ML20056D677
| ML20056D677 | |
| Person / Time | |
|---|---|
| Issue date: | 02/05/2020 |
| From: | Kent Howard Advisory Committee on Reactor Safeguards |
| To: | |
| Howard, K, ACRS | |
| References | |
| NRC-0787 | |
| Download: ML20056D677 (249) | |
Text
Official Transcript of Proceedings NUCLEAR REGULATORY COMMISSION
Title:
Advisory Committee on Reactor Safeguards Plant License Renewal Subcommittee Docket Number: (n/a)
Location: Rockville, Maryland Date: Wednesday, February 5, 2020 Work Order No.: NRC-0787 Pages 1-182 NEAL R. GROSS AND CO., INC.
Court Reporters and Transcribers 1323 Rhode Island Avenue, N.W.
Washington, D.C. 20005 (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.
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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 FEBRUARY 5, 2020 11 + + + + +
12 ROCKVILLE, MARYLAND 13 + + + + +
14 The Subcommittee met at the Nuclear 15 Regulatory Commission, Two White Flint North, Room 16 T2B10, 11545 Rockville Pike, at 8:30 a.m., Matthew W.
17 Sunseri, Chair, presiding.
18 19 COMMITTEE MEMBERS:
20 MATTHEW W. SUNSERI, Chair 21 RONALD G. BALLINGER, Member 22 CHARLES H. BROWN, JR., Member 23 WALTER L. KIRCHNER, Member 24 PETER RICCARDELLA, Member 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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2 1 ACRS CONSULTANT:
2 STEPHEN SCHULTZ 3
4 DESIGNATED FEDERAL OFFICIAL:
5 KENT HOWARD 6
7 ALSO PRESENT:
8 PAUL AITKEN, Dominion 9 BRIAN ALLIK, NRR 10 ERIC BLOCHER, Dominion 11 LAWRENCE BURKHART, ACRS TSB 12 BOB CALDWELL, NRR 13 JOSEPH COLACCINO, NRR 14 DAVID DIJAMCO, NRR 15 JOHN DISOSWAY, Dominion 16 STEVEN DOWNEY, NRR 17 JAMES GAVULA, NRR 18 LAUREN GIBSON, NRR 19 DARRYL GODWIN, Dominion 20 ALLEN HARROW, Dominion 21 CRAIG HEAH, Dominion 22 ALLEN HISER, NRR*
23 GREG IMBROGNO, Dominion 24 JAMES JOHNSON, Dominion 25 JUAN LOPEZ, NRR NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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3 1 TANIA MARTINEZ NAVEDO, NRR 2 LOUIS McKOWN, NRR 3 KEITH MILLER, Dominion 4 FRED MLADEN, Dominion 5 SCOTT MOORE, Executive Director, ACRS 6 ERIC OESTERLE, NRR 7 SHIE-JENG X. PENG, NRR 8 PAUL PHELPS, Dominion 9 RICH PHILPOT, Dominion 10 BRET RICKERT, Dominion 11 TROY SCARBOROUGH, Dominion 12 CHUCK TOMES, Dominion 13 DAVID WILSON, Dominion 14 ANGELA WU, NRR 15 16 *Present via telephone 17 18 19 20 21 22 23 24 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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4 1 C-O-N-T-E-N-T-S 2 Welcome and Opening Remarks 3 by Chair Sunseri . . . . . . . . . . . . . 5 4 Introductory Remarks 5 by Mr. Caldwell . . . . . . . . . . . . . . 8 6 Dominion Engineering Presentation 7 by Mr. Phelps . . . . . . . . . . . . . . . 11 8 Dominion Overview 9 by Mr. Aitken . . . . . . . . . . . . . . . 23 10 Aging Management Programs 11 by Mr. Blocher . . . . . . . . . . . . . . 33 12 NRC Staff Presentation 13 Angela Wu, NRR . . . . . . . . . . . . . . . . . 86 14 Steven Downey, NRR . . . . . . . . . . . . . . 105 15 Committee Discussion . . . . . . . . . . . . . 107 16 Adjourn . . . . . . . . . . . . . . . . . . . . 182 17 18 19 20 21 22 23 24 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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5 1 P R O C E E D I N G S 2 8:28 a.m.
3 CHAIR SUNSERI: Good morning. The meeting 4 will now come to order. This is a meeting of the 5 Plant License Renewal Subcommittee. I am Matthew 6 Sunseri, Chairman of the Subcommittee.
7 ACRS members in attendance are Ron 8 Ballinger, Walt Kirchner, Pete Riccardella. Charles 9 Brown will be joining us in about an hour. And Steven 10 Schultz, our consultant, is here for this meeting. I 11 note that we have a quorum. Kent Howard of the ACRS 12 staff is the designated federal official for this 13 meeting.
14 The purpose of this Subcommittee meeting 15 is for Virginia Electric Power Company, we will refer 16 to them as either Dominion or the applicant, and the 17 NRC staff to brief the Subcommittee on the subsequent 18 license renewal application for the Surry Power 19 Station's Units 1 and 2.
20 This is the third subsequent license 21 renewal application to be reviewed by the 22 Subcommittee. The Subcommittee will gather 23 information, analyze relevant issues and facts, and 24 formulate a proposed position and actions as 25 appropriate for deliberation by the full Committee.
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6 1 The ACRS was established by statute, and 2 is governed by the Federal Advisory Committee Act.
3 That means that the Committee can only speak through 4 its published letter reports. We hold meetings to 5 gather information to support our deliberations.
6 The ACRS reviews and advises the 7 Commission with regard to the licensing, operation of 8 production and utilization facilities, and related 9 safety issues, the adequacy of proposed safety 10 standards, technical and policy issues related to the 11 licensing of evolutionary and passive plant designs, 12 and other matters referred to it by the Commission.
13 The ACRS section of the USNRC public 14 website provides out charter, by-laws, letter reports, 15 and full. transcripts of all full and Subcommittee 16 meetings, including the slides presented at the 17 meetings.
18 The rules for participation in today's 19 meeting were announced in the Federal Register. We 20 have not received any written comments, or a request 21 for time to make oral statements from members of the 22 public regarding today's meeting.
23 A transcript of the meeting is being kept, 24 and will be made available as stated in the Federal 25 Register notice. Therefore, we request that NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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7 1 participants in the meeting use the microphones 2 located throughout the meeting room when addressing 3 the Subcommittee.
4 Participants should first identify 5 themselves, and speak with sufficient clarity and 6 volume so they may be readily heard. A telephone 7 bridge line has been opened for members of the public 8 to listen in on the presentations and deliberations by 9 the Subcommittee.
10 We have set aside time at the end of the 11 meeting for the agenda to offer members of the public 12 the opportunity to provide comments. We also have a 13 separate bridge line for NRC staff that will not be 14 muted, and allow them to participate in the meeting.
15 To preclude interruptions of the meeting 16 please mute your individual lines during the 17 presentations and Committee discussions. At this time 18 I request everyone silence their cell phones.
19 We will now proceed with the meeting. And 20 I call upon Bob Caldwell to make introductory remarks.
21 But before I do that, is it Bob? Bob's going to do 22 that? Okay.
23 I just want to note here that a little 24 before 11 o'clock today I may have to step out. I 25 will likely have to step out. And at that time I'll NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 1 turn over the Chairmanship to Walt Kirchner. I mean 2 no disrespect to the group presenting. It's just a 3 unavoidable conflict. Okay, Bob.
4 MR. CALDWELL: Thank you, Chairman and 5 Members of the ACRS Subcommittee on Plant License 6 Renewal. I am Bob Caldwell. I am the Deputy Director 7 of the Division of New and Renewed Licenses in NRR.
8 We sincerely appreciate the opportunity 9 today to present to the ACRS Subcommittee on License 10 Renewal the results of the staff's review on the third 11 application for subsequent license renewal.
12 This application was submitted by Virginia 13 Power and Electric, or Dominion, for the Surry Power 14 Station Units 1 and 2, located in Surry County, 15 Virginia.
16 By way of background, Surry Units 1 and 2 17 received approval for their initial renewal license 18 from the NRC in March 20, 2003. The NRC review at 19 that time was performed using guidance developed prior 20 to the issuance of the generic aging license lessons 21 learned report, or the GALL report.
22 The NRC guidance for license renewal over 23 the years has evolved through enhancements and 24 improvements based on the lessons learned from NRC 25 reviews from both domestic and international industry NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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9 1 operating experience.
2 The GALL report went through two 3 revisions, and additional interim staff guidance was 4 issued following Revision 2. The guidance for 5 subsequent license renewal contains in the GALL-SLR 6 built upon previous guidance, and included additional 7 focus and enhancements where necessary on aging 8 management and time limiting analysis for the 9 operation in the 60 to 80 year period.
10 The staff's presentation today, in the 11 staff's presentation today you will hear about some of 12 the specific SLR issues as applied to the Surry 13 Review.
14 The NRC project managers for the Surry 15 subsequent license renewal application review are Ms.
16 Angela Wu, and Ms. Lauren Gibson. Angela will 17 introduce the staff seated at the table who will be 18 presenting or addressing the questions regarding the 19 staff's review of the Surry subsequent license 20 renewal.
21 Part of the management team here with me 22 today are Eric Oesterle, the Chief of the License 23 Renewal Project Branch. And in the audience we have 24 other members of the NRR technical review, branch 25 chiefs. And Joe Colaccino is here. And Tania NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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10 1 Martinez Navedo is here.
2 We have with us representatives from 3 Region II, Mr. Louis McKown, Acting Chief of the 4 Engineering Branch 4 in the Division of Reactor 5 Projects, Region II, and Dr. Steve Downey, Senior 6 Reactor Inspector from the Division of Reactor Safety 7 Engineering Branch 3.l Joining us by phone I believe 8 is Mack Reed, Resident Inspector at Surry.
9 I'd like to note that the staff completed 10 its review with no confirmatory or open items in the 11 safety evaluation report. The staff will provide an 12 overview of its safety plans, and highlight a few 13 technical areas that may be of interest to the 14 Subcommittee Members.
15 In addition, following the staff's 16 presentation Mr. Brian Allik and Mr. James Gavula of 17 the staff will share their technical positions on the 18 SLR, followed by Eric Oesterle, who will present NRR's 19 preliminary perspectives on the technical positions.
20 Finally, we will address any questions you 21 may have on the staff's presentations. We look 22 forward to a productive discussion today with the ACRS 23 Subcommittee. And at this time I'd like to turn the 24 presentation over to Mr. Paul Phelps, Dominion 25 Engineering Director, SLR, to introduce his team and NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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11 1 commence the presentation.
2 MR. PHELPS: Thank you, Bob. Good 3 morning. My name is Paul Phelps, and I'm the 4 Director, Nuclear Projects Responsible for Surry Power 5 Station Subsequent License Renewal, or SLR project.
6 We appreciate the opportunity to speak 7 with the Advisory Committee on Reactor Safeguards, 8 ACRS Subcommittee today on Dominion Energy's 9 application for subsequent license renewal.
10 This is a very important day. And we 11 appreciate the support, and look forward to presenting 12 the SLR application highlights to the Subcommittee.
13 By the way of my background, I have been 14 in the nuclear industry for nearly 30 years. I am 15 responsible for various SLR related projects that are 16 currently under development in Virginia.
17 We have stood up an organization not only 18 to perform the requisite work for the re-licensing of 19 the station. But we also have a larger organization 20 that is currently working on projects to improve the 21 safety, reliability, and aging management for Surry 22 Power Station through various modifications.
23 I will provide some of those insights in 24 a couple of slides. First, my personal history is 25 extensive at Surry. I have worked at Surry for 13 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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12 1 years of my career with Dominion Energy.
2 As part of my tenure at Surry I received 3 my Senior Reactor Operator Certification, and worked 4 in many engineering leadership roles. My last 5 assignment on site was the Design Engineering Manager, 6 which I held for six years before I moved to our 7 corporate office and became the Manager of Fleet 8 Projects. Next slide, please.
9 I want to take the time to introduce the 10 team assembled with me here today. To my right is 11 Paul Aitken, Engineering Manager responsible for the 12 development of the Surry SLR application.
13 Paul was also involved in a leadership 14 role in all of Dominion Energy's first license renewal 15 projects dating back to 1999. Over the last few years 16 he has been engaged with various organizations such as 17 Electrical Power Research Institute, EPRI, Department 18 of Energy, DOE, Pressurized Water Reactor Owners 19 Group, PWROG, Nuclear Energy Institute, NEI, and 20 various vendors to ensure alignment on various 21 technical topics in the support of subsequent license 22 renewal.
23 Next to Paul is Eric Blocher. Eric has 24 been involved in various first renewal license 25 applications in the industry. He brings his extensive NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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13 1 knowledge to the team, and has been deeply involved in 2 the development of the generic aging lessons learned, 3 GALL, SLR, not only on behalf of Dominion Energy, but 4 for the nuclear industry.
5 To the right of Eric is Chuck Tomes.
6 Chuck is a principle engineer with Dominion Energy, 7 with nearly 40 years of nuclear experience in various 8 technical capacities.
9 Chuck has been working with various 10 industry groups and vendors on establishing priorities 11 on a needed basis, that would be benefit not only 12 Dominion Energy, but our industry partners.
13 He is responsible for the time limited 14 aging analysis portion, and will provide his insights 15 later in the presentation.
16 On my far right is Allen Harrow. Allen is 17 the site engineering manager at Surry Power Station, 18 with nearly 30 years of commercial nuclear experience 19 with Dominion Energy.
20 Allen started in the operations 21 department, receiving a shift technical advisor and 22 senior reactor operator certifications before serving 23 in various supervisory and management roles at the 24 station in engineering and organizational 25 effectiveness, including --
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14 1 (Technical difficulties) 2 CHAIR SUNSERI: Okay. Please continue, 3 Paul. Sorry for the interruption. I apologize.
4 MR. PHELPS: Can you hear me? In 5 conclusion, to my left is Craig Heah, who is the 6 technical lead in the civil mechanical area, 7 responsible for scoping and screening activities.
8 Craig has 12 years of nuclear experience.
9 He was the last chairman of the NEI Mechanical License 10 Renewal Working Group during the transition to GALL-11 SLR.
12 Craig will be assisting the team with the 13 slide show, and will be available to answer any 14 scoping and screening questions that you may have 15 during the presentation.
16 Along with the team at the table we have 17 several technical staff available in the audience, 18 should we need some assistance on any questions you 19 may have during our portion of the presentation. If 20 needed they will identify themselves and address your 21 questions.
22 (Technical difficulties) 23 MR. PHELPS: Lastly I would like to 24 recognize Fred Mladen, in the front row. Fred is the 25 site VP at Surry Power Station. Next slide, please.
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15 1 I want to cover the agenda for today's 2 meeting. We will discuss the station overview 3 performance, SLR application development, GALL-SLR 4 consistency, SLR aging management programs, technical 5 topics, and closing remarks. Next slide, please.
6 Here's an overview of the station and the 7 50 mile radius, Surry Power Station. Surry Power 8 Station is located in Surry County, Virginia, and is 9 located on the south side of the James River, 10 approximately 25 miles upstream of the point where the 11 river enters the Chesapeake Bay.
12 The area includes both populated and 13 industrialized areas, as well as expansive rural 14 areas. And spans from the northern neck area of 15 Virginia into North Carolina, and from the eastern 16 shore over to our state capital, Richmond, in central 17 Virginia.
18 Included in this area are many military 19 installations, and airports providing international 20 travel. Next slide, please.
21 Surry is a Westinghouse three loop 22 pressurized water reactor, with an output net capacity 23 of nearly 1,700 megawatts. Together these two units 24 produce approximately 15 percent of Virginia's 25 electricity needs. Unit 1 started commercial NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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16 1 operation in 1972, and Unit 2 started commercial 2 operation in 1973.
3 The independent Smithfield Storage 4 Installation facility was one of the first in the 5 country, and will have the capacity to store the fuel 6 required for 60 years of operation.
7 A 4.3 power upgrade was implemented in 8 1995, prior to the initial license renewal. The 9 renewed licenses were --
10 (Technical difficulties) 11 MR. PHELPS: -- power stations were issued 12 in March of 2003. Lastly, Surry entered the period of 13 extended operation in 2012 and 2013 for Units 1 and 2 14 respectively. Next slide, please.
15 Here's an aerial view of the station. I 16 will highlight some of the more significant features, 17 and I will ask Craig to superimpose a red laser marker 18 to help the Committee get oriented.
19 Again, the orientation of the site and 20 riverflow are from west to east, or upstream the James 21 River, around Hogg Island, a state designated wildlife 22 management area, to downstream James River towards the 23 Chesapeake Bay.
24 Features from the plant I'd like to point 25 out include the intake canal that provides the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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17 1 ultimate heat sink from the James River, the discharge 2 canal, back into the James, about six miles upstream 3 of the intake.
4 A unique feature of Surry is that the 5 water from the James River is pumped into an intake 6 canal, and the water flows over a mile, and is gravity 7 fed through the plant without any pumps.
8 Also depicted are the Unit 1 and Unit 2 9 reinforced concrete containment structures, and the 10 turbine building in the light blue. The switch yard 11 is across the property on the other side of the intake 12 canal. The administrative building, located on the 13 bottom of this picture, is where many of the plant 14 staff work. Next slide, please.
15 Here's some of the high level information 16 on the performance of Surry. To note, Surry operates 17 on an 18 month refueling frequency. The plant 18 capacity factor has been very good, as reflected in 19 the bullets.
20 As far as the regulatory oversight 21 process, Surry is in Column 1, and has been there 22 since 2007. Next slide, please.
23 MR. SCHULTZ: Excuse me, Paul. Staying at 24 the high level. You've got some good information 25 about what's happened recently with the, for the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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18 1 station.
2 What's the estimated average capacity 3 factor since the facility entered the period of 4 extended operation, or the decade in, that we've just 5 passed? Just to get an appreciation for how the 6 station has operated over a longer period of time than 7 the three years you've posted here.
8 MR. TOMES: Good morning. My name's Chuck 9 Tomes. Our refueling philosophy is that we typically 10 operate a short refueling outage of about 20 days, a 11 medium refueling outage of about 25 days, and then a 12 longer refueling outage, maybe 30 days.
13 And we've had our capacity factors being 14 able to support our objectives over the last three 15 years.
16 MR. SCHULTZ: Okay. So, you haven't had 17 any outage during this, outages during this period, 18 forced outages that have been significant for the 19 station?
20 MR. PHELPS: We've had no significant 21 outages since our period of extended operation.
22 MR. SCHULTZ: Right. Thank you.
23 MR. PHELPS: Next slide, please.
24 CHAIR SUNSERI: So, just as a update, the 25 entire phone system at the NRC is having trouble.
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19 1 That's why we're being so disruptive. So, I'm not 2 certain how long we're going to have to deal with 3 that. But just please be patient, and proceed on with 4 your, we'll work through it the best we can. Thank 5 you.
6 MEMBER RICCARDELLA: Could I just ask for 7 my education how you can have a capacity factor 8 greater than 100 percent?
9 MR. PHELPS: The capacity factor is 10 calculated all from, you know, we use the NERC 11 requirements. And the NERC requirements are for 12 periods of operation.
13 So, they don't take into effect if we have 14 a fall outage or a spring outage. So, if you have no 15 forced outages, and you operate breaker to breaker for 16 one full year, you're going to be over 100 percent 17 capacity.
18 MEMBER RICCARDELLA: Okay. Thank you.
19 MR. PHELPS: There has been nearly $1 20 billion in capital investments made to Surry since the 21 first renewed license was issued in 2003.
22 As I mentioned in my opening remarks 23 Dominion Energy will continue to invest in Surry to 24 maintain safety and plant reliability for the current 25 and subsequent period of operation.
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20 1 I would like to highlight a few. Dominion 2 Energy was very proactive to replace the reactor 3 vessel heads at both North Anna and Surry Power 4 Stations. In addition, Surry has replaced, or is 5 scheduled to replace all of the high voltage 6 transformers.
7 I will note the carbon fiber reinforced 8 polymer installation is one of the first projects the 9 SLR team implemented at Surry, to address longstanding 10 aging management of large bore circulating water in 11 service water piping.
12 Let me provide some additional details for 13 the benefit of the Committee on this innovative, first 14 of a kind carbon fiber reinforced polymer project.
15 Next slide, please.
16 The carbon fiber patented technology is a 17 multi-layered system that is applied to the internal 18 surfaces of the carbon steel pipe that becomes the new 19 pressure boundary.
20 This has been previously employed in the 21 industry in non-safety related applications. But 22 Dominion Energy was the first to receive NRC approval 23 for the use in safety related applications.
24 In the picture this is a 96 inch 25 circulating water discharge pipe that had the carbon NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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21 1 fiber reinforced polymer installed for five years.
2 Look at the condition of the surface, and how much of 3 a change this means towards aging management.
4 This technology improves safety by 5 reducing the amount of repairs that have been a 6 chronic problem due to the brackish internal 7 environment. But it also reflects Dominion Energy's 8 commitment to address aging management.
9 I would also like to point out the carbon 10 fiber reinforced polymer project was recognized as the 11 best of the best of all top innovative practice awards 12 last year at the NEI awards ceremony. Dominion Energy 13 is extremely proud of this recognition and award.
14 In addition, we have plans to continue to 15 invest in the station over the areas, to ensure 16 continued safe and reliable operations for 80 years.
17 Some of the projects include main electrical generator 18 replacement, feedwater heater replacements, residual 19 heat removal heat exchanger replacements, and the 20 replacement of the in core instrumentation system.
21 I'm sure that you can appreciate that 22 these are significant capital investments for the 23 future operation of Surry Power Station. Let me 24 pause, and ask if there are any questions, before I 25 turn the presentation over to Paul Aitken.
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22 1 CHAIR SUNSERI: Well, how much, so how 2 much of an issue was the condition of the pipe for the 3 aging, the degradation of the pipe before you 4 initiated the carbon fiber?
5 MR. PHELPS: Well, our strategy to 6 maintain the carbon, that pipe is, we go in and we 7 blast it. And we do weld and coat it. It was in, you 8 know, as pipe degrades it was in pretty poor 9 condition. So, this fix, carbon fiber is good for 50 10 years.
11 CHAIR SUNSERI: And it was internal 12 degradation?
13 MR. PHELPS: it was internal degradation.
14 That's right.
15 CHAIR SUNSERI: Does this pipe have like 16 a cathodic protection for the external protection?
17 MR. PHELPS: This pipe does not have 18 cathodic protection installed on it.
19 CHAIR SUNSERI: Thank you.
20 MR. SCHULTZ: Okay. Paul, a question.
21 The projects that you mentioned, how near term are 22 they? The ones that are upcoming? You mentioned four 23 of them.
24 MR. PHELPS: We have been working on these 25 projects for two years. The carbon fiber is active NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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23 1 right now.
2 MR. SCHULTZ: Right.
3 MR. PHELPS: We have one more line to 4 install this year, and it will be done at the station.
5 The other projects are five to seven years out. But 6 we're actively working on them. We've cut contracts 7 with them. So, they're in the plan to work in five to 8 seven years.
9 MR. SCHULTZ: So, they're relatively firm 10 commitments, given that you're working forward with 11 them already?
12 MR. PHELPS: That is correct.
13 MR. SCHULTZ: Thank you.
14 MR. AITKEN: Okay? Thanks, Paul, and good 15 morning. Again, my name is Paul Aitken, and I'm the 16 engineering manager responsible for the development of 17 the Surry License Renewal Application.
18 By way of background I've been in the 19 nuclear industry for 35 years. And as Paul mentioned, 20 was previously involved in the first renewals for the 21 Dominion Energy fleet.
22 I'll be providing an overview of the 23 application development process, and other 24 considerations for the Subcommittee today. Next 25 slide, please.
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24 1 Dominion Energy team has worked closely 2 with various research organization and utility 3 sponsored groups to collectively represent the 4 industry when working with the NRC staff during the 5 development of the GALL-SLR and SRP.
6 We supported several public meetings over 7 the last few years to finalize the GALL-SLR, as well 8 as the industry guidance for SLR as reflected in NEI 9 Document 17, excuse me, 17-01.
10 This integral involvement allowed Dominion 11 Energy to benefit from the industry engagement, and 12 use those insights during the development of the SLR 13 application. We also reviewed previously issued REIs 14 to incorporate additional lessons learned from the 15 first license renewal applicants.
16 Dominion Energy participated in the peer 17 reviews at Turkey Point and Peach Bottom. We were 18 able to provide feedback on their respective 19 applications, while also incorporating insights that 20 we learned during those interactions.
21 We also conducted an industry peer review 22 using the expertise in the NEI licensure civil, 23 mechanical, and electrical working groups, and other 24 SLR applicants. I personally found these peer reviews 25 to be extremely helpful in our pursuit of a high NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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25 1 quality application.
2 Dominion Energy had a pre-submittal 3 meeting with the NRC on the safety portion of the 4 application. The meeting provided a public forum that 5 allowed additional clarifications and questions to be 6 asked between Dominion Energy and the NRC staff.
7 These insights were extremely beneficial during the 8 development of the application.
9 Based on these collective interaction 10 Dominion Energy submitted a high quality application, 11 as reflected by fewer REIs, as compared to our first 12 license renewal applications, and a safety evaluation 13 report with no open items, and no confirmatory items.
14 MR. SCHULTZ: Paul, in a few sentences can 15 you describe what entails industry peer review?
16 MR. AITKEN: Sure, yes. We --
17 MR. SCHULTZ: Very important, as you 18 mentioned. But how is it conducted? And how are your 19 results obtained?
20 MR. AITKEN: Yes. So, what we do is, we 21 pull the application together internally. We review 22 it as a project team. And then we send it out to the 23 industry, to the working groups.
24 And the working groups meet a couple of 25 times a year. And what we do is, we spend time, a NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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26 1 day, a day and a half, on each portion of the 2 application, have the interaction, and allow, you 3 know, take the comments.
4 And then, we'll take the comments back to 5 the office and go through and do a prioritization on 6 what we're going to incorporate, and what we're not 7 going to incorporate, and fold that in. And then, 8 that's all done before we go up through the management 9 review process.
