ML20154S165
| ML20154S165 | |
| Person / Time | |
|---|---|
| Issue date: | 07/18/1997 |
| From: | Joseph Colaccino NRC (Affiliation Not Assigned) |
| To: | NRC (Affiliation Not Assigned) |
| References | |
| NUDOCS 9810270327 | |
| Download: ML20154S165 (157) | |
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NUCLEAR REGULATORY >GOMMISSION S
WASHINGTON, D.C. 20e66-0001 o%
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July 18, 1997 MEMORANDUM T0:
File FROM:
Joseph Colaccino, Mechanical Engineer Components and Testing Section V
Mechanical Engineering Branch Division of Engineering, NRR
SUBJECT:
SUMMARY
OF PUBLIC WORKSHOPS HELD IN NRC REGIONS ON INSPECTION PROCEDURE 73756, " INSERVICE TESTING OF PUMPS AND VALVES," AND ANSWERS TO PANEL QUESTIONS ON INSERVICE TESTING ISSUES In January and February 1997, the NRC staff and their contractor, Brookhaven National Laboratory (BNL), conducted one-day public workshops in each Region to discuss Inspection Procedure (IP) 73756, " Inservice Testing of Pumps and Valves," and current issues related to inservice testing (IST).
The workshops were attended by rwesentatives of nuclear power plant licensees in the applicable Regions and members of the public. Attachment 1 is a list of meeting participants.
The Mechanical Engineering Branch of NRR, the Office of Nuclear Regulatory Research, Regional management and staff, and a representative from BNL participated in the workshops. During each workshop, the NRC staff and the BNL contractor gave presentations on the following subjects:
Elements of IP 73756; Revisions to ASME Operation and Maintenance (0M) Code That Address NRC Positions in Generic Letter 89-04 and its Supplement; Use of Analysis to Evaluate Pumps in Alert and Required Action Ranges; Vibration Testing for Very Smooth Pumps; GL 96-05 (Periodic Verification of Motor-0perated Valves) and OM Code Case OMN-1 as an Alternative to Stroke-Time Testing of MOVs; and Findings from Recent IST Inspections. Attachment 2 includes the agenda at each Regional workshop plus the handouts and slides ggslWfidpresentations.
During each Regional workshop, there were bre'akout sessiong,maderated by NRC staff and the BNL contractor discussing current, JSTds19esPIndividual questions were recorded by the moderators agi'.terdned in the afternoon panel sessions with the caveat that the answers may change in the final meeting minutes. The staff and BNL have assembled the' questions and the staff's
. answers in Attacht.9nt 3 of the minutes. Questions that were not related to IST issues were not' included in the meeting minutes. Responses to questions in do not include any new staff positions or guidance with the exception of questions 1.3.6 and 2.3.19.
These two responses.are interpretations of existing NRC guidance and positions that are not documented in any previous NRC guidance and are not being imposed on licensees. The remaining answers do not include any new staff positions or guidance and are
' intended to be clarifications only..Where the staff determined that a question could not be addressed without issuing a new staff guidance or position, the answer states that further NRC review is required.
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2 A number of questions raised by the workshop attendees are ASME Code issues.
At the March 1997 ASME Operation & Maintenance (0M) Code Committee meeting in Seattle, Washington, the BNL contractor gave a presentation on these issues to the OM Main Committee.
The ccmmittee appointed an ASME Task Force to work with the NRC and identify the workshop questions that may involve ASME Code changes or inquiries.. A public meeting was held on April 30, 1997, at BNL, between the NRC, the BNL contractor, and the two members of the ASME Task Force, to discuss which questions should be further considered by ASME as code changes or inquiries.
Questions in Attachment 3 which were identified by the ASME Task Force as issues which may merit a code change or inquiry have been identified with an asterisk following the question number. Approximately one-third of the workshop questions fall into this category.
The NRC response to these particular questions reflects current NRC guidance and understanding of the ASME Code.
Attachments:
1.
Attendees
-2.
Slides and Handouts 3.
Panel Questions and Responses cc w/ attachments:
IST Service List Meeting attendees Distribution:
File Center Regional DRS Directors Glainas EMEB RF/CHRON DOCUMENT NAME: G:\\COLACCIN\\lST To receive a copy of this document, indicate in the box C= Copy w/o attachment / enclosure E= Copy with attachment / enclosure N a No copy 0FFICE EMEB:DE E
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I NAME JColaccino DTerao RWesk k N g7
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0FFICIAL RECORD COPY
John A. Addison Larry Alexander, IST Engr.
150 Pruett Place P. O. Box 2000 Oakdale, CT 06370 OSPS-3C
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e-mail ADDIS0NJ0ASME.0RG Daisy, TN 37379 860-439-1052 Andre N. Anderson, Engineer Rick Aron Duke Power Co.
VYNPC 526 S, Church St.
P O Box 157 Charlotte, NC 28242 Vernon, VT 05354 802-257-7711 Denver Atwood, Sr. Engr.
Mike Baker, PECO Southern Nuclear Peach Bottom P. O. Box 1295 1848 Lay Road Birmingham, AL 35201 Delta, PA 17314 717-456-7014x4094 Mike Ball Darryl Barney, IST Coordinator VYNPC San Onofre NGS P O Box 157 Southern California Edison Co.
Vernon, VT 05354 P.O. Box 128 802-258-5577 San Clemente, CA 92674-0128 714/368-9270 David B. Black Paul Brown IST Engineer - FPC Principal Engineer Mail Code NA2J Yankee Atomic j
Joe Buczynski Mike Bufford Pennsylvania Power & Light Dresden Station P O Box 451 6500 N. Dresden Road i
Berwick, PA 18603 Morris, IL 60450 717-542-1803 Augustine Cardillo Dennis W. Carlson Test Programs NSP - Prairie Island Plant Carolina Power & Light Company 1717 Wakonade Dr., E West Entrance Road Welch, MN 55089 Hartsville, SC 803/857-5267 Dean A. Carstens Eric Cartwright, PEC0 Monticello Plant Peach Bottom 2807 W. Hwy 75 1848 Lay Road Monticello, MN 55362 Delta, PA 17314 717-456-7014x3089 ATTACHMENT 1 Al-1
Loretta Cecelu P.C. Chiu, Program Engr.
Licensing Engr. - FPC Comanche Peak Steam ES Mail Code SA2A TU Electric P O Box 14000 P.O. Box 1002 Juno Beach, FL 33408-0420 Glen Rose, TX 76043 817/897-6510 Jeff Chizever Mark Clouse Sr. Engineer IST Engr. - CP&L Yankee Atomic 3581 West Entrance Rd.
Hartsville, SC 29550 Bret R. Collier Shawn Comstock, IST Engineer Zion Nuclear Generating Station Wolf Creek Generating Station 101 Shiloh Blvd Wolf Creek Nuclear Op. Corp.
Zion, IL 60099 P.O. Box 411 Burlington, KS 66839 316/364-8831 X4412 James Connolly Carl Corbin, Licensing CP&L Comanche Peak Steam ES HNP Zone 4 TU Electric P. O. Box 165 P.O. Box 1002 New Hill, NC 27562 Glen Rose, TX 76043 817/897-0121 Michael J. Delzinga Adele DiBiasio General Manager Brookhaven National Laboratory Liberty Technologies, Inc.
Building 130 Upton, NY 11973 Phyllis Dixon John J. Dore, Jr.
i ISI/IST Supv. - FPC Duke Engr & Services, Inc.
Mail Code NA2J 1210 Chestnut St.
P O Box 14000 Reading, PA 19601 Juno Beach, FL 33408-0420 Robert J. Dolansky Charles Driskell, ISI Engr.
NYPA TVA - BFN PEC-1C Indian Point 3 P. O. Box 2000 Buchanan, NY Decatur, AL 35609 914-736-8458 Bob Drogan Cuong T. Duong, Dr. Engr.
PEC0 Virginia Power - Surry Power P O Box 2300 P. O. Box 315 Sanatoga, PA 19464-0920 Surry, VA 23883 610-718-3784 Al-2
N Mark Ebel, IST Engineer' Ted Eliakis '
South Texas Project Comed Houston Lighting & Power Co.
Braidwood Station P.O. Box 289 Wadsworth, TX 77483.
RR1 Box 84 Braceville, IL 60407 512/972-7744 John Feigl Rich Fielding Dresden Station Dresden Station 6500 N. Dresden Road 6500 N. Dresden Road Morris, IL 60450 Morris, IL 60450 Len Firebuagh,.Sr. Engr.
Tom Frolo EC09E NAESCO P.'O. Box 1006 P O Box 300-Charlotte, NC 28201-1006 Seabrook, NH 03874 Ivo A. Garza Tony Glass, IST Engineer Comed Suite 400 River 9end Station-1600 Opus Pl.
Entergy Operations, Inc.
Downers Grove,.IL 60516 P.O. Box 220
-St. Francisville, LA 70775 504/381-4774 Jim Glover Mark Golden Comed Suite 400 P O Box 467 1400 Opus Pl..
Berkwick, PA 18603 Downers Grove, IL 60516 717-542-3934 Joe Hair-Jon Hallem, ISI Engr.
Hartford Steam Boiler Inspection &
FPL - St. Lucie Insurance Co.
P. O. Box 128 Resident Authorized Inservice Ft. Pierce, FL 34954-0128 Inspector - Comanche Peak William Hinchie, IST Engineer-John Hjalmarson Union. Electric Co.
IST Coordinator Callaway P.O. Box 620 Diablo Canyon Power. Plant Fulton,' M0 65251 Pacific Gas & Electric Company 573/676-8176 P.O. Box 56 Avila Beach, CA 93424 805/545-4735 Hal H' odges, ISI Engr.
Brian Hohman TVA -- BFN PEC-lC Consumers Energy - Palisades P. O. Box 2000 27780' Blue Star Highway Decatur, AL 35609 Covert, MI 49043 Michael Hooshmund Tim Howard, Sr. Engineer
- Engr..Supv.
Plant Hatch Arizona Public Service P. O. Box 439 P.O.' Box 53999.
Baxley,' GA 31513 Phoenix, AZ 85072-3999 Al-3
l Tom Ickes Ron Jaquin l
NNECO RG&E Rope Ferry Road 89 East Avenue Waterford, CT 06385 Rochester, NY 14649 860-447-1791x6757 Keith Jensen Gary Johnson, Mech. Engr.
CP&L - Robinson TVA - Watts Bar 3581 West Entrance Road P. O. Box 2000, EQB IF-WBN Hartsville, SC 29550 Spring City, TN 37381 Peter Jordan, Project Mgr.
Greg Joss NUS Info. Sves, Inc.
RG&E 2650 McCormick Dr., Suite 300 1503 Lake Road Clearwater, FL 34619 Ontario, NY 14519 Wavel Justice Doug Kerr, Staff Engr.
Engineering Programs Virginia Power - NAPS Entergy Operations, Inc.
P.O. Box 42 P.O. Box 31995 Mineral, VA 23117 Jackson, MS 39286-1995 601/368-5452 John Kin,. Sr. Staff Engr.
Saragrace Knauf, IST Engineer Virginia Power Palo Verde NGS Innsbrook Tech Center Arizona Public Service Company 5000 Dominion Blvd.
P.O. Box 53999 Glen Allen, VA 23060 Phoenix, AZ 85072-3999 602/393-5248 Bob Knight Lewis Kurnegay GPUN Engr. T - CP&L L
P O Box 480 P. O. Box 10427 Middletown, PA 17057 Southport, NC 28461 717-948-8554 Ron Lippy, ISI/IST Engineer Ira Luker, Sr. Engr.
Fort Calhoun Station Southern Nuclear Omaha Public Power District P. O. Box 1295 l
P.O. Box 399 Birmingham, AL 35201 Ft. Calhoun, NE 68023-0399 402/533-6498 Tim Lupold Dean Lurk BGE Comed 1650 Calvert Cliffs Parkway Byron Nuclear Power Station i
Lusby, MD 20657 4450 N. German Church Road l
Byron, IL 61010 Joseph R. Lynch Jim Marchi Sr. Systems Engineer NAESCO Yankee Atomic P. O. Box 300 Seabrook, NH 03873 603-773-7024 i
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'I Bob Maseoro Duncan Massey, Engr.
GPUN.
TVA - BR 4J-C P O Box 480-1101 Market Street-Middletown, PA Chattanooga, TN 87402-2801 717-948-8884 Joe Mayer.
Ben Mays NAESCO.
Supv. Engineering Programs P. O. Box 300 Comanche Peak Steam ES Seebrook, NH 03874 TU Electric 603-773-7024 P.O. Box 1002-Glen Rose, TX 76043 817/897-6816
~ Jerry McClanahan, IST Engr Craig McClung, Sr. Engr.
TVA Virginia Power - NAPS 4H Lookout Place-P. 0. Box 42 1101 Market-Street' Mineral, VA 23117 Chattanooga, TN 87402-2801 Gary McGee; IST Coordinator Wes McGow Comanche Peak Steam ES CP&L TU Electric 412 S. Wilmington Street P.O. Box 1002 MC: OH5-9 Glen Rose, TX 76043 Raleigh, NC 27601 817/897-5477' Robert B.4McGowen, Consultant Mike McKenney BCP Technical Services Inc.
VYNPC.
P.0 Box 157 Vernon, VT 05354 802-258-5443 Robert McWilliams Paul " Matt" Melancon IST Engineer - AN0 IST Coordinator Entergy Operations, Inc Waterford 2 Steam Electric Sta 1448 S.R. 333 Entergy Operations, Inc.
Russellville, AR 72801-0967 P. O. Box B 501/858-4928 Killona, LA 70066 504/739-6614 Larry Merritt, System Engr Mike Metill South Texas Project VYNPC Houston Lighting & Power Co.
P O Box 157 P.O. Box-289 Vernon, VT 05354 Wadsworth,=TX 77483 802-257-7711 512/972-7240 Brent Metrow Steve Meyer, Quality Assurance Illinois. Dept. Nuclear Safety Union Electric Co.- Callaway P.O.
1035 Outer Park Drive Box 620 Springfield, IL 62704 Fulton, MO 65251 573/676-8184 Al-5
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' David C; Miller Derrick D. Miller
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LaSalle County Nuclear Station Duke Engineering & Services 2601 North 21st Road Dresden Nuclear Station Marseilles, IL 61341-9757-6500 N. Dresden Road Morris, IL 60450 Carl Moore Ken Muller-
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Comed RG&E Braidwood Station 1503 Lake Road RR1 Box 84 Ontario, NY 14519 Braceville,-IL 60407
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Jeff Neyhard Daniel Oakley Duke-E&S Comed - Dresden Station 203 Prairie Drive, Apt. H 6500 N. Dresden Road Elkton, MD 21921 Morris, IL 60450 410-620-0451 John Osborne Lee Parris BGE ENERTECH 1650 Calvert Cliffs Parkway 326 Craven Ave Lusby, MD 20657 Salem, NJ 08079 609-935-0165 Andy Patko, Sr.' Engr.
Joe Pendergast Southern Nuclear Fermi 2 Plant P. O. Box 1295 6400 North Dixie Hwy Birmingham, AL 35201 Newport, MI Bill l Phalen, IST Engineer G. L. Plumlee, III Palo Verde NGS Supervisor Regulatory j
Arizona Public Service Company Compliance 1
P.O. Box 53999 San Onofre NGS Phoenix, AZ 85072-3999 Southern California Edison Co.
1 602/393-5763 P.O. Box 128 i
San Clemente, CA 92674-0128 714/368-9222 Steve Quan, IST Engineer Raj Rana, IST Engineer Palo Verde NGS WNP ' Arizona Public Service Company WPPSS P.O. Box 53999 P.O. Box 968 Phoenix, AZ 85072-3999 Richland, WA 99352-0968 i
602/393-6215 509/377-4313 Kevin Remington Doug Ritter FPL-Turkey Point Pennsylvania Power & Light P.'O.-Box 029100 RR 4, Box 43098 Miami, FL 33102 Berwick, PA 18603 717-542-3547 L
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Tom Robinson.
Jim Rogers Comed-CATARACT Byron Nuclear Power Station 4 Salem Ridge Drive 4450 N. German Church Road Salem, CT 06420 Byron,=IL 61010 860-889-7356 C. Wesley Rowley, VP_
Joseph L. Sabina, BECo The Wesley Corporation Pilgrim NPS Tulsa,-Oklahoma' Rockhill Road 918/299-0255 Plymouth, MA 02360 William F. Sadowsky Roger Samson Sr. Engineer NAESCO Wyle Labs P O Box 300 P O Box 07-7777 Seabrook, NH 03874 Huntsville, AL 35807-7777 603-773-7024 Rocky Schultz, IST Engineer Jon Sears Cooper Nuclear. Station Nuclear Assurance Engineer Nebraska Public Power District Palo ' Verde NGS P.O. Box 98 Arizona Public Service Company Brownsville, NE 68321 P.O.-Box 53999 402/825-5675 Phoenix, AZ 85072-3999 602/393-6015
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Scott Seman Russell J. Severson Centerior Energy-Perry Plant DAEC i
10 Center Road N. Perry, OH 44081.
3313 DAEC Road Palo, IA 52324 MZ-A250 Ron Shires, Sr. QA Engineer Robert Shirk Crystal River Unit 3 General Physics 15760 W. Power Line Street 8401 J Benjamin Road Crystal River, FL 34428 Tampa, FL 33634 813-886-8983 Chad Smith Dennis Smith i
MOV Coordinator Surry Power Station Duke Energy 2750 Hog Island Road Surry, VA 23883 757-365-2764 George' Smith-Greg Smyth Nuclear Manager Senior Engineer Liberty' Tech Wyle Labs P O Box 07-7777 Huntsville, AL 35807-7777 Gary Strauss Dennis Swann BGE Engr. Supv.
1650 Calvert Cliffs Parkway Southern Nuclear Lusby, MD 20657 P. O. Box 1295 Birmingham, AL 35201 Al-7
Frank Szanyi Dan Szumski i
PSE&G Dresden Station P O Box 236 6500 N. Dresden Road Hancocks Bridge, NJ 08038' Morris, IL 60450 609-339-3488 Claude Thibault Allen L. Thomas Director - Nuclear Engineering DAEC Wyle Labs 3313 DAEC R)ad P O Box 07-7777 Palo, IA 52324 Huntsville, AL 35807-7777 Kenneth Tipton-IST Consultants Bau Tran, Staff Engineer BCP Technical Services South Texas Project' New Orleans, Louisiana Houston Lighting & Power Co.
504/361-4236 P.O. Box 289 Wadsworth, TX 77483 512/972-7419
' Jim Turkett, Licensing Engr.
Mark D. Uhrich South Carolina Electric & Gas Comed - Quad Cities Station V C Summer Station 22710 206th Ave, North P O Box 88 Cordova, IL
-Jenkinsville, SC 29065 Doug Urciuoli,.Lic. Engineer Bob Vasey Waterford 2 Steam Electric Sta AEP l
Entergy Operations, Inc.
500 Circle Drive P. 0. Box B Buchanan, MI 49107 Killona, LA 70066 504/739-6625' L. J.- Victory, Jr.
Philip Walker.
Programs Manager Staff Licensing Engr.
Enertech South Texas Project 326 Craven Avenue Houston Lighting & Power Co.
i Salem, NJ 08079 P.O. Box 289 Wadsworth, TX 77483 512/972-8392
.Gil Williams, Principle Engr.
Joann West South' Carolina Electric & Gas P O Box 4 V C Summer Station ~
Shippingport, PA 15077 P O Box 88 412-393-4961 Jenkinsville, SC 29065 David Williams Mike Williamson Consumers Energy Palisades MOV Team Leader 27780 Blue Star-Highway Diablo Canyon Power Plant Covert, MI 49043 Pacific Gas & Electric Company P.O. Box 56 i_
Avila Beach, CA 93424 4-805/545-4628
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Roger Wink, IST Engineer Jeff Wright Union Electric Co.- Callaway P.O.
Supervisor - Design Eng l
Box 620 Grand Gulf Nuclear Station Fulton, MO 65251 Entergy Operations, Inc.
i 573/676-8498 P.O. Box 756 Port Gibson, MS 39150 l
601/437-6229 Randy Womack Ken Worthington ENERTECH AEP/ Cook Nuclear Plant 89 North Road One Cook Place Waterford, CT 06835 Bridgman, MI 49106 e-mail WOMACK,RL9ASME.0RG Ralph Yeardley Don Zebrauskas Engineer Comed Wyle Labs Braidwood Station P O Box 07-7777 RR1 Box 84 Huntsville, AL 35807-7777 Braceville, IL 60407 NRC Particioants Headauarters Reaion III Zena Abdullahi Andy Dunlop Joseph Colaccino Wayne Kropp Ken Dempsey Melvyne Leach Gary Hammer David Roth John Huang Son Ninh Joel Page Thomas Scarbrough Richard Wessman Reaion I REGION IV Doug Dempsey Lee Ellershaw Harold Gray Dale Powers Gene Kelly Charles Paulk Thomas Kenny John Whittemore Ken Kolaczyk Bill McNeill Cliff Clark Reaion II H. Christensen James L. Coley, Jr.
Billy R. Crowley Ed Girard Edwin Lea i
Norman Merriweather Marvin Sykes l
McKenzie Thomas Al-9 l
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TABLE OF CONTENTS t
HANDOUTS / SLIDES Eggg Individual Regional Agendas......................
A2-2 l-Inspection Procedure 73756
" Inservice' Testing of Pumps and Valves" Slides
.............................. A2-6 Handouts
.,........................... A2-28 Revisions to ASME Operation and Maintenance (DM) Code that Address l
NRC Positions in Generic Letter 89-04 and its Supplement A2-38 i-"
Use of ' Pump Analyses for Alert & Required Action Ranges........ A2'-54 l
l l
Vibration Testing for Very Smooth Pumps................ A2-60 l~
Generic Letter 96-05 Periodic Verification of MOV Design-Basis j-Capability and ASME Code Case OMN-1................... A2-66
. Summary of Inspection Findings of Licensee Inservice Testing Programs r.
at United' States Commercial Nuclear Power Plants A2-76
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ATTACHMENT 2 A2-1
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l INSPECTION PROCEDURE 73756 REGION I AGENDA FEBRUARY 4, 1997 8:30 - 9:00 a.m.
Welcome and Introductions - James T. Wiggins, Division Director, Division of Reactor Safety (DRS), NRC Region I 9:00 - 9:20 a.m.
Elements of Inspection Procedure 73756, Inservice i
Testing (IST) Programs - Joseph Colaccino, Mechanical Engineering Branch (EMEB), NRC Office of Nuclear Reactor Regulation (NRR) 9:20 - 9:40 a.m.
Revisions to ASME Operation and Maintenance (OH) Code That Address hRC Positions in Generic Letter 89-04 and its Supplement - Adele DiBiasio, Brookhaven National' Laboratory 9:40 - 10:00 a.m.
Use of Analysis to Evaluate Pumps in Alert and Required-Action Ranges _ - Joel Page, NRC Office of Nuclear Regulatory Research (RES) l 10:00 - 10:15 a.m.
Break 10:15 - 10:30 a.m.
Presentation on GL 96-05 (Periodic Verification of Motor-0perated Valves) and OM Code Case OMN-1 as Alternative to Stroke-Time Testing of MOVs - Richard H. Wessman, Chief, EMEB, NRR 10:30 - 11:00 a.m.
Presentation on Findings from Recent IST Inspections -
J. Colaccino, EMEB, NRR, and Douglas Dempsey, DRS, NRC Region 1 11:00 a.m. - 12 Noon Question and Answer Breakout Session Noon - 1:30 p.m.
Lunch 1:30 - 3:00 p.m.
Question and Answer Panel Session 3:00 - 3:15 p.m.
Break 3:15 - 5:00 p.m.
Question and Answer Panel Session (continued) l l
A2-2 l
PUBLIC WORKSHOP ON INSERVICE TESTING INSPECTION PROCEDURE 73756 I
REGION II l
February 6, 1997
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8:30 - 9:00 a.m.
Welcome and Introductions - Ellis W. Merschoff, Acting i
Deputy Regional Administrator, NRC Region Il 9:00 - 9:20 a.m.
Elements of Inspection Procedure 73756, Inservice Testing (IST) Programs - Joseph Colaccino, Mechanical Engineering Branch (EMEB), NRC Office of Nuclear Reactor Regulation (NRR)
'9:20 - 9:40 a.m.
Revisions to ASME Operation and Maintenance (0M) Code That Address NRC Positions in Generic Letter 89-04 and its Supplement - Adele DiPiasio, Brookhaven National Laboratory 9:40 - 10:00 a.m.
Use of Analysis to Evaluate Pumps in Alert and Required Action Ranges - Joel Page, NRC Office of Nuclear Regulatory Research (RES) 10:00 - 10:15 a.m.
Break l
10:15 - 10:30 a.m.
Presentation on GL 96-05 (Periodic Verification of Motor-0perated Valves) and OM Code Case OMN-1 as Alternative to Stroke-Time Testing of MOVs -
i
. Thomas Scarbrough, Acting Chief of Cobiponents and Testing-Section, EMEB, NRR 10:30 - 11:00 a.m.-
Presentation on Findings from Recent IST Inspections -
J. Colaccino, EMEB, NRR, and Rudolph H. Bernhard, DRS, NRC Region II 11:00 a.m. - 12 Noon Question and Answer Breakout Session Noon - 1:30 p.m.
Lunch 1:00 - 3:00 p.m.
Question and Answer Panel Session 3:00 - 3:15 p.m.
Break 3:15 - 5:00 p.m.
