing the “3T” hole in a hole type IQI 7. What finished surface is required of butt welds? 1. all surface cracks must run vertically in the center 2. all surface cracks must run horizontally in the center 3. they must not have any irregularities or contours that will mask defects or interfere with interpretation 4. they must not have any undercut or pinholes that will mask defects or interfere with interpretation 8. One reason for a system of radiographic film identification is: 1. to identify the film manufacturer 2. so the location of defects will be traceable to the weldment 3. to keep track of how much film is used for billing purposes 4. so the welders will know where to have the film placed by the radiographer 9. Intensifying screens may be used __________________ . 1. only when radiographing at night 2. only for Polaroid SE-1968 instant radiographs 3. when performing radiography in accordance with ASME Section V, Article 2 4. for color radiographs only 10. IQIs may be what types? 1. wire 2. hole 3. crack 4. 1 & 2 above 11. Viewing facilities for radiographs shall __________________ .
1. be small, warm and comfortable enough for afternoon naps 2. have adjustable lighting with variable temperature control for film storage 3. be bright and airy with lots of ferns and plants 4. have subdued background lighting that will not cause glare on the film 12. The direction of the central beam of radiation should be ______________ the area of interest whenever practical. 1. as close as possible to 2. centered on 3. no more than 18” from 4. at least 36” from
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13. Where are hole type IQIs placed when radiographing welds? 1. always in the center of the weldment 2. adjacent to or on the weld but not in the area of interest 3. on the film side 4. none of the above 14. Where are location markers placed if they are to appear as a radiographic image? 1. on the part to be radiographed 2. on the film in the dark room 3. on the IQI top side over the “2T” hole 4. 1 & 3 above 15. The IQI is normally placed on which side of a part? 1. the IQI is optional so it doesn’t matter 2. the film side; the same side of the part to be inspected as the comparator 3. the source side except when inaccessibility prevents hand placement on that side 4. the film side; the same side of the part to be inspected as the film 16. What designation is used to indicate the IQI is on the film side? 1. it is only noted on the radiographic report - there is no other designation used 2. the welder noted it on the weld map 3. the IQI may not be placed on the film side 4. a lead letter “F” placed next to or on the IQI 17. How many IQIs should appear on each radiograph? 1. there must always be one on every radiograph and it must appear as a radiographic image 2. there must always be one on every radiograph but it need not appear as a radiographic image 3. there must always be two on every radiograph and it must appear as a radiographic image 4. it depends on the configuration used to set up the shot (panoramic multifilm, single shots, etc...) 18. Shims may be placed under IQIs to simulate weld reinforcement to assure the density in the area of interest is no more than _________ lighter than the density through the IQI. 1. 10% 2. 25% 3. 15% 4. 5% 19. Which of the following blemishes is permitted on film as long as they do not interfere with interpretation and do not mask or become confused with discontinuities in the area of interest? 1. fogging & false indications from defective screens 2. scratches, crimps, static marks & dirtiness 3. processing defects such as streaks & water marks 4. all of the above
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20. The minimum density requirements for single film viewing are: 1. 1.8 for film made with gamma ray and 2.0 for film made with an X-ray machine 2. 4.0 for film made with gamma ray and 4.0 for film made with an X-ray machine 3. 2.0 for film made with gamma ray and 1.8 for film made with an X-ray machine 4. no more than 25% lighter in any area than the density in the darkest area 21. When using only one IQI per film density measurements may vary through the area of interest by no more than ____________ or additional IQIs will be required. 1. minus 15% or plus 30% 2. plus 15% or minus 30% 3. plus 1.5 X ratio of average densities 4. no more than 15% from the density of the step wedge 22. Which of the below is an essential indication of sensitivity for image quality of a radiograph? 1. display of the welders stampings 2. clearly visible location markers 3. display of the designated hole or essential wire of the IQI used 4. proper density variations within 50% of the IQI thickness 23. Excessive backscatter in indicated by: 1. a lead letter “F” being visible on the radiograph 2. a dark image of the lead letter “B” on a lighter background 3. any image of the lead letter “B” in the background of the film
4. a light image of the lead letter “B” on a dark background 24. A tank is built with plate under 2 inches thick. The geometric unsharpness of the radiographs shall not exceed: 1. 0.010" 2. 0.020" 3. 0.030" 4. 0.040" 25. The following information may not be included in the documentation accompanying the radiographs: 1. minimum source to object distances and film brand & designation 2. number of exposures & film identification 3. Isotope & effective focal spot sizes 4. development time & exact shim material specifications 26. When the radiographs are presented to the Authorized Inspector _________________ 1. he will interpret them and indicate the disposition of each film on the report. 2. he will view them only after a good lunch paid for by the NDE technician. 3. the manufacturer will have interpreted all the film and will have indicated the disposition of each on the report and will have also included all the other information required to on the report. 4. the radiographs will be marked with a permanent marker or by other means to indicate which technician processed them.
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27. Which of the following is not a type of discontinuity liquid penetrant examination is effective in detecting. 1. cold shuts & laminations 2. subsurface cracks 3. pinholes 4. seams
28. Which of the following need not be included in a Liquid Penetrant procedure? 1. post examination cleaning details 2. materials, shapes & sizes to be examined 3. temperature of penetrant after the examination 4. processing details for removal of excess penetrant 29. Revisions to PT procedures may be required if there is 1. a change in part processing that may close the surface openings of defects or leave interfering deposits 2. a change or substitution in type or family of penetrant materials 3. a change or substitution is made in the precleaning materials or process 4. All of the above 30. Which of the following penetrant techniques may not be used? 1. solvent removable 2. hard drying fluorescent 3. water washable 4. post emulsifying 31. What materials require the use of tested and certified liquid penetrants as to the contaminants in the penetrant? 1. carbon steels with > 3% chrome 2. aluminum 3. nickel base alloys & titanium 4. copper 32. What condition must the surface to be examined be in prior to conducting the examination? 1. dry & free of all remedial demagnetization materials & effects 2. dry & free of any oil, grease, lint, scale or other extraneous matter for 1” on all sides of the area to be examined 3. free of all subsurface defects previously detected by other methods 4. dry & free of extraneous matter for 2” on all sides of the area to be examined 34. The minimum period of drying time after initial cleaning is _____________________ . 1. at least 5 minutes to assure that all the cleaning solution has evaporated prior to applying the penetrant 2. a minimum time established to assure that all the cleaning solution has evaporated prior to applying the penetrant 3. at least 15 minutes to assure that all the cleaning solution has evaporated prior to applying the penetrant 4. at least 10 minutes to assure that all the cleaning solution has evaporated prior to applying the penetrant
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35. Which of the following is not a suitable means of removing penetrant. 1. flushing water washable penetrant with water spray of less than 50 PSI & 110 F 2. steaming water washable penetrant at 300 PSI to remove it 3. wiping solvent removable penetrant with a lint free cloth 4. rinsing post emulsifying penetrant at a temperature & pressure as recommended by the manufacturer
36. Without special qualification penetrant testing can be performed between ______________ degrees. 1. 50 degrees F to 135 Degrees F 2. 50 degrees F to 125 degrees F 3. 72 degrees F to 130 Degrees F 4. 50 degrees F to 130 Degrees F 37. When PT examination is to be performed above or below ________ the procedure is qualified for the temperature range intended using a ________________ . 1. 50 degrees F to 125 degrees F ---- Image Quality Indicator 2. 50 degrees F to 125 degrees F ---- field indicator 3. 50 degrees F to 125 degrees F ---- comparator 4. 50 degrees F to 125 degrees F ---- and DAC curve 38. Fluorescent penetrant examination shall not follow _________________ . 1. UT thickness measurement 2. radiography because the residual radiation will cause false indications 3. Eddy current examination 4. color contrast PT examination 39. The emulsification time for lipophilic emulsification of a post emulsifying penetrant is: 1. 90 seconds 2. 6 minutes 3. 10 minutes 4. as determined experimentally 40. When removing water washable penetrant the spray of water may not exceed? 1. 100 degrees F & 50 psi 2. 90 degrees F & 60 psi 3. 110 degrees F & 50 psi 4. 110 degrees F & 55 psi 41. Water washable and post emulsifying penetrants may be dried using circulated air as long as the surface of the part does not exceed: 1. 100 degrees F 2. 110 degrees F 3. 212 degrees F 4. 125 degrees F
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42. How shall PT indications be evaluated per ASME Article 6? 1. per universal acceptance standards in ASNT SNT-TC-1A 2. in terms of the acceptance standards of the referencing code section 3. per the specific requirements in appendix N.5.3 of API-789 4. per the Owner/User procedures for NDE 43. Five typical of discontinuities detectable by the magnetic particle method are: 1. seams, low carbon content, cold shuts, laminations, and bad developing 2. cracks, caustic embrittlement, seams, and silicon isotope matrix syndrome 3. excessive weld seam reinforcement, cracks, cold shuts, seams, and low viscosity 4. cracks, laps, seams, cold shuts and laminations 44. What is the magnetic particle examination medium? 1. the surfaces of ferromagnetic work pieces 2. dry, wet or fluorescent ferromagnetic particles 3. any type of small metal particles 4. high iron content enamel or latex coatings 45. If coatings are left in place during MT examination _____________________ 1. the particles used must be the same color as the coating 2. coatings are not allowed to be left in place - all coatings must be removed 3. the procedure must be demonstrated as capable of detecting indications through the maximum thickness of the coating applied 4. all indications must be verified with penetrant examination in addition to the magnetic particle examination 46. What type of discontinuity is the magnetic particle method most sensitive to? 1. subsurface discontinuities 2. slag inclusions not open to the surface 3. linear discontinuities perpendicular to the lines of flux 4. high nickel alloy weld defects 47. When performing fluorescent MT examiners shall allow _____ _____________ for their eyes to adjust to the darkened conditions. 1. 5 minutes 2. 90 seconds 3. 3 minutes 4. 10 minutes 48. The intensity of the black light used shall be a minimum of: 2 1. 800 μW / cm 12” from the surface of the part being examined 2. 600 μW / cm2 on the surface of the part being examined 3. 1800 μW / cm2 18” from the surface of the part being examined 4. 1000 μW / cm2 on the surface of the part being examined
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49. Normally dry particles may not be used on surfaces above: 1. 800 0F and 135 0F 2. ambient temperatures 3. 600 0F and 135 0F 4. the manufacturer’s recommendations 50. Magnetic field strength may be verified by using ___________________ 1. an amp meter to determine if the field is within + 10% of full scale 2. the proper IQI manufactured using all magnetically identical materials 3. an ohm meter to determine if the field is within + 5% of full scale 4. pie shaped magnetic particle field indicator or artificial flaw shims 51. All examinations will be conducted with sufficient overlap to assure an minimum of _________ coverage? 1. 99% 2. 100% 3. 80% 4. 90% 52. When using the prod technique the maximum prod spacing allowed is __________ 1. 1 foot 2. 3 inches 3. 1/2 foot 4. 8 inches 53. Magnetic particle equipment with ammeters must be calibrated _____________ 1. always prior to each use 2. after every 10 examination sessions 3. before and after each examination 4. prior to first use if it the equipment has not been used for a year or more.
54. AC yokes must be able to lift _______ pounds at a maximum spacing of __________ . 1. 40 pounds at the maximum spacing to be used during examinations 2. 10 pounds at a maximum spacing of 18 inches or 1 1/2 feet 3. 40 pounds at a maximum spacing of 1.5 times the length of the yoke legs 4. 10 pounds at the maximum spacing to be used during examinations
55. MT equipment with ammeters must be calibrated to a standard ___________
1. supplied by the MT equipment manufacturer
2. supplied by the ISO MT standards committee 3. traceable to a National Standard 4. welded by a qualified welder or welding operator qualified in accordance with ASME Section V
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56. What is the maximum temperature of materials covered under SE 797? 1. 2. 3. 4.
3500 F 4000 F 1500 F 2000 F*
57. SE-797 provides guide lines for the ______________________ method for measuring thickness.
1. “Z” scan 2. contact pulse echo* 3. submerged radiant echo 4. real time 1/2 echo 58. A pulse echo instrument measures the _____________ of the ultrasonic pulse though the part. 1. 2. 3. 4.
speed wave velocity transit time*
59. Reference blocks used to calibrate equipment should have an ultrasonic velocity:
1. 2. 3. 4.
of V = .4562 X 3 of no less than 10,000 inches the same as the piece to be tested* based on sheer wave impact
60. Which is not a type of thickness measurement instrument? 1. 2. 3. 4.
Flaw detectors with CRT readout Flaw detectors with CRT floor scan pressure readout* Flaw detectors with CRT and direct thickness readout Direct thickness readout
61. For measuring thin sections which type of search unit is generally used? 1. 2. 3. 4.
Highly damped, high frequency Highly attenuated, low frequency Highly damped, low frequency 5 MHz single element
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62. When using a direct contact, single element search unit the display start is: 1. 2. 3. 4.
based on the average value of the display syncronized to the initial pulse* equal to e = m2 always at the top
63. When performing a complete calibration of an instrument using a delay line single element search unit calibration blocks should be: 1.
At least two – one near the maximum thickness of the range to be measured and one near the mid range At least two – a 1 inch block and a 6 inch block of the same velocity At least three blocks with a minimum differnce in thickness between each of at least 1 inch At least two with a thickness near the maximum of the range to be measured and the other block near the minimum thickness*
2. 3. 4.
64. When calibrating a UT instrument using Case II, what minimum number of test blocks should be used when the instrument must be completely calibrated with the delay line search unit? 1. 2. 3. 4.
3 4 2 1
65. When using dual search units there is an inherent error due to the: 1. distance between the units 2. velocity rate averages 3. Vee path that the sound beam travels* 4. geometry of the special calibration blocks required
66. When measuring materials at high temperatures the readings are high by a factor of: 1. 2. 3. 4.
1% per 500F 1% per 100F 5% per 500F 1% per 1000F
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67. When measuring materials at high temperatures the readings are high by a factor of: 1. 2. 3. 4.
1% per 500F 1% per 100F 5% per 500F 1% per 1000F
68. When developing a detailed UT thickness measurement procedure which of the following does not need to be considered?
1. 2. 3. 4.
Equipment lighting conditions surface preparation and couplant allowable tolerances and calibration
69. Which of the following would not be included in a UT report: 1. 2. 3. 4.
Inspection procedure Calibration blocks, size and material type density readings* Size, frequency, and type of search unit
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ANSWER SHEET FOR API RP 577 PRACTICE QUESTIONS
1. 1, T-130
24. 2, T-285
47. 4, T-778
2. 2, T-150
25. 4, T-291
48. 4, T-731
3. 4, T-170
26. 3, T-292
49. 4, T-753
4. 2, T-140, (a)
27. 2, T-600
50. 2, T-772
5. 2, T-221.1
28. 3, T-621.1
51. 4, T-773
6. 3, T-221.2
29. 4, T-621.2
52. 4, T-761
7. 3, T-222.2
30. 2, T-651
53. 4, T-762
8. 2, T-224
31. 3, T-641
54. 3, T-761
9. 3, T-232
32. 2, T-642
55. 4, T-773
10. 4, T-233
33. 2, T-643
56. 797 – 1.1
11. 4, T-234
34. 2, T-673
57. 797 – 1.1
12. 2, T-273
35. 2, T-652
58. 797 – 4.2
13. 2, T-277
36. 3, T-653
59. 797 – 4.4
14. 1, T-275
37. 4, T-654
60. 797 – 6.1
15. 3, T-277.1, (a)
38. 4, T-673.2
61. 797 – 6.2
16. 4, T-277.1, (b)
39. 3, T-673.1
62. 797 – 7.1.1
17. 4, T-277.2
40. 4, T-674
63. 797 – 7.2.2.1
18. 3, T-277.3
41. 2, T-680
64. 797 – 7.2.2.1
19. 4, T-281
42. 4, T-720
65. 797 – 7.3.1
20. 3, T-282
43. 2, T-731
66. 797 – 8.1
21. 1, T-282
44. 3, T-741
67. 797 – 8.1
22. 3, T-283
45. 3, T-720
68. 797 - 9
23. 4, T-284
46. 1, T-778
69. 797 - 10
Document Status: Last Updated March 15 2005 – Verified To ASME V Article 2 2003 Addenda
281
SUBJECT:
API AUTHORIZED PRESSURE VESSEL INSPECTOR CERTIFICATION EXAM
LESSON:
REVIEW REQUIREMENTS FOR ULTRASONIC EXAMINATION
OBJECTIVE:
FAMILIARIZE CANDIDATES FOR THE API-653 CERTIFICATION WITH RELEVANT REQUIREMENTS FOR ULTRASONIC EXAMINATION.
REFERENCE:
ASME SECTION V, ARTICLE 23
Module Objective. The current Body Of Knowledge limits the examination on ultrasonic techniques. The Body Of Knowledge refers to Section 23 of ASME Section V, which is a collection of 10 referenced ASTM Standards dealing with the application of Ultrasonics in a variety of situations. You will however only be examined upon SE-797 Standard Practice For Measuring Thickness By Manual Ultrasonic Pulse-Echo Contact Method. This is an important knowledge area as ultrasonic thickness measurement is a common technique for detecting and recording material loss due to corrosion/erosion. Since the API Inspector will go on to make calculations based on this data it is critical that the data is valid. This module is not designed to qualify you to make UT measurements but to provide you the skills to ensure the quality control requirements are met in collecting data and therefore ensuring the numbes you work with are valid. 1. Scope The scope of the document is very straightforward. The most significant issue is that it does specify an upper 0 0 temperature limit of 200 F (93 C). Why is this? 2. Referenced Documents. Simple listing there is nothing of great significance here. 3. Terminology. It is important that candidates understand the terminology commonly applied to ultrasonic examinations. There have been a lot of examination questions in this area.
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- Definitions of terms used are in: a) Mandatory Appendix III that will send you to: b) SE-1316 (now a general section on definitions as of the 1994 addenda) - The SA, SB & SE documents referenced are in Article 23. Some common definitions from SE-1316 are given below: A-scan -- a method of data presentation utilizing a horizontal base line that indicates distance, or time, and a vertical deflection from the base line which indicates amplitude.
back reflection --- indication of the echo from the far boundary of the material under test. contact inspection --- the method in which the search unit makes direct contact with the material, with a minimum couplant film. couplant --- a substance used between the search unit and test surface to permit or improve transmission of ultrasonic energy. crystal --- a piezoelectric element in a probe or search unit. dual search unit (twin probes) --- a probe or search unit containing two elements, one a transmitter, the other a receiver (T-R, S-E) echo --- indication of reflected energy initial pulse --- the response of the ultrasonic system display to the transmitter pulse (sometimes called the "main bang" ). interface --- the boundary between two materials loss of back reflection --- an absence or significant reduction in the amplitude of the indication from the back surface of the part under examination.
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multiple back reflections --- successive reflections from the back surface of the material under examination. normal incidence (straight beam)--- a condition in which the axis of the ultrasonic beam is perpendicular to the entry surface of the part under examination. pulse echo method --- an inspection method in which the presence and the position of a reflector are indicated by the echo amplitude and time. reference block --- a block used to establish a measurement scale, and a means of producing a reflection of known characteristics. scanning --- the relative movement of the search unit over a test piece. search unit --- a device incorporating one or more transducers. straight beam --- a vibrating pulse wave train traveling normal to the test surface. transducer -- an electro-acoustical device for converting electrical energy into acoustical energy and vice versa. ultrasonic --- pertaining to mechanical vibrations having frequency greater than approximately 20,000 Hz.
4. Summary of Practice. 1. We shall understand the relationship between the thicknesses measured by ultrasound is a transit time out and back so the product is the velocity of sound in the material divided by two for the return time of the signal. 2. This goes on to explain that the pulse-echo approach measures the total transit time, even though the instrument may automatically do the division for you. 3. This expands on 4.1 that since the thickness is dependent upon velocity then the material characteristics are important as velocity changes with material. In many common applications a standard velocity is accepted for a given group of material i.e. Carbon Steels. 4. Reference blocks are therefore required having a known velocity, or of the same material to be tested and having a thickness in the range of that to be examined. This is a common deviation or error in practical filed testing. Lack of availability, cost cutting, laziness means that operators often ignore this rule. A reference block should have different reference thickness close to the minimum and maximum thickness to be examined. 5. Instrument displays must present a convenient presentation of thickness over the range of interest. Adjustments are commonly termed, range, sweep, material calibrate of velocity. The term used is not important it is the understanding behind it that matters. 6. This discusses the relationship between Transit Time and Thickness. There is no great significance in this. 5 Significance And Use. 5.1 This reinforces that the practice is designed for indirect measurement of thickness in material not exceeding the scope of the practice. It goes on to explain that these are single sided measurements without access to the far side of the component. 5.2 Discusses simple applications for the practice including precision machined parts, corrosion and erosion detection. These latter phenomena are discussed in the API Inspection Documents.
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6 Apparatus. 6.1 Instruments covered include Flaw Detectors with CRT A-Scan readouts Flaw Detectors with both A-Scan & digital readouts Digital Thickness read out. The last is not well liked in the oil and gas industry as discussed in some of the API documents.
The section then goes on to discuss the various modes of screen presentation. 6.2 Search Units For thickness measurement less than 0.6 mm (0.025 in) high frequency 10 MHz or greater are usually required. Special search units with delay lines, dual element etc. can all be used but in some cases need to be matched to the instrument for optimum performance. 6.3 Calibration Blocks. General requirements discussed previously and application is discussed in section 7. Step wedge examples are found in the Appendix to SE-797. 7
Procedure – Calibration and Adjustment of Apparatus.
Four basic case conditions are reviewed in detail: ¾ ¾ ¾ ¾
Direct Contact Single Element. Delay Line Single Element. Dual Search Units Thick Sections.