10 MR. SCHULTZ: Do you report back to the 11 peer review team?
12 MR. AITKEN: Yes. We, yes, we develop a 13 spreadsheet, and we send that comment disposition back 14 to the various organizations.
15 MR. SCHULTZ: Thank you.
16 MR. AITKEN: We have a lot of 17 participation from a lot of utilities, which is very 18 beneficial. And it's not just the SLR applicants.
19 It's still first, you know, first licensure applicants 20 that are still involved in the working groups.
21 CHAIR SUNSERI: Does that interaction 22 result in lessons learned being re-factored into the 23 program? I mean, the generic industry program?
24 MR. AITKEN: Yes. So, that process 25 continues. And we've been working with Eric and the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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27 1 staff on areas for continued improvement. So yes, 2 there's still lessons to be learned.
3 MEMBER KIRCHNER: Paul, on your last 4 bullet you, I think you said that this provided a 5 public forum?
6 MR. AITKEN: Yes, sir.
7 MEMBER KIRCHNER: Did you have much 8 participation from the public in that meeting?
9 MR. AITKEN: We had some public 10 participation. We had people calling on the phone 11 lines. We had a lot of utility representation. We 12 had vendor participation.
13 MEMBER KIRCHNER: Okay.
14 MR. AITKEN: So, we had over ten public 15 meetings, I think that, even for the GALL-SLR 16 development. So --
17 MR. AITKEN: Okay. Next slide. I want to 18 provide a brief summary on the differences between the 19 first license renewal and subsequent license renewal, 20 with respect to the integrated plan assessment.
21 For scoping and screening there were 22 minimal changes in the overall process approach. This 23 is primarily because the established industry guidance 24 hasn't changed very much since the first license 25 renewal.
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28 1 Having said that, one area that we 2 expected to have adjustments was related to scoping 3 and screening for Alpha 2. That's non safety related 4 equipment which can affect safety related equipment.
5 This change was due to the guidance evolving since the 6 first license renewals.
7 As above noted Surry is a pre GALL plant, 8 like the previous two SLR applicants. So, we were in 9 the same situation of updating the methodology in 10 scoping and in additional systems.
11 In the area of aging management reviews 12 the expansion and number of aging effects we had to 13 address significantly increased, due to the vintage of 14 the previous application, and the overall evolution of 15 the GALL over the years.
16 The biggest difference was in aging 17 management programs. Currently, for first license 18 renewal we have 25 aging management programs. Moving 19 into subsequent license renewal there are going to be 20 47 aging management programs. And Eric will speak to 21 the aging management program details after me.
22 Lastly, the time limited aging analyses 23 were re-evaluated for 80 years. There was only one 24 new TLAA identified since first license renewal. The 25 new TLAA was related to high cycle fatigue concerns NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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29 1 related steam generator tubes made from Alloy 600 2 thermally treated material that are potentially 3 unsupported by an anti-vibration bar.
4 This concern was identified by 5 Westinghouse in a nuclear safety advisory letter NSAL 6 12-7. The potential for tube fatigue was evaluated by 7 Westinghouse, and concluded that none of the 8 potentially unsupported tubes identified in the Unit 9 1 and Unit 2 steam generators would be at risk of 10 fatigue related failure during the subsequent period 11 of operation.
12 The remaining time limited aging analyses 13 were disposition consistent with the GALL-SLR 14 guidance.
15 MEMBER RICCARDELLA: Excuse me. Are these 16 the original steam generators at the plant? Or were 17 they replaced?
18 MR. AITKEN: They were replaced.
19 MEMBER RICCARDELLA: Thermally treated.
20 MR. AITKEN: Yes. We were the first in 21 the industry to replace the tubes. And there was a 22 modified steam generator replacement.
23 MEMBER RICCARDELLA: Thank you.
24 MR. AITKEN: Next slide, please, Craig.
25 So, during the aging management review our alignment NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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30 1 with the GALL-SLR was over 99 percent for the industry 2 footnotes Alpha through Echo.
3 I believe that this high degree of 4 alignment to the GALL-SLR was a result of the efforts 5 by the NRC staff and the industry to broaden the GALL-6 SLR to capture the additional material, environment, 7 and aging effect combinations that were identified 8 during the first license renewal applications.
9 In terms of commitments, we have a total 10 of 47. And they're primarily on a AMP by AMP basis, 11 and are reflected in Appendix Alpha of the safety 12 evaluation report. These commitments will be tracked 13 in the Dominion Energy commitment tracking system.
14 I will leave you with a sense that these 15 commitments were discussed with the station team, and 16 agreed upon for implementation. Some commitment items 17 have already been addressed. And Dominion Energy will 18 ensure the proper time, talent, and resources are in 19 place to implement the commitments as required.
20 That's all I had for my portion of the 21 presentation. Are there any questions before I hand 22 it over to Eric?
23 MEMBER KIRCHNER: Paul, I'd like to ask, 24 of the AMPs that you have, now you're up to 47, how 25 many of them are unique to your particular plant? Or NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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31 1 are these pretty much following what the industry wide 2 is doing?
3 MR. AITKEN: I think they're pretty 4 consistent industry wide.
5 MEMBER KIRCHNER: So, there's nothing -
6 MR. AITKEN: Site specific.
7 MEMBER KIRCHNER: -- site specific or --
8 MR. AITKEN: No.
9 MEMBER KIRCHNER: Okay.
10 MR. AITKEN: And our -- Go ahead. I'm 11 sorry.
12 MEMBER BALLINGER: Did you folks do an 13 estimate of the probability of failure for steam 14 generator tubes out to 80 years, using thermally, with 15 the thermally treated tubing?
16 (Off microphone comment) 17 MEMBER BALLINGER: In other words, 18 thermally treated tubing is --
19 MR. AITKEN: I mean, we --
20 MR. TOMES: The, this is Chuck Tomes. So, 21 there's two aging management considerations related to 22 the tubes. They would be intergranular stress 23 corrosion cracking, and fatigue.
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32 1 of plant operation. And the intergranular stress 2 corrosion cracking is really managed through the ISI 3 program.
4 MEMBER BALLINGER: Okay. So, it's really, 5 you're not doing a projection? It's just an ISI?
6 MR. TOMES: For the stress corrosion 7 factor.
8 MEMBER RICCARDELLA: Have you had to plug 9 any tubes in the new generator?
10 MR. TOMES: Yes.
11 MEMBER BALLINGER: How much margin do you 12 have?
13 MR. BLOCHER: This is Eric Blocher. We 14 have not done a probabalistic assessment of the 15 thermally treated tubes. Generators, the lower half 16 was replaced in 1981.
17 And based on our trend to date in each of 18 the units, less than one percent of the tubes are 19 plugged. So, we've had excellent performance so far 20 with the thermally treated tubes.
21 MEMBER BALLINGER: And you have a lot of 22 margin?
23 MR. BLOCHER: Yes.
24 MEMBER BALLINGER: Thank you.
25 MR. AITKEN: So, at this time I'll --
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33 1 CHAIR SUNSERI: I'm told that the phone 2 lines are back in service.
3 MR. AITKEN: They're back in service?
4 CHAIR SUNSERI: Yes.
5 MR. AITKEN: Okay. So, at this time I'll 6 turn over the next portion of the presentation to Eric 7 Blocher to discuss aging management programs.
8 MR. BLOCHER: Thanks, Paul, and good 9 morning. My name is Eric Blocher, and I am the SLR 10 technical lead responsible for the technical content 11 and assembly of the Surry SLR application.
12 By way of background, I've been in the 13 nuclear industry for 43 years. And as Paul mentioned 14 I was previously involved in numerous industry license 15 renewal projects.
16 I will be providing an overview of the 17 significant considerations associated with the aging 18 management programs in the SLR application for the 19 Subcommittee today. Next slide on SLR and 20 considerations.
21 In addition to being responsive to GALL-22 SLR AMP program elements, effectiveness of the Surry 23 SLR AMPs was influenced by involvement of our project 24 team members, and industry activities, incorporation 25 of operating experience, and the performance of AMP NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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34 1 effectiveness reviews.
2 As part of our engagement with the 3 industry several Surry SLR project team members have 4 held leadership roles on the NEI task forces and 5 working groups.
6 Other members collaborated with EPRI on 7 activities such as guidance for aging management 8 alkali silicate reaction, concrete irradiation 9 evaluation, and reactor internals inspections. And 10 others have participated in the PWR owners' group 11 reactor vessel integrity and time limited aging 12 analysis report projects.
13 Project team participation not only 14 benefitted the Surry application, but provided 15 guidance and technical reports that include several 16 reports with NRC safety evaluations that are 17 generically applicable to other SLR applications.
18 Review and incorporation of operating 19 experience was performed for a ten year period, to 20 inform the aging management programs. In addition to 21 operating experience, recent license renewal REIs 22 associated with the Turkey Point and Peach Bottom SLR 23 projects, and recent first license renewal projects, 24 were reviewed for insights and lead plant alignment.
25 Our project team also participated in NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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35 1 Turkey Point and Peach Bottom industry peer reviews to 2 provide AMP insights, and share constructive comments.
3 Prior to submittal of the application the 4 effectiveness of aging management activities was 5 assessed using the evaluation elements identified in 6 NEI 1412, the guideline for aging management program 7 effectiveness. Next slide.
8 MEMBER BALLINGER: I'm sorry to go back 9 again.
10 MR. BLOCHER: No problem.
11 MEMBER BALLINGER: What's your TH? What's 12 your TH?
13 MR. BLOCHER: T Hot.
14 MEMBER BALLINGER: T Hot.
15 (Off microphone comments) 16 MR. HARROW: T Hot is 547.
17 MEMBER BALLINGER: 547?
18 (Simultaneous speaking.)
19 (Off microphone comments) 20 MR. WILSON: I believe the mic is on. So, 21 too short. So, T Hot. I'm sorry, my name is David 22 Wilson, Director of Safety and Licensing, Surry Power 23 Station, a member of the Dominion Energy team. T Hot 24 at Surry Power Station is 605 degrees.
25 MEMBER BALLINGER: Okay. There we go.
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36 1 MR. WILSON: T Cold is 537 degrees.
2 MEMBER BALLINGER: Now I'm calibrated.
3 PARTICIPANT: T Cold 547?
4 MR. WILSON: That's correct.
5 MEMBER KIRCHNER: Eric, before you go on, 6 just out of curiosity, when you participate in these 7 peer reviews, obviously you get a more inclusive view.
8 Did, as a result of these did, was something 9 identified that wasn't already on, in your plan, or on 10 your list, or so to speak?
11 Just curious to -- One could say, you 12 know, you all worked together on this. And you get 13 group think. So, did, as a result of the peer reviews 14 did you get new insights that changed any of your 15 planned AMPs or activities?
16 MR. BLOCHER: The peer reviews were quite 17 helpful in gaining insights. For example, in the AMPs 18 that we're talking about now, many of the insights 19 dealt with ways of presenting some of the 20 enhancements, innovative ways to get to an aging or 21 inspection process that would satisfy GALL 22 efficiently.
23 Some of the critiques relative to our 24 exceptions that we took not only benefitted us, but 25 the other team members. And that has helped when we NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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37 1 go to NRC meetings where we talk about these changes 2 with the staff, in terms of influencing of future ISG 3 or revision to the GALL-SLR.
4 So, it not only benefits us, it benefits 5 team members. And to the extent practical we usually 6 share that information as practical with the 7 regulator.
8 MEMBER KIRCHNER: Yes. I was actually 9 thinking a little beyond just process, and helping 10 expedite your way through the reviews and interactions 11 with the staff to any technical findings as a result 12 of your review group activities, peer group 13 activities.
14 (Off microphone comment) 15 MR. TOMES: Good morning. This is Chuck.
16 There were several helpful observations and input from 17 our peer review process. One of, in particular when 18 we worked on our environmental assisted fatigue.
19 We had experts from our vendors challenge 20 the selection of the materials and the locations that 21 we would use for fatigue monitoring. That's one area 22 where we actually made changes.
23 MEMBER KIRCHNER: Thank you.
24 MR. BLOCHER: Okay. First license renewal 25 AMPs. Twenty-five firs license renewal aging NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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38 1 management programs were the starting point for the 2 evolution and enhancement into subsequent license 3 renewal aging management programs.
4 All first license renewal aging management 5 activities were continued, and incorporated into SLR 6 AMPs. None were discontinued. Several first license 7 renewal AMPs were consistent with GALL, or required 8 enhancement to be consistent with GALL-SLR.
9 Several first license renewal aging 10 programs were subdivided into GALL AMPs. First 11 license renewal programs such as containment 12 inspection were subdivided into ASME Subsection IWE or 13 IWL inspections, or structures monitoring that was 14 subdivided into three GALL-SLR programs, or work 15 control that was subdivided into five GALL-SLR 16 programs. Next slide.
17 MEMBER KIRCHNER: Eric, pardon the 18 interruption again. As a result of that, so you went 19 from 25 to 47. And you just mentioned you subdivided 20 some of the previous AMPs to be more consistent with 21 GALL.
22 But going back to my prior question. Did 23 the GALL report force you to add AMPs that covered 24 activities of a technical nature that weren't 25 previously in the SL, the first license renewal?
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39 1 MR. BLOCHER: Yes. There were several new 2 AMPs that were added. I'm going to cover that on a 3 future --
4 MEMBER KIRCHNER: Okay.
5 MR. BLOCHER: -- slide.
6 MEMBER KIRCHNER: All right. Well 7 sometimes, my question is more technical. Because 8 sometimes new is just to be in conformance with 9 process.
10 And sometimes new is because you actually 11 discovered a technical issue, and then created 12 something to address that. So, that, it's the latter 13 I'm more interested in than the former.
14 MR. BLOCHER: I agree. I know where 15 you're coming from. And you'll see that when I get to 16 the new AMP slide. Okay. So, based on the slide that 17 you see, this combination and subdivision process of 18 first license renewal AMPs resulted in 47 GALL aging 19 management programs noted on this slide.
20 There are 28 mechanical programs that 21 evolved from 19 first license renewal programs. There 22 are eight structural programs that evolved from four 23 license renewal programs.
24 And there are eight electrical programs 25 that started with splitting one of the first license NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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40 1 renewal AMPs into two programs, then crediting two 2 existing electrical programs. And then doubling the 3 electrical programs with the addition of four new SLR 4 programs.
5 And, Walt, I think there's a slide after 6 this that will touch on this. I think the electrical 7 area is an example of what you were thinking about.
8 There are three time limited aging 9 analysis programs. And the subdivision process also 10 resulted in varying degrees of GALL-SLR consistency, 11 as noted on the next slide.
12 Looking at the left hand column, there are 13 40 existing AMPs that resulted from the combination 14 and subdivision process of the first license renewal 15 AMPs. The SLR existing AMPs were augmented by seven 16 new AMPs.
17 The remainder of the columns provide 18 perspectives on GALL-SLR AMP consistency.
19 Approximately one-quarter of the 47 AMPs are 20 consistent with GALL, without enhancement.
21 Approximately one-half of the 47 are 22 consistent with enhancement. And approximately one-23 quarter of the SLR AMPs are consistent with one or 24 more exceptions.
25 Now let me provide some context on the new NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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41 1 GALL-SLR AMPs, and the AMPs with exceptions on the 2 next slide.
3 MEMBER BALLINGER: I was looking ahead.
4 And the neutron fluence monitoring AMP, TLA, time 5 limited aging is not one of the new ones. It's one of 6 the existing ones I presume.
7 MR. BLOCHER: Correct. This is 8 Subdivision 1.
9 MEMBER BALLINGER: Yes. Now, are you guys 10 following the Reg Guide 1.99 review, or potential 11 review process? And does that have any, would that 12 have any effect on your fluence monitoring?
13 MR. BLOCHER: Chuck, would you like to 14 ask, answer that?
15 MR. TOMES: Sure. We do follow the Reg 16 Guide 1.190 process. And we have conducted 17 calculations on the neutron shield tank. And we use 18 the surveillance capsules that are in the reactor 19 vessel to project our fluence.
20 MEMBER BALLINGER: Yes.
21 MR. TOMES: And we are following the 22 changes that are being proposed by the staff --
23 MEMBER BALLINGER: Okay.
24 MR. TOMES: -- on the embrittlement curve, 25 and also for assessing areas above and below the belt NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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42 1 line region.
2 MEMBER BALLINGER: Thank you.
3 MR. BLOCHER: Okay. There are seven new 4 SLR aging management programs. The first three aging 5 management programs involve one time inspections. The 6 next four electrical AMP programs involve inspections 7 of inaccessible cables, cable connectors, and high 8 voltage insulators.
9 So, Walt, I think you can see from this, 10 in the electrical area there are new things that we 11 had not previously done. Some are new components, 12 like the high voltage insulators. Some involve 13 additional inspections of instrument and control, and 14 low voltage power cables.
15 CHAIR SUNSERI: But are any of those as a 16 result of operating experience at Surry? Or is it 17 just all industry generic?
18 MR. BLOCHER: None of those have 19 significant operating experience at Surry. These were 20 added by the GALL. We were a pre-GALL plant. So, 21 they were added in, during our first license renewal 22 interval.
23 CHAIR SUNSERI: And for the AMPs that were 24 with enhancement, is it the same kind of story on 25 that? They were enhanced because of the transition to NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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2 MR. BLOCHER: Correct.
3 CHAIR SUNSERI: -- some operating 4 experience?
5 MR. BLOCHER: Correct.
6 CHAIR SUNSERI: Thank you.
7 MR. BLOCHER: Okay. Okay. Next I'll 8 provide a listing of GALL AMPs with exceptions. So, 9 there are 12 SLR aging management programs with 10 exceptions that include 14 exceptions. This number of 11 exceptions is consistent with other SLR applicants.
12 For example, Peach Bottom had 11 AMPs with 14 13 exceptions.
14 We can discuss any one of these 15 enhancements noted on this slide. Or otherwise I can 16 provide a summary of the general types of exceptions 17 on the next slide. Next slide.
18 As noted previously, there are 12 aging 19 management programs that include 14 exceptions as 20 noted on this slide. There are six AMP exceptions 21 that involve exceptions to GALL-SLR test frequencies, 22 and are proposed inspection technique alternatives.
23 For example, the ASME Section 11, 24 Subsection IWE program requires containment 25 penetrations that are subject to cyclic loads that do NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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44 1 not have current licensing basis analysis to be 2 periodically inspected with a service and visual 3 examination for cracking.
4 Dominion Energy prepared a fatigue waiver 5 for containment penetrations with operating 6 temperatures less than 200 degrees, to demonstrate 7 that cracking due to cyclic loading is not an 8 applicable aging effect requiring management.
9 There are five AMP exceptions that involve 10 exception to GALL-SLR program elements due to plant 11 specific configurations.
12 For example, the metal enclosed bus 13 program requires a periodic ten year inspection of 100 14 percent of all metal enclosed busses. Inspection of 15 metal enclosed bus between Unit 1 Foxtrot bus, and 16 Unit 2 Foxtrot bus requires a dual unit outage.
17 Inspection of the other mechanical busses, 18 coupled with opportunistic inspection of transfer bus 19 Foxtrot are used to demonstrate that effective aging 20 management of all metal enclosed busses.
21 Other more common plant specific 22 configuration considerations not addressed by GALL-SLR 23 include metal tanks encased in concrete missile 24 shields, and double wall fuel oil storage tanks.
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45 1 required because the GALL-SLR references outdated EPRI 2 chemistry guidance for PWR secondary water chemistry, 3 and closed treated water systems.
4 We identified and evaluated each change in 5 the new EPRI chemistry guidance for aging management 6 effectiveness, and consistent with industry operating 7 experience. EPRI chemistry guidance changes were 8 found to be acceptable by the NRC staff.
9 The last exception was required to allow 10 Dominion Energy to conservatively apply the elements 11 of aging management activities associated with high 12 voltage insulators to the medium voltage insulators on 13 the Surry SBL recovery path. Next slide, please.
14 MR. SCHULTZ: Eric, before you leave that.
15 MR. BLOCHER: Yes.
16 MR. SCHULTZ: What is the, where does the 17 reactor head closure stud bolting fall? Which of 18 these categories does it fall into?
19 MR. BLOCHER: That's a configuration 20 issue, based on the tensile strengths that are 21 involved with our replacement studs.
22 MR. SCHULTZ: Okay. Thank you.
23 MR. BLOCHER: First license renewal AMPs 24 have been, and will continue to be assessed for AMP 25 effectiveness. Four AMP reviews, including NEI 1412 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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46 1 AMP effectiveness reviews confirm implementation of 2 first license renewal commitments, and performed 3 assessment of inspection schedules, inspection 4 results, and trending data.
5 In addition, these reviews also ensured 6 identified gaps were addressed or included in the 7 corrective action program.
8 Program owners receive periodic training, 9 and are required to complete AMP effectiveness reviews 10 every five years, as well as perform systematic 11 operating experience reviews on an ongoing basis, to 12 inform AMPs and augment AMP effectiveness.
13 As an indication of regulatory 14 acceptability of the Dominion Energy aging management 15 programs, the IP 71003 Phase 4 NRC inspection 16 identified no findings or concerns in the third 17 quarter 2019 inspection. The NRC staff will provide 18 details of the 71003 Phase 4 inspection during their 19 presentations.
20 This is all I had for the AMP portion of 21 the presentation. Are there any questions for me 22 before I start the next portion of the presentation on 23 --
24 MR. SCHULTZ: Eric, on this slide you talk 25 about the training conducted periodically for program NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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47 1 owners. What is that periodicity? Or is it on an as 2 needed basis?
3 MR. BLOCHER: There's an annual training 4 that's given by the license renewal coordinator on 5 significant operating experience and industry updates.
6 And then it's, after that it's as needed.
7 MR. SCHULTZ: So, it's really an 8 opportunity for the program owners to get together and 9 discuss where things stand, learn from what has been 10 gleaned from the industry activity --
11 MR. BLOCHER: Yes.
12 MR. SCHULTZ: -- type of training?
13 MR. BLOCHER: Yes.
14 MR. SCHULTZ: Long course? A day's 15 exercise, or --
16 MR. BLOCHER: It varies.
17 MR. AITKEN: I would say it's four to six 18 hours2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br />.
19 MR. SCHULTZ: And the program owners have 20 been in place generally for a real, a long period of 21 time? Is it a rotational position? How would you 22 characterize it?
23 MR. BLOCHER: Right. Each of the 25 first 24 license renewal AMPs identified in the UFSR supplement 25 has an assigned individual responsible for that. And NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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48 1 then, as we rotate to the 47 first, second license 2 renewal programs, those two will have program owners.
3 We work with individuals that were 4 assigned to work with us as we transition, either 5 subdivide or create the new ones. So, there are some 6 new individuals that are spinning up on the --
7 MR. SCHULTZ: These are individual program 8 owners?
9 MR. BLOCHER: Right.
10 MR. SCHULTZ: In other words, one person 11 isn't assigned four programs?
12 MR. BLOCHER: Well, as you can see, like 13 Section 11, there are, because GALL-SLR subdivided a 14 lot of the Section 11 topics, there will be one 15 program owner for that.
16 But usually when it comes to 17 implementation of the inspections that overarching 18 program owner might not be involved with the 19 inspections.
20 For example, nickel alloys are all Section 21 11 code cases. The ASME Section 11 program owner is 22 responsible for that. But another individual may be 23 involved with the outage inspections for --
24 MR. SCHULTZ: Right.
25 MR. BLOCHER: -- nickel alloys.
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49 1 MR. SCHULTZ: Okay. Thank you.
2 MR. BLOCHER: Next slide. In the next 3 portion of the presentation I will cover technical 4 topics dealing with concrete, reactor internals, and 5 other aging management enhancements.
6 Chuck Tomes will then cover the technical 7 topics of reactor vessel integrity and reactor vessel 8 support steel.
9 Allen Harrow will conclude with technical 10 topics, with a discussion of our recent operating 11 experience associated with the buried fire protection 12 yard loop piping. Next slide.
13 Concrete for Surry structures within the 14 scope of subsequent license renewal is in good 15 condition. There have been no loss of license renewal 16 intended function due to aging since entering the 17 period of extended operation.
18 Dominion Energy has recently implemented 19 the EPRI Alkali-Silicate Reaction Inspection Guidance 20 that was developed in part by members of the SLR team.
21 The guidance uses identification of leading indicator 22 structures, conduct of augmented examinations for 23 pattern cracking, detection of water ingress, and 24 identification of structural misalignment.
25 No effects of Alkali-Silicate reaction NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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50 1 have been identified. Aging management of the 2 structural concrete is accomplished by aging 3 management programs noted on the slide.
4 Surry reinforced concrete containments are 5 also in good condition. Recent examinations of the 6 concrete liner to concrete slab interface in October 7 of 2016 for Unit 1, and May 2017 for Unit 2, did not 8 identify any degradation.
9 Containment concrete biological shield 10 wall gamma and neutron dose radiation remains 11 conservatively below GALL-SLR radiation exposure 12 levels throughout the subsequent period of extended 13 operation.
14 Aging management of Surry reinforced 15 concrete containments is accomplished by the aging 16 management programs noted on the slide. Next slide.
17 MEMBER BALLINGER: I have questions on 18 this.
19 MR. BLOCHER: Yes.
20 MEMBER BALLINGER: Do you know what the 21 groundwater chloride concentration is at the site?
22 MR. BLOCHER: the GALL requires 23 groundwater chloride to be less than 500 ppm.
24 MEMBER BALLINGER: Right.
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51 1 provide some additional trend details?
2 MR. JOHNSON: Yes. I'm Jim Johnson, with 3 the SLR team at Dominion. The groundwater monitoring 4 that's been done at the plant, we're committed to do 5 it at a frequency no greater than five years. But 6 they've actually been doing it quarterly.
7 And there has been one well point that had 8 chlorides that exceeded 500 parts per million. This 9 was in the turbine building. And it's kind of an 10 anomaly, where they were pumping the water out, we 11 feel like they're concentrating that.
12 And then they're inspecting, and haven't 13 found any degradation due to the chlorides there. And 14 they're continuing to monitor that. But overall the 15 plant has had good quality water. And we haven't had 16 any issues with chlorides or PH, or sulfates.