Question and Answer Panel Session (continued) i J
f i
A2-3
PUBLIC WORKSHOP DN INSERVICE TESTING INSPECTION PROCEDURE 73756 REGION III JANUARY 21, 1997 8:30 - 9:00 a.m.
Welcome and Introductions - Melvyn Leach, Acting Deputy Division Director, Division of Reactor Safety (DRS), NRC Region III 9:00 - 9:20 a.m.
Elements of Inspection Procedure 73756, Inservice Testing (IST) Programs - Joseph Colaccino, Mechanical Engineering Branch (EMEB), NRC Office of Nuclear Reactor Regulation (NRR) 9:20 - 9:40 a.m.
Revisions to ASME Operation and Maintenance (OH) Code That Address NRC Positions in Generic Letter 89-04 and its Supplement - Adele DiBiasio, Brookhaven National Laboratory 9:40 - 10:00 a.m.
Use of Analysis to Evaluate Pumps in Alert and Required Action Ranges - Joel Page, NRC Office of Nuclear Regulatory Research (RES) 10:00 - 10:15 a.m.
Break 10:15 - 10:30 a.m.
Presentation on GL 96-05 (Periodic Verification of Motor-0perated Valves) and OM Code Case OMN-1 as Alternative to Stroke-Time Testing of MOVs -
Thomas Scarbrough, Acting Chief of Components and Testing Section, EMEB, NRR 10:30 - 11:00 a.m.
Presentation on Findings from Recent IST Inspections -
J. Colaccino, EMEB, NRR, and Andrew Dunlop, DRS, NRC Region III 11:00 a.m. - 12 Noon question and Answer Breakout Session Noon - 1:00 p.m.
Lunch 1:00 - 3:00 p.m.
Question and Answer Panel Session 3:00 - 3:15 p.m.,
Break 3:15 - 5:00 p.m.
Question and Answer Panel Session (continued)
A2-4 1
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I PUBLIC WORKSHOP ON INSERVICE TESTING INSPECTION PROCEDURE 73756 l
REGION IV JANUARY 23, 1997 8:30 - 9:00 a.m.
Welcome and Introductions - Thomas P. Gwynn, Division Director, Division of Reactor Safety (DRS), NRC Region l
IV l
9:00 - 9:20 a.m.
Elements of Inspection Procedure 73756, Inservice Testing (IST) Programs - Joseph Colaccino, Mechanical Engineering Branch (EMEB), NRC Office of Nuclear Reactor Regulation (NRR) 9:20 - 9:40 a.m.
Revisions to ASME Operation and Maintenance (OH) Code That Address NRC Positions in Generic Letter 89-04 and its Supplement - Adele DiBiasio, Brookhaven National Laboratory 9:40 - 10:00 a.m.
Use of Analysis to Evaluate Pumps in Alert and l
Required Action Ganges - Joel Page, NRC Office of Nuclear Regulatory Research (RES) 10:00 - 10:15 a.m.
Break L
10:15 - 10:30 a.m.
Presentation on GL 96-05 (Periodic Verification of l
Motor-Operated Valves) and OM Code Case OMN-1 as Alternative to Stroke-Time Testing of MOVs -
Thomas Scarbrough, Acting Chief of Components and Testing Section, EMEB, NRR i
10:30 - 11:00 a.m.
Presentation on Findings from Recent IST Inspections -
J. Colaccino, EMEB, NRR, and Lee Ellershaw, DRS, NRC Region IV 11:00 a.m. - 12 Noon Question and Answer Breakout Session Noon - 1:00 p.m.
Lunch 1:00 - 3:00 p.m.
Question and Answer Panel Session 3:00 - 3:15 p.m.
Break 3:15 - 5:00 p.m.
Question and Answer Panel Session (continued)
L A2-5 l
I l
Inspection Procedure 73756 "Inservice Testing of Pumps and Valves" Workshop Slides January and February 1997 Joseph Colaccino Mechanical Engineering Branch Office of Nuclear Reactor Regulation U.S. Nuclear Regulatory Commission I
A2-6 4
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Background===
- IP 73756: IST of Pumps and Valves. Previously revised March 16,1987 i
- TI 2515/114: Inspection Requirements for GL 89-04,
{
Acceptable IST Programs. Issued January 15, 1992
- TI 2515/110: Performance of Safety-Related Check Valves.
j Issued November 19,1991 l
- Bulletin 88-04: Potential Safety-Related Pump Loss.
Issued May 5,1988
- NUREG-1482, Guidelines for IST at Nuclear Power Plants, i
Issued April 1995 (GL 89-04)
- Revised Version of IP 73756 issued July 27,1995 l
A2-7 i
m
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Insnection Requirement 02.01 - Verify that the licensee has assigned responsibilities to persons and organizations for various programmatic aspects of inservice testing.
Determine ownership of program Inspection Requirement 02.02 - Select sample systems to review.
i Systems chosen generally based on:
-system risk
-previously identified programmatic weakness
-system maintenance
-testing activities i
Lessons learned from inspection expected to be applied to entire program A2-8
Insnection Requirement 02.03 - General IST program review.
- (a) Verify that the pumps and valves that perform a safety-related function (s) in the selected systems are in the IST program.
Licensees determine plant program scope IST scope evaluation performed using:
-P& ids
-technical specifications
-plant safety analysis report
-design basis documentation IST Program Scope: NUREG-1482, Section 2.2
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Typical IST Components: NUREG-1482, Tables 2.1-2 IST Bases Document: NUREG-1482, Section l
A2-9 s.
2.4.4 Inspection-Requirement 02.03 -;(Continued)
(b) Verify. test performed for-the pumps and valves in 02.03(a) meets the Code test method and frequency requirements, except where NRC has granted relief or approved alternatives.
Categorization Safety function Frequency L
Test method h
A2-10
1 Insnection Requirement 02.03 - (Continued) f (c) Verify that requests for relief or approval for alternative l
testing have been submitted to the NRC. When the requests are l
not based on an impractical condition, verify that the alternative is not implemented in lieu of the Code requirements prior to NRC l
approval.
l NRC approval needed for proposed alternatives i
(d) Review the basis for requests for relief and alternatives and assess the adequacy of the implementation of the alternative testing.
NUREG-1482, Section 2.5 NUREG/CR-6396: Examples, Clarifications, and Guidance j
on Preparing Requests for Relief from Pump and Valve IST Requirements.
j A2-11 l
-e-Insnection Requirement 02.03 - (Continued)
(e) Review the justification for deferring testing to cold shutdowns
~
or refueling outages.
Clearly state reason for deferral Partial-stroke exercising for check valves NUREG-1482, Section 2.,4.4 f
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A2-12 i
i
t Inspection Requirement 02.03 - (Continued) 1 (f) Review administrative controls for tracking tests performed f
quarterly, or a cold shutdown frequency, or during refueling t
outages.
. Scheduling of cold shutdown testing i
NUREG-1482, Section 3.1.3 i
1 A2-13 i
Inspection-Requirement 02.03 - (Continued) f (g) Review the test plan, implementing procedures, or test records i
to ensure reference values and acceptance criteria are identified and l
are in accord with Code limits.
l Reference values Check valve acceptance criteria l
4 i
i A2-14
1 Inspection Requirement 02.03 - (Continued) t (h) Review program controls and IST procedures for reverifying or establishing reference values after component maintenance, replacement, or modification, and (i) Review controls for post-maintenance testing to ensure that a component is tested prior to its j
return to service.
t i
Procedures to perform post-maintenance testing i
(j) Review evaluation process for instruments found out-oi-calibration to determine the effect on previous test results.
~
Corrective action requirements of 10 CFR 50 App. B i
Questionable tests re-performed as soon as practical Operability determination using guidance of GL 91-18 l
(NUREG-1482, Section 7.1) t i
I A2-15 i
f
L Insnection Requirement:02.04 - Review ongoing testing activities, if any,
. for components in the selected systems.-
a (a) Observe and evaluate any testing conducted for pumps and valves in the IST program, especially in the selected systems.
1 Vibration probe locations j
Attainability of pump fixed reference valves l
t (b) Verify the instruments used for:the test meet the code-specified j
range and calibration accuracies and that the calibration is current.
NUREG-1482, Section 5.5 a
I A2-16 j
g
' Inspection Requirement 02.05 - Evaluate test results for,a sample of pumps and valves in the selected system, with a minimum of four pumps and-six valves.
(a) Review at least one fuel cycle of test data for selected pumps and valves.
(b) Ensure that the code-specified corrective actions were taken for any test results in the " Alert Range" or " Required Action Range" or where acceptance criteria were otherwise exceeded.
Verify test frequency Component in alert or required action range A2-17
Insnection Requirement 02.05 - (Continued)
(c) Verify compliance with applicabie technical specification ACTION statements and applicable reporting requirements when components are declared inoperable as a result of IST.
Declare a component inoperable when it enters the required action range i
i A2-18
Insnection Requirement 02.05 - (Continued)
.(d) Review method of test data comparison to previous tests and actions taken on components indicating a degrading condition or a repetitive problem.
Monitoring.for degradation by trending (e) Review the documented results of engineering evaluations performed for inoperable components for a minimum of two fuel cycles, particularly root cause analysis of the problem and the bases for returning the components to operable status.
Technicaljustification included in engineering evaluations Generic implications.
l A2-19
i Inspection Requirement 02.05 - (Continued) j i
(f) Review administrative controls for design modifications or replacement of safety-related pumps to ensure IST is identified, where appropriate.
j Consider system design basis and required. Code testing-Post-modification or -maintenance testing i
Establishment or reconfirmation of reference values 1
(g) Verify completed test documents require appropriate review and are maintained as quality controlled records.
l i
Appropriate supervisory review i
I l
1 A2-20 l
l
Insnection Requirement 02.06 - Valve testing. Evaluate a sample cf valves in the selected systems.
l (a) Evaluate the test method, acceptance criteria (including the limiting value for stroke time), and corrective action for stroke i
timing power-operated valves in the test procedures.
t Test methods l
-position indicating lights
-stem travel
-diagnostics Acceptance criteria
-multipliers (pre-1989 ASME Section XI)
-reference values (OM-10)
Method of establishing acceptance criteria j
Accessibility of acceptance criteria j
i A2-21
Inspection Requirement 02.06 - (Continued)
(b) Verify that valves with remote position indications, including passive and manual valves, are subject to position indication verification once every two years in accord with the Code requirements.
OM-10 requires position indication of passive and manual j
valves, where provided j
i NUREG-1482, Sections 4.2.5 and 6 (c) Evaluate leak rate testing of Category A valves.
i PIVs are generally individually monitored l
NUREG-1482, Sections 4.4.5, 4.4.7 and 8 I
A2-22 I
i f
l Insnection Requirement 02.06 - (Continued)
(d) Evaluate the adequacy of check valve testing, including disassembly and inspection where applicable.
t If applying GL 89-04 Position 2, use design basis flow for forward flow testing Adequate check valve acceptance criteria l
Accuracy requirements not as stringent as for pumps l
(e) Verify that manual valves in the program are periodically exercised in accord with the Code requirements.
Manual valves with a safety function are within the scope of the IST program t
NUREG-1482, Section 4.4.6 A2-23
i Inspection Requirement 02.06 - (Continued) i (f) Review the set pressure testing for safety and relief valves.
j 1986 Edition of ASME Section XI enlarges scope of relief valves Correlation for valves tested at low temperatures but designed for elevated temperatures i
NUREG-1482, Section 4.3 (g) Review the adequacy of non-reclosing pressure relief device j
(rupture disc) testing and replacement.
j I
t A2-24 i
(
Insnection Requirement 02.07 - Pump testing. Evaluate the fellswing.
l areas for. testing of a sample. of-pumps in the selected systems.
(a) Review pump testing methods, acceptance criteria, and corrective actica in the test procedures.
t Establishing pump fixed reference values l
Appropriate corrective action requirements l
l j
t A2-25 l
Insnection Requirement 02.07
-(Continued)
(b) Review pump testing for the selected systems in cases where minimum-flow recirculation flow paths are used during testing to ensure conformance with guidance in GL 89-04, Position 9.
Full or substantial flow testing at cold shutdowns or refueling outages Evaluate resolution of long-term actions sp.ecified in GL 88-l 04 submittals against current system configurations l
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A2-26 l
t
i Inspection Requirement 02.07 - (Continued) l(c) Verify the ranges and calibration accuracies of test instruments meet Code requirements.-
i (d) Verify that pumps are declared inoperable in completed test j
procedures when test results are in the " Required Action Range" or i
that the test frequency-is doubled when the test results are in the t
" Alert Range."
l 3
(e) Ensure that testing is performed at established reference values.
l Pump reference curves 1
l i
A2-27
l 1
l i-Inspection Procedure 73756 Handouts
" Inservice Testing of Pumps and Valves" i
J i
Workshops 4
January and February 1997 i
i U.S. Nuclear Regulatory Commission l
Office of Nuclear Reactor Regulation Division of Engineering Mechanical Engineering Branch 3
e A2-28
Inspection Requirement 02.01 - Verify that the licensee has assigned responsibilities to persons and organizations for various programmatic aspects of inservice testing.
Purpose of Requirement:
In the past, the NRC has identified that licensees often have the responsibilities for inservice testing (IST) spread over several organizations. At some plants, there was not an individual designated as the "IST Coordinator" and no one had the ownership of the program.
This resulted in certain elements of the program being missed.
The purpose of inspecting the responsibilities is to ensure that there is, at a minimum, someone assigned to implement all aspects of the program, with the appropriate level of knowledge of the ASME Code and regulatory requirements and how these are implemented.
Inspection Requirement 02.02 - Select sample systems to review.
Purpose of Requirement: Because the inspections are limited in time, a few systems are selected to focus the review.
If problems are identified in the selected systems, the NRC would expect that licensees, in addressing the inspection findings, would expand the review to the remaining systems to ensure that any problems affecting other systems are corrected.
General IST program review. (a) Verify that the pumps and valves that perform a safety-related function (s) in the selected systems are in the IST program.
Purpose of Requirement:
Because the NRC does not review the entire scope of the IST program when licensees submit program updates, it is important to inspect a few systems for completeness of-the scope. The scope of the selected systems is verified against plant drawings, the safety analysis report, and the technical specifications using NRC guidance.
Inspection Requirement 02.03 - General IST program review.
(b) Verify test performed for the pumps and valves is 02.03(a) meet the Code test method and frequency requirements, except where NRC has granted relief or approved alternatives.
Purpose of Requirement: The review of application and implementation of the ASME Code requirements for the types of testing applicable to each component and the frequency for each of the tests is performed for the selected systems to ensure that the licensee is correctly interpreting the ASME Code requirements.
Where Code requirements cannot be met, or where alternatives have been implemented, the inspector verifies that relief has been granted or an alternative has been approved.
A2-29
Inspection Requirement 02.03 - General IST program review. (c) Verify that requests for relief or approval for alternative testing have been submitted to the NRC. When the requests are not based on an impractical condition, verify that the alternative is not implemented in lieu of the code requirements prior to NRC approval.
Purpose of Requirement: Where testing is impractical, there is a condition which precludes meeting the Code requirements, and licensees have no choice but to implement an alternative while seeking a relief request from the NRC. However, where testing is practical, but the licensee desires to perform testing in a different manner or at a different frequency, an alternative must be approved prior to implementation.
Inspection Requirement 02.03 - Inspection Requirement 02.03 - General IST program review. (d) Review the basis for requests for relief and alternatives and assess the adequacy of the implementation of the alternative testinq.
Purpose of Requirement: When the NRC grants relief or approves alternatives, the staff relies on statements mada by licensees in their submittals.
The accuracy of this information is verified during an inspection. Also, it is important to verify that the implementation of the alternative is in accord with the proposal, with any additional provisions, as approved by the NRC.
Inspection Requirement 02.03 - General IST program review.
(e) Review the justification for deferring testing to cold shutdowns or refueling outages.
Purpose of Requirement:
Because the NRC does not evaluate test deferrals which are allowed by the Code (though in some SEs the NRC will comment on the test deferrals), inspection of the justification is necessary to ensure its adequacy and correctness.
In the past, inspections have uncovered test deferrals that were not justified because testing actually could be performed at power operating conditions, or in some cases, during cold shutdowns.
Inspection Requirement 02.03 - General IST program review.
(f) Review administrative controls for tracking tests performed quarterly, or a cold shutdown frequency, or during refueling outages.
Purpose of Requirement:
License Event Reports are often submitted because an inservice test was missed or performed after the test interval has been exceeded (even with app'lication of the 25%
extension allowed by plant technical specifications).
Scheduling is a major element of the IST program and can result in a failure to comply with technical specifications if not adequate.
The inspection is also important to ensure that the method of scheduling deferred testing is adequate to ensure that testing is initiated and completed, as appropriate, during cold shutdowns and refueling outages.
Inspectors will also check the adequacy of actions taken when missed tests are identified.
A2-30 n
- - - = -.
i Inspection Requirement 02.03 - General IST program review.
(g) Review the test plan, implementing procedures, or test records to ensure reference values and acceptance criteria are identified and are in accord with Code limits.
Purpose of Requirement: The establishment and documenting of reference values is important to ensure that acceptance criteria are proper.
lhe method for ensuring that the reference values are updated when appropriate is important to ensure that a component is not " accepted" when the test data would indicate otherwise, i
When the acceptance criteria are not readily apparent to the individuals performing testing, a component that has failed the acceptance criteria may be considered operable until some later review of test data is brought to the attention of the operators.
Acceptance criteria must be at the limits given in the ASME Code.
Inspection Require, ment 02.03 - General IST program review.
(h) Review program controls and IST procedures for reverifying or establishing reference values after component maintenance, replacement, or modification, and (i) Review controls for post-maintenance testing to ensure that a component is tested prior to its return to service.
Purpose of Requirement: The Code includes certain requirements for testing following maintenance, replacement, or modification i
that must be part of an administrative control on the components in the IST program.
Past inspections have identified that licensees may not have adequate controls to ensure that a component is not put into service until post-maintenance, post-l l
replacement, or post-modification testing is complete.
Generally, a step in the maintenance, replacement, or modification package should require inservice testing, with a notation to establish or reverify reference values.
Inspection Requirement 02.03 - General IST program review.
(j) Review evaluation process for instruments found out-of-calibration to determine the affect on previous test results.
Purpose of Requirement:
The NRC expects that licensees, as part of their corrective action requirements under Appendix B to 10 CFR 50, would review the previous tests which used the instrument since its most recent calibration. Where testing is suspect, or where the date the instrument went out of calibration indicates it was not calibrated properly during testing, the testing should be re-performed as soon as practical. Where testing cannot be perfr.rmed during the current plant mode, an operability determination following the guidance of Generic Letter 91-18 shoubt be completed for the noncompliance.
A2-31
_ _ ~ _.. _ __ _ _ _ _.. _ __. _.. _. _. _ _
Inspection Requirement 02.04 - Review ongoing testing activities, if any, for components in the selected systems.
(a) Observe and e uluate any testing conducted for pumps and valves in the IST program, especially in the selected systems.
Purpose of Requirement:
By observing ongoing testing, inspectors have a chance to assess whether the implementation of the Code requirements is adequate and understood by those performing the testing.
Inspection Requirement 02.04 - Review ongoing testing activities, if any, for components in the selected systems.
(b) Verify the instruments used for the test meet the code-specified range and calibration accuracies and that the calibration is current.
Purpose of Requirement:
In past inspectioris, the NRC identified that certain instruments used for IST did not meet the range and accuracy requirements of the Code. Observation and a review of the testing being performed during the inspection presents an opportunity to verify the adequacy of one or more examples of-testing.
If problems are identified, the licensee can review other testing for similar problems.
Inspection Requirement 02.05 - Evaluate test results for a sample of pumps and valves in the selected system, with a minimum of four pumps and six valves.
(a) Review at least one fuel cycle of test data for selected pumps and valves.
' Purpose of Requirement: The data samples for one cycle of operation will provide a " snapshot" view of test results and the adequacy of the licensee's actions related to test data.
If problems are identified, the licensee can review other components for similar problems.
Inspection Requirement 02.05 - Evaluate test results for a sample of pumps and valves iii the selected system, with a minimum of four pumps and six valves.
(b) Ensure that the code-specified corrective actions were taken for any test results in the " Alert Range" or " Required Action Range" or where acceptance criteria were otherwise exceeded.
Purpose of Requirement:
In past inspections, the NRC has found instances of pump test data being in the " alert range" without proper action taken by the licensee.
In other instances, the pump or valve may not have been declared inoperable even when action limits were reached. The examples indicate that there were problems in the clarity of the alert values or required action limits that were generic to all of the implementing procedures or.
to the manner in which these values and limits were documented.
The NRC will inspect the procedures to ensure that the limits are obvious to the individual responsible for evaluating the results.
A2-32
Inspection Requirement 02.05 - Evaluate test results for a sample of pumps and valves in the selected system, with a minimum of four pumps and six valves.
(c) Verify compliance with applicable technical specification ACTION statements and applicable reporting requirements when components are declared inoperable as a result of IST.
Purpose of Requirement: The purpose of reviewing the actions taken when pumps or valves are declared inoperable it to ensure that code limits are treated as operability limits.
Even if the licensee ultimately dispositions the " failure" by performing an l
evaluation justifying continued operation of the compenent, the-licensee must go through the process and take appropriate actions until such an evaluation indicates a positive result.
Past inspections have identified that in certain instances, equipment that did not meet the Code limits as defined in the licensee's procedures was allowed to remain operable for long periods of time while evaluations were ongoing.
Inspection Requirement 02.05 - Evaluate test results for a sample of pumps and valves in the selected system, with a minimum of four pumps and six valves.
(d) Review mdhod of test data comparison to previous tests and actions taken a components indicating a degrading condition or a repetitive problem.
Purpose of Requirement:
It is important to assess the licensee's i
process for comparison of test data to previous data and whether trending is being performed. One purpose of IST is to monitor for degradation.
Repetitive problems, though possibly not a degrading issue, may indicate that corrective actions to correct a potential operability problem should be taken rather than allowing the problem to continue. Appendix B of 10 CFR 50 includes requirements for corrective actions in addition to those in the Code.
Inspection Requirement 02.05 - Evaluate test results for a sample of pumps and valves in the selected system, with a minimum of four pumps and six valves.
(e) Review the documented results of engineering evaluations performed for inoperable components for a minimum of two fuel cycles, particularly root cause analysis of the problem and the vases for returning the components to operable status.
Purpose of Requirement:
Because engineering evaluations are often subjective, depending on the circumstances, any time a component is returned to an operable state based on an engineering evaluation, it warrants review by the NRC inspectors to ensure that the licensee is thorough and concise.
Such evaluations should not be used to avoid taking corrective actions that are clearly needed and should not be used when the plant is in a mode that allows repair without extenuating circumstances.
Inspectors should ensure that the evaluation includes justification for operability at least to the next test.
A2-33
i l
Inspection Requirement 02.05 - Evaluate test'results' for a sample of pumps and valves in the selected system, with a minimum of four pumps and six valves.
(f) Review administrative controls for design modifications or replacement of safety-related pumps to ensure IST is identified, where appropriate.
Purpose of Requirement: This inspection element is to ensure that.
licensees.have included post-modification or post-replacement IST l
in the change process so that a component is subjected to IST prior to being placed.in service. New reference values should be established, or previous reference values reconfirmed.
Inspection Requirement 02.05 - Evaluate test results for a sample of pumps and valves in the selected system, with a minimum of four pumps and six valves.
(g) Verify completed test documents require appropriate review and are j
maintained as quality controlled records.
Purpose of Requirement:' The individual responsible for completing the testing should do an initial evaluation of the test results; howaver, the test documents should be reviewed by the appropriate parties to ensure agreement on the results.
Records must be maintained in accord with the regulations applicable to safety-t related records.
Inspection Requirement 02.06 - Valve testing.
Evaluate _ a sample of valves in the selected systems.
(a) Ev'aluate the test method, acceptance criteria (including the limiting value for stroke time), and corrective action for stroke timing power-operated valves in the test procedures.
Purpose of Requirement: Test methods include monitoring position indicating lights to diagnostic testing. The acceptance criteria for valves may be based on multipliers of reference values, limits in technical specification or safety analyses, or comparison other methods as allowed by relief requests when code requirements are impractical (e.g., power-operated valves with no position indication). The inspection will cover the licensee's method of l
establishing acceptance criteria, changing values and limits, and documentation of the test results.
Inspectors will verify that acceptance criteria and corrective actions are specified in the test procedures to ensure prompt o)erability determinations and initiation of corrective actions wien limits are exceeded.
A2-34
Inspection Requirement 02.06 (b) Verify that valves with remote position indications, including passive and manual valves, are subject to position indication verification once every two years in accord with the code requirements.
Purpose of Requirement:
Early Code editions did not clearly require position indication for passive valves (see Table IWV-3700-1); however, OH-10 clearly requires position indication of passive valves, where provided.
If an IST program has been updated to use OM-10, position indication verification is required for passive and manual valves that are designed with this feature.
Even if under an earlier Code edition which does not include this as an IST requirement, position indication that could be relied upon by an operator should be periodically verified. The NRC has identified that some licensees do not adequately maintain remote shutdown panels, and in certain instances for passive valves do not adequately maintain position indication in the control room.
Inspection Requirement 02.06 (c) Evaluate leak rate testing od Category A' valves.
]
Purpose of Requirement: The primary purpose of this inspection element is to ensure that valves are individually monitored except where only one of two in-series valves is relied upon in the safety analysis, and that pressure isolation valves are 1
individually monitored.
In past inspections, the NRC has identified that some valves were not adequately leak tested on an individual valve basis.
Inspection Requirement 02.06 (d) Evaluate the adequacy of check valve testing, including disassembly and inspection where applicable.
