ML21356A785
| ML21356A785 | |
| Person / Time | |
|---|---|
| Issue date: | 12/15/2021 |
| From: | Advisory Committee on Reactor Safeguards |
| To: | |
| Howard, K, ACRS | |
| References | |
| NRC-1794 | |
| Download: ML21356A785 (165) | |
Text
Official Transcript of Proceedings NUCLEAR REGULATORY COMMISSION
Title:
Advisory Committee on Reactor Safeguards (ACRS) Plant License Renewal Subcommittee Docket Number: N/A Location: Video-teleconference Date: Wednesday, December 15, 2021 Work Order No.: NRC-1794 Pages 1-108 NEAL R. GROSS AND CO., INC.
Court Reporters and Transcribers 1716 14th Street, N.W., Suite 200 Washington, D.C. 20009 (202) 234-4433
1 1
2 3
4 DISCLAIMER 5
6 7 UNITED STATES NUCLEAR REGULATORY COMMISSIONS 8 ADVISORY COMMITTEE ON REACTOR SAFEGUARDS 9
10 11 The contents of this transcript of the 12 proceeding of the United States Nuclear Regulatory 13 Commission Advisory Committee on Reactor Safeguards, 14 as reported herein, is a record of the discussions 15 recorded at the meeting.
16 17 This transcript has not been reviewed, 18 corrected, and edited, and it may contain 19 inaccuracies.
20 21 22 23 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com
1 1 UNITED STATES OF AMERICA 2 NUCLEAR REGULATORY COMMISSION 3 + + + + +
4 ADVISORY COMMITTEE ON REACTOR SAFEGUARDS 5 (ACRS) 6 + + + + +
7 PLANT LICENSE RENEWAL SUBCOMMITTEE 8 + + + + +
9 WEDNESDAY 10 DECEMBER 15, 2021 11 + + + + +
12 The Subcommittee met via Video-13 Teleconference, at 2:00 p.m. EST, Matthew Sunseri, 14 Chairman, presiding.
15 COMMITTEE MEMBERS:
16 MATTHEW SUNSERI, Chair 17 RONALD G. BALLINGER, Member 18 VICKI BIER, Member 19 CHARLES H. BROWN, JR. Member 20 VESNA B. DIMITRIJEVIC, Member 21 GREGORY HALNON, Member 22 WALT KIRCHNER, Member 23 DAVID PETTI, Member 24 JOY L. REMPE, Member 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
2 1 ACRS CONSULTANT:
2 STEPHEN SCHULTZ 3
4 DESIGNATED FEDERAL OFFICIAL:
5 KENT HOWARD 6
7 ALSO PRESENT:
8 PAUL AITKEN, Dominion Energy 9 BRIAN ALLIK, NRR 10 STEWART BAILEY, Region II 11 ERIC BLOCHER, Dominion Energy 12 STEVE BLOOM, NRR 13 CHRISTOPHER BROWN, ACRS 14 LARRY BURKHART, ACRS 15 KENYA CARRINGTON, Region II 16 JOE COLACCINO, NRR 17 JOHN DISOSWAY, Dominion Energy 18 JEN ENGLAND, Region II 19 LAUREN GIBSON, NRR 20 CRAIG HEAH, Dominion Energy 21 ALLEN HISER, NRR 22 LOIS M. JAMES, NRR 23 BETH KEHLER HALUSKA, Dominion Energy 24 WILLIE LLOYD, Dominion Energy 25 KEITH MILLER, Dominion Energy NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
3 1 DUC NGUYEN, NRR 2 PAUL PHELPS, Dominion Energy 3 HECTOR RODRIGUEZ-LUCCIONI, NRR 4
5 6
7 8
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4 1 P R O C E E D I N G S 2 2:00 p.m.
3 CHAIR SUNSERI: Good afternoon, the 4 meeting will now come to order. My name is Matthew 5 Sunseri and I am the Subcommittee Chair for the Plant 6 License Renewal Subcommittee.
7 The purpose of this Subcommittee meeting 8 is for the NRC staff and Dominion Energy to brief the 9 Subcommittee on the North Anna Power Station Units 1 10 and 2 subsequent license renewal application.
11 ACRS members in attendance are -- I'm 12 looking across the screen and see Member Ron 13 Ballinger, Vicki Bier, Vesna Dmitrijevic, Greg Halnon, 14 Dave Petti, Joy Rempe, and we are also joined by our 15 consultant Steve Schultz.
16 Did I miss anybody that's hidden in a 17 phone number without a name?
18 MEMBER BROWN: You missed me, but I'm not 19 hidden. It's Charlie and I couldn't see anybody 20 else's name other than yours and Vicki's, which was 21 interesting.
22 CHAIR SUNSERI: Charles Brown, I see you 23 now. During today's meeting, the Subcommittee will 24 gather information, analyze relevant issues and facts, 25 and formulate proposed positions and actions as NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
5 1 appropriate. At the Subcommittee's discretion, any 2 matter discussed will be considered for presentation 3 to the full Committee, and I will summarize those at 4 the end of the meeting.
5 The ACRS was established by statute and 6 was governed by the Federal Advisory Committee Act.
7 The Committee only speaks through its published letter 8 reports. Because this is a Subcommittee meeting, 9 participants should consider any remarks by ACRS 10 members as their individual comments and not Committee 11 positions.
12 We hold Subcommittee meetings to gather 13 information and perform preparatory work that will 14 support our deliberation at full Committee meetings.
15 And just as a reminder, I believe the full Committee 16 for this session is scheduled for February 2, 2022.
17 The rules for participation in all ACRS 18 meetings including today's were announced previously 19 in the Federal Register and included on our website.
20 The ACRS Section of the U.S. NRC public website 21 provides our charters, bylaws, agendas, letter 22 reports, and transcripts of all full and Subcommittee 23 meetings including the material present.
24 As stated on our website, members of the 25 public who desire to provide written or oral input to NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
6 1 the Subcommittee may do so and should contact the 2 designated federal officer.
3 Kent, have we had any request for public 4 comment?
5 MR. HOWARD: None yet.
6 CHAIR SUNSERI: Okay, but we will still 7 open up the line at the end. During today's meeting, 8 it's open to public attendance and there will be time 9 set aside during the meeting for comments from members 10 of the public attending or listening in.
11 Due to the COVID-19 pandemic, today's 12 meeting is being held over Microsoft Teams for ACRS 13 members, Dominion Energy, and NRC attendees. There is 14 also a call-in number allowed for participation of the 15 public to connect to the Teams session.
16 A transcript of today's meeting is being 17 kept; therefore, we request that meeting participants 18 not on the agenda identify themselves when they are 19 asked to speak, and to speak with sufficient clarity 20 and volume so they could readily be heard.
21 At this time, I asked the attendees, with 22 the exception of the Dominion presenters, 23 participating through the public line to put their 24 devices on mute to minimize disruptions and only 25 unmute when you are speaking. And it's command star-6 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
7 1 to unmute yourself.
2 Based on some affiliations outside of the 3 ACRS, I will be recusing myself for deliberations on 4 metal fatigue analysis of the primary system and 5 radiation analysis of the reactor pressure vessel.
6 Members, before we get into any comments, 7 are there questions from members about today's agenda?
8 All right, then, we will proceed. And at 9 this time I call on Mr. Brian Smith, Division Director 10 of the Division of New and Renewed Licenses.
11 Brian, you have the floor.
12 MR. SMITH: Thank you, Chairman Sunseri 13 and members of the ACRS Subcommittee on Plant License 14 Renewal. Good afternoon. As the Chairman said, my 15 name is Brian Smith and I'm the Director of the 16 Division of New and Renewed Licenses here at NRR.
17 We sincerely appreciate the opportunity 18 today to present to the ACRS Subcommittee on the 19 results of the staff's review of the fourth 20 application for subsequent license renewal.
21 This application was submitted by Virginia 22 Electric and Power Company, or Dominion, for the North 23 Anna Power Station Units 1 and 2, located in Louisa, 24 Virginia.
25 By way of background, North Anna Units 1 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
8 1 and 2 received approval for their initial license 2 renewal license from the NRC on March 20th of 2003.
3 The NRC review at that time was performed 4 using guidance developed prior to the issuance of the 5 generic aging license lessons learned report, or the 6 GALL report.
7 The NRC guidance for license renewal over 8 the years has evolved through enhancements and 9 improvements based on the lessons learned from NRC 10 reviews from both domestic and international industry 11 operating experience.
12 The GALL report has gone through two 13 revisions and additional interim staff guidance was 14 issued following Revision 2. The guidance for 15 subsequent license renewal is contained in the GALL 16 SLR document.
17 This was built upon previous guidance and 18 included additional focus and enhancements where 19 necessary on aging, management, and time-limiting 20 aging analysis for operation in the 60 to 80-year time 21 period.
22 In the staff's presentation today, you 23 will hear about some of the specific SLR issues as 24 applied to the North Anna review. The NRC Project 25 Managers for the North Anna subsequent license renewal NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
9 1 application review are Lois James and Hector 2 Rodriguez-Luccioni.
3 Hector will introduce the staff who will 4 be introducing or presenting the questions regarding 5 the staff's review.
6 Part of the management team here with me 7 today is Lauren Gibson, the chief of the License 8 Renewal Project Branch, and branch chiefs for the 9 staff involved in the technical review, including Joe 10 Colaccino and Steve Bloom.
11 We also have with us representatives from 12 Region II including Stewart Bailey, chief of the 13 Reactor Project Branch and the Division of Reactor 14 Projects in Region II. And Jen England, senior 15 resident inspector at North Anna.
16 Id like to note that the staff completed 17 its review with no confirmatory or open items in the 18 safety evaluation report.
19 The staff will provide an overview of the 20 safety review and highlight a few technical areas that 21 may be of interest to the Subcommittee members.
22 Finally, we will address any questions you 23 might have on the staff's presentations. We look 24 forward to a productive discussion today with the ACRS 25 Subcommittee.
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10 1 At this time Id like to turn the 2 presentation over to Paul Phelps, Dominion Engineering 3 Director, SLR, to introduce his team and commence the 4 presentation.
5 MR. PHELPS: Thank you, Brian. Good 6 afternoon. My name is Paul Phelps and I am the 7 Engineering Director responsible for the North Anna 8 Power Station subsequent license renewal, or SLR, 9 project.
10 We appreciate the opportunity to speak 11 with the ACRS Committee today on Dominion Energy's 12 application for subsequent license renewal. This is 13 a very important day and we appreciate the support and 14 look forward to presenting the SLR application 15 highlights to the Committee.
16 By the way of my background, I have been 17 in the nuclear industry for over 30 years. I am 18 responsible for various SLR-related projects that are 19 currently under development in Virginia.
20 We have stood up the organization not only 21 to perform the requisite work for the relicensing of 22 the station, but we also have a large organization 23 that is currently working on projects to improve the 24 safety, reliability, and aging management for North 25 Anna Power Station through various modifications. I NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
11 1 will provide some of those insights in a couple of 2 slides.
3 Next slide. I want to take the time to 4 introduce the team assembled with me here today. Paul 5 Aiken is the engineering manager responsible for the 6 development of the North Anna SLR application. Paul 7 led the team for the successful Surry subsequent 8 license renewal project, which was the third SLR for 9 the industry.
10 Paul was also involved in a leadership 11 role in all of the Dominion Energy's first license 12 renewal projects dating back to 1999 and over the last 13 few years has been engaged with various organizations 14 such as EPRI, Department of Energy, PWR Owners Group, 15 NEI, and various vendors to ensure alignment on 16 various technical topics in support of subsequent 17 license renewal.
18 Keith Miller is one of the team's 19 technical leads. Keith has been a member of the SLR 20 team since 2017. He has served in different roles 21 within the SLR team and is currently the technical 22 staff lead for again management programs.
23 Eric Blocher is the next technical lead.
24 Eric has been involved in various first license 25 renewal applications in the industry. He brings his NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
12 1 extensive knowledge to the team and has been deeply 2 involved in the development of the GALL SLR, not only 3 on behalf of Dominion Energy but for the nuclear 4 industry. Eric will be presenting the technical 5 topics later in the presentation.
6 Craig Heah is the technical lead in the 7 scoping and screening activities. Craig has 14 years 8 of nuclear experience, he was the last chairman of the 9 NEI mechanical license renewal working group during 10 the transition to GALL SLR. Craig will be assisting 11 the team with a slideshow and will be available to 12 answer any scoping or screening questions that you may 13 have during the presentation.
14 Along with the team I introduced, we have 15 senior station leaders on the virtual call as well.
16 I would like to recognize Fred Mildan. Fred is 17 currently the site vice president at North Anna Power 18 Station. Fred will be transitioning to Surry Power 19 Station to be the site vice president in the New Year.
20 Lisa Hilbert, who is currently the plant 21 manager, will transition to be the new site vice 22 president at North Anna power station on January 1st, 23 2022.
24 In addition, we also have technical staff 25 available in the virtual audience or in the room with NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
13 1 me should we need some assistance on any questions you 2 may have during our portion of the presentation. If 3 needed, they will identify themselves and address your 4 question.
5 Next slide. I want to cover the agenda 6 for today's meeting. We will discuss the station 7 overview performance, SLR application development, SLR 8 aging management programs, technical topics, and 9 closing remarks.
10 Next slide. Here's an overview of the 11 station in a 50-mile radius. North Anna Power Station 12 is located in Louisa County, Virginia adjacent to Lake 13 Anna. Lake Anna was constructed to serve the needs of 14 the station by damming the North Anna River.
15 The area includes both populated and 16 industrialized areas as well as expansive rural areas 17 and spans from Northern Virginia to the suburb south 18 of our state capital, Richmond, and from the upper 19 Chesapeake Bay to the area West of Charlottesville.
20 Included in this area are many military 21 installations and airports providing international 22 travel. Next slide. North Anna is a Westinghouse 23 three-loop pressurized water reactor with an output 24 net capacity of over 1900 megawatts.
25 Together, these two units are capable of NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
14 1 producing approximately 15 percent of Virginia's 2 electricity needs. Unit 1 started commercial 3 operation in 1978 and Unit 2 started commercial 4 operation in 1980.
5 The independent spent fuel storage 6 installation facility recently had the site-specific 7 license renewed in 2018. A 4.3 percent power upgrade 8 was implemented in 1986 prior to the initial license 9 renewal.
10 The renewed licenses for both Surry and 11 North Anna Power Stations were issued in March of 12 2003. Lastly, North Anna entered the period of 13 extended operation in 2018 and 2020 for Units 1 and 2 14 respectively.
15 Next slide. Here is an aerial view of the 16 station. I will highlight some of the more 17 significant features to help the Committee get 18 orientated. At the upper right of the photo is the 19 North Anna reservoir.
20 The reservoir is approximately 9600 acres 21 and provides the condenser cooling water source for 22 the station. After traveling through the station, 23 circulating water exits to the discharge canal 24 pictured in the bottom right.
25 The discharge canal flows into the waste NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
15 1 heat treatment facility which serves to dissipate 2 waste heat from the circulating water discharged prior 3 to returning to the reservoir.
4 The waste heat treatment facility is a 5 series of a lagoons totaling about 3400 acres that is 6 separated from the reservoir by a series of dikes.
7 The water cools as the water traverses through the 8 waste treatment facility and ultimately re-enters the 9 North Anna reservoir at one of the dikes.
10 In the center of the photo are the Unit 1 11 and 2 reinforced concrete containment structures in 12 the turbine building behind them in the light blue.
13 At the upper left is the switch yard. At the lower 14 left is the service water reservoir.
15 The administration building, the two-story 16 white building between the reservoir and the discharge 17 canal, is where many of the plant staff work. Here is 18 some high-level information under performance of North 19 Anna.
20 To note, North Anna operates on an 18-21 month refueling frequency. The plant capacity factor 22 has been good, as reflected in the bullets above. As 23 far as the regulatory oversight process, North Anna is 24 in Column 1 and has been there since 2013.
25 Additionally, ROP indicator status has NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
16 1 been all green since 2000 for Unit 1 and 2010 for Unit 2 2. Next slide. There has been significant capital 3 investments made to North Anna since the first re-4 license was issued in 2003.
5 As I mentioned in my opening remarks, 6 Dominion Energy will continue to invest in North Anna 7 to maintain safety and plant reliability for the 8 current and the subsequent period of extended 9 operation.
10 There is a partial list of some of the 11 major mods that have been completed at North Anna. I 12 would like to highlight a few.
13 North Anna has performed a reactor vessel 14 head replacement on both units, replaced the reserve 15 station service transformers, which supply power to 16 the emergency buses, replaced the main transformers on 17 both units, replaced the main generators on both 18 units, and performed reactor vessel upflow conversion 19 on both units.
20 At this time, I will transition the 21 presentation to Paul Aiken to provide an overview of 22 the SLR application development process.
23 MR. AITKEN: Thanks, Paul, good afternoon.
24 My name is Paul Aiken and I'm the engineering manager 25 responsible for the development of the Surry and North NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
17 1 Anna subsequent license renewal applications.
2 By way of background, I have been in the 3 nuclear industry for over 30 years and as what 4 previously mentioned by Paul, involved in license 5 renewals for the Dominion fleet and most recently, the 6 Surry applications.
7 I will be providing an overview of the 8 North Anna SLR application development process and 9 other considerations for the Committee today. Next 10 slide, please.
11 Following a successful Surry project, the 12 SLR team did a thorough evaluation to identify things 13 that went well and things that we could improve on for 14 North Anna both internally and working with the NRC on 15 the NRC review process.
16 One area that we focused on was improving 17 consistency with the GALL SLR. A significant 18 advantage that we could leverage in the development of 19 the North Anna application is that Surry and North 20 Anna are considered sister plants based on 21 similarities and design and operation.