The paragraphs through to 7.4.6 describe the set up and calibration approaches and will be reviewed in class in detail. A. Case I - Direct Contact, Single-Element Search Unit:
1. Conditions a. display start is synchronized to the initial pulse b. all display elements are linear c. full thickness is displayed on CRT Note: Under these conditions, we can assume that the velocity conversion line effectively pivots about the origin (Fig. 1). It may be necessary to subtract the wear-plate time, requiring minor use of delay control. It is recommended that test blocks providing a minimum of two thicknesses that span the thickness range be used to check the full-range accuracy.
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2. Calibration & Adjustment a. place the search unit on a test block of known thickness with suitable couplant b. adjust the instrument controls (material calibrate, range, sweep, or velocity) until the display presents the appropriate thickness reading c. readings should then be checked and adjusted on test blocks with thickness of lesser value to improve the overall accuracy of the system. B. Case II - Delay Line Single-Element Search Unit: 1. Conditions a. the equipment must be capable of correcting for the time during which the sound passes through the delay line so that the end of the delay can be made to coincide with zero thickness b. this requires a "delay" control in the instrument, or automatic electronic sensing of zero thickness Note: In most instruments, if the material calibrate circuit was previously adjusted for a given material velocity, the delay control should be adjusted until a correct thickness reading is obtained on the instrument. However, if the instrument must be completely calibrated with the delay line search unit. the following technique is recommended: 2. Calibration & Adjustment a. use at least two test blocks 1. one should have a thickness near the maximum of the range to be measured 2. one should have a thickness near the minimum thickness to be measured 3. it is desirable that the thickness should be "round numbers" so that the difference between them also has a "round number" value b. place the search unit sequentially on one and then the other block, and obtain both readings and calculate the difference between the readings 1. if the reading thickness difference is less than the actual thickness difference a. place the search unit on the thicker specimen b. adjust the material calibrate control to expand the thickness range 2. If the reading thickness difference is greater than the actual thickness difference a. place the search unit on the thicker specimen, and adjust the material calibrate control to decrease the thickness range (a certain amount of over correction is usually recommended) b. reposition the search unit sequentially on both blocks c. note the reading differences while making additional appropriate corrections d. when the reading thickness differential equals the actual thickness differential, the material thickness range is correctly adjusted e. a single adjustment of the delay control should then permit correct readings at both the high and low end of the thickness range. Note: An alternative technique for delay line search units is a variation of that described in 7.2.2. A series of sequential adjustments are made. using the "delay" control to provide correct readings on the thinner test block and the "range" control to correct the readings on the thicker block. Moderate over-correction is sometimes useful. When both readings are "correct" the instrument is adjusted properly. C. Case III - Dual Search Units: 1. Conditions, Calibration & Adjustment a. the method described in Case II is also suitable for dual search units in the thicker ranges, above 3 mm (0.125 in.)
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b. below those values there is an inherent error due to the Vee path that the sound beam travels and: 1. transit time is no Ionger linearly proportional to thickness 2. the condition deteriorates toward the low thickness end of the range 3. the variation is also shown schematically in Fig. 2(a). Typical error values are shown in Fig. 2(b). c. Measuring thin materials: 1. if measurements are to be made over a very limited range near the thin end of the scale 2. it is possible to calibrate the instrument with the technique in Case II using appropriate thin test blocks 3. this will produce a correction curve that is approximately correct over that limited range 4. Note that it will be substantially in error at thicker measurements. d. Measuring a wide range of thickness: 1. if a wide range of thicknesses is to be measured, it may be more suitable to calibrate as in Case II 2. using test blocks a. at the high end of the range b. and perhaps halfway toward the low end 3. Following this, empirical corrections can be established for the very thin end of the range. e. for a direct-reading panel-type meter display, it is convenient to build these corrections into tile display as a nonlinear function. D. Case IV - Thick Sections: 1. Conditions a. for use when a high degree of accuracy is required for thick sections b. direct contact search unit and initial pulse synchronization are used c. the display start is delayed as described in h below d. all display elements should be linear e. incremental thickness is displayed on the CRT f. Basic calibration of the sweep will be made as described in Case 1 g. the test block chosen for this calibration should have a thickness that will permit calibrating the full-sweep distance to adequate accuracy that is, about 10 mm (0.4 in.) or 25 mm (1.0 in.) full scale h. after basic calibration. the sweep must be delayed. For instance: 1. if the nominal part thickness is expected to be from 50 to 60 mm (2.0 to 2.4 in.) and a the basic calibration block is 10 mm (0.4 in.) b the incremental thickness displayed will also be from 50 to 60 min (2.0 to 2.4 in.) g. the following steps are required. 1. adjust the delay control so that 2. the fifth back echo of the basic calibration block. equivalent to 50 min (2.0 in.). is aligned with the 0 reference on the CRT. 3. the sixth back echo should then occur at the right edge of the calibrated sweep 4. this calibration can be checked on a known block of the approximate total thickness Note: The reading obtained on the unknown specimen must be added to the value delayed off screen. For example, if the reading is 4 min (0.16 in.), the total thickness will be 54 mm (2.16 in.).
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8. Technical Hazards Not really hazards more limitations of techniques. 1. Dual search units: a. may be used effectively with rough surface conditions b. only the first returned echo, such as from the bottom of a pit, is used in the measurement c. generally, a localized scanning search is made to detect the minimum remaining wall. 2. Material Properties: a. the instrument should be calibrated on a material having the same acoustic velocity and attenuation as the material to be measured b. where possible, calibration should be confirmed by direct dimensional measurement of the material to be examined. 3. Scanning: a. the maximum speed of scanning should be stated in the procedure b. the following may require slower scanning: - material conditions - type of equipment - operator capabilities 4. Geometry: a. Highest accuracy can be obtained from materials with parallel or concentric surfaces b. it is possible to obtain measurements from materials with nonparallel surfaces. However: the accuracy of the reading may be limited as follows: - the reading obtained is generally that of the thinnest portion of the section being interrogated by the sound beam at a given instant - relatively small diameter curves often require special techniques and equipment - when small diameters are to be measured, special procedures including additional specimens may be required to ensure accuracy of setup and readout. 5. High-temperature materials: a. high-temperature materials, up to about 540*C ( 1000 F ) can be measured with specially designed Instruments with high temperature compensation, search unit assemblies, and couplants b. normalization of apparent thickness reading for elevated temperatures is required c. a rule of thumb often used is as follows: - the apparent thickness reading obtained from steel walls having elevated temperatures is high (too thick) by a factor of about 1% per 55*C (100*F) - if the instrument was calibrated on a piece of similar material at 20'C (68*F), and if the reading was obtained with a surface temperature of 460*C (860*F), the apparent reading should be reduced by 8% - this correction is an average one for many types of steel - other corrections would have to be determined empirically for other materials. 6. Instrument: a. time base linearity is required so that a change in the thickness of material will produce a corresponding change of indicated thickness b. if a CRT is used as a readout. its horizontal linearity can be checked by using Practice E 317.
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7. Back Reflection Wavetrain: a. direct-thickness readout instruments read the thickness at the first half cycle of the wavetrain that exceeds a set amplitude a fixed time. b. If the amplitude of the back reflection from the measured material is different from the amplitude of the back reflection from the calibration blocks, the thickness readout may read to a different half cycle in the wavetrain, thereby producing an error c. this may be reduced by: - using, calibration blocks having attenuation characteristics equal to those in the measured material - or adjusting back reflection amplitude to be equal for both the calibrating blocks and measured material. d. using an instrument with automatic gain control to produce a constant amplitude back reflection. 8. Readouts: a. CRT displays are recommended where reflecting surfaces are rough, pitted, or corroded b. direct-thickness readout, without CRT, presents hazards of misadjustment and misreading under certain test conditions such as: - especially thin sections - rough corroded surfaces - and rapidly changing thickness ranges 9. Calibration Standards: a. Greater accuracy can be obtained when the equipment is calibrated on areas of known thickness of the material to be measured 10. Variations in echo signal strength a. may produce an error equivalent to one or more half-cycles of the RF frequency, dependent on instrumentation characteristics. 9. Procedure Requirements A. In developing the detailed procedure. the following items should be considered 1. Instrument manufacturer's operating instructions 2. Scope of materials/objects to be measured 3. Applicability, accuracy requirements 4. Definitions 5. Requirements 6. Personnel 7. Equipment 8. Procedure qualification 9. Procedure 10. Measurement conditions 11. Surface preparation and couplant 12. Calibration and allowable tolerances 13. Scanning parameters 14. Report 15. Procedure used 16. Calibration record 17. Measurement record
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10. Report A. Record the following information at the time of the measurements and include it in the report: 18. Inspection procedure. 19. Type of instrument. 20. Calibration blocks, size and material type 21. Size, frequency, and type of search unit 22. Scanning method 23. Results 24. Maximum and minimum thickness measurements 25. Location of measurements 26. Personnel data, certification level
11. Keywords 27. 28. 29. 30. 31.
contact testing nondestructive testing pulse echo thickness measurement ultrasonics
Document Status: Last Updated 27 January 2006 – Verified To ASME V Article 23 2004 Addenda
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REVIEW OF API RP 571
291
SUBJECT:
API AUTHORIZED PRESSURE VESSEL INSPECTOR CERTIFICATION EXAM
&
PIPING
LESSON:
REVIEW OF SELECTED RP 571 DAMAGE MECHANISMS
OBJECTIVE:
FAMILIARIZE CANDIDATES FOR THE API-510 & API-570 CERTIFICATION WITH RELEVANT REQUIREMENTS OF RP 571 DAMAGE MECHANISMS
REFERENCE:
API RP 571
Module Objective. The API ICP Committee has deemed that inspectors shall demonstrate their knowledge and understanding of a selected list of common damage mechanism that occur in the refining industry and are listed in API Recommended Practice 571.
The current list of damage mechanisms given in the published body of knowledge are:
4.2.3 – Temper Embrittlement 4.2.7 – Brittle Fracture 4.2.9 – Thermal Fatigue 4.2.14 – Erosion/Erosion-Corrosion 4.2.16 – Mechanical Failure 4.3.2 – Atmospheric Corrosion 4.3.3 – Corrosion Under Insulation (CUI) 4.3.4 – Cooling Water Corrosion 4.3.5 – Boiler Water Condensate Corrosion 4.4.2 – Sulfidation 4.5.1 – Chloride Stress Corrosion Cracking (Cl-SCC) 4.5.2 – Corrosion Fatigue 4.5.3 – Caustic Stress Corrosion Cracking (Caustic Embrittlement) 5.1.2.3 – Wet H2S Damage (Blistering/HIC/SOHIC/SCC) 5.1.3.1 – High Temperature Hydrogen Attack (HTHA) the aim of this module is to review the selected mechanisms in such a way as to prepare candidates to correctly answer questions posed about each mechanism. This module is not an exhaustive review and great emphasis is placed on students studying and re-studying the document to commit essential information to memory.
Unlike other modules this material is new to the examination so experience on the type of question and answer sets is not available.
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1.3 ORGANIZATION AND USE The information for each damage mechanism is provided in a set format as shown below. This recommended practice format facilitates use of the information in the development of inspection programs, FFS assessment and RBI applications.
a) Description of Damage – a basic description of the damage mechanism. b) Affected Materials – a list of the materials prone to the damage mechanism. c) Critical Factors – a list of factors that affect the damage mechanism (i.e. rate of damage). d) Affected Units or Equipment – a list of the affected equipment and/or units where the damage mechanism commonly occurs is provided. This information is also shown on process flow diagrams for typical process units. e) Appearance or Morphology of Damage – a description of the damage mechanism, with pictures in some cases, to assist with recognition of the damage. f) Prevention / Mitigation – methods to prevent and/or mitigate damage. g) Inspection and Monitoring – recommendations for NDE for detecting and sizing the flaw types associated with the damage mechanism. h) Related Mechanisms – a discussion of related damage mechanisms. i) References – a list of references that provide background and other pertinent information. Damage mechanisms that are common to a variety of industries including refining and petrochemical, pulp and paper, and fossil utility are covered in Section 4.0. Damage mechanisms that are specific to the refining and petrochemical industries are covered in Section 5. In addition, process flow diagrams are provided in 5.2 to assist the user in determining primary locations where some of the significant damage mechanisms are commonly found. These are important, as the ICP committee has deemed that these are sources of questions. 3.1 Terms As the current body of knowledge focuses on selected mechanisms there is a lack of clarity about exactly where in the document questions may be drawn. As the whole document is referenced related questions where the answer may be in the terms can be expected as with all definitions they are ‘easy’ places to write questions from. 3.1.1 Austenitic – a term that refers to a type of metallurgical structure (austenite) normally found in 300 Series stainless steels and nickel base alloys. 3.1.2 Austenitic stainless steels – the 300 Series stainless steels including Types 304, 304L, 304H, 309, 310, 316, 316L, 316H, 321, 321H, 347, and 347H. The “L” and “H” suffixes refer to controlled ranges of low and high carbon content, respectively. These alloys are characterized by an austenitic structure. 3.1.3 Carbon steel – steels that do not have alloying elements intentionally added. However, there may be small amounts of elements permitted by specifications such as SA516 and SA106, for example that can affect corrosion resistance, hardness after welding, and toughness. Elements which may be found in small quantities include Cr, Ni, Mo, Cu, S, Si, P, Al, V and B.
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3.1.4 Diethanolamine (DEA) – used in amine treating to remove H2S and CO2 from hydrocarbon streams. 3.1.5 Duplex stainless steel – a family of stainless steels that contain a mixed austenitic-ferritic structure including Alloy 2205, 2304, and 2507. The welds of 300 series stainless steels may also exhibit a duplex structure. 3.1.6 Ferritic – a term that refers to a type of metallurgical structure (ferrite) normally found in carbon and low alloy steels and many 400 series stainless steels. 3.1.7 Ferritic stainless steels – include Types 405, 409, 430, 442, and 446. 3.1.8 Heat Affected Zone (HAZ) – the portion of the base metal adjacent to a weld which has not been melted, but whose metallurgical microstructure and mechanical properties have been changed by the heat of welding, sometimes with undesirable effects. 3.1.9 Hydrogen Induced Cracking (HIC) – describes stepwise internal cracks that connect adjacent hydrogen blisters on different planes in the metal, or to the metal surface. No externally applied stress is needed for the formation of HIC. The development of internal cracks (sometimes referred to as blister cracks) tends to link with other cracks by a transgranular plastic shear mechanism because of internal pressure resulting from the accumulation of hydrogen. The link-up of these cracks on different planes in steels has been referred to as stepwise cracking to characterize the nature of the crack appearance. 3.1.10 Low alloy steel – a family of steels containing up to 9% chromium and other alloying additions for high temperature strength and creep resistance. The materials include C-0.5Mo, Mn-0.5Mo, 1Cr-0.5Mo, 1.25 Cr0.5Mo, 2.25Cr-1.0Mo, 5Cr-0.5Mo, and 9Cr-1Mo. These are considered ferritic steels. 3.1.11 Martensitic – a term that refers to a type of metallurgical structure (martensite) normally found in some 400 series stainless steel. Heat treatment and or welding followed by rapid cooling can produce this structure in carbon and low alloy steels. 3.1.12 Martensitic stainless steel – include Types 410, 410S, 416, 420, 440A, 440B, and 440C. 3.1.13 Methyldiethanolamine (MDEA) – used in amine treating to remove H2S and CO2 from hydrocarbon streams. 3.1.14 Monoethanolamine (MEA) – used in amine treating to remove H2S and CO2 from hydrocarbon streams. 3.1.15 Nickel base – a family of alloys containing nickel as a major alloying element (>30%) including Alloys 200, 400, K-500, 800, 800H, 825, 600, 600H, 617, 625, 718, X-750, and C276. 3.1.16 Stress oriented hydrogen induced cracking (SOHIC) – describes an array of cracks, aligned nearly perpendicular to the stress, that are formed by the link-up of small HIC cracks in steel. Tensile strength (residual or applied) is required to produce SOHIC. SOHIC is commonly observed in the base metal adjacent to the Heat Affected Zone (HAZ) of a weld, oriented in the through-thickness direction. SOHIC may also be produced in susceptible steels at other high stress points, such as from the tip of the mechanical cracks and defects, or from the interaction among HIC on different planes in the steel.
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3.1.17 Stainless steel – there are four categories of stainless steels that are characterized by their metallurgical structure at room temperature: austenitic, ferritic, martensitic and duplex. These alloys have varying amounts of chromium and other alloying elements that give them resistance to oxidation, sulfidation and other forms of corrosion depending on the alloy content.
3.2 Symbols and Abbreviations 3.2.1 ACFM – alternating current magnetic flux leakage testing. 3.2.2 AE – acoustic emission. 3.2.3 AET – acoustic emission testing. 3.2.4 AGO – atmospheric gas oil. 3.2.5 AUBT – automated ultrasonic backscatter testing. 3.2.6 BFW – boiler feed water. 3.2.7 C2 – chemical symbol referring to ethane or ethylene. 3.2.8 C3 – chemical symbol referring to propane or propylene. 3.2.9 C4 – chemical symbol referring to butane or butylenes. 3.2.10 Cat – catalyst or catalytic. 3.2.11 CDU – crude distillation unit. 3.2.12 CH4 – methane. 3.2.13 CO – carbon monoxide. 3.2.14 CO2 – carbon dioxide. 3.2.15 CVN – charpy v-notch. 3.2.16 CW – cooling water. 3.2.17 DIB – deisobutanizer. 3.2.18 DNB – Departure from Nucleate Boiling. 3.2.19 DEA – diethanolamine, used in amine treating to remove H2S and CO2 from hydrocarbon streams. 3.2.20 EC – eddy current, test method applies primarily to non-ferromagnetic materials. 3.2.21 FCC – fluid catalytic cracker. 3.2.22 FMR – field metallographic replication. 3.2.23 H2 – hydrogen. 3.2.24 H2O – also known as water. 3.2.25 H2S – hydrogen sulfide, a poisonous gas. 3.2.26 HAZ – Heat Affected Zone 3.2.27 HB – Brinnell hardness number. 3.2.28 HCO – heavy cycle oil. 3.2.29 HCGO – heavy coker gas oil. 3.2.30 HIC – Hydrogen Induced Cracking 3.2.31 HP – high pressure. 3.2.32 HPS – high pressure separator. 3.2.33 HVGO – heavy vacuum gas oil. 3.2.34 HSLA – high strength low alloy. 3.2.35 HSAS – heat stable amine salts. 3.2.36 IC4 – chemical symbol referring isobutane. 3.2.37 IP – intermediate pressure. 3.2.38 IRIS – internal rotating inspection system. 3.2.39 K.O. – knock out, as in K.O. Drum. 3.2.40 LCGO – light coker gas oil. 3.2.41 LCO – light cycle oil. 3.2.42 LP – low pressure. 3.2.43 LPS – low pressure separator.
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3.2.44 LVGO – light vacuum gas oil. 3.2.45 MDEA – methyldiethanolamine. 3.2.46 MEA – monoethanolamine. 3.2.47 mpy – mils per year. 3.2.48 MT – magnetic particle testing. 3.2.49 NAC – naphthenic acid corrosion. 3.2.50 NH4HS – ammonium bisulfide. 3.2.51 PMI – positive materials identification. 3.2.52 PFD – process flow diagram. 3.2.53 PT – liquid penetrant testing. 3.2.54 RFEC – remote field eddy current testing. 3.2.55 RT – radiographic testing. 3.2.56 SCC – stress corrosion cracking. 3.2.57 SOHIC – Stress Oriented Hydrogen Induced Cracking 3.2.58 SS: Stainless Steel. 3.2.59 SW – sour water. 3.2.60 SWS – sour water stripper. 3.2.61 SWUT – shear wave ultrasonic testing. 3.2.62 Ti – titanium. 3.2.63 UT – ultrasonic testing. 3.2.64 VDU – vacuum distillation unit. 3.2.65 VT – visual inspection. 3.2.66 WFMT – wet fluorescent magnetic particle testing.
4.2.3 Temper Embrittlement
4.2.3.1 Description of Damage Temper embrittlement is the reduction in toughness due to a metallurgical change that can occur in some low o o o alloy steels as a result of long term exposure in the temperature range of about 650 F to 1100 F (343 C to o 593 C). This change causes an upward shift in the ductile-to-brittle transition temperature as measured by Charpy impact testing. Although the loss of toughness is not evident at operating temperature, equipment that is temper embrittled may be susceptible to brittle fracture during start-up and shutdown.
4.2.3.2 Affected Materials a) Primarily 2.25Cr-1Mo low alloy steel, 3Cr-1Mo (to a lesser extent), and the high-strength low alloy Cr- Mo-V rotor steels. b) Older generation 2.25Cr-1Mo materials manufactured prior to 1972 may be particularly susceptible. Some high strength low alloy steels are also susceptible. c) The C-0.5Mo and 1.25Cr-0.5Mo alloy steels are not significantly affected by temper embrittlement. However, other high temperature damage mechanisms promote metallurgical changes that can alter the toughness or high temperature ductility of these materials.
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4.2.3.3 Critical Factors a) Alloy steel composition, thermal history, metal temperature and exposure time are critical factors. b) Susceptibility to temper embrittlement is largely determined by the presence of the alloying elements manganese and silicon, and the tramp elements phosphorus, tin, antimony, and arsenic. The strength level and heat treatment/fabrication history should also be considered. c) Temper embrittlement of 2.25Cr-1Mo steels develops more quickly at 900oF (482oC) than in the 800oF to 850oF (427oC to 440oC) range, but the damage is more severe after long-term exposure at 850oF (440oC). d) Some embrittlement can occur during fabrication heat treatments, but most of the damage occurs over many years of service in the embrittling temperature range. e) This form of damage will significantly reduce the structural integrity of a component containing a crack like flaw. An evaluation of the materials toughness may be required depending on the flaw type, the severity of the environment, and the operating conditions, particularly in hydrogen service.