Purpose of Requirement: When using GL 89-04 positions, certain flow rates are required for forward flow testing, and manual stroking is required, if practical, when disassembly and
. inspection is performed.
The method and frequency of testing will be reviewed to ensure that all safety functions are verified (e.g., capability to open, close, and be leaktight).
Inspection Requirement 02.06 (e) Verify that manual valves in the program are periodically exercised in accord with the code requirements.
Purpose of Requirement:
Inspections have identified that not all Code Class.1, 2, and 3 manual valves that must be repositioned are included in the IST program and subject to periodic exercising.
The Code does not exclude these valves.
A2-35
Inspection Requirement 02.06 (f) Review the set pressure testing for safety and relief valves.
Purpose of Requirement: Testing is often performed off site and a thorough review of the test results, as well as meeting contractual requirements, is warranted.
For on site testing, test media are important. When testing is performed insitu, the test equipment must be qualified for safety-related testing.
Appropriate acceptance criteria must be established'so that an j
assessment of "as-found" conditions can be made. Additionally, the scope of the valves subject to set pressure testing was enlarged beginning with the 1986 Edition of the Code.
Inspection Requirement 02.06 (g) Review the adequacy of non-reclosing pressure relief device (rupture disc) testing and replacement.
Purpose of Requirement: The code includes periodic replacement l
and past inspections have indicated that these devices are not always replaced on schedule.
Inspection Requirement 02.07 - Pump testing.
Evaluate the following areas for testing of a sample of pumps in the selected systems.
(a) Review pump testing methods, acceptance criteria, and corrective action in the test procedures.
l Purpose of Requirement: The purpose of this inspection element is to assess compliance with the Code requirements and to assure that relief is requested where the Code requirements are impractical.
Inspection Requirement 02.07 (b) Review pump testing for the selected systems in cases where minimum-flow recirculation flow paths are used during testing to ensure testing conforms with guidance in GL 89-04, Position 9.
Purpose of Requirement:
Prior to Position 9, certain testing was performed on minimum recirculation flow using flowpaths without flow instrumentation.
If a licensee continues to use the flowpaths for quarterly testing, a test through an instrumented line must be performed during plant shutdowns or the testing is l
considered not in compliance with the Code.
Inspection Requirement 02.07 (c) Verify the ranges and calibration accuracies of test instruments meet code requirements.
Purpose of Requirement:
Past inspections have indicated that range and accuracy requirements are not always met with installed instrumentation. When this is the case, temporary instruments may be used for IST, or relief must be sought to use the installed instruments.
i 2
A2-36
l Inspection Requirement 02.07 (d) Verify that pumps are declared inoperable in completed test procedures when test results are in the " Required Action Range" or that the test frequency is doubled when the test results are in the " Alert Range."
Purpose of Requirement:
Past inspections have indicated that if the limits are not properly included in test procedures, l
inoperable components may not be declared inoperable in a timely manner. Another problem that has been identified is that scheduling is often not notified when the test data is in the
" alert range" and the more frequent testing is not, then, scheduled.
Inspection Requirement 02.07 (e) Ensure that testing is performed at established reference values.
Purpose of Requirement: The Code is-very specific on setting a reference value and measuring the other parameter (flow, differential pressure). Testing at any point on the pump curve is not in accord with the Code and a relief request is required when it is impractical to set one of the parameters and measure the j
other.
i A2-37 l
i
t REVISIONS TO ASME OPERATION AND t
MAINTENANCE (OM) CODE THAT ADDRESS NRC POSITIONS IN GENERIC LETTER 89-04 l
AND ITS SUPPLEMENT l
Presented by:
Adele DiBiasio i
Engineering Technology Division l
Department of Advanced Technology Brookhaven National Laboratory Presented at:
~
NRC Inservice Testing lnspection Procedure 73756 Workshops f%
(!!!!!J i
l A2-38
t SKID-MOUNTED COMPONENTS AND COMPONENT SUBASSEMBLIES (NUREG-1482, SECTION 3.4)
Skid-mounted components and component subassemblies are excluded in ISTB 1.2 and ISTC 1.2 of the 1996 Addenda of the OM Code provided that they are tested as j
part of the major component and are determined by the l
Owner to be adequately tested.
l L
Skid-mounted components are defined as:
l
" Components integral to or that support operation of major components, even though these components may not be located directly on the skid.
In general, these components are supplied by the manufacturer of the major component.
Examples include: diesel skid-mounted fuel oil pumps and valves, steam admission i
and trip throttle valves for high-pressure coolant injection or auxiliary feedwater turbine-driven pumps, and solenoid-operated valves provided to control the air-operated valve." (ISTA 1.7)
A2-39 l
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1 CRITERIA FOR SELECTING PUMPS AND.
1 VALVES FOR THE IST PROGRAM (NUREG-1482, Section '2.2) t l
i The 1996 Addenda revised the applicability statements (ISTB 1.1 and i
ISTC 1.1) to require testing of components required to achieve and maintain safe shutdown, instead of cold shutdown.
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A2-40 l
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CLOSURE VERIFICATION FOR SERIES CHECK VALVES WITHOUT INTERMEDIATE TEST CONNECTIONS (NUREG-1482, SECTION 4.1.1)
Paragraph ISTC 4.5.7, Series Valve Pairs, was added to the 1996 Addenda-I "If two check valves are in a series configuration without provisions j
to verify individual reverse flow closure (e.g., keepfill pressurization j
valves) and the plant safety analysis assumes closure of either valve (but not both), the valve pair may be operationally tested closed as a l
unit.
if the plant safety analysis assumes that a specific valve or both valves l
of the pair close to perform the safety function (s), the required valve (s)
{
shall be tested to demonstrate individual valve closure."
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A2-41 i
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l EXERCISING' CHECK VALVES WITH FLOW AND NON-INTRUSIVE TECHNIQUES (NUREG-1482, SECTION 4.1.2)
I i
The 1996 Addenda explicitly identified. in ISTC 4.5.4(3) that non-intrusive testing was an "other positive means" and added to ISTC 2,.
Owner's Responsibility:" The Owner shall ensure that the application, j
method, and capability of each nonintrusive technique is qualified."
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A2-42 I
MEASUREMENT OF VALVE STROKE TIME i
.(NUREG-1482, SECTION 4.2.3)
J t
i The ASME issued with the 1996 Addenda, Code Case OMN-1,
" Alternate Rules for Preservice and inservice Testing of Certain Electric Motor-Operated Valve Assemblies in Light-Water Reactor Power l
Plants."
This code case allows the use.of static or dynamic l
performance testing on an extended frequency in lieu of quarterly stroke timing.
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A2-43 l
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h
CONTROL VALVES WITH A SAFETY FUNCTION i
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(NUREG-1482, SECTION 4.2.9) l r
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b The Code Committees are currently working on a change to delete the j
stroke timing requirements for control valves that only have a fail-safe l
safety function.
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A2-44
1 r
i FREQUENCY AND METHOD OF TESTING ADS VALVES IN BWRS (NUREG-1482, SECTION 4.3.4)
The 1996 Addenda in ISTC 1.2 excludes Category A and B safety and relief valves from the requirements of ISTC 4.1, Valve Position Verification, and ISTC 4.2, inservice Exercising Test.
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A2-45
VACUUM RELIEF VALVES (NUREG-1482, SECTION 4.3.8)
The Code Committees are currently attempting to clarify the requirements for check valves that operate as vacuum relief valves.
The committee has proposed that if the valve is capacity certified, then it shall be tested in acco~rdance with Appendix-1, otherwise, it shall be tested in accordance with ISTC 4.5.
Additionally the committee has proposed clarifying that Class 2 and 3 vacuum relief valves be tested every 2 years.
A2-46
MANUAL VALVES (NUREG-1482, SECTION 4.4.6)
The Code Committees are pursuing a revision that explicitly addresses manual valves and allows them. to be tested once every 5 years, except where adverse conditions may require more frequent testing.
l A2-47
l CIVS WHICH HAVE OTHER LEAK-TIGHT SAFETY
[
FUNCTION (S) CNUREG-1482, SECTION 4.4.8)
The 1996 Addenda includes clarification in ISTC 4.3.2, that if a CIV l
has a leakage requirement based on other functions it shall be tested in accordance with ISTC 4.3.2 and 4.3.3.
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1 A2-48 l
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t USE OF VARIABLE REFERENCE VALUES FOR FLOW l
RATE AND DIFFERENTIAL PRESSURE DURING PUMP TESTING (NUREG-1482, SECTION 5.2)
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1 The 1994 Addenda allows the use of pump curves. This change was part of a major revision to require a comprehensive pump test j
biennially.
I A2-49 l
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USE OF TANK OR BAY LEVEL TO CALCULATE DIFFERENTIAL PRESSURE (NUREG-1482, SECTION 5.5.3) i The 1994 Addenda in ISTB 4.7.1 (a) clarified-that parameters determined by analytical methods shall meet the accuracy requirements of l
Table 4.7.1-1.
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A2-50 l
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OPERABILITY LIMITS OF PUMPS (NUREG-1482, SECTION 5.6) l I
The 1994 Addenda (ISTB 4.6) allows the establishment of a new set of reference valves when the pump is in the alert or required action l
range, but whose continued operation at the new valves is supported by analysis.
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i A2-51
FULL-FLOW TESTING OF CHECK VALVES (GENERIC. LETTER 89-04, POSITION 1 & 2D i
l The 1994 Addenda allows a sample disassembly.and inspection program as an alternate to exercising check valves. The Code allows a 8 year interval, l
however, it does not include provisions to extend the interval past 8 years or to forego disassembling valves at each refueling outage. Position 2 allows up to a 6 year interval and allows an extension in cases of " extreme hardsifg."
i The 1996 Addenda now require exercising check valves in both directions (ISTC 4.5.4). The test is performed when its practical to perform both tests and for valves with a open safety function, only a full-stroke is required.
If Position 2 is utilized, a partial stroke quarterly or at cold shutdowns, if practical, is required.
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The condition monitoring revisions included in the 1996 Addenda de-emphasizes full flow exercising, which contradicts the guidance provided in Position 1.
l A2-52
PUMP TESTING USING MIMMUM-FLOW RETURlV LINES (GENERIC LETTER 89-04, POSITION 9)
Partially in response to the issue of potential pump damage caused by testing using the minimum flow line, the Code in the 1994 Addenda was revised to include the comprehensive pump test.
For standby pumps, only differential pressure or flow j
rate measurement is required quarterly, with a
more j
comprehensive test performed biennially. If Position 9 is used, quarterly measurement of differential pressure and vibration measurement is required.
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A2-53 4
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USE OF PUMP ANALYSES FOR 1
ALER1 & REQUIRED ACTION RANGES h
Workshops 1
January and February 1997 l
Joel Page Generic Safety Issues Branch Office of Research U.S. Nuclear Regulatory Commission i
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1 A2-54 i'
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USE OF PUMP ANALYSES FOR ALERT & REQUIRED ACTION RANGES i
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ISSUE DESCRIPTION I
BACKGROUND l
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i TECHNICAL ISSUES i
A2-55
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ISSUE DESCRIPTION A
i ANALYSIS ALLOWED BY SECTION XI i
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NOT ALLOWED BY-PRE-94 OM CODE IIYDRAULIC RANGE EXPANSION INTENTIONALLY DELETED MUST FIND CAUSE & CORRECT i
A2-56
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i BACKGROUND i
1 ASME/NRC MEETING IN LATE 80s EXPANDED RANGE CONCERN j
OM TASK GROUP FORMED 4
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NON-MANDATORY APPENDIX WORK DISCONTINUED i
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CODE CASE INITIATED IN 1993 REJECTED BY UPPER COMMirrEE NOT NEEDED OT11ER OPTIONS GL 91-18 i
i A2-57 i
4 TECHNICAL ISSUES TIME ALLOWED FOR ANALYSIS i
ALL RELATED REQUIREMENTS t
MORE DATA-IN 94/95 CODES l
1 COMPREHENSIVE TEST MORE VIBRATION DATA POTENTIAL STAIRSTEPPING l
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'I A2-58 i
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TECHNICAL ISSUES (CONTINUED) 1 VARIABLE ANALYSIS TECHNIQUES EXCESSIVE JJANPOWER INDUSTRY & NRC COMPONENT & SYSTEM CONCERNS BULLETIN 88-04 L
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1 A2-59
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i VIBRATION TESTING l
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. FOR-l VERY. SMOOTH PUMPS i
Workshops
' January and February 1997
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i Joel Page i
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Generic Safety Issues Branch j
Office of Research U.S. Nuclear Regulatory Commission j
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VIBRATION TESTING l
FOR VERY SMOOTH PUMPS
-i ISSUE DESCRIPTION 1
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BACKGROUND i
TECHNICAL ISSUES I
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A2-61
ISSUE DESCRIPTION SECTION XI & OM BASED ON MULTIPLES OF REFERENCE VALUE
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- 2.5 X Vr: ALERT
- 6 X Vr:
REQUIRED ACTION l
SMALL CHANGES RESULT IN OVER-TEST / MAINTENANCE VARIATIONS MAY BE DUE TO INSTRUMENT / TEST VARIATIONS
- NOT. CHANGES IN MACHINE CONDITION f
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l A2-62
BACKGROUND
- RECEIVED BY OM 89/90
- TWO REQUESTORS (MAXWELL, VEPCO)
- ASSIGNED TO WG-P&V/TG-VIB TG/WG CONSENSUS ON MINIMUM REFERENCE APPROACH i
i
- VARIED OPINIONS ON SPECIFIC VALUE i
REJECTED BY UPPER COMMITTEE 9/94
- DIFFICULT TO UNDERSTAND
- CONCERNED ABOUT TG-VIB LACK OF CONSENSUS
- CONCERNED ABOUT PLANT PUMP FAILURE j
4 A2-63 l
1 BACKGROUND (CONTINUED) i
- RETURNED TO WG/TG 9/94
- TG/WG MADE INACTIVE 3/95 PRIORITIZATION" VOTE W/ OTHER ACTION ITEMS 1
- REACTIVATED 12/96 l
- SCCM INPUT REQUESTED (REQUESTOR)
- EVALUATE OTHER TECHNICAL APPROACHES i
f A2-64 I
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i MINIMUM REFERENCE APPROACH TECHNICAL ISSUES i
MANY CHOICES MINIMUM REFERENCE VALUES EVALUATED
- 0.02 INCHES PER SECOND (IPS)
MINIMUM INSTRUMENT READABILITY i
1
- 0.1 IPS i
ESSENTIALLY ABSOLUTE CRITERIA i
NRC APPROVED RELIEF REQUEST AT 0.05 IPS i
- PUMP FAILURE i
A2-65
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i GENERIC LETTER 96-05 PERIODIC VERIFICATION OF MOV DESIGN-BASIS CAPABILITY
.i AND ASME CODE CASE OMN-1 i
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Thomas G. Scarbrough j
Mechanical Engineering Branch Office of Nuclear Reactor Regulation l
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February 1997 l
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A2-66 f
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GENERIC LETTER 96-05 (SEPTEMBER 18,1996) l PURPOSE REQUESTS THAT LICENSEES ESTABLISH PROGRAM, OR ENSURE EFFECTIVENESS OF CURRENT PROGRAM, TO VERIFY ON PERIODIC BASIS THAT SAFETY-RELATED MOVs CONTINUE TO BE CAPABLE OF PERFORMING THEIR SAFETY FUNCTIONS WITHIN CURRENT LICENSING BASES OF THE FACILITY.
REQUIRED RESPONSE I
WITHIN 60 DAYS, SUBMIT RESPONSE INDICATING WHETHER REQUESTED ACTION WILL BE IMPLEMENTED OR ALTERNATIVE COURSE OF ACTION FOLLOWED. [ COMPLETED]
j WITHIN 180 DAYS (MARCH 17,1997) OR COMPLETION OF GL 89-10 (WHICHEVER IS LATER), SUBMIT
SUMMARY
DESCRIPTION OF MOV PERIODIC VERIFICATION PROGRAM IN i
ACCORDANCE WITH REQUESTED ACTIONS OR ALTERNATIVE COURSE OF ACTION.
.l INDUSTRY ACTIVITIES t
EPRI MOV PERFORMANCE PREDICTION PROGRAM l
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BWR OWNERS' GROUP MOV RANKING METHODOLOGY l
ASME CODE CASE OMN-1 A2-67
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GL 96-05 (CONTINUED) j ATTRIBUTES OF AN EFFECTIVE PROGRAM RISK INSIGHTS MAY SE USED TO PRIORITIZE VALVE TEST ACTIVITIES.
VALVE TESTING SHOULD PROVIDE ADEQUATE CONFIDENCE THAT SAFETY-RELATED MOVs WILL REMAIN OPERABLE UNTIL NEXT SCHEDULED TEST.
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lMPORTANCE OF VALVE SHOULD BE CONSIDERED IN DETERMINING APPROPRIATE MIX.
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OF EXERCISING AND DIAGNOSTIC TESTING. LICENSEE SHOULD CONSIDER BENEFITS AND POTENTIAL ADVERSE EFFECTS WHEN DETERMINING APPROPRIATE MOV TESTING.
ALL SAFETY-RELATED MOVs COVERED BY GL 89-10 SHOULD BE CONSIDERED IN i
DEVELOPING GL 96-05 PROGRAM. INCLUDE SAFETY-RELATED MOVs ASSUMED TO BE l
CAPABLE OF RETURNING TO THEIR SAFETY POSITION WHEN PLACED IN POSITION THAT PREVENTS TRAIN FROM PERFORMING iTS FUNCTION BUT NOT DECLARED INOPERABLE.
LICENSEES SHOULD EVALUATE AND MONITOR VALVE PERFORMANCE AND l
MAINTENANCE AND PERIODICALLY ADJUST PROGRAM, AS APPROPRIATE.
EXAMPLES OF PLANTS W!TH ACCEPTABLE PLANS FOR PERIODIC VERIFICATION PROGRAMS ARE CALLAWAY, MONTICELLO AND SOUTH TEXAS.
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A2-68 i
. _- -.- ~. -.. -.
r ASME CODE CASE OMN-1 ALTERNATIVE RULES FOR PRESERVICE AND INSERVICE TESTING I
OF CERTAIN ELECTRIC MOV ASSEMBLIES l
IN LWR POWER PLANTS i
LICENSEES BOUND BY CODE OF RECORD FOR STROKE-TIME TESTING REQUIREMENTS.
LICENSEES HAVE GL 89-10 COMMITMENTS FOR MOV TESTING.
OMN-1 ALLOWS REPLACEMENT OF STROKE-TIME TESTING WITH PERIODIC EXERCISING AND i
APPROPRIATE DIAGNOSTIC TESTING.
l METHOD DESCRIBED IN OMN-1 MEETS INTENT OF GL 96-05 WITH CERTAIN LIMITATIONS:
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(1) PRECAUTION ON BENEFITS AND POTENTIAL ADVERSE EFFECTS WHEN DETERMINING i
APPROPRIATE TESTING.
(2) WHERE APPLYING OMN-1 MAXIMUM TEST INTERVAL OF 10 YEARS, LICENSEE SHOULD EVALUATE INFORMATION DURING FIRST 5-YEAR (OR 3 RFO) INTERVAL TO l
VALIDATE ASSUMPTIONS.
l (3) LICENSEES INVOLVED WITH IST PROGRAMS EMPLOYING RISK INSIGHTS NEED TO ADDRESS RELATIONSHIP BETWEEN PILOT PROGRAM AND OMN-1.
l A2-69 l
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INQUIRY 1
WHAT ALTERNATIVE RULES, TO THOSE OF OM CODE, SUBSECTION ISTC, MAY BE USED FOR-PRESERVICE AND INSERVICE TESTING TO ASSESS THE' OPERATIONAL READINESS OF CERTAIN ELECTRIC MOV ASSEMBLIES IN LWR POWER PLANTS?
4 REPLY IT IS THE OPINION OF THE COMMITTEE THAT, IN LIEU OF THE RULES FOR PRESERVICE AND INSERVICE TESTING TO ASSESS THE OPERATIONAL READINESS OF CERTAIN ELECTRIC MOV j
' ASSEMBLIES IN LWR POWER PLANTS IN OM CODE-1995 SUBSECTION ISTC EXCEPT FOR ISTC 4.3,'THE ALTERNATIVE REQUIREMENTS IN OMN-1 MAY BE APPLIED.
j ELECTRIC MOVs FOR WHICH SEAT LEAKAGE IS LIMITED TO A SPECIFIC MAXIMUM AMOUNT l
IN THE CLOSED POSITION FOR FULFILLMENT OF THEIR REQUIRED FUNCTION (CATEGORY A)
MUST ALSO BE SEAT LEAKAGE RATE TESTED IN ACCORDANCE WITH THE REQUIREMENTS OF-ISTC 4.3.
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l A2-70 f
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ASME CODE CASE OMN-1 SCOPE MOVs REQUIRED TO PERFORM A SPECIFIC FUNCTION IN SHUTTING DOWN A REACTOR TO THE SAFE SHUTDOWN CONDITION, IN MAINTAINING THE SAFE SHUTDOWN l
CONDITION, OR IN MITIGATING THE CONSEQUENCES OF AN ACCIDENT.
j REQUIREMENTS i
DESIGN-BASIS VERIFICATION TEST' ONE-TIME TEST TO VERIFY-MOV' CAPABILITY TO MEET SAFETY-RELATED i
DESIGN-BASIS REQUIREMENTS.
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PRESERVICE TEST i
MOV TEST BEFORE IMPLEMENTATION OF INSERVICE TESTING AS NEAR AS j
PRACTICABLE TO PLANNED INSERVICE TESTS.
l INSERVICE TEST i
MOV TEST TO ASSESS CHANGES IN MOV FUNCTIONAL MARGIN.
i INSERVICE TESTS SHALL BE CONDUCTED IN AS-FOUND CONDITION.
INSERVICE TEST PROGRAM SHALL BE A MIX OF STATIC AND DYNAMIC TESTING.
1 A2-71
REQUIREMENTS (continued)
INSERVICE TEST FREQUENCY INSERVICE TEST FREQUENCY TO BE DETERMINED BY FUNCTIONAL MARGIN.
l MOV TEST SHALL BE EVERY 3 YEARS OR 2 RFO (WHICHEVER LONGER) IF INSUFFICIENT DATA EXIST TO JUSTIFY LONGER INTERVAL.
t MAXIMUM IST FREQUENCY SHALL NOT EXCEED 10 YEARS.
EFFECT OF MOV REPLACEMENT, REPAIR OR MAINTENANCE NEW IST VALUES SHALL BE DETERMINED OR PREVIOUS VALUES CONFIRMED AFTER MOV REPLACEMENT, REPAIR OR MAINTENANCE THAT COULD AFFECT l'
PERFORMANCE.
MOV GROUPING MOVs WITH IDENTICAL OR SIMILAR MOTOR OPERATORS OR VALVES AND WITH 1
SIMILAR PLANT SERVICE CONDITIONS MAY BE GROUPED TOGETHER.
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l A2-72 I
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REQUIREMENTS (continued)
- MOV EXERCISING
- ALL MOVs WITHIN OMN-1 SCOPE SHALL BE EXERCISED ON AN INTERVAL NOTTO i
EXCEED ONE YEAR OR ONE RFO (WHICHEVER IS LONGER).
NORMAL OPERATIONS MAY SATISFY THIS REQUIREMENT.
RISK-BASED CRITERIA
.i RISK-BASED CRITERIA FOR MOV TESTING ARE PERMISSIBLE.
I RISK-BASED CRITERIA SHALL BE USED IN CONJUNCTION WITH MOV MARGIN.
TEST METHODS ALL TESTING SHALL BE CONDUCTED IN ACCORDANCE WITH PLANT-SPECIFIC TECHNICAL SPECIFICATIONS AND PROCEDURES.
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l A2-73 l
ANALYSIS AND EVALUATION OF DATA ACCEPTANCE CRITERIA ACCEPTANCE CRITERIA SHALL BE BASED ON MINIMUM AMOUNT BY WHICH AVAILABLE STEM TORQUE MUST EXCEED REQUIRED DESIGN-BASIS STEM TORQUE.
UNCERTAINTIES OF TEST MEASUREMENT; EQUIPMENT; ANALYSIS, EVALUATION, AND EXTRAPOLATION: AND GROUPING SHALL BE CONSIDERED.
MCV MARGIN MAY BE EXPRESSED IN OTHER TERMS, SUCH AS STEM THRUST.
ANALYSIS OF DATA IF FUNCTIONAL MARGIN DOES NOT MEET ACCEPTANCE CRITERIA, MOV SHALL SE DECLARED INOPERABLE.
DATA ANALYSIS SHALL INCLUDE QUALITATIVE REVIEW TO IDENTIFY ANOMALOUS BEHAVIOR. IF IDENTIFIED, CORRECTIVE ACTION SHALL BE 1 AKEN.
EVALUATION OF DATA EVALUATIONS SHALL DETERMINE AMOUNT OF DEGRADATION IN FUNCTIONAL MARGIN THAT OCCURRED OVER TIME.
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EVALUATIONS SHALL APPLY TO ALL MOVs IN GROUP.
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A2-74 1
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ANALYSIS AND EVALUATION OF DATA (cont'muod)
DETERMINATION OF MOV FUNCTIONAL MARGIN ADEQUATE MARGIN SHALL EXIST TO ENSURE THAT CHANGES IN MOV OPERATING
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CHARACTERISTICS OVER TIME DO NOT RESULT IN REACHING POINT OF INSUFFICIENT MARGIN BEFORE NEXT SCHEDULED TEST.
i DESIGN-BASIS REQUIRED TORQUE SHALL BE DETERMINED FROM MEASUREMENTS TAKEN DURING TESTING AT DESIGN-BASIS CONDITIONS OR WITH JUSTlFICATION i
FROM TESTING AT OTHER CONDITIONS.
