IN15-1101 JTP Proposed Alternate Q&R Rev 2 final 2016-07-20 120IN16-0101 Explosion Plugging of HX Tubes R1 7-21-16 final MC 121IN16-0601 Rev 2 7-20-2016 Final 122NB11-0204B 1-12-16 Pt 3 Suppl 2 NDE updates RVU Formated WV 7-19-2016 (2) (1) 124NB13-0902 formated WV 7-13-2016 Final (1) 135NB14-0301 Boseo 5-16-16 Encap Final MC 7-21-16 (1) 138NB15-0512 SG Graphite 4-6-16 final 139NB15-2206B final7-20-2016 141NB15-2207 SG Graphite 4-6-16 final 142NB15-2305 Troutt 4-27-16 Footnote MC Final 143NB15-2801_NBIC Part 3_Para 4.2 b) Rev 3 final 7-19-2016 157NB15-2901 ASME Historical Boiler Final 7-20-16 159NB16-0602 7-18-16 final (1) 160NB16-0606 Withers 7-18-16 (2) 161NB16-0701 Sekely 7-20-16 final 162NB16-0809B Besserman 7-20-16 Final (2) 168NBIC Item 16-1101 Supplement 11 Rev-2 7-20-2016 Final to MC 172Update of Alternative Weld Repairs in Grade 91 Steel 180NB16-1102 2.5.3 d 7-19-2016 WV final 191NB16-1301 SG Graphite 4-7-16 final 192NB16-2101 Wielgoszinski 7-15-16 (1) final 193NB16-2502,03,05 Loco 7-20-16 final 198NB16-2601 -Plugging of HX Tubes FINAL 7-20-16 200
August 15th – Submit Public Review Document to ANSI
August 26th – Public Review period begins
September 22th‐23st – Practice WebEx sessions
October 10th – Public Review period ends
October 19th‐20th – SC Public Review WebEx sessions
o October 19th, 11am – SC Installation
o October 19th, 2pm – SC Inspection
o October 21st, 11am – SC PRD
o October 20th, 2pm – SC Repairs and Alterations
October 25th, 1pm – Main Committee Public Review WebEx session
December 7th, 1pm – Main Committee Final Approval WebEx session
January 2017 – Approved document submitted to internal publishing department
May 2017 – Finished document submitted to printers
July 1st, 2017 – 2017 NBIC available for purchase
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2017 NBIC Publication Schedule
David M Buechel AVP Inspection Services
Hartford Steam Boiler I&I Co. 4300 Seton St. Pittsburgh, PA 15227
412-885-8120
Professional Experience
The Hartford Steam Boiler Inspection and Insurance Company- 1980 – Present
Manage inspection activity in twelve jurisdictions (CT, DE, MA, ME, NH, NJ,
NY, PA, RI, VT, WV, and Washington, DC). Maintain direct contact with Chief Inspectors in these jurisdictions. Manage four supervisors, and fifty-four inspectors. Developed and implemented work scheduling system. Conducted risk assessments and claim investigations. Served as full-time Authorized Inspector at a Japanese vessel fabrication facility. Conducted Boiler Useful Life studies. Developed and maintain on-line manuals for HSB system and training Conducted NB-369 audits
US Navy 1974 – 1976
Honorably discharged Achieved rank of Machinist Mate first class Engine Room supervisor
Commissions
National Board Commission # 9539 Active state Commissions in MD (#1282 ), and PA (# 2390 ) Inactive commissions in NY (#5171), OH (Ohio), and WV (#1110)
Education
High School graduate St. Joseph’s High School, Pittsburgh, PA US Navy Nuclear Propulsion School Machinist Mate A-School
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David M Buechel Resume 7-19-16
Bryce A. Hart 1030 Alexander Drive, Temple, PA 19560
SUMMARY I am a risk engineering technical director with more than 15 years of experience in the insurance equipment breakdown discipline. I have demonstrated collaboration in the development of products to improve our customers risk and meet the needs of our underwriting partners. As a risk engineering manager, I have led my staff to improve their efficiency and productivity while maintaining high quality service. I have proven my abilities in planning and managing projects throughout my career, improving operational efficiencies, team building, and project analysis to determine effective and efficient processes. EXPERIENCE: Zurich North America AVP, Machinery Breakdown Technical Director – March 2016 to Present Regional Risk Engineering Manager – June 2013 to March 2016 Midatlantic Region Portfolio Engineer – December 2006 thru June 2013 Midatlantic Region MB Field Staff – May 2005 thru June 2013
Currently responsible for determining the direction of our Machinery Breakdown team with
respect to emerging risks, new technologies, and ensuring compliance with the rules and regulations of the National Board and the jurisdictions where we perform our service.
Previously served as the Boiler & Machinery Northeast Regional Manager (since June 2013), leading a team of 10 staff members.
Performing monthly conference calls with the regional staff and biweekly individual calls to ensure all appropriate guidance is understood and implemented, and to allow team building within the regional staff.
Directing the ASME and National Board Inspection Code activity within the Northeast Team to meet the jurisdictional inspection requirements of the region.
Developed an education program for our underwriting partners, improving Equipment Breakdown Underwriting technical acumen and aiding in building collaboration with the MB staff.
Developed and implemented methods to ensure compliance with complex regulatory requirements, and empowered his staff to take the lead in their areas of responsibility.
Provided leadership in the servicing of a major EB reinsurance customer, including analyzing their needs for additional services that lead to the development and implementation of our Observe and Report.
As the Portfolio Engineer for the Midatlantic region I provided analysis of prospect and renewal accounts and collaborated with the RE property staff in this region, providing direction and support to our customers and business partners.
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Bryce Hart Resume 7-19-16
J. C. Penny, Inc. November, 2002 to April 2005 Maintenance Manager Analyzed utility usage and instituted a program that saved more than $20,000 per month in
utility bills. Aggressively pursued solutions to improve the operational accuracy and consistency of the
sortation equipment. Implementing these solutions improved the operational accuracy to more than 99.8%, and reduced the rework caused by these inaccuracies by 90%.
Managed and scheduled a department of eighteen mechanics and housekeepers. This included interviewing, hiring, evaluating and terminating employees, ensuring company policies were adhered to.
Managed the maintenance department and warehouse supplies budgets, both closing the fiscal year below the forecasted budgets. .
R-V Industries, Inc. August, 2000 to October, 2002 Project Manager Managed construction and fabrication projects for this ASME Code shop/specialty metal
fabrication facility. At the height of activity, I managed eight projects with a combined value of $5.1 million in four separate fabrication facilities.
Developed several models for analysis of labor, material, and overhead costs in four manufacturing facilities. Using these models reduced the time for data acquisition by 96%, and increased the project manager productivity by 20%.
Hartford Steam Boiler Inspection & Insurance Company April, 1995 to August, 2000 Program Manager and Inspector Business Unit Manager for the Technical Resource Support Group, performing all duties
required to operate this three person stand-alone business unit. Performed shop and field repair inspections for LJE Brunner and Potts Boiler Repair in
Delaware. Grew the annual revenue 300% in three years. Coordinated and supervised the activities of up to 39 inspectors operating in six countries. MILITARY: U. S. Navy October, 1980 to July, 1994 Chief Electronics Technician/Nuclear Operator Assistant Engineering Officer on Submarine NR-1: Developed a Nuclear Refueling Test Plan
for Bettis Atomic Power Laboratory which included training of test personnel, scheduling of
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Bryce Hart Resume 7-19-16
ships force and civilian contractor personnel for testing, obtaining necessary test equipment, and supervising the conduct of the testing. Testing completed 7 shifts ahead of schedule.
Education: Industrial Technology Bachelor of Science, Southern Illinois University at Carbondale, December 2000 Credentials: National Board of Boiler & Pressure Vessel Inspectors Commissioned Boiler Inspector #11747 Commissioned Boiler & Pressure Vessel Inspector in Pennsylvania, New Jersey, New York, and Delaware.
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Bryce Hart Resume 7-19-16
NB-240, Proposed Rev. 14 Page 1 of 21
National Board Inspection Code Procedure
Approved by NBIC Committee: Approved by the Board of Trustees: Approved by ANSI:
The National Board of Boiler & Pressure Vessel Inspectors
1055 Crupper Avenue Columbus, OH 43229-1183
Phone: (614)888-8320
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NB-240 Proposed Rev. 14 7-13-16 FINAL
NB-240, Proposed Rev. 14 Page 2 of 21
Table of Contents 1.0 Purpose .............................................................................................................................................. 3
8.5 General .................................................................................................................................. 19
9.0 Due Process ..................................................................................................................................... 19
10.0 Records ............................................................................................................................................ 20
1.0 Purpose This procedure defines the organization, scope, duties and responsibilities of the NBIC Committee, subcommittees, subgroups and task groups. The NBIC Committee is established by the National Board of Boiler and Pressure Vessel Inspectors (NBBPVI) Board of Trustees for the purpose of maintaining the NBIC. The NBIC CommitteeNBBPVI is accredited by ANSI as a “developer of American National Standards” in accordance with the ANSI Essential Requirements. This procedure also describes the administrative process for the publication of the National Board Inspection Code. Revisions to this procedure must be approved by the NBIC Committee, the Board of Trustees, and ANSI. A copy of this procedure or any referenced document is either available on the National Board’s Web site: www.nationalboard.org or may be obtained from the NBIC secretary.
2.0 Responsibilities
The Executive Director of the National Board is responsible for ensuring that the requirements of this procedure are met. The Secretary of the NBIC Committee is responsible for the day-to-day implementation of this procedure. Other responsibilities are described throughout this procedure.
3.0 Definitions
The following are terms and their definitions used throughout this document. ANSI American National Standards Institute
Board The Board of Trustees of the National Board
Code The National Board Inspection Code (NBIC)
committee The NBIC Committee and all subcommittees, groups and task
groups
NBIC Committee The NBIC Main Committee, accredited by ANSI as the is the final consensus body for the purpose of approving American National Standards
National Board The National Board of Boiler and Pressure Vessel Inspectors (NBBPVI) is the ANSI-Accredited Standards Developer
NB Mark A National Board Code Symbol Stamp
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NBIC The National Board Inspection Code which was established to provide rules and guidelines for the repair, alteration, inspection, installation, maintenance and testing of boilers, pressure vessels and other pressure retaining items.
project manager Individual assigned the responsibility for developing, monitoring and responding to technical items.
subcommittee A unit established to address recurring functions, address specific issues or maintain specific sections of the NBIC. A subcommittee is established by the NBIC Committee. Each subcommittee will follow rules for consensus approval insofar as possible but is not considered the final consensus body for the purpose of approving American National Standards.
subgroup A unit established to address recurring topics or functions specific to a subcommittee. A subgroup is established by the NBIC Committee. Subgroup actions are reported to the subcommittee for approval.
task group A unit established to address a specific topic. A task group may be established by the NBIC Committee, subcommittee or subgroup.
4.0 Committee Structure
The committee structure consists of the NBIC Committee, subcommittees, and subgroups appointed by the NBIC Committee and task groups appointed by the NBIC Committee, a subcommittee or subgroup. The duties, responsibilities and administration of each are described below.
4.1 NBIC Committee
4.1.1 Responsibilities
The NBIC Committee is responsible for:
a. approving new rules and revising existing rules of the Code and voting
on such additions and revisions;
b. approving interpretations of the rules of the Code;
c. hearing requests for reconsideration regarding interpretations and revisions to the Code;
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d. acting on any matter related to the scope of the Code as may be assigned by the Board.
4.1.2 Membership
The NBIC Committee shall consist of not more than twenty-six (26) voting members within the interest categories described in paragraph 4.5.
a. At least one individual representing manufacturers shall be employed by
a manufacturer of safety relief devices.
b. At least one individual representing National Board Certificate Holders shall be employed by an organization holding a valid “R” Certificate of Authorization.
c. At least one individual representing National Board Certificate Holders shall be employed by an organization holding a valid “VR” Certificate of Authorization.
d. Not more than one-third of the total NBIC Committee membership shall represent any single category of interest. The chair and vice chair of the NBIC Committee are considered within this membership. The secretary is a member of the NBIC Committee without vote.
e. Each member of the NBIC Committee may recommend a person, within the same interest category, as a representative to serve in the absence of the member at a specific meeting. Representatives have the same privileges and responsibilities as the member when serving in the member’s capacity. The representative’s involvement terminates at the conclusion of the specific meeting requested by the member.
f. Upon change of employment status affecting the member’s category of interest, NBIC Committee members shall notify the NBIC Committee secretary and will be deemed to have submitted their resignations from the NBIC Committee. Reappointment to the NBIC Committee shall follow the requirements of paragraph 4.1.3.
4.1.3 NBIC Committee Member Selection, Approval, and Term
a. A candidate for appointment or reappointment as a voting member of the
NBIC Committee is selected by a majority vote of the NBIC Committee membership. The candidate’s name is then submitted to the Chairman of the Board for consideration. All voting members of the NBIC Committee must be appointed by the Chairman of the Board.
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b. A candidate for appointment or reappointment as the NBIC Committee Chair or Vice Chair is selected by a majority vote of the NBIC Committee membership. The candidate’s name is then submitted to the Chairman of the Board for consideration. The chair and vice chair must be appointed by the Chairman of the Board.
c. The NBIC Committee secretary is selected by the Executive Director of the National Board and is considered to be a non-voting member of the NBIC Committee without any interest affiliation.
d. The term of all voting members is three (3) years. Voting members are eligible for reappointment.
e. The term for the chair and vice chair is the same as their NBIC Committee membership expiration date. The chair and vice chair are eligible for renewal of their terms of office.
f. A candidate for membership on the NBIC Committee must provide a work history/resume to the NBIC Committee secretary.
4.2 Subcommittees
4.2.1 Responsibilities
Subcommittees are responsible for:
a. maintaining (adding new requirements, revising existing requirements)
those sections of the NBIC that are assigned to the subcommittee.
b. acting on requests for interpretations of the rules for those assigned sections of the NBIC;
c. acting on any matter related to the scope of the NBICas may be assigned by the NBIC Committee;
d. forwarding all subcommittee actions to the NBIC Committee.
4.2.2 Membership
a. The number of members appointed to each subcommittee shall be as necessary to carry on the assigned responsibility. The size of subcommittees will be limited to numbers which will best serve operational needs.
b. Each member of the NBIC subcommittee may recommend a person, within the same interest category, as a representative to serve in the
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absence of the member at a specific meeting. Representatives shall have the same privileges and responsibilities as the member when serving in the member’s capacity. The representative’s involvement automatically terminates at the conclusion of the specific meeting requested by the member.
c. Upon change of employment status affecting the member’s category of interest, NBIC Subcommittee members shall notify the NBIC Committee secretary and will be deemed to have submitted their resignations from the subcommittee. Reappointment to the NBIC Subcommittee shall follow the requirements of paragraph 4.2.3.
4.2.3 Subcommittee Member Selection, Approval and Term
a. A candidate for appointment or reappointment as a voting member of the
subcommittee is selected by majority vote of the NBIC Committee membership. Subcommittee members need not necessarily be members of the NBIC Committee or subgroup. The candidate’s name is then submitted to the Chairman of the Board for consideration. All voting members of the subcommittee must be appointed by the Chairman of the Board.
b. Candidates for appointment or reappointment as the subcommittee chair and vice chair are selected by a majority vote of the subcommittee membership. The candidate’s names are then submitted to the Chairman of the Board for consideration. The chair and vice chair must be appointed by the Chairman of the Board.
c. The subcommittee secretary is a member of the subcommittee without vote and is selected by the Executive Director of the National Board.
d. The term for all voting members is three (3) years. Voting members are eligible for reappointment.
e. The term for the chair and vice chair is the same as their subcommittee membership expiration date. The chair and vice chair are eligible for renewal of their terms of office.
f. A candidate for membership on the subcommittee must provide a work history/resume to the NBIC Committee secretary.
4.3 Subgroups
4.3.1 Responsibilities
Subgroups are responsible for:
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a. developing new rules and revising existing rules for specific Code
sections or paragraphs;
b. acting on requests for interpretations of the rules for specific Code sections or paragraphs;
c. acting on any matter related to the scope of the Code as may be assigned by the committee or subcommittee;
d. forwarding all subgroup actions to the subcommittee, as appropriate
4.3.2 Membership
The number of members appointed to each subgroup shall be as necessary to carry out the assigned work. The size of subgroups will be limited to numbers to best serve operational needs.
4.3.3 Subgroup Member Selection, Approval and Term
a. A candidate for appointment or reappointment as a member of the
subgroup is selected by the majority vote of the subcommittee membership. Subgroup members need not necessarily be members of the Committee or subcommittee. The candidate’s name is then submitted to the Chairman of the Board for consideration. All voting members of the subgroup must be appointed by the Chairman of the Board.
b. Candidates for appointment or reappointment as subgroup chair and vice chair are selected by a majority vote of the subcommittee membership. The chair and vice chair of each subgroup shall be appointed by the NBIC Committee ChairChairman of the Board.
c. The subgroup secretary is selected by the Executive Director of the National Board and is a member of the subgroup without vote. In the absence of a selected secretary, the subgroup chair may appoint a voting member of the subgroup to act as secretary.
d. The term for all voting members is for three years. Voting members are eligible for reappointment.
e. The term for the chair or vice chair is the same as their membership expiration date and these positions are eligible for renewal.
f. The name of a National Board Member who is a candidate to serve on a subgroup, but is not a member of the NBIC Committee or a
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subcommittee, must be submitted to the Chairman of the Board for approval.
g. A candidate for membership on a subgroup must provide a work history/resume to the NBIC Committee secretary.
4.4 Task Groups
4.4.1 Responsibilities
Task groups are responsible for:
a. developing new rules and revising existing rules for specific Code topics
or paragraphs;
b. acting on requests for interpretations of the rules for specific Code topics or paragraphs;
c. acting on any matter related to the scope of the Code as may be assigned by committees;
d. forwarding all task group actions to the committee as appropriate.
4.4.2 Membership
The number of members appointed to each task group shall be as necessary to carry out the assigned task. The size of task groups will be limited to numbers which will best serve operational needs.
4.4.3 Task Group Members Selection, Approval, and Term
a. When the committee agrees on the need or at the discretion of the chair
of a committee, a task group, members, and chair shall be appointed by the committee chair. A member of the task group may be appointed as task group secretary by the task group chair. Task group members need not necessarily be members of a committee.
b. The name of a National Board Member who is a candidate to serve on a
task group, but is not a member of the NBIC Committee or a subcommittee, must be submitted to the Chairman of the Board for approval.
b.c. The task group will be dismissed once the task has been completed or at
the discretion of the chair of the committee.
4.5 Interest Categories
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NBIC Committee, subcommittee, subgroup and task group members shall not be considered as representing any specific organization. Participation by individuals employed by governmental agencies or affiliated with industry is not to be interpreted as government or industry endorsement. Membership shall be selected from the categories of interest listed below.
a. General Interest: Individuals who are not employed by an organization
characterized by b through h shall be considered General Interest.
b. Manufacturers: Any organization accredited by ASME to hold an ASME Code symbol stamp.
c. Authorized Inspection Agency: An authorized (insurance) inspection agency recognized by the National Board.
d. Jurisdictional Authorities: National Board members.
e. National Board Certificate Holders: Repair organizations accredited by the National Board to hold “R”, “NR” or “VR” certification.
f. Users: Owners or users of boilers/pressure vessels.
g. Labor: Individuals representing labor organizations whose members are skilled workers in boiler or pressure vessel manufacturing or repairing, such as the United Association of Journeymen and Apprentices of Plumbing and Pipe Fitting Industry of the United States and Canada or the International Brotherhood of Boilermakers, Ship Builders, Blacksmiths, Forgers and Helpers.
h. Regulatory Authorities: Representatives of US Governmental agencies that regulate boilers or pressure vessels or both.
Lack of any particular representative of any interest category at a meeting shall not preclude the committee from conducting its business when a quorum is present.
5.0 Duties of NBIC Committee, Subcommittee, Subgroup and Task Group Membership
5.1 Chair
The chair shall preside at meetings of the committee and shall perform other duties as are customarily assigned to that position.
The chair of the NBIC Committee shall make an annual review of the activity of each voting member of the NBIC Committee, subcommittee and subgroup with regard to the member’s contribution to the work, attention to correspondence, and
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attendance at meetings. Based on this review, if a consistent lack of attendance or participation within the past year is noted, the chair may recommend to the Chairman of the Board that the member’s appointment to the NBIC Committee be terminated. The chair’s report of NBIC Committee member’s activities shall be sent to the Chairman of the Board and the Executive Director of the National Board.
5.2 Vice Chair
The vice chair shall, in the absence of the chair, fulfill the duties of the chair.
5.3 Secretary
In addition to the responsibilities required by this procedure, the Secretary shall prepare agendas and record minutes of meetings and shall perform such other duties as are customarily assigned to such an office. In the absence of the chair and vice chair at a meeting, the secretary shall take the chair for the purpose of receiving nominations from the members present for election of a chair pro tem, who shall then preside at the meeting.
5.4 Members
The duty of each member is to give thorough consideration to each subject brought before the committee for action, vote on acceptance or rejection of each proposal, and assist generally in carrying out the assigned functions. Such duties may be carried out by attendance at meetings, by correspondence, and by telephone.
6.0 Meetings
6.1 Scheduled Meetings
NBIC Committee meetings shall be held at the call of the Chair, as decided upon by a majority of NBIC Committee members, or as directed by the Chairman of the Board. Subcommittee, subgroup and task group meetings held at times and locations other than in conjunction with the NBIC Committee meeting shall require the approval of the National Board Executive Director. Meeting requests shall be in writing to the Executive Director and include the subcommittee, subgroup or task group members’ roster.
6.2 Locations
The NBIC Committee shall meet in National Board member jurisdictions.
6.3 Meeting Notification
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All committee meeting schedules shall be posted on the National Board web site. The National Board member in whose jurisdiction the NBIC Committee is meeting shall be invited to attend the meeting. A meeting agenda shall be made available to the members prior to the meeting and shall be subject to approval at the commencement of each meeting.
6.4 Public Meetings
Meetings at which the committee considers proposed revisions to the NBIC, reaffirmation of previously considered revisions or withdrawal of previously approved revisions shall be open to the general public. Unless matters to be discussed by the committee are deemed to be of a confidential nature by the chair, committee meetings shall be open to any interested person who shall be given an opportunity to participate in the discussions on subjects of interest to them.
6.5 Quorum
Fifty-one percent of the NBIC Committee, subcommittee or subgroup voting membership eligible to vote must be present to conduct committee business.
6.6 Meeting Conduct
The committee shall conduct meetings in accordance with the latest available edition of Roberts Rules of Order (Revised) unless rules to the contrary are specified in these procedures.
6.7 Recording Meeting Proceedings
Taping of committee meetings, other than by the secretary, is prohibited.
6.8 Minutes
All meetings of the NBIC Committee, subcommittees and subgroups shall be documented in minutes of the meeting. The minutes are not to be considered a verbatim record of the meeting but rather a record of the voted actions and highlights of significant discussions or conclusions. The title page of committee minutes shall include the following statements:
“These minutes are subject to approval and are for committee use only. They are not to be duplicated or quoted for other than committee use.”
Minutes of committee meetings will be distributed to the members of the committees, the Executive Director, National Board members and Advisory Committee members, as requested. Copies of committee minutes will be made
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available on the National Board’s Web site for review until the next scheduled meeting minutes are available.
7.0 Voting
7.1 General
7.1.1 Each committee member shall exercise their vote within the presented time limits. When a committee member fails to report when due, or consistently abstains from voting, the committee member’s appointment shall be subject to termination. The individual may appeal such action. Committee members are encouraged to vote as soon as possible.
7.1.2 Votes for committee actions may be obtained by letter, fax, recorded votes at
meetings, or electronic means. All committee members shall have an opportunity to vote. When recorded votes are taken at meetings, the committee members who are absent shall be given the opportunity to vote.
7.1.3 The vote of each committee member shall be in one of the following
categories:
Approved Disapproved Abstention Not voting (for possible conflict of interest)
A response of not voting signifies neither approval nor disapproval and should be executed only when the committee member believes that they have a conflict of interest or potential conflict of interest and is removing themselves from the voting process. Committee members casting disapproved responses should include an alternate action that will resolve their disapproved vote. Committee members casting abstained responses should include a reason for the abstention.
7.1.4 Approval of committee actions shall be by a majority vote. Approval of the
following actions of the NBIC Committee or subcommittee shall require two-thirds (2/3) majority vote of the committee membership, excluding not voting responses:
committee procedures and interest categories reaffirmation of the NBIC as an ANSI Standard NBIC revisions interpretation of the NBIC
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scope of the NBIC Committee or subcommittee New ANSI standard
7.1.5 Voting by NBIC Committee members not present at a meeting or by letter
ballot may be obtained by letter, facsimile, or by other electronic means.
7.2 Voting at Meetings
NBIC Committee members not present at a meeting for final approval of Code revisions shall be afforded the opportunity to submit their vote within two weeks after the date of the NBIC Committee meeting. It is the responsibility of the National Board to provide the information relating to the items prior to the meeting in the form of posted Agendas. Disapproved actions at the meeting shall be placed on the Subcommittee agenda for the next scheduled meeting.
7.3 Voting by Letter Ballot
7.3.1 A letter ballot on any subject requires a response of at least fifty-one percent
of committee members eligible to vote and may be authorized by the Chair of the NBIC Committee, Chair of a subcommittee, Chairman of the Board, or a majority vote of those present and voting at a NBIC Committee or subcommittee meeting. The voting period for a letter ballot may be four (4) calendar weeks; however, in order to expedite the item, this period may be shortened to no less than two calendar weeks by the person authorizing the letter ballot. Voting periods shall be closed upon receipt of all responses, but not later than the established closing date. All letter ballots shall be coordinated by the NBIC Committee secretary.
7.3.2 At the conclusion of the letter ballot period, the NBIC Committee or
subcommittee secretary shall tally the votes and report the results to the members. If the letter ballot is disapproved, the item shall be placed on the agenda for the next meeting. All comments may be reviewed electronically by the NBIC Committee members or subcommittee members during the letter ballot period. The Project Manager shall respond in writing to all negative comments received. The response shall include a disposition to the comment, and reasons for that disposition. If a comment is submitted that does not pertain to the ballot under consideration, the comment shall be reviewed as a new revision request to the code. Upon Project Manager responses to negative comments, the letter ballot, with or without substantive revisions, shall be resubmitted for a two week time period for members to respond, reaffirm or change their original vote. Reaffirmation does not require a response during this voting period. At the conclusion of the letter ballot period, the NBIC Committee or subcommittee secretary shall tally the votes and report the
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results to the members. The Project Manager shall communicate with negative commenters in order to resolve their concerns, whenever possible.
If the required vote approval percentage is affirmative after this time period, the ballot shall be considered approved. Letter ballots not approved shall be placed on the agenda for the next scheduled meeting of the NBIC Committee or subcommittee.
7.4 Final Approval Vote
Prior to publication of a new edition of the NBIC, all substantive changes to the NBIC that have been approved by the NBIC Committee shall be gathered in a final draft standard document. A vote shall be taken by the NBIC Committee to approve the final draft standard document as the new edition of the NBIC. This vote serves as the final approval for all revisions to the NBIC. No substantive changes shall be made to the approved final draft standard unless the final draft standard is recirculated to the NBIC Committee in order to afford all members the opportunity to respond, reaffirm, or change their vote. Additionally, the draft standard shall be submitted for a second public review period if substantive changes are made to the document. If an NBIC Committee member votes ‘Disapproved’ on the final vote, that member shall submit reasons for the ‘Disapproved’ vote in writing to the NBIC Secretary. If a negative vote is received, the ballot shall be resubmitted for a two week time period for members to respond, reaffirm or change their original vote. The NBIC Secretary may communicate with the member to resolve their comment during this period. If the member remains unresolved with their ‘Disapprove’ vote after the two week reaffirmation period, the member shall be notified in writing of their right to appeal the final committee decision.
8.0 National Board Inspection Code Publication Information
8.1 ANSI Approval Process
The NBIC CommitteeNBBPVI is accredited by ANSI as a developer of American National Standards. The NBIC Committee, subcommittees, subgroups and task groups must conduct activities in accordance with this procedure and the current rules and procedures of ANSI.
8.1.1 Documentation
a. After the NBIC Committee has approved the revisions to be included in
the editiondraft standard, the secretary shall prepare and submit a Standards Action Public Review Request (BSR-8) form. A notice of all
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revisions shall be posted on the National Board’s Web site for public review and comment. This notice shall be posted for a minimum of forty five days, or a minimum of sixty days if requested by an interested party.
b. The secretary shall coordinate the disposition of public review comments with the Project Manager.
c. The disposition of all public review comments shall be approved by the NBIC Committee.
d. The commenter shall be advised, in writing, of the disposition of the public review comment and the reasons for the disposition. and t The commenter shall be notified of their’s right to appeal the NBIC Committee’s decision.
e. All NBIC Committee members shall be notified of all unresolved public review comments and attempts at resolution to afford all members an opportunity to respond, reaffirm or change their vote. Any commenter with unresolved comments shall be notified in writing of their right to appeal.
f. Resolutions involving substantive changes to approved text shall be resubmitted for public review at the next scheduled public review and comment period or a new action shall be generated to address the commentators recommended change as appropriate. No substantive changes shall be made to an approved revision unless ANSI Essential Requirements are met.
g.f. h.g.When the disposition of all comments has been completed, or if no
comments were submitted, the secretary shall prepare and submit the Formal Submittal Checklist for approval or withdrawal as an American National Standard (BSR-9) Form.
8.1.2 Secretariat
a. The National Board is the secretariat for the NBIC Committee. Its duties
include:
1. providing administrative support for the activities of the secretary, and
2. publishing and distributing the Code, minutes and interpretations approved in accordance with these procedures.
b. It shall be the responsibility of the secretary to:
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1. ensure that the NBIC Committee adheres to these and other referenced or applicable procedures,
2. apply to ANSI for accreditation of the NBIC Committee by that organization,
3. maintain a committee roster of the members which shall include names of the officers, and members, their address, business affiliation, category of interest, appointment expiration date,
4. comply with ANSI requirements for the NBIC Committee administration, and
5. submit proposed revisions to this procedure to ANSI for approval.
8.1.3 Internal Audits
At least once every three calendar years, the Executive Director of the National Board shall have an audit made of the NBIC Committee’s activities to ensure these procedures are followed. The audit shall be conducted by person(s) who are not members of the NBIC Committee. The audit report and follow-up action of deficiencies uncovered by an audit shall be reported to the NBIC Committee and the Chairman of the Board.
8.1.4 Patent Policy
The National Board shall comply with the ANSI patent policy as described in the ANSI Essential Requirements.
8.1.5 Commercial Terms
The National Board shall comply with the ANSI Commercial Terms and Conditions Policy as described in the ANSI Essential Requirements
8.1.6 Withdrawal of American National Standard
When required by ANSI Essential Requirements or the National Board elects to withdraw or discontinue an American National Standard or portion thereof, the National Board shall immediately notify ANSI for announcement in ANSI Standards Action. The National Board shall comply with all ANSI Essential Requirements for withdrawal of an American National Standard.
8.2 Revisions to the NBIC
8.2.1 Any interested person may request consideration of a revision to the NBIC
by submitting such request in writing to the secretary. If deemed editorial as determined by the secretary, requests will be incorporated into the NBIC draft edition for distribution and public review. Comments which are editorial in nature need not be submitted to the NBIC Committee or subcommittees for consideration prior to inclusion in the edition. Any public
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review comments associated with these editorial comments will be handled as such and will be considered by the NBIC Committee and subcommittee at the next scheduled meetings for final approval.
Requests which are technical in nature will be forwarded to the appropriate subcommittee for consideration and recommendations made to the NBIC Committee, for their approval. Once approved, these revisions will be incorporated into the next draft. If approval is not reached, the item will be returned to the subcommittee for further action.
8.2.2 Following approval of a revision by the NBIC Committee and acceptance
under ANSI procedures, the approved revision shall be published in the next edition.
8.3 Interpretations of the NBIC
8.3.1 The NBIC Committee has the responsibility for interpreting and replying to
questions concerning the application of NBIC rule or guideline. Any interested person may request, in writing, an interpretation of a rule or guideline contained in the NBIC through the NBIC Committee secretary.
8.3.2 Upon receipt of such a request the NBIC Committee secretary determines
which subcommittee should develop a technical response.
When responding to questions concerning the interpretation of a rule or guideline, the following is to be used as a response:
“The NBIC was developed under procedures approved by the American National Standards Institute. The NBIC Committee that approved the NBIC and revisions thereto is a consensus NBIC Committee balanced to assure that individuals from competent and concerned interests have been afforded the opportunity to participate. Further, all proposed revisions to the NBIC are made available for public review and comment which provides an opportunity for additional input from jurisdictions, industry and the public at large.”
From time to time a request for interpretation regarding a superseded edition of the NBIC may be submitted to the NBIC Committee. If in the opinion of the members of the NBIC Committee, a response can be formulated, the NBIC Committee should respond to the inquirer's question. However, when it is the consensus of the NBIC Committee that a response cannot be formulated, the NBIC Committee should respond as follows:
“The (edition of the NBIC) has been superseded. The historical knowledge that the NBIC Committee feels is needed to respond to your request for interpretation is no longer available to the NBIC Committee.”
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8.3.3 All interpretations of the NBIC shall be approved by the NBIC Committee. 8.3.4 All interpretations of the NBIC shall be posted on the National Board web
site. A written response will also be sent to the inquirer. 8.3.5 The National Board accepts responsibility for, and recognizes only those
interpretations approved by the NBIC Committee.
8.4 Publications
8.4.1 NBIC
The NBIC shall be identified as "An American National Standard" and "ANSI/NB-23" in accordance with ANSI procedures. A new edition of the NBIC shall be published every two years. Each edition shall have a date of issue. The NBIC may be used beginning with the date of issue. Six (6) months after the date of issue, the edition becomes the requirement for compliance with NBIC. Complimentary copies of the NBIC will be provided to the members of the NBIC Committee and subcommittees., subcommittees, and subgroups.
8.4.2 Forms
National Board forms are part of the standard and follow the same requirements for revision as outlined in this procedure.
8.5 General
8.5.1 Referencing Other Standards
When the NBIC Committee wishes to reference another code or standard, the date of the specific, referenced code or standard shall not be cited unless required.
8.5.2 Copyrights
Copyright and all rights in all materials produced by the committee are owned by the National Board
9.0 Due Process
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The National Board provides due process for the impartial handling of complaints regarding procedural or technical issues for any action or inaction. As part of this due process there are several levels to which an aggrieved party may appeal. This section gives criteria regarding right to appeal, how appeals are made and what may be appealed. At any level of the appeal process, there shall be no informal discussions between the body hearing the appeal and representatives of the appellant. Persons who have directly and materially affected interests and who have been or will be adversely affected by any procedural or technical action or inaction with regard to the development of a proposed American National Standard or the revision, reaffirmation or withdrawal of the NBIC have the right to appeal. Appeals shall be addressed promptly and a decision made expeditiously. The following process shall be followed:
a. Any person aggrieved by an interpretation, disposition of comments, procedural or
technical issues may appeal to the NBIC Committee.
b. The aggrieved person shall first request reconsideration by the NBIC Committee. Such request shall be in writing, addressed to the NBIC Committee secretary, and shall state the reasons for requesting reconsideration.
c. Should the person remain aggrieved following such reconsideration by the NBIC Committee or should such reconsideration be denied, the aggrieved person then, in writing, addressed to the National Board’s Executive Director, may request review by the National Board Appeals Committee. The findings of the National Board Appeals Committee operating under their procedures, shall be binding on the NBIC Committee as to the specific item under appeal and it shall be incumbent upon the NBIC Committee to consider incorporating the National Board Appeals Committee findings.
d. Should the person remain aggrieved following the National Board Appeals Committee’s decision, further appeal may be taken to the Board. Such appeal is initiated by a written request, addressed to the National Board’s Executive Director setting forth the grounds for such appeal. The appeal shall be heard at the next regular or special meeting of the Board which is held at a time of sufficient duration following such request as to allow distribution of all relevant documents and materials to the Board members. The Board, upon considering such appeal, by affirmative majority vote of those present, may allow a variance, may direct the NBIC Committee to consider a revision, or may sustain the action of the National Board Appeals Committee. The decision of the Board of Trustees on such appeal shall be final.
10.0 Records
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Records shall be retained for a minimum of five (5) years or until approval of the subsequent revision or reaffirmation of the complete standard. Records for withdrawn standards shall be retained for a minimum of 5 years after withdrawal or until the next ANSI audit, whichever is longer.
11.0 Antitrust Policy
The National Board of Boiler and Pressure Vessel Inspectors shall comply with the ANSI Antitrust Policy as described in the most current version of the ANSI Essential Requirements.
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NB15‐0103 Part 1, Section 2.9.6 c) / Part 4, 1.3.10 c) c) The opening or connection between the boiler and the safety or safety relief valve shall have at least the area of the valve inlet and the inlet pipe to the pressure relief valve shall be as short and straight as possible, no longer than the face to face twice the center-to-end (face) dimension of the a corresponding tee fitting of the same diameter, and pressure class, and connection type. When a discharge pipe is used, the cross-sectional area shall not be less than the full area of the valve outlet or of the total of the areas of the valve outlets discharging thereinto and shall be as short and straight as possible and arranged to avoid undue stresses on the valve or valves.
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SC PRD Attachments /NB15-0103 SC-PRD PASS
89
NATIONAL BOARD INSPECTION CODE2015
SECTION 5
SEC
TIO
N 5
5.12.3 CHANGES TO ORIGINAL PRESSURE RELIEF VALVE NAMEPLATE INFORMATION
a) If the set pressure is changed, the set pressure, capacity, and blowdown, if applicable, on the original nameplate or stamping shall be marked out, but left legible. The new capacity shall be based on that for which the valve was originally certified.
b) If service fluid is changed, the capacity, including units, on the original nameplate or stamping shall be marked out, but left legible. The new capacity shall be based on that for which the valve was originally certified, or if a conversion has been made, as described in NBIC Part 3, S7.2 on the capacity certifica-tion for the valve as converted.
c) If the Type/Model number is changed, the Type/Model number on the original nameplate shall be marked out, but left legible.
d) If the blowdown is changed, the blowdown on the original nameplate or stamping shall be marked out, but left legible. The new blowdown may be based on the current ASME Code requirements.
e) Incorrect information on the original manufacturer’s nameplate shall be marked out, but left legible. Cor-rected information shall be indicated on the repair nameplate and noted on the document as required by the quality system.
5.12.4 TEST ONLY NAMEPLATE
a) Where a valve has been tested and adjusted to restore the nameplate set pressure , as permitted by NBIC Part 3, S7.10.1, but not otherwise repaired, a “Test Only” nameplate shall be applied that contains the following information:
1) Name of responsible organization;
2) Date of test;
3) Set Pressure; and
4) Identification, such as “Test Only.”
b) A “Test Only” nameplate is also recommended when periodic testing has been performed, even when no adjustments have been made, for the purpose of identifying the date the valve was tested.
c) The existing repair nameplates, if applicable, shall not be removed during such testing.
5.12.5 REPLACEMENT OF ILLEGIBLE OR MISSING NAMEPLATES
a) Illegible Nameplates
When information on the original manufacturer’s or assembler’s nameplate or stamping is illegible, but traceability can be confirmed, the nameplate or stamping will be augmented by a nameplate furnished by the “VR” Stamp Holder stamped “Duplicate.” It shall contain all information that originally appeared on the nameplate or valve, as required by the applicable section of the ASME Code, except the “V,” “HV,” or “UV” symbol and the National Board mark. The repair organization’s nameplate, with the “VR” stamp and other required data specified in NBIC Part 3, 5.12.2, will make the repairer responsible to the owner and the Jurisdiction that the information on the duplicate nameplate is correct.
b) Missing Nameplates
When the original valve nameplate is missing, the repair organization is not authorized to perform repairs to the valve under the “VR” program, unless positive identification can be made to that specific valve and
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SC PRD Attachments /NB15-0304_Proposal_2016_01_13
Brandon K. Nutter
Callout
Repair organizations shall verify the Type/Model number, inlet size, set pressure, and capacity on the original nameplate or stamping that is not marked out.
Brandon K. Nutter
Text Box
NB15-0304 01/13/2016 Page 1 of 1
Brandon K. Nutter
Callout
or stamping
Brandon K. Nutter
Cross-Out
Brandon K. Nutter
Pencil
Brandon K. Nutter
Callout
or stamping
NB15‐0312 AMR Edits 2‐22‐16 Rev 3 Assigned Action: Revise potable hot water PRV requirements, and revise all hot water tank PRV inspection requirements, per Mr. Boiko’s recommendations. Boiko request #1: Add requirements for CSA stamp and rating to be used on potable water PRV. Boiko request #2: Require inspection of temperature probe on potable water PRV. Part 4, 1.5.4 (Part 1, 3.9.4) TEMPERATURE AND PRESSURE RELIEF VALVE REQUIREMENTS FOR POTABLE WATER HEATERS c) The required relieving capacity in Btu/hr (W) of the pressure relief valve shall not be less than the maximum allowable input unless the water heater is marked with the rated burner input capacity of the water heater on the casing in a readily visible location, in which case the rated burner input capacity may be used as a basis for sizing the pressure relief valves. The relieving capacity for electric water heaters shall be 3500 Btu/hr (1.0 kW) per kW of input. In every case, the following requirements shall be met. Pressure relief valve capacity for each water heater shall be such that with the fuel burning equipment installed and operating at maximum capacity, the pressure cannot rise more than 10% above the maximum allowable working pressure. Many temperature and pressure relief valves have a National Board capacity certified rating which was determined according to ASME Code requirements, and a lower Canadian Standards Association (CSA) rating value. Where the ASME Code is the only referenced Code of Construction the National Board capacity certified rating may be used. If the water heater is not an ASME vessel, or the CSA rating is required by another standard (such as a plumbing or building code) then that rating shall be used. Part 4, 2.2.6 (Part 2, 2.5.8) RECOMMENDED INSPECTION AND TEST FREQUENCIES FOR PRESSURE RELIEF DEVICES e) Water heaters Manual check every two months, or as determined based upon inspection history and manufacturer recommendations. Every 3 years, remove safety valve to inspect temperature probe for damage, buildup, or corrosion. The temperature probe shall be checked for the condition of the coating material and freedom of movement without detaching. If the probe pulls out or falls off during inspection, the valve shall be repaired or replaced. Due to the relatively low cost of safety valves for this service, it is recommended that a defective valve be replaced with a new valve if a repair or resetting is indicated.
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SUPPLEMENT 9 PROCEDURES TO EXTEND THE “VR” CERTIFICATE OF AUTHORIZATION AND STAMP TOFOR REPAIRS OF ASME “NV” STAMPED PRESSURE RELIEF DEVICES S9.1 INTRODUCTION
Approval to extend the scope of the National Board “VR” Certificate of Authorization to the Certificate Holder to use the “VR” Stamp on ASME Code “NV” Class 1, 2, or 3 stamped pressure relief devices, which have been capacity certified by the National Board, may be given subject to the provisions that follow. may be repaired provided the following requirements are met.
S9.2 ADMINISTRATIVE PROCEDURES a) The repair organization shall hold a valid “VR” Certificate of Authorization. b) The repair organization shall obtain a National Board “NR” Certificate of Authorization and stamp. The
requirements for said certificate and stamp include, but are not limited to, the following. The repair organization shall:
1) Maintain a documented quality assurance program that meets the applicable requirements of NBIC Part 3,
1.8. This program shall also include all the applicable requirements for the use of the “VR” stamp; 2) Have a contract or agreement with an Inspection Agency to provide inspection of repaired “NV”- stamped
pressure relief devices by Inspectors who have been qualified in accordance with the requirements of ASME QAI-1, Qualifications for Authorized Inspection;
3) Successfully complete a survey of the quality assurance program and its implementation. This survey shall
be conducted by representatives of the National Board, the Jurisdiction wherein the applicant’s repair facilities are located, and the applicant’s Authorized Inspection Agency. Further verification of such implementation by the survey team may not be necessary if the applicant holds a valid ASME “NV” certificate and can verify by documentation the capability of implementing the quality assurance program for repair of “NV”-stamped pressure relief devices, covered by the applicant’s ASME “NV” certificate.
c) The application of the “NR” Certificate of Authorization and stamp shall clearly define the scope of intended
activities with respect to the repair of Section III, “NV”-stamped pressure relief devices. d) Revisions to the quality assurance program shall be acceptable to the Authorized Nuclear Inspector Supervisor
and the National Board before being implemented. e) The scope of the “VR” Certificate of Authorization shall include repair of “NV”-stamped pressure relief devices. f) Verification testing of valves repaired by the applicant shall not be required provided such testing has been
successfully completed under the applicant’s “VR” certification program for the applicable test fluids. g) A survey of the applicant for the “VR” Certificate of Authorization and endorsement of the repair of “NV”-
stamped pressure relief devices may be made concurrently.
S9.3 GENERAL RULES a) ASME Code Section III, “NV”-stamped pressure relief devices, which have been repaired in accordance with
these rules, shall be stamped with both the “VR” and “NR” stamps.
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b) The “VR” and “NR” stamps shall be applied only to “NV” stamped (Class 1, 2, or 3) National Board capacity certified pressure relief devices that have been disassembled, inspected, and repaired as necessary, such that the valves’ condition and performance are equivalent to the standards for new valves.
c) All measuring and test equipment used in the repair of pressure relief devices shall be calibrated against
certified equipment having known valid relationships to nationally recognized standards. d) Documentation of the repair of “NV”-stamped pressure relief devices shall be recorded on the National Board
Form NVR-1, Report of Repair/ Replacement Activities for Nuclear Pressure Relief Devices, in accordance with the requirements of NBIC Part 3, 1.8.
e) When an ASME “NV”-stamped pressure relief device requires a duplicate nameplate because the original
nameplate is illegible or missing, it may be applied using the procedures of NBIC Part 3, 5.12.5 provided concurrence is obtained from the Authorized Nuclear Inspector and Jurisdiction. In this case the nameplate shall be marked “SEC. III” to indicate original ASME Code stamping.
f) Repair activities for pressure relief devices shall not include rerating of the device. Set pressure changes within
the range of the valve manufacturer’s capacity certification and the design pressure of the valve (see Part 3, 5.12.3) are permitted, provided the new set pressure and capacity rating are reconciled with the design of the system where the device will be used. Set pressure changes are not considered to be rerating.
g) Conversions of pressure relief devices as described in NBIC Part 3, S7.2 ba) are permitted as part of repair
activities. h) Set pressure changes or conversions of pressure relief devices shall be described in the “Remarks” section of
Form NVR-1.
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NB15‐3201 AMR edits Rev 1, 1‐14‐16 Part 2, S8.2 / Part 4 S2.2 The purpose of this action item is to correct the math in example (b). 100/1.25 = 80, not 75. I also moved the advice about blowdown from example (b) into a separate paragraph. That way, a reader who doesn’t feel the need to see the examples, because he can do math, will still see the advice about blowdown. Per Mr. Nutter’s recommendation, I added the parenthetical noting that the differential from 25% of operating pressure is equivalent to 20% of safety relief valve set pressure. Mathematically, the two are identical. That is why I use ie instead of eg. Maximum recommended boiler operating pressure = safety relief valve set pressure/125% = 80% of safety relief valve set pressure. 100% ‐ 80% = 20% differential from safety relief valve set pressure S8.2 HOT-WATER HEATING BOILERS For hot-water heating boilers, the recommended pressure differential between the pressure relief valve set pressure and the boiler operating pressure should be at least 10 psi (70 kPa), or 25% of the boiler operating pressure, whichever is greater. Two examples follow: a) If the safety relief valve of a hot-water heating boiler is set to open at 30 psi (200 kPa), the boiler operating pressure should not exceed 20 psi (140 kPa). b) If the safety relief valve of a hot water heating boiler is set to open at 100 psi (700 kPa), the boiler operating pressure should not exceed 8075 psi (5520 kPa). Section IV of the ASME Code does not require that safety relief valves used on hot water heating boilers have a specified blowdown. Therefore, to help ensure that the safety relief valve will close tightly after opening and when the boiler pressure is reduced to the normal operating pressure, the pressure at which the valve closes should be well above the operating pressure of the boiler.
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NB16‐0601 7‐18‐16
Glossary of Terms
Re‐rating (re‐rate) – See alteration. Re‐rate does not apply to pressure relief devices.
PART 4, SECTION 1 PRESSURE RELIEF DEVICES-GENERAL AND ADMINISTRATIVE REQUIREMENTS 1.1 SCOPE This Part provides guidelines and requirements for the installation, inservice inspection and testing, and repairs of pressure relief devices. 1.2 CONSTRUCTION STANDARDS FOR PRESSURE RELIEF DEVICES a) When the standard governing the original construction is the ASME Code, installation and repairs to pressure relief devices shall conform to the ASME Code section and edition most applicable to the work planned. b) If the pressure relief device was not constructed to the ASME Code, then installation, inspection and repair shall wherever possible reference the original code of construction most applicable to the work. c) If the pressure relief device was not constructed to any recognized construction code or standard, then installation, inspection, and repair shall reference a construction standard or specification most applicable to the work. d) Where this is not possible or practicable, it is permissible to use other codes, standards, or specifications, including the ASME Code, provided there is concurrence of the Inspector (if applicable) and the Jurisdiction where the pressure relief device is installed. 1.3 PRESSURE RELIEF DEVICES — DEFINITIONS Refer to glossary for definitions relating to pressure relief devices.
1.3.1 ADDITIONAL DEFINITIONS RELATING TO PRESSURE RELIEF DEVICES Unless otherwise specified in the NBIC, the definitions relating to pressure relief devices in Section 2 of ASME PTC-25 shall apply. 1.4 ACCREDITATION a) Organizations performing repairs to pressure relief valves shall be accredited as described in this section, as appropriate for the scope of work to be performed. b) Organizations performing repairs to pressure relief valves outside the scope of the NBIC may be accredited and shall meet any additional requirements of the Jurisdiction where the work is performed. 1.4.1 ACCREDITATION PROCESS a) The National Board administers accreditation programs for authorization of organizations performing repairs to pressure relief valves. b) Any organization may apply to the National Board to obtain a Certificate of Authorization for a requested scope of activities. A review shall be conducted to evaluate the organization’s Quality System. The individual assigned to conduct the evaluation shall meet the qualification requirements prescribed by the National Board. Upon completion of the evaluation, any deficiencies within the organization’s Quality System will be documented and a recommendation will be made to the National Board regarding issuance of a Certificate of Authorization.
c) National Board procedures provide for the confidential review resulting in recommendations to issue or not issue a Certificate of Authorization. d) The accreditation program provides requirements for organizations performing repairs to pressure relief valves. Depending upon the expected scope of activities at the time of review, organizations may be authorized to perform repairs either in the shop only, field only, or shop and field. Repair activities shall be limited to the scope of work authorized. e) Organizations desiring to renew or obtain a National Board Certificate of Authorization shall apply to the National Board using forms obtained from the National Board. Application for renewal shall be made prior to the expiration date of the Certificate of Authorization. f) When an organization has plants or shops in more than one location, the organization shall submit separate applications for each plant or shop. The organization may perform repairs in its plants, shops, or in the field, provided such operations are described in the organization’s Quality System.
PART 4, SECTION 12 INSTALLATION OF PRESSURE RELIEF DEVICES 12.1 INSTALLATION OF PRESSURE RELIEF DEVICESSCOPE NBIC Part 4 Section 2 provides requirements for the installation of pressure relief devices on power boilers, steam heating boilers, hot-water heating boilers, hot-water supply boilers, potable water heaters, pressure vessels and piping. The correct selection of appropriate pressure relief devices (PRDs) and the proper installation of those devices are critical to the safe operation of pressure retaining Items. Following are requirements for the installation of pressure relief devices for protection of different types of pressurized equipment. See NBIC Part 1 for general installation requirements. 1.2 PRESSURE RELIEF DEVICES — DEFINITIONS a) Pressure Relief Device: A device designed to prevent pressure or vacuum from exceeding a predetermined value in a pressure vessel by the transfer of fluid during emergency or abnormal conditions.
b) Pressure Relief Valve (PRV): A pressure relief device designed to actuate on inlet static pressure and reclose after normal conditions have been restored.
c) Safety valve: A pressure relief valve characterized by rapid opening and normally used to relieve compressible fluids.
d) Safety relief valve: A pressure relief valve characterized by rapid opening or by gradual opening that is generally proportional to the increase in pressure. It can be used for compressible or incompressible fluids.
e) Relief valve; A pressure relief valve characterized by gradual opening that is generally proportional to the increase in pressure. It is normally used for incompressible fluids.
f) Pilot operated pressure relief valve: A pressure relief valve in which the disk is held closed by system pressure, and the holding pressure is controlled by a pilot valve actuated by system pressure. 1.2.1 ADDITIONAL DEFINITIONS RELATING TO PRESSURE RELIEF DEVICES Unless otherwise specified in these rules and procedures, the definitions relating to pressure relief devices in Section 2 of ASME PTC25 shall apply. 21.32 PRESSURE RELIEF VALVES FOR POWER BOILERS See NBIC Part 1, par. 2.2 for the boilers covered under this section. 21.32.1 GENERAL REQUIREMENTS a) Only direct spring loaded safety valves, direct spring loaded safety relief valves, or pilot operated pressure relief valves designed to relieve steam shall be used for steam service.
b) Safety relief valves are valves designed to relieve either steam or water, depending on the application.
c) Pressure relief valves shall be manufactured in accordance with a national or international standard.
d) Deadweight or weighted-lever pressure relief valves shall not be used.
e) For high temperature water boilers, pressure relief valves shall have a closed bonnet, and valve bodies shall not be constructed of cast iron.
PART 4, SECTION 23 INSERVICE INSPECTION OF PRESSURE RELIEF DEVICES 23.1 INSERVICE INSPECTION OF PRESSURE RELIEF DEVICES SCOPE This section provides general guidelines and requirements for conducting inservice inspection and testing of pressure relief devices. The inspection of pressure relief devices is often coordinated with the inspection of the system. See NBIC Part 2 for inservice inspection requirements and procedures for other portions of the equipment not discussed in this section. 23.2 SCOPE GENERAL a) The most important appurtenances on any pressurized system are the pressure relief devices provided for overpressure protection of that system. These are devices such as pressure relief valves, rupture disks, and other nonreclosing devices that are called upon to operate and reduce an overpressure condition.
b) These devices are not designed or intended to control the pressure in the system during normal operation. Instead, they are intended to function when normal operating controls fail or abnormal system conditions are encountered.
c) Periodic inspection and maintenance of these important safety devices is critical to ensure their continued functioning and to provide assurance that they will be available when called upon to operate. See 23.2.6 for recommended testing frequency for PRDs.
d) Inspection areas of concern include: 1) correct set pressure; (matching of set pressure to MAWP) 2) safety considerations; 3) device data; 4) condition of the device; 5) condition of the installation; and 6) testing and operational inspection. 23.2.1 PRESSURE RELIEF DEVICE DATA a) Nameplate marking or stamping of the device should be compared to stamping on the protected pressure-retaining item. For a single device, the set pressure shall be no higher than the maximum allowable working pressure (MAWP) marked on the protected pressure-retaining item or system.
b) When more than one pressure relief device is provided to obtain the required capacity, only one pressure relief device set pressure need be at or below the maximum allowable working pressure. The set pressure of additional devices may exceed the MAWP, as permitted by the original code of construction.
c) Verify nameplate capacity and, if possible, compare to system capacity requirements.
d) Check identification on seals and ensure they match nameplates or other identification (repair or reset nameplate) on the valve or device. 23.2.2 DEVICE CONDITIONS a) The valve or device shall be checked for evidence that it is not leaking or not sealing properly. Evidence of leakage through pressure-relief valves may indicate that the system is being operated at a pressure that is too close to the valve’s set pressure. (See Supplement 2 for guidance on the pressure differential between the pressure relief valve set pressure and system operating pressure.)
PART 4, SECTION 34 REPAIR OF PRESSURE RELIEF VALVES 34.1 REPAIR OF PRESSURE RELIEF DEVICES, SCOPE This section provides general requirements that apply to repairs to pressure relief valves. a) Repairs may be required because of defects found during periodic inspections, because testing, operation, or maintenance.has identified that valve performance does not meet the original code of construction requirements, failure during operation, or for routine preventative maintenance. Since pressure relief devices are provided for safety and the protection of personnel and property, repairs are often regulated by the jurisdiction where the pressure relief device is installed. The jurisdiction should be contacted for their specific requirements. b) The National Board administers four specific accreditation programs: “R” — Repairs and Alterations to Pressure-Retaining Items “VR” — Repairs to Pressure Relief Valves “NR” — Repair and Replacement Activities for Nuclear Items “T/O” – Inservice Testing Only of Pressure Relief Valves c) This section describes some of the administrative requirements for the accreditation of repair organizations. Additional administrative requirements can be found in NB-514, Accreditation of “VR” Repair Organizations. Some jurisdictions may independently administer a program of authorization for organizations to perform repairs within that Jurisdiction. d) Requirements for the “T/O” are found in NB-528, Accreditation of “T/O” Test Only Organizations. e) Requirements for repairs and alterations to pressure-retaining items and repair and replacement activities for nuclear items can be found in NBIC Part 3. 34.2 GENERAL REQUIREMENTS a) Repair of a pressure relief valve is considered to include the disassembly, replacement, re-machining, or cleaning of any critical part, lapping of a seat and disc, reassembly, adjustment, testing, or any other operation that may affect the flow passage, capacity, function, or pressure-retaining integrity.
b) Conversions, changes, or adjustments affecting critical parts are also considered repairs. The scope of conversions may include changes in service fluid and changes such as bellows, soft seats, and other changes that may affect Type/Model number provided such changes are recorded on the document as required for a quality system and the repair nameplate. (See 34.7.1). c) The scope of repair activities shall not include changes in ASME Code status. 34.2.1 VR REPAIR a) When a repair is being performed under the administrative requirements for National Board Accreditation, a repair shall consist of the following operations as a minimum: 1) Complete disassembly, cleaning, and inspection of parts, repair or replacement of parts found to be defective, reassembly, testing as required by 34.6, sealing and application of a repair nameplate. When completed, the valve’s condition and performance shall be equivalent to the standards for new valves.
2) The administrative requirements for National Board Accreditation apply only to valves that are stamped with an ASME “V,” “UV,” or “NV” Code symbol or marked with an ASME “HV” symbol and have been capacity certified on the applicable fluid by the National Board.
Liquid Pressure Test — A pressure test using water or other incompressible fluid as a test medium. Manufacturer’s Documentation — The documentation that includes technical information and certification required by the original code of construction. Mechanical Assembly — The work necessary to establish or restore a pressure retaining boundary, under supplementary materials, whereby pressure-retaining capability is established through a mechanical, chemical, or physical interface, as defined under the rules of the NBIC. Mechanical Repair Method — A method of repair, that restores a pressure retaining boundary to a safe and satisfactory operating condition, where the pressure retaining boundary is established by a method other than welding or brazing, as defined under the rules of the NBIC Metering Device – A method of controlling the amount of fuel, or air, flowing into the combustion zone. NBIC — The National Board Inspection Code published by The National Board of Boiler and Pressure Vessel Inspectors. “NR” Certificate Holder — An organization in possession of a valid “NR” Certificate of Authorization issued by the National Board. National Board — The National Board of Boiler and Pressure Vessel Inspectors. National Board Commissioned Inspector — An individual who holds a valid and current National Board Commission. Nuclear Items — Items constructed in accordance with recognized standards to be used in nuclear power plants or fuel processing facilities. Original Code of Construction — Documents promulgated by recognized national standards writing bodies that contain technical requirements for construction of pressure-retaining items or equivalent to which the pressure retaining item was certified by the original manufacturer. Overfire Air – Air admitted to the furnace above the grate surface /fuel bed. Used to complete the combustion of fine particles, in suspension. Also aids in reducing NOx formation. Owner or User — As referenced in lower case letters means any person, firm or corporation legally responsible for the safe operation of any pressure-retaining item. Owner-User Inspection Organization — An owner or user of pressure-retaining items that maintains an established inspection program, whose organization and inspection procedures meet the requirements of the National Board rules and are acceptable to the jurisdiction or jurisdictional authority wherein the owner or user is located. Owner-User Inspector — An individual who holds a valid and current National Board Owner-User Commission. Piecing — A repair method used to remove and replace a portion of piping or tubing material with a suitable material and installation procedure. Pilot Operated Pressure Relief Valve -- A pressure relief valve in which the disk is held closed by system pressure, and the holding pressure is controlled by a pilot valve actuated by system pressure. Pneumatic Test — A pressure test which uses air or another compressible gas as the test medium. Potable Water Heaters — A corrosion resistant appliance that includes the controls and safety devices to supply potable hot water at pressure not exceeding 160 psig (1100 kPa) and temperature not in excess of 210°F (99°C).
1) Fired Storage Water Heater - A potable water heater in which water is heated by electricity, the combustion of solid, liquid, or gaseous fuels and stores water within the same appliance.
2) Indirect Fired Water Heater - A potable water heater in which water is heated by an internal coil or heat exchanger that receives its heat from an external source. Indirect fired water heaters provide water directly to the system or store water within the same appliance.
3) Circulating Water Heater - A potable water heater which furnishes water directly to the system or to a separate storage tank. Circulating water heaters may be either natural or forced flow. Pressure-Retaining Items (PRI) — Any boiler, pressure vessel, piping, or material used for the containment of pressure, either internal or external. The pressure may be obtained from an external source, or by the application of heat from a direct source, or any combination thereof. Pressure Relief Device -- A device designed to prevent pressure or vacuum from exceeding a predetermined value in a pressure vessel by the transfer of fluid during emergency or abnormal conditions.
Pressure Relief Valve (PRV) -- A pressure relief device designed to actuate on inlet static pressure and reclose after normal conditions have been restored.
Pressure Test — A test that is conducted using a fluid (liquid or gas) contained inside a pressure-retaining item. Pressure Vessel — A pressure vessel is a container other than a boiler or piping used for the containment of pressure. Relief Valve -- A pressure relief valve characterized by gradual opening that is generally proportional to the increase in pressure. It is normally used for incompressible fluids. Repair — The work necessary to restore pressure-retaining items to a safe and satisfactory operating condition. Re-ending — A method used to join original code of construction piping or tubing with replacement piping or tubing material for the purpose of restoring a required dimension, configuration or pressure-retaining capacity. Re-rating — See alteration. “R” Certificate Holder — An organization in possession of a valid “R” Certificate of Authorization issued by the National Board. Safe Point of Discharge — A location that will not cause property damage, equipment damage, or create a health or safety threat to personnel in the event of discharge. Safety Relief Valve -- A pressure relief valve characterized by rapid opening or by gradual opening that is generally proportional to the increase in pressure. It can be used for compressible or incompressible fluids. Safety Valve -- A pressure relief valve characterized by rapid opening and normally used to relieve compressible fluids. Settings — Those components and accessories required to provide support for the component during operation and during any related maintenance activity. Shop — A permanent location, whose address is shown on the Certificate of Authorization, from which a Certificate Holder controls the repair and/or alteration of pressure-retaining items.
NB16-0902 2015 NBIC Part 2 2.5.8 RECOMMENDED INSPECTION AND TEST FREQUENCIES FOR PRESSURE RELIEF DEVICES a) Power Boilers
1) Pressure less than 400 psig (2.76 MPa): Manual check every 6 months; pressure test annually to verify nameplate set pressure or as determined by operating experience as verified by testing history.
2) Pressure greater than of 400 psig (2.76 MPa) or greater: Pressure test to verify nameplate set pressure every three years or as determined by operating experience as verified by testing history.
Attachment Page 46
Attachment Page 46
SC PRD Attachments /NB16-0902 MC Revised
NB16‐1501 NR Task Group 7‐18‐16
Note 4: For Group 3, see Part 3, S9.3 a)
Unique Identifier
Unique Identifier
4
Comment [TB1]: Can be added back in if item NB16‐0603 gets approved.
Attachment Page 47
Attachment Page 47
SC PRD Attachments /NB16-1501 NR Task Group 7-18-16 (2)
Item Number: NB15-0106 NBIC Location: Part 1, 3.7.5.1 No Attachment
General Description: Address Figure 3.7.5.1
Subgroup: Installation Task Group: B. Moore (PM), T. Creacy, and M. Washington
History: July 2015 Mr. Richards gave a progress report and explained the purpose of the new item. Mr. Brian Moore has been as-
signed as progress report. January 2016 Mr. Paul Schuelke reported that Mr. Moore wasn’t present, so no progress was made.
S3.1 SCOPE This supplement provides requirements for the installation of Liquid Carbon Dioxide Storage Vessels (LCDSVs), fill boxes, fill lines, and pressure relief discharge/vent circuits used for carbonated beverage systems, swimming pool PH control systems, and other fill in place systems storing 1,000 lbs (454 kg) or less of liquid CO2. S3.2 GENERAL REQUIREMENTS STORAGE TANK LOCATION LCDSVs should be installed in an unenclosed area whenever possible. LCDSVs that do not meet all criteria for an unenclosed area shall be considered an enclosed area installation. An unenclosed area: c) Shall be outdoors; d) Shall be above grade; and e) Shall not obstruct more than three sides of the perimeter with supports and walls. At least 25% of the perimeter area as calculated from the maximum height of the storage container shall be open to atmosphere and openings shall be in direct conveyance with ground level. S3.2.1 GENERAL REQUIREMENTS (ENCLOSED AND UNENCLOSED AREAS) a) LCDSVs shall not be located within 10 feet (3,050 mm) of elevators, unprotected platform ledges, or other areas where falling would result in dropping distances exceeding half the container height. b) LCDSVs shall be installed with sufficient clearance for filling, operation, maintenance, inspection, and replacement. c) Orientation of nozzles and attachments shall be such that sufficient clearance between the nozzles, attachments, and the surrounding structures is maintained during the installation, the attachment of associated piping, and operation. d) LCDSVs shall not be installed on roofs. e) LCDSVs shall be safely supported. Vessel supports, foundations, and settings shall \be in accordance with jurisdictional requirements, manufacturer recommendations and/or other industry standards as applicable. The weight of the vessel when full of liquid carbon dioxide shall be considered when designing vessel supports. Design of supports, foundations, and settings shall consider vibration (including seismic and wind loads where necessary), movement (including thermal movement), and loadings. Vessel foundations or floors in multistory buildings must be capable of supporting the full system weight and in accordance with building codes. f) LCDSVs shall not be installed within 36 in. (915 mm) of electrical panels. g) LCDSVs installed outdoors in areas in the vicinity of vehicular traffic shall be guarded to prevent accidental impact by vehicles. The guards or bollards shall be installed in accordance with local building codes or to a national recognized standard when no local building code exists. h) LCDSVs shall be equipped with isolation valves in accordance with paragraph NBIC Part 1, S3.6. S3.2.2 UNENCLOSED AREA LCDSV INSTALLATIONS If LCDSVs are installed outdoors and exposed to the elements, appropriate additional protection may be provided as necessary based on the general weather conditions and temperatures that the tank may be exposed to. Some possible issues include: a) Exposure to high solar heating loads will increase the net evaporation rate and will decrease hold times in low CO2 usage applications. The vessel may be covered or shade provided to help reduce the solar load and increase the time needed to reach the relief valve setting in low use applications. b) If supply line is not UV resistant then the supply line should be protected via conduit or appropriate covering.
S3.2.3 ENCLOSED AREA LCDSV INSTALLATIONS a) Permanent LCDSV installations with remote fill connections: 1) Shall be equipped with a gas detection system installed in accordance with NBIC Part 1, S3.4; 2) Shall have signage posted in accordance with NBIC Part 1, S3.5; and 3) Shall be equipped with fill boxes; fill lines and safety relief/vent valve circuits installed in accordance with NBIC Part 1, S3.6. b) Portable LCDSV installations with no permanent remote fill connection: Warning: LCDSVs shall not be filled indoors or in enclosed areas under any circumstances. Tanks must always be moved to the outside to an unenclosed, free airflow area for filling. 1) Shall be equipped with a gas detection system installed in accordance with NBIC Part 1, S3.4; 2) Shall have signage posted in accordance with NBIC Part 1, S3.5; 3) Shall have a safety relief/vent valve circuit connected at all times except when the tank is being removed for filling. Connects may be fitted with quick disconnect fittings meeting the requirements of NBIC Part 1, S3.6; and 4) Shall be provided with a pathway that provides a smooth rolling surface to the outdoor, unenclosed fill area. There shall not be any stairs or other than minimal inclines in the pathway. S3.3 FILLBOX LOCATION / SAFETY RELIEF/VENT VALVE CIRCUIT TERMINATION Fill boxes and/or vent valve terminations shall be installed above grade, outdoors in an unenclosed, free airflow area. The fill connection shall be located so not to impede means of egress or the operation of sidewalk cellar entrance doors, including during the delivery process and shall be: 1) At least 36 in. (915 mm) from any door or operable windows; 2) At least 36 in. (915 mm) above grade; 3) Shall not be located within 10 ft. (31 m) from side to side at the same level or below, from any air intakes; and 4) Shall not be located within 10 ft. (31 m) from stairwells that go below grade. S3.4 GAS DETECTION SYSTEMS Rooms or areas where carbon dioxide storage vessel(s) are located indoors or in enclosed or below grade outdoor locations shall be provided with a gas detection and alarm system for general area monitoring that is capable of detecting and notifying building occupants of a CO2 gas release. Alarms will be designed to activate a low level pre-alarm at 5,000 ppm concentration of CO2 and a full high alarm at 30,000 ppm concentration of CO2 which is the NIOSH & ACGIH 15 minute Short Term Exposure Limit for CO2. These systems are not designed for employee personal exposure monitoring. Gas detection systems shall be installed and tested in accordance with manufacturer’s installation instructions and the following requirements: a) Activation of the gas detection system shall activate an audible alarm within the room or area in which the carbon dioxide storage vessel is located. b) Audible alarms shall also be placed at the entrance(s) to the room or area where the carbon dioxide storage vessel and/or fill box is located to notify anyone who might try to enter the area of a potential A continuous gas detection system shall be provided in the room or area where container systems are filled and used, in areas where the heavier thatthan air gas can congregate and in below grade outdoor locations. Carbon dioxide (CO2) sensors shall be provided within 12 inches (305mm) of the floor in the area where the gas is most likely to accumulate or leaks are most likely to occur. The system shall be designed to detect and notify at a low level alarm and high level alarm.
a) The threshold for activation of the low level alarm shall not exceed a carbon dioxide concentration of 5,000 ppm (9,000 mg/m3) Time Weighted Average (TWA) over 8 hours. When carbon dioxide is detected at the low level alarm, the system shall activate a signal at a normally attended location within the building.
b) The threshold for activation of the high level alarm shall not exceed a carbon dioxide concentration 30,000 ppm (54,000 mg/m3). When carbon dioxide is detected at the high level alarm, the systemshall activate an audible and visual alarm at a location approved by the jurisdiction having authority.
Warning Hazard identification signs shall be posted at the entrance to the building, room, enclosure, orand / or the confined enclosed area where the LCDSV container is located. The warning sign shall be at least 8 in. (200 mm) wide and 6 in. (150 mm) high and indicate . The wording shall be concise and easy to read and the upper portion of the sign must be orange as shown in figure NBIC Part 1, S3.5. The size of the lettering must be as large as possible for the intended viewing distance and in accordance with jurisdictional requirements. When no jurisdictional requirements exist, the minimum letter height shall be in accordance with NEMA American National Standard for Environmental and Facility Safety Signs (ANSI Z535.2). The warning sign shall be as shown in Figure S3.5. Additional instructional signage shall be posted outside of the area where the container is located and such signage shall contain at minimum the following information: a) Carbon Dioxide Monitors for general area monitoring (not employee personal exposure monitoring) are provided in this area. These monitors are set to alarm at 5,000 ppm for the low level alarm and at 30,000 ppm for high level alarm. b) Low Level Alarm (5,000 ppm) – Provide appropriate cross ventilation to the area. Personnel may enter area for short periods of time (not to exceed 15 minutes at a time) in order to identify and repair potential leaks. c) High Level Alarm (30,000 ppm) – Personnel should evacuate the area and nobody should enter the affected area without proper self-contained breathing apparatus until the area is adequately ventilated and the concentration of CO2 is reduced below the high alarm limit.
CAUTION‐ CARBON DIOXIDE GAS Ventilate the area before entering.
A high carbon dioxide (CO2) gas concentration In this area can cause asphyxiation.
S3.6 VALVES, PIPING, TUBING, AND FITTINGS a) Materials – Materials selected for valves, piping, tubing, hoses, and fittings used in the LCDSV system shall meet following requirements: 1) Components must be compatible for use with CO2 in the phase (gas, or liquid in the applicable circuit) it encounters in the system. 2) Components shall be rated for the operational temperatures and pressures encountered in the applicable circuit of the system. 3) Shall be stainless steel, copper, brass, or plastic/polymer materials rated for CO2. 4) Only fittings and connections recommended by the manufacturer shall be used for all hoses, tubes, and piping. 5) All valves and fittings used on the LCDSV shall be rated for the maximum allowable working pressure stamped on the tank. 6) All piping, hoses, and tubing used in the LCDSV system shall be rated for the working pressure of the applicable circuit in the system and have a burst pressure rating of at least four times the maximum allowable working pressure of the piping, hose, or tubing. b) Relief Valves – Each LCDSV shall have at least one ASME/NB stamped & certified relief valve with a pressure setting at or below the MAWP of the tank. The relief valve shall be suitable for the temperatures and flows experienced during relief valve operation. The minimum relief valve capacity shall be designated by the manufacturer. Additional relief valves that do not require ASME stamps may be added per recommendations in Compressed Gas Association pamphlet, CGA S-1.3 Pressure Relief Device Standards Part 3, Stationary Storage Containers for Compressed Gases. Discharge lines from the relief valves shall be sized in accordance with tables NBIC Part 1, S3.6-a and S3.6-b. Note: Due to the design of the LCDSV, the discharge line may be smaller in diameter than the relief valve outlet size. Caution: Companies and/or individuals filling or refilling LCDSVs shall be responsible for utilizing fill equipment that is acceptable to the manufacturer to prevent over pressurization of the vessel. c) Isolation Valves – Each LCDSV shall have an isolation valve installed on the fill line and tank discharge,or gas supply line in accordance with the following requirements: 1) Isolation valves shall be located on the tank or at an accessible point as near to the storage tank as possible. 2) All valves shall be designed or marked to indicate clearly whether they are open or closed. 3) All valves shall be capable of being locked or tagged in the closed position for servicing. 4) Gas Supply and Liquid CO2 Fill Valves shall be clearly marked for easy identification. d) Safety Relief/Vent Lines – Safety relief/vent lines shall be as short and straight as possible with a continuous routing to an unenclosed area outside the building and installed in accordance with the manufacturer’s instructions. The vent line(s) shall be a continuous run from the vessel pressure relief device vent piping to the outside vent line discharge fitting. Mechanical joints in metallic piping and tubing shall be visible and inspectable. Any splices in plastic or polymeric tubing shall be done within three feet of the vessel and must be visible and inspectable. These lines shall be free of physical defects such as cracking or kinking and all connections shall be securely fastened to the LCDSV and the fill box. All safety relief/vent lines shall be protected to prevent penetration by nail, projectile, or other foreign object when routed through a wall, floor, or ceiling. The minimum size and length of the lines shall be in accordance with NBIC Part 1, Tables S3.6-a and S3.6-b. Fittings or other connections may result in a localized reduction in diameter have been factored into the lengths given by the NBIC Part 1, Tables S3.6-a and S3.6-b. Note: Due to the design of the LCDSV, the discharge line may be smaller in diameter than the relief valve outlet size but shall not be smaller than that shown in NBIC Part 1, Tables S3.6-a and S3.6-b.
NB16‐0809C ‐ 7‐13‐16 ‐ Besserman 1.1 SCOPE NBIC Part 1This part provides requirements and guidelines guidance for the installation of power boilers, steam heating boilers, hot‐water heating boilers, hot‐water supply boilers, potable water heaters, pressure vessels and piping. The proper installation of boilers, pressure vessels, piping, and other pressure‐retaining items is essential for safe and satisfactory operation. The owner‐user is responsible for ensuring that installations meet all the requirements of the Jurisdiction at the point of installation including licensing, registration, or certification of those performing installations. NBIC Part 1 identifies minimum safety requirements for installing pressure‐retaining items when NBIC Part 1 is mandated by a Jurisdiction. Otherwise, the requirements specified in NBIC Part 1 provide information and guidance for installers, contractors, owners, inspectors, and Jurisdictions to ensure safe and satisfactory installation of specified pressure‐retaining items. Jurisdictions may require other safety standards, including following manufacturer’s recommendations. When a Jurisdiction establishes different requirements or where a conflict exists, the rules of the Jurisdiction prevail. Users of NBIC Part 1 are cautioned that other requirements may apply for a particular installation and NBIC Part 1 is not a substitute for sound engineering evaluations.
2.1 SCOPE NBIC Part 1, Section 2This section provides requirements and guidelines guidance for the installation of power boilers.
3.1 SCOPE The scope of NBIC Part 1, Section 3 This section shall apply toprovides requirements and guidelines guidance for the installation of steam heating boilers, hot‐water heating boilers, hot‐water supply boilers, and potable water heaters.
4.1 SCOPE NBIC Part 1, Section 4This section provides requirements and guidelines guidance for the installation of pressure vessels.
5.1 SCOPE NBIC Part 1, Section 5This section provides requirements and guidelines guidance for the installation of piping.
S1.1 SCOPE a) This supplement describes provides guidelines for the installation of a Yankee dryer. A Yankee dryer is a pressure vessel with the following characteristics: a) A Yankee dryer is a rotating steam‐pressurized cylindrical vessel commonly used in the paper industry, and is typically made of cast iron, finished to a high surface quality, and characterized by a center shaft connecting the heads. b) Yankee dryers are primarily used in the production of tissue‐type paper products. When used to produce machine‐glazed (MG) paper, the dryer is termed an MG cylinder. A wet paper web is pressed onto the finished dryer surface using one or two pressure (pressing) rolls. Paper is dried through a combination of mechanical
dewatering by the pressure roll(s), thermal drying by the pressurized Yankee dryer, and a steam‐heated or fuel‐fired hood. After drying, the paper web is removed from the dryer. c) A Yankee dryer is typically manufactured in a range of outside diameters from 8 to 23 ft. (2.4 to 7 m), widths from 8 to 28 ft. (2.4 to 8.5 m), pressurized and heated with steam up to 160 psi (1,100 kPa), and rotated at speeds up to 7,000 ft/min (2,135 m/min). Typical pressure roll loads against the Yankee dryer are up to 600 pounds per linear inch (105 kN/m). A thermal load results from the drying process due to difference in temperature between internal and external shell surfaces. The dryer has an internal system to remove steam and condensate. These vessels can weigh up to 220 tons (200 tonnes). d) The typical Yankee dryer is an assembly of several large castings. The shell is normally a gray iron casting, in accordance with ASME designation SA‐278. Shells internally may be smooth bore or ribbed. Heads, center shafts, and journals may be gray cast iron, ductile cast iron, or steel.
S2.1 SCOPE This supplement provides requirements and guidelines for the installation of safety valves on the low‐pressure side of steam pressure‐reducing valves. a) The subject of protection of vessels in steam service connected to the low‐pressure side of a steam‐pressure‐reducing valve is of considerable importance to proper operation of auxiliary equipment such as pressure cookers, hot‐water heating systems, etc., operating at pressures below that which the primary boiler generating unit is operating. b) To automatically reduce the primary boiler pressure for such processing equipment, pressure‐reducing valves are used. The manufacturers of such equipment have data available listing the volume of flow through reducing valves manufactured by them, but such data are not compiled in a form that the results can be deduced readily. To protect the equipment operating on the low‐pressure side of a pressure‐reducing valve, safety valves of a relieving capacity sufficient to prevent an unsafe pressure rise in case of failure of the pressure‐reducing valve, should be installed. c) The pressure‐reducing valve is a throttling device, the design of which is based on certain diaphragm pressures opposed by spring pressure which, in turn, controls the opening through the valve. If the spring, the diaphragm, or any part of the pressure‐reducing valve fails, steam will flow directly through the valve and the low pressure equipment will be subjected to the boiler pressure. To protect the equipment operating on the low pressure side of the pressure‐reducing valve, safety valve(s) should be installed on the low pressure side of the pressure‐reducing valve, which will provide a relieving capacity sufficient to prevent the pressure from rising above the system design pressure. d) In most cases pressure‐reducing valves used for the reduction of steam pressures have the same pipe size on the inlet and outlet. In case of failure of a pressure‐reducing valve, the safety valve on the low‐pressure side must have a capacity to take care of the volume of steam determined by the high pressure side and the area of the pipe.
S3.1 SCOPE This supplement provides requirements and guidelines for the installation of Liquid Carbon Dioxide Storage Vessels (LCDSVs), fill boxes, fill lines, and pressure relief discharge/vent circuits used for carbonated beverage systems, swimming pool PH control systems, and other fill in place systems storing 1,000 lbs (454 kg) or less of liquid CO2.
S4.1 SCOPE This supplement provides requirements and guidelines for the installation of biomass (wood/solid fuel) fired boilers as defined in NBIC Part 1, Section 9.
S5.1 SCOPE This supplement provides requirements anddescribes guidelines for the installation of a thermal fluid heater. A thermal fluid heater system consists of the heater, expansion tank, circulating pump, safe catchment with the proper piping and controls to heat jacketed kettles, presses, reactors, ovens, exchangers, etc. The scope does not include thermal fluid vaporizers.
3.8.1.5 AUTOMATIC LOW-WATER FUEL CUTOFF AND/OR WATER FEEDING DEVICE a) Each automatically fired steam-or vapor-system boiler shall have an automatic low-water fuel cutoff. The low-water fuel cutoffs must be so located as to automatically cut off the fuel supply when the surface of the water falls to a level not lower than the lowest visible part of the water-gage glass. If a water feeding device is installed, it shall be so constructed that the water inlet valve cannot feed water into the boiler through the float chamber and so located as to supply requisite feedwater.
National Board Inspection Code Action item NB13‐1002‐ Revision Dated 7/19/2016
NB13‐1002 ‐ Part 2, SG Insp. Spec. – Review inspection requirements for B31.1 Power Piping. A Task
Group consisting of Mike Schwartzwalder (Lead), Joe Frey, Venus Newton, Mark Mooney, Marshall Clark,
Domenic Canonico, Mark Horbaczewski, Robbie Dobbins and Chuck Withers were assigned.
For Discussion, I propose the following additions to the Part 2‐ Inspection, 2017 edition Section 1.3 add
paragraph 1.3(v) ASME B31.1, Power Piping, Chapter VII, Operation and Maintenance.
Add to Part 2‐ Section 9 Inspection, Glossary of Terms Definitions; 9.1 Definitions; Covered Piping
Systems (CPS) (not to be confused with insulated piping) are ASME B31.1 pressure piping systems or
other piping systems where safety risks to personnel and equipment may exist during facility
operations.
2.4.9 –COVERED PIPING SYSTEMS
Covered Piping Systems (CPS) designed to ASME B31.1 or other construction piping codes as deemed
necessary by the owner may be subjected to the same damage mechanisms as “covered piping”, such as
boiler and boiler external piping, based on temperature, pressure and environmental conditions.
Examples of CPS are main steam, hot and cold reheat, feedwater, drains and other piping systems where
failure may occur as a result of creep, fatigue, erosion–corrosion, corrosion–fatigue, wall thinning,
graphitization and other failure mechanisms. Based on these considerations a program should be
established where CPS is periodically evaluated by an owner’s assessment program using suitable NDE,
metallurgical analysis or other methods to determine whether continued operation of this piping is
justified. ASME B31.1, Chapter VII ‐Operation and Maintenance provides guidance on how these
systems should be evaluated, maintained and documented. It is recognized that all of the
documentation, data and records for CPS, identified in ASME B31.1, Chapter VII may not be available for
a specific plant, particularly for older plants and for piping systems identified as nonboiler external or
similar piping. The rigor and detail of the owner’s CPS assessment programs are the responsibility of the
owner and should ensure the continued safe operation of this piping. The owner should ensure to the
extent possible that CPS do not represent safety risks. The assessment program should be made
available for review.
Attachment Page 65
Attachment Page 65
SC Inspection Attachments /NB13-1002 - 160721 - Metzmaier - Revised at MC
NBIC Item NB13-1701
2.3.6.6 INSPECTION OF WIRE WOUND PRESSURE VESSELS
(a) This section provides guidelines for inspection of wire wound pressure vessels typically designed for 10,000 psi or greater service. The scope of inspection of these vessels should include components affected by repeated opening and closing, such as the frame, yolk and cylinder inner diameter surface, or alignment of the yolk with the cylinder, lack of maintenance and a check for inoperable or bypassed safety and warning devices. Early detection of any damage to the cylinder, closures or frame is essential to avoid catastrophic failure. (Moved from paragraph c)
(b) These vessels consist of four parts, a wire wound cylinder, two end closures and a frame to retain the closures in the cylinder. The wire is one continuous piece and is wound in tension. On the cylinder, the wire can only carry circumferential or radial loading. The cylinder is typically not of sufficient thickness to carry axial load which requires the end closures have no threads or retaining grooves and requires a frame to retain the pressure vessel axial load imposed on the closures. The purpose for this design is to minimize weight of the containment cylinder using thinner wall materials and using external wound wire to induce a compressive preload. This design also provides increased resistance to damage from fatigue loading. Note that some vessels may be monoblock cylinders (no winding) with wire wound frame and some vessels may be wire wound cylinder with a forged or welded plate frame (not wire wound). Use of a frame to retain the end closures removes the sharp transitions in shape (threads or grooves) associated with monoblock cylinder failures. The design of high pressure vessels is typically based on fatigue life criteria. The majority of operating wire wound vessels in North America today were manufactured to ASME BPVC Section VIII Division 3, Alternative Rules for Construction of High Pressure Vessels. Some inservice vessels may have been manufactured to ASME BPVC Section VIII Division 1 or Division 2, and others have been installed as “State Specials” that require fatigue life analysis to determine a safe operating life. The primary failure mode is fatigue cracking. Early detection of any damage to the cylinder, closures or frame is essential to avoid catastrophic failure
High pressure design requires use of high strength materials, which have relatively low ductility. The material thickness required for reasonable fatigue life is greatly reduced by the pre-tensioned wire wound design. Typical winding design provides compression sufficient that at vessel design conditions there is no circumferential stress in the cylinder. These vessels have been used in various industrial applications, including foods and drinks processing, ceramic or refractory processing and powdered metal processing utilizing a liquid compressing fluid at ambient or slightly elevated temperature. The most frequent of these are isostatic pressing and hydrostatic extrusion. Isostatic pressing can be performed at either cold temperatures, at room temperature, with liquid as the pressure medium, or hot, at temperatures of 2000 to 3300°F with gas as the pressure medium. In hot isostatic presses, the vessel wall is
separated from the hot space by insulation, which keeps the vessel wall operating at a low temperature of approximately 120 to 180°F.
Cold pressing is used for regular production at pressures up to 87,000 psi. Ceramic, refractory and metal processing is also performed at elevated temperature, up to 3632°F (2000°C). The “hot” processes utilize an inert gas fluid pressure up to 45,000 psi (310 MPa). Continuous cooling is necessary for the hot process and may contribute to corrosion damage of the cylinder of closures.
Hydrostatic extrusion is generally performed either cold, at room temperature, or warm, at temperatures up to 1110°F, in both cases with liquid as the pressure medium. Hydrostatic extrusion is used for regular production at pressures up to 200,000 psi. Both cold and hot processes are commonly found in research facilities and in universities.
(c) Record keeping (1) Since these vessels have a finite fatigue life, it is essential a record be maintained of
each operating cycle, recording both temperature and pressure. Deviation beyond design limits is cause for suspending operation and reevaluation of remaining fatigue life. Vessels having no operating record should shall be inspected and a fracture mechanics evaluation with a fatigue analysis test be performed to establish remaining life before resuming operation. Vessels having no operating record shall not be used for service until such time previous operating history can be determined.
(2) Operating data should be recorded and include the following whenever the vessel is
operating: a. Number of cycles b. Maximum pressure c. Maximum temperature d. Any unusual conditions
(d) Any damage to the cylinder or closures can lead to premature failure. Frequent visual
inspection should be made of internal and external surfaces of the cylinder, frame and closures. A thorough examination should be completed if any visually apparent damage is identified or if any excursion beyond design temperature or pressure occurs. In addition, surfaces of the cylinder and closures should be examined by dye penetrant or magnetic particle method at intervals based on vessel remaining life. Closures may require ultrasonic examination of passageways.
Following is an example of what the results of such a study might reveal as allowable cycles for a particular wire wound vessel:
Columns > 106 Cycles “Columns” are beams on either side of frame, between the yokes.
Yokes > 106 Cycles “Yokes” are the circular ends of the frame. Wires of frames > 106Cycles “Wires” place frame in compression
60 X 103 cycles “Wires” place cylinder in compression.
Closures 30 X 103 cycles All connections to the vessel are through the closures. These passageways create stress raisers, as do grooves for sealing system.
The vessel design life in this example is thus limited by the closure. The calculated design life is 30,000 cycles at design pressure and temperature.
An acceptable factor of safety for vessel fatigue inspection interval varies between 0.25 and 0.5 of the remaining design life. The inspection interval for the above example is therefore 10,000 to 20,000 cycles, but should not exceed five years.
In addition to scope of frequent inspection, the fatigue inspection should include measurement of the cylinder inside diameter and frame inside length to detect reduced tension in the wire windings. Note that monoblock cylinders and plate frames require additional inspection due to differing construction.
If a crack or flaw is detected during any inspection, an immediate evaluation, repair and study of impact on remaining fatigue life should be completed by a National Board authorized repair agency. Using the results of this study, and application of safety factor 0.25 (due to known damage), the number of cycles of operation to the next fatigue inspection is established. As part of this inspection guideline for wire wound pressure vessels frequent inspection, the following items should be reviewed:
(1) Verify no change in the process, such as the processing fluid, that might adversely impact vessel integrity.
(2) Review the vessel manufacturer’s inspection recommendations for vessel, closures and
frame. If manufacturer’s recommendations are not available, obtain recommendations from a recognized wire wound vessel service provider.
(3) Verify any repair to pressure retaining items has been completed by National Board
authorized service provider having wire wound vessel expertise. (4) Verify overpressure protection with appropriate set pressure and capacity is provided.
Rupture discs are commonly used for pressures exceeding 14,500 psi (100 MPa) to avoid valve seat leakage. Overpressure protection devices are frequently replaced to avoid premature operation.
(5) If there are no manufacturer’s recommendations available for the vessel, the following
are additional recommended inspections that should be conducted to ensure vessel integrity and safety
a. Conduct annual visual and dimensional vessel inspections with liquid penetrant
examination of maximum stressed areas to ensure that the surfaces are free of defects. Conduct ultrasonic examination of the vessel after every 25% of the design cycle life or every five years, whichever comes first, to detect subsurface cracks. Special attention should be given to the roots of threads and closures
using threaded head retention construction. Other geometric discontinuities that are inherent in the design or irregularities resulting from localized corrosion, erosion, or mechanical damage should be carefully examined. This is particularly important for units of monoblock construction.
b. The closure mechanism of the vessel end-closure is opened and closed frequently during operation. It should be closely inspected for freedom of movement and proper contact with its locking elements. Wire wound vessels must have yoke-type closures so the yoke frame will need to be closely inspected on a regular basis
c. Should pitting, cracks, corrosion, or other defects are found during scheduled
inspection, verify that an evaluation using fracture mechanics techniques is performed. This is to determine MAWP, cyclic life and extent of NDE frequency based on crack growth rate.
(6) Gages, Safety Devices, and Controls
a. Verify that the vessel is provided with control and monitoring of pressure, temperature, the electrical system, fluid flow, liquid levels and all variables that are essential for the safe operation of the system. If the vessel is automatically controlled, manual override should be available. Also, safety interlocks should be provided on the vessel closure to prevent vessel pressurization if the vessel closure is not complete and locked.
b. Verify that all safety device isolation valves are locked open if used.
c. Verify appropriate pressure relief device is installed with the setpoint at the
lowest pressure possible, consistent with the normal operating pressure but in no case higher than the design operating pressure of the vessel. Rupture discs are normally considered more suitable for these types of applications since pressure relief devices operating at pressures above 14500 psi may tend to leak by their seat.
d. Verify that pressure and temperature of the vessel coolant and vessel wall is
controlled and monitored. Interlock devices should be installed that will de-energize or depressurize the vessel at established setpoints.
e. Verify audible and visual alarms are installed to indicate unsafe conditions.
Ballot item NB15‐0201 review wording in Part 2 on Pitting Corrosion
Current wording in NBIC sections
3.3.1 MACROSCOPIC CORROSION ENVIRONMENTS Macroscopic corrosion types are among the most prevalent conditions found in pressure-retaining items causing deterioration. The following corrosion types are found. e) Pitting Corrosion Pitting corrosion is the formation of holes in an otherwise relatively un-attacked surface. Pitting is usually a slow process causing isolated, scattered pits over a small area that does not substantially weaken the vessel. It could, however, eventually cause leakage.
4.4.7.2 METHOD FOR ESTIMATING INSPECTION INTERVALS FOR EXPOSURE TO CORROSION
NB13-0701 4.4.8.7.2(J)(1)
Wording in 2015 NBIC
j) Local Metal Loss
Corrosion pitting shall be evaluated in accordance with NBIC Part 2, 4.4.8.7. Widely scattered corrosion pits may be left in the pressure-retaining item in accordance with the following requirements: 1) Their depth is not more than one-half the required thickness of the pressure-retaining item wall (exclusive
of corrosion allowance); and 2) The total area of the pits does not exceed 7 sq. in. (4500 sq mm) within any 50 sq. inches (32000 sq. mm); and 3) The sum of their dimensions (depth and width) along any straight line within this area does not exceed 2 in. (50 mm). 4.4.8.7 EVALUATING PRESSURE·RETAINING ITEMS CONTAINING LOCAL THIN AREAS a) Local thin areas can result from corrosion/erosion, mechanical damage, or blend/grind techniques during fabrication or repair, and may occur internally or externally. Types of local thin areas are grooves, gouges, and pitting. When evaluating these types of flaws, the following should be considered:
d) Required measurements for evaluation of local thin areas shall include: 1) Thickness profiles within the local region; 2) Flaw dimensions; 3) Flaw to major structural discontinuity spacing; 4) Vessel geometry; 5) Material properties. e) Required measurements for evaluation of pitting corrosion shall include: 1) Depth of the pit; 2) Diameter of the pit; 3) Shape of the pit; 4) Uniformity. f) If metal loss is less than specified corrosion/erosion allowance and adequate thickness is available for future corrosion, then monitoring techniques should be established. If metal loss is greater than specified corrosion/erosion allowance and repairs are not performed, a detailed engineering evaluation shall be performed to ensure continued safe operation. g) Techniques for evaluating local thin areas and pitting are referenced in applicable standards. See NBIC Part 2, 1.3.
SUPPLEMENT 7 INSPECTION OF PRESSURE VESSELS IN LIQUEFIED PETROLEUM GAS (LPG) SERVICE NBIC 2015 Edition
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S7.8.5 CORROSION a) Line and Crevice Corrosion For line and crevice corrosion, the depth of the corrosion shall not exceed
25% of the original wall thickness.
b) Isolated Pitting Isolated pits may be disregarded provided that:
1) Their depth is not more than 25% the required thickness of the container wall;
2) The total area of the pits does not exceed 7 sq. in. (4,500 sq. mm) within any 8 in. (200 mm) diameter
circle; and
3) The sum of their dimensions along any straight line within this circle does not exceed 2 in. (50 mm).
c) General Corrosion
For a corroded area of considerable size, the thickness along the most damaged area may be averaged
over a length not exceeding 10 in. (250 mm). The thickness at the thinnest point shall not be less than
75% of the required wall thickness, and the average shall not be less than 90% of the required wall
thickness. When general corrosion is identified that exceeds the limits set forth in this paragraph, the
pressure vessel shall be removed from service until it is repaired by a qualified “R” Stamp holder or
permanently removed from service unless an acceptable for service evaluation is performed in
accordance with NBIC Part 2, 4.4.
~
Add d) to S7.8.5:
d) When general, localized or pitting corrosion exceeds the specified corrosion/erosion allowance, but meets the requirements of b) and c), consideration should be given to previous inspections. Patterns of corrosion and damage that are expected to occur over the future service life should be used to determine a specific inspection plan. Repairs may be necessary to maintain a safe and satisfactory operating condition.
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S2.10.8 BOILER INSULATION AND JACKETING
a) The pressure retaining item shall be subjected to ultrasonic thickness testing (UT) per S2.6.2
to establish a baseline thickness for all of the boiler components. The original
Manufacturer’s Data Report may be used to establish baseline thickness. Recurring UT
inspections per S2.6.2 f may be taken at the bottom of the barrel and around the bottom of
the firebox.
b) Should removal of the insulation and jacket be requested by the Inspector, agreement
should be obtained by the owner or user, Inspector and jurisdiction if required.
If the Inspector requires further examination of the pressure retaining item, then they must
provide specific reason to the owner/user for removal of the insulation and jacket. Should
there be a disagreement between the Inspector and owner/user the Jurisdiction shall be
contacted.
NB15‐1601
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NB15-2206A- REVIEW PART 2 SUP 3 FOR PROPER USE OF SHALL, SHOULD, MAY
SUPPLEMENT 3 INSPECTION OF GRAPHITE PRESSURE EQUIPMENT
S3.1 SCOPE
a) The purpose of this supplement is to provide requirements for inservice inspection of pressure equipment manufactured from impervious graphite materials.
b) The impervious graphite (carbon, graphite, or graphite compound) used for the construction of graphite pressure vessels is a composite material, consisting of “raw” carbon or graphite that is impregnated with a resin using a tightly controlled pressure/heat cycle(s). The interaction between the raw material and the resin is the determining factor when considering the design characteristics of the material. The design characteristics include the strengths (flexural, compressive, and tensile), permeability, co-efficient of thermal expansion, thermal conductivity, and ultimately, the safe operating life of the vessel.
c) The process used in the manufacturing of the raw material is well documented. The expertise developed in this field allows for many different grades to be manufactured to meet the specific needs of various industries, including corrosive chemical-processing pressure vessels. In the chemical processing industry the properties of the raw material are dictated by the manufacturer of the impregnated material, based on the pressure/temperature cycle and the type of resin used for impregnation. The raw material requirements are defined and communicated to the manufacturer of the raw material. The cycle and resin type may vary from manufacturer to manufacturer, and also for each “grade” of impregnated material a manufacturer produces.
d) After over a century of experience with graphite pressure equipment, the essential variables of the process have been defined and apply universally to all manufacturers of impervious graphite equipment. Therefore, by requiring the essential variables of the resin impregnation cycle to be identified and verified, it is possible to assign a “lot” number to all certified materials at completion of the resin impregnation process. This can be done with the assurance of meaningful and consistent test results.
S3.2 APPLICATION
Due to inherent resistance to chemical attack, graphite pressure equipment is often used in corrosive applications, which may include lethal service.
S3.3 OPERATIONS
The owner should shall maintain controlled conditions for use of graphite pressure equipment, including the use of temperature and pressure recorders and/or operating logs. The owner should shall maintain operating procedures, and ensure that pressure and temperature are controlled. A thermal or pressure spike may damage the graphite or metal components.
S3.4 INSERVICE INSPECTION
a) The guidelines provided in NBIC Part 2, Section 1 shall apply to graphite pressure equipment, except as modified herein.
b) Graphite pressure vessels, pressure parts, and vessel components should shall receive an external visual examination biennially. All accessible surfaces should be chemically cleaned. Cleaning fluids containing strong oxidants should shall not be used.
c) Typical indicators that should necessitate graphite pressure equipment inspection, evaluation, and repair include:
1) Cross-contamination of either process or service fluids;
2) ObeservationObservation of external leaking;
3) Observation of reduced rate or excessive pressure drop; and
d) Cracks, bulges, blisters, delaminations, spalling conditions, and excessive erosion are cause for repair or replacement. Any surface discoloration should be recleaned and examined more closely to determine if a delamination or spalling condition exists.
e) Other typical discontinuities include chipping, erosion, baffle cutting due to vibration, and cement deterioration. All passageways are susceptible to fouling.
Hi Tom (and Mike), I can only look at the "For Committee Use Only" PDF of NBIC ‐ my printed copies are at home. 1.) When we introduced the differentiation between iron and steel staybolts, we introduced new tables. The 4 correct tables are in S2.10.4.1.a, S2.10.4.1.b, pages 152‐155. The 2 tables on pages 150, 151, titled S2.10.4.1 (imperial and metric) should have been deleted when the new tables were introduced, but were not. I've reported this error more than twice, but it appears that somebody is refusing to fix this. It was submitted correctly, it wasn't transcribed into the text correctly. 2.) The equation for rectangular stayed surfaces is found on S2.10.4 (pg. 145). It was transcribed incorrectly from our submission, where the denominator was supposed to be l^2 + w^2, but was written in as t^2 + w^2. These kinds of errors have happened repeatedly and seldom get fixed (even after I've reported them multiple times ‐ like #1 above). We typically submit them as PDF, should we be submitting them as DOCX files so the people can copy/paste rather than re‐type? The original proposal also suggested modifying S2.10.4.1 to handle rectangular pitches as well, but Tom decided against it because it may become too complicated even if it'd keep our text consistent with the construction codes (but changing p^2 with l*w can't be that complicated...) We never produced any tables for this work because those would have to be 3‐dimensional. 3.) In S2.10.6, the definition of 'hypotenuse' is unclear what the square‐root symbol is supposed to cover. 4.) The values in table S2.10.4.1.a (imperial units, pg. 152) do not match what we originally submitted (what my records say) ‐ wrong #'s! I randomly checked a couple and I believe that our submitted table is correct, and the published table (don't know where it came from) is incorrect. I did a few random checks on the other 3 tables and they appear OK. 5.) We are inconsistent on the use of the symbol for multiplication. In the 4 tables above, we use the 'dot' symbol. In the equation on page 145, for S2.10.4.1.b, we use the 'cross' symbol in the denominator but nothing in the numerator. For S2.10.4, we use the 'cross' symbol. For S2.10.4.1.a, there is no symbol. They are all acceptable, but should be consistent. 6.) There are a lot of formatting inconsistencies with the cylindrical surface tables (bolding, inverted table headings, etc.) that could be cleaned up.
7.) I've wondered, should we provide an example in the text for how to calculate MAWP for locally thinned areas, to help people understand how to use the text in S2.6.3.3? I've found these, and drafted these issues within an hour of starting on this. I'm kinda afraid to go looking for more transcription errors... ‐‐Rob Bryce
NB16‐0201 Supplement 7 (below) uses alternate terminology for pressure vessel(s). The uses are highlighted in bold large red. The general terms container, vessel, or tank were used as alternates to pressure vessel. If we want to standardize all uses to pressure vessel or pressure vessels, then the following edits just need to be made: 1) Replace “container” with “pressure vessel” 2) Replace “containers” with “pressure vessels” 3) Replace “tank” with “pressure vessel” 4) Replace “vessel” (when not preceded by “pressure”) with “pressure vessel” 5) Replace “vessels” (when not preceded by “pressure”) with “pressure vessels” SUPPLEMENT 7 INSPECTION OF PRESSURE VESSELS IN LIQUEFIED PETROLEUM GAS SERVICE S7.1 SCOPE a) ContainersPressure vessels designed for storing liquefied petroleum gas (LPG) can be stationary or can be mounted on skids. LPG is generally considered to be non‐corrosive to the interior of the vesselpressure vessel. NBIC Part 2, Supplement 7 is provided for guidance of a general nature for the owner, user, or jurisdictional authority. There may be occasions where more detailed procedures will be required such as changing from one service to another (e.g., above ground to underground; or containerspressure vessels that are commercially refurbished). b) The application of this supplement to underground containerspressure vessels will only be necessary when evidence of structural damage to the vesselpressure vessel has been observed, leakage has been determined, or the tankpressure vessel has been dug up, and is to be reinstalled. Special consideration will be given to containerspressure vessels that are going to be commercially refurbished (see NBIC Part 2, S7.9). S7.2 PRE‐INSPECTION ACTIVITIES a) A review of the known history of the containerpressure vessel should be performed. This should include a review of information, such as: 1) Operating conditions; 2) Historical contents of the vesselpressure vessel; 3) Results of any previous inspection; 4) Current jurisdictional inspection certificate, if required; 5) ASME Code symbol stamping or mark of code of construction, if required; and 6) National Board and/or jurisdictional registration number, if required. b) The containerpressure vessel shall be sufficiently cleaned to allow for visual inspection. For commercially refurbished containerspressure vessels see NBIC Part 2, S7.9. S7.3 INSERVICE INSPECTION FOR VESSELPRESSURE VESSELS IN LP GAS SERVICE The type of inspection given to pressure vessels should take into consideration the condition of the vesselpressure vessel and the environment in which it operates. The inspection may be external or
internal, and use a variety of nondestructive examination methods. Where there is no reason to suspect an unsafe condition or where there are no inspection openings, internal inspections need not be performed. When service conditions change from one service to another, i.e. above ground to underground; or containerspressure vessels that are commercially refurbished, an internal inspection may be required. The external inspection may be performed when the containerpressure vessel is pressurized or depressurized, but shall provide the necessary information that the essential sections of the vesselpressure vessel are of a condition to operate. S7.3.1 NONDESTRUCTIVE EXAMINATION (NDE) Listed below are a variety of methods that may be employed to assess the condition of the pressure vessel. These examination methods should be implemented by experienced and qualified individuals. Generally, some form of surface preparation will be required prior to the use of these examination methods: visual, magnetic particle, liquid penetrant, ultrasonic, radiography, radioscopy, eddy current, metallographic examination, and acoustic emission. When there is doubt as to the extent of a defect or detrimental condition found in a containerpressure vessel, additional NDE may be required. S7.4 EXTERNAL INSPECTION The containerpressure vessel shall be inspected for corrosion, distortion, cracking, or other conditions as described in this section. In addition, the following should be reviewed, where applicable: a) Insulation or Coating If the insulation or coating is in good condition and there is no reason to suspect an unsafe condition behind it, then it is not necessary to remove the insulation or coating in order to inspect the vesselpressure vessel. However, it may be advisable to remove a small portion of the insulation or coating in order to determine its condition and the condition of the containerpressure vessel surface. For commercially refurbished containerspressure vessels see NBIC Part 2, S7.9. b) Evidence of Leakage Any leakage of vapor or liquid shall be investigated. Leakage coming from behind insulation or coating, supports, or evidence of past leakage shall be thoroughly investigated by removing any insulation necessary until the source is established. c) Structural Attachments The pressure vessel mountings should be checked for adequate allowance for expansion and contraction, such as provided by slotted bolt holes or unobstructed saddle mountings. Attachments of legs, saddles, skirts, or other supports should be examined for distortion or cracks at welds. d) VesselPressure Vessel Connections Components that are exterior to the vesselpressure vessel and are accessible without disassembly shall be inspected as described in this paragraph. Manholes, reinforcing plates, nozzles, couplings, or other connections shall be examined for cracks, deformation, or other defects. Bolts or nuts should be examined for corrosion or defects. Weep holes in reinforcing plates shall remain open to provide visual evidence of leakage as well as to prevent pressure buildup between the vesselpressure vessel and the reinforcing plate. Accessible flange faces should be examined for distortion. It is not intended that flanges or other connections be opened unless there is evidence of corrosion to justify opening the connection. e) Fire Damage
Pressure vessels shall be carefully inspected for evidence of fire damage. The extent of fire damage determines the repair that is necessary, if any. (See NBIC Part 2, S7.7). S7.5 INTERNAL INSPECTION When there is a reason to suspect an unsafe condition, the suspect parts of the vesselpressure vessel shall be inspected and evaluated. The vesselpressure vessel shall be prepared and determined to be gas‐free and suitable for human entry prior to internal inspection. (See NBIC Part 2, 2.3.4). S7.6 LEAKS Leakage is unacceptable. When leaks are identified, the vesselpressure vessel shall be removed from service until repaired by a qualified repair organization or permanently removed from service. SUPPL. 7 S7.7 FIRE DAMAGE a) VesselPressure vessels in which bulging exceeds the limits of NBIC Part 2, S7.8.3 or distortion that exceeds the limits of the original code of construction (e.g., ASME Section VIII, Div. 1), shall be removed from service until repaired by a qualified repair organization or permanently removed from service. b) Common evidence of exposure to fire is: 1) Charring or burning of the paint or other protective coat; 2) Burning or scarring of the metal; 3) Distortion; or 4) Burning or melting of the valves. c) A pressure vessel that has been subjected to action of fire shall be removed from service until it has been properly evaluated. The general intent of this requirement is to remove from service pressure vessels which have been subject to action of fire that has changed the metallurgical structure or the strength properties of the steel. Visual examination with emphasis given to the condition of the protective coating can be used to evaluate exposure from a fire. This is normally determined by visual examination as described above with particular emphasis given to the condition of the protective coating. If there is evidence that the protective coating has been burned off any portion of the pressure vessel surface, or if the pressure vessel is burned, warped, or distorted, it is assumed that the pressure vessel has been overheated. If, however, the protective coating is only smudged, discolored, or blistered, and is found by examination to be intact underneath, the pressure vessel shall not be considered affected within the scope of this requirement. ContainersPressure vessels that have been involved in a fire and show no distortion shall be requalified for continued service by retesting using the liquid pressure test procedure applicable at the time of original fabrication. d) Subject to the acceptance of the Jurisdiction and the Inspector, alternate methods of pressure testing may be used. S7.8 ACCEPTANCE CRITERIA The acceptance criteria for LPG vesselpressure vessels is based on successfully passing inspections without showing conditions beyond the limits shown below. S7.8.1 CRACKS
Cracks in the pressure boundary (e.g., heads, shells, welds) are unacceptable. When a crack is identified, the vesselpressure vessel shall be removed from service until the crack is repaired by a qualified repair organization or permanently retired from service. (See NBIC Part 3, Repairs and Alterations). S7.8.2 DENTS a) Shells The maximum mean dent diameter in shells shall not exceed 5% of the shell diameter, and the maximum depth of the dent shall not exceed 5% of the mean dent diameter. The mean dent diameter is defined as the average of the maximum dent diameter and the minimum dent diameter. If any portion of the dent is closer to a weld than 5% of the shell diameter, the dent shall be treated as a dent in a weld area, see b) below. b) Welds The maximum mean dent diameter on welds (i.e., part of the deformation includes a weld) shall not exceed 10% of the shell diameter. The maximum depth shall not exceed 5% of the mean dent diameter. c) Head The maximum mean dent diameter on heads shall not exceed 10% of the shell diameter. The maximum depth shall not exceed 5% of the mean dent diameter. The use of a template may be required to measure dents on heads. d) When dents are identified which exceed the limits set forth in these paragraphs, the vesselpressure vessel shall be removed from service until the dents are repaired by a qualified repair organization or permanently retired from service. S7.8.3 BULGES a) Shells If a bulge is suspected, the circumference shall be measured at the suspect location and in several places remote from the suspect location. The variation between measurements shall not exceed 1%. b) Heads 1) If a bulge is suspected, the radius of curvature shall be measured by the use of templates. At any point the radius of curvature shall not exceed 1.25% of the diameter for the specified shape of the head. 2) When bulges are identified that exceed the limits set forth in these paragraphs, the vesselpressure vessel shall be removed from service until the bulges are repaired by a qualified repair organization or permanently retired from service. S7.8.4 CUTS OR GOUGES When a cut or a gouge exceeds 25% of the thickness of the vesselpressure vessel, the vesselpressure vessel shall be removed from service until it is repaired by a qualified repair organization or permanently removed from service. S7.8.5 CORROSION
a) Line and Crevice Corrosion For line and crevice corrosion, the depth of the corrosion shall not exceed 25% of the original wall thickness. b) Isolated Pitting Isolated pits may be disregarded provided that: 1) Their depth is not more than 25% the required thickness of the containerpressure vessel wall; 2) The total area of the pits does not exceed 7 sq. in. (4,500 sq. mm) within any 8 in. (200 mm) diameter circle; and 3) The sum of their dimensions along any straight line within this circle does not exceed 2 in. (50 mm). PL. 7 c) General Corrosion For a corroded area of considerable size, the thickness along the most damaged area may be averaged over a length not exceeding 10 in. (250 mm). The thickness at the thinnest point shall not be less than 75% of the required wall thickness, and the average shall not be less than 90% of the required wall thickness. When general corrosion is identified that exceeds the limits set forth in this paragraph, the pressure vessel shall be removed from service until it is repaired by a qualified “R” Stamp holder or permanently removed from service unless an acceptable for service evaluation is performed in accordance with NBIC Part 2, 4.4. S7.8.6 ANHYDROUS AMMONIA SERVICE ContainersPressure vessels that have been previously used in anhydrous ammonia service shall not be converted to LPG service. Any blue coloring of the brass valves indicates that the containerpressure vessel has been in anhydrous ammonia service. S7.9 ASME LPG CONTAINERSPRESSURE VESSELS LESS THAN 2000 GALLONS BEING REFURBISHED BY A COMMERCIAL SOURCE. Commercially refurbished containerspressure vessels are used containerspressure vessels that are temporarily taken out of service for repair and or renewal and sent to a company which specializes in this type of work. Because the history of some of these containerspressure vessels is unknown, special attention shall be given to inspection and repair before returning any of these containerspressure vessels back to service. ASME LPG containerspressure vessels less than 2,000 gal. (7,570 l) may be refurbished subject to the following conditions: a) A complete external inspection shall be completed under the guidelines of this supplement. If any defects are found, as defined in S7.8.1 through S7.8.5, the defect shall be repaired under NBIC Part 3, Repairs and Alterations, by qualified personnel or permanently removed from service; b) ContainersPressure vessels that have been previously used in anhydrous ammonia service shall not be converted to LPG service. See NBIC Part 2, S7.8.6; c) The coating on the outside of the containerpressure vessel shall be removed down to bare metal so that an inspection can be performed under the guidelines of this supplement; and d) Verify that there is no internal corrosion if the tankpressure vessel has had its valves removed or is known to have been out of service for an extended period.
S7.10 REQUIREMENTS FOR CHANGE OF SERVICE FROM ABOVE GROUND TO UNDERGROUND SERVICE ASME LPG storage pressure vessels may be altered from above ground (AG) service to underground (UG) service subject to the following conditions. a) VesselPressure vessels that have been previously used in anhydrous ammonia service are not permitted to be converted to LPG service. b) The outside surface of the vesselpressure vessel shall be cleaned to bare metal for an external inspection of the vesselpressure vessel under the guidelines of this supplement. Prior to placing underground, the outside surface of the vesselpressure vessel shall be prepared consistent with the paint manufactures specification and coated with a coating suitable for UG service. Any touch‐up coating shall be the same coating material. All corrosion shall be repaired in accordance with the NBIC. c) Verify that there is no internal corrosion due to valves having been removed while the containerpressure vessel is out or service. d) Any unused connections located on the vesselpressure vessel shall be closed by seal welding around a forged plug or removed using a flush patch. If a flush patch is used the material shall be the same material thickness and material grade as the original code of construction. e) All connections on top of the vesselpressure vessel, except for the liquid withdrawal opening, shall be replaced with a riser pipe with multi‐valve suitable for UG LPG service. The valve shall be enclosed in a protective housing and placed underground in accordance with jurisdictional requirements. f) The liquid withdrawal opening shall be located within the protective housing. g) The liquid level tube in the multivalve shall be the length required according to jurisdictional requirements. h) The NBIC nameplate shall be made of stainless steel and continuous welded to the vesselpressure vessel wall. The nameplate shall also have the information from the original nameplate. This shall include the manufactures name, containerpressure vessel serial number, National Board number, (if registered with the National Board) MAWP, year built, head and shell thickness, be stamped for “UG service”, the “liquid level tube length = inches” and the National Board “R” stamp. The original manufacturer’s nameplate shall remain attached to the vesselpressure vessel. See Part 2, Section 5.2 of this Part and NBIC, Part 3, Section 5.7 for additional stamping requirements. i) The support legs and lifting lugs may remain in place and shall be welded around the entire periphery to prevent crevices that create a potential area for corrosion. Unused attachments shall be removed and welds ground flush. j) A connection shall be added for the attachment of an anode for cathodic protection, per NFPA, 58 . k) All welding shall be performed by a holder of a current “R” Certificate of Authorization, using a qualified welding procedure.
e) Remove gage glass and valves, and inspect these connections for lime deposits and clean if necessary. This should be done once a year; more often if conditions warrant it.
f) After inspection, replace glass (clean if necessary). Also inspect gage glass sealing washers and re-place if necessary.
g) During cold weather, the historical boiler should be moved into a heated area and the boiler allowed to warm up in the air for several days until it is the same temperature as the air.
h) The initial fire-up should be done slowly to allow even heating of the boiler.
i) Before movement, the cylinder(s) should be warmed up by allowing a small quantity of steam to blow through them and out the cylinder cocks and exhaust passage(s). This is necessary to reduce the stress in the casting from thermal expansion of the metal.
j) Steam should be discharged through the cylinder cocks for several minutes to aid removal of any sol-vent, debris, or rust that may have formed in the steam pipes, cylinder, valve chest, and dry pipe.
k) All appliances should be tested under steam pressure before the historical boiler is moved or put under load.
S2.14 SAFETY PROCEDURES4
This chapter of text covers procedures in certain situations or emergencies that may occur.
S2.14.1 EXPERIENCE
a) Reading check lists and procedures can be of some value to get you thinking about what you are doing, but nothing can replace the experience gained by working beside conscientious and knowledgeable engineers. Ask questions, observe, read, listen, study, and think.
b) Safe operations depend upon thorough attention to detailed routines. Having procedures thought out, planned, and practiced before they are needed could minimize accidents and improve public safety. Know your abilities as well as the limitations of the machine that you are operating. In most cases know-ing and keeping your machine in top operating condition can prevent most emergency situations from occurring. However, sometimes problems or situations beyond your control do occur. In any situation the first rule to remember is to keep a cool head. Haste and panic can never solve any emergency.
c) Don’t be afraid to ask for help or advice. A lot of shows and public demonstrations have a designated individual in the area to ensure safe operation and assistance should a problem arise.
S2.14.2 STOPPING ENGINE IN AN EMERGENCY
a) Know how to stop the engine suddenly. For example, if someone or something runs out in front of the engine or some problem happens with whatever it is belted up to:
1) Close throttle.
2) Reverse valve quadrant position.
3) Open throttle for a moment (this will quickly stop your engine).
SUPPLEMENT 10 INSPECTION OF LIQUID CARBON DIOXIDE STORAGE VESSELS S10.1 SCOPE This supplement provides guidelines for owners or users for the inspection of Liquid Carbon Dioxide Storage Vessels (LCDSVs), fill boxes, fill lines and pressure relief discharge/vent circuits used for carbonated beverage systems, swimming pool pH control systems and other fill in place systems storing liquid CO2. S10.2 GENERAL REQUIREMENTS (ENCLOSED AND UNENCLOSED AREAS) The inspection should verify that LCDSVs are:
a) not located within 10 feet (3050 mm) of elevators, unprotected platform ledges or other areas where falling would result in dropping distances exceeding half the container height; b) installed with clearance to satisfactorily allow for filling, operation, maintenance, inspection and replacement of the vessel parts or appurtenances; c) not located on roofs; d) adequately supported to prevent the vessel from tipping or falling, and to meet seismic requirements as required by design; e) not located within 36 in. (915 mm) of electrical panels; and
f) located outdoors in areas in the vicinity of vehicular traffic are protected with barriers designed to prevent accidental impact by vehicles.
S10.3 ENCLOSED AREA LCDSV INSTALLATIONS The inspection should verify that:
a) LCDSV installations that are not periodically removed with remote fill connections: 1) Are equipped with a gas detection system installed in accordance with paragraph S10.5 of this supplement; 2) Have signage posted in accordance with paragraph S10.6 of this supplement; and 3) Are equipped with fill boxes, fill lines and safety relief/vent valve circuits installed in accordance with paragraph S10.4 of this supplement.
b) Portable LCDSV installations with no permanent remote fill connection: Warning: LCDSVs shall not be filled indoors or in enclosed areas under any circumstances. Tanks must always be moved to the outside to an unenclosed, free airflow area for filling.
1) Are equipped with a gas detection system installed in accordance with paragraph S10.5 of this supplement; 2) Have signage posted in accordance with paragraph S10.6 of this supplement. 3) Have a safety relief/vent valve circuit connected at all times except when the tank is being removed for filling. Connections may be fitted with quick disconnect fittings meeting the requirements of paragraph S10.4 of this supplement. 4) Are provided with a pathway that provides a smooth rolling surface to the outdoor, unenclosed fill area. There shall not be any stairs or other than minimal inclines in the pathway.
S10.4 FILL BOX LOCATION /SAFETY RELIEF/VENT VALVE CIRCUIT TERMINATION The inspection should verify that fill boxes and/or vent valve terminations are installed above grade, outdoors in an unenclosed, free airflow area, and that the fill connection is located so not to impede means of egress or the operation of sidewalk cellar entrance doors, including during the delivery process and that they are:
a) At least three (3) feet (915 mm) from any door or operable windows;* b) At least three (3) feet (915 mm) above grade;* c) Not located within ten (10) feet (3050 mm) from side to side at the same level or below, from any air intakes;* d) Not located within ten (10) feet (3050 mm) from stair wells that go below grade.* * Note: Many systems installed prior to 1/1/2014 do not meet the above requirements and the local Jurisdiction should be consulted for guidance.
S10.5 GAS DETECTION SYSTEMS Rooms or areas where carbon dioxide storage vessel(s) are located indoors or in enclosed or below grade outdoor locations shall be provided with a gas detection and alarm system for general area monitoring that is capable of detecting and notifying building occupants of a CO2 gas release. Alarms will be designed to activate a low level pre‐alarm at 1.5% concentration of CO2 and a full high alarm at 3% concentration of CO2 which is the NIOSH & ACGIH 15 minute Short Term Exposure Limit for CO2. These systems are not designed for employee personal exposure monitoring. Gas detection systems shall be installed and tested in accordance with manufactures installation instructions and the following requirements: A continuous gas detection system shall be provided in the room or area where container systems are filled and used, in areas where the heavier that air gas can congregate and in below grade outdoor
locations. Carbon dioxide (CO2) sensors shall be provided within 12 inches (305mm) of the floor in the area where the gas is most likely to accumulate or leaks are most likely to occur. The system shall be designed to detect and notify at a low level alarm and high level alarm.
a) The threshold for activation of the low level alarm shall not exceed a carbon dioxide concentration of 5,000 ppm (9,000 mg/m3) Time Weighted Average (TWA) over 8 hours. When carbon dioxide is detected at the low level alarm, the system shall activate a signal at a normally attended location within the building.
b) The threshold for activation of the high level alarm shall not exceed a carbon dioxide concentration 30,000 ppm (54,000 mg/m3). When carbon dioxide is detected at the high level alarm, the system shall activate an audible and visual alarm at a location approved by the jurisdiction having authority.
The inspection should verify that the gas detection system and audible alarm is operational and tested in accordance with manufacturer’s guidelines. The inspection should verify that audible alarms are placed at the entrance(s) to the room or area where the carbon dioxide storage vessel and/ or fill box is located to notify anyone who might try to enter the area of a potential problem. S10.6 SIGNAGE The inspection should verify that warning hazard identification signs are posted at the entrance to the building, room, enclosure, or enclosed area where the container is located. The warning sign shall be at least 8 in (200mm) wide and 6 in. (150mm) high. And indicate The wording shall be concise and easy to read and the upper portion of the sign must be orange as shown in figure NBIC Part 2, Figure S10.6. The size of the lettering must be as large as possible for the intended viewing distance and in accordance with jurisdictional requirements. When no jurisdictional requirements exist, the minimum letter height shall be in accordance with NEMA American National Standard for Environmental and Facility Safety Signs (ANSI Z535.2). The warning signs shall be as shown in figure S10.6.
CAUTION- CARBON DIOXIDE GAS
Ventilate the area before entering.
A high carbon dioxide (CO2) gas concentration
In this area can cause asphyxiation.
Figure S10.6 Additional instructional signage shall be posted outside of the area where the container is located and such signage shall contain at minimum the following information:
a) Carbon dioxide monitors for general area monitoring (not employee personal exposure monitoring) are provided in this area. These monitors are set to alarm at 5,000 ppm(1.5% concentration) for the low level alarm and at 30,000 ppm (3% concentration) for high level alarm.
b) Low Level Alarm (5,000 ppm) – Provide appropriate cross ventilation to the area. Personnel may enter area for short periods of time (not to exceed 15 minutes at a time) in order to identify and repair potential leaks. c) High Level Alarm (30,000 ppm) – Personnel should evacuate the area and nobody should enter the affected area without proper self‐contained breathing apparatus until the area is adequately ventilated and the concentration of CO2 is reduced below the high alarm limit.
S10.7 VALVES, PIPING, TUBING AND FITTINGS a) Materials – The inspection should verify that the materials selected for valves, piping, tubing, hoses and fittings used in the LCDSV system meet following requirements:
1) Components shall be rated for the operational temperatures and pressures encountered in the applicable circuit of the system. 2) All valves and fittings used on the LCDSV shall be rated for the maximum allowable working pressure(MAWP) stamped on the tank. 3) All piping, hoses and tubing used in the LCDSV system shall be rated for the working pressure of the applicable circuit in the system and have a burst pressure rating of at least four times the MAWP of the piping, hose or tubing.
b) Relief Valves – The inspection should verify that each LCDSV shall have at least one ASME/NB stamped & certified relief valve with a pressure setting at or below the MAWP of the tank. The relief valve shall be suitable for the temperatures and flows experienced during relief valve operation. The minimum relief valve capacity shall be designated by the manufacturer. Additional relief valves that do not require ASME stamps may be added per Compressed Gas Association pamphlet, CGA S‐1.3 Pressure Relief Device Standards Part 3, Stationary Storage Containers for Compressed Gases, recommendations. Discharge lines from the relief valves shall be sized in accordance with NBIC Part 2, Tables S10‐a and S10‐b. Note: Due to the design of the LCDSV the discharge line may be smaller in diameter than the relief valve outlet size. Caution: Company’s and or individuals filling or refilling LCDSV’s shall be responsible for utilizing fill equipment that is acceptable to the manufacturer to prevent over pressurization of the vessel. c) Isolation Valves – The inspection should verify that each LCDSV shall have an isolation valve installed on the fill line and tank discharge, or gas supply line in accordance with the following requirements:
1) Isolation valves shall be located on the tank or at an accessible point as near to the storage tank a possible. 2) All valves shall be designed or marked to indicate clearly whether they are open or closed. 3) All valves shall be capable of being locked or tagged in the closed position for servicing. 4) Gas supply and liquid CO2 fill valves shall be clearly marked for easy identification.
d) Safety Relief/Vent Lines – The inspection, where possible, should verify the integrity of the pressure relief/vent line from the pressure relief valve to outside vent line discharge fitting. All connections shall be securely fastened to the LCDSV. The minimum size and length of the lines shall be in accordance with NBIC Part 2, Tables S2 10‐a and S2 10‐b. Fittings or other connections may result in a localized reduction in diameter have been factored into the lengths given by the NBIC Part 2, Tables S2 10‐a and S2 10‐b. e) Indicators – The inspection should verify the LCDSV is provided with pressure gauges and liquid level gauges or indicators. Where the filling connection is remote from the storage container, a means shall be provided to determine when the container is filled to its design capacity that is visible from the filling location.
Table S10-a Minimum LCDSV System Pressure Relief/Vent Line Requirements (Metallic) Tank Size (Pounds) Fire Flow Rate Requirements (Pounds per Minute) Maximum Length of 3/8 inch ID Nominal Metallic Tube Allowed Maximum Length of 1/2 inch ID Nominal Metallic Tube Allowed Less than 500 2.60 maximum 80 feet 100 feet 500‐750 3.85 maximum 55 feet 100 feet Over 750‐1000 5.51 maximum 18 feet 100 feet Table S10-b Minimum LCDSV System Pressure Relief/Vent Line Requirements (Plastic/Polymer) Tank Size (Pounds) Fire Flow Rate Requirements (Pounds per Minute) Maximum Length of 3/8 inch ID Plastic/Polymer Materials Tube Allowed Maximum Length of ½ inch ID Plastic/Polymer Materials Tube Allowed Less than 500 2.60 maximum 100 feet 100 feet 500‐750 3.85 maximum 100 feet 100 feet Over 750‐1000 5.51 maximum N/A see ½ inch 100 feet Table S10-a Metric Minimum LCDSV System Pressure Relief /Vent Line Requirements (Metallic) Tank Size (Kilograms) Fire Flow Rate Requirements (Kilograms per Minute) Maximum Length of 10mm ID Nominal Metallic Tube Allowed
Maximum Length of 13mm ID Nominal Metallic Tube Allowed Less than 227 1.8 maximum 24 m 30.5 m 227‐340 1.75 maximum 17 m 30.5 m 340‐454 2.50 maximum 5.5 m 30.5 m Table S10-b Metric Minimum LCDSV System Pressure Relief/Vent Line Requirements (Plastic/Polymer) Tank size (kg) Fire Flow Rate (kg per Minute) Maximum Length of 10 mm ID Nominal Metallic Tube Allowed Maximum Length of 10 mm ID Plastic/Polymer Materials Tube Allowed Less than 227 1.18 maximum 30.5 m 30.5 m 227‐340 1.75 maximum 30.5 m 30.5 m Over 340‐454 2.5 maximum N/A see 13 mm 30.5 m Note: Due to the design of the LCDSV the discharge line may be smaller in diameter than the pressure relief valve outlet size but shall not be smaller than that shown in tables NBIC Part 2, S10‐a and S10‐b.
NB16‐0809D – 7‐13‐16 ‐ Besserman 1.1 SCOPE This sectionThis part provides general guidelines and requirements and guidelines for conducting inservice inspection of pressure‐retaining items. AppropriatelyThis section provides general requirements and guidelines for inservice inspection. , tThis section includes precautions for the safety of inspection personnel. The safety of the public and the Inspector is the most important aspect of any inspection activity.
2.1 SCOPE a) This section describes provides general and detailed inspection requirements and guidelines for pressure‐retaining items to determine corrosion deterioration and possible prevention of failures for boilers, pressure vessels, piping, and pressure relief devices. b) Materials to be inspected shall be suitably prepared so that surface irregularities will not be confused with or mask any defects. Material conditioning such as cleaning, buffing, wire brushing, or grinding may be required by procedure or, if requested, by the Inspector. The Inspector may require insulation or component parts to be removed.
3.1 SCOPE This section describes damage mechanisms applicable to pressure‐retaining items. Further information concerning metallurgical properties of steels and nonferrous alloys are described in ASME Section II, Part D, of the Boiler and Pressure Vessel Code, Non Mandatory Appendix A, titled Metallurgical Phenomena. A damage (or deterioration) mechanism is a process that induces deleterious micro and/or macro material changes over time that are harmful to the material condition or mechanical properties. Damage mechanisms are usually incremental, cumulative and, in some instances, unrecoverable. Common damage mechanisms include corrosion, chemical attack, creep, erosion, fatigue, fracture, and thermal aging.
4.1 SCOPE This section describes acceptable examination and test methods that are available to the Inspector during inspection of pressure‐retaining items. This section also describes evaluation of test results and assessment methodologies.
5.1 SCOPE This section provides guidelines and requirementsrequirements and guidelines for stamping and documentation (forms) for inservice inspections of PRIs. This section also describes evaluation of inspection results and assessment methodologies.
S1.1 SCOPE This This supplement supplement is provided as a guideprovides requirements and guidelines for inspection and storage of steam locomotive firetube boilers operating on tracks gaged 24 in (610 mm) or greater or for steam locomotives under the requirements of the Federal Railroad Administration (FRA). These rules shall be used in conjunction with the applicable rules of the NBIC. See NBIC Part 2, Figures S1.1‐a and S1.1‐b.
S2.1 SCOPE a) This supplement is provided as a This supplement guideprovides requirements and guidelines to for inspection of historical steam boilers of riveted and/or welded construction not falling under the scope of NBIC Part 2, Supplement 1. These historical steam boilers would include: steam tractors, traction engines, hobby steam boilers, portable steam boilers, certain steam locomotive boilers, and other such boilers that are being preserved, restored, and maintained for demonstration, viewing, or educational purposes. (See Note below) Note: This supplement is not to be used for steam locomotive boilers operating on tracks gaged 24 in. (610 mm) or greater or for steam locomotive boilers falling under the requirements of the Federal Railroad Administration (FRA). FRA rules for steam locomotive boilers are published in 49 CFR 230. Specific rules and special requirements for inspection, repairs, alterations, and storage of steam locomotive boilers are identified in NBIC Part 2, Supplement 1. b) The rules specified in this supplement shall be used in conjunction with the applicable rules in this code. References specified or contained in this supplement may provide additional information to assist the user when applying the requirements of this supplement.
S3.1 SCOPE a) The purpose of this supplement is This supplement to provides requirements and guidelines for inservice inspection of pressure equipment manufactured from impervious graphite materials. ab) The impervious graphite (carbon, graphite, or graphite compound) used for the construction of graphite pressure vessels is a composite material, consisting of “raw” carbon or graphite that is impregnated with a resin using a tightly controlled pressure/heat cycle(s). The interaction between the raw material and the resin is the determining factor when considering the design characteristics of the material. The design characteristics include the strengths (flexural, compressive, and tensile), permeability, co‐efficient of thermal expansion, thermal conductivity, and ultimately, the safe operating life of the vessel. bc) The process used in the manufacturing of the raw material is well documented. The expertise developed in this field allows for many different grades to be manufactured to meet the specific needs of various industries, including corrosive chemical‐processing pressure vessels. In the chemical processing industry the properties of the raw material are dictated by the manufacturer of the impregnated material, based on the pressure/temperature cycle and the type of resin used for impregnation. The raw material requirements are defined and communicated to the manufacturer of the raw material. The cycle and resin type may vary from manufacturer to manufacturer, and also for each “grade” of impregnated material a manufacturer produces. cd) After over a century of experience with graphite pressure equipment, the essential variables of the process have been defined and apply universally to all manufacturers of impervious graphite equipment. Therefore, by requiring the essential variables of the resin impregnation cycle to be identified and verified, it is possible to assign a “lot” number to all certified materials at completion of the resin impregnation process. This can be done with the assurance of meaningful and consistent test results.
S4.1 SCOPE This supplement provides specific requirements and guidelines for inspection of fiber‐reinforced thermosetting plastic pressure equipment.
a) This This supplement supplement describes provides guidelines for the inservice inspection of a Yankee dryer. A Yankee dryer is a pressure vessel with the following characteristics: a) A Yankee dryer is a rotating steam‐pressurized cylindrical vessel commonly used in the paper industry, and is made of cast iron, finished to a high surface quality, and characterized by a center shaft connecting the heads. b) Yankee dryers are primarily used in the production of tissue‐type paper products. When used to produce machine‐glazed (MG) paper, the dryer is termed an MG cylinder. A wet paper web is pressed onto the finished dryer surface using one or two pressure (pressing) rolls. Paper is dried through a combination of mechanical dewatering by the pressure roll(s); thermal drying by the pressurized Yankee dryer; and a steam‐heated or fuel‐fired hood. After drying, the paper web is removed from the dryer. c) The dryer is typically manufactured in a range of outside diameters from 8 to 23 ft. (2.4 m to 7 m), widths from 8 to 28 ft. (2.4 m to 8.5 m), pressurized and heated with steam up to 160 psi (1,100 kPa), and rotated at speeds up to 7,000 ft./min (2,135 m/min). Typical pressure roll loads against the Yankee dryer are up to 600 pounds per linear inch (105 kN/m). A thermal load results from the drying process due to difference in temperature between internal and external shell surfaces. The dryer has an internal system to remove steam and condensate. These vessels can weigh up to 220 tons (200 tonnes). d) The typical Yankee dryer is an assembly of several large castings. The shell is normally a gray iron casting, in accordance with ASME designation SA‐278. Shells internally may be smooth bore or ribbed. Heads, center shafts, and journals may be gray cast iron, ductile cast iron, or steel.
S6.1 SCOPE This supplement provides rules requirements and guidelines for continued service inspections of transport tanks, i.e., cargo tanks, rail tanks, portable tanks, and ton tanks that transport dangerous goods as required in the Code of Federal Regulations, Title 49, Parts 100 through 185, and the United Nations Recommendations for Transport of Danger ous Goods‐Model Regulations. This supplement, where applicable, shall be used in conjunction with other applicable Parts of the National Board Inspection Code (NBIC) and Section XII, Transport Tanks, of the ASME Boiler and Pressure Vessel Code.
S7.1 SCOPE This supplement provides requirements and guidelines for the inspection of pressure vessels in liquefied petroleum gas service. a) Containers designed for storing liquefied petroleum gas (LPG) can be stationary or can be mounted on skids. LPG is generally considered to be non‐corrosive to the interior of the vessel. NBIC Part 2, Supplement 7 is provided for This supplement provides guidance guidelines of a general nature for the owner, user, or jurisdictional authority. There may be occasions where more detailed procedures will be required such as changing from one service to another (e.g., above ground to underground; or containers that are commercially refurbished). b) The application of this supplement to underground containers will only be necessary when evidence of structural damage to the vessel has been observed, leakage has been determined, or the tank has been dug up, and is to be reinstalled. Special consideration will be given to containers that are going to be commercially refurbished (see NBIC Part 2, S7.9).
S8.1 SCOPE This supplement provides guidelines for determining the pressure differential between the pressure relief valve setting and the boiler or pressure vessel operating pressure. If a safety valve or safety relief valve is subjected to
pressure at or near its set pressure, it will tend to weep or simmer, and deposits may accumulate in the seat and disk area. Eventually, this can cause the valve to freeze closed and thereafter the valve could fail to open at the set pressure. Unless the source of pressure to the boiler or pressure vessel is interrupted, the pressure could exceed the rupture pressure of the vessel. It is important that the pressure differential between the valve set pressure and the boiler or pressure vessel operating pressure is sufficiently large to prevent the valve from weeping or simmering.
S9.1 SCOPE This supplement provides requirements and guidelines to be followed when a change of service or service type is made to a pressure‐retaining item. Whenever there is a change of service, the jurisdiction where the pressure‐retaining item is to be operated shall be notified for acceptance. Any specific jurisdictional requirements shall be met.
S10.1 SCO PE This supplement provides specific requirements and guidelines for inspection of high‐pressure composite pressure vessels, hereafter referred to as vessels. This supplement is applicable to pressure vessels with a design pressure that exceeds 3,000 psi (21 MPa) but not greater than 15,000 psi (103 MPa), and is applicable to the following four types of pressure vessels: a) Metallic vessel with a hoop Fiber Reinforced Plastic (FRP) wrap over the straight shell cylindrical part of the vessel (both load sharing). b) Fully wrapped FRP vessel with a non‐load sharing metallic liner. c) Fully wrapped FRP vessel with a non‐load sharing non‐metallic liner. d) Fully wrapped FRP vessel with load sharing metallic liner. This supplement is intended for inspection of ASME Section X, Class III, vessels and ASME Section VIII, Division 3, Composite Reinforced Pressure Vessels (CRPVs). However, it may be used for inspection of similar vessels manufactured to other construction codes with approval of the jurisdiction in which the vessels are installed.
PART 2, SECTION 3 INSPECTION — CORROSION AND FAILURE MECHANISMS 3.1 SCOPE This section describes damage mechanisms applicable to pressure-retaining items. Further information concerning metallurgical properties of steels and nonferrous alloys are described in ASME Section II, Part D, of the Boiler and Pressure Vessel Code, Non Mandatory Appendix A, titled Metallurgical Phenomena.
The installation date should be stamped or stenciled on the replaced boiler piping. Alternatively, the
installation date may be documented in permanent boiler records, such as the operator log book.
S2.10 MAXIMUM ALLOWABLE WORKING PRESSURE (MAWP)
The MAWP of a boiler shall be determined by computing the strength of each boiler component. The
computed strength of the weakest component using the factor of safety allowed by these rules shall
determine the MAWP.
Note: The rules of ASME Section I 1971 Edition, Part “PR”, and “PFT” and 2015 Edition, Part “PL” may be
used for determining specific requirements of design and construction of boilers and parts fabricated by
riveting.3 Copies of these referenced ASME sections may be obtained by contacting the National board
of boiler and Pressure Vessel Inspectors, 1055 Crupper Ave., OH 43229 or www.nationalboard.org.
S2.10.1 STRENGTH
a) In calculating the MAWP, when the tensile strength of the steel or wrought iron is known, that value
shall be used. When the tensile strength of the steel or wrought iron is not known, the values to be used
are 55,000 psi (379 MPa) for steel and 45,000 psi (310 MPa) for wrought iron. Original steel stamp
marks, original material certifications, or current laboratory tests are acceptable sources for verification
of tensile strength. Catalogs and advertising literature are not acceptable sources for tensile strength
values.
b) In computing the ultimate strength of rivets in shear, the following values shall be used:
1) Iron rivets in single shear 38,000 psi (262 MPa)
2) Iron rivets in double shear 76,000 psi (524 MPa)
3) Steel rivets in single shear 44,000 psi (303 MPa)
4) Steel rivets in double shear 88,000 psi (607 MPa)
c) The resistance to crushing of mild steel shall be taken as 95,000 psi (655 MPa) unless otherwise
known. d) S = TS/FS. See definitions of nomenclature in NBIC Part 2,S2.10.6.
3 Copies of ASME Section I 1971 Edition Part “PR” and “PFT” referenced section may be obtained by
contacting the National Board of Boiler and Pressure Vessel Inspectors, 1055 Crupper Ave., Columbus,
OH 43229.
Attachment Page 116
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SC Inspection Attachments /NB16-2201 - 160721 - Metzmaier - Revised at MC
Action Item Request Form
8.3 CODE REVISIONS OR ADDITIONS Request for Code revisions or additions shall provide the following: a) Proposed Revisions or Additions For revisions, identify the rules of the Code that require revision and submit a copy of the appropriate rules as they appear in the Code, marked up with the proposed revision. For additions, provide the recommended wording referenced to the existing Code rules.
Existing Text:
Provide a brief explanation of the need for the revision or addition.
c) Background Information Provide background information to support the revision or addition, including any data or changes in technology that form the basis for the request that will allow the Committee to adequately evaluate the proposed revision or addition. Sketches, tables, figures, and graphs should be submitted as appropriate. When applicable, identify any pertinent paragraph in the Code that would be affected by the revision or addition and identify paragraphs in the Code that reference the paragraphs that are to be revised or added.
The present wording does not specify the type of valve to be used in a given location. Specifically,
examples of globe valves used in blow‐down applications exist, which are prohibited in other codes.
Suggest additional wording to keep text consistent with other standards.
Proposed Alternate Q&R Subject: NBIC 2013, Part 3, 3.2.6, Reference To Other Codes And Standards Q: The Inspector and, as required, the Jurisdiction have accepted the use of ASME PCC-2, Article 2.12, for work on a pressure retaining item (PRI). Is the installation of a fillet welded patch meeting the limitations, design, fabrication, examination and testing requirements of ASME PCC-2, Article 2.12, considered an alteration to the PRI? R: Yes. Rationale: The NBIC defines an alteration as a change in the item described on the original manufacturer’s data report which affects the pressure containing capability of the item. While this definition may not apply when there is no manufacturer’s data report, Part 3, 3.4.3(d), gives as an example of an alteration “A change in the dimensions or contour of a pressure-retaining item”. Also, installation of a fillet welded patch using PCC-2, Article 2.12 as a guide requires extensive engineering evaluation, design calculations as well as examination and testing of the work. Installation of a fillet welded patch is certainly not a “replacement in kind” and is not described by any other example of a repair given in Part 3, 3.3.3.
Interpretation IN15-1101 Proposed Interpretation Inquiry: IN15-1101 Source: Mr. Earl Tullis, Dow Subject: NBIC 2013 Part 3 (3.2.6) Edition: Question: Is the use of ASME PCC-2 Article 2.12 Fillet Welded Patches an alteration? Reply: Yes Committee’s Are fillet welded patches permitted by the NBIC for Question: repairs or alterations to pressure retaining itmes? Committee’s Reply:
Fillet welded patches are not addressed by the NBIC.
Rationale: Alterative repair methods addressed by other referenced codes and standards may be permitted provided they
are approved by the Inspector and Jurisdiction. SC Vote NBIC Vote
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SC Repairs and Alterations Attachments /IN15-1101 JTP Proposed Alternate Q&R Rev 2 final 2016-07-20
Request for Inerpretation Robert V. Underwood HSB Global Standards
Purpose To determine if explosive welding of plugs into leaking heat exchanger tubes is considered a repair per the NBIC Part 3.
Scope: Repairs to leaking vessel heat exchanger tubes by explosively welding plugs into them.
Background An “R” Certificate Holder asked if plugging leaking tubes in an ASME feedwater heater by the explosive welding process was considered a repair per the NBIC Part 3. Apparently, this is common repair to feedwater heaters installed in utilities throughout the U.S. It is also commonly accepted as a non‐Code repair. Many of these companies who perform the tube plugging do not have “R” Certificates of Authorization. Some in the industry have the opinion that explosive “plugging” is not considered welding and is not a Code repair. However, the repair firms that perform explosive plugging advertise this as a welding process. Further, ASME Section IX defines weld as a localized coalescence of metals produced by heat or the application of pressure. Paragraph UW‐27(a)(2) of ASME Section VIII, Div. 1 permits the explosive welding process and footnote 70 defines explosive welding as a solid state welding process wherin coalescence is produced by the application of pressure by means of explosion. Although the NBIC does not address explosive welding, the 2015 Edition now has rules for plugging of firetube boilers. Also, it is clear that the ASME Code defines explosive welding and the repair firms are claiming they are explosively welding these plugs into the tubes.
Proposed Question
Question: Is explosion welding of plugs into leaking heat exchanger tubes considered a repair per the NBIC Part 3? Proposed Reply: Yes
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SC Repairs and Alterations Attachments /IN16-0101 Explosion Plugging of HX Tubes R1 7-21-16 final MC
IN16-0601 Besserman 5-16-16 Dear Sir, Thank you for your reply. Please find below the background of the inquiry. Background: Heat exchanger has (was) installed on remote offshore site in 2011. During routine inspection by the owners, it was revealed that tubesheet and channel flange needs clad restoration. Client wish to send these parts only to manufacturers' location for repair. Client will send the photograph of original nameplate and MDR of the vessel for identification. They do not wish the manufacturer or their inspector to visit the site due to security and logistic reasons. However, they will provide all the nameplate photos, MDR and GA drg to identify the parts. Also after completing the repair, they wish the manufacturer to send the R stamped nameplate to site. Client will install that nameplate on the correct vessel and send the photographs for verification to manufacturer and their Inspector. Inquiry: Is this method of verification acceptable as per NBIC cl. 1.3.2.C) considering it as repair and not routine repair as PWHT is involved in the repair. Expected reply: Yes / No With best regards, Pradeep Subhedar
Interpretation IN16-0601 Proposed Interpretation
Inquiry IN16-0601 Source Mr. Pradeep Subhedar Subject Method of Verification of the Installation of a Repair Nameplate by the
Inspector Question 1 Is owner’s method of verification of the installation of the Repair Nameplate
acceptable per NBIC 1.3.2 c) considering it as repair and not routine repair as PWHT is involved in the repair?
Reply 1 Yes (with the authorization and knowledge of the Inspector)
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SC Repairs and Alterations Attachments /IN16-0601 Rev 2 7-20-2016 Final
Inquiry IN16-0601 Source Mr. Pradeep Subhedar Subject 1.3.2 c) Method of Verification of the Installation of a Repair Nameplate by the
Inspector Committee Question 1
Does the NBIC address the method of verification by the Inspector of the repair or alteration nameplate stamping and nameplate attachment to the pressure retaining item?
Reply 1 No Rationale NBIC Part 3, 1.3.2 c) does not address the method of verification by the
Inspector, of the repair or alteration nameplate stamping or nameplate attachment to the pressure retaining item. 1.3.2 ACCEPTANCE INSPECTION c) The Inspector shall verify the stamping or nameplate is correct and where applicable, the nameplate has been properly attached.
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SC Repairs and Alterations Attachments /IN16-0601 Rev 2 7-20-2016 Final
1
File Number: NB11-0204B Task Group Mike Wahl (PM) J. Larson, F. Johnson Subject: Part 3 Supplement 2 Pages: See Below Proposal: Several areas in the repair section need updating for NDE examination.
1. In Part 3, Supplement 2, S2.11 (page 140) add the following text the existing statement:
The nondestructive examination (NDE) requirements, including technique, extent of coverage, procedures, personnel qualification, and acceptance criteria, shall be in accordance with the original code of construction for the pressure-retaining item. Weld repairs and alterations shall be subjected to the same nondestructive examination requirements as the original welds. Where the original code of construction is unknown or the NDE method is not possible or practicable, alternative NDE methods may be used. These methods shall be acceptable to the owner, the Inspector and where required, the Jurisdiction of the pressure-retaining item. NDE methods used shall be suitable for providing meaningful results to verify the integrity of the repair and or alteration. Exclusive use of visual examination (VT) for repair inspection is only permitted when following the requirements of Part 3, 4.4.1 e).
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2
2. In Part 3, Supplement 2, S2.13 (c) (page 140) replace (c) with statement currently used in Part 3, 3.3.4.1 and Supplement 1, S1.2.10. This changes the paragraph by:
a. Adding a reference to Part 3,3.3.4.8, b. Adding the inspector and jurisdiction acceptance of other corrective measures c. Removes the last two sentences that are covered in detail in Supplement 2.
c) Except as provided in NBIC Part 3, 3.3.4.8, a repair of a defect in a welded joint or base material shall not be made until the defect has been removed. A suitable nondestructive examination (NDE) method, such as magnetic particle (MT) or liquid penetrant (PT), may be necessary to ensure complete removal of the defect. If the defect penetrates the full thickness of the material, the repair shall be made with a full penetration weld such as a double buttweld or single buttweld with or without backing. Where circumstances indicate that the defect is likely to recur, consideration should be given to removing the defective area and installing a flush patch or taking other corrective measures acceptable to the Inspector, and when required, by the Jurisdiction. A repair of a bulge or blister shall be made if a bulge or blister will affect the pressure retaining capability of the plate or tube or when evidence of leakage is noted. Defects such as cracks, grooving, and wastage may be repaired by weld buildup, welded repair, a welded flush patch, or a riveted patch as appropriate.
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3
3. In Part 3, Supplement 2, In S.2.13.9.2 (c) (page150) change “be radiographed” to “have Volumetric NDE performed”
4. In Part 3, Supplement 2, In S.2.13.9.3 (a) (page150) change “be radiographically examined” to “have Volumetric NDE performed”
Replace “be radiographed” to “have Volumetric NDE performed”
Replace “be radiographically examined” with “have volumetric NDE performed”
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4
5. In Part 3, Supplement 2, S.2.13.10.2 (page 153) add (c) stating:
c) If the load on repair area is carried by other forms of construction, such as staybolts,
rivets or tubes, volumetric NDE of the welds is not required.
6. In Part 3, Supplement 2, S.2.13.10.3 b) (page 153) change “radiographically examined”
to “Volumetric NDE”
Replace “be radiographically examined” with “have volumetric NDE performed”
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5
7. In Part 3, Supplement 2, S.2.13.10.3 d) (page 153) remove current statement redundant with information in S2.13.11.3 and reference S2.13.11.3 Welded Flush Patches in Firebox and Tubesheet Knuckles. Text for d) would change to :
d) For welded flush patches in stayed areas that include a knuckle area see S2.13.11.3.
Welded Flush Patches in Firebox and Tubesheet Knuckles.
8. In Part 3, Supplement 2, Figure S2.13.10.3-a (page 154) Remove figure S2.13.10.3-b Figure will be added to S2.13.11.3 to have all knuckle patch information in one area.
Remove This Figure
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9. In Part3, Supplement 2, S.2.13.11.2 (b) (page 156) replace (b) with the following text:
b) Welded repair of cracks within the points of tangency of a knuckle are permitted. All welds
within the points of tangency of the knuckle shall have volumetric NDE performed.
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7
10. In Part 3, Supplement 2, Figure S2.13.11.2 (page 157) Remove figure because all welded repair of cracks in knuckle areas require nondestructive examination to be performed from the changes to S.2.13.11.2 (b)
Remove This Figure
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8
11. In Part 3, Supplement 2, S2.13.11.3 (page 157) Replace current text with a), b), & c) to have all knuckle information in one area (information moved from S S.2.13.10.3) and give more information. New text would state:
a) Any patch not supported by means other than the weld, such as rivets, staybolts, tubes, or other forms of construction, shall have volumetric NDE performed on the weld seams. (See NBIC Part 3, Figure S2.13.11.3-b).
b) Weld seams parallel to a knuckle shall be located no closer to the knuckle than the knuckle point of tangency. (See NBIC Part 3, Figure S2.13.11.3-a).
c) All other requirements specified in NBIC Part 3, S2.13.9.3, S2.13.10.3 and S2.13.12.3 shall be followed
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9
12. In Part 3, Supplement 2, Figure S2.13.11.3 (page 158) replace current figure S2.13.11.3 with two new ones showing the changes in S2.13.11.3.
Note: Figure S2.13.11.3-a and Figure S2.13.11.3-b have been created in Solid Works and can be exported to a several different file formats. Please e-mail [email protected] and I can send requested format.
Attachment Page 132
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10
Add This Figure
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11
Add This Figure
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Page 1 of 3 NB13-0902
1. Add New Text
S2.13.12.3 WELDED FLUSH PATCHES IN TUBESHEETS a) The method of repair shall follow the same requirements identified in S2.13.10.3 with the following requirement as noted below: 1) Tubes, staybolts, and rivets should be installed after welding of the patch is completed. (See NBIC Part 3, Figure S2.13.12.3).
2) A flush patch repair can be welded through tube holes or around tube holes. (See NBIC Part 3, Figure S2.13.12.3)
3) If the Flush Patch repair extends through the tube sheet radius either the sheet should be flanged to match the original tube sheet flange or a welded alternative may be used as shown in NBIC Part 3, Figure S2.13.12.3.A
Attachment Page 135
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SC Repairs and Alterations Attachments /NB13-0902 formated WV 7-13-2016 Final (1)
Page 2 of 3 NB13-0902
2. Update Figure S2.13.12.3
Add a 4th diagram to figure S2.13.12.3 to show a tube sheet repair, which encompasses the hand hole opening area, however doesn’t extend through the tube area.
Add 4th diagram here
Attachment Page 136
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SC Repairs and Alterations Attachments /NB13-0902 formated WV 7-13-2016 Final (1)
Page 3 of 3 NB13-0902
3. Add Figure S2.13.12.3A
Add figure S2.13.12.3a to show acceptable and non-acceptable tube sheet repair methods. Info Note: Figure S2.13.12.3A has been created in Solid Works and can be exported to a several different file
formats. Please e-mail [email protected] and I can send requested format.
Attachment Page 137
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SC Repairs and Alterations Attachments /NB13-0902 formated WV 7-13-2016 Final (1)
1
Item NB14-0301, add Encapsulation as a method of altering a Pressure Retaining Item (PRI)
All New 3.4.3 Paragraph PROPOSED:
3.4.3 ENCAPSULATION
Encapsulation is a method used to maintain the pressure retaining capability of pipe, nozzles, fittings and valves an item (with the exception of fire tube boilers) by fabricating a new pressure containing boundary over the item in the form of a “welded leak box” as described by ASME PCC-2, Article 2.4.
a) Except as required in 3.4.3 c)(1), ASME PCC-2 should be used as a guideline for the design of the welded leak box and fabrication shall be in accordance with the original code of construction, when practicable. Design of the encapsulation shall consider original design conditions, taking into account current service conditions and damage mechanisms. Use of this method shall be acceptable to the inspector and when required, the jurisdiction.
b) The “R” Certificate Holder responsible for the design of the encapsulation shall ensure a Fitness for Service Assessment (FFSA) has been performed on the portion of the item being encapsulated in accordance with NBIC, Part 2, 4.4.1, supporting the continued service of the item. The leak box shall not remain in place beyond the calculated remaining life of the encapsulated portion of the pressure retaining item.
1) The remaining life of the encapsulated pressure retaining item shall be documented on the Report of FFSA in the Remarks section. The Report of FFSA Form shall be affixed to the Form R-2 and identified in the Remarks section.
2) The leak box shall fully encapsulate the thinned or leaking area, as specified in the FFSA, to the distance where the minimum required metal thickness is verified. Wall thickness shall be verified in the area to be welded.
3) A Welded Leak Box shall not be used to encapsulate a crack unless it has been removed and repaired in accordance with Part 3, Paragraph 3.3.4.2 a).
c) Hazards associated with welding on degraded components should be addressed with the Owner-User by the use of engineering controls, administrative controls and personal protective equipment.
1) When the pressure retaining item will remain in service while implementing this method, the requirements and limitations described within ASME PCC-2, Part-1 shall be used in conjunction with ASME PCC-2, Part-2, Article 2.10.
2) API RP-2201, “Safe Hot Tapping Practices in the Petroleum and Petrochemical Industries” may be used as a guideline for identifying hazards associated with welding to a component that is under pressure, including service restrictions.
d) Visual examination shall be in accordance with the NBIC, Part 3, Paragraph 4.4.1 e).
e) Completion of the FORM R-2 shall follow the requirements for PREPARATION, DISTRIBUTION, and REGISTRATION as described in Part 3, Section 5.
Additional actions required by accepting this item:
Revise the succeeding paragraph numbering order (ref.2015-edition) to:
3.4.4 EXAMPLES OF ALTERATIONS
Add “j”: j) The installation of a welded leak box.
3.4.5 ALTERATIONS OF ASME CODE SECTION VIII, DIVISION 2 or 3, PRESSURE VESSELS
3.4.5.1 ALTERATION PLAN
SECTION 5, 5.13.2 FORM R-2, REPORT OF ALTERATION
Page 1, line-7 of Form R-2; add underlined check-box and script: FFSA Form (NB-403) is attached.
See FORM R-2 example, page-2
Attachment Page 138
Attachment Page 138
SC Repairs and Alterations Attachments /NB14-0301 Boseo 5-16-16 Encap Final MC 7-21-16 (1)
180
2015
SECTION 6
SU
PPL. 3
NB-23
S3.5.5 PLUGGING OF LEAKING OR DAMAGED TUBES
a) ������������ ������������������ � ���������������������������� ������������������������ ����� ���!���"���������###"�$% ���&"�����'#(*
b) ��������+ ,�������-���� ��������%�.��"������������ ����������-� ��+ ,� ����������-��/�����������the tubesheet, and recorded.
c) ���������������+2,������������ "����������������������������&��*�+23���,"� ��������� �����������each end of the tube(s) in question. This represents a minimum total of four (4) plugs per tube.
d) The tube(s) shall be prepared for plugging by enlarging the inside of the tube(s) with a suitable drill bit or reamer.
1) To ensure a sound cement joint between the tube sidewall and the plug, a slightly smaller diameter ����� �������� �������*�������7������������������������������� ��������������������� ���������������������� ����������7�����8/82��*�+2*9���,*
2) As an alternative to d)1) a mandrel with an abrasive, such as sandpaper, may be used, as long as ������7���������#*$*���������;*$*�������������8/82��*�+2*9���,� ������7������*
3) The minimum plug insertion depth of the prepared hole(s) shall meet the minimum combined plug ��������������� ����=�>*�?�����������������������������=�>� ��7������"������������ ���������������������� ������7����������������������������������� @�����%�"��������������� � �����not project outside the face of the tube(s) being plugged.
f) The cement shall be prepared per the cement manufacturer’s instructions.
g) When cementing the plugs, 100% of individual plugs, as well as the inside diameter of the tube opening(s), shall be coated with cement. The plugs shall then be inserted one by one, against each other, into each end of the tube(s) being plugged.
i) Curing time is dependent upon the cement manufacturer’s instructions, and is considered complete ���������������� ���������������������������������������������������� ���������E���screwdriver or other similar instrument.
j) After the cement is completely cured, the plugged, cemented area(s) on the tubesheet face may be dressed with sandpaper or other suitable abrasive.
k) Repaired tubes shall be tested in accordance with this code, using a method acceptable to the Inspector, with a written procedure as approved by the manufacturer’s internal quality system, to ensure leaks have been repaired.
Tube replacement should be performed with the unit preferably in the horizontal position. Avoid replacing adjacent tubes simultaneously because the replacement areas may overlap or reduce the ligament between
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Attachment Page 139
Attachment Page 139
SC Repairs and Alterations Attachments /NB15-0512 SG Graphite 4-6-16 final
181
NATIONAL BOARD INSPECTION CODE2015
SECTION 6
SU
PPL. 3
holes and possibly damage the tubesheet. The general steps used in horizontal tube replacement follow below.
a) ������������ ���������������������� ���������������������������� ������������������������ ����� ���!���"���������###"�$% ���&"�����'#(*�
b) ���������������� �����������������������.�������������������� "�� �������.������������������� "����������������������������� ������������������������ ����� ���!���"���������###"�$% ���&"�����'#(HJK+�,"�+�,"�����'#(HLM+�,*�
c) Determine the thickness of each tubesheet and inside distance between the tubesheets to obtain tube and sleeve length.
d) Access each tubesheet face, clearly identify and mark each tube hole on each tubesheet of the tubes to be replaced.
e) �����/�����������7 �����������������������������7�����������������������*���������� �����contain plugs which require removal. A boring tool slightly larger than the outside diameter of the tube being replaced is required.
h) Replacement tube shall have sleeves at the ends cemented in the bored holes to replace the material ���������� ������������ ����������������� ������������������+F�*��8*3*OH�������8*3*OH�,*�
1) $�H.����������������� ���%�*�
2) The sleeve length may vary.
3) Prior to applying cement, prepare and clean all surfaces to be cemented.
SC Repairs and Alterations Attachments /NB15-0512 SG Graphite 4-6-16 final
NB15-2206B- REVIEW PART 3 SUP 3 FOR PROPER USE OF SHALL, SHOULD, MAY
PART 3 SUPPLEMENT 3 REPAIR AND ALTERATION OF GRAPHITE PRESSURE EQUIPMENT
S3.2 REPAIRS
a) When the original code of construction is other than ASME, replacement parts subject to internal or external pressure shall be manufactured by an organization certified as required by the original code of construction. The item shall be inspected and stamped as required by the original code of construction. Certification to the original code of construction as required by the original code of construction or equivalent shall be supplied with the item. When this is not possible or practicable, the organization fabricating the part may shall have a National Board Certificate of Authorization; replacement parts shall be documented on Form R-3 and the “R” Symbol Stamp applied as described in NBIC Part 3, Section 5.
S3.5.2.4 FINISHING THE REPAIR
a) The parts should be held in place to prevent movement while curing the cemented joint to achieve a proper repair. The repair firm should shall take care to ensure that the cement joint thickness is within the range recommended by the cement manufacturer. Care spent in precisely aligning the parts while clamping will avoid many finishing and machining operations later. Particular attention should be given to gasket and other bearing surfaces.
Attachment Page 141
Attachment Page 141
SC Repairs and Alterations Attachments /NB15-2206B final7-20-2016
NB15‐2207 – 4‐6‐16
Part 3, S3.5.5 c)
c) A minimum of two (2) graphite plugs, each with a minimum length of 1 in. (25 mm), shall be used to plug each end of the tube(s) in question. This represents a minimum total of four (4) plugs per tube.
c) A plug shall be used to plug each end of the tube(s) in question and each plug shall have a
minimum length of 1 in. (25 mm). Multiple plugs may be used.
Attachment Page 142
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NB-23 2015
parentheses. In Part 2, Supplement 6 and Part 3, Supplement 6 regarding DOT Transport Tanks, the metric units are shown first with the U.S. customary units shown in parentheses.
U.S. customary units or metric units may be used with this edition of the NBIC, but one system of units shall be used consistently throughout a repair or alteration of pressure-retaining items. It is the responsibility of National Board accredited repair organizations to ensure the appropriate units are used consistently throughout all phases of work. This includes materials, design, procedures, testing, documentation, and stamping. The NBIC policy for metrication is outlined in each part of the NBIC.
ACCREDITATION PROGRAMS
The National Board administers and accredits three specific repair programs1 as shown below:
"R" ... ....... Repairs and Alterations to Pressure-Retaining Items "VR" ........ Repairs to Pressure Relief Valves "NR" ..... ... Repair and Replacement Activities for Nuclear Items
Part 3, Repairs and Alterations, of the NBIC describes the administrative requ irements for the accreditation of these repair organizations.
The National Board also administers and accredits four specific inspection agency programs as shown below:
New Construction Criteria for Acceptance of Authorized Inspection Agencies for New Construction (NB-360)
lnservice Qualifications and Duties for Authorized Inspection Agencies (AIAs) Performing lnservice Inspection Activities and Qualifications for Inspectors of Boilers and Pressure Vessels (NB-369)
Owner-User Accreditation of Owner-User Inspection Organizations (OUIO) (NB-371) Owners or users may be accredited for both a repair and inspection program provided the requirements for each accreditation program are met.
Federal Government Qualifications and Duties for Federal Inspection Agencies Performing lnservice Inspection Activities (FIAs) (NB-390)
These programs can be viewed on the National Board Website at www.nationalboard.org. For questions or further information regarding these programs contact the National Board by phone at (614) 888-8320 or by fax at (614) 847-1828
CERTIFICATES OF AUTHORIZATION FOR ACCREDITATION PROGRAMS
Any organization seeking an accredited program may apply to the National Board to obtain a Certificate of Authorization for the requested scope of activities. A confidential review shall be conducted to evaluate the organization's quality system. Upon completion of the evaluation, a recommendation will be made to the National Board regarding issuance of a Certificate of Authorization.
Certificate of Authorization scope, issuance, and revisions for National Board accreditation programs are specified in the applicable National Board procedures. When the quality system requirements of the appropriate accreditation program have been met, a Certificate of Authorization and appropriate National Board symbol stamp shall be issued.
1 Caution, some Jurisdictions may independently administer a program of authorization for organizations to perform repairs and alterations within that Jurisdiction.
INTRODUCTION I XIII
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201 s I NATIONAL BOARD INSPECTION C:OOE
PART 3, SECTION 1 REPAIRS AND ALTERATIONS - GENERAL AND
ADMINISTRATIVE REQUIREMENTS
1.1 SCOPE
a) This part provides general requirements that apply when performing repairs and alterations to pressure-retaining items.
b) This part describes the administrative requirements for the accreditation of repair organizations.2
c) The National Board administers three specific accreditation programs:
"R" - Repairs and Alterations to Pressure-Retaining Items
"VR" - Repairs to Pressure Relief Valves
"NR" - Repair and Replacement Activities for Nuclear Items
1.2 CONSTRUCTION STANDARDS FOR PRESSURE-RETAINING ITEMS
a) When the standard governing the original construction is the ASME Code or ASME RTP-1, repairs and alterations to pressure-retaining items shall conform, insofar as possible, to the section and edition of the ASME Code most applicable to the work planned.
b) If the pressure-retaining item was not constructed to a construction code or standard, or when the standard governing the original construction is not the ASME Code or ASME RTP-1, repairs or alterations shall conform, insofar as possible, to the edition of the construction standard or specification most applicable to the work. Where this is not possible or practicable, it is permissible to use other codes, standards, or specifications, including the ASME Code or ASME RTP-1, provided the "R" Certificate Holder has the concurrence of the Inspector and the Jurisdiction where the pressure-retaining item is installed.
c) For historical boilers, the 1971 Edition of Section I of ASME Boiler Code, Part PR and PFT provides the many pressure-related components and features of construction encountered in firetube boilers.
d) For pressure relieving devices the applicable standard for new valves to be used for reference during repairs is the ASME Code. ASME Code Cases shall be used for repairs when they were used in the original construction of the valve. ASME Code Cases may be used when they have been accepted for use by the NBIC Committee and the Jurisdiction where the pressure-retaining item is installed.
1) For pressure relieving devices the code case number shall be noted on the repair document and, when required by the code case, stamped on the repair nameplate.
2) The Jurisdiction where the pressure-retaining item is installed shall be consulted for any unique requirements it may have established.
e) Piping systems are designed for a variety of service conditions such as steam, water, oil, gas, or air. Design requirements for repairs and alterations are to meet the original code of construction or the code most appropriate for the repair or alteration. These systems shall be designed for the most severe conditions of pressure, temperature, loadings, and expected transients considered for normal operation. All pipe materials, fittings, and valves shall be rated for the maximum service conditions for normal operation. Design corrosion of piping systems should also be considered when determining types of materials and thicknesses.
2 Caution: Some jurisdictions may independently administer a program of authorization for organizations to perform repairs and alter-ations within that Jurisdiction.
SECTION l
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201 s I NATIONAL BOARD INSPECTION CODE
1.5 ACCREDITATION
a) Organizations performing repairs or alterations to pressure-retaining items shall be accredited as described in this section, as appropriate for the scope of work to be performed.
b) Organizations performing repairs outside the scope of the NBIC may be accredited and shall meet any additional requirements of the Jurisdiction where the work is performed.
1.5.1 ACCREDITATION PROCESS
a) The National Board administers accreditation programs for authorization of organizations performing repairs and alterations to pressure-retaining items and/or pressure relief valves.
b) Any organization may apply to the National Board to obtain a Certificate of Authorization for the requested scope of activities. A review shall be conducted to evaluate the organization's quality system. The individual assigned to conduct the evaluation shall meet the qualification requirements prescribed by the National Board. Upon completion of the evaluation, any deficiencies within the organization's quality system will be documented and a recommendation will be made to the National Board regarding issuance of a Certificate of Authorization.
c) As part of the accreditation process, an applicant's quality system is subject to a review. National Board procedures provide for the confidential review resulting in recommendations to issue or not issue a Certificate of Authorization.
d) The accreditation programs provide requirements for organizations performing repairs and alterations to pressure-retaining items. Depending upon the expected scope of activities at the time of review, organizations may be authorized to perform design only, metallic or non-metallic repairs, and/or alterations either in the shop only, field only, or shop and field. Repairs and/or alterations to metallic and non-metallic pressure-retaining items are made by welding, bonding and/or mechanical assembly.
e) Organizations desiring to renew or obtain a National Board Certificate of Authorization shall apply to the National Board using forms obtained from the National Board. Application for renewal shall be made prior to the expiration date of the Certificate of Authorization.
f) When an organization has plants or shops in more than one location, the organization shall submit separate applications for each plant or shop. The organization may perform repairs or alterations in its plants, shops, or in the field, provided such operations are described in the organization's Quality System.
g) The Jurisdiction3 may audit the Quality System and activities of an organization upon a valid request from an owner, user, inspection agency, or the National Board.
h) The NBIC Committee may at any time change the rules for the issuance of Certificates of Authorization and use of the "R" Symbol Stamp. These rules shall become binding on all certificate holders.
1.5.2 NATIONAL BOARD "R" SYMBOL STAMP
a) All "R" Symbol Stamps shall be obtained from The National Board of Boiler and Pressure Vessel Inspectors. Authorization to use the "R" Symbol Stamp may be granted by the National Board at its absolute discretion to the certificate holder.
b) The "R" Symbol Stamp is furnished on loan by the National Board for a nominal fee. Each organization
3 Jurisdiction: The National Board member Jurisdiction where the organization is located. Alternatively, where the Jurisdiction elects not to perform the review or where there is no Jurisdiction or where the Jurisdiction is the organization's Authorized Inspection Agency, The National Board of Boiler and Pressure Vessel Inspectors will represent the Jurisdiction. At the Jurisdiction's discretion, the Jurisdiction may choose to be a member of the review team if the Jurisdiction chooses not to be the team leader.
3 SECTION 1
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NB-23 2015
welding. Similar responsibility for nondestructive examination and heat treatment shall be described in the manual.
I) Examinations and Tests
Reference shall be made in the manual for examinations and tests upon completion of the repair or alteration.
m) Calibration
The manual shall describe a system for the calibration of examination, measuring, and test equipment used in the performance of repairs and alterations.
n) Acceptance and Inspection of Repair or Alteration
The manual shall specifically indicate that before the work is started, acceptance of the repair/alteration shall be obtained from an Inspector who will make the required inspections and confirm NBIC compliance by signing and dating the applicable NBIC Report Form 4 upon completion of the work.
o) Inspections
The manual shall make provisions for the Inspector to have access to all drawings, design calculations, specifications, procedures, process sheets, repair or alteration procedures, test results, and other documents as necessary to ensure compliance with the NBIC. A copy of the current manual shall be available to the inspector.
p) Report of Repair or Alteration Form
The manual shall indicate the title of the individuals responsible for preparing, signing, and presenting the NBIC Report Forms to the Inspector. The distribution of the NBIC Report Forms4 shall be described in the manual.
q) Exhibits
Any forms referenced in the manual shall be included. The form may be a part of the referencing document or included as an appendix. For clarity, the forms may be completed and identified as examples. The name and accepted abbreviations of the "R" Certificate Holder shall be included in the manual.
r) Construction Code
The manual shall include provisions for addressing the requirements that pertain to the specific construction code for the equipment being repaired or altered.
s) Nonconforming Items
There shall be a system acceptable to the Inspector for the correction of nonconformities. A nonconformance is any condition that does not comply with the applicable rules of the NBIC, construction code, jurisdictional requirements, or the quality system. Nonconformance must be corrected or eliminated before the repaired or altered component can be considered in compliance with the NBIC.
t) Records Retention
The quality manual shall describe a system for filing, maintaining, and easily retrieving records supporting or substantiating the administration of the Quality System within the scope of the "R" Certificate of Authorization.
4 NBIC Report Form: National Board Form R-1 for Repair, Form R-2 for Alterations, Form R-3 for Fabricated Parts, or Form R-4 Report Supplementary Sheet.
SECTION 1 6
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2a1 s J NATIONAL BOARD INSPECTION CODE
(15) 1.8
3) If owner-user personnel will assist with repairs, provisions for the use of owner-user personnel shall be included; and
4) Provisions for use of owner-user measurement and test equipment, if applicable, shall be addressed.
"NR" PROGRAM REQUIREMENTS
(15) 1.8.1 SCOPE
a) This section provides requirements that must be met for an organization to obtain a National Board Certificate of Authorization to use the "NR" Symbol Stamp for repair/replacement activities to nuclear items constructed in accordance with the requirements of the ASME Code or other internationally recognized codes or standards for construction or inservice inspection of nuclear facilities .
b) For administrative requirements to obtain or renew a National Board "NR" Certificate of Authorization and the "NR" Symbol Stamp, refer to National Board Procedure NB-4175 , Accreditation of "NR" Repair Organizations.
(15) 1.8.2 GENERAL
a) An organization applying for an "NR" Certificate of Authorization shall have a written Quality Assurance Program (QAP) that details the specific requirements to be met based on the intended category of activities selected by that organization as described below and shown in Table 1.8.2. Controls used, including electronic capabilities, in the Quality Assurance Program shall be documented in a Quality Assurance Manual (QAM). Controls required to be included within the QAM shall include who, what, when, where, why and how with an understanding that the how can be a reference to an implementation procedure or instruction. Quality activities to be described in the Quality Assurance Program is identified in Section 1.8.5 of this part. Applicants shall address all requirements in their Quality Assurance Program based on the category of activity and scope of work to be performed (organization's capabilities) to which certification is requested.
b) Category 1
Any ASME Code certified item or system requiring repair/replacement activities irrespective of physical location and installation status prior to fuel loading.
c) Category 2
After fuel loading, any item or system under the scope of ASME Section XI requiring repair/replacement activities irrespective of physical location.
d) Category 3
Items constructed to codes or standards other than ASME, requiring repair/replacement activities irrespective of physical location, installation status and fuel loading.
5 Requirements for Accreditation of "NR" Repair Organizations NB-41 7, may be found on the NB website www.nationalboard.org unde r tab "Stamps and Marks."
1 3 I SECTION 1
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201 s I NATIONAL BOARD INSPECTION CODE
(15) TABLE1.8.2.1
ACRONYMS
ASME American Society of Mechanical Engineers
Applicant An Organization applying for "NR" Certificate of Authorization
(new or renewal)
CFR Code of Federal Regulations
ASME Code of Construction, Section Ill, Division I, (NCA, NB, NC, Code ND, NE, NF, NG, and NH) or ASME Section XI Rules for lnservice
Inspection of Nuclear Power Plant Components as applicable.
Jurisdiction Enforcement Authority
NB National Board of Boiler and Pressure Vessel Inspectors
NBIC National Board Inspection Code
NB-263 Rules for National Board lnservice and New Construction
Commissioned Inspectors
NCA ASME Section Ill, Subsection NCA, General Requirements for
Division 1 and Division 2
NQA-1* ASME Quality Assurance Requirements for Nuclear Facility
Applications
NR Nuclear Repair
"NR" CH "NR" Certificate Holder
QA Quality Assurance
QAl-1 ASME Qualifications for Authorized Inspection
QAM Quality Assurance Manual
QAP Quality Assurance Program
QC Quality Control
WA ASME Section Ill, Division 3, Subsection WA, General
Requ irements
Note:
* Latest Edition endorsed by the Regulatory Authority
(15) 1.8.3 PREREQUISITES FOR ISSUING A NATIONAL BOARD "NR" CERTIFICATE OF AUTHORIZATION
Before an organization can obtain a National Board "NR" Certificate of Authorization, the organization shall:
a) Have and maintain an inspection agreement with an Authorized Nuclear Inspection Agency accepted in accordance with NB-3606 or accredited in accordance with NB-3697•
b) Have a written Quality Assurance Program that complies with the requirements of this section and address all controls for the intended category and scope of activities.
c) Have a current edition of the NBIC.
6 NB-360, Criteria for Acceptance of Authorized Inspection Agencies for New Construction. 7 NB-369, Qualifications and Duties for Authorized Inspection Agencies (AIAs) Performing lnservice Inspection Activities and Qualification of Inspectors of Boilers and Pressure Vessels.
1 s I SECTION 1
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d) Have available ASME Section XI, the code of construction and referenced code sections and standards appropriate for the scope of work to be performed. ASME Section XI and codes of construction (Editions/Addenda) shall meet the requirements of the Regulatory Authority8 and the owner.
1.8.4 OBTAINING OR RENEWING A NATIONAL BOARD "NR" CERTIFICATE OF AUTHORIZATION
a) Before an "NR" Certificate of Authorization will be issued or renewed, the applicant must have the Quality Assurance Program and the implementation of the program reviewed and found acceptable by representatives of the National Board, the Jurisdiction , and the Authorized Nuclear Inspection Agency. The Jurisdiction will be the National Board Member Jurisdiction in which the applicant is located or the location where the Quality Assurance Program is demonstrated/implemented. At the request of the Jurisdiction, or where there is no National Board Member Jurisdiction, the National Board representative shall act on behalf of the Jurisdiction. The implementation of the Quality Assurance Program shall be satisfactorily demonstrated by the organization. Demonstration of implementation shall meet the most stringent (classification) code requirements for the scope and category of work to be specified on the Certificate of Authorization or as requested by the applicant.
b) If the applicant is an ASME "N" type Certificate of Authorization holder, has satisfactorily demonstrated within the last twelve (12) months the implementation of their Quality Assurance Program and can provide documentation that the organization is capable of implementing its Quality Assurance Program as being in compliance with this section, a further hardware verification implementation may not be necessary.
c) The Regulatory Authority or Jurisdiction, upon request to the National Board, may attend the survey process for an "NR" Certificate of Authorization to be issued or renewed.
d} The "NR" Certificate of Authorization holder shall be subject to an audit annually by the Authorized Nuclear Inspection Agency to ensure compliance with the Quality Assurance Program.
1.8.5 QUALITY ASSURANCE PROGRAM
a) An applicant or a holder of a National Board "NR" Certificate of Authorization ("NR" Certificate Holder) shall have and maintain a written Quality Assurance Program. The Quality Assurance Program shall satisfactorily meet the requirements of this section, and Jurisdictional and Regulatory requirements as applicable. The Quality Assurance Program may be brief or voluminous, depending on the circumstances. It shall be treated confidentially by the National Board and available for review by the Survey Team.
b) Each applicant or "NR" Certificate Holder is responsible for establishing and executing a Quality Assurance Program. The applicant or "NR" Certificate Holder may subcontract activities needed to implement the Quality Assurance Program, as limited by ASME Section Ill and XI, but responsibility for adherence to the Quality Assurance Program remains with the Applicant or "NR" Certificate Holder.
c) These rules set forth the requirements for planning, managing, and implementing the organization's Quality Assurance Program to control and ensure quality is performed and maintained during repair/ replacement activities of components, items, parts, and systems for nuclear facilities . These rules are to be the basis for evaluating such programs prior to the issuance or renewal of the National Board "NR" Certificate of Authorization. Rules identified in subsections 1.8.6, 1.8. 7 and 1.8.8 of this section detail the Quality Assurance Program requirements for each category of activity. These rules are established to meet and follow the requirements specified in NBIC Part 3, Table 1.8.2-1 of this section.
1.8.6 QUALITY ASSURANCE PROGRAM REQUIREMENTS FOR CATEGORY 1 ACTIVITIES
8 Regulatory Authority, A government agency, such as the United States Nuclear Regulatory Commission, empowered to issue and enforce regulations concerning the design, construction, and operation of nuclear power plants.
(15)
(15)
(15)
SECTION 1 1 5
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201 s I NATIONAL BOARD INSPECTION CODE
e) The test material for the welding procedure qualification shall be of the same material specification (including specification type, grade, class, and condition of heat treatment) as the material being repaired. In the event that the notch toughness of the material to be repaired is unknown, evidence from tests of that material or from another acceptable source (see NBIC Part 3, 2.5.3) may be used for the base metal notch toughness when qualifying the WPS as required in NBIC Part 3, 2.5.3.2 h). In the event that the original material specification is obsolete, the test material used should conform as closely as possible to the original material used for construction based on nominal composition and carbon equivalent (llW Formula), 9 but in no case shall the material be lower in strength.
(15) f) The qualification thickness for the test plates and repair groove depths shall be in accordance with ASME Section IX; for pressure retaining items repaired using this temper bead method, hardness testing and carbon equivalency requirements may be waived for ASME Section IX temper bead procedure qualification provided the pressure retaining item operates in steam service above 900°F (482°C).
g) The organization making the repair shall include, when qualifying its WPS, sufficient tests to determine that the notch toughness of the weld metal and the heat-affected zone of the base metal in the "as-welded" condition is adequate at the minimum operating and pressure test temperatures (including start-up and shutdown). If for reasons of corrosion resistance, special hardness limits are necessary, such limits shall be included when qualifying the WPS.
h) Notch toughness shall be determined and evaluated by Charpy impact tests in accordance with the provisions of the original code of construction at the temperature determined in accordance with NBIC Part 3, 2.5.3.2 d). Exemptions from impact testing described in the original code of construction are not applicable.
i) For the welding process in NBIC Part 3, 2.5.3.2 c), use of austenitic or ferritic filler metals is permitted. For ferritic filler metals, use only electrodes and filler metals that are classified by the filler metal specification with a diffusible-hydrogen designator of H8 or lower. When shielding gases are used with a process, the gas shall exhibit a dew point that is below -60°F (-50°C). Surfaces on which welding will be done shall be maintained in a dry condition during welding and be free of rust, mill scale, and hydrogen producing contaminants such as oil, grease, and other organic materials.
j) After the weld has been deposited flush with the base metal, a surface temper reinforcing weld layer shall be applied.
k) For welds made by SMAW and FCAW, after completion of welding and without allowing the weldment to cool below the minimum preheat temperature, the temperature of the weldment shall be raised to a temperature of 450°F (232°C) minimum for a minimum period of two hours. This hydrogen bake-out treatment may be omitted provided the electrode used is classified by the filler metal manufacturer with a diffusible-hydrogen designator of H4 (e.g., E7018-H4).
I) After the finished repair weld has cooled to ambient temperature, the surface temper reinforcing layer shall be removed substantially flush with the surface of the base material.
2.5.3.3 WELDING METHOD 3
When using this method, the following is required:
a) This method may be used when the applicable rules of the original code of construction did not require notch toughness testing;
b) The materials shall be limited to any P-No. 1 or P-No. 3 material as permitted for welded construction by the applicable rules of the original code of construction;
c) The welding shall be limited to the SMAW, FCAW, and GTAW processes;
9 The llW Carbon Equivalent Formula is CE= C+ Mn/6 + (Cr+Mo+V)/5 + (Ni+Cu)/15. Elements are expressed in Weight Percent Amounts.
47 I SECTION 2
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d) The test material for the welding procedure qualification shall be of the same P-No. and Group No. as the base material specification of the repair. In the event that the original material specification is obsolete, the test material used should conform to the nominal composition and carbon equivalent (llW Formula)10 as the material being repaired, but in no case shall the material be lower in strength;
e) If for reasons of corrosion resistance, special hardness limits are necessary, such limits shall be included when qualifying the WPS. For pressure retaining items repaired using this temper bead method, hardness testing and carbon equivalency requirements may be waived for ASME Section IX temper bead procedure qualification provided the pressure retaining item operates in steam service above 900°F (482°C);
f) The qualification thickness for the test plates and repair groove depths shall be in accordance with ASME Section IX;
g) The WPS shall be qualified in accordance with the temper bead procedure qualification requirements in QW-290 of ASME Section IX, and shall include the following additional requirements:
1) The minimum preheat temperature for welding shall be 350°F (177°C) and the maximum interpass temperature shall be 450°F (232°C); ·
2) For the welding processes in NBIC Part 3, 2.5.3.3 c), use of austenitic or ferritic filler metal is permitted. For ferritic filler metals, use only electrodes or filler metals that are classified by the filler metal specification with a diffusible-hydrogen designator of H8 or lower may be used. When shielding gases are used with a process, the gas shall exhibit a dew point that is below -60°F (-50°C). Surfaces on which welding will be done shall be maintained in a dry condition during welding and be free of rust, mill scale, and hydrogen producing contaminants such as oil, grease, and other organic materials;
3) After completion of welding using SMAW and without allowing the weldment to cool below the minimum preheat temperature, the temperature of the weldment shall be raised to a temperature of 450°F (232°C) minimum for a minimum period of two hours. This hydrogen bake-out treatment may be omitted, provided the electrode used is classified by the filler metal manufacturer with a diffusible-hydrogen designator of H4 (e.g., E7018-H4);
4) After the finished repair weld has cooled to ambient temperature, the final temper bead reinforcement layer shall be removed substantially flush with the surface of the base material.
2.5.3.4 WELDING METHOD 4
When using this method, the following is required:
a) This method is limited to repair welds in pressure retaining items for which the applicable rules of the original code of construction did not require notch toughness testing. The repair depth for temper bead repairs to pressure retaining items is limited to welds not penetrating though the full thickness.
For ASME Section VIII Division 2 pressure vessels, where application of PWHT on in-service vessels has been demonstrated to cause harm to vessel material, full thickness temper bead repairs are permitted. They shall be completed per NBIC Part 3, 3.3.5 with the following requirements:
1) The full thickness repair weld shall be verified as being full penetration.
2) Volumetric examination of the full thickness weld shall be performed.
b) The materials shall be limited to P-No. 4, Groups 1 and 2, and P-No. 5A steels as permitted for welded construction by the applicable rules of the original code of construction;
10 The llW Carbon Equivalent Formula is CE= C+ Mn/6 + (Cr+Mo+V)/5 + (Ni+Cu)/15. Elements are expressed in Weight Percent Amounts.
SECTION 2 48
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c) The welding shall be limited to the SMAW, FCAW, GMAW or GTAW processes using low-hydrogen electrodes and filler metals classified by the filler metal specification with a diffusible-hydrogen designator of H8 or lower, and suitably controlled by maintenance procedures to avoid contamination by hydrogen producing sources. The surface of the metal prepared for welding shall be free of contaminants;
d) The test material for the welding procedure qualification shall be of the same P-No. and Group No. as the original material specification for the repair. In the event that the original material specification is obsolete, the test material used shall conform to the nominal composition and carbon equivalent (llW formula) 11 as the original material used for construction, and in no case shall the material be lower in strength;
e) If for reasons of corrosion resistance, special hardness limits are necessary, such limits shall be included when qualifying the WPS;
(15) f) The qualification thickness for the test plates and repair groove depths shall be in accordance with ASME Section IX. For pressure-retaining items repaired using thistemper bead method, hardness testing and carbon equivalency requirements may be waived for ASME Section IX temper bead procedure qualification provided the pressure-retaining item operates in steam service above 900°F (482°C);
g) The welding procedures (WPS) shall be qualified in accordance with the temper bead procedure qualification requirements in QW-290 of ASME Section IX, and shall include the following additional requirements:
1) The minimum preheat temperature for welding shall be 300°F (150°C) for P-No. 4 material and 400 °F (200 °C) for P-No. 5A material. The preheat temperature shall be checked to ensure that 4 in. (102 mm) of the material or four times the material thickness (whichever is greater) on each side of the groove (or full thickness of joint for a groove weld) is maintained at the minimum temperature during welding. The interpass temperature shall not exceed 800°F (430°C). When the weld does not penetrate through the full thickness of the material, the minimum preheat and maximum interpass temperature need only be maintained for 4 in. (102 mm) or four times the depth of the repair weld (whichever is greater) on each side of the joint;
2) For the welding processes in NBIC Part 3, 2.5.3.4 c), use of austentic or ferritic filler metal is permitted. For ferritic filler metals, use only electrodes or filler metals that are classified by the filler metal specification with a diffusible-hydrogen designator of H8 or lower. When shielding gases are used with a process, the gas shall exhibit a dew point that is below -60°F (-50°C) . Surfaces on which welding be done shall be maintained in a dry condition during welding and be free of rust, mill scale, and hydrogen producing contaminants, such as oil, grease, and other organic materials;
3) After the weld has been deposited flush with the base metal, a surface temper reinforcing weld layer shall be applied ;
4) For welds made by the SMAW and FCAW processes, after completion of welding and without allowing the weldment to cool below the minimum preheat temperature, the temperature of the weldment shall be raised to 450°F (232°C) minimum for a minimum period of two hours. This hydrogen bake-out treatment may be omitted, provided the electrode used is classified by the filler metal manufacturer with a diffusible-hydrogen designator of H4 (e.g., E7018 H4);
5) After the finished repair weld has cooled to ambient temperature, the surface temper reinforcing weld layer shall be removed substantially flush with the surface of the base metal (and for a fillet weld to the required size and suitable contour of the toes).
2.5.3.5 WELDING METHOD 5
When using this method, the following is required:
11 The llW Carbon Equivalent Formula is CE=C+ Mn/6 + (Cr+Mo+V)/5 + (Ni+Cu)/15. Elements are expressed in Weight Percent Amounts
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b) Authorized Inspection Agency Acceptance
Following review and certification, the repair plan shall be submitted for acceptance to the Authorized Inspection Agency/Owner-User Inspection Organization whose Inspector will make the acceptance inspection and sign the Form R-1.
3.4 ALTERATIONS
3.4.1 RE-RATING12
Re-rating of a pressure-retaining item by increasing the maximum allowable working pressure (internal or external) or temperature or decreasing the minimum design metal temperature below which notch toughness testing is required by the original code of construction, shall be done only after the following requirements have been met to the satisfaction of the Jurisdiction at the location of the installation:
a) Revised calculations verifying the new service conditions shall be prepared in accordance with the "R" Certificate Holder's Quality Control System. Establishing a higher joint efficiency to re-rate a pressure-retaining item is not permitted;
b) All re-ratings shall be established in accordance with the requirements of the construction standard to which the pressure-retaining item was built;
c) Current inspection records verify that the pressure-retaining item is satisfactory for the proposed service conditions;
d) The pressure-retaining item has been pressure tested, as required, for the new service conditions. Any insulation, coatings, or coverings that may inhibit or compromise a meaningful pressure test shall be removed, to the extent identified by the Inspector;
e) In lieu of pressure testing, alternative methods can be used to ensure the structural integrity of the re-rated pressure-retaining item. The alternative methods shall be documented and subject to review and approval by the Jurisdiction.
3.4.2 ALTERATIONS BASED ON ALLOWABLE STRESS VALUES
For re-rating or re-calculating a new minimum wall thickness for a pressure-retaining item using a later edition/addenda of the original code of construction or selected construction standard or code that permits use of higher allowable material stress values than were used in the original construction, the following requirements shall apply:
a) The "R" Certificate Holder shall verify, by calculations and other means, that the re-rated item can be satisfactorily operated at the new service condition (e.g., stiffness, buckling, external mechanical loadings);
b) The pressure-retaining item shall not be used in lethal service;
c) The pressure-retaining item shall not be used in high-cycle operation or fatigue service (i.e., loadings other than primary membrane stress are controlling design considerations) unless the pressure-retaining item was originally designed for fatigue service and a fatigue analysis is performed;
d) The pressure-retaining item shall have been constructed to the 1968 edition or later edition/addenda of the original code of construction;
12 Re-rating: Except as provided for Yankee dryers in Supplement 5, this code does not provide rules for de-rating boilers or pressure vessels; however, when the MAWP and/or allowable temperature of a boiler or pressure vessel is reduced, the Jurisdiction where the object is installed should be contacted to determine if specific procedures should be followed.
SECTION 3 70
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NB-23 2015
PART 3, SECTION 6 REPAIR AND ALTERATION SUPPLEMENTS
This supplement applies to all boilers attached to steam locomotives operating on track gaged 24 in. (610 mm) or greater.
S1.1.1 FEDERAL RAILROAD ADMINISTRATION (FRA)
The FRA rules for steam locomotive boilers are published in the Code of Federal Regulations (CFR) 49CFR Part 230, dated November 17, 1999. 13 All locomotives under FRA jurisdiction are documented on FRA Form 4 as defined in 4.9CFR Part 230. This document is the formal documentation of the steam locomotive boiler and is required to be completed prior to the boiler being placed in service. This document shall be used as the data report for the boiler, applicable to all repairs and alterations performed. National Board "R" Certificate Holders shall document their repairs and/or alterations on National Board Forms R-1 or R-2. These reports shall be distributed to the owner-user of the boiler, who is required to incorporate them into a FRA Form 19, which becomes an attachment to the FRA Form 4. The design margin for all such repairs or alterations shall not be less than four, based on ultimate tensile strength of the material.
S1.1.2 REQUIREMENTS FOR WELDING ACTIVITIES
a) Before performing any welding activities, consideration shall be given to ensure the weldability of locomotive boiler materials.
b) Special jurisdictional approval may be required prior to starting welding activity on locomotive boilers.
S1.1.3 MATERIALS
a) The older steels used in riveted construction were frequently rimmed steels, high in carbon, sulfur, phosphorus and hydrogen. The older steels were not melted to a fine grain practice and will typically have poor toughness properties.
b) If welding is to be used to repair a pressure-retaining item that was manufactured using riveted construction, the repair organization should perform a chemical composition analysis on the steel plate base metal and rivet material to determine weldability. Specific quantities of carbon, manganese, sulfur, phosphorus, and aluminum shall be identified and included in the analysis. The result of the analysis shall be acceptable to the Inspector and Jurisdiction when required.
S1.1.3.1 MATERIAL LIST FOR STEAM LOCOMOTIVE BOILERS
Table S1 .1.3.1 is intended as a basic guideline only and covers basic carbon steel and some alloy steel (15) material specifications. Other alloy materials may be available for these applications if necessary.
a) SA-516 steel is recommended for firebox repairs. It is a fine grain steel that accepts flanging and bending with less tendency to crack than coarse grain steels such as SA-515 or SA-285 Grade C.
13 Steam locomotive inspection and maintenance standards, which is now codified at 49 CFR Part 230, may be obtained at the FRA website.
SECTION 6 ] 1 04
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NB-23 2015
S1.1.4 FORMULA AND CALCULATIONS FOR STEAM LOCOMOTIVE BOILERS
a) Most steam locomotive boilers were manufactured in the first half of the 20th century or before. The calculations, formula, and shop practices used are now distant history and quite difficult to obtain. The rules for riveted construction were last published by ASME in Section I Code, 1971 Edition.
b) This supplement herein, is based in part on the ASME Code, Section 111, 1952Edition,14 which was the last published edition of the Steam Locomotive Code. The railroad industry has attempted to collect the old formula and some shop practices. These have been published by The Engineering Standards Committee for Steam Locomotives, Inc. (ESC) as Compendium, Volume 1, Compilation of Calculations. 15
S1.2 LOCOMOTIVE FIRETUBE BOILER REPAIRS
S1.2.1 REPAIR OF STAYBOLT HOLES
a) Staybolt holes may be repaired by welding, reaming, or retapping to a larger size or by installing a flush patch.
b) If the staybolt hole was threaded and is to be repaired by welding, the threads shall be removed prior to welding.
S1.2.2 THREADED STAYBOLTS
a) All threaded staybolts shall have either 11- or 12-thread pitch. Staybolt threads shall have a good close fit in sheets. Changing the staybolt thread pitch from 11 to 12 or the reverse shall be considered a repair.
b) All staybolts shorter than 8 in. (200 mm) in length shall have telltale holes. Staybolt telltale holes in existing staybolts shall be 3/16 in. (5 mm) to 7/32 in. (5.5 mm) in diameter and at least 1-1/4 in. (32 mm) deep in the outer end. When staybolts 8 in. (200 mm) or less in length are replaced, they shall be replaced with staybolts that have a telltale hole 3/16 in. (5 mm) to 7/32 in. (5.5 mm) in diameter their entire length, or with ones that have a 3/16 in. (5 mm) to 7/32 in. (5.5 mm) diameter hole in each end, drilled a minimum of 1-1/4 in. (32 mm) deep. On reduced body staybolts, the telltale hole shall extend beyond the fillet and into the reduced section of the staybolt. Ball socket-type flexible staybolts may have telltale holes that extend from the threaded end of the bolt into the bolt head for a distance of onethird the spherical bolt head diameter.
c) Telltale holes shall be reopened after driving and riveting heads.
d) Staybolt length shall be sized so the length of bolt projecting through the sheet is not less than 1/8 in. (3 mm) and is sufficient to produce a full head after driving and riveting the head.
e) The thread lead of both bolt ends and both firebox sheets shall be synchronized to permit the staybolt to be installed without stripping the threads.
f) When riveting staybolt heads, the bolt's opposite end shall be bucked or braced to prevent damaging the staybolt's threads. Bracing can be done several ways, such as using a pneumatic holder or a heavy steel bucking bar. Driving the heads on both ends of the staybolt simultaneously, using two pneumatic rivet hammers (double gunning), is acceptable. Staybolts are to be driven in such a manner as to expand radially the staybolt body and threads into the sheet prior to forming the head. Merely driving over the head is not acceptable.
14 This code is available from the National Board. 15 Copies of The Engineering Standards Committee for Steam Locomotives, Inc., Compendium, Volume 1, Compilation of Calculations, may be obtained from the Strasburg Rail Road, P.O. Box 96, Strasburg, PA 17579, 717.687.8421.
SECTION 6 I 1 06
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201 s I NATIONAL BOARD INSPECTION CODE
e) Reheating of rivets above 600°F (316°C) after the original installation is prohibited. When seal welding rivet heads, inter or post-pass head temperature shall be kept below 600°F (316°C).
f) Each rivet head shall contact the plate over the entire circumference upon completion of the installation. Rivets on which either head does not have contact with the plate over the entire area of the driven head, not including any excess washer (excess material at the base of the rivet head), shall be replaced. Repair is prohibited.
g) Caulking refers to the sealing of plate seams and rivet heads by driving the edge of one surface onto the other by using an impact tool.
h) Caulked rivet seams and rivet heads shall be in accordance with ASME Code Section I, Part PR, 1971 Edition.16
FIGURE S1.2.12.1
Caulking tool~
Caulked edge of plate
S1 .2.12.2 THREADED OPENINGS IN VESSEL WALLS, BUSHINGS, AND WELDED NOZZLES (WASHOUT PLUG HOLES AND OTHER CONNECTIONS)
a) Threaded openings in vessel walls and welded nozzles with damaged threads that cannot be repaired by retapping or rethreading should be repaired by welding a nozzle in the sheet. The nozzle shall be of such a size as to not interfere with proper washout and inspection.
b) Threaded bushings and nozzles found to be defective shall be replaced. Seal welding is not permitted.
c) New threaded bushings equipped with shoulders may be seal welded at the shoulder.
d) New threaded bushings without shoulders that are seal welded after installation shall have the threads removed from the weld zone of the bushing prior to welding.
e) Threaded holes with damaged threads may be repaired by weld buildup and re-tapping. The threads shall be removed prior to welding.
16 This code is available from the National Board.
1 35 I SECTION 6
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NBIC Subcommittee R&A Action Block
Subject Remove revision of ACCP Program in Paragraph 4.2 b)
File Number NB15-2801
Prop. on Pg.
Proposal
Explanation
In NBIC Part 3, Paragraph 4.2 b), a year and date is listed for ACCP (i.e. “Rev. 3, Nov 1997”). This is an improper way to reference the ACCP Program. The correct way is to adopt the program and list solely, “ASNT Central Certification Program (ACCP)” without a date and revision. The ACCP-CP-1 document used by ASNT is not a standard. It is an internal program document used solely by ASNT and their Authorized Examination Centers (AEC) for the Central Certification of NDT Personnel. ASNT is currently working to Rev 8 of this document. There are multiple problems that can arise from listing a Revision and Year for this document. First, if a NB Team Leader were to request proof that an ACCP Professional Level II or III performing work to the NBIC, was certified to “Rev. 3, Nov 1997” of the ACCP Program, there would be no direct way to do so. The two certification documents issued by ASNT (i.e. wallet card and wall certification) do not reference the ACCP-CP-1 document or its revision and date. ASNT’s online “certification check” also doesn’t reflect a revision and date for the ACCP-CP-1 document used to certify the ACCP Professional by ASNT. This potentially would be a finding, which is an unfair burden to place on the R-Certificate Holder with no direct way to clear. Also, by listing “Rev. 3, Nov 1997”, literal interpretation would mean that ONLY ACCP Professionals Certified by ASNT when they used Rev 3 of the ACCP-CP-1 document are valid for performing work to the NBIC. Therefore, if an ACCP Professional Level II or III was initially certified to Rev 1, 2, or 4-8, then they can’t perform work to the NBIC, including people being certified today. Also, ACCP Professionals are recertified by ASNT, if they meet the requirements on a 5-year cycle. When you consider this and since Rev. 3 went into effect in Nov. 1997, which was roughly 18 years ago, and since Rev 7 is dated 7/17/2010, literal interpretation of Paragraph 4.2 b) would beg the question if there are any ACCP Professional Level II or IIIs technically eligible to perform work to the NBIC today? This proposal recognizes that as long as the ACCP Professional is properly certified by ASNT and maintains that certification, then the adoption of the ACCP Program in itself is sufficient. It also includes “ANSI” as part of the title for CP-189. Revised Proposal to strike mention of the ACCP Program in this paragraph. This parallels a recent action by Section I in their book. Functionally, there is no change, since the ACCP Program is listed in both SNT-TC-1A and CP-189 as permissive to meet some of the requirements of the written practice. By striking mention of the ACCP Program in Para 4.2 b), this removes the potential for a joint review finding in meeting the revision requirement, which doesn’t practically exist today.
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NBIC Subcommittee R&A Action Block
Project Manager
Nathan Carter
Task Group Negatives
TG Meeting Date
NBIC Part 3, Paragraph 4.2 b)
Current b) NDE personnel shall be qualified and certified in accordance with the requirements of the original code of construction. When this is not possible or practicable, NDE personnel may be qualified and certified in accordance with their employer’s written practice. ASNT SNT-TC-1A, Recommended Practice Nondestructive Testing Personnel Qualification and Certification (2006 edition), or ASNT CP-189, Standard for Qualification and Certification of Nondestructive Testing Personnel (2006 edition), shall be used as a guideline for employers to establish their written practice. The ASNT Central Certification Program (ACCP, Rev. 3, Nov. 1997) may be used to fulfill the examination and demonstration requirements of the employer’s written practice. Provisions for training, experience, qualification, and certification of NDE personnel shall be described in the “R” Certificate Holder’s written quality system.
Proposed
b) NDE personnel shall be qualified and certified in accordance with the requirements of the original code of construction. When this is not possible or practicable, NDE personnel may be qualified and certified in accordance with their employer’s written practice. ASNT SNT-TC-1A, Recommended Practice Nondestructive Testing Personnel Qualification and Certification (2006 edition), or ANSI/ASNT CP-189, Standard for Qualification and Certification of Nondestructive Testing Personnel (2006 edition), shall be used as a guideline for employers to establish their written practice. The ASNT Central Certification Program (ACCP, Rev. 3, Nov. 1997) may be used to fulfill the examination and demonstration requirements of the employer’s written practice. Provisions for training, experience, qualification, and certification of NDE personnel shall be described in the “R” Certificate Holder’s written quality system.
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1.2 c) For historical boilers, the 1971 Edition of ASME Code Section I of ASME Code, Part PR, and PFT provides rules for design the many pressure-related components and features of construction. encountered in firetube boilers.
NB15‐2901
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NB16-0602 7-18-16 1.8.2 GENERAL a) An organization applying for an “NR” Certificate of Authorization shall have a written Quality Assurance Program (QAP) that details the specific requirements to be met based on the intended category of activities selected by that organization as described below and shown in Table 1.8.2. Controls used, including electronic capabilities, in the Quality Assurance Program shall be documented in a Quality Assurance Manual (QAM). Controls required to be included within the QAM shall include who, what, when, where, why and how with an understanding that the how can be a reference to an implementation procedure or instruction. Quality activities to be described in the Quality Assurance Program is identified in Section 1.8.5 of this part. Applicants shall address all requirements in their Quality Assurance Program based on the category of activity and scope of work to be performed (organization’s capabilities) to which certification is requested. b) Category 1 Any ASME Code certified item or system requiring repair/replacement activities irrespective of physical location and installation status prior to fuel loading. c) Category 2 After fuel loading, any item or system under the scope of ASME Section XI requiring repair/replacement activities irrespective of physical location. Based on regulatory or jurisdictional acceptance, Category 2 may be used prior to fuel loading. d) Category 3 Items constructed to codes or standards other than ASME, requiring repair/replacement activities irrespective of physical location, installation status and fuel loading.
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NB16-0606 – 7-18-16 1.8.6.2 n ) 3) Forms NR-1 and NVR-1 as applicable shall be completed by the “NR” Certificate Holder upon completion of all repair/replacement activities. Completion of forms, registrations and stamping of the “NR” symbol stamp shall meet the requirements of NBIC Part 3, Section 5. A log shall be maintained in accordance with NBIC Part 3, 5.6; and 1.8.7.2 n) 5) The original of the completed Form NR-1 or Form NVR-1, as applicable, shall be registered with the National Board and, if required, a copy forwarded to the Jurisdiction where the nuclear power plant is located. A log shall be maintained in accordance with NBIC Part 3, 5.6. 1.8.8.2 m)
a) All quality related records shall be classified, identified, verified, maintained, distributed, retraceable, and accessible. When the “NR” Certificate Holder is the owner, designated records and reports received by the owner, shall be filed and maintained in a manner to allow access by the Authorized Nuclear Inservice Inspector (ANII). Suitable protection from deterioration and damage shall be provided by the owner. These records and reports shall be retained as specified in the owner’s QAP for the lifetime of the component or system.
a)b) The original of the completed Form NR-1 or Form NVR-1, as applicable, shall be registered with the National Board and, if required, a copy forwarded to the Jurisdiction where the nuclear power plant is located. A log shall be maintained in accordance with NBIC Part 3, 5.6.
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2015 NATIONAL BOARD INSPECTION CODE
35 SECTION 2
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TABLE 2.3
CARBON STEEL — (P1 MATERIALS)
SMAW — Shielded Metal Arc Welding
Standard Welding Procedure Specification for Shielded Metal Arc Welding of Carbon Steel,(M‐1/P‐1, Group 1 or 2), 3/16 in. (5 mm) through 3/4 in. (19 mm), in the As‐Welded
Condition, With Backing.
B2.1.001‐90 and B2.1‐1‐001: 90(R2006)
Standard Welding Procedure Specification for Shielded Metal Arc Welding of Carbon Steel (M‐1/P‐1/S‐1, Group 1 or 2), 1/8 in. (3.2 mm) through 1 ½ in. (38 mm) Thick, E7018, As‐
Welded or PWHT Condition.
B2.1‐1‐016‐94 and B2.1‐1‐016‐94R
Standard Welding Procedure Specification for Shielded Metal Arc Welding of Carbon Steel (M‐1/P‐1/S‐1, Group 1 or 2), 1/8 in. (3.2 mm) through 1 ½ in. (38 mm) Thick, E6010, As‐
Welded or PWHT Condition.
B2.1‐1‐017‐94 and B2.1‐1‐017‐94R
Standard Welding Procedure Specification for Shielded Metal Arc Welding of Carbon Steel (M‐1/P‐1/S‐1, Group 1 or 2), 1/8 in. (3.2 mm) through 1 ½ in. (38 mm) Thick, E6010
(Vertical Uphill) followed by E7018, As‐Welded or PWHT Condition.
B2.1‐1‐022‐94 and B2.1‐1‐022‐94R
Standard Welding Procedure Specification for Shielded Metal Arc Welding of Carbon Steel (M‐1/P‐1/S‐1, Group 1 or 2), 1/8 in. (3.2 mm) through 1 ½ in. (38 mm) Thick, E6010
(Vertical Downhill) followed by E7018, As‐Welded or PWHT Condition.
B2.1‐1‐026‐94 and B2.1‐1‐026‐94R
Standard Welding Procedure Specification for Shielded Metal Arc Welding of Carbon Steel (M‐1/P‐1/S‐1, Group 1 or 2), 1/8 in. (3.2 mm) through 3/4 in. (19 mm) Thick, E6010 (Vertical Downhill) followed by E7018, (Vertical Uphill) As‐Welded Condition, Primarily
Pipe Applications.
B2.1‐1‐201‐96, and B2.1‐1‐201‐96(R2007)
Standard Welding Procedure Specification for Shielded Metal Arc Welding of Carbon Steel (M‐1/P‐1/S‐1, Group 1 or 2), 1/8 in. (3.2 mm) through 3/4 in. (19 mm) thick, E6010 (Vertical Downhill) followed by E7018 (Vertical Uphill), As‐Welded Condition, Primarily
Pipe Applications.
B2.1‐1‐202‐96(R2007)
Standard Welding Procedure Specification for Shielded Metal Arc Welding of Carbon Steel (M‐1/P‐1/S‐1, Group 1 or 2), 1/8 in. (3.2 mm) through 3/4 in. (19 mm) Thick, E6010
Standard Welding Procedure Specification for Shielded Metal Arc Welding of Carbon Steel (M‐1/P‐1/S‐1, Group 1 or 2), 1/8 in. (3.2 mm) through 3/4 in. (19 mm) Thick, E6010 (Vertical downhill root with balance vertical uphill), As‐Welded Condition, Primarily Pipe
Applications.
B2.1‐1‐204‐96 and B2.1‐1‐204‐96(R2007)
Standard Welding Procedure Specification for Shielded Metal Arc Welding of Carbon Steel (M‐1/P‐1/S‐1, Group 1 or 2), 1/8 in. (3.2 mm) through 1 ½ in. (38 mm) Thick, E6010
(Vertical Uphill) followed by E7018 (Vertical Uphill), As‐Welded or PWHT Condition, Primarily Pipe Applications.
B2.1‐1‐205‐96 and B2.1‐1‐205‐96(R2007)
Standard Welding Procedure Specification for Shielded Metal Arc Welding of Carbon Steel (M‐1/P‐1/S‐1, Group 1 or 2), 1/8 in. (3.2 mm) through 3/4 in. (19 mm) Thick, E6010 (Vertical Downhill) followed by E7018 (Vertical Uphill), As‐Welded or PWHT Condition,
Primarily Pipe Applications.
B2.1‐1‐206‐96 and B2.1‐1‐206‐96(R2007)
Standard Welding Procedure Specification for Shielded Metal Arc Welding of Carbon Steel (M‐1/P‐1/S‐1, Group 1 or 2), 1/8 in. (3.2 mm) through 3/4 in. (19 mm) Thick, E7018, As‐
Welded or PWHT Condition, Primarily Pipe Applications. B2.1‐1‐208‐96
Standard Welding Procedure Specification for Shielded Metal Arc Welding of Carbon Steel (M‐1/P‐1/S‐1, Group 1 or 2), 1/8 in. (3.2 mm) through1 ½ in. (38 mm) Thick, E7018, As‐
Welded or PWHT Condition, Primarily Pipe Applications. B2.1‐1‐208‐96(R2007)
GTAW — Gas Tungsten Arc Welding
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Standard Welding Procedure Specification for Gas Tungsten Arc Welding of Carbon Steel, (M‐1/P‐1, Group 1 or 2), 3/16 in. (5 mm) through 7/8 in. (22 mm) Thick, in the As‐Welded
Condition, With or Without Backing.
B2.1‐002‐90, B2.1‐002‐ 90(R2006) and B2.1‐1‐002‐90R
Standard Welding Procedure Specification for Gas Tungsten Arc Welding of Carbon Steel (M‐1/P‐1/S‐1, Group 1 or 2), 1/8 in. (3.2 mm) through 3/4 in. (19 mm) Thick, ER70S‐2, As‐
Welded or PWHT Condition, Primarily Pipe Application. B2.1‐1‐207‐96
Standard Welding Procedure Specification for Gas Tungsten Arc Welding of Carbon Steel (M‐1/P‐1/S‐1, Group 1 or 2), 1/8 in. (3.2 mm) through 1 ½in. (38 mm) Thick, ER70S‐2, As‐
Welded or PWHT Condition, Primarily Pipe Application. B2.1‐1‐207‐96 (R2007)
Standard Welding Procedure Specification for Gas Tungsten Arc Welding (Consumable Insert) of Carbon Steel (M‐1/P‐1/S‐1, Group 1 or 2), 1/8 in. (3.2 mm) through 3/4 in. (19 mm) Thick, INMs1 and ER70S‐2, As‐Welded or PWHT Condition, Primarily Pipe
Application.
B2.1‐1‐210‐96
Standard Welding Procedure Specification for Gas Tungsten Arc Welding with Consumable Insert Root of Carbon Steel (M‐1/P‐1/S‐1, Group 1 or 2), 1/8 in. (3.2 mm) through 1‐1/2 in.
Standard Welding Procedure Specification for Self‐Shielded Flux Cored Arc Welding of Carbon Steel (M‐1/P‐1/S‐1, Group 1 or 2), 1/8 in. (3.2 mm) through 1 ½ in. (38 mm) Thick,
E71T‐8, As‐Welded Condition.
B2.1‐1‐018‐94 and B2.1‐1.018‐94R
Standard Welding Procedure Specification for CO2 Shielded Flux Cored Arc Welding of Carbon Steel (M‐1/P‐1/S‐1, Group 1 or 2), 1/8 in. (3.2 mm) through 1 ½ in. (38 mm) Thick,
E70T‐1 and E71T‐1, As‐Welded Condition.
B2.1‐1‐019‐94 and B2.1‐1‐019‐94R
Standard Welding Procedure Specification for 75% Ar/25% CO2 Shielded Flux Cored Arc Welding of Carbon Steel (M‐1/P‐1/S‐1, Group 1 or 2), 1/8 in. (3.2 mm) through 1‐1/2 in.
(38 mm) Thick, E70T‐1M and E71T‐1M, As‐Welded or PWHT Condition.
B2.1‐1‐020‐94 and B2.1‐1‐020‐94R
Standard Welding Procedure for Self‐Shielded Flux Cored Arc Welding of Carbon Steel (M‐1/P‐1/S‐1, Group 1 or 2), 1/8 in. (3.2 mm) through 1/2 in. (13 mm) Thick, E71T‐11,
As‐Welded Condition.
B2.1‐1‐027:1995 and B2.1‐1‐027‐1998
Standard Welding Procedure Specification (SWPS) for Argon Plus 25% Carbon Dioxide Shielded Flux Cored Arc Welding of Carbon Steel (M‐1/P‐1/S‐1, Groups 1 and 2), 1/8 in. (3.2 mm) through 1 ½ in. (38 mm) Thick, E7XT‐XM, As‐Welded or PWHT Condition,
Primarily Pipe Applications.
B2.1‐1‐234: 2006
GMAW – Gas Metal Arc Welding
Standard Welding Procedure Specification for Argon Plus 25% Carbon Dioxide Shielded Gas Metal Arc Welding (Short Circuiting Transfer Mode) followed by Argon Plus 2% Oxygen Shielded Gas Metal Arc Welding (Spray Transfer Mode) of Carbon Steel
(M‐1/P‐1/S‐1, Groups 1 and 2), 1/8 in. (3.2 mm) through 1 ½ in. (38 mm) Thick, ER70S‐3, Flat Position Only, As‐Welded or PWHT Condition, Primarily Pipe Applications.
B2.1‐1‐233: 2006
Standard Welding Procedure Specification for Argon Plus 2% Oxygen Shielded Gas Metal Arc Welding (Spray Transfer Mode) of Carbon Steel (M‐1/P‐1/S‐1, Groups 1 and 2), 1/8 in. (3.2 mm) through 1 ½ in. (38 mm) Thick, ER70S‐3, Flat Position Only, As‐Welded or PWHT
Condition, Primarily Pipe Applications.
B2.1‐1‐235: 2006
GTAW/SMAW Combination of Welding Processes
Standard Welding Procedure Specification for Gas Tungsten Arc Welding Followed by Shielded Metal Arc Welding of Carbon Steel (M‐1/P‐1/S‐1, Group 1 or 2), 1/8 in. (3.2 mm)
through 1 ½ in. (38 mm) Thick, ER70S‐2 and E7018, As‐Welded or PWHT Condition.
B2.1‐1‐021‐94 and B2.1‐1‐021‐94R
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Standard Welding Procedure Specification for Gas Tungsten Arc Welding followed by Shielded Metal Arc Welding of Carbon Steel (M‐1/P‐1/S‐1, Groups 1 or 2), 1/8 in. (3.2
mm) through 3/4 in. (19 mm) Thick, ER70S‐2 and E7018, As‐Welded or PWHT Condition, Primarily Pipe Applications.
B2.1‐1‐209‐96
Standard Welding Procedure Specification for Gas Tungsten Arc Welding followed by Shielded Metal Arc Welding of Carbon Steel (M‐1/P‐1/S‐1, Groups 1 or 2), 1/8 in. (3.2
mm) through 1 ½ in. (38 mm) Thick, ER70S‐2 and E7018, As‐Welded or PWHT Condition, Primarily Pipe Applications.
B2.1‐1‐209‐96 (R2007)
Standard Welding Procedure Specification for Gas Tungsten Arc Welding (Consumable Insert) Followed by Shielded Metal Arc Welding of Carbon Steel (M‐1/P‐1/S‐1, Group 1 or2), 1/8 in. (3.2 mm) through 3/4 in. (19 mm) Thick, INMs1 and E7018, As‐Welded or PWHT
Condition, Primarily Pipe Applications.
B2.1‐1‐211‐96
Standard Welding Procedure Specification for Gas Tungsten Arc Welding with ConsumableInsert Root Followed by Shielded Metal Arc Welding of Carbon Steel (M‐1/P‐1/S‐1, Group1 or 2), 1/8 in. (3.2 mm) through 1 ½ in. (38 mm) Thick, INMs‐1, ER70S‐2, and E7018 As‐
Welded or PWHT Condition, Primarily Pipe Applications.
B2.1‐1‐211:2001 R2012
GMAW/FCAW – Combination of Welding Processes
Standard Welding Procedure Specification for Argon Plus 25% Carbon Dioxide Shielded Gas Metal Arc Welding (Short Circuiting Transfer Mode) Followed by Argon Plus 25%
Carbon Dioxide Shielded Flux Cored Arc Welding of Carbon Steel (m‐1/P‐1/S‐1, Groups 1 and 2), 1/8 in. (3.2 mm) through 1 ½ in. (38 mm) Thick, ER70S‐3 and EXT‐X, As‐Welded or
PWHT Condition, Primarily Pipe Applications.
B2.1‐1‐232:2006
Austenitic Stainless Steel — (M8/P8/S8 Materials)
SMAW — Shielded Metal Arc Welding
Standard Welding Procedure Specification for Shielded Metal Arc Welding of Austenitic Stainless Steel (M‐8/P‐8/S‐8, Group 1), 1/8 in. (3.2 mm) through 1½ in. (38 mm) Thick, As‐
Welded Condition. B2.1‐8‐023‐94
Standard Welding Procedure Specification for Shielded Metal Arc Welding of Austenitic Stainless Steel (M‐8/P‐8/S‐8, Group 1), 1/8 in. (3.2 mm) through 1½ in. (38 mm) Thick,
Standard Welding Procedure Specification for Gas Tungsten Arc Welding of Austenitic Stainless Steel (M‐8/P‐8/S‐8, Group 1), 1/8 in. (3.2 mm) through 1 ½ in. (38 mm) Thick, As‐
Welded Condition. B2.1‐8‐024‐94
Standard Welding Procedure Specification for Gas Tungsten Arc Welding of Austenitic Stainless Steel (M‐8/P‐8/S‐8, Group 1), 1/16 in. (1.6 mm) through 1 ½ in. (38 mm) Thick,
ER3XX, As‐Welded Condition, Primarily Plate and Structural Applications. B2.1‐8‐024:2001
Standard Welding Procedure Specification for Gas Tungsten Arc Welding of Austenitic Stainless Steel (M‐8/P‐8/S‐8, Group 1), 1/16 in. (1.6 mm) through 1 ½ in. (38 mm) Thick,
Standard Welding Procedure Specification for Gas Tungsten Arc Welding of Austenitic Stainless Steel (M‐8/P‐8/S‐8, Group 1), 1/16 in. (1.6 mm) through 1 ½ in. (38 mm) thick,
Standard Welding Procedure Specification for Gas Tungsten Arc Welding With ConsumableInsert Root of Austenitic Stainless Steel (M‐8/P‐8/S‐8, Group 1), 1/8 in. (3.2 mm) through1 ½ in. (38 mm) Thick, IN3XX and ER3XX As‐Welded Condition, Primarily Pipe Applications.
B2.1‐8‐215:1998 B2.1‐8‐ 215:2001, R2012
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Combination Processes GTAW/SMAW
Standard Welding Procedure Specification for Gas Tungsten Arc Welding followed by Shielded Metal Arc Welding of Austenitic Stainless Steel (M‐8/P‐8/S‐8, Group 1), 1/8 in.
(3.2 mm) through 1 ½ in. (38 mm) Thick, As‐Welded Condition. B2.1‐8‐025‐94
Standard Welding Procedure Specification for Gas Tungsten Arc Welding followed by Shielded Metal Arc Welding of Austenitic Stainless Steel (M‐8/P‐8/S‐8, Group 1), 1/8 in. (3.2 mm) through 1 ½ in. (38 mm) Thick, ER3XX and E3XX‐XX, As‐Welded Condition,
Primarily Plate and Structural Applications.
B2.1‐8‐025:2001
Standard Welding Procedure Specification for Gas Tungsten Arc Welding Followed by Shielded Metal Arc Welding of Austenitic Stainless Steel (M‐8/P‐8/S‐8, Group 1), 1/8 in. (3.2 mm) through 1 ½ in. (38 mm) Thick, ER3XX and E3XX‐XX, As‐Welded Condition,
Primarily Pipe Applications.
B2.1‐8‐214‐97
Standard Welding Procedure Specification for Gas Tungsten Arc Welding Followed by Shielded Metal Arc Welding of Austenitic Stainless Steel (M‐8/P‐8/S‐8, Group 1), 1/8 in. (3.2 mm) through 1 ½ in. (38 mm) Thick, ER3XX and E3XX‐XX, As‐Welded Condition,
Primarily Pipe Applications.
B2.1‐8‐214:2001 R2012
Standard Welding Procedure Specification for Gas Tungsten Arc Welding With ConsumableInsert Followed by Shielded Metal Arc Welding of Austenitic Stainless Steel (M‐8/P‐8/S‐8, Group 1), 1/8 in. (3.2 mm) through 1 ½ in. (38 mm) thick, IN3XX, ER3XX, and E3XX‐XX As‐
Welded Condition, Primarily Pipe Application.
B2.1‐8‐216‐1998
Standard Welding Procedure Specification for Gas Tungsten Arc Welding with ConsumableInsert Root followed by Shielded Metal Arc Welding of Austenitic Stainless Steel (M‐8/P‐8/S‐8, Group 1), 1/8 in. (3.2 mm) through 1 ½ in. (38 mm) Thick, IN3XX, ER3XX, and E3XX‐
XX As‐Welded Condition, Primarily Pipe Applications.
B2.1‐8‐216:2001 R2012
Combination of Carbon Steel (P-1 Material) To Austenitic Stainless Steel (P-8 Material)
SMAW — Shielded Metal Arc Welding
Standard Welding Procedure Specifications for Shielded Metal Arc Welding of CarbonSteel (M‐1/P‐1/S‐1, Groups 1 or 2) to Austenitic Stainless Steel (M‐8/P‐8/S‐8, Group 1), 1/8 in. (3.2 mm) through 1 ½ in. (38 mm) Thick, E309(L)‐15, ‐16, or ‐17, As‐Welded
Condition, Primarily Pipe Applications.
B2.1‐1/8‐228:2002 2013 R
GTAW — Gas Tungsten Arc Welding
Standard Welding Procedure Specification for Gas Tungsten Arc Welding of Carbon Steel (M‐1/P‐1/S‐1, Groups 1 or 2) to Austenitic Stainless Steel (M‐8/P‐8/S‐8, Group 1), 1/16 in. (1.6 mm) through 1 ½ in. (38 mm) Thick, ER309(L), As‐Welded Condition,
Primarily Pipe Applications.
B2.1‐1/8‐227:2002 R2013
Standard Welding Procedure Specifications for Gas Tungsten Arc Welding with Consumable Insert Root of Carbon Steel (M‐1/P‐1/S‐1, Groups 1 or 2) to Austenitic
Stainless Steel (M‐8/P‐8/S‐8, Group 1), 1/16 in. (1.6 mm) through 1½ in. (38 mm) Thick, IN309 and ER309(L), As‐Welded Condition, Primarily Pipe Applications.
B2.1‐1/8‐230:2002 R2013
GTAW/SMAW Combination of Welding Processes
Standard Welding Procedure Specifications for Gas Tungsten Arc Welding followed by Shielded Metal Arc Welding of Carbon Steel (M‐1/P‐1/S‐1,Groups 1 or 2) to Austenitic Stainless Steel (M‐8/P‐8/S‐8, Group 1), 1/8 in. (3.2 mm) through 1½ in. (38 mm) Thick, ER309(L) and E309(L)‐15, ‐16, or ‐17, As‐Welded Condition, Primarily Pipe Applications.
B2.1‐1/8‐229:2002 R2013
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39 SECTION 2
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Standard Welding Procedure Specifications for Gas Tungsten Arc Welding with Consumable Insert Root followed by Shielded Metal Arc Welding of Carbon Steel
(M‐1/P‐1/S‐1, Groups 1 or 2) to Austenitic Stainless Steel (M‐8/P‐8/S‐8, Group 1), 1/8 in. (3.2 mm) through 1½ in. (38 mm) Thick, IN3009, ER309, and E309‐15, ‐16, or ‐17 or IN309, ER309(L) and ER309(L)‐15, ‐16, or ‐17, As‐Welded Condition, Primarily Pipe
Applications.
B2.1‐1/8‐231:2002 R2015
Chromium Molybdenum Steel (M4/P4 and M5a/P5A Materials)
SMAW — Shielded Metal Arc Welding
Standard Welding Procedure Specifications for Shielded Metal Arc Welding of Chromium‐Molybdenum Steel (M‐4/P‐4, Group 1 or 2), E8018‐B2, 1/8 in. (3.2 mm) through 1 ½ in. (38 mm) Thick, As‐Welded Condition, 1/8 in. (3.2 mm) through 1½ in.
Standard Welding Procedure Specifications for Shielded Metal Arc Welding of Chromium‐Molybdenum Steel (M‐5A/P‐5A), E9018‐B3, 1/8 in. (3.2 mm) through 1 ½ in. (38 mm) Thick, As‐Welded Condition, 1/8 in. (3.2 mm) through 1½ in. (38 mm) Thick,
PWHT Condition, Primarily Pipe Applications.
B2.1‐5A‐223:1999 R2009
GTAW — Gas Tungsten Arc Welding
Standard Welding Procedure Specifications for Gas Tungsten Arc Welding of Chromium‐Molybdenum Steel (M‐4/P‐4, Group 1 or 2), ER80S‐B2, 1/8 in. (3.2 mm) through 1 ½ in. (38 mm) Thick, As‐Welded Condition, 1/8 in. (3.2 mm) through 3/4 in. (19 mm) Thick,
PWHT Condition, Primarily Pipe Applications.
B2.1‐4‐217:1999 R2009
Standard Welding Procedure Specifications for Gas Tungsten Arc Welding (Consumable Insert Root) of Chromium‐Molybdenum Steel (M‐4/P‐4, Group 1 or 2), E8018‐B2, 1/8 in. (3.2 mm) through 1 ½ in. (38 mm) Thick, As‐Welded Condition, 1/8 in. (3.2 mm) through 3/4 in. (19 mm) Thick, PWHT Condition, IN515 and ER80S‐B2, Primarily Pipe
Applications.
B2.1‐4‐220:1999 R2009
Standard Welding Procedure Specifications for Gas Tungsten Arc Welding of Chromium‐Molybdenum Steel (M‐5A/P‐5A), ER90S‐B3, 1/8 in. (3.2 mm) through 1½ in. (38 mm) Thick, As‐Welded Condition, 1/8 in. (3.2 mm) through 3/4 in. (19 mm) Thick, PWHT
Condition, Primarily Pipe Applications.
B2.1‐5A‐222:1999 R2009
Standard Welding Procedure Specifications for Gas Tungsten Arc Welding (ConsumableInsert Root) of Chromium‐Molybdenum Steel (M‐5A/P‐5A), 1/8 in. (3.2 mm) through1‐1/2 in. (38 mm) Thick, As‐Welded Condition, 1/8 in. (3.2 mm) through 3/4 in. (19 mm) Thick, PWHT Condition, IN521 and ER90S‐B3, Primarily Pipe Applications.
B2.1‐5A‐225:1999 R2009
Chromium‐Molybdenum Steel Processes GTAW/SMAW
Standard Welding Procedure Specifications for Gas Tungsten Arc Welding (Consumable Insert Root) followed by Shielded Metal Arc Welding of Chromium‐Molybdenum Steel (M‐4/P‐4, Group 1 or 2), 1/8 in. (3.2 mm) through 1‐1/2 in. (38 mm) Thick, As‐Welded Condition, 1/8 in. (3.2 mm) through 1 ½ in. (38 mm) Thick, PWHT Condition, IN515,
ER80S‐B2, and E8018‐B2, Primarily Pipe Applications.
B2.1‐4‐221:1999 R2009
Standard Welding Procedure Specifications for Gas Tungsten Arc Welded followed by Shielded Metal Arc Welding of Chromium‐Molybdenum Steel (M‐5A/P‐5A), 1/8 in. (3.2 mm) through 1 ½ in. (38 mm) Thick, As‐Welded Condition, 1/8 in. (3.2 mm) through 1 ½ in. (38 mm) Thick, PWHT Condition, ER90S‐B3 and E9018‐B3, Primarily Pipe
Applications.
B2.1‐5A‐224:1999 R2009
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Standard Welding Procedure Specifications for Gas Tungsten Arc Welding (Consumable Insert Root) followed by Shielded Metal Arc Welding of Chromium‐Molybdenum Steel (M‐5A/P‐5A), 1/8 in. (3.2 mm) through 1 ½ in. (38 mm) Thick, As‐Welded Condition,
1/8 in. (3.2 mm) through 1 ½ in. (38 mm) Thick, PWHT Condition, IN521, ER90S‐B3, andE9018‐B3, Primarily Pipe Applications.
B2.1‐5A‐226:1999 R2009
Standard Welding Procedure Specifications (SWPS) for Gas Tungsten Arc Welded followed by Shielded Metal Arc Welding of Chromium‐Molybdenum Steel (M‐4A/P‐4, Group 1 or 2), 1/8 in. (3.2 mm) through 1/2 in. (13 mm) Thick, As‐Welded Condition, 1/8 in. (3.2 mm) through 1 ½ in. (38 mm) Thick, PWHT Condition, ER80S‐B2 and
E9018‐B2, Primarily Pipe Applications.
B2.1‐4‐219:1999 R2009
2.4 AWS REFERENCE STANDARDS
The following AWS Standards have been adopted by the NBIC for use as referenced below:
a) AWS B2.1 - Specification for Welding Procedure and Performance Qualification
b) AWS B2.1 BMG - Base Metal Grouping for Welding Procedure and Performance Qualification
2.5 HEAT TREATMENT
2.5.1 PREHEATING
a) Preheating may be employed during welding to assist in completion of the welded joint. The need for and the temperature of preheat are dependent on a number of factors such as chemical analysis, de- gree of restraint of the items being joined, material thickness, and mechanical properties. The Welding Procedure Specification for the material being welded shall specify the preheat temperature require- ments.
b) See minimum temperatures for preheating given in NBIC Part 3, Table 2.5.1 as a general guide. It is
cautioned that the preheating temperatures listed do not necessarily ensure satisfactory completion of the welded joint. Requirements for individual materials within the P-Number listing may have preheating requirements more or less restrictive than this general guide. When reference is made in this section to materials by the ASME designation, P-Number and Group Number, the suggestions of this section ap- ply to the applicable materials of the original code of construction, either ASME or other, which conform by chemical composition and mechanical properties to ASME materials having the ASME P-Number and Group Number designations.
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NB16‐0809B 1.1 SCOPE a) This part provides general requirements and guidelines that apply when performing repairs and alterations to pressure‐retaining items. b) This part describes the administrative requirements for the accreditation of repair organizations.
cb) The National Board administers three specific accreditation programs: “R” — Repairs and Alterations to Pressure‐Retaining Items “VR” — Repairs to Pressure Relief Valves “NR” — Repair and Replacement Activities for Nuclear Items
bc) This part describes some of the administrative requirements for the accreditation of repair organizations. Additional administrative requirements can be found in: 1) NB‐415, Accreditation of “R” Repair Organizations 2) NB‐417, Accreditation of “NR” Repair Organizations 3) NB‐514, Accreditation of “VR” Repair Organizations d) General Rrequirements for repairs to pressure relief valves can be found in NBIC Part 4.
2.1 SCOPE
This section provides general and specific requirements and guidelines for welding and heat treating when
performing welded repairs and alterations to pressure‐retaining items. Careful consideration shall be given to
pressure‐retaining items that have been fabricated of either creep strength enhanced ferritic materials or ferritic
materials enhanced by heat treatment. The tensile and creep strength properties of these materials can be
degraded by not following specific welding and heat treatment requirements. The user is cautioned to seek
technical guidance for welding and heat treating requirements in accordance with the original code of
construction.
3.1 SCOPE
This section provides general and specific requirements and guidelines for materials, replacement parts, and
methods used when performing repairs and alterations to pressure‐retaining items. Specific repair or alteration
methods for other types of pressure equipment are in NBIC Part 3, Section 7.
4.1 SCOPE
This section provides requirements and guidelines for performing examinations and tests for repairs and
alterations to pressure‐retaining items.
Formatted: Strikethrough
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5.1 SCOPE
This section provides requirements for certification, stamping, and documentation of repairs and alterations to
pressure‐retaining items. Applicable forms are provided in this section for reference. Forms may be obtained from
the National Board website.
S1.1 SCOPE
This supplement provides requirements and guidelines for repair and alteration applies to all boilers attached to
of steam locomotives operating on track gaged 24 in. (610 mm) or greater or for steam locomotives under the
requirements of the Federal Railroad Administration (FRA). These rules shall be used in conjunction with the
applicable rules of the NBIC.
S2.1 SCOPE
This supplement is provided as a guide This supplement toprovides requirements and guidelines for repair
and alteration of historical steam boilers of riveted and/or welded construction not falling under the
scope of Supplement 1. These historical steam boilers would include: steam tractors, traction engines,
hobby steam boilers, portable steam boilers, and other such boilers that are being preserved, restored
and maintained for demonstration, viewing, or educational purposes.
Note: This supplement is not to be used for steam locomotive boilers falling under the requirements of
the Federal Railroad Administration (FRA). FRA rules for steam locomotive boilers are published in 49 CFR
230. Specific rules and special requirements for inspection, repairs, alterations, and storage of steam
locomotive boilers are identified in NBIC Parts 2 and 3, Supplement 1.
The rules specified in this supplement shall be used in conjunction with the applicable rules in this Code.
References specified or contained in this supplement may provide additional information to assist the
user when applying the requirements of this supplement.
S3.1 SCOPE
This supplement provides requirements and guidelines forR repairs to graphite pressure equipment require the use of certified impregnated graphite and cement. The determining factor in establishing the desired material properties is the resin impregnation cycle. If the resin impregnation cycle is not controlled, it is not possible to meet the minimum design values.
S4.1 SCOPE
a) This supplement provides general requirements and guidelines that apply to repairs and alterations to
fiber‐reinforced pressure‐retaining items.
b) The letters “RP” shall be included on the “R” Certificate of Authorization for those organizations
authorized to perform repairs/alterations of fiber‐reinforced plastic pressure equipment.
Formatted: Font color: Red, Strikethrough
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S5.1 SCOPE
This supplement provides additional requirements and guidelines for repairs and alterations to Yankee dryer
pressure‐retaining components and shall be used in conjunction with inspection requirements identified in NBIC
Part 2, Inspection Supplement 5.
S6.1 SCOPE
This supplement provides general requirements and guidelines that apply to thefor repairs, alterations, or
modifications to DOT Transport Tanks used for the transportation of dangerous goods via highway, rail, air, or
water.
S7.1 SCOPE
This supplement provides general requirements and guidelines that apply to repairs to pressure relief valves.
Repairs may be required because of defects found during periodic inspections because testing has identified that
valve performance does not meet the original code of construction requirements, failure during operation, or for
routine preventative maintenance.
S8.1 INTRODUCTION
This supplement provides guidance for the design of a test system using compressible fluids (e.g., steam or air/gas)
and permits the determination of pressure relief valve set pressure and valve operating characteristics such as
blowdown. The size of the test vessel needed depends on the size of the valve, its set pressure, the design of the
test system, and whether blowdown must be demonstrated. A repair organization may use the information
provided in this supplement to determine the minimum size test vessel needed so that the measured performance
is characteristic of the valve and not the test system.
S9.1 INTRODUCTION PARAGRAPH S9.1 IS NOT PART OF THIS ACTION
This supplement provides requirements for Certificate Holders that wish to Approval to extend the scope of the
National Board “VR” Certificate of Authorization to the Certificate Holder to use the “VR” Stamp on ASME Code
“NV” Class 1, 2, or 3 stamped pressure relief devices, which have been capacity certified by the National Board,
may be given subject to the provisions that follow..
S10.1 SCOPE
This supplement provides general and specific requirementsrequirements and guidelines that apply to the repairs
or alterations to pressure vessels designed for storing Liquid Petroleum Gas (LPG) and fabricated in accordance
with the ASME Boiler and Pressure Vessel Code, Section VIII, Division 1, or the API‐ASME Code for Unfired Pressure
SC Repairs and Alterations Attachments /NB16-0809B Besserman 7-20-16 Final (2)
Vessels for Petroleum Liquid and Gases. When the standard governing the original construction is not the ASME
Boiler and Pressure Vessel Code, Section VIII, Division 1 or the API‐ASME Code for Unfired Pressure Vessels for
Petroleum Liquid and Gases, the requirements of NBIC Part 3, 1.2 b, shall apply. In addition to this supplement,
the applicable paragraphs of Part 3 of the NBIC shall be met. Vessels used for anhydrous ammonia service shall not
be considered for repair or alteration in accordance with this supplement.
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Item NB16-1101 Revisions are underlined
Supplement 11
WELD AND POST REPAIR INSPECTION OF CREEP STRENGTH ENHANCED
FERRITIC STEELS
S11.1 SCOPE The technical information provided in this supplement pertains to weld repair and post repair inspection of creep strength enhanced ferritic steel (CSEF) pressure retaining items. This Supplement provides guidance for full penetration and partial penetration weld repairs not covered under Welding Method 6 (2.5.3.6). Creep Strength Enhanced Ferritic alloys (CSEF’s) are a collection of ferritic steels whose creep strength is enhanced by the creation of a precise condition of micro-structure, specifically martensite or bainite, which is stabilized during tempering by controlled precipitation of temper‐resistant carbides, carbo‐nitrides, or other stable and/or meta‐stable phases. Careful consideration shall be given to pressure-retaining items that are fabricated from CSEF’s. The behavior of these materials in low temperature (i.e. fracture toughness and/or fatigue) and in high temperature (i.e. creep and/or creep-fatigue) components can be degraded by not adhering to the welding procedures and improper application of post-weld heat treatment (PWHT). Experienced inspection personnel should oversee weld repairs of this nature for strict compliance with all welding procedure and repair requirements. Post Construction access and in-service operation may not allow the practicable application of PWHT following original construction fabrication requirements and repair weld joint design. This supplement provides guidelines for weld repair options and post repair inspection using a well-engineered approach for CSEF steels. The user is cautioned to seek technical guidance for welding and selection of heat treating requirements. Prior to using this guideline an engineering evaluation shall be performed to determine the scope of the repair and impact to safety prior to returning the pressure-retaining item to service for a specified period of time, based on acceptance by the Inspector, and when required the Jurisdiction. The organization performing the engineering evaluation shall have demonstrated experience with Grade 91 CSEF steels.
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S11.2 WELD REPAIR OF GRADE 91 STEEL S11.2.1 Weld Repair Options (1) 9Cr-1Mo-VNbN Filler Metal (i.e. matching to Grade 91) + Controlled Fill + Low PWHT (Minimum temperature is 1250°F, 675°C). Acceptable filler materials are referenced in Table 11-1. The minimum time and maximum heat treatment temperature shall be in accordance with the original code of construction. For reference, where the Ni+Mn content of the filler metal is not known, the maximum PWHT temperature shall be 1425°F (775°C). As general best practice, This maximum shall be enforced to avoid over-tempering or exceeding the absolute maximum PWHT temperature. PWHT hold times at temperature shall be as follows;
a. Minimum holding time at PWHT temperature is specified as 1 hour per 1.0 inch (25 mm) of thickness, 30 minute minimum provided the component < 0.5 inches (12.5 mm) in thickness;
b. Minimum holding time at PWHT temperature is specified as 5 hours plus 15 minutes for each additional 1.0 inch (25 mm) over 5.0 inches (125 mm);
(2) 9Cr-1Mo Filler Metal + Controlled Fill and No PWHT. Acceptable filler materials are detailed in Table 11-1.
(3) Ni-base Filler Metal + Controlled Fill and No PWHT. Acceptable nickel base consumables include selected ASME F No. 43 filler metals as detailed in Table 11-1.
Table 11-1. Alternative Weld Repair Methods, Filler Metals and Welding Processes for Grade 91 Steel.
Acceptable Weld Repair Method Welding Process and Filler Metal AWS Classification Filler Metal Welding Procedure
Matching (9Cr-1Mo-VNbN) Controlled Fill + Low
PWHT
SMAW – E9015-B9, E9016-B9, E9018-B9 or E9015-B91A, E9016-B91A or E9018-B91A
FCAW – E91T1-B9 or E91T1-B91A GTAW – ER90S-B9 or ER90S-
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B91A
9Cr-1Mo Controlled Fill
SMAW – E8015-B8, E8016-B8 or E8018-B8
FCAW – E81T1-B8 GTAW – ER80S-B8
Ni-base Controlled Fill
SMAW – EPRI P87B, ENiCrFe-2, ENiCrFe-3
FCAW – None available GTAW – EPRI P87C, ERNiCr-3
A –B91 AWS classification is pending for the various Grade 91 filler metal product forms (currently –B9) BIncorporated by ASME B&PV Code as Code Case 2734 for classification as an F No. 43 filler materialCIncorporated by ASME B&PV Code as Code Case 2733 for classification as an F No. 43 filler material
S11.3 Application of Controlled Fill Welding Procedure (a) The minimum preheat for the repair procedure shall be 300 oF (150 oC). The preheat temperature shall be checked to ensure the minimum preheat temperature is maintained during all welding and until welding is completed. The maximum interpass temperature shall be 550 oF (290 oC). At the completion of welding, a post weld hydrogen bake-out is not required nor prohibited.
(b) In general To control heat input, it is recommended to weld the repair groove the weld repair shall be performed using a “controlled fill” technique. In this technique, the first layer in contact with the repair groove can be identical or smaller in diameter than the fill passes. (c) Figures 11-1 through 11-4 illustrate the various types of recommended acceptable weld joint details using the controlled fill technique for full or partial penetration weld repairs. (d) The bead-to-bead overlap shall be ~50% or greater. The fill passes shall be deposited working from the bevel of the machined excavation towards the center of the excavation with a minimum overlap of 25% and ideally 50%. As a rule of thumb, if the welder aims for the toe of the previously deposited weld bead, an overlap of at least 40% will be achieved. (e) When the SMAW process is specified with ferrous filler metals, the fill passes are restricted to a maximum electrode diameter of 1/8 in. (3.2 mm). When the SMAW process is specified with nickel-base filler metals, the fill passes in immediate contact with the excavation shall not exceed an electrode diameter of 1/8” (3.2 mm), and for the remaining fill passes to restore the excavated material an increase in the electrode diameter to 5/32 in. (4.0 mm) is permitted. When the
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GTAW process is specified, any limits for filler metal size shall be reflected in the qualified PQR and WPS.
Figure 11-1. Schematic of the Controlled Fill Welding Procedure for Grade 91 Steel for a Partial Penetration Weld Repair. Note 1 – The excavation shall have rounded corners to prevent lack of fusion defects. In these locations it is recommended to use a smaller diameter electrode (such as 3/32 in., 2.4 mm) to ensure acceptable fusion. Note 2 – The repair cavity width shall extend at least 0.40 in. (10 mm) beyond the fusion line of the original weld Note 3 – Where the excavation may pose challenges with electrode access, it is recommended that the fill passes in immediate contact with the machined excavation be restricted in height as the weld repair is performed.
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Figure 11-2. Schematic of the Controlled Fill Welding Procedure for Grade 91 Steel for a Full Penetration Weld Repair using a Compound Bevel. Note 1 – Where the excavation may pose challenges with electrode access, it is recommended that the fill passes in immediate contact with the machined excavation be restricted in height as the weld repair is performed.
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Figure 11-3. Schematic of the Controlled Fill Welding Procedure for Grade 91 Steel for Full Penetration Weld Repair using a land. Note 1 – The excavation shall have rounded corners to prevent lack of fusion defects. In these locations it is recommended to use a smaller diameter electrode (such as 3/32 in., 2.4 mm) to ensure acceptable fusion.
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Figure 11-4. Schematic of the Controlled Fill Welding Procedure for Grade 91 Steel for a Full Penetration Weld repair using a Step Weld Preparation. Note 1 – The excavation shall have rounded corners to prevent lack of fusion defects. In these locations it is recommended to use a smaller diameter electrode (such as 3/32 in., 2.4 mm) to ensure acceptable fusion. Note 2 – The repair cavity width shall extend at least 0.40 in. (10 mm) beyond the fusion line of the original weld Note 3 – Where the excavation may pose challenges with electrode access, it is recommended that the fill passes in immediate contact with the machined excavation be restricted in height as the weld repair is performed.
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S11.4 Qualification of Controlled Fill Welding Procedure (a) The test material for the welding procedure qualification shall be P-No 15E, Group 1, Grade 91.
(b) Qualification thickness for the test plates and repair groove depths shall be in accordance with ASME Section IX.
(c) The Welding Procedure Specification (WPS) shall be qualified in accordance with requirements of ASME Section IX. If qualifying the WPS with PWHT, the PWHT is to be low temperature PWHT, i.e., a minimum temperature of 1250 deg F (675 deg C) and a maximum temperature of 1445 deg F(785 deg C).
(d) For qualification of weld repair procedures using 9Cr-1Mo filler metal and in the as-welded condition, the requirements for the bend test shall be performed using a bend radius which achieves a minimum of 14% elongation in the outer fibers. S11.5 POST REPAIR INSPECTION (a) After the completion of weld repairs to CSEF steels, post inspection requirements shall be developed and implemented based on acceptance from the Inspector, and if applicable, the Jurisdiction. (b) Post-repair inspection intervals and methods of examination shall be implemented to ensure safe operation and margin to locate and monitor defect growth in the weld repair area. The selected non-destructive examination method shall provide meaningful results and shall follow NBIC Part 3, Section 4.. (c) Post repair inspection shall be on-going until the component reaches end of life or is replaced. A recommended re-inspection interval is every other planned major outage or six years, whichever is less. The Owner/User may revise the re-inspection interval based on inspection results from previous inspections. For NBIC Committee use only
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BackgroundAs part of EPRI’s commitment to Technology Transfer, a
number of activities are planned in 2016 and 2017:– [June 15, 2016] Session at the Creep Strength Enhanced Ferritic
Steel Interest Group Meeting on recent end-user application of alternative weld repairs,
– [August 9-11, 2016] Workshop on Life Management of Grade 91 Steel with an emphasis on weld repair, co-hosted by American Electric Power
– [October 11-14, 2016] 8th International Conference on Advances in Materials Technology for Fossil Power Plants
– [June 22, 2017] Special Session in the Welding and Repair Technology for Power Plants 12th International Conference on alternative weld repair of Grade 91 steel
– [On-going] Databasing/communication of alternative weld repairs
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Recent Repair ExamplesThere are no less than seven end-users that have performed
alternative weld repairs in the last 7 years. More active use has occurred within the last 12 months. Examples include a wide range of components:– Superheater and reheater tube to tube butt welds [>250]– Thick-section valve body to piping butt welds [1]– Tube to header replacement [7]– Thermowell replacement [3]– Thermocouple pad replacement [2]– Shear lugs [1]– Support lugs [1]– Replacement small diameter valve replacement [19]– Piping repair [10] – Balance line/drain line in valve [2]– Gamma plugs on piping/headers [unknown]– Header inspection welds [27]
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One Utility’s Breakdown of 65 Alternative Weld Repairs in Grade 91 Steel in the Last 12 months [CSEF IG Meeting]
Utilized procedures include the gas tungsten arc welding process and both ER80S-B8 and ERNiCr-3 filler metals– 65% of repairs with ERNiCr-3 and 35% of repairs with ER80S-B8
– General guidance consistent with EPRI Document 3002003833; operating temperature <550°C (1022°F) -B8 type filler material
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SC Repairs and Alterations Attachments /Update of Alternative Weld Repairs in Grade 91 Steel
2.5.3
d)The detailed welding methods listed in the following subsections may be used as an alternative to postweld heat treatment (PWHT). NBIC Part 3, 2.5.3.1 is a method in which the welding procedure requires an elevation of the preheat temperature. In contrast, NBIC Part 3, 2.5.3.2 through 2.3.5.5 are methods in which the procedure requires use of the temper‐bead welding technique. Welding Method 6 as described in 2.3.5.6 requires use of a controlled fill technique. In 2.5.3.5 is a method in which the welding procedure used for joining dissimilar materials requires either an elevation of the preheat temperature or a temper-bead welding technique, depending on the chemical composition of the base metal that is joined to an austenitic steel. Temper-bead welding procedure nomenclature is defined in Section IX of the ASME Boiler and Pressure Vessel Code. Typically, this technique minimizes heat input of the initial beads, thus limiting heat beyond the weld heat-affected zone (HAZ) of the base metal. Heat input shall be increased for successive beads in accordance with the rules of QW- 290 for temper bead welding in ASME Section IX. The Welding Procedure and Welder Performance Qualifications shall, in all cases, be in accordance with the requirements of the latest Edition of Section IX of the ASME Boiler and Pressure Vessel Code.
NB16‐1102
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S3.1 SCOPE
a) Repairs to graphite pressure equipment require the use of certified impregnated graphite and cement. The determining factor in establishing the desired material properties is the resin impregnation cycle. If the resin impregnation cycle is not controlled, it is not possible to meet the minimum design values.
a)b) The letter “G” shall be included on the “R” Certificate of Authorization for those organizations authorized to perform repairs/alterations of graphite pressure equipment.
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NBIC Committee Action Box
Subject Hydrostatic test for re-rated item File Number NB 16-2101 (R & A)
Proposal on Pg. 2
Proposal Revision to Part 3: Add a new sentence onto 3.4.1 d) that will permit the original construction hydrostatic test to satisfy the NBIC requirement for a pressure test following a re-rate of the pressure retaining item
Explanation
There are many occasions when a boiler or pressure vessel is re-rated to a higher MAWP or there is a change in design temperature (increase or decrease). And there is no physical work performed on the PRI. However, re-rating is an alteration and the NBIC calls for a pressure test to be performed to satisfy the new service conditions. Sometimes, the re-rating design change is small. Small enough where an NBIC pressure test would be equal to or less than what would be required by the code of construction. And the NBIC test to verify new service conditions would be no higher than what was performed when the vessel was constructed and what is recorded on the ASME nameplate. The NBIC issued interpretation 98-15 that allowed the construction hydro to satisfy the required NBIC hydro if it was at least equal to the calculated test pressure required to verify the integrity of the re-rate. This revision to 3.4.1 d) incorporates that permission.
Project Manager
Robert Wielgoszinski
SubGroup Results
SG Meeting Date
SubCommittee Results
SC Meeting Date
Main Committee Results
MC Meeting Date
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n1201533
Callout
INSERT NEW SENTENCE: The pressure test may be waived if the original pressure test as recorded on the Manufacturer's Data Report is at least equal to the calculated test pressure required to verify the integrity of the pressure-retaining item for the new conditions.
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NB16-2502 Add Patch bolts to material list in the Threaded stay bolt box
NB16-2503 delete grade B from SA 31 for Welded staybolts
NB16-2505 SA 696 to Hollow Cylindrical Pressure-Retaining Parts and Staybolt caps and
Sleeves.
TABLE S1.1.3.1
Application Boiler Tubes & Flues, Arch Tubes Superheater Units
SA‐31 Grade A SA‐675 with a tensile strength of 47,000 psi to 65,000 psi inclusive
Staybolt Sleeves and Caps
SA‐105 Forging, SA‐675, SA696
Boiler Braces SA‐675, SA‐36
Rivets SA‐675, SA‐31
Forged Parts & Fittings
SA‐105, SA‐181
Pressure‐Retaining Steel Castings
SA‐216, SA‐217
Formatted: List Paragraph, Indent: Left: 0.88", Adjust space between Latin and Asiantext, Adjust space between Asian text andnumbers
Formatted Table
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Hollow Cylindrical Pressure‐Retaining Parts
SA‐105 Forgings, SA‐675 Bar Stock SA 696
Superheater Unit Bolts & Nuts Bolts
‐ SA‐193, Nuts ‐ SA‐194
Pipe Flanges SA‐181, SA‐105
Bolts & Studs SA‐307 Grades A&B
Pipe SA‐106, SA‐53 seamless
Bronze Castings & Washout Plugs
SB‐61, SB‐62, SB‐148
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NB16‐2601 Action Item Request Form
PLUGGING OF HX TUBES
8.3 CODE REVISIONS OR ADDITIONS
Request for Code revisions or additions shall provide the following:
a) Proposed Revisions or Additions
For revisions, identify the rules of the Code that require revision and submit a copy of the appropriate
rules as they appear in the Code, marked up with the proposed revision. For additions, provide the
recommended wording referenced to the existing Code rules.
Existing Text: NBIC PART 3
b) Statement of Need
Provide a brief explanation of the need for the revision or addition.
Propose revising the example of repairs in 3.3.3(f) as follows: “Replacement or plugging of boiler and heat exchanger tubes where welding is involved”
The NBIC does not address plugging of heat exchanger tubes. It only has rules for plugging tubes in firetube boilers. This proposed revision to the NBIC will make it clear that plugging of heat exchanger tubes by any welding method shall be considered a repair.
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c) Background Information
Provide background information to support the revision or addition, including any data or changes in
technology that form the basis for the request that will allow the Committee to adequately evaluate the
proposed revision or addition. Sketches, tables, figures, and graphs should be submitted as appropriate.
When applicable, identify any pertinent paragraph in the Code that would be affected by the revision or
addition and identify paragraphs in the Code that reference the paragraphs that are to be revised or
added.
Explosion Plugging of leaking feedwater heater tubes is a common repair in the utility industry. Many times, this activity is not being performed in accordance with the NBIC and, in some cases, not being performed by “R” Certificate Holders. Currently, the NBIC provides no rules on plugging of heat exchanger tubes. Although the
proposed revision to 3.3.3(f) does not directly address the explosive plugging method, it
will now be clear that plugging of heat exchanger tubes by any welding method shall be
considered a repair.
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3.3.3 EXAMPLES OF REPAIRS a) Weld repairs or replacement of pressure parts or attachments that have failed in a weld or in the base
material; b) The addition of welded attachments to pressure parts, such as:
1) Studs for insulation or refractory lining;
2) Hex steel or expanded metal for refractory lining;
3) Ladder clips;
4) Brackets having loadings that do not affect the design of the pressure-retaining item to which they are attached; and
5) Tray support rings. c) Corrosion resistant strip lining, or weld overlay; d) Weld buildup of wasted areas; e) Replacement of heat exchanger tubesheets in accordance with the original design; f) Replacement or plugging of boiler and heat exchanger tubes where welding is involved; g) In a boiler, a change in the arrangement of tubes in furnace walls, economizers, or super heater
sections; h) Replacement of pressure-retaining parts identical to those existing on the pressure-retaining item and
described on the original Manufacturer’s Data Report. For example:
1) Replacement of furnace floor tubes and/or sidewall tubes in a boiler;
2) Replacement of a shell or head in accordance with the original design;
3) Rewelding a circumferential or longitudinal seam in a shell or head;
4) Replacement of nozzles of a size where reinforcement is not a consideration.
i) Installation of new nozzles or openings of such a size and connection type that reinforcement and
strength calculations are not a consideration required by the original code of construction; j) The addition of a nozzle where reinforcement is a consideration may be considered to be a repair,
provided the nozzle is identical to one in the original design, located in a similar part of the vessel, and not closer than three times its diameter from another nozzle. The addition of such a nozzle shall be restricted by any service requirements;
k) The installation of a flush patch to a pressure-retaining item; l) The replacement of a shell course in a cylindrical pressure vessel; m) Welding of gage holes;
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n) Welding of wasted or distorted flange faces; o) Replacement of slip-on flanges with weld neck flanges or vice versa; p) Seal welding of buttstraps and rivets; q) Subject to the administrative procedures of the Jurisdiction and approval of the Inspector, the
replacement of a riveted section or part by welding; r) The repair or replacement of a pressure part with a code-accepted material that has a nominal
composition and strength that is equivalent to the original material, and is suitable for the intended service; and
s) Replacement of a pressure-retaining part with a material of different nominal composition and, equal
to or greater in allowable stress from that used in the original design, provided the replacement material satisfies the material and design requirements of the original code of construction under which the vessel was built. The minimum required thickness shall be at least equal to the thickness stated on the original Manufacturer’s Data Report.
t) The replacement of a pressure relieving device (PRD) attached by welding, provided the replacement
device’s relieving capacity is equal to or greater than the PRD capacity required by the original code of construction.
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NBIC Agenda 07/21/16 - Item 9.a
NBIC – ASME Liaison Report
NBIC Standards CommitteeJuly 21, 2016
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ASME Liaison Report - NBIC Mtg 07-21-2016
NBIC Agenda 07/21/16 - Item 9.a
Separation of Conformity Assessment Requirements CA-1 – 2014 published to establish a uniform Standard for
ASME Conformity Assessment Requirements Working with BPV Book Sections to incorporate CA-1 as
Evergreen reference Ongoing work at CAR Committee to address Certificate
Scope Statements, Field Sites, CAP-21, and CAP-22 Future coverage planned for Nuclear Conformity
Assessment
Authorized Inspection Agency Oversight Program implemented for feedback on AIA performance,
by Team Leaders during Certificate holder surveys/reviews Proposal under consideration for an interim audit between
triennial surveys
ASME Conformity Assessment Activities
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ASME Liaison Report - NBIC Mtg 07-21-2016
NBIC Agenda 07/21/16 - Item 9.a
AI / ANI Inspection Requirements QAI Task Group developing uniform AI / ANI inspection
requirements, for incorporation in BPV Book Sections Coordinating alignment with NB-263, RC-1 “Rules for
Commissioned Inspectors”
BPV Parts Fabrication Certificate Program New Certificate scope with “PRT” Designator, providing for
fabrication w/o design responsibility Published in 2015 Edition for BPV-I, IV and XII; work
continues at BPV-VIII 2 certificates issued; 9 applications in process Follow-up clarification on scope statements and
New ASME Section XIII, “Rules for Overpressure Protection”
Addition of Certificate Numbers on Data Plates Proposed certification program for ASME B31.1 Covered
Piping Special Joining Processes Certificate Designator (Replace
Code Case 2590 Welding by Non-Certificate Holders) ASME III recognition of NR program for repair /
replacement activities
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ASME Liaison Report - NBIC Mtg 07-21-2016
Status of API‐CRE‐ SCI (Subcommittee on Inspection)– June 2016 (the 2016 Spring meeting minutes were not yet available, so this status update was provided by John Harville of Phillips 66)
Page 1 of 2
Document Title of Current Edition Rev. Due
Chair/Group Expert
Status Start Work Possession
API 510 Pressure Vessel Inspection Code—10th Edition
2019 J. Harville R. Konet
Addendum to be published this year with minor changes. Work on 11th edition not started yet, but chairperson for that effort will be John Harville and Vice Chair is Ray Konet.
SCI
API 570 Piping Inspection Code—4th Edition, Feb 2016
2021 D. Wang The 4th edition was published Feb 2016. Addendum scheduled to be pub’d later this year.
SCI
RP 571 Damage mechanisms – 2nd Edition
2016 (3rd Ed. Due)
J. Monroe(SCI) J. Staats (SCCM)
2 year extension granted. Joint work (between SCI and SCCM) is continuing on 3rd Edition. Still a year or more away from being pub’d
In Process SCCM
RP 572 Inspection of Pressure Vessels—3rd Edition, 2009
2016 ( 2 year CRE ext.)
R. Konet The 4th edition should have been published by now, but API was backed up wrt technical editors.
In Process SCI
RP 573 Inspection of Fired Boilers and Heaters—2nd Edition, 2002. Reaffirmed 2010.
2018 J. Scott T. Harrington
Task group formed for next edition/re‐write and initial meeting held May 2016.
SCI
RP 574 Inspection Practices for Piping System Components—3rd Edition, 2009
2016 (CRE 2 year ext.)
D. Wang The 4th edition should have been published by now, but API was backed up wrt technical editors.
In Process
SCI
RP 575 Inspection of Atmospheric and Low Pressure Storage Tanks—3rd Edition, 2014
2019 J. Scott N. Acosta
Task group is NOT yet formed for next edition/re‐write. Anticipated Chairs listed.
SCAST
RP 576 Inspection of Pressure Relieving Devices—3rd Edition, 2009
2016 (CRE 2 year ext.)
R. Schubert B. Thomas
Ballot resolution complete. Should be getting published this year.
In Process SCI
RP 577 Welding Inspection and Metallurgy—2nd Edition, December 2013
2018 S. Bolinger Task group formed for next edition/re‐write and initial meeting held May 2016.
In Process API
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API Liaison Report 6-17-16 Riley
Status of API‐CRE‐ SCI (Subcommittee on Inspection)– June 2016 (the 2016 Spring meeting minutes were not yet available, so this status update was provided by John Harville of Phillips 66)
Page 2 of 2
Document Title of Current Edition Rev. Due
Chair/Group Expert
Status Start Work Possession
RP 578 Material Verification Program for New and Existing Alloy Piping Systems—2nd Edition, 2010
2015 J.Yoakum D.Mears
Ballot comment resolution continues. Lots of changes made, so it WILL be reballoted, so it’s at least a year or more away from being published.
Spring 2014
SCI
RP 579 Fitness for Service—2nd Edition, 2007
2012 D. Osage Balloting complete by ASME and approved by ANSI. 3rd edition should be getting pub’d this year.
CRE
RP 580 Risk Based Inspection—3rd Edition, Feb 2016
2021 3rd Edition was pub’d Feb 2016. No current work on this doc.
SCI
RP 581 Risk Based Inspection Technology—3rd Edition, April 2016
2021 B. Ray 3rd Edition was pub’d Apr 2016. This doc has a standing task group, so it always being worked.
Ongoing SCI
RP 583 Corrosion Under Insulation—1st Edition, May 2014
2019 Work has not yet begun on the 2nd edition.
API
RP 584 Integrity Operating Windows—1st Edition, May 2014
2019 C White / J. Reynolds
Work has not yet begun on the 2nd edition. Chair will likely be Clay White.
SCI
RP 585 Pressure Equipment Integrity Incident Investigation—1st Edition, April 2014
2019 Work has not yet begun on the 2nd edition.
SCI
RP 586 ‐ check with editing for number
NDE Methods for Equipment Damage Mechanisms Document – NEW
New First edition
J. Nyholt J. Krynicki
Still under development New first edition
SCI
Pub. 587 Ultrasonic Examiner Qualification
New First edition
J. Krynicki 1st Edition balloted but did not pass. Intent is to document what is considered equivalent to “ API CUTE/QUSE” testing program. Still being worked.