17 MEMBER BALLINGER: Okay. And now, just, 18 this is, probably you don't know the answer to this.
19 But with respect to the containment, is the rebar 20 three or four inches deep? What's the cover amount?
21 MR. JOHNSON: There's five inches in most 22 places.
23 MEMBER BALLINGER: Five inches?
24 MR. JOHNSON: Yes.
25 MEMBER BALLINGER: Okay. All right.
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52 1 Thank you.
2 MR. BLOCHER: I am ready for the next 3 slide, Craig.
4 MEMBER KIRCHNER: Eric? Could you just --
5 for the record, just define good condition?
6 MR. BLOCHER: Well first, from a licensure 7 point of view, there's been no loss of intended 8 function.
9 MEMBER KIRCHNER: Right.
10 MR. BLOCHER: And there's been no 11 significant code degradation noted that would appear 12 in the operating activities report.
13 MEMBER KIRCHNER: Yes. I think good just 14 doesn't quite catch it. All right, thank you.
15 MR. BLOCHER: I understand your comment, 16 thank you. Surry will manage reactor vessel internals 17 at primary, expansion and existing examinations 18 consistent with MRP-227, Rev. 1-Alpha, inspection and 19 evaluation guidance that was issued in December of 20 2019 and includes NRC safety evaluation dated April 21 25th, 2019 -- for the first period of extended 22 operation. In addition, the examinations for the 10 23 SLR reactor vessel internals compound as noted on the 24 slide are also incorporated into PWR vessel internals 25 program.
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53 1 With exception to the control rod guide 2 tubes sheathes and seed tubes, the additional 3 examinations are identified in MRP 2018-022, interim 4 SLR guidance, and are required in part due to where an 5 irradiation related degradation that is very 6 conservatively projected for the subsequent period of 7 extended operation. In addition to the PWR vessel 8 internals program, the neutron fluence monitoring 9 program defines and monitors the projected fluence 10 associated with the reactor vessel internals during 11 the subsequent period of extended operation, and will 12 supplement the MRP-227, rev. 1-Alpha, inspection and 13 evaluation guidance. Next slide.
14 MEMBER RICCARDELLA: Excuse me, I don't 15 see anything on baffle bolts. Have you had an issue 16 with that? Had there been an inspection?
17 MR. BLOCHER: Chuck, would you like to 18 answer that?
19 MR. TOMES: Yes. Our baffle bolts have 20 been inspected at the Surry Nuclear Plant and we have 21 one defect in one of the units.
22 MEMBER RICCARDELLA: Is it an up-flow or 23 a down-flow configuration?
24 MR. TOMES: It's been converted.
25 MEMBER RICCARDELLA: It's been converted?
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54 1 MR. TOMES: Let me re-speak -- let me re-2 speak -- let me clarify. We're in the process of 3 working to convert. We will convert in a couple 4 refueling outages. Thank you.
5 MR. BLOCHER: Next slide, please. Other 6 aging management enhancements identified on this slide 7 demonstrate the value of Dominion Energy industry 8 leadership, EPRI collaboration and PWR owners-group 9 participation. Dominion Energy's SLR team members 10 contributed to the development of the draft ASME code 11 case, and 871 examinations that will manage the aging 12 and the pressure boundary for the newly installed 13 carbon fiber reinforced polymer pipe lining consistent 14 with the open cycle cooling water system program.
15 Surry program owners have implemented 16 erosion monitoring that manages wall thinning due to 17 cavitation, liquid drop impingement, flashing and 18 solid particle erosion. The program is consistent 19 with the EPRI erosion guideline and it includes 20 erosion susceptibility evaluation, engineering 21 evaluations to determine inspection locations, and the 22 use of CHECWORKS erosion module to predict erosion 23 inspection locations on susceptible lines.
24 MR. SCHULTZ: Eric, how long has that 25 program been in place? You're using it, but how long NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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55 1 has it been used? Is this recent? Or has it been 2 longer-term?
3 MR. BLOCHER: This is a recent program 4 change that we added due to requirements of the GALL-5 SLR. And we are in the process of getting that 6 implemented for inspections coming up in this year and 7 the following year.
8 MR SCHULTZ: Okay, thank you.
9 MR. BLOCHER: Soil surveys and analysis 10 consistent with recent EPRI guidance that confirms 11 soil environment corrosivity now supplements the 12 varied and underground piping and tanks program aging 13 management inspection criteria. Dominion SLR team 14 members have participated in PWR owners group 15 activities for development of time-limited aging 16 analysis topical reports such as the report associated 17 with the reactor coolant pump fatigue crack growth 18 analysis, and reactor cooling pump code case N481.
19 These were recently also approved by the 20 NRC safety evaluations. An NRC safety evaluation for 21 the topical report of reactor vessel under-clad 22 cracking associated with well deposit cracking, is in 23 progress with an estimated March 2020 completion date.
24 That is all I had for my portion of the presentation.
25 Are there any questions for me before I hand over to NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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56 1 Chuck Tomes?
2 MR. SCHULTZ: Yes, one question on this 3 slide, Eric. The soil surveys and analysis that 4 you've incorporated from the EPRI program, can -- can 5 you expand on -- on what is being done there? What 6 I've seen in the -- what I've seen in the updates to 7 the program is that you're -- you're incorporating 8 soil sampling and testing in a couple of different 9 ways. That is, you've got -- you've got a site-wide 10 approach and a -- a specific approach, depending on 11 what is happening on the site. Can you describe that?
12 Or is that something that we ought to wait for the 13 next section to discuss?
14 MR. BLOCHER: Now is an appropriate time 15 to discuss that. So the initial soil surveys were 16 done in 2012 on the station for the buried pipe 17 program. And in 2018 they were revisited. The 18 initial soil surveys were 44 points. The recent ones 19 in 2018 were 11 points. The recent ones fully employ 20 the EPRI guidance, which looks for soil 21 characteristics, resistivity, pH, redox potential, 22 sulfides, chlorides and soil consortium -- which is a 23 check of the bacteria in the soil. Those parameters 24 are all taken. They're scored on an index that awards 25 up to 15 points. Anything under 10 points is not NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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57 1 considered very corrosive. In fact, there's two grade 2 categories under 10 points. Ten to 15 is considered 3 moderately corrosive. Anything greater than 15 -- no, 4 excuse me -- 10 to 15 is appreciably corrosive. And 5 anything greater than 15 points is severely corrosive.
6 Those would tend to focus our action on anything that 7 scores 10 or greater.
8 MR. SCHULTZ: So with -- with that scoring 9 system, are there areas of the site that are of 10 concern? Or -- what -- what has been found? And --
11 (Pause.)
12 MR. BLOCHER: Yes --
13 MR. SCHULTZ: Are there programs moving 14 forward as a result of that work?
15 MR. BLOCHER: Right, so you have to 16 remember that the License Renewal Buried Pipe Program 17 augments the industry NEI-09-14 program. So the 09-14 18 looks at other piping systems that are not within the 19 scope of license renewal. So for some of those the 20 corrosive areas fall under an 0914 concern. The 21 license renewal piping is all either mildly corrosive 22 or moderately corrosive areas.
23 MR. SCHULTZ: Okay. Well we'll -- we'll 24 take a look at some pictures.
25 MR. BLOCHER: Thank you.
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58 1 MR. TOMES: Before I cover the technical 2 comp issues, I want to just finish clarifying the 3 question that Pete Riccardella had on the baffle 4 bolts. And we have one bolt that's non-functional for 5 Unit 1 and two bolts that are non-functional for Unit 6 2. So I didn't get a chance to squeeze that in.
7 Okay.
8 Good morning, my name is Chuck Tomes from 9 Dominion Energy. And thank you for taking the time to 10 review the Safety Evaluation Report issued by the 11 Nuclear Regulatory Commission for the Surry subsequent 12 license renewal application. During my career, 13 reaching back to the early 1980s, I've had the 14 privilege of working with NSSS vendors, owners groups, 15 the Electrical Power Research Institute, ASTM 16 committees and ASME committees on projects from 17 managing reactor vessel integrity and reactor cooler 18 pump issues. And these industry groups are the one 19 that allowed us to move forward to where we're at 20 today. And we're quite thankful for their help over 21 the years.
22 My role on the Surry SLR project has been 23 to work with these groups to ensure that the time 24 limiting aging analyses are technically correct. At 25 this time I'll discuss the two topics that Eric NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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59 1 Blocher mentioned -- dealing with reactor vessel 2 integrity and reactor vessel support steel.
3 So the first thing that we did to assess 4 reactor vessel embrittlement was to project the 5 fluence values on the reactor vessel for 80 years of 6 plant operation, using 68 effective full-power years 7 as our target. This is conservative because the 8 current fluence projection for 60 years of plant 9 operation is 48 effective full-power years. Then we 10 contracted the PWR owners group to assist Dominion in 11 reviewing the reactor vessel certificate of material 12 test reports for re-baselining the initial fracture 13 toughness values in the accordance with the ASME code 14 and branch technical position 5-3. The various 15 reactor vessel time-limiting aging analyses for 16 pressurizer thermal shock, upper-shelf energy, low-17 temperature over pressure protection, and the heat-up 18 and cool-down curves were then revised through 80 19 years of plant operation using updated fluence and 20 material property information.
21 MEMBER RICCARDELLA: Excuse me, Chuck.
22 What is the end of life fluence? Peak end of life --
23 what is the peak end of life fluence?
24 MR. TOMES: The peak end of the license 25 fluence for Unit 1 is on the -- is 6.35 E to the 19 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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60 1 and 7.22 -- for Unit 2.
2 MEMBER RICCARDELLA: Got it.
3 (Simultaneous speaking.)
4 MR. TOMES: E to the 19.
5 MEMBER RICCARDELLA: So would you -- would 6 you be affected if the -- if the trend curve is 7 revised to the ASTM trend curve?
8 MR. TOMES: We have margin on the PTS 9 evaluation, the upper-shelf energy evaluation, the 10 LTOP system. And so impact from the -- if we were to 11 drive -- draw a new best-fit line through the data, so 12 that some plants were above and some plants were below 13 -- it would not impact us in these areas. But it 14 would impact the heat-up and cool-down curves more 15 than likely because we would end up with a new 16 criteria on how to adjust margin and -- and shift.
17 MEMBER BALLINGER: Yes, I think 6 times 10 18 of the 19th is the -- where it starts to -- right 19 where it starts to go off. So.
20 MR. TOMES: Okay, so we're going to talk 21 about this a little bit more. But it would have a --
22 it would have a dramatic impact on our plant 23 procedures. And what -- yes -- on the heat-up and 24 cool-down curves. Yes.
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61 1 values that have less than 50 foot pounds of Charpy 2 energy have been assessed using the equivalent margins 3 method outlined in the ASME code. So the 4 applicability of the existing heat-up and cool-down 5 curves can be extended to 68 effective full-power 6 years based upon using the updated material 7 properties, the revised fluence values and application 8 of the K1c methodology currently included in the ASME 9 code.
10 Surry will use two aging management 11 programs, which are consistent with GALL-SLR -- to 12 manage fluence and embrittlement during the subsequent 13 period of extended operation. And Dominion plans to 14 remove and test one surveillance capsule from each of 15 the reactor vessels during the period of extended 16 plant operation. Next -- okay, next slide.
17 This next technical topic that I will 18 discuss deals with reactor vessel steel. Dominion 19 Energy created this sketch to provide an overview of 20 the reactor vessel support configuration at Surry.
21 The reactor vessel supports at Surry are different 22 from the reactor vessel supports used at many of the 23 other nuclear plants. At Surry, the reactor vessel 24 support is provided by the neutron shield tank. At 25 some other plants, reactor vessel support is provided NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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62 1 by columns and cantilever beams.
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 wall. The reactor vessels located 6 in the center of the sketch. The position of the core 7 where the neutrons are generated within the reactor is 8 shown by the blue and grey stripes. The neutron 9 shield tank and the concrete biological shield wall 10 surround the reactor vessel. The neutron shield tank 11 is shown in blue. The tank is about 23 feet high, is 12 filled with water -- with chromated water, which 13 provides 34-inches of shielding. The inner and outer 14 plates are 1.5 inches thick.
15 Next to the neutron shield tank is the 16 concrete biological shield wall. The concrete 17 biological shield wall was 4.5 feet thick. One of the 18 purposes of the neutron shield tank is to provide 19 shielding to protect the concrete, biological shield 20 wall. The other purpose of then neutron shield tank 21 is to transmit the loads from the reactor vessel, 22 through the supports located under the nozzles of the 23 reactor vessel, to the top of the neutron shield, and 24 then to the lower elevation of containment. Okay, 25 next slide.
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63 1 Now that we've reviewed the general 2 configuration of the neutron shield tank, I will 3 discuss irradiation of reactor vessel support steel 4 for Surry. At Surry the support steel of interest is 5 the region of the neutron shield tank adjacent to the 6 reactor core, where the neutrons are generated. The 7 issue of irradiation of a reactor vessel support steel 8 was originally assessed in 1986 using fracture 9 mechanics in preparation of future license renewal 10 considerations by Stone and Webster, under contract 11 from the Department of Energy, Westinghouse Owners 12 Group, EPRI and Virginia Power.
13 This original assessment used a 14 Westinghouse discreet ordinance radiation transport 15 fluence model for projecting fluence on the neutron 16 shield tank through 100 years of plant operation. To 17 address the irradiation of the neutron shield tank for 18 subsequent license renewal, a new fracture mechanics 19 evaluation was performed by Dominion Energy. The new 20 fracture mechanics evaluation uses loads from dead 21 weight, LOCA and seismic, press intensity formulas 22 from the ASME code that are normally used for 23 developing heat-up and cool-down limit curves for 24 operation reactor vessel, and an infinite amount of 25 fluence based upon the use of the lower-bound K1r NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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64 1 curve, which is 26.7 KSI square root inches.
2 The analysis shows that the allowable 3 stress is greater than the stress on the neutron 4 shield tank, therefore brittle fracture will not 5 occur. The fracture mechanics evaluation is bounding 6 through the use of the lower-bound K1r value of 26.78 7 KSI square-root inches were not required because the 8 fracture mechanics evaluation is bounding. It 9 includes a margin of square-root of two consistent 10 with the ASME code for pressure vessels, even though 11 the neutron shield tank is not a class one vessel.
12 Thus the Surry fracture mechanics 13 evaluation of the neutron shield tank is both bounding 14 and conservative. And we have three programs for 15 managing aging during SLR that are shown on the slide.
16 Before we move on to the next part of the 17 presentation, I want to provide an opportunity to 18 answer questions.
19 MEMBER RICCARDELLA: The -- the 26.7 KSI 20 root inches, that's the lower shelf of the KIR curve?
21 MR. TOMES: Yes, that's right. That's 22 where it -- that's where it intersects, at the lowest 23 toughness level.
24 MEMBER RICCARDELLA: And the -- the square 25 root of two safety factor is --
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65 1 (Simultaneous speaking.)
2 MR. TOMES: For fault --
3 MEMBER RICCARDELLA: -- for seismic --
4 MR. TOMES: For fault -- it's actually for 5 LOCA. The seismic is insignificant in terms of the 6 loads.
7 MEMBER RICCARDELLA: Oh, okay. Thank you.
8 (Pause.)
9 MR. TOMES: If there are no other 10 additional questions, Mr. Allen Harrow will now 11 provide a summary of the recent operating experience 12 that occurred at Surry.
13 MR. HARROW: Good morning. My name is 14 Allen Harrow and I am the site engineering manager at 15 Surry Power Station. I have worked for Dominion 16 Energy for nearly 29 years. In my current role, I 17 provide management oversight of the various plant 18 systems and engineering programs. I will be providing 19 an overview of the recent fire protection yard loop 20 pipe break, including failure analysis, current 21 status, the highlights of the ongoing fire protection 22 yard loop repair project.
23 The Surry Power Station fire protection 24 yard loop completely circles the plant and consists of 25 a 12-inches looped fire main, supplying fire hydrants, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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66 1 phone stations and deluge systems on the outside. And 2 sprinklers, deluge systems and hose racks inside plant 3 structures.
4 The fire main piping is cast iron with 5 mechanical joints, and is cement mortar lined with a 6 bituminous external coating. The loop is 7 sectionalized to permit repairs without affecting any 8 other portion of the loop. Next slide?
9 CHAIR SUNSERI: Allen, could you pull the 10 microphone a little closer to you and just -- thank 11 you.
12 MR. HARROW: A fire protection loop piping 13 break occurred in July 2019, following the start of 14 the motor-driven fire pump. Following the failure of 15 the fire protection loop piping, the affected sections 16 of piping were isolated to stop the leak. Upon 17 excavation, it was identified that there were two 18 sections of 12-inch fire protection loop piping that 19 were degraded and leaking. The degraded sections of 20 pipe and dislocation were replaced, but remain 21 isolated and available if needed. Next slide.
22 MR. SCHULTZ: Allen, you mentioned that --
23 it occurred just after the fire pump start up. Was 24 that a normal operation? The fire pump start-up? Was 25 that a normal operation?
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67 1 MR. HARROW: Yes, since the fire pump was 2 started in collaboration with surveillance testing 3 that was being performed.
4 MR. SCHULTZ: But nothing was out of the 5 ordinary with regard to the operation of the pump? Or 6 the system?
7 MR. HARROW: There was nothing out of the 8 ordinary at that point in time.
9 MR. SCHULTZ: Thank you.
10 MR. HARROW: Uh --
11 MEMBER RICCARDELLA: I am sorry -- were 12 they breaks or leaks?
13 MR. HARROW: I would classify it as a 14 break because leakage -- you can classify it as a 15 rupture.
16 MEMBER RICCARDELLA: Rupture -- you know 17 --
18 MR. HARROW: The pipe -- the pipe was not 19 severed.
20 MEMBER RICCARDELLA: Okay.
21 MR. HARROW: Okay, next slide.
22 (Pause.)
23 MEMBER KIRCHNER: This -- was this a water 24 hammer effect? Or just it came up to normal operating 25 pressure and then you figured out that you had a large NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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68 1 leak?
2 MR. HARROW: There -- there was no water 3 hammer impact here. So the piping is normally 4 maintain solid. So when the motor-driven fire pump 5 started, no impact from water hammer.
6 MEMBER RICCARDELLA: How did you detect 7 the leak? Just from water?
8 MR. HARROW: So the leakage was detected 9 multiple ways. First of all, we had annunciators in 10 the Control Room that alerted the operating staff to 11 the leak. And the leak was also readily identifiable 12 in the field.
13 (Pause.)
14 MR. HARROW: All right. This fire 15 protection pipe failure was entered into the 16 Corrective Action Program, and an immediate review of 17 the cause and extended condition was ensued by the 18 station. Sections of the failed pipes were sent to 19 the -- to the Dominion Energy Materials Laboratory for 20 detailed analysis, in which the failure mechanism was 21 determined to be graphitic corrosion.
22 The failure analysis concluded that the 23 most notable corrosion was limited to the bottom 24 section of piping between roughly the 5:00 to 7:00 25 positions. It was determined through metallurgical NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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69 1 analysis that the identified material laws was a 2 result of the cast-iron fire protection piping 3 exposure to ground water over an extended period of 4 time. The bituminous coating in the area of rupture 5 locations on the bottom of pipe was noted to be 6 degraded, allowing the water to have direct contact 7 with the external surface of the pipe. The bituminous 8 coating around the pipe that was not exposed to the 9 ground water appeared to be in acceptable condition.
10 The scenario for the northern pipe 11 failure, based on the lab observations, is that long-12 term external corrosion ultimately resulted in a 13 reduction in wall thickness in the pipe. Once this 14 area reached its current size -- approximately 4-15 inches long -- the pipe suddenly ruptured from the 16 pressure surge associated with the starting of the 17 motor-driven fire pump.
18 The second failure location on the 19 southern section of fire protection loop pipe had a 20 circumferential flaw approximately eight feet south of 21 the northern fire protection loop pipe mechanical 22 connection. This type of flaw is typically associated 23 with bending stress and an overload condition. The 24 flaw propagated from a small pocket of external 25 graphitic corrosion located at the bottom of the fire NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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70 1 protection loop pipe. The cause evaluation concluded 2 that the circumferential flaw occurred as a result of 3 an initial longitudinal flaw, and rupture in the 4 northern piping.
5 The initial rupture created an uplifting 6 force and motion in the southern pipe, which caused 7 the circumferential flaw that was initiated at the 8 weakened area of graphitic corrosion. Next slide?
9 MR. SCHULTZ: Excuse me -- the coating, it 10 was hard to tell from the pictures what the condition 11 of the coating was. But as you've indicated here, in 12 -- on the one pipe with the longitudinal crack, that 13 -- that was in that region of 5 to 7 -- excuse me, 14 yes, 5:00 to 7:00, that coating was affected is what 15 you're saying in that -- the -- in other words, the 16 degradation of coating was regional.
17 MR. HARROW: Correct. The degradation of 18 coating was regional in the 5:00 to 7:00 position.
19 And we feel that that was a direct result of 20 groundwater that was in the vicinity of the 5:00 to 21 7:00 position. In other words, we do not feel the 22 groundwater completely encompassed the entire pipe.
23 MR. SCHULTZ: And as you looked at the 24 other -- other section of pipe that had failures, what 25 was the condition of the coating there? Or have you NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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71 1 -- have you noticed that there was a problem with 2 coating condition otherwise as you've continued your 3 corrective action program?
4 MR. HARROW: So -- so one thing that's 5 very difficult to identify is, when we initially 6 visually looked at the pipe, before you actually do 7 destructive testing, it is very difficult to identify 8 the acidic corrosion. It's a destructive testing 9 modality to actually identify the graphitic corrosion.
10 MR. SCHULTZ: Okay, that's -- that was the 11 problem I was having. Looking at it doesn't tell you.
12 MEMBER RICCARDELLA: In that photo, the 13 coating is removed.
14 MR. HARROW: That's correct.
15 MEMBER RICCARDELLA: And it's obviously 16 rotated.
17 MR. SCHULTZ: Right, right.
18 CHAIR SUNSERI: But for the -- for the 19 segment of pipe that had the circumferential break, 20 though, the galvanic corrosion initiating site was 21 also in the 5:00 to 7:00 range? Or was it in a 22 different place?
23 MR. HARROW: It was on the bottom of the 24 pipe. And it was -- it was basically a line or a stem 25 from the original graphitic corrosion that was NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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72 1 identified.
2 MEMBER RICCARDELLA: What's the operating 3 pressure when the system is operating?
4 MR. HARROW: The operating pressure of the 5 fire protection system is approximately 100 pounds.
6 (Pause.)
7 MR. HARROW: Previously performed visual 8 inspections and soil samples taken at various 9 locations around the protective area in conjunction 10 with additional excavations performed for this failure 11 support dry or acceptable conditions in all areas 12 where inspection and samples were performed. In order 13 to determine the extent of the fire protection main 14 loop that was exposed to ground water, exploratory 15 holes approximately 10-inches in diameter were 16 vacuumed at strategic locations around the fire water 17 header around the station.
18 To identify strategic locations for the 19 exploratory holes, a review of several previous buried 20 pipe inspection results was conducted to identify any 21 instances of ground water that were identified during 22 other excavations. This review provided insights as 23 to where ground water may be present and a methodology 24 to plot where exploratory holes should be dug to 25 determine if ground water was in contact with fire NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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73 1 main piping.
2 The holes were then evacuated to a depth 3 of 7 feet, or until water was located. Seven feet was 4 chosen because it is below the depth of the fire 5 protection piping, which is buried at 6 feet on center 6 line. The water found in the holes was sampled, but 7 was determined to not include chlorides, which 8 eliminated the possibility that the higher-than-9 expected groundwater level is leakage from the station 10 intake canal.
11 This information supports the conclusion 12 that potential corrosion concerns were confined to a 13 limited area near the recent failures. Soil analysis 14 were taken at the repair locations of the northern and 15 southern pipe sections that had failed. Analysis 16 results determined that one sample was in the lowest 17 level of corrosivity achievable based on EPRI's sole 18 corrosivity guidance. The other sample was in the 19 next-to-lowest classification. And this was as Eric 20 previously discussed. To address the current 21 condition of the fire protection yard loop piping, 22 compensatory measures have been put in place to 23 maintain fire suppression capabilities. Next slide?
24 MEMBER BALLINGER: I have another 25 question. So does what you have done so far give you NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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74 1 enough confidence that -- you know, this graphitic 2 corrosion, you can't really see it until you see it, 3 right? So do you have confidence that there are other 4 locations on that loop that hadn't, at some time in 5 their life, been -- had groundwater access? In other 6 words, you drilled your wells and you don't see any 7 water here and here and here. But does that mean that 8 you haven't seen water there? And there may not be 9 water at other places?
10 MR. HARROW: The -- to address -- I 11 believe that question is going to be addressed on the 12 next slide --
13 MEMBER BALLINGER: Okay.
14 MR. HARROW: If I can just hold off on 15 that.
16 MEMBER BALLINGER: Yes.
17 MR. HARROW: Okay. I want to provide some 18 context on the current actions that are underway in 19 response to this event. The station is taking 20 proactive action to replace the affected fire 21 protection yard loop piping, including associated fire 22 hydrants and isolation valves through the Corrective 23 Action Program. Funding has been approved for the 24 project.
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75 1 component replacement based on yard loop piping 2 susceptibility, as well as other key factors such as 3 piping location, with respect to the fire protection 4 pumps. Their primary focus, or phase one, is on the 5 area of the main fire protection loop piping nearest 6 to the fire protection pumps where groundwater has 7 been identified and is in contact with the pipe. As 8 piping is excavated and replaced, samples of pipe will 9 be analyzed to validate the extended condition of the 10 graphitic corrosion is bounded.
11 The Corrective Action Program will be 12 utilized if graphitic corrosion is identified in 13 additional sections of piping beyond phase one. An 14 on-site project manager is in place and is actively 15 working to select vendors who have the experience and 16 capability of working with materials such as high-17 density polyethylene piping, or pipe within a pipe 18 technologies, as examples. In coordination with the 19 vendor selection, a conceptual design of the overall 20 project is underway. Exploratory holes in support of 21 phase one is currently in progress, with weekly 22 report-outs to the station leadership team on project 23 status.
24 MEMBER BALLINGER: Is this system 25 cathodically protected?
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76 1 MR. HARROW: The fire protection system is 2 not cathodically protected.
3 MEMBER KIRCHNER: Allen, on an earlier 4 slide you mentioned compensatory measures. So could 5 you just -- for the record, just explain a little 6 further what you're doing --
7 MR. HARROW: Yes.
8 MEMBER KIRCHNER: -- while you're 9 undertaking this project?
10 MR. HARROW: Okay, so we -- the 11 compensatories we currently have in place are, while 12 -- while the current fire protection pumps -- both the 13 motor-driven and the diesel-driven fire pumps are 14 capable of being started and supplying fire protection 15 water to the loop, we have put in an additional pump 16 that has similar pump capacity capabilities to supply 17 fire protection water from a separate source 18 completely -- from the fire protection tanks -- which 19 is capable of providing the backup fire suppression 20 capability that are needed.
21 MEMBER KIRCHNER: Almost like some of the 22 post-Fukushima kind of equipment -- like, that's the 23 idea I am getting.
24 MR. HARROW: Yes, very similar to post-25 Fukushima -- beyond design basis --
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77 1 MEMBER KIRCHNER: Okay. Do you have to 2 have the extended fire watches during this? Or any 3 other special demands that are -- I don't want to say 4 the word tech specs, but something that are -- you 5 know, condition of operation?
6 MR. HARROW: We have no additional fire 7 watches required. However, we do have compensatory 8 actions in place to isolate certain sections of the 9 fire protection loop within a specific period of time 10 if needed. To allow the other -- the other backup 11 fire suppression pump to -- to supply the loop.
12 MEMBER KIRCHNER: And you -- you mentioned 13 that the -- the loop design is segmented in a way so 14 you can tap into headers or risers -- like, for the 15 turbine building and other important areas from the 16 safety standpoint.
17 MR. HARROW: That is correct. The loop 18 has multiple points at which you can feed the loop and 19 still supply the entire fire protection yard loop.
20 MEMBER KIRCHNER: Thank you.
21 MR. HARROW: You can do that --
22 (Simultaneous speaking.)
23 MR. HARROW: -- applicable locations.
24 MR. SCHULTZ: Allen, we talked earlier 25 about soil testing in accordance with the EPRI NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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78 1 methodology. As you've taken these other samples from 2 other regions of the site, have you done soil testing 3 as well as groundwater identification testing?
4 MR. HARROW: Soil testing has been done 5 from other areas of the site. And I think this is a 6 great opportunity for us -- for us to have the program 7 owner for the buried piping who can get up and speak 8 to that -- to that point.
9 MR. SCHULTZ: I would appreciate that, 10 thank you.
11 MR. SCARBOROUGH: Good morning. I am Troy 12 Scarborough. I am the buried pipe program owner at 13 Surry Power Station and I work with the Dominion 14 Energy team. And we have taken many soil samples. I 15 believe Allen mentioned in -- I believe it was Eric --
16 in 2012 and in 2018. And in 2018, you know, we didn't 17 identify any water during those samples. And we 18 didn't take samples specifically at this location on 19 the fire loop piping, but we took them around the --
20 safety-related piping around the RCA in the plant.
21 MR. SCHULTZ: I would understand that 22 moisture is obviously a component. But the other 23 aspects of EPRI's evaluation, as Erik indicated, was 24 the chemistry -- evaluation of the chemistry of the 25 soil. So I am wondering what has been done there.
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79 1 When I look at what has been proposed, or expanded, in 2 the -- in the SLR -- I don't know what you call it.
3 The requirements process in place -- license renewal 4 commitments. You have in there that you're going to 5 follow the EPRI program and that you're going to take 6 samples across the site on a -- not -- not every day, 7 but as you're going through the process now, I would 8 have expected that you'd get a -- be getting some sort 9 of baseline associated with the samples, given that 10 you've got them and you could simply do some chemistry 11 testing to match up with the EPRI. You said you did 12 it right around the location of the -- of the event.
13 So have you considered looking at that chemistry in 14 other areas of the -- of the piping that surrounds the 15 site?
16 MR. HARROW: Yes, so as we continue to 17 excavate and dig up piping, we are going to take soil 18 samples, have them analyzed -- as well as sending 19 piping off for metallurgical analysis as well. To 20 identify graphitic --
21 MEMBER RICCARDELLA: Do I understand that 22 there's other piping systems that are potentially 23 affected, other than the fire -- the fire protection 24 system? Is that what you said?
25 MR. SCARBOROUGH: We have some lower-NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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80 1 tiered systems such as some cast-iron drain piping.
2 Mainly roof drains -- and one other piping -- that --
3 we're going to take a look at that as well. Yes.
4 MEMBER BALLINGER: I heard -- say that 5 this groundwater and the things like that was 500 --
6 less than 500 ppm chlorides, but one other place a 7 little bit above that. But I think the ACI 8 requirements as well as the EPRI guidelines require 9 not just chloride concentration sampling, but sulfide 10 -- or sulfur -- sulfate or whatever -- and the pH.
11 When you do these samples, do you take all those 12 things as well so you have records of those values as 13 well? Because there's some kind of an index which you 14 can -- the rules for concrete degradation contain the 15 chloride limit, but it also contains the suggestions 16 about sulfide and pH. And you have all that 17 information.
18 MR. SCARBOROUGH: Correct.
19 MEMBER BALLINGER: Yes, thank you.
20 MR. SCARBOROUGH: We do sample for all of 21 those parameters, yes.
22 CHAIR SUNSERI: So just -- just a follow-23 up question for the program owner. In regards to 24 Member Riccardella's question about other systems --
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81 1 the ultimate heat sink that's buried also? Or 2 affected -- potentially affected?
3 (No audible response.)
4 CHAIR SUNSERI: We -- when you said 5 there's other piping, it was unclear what other piping 6 is. And I am asking specifically if there's safety-7 related piping affiliated with access to the ultimate 8 heat sink.
9 MR. SCARBOROUGH: There's no safety-10 related piping in regards to this cast-iron phenomena.
11 CHAIR SUNSERI: Okay, great. Thank you.
12 (Pause.)
13 MR. HARROW: Okay ,continuing. EPRI is 14 sponsoring a selective leaching industry task force.
15 And this group of industry experts has been working on 16 these very issues. We are actively participating with 17 this task force to remain engaged in developments that 18 will ultimately promote effective methods for aging 19 management.
20 In that spirit, Surry Power Station's 21 program owner has shared this operating experience 22 with the industry, as noted in recent and upcoming 23 meetings on the slide, with the goal of increasing 24 industry awareness. Dominion Energy has also sent 25 sections of fire protection piping from the recent NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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82 1 event to EPRI, who continues to research enhanced 2 methods to detect graphitic corrosion. Dominion 3 Energy will update the site programs and procedures as 4 new information becomes available from the efforts of 5 the research and industry groups.
6 In conclusion, Dominion Energy is 7 committed to ensuring the appropriate resources are in 8 place to maintain the integrity and aging management 9 of the fire protection yard loop. I am open for any 10 questions at this time.
11 MR. SCHULTZ: Allen, what's the schedule 12 for the EPRI evaluation of the piping?
13 (No audible response.)
14 MR. SCHULTZ: Or, do you have a schedule 15 yet? Or can you give an appreciation for what it 16 would appear to be? Troy?
17 MR. SCARBOROUGH: Troy Scarborough again.
18 Yes, so I went to a conference last week on that. And 19 they expect to have some NDE results coming out later 20 this year that they -- they believe to be, you know, 21 effective in determining selective leaching.
22 MR. SCHULTZ: Thank you, Troy.
23 MR. HARROW: Okay. At this time I will 24 now turn the presentation over to Paul Aitken, who 25 will provide summary remarks.
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83 1 MEMBER RICCARDELLA: Quick question --
2 before we move on. Just one question related -- it's 3 kind of related to my question earlier about leakage 4 versus rupture. Had you had a fire when you turned on 5 that pump, would the system have supplied sufficient 6 water to -- to fight that fire? Or would all the 7 water be going out the brick?
8 MR. HARROW: Well, so the system was --
9 remained pressurized. The fire pump itself started to 10 maintain the system pressurize. So the fire 11 protection water would have been able to be supplied 12 to a fire. It's interesting to note that, for this 13 particular issue, that the -- the station who was --
14 you know, obviously -- obviously, this wasn't 15 something that was anticipated that was going to 16 happen. It was on a weekend. Saturday afternoon.
17 That section of pipe was completely isolated within 19 18 minutes. And then the -- the fire protection tank 19 water itself was completely restored in less than 20 three hours.
21 The -- the capability of continuing to 22 fight a fire existed at that time.
23 MEMBER RICCARDELLA: Yes, thank you.
24 MR. BLOCHER: Okay. On behalf of Dominion 25 Energy, we first want to commend the NRC staff on NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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84 1 their efforts over the last couple of years. The 2 staff has worked very hard in developing the goal SLR 3 and SRP and conducting the various public meetings 4 which provided the appropriate forum for stakeholder 5 involvement. This was not an insignificant effort.
6 I can attest to that.
7 I would also like to recognize the NRC 8 staff on the thoroughness of the safety review 9 performed on the SLR application for Surry. I want to 10 reiterate that Dominion Energy has been engaged and 11 integrated with the work leading up to the GALL-SLR 12 issuance. We have been heavily invested, along with 13 others in the industry, over the last couple of years 14 to ensure we have the appropriate guidance and have 15 explored areas for optimization with the NRC staff 16 based on the vast experiences during the first 17 licensed renewals.
18 Dominion Energy has developed a high 19 quality SLR application that benefitted from the GALL-20 SLR and SRP as well as the industry support. Dominion 21 Energy will continue to invest in Surry Power Station 22 now and into the future to ensure the continued safe 23 and reliable operation for 80 years of operation.
24 This ends our prepared remarks. And I would like to 25 express our appreciation to the subcommittee for this NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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85 1 opportunity to discuss operation of Surry for 80 2 years. Are there any remaining questions?
3 CHAIR SUNSERI: Do members have any other 4 questions for them?
5 (No audible response.)
6 CHAIR SUNSERI: Okay, all right. Well we 7 appreciate your presentation. Very thorough and 8 informing. At this time, I would like to transition 9 to the staff presentation. We would normally take a 10 break, but we are tracking right along schedule and we 11 have a hard stop at noon because there's other 12 activities that we need to participate in. So I would 13 ask that if anybody needs to take a biological break, 14 that you do so individually and just quietly excuse 15 myself and then come on back in. All right? So let's 16 transition. Thank you.
17 (Pause.)
18 MR. MOORE: Mr. Chairman, we got a message 19 during the presentation that Dominion and Exelon -- is 20 that correct? Or, Southern and Exelon are on the 21 public line. But they'll be muted with all the other 22 members of the public until we unmute the public line.
23 CHAIR SUNSERI: Okay.
24 (Pause.)
25 CHAIR SUNSERI: Yes, you can't leave.
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86 1 (Off microphone comments.)
2 CHAIR SUNSERI: Yes, we have a quorum. We 3 maintain that quorum. Right, yes. Right. But I 4 don't know if I am a warm body. I am kind of cold 5 right now. My balding head -- it is chilly. So, 6 Angela, are you leading this effort here? Okay, 7 great. But we do have a quorum. And if you're 8 prepared to get started, then we're ready. Yes.
9 MS. WU: Can you hear me over there?
10 Okay, perfect. Can everyone hear me on the phone on 11 the open line? Allen, can you say hello first?
12 MR. HISER: Good morning.
13 MS. WU: Great, okay. I think we're ready 14 to get started. We just want checks --
15 (Simultaneous speaking.)
16 CHAIR SUNSERI: Yes, absolutely no 17 problem.
18 MS. WU: Thank you, hello. Good morning, 19 Chairman Sunseri and members of the ACRS Plant 20 Licensed Renewal Subcommittee. My name is Angela Wu 21 and I am one of the project managers for the Surry 22 Power Station, Units 1 and 2 Subsequent Licensed 23 Renewal Application -- or, SLRA. As you heard from 24 Bob Caldwell at the start of the meeting, we are here 25 to discuss the NRC staff's safety review of the Surry NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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87 1 SLRA as documented in the Safety Evaluation Report, or 2 SER, that was issued on December 27th, 2019.
3 Joining me here at the table today are 4 Lauren Gibson, the second safety project manager for 5 the Surry SLRA. Dr. Steven Downey, Senior Reactor 6 Inspector from Region II, and Lewis McKown, Acting 7 Chief of Engineering, Branch 4, in the Division of 8 Reactor Projects, Region II. In addition, joining us 9 on the phone is Dr. Allen Hiser, Senior Technical 10 Advisor for Licensed Renewal Aging Management, 11 Division of New and Renewed Licenses -- who you just 12 heard from.
13 Seated in the audience and joining in on 14 the phone are members of the technical staff who 15 participated in the review and conducted the audits.
16 Next slide, please.
17 So we begin today's presentation with an 18 overview of the -- safety review of the Surry SLRA 19 before moving into the SER. Section 2, Scoping and 20 Screening Review; Section 3, the Aging Management 21 Review; Section 4, Time-limited Aging Analyses; as 22 well as specific areas of the review. Then we will 23 hear from Region II on inspections and plant material 24 conditions before sharing the staff's conclusion on 25 the Surry SLRA. Finally, we will have a discussion on NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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88 1 some differing reviews. Differing views, sorry. Next 2 slide, please.
3 Surry Units 1 and 2 were initially 4 licensed in May 1972 and January 1973, respectively.
5 In May 2001 the Applicant, Virginia Electric and Power 6 Company -- or Dominion -- submitted the initial 7 license renewal application. The initial renewed 8 licenses were issued March 2003, extending the 9 expiration dates to May 2032 and January 2033 for 10 Units 1 and 2 respectively.
11 On October the 15th, 2018 Dominion 12 submitted their subsequent license renewal application 13 for Surry Units 1 and 2. The application was accepted 14 for review on December 10th, 2018 and the draft safety 15 evaluating report was issued on December 27th, 2019 16 with no open or confirmatory items. Next slide, 17 please.
18 The Surry review is the third safety 19 review performed by the staff using the GALL-SLR and 20 SRP-SLR guidance issued -- since their issuance in 21 2017. For the review we conducted a total of three 22 audits, as identified on this slide. During the 23 operating experience audit, the staff performed an 24 independent review of plant-specific operating 25 experience to identify pertinent examples of age-NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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89 1 related degradation as documented into Applicant's 2 Corrective Action Program database. During the in-3 office audit, the audit team focused on two areas.
4 First, the scoping and screening review. And second, 5 the review of aging management programs -- or AMPs --
6 aging management review items, or AMRs -- or time-7 limited -- and time-limited aging analyses, or TLAAs.
8 An on-site audit limited to those 9 technical areas that needed further review following 10 the in-office audit was conducted at both Surry Power 11 Station Units 1 and 2 in Surry County, Virginia and 12 Dominion Headquarters in Innsbrook, Virginia. Next 13 slide, please.
14 The Surry draft SER was issued with no 15 open or performatory items on December 27th, 2019.
16 During the staff's in-depth, technical review, a total 17 of 71 requests for additional information were issued.
18 Slide please. In the next few slides I will present 19 the results of the staff safety review as described in 20 the SER. SER, Section 2, describes the scoping and 21 screening of the structures and components subject to 22 aging management review. The staff reviewed the 23 Applicant's scoping and screening methodology, 24 procedures and results. The staff also reviewed the 25 various summaries of the safety-related systems, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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90 1 structures and components -- or SSEs -- non-safety 2 related SSEs affecting safety functions, and SSEs 3 relied upon to perform functions in compliance with 4 the Commission's regulations for fire protection, 5 environmental qualification, station blackout, 6 anticipated transients without scram, and pressurized 7 thermal shock.
8 Based on the review, the results of the 9 audits and additional information provided by the 10 Applicant, the staff concluded that the Applicant's 11 scoping and screening methodology and implementation 12 were consistent with the criteria of the SRP-SLR and 13 requirements of 10 CFR Part 54. Next slide, please.
14 SER Section 3 and its subsections cover 15 this fast review of the Applicant's programs for 16 managing the effects of aging in accordance with 10 17 CFR 52 -- 54.21 A-3. Sections 3.1 to 3.6 include the 18 AMR items in each of the general system areas within 19 the scope of subsequent licensed renewal, as shown on 20 this slide. For a given AMR item, the staff reviewed 21 the item in accordance with the criteria of the SRP-22 SLR to determine whether it is consistent with the 23 GALL-SLR. For AMR items not consistent with the GALL-24 SLR, the staff reviewed the Applicant's evaluation to 25 determine whether the Applicant has demonstrated that NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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91 1 there is reasonable assurance that the effects of 2 aging will be adequately managed so that the intended 3 functions will be maintained consistent with the 4 current licensing basis for the subsequent period of 5 extended operation.
6 Based on the review, the results from the 7 audits and additional information that was provided by 8 the Applicant, the staff concluded that the 9 Applicant's aging management review activities and 10 results were consistent with the criteria of the SRP-11 SLR and requirements of 10 CFR Part 54. Next slide.
12 So the SLRA described a total of 47 AMPs 13 -- seven new and 40 existing. This slide identifies 14 the Applicant's original disposition of these AMPs, as 15 stated in the SLRA in the left column, and the final 16 disposition as documented in the SCLR in the right 17 column. All of the AMPs were evaluated for 18 consistency with the GALL-SLR. As a result of the 19 staff's review, the Applicant made one change to the 20 disposition of the AMPs. Based on the review, the 21 results from the audits and additional information 22 provided by the Applicant, the staff concluded that 23 the Applicant's aging management program activities 24 and results were consistent with the criteria of the 25 SRP-SLR and requirements of 10 CFR Part 54.
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92 1 SER Section 4 identifies time-limited 2 aging analyses, or TLAAs. Section 4.1 documents the 3 staff's evaluation of the Applicant's identification 4 of applicable TLAAs. The staff evaluated the 5 Applicant's bases for identifying these plant-specific 6 or generic analyses that need to be identified as 7 TLAAs, and determined that the Applicant has provided 8 an accurate list of TLAAs as required by 10 CFR 54.21 9 C-1. Section 4.2 to 4.7 document the staff's review 10 off the applicable TLAAs for the areas shown on this 11 slide.
12 Based on its review and the information 13 provided by the Applicant, the staff concludes that 14 each TLAA is classified, as required by 10 CFR 54.21 15 C-1, as either I, the analysis remains valid for the 16 subsequent period of extended operation; ii, the 17 analysis has been projected to the end of this 18 subsequent period of extended operation; or iii, the 19 effects of aging on the intended functions will be 20 adequately managed for the subsequent period of 21 extended operations. So based on the review, the 22 results from the audits and additional information 23 provided by the Applicant, the staff concluded that 24 the Applicant's TLAA activities and results were 25 consistent with the criteria of the SRP-SLR and NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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93 1 requirements of 10 CFR Part 54.
2 So because the draft SER was issued with 3 no open or performatory items, we will now be 4 highlighting some specific areas of the review that we 5 think may be of interest -- as shown on this slide.
6 CHAIR SUNSERI: And before I forget and 7 you move on, I did look at the audit report. And that 8 was quite a thorough report. So you all did a nice 9 job on that.
10 MS. WU: Do you have any questions on 11 that? Or just -- making a comment?
12 CHAIR SUNSERI: No, no.
13 MS. WU: Thank you. So we're on slide 11.
14 Irradiation fluence and dose -- experience through 80 15 years of operation by concrete and steel structural 16 components located in the vicinity of the reactor 17 vessel could be significant. For Surry, the concrete 18 biological shield wall and reactor vessel steels 19 supports were evaluated for these irradiation aging 20 effects. This slide presents the staff's review of 21 Dominion's evaluation for the concrete biological 22 shield wall. And the next slide will then discuss the 23 reactor vessel steel supports.
24 The staff reviewed Dominion's further 25 evaluation of the irradiation aging effects of NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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94 1 reduction of strength and mechanical properties of the 2 concrete biological shield wall against the criteria 3 of the corresponding SRP-SLR section. The figure on 4 the slide shows the general configuration of the 5 concrete biological shield wall relative to the 6 reactor vessel and a neutron shield tank, which is 7 shaded in blue.
8 Although not fully shown, the concrete 9 biological shield wall extends above and below the 10 neutron shield tank. Based on the review, responses 11 to the REIs and the staff's audits, the staff finds 12 that Dominion has met the further evaluation criteria 13 in the SRP-SLR for the concrete biological shield wall 14 concrete. Dominion's determination that a plant-15 specific AMP is not required to manage the aging 16 effects of irradiation on the concrete biological 17 shield wall during the subsequent period of extended 18 operation is acceptable for the following reasons.
19 The calculated limiting neutron fluence 20 and limiting gamma dose are less in the respective 21 thresholds, as noted in the SRP-SLR. The use of 72 22 effective full-power years for fluence and dose 23 estimates is conservative, whereas anticipated plant 24 operation is 68 effective full-power years. There is 25 no plant-specific operating experience noted to date NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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95 1 of concrete biological shield irradiation degradation.
2 And the accessible areas of the concrete biological 3 shield wall will continue to be monitored by visual 4 inspection in a five-year interval using the 5 structure's monitoring program.
6 Slide, please. Dominion's SLRA Section 7 35-226 addresses Surry's reactor vessel steel support 8 assemblies. Surry's reactor vessels are supported by 9 six steel sliding foot assemblies on neutron shield 10 tanks, as illustrated in the figure. The neutron 11 shield tank skirt is supported on the containment base 12 net floor, approximately 15 feet below the bottom of 13 the angular tank. Based on the review, the staff 14 finds that the neutron shield tanks will maintain 15 their structural integrity. This is based on a 16 fracture toughness evaluation, made in accordance with 17 the ASME Code Section 11, Appendix A, and the 18 fractured mechanics approach of NU-REG 1509.
19 The fractured toughness evaluation 20 demonstrated that critical stress regions of the 21 neutron shield tanks are not susceptible to brittle 22 fracture due to irradiation embrittlement because the 23 maximum applied stresses under design loads remain 24 below the critical stress values for postulated 25 evaluated flaws during the subsequent period of NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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96 1 extended operation. In addition, accessible surfaces 2 of the neutron shield tank and its sliding foot 3 assemblies will continue to be periodically inspected 4 externally for susceptible aging effects by one or 5 more of the following programs -- the ASME Section 11, 6 subsection IWF program at a 10-year frequency, and the 7 structures monitoring program at a 5-year frequency.
8 The neutron shield tank is filled with 9 chromated fluid. To prevent loss of material in the 10 neutron shield tank, the closed treated water systems 11 AMP specifies monitoring this chemistry of the 12 naturally circulating chromated fluid every fueling 13 outage. The staff determined that Dominion's 14 evaluation for the neutron shield tank and reactor 15 vessels support sliding foot assemblies meets the 16 intent of the SRP-SLR for the evaluation criteria 17 consistent with the GALL-SLR principles.
18 For the buried and underground piping and 19 tanks program, the Applicant proposed using a one-time 20 inspection along with groundwater and soil testing.
21 To manage the effects of aging on the external 22 surfaces of uncoated, buried cementitious circulating 23 water piping. The staff notes that the Applicant's 24 approach to manage the effects of aging differs from 25 the GALL-SLR guidance.
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97 1 The GALL-SLR recommends periodic 2 inspections, as noted on the slide, for this 3 component, material and environment combination. For 4 the one-time inspection, the Applicant proposed a one-5 time inspection of the turbine building below 6 subsurface concrete as the surrogate concrete 7 structure if it is bare or uncoated. Otherwise, a 8 one-time inspection of the buried cementitious 9 circulated water piping will be performed.
10 The circulating water pipe has an inside 11 diameter of 8 feet, a wall thickness of 9 inches and 12 it is reinforced with rebar longitudinally and 13 circumferentially on both the inside and outside 14 surface. The staff evaluated whether the turbine 15 building's subsurface concrete would be an appropriate 16 surrogate concrete by comparing its properties and 17 environment to those of the circulating water piping.
18 It is noted that the surrogate concrete structure and 19 the circulating water piping concrete were made to 20 meet the same American Society for Testing and 21 Materials Standards for a cement aggregates, water and 22 reinforcing steel.
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98 1 environment as the circulating water piping. This is 2 because both components are located at a depth that is 3 below the groundwater level and freeze-thaw line. At 4 this depth, the groundwater and soil is not aggressive 5 for concrete. The staff also noted that the turbine 6 building concrete has a higher water-to-cement ratio 7 and a lower concrete strength.
8 Considering the concrete design standards 9 and concrete properties of the turbine building and 10 circulator water piping, the staff finds that the 11 turbine building concrete is expected to be more 12 susceptible to degradation than the circulating water 13 piping concrete. Therefore, the staff finds that the 14 turbine building concrete to be an adequate surrogate 15 concrete structure that can serve as a leading 16 indicator of potential degradation at the circulating 17 water piping because its concrete properties are such 18 that, if the environmental conditions were conducive 19 of concrete degradation, signs of such degradation 20 would also be present and identified at the turbine 21 building surface concrete and corrective actions would 22 be taken to evaluate the circulating water piping 23 degradation before there's a loss of their intended 24 function.
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99 1 one-time inspections in lieu of performing periodic 2 inspections as recommended in the GALL-SLR, the staff 3 noted that the Applicant performed groundwater testing 4 at every five years and soil testing at every ten 5 years.
6 CHAIR SUNSERI: Regarding the surrogate 7 sampling approach and the -- I understand the 8 comparison of the ASME standard so that they're the 9 same standard. But was the aggregate used to actually 10 construct the two, I'll call them facilities from the 11 same quarry because it's my, or similar because it's 12 my understanding that aggregate can have a big effect 13 on the degradation potential. So do we know if it was 14 constructed from the same material, not only the same 15 standard?
16 MS. WU: So is Brian Allik available to 17 answer that question? Oh --
18 MR. JOHNSON: Excuse me. This is Jim 19 Johnson again. The aggregate was not, as far as we 20 know, from the same quarry because the pipe was 21 manufactured offsite. But we haven't had any 22 indications of ASR in any of the concrete. The ASR 23 was studied.
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100 1 drills for several structures around site and did not 2 find ASR at that time.
3 CHAIR SUNSERI: Okay. I'm satisfied.
4 Thank you.
5 MR. SCHULTZ: But just for clarification, 6 both of these inspections are one-time inspections?
7 MS. WU: So the groundwater testing is 8 every five years, and the soil testing every ten 9 years.
10 MR. SCHULTZ: Okay. I was thinking of the 11 turbine building concrete. That's happening one time.
12 MS. WU: Yes, yes.
13 MR. SCHULTZ: And has that -- that's been 14 done or it will be done?
15 MS. WU: It will be done.
16 MR. SCHULTZ: At what, on what time 17 schedule? When will it be done, before, sometime 18 before the --
19 MS. WU: A subsequent period of extended 20 operation.
21 MR. SCHULTZ: Yeah, sometime before, yeah, 22 to be defined?
23 MS. GIBSON: I don't have those details 24 right now. Is Brian Allik available? Oh, Juan Lopez 25 is.
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101 1 MR. SCHULTZ: Right. Thank you.
2 MR. LOPEZ: This is Juan Lopez from the 3 staff. The commitment right now is to do it one time 4 before the subsequent period of extended operation.
5 MR. SCHULTZ: But no time has been 6 specified at this point.
7 MR. LOPEZ: Not a specific time that it 8 will be happening before.
9 MR. SCHULTZ: And we'll just see what 10 happens with the one-time inspection. All right.
11 MEMBER BALLINGER: We were told that the 12 containment building cover is five inches. What's the 13 turbine building cover?
14 MR. JOHNSON: This is Jim Johnson. I 15 don't know offhand. I think it's three inches at that 16 point. That would be per ACI codes for the turbine 17 building.
18 MEMBER BALLINGER: Okay. That's --
19 MS. WU: Thank you, Jim and Juan. Any 20 other questions before I continue?
21 The staff notes that the GALL-SLR 22 identifies the same groundwater and soil environment 23 parameters as the main environmental stressors for 24 below-grade concrete used in buried cementitious 25 piping.
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102 1 Based on the inclusion of groundwater and 2 soil testing, the staff finds that a one-time 3 inspection of either a surrogate structure or buried 4 circulating water piping provides the staff reasonable 5 assurance that the effects of aging will be adequately 6 managed.
7 MEMBER KIRCHNER: Angela, is there any, 8 pardon me, are there any aging effects internal to the 9 pipe?
10 MS. WU: Oh, internal.
11 MS. GIBSON: I believe those would be 12 handled --
13 MEMBER KIRCHNER: Like long-term erosion 14 corrosion.
15 MS. WU: Yeah, that would be a different 16 AMP than this one.
17 MEMBER KIRCHNER: Hmm?
18 MS. GIBSON: It would be handled under a 19 different AMP.
20 MEMBER KIRCHNER: Different AMP.
21 MS. GIBSON: Yes. Would that be internal 22 coatings?
23 MS. WU: Yes, internal coatings.
24 MS. GIBSON: Or internal surface.
25 (Off mic comments.)
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103 1 MS. WU: Okay. So we're on slide 14. On 2 October 14, 2019, Dominion submitted an annual update 3 to the SLRA that identified two ruptures of the buried 4 fire protection system piping which occurred in July 5 of 2019.
6 Analysis concluded that the failure was a 7 result of external graphitic corrosion and determined 8 that it was a result of groundwater exposure of the 9 cast iron fire protection piping.
10 In response to this operating experience, 11 the applicant has augmented the new selective leaching 12 program to address the graphitic corrosion that led to 13 the ruptures by including requirements to drill 14 exploratory holes to confirm the presence of 15 groundwater.
16 These holes will be drilled in areas of 17 suspected system leakage or elevated groundwater. For 18 each hole identified with groundwater, the applicant 19 will excavate and inspect the fire protection loop 20 piping at each hole. Each excavation will include a 21 soil sample.
22 The applicant will also drill additional 23 exploratory holes to confirm the extent of any 24 identified elevated groundwater along with the notice 25 sample expansion activities.
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104 1 For each excavation, a minimum of ten feet 2 of buried fire protection main loop piping will be 3 excavated and then cleaned using aggressive cleaning 4 techniques sufficient to remove the alloyed material 5 and visually examined for evidence of selective 6 leaching.
7 A minimum of five destructive exams will 8 be performed in separate, one-foot sample sections of 9 fire protection pipe that exhibit signs of selective 10 leaching.
11 If water in an exploratory hole is 12 identified to be a result of fire protection system 13 leakage or other plant system leakage and not due to 14 elevated groundwater, then corrective actions would be 15 initiated consistent with the selective leaching 16 program.
17 Changes to the aging management programs 18 to address possible issues, if necessary, would be 19 identified as Dominion completes these corrective 20 actions for the July 2019 pipe ruptures.
21 In conclusion, the staff has reasonable 22 assurance that the newly augmented selective leaching 23 program will be adequate to manage selective leaching.
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105 1 inspecting fire protection loop piping, are capable of 2 detecting adverse conditions due to groundwater 3 immersion that may lead to graphitic corrosion.
4 Next slide, please.
5 MEMBER KIRCHNER: Before you go on, so is 6 -- we heard from the applicant there are plans on this 7 project underway to replace the fire loop piping. To 8 what extent is that a commitment that you, the NRC, 9 will have some oversight of or regulatory review?
10 MS. WU: So the selective leaching 11 program, following the annual update that was provided 12 on October 14, 2019, there was a subsequent letter 13 that came in October 31, 2019 from Dominion that 14 augmented the selective leaching program itself in the 15 description of the AMP.
16 However, there was no change to the 17 commitments. So, if that's what you're asking, there 18 was no modification to the commitments in that matter.
19 Do you have something to add?
20 MR. DOWNEY: Well, I can speak from the 21 perspective of oversight. So, if this were in the 22 initial period of extended operation, our Phase 2 type 23 inspection would be where we would go in and verify 24 that the commitments made by the licensee had been 25 appropriately implemented.
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106 1 For subsequent license renewal, currently 2 there aren't any inspections in the program for 3 subsequent license renewal. We understand that the 4 license renewal inspection program is being updated.
5 So there may be some added in the future.
6 MEMBER KIRCHNER: And this initial fire 7 loop system was in place since the plant was first 8 licensed. So it had a lifetime of the, oh, now close 9 to 50 years. Is that correct?
10 So one could expect that if they replace 11 substantial parts of the piping, that would be a 12 lifetime that might be well beyond the extended period 13 of operation. Okay.
14 But it's through your inspection process, 15 Steven, that you would stay abreast of what changes 16 are being made and --
17 MR. McKOWN: In both the license renewal 18 phase and in the normal baseline ROP, we have 19 processes and procedures that would guide governance 20 for long-lived passive systems being reviewed under 21 that inspection phase. So it would fall --
22 MEMBER KIRCHNER: Through the inspection 23 process. Okay. That answers my question.
24 MR. OESTERLE: This is Eric Oesterle from 25 the staff. I'd just like to supplement the answer.
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107 1 So there are two or three different processes involved 2 here. One is the subsequent license renewal review 3 that the staff is performing on the application. The 4 other process is the inspection of the initial license 5 renewal implementation of aging management programs.
6 And then there's the corrective actions 7 program. The NRC always has oversight over the 8 corrective actions program and --
9 MEMBER KIRCHNER: Okay. Thank you.
10 MS. WU: Thank you for your question.
11 MR. SCHULTZ: Steven, I'm looking ahead in 12 the slides, so maybe it's being covered later in 13 detail. But under the AMP inspections, there's one 14 that's coming up in the first quarter of 2020 on the 15 2019 fire loop piping rupture burying piping program.
16 So does that not enter into our discussion here?
17 MR. DOWNEY: Yes, you're talking about the 18 focused PI&R.
19 MR. SCHULTZ: Yes.
20 MR. DOWNEY: PI&R meaning problem 21 identification and resolution.
22 MR. SCHULTZ: Thank you.
23 MR. DOWNEY: So that's corrective action 24 inspection.
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108 1 you're describing here is the, is something that's 2 upcoming. And what is the scope of that, if you don't 3 mind covering it now?
4 MR. DOWNEY: So you're stealing my thunder 5 a little bit here.
6 MR. SCHULTZ: Oh, I'm sorry.
8 MR. SCHULTZ: I can --
9 MR. DOWNEY: Yeah, I'll cover it during 10 the --
11 MR. SCHULTZ: Let's wait.
12 MR. DOWNEY: -- presentation.
13 CHAIR SUNSERI: Steve, is your mic on?
14 MR. SCHULTZ: Yes, it is.
15 CHAIR SUNSERI: Okay.
16 MR. SCHULTZ: Did you catch it?
17 CHAIR SUNSERI: Yeah, no, that's all 18 right.
19 MR. SCHULTZ: The other question I had, 20 Angela, you mentioned that there weren't any changes 21 to the commitments related to the issues related to 22 the --
23 MS. WU: To the new operating experience.
24 But they did provide commitments, as they would for 25 any AMPs, so when they would have submitted the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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109 1 application --
2 MR. SCHULTZ: Okay. Maybe I misunderstood 3 how the process goes, because in the information that 4 Surry provided in the, I think it was October, 5 September timeframe, they included new, their 6 commitment that dictates that they're going to follow 7 for soil sample evaluation the EPRI guidelines. And 8 they've talked about how they're going to identify 9 soil corrosivity index networks that are in that 10 document. So that's been added specifically --
11 MS. WU: Right.
12 MR. SCHULTZ: -- in their program going 13 forward.
14 MS. GIBSON: So, correct me if I'm wrong, 15 but I believe that that was added to their program 16 description --
17 MS. WU: Yes.
18 MR. SCHULTZ: Okay.
19 MS. GIBSON: -- as opposed to the formal 20 listing of commitments that's going to be incorporated 21 into the FSAR.
22 MR. SCHULTZ: What's the difference, if 23 you can help me?
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110 1 become part of the FSAR and under a change control 2 program.
3 MR. SCHULTZ: Okay. So, then, does that 4 mean that the procedure is under their control and not 5 in the FSAR, which would be under NRC control? I'm 6 trying to understand the distinction --
7 MS. GIBSON: Yes.
8 MR. SCHULTZ: -- in terms of 9 implementation.
10 MS. GIBSON: There's a lower degree of 11 control that we have over the procedures. It has to 12 go through -- it's incorporated into the license 13 through the FSAR updates with the commitments. And 14 those commitments are subject then to the 50.59 15 process.
16 So it's under a changed control mechanism.
17 But it is not like a tech spec where they would have 18 to come in to change a word.
19 MR. SCHULTZ: I understand.
20 CHAIR SUNSERI: But would the requirements 21 of 50.59 still apply though or not?
22 MS. GIBSON: Well, they would. But I'm 23 not sure whether this would actually rise to the level 24 of being --
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111 1 for subsequent license renewal is anything similar to 2 the license conditions for initial license renewal, 3 then it folds in that any changes to the activities 4 described in programs, et cetera, would be evaluated 5 using a 50.59 process. So that's how it ties in 6 through the license condition.
7 MR. SCHULTZ: So, just to clarify, so this 8 is under the topic of subsequent license renewal 9 conditions, commitments, but it's a commitment to have 10 procedures in place. Is that what you're saying?
11 MS. GIBSON: Yes.
12 MS. WU: Yes.
13 MR. SCHULTZ: So it doesn't change the 14 FSAR.
15 MS. WU: No.
16 MR. SCHULTZ: Thank you. I got it.
17 MS. WU: The selective leaching program 18 does have a commitment tied to it. It just was not 19 revised as a result of the July 2019 pipe ruptures 20 that was then reported to us on the October 14, 2019 21 annual update.
22 MR. SCHULTZ: So let me back up a bit.
23 When you were talking about the turbine building 24 concrete, you indicated that soil testing was going to 25 be done as part of that program to make sure there NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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112 1 wasn't anything else that was coming up. And that 2 would be the going forward process to do a double-3 check or evaluation on a, going forward time basis 4 versus the one-time inspection. So is that a 5 commitment, or is that part of another procedure?
6 MS. WU: That one, Brian, do you want to 7 --
8 MR. ALLIK: Brian Allik, NRC staff. Just 9 to clarify a point, there's two specific commitments 10 related to soil testing.
11 The first one, which references that EPRI 12 report, is in context with carbon steel. And then 13 there's another commitment related to, you know, the 14 alternative approach that was previously described to 15 do soil testing near the, in the vicinity of that 16 concrete or cementitious piping. So I just wanted to 17 clarify that point.
18 MR. SCHULTZ: I appreciate that.
19 MR. ALLIK: All right.
20 MR. SCHULTZ: I knew they were different.
21 But it sounded similar. And it's also characterizing 22 the soil, which is a good thing to do. Thank you.
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113 1 that we're talking about.
2 So the commitments for the aging 3 management programs included in the application, in 4 which they're also included in Attachment A to the 5 SAR, often talk about a timeframe in which the AMP 6 will be implemented. And there's the description of 7 the aging management program itself, which gets 8 included in the FSAR and, therefore, becomes part of 9 the current licensing basis.
10 There are implementing procedures that are 11 lower-tiered documents from that FSAR level 12 information which the applicant will use to implement 13 those activities.
14 Both things, the FSAR, compliance with the 15 current licensing basis, and those implementing 16 procedures are all part of NRC oversight.
17 MR. SCHULTZ: And subject to inspection.
18 MR. OESTERLE: Correct.
19 MR. SCHULTZ: Thank you, Eric.
20 CHAIR SUNSERI: I am going to interject 21 right here. As I announced earlier at the start of 22 the meeting, I'm going to have to excuse myself for a 23 short period of time. And in my absence, Walt will be 24 the chairperson running the meeting. And I note that 25 even with my absence we do have a quorum still. So NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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114 1 thank you.
2 MS. WU: Slide 15, neutron fluence 3 monitoring. In its review, the staff identified a 4 difference between the program elements that the 5 applicant defined for the neutron fluence monitoring 6 AMP and the corresponding elements defined in the 7 GALL-SLR.
8 The difference is that the applicant will 9 not monitor neutron fluence of the reactor vessel 10 internals through an SLR period.
11 Appendix C of the SLRA included generic 12 80-year fluence ranges as part of the screening 13 criteria for reactor vessel internals components in 14 the MRP-227, Revision 1, gap analysis.
15 However, the applicant did not provide 80-16 year fluence values specific to the Surry reactor 17 vessel internals.
18 Because the applicant will not be 19 monitoring neutron fluence of the reactor vessel 20 internals, the staff needed the 80-year fluence 21 projections of the reactor vessel internals to verify 22 if the fluence values of the reactor vessel internals 23 fall within the generic fluence ranges as cited in 24 Appendix C of the SLRA.
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115 1 requesting for the 80-year fluence projections 2 specific to the Surry reactor vessel internals.
3 In its RAI response, the applicant 4 provided a proprietary report that included the 80-5 year fluence projections specific to the Surry reactor 6 vessel internals and described the fluence projection 7 methodology used in the report.
8 The staff reviewed the 80-year Surry-9 specific fluence values for the reactor vessel 10 internals and the fluence methodology in the 11 proprietary report. The staff found the fluence 12 values acceptable.
13 Based on the 80-year fluence projections 14 of the Surry reactor vessel internals falling within 15 the specified ranges of The MRP-227, Revision 1, gap 16 analysis, the AMP provides reasonable assurance that 17 the effects of aging will be adequately managed.
18 MEMBER KIRCHNER: Angela, do you do a kind 19 of assessment of their proprietary report through your 20 own benchmarks or other look-up tables or even going 21 as far as doing actual calculations to have confidence 22 that their estimate is reasonably accurate so then you 23 can draw the final conclusion that you have?
24 MS. WU: Do David Dijamco is going to 25 speak to that since he did the technical review.
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116 1 MR. DIJAMCO: This is David Dijamco from 2 the staff. We basically just reviewed the proprietary 3 report. We just made sure that the fluence values for 4 the internals fall within the ranges.
5 And we also reviewed the methodology, the 6 fluence methodology and that they were, made sure that 7 they were consistent with the Reg Guide 1.190. But we 8 didn't do actual independent calculations.
9 MEMBER KIRCHNER: But this is something 10 that's been done through the industry quite 11 frequently. So one could have some confidence just 12 based on, I don't want to say back-of-the-envelope 13 calculations, but, you know, other submittals and such 14 in terms of whether it's a reasonable estimate or not, 15 right? Do you do anything like that? When you said 16 --
17 MR. DIJAMCO: No, we did not do that, no, 18 yeah.
19 MEMBER KIRCHNER: But when you said you 20 reviewed the methods, is this like -- I don't want to 21 go into proprietary information here. But say they 22 were using MC&P. That's a widely accepted tool for 23 this particular application.
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117 1 when you say you reviewed the methodology?
2 MR. DIJAMCO: Correct. Is Dr. Peng here?
3 Dr. Peng.
4 DR. PENG: This is Shie-Jeng Peng from 5 staff. I understand your question regarding the 6 benchmark on the methodology.
7 Yes, they asked Westinghouse to -- time to 8 have, it's a variance capsule come out with -- they 9 used the same methodology to check the calculations 10 with measurements with a certainty or not.
11 And this is a very good conclusions at, 12 for both unit within the 1 Sigma, 20 percent 13 uncertainty.
14 MEMBER KIRCHNER: Okay. Good. Thank you.
15 MR. SCHULTZ: It was noted by Surry that 16 they are going to withdraw capsules during the period 17 of extended operation and, on both units. So that has 18 been taken into account in your evaluation as well?
19 MS. WU: We would have to -- was it? Yes, 20 it was.
21 MR. SCHULTZ: Thank you.
22 MS. WU: Okay. Next slide, please.
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118 1 matrix.
2 The applicant provides the inaccessible 3 medium-voltage cable AMP to include a test matrix that 4 includes inspection methods, test methods, and 5 acceptable criteria for the inaccessible medium-6 voltage cables.
7 The staff reviewed this revision and finds 8 it acceptable because it is consistent with the GALL-9 SLR.
10 Also, the applicant's proposed 11 environmental qualification, or EQ program, excluded 12 mechanical components. It is not clear that the 13 interfacing mechanical components, such as seals, 14 lubricants, and gaskets, will be age-managed as part 15 of the EQ AMP.
16 The staff performed an onsite audit and 17 verified that the mechanical interfaces are addressed 18 in the EQ program.
19 The plant qualification evaluations 20 document replacement components and their respective 21 replacement schedules as well as routine maintenance 22 to maintain qualifications.
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119 1 and calculations are consistent with the current rules 2 and regulations.
3 The staff, therefore, concluded that the 4 EQ program is adequate to satisfy the TLLA, consistent 5 with 10 CFR 54.21(c)(1)(iii).
6 Now, Dr. Steven Downey will discuss 7 inspections and plant conditions.
8 MR. DOWNEY: Good morning. As mentioned, 9 my name is Steven Downey. I'm a Senior Reactor 10 Inspector.
11 MEMBER KIRCHNER: May I just -- yeah.
12 MR. DOWNEY: Yes.
13 MEMBER KIRCHNER: Bring your microphones 14 closer to you. This room has, absorbs sound. So you 15 have to speak loudly to be recorded for the record, 16 please.
17 MR. DOWNEY: Okay. Thank you. So my name 18 is Steven Downey. I'm a Senior Reactor Inspector in 19 Region II, Division of Reactor Safety, Engineering 20 Branch 3. I am one of the license renewal point of 21 contacts for Region II. And I was the team lead for 22 the recent Phase 4 license renewal inspection at 23 Surry.
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120 1 Projects, Reactor Projects Branch 4.
2 And we are here to discuss Region II's 3 review and assessment of the implementation of aging 4 management programs at Surry, the material condition 5 of the plant, and the overall regulatory assessment of 6 Surry Units 1 and 2.
7 So, before I get started, the license 8 renewal inspection program and the reactor oversight 9 process baseline inspection program are both used to 10 inspect aging management programs at Surry.
11 I'll start with activities performed under 12 the license renewal inspection program and then 13 discuss the baseline inspections and follow up with 14 the material condition of the plant discussion.
15 So, in order to assess the adequacy of 16 license, of the license renewal program for the 17 initial period of extended operation, Inspection 18 Procedure 71003 recommends a four-phased approach to 19 license renewal inspection.
20 This slide details the license renewal 21 inspections that we have performed at Surry. And as 22 I discuss each line item, I will give a bit of detail 23 on what the inspection entails.
24 So first item is the Phase 1 inspection, 25 which we performed for both units back in April 2011.
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121 1 This is an outage inspection that focuses on observing 2 the implementation of select aging management programs 3 and activities credited for managing aging, as well as 4 any testing or visual inspections of structures, 5 systems, and components that are only accessible at 6 reduced power levels.
7 April 2011 was the spring outage for Unit 8 2, so the inspectors were able to maximize the 9 observation of activities credited for license renewal 10 that were performed on Unit 2 prior to entering its 11 period of extended operation, while also observing 12 license renewal activities performed on Unit 1, such 13 as the external visual examination of the Unit 1 14 containment in accordance with ASME Section 11 15 requirements.
16 No findings of significance were 17 identified as a result of the Phase 1 inspection.
18 Next, the Phase 2 inspection, which we 19 performed on both units in July 2011, is our one-time 20 major team inspection during which the inspectors 21 assess the adequacy and effectiveness of the 22 implementation and/or completion of the programs and 23 activities described in regulatory commitments, the 24 UFSAR supplement program descriptions, time-limited 25 aging analyses, or TLAAs, and license conditions.
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122 1 During the Phase 2 inspection, the 2 inspectors also evaluate the need for additional 3 follow-up inspections.
4 So no findings of significance were 5 identified as a result of this inspection. However, 6 the inspectors identified eight observations that were 7 subject to a follow-up inspection in accordance with 8 the IP, inspection procedure.
9 MR. SCHULTZ: Steven --
10 MR. DOWNEY: Yes.
11 MR. SCHULTZ: -- when you say a team 12 inspection, what does that entail? How many --
13 MR. DOWNEY: So we --
14 MR. SCHULTZ: How many inspectors are 15 incorporated?
16 MR. DOWNEY: For a Phase 2, we typically, 17 six inspectors. We typically send our whole branch 18 for a team inspection.
19 MR. SCHULTZ: Different areas of 20 expertise.
21 MR. DOWNEY: Yes. And --
22 (Simultaneous speaking.)
23 MR. DOWNEY: So, for Surry, and this 24 inspection happened back in 2011. So Surry has 30 25 license renewal commitments that can be bent into NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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123 1 enhancements to aging management programs for license 2 renewal, newly implemented programs, and stand-alone 3 commitments that can be anything from following 4 industry guidance to doing certain inspections.
5 And we just divide, we divide those 6 amongst the team and --
7 MR. SCHULTZ: Do any of the observations 8 that --
9 MR. DOWNEY: Yes.
10 MR. SCHULTZ: This is the one that has 11 eight observations. Do any of them come to mind as 12 something you'd share as an example observation?
13 MR. DOWNEY: So I have all of them. And 14 typically observations are those items that -- well, 15 first I'll say the Phase 2 inspection typically occurs 16 prior to entering the period of extended operation.
17 As we discussed a little bit earlier, when 18 the licensee commits to activities, they may commit 19 to, that this activity is completed prior to entering 20 that period.
21 So, during the Phase 2 inspection, let's 22 say we identify that some one-time inspections under 23 the buried piping program were not completed at the 24 time of the inspection. That rose to the level of an 25 observation, which we come back and follow up to NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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124 1 verify technically acceptable completion. And that 2 inspection for us happened in 2012.
3 So all of the observations have that 4 flavor to them. And I can give some details on each 5 one if you'd like.
6 MR. SCHULTZ: No, that's fine.
7 MR. DOWNEY: Okay.
8 MR. SCHULTZ: I just wanted to get a 9 flavor of what they look like and --
10 MR. DOWNEY: Okay.
11 MR. SCHULTZ: -- what you were looking to 12 do as you move forward in the different phases. Thank 13 you.
14 MR. DOWNEY: Yeah. So the Phase 3 15 inspection, which is our follow-up inspection, was 16 performed at Surry in June 2012.
17 At the conclusion of that inspection, the 18 inspectors identified one minor violation of 10 CFR 19 Part 50, Appendix B, Criterion XVI, Corrective Action.
20 Otherwise, no findings of significance 21 were identified. And the inspection team concluded 22 that the licensee had completed all necessary actions 23 to meet its license renewal commitments.
24 If you're interested in hearing more about 25 the minor, I have the description of that here as NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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125 1 well. Otherwise, I will proceed.
2 MR. SCHULTZ: Does it bear on the things 3 that we have discussed today related to SLR?
4 MR. DOWNEY: Let's see. Not, it's -- so 5 it was for inadequate corrective action related to a 6 leak in the Unit 2 neutron shield tank.
7 MR. SCHULTZ: Thank you.
8 MR. DOWNEY: So, finally, the Phase 4 9 inspection, which typically occurs five to ten years 10 into the period of extended operation, was performed 11 at both, for both units at Surry in August 2019.
12 This, the Phase 4 inspection is intended 13 to verify that the licensee is managing aging effects 14 in accordance with the aging management programs 15 described in the UFSAR.
16 No findings were identified as a result of 17 this inspection. But I'll take a bit of time to 18 explain what we looked at and our approach. Next 19 slide, please.
20 For the initial license renewal period, 21 the Surry UFSAR identifies 22 programs and activities 22 credited for managing the effects of aging. Three of 23 those were new aging management programs. And 19 were 24 previously existing aging management programs.
25 For the Phase 4 inspection, the nine aging NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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126 1 management programs shown here on the slide were 2 selected for review using the criteria provided in 3 Inspection Procedure 71003.
4 And for each program we selected, the 5 inspectors reviewed the licensee's implementation of 6 that program by selecting a sample of structures, 7 systems, and components within the scope of the 8 respective program and verifying that the aging of the 9 selected items, I'm sorry, were being adequately 10 managed.
11 To make that determination -- sure. Yes.
12 MEMBER KIRCHNER: Of that same, of the 13 list that you have there, how did you -- I'm sorry.
14 I thought I pushed it. Of the list, how did you come 15 about picking those, for example, tank --
16 MR. DOWNEY: Sure.
17 MEMBER KIRCHNER: -- inspection, because 18 back in 2012 you had a corrective action observation, 19 et cetera? So --
20 MR. DOWNEY: So corrective actions is one 21 component. And in Section 0302 of the IP, it gives a 22 list of inspection sample attributes. But I like to 23 use examples. So I'll use one here.
24 MEMBER KIRCHNER: Yeah.
25 MR. DOWNEY: So you're starting with 22 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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127 1 programs. And we'll say, okay, here are these 2 programs that are long-existing and mature programs.
3 So we'll cut off like in-service inspections, steam 4 generator integrity. We'll cut off some of those.
5 MEMBER KIRCHNER: Right.
6 MR. DOWNEY: Then we'll say here, what 7 subset of those programs have been subject to previous 8 baseline inspections or previous license renewal 9 inspections.
10 MEMBER KIRCHNER: Right.
11 MR. DOWNEY: Then we'll do those. Then 12 we'll look at operating, recent operating experience, 13 corrective actions associated with managing aging.
14 And that will help us pick select samples.
15 The tank inspection program was selected 16 because of some corrective actions.
17 MEMBER KIRCHNER: Right.
18 MR. DOWNEY: And in addition to that, we 19 take input from our resident inspectors, as well as we 20 took input from our counterparts in NRR to provide 21 insights to selecting a sample for this inspection.
22 MEMBER KIRCHNER: And just one further 23 question, the timing. So this was about seven years 24 into the first extended period of operation.
25 MR. DOWNEY: Yes.
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128 1 MEMBER KIRCHNER: So is there any, in your 2 Inspection Procedure 71003 and the GALL and other 3 things that you use as points of reference, is there 4 any mandatory time to do that inspection, or that was 5 just decided this is, it's time to do it, seven years 6 into the extended period --
7 MR. DOWNEY: Just we --
8 MEMBER KIRCHNER: -- of operation?
9 MR. DOWNEY: In that window of five to 10 ten.
11 MEMBER KIRCHNER: Okay.
12 MR. DOWNEY: Any other questions?
13 MEMBER KIRCHNER: So the interval for 14 Phase 4 inspection would be at least five years?
15 MR. DOWNEY: Into, yes, into the period --
16 MEMBER KIRCHNER: Okay.
17 MR. DOWNEY: -- of extended operation, 18 yes.
19 MEMBER KIRCHNER: Thank you.
20 MR. DOWNEY: So to, I was discussed the 21 SSCs within the scope of their respective aging 22 management programs and verifying that the aging of 23 those items were being adequately managed.
24 And to make that determination, the 25 inspectors performed the following activities as NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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129 1 applicable to the items in their respective samples.
2 So we walked down all accessible 3 structures, systems, and components to observe their 4 general condition and identify any signs of aging-5 related degradation.
6 We interviewed plant personnel, reviewed 7 completed work orders to verify that aging management 8 activities were being performed in accordance with 9 plant procedures and at the intervals prescribed in 10 their respective programs.
11 We reviewed applicable monitoring and 12 trending data and reviewed the acceptability of 13 inspection and test results.
14 Also, for all programs here, the 15 inspectors reviewed a sample of aging-related issues 16 entered into the licensee's corrective action program 17 to verify that aging-related degradation is being 18 identified at an appropriate threshold.
19 Based on our inspection, no findings of 20 significance were identified. And this inspection 21 result provided us with a reasonable assurance that 22 the licensee was appropriately implementing the 23 selected aging management programs.
24 Now, while on site for the Phase 4 25 inspection, the inspection team also assisted the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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130 1 resident inspectors with the review of two current 2 aging management issues, one related to the failure of 3 reactor protection system relays and the other related 4 to the degradation and failure of the fire protection 5 system piping.
6 As we know now, pertinent details of the 7 fire protection system issue were not available to the 8 inspectors at the time of, until sometime after our 9 Phase 4 inspection. So I have a later slide prepared 10 to discuss that issue, the timeline, and the path 11 forward for the region in more detail. Next slide, 12 please.
13 MEMBER KIRCHNER: Can you elaborate on the 14 other one that you looked at, the -- and I want to 15 note for the record that Member Charles Brown has 16 joined us. The, on the reactor protection trip 17 relays.
18 MR. DOWNEY: Yes. And I should have 19 mentioned that I have some talking points on that --
20 MEMBER KIRCHNER: Okay.
21 MR. DOWNEY: -- on the next slide as well.
22 MEMBER KIRCHNER: All right. I'll wait 23 for it, then.
24 MR. DOWNEY: I'm sorry, on slide 20, not 25 this slide. I'm sorry. Yep.
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131 1 So, in addition to the inspections 2 mandated by the license renewal inspection program, 3 the inspectors have several baseline inspections that 4 can be used to evaluate the implementation of aging 5 management activities.
6 For example, the baseline ISI inspection, 7 ISI meaning in-service inspection, which is performed 8 in accordance with Inspection Procedure 71111.08 at 9 every outage, gives the inspectors the opportunity to 10 take a look at activities credited for managing aging 11 that are within the scope of seven different Surry 12 programs.
13 Another example is the heat sink 14 inspection, which gives the inspectors an opportunity 15 to look at the service water system, including heat 16 exchangers, the service water intake structure, and 17 both above-ground and buried or inaccessible piping 18 and components, all of which are within the scope of 19 license renewal.
20 Next is the design basis assurance, or 21 DBAI, inspection, which procedure, that inspection 22 procedure directs the inspectors to ensure that SSCs 23 selected in the inspection sample that are subject to 24 aging management review are being managed in 25 accordance with the appropriate aging management NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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132 1 programs.
2 At Surry, the inspectors have found no 3 violations or findings of significance as a result of 4 the inspections performed using these procedures.
5 I'll also note here that similar 6 instructions to those provided in the DBAI procedure 7 have been recently added to the tri-annual fire 8 protection procedure. I didn't list that procedure 9 here on this list because the most recent fire 10 protection inspection was performed prior to that 11 procedure update.
12 Additionally, the resident inspectors at 13 Surry have performed maintenance effectiveness and 14 PI&R, problem identification and resolution, 15 inspections on samples that focus directly or 16 indirectly on associated aging management programs.
17 These inspections resulted in two 18 violations of very low safety significance, which you 19 will hear me call green. And we'll focus, discuss 20 more in detail on the next slide.
21 Also, we are planning to perform the 22 focused PI&R inspection related to the recent fire 23 protection system issue that I will be discussing on 24 the slide next after next. Next slide, please.
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133 1 condition of Surry from the resident inspector 2 viewpoint.
3 Currently, Surry Units 1 and 2 are in the 4 licensee response column and have all green findings 5 and performance indicators. This indicates that the 6 licensee has been able to effectively identify 7 conditions adverse to quality and correct them in a 8 timely manner.
9 We did want to highlight the output of 10 some inspection results that related to the material 11 condition of the plant.
12 As mentioned, no findings were identified 13 as a, during the license renewal program inspections, 14 which indicates that the licensee has established 15 adequate programs to manage the effects of aging.
16 So, first, in 2016 the NRC issued a self-17 revealing green, non-cited violation of 10 CFR Part 18 50, Appendix B, Criterion XVI, which is corrective 19 action, for failure to promptly identify a condition 20 adverse to quality associated with the material 21 condition of the graded supports in the emergency 22 service water pump house.
23 The issue was self-revealing because 24 fasteners on one base plate for the service water pump 25 diesel cooling water outlet valve seismic supports NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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134 1 were found to be severed by corrosion. The failure of 2 the seismic support led to the Bravo service water 3 pump being declared inoperable, which made the 4 violation more than minor. The degradation mechanism 5 was wetting of the supports and base plates, I'm 6 sorry, where the brackets wore.
7 Both the licensee and the residents also 8 noted many more areas of the plant that had corroded 9 supports which needed to be remediated to provide 10 long-term reliability and seismic protection.
11 Over the course of several years, Surry 12 has proactively remediated the supports by either 13 coating or replacing with stainless steel.
14 Next, in 2018, following multiple relay 15 failures, the NRC issued an NRC-identified green, non-16 cited violations of Surry technical specification 6.4 17 Delta, which is administrative controls over unit 18 operating procedures, for failure to follow, I'm 19 sorry, Surry's preventative maintenance procedure.
20 Specifically, many of the under-voltage 21 and degraded voltage relays in the plant were past 22 their service life of 20 years per the EPRI 23 guidelines. Independent lab testing indicated that 24 prolonged thermal damage was the cause of the failure.
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135 1 and is scheduled to complete replacement by 2022.
2 MEMBER BROWN: What do they mean by 3 thermal damage?
4 MR. McKOWN: So many of these relays are 5 normally energized. So, in addition to their normal 6 service life --
7 MEMBER BROWN: Those are, these are 8 reactor trip? These are trip relays?
9 MR. McKOWN: Some of them are, yes.
10 MEMBER BROWN: But when they fail, they 11 trip and give you a channel trip, if that's the case 12 --
13 MR. McKOWN: They could give an individual 14 channel trip.
15 MEMBER BROWN: And there's a 20-year life 16 on those supposedly by guidelines?
17 MR. McKOWN: By guidelines, yeah.
18 MEMBER BROWN: What about thermal? Had 19 they failed testing of any kind, or was it just based 20 on a physical inspection?
21 MR. McKOWN: Some of them were based on 22 physical inspection, identified embrittlement as the 23 technician --
24 MEMBER BROWN: Like insulation of the --
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136 1 visually identify --
2 MEMBER BROWN: Insulation around the coil 3 embrittlement?
4 MR. McKOWN: Yeah, they can identify 5 visual degradation, or they will be identified during 6 testing. And we've observed the plant being able to 7 replace those on an individual basis and online. But 8 more larger scale remediations are being performed 9 during outages.
10 MEMBER BROWN: I was just surprised at the 11 20-year issue. In my past program, I had some of 12 those trip relays normally energized. They lasted for 13 40 years, and we never had a problem with them, so a 14 couple of projects. So, and just a --
15 MR. McKOWN: Yeah.
16 MEMBER BROWN: Just a point of 17 information. That's why I asked. Thank you.
18 MR. DOWNEY: Thank you. So this issue is 19 very similar to an issue identified back in 2010 when 20 the relays in the reactor protection system, the 21 safety injection system, and the consequence limiting 22 safeguard system were identified as beyond their 23 service life.
24 To address that issue, Surry has 25 prioritized and scheduled relay replacements during NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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137 1 every refueling outage since 2013 and continues to 2 replace relays upon failure or as part of their 3 prioritized replacement schedule.
4 MEMBER BROWN: You really don't mean upon 5 failure. You mean not meeting the requirement. Are 6 the relays failing, or are they just not meeting the 7 20-year requirement?
8 MR. DOWNEY: Some are failing, correct?
9 MR. McKOWN: When identified by failure, 10 like when we were talking about online replacements 11 during testing or a degraded condition as identified 12 --
13 MEMBER BROWN: So, if they don't trip when 14 asked to.
15 MR. McKOWN: Right, during testing, in 16 addition to the lifecycle management plan of replacing 17 the large scale --
18 MEMBER BROWN: Okay.
19 MR. McKOWN: -- lot during outages.
20 MEMBER BROWN: Okay. Based on lifetime 21 expectations.
22 MR. McKOWN: Based on lifetime.
23 MEMBER BROWN: Okay. Thank you.
24 MR. McKOWN: So as required by maintenance 25 or as required by --
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138 1 MEMBER BROWN: I got it.
2 MR. McKOWN: -- lifecycle.
3 MR. DOWNEY: Okay. So the highest 4 priority relays, which number approximately 570, will 5 be completed in the next two years. And the licensee 6 plans to replace an estimated 80 relays per refueling 7 outage.
8 The residents note that the licensee is 9 managing the relay replacement schedules and has 10 demonstrated the ability to replace failed relays 11 online and has not challenged any maintenance rule 12 Alpha 1 goals, maintenance rule being 10 CFR 50.65.
13 MEMBER BROWN: I take it they're going to 14 replace 80, but I presume the remaining ones are still 15 operational even though they may pass the 20-year 16 lifetime or --
17 MR. McKOWN: Yes.
18 MEMBER BROWN: -- the thermal doesn't 19 appear to have -- I mean, it's anything that breaks or 20 doesn't operate gets replaced immediately I would --
21 MR. McKOWN: They get replaced upon 22 identification. And then --
23 MEMBER BROWN: Okay. Thank you. That's 24 all, that's -- you answered my --
25 MR. McKOWN: Yes.
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139 1 MEMBER BROWN: Just the way phrased it, I 2 wanted to make sure I understood what was going on.
3 MR. McKOWN: Yep.
4 MR. DOWNEY: So, if there are no other 5 questions, finally, we'll get to the July 2019 rupture 6 of a section of the Surry fire protection loop. This 7 issue is currently ongoing. And I'll provide more 8 details on the next slide. Next slide, please.
9 So the Surry fire protection loop is made 10 of cast iron piping and is buried approximately six 11 feet below grade throughout the site. In July 2019, 12 two fire protection piping failures occurred at the 13 west end of the old administration building and below 14 the road leading to the turbine building track bay.
15 The first rupture was a ten-foot long 16 longitudinal crack along the bottom surface of the 17 pipe. And the second failure was due to a 18 circumferential crack on an adjacent pipe section.
19 I'll note that the Phase 4 inspection 20 occurred in August 2019. And at that time, the 21 licensee was in the process of excavating the area in 22 order to replace the affected piping.
23 Also at that time, several CRs, condition 24 reports, had been written. But the root cause and 25 extent of condition of the issue had yet to be NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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140 1 determined.
2 Subsequently, the licensee determined that 3 longstanding exposure to moist or wet soil had 4 resulted in the reduction in the wall thickness at 5 several locations due to graphitic corrosion.
6 To determine which areas of the fire 7 protection loop had been exposed to groundwater, the 8 licensee dug several initial exploratory holes 9 approximately 300 feet apart and found that the water 10 level in some of the holes was much higher than the 11 elevation of the buried piping.
12 The findings indicate that there is a 13 higher potential for additional sections of buried 14 piping to be degraded. But until additional areas can 15 be explored, the soil characteristics and condition of 16 the piping cannot be determined.
17 On October 18, 2019, the entire fire 18 protection loop was declared non-functional because 19 the licensee's evaluation could not determine that the 20 loop had reasonable assurance of safety.
21 With no fire suppression system 22 functional, the Surry technical requirements manual 23 requires that a backup suppression system be 24 established within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
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141 1 within that timeframe, which include, as the licensee 2 had previously described, the use of backup fire pumps 3 and hoses connected to the hydrants in the current 4 system.
5 In an October 31st letter response to NRC 6 comments on Dominion's annual subsequent license 7 renewal update letter, the licensee committed to drill 8 a minimum of 25 exploratory holes along the piping to 9 determine if additional corrective actions are 10 necessary, including excavation and evaluation of any 11 piping in the presence of groundwater.
12 The letter states in part that this 13 activity will be performed once prior to the 14 subsequent period of extended operation and during 15 each ten-year inspection interval in the subsequent 16 period of extended operation to identify suspected 17 system leakage and elevated groundwater.
18 Compensatory measures are still in place 19 at the site. And the current path forward for the 20 region is to perform a focused PI&R inspection. The 21 inspection will focus on reviewing the licensee's 22 corrective actions, including if and how this recent 23 operating experience will be incorporated into the 24 Surry buried piping program.
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142 1 our counterparts in the Office of Nuclear Reactor 2 Regulation to ensure that the latest information from 3 the site is available to them for their consideration 4 in the subsequent license renewal application review.
5 Next slide, please.
6 So, overall, for a plant that is in its 7 first or initial period of extended operation, the 8 material condition is generally acceptable.
9 As mentioned earlier, the licensee has 10 been successful at completing large capital 11 improvement projects that maintain or improve the 12 material condition of its structures, systems, and 13 components.
14 Furthermore, all NRC performance 15 indicators are green. And having no greater-than-16 green inspection findings indicate that the material 17 condition of SSCs has been maintained to sustain 18 adequate protection.
19 Finally, the license renewal program 20 inspections did not identify any substantial 21 weaknesses in the station's performance in managing 22 the effects of aging at the site.
23 The resident inspectors continue to 24 inspect and assess the licensee's ability to manage 25 the effects of aging through our baseline inspection NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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143 1 program.
2 So, if there are no further questions, 3 I'll yield the floor back to Angela Wu to conclude the 4 presentation.
5 MEMBER RICCARDELLA: I have a couple of 6 questions.
7 MR. DOWNEY: Sure.
8 MEMBER RICCARDELLA: The first would be, 9 Steven, so we had in your summary table on your 10 inspections for Phases 1 through 4 no findings and 11 just eight observations in that Phase 2.
12 Could you calibrate us? And for the 13 record, how does that compare to other plants, without 14 naming other plants? Is this typical or is this 15 exemplary or is it average? You used the word 16 acceptable.
17 MR. DOWNEY: Generally acceptable, the 18 most objective term that I could think of --
19 MEMBER RICCARDELLA: Yes, so, okay. I 20 understand the guarded word. But can you just 21 calibrate us versus other plants where you've done 22 these kinds of inspections --
23 MR. DOWNEY: So --
24 MEMBER RICCARDELLA: -- as an Agency?
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144 1 don't have a lot of, a lot of the aging management 2 issues tend to not reach the level of being determined 3 as more than minor, meaning significant, you know, if 4 left uncorrected would lead to a significant safety 5 issue --
6 MEMBER RICCARDELLA: Right.
7 MR. DOWNEY: -- precursor to a significant 8 event, et cetera.
9 So you'll see at a high level that 10 typically this is in line with what we see in terms of 11 no findings of significance, because that's what 12 determines getting to the area of significance being 13 more than minor.
14 Observations are, I can't really attest to 15 in number. But we typically have observations during 16 these inspections. We haven't any, none that I have 17 seen have had any findings of significance, more than 18 maybe one or two.
19 MEMBER BROWN: Do these become 20 suggestions? Does the plant ever do anything with the 21 observations which are not --
22 MR. DOWNEY: So --
23 MEMBER BROWN: They're not requirements to 24 do something. They're just --
25 MR. DOWNEY: So that's --
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145 1 MEMBER BROWN: We saw this, whatever, 2 right?
3 MR. DOWNEY: So that's, that falls into 4 the timing of the inspection. So, for the Phase 2, 5 these, they're observations because if we were, if 6 this inspection had occurred during the period of 7 extended operation, they would have been in violation 8 of their license condition.
9 So that's why we come back during the PEO 10 and do that follow up to make sure that they have 11 corrected those issues prior to when that requirement 12 kind of comes in force for us.
13 MEMBER BROWN: Thank you.
14 MR. DOWNEY: If that makes sense, yeah.
15 MEMBER KIRCHNER: My other question was I 16 was thinking, you know, a lot of what you cover is 17 also covered by the Boiler and Pressure Vessel Code, 18 you know, Section 11.
19 So do you leave it to the applicant in 20 general to fold that into their AMP programs, or do 21 those things because they're code cases or governed by 22 the code, I didn't say that correctly, those are 23 independent of your AMP programs?
24 I mean, is there -- do you kind of bring 25 them together when Section 11 would require an NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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146 1 inspection of the steam generator or whatever?
2 MR. DOWNEY: So, typically, your 3 longstanding programs like ISI, for example --
4 MEMBER KIRCHNER: Yeah, that's what I was 5 thinking.
6 MR. DOWNEY: -- also aging management 7 programs --
8 MEMBER KIRCHNER: I was thinking of your 9 chart of ISI in particular.
10 MR. DOWNEY: Yeah, also aging management 11 programs. But what I've seen is, for example, if a 12 licensee augments their program, like there was some 13 discussion earlier about small bore piping, that those 14 would typically be outside of the scope of ASME 15 Section 11. But it would be as an augment to their 16 ASME Section 11 program. So it all does fold 17 together.
18 MEMBER KIRCHNER: All right. Thank you.
19 MR. SCHULTZ: Steven, the --
20 MR. DOWNEY: Yes.
21 MR. SCHULTZ: The inspection that's 22 related to, that's upcoming on the buried piping 23 program and the corrective actions that have come from 24 that, could you expand on what you see as the scope of 25 that inspection?
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147 1 MR. DOWNEY: So that --
2 MR. SCHULTZ: Late February, it's coming 3 up. And what will it entail in terms of inspection 4 personnel --
5 MR. DOWNEY: So I'll --
6 MR. SCHULTZ: -- duration? What, is there 7 a plan for it yet or is that --
8 MR. DOWNEY: Yes. So I'll be on site the 9 week of February 24th, myself in support of the 10 residents, to perform this focused PI&R sample.
11 One week is what the length of the 12 inspection will be. And the scope will be as typical 13 for inspections performed under Inspection Procedure 14 71152, which is our problem identification and 15 resolution inspection.
16 So just a deep dive into making sure that 17 we understand the issue and understand the licensee's 18 corrective action related to the issue and how it ties 19 to their different programmatic requirements that they 20 have in place at the site.
21 MR. SCHULTZ: I'm expecting that 22 corrective action has many tentacles depending on how 23 you define those. But --
24 MR. DOWNEY: It does.
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148 1 interwoven with all of the, many of the activities in 2 this particular area --
3 MR. DOWNEY: Yeah.
4 MR. SCHULTZ: -- technical area that took 5 place.
6 MR. DOWNEY: Yeah, so one thing --
7 MR. SCHULTZ: September, October, 8 November, December, and right on up to the draft SCR.
9 So are you going to be looking at that --
10 MR. DOWNEY: So that --
11 MR. SCHULTZ: -- as well?
12 MR. DOWNEY: And we've been in 13 communication with our counterparts at NRR in that the 14 portion of this that involves updates to programs 15 proposed for subsequent license renewal is beyond our 16 scope in the region to look at.
17 We are dealing with oversight on the plant 18 during the initial period of extended operation. And 19 --
20 MR. SCHULTZ: Right.
21 MR. DOWNEY: -- the programs that they are 22 -- like even the programs are different that they are 23 proposing versus what's on the site right now. So 24 there's a, there's pieces that we can handle --
25 MR. SCHULTZ: Yeah.
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149 1 MR. DOWNEY: -- and pieces that are 2 handled by --
3 MR. SCHULTZ: But there's not a direct --
4 I overstated the connection between what was done in 5 preparing the draft SCR and so forth.
6 At the same time, one would expect that 7 that corrective action does, in fact, identify all 8 those types of things that we've been talking about 9 here in terms of things that they would have 10 determined, should have determined, would be done, 11 should be done in order to correct the problem as well 12 as identify --
13 MR. DOWNEY: Agreed.
14 MR. SCHULTZ: -- programs to assure that 15 similar events don't happen again. Thank you. I just 16 -- it looks like you're getting to close here. But 17 just to follow up on my comments about the activities 18 in the August --
19 MR. DOWNEY: Yes.
20 MR. SCHULTZ: -- August through the 21 January timeframe, and this refers really to the 22 program that was developed in the aging for the 23 reviews.
24 MR. DOWNEY: Yeah. So are --
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150 1 mentioned the quality of the staff review associated 2 with it.
3 The other area that is remarkable is the 4 interactions that has gone on between the staff and 5 the licensee associated with the request for 6 additional information and the responses.
7 In reviewing what has been done, it is 8 certainly remarkable that the quality, content, and 9 thoroughness of the request for additional information 10 and the responses from the licensee has been of very 11 high quality and a lot of information that's been 12 exchanged and a lot of changes that have come from the 13 requests from the staff on, for additional information 14 and for clarification and development of the final 15 safety evaluation. So I appreciate that.
16 MEMBER KIRCHNER: Angela, do we go back to 17 you to conclude?
18 MS. WU: Thank you, Steven. In 19 conclusion, for the Surry SLRA safety review, the 20 staff finds that the requirements of 10 CFR 54.29(a) 21 have been met for the subsequent license renewal of 22 Surry Power Station Units 1 and 2.
23 At this time, you will hear from two 24 members of the NRC staff on differing views, starting 25 with Brian Allik, Materials Engineer, Division of New NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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151 1 and Renewed Licenses, and then James Gavula, 2 Mechanical Engineer, Division of New and Renewed 3 Licenses. So, first, with Brian and then we'll give 4 him some room, yeah. Thank you.
5 (Off mic comments.)
6 MR. ALLIK: Okay. So my name is Brian 7 Allik. And I'm a materials engineer in the Division 8 of New and Renewed Licenses. And I'll go through my 9 differing view related to the SCR for Surry's 10 subsequent license renewal application.
11 In response to the fire water system 12 ruptures discussed previously, the applicant modified 13 a selective leaching program to include a requirement 14 to dig exploratory holes to confirm the presence of 15 groundwater around buried fire water system piping.
16 The applicant is, therefore, relying on a 17 singular criterion, in other words, the presence of 18 groundwater, to detect adverse soil conditions that 19 may lead to graphitic corrosion.
20 From my perspective, it is unclear why 21 relying on a singular criterion is technically 22 adequate. In addition to the presence of standing 23 water, it is well established that several soil 24 parameters, including soil resistivity and pH play an 25 important role in the corrosion of cast iron in soil NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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152 1 environments.
2 A few literature examples supporting this 3 statement are provided on this slide for reference.
4 Next slide, please.
5 In addition, by a letter dated October 31, 6 2019, the applicant provided a summary of the soil 7 analysis in the vicinity of the ruptured piping. The 8 soil analysis documents low pH and low soil 9 resistivity in one of the two samples, which would 10 indicate that soil parameters other than standing 11 water may have contributed to the ruptures.
12 During a call with the applicant on 13 November 7, 2019, I questioned why relying on a 14 singular criterion is technically adequate. However, 15 the NRC subsequently determined that no action was 16 required on behalf of the applicant to address this 17 concern.
18 I, therefore, elected to engage in a 19 formal process for differing views because the concern 20 I described during the November 7th call was not 21 addressed.
22 In conclusion, without a basis for relying 23 on a singular criterion, or a specific commitment to 24 conduct soil corrosivity testing in the vicinity of 25 buried gray cast iron fire water system piping if a NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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153 1 basis cannot be provided, it is unclear how the NRC 2 staff can conclude that the applicant has demonstrated 3 that the effects of aging will be adequately managed 4 so that the intended functions will be maintained 5 consistent with the current licensing basis for the 6 subsequent period of extended operation as required by 7 10 CFR Part 54.21(a)(3).
8 I will now turn the presentation over to 9 Jim Gavula.
10 MEMBER KIRCHNER: Brian, maybe stop and --
11 MR. ALLIK: Sure.
12 MEMBER KIRCHNER: -- just ask you -- thank 13 you, first of all. Member Ballinger I think was the 14 first to ask along the lines of when they do their 15 test holes, that they would also be looking at other 16 parameters. So I just wanted to understand --
17 MR. ALLIK: That's if they find standing 18 water in the exploratory hole. And then if they find 19 water in the hole, that would drive them through 20 excavations and soil sampling.
21 MEMBER KIRCHNER: Yes. But my 22 understanding, the commitment to do the 25 additional 23 test holes, do you not feel that that would give 24 enough coverage of the site to look for problems, not 25 just standing water, but if they also do the soil NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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154 1 sampling for pH and sulfides, those things that are on 2 your list.
3 MR. ALLIK: That testing is --
4 MEMBER KIRCHNER: Would that be adequate 5 to address the concern that you've put before us?
6 MR. ALLIK: That testing is if there's 7 water in the hole to look at that water. So, 8 basically if they don't find standing water in the 9 hole, then they're not driven to do any type of soil 10 testing. So my contention is basically it's just 11 relying on --
12 MEMBER KIRCHNER: Right.
13 MR. ALLIK: -- the concept of standing, 14 or, you know, the presence of standing water.
15 Whereas, I feel having a specific commitment to do 16 soil testing, in addition to those, would be more 17 appropriate.
18 MEMBER KIRCHNER: Well, perhaps, it's just 19 one member. Perhaps I misunderstood the 20 presentations. I had the impression once they dig 21 these 25 test holes that they would go through and 22 actually do the sampling.
23 So your contention, if I understand it 24 correctly, is only if they find water will they then 25 go and look at these other --
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155 1 MR. ALLIK: That's my understanding.
2 MEMBER KIRCHNER: -- parameters. Okay.
3 MEMBER RICCARDELLA: Could maybe somebody 4 clarify that, please?
5 MEMBER KIRCHNER: Can we clarify that?
6 Well, maybe this isn't the place to do it. But, 7 anyway, but, okay, Brian. That was perhaps my 8 misunderstanding from the presentations. But I 9 assumed once you dig a hole --
10 (Simultaneous speaking.)
11 MEMBER RICCARDELLA: Either they're going 12 to do the soil sampling or they're not. And the 13 contention is that if there's no standing water 14 they're not going to do any soil testing.
15 It would seem that the licensee could 16 clarify that. Are they going to do soil testing or 17 not?
18 MR. MOORE: It's fair to ask the staff to 19 have the licensee clarify it, or if the licensee is 20 here, they can clarify it.
21 MEMBER KIRCHNER: All right. I'm just 22 sharing my, perhaps, misunderstanding of what was 23 presented earlier.
24 MR. MOORE: I think somebody was going to 25 stand up.
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156 1 MEMBER KIRCHNER: Okay. If we could 2 proceed to James.
3 CHAIR SUNSERI: I think somebody wants to 4 --
5 MEMBER KIRCHNER: Yeah, okay. Someone --
6 MEMBER BROWN: If somebody's got an 7 answer, we ought to hear it.
8 MR. MOORE: Yeah, right.
9 MR. SCARBOROUGH: Good morning. Troy 10 Scarborough, Surry Power Station.
11 So, when we do excavations, we do take a 12 soil sample. As Brian mentioned, you know, when we 13 excavate this fire protection piping based on our 14 initial look for water present, we will do a soil 15 sample at, you know, at that time.
16 MEMBER BROWN: But whether there's water 17 present or not? Or will you only do the soil sample 18 if there's water present?
19 MR. SCARBOROUGH: If there's water 20 present, that's when we'll take the sample.
21 MEMBER BROWN: So, if you dig the hole and 22 it's dry, there's no soil sample. I want to put this 23 in straightforward language.
24 MR. SCARBOROUGH: Well, if we dig a hole, 25 we will take a soil sample.
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157 1 MEMBER BROWN: So you take it regardless, 2 but whether you test it or not --
3 MEMBER KIRCHNER: That was my impression, 4 yeah.
5 MEMBER BROWN: But whether you test it or 6 not is dependent upon whether there was groundwater in 7 the hole. Is that --
8 MR. SCARBOROUGH: No, we'll --
9 MEMBER BROWN: Would that be corollary to 10 that?
11 MR. SCARBOROUGH: We'll send every soil 12 sample out for testing.
13 MEMBER BROWN: Okay. Let me restate this 14 again, because I'm now lost. You dig a hole. No 15 water. However far down you have to dig it, if 16 there's no water, do you take a soil sample? You said 17 yes.
18 MR. SCARBOROUGH: Not on an exploratory 19 hole. But --
20 MEMBER BROWN: Okay. So, if there's no 21 water in it, you don't take a soil sample.
22 MR. SCARBOROUGH: That's correct. We --
23 MEMBER BROWN: Okay. I think that's what 24 you were --
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158 1 there's -- exploratory hole is different from 2 excavation. But your understanding is my 3 understanding, that if it's a dry hole --
4 MEMBER BROWN: Well, the way I read and 5 the way -- I was late. So I -- but I did catch the 6 inspector's discussion of the issue. And I guess the 7 25 holes, those were just exploratory holes but not 8 excavations. That's my understanding of the way that 9 the words went.
10 MR. ALLIK: That's correct.
11 MEMBER BROWN: And so that's all that 12 would be done, period, no excavations of any kind. It 13 would be just the holes, no water, no sample. If 14 there's water, you take sample. If you get a sample, 15 you test it.
16 MR. ALLIK: Right.
17 MEMBER BROWN: Okay. That's my 18 understanding.
19 I had one other question, because I'm not 20 a big fire person. I'm an electrical. So these, the 21 fire systems are tested periodically also I presume.
22 And I missed probably some earlier discussion of that.
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159 1 not every ten years, of the fire system to ensure you 2 really get water --
3 MR. ALLIK: Um-hmm, yes.
4 MEMBER BROWN: -- in a volume suitable 5 enough to deal with whatever the requirements are.
6 And so --
7 MR. ALLIK: I would just say it's a 8 brittle material, though. And especially once it's 9 undergone graphitic corrosion, it's very susceptible 10 to more than just a leak type failure --
11 MEMBER BROWN: Well, I understand that.
12 And that's why I'm trying to clarify. I'm not a soil 13 mechanics guy. But once you have a --
14 MEMBER RICCARDELLA: But the failures that 15 did occur were leak type failures, right, not 16 ruptures?
17 MR. ALLIK: They were ruptures.
18 MEMBER RICCARDELLA: The licensee said 19 that they could have maintained pressure in the system 20 and delivered fire water. That's --
21 MR. GAVULA: 4,500 gpm leak.
22 MEMBER RICCARDELLA: Pardon me?
23 MR. GAVULA: It was a 4,500 gpm leak was 24 the documentation I read from the licensee. So the 25 overall capacity of the fire water system is 5,000 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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160 1 gpm. At that point, you're going to be at run-out on 2 the pumps. It's all going out the hole.
3 MEMBER RICCARDELLA: Okay.
4 MEMBER BROWN: My last question was, is 5 there any other functional testing that -- how often 6 are the fire systems tested, or did that come out in 7 the other discussions? I mean, is it annually or is 8 it every six months or is it every five years or what?
9 Does anybody got an answer to that for capacity tests?
10 CHAIR SUNSERI: The leak was determined 11 during a fire suppression surveillance test which --
12 MEMBER BROWN: Yeah, my point is how often 13 are those done.
14 CHAIR SUNSERI: I think the applicant can 15 answer that.
16 MR. HARROW: This is Allen Harrow. So we 17 do fire protection surveillance tests monthly.
18 MEMBER BROWN: Monthly? Okay.
19 CHAIR SUNSERI: Yeah.
20 MR. GAVULA: But that's just start the 21 pump, make sure it runs, if there is no flow, 22 verification at that point, because don't have a 23 demand on the system.
24 MEMBER BROWN: So there's no capacity 25 testing done at all ever?
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161 1 MR. GAVULA: There may be some flow test 2 during the outages is my understanding if --
3 MEMBER BROWN: Can the licensee address 4 that? That was the question I was really answering.
5 I mean, obviously, if they test it with no, just to 6 see if the pump runs, that doesn't --
7 MEMBER RICCARDELLA: Well, unless it 8 pressurizes the system.
9 MEMBER BROWN: Well, if it pressurizes the 10 system, then that should indicate there's no leaks, 11 right?
12 MEMBER RICCARDELLA: Well, yeah.
13 MEMBER BROWN: Or no significant leaks.
14 CHAIR SUNSERI: Yeah, Charlie, so I don't 15 know the licensee's, in this particular case, specific 16 program.
17 But my experience from other nuclear 18 plants is that the fire protection system pumps do 19 undergo period capacity testing to ensure that they 20 can deliver the required amount. Okay. They also 21 undergo more frequent testing to verify that they can 22 start. They go on recert. The system pressurizes --
23 MEMBER BROWN: Yeah, yeah, that's good 24 also.
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162 1 they're going to start on demand. But, you know --
2 MEMBER BROWN: I was just familiar with 3 the commercial plants. The Navy plants I was familiar 4 with. We always worry about fires in ships, 5 particularly in submarines.
6 So those systems were tested to make sure 7 they deliver what they were supposed to deliver when 8 you have the opportunity. You can't do it when you're 9 way down under water. It doesn't work very well. But 10 there are other systems that you can test.
11 So that's why I was asking. I'm trying to 12 get some familiarity with the fire system in this 13 circumstance. You were going to say something.
14 MR. RICKERT: This is Bret Rickert. I'm 15 an engineering supervisor at Surry. We perform a 16 capacity test every 18 months.
17 MEMBER BROWN: Okay. That's -- okay.
18 That's an answer. All right.
19 CHAIR SUNSERI: And start-up pressure 20 monthly.
21 MEMBER BALLINGER: I have a little bit 22 more detailed question. When these plants are -- it's 23 on. When these plants are initially constructed, 24 there's a groundwater migration model and everything 25 that gets constructed for these plants. And so you'd NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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163 1 pretty much know where the water table is. You should 2 know where the water table is.
3 For this particular failure, did anybody 4 compare where the water table actually was compared to 5 what they thought it would be to see if this is a one-6 off thing?
7 And when you decide to drill 25 holes, 8 what's the basis for where you drill those holes? Is 9 it based on what you think the water table looks like, 10 or what's the criteria for where you drill the holes?
11 CHAIR SUNSERI: I think they said they're 12 exploring in places near where the pipe is and they're 13 checking for water. They go down seven feet. The 14 pipe is six feet. And that's what their criteria is.
15 MEMBER BALLINGER: But then the 16 presumption is that the water table is below seven 17 feet.
18 CHAIR SUNSERI: No, they're only going 19 down to the bottom of the pipe because that's all they 20 care about.
21 MEMBER BALLINGER: Oh, okay. So they're 22 assuming that if they find water, the water table is 23 higher than that.
24 CHAIR SUNSERI: Okay. I think we have 25 some statement from the applicant.
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164 1 MR. HARROW: Okay. So this is Allen 2 Harrow again.
3 The water table is greater than seven feet 4 deep. So it's greater than the depth of the center 5 line of the pipe, which is six feet.
6 In the case of the two sections of failed 7 pipe, the water table at that location was identified 8 less than six feet. Okay. So we feel that the water 9 table in this particular case was a result of some 10 type of parched aquifer where water was sitting on top 11 of soil that was not similar to where we have seen 12 previous water table levels.
13 So, in regard to this question about, 14 well, how are we going to treat this in terms of a 15 water table, our goal is to, as we replace pipe, to 16 replace pipe that is not susceptible to graphitic 17 corrosion. So we're thinking about such pipes such as 18 high density polyethylene and that thing.
19 And in that case, the actual water table 20 question in itself becomes moot.
21 MEMBER BROWN: Okay. Thank you.
22 MEMBER RICCARDELLA: I have a question 23 relative to how this concern interfaces with the 24 ongoing corrective action program and the, you know, 25 the fire protection yard loop project that the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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165 1 applicant described.
2 Is it true that this commitment for the 25 3 holes and the holes just based on the, just, that 4 would only be further investigated if there is water 5 found in the holes is what's currently in the 6 application?
7 But before we get into the period of 8 subsequent license renewal operation, won't the, any 9 effect, any results from the corrective action program 10 come into play and they would modify the AMP based on 11 the results of that program, won't they?
12 MR. GAVULA: My name is Jim Gavula with 13 the staff.
14 The answer is it could. But the 15 corrective action aspect for license renewal for the 16 corrective action portion of the current license, the 17 current Part 50, all of those corrective actions are 18 not part of our review for license renewal. That's a 19 Part 50 issue.
20 And our reviews are looking at the Part 21 54, will they establish, will the program that they 22 have established adequately manage the effects of 23 aging during the 60 to 80 timeframe. So that's the 24 portion that we're reviewing.
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166 1 commitment to modify that program based on the results 2 of the corrective action program and this ongoing 3 project?
4 MR. GAVULA: If that commitment -- it's 5 not a current commitment in their subsequent license 6 renewal application. There is no commitment for that 7 aspect.
8 MEMBER KIRCHNER: I think I'm with Pete in 9 the sense that let's put the immediate matter just to 10 the side for a moment.
11 If we find issues, and you are going to 12 find new issues as the plants age, then it suggests, 13 where I think you were going, is that the process that 14 the Agency use and should allow for, well, some 15 interaction with the applicant and modification of an 16 AMP program to address problems that are identified 17 going out, because one isn't all knowing for -- what, 18 this license renewal will not start until 2030.
19 MR. GAVULA: And in that regard, I don't 20 have a problem. But --
21 MEMBER KIRCHNER: Yeah.
22 MR. GAVULA: -- knowing what I know today, 23 with respect to the aging management program that 24 would provide reasonable assurance with Brian Allik's 25 issue of the expectation that they do some soil NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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167 1 sampling while they do exploratory holes seems like 2 that would be what would be expected in the 60 to 80-3 year timeframe.
4 Now, whether that actually happens as part 5 of the corrective action program I don't know and I 6 don't have any --
7 MEMBER KIRCHNER: Okay.
8 MR. GAVULA: -- anything put to it.
9 MEMBER KIRCHNER: And, James, we didn't 10 give you a fair chance to state your differing view.
11 And we are running up against a timeline. So may I 12 turn to you and --
13 MR. GAVULA: Good morning. My name is 14 James Gavula. I'm a mechanical engineer in the 15 Division of New and Renewed Licenses.
16 I've worked for the NRC since 1986. I was 17 a senior reactor inspector in the Region III office 18 near Chicago for 23 years, the last 6 years of which 19 were spent with the NRC's Office of Investigations and 20 the U.S. Department of Justice on the criminal 21 prosecution and conviction of the individuals at Davis 22 Besse associated with the hole in the head event.
23 Since 2009 I've worked for the NRR as a 24 mechanical engineer performing license renewal 25 reviews. Prior to the NRC, I had eight years of NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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168 1 industry experience working with Combustion 2 Engineering and Nutech Engineering, which is a 3 consulting firm.
4 I am here today to briefly discuss my 5 differing views with some of the conclusions stated in 6 Surry's SLRA.
7 For the selective leaching program, SCR 8 Section 3.0.3.1.6, the FSAR supplement does not 9 describe critical aspects of the revised program, such 10 as drilling 25 exploratory holes during each ten-year 11 interval, corrective actions that will be taken in the 12 presence of groundwater, and sample expansion if 13 groundwater is found in the exploratory holes.
14 In my opinion, the SLRA does not meet the 15 requirements of 10 CFR 54.21 Delta.
16 The next issue is the number of periodic 17 visual and mechanical inspections per unit were 18 reduced from the GALL AMP recommended ten down to 19 eight based on similarly, sufficiently similar 20 conditions between units.
21 However, recently identified soil 22 chemistry variations between two fire piping rupture 23 sites demonstrates that soil conditions vary across 24 the site, questioning the justification for the 25 reduced inspections.
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169 1 In my opinion, the SLRA doesn't contain 2 information required by 10 CFR 54.21(a)(3) to 3 demonstrate that the effects of aging will be 4 adequately managed.
5 Piping will be excavated and inspected at 6 each exploratory hole where groundwater, and the 7 emphasis is on groundwater, has been confirmed.
8 However, water caused by system leakage results in 9 different corrective actions.
10 Corrective action documents from the fire 11 water system rupture noted that corrosion was greater 12 near a leaking valve such that long-term external 13 system leakage may have kept soil moist, the soil 14 moist and was responsible for much of the corrosion 15 damage.
16 Since piping will not be excavated and 17 inspected if water in the exploratory holes is caused 18 by system leakage, in my opinion, the SLRA does not 19 contain information required by 10 CFR 54.21(a)(3) to 20 demonstrate that the effects of aging will be 21 adequately managed. Next slide, please.
22 For the open cycle cooling water system, 23 there are no aging management review items for the 24 essential service water pump diesel engine heat 25 exchangers or gear drive coolers. Dominion consider NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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170 1 these passive components as part of a, quote, active 2 skid-mounted assembly, unquote, and excluded them from 3 the scope of license renewal.
4 Dominion's lack of an AMR item was 5 dispositioned by use of a staff-identified difference 6 in SCR Section 3.0.3.2.7 where the staff credited 7 Dominion's generic letter 8913 inspection and 8 maintenance activities as providing sufficient 9 assurance that the effects of aging would be 10 adequately managed.
11 The staff's approach is inconsistent with 12 SECY Paper 1999-148 for crediting existing programs 13 for license renewal where the applicant provides the 14 information in order for the staff to have reasonable 15 assurance.
16 Comparable guidance from the Office of 17 General Counsel regarding staff attempts to use 18 statements in an NRC audit report as being considered 19 docketed information states, quote, under NRC case law 20 and regulations, the applicant has the burden for 21 demonstrating the adequacy of its license application.
22 The staff, in contrast, is an objective 23 reviewer of the application, not a proponent of the 24 application information or a consultant on the scope 25 for license ability of the proposed activities.
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171 1 The precedent being set in the SCR can be 2 used in future submittals where excluding passive 3 components that are inconsistent with the guidance in 4 the SRP SLR for complex assemblies.
5 In my opinion, the SLRA does not contain 6 the information required by 10 CFR 54.21(a)(3) to 7 demonstrate that the effects of aging will be 8 adequately managed.
9 For the buried and underground piping and 10 tanks program, pictures from the ruptured fire water 11 system showed significant corrosion of the carbon 12 steel tie rods. Although current corrective actions 13 to replace gray cast iron with ductile cast iron will 14 potentially resolve the selective leaching issue, it 15 will not address the noted corrosion of the tie rods.
16 In my opinion, the SLRA did not contain 17 the information required by 10 CFR 54.21(a)(3) for 18 demonstrating that the effects of aging will be 19 adequately managed.
20 Next issue, the response to RAI B2127-3 21 led the staff to accept the coatings on the buried 22 fire system piping as meeting the preventive actions 23 portion of the GALL buried pipe program.
24 Corrective action documents from the fire 25 system rupture noted that the coating was not NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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172 1 consistent with a normal coating thickness and was too 2 thin for long-term protection in high moisture soil.
3 Based on this operating experience, credit 4 cannot be given to the buried fire piping coating and 5 adjustments to the buried pipe program are needed.
6 In my opinion, the SLRA does not contain 7 the information required by 10 CFR 54.21(a)(3) to 8 demonstrate that the effects of aging will be 9 adequately managed. Next slide, please.
10 As discussed in SCR Section 6, in 11 accordance with 10 CFR 54.29 Alpha, the Commission may 12 issue a renewed license if it finds that actions have 13 been identified, and put the emphasis on actions have 14 been identified, with respect to managing the effects 15 of aging during the period of extended operation.
16 For the issues that I've briefly 17 discussed, the staff was informed that no further 18 aging management program information would be provided 19 until the applicant's corrective actions were 20 completed and that no further action would be 21 provided.
22 10 CFR 54.30 specifically excludes from 23 the scope of license renewal review a licensee's 24 obligation to take corrective actions under its 25 current license to ensure that the intended functions NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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173 1 will be maintained throughout the term of the current 2 license.
3 The current license does not include any 4 obligation to ensure that the effects of aging are 5 adequately managed during the subsequent period of 6 extended operation.
7 Based on the issues with the aging 8 management programs, I do not concur with the SCR's 9 conclusion in Section 6 that the applicant has met the 10 requirements of 10 CFR 54.29 Alpha relative to, quote, 11 actions have been identified with respect to managing 12 the effects of aging during the subsequent period of 13 extended operation.
14 That concludes my remarks. Thank you for 15 your time.
16 MEMBER KIRCHNER: Thank you, Brian and 17 James, for being with us and presenting your views.
18 We are running a little bit over. We need 19 to turn to public comment before closing our meeting.
20 (Off mic comments.)
21 MEMBER KIRCHNER: Oh, there's one more 22 slide. I'm sorry. Eric, this is you?
23 (Off mic comments.)
24 CHAIR SUNSERI: I can remove the time 25 constraint if I go ahead and leave. We can move the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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174 1 meeting to the other room over there. So I'll excuse 2 myself.
3 MEMBER KIRCHNER: Okay. Well, I'll join 4 you.
5 CHAIR SUNSERI: You still have a quorum.
6 (Off mic comments.)
7 MR. OESTERLE: I promise to be brief.
8 MEMBER KIRCHNER: Okay, Eric.
9 MR. OESTERLE: Well, good morning. My 10 name is Eric Oesterle. And I'm Chief of the License 11 Renewal Projects Branch in the Division of New and 12 Renewed Licenses.
13 NRR's management appreciates and supports 14 the opportunity for the staff to present their 15 differing views. Consideration of how to address 16 these views is still in process. And, therefore, 17 management perspectives on these views are 18 preliminary.
19 We believe that the technical positions 20 are accurately characterized and that all these 21 positions or views are manageable through our existing 22 process using the NRC's regulatory framework.
23 As noted, the applicant entered the 24 condition regarding the degraded fire protection loop 25 piping into its corrective action program. And NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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175 1 completion of that process is still underway.
2 Our understanding is that selective 3 leaching has been determined to be the root cause.
4 However, the extent of condition and final 5 determination of corrective actions remain to be 6 completed by the applicant.
7 Without knowing this final resolution, 8 concluding that there is any impact on the augmented 9 selective leaching AMP that may be proposed by the 10 applicant is premature.
11 The applicant has included an aging 12 management program for selective leaching, and in 13 response to this operating experience and NRC 14 questions, has augmented that program to include 15 additional measures to monitor and evaluate the 16 conditions as discussed earlier in the presentation.
17 Currently, this plant condition and its 18 resolution is being monitored by appropriate NRC 19 personnel. And we are confident that through 20 continued oversight and communication with the region, 21 that any impact on the selective leaching AMP will be 22 addressed as part of the corrective actions program.
23 Given the totality of the NRC's regulatory 24 framework, we have reasonable assurance of adequate 25 protection of public health and safety.
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176 1 And I would like to note that the 2 Commission had contemplated situations just like this 3 during the development of the 1995 license renewal 4 rule, that is situations such as when an operational 5 issue arises during the review of a license renewal 6 application that may have an impact on aging 7 management of plant structures and components.
8 For background, I'll provide a quote from 9 the statements of consideration from the 1995 license 10 renewal rule.
11 I quote, if aging issues are identified 12 during the license renewal review that applied to the 13 current operating term, licensees are required to take 14 measures under their current license to ensure that 15 the intended function of systems, structures, and 16 components will be maintained in accordance with their 17 current licensing basis throughout the term of the 18 current license.
19 In addition, if aging issues are 20 identified during a license renewal review that 21 applied to the current operating term, the NRC will 22 evaluate these issues for generic applicability as 23 part of the regulatory process.
24 This concludes my remarks.
25 MEMBER KIRCHNER: Thank you, Eric. In NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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177 1 lieu of the time, I think we need to now ask for any 2 public comment. I'll turn first to the room. If 3 there is anyone in the room who wishes to make a 4 comment, please come up to the microphone, state your 5 name, and make your comment.
6 Kent, do we have the bridge line open?
7 Okay. On the bridge line to the public, if there is 8 anyone out there who wishes to make a comment, please 9 state your name and make your comment.
10 I'm using the five-second rule. So 11 hearing none, at this point, we can close the bridge 12 line. And I'll turn to members. Starting with Pete, 13 did you wish to make any other further comments?
14 MEMBER RICCARDELLA: No, I don't think so 15 at this time.
16 MEMBER KIRCHNER: Charlie?
17 MEMBER BROWN: Only that you mentioned 18 that staff had not -- I'm sorry. In your opening 19 remarks, you commented that you had not completed your 20 overall assessment of how the differing views would be 21 addressed as part of the final resolution and 22 determination. Is that correct?
23 MR. OESTERLE: That's correct.
24 MEMBER BROWN: Okay. So there's more to 25 come.
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178 1 MR. OESTERLE: More to come.
2 MEMBER KIRCHNER: Yeah, and there's a 3 formal process for that.
4 MEMBER BROWN: No, I understand that. So 5 we will hear more at some other circumstance --
6 MEMBER KIRCHNER: Yeah.
7 MEMBER BROWN: -- relative to its 8 resolution.
9 MR. OESTERLE: Yes, sir.
10 MEMBER BROWN: Okay. Thank you very much.
11 That's the only question I had.
12 MEMBER RICCARDELLA: We will hear more?
13 MEMBER BROWN: Yes.
14 MEMBER RICCARDELLA: I mean, there will be 15 more. But it is not clear --
16 (Simultaneous speaking.)
17 MEMBER BROWN: We've got a full committee 18 meeting.
19 MEMBER RICCARDELLA: Okay.
20 MEMBER BROWN: Yeah, that's where we will 21 address this.
22 MEMBER RICCARDELLA: And that will be 23 resolved before the full committee meeting?
24 MEMBER BROWN: Hopefully.
25 MR. OESTERLE: That's the intent.
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179 1 MEMBER RICCARDELLA: Huh?
2 MR. OESTERLE: That's the intent. Yes, 3 sir.
4 MEMBER RICCARDELLA: Okay. Thank you.
5 MEMBER KIRCHNER: Eric, have you any 6 comments?
7 MR. SCHULTZ: I have one question for 8 Eric.
9 MR. OESTERLE: Yes.
10 MR. SCHULTZ: Just for my understanding, 11 that your preliminary review is that the technical, 12 there are technical merits which have been presented 13 by the differing views to be considered through the 14 overall process for resolution.
15 And your timeframe is that by the time we 16 reach the full committee meeting a couple things will 17 happen. The corrective action inspection will have 18 been done. There may be some results from that 19 activity --
20 MR. OESTERLE: Could be.
21 MR. SCHULTZ: -- as well as your 22 evaluations that are going to be moving forward here.
23 MR. OESTERLE: So, yes, our view is that 24 the, we have, the NRC has adequate processes in place 25 to address these technical issues. They may be NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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180 1 outside of license renewal space and in corrective 2 action space as part of the current operating term.
3 And we would expect that the outcome of the corrective 4 actions may impact the selective leaching AMP.
5 MR. SCHULTZ: Okay.
6 MR. OESTERLE: But we have yet to see what 7 the final resolution is.
8 (Simultaneous speaking.)
9 MEMBER BROWN: Well, that was interesting 10 choices of words as you went through. That was a good 11 question. I didn't follow up with it the same way.
12 I presume you will be able to say at the 13 full committee meeting how you've addressed or not 14 addressed based on any subsequent corrective action, 15 other type changes that might be made. But that would 16 be addressed at the full committee meeting.
17 MR. OESTERLE: Yes. So, if we do a 18 thought experiment --
19 MEMBER BROWN: But let me interrupt for a 20 second. You said the existing programs are adequate 21 to address this issue.
22 MR. OESTERLE: Yes.
23 MEMBER BROWN: Processes rather.
24 MR. OESTERLE: Right.
25 MEMBER BROWN: So we would --
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181 1 MEMBER KIRCHNER: Framework.
2 MEMBER BROWN: We will hear about how 3 those processes are going to address this issue.
4 MR. OESTERLE: Right. So, if you carry 5 this forward, there may be several different outcomes 6 of the corrective actions program.
7 MEMBER BROWN: That's fine.
8 MR. OESTERLE: Right? One which may 9 impact the aging management program and others which 10 may not.
11 MEMBER BROWN: I'm not asking for a 12 judgment as to what's what, just that we will know 13 what the differentials are on that when we get here at 14 the next time.
15 MR. OESTERLE: Yes.
16 MEMBER BROWN: Well, actually, I will 17 request that.
18 MR. OESTERLE: Okay.
19 MR. SCHULTZ: I have no further questions 20 or comments except to --
21 MEMBER KIRCHNER: Okay. Good. All right.
22 I --
23 MR. SCHULTZ: -- remark that the 24 presentations were very helpful today --
25 MEMBER BROWN: Yeah.
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182 1 MEMBER KIRCHNER: Yeah.
2 MR. SCHULTZ: -- as well as the, as we've 3 commented on, the work and quality of the application 4 and the -- I don't want to rank order. But the review 5 has been substantial and very effective in my view.
6 MEMBER KIRCHNER: Okay. I want to close 7 by thanking the applicant and the staff for their 8 presentations and also single out Brian Allik and 9 James Gavula for coming before us and presenting their 10 differing views.
11 And with that, we are, let me get this, 12 adjourned. Thank you.
13 (Whereupon, the above-entitled matter went 14 off the record at 12:08 p.m.)
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Surry Power Station Units 1 and 2 Subsequent License Renewal Application ACRS Sub-Committee Meeting February 5, 2020
Introductions
Paul Phelps SLR Director Paul Aitken SLR Manager Eric Blocher SLR Technical Lead Chuck Tomes TLAA Principal Engineer Allen Harrow Surry Engineering Manager Craig Heah SLR Technical Lead 2
Agenda Station Overview/Performance SLR Application Development GALL SLR Consistency SLR Aging Management Programs Technical Topics Closing Remarks 3
Surry Power Station 4
Station Overview Unit 1 Unit 2 Full Power License - 2,441 MWt May 25, 1972 January 29, 1973 (Operating (Operating License Issued) License Issued)
Independent Spent Fuel Storage 1986 Installation (ISFSI), Pads 1 & 2 4.3% Power Uprate to 2,546 MWt 1995 First License Renewal Approval 2003 1.6% MUR to 2,587 MWt 2010 Entered Period of Extended Operation May 25, 2012 January 29, 2013 Current License Expiration May 25, 2032 January 29, 2033 5
Station Overview 6
Surry Performance Surry operates on an 18-month refueling frequency Plant Capacity Factor:
- 2017: U1 - 102.35% U2 - 94.18%
- 2018: U1 - 89.39% U2 - 90.69%
- 2019: U1 - 90.48% U2 - 102.59%
Regulatory Status
- ROP Actions Matrix Column 1
- All ROP Indicators are Green 7
Significant Plant Modifications Surry Unit 1 Unit 2 Flux Thimble Replacement 2001 2011 Reactor Vessel Head Replacement 2003 2003 FAC Pipe Replacement N/A 2005 Ultrasonic Feedwater Flow Installation 2009 2011 Reactor Coolant Pump Main Flange Bolt Replacement 2009 2009 Steam Generator Feed Ring Replacement 2010 2011 Isolated Phase Bus Duct Replacement 2010 2011 Fire Detection System Replacement 2012 2012 Main and Station Service Transformer Replacement 2015 2005 Carbon Fiber Reinforced Polymer (CFRP) Installation 2016 2016 Reserve Station Service Transformers (RSST) Replacement 2019 2020 8
Carbon Fiber Reinforced Piping 9
SLR Application Development 10
SLR Application Development Regulatory and Industry Guidance Dominion Energy staff integrally involved in the development of the GALL SLR/SRP Followed NUREG-2191 (GALL-SLR) and NUREG-2192 (GALL-SRP) to the greatest extent possible (discussed later)
Followed NEI 17-01 guidance (updated for SLR)
Reviewed previous RAIs from several previous licensees during application development Conducted Industry Peer Reviews Conducted a Safety pre-application meeting with the NRC Staff in April 2018 to discuss SLRA content and obtain insights 11
Integrated Plant Assessment Deltas between First License Renewal (FLR) and 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
- Surry FLR was pre-GALL, additional aging effects required disposition based on NUREG-2191 (GALL-SLR)
Aging Management Programs
- Existing TLAAs Re-assessed
- One new TLAA identified - S/G AVB Tube Wear
- TLAAs analysis dispositioned as acceptable for 80 years per GALL-SLR Guidance 12
GALL Consistency Submittal consistent with GALL-SLR High AMR Consistency (99.6% Notes A thru E)
License Renewal Commitments
- 47 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 13
SLR Aging Management Programs 14
Surry SLR AMP Considerations NEI involvement, collaboration with EPRI, and PWROG participation informed AMPs with New Industry Guidance and R&D products Incorporation of operating experience (OE):
- Industry and plant specific OE reviewed for a 10 year period
- Participation in Industry Peer Reviews
- SLR Lead Plant Alignment AMP Effectiveness Reviews performed on all first license renewal AMPs using elements of NEI 14-12 15
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 NUREG-2191 (GALL-SLR) AMPs Several FLR AMPs required enhancement for consistency with GALL-SLR AMPs Several FLR AMPs subdivided into other GALL-SLR AMPs 16
17 Surry SLR - 47 GALL-AMPs Consistent With With Exception Plant with Enhancement Exception and Specific GALL-SLR Enhancement Existing 40 6 24 1 9 0 New 7 5 0 2 0 0 Total 47 18
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 19
AMPs with Exceptions XI.M2 Water Chemistry XI.M3 Reactor Head Closure Stud Bolting XI.M20 Open-Cycle Cooling Water System XI.M21A Closed Treated Water Systems XI.M27 Fire Water System XI.M29 Atmospheric Metallic Storage Tanks XI.M30 Fuel Oil Chemistry XI.M35 ASME Code Class 1 Small Bore Piping XI.M42 Internal Coatings/Linings X1.S1 ASME Section X1, Subsection IWE XI.E4 Metal Enclosed Bus XI.E7 High Voltage Insulators 20
Types of AMP Exceptions 6 AMP Exceptions - Test frequency and/or inspection technique alternatives proposed 5 AMP Exceptions - Plant-specific configurations 2 AMP Exceptions - EPRI Chemistry guideline revision 1 AMP Exception - Management of a different component type 21
First License AMP Effectiveness FLR AMPs have been evaluated for AMP effectiveness:
- AMP reviews conducted in 2015, 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 4 inspection identified no findings or concerns in 3Q19 22
Technical Topics 23
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
- SPS 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 SPS 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
- SPS 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 24
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 Appendix C MRP-227-A GAP Analysis for PWR Vessel Internals Aging Management SPS 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: Lower Girth Welds, Clevis Insert Bolts, Thermal Sleeves, Radial Support Keys, Clevis Stellite Surfaces Expansion: Upper Core Plate (VT3 exam)
Existing: Fuel Alignment Pins (malcomized)
- MRP 2019-009: Lower Girth Welds (Primary-OTI)
- WCAP-17451: CRGT Sheaths and C-Tubes (Expansion)
SPS will manage RVI fluence projections consistent with GALL-SLR AMP X.M2, Neutron Fluence Monitoring Program SPS will manage RVI examinations consistent with GALL-SLR AMP XI.M16A, PWR Vessel Internals 25
Other Aging Management Enhancements SLRA Sections Addressing GALL-SLR Recommendations Other Aging A1.8 Flow-Accelerated Corrosion A1.11 Open-Cycle Cooling Water System Management A1.27 Buried and Underground Piping and Tanks Considerations A3.7.1 Reactor Coolant Pump Fatigue Crack Growth Analysis A3.7.6 Reactor Coolant Pump Code Case N-481 A3.7.7 Cracking Associated With Weld Deposited Cracking Draft ASME Code Case N-871 examinations will manage the aging of the pressure boundary of the newly installed carbon fiber reinforced polymer pipe lining consistent with GALL-SLR AMP XI.M20, Open-Cycle Cooling Water System Program.
Erosion monitoring manages wall thinning due to cavitation, liquid droplet impingement, flashing, and solid particle erosion consistent with GALL-SLR AMP XI.M17, Flow-Accelerated Corrosion.
Soil surveys and analysis consistent with EPRI 3002005294 that confirms soil environment corrosivity now supplements AMP XI.M41, Buried and Underground Piping and Tanks Program.
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-A)
Fracture mechanics integrity assessment for RCP Code Case N-481 (PWROG-17033-P-A Rev 1-A)
Reactor vessel underclad cracking associated weld deposited cracking (PWROG-17031-NP-A Rev 1 - draft NRC Safety Evaluation in progress) 26
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 3.1.2.2.13 Loss of Fracture Toughness Due to Neutron Irradiation Embrittlement or Thermal Embrittlement Embrittlement at 4.2 Reactor Vessel Neutron Embrittlement Analysis High Fluence A1.9 Reactor Vessel Material Surveillance A2.2 Neutron Fluence Monitoring Fluence projections through SPEO (68 EFPY) were performed for neutron embrittlement analyses Analyses for USE, ART, and P-T Limits for beltline materials have been satisfactorily evaluated using the 68 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 68 EFPY with the use of updated initial material properties used to calculate ART values and KIC methodology SPS will manage fluence projections consistent with GALL-SLR AMP X.M2, Neutron Fluence Monitoring Program SPS will manage embrittlement consistent with GALL-SLR AMP XI.M31, Reactor Vessel Material Surveillance Program
- One capsule will be withdrawn from each unit during SPEO at 60-63 EFPY 27
Reactor Vessel (RV) Support Steel Configuration 28
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 A1.31 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 SPS SLR Fracture mechanic evaluation (ASME Code formulas for PT Curves)
Loads for dead weight, LOCA, and seismic Based on use of lower bound KIR value of 26.7 ksi in to represent infinite amount of fluence Critical stress (based on the KIR curve) using the lower bound toughness of 26.7 ksi in is greater than the stress on NST Therefore, brittle fracture will not occur SPS will manage aging consistent with:
B2.1.12 Closed Treated Water Systems B2.1.31 ASME Section XI, subsection IWF B2.1.34 Structures Monitoring 29
Fire Protection Yard Loop Operating Experience 30
Fire Protection Loop Piping Break In July 2019, leakage was experienced from two adjacent 18 foot to 20-foot-long sections of 12 diameter fire protection loop piping 31
Analysis of Piping Failure The FP pipe failure was entered into the Corrective Action Program to determine the cause of the failure and the extent of condition Graphitic corrosion was identified as the cause of the piping failure Elevated levels of corrosion are confined to a limited area near the identified failure between the 5 o clock and 7 o clock positions Bituminous coating was observed to have been degraded in these locations. Other locations on the pipe above the areas of water contact were not affected.
Hydraulic pressure surge caused by the start of the motor-driven pump contributed to the initial failure, which led to bending stresses and an overload condition affecting adjacent FP piping Failures due to extended exposure of the susceptible gray cast iron material to moist/wet soil in the area of failures 32
Analysis of Piping Failure Additional inspections were conducted to identify the extent of condition to identify other FP piping locations in the main loop that were exposed to groundwater
- Reviewed OE from previous excavations around the plant site to map location to vacuum exploratory holes
- Exploratory holes were vacuumed to depths below the buried FP Piping to confirm the absence of groundwater
- Identified locations with groundwater were sampled and determined not to include chloride levels indicative of leakage from the intake canal
- Soil samples were taken at the excavation location during the repairs of the ruptured FP piping and the corrosivity levels were determined to be low Fire suppression capabilities have been maintained through compensatory measures 33
Fire Protection Yard Loop Project Funding approved for the project includes piping as well as hydrants/valves Prioritized four phased approach
- Susceptibility to graphitic corrosion
- Location with respect to fire pumps On site project manager is actively working
- Conceptual design in progress considering best technical solutions using outside expertise Vacuum excavation of Phase 1 in progress 34
Improved Aging Management Methods Operating Experience is being shared with the industry
- Program owner presented to the Selective Leaching Task Force in January 2020 and is scheduled to present to the Buried Pipe Integrity Group in February 2020 to inform the industry
- Sections of pipe transported to EPRI to conduct selective leaching research on methods of detection Aging management programs will be informed with information that is learned through our experiences and as new information related to materials and examination methods Dominion Energy is committed to improving the integrity of the Fire Protection system 35
Dominion Energy SLR Summary NRC coordination on GALL SLR and SRP was transparent to all stakeholders Surry SLR met the expected norms established with the most recent industry LR/SLR applications Surry had a high degree of consistency with GALL-SLR, which resulted in a high quality SLR Application AMPs will effectively manage the effects of aging to provide reasonable assurance for the SLR period Dominion Energy has committed future investments in people, program enhancements and equipment modifications for the SPEO 36
Advisory Committee on Reactor Safeguards Plant License Renewal Subcommittee Surry Power Station, Units 1 and 2 Subsequent License Renewal Application (SLRA)
Safety Evaluation Report (SER)
February 5, 2020 Angela Wu, Project Manager Lauren Gibson, Project Manager Office of Nuclear Reactor Regulation
Presentation Outline
- Overview of Safety Review of Surry SLRA
- SER:
- Section 2: Scoping and Screening Review
- Section 3: Aging Management Review
- Section 4: Time-Limited Aging Analyses
- Specific Areas of Review
- Region II: Inspections and Plant Material Conditions
- Conclusion
- Discussion on Differing Views 2
Surry, Units 1 & 2:
License Renewal Initial License Renewal Unit Initial Initial License Renewed Expiration License Renewal Application License Date 1 5/25/1972 5/29/2001 3/20/2003 5/25/2032 2 1/29/1973 5/29/2001 3/20/2003 1/29/2033 Subsequent License Renewal Application Submitted 10/15/2018 Acceptance Determination 12/10/2018 Draft Safety Evaluation Report with 12/27/2019 No Open or Confirmatory Items 3
Audits Audits Dates Location Operating December 6 - 19, 2018 Rockville, MD Experience In-Office February 4 - 28, 2019 Rockville, MD Surry Power Station, Units 1 and 2 (Surry County, VA)
On-Site April 22 - 25, 2019 Dominion HQ (Innsbrook, VA) 4
SER Overview
- Draft SER with No Open or Confirmatory Items:
December 27, 2019
- Requests for Additional Information (RAIs): 71 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
- 5 consistent
- 5 consistent
- 2 consistent with exceptions
- 2 consistent with exceptions o 40 existing programs o 40 existing programs
- 7 consistent
- 6 consistent
- 33 consistent with
- 34 consistent with enhancements/exceptions enhancements/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
- Irradiation Effects on the Concrete Biological Shield Wall + Reactor Vessel Steel Supports
- Buried Cementitious Piping
- Selective Leaching
- Neutron Fluence Monitoring
- Electrical Cable Qualification and Condition Assessment 10
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 (3.17 x 1018 n/cm2) and gamma dose (2.97 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 11
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 12
Buried Cementitious Piping
- Issue: Dominion proposed an alternative approach to manage the effects of aging on the external surfaces of uncoated buried cementitious circulating water (CW) piping:
- A one-time inspection of one of the following:
- Below-grade turbine building concrete (i.e., surrogate structure); or
- Buried cementitious CW piping if the surrogate structure is coated
- Groundwater + soil testing
- GALL-SLR: GALL-SLR Table XI.M41-2, Inspection of Buried and Underground Piping and Tanks, recommends periodic inspections (i.e.,
two inspections in each ten-year period for a two-unit site)
- Reasonable Assurance: Combined approach of a one-time inspection, coupled with groundwater and soil testing 13
Selective Leaching
- Issue: Identified in October 14, 2019 Annual SLRA Update
- Two ruptures of cast iron buried fire protection system piping (July 2019)
- Failure due to external graphitic corrosion from groundwater exposure
- Resolution: AMP Augmented to Include Exploratory Holes
- Excavate + inspect fire protection loop piping where groundwater is identified
- Additional holes to confirm extent of identified elevated groundwater, water from fire protection system leakage or other plant system leakage
- Completion of corrective actions for 2019 pipe ruptures may result in additional changes to AMPs
- Reasonable Assurance: Identified activities (exploratory holes to confirm the presence of groundwater, excavating and inspecting fire protection loop piping) are capable of detecting adverse conditions due to groundwater immersion that may lead to graphitic corrosion 14
Neutron Fluence Monitoring
- Issue: Staff could not verify if 80-year neutron fluence values for the reactor vessel internals (RVI) fall within the ranges in the generic fluence screening criteria of the MRP-227-Revision 1 gap analysis
- Resolution: Proprietary report included the neutron fluence values projected to 80 years specific to the Surry RVI
- Reasonable Assurance: 80-year neutron fluence values for the RVI are within the ranges specified in the generic screening criteria in the MRP-227-Revision 1 gap analysis 15
Electrical Cable Qualification and Condition Assessment
- Issues:
- No test matrix for inaccessible medium voltage cables in AMP B2.1.39
- Exclusion of mechanical components in the Environmental Qualification (EQ) program. Maintaining qualification of interface between mechanical + electrical equipment in the EQ program was unclear
- Resolution:
- AMP was revised to include a test matrix
- Staffs onsite audit confirmed that mechanical interfaces are included in the EQ program
- Reasonable Assurance: EQ program is adequate to satisfy the TLAA consistent with 10 CFR 54.21(c)(1)(iii) 16
Region II AMP Inspections License Renewal Inspection Program for Initial Period of Extended Operations Inspection Dates Results U1 & U2 IP 71003 April 25 - 29, 2011 No Findings Phase 1 ML111460331 U1 & U2 IP 71003 July 11 - July 29, 2011 No Findings Phase 2 ML112560062 8 Observations U1 & U2 IP 71003 June 18 - June 22, 2012 No Findings Phase 3 ML12220A541 U1 & U2 IP71003 August 12 - 16, 2019 No Findings Phase 4 ML19311C688 17
Region II AMP Inspections AMPs Reviewed During 71003 Phase 4 Inspection
- Augmented Inspection Program (Existing)
- Buried Piping and Valve Inspection Program (New)
- Chemistry Control Programs for Primary Systems (Existing)
- Chemistry Control Program for Secondary Systems (Existing)
- Civil Engineering Structural Inspection Program (Existing)
- General Condition Monitoring Program (Existing)
- Non-EQ Cable Monitoring Program (Existing)
- Tank Inspection Program (New)
- Work Control Process (Existing) 18
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 2011, 2014, Service Water System Inspections 2017 IP71111.21M DBAI 3Q 2018 Ensure the selected SSCs that are subject (operating 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.
IP71111.12 Maintenance Effectiveness 4Q 2016 Maintenance Rule Structural Monitoring Program B Emergency Service Water Pump Cracked Discharge Flange IP71152 PI&R Sample 3Q 2018 Non-EQ Cable Monitoring Program Emergency Bus Degraded Voltage and Undervoltage Relay Failures IP71152 PI&R Sample 1Q 2020 Buried Piping Program 2019 Fire Loop Piping Rupture reveals 19 unexpected corrosive soil conditions
Region II AMP Inspections Resident Inspector Insight and Inspection Results
- No findings from License Renewal Program inspections
- 2016: Green NCV for failing to identify degraded supports associated with the emergency service water pumps (NCV 05000280, 281/2016003-01)
- 2018: Green NCV for inadequate preventative maintenance and multiple beyond service life relay failures (05000281/2018002-01)
- 2019: Fire Loop Piping Rupture 20
Region II AMP Inspections July 2019 Fire Loop Piping Rupture
- External corrosion from long-standing exposure to moist or wet soil resulted in wall thickness reductions at several locations via graphitic corrosion (i.e., selective leaching)
- Dominion committed to dig 25 exploratory holes along the piping to determine if additional corrective actions are necessary, including excavation and evaluation of any piping in the presence of groundwater.
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Region II Conclusion
- Regional Inspections:
- In general, the inspectors found that aging management programs were being implemented in accordance with the license condition.
- The region will continue to monitor AMPs using the baseline Reactor Oversight Process.
- A focused PIR inspection using insights from the revised IP71111.12 is scheduled for late February 2020 to review licensee corrective actions and incorporation of new operating experience into the Buried Piping Program.
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SLRA Review Conclusion 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 Surry Power Station, Units 1 and 2.
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Differing View - Person #1:
Selective Leaching Program
- Issue: A singular criterion (i.e., presence of groundwater) is used to detect adverse conditions that may lead to graphitic corrosion of buried gray cast iron fire protection loop piping.
- Other soil parameters besides standing water (e.g., soil resistivity, pH, redox potential, sulfides) play an important role in the corrosion of cast iron in soil.
- Elayaperumal, K. Raja, V. S.. (2015). Corrosion Failures - Theory, Case Studies, and Solutions.
- EPRI Report 3002005294, Soil Sampling and Testing Methods to Evaluate the Corrosivity of the Environment for Buried Piping and Tanks at Nuclear Power Plants, Table 9-4, Soil Corrosivity Index from BPWORKS.
- AWWA C105, Polyethylene Encasement for Ductile-Iron Pipe Systems, Table A.1, Soil-Test Evaluation.
This is the personal position of the presenter and not that of the Agency. 24
Differing View - Person #1:
Selective Leaching Program (Continued)
- October 31, 2019 (ADAMS Accession No. ML19310E716) Submittal:
- Limited soil corrosivity testing documents low pH and low soil resistivity, indicating that soil parameters other than standing water may have contributed to the ruptures.
- No Reasonable Assurance: No basis for relying on a singular criterion makes it unclear how reasonable assurance can be achieved This is the personal position of the presenter and not that of the Agency. 25
Differing View - Person #2:
SER Sections 3.0.3.1.6, 3.0.3.2.7, and 3.0.3.2.20
- Selective Leaching (SER Section 3.0.3.1.6)
- Issue: Final Safety Analysis Report supplement lacks critical details of currently revised program
- Requirements of 10 CFR 54.21(d) for a summary description of the program were not met.
- Issue: Bases for inspection reduction crediting common conditions for two-unit site do not address soil chemistry variation
- SLRA did not contain information required by 10 CFR 54.21(a)(3) to demonstrate that the effects of aging will be adequately managed for the reduced component inspections.
- Issue: Excavation limited to confirmed groundwater but not system leakage
- SLRA did not contain information required by 10 CFR 54.21(a)(3) to demonstrate that the effects of aging will be adequately managed for components exposed to system leakage.
- Issue: Operating conditions at the plant are not bounded by those for which the GALL-SLR Report program was evaluated
- The staffs inaccurate statements in the SER should be corrected.
This is the personal position of the presenter and not that of the Agency. 26
Differing View - Person #2
- Open-Cycle Cooling Water System (SER Section 3.0.3.2.7)
- Issue: No aging management review of passive components for essential service water pump diesel engines or drives
- SLRA did not contain information required by 10 CFR 54.21(a)(3) to demonstrate that the effects of aging will be adequately managed for diesel engine heat exchanger and right angle gear oil cooler.
- Buried and Underground Piping and Tanks (SER Section 3.0.3.2.20)
- Issue: Bell and spigot fire water system tie rod corrosion not addressed
- SLRA did not contain information required by 10 CFR 54.21(a)(3) to demonstrate that the effects of aging will be adequately managed for fire water system tie rods.
- Issue: Buried fire water piping external coating found to be inadequate
- SLRA did not contain information required by 10 CFR 54.21(a)(3) to demonstrate that the effects of aging will be adequately managed for thinly coated fire water system piping.
This is the personal position of the presenter and not that of the Agency. 27
Differing View - Person #2:
SER Section 6, Conclusion
- Issue: For above SER sections, the applicant did not identify actions for managing the effects of aging during the subsequent period of extended operation
- Actions to establish adequate aging management programs are pending corrective actions under current license or were not provided.
- Without identifying actions, the applicant did not meet the requirements of 10 CFR 54.29(a) as stated in the SER.
This is the personal position of the presenter and not that of the Agency. 28
NRR Preliminary Perspective on Differing Views
- Technical issues accurately characterized
- Manageable by existing process
- Entered into Corrective Action Program
- Final corrective actions are pending
- Established regulatory framework ensures reasonable assurance 29