AVAiLABLE STEM TORQUE SHALL BE BASED ON MOTOR CAPABILITIES OR TORQUE
[
SWITCH SETTING AS APPLICABLE.
MOV FUNCTIONAL MARGIN SHALL BE CALCULATED AS THE DIFFERENCE BETWEEN i
AVAILABLE STEM TORQUE AND REQUIRED STEM TORQUE.
l lNTERVAL BETWEEN TESTS SHALL BE LESS THAN THE ANTICIPATED TIME FOR THE FUNCTIONAL MARGIN TO DECREASE TO THE ACCEPTANCE CRITERIA.
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IF MOV PERFORMANCE UNACCEPTABLE, CORRECTIVE ACTION SHALL BE TAKEN WITH RECORD MAINTAINED.
RECORDS AND REPORTS TEST INFORMATION AND RESULTS SHALL BE RECORDED.
ANALYSIS AND EVALUATION OF DATA SHALL BE DOCUMENTED.
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l A2-75
SUMMARY
OF INSPECTION FINDINGS OF LICENSEE INSERVICE TESTING PROGRAMS AT UNITED STATES COMMERCIAL NUCLEAR POWER i
PLANTS Andrew Dunlop, inspector, Region ill j
Joseph Colaccino, Engineer Office of Nuclear Reactor Regulation l
United States Nuclear Regulatory Commission j
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i A2-76 j
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INTRODUCTION Results of IST Inspections at Numerous Plants Since January of 1990 l
l Inspection Finding Categories:
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Program Scope Pump Testing Methodology i
Valve Testing Methodology j
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i Test Result Analysis IST Program Submittals to the NRC
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i A2-77 i
PROGRAM SCOPE t
isolation of Non Essential or Non Safety-Related Systems I
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Cross-Connect Valves Control Valves i
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i A2-78 i
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PUMP TESTING METHODOLOGY I
Pump Reference Curves Bearing Vibration Directions Post Maintenance Testing i
i Acceptance Criteria Established Below Design Limits j
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A2-79 I
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i VALVE TESTING METHODOLOGY Stroke-Timing of Power-Operated Valves Valve Maximum Stroke-Time Exceeds Design r
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A2-80 i
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' POST MAINTENANCE / MODIFICATION TESTING t
Administrative Controls Inadequate Acceptance Criteria for Check Valves Check Valve Inspection and Testing Relief Valve Testing Under Operational or Accident Conditions i
t A2-81
Valves not Added to IST Program After Plant Modification Self-Assessments Which Add Components to IST Program i
i Testing Contrary to IST Program Documents Shared Systems at Multi-Unit Sites i
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I A2-82 t
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TEST ANALYSIS Components in Required Action Range Components in Alert Range i
Relief Valve Testing Sample Expansion i
. Corrective Action i
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A2-83 t
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IST PROGRAM DOCUMENTATION t
Relief Requests Provisional Relief Requests not implemented t
Relief implemented Without Approval t
1 Deferred Test Justifications i
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A2-84 i
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CONCLUSIONS Problems with IST Programs:
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Administrative and Surveillance Procedures t
Detail of System Reviews l
Implementation of Regulatory Requirements l
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A2-85 i
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t IST Coordinators Need to Have A Questioning Attitude What are the accident requirements for this pump-or valve?
Is IST verifying these requirements?
t Why are the test results changing?
What affect will this modification have on the IST l
program or associated tests?
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A2-86
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I E
-- ------- ---- ------- ---------- ------------------.-----a
TABLE OF CONTENTS WORKSHOP QUESTIONS AND ANSWERS 1.0 GENERAL QUESTIONS........................
A3-2 1.1 SCOPE
............................ A3-2 l.2 OPERABILITY /REPORTkPILITY
.................. A3-3 1.3 TEET FREQUENCY / SCHEDULING................... A3-5 1.4 USE OF CODE EDITIONS AND CODE CASES.............. A3-8 1.5 POST MAINTENANCE TESTING
. A3-10 1.6 SKID-MOUNTED COMPONENTS................... A3-10 1.7 DOCUMENTATION........................ A3 1.8 RISK-INFORMED IST...................... A3-13 1.9 OTHER GENERAL QUESTIONS................... A3-15 i
2.0 VALVES............................. A3-18
- 2.1 GENERAL.-............................ A3-18 2.2 VALVE POSITION INDICATION.................. A3-24 2.3 CHECK VALVES A3-27 2.4 RELIEF VALVES...
A3-34 2.5 MOTOR-OPERATED VALVES.................... A3-40 2.6 CONTROL VALVES....................... A3-44 2.7 SOLEN 0ID VALVES....................... A3-45 2.8 PRESSURE ISOLATION VALVES AND CONTAINMENT ISOLATIuN VALVES
. A3-46 3.0 PUMPS.............................. A3 88 3.1 GENERAL........................... A3-48 3.2 INSTRUMENTATION.......................- A3-50 3.3 ACCEPTANCE CRITERIA..................... A3-52 3.4 VIBRATION.......................... A3-55 3.5 USE OF THE OM CODE A3-56 i
3.6 POST-MAINTENANCE TESTING A3-56 Note: Questions marked with'an (*) have been referred to the ASME OM Committee for evaluation and consideration for either a Code change lor Code.
inquiry. The NRC response to these particular questions reflects current NRC guidance and understanding of the ASME Code.
ATTACHMENT 3 7-A3-1 y
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L 1.0 GENERAL QUESTIONS I
1.1 SCOPE l
1.1.1 Are valves and pumps which are not ASME Code Class 1, 2, or 3 required to be in the IST program?
The current regulations, 10 CFR 50.55a(f), only address ASME Code Class l
1, 2, and 3 pumps and valves. Licensees may elect to include other non-l Code Class components in the IST program, however. The reader is referred to NUREG-1482, " Guidelines for Inservice Testing at Nuclear Power Plants," Section 2.2 and Question Group 53 in Appendix A.
Many of the older plants were not constructed to ASME Section III and their pumps and valves are not classified as Code Class 1, 2, or 3.
The regulations, 50.55a(f)(1) state that for plants whose construction permit was issued prior to January 1, 1971; pumps and valves that are part of the reactor coolant pressure boundary must meet the requirements l
ap)licable to components which are classified as ASME Code Class 1.
Otler safety-related pumps and valves must meet the requirements applicable to components which are classified as ASME Code Class 2 or Class 3.
For these older plants, the basis for the regulations requiring all safety related pumps and valves, that would not be required to be classified as Code Class 2 or 3 under the current 1
regulations (i.e., 10 CFR 50.55a(f)(3)), to be tested in accordance with the Code-is not apparent. The NRC intends to clarify this issue in the l
current rulemaking activities on 10 CFR 50.55a.
The licensees must classify their components and may use the guidance provided in footnote 9 to 550.55a (i.e., Regulatory Guide 1.26 or Section 3.2.2 of NUREG-0800).
l 1.1.2 If a component, that does not have a specific safety function for accident mitigation, is used in an emergency operating procedure (E0P) as an a'ternative method for mitigation of an accident in the event the primary method is unavailable, should the component be included in the IST program based solely on its potential use in an E0P7 l
Components are required by the regulations,10 CFR 50.55a(a)(1), to be l
tested to quality standards commensurate with their importance of the safety function to be performed.
Pursuant to the regulations, only Code Class 1, 2, or 3 pumps and valves are required to be tested in accordance with Section XI. Comnenents in the E0Ps would only be required to be in the IST progrs i f they are classified Code Class 1, l
2, or 3 and are within the scope of the Code, l
The licensee may elect to include such components in the IST program based on their safety or risk significance.
These components should, however, be clearly identified in the IST programs as outside the scope of the regulations (e.g., augmented).
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A3-2 l
4 1.1.3 Should components outside the Code Class 1, 2, 3 boundaries which meet the scoping statements of OM-6 and 10 be considered " augmented" IST7 The licensee may elect to include such components in the IST program based on their safety or risk significance. However, there is no requirement for components included in the scope of OM Parts 6 and 10 that are not Code Class 1, 2, or 3, to be tested in accordance with Section XI.
The regulations, 10 CFR 50.55a(f), only address inservice testing of Code Class 1, 2 and 3 pumps and valves.
If included in the IST program, these components should be clearly identified as outside the scope of the regulations (e.g., augmented).
Refer to Section 2.2 of NUREG-1482 for further information.
1.1.4 If there is no credit taken in the FSAR for operation of a particular system to shut the plant down, maintain the shutdown condition, or mitigate the consequences of a design basis accident, is the system requ' red to be included in the IST program even though it is considered safety-related? For example, the reactor core isolation cooling (RCIC) system in boiling water reactors (BWRs).
1 If specific systems are not required by the safety analysis report (SAR) to shut the plant down to the safe shutdown condition, maintain the safe i
shutdown condition, or mitigate the consequences of a design basis accident, then they are not required to be tested in accordance with the ASME Code. Other commitments made by the licensee, however, may mandate i
testing these systems in accordance with the Corie. As an example, the RCIC system at one BWR was not required to be included within the scope of the plant's IST program, however the licensee formally committed to the NRC to test this system in accordance with the Code requirements.
1.2 OPERABILITY /REPORTABILITY 1.2.1 When a component is identified to have a safety function, and is added late in the life of the IST program, is operability a concern before testing ud degradation detection takes place? If yes, why is design ignored or not considered enough assurance to allow operation until testing is performed?
A nonconforming condition is defined in GL 91-18, "Information to Licensees Regarding Two NRC Inspection Manual Sections on Resolution of Degraded and Nonconforming Conditions and on Operability," Enclosure 1, NRC Inspection Manual Part 9900, " Technical Guidance, Resolution of Degraded and I;onconforming Conditions," as a condition of a system, structure, or component (SSC) in which there is failure to meet require-ments or licensing commitments.
Improper exclusion of a pump or valve from an IST program is considered a nonconforming condition because the licensee has failed to meet the ASME Code requirements referenced in the safety analysis report.
In addition, not performing the specified Code testing during the period that the component was excluded from the IST program would be considered similar to a missed technical specification surveillance which is also a nonconforming condition.
A3-3
l Guidance for missed surveillance is provided in GL 91-18, Enclosure 2, Part 9900 NRC Inspection Manual, " Operable / Operability: Ensuring the Function Capability of a System or Component," Section 6.6.
When determining the basis for declaring the affected system operable; analysis, tests, operating experience, and engineering judgement (which may include design considerations) should be considered.
1.2.2 Does the NRC consider non-compliance with the Code to be a separate issue from " operability" (i.e., can you be "non-compliant" with the Code, but still " operable")?
Yes.
NUREG-1482, Section 3.2, provides guidance in situations where components exceed their Code acceptance criteria. Although a component may be required to be declared inoperable per the Code, licensees are able to determine the component's technical specification (TS) operability using guidance contained in GL 91-18, Enclosure 2, Section 6.11.
1.2.3 If a licensee determines that a component (e.g., pump) is not being tested in accordance with the Code (e.g., instrument range too large, portion of flow not measured), will an operability determination in accordance with GL 91-18 always be required?
Yes.
Code non-compliance is one of the nonconforming conditions described in GL 91-18.
1.2.4 If a utility has evaluated certain maintenance activities (instrument calibration checks, positioner controls, etc.) as not affecting stroke times and has historical data to support this, but discovers a unique activity, not generally performed, that does affect stroke time, if a post-maintenance test is not performed, is this a reportable occurrence?
Yes.
10 CFR 50.73(a)(2)(I)(B) requires any operation or condition that is prohibited by the plant's TS to be reported in a licensee event report.
1.2.5 Is an LER required for a missed surveillance test if subsequent testing and/or other information on the component supports the determination that the component and its system were operable during the period of the missed surveillance?
10 CFR 50.73(a)(2)(I)(B) requires any operation or condition that is prohibited by the plant's TS to be reported in a licensee event report.
Missed surveillance are reportable when the surveillance interval plus allowed surveillance interval extension (e.g., Standard TS, Section 4.02) plus the LC0 statement time is exceeded. The event is reportable even though the surveillance is subsequently satisfactorily performed.
(See NUREG-1022, Revision 1, Second Draft for Comment, " Event Reporting Guidelines 10 CFR 50.72 and 50.73")
A3-4
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1.2.6 Can users of older Codes and standards (pre-1994) use a 10 CFR 50.59
)
evaluation in lieu of code required corrective act' ens?
NUREG-1482, Section 3.2, provides guidance in situations where components exceed their Code acceptance criteria. Although a component may be required to be declared inoperable per the Code, licensees are i
able to determine the component's TS operability using guidance j
~
contained in GL 91-18 in the Technical Guidance on Operable / Operability, i
Section 6.11. A 50.59 evaluation would be required when the acceptance criteria are revised in the test procedures. NUREG-1482 Appendix G Responses 2.1-2 and 2.1-3 provide additional insights into the uses of 10 CFR 50.59.
1.2.7 Can licensees justify, deviations from TS and Code requirements' using a 50.59 evaluation?
(
i Generally, deviations from TS Code requirements cannot be justified using 10 CFR 50.59 evaluations.
See question above.
1.2.8 What must a licensee have in place to ng_t declare an equipment train inoperable per TS, when lined up to run in a test mode? Is auto-transfer valve logic to safety mode on an accident signal alone adequate, or do valve realignment times versus LOCA analysis assumptions need to be validated via calculations / testing? Can operability be argued on a PRA/ risk basis?
If a licensee does not wish to enter an LC0 to complete IST, then a plant specific analysis would have to be performed to ensure that the system was still operable. As discussed in NUREG-1482, Section 3.1.2, if a system or subsystem is designed to realign automatically during testing, and therefore is not considered out of service, the licensee does not need to enter an LCO.
The applicable valves must be capable of repositioning against the evaluated conditions. See GL 96-05 on M0V periodic verification program. The limiting stroke time for the auto-transfer valve would have to be deterrined considering the safety analysis report assumptions. Operability determinations using probabilistic risk assessment or risk analysis have not previously been performed and their utilization would be closely examined by the staff.
1.3 TEST FREQUENCY / SCHEDULING 1.3.1*
When updating to the 1989 Code, which does not require alert frequency testing for valves and for certain pump testing, if a pump or valve is currently on increased frequency, what action, if any, is needed when the program is updated and the increased frequency requirement goes away?
The Code, Regulations, and published staff guidance do not address the transition from one Code edition to another.
However, it is recommended that the licensee follow the increased test frequency until after the first test using the updated program. The first test results should then be evaluated using the updated Code. The licensee should, however, A3-5
If the deferral to refueling is based on the 1mpracticality of performing the test during operation, and it is in fact practical to perform the test during operation (e.g., during system maintenance j
l outages), the basis for the deferral would be invalid and testing should be performed quarterly, in accordance with the ASME code test frequency requirements.
Licensees may request an alternate test frequency based on the burden of testing quarterly.
Such alternatives have been evaluated for excess flow check valves at other plants. (
Reference:
(
Safety Evaluations for Susquehanna and Peach Bottom dated February 23, i
1996, and July 1, 1996, respectively).
1.3.9 For relief granted through GL 89-04 to extend test intervals to cold l
shutdowns or refueling outages, could clarification of licensee actions for " alert range" conditions be provided?
As discussed in the Current Considerations for Position 9 (page A-42 of NUREG-1482), it is recommended that efforts be made to take corrective actions during the outage and repeat the test post-maintenance for pumps or valves which can only be tested in accordance with the Code during refueling outages or cold shutdowns. The increased test frequency when pumps or valves (i.e., those valves tested in accordance with IWV) parameters are in the alert range does apply to testing performed during refueling outages or cold shutdowns, but NRC is not requiring an outage or cold shutdown specifically for doing the test.
1.4 USE OF CODE EDITIONS AND CODE CASES 1.4.1 Are there any plans to revise NUREG-1482 to allow various later positions in the Code and Code Cases, so as not to require utilities to submit relief requests? Of special interest are codes to be endorsed in upcoming 150.55a rule change.
The are no plans to revise NVREG-1482 in the near term.
The proposed rule change will address the use of portions of later Code editions and addenda.
1.4.2 What is the status of Regulatory Guide 1.1477 Regulatory Guide 1.147 will continue to addressSection XI Code Cases.
It is anticipated that OM Code Cases will either be addressed in a new Regulatory Guide, or the scope of Regulatory Guide 1.147 will be expanded to address both Section XI and OM Code cases.
1.4.3 Must utilities demonstrate hardship to the staff for utilization of Code Cases which are scheduled to be approved by NRC (i.e., in Regulatory Guide 1.147)?
Regulatory Guide 1.147 and the possible new Regulatory Guide to address OM Code Cases stipulate or would stipulate any contingencies or limitations for application.
If licensees wish to use an OM Code Case before it is endorsed in a Regulatory Guide or rule, approval could be requested in accordance with 10 CFR 50.55a(a)(3)(i) or (ii).
A3-8
l 1.3.6*
If a nuclear unit was required to enter a mid-cycle forced shutdown, whereby the return to service date was undetermined and the plant was required to enter a TS mode / condition of " refueling" for repairs, could some refueling deferred tests be performed, so that at the scheduled RF0, fewer tests would be necessary?
j Licensees could perform some tests at a mid-cycle shutdown where plant conditions permit the conduct of refueling outage deferred tests.
However, without an authorized alternative, all testing scheduled for the refueling outage (i.e., deferred tests) would have to be performed as required by the Code unless the licensee can take advantage of the i
l allowed extensions as described below.
If the forced shutdown occurred shortly before the ant refueling outage such that the cycle length plus the 25% TS-allowed test frequency l
extension ended in the followina scheduled refueling outage, then some l
refueling outage tests could be performed in.the forced shutdown and deferred to the following refueling outage. As an example, a plant with a 12-month cycle has a 1-month forced shutdown, 2 months before the end of the current cycle. The licensee could perform some refueling outage testing during the forced shutdown and not test these components until the following refueling outage 15 months later.
However, an additional extension of the surveillance interval should the following refueling outage be delayed for components tested during the forced shutdown would not be allowed since the TS " extension" was already taken at the start of the surveillance interval.
1.3.7 please clarify the statement in NUREG-1482, Section 3.1.2 that l
states that entry into multiple LCOs to perform IST should be avoided. Are there restrictions to this provision? Can this be i
taken to mean that entry into more than one LC0 to perform an IST test justifies deferral of testing until plant conditions allow I
(e.g., in the case of the service water or other support systems, which when removed for testing, cause a number of other dependent systems to be in LCOs)?
NUREG-1482 was written to caution against entry into multiple, i
independent LCOs, for testing, in order to limit plant risk.
The maintenance rule also addresses this issue of plant configuration risk
(
(i.e., 150.65(a)(3)) and is pertinent to IST.
Entry into LCOs is not in j
itself a sufficient reason for deferring tests to cold shutdowns or refueling outages.
It is recommended that the out-of-service time of the tested train be minimized.
1.3.8 If it is practical to perform on-line maintenance, is a relief request (e.g., concerning excess flow check valves) which effects a refueling outage test frequency invalidated? If a valve has its test frequency deferred to refueling, but the test can actually be done 1 week before refueling, can this test be credited or must the t
test be reperformed with a hydro pump during the actual " refueling outage"?
E A3-7 l:
1
evaluate the need for corrective action when the component is in the alert range, and not postpone the corrective action when warranted.
1.3.2 For cold shutdown testing, where testing must start within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> (but is not required to be complete before restart), how should the appropriate number of valves to be tested be determined (e.g., per hour, day,etc.)?
As discussed in NUREG-1482, Section 3.1.1.1, the licensee should make a
" good faith" reasonable effort in scheduling and performing the cold shutdown tests.
1.3.3*
Nost plants have a 25% grace period for surveillance.
If a pump is in the alert range, can the 25% extension be applied to the 6-week test frequency?
l The new Standard TS (e.g., NUREG-1434, SR 3.0.2) allow the 25% extension i
to be applied to all surveillances, unless otherwise noted.
Section L
5.7.2.12 specifies that the provisions of SR 3.0.2 are applicable for l
specific frequencies for performing IST.
Quarterly, biennially, and monthly testing frequencies are specified. However, bi-quarterly testing, as required when pumps are in the alert range, and relief valve testing (i.e., 5-and 10-year test frequencies), are not specified in the TS.
Therefore, relief or a TS revision would be required to extend these test intervals.
See NUREG-1482, Section 3.1.3.
1.3.4 NUREG-1482, Section 3.1.3 states that other than to coincide with a refueling outage, that the TS 25% test extension for the test interval does not apply to safety and relief valves. Does this imply that a relief request is not needed to exceed the 5 yr. Class I test frequency to allow testing during the refuel outage, but the l
25% test extension cannot be used to justify not testing during a refuel outage and then test during a maintenance outage?
Yes, for valves tested in accordance with the 1983 Edition of Section XI. The 1983 Edition of Section XI specifies a testing. schedule based l
on refueling outages.
Later Editions of Section XI and the OM Code require testing within five years and do not allow an extension to refueling outages.
1.3.5*
If a plant is required to shutdown and enters a refueling mode per TS to " sip fuel," but it is not a scheduled refueling, are the refueling outage inservice tests required to be performed?
As discussed in Code Interpretation XI-1-83-73, the Code does not define cold shutdown.
The Code also does not define refueling outage.
The refueling mode, and not refueling outage, is defined in plant technical specifications. The licensee defines refueling outages.
It does not appear that the intent of the Code was to require all valves scheduled for refueling outages to be tested during short, unplanned outages to sip fuel or even to replace leaking fuel assemblies.
The Code requires f
that the cold shutdown frequency tests be performed during cold shutdowns.
]
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1.4.4 Is there a potential for rulemaking requiring utilities to update IST programs in addition to the required 10 year update (i.e.,
-baseline updating for all utilities)?
At this time, the staff is not considering requiring all licensees to update to a specific Code edition at a time other than the ten year update. However, future rulemaking may require expedited implementation of selected Code requirements, subject to the backfit rule.
1.4.5 Does the NRC expect utilities to comply with later Codes if they are not required by their current 10 year program?
For ISI, the currently pro)osed rulemaking does not include any provisions for requiring tie use of later Codes, unless they are part of the ten year update. Future rulemaking may, however, mandate the expedited use of later editions and addenda, or portions of, subject to the backfit rule.
1.4.6 Can relief be based on the 1996 Addenda of the OM Code? Will the proposed rule change include the 1996 Addenda?
Until the NRC reviews and approves the 1996 Addenda, which (with certain exceptions and limitations) will be included in the upcoming rulemaking, approval could be requested using 10 CFR 50.55a (a)(3) or (f)(6)(i).
1.4.7 Is anyone using the 1990 Edition or 1995 Addenda of the ON Code? If so, is relief required?
Approval by the NRC staff is required, and has been granted to several licensees, to use the 1990 Edition of the OM Code. Although the requirements far pump and valve testing in this edition are identical to those provided in the 1989 Edition of Section XI, the 1990 Edition is not referenced in the regulations. Approval is also required to use the 1995 Edition of the ASME OM Code. An alternative has been authorized by the NRC to use Section ISTB 6.2.2 of the 1995 Edition, which allows the licensee to use analysis to establish new reference values when the pump is in the required action range, because these requirements are already allowed by NRC GL 91-18.
1.4.8 Currently, what is the latest NRC-endorsed edition / addenda of the Code?
The 1989 Edition of Section XI has been referenced in 650.55a(b), with a limitation regarding testing of containment isolation valves.
1.4.9 What is the status of NRC adopting later Codes? Will the 1989 edition of Section XI still be in effect in future years?
IST programs during successive 120 month intervals must comply with the requirements of the latest edition and addenda referenced in 10 CFR 50.55a(b), 12 months prior to the start of the next ten year interval.
The staff is currently working on rulemaking to update the reference in A3-9 i
i 10 CFR 50.55a(b) to the 1996 Addenda of the OM Code with certain exceptions and limitations.
The proposed rule change is scheduled, at this time, to be published for public comment in late 1997.
The staff understands the difficulty with planning and scheduling an IST program update. At this time, it is impossible to predict when and what editions of the Code will be referenced in the regulations at a later date. Licensees could request an extension, if proposed rulemaking was out for public comment during the period when a licensee would be updating their IST program.
1.5 POST MAINTENANCE TESTING 1.5.1 Does the utility decide if a post maintenance test for pumps or valves is required after maintenance? For example, after a core spray pump seal package was replaced, a full-flow test could not be performed due to plant conditions. The licensee performed a minimum flow test and determined that only vibration was affected.
In general, some form of post maintenance testing is always required.
Further, relative to Section XI, the licensee is responsible for determin-ing if maintenance on a pump or valve could affect the component reference values.
Recently, a plant performed maintenance on a pump similar to that described above while at power and discovered during the next refueling outage full-flow test that one vibration reference value was significantly different.
Licensees should consider their maintenance activities carefully in order to assess their effect on component performance.
1.5.2 Is it acceptable to schedule preventative or corrective maintenance i
and the associated post maintenance tests during power operation for those components tested during cold shutdown / refueling only?
Yes, but several caveats apply. The Maintenance Rule and licensee TS must be consulted.
If the maintenance could affect the reference values, a post-maintenance test would be required. As discussed in NUREG-1482, Section 4.4.4, the NRC would expect the licensee to shut down the plant to perform the post maintenance IST, unless the licensee has an alternative to ensure that the operational readiness of the component is maintained.
1.5.3*
If post-maintenance testing results are acceptable pursuant to the Code, but are not identica' to the reference values, must the reference values be revised? If not, is a formal evaluation needed to analyze the difference?