4.2.3.4 Affected Units or Equipment a) Temper embrittlement occurs in a variety of process units after long term exposure to temperatures above o o 650 F (343 C). It should be noted that there have been very few industry failures related directly to temper embrittlement. b) Equipment susceptible to temper embrittlement is most often found in hydroprocessing units, particularly reactors, hot feed/effluent exchanger components, and hot HP separators. Other units with the potential for temper embrittlement include catalytic reforming units (reactors and exchangers), FCC reactors, coker and visbreaking units. c) Welds in these alloys are often more susceptible than the base metal and should be evaluated.
4.2.3.5 Appearance or Morphology of Damage a) Temper embrittlement is a metallurgical change that is not readily apparent and can be confirmed through impact testing. Damage due to temper embrittlement may result in catastrophic brittle fracture. b) Temper embrittlement can be identified by an upward shift in the ductile-to-brittle transition temperature measured in a Charpy V-notch impact test, as compared to the non-embrittled or de-embrittled material. Another important characteristic of temper embrittlement is that there is no effect on the upper shelf energy.
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4.2.3.6 Prevention / Mitigation a) Existing Materials i) Temper embrittlement cannot be prevented if the material contains critical levels of the embrittling impurity elements and is exposed in the embrittling temperature range. ii) To minimize the possibility of brittle fracture during startup and shutdown, many refiners use a pressurization sequence to limit system pressure to about 25 percent of the maximum design pressure for temperatures below a Minimum Pressurization Temperature (MPT). iii) MPT’s generally range from 350oF (171oC) for the earliest, most highly temper embrittled steels, down to 150oF (38oC) or lower for newer, temper embrittlement resistant steels (as required to also minimize effects of hydrogen embrittlement). iv) If weld repairs are required, the effects of temper embrittlement can be temporarily reversed (deembrittled) by heating at 1150°F (620°C) for 2 hours per inch of thickness, and rapidly cooling to room temperature. It is important to note that re-embrittlement will occur over time if the material is re-exposed to the embrittling temperature range. b) New Materials i) The best way to minimize the likelihood and extent of temper embrittlement is to limit the acceptance levels of manganese, silicon, phosphorus, tin, antimony, and arsenic in the base metal and welding consumables. In addition, strength levels and PWHT procedures should be specified and carefully controlled. ii) A common way to minimize temper embrittlement is to limit the "J*" Factor for base metal and the"X" Factor for weld metal, based on material composition as follows: J* = (Si + Mn) x (P + Sn) x 104 {elements in wt%} X =(10P + 5Sb + 4Sn + As)/100 {elements in ppm} iii) Typical J* and X factors used for 2.25 Cr steel are 100 and 15, respectively. Studies have also shown that limiting the (P + Sn) to less than 0.01% is sufficient to minimize temper Embrittlement because (Si + Mn) control the rate of embrittlement. iv) Expert metallurgical advice should be solicited to determine acceptable composition, toughness and strength levels, as well as appropriate welding, fabricating and heat treating procedures for new low alloy steel heavy wall equipment and low alloy equipment operating in the creep range. 4.2.3.7 Inspection and Monitoring a) A common method of monitoring is to install blocks of original heats of the alloy steel material inside the reactor. Samples are periodically removed from these blocks for impact testing to monitor progress of temper embrittlement or until a major repair issue arises. b) Process conditions should be monitored to ensure that a proper pressurization sequence is followed to help prevent brittle fracture due to temper embrittlement. 4.2.3.8 Related Mechanisms Not applicable. 4.2.7 Brittle Fracture 4.2.7.1 Description of Damage Brittle fracture is the sudden rapid fracture under stress (residual or applied) where the material exhibits little or no evidence of ductility or plastic deformation.
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4.2.7.2 Affected Materials Carbon steels and low alloy steels are of prime concern, particularly older steels. 400 Series SS are also susceptible.
4.2.7.3 Critical Factors a) When the critical combination of three factors is reached, brittle fracture can occur: i) The materials’ fracture toughness (resistance to crack like flaws) as measured in a Charpy impact test; ii) The size, shape and stress concentration effect of a flaw; iii) The amount of residual and applied stresses on the flaw. b) Susceptibility to brittle fracture may be increased by the presence of embrittling phases. c) Steel cleanliness and grain size have a significant influence on toughness and resistance to brittle fracture. d) Thicker material sections also have a lower resistance to brittle fracture due to higher constraint which increases triaxial stresses at the crack tip. e) In most cases, brittle fracture occurs only at temperatures below the Charpy impact transition temperature (or ductile-to-brittle transition temperature), the point at which the toughness of the material drops off sharply.
4.2.7.4 Affected Units or Equipment a) Equipment manufactured to the ASME Boiler and Pressure Vessel Code, Section VIII, Division 1, prior to the December 1987 Addenda, were made with limited restrictions on notch toughness for vessels operating at cold temperatures. However, this does not mean that all vessels fabricated prior to this date will be subject to brittle fracture. Many designers specified supplemental impact tests on equipment that was intended to be in cold service. b) Equipment made to the same code after this date were subject to the requirements of UCS 66 (impact exemption curves). c) Most processes run at elevated temperature so the main concern is for brittle fracture during startup, shutdown, or hydrotest/tightness testing. Thick wall equipment on any unit should be considered. d) Brittle fracture can also occur during an autorefrigeration event in units processing light hydrocarbons such as methane, ethane/ethylene, propane/propylene, or butane. This includes alkylation units, olefin units and polymer plants (polyethylene and polypropylene). Storage bullets/spheres for light hydrocarbons may also be susceptible. e) Brittle fracture can occur during ambient temperature hydrotesting due to high stresses and low toughness at the testing temperature.
4.2.7.5 Appearance or Morphology of Damage a) Cracks will typically be straight, non-branching, and largely devoid of any associated plastic deformation (no shear lip or localized necking around the crack) b) Microscopically, the fracture surface will be composed largely of cleveage, with limited Intergranular cracking and very little microvoid coalescence.
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4.2.7.6 Prevention / Mitigation a) For new equipment, brittle fracture is best prevented by using materials specifically designed for low temperature operation including upset and autorefrigeration events. Materials with controlled chemical composition, special heat treatment and impact test verification may be required. Refer to UCS 66 in Section VIII of the ASME BPV Code. b) Brittle fracture is an “event” driven damage mechanism. For existing materials, where the right combination of stress, material toughness and flaw size govern the probability of the event, an engineering study can be performed in accordance with API RP 579, Section 3, Level 1 or 2. c) Preventative measures to minimize the potential for brittle fracture in existing equipment are limited to controlling the operating conditions (pressure, temperature), minimizing pressure at ambient temperatures during startup and shutdown, and periodic inspection at high stress locations. d) Some reduction in the likelihood of a brittle fracture may be achieved by: i) Performing a post weld heat treatment (PWHT) on the vessel if it was not originally done during manufacturing; or if the vessel has been weld repaired/modified while in service without the subsequent PWHT. ii) Perform a “warm” pre-stress hydrotest followed by a lower temperature hydrotest to extend the Minimum Safe Operating Temperature (MSOT) envelope. 4.2.7.7 Inspection and Monitoring a) Inspection is not normally used to mitigate brittle fracture. b) Susceptible vessels should be inspected for pre-existing flaws/defects. 4.2.7.8 Related Mechanisms o o Temper embrittlement (see 4.2.3), strain age embrittlement (see 4.2.4), 885 F (475 C) embrittlement (see 4.2.5), titanium hydriding (see 5.1.3.2) and sigma embrittlement (see 4.2.6). 4.2.9 Thermal Fatigue 4.2.9.1 Description of Damage Thermal fatigue is the result of cyclic stresses caused by variations in temperature. Damage is in the form of cracking that may occur anywhere in a metallic component where relative movement or differential expansion is constrained, particularly under repeated thermal cycling. 4.2.9.2 Affected Materials All materials of construction. 4.2.9.3 Critical Factors a) Key factors affecting thermal fatigue are the magnitude of the temperature swing and the frequency (number of cycles). b) Time to failure is a function of the magnitude of the stress and the number of cycles and decreases with increasing stress and increasing cycles. c) Startup and shutdown of equipment increase the susceptibility to thermal fatigue. There is no set limit on temperature swings; however, as a practical rule, cracking may be suspected if the temperature o swing exceeds about 200°F (93 C).
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d) Damage is also promoted by rapid changes in surface temperature that result in a thermal gradient through the thickness or along the length of a component. For example: cold water on a hot tube (thermal shock); rigid attachments and a smaller temperature differential; inflexibility to accommodate differential expansion. e) Notches (such as the toe of a weld) and sharp corners (such as the intersection of a nozzle with a vessel shell) and other stress concentrations may serve as initiation sites. 4.2.9.4 Affected Units or Equipment a) Examples include the mix points of hot and cold streams such as locations where condensate comes in contact with steam systems, such as de-superheating or attemporating equipment . b) Thermal fatigue cracking has been a major problem in coke drum shells. Thermal fatigue can also occur on coke drum skirts where stresses are promoted by a variation in temperature between the drum and skirt . c) In steam generating equipment, the most common locations are at rigid attachments between neighboring tubes in the superheater and reheater. Slip spacers designed to accommodate relative movement may become frozen and act as a rigid attachment when plugged with fly ash. d) Tubes in the high temperature superheater or reheater that penetrate through the cooler waterwall tubes may crack at the header connection if the tube is not sufficiently flexible. These cracks are most common at the end where the expansion of the header relative to the waterwall will be greatest. e) Steam actuated soot blowers may cause thermal fatigue damage if the first steam exiting the soot blower nozzle contains condensate. Rapid cooling of the tube by the liquid water will promote this form of damage. Similarly, water lancing or water cannon use on waterwall tubes may have the same effect. 4.2.9.5 Appearance or Morphology of Damage a) Thermal fatigue cracks usually initiate on the surface of the component. They are generally wide and often filled with oxides due to elevated temperature exposure. Cracks may occur as single or multiple cracks. b) Thermal fatigue cracks propagate transverse to the stress and they are usually dagger-shaped, transgranular, and oxide filled. However, cracking may be axial or circumferential, or both, at the same location. c) In steam generating equipment, cracks usually follow the toe of the fillet weld, as the change in section thickness creates a stress raiser. Cracks often start at the end of an attachment lug and if there is a bending moment as a result of the constraint, they will develop into circumferential cracks into the tube. d) Water in soot blowers may lead to a crazing pattern. The predominant cracks will be circumferential and the minor cracks will be axial. 4.2.9.6 Prevention / Mitigation a) Thermal fatigue is best prevented through design and operation to minimize thermal stresses and thermal cycling. Several methods of prevention apply depending on the application. i) Designs that incorporate reduction of stress concentrators, blend grinding of weld profiles, and smooth transitions should be used. ii) Controlled rates of heating and cooling during startup and shutdown of equipment can lower stresses. iii) Differential thermal expansion between adjoining components of dissimilar materials should be considered. b) Designs should incorporate sufficient flexibility to accommodate differential expansion. i) In steam generating equipment, slip spacers should slip and rigid attachments should be avoided. ii) Drain lines should be provided on soot-blowers to prevent condensate in the first portion of the soot blowing cycle. c) In some cases, a liner or sleeve may be installed to prevent a colder liquid from contacting the hotter pressure boundary wall
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4.2.9.7 Inspection and Monitoring a) Since cracking is usually surface connected, visual examination, MT and PT are effective methods of inspection. b) External SWUT inspection can be used for non-intrusive inspection for internal cracking and where reinforcing pads prevent nozzle examination. c) Heavy wall reactor internal attachment welds can be inspected using specialized ultrasonic techniques.
4.2.9.8 Related Mechanisms Corrosion fatigue (see 4.5.2) and dissimilar metal weld cracking (see 4.2.12). 4.2.14 Erosion/Erosion – Corrosion 4.2.14.1 Description of Damage a) Erosion is the accelerated mechanical removal of surface material as a result of relative movement between, or impact from solids, liquids, vapor or any combination thereof. b) Erosion-corrosion is a description for the damage that occurs when corrosion contributes to erosion by removing protective films or scales, or by exposing the metal surface to further corrosion under the combined action of erosion and corrosion. 4.2.14.2 Affected Materials All metals, alloys and refractories. 4.2.14.3 Critical Factors a) In most cases, corrosion plays some role so that pure erosion (sometimes referred to as abrasive wear) is rare. It is critical to consider the role that corrosion contributes. b) Metal loss rates depend on the velocity and concentration of impacting medium (i.e., particles, liquids, droplets, slurries, two-phase flow), the size and hardness of impacting particles, the hardness and corrosion resistance of material subject to erosion, and the angle of impact. c) Softer alloys such as copper and aluminum alloys that are easily worn from mechanical damage may be subject to severe metal loss under high velocity conditions. d) Increasing hardness of the metal substrate is not always a good indicator of improved resistance to erosion, particularly where corrosion plays a significant role. e) For each environment-material combination, there is often a threshold velocity above which impacting objects may produce metal loss. Increasing velocities above this threshold result in an increase in metal loss rates as shown in Table 4-3. This table illustrates the relative susceptibility of a variety of metals and alloys to erosion/corrosion by seawater at different velocities. f) The size, shape, density and hardness of the impacting medium affects the metal loss rate. g) Increasing the corrosivity of the environment may reduce the stability of protective surface films and increase the susceptibility to metal loss. Metal may be removed from the surface as dissolved ions, or as solid corrosion products which are mechanically swept from the metal surface. h) Factors which contribute to an increase in corrosivity of the environment, such as temperature, pH, etc., can increase susceptibility to metal loss.
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4.2.14.4 Affected Units or Equipment a) All types of equipment exposed to moving fluids and/or catalyst are subject to erosion and erosion corrosion. This includes piping systems, particularly the bends, elbows, tees and reducers; piping systems downstream of letdown valves and block valves; pumps; blowers; propellers; impellers; agitators; agitated vessels; heat exchanger tubing; measuring device orifices; turbine blades; nozzles; ducts and vapor lines; scrapers; cutters; and wear plates. b) Erosion can be caused by gas borne catalyst particles or by particles carried by a liquid such as a slurry. In refineries, this form of damage occurs as a result of catalyst movement in FCC reactor/regenerator systems in catalyst handling equipment (valves, cyclones, piping, reactors) and slurry piping; coke handling equipment in both delayed and fluidized bed cokers; and as wear on pumps compressors and other rotating equipment. c) Hydroprocessing reactor effluent piping may be subject to erosion-corrosion by ammonium bisulfide. The metal loss is dependent on the ammonium bisulfide concentration, velocity and alloy corrosion resistance. d) Crude and vacuum unit piping and vessels exposed to naphthenic acids in some crude oils may suffer severe erosion-corrosion metal loss depending on the temperature, velocity, sulfur content and TAN level. 4.2.14.5 Appearance or Morphology of Damage a) Erosion and erosion-corrosion are characterized by a localized loss in thickness in the form of pits, grooves, gullies, waves, rounded holes and valleys. These losses often exhibit a directional pattern. b) Failures can occur in a relatively short time. 4.2.14.6 Prevention / Mitigation a) Improvements in design involve changes in shape, geometry and materials selection. Some examples are: increasing the pipe diameter to decrease velocity; streamlining bends to reduce impingement; increasing the wall thickness; and using replaceable impingement baffles. b) Improved resistance to erosion is usually achieved through increasing substrate hardness using harder alloys, hardfacing or surface-hardening treatments. Erosion resistant refractories in cyclones and slide valves have been very successful. c) Erosion-corrosion is best mitigated by using more corrosion-resistant alloys and/or altering the process environment to reduce corrosivity, for example, deaeration, condensate injection or the addition of inhibitors. Resistance is generally not improved through increasing substrate hardness alone. d) Heat exchangers utilize impingement plates and occasionally tube ferrules to minimize erosion problems. e) Higher molybdenum containing alloys are used for improved resistance to naphthenic acid corrosion. 4.2.14.7 Inspection and Monitoring a) Visual examination of suspected or troublesome areas, as well as UT checks or RT can be used to detect the extent of metal loss. b) Specialized corrosion coupons and on-line corrosion monitoring electrical resistance probes have been used in some applications. c) IR scans are used to detect refractory loss on stream. 4.2.14.8 Related Mechanisms Specialized terminology has been developed for various forms of erosion and erosion-corrosion in specific environments and/or services. This terminology includes cavitation, liquid impingement erosion, fretting and other similar terms.
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4.2.16 Mechanical Fatigue 4.2.16.1 Description of Damage a) Fatigue cracking is a mechanical form of degradation that occurs when a component is exposed to cyclical stresses for an extended period, often resulting in sudden, unexpected failure. b) These stresses can arise from either mechanical loading or thermal cycling and are typically well below the yield strength of the material. 4.2.16.2 Affected Materials All engineering alloys are subject to fatigue cracking although the stress levels and number of cycles necessary to cause failure vary by material. 4.2.16.3 Critical Factors Geometry, stress level, number of cycles, and material properties (strength, hardness, microstructure) are the predominant factors in determining the fatigue resistance of a component. a) Design: Fatigue cracks usually initiate on the surface at notches or stress raisers under cyclic loading. For this reason, design of a component is the most important factor in determining a component’s resistance to fatigue cracking. Several common surface features can lead to the initiation of fatigue cracks as they can act as stress concentrations. Some of these common features are: i) Mechanical notches (sharp corners or groves); ii) Key holes on drive shafts of rotating equipment; iii) Weld joint, flaws and/or mismatches; iv) Quench nozzle areas; v) Tool markings; vi) Grinding marks; vii) Lips on drilled holes; viii) Thread root notches; ix) Corrosion. b) Metallurgical Issues and Microstructure i) For some materials such as titanium, carbon steel and low alloy steel, the number of cycles to fatigue fracture decreases with stress amplitude until an endurance limit reached. Below this stress endurance limit, fatigue cracking will not occur, regardless of the number of cycles. ii) For alloys with endurance limits, there is a correlation between Ultimate Tensile Strength (UTS) and the minimum stress amplitude necessary to initiate fatigue cracking. The ratio of endurance limit over UTS is typically between 0.4 and 0.5. Materials like austenitic stainless steels and aluminum that do not have an endurance limit will have a fatigue limit defined by the number of cycles at a given stress amptitude. iii) Inclusions found in metal can have an accelerating effect on fatigue cracking. This is of importance when dealing with older, “dirty” steels or weldments, as these often have inclusions and discontinuities that can degrade fatigue resistance. iv) Heat treatment can have a significant effect on the toughness and hence fatigue resistance of a metal. In general, finer grained microstructures tend to perform better than coarse grained. Heat treatments such as quenching and tempering, can improve fatigue resistance of carbon and low alloy steels. c) Carbon Steel and Titanium: These materials exhibit an endurance limit below which fatigue cracking will not occur, regardless of the number of cycles. d) 300 Series SS, 400 Series SS, aluminum, and most other non-ferrous alloys: i) These alloys have a fatigue characteristic that does not exhibit an endurance limit. This means that fatigue fracture can be achieved under cyclical loading eventually, regardless of stress amplitude. ii) Maximum cyclical stress amplitude is determined by relating the stress necessary to cause fracture to the desired number of cycles necessary in a component’s lifetime. This is typically 106 to 107 cycles.
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4.2.16.4 Affected Units or Equipment a) Thermal Cycling i) Equipment that cycles daily in operation such as coke drums. ii) Equipment that may be auxiliary or on continuous standby but sees intermittent service such as auxiliary boiler. iii) Quench nozzle connections that see significant temperature deltas during operations such as water washing systems. b) Mechanical Loading i) Rotating shafts on centrifugal pumps and compressors that have stress concentrations due to changes in radii and key ways. ii) Components such as small diameter piping that may see vibration from adjacent equipment and/or wind. For small components, resonance can also produce a cyclical load and should be taken into consideration during design and reviewed for potential problems after installation. iii) High pressure drop control valves or steam reducing stations can cause serious vibration problems in connected piping. 4.2.16.5 Appearance or Morphology of Damage a) The signature mark of a fatigue failure is a “clam shell” type fingerprint that has concentric rings called “beach marks” emanating from the crack initiation site (Figure 4-29 and Figure 4-30). This signature pattern results from the “waves” of crack propagation that occur during every cycle above the threshold loading. These concentric cracks continue to propagate until the cross-sectional area is reduced to the point where failure due to overload occurs. b) Cracks nucleating from a surface stress concentration or defect will typically result in a single “clam shell” fingerprint c) Cracks resulting from cyclical overstress of a component without significant stress concentration will typically result in a fatigue failure with multiple points of nucleation and hence multiple “clam shell” fingerprints. These multiple nucleation sites are the result of microscopic yielding that occurs when the component is momentarily cycled above its yield strength. 4.2.16.6 Prevention / Mitigation a) The best defense against fatigue cracking is good design that helps minimize stress concentration of components that are in cyclic service. b) Select a metal with a design fatigue life sufficient for its intended cyclic service. c) Allow for a generous radius along edges and corners. d) Minimize grinding marks, nicks and gouges on the surface of components. e) Insure good fit up and smooth transitions for welds. Minimize weld defects as these can accelerate fatigue cracking. f) Remove any burrs or lips caused by machining. g) Use low stress stamps and marking tools. 4.2.16.7 Inspection and Monitoring a) NDE techniques such as PT, MT and SWUT can be used to detect fatigue cracks at known areas of stress concentration. b) VT of small diameter piping to detect oscillation or other cyclical movement that could lead to cracking. c) Vibration monitoring of rotating equipment to help detect shafts that may be out of balance. d) In high cycle fatigue, crack initiation can be a majority of the fatigue life making detection difficult.
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4.2.16.8 Related Mechanisms Vibration induced fatigue (see 4.2.17). 4.3.2 Atmospheric Corrosion
4.3.2.1 Description of Damage A form of corrosion that occurs from moisture associated with atmospheric conditions. Marine environments and moist polluted industrial environments with airborne contaminants are most severe. Dry rural environments cause very little corrosion.
4.3.2.2 Affected Materials Carbon steel, low alloy steels and copper alloyed aluminum.
4.3.2.3 Critical Factors a) Critical factors include the physical location (industrial, marine, rural); moisture (humidity), particularly designs that trap moisture or when present in a cooling tower mist; temperature; presence of salts, sulfur compounds and dirt. b) Marine environments can be very corrosive (20 mpy) as are industrial environments that contain acids or sulfur compounds that can form acids (5-10 mpy). c) Inland locations exposed to a moderate amount of precipitation or humidity are considered moderately corrosive environments (~1-3 mpy). d) Dry rural environments usually have very low corrosion rates (<1 mpy). e) Designs that trap water or moisture in crevices are more prone to attack. o o o o f) Corrosion rates increase with temperature up to about 250 F (121 C). Above 250 F (121 C), surfaces are usually too dry for corrosion to occur except under insulation (see 4.3.3). g) Chlorides, H2S, fly ash and other airborne contaminates from cooling tower drift, furnace stacks and other equipment accelerate corrosion. h) Bird turds can also cause accelerated corrosion and unsightly stains.( For those unfamiliar the word ‘turds’ means excrement from birds suach as guano etc)
4.3.2.4 Affected Units or Equipment a) Piping and equipment with operating temperatures sufficiently low to allow moisture to be present. b) A paint or coating system in poor condition. c) Equipment may be susceptible if cycled between ambient and higher or lower operating temperatures. d) Equipment shut down or idled for prolonged periods unless properly mothballed. e) Tanks and piping are particularly susceptible. Piping that rests on pipe supports is very prone to attack due to water entrapment between the pipe and the support. f) Orientation to the prevailing wind and rain can also be a factor. g) Piers and docks are very prone to attack. h) Bimetallic connections such as copper to aluminum electrical connections
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4.3.2.5 Appearance a) The attack will be general or localized, depending upon whether or not the moisture is trapped. b) If there is no coating or if there is a coating failure, corrosion or loss in thickness can be general. c) Localized coating failures will tend to promote corrosion. d) Metal loss may not be visually evident, although normally a distinctive iron oxide (red rust) scale forms. 4.3.2.6 Prevention / Mitigation Surface preparation and proper coating application are critical for long-term protection in corrosive environments. 4.3.2.7 Inspection and Monitoring VT and UT are techniques that can be used.
4.3.2.8 Related Mechanisms Corrosion under insulation (see 4.3.3).
4.3.3 Corrosion Under Insulation (CUI) 4.3.3.1 Description of Damage Corrosion of piping, pressure vessels and structural components resulting from water trapped under insulation or fireproofing.
4.3.3.2 Affected Materials Carbon steel, low alloy steels, 300 Series SS and duplex stainless steels. 4.3.3.3 Critical Factors a) Design of insulation system, insulation type, temperature, environment (humidity, rainfall and chlorides from marine environment, industrial environments containing high SO2) are critical factors. b) Poor design and/or installations that allow water to become trapped will increase CUI. c) Corrosion rates increase with increasing metal temperature up to the point where the water evaporates quickly. 0 0 0 d) Corrosion becomes more severe at metal temperatures between the boiling point 212 F (100 C) and 250 F 0 (121 C), where water is less likely to vaporize and insulation stays wet longer.
e) In marine environments or areas where significant amounts of moisture may be present, the upper temperature range where CUI may occur can be extended significantly above 250oF (121oC). f) Insulating materials that hold moisture (wick) can be more of a problem.
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g) Cyclic thermal operation or intermittent service can increase corrosion. h) Equipment that operates below the water dew point tends to condense water on the metal surface thus providing a wet environment and increasing the risk of corrosion. i) Damage is aggravated by contaminants that may be leached out of the insulation, such as chlorides. j) Plants located in areas with high annual rainfall or warmer, marine locations are more prone to CUI than plants located in cooler, drier, mid-continent locations. k) Environments that provide airborne contaminants such as chlorides (marine environments, cooling tower drift) or SO2 (stack emissions) can accelerate corrosion. 4.3.3.4 Affected Units or Equipment a) Carbon and low alloy steels are subject to pitting and loss in thickness. b) 300 Series SS, 400 Series SS and duplex SS are subject to pitting and localized corrosion. c) 300 Series SS are also subject to Stress Corrosion Cracking (SCC) if chlorides are present, while the duplex SS are less susceptible. 4.3.3.5 Affected Units or Equipment a) Location Issues Common areas of concern in process units are higher moisture areas such as those areas down-wind from cooling towers, near steam vents, deluge systems, acid vapors, or near supplemental cooling with water spray. b) Design Issues i) CUI can be found on equipment with damaged insulation, vapor barriers, weatherproofing or mastic, or protrusions through the insulation or at insulation termination points such as flanges. ii) Equipment designed with insulation support rings welded directly to the vessel wall (no standoff); particularly around ladder and platform clips, and lifting lugs, nozzles and stiffener rings. iii) Piping or equipment with damaged/leaking steam tracing. iv) Localized damage at paint and/or coating systems. v) Locations where moisture/water will naturally collect (gravity drainage) before evaporating (insulation support rings on vertical equipment) and improperly terminated fireproofing. vi) The first few feet of a horizontal pipe run adjacent to the bottom of a vertical run is a typical a CUI location. 4.3.3.6 Appearance or Morphology of Damage a) After insulation is removed from carbon and low alloy steels, CUI damage often appears as loose, flaky scale covering the corroded component. Damage may be highly localized . b) In some localized cases, the corrosion can appear to be carbuncle type pitting (usually found under a failed paint/coating system). c) For 300 Series SS, specifically in older calcium silicate insulation (known to contain chlorides), localized pitting and chloride stress corrosion cracking can occur. d) Tell tale signs of insulation and paint/coating damage often accompany CUI.
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4.3.3.7 Prevention / Mitigation a) Since the majority of construction materials used in plants are susceptible to CUI degradation, mitigation is best achieved by using appropriate paints/coatings and maintaining the insulation/sealing/vapor barriers to prevent moisture ingress. b) High quality coatings, properly applied, can provide long term protection. c) Careful selection of insulating materials is important. Closed-cell foam glass materials will hold less water against the vessel/pipe wall than mineral wool and potentially be less corrosive. d) Low chloride insulation should be used on 300 Series SS to minimize the potential for pitting and chloride SCC. e) It is not usually possible to modify operating conditions. However, consideration should be given to removing the insulation on equipment where heat conservation is not as important. f) An inspection plan for corrosion under insulation should be a structured and systematic approach starting with prediction/analysis, then looking at the more invasive procedures. The inspection plan should consider operating temperature; type and age/condition of coating; and type and age/condition of insulation material. Additional prioritization can be added from a physical inspection of the equipment, looking for evidence of insulation, mastic and/or sealant damage, signs of water penetration and rust in gravity drain areas around the equipment. g) Utilize multiple inspection techniques to produce the most cost effective approach, including: i) Partial and/or full stripping of insulation for visual examination. ii) UT for thickness verification. iii) Real-time profile x-ray (for small bore piping). iv) Neutron backscatter techniques for identifying wet insulation. v) Deep penetrating eddy-current inspection (can be automated with a robotic crawler). vi) IR thermography looking for wet insulation and/or damaged and missing insulation under the jacket. vii) Guided Wave UT. 4.3.3.8 Related Mechanisms Atmospheric corrosion (see 4.3.2), oxidation (see 4.4.1) and chloride SCC (see 4.5.1). 4.3.4 Cooling Water Corrosion 4.3.4.1 Description of Damage General or localized corrosion of carbon steels and other metals caused by dissolved salts, gases, organic compounds or microbiological activity. 4.3.4.2 Affected Materials Carbon steel, all grades of stainless steel, copper, aluminum, titanium and nickel base alloys. 4.3.4.3 Critical Factors a) Cooling water corrosion and fouling are closely related and should be considered together. Fluid temperature, type of water (fresh, brackish, salt water) and the type of cooling system (once-through, open circulating, closed circulating), oxygen content, and fluid velocities are critical factors. b) Increasing cooling water outlet temperatures and or process side inlet temperatures tend to increase corrosion rates as well as fouling tendency. c) Increasing oxygen content tends to increase carbon steel corrosion rates.
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d) If the process side temperature is above 140oF (60oC), a scaling potential exists with fresh water and becomes more likely as process temperatures increase and as cooling water inlet temperatures rise. Brackish and salt water outlet temperatures above about 115 oF (46oC) may cause serious scaling. e) Fouling may occur from mineral deposits (hardness), silt, suspended organic materials, corrosion products, mill scale, marine and microbiological growth. f) Velocities should be high enough to minimize fouling and drop out of deposits but not so high as to cause erosion. Velocity limits depend on the tube material and water quality. g) Low velocities can promote increased corrosion. Velocities below about 3 fps (1 m/s) are likely to result in fouling, sedimentation and increased corrosion in fresh and brackish water systems. Accelerated corrosion can also result from dead spots or stagnant areas if cooling water is used on the shell side of condensers/coolers rather than the preferred tube side. h) 300 Series SS can suffer pitting corrosion, crevice corrosion and SCC in fresh, brackish and salt water systems. i) Copper/zinc alloys can suffer dezincification in fresh, brackish and salt water systems. The copper/zinc alloys can suffer SCC if any ammonia or ammonium compounds are present in the water or on the process side. j) ERW carbon steel may suffer severe weld and/or heated affected zone corrosion in fresh and/or brackish water. k) When connected to a more anodic material, titanium may suffer severe hydriding embrittlement. Generally, o o the problem occurs at temperatures above 180 F (82 C) but can occur at lower temperatures. 4.3.4.4 Affected Units or Equipment Cooling water corrosion is a concern with water-cooled heat exchangers and cooling towers in all applications across all industries. 4.3.4.5 Appearance or Morphology of Damage a) Cooling water corrosion can result in many different forms of damage including general corrosion, pitting corrosion, MIC, stress corrosion cracking and fouling. b) General or uniform corrosion of carbon steel occurs when dissolved oxygen is present. c) Localized corrosion may result from underdeposit corrosion, crevice corrosion or microbiological corrosion d) Deposits or crevices can lead to underdeposit or crevice corrosion of any of the affected materials. e) Wavy or smooth corrosion at nozzle inlets/outlets and tube inlets may be due to flow induced corrosion, erosion or abrasion. f) Corrosion at ERW weld areas will appear as grooving along the weld fusion lines. g) Metallurgical analysis of tube samples may be required to confirm the mode of failure. 4.3.4.6 Prevention / Mitigation a) Cooling water corrosion (and fouling) can be prevented by proper design, operation and chemical treatment of cooling water systems. o o b) Design for process side inlet temperatures below 135 F (57 C). c) Minimum and maximum water velocities must be maintained, particularly in salt water systems. d) The metallurgy of heat exchanger components may need to be upgraded for improved resistance, especially in waters with high chloride content, low velocity, high process temperatures, and/or poorly maintained water chemistry. e) Periodic mechanical cleaning of tube ID’s and OD’s should be performed in order to maintain clean heat transfer surfaces. f) With very few exceptions, cooling water should be on the tube side to minimize stagnant areas.
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4.3.4.7 Inspection and Monitoring a) Cooling water should be monitored for variables that affect corrosion and fouling including, pH, oxygen content, cycles of concentration, biocide residual, biological activity, cooling water outlet temperatures, hydrocarbon contamination and process leaks. b) Periodic calculation of U-factors (heat exchanger performance measurement) will provide information on scaling and fouling. c) Ultrasonic flow meters can be used to check the velocity of water in the tubes. d) EC or IRIS inspection of tubes. e) Splitting representative tubes. 4.3.4.8 Related Mechanisms Microbiologically induced corrosion (see 4.3.8), chloride stress corrosion cracking (see 4.5.1) and galvanic corrosion (see 4.3.1). 4.3.5 Boiler Water Condensate Corrosion 4.3.5.1 Description of Damage General corrosion and pitting in the boiler system and condensate return piping. 4.3.5.2 Affected Materials Primarily carbon steel, some low alloy steel, some 300 Series SS and copper based alloys. 4.3.5.3 Critical Factors a) Corrosion in boiler feedwater and condensate return systems is usually the result of dissolved gases, oxygen and carbon dioxide. b) Critical factors are the concentration of dissolved gas (oxygen and carbon dioxide), pH, temperature, quality of the feedwater and the specific feedwater treating system. c) Corrosion protection in the boiler is accomplished by laying down and continuously maintaining a layer of protective Fe3O4 (magnetite). d) The chemical treatment for scale and deposit control must be adjusted to coordinate with the oxygen scavenger for the specific water service and boiler feedwater treating system. e) Ammonia SCC of Cu-Zn alloys can occur due to hydrazine, neutralizing amines or ammoniacal compounds. 4.3.5.4 Affected Units or Equipment Corrosion can occur in the external treatment system, deaerating equipment, feedwater lines, pumps, stage heaters and economizers as well as the steam generation system on both the water and fire sides and the condensate return system.
4.3.5.5 Appearance or Morphology of Damage a) Corrosion from oxygen tends to be a pitting type damage and can show up anywhere in the system even if only very small quantities break through the scavenging treatment. Oxygen is particularly aggressive in equipment such as closed heaters and economizers where there is a rapid water temperature rise.
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b) Corrosion in the condensate return system tends to be due to carbon dioxide although some oxygen pitting problems can occur if the oxygen scavenging treatment is not working correctly. Carbon dioxide corrosion tends to be a smooth grooving of the pipe wall. 4.3.5.6 Prevention/Mitigation a) Oxygen scavenging treatments typically include catalyzed sodium sulfite or hydrazine depending on the system pressure level along with proper mechanical deareator operation. A residual of the oxygen scavenger is carried into the steam generation system to handle any oxygen ingress past the deaerator. b) If the scale/deposit control/magnetite maintenance treatment scheme does not minimize carbon dioxide in the condensate return system, an amine inhibitor treatment might be required. 4.3.5.7 Inspection and Monitoring a) Water analysis is the common monitoring tool used to assure that the various treatment systems are performing in a satisfactory manner. Parameters which can be monitored for signs of upset include the pH, conductivity, chlorine or residual biocide, and total dissolved solids to check for leaks in the form of organic compounds. b) There are no proactive inspection methods other than developing an appropriate program when problems such as a ruptured boiler tube or condensate leaks are recognized in the various parts of complex boiler water and condensate systems. c) Deaerator cracking problems can be evaluated off-line at shutdowns by utilizing properly applied wet fluorescence magnetic particle inspection. 4.3.5.8 Related Mechanisms CO2 corrosion (see 4.3.6), corrosion fatigue (see 4.5.2), and erosion/erosion-corrosion (see 4.2.14).
4.4.2 Sulfidation 4.4.2.1 Description of Damage Corrosion of carbon steel and other alloys resulting from their reaction with sulfur compounds in high temperature environments. The presence of hydrogen accelerates corrosion. 4.4.2.2 Affected Materials a) All iron based materials including carbon steel and low alloy steels, 300 Series SS and 400 Series SS. b) Nickel base alloys are also affected to varying degrees depending on composition, especially chromium content. c) Copper base alloys form sulfide at lower temperatures than carbon steel. 4.4.2.3 Critical Factors a) Major factors affecting sulfidation are alloy composition, temperature and concentration of corrosive sulfur compounds. b) Susceptibility of an alloy to sulfidation is determined by its ability to form protective sulfide scales. o o c) Sulfidation of iron-based alloys usually begins at metal temperatures above 500 F (260 C).
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d) In general, the resistance of iron and nickel base alloys is determined by the chromium content of the material. Increasing the chromium content significantly increases resistance to sulfidation. 300 Series SS, such as Types 304, 316, 321 and 347, are highly resistant in most refining process environments. Nickel base alloys are similar to stainless steels in that similar levels of chromium provide similar resistance to sulfidation. e) Crude oils, coal and other hydrocarbon streams contain sulfur at various concentrations. Total sulfur content is made up of many different sulfur-containing compounds. f) Sulfidation is primarily caused by H2S and other reactive sulfur species as a result of the thermal decomposition of sulfur compounds at high temperatures. Some sulfur compounds react more readily to form H2S. Therefore, it can be misleading to predict corrosion rates based on weight percent sulfur alone. g) A sulfide scale on the surface of the component offers varying degrees of protection depending on the alloy and the severity of the process stream. 4.4.2.4 Affected Units or Equipment a) Sulfidation occurs in piping and equipment in high temperature environments where sulfur-containing streams are processed. b) Common areas of concern are the crude, FCC, coker, vacuum, visbreaker and hydroprocessing units. c) Heaters fired with oil, gas, coke and most other sources of fuel may be affected depending on sulfur levels in the fuel. d) Boilers and high temperature equipment exposed to sulfur-containing gases can be affected.
4.4.2.5 Appearance or Morphology of Damage a) Depending on service conditions, corrosion is most often in the form of uniform thinning but can also occur as localized corrosion or high velocity erosion-corrosion damage. b) A sulfide scale will usually cover the surface of components. Deposits may be thick or thin depending on the alloy, corrosiveness of the stream, fluid velocities and presence of contaminants.
4.4.2.6 Prevention / Mitigation a) Resistance to sulfidation is generally achieved by upgrading to a higher chromium alloy. b) Piping and equipment constructed from solid or clad 300 Series SS or 400 Series SS can provide significant resistance to corrosion. c) Aluminum diffusion treatment of low alloy steel components is sometimes used to reduce sulfidation rates and minimize scale formation, however, it may not offer complete protection. 300 Series SS catalyst support screens in hydroprocessing reactors can also be treated to prolong life.
4.4.2.7 Inspection and Monitoring a) Process conditions should be monitored for increasing temperatures and/or changing sulfur levels. b) Temperatures can be monitored through the use of tubeskin thermocouples and/or infrared thermography. c) Evidence of thinning can be detected using external ultrasonic thickness measurements and profile radiography. d) Proactive and retroactive PMI programs are used for alloy verification and to check for alloy mix-ups in services where sulfidation is anticipated.
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4.4.2.8 Related Mechanisms Sulfidation is also known as sulfidic corrosion. High temperature sulfidation in the presence of hydrogen is covered in 5.1.1.5.
4.5.1 Chloride Stress Corrosion Cracking (Cl-SCC) 4.5.1.1 Description of Damage Surface initiated cracks caused by environmental cracking of 300 Series SS and some nickel base alloys under the combined action of tensile stress, temperature and an aqueous chloride environment. The presence of dissolved oxygen increases propensity for cracking. 4.5.1.2 Affected Materials a) All 300 Series SS are highly susceptible. b) Duplex stainless steels are more resistant. c) Nickel base alloys are highly resistant. 4.5.1.3 Critical Factors a) Chloride content, pH, temperature, stress, presence of oxygen and alloy composition are critical factors. b) Increasing temperatures increase the susceptibility to cracking. c) Increasing levels of chloride increase the likelihood of cracking. d) No practical lower limit for chlorides exists because there is always a potential for chlorides to concentrate. e) Heat transfer conditions significantly increase cracking susceptibility because they allow chlorides to concentrate. Alternate exposures to wet-dry conditions or steam and water are also conducive to cracking. f) SCC usually occurs at pH values above 2. At lower pH values, uniform corrosion generally predominates. SCC tendency decreases toward the alkaline pH region. g) Cracking usually occurs at metal temperatures above about 140oF (60oC), although exceptions can be found at lower temperatures. h) Stress may be applied or residual. Highly stressed or cold worked components, such as expansion bellows, are highly susceptible to cracking. i) Oxygen dissolved in the water normally accelerates SCC but it is not clear whether there is an oxygen concentration threshold below which chloride SCC is impossible. j) Nickel content of the alloy has a major affect on resistance. The greatest susceptibility is at a nickel content of 8% to 12%. Alloys with nickel contents above 35% are highly resistant and alloys above 45% are nearly immune. k) Low-nickel stainless steels, such as the duplex (ferrite-austenite) stainless steels, have improved resistance over the 300 Series SS but are not immune. l) Carbon steels, low alloy steels and 400 Series SS are not susceptible to Cl-SCC. 4.5.1.4 Affected Units or Equipment a) All 300 Series SS piping and pressure vessel components in any process units are susceptible to Cl-SCC. b) Cracking has occurred in water-cooled condensers and in the process side of crude tower overhead condensers. c) Drains in hydroprocessing units are susceptible to cracking during startup/shutdown if not properly purged. d) Bellows and instrument tubing, particularly those associated with hydrogen recycle streams contaminated with chlorides, can be affected.
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e) External Cl–SCC has also been a problem on insulated surfaces when insulation gets wet. f) Cracking has occurred in boiler drain lines. 4.5.1.5 Appearance or Morphology of Damage a) Surface breaking cracks can occur from the process side or externally under insulation. b) The material usually shows no visible signs of corrosion. c) Characteristic stress corrosion cracks have many branches and may be visually detectable by a crazecracked appearance of the surface. d) Metallography of cracked samples typically shows branched transgranular cracks . Sometimes intergranular cracking of sensitized 300 Series SS may also be seen. e) Welds in 300 Series SS usually contain some ferrite, producing a duplex structure that is usually more resistant to Cl–SCC. f) Fracture surfaces often have a brittle appearance. 4.5.1.6 Prevention / Mitigation a) Use resistant materials of construction. b) When hydrotesting, use low chloride content water and dry out thoroughly and quickly. c) Properly applied coatings under insulation. d) Avoid designs that allow stagnant regions where chlorides can concentrate or deposit. e) A high temperature stress relief of 300 Series SS after fabrication may reduce residual stresses. However, consideration should be given to the possible effects of sensitization that may occur, increasing susceptibility to polythionic SCC, possible distortion problems and potential reheat cracking. 4.5.1.7 Inspection and Monitoring a) Cracking is surface connected and may be detected visually in some cases. b) PT or phase analysis EC techniques are the preferred methods. c) Eddy current inspection methods have also been used on condenser tubes as well as piping and pressure vessels. d) Extremely fine cracks may be difficult to find with PT. Special surface preparation methods, including polishing or high-pressure water blast, may be required in some cases, especially in high pressure services. e) UT. f) Often, RT is not sufficiently sensitive to detect cracks except in advanced stages where a significant network of cracks has developed. 4.5.1.8 Related Mechanisms Caustic SCC (see 4.5.3) and polythionic acid SCC. 4.5.2 Corrosion Fatigue 4.5.2.1 Description of Damage A form of fatigue cracking in which cracks develop under the combined affects of cyclic loading and corrosion. Cracking often initiates at a stress concentration such as a pit in the surface. Cracking can initiate at multiple sites.
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4.5.2.2 Affected Materials All metals and alloys. 4.5.2.3 Critical Factors a) The critical factors are the material, corrosive environment, cyclic stresses and stress raisers. b) Cracking is more likely to occur in environments that promote pitting or localized corrosion under cyclic stress due to thermal stress, vibration or differential expansion. c) Contrary to a pure mechanical fatigue, there is no fatigue limit load in corrosion-assisted fatigue. Corrosion promotes failure at a lower stress and number of cycles than the materials’ normal endurance limit in the absence of corrosion and often results in propagation of multiple parallel cracks. d) Crack initiation sites include concentrators such as pits, notches, surface defects, changes in section or fillet welds. 4.5.2.4 Affected Units or Equipment Rotating equipment, deaerators and cycling boilers, as well as any equipment subjected to cyclic stresses in a corrosive environment. Some examples include: a) Rotating Equipment Galvanic couples between the impeller and the pump shaft or other corrosion mechanisms may result in a pitting problem on the shaft. The pitting can act as a stress concentrator or stress riser to promote cracking. Most cracking is transgranular with little branching. b) Deaerators In the late 1980’s, deaerators in the pulp and paper, refining and petrochemical and fossil fueled utility industries had major deaerator cracking problems. Complete vessel failures in the pulp and paper industry resulted in a diligent inspection program that found major cracking problems across the various industries. It was concluded that residual welding and fabrication stresses, stress risers (attachments and weld reinforcement) and the normal deaerator environment could produce multiple corrosion fatigue cracking problems. c) Cycling Boilers A cycling boiler may see several hundred cold starts over its useful life which, because of differential expansion, continually cracks the protective magnetite scale, allowing corrosion to continue. 4.5.2.5 Appearance or Morphology of Damage a) The fatigue fracture is brittle and the cracks are most often transgranular, as in stress-corrosion cracking, but not branched, and often results in propagation of multiple parallel cracks. b) Fatigue cracking will be evidenced by very little plastic deformation except that final fracture may occur by mechanical overload accompanied by plastic deformation. c) In cycling boilers, the damage usually appears first on the water side of buckstay attachments. The cracking pattern may be circular cracks surrounding the weld between the buckstay attachment and the waterwall tube. In cross-section, the cracks tend to be bulbous with numerous lobes. The crack tips themselves may be somewhat blunted but are oxide filled and transgranular. d) In sulfidizing environments, cracks will have a similar appearance but will be filled with a sulfide scale. e) In rotating equipment, most cracking is transgranular with minimal branching.
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4.5.2.6 Prevention / Mitigation a) Rotating Equipment i) Modify the corrosive environment by using coatings and/or inhibitors. ii) Minimize galvanic couple effects. iii) Use more corrosion resistant materials. b) Deaerators i) Proper feedwater and condensate chemical control. ii) Minimize residual welding and fabrication stresses through PWHT. iii) Minimize weld reinforcement by grinding weld contours smooth. c) Cycling Boilers i) Start up slowly to minimize the differential expansion strains. ii) Always start up with the chemistry of the boiler water under proper control.
4.5.2.7 Inspection and Monitoring a) Rotating Equipment i) UT and MT techniques can be used for crack detection. b) Deaerators i) Cracking is generally detected with WFMT inspection. ii) Many of the cracks are very tight and difficult to detect. c) Cycling Boilers i) The first sign of damage is usually a pinhole leak on the cold side of a waterwall tube at a buckstay attachment. ii) Inspect highly stressed regions in the boiler by UT or EMATS techniques. iii) Cracking may occur at the membranes in the highly stressed regions, particularly corners at buckstays.
4.5.2.8 Related Mechanisms Mechanical fatigue and vibration induced fatigue.
4.5.3 Caustic Stress Corrosion Cracking (Caustic Embrittlement)
4.5.3.1 Description of Damage Caustic embrittlement is a form of stress corrosion cracking characterized by surface-initiated cracks that occur in piping and equipment exposed to caustic, primarily adjacent to non-PWHT’d welds. 4.5.3.2 Affected Materials Carbon steel, low alloy steels and 300 Series SS are susceptible. Nickel base alloys are more resistant.
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4.5.3.3 Critical Factors a) Susceptibility to caustic embrittlement in caustic soda (NaOH) and caustic potash (KOH) solutions is a function of caustic strength, metal temperature and stress levels. b) Increasing caustic concentration and increasing temperatures increase the likelihood and severity of cracking. Conditions likely to result in cracking have been established through plant experience and are presented in Figure 4-85. c) Cracking can occur at low caustic levels if a concentrating mechanism is present. In such cases, caustic concentrations of 50 to 100 ppm are sufficient to cause cracking. d) Stresses that promote cracking can be residual that result from welding or from cold working (such as bending and forming) as well as applied stresses (Figure 4-86 and Figure 4-87). e) It is generally accepted that stresses approaching yield are required for SCC so that thermal stress relief (PWHT) is effective in preventing caustic SCC. Although failures have occurred at stresses that are low relative to yield, they are considered more rare (Figure 4-88 through Figure 4-91). f) Crack propagation rates increase dramatically with temperature and can sometimes grow through wall in a matter of hours or days during temperature excursions, especially if conditions promote caustic concentration. Concentration can occur as a result of alternating wet and dry conditions, localized hot spots or high temperature steamout. g) Special care must be taken with steam tracing design and steamout of non-PWHT’d carbon steel piping and equipment.
4.5.3.4 Affected Units or Equipment a) Caustic embrittlement is often found in piping and equipment that handles caustic, including H2S and mercaptan removal units, as well as equipment that uses caustic for neutralization in sulfuric acid alkylation units and HF alkylation units. Caustic is sometimes injected into the feed to the crude tower for chloride control. b) Failures have occurred in improperly heat-traced piping or equipment as well as heating coils and other heat transfer equipment. c) Caustic embrittlement may occur in equipment as a result of steam cleaning after being in caustic service. d) Traces of caustic can become concentrated in BFW and can result in caustic embrittlement of boiler tubes that alternate between wet and dry conditions due to overfiring.
4.5.3.5 Appearance or Morphology of Damage a) Caustic stress corrosion cracking typically propagates parallel to the weld in adjacent base metal but can also occur in the weld deposit or heat-affected zones. b) The pattern of cracking observed on the steel surface is sometimes described as a spider web of small cracks which often initiate at or interconnect with weld-related flaws that serve as local stress raisers. c) Cracks can be confirmed through metallographic examination as surface breaking flaws that are predominantly intergranular. The cracking typically occurs in as-welded carbon steel fabrications as a network of very fine, oxide-filled cracks. d) Cracking in 300 Series SS is typically transgranular and is very difficult to distinguish from chloride stress corrosion cracking (Figure 4-92).
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4.5.3.6 Prevention / Mitigation a) Cracking can be effectively prevented by means of a stress-relieving heat treatment (e.g. PWHT). A heat treatment at 1150°F (621°C) is considered an effective stress relieving heat treatment for carbon steel. The same requirement applies to repair welds and to internal and external attachment welds. b) 300 Series SS offer little advantage in resistance to cracking over CS. c) Nickel base alloys are more resistant to cracking and may be required at higher temperatures and/or caustic concentrations. d) Steamout of non-PWHT’d carbon steel piping and equipment should be avoided. Equipment should be water washed before steamout. Where steamout is required, only low-pressure steam should be used for short periods of time to minimize exposure. e) Proper design and operation of the injection system is required to ensure that caustic is properly dispersed before entering the high-temperature crude preheat system. 4.5.3.7 Inspection and Monitoring a) Although cracks may be seen visually, crack detection is best performed with WFMT, EC, RT or ACFM techniques. Surface preparation by grit blasting, high pressure water blasting or other methods is usually required. b) PT is not effective for finding tight, scale-filled cracks and should not be used for detection. c) Crack depths can be measured with a suitable UT technique including external SWUT. d) AET can be used for monitoring crack growth and locating growing cracks. 4.5.3.8 Related Mechanisms Amine cracking (see 5.1.2.2) and carbonate cracking (see 5.1.2.5) are two other similar forms of alkaline SCC. 5.1.2.3 Wet H2S Damage (Blistering/HIC/SOHIC/SSC) 5.1.2.3.1 Description of Damage This section describes four types of damage that result in blistering and/or cracking of carbon steel and low alloy steels in wet H2S environments. a) Hydrogen Blistering Hydrogen blisters may form as surface bulges on the ID, the OD or within the wall thickness of a pipe or pressure vessel. The blister results from hydrogen atoms that form during the sulfide corrosion process on the surface of the steel, that diffuse into the steel, and collect at a discontinuity in the steel such as an inclusion or lamination. The hydrogen atoms combine to form hydrogen molecules that are too large to diffuse out and the pressure builds to the point where local deformation occurs, forming a blister. Blistering results from hydrogen generated by corrosion, not hydrogen gas from the process stream. b) Hydrogen Induced Cracking (HIC) Hydrogen blisters can form at many different depths from the surface of the steel, in the middle of the plate or near a weld. In some cases, neighboring or adjacent blisters that are at slightly different depths (planes) may develop cracks that link them together. Interconnecting cracks between the blisters often have a stair step appearance, and so HIC is sometimes referred to as “stepwise cracking” c) Stress Oriented Hydrogen Induced Cracking (SOHIC) SOHIC is similar to HIC but is a potentially more damaging form of cracking which appears as arrays of cracks stacked on top of each other. The result is a through-thickness crack that is perpendicular to the surface and is driven by high levels of stress (residual or applied). They usually appear in the base metal adjacent to the weld heat affected zones where they initiate from HIC damage or other cracks or
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defects including sulfide stress cracks. d) Sulfide Stress Corrosion Cracking (SSC) Sulfide Stress Cracking (SSC) is defined as cracking of metal under the combined action of tensile stress and corrosion in the presence of water and H2S. SSC is a form of hydrogen stress cracking resulting from absorption of atomic hydrogen that is produced by the sulfide corrosion process on the metal surface. SSC can initiate on the surface of steels in highly localized zones of high hardness in the weld metal and heat affected zones. Zones of high hardness can sometimes be found in weld cover passes and attachment welds which are not tempered (softened) by subsequent passes. PWHT is beneficial in reducing the hardness and residual stresses that render a steel susceptible to SSC. High strength steels are also susceptible to SSC but these are only used in limited applications in the refining industry. Some carbon steels contain residual elements that form hard areas in the heat affected zones that will not temper at normal stress relieving temperatures. Using preheat helps minimize these hardness problems. 5.1.2.3.2 Affected Materials Carbon steel and low alloy steels. 5.1.2.3.3 Critical Factors a) The most important variables that affect and differentiate the various forms of wet H2S damage are environmental conditions (pH, H2S level, contaminants, temperature), material properties (hardness, microstructure, strength) and tensile stress level (applied or residual). These factors are outlined below. b) All of these damage mechanisms are related to the absorption and permeation of hydrogen in steels. i) pH • Hydrogen permeation or diffusion rates have been found to be minimal at pH 7 and increase at both higher and lower pH’s. The presence of hydrogen cyanide (HCN) in the water phase significantly increases permeation in alkaline (high pH) sour water. • Conditions which are known to promote blistering, HIC, SOHIC and SSC are those containing free water (in liquid phase) and: • >50 wppm dissolved H2S in the free water, or • free water with pH <4 and some dissolved H2S present, or • free water with pH >7.6 and 20 wppm dissolved hydrogen cyanide (HCN) in the water and some dissolved H2S present, or • >0.0003 MPa (0.05 psia) partial pressure of H2S in the gas phase. • Increasing levels of ammonia may push the pH higher into the range where cracking can occur. ii) H2S • Hydrogen permeation increases with increasing H2S partial pressure due to a concurrent increase in the H2S concentration in the water phase. • An arbitrary value of 50 wppm H2S in the water phase is often used as the defining concentration where wet H2S damage becomes a problem. However, there are cases where cracking has occurred at lower concentrations or during upset conditions where wet H2S was not ordinarily anticipated. The presence of as little as 1 wppm of H2S in the water has been found to be sufficient to cause hydrogen charging of the steel. • Susceptibility to SSC increases with increasing H2S partial pressures above about 0.05 psi (0.0003 mpa) H2S in steels with a tensile strength above about 90 ksi or in steels with localized zones of weld or weld HAZ hardness above 237 HB. iii) Temperature • Blistering, HIC, and SOHIC damage have been found to occur between ambient and 300oF (150oC) or higher. • SSC generally occurs below about 180oF (82oC). iv) Hardness
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• Hardness is primarily an issue with SSC. Typical low-strength carbon steels used in refinery applications should be controlled to produce weld hardness <200 HB in accordance with NACE RP0472. These steels are not generally susceptible to SSC unless localized zones of hardness above 237 HB are present. • Blistering, HIC and SOHIC damage are not related to steel hardness. v) Steelmaking • Blistering and HIC damage are strongly affected by the presence of inclusions and laminations which provide sites for diffusing hydrogen to accumulate. • Steel chemistry and manufacturing methods also affect susceptibility and can be tailored to produce the HIC resistant steels outlined in NACE Publication 8X194. • Improving steel cleanliness and processing to minimize blistering and HIC damage may still leave the steel susceptible to SOHIC. • The disadvantage is that an absence of visual blistering may leave a false sense of security that H2S damage is not active yet subsurface SOHIC damage may be present. • HIC is often found in so-called “dirty” steels with high levels of inclusions or other internal discontinuities from the steel-making process. vi) PWHT • Blistering and HIC damage develop without applied or residual stress so that PWHT will not prevent them from occuring. • High local stresses or notch-like discontinuities such as shallow sulfide stress cracks can serve as initiation sites for SOHIC. PWHT is highly effective in preventing or eliminating SSC by reduction of both hardness and residual stress. • SOHIC is driven by localized stresses so that PWHT is also somewhat effective in reducing SOHIC damage. 5.1.2.3.4 Affected Units or Equipment a) Blistering, HIC, SOHIC and SSC damage can occur throughout the refinery wherever there is a wet H2S environment present. b) In hydroprocessing units, increasing concentration of ammonium bisulfide above 2% increases the potential for blistering, HIC and SOHIC. c) Cyanides significantly increase the probability and severity of blistering, HIC and SOHIC damage. This is especially true for the vapor recovery sections of the fluid catalytic cracking and delayed coking units. Typical locations include fractionator overhead drums, fractionation towers, absorber and stripper towers, compressor interstage separators and knockout drums and various heat exchangers, condensers, and coolers. Sour water stripper and amine regenerator overhead systems are especially prone to wet H2S damage because of generally high ammonia bisulfide concentrations and cyanides. d) SSC is most likely found in hard weld and heat affected zones and in high strength components including bolts, relief valve springs, 400 Series SS valve trim, compressor shafts, sleeves and springs. 5.1.2.3.5 Appearance or Morphology of Damage a) All four forms of wet H2S damage are best illustrated though the pictures and diagrams shown in 571. b) Hydrogen blisters appear as bulges on the ID or OD surface of the steel and can be found anywhere in the shell plate or head of a pressure vessel. Blistering has been found on rare occasions in pipe and very rarely in the middle of a weld. HIC damage can occur wherever blistering or subsurface laminations are present. c) In pressure-containing equipment, SOHIC and SSC damage is most often associated with the weldments. SSC can also be found at any location where zones of high hardness are found in vessels or in high strength steel components.
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5.1.2.3.6 Prevention / Mitigation a) Effective barriers that protect the surface of the steel from the wet H2S environment can prevent damage including alloy cladding and coatings. b) Process changes that affect the pH of the water phase and/or ammonia or cyanide concentration can help to reduce damage. A common practice is to utilize wash water injection to dilute the HCN concentration, for example, in FCC gas plants. Cyanides can be converted to harmless thiocyanates by injecting dilute streams of ammonium polysulfides. Injection facilities require careful design. c) HIC-resistant steels can be used to minimize the susceptibility to blistering and HIC damage. Detailed materials and fabrication guidance can be found in NACE Publication 8X194. d) SSC can generally be prevented by limiting the hardness of welds and heat affected zones to 200 HB maximum through preheat, PWHT, weld procedures and control of carbon equivalents. Depending on the service environment, small zones of hardness up to 22 HRC should be resistant to SSC. Refer to NACE RP0472 for additional details. e) PWHT can also help to minimize susceptibility to SOHIC. PWHT has limited value in preventing blistering and HIC damage from initiating but is beneficial in reducing residual stresses and strength levels that might otherwise contribute to crack propagation. f) Specialized corrosion inhibitors can be used.
5.1.2.3.7 Inspection and Monitoring a) Process conditions should be evaluated by process engineers and corrosion/materials specialists to identify piping and equipment where conditions are most likely to promote wet H2S damage. Field sampling of the free water phase should be performed on a periodic or as-needed basis to monitor conditions or changes in conditions, particularly if water washing or polysulfide injection is used. b) Inspection for wet H2S damage generally focuses on weld seams and nozzles. Since the consequences can be severe, refineries generally have a procedure to prioritize and execute inspection for this type of damage. General notes on inspection for wet H2S damage are included below. However, for the development of more detailed inspection plans including methods, coverage and surface preparation, the reader is directed to extensive recommendations on detection and repair outlined in NACE RP0296. c) Although cracks may be seen visually, crack detection is best performed with WFMT, EC, RT or ACFM techniques. Surface preparation by grit blasting, high pressure water blasting or other methods is usually required for WFMT but not for ACFM. PT cannot find tight cracks and should not be depended on. d) UT techniques including external SWUT can be used. SWUT is especially useful for volumetric inspection and crack sizing. Electrical resistance instruments are not effective for measuring crack depth. e) Grinding out the crack or removal by thermal arc gouging is a viable method of crack depth determination. f) AET can be used for monitoring crack growth.
5.1.2.3.8 Related Mechanisms a) SSC is a form of hydrogen stress cracking (hydrogen embrittlement). Refer to 4.5.7. b) Amine cracking (see 5.1.2.2) and carbonate cracking (see 5.1.2.5) can also occur in wet H2S environments, may be similar in appearance, and are sometimes confused with the various forms of wet H2S damage.
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5.1.3.1 High Temperature Hydrogen Attack (HTHA) 5.1.3.1.1 Description of Damage a) High temperature hydrogen attack results from exposure to hydrogen at elevated temperatures and pressures. The hydrogen reacts with carbides in steel to form methane (CH4) which cannot diffuse through the steel. The loss of carbide causes an overall loss in strength. b) Methane pressure builds up, forming bubbles or cavities, microfissures and fissures that may combine to form cracks. c) Failure can occur when the cracks reduce the load carrying ability of the pressure containing part. 5.1.3.1.2 Affected Materials In order of increasing resistance: carbon steel, C-0.5Mo, Mn-0.5Mo, 1Cr-0.5Mo, 1.25Cr-0.5Mo, 2.25Cr-1Mo, 2.25Cr-1Mo-V, 3Cr-1Mo, 5Cr-0.5Mo and similar steels with variations in chemistry. 5.1.3.1.3 Critical Factors a) For a specific material, HTHA is dependent on temperature, hydrogen partial pressure, time and stress. Service exposure time is cumulative. b) HTHA is preceded by a period of time when no noticeable change in properties is detectable by normal inspection techniques. c) The incubation period is the time period during which enough damage has occurred to be measured with available inspection techniques and may vary from hours at very severe conditions to many years. d) Figure 5-35 of 571 contains curves that show a temperature/hydrogen partial pressure safe operating envelope for carbon and low alloy steels. Additional information on HTHA can be found in API RP 941. e) The curves are reasonably conservative for carbon steel up to about 10,000 psi hydrogen partial pressure. f) 300 Series SS, as well as 5Cr, 9Cr and 12 Cr alloys, are not susceptible to HTHA at conditions normally seen in refinery units. 5.1.3.1.4 Affected Units a) Hydroprocessing units, such as hydrotreaters (desulfurizers) and hydrocrackers, catalytic reformers, hydrogen producing units and hydrogen cleanup units, such as pressure swing absorption units, are all susceptible to HTHA. b) Boiler tubes in very high pressure steam service.
5.1.3.1.5 Appearance or Morphology of Damage a) HTHA can be confirmed through the use of specialized techniques including metallographic analysis of damaged areas as described.. b) The hydrogen/carbon reaction can cause surface decarburization of steel. If the diffusion of carbon to the surface is limiting, the reaction can result in internal decarburization, methane formation and cracking. c) In the early stages of HTHA, bubbles/cavities can be detected in samples by a scanning microscope, although it may be difficult to tell the difference between HTHA cavities and creep cavities. Some refinery services expose low alloy steels to both HTHA and creep conditions. Early stages of HTHA can only be confirmed through advanced metallographic analysis of damaged areas.
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d) In later stages of damage, decarburization and/or fissures can be seen by examining samples under a microscope and may sometimes be seen by in-situ metallography. e) Cracking and fissuring are intergranular and occur adjacent to pearlite (iron carbide) areas in carbon steels. f) Some blistering may be visible to the naked eye, due to either molecular hydrogen or methane accumulating in laminations in the steel. 5.1.3.1.6 Prevention/Mitigation a) Use alloy steels with chromium and molybdenum to increase carbide stability thereby minimizing methane formation. Other carbide stabilizing elements include tungsten and vanadium. b) Normal design practice is to use a 25oF to 50oF (14oC to 28oC) safety factor approach when using the API RP 941 curves. c) While the curves have served the industry well, there have been several failures of C-0.5Mo steels in refinery service under conditions that were previously considered safe. C-0.5Mo carbide stability under HTHA conditions may be due at least in part to the different carbides formed during the various heat treatments applied to the fabricated equipment. d) As a result of the problems with the 0.5 Mo alloy steels, its curve has been removed from the main set of curves and the material is not recommended for new construction in hot hydrogen services. For existing equipment, this concern has prompted an economic review of inspection cost versus replacement with a more suitable alloy. Inspection is very difficult because problems have occurred in weld heat affected zones as well as base metal away from welds. e) 300 Series SS overlay and/or roll bond clad material is used in hydrogen service where the base metal does not have adequate sulfidation resistance. Although it is recognized that properly metallurgically bonded austenitic overlay/clad will decrease the hydrogen partial pressure seen by the underlying metal, most refiners make sure the base metal has adequate resistance to HTHA under service conditions. In some cases, refiners take the decrease in partial pressure into account when evaluating the need for hydrogen outgassing while shutting down heavy wall equipment. 5.1.3.1.7 Inspection and Monitoring a) Damage may occur randomly in welds or weld heat affected zones as well as the base metal, making monitoring and detection of HTHA in susceptible materials extremely difficult. b) Ultrasonic techniques using a combination of velocity ratio and backscatter have been the most successful in finding fissuring and/or serious cracking. c) In-situ metallography can only detect microfissuring, fissuring and decarburization near the surface. However, most equipment has decarburized surfaces due to the various heat treatments used during fabrication. d) Visual inspection for blisters on the inside surface may indicate methane formation and potential HTHA. However, HTHA may frequently occur without the formation of surface blisters. e) Other conventional forms of inspection, including WFMT and RT, are severely limited in their ability to detect anything except the advanced stages of damage where cracking has already developed. f) AET is not a proven method for the detection of damage. 5.1.3.1.8 Related Mechanisms A form of HTHA can occur in boiler tubes and is referred to by the fossil utility industry as hydrogen damage.
Document Status: Last Updated 11 August 2005 – Verified To API RP 571 First Edition
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Closed Book Practice Questions API RP 571 PRACTICE QUESTIONS
1. Vibration-induced fatigue produces cracks in ________________. a. b. c. d.
carbon steel only stainless steel only duplex steels only can occur in virtually any materials
2. Biologically-induced degradation may be caused by which of the following mechanisms: a. b. c. d.
MIC HIC SOHIC DICK
3. The appearance of erosion/corrosion is characterized by which of the following: a. b. c. d.
localized loss of thickness grooves gulleys may be any or all of the above
4. An area that should be inspected carefully for mechanical fatigue cracking would be: a. b. c. d.
plate base materials smooth, rounded areas toes of fillet welds pipe base materials
5. Boiler water condensate corrosion can best be preventefd or mitigated by: a. b. c. d.
UT thickness checks oxygen scavenging treatments using heat treated carbon steel using full radiography
6. Corrosion of steels from reaction with sulfur compounds in high temperature environments will be greater in which of the following materials: a. b. c. d.
1% chrome 2 1/4 % chrome 5% chrome 9% chrome
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7. Of the following, which would be the least effective method of locating tight caustic S.C.C., according to RP 571. a. b. c. d.
WFMT PT ACFM SWUT
8. The best way to prevent caustic embrittlement is to: a. b. c. d.
PWHT use 300 Series SS use a steamout use a carbide equalizer with a galvanic injection
9. A primary failure mechanism that is particularly prevalent in 300 Series stainless steel materials is: a. b. c. d.
fatigue cracking therml fatigue cracking chloride SCC soil corrosion
10. MIC is usually observed by: a. b. c. d.
general corrosion loss large blisters tight cracks pitting under deposits or tubercles
11. The cause of “atmospheric corrosion”, per RP 571 includes all of the following except: a. b. c. d.
bird turns cooling tower drift marine locations HTHA
12. Vibration-induced fatigue cracking can sometimes be located by NDE methods. The best NDE methods to detect this cracking would be: a. b. c. d.
SWUT RT N RT PT or MT
13. HTHA will normally not occur in which of the following materials: a. b. c. d.
300 Series SS 5 CR 9 CR all of the above
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14. Flue Gas Dew Point Corrosion is normally found in: a. b. c. d.
reactors regenerators boilers/heaters cooling towers
15. Marine environments can cause corrosion at a rate of: a. b. c. d.
20 mpy 5 mpy 200 mpy < 1 mpy
16. Erosion/corrosion is best mitigated by: a. b. c. d.
using better PWHT using corrosion/erosion resistant alloys using better welding techniques using a weld overlay of titanium
17. Brittle fracture can be mitigated by which of the following inspection techniques: a. b. c. d.
PT WFMT RT/UT none of the above
18. Refractory loss by erosion can be located on-stream by: a. b. c. d.
UT corrosion coupons BRFT IR scan
19. After insulation is removed, CUI often appears as: a. b. c. d.
blisters small, interconnected pits loose flaky scale general, clean metal loss
20. One of the best approaches for predicting whether boiler water condensate corrosion may be prevalent is: a. b. c. d.
research records of deaerator operation conduct a magnetite study see if the water tastes “funny” check for MIC and chlorine hideouts
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21. Dew Point corrosion caused by hydrochloric acids will normally occur at: a. b. c. d.
280°F 130°F 130°C 138°C
22. A sulfide scale on the surface of a component may: a. b. c. d.
cause very bad corrosion due to sulfidation cause very bad cracking doe to sulfidation offer some degree of protection to sulfidation offer some degree of protection to erosion
23. The greatest susceptibility of stainless steels to CL-SCC is in which of the following nickel contents: a. b. c. d.
> 35% >45% 8% - 12% < 8%
24. When hydrotesting 300 Series stainless steels, what precautions should be taken to prevent CL-SCC? a. b. c. d.
pressurize to 1.5 x P only use only gas to test use heated water use low chloride water and dry quickly
25. Caustic stress cracking can occur at low levels if concentrated in a local area. These concentrations may cause cracking at: a. b. c. d.
50 – 100 ppm > 300 ppm > 500 ppm < 50 ppm
26. As a general rule, cracking due to thermal fatigue may be expected if temperature swings exceed: a. b. c. d.
100°F 200°F 300°F 400°F
27. In steam generating equipment, thermal fatigue cracks: a. b. c. d.
are always linear are never surface-breaking usually follow the tow of a fillet weld, where applied are best inspected using RT
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28. The erosion/corrosion rate of carbon steel in seawater, using 1FPS (tidal current) will be: a. b. c. d.
6 mpy 13 mpy 47 mpy 0 mpy
29. The ratio of endurance limit over ultimate tensile strength is usually between: a. b. c. d.
0.4 – 0.5 0.5 – 0.6 0.08 – 0.09 0.04 – 0.05
30. One of the primary factors that contribute to fatigue cracking is: a. b. c. d.
material erosion NOTT of material lack of proper support material upgrades
31. Inspection and monitoring of atmospheric corrosion is generally conducted using which of the following NDE techniques, per API RP 571? a. b. c. d.
MT and PT UT and VT AET and NRT RT and LT
32. Which of the following insulation materials will contribute to CL-SCC on insulated 300 Series SS materials? a. b. c. d. 33.
closed cell foam spray –on refractory calcium silicate carbonate di-sulfate
Deaerator cracking can best be detected by removing the equipment from service, and utilizing ___________. a. RT b. WFMT c. PT d. UT
34. For HRSG’s, the use of _______ materials in the feedwater heaters should be avoided, if the environment will contain chlorides. a. 400 Series SS b. carbon steel c. aluminum d. 300 Series SS
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35. MIC must have which of the following to thrive: a. water b. oil c. gas d. norm 36. Soil corrosivity can be determined using which of the following single factors: a. moisture b. compaction c. resistivity d. no single factor that can be used to determine soil corrosivity 37. Sulfidation is also know as: a. SCC b. MIC c. sulfidic corrosion d. sulfanilamide 38. Nickel alloys above _______ nickel are nearly immune from CL-SCC a. 35% b. 45% c. 8% d. 16% 39. Susceptability to caustic embrittlement in NaOH and KoH solutions is a function of __________. a. caustic strength b. metal temperature c. stress levels d. all of the above
40. In the early stages of HTHA, bubbles/cavities can be detected in samples by: a. b. c. d.
PT UTSW scanning microscope AET
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ANSWER SHEET API RP 571 PRACTICE QUESTIONS
1. 2. 3. 4. 5. 6. 7. 8. 9. 10. 11. 12. 13. 14. 15. 16. 17. 18. 19. 20.
d, 4.2.17.2 a, 4.3.8.1 d, 4.2.14.5 c, 4.2.16.3 b, 4.3.5.6 a, 4.4.2.3 b, 4.5.3.7 a, 4.5.3.6 c, 4.5.1.1 d, 4.3.8.5 d, 4.3.2.3 d, 4.2.17.7 d, 5.1.3.1.3 c, 4.3.7.4 a, 4.3.2.3 b, 4.2.14.6 d, 4.2.7.7 d, 4.2.14.7 c, 4.3.3.6 a, 4.3.5.4
21. 22. 23. 24. 25. 26. 27. 28. 29. 30. 31. 32. 33. 34. 35. 36. 37. 38. 39. 40.
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b, 4.3.7.3 c, 4.4.2.3 c, 4.5.1.3 d, 4.5.1.6 a, 4.5.3.3 b, 4.2.9.3 c, 4.2.9.5 a, Table 4-3 a, 4.2.16.3 c, 4.2.17.3 b, 4.3.2.7 c, 4.3.3.6 b, 4.3.5.3 d, 4.3.7.4 a, 4.3.8.6 d, 4.3.9.3 c, 4.4.2.8 b, 4.5.1.3 d, 4.5.3.3 c, 5.1.3.5
API 510,572,576 QUESTIONS
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Closed Book Questions API 510 QUESTIONS
SELECT THE BEST ANSWER 1. The application of API 510 is restricted to organizations that: a. fabricate or build pressure vessels according to ASME B&PV Code. b. employ or have access to an authorized inspection agency. c. manufacture or inspect pressure vessels according to NBIC. d. hire or have access to an unsanctioned inspection agency. 2. API 510 Inspection Code is only applicable to pressure vessels used by the petroleum and chemical process industries that: a. are being fabricated for the petroleum/chemical industries. b. can be fabricated to ASME B&PV Code and inspected by NBIC inspectors. c. will be place in service after fabrication to the ASME B&PV Code. d. have been placed in service; inspected and/or repaired by an authorized agency. 3. The following is an example of a pressure vessel not excluded from coverage by API 510. (All of the vessels are in-service.) 0 a. Pressure vessel on an ocean-going ship, operates at 100 psig & 100 F. 0 b. Pressure vessel in a oil refinery, operates at 5 psig and 70 F. c. Pressure vessel in a oil refinery, operates at 100 psig and 2000 F. d. Pressure vessel in a oil refinery, vol. of 4 cu. ft., & operates at 70 psig and 700 F.
4. If there is a conflict between the ASME Code and API 510 for vessels that have been placed in service, the requirements of: a. API 510 shall take precedence over the ASME Code. b. ASME Code shall take precedence over API 510. c. NBIC shall be used as an arbitration Code. d. the owner/user shall take precedence over both Codes.
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5. One type of Authorized Inspection Agency is: a. An inspection organization that does inspections. b. An insurance/inspection agency, which does not write pressure vessel insurance. c. An owner/user of pressure vessels who maintains an inspection organization only for his own equipment. d. An independent third party consultant. 6. The term “minimum allowable shell thickness” is the thickness: a. essential for the shell and heads of a vessel. b. required for each element of a vessel. c. necessary for the shell of a vessel. d. including the corrosion allowance for the shell of a vessel. 7. Lowering of the maximum allowable working pressure or temperature rating of a vessel or both below the design conditions is: a. a not a permissible way to provide for corrosion. b. the preferred way to provide for corrosion. c. the only way to keep a vessel in service when it is corroded. d. a permissible way to provide for corrosion. 8. An owner-user is responsible for developing, documenting, implementing, executing, and assessing pressure vessel inspection systems and inspection procedures that will meet the requirements of API 510. These systems and procedures will be: a. maintained in a engineering procedure document. b. kept as a standard procedure. c. contained in a quality assurance inspection manual. d. in hand and available at owner-user headquarters. 9. Safety precautions are important in pressure vessel inspection because of the limited access to and the confined spaces of pressure vessels. Out of the organizations listed, which is the primary one that should be reviewed and followed? a. ASME b. OSHA c. NFPA d. NBIC 10. ___________ may occur if equipment is subjected to temperatures above those for which it is designed. a. Creep b. Brittle fracture c. Stress Corrosion d. Erosion
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11. If a probable corrosion rate cannot be determined from reviewing data from the same or similar service vessels or estimated form published data, on-stream determinations shall be made after approximately __________ hours of service by using NDE methods and a corrosion rate is established. a. 500 b. 1000 c. 5000 d. 10000 12. The maximum allowable working pressure for the continued use of a pressure vessel shall be based on computations determined by using the a. latest edition of the National Boiler Inspection Code or the construction code to which the vessel was built. b. latest edition of the ASME Code or the construction code to which the vessel was built. c. latest edition of the API/ASME Code or the construction code to which the vessel was built. d. latest edition of the Underwriters Laboratories Code or the construction code to which the vessel was built. 13. Out of the many methods of inspection ___________ is considered the most important and the most universally accepted method of inspection. a. radiographic examination b. careful visual inspection c. ultrasonic thickness measurement d. hammer testing 14. If external or internal coverings, such as insulation, refractory protective linings, and corrosion resistant linings are in good condition and there is no reason to suspect that an unsafe condition is behind them. a. it is not necessary to remove them for inspection. b. it is necessary to remove them completely for inspection. c. it is necessary to partially remove them for inspection. d. it is required to remove them completely for inspection on some set interval. 15. What API standard provides more information on the inspection of piping, valves and fittings associated with pressure vessels? a. API Recommended Practice 576. b. API Recommended Practice 575. c. API Recommended Practice 574. d. API Recommended Practice 573. 16. For a corroded area of considerable size in which the circumferential stresses govern, the least thickness along the most critical element of the area may be averaged over a length not exceeding the following: 16a. For vessels with inside diameters less than or equal to 60 inches-a. 1/4 the vessel diameter or 5 inches, whichever is less. b. 1/2 the vessel diameter or 10 inches, whichever is less. c. 1/4 the vessel diameter or 15 inches, whichever is less. d. 1/2 the vessel diameter or 20 inches, whichever is less.
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16b. For vessels with inside diameters greater than 60 inches-a. 1/3 the vessel diameter or 40 inches, whichever is less. b. 1/4 the vessel diameter or 30 inches, whichever is less. c. 1/3 the vessel diameter or 50 inches, whichever is less. d. 1/4 the vessel diameter or 25 inches, whichever is less. 17. For corrosion calculations the surface of the weld is considered to be: a. inch on either side of the weld or twice the minimum thickness on either side of the weld, whichever is greater. b. 2 inches on either side of the weld or 2 times the minimum thickness on either side of the weld, whichever is greater. c. 4 inches on either side of the weld or 4 times the minimum thickness on either side of the weld, whichever is greater. d. 6 inches on either side of the weld or 6 times the minimum thickness on either side of the weld, whichever is greater 18. Under what conditions is an internal field inspection of a newly installed pressure vessel waived? a. The contractor installing the vessel assures the owner-user that the vessel is satisfactory for its intended service. b. A manufacturers data report assuring the vessel is satisfactory for its intended service is available. c. The owner-user assures the inspector that the vessel is satisfactory for its intended service. d. The manufacturer orally assures the owner-user that the vessel is satisfactory for its intended service. 19. An above ground pressure vessel shall be given a visual external inspection, preferably while in operation, at least every _____ years or at the same interval as the internal/on-stream inspection, whichever is less. a. 2 b. 3 c. 5 d. 10 20. The period between internal or on-stream inspections shall not exceed one-half the estimated remaining life of the vessel based on corrosion rate or _______ years whichever is less. a. 10 b. 15 c. 5 d. 12 21. In cases where the remaining safe operating life is estimated to be less than 4 years, the inspection interval may be the full remaining safe operating life up to a maximum of _____ years. a. 1 b. 2 c. 3 d. 4
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22. If both the ownership and the location of a vessel are changed, what must happen before it is reused? a. It must be internally and externally inspected. b. All the records must be reviewed. c. It must be thoroughly ultrasonically checked. d. It must have all the paper work transferred to the new owner. 23. A pressure vessel has been in service for 12 years and has shown a history of corrosion over its service life. The original thickness was 1.9375” thick and the present thickness is 1.405”. What is the corrosion rate for this vessel? a. 0.266250 inches/year b. 0.532500 inches/year c. 0.088750 inches/year d. 0.044375 inches/year 24. When must a pressure test be performed on a pressure vessel? a. When the contractor working on the vessel deems it is necessary. b. When the API authorized pressure vessel inspector believes that it is necessary. c. When the safety group of the owner-user requests it. d. When the NFPA requests it. 25. Who is authorized to test and repair a pressure relief valve? a. An organization experienced in PRV maintenance. b. A valve repair shop. c. A certified pressure vessel inspector. d. A contractor with valve mechanics. 26. What is the maximum inspection interval of a pressure-relieving device? a. 15 years. b. 12 years, c. 10 years. d. 20 years. 27. What determines the inspection interval of a pressure-relieving devices? a. The interval is determined by the authorized pressure vessel inspector. b. The interval is determined by the owner-user. c. The interval is determined by the performance of the device. d. The interval is determined by the size of the device. 28. The following is not normally found in pressure vessel records. a. Manufacturers data reports. b. Vessel identification numbers c. Piping past the first vessel flange. d. Relief valve information.
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29. When repairs or alterations are to be performed on a pressure vessel, all materials, and all welding procedures that are to be used must be approved by: a. the insurance carrier for the company that the pressure vessel belongs to and the owner-user of the pressure vessel. b. the owner-user and the contractor performing the repairs or alterations to the pressure vessel. c. the API authorized pressure vessel inspector and, if necessary, by an engineer experienced in pressure vessel design, fabrication, or inspection. d. the original vessel fabricator and the insurance carrier for the company that owns the pressure vessel. 30. What type of repairs can an authorized inspector give prior general authorization for? a. major repairs that require pressure tests. b. alterations that require pressure tests. c. major alterations that require pressure tests. d. limited or routine repairs that will not require pressure tests. 31. When does an inspector normally approve all specified repair and alteration work. a. Work is approved after the work contractor certifies the work to be satisfactory and the contractor has pressure tested the vessel. b. Work is approved by a process/chemical engineer for the owner-user and the contractor has pressure tested the vessel. c. Work is approved after an inspection by the authorized inspector has proven the work to be satisfactory and any required pressure test has been witnessed by him b. Work is approved after an inspection and test by the contractor and the unit operators accept the vessel. 32. Who should be consulted before repairing a crack at a discontinuity, where stress concentrations may be serious? a. The operators of the vessel. b. The owner-user. c. An engineer experienced in the operation of the vessel. d. An engineer experienced in pressure vessel design. 33. All repair and alteration welding shall be in accordance with: a. NBIC Welding Code b. AWS D1.1 Welding Code c. Original Construction Code d. NFPA Welding Code 34. The repair organization shall use qualified welders and welding procedures qualified in accordance with the applicable requirements of: a. Section V of the ASME Code. b. Section IX of the ASME Code. c. AWS D1.1 Welding Code. d. API Standard 1104, Welding.
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35. The repair organization shall maintain records of its qualified welding procedures and its welding performance qualifications. These records shall be available to the ____________ prior to the start of welding. a. operator b. owner-user c. welder d. inspector 36. For alterations or repairs of vessels initially postweld heat treated as a code requirement and constructed of P-1 and P-3 steels listed in the ASME Code, preheating to not less than _______ degrees F may be considered as an alternative to PWHT. a. 200 b. 300 c. 400 d. 500 37. A 2 1/4 % chrome material (P-5) vessel must be repaired by welding in a flush patch (replacing a corroded area). The vessel is in caustic service and was originally post weld heat treated. Notch toughness is not a consideration. Which of the following is correct. a. No post weld heat treatment (PWHT) is required. b. The repair may be pre-treated to 300 degrees F. while welding and PWHT waived. c. The repair may be made by using the temper-bead welding technique. d. The repair must be post weld heat treated. 38. If local post weld heat treatment is approved for a vessel repair (a complete 360 degree band around the vessel is not used--only a localized spot), what are the minimum number of thermocouples required around the localized area to monitor the temperature? a. 1 b. 2 c. 4 d. 6 39. When repairing vessels with stainless steel weld overlay and cladding (vessels constructed of P-3, P-4, or P-5 base materials) the base metal in the area of repair should be examined for cracking by UT per ASME Section V. This UT inspection should be made________ hours after repairs have been completed for equipment in hydrogen service, especially for chromium-molybdenum alloys that could be affected by delayed cracking. a. 12 b. 24 c. 36 d. 42 40. When are fillet welded patches (lap patches) allowed. a. They may be only used in vessels with shells 3/8” thick or less. b. They may be used only if approved by the operators. c. They may be used only on low pressure vessels. d. They are used for only temporary repairs – unless approved for longer use by the Engineer/Inspector
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41. Carbon or alloy steel with a carbon content over _____ percent shall not be welded. a. 0.30 b. 0.35 c. 0.40 d. 0.45 42. Acceptance criteria for a welded repair or alteration should include NDE techniques that are in accordance with the: a. applicable section of the NBIC. b. applicable section of the ASME Code. c. jurisdiction. d. owner-user. 43. A pressure test is normally required after: a. an alteration. b. a repair. c. a lightning strike. d. a unit upset. 44. When is a rerating of a pressure vessel considered complete? a. When the pressure vessel engineer approves the rerating. b. When the authorized construction organization attaches the nameplate to the rerated vessel. c. When the API authorized PV inspector oversees the attachment of an API 510 nameplate. d. When the owner-user accepts the rerating from the rerating organization. 45. An API certified inspector who has not been actively engaged, as such, within the previous three years can be recertified by: a. being employed by a refinery. b. being licensed by the jurisdiction. c. an oral examination. d. a written examination. 46. An Examiner is normally: a. an API 510 Inspector b. A UTT Level II NDE Examiner c. A person that assists the API 510 Inspector, but does not necessarily have to qualify as an API 510 Inspector d. An independent API 510 Inspector 47. The minimum number of TML’s on any given vessel is: a. b. c. d.
determine by the API 510 Inspector determined by the owner/user at least one at least 4 on each shell and head
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48. If a short-term corrosion rate reflects a .001” per year corrosive environment currently exists and the longterm corrosion rate is .009” per year, the corrosion rate used in calculating the inspection interval should be: a. b. c. d.
the long term the short term both terms as defined by the Inspector for the process
49. Risk Based Inspection may be conducted to evaluate: a. consequence of a failure b. likelihood of a failure c. possibility of a failure d. a & b above 50. Which assessment should be repeated each time equipment or process changes are made that could affect the degradation or failure of the vessel? a. b. c. d.
consequence probability likelihood internal/external
51. RBI assessments shall be reviewed and approved by the ________________ when used to increase the 10 year inspection limit. a. b. c. d.
pressure vessel owner/user pressure vessel engineer pressure vessel inspector both b and c above
52. “Actively Engaged” is defined as __________________. d. a minimum of 30% of time spent performing/supervising inspections over the 3 year certification period. b. performing/supervising inspections on 65 pressure vessels over the 3 year certification period. c. conducting 20 repair/alteration pressure tests per year for each of the 3 years. d. none of the above 53. What is the maximum carbon content of a material that will be used for a welded repair? a. b. c. d.
.34% .35% .40% .30%
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54. If a pressure-relieving device is in clean (non-fouling), non-corrosive service, what is the maximum inspection interval in accordance with API 510? a. b. c. d.
5 Years 1 Year 10 Years At the same interval as the internal or on-stream inspection.
55. If a pressure vessel was constructed in accordance with ASME Section VIII Division 1 in 1966, can it be rerated in accordance with the latest edition / addendum of ASME Section VIII Division 1? a. b. c. d.
Yes No Maybe Homework Sucks
56. Any welding technique used to obtain controlled grain refinement and tempering of the underlying heat affected zone in the base metal is? a. b. c. d.
Heat refinement welding Postweld heat treatment Annealing Controlled-deposition welding
57. Who must give prior authorization for all alteration work to be done on pressure vessels that comply with ASME Section VIII Division 1? a. b. c. d.
Authorized pressure vessel inspector Pressure vessel engineer Authorized pressure vessel inspector and pressure vessel engineer The examiner
58. When using preheat as an alternative to postweld heat treatment, which of the following welding techniques cannot be used? a. b. c. d.
SMAW GTAW GMAW FCAW
59. A pressure vessel is constructed with a shell thickness of 2 ½”, the vessel has an MDMT of 30 8F, what is the minimum temperature at which a pressure test should be performed? a. b. c. d.
50 8F 60 8F 30 8F 40 8F
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60. For pressure vessels that have no nameplate, minimal or no design and construction documentation, and the extent of radiography originally performed is not known, what joint factor should be used for butt welds? a. b. c. d.
0.70 0.75 0.85 0.90
61. A pressure vessel has an established corrosion rate of .012” per year. The vessel was last inspected in 2001 and had a measured wall thickness of .375”. The minimum required thickness for this vessel based on calculation performed in accordance with the original construction code is .265”. Utilizing this information, what is the remaining life of this pressure vessel? a. b. c. d.
9 Years 5 Years 15 Years 7 Years
62. Which of the following is characterized as a loss of ductility and notch toughness due to postweld heat treatment or high temperature service. a. b. c. d.
Stress Corrosion Cracking Carburization Graphitization Temper Embrittlement
63. If both the ownership and the location of a pressure vessel are changed, what inspection(s), if any, will need to be performed? a. The pressure vessel does not need to be inspected if current documentation is available to insure the pressure vessels integrity. b. The pressure vessel shall have an internal and external inspection. c. The pressure vessel shall have an external inspection. d. The pressure vessel shall have an internal inspection and an on-stream inspection. 64. In accordance with API 510, to what extent must NDE examiners be trained or certified? a. b. c. d.
NDE examiners must be certified in accordance with ASNT SNT-TC-1A. NDE examiners must be certified in accordance with ASNT CP-189. NDE examiners must be trained and competent. NDE examiners must be trained and certified in accordance with the referencing code.
65. Which of the following vessels is not exempt from the specific requirements of API 510? a. A vessel that does not exceed 5 cubic feet in volume and 600 PSI design pressure. b. A vessel that is on moveable structures covered by other jurisdictional regulations. c. A vessel listed for exemption from the construction in the scope of ASME Section VIII, Division 1, of the ASME Code. d. A vessel that does not exceed 1 ½ cubic feet in volume and 600 PSI design pressure
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66. Before local postweld heat treatment is used in lieu of 360-degree banding on local repairs, what type of review must be conducted to determine if a vessel was postweld heat treated due to the characteristics of the fluid being handled? a. b. c. d.
Welding Procedure Specification review. Past inspection reports review. Pressure Test review. Metallurgical review.
67. A pressure vessel rerating will not be considered complete until? a. The pressure vessel engineer certifies that all inspections and examinations have been performed in accordance with API 510. b. The pressure vessel inspector oversees the attachment of an additional nameplate or additional stamping. c. The pressure vessel inspector certifies that all inspections and examinations have been performed in accordance with API 510. d. The examiner completes all required NDE examinations. 68. A pressure vessel was placed into service in 1989 and was constructed with a design thickness of .750”. In 2001 the wall thickness was measured at .630”. Based on this information and a minimum thickness of .550”, when is the next internal inspection due for this pressure vessel? a. b. c. d.
4 Years 2 Years 8 Years 10 Years
69. Which of the following NDE methods is the most important and the most universally accepted? a. b. c. d.
RT VT MT PT
70. When making welded repairs to a pressure vessel, who is responsible for maintaining the records for welding procedures and welder performance qualifications? a. b. c. d.
The owner/user. The inspector. The pressure vessel engineer. The repair organization.
71. What is the time interval between the issuance of an edition, revision, or addenda of an API standard and when it goes into effect? a. b. c. d.
Immediately upon issuance. 1 month after issuance. 6 months after issuance. 1 Year after issuance.
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72. The work necessary to restore a vessel to a condition suitable for safe operation at the design conditions is considered a? a. Repair b. Alteration c. Quality Assurance/Quality Control review d. Rerating 73. Which of the following is not considered an acceptable means of determining the probable corrosion rate of a new vessel? a. From data collected on vessels providing the same or similar service. b. On-stream determination after 6 months of service using appropriate NDE. c. From the owner/users experience or published data on vessels providing comparable service. d. On-stream determination after 1000 hours of service using appropriate NDE. 74. If a pressure vessel is to have a pressure test and there is no available information as to the vessel’s minimum design metal temperature, what should be used to determine the minimum temperature at which the pressure test should be performed? a. Published information on the material of construction. b. The minimum acceptable operating temperature. c. A material sample should be taken from the vessel and a metallurgical analysis performed. d. The pressure test should be performed at a minimum temperature of 72 8F. 75. How many years is an API certificate valid for an authorized pressure vessel inspector? a. 2 Years from issuance. b. 3 Years from issuance. c. 4 Years from issuance. d. 5 Years from issuance. 76. When should “Industry-qualified” UT shearwave operators be used per API 510? a. b. c. d.
Mandatory as of Dec. 2001. Mandatory as of Dec. 2002. Mandatory as of Dec. 2003. Mandatory as of Dec. 2004.
77. RP 579 covers: a. RBI b. UT Shearwave Operators c. FFS Assessments d. IRE II Assessments 78. An industry-qualified UT shearwave operator may be qualified in accordance with: a. b. c. d.
API rules CP-189 SNT-TC-1A Any of the above if acceptable to the owner/user
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Closed Book Questions API 572 QUESTIONS
SELECT THE BEST ANSWER 1. Several different methods are used to construct pressure vessels. Most pressure vessels are constructed today using ____________ construction. a. welded b. hot forged c. riveted d. multilayer 2. The most common material used to construct pressure vessels is: a. titanium b. austenitic stainless steel c. Monel d. carbon steel. 3. Construction codes are periodically revised as the designs of pressure vessels improve and as new construction materials become available. A pressure vessel should be maintained according to the:
a. requirements under which it was designed and constructed. b. standards and specifications of the owner/user. c. principles and specifications of the jurisdiction. d. guidelines of the NBIC. 4. The basic reasons for inspection are: a. to meet the prerequisites of the ASME Code. b. to fulfill the provisions of the API 510. c. to satisfy the requirements of OSHA. d. to determine the physical condition of the vessel and to determine the type, rate, and causes of deterioration.
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5. The most common environmental cracking in pressure vessels in refineries are: a. wet H2S and CUI. b. polythionic cracking in ferritic stainless steel. c. amine stress cracking in stress relieved vessels. d. caustic embrittlement under 400°F.
6. Erosion is the attrition of a surface caused by: a. loss of material caused by sulfur and chloride compounds. b. attrition of material cased by acid or caustic attack. c. the impingement of solid particles or liquid drops. d. wearing down of a material caused by oxidation. 7. Many problems with pressure vessels are caused by faulty fabrication. Which item on the following list is not related to faulty fabrication. a. poor welding. b. chloride stress corrosion cracking. c. improper heat treatment. d. dimensional intolerance. 8. The external inspection of a pressure vessel should start with: a. vessel foundation and anchor bolts. b. ladders, stairways, platforms, or walkways connected or bearing on the vessel. c. nozzles and connecting piping. d. protective coatings and insulation. 9. If an internal inspection of a vessel is not the initial one, the first step is to: a. make a walk around visual check of the vessel. b. review the previous records of the vessel to be inspected. c. check with the vessel operators for unusual operating conditions. d. make a preliminary manway inspection. 10. Which of the following is not a tool for measuring thickness of vessel shells? a. acoustic emission transducers. b. ultrasonic instruments. c. radiography with step gages. d. corrosion buttons and depth drilling. 11. What is the primary method used to obtaining thickness measurements on process equipment? a. b. c. d.
Calipers Profile Radiography Ultrasonic instruments Depth drilling
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12. Which of the following may leave high residual stresses near welds and may affect the physical properties and corrosion resistance of a metal? a. b. c. d.
Stress corrosion cracking Galvanic corrosion Carburization Improper heat treatment
13. Titanium vessels may lose ductility due to absorption of hydrogen and the resulting formation of: a. hydride phases b. caustic embrittlement c. polythionic acid embrittlement d. Sigma phase 14. Which pressure vessel component is normally the most likely to suffer deformation? a. b. c. d.
Heads Shell Nozzles Manways
15. What is the suggested spacing of wire rope clips used on guy wire cables? a. b. c. d.
At least 4 rope diameters apart. At least 6 rope diameters apart. At least 8 rope diameters apart. At least 10 rope diameters apart
16. High temperature sulfidic corrosion will normally take place above what temperature? a. b. c. d.
300°F 200°F 450°C 450°F
17. Which of the following vessels is the most likely to undergo uneven settlement? a. b. c. d.
A vessel that is supported by a short concrete slab A vessel that is supported by a short fireproofed concrete slab. A vessel that is supported by a steel reinforced concrete slab. A vessel that is supported by two separate concrete slabs.
18. If a crack is found in a pressure vessel, to what extent must the crack be removed prior to welded repair? a. The crack must be removed entirely. b. The crack shall be removed sufficiently enough to prevent further propagation. c. The removal of cracks shall be to the extent as agreed upon between the repair organization and the authorized inspector. d. If a crack is found in a pressure vessel, a metallurgist shall be consulted as to the extent of crack removal.
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19. This method of deterioration is usually localized, but at times is very general. It can occur at cyclone separator internals, exchanger tubes, impingement baffles and mixing columns. This deterioration is: a. b. c. d.
Corrosion Dezincification Erosion Carburization
20. The three types of information that should make-up a complete record file are? a. b. c. d.
Basic data, field notes, and the data that accumulates in a “continuous file”. Metallurgical reviews, original construction drawings, and inspection reports. The original construction radiographs, U-1 report, and ultrasonic examination reports. The “as built” drawings, in-service inspection reports, and engineering design reports.
21. The limits of wall thickness loss that may be tolerated should be based on: a. b. c. d.
Fatigue strength. Retiring thickness of the vessel. Rate of deterioration. Both B & C, above.
22. Grounding systems should be tested to insure that the resistance to ground does not exceed? a. b. c. d.
5 ohms 10 ohms 20 ohms 25 ohms
23. Which of the following would be used to aid an inspector in locating hydrogen blistering? a. b. c. d.
Thermal imaging A flash light Magnetic Particle Examination Radiography
24. Incomplete penetration, lack of fusion, and slag inclusion are all deficiencies associated with? a. b. c. d. 25.
Improper heat treatment Poor welding Corrosion Metallurgical changes
Dealloying is a degradation characterized by the loss of one or more alloys. commonly found in copper alloys. One of these is: a. b. c. d.
Creep. Dezincification. Decarburization. Deschindlerization.
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3 common forms are
26. The most important biological mechanism that directly influences the rate of corrosion is: a. b. c. d.
H2S. SRB. S04. PMS.
27. Where are leaks on a pressure vessel most likely to occur? a. b. c. d.
At piping attachments to the vessel wall. At the “start-stop” locations in a weld seam. At intersecting weld seams (tee junctions). Around the data plate attachment welds.
28. What are the primary reasons for scheduling units for inspection, per API RP 572? a. b. c. d.
Economics Safety and Reliability OSHA regulations To satisfy local environmental concerns
29. Determining the physical condition of a pressure vessel and determining the type, rate, and causes of deterioration are the basic reasons for? a. b. c. d.
Metallurgical analysis NDE examinations Inspections Impact test
30. Which of the following is not a code or standard used for the design and construction of heat exchangers and condensers in the United States? a. b. c. d.
TEMA ASME Code API Standard 660 BOCA
31. When performing an inspection, the two most important factors in determining the limits of corrosion and any other type of deterioration that may be tolerated are? a. b. c. d.
The retirement thickness of the part considered and the rate of deterioration. The modules of elasticity and the hoop stress. The amount of NDE originally performed and the type of discontinuities found. The type of welding process used in the original construction and the name of the manufacturer.
32. Under which of the following conditions would external corrosion most likely occur. a. b. c. d.
On a vessel that is maintained at elevated temperatures. On a vessel that is in cryogenic service. On a vessel that is located directly downwind of a cooling tower. On a vessel that is epoxy coated.
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33. Which of the following methods could be used to detect de-carburization of austenitic stainless steels? a. b. c. d.
Metallurgical examinations Ultrasonics Acoustic Emissions None of the above
34. The bottom head and shell of fractionators processing high-sulfur oils are susceptible to what type of deterioration? a. b. c. d.
Hydrogen Embrittlement Sulfide Corrosion Chloride Stress Corrosion Cracking Sulfur De-oxidation
35. Which of the following types of corrosion is normally not found on the external surfaces of operating pressure vessels? a. b. c. d.
Soil corrosion CUI Atmospheric corrosion Hydrogen blistering
36. What NDE technique can be utilized to determine if creep cracking is prevalent, per RP 572? a. b. c. d.
MT PT AE Any of the above
37. When a vessel is supported with guy wires, how should the wire rope clips be attached to the wire rope? a. With the base against the dead or short end and the u-bolt against the live or long end of the wire rope. b. With the base against the live or long end and the u-bolt against the dead or short end of the wire rope. c. The orientation of the wire rope clip in regards to the wire rope is irrelevant. d. Two wire rope clips should be used to secure the wire rope. One clip needs to be oriented with the base against the dead or short end and one clip needs to be oriented with the base against the live or long end. 38. Which of the following is not considered to be a metallurgical or physical change of a pressure vessel metal? a. b. c. d.
Carbide precipitation High-temperature hydrogen attack Embrittlement Amine cracking
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39. When profile radiography is performed, what has to be shown on the developed film of the vessel part, per RP 572? a. b. c. d.
Image Quality Indicator Location markers Step gauge of known thickness All of the above
40. Which magnetic particle analysis is the most sensitive in finding cracks, per RP 572? a. b. c. d.
Wet fluorescent magnetic particle Dry fluorescent magnetic particle Dry color contrast magnetic particle Wet color contrast magnetic particle
41. Which of the following would not be considered a process that could change the hardness of a metal? a. b. c. d.
Temper embrittlement Neutralization Graphitization Decarburization
42. What is PMI used for per RP 572? a. b. c. d.
To check for correct alloy materials To check for correct steel materials To check for correct pressure monitoring installations To check for correct valve installation
43. If amine materials are used or stored in a pressure vessel, where is cracking most likely to occur? a. b. c. d.
Welds and HAZ’s. Base metal of stress relieved nozzles. Skirts. Flanges.
44. Which of the following inspection methods would be best suited for the inspection of internal linings such as paint, glass, plastic, and rubber? a. b. c. d.
Magnetic Particle Liquid Dye Penetrant Profile Radiography Spark Tester
45. When settlement of pressure vessel foundations and/or supports is found, and routine monitoring is taking place, at what time should the taking of settlement measurements be suspended? a. When sufficient information has been obtained to reliably predict the amount of settlement occurring. b. When sufficient information has been obtained to calculate the amount of settlement that will take place over the life of the vessel. c. When the information obtained reveals that uniform settlement is taking place. d. Measurements should be taken until the settlement stops.
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46. What type of pressure vessel is constructed with a casing or outer shell that forms a space between itself and the main shell? a. b. c. d. 47.
A cylindrical pressure vessel. A jacketed pressure vessel. A spheroidal pressure vessel. A spherical pressure vessel.
Above what operating temperature would catalytic reformer equipment be susceptible to creep embrittlement damage? a. b. c. d.
500 8F 750 8F 800 8F 900 8F
48. If vibration is noted on auxiliary equipment associated with a pressure vessel and supports cannot be added to reduce the vibration, what should be done? a. The inspector should consult with operations personnel to determine if the auxiliary equipment can be removed. b. The auxiliary equipment should be placed on a preventive maintenance schedule to monitoring for fatigue cracking. c. A qualified engineer should perform calculation to assure that the vibrations will not cause fatigue cracking. d. The auxiliary equipment should be radiographed on a routine basis to ensure no fatigue cracking is taking place. 49. Which of the following inspection techniques should not be used on pressure vessels that are under pressure? a. b. c. d.
Magnetic Particle Examination Hammer testing Ultrasonic Examination Acoustic Emissions
50. Tube sheets that are in water service are generally constructed from what types of metal? a. b. c. d.
Naval brass or steel. Stainless steel or Aluminum Copper or Chrome Monel or Nickel
51. CUI would not be a factor in which of the following conditions? a. b. c. d.
Vessels operating at -4°C - 120°C Aus. stainless steel vessels operating at 450°F Insulated vessels downwind from a cooling tower Carbon steel vessels with damaged insulation
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52. What are the most important conditions to check for when examining metallic linings? a.
That the lining is applied evenly, it has sufficient ductility, and no film lifting is visible. b. There is no corrosion, it was properly installed, and that no holes or cracks exist. c. That the lining is of sufficient strength to resist mechanical forces and there are no blisters caused by inadequate surface preparations. d. All of the above. 53.
What type of deterioration can be expected on the shell of exchangers next to bundle baffles and impingements plates? a. b. c. d.
Stress Corrosion Cracking Hydrogen Blistering Erosion Intergranular Corrosion
54. What must the manufacturers of pressure vessels constructed in accordance with ASME Section VIII Division 1 and Division 2 have? a. An on-site Authorized Inspector. b. A quality control system. c. Employees trained and certified in accordance with SNT-TC-1A to perform nondestructive examinations. d. All of the above. 55. If external or internal coatings or linings appear visually to be in good condition, with no evidence of corrosion or deterioration, the Inspector should: a. b. c. d.
“Spot” clean, and then inspect the metal. Chip off a large area for UT examination. Schedule a ET to check for coating thickness. Leave it alone.
56. If a pressure vessel has historical records of past inspections, little or no corrosion is evident, and the vessel has operated under normal conditions, what is the least amount of thickness measurements that should be taken? a. b. c. d.
Measurements taken in each quadrant of each shell ring and head. One measurement in each shell ring and one measurement on each head. In each quadrant of each head and at least one measurement in each shell ring. In each quadrant of each shell ring and at least one measurement in each head.
57. In exchanger pressure testing, when is a “test ring” used? a. b. c. d.
On floating head exchangers On stationary head exchangers On drum-type exchangers On fin-fan air coolers
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58. When should a service history record be established for a pressure vessel? a. b. c. d.
As soon as the pressure vessel is placed into service. Prior to the pressure vessel being stamped with the ASME Code symbol. After the first on-stream or internal inspection. Following the initial pressure test.
59. When performing an external inspection, what type of corrosion would be expected around the heads of bolts and nuts, at brackets connections between stair treads and angle supports, and at connections between intermediate supports and pressure vessel walls? a. b. c. d.
Crevice Corrosion Biological Corrosion Galvanic Corrosion Intergranular Corrosion
60. When performing a pneumatic pressure test in lieu or a hydrostatic pressure test, the recommendations set forth in which code or standard should be followed? a. b. c. d.
API 510 API 574 API 576 ASME Code
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Closed Book Questions API 576 QUESTIONS
SELECT THE BEST ANSWER 1. Using the following description, pick the type pressure-relieving device from the list. The spring is fully exposed; it is used on steam boiler drums; it is also used for general air and steam service in a refinery. a. Rupture Disk. b. Safety Relief Valve. c. Relief Valve. d. Safety Valve. 2. Using the following description, pick the type pressure-relieving device from the list. They are used in liquid or incompressible fluid service. They have closed bonnets. They should not be used in steam, air, gas, or vapor service. a. Rupture Disk. b. Safety Relief Valve. c. Relief Valve. d. Safety Valve. 3. Using the following description, pick the type pressure-relieving device from the list. They are used in gas or vapor service and liquid service. They have closed bonnets. They should not be used on steam boilers. They are used in corrosive refinery service. a. Rupture Disk. b. Relief Valve. c. Safety Relief Valve. d. Safety Valve. 4. Using the following description, pick the type pressure-relieving device from the list. They are used in refinery process industries for gas, vapor, air or liquids. They can be used in corrosive refinery service. They minimize the effects of back pressure on its operation characteristics. They should not be used as pressure control or bypass valves. a. Safety Valve. b. Balanced Safety Relief Valve. c. Relief Valve. d. Rupture Disk.
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5. What is the common limitation for use on the following pressure relief devices: Safety Valve, Relief Valve, Safety Relief Valve, Balanced Safety Relief Valves. a. use in corrosive refinery service. b. use as a pressure control or bypass valve. c. use as on steam boiler drums or superheaters. d. use in liquid service. 6. Which of the following in NOT a cause of a pressure-relieving devices improper performance? a. corrosion. b. proper maintenance. c. damaged seating surfaces d. failed spring. 7. Why is a definite time interval between inspections of pressure-relieving devices necessary? a. To insure proper performance. b. To satisfy OSHA requirements. c. To fulfill owner-user limitations. d. To meet manufacturers conditions. 8. An inspection or testing of a pressure-relieving device is required by API 510 at least every ________ years maximum. a. 7 b. 10 c. 15 d. 20 9. Which one of the following list is not an item to be checked when a visual on-stream inspection of a pressurerelieving device. a. Check to make sure the inlet nozzle of the valve and/or the piping to the valve inlet is not plugged. b. Check to make sure the correct relief device was installed. c. Check to make sure no gags, blinds, closed valves or piping obstruction prevent the relief device from working. d. Check to make sure the seals installed to protect the spring setting have not been broken. 10. When a pressure-relief valve is first received in the shop, what should be done prior to dismantling? a. dismantle and clean the valve. b. check the valve spring for corrosion. c. dip the valve in a cleaning solution. d. test pop the valve to determine the “as received” relieving pressure.
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11. A self locking seal that when placed in position and closed, locks and must be physically cut or broken to be removed is a ? a. b. c. d.
Lock-Out Car Seal Locking Pin Cotter Key
12. Which of the following should be on a pressure relieving device’s identification tag? a. b. c. d.
Test dates. Unit designation. Set pressure. All of the above.
13. Which of the following is not a limitation of a relief valve? a. b. c. d.
It should not be used as a pressure control or bypass valve. It should not be used for incompressible fluids. It should not be used in steam, air, gas or other vapor services. It should not be used in services piped to a closed header without consideration of the effects of back pressure.
14. Which of the following pressure-relieving devices is characterized as having a bonnet that encloses the spring and forms a pressure tight-cavity, with the bonnet cavity being vented to the discharge side of the valve? a. b. c. d.
Conventional Safety Relief Valve Balanced Safety Relief Valve Pilot-Operated Safety Relief Valve Rupture Disk
15. If a pressure relief valve is received and the valve’s inlet and outlet are not covered, what should be done? a. Provisions should be made to ensure that in the future they are covered before leaving the shop. b. The relief valve shall be sent back to the shop to verify the set pressure. c. The inlet and outlet of the relief valve should be flushed with water, steam or another suitable medium. d. The relief valve should be dismantled and cleaned. 16. Which of the following may cause the improper performance of a pressure-relieving device? a. b. c. d.
Damaged seating surfaces Failed springs Rough handling All of the above
17. Pressure gauges to be used for the setting of pressure relief valves should be calibrated by what means? a. b. c. d.
By utilizing a calibrated gauge in conjunction with the test gauge to insure uniformity. With a regularly calibrated dead weight tester. Gauges should be sent to an outside testing agency for calibration. Gauges should be calibrated in accordance with the manufacturers recommendations.
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18. Which of the following pressure-relieving devices would be used to protect the upstream side of a pressure relief valve against corrosion? a. b. c. d.
Safety Valve Relief Valve Rupture Disk Conventional Safety Relief Valve
19. How should pressure relief valves be shipped? a. b. c. d.
In an upright position. Incased in a protective compartment On their side to prevent the relief device from falling over during shipment. UPS ground.
20. What is the reason(s) for inspecting pressure relief devices? a. To determine if the devices were manufactured in accordance with ASME and API requirements. b. To determine the general physical and operating conditions of the devices, and to ensure that their performance meets the requirements for a given installation. c. To ensure the devices ability to withstand external shock loadings. d. All of the above. 21. A pressure-relieving device whose spring is fully exposed outside of the valve bonnet and is normally used on stream boiler drums and super-heaters. a. b. c. d.
Relief Valve Safety Relief Valve Safety Valve Conservation Vent
22. Which of the following would not be a precaution taken when removing a pressure-relieving device while the equipment is in operation? a. The space between the relief device and any adjacent block valve should be vented to a safe location. b. The bonnet of the relieving device should be removed and tested for hazardous materials or explosive mixtures. c. A blind should be inserted between the pressure relief device and any adjacent upstream block valve. d. An authorized person should isolate a relief device by closing any adjacent block valves upstream or downstream. 23. What is essential to the effective administration and control of any pressure-relieving device program in a process industry? a. b. c. d.
The use of preventive maintenance software. Personnel trained in observing pressure relief valve maintenance. Authorized Inspectors. A suitable system of keeping records and making reports.
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24. What normally causes the failure of pressure relief valve springs? a. b. c. d.
Over tightening of the set screw. Improper assembly Lack of maintenance Corrosion
25. Which of the following pressure relieving devices is normally used for the protection of atmospheric storage tanks? a. b. c. d.
Pressure and/or vacuum vent valves Safety Valves Relief Valves Rupture Disk
26. A visual on-stream inspection should be performed on pressure relieving devices at what intervals? a. As determined by the performance of the devices in the particular service concerned with a maximum interval of 10 years. b. As determined by previous on-stream inspections - with a maximum interval of 5 years. c. In accordance with manufacturers recommendations. d. As determined by previous on-stream inspection - with a maximum interval of 10 years. 27. What is the usual service life of a pre-bulged metal rupture disk under normal operating conditions? a. b. c. d.
1 Year 2 Years 3 Years As determined from previous inspections.
28. When is the best time to perform inspections on pressure relieving devices? a. When the owner/user specifies. b. During plant emergency drills. c. When the inspection least interferes with the process and maintenance manpower is readily available. d. When environmental conditions are best suited for outside activities. 29. Which of the following shall be installed between a rupture disk device and the inlet of a pressure relief valve to detect disk rupture or leakage? a. b. c. d.
Try cock Pressure gauge A free vent All of the above
30. If a rupture disk’s manufacturer specifies a bolting torque procedure and the tightened bolts are loosened, the rupture disk should be what? a. Replaced b. Disassembled and inspected to insure no damage has occurred. c. The bolting should be retightened in accordance with the manufacturers recommendations. d. The rupture disk and housing should be externally visually inspected to insure no damage has occurred.
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31. What type of pressure relief valve should be installed in a system that is corrosive and may contain foreign particles? a. b. c. d.
Conventional Safety Relief Valve Balanced Bellows Safety Relief Valve Safety Valve Pilot Operated Safety Relief Valve
32. The annular pressure chamber located downstream of the seat of a pressure relief valve for the purpose of assisting the valve to achieve lift is? a. b. c. d.
Bonnet Chamber Huddling Chamber Try Cock Chamber Seating Chamber
33. Which side of a conventional domed rupture disk (pre-bulged) is designed for pressure? a. b. c. d. 34.
The convex side. The concave side. Both sides of the disk are designed for pressure. Pressure cannot be placed on this type of rupture disk.
If unusual corrosion, deposits, or conditions are noted during the shop maintenance/inspection of a pressure relief valve, who should be called upon to assist in the inspection? a. b. c. d.
The Inspector The Employer The Pressure Relief Valve Engineer The Pressure Vessel Engineer
35. When operating pressures are as high as 90% of a disks design bursting pressure, what type of rupture disk should be used? a. b. c. d.
Pre-bulged metal rupture disk. Graphite rupture disk. Tension loaded rupture disk. Reverse buckling rupture disk.
36. Why is the size (capacity) of a pressure relief valve test stand important? a. Insufficient surge volume could damage a pressure relief valve’s internal parts. b. Insufficient surge volume could produce inaccurate test gauge readings. c. Insufficient surge volume might not cause a distinct “pop”, and may cause an incorrect set pressure. d. The size of the pressure relief valve test stand is irrelevant. 37. For pressure relief valves that comply with ASME Section VIII, Division 1, what is the minimum and maximum deviation between the “pop” pressure and the set pressure? a. Not less than 0% or greater than 10% of the set pressure. b. No more than 10% above or 10% below the set pressure. c. Not less than 5% or greater than 5% of the set pressure. d. Not less than 10% or greater than 0% of the set pressure.
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38. In accordance with the ASME Code, liquid service pressure relief valves installed after this date have to have their capacity certified and stamped on the nameplate? a. b. c. d.
January 1, 1990 January 1, 1986 January 1, 1998 January 1, 1989
39. What is the relieving capacity used as the basis for the application of a pressure relief device determined in accordance with the applicable code or regulation? a. b. c. d.
Rated relieving capacity. Stamped relieving capacity. The set pressure The specified burst pressure.
40. When inspecting reverse acting rupture disk that utilizes knife blades, what should the inspector look for? a. A reduction of the void between the knife blades and the disk. b. The inspector should verify the orientation of the knife blades. c. Misalignment between the diaphragm and knife blades, which can cause the reduction of the available cutting surface. d. Dulling of the knife edges, which could cause the knife not to sever the disk.
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API 510 ANSWER KEY
1. 2. 3. 4. 5. 6. 7. 8. 9. 10. 11. 12. 13. 14. 15. 16. 17. 18. 19. 20.
b (Para. 1.1) d (Para. 1.1) c (Para. 1.2.2) a (Para. 3.2) c (Para. 3.4) b (Para. 3.10) d (Para. 3.17) c (Para. 4.3) b (Para. 5.1) a (Para. 5.2) b (Para. 5.3) b (Para. 5.4) b (Para. 5.5) a (Para. 5.5) c (Para. 5.6) A) d B) a (Para. 5.7) a (Para. 5.7) b (Para. 6.1) c (Para. 6.3) a (Para. 6.4)
21. 22. 23. 24. 25. 26. 27. 28. 29. 30. 31. 32. 33. 34. 35. 36. 37. 38. 39. 40.
b a d b a c c c c d c d c b d b d b b d
(Para. 6.4) (Para. 6.4) (Para. 6.4) (Para. 6.5) (Para. 6.6) (Para. 6.6) (Para. 6.6) (Para. 6.7) (Para. 7.1) (Para. 7.1.1) (Para. 7.1.2) (Para. 7.1.3) (Para. 7.2) (Para. 7.2.1) (Para. 7.2.2) (Para. 7.2.3.1) (Para. 7.2.3) (Para. 7.2.5) (Para. 7.2.6) (Para. 7.2.7)
41. 42. 43. 44. 45. 46. 47. 48. 49. 50. 51. 52. 53. 54. 55. 56. 57. 58. 59. 60.
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b b a c d c a a d c d d b c b d c d b a
(Para. 7.2.8) (Para. 7.2.9) (Para. 7.2.10) (Para. 7.3) (Para. B.5.1) (Para. 3.18) (Para. 6.4) (Para. 6.4) (Para. 6.2) (Para. 6.2) (Para. 6.2) (Para. B.5 (Para. 7.2.8) (Para. 6.6) (Figure 7-1) (Para. 3.19) (Para. 7.1.1) (Para. 7.2.3.1) (Para. 6.5) (Para. 6.7)
61. 62. 63. 64. 65. 66. 67. 68. 69. 70. 71. 72. 73. 74. 75.
76. 77. 78.
a (Para. 6.4) d (Para. 5.2) b (Para. 6.4) c (Para. 3.18) a (Para. 1.2.2) d (Para.7.2.5 note) b (Para. 7.3) a (Para. 6.4) b (Para. 5.5) d (Para. 7.2.2) c (Forward) a (Para. 3.15) b (Para. 5.3) b (Para. 6.5 note) b (Appendix B – B.2.3) c (Para. 5.5) c (Para. 5.8) d (Para. 3.21)
API 572 ANSWER KEY
1. 2. 3. 4. 5. 6. 7. 8. 9. 10. 11. 12. 13. 14. 15. 16. 17. 18. 19. 20.
a d a d a c b b b a c d a b b d d a c a
(Para. 4.2.2) (Para. 4.2.3) (Section 6) (Para. 7.1) (Para. 8.2.3) (Para. 8.2.2) (Para. 8.5) (Para. 10.3.2) (Para. 10.4.3) (Para. 10.5) (Para. 10.5) (Para. 8.5.3) (Para. 8.3.7) (Para. 10.4.4) (Para. 10.3.7) (Para. 8.2.8) (Para. 10.3.3) (Section 11) (Para. 8.2.2) (Para. 12.1)
21. 22. 23. 24. 25. 26. 27. 28. 29. 30. 31. 32. 33. 34. 35. 36. 37. 38. 39. 40.
d (Para. 10.9) d (Para. 10.3.9) b (Para. 10.4.4) b (Para. 8.5.2) b (Para. 8.3.3) b (Para. 8.2.10) a (Para. 10.3.8) b (Para. 9.3) c (Para. 7.1) d (Section 5) a (Para. 10.9) c (Para.10.3.13) d (Para. 8.3.1) b (Para. 10.4.3) d (Para. 10.3.13) d (Para. 8.2.6) b (Para. 10.3.7) d (Para. 8.3) c (Para. 10.5) a (Para. 10.3.13)
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41. 42. 43. 44. 45. 46. 47. 48. 49. 50. 51. 52. 53. 54. 55. 56. 57. 58. 59. 60.
b (Para. 8.3) a (Para. 8.5.7) a (Para. 10.4.4) d (Para. 10.4.6) d (Para. 10.3.3) b (Para. 4.1) d (Para. 10.3.8) c (Para. 10.3.10) b (Para. 10.8.1) a (Para. 4.3) b (Para. 8.2.1) b (Para. 10.4.5) c (Para. 10.4.4) b (Section 5) d (Para. 8.2.4) b (Para. 10.3.12) a (Para. 10.8.3) c (Para 9.1) a (Para. 10.3.2) d (Para. 10.8.2)
API RP 576 ANSWER KEY 1. 2. 3. 4. 5. 6. 7. 8. 9. 10. 11. 12. 13. 14. 15. 16. 17. 18. 19. 20.
d (Para. 4.2) c (Para. 4.3) c (Para. 4.4) b (Para. 4.6) b (Para. 4.2 – 4.6) b (Section 5) a (Para. 6.4) b (Para. 6.4) a (Para. 6.3) d (Para. 6.2.8) b (Para. 3.1.1) d (Figure 37) b (Para. 4.3.2) a (Para. 4.5) a (Para. 5.8.3) d (Section 5) b (Para. 5.4) a (Para. 5.8.1) c (Para. 4.9.2) b (Para. 6.1)
21. 22. 23. 24. 25. 26. 27. 28. 29. 30. 31.
32. 33. 34.
35. 36. 37. 38. 39. 40.
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c (Para. 4.2) b (Para. 6.2.4) d (Para. 7.1) d (Para. 5.3) a (Para. 4.8) b (Para. 6.4.2) a (Para. 4.9.3) c (Para. 6.5.1) d (Para. 4.9.2) a (Para. 6.2.21) b (Para. 4.6.1) & (Para. 5.5) b (Para.3.2.2) b (Para. 4.9.1.1) a (Para. 6.2.9 Caution Note) d (Para. 4.9.3) c (Para. 5.4) a (Para. 6.2.14) b (Para. 4.3) a (Para. 3.3.6) d (Para. 4.9.1.4)
EXTERNAL PRESSURE CHARTS CHARTS AND TABLES FOR DETERMINING SHELL THICKNESS OF COMPONENTS UNDER EXTERNAL PRESSURE
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(Fig.G)
GEOMETRIC CHART FOR COMPONENTS UNDER EXTERNAL OR COMPRESSIVE LOADINGS ( for All Materials ).
367
(Fig.G)
GEOMETRIC CHART FOR COMPONENTS UNDER EXTERNAL OR COMPRESSIVE LOADINGS ( for All Materials ) -- continue.
368
(Fig.CS-1)
CHART FOR DETERMINING SHELL THICKNESS OF COMPONENTS UNDER EXTERNAL PRESSURE WHEN CONSTRUCTED OF CARBON OR LOW ALLOY STEELS ( Specified Minimum Yield Strength 24,000 psi to, but not including, 30,000 psi ).
369
(Fig.CS-2)
CHART FOR DETERMINING SHELL THICKNESS OF COMPONENTS UNDER EXTERNAL PRESSURE WHEN CONSTRUCTED OF CARBON OR LOW ALLOY STEELS ( Specified Minimum Yield Strength 30,000 psi and Over Expect for Materials within this Range where other specific Charts are Referenced ) AND TYPE 405 AND TYPE 410 STAINLESS STEELS.
370
(Fig.CS-3)
CHART FOR DETERMINING SHELL THICKNESS OF COMPONENTS UNDER EXTERNAL PRESSURE WHEN CONSTRUCTED OF CARBON STEEL, LOW ALLOY STEELS, OR STEELS WITH PROPERTIES ENHANCED BY HEAT TREATMENT ( Specified Minimum Yield Strength Over 38,000 psi for Materials where other specific Charts are not Referenced ).
371
(Fig.CS-4)
CHART FOR DETERMINING SHELL THICKNESS OF COMPONENTS UNDER EXTERNAL PRESSURE WHEN CONSTRUCTED OF SA-537.
372
(Fig.CS-5)
CHART FOR DETERMINING SHELL THICKNESS OF COMPONENTS UNDER EXTERNAL PRESSURE WHEN CONSTRUCTED OF SA-508 CLASS 1 GRADE 2 AND 3; SA-508 CLASS 2 GRADE 2; SA-533 CLASS 1 GRADES A, B, C& D; SA-533 CLASS 2 GRADES A, B, C AND D; OR SA-541 GRADES 2 AND 3.
373
(Fig.CS-6)
CHART FOR DETERMINING SHELL THICKNESS OF COMPONENTS UNDER EXTERNAL PRESSURE WHEN CONSTRUCTED OF SA-562 OR SA-620 CARBON STEEL.
374
(Fig.HT-1)
CHART FOR DETERMINING SHELL THICKNESS OF COMPONENTS UNDER EXTERNAL PRESSURE WHEN CONSTRUCTED OF QUENCHED AND TEMPERED LOW ALLOY STEEL, SA-517 ALL GRADES, AND SA-592 GRADES A, E, AND F WHERE t ≤ 2½ in.
375
(Fig.HT-2)
CHART FOR DETERMINING SHELL THICKNESS OF COMPONENTS UNDER EXTERNAL PRESSURE WHEN CONSTRUCTED OF QUENCHED SA-508 GRADE 4N, CLASS 2 OR SA-543 TYPES B AND C, CLASS 2.
376
(Fig.HA-1)
CHART FOR DETERMINING SHELL THICKNESS OF COMPONENTS UNDER EXTERNAL PRESSURE WHEN CONSTRUCTED OF AUSTENITIC STEEL (18Cr-8Ni, Type 304).
377
(Fig.HA-2)
CHART FOR DETERMINING SHELL THICKNESS OF COMPONENTS UNDER EXTERNAL PRESSURE WHEN CONSTRUCTED OF AUSTENITIC STEEL [16Cr-12Ni-2Mo, Type 316; 18Cr10Ni-Ti, Type 321; 18Cr-10Ni-Cb, Type 347; 25Cr-12Ni, Type 309 (Through 1100ºF Only); 25Cr20Ni, Type 310; and 17Cr, Type 430B Stainless Steel (Through 700ºF Only)].
378
(Fig.HA-3)
CHART FOR DETERMINING SHELL THICKNESS OF COMPONENTS UNDER EXTERNAL PRESSURE WHEN CONSTRUCTED OF AUSTENITIC STEEL (18Cr-8Ni-0.035 Maximum Carbon, Type 304L).
379
(Fig.HA-4)
CHART FOR DETERMINING SHELL THICKNESS OF COMPONENTS UNDER EXTERNAL PRESSURE WHEN CONSTRUCTED OF AUSTENITIC STEEL (18Cr-8Ni-Mo-0.035 Maximum Carbon, Type 316L and 317L).
380
(Fig.HA-5)
CHART FOR DETERMINING SHELL THICKNESS OF COMPONENTS UNDER EXTERNAL PRESSURE WHEN CONSTRUCTED OF Cr-Ni-Mo Alloy S31500.
381
(Fig.HA-6)
CHART FOR DETERMINING SHELL THICKNESS OF COMPONENTS UNDER EXTERNAL PRESSURE WHEN CONSTRUCTED OF 21Cr-11Ni-N Alloy S30815.
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