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
NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 1
1 2
3 DISCLAIMER 4
5 6
UNITED STATES NUCLEAR REGULATORY COMMISSIONS 7
ADVISORY COMMITTEE ON REACTOR SAFEGUARDS 8
9 10 The contents of this transcript of the 11 proceeding of the United States Nuclear Regulatory 12 Commission Advisory Committee on Reactor Safeguards, 13 as reported herein, is a record of the discussions 14 recorded at the meeting.
15 16 This transcript has not been reviewed, 17 corrected, and edited, and it may contain 18 inaccuracies.
19 20 21 22 23
1 UNITED STATES OF AMERICA 1
NUCLEAR REGULATORY COMMISSION 2
+ + + + +
3 669TH MEETING 4
ADVISORY COMMITTEE ON REACTOR SAFEGUARDS 5
(ACRS) 6
+ + + + +
7 OPEN SESSION 8
+ + + + +
9 WEDNESDAY 10 DECEMBER 4, 2019 11
+ + + + +
12 ROCKVILLE, MARYLAND 13
+ + + + +
14 The Advisory Committee met at the Nuclear 15 Regulatory Commission, Two White Flint North, Room 16 T2D30, 11545 Rockville Pike, at 1:00 p.m., Peter 17 Riccardella, Chairman, presiding.
18 19 COMMITTEE MEMBERS:
20 PETER RICCARDELLA, Chairman 21 MATTHEW W. SUNSERI, Vice Chairman 22 JOY L. REMPE, Member-at-Large 23 RONALD G. BALLINGER, Member 24 DENNIS BLEY, Member 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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2 CHARLES H. BROWN, JR. Member 1
VESNA B. DIMITRIJEVIC, Member 2
WALTER L. KIRCHNER, Member 3
JOSE MARCH-LEUBA, Member 4
DAVID A. PETTI, Member 5
6 ACRS CONSULTANTS:
7 MICHAEL L. CORRADINI*
8 STEPHEN SCHULTZ*
9 10 DESIGNATED FEDERAL OFFICIALS:
11 KENT HOWARD 12 MIKE SNODDERLY 13 14 15 16 17 18 19 20 21 22 23
- Present via telephone 24 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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3 CONTENTS 1
Opening Remarks by the ACRS Chairman 4
2 Peach Bottom Subsequent License Renewal.....
6 3
Public Comments................. 45 4
NuScale Source Term Topical Report Methodology
. 46 5
Adjourn....................
112 6
7 8
9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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4 P R O C E E D I N G S 1
1:00 p.m.
2 CHAIRMAN RICCARDELLA: The meeting will 3
come to order.
4 Scott?
5 MR. BROWN: Sure. I would just like to 6
announce for the Committee that we have a new member 7
on the ACRS staff, Thomas Dashiell. Thomas comes to 8
us to be our Conference Room Manager, which we badly 9
need, as you all have seen. Thomas has served for 10 years in the Navy, retired with honors from the Navy.
11 We won't hold that against you, Thomas.
12 And following that, he's been here at NRC 13 for 15 years as an AV Project Manager, IT Project 14 Manager. While he was in the Navy, he worked directly 15 under two Presidents. So, he comes with high 16 credentials. And here at NRC, he worked the AV 17 equipment for the Commission itself in the hearing 18 rooms and in the auditorium. So, he comes with high 19 skills and we're glad to have him on our staff.
20 So, we're glad you're here, Thomas.
21 Thanks.
22 CHAIRMAN RICCARDELLA: Welcome, Thomas.
23 So, this is the first day of the 669th 24 meeting of the Advisory Committee on Reactor 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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5 Safeguards. I'm Pete Riccardella, Chairman of ACRS.
1 ACRS was established by the Department of 2
Energy Act and is governed by the Federal Advisory 3
Committee Act, or FACA. The ACRS section of the U.S.
4 NRC public website provides information about the 5
history of the ACRS and provides FACA-related 6
documents, such as our Charter, Bylaws, Federal 7
Register notices for meetings, letter reports, and 8
transcripts of all full and subcommittee meetings, 9
including slides and presentations at the meetings.
10 The Committee provides its advice on 11 safety matters to the Commission through its publicly-12 available letter reports. The Federal Register notice 13 announcing the meeting was published on November 18th, 14 2019, and provided an agenda and instructions for 15 interested parties to provide written documents or 16 request opportunities to address the Committee, as 17 required by FACA.
18 In accordance with FACA, there is a 19 Designated Federal Official for the meeting. The DFO 20 for today's meeting is Mr. Kent Howard.
21 During this meeting, the Committee will 22 consider the following: Peach Bottom subsequent 23 license renewal; NuScale Source Term Topical Report 24 methodology; Susquehanna Atrium 11 fuel transition and 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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6 application/Framatome, and preparation of reports.
1 As reflected in the agenda, portions of 2
the NuScale and Atrium 11 sections may be closed in 3
order to discuss the proprietary information 4
designated as sensitive or proprietary information.
5 There is a phone bridge line. To preclude 6
interruptions of the meeting, the phone will be placed 7
in a listen-in mode during the presentations and 8
Commission discussions. We have received no written 9
comments or requests to make oral statements from 10 members of the public regarding today's session.
11 There will be an opportunity for public comment, as we 12 have set aside 10 minutes in the agenda for comments 13 from members of the public attending or listening into 14 our meeting. Written comments may be forwarded to Mr.
15 Kent Howard, the Designated Federal Official.
16 A transcript of open portions of the 17 meeting is being kept. And it is requested that 18 speakers use one of the microphones in the room, 19 identify themselves, and speak with sufficient clarity 20 and volume, so that they may be readily heard.
21 So, the first topic on the agenda is Peach 22 Bottom Atomic Power Station subsequent license renewal 23 application, and I will turn the meeting over to Matt 24 Sunseri, who is Chairman of the License Renewal 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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7 Subcommittee.
1 VICE CHAIRMAN SUNSERI: Thank you, 2
Chairman Riccardella.
3 As Pete mentioned, I'm Matt Sunseri, 4
Chairman of the Plant License Renewal Subcommittee.
5 The purpose of this full Committee meeting 6
is for Exelon Generation Company LLC and the NRC staff 7
to brief the full Committee on the subsequent license 8
renewal application for the Peach Bottom Atomic Power 9
Station's Units 2 and 3. The Plant License Renewal 10 Subcommittee previously met on November 5th of this 11 year to discuss the matter.
12 At the conclusion of these presentations, 13 we will be ready to start our Committee work on letter 14 writing at your pleasure following this briefing. So, 15 anytime after that.
16 There are members of both the NRC and 17 Exelon staff listening in on the phone. So, this 18 reminder about using the microphones is particularly 19 important because they just can't hear us if we don't 20 do that.
21 At this point, I'd like to turn to Meena 22 Khanna to see if she has any opening remarks as well.
23 MS. KHANNA: Thank you. Thank you, 24 Chairman Riccardella and Subcommittee Chairman 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 Sunseri, and Members of the ACRS.
1 I am Meena Khanna, Acting Deputy Director 2
of the Division of New and Renewed Licenses, which is 3
DNRL. We sincerely appreciate the opportunity today 4
to present to the ACRS full Committee the results of 5
the staff's review of the second application for 6
subsequent license renewal and which is the first 7
subsequent license renewal application for a boiling 8
water reactor. This application was submitted by 9
Echelon Generation Company LLC for the Peach Bottom 10 Atomic Power Station, Units 2 and 3, located near 11 Delta, Pennsylvania.
12 As Subcommittee Chairman Sunseri 13 mentioned, we had the opportunity to present the 14 results of the review of this application to the ACRS 15 Subcommittee on Plant License Renewal approximately a 16 month ago on November 5th. Subsequently, we issued 17 the updated SER on November 19th.
18 By way of background, Peach Bottom Units 19 2 and 3 received approval for their initial renewed 20 licenses from the NRC on May 7th, 2003. The NRC 21 review at that time was performed using guidance 22 developed prior to the issuance of the Generic Aging 23 Lessons Learned Report, or the GALL report. The NRC 24 developed guidance for review of subsequent license 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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9 renewal applications, and it was issued in July 2017 1
as NUREG-2191, also referred to as GALL SLR, and 2
NUREG-2192, SLR SRP, following extensive interactions 3
with the ACRS. The staff performed its review of the 4
Peach Bottom SLR application using these NUREGs.
5 The NRC Project Manager for the Peach 6
Bottom SLR application review is Ms. Bennett Brady, 7
seated behind me. Ms. Brady will introduce the staff, 8
who will be seated at the table, that will be 9
presenting or addressing questions regarding the 10 staff's review of the Peach Bottom SLR application.
11 Part of the management team that are here 12 with me today: to the left is Anna Bradford, the 13 Director of the Division of New and Renewed Licenses.
14 To my right is Eric Oesterle, Chief of the License 15 Renewal Projects Branch. And in the audience are 16 other DNRL and NRR technical review Branch Chiefs and 17 their staffs that have been involved with the review.
18 There may also be some technical staff on the phone.
19 In addition, we are fortunate to have 20 representatives from Region I also on the phone that 21 include Kevin Mangan, Senior Reactor Inspector, as 22 well as Justin Heinly, Senior Resident Inspector at 23 Peach Bottom.
24 The staff will provide an overview of its 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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10 safety review which will include a discussion of the 1
confirmatory item related to the core plate rim hold-2 down bolts, which, as we discussed at the ACRS 3
Subcommittee meeting, was closed based on the 4
supplemental information provided by Exelon.
5 Staff will also provide a discussion of 6
the regional inspection of the Aging Management 7
Program implementation for initial license renewal and 8
address the material condition of the Peach Bottom 9
facility.
10 We look forward to a productive discussion 11 today with the ACRS and will address any questions 12 that you may have.
13 At this time, I'd like to turn the 14 presentation over to Mr. Michael Gallagher, Exelon 15 Nuclear Vice President for License Renewal and 16 Decommissioning, to introduce his team and commence 17 their presentation.
18 Thank you.
19 VICE CHAIRMAN SUNSERI: Thank you.
20 And, Mike, one other thing I need to 21 mention is that Members Riccardella and myself are 22 going to recuse ourselves from any discussions on the 23 metal and environmental fatigue issues and radiation 24 embrittlement issues with the reactor pressure vessel 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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11 and the sacrificial shield wall. That's just due to 1
some outside business that we've done.
2 Thank you.
3 MR. GALLAGHER: Okay. Thank you, and 4
thank you, Meena.
5 Good afternoon.
My name is Mike 6
Gallagher, and I'm the Vice President of License 7
Renewal at Exelon. I have 38 years of nuclear power 8
plant experience, all at Exelon, and have been working 9
on our license renewal project since 2006.
10 Slide 1, please.
11 Before we get into today's presentation, 12 I'd like to introduce the presenters.
13 To my right is Anna Krause, and Anna is 14 our Senior Manager of Design Engineering for Peach 15 Bottom. And Anna has 14 years of nuclear power plant 16 experience.
17 To Anna's right is Paul Weyhmuller, and 18 Paul is our License Renewal Technical Manager for the 19 Peach Bottom project. Paul has 37 years of nuclear 20 power plant experience, including working on Exelon's 21 license renewal project since 2011.
22 And to Paul's right is Julian Laverde, and 23 Julian is our Mechanical Design Manager for Peach 24 Bottom. And Julian has nine years of nuclear power 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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12 plant experience.
1 And to my left is Dave Distel, and Dave is 2
our Project Licensing Lead. And Dave has 39 years of 3
nuclear power plant experience.
4 In addition, here in the room we have our 5
technical support personnel, and, also, as mentioned, 6
on the NRC conference line, we have our Peach Bottom 7
technical staff available to answer questions on the 8
conference line.
9 And we also have with us here today Pat 10 Navin, and Pat is our Site Vice President at Peach 11 Bottom.
12 Slide 2.
13 So, this slide shows our agenda for the 14 presentation. This is a similar presentation that we 15 gave the Subcommittee and that we abbreviated somewhat 16 to be focused on the main activities. Included in our 17 presentation, we did include slides that we presented 18 to the Subcommittee meeting as backup material. And 19 again, we can go into any questions that the full 20 Committee may have.
21 We believe we developed a robust, high-22 quality subsequent license renewal application, and we 23 also have developed effective aging management 24 programs to ensure the continued safe operation of 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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13 Peach Bottom.
1 We appreciate the opportunity to make this 2
presentation and look forward to answering any 3
questions you may have.
4 With that, I'll turn it over to Anna 5
Krause.
6 Anna?
7 MS. KRAUSE: Thank you, Mike.
8 Slide 3, please.
9 Good afternoon. My name is Anna Krause, 10 and I'm a Senior Manager of Design Engineering at 11 Peach Bottom.
12 Peach Bottom Units 2 and 3 are GE boiling 13 water reactors with Mark I containments that are 14 jointly owned by Exelon and PSE&G and operated by 15 Exelon.
16 The Peach Bottom Station is located in the 17 Commonwealth of Pennsylvania, approximately 40 miles 18 northeast of Baltimore, Maryland, and 60 miles 19 southwest of Philadelphia, Pennsylvania.
20 On the aerial view of Peach Bottom, you 21 can see the power block; the independent spent fuel 22 storage installation pad; the north and south 23 substations; the plant intake and discharge canal, 24 which is the normal heat sink for the station, and the 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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14 emergency cooling tower, which comprises the emergency 1
heat sink for the station in the event that the normal 2
heat sink is not available.
3 Slide 4, please.
4 Peach Bottom is operated on 24-month 5
refueling cycles. The station capacity factor for 6
2018 was 94.2 percent, and then, year to date through 7
October 31st is 96.2 percent.
8 Our regulatory performance as Peach Bottom 9
is in action matrix column 1 and all ROP indicators 10 are green.
11 Slide 5, please.
12 Now this slide shows the dates for thermal 13 power license changes for Peach Bottom Units 2 and 3.
14 We also show that the independent spent fuel storage 15 installation was installed in 2000. And then, the 16 current license expiration dates are August 8th, 2033, 17 for Unit 2, and July 2nd, 2034, for Unit 3.
18 MEMBER REMPE: Anna, I thought there was 19 a measurement uncertainty recapture in 2002, but it's 20 not shown here. Is that true? The reason I'm asking 21 is because I kind of looked ahead and it might be good 22 for us to clarify that.
23 MR. GALLAGHER: Yes, that's a license 24 recapture.
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15 MR. WEYHMULLER: Yes, we did a -- it was 1
called Appendix K in its day, where they did the 2
measurement uncertainty recapture at that point. And 3
then, subsequent to that, you see that we did the EPU 4
modification. With that, the Appendix K mod was taken 5
away, and they did the EPU project, and then, 6
subsequently, followed back up with what was now known 7
as MUR, or the uncertainty recapture, and reinstated, 8
basically, what had been there in the past.
9 MEMBER REMPE: The reason I'm asking is I 10 was involved in the EPU approval, and I remember that 11 earlier
- letter, but it may come up in our 12 deliberations on the letter today. So, thank you.
13 MR. WEYHMULLER: Okay.
14 MS. KRAUSE: All right. Moving to Slide 15 6, this slide provides an overview of significant 16 plant modifications that have been implemented at 17 Peach Bottom that address component aging and long-18 term operations.
19 Okay. I will now turn it over to Paul 20 Weyhmuller, who will present to you the highlights of 21 our subsequent license renewal application.
22 MR. WEYHMULLER: Thank you, Anna.
23 Slide 7, please.
24 Good afternoon.
My name is Paul 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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16 Weyhmuller. I'm the Technical Manager for the Peach 1
Bottom license renewal project. I will discuss the 2
highlights of our subsequent license renewal 3
application, focusing on application development, our 4
new time-limited aging analyses, the overall GALL SLR 5
consistency, a review of the aging management 6
programs, the exceptions we have taken, and a summary 7
of the first license renewal aging management program 8
affecting these reviews that have been conducted.
9 Slide 8, please.
10 Exelon used industry and NRC guidance to 11 make our application as consistent with GALL SLR as 12 possible. Our submittal is based on the guidance 13 provided in both NUREG-2191 and 2192.