The Code requires that new reference values be determined or the previous reference value be reconfirmed. There are no provisions for a tolerance around the previous reference values.
1.6 SKID-MOUNTED COMPONENTS 1.6.1 When the licensee includes skid-mounted components in their IST program pursuant to NUREG-1482, Section 3.4, is it acceptable for A3-10
l the licensee to simply identify that the skid-mounted components' operational readiness is verified during testing of the major component.
j Yes. As discussed in NUREG-1482, the licensee should state in the IST program that the surveillance tests of the major component adequately tests the skid-mounted components.
It should be noted that the OM Code has addressed skid-mounted components in the 1996 Addenda.
The Code revision corresponds to the discussion in NUREG-1482.
l 1.6.2 What guidance does the NRC provide regarding component / system
)
designation of " skid-mounted" equipment?
l Guidance is provided in NUREG-1482, Section 3.4.
t 1.6.3 Is the format of documenting " skid" testing important to the staff?
closed) ple, should the normal test type (e.g., stroke open, stroke For exam l
l be specified and then a footnote stating that the component is skid tested be included, or may a licensee use " skid" as a test l
designation, and then describe in the bases document how that skid test meets the various safety functions?
l There are no requirements on the format of the information presented in the IST program.
The licensee should document in the IST program that the components are skid-mounted and that their operational readiness (safety function (s)) is verified during the test of the major component.
1.7 DOCUMENTATION 1.7.1 What documentation, if any, would the NRC staff expect from i
licensees to support a position that hot shutdown is the licensed safe shutdown condition?
r This type of information should be formally documented'on the docket.
The licensing bases may be contained in the plant license, safety analysis report or TS.
Individual plants should check with their NRR i
Project Manager.l.7.2
- 'r What reports or submittals, if any, are required to close out a ten
/ _
year testing interval? The Code clearly requires updated programs.
to be filed, but is any final summary report of testing conducted r
during the interval required?
As discussed in Interpretation XI-I-83-08, "Section XI, Division 1, IWA-l 6230, Inclusion of Inservice Testing Results on Pumps and Valves in p
Summary Report Submittal," it is not the intent of Section XI that a Summary Report of inservice testing activities be included in the ISI Summary Report.
Test records are required to be maintained by the licensee. No IST submittal or report at the end of the interval is required.
1 A3-11 t
-m
. =. -..-
l 1
1.7.3 How much documented evidence does the NRC expect or require in an IST program to justify exclusion of components from the program? In particular tddress "important to safety" systems, which may not be designated as safety-related in the plant's licensing bases, e.g.,
standby gas treatment, fuel pool cooling, control room HVAC, or reactor core isolation cooling (RCIC) systems in a BWR.
l There is no requirement to document the basis for excluding or including L
components in the IST program. However, a plant IST bases document, l
under administrative controls, would provide a means to describe l
decisions on component scope, safety function, and test method, i
throughout the life of the plant. This is especially useful for important to safety systems that are not required to be tested in accordance with the Code, but are required to be tested commensurate with the importance of the safety function to be performed. This is particularly helpful when the individuals responsible for establishing the IST program are no longer accessible. NUREG-1482, Section 2.4.4, provides some general guidance on bases documents.
NRC inspectors have noted a strength in the IST program for licensees that have well established bases documents.
1.7.4 When developir.g the IST program bases pursuant to NUREG-1482, how far does the licensee need to go on defining what components are ngi in the program?
The document typically would enable the reader to clearly understand the reasons that the components are not included in the program. Some i
L licensees have simply compiled lists of manual test valves, for example,
(
that would be exempt per Part 10, Paragraph 1.2(a)(1), without any l
further explanation.
Other licensees have provided specific evaluatior.s of each valve and/or system.
l 1.7.5 How are plants controlling their IST bases documents? Are they l
required to be controlled documents?
Most licensees maintain their bases document as a controlled document.
However, there is no requirement for establishing or maintaining bases documents.
1.7.6 Is a 50.59 evaluation required for All changes to IST programs? Or l
will a 50.59 evaluation for testing procedures suffice?
IST programs (i.e., not only the test procedures) are typically l
described in a licensee's final safety analysis report (FSAR).
If changes to these activities or controls are made, such changes qualify l
as changes to procedures as described in the safety analysis report, and the changes would be governed by the requirements of 10 CFR 50.59 [The staff's current recommendation is provided in SECY-97-035,Section III.C, " Proposed Regulatory Guidance Related to Implementation of 10 CFR 50.59 (Changes, Tests, and Experiments)"].
l A3-12
1.7.7 Many newer plants have an active valva list identified in their FSAR in Section 3.g.3.
Additionally, active valves are identified in IST program plans. The FSAR active valve lists typically have been generated by the NSSS vendor and architect / engineer companies without regard to IST program requirements.
Is the definition of active considered the same? If, so, should IST programs be reconciled with these FSAR lists?
The IST program should be consistent with the updated safety analysis report.
Both documents form part of the current licensing basis for the pl ant. This does not preclude referencing one document in '3e other so as to minimize duplication and any associated administrative burden. If the definition of active valves is not the same in both documents, the differences should be clearly described.
It should be noted that the definition of active pumps and valves in the Standard Review Plan, NUREG-0800, Section 3.9.3, Table 2 is not the same as the definition in the Code.
1.7.8 Would the staff be receptive to changes to the SAR to delete the active valve table?
The active valve table in Section 3.9.3 provides useful information beyond that required in a licensee's IST program.
This section addresses the structural integrity of components.
1.8 RISK-INFORMED IST l
1.8.1 What is status of risk informed regulations, standard review plans, regulatory guides, etc., and how will it effect the IST inspection procedure?
The staff is currently preparing the standard review plan (Chapter 19 on general PRA applications and Section 3.9.7 on Risk-Informed IST), Draft Regulatory Guides DG-1061, "An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Current Licensing Basis," and DG-1062, "An Approach for Plant-Specific, Risk-Informed Decision Making: Inservice Testing," and Draft NUREG-1602,
" Guidelines for Use of PRA in Risk-Informed Applications." It is anticipated that these documents will be available for public comment in Summer 1997.
Implementing a risk-informed IST program would be a voluntary initiative for licensees and would be subject to NRC approval.
The NRC's IST inspection procedure will need to be revised to address the risk-informed initiatives, after they are approved.
1.8.2 Do risk-informed IST programs need to consider the increase in core damage frequency?
The risk-informed IST pilot submittals did consider changes in core damage frequency.
Guidance on development and implementation of risk-informed IST programs will be provided in regulatory guides and standard review plans.
i A3-13 i
I l
1.8.3 How can licensees request implementation of a risk-informed IST program?.Is risk-based testing considered an " alternative" to Code testing that utilities may use (via a request for approval) or must licensees _ wait for final generic approval by the NRC7 There are two pilot plants, Comanche Peak and Palo Verde, that have requested to implement a risk-informed IST program as an alternate to the Code requirements.
Eight other plants are also involved with the industry's pilot effort.
The staff does not have the resources to evaluate proposed alternates from other licensees until the standard review plan and regulatory guides are completed, and the safety evaluation of the two pilots has been issued. The schedule is for these items to be completed by the end of 1997.
1.8.4 What is the status of the Palo Verde and Comanche Peak risk-informed IST programs?
Significant work has been completed on the risk-informed IST pilot programs. However, there are still a number of outstanding issues that need to be resolved before a safety evaluation (SE) can be issued.
Completion of the SEs is contingent on issuance of the draft Regulatory Guides (RGs) and Standard Review Plans (SRPs) for public comment, resolution of open items, and prompt response by the pilot licensees regarding how their proposed risk-informed IST programs conform to the draft RGs and SRPs.
1.8.5 What are the advantages and disadvantages of risk-informed IST?
The staff views the ability to redirect resources to more safety important component testing, resulting in more effective and focused testing, and to decrease the testing frequency of less safety important components as positive attributes of risk-informed IST.
These initiatives may result in less uniformity in licensees' programs.
1.8.6*
What is the status of Code activities related to risk-informed IST7 The ASME Code committees are developing risk-informed Code Cases.
The current approach is to have one Code Case that will address risk-ranking and categorization, and other Code Cases that will be component specific and provide the requirements for IST of high and low safety significant components. The risk-ranking Code Case has recently been voted on by the OM Main Committee, and committee members are resolving the negative ballots.
The component specific Code Cases are still being developed by the lower tier committees.
1.8.7*
Has any thought been given concerning the risk impact of test frequency, i.e., that the testing performed can increase the probability of failure?
The potential for testing to increase the failure probability was i
considered in revising provisions for testing emergency diesel generators and pumps using minimum flow (GL 89-04, Position 9 and the a
J A3-14 r
comprehensive pump test revisions in the Code). Additionally, another impact of increased test frequency is a potential for higher unavailability. This has been considered in NRC risk-informed TS analyses (See NUREG/CR-6141, BNL-NUREG-52398, " Handbook of Methods for Risk-Based Analysis of Technical Specifications," P. Samanta, et al, March 1995).
In addition, Attachment 1 to GL 96-05, Periodic Verification of Design-Basis Capability of Safety-Related Motor-0perated Valves, stated that dynamic testing is the preferred method of periodic j
verification; however, it may not be appropriate for certain situations.
1.9 OTHER GENERAL QUESTIONS 1.9.1 Does the NRC plan to continue the practice of providing generic relief of new and evolving IST issues in the format of NUREG documents (similar to NUREG-1482)?
Generic relief was not provided in NUREG-1482. The NUREG approved portions of.later Codes referenced in 10 CFR 50.55a(b), as allowed by 10 CFR 50.55a(f)(4)(vi); provided guidance; clarified issues; and clarified information to be included in requests for specific relief.
Generic relief, such as provided in GL 89-04, will no longer be provided by the staff. The preparation of GL 89-04 was a special case to allow prompt and reasonable resolution of numerous outstanding IST issues.
l l
1.9.2 Does the NRC believe that the current guidance published on IST is adequate for licensees to know whether they are in compliance and should have successful inspections?
If not, what initiatives are planned to correct this situation?
The NRC st.aff considers current IST guidance adequate to allow licensees to remain in compliance with the regulations and to have successful inspections. To improve the guidance, the staff has published NUREG-1482 and NUREG/CR-6396, " Examples, Clarifications, and Guidance on Preparing Requests for Relief from Pump and Valve Inservice Testing Requirements." Additionally, the four IST workshops held in early 1997 provided a forum for licensees to ask questions and these meeting minutes provide additional clarifications.
I 1.9.3 What is the availability of NRC technical staff for discussion of IST issues?
NRC technical staff should not be contracted directly to discuss plant specific IST issues.
Licensees may contact regional staff or their NRR Project Manager to request that their question be directed to the technical staff.
1.9.4 Who is the authority within the NRC to make the final NRC interpretations on IST requirements? How do the regions work together with NRR to facilitate this?
NRC resident and regional ins)ectors are responsible for inspections at licensee facilities. NRR Meclanical Engineering Branch (NRR/EMEB)
A3-15 i-I
personnel prepare Safety Evaluations on licensees' IST program relief requests and proposed alternative testing and provide technical guidance to NRC staff on IST issues. NRR/EMEB personnel often accompany regional inspectors when performing IST inspections.
Inspectors also contact EMEB while on site or in the regional office to obtain information on Code requirements or current NRC positions. Occasionally, a formal request is made by the regional office for EMEB to address an IST issue at a specific plant.
If licensees have questions on interpretations made by the inspectors, they may discuss these issues with their NRR Project Manager or NRC Regional Manageu nt.
1.9.5 If interim relief is granted, what is expected at the end of the interim period? Is all plant /NRC correspondence expected to be complete and relief approved, or must the Code requirements be satisfind?
The answer depends on the stipulations included in the evaluation and conclusion sections for the individual relief request in the safety evaluation.
If a revised or new relief request is required as part of the evaluation, then the relief should be requested to allow ample time for the NRC to review the request for relief or proposed alternative.
If documentation, evaluation, or some other action is required with no additional submittals to the NRC, then this activity only needs to be completed before the interim period expires. Appropriate documentation should be available to verify completion of the stipulations in the interim relief request.
If the licensee is directed to comply with the Code during the interim period, the licensee should have completed the changes to the test procedures prior to the end of the interim period.
1.9.6 Due to the complexity and number of requirements which are involved in successfully implementing an IST program, many of our IST problems appear to be caused by inadequate numbers or experience level of IST engineers. Does the NRC staff have a position or guidance document recommending IST staff levels, experience, or training for a typical LWR 7 The NRC does not have a specific requirement or position on the staffing level for an IST program.
It is expected that the individuals involved with IST have an understanding of pump, valve, and system testing, as well as ASME Code requirements.
1.9.7 Is there a schedule, plan or objective to perform IST inspections with regional NRC teams? How is consistency maintained in each of the four regions?
There are currently no plans to perform IST inspections using regional teams following a specific schedule.
IST inspections are currently performed on an as-needed basis.
Resident inspectors may elect to
-either perform some or all of Inspection Procedure 73756, Inservice Testing of Pumps and Valves, during the course of their duties. They also may request regional support to perform a dedicated IST inspection.
Region-based inspectors may perform IST inspections individually, with A3-16 1
l another regional inspector, a NRR IST technical reviewer, or a contractor tasked by NRR to provide technical assistance in IST ins)ections.
IST issues are also addressed by the region in conjunction wit 1 temporary instructions and inspection modules performed in team inspections, such as the service water system operational performance inspection.
i The NRC has published guidance in NUREG-1482 on IST issues.
NRR technical reviewers are available to NRC inspectors, either on site or at the regions, to assist in interpreting ASME Code requirements and published NRC guidance.
1.9.8 Are utilities keeping track of IST data to use in plant life extension?
Code Case DMN-1 includes data maintenance that could be used for life extension. We are currently not aware of utilities compiling specific IST data for plant life extension.
Licensees may use INP0's NPRDS or EPIX databases to support plant life extension. These databases include IST results.
l 1.9.9 Has the NRC position on reviewing and approving IST relief requests changed over the past 6 months?
i The staff's position on the submittal of requests has not changed.
Licensees are encouraged to submit requests for relief, when necessary.
1.9.10 Can NUREG-1482 be used for only selected components and not all (e.g., use OM-6 for selected pump's vibration monitoring, as allowed by Section 5.4)?
The guidance in the NUREG-1482 may be used on selected components, unless specific restrictions are contained in individual sections of the NUREG.
The application of the NUREG should be clearly stated in the IST program.
1.9.11 We have a vacuum breaker (i.e., spring loaded valve', installed on top of an " unsafe" tank which requires scaffolding, etc. to test.
i This valve is new. Must we follow the Code until relief is granted? What if it is impractical to test?
As discussed in NUREG-1482, Section 2.5, the requirements of the Code must be met until an alternate is approved, unless the requirements are clearly impractical.
1.9.12*
Is as-found testing only required for relief valves?
l As-found testing is only required in the Code for relief valve testing.
No maintenance, adjustment, disassembly, or other activity which could l
affect as-found set pressure or seat tightness is permitted by Appendix I prior to relief valve testing. However, the IST program is intended to assess the operational readiness of all components.
Licensees should A3-17 l
be aware of, and limit, any maintenance, especially during refueling outages, that is routinely scheduled and performed before the specified tests. Additionally, licensees should note that Appendix J implementing documents (e.g., Regulatory Guide 1.163 and NEl 94-01) require as-found i
testing. NRC Information Notice 97-16, " Preconditioning of Plant i
Structures, Systees, and Components Before ASME Code Inservice Testing or Technical Specification Surveillance Testing," provides additional information on this issue.
2.0 VALVES 2.1 GENERAL 2.1.1*
A current proposal before the Code committees is to exercise manual valves every 5 years, with valves in adverse conditions requiring i
more frequent testing.
If the valve is significant enough to be included in the IST program, there should be confidence that the i
valve will function, a 5 year frequency does not provide this confidence. Can this be relayed to the NRC representative on the working group looking at this issue?
The ASME 0&M Code is a consensus document developed by volunteers. Any interested party may attend Code committee meetings and provide input.
Additionally, public comments on proposed Code changes are solicited in Mechanical Engineering magazine and in the ANSI Reporter.
Changes to the OM Code are not required unless justified as part of rulemaking.
Proposed rulemaking is also subject to a public comment period. This comment will be forwarded to the OM Main Committee for consideration.
In addition, the NRC may impose additional requirements when the Code is endorsed in the regulations subject to appropriate backfit justification.
2.1.2*
If the plant computer is used to measure stroke time, are there any accuracy requirements? Does the use of the computer for IST require that it be safety-related? In using plant computers there may be delays due to signal processing / feedback to the computer, in addition to the actual stroke times.
Is this acceptable, if it can meet the Code reference bounds?
The Code requires the use of an appropriate indicator for measuring valve obturator movement. Stroke times are required to be measured to at least the nearest second. There are no other Code requirements for stroke measurement. Test and measuring equipment used for safety-1 related components must meet the requirements of 10 CFR 50, Appendin B, but are not required themselves to be safety-related. The use of computers that can measure to at least the nearest second would be acceptable for IST.
2.1.3*
A valve which has a specific leakage limit assigned for the close direction is leak tested per Category A requirements.
If a system has a leakage limit (e.g., for required inventory), but individual valve (s) have no specific leakage assigned (as in an off-site dose A3-18 m.
i analysis), are the system valves required to be category A in the IST program? If no, why are containment isolation valves required to be Category A, since the leakage limit is for the whole system (i.e., the containment)?
~
The staff recently evaluated this issue (Reference letter dated August 20, 1996 from NRC to Arkansas Nuclear One, Docket 50-313 and 368,
" Safety Injection System Recirculating Valve Leak Test Requirements, Arkansas Nuclear One, Units 1 and 2"), and has determined that if a licensee has determined that a total system leakage limit, rather than a valve specific leakage limit, is appropriate, Category A does not apply and reverse flow closure verification meets the inservice testing i
requirements for valve seating.
Containment isolation valves have a i
total system limit (i.e., 0.60 La per 10 CFR 50, Appendix J), therefore, i
these valves would not have to be classified Category A, unless Option B of Appendix J was utilized or the licensee requires each valve's leakage 4
to be limited to a specific amount (See Interpretation XI-81-01).
i Option B requires that a performance criterion be established for Type C l
tests.
The staff in GL 89-04, Position 10, however, states that all containment isolation valves that are included in the Appendix J program 1
should be included in the IST program as Category A or A/C valves.
Additional staff guidance may be required.
1 2.1.4 In adopting GL 89-04, Position 6, it is unclear as to whether this position must be adopted for all valves or may be selectively i
applied at the owner's discretion?
GL 89-04, Position 6 may be applied to individual valves.
2.1.5 How do you treat post maintenance testing for main steam isolation valves (MSIVs) when the control circuit must be repaired (pneumatic or electric)? Normally a stroke test would be required, however, 4
NUREG-1431, Improved Standard TS, Section B3.72 (SR 3.7.2.1) l states: "MSIVs are exempt from the ASME Code Section XI requirements during operation in Mode 1 or 2."
1 i
As discussed in the NUREG-1482, Section 4.4.4, if the licensee can demonstrate that the performance parameters will not be adversely affected by maintenance, relief is not required to defer post-4 maintenance testing to the first opportunity when testing is allowed.
If the maintenance could affect the performance parameters and the licensee has no alternate to ensure that the operational readiness of the component is maintained, the licensee may need to shut down the plant to perform the post-maintenance test.
This guidance is also j
applicable to MSIVs.
}
2.1.6 The Code requires testing of valves which have had maintenance that 4
could affect stroke time.
"An interpretation exists" which states that if an engineering evaluation is performed that concludes that maintenance d'd not " adversely" affect stroke time, testing can be i
deferred to the next regularly scheduled performance test. What parameters should be included in this evaluation?
l A3-19 l
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i
i-l
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j NUREG-1482, Section 4.4.4 provides detailed guidance on stem packing adjustment and backseating of valves to prevent packing leakage when post maintenance testing in the current plant mode is impractical.
i Testing may be deferred to the first available opportunity when plant conditior.s allow testing, which may not necessarily be the next scheduled performance test. The licensee must justify by analysis, among other things, that: the packing adjustment is within torque limits 1
specified by the manufacturer for the existing configuration of packing, i
the backseating does not deform the valve stem, and the performance parameters are not adversely affected. Backseating can damage the valve
.i and/or cause the actuator not to be able to close the valve.
For i
1
}
maintenance activities, other than backseating and stem packing i
adjustment, that could affect the valve's performance, post-maintenance l
testing would be required, unless the licensee has an alternate to 1
ensure that the operational readiness of the component is maintained.
The staff.is unable to identify other general parameters as they may be i
different for individual valves.
l 2.1.7 The 1986 Edition of Section XI lists valve stem packing adjustments as "cause" for verifying valve operability by stroking and timing the valve.
If a threshold value for maximum packing torque utilizing vendor and other information is established and that value is never exceeded on an as-left basis, can that serve as justification to not do post-packing adjustment valve stroking if validation testing to support this position for all typet of power operated valves is conducted? What would the NRC be looking for if it were to consider approving such a position?
Since packing adjustment is one type of maintenance that could affect valve performance, a post-maintenance test must be performed, unless'a plant-specific testing program justifies an alternate.
Detailed guidance is provided in NUREG-1482, Section 4.4.4 when a post-maintenance test is not practical to be performed in the current plant mode.
2.1.8 At times there are a group of valves that are all operated from one control switch.
Stroke timing these valves requires the control switch to be activated repeatedly, for each of the valves to be timed. There is not enough personnel to be at all the locations to allow one initiation of the control switch. Once the first valve is timed, could this be considered preconditioning for the remaining valves? Could the staff provide examples of preconditioning?
The IST program is intended to assess operational readiness. The licensee should ensure that repeated operation does not significantly affect the valves' stroke times, and therefore, the ability of the licensee to assess the valves' operational readiness.
It would appear prudent, from a preconditioning and avoidance of excessive equipment cycles standpoint, to obtain extra personnel during the timing. While good practice, the Code, however, does not require valves, other than relief valves, to be tested in the as-found condition. The staff in NRC A3-20 i
i i
Information Notice 97-016, " Preconditioning of Plant Structures, Systems and Components Before ASME Code Inservice Testing or Technical Specification Surveillance Testing," provides examples of preconditioning that adversely affect the ability to assess operational readiness.
2.1.9*
Some containment isolation valves which are normally open and required to close, have a safety function in both positions.
Is it acceptable to classify them as passive open, active closed? If yes, does the valve need to be stroke timed in both directions?
If a valve is required to change obturator position to accomplish a required safety function, the valve is defined as active. The Code does not recognize valves that are active in one direction and passive in the other direction. The valve is either active or passive. The valves which are subject of this question are required by the Code to be exercised and stroke timed in both the open and closed direction, since they have a safety function in both positions. The Code requires valves to be exercised to the position (s) required to fulfill its function (s).
2.1.10*
If a valve receives an open engineered safeguards signal.and later in the accident is throttled by the operator, does the valve have a closed safety function?
In evaluating whether a component is within the scope of the IST program (and has a safety function in a specific direction), the licensee must consider the plant safety analysis report, TS, and design basis documentation. A determination of applicability usually cannot be made without consulting all of these documents. As to the specific example cited in the question, there is not enough information to make a determination of the valve's closed safety function.
Howeve, the Code requires valves to be exercised to the position (s) requireo to fulfill its function in shutting down the reactor to the safe shutdown condition, maintain the shutdown condition, or mitigate the consequences of an accident.
The Code would require exercising to the throttled position, if this is required for the valve to fulfill its function.
In addition, valves'that are only used for system control are exempt from the Code requirements for their control function, but not their function to either open or close.
2.1.11 If there is a small chance that a valve may for a short time be considered " active," but it is usually passive, must it be tested as an active valve?
If the -licensee has classified the valve as active, it should be tested as an active valve. However, as discussed in NUREG-1482, Section 2.4.2, a valve need not be considered active if it is only temporarily removed from service or from its safety position for a short period of time.
A3-21
2.1.12 Does the NRC plan to issue any additional testing requirements for air-operated valves?
The NRC continues to monitor the efforts of the industry to evaluate A0V performance and share lessons-learned from A0V programs that are being developed at several plants (e.g., NRC Information Notice 96-68,
" Incorrect Effective Diaphragm Area Values in Vendor Manual Result in Potential Failure of Pneumatic Diaphragm Actuators"). Any decision to prepare regulatory guidance on A0Vs will be based on the NRC's evaluation of A0V performance.
It should be noted that the ASME has recently approved a standard on hydraulically and pneumatically operated valves, Part 19.
This will be published with the 1998 Addenda of the r
l 2.1.13*
What is the expectation for testing a valve when the valve has redundant' activation systems or air supplies? If there are two air supplies, one safety-related and one non-safety-related, is it required that quarterly valve stroking with the safety-related source be performed?
The Code does not specify which actuation system is required for testing.
Therefore, the quarterly stroke test can be performed with either system.
However, the licensee must still have assurance that the valve will perform its design basis function.
Fail-safe testing of valves must be done without any source of actuating power. NUREG-1482, Section 4.2.4 contains additional guidance on fail-safe testing.
TS functional testing may require testing of actuation systems.
2.1.14 For valve testing in accordance with ASME OMa-1988, Part 10 (OM-
)
10), if a utility elects to immediately retest a failed valve (i.e., above the stroke time acceptance criteria specified in Paragraph 4.2.1.8, but less than the limiting stroke time), and the retest also exceeds the acceptance criteria but is less than the limiting value of full-stroke time, how does the 96-hour review time relate to the TS action statements? Is this a change in philosophy, or will the valve be considered inoperable from the time the first stroke time was measured?
0M-10, Paragraph 4.2.1.9(b), " Corrective Action," specifies that valves which do not meet the acceptance criteria of Paragraph 4.2.1.8 shall be immediately retested or declared inoperable.
If the valve retest stroke time exceeds the acceptance criteria, the licensee has 96 hours0.00111 days <br />0.0267 hours <br />1.587302e-4 weeks <br />3.6528e-5 months <br /> to analyze the data to ensure that the new stroke time represents acceptable valve operation.
Paragraph 4.2.1.9(a) states that if the valve exceeds the limiting stroke time, it shall be immediately declared inoperable. The 96-hour analysis period does not apply to valves which exceed their limiting stroke time.
i NUREG-1482, Section 3.2, provides guidance in situations where valves exceed their limiting stroke time.
It recommends that test procedures i
include test parameter reference values and acceptance criteria to enable the individuals performing the test to quickly determine whether i
A3-22 a
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i the valve meets the stroke time requirements and ensure it is operable.
If the valve is determined to be inoperable and the licensee has determined that an engineering analysis is appropriate to determine if the component can be returned to service (i.e., if the limiting stroke time, which was exceeded, is less than the design basis stroke time for this valve), the analysis would typically be performed within the time limits of the TS action statement.
Further guidance is contained in GL 91-18, Enclosure 2, Section 6.11.
Exceeding the acceptance criteria of Paragraph 4.2.1.8 does not require the component to be immediately declared inoperable.
Exceeding the limiting stroke time of the valve, the technical specification stroke time, or the design basis stroke time, which ever is the most conservative, does require the component to be declared inoperable.
This is not a change in philosophy.
If the initial and retest valve stroke time. exceeds the acceptance criteria in Paragraph 4.2.1.8 but remains below the limiting stroke time, the starting time in the TS action statement begins if and when the valve is subsequently determined inoperable sometime during the 96-hour analysis period.
(Reference NUREG-1482, Appendix A, Page A-24) 2.1.15 OM Part 10, Paragraph 4.2.1.9 allows the use of analysis to verify J
that the new stroke time represents acceptable valve operation.
What does the NRC define as an acceptable analysis?
The NRC does not have specific guidance published that defines what constitutes an acceptable analysis to assess the operation of power-operated valves which exceed the ASME Code acceptance criteria.
It is 2
acceptable for licensees to review 1) past test and maintenance trends to ensure that the valve will not fail before the next scheduled test, 1
- 2) system requirements, 3) the margin between the test data and the limiting stroke times, 4) SAR assumptions, and 5) TS limits.
2.1.16*
In developing a basis for acceptance criteria for stroke time testing of valves, if the FSAR, TS, and enhanced design basis documents do not contain a specific limiting stroke time for a valve, is it acceptable to use ASME Section XI methodology to establish reference values and acceptance criteria for the valve, or do valve specific analyses need to be developed for each valve to demonstrate use of ASME methodology is conservative prior to its application?
As discussed in NUREG-1482, Section 4.2.7, GL 89-04, Position 5 remains acceptable guidance for establishing limiting values.
Limiting stroke times may be established based on reference values. The purpose of the limiting stroke time is to establish a value for taking corrective action on a degraded valve before the valve reaches the point where there is a high probability of failure to perform its safety function if called upon.
A3-23
2.2 VALVE POSITION INDICATION j
2.2.1*
NUREG-1482 states that position indication verification tests need only be performed on those lights used for stroke time testing.
Is the licensee required to verify alternate lights (e.g., local panels or auxiliary shutdown panels)?
As discussed in NUREG-1482, Section 4.2.6, the Code committee stated in Interpretation XI-1-89-10, that only the remote position indicator at the location utilized in exercising the valve and timing the stroke time must be verified for accurately indicating valve operation.
This pertains to testing performed in accordance with the Code.
If local l
panels or auxiliary shutdown panels are used in exercising or stroke timing the valve, these indications would also be required to be verified.
2.2.2 ON-10, para. 4.1 states that " valves with remote position indicators shall be observed locally at least every 2 years to verify that valve operation is accurately indicated." Please expand on " remote position indicators." Is remote position indication limited to red / green lights or does this include position indicators that serve alarms and permissive logic?
Are the IST testing requirements different for:
(1) a manual suction isolation valve for an ECCS pump that is a Category B passive valve, excluded from testing as a valve used only for system maintenance, and that has a position indicating device that signals a pump start permissive, and (2) the same valve with red / green indicating lights to indicate valve position so that the operators can determine valve position prior to a pump start?
As discussed above, position indication verification is only required by the Code for those indicator (s) used during the exercise test and stroke timing.
Indicators that may provide input to a pump permissive would not be required by the Code to be verified, unless they were used during the valve exercise test. The example provided states that the valve is excluded from testing since it is a valve used only for system maintenance.
Part 10, Paragraph 1.2(a)(3), exempts this valve from all the requirements provided in Part 10, including valve position verification.
It should be noted that Category A and B passive valves, not excluded from the requirements of Part 10, are required by Table 1 to have their position indication verified.
2.2.3*
Is the intent of the Code to require position indication verification to ensure that the test results are correct, as implied in NUREG-1482, Section 4.2.5, or to verify that the valve's position is correctly indicated for any circumstance? Based on Interpretation XI-1-89-10, which states that position indication is only required to be verified at the indicator at the location used 1
A3-24
in exercising the valve and timing the stroke, why are passive i
valves (which are not required to be stroked) required to have i
their position indication verified? prior to the 1977 Code, passive valves were excluded from position indication verification.
The NRC cannot comment on the intent of the Code. As discussed in i
NUREG-1482, Code Interpretation XI-1-89-10 is acceptable to the staff.
Position indication is only required to be verified for the indicator at the location used in exercising the valve and timing the stroke.
l 2.2.4*
Is the presence of administrative controls for passive valves with valve position indication an acceptable basis for relief?
Administrative controls would be acceptable if the licensee demonstrates that the alternative provides an acceptable level of quality and safety, or that complying with the Code requirements would result in a hardship or unusual difficulty without a compensating increase in the level of quality and safety in accordance with 10 CFR 50.55a.
)
2.2.5*
Does a passive valve secured or failed in its safeguards position (i.e., locked, or air supply isolated) require position indication verification?
The Code (0Ma-1988 Part 10, Table 1) requires valve position indication verification for all Category A and B passive valves. The valve position indication verification requirements must be met, even for valves in systems out of service.
2,.2.6*
OM-10, parag aph 4.1 states, for position indication testing, "where pract cable, this local observation should be supplemented by other indications'such as use of flow meters or other suitable i
instrumentation to verify obturator position."
Is it the NRC i
expectation that all valve position verification testing be supplemented by "other indications" unless documented specifically as "not practicable," or is this requirement only applicab to j
valves w11ch cannot be locally observed?
l If practicable, local observation should be supplemented by other indications to verify obturator position.
Licenses could explicitly document the cases where other indications are not practical (e.g., in 4
their bases document), however, there is no code requirement to provide documentation.
If, however, it is not documented, licensees should be prepared to answer such questions to NRC inspectors.
If local observation is not practicable, other indications must be used, as discussed in NUREG-1482, Section 4.2.5.
1 k
t a
J A3-25 p-m
2.2.7*
Does the Code require valve position verification be performed in both directions (i.e., open and closed, even if the valve only has a safety-related function in one direction)? Please clarify the response to Comment 4.2.6-1 in Appendix 6 of NUREG-1482.
The Code requires position indication verification to " verify that valve operation is accurately indicated." There is no restriction to only perform this. verification in the safety-related direction. However, the Code could be interpreted that verification is only required for the safety-related direction, and that is why the recommendation to verify both directions was deleted from Section 4.2.6 of Draft NUREG-1482 that was issued for public comment, as discussed in response to Comment 4.2.6-1 in the final NUREG.
2.2.8*
For certain types of valves that can be observed locally, but for which valve stem travel does not ensure that the stem is attached to the disk, the local observation must be supplemented by other indications.
If this test is not practicable, such as lack of instruments to observe operating parameters, does this Code requirement apply?
Yes, when local observation is not possible, the Code requires that other indications must be used.
If this is not practical, relief must be requested.
2.2.9*
The Code (0Ma-1988, Part 10, Paragraph 4.1) states that local observation and observation of other indicators, if practicable, need not be concurrent.
Is observation of other indicators any time during the two years acceptable or would the observations have to performed at a two year frequency?
The Code requires valves with remote position indicators to be observed locally at least every 2 years to verify that valve operation is accurately indicated. Where practicable, this local observation should be supplemented by other indications. These observations need not be concurrent.
If the local observation and observation of other indicators is not concurrent, then the 2 year interval should be applied when both verification methods are complete.
2.2.10 Is 90% or 95% of valve travel indication (i.e., where you set the limit switches) sufficient for a full stroke?
The Code requires licensees to full-stroke exercise valves to the position (s) required to fulfill its function (s) and to " verify that valve operation is accurately indicated."
If the licensee has determined that 90 or 95% of valve travel is the position required for the valve to fulfill its function, indication of this range of travel is acceptable.
A3-26
2.2.11*
Is it acceptable to use " normal plast operation" (i.e., no specific action) to provide the " supplemental" position verification required by ISTC 4.17 There are no restrictions concerning verifying position indication during routine or normal plant operhtion.
However, the observations must be documented in plant records at intervals no greater than 2 years to meet the provisions of the Code.
2.3 CHECK VALVES 2.3.1*
In paragraph ISTC 4.5.4(3) of the OM Code, what does "each nonintrusive technique is qualified" mean? What is expected? Is acoustic monitoring training by vendors acceptable?
A " qualified" non-intrusive techniq1e (NIT) is a technique has been successfully and reliably demonstratad for the examination method and specific valve application.
It is the. licensee's responsibility to qualify and document the results. The licei. ee may have qualified the technology and application on its own equipment, subcontracted to a vendor, or relied on the results of Nuclear Industry Check Valve Group l
(NIC) evaluation of nonintrusive diagnostic technologies for check l
valves, conducted at the Utah State University Foundation Water Research l
Laboratory. The NRC inspector may examine the licensee's records.
l Personnel training and qualification performed by a vendor in accordance with the licensee's quality assurance program may be acceptable, however, the technique must also be qualified, as discussed above.
2.3.2 When submitting relief for disassembly and inspection, do you need to discuss nonintrusive testing?
When proposing to perform disassembly and inspection in accorJance with the guidance in GL 89-04, Position 2, relief is granted pursuant to the GL. The licensee should document the activity in its IST program.
For disassembly and inspection frequencies that are not in accordance with GL 89-04, approval of a relief request is required.
In any review or evaluation of a check valve relief request involving disassembly, the staff will typically inquire as to the extent that nonintrusive test techr.iques were ex lored, recognizing the extensive work that has been d?ne in this area NIC.
2.3.3*
For check valves with an open and closed safety function, how long l
after open verification testing must closure be verified? In other words, when the differential pressure causing the valve to open is l
removed, must verification of closure be immediate?
1 The practical method is to check closure after pressure decay.
l Otherwise flow through the valve may have to be reestablished to i
determine if the disc returns to the seat upon flow reversal. There are no requirements for these tests to be performed sequentially; however, l
the test interval requirements must be met for each test.
l I
A3-27 l
2.3.4 For a check valve in a line that supplies cooling water to an EFW pump with the water supply being a condensate tank, where the flow of-cooling water is constant regardless if the pump is operating or not, can this check valve be considered passive open? If not, can it be considered " skid mounted?"
A The disk of this check valve is not locked in position and responds to flow parameters, therefore, the valve is not passive. NUREG-1482, Section 3.4, provides guidance for determining if the valve is skid-mounted, and_can adequately be tested during the test of the pump.
2.3.5
-The Code requires full open and close testing for check valves.
I However, where non-intrusive methods are used, trending is additionally required. What is the NRC position on th's trending?
J The Code does not currently require trending for the IST open and close exercise tests even when using non-intrusive techniques. However, trending is a good tool for assessing the valve's condition or the need for maintenance. Nonintrusive techniques provide an opportunity to j
perform trending.
j 2.3.6 Does the NRC staff have problems with the condition monitoring appendix (i.e., Appendix II of OMa-1996) for check valves as it is currently written? When will this appendix be approved for use (if it is being reviewed separate from 0Ma-1996)?
4 l
Condition monitoring is being considered in the current rulemaking process. There are some concerns with Appendix II, such as, no maximum 4
limits on extending test intervals, no consideration of the safety impact on the plant when the interval is extended, no requirement for testing and examination of the valve in the open and closed directions, and no consideration of trending of the valve's condition, performance j
and/or degradation to justify test and examination interval extensions.
I 2.3.7 When full flow testing check valves, what instrumentation requirements should the licensee consider when establishing flow criteria? Do the flow instruments have to meet i2% accuracy? If the accuracy is 23%, is it acceptable to add 3% to the required full flowrate, and establish that value as the acceptance criterion?
The Code does not currently specify instrument accuracy requirements for valve testing. The IWP or 0M-6 accuracy requirements related to pump testing need not be met for the valve test. The Code Committees have i
recently approved an action to address instrumentation requirements in l
ISTC.
The proposal requires instrumentation used for valve testing and examination to be properly controlled, calibrated and adjusted in accordance with the owners QA program, and have the accuracy, range, and repeatability characteristics necessary to verify compliance with the Code. Additionally, instrument accuracy must be considered when i
establishing valve test acceptance criteria (ROM 96-01). The licensee j
must be certain that the maximum required flow passes through the valve A3-28 4
or that the valve is fully open.
Instrument accuracy should be considered when determining the maximum required accident flowrate.
l l
2.3.8*
What are the instrumentation and/or diagnostic equipment accuracy requirements for equipment used for non-intrusive testing? Does the NRC have a reference document that gives the owner acceptable guidance for using this equipment for safety-related determinations?
There is no NRC reference document that provides guidance on the use of l
diagnostic equipment for nonintrusive check valve testing.
Requirements i
for instrumentation used for check valve testing and examination (for example:
application, suitability, accuracy, range, and repeatability) are the responsibility of the licensee. NIC is working with member i
utilities to develop industry guidance for the use of nonintrusive test (NIT) techniques for check valve testing.
2.3.9 Is testing check valves in both the open and closed direction i
mandatory?
The version of the Code referenced in the regulations requires check valves to be tested in both the open and closed direction if they have a safety function in both directions. However, testing all check valves in both directions, even if they only have a safety function in one direction, provides additional assurance the valve will perform its safety function (s). For example, if there is only a forward flow requirement, the valve will pass that test with the disc missing or laying in the bottom of the valve, yet under LOCA conditions the disk may have moved to block flow. The Code has been revised in the 1996 Addenda to state that exercise testing shall be demonstrated by performing both an open and close test.
2.3.10*
At what frequency are passive check valves tested that have a safety-related function in closed position only (e.g., containment isolation valve for auxiliary steam to containment)?
Check valves are generally not considered passive unless they are positively held in place (e.g., a stop check) or flow is blocked (e.g.,
by a closed manual valve upstream).
Licensees are referred to the discussion in Section 4.1 of NUREG-1482. The example referenced in the question does not appear to be an example of a passive check valve.
There are no Code requirements for passive non-category A/C check valves, as Table ISTC 3.6-1 does not address these valves.
2.3.11 If excess flow check valves can be classified as " passive" per the safety / design analysis and leakage through the valve seat is not important, what Code tests need to be performed for these excess flow check valves?
The ASME Code requires that components which mitigate the consequences of an accident be included in an IST program.
BWR excess flow check valves located outside containment on instrument lines that penetrate i
!~
A3-29 I
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containment are normally open and have a safety function to close to prevent loss of reactor coolant system inventory on an instrument line break outside containment. Because the valve has to move from the open to closed position to perform its safety function, these valves I
do not satisfy the definition of passive valves as stated in the ASME I
Code.
Further guidance on the requirements of excess flow check valves is included in Regulatory Guide 1.11 (Safety Guide 11),
Instrument Lines Penetrating Primary Containment."
There are very few instances in which a check valve is considered passive using the definition of passive valves in the ASME Code. One example is when a check valve is downstream of a manual or power-1 operated valve that is either locked or administratively verified l
closed. A check valve which has only a closed safety function and is not required to open to perform its safety function would still be 1
regarded as an active valve unless it was isolated as described above.
4 2.3.12 If a check valve is normally closed, and opens slightly to keep the system pressurized, should it be considered active?
i Yes. Check valves are considered active unless they are positively l
held in place (e.g., a stop check valve) or flow is blocked. See l
NUREG-1482, Section 4.1.
2.3.13 If check valves are disassembled and inspected at refueling outage frequencies, and the performance history has been excellent, can the inspection frequency be extended to 10 years or more, to prevent damaging good valves with disassembles?
GL 89-04 allows a sample disassembly and inspection plan with an l
inspection interval of 6 years.
Extension of the interval should only l
be' considered in cases of extreme hardship where the extension is supported by previous testing / maintenance data. Justification of l
extreme hardship is discussed in NUREG-1482, Appendix A, Question l
Group 19. The extension of a check valve's inspection interval is subject to NRC inspection. The OM Code was revised in the 1996 Addenda to include a condition monitoring program, as a means of justifying interval extensions. This Code Addenda has not yet been l
endorsed by the NRC and the staff has some concerns regarding this revision. See response to Question 2.3.6.
2.3.14 Must IST disassembles be listed separately in the IST plan for both l
open and closed testing, or can the IST plan state that " component disassembly" is the test alternative and provide the bases for this rationale in plan footnotes and bases document?
Either format is acceptable to the NRC, provided the IST program indicates in some way that exercising in both directions, if required, is being verified by disassembly and inspection. The test results should clearly indicate both directions were demonstrated.
l l
A3-30 l
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2.3.15*
The spray additive tank vacuum breakers (two on one tank, which serves both safety trains) permit outflow of NaOH for iodine removal. The valves do not protect the tank, but do have an adjustable set point (spring loaded swing check), and are not capacity ratad. Do these valves require testing as relief valves (i.e., per Appendix I or Part 1)?
i It is the responsibility of the licensee to determine the scope of components in the IST program and to classify those components in accordance with the Code. NUREG-1482, Section 4.3.8 provides guidance on vacuum relief valves.
Since publication of the NUREG, the ASME OM Code committees have proposed some Code changes:
If the check valve is a capacity certified valve, then it shall be classified as a pressure or vacuum relief device and tested in accordance with Appendix I; If the check valve is not a capacity certified valve, it shall be classified as a check valve and tested in accordance with ISTC.
This proposal is currently under consideration and has not been approved by the Code committees. Pending endorsement of the OM Code which addresses this issue, use of this clarification is acceptable.
Licensees should document this approach in the IST program.
2.3.16 Should check valves which provide overpressure protection for containment penetrations be classified as relief devices and tested per OM-1, or should they be treated as Category A/C check valves and tested per 0M-107 If both apply, for setpoint testing per OM-1, does the ISTC requirement of breakaway force not exceeding 50%
of reference value apply?
As discussed in the previous response, check valves would only be tested as pressure relief devices if they are capacity certified.
Both Part 10 and Part I would not apply. The breakaway requirements of Part 10, Paragraph 4.3.2.4(b), only apply if the licensee is using a mechanical exerciser to exercise a check valve.
If the valve is exercised open with flow, the breakaway requirement in Part 10 does not apply.
2.3.17 If check ~ valves are treated as relief devices, can they be tested during the performance of the LLRT at the Appendix J, Option B interval?
Pressure relief devices may be tested during the Appendix J test, provided the Code test frequency requirements are met.
Otherwise, a request for approval of an alternate frequency would be required.
2.3.18 For partial stroke testing of check valves, is a criterion such as any flow acceptable? Or should a quantitative value be established?
Generic Letter 89-04, Position 1, states that an acceptable verification of a full-stroke exercise of a check valve can be performed by passing the maximum required accident condition flow through the valve. Any flow rate less than this is considered a A3-31
partial-stroke. The guidance in Position 1 did not sti partial-stroke test had to include a quantified value, pulate that the such as a flow rate. However, the licensee typically would ensure that the criteria used to verify a partial flow test be related to system operation, whether it be a change in system pressure, flow, or another parameter.
2.3.19*
In NUREG/CP-0152, Proceedings of the Fourth NRC/ASME Sym)osium on Valve and Pump Testing, a paper written by NRC staff men)ers entitled, " Summary of Inspection Findings of Licensee Inservice Testing Programs at United States Commercial Nuclear Power Plants,"
included an inspection finding on page 2C-21 which implied that quarterly nonintrusive testing of check valves on a sampling basis was required if the testing was practical.
Can this finding be clarified?
The inspection finding cited in the referenced paper appears to imply that the guidance in NUREG-1482, Section 4.1.2, where a sampling plan may be employed for NIT of a group of check valves, applies to all frequencies (i.e., quarterly, cold shutdown, refueling outage) where testing is practicable. However, it is the licensee's responsibility to determine at what frequency valve testing is practicable.
The determination of the practicability of exercising with flow should be considered separate from the practicability of using NIT.
Section 4.1.4 of NUREG-1482 states that the need to set up test equipment is adequate justification to defer backflow testing of check valves to a refueling outage frequency. Although not stated in NUREG-1482, this guidance could be applied to the use of NIT for forward flow testina of check valves as well. This should be documented in the licensee's IST program. As an example, it may be practicable to exercise a group of check valves with sufficient flow to fully open the valves quarterly; however, NIT may only be practicable to use on a refueling outage basis due to the need to setup equipment. Therefore, one valve of the sample would be verified using NIT for forward-and reverse-flow testing (if reverse-flow testing is required) at refueling outages, while all four valves in the group would be exercised with flow quarterly.
2.3.20 If NIT can be performed quarterly on a check valve which is currently being disassembled and inspected each refueling outage in accordance with GL 89-04, Position 2, what justification would be considered by the staff to perform the non-intrusive test each refueling outage?
As stated in the previous question, it is the licensee's responsibility to determine and document the frequency that check valve testing using NIT on a sampling basis will be performed.
The licensee should refer to the guidance in NUREG-1482, Section 4.1.2.
A3-32
l.
2.3.21 Using NIT for check valves, can " similarity" be used for i
establishing baseline data for valves? If a utility has 10 valves j
that are the same size and manufacturer, can a baseline test for one valve be used on the remaining valves?
No. As discussed in NUREG-1482, Section 4.1.2, during the initial or baseline test, all valves should be subject to NIT to verify that the flow / pressure conditions specified in the test procedure cause the valve to fully stroke. After the initial test, valves in the group can be tested with NIT techniques on a sampling basis, i
2.3.22 If water hammer is only postulated to occur during a loss of i
coolant accident (LOCA) with station blackout, are check valves required to be included in the IST program, if they are only provided for water hausner prevention? Or do they fall under j
protection function not covered by the Code?
It is the responsibility of the licensee to determine the scope of j
components in the IST program. The Code addresses pumps and valves required to perform a specific function in shutting down a reactor, l
maintaining the shutdown condition, or mitigating the consequences of an accident. NUREG-1482, Section 2.2, provides clarification that the
" accident" refers to the accident analyses in the safety analysis j
reports.
Licensees should review their plant updated FSAR.
1 i
2.3.23 The response to Question Group 15 (Appendix A, NUREG-1482) states i
j that check valve disassembly is not considered a " test," and that disassembly is not a true substitute for an operability test using i
flow, but is allowed as an alternate to flow testing where that test is not practical. - Has the NRC changed their position on check j
valve disassembly as a test versus an alternate?
No. The staff's position is that check valves should be tested with flow, if practical.
If testing with flow is impractical, disassembly and inspection is an acceptable alternate.
2.3.24 If a relief request has been approved for a check valve to be disassembled and inspected every 6 years, can the disassembly and inspection be done at a time other than refueling outages?
The answer will depend on the relief request's basis and the staff's j
evaluation of the request.
If the basis or the NRC evaluation is based on the premise that disassembly and inspection can only be performed during refueling outages, and if the disassembly and 1
inspection can, in fact, be done at other times, the request would be invalid. Testing in accordance with the Code would be required unless
]
a revised request was submitted. GL 89-04 Position 2 allows disassembly and inspection to be performed during refueling outages due to the scope of testing, personnel hazards and system operating i
restrictions, which make disassembly during operation impractical.
If i
disassembly and inspection is practical during times other than 1
refueling outages, specific relief would be required.
1 A3-33 4
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'2.3.25 If a licensee has received relief for check valves to be exercised at refueling outages (i.e., using NIT) based on the difficulty of i
installing equipment, but the licensee can exercise the valves at I
power, is the relief valid or must the valves be exercised every quarter? Should post-maintenance testing in extreme cases count in basis?
The basis of the specific request and the staff's evaluation would need to be reviewed to determine if the request is still valid.
If
^
the basis is based on the hardship or difficulty (i.e., approved pursuant to 50.55a(a)(3)(ii)), as opposed to impracticality (i.e.,
j relief granted pursuant to 50.55a(f)(6)(i)), the ability to perform quarterly testing would not necessarily invalidate the request.
If l
the request is greated based on the impracticality of testing quarterly, very seldom performed post-maintenance tests may not invalidate the request, however, the request would need to be reviewed.
l 2.3.26 Have any relief requests been approved to allow safety injection tank outlet check valve testing (NIT) on a rotating basis? If disassembled, they are only required, based on approved relief, to be opened, one valve per outage.
If a NIT method is utilized, is this frequency still applicable?
NUREG-1482,.Section 4.1.2 allows the use of non-intrusive techniques i
on a sample basis. However, each of the valves in the sample must be i
i tested with flow when practical, e.g., at each refueling outage. A request to extend the test frequency beyond each refueling outage when i
using NIT techniques has been submitted by one licensee, however, sufficient justification was not provided to the staff, and the request was denied. See NUREG/CR-6396, S6ction 2.2.3 for additional information.
i l
2.4 RELIEF VALVES 2.4.1 NUREG-1482, Section 4.3.9, states that sample expansion is required if the as found test exceeds the greater of the owner established tolerance limit or i3% of the set pressure.
If the technical specification tolerance is t1% of setpressure for the BWR main steam safety valves, should sample expansion requirements be applied if the setpressure is out of tolcrance by more than 1% or 3%? Some plants expand sample when more restrictive technical specification requirements are exceeded and are spending significant sums of money to change technical specification tolerances to 13%. Other plants follow the guidance of NUREG-1482, and do not expand the sample until the drift exceeds 3%. These valves protect a reactor safety limit. What is the correct requirement for sample expansion?
Licensees need to review and meet the technical specification requirements.
Licensees may submit an application, with appropriate justification, to have those limits changed.
However, the 1994 A3-34
Addenda of the OM Code, Appendix I only requires additional testing if the valve exceeds 13% of valve nameplate set-pressure or the tolerance limit of the owner established set pressure, whichever is greater. As discussed in NUREG-1482, Section 4.3.9, this clarification may be used without further NRC approval, unless a technical specification limit is involved.
In the example discussed above, testing expansion would be required if the valves exceed 3% of the setpoint (per the Code) 2r if the TS required additional valves to be tested when the valves i
exceed 1%.
4 2.4.2 OM-1 and NUREG-1482 state "0wner established engineering basis."
What parameters arc required to be included in such basis?
The Code (1994 Addenda and later) and NUREG-1482 discuss owner-established set pressure acceptance criteria. Appendix I, para.
1.3.1(e) states that the acceptance criteria should be based upon system and valve design bases [ sic] or TS.
2.4.3 Can licensees use owner specified acceptance criteria (0Mc-1994) to define setpoints for relief valves while testing under 0M-1-1981 or 0M-1-19877 NUREG-1482, Section 4.3.9 allows the use of clarifications provided in the 1994 Addenda of the OM Code.
Licensees can use the greater of either the tolerance limit of the Owner specified acceptance criteria, or 3 % of valve nameplate set pressure when determining the requirements for testing additional valves.
2.4.4 When adding relief valves to an IST plan in the middle of 10-year IST interval, can the valves be scheduled over the remaining
. interval or do all the valves have to be tested immediately?
The issue concerning components that are added to the IST program as a re'sult of a " Code non-compliance" is discussed in NUREG-1482, Section 7.
This situation could be considered a missed surveillance and the licensee should use the guidance provided in GL 91-18. A justification would be required to continue plant operation if testing could not be performed immediately.
2.4.5 0M-1-1987 increacas the scope of relief valves required to be tested in tho'IST program. During a program update to 0M-1, should preservice tests be performed prior to the start of new interval for the valves added to the program 7 There is no Code requirement to perform preservice tests for those relief valves added to the program as a result of Code revisions.
Appendix I does not require baseline or reference values to be established for relief devices.
A3-35
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I' 2.4.6*
With regard to relief valves tested at low temperature, but designed for elevated temperatures, what kind of temperature delta requires a correlation? Define elemted temperature? Is the difference between 70*F and 130*F s.gnificant (as an example)?
The Code requires a correlation when a " test medium (fluid and temperature), other than that for which they are designed," is used.
The Code does not provide a tolerance. The Code committees are l-evaluating this issue and so far have not reached a consensus on establishing a tolerance or limit. The limited data received from i-valve manufacturers to date does not indicate a limit or tolerance.
Therefore, at this time it is left to the engineering judgement of j
licensees, subject to NRC inspector review.
2.4.7 For cases where relief valves are tested at temperatures lower than the accident temperature, what steps should the licensee be taking when there is no correlation available between the test temperature setpoint and the accident temperature setpoint?
Licensees should contact the valve vendor to determine if a correlation is available. Alternatively, licensees should develop the correlation or evaluate sending valves to a test lab in order to comply with the Code.
If testing in accordance with the Code is impracticable, licensees should submit a relief request which includes, as a minimum, a discussion of the safety significance of the valve, the test and design temperatures, discussions with the valve i
i vendor, and why the valve cannot be bench tested at design conditions l
or why a correlation cannot be developed by the licensee.
2.4.8*
ON-1 is very specific on testing with alternate fluids for dynamic l
(blowdown) tests. Does the NRC expect as rigorous a correlation for static testing? Many testing vendors want licensees to test oil valves using water, so that their test equipment does not become fouled w th oil.
If head differences, temperature / density chan!)es, and appropriate weep points are used, is this sufficient?
l Are 'iconsees able to use only analysis for developing the correlation, or is test data needed?
OH-1 does not differentiate between static and dynamic tests. The l
Code requires a correlation if an alternate medium (i.e., fluid or l
temperature) is used. The Code requirements for the correlation must l
be met regardless if the test is static or dynamic.
Per 0M-1, para.
4.3.2, a test must be performed to verify adequacy of correlation.
Analysis alone is not sufficient to meet the Code requirements.
2.4.9 Do relief valves on the non-safety related component cooling water (CCW) header, which is connected to the safety related CCW headers, belong in the IST program? These valves protect non-safety related components.
l-A definitive determination would require a full review using the piping and instrumentation drawings and plant safety analysis report.
I A3-36
However, it would appear that since the relief valves do not protect safety related components, the code would not require testing.
The Code requires testing of relief valves that protect systems or portions of systems that perform a required function in shutting down the reactor to the safe shutdown condition, in maintaining the safe shutdown condition, or in mitigating the consequences of an accident.
(Note that a failure in the non-safety-related portion of the CCW system could affect the safety-related portion and the staff is assuming suitable isolation capability exists.)
2.4.10 Pertaining to GL 96-06, various plants are taking credit for non-safety relief valves to preserve the integrity of containment isolation valves. Should these relief valves be included in the IST program, and if so, would the temperature correlation apply since post-LOCA temperature is external to the valve with stagnant water internal?
The regulations only require ASME Code Class 1, 2, or 3 relief valves that protect systems or portions of systems that perform a required function in shutting down the reactor.to the safe shutdown condition, in maintaining the safe shutdown condition, or in mitigating the consequences of an accident to be in the IST program. However, relief valves which are being credited for preserving the integrity of containment isolation valves and are not ASME Code Class 1, 2, or 3 should, at a minimum, be tested in accordance with 10 CFR 50, Appendix B.
Portions of non safety-related piping may be Code Class 2 or 3 (at the containment penetration) and should a relief be installed pursuant to GL 96-06, the staff would expect it to be. included in the IST program.
If these valves are tested in accordance with the Code, a 1
correlation would be required since the valves may be tested using a medium (i.e., temperature) other than that for which they are designed.
2.4.11*
Are Safety Class 2 and 3, simple check valve style vacuum relief valves, without setpoint adjustment capability, required to be tested to the requirements of OM-17 The wording of NUREG-1482 states they are subjected to the *equirement of OM-10 and IWV as well as 0M-1, "if applicable." Piease clarify what is meant by "if applicable."
NUREG-1482, Section 4.3.8 provides guidance on vacuum relief valves.
The Code requires Code Category " check valves" to be tested in accordance with Part 10, Paragraph 4.3.2 and " safety and relief i
valves" to be tested in accordance with Part 1.
When more than one distinguishing. category characteristic is applicable, all requirements of each of the individual categories are applicable, although duplication or repetition of common testing requirements is not necessary.
Since publication of NUREG-1482, the ASME OM Code committees have proposed some Code changes:
If the check valve is a capacity certified valve, then it shall be classified as a pressure or vacuum relief device and tested in accordance with Appendix I; if the check valve is not a capacity certified valve, it shall be classified as a check valve and tested in accordance with ISTC.
This proposal is currently under consideration and has not been approved by the Code A3-37 t
committees.
Pending endorsement of the OM Code which addresses this issue, use of this clarification is acceptable.
Licensees should document this approach in the IST program.
2.4.12 If certain check valves are in the IST program ar.d design basis documents specify that their fur.ction is to provide overpressure protection, but the valves must only " pop" open relieving insignificant amount of water / steam (al) to prevent overpressure conditions in the event of trapped water heating and expanding due to CIVS closing to provide containment isolation, are these valves check valves or relief valves? Do they fall under testing 4
requirements (both direction testing) of check valves?
If the licensee has classified these valves as chack valves, they must be exercised in the direction (s) in which they perform a safety function. As discussed above, based on current discussions at the Code committees, these valves would be required to be tested as check valves if they are not capacity certified.
i 2.4.13 If an emergency service water system simple 1-1/2" lift check valve is being used as a relief valve at the pump discharge, does the 1983 Ed' tion of Section XI require this valve to be tested at design-basis conditions?
l If the owner has categorized it as a check valve, then it must be exercised to its full open position as discussed in GL 89-04, Position 1.
Otherwise, it would be tested as a pressure relief device in 4
accordance with Paragraph IWV-3510.
See the two previous questions and responses.
2.4.14*
Why are the Code's rupture disc replacement requirements so stringent, when the manufacturer's life is 40 yrs.?
This' question has been directed to the ASME OM Code committee for future consideration. The basis for the five year replacement schedule is not readily available.
i 2.4.15 ON-1 requires that rupture disks be replaced every 5 years. Do torus vent rupture disks fall into this category? Please note that many plants consider these disks as "beyond" design bases and, therefore, are not required to be tested under 0M-1.
They are only required to open. Approximately 99'% of the times, these disks are exposed to about 0 psid.
For the Appendix J, Type A test, these components see approximately 70% of system relief pressure, i
therefore, they are not challenged.
The Code requires testing of rupture disks that protect systems or portions of systems that perform a required function in shutting down the reactor to the safe shutdown condition, in maintaining the safe shutdown condition, or in mitigating the consequences of an accident.
NUREG-1482, Section 2.2 provides clarification on the term " accident."
l A3-38
e It is the responsibility of the licensee to determine the scope of the 2
IST program, in accordance with this guidance.
I 2.4.16 Based on recent ON-1 Working Group discussions, is the NRC in favor i
of testing and/or replacing BWR control rod drive (CRD) hydraulic i
control m it (HCU) rupture disks in accordance with licensee's c quality assurance program, instead of ON-17 i
This item is in the early stages of the Code ap)roval cycle. The staff does not have any significant problem wit 1 the concept of testing CRD HCU rupture disks in accordance with the licensee's QA l
program. NRC staff approval may be part of future rulemaking.
I 2.4.17 The vacuum relief valves on the service water pumps do not have a stamped relief pressure, do they only need to meet the open/close j
function?
l Yes, if the licensee has classified them as a check valve.
- However, if the licensee has classified them as pressure relief devices, the 1
requirements of Appendix I or Part 1 must be met.
1 l
2.4.18 NUREG-1482, Section 4.3.4-indicates some plants have categorized the BWR automatic depressurization system (ADS) valves differently (B/C vs. C). What is the NRC's current position on categorization of ADS valves? If proper justification is provided, wouldn't l
either designation be acceptable?
'It is the responsibility of the Owner to categorize the valves in i
their IST program. With proper documentation, either category may be i
acceptable.
Licensees should note that the OH Code has been revised (i.e., in the 1996 Addenda) to clarify that Category A and B safety and relief valves are excluded from the requirements of ISTC 4.1, Valve Position Verification, and ISTC 4.2, Inservice Exercising Test.
i Therefore, these valves will only be required to be tested in accordance with Appendix I.
As discussed in NUREG-1482, Section j
4.3.9, clarifications may be used without further NRC approval.
?
2.4.19*
Relief valves are often put into groups and then tested on a sampling basis. When this test is performed on line, during a planned LCO, and a valve fails, when must the additional va' ves be i
tested? If "a" train fails, is "b" train considered inoperable?
i Must an LC0 be entered immediately? Is the next planned "b" train i
LC0 soon enough?
i The Code does not specify when the additional testing should be done j'
when a relief valve fails the acceptance criteria.
Licensees would be l
expected to perform testing as soon as practical. The Code allows 3 months for testing a partial complement of valves.
Performance of all tests (including the required additional tests) within the 3 month period would be appropriate.
If the cause of the valve failure has i'
corrective action in accordance with the ASME Code or a justification been determined to be applicable to the other valves, immediate 4
k A3-39 i
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.. ~. - - - -
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L for continued operation in accordance with GL 91-18 may be required.
Any LC0 for the failed "a" train valve must be entered immediately.
The other valves in the group (e.g., the "b" train valves) would not necessarily be considered inoperable, unless the circumstances and test data so indicate.
2.5 MOTOR-0PERATED VALVES l
2.5.1*
In performing dynamic testing as part of periodic verification to l
develop a rate of degradation for the valve or valve group, how long will a valve be required to be dynamically tested if the results continually fall within the test equipment error band?
In GL 96-05, the NRC staff requests licensees to develop programs to periodically verify the design basis capability of safety-related motor-operated valves (MOVs). GL 96-05 provides guidance on various approaches in developing M0V periodic verification programs. The program developed by each licensee should ensure that changes in
- required performance resulting from degradation (such as those caused l
by age) can.be properly identified and accounted for.
2.5.2 Is it acceptable to request relief from MOV IST requirements as follows:
eliminate all quarterly stroke time tests, l
eliminate all non-refueling cold shutdown stroke time testing, keep stroke 1.13g test procedures. Use them on a refueling outage frequency to satisfy OMN-1 exercisina requirements and for certain post-maintenance testing, l
use GL 89-10 periodic verification to satisfy IST requirements for i
NOVs?
l The use of ASME Code Case OMN-1, with the provisions included in L
GL 96-05, would be an acceptable alternative. Specific approval of l
the alternative by the staff is, however, required. The staff would need to review the specific approach proposed by the licensee.
It is 4
l not clear from the question whether the proposed approach would be acceptable.
l 2.5.3*
Is it acceptable to perform design-basis testing on a very l
infrequent basis (i.e., substitute static testing most of the time) for globe valves since the valve stresses are essentially the same for both tests?
The staff does not have sufficient data to demonstrate that globe valves are not susceptible to degradation.
Licensees will be expected to justify their MOV periodic verification program for globe valves.
2.5.4 Can the response to GL 96-05 be used as the vehicle to switch IST of M0Vs from quarterly stroke time testing to force (Votes /Movats) j or motor power (mps) testing, if spa can be shown to be accurate A3-40 l
for purposes intended based on margin accuracy of test method, risk insights, and maintenance history?
Licensees can request relief to use Code Case OMN-1 in lieu of i
quarterly exercising as part of their GL 96-05 submittal.
Licensees should ensure that the diagnostic equipment has justified accuracy (such as for mpm testing) and can observe trends in the degradation of
-performance.
t 2.5.5*
If a licensee is using ASME Code Case OMN-1, and MOV design-basis information (required stroke time, leakage, etc.) is changed as a result of a reanalysis (similar to a design-basis reconststution),
would tests need to be done immediately after new IST reference values are calculated, or at the next time the MOV was scheduled for testing per Code Case OMN-1 before calculations were performed?
j A licensee must evaluate the effect of a reanalysis on the operability of safety-related equipment at the time of the reanalysis in accordance with GL 91-18. With respect to the OMN-1 program, the licensee will need to ensure:
that the margin is maintained until the next test for the MOV in question; that the information does not adversely affect the determined capability of any MOVs grouped with the MOV in question; and that sufficient information on M0V performance and potential degradation remains available for implementation of the OMN-1 program (for example, evaluate the need for additional static or dynamic diagnostic testing of MOVs).
I 2.5.6*
When conducting " design-basis verification tests" under ASME Code Case OMN-1, is it required to perform reference stroke-time tests in the open and/or closed direction, to validate assumptions or values published in design-basis calculations of record (for example, Updated Final Safety Analysis Report and design-basis document assumptions) in addition to other safety-related design-basis requirements?
i Plant TS have typically included requirements for the stroke time of MOVs as a principal criterion for MOV operability. Over the last few years, the NRC staff and nuclear industry have determined that stroke-time testing does not always provide adequate confidence that MOVs will perform their design-basis functions. This determination contributed to the development of GL 89-10, GL 96-05 and ASME Code Case OMN-1. At this time, most licensees use diagnostic equipment when testing MOVs for verification of their design-basis capability.
Although a measurement of stroke time alone may not be sufficient to 1
demonstrate MOV design-basis capability, the safety analysis report 4
and other licensing documents require safety systems to perform their function within a specific time period.
Therefore, licensees will be i
expected to ensure that the stroke time of MOVs being tested is consistent with the requirements for the safety system to operate within prescribed time limits.
Licensees may wish to revise their TS or licensing documents such that M0V operability criteria do not rely solely on the stroke time of the valve.
i l
A3-41
,n
2.5.7 Where is functional margin defined? Can you compare functional margin to safety margin?
In Section 2 of ASME Code Case OMN-1, "MOV functional margin" is defined as "the increment by which an MOV's available capability l
exceeds the capability required to operate the MOV under design basis i
conditions." Section 6.4 of the Code Case discusses the determination 1
(
of MOV functional margin based on required and available torque and l
thrust. Section 6.1 of the Code Case states that an acceptance criteria shall be based on the minimum amount by which the available stem torque must exceed the required design-basis stem torque, including consideration of equipment, analysis, and grouping t
uncertainties.
Section 6.2 of the Code Case requires that an MOV be declared inoperable if its functional margin does not meet the acceptance criteria.
Section 6.4.4 of.the Code Case discusses the determination of the MOV test interval and states that the interval i
l between tests shall be less than the anticipated time for the MOV i
functional margin to decrease to the acceptance criteria.
Some licensees have included a " safety margin" in their MOV calculations to compensate for unquantified general uncertainties in the test data, equipment, or methodology. The discussion'of MOV functional margin in ASME Code Case OMN-1 focuses on a reliable evaluation of required and available torque and thrust, and aging degradation with time. The Code Case does not address a " safety margin" as used by some licensees.
In applying OMN-1, licensees will need to have sufficient confidence in their test data, equipment, and l
methodology to allow the determination of M0V functional margin and acceptance criteria as defined in the Code Case.
2.5.8*
Position indication is not addressed in OMN-1.
Is verification required?
The Code Case addresses alternates to preservice and inservice tests.
Leak rate testing and position indication verification are still required to be performed in accordance with ISTC.
2.5.9*
Post maintenance testing in ASME Code Case OMN-1 could be drawback in applying the Code case.
Please comment.
As required by the Code Case, it is the licensees' responsibility to determine the level of testing required after replacement, repair, or i
maintenance. This may have to include static or dynamic performance testing. Although the tests required by the Code Case are more difficult, the decreased test frequency may outweigh the disadvantages. Additionally, post maintenance testing is moving toward more informative testing, even where licensees use the current Code requirements.
l A3-42
2.5.10 When stroking valves in the test mode, if the stroke time is greater than the design basis accident allowable (e.g., 3 to 4 times greater), are the valvos operable?
l The limiting stroke time should be developed considering the design l
basis allowable stroke time.
If the limiting stroke time is exceeded, per the Code, the valve would be considered inoperable. The valve in the example given would appear to be inoperable.
l 2.5.11 Have any licensees submitted a relief request to implement Code l
Case OMN-17 What is the advantage to using it? Are there any l
pilot plant efforts for OMN-17 One licensee has submitted a request for relief to implement Code Case OMN-1 in lieu of the quarterly stroke-time testing in the ASME Code.
The NRC staff is reviewing the relief request. Other licensees have also indicated an interest in submitting a relief request to implement i
l OMN-1.
The Code Case allows less frequent exercising and the testing i
provides information more indicative of the valve's condition and l
operational readiness.
2.5.12 If the NRC finds Code Case OMN-1 appropriate for use, could notification through the Federal Register be utilized as reference for utilities to implement in their IST program (e.g., the way IWE/IWL was referenced in the regulations)?
The proposed Rule change is expected to endorse OMN-1, with limitations similar to the limitations in GL 96-05.
(
2.5.13 Can OMN-1 be used for only some valves?
l l
Licensees may submit requests for selective application. The IST program would need to clearly differentiate to what valves Code Case OMN-1 was applied.
2.5.14 Is it the intent of the Commission to apply OMN-1 to all valves i
types (in entirety) that have electric motor operators as defined by the Code scope, even if they are outside of GL 89-10's scope?
At this time, the NRC does not plan to mandate OM Code Case OMN-1.
L The OM Code may, however, incorporate the Code Case into the Code as requirements.
However, endorsement of any future Codes by the Commission would be subject to the rulemaking 3rocess.
GL 96-05's scope and the scope contained in the Code may se different.
Licensees may propose to use OMN-1 for selected valves.
2.5.15 When submitting a relief request.to use Code Case OMN-1 in lieu of i
quarterly test < ng of MOVs, must the valves be low risk significant l
valves as determined by the plants' PRA?
OMN-1 can be applied to any or all MOVs, regardless of their risk significance.
i A3-43 f
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2.5.16 May a relief request to use OMN-1 be submitted before receipt of a Safety Evaluation on the GL 96-05 program? At what point can I implement OMN-17 Licensees may request approval of an alternate to use Code Case OMN-1 at anytime.
Receipt of a Safety Evaluation on GL 96-05 is not a prerequisite. Howeter, licensees cannot implement OMN-1 in lieu of quarterly testing until after NRC approval is received.
l 2.5.17 Does the NRC expect licensees to perform differential pressure testing of site valves over and above what is required to support the Jo'nt BWR and Westinghouse Owners' Group (J0G) Program on MOV Periodic Verification initiative (i.e., will a licensee be expected l
to test more valves than the share being tested in support of J06)?
Each participating licensee should ensure that the J0G program, and the!r participation therein, will gather enough data to cover plant-spe:ific situations. See NRC's preliminary comments on the J0G Progr:.m (Letter dated January 17, 1997 from C. Craig, NRC, to D.
Matthews, NRC, " Summary of Meeting with Boiling Water Reactor Owners Group (BWROG) and the Westinghouse Owners Group (WOG) to Discuss the Joint Effort on Periodic Verification of Motor-0perated Valves").
2.5.18 Are random occurrences of pre-lube, due to preventive maintenance (PM) considered pre-conditioning? Could this result in a violation? Does the licensee have to ensure that PMs are not scheduled "too close" to a scheduled surveillance test?
Licen;ees need to ensure that the IST program assesses the valves' operational readiness.
Preventative maintenance may occur before IST, however, tiie licensee should evaluate its effect.
Preventative maintenance should not specifically and intentionally be scheduled to precede surveillance testing.
See NRC Information Notice 97-016 on preconditioning.
-2.5.19*
Does Code Case OMN-1 discuss the " appropriate mix of static and dynamic testing?"
No.
In implementing Code Case OMN-1, licensees will need to develop a program that obtains sufficient information to estimate the rate of age-related degradation in MOV dynamic performance.
Licensees should establish a program that ensures that the MOVs remain capable of operation until the next scheduled test. Code Case OMN-1 allows licensees to determine those valves that will need dynamic testing and those valves that only need static testing.
2.6 CONTROL VALVES 2.6.1 A Code change is in the works to specify that control valves which have a required fail-safe function need not be full-stroke timed.
The Code does not explicitly require that control valves be stroke timed. Does the staff feel that relief is required not to stroke A3-44
time these valves, or is a technical position in the test plan adequate?
As discussed in NUREG-1482, Section 4.2.9, the Code currently does require stroke timing of power-operated valves. This would include the control. valves referenced in the question.
If the Code requirements can not be met, relief is required. The Code change in process has not yet been endorsed by the staff in the regulations.
Licensees may not use future Code changes unless they are endorsed in 50.55a or a request for an alternate is approved by the staff.
2.6.2 If the stroke time requirement for control valves is eliminated, will the valve need to be fail-safe tested, if applicable, and at least exercised, if not fail-safe tested?
The Code committees are currently proposing only to exempt the stroke time measurement.
Fail-safe testing will still be required, as currently proposed.
Proposed Code changes are subject to change in the course of the ASME approval cycle and, as stated above, Code changes require staff endorsement before licensees may use them.
2.6.3*
NUREG-1482, Section 4.2.9 implies that control valves that have a safety-related modulating function (and no fail-safe function) at e not exempt ("... valves are required to be tested in accordance with the requirements for IST if they perform a safety or fail-safe function"). Are these valves required to be in the IST program?
4 Valves with only a control or modulating function, are exempt per the Code.
Control valves with a fail-safe function or other safety function (e.g., control valves that are normally closed, but are required to go to an open position, including a throttled position, on an accident signal) are required to be tested to their safety position in accordance with the Code.
- 2.7 SOLEN 0ID VALVES 2.7.1*
Is it acceptable to use acoustic monitoring for solenoid valves?
As discussed in NUREG-1482, Section 4.2.8, acoustics or diagnostic 4
systems may be used without relief for stroke timing, provided that the test frequency is in accordance with the Code.
Staff guidance 4
related to testing solenoid valves may also be found in NUREG/CR-6396, Sections 2.1.2(4) and 2.1.4 (See the example from Dresden).
2.7.2 For solenoid valves that typically stroke in 1 to 1.5 seconds (FSAR limit is 4 seconds), can relief be granted for the difficult trending criteria of the Code?
The staff, in Generic Letter 89-04, Position 6, addresses stroke tiae measurements for rapid-acting valves and, as discussed in NUREG-1482, the use of OMa-1988, Part 10, which does not require trending, is acceptable.
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2.8 PRESSURE ISOLATION VALVES AND CONTAINMENT ISOLATION VALVES 2.8.1 In the response to Question Group 27 regarding Position 4 of Generic Letter 89-04, it was identified that the staff has l
undertaken a program to reevaluate various aspects of pressure isolation valves (PIVs), including testing. What progress has the staff made in this area? Have there been any documents identifying the staff's findings? What is the staff's position on PIVs which do not have test connections between two valves in series if the valve cannot be exempted as stated in Section 4.1.1 of NUREG-14827 The staff's findings on PIV issues can be found in NUREG-1463,
" Regulatory Analysis for the Resolution of Generic Safety Issue 105:
Interfacing System Loss-of Coolant Accident in Light-Water Reactors,"
and Information Notice 92-36, "Intersystem LOCA Outside Containment."
PIVs that are required to be individually leakage tested, but do not l
have intermediate test connections, cannot be tested in series, as discussed in NUREG-1482, Section 4.1.1.
Plant modifications may be i
necessary to )rovide testing capability. Other alternatives may be proposed by t1e licensee.
2.8.2 In order to fully utilize Option B of Appendix J, what details are required in a relief request to allow the extension of testing other than Appendix J leak rate tests (e.g., check valve closure testing that has been deferred to refueling outages, solenoid valve position indication verification), that is satisfied by the Appendix J surveillance? Have any utilities obtained approval to utilize such a request?
Licensees need to provide adequate justification to defer exercising or position indication verification. These activities need not be performed to the rigor required for local leak rate testing. Water testing would be adequate to verify that a check valve or solenoid valve is in a closed position, thereby negating the need for draining the water from the system. OM Part 10 includes disassembly and inspection as a means for exercising check valves.
The justification should dis:uss any other possible alternatives to local leakage rate testing for meeting the Code requirements. To date, one licensee has proposed to verify a number of valves' capability to close and the remote position indication verification at a frequency determined by its Appendix J performance based Type C program. This request was denied based on insufficient justification.
2.8.3 If Appendix J, Option B is implemented, are the requirements of Section XI, IWV for leak testing satisfied? To use Option B for Code leak test requirements, is a relief request required?
If so, should the frequency of testing be included in the relief request?
In GL 89-04, Position 10, the staff has determined that testing of CIVs in accordance with Appendix J and the analysis of leakage rates and corrective action requirements of paragraph IWV-3426 and 3427(a) is acceptable.
The use of either Option A or B is allowed by this A3-46 l
-- -. - -... -. ~. _.. -. - ~ ~ -. -
position and relief is not required. Use of this position must be documented in the IST program.
CIVs that have other leak tight functions must, however, meet the requirements of IWV, or Part 10 as allowed by NUREG-1482, Section 4.4.5; unless an alternate is approved.
2.8.4 Can licensees extend the testing frequency of PIVs that are also Appendix J valves (i.e., containment isolation valves)? Is relief necessary?
Appendix J, Option B allows Type C testing to be performance based.
Regulatory Guide 1.163 restricts Type C testing to a maximum interval of five years.
The Code, as well as some plant TSs, require leak testing of Category A valves, with leak tight functions besides containment isolation to be leak tested at least once every two years.
If licensees wish to employ the Appendix J test frequency for PIV leak i
testing, relief would be required, as the Code requirements would not j
be met. Additionally, revisions to the plant TS may be required.
2.8.5 ON Part 10 refers to Appendix J for CIVs which only have a leakage important safety function for containment isolation.
If a CIV is exempted from Appendix J, is leak rate testing not required?
Part 10 states that Category A valves that are CIVs shall be tested in accordance with Appendix J.
If Appendix J exempts these valves, and containment isolation is their only leak tight function, then leak testing of these valves is not required.
2.8.6*
Is it acceptable to revise the leakage acceptar.ce criteria, in lieu of corrective action (repair or replacement), when a CIV exceeds its owner specified leakage rate? Can the acceptance criteria be revised without declaring the valve inoperable?
As discussed in NUREG-1482, Section 3.2, as soon as the data is recognized as being in the required action range, the component must be declared inoperable.
Part 10, paragraph 4.2.2.3(f) requires the valves to be declared inoperable when the leakage rates exceed the Owner specified limits. With proper engineering justification, acceptance criteria may be reviewed and revised.
Valves meeting the-revised criteria could then be declared operable. Additionally, it is noted that if a CIV exceeds a licensee defined administrative leakage i
-limit under Option B of Appendix J, a cause determination and corrective action is required. The NRC staff expects licensees to take corrective action when warranted.
i
'2.8.7 Can the approach used for Type C Appendix J 1eak tests be applied to systems with a maximum system leakage limit with multiple leakage pathways?
j The Code only requires leak tests for valves with a specified maximum leakage limit.
Licensees may perform system leak tests for other reasons and the approach taken in Appendix J Type C tests could be considered.
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2.8.8*
Is it acceptable to perform one test for a CIV that is also a PIV, using a correlation for low pressure air to high pressure water to determine an upper bound for leakage?
No. The Code requires that the test medium be specified by the owner and provides requirements in Part 10, Paragraph 4.2.2.3(b)(4) for leakage tests involving pressure differentials lower than function pressure differentials.Section XI, IWV-3423(f) previously allowed a i
correlation to use an alternate medium. However, the Code Committees deleted this option in Part 10, citing in their white paper that correlations were not supported by in-field test data. Additionally, all the TS PIV requirements must be met.
2.8.9 Is it acceptable to use the corrective action requirements of Appendix J, in lieu of the corrective action requirement of OM-107 Why should individual valve operability limits be required?
1 10 CFR 50.55a(b)(2)(vii) requires that CIVs must be individually analyzed in accordance with paragraph 4.2.2.3(e) of OM Part 10 &nd corrective actions for these valves must be made in accordance with paragraph 4.2.2.3(f) of OM Part 10. A comprehensive review of the Part 10 CIV requirements was performed by the ASME OM Committee. The staff is considering the ASME proposal to delete the requirements in ongoing rulemaking.
Until any change in the regulations is finalized, however, corrective actions must be made in accordance with paragraph 4.2.2.3(f) of Part 10. Additionally, it is noted that if a CIV exceeds a licensee defined administrative leakage limit under Option B of Appendix J, a cause determination and corrective action is required.
3.0 PUMPS 3.1 GENERAL 3.1.1 Is it a requirement to measure total flow if there are multiple flow paths? For example, when testing an auxiliary feedwater pump, and measured flow is being injected into the steam generators and unmeasured flow is also being provided through recirculation, does the flow through both flow paths need to be recorded?
The Code requires the total flow through the pump to be measured.
Specific relief has been granted when the unmetered flow can be assured not to mask pump degradation. (See NUREG/CR-6396, Section 3.2) 3.1.2 Is it the staff's intent to require all licensees (i.e., BWRs and PWRs) through rulemaking to use the comprehensive pump test included in the OMc Code-19947 The staff is currently considering rulemaking that would include a reference to the OM Code, through the 1996 Addenda.
If there are s)ecific issues related to the reactor type, licensees may comment on t1e rulemaking when it is issued for public comment.
I A3-48 l
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l 3.1.3 Have there been any examples of the variable properties of diesel l
fuel making pump analysis difficult?
The *taff is not aware of how the properties of diesel fuel would affect the analysis of a pump.
3.1.4 Can a recirculation flow test be correlated to performance at full flow conditions to verify that a pump meets its design basis flow conditions?
l The Code does not require pump flow testing to be performed at design basis conditions.
However, 10 CFR 50, Appendix B, states that licensees shall establish a test program to demonstrate that l
components such as pumps, perform satisfactorily in service in l
accordance with written test procedures which incorporate the requirements and acceptance limits in applicable design documents such as the safety analysis report.
It is expected that the licensee would l
perform a design verification test following major maintenance.
It is the responsibility of the licensee to demonstrate that the results of the recirculation test can he correlated to full flow conditions, if a design basis condition test cannot be performed. The NRC is considering issuing an Information Notice on this issue.
3.1.5*
When a pump curve approximation is used for flow versus differential pressure, what is the recommended way to determine vibration reference values (e.g., average of baseline tests, most conservative (lowest) value)?
NUREG-1482 Section 5.2 discusses the use of pump curves.
Licensees are responsible for developing a method of assigning appropriate pump vibration acceptance criteria for regions of the pump curve.
The staff cannot recommend a method; however, as discussed in NUREG/CR-6396, Section 3.4, the use of the most limiting acceptance criteria for a given range may be one acceptable method.
3.1.6 When tests are done monthly due to management decisions as a result of past problems, does the test frequency have to be reduced to 2 weeks if pump goes into the alert range?
No.
If pumps are tested more frequently than required by the Code, and the pump enters the alert range, the Code would only require the test frequency to be decreased from quarterly to 6 weeks.
3.1.7*
For most ESF pumps, only run for testing, can test frequencies be extended, since testing may introduce failure mechanisms?
The Code requires that pumps be tested to ensure operability.
For specific pumps, the NRC has granted relief, via GL 89-04, Position 9, to defer full flow testing to cold shutdowns or refueling outages, provided that some testing on the pumps is conducted quarterly.
In addition, the 1995 Edition of the OM Code includes provisions for the A3-49 l
l
l comprehensive pump test which allows for a biennial test at full or substantial flow conditions to monitor Code parameters. However,
. quarterly measurement of differential pressure or flowrate is still required. Approval of a proposed alternate is required to implement the comprehensive pump test.
- 3. l ~. 8 During the Workshop presentations, it was stated that the Code comeittee were developing a Code change that would allow pump L
curves to be based on three points versus five. What is the basis l
for this change?
L The Code committees are considering a change to address the use of pump curves.
In the proposal a minimum of three points is required, to address curves over only a small range of flow or pressure.
In addition, the proposal requires, one point for every 20% of the difference between pump shutoff to run out, to ensure the points are 1
adequately spaced.
Therefore, over the total pump curve, five points would be required. This Code change is currently in the discussion stage and has not been approved.
)
3.2 INSTRUMENTATION l
3.2.1*
Do the 2% instrument inaccuracies need to be considered for use when establishing the *2% tolerance band around fixed reference values?
Yes. NUREG-1482, Section 5.3 provides the NRC recommendation for this issue. NUREG-1482 states that a total tolerance of i2% of the reference value is allowable without approval from the NRC. The allowed tolerance for setting the fixed parameter must be established for each case individually including the accuracy of the instrument and the precision of the' display.
3.2.2*
NUREG-1482, Section 5.3 allows a tolerance of c2% of the reference value (e.g., 500
- 10 gpa), when determining an acceptable range around a fixed pump reference value.
Is re' ief required to increase the tolerance based on accuracy (i.e., for analog instruments, can a licensee use a tolerance of t6% of reference values)?
l As discussed in Section 5.3 of NUREG-1482, the variance of i2% from i
the reference value is based on paragraph IWP-4150 of Section XI.
This paragraph allows symmetrical damping devices or averaging techniques to reduce instrument fluctuations to within 12% of the observed readings.
For a variance greater than 2%, a corresponding adjustment to acceptance criteria may be made to compensate for the uncertainty, or an evaluation would be performed and documented l
justifying a greater tolerance. The variance in the acceptance criteria and the method used for establishing the variance must be documented in the IST program. Approval by the staff is not required.
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3.2.3 Should design basis limits for pumps consider instrument inaccuracies?
Yes, Section 5.10 of NUREG-1482 provides guidance on this issue.
3.2.4 What is the current NRC policy / position on treating instrument uncertainty for ECCS pump pressures and flows for technical specification surveillance compliance? Are licensees expected to show how uncertainty is explicitly included in the technical specification bases and in development of acceptance criteria for technical specification pump tests?
The treatment of instrument uncertainties for technical specification testing is not an IST or Code question.
However, if instrument accuracies are not taken into account when developing technical specification acceptance criteria, there is a possibility that the pump would not be able to deliver the flowrate required by the safety analysis. Therefore, instrument inaccuracies must be taken into account.
3.2.5 What action is required when a permanently installed instrument is found to be out of calibration and this instrument has been used in several tests related to IST of pumps?
The actions required will depend on the component and system in question.
Generally, if the pump surveillance interval has been exceeded, the component would have to be declared inoperable and an LC0 entered. The instrument could then be calibrated, replaced, and a retest performed.- The licensee would perform an evaluation to assess the impact of using the out of calibration instrument.
From the question it is unclear whether the instrument was failed or that a instrument calibration interval was missed.
If the instrument was found to still be in calibration, and the problem was missed calibration intervals, a calculation could document this and assess the impact (if any) on the pump's performance.
If the instrument was found to be out of calibration, then the licensee would assess the impact on the parameters measured, and take action in accordance with the plant TS. The licensee would review the test results where this instrument was used, back to when the instrument was last determined to be within calibration.
The licensee must also evaluate the cause of the out of calibration condition and take appropriate measures to prevent recurrence, in accordance with 10 CFR 50, Appendix B.
Addi-tional guidance is provided in NUREG-1482, Section 7 and Appendix G.
3.2.6*
When separate instruments are used to measure suction and discharge pressure, and inaccuracies are discovered during post calibration such that the differential pressure accuracy criteria is not exceeded, are the test results invalid?
The Code requires differential pressure to be determined for centrifugal, including vertical line shaft, pumps.
Instrument accuracy for differential pressure shall be within 12%.
Therefore, A3-51
- - - - - - ~. - - -
although the accuracy of the individual pressure instrument may exceed 12%, as long as the accuracy requirements for differential pressure are met, the test would not need to be invalidated.
If the inaccuracy does exceed f2%, a relief request would be required to use the existing instrumentation. See NUREG-6396, page 3-67.
If a problem with an instrument is discovered during the performance of the test, and it is clear that the instrument, not the pump, is malfunctioning, the test could be halted, the instrument repaired or replaced, and the test redone (see NUREG-1482, Question Group 46 in Appendix A).
Licensees should determine what caused the instrument to go out of calibration, and take the necessary actions to preclude this from recurring.
3.2.7*
Can an evaluation and corresponding adjustment of the acceptance criteria be used in lieu of a relief request when instrument accuracy is minimally outside 2%? For example, if the instrument loop inaccuracy is 2.03% for a tank level which is used to calculate suction pressure on a pump and the suction pressure is only a small fraction of the differential pressure determination, can an evaluation be used?
Yes. As discussed above, the Code requires differential pressure to be determined for centrifugal, including vertical line shaft, pumps.
Instrument accuracy for differential pressure shall be within 12%.
Therefore, although the accuracy of the individual pressure instrument may exceed 12%, as long as the accuracy requirements for differential pressure are met, the test would be acceptable and relief would not be i
required.
3.3 ACCEPTANCE CRITERIA 3.3.1*
If a pump fails a test, and it is obvious that the failure was due to an instrument problem, can the pump be declared operable when the failed instrument is identified? What is the Code requirement regarding the time allowed for retest when the instruments involved are recalibrated?
The pump may be declared operable, provided that it is clear the failed instrument is the overwhelming cause of the failed test. The failed instrument should be recalibrated, and data promptly taken with the new equipment. There is no Code requirement for the timing of the retest, beyond satisfying the pump surveillance interval.
- However, the licensee should redo the test promptly to verify that the cause was indeed the instrumentation.
If the cause of anomalous data cannot clearly be attributed to the malfunctioning gauge, then it should be attributed to pump failure. The licensee would then declare the pump inoperable and evaluate the condition of the pump in accordance with the applicable technical specification.
See NUREG-1482, Appendix A, Question Group 45 and 46.
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i j
3.3.2*
What relief is currently being provided by NRC for use of pump analyses for alert and required action range?
Approval has been granted by the staff for licensees to use Paragraph 6.2.2 of the 1995 Edition of the ASME OM Code.
This paragraph requires pumps performing in the required action range to be declared inoperable until the cause of the deviation has been determined and the condition corrected, or an analysis of the pump is performed and i
new reference values are established. This analysis would be expected j-to include, at a minimum, both a pump level and a system level evaluation of operational readiness, the cause of the performance change, and an evaluation of all trends indicated by the data.
The results would be documented in the test record. This alternate was approved because licensees are already allowed to perform an analysis j
in accordance with GL 91-18.
I 3.3.3 When testing pumps, if a utility submits a relief request to use the 1995 Edition of the OM Code concerning corrective action (to use evaluation instead of repair / replacement), can the relief a
request be implemented immediately or is NRC approval required prior to implementation?
i As discussed in NUREG-1482, Section 6.3, alternates, such as using the 1
1995 Edition corrective action requirements, cannot be implemented until the alternative is authorized by the NRC.
3.3.4 Could examples of acceptable evaluations that should be performed for a pump in the alert / action range be published by the NRC for use as references by licensee?
It is difficult to publish specific examples because the detailed analyses may contain proprietary information. However, as discussed above, this analysis would be expected to include, as a minimum, both a pump level and a system level evaluation of operational readiness, the cause of the performance change, and an evaluation of all trends indicated by the data.
3.3.5*
For pumps that are tested in accordance with GL 89-04, Position 9, what are the requirements if a pump violates an alert limit?
As discussed in the Current Considerations for Position 9 (page A-42 of NUREG-1482), it is recommended that efforts be made to take corrective actions during the outage and repeat the test post-maintenance for pumps which can only be tested in accordance with the Code during refueling outages. The increased test frequency when pumps' parameters are in the alert range does apply to testing i
performed during refueling outages or cold shutdowns.
A3-53
3.3.6*
Can a pump curve be adjusted down to design limits in order to readjust the alert and action levels in the IST program?
NUREG-1482, Section 5.2 discusses the use of pump curves.
The pump curve must be based on reference points, when the pump is known to be operating acceptably. The alert and required action ranges are based on the points on the curve. The acceptance criteria cannot conflict with the operability criteria in the TS or safety analysis report. A new pump curve must be generated if the original one was affected by repair, replacement, or routine maintenance. Additionally, new reference values (i.e., pump curves) may be established when pump parameters are in the required action range, if the pumps continued use at the changed values is supported by analysis, as allowed by GL 91-18.
3.3.7*
Is an alert range needed for pumps when the design basis limit is more conservative than the Code limit?
If the design-limit '.s more restrictive than the Code limit, the design limit (including instrument inaccuracies) must be met.
The Code does not currently require the licensee to establish alternate limits than what is specified in the Code.
Section XI, IWP-3210 previously allowed licensees to specify reduced range limits in lieu of those specified, when those limits specified could not be met (See NUREG-1482, Section 5.6).
It would be prudent, however, for the licensee to establish administrative limits, in order to increase testing or take corrective action, before the operability criteria is exceeded.
3.3.8 When a pump has entered the required action range and has been declared inoperable, what criteria should be used for future degradation monitoring after an analysis which demonstrates design basis acceptability has been performed?
As discussed in GL 91-18, Enclosure 2, Section 6.11, an analysis demonstrating that the specific performance degradation does not impair operability and that the pump will still fulfill its function may be performed, in lieu of repair or replacement, when the Code required action range is more conservative than its corresponding technical specification limit. A new required action range may be established after such analysis which would allow a new determination of operability.
The 1995 Edition of the OM Code allows for the performance of an analysis to demonstrate the acceptable operation of pumps if it exceeds the required action range. The 1995 Code states that new reference values are to be established, following a analysis demonstrating the acceptability of continued plant use. The Code acceptance criteria would be required to be applied to the new reference values. However, the acceptance criteria cannot conflict with the operability criteria in the TS or safety analysis report.
A3-54
3.4 VIBRATION 3.4.l*
What is the regulatory position on smooth running pumps, and does the use of spectral analysis to evaluate vibration levels affect I
this position?
A small number of plants in the past have received approval for requests on smooth running pumps. As discussed in NUREG-1482, Section 5.4, however, a pump with very low vibration (i.e., at levels below the criteria for smooth running pumps approved at this facility) experienced an increase in vibration levels over three successive i
tests. The licensee determined that the cause of the increase was a degraded bearing which required replacement. Had the Code alert range relative vibration limits been in effect, the degradation would have required increased monitoring until the condition was corrected.
Therefore, the staff is reluctant. to approve such relief requests.
The Code committees have recently reactivated this issue for consideration. Using spectral analysis is also being considered by the Code Committees, but not necessarily for smooth running pumps.
3.4.2 Is there any ongoing or pending NRC initiative which will mandate testing of safety-related pump motors?
There is no ongoing or pending NRC initiative at this time.
Licensees are expected to remain cognizant of the potential effect that degraded pump drivers may have on pump performance when assessing degraded operations.
3.4.3*
For pumps which are not run continuously or regularly does the test frequency need to be increased when vibration enters the alert range since the degradation mechanism, if any, is not active then?
A licensee would require approval of an alternate not to increase the test frequency as required by the Code.
The licensee would need to demonstrate in the basis that there is no trend towards further degradation, and that operation at the increased vibration level does not affect the pump's operational readiness. The ON Committee is considering the use of evaluation or spectral analysis for exiting the required increased frequency.
3.4.4*
Could the fact that the upper motor bearing housing is not accessible on many vertical shaft pumps be addressed on a generic basis, so a relief request would not be necessary?
If this issue is a generic concern, the Code committees could consider revising the Code to address these pumps.
As discussed previously, the staff has no plans to supplement GL 89-04 to provide generic relief.
Specific relief has been granted from the Code vibration l
requirements where access to the upper motor bearing housing is inaccessible (e.g., Hatch Safety Evaluation dated June 13, 1994, Section 3.1.3.1).
l A3-55 I
f 3.4.5*
Is the 05-6 required vibration frequency response range from 1/3 pump speed an absolute minimum low end threshold? Is it acceptable to use an instrument that could monitor from 1/4 or 1/5 pump' speed, or would the low frequency signal need to be filtered? Would use of the instrument require a relief request?
An instrument that has a frequency response range lower than one third minimum pump speed would envelop the potential low frequency noise contributors and would be acceptable for IST use.
Relief to use this instrument would not be required.
3.5 USE OF THE OM CODE 3.5.1 Does a plant need to submit a relief request to use the comprehensive pump test? -How are' associated requirements incorporated in an IST program if a plant is not committed to that edition of code?
Approval of an alternate is required to use the comprehensive pump test since the NRC regulations do not currently endorse the 1994 Addenda of the ON Code.
Licensees would be ex)ected to identify all related requirements in the request; if not, t1e NRC may grant provisional approval and will require the related requirements to be met.
NUREG/CP-0137, Proceedings of the Third NRC/ASME Symposium on Valve and Pump Testing, pages 493-509, provides a discussion of the comprehensive pump test and identifies the affected sections of the Code and the basis for the changes.
3.5.2 When updating to 0M-6, do new reference values (rebaselining) for both hydraulic and mechanical conditions need to be established?
If licensees are updating from IWP to 0Ma-1988, Part 6, the pump vibration readings may now be taken in inches per second instead of in mils. Additionally, pump vibration measurement instrumentation requirements have changed.
Therefore, the mechanical reference values must be reestablished. There does not appear to be any differences iatween IWP and Part 10 that would affect the hydraulic reference values. However, licensees would be expected to review the revisions to their testing procedures to ensure that the new testing procedures will not invalidate the previous reference values.
3.6 POST-MAINTENANCE TESTING 3.6.1 If the service water pumps are found to be in the alert or required action range, an impeller adjustment is made, and reconfirmation or new reference values are established; is it necessary to reconfirm points on the pump curve at some later date where plant conditions allow this confirmation, or is this one point verification (reference value) as' allowed by the Code acceptable?
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l When performing post-maintenance testing on pumps, how extensive is the reconfirmation required to be (sing'e point or pump curve)?
What if the repair is done at power?
If licensees are utilizing an approved relief request to use pump curves, then as discussed in NUREG-1482, Section 5.2, a new reference curve needs to be developed or the previous curve revalidated prior to declaring the pump operable. Additional guidance is provided in NUREG-1482, Appendix G, Response 5.2-3 which states that the licensee is responsible to make the determination based on the type and extent of the maintenance, and document the basis for the single point.
Certain plant conditions may preclude more than one point until plant shutdown, which would be an acceptable basis until additional points are verified at the next shutdown.
For post maintenance, only the portion of the curve used in the test procedure needs to be reverified for inservice testing.
If a major modification or repair / replacement is performed, a design basis (start up type) test may be necessary before placing the pump back in service, however, this is outside the Code requirements.
3.6.2 If maintenance was performed on the HPCI/RCIC pumps during refueling outages that could have affected reference values, what is NRC's expectation on the operable status of these systems between 150 psig and 1000 psig reactor pressure (1000 psig being inservice test pressure)? Can the 150 psig test be used to ver'fy the system is operable until 1000 psig is reached?
f As discussed in Response to Comment 5.2-3 in NUREG-1482 Appendix G, the 150 psig test may be used as a post-maintenance test, provided the i
licensee had previously established reference values at this pressure, when the pump was known to be operating acceptably. The use of multiple reference values is allowed by the Code.
3.6.3 Following pump replacement or major maintenance which could affect pump performance, why is the first test data required to be used as the basis for new reference values? With nonstandby pumps (e.g.,
service water, component cooling) there is no allowance given for break-in or run-in time during which hydraulic parameters can
" settle in."
Part 6, Paragraph 4.4, requires a new reference value(s) be determined or the previous set reconfirmed by an inservice test run prior to declaring the pump operable.
Licensees may allow the pumps to settle in before taking data, and then declare the pumps operable.
Licensees may also run a series of tests to confirm repeatability prior to declaring a pump operable. The requirements of Paragraph 4.3, which state that the reference values shall be determined from the results of the preservice tests or the first inservice test, would not apply if the reference values were affected by repair, replacement, or maintenance.
Paragraph 4.4 applies.
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3.6.4 When a new impeller is installed in a pump, is it a requirement to perform an in-situ test to verify that pump performance meets the design requirements or can the manufacturer's test stand data be used?
l If the pump manufacturer tested the entire pump on the stand, this data is acceptable. The licensee would still r.eed to verify proper j
operation of the pump following installation, and to establish or reconfirm reference values in accordance with the Code.
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