22 In fact, the similarities were so profound 23 that there was only one license renewal application 24 submitted for both plants during the first license 25 renewal.
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18 1 I believe that the similarities between 2 North Anna and Surry allow for a more efficient review 3 by the NRC staff since many of the aging management 4 programs and supporting materials where either the 5 same or very similar.
6 For those three programs, we were 7 proactive and implemented as many enhancements as we 8 could for North Anna that were identified during the 9 Surry application preparation in review.
10 For every procedure enhancement that we 11 were able to implement prior to the North Anna 12 application submittal, we increased our alignment to 13 the GALL SLR and decreased the number of enhancements 14 the station would need to implement upon issuance of 15 the subsequent or renewed licenses.
16 I feel that we are very effective in that 17 regard and reduce our total enhancements by over half.
18 In addition, the same Dominion project 19 team identified and examined any lessons learned from 20 the Surry review, including audit questions and RAIs, 21 and incorporated those improvements into the North 22 Anna application as appropriate.
23 Together, this resulted in reducing the 24 overall number of RAIs between Surry and North Anna.
25 Additionally, following the Surry review, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
19 1 the NRC staff in the first three lead SLR applicants, 2 had identified various areas for which future SLR 3 applications and staff reviews could be completed more 4 effectively and efficiently.
5 One of the focus areas was related to 6 aging management programs that required exceptions to 7 be taken for issues that were generic in nature.
8 As an example, the GALL SLR water 9 chemistry has endorsed an EPRI document that has since 10 been revised to update the content based on more 11 current information.
12 Due to the difference in revision levels, 13 the SLR applicants had to take an exception and 14 provide a basis.
15 It was an easy technical justification but 16 the industry felt it was an opportunity to reduce an 17 exception and suggested the change to the staff.
18 Ultimately, this example resulted in a 19 series of four interim staff guidance documents issued 20 in early 2021, which reduced the number of AMPs with 21 exceptions by nearly half of North Anna.
22 Keith Miller will provide some additional 23 context for the Committee following my presentation.
24 Dominion and the industry also worked with the NRC to 25 identify opportunities to streamline the overall NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
20 1 review process.
2 There were several improvements supported 3 by the NRC. Among them were a focus from the industry 4 -- there were several improvements supported by the 5 NRC.
6 Among them were a focus from the industry 7 and the NRC management teams on minimizing multiple 8 rounds of RAIs, which can be a resource strength for 9 the NRC staff and the applicant.
10 Another item that I would like to mention 11 is the integration of the standalone OE audit used for 12 the SLR lead plans. Instead, the NRC staff adjusted 13 their review of OE into the larger safety office.
14 This change reduced the administrative 15 burden on the staff related to the execution and 16 reporting of a separate audit but it also eliminated 17 the cost of supporting a separate audit for the 18 applicants.
19 CHAIR SUNSERI: Hey, Paul, before you go 20 onto the next slide, just a question. I think I heard 21 you say that on the first round of license renewal, 22 Surry and North Anna were treated as one application.
23 Did I hear that right?
24 MR. AITKEN: Yes, sir, that's correct.
25 CHAIR SUNSERI: And so was there some NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
21 1 reason it was different this time?
2 MR. AITKEN: It was really just the timing 3 of the plant, it was a period of extended operations.
4 Surry entered in 2012 and 2013 respectively where 5 North Anna was 2018 and 2020.
6 So, it was just a timing issue but if they 7 were on the PO we could have done the same thing.
8 CHAIR SUNSERI: That makes sense to me 9 then. I just was exploring whether or not there was 10 any technical reasons but it's the administrative 11 timing.
12 MR. AITKEN: No problem, good question, 13 thank you.
14 I want to provide a brief summary of the 15 difference between the first license renewal and the 16 subsequent license renewal with respect to the 17 integrated plan assessment.
18 For scoping and screening there were 19 minimal changes in the overall process approach. This 20 is primarily because the established industry criteria 21 hasn't changed very much from first license renewal.
22 However, one area we expected to have 23 adjustments was related to scoping and screening for 24 altitude that's non-safety-related which can affect 25 safety-related equipment.
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22 1 This was due to the criteria and guidance 2 evolving since the first license renewal, as Brian 3 noted in his opening remarks. North Anna, as well as 4 Surry, were pre-op plans so we're in the same 5 situation of updating the methodology and scoping of 6 additional plan equipment.
7 In the area of aging management reviews, 8 the expansion in the number of aging effects that we 9 had to address significantly increased due to the 10 vintage of the previous application and the evolution 11 of the GALL over the years.
12 The biggest difference was in aging 13 management programs. Currently, for first license 14 renewal, we have 25 aging management programs. Moving 15 into subsequent license renewal, there will be 48 16 aging management programs.
17 Again, Keith Miller will speak to the 18 aging management program details following my remarks.
19 Next slide, please. During the aging management 20 review, our alignment with the GALL SLR was at 99.7 21 percent, with the use of industry footnotes alpha 22 through echo for aging management reviews.
23 I believe that this high degree alignment 24 to the GALL SLR was the result of the efforts by the 25 NRC staff in the industry to broaden the GALL SLR to NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
23 1 capture the additional material, environment, and 2 aging accommodations that were identified during the 3 first license renewal application.
4 Also, the recent interim staff guidance 5 documents that I previously mentioned also adopted 6 additional aging effects for material and environment 7 combinations that did not previously exist that could 8 now be used during the application development to 9 further increase alignment with GALL SLR.
10 In terms of aging management programs, we 11 have a total of 48 and the associated enhancements 12 will be tracked on an amp-by-amp basis within the 13 Dominion Energy commitment tracking system following 14 issuance of the renewed license.
15 I will leave you with a sense that these 16 commitments were discussed with the station team and 17 agreed upon for implementation.
18 Some commitment items have already been 19 addressed and Dominion Energy will ensure the proper 20 resources in place to implement the commitment on or 21 ahead of schedule.
22 That's all I have for my portion of the 23 presentation. Are there any questions for me before 24 I turn it over to Keith Miller?
25 CHAIR SUNSERI: This is Matt again, maybe NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
24 1 it's a question for you or somebody else later on.
2 I'll just pose it here and then if you can answer it, 3 fine, and if it needs to wait until later, that's fine 4 too.
5 So, you're going to be in the situation 6 where your requirements from your first license 7 renewal are going to be overlapping with the 8 subsequent license renewal.
9 So, is there any synergy there or overlap 10 of activities that either make it more difficult or 11 make it easier to transition to the subsequent license 12 period?
13 MR. AITKEN: I think we're going to touch 14 upon that matter with some of the Keith's information 15 and if we don't hit the bulls eye with the question 16 we'll revisit that.
17 CHAIR SUNSERI: Yes, because I just know 18 some inspections are required in a timeframe tenure 19 before entering the subsequent and the one period 20 they're doing inspections and monitoring as well, I 21 just was curious of how that was going to work.
22 Thanks.
23 MEMBER HALNON: This is Greg, I've got a 24 couple questions if I can.
25 CHAIR SUNSERI: Yes, Greg, go ahead.
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25 1 MEMBER HALNON: You've almost doubled your 2 aging management programs and you said you had 3 sufficient staff. How are those distributed? Are 4 they mostly in the mechanical area?
5 Give me a general overview of the 23 new 6 programs that you have and how those are being 7 distributed with the staff?
8 MR. AITKEN: Yes, Greg, good question.
9 Again, Keith is going to break that down for you in 10 the next few slides and he'll give you a sense of the 11 breakdown between mechanical, electrical and subtle.
12 MEMBER HALNON: Okay, I'll take that as a 13 commitment. The other question, I'm just curious, 14 with the experience you have with the license renewal, 15 have you done any focused self-assessments on the 16 aging management programs that are existing?
17 And if you did, what were the findings 18 there?
19 MR. AITKEN: Yes, we did. We did some 20 effectiveness reviews on the current aging management 21 programs and I think, Keith is going to talk about 22 that. I don't want to steal his thunder because he 23 does have some good information to share with you.
24 MEMBER HALNON: You gave him plenty to 25 talk about, I'll wait.
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26 1 MR. AITKEN: For sure, good question and 2 we appreciate it.
3 MR. MILLER: Thanks, Paul, and good 4 afternoon. Again, my name is Keith Miller and I'm the 5 aging management program lead for the North Anna 6 subsequent license renewal project.
7 I'll be providing an overview of the SLR 8 aging management programs and some other 9 considerations for the Committee today.
10 North Anna SLR project team member have 11 been deeply involved with industry groups such as NEI, 12 EPRI, and the PWR Owners Group.
13 Additionally, as Paul previously 14 mentioned, Dominion Energy actively participated in 15 the identification and development of the ISGs issued 16 in early 2021.
17 Operating experience was reviewed for a 18 ten-year period to inform the aging management 19 programs and in addition to operating experience, 20 recent license renewal RAIs associated with the Surry, 21 Turkey Point, and Peach Bottom SLR projects, and 22 recent first license renewal projects were reviewed 23 for insights.
24 A project team also participated in the 25 Turkey Point and Peach Bottom industry peer reviews to NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
27 1 provide AMP insights and share constructive comments.
2 Prior to the submittal of the application, 3 the effectiveness of aging management activities was 4 assessed using the evaluation elements identification 5 in NEI 1412, which provides industry guidance on AMP 6 effectiveness reviews.
7 I think this goes to one of the previous 8 questions but many of the programs had no gaps 9 identified when that NEI 1412 review was performed.
10 Where gaps were identified, they were recorded in the 11 corrective action program.
12 And those NEI 1412 reviews were discussed 13 in each of the Appendix B sections on operating 14 experience in the application.
15 MEMBER HALNON: This is Greg. Did you 16 have gaps that surprised you to the point where you 17 had to take some immediate action? Or were they just 18 basically administrative?
19 MR. MILLER: Yes, I would characterize any 20 of the gaps you identified as administrative. There 21 was nothing that jumped out to that extent that you 22 highlighted.
23 MEMBER HALNON: I kind of figured that but 24 when you double the programs, I was just curious if 25 there was anything that carried over as corrective NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
28 1 actions that would be used in the new programs to 2 ensure that those gaps didn't show up.
3 MR. MILLER: This slide provides some 4 perspective on the first license renewal AMPs and how 5 they've evolved for subsequent license renewal.
6 25 first license renewal aging management 7 programs were the starting point for the evolution and 8 enhancement into subsequent license renewal aging 9 management programs.
10 All first license renewal aging management 11 activities were continued and incorporated into SLR 12 AMPs. None were discontinued, and several first 13 license renewal AMPs were consistent with GALL SLR or 14 else they required enhancement to be consistent.
15 As sort of an example of how we got to a 16 total of 48 AMPs, we had several first license renewal 17 aging management programs that were subdivided into 18 GALL SLR AMPs.
19 One example I can give you is the 20 containment inspection first license renewal program, 21 which was subdivided into ASME Subsection IWE or IWL 22 inspections. Another example is a work control 23 program, which was actually subdivided into five GALL 24 SLR programs.
25 This pie chart slide shows the final NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
29 1 results of the combination and subdivision process of 2 the first license renewal AMPs, which produced 48 GALL 3 SLR aging management programs. So, I think this gets 4 to another of the previous questions.
5 But you can see there the majority of the 6 SLR AMPs are mechanical-related. We had 28 SLR 7 mechanical programs that evolved from 19 first license 8 renewal programs.
9 You see there's also some significant 10 change from first license renewal to SLR in the 11 structural and electrical areas.
12 For structural we have eight SLR programs 13 that have evolved from four first license renewal 14 programs and electrical has nine SLR programs from two 15 first license renewal programs.
16 And then you can see the three time-17 limited aging analyses. Next I'm going to discuss the 18 consistency of the North Anna AMPs with the GALL SLR.
19 Looking at the left-hand column, you can 20 see there are 41 existing AMPs that resulted from the 21 combination and subdivision process of the first 22 license renewal AMPs.
23 And SLR existing AMPs are augmented by 24 seven new aging management programs. The remainder of 25 the columns provide some perspective on our NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
30 1 consistency with GALL. So, half of the 48 SLR AMPs 2 are consistent without enhancement.
3 Approximately a third are consistent with 4 enhancement. We have three AMPs that are consistent 5 with exception and four have exceptions and 6 enhancements.
7 So, with regards to exceptions, this was 8 particularly a major improvement from Surry.
9 Surry, we had 12 AMPs with exceptions 10 whereas for North Anna we only have 7 AMPs with 11 exceptions. For the next slide, I'll provide some 12 context on the new GALL SLR AMPs and the AMPs with 13 exceptions.
14 CHAIR SUNSERI: I would just comment that 15 I think it's notable you had seven new AMPs and they 16 were all consistent with the GALL, that's very good.
17 MR. MILLER: Thank you for that comment.
18 So, this slide shows our new SLR aging management 19 programs. The first three are mechanical in nature and 20 primarily involve one-time inspections.
21 The next four are electrical-related and 22 involve inspections of inaccessible cables, cable 23 connectors, and high voltage insulators. Next, I'll 24 provide a listing of GALL AMPs with exceptions.
25 So, this slide lists all the AMPs with one NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
31 1 or more exceptions and a brief description of the 2 nature of each exception. The majority of these are 3 related to alternate test frequencies, alternate 4 inspection techniques, or to account for plant-5 specific configurations.
6 It's notable that six of the ten 7 exceptions were confined to just three AMPs indicating 8 that there's not exceptions spread across a large 9 number of AMPs.
10 So, just to give you an example of the 11 category of one that would fall into a test frequency 12 exception, for outfits like cooling water, North Anna 13 takes exception to the requirement to perform testing 14 of the research spray heat exchangers every five 15 years, due in part to the fact that significant design 16 modifications would be required to support heat 17 transfer testing of the research spray heat 18 exchangers.
19 It's notable that their normal plant 20 operation, the recirculation coolers are maintained in 21 dry layout. North Anna flow tests the research spray 22 heat exchangers every 18 months and any current tests 23 individually inspects them every 18 years.
24 And engineering evaluated the once every 25 12 refueling outage at every current inspection NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
32 1 period. They looked at a review of prior operating 2 experience, flow tests between 2009 and 2019 3 identified little or no blockage.
4 And all the tests were completed 5 satisfactorily, as well as piping inspection results 6 between 2007 and 2017 show the piping was in 7 satisfactory condition.
8 An example I can give you of a plant-9 specific configuration exception is related to reactor 10 head closure stud bolting.
11 The GALL recommends the use of material 12 with actual yield strengths of less than 150K a side 13 for replacement studs or 170K a side ultimate yield 14 strength for in-service studs.
15 North Anna studs were not procured under 16 prospects that limited the max yield and ultimate 17 tests of strength, which presents the potential 18 concern for stress corrosion cracking.
19 The volumetric exam method in place for 20 the ASME code is appropriate to identify cracking and 21 no recordable indications of cracking have been 22 identified, indicating the program's been effective.
23 Next slide, please.
24 CHAIR SUNSERI: One question, Keith. On 25 the open cycle cooling water heat exchanger, how much NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
33 1 margin do you have on that heat exchanger between 2 baseline capacity and necessary capacity? Do you know 3 or have any idea?
4 MR. MILLER: Off the top of my head, I 5 don't know but we could take that question to the 6 larger group and get back with you at the next break.
7 CHAIR SUNSERI: I'm just curious, if 8 you're deferring or taking exception to the challenge, 9 I just was curious of how much margin you have to 10 support that. That would be good if you could get 11 that.
12 MEMBER HALNON: Keith, one other question, 13 this is Greg.
14 On the metallic storage tanks, the 15 inspections of tank concrete foundation interfaces, 16 back in 2013, I think in the October letter you guys 17 had one issue that you identified from the earthquake, 18 which is some grouting in containment that I think was 19 cracked between a concrete wall and some grout.
20 Has this exception got anything to do with 21 the earthquake to make sure any movement that would 22 have occurred doesn't carry over into future 23 inspections? What are the exceptions for?
24 Let me ask you that.
25 MR. MILLER: It doesn't have anything to NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
34 1 do with the earthquake. Primarily, it's a plant-2 specific consideration issue. An example I can give 3 you is one piece of the exception is for the emergency 4 common safe storage tanks.
5 They don't use hawking or sealant for the 6 concrete component interface so they don't require 7 inspection of it.
8 Their configuration is a little bit 9 different in that they have a concrete missile shield 10 that surrounds them and expansion filler foam that 11 goes in between the gap between the shield and the 12 tank itself, which prevents water from entering, 13 basically serves the function of what the grout would 14 do at the base of a tank.
15 MEMBER HALNON: So, the term emergency 16 concrete storage tank, is that your emergency 17 feedwater storage for extended-type access?
18 MR. MILLER: It is.
19 MEMBER HALNON: So, that's why it's a 20 missile shield and whatnot to protect it.
21 And the next one down, the column where 22 diesel fuel is just a one-time inspection, why just a 23 one-time inspection?
24 Is it just to make sure everything is 25 installed correctly? Explain why it's just one time.
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35 1 MR. MILLER: Another plant-specific 2 configuration issue, the fuel chemistry program 3 primarily deals with loss of material of metallic fuel 4 tanks. We have recently replaced those fuel tanks 5 with fiber glass tanks.
6 So, we took exception to that so instead, 7 we'll be looking for aging effects associated with 8 polymer materials as opposed to metallic and because 9 it's newly installed, we justified the 30 to 40-year 10 inspection period because it's consistent with initial 11 license renewal fuel chemistry verifications that were 12 identified in NUREG 1801.
13 MEMBER HALNON: So, that one-time 14 inspection is down the road a ways?
15 MR. MILLER: It is. And I should say too 16 that there's also a component to sampling for water 17 and sediment.
18 So, if we do sample and see water and 19 sediment, there are some corrective actions associated 20 with that, that would provide assurance that we don't 21 have microbiological issues in the tank.
22 MEMBER HALNON: Did you use operating 23 experience from outside the nuclear industry on that 24 one? Because I'm sure there's plenty of that for fuel 25 oil tanks underground.
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36 1 MR. MILLER: I don't know the answer to 2 that question. Again, I can get back with you.
3 MEMBER HALNON: I'm just curious if you 4 limited your operating experience to justify that one-5 time inspection to just within the nuclear industry or 6 if you went outside of that.
7 There's probably a ton of operating 8 experience outside nuclear that could be used. So, if 9 you could just go back and let me know what your 10 sample size was there.
11 MR. MILLER: Sure. So, the first license 12 renewal aging management programs have been and will 13 continue to be assessed for AMP effectiveness.
14 As I mentioned before, AMP reviews, 15 including NEI 1412 effectiveness review have confirmed 16 implementation of the first license renewal 17 commitments and performed assessments of inspection 18 schedules, inspection results, and trending data.
19 And again, any identified gaps were 20 addressed or included in the corrective action 21 program.
22 Program owners received periodic training 23 and are required to complete AMP effectiveness for use 24 every five years as well as perform systematic 25 operating experience reviews on an ongoing basis to NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
37 1 inform AMPs and augment AMP effectiveness.
2 As an example of regulatory acceptability 3 of the Dominion Energy aging management programs, the 4 IP 71003 Phase 2 NRC inspection identified no findings 5 or concerns in the fourth quarter of 2017.
6 So, that's all I have for the AMP portion 7 of the presentation.
8 I noted that we have two outstanding 9 questions we're going to chase on margin on research 10 for a heat exchanger and industry operating experience 11 on the polymer diesel tank.
12 Are there any other questions before I 13 turn it over Eric Blocher to discuss technical topics?
14 CHAIR SUNSERI: Members, any questions?
15 Thank you, Keith.
16 MR. BLOCHER: Thank you, Keith and Matt, 17 and good afternoon. My name is Eric Blocher and I was 18 the SLR technical lead for the North Anna TL8As at SLR 19 application development.
20 I will cover the technical topics of 21 concrete and containment segmentation, reactor 22 internals, plant-specific TLAAs, reactor vessel 23 integrity, and reactor vessel support steel.
24 Next slide.
25 Aging management of structural concrete is NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
38 1 accomplished by the aging management programs noted 2 upon the slide. There have been no loss of license 3 renewal intended function due to aging since entering 4 the period of extended operation.
5 Dominion Energy has recently implemented 6 the EPRI alkali silicate reaction inspection guidance 7 that was developed in part by members of the SLR team.
8 The guidance uses identification of 9 leading indicator structures, conduct of augmented 10 examinations for pattern cracking, section of water 11 ingress, and identification of structural 12 misalignment.
13 Plant operating experience has not 14 identified any indications of ASR for the concrete 15 structures at North Anna except for pre-cast concrete 16 poles that support overhead electrical circuits from 17 the Reserve Station Service Transformers to the 18 turbine building.
19 There is a design change currently being 20 implemented that either replaces or refurbishes the 21 pre-cast concrete poles. After the design change is 22 implemented, only three pre-cast concrete poles which 23 are adjacent to the turbine building will remain.
24 The design change will reinforce these 25 three pre-cast concrete poles with a carbon fiber NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
39 1 polymer wrap, which provides confinement and 2 strengthening to the poles and will minimize future 3 ASR-induced expansion.
4 Pre-cast concrete poles were fabricated 5 offsite and their concrete is not representative of 6 the concrete used in other site structures.
7 During the SLR review, service for how 8 Settlement Monitoring Point 28 exceeded 75 percent of 9 the technical requirements manual total allowable 10 settlement.
11 The service water expansion joints were 12 adjusted consistent with technical requirements manual 13 required actions. Settlement Monitoring Point 28 was 14 surveyed and new baseline elevations established for 15 the 4 service water bath house settlement monitoring 16 points.
17 Expansion joints are still well within 18 their limits for face-to-face, lateral, and concurrent 19 movement.
20 North Anna reinforced concrete containment 21 examinations did not identify any loss of intended 22 function or any areas requiring code repair based upon 23 Unit 1 and Unit 2 inspections in the summer of 2016.
24 Unit 1 and Unit 2 concrete containment 25 inspections are currently in progress.
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40 1 Recent examinations of the liner to the 2 concrete slab interface did not identify any relevant 3 conditions based upon Unit 1 and Unit 2 inspections in 4 the summer of 2016 and the summer of Unit 1 5 inspections in the summer of 2021.
6 Examination of the containment liner did 7 not identify any relevant conditions based upon Unit 8 1 and 2 inspections in March 2015 and March 2016.
9 Containment concrete biological shield 10 wall gamma and neutron for radiation remains 11 conservatively low, GALL SLR radiation exposure levels 12 through the subsequent period of operation.
13 Aging management of the North Anna 14 reinforced concrete containments is accomplished by 15 the aging management programs noted on the slide.
16 Next slide, please.
17 North Anna will manage reactor vessel 18 internal's primarily expansion and existing 19 examinations consistent with MRP 227 Rev 1 Alpha 20 inspection and evaluation guidance that was issued in 21 December of 2019 and includes NRC safety evaluation 22 dated April 25, 2019 for the first period of extended 23 operation.
24 The reactor vessel --
25 CHAIR SUNSERI: Did we lose him?
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41 1 MEMBER BROWN: He can call back in.
2 MR. BURKHART: Somebody muted him. They 3 can unmute themselves by hitting star 6. Somebody 4 muted him and please don't do that again.
5 Somebody disabled your mic, now I just re-6 allowed it.
7 Please start.
8 MR. BLOCHER: Okay, I understand we're 9 back on. So, I believe I left off -- Can you hear me?
10 CHAIR SUNSERI: Yes.
11 MR. BLOCHER: I believe we left off with 12 a discussion about our program, including the NRC 13 safety evaluation dated April 25, 2019.
14 The Reactor Vessel Internals Program also 15 incorporates recent NRC interim staff guidance for 16 update teaching management criteria for reactor vessel 17 internal components and PWR that was issued in January 18 of this year.
19 In addition, the examinations for the 10 20 SLR reactor vessel internals components noted on the 21 slide are also incorporated into the PWR Vessel 22 Internals Programs.
23 With the exception of the control rod 24 guide tubes and the middle and lower axial weld 25 examinations, the additional examinations are all NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
42 1 identified in MRP 2018-022 interim SLR guidance, and 2 are required in part due to where the 3 radiation-related degradation, that is very 4 conservatively projected for the subsequent period of 5 extended operation.
6 In addition to PWR vessel internals 7 program, the neutron fluence monitoring program 8 defines and monitors the protected fluence associated 9 with the reactor vessel internals during the 10 subsequent period of extended operation and will 11 supplemental MRP 227 Rev 1 output inspection and 12 evaluation guidance.
13 Next slide, please. Three plant-specific 14 TLA technical reports were updated for 80 years and 15 were recently approved by NRC safety evaluations.
16 These updates demonstrate the value of 17 Dominion Energy's industry leadership and PWR Owner 18 Group's participation.
19 PWR OT 17011, non-proprietary approved 20 Revision 2 confirms the previous initial license 21 renewal reactor coolant pump fly wheel in the fatigue 22 crack growth analysis remains appropriate for 80 23 years.
24 The fatigue crack growth calculation 25 assumes 6000 cycles of the reactor coolant pumps for NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
43 1 the 80 years of plant life bounds the projected North 2 Anna cycle count for the reactor coolant pump 3 operations.
4 ASME Code Case M481 allows the replacement 5 of volumetric examinations of reactor coolant pump 6 casings with a fracture and mechanics-based integrity 7 evaluation supplemented by specific visual 8 examinations.
9 North Anna reactor coolant pump model 93A 10 casings are bounded by the evaluations and conclusions 11 in PWR OG 17033 proprietary approved Revision 1 for 12 the crack stability analysis and the fatigue crack 13 growth analysis.
14 Therefore, ASME Code Case M481 is allowed.
15 PWROG-17033-P-A, Rev 1 projected the reactor vessel 16 under clad fatigue crack growth analysis associated 17 with well deposited cladding to 80 years.
18 North Anna confirmed the three TLA action 19 items identified in the NRC safety evaluation of PWR 20 OG 17031 noted on the slide will be applicable to 80 21 years of operation.
22 Next slide, please. North Anna projected 23 fluence values for a reactor vessel through 80 years 24 of plant operation or based upon 72 effective full 25 power years.
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44 1 This is conservative because the current 2 fluence projection for 60 years of plant operations is 3 50.3 effective full power years for Unit 1 and 52.3 4 effective full power years for Unit 2.
5 It is extended to 80 years using a 100 6 percent capacity factor for the additional 20 years.
7 The PWR Owner's Group assisted Dominion in reviewing 8 the reactor vessel CMTRs for re-baselining the initial 9 toughness values in accordance with the ASME code and 10 branch technical position 5.3.
11 The various reactor vessel time limit aging 12 analysis for pressurized femoral shock, upper shelf 13 energy, flow temperature over pressure protection, and 14 heat-up and cool-down curves were then revised through 15 80 years of plant life using the updated fluence and 16 material property information.
17 Locations with upper shelf energy values 18 that have less than 50 pounds of sharp energy have 19 been assessed through 72 effective full-power years 20 using the equivalent margin analysis method outlined 21 in the ASME code.
22 The applicability of existing heat-up and 23 cool-down curves can be extended to 72 effective full-24 power years based upon using updated material property 25 data and application of the K1C methodology.
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45 1 The reactor vessel surveillance program will 2 update the PT limits through the 5059 process at a 3 later appropriate date.
4 North Anna will use the two aging management 5 programs which are consistent with GALL to manage 6 fluence and embrittlement during the subsequent period 7 of extended operations.
8 Dominion plans to remove and test one 9 surveillance capsule for each reactor prior to the 10 subsequent period of extended operation.
11 This leaves four untested capsules remaining 12 in each unit that are available for a subsequent 13 period of extended operation fluence monitoring.
14 Next slide, please.
15 MEMBER HALNON: Before you go too far on 16 that one, this was very good.
17 We just had a presentation not too long ago 18 about Reg Guide 1.99 Rev 2 which I think you guys 19 used. That showed some significant deviations at 20 super high fluences, 10 to the -19 I think in the 21 upper hood.
22 Where are you guys with your fluence and 23 what that deviation, that 199, now shows happening?
24 Are you getting a margin there?
25 MR. BLOCHER: Yes, this is the embrittlement NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
46 1 trend curve and potential impact of ASME code changes 2 on that. Id like some assistance from Dr. Beth 3 Kehler Haluska for that. Beth, are you online?
4 MS. KEHLER HALUSKA: Yes, can you hear me?
5 MEMBER HALNON: Yes, I can hear you.
6 MS. KEHLER HALUSKA: We would see some 7 changes if the embrittlement trend curve changed.
8 Towards 80 years you'll start to see those higher 9 fluences.
10 But North Anna's capsule and reactor vessel 11 integrity program are designed to ensure that all of 12 the NRC requirements are implemented and changes are 13 made as needed.
14 MEMBER HALNON: I guess the point is those 15 NRC requirements may be changing based on the 16 revelation of this deviation in the curve at high 17 fluences. It looks like if you use international data 18 you'll get a lot better correlations.
19 I guess I was wondering what is the margin 20 to that magical -- it's not really magical -- at least 21 today we see that around 10 to the 19 fluence levels, 22 at 80 years where will these plants be relative to 23 that point?
24 MS. KEHLER HALUSKA: At 80 years they're 25 around 7 times 10 to the 19.
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47 1 MEMBER BALLINGER: This is Ron Ballinger.
2 You use the words magic numbers I guess but if you 3 look at Table 4, Tables 4, it gives you all the 4 fluence in there. Up over the number 6 times 10 to 5 the 19th, which is when you get significant deviation.
6 MEMBER HALNON: Okay, so it's something to 7 keep an eye on very closely obviously, then. This 8 whole study is going in research.
9 MEMBER BALLINGER: In fact, the presentation 10 that we saw, I believe, if I'm correct, North Anna was 11 the example that they used.
12 CHAIR SUNSERI: Steve Schultz has a 13 question. Steve?
14 MR. SCHULTZ: Yes, thank you. Is there any 15 prospective planning associated with those four 16 untested capsules in each unit? Have you thought 17 about that with regards to your long-term fluence 18 management program?
19 MR. BLOCHER: Well, for surveillance 20 capsules we're planning on pulling Capsule X in 2025 21 for Unit 1 and Unit 2 in 2026, and again, that will 22 satisfy both the current period of extended operation 23 and the subsequent period of extended operation.
24 And if you project out, I assume that's what 25 your question is, Steve?
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48 1 MR. SCHULTZ: Yes.
2 MR. BLOCHER: We'll have Capsule Z some time 3 in 2036 for Unit 1 and 2032 for Unit 2, 2043 and 2044, 4 Capsule Y, Unit 1 and Unit 2. And then Capsule T, 5 2049 for Unit 1, 2047 for Unit 2.
6 And again, those projections would be 7 dependent on what we see with Capsule X.
8 MR. SCHULTZ: Of course, I appreciate the 9 tentative schedule, thank you. That helps.
10 MEMBER BALLINGER: According to my records, 11 you've delayed twice removal of capsules, right?
12 MR. SCHULTZ: Exactly.
13 MR. BLOCHER: Yes. Hearing no more 14 questions, next slide, please.
15 The next technical topical I will discuss 16 deals with reactor vessel support steel. Dominion 17 Energy created this sketch to provide an overview of 18 reactor vessel support configuration at North Anna.
19 The reactor vessel supports at Surry and 20 North Anna are similar. The Surry and North Anna 21 reactor supports are different from reactor vessel 22 supports used at many other nuclear plants.
23 At North Anna, reactor vessel support is 24 provided by the neutron shield tank. At some other 25 plants, reactor vessel support is provided by columns NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
49 1 and candelene (phonetic) ravines.
2 This sketch shows the position of the 3 reactor vessel and how it is supported by the neutron 4 shield tank relative to the location of the concrete 5 biological shield goal.
6 The reactor vessel is located in the center 7 of the sketch. The position of the core where the 8 neutrons are generated within the reactor is shown by 9 the blue and gray stripes. The neutron shield tank is 10 shown in blue.
11 The tank is about 23 feet high, it split 34 12 inches, filled with chromated water. The inner and 13 outer plates are 1.5 inches thick. Next to the 14 neutron shield tank is the concrete biological shield 15 wall.
16 The concrete biological shield wall is 4.5 17 feet thick. One of the purposes of the neutron shield 18 tank is to provide shielding to protect the concrete 19 biological shield wall.
20 CHAIR SUNSERI: Eric, this is Matt, let me 21 interrupt you for a second.
22 I know you're in a challenged audio 23 configuration there but if the folks in your room 24 could avoid typing right next to the microphone or 25 shuffling papers?
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50 1 It really comes across pretty loud and I'm 2 having a hard time hearing you.
3 MR. BLOCHER: Okay, let us know if there's 4 problems in the future, Matt. I think we're going to 5 stop shuffling papers.
6 Okay, the other purpose of the neutron 7 shield tank is to transmit loads from the reactor 8 vessel through the supports located under the nozzle 9 of the reactor vessel to the top of the neutron shield 10 tank, and then to the lower elevation of containment.
11 There is no vertical loading on the concrete 12 biological shield wall. Next slide, please.
13 Now that we have reviewed the general 14 configuration of the neutron shield tank, I will 15 discuss the radiation of the reactor vessel support 16 steel for North Anna.
17 At North Anna the support steel of interest 18 is the region of the neutron shield tank adjacent to 19 the reactor core where the neutrons are generated.
20 The radiation of the reactor vessel support 21 steel was originally assessed in 1986 using fractured 22 mechanics in preparation for future license renewal 23 considerations by Stone & Webster under contract from 24 the Department of Energy, Westinghouse Owner's Group, 25 EPRI, and Virginia Power.
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51 1 The original assessment used a Westinghouse 2 discreet ordinance radiation transport fluence model 3 for projecting fluence on the neutron shield tank 4 through 100 years of plant operation, roughly 76.8 5 effective full power years.
6 To address the radiation of the neutron 7 shield tank for SLR, a new fracture mechanics 8 evaluation was performed by Dominion Energy. The new 9 fracture mechanics evaluation uses load for dead 10 weight, LOCA, and seismic.
11 Stress intensity formulas for the ASME code 12 that are normally used for developing heat-up and 13 cool-down limit curves for operation of the reactor 14 vessel, and an infinite amount of fluence based on the 15 use of the lower K1C curve, which is 33.2 KSI square 16 root inches.
17 The analysis shows that the allowable 18 critical stress is greater than the stress on the 19 neutron shield tank, therefore, brittle fracture will 20 not occur.
21 The future mechanics evaluation is bounding 22 through the use of the lower K1C curve, 33.2 KSI per 23 square root inch or NUREG 1509 Section 4.3.4.1. It is 24 permissible to use K1C instead of K1R when there is 25 information available for material toughness.
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52 1 Thus, North Anna fracture mechanics 2 evaluation and neutron shield tank is both bounding 3 and conservative. North Anna has four programs for 4 managing aging of the reactor vessel support steel 5 during the SLR.
6 The closed treated water system monitors the 7 corrosion in each refueling outage. A Section 11 IWF 8 inspection is performed on the nozzle supports every 9 10 years.
10 The structure is monitoring an external 11 services monitoring program performance of visual 12 inspection of the external services of the neutron 13 shield tank and neutron shield tank support skirt.
14 At this time, I will turn the presentation 15 over to Paul Aiken who will provide summary remarks.
16 MR. AITKEN: Thanks, Eric. I hope you found 17 the presentation informative and helpful today. I 18 would just quickly summarize by stating I first want 19 to commend the NRC staff on their efforts over the 20 last couple of years.
21 The staff has worked very hard in reviewing 22 the North Anna application and in conducting the 23 various public meetings which provided the appropriate 24 form for stakeholder involvement.
25 I want to emphasize that the Department of NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
53 1 Energy has been engaged and integrated with the work 2 leading up to SLR issuance through our highly 3 experienced team.
4 We have been heavily invested along with the 5 others in the industry over the last couple of years 6 to ensure that we have the appropriate guidance and 7 have explored areas for optimization with the NRC 8 staff.
9 Dominion Energy has developed a high-quality 10 application for North Anna, has benefitted from the 11 insights and lessons learned gained from the Surry 12 application that I mentioned earlier.
13 As Paul Phelps mentioned at the opening, 14 Dominion Energy will continue to invest in North Anna 15 Power Station and into the future to ensure the 16 continued safe and reliable operation for 80 years.
17 So, this ends our prepared remarks. I know 18 we have a couple of opening questions. I think we can 19 try to address the research with Willie.
20 MR. LLOYD: Yes, I'm Willie Lloyd, the site 21 engineering manager at North Anna Power Station.
22 Our USFAR for North Anna assumes a two 23 percent plugging margin. Our program for heat 24 exchangers, those calculations assume a one percent 25 plugging margin is allowable.
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54 1 For these heat exchangers, each heat 2 exchanger has 1500 tubes and that results in a 15-tube 3 plugging margin and then for 2 of those heat 4 exchangers, 1 on each unit they have 1 plug each.
5 So, programmatically, we have in most heat 6 exchangers 15 allowable tubes margins for plugging and 7 for those two heat exchangers I spoke of, there would 8 be 14 tubes available.
9 And then it would be a double-back for the 10 ultimate USFAR margin.
11 CHAIR SUNSERI: Very good, that answers my 12 question, I appreciate it.
13 MR. AITKEN: Okay, I think Keith Miller will 14 address the question on the tank.
15 MR. MILLER: Yes, I can circle back on the 16 fuel and storage tanks. So, the short answer is we 17 didn't look outside of the nuclear industry for OE 18 related to these types of tanks.
19 But we are very confident in the one-time 20 inspection for a couple of reasons. First, the tank 21 was just installed in 2015, so it's basically new.
22 Also of note is the double-wall tank.
23 I should point out that, and this is in the 24 justification in the application, the Vermont Yankee 25 first license renewal safety evaluation report NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
55 1 documented that underground fiberglass diesel fuel 2 tanks do not have any aging effects requiring 3 management.
4 So, we're not expecting any aging with these 5 tanks without having water or microbiological 6 contamination. And a little bit more on that, we are 7 sampling for water and sediment quarterly. We do look 8 for bacteria if water is present and treat with a 9 biocide if bacteria are present.
10 And also, on the periodicity, the draining 11 and cleaning between 30 and 40 years of service, 12 that's consistent with GALL Revision 2 guidance, which 13 recommended performing those types of inspections 14 within 10 years of the initial period of extended 15 operation, which would be that 30 to 40-year window.
16 MEMBER HALNON: Thanks for that. I had 17 some experience with some polymer tanks and basically, 18 it wasn't installed correctly and we had some shifting 19 of the soils and it caused some problems.
20 So, I was just curious, I'm sure the 21 modification took into account all the different 22 requirements for soil in protecting from creep and 23 other things.
24 I never really did get a good feel from the 25 aging management programs.
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56 1 I mentioned that it looks like you almost 2 doubled the amount of programs you had and I was 3 curious if it caused any excessive burden on any part 4 of the staff relative to either mechanical, 5 electrical, INC type of thing.
6 Was it pretty well distributed or did you 7 have to share some resources with Surry, or add any 8 resources because of the amount of aging management 9 programs you had to have or modify?
10 That's probably a question for leadership.
11 MEMBER BROWN: Greg, I think they dropped 12 off but they're trying to call back in.
13 MEMBER HALNON: I don't know if I can ask 14 the question again. I'll try to figure it out, see if 15 I can ask it more succinctly.
16 CHAIR SUNSERI: Well, if they dropped off, 17 did the public line drop? I don't see it. Oh, wait, 18 there it is.
19 MEMBER HALNON: We can move on, it's not a 20 critical question, it's more curiosity, Matt. We can 21 go ahead and move on.
22 CHAIR SUNSERI: I believe Dominion was 23 finished with their presentation.
24 MEMBER BROWN: Matt?
25 CHAIR SUNSERI: Yes.
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57 1 MEMBER BROWN: Can I backtrack for a second?
2 It's Charlie.
3 CHAIR SUNSERI: Sure, I was going to ask 4 members if you had anything before we --
5 MEMBER BROWN: I'm ahead of you. Should I 6 go on?
7 CHAIR SUNSERI: Yes.
8 MEMBER BROWN: Could you backtrack to Slide 9 -- if I can find it for myself.
10 CHAIR SUNSERI: We're not going to be able 11 to do that because we lost the applicant.
12 MEMBER BROWN: I can do this without that.
13 Okay, it doesn't matter. Is the applicant still on at 14 all?
15 CHAIR SUNSERI: They will be joining again.
16 MEMBER BROWN: Should I wait then because 17 the question is to them?
18 CHAIR SUNSERI: Okay, if the question is to 19 them then yes, wait.
20 MR. HOWARD: They are about to be back on 21 people, hang on. Hang on, Charlie.
22 MEMBER BROWN: That's okay.
23 MR. HOWARD: They should be up now.
24 MR. AITKEN: We're back. Sorry, challenges 25 of the virtual world, I guess. That ended our NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
58 1 prepared remarks. I think Charlie had a question.
2 MEMBER BROWN: Yes, you talked about 3 existing GALL lamp programs, a number of them with 4 enhancements. Looking at the electrical items, I just 5 had a question on -- I'll just use one as an example.
6 And it applied to I think your Section 7 B2.1.37, it was on electrical installation of 8 electrical cables and connections not subject to 10 9 CFR 5059,environmental qualification requirements.
10 And that's an existing program today and 11 you're expanding that program. You had about half a 12 dozen or more enhancements to it.
13 Just an example of the enhancements, which 14 is where I have the questions, I'll just use an 15 example instead of all seven of them, like if adding 16 a description of the testing methodology, should 17 testing be deemed necessary?
18 That's one item. These during the visual 19 lead will be addressed through the corrective action 20 program and another one which comes out says that 21 verify that test results for the cable are to be 22 within acceptance criteria as identified in the 23 procedures.
24 I guess I would have expected all of those 25 items to be part of the existing program and not have NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
59 1 to be added as enhancements. I was going to ask the 2 question of the staff but it's really you all's 3 program so I thought I'd ask that of you.
4 And the last thing you say in each of these 5 is you will implement the enhanced program within six 6 months, I think, of the period of extended operation 7 in the subsequent license period.
8 I guess my question is why aren't those 9 specific types of items needed today? It gives the 10 implication that we don't evaluate test results 11 against acceptance criteria but now you're going to do 12 it later. I'm not trying to be critical, it's just 13 that's the way it read.
14 MR. DISOSWAY: This is John Disoway, I'm 15 responsible for the electrical portion of the 16 application. So, what we found in looking at this as 17 well as Surry is that the procedure that was used for 18 initial license renewal was a type of procedure called 19 the guidance and reference document, which is not a 20 level of document, we'll call it a tier of document 21 that we would now consider acceptable to implement 22 this kind of program.
23 So, what we're trying to say, which may not 24 have been worded the best, in here is that we're 25 replacing that particular type of guidance document NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
60 1 with a procedure, a standard procedure.
2 So, it's a matter of are rewriting the 3 guidance that was given originally and the guidance 4 and reference document into a higher-tier procedure.
5 That captures not only what we're already 6 doing but it also captures the few items that were 7 more or less an increased focus with subsequent 8 license renewals.
9 That's really what that's trying to get to.
10 It's not that we have not done that type of inspection 11 with that type of analysis in the past, it's just the 12 type of document we're using procedurally to document 13 what we're doing.
14 MEMBER BROWN: Okay, so I take it from the 15 explanation that in fact, if you went back and looked 16 at what you were doing today explicitly, you're 17 already into your first license renewal, in fact, you 18 would be looking at the test results and making sure 19 they're within the acceptance criteria?
20 It's just that it's not called out the right 21 way? Is that what you're telling me?
22 MR. DISOSWAY: Let me give you a different 23 example that maybe is better.
24 A subsequent license renewal being done with 25 sample size 20 percent, maximum sample of 25 to be NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
61 1 tested, that type of guidance does not exist for 2 initial license renewals either.
3 So, that's the type of thing we're adding as 4 we upgrade this procedure. That's what we're saying.
5 In fact, we've done this inspection before 6 and the things that we found which were minimal were 7 evaluated and were addressed by engineering 8 transmittal to accept what was found in the fields 9 corrected.
10 So, it's not a matter of not evaluating, 11 it's a matter of how we evaluate it, and the fact that 12 there are some things that are included in subsequent 13 license renewals not represented in initial license 14 renewals that we're putting in.
15 MEMBER BROWN: I guess the staff ought to 16 amplify that for me so we don't hold things up. If 17 they can keep that in their knapsacks until we get 18 there? Is that okay, staff?
19 CHAIR SUNSERI: Yes, that's fine, Charlie, 20 you'll have to remind him.
21 MEMBER BROWN: I will.
22 I'm not trying to be critical, it's just the 23 way they were worded made it sound like -- when you 24 say connection materials, insulation is make sure 25 they're the acceptance criteria within the boundaries NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
62 1 or the values within the acceptance criteria.
2 It has very specific wording, that's why I 3 asked the question. I'll finish at that point.
4 CHAIR SUNSERI: Any other members? All 5 right, thank you for that presentation, very good.
6 We'll go into the staff presentation right now but 7 it's 3:17 p.m.
8 Why don't we take a little bit of a break to 9 allow a transition here? While the staff is getting 10 their shared screen up and getting ready, the rest of 11 us will take a break until 3:25 p.m.
12 Is that right? Yes, 3:25 p.m. Eastern time.
13 We are recessed until 3:25 p.m. Thanks.
14 (Whereupon, the above-entitled matter went 15 off the record at 3:18 p.m. and resumed at 3:25 p.m.)
16 CHAIR SUNSERI: Okay, it's 3:25 p.m., we 17 will reconvene the meeting. At this point, we are 18 ready to hear from the staff and I will turn the floor 19 over to I believe it's Hector Rodriguez Luccioni.
20 MR. RODRIGUEZ-LUCCIONI: Yes, good 21 afternoon, can you hear me?
22 CHAIR SUNSERI: Yes, very well, thank you.
23 MR. RODRIGUEZ-LUCCIONI: Good afternoon, 24 Chairman Sunseri and members of the ACRS. My name is 25 Hector Rodriguez and I go by they, he, and she NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
63 1 pronouns. I am a project manager for the safety 2 review of subsequent license renewal applications, or 3 SLRA.
4 We are here today to discuss the NRC 5 staff's safety review of the North Anna Power Station 6 SLRA as documented in the safety evaluation report.
7 Joining me today are Lauren Gibson, chief of the 8 License Renewal Projects Branch; Jen England, North 9 Anna's senior resident inspector; and Dr. Allen Hiser, 10 senior technical advisor for license renewal, Aging 11 Management Division of New and Renewed Licenses. Also 12 joining us are members of the technical regional 13 staff.
14 We will begin today's presentation with an 15 overview of the safety review of the North Anna SLRA 16 before moving onto the SER specifically to Section 2, 17 the scoping and screening review, Section 3, the 18 18 management review, Section 4, the time-limited aging 19 analysis.
20 Then we will hear from Region II on 21 inspections and plant material conditions before 22 sharing the conclusions of the different views as 23 related to the North Anna accelerated review.
24 North Anna Units 1 and 2 were initially 25 licensed in April 1978 and August 1980 respectively.
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64 1 In May 2001, the applicant, Virginia Electric and 2 Power Company, or Dominion, submitted the initial 3 license renewal application.
4 The initial renewed licenses were issued in 5 March 2003 extending the expiration dates to April 6 2038 and August 2040 for Units 1 and 2 respectively.
7 On August 24, 2020, Dominion submitted an SLRA for 8 North Anna Units 1 and 2.
9 The application was accepted for review on 10 October 15, 2020 and the draft safety relation report 11 was issued on October 18, 2021 with no open 12 confirmatory items.
13 The North Anna review is the fourth safety 14 review performed by the staff using the GALL SLR and 15 SLP SLR guidance since their issuance in 2017.
16 Between the third and fourth SLR reviews, we 17 implemented the lessons learned, including 18 consolidating the previous three audits into single 19 audit with three parts, an office technical review 20 audit, onsite audit, and an in-office breakout 21 session.
22 During the in-office technical review 23 portion of the audit, the staff reviewed information 24 presented in the application by specific operations 25 experience provided by the applicant in the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
65 1 application, and audit information provided on the 2 electronic portal.
3 During the next phase of the audit, the 4 staff developed audit questions that were discussed 5 with the applicant during the breakout session to 6 better understand the information provided in the 7 application and to fill holes in the development of 8 the safety evaluation report.
9 The onsite audit portion of the audit is 10 limited to those technical areas that needed further 11 review following the in-office audit. For North Anna, 12 no onsite audit was performed through the COVID-19 13 pandemic.
14 The North Anna Draft SER was issued with no 15 open or confirmatory items on October 18, 2021 --
16 CHAIR SUNSERI: Hector, can I interrupt you 17 for a second? I think your slides are off by quite a 18 few by now. It seems like they're advancing by two 19 every time. I think you're on Slide 5 right now but 20 I'm not sure.
21 Are you on the right slide?
22 MR. RODRIGUEZ-LUCCIONI: No, I'm not, thank 23 you. Let me go back, I am on Slide 5.
24 CHAIR SUNSERI: Thank you, it helps to keep 25 up with you so thanks.
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66 1 MR. RODRIGUEZ-LUCCIONI: Thank you so much.
2 The North Anna draft SER was issued with no 3 open or confirmatory items on October 18, 2021.
4 During the staff in-depth technical review, a total of 5 47 requests for information were issued.
6 38 requests for additional information and 7 9 requests for confirmation of information. In the 8 next few slides, I will present the results of the 9 staff's safety review as described in the SER.
10 The SER Section 2 described the scoping and 11 screening of structures and components subject to 12 aging management review. The staff reviewed the 13 applicant's scoping and screening methodology, 14 procedures, and results.
15 The staff also reviewed the various 16 summaries of the safety-related system structures and 17 components, the non-safety-related system and 18 components affecting safety functions, and system 19 structure and components relied upon to perform 20 functions in compliance with the Commission's 21 regulation for fire protection, environmental 22 qualification, station blackout, anticipated 23 transience without scram, and pressurized thermal 24 shock.
25 Based on the review, the results from the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
67 1 audits and additional information provided by the 2 applicant, the staff concluded that the scoping and 3 screening methodology and implementation were 4 consistent with the criteria of the SRP SLR and 5 requirements of 10 CFR Part 54.
6 CHAIR SUNSERI: I have a question. You 7 mentioned because of the pandemic we were not able to 8 do the, quote, on-site portion of the audit. Did that 9 have any effect on you?
10 Was there any compensatory action --
11 (Simultaneous speaking.)
12 CHAIR SUNSERI: -- in the resident inspector 13 photographs? Can you walk me through that a little 14 bit?
15 MR. RODRIGUEZ-LUCCIONI: That's correct, the 16 staff actually work with an applicant by virtually 17 getting pictures and videos and anything that was 18 requested. It was uploaded to the e-portal and that 19 way they were able to continue the review.
20 CHAIR SUNSERI: So, you were able to 21 complete the audit then with some, I'll call it, 22 visualization of the material conditions of the 23 station?
24 MR. RODRIGUEZ-LUCCIONI: Correct.
25 CHAIR SUNSERI: Thank you.
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68 1 MEMBER BALLINGER: This is Ron Ballinger.
2 To follow up on that, what you said was, at least what 3 I thought I heard was, that normally what happens is 4 you do an onsite audit and then based on the results 5 of the onsite audit, you do the next step I guess.
6 I'm wondering whether or not not being able 7 to do the onsite audit may have resulted in missing 8 something, is that possible?
9 MR. RODRIGUEZ-LUCCIONI: The three onsite 10 audits for the technical review in the office that 11 everybody does, based on that technical review in the 12 office, which is the first step of the audit, the 13 technical staff make a decision if they need these 14 onsite audits.
15 Not every single technical staff requires to 16 do an onsite audit. It depends on what they looked at 17 in the application and if they need or require 18 additional information to continue their review.
19 And then the next step is breakout questions 20 and breakout sessions, and the breakout session 21 questions may be based on the initial review that they 22 did or additional information that they need after 23 they do the onsite audit.
24 But the onsite audit does not need to have 25 it unless the technical staff need it.
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69 1 MEMBER BALLINGER: Thank you.
2 MEMBER HALNON: Typically, isn't the scoping 3 and screening results a comprehensive walk-down of the 4 plant done to make sure the scoping was done 5 appropriately, non-pandemic?
6 MR. RODRIGUEZ-LUCCIONI: Lauren, there was 7 an echo.
8 MS. GIBSON: Yes, we just switched with the 9 method of me getting on. This is Lauren Gibson, I'm 10 the Branch Chief. There are different procedures for 11 the initial license renewal than there are for the 12 subsequent license renewal.
13 And so that type of walk-down may have been 14 part of the initial but it's not part of the 15 subsequent license renewal right now.
16 MEMBER HALNON: That makes sense. This is 17 my first experience with subsequent so, yes, I'm kind 18 of going off a little bit of the first license renewal 19 knowledge.
20 So, I guess there would be a delta analysis 21 on first versus subsequent license renewal to see if 22 anything additional is added. I'm making that 23 assumption but that would trigger me to at least ask 24 questions, I think.
25 MS. GIBSON: We do usually review the whole NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
70 1 thing as an application as a whole, not just delta 2 from what was in the initial one.
3 MEMBER HALNON: All right, thanks.
4 MR. RODRIGUEZ-LUCCIONI: Any additional 5 question before I continue?
6 So SER Section 3 and it's subsections cover 7 the staff's review of the applicant's program for 8 managing the effects of aging in accordance with 10 9 CFR 54.2183.
10 Section 3.1 through 3.6 include the aging 11 management review or AMR items in each of the general 12 system areas within the scope of subsequent license 13 renewal as shown on this slide.
14 For a given aging management review item, 15 the staff reviewed the item in accordance with the 16 criteria of the SRP SLR to determine whether it is 17 consistent with the GALL SLR.
18 For AMR items not consistent with the GALL 19 SLR, the staff reviewed the applicant's evaluation to 20 determine whether the applicant has demonstrated that 21 there is reasonable assurance that the effects of 22 aging will be adequately managed so that the intended 23 functions will be maintained, consistent with the 24 current licensing basis for the subsequent period of 25 extended operation.
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71 1 Based on the review, the results from the 2 audits, and additional information provided by the 3 applicant, the staff concluded that the applicant's 4 aging management review activities and results were 5 consistent with the criteria of SRP SLR and the 6 requirements of 10 CFR Part 54.
7 The SLRA describes a total of 48 AMPs, 7 new 8 and 41 existing. The slide identified the applicant's 9 original disposition of these AMPs as stated in the 10 SLRA in the left column and the final disposition, as 11 documented in the SER in the right column.
12 All of the AMPs were evaluated for 13 consistency with the GALL SLR. As a result of the 14 review, the staff documented one staff-identified 15 exemption in the neutral influence monitoring program 16 in the SER.
17 This accounts for the different and the 18 existing programs consistent with GALL SLR from 17 19 consistent in the SLRA to 16 consistent in the SER.
20 And 24 consistent with enhancements are exemptions to 21 25 consistent with enhancements and/or exemptions.
22 Also, in preparing for this presentation, we 23 identified an error in SER Table 3.01. North Anna 24 aging management programs selective leaching shall be 25 new and consistent, not new and consistent with NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
72 1 enhancements.
2 Neutron influence moderating should be 3 existing and consistent with exemptions. The SER 4 section for selective leaching mentions an enhancement 5 in the various piping program and this enhancement was 6 inadvertently translated to Table 3.01.
7 The SER section for neutral influence 8 monitoring notes that staff identified exceptions. We 9 will character this in the final SER.
10 Based on the review, the results from the 11 audits and additional information provided by the 12 applicant, the staff concluded that the applicant's 13 aging management program activities and results were 14 consistent with the criteria of the SRP SLR and 15 requirements of 10 CFR Part 54.
16 SER Section 4 identifies time-limited aging 17 analysis or TLAAs. Section 4.1 documents the staff's 18 evaluation of the applicant's identification of 19 applicable TLAAs.
20 The staff evaluated the applicant's basis 21 for identifying those plant-specific or generic 22 analysis that need to be identified as CLAAs and 23 determine that the applicant has provided an accurate 24 list of TLAAs as required by 10 CFR 54.21 C1.
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73 1 review of the applicable TLAAs for the areas shown on 2 this slide.
3 Based on the review and the information 4 provided by the applicant, the staff concludes that 5 each TLAA is classified, as required by 10 CF 54.21 C1 6 as either the analysis remains valid for the 7 subsequent period of extended operation, that analysis 8 has been projected to the end of the subsequent period 9 of extended operation, or the effects of aging on the 10 intended functions will be adequately managed for the 11 subsequent period of extended operation.
12 Based on the review, the results from the 13 audits, and additional information provided by the 14 applicant, the staff concluded that the applicant's 15 CLAA activities and results were consistent with the 16 criteria of SLP SLR and the requirements of 10 CFR 17 Part 54.
18 At this time, I would like to pass it to 19 Alan Hiser that will discuss specific areas of review.
20 MR. HISER: Thank you, Hector. As Hector 21 mentioned, my name is Allen Hiser, I'm the senior 22 Technical advisor for license renewal and aging 23 Management in the Division of New and Renewed 24 Licenses.
25 Since the draft SER was issued with no open NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
74 1 or confirmatory items, I will highlight some specific 2 areas of the review. The first topic identified on 3 this slide is a plant-specific item that was 4 identified during the staff's review.
5 The remaining topics were identified in the 6 Commission's staff requirements memorandum on 7 subsequent license renewal. This is SRM-SECY-014-8 0016, which was issued in August 2014.
9 In the SRM these items were identified as 10 requiring plant-specific evaluation until generic 11 resolutions were approved. Next slide. The plant-12 specific addresses varied great cast-iron piping in 13 the fire protection system.
14 This piping had six ruptures prior to 2003 15 with the root cause identified as cracking due to 16 cyclic loading that occurred during pump start 17 testing.
18 The plant changed the test procedures to 19 limit the pressure transient in the downstream piping 20 and no ruptures have occurred since 2003. Multiple 21 inadvertent pump starts have occurred since 2003 22 without any ruptures occurring.
23 The gray cast iron piping material is also 24 subject to loss of material due to selective leaching 25 and the material was identified in Dominion documents NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
75 1 as brittle from impact testing.
2 Next slide, Hector.
3 MEMBER HALNON: This is Greg. Just real 4 quick, they had some underground leaks other than fire 5 protection system piping so there's a 2016 fuel oil 6 leak where the pipes are replaced. Was this extended 7 condition any concern of you guys when you were 8 looking at the full gamut of underground piping?
9 MR. HISER: If I could ask Brian Allik. Are 10 you available, Brian?
11 MR. ALLIK: Yes, this is Brian Allik with 12 the staff. So, this specific issue on the slide, I 13 believe that was carbon steel lines that fuel oil 14 2016, is that correct?
15 MEMBER HALNON: Yes, correct, it was 16 December of 2016 fuel oil.
17 MR. ALLIK: So, that certainly impacted our 18 review. That's why we asked questions about cathodic 19 protection, making sure those buried steel lines are 20 coded.
21 So, this cyclic loading issue wasn't 22 pertaining to the gray cast iron that wasn't really 23 part of the steel review that we did.
24 MEMBER HALNON: So, you chased the other 25 leaks to your satisfaction then?
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76 1 MR. ALLIK: Yes, so the difference here was 2 those are where you would have leaks before you would 3 have a rupture in the system where you had a brittle 4 type fracture.
5 So, that's why this issue was flagged in the 6 acceptance review letter that we issued a month or two 7 after receiving the application.
8 MEMBER HALNON: I'm done, Ron, go ahead.
9 MEMBER BALLINGER: I was looking at the gray 10 cast iron leaks and it made me wonder, I'm assuming 11 you did a root cause analysis, or they did, and if you 12 get rupture on these things without some kind of other 13 degradation prior to that, does that tell us the 14 margin is pretty low?
15 MR. HISER: I think their conclusion for the 16 root cause was that there was crack growth from the 17 manufacturing flaws if you will that's in the piping.
18 So, there was additional aging that 19 ultimately resulted in a rupture when these pressure 20 spikes occurred from the pump start test.
21 MEMBER BALLINGER: So, it was an initiation 22 and propagation followed by ruptures?
23 MR. HISER: That's correct.
24 And as indicated on the prior slide, they 25 have had multiple similar, if you will, pressure NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
77 1 excursions, presumably from inadvertent pump starts 2 and have had no failures.
3 MEMBER BALLINGER: I think I recall 4 something about that. Now, the enhancements to the 5 aging management program, are we satisfied that they 6 have identified what samples need to be taken where?
7 MR. HISER: Yes, we are.
8 MEMBER BALLINGER: Thank you.
9 MR. HISER: We're on Slide 12. The 10 applicant provided two enhancements to the buried and 11 underground piping and tanks program, directed towards 12 management of selected leaching for Enhancement 5.
13 And then also cracking due to cyclic loading 14 in Enhancement 6.
15 For these enhancements the applicant 16 committed to Excavate 6 gray cast iron locations of 17 each unit in each ten-year operating period beginning 18 prior to entering the subsequent period of extended 19 operation.
20 So, a total of three periods under which 21 they would do these excavations.
22 Five of these excavations will be ten-foot 23 blanks of piping, the remaining excavation will be 24 either piping or a component location, for example, a 25 hydrant location with a focus on identification of NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
78 1 selective leaching in that sixth location.
2 For the piping location, the applicant will 3 use visual and magnetic particle testing to inspect 4 for cracking on both the inside diameter and the 5 outside diameter of the piping.
6 If cracks are identified, the applicant will 7 perform radiography on a one-foot length to determine 8 the cause of the cracking. If the cause is from 9 manufacturing flaws and not an age-related degradation 10 mechanism, then the results from the inspections will 11 be documented.
12 If the cracking is identified as due to 13 aging, then the applicant will perform crack and lost 14 stability evaluations that will cover through the end 15 of the subsequent period of extended operation.
16 If these evaluations project a loss of 17 function of the piping, this finding will be entered 18 into the applicant's corrective action program for an 19 evaluation of an extent of condition, an extent of 20 cause, and to identify any needed follow-on actions.
21 The staff found these enhancements to be 22 adequate to provide reasonable assurance that the 23 piping will perform its intended functions during the 24 subsequent period of extended operation.
25 MEMBER BALLINGER: This is Ron Ballinger NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
79 1 again. I think we're talking about two different 2 things here. It's one thing to identify areas where 3 you suspect selective leaching might be occurring and 4 do that inspection.
5 But if the failures before due to crack 6 initiation and propagation were due to manufacturing 7 defects of some kind, then that's pretty random. And 8 it's hard for me to understand how you would decide 9 what section of pipe to excavate to deal with those.
10 And then you would have to fall back on 11 operational parameters that don't result in start/stop 12 cycles for the pumps.
13 MR. HISER: Their inspections will look at 14 locations that they believe are potentially 15 susceptible to the cyclic loading. And I guess from 16 that perspective, they are out there taking a look at 17 some of the piping.
18 And just to be clear, they did change their 19 pump test procedure, and to me that's where the 20 inadvertent pump starts provide some assurance there 21 are not conditions that would have led to failure 22 during the inadvertent pump starts.
23 MEMBER BALLINGER: Thanks.
24 MR. HISER: Next slide, Hector.
25 One of the topics identified in the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
80 1 Commission's SRM on subsequent license renewal relates 2 to reactor pressure vessel neutron embrittlement at 3 high fluence.
4 This topic has two aspects, the adequacy of 5 the applicant's reactor vessel material surveillance 6 program, and the disposition of the vessel 7 embrittlement, time limited aging analyses for the 80-8 year operating period.
9 This slide identifies the peak reactor 10 vessel levels for each unit on the left, which are in 11 excess of 7 times 10 to the 19 neutrons per 12 centimeters squared on the reactor vessel surface.
13 The applicant has identified one capsule at 14 each unit to assess the RPV embrittlement at the 80-15 year fluence levels. As indicated, testing of these 16 capsules will occur in about the next five years.
17 On the right side of this slide, we plotted 18 the completed surveillance testing and the planned 19 testing for North Anna Unit 1. The graph for Unit 2 20 is nearly identical to this.
21 The axes on this graph are calendar time on 22 the IKSISA and the neutron fluence on the ordinate.
23 The blue dashed lines represent the 60-year RPP 24 fluence and the end of the current 60-year license.
25 The solid green lines represent the same NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
81 1 quantities for 80 years. The solid black data-points 2 provide the neutron fluence and the test date for the 3 prior tested capsules.
4 The orange symbols represent the applicant's 5 change in testing of a capsule to obtain the 80-year 6 fluence.
7 In this case, the applicant will test the 8 capsule that is located at a higher neutron flux 9 location and will acquire data for 80-year fluence 10 levels earlier than originally planned.
11 Next slide, Hector.
12 MEMBER HALNON: Allen, do you recall the 13 capacity factor they assumed?
14 MR. HISER: I believe for an 80-year fluence 15 it was 7280 FPY. It's actually indicated on the slide 16 on the screen, it's about 90 percent for the entire 17 80-year operating period. I think as Eric mentioned, 18 they've assumed more than 100 percent capacity factor 19 for the 60 to 80-year period.
20 MR. HISER: For the TLAAs, time-limited 21 aging analyses, certain RPV materials at Unit 2 were 22 projected to exhibit upper shelf energies below the 23 50-foot pound limit of Appendix G to 10 CFR Part 50.
24 For all of the RPD materials in both units, 25 the applicant implemented equivalent margin analyses, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
82 1 or EMAs, to demonstrate adequate safety margins for 2 these locations to the end of the subsequent period of 3 extended operation, consistent with the requirements 4 of Appendix G to 10 CFR Part 50.
5 Regarding pressurized thermal shock, the 6 applicant projected the pressurized thermal shock 7 evaluations to the end of subsequent period of 8 extended operation and demonstrated all of the RPD 9 materials meet the screening criteria in 10 CFR 50.61 10 generally with considerable margin.
11 The applicant has demonstrated that the 12 upper shelf energy and pressurized thermal shock TLAs 13 had been projected to the end of the subsequent period 14 of extended operations in accordance with 10 CFR 54.21 15 C(1)(ii).
16 Next slide, Hector. There is no staff 17 approved generic methodology for aging management of 18 reactor vessel internals for 80 years of operation.
19 The SLR report finds it acceptable for 20 applicants to use the staff-approved guidance for 60 21 years and MRP 227 Revision 2 in combination with a gap 22 analysis to identify appropriate changes in the 23 inspection program for 80 years of operation.
24 The GALL SLR guidance for PWR reactor 25 internals has been updated in recent interim staff NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
83 1 guidance, SLR ISG 2021-01-PWRVI, which allows use of 2 MRP 2018-022 for fluence-related screening of RVI 3 components.
4 As Hector mentioned, the scope of the 5 applicant's neutron fluence monitoring AMP is limited 6 to the monitoring of the neutron fluence exposures of 7 the reactor pressure vessel materials, which 8 represented an exception from the GALL SLR AMP, X.M2, 9 neutron fluence monitoring.
10 For the assessment of neutron fluence 11 projections for the reactor pressure vessel internals 12 components at 72 effective full power years, the staff 13 reviewed the vessel internal neutron fluence exposures 14 as part of its review of the PWR vessel internals 15 aging management program and the gap analysis in 16 Appendix C of the SLRA.
17 From its audited information, the staff 18 verified that the neutron fluence methodology and the 19 calculated fluence values for the internal components 20 are acceptable.
21 The staff also verified that the 22 component-specific fluence exposures were consistent 23 with the MRP guidance identified in the ISG-SLR, and 24 thus acceptable for use in the RVI aging management 25 program.
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84 1 Next slide. In this structural area, two 2 topics were identified for effects of radiation, 3 specifically for the concrete biological field or CBS 4 wall, and the reactor vessel steel support assemblies.
5 The latter is principally the neutron shield 6 tank structural steel and sliding support feet 7 assemblies. The staff reviewed various applicant 8 documents, audit activities, and requests for 9 additional information.
10 Next slide, please. For the CBS wall, the 11 staff agreed with the applicant that a plant-specific 12 program was not necessary for several reasons, 13 principally because the calculated limiting neutron 14 fluence and the limiting gamma dose on the CBS wall 15 are below criteria in the SRP-SLI.
16 In addition, the maximum temperature 17 estimated in the CBS wall concrete including radiation 18 induced heating is also below the criteria in the SRP 19 SLR.
20 In lieu of a plant-specific program, the 21 applicant stated that it will continue to monitor 22 accessible areas in the CBS wall by visual inspection 23 on a five-year interval using a structures monitoring 24 program.
25 Based on this approach, the staff concluded NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
85 1 that the effects of aging due to radiation on the CBS 2 walls will be adequately managed so that the intended 3 functions will be maintained, consistent with the CLB 4 during the subsequent period of extended operation.
5 For the reactor vessel steel supports, the 6 applicant at the application included a fracture 7 mechanics evaluation consistent with NUREG 1509 and 8 concluded that a plant-specific program is not needed.
9 The staff's review of this evaluation 10 concluded that the fractured mechanics evaluation 11 adequately addressed the loss of fracture toughness of 12 the RVE steel supports for the subsequent period of 13 extended operation.
14 In addition, the staff concluded that other 15 aging effects for the reactor vessel steel supports 16 specifically, loss of material and loss of mechanical 17 function, will be adequately managed by the structures 18 monitoring, the external surface monitoring of 19 mechanical components and the closed treated water 20 system AMPs to provide reasonable assurance that 21 applicable aging effects will be adequately monitored 22 and managed during the subsequent period of extended 23 operation.
24 Next slide, please. Capable qualification 25 is required in accordance with 10 CFR 50.49 and as a NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
86 1 PLAA for subsequent license renewal.
2 The applicant disposition to TLAA in 3 accordance with 10 CFR 5421 C(1)(iii) by demonstrating 4 that the effects of aging on the intended functions 5 will be adequately managed for the subsequent period 6 of extended operation.
7 The staff reviewed each U for environmental 8 components AMP and finds it acceptable to manage the 9 qualification PLAA because it is consistent with all 10 SLR AMPs X.E1.
11 For cable condition assessment, in addition 12 to aging management of electrical installation for in-13 scope, inaccessible meeting voltage power cables, the 14 applicant also proposed aging management for in-scope 15 and accessible instrumentation and control cables and 16 low-voltage power cables.
17 The AMPs proposed by the applicant are 18 condition monitoring AMPs, however, periodic actions 19 are taken to prevent inaccessible in-scope cables for 20 being exposed to significant moisture such as 21 identifying and inspecting conduit ends in cable 22 manhole vaults for water accumulation and removing the 23 water as needed.
24 The inspections are performed based on 25 plant-specific operating experience with cable wetting NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
87 1 or submergence. The periodic inspection occurs at 2 least annually.
3 Additional inspections for water 4 accumulation are also performed after event-driven 5 occurrences such as heavy rain, rapid thawing of ice 6 and snow, or flooding.
7 staff reviewed these AMPs and finds them 8 acceptance because they are consistent with the 9 related GALL SLR AMPs that are indicated in this 10 slide.
11 Based on its review, the staff concluded 12 that the applicant has demonstrated that the effects 13 of aging will be adequately managed so that the 14 intended functions will be maintained consistent with 15 the COB for the subsequent period of extended 16 operation as required by 10 CFR 54.21 A3.
17 Next slide.
18 MEMBER BROWN: Before you shift slides, this 19 is Charlie again. I asked a question before, did you 20 hear it or do I have to repeat it?
21 MR. HISER: Actually, if you could repeat it 22 because we have the electrical reviewer too?
23 MEMBER BROWN: Yes, I want to get your read.
24 You did a nice job of going through the enhancements 25 and giving a break-out of what was added to existing NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
88 1 program elements that they have in place today.
2 And I guess I was a little surprised, and 3 I'm not quite sure I understood their answer all the 4 way, when I think Enhancement 6 on the D2137, which is 5 I think if I read it again it's electrical insulation 6 for electric cables, connections not subject to 10 CFR 7 50.49.
8 There were seven or eight, seven I think, 9 enhancements on this one and they had at the 10 description of the testing methodology in case testing 11 should be deemed necessary, that was Enhancement 4.
12 Then they added a requirement that if 13 anomalies are found during visual, they will address 14 during a corrective action program.
15 I would have expected in the last one I used 16 in the example was adding a requirement for the test 17 results when they run insulation resistance or time to 18 remain or whatever type of testing they're doing.
19 The test results equally over the last 50 20 years would have been addressed to ensure they were 21 within acceptance criteria, and yet, they've been 22 added to this, and its nice that it's written down, 23 but did you all see that as it wasn't there before or 24 not? I understand they're consistent with the 25 generalities in the GALL, as you all stated, but did NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
89 1 you all read that as something they hadn't been doing 2 before?
3 Or what? Is your electrical guy there?
4 MR. NGUYEN: I cannot check that. My name 5 is Duc Nguyen, I am the technical review of the 6 electrical portion. Okay, let's go back to the 7 history of the GALL, the GALL Version 2, Revision 1, 8 Revision 2.
9 We did not require the applicant to do the 10 testing for the interim control cable and a low-11 voltage cable. So, they had one pull-down which 12 includes XIE1 and XIE2 and XIE3.
13 But the XIE3 is only covered intercepted 14 medium voltage and that program testing was only 15 there. The testing acceptance criteria is spelled out 16 in the general document.
17 So, after we issued the GALL revised 3M, 18 XIE1A, E1B, and E1C, this one, they'll provide 19 acceptance criteria in the position. And the staff 20 during the oversight inspection will look at the 21 procedure.
22 Typically, the acceptance criteria would not 23 include the end, it would include a specific 24 procedure. And the procedure according would actually 25 pay 400, it would spell out what the acceptance NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
90 1 criteria, how often you have to test.
2 So, for medium voltage cable, they have to 3 do the testing every six years and if they don't miss 4 the criteria they have to sort the frequency and 5 eventually, if they don't meet the criteria they have 6 to replay the cable.
7 So, that's already there. For the low-8 voltage cable and internal-controlled cable, initially 9 they don't have the program because of the GALL 10 Revision 2, Revision 1, and Revision 3.
11 We don't have that program because the 12 water-free phenomenon only affected the medium from 13 the cable. But seeing we issue the generic order, we 14 found out some examples for low-voltage cable 15 failures.
16 So, that's why we edit in the subsequent 17 license renewal but the third license renewal, these 18 two programs are not there.
19 So, we added subsequent license renewal but 20 to answer your question, test procedure is always 21 there in the original engineering program.
22 Does that answer your question?
23 MEMBER BROWN: I'm working on it.
24 I appreciate the little bit of history back 25 on the original GALL because I know we went through NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
91 1 the existing version of it a little while ago in terms 2 of what we would do for the subsequent license 3 renewals.
4 So, you're telling me, if I read you right, 5 that the GALL before, this expanded what was already 6 required in the GALL that was approved for SLRs?
7 MR. NGUYEN: Yes.
8 MEMBER BROWN: And we provide more 9 definition to it. That didn't mean they weren't doing 10 what they should be doing before, and I presume you 11 all would have known that if they hadn't, I hope?
12 MR. NGUYEN: Yes.
13 MEMBER BROWN: Let me ask the second. I'll 14 accept your answer on that. I'm not going to mouse-15 milk this one too hard.
16 The other thing they committed to with these 17 new requirements, they're 18 years away from SLRs 18 right now, they're quite a while. I think it would be 19 2038 or so. They said they would be implementing this 20 within six months prior to the subsequent period of 21 extended operations. So, we're going to go 17 or 18 22 years without these, quote, enhancements.
23 And you all deem that okay even though they 24 needed to add those for the SLR? But it's okay to go 25 --
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92 1 MR. NGUYEN: I plan to do the low-voltage 2 cable and not the concern for the water tree. The 3 water tree only concerns from the voltage. So, now 4 this program during the subsequent license renewal, 5 they still inspect the water. They still inspect the 6 water in the manhole and remove the water every 7 quarter.
8 MEMBER BROWN: But I'm now looking at the 9 medium-voltage one. The medium-voltage one had the 10 same issues in it.
11 MR. NGUYEN: As they do right now, they 12 still continue to do now to the subsequent license.
13 They still do it right now. They have to require to 14 test and they have to require to remove the water in 15 the manhole.
16 MR. HISER: Can I jump in for a minute?
17 MR. NGUYEN: Yes.
18 MR. HISER: I think partly what may be going 19 on is the enhancements are things that are not 20 identified in their current AMP but it is things they 21 are doing by plant procedure.
22 So, in order to bring their program as 23 defined in their program documents up to be consistent 24 with GALL SLR, they need to take these things that 25 they are currently doing and identify them NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
93 1 specifically in the GALL SLR AMP.
2 MEMBER BROWN: Thank you, I guess what 3 you're saying is that they're doing them, they're not 4 as part of the existing GALL programs they have for 5 their extended procedure but they are in other 6 procedures. They're not getting lost, in other words.
7 MR. HISER: That's correct and the applicant 8 may be able to confirm that.
9 MEMBER BROWN: I'll take your word for it.
10 You guys know how to look for stuff. You answered my 11 question. This applied to a number of the different 12 electrical testing operations. The medium voltage one 13 was my biggest concern because there were seven 14 enhancements on that one as well.
15 It's nice to have them explicitly called out 16 but medium voltage, we've had issues in the past when 17 we were looking at extensions on how were their 18 medium-voltage cables addressed and were they 19 satisfactory? That's what triggered my thought 20 process based on some of our reviews from several 21 years ago.
22 MR. HISER: That is a subtle point, that 23 enhancements may not be things I'm not doing now but 24 suddenly I'll start to do them, they're just not 25 within my program definition right now.
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94 1 MEMBER BROWN: It was just the way it was 2 worded that was raised and I asked the question.
3 You've satisfactorily answered my question and I 4 appreciate that.
5 MR. HISER: Okay.
6 MEMBER BROWN: Thank you very much.
7 MR. NGUYEN: You're welcome.
8 MR. HISER: If we go to the next slide, Jen 9 England, senior resident inspector at North Anna, will 10 present retail activities associated with license 11 renewal. Jen?
12 MS. ENGLAND: Good afternoon. My name is 13 Jennifer England and I use the pronouns she and her.
14 I'm the acting senior resident inspector at North 15 Anna. With me is Kenya Carrington, North Anna 16 resident inspector; Adam Wilson, our senior project 17 engineer; and Stu Bailey, our branch chief.
18 We are here to provide Region II's review 19 and assessment of the implementation of the aging 20 management programs, material condition, and overall 21 regulatory assessment of North Anna Units 1 and 2.
22 The license renewal inspection program and 23 the RLP baseline inspection program are both used to 24 inspect aging management activities at North Anna.
25 I'll start with the activities performed NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
95 1 under the license renewal inspection program, then 2 discuss the ROP inspections and follow up with 3 material condition of the plant.
4 In order to assess the adequacy of the 5 license renewal program for the initial period of 6 extended operation, inspection procedure 71003 7 recommends using a four-phase approach to license 8 renewal inspections.
9 This slide details the specific license 10 renewal inspections that have been performed at North 11 Anna. The Phase 1, 2, and 3 inspections were 12 performed for both units on the dates listed with no 13 findings identified.
14 Finally, the Phase 4 inspection, which 15 typically occurs 5 to 10 years into the period of 16 extended operation has not been performed at North 17 Anna as the period of extended operation began in 2018 18 for Unit 1 and 2020 for Unit 2.
19 Next slide, please.
20 In addition to the inspections mandated by 21 the license renewal inspection program, inspectors use 22 several ROP-baseline procedures to evaluate the 23 implementation of aging management activities.
24 As an example, the baseline inspection of 25 the in-service inspection program, this inspection is NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
96 1 performed each refueling outage and provides the 2 inspectors the opportunity to review and assess 3 inspections credited for aging management.
4 The second example is the HESIC inspection, 5 which provides the inspectors an opportunity to review 6 the service water system including heat exchangers, 7 the service water intake structure, and both above 8 ground and buried or inaccessible piping and 9 components.
10 All of these activities are within the scope 11 of license renewal. Lastly, the design basis assures 12 inspection or DBAI includes a review of the aging 13 management activities for the safety structure systems 14 and component selected.
15 At North Anna, the regional inspectors have 16 found no violations or findings of greater than green 17 significance as a result of the inspections performed 18 using these procedures.
19 Also of note, the tri-annual fire protection 20 procedure has been updated to review aging management 21 of this equipment. Next slide, please.
22 MEMBER HALNON: Jen, this is Greg, did you 23 guys see any trends in their cross-cutting areas?
24 MS. ENGLAND: No, we have not. Currently, 25 North Anna Units 1 and 2 are in the licensee response NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
97 1 column and have all green findings and performance 2 indicators.
3 This indicates that the licensee has been 4 able to effectively identify conditions adverse to 5 quality and correct them in a timely manner.
6 We did want to highlight some inspection 7 results that relate to the material condition of the 8 plant.
9 As mentioned, no findings were identified 10 during the license renewal program inspections but in 11 2013, the NRC issued a self-revealing green finding 12 for the failure to establish and implement appropriate 13 periodic maintenance for the Charlie 4 capacitor in 14 the speed era amplifier card, which resulted in a 15 reactor trip.
16 In 2021, the NRC identified a green finding 17 and a non-cited violation for inadequate instructions 18 for handling of aged cables. This procedure did not 19 identify the allowable end radius for battery cabling.
20 Next slide, please.
21 MEMBER BROWN: Jen, could you go back? Stay 22 on the existing slide, please. I just had a question.
23 It's just an understanding question.
24 On the previous slide, if you go back it was 25 on the 2013, the C4 capacitor that was in the -- what NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
98 1 system or what instrument was that in or do you know?
2 MS. ENGLAND: Yes, it was for the main 3 turbine, it resulted in a turbine trip and a reactor 4 trip.
5 MEMBER BROWN: That's not unexpected. I've 6 been dealing with this stuff in the naval nuclear 7 program forever, since 1965. Is that now a standard 8 part of their PMs for this particular capacitor or 9 inspections?
10 MS. ENGLAND: Yes.
11 MEMBER BROWN: It doesn't bother me, it just 12 that's kind of a very unique thing to focus in on one 13 capacitor when I suspect that there's other individual 14 cases that face different failure modes at various 15 times with age. And I just wanted to understand it a 16 little bit better. So, they're replacing that 17 periodically now because of this?
18 MS. ENGLAND: Yes, that's correct. We 19 basically wanted to go through and we went back to 20 pre-2013 just to look for anything related to aging 21 management and just bring anything we could find to 22 your attention.
23 MEMBER BROWN: Thanks. Just out of 24 curiosity, just good information for me since I've not 25 been in the commercial world that long, only the last NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
99 1 12 years.
2 (Simultaneous speaking.)
3 MEMBER KIRCHNER: Jen, this is Walt 4 Kirchner. On the last bullet on this slide, was the 5 inadequate procedure finding -- not finding, but was 6 that identified because there was a degraded 7 safety-related cable that was found?
8 Do you see what I mean? Did you have a 9 plant-related problem that led to determining there 10 was an inadequate procedure? Was this just a desk 11 review of procedures that uncovered this issue?
12 MS. CARRINGTON: Jen, I can speak to that.
13 This is Kenya Carrington, Resident Inspector. So, we 14 had a design basis assurance inspection this year 15 performed at North Anna and inspectors performed a 16 walkdown of various areas of the plant.
17 They reviewed various procedures. So, it 18 wasn't specifically related to a degraded cable but 19 the procedure was based on how they handle degraded 20 safety-related cables, if that answers your question.
21 MEMBER KIRCHNER: Thank you.
22 MS. ENGLAND: I can add a little bit to 23 that. If they manipulate the cables, they didn't have 24 criteria to ensure that the bed radius was not 25 exceeded. And that was what was identified in the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
100 1 inspection, if that detail helps you at all.
2 MEMBER KIRCHNER: Thank you very much.
3 CHAIR SUNSERI: Steve Schultz has his hand 4 up. Go ahead, Steve.
5 MR. SCHULTZ: Walter began the discussion.
6 I presume then that essentially, the corrective action 7 was identified as part of the inspection finding?
8 MS. CARRINGTON: That would be correct. The 9 licensee placed this issue or captured this issue into 10 their corrective action program.
11 MR. SCHULTZ: And resolved the issue?
12 MS. CARRINGTON: That's correct.
13 MR. SCHULTZ: Thank you.
14 MS. ENGLAND: Are there anymore questions?
15 CHAIR SUNSERI: No, please continue, thanks.
16 MS. ENGLAND: Next slide, please. I will 17 now speak to the material condition of North Anna from 18 the resident inspector viewpoint. Overall --
19 MS. CARRINGTON: Sorry, Jen, we have another 20 question. Steve Schultz, do you have a question?
21 MR. SCHULTZ: That was just my question, I'm 22 just taking my hand down. Thank you.
23 MS. ENGLAND: Overall, the plant that is in 24 its first period of extended operation, the material 25 condition is generally acceptable. The licensee has NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
101 1 been successful at completing large, capital 2 improvement projects that maintain or improve the 3 material condition of its structured systems and 4 components.
5 The licensee renewal program inspections did 6 not identify any substantial weaknesses in the 7 station's performance in managing the effects of aging 8 at the site. The inspectors will continue to 9 inspection and assess the licensee's ability to manage 10 the effects of aging through the NRC's baseline 11 inspections. Are there any additional questions?
12 MEMBER BROWN: This is Charlie Brown again.
13 You say the plant condition is generally acceptable, 14 that gives a connotation that there's something that's 15 not generally acceptable.
16 (Simultaneous speaking.)
17 MS. ENGLAND: And it is. We don't generally 18 bless them off and say it's excellent or something 19 like that, that's just not --
20 MEMBER BROWN: That part I got. I just 21 would have not put generally, I just would have said 22 plant condition is acceptable. Our sailors would have 23 gotten killed if they said we were sort of okay but 24 not really.
25 (Simultaneous speaking.)
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102 1 MEMBER BROWN: It's wordsmithing, that's 2 all.
3 MS. ENGLAND: Lessons learned. Are there 4 any other questions? Okay, I would like to hand the 5 presentation over to Lauren, thank you.
6 MS. GIBSON: This is Lauren. Good 7 afternoon. Before we get to our final wrap up slide, 8 Id like to note that we did receive two different 9 professional views during the review.
10 They both related to the gray cast iron 11 piping in the fire protection system. Management has 12 been working to address the issues.
13 As part of that, we ask the licensee through 14 an RAI to ensure that their FSAR supplement portion 15 matches the program description that they've given in 16 the supplements and previous RAI responses.
17 We received that from the licensee and are 18 reviewing it. The final SER will address that RAI in 19 the response. Next slide, please.
20 In conclusion, for the SLRA safety review, 21 the staff finds the requirements of 10 CFR 54.29A have 22 been met for the subsequent license renewal of North 23 Anna Power Station Units 1 and 2.
24 We will now be happy to answer any 25 additional questions that you may have. Thank you.
NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
103 1 MEMBER BALLINGER: This is Ron Ballinger.
2 I looked at the buried piping thing pretty carefully.
3 Can you tell us the nature of the differing 4 professional opinions? Not the detail, I suppose, but 5 just the nature of them.
6 MS. ENGLAND: No, we can't at this time.
7 We're still working through the process and the 8 details on it will be available closer to when the SER 9 is issued as final. Everything will be documented.
10 Allen, is there anything further that we can 11 say?
12 MR. HISER: No, just that we're working to 13 resolve them and at that point, the entire packages 14 should be made public, I think is the expectation 15 right now.
16 CHAIR SUNSERI: As I read through the SER, 17 I saw in this area a lot of what looked like 18 additional requests for additional information as the 19 review is conducted. And those RAIs have been 20 addressed and incorporated into the SE.
21 So, is it fair to say that the technical 22 aspects of any concerns are incorporated into the 23 current version of the SC that we reviewed?
24 Can I have the licensee's response?
25 MS. GIBSON: I think it would be fair to say NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
104 1 that there's a differing professional view on whether 2 or not they have been.
3 MR. HISER: And we do have the FSAR RAI that 4 went out recently and that the applicant has responded 5 to. That is a part of our technical review.
6 CHAIR SUNSERI: Very good then.
7 MEMBER BROWN: Matt, when's our full 8 Committee meeting on this?
9 CHAIR SUNSERI: February 2, 2022.
10 MEMBER BALLINGER: This is Ron again. I 11 don't know what the exact procedure needs to be, but 12 is this something that we need to think about delaying 13 until we have a completed adjudication of the 14 difference of professional opinions?
15 MS. GIBSON: No, we will have the completed 16 adjudication of the differing professional view when 17 the final SER is published to support the ACRS 18 Subcommittee meeting.
19 MEMBER BROWN: You mean full Committee 20 meeting?
21 MS. GIBSON: I'm sorry, yes, I mean full 22 Committee meeting.
23 CHAIR SUNSERI: Which is on track for 24 February still with the final SE?
25 MS. GIBSON: Yes, and the documentation NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
105 1 related to these views will be made publicly available 2 to support that meeting.
3 MEMBER BALLINGER: Good, thank you.
4 CHAIR SUNSERI: Good questions. Any other 5 members' questions?
6 MEMBER KIRCHNER: Just a comment, Matt, this 7 is Walt. We should go back and look at the other 8 differing professional views on the same topical area 9 for another plant.
10 MEMBER BALLINGER: That's the reason I was 11 making the comments.
12 MEMBER KIRCHNER: I think we just should 13 revisit what we heard then. It seems to me this is a 14 very similar issue. Thank you.
15 CHAIR SUNSERI: I have some points that I 16 think should be included for the full Committee 17 briefing and I'll characterize how I've got this 18 covered. But any other questions from members?
19 I would just say this has gotten a lot of 20 attention here at the end of this meeting. The ACRS 21 is always appreciative of hearing from individuals 22 with differing views and it just aids in informing our 23 own technical perspectives on these topics.
24 It helps us identify whether or not we 25 missed anything or not. So, we are interested in the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
106 1 outcome of the review and so as far as the full 2 Committee goes, I have a couple of recommendations 3 here.
4 First off, I think for the full Committee 5 review, we don't need so much emphasis on the process 6 improvements. Those were interesting and we're always 7 glad to hear those from the Subcommittee's perspective 8 and see that progress has really been made on 9 improving the process and learning from the industry.
10 We seek to improve our process as well.
11 I don't think there needs to be so much 12 emphasis at the full Committee because it's not 13 relevant to the license approval.
14 The grey cast iron pipe, the cyclical 15 fatigue, I think that would be an area that we would 16 love to see emphasized in the technical part of the 17 presentation in addition to the reactor pressure 18 vessel fluence.
19 Both those topics have been of general 20 interest to the full Committee outside of subsequent 21 license renewals. So, just touching on those I think 22 would be important.
23 And then finally, to get the update on the 24 outcome of the differing professional view or 25 assessment or reconciliation. So, those are the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
107 1 things to be emphasized.
2 Any questions about that?
3 MS. GIBSON: No, but I've gotten written 4 down in my notes that this is what you'd like.
5 CHAIR SUNSERI: Members, anything else?
6 Okay, at this point, we would like to open up the 7 floor to any comments that the general public might 8 have.
9 So, members of the public listening in, this 10 is your opportunity to provide a statement or comment.
11 If you are on a phone, you can unmute using star 6.
12 If you're in the Teams session, just unmute your phone 13 on your entry and make your statement.
14 All right, we can close the public line, not 15 close it, close it figuratively speaking. And I've 16 offered the same courtesy that any members of staff or 17 others listening in on the Teams chat as a member of 18 the public, any comments?
19 All right, well, then I suppose that 20 concludes are meeting today. I would like to express 21 appreciation to the Dominion staff.
22 I know it's hard work operating the plants 23 and this time of year there's a lot of things going 24 on, so we appreciate the senior staff took such 25 valuable time and devoted it to this.
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108 1 And this activity is certainly useful to us 2 as we deliberate the application. The staff 3 presentations were informative and very insightful so 4 thank you to the staff.
5 Thank you to our staff for helping make this 6 virtual call or meeting a success. So, without any 7 further comments, I will adjourn this meeting. Thank 8 you, the meeting is adjourned.
9 (Whereupon, the above-entitled matter went 10 off the record at 4:30 p.m.)
11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1716 14th STREET, N.W., SUITE 200 (202) 234-4433 WASHINGTON, D.C. 20009-4309 www.nealrgross.com
North Anna Power Station Units 1 and 2 Subsequent License Renewal Application ACRS Sub-Committee Meeting December 15, 2021
Introductions
Paul Phelps - SLR Director Paul Aitken - SLR Manager Keith Miller - SLR Technical Lead Eric Blocher - SLR Technical Lead Craig Heah - SLR Technical Lead 2
Agenda Station Overview/Performance SLR Application Development SLR Aging Management Programs Technical Topics Closing Remarks 3
North Anna Power Station 4
Station Overview Unit 1 Unit 2 Full Power License - 2,775 MWt April 1, 1978 August 21, 1980 (Operating (Operating License Issued) License Issued)
Independent Spent Fuel Storage Loading Pad 1: 1998, Pad 2: 2008, (ISFSI) Pad 3: 2021 4.3% Power Uprate to 2,893 MWt 1986 First License Renewal Approval 2003 1.6% MUR to 2,940 MWt 2010 Entered Period of Extended Operation April 1, 2018 August 21, 2020 Current License Expiration April 1, 2038 August 21, 2040 5
Station Overview 6
North Anna Performance North Anna operates on an 18-month refueling frequency Plant Capacity Factor:
- 2018: U1 - 91.14% U2 - 101.93%
- 2019: U1 - 94.53% U2 - 90.38%
- 2020: U1 - 101.7% U2 - 88.41%
Regulatory Status
- ROP Actions Matrix Column 1
- All ROP Indicators are Green 7
Significant Plant Modifications North Anna Power Station Unit 1 Unit 2 A/B RSS Transformer Replacement 2021 2021 C RSS Transformer Replacement 2019 2019 Reactor Vessel Upflow Conversion 1996 2018 Buried Fuel Lines Replacement- EDG Transfer Pumps 2017 2017 Reactor Vessel Head Replacement 2003 2003 Main Transformer Replacement 2006 2006 Station Service Transformers Replacement 2010 2010 Main Generator Replacement 2014 2008 Underground Fire Protection Piping Replacement 2012 2012 Fire Detection System Replacement 2021 2012 Service Water Spray Array Piping Replacement 2009 2009 AL-6XN Service Water Charging Piping Replacement 2001 N/A Service Water Instrument Air Compressor Dryer 2003 2003 Replacement Underground Security Diesel Generator Fuel Oil Supply 2015 N/A Tank Replacement Flux Thimble Tube Replacements 2016 N/A 8
SLR Application Development 9
SLR Application Improvement Implementation of Lessons Learned from Surry
- Fewer Than Half the Enhancements
- Led Industry/NRC Effort to Identify and Issue ISGs
- Reduced Number of AMPs with Exceptions Review Process Improvement
- Focus on Minimizing Multiple-Round RAIs
- OE Audit - Integrated with Safety Audit 10
Integrated Plant Assessment Deltas between First License Renewal (FLR) and Subsequent License Renewal
( SLR)
Scoping & Screening
- Minimal Differences from FLR (pre-GALL)
- Some updates required to address 10 CFR 54.4(a)(2)
- Followed NUREG-2191 (GALL-SLR) and NUREG-2192 (GALL-SRP)
Aging Management Reviews
- NAPS FLR was pre-GALL, additional aging effects required disposition based on NUREG-2191 (GALL-SLR)
Aging Management Programs
GALL SLR Consistency Submittal consistent with GALL-SLR High AMR Consistency (99.7% Notes A thru E)
License Renewal Commitments
- 48 Aging Management Programs
- UFSAR Supplement (Appendix A)
- Managed by the Dominion Commitment Tracking System Implementation activities have begun and will continue following issuance of renewed license 12
SLR Aging Management Programs 13
North Anna SLR AMP Considerations NEI involvement, collaboration with EPRI, and PWROG participation informed AMPs with New Industry Guidance, R&D products, and NRC Interim Staff Guidance Incorporation of operating experience (OE):
- Industry and plant specific OE reviewed for a 10-year period
- Participation in Industry Peer Reviews AMP Effectiveness Reviews performed on all first license renewal AMPs using elements of NEI 14-12 14
First License Renewal AMPs All First License Renewal (FLR) AMPs will be continued and incorporated into SLR AMPs:
No FLR AMPs discontinued Some FLR AMPs are consistent with GALL-SLR AMPs Several FLR AMPs required enhancement for consistency with GALL-SLR AMPs Several FLR AMPs subdivided into other GALL-SLR AMPs 15
Mechanical Column1 Structural XI.M1 ASME Section XI Inservice Inspections, XI.M30 Fuel Oil Chemistry XI.S1 ASME Section XI, Subsetion IWE Subsections IWB, IWC, and IWD XI.M2 Water Chemistry XI.M31 Reactor Vessel Material Surveillance XI.S2 ASME Section XI, Subsetion IWL XI.M3 Reactor Head Closure Stud Bolting XI.M32 One-Time Inspection XI.S3 ASME Section XI, Subsetion IWF XI.M10 Boric Acid Corrosion XI.M33 Selective Leaching XI.S4 10 CFR Part 10, Appendix J XI.M11B Cracking of Nickel-Alloy Components and Loss of Material Due to Boric Acid-Induced Corrosion in XI.M35 ASME Code Class 1 Small-Bore Piping XI.S5 Masonry Walls Reactor Coolant Pressure Boundary Components XI.M12 Thermal Aging Embrittlement of Cast Austenitic XI.M36 External Surfaces Monitoring of Mechanical XI.S6 Structures Monitoring Stainless Steel (CASS) Components XI.S7 Inspection of Water-Control Structures XI.M16A PWR Vessel Internals XI.M37 Flux Thimble Tube Inspection Associated with Nuclear Power Plants XI.M38 Inspection of Internal Surfaces in Miscellaneous XI.M17 Flow-Accelerated Corrosion XI.S8 Protective Coating Monitoring and Maintenance Piping and Ducting Components XI.M18 Bolting Integrity XI.M39 Lubricating Oil Analysis Electrical XI.E1 Electrical Insulated for Electrical Cables and Connections Not Subject to XI.M19 Steam Generators XI.M41 Buried and Underground Piping and Tanks 10 CFR 50.49 Environmental Qualification Requirements XI.E2 Electrical Insulation for Electrical Cables and XI.M42 Internal Coatings/Linings For In-Scope Piping, Connections Not Subject to XI.M20 Open-Cycle Cooling Water System Piping Components, Heat Exchangers, and Tanks 10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits XI.E3A Electrical Insulation for Inaccessible Medium-XI.M21A Closed Treated Water Systems TLAA Voltage Power Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements XI.E3B Electrical Insulation for Inaccessible Instrument XI.M23 Inspection of Overhead Heavy Load and Light X.M1 Fatique Monitoring and Control Cables Not Subject to 10 CFR 50.49 Load (Related to Refuling) Handling Systems Environmental Qualification Requirements XI.E3C Electrical Insulation for Inaccessible Low-XI.M24 Compressed Air Monitoring X.M2 Neutron Fluence Monitoring Voltage Power Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements XI.M26 Fire Protection X.E1 Environmental Qualification of Electric Components XI.E4 Metal Enclosed Bus XI.M27 Fire Water System XI.E5 Fuse Holders XI.M29 Outdoor and Large Atmospheric Metallic Storage XI.E6 Electrical Cable Connections Not Subject to 10 Tanks CFR 50.49 Environmental Qualification Requirements XI.E7 High Voltage Insulators 16
North Anna SLR - 48 GALL-AMPs Consistent With With Exception Plant with Enhancement Exception and Specific GALL-SLR Enhancement Existing 41 17 17 3 4 0 New 7 7 0 0 0 0 Total 48 17
New SLR AMPs XI.M32 - One-Time Inspection XI.M33 - Selective Leaching XI.M35 - ASME Code Class 1 Small Bore Piping XI.E3B - Inaccessible Instrument and Control Cables Not Subject to 10 CFR 50.49 XI.E3C - Inaccessible Low-Voltage Power Cables Not Subject to 10 CFR 50.49 XI.E6 - Electrical Cable Connections Not Subject to 10 CFR 50.49 XI.E7 - High Voltage Insulators 18
AMPs with Exceptions X.M2 Neutron Fluence Monitoring
- Monitoring for changes in fluence values of reactor vessel internal components XI.M3 Reactor Head Closure Stud Bolting
- Closure stud yield strength and ultimate tensile strength recommendations XI.M20 Open-Cycle Cooling Water System
- Recirc spray heat exchanger test interval XI.M27 Fire Water System
- Fire pump suction screen inspection alternative
- Main drain test frequency of water-based system risers XI.M29 Atmospheric Metallic Storage Tanks
- Inspections of caulking at tank/concrete foundation interfaces
- Emergency Condensate Storage Tanks external surface examination alternative XI.M30 Fuel Oil Chemistry
- One Time Inspection of the recently installed polymer diesel fuel oil storage tank XI.M42 Internal Coatings/Linings
- Service water inspection sample size, inspection, and re-inspection frequency
- Inspection frequency for turbine lube oil storage and transfer subsystem 19
FLR AMP Effectiveness FLR AMPs have been evaluated for AMP effectiveness:
- AMP reviews conducted in 2016 and 2017
- FLR commitments have been implemented
- Assessment of inspection schedules, results and data have been conducted Identified gaps have been included in the CAP system as described in Appendix B Periodic AMP effectiveness reviews are required to be completed by the program owners every 5 years OE is systematically reviewed on an on-going basis Training is conducted periodically for program owners IP 71003 Phase 2 inspection identified no findings or concerns in 4Q17 20
Technical Topics 21
Concrete and Containment Degradation SLRA Sections Addressing GALL-SLR Recommendations Concrete and 3.5.2.2.1 Pressurized Water Reactor and Boiling Water Reactor Containments containment 3.5.2.2.2.6 Reduction of Strength and Mechanical Properties of Concrete Due To Irradiation 4.6 Containment Liner Plate, Metal Containments, and Penetrations Fatigue Analysis degradation A1.29 ASME Section XI, Subsection IWE A1.30 ASME Section XI, Subsection IWL A1.32 10CFR Part 50, Appendix J A1.34 Structures Monitoring A1.35 Inspection of Water-Control Structures Associated with Nuclear Power Plants Concrete overall is in good condition
- With exception of the reserve station service transformer concrete poles, no effects of ASR have been identified for NAPS concrete structures
- During SLRA review, Service Water Valve House SM-28 exceeded 75% of the TRM total allowable settlement. Service water expansion joints were adjusted consistent with TRM required actions. SM-28 was surveyed and new baseline elevations established
- NAPS concrete structures are managed consistent with GALL-SLR AMPs XI.S2, ASME Section XI, Subsection IWL, XI.S6, Structures Monitoring, and XI.S7, Inspection of Water-Control Structures Associated with Nuclear Power Plants The NAPS reinforced concrete Containments are in good condition
- Recent containment liner - slab interface region examinations did not identify degradation
- Containment concrete biological shield wall gamma and neutron irradiation remains within conservative radiation exposure levels, through SPEO, consistent with GALL-SLR
- NAPS will manage each Containment consistent with GALL-SLR AMPs XI.S1, ASME Section XI, Subsection IWE, XI.S2, ASME Section XI, Subsection IWL, and XI.S4, 10CFR Part 50, Appendix J 22
Reactor Vessel Internals (RVI)
SLRA Sections Addressing GALL-SLR Recommendations Aging management 3.1.2.2.9 Aging Management of PWR Vessel Internals (GAP Analysis) 3.1.2.2.10(2) Loss of Material Due to Wear of reactor vessel A1.7 PWR Vessel Internals internals A2.2 Neutron Fluence Monitoring B2.1.7 PWR Vessel Internals NAPS will manage RVI Primary (P), Expansion (E), and Existing (X) examinations consistent with MRP-227, Rev. 1-A and associated NRC Safety Evaluation dated April 25, 2019 In addition, the following SLR RVI component examinations are also incorporated into the PWR Vessel Internals program:
- MRP-2018-022:
Primary: Clevis Insert Bolts, Clevis Insert Dowels, Thermal Sleeves, Radial Support Key and Clevis Bearing Stellite Wear Surfaces Existing: Fuel Alignment Pins (Malcomized)
- WCAP-17451, Rev 2: CRGT Continuous Section Sheaths and C-Tubes (Expansion)
NAPS will manage RVI fluence projections consistent with GALL-SLR AMP X.M2, Neutron Fluence Monitoring Program NAPS will manage RVI examinations consistent with GALL-SLR AMP XI.M16A, PWR Vessel Internals including recent NRC guidance changes noted in SLR-ISG-2021-01, Updated Aging Management Criteria for Reactor Vessel Internals Components for PWRs.
23
Plant Specific TLAAs SLRA Sections Addressing GALL-SLR Recommendations Plant Specific Time A3.7.2 Reactor Coolant Pump Flywheel Fatigue Crack Growth Analysis A3.7.6 Reactor Coolant Pump Code Case N-481 Limited Aging A3.7.7 Cracking Associated With Weld Deposited Cracking Analysis The following TLAA topical reports updated for 80 years were recently approved by NRC SE Reactor coolant pump (RCP) fatigue crack growth analysis (PWROG-17011-NP-A, Rev 2)
- PWROG-17011-NP-A, Rev 2 confirms the previous analysis remains appropriate for 80 years
- The fatigue crack growth calculations assumed 6000 cycles of RCP start/stop for 80 years of plant life that bounds the projected NAPS cycle count.
Fracture mechanics integrity assessment for RCP Code Case N-481 (PWROG-17033-P-A, Rev 1)
- NAPS RCP model 93A casings are bounded by the evaluations and conclusions in PWROG-17033-P-A, Rev 1 for the crack stability analysis and the fatigue crack growth analysis; therefore, ASME Code Case N-481 is allowed.
Reactor vessel underclad cracking associated weld deposited cracking (PWROG-17031-NP-A, Rev 1)
- PWROG-17031-NP-A, Rev 1 projected the reactor vessel underclad fatigue crack growth analysis associated with weld deposited cladding to 80 years.
- The following TLAA Action Items in the NRC Safety Evaluation were confirmed:
- NAPS transient types and projected number of transient cycles are bounded by the analysis
- Limiting RPV beltline forgings meet the 10 CFR 50.61 PTS screening criterion of 270°F
- NAPS has implemented Leak-Before Break (LBB) analyses for primary loop piping 24
Reactor Vessel Embrittlement SLRA Sections Addressing GALL-SLR Recommendations Reactor Pressure 3.1.2.2.3 Loss of Fracture Toughness Due to Neutron Irradiation Embrittlement Vessel Neutron 4.2 Reactor Vessel Neutron Embrittlement Analysist Embrittlement at A1.19 Reactor Vessel Material Surveillance High Fluence A2.2 Neutron Fluence Monitoring Fluence projections through SPEO (72 EFPY) were performed for neutron embrittlement analyses Analyses for USE, ART, and P-T Limits for beltline materials have been satisfactorily evaluated using the 72 EFPY fluence projections USE analysis with less than 50 ft-lb Charpy USE was projected to the end of the SPEO with Equivalent Margin Analysis The applicability of the existing P-T limit curves has been extended to 72 EFPY with the use of updated initial material properties used to calculate ART values and KIC methodology NAPS will manage fluence projections consistent with GALL-SLR AMP X.M2, Neutron Fluence Monitoring Program NAPS will manage embrittlement consistent with GALL-SLR AMP XI.M31, Reactor Vessel Material Surveillance Program
- One capsule will be withdrawn from each unit prior to the SPEO during 2025 and 2026 RFOs
- Four untested capsules remain in each unit and are available for SPEO fluence monitoring 25
Reactor Vessel (RV) Support Steel Configuration 26
Irradiation of RV Support Steel SLRA Sections Addressing GALL-SLR Recommendations Irradiation of RV 3.5.2.2.2.6 Reduction of Strength and Mechanical Properties of Concrete Due To Irradiation Support Steel A1.12 Closed Treated Water Systems A1.24 External Surface Monitoring of Mechanical Components A1.31 ASME Section XI, subsection IWF A1.34 Structures Monitoring Originally assessed in preparation of future license renewal activities by Stone & Webster under contract from DOE, WOG, EPRI, and Virginia Power Westinghouse DORT fluence model through 100 years (76.8 EFPY)
New analysis was performed by Dominion for North Anna SLR
- Loads for dead weight, LOCA, and seismic
- Based on use of lower bound KIc value of 33.2 ksi in to represent infinite amount of fluence
- Critical stress (based on the KIc curve) using the lower bound toughness of 33.2 ksi in is greater than the stress on NST
- Therefore, brittle fracture will not occur NAPS will manage aging consistent with:
- B2.1.12 Closed Treated Water Systems
- B2.1.24 External Surface Monitoring of Mechanical Components
- B2.1.31 ASME Section XI, subsection IWF
- B2.1.34 Structures Monitoring 27
Dominion Energy SLR Summary North Anna SLR met the expected norms established with the most recent industry LR/SLR applications North Anna SLRA was developed using the same highly experienced team used for Surry SLR North Anna had a high degree of consistency with GALL-SLR, which resulted in a high quality SLR Application that included lessons learned from Surrys SLRA Dominion Energy has committed future investments in people, program enhancements and equipment modifications for the SPEO 28
Advisory Committee on Reactor Safeguards Plant License Renewal Subcommittee North Anna Power Station, Units 1 and 2 Subsequent License Renewal Application (SLRA)
Safety Evaluation Report (SER)
December 15, 2021 Hector Rodriquez-Luccioni, Project Manager Office of Nuclear Reactor Regulation
Presentation Outline
- Overview of Safety Review of North Anna SLRA
- SER:
- Section 2: Scoping and Screening Review
- Section 3: Aging Management Review
- Section 4: Time-Limited Aging Analyses
- Specific Areas of Review
- Inspections and Plant Material Conditions
- Conclusion on North Anna SLRA Review 2
North Anna, Units 1 & 2:
License Renewal Initial License Renewal Initial Initial License Renewed Expiration Unit License Renewal Application License Date 1 4/1/1978 5/29/2001 3/20/2003 4/1/2038 2 8/21/1980 5/29/2001 3/20/2003 8/21/2040 Subsequent License Renewal Application Submitted 8/24/2020 Acceptance Determination 10/15/2020 Draft Safety Evaluation Report with 10/18/2021 No Open or Confirmatory Items 3
Audits
- Aging Management Audit
- October 13, 2020 - January 8, 2021
- Three Parts
- In-Office Technical Review Audit
- In-Office Breakout Sessions
- On-Site Audit 4
SER Overview
- Draft SER with No Open or Confirmatory Items:
October 18, 2021
- Requests for Information (total - 47):
- Request for Additional Information (RAIs)- 38
- Request for Confirmation of Information (RCIs) - 9 5
SER Section 2 Structures and Components Subject to Aging Management Review (AMR)
- Section 2.1 - Scoping and Screening Methodology
- Section 2.2 - Plant Level Scoping Results
- Sections 2.3, 2.4, 2.5 - Scoping and Screening Results 6
SER Section 3 Aging Management Review (AMR)
- 3.0 - Use of the Generic Aging Lessons Learned Report
- 3.1 - Reactor Vessel, Internals, and Reactor Coolant System
- 3.2 - Engineered Safety Features
- 3.3 - Auxiliary Systems
- 3.4 - Steam and Power Conversion Systems
- 3.5 - Containment, Structures and Component Supports
- 3.6 - Electrical and Instrumentation and Control Commodities 7
SER Section 3 3.0.3 - Aging Management Programs (AMPs)
SLRA - Original Disposition of AMPs SER - Final Disposition of AMPs o 7 new programs o 7 new programs
- 7 consistent
- 7 consistent o 41 existing programs o 41 existing programs
- 17 consistent
- 16 consistent
- 24 consistent with
- 25 consistent with enhancements and/or enhancements and/or exceptions exceptions 8
SER Section 4 Time-Limited Aging Analyses (TLAAs)
- 4.1 - Identification of TLAAs
- 4.2 - Reactor Vessel and Internals Neutron Embrittlement Analyses
- 4.3 - Metal Fatigue Analyses
- 4.4 - Environmental Qualification of Electric Equipment
- 4.5 - Concrete Containment Tendon Prestress Analysis
- 4.6 - Primary Containment Fatigue Analysis
- 4.7 - Other Plant-Specific TLAAs 9
Specific Areas of Review
- Buried Gray Cast Iron Piping
- Reactor Pressure Vessel Neutron Fluence
- Irradiation Effects on Reactor Internals
- Reduction of Strength and Mechanical Properties of Concrete Due to Irradiation
- Electrical Cable Qualification 10
Buried Gray Cast Iron Piping in Fire Protection System
- 6 ruptures prior to 2003
- Identified as cracking due to cyclic loading -
during pump start testing
- Changed test procedure in 2003 to limit pressure in downstream piping - no ruptures since then
- Multiple inadvertent pump starts have occurred without failures
- Material is also subject to selective leaching
- Material is brittle 11
Buried Gray Cast Iron Piping in Fire Protection System
- Enhancements 5 (for selective leaching) and 6 (for cracking) to the Buried and Underground Piping and Tanks Program
- 6 gray cast iron locations to be excavated each 10 years
- 5 piping 10-foot lengths and 1 piping or component for Selective Leaching program
- Visual and magnetic particle to inspect for cracking
- Radiography on a 1-ft section if cracking is identified, to determine cause
- If defect is from manufacturing and not aging: document
- Cracking due to aging will result in crack growth and flaw stability evaluations to end of subsequent PEO
- Projected loss of function will enter the Corrective Action Program for extent of condition, extent of cause and further follow-on actions 12
Reactor Pressure Vessel Neutron Embrittlement
- Unit 1 year projected peak neutron fluence of 7.20 x 1019 n/cm2 (E>1.0 MeV)
- Capsule X achieves 80-year projected peak neutron fluence at approximately 39.1 EFPY (~2025)
- Unit 2 year projected peak neutron fluence of 7.34 x 1019 n/cm2 (E>1.0 MeV)
- Capsule X achieves 80-year projected peak neutron fluence at approximately 39.3 EFPY (~2026) 13
Reactor Pressure Vessel Neutron Embrittlement
- Upper Shelf Energy (USE)
- Limiting USE value at 72 EFPY
- 50.0 ft-lbs for the Unit 1 Inlet Nozzle Forging 11
- 48.2 ft-lbs for the Unit 2 Intermediate Shell Forging 04
- Applicant conservatively performed equivalent margin analysis (EMA) for:
- Upper and Intermediate Shell Forgings
- Inlet and Outlet Nozzle Forgings and Welds
- Analyses have been projected to be no less than 50 ft-lbs or EMA demonstrated lower values of Charpy USE will provide margins of safety against fracture to the end of the SPEO
- Pressurized Thermal Shock (PTS)
- Limiting RTPTS value for base metal or longitudinal weld materials at 72 EFPY
- 212.2°F - Unit 2 Lower Shell Forging 03
- Limiting RTPTS value for circumferentially oriented welds at 72 EFPY
- 136.3°F - Unit 1 Intermediate to Lower Shell Circumferential Weld Heat # 25531
- PTS analyses have been projected to be below screening criteria in 10 CFR 50.61 at the end of the SPEO 14
Reactor Vessel Internals Neutron Fluence
- Review Basis: The staff reviewed the 80-year neutron fluence values for the reactor vessel internals (RVI) components as part of the staff review of the RVI gap analysis that was included as part of SLRA AMP B2.1.7, PWR Vessel Internals.
- Staff Verification: The staff verified that the 80-year neutron fluence values for the RVI components were within the MRP-2018-022 neutron fluence ranges for the components at 72 EPFY.
- Reasonable Assurance: The staff determined that the 80-year neutron fluence values for the RVI components are appropriately accounted for in the applicants gap analysis-adjusted PWR Vessel Internals Program.
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Reduction of Strength and Mechanical Properties of Concrete Due to Irradiation
- Review Basis: The staff reviewed Dominions further evaluation of Reduction of Strength and Mechanical Properties of Concrete Due to Irradiation of the concrete biological shield (CBS) wall and the reactor vessel (RV) steel support assemblies (SSAs).
- Staff Verification: Through review of documentation, audit activities, and requests for additional information, the staff reviewed and evaluated the aging management reviews (AMRs) of CBS wall and RV SSAs.
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Reduction of Strength and Mechanical Properties of Concrete Due to Irradiation (cont.)
- Reasonable Assurance:
For the CBS wall, the staff concludes that:
- A plant-specific AMP is not required to manage aging effects due to irradiation.
- Dominion Energy has demonstrated that the effects of aging due to radiation for Units 1 and 2 CBS walls will be adequately managed so that their intended function(s) will be maintained consistent with the CLB during the subsequent period of extended operation, as required by 10 CFR 54.21(a)(3).
- For the RV SSAs (including Neutron Shield Tanks -NSTs), the staff concludes that:
- Dominion Energy adequately assessed through fracture mechanics evaluations that a plant specific program is not needed to manage the effects of aging due to radiation (loss of fracture toughness, loss of function due to irradiation embrittlement) for Units 1 and 2 RV SSAs.
- Dominion Energy has demonstrated that the effects of aging for the RV SSAs will be adequately managed so that their intended function(s) will be maintained consistent with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).
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Electrical Cable Qualification and Condition Assessment
- Review Basis:
- Cable qualification is required per 10 CFR 50.49.
- For license renewal, cable qualification is a TLAA.
- The applicant dispositioned the TLAA in accordance with 10 CFR 54.21c(1)(iii).
- Environmental qualification (EQ) of electric component aging management program (AMP) consistent with GALL-SLR AMP X.E1.
- For cable condition assessment, the applicant proposed aging management consistent with:
- XI.E3A, Electrical Insulation for Inaccessible Medium Voltage Power Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements
- XI.E3B, Electrical Insulation for Inaccessible Instrument and Control Cables Not Subject to 10 CFR 50.49 Environmental Qualification
- XI.E3C, Electrical Insulation for Inaccessible Low Voltage Power Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements
- Staff Verification: Through review of documentation, audit activities, and requests for additional information, the staff verified that the electrical cables will be age managed by AMPs that address the 10 program elements described in the GALL-SLR report.
- Reasonable Assurance: The staff determined that Dominion Energy has demonstrated that the effects of aging will be adequately managed, so that the intended function(s) will be maintained consistent with the CLB for the subsequent period of extended operation, as required by 10 CFR 54.21(a)(3).
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Region II AMP Inspections License Renewal Inspection Program for Initial Period of Extended Operations Inspection Dates Results U1 & U2 IP 71003 September 19-22, 2016 No Findings Phase 1 ML16306A189 U1 & U2 IP 71003 Nov 27-Dec 15, 2017 No Findings Phase 2 ML18029A029 U1 & U2 IP 71003 March 11-15, 2019 No Findings Phase 3 ML19134A146 U1 & U2 IP71003 TBD Phase 4 19
Region II: AMP Inspections ROP Baseline Inspections Inspection Date Aging Management Program IP71111.08 ISI Annually Augmented Inspection Activities alternate units Boric Acid Corrosion Surveillance ISI Program - Component and Component Support Inspections ISI Program - Containment Inspections ISI Program - Reactor Vessel Reactor Vessel Internals Inspection Steam Generator Inspections IP71111.07T Heat Sink 2006, 2008, Service Water System Inspections 2011, 2014, 2017, 2020 IP71111.21M DBAI 4Q 2018 Ensure the selected SSCs that are subject (operating 4Q 2021 in the post-40-year licensing period) to aging management review pursuant to 10 CFR Part 54 are being managed for aging in accordance with appropriate aging management programs.
IP71152 PI&R Sample 2Q 2018 Preventive Maintenance Program Age-related capacitor degradation resulted in a reactor trip 20
Region II AMP Inspections Resident Inspector Insight and Inspection Results
- No findings from License Renewal Program inspections
- 2013: Green finding for the failure to failure to establish and implement appropriate periodic preventive maintenance for replacement frequency of the C4 capacitor on the Speed Error Amplifier card B (1A08D). The C4 capacitor failed due to age related degradation. (FIN 05000339/2013007-01)
- 2021: Green NCV for an inadequate procedure for handling age degraded safety related cable. (NCV 05000338,05000339/2021010-03) 21
Region II: Plant Material Condition + Conclusion
- Plant material condition is generally acceptable and meets regulatory requirements for systems, structures, and components.
- The inspectors found that the AMPs were being implemented in accordance with the license condition.
- The NRC will continue to monitor AMPs using the baseline Reactor Oversight Process.
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SLRA Review Conclusion Two differing professional views were provided during the review and concurrence process regarding the buried gray cast iron piping in fire protection system:
- Management has been working to address the issues identified.
- On December 6, 2021, Dominion provided a response to the staffs request for additional information (RAI) to ensure that the Final Safety Analysis Report (FSAR) supplement submitted on the docket matches the program as described in the supplements and RAI responses. The final safety evaluation will address the RAI and response.
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SLRA Review Conclusion -
cont.
On the basis of its review of the SLRA, the staff determined that the requirements of 10 CFR 54.29(a) have been met for the subsequent license renewal of North Anna Power Station, Units 1 and 2.
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Backup Slides 25
Irradiation Effects on Concrete Biological Shield Wall SRP-SLR 3.5.2.2.2.6 criteria for concrete is met and Dominions determination that a plant-specific AMP is not required is acceptable:
- Calculated neutron fluence (3.15 x 1018 n/cm2) and gamma dose (2.93 x 108 rad) at limiting locations for 72 Effective Full Power Years
[EFPY] are below respective SRP-SLR thresholds (1 x 1019 n/cm2 and 1 x 1010 rad) for potential degradation
- No plant-specific operating experience of irradiation degradation NST Support Skirt noted to date
[Extends below to containment floor]
- Accessible portions of wall will Containment Floor continue to be visually inspected by Reactor Vessel Support Configuration the Structures Monitoring Program NST = Neutron Shield Tank 26
Irradiation Effects on Reactor Vessel (RV) Steel Supports The loss of fracture toughness due to irradiation embrittlement is an aging effect that does not require management:
- NST fluence and fracture mechanics evaluation demonstrated the aging effect will not occur and structural integrity will be maintained during subsequent period of extended operation
- No plant-specific operating experience of the aging effect identified to date
- Susceptible aging effects (loss of material /
mechanical function) of RV Support Sliding Feet Assemblies (above NST) managed by ASME Section XI, Subsection IWF AMP NST Support Skirt
[Extends below to containment floor]
- Susceptible aging effects (loss of material /
Containment Floor support function) of NST managed by Reactor Vessel Structures Monitoring, and Closed Treated Support Configuration Water Systems AMPs NST = Neutron Shield Tank 27