14 In developing the Peach Bottom subsequent 15 license renewal application, changes noted from first 16 license renewal include:
17 For scoping and screening, we have updated 18 our packages for plant modifications as well as to 19 address NEI 17-01 guidance.
20 For aging management reviews, the first 21 license renewal was pre-GALL. So, additional aging 22 effects required assessment based on NUREG-2191 GALL 23 SLR.
24 For aging management programs, we have 47 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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17 programs for subsequent license renewal utilizing the 1
GALL SLR guidance. Activities from first license 2
renewal have been addressed in subsequent license 3
renewal programs.
4 Our aging management programs were 5
developed incorporating lessons learned from previous 6
Exelon projects as well as from benchmarking current 7
industry applications. The aging management programs 8
were also developed using insights from industry RAIs.
9 For time-limited aging analyses, the Peach 10 Bottom subsequent license renewal application has 11 reassessed the existing plant current licensing basis 12 TLAAs. Additional TLAAs for repair or replacement 13 activities not part of the first license renewal 14 application have been added. There are a total of 35 15 TLAAs found in the subsequent license renewal 16 application.
17 MEMBER BLEY: Before you go on, in the 18 core plate replacement -- I may have asked this 19 before, but I'm asking it again -- what was the main 20 difference between Units 2 and 3? Why did 3 need the 21 improvement?
22 MR. WEYHMULLER: There was cracking noted 23 on Unit 3 attributed from early operation. That was 24 thought to be the cause of why there were additional 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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18 defects found in that piping system that warranted 1
replacement. It got to be --
2 MEMBER BLEY: And none on Unit 2?
3 MR. WEYHMULLER: That's correct.
4 MEMBER BLEY: Thank you.
5 MR. WEYHMULLER: Okay. Slide 9, please.
6 As stated earlier, Peach Bottom subsequent 7
license renewal application is based on GALL SLR.
8 Peach Bottom aging management review achieved 9
significant consistency with the GALL SLR, as 10 reflected by the fact that 98.6 of AMR line items are 11 covered by notes A through E.
12 There are 50 commitments for the 13 implementation of subsequent license renewal at Peach 14 Bottom, consisting of 47 commitments from the 15 implementation of individual aging management programs 16 and 3 additional commitments for OPEX actions and for 17 the continued use of FERC inspections for specific 18 water-controlled structures. These commitments will 19 be captured within the subsequent license renewal 20 UFSAR supplement, which is contained in Appendix A of 21 the subsequent license renewal application.
22 These commitments are managed in 23 accordance with Exelon's commitment tracking program, 24 which is based on the NRC-endorsed NEI 99-04, 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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19 "Guidelines for Managing NRC Commitment Changes 1
Process".
2 The table shown on the slide provides a 3
breakdown of aging management programs in regards to 4
consistency with GALL SLR. The summary table also 5
provides a numerical breakdown for existing and new 6
AMPs.
7 There are only 11 programs with 8
exceptions. For each exception, we have provided an 9
alternative to the recommendation found in GALL SLR.
10 Supporting technical justification has been provided 11 and has been found acceptable, as identified in the 12 SER.
13 Slide 10, please.
14 The Peach Bottom aging management program 15 effectiveness reviews assessed first license renewal 16 activities and included a
detailed review of 17 inspection schedules, results, and data, as well as a 18 review of relevant operating experience within the 19 corrective action program. All first license renewal 20 programs were determined to be effectively 21 implemented. A summary of each review is found in 22 Appendix B
of the subsequent license renewal 23 application for each specific aging management program 24 under OPEX Item No. 1.
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20 In November of 2018, the NRC staff 1
conducted an IP 71003 Phase 4 inspection, post-2 approval site inspection for license renewal at Peach 3
Bottom. This inspection found no issues.
4 I will now turn the presentation over to 5
Julian Laverde, who will discuss how we closed the one 6
confirmatory item and a brief summary on the specific 7
technical topics involved in subsequent license 8
renewal.
9 MR. LAVERDE: Thank you, Paul.
10 Slide 11, please.
11 Good afternoon. My name is Julian 12 Laverde, and I am the Site Mechanical Design 13 Engineering Manager at Peach Bottom.
14 There was one confirmatory item involving 15 a commitment for the BWR vessel internals aging 16 management program. Additional information was 17 required by the NRC staff to complete the assessment 18 of the proposed enhancement for core plate rim hold-19 down bolts. This was addressed by revising the 20 enhancement to provide the source document, BWR 25, 21 Revision 1, which was used to determine the 22 appropriate actions to be taken to address stress 23 corrosion cracking of core plate rim hold-down bolts.
24 This issue has been resolved with the 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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21 submittal of a supplement to the NRC staff on October 1
9th, 2019, and the NRC has closed this item, as stated 2
in the updated SER dated November 19, 2019.
3 Slide 12, please.
4 In the Subcommittee meeting, we presented 5
how Exelon addressed the four technical topics related 6
to SLR that were of interest to the NRC Commissioners 7
during the NRC staff preparations for SLR. These 8
topics were discussed in Staff Requirements Memo for 9
The four topics are:
RPV 10 embrittlement, IASCC of reactor vessel internals, 11 concrete and containment degradation, and electrical 12 cable EQ and condition assessment.
13 To summarize, we have constructed our 14 aging management programs in these areas to be 15 consistent with the GALL SLR guidance. For example, 16 for RPV embrittlement, we have developed flows 17 projections through SPEO, satisfactorily evaluated 18 reactor vessel material properties through SPEO, and 19 added a commitment to withdraw and test an RPV 20 surveillance capsule for each unit.
21 For
- IASCC, we have confirmed the 22 acceptability of existing BWR guidelines to manage the 23 aging of reactor vessel internals to SPEO.
24 For concrete and containments, we have 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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22 reported that the concrete and containment at Peach 1
Bottom are in good condition.
2 And finally, the EQ cable and condition 3
assessment, we have updated analysis to show EQ cables 4
have a qualified life greater than 80 years. And we 5
continue to visually inspect and test, per GALL SLR 6
recommendations.
7 I will pause here to see if we have any 8
questions on these topics.
9 (No response.)
10 I will now turn the presentation over to 11 Mike Gallagher for closing remarks.
12 MR. GALLAGHER: Okay. Thank you, Julian.
13 Slide 13, please.
14 This was our summary presentation of what 15 we gave earlier to the Subcommittee. And as I stated 16 before, we developed a comprehensive, high-quality 17 subsequent license renewal application, along with 18 robust aging management programs that will ensure the 19 continued safe operation of Peach Bottom during the 20 subsequent period of extended operation.
21 Pending any questions you may have, this 22 concludes our presentation.
23 VICE CHAIRMAN SUNSERI: I didn't want to 24 distract. I missed an opportunity to ask a question 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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23 a little earlier. So, I'll ask you now, just for 1
completeness, and I'll ask the staff also when it's 2
their turn.
3 But the 71003 Phase 4 inspection, that 4
seems like a significant activity to meet the 5
effectiveness of the aging management program. And to 6
have no findings, how extraordinary is that? I mean, 7
in your experience working with your peers, is that a 8
typical finding or is that an extraordinary finding?
9 MR. GALLAGHER: I mean, there have been 10 several or many Phase 4 inspections done at other 11 sites, and there have been findings, usually a green 12 finding. And in ours, we didn't have that, not to say 13 we didn't get any lessons learned at all from the NRC 14 review. I think the staff, the regional staff did 15 thorough reviews. We had well prepared for it, for 16 the inspection. And we would have initiated any 17 corrective actions for further improvements in our 18 programs, and there were items like that that were 19 identified and acted on. But there were no findings.
20 VICE CHAIRMAN SUNSERI: Yes. I mean, I 21 asked the question because we don't get to go visit 22 the sites and do the detailed reviews. So, we rely on 23 staff's feedback for a lot of our information. We 24 always want to push to make sure that these reviews 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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24 are being done with the rigor and technical competence 1
that we need to ensure the regulations are going to be 2
met and that the applicants are upholding their end of 3
the story also. So, this seems like a good news story 4
to me, anyway.
5 MR. GALLAGHER: Yes, I think so.
6 VICE CHAIRMAN SUNSERI: Anyone else?
7 (No response.)
8 All right.
9 MS. KHANNA: So, we'll definitely address 10 that. We've got the regional folks on the phone, and 11 they'll be happy to address a little bit more details 12 of the inspections.
13 Thanks.
14 VICE CHAIRMAN SUNSERI: Thank you.
15 All right. Well, we can swap out then.
16 MS. BRADY: Good afternoon, Chairmen and 17 Members of the ACRS.
18 My name is Bennett Brady. I am the 19 Project Manager for the safety review of the Peach 20 Bottom Atomic Power Station, Units 2 and 3, subsequent 21 license renewal application.
22 As you know from Meena, we are here today 23 to discuss the NRC staff's safety review of the Peach 24 Bottom SLRA, as documented in the Safety Evaluation 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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25 Report, or SER, as it's known, which was issued on 1
November 19, 2019.
2 Joining me here at the table is Bill 3
Rogers, Senior Project Manager in the Division of New 4
and Renewed Licenses, or DNRL, who also assisted me in 5
managing the project. In addition, joining us by 6
telephone is Kevin Mangan, Region I, Senior Reactor 7
Inspector, and Jon Greives, Region I, DRP Branch 8
Chief, responsible for Peach Bottom.
9 I would suggest that we ask them, when we 10 get to the end of our presentation, to address your 11 question about how unusual this finding is.
12 Angela Wu, also a Project Manager in DNRL, 13 will be controlling the slides.
14 Seated in the audience and joining us by 15 phone are members of the NRR technical staff who 16 participated in the review of SLRA and conducted the 17 audits.
18 Next slide, please.
19 We will begin the presentation with a 20 general overview of the staff's safety review, 21 followed by an overview of SER Section 2 on scoping 22 and screening; SER Section 3, aging management review, 23 and Section 4, time-limited aging analysis. We will, 24 then, discuss the closure of the confirmatory item, 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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26 the Region I initial license renewal inspection that 1
coincided with the staff's SLRA review, and the 2
Resident Inspector's perspective on plant material 3
conditions, and then, finally, the summary conclusion.
4 Next slide, please.
5 Peach Bottom Units 2 and 3 were initially 6
licensed in October 1973 and July 1984, respectively.
7 The licensee, Exelon Generation Company LLC, or 8
Exelon, submitted the application for a subsequent 9
license renewal in July 10, 2018.
10 Next slide, please.
11 As you've heard, the Peach Bottom SLRA is 12 the second safety review performed by the staff using 13 the GALL SLR and SRP SLR guidance issued in 2017. The 14 staff's Peach Bottom SLR review was the same as that 15 used for Turkey Point SLRA review. The staff 16 identified and implemented several efficiencies as 17 compared to the safety review of initial license 18 renewal applications.
19 One of these efficiencies dealt with the 20 conduct of audits. Instead of one large and lengthy 21 onsite audit, the staff conducted two standard audits, 22 an operating experience audit, and an in-office audit.
23 The majority of audit activities and breakout 24 discussions were conducted in-office through the use 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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27 of portals and telecommunications.
1 During the Peach Bottom operating 2
experience audit, the staff performed an independent 3
review of plant-specific operating experience to 4
identify pertinent examples of age-related 5
degradation, as documented in the applicant's program 6
corrective action program database.
7 During the in-office audit, the audit team 8
first focused on two areas: first, the scoping and 9
screening review and, second, the review of aging 10 management programs, or AMPs; aging management review 11 items, and the time-limited aging analysis.
12 For the Peach Bottom SLRA, the staff 13 review was informed by the results of the Region I 14 initial license renewal inspection, the IP003 Phase 4.
15 This inspection was performed in November of 2018, as 16 has been mentioned, and coincided with the SLRA review 17 timeline. However, it should be noted that the Phase 18 4 inspection is related to the initial renewed license 19 and is independent of the SLRA review. We will 20 discuss this inspection more in detail later in our 21 presentation.
22 Next slide, please.
23 The Peach Bottom SER with a confirmatory 24 item was issued on October 7, 2019. The confirmatory 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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28 item was related to the core plate rim hold-down 1
bolts. During the ACRS Subcommittee meeting on 2
November 5, 2019, the staff presented how this 3
confirmatory item was closed on the basis of 4
supplemental information provided by Exelon. Since 5
that meeting, the staff has updated the SER to close 6
the confirmatory item. The updated SER was issued on 7
November 19, 2019, and details of the closure of this 8
confirmatory item will be discussed later in this 9
presentation.
10 During the staff's technical review of the 11 SLRA, it issued 48 RAIs, four of which were followup 12 RAIs. Although this was an early SLRA review, and new 13 topics were reviewed for the 60-to-80-year time 14 period, one might well have expected to have more RAIs 15 than initial license renewal. However, this was a 16 significant decrease in the number of RAIs from the 17 recent initial license renewal application reviews.
18 The staff believes that this was due to the high 19 quality of the subsequent license renewal application.
20 Next slide, please.
21 In the next few slides, we will present 22 the results of the staff's safety review, as described 23 in the SER. SER, Section 2, describes the scoping and 24 screening of structures and components subject to an 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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29 aging management review. The staff reviewed the 1
applicant's scoping and screening methodology, 2
procedures, and the results. The staff review 3
included, as required by the license renewal rule, the 4
results of the integrated plant assessment, the 5
safety-related SSCs, non-safety-related SSCs affecting 6
safety functions, and SSCs relied upon to perform 7
functions in compliance with the Commission's 8
regulations for fire protection, environmental 9
qualification, station blackout, and anticipated 10 scrams without a scram.
11 Based on the staff's review, the results 12 from the in-office audit, and review of additional 13 information provided by the applicant, the staff 14 concluded that the applicant's scoping and screening 15 methodology and implementation were consistent with 16 the SRP SLR and the requirements of 10 CFR Part 54.
17 Next slide, please.
18 SER, Section 3, and its subsections, cover 19 the staff's review of the aging management programs 20 for managing the effects of aging, in accordance with 21 10 CFR 54.21(a)(3). Sections 3.1 through 3.6 include 22 the AMR items in each of the general system areas 23 within the scope of license renewal, which is shown on 24 this slide. For a given AMR item, the staff reviewed 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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30 the item to determine whether it is consistent with 1
the GALL SLR report. For AMR items not consistent 2
with the GALL SLR report, the staff reviewed the 3
applicant's evaluation to determine whether the 4
applicant has demonstrated there is reasonable 5
assurance that the effects of aging will be adequately 6
managed, so that the intended functions will be 7
maintained, consistent with the current licensing 8
basis for the subsequent period of extended operation.
9 Based on this review, the results from the 10 in-office audit, and additional information provided 11 by the applicant, the staff concluded that the 12 applicant's aging management review activities and the 13 results were consistent with the SRP SLR and the 14 requirements of 10 CFR Part 54.
15 Next slide, please.
16 The SLRA described a total of 47 AMPs, 11 17 new AMPs, and 35 existing. This slide identifies the 18 applicant's original SLRA distribution of these AMPs 19 in the left column and the final disposition, as 20 documented in the SER, in the right column. All of 21 the AMPs, with the exception of the plant-specific 22 AMP, were evaluated by the staff for consistency with 23 the GALL SLR report. As a result of the staff review, 24 the applicant made several changes in the AMPs.
25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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31 However, the distribution of AMPs did not change, as 1
you will see comparing the left column and the right 2
column. The plant-specific AMP was evaluated against 3
the criteria contained in Appendix A1 of the SRP SLR.
4 Based on the staff's review, the results 5
from the in-office audit, and review of additional 6
information provided by the applicant, the staff 7
concluded that the applicant's aging management 8
program activities and results were consistent with 9
the SRP SLR and the requirements of 10 CFR Part 54.
10 Next slide, please.
11 SER, Section 4, identifies time-limited 12 aging analysis, or TLAAs. Section 4.1 of the report 13 documents the staff evaluation of the applicant's 14 identification of applicable TLAAs. The staff 15 evaluated the applicant's basis for identifying those 16 plant-specific or generic analyses that need to be 17 identified as TLAAs and determined that the applicant 18 has provided an accurate list of TLAAs, as required by 19 10 CFR 54.21(c)(1).
20 Section 4.2 and 4.7 document the staff's 21 review of the applicable Peach Bottom TLAAs for the 22 areas shown on this slide. Based on its review, the 23 information provided by the applicant, the staff 24 concludes that either one of three conditions are met:
25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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32 (I) the analysis remains valid for the subsequent 1
period of extended operation; (ii) the analysis has 2
been projected to the end of the subsequent period of 3
extended duration, or (iii) the effects of aging on 4
the intended functions will be adequately managed for 5
the subsequent period of extended operation, as 6
required by 10 CFR 51.21(C)(1).
7 Based on the staff review, the results 8
from the in-office audit, and the review of additional 9
information provided by the applicant, the staff 10 concluded that the applicant's TLAAs analysis and 11 results were consistent with the SRP SLR and the 12 requirements of 10 CFR Part 54.
13 Next, Bill Rogers will assess the closure 14 of the confirmatory item and the Region I activities.
15 Thank you.
16 MR. ROGERS: Thank you, Bennett.
17 Good afternoon.
18 The SER with confirmatory item issued 19 October 7th, 2019, included one confirmatory item 20 associated with the BWR vessel internals AMP B.2.1.7.
21 Specifically, the applicant had proposed an 22 enhancement to perform one of two future activities 23 post-licensing to address the potential for stress 24 corrosion cracking of the core plate rim hold-down 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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33 bolts and its mitigation.
1 The first option was to install core plate 2
wedges, which the staff found acceptable. The second 3
option was to submit an inspection plan to the NRC for 4
future review and approval. Since the completed 5
inspection plan as well as the acceptance criteria was 6
not currently available during the staff's SLRA 7
review, that is, it would be developed at a future 8
date, this option did not satisfy the staff's need to 9
complete its technical review prior to granting a new 10 license.
11 In response to the staff's concern 12 regarding the inspection plan, the applicant submitted 13 a supplement to the SLRA which revised the enhancement 14 to AMP B.2.1.7, to be in accordance with BWRVIP 25, 15 Revision 1, to: one, install wedges or, two, install 16 core plate rim hold-down -- excuse me -- inspect core 17 plate rim hold-down bolts, or, three, demonstrate via 18 analysis that the installation of wedges and 19 inspection of the core plate rim hold-down bolts were 20 not required. The staff determined each of the three 21 options included in the SLRA supplement can be 22 confirmed by inspection through the reactor oversight 23 process and were, therefore, acceptable.
24 On the basis of this information, the 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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34 staff determined that its concerns related to the 1
confirmatory item are resolved, as documented in the 2
November 19, 2019, updated SER.
3 Next slide, please.
4 In conclusion, for the SLRA safety review, 5
the staff finds that the requirements of 6
10 CFR 54.20(a) have been met for the subsequent 7
license renewal of Peach Bottom Units 2 and 3.
8 Next, I'll discuss regional inspections 9
and observations on the plant condition.
10 The Region conducts a license renewal team 11 inspection, IP 71003 Phase 4, 5 to 10 years following 12 the entry into the initial period of extended 13 operation. The team examines a sample of AMPS to 14 verify the effects of aging were being managed 15 effectively to ensure structures, systems, and 16 components in the scope of these programs maintain the 17 ability to perform their intended functions.
18 I'll address the Peach Bottom IP 71003 19 Phase 4 initial license renewal inspection on the next 20 slide. The Peach Bottom IP 71003 Phase 4 initial 21 license renewal inspection was performed in November 22 of 2018 on both Units 2 and 3. Exelon had committed 23 to 35 aging management programs at Peach Bottom for 24 the initial period of extended operation. Seventeen 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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35 AMPs were previously existing program in which no 1
changes were required.
Twelve programs were 2
previously existing, but were enhanced. And there 3
were six new AMPs created.
4 For the Phase 4 inspection, a sample of 5
six of these AMPs were reviewed. The AMPs listed here 6
on the slide were selected based on inspection 7
procedure criteria such as new enhanced AMPs, AMPs 8
impacted by internal or external operating experience, 9
Resident Inspector input, AMPs not inspected by other 10 baseline inspections, and risk insights.
11 In addition, the staff considered the 12 applicant's periodic AMP effectiveness review, which 13 is performed every five years. The applicant's 14 reports on this activity were used by the staff in the 15 AMP selection process and to provide insights on 16 program performance.
17 The Region's inspection focuses on the 18 program's detection of aging effects, monitoring and 19 trending, corrective actions, and implementation of 20 operating experience elements. The inspection team 21 did not identify any findings and concluded that 22 Exelon that was effectively implementing the AMPs 23 review.
24 Next slide, please.
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36 And before we go on, were there any 1
questions on that specific topic related to the 2
earlier question?
3 VICE CHAIRMAN SUNSERI: It just strikes me 4
as, I guess, impressive that an inspection scope so 5
big and of so many technical areas, and you have no 6
findings. I mean, you could look at it, I want to 7
look at as a glass half full; it was a very thorough 8
inspection and they did a good job. Another way of 9
looking at it, though, is you didn't look at it very 10 good and missed something, right? So, that's what I'm 11 trying to figure out.
12 MR. ROGERS: Okay. I'd like us to give 13 the Region an opportunity to address that comment or 14 question.
15 MR. GRAY: Thanks for that.
16 This is Mel Gray. I'm a Branch Chief in 17
- NRC, Region I,
responsible for oversight of 18 inspections in license renewal. And I have with me 19 Kevin Mangan, and he was a team leader. But I'm going 20 to turn it over to Kevin.
21 My opinion definitely is it was an 22 invasive inspection that demonstrated licensee 23 performance.
24 But go ahead, Kevin.
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37 MR. MANGAN: Yes, so for that inspection, 1
as you said, this is Kevin Mangan and I was the team 2
lead.
3 That inspection is a one-week inspection 4
with three inspectors. And as you said, we didn't 5
identify any violations. Of note, it was the first 6
Phase 4 inspection ever done in the United States. We 7
have done a couple since then, one in Region I and I 8
think one in Region II. There may be one or two 9
others.
10 There were some violations identified in 11 other inspections of this inspection, but here and, 12 then, we also did Ginna, and that also identified no 13 finding.
14 MEMBER KIRCHNER: Could I ask a follow-on 15 question then, Bill?
16 I know at the Subcommittee meeting we 17 heard good things about the applicant's preventive 18 maintenance program, particularly with regard to 19 cables. We heard about the diesel generator cables.
20 So, fairly proactive.
21 If my notes are correct, the applicant, 22 they changed out about 100 -- there are about 100 23 medium-voltage circuits and they replaced about half.
24 So, I'm curious why you inspected medium-voltage 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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38 cables rather than, say, I&C protection system cables.
1 MR. MANGAN: This is Kevin Mangan again.
2 So, for that particular AMP, a lot of the 3
cables you've mentioned are, for the scope of the AMP, 4
I think there was only 8 or 10 cables in scope. The 5
cables that were replaced were not in the scope of the 6
AMP. They were in the scope of license renewal, but 7
were excluded because they were energized less than 25 8
percent of the time, which was the criteria when they 9
first received their license renewal.
10 So, for the cables we looked at, which is 11 limited scope, they are risk-significant and there 12 were changes to the GALL from -- Peach Bottom was a 13 pre-GALL plant. Through Rev. 1 and Rev. 2, they went 14 from 10-year inspections to seven-year inspections, 15 and that particular requirement that excluded cables 16 that were energized less than 25 percent of the time 17 was removed. So, those are some of the reasons why we 18 looked at that, to see what kind of changes Exelon was 19 making to the program to address the operating 20 experiences of the GALL reports.
21 MEMBER KIRCHNER: Well, if I remember 22 correctly from the Subcommittee meeting, and the 23 applicant and your inspections, going back to the 24 diesel generator cables, those are active less than 25 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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39 percent of the time. And yet, there was a problem 1
there which the applicant addressed and corrected.
2 I'm not sure about that 25 percent of the 3
time. It's still sticking in my mind as not a good 4
criterion to use on cable inspection. So, this is a 5
more generic question than just the applicant.
6 MR. ROGERS: So, I think it might be 7
helpful to have one of the electrical reviewers 8
address the change to the GALL and how that's been 9
modified.
10 MR. SADOLLAH: Yes. Hi. This is Mo 11 Sadollah at NRR, a Design Engineer.
12 So, that provision that was in the 13 previous GALL revision, Rev. 0, subsequently, in Rev.
14 1 and Rev. 2, and then, ultimately, in the SMR, that 15 was removed. So, that 25 percent threshold was no 16 longer there. Whether the cables are energized or 17 not, they're considered in the scope.
18 MEMBER KIRCHNER: That's what I was 19 looking for. So, that's been removed?
20 MR. SADOLLAH: Yes.
21 MEMBER KIRCHNER: Okay. Thank you.
22 MR. SADOLLAH: Yes.
23 MR. ROGERS: Any additional questions on 24 that topic?
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40 (No response.)
1 Go to slide 14.
2 Okay. At the ACRS Subcommittee meeting on 3
November 5th, 2019, the Senior Resident Inspector 4
discussed the plant's performance and material 5
condition. The Senior Resident stated that the NRC 6
assessment of Peach Bottom was that the material 7
condition of the plant was acceptable and meets 8
regulatory requirements for systems, structures, and 9
components, based on the inspection results and green 10 performance indicators which resulted in both Peach 11 Bottom units being in the licensee response column.
12 In addition, Resident Inspectors continue 13 to inspect and assess the licensee's ability to manage 14 the effects of aging through the baseline inspection 15 program.
16 And again, if there are any additional 17 questions related to plant material conditions or how 18 this assessment was made, I would offer the question 19 to the Region in that area.
20 VICE CHAIRMAN SUNSERI: I recall the 21 discussion was very good at the Subcommittee. So, we 22 got a really thorough briefing then.
23 MR. ROGERS: Good. Thank you.
24 And considering the NRC inspection 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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41
- results, the inspectors found that the aging 1
management programs were being effectively implemented 2
in accordance with the facility's renewed license.
3 And the NRC will continue to monitor AMP effectiveness 4
using the baseline reactor oversight process.
5 And if there are no additional questions 6
at this point, I'll turn the presentation over to 7
Bennett for a summary conclusion.
8 MS. BRADY: The NRC has now completed its 9
presentation of its conclusions from the staff's 10 safety review of the Peach Bottom SLRA and the Region 11 I conclusions on AMP inspections and plant license 12 conditions.
13 At this point, we would be pleased to 14 address any further questions that you may have.
15 VICE CHAIRMAN SUNSERI: Any additional 16 questions or comments?
17 MEMBER BLEY: Yes, I have one. This is 18 not related to this particular application, but from 19 the NRC staff side, and the licensee using the new 20 GALL, and your reviews, did you find places where you 21 think you're going to need to make changes to the 22 subsequent licensee renewal GALL? And could you tell 23 us about any of those?
24 MS. BRADY: Yes. Right now, we are just 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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42 beginning the process. We've collected a lot of 1
ideas/opinions on changes that should be made to the 2
GALL SLR and SRP SLR. We will be reviewing the 3
proposed changes. At some point in the future, there 4
will be an Interim Staff Guidance with these changes.
5 And they'll likely incorporate -- that would be one 6
that would be considered to be modified.
7 MEMBER BLEY: Okay. Thanks. Any idea 8
when that timeframe will come to pass?
9 MR. ROGERS: That person is sitting behind 10 you.
11 (Laughter.)
12 MEMBER BLEY: Maybe they would like to 13 comment.
14 MR. OESTERLE: Thank you, Bill.
15 This is Eric Oesterle from the NRC staff.
16 So, thanks for the question, Dennis.
17 Back in March of this year, we did have 18 our first SLR lessons learned meeting from reviews of 19 the first three applications to date, and we did 20 identify a number of technical issues which we thought 21 were ripe for considerations and inclusion perhaps in 22 an update to the SLR guidance documents, one of which 23 happened to be an issue regarding irradiated 24 structural steel.
25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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43 So, we have compiled a list of those 1
technical issues, and, in fact, we're having our 2
second SLR lessons learned public meeting on December 3
the 12th. So, we're continuing to engage with the 4
applicants and with industry to address these 5
technical issues that have come up.
6 MEMBER BLEY: Thanks a lot. We look 7
forward to seeing that whenever it comes to pass.
8 VICE CHAIRMAN SUNSERI: Yes. This is kind 9
of a crystal-ball question, but would you anticipate 10 that those improvements would help reduce the number 11 of RAIs coming through the process?
12 MR. OESTERLE: Yes.
13 VICE CHAIRMAN SUNSERI: Because people 14 will know in advance what they should be providing?
15 MR. OESTERLE: Eric Oesterle from the 16 staff.
17 And, yes, that's one of the goals or one 18 of the criteria for identifying some of these 19 technical issues, if not as a new issues, but areas 20 where clarification can be provided. One of the goals 21 is to reduce the number of RAIs.
22 And to address a question that you had, 23 Member Dennis, we're looking, currently looking at 24 whether or not we're going to do an update of the 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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44 entire document or whether or not we're going to group 1
issues and put them out in three or four separate 2
ISGs. But, tentatively, we're looking at the latter 3
part of next year to start coming out with the drafts.
4 VICE CHAIRMAN SUNSERI: Okay. Any other 5
questions?
6 (No response.)
7 So, while we're opening up the phone line 8
for public comments, I'll turn it to the room and ask 9
if there's any members of the public in the room that 10 would like to make a statement or a comment. Now come 11 to the microphone and state your name and your 12 comment.
13 I can't see anyone.
14 MEMBER BLEY: No, nobody.
15 VICE CHAIRMAN SUNSERI: Okay. Thank you, 16 Dennis.
17 And now, we'll go to the open public phone 18 line for any comments. State your name and provide 19 your comment, please.
20 (No response.)
21 All right. No comments. So, we'll close 22 the phone line again.
23 And I just would like to extend our 24 appreciation to the applicant and the staff for the 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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45 thoroughness of your review and a very good 1
Subcommittee where we reviewed these in great detail.
2 And now, it makes the full Committee meeting almost 3
seem anticlimactic, which I guess is a good thing, 4
right? So, we did all the hard work and this is the 5
fruit of the labor here.
6 So, thank you all for your comments, and 7
I'll turn it back to the Chairman now.
8 CHAIRMAN RICCARDELLA: Thanks.
9 We're supposed to take a break at 2:30.
10 We have until 2:45 until the next meeting --
11 VICE CHAIRMAN SUNSERI: Yes. So, we have 12 a letter that we could read in, you know, do the read-13 in on. I mean, we could fit it in the 30 minutes.
14 CHAIRMAN RICCARDELLA: Okay.
15 VICE CHAIRMAN SUNSERI: So, are you going 16 to pull that up? Got it. All right.
17 Thank you. You are excused. Thank you.
18 We'll need you again at 2:45.
19 (Whereupon, the foregoing matter went off 20 the record at 1:59 p.m. and went back on the record at 21 2:45 p.m.)
22 CHAIRMAN RICCARDELLA: So, we'll reconvene 23 the meeting.
24 And the subject is NuScale source term, 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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46 and the lead on this is Dave Petti.
1 MEMBER PETTI: So, we had the Subcommittee 2
-- what? -- two weeks ago, the week in front of 3
Thanksgiving, and discussed a lot of these issues in 4
detail. There was only one area that came up sort of 5
as a questionable one that I believe NuScale will talk 6
about it in a high-level summary, and then, NRC will 7
give a more complete, but a high-level overview, 8
again, because most of us were in the Subcommittee 9
meeting.
10 So, let's start with NuScale.
11 MR. MILTON: Sure. This is Mike Milton.
12 I'm basically going to turn the slides and be here for 13 moral support. Zack Rad, Director of Regulatory 14 Affairs, is going to kick us off from Corvallis. And 15 then, our team in Corvallis will lead the discussion.
16 Okay?
17 Okay. So, I'll turn it over now to you, 18 Corvallis. Is that correct? Please go.
19 CHAIRMAN RICCARDELLA: Corvallis, are you 20 there?
21 MR. MILTON: I heard sound, too. It was 22 very low.
23 Carrie, can you hear us in the room okay?
24 Because we didn't hear anything coming from the phone 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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47 line at the moment.
1 MS. FOSAAEN: Yes. We just need one 2
minute here in Corvallis, if that's all right.
3 CHAIRMAN RICCARDELLA: Okay.
4 MR. MILTON: Okay.
5 MR. RAD: Okay. Good afternoon. This is 6
Zachary Rad, Director of Reg Affairs for NuScale 7
Power. I just have a few opening remarks.
8 Like we discussed at the Subcommittee 9
meeting, we only intend to provide supplemental 10 information on a single topic during this meeting, and 11 not repeat our comprehensive presentation. So, as we 12 discussed in the Subcommittee meeting, one of the 13 topics that came up late in the review of the Accident 14 Source Term Topical Report was associated with 15 postulated leakage from the hydrogen monitoring system 16 coincident with a beyond design basis severe accident.
17 We're going to provide information regarding elements 18 on the topic that hadn't been fully addressed during 19 the Subcommittee meeting to ensure that the record 20 accurately reflects our position.
21 So, as I noted in the Subcommittee 22 meeting, the reason this topic is here for discussion 23 in this forum is because it's a specific item we were 24 unable to reach alignment on with the staff during the 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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48 review, and the decision has been made to move forward 1
by --
2 (Interference on the public line.)
3 MEMBER REMPE: Excuse me for just a 4
minute, Zack.
5 If you are on the public
- line, 6
unfortunately, we can hear everything you're saying.
7 So, could we please ask you to mute your phones and we 8
can hear the applicant. Thank you.
9 MEMBER BLEY: Go ahead, Zack.
10 MR. RAD: All right. So, I'm just going 11 to take a few minutes to address our position in 12 summary. Jim Osborn, who's here with me as well, will 13 provide some supporting details.
14 So, as I just noted, late in the review 15 the staff raised some questions regarding the 16 inclusion of some postulated leakage from the hydrogen 17 monitoring system, in addition to a severe or 18 concurrent with a severe beyond design basis accident.
19 And that's specifically estimation of the contribution 20 from operational leakage.
21 It's our position that NuScale has 22 addressed this topic consistent with the applicable 23 regulations and
- guidance, and specifically, 24 NUREG-0737, and within that, the provisions addressing 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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49 control room habitability requirements and integrity 1
of systems outside containment likely to contain 2
radioactive material.
3 It's important that the existent systems, 4
such as the hydrogen monitoring system, and their 5
potential to contain active source
- term, was 6
considered at the time the guidance was developed and 7
addressed within the guidance.
8 So, the guidance as well as the operating 9
fleet, and all previous applicants, addressed the 10 topic by including these systems in a program to 11 reduce leakage as low as practical. And this is an 12 operating program. So, I think that that's also 13 important to note. It includes testing during 14 refueling outages and a variety of other provisions.
15 NUREG-0737 also addresses systems with 16 known leakage, such as ESF systems, by specifically 17 addressing those, where applicable, and those are 18 addressed within the provisions, specifically control 19 room habitability requirements. It's probably also 20 worth noting that NuScale doesn't have any such 21 systems.
22 So, NuScale addressed the topic in the 23 same manner at the same level of detail, or even a 24 greater level of detail, than previous applicants.
25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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50 It's our position that there's no material difference 1
in the NuScale design that makes existing guidance 2
insufficient or diminishes the applicability of 3
precedence. It's also important to note that, for 4
NuScale, this is not a safety concern; it's not a 5
design or a licensing basis issue for NuScale. It's 6
just a matter of reasonable assurance; that is, that 7
the guidance and precedent for design -- following 8
guidance and precedence for a design with lower 9
associated risk is sufficient for reasonable 10 assurance.
11 So, with that, that's my summary. If 12 there aren't any questions, I'm going to turn it over 13 to Jim to address some supporting elements in more 14 detail.
15 MR. MILTON: Yes, we can proceed.
16 MR. RAD: All right. Thanks.
17 MR. OSBORN: Good afternoon. This is Jim 18 Osborn.
19 So, I want to preface the presentation and 20 say that the purpose of the presentation is to convey 21 the fact that NuScale has designed out a core melt 22 scenario, and therefore, there is no design deficiency 23 related to the hydrogen monitoring system. This was 24 discussed in the earlier meeting a couple of weeks 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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51 ago.
1 The first slide here talks about risk 2
significance. So, the core damage frequency of the 3
NuScale power module is very small. The sum of the 4
internal events has a core damage frequency of on the 5
order of 3E to the minus 10 module critical years per 6
year. This is a significant margin of about five 7
orders of magnitude to the NRC's safety goal.
8 So, accidents in which hydrogen monitoring 9
could be used, i.e., those that have an intake 10 containment that results in core damage, are even a 11 lower frequency, on the order of E to the minus 11.
12 But, even with a significant increase in consequences, 13 the overall risk still remains small, considering the 14 frequency of these events is so small. You see the 15 equation up there for risk.
16 And I will quote from the last bullet on 17 the slide. It says, "In any licensing review or other 18 regulatory decision, the staff should apply risk-19 informed principles when
- strict, prescriptive 20 application of deterministic criteria is unnecessary 21 to provide reasonable assurance of adequate protection 22 of public health and safety." This quote is from the 23 SRM for SECY-19-0036, which was entitled, "Application 24 of the Single Failure Criteria to the NuScale's 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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52 Inadvertent Actuation Block Valves".
1 But this directive should also be applied 2
to other deterministic criteria like hydrogen 3
monitoring system leakage. The core melt sequences in 4
which hydrogen monitoring could even be utilized, 5
i.e., there's an intact containment, can be considered 6
negligible and, therefore, not risk-significant.
7 Therefore, to provide reasonable assurance of adequate 8
protection of the public health and safety, this 9
incredible sequence would not need to be considered in 10 a review using proper application of risk-informed 11 principles.
12 Next slide, please.
13 The systems used for hydrogen monitoring 14 are included in the leakage monitoring program. This 15 program is one of the post-TMI action items that is 16 intended to minimize the potential leakage from 17 systems outside containment that may contain actual 18 source term. NuScale is in compliance with this 19 regulation. The implementation of this program 20 ensures that these systems are essentially leak-tight 21 and are available for use post-accident.
22 The seismic aspects of the next bullet 23 will be addressed in a later slide. So, next slide, 24 please.
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53 But what if it's hypothesized 1
deterministically that the hydrogen monitoring system 2
does leak? There would be subsequent emergency 3
response actions to isolate that leak. The 4
particulars of this action would be the responsibility 5
of the emergency response organization as an unplanned 6
and unanticipated emergency action, for which there 7
are no explicit dose acceptance criteria.
8 Recently, just two weeks ago, the NRC 9
stated in the Brunswick SER for hardened vents that, 10 "For plant personnel performing emergency response 11 actions during a beyond design basis severe accident, 12 there are no explicit dose acceptance criteria." The 13 only purpose for the NuScale hydrogen monitoring 14 system is for a beyond design basis severe accident.
15 Therefore, the 5-rem limit of 10 CFR 50.34(f)(2)(vii) 16 does not apply to the operator action of re-isolating 17 the containment isolation valves used in hydrogen 18 monitoring.
19 Next slide.
20 Based on the nuclear industry's low risk 21 from severe accidents, which are even lower for the 22 NuScale design, the NRC relaxed the regulatory 23 requirements for hydrogen monitoring. As a severe 24 accident monitoring system, it is not required to be 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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54 safety-related or Seismic Cat 1 because there is no 1
design basis accident that involves the hydrogen 2
monitoring system.
3 So, for the NRC staff to compare NuScale's 4
non-safety-related, non-seismic, Cat 1 design of a 5
hydrogen monitoring system to other designs that are 6
safety-related or Seismic Cat 1, is not commensurate 7
with a risk-informed review. It is not appropriate 8
for the NRC to relax requirements based on the risk 9
significance
- and, then, penalize a
design by 10 deterministically presuming it will leak because it is 11 non-safety or not Seismic Cat 1.
12 This application of risk significance is 13 evident in the guidance provided in Reg Guide 1.183 14 related to offsite dose consequences for hydrogen 15 purge operations for severe beyond design basis 16 accidents. For the NRC to require NuScale to 17 deterministically account for hydrogen monitoring 18 system leakage runs counter to the application of its 19 risk significance and does not reflect a risk-informed 20 review.
21 Are there any questions?
22 MEMBER MARCH-LEUBA: Yes, this is Jose.
23 Can you clarify something for me? The hydrogen 24 monitoring system is non-safety grade and it is 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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55 connected to the containment evacuation system, is 1
that correct?
2 MR. OSBORN: So, yes, the hydrogen 3
monitoring system is made up of three different 4
systems: the containment evacuation, the sample 5
system, and the core flood and drain. They are 6
connected to the containment through containment 7
isolation --
8 PARTICIPANT: I'm on this call and I can't 9
hear anything from the actual meeting.
10 MR. OSBORN: The containment isolation 11 valves are safety-related.
12 MEMBER KIRCHNER: Can you wait a moment?
13 We're having a problem.
14 PARTICIPANT: I can hear you talking now, 15 but I can't hear the ACRS meeting apparently.
16 CHAIRMAN RICCARDELLA: No, this is the 17 ACRS meeting room. I think what you're not hearing is 18 the NuScale remote call-in. So, we're trying to 19 address that right now.
20 PARTICIPANT: Oh, okay.
21 CHAIRMAN RICCARDELLA: Steve, can you hear 22 me? Steve Schultz?
23 DR. SCHULTZ: Yes. Yes, Pete.
24 CHAIRMAN RICCARDELLA: But you couldn't 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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56 hear NuScale talking from Corvallis?
1 DR. SCHULTZ: That's correct. Whenever 2
you go to the phone line, we can't hear. The same 3
thing happened in the Peach Bottom meeting.
4 CHAIRMAN RICCARDELLA: Okay. We're trying 5
to work on it.
6 Mike, are you there?
7 DR. CORRADINI: I am here.
8 CHAIRMAN RICCARDELLA: And you can hear 9
Corvallis, too?
10 DR. CORRADINI: At this moment I can only 11 hear you.
12 CHAIRMAN RICCARDELLA: Yes, because 13 they're not talking right now.
14 (Laughter.)
15 But, when they were talking, you could 16 hear?
17 DR. CORRADINI: Yes, I could, sir.
18 CHAIRMAN RICCARDELLA: Are you on the 19 closed line or the public line?
20 DR. CORRADINI: The closed line.
21 CHAIRMAN RICCARDELLA: Okay. I think the 22 other people who are having problems are on the public 23 line, not the closed line.
24 MEMBER MARCH-LEUBA: Okay. So, let's try 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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57 it again. Corvallis, this is Jose March-Leuba.
1 So, I was trying to confirm that the 2
hydrogen monitoring system is connected to the CES, 3
and you were describing the three systems that are 4
interconnected.
5 MR. OSBORN: Yes, that's correct. Yes, 6
that's correct.
7 So, to understand, the hydrogen monitoring 8
system is portions of three systems. So, it's not in 9
itself its own system. It's just a pathway utilizing 10 three different systems.
11 MR. MILTON: Okay. Hang on a second, Jim.
12 So, it's a pathway utilizing three 13 different systems, and the hydrogen monitoring system 14 is actually a portion of three systems.
15 MEMBER MARCH-LEUBA: But all of those 16 three systems are downstream of the containment 17 isolation valves, which is the last safety-grade 18 system that protects containment on a safety-grade 19 basis, is that correct?
20 MR. OSBORN: I believe that's correct, 21 yes.
22 MEMBER MARCH-LEUBA: All right.
23 MR. MILTON: We believe that's correct.
24 MEMBER MARCH-LEUBA: Yes. I realize that 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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58 the probabilities or the frequencies might be 10 to 1
the minus 11, but giving the operator the temptation 2
to open the isolation valves for the containment to 3
measure the hydrogen because he's suspects that it's 4
hydrogen, it's counterproductive. I mean, you should 5
never under any circumstance open the isolation valves 6
if you suspect that the containment is contaminated.
7 So, in my opinion, we have two options.
8 We can just not have a hydrogen system or connect the 9
hydrogen system that works. Because connecting the 10 system to the CES and the third system, which I don't 11 know what it is, which none of them are seismically-12 qualified, you are asking for trouble.
13 MR. OSBORN: So, I understand that they're 14 not seismically-qualified, they're not Seismic Cat 1, 15 they're not safety-related. That's because the NRC 16 relaxed the regulatory requirements on this system 17 based on its risk significance. So, NuScale did not 18 do this on their own. They did this in response to 19 the NRC regulations.
20 MEMBER MARCH-LEUBA: Okay. So, we will 21 talk to the staff here in person.
22 Sorry, can you relay for the public?
23 MR. MILTON: Oh, sure. The answer is it's 24 we understand that our system was designed because the 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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59 NRC relaxed the requirements based on the risk 1
significance. We understand your point, but we feel 2
our design was justified, per the regulations.
3 MEMBER MARCH-LEUBA:
Yes.
In my 4
opinion -- and I will take care of this with the staff 5
-- the hydrogen system the way it's designed is 6
producing more problems than it solves. Because if 7
you ever need it, you are going to de-isolate the 8
containment.
9 MEMBER PETTI: So, let's ask the question 10 and the staff may know. Current PWRs, is the hydrogen 11 monitoring system safety-grade or non-safety-grade?
12 We can wait for the answer until staff speaks.
13 MS. FOSAAEN: Okay. I was going to say 14 Reg Guide 1.7 provides the requirements for hydrogen 15 monitoring systems, and our system followed Reg Guide 16 1.7, and it does specify that it does not need to be 17 safety-related.
18 MEMBER PETTI: Okay. Thank you for that 19 information.
20 MR. MILTON: So, to repeat, our design, 21 per Reg Guide 1.7, does not require the system to be 22 safety-related, and we followed the design per the Reg 23 Guide, to repeat that.
24 MEMBER MARCH-LEUBA: I'll follow up with 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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60 the staff when we can actually communicate.
1 MR. MILTON: I understand. Thanks.
2 MEMBER PETTI: Any more questions?
3 MEMBER REMPE: Okay. So, I have a 4
question that stems from what was discussed at the 5
Subcommittee meeting, that comes from the source term 6
evaluation. And it was discussed in the open session.
7 And I'd like to bring it up again to NuScale because 8
I think we dismissed something I was trying to raise 9
last meeting prematurely. Okay? So, I want to give 10 them the opportunity to respond.
11 When you did your source term, you looked 12 at small break LOCAs; you looked at rod ejection 13 accidents. And as the release is coming from the 14 vessel, you know, the depressurization occurs, I 15 mentioned some concerns about some aerosols that might 16 be going out into the containment that would interfere 17 with that wonderful radar-based sensor for water level 18 detection.
19 And NuScale came back and said, hey, we 20 won't have degradation; we're only worried about 21 design basis events here, and the iodine spike came 22 from that.
23 But there is something called fuel 24 fragmentation and dispersal that we've been talking 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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61 about. And that occurs before you have core 1
degradation. And so, I'd like to bring that up again, 2
that there is the potential that there could be some 3
aerosols released into the containment, and the ECCS 4
is triggered when the water level gets to a certain 5
height, and that could interfere with the triggering 6
of the ECCS.
7 And so, I'd like to hear NuScale's 8
response back again on that question.
9 MEMBER BROWN: Would the aerosols be any 10 different than the normal foaming you get from the 11 boiling in the upper area? Because that's the 12 pressurizer. So, you've got a steam-water interface 13 there that gives you the same issues relative to 14 whatever detector you're worried about, which I'm 15 aware of, as any injected or introduced aerosols would 16 be due to something else. I mean, they've got to make 17 the system work at this steam-water interface where 18 all these bubbles -- and you've got to compensate for 19 that. I mean, everybody that builds these things has 20 to compensate for it, like 30 percent. It's not a 21 half-a-percent error thing.
22 MEMBER REMPE: The staff has defined an 23 ITAAC that talks about pressure conditions, radiation 24 conditions, et cetera. There's nothing in there about 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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62 dispersed aerosols. And so, yes, it would be 1
different than just a foamy thing. You could have 2
depressurization occurring and they could be elevated.
3 There's uncertainty on what those aerosols would be 4
like, but it's something that the staff has raised for 5
PWRs.
6 MEMBER BROWN: But if they're in the upper 7
part, as opposed to part of the surface steam 8
interface --
9 MEMBER REMPE: They don't have to be in 10 there.
11 MEMBER BROWN: -- that would be a 12 different issue --
13 MEMBER REMPE: Yes.
14 MEMBER BROWN: -- relative to the 15 disturbing of the thing.
16 MEMBER REMPE: Absolutely.
17 MEMBER PETTI: Just to be clear, the fuel 18 aerosols, this is pieces of fuel, right?
19 MEMBER REMPE: Right.
20 MEMBER PETTI: These would be fairly 21 large.
22 MEMBER REMPE: No, not necessarily. If 23 you looked at some of the pictures of fuel 24 fragmentation and dispersant from the tests --
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63 MEMBER PETTI: When you call them 1
"aerosol," it sounds like they're pieces of metal.
2 MEMBER REMPE: It's not pieces of metal.
3 They're fine fragments.
4 MEMBER PETTI: Fines of -- fine micron?
5 MEMBER REMPE: I'd have to go back and 6
look at some of the reports, but they looked pretty 7
small. And they could be elevated just like the 8
sediment, or whatever they talked about that they 9
artificially --
10 MEMBER PETTI: They're really particulate 11 dust?
12 MEMBER REMPE:
It could be,
- yes, 13 particulates that are elevated.
14 MEMBER PETTI: Not aerosol necessarily?
15 MEMBER REMPE: Yes. And so, again, it 16 could be particulates.
17 So, anyway, I'm waiting for NuScale to 18 respond back to the question again.
19 MR. MILTON: So, this is Mike. I have to 20 repeat back the responses. So, just kind of break up 21 a little bit and give me a moment to be able to relay 22 the information because of the phone line issue going 23 on.
24 Back to you guys, Jim, Carrie.
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64 MEMBER REMPE: Has the connection been 1
lost?
2 MEMBER BROWN: NuScale?
3 MR. OSBORN: Could you give us a second, 4
please?
5 MEMBER BROWN: Oh, okay.
6 MR. MILTON: Yes, let me know. Let me 7
know.
8 MR. OSBORN: All right. Just a moment.
9 (Pause.)
10 MEMBER REMPE: You know, they don't have 11 to answer like right now because I'd like the staff to 12 also weigh-in on it, and they could perhaps answer 13 later, instead of just waiting here.
14 MR. MILTON: That's fine.
15 MEMBER REMPE: Is that okay with you?
16 CHAIRMAN RICCARDELLA: Hey, guys, can we 17 have one meeting, please?
18 MEMBER KIRCHNER:
So,
- Joy, for 19 clarification, are you asking whether the particulate, 20 whatever comes out of the core, is going to actually 21 deposit upon the sensor and interfere with its 22 performance, or it's dispersed in the atmosphere and 23 it's going to impact the performance of the radar?
24 MEMBER REMPE: It's the latter. It's the 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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65 fact that radar -- and we can say it's a radar-based 1
sensor. That's in the open now, but --
2 MEMBER KIRCHNER: Then, the issue isn't 3
fuel aerosol particulate; it's how it performs in the 4
fog and steam.
5 MEMBER REMPE: Right. Well, but fog with 6
particulates.
7 MEMBER KIRCHNER: Okay, but you're looking 8
for a hard interface and a water level, and it's not 9
likely that -- I'm not going to answer the question 10 for NuScale. But, based on my experience with radar 11 systems, fog and steam is not going to impact its 12 ability to find a hard object or an interface.
13 MEMBER REMPE: But this is not just fog 14 and steam. It could be particulates. You've seen 15 pictures of what happens --
16 MEMBER KIRCHNER: Yes, but it's still my 17 understanding that --
18 MEMBER REMPE: -- with the fuel that way.
19 It's oxidized cladding.
20 MEMBER KIRCHNER: Yes, but you're not 21 going to have that much fuel dispersed.
22 MEMBER REMPE: We don't know that.
23 MEMBER BROWN: If you'll go look at some 24 of the designs of radar-type detectors for this, they 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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66 talk about a frothy steam-water interface --
1 MEMBER KIRCHNER: Right. Yes, that's more 2
of an issue, but that's independent of having any 3
particulate.
4 MEMBER BROWN: Put aside the particulate, 5
okay?
6 MEMBER KIRCHNER: Yes.
7 MEMBER BROWN: That you have to have 8
compensation for.
9 MEMBER KIRCHNER: Right.
10 MEMBER BROWN: And I think they're 11 advertising a fairly decent accuracy for it, like 1 12 percent or a half a percent or 2 percent. I don't 13 remember the number. I read it at one time. So, 14 Joy's concern about that, basically the steam-water 15 interface, and then, the particulate thing comes in as 16 a secondary relative to the --
17 MEMBER REMPE: But the staff has taken 18 great pains to have ITAACs that identify the 19 characteristics that have to be validated.
20 MEMBER BROWN: No, I understand that.
21 MR. OSBORN: So this is NuScale if you 22 guys are ready.
23 Right. So we've taken a look. And we 24 don't have this level of detail yet because it hasn't 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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67 been defined yet in the EQ program, but the EQ program 1
does require that we identify the specific environment 2
in which the instruments are required to operate in.
3 And there are a lot of variables here including 4
whether or not it's a plausible scenario to have 5
significant core melt at the time that the instrument 6
would be required to operate and then evaluate whether 7
or not the equipment would operate in that 8
environment, if required.
9 So the program has to define those 10 attributes and then determine whether or not the 11 equipment is qualified to operate then. And that's 12 where we are. So we don't have the answer to your 13 specific question.
14 MEMBER REMPE: Let me be real clear. This 15 is before you get core melt. This is something that 16
-- that's how you deterred me a couple of weeks ago 17 and I thought about it some more and it's like no, 18 it's operations. Some of the cladding becomes 19 oxidized and that's something that's been discussed in 20 the LWRs and now we are trying to deal with what 21 happens with a design basis accident and I'm not 22 talking about core melt. And the staff has been very 23 specific about what you've got to qualify that since 24 before and I'm probing about maybe the staff did add 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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68 another piece to that. Okay?
1 MR. OSBORN: Right, so the fundamental 2
tenants of my answer still apply, that the environment 3
in which they're qualified to operate and has to be 4
defined at that level of detail and it hasn't yet been 5
done.
6 MEMBER REMPE: But the staff has radiation 7
levels. They've got humidity levels. They've got a 8
bunch of temperatures. They've got a bunch of 9
requirements.
10 Yes, so I'll probe with the staff, but 11 anyway, I appreciate us discussing it now. Thank you.
12 CHAIRMAN RICCARDELLA: Let me just do a 13 check now.
14 Steve Schultz, are you hearing the full 15 conversation now?
16 DR. SCHULTZ: Yes, we are. It seems as if 17 it's fixed.
18 CHAIRMAN RICCARDELLA: Okay. Thank you.
19 MEMBER PETTI: Any other questions for 20 NuScale? Okay. Thank you. Time goes fast. Thank 21 you.
22 (Pause.)
23 MR. TESFAYE: Are you ready for us?
24 MEMBER PETTI: Yes, go ahead.
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69 MR. TESFAYE: Thank you. Good afternoon, 1
everyone. My name is Getachew Tesfaye. I am the NRC 2
Project Manager for NuScale's topical report on 3
accident source term and the TR as you know describes 4
a general methodology for developing accident source 5
terms and performance corresponding design base 6
accidents and other required accident radiological 7
consequence analysis to be referenced for NuScale's 8
Small Modular Reactor and other applications are 9
referenced in NuScale's SMR.
10 The NRC staff submitted an advanced 11 topical report evaluation to this committee on October 12 18 and presented its finding to the NuScale 13 Subcommittee on November 20 of this year.
14 Today, we will present the high-level 15 summary of the staff's findings with a focus on a 16 couple of items we took from the subcommittee meeting.
17 Jason, here to my right, and I will be 18 making presentation. The rest of the staff are 19 sitting in the audience and will be ready to answer 20 any question you have.
21 So topical report positions to NuScale and 22 NuScale requested a profile of 15 specific positions 23 listed in Section 1.2 of the report. And NRC staff 24 has determined that subject to the conditions and 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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70 limitations specified in Section 6 of the SER, the 1
methods described in the topical report are acceptable 2
for developing accident source terms and performing 3
accident radiological consequence analysis to be 4
referenced by the NuScale SMR design.
5 The staff approved positions 2 through 15 6
requested in topical report. The staff did not make 7
any finding of position 1 where NuScale categorizes a 8
core melt accident as beyond design basis event. And 9
the applicable NRC regulations do not require 10 classification of source terms of design basis or 11 beyond design basis to demonstrate compliance as a 12 requirement.
13 Therefore, the staff has determined that 14 the classification of a core melt accident as a beyond 15 design event for the NuScale design is not material 16 with staff's findings under this regulation.
17 Therefore, the staff did not make a finding on 18 position 1.
19 With that, I'll go to Jason to present one 20 takeaway from the subcommittee meeting, that is the 21 staff's independent analysis.
22 MR. SCHAPEROW: So one thing that the 23 staff did as part of its evaluation of NuScale's 24 topical report methodology was to perform an 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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71 independent analysis. This was to evaluate NuScale's 1
core damage event and their analysis of that and the 2
off-site consequences resulting from that.
3 Our approach was to use MELCOR. We used 4
MELCOR to simulate two scenarios, two core damage 5
scenarios. One was a CVCS line break inside 6
containment and the other was a failed open reactor 7
vent valve. In both of these scenarios, we assumed 8
that the ECCS failed to function properly.
9 So we used MELCOR. We calculated the 10 fission prior release into the environment for the two 11 scenarios and we took each of the two MELCOR results 12 and we put them into RADTRAD to turn them into a dose.
13 We predicted EAB, LPZ, and controlling doses and we 14 used this independent evaluation to compare against 15 what the applicant had come up with. And the doses 16 were comparable and also they were below the 17 regulatory dose criteria.
18 So this is -- again, this is one thing 19 that we did as part of our evaluation.
20 Next slide, please?
21 So the documentation is a little bit 22 complicated and in case the committee would like to go 23 into a little more detail on this. So the MELCOR 24 calculations themselves that the staff did are 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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72 documented in the report from April of this year.
1 It's listed at the top of slide 7.
2 We actually did calculations for three 3
scenarios in this report. The third scenario was a 4
bypass accident which wasn't used for the topical 5
report review. The reason we did these three 6
scenarios was to help the staff understand the 7
behavior of the NuScale reactor under severe accident 8
conditions and we also did a number of comparisons 9
against NuScale results for severe accident 10 simulations.
11 The second report listed here is -- we 12 took the MELCOR output from the two scenarios that 13 were in containment, had in containment releases, not 14 to bypass accident, and again, we turned those into 15 doses using standard -- using our RADTRAD model. So 16 the second report documents in further detail the 17 MELCOR results, MELCOR releases to the environment, 18 release two scenarios, and it also explains how the 19 releases were used in RADTRAD to calculate doses.
20 MEMBER PETTI: Just to be clear, you only 21 took two of them for the dose stage.
22 MR. SCHAPEROW: That's correct. The third 23 one was a bypass accident. We didn't take that 24 through the dose stage.
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73 MEMBER REMPE: So during our subcommittee 1
meeting, there was some confusion, but I was looking 2
at the correct report and although ACRS had looked at 3
it previously, but looked for a different reason to 4
support the PRA. And if I look at that report from 5
MELCOR, there are a lot of postulated reasons on why 6
there were differences in the result, whether it was 7
nodalization, where you assume the break was.
8 Do you have any -- now that you've had 9
since I think it was April when it was issued and you 10 had more time to think about it, do you have any 11 strong feelings on why there was so many differences?
12 Because I think the actual doses were a factor of 2 to 13 3 off. They were low, like by this earlier latter 14 stage that you probably applied, but there were some 15 significant differences in the report.
16 MR. SCHAPEROW: Yes, so I've thought about 17
-- so there's no -- because it's an integrated 18 calculation, there's not really it's very 19 difficult, it's very, very difficult to tease out 20 exactly what factors are dominating, driving the 21 differences.
22 There's a couple, in my mind, there's a 23 couple of obvious differences. If we could explore 24 just a little bit. One was the assumption of five 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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74 percent of the iodine was vapor that NuScale had made.
1 Another one dealt with a containment leak rate and the 2
NRC was calculating higher leak rates. So this is 3
some of -- maybe the bigger differences. There were 4
some differences between the NuScale calculations and 5
the staff calculations.
6 MEMBER REMPE: And even the code was 7
different is what I had heard in the past, that you 8
had different versions of MELCOR --
9 MR. SCHAPEROW: Yes --
10 MEMBER REMPE: -- being made.
11 MR. SCHAPEROW: So our comparison of our 12 MELCOR severe accident simulation against NuScale 13 severe accident simulation in the first document you 14 see on the slide, there were some differences, but 15 standing back the staff -- we don't feel the 16 differences were significant enough to affect these 17 kinds of calculations.
18 MEMBER PETTI: But in terms of the leak 19 rate, as I recall, NuScale just assumed a leak rate.
20 They didn't let the pressure determine the leak rate.
21 You guys used the actual pressure of the --
22 MR. SCHAPEROW: So NuScale had a technical 23 specification leak rate that they used in their 24 analysis. We did -- I think it was done classically 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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75 for many, many years which is to take the tech spec 1
leak rate and convert that into a hole size, a very, 2
very small hole, but convert that into a hole size and 3
then use that for the MELCOR simulation.
4 MEMBER PETTI: If the pressure goes 5
higher, then you get greater leak.
6 MR. SCHAPEROW: That's correct. And also, 7
if the materials -- if the gases in the containment 8
are different, you're going to get a different leak.
9 So NuScale's tech spec leak rate was based 10 on pressurizing the containment to err at a thousand 11 pounds. So we did that with MELCOR. We pressurized 12 NuScale's containment to a thousand pounds and we set 13 the hole size so that we got the 2 percent per day 14 leak rate, I'm sorry,.2 percent per day leak rate.
15 And then -- but that was it. We set the leak rate and 16 then we ran our MELCOR severe accident simulations.
17 And we ended up getting time variant leak rates, 18 exactly.
19 Actually, at one point the leak rate went 20 the other way, actually started going into the NuScale 21 containment because in a NuScale accident before you 22 start the heat up and generate hydrogen, you've got a 23 vacuum in there. So you actually -- actually, at one 24 point you draw a vacuum just before you get to the 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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76 core damage stages.
1 MEMBER PETTI: For the benefit of the 2
other
- members, it was not presented at the 3
subcommittee, but in the report, NuScale compared 4
STARNAUA the aerosol code they used in the containment 5
against MAEROS which is the subroutine inside MELCOR.
6 And they were on top of each other. So I think the 7
aerosol physics is the same in the two codes and it 8
has something to do with bounding conditions and 9
initial conditions in terms of the differences.
10 MR. SCHAPEROW: In my mind, two of the big 11 differences again was in one case NuScale had -- I 12 would characterize that as a conservative approach for 13 the amount of iodine vapor that's going to be sitting 14 in containment hour after hour after hour. But on the 15 other hand, we also were calculating a time dependent 16 leak rate which in some cases went above the.2 17 percent per day per leak rate that NuScale had 18 assumed.
19 So again, the calculations were different.
20 We did an independent calculation and to the best of 21 our ability to predict what would be leaving the 22 containment and we said fed that into RADTRAD.
23 MEMBER REMPE: I have one question that 24 I'd love to ask you just now and get it over with and 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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77 not close the meeting, but there's been a sentence in 1
this report that I tried to ask at the subcommittee 2
meeting, but we were in an open and I was told it was 3
the wrong version.
4 I would like to close it because it 5
doesn't make sense and it may be a typo. But I am 6
curious on what the sentence is and I'm afraid to say 7
it aloud in the open session, so let's -- if we can 8
have a brief closed session, if you don't mind.
9 MEMBER PETTI: If it's only on the staff's 10 confirmatory, that can't be in the open session?
11 MEMBER REMPE: Well, there's some numbers 12 in it. I sure would love to, but I'm afraid I'll get 13 in trouble, so I don't know what to do.
14 MR. SCHAPEROW: Are you referring to the 15 second report here?
16 MEMBER REMPE: No, the very first report, 17 there were some hours that are cited and I don't know, 18 the document is marked proprietary, so I don't know.
19 I have been curious about it for the last month or so 20 and I'd like to have my curiosity satisfied.
21 MR. SCHAPEROW: There is a public version 22 of the first document. I don't know if you --
23 MEMBER REMPE: I did not have that. I was 24 only given the proprietary one. I could try and read 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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78 it without the numbers, but I don't think it will make 1
much sense to you, so if you don't mind, just close 2
and ask you the question. Thank you. Go ahead.
3 MR. TESFAYE: Any additional questions to 4
Jason?
5 MEMBER BLEY: Joy, were you saving your 6
question about --
7 MEMBER REMPE: I think I have to until we 8
close the --
9 MEMBER BLEY: No, I mean the hydrogen one 10 you were asking --
11 MEMBER REMPE: Oh, you mean about the 12 aerosols and the seal crack mutation one?
13 MEMBER BLEY: Yes, and I was a little 14 surprised NuScale said what they did. It sounds like 15 they're saying you have to give the environmental 16 conditions under which it has to work, but it would 17 seem to me they should have set that up and should 18 have addressed the issue you raised about particulates 19 out there.
20 In any case, you heard the discussion. Is 21 there anything you guys can say about that issue?
22 Either the issue itself or whether that might --
23 somehow you're setting the environmental conditions 24 under which the detector has to work.
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79 MEMBER REMPE: There's a later slide that 1
I was going to ask that part on and I don't know if 2
Jason is the right person or not.
3 MR. SCHAPEROW: I have not been involved 4
at all.
5 MEMBER REMPE: Slide 8 is a good place to 6
ask it.
7 MR. TESFAYE: So I'm going to go over some 8
of the high level conclusions we made in terms of all 9
of the chapters that were impacted by the accident 10 source term in the topical report.
11 One of the things the environmental 12 qualifications the staff finds acceptable to use 13 iodine spike source term methodology and the 14 environment has qualification dose methodology 15 described in Appendix B of the topical report for 16 calculating one of that qualification, the doses 17 inside containment and under the bioshield.
18 We also give a detailed discussion of the 19 equipment survivability when core damage was not 20 assessed for EQ. Certain equipment associated with 21 the containment integrity and combustible gas 22 monitoring is designed to function to withstand core 23 damage events. Qualitative assessment testing and all 24 additional analysis may need to be performed to ensure 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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80 equipment survivability. And this evaluation is 1
performed in Chapter 19 of the SER.
2 MEMBER REMPE: So here's where I was going 3
to ask, the discussion about my concerns about fuel 4
fragmentation and dispersal. I know this was not the 5
primary focus, the radar base sensor wasn't the 6
primary focus of this chapter. But do you have any 7
thoughts about maybe that somebody needs to add 8
something to that list of environmental conditions for 9
this --
10 MR. TESFAYE: I don't know if we have the 11 right people here in the audience.
12 MEMBER REMPE: I kind of expected what 13 happened.
14 MS. GRADY: This is Anne-Marie Grady with 15 NRR. And aerosols and fuel fragments are not 16 specified under the conditions of equipment 17 survivability neither in SECY 90-016 or 93-087.
18 NuScale didn't provide that information and we didn't 19 ask a question about it.
20 MEMBER REMPE: So again, you understand my 21 concern and I'm sure that the guidance didn't think 22 about this because it's a different design. The 23 guidance wasn't written for it. So I just think it's 24 another -- we've raised issues about this since or 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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81 before in our letters and it's another thing that came 1
to light during this discussion.
2 MR. TESFAYE: Thank you. The other 3
related topic that we discussed in the subcommittee 4
was the post-accident sampling exemption request and 5
it's related to the topical report.
6 The regulation requires that applicants 7
provide the capability to promptly obtain normalized 8
post-accident samples from the reactor coolant system 9
and containment atmosphere.
10 Since equivalent information to that 11 provided by the sampling is provided by other means 12 such as radiation monitors, under the bioshield, core 13 exit thermal couplers, and hydrogen and oxy monitors.
14 The staff determined that a post-accident 15 sampling need not be required. Therefore, the staff 16 approved the exemption request for post-accident 17 sampling for the NuScale design.
18 MEMBER MARCH-LEUBA: Wait, let's clarify.
19 MR. TESFAYE: Okay.
20 MEMBER MARCH-LEUBA: First, why do you say 21 need not be required? Do you mean it's not required?
22 MR. TESFAYE: Yes, that's probably it.
23 It's not required. We have other means to gather the 24 same information as we could get from that --
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82 MEMBER MARCH-LEUBA: Did NuScale ask for 1
an exception not to have a hydrogen system?
2 MR. TESFAYE: No, they did not. In fact, 3
they used the hydrogen monitoring to justify this 4
5 MEMBER MARCH-LEUBA: This goes back to 6
what I was trying to explain before. If you connect 7
your hydrogen monitoring system downstream from the 8
safety isolation valves of the CES, in order to 9
operate the hydrogen system, you need to open up the 10 containment.
11 MR. TESFAYE: Yes.
12 MEMBER MARCH-LEUBA: To a whole bunch of 13 non-safety related components. If the equipment -- I 14 mean in operating plans you have a hydrogen monitoring 15 system which is non-safety related, but is connected 16 to the safety-related containment. I mean what the 17 design levels as defined is equivalent to opening of 18 the containment to the turbine building and then 19 measuring the hydrogen inside the building which would 20 be completely crazy.
21 By connecting the hydrogen monitoring 22 system to a CES and whatever the second component is, 23 you are telling the operator, if you suspect there is 24 a severe accident, the isolated containment and send 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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83 all that contamination to these three non-safety 1
related systems.
2 If we don't think a hydrogen monitoring 3
system is needed, they should not have one. The 4
operator should not be tempted to open the 5
containment.
6 MR. TESFAYE: Okay. I'll defer that to my 7
colleague, Anne-Marie.
8 MS. GRADY: This is Anne-Marie Grady again 9
from NRR.
10 The means of hydrogen and oxygen post-11 accident monitoring is established by a closed loop.
12 Containment atmospheric sample is taken by opening the 13 CIV in the containment evacuation system, sending it 14 past the two-line monitor for both hydrogen and oxygen 15 back through the containment flooding and drain system 16 back to the containment. So unless it leaks, it's not 17 released to any other environment. It's a closed 18 loop.
19 Severe accident mitigation is the reason 20 why we needed to have hydrogen and oxygen monitoring 21 and for severe accident mitigation, none of this has 22 to be safety related.
23 MEMBER MARCH-LEUBA: The hydrogen loop, 24 hydrogen monitoring loop doesn't need to be safety 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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84 related.
1 MS. GRADY: Does not.
2 MEMBER MARCH-LEUBA: But you're connecting 3
it to the containment operation system which is a two-4 inch -- or four-inch pipe with a valve, with a pump 5
that goes all the way outside to the support building 6
and comes back and all of it is non-safety qualified.
7 I think that by opening the isolation 8
valves to the containment into that CES system, you 9
are creating more problems than you're solving.
10 MS. GRADY: So you're concerned that 11 they're leaving the system by some other means.
12 MEMBER MARCH-LEUBA: The only reason you 13 can have a severe accident if you have a really bad 14 day.
15 MS. GRADY: Yes, sir.
16 MEMBER MARCH-LEUBA: And most of these are 17 seismic and that CES is going to be broken. I mean 18 you're worried about leaking from the high-level 19 leakage just a one-eighth inch line which is probably 20
-- and you have this four-inch line with a big pump 21 with seals. You are venting -- the containment 22 bounding becomes the CES bounding.
23 MS. GRADY: Because it's not safety 24 related, required to be safety related and in fact, it 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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85 was not safety related. We don't have to postulate a 1
further accident.
2 MEMBER MARCH-LEUBA: In operating the 3
reactor the rule was written for, you connect the 4
high-level system to a safety-related containment, so 5
you're only ever creating hydrogen through your 6
hydrogen monitoring system.
7 In the design proposal of NuScale, you are 8
-- the isolated containment surrounding the CES which 9
is a lot of a system with pumps, seals, vents and 10 you're flooding that with all of the contamination 11 from the containment in order to sample hydrogen.
12 You're making the problem worse. I really don't know.
13 MS. GRADY: I don't follow that scenario 14 as to how it makes --
15 MEMBER MARCH-LEUBA: CES has a valve, has 16 a vacuum pump.
17 MS. GRADY: Right.
18 MEMBER MARCH-LEUBA: And seals with 19 components when it reaches, safety goes up.
20 MS. GRADY: The CES --
21 MEMBER MARCH-LEUBA: You are dumping all 22 the containment environment, the containment 23 atmosphere with all those aerosols and iodine, you're 24 putting it on your vacuum pump which is up there on 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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86 the operating floor in order to measure hydrogen.
1 MS. GRADY: When we un-isolate the CES 2
portion of that closed loop, the CES system isn't 3
operating.
4 MEMBER MARCH-LEUBA: But it's open.
5 MS. GRADY: Once we open the containment 6
isolation valve it is, yes.
7 MEMBER MARCH-LEUBA: Yes, so you're 8
dumping all of the containment environment --
9 MS. GRADY: It's flowing through a closed 10 loop flow path.
11 MEMBER MARCH-LEUBA: No, into all of it, 12 it's in vacuum. It will fill it up with iodine and 13 astringent.
14 MS. GRADY: The containment atmosphere 15 will be in that closed loop, I agree.
16 MEMBER MARCH-LEUBA: Not the closed loop, 17 the CES.
18 MS. GRADY: I don't think the CES system 19 is open to any --
20 MEMBER MARCH-LEUBA: You just opened it.
21 MS. GRADY: -- any open path from the CES 22 portion of the line we're using. I don't believe it 23 is. I'll double check on that.
24 MS. BRADFORD: This is Anna Bradford from 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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87 the staff. Is this a question that really should be 1
directed to NuScale and the design in terms of why 2
it's designed this way?
3 MEMBER MARCH-LEUBA: I think if we have 4
reached the conclusion that the hydrogen system is not 5
needed --
6 MS. BRADFORD: We have not reached that, 7
no.
8 MR. STUTZCAGE: This is Ed Stutzcage.
9 I'll try to clarify it for the NRC.
10 So the exemption that NuScale has is an 11 exemption from physically taking grab samples, taking 12 them to a lab to analyze it. And as part of their 13 exemption to not need to take grab samples, they 14 credited the hydrogen and oxygen monitors, so the 15 monitors, you know --
16 MEMBER MARCH-LEUBA: It's a different 17 exemption.
18 MR.
STUTZCAGE:
It's a
different 19 exemption. The exemption is just physically grabbing 20 the material and analyzing it in a lab. They still 21 have the requirement to monitor, have the monitor --
22 had it monitored.
23 MEMBER MARCH-LEUBA: But do you understand 24 what I'm saying that in order to operate the hydrogen 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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88 sampling system, you need to open up the containment 1
isolation valve and then the containment radiation 2
aggregate into a CES system which is a vacuum pump, 3
it's a HEPA filter. It's a tower. You're putting all 4
the junk, the containment, in the containment, you're 5
sampling and you're putting it on the floor of your --
6 that is not reasonable.
7 MR. STUTZCAGE: Right, and NuScale hasn't 8
requested an exemption from the 5044 hydrogen and 9
oxygen monitoring requirement and that's where our 10 concerns in radiologic rates protection comes from 11 where you're doing this, you're operating the system 12 and they haven't demonstrated an ability to re-isolate 13 the system and they haven't analyzed leakage --
14 MEMBER MARCH-LEUBA: They can re-isolate 15 the isolation valves to take a sample, but all the 16 iodine and the strontium and it's already in the pump 17 and the HEPA filter.
18 MR. STUTZCAGE: Right. To us, they never 19 provided us any assurance that they could re-isolate 20 the system.
21 MEMBER MARCH-LEUBA: You have the valves in 22 there.
23 MR. STUTZCAGE: Go ahead, Ron.
24 MR. LAVERA: So the way the system works 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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89 is that they can open some of the valves from the 1
control room. They may have to go out to the skids 2
which are located in the 100-foot, 126-foot elevation 3
and manually open some of the other valves.
4 When they go to isolate the system, it's 5
the same thing. They can isolate some of them from 6
the control room, one pair of them, but not the other 7
pair. So they have to physically go out to the skids 8
and push the buttons.
9 Where the staff has some concern is that 10 the amount of leakage that you use to get from the 11 system to cause a problem for people trying to access 12 those valves is not the pipes falling off. The 13 analysis that the staff did was using.3 CFM -- I 14 think it was -- I'm going off of memory here so it's 15 close to 30 rem to the control room operator. So it 16 was a significant dose.
17 So that led us to believe that there would 18 be issues for personnel trying to access this area 19 even under the exposure elevated exposure 20 authorization.
21 MEMBER MARCH-LEUBA: My claim is whatever 22 leak rate you assume from operating this closed loop 23 hydrogen monitoring system, multiply times a hundred 24 because all of the leakage from the CES system.
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90 MR. LAVERA: We were counting on the 1
activity in containment from the core damage event 2
going out into all these three systems and the total 3
leakage from all these three systems being.3 CFM. So 4
that's how we did our analysis of the --
5 MEMBER MARCH-LEUBA: -- so we're assuming 6
this is a normal system --
7 MR. LAVERA: We were looking at that.
8 MEMBER MARCH-LEUBA: -- is still intact.
9 MR. LAVERA: So now the -- yes, and we 10 agree with you that there's going to be seals and 11 stuff, valves, interfacing valves that are going to 12 leak, so we understand this. So we don't agree with 13 the characterization that you would have to have a 14 pipe break causing those problems.
15 We believe that if you do have a leak from 16 the system that you may not even be able to isolate 17 the system under the plan's special exposure provision 18 to Part 20, never mind the 5 rem limits of Part 20.
19 We believe that if you do have a leak from the system 20 from leakage rates on the order of.3 CFM that you do 21 present a challenge to the public health and safety.
22 And this also impacts the LPZ zone is what we call it.
23 And then it also impacts the control room operator 24 dose.
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91 So in part of our review that started on 1
this question back on March of 2018, we were asking 2
NuScale to tell us, hey, what is the maximum and 3
allowable leakage rate that you could tolerate from 4
this system and not challenge the dose to the control 5
room and the offsite? Can you isolate the system by 6
doing this manual actuation? Can you safely send 7
somebody in to the area? What's the maximum dose that 8
you can get from that?
9 We have not been able to get an allowable 10 leakage value from NuScale. They don't have the 11 ability to isolate this from the control room without 12 sending somebody out to the field. So this is the 13 reason the staff has concerns about this.
14 MEMBER MARCH-LEUBA: We were also told 15 that to open those valves, the containment has to be 16 below 200 psi in order to bypass.
17 MR. LAVERA: And they have to go out to 18 the skid to do it. Now you wouldn't have a vacuum.
19 After a couple of days, you will not have a vacuum in 20 containment. You will be at 60 pounds, I think, just 21 from the normal stuff going on. And over the course 22 of the accident, it can go up to 160 pounds.
23 MEMBER MARCH-LEUBA: And all those 160 24 pounds of dirt are going to move into the CES system 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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92 the moment you open those valves.
1 MR. LAVERA: So my understanding is and 2
Anne-Marie, you're welcome to correct me if I 3
misspeak. The people responsible for containment 4
integrity in the hydrogen monitoring have determined 5
that hydrogen monitoring is required.
6 NuScale has put in for an exemption 7
request from that. So from a radiation protection 8
perspective which leads us how do you know a valve 9
leak will result in having this activity in this 10 system. That's weighted against leakage criteria that 11 represent a potential challenge to the control room 12 operator and members of the public and anybody that 13 would have to go in there and manually shut the 14 system. So if it's the only way you have to go in 15 there and shut the system, if you do determine that 16 you have enough leakage that's causing problems to the 17 control room or offsite dose, send somebody out there 18 to push a button.
19 MEMBER MARCH-LEUBA: I made my point. The 20 last time I will interrupt. Either the hydrogen 21 system is required or it is not, but if it is 22 required, how we need from a non-safety grade large 23 system full of valves, seals, pumps, HEPA filters, 24 connected to the exhaust power, all non-safety grade.
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93 And that's my opinion.
1 Is it required, is it not required? If it 2
is required, collect it like the operating plants do 3
to the containment.
4 MS. GRADY: Dr. March-Leuba, it is 5
required. It is part of NuScale's design and we've 6
accepted it.
7 MEMBER MARCH-LEUBA: But the argument I'm 8
making is if it is required, the design is defective.
9 MS. GRADY: The guidance --
10 MEMBER MARCH-LEUBA: They're making the --
11 CHAIRMAN RICCARDELLA: Excuse me just a 12 second. Everyone needs to speak up louder because 13 Corvallis can't hear what we're saying. Okay? Get 14 closer to the mic and speak up.
15 MEMBER MARCH-LEUBA: Okay, this is 16 equivalent to an operating plant, so it wants to 17 sample the high-level in containment and you still are 18 sampling the containment, they put the sample in the 19 turbine building. And to sample the hydrogen, they 20 open up the valves so the containment was in the 21 turbine building and then they measure the hydrogen in 22 the turbine building. I mean you would consider that 23 ludicrous, right?
24 MS. GRADY: Yes.
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94 MEMBER MARCH-LEUBA: But this is what 1
we're doing here. We are opening up to the CES system 2
which is a non-safety grade, vacuum pumps, HEPA 3
filters, connected to the tower, which may or may not 4
have isolated and you dump all your dirt into there 5
and then you sample the CES. It's the same thing as 6
dumping it in the turbine building. It's crazy.
7 MEMBER DIMITRIJEVIC: Well, Jose, we can 8
address this also as a part of PRA because it's a 9
matter of containment isolation during the accident, 10 and if this actually means guaranteed containment 11 bypass. With some accidents, that shouldn't be the 12 case. So we should really -- I mean I made the note 13 for myself to look into this because it seems like you 14 will have an accident and you're going to bypass 15 containment which is against the plan and the 16 additional containment probability failure is less 17 than one because it definitely in seismic cases is 18 going to be point something. So the thing is that we 19 have to look what does that mean from the containment 20 condition of failure probability the safety plan.
21 MEMBER REMPE: So Jose, you keep bringing 22 this up to the staff and what can they do? If 23 somebody comes in to a design, what regulatory hook 24 could they use?
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95 MEMBER MARCH-LEUBA: They can tell them 1
that this is not good enough.
2 MEMBER REMPE: What regulation are they 3
breaking is where I'm kind of going? I know you tried 4
to get the NuScale folks to do something about it and 5
they didn't want to, so what do you do with the 6
regulator?
7 MEMBER MARCH-LEUBA: The thing is the 8
operator is more than 5 rem, you push a button, so 9
therefore this design doesn't work. That's what I'm 10 getting at.
11 MS. BRADFORD: This is Anna Bradford from 12 the NRC. I think what you're saying is you think it's 13 not a good idea for those systems to all be connected.
14 That's what I'm hearing you say, right?
15 NuScale came in with this design. We 16 evaluate it. They were able to meet our regulations 17 except for where they requested exemptions and it was 18 fine. Like you said, it's not our job to say you 19 know, we don't think this is the best design. It 20 would be better if we designed it this way and I don't 21 know if that's even true, but that's really not our 22 responsibility.
23 MEMBER REMPE: It's why they've got this 24 carve out which may be difficult to meet, but they've 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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96 got a carve out. I mean I get what you're saying.
1 It's kind of like I don't what I'd do if I was in 2
staff's position.
3 MEMBER MARCH-LEUBA: What I would do is 4
have them give me a probability of failure of the CES 5
system in a severe accident event. The CES system --
6 MEMBER DIMITRIJEVIC: I mean they will not 7
meet safety goal if this is an inability to fail for 8
an accident, definitely. So that's why they would 9
call that.
10 MEMBER BLEY: Well, it's also not so much 11 what can the staff do about it. We advise the 12 Commission. If we really think this is a problem and 13 the regulations don't cover it, then it's up to us to 14 raise it to the Commission and say for this new kind 15 of design it ought to be there. I'm not saying I'm of 16 that opinion, but that is a way for us to proceed.
17 MEMBER KIRCHNER: Can I recap where we 18 might be? And that is the applicant has asked for an 19 exemption from post-accident sampling. Is your 20 granting that because they can provide equivalent 21 information by sampling by other means? So one is 22 radiation monitored under the bioshield. That will 23 tell you something. Core exit thermocouples. And 24 then hydrogen and oxygen monitors.
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97 Now specifically then this system would be 1
necessary --
2 MR. TESFAYE: Absolutely --
3 MEMBER KIRCHNER: -- to support your 4
exemption.
5 MR. TESFAYE: Absolutely.
6 MEMBER KIRCHNER: And then the issue is 7
what dose would be at risk for the operators to 8
operate the system and then to isolate it?
9 MR.
TESFAYE:
- Yes, to open the 10 containment, I think we have evaluated that.
11 MEMBER KIRCHNER: Notwithstanding the.3 12 CFM leak rate and the containment evacuation system, 13 what's the dose just in the pipe from the piping when 14 it's filled with all of the containment atmosphere?
15 Do you have a ballpark number for that?
16 MR. STUTZCAGE: I don't think we have 17 that. We only reviewed the dose to un-isolate the 18 system and --
19 MEMBER KIRCHNER: Yes, I think that's what 20 was presented by Anne-Marie and the staff. You 21 proposed a leak rate and then there's a dose 22 associated with that. If the system doesn't leak, 23 what is the dose? There will be dose.
24 MR. LAVERA: There will be dose, so it 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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98 won't be -- first of all, NuScale's proposal is if the 1
system doesn't leak you don't change anything, you 2
just let it go, and we're okay with that. There's no 3
need to go out there and re-isolate the system.
4 If you have a leak, it's most likely that 5
the airborne cloud around the area is going to be the 6
major dose driver. We didn't do that because NuScale 7
didn't specify a maximum allowable leakage rate, so we 8
didn't do the dose calculation for that specific area 9
and there's other issues that were keeping us from 10 trying to do that calculation.
11 We were able to do the calculation for the 12 control room dose and the LPZ and those calculations 13 led us to believe that it could be a significant 14 problem for public health and safety.
15 MEMBER KIRCHNER: Well, I think Jose has 16 eloquently stated the design concerns that we have, 17 that you open up -- you bypass containment, open up a 18 large, I believe that line is four inches to 19 penetration. And that is a concern from the design 20 standpoint. Although we're not here to re-design the 21 system. We stated that in our subcommittee meeting.
22 MEMBER BLEY: We must have written a 23 letter on the SER with open items on Chapter 9. Did 24 we raise this back then? Is it in our letter?
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99 MEMBER MARCH-LEUBA: Probably not.
1 MEMBER KIRCHNER: I don't know that that 2
detail was available then. It may have been and we 3
just didn't cover it.
4 DR. CORRADINI: Can I ask a question? I 5
want to make sure that the two line requirements are 6
both short-term monitoring and long-term monitoring or 7
just short term?
8 MS. GRADY: Continuous, long-term.
9 DR. CORRADINI: And so long term is 10 defined within 30 days. So short term is of no 11 consequence to the staff. It's the long-term 12 monitoring that's --
13 MS. GRADY: For this particular change, 14 Dr. Corradini, the hydrogen and oxygen monitoring has 15 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 16 containment integrity is not challenged, even if there 17 is combustion in the containment.
18 Long term, we looked at and NuScale looked 19 at up to 60 days and there's a potential challenge 20 again due to the fact that there's radiolysis around 21 45 to 54 days, but that's long term.
22 DR. CORRADINI: Okay, just so -- let me 23 repeat. I want to make sure I'm clear about the 24 regulatory requirement. The regulatory requirement is 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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100 they must establish hydrogen monitoring before 72 1
hours.
2 MS. GRADY: They must establish it and 3
they have shown us that they don't need to do it 4
before 72. Seventy-two is not in the regulation.
5 DR. CORRADINI: Okay, excuse me. I'm 6
sorry. Thank you. Thank you for clarifying my point.
7 And then once established, then according 8
to regulation, it must be maintained continuously 9
after that --
10 MS. GRADY: Yes.
11 DR. CORRADINI: Or intermittently?
12 MS. GRADY: No, continuously after that.
13 Practically speaking, it could be intermittent if that 14 were an operationable decision, but the regulation is 15 continuous.
16 DR. CORRADINI: Okay. Thank you.
17 MS. GRADY: You're welcome.
18 DR. CORRADINI: Thank you, Anne-Marie.
19 MEMBER PETTI: So my question is the 20 source term is where at 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> in these 21 calculations? These calculations of source term is 22 weighed out. All the aerosols have settled. The 23 steam is condensed. So what source term did you use 24 in your analysis? Because your big peak, I'm with 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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101 you, but I think there's a timing offset here that 1
might be important.
2 MR. SCHAPEROW: So just to maybe throw out 3
a fact idea, so NuScale's assumptions for their source 4
term topical is that 5 percent remains airborne 5
forever, at least for 30 days.
6 So that might be the source of -- I can't 7
speak for Michelle Hart. Unfortunately, she's not 8
here today. There is an assumption, a conservative 9
assumption in NuScale's topical report in the area of 10 iodine vapor.
11 MEMBER REMPE: And Dennis, because it may 12 come up later this week with respect to the letter on 13 Chapter 9, one of our conclusions was there were 14 potentially risk-significant items in NuScale's 15 design that are not yet fully developed. So these 16 items, requirements to be included in the DCA to 17 ensure that the licensee's plant will perform as 18 credited.
19 So we didn't call out this particular 20 item, but we acknowledged that we were uncertain about 21 a lot of aspects in the plant design.
22 MEMBER BLEY: And there's a lot of parts 23 to Chapter 9.
24 MR. TESFAYE: Okay. Thank you.
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102 DR. CORRADINI: There's silence again. May 1
I get another clarification point just to be clear?
2 So it's NuScale's contention that they 3
don't -- that their design will meet the requirement 4
if they can be exempt from long-term monitoring? I 5
want to make sure I understand what the exemption is 6
that is being requested. I'm sorry that I'm going 7
over old ground.
8 MEMBER PETTI: No, I think to be clear 9
there's an exemption from physical sampling. They 10 actually need the hydrogen and oxygen monitoring to 11 support the exemption. Have I got it?
12 MS. GRADY: That's my understanding of it.
13 DR. CORRADINI: And then NuScale has gone 14 further to say that they can go in an un-isolate and 15 re-isolate if necessary with operator action. Am I 16 understanding that correctly?
17 MR. STUTZCAGE: This is Ed Stutzcage at 18 the NRC. They provided information to show that they 19 can un-isolate the system. They have not provided 20 information to the NRC to demonstrate that they can 21 re-isolate the system.
22 They have indicated that that's something 23 that will be handled as part of their emergency 24 action, if necessary. They didn't say -- respond, 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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103 they don't have to provide that information to the 1
staff at this time.
2 DR. CORRADINI: Okay, thank you. Thank 3
you for the clarification, I appreciate it.
4 MR. TESFAYE: Okay. Thank you. I think 5
we have discussed this, this slide --
6 PARTICIPANT: Just a little.
7 MR. TESFAYE: -- the last 15, 20 minutes, 8
so I'm not going to go over that. So I will jump 9
straight to what the subcommittee requested us to 10 present at this meeting, which is the proposed 11 recommendation to the rulemaking.
12 I am not going to read this. This is out 13 of the Chapter 12 SER. I am just going to highlight 14 the areas where we are going to focus. Specifically, 15 10 CFR Part 52, Appendix 2, which is not there yet, 16 that will be the NuScale SMR appendix.
17 Under issue resolution we will state the 18 design and evaluation of leakage from combustible gas 19 monitoring loop is not considered but it was in the 20 meaning of 52.63 which is with respect to the finality 21 of the standard design.
22 And then in Section 14, Additional 23 Requirements, it will be stated a COL applicant is 24 responsible for providing sufficient design 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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104 information demonstrating that the requirements of 10 1
CFR 50.34(f)(2)(xxv)(8) are met with respect to 2
potential radiation release under accident conditions 3
from systems used for post-accident hydrogen and 4
oxygen monitoring.
5 So this is what we are recommending, and, 6
again, I note this is not the proposed rule language.
7 This is what is in the SER. The rule language has not 8
yet been developed yet.
9 So as an example on the next slide I give 10 you two carve outs, as we call, carve outs of 11 recommendation. This is from the design specification 12 rule for ESBWR design an applicant for COL include as 13 part of its application.
14 One of them is for the hurricane loads in 15 excess of total tornado loads and hurricane-generated 16 missile loads, so on the structures this was not part 17 of -- It was in the design specification a scope, but 18 it was not done so they carved out or they included 19 this in the rulemaking.
20 And the other one is similar to what we 21 are doing here, that's the spent fuel pool level 22 instrumentation was not fully developed in the design 23 specification rule.
24 Another way to handle this is to include 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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105 this kind of information in 2-1 Chapter 4 under 1
interface requirements with an ITAC and that would 2
have an easier way to go but the applicant chose not 3
to include this language in the Tier 1 interface 4
requirement.
5 So the staff is kind of forced to do this 6
rule carve out in the design specification rulemaking.
7 So this is, again, the takeaway from the subcommittee 8
meeting.
9 There was other items that was requested 10 of us. Chapter 12 which had all this recommended 11 rulemaking language, we gave you the draft of that and 12 when we issued the final there was some change to the 13 draft and we have provided the compare and contrast 14 between the draft and what the final one.
15 The major difference is the ventilation 16 system fire dampers, which is the second item here.
17 Obviously we didn't have enough information. The 18 ventilation dampers were not closing on high radiation 19 monitor.
20 The staff looked at the risk and they said 21 the primer is to operator or equivalence of 22 operability involves core damage event with a failure 23 of the ventilation's exhaust fans as well as an open 24 bay exhaust damper, so all these three things have to 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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106 happen.
1 And before we issue the final SER for 2
Chapter 12 we made a finding on this although the 3
design did need something in order to be fully 4
responsive to the staff's questions.
5 It wasn't, but the staff took the risk 6
approach and whatever to make a finding on this. So 7
we have two rule carve outs, one is the penetration 8
shielding design, which is the first bullet, and we 9
have discussed that at subcommittee, and the other one 10 is the leakage issue that we discussed earlier.
11 MEMBER BLEY: And up on Slide 11 where you 12 started this rulemaking discussion the rule would 13 state that the COL applicant is responsible for --
14 MR. TESFAYE: Providing the information --
15 MEMBER BLEY: -- providing the information.
16 (Simultaneous speaking.)
17 MR. TESFAYE: -- information, and making 18 sure the regulations are met in terms of those.
19 MEMBER BLEY: Okay.
20 MR. TESFAYE: Or, you know, design a means 21 to re-isolate the containment. So if you don't have 22 any questions on this, I think we've discussed this at 23 length, we'll go to the conclusion.
24 Staff found acceptable the methods for 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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107 developing accident source terms and performing 1
accident radiological consequence analysis to be 2
referenced by NuScale SMR design.
3 All phase three SER open items related to 4
the accident source term methodology have been closed 5
except those involving penetration shielding and the 6
leakage from hydrogen/oxygen monitoring system.
7 They are not considered resolved and must 8
be addressed by the COL applicant. And that's all we 9
have.
10 MEMBER KIRCHNER: May I go to the first 11 one then. When you push of, pardon my phraseology, 12 the responsibility for the radiation shield wall 13 design to the COL, I'm trying to think through the 14 implications of that.
15 The applicant has a nominal design for the 16 shield blocks and so on. If it turns out, and I'll 17 just do this rhetorically, that twice as much 18 shielding is needed to meet whatever the dose criteria 19 are that has implications that ripple through the 20 design, simple things like the building, the main, the 21 reactor building crane operations, et cetera, and 22 potential dose during refueling operations, et cetera.
23 I am wondering what the ramifications are 24 of making that a COL applicant responsibility. Can 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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108 you talk through that?
1 MR. LAVERA: So this is part of the 2
reason that we went down this path is we wanted to 3
make sure that this got designed appropriately.
4 We recognized that the potential 5
interactions of the shielding that they would have to 6
install, it's equivalent to five feet of concrete over 7
what appears to us to be a fairly large area, so we, 8
too, are concerned about that.
9 We tried to work with NuScale to determine 10 several ways of addressing it within the scope of the 11 application without having physical design information 12 there.
13 The only way we could reach a safety 14 finding on this was to do a carve out, so that's why 15 we went down that path.
16 MEMBER BLEY: Well I said this at the 17 subcommittee meeting, but putting this off on the COL 18
-- Well, I'm not NuScale, but if I were this would 19 make it a lot harder to deal with potential customers 20 when they look at this and say, hey, I got to make 21 this work after I commit to this design. It just 22 seems a bad place to leave things.
23 MEMBER KIRCHNER: Yes. I am thinking 24 through the ramifications, because, pardon the 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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109 digression, but if I remember right the initial 1
lifting mechanism for moving the modules was to kind 2
of strap on to two solid anchors, take it up.
3 Then I believe that changed so that the 4
upper frame then connected to the module and became 5
the lifting point and the interactions of that design, 6
which may be in FLEX, I'm not sure where that design 7
came out, and the shielding are, there is important 8
ramifications there as they change that in terms of, 9
as you labeled this, large penetrations in the shield 10 wall and others.
11 So have you looked at that at the latest 12 iterations on that upper lifting design and the 13 ramifications for radiation protection?
14 MR. LAVERA: Okay, so, yes, we have been 15 looking at that shield block on the top of the module 16 bay. This shielding is not anywhere near that. It 17 won't interact with that particular issue, particular 18 thing.
19 MEMBER KIRCHNER: Right.
20 MR. LAVERA: So I understand where you are 21 coming from, but there is absolutely no interaction 22 between those two.
23 There are other interactions, potential 24 interactions for equipment, locations,
- weight, 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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110 structural loading, structural analysis for components 1
in structures outside of the module bay wall on the 2
100-foot and out.
3 So it's not the module shield that's on 4
top that you lift with a crane and move it around.
5 MEMBER KIRCHNER: So it's more the 6
penetrations into the reactor building?
7 MR. TESFAYE: Yes.
8 MR. LAVERA: So, yes, that's a closer 9
approximation to it.
10 MEMBER KIRCHNER: Okay.
11 MR. LAVERA: It's between the power module 12 bay and the rest of the reactor building.
13 MEMBER KIRCHNER: Thank you.
14 MEMBER PETTI: Any other questions?
15 MEMBER REMPE: Well I wanted to --
16 MEMBER PETTI: I know that though. Do we 17 ask for public comment around?
18 PARTICIPANT: Yes.
19 PARTICIPANT: Yes, we do, and we have some 20 21 (Simultaneous speaking.)
22 MS. FOSAAEN: This is NuScale Corvallis if 23 I could just make a quick statement with regard to the 24 shielding. I just want to clarify that the shielding 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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111 that we have not provided is just the shielding around 1
piping penetrations in the ventilation.
2 The rest of the information and what we 3
have provided is consistent with the level of 4
information provided by previous applicants.
5 So, you know, we're talking about what 6
material goes around the piping equivalent and we did 7
provide a COL item that said the shielding that would 8
be provided in those penetrations around the piping 9
would be equivalent to the dose rate maps that were 10 provided as part of the DCD.
11 So we had provided, in fact, with that COL 12 item more than previous applications.
13 MR. LAVERA: So this is Ron Lavera. You 14 know, I have been involved in the previous reviews and 15 when you're talking about having a small gap around a 16 pipe or a small pipe, yes, the NuScale application is 17 consistent with that.
18 We are looking at penetration for main 19
- steam, main feedwater
- lines, these are big 20 penetrations.
21 The ventilation ducts, which are feet in 22 size, and you're not talking about a little bit of 23 shielding, you're talking five feet of concrete 24 shielding that they are crediting both for 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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112 occupational, EQ, and beyond design basis equipment 1
survivability considerations.
2 So in our -- The way we look at things 3
that is not an inconsequential something that you 4
should be able to just squirt a little goop in there 5
and move on your way.
6 MEMBER KIRCHNER: Yes. Yes, but they are 7
the concretes tight fit around one pipe probably.
8 MR. LAVERA: And if you were to try to do 9
shadow shielding it would be a significant way to 10 interfere with the equipment that is there. Like I 11 said you have main steam lines and other things there, 12 so we have concerns about physically being able to fit 13 the equipment in there, the shielding in there when 14 the other equipment is present.
15 MEMBER PETTI: Okay. Let's try to take 16 public comment. Anybody in the room?
17 (No response.)
18 MEMBER PETTI: Seeing no one, anybody on 19 the public line want to make a comment?
20 (No response.)
21 MEMBER PETTI: Okay. Then we'll adjourn 22 this part of the meeting and go into closed session.
23 (Whereupon, the above-entitled matter went 24 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 Michelle Hart, NRR Jason White, NRR Jason Schaperow, NRR Tony Gardner, NRR Ed Stutzcage, NRR 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
Hossein Esmaili, RES Anne-Marie Grady, NRR Boyce Travis, NRR Ryan Nolan, NRR Zach Gran, NRR Amanda Marshall, NSIR
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 CDST core damage source term COL combined operating license CRHS control room habitability system CRVS normal control room HVAC system CVCS chemical and volume control system DBST design basis source term DCA design certification application DF decontamination factor 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 rem Roentgen equivalent man RG regulatory guide RVV reactor vent valve SECY Commission paper SGTF steam generator tube failure SMR small modular reactor SSCs structures, systems and components TEDE total effective dose equivalent TR topical report December 4, 2019 Accident Source Term Methodology and Related Topics 15
LO-1219-68130 NuScale Power, LLC 1100 NE Circle Blvd., Suite 200 Corvallis, Oregon 97330 Office 541.360-0500 Fax 541.207.3928 www.nuscalepower.com 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
LO-1219-68130 NuScale Power, LLC 1100 NE Circle Blvd., Suite 200 Corvallis, Oregon 97330 Office 541.360-0500 Fax 541.207.3928 www.nuscalepower.com
Enclosure:
ACRS Full Committee Presentation: Accident Source Term Methodology Phase 5 Implementation, PM-1219-68131, Revision 0
Copyright 2019 by NuScale Power, LLC.
Revision: 0 Template #: 0000-21727-F01 R5 NuScale Nonproprietary ACRS Full Committee Presentation Accident Source Term Phase 5 Implementation December 4, 2019
Copyright 2019 by NuScale Power, LLC.
Revision: 0 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.
Copyright 2019 by NuScale Power, LLC.
Revision: 0 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.
Copyright 2019 by NuScale Power, LLC.
Revision: 0 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.
Copyright 2019 by NuScale Power, LLC.
Revision: 0 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.
Copyright 2019 by NuScale Power, LLC.
Revision: 0 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
Copyright 2019 by NuScale Power, LLC.
Revision: 0 Template #: 0000-21727-F01 R5 Portland Office 6650 SW Redwood Lane, Suite 210 Portland, OR 97224 971.371.1592 Corvallis Office 1100 NE Circle Blvd., Suite 200 Corvallis, OR 97330 541.360.0500 Rockville Office 11333 Woodglen Ave., Suite 205 Rockville, MD 20852 301.770.0472 Charlotte Office 2815 Coliseum Centre Drive, Suite 230 Charlotte, NC 28217 980.349.4804 Richland Office 1933 Jadwin Ave., Suite 130 Richland, WA 99354 541.360.0500 Arlington Office 2300 Clarendon Blvd., Suite 1110 Arlington, VA 22201 London Office 1st Floor Portland House Bressenden Place London SW1E 5BH United Kingdom
+44 (0) 2079 321700 http://www.nuscalepower.com Twitter: @NuScale_Power
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 3
- 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 Unit Initial License Initial License Renewal Application Renewed License Expiration Date Subsequent License Renewal 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
4 Dates Location Operating Experience Audit September 17-27, 2018 Rockville, MD In-office Audit November 13, 2018 - April 29, 2019 Rockville, MD SLRA Audits and Inspections
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
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
SLRA - Original Disposition of AMPs 11 new GALL programs 8 consistent 3 consistent with exceptions 35 existing GALL programs 8 consistent 27 consistent with enhancements/exceptions 1 plant specific with enhancement SER - Final Disposition of AMPs 11 new GALL programs 8 consistent 3 consistent with exceptions 35 existing GALL programs 8 consistent 27 consistent with enhancements/exceptions 1 plant specific with enhancement 8
3.0.3 - Aging Management Programs (AMPs)
SER Section 3
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
SER Section 4
Closure of Confirmatory Item 3.0.3.2.3-1 BWR Vessel Internals 10 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.
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 SLRA Review Conclusion
- 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 Initial License Renewal Inspections
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 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.
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
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 NRC Inspection Results
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
ACRS Full Committee Presentation December 4, 2019 Peach Bottom Atomic Power Station, Units 2 and 3 Subsequent License Renewal Application
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 Peach Bottom Atomic Power Station, Units 2 and 3 1
Agenda Peach Bottom Atomic Power Station, Units 2 and 3 2
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
Peach Bottom Station Peach Bottom Atomic Power Station, Units 2 and 3 3
Turbine Building Reactor Buildings Discharge Canal EDGs Emergency Cooling Towers North Substation Cooling Water Intake Structure South Substation North Substation ISFSI Pad Intake Discharge Canal South Substation North Substation ISFSI Pad Discharge Canal Plant Intake
[Normal Heat Sink]
Power Block NORTH Emergency Cooling Tower
[Emergency Heat Sink]
Peach Bottom Current Performance Peach Bottom Atomic Power Station, Units 2 and 3 4
- 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
Station Overview Peach Bottom Atomic Power Station, Units 2 and 3 5
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 Installation (ISFSI) 2000 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
Significant Plant Modifications Peach Bottom Atomic Power Station, Units 2 and 3 6
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
GALL-SLR Consistency and Commitments Peach Bottom Atomic Power Station, Units 2 and 3 7
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 Peach Bottom Atomic Power Station, Units 2 and 3 8
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 Peach Bottom Atomic Power Station, Units 2 and 3 9
AMPs Consistent with GALL AMPs Consistent with Enhancement AMPs with Exception without Enhancement AMPs with Exception and Enhancement Plant Specific AMPs Existing 36 8
19 2
6 1
New 11 8
0 3
0 0
Total 47 AMPs
FLR Aging Management Effectiveness Reviews Peach Bottom Atomic Power Station, Units 2 and 3 10
- 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
Confirmatory Item Peach Bottom Atomic Power Station, Units 2 and 3 11 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
Technical Topics Peach Bottom Atomic Power Station, Units 2 and 3 12 RPV Embrittlement IASCC of Reactor Vessel Internals Concrete and Containment Degradation Electrical Cable EQ and Condition Assessment Peach Bottom will manage aging consistent with recommendations in GALL-SLR
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 Atomic Power Station, Units 2 and 3 Subsequent License Renewal Application
Peach Bottom Station Location Peach Bottom Atomic Power Station, Units 2 and 3 15 Peach Bottom Station
GALL Consistency - AMP Exceptions Peach Bottom Atomic Power Station, Units 2 and 3 16 Program Exception Justification Water Chemistry Using this AMP to manage Auxiliary Boiler water chemistry.
Scope addition, while not part of BWRVIP-190, standards exist for monitoring water parameter (ISBN-0-7918-1204-9).
Bolting Integrity Using this AMP to manage submerged mechanical bolting on intake structure traveling screens.
Scope addition, while this AMP is used to manage closure bolting for pressure retaining components, inspection requirements will be adequate to manage loss of preload.
Closed Treated Water NUREG-2191 recommends EPRI document Closed Cooling Water Chemistry Guideline Rev. 1.
Peach Bottom uses Rev.2 of this guideline.
Revised guideline incorporates latest industry OPEX.
No changes to monitoring criteria.
Reactor Head Closure Stud Bolting NUREG-2191 requires the use of material with ultimate tensile strength of less than 170 ksi for in-service studs. Both units have studs installed with studs over 170 ksi.
Test reports show some test values over limit. Studs are inspected for cracking.
NUREG-2191 requires the use of material with yield strength of less than 150 ksi for replacement studs. Replacement stud has test results over 150 ksi.
Test reports show some test values over limit. Stud was inspected for cracking and will be re-inspected if utilized.
BWR Vessel Internals Steam Dryer will not be inspected per BWRVIP-139-A BWRVIP-139-A is for GE designed steam dryer assemblies. PB has installed Westinghouse steam dryers and has submitted an inspection plan to the NRC.
GALL Consistency - AMP Exceptions Peach Bottom Atomic Power Station, Units 2 and 3 17 Program Exception Justification Fire Water System NUREG-2191 requires foam system discharge test annually to confirm spray patterns. When not possible, visual inspection of nozzles and air testing is performed.
Single nozzle which sprays across down the inside of the tank. Nozzle has a vapor seal. One time visual inspection to assure proper orientation as it is within the fuel tank.
Internal Coatings NUREG-2191 requires an internal inspection of portions of concrete lined pipe. Opportunistic inspections will be performed.
Fire header piping is buried. Various periodic flow tests will assure coating has not degraded impacting performance. 2014 inspections found concrete lining in good condition. When made available, visual inspection will be performed.
NUREG-2191 requires coating found not meeting acceptance criteria are repaired, replaced, or removed. HPCI lube oil reservoir coating will not be repaired.
NMACs Terry Turbine Users Group provides recommendations that degraded coatings not be replaced. Only remove portions that show poor adhesion.
ASME Section XI-IWE NUREG-2191 requires pressure retaining components subject to cyclic loading that have no fatigue analysis are inspected for cracking. Peach Bottom will only inspect high temperature mechanical penetrations.
Peach Bottom, had it been constructed to a later code, would have met requirements of ASME Code for fatigue waivers for low temperature penetrations. High temperature penetration accessible surfaces will be inspected for cracking.
Program will manage flow blockage due to fouling for the Core Spray System, High Pressure Coolant Injection System, Reactor Core Isolation Cooling System, and Residual Heat Removal System pump suction strainers.
No existing GALL line items exist for the management of flow blockage due to fouling for these components and as a result the IWE Program was selected because the station Containment ISI program plan and procedures will perform the required aging management actions.
GALL Consistency - AMP Exceptions Peach Bottom Atomic Power Station, Units 2 and 3 18 Program Exception Justification E3A - Medium Voltage Cables NUREG-2191 recommends, inspections for water accumulation and manhole condition annually.
Additionally, inspections for water accumulation are also to be performed after event driven occurrences, such as heavy rain.
Manholes with level monitoring and alarms that result in consistent, subsequent pump out of accumulated water prior to wetting or submergence of cables will be inspected at least once every five years with additional inspections following event driven occurrences, such as heavy rain, rapid thawing of ice and snow, or flooding, when level monitoring indicates water is accumulating.
Level monitoring instrumentation, with alