ML20029E958
| ML20029E958 | |
| Person / Time | |
|---|---|
| Issue date: | 12/04/2019 |
| From: | Advisory Committee on Reactor Safeguards |
| To: | |
| Burkhart, L ACRS | |
| References | |
| NRC-0726 | |
| Download: ML20029E958 (177) | |
Text
Official Transcript of Proceedings NUCLEAR REGULATORY COMMISSION
Title:
Advisory Committee on Reactor Safeguards Open Session Docket Number: (n/a)
Location: Rockville, Maryland Date: Wednesday, December 4, 2019 Work Order No.: NRC-0726 Pages 1-112 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 669TH MEETING 5 ADVISORY COMMITTEE ON REACTOR SAFEGUARDS 6 (ACRS) 7 + + + + +
8 OPEN SESSION 9 + + + + +
10 WEDNESDAY 11 DECEMBER 4, 2019 12 + + + + +
13 ROCKVILLE, MARYLAND 14 + + + + +
15 The Advisory Committee met at the Nuclear 16 Regulatory Commission, Two White Flint North, Room 17 T2D30, 11545 Rockville Pike, at 1:00 p.m., Peter 18 Riccardella, Chairman, presiding.
19 20 COMMITTEE MEMBERS:
21 PETER RICCARDELLA, Chairman 22 MATTHEW W. SUNSERI, Vice Chairman 23 JOY L. REMPE, Member-at-Large 24 RONALD G. BALLINGER, Member 25 DENNIS BLEY, Member NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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2 1 CHARLES H. BROWN, JR. Member 2 VESNA B. DIMITRIJEVIC, Member 3 WALTER L. KIRCHNER, Member 4 JOSE MARCH-LEUBA, Member 5 DAVID A. PETTI, Member 6
7 ACRS CONSULTANTS:
8 MICHAEL L. CORRADINI*
9 STEPHEN SCHULTZ*
10 11 DESIGNATED FEDERAL OFFICIALS:
12 KENT HOWARD 13 MIKE SNODDERLY 14 15 16 17 18 19 20 21 22 23 24 *Present via telephone 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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3 1 CONTENTS 2 Opening Remarks by the ACRS Chairman . . . . . . 4 3 Peach Bottom Subsequent License Renewal . . . . . 6 4 Public Comments . . . . . . . . . . . . . . . . . 45 5 NuScale Source Term Topical Report Methodology . 46 6 Adjourn . . . . . . . . . . . . . . . . . . . . 112 7
8 9
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4 1 P R O C E E D I N G S 2 1:00 p.m.
3 CHAIRMAN RICCARDELLA: The meeting will 4 come to order.
5 Scott?
6 MR. BROWN: Sure. I would just like to 7 announce for the Committee that we have a new member 8 on the ACRS staff, Thomas Dashiell. Thomas comes to 9 us to be our Conference Room Manager, which we badly 10 need, as you all have seen. Thomas has served for 11 years in the Navy, retired with honors from the Navy.
12 We won't hold that against you, Thomas.
13 And following that, he's been here at NRC 14 for 15 years as an AV Project Manager, IT Project 15 Manager. While he was in the Navy, he worked directly 16 under two Presidents. So, he comes with high 17 credentials. And here at NRC, he worked the AV 18 equipment for the Commission itself in the hearing 19 rooms and in the auditorium. So, he comes with high 20 skills and we're glad to have him on our staff.
21 So, we're glad you're here, Thomas.
22 Thanks.
23 CHAIRMAN RICCARDELLA: Welcome, Thomas.
24 So, this is the first day of the 669th 25 meeting of the Advisory Committee on Reactor NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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5 1 Safeguards. I'm Pete Riccardella, Chairman of ACRS.
2 ACRS was established by the Department of 3 Energy Act and is governed by the Federal Advisory 4 Committee Act, or FACA. The ACRS section of the U.S.
5 NRC public website provides information about the 6 history of the ACRS and provides FACA-related 7 documents, such as our Charter, Bylaws, Federal 8 Register notices for meetings, letter reports, and 9 transcripts of all full and subcommittee meetings, 10 including slides and presentations at the meetings.
11 The Committee provides its advice on 12 safety matters to the Commission through its publicly-13 available letter reports. The Federal Register notice 14 announcing the meeting was published on November 18th, 15 2019, and provided an agenda and instructions for 16 interested parties to provide written documents or 17 request opportunities to address the Committee, as 18 required by FACA.
19 In accordance with FACA, there is a 20 Designated Federal Official for the meeting. The DFO 21 for today's meeting is Mr. Kent Howard.
22 During this meeting, the Committee will 23 consider the following: Peach Bottom subsequent 24 license renewal; NuScale Source Term Topical Report 25 methodology; Susquehanna Atrium 11 fuel transition and NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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6 1 application/Framatome, and preparation of reports.
2 As reflected in the agenda, portions of 3 the NuScale and Atrium 11 sections may be closed in 4 order to discuss the proprietary information 5 designated as sensitive or proprietary information.
6 There is a phone bridge line. To preclude 7 interruptions of the meeting, the phone will be placed 8 in a listen-in mode during the presentations and 9 Commission discussions. We have received no written 10 comments or requests to make oral statements from 11 members of the public regarding today's session.
12 There will be an opportunity for public comment, as we 13 have set aside 10 minutes in the agenda for comments 14 from members of the public attending or listening into 15 our meeting. Written comments may be forwarded to Mr.
16 Kent Howard, the Designated Federal Official.
17 A transcript of open portions of the 18 meeting is being kept. And it is requested that 19 speakers use one of the microphones in the room, 20 identify themselves, and speak with sufficient clarity 21 and volume, so that they may be readily heard.
22 So, the first topic on the agenda is Peach 23 Bottom Atomic Power Station subsequent license renewal 24 application, and I will turn the meeting over to Matt 25 Sunseri, who is Chairman of the License Renewal NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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7 1 Subcommittee.
2 VICE CHAIRMAN SUNSERI: Thank you, 3 Chairman Riccardella.
4 As Pete mentioned, I'm Matt Sunseri, 5 Chairman of the Plant License Renewal Subcommittee.
6 The purpose of this full Committee meeting 7 is for Exelon Generation Company LLC and the NRC staff 8 to brief the full Committee on the subsequent license 9 renewal application for the Peach Bottom Atomic Power 10 Station's Units 2 and 3. The Plant License Renewal 11 Subcommittee previously met on November 5th of this 12 year to discuss the matter.
13 At the conclusion of these presentations, 14 we will be ready to start our Committee work on letter 15 writing at your pleasure following this briefing. So, 16 anytime after that.
17 There are members of both the NRC and 18 Exelon staff listening in on the phone. So, this 19 reminder about using the microphones is particularly 20 important because they just can't hear us if we don't 21 do that.
22 At this point, I'd like to turn to Meena 23 Khanna to see if she has any opening remarks as well.
24 MS. KHANNA: Thank you. Thank you, 25 Chairman Riccardella and Subcommittee Chairman NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 1 Sunseri, and Members of the ACRS.
2 I am Meena Khanna, Acting Deputy Director 3 of the Division of New and Renewed Licenses, which is 4 DNRL. We sincerely appreciate the opportunity today 5 to present to the ACRS full Committee the results of 6 the staff's review of the second application for 7 subsequent license renewal and which is the first 8 subsequent license renewal application for a boiling 9 water reactor. This application was submitted by 10 Echelon Generation Company LLC for the Peach Bottom 11 Atomic Power Station, Units 2 and 3, located near 12 Delta, Pennsylvania.
13 As Subcommittee Chairman Sunseri 14 mentioned, we had the opportunity to present the 15 results of the review of this application to the ACRS 16 Subcommittee on Plant License Renewal approximately a 17 month ago on November 5th. Subsequently, we issued 18 the updated SER on November 19th.
19 By way of background, Peach Bottom Units 20 2 and 3 received approval for their initial renewed 21 licenses from the NRC on May 7th, 2003. The NRC 22 review at that time was performed using guidance 23 developed prior to the issuance of the Generic Aging 24 Lessons Learned Report, or the GALL report. The NRC 25 developed guidance for review of subsequent license NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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9 1 renewal applications, and it was issued in July 2017 2 as NUREG-2191, also referred to as GALL SLR, and 3 NUREG-2192, SLR SRP, following extensive interactions 4 with the ACRS. The staff performed its review of the 5 Peach Bottom SLR application using these NUREGs.
6 The NRC Project Manager for the Peach 7 Bottom SLR application review is Ms. Bennett Brady, 8 seated behind me. Ms. Brady will introduce the staff, 9 who will be seated at the table, that will be 10 presenting or addressing questions regarding the 11 staff's review of the Peach Bottom SLR application.
12 Part of the management team that are here 13 with me today: to the left is Anna Bradford, the 14 Director of the Division of New and Renewed Licenses.
15 To my right is Eric Oesterle, Chief of the License 16 Renewal Projects Branch. And in the audience are 17 other DNRL and NRR technical review Branch Chiefs and 18 their staffs that have been involved with the review.
19 There may also be some technical staff on the phone.
20 In addition, we are fortunate to have 21 representatives from Region I also on the phone that 22 include Kevin Mangan, Senior Reactor Inspector, as 23 well as Justin Heinly, Senior Resident Inspector at 24 Peach Bottom.
25 The staff will provide an overview of its NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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10 1 safety review which will include a discussion of the 2 confirmatory item related to the core plate rim hold-3 down bolts, which, as we discussed at the ACRS 4 Subcommittee meeting, was closed based on the 5 supplemental information provided by Exelon.
6 Staff will also provide a discussion of 7 the regional inspection of the Aging Management 8 Program implementation for initial license renewal and 9 address the material condition of the Peach Bottom 10 facility.
11 We look forward to a productive discussion 12 today with the ACRS and will address any questions 13 that you may have.
14 At this time, I'd like to turn the 15 presentation over to Mr. Michael Gallagher, Exelon 16 Nuclear Vice President for License Renewal and 17 Decommissioning, to introduce his team and commence 18 their presentation.
19 Thank you.
20 VICE CHAIRMAN SUNSERI: Thank you.
21 And, Mike, one other thing I need to 22 mention is that Members Riccardella and myself are 23 going to recuse ourselves from any discussions on the 24 metal and environmental fatigue issues and radiation 25 embrittlement issues with the reactor pressure vessel NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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11 1 and the sacrificial shield wall. That's just due to 2 some outside business that we've done.
3 Thank you.
4 MR. GALLAGHER: Okay. Thank you, and 5 thank you, Meena.
6 Good afternoon. My name is Mike 7 Gallagher, and I'm the Vice President of License 8 Renewal at Exelon. I have 38 years of nuclear power 9 plant experience, all at Exelon, and have been working 10 on our license renewal project since 2006.
11 Slide 1, please.
12 Before we get into today's presentation, 13 I'd like to introduce the presenters.
14 To my right is Anna Krause, and Anna is 15 our Senior Manager of Design Engineering for Peach 16 Bottom. And Anna has 14 years of nuclear power plant 17 experience.
18 To Anna's right is Paul Weyhmuller, and 19 Paul is our License Renewal Technical Manager for the 20 Peach Bottom project. Paul has 37 years of nuclear 21 power plant experience, including working on Exelon's 22 license renewal project since 2011.
23 And to Paul's right is Julian Laverde, and 24 Julian is our Mechanical Design Manager for Peach 25 Bottom. And Julian has nine years of nuclear power NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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12 1 plant experience.
2 And to my left is Dave Distel, and Dave is 3 our Project Licensing Lead. And Dave has 39 years of 4 nuclear power plant experience.
5 In addition, here in the room we have our 6 technical support personnel, and, also, as mentioned, 7 on the NRC conference line, we have our Peach Bottom 8 technical staff available to answer questions on the 9 conference line.
10 And we also have with us here today Pat 11 Navin, and Pat is our Site Vice President at Peach 12 Bottom.
13 Slide 2.
14 So, this slide shows our agenda for the 15 presentation. This is a similar presentation that we 16 gave the Subcommittee and that we abbreviated somewhat 17 to be focused on the main activities. Included in our 18 presentation, we did include slides that we presented 19 to the Subcommittee meeting as backup material. And 20 again, we can go into any questions that the full 21 Committee may have.
22 We believe we developed a robust, high-23 quality subsequent license renewal application, and we 24 also have developed effective aging management 25 programs to ensure the continued safe operation of NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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13 1 Peach Bottom.
2 We appreciate the opportunity to make this 3 presentation and look forward to answering any 4 questions you may have.
5 With that, I'll turn it over to Anna 6 Krause.
7 Anna?
8 MS. KRAUSE: Thank you, Mike.
9 Slide 3, please.
10 Good afternoon. My name is Anna Krause, 11 and I'm a Senior Manager of Design Engineering at 12 Peach Bottom.
13 Peach Bottom Units 2 and 3 are GE boiling 14 water reactors with Mark I containments that are 15 jointly owned by Exelon and PSE&G and operated by 16 Exelon.
17 The Peach Bottom Station is located in the 18 Commonwealth of Pennsylvania, approximately 40 miles 19 northeast of Baltimore, Maryland, and 60 miles 20 southwest of Philadelphia, Pennsylvania.
21 On the aerial view of Peach Bottom, you 22 can see the power block; the independent spent fuel 23 storage installation pad; the north and south 24 substations; the plant intake and discharge canal, 25 which is the normal heat sink for the station, and the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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14 1 emergency cooling tower, which comprises the emergency 2 heat sink for the station in the event that the normal 3 heat sink is not available.
4 Slide 4, please.
5 Peach Bottom is operated on 24-month 6 refueling cycles. The station capacity factor for 7 2018 was 94.2 percent, and then, year to date through 8 October 31st is 96.2 percent.
9 Our regulatory performance as Peach Bottom 10 is in action matrix column 1 and all ROP indicators 11 are green.
12 Slide 5, please.
13 Now this slide shows the dates for thermal 14 power license changes for Peach Bottom Units 2 and 3.
15 We also show that the independent spent fuel storage 16 installation was installed in 2000. And then, the 17 current license expiration dates are August 8th, 2033, 18 for Unit 2, and July 2nd, 2034, for Unit 3.
19 MEMBER REMPE: Anna, I thought there was 20 a measurement uncertainty recapture in 2002, but it's 21 not shown here. Is that true? The reason I'm asking 22 is because I kind of looked ahead and it might be good 23 for us to clarify that.
24 MR. GALLAGHER: Yes, that's a license 25 recapture.
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15 1 MR. WEYHMULLER: Yes, we did a -- it was 2 called Appendix K in its day, where they did the 3 measurement uncertainty recapture at that point. And 4 then, subsequent to that, you see that we did the EPU 5 modification. With that, the Appendix K mod was taken 6 away, and they did the EPU project, and then, 7 subsequently, followed back up with what was now known 8 as MUR, or the uncertainty recapture, and reinstated, 9 basically, what had been there in the past.
10 MEMBER REMPE: The reason I'm asking is I 11 was involved in the EPU approval, and I remember that 12 earlier letter, but it may come up in our 13 deliberations on the letter today. So, thank you.
14 MR. WEYHMULLER: Okay.
15 MS. KRAUSE: All right. Moving to Slide 16 6, this slide provides an overview of significant 17 plant modifications that have been implemented at 18 Peach Bottom that address component aging and long-19 term operations.
20 Okay. I will now turn it over to Paul 21 Weyhmuller, who will present to you the highlights of 22 our subsequent license renewal application.
23 MR. WEYHMULLER: Thank you, Anna.
24 Slide 7, please.
25 Good afternoon. My name is Paul NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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16 1 Weyhmuller. I'm the Technical Manager for the Peach 2 Bottom license renewal project. I will discuss the 3 highlights of our subsequent license renewal 4 application, focusing on application development, our 5 new time-limited aging analyses, the overall GALL SLR 6 consistency, a review of the aging management 7 programs, the exceptions we have taken, and a summary 8 of the first license renewal aging management program 9 affecting these reviews that have been conducted.
10 Slide 8, please.
11 Exelon used industry and NRC guidance to 12 make our application as consistent with GALL SLR as 13 possible. Our submittal is based on the guidance 14 provided in both NUREG-2191 and 2192.
15 In developing the Peach Bottom subsequent 16 license renewal application, changes noted from first 17 license renewal include:
18 For scoping and screening, we have updated 19 our packages for plant modifications as well as to 20 address NEI 17-01 guidance.
21 For aging management reviews, the first 22 license renewal was pre-GALL. So, additional aging 23 effects required assessment based on NUREG-2191 GALL 24 SLR.
25 For aging management programs, we have 47 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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17 1 programs for subsequent license renewal utilizing the 2 GALL SLR guidance. Activities from first license 3 renewal have been addressed in subsequent license 4 renewal programs.
5 Our aging management programs were 6 developed incorporating lessons learned from previous 7 Exelon projects as well as from benchmarking current 8 industry applications. The aging management programs 9 were also developed using insights from industry RAIs.
10 For time-limited aging analyses, the Peach 11 Bottom subsequent license renewal application has 12 reassessed the existing plant current licensing basis 13 TLAAs. Additional TLAAs for repair or replacement 14 activities not part of the first license renewal 15 application have been added. There are a total of 35 16 TLAAs found in the subsequent license renewal 17 application.
18 MEMBER BLEY: Before you go on, in the 19 core plate replacement -- I may have asked this 20 before, but I'm asking it again -- what was the main 21 difference between Units 2 and 3? Why did 3 need the 22 improvement?
23 MR. WEYHMULLER: There was cracking noted 24 on Unit 3 attributed from early operation. That was 25 thought to be the cause of why there were additional NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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18 1 defects found in that piping system that warranted 2 replacement. It got to be --
3 MEMBER BLEY: And none on Unit 2?
4 MR. WEYHMULLER: That's correct.
5 MEMBER BLEY: Thank you.
6 MR. WEYHMULLER: Okay. Slide 9, please.
7 As stated earlier, Peach Bottom subsequent 8 license renewal application is based on GALL SLR.
9 Peach Bottom aging management review achieved 10 significant consistency with the GALL SLR, as 11 reflected by the fact that 98.6 of AMR line items are 12 covered by notes A through E.
13 There are 50 commitments for the 14 implementation of subsequent license renewal at Peach 15 Bottom, consisting of 47 commitments from the 16 implementation of individual aging management programs 17 and 3 additional commitments for OPEX actions and for 18 the continued use of FERC inspections for specific 19 water-controlled structures. These commitments will 20 be captured within the subsequent license renewal 21 UFSAR supplement, which is contained in Appendix A of 22 the subsequent license renewal application.
23 These commitments are managed in 24 accordance with Exelon's commitment tracking program, 25 which is based on the NRC-endorsed NEI 99-04, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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19 1 "Guidelines for Managing NRC Commitment Changes 2 Process".
3 The table shown on the slide provides a 4 breakdown of aging management programs in regards to 5 consistency with GALL SLR. The summary table also 6 provides a numerical breakdown for existing and new 7 AMPs.
8 There are only 11 programs with 9 exceptions. For each exception, we have provided an 10 alternative to the recommendation found in GALL SLR.
11 Supporting technical justification has been provided 12 and has been found acceptable, as identified in the 13 SER.
14 Slide 10, please.
15 The Peach Bottom aging management program 16 effectiveness reviews assessed first license renewal 17 activities and included a detailed review of 18 inspection schedules, results, and data, as well as a 19 review of relevant operating experience within the 20 corrective action program. All first license renewal 21 programs were determined to be effectively 22 implemented. A summary of each review is found in 23 Appendix B of the subsequent license renewal 24 application for each specific aging management program 25 under OPEX Item No. 1.
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20 1 In November of 2018, the NRC staff 2 conducted an IP 71003 Phase 4 inspection, post-3 approval site inspection for license renewal at Peach 4 Bottom. This inspection found no issues.
5 I will now turn the presentation over to 6 Julian Laverde, who will discuss how we closed the one 7 confirmatory item and a brief summary on the specific 8 technical topics involved in subsequent license 9 renewal.
10 MR. LAVERDE: Thank you, Paul.
11 Slide 11, please.
12 Good afternoon. My name is Julian 13 Laverde, and I am the Site Mechanical Design 14 Engineering Manager at Peach Bottom.
15 There was one confirmatory item involving 16 a commitment for the BWR vessel internals aging 17 management program. Additional information was 18 required by the NRC staff to complete the assessment 19 of the proposed enhancement for core plate rim hold-20 down bolts. This was addressed by revising the 21 enhancement to provide the source document, BWR 25, 22 Revision 1, which was used to determine the 23 appropriate actions to be taken to address stress 24 corrosion cracking of core plate rim hold-down bolts.
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21 1 submittal of a supplement to the NRC staff on October 2 9th, 2019, and the NRC has closed this item, as stated 3 in the updated SER dated November 19, 2019.
4 Slide 12, please.
5 In the Subcommittee meeting, we presented 6 how Exelon addressed the four technical topics related 7 to SLR that were of interest to the NRC Commissioners 8 during the NRC staff preparations for SLR. These 9 topics were discussed in Staff Requirements Memo for 10 SECY-14-0016. The four topics are: RPV 11 embrittlement, IASCC of reactor vessel internals, 12 concrete and containment degradation, and electrical 13 cable EQ and condition assessment.
14 To summarize, we have constructed our 15 aging management programs in these areas to be 16 consistent with the GALL SLR guidance. For example, 17 for RPV embrittlement, we have developed flows 18 projections through SPEO, satisfactorily evaluated 19 reactor vessel material properties through SPEO, and 20 added a commitment to withdraw and test an RPV 21 surveillance capsule for each unit.
22 For IASCC, we have confirmed the 23 acceptability of existing BWR guidelines to manage the 24 aging of reactor vessel internals to SPEO.
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22 1 reported that the concrete and containment at Peach 2 Bottom are in good condition.
3 And finally, the EQ cable and condition 4 assessment, we have updated analysis to show EQ cables 5 have a qualified life greater than 80 years. And we 6 continue to visually inspect and test, per GALL SLR 7 recommendations.
8 I will pause here to see if we have any 9 questions on these topics.
10 (No response.)
11 I will now turn the presentation over to 12 Mike Gallagher for closing remarks.
13 MR. GALLAGHER: Okay. Thank you, Julian.
14 Slide 13, please.
15 This was our summary presentation of what 16 we gave earlier to the Subcommittee. And as I stated 17 before, we developed a comprehensive, high-quality 18 subsequent license renewal application, along with 19 robust aging management programs that will ensure the 20 continued safe operation of Peach Bottom during the 21 subsequent period of extended operation.
22 Pending any questions you may have, this 23 concludes our presentation.
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23 1 a little earlier. So, I'll ask you now, just for 2 completeness, and I'll ask the staff also when it's 3 their turn.
4 But the 71003 Phase 4 inspection, that 5 seems like a significant activity to meet the 6 effectiveness of the aging management program. And to 7 have no findings, how extraordinary is that? I mean, 8 in your experience working with your peers, is that a 9 typical finding or is that an extraordinary finding?
10 MR. GALLAGHER: I mean, there have been 11 several or many Phase 4 inspections done at other 12 sites, and there have been findings, usually a green 13 finding. And in ours, we didn't have that, not to say 14 we didn't get any lessons learned at all from the NRC 15 review. I think the staff, the regional staff did 16 thorough reviews. We had well prepared for it, for 17 the inspection. And we would have initiated any 18 corrective actions for further improvements in our 19 programs, and there were items like that that were 20 identified and acted on. But there were no findings.
21 VICE CHAIRMAN SUNSERI: Yes. I mean, I 22 asked the question because we don't get to go visit 23 the sites and do the detailed reviews. So, we rely on 24 staff's feedback for a lot of our information. We 25 always want to push to make sure that these reviews NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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24 1 are being done with the rigor and technical competence 2 that we need to ensure the regulations are going to be 3 met and that the applicants are upholding their end of 4 the story also. So, this seems like a good news story 5 to me, anyway.
6 MR. GALLAGHER: Yes, I think so.
7 VICE CHAIRMAN SUNSERI: Anyone else?
8 (No response.)
9 All right.
10 MS. KHANNA: So, we'll definitely address 11 that. We've got the regional folks on the phone, and 12 they'll be happy to address a little bit more details 13 of the inspections.
14 Thanks.
15 VICE CHAIRMAN SUNSERI: Thank you.
16 All right. Well, we can swap out then.
17 MS. BRADY: Good afternoon, Chairmen and 18 Members of the ACRS.
19 My name is Bennett Brady. I am the 20 Project Manager for the safety review of the Peach 21 Bottom Atomic Power Station, Units 2 and 3, subsequent 22 license renewal application.
23 As you know from Meena, we are here today 24 to discuss the NRC staff's safety review of the Peach 25 Bottom SLRA, as documented in the Safety Evaluation NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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25 1 Report, or SER, as it's known, which was issued on 2 November 19, 2019.
3 Joining me here at the table is Bill 4 Rogers, Senior Project Manager in the Division of New 5 and Renewed Licenses, or DNRL, who also assisted me in 6 managing the project. In addition, joining us by 7 telephone is Kevin Mangan, Region I, Senior Reactor 8 Inspector, and Jon Greives, Region I, DRP Branch 9 Chief, responsible for Peach Bottom.
10 I would suggest that we ask them, when we 11 get to the end of our presentation, to address your 12 question about how unusual this finding is.
13 Angela Wu, also a Project Manager in DNRL, 14 will be controlling the slides.
15 Seated in the audience and joining us by 16 phone are members of the NRR technical staff who 17 participated in the review of SLRA and conducted the 18 audits.
19 Next slide, please.
20 We will begin the presentation with a 21 general overview of the staff's safety review, 22 followed by an overview of SER Section 2 on scoping 23 and screening; SER Section 3, aging management review, 24 and Section 4, time-limited aging analysis. We will, 25 then, discuss the closure of the confirmatory item, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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26 1 the Region I initial license renewal inspection that 2 coincided with the staff's SLRA review, and the 3 Resident Inspector's perspective on plant material 4 conditions, and then, finally, the summary conclusion.
5 Next slide, please.
6 Peach Bottom Units 2 and 3 were initially 7 licensed in October 1973 and July 1984, respectively.
8 The licensee, Exelon Generation Company LLC, or 9 Exelon, submitted the application for a subsequent 10 license renewal in July 10, 2018.
11 Next slide, please.
12 As you've heard, the Peach Bottom SLRA is 13 the second safety review performed by the staff using 14 the GALL SLR and SRP SLR guidance issued in 2017. The 15 staff's Peach Bottom SLR review was the same as that 16 used for Turkey Point SLRA review. The staff 17 identified and implemented several efficiencies as 18 compared to the safety review of initial license 19 renewal applications.
20 One of these efficiencies dealt with the 21 conduct of audits. Instead of one large and lengthy 22 onsite audit, the staff conducted two standard audits, 23 an operating experience audit, and an in-office audit.
24 The majority of audit activities and breakout 25 discussions were conducted in-office through the use NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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27 1 of portals and telecommunications.
2 During the Peach Bottom operating 3 experience audit, the staff performed an independent 4 review of plant-specific operating experience to 5 identify pertinent examples of age-related 6 degradation, as documented in the applicant's program 7 corrective action program database.
8 During the in-office audit, the audit team 9 first focused on two areas: first, the scoping and 10 screening review and, second, the review of aging 11 management programs, or AMPs; aging management review 12 items, and the time-limited aging analysis.
13 For the Peach Bottom SLRA, the staff 14 review was informed by the results of the Region I 15 initial license renewal inspection, the IP003 Phase 4.
16 This inspection was performed in November of 2018, as 17 has been mentioned, and coincided with the SLRA review 18 timeline. However, it should be noted that the Phase 19 4 inspection is related to the initial renewed license 20 and is independent of the SLRA review. We will 21 discuss this inspection more in detail later in our 22 presentation.
23 Next slide, please.
24 The Peach Bottom SER with a confirmatory 25 item was issued on October 7, 2019. The confirmatory NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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28 1 item was related to the core plate rim hold-down 2 bolts. During the ACRS Subcommittee meeting on 3 November 5, 2019, the staff presented how this 4 confirmatory item was closed on the basis of 5 supplemental information provided by Exelon. Since 6 that meeting, the staff has updated the SER to close 7 the confirmatory item. The updated SER was issued on 8 November 19, 2019, and details of the closure of this 9 confirmatory item will be discussed later in this 10 presentation.
11 During the staff's technical review of the 12 SLRA, it issued 48 RAIs, four of which were followup 13 RAIs. Although this was an early SLRA review, and new 14 topics were reviewed for the 60-to-80-year time 15 period, one might well have expected to have more RAIs 16 than initial license renewal. However, this was a 17 significant decrease in the number of RAIs from the 18 recent initial license renewal application reviews.
19 The staff believes that this was due to the high 20 quality of the subsequent license renewal application.
21 Next slide, please.
22 In the next few slides, we will present 23 the results of the staff's safety review, as described 24 in the SER. SER, Section 2, describes the scoping and 25 screening of structures and components subject to an NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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29 1 aging management review. The staff reviewed the 2 applicant's scoping and screening methodology, 3 procedures, and the results. The staff review 4 included, as required by the license renewal rule, the 5 results of the integrated plant assessment, the 6 safety-related SSCs, non-safety-related SSCs affecting 7 safety functions, and SSCs relied upon to perform 8 functions in compliance with the Commission's 9 regulations for fire protection, environmental 10 qualification, station blackout, and anticipated 11 scrams without a scram.
12 Based on the staff's review, the results 13 from the in-office audit, and review of additional 14 information provided by the applicant, the staff 15 concluded that the applicant's scoping and screening 16 methodology and implementation were consistent with 17 the SRP SLR and the requirements of 10 CFR Part 54.
18 Next slide, please.
19 SER, Section 3, and its subsections, cover 20 the staff's review of the aging management programs 21 for managing the effects of aging, in accordance with 22 10 CFR 54.21(a)(3). Sections 3.1 through 3.6 include 23 the AMR items in each of the general system areas 24 within the scope of license renewal, which is shown on 25 this slide. For a given AMR item, the staff reviewed NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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30 1 the item to determine whether it is consistent with 2 the GALL SLR report. For AMR items not consistent 3 with the GALL SLR report, the staff reviewed the 4 applicant's evaluation to determine whether the 5 applicant has demonstrated there is reasonable 6 assurance that the effects of aging will be adequately 7 managed, so that the intended functions will be 8 maintained, consistent with the current licensing 9 basis for the subsequent period of extended operation.
10 Based on this review, the results from the 11 in-office audit, and additional information provided 12 by the applicant, the staff concluded that the 13 applicant's aging management review activities and the 14 results were consistent with the SRP SLR and the 15 requirements of 10 CFR Part 54.
16 Next slide, please.
17 The SLRA described a total of 47 AMPs, 11 18 new AMPs, and 35 existing. This slide identifies the 19 applicant's original SLRA distribution of these AMPs 20 in the left column and the final disposition, as 21 documented in the SER, in the right column. All of 22 the AMPs, with the exception of the plant-specific 23 AMP, were evaluated by the staff for consistency with 24 the GALL SLR report. As a result of the staff review, 25 the applicant made several changes in the AMPs.
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31 1 However, the distribution of AMPs did not change, as 2 you will see comparing the left column and the right 3 column. The plant-specific AMP was evaluated against 4 the criteria contained in Appendix A1 of the SRP SLR.
5 Based on the staff's review, the results 6 from the in-office audit, and review of additional 7 information provided by the applicant, the staff 8 concluded that the applicant's aging management 9 program activities and results were consistent with 10 the SRP SLR and the requirements of 10 CFR Part 54.
11 Next slide, please.
12 SER, Section 4, identifies time-limited 13 aging analysis, or TLAAs. Section 4.1 of the report 14 documents the staff evaluation of the applicant's 15 identification of applicable TLAAs. The staff 16 evaluated the applicant's basis for identifying those 17 plant-specific or generic analyses that need to be 18 identified as TLAAs and determined that the applicant 19 has provided an accurate list of TLAAs, as required by 20 10 CFR 54.21(c)(1).
21 Section 4.2 and 4.7 document the staff's 22 review of the applicable Peach Bottom TLAAs for the 23 areas shown on this slide. Based on its review, the 24 information provided by the applicant, the staff 25 concludes that either one of three conditions are met:
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32 1 (I) the analysis remains valid for the subsequent 2 period of extended operation; (ii) the analysis has 3 been projected to the end of the subsequent period of 4 extended duration, or (iii) the effects of aging on 5 the intended functions will be adequately managed for 6 the subsequent period of extended operation, as 7 required by 10 CFR 51.21(C)(1).
8 Based on the staff review, the results 9 from the in-office audit, and the review of additional 10 information provided by the applicant, the staff 11 concluded that the applicant's TLAAs analysis and 12 results were consistent with the SRP SLR and the 13 requirements of 10 CFR Part 54.
14 Next, Bill Rogers will assess the closure 15 of the confirmatory item and the Region I activities.
16 Thank you.
17 MR. ROGERS: Thank you, Bennett.
18 Good afternoon.
19 The SER with confirmatory item issued 20 October 7th, 2019, included one confirmatory item 21 associated with the BWR vessel internals AMP B.2.1.7.
22 Specifically, the applicant had proposed an 23 enhancement to perform one of two future activities 24 post-licensing to address the potential for stress 25 corrosion cracking of the core plate rim hold-down NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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33 1 bolts and its mitigation.
2 The first option was to install core plate 3 wedges, which the staff found acceptable. The second 4 option was to submit an inspection plan to the NRC for 5 future review and approval. Since the completed 6 inspection plan as well as the acceptance criteria was 7 not currently available during the staff's SLRA 8 review, that is, it would be developed at a future 9 date, this option did not satisfy the staff's need to 10 complete its technical review prior to granting a new 11 license.
12 In response to the staff's concern 13 regarding the inspection plan, the applicant submitted 14 a supplement to the SLRA which revised the enhancement 15 to AMP B.2.1.7, to be in accordance with BWRVIP 25, 16 Revision 1, to: one, install wedges or, two, install 17 core plate rim hold-down -- excuse me -- inspect core 18 plate rim hold-down bolts, or, three, demonstrate via 19 analysis that the installation of wedges and 20 inspection of the core plate rim hold-down bolts were 21 not required. The staff determined each of the three 22 options included in the SLRA supplement can be 23 confirmed by inspection through the reactor oversight 24 process and were, therefore, acceptable.
25 On the basis of this information, the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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34 1 staff determined that its concerns related to the 2 confirmatory item are resolved, as documented in the 3 November 19, 2019, updated SER.
4 Next slide, please.
5 In conclusion, for the SLRA safety review, 6 the staff finds that the requirements of 7 10 CFR 54.20(a) have been met for the subsequent 8 license renewal of Peach Bottom Units 2 and 3.
9 Next, I'll discuss regional inspections 10 and observations on the plant condition.
11 The Region conducts a license renewal team 12 inspection, IP 71003 Phase 4, 5 to 10 years following 13 the entry into the initial period of extended 14 operation. The team examines a sample of AMPS to 15 verify the effects of aging were being managed 16 effectively to ensure structures, systems, and 17 components in the scope of these programs maintain the 18 ability to perform their intended functions.
19 I'll address the Peach Bottom IP 71003 20 Phase 4 initial license renewal inspection on the next 21 slide. The Peach Bottom IP 71003 Phase 4 initial 22 license renewal inspection was performed in November 23 of 2018 on both Units 2 and 3. Exelon had committed 24 to 35 aging management programs at Peach Bottom for 25 the initial period of extended operation. Seventeen NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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35 1 AMPs were previously existing program in which no 2 changes were required. Twelve programs were 3 previously existing, but were enhanced. And there 4 were six new AMPs created.
5 For the Phase 4 inspection, a sample of 6 six of these AMPs were reviewed. The AMPs listed here 7 on the slide were selected based on inspection 8 procedure criteria such as new enhanced AMPs, AMPs 9 impacted by internal or external operating experience, 10 Resident Inspector input, AMPs not inspected by other 11 baseline inspections, and risk insights.
12 In addition, the staff considered the 13 applicant's periodic AMP effectiveness review, which 14 is performed every five years. The applicant's 15 reports on this activity were used by the staff in the 16 AMP selection process and to provide insights on 17 program performance.
18 The Region's inspection focuses on the 19 program's detection of aging effects, monitoring and 20 trending, corrective actions, and implementation of 21 operating experience elements. The inspection team 22 did not identify any findings and concluded that 23 Exelon that was effectively implementing the AMPs 24 review.
25 Next slide, please.
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36 1 And before we go on, were there any 2 questions on that specific topic related to the 3 earlier question?
4 VICE CHAIRMAN SUNSERI: It just strikes me 5 as, I guess, impressive that an inspection scope so 6 big and of so many technical areas, and you have no 7 findings. I mean, you could look at it, I want to 8 look at as a glass half full; it was a very thorough 9 inspection and they did a good job. Another way of 10 looking at it, though, is you didn't look at it very 11 good and missed something, right? So, that's what I'm 12 trying to figure out.
13 MR. ROGERS: Okay. I'd like us to give 14 the Region an opportunity to address that comment or 15 question.
16 MR. GRAY: Thanks for that.
17 This is Mel Gray. I'm a Branch Chief in 18 NRC, Region I, responsible for oversight of 19 inspections in license renewal. And I have with me 20 Kevin Mangan, and he was a team leader. But I'm going 21 to turn it over to Kevin.
22 My opinion definitely is it was an 23 invasive inspection that demonstrated licensee 24 performance.
25 But go ahead, Kevin.
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37 1 MR. MANGAN: Yes, so for that inspection, 2 as you said, this is Kevin Mangan and I was the team 3 lead.
4 That inspection is a one-week inspection 5 with three inspectors. And as you said, we didn't 6 identify any violations. Of note, it was the first 7 Phase 4 inspection ever done in the United States. We 8 have done a couple since then, one in Region I and I 9 think one in Region II. There may be one or two 10 others.
11 There were some violations identified in 12 other inspections of this inspection, but here and, 13 then, we also did Ginna, and that also identified no 14 finding.
15 MEMBER KIRCHNER: Could I ask a follow-on 16 question then, Bill?
17 I know at the Subcommittee meeting we 18 heard good things about the applicant's preventive 19 maintenance program, particularly with regard to 20 cables. We heard about the diesel generator cables.
21 So, fairly proactive.
22 If my notes are correct, the applicant, 23 they changed out about 100 -- there are about 100 24 medium-voltage circuits and they replaced about half.
25 So, I'm curious why you inspected medium-voltage NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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38 1 cables rather than, say, I&C protection system cables.
2 MR. MANGAN: This is Kevin Mangan again.
3 So, for that particular AMP, a lot of the 4 cables you've mentioned are, for the scope of the AMP, 5 I think there was only 8 or 10 cables in scope. The 6 cables that were replaced were not in the scope of the 7 AMP. They were in the scope of license renewal, but 8 were excluded because they were energized less than 25 9 percent of the time, which was the criteria when they 10 first received their license renewal.
11 So, for the cables we looked at, which is 12 limited scope, they are risk-significant and there 13 were changes to the GALL from -- Peach Bottom was a 14 pre-GALL plant. Through Rev. 1 and Rev. 2, they went 15 from 10-year inspections to seven-year inspections, 16 and that particular requirement that excluded cables 17 that were energized less than 25 percent of the time 18 was removed. So, those are some of the reasons why we 19 looked at that, to see what kind of changes Exelon was 20 making to the program to address the operating 21 experiences of the GALL reports.
22 MEMBER KIRCHNER: Well, if I remember 23 correctly from the Subcommittee meeting, and the 24 applicant and your inspections, going back to the 25 diesel generator cables, those are active less than 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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39 1 percent of the time. And yet, there was a problem 2 there which the applicant addressed and corrected.
3 I'm not sure about that 25 percent of the 4 time. It's still sticking in my mind as not a good 5 criterion to use on cable inspection. So, this is a 6 more generic question than just the applicant.
7 MR. ROGERS: So, I think it might be 8 helpful to have one of the electrical reviewers 9 address the change to the GALL and how that's been 10 modified.
11 MR. SADOLLAH: Yes. Hi. This is Mo 12 Sadollah at NRR, a Design Engineer.
13 So, that provision that was in the 14 previous GALL revision, Rev. 0, subsequently, in Rev.
15 1 and Rev. 2, and then, ultimately, in the SMR, that 16 was removed. So, that 25 percent threshold was no 17 longer there. Whether the cables are energized or 18 not, they're considered in the scope.
19 MEMBER KIRCHNER: That's what I was 20 looking for. So, that's been removed?
21 MR. SADOLLAH: Yes.
22 MEMBER KIRCHNER: Okay. Thank you.
23 MR. SADOLLAH: Yes.
24 MR. ROGERS: Any additional questions on 25 that topic?
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40 1 (No response.)
2 Go to slide 14.
3 Okay. At the ACRS Subcommittee meeting on 4 November 5th, 2019, the Senior Resident Inspector 5 discussed the plant's performance and material 6 condition. The Senior Resident stated that the NRC 7 assessment of Peach Bottom was that the material 8 condition of the plant was acceptable and meets 9 regulatory requirements for systems, structures, and 10 components, based on the inspection results and green 11 performance indicators which resulted in both Peach 12 Bottom units being in the licensee response column.
13 In addition, Resident Inspectors continue 14 to inspect and assess the licensee's ability to manage 15 the effects of aging through the baseline inspection 16 program.
17 And again, if there are any additional 18 questions related to plant material conditions or how 19 this assessment was made, I would offer the question 20 to the Region in that area.
21 VICE CHAIRMAN SUNSERI: I recall the 22 discussion was very good at the Subcommittee. So, we 23 got a really thorough briefing then.
24 MR. ROGERS: Good. Thank you.
25 And considering the NRC inspection NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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41 1 results, the inspectors found that the aging 2 management programs were being effectively implemented 3 in accordance with the facility's renewed license.
4 And the NRC will continue to monitor AMP effectiveness 5 using the baseline reactor oversight process.
6 And if there are no additional questions 7 at this point, I'll turn the presentation over to 8 Bennett for a summary conclusion.
9 MS. BRADY: The NRC has now completed its 10 presentation of its conclusions from the staff's 11 safety review of the Peach Bottom SLRA and the Region 12 I conclusions on AMP inspections and plant license 13 conditions.
14 At this point, we would be pleased to 15 address any further questions that you may have.
16 VICE CHAIRMAN SUNSERI: Any additional 17 questions or comments?
18 MEMBER BLEY: Yes, I have one. This is 19 not related to this particular application, but from 20 the NRC staff side, and the licensee using the new 21 GALL, and your reviews, did you find places where you 22 think you're going to need to make changes to the 23 subsequent licensee renewal GALL? And could you tell 24 us about any of those?
25 MS. BRADY: Yes. Right now, we are just NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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42 1 beginning the process. We've collected a lot of 2 ideas/opinions on changes that should be made to the 3 GALL SLR and SRP SLR. We will be reviewing the 4 proposed changes. At some point in the future, there 5 will be an Interim Staff Guidance with these changes.
6 And they'll likely incorporate -- that would be one 7 that would be considered to be modified.
8 MEMBER BLEY: Okay. Thanks. Any idea 9 when that timeframe will come to pass?
10 MR. ROGERS: That person is sitting behind 11 you.
12 (Laughter.)
13 MEMBER BLEY: Maybe they would like to 14 comment.
15 MR. OESTERLE: Thank you, Bill.
16 This is Eric Oesterle from the NRC staff.
17 So, thanks for the question, Dennis.
18 Back in March of this year, we did have 19 our first SLR lessons learned meeting from reviews of 20 the first three applications to date, and we did 21 identify a number of technical issues which we thought 22 were ripe for considerations and inclusion perhaps in 23 an update to the SLR guidance documents, one of which 24 happened to be an issue regarding irradiated 25 structural steel.
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43 1 So, we have compiled a list of those 2 technical issues, and, in fact, we're having our 3 second SLR lessons learned public meeting on December 4 the 12th. So, we're continuing to engage with the 5 applicants and with industry to address these 6 technical issues that have come up.
7 MEMBER BLEY: Thanks a lot. We look 8 forward to seeing that whenever it comes to pass.
9 VICE CHAIRMAN SUNSERI: Yes. This is kind 10 of a crystal-ball question, but would you anticipate 11 that those improvements would help reduce the number 12 of RAIs coming through the process?
13 MR. OESTERLE: Yes.
14 VICE CHAIRMAN SUNSERI: Because people 15 will know in advance what they should be providing?
16 MR. OESTERLE: Eric Oesterle from the 17 staff.
18 And, yes, that's one of the goals or one 19 of the criteria for identifying some of these 20 technical issues, if not as a new issues, but areas 21 where clarification can be provided. One of the goals 22 is to reduce the number of RAIs.
23 And to address a question that you had, 24 Member Dennis, we're looking, currently looking at 25 whether or not we're going to do an update of the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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44 1 entire document or whether or not we're going to group 2 issues and put them out in three or four separate 3 ISGs. But, tentatively, we're looking at the latter 4 part of next year to start coming out with the drafts.
5 VICE CHAIRMAN SUNSERI: Okay. Any other 6 questions?
7 (No response.)
8 So, while we're opening up the phone line 9 for public comments, I'll turn it to the room and ask 10 if there's any members of the public in the room that 11 would like to make a statement or a comment. Now come 12 to the microphone and state your name and your 13 comment.
14 I can't see anyone.
15 MEMBER BLEY: No, nobody.
16 VICE CHAIRMAN SUNSERI: Okay. Thank you, 17 Dennis.
18 And now, we'll go to the open public phone 19 line for any comments. State your name and provide 20 your comment, please.
21 (No response.)
22 All right. No comments. So, we'll close 23 the phone line again.
24 And I just would like to extend our 25 appreciation to the applicant and the staff for the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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45 1 thoroughness of your review and a very good 2 Subcommittee where we reviewed these in great detail.
3 And now, it makes the full Committee meeting almost 4 seem anticlimactic, which I guess is a good thing, 5 right? So, we did all the hard work and this is the 6 fruit of the labor here.
7 So, thank you all for your comments, and 8 I'll turn it back to the Chairman now.
9 CHAIRMAN RICCARDELLA: Thanks.
10 We're supposed to take a break at 2:30.
11 We have until 2:45 until the next meeting --
12 VICE CHAIRMAN SUNSERI: Yes. So, we have 13 a letter that we could read in, you know, do the read-14 in on. I mean, we could fit it in the 30 minutes.
15 CHAIRMAN RICCARDELLA: Okay.
16 VICE CHAIRMAN SUNSERI: So, are you going 17 to pull that up? Got it. All right.
18 Thank you. You are excused. Thank you.
19 We'll need you again at 2:45.
20 (Whereupon, the foregoing matter went off 21 the record at 1:59 p.m. and went back on the record at 22 2:45 p.m.)
23 CHAIRMAN RICCARDELLA: So, we'll reconvene 24 the meeting.
25 And the subject is NuScale source term, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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46 1 and the lead on this is Dave Petti.
2 MEMBER PETTI: So, we had the Subcommittee 3 -- what? -- two weeks ago, the week in front of 4 Thanksgiving, and discussed a lot of these issues in 5 detail. There was only one area that came up sort of 6 as a questionable one that I believe NuScale will talk 7 about it in a high-level summary, and then, NRC will 8 give a more complete, but a high-level overview, 9 again, because most of us were in the Subcommittee 10 meeting.
11 So, let's start with NuScale.
12 MR. MILTON: Sure. This is Mike Milton.
13 I'm basically going to turn the slides and be here for 14 moral support. Zack Rad, Director of Regulatory 15 Affairs, is going to kick us off from Corvallis. And 16 then, our team in Corvallis will lead the discussion.
17 Okay?
18 Okay. So, I'll turn it over now to you, 19 Corvallis. Is that correct? Please go.
20 CHAIRMAN RICCARDELLA: Corvallis, are you 21 there?
22 MR. MILTON: I heard sound, too. It was 23 very low.
24 Carrie, can you hear us in the room okay?
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47 1 line at the moment.
2 MS. FOSAAEN: Yes. We just need one 3 minute here in Corvallis, if that's all right.
4 CHAIRMAN RICCARDELLA: Okay.
5 MR. MILTON: Okay.
6 MR. RAD: Okay. Good afternoon. This is 7 Zachary Rad, Director of Reg Affairs for NuScale 8 Power. I just have a few opening remarks.
9 Like we discussed at the Subcommittee 10 meeting, we only intend to provide supplemental 11 information on a single topic during this meeting, and 12 not repeat our comprehensive presentation. So, as we 13 discussed in the Subcommittee meeting, one of the 14 topics that came up late in the review of the Accident 15 Source Term Topical Report was associated with 16 postulated leakage from the hydrogen monitoring system 17 coincident with a beyond design basis severe accident.
18 We're going to provide information regarding elements 19 on the topic that hadn't been fully addressed during 20 the Subcommittee meeting to ensure that the record 21 accurately reflects our position.
22 So, as I noted in the Subcommittee 23 meeting, the reason this topic is here for discussion 24 in this forum is because it's a specific item we were 25 unable to reach alignment on with the staff during the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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48 1 review, and the decision has been made to move forward 2 by --
3 (Interference on the public line.)
4 MEMBER REMPE: Excuse me for just a 5 minute, Zack.
6 If you are on the public line, 7 unfortunately, we can hear everything you're saying.
8 So, could we please ask you to mute your phones and we 9 can hear the applicant. Thank you.
10 MEMBER BLEY: Go ahead, Zack.
11 MR. RAD: All right. So, I'm just going 12 to take a few minutes to address our position in 13 summary. Jim Osborn, who's here with me as well, will 14 provide some supporting details.
15 So, as I just noted, late in the review 16 the staff raised some questions regarding the 17 inclusion of some postulated leakage from the hydrogen 18 monitoring system, in addition to a severe or 19 concurrent with a severe beyond design basis accident.
20 And that's specifically estimation of the contribution 21 from operational leakage.
22 It's our position that NuScale has 23 addressed this topic consistent with the applicable 24 regulations and guidance, and specifically, 25 NUREG-0737, and within that, the provisions addressing NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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49 1 control room habitability requirements and integrity 2 of systems outside containment likely to contain 3 radioactive material.
4 It's important that the existent systems, 5 such as the hydrogen monitoring system, and their 6 potential to contain active source term, was 7 considered at the time the guidance was developed and 8 addressed within the guidance.
9 So, the guidance as well as the operating 10 fleet, and all previous applicants, addressed the 11 topic by including these systems in a program to 12 reduce leakage as low as practical. And this is an 13 operating program. So, I think that that's also 14 important to note. It includes testing during 15 refueling outages and a variety of other provisions.
16 NUREG-0737 also addresses systems with 17 known leakage, such as ESF systems, by specifically 18 addressing those, where applicable, and those are 19 addressed within the provisions, specifically control 20 room habitability requirements. It's probably also 21 worth noting that NuScale doesn't have any such 22 systems.
23 So, NuScale addressed the topic in the 24 same manner at the same level of detail, or even a 25 greater level of detail, than previous applicants.
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50 1 It's our position that there's no material difference 2 in the NuScale design that makes existing guidance 3 insufficient or diminishes the applicability of 4 precedence. It's also important to note that, for 5 NuScale, this is not a safety concern; it's not a 6 design or a licensing basis issue for NuScale. It's 7 just a matter of reasonable assurance; that is, that 8 the guidance and precedent for design -- following 9 guidance and precedence for a design with lower 10 associated risk is sufficient for reasonable 11 assurance.
12 So, with that, that's my summary. If 13 there aren't any questions, I'm going to turn it over 14 to Jim to address some supporting elements in more 15 detail.
16 MR. MILTON: Yes, we can proceed.
17 MR. RAD: All right. Thanks.
18 MR. OSBORN: Good afternoon. This is Jim 19 Osborn.
20 So, I want to preface the presentation and 21 say that the purpose of the presentation is to convey 22 the fact that NuScale has designed out a core melt 23 scenario, and therefore, there is no design deficiency 24 related to the hydrogen monitoring system. This was 25 discussed in the earlier meeting a couple of weeks NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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51 1 ago.
2 The first slide here talks about risk 3 significance. So, the core damage frequency of the 4 NuScale power module is very small. The sum of the 5 internal events has a core damage frequency of on the 6 order of 3E to the minus 10 module critical years per 7 year. This is a significant margin of about five 8 orders of magnitude to the NRC's safety goal.
9 So, accidents in which hydrogen monitoring 10 could be used, i.e., those that have an intake 11 containment that results in core damage, are even a 12 lower frequency, on the order of E to the minus 11.
13 But, even with a significant increase in consequences, 14 the overall risk still remains small, considering the 15 frequency of these events is so small. You see the 16 equation up there for risk.
17 And I will quote from the last bullet on 18 the slide. It says, "In any licensing review or other 19 regulatory decision, the staff should apply risk-20 informed principles when strict, prescriptive 21 application of deterministic criteria is unnecessary 22 to provide reasonable assurance of adequate protection 23 of public health and safety." This quote is from the 24 SRM for SECY-19-0036, which was entitled, "Application 25 of the Single Failure Criteria to the NuScale's NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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52 1 Inadvertent Actuation Block Valves".
2 But this directive should also be applied 3 to other deterministic criteria like hydrogen 4 monitoring system leakage. The core melt sequences in 5 which hydrogen monitoring could even be utilized, 6 i.e., there's an intact containment, can be considered 7 negligible and, therefore, not risk-significant.
8 Therefore, to provide reasonable assurance of adequate 9 protection of the public health and safety, this 10 incredible sequence would not need to be considered in 11 a review using proper application of risk-informed 12 principles.
13 Next slide, please.
14 The systems used for hydrogen monitoring 15 are included in the leakage monitoring program. This 16 program is one of the post-TMI action items that is 17 intended to minimize the potential leakage from 18 systems outside containment that may contain actual 19 source term. NuScale is in compliance with this 20 regulation. The implementation of this program 21 ensures that these systems are essentially leak-tight 22 and are available for use post-accident.
23 The seismic aspects of the next bullet 24 will be addressed in a later slide. So, next slide, 25 please.
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53 1 But what if it's hypothesized 2 deterministically that the hydrogen monitoring system 3 does leak? There would be subsequent emergency 4 response actions to isolate that leak. The 5 particulars of this action would be the responsibility 6 of the emergency response organization as an unplanned 7 and unanticipated emergency action, for which there 8 are no explicit dose acceptance criteria.
9 Recently, just two weeks ago, the NRC 10 stated in the Brunswick SER for hardened vents that, 11 "For plant personnel performing emergency response 12 actions during a beyond design basis severe accident, 13 there are no explicit dose acceptance criteria." The 14 only purpose for the NuScale hydrogen monitoring 15 system is for a beyond design basis severe accident.
16 Therefore, the 5-rem limit of 10 CFR 50.34(f)(2)(vii) 17 does not apply to the operator action of re-isolating 18 the containment isolation valves used in hydrogen 19 monitoring.
20 Next slide.
21 Based on the nuclear industry's low risk 22 from severe accidents, which are even lower for the 23 NuScale design, the NRC relaxed the regulatory 24 requirements for hydrogen monitoring. As a severe 25 accident monitoring system, it is not required to be NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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54 1 safety-related or Seismic Cat 1 because there is no 2 design basis accident that involves the hydrogen 3 monitoring system.
4 So, for the NRC staff to compare NuScale's 5 non-safety-related, non-seismic, Cat 1 design of a 6 hydrogen monitoring system to other designs that are 7 safety-related or Seismic Cat 1, is not commensurate 8 with a risk-informed review. It is not appropriate 9 for the NRC to relax requirements based on the risk 10 significance and, then, penalize a design by 11 deterministically presuming it will leak because it is 12 non-safety or not Seismic Cat 1.
13 This application of risk significance is 14 evident in the guidance provided in Reg Guide 1.183 15 related to offsite dose consequences for hydrogen 16 purge operations for severe beyond design basis 17 accidents. For the NRC to require NuScale to 18 deterministically account for hydrogen monitoring 19 system leakage runs counter to the application of its 20 risk significance and does not reflect a risk-informed 21 review.
22 Are there any questions?
23 MEMBER MARCH-LEUBA: Yes, this is Jose.
24 Can you clarify something for me? The hydrogen 25 monitoring system is non-safety grade and it is NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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55 1 connected to the containment evacuation system, is 2 that correct?
3 MR. OSBORN: So, yes, the hydrogen 4 monitoring system is made up of three different 5 systems: the containment evacuation, the sample 6 system, and the core flood and drain. They are 7 connected to the containment through containment 8 isolation --
9 PARTICIPANT: I'm on this call and I can't 10 hear anything from the actual meeting.
11 MR. OSBORN: The containment isolation 12 valves are safety-related.
13 MEMBER KIRCHNER: Can you wait a moment?
14 We're having a problem.
15 PARTICIPANT: I can hear you talking now, 16 but I can't hear the ACRS meeting apparently.
17 CHAIRMAN RICCARDELLA: No, this is the 18 ACRS meeting room. I think what you're not hearing is 19 the NuScale remote call-in. So, we're trying to 20 address that right now.
21 PARTICIPANT: Oh, okay.
22 CHAIRMAN RICCARDELLA: Steve, can you hear 23 me? Steve Schultz?
24 DR. SCHULTZ: Yes. Yes, Pete.
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56 1 hear NuScale talking from Corvallis?
2 DR. SCHULTZ: That's correct. Whenever 3 you go to the phone line, we can't hear. The same 4 thing happened in the Peach Bottom meeting.
5 CHAIRMAN RICCARDELLA: Okay. We're trying 6 to work on it.
7 Mike, are you there?
8 DR. CORRADINI: I am here.
9 CHAIRMAN RICCARDELLA: And you can hear 10 Corvallis, too?
11 DR. CORRADINI: At this moment I can only 12 hear you.
13 CHAIRMAN RICCARDELLA: Yes, because 14 they're not talking right now.
15 (Laughter.)
16 But, when they were talking, you could 17 hear?
18 DR. CORRADINI: Yes, I could, sir.
19 CHAIRMAN RICCARDELLA: Are you on the 20 closed line or the public line?
21 DR. CORRADINI: The closed line.
22 CHAIRMAN RICCARDELLA: Okay. I think the 23 other people who are having problems are on the public 24 line, not the closed line.
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57 1 it again. Corvallis, this is Jose March-Leuba.
2 So, I was trying to confirm that the 3 hydrogen monitoring system is connected to the CES, 4 and you were describing the three systems that are 5 interconnected.
6 MR. OSBORN: Yes, that's correct. Yes, 7 that's correct.
8 So, to understand, the hydrogen monitoring 9 system is portions of three systems. So, it's not in 10 itself its own system. It's just a pathway utilizing 11 three different systems.
12 MR. MILTON: Okay. Hang on a second, Jim.
13 So, it's a pathway utilizing three 14 different systems, and the hydrogen monitoring system 15 is actually a portion of three systems.
16 MEMBER MARCH-LEUBA: But all of those 17 three systems are downstream of the containment 18 isolation valves, which is the last safety-grade 19 system that protects containment on a safety-grade 20 basis, is that correct?
21 MR. OSBORN: I believe that's correct, 22 yes.
23 MEMBER MARCH-LEUBA: All right.
24 MR. MILTON: We believe that's correct.
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58 1 the probabilities or the frequencies might be 10 to 2 the minus 11, but giving the operator the temptation 3 to open the isolation valves for the containment to 4 measure the hydrogen because he's suspects that it's 5 hydrogen, it's counterproductive. I mean, you should 6 never under any circumstance open the isolation valves 7 if you suspect that the containment is contaminated.
8 So, in my opinion, we have two options.
9 We can just not have a hydrogen system or connect the 10 hydrogen system that works. Because connecting the 11 system to the CES and the third system, which I don't 12 know what it is, which none of them are seismically-13 qualified, you are asking for trouble.
14 MR. OSBORN: So, I understand that they're 15 not seismically-qualified, they're not Seismic Cat 1, 16 they're not safety-related. That's because the NRC 17 relaxed the regulatory requirements on this system 18 based on its risk significance. So, NuScale did not 19 do this on their own. They did this in response to 20 the NRC regulations.
21 MEMBER MARCH-LEUBA: Okay. So, we will 22 talk to the staff here in person.
23 Sorry, can you relay for the public?
24 MR. MILTON: Oh, sure. The answer is it's 25 we understand that our system was designed because the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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59 1 NRC relaxed the requirements based on the risk 2 significance. We understand your point, but we feel 3 our design was justified, per the regulations.
4 MEMBER MARCH-LEUBA: Yes. In my 5 opinion -- and I will take care of this with the staff 6 -- the hydrogen system the way it's designed is 7 producing more problems than it solves. Because if 8 you ever need it, you are going to de-isolate the 9 containment.
10 MEMBER PETTI: So, let's ask the question 11 and the staff may know. Current PWRs, is the hydrogen 12 monitoring system safety-grade or non-safety-grade?
13 We can wait for the answer until staff speaks.
14 MS. FOSAAEN: Okay. I was going to say 15 Reg Guide 1.7 provides the requirements for hydrogen 16 monitoring systems, and our system followed Reg Guide 17 1.7, and it does specify that it does not need to be 18 safety-related.
19 MEMBER PETTI: Okay. Thank you for that 20 information.
21 MR. MILTON: So, to repeat, our design, 22 per Reg Guide 1.7, does not require the system to be 23 safety-related, and we followed the design per the Reg 24 Guide, to repeat that.
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60 1 the staff when we can actually communicate.
2 MR. MILTON: I understand. Thanks.
3 MEMBER PETTI: Any more questions?
4 MEMBER REMPE: Okay. So, I have a 5 question that stems from what was discussed at the 6 Subcommittee meeting, that comes from the source term 7 evaluation. And it was discussed in the open session.
8 And I'd like to bring it up again to NuScale because 9 I think we dismissed something I was trying to raise 10 last meeting prematurely. Okay? So, I want to give 11 them the opportunity to respond.
12 When you did your source term, you looked 13 at small break LOCAs; you looked at rod ejection 14 accidents. And as the release is coming from the 15 vessel, you know, the depressurization occurs, I 16 mentioned some concerns about some aerosols that might 17 be going out into the containment that would interfere 18 with that wonderful radar-based sensor for water level 19 detection.
20 And NuScale came back and said, hey, we 21 won't have degradation; we're only worried about 22 design basis events here, and the iodine spike came 23 from that.
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61 1 about. And that occurs before you have core 2 degradation. And so, I'd like to bring that up again, 3 that there is the potential that there could be some 4 aerosols released into the containment, and the ECCS 5 is triggered when the water level gets to a certain 6 height, and that could interfere with the triggering 7 of the ECCS.
8 And so, I'd like to hear NuScale's 9 response back again on that question.
10 MEMBER BROWN: Would the aerosols be any 11 different than the normal foaming you get from the 12 boiling in the upper area? Because that's the 13 pressurizer. So, you've got a steam-water interface 14 there that gives you the same issues relative to 15 whatever detector you're worried about, which I'm 16 aware of, as any injected or introduced aerosols would 17 be due to something else. I mean, they've got to make 18 the system work at this steam-water interface where 19 all these bubbles -- and you've got to compensate for 20 that. I mean, everybody that builds these things has 21 to compensate for it, like 30 percent. It's not a 22 half-a-percent error thing.
23 MEMBER REMPE: The staff has defined an 24 ITAAC that talks about pressure conditions, radiation 25 conditions, et cetera. There's nothing in there about NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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62 1 dispersed aerosols. And so, yes, it would be 2 different than just a foamy thing. You could have 3 depressurization occurring and they could be elevated.
4 There's uncertainty on what those aerosols would be 5 like, but it's something that the staff has raised for 6 PWRs.
7 MEMBER BROWN: But if they're in the upper 8 part, as opposed to part of the surface steam 9 interface --
10 MEMBER REMPE: They don't have to be in 11 there.
12 MEMBER BROWN: -- that would be a 13 different issue --
14 MEMBER REMPE: Yes.
15 MEMBER BROWN: -- relative to the 16 disturbing of the thing.
17 MEMBER REMPE: Absolutely.
18 MEMBER PETTI: Just to be clear, the fuel 19 aerosols, this is pieces of fuel, right?
20 MEMBER REMPE: Right.
21 MEMBER PETTI: These would be fairly 22 large.
23 MEMBER REMPE: No, not necessarily. If 24 you looked at some of the pictures of fuel 25 fragmentation and dispersant from the tests --
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63 1 MEMBER PETTI: When you call them 2 "aerosol," it sounds like they're pieces of metal.
3 MEMBER REMPE: It's not pieces of metal.
4 They're fine fragments.
5 MEMBER PETTI: Fines of -- fine micron?
6 MEMBER REMPE: I'd have to go back and 7 look at some of the reports, but they looked pretty 8 small. And they could be elevated just like the 9 sediment, or whatever they talked about that they 10 artificially --
11 MEMBER PETTI: They're really particulate 12 dust?
13 MEMBER REMPE: It could be, yes, 14 particulates that are elevated.
15 MEMBER PETTI: Not aerosol necessarily?
16 MEMBER REMPE: Yes. And so, again, it 17 could be particulates.
18 So, anyway, I'm waiting for NuScale to 19 respond back to the question again.
20 MR. MILTON: So, this is Mike. I have to 21 repeat back the responses. So, just kind of break up 22 a little bit and give me a moment to be able to relay 23 the information because of the phone line issue going 24 on.
25 Back to you guys, Jim, Carrie.
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64 1 MEMBER REMPE: Has the connection been 2 lost?
3 MEMBER BROWN: NuScale?
4 MR. OSBORN: Could you give us a second, 5 please?
6 MEMBER BROWN: Oh, okay.
7 MR. MILTON: Yes, let me know. Let me 8 know.
9 MR. OSBORN: All right. Just a moment.
10 (Pause.)
11 MEMBER REMPE: You know, they don't have 12 to answer like right now because I'd like the staff to 13 also weigh-in on it, and they could perhaps answer 14 later, instead of just waiting here.
15 MR. MILTON: That's fine.
16 MEMBER REMPE: Is that okay with you?
17 CHAIRMAN RICCARDELLA: Hey, guys, can we 18 have one meeting, please?
19 MEMBER KIRCHNER: So, Joy, for 20 clarification, are you asking whether the particulate, 21 whatever comes out of the core, is going to actually 22 deposit upon the sensor and interfere with its 23 performance, or it's dispersed in the atmosphere and 24 it's going to impact the performance of the radar?
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65 1 fact that radar -- and we can say it's a radar-based 2 sensor. That's in the open now, but --
3 MEMBER KIRCHNER: Then, the issue isn't 4 fuel aerosol particulate; it's how it performs in the 5 fog and steam.
6 MEMBER REMPE: Right. Well, but fog with 7 particulates.
8 MEMBER KIRCHNER: Okay, but you're looking 9 for a hard interface and a water level, and it's not 10 likely that -- I'm not going to answer the question 11 for NuScale. But, based on my experience with radar 12 systems, fog and steam is not going to impact its 13 ability to find a hard object or an interface.
14 MEMBER REMPE: But this is not just fog 15 and steam. It could be particulates. You've seen 16 pictures of what happens --
17 MEMBER KIRCHNER: Yes, but it's still my 18 understanding that --
19 MEMBER REMPE: -- with the fuel that way.
20 It's oxidized cladding.
21 MEMBER KIRCHNER: Yes, but you're not 22 going to have that much fuel dispersed.
23 MEMBER REMPE: We don't know that.
24 MEMBER BROWN: If you'll go look at some 25 of the designs of radar-type detectors for this, they NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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66 1 talk about a frothy steam-water interface --
2 MEMBER KIRCHNER: Right. Yes, that's more 3 of an issue, but that's independent of having any 4 particulate.
5 MEMBER BROWN: Put aside the particulate, 6 okay?
7 MEMBER KIRCHNER: Yes.
8 MEMBER BROWN: That you have to have 9 compensation for.
10 MEMBER KIRCHNER: Right.
11 MEMBER BROWN: And I think they're 12 advertising a fairly decent accuracy for it, like 1 13 percent or a half a percent or 2 percent. I don't 14 remember the number. I read it at one time. So, 15 Joy's concern about that, basically the steam-water 16 interface, and then, the particulate thing comes in as 17 a secondary relative to the --
18 MEMBER REMPE: But the staff has taken 19 great pains to have ITAACs that identify the 20 characteristics that have to be validated.
21 MEMBER BROWN: No, I understand that.
22 MR. OSBORN: So this is NuScale if you 23 guys are ready.
24 Right. So we've taken a look. And we 25 don't have this level of detail yet because it hasn't NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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67 1 been defined yet in the EQ program, but the EQ program 2 does require that we identify the specific environment 3 in which the instruments are required to operate in.
4 And there are a lot of variables here including 5 whether or not it's a plausible scenario to have 6 significant core melt at the time that the instrument 7 would be required to operate and then evaluate whether 8 or not the equipment would operate in that 9 environment, if required.
10 So the program has to define those 11 attributes and then determine whether or not the 12 equipment is qualified to operate then. And that's 13 where we are. So we don't have the answer to your 14 specific question.
15 MEMBER REMPE: Let me be real clear. This 16 is before you get core melt. This is something that 17 -- that's how you deterred me a couple of weeks ago 18 and I thought about it some more and it's like no, 19 it's operations. Some of the cladding becomes 20 oxidized and that's something that's been discussed in 21 the LWRs and now we are trying to deal with what 22 happens with a design basis accident and I'm not 23 talking about core melt. And the staff has been very 24 specific about what you've got to qualify that since 25 before and I'm probing about maybe the staff did add NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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68 1 another piece to that. Okay?
2 MR. OSBORN: Right, so the fundamental 3 tenants of my answer still apply, that the environment 4 in which they're qualified to operate and has to be 5 defined at that level of detail and it hasn't yet been 6 done.
7 MEMBER REMPE: But the staff has radiation 8 levels. They've got humidity levels. They've got a 9 bunch of temperatures. They've got a bunch of 10 requirements.
11 Yes, so I'll probe with the staff, but 12 anyway, I appreciate us discussing it now. Thank you.
13 CHAIRMAN RICCARDELLA: Let me just do a 14 check now.
15 Steve Schultz, are you hearing the full 16 conversation now?
17 DR. SCHULTZ: Yes, we are. It seems as if 18 it's fixed.
19 CHAIRMAN RICCARDELLA: Okay. Thank you.
20 MEMBER PETTI: Any other questions for 21 NuScale? Okay. Thank you. Time goes fast. Thank 22 you.
23 (Pause.)
24 MR. TESFAYE: Are you ready for us?
25 MEMBER PETTI: Yes, go ahead.
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69 1 MR. TESFAYE: Thank you. Good afternoon, 2 everyone. My name is Getachew Tesfaye. I am the NRC 3 Project Manager for NuScale's topical report on 4 accident source term and the TR as you know describes 5 a general methodology for developing accident source 6 terms and performance corresponding design base 7 accidents and other required accident radiological 8 consequence analysis to be referenced for NuScale's 9 Small Modular Reactor and other applications are 10 referenced in NuScale's SMR.
11 The NRC staff submitted an advanced 12 topical report evaluation to this committee on October 13 18 and presented its finding to the NuScale 14 Subcommittee on November 20 of this year.
15 Today, we will present the high-level 16 summary of the staff's findings with a focus on a 17 couple of items we took from the subcommittee meeting.
18 Jason, here to my right, and I will be 19 making presentation. The rest of the staff are 20 sitting in the audience and will be ready to answer 21 any question you have.
22 So topical report positions to NuScale and 23 NuScale requested a profile of 15 specific positions 24 listed in Section 1.2 of the report. And NRC staff 25 has determined that subject to the conditions and NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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70 1 limitations specified in Section 6 of the SER, the 2 methods described in the topical report are acceptable 3 for developing accident source terms and performing 4 accident radiological consequence analysis to be 5 referenced by the NuScale SMR design.
6 The staff approved positions 2 through 15 7 requested in topical report. The staff did not make 8 any finding of position 1 where NuScale categorizes a 9 core melt accident as beyond design basis event. And 10 the applicable NRC regulations do not require 11 classification of source terms of design basis or 12 beyond design basis to demonstrate compliance as a 13 requirement.
14 Therefore, the staff has determined that 15 the classification of a core melt accident as a beyond 16 design event for the NuScale design is not material 17 with staff's findings under this regulation.
18 Therefore, the staff did not make a finding on 19 position 1.
20 With that, I'll go to Jason to present one 21 takeaway from the subcommittee meeting, that is the 22 staff's independent analysis.
23 MR. SCHAPEROW: So one thing that the 24 staff did as part of its evaluation of NuScale's 25 topical report methodology was to perform an NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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71 1 independent analysis. This was to evaluate NuScale's 2 core damage event and their analysis of that and the 3 off-site consequences resulting from that.
4 Our approach was to use MELCOR. We used 5 MELCOR to simulate two scenarios, two core damage 6 scenarios. One was a CVCS line break inside 7 containment and the other was a failed open reactor 8 vent valve. In both of these scenarios, we assumed 9 that the ECCS failed to function properly.
10 So we used MELCOR. We calculated the 11 fission prior release into the environment for the two 12 scenarios and we took each of the two MELCOR results 13 and we put them into RADTRAD to turn them into a dose.
14 We predicted EAB, LPZ, and controlling doses and we 15 used this independent evaluation to compare against 16 what the applicant had come up with. And the doses 17 were comparable and also they were below the 18 regulatory dose criteria.
19 So this is -- again, this is one thing 20 that we did as part of our evaluation.
21 Next slide, please?
22 So the documentation is a little bit 23 complicated and in case the committee would like to go 24 into a little more detail on this. So the MELCOR 25 calculations themselves that the staff did are NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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72 1 documented in the report from April of this year.
2 It's listed at the top of slide 7.
3 We actually did calculations for three 4 scenarios in this report. The third scenario was a 5 bypass accident which wasn't used for the topical 6 report review. The reason we did these three 7 scenarios was to help the staff understand the 8 behavior of the NuScale reactor under severe accident 9 conditions and we also did a number of comparisons 10 against NuScale results for severe accident 11 simulations.
12 The second report listed here is -- we 13 took the MELCOR output from the two scenarios that 14 were in containment, had in containment releases, not 15 to bypass accident, and again, we turned those into 16 doses using standard -- using our RADTRAD model. So 17 the second report documents in further detail the 18 MELCOR results, MELCOR releases to the environment, 19 release two scenarios, and it also explains how the 20 releases were used in RADTRAD to calculate doses.
21 MEMBER PETTI: Just to be clear, you only 22 took two of them for the dose stage.
23 MR. SCHAPEROW: That's correct. The third 24 one was a bypass accident. We didn't take that 25 through the dose stage.
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73 1 MEMBER REMPE: So during our subcommittee 2 meeting, there was some confusion, but I was looking 3 at the correct report and although ACRS had looked at 4 it previously, but looked for a different reason to 5 support the PRA. And if I look at that report from 6 MELCOR, there are a lot of postulated reasons on why 7 there were differences in the result, whether it was 8 nodalization, where you assume the break was.
9 Do you have any -- now that you've had 10 since I think it was April when it was issued and you 11 had more time to think about it, do you have any 12 strong feelings on why there was so many differences?
13 Because I think the actual doses were a factor of 2 to 14 3 off. They were low, like by this earlier latter 15 stage that you probably applied, but there were some 16 significant differences in the report.
17 MR. SCHAPEROW: Yes, so I've thought about 18 -- so there's no -- because it's an integrated 19 calculation, there's not really -- it's very 20 difficult, it's very, very difficult to tease out 21 exactly what factors are dominating, driving the 22 differences.
23 There's a couple, in my mind, there's a 24 couple of obvious differences. If we could explore 25 just a little bit. One was the assumption of five NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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74 1 percent of the iodine was vapor that NuScale had made.
2 Another one dealt with a containment leak rate and the 3 NRC was calculating higher leak rates. So this is 4 some of -- maybe the bigger differences. There were 5 some differences between the NuScale calculations and 6 the staff calculations.
7 MEMBER REMPE: And even the code was 8 different is what I had heard in the past, that you 9 had different versions of MELCOR --
10 MR. SCHAPEROW: Yes --
11 MEMBER REMPE: -- being made.
12 MR. SCHAPEROW: So our comparison of our 13 MELCOR severe accident simulation against NuScale 14 severe accident simulation in the first document you 15 see on the slide, there were some differences, but 16 standing back the staff -- we don't feel the 17 differences were significant enough to affect these 18 kinds of calculations.
19 MEMBER PETTI: But in terms of the leak 20 rate, as I recall, NuScale just assumed a leak rate.
21 They didn't let the pressure determine the leak rate.
22 You guys used the actual pressure of the --
23 MR. SCHAPEROW: So NuScale had a technical 24 specification leak rate that they used in their 25 analysis. We did -- I think it was done classically NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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75 1 for many, many years which is to take the tech spec 2 leak rate and convert that into a hole size, a very, 3 very small hole, but convert that into a hole size and 4 then use that for the MELCOR simulation.
5 MEMBER PETTI: If the pressure goes 6 higher, then you get greater leak.
7 MR. SCHAPEROW: That's correct. And also, 8 if the materials -- if the gases in the containment 9 are different, you're going to get a different leak.
10 So NuScale's tech spec leak rate was based 11 on pressurizing the containment to err at a thousand 12 pounds. So we did that with MELCOR. We pressurized 13 NuScale's containment to a thousand pounds and we set 14 the hole size so that we got the 2 percent per day 15 leak rate, I'm sorry, .2 percent per day leak rate.
16 And then -- but that was it. We set the leak rate and 17 then we ran our MELCOR severe accident simulations.
18 And we ended up getting time variant leak rates, 19 exactly.
20 Actually, at one point the leak rate went 21 the other way, actually started going into the NuScale 22 containment because in a NuScale accident before you 23 start the heat up and generate hydrogen, you've got a 24 vacuum in there. So you actually -- actually, at one 25 point you draw a vacuum just before you get to the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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76 1 core damage stages.
2 MEMBER PETTI: For the benefit of the 3 other members, it was not presented at the 4 subcommittee, but in the report, NuScale compared 5 STARNAUA the aerosol code they used in the containment 6 against MAEROS which is the subroutine inside MELCOR.
7 And they were on top of each other. So I think the 8 aerosol physics is the same in the two codes and it 9 has something to do with bounding conditions and 10 initial conditions in terms of the differences.
11 MR. SCHAPEROW: In my mind, two of the big 12 differences again was in one case NuScale had -- I 13 would characterize that as a conservative approach for 14 the amount of iodine vapor that's going to be sitting 15 in containment hour after hour after hour. But on the 16 other hand, we also were calculating a time dependent 17 leak rate which in some cases went above the .2 18 percent per day per leak rate that NuScale had 19 assumed.
20 So again, the calculations were different.
21 We did an independent calculation and to the best of 22 our ability to predict what would be leaving the 23 containment and we said fed that into RADTRAD.
24 MEMBER REMPE: I have one question that 25 I'd love to ask you just now and get it over with and NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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77 1 not close the meeting, but there's been a sentence in 2 this report that I tried to ask at the subcommittee 3 meeting, but we were in an open and I was told it was 4 the wrong version.
5 I would like to close it because it 6 doesn't make sense and it may be a typo. But I am 7 curious on what the sentence is and I'm afraid to say 8 it aloud in the open session, so let's -- if we can 9 have a brief closed session, if you don't mind.
10 MEMBER PETTI: If it's only on the staff's 11 confirmatory, that can't be in the open session?
12 MEMBER REMPE: Well, there's some numbers 13 in it. I sure would love to, but I'm afraid I'll get 14 in trouble, so I don't know what to do.
15 MR. SCHAPEROW: Are you referring to the 16 second report here?
17 MEMBER REMPE: No, the very first report, 18 there were some hours that are cited and I don't know, 19 the document is marked proprietary, so I don't know.
20 I have been curious about it for the last month or so 21 and I'd like to have my curiosity satisfied.
22 MR. SCHAPEROW: There is a public version 23 of the first document. I don't know if you --
24 MEMBER REMPE: I did not have that. I was 25 only given the proprietary one. I could try and read NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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78 1 it without the numbers, but I don't think it will make 2 much sense to you, so if you don't mind, just close 3 and ask you the question. Thank you. Go ahead.
4 MR. TESFAYE: Any additional questions to 5 Jason?
6 MEMBER BLEY: Joy, were you saving your 7 question about --
8 MEMBER REMPE: I think I have to until we 9 close the --
10 MEMBER BLEY: No, I mean the hydrogen one 11 you were asking --
12 MEMBER REMPE: Oh, you mean about the 13 aerosols and the seal crack mutation one?
14 MEMBER BLEY: Yes, and I was a little 15 surprised NuScale said what they did. It sounds like 16 they're saying you have to give the environmental 17 conditions under which it has to work, but it would 18 seem to me they should have set that up and should 19 have addressed the issue you raised about particulates 20 out there.
21 In any case, you heard the discussion. Is 22 there anything you guys can say about that issue?
23 Either the issue itself or whether that might --
24 somehow you're setting the environmental conditions 25 under which the detector has to work.
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79 1 MEMBER REMPE: There's a later slide that 2 I was going to ask that part on and I don't know if 3 Jason is the right person or not.
4 MR. SCHAPEROW: I have not been involved 5 at all.
6 MEMBER REMPE: Slide 8 is a good place to 7 ask it.
8 MR. TESFAYE: So I'm going to go over some 9 of the high level conclusions we made in terms of all 10 of the chapters that were impacted by the accident 11 source term in the topical report.
12 One of the things the environmental 13 qualifications the staff finds acceptable to use 14 iodine spike source term methodology and the 15 environment has qualification dose methodology 16 described in Appendix B of the topical report for 17 calculating one of that qualification, the doses 18 inside containment and under the bioshield.
19 We also give a detailed discussion of the 20 equipment survivability when core damage was not 21 assessed for EQ. Certain equipment associated with 22 the containment integrity and combustible gas 23 monitoring is designed to function to withstand core 24 damage events. Qualitative assessment testing and all 25 additional analysis may need to be performed to ensure NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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80 1 equipment survivability. And this evaluation is 2 performed in Chapter 19 of the SER.
3 MEMBER REMPE: So here's where I was going 4 to ask, the discussion about my concerns about fuel 5 fragmentation and dispersal. I know this was not the 6 primary focus, the radar base sensor wasn't the 7 primary focus of this chapter. But do you have any 8 thoughts about maybe that somebody needs to add 9 something to that list of environmental conditions for 10 this --
11 MR. TESFAYE: I don't know if we have the 12 right people here in the audience.
13 MEMBER REMPE: I kind of expected what 14 happened.
15 MS. GRADY: This is Anne-Marie Grady with 16 NRR. And aerosols and fuel fragments are not 17 specified under the conditions of equipment 18 survivability neither in SECY 90-016 or 93-087.
19 NuScale didn't provide that information and we didn't 20 ask a question about it.
21 MEMBER REMPE: So again, you understand my 22 concern and I'm sure that the guidance didn't think 23 about this because it's a different design. The 24 guidance wasn't written for it. So I just think it's 25 another -- we've raised issues about this since or NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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81 1 before in our letters and it's another thing that came 2 to light during this discussion.
3 MR. TESFAYE: Thank you. The other 4 related topic that we discussed in the subcommittee 5 was the post-accident sampling exemption request and 6 it's related to the topical report.
7 The regulation requires that applicants 8 provide the capability to promptly obtain normalized 9 post-accident samples from the reactor coolant system 10 and containment atmosphere.
11 Since equivalent information to that 12 provided by the sampling is provided by other means 13 such as radiation monitors, under the bioshield, core 14 exit thermal couplers, and hydrogen and oxy monitors.
15 The staff determined that a post-accident 16 sampling need not be required. Therefore, the staff 17 approved the exemption request for post-accident 18 sampling for the NuScale design.
19 MEMBER MARCH-LEUBA: Wait, let's clarify.
20 MR. TESFAYE: Okay.
21 MEMBER MARCH-LEUBA: First, why do you say 22 need not be required? Do you mean it's not required?
23 MR. TESFAYE: Yes, that's probably it.
24 It's not required. We have other means to gather the 25 same information as we could get from that --
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82 1 MEMBER MARCH-LEUBA: Did NuScale ask for 2 an exception not to have a hydrogen system?
3 MR. TESFAYE: No, they did not. In fact, 4 they used the hydrogen monitoring to justify this 5 exemption request.
6 MEMBER MARCH-LEUBA: This goes back to 7 what I was trying to explain before. If you connect 8 your hydrogen monitoring system downstream from the 9 safety isolation valves of the CES, in order to 10 operate the hydrogen system, you need to open up the 11 containment.
12 MR. TESFAYE: Yes.
13 MEMBER MARCH-LEUBA: To a whole bunch of 14 non-safety related components. If the equipment -- I 15 mean in operating plans you have a hydrogen monitoring 16 system which is non-safety related, but is connected 17 to the safety-related containment. I mean what the 18 design levels as defined is equivalent to opening of 19 the containment to the turbine building and then 20 measuring the hydrogen inside the building which would 21 be completely crazy.
22 By connecting the hydrogen monitoring 23 system to a CES and whatever the second component is, 24 you are telling the operator, if you suspect there is 25 a severe accident, the isolated containment and send NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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83 1 all that contamination to these three non-safety 2 related systems.
3 If we don't think a hydrogen monitoring 4 system is needed, they should not have one. The 5 operator should not be tempted to open the 6 containment.
7 MR. TESFAYE: Okay. I'll defer that to my 8 colleague, Anne-Marie.
9 MS. GRADY: This is Anne-Marie Grady again 10 from NRR.
11 The means of hydrogen and oxygen post-12 accident monitoring is established by a closed loop.
13 Containment atmospheric sample is taken by opening the 14 CIV in the containment evacuation system, sending it 15 past the two-line monitor for both hydrogen and oxygen 16 back through the containment flooding and drain system 17 back to the containment. So unless it leaks, it's not 18 released to any other environment. It's a closed 19 loop.
20 Severe accident mitigation is the reason 21 why we needed to have hydrogen and oxygen monitoring 22 and for severe accident mitigation, none of this has 23 to be safety related.
24 MEMBER MARCH-LEUBA: The hydrogen loop, 25 hydrogen monitoring loop doesn't need to be safety NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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84 1 related.
2 MS. GRADY: Does not.
3 MEMBER MARCH-LEUBA: But you're connecting 4 it to the containment operation system which is a two-5 inch -- or four-inch pipe with a valve, with a pump 6 that goes all the way outside to the support building 7 and comes back and all of it is non-safety qualified.
8 I think that by opening the isolation 9 valves to the containment into that CES system, you 10 are creating more problems than you're solving.
11 MS. GRADY: So you're concerned that 12 they're leaving the system by some other means.
13 MEMBER MARCH-LEUBA: The only reason you 14 can have a severe accident if you have a really bad 15 day.
16 MS. GRADY: Yes, sir.
17 MEMBER MARCH-LEUBA: And most of these are 18 seismic and that CES is going to be broken. I mean 19 you're worried about leaking from the high-level 20 leakage just a one-eighth inch line which is probably 21 -- and you have this four-inch line with a big pump 22 with seals. You are venting -- the containment 23 bounding becomes the CES bounding.
24 MS. GRADY: Because it's not safety 25 related, required to be safety related and in fact, it NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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85 1 was not safety related. We don't have to postulate a 2 further accident.
3 MEMBER MARCH-LEUBA: In operating the 4 reactor the rule was written for, you connect the 5 high-level system to a safety-related containment, so 6 you're only ever creating hydrogen through your 7 hydrogen monitoring system.
8 In the design proposal of NuScale, you are 9 -- the isolated containment surrounding the CES which 10 is a lot of a system with pumps, seals, vents and 11 you're flooding that with all of the contamination 12 from the containment in order to sample hydrogen.
13 You're making the problem worse. I really don't know.
14 MS. GRADY: I don't follow that scenario 15 as to how it makes --
16 MEMBER MARCH-LEUBA: CES has a valve, has 17 a vacuum pump.
18 MS. GRADY: Right.
19 MEMBER MARCH-LEUBA: And seals with 20 components when it reaches, safety goes up.
21 MS. GRADY: The CES --
22 MEMBER MARCH-LEUBA: You are dumping all 23 the containment environment, the containment 24 atmosphere with all those aerosols and iodine, you're 25 putting it on your vacuum pump which is up there on NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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86 1 the operating floor in order to measure hydrogen.
2 MS. GRADY: When we un-isolate the CES 3 portion of that closed loop, the CES system isn't 4 operating.
5 MEMBER MARCH-LEUBA: But it's open.
6 MS. GRADY: Once we open the containment 7 isolation valve it is, yes.
8 MEMBER MARCH-LEUBA: Yes, so you're 9 dumping all of the containment environment --
10 MS. GRADY: It's flowing through a closed 11 loop flow path.
12 MEMBER MARCH-LEUBA: No, into all of it, 13 it's in vacuum. It will fill it up with iodine and 14 astringent.
15 MS. GRADY: The containment atmosphere 16 will be in that closed loop, I agree.
17 MEMBER MARCH-LEUBA: Not the closed loop, 18 the CES.
19 MS. GRADY: I don't think the CES system 20 is open to any --
21 MEMBER MARCH-LEUBA: You just opened it.
22 MS. GRADY: -- any open path from the CES 23 portion of the line we're using. I don't believe it 24 is. I'll double check on that.
25 MS. BRADFORD: This is Anna Bradford from NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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87 1 the staff. Is this a question that really should be 2 directed to NuScale and the design in terms of why 3 it's designed this way?
4 MEMBER MARCH-LEUBA: I think if we have 5 reached the conclusion that the hydrogen system is not 6 needed --
7 MS. BRADFORD: We have not reached that, 8 no.
9 MR. STUTZCAGE: This is Ed Stutzcage.
10 I'll try to clarify it for the NRC.
11 So the exemption that NuScale has is an 12 exemption from physically taking grab samples, taking 13 them to a lab to analyze it. And as part of their 14 exemption to not need to take grab samples, they 15 credited the hydrogen and oxygen monitors, so the 16 monitors, you know --
17 MEMBER MARCH-LEUBA: It's a different 18 exemption.
19 MR. STUTZCAGE: It's a different 20 exemption. The exemption is just physically grabbing 21 the material and analyzing it in a lab. They still 22 have the requirement to monitor, have the monitor --
23 had it monitored.
24 MEMBER MARCH-LEUBA: But do you understand 25 what I'm saying that in order to operate the hydrogen NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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88 1 sampling system, you need to open up the containment 2 isolation valve and then the containment radiation 3 aggregate into a CES system which is a vacuum pump, 4 it's a HEPA filter. It's a tower. You're putting all 5 the junk, the containment, in the containment, you're 6 sampling and you're putting it on the floor of your --
7 that is not reasonable.
8 MR. STUTZCAGE: Right, and NuScale hasn't 9 requested an exemption from the 5044 hydrogen and 10 oxygen monitoring requirement and that's where our 11 concerns in radiologic rates protection comes from 12 where you're doing this, you're operating the system 13 and they haven't demonstrated an ability to re-isolate 14 the system and they haven't analyzed leakage --
15 MEMBER MARCH-LEUBA: They can re-isolate 16 the isolation valves to take a sample, but all the 17 iodine and the strontium and it's already in the pump 18 and the HEPA filter.
19 MR. STUTZCAGE: Right. To us, they never 20 provided us any assurance that they could re-isolate 21 the system.
22 MEMBER MARCH-LEUBA: You have the valves in 23 there.
24 MR. STUTZCAGE: Go ahead, Ron.
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89 1 is that they can open some of the valves from the 2 control room. They may have to go out to the skids 3 which are located in the 100-foot, 126-foot elevation 4 and manually open some of the other valves.
5 When they go to isolate the system, it's 6 the same thing. They can isolate some of them from 7 the control room, one pair of them, but not the other 8 pair. So they have to physically go out to the skids 9 and push the buttons.
10 Where the staff has some concern is that 11 the amount of leakage that you use to get from the 12 system to cause a problem for people trying to access 13 those valves is not the pipes falling off. The 14 analysis that the staff did was using .3 CFM -- I 15 think it was -- I'm going off of memory here so it's 16 close to 30 rem to the control room operator. So it 17 was a significant dose.
18 So that led us to believe that there would 19 be issues for personnel trying to access this area 20 even under the exposure -- elevated exposure 21 authorization.
22 MEMBER MARCH-LEUBA: My claim is whatever 23 leak rate you assume from operating this closed loop 24 hydrogen monitoring system, multiply times a hundred 25 because all of the leakage from the CES system.
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90 1 MR. LAVERA: We were counting on the 2 activity in containment from the core damage event 3 going out into all these three systems and the total 4 leakage from all these three systems being .3 CFM. So 5 that's how we did our analysis of the --
6 MEMBER MARCH-LEUBA: -- so we're assuming 7 this is a normal system --
8 MR. LAVERA: We were looking at that.
9 MEMBER MARCH-LEUBA: -- is still intact.
10 MR. LAVERA: So now the -- yes, and we 11 agree with you that there's going to be seals and 12 stuff, valves, interfacing valves that are going to 13 leak, so we understand this. So we don't agree with 14 the characterization that you would have to have a 15 pipe break causing those problems.
16 We believe that if you do have a leak from 17 the system that you may not even be able to isolate 18 the system under the plan's special exposure provision 19 to Part 20, never mind the 5 rem limits of Part 20.
20 We believe that if you do have a leak from the system 21 from leakage rates on the order of .3 CFM that you do 22 present a challenge to the public health and safety.
23 And this also impacts the LPZ zone is what we call it.
24 And then it also impacts the control room operator 25 dose.
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91 1 So in part of our review that started on 2 this question back on March of 2018, we were asking 3 NuScale to tell us, hey, what is the maximum and 4 allowable leakage rate that you could tolerate from 5 this system and not challenge the dose to the control 6 room and the offsite? Can you isolate the system by 7 doing this manual actuation? Can you safely send 8 somebody in to the area? What's the maximum dose that 9 you can get from that?
10 We have not been able to get an allowable 11 leakage value from NuScale. They don't have the 12 ability to isolate this from the control room without 13 sending somebody out to the field. So this is the 14 reason the staff has concerns about this.
15 MEMBER MARCH-LEUBA: We were also told 16 that to open those valves, the containment has to be 17 below 200 psi in order to bypass.
18 MR. LAVERA: And they have to go out to 19 the skid to do it. Now you wouldn't have a vacuum.
20 After a couple of days, you will not have a vacuum in 21 containment. You will be at 60 pounds, I think, just 22 from the normal stuff going on. And over the course 23 of the accident, it can go up to 160 pounds.
24 MEMBER MARCH-LEUBA: And all those 160 25 pounds of dirt are going to move into the CES system NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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92 1 the moment you open those valves.
2 MR. LAVERA: So my understanding is and 3 Anne-Marie, you're welcome to correct me if I 4 misspeak. The people responsible for containment 5 integrity in the hydrogen monitoring have determined 6 that hydrogen monitoring is required.
7 NuScale has put in for an exemption 8 request from that. So from a radiation protection 9 perspective which leads us how do you know a valve 10 leak will result in having this activity in this 11 system. That's weighted against leakage criteria that 12 represent a potential challenge to the control room 13 operator and members of the public and anybody that 14 would have to go in there and manually shut the 15 system. So if it's the only way you have to go in 16 there and shut the system, if you do determine that 17 you have enough leakage that's causing problems to the 18 control room or offsite dose, send somebody out there 19 to push a button.
20 MEMBER MARCH-LEUBA: I made my point. The 21 last time I will interrupt. Either the hydrogen 22 system is required or it is not, but if it is 23 required, how we need from a non-safety grade large 24 system full of valves, seals, pumps, HEPA filters, 25 connected to the exhaust power, all non-safety grade.
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93 1 And that's my opinion.
2 Is it required, is it not required? If it 3 is required, collect it like the operating plants do 4 to the containment.
5 MS. GRADY: Dr. March-Leuba, it is 6 required. It is part of NuScale's design and we've 7 accepted it.
8 MEMBER MARCH-LEUBA: But the argument I'm 9 making is if it is required, the design is defective.
10 MS. GRADY: The guidance --
11 MEMBER MARCH-LEUBA: They're making the --
12 CHAIRMAN RICCARDELLA: Excuse me just a 13 second. Everyone needs to speak up louder because 14 Corvallis can't hear what we're saying. Okay? Get 15 closer to the mic and speak up.
16 MEMBER MARCH-LEUBA: Okay, this is 17 equivalent to an operating plant, so it wants to 18 sample the high-level in containment and you still are 19 sampling the containment, they put the sample in the 20 turbine building. And to sample the hydrogen, they 21 open up the valves so the containment was in the 22 turbine building and then they measure the hydrogen in 23 the turbine building. I mean you would consider that 24 ludicrous, right?
25 MS. GRADY: Yes.
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94 1 MEMBER MARCH-LEUBA: But this is what 2 we're doing here. We are opening up to the CES system 3 which is a non-safety grade, vacuum pumps, HEPA 4 filters, connected to the tower, which may or may not 5 have isolated and you dump all your dirt into there 6 and then you sample the CES. It's the same thing as 7 dumping it in the turbine building. It's crazy.
8 MEMBER DIMITRIJEVIC: Well, Jose, we can 9 address this also as a part of PRA because it's a 10 matter of containment isolation during the accident, 11 and if this actually means guaranteed containment 12 bypass. With some accidents, that shouldn't be the 13 case. So we should really -- I mean I made the note 14 for myself to look into this because it seems like you 15 will have an accident and you're going to bypass 16 containment which is against the plan and the 17 additional containment probability failure is less 18 than one because it definitely in seismic cases is 19 going to be point something. So the thing is that we 20 have to look what does that mean from the containment 21 condition of failure probability the safety plan.
22 MEMBER REMPE: So Jose, you keep bringing 23 this up to the staff and what can they do? If 24 somebody comes in to a design, what regulatory hook 25 could they use?
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95 1 MEMBER MARCH-LEUBA: They can tell them 2 that this is not good enough.
3 MEMBER REMPE: What regulation are they 4 breaking is where I'm kind of going? I know you tried 5 to get the NuScale folks to do something about it and 6 they didn't want to, so what do you do with the 7 regulator?
8 MEMBER MARCH-LEUBA: The thing is the 9 operator is more than 5 rem, you push a button, so 10 therefore this design doesn't work. That's what I'm 11 getting at.
12 MS. BRADFORD: This is Anna Bradford from 13 the NRC. I think what you're saying is you think it's 14 not a good idea for those systems to all be connected.
15 That's what I'm hearing you say, right?
16 NuScale came in with this design. We 17 evaluate it. They were able to meet our regulations 18 except for where they requested exemptions and it was 19 fine. Like you said, it's not our job to say you 20 know, we don't think this is the best design. It 21 would be better if we designed it this way and I don't 22 know if that's even true, but that's really not our 23 responsibility.
24 MEMBER REMPE: It's why they've got this 25 carve out which may be difficult to meet, but they've NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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96 1 got a carve out. I mean I get what you're saying.
2 It's kind of like I don't what I'd do if I was in 3 staff's position.
4 MEMBER MARCH-LEUBA: What I would do is 5 have them give me a probability of failure of the CES 6 system in a severe accident event. The CES system --
7 MEMBER DIMITRIJEVIC: I mean they will not 8 meet safety goal if this is an inability to fail for 9 an accident, definitely. So that's why they would 10 call that.
11 MEMBER BLEY: Well, it's also not so much 12 what can the staff do about it. We advise the 13 Commission. If we really think this is a problem and 14 the regulations don't cover it, then it's up to us to 15 raise it to the Commission and say for this new kind 16 of design it ought to be there. I'm not saying I'm of 17 that opinion, but that is a way for us to proceed.
18 MEMBER KIRCHNER: Can I recap where we 19 might be? And that is the applicant has asked for an 20 exemption from post-accident sampling. Is your 21 granting that because they can provide equivalent 22 information by sampling by other means? So one is 23 radiation monitored under the bioshield. That will 24 tell you something. Core exit thermocouples. And 25 then hydrogen and oxygen monitors.
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97 1 Now specifically then this system would be 2 necessary --
3 MR. TESFAYE: Absolutely --
4 MEMBER KIRCHNER: -- to support your 5 exemption.
6 MR. TESFAYE: Absolutely.
7 MEMBER KIRCHNER: And then the issue is 8 what dose would be at risk for the operators to 9 operate the system and then to isolate it?
10 MR. TESFAYE: Yes, to open the 11 containment, I think we have evaluated that.
12 MEMBER KIRCHNER: Notwithstanding the .3 13 CFM leak rate and the containment evacuation system, 14 what's the dose just in the pipe from the piping when 15 it's filled with all of the containment atmosphere?
16 Do you have a ballpark number for that?
17 MR. STUTZCAGE: I don't think we have 18 that. We only reviewed the dose to un-isolate the 19 system and --
20 MEMBER KIRCHNER: Yes, I think that's what 21 was presented by Anne-Marie and the staff. You 22 proposed a leak rate and then there's a dose 23 associated with that. If the system doesn't leak, 24 what is the dose? There will be dose.
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98 1 won't be -- first of all, NuScale's proposal is if the 2 system doesn't leak you don't change anything, you 3 just let it go, and we're okay with that. There's no 4 need to go out there and re-isolate the system.
5 If you have a leak, it's most likely that 6 the airborne cloud around the area is going to be the 7 major dose driver. We didn't do that because NuScale 8 didn't specify a maximum allowable leakage rate, so we 9 didn't do the dose calculation for that specific area 10 and there's other issues that were keeping us from 11 trying to do that calculation.
12 We were able to do the calculation for the 13 control room dose and the LPZ and those calculations 14 led us to believe that it could be a significant 15 problem for public health and safety.
16 MEMBER KIRCHNER: Well, I think Jose has 17 eloquently stated the design concerns that we have, 18 that you open up -- you bypass containment, open up a 19 large, I believe that line is four inches to 20 penetration. And that is a concern from the design 21 standpoint. Although we're not here to re-design the 22 system. We stated that in our subcommittee meeting.
23 MEMBER BLEY: We must have written a 24 letter on the SER with open items on Chapter 9. Did 25 we raise this back then? Is it in our letter?
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99 1 MEMBER MARCH-LEUBA: Probably not.
2 MEMBER KIRCHNER: I don't know that that 3 detail was available then. It may have been and we 4 just didn't cover it.
5 DR. CORRADINI: Can I ask a question? I 6 want to make sure that the two line requirements are 7 both short-term monitoring and long-term monitoring or 8 just short term?
9 MS. GRADY: Continuous, long-term.
10 DR. CORRADINI: And so long term is 11 defined within 30 days. So short term is of no 12 consequence to the staff. It's the long-term 13 monitoring that's --
14 MS. GRADY: For this particular change, 15 Dr. Corradini, the hydrogen and oxygen monitoring has 16 to be established by 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. Before then, the 17 containment integrity is not challenged, even if there 18 is combustion in the containment.
19 Long term, we looked at and NuScale looked 20 at up to 60 days and there's a potential challenge 21 again due to the fact that there's radiolysis around 22 45 to 54 days, but that's long term.
23 DR. CORRADINI: Okay, just so -- let me 24 repeat. I want to make sure I'm clear about the 25 regulatory requirement. The regulatory requirement is NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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100 1 they must establish hydrogen monitoring before 72 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />.
3 MS. GRADY: They must establish it and 4 they have shown us that they don't need to do it 5 before 72. Seventy-two is not in the regulation.
6 DR. CORRADINI: Okay, excuse me. I'm 7 sorry. Thank you. Thank you for clarifying my point.
8 And then once established, then according 9 to regulation, it must be maintained continuously 10 after that --
11 MS. GRADY: Yes.
12 DR. CORRADINI: Or intermittently?
13 MS. GRADY: No, continuously after that.
14 Practically speaking, it could be intermittent if that 15 were an operationable decision, but the regulation is 16 continuous.
17 DR. CORRADINI: Okay. Thank you.
18 MS. GRADY: You're welcome.
19 DR. CORRADINI: Thank you, Anne-Marie.
20 MEMBER PETTI: So my question is the 21 source term is where at 72 hours in these 22 calculations? These calculations of source term is 23 weighed out. All the aerosols have settled. The 24 steam is condensed. So what source term did you use 25 in your analysis? Because your big peak, I'm with NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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101 1 you, but I think there's a timing offset here that 2 might be important.
3 MR. SCHAPEROW: So just to maybe throw out 4 a fact idea, so NuScale's assumptions for their source 5 term topical is that 5 percent remains airborne 6 forever, at least for 30 days.
7 So that might be the source of -- I can't 8 speak for Michelle Hart. Unfortunately, she's not 9 here today. There is an assumption, a conservative 10 assumption in NuScale's topical report in the area of 11 iodine vapor.
12 MEMBER REMPE: And Dennis, because it may 13 come up later this week with respect to the letter on 14 Chapter 9, one of our conclusions was there were 15 potentially risk-significant items in NuScale's 16 design that are not yet fully developed. So these 17 items, requirements to be included in the DCA to 18 ensure that the licensee's plant will perform as 19 credited.
20 So we didn't call out this particular 21 item, but we acknowledged that we were uncertain about 22 a lot of aspects in the plant design.
23 MEMBER BLEY: And there's a lot of parts 24 to Chapter 9.
25 MR. TESFAYE: Okay. Thank you.
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102 1 DR. CORRADINI: There's silence again. May 2 I get another clarification point just to be clear?
3 So it's NuScale's contention that they 4 don't -- that their design will meet the requirement 5 if they can be exempt from long-term monitoring? I 6 want to make sure I understand what the exemption is 7 that is being requested. I'm sorry that I'm going 8 over old ground.
9 MEMBER PETTI: No, I think to be clear 10 there's an exemption from physical sampling. They 11 actually need the hydrogen and oxygen monitoring to 12 support the exemption. Have I got it?
13 MS. GRADY: That's my understanding of it.
14 DR. CORRADINI: And then NuScale has gone 15 further to say that they can go in an un-isolate and 16 re-isolate if necessary with operator action. Am I 17 understanding that correctly?
18 MR. STUTZCAGE: This is Ed Stutzcage at 19 the NRC. They provided information to show that they 20 can un-isolate the system. They have not provided 21 information to the NRC to demonstrate that they can 22 re-isolate the system.
23 They have indicated that that's something 24 that will be handled as part of their emergency 25 action, if necessary. They didn't say -- respond, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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103 1 they don't have to provide that information to the 2 staff at this time.
3 DR. CORRADINI: Okay, thank you. Thank 4 you for the clarification, I appreciate it.
5 MR. TESFAYE: Okay. Thank you. I think 6 we have discussed this, this slide --
7 PARTICIPANT: Just a little.
8 MR. TESFAYE: -- the last 15, 20 minutes, 9 so I'm not going to go over that. So I will jump 10 straight to what the subcommittee requested us to 11 present at this meeting, which is the proposed 12 recommendation to the rulemaking.
13 I am not going to read this. This is out 14 of the Chapter 12 SER. I am just going to highlight 15 the areas where we are going to focus. Specifically, 16 10 CFR Part 52, Appendix 2, which is not there yet, 17 that will be the NuScale SMR appendix.
18 Under issue resolution we will state the 19 design and evaluation of leakage from combustible gas 20 monitoring loop is not considered but it was in the 21 meaning of 52.63 which is with respect to the finality 22 of the standard design.
23 And then in Section 14, Additional 24 Requirements, it will be stated a COL applicant is 25 responsible for providing sufficient design NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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104 1 information demonstrating that the requirements of 10 2 CFR 50.34(f)(2)(xxv)(8) are met with respect to 3 potential radiation release under accident conditions 4 from systems used for post-accident hydrogen and 5 oxygen monitoring.
6 So this is what we are recommending, and, 7 again, I note this is not the proposed rule language.
8 This is what is in the SER. The rule language has not 9 yet been developed yet.
10 So as an example on the next slide I give 11 you two carve outs, as we call, carve outs of 12 recommendation. This is from the design specification 13 rule for ESBWR design an applicant for COL include as 14 part of its application.
15 One of them is for the hurricane loads in 16 excess of total tornado loads and hurricane- generated 17 missile loads, so on the structures this was not part 18 of -- It was in the design specification a scope, but 19 it was not done so they carved out or they included 20 this in the rulemaking.
21 And the other one is similar to what we 22 are doing here, that's the spent fuel pool level 23 instrumentation was not fully developed in the design 24 specification rule.
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105 1 this kind of information in 2-1 Chapter 4 under 2 interface requirements with an ITAC and that would 3 have an easier way to go but the applicant chose not 4 to include this language in the Tier 1 interface 5 requirement.
6 So the staff is kind of forced to do this 7 rule carve out in the design specification rulemaking.
8 So this is, again, the takeaway from the subcommittee 9 meeting.
10 There was other items that was requested 11 of us. Chapter 12 which had all this recommended 12 rulemaking language, we gave you the draft of that and 13 when we issued the final there was some change to the 14 draft and we have provided the compare and contrast 15 between the draft and what the final one.
16 The major difference is the ventilation 17 system fire dampers, which is the second item here.
18 Obviously we didn't have enough information. The 19 ventilation dampers were not closing on high radiation 20 monitor.
21 The staff looked at the risk and they said 22 the primer is to operator or equivalence of 23 operability involves core damage event with a failure 24 of the ventilation's exhaust fans as well as an open 25 bay exhaust damper, so all these three things have to NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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106 1 happen.
2 And before we issue the final SER for 3 Chapter 12 we made a finding on this although the 4 design did need something in order to be fully 5 responsive to the staff's questions.
6 It wasn't, but the staff took the risk 7 approach and whatever to make a finding on this. So 8 we have two rule carve outs, one is the penetration 9 shielding design, which is the first bullet, and we 10 have discussed that at subcommittee, and the other one 11 is the leakage issue that we discussed earlier.
12 MEMBER BLEY: And up on Slide 11 where you 13 started this rulemaking discussion the rule would 14 state that the COL applicant is responsible for --
15 MR. TESFAYE: Providing the information --
16 MEMBER BLEY: -- providing the information.
17 (Simultaneous speaking.)
18 MR. TESFAYE: -- information, and making 19 sure the regulations are met in terms of those.
20 MEMBER BLEY: Okay.
21 MR. TESFAYE: Or, you know, design a means 22 to re-isolate the containment. So if you don't have 23 any questions on this, I think we've discussed this at 24 length, we'll go to the conclusion.
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107 1 developing accident source terms and performing 2 accident radiological consequence analysis to be 3 referenced by NuScale SMR design.
4 All phase three SER open items related to 5 the accident source term methodology have been closed 6 except those involving penetration shielding and the 7 leakage from hydrogen/oxygen monitoring system.
8 They are not considered resolved and must 9 be addressed by the COL applicant. And that's all we 10 have.
11 MEMBER KIRCHNER: May I go to the first 12 one then. When you push of, pardon my phraseology, 13 the responsibility for the radiation shield wall 14 design to the COL, I'm trying to think through the 15 implications of that.
16 The applicant has a nominal design for the 17 shield blocks and so on. If it turns out, and I'll 18 just do this rhetorically, that twice as much 19 shielding is needed to meet whatever the dose criteria 20 are that has implications that ripple through the 21 design, simple things like the building, the main, the 22 reactor building crane operations, et cetera, and 23 potential dose during refueling operations, et cetera.
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108 1 you talk through that?
2 MR. LAVERA: So this is part of the 3 reason that we went down this path is we wanted to 4 make sure that this got designed appropriately.
5 We recognized that the potential 6 interactions of the shielding that they would have to 7 install, it's equivalent to five feet of concrete over 8 what appears to us to be a fairly large area, so we, 9 too, are concerned about that.
10 We tried to work with NuScale to determine 11 several ways of addressing it within the scope of the 12 application without having physical design information 13 there.
14 The only way we could reach a safety 15 finding on this was to do a carve out, so that's why 16 we went down that path.
17 MEMBER BLEY: Well I said this at the 18 subcommittee meeting, but putting this off on the COL 19 -- Well, I'm not NuScale, but if I were this would 20 make it a lot harder to deal with potential customers 21 when they look at this and say, hey, I got to make 22 this work after I commit to this design. It just 23 seems a bad place to leave things.
24 MEMBER KIRCHNER: Yes. I am thinking 25 through the ramifications, because, pardon the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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109 1 digression, but if I remember right the initial 2 lifting mechanism for moving the modules was to kind 3 of strap on to two solid anchors, take it up.
4 Then I believe that changed so that the 5 upper frame then connected to the module and became 6 the lifting point and the interactions of that design, 7 which may be in FLEX, I'm not sure where that design 8 came out, and the shielding are, there is important 9 ramifications there as they change that in terms of, 10 as you labeled this, large penetrations in the shield 11 wall and others.
12 So have you looked at that at the latest 13 iterations on that upper lifting design and the 14 ramifications for radiation protection?
15 MR. LAVERA: Okay, so, yes, we have been 16 looking at that shield block on the top of the module 17 bay. This shielding is not anywhere near that. It 18 won't interact with that particular issue, particular 19 thing.
20 MEMBER KIRCHNER: Right.
21 MR. LAVERA: So I understand where you are 22 coming from, but there is absolutely no interaction 23 between those two.
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110 1 structural loading, structural analysis for components 2 in structures outside of the module bay wall on the 3 100-foot and out.
4 So it's not the module shield that's on 5 top that you lift with a crane and move it around.
6 MEMBER KIRCHNER: So it's more the 7 penetrations into the reactor building?
8 MR. TESFAYE: Yes.
9 MR. LAVERA: So, yes, that's a closer 10 approximation to it.
11 MEMBER KIRCHNER: Okay.
12 MR. LAVERA: It's between the power module 13 bay and the rest of the reactor building.
14 MEMBER KIRCHNER: Thank you.
15 MEMBER PETTI: Any other questions?
16 MEMBER REMPE: Well I wanted to --
17 MEMBER PETTI: I know that though. Do we 18 ask for public comment around?
19 PARTICIPANT: Yes.
20 PARTICIPANT: Yes, we do, and we have some 21 --
22 (Simultaneous speaking.)
23 MS. FOSAAEN: This is NuScale Corvallis if 24 I could just make a quick statement with regard to the 25 shielding. I just want to clarify that the shielding NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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111 1 that we have not provided is just the shielding around 2 piping penetrations in the ventilation.
3 The rest of the information and what we 4 have provided is consistent with the level of 5 information provided by previous applicants.
6 So, you know, we're talking about what 7 material goes around the piping equivalent and we did 8 provide a COL item that said the shielding that would 9 be provided in those penetrations around the piping 10 would be equivalent to the dose rate maps that were 11 provided as part of the DCD.
12 So we had provided, in fact, with that COL 13 item more than previous applications.
14 MR. LAVERA: So this is Ron Lavera. You 15 know, I have been involved in the previous reviews and 16 when you're talking about having a small gap around a 17 pipe or a small pipe, yes, the NuScale application is 18 consistent with that.
19 We are looking at penetration for main 20 steam, main feedwater lines, these are big 21 penetrations.
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112 1 occupational, EQ, and beyond design basis equipment 2 survivability considerations.
3 So in our -- The way we look at things 4 that is not an inconsequential something that you 5 should be able to just squirt a little goop in there 6 and move on your way.
7 MEMBER KIRCHNER: Yes. Yes, but they are 8 the concretes tight fit around one pipe probably.
9 MR. LAVERA: And if you were to try to do 10 shadow shielding it would be a significant way to 11 interfere with the equipment that is there. Like I 12 said you have main steam lines and other things there, 13 so we have concerns about physically being able to fit 14 the equipment in there, the shielding in there when 15 the other equipment is present.
16 MEMBER PETTI: Okay. Let's try to take 17 public comment. Anybody in the room?
18 (No response.)
19 MEMBER PETTI: Seeing no one, anybody on 20 the public line want to make a comment?
21 (No response.)
22 MEMBER PETTI: Okay. Then we'll adjourn 23 this part of the meeting and go into closed session.
24 (Whereupon, the above-entitled matter went 25 off the record at 4:10 p.m.)
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NuScale Design Certification Application Accident Source Term Methodology Topical Report and Related Topics Presentation to the ACRS Full Committee December 4, 2019
Staff Review Team Technical Staff Hossein Esmaili, RES Michelle Hart, NRR Anne-Marie Grady, NRR Jason White, NRR Boyce Travis , NRR Jason Schaperow, NRR Ryan Nolan, NRR Tony Gardner, NRR Zach Gran, NRR Ed Stutzcage, NRR Amanda Marshall, NSIR Ron LaVera, NRR Shawn Campbell, RES Project Managers Getachew Tesfaye - Chapter PM Greg Cranston - Lead PM December 4, 2019 Accident Source Term Methodology and Related Topics 2
Contents NuScale SMR Accident Source Term Methodology Staff Independent Analysis Accident Source Term Related Major Topics Environmental Qualification and Equipment Survivability Post Accident Sampling (PAS) Exemption Hydrogen and Oxygen Monitoring Radiological Review December 4, 2019 Accident Source Term Methodology and Related Topics 3
NuScale SMR Accident Source Term Methodology In Topical Report TR-0915-17565, Revision 3, NuScale requested approval of 15 specific positions listed in Section 1.2 of the report.
The NRC staff has determined that, subject to the conditions and limitations specified in Section 6.0 of this SER, the methods described in the topical report are acceptable for developing accident source terms and performing accident radiological consequence analyses to be referenced by the NuScale SMR design.
December 4, 2019 Accident Source Term Methodology and Related Topics 4
NuScale SMR Accident Source Term Methodology The staff approves Positions 2 through 15 requested in the topical report.
The staff does not make a finding on Position 1 where NuScale categorizes a core melt accident as a beyond-design-basis event.
The applicable NRC regulations do not require classification of source terms as design basis or beyond design basis to demonstrate compliance with the requirements. Therefore, the staff has determined that the classification of a core melt accident as a beyond-design-basis event for the NuScale design is not material to the staff's findings under these regulations. Therefore, the staff does not make a finding on Position 1.
December 4, 2019 Accident Source Term Methodology and Related Topics 5
Staff Independent Analysis Objective: Evaluate NuScales methodology for core-damage-event offsite radiological consequence assessment Approach:
Use MELCOR to predict releases to the environment for 2 scenarios Input MELCOR-predicted releases to the environment into RADTRAD to predict EAB, LPZ, and control room doses
Conclusion:
Staffs predicted doses were comparable to applicants predicted doses and were below regulatory dose criteria November 20, 2019 Accident Source Term Methodology Topical Report 6
Staff independent analysis -
reports Independent MELCOR Confirmatory Analysis of NuScale Small Modular Reactor, RES/FSCB 2019-01, April 2019 (ML19205A016)
Documents staffs MELCOR calculations for 3 scenarios (LEC-06T, LCC-05T, LCU-03T)
Helps understand behavior of NuScale under severe accident conditions Compares the staffs severe accident predictions with NuScales Independent Confirmatory Analysis for NuScale Offsite Radiological Consequence Assessment, RES/FSCB 2019-03, August 2019 (ML19240A046)
Documents the fission product releases to the environment from the staffs MELCOR calculations for LEC-06T, LCC-05T Explains how the releases were input into the staffs RADTRAD analysis November 20, 2019 Accident Source Term Methodology Topical Report 7
Accident Source Term Related Topics Environmental Qualification and Equipment Survivability The staff finds it acceptable to use the iodine spike source term methodology and the environmental qualification dose methodology described in Appendix B of the topical report for calculating environmental qualification (EQ) doses inside containment and under the bioshield.
While core damage was not assessed for EQ, certain equipment associated with containment integrity and combustible gas monitoring is designed to function to withstand core damage events. Qualitative assessments, testing, and/or additional analyses may need to be performed to assure equipment survivability. This evaluation is performed in Chapter 19 of the SER.
December 4, 2019 Accident Source Term Methodology and Related Topics 8
Accident Source Term Related Topics Post Accident Sampling (PAS) Exemption 10 CFR 50.34(f)(2)(viii) requires that applicants provide the capability to promptly obtain and analyze post-accident samples from the reactor coolant system and containment atmosphere.
Since equivalent information to that provided by sampling is provided by other means, such as radiation monitors under the bio-shield, core exit thermocouples, and hydrogen and oxygen monitors, the staff determined that post-accident sampling need not be required. Therefore, the staff approves the exemption from post-accident sampling for the NuScale design.
December 4, 2019 Accident Source Term Methodology and Related Topics 9
Accident Source Term Related Topics Hydrogen and Oxygen Monitoring Radiological Review Post-accident hydrogen and oxygen monitoring can be safely established.
NuScale did not specify an acceptable amount of leakage and did not assess the leakage from the Hydrogen and Oxygen monitoring systems in the main control room or offsite dose assessment.
Staff calculations using the limited amount of available information indicates the potential for leakage from these system to be a significant contributor to offsite and MCR dose limits and could potentially result in exceeding dose limits.
The applicant has not demonstrated a capability to re-isolate the systems, so it is unclear if unacceptable leakage can be mitigated.
December 4, 2019 Accident Source Term Methodology and Related Topics 10
Accident Source Term Related Topics Hydrogen and Oxygen Monitoring Radiological Review -
Recommended wording for Rule making:
Therefore, the NRC staff recommends that the Commission include language in the proposed rule stating that the NRC is not making a finding on the design of components to minimize and control leakage from systems outside containment. This includes potential leakage from these systems that could impact the offsite dose analyses, the dose analyses for the MCR, and if necessary, the ability to safely re-isolate these systems after monitoring has been initiated. Specifically, 10 CFR Part 52, Appendix G for the DC for the NuScale SMR,Section VI, Issue Resolution, will state that the design and evaluation of the leakage from the combustible gas monitoring loop is not considered resolved within the meaning of § 52.63(a)(5) and Section IV, Additional Requirements and Restrictions, will state that the COL applicant is responsible for providing sufficient design information demonstrating that the requirements of 10 CFR 50.34(f)(2)(xxviii) are met with respect to potential radiation releases under accident conditions from the systems used for post-accident hydrogen and oxygen monitoring. The COL applicant is to provide assurance that post-accident leakage from these systems does not result in the total MCR dose exceeding the dose criteria (i.e. 5 rem) for the surrogate event with significant core damage and/or include design features in accordance with 10 CFR 50.34(f)(2)(xxvi) and 10 CFR 50.34(f)(2)(xxviii) to provide assurance that the dose criteria are not exceeded. The COL applicant will also provide information to verify, as appropriate, that post-accident leakage from these systems does not result in the total dose for the surrogate event with significant core damage exceeding the offsite dose criteria, as required by 10 CFR 52.47(a)(2)(iv). In addition, if manual actuation is required to re-isolate the system in order to contain potential leakage, the COL applicant will demonstrate that this can be done safely and within the requirements of 10 CFR 50.34(f)(2)(vii).
December 4, 2019 Accident Source Term Methodology and Related Topics 11
Accident Source Term Related Topics Examples of Rule Language from Previously Certified Design:
Appendix E to Part 52Design Certification Rule for the ESBWR Design An applicant for a COL Include, as part of its application:
IV(g). Information demonstrating that hurricane loads on those structures, systems, and components described in Section 3.3.2 of the generic DCD are either bounded by the total tornado loads analyzed in Section 3.3.2 of the generic DCD or will meet applicable NRC requirements with consideration of hurricane loads in excess of the total tornado loads; and hurricane-generated missile loads on those structures, systems, and components described in Section 3.5.2 of the generic DCD are either bounded by tornado-generated missile loads analyzed in Section 3.5.1.4 of the generic DCD or will meet applicable NRC requirements with consideration of hurricane-generated missile loads in excess of the tornado-generated missile loads.
IV(h). Information demonstrating that the spent fuel pool level instrumentation is designed to allow the connection of an independent power source, and that the instrumentation will maintain its design accuracy following a power interruption or change in power source without requiring recalibration.
December 4, 2019 Accident Source Term Methodology and Related Topics 12
Accident Source Term Related Topics Other related areas where NRC is not making a finding on design finality:
Large Penetrations in the Radiation Shield Wall:
The penetrations and penetrations shielding design were not finalized at the design certification stage. NuScale has stated that it would be completed in a future phase of the design, that will be the responsibility of the COL applicant. Therefore the staff recommends that the Commission include language in the proposed rule stating that the NRC is not making a finding on the adequacy of the necessary shielding.
Ventilation System Fire Damper:
NuScale application neither describes the instruments and controls for closing the dampers on a signal other than smoke or fire (e.g., high radiation) nor states that the operators will perform a manual action to shut the fire dampers following an accident. However, using a risk informed approach the staff is not recommending a rule language to include a means to close the dampers on high radiation. The primary risk to operators or equipment survivability involves a core damage event with a failure of the RBVS exhaust fans as well as an open NPM bay exhaust damper. The NRC staff concludes that there is a low risk of these events occurring concurrently.
December 4, 2019 Accident Source Term Methodology and Related Topics 13
Conclusion Staff found acceptable the methods for developing accident source terms and performing accident radiological consequence analyses to be referenced by the NuScale SMR design.
All Phase 2 SER open items related to accident source term methodology have been closed except those involving the penetration shielding and the leakage from the Hydrogen and Oxygen monitoring systems that are not considered resolved and must be addressed by the COL applicant.
December 4, 2019 Accident Source Term Methodology and Related Topics 14
Abbreviations CDE core damage event rem Roentgen equivalent man CDST core damage source term RG regulatory guide COL combined operating license RVV reactor vent valve CRHS control room habitability system SECY Commission paper CRVS normal control room HVAC system SGTF steam generator tube failure CVCS chemical and volume control system SMR small modular reactor DBST design basis source term SSCs structures, systems and components DCA design certification application TEDE total effective dose equivalent DF decontamination factor TR topical report EQ environmental qualification FHA fuel handing accident HVAC heating ventilation and air conditioning LWR light water reactor MHA maximum hypothetical accident MSLB main steam line break pHT temperature dependent pH PWR pressurized water reactor REA rod ejection accident December 4, 2019 Accident Source Term Methodology and Related Topics 15
LO-1219-68130 December 3, 2019 Docket No. PROJ0769 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk One White Flint North 11555 Rockville Pike Rockville, MD 20852-2738
SUBJECT:
NuScale Power, LLC Submittal of Presentation Materials Titled ACRS Full Committee Presentation: Accident Source Term Phase 5 Implementation, PM-1219-68131, Revision 0 The purpose of this submittal is to provide presentation materials to the NRC for use during the upcoming Advisory Committee on Reactor Safeguards (ACRS) NuScale Full Committee Meeting on December 4, 2019. The materials support NuScales presentation of Topical Report, Accident Source Term Phase 5 Implementation.
The enclosure to this letter is the presentation titled ACRS Full Committee Presentation: Accident Source Term Phase 5 Implementation, PM-1219-68131, Revision 0.
This letter makes no regulatory commitments and no revisions to any existing regulatory commitments.
If you have any questions, please contact Carrie Fosaaen at 541-452-4126 or at cfosaaen@nuscalepower.com.
Sincerely, Zackary W. Rad Director, Regulatory Affairs NuScale Power, LLC Distribution: Robert Taylor, NRC, OWFN-8H12 Michael Snodderly, NRC, OWFN-8H12 Samuel Lee, NRC, OWFN-8H12 Gregory Cranston, NRC, OWFN-8H12 Getachew Tesfaye, NRC, OWFN-8H12 Michael Dudek, NRC, OWFN-8H12
Enclosure:
ACRS Full Committee Presentation: Accident Source Term Phase 5 Implementation, PM-1219-68131, Revision 0 NuScale Power, LLC 1100 NE Circle Blvd., Suite 200 Corvallis, Oregon 97330 Office 541.360-0500 Fax 541.207.3928 www.nuscalepower.com
LO-1219-68130
Enclosure:
ACRS Full Committee Presentation: Accident Source Term Methodology Phase 5 Implementation, PM-1219-68131, Revision 0 NuScale Power, LLC 1100 NE Circle Blvd., Suite 200 Corvallis, Oregon 97330 Office 541.360-0500 Fax 541.207.3928 www.nuscalepower.com
NuScale Nonproprietary ACRS Full Committee Presentation Accident Source Term Phase 5 Implementation December 4, 2019 1
PM-1219-68131 Revision: 0 Copyright 2019 by NuScale Power, LLC.
Template #: 0000-21727-F01 R5
Risk Significance
- Because of the very low frequency of core damage events, the sequences in which the hydrogen monitoring system could be in operation are negligible
- Risk = Frequency x Consequence
- Sequences that contribute to the core damage frequency for an operating module with intact containment are on the order of <3E-11/mcyr (Table 19.1-18, FSAR)
- If leakage were to increase the dose (consequence) by a factor of two, there would NOT be an appreciable change to risk. Even if the dose increased by an order of magnitude, the risk would still be insignificant
- In any licensing review or other regulatory decision, the staff should apply risk-informed principles when strict, prescriptive application of deterministic criteria is unnecessary to provide for reasonable assurance of adequate protection of public health and safety. SRM for SECY-19-0036, July 2, 2019.
2 PM-1219-68131 Revision: 0 Copyright 2019 by NuScale Power, LLC.
Template #: 0000-21727-F01 R5
Hydrogen Monitoring System Leakage
- The hydrogen monitoring system is included in the Leakage Monitoring Program, required by post-TMI action item III.D.1.1
- Therefore the only way there would be an increase in leakage during a severe accident is if it induced a concurrent pipe break in the monitoring system
- The most probable initiating event that could induce a concurrent pipe break in the monitoring systems is a very large seismic event, which is assumed to result in a containment bypass, and hydrogen monitoring is therefore irrelevant.
3 PM-1219-68131 Revision: 0 Copyright 2019 by NuScale Power, LLC.
Template #: 0000-21727-F01 R5
Hydrogen Monitoring System Leakage
- What if - the hydrogen monitoring system leaks excessively? The operators have the ability to isolate the leak.
- Because this is an unplanned and unanticipated emergency response action, there are no explicit regulatory dose acceptance criteria.
- In the Brunswick SER for Hardened Vents, dated 11/21/2019, the NRC states, there are no explicit regulatory dose acceptance criteria for personnel performing emergency response actions during a beyond-design-basis severe accident.
- Therefore, the 5 rem limit of 10 CFR 50.34(f)(2)(vii) does not apply to emergency response actions during a beyond design basis event.
4 PM-1219-68131 Revision: 0 Copyright 2019 by NuScale Power, LLC.
Template #: 0000-21727-F01 R5
Hydrogen Monitoring System Leakage
- The hydrogen monitoring system is only used for severe accidents and can therefore be classified as non-safety related.
- Regarding 10 CFR 50.44, 68 FR 54123 Combustible Gas Control in Containment states, The final rule relaxes the requirements for hydrogen and oxygen monitoring equipment to make them commensurate with their risk significance.
- It is not appropriate to relax the requirements based on risk significance, and then penalize the design by presuming it will leak because it is non-safety related.
- Per RG 1.183, offsite dose consequence evaluations are not required for containment venting/purging, if only used for severe accidents.
5 PM-1219-68131 Revision: 0 Copyright 2019 by NuScale Power, LLC.
Template #: 0000-21727-F01 R5
Acronyms FR Federal Register Mcyr module critical year SER Safety Evaluation Report SRM Staff Requirements Memo TMI Three Mile Island 6
PM-1219-68131 Revision: 0 Copyright 2019 by NuScale Power, LLC.
Template #: 0000-21727-F01 R5
Portland Office Richland Office 6650 SW Redwood Lane, 1933 Jadwin Ave., Suite 130 Suite 210 Richland, WA 99354 Portland, OR 97224 541.360.0500 971.371.1592 Arlington Office Corvallis Office 2300 Clarendon Blvd., Suite 1110 1100 NE Circle Blvd., Suite 200 Arlington, VA 22201 Corvallis, OR 97330 541.360.0500 London Office 1st Floor Portland House Rockville Office Bressenden Place 11333 Woodglen Ave., Suite 205 London SW1E 5BH Rockville, MD 20852 United Kingdom 301.770.0472 +44 (0) 2079 321700 Charlotte Office 2815 Coliseum Centre Drive, Suite 230 Charlotte, NC 28217 980.349.4804 http://www.nuscalepower.com Twitter: @NuScale_Power 7
PM-1219-68131 Revision: 0 Copyright 2019 by NuScale Power, LLC.
Template #: 0000-21727-F01 R5
Advisory Committee on Reactor Safeguards Peach Bottom Atomic Power Station Units 2 and 3 Subsequent License Renewal December 4, 2019 Bennett Brady, Senior Project Manager Division of New and Renewed Licenses (DNRL)
Office of Nuclear Reactor Regulation
Presentation Outline
- Overview of Safety Review of Peach Bottom SLRA
- SER Section 2, Scoping and Screening Review
- SER Section 3, Aging Management Review
- SER Section 4, Time-Limited Aging Analyses
- Closure of Confirmatory Item
- SLRA Review Conclusion
- Region I Initial License Renewal Inspection and Plant Material Conditions and Conclusion
- Summary Conclusion 2
Overview of Safety Review of Peach Bottom SLRA Unit Initial Initial License Renewed Expiration Subsequent License License Renewal License Date Renewal Application Application 2 10/25/1973 07/02/2001 05/07/2003 08/08/2033 07/10/2018 3 07/02/1974 07/02/2001 05/07/2003 07/02/2034 07/10/2018
- Application Submitted - July 10, 2018
- Acceptance Determination - September 6, 2018
- Safety Evaluation Report with Confirmatory Item -
October 7, 2019
- Safety Evaluation Report - November 19, 2019 3
SLRA Audits and Inspections Dates Location Operating September 17-27, Rockville, MD Experience Audit 2018 November 13, In-office Audit 2018 - April 29, Rockville, MD 2019 4
SER Overview
- SER with Confirmatory Item Issued October 7, 2019
- Confirmatory Item 3.0.3.2.3-1 on BWR Vessel Internals
- Safety Evaluation Report issued November 19, 2019
- Confirmatory Item 3.0.3.2.3-1 closed
- Requests for Additional Information (RAIs)
- 48 RAIs issued, 4 of which were follow-up RAIs 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, and 2.5 Scoping and Screening Results 6
SER Section 3 Aging Management Review (AMR)
- Section 3.0 Use of the Generic Aging Lessons Learned Report
- Section 3.1 Reactor Vessel, Internals, and Reactor Coolant System
- Section 3.2 Engineered Safety Features
- Section 3.3 Auxiliary Systems
- Section 3.4 Steam and Power Conversion Systems
- Section 3.5 Containment, Structures, and Component Supports
- Section 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
- 11 new GALL programs
- 11 new GALL programs 8 consistent 8 consistent 3 consistent with exceptions 3 consistent with exceptions
- 35 existing GALL programs
- 35 existing GALL programs
- 8 consistent - 8 consistent
- 27 consistent with - 27 consistent with enhancements/exceptions enhancements/exceptions
- 1 plant specific with
- 1 plant specific with enhancement enhancement 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
Closure of Confirmatory Item 3.0.3.2.3-1 BWR Vessel Internals Issue SLRA, AMP B.2.1.7 BWR Vessel Internals proposed and enhancement to either:
- install core plate wedges or
- submit for NRC approval an inspection plan for the core plate rim hold-down bolts to mitigate stress corrosion cracking.
Resolution Applicant revised the AMP B.2.1.7 enhancement to be in accordance with BWRVIP-25, Revision 1 to:
- install wedges or
- inspect core plate rim hold-down bolts, or
- demonstrate instead via analysis that the installation of wedges and inspections of the core plate rim hold-down bolts are not required.
10
SLRA Review Conclusion On the basis of its review of the SLRA and the resolution of the confirmatory item, the staff determined that the requirements of 10 CFR 54.29(a) have been met for the subsequent license renewal of Peach Bottom Atomic Power Station Units 2 and 3.
11
Region I Initial License Renewal Inspections
- Five to ten years following the entry into the period of extended operation the Region conducts one additional license renewal team inspectionIP 71003 Phase 4.
- The team examines a sample of AMPs to verify the effects of aging were being managed effectively to ensure structures, systems, and components in the scope of these programs maintained the ability to perform their intended functions.
12
Region I AMP Inspections The Peach Bottom IP 71003 Phase 4 initial license renewal inspection was performed in November 2018 on both Units 2 and 3.
- Flow Accelerated Corrosion Program (existing)
- Maintenance Rule Structural Monitoring Program (existing)
- Ventilation System Inspection and Testing Activities (enhanced)
- Outdoor, Buried and Submerged Component Inspection Activities (enhanced)
- Fire Protection Activities (enhanced)
- In-accessible Medium Voltage Cables not subject to 10 CFR 50.49 Environmental Qualification Requirements (New) 13
Inspection of Plant Material Condition
- Reactor Oversight Process performance indicators and findings indicate plant material condition meets regulatory requirements.
- Resident Inspector routine plant walkdowns support this conclusion.
- Resident and Region based inspectors continue to inspect and assess the licensee performance to manage the effects of aging through the baseline inspection program.
14
NRC Inspection Results The inspectors found the licensees aging management programs were being effectively implemented in accordance with the facilitys renewed license. The NRC will continue to monitor AMPs using the baseline Reactor Oversight Process.
15
Summary Conclusion
- The staff has completed its presentation and conclusions on the safety review of the Peach Bottom SLRA and the Region I conclusions on inspections and plant material conditions.
- Additional questions 16
Peach Bottom Atomic Power Station, Units 2 and 3 Subsequent License Renewal Application ACRS Full Committee Presentation December 4, 2019
Introductions
- Mike Gallagher VP, License Renewal
- Anna Krause PB Sr. Mgr. Design Engineering
- Paul Weyhmuller LR Technical Manager
- Julian Laverde PB Mechanical Design Manager
- Dave Distel LR Licensing Engineer 1 Peach Bottom Atomic Power Station, Units 2 and 3
Agenda
- Introductions Mike Gallagher
- Station Description and Overview Anna Krause
- GALL Consistency and Commitments Paul Weyhmuller
- Confirmatory Item Julian Laverde
- Technical Topics Julian Laverde
- Closing Remarks Mike Gallagher 2 Peach Bottom Atomic Power Station, Units 2 and 3
Peach Bottom Station NORTH North Substation North Substation South Substation North Substation Reactor Buildings Power Block South Substation Emergency Cooling Towers EDGs ISFSI Pad ISFSI Pad Emergency Cooling Tower
[Emergency CoolingHeat Sink]
Water Turbine Building Intake Structure Discharge Canal Discharge Canal Discharge Canal Plant Intake
[Normal Heat Sink]
Intake 3 Peach Bottom Atomic Power Station, Units 2 and 3
Peach Bottom Current Performance
- Plant operates on 24 month refueling cycle
- Plant Capacity Factor:
- 2018 94.2%
- 2019 96.2% (as of 10/31)
- Regulatory Status
- ROP Action Matrix Column 1 (Licensee Response/Baseline Inspection)
- All ROP Indicators are Green 4 Peach Bottom Atomic Power Station, Units 2 and 3
Station Overview Peach Bottom Unit 2 Unit 3 Full Power License - 3293 MWt 10/25/1973 7/02/1974 5% Power Uprate to 3458 MWt 1994 1995 Independent Spent Fuel Storage 2000 Installation (ISFSI)
First License Renewal Approval 2003 2003 15% EPU to 3951 MWt 2014 2014 1.66% MUR to 4016 MWt 2017 2017 Current License Expiration 8/08/2033 7/02/2034 5 Peach Bottom Atomic Power Station, Units 2 and 3
Significant Plant Modifications Peach Bottom Unit 2 Unit 3 Main Condenser Upgrades (titanium tubes) 1991 1991 Hydrogen Water Chemistry 1997 1997 Noble Metal Chemical Addition 1998 1999 Main Power Transformers 2010 2009 RPV Core Spray Piping Upgrade Not Required 2013 Torus Recoat 2012 2013 RHR Cross-tie Modification (EPU) 2014 2015 Steam Dryer Replacement (EPU) 2014 2015 Turbine/Generator Set Upgrade (EPU) 2014 2015 Digital Control Systems (EHC and Feedwater) 2018 2017 Fuel Pool Cooling Heat Exchangers 2017 2017 ISFSI Pad Expansion 2020 6 Peach Bottom Atomic Power Station, Units 2 and 3
GALL-SLR Consistency and Commitments 7 Peach Bottom Atomic Power Station, Units 2 and 3
SLR Application Development
- Scoping and Screening Updated for plant modifications Updated to NEI 17-01 guidance
- Aging Management Reviews PB FLR was pre-GALL, additional aging effects required assessment based on NUREG-2191 GALL-SLR
- Aging Management Programs (AMPs)
Total of 47 AMPs per GALL-SLR guidance
- Time-Limited Aging Analyses (TLAAs)
Existing TLAAs re-assessed New TLAAs for SLR due to component repair/replacement Jet Pump repair components for Loss of Preload Replacement Steam Dryer Stress Report and Fatigue Evaluations Replacement Core Plate Plugs for Stress Relaxation Analysis U/3 Core Spray Replacement Piping for Fatigue and Loss of Preload Total of 35 TLAA analyses per GALL-SLR guidance 8 Peach Bottom Atomic Power Station, Units 2 and 3
GALL Consistency
- Submittal based on GALL-SLR
- High AMR consistency (98.6% Notes A thru E)
- 50 License Renewal Commitments 47 Aging Management Programs 3 Additional Commitments OPEX Review, EPU OPEX Review, FERC Inspection of Conowingo Dam UFSAR Supplement (Appendix A of the SLRA)
Managed by Exelon Commitment Tracking program based on NEI 99-04, Guidelines for Managing NRC Commitment Changes AMPs AMPs AMPs with AMPs with Plant Consistent Consistent Exception Exception Specific with GALL with without and AMPs Enhancement Enhancement Enhancement Existing 36 8 19 2 6 1 New 11 8 0 3 0 0 Total 47 AMPs 9 Peach Bottom Atomic Power Station, Units 2 and 3
FLR Aging Management Effectiveness Reviews
- Program effectiveness reviews included:
Detailed review of inspection schedules, results, and data Review of relevant operating experience within the Corrective Action Program
- All first LR Programs were effectively implemented
- Summary of each review is found in Element 10, Operating Experience of each AMP and in the SLRA in Appendix B
- In November 2018, the NRC staff conducted a 71003 Phase 4 inspection at PBAPS, to assess aging management program effectiveness, and identified no issues 10 Peach Bottom Atomic Power Station, Units 2 and 3
Confirmatory Item
- Confirmatory Item
- CI 3.0.3.2.3-1: BWR Vessel Internals Program
- NRC Staff review of Enhancement 1 identified that additional information was required for core plate rim holddown bolts
- A revision to Enhancement 1 was made to include the guidance of BWRVIP-25, Revision 1
- Response to this Confirmatory Item was submitted to the NRC Staff in a supplement October 9, 2019
- Closed by NRC Staff in the Updated SER dated November 19, 2019 11 Peach Bottom Atomic Power Station, Units 2 and 3
Technical Topics RPV Embrittlement IASCC of Reactor Vessel Internals Peach Bottom will manage aging consistent with recommendations in GALL-SLR Concrete and Electrical Cable EQ and Containment Condition Assessment Degradation 12 Peach Bottom Atomic Power Station, Units 2 and 3
Peach Bottom Atomic Power Station, Units 2 and 3 Subsequent License Renewal Application ACRS Full Committee Presentation December 4, 2019
Peach Bottom Atomic Power Station, Units 2 and 3 Subsequent License Renewal Application ACRS Full Committee Presentation December 4, 2019 Back-up Slides
Peach Bottom Station Location Peach Bottom Station 15 Peach Bottom Atomic Power Station, Units 2 and 3
GALL Consistency - AMP Exceptions Program Exception Justification Water Chemistry Using this AMP to manage Auxiliary Boiler water Scope addition, while not part of BWRVIP-190, chemistry. standards exist for monitoring water parameter (ISBN-0-7918-1204-9).
Bolting Integrity Using this AMP to manage submerged mechanical Scope addition, while this AMP is used to manage bolting on intake structure traveling screens. closure bolting for pressure retaining components, inspection requirements will be adequate to manage loss of preload.
Closed Treated NUREG-2191 recommends EPRI document Closed Revised guideline incorporates latest industry OPEX.
Water Cooling Water Chemistry Guideline Rev. 1. No changes to monitoring criteria.
Peach Bottom uses Rev.2 of this guideline.
Reactor Head NUREG-2191 requires the use of material with Test reports show some test values over limit. Studs Closure Stud Bolting ultimate tensile strength of less than 170 ksi for in- are inspected for cracking.
service studs. Both units have studs installed with studs over 170 ksi.
NUREG-2191 requires the use of material with Test reports show some test values over limit. Stud yield strength of less than 150 ksi for replacement was inspected for cracking and will be re-inspected if studs. Replacement stud has test results over 150 ksi. utilized.
BWR Vessel Steam Dryer will not be inspected per BWRVIP-139-A BWRVIP-139-A is for GE designed steam dryer Internals assemblies. PB has installed Westinghouse steam dryers and has submitted an inspection plan to the NRC.
16 Peach Bottom Atomic Power Station, Units 2 and 3
GALL Consistency - AMP Exceptions Program Exception Justification Fire Water System NUREG-2191 requires foam system discharge test Single nozzle which sprays across down the inside of annually to confirm spray patterns. When not the tank. Nozzle has a vapor seal. One time visual possible, visual inspection of nozzles and air testing inspection to assure proper orientation as it is within is performed. the fuel tank.
Internal Coatings NUREG-2191 requires an internal inspection of Fire header piping is buried. Various periodic flow tests portions of concrete lined pipe. Opportunistic will assure coating has not degraded impacting inspections will be performed. performance. 2014 inspections found concrete lining in good condition. When made available, visual inspection will be performed.
NUREG-2191 requires coating found not meeting NMACs Terry Turbine Users Group provides acceptance criteria are repaired, replaced, or recommendations that degraded coatings not be removed. HPCI lube oil reservoir coating will not be replaced. Only remove portions that show poor repaired. adhesion.
ASME Section XI- NUREG-2191 requires pressure retaining Peach Bottom, had it been constructed to a later code, IWE components subject to cyclic loading that have no would have met requirements of ASME Code for fatigue analysis are inspected for cracking. Peach fatigue waivers for low temperature penetrations. High Bottom will only inspect high temperature mechanical temperature penetration accessible surfaces will be penetrations. inspected for cracking.
Program will manage flow blockage due to fouling for No existing GALL line items exist for the management the Core Spray System, High Pressure Coolant of flow blockage due to fouling for these components Injection System, Reactor Core Isolation Cooling and as a result the IWE Program was selected System, and Residual Heat Removal System pump because the station Containment ISI program plan and suction strainers. procedures will perform the required aging management actions.
17 Peach Bottom Atomic Power Station, Units 2 and 3
GALL Consistency - AMP Exceptions Program Exception Justification E3A - Medium NUREG-2191 recommends, inspections for water Level monitoring instrumentation, with alarms Voltage Cables accumulation and manhole condition annually. monitored by Operations Personnel, provide for Additionally, inspections for water accumulation are detection of water level on an on-going basis.
E3B - I&C Cables also to be performed after event driven occurrences, Corrective actions are taken when an alarm is such as heavy rain. received which includes manual pumping of the E3C - Low Voltage manhole as needed. In cases where it can be Cables Manholes with level monitoring and alarms that result determined that cables have not been subjected to in consistent, subsequent pump out of accumulated significant moisture, manhole inspections will be water prior to wetting or submergence of cables will performed on a five-year frequency when structural be inspected at least once every five years with inspections are performed.
additional inspections following event driven Following event driven occurrences, inspections and occurrences, such as heavy rain, rapid thawing of ice subsequent pump outs, as needed, will be performed and snow, or flooding, when level monitoring indicates when level instrumentation has detected increasing water is accumulating. water levels.
18 Peach Bottom Atomic Power Station, Units 2 and 3
RPV 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 or Thermal Aging Embrittlement embrittlement at 4.2 Reactor Vessel and Internals Neutron Embrittlement Analyses high fluence A.2.1.20 Reactor Vessel Material Surveillance A.3.1.2 Neutron Fluence Monitoring
- Fluence projections through SPEO (70 EFPY) were performed for neutron embrittlement analyses
- Analysis for USE, ART, Axial/Circ Weld Failure Probability, and Reflood Thermal Shock for beltline materials have been satisfactorily evaluated using the 70 EFPY fluence projections
- PBAPS will manage fluence projections consistent with GALL-SLR AMP X.M2, Neutron Fluence Monitoring Program
- PBAPS 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 60-62 EFPY 19 Peach Bottom Atomic Power Station, Units 2 and 3
IASCC of Reactor Vessel Internals (RVI)
SLRA Sections Addressing GALL-SLR Recommendations IASCC of reactor 3.1.2.2.12 Cracking Due to Irradiation-Assisted Stress Corrosion Cracking internals and 4.2.1.2 Reactor Vessel Internals Neutron Fluence Analyses primary system 4.2.14 First License Renewal Application Core Shroud IASCC and Embrittlement Analysis components A.2.1.7 BWR Vessel Internals A.3.1.2 Neutron Fluence Monitoring
periodic inspection using techniques capable of detecting cracking due to SCC flaw tolerance guidance that considers the effect of neutron fluence on material properties and SCC growth rates.
- BWRVIP guidelines are adequate for use to determine the proper re-inspection interval and are not time dependent, rather are based on neutron fluence values.
- PBAPS Rx vessel internals have been assessed using governing BWRVIP inspection guidelines and existing program requirements were found acceptable
- PBAPS will manage RVI components and welds that are susceptible to IASCC consistent with GALL-SLR AMP XI.M9 20 Peach Bottom Atomic Power Station, Units 2 and 3
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 Safety-Related and Other Structures and Component Supports degradation 4.6 Primary Containment Fatigue Analyses A.2.1.30 ASME Section XI, Subsection IWE A.2.1.32 10 CFR Part 50, Appendix J A.2.1.34 Structures Monitoring A.2.1.35 Inspection of Water-Control Structures Associated with Nuclear Power Plants
- Concrete overall is in good condition No effects of ASR have been identified for PBAPS concrete structures PBAPS will manage concrete structures consistent with GALL-SLR AMPs XI.S6, Structures Monitoring and XI.S7, Inspection of Water-Control Structures Associated with Nuclear Power Plants
- The Peach Bottom Mark I steel containments are in good condition The Sand Pocket Region has been observed to be free of water leakage, each refueling outage Reactor Vessel Shield Wall gamma and neutron irradiation remains within conservative radiation exposure levels, through SPEO, consistent with GALL-SLR PBAPS will manage each containment consistent with GALL-SLR AMPs XI.S1, ASME Section XI, Subsection IWE and XI.S4, 10CFR 50, Appendix J 21 Peach Bottom Atomic Power Station, Units 2 and 3
Electrical Cable EQ and Condition Assessment SLRA Sections Addressing GALL-SLR Recommendations Electrical cable 3.6.2.2.1/4.4.1 Environmental Qualification of Electric Equipment qualification and A.2.1.37 through 41 Cable and Connection Insulation Programs condition A.3.1.3 Environmental Qualification of Electric Equipment assessment
- Environmental Qualification of Electrical Equipment EQ cable analyses have been updated for 80 years of operation EQ cables have been evaluated to have a qualified life > 80 years Cable analysis and EQ program are consistent with GALL-SLR
- Electrical cable condition assessment Added new or enhanced programs to be consistent with GALL-SLR o E1 Accessible Non-EQ Cables and Connections (enhanced) o E2 Non-EQ Instrument Cables and Connections (enhanced) o E3A for Medium Voltage Cables (enhanced) o E3B for Instrument & Control Cables (new) o E3C for Low Voltage Cables (new) 22 Peach Bottom Atomic Power Station, Units 2 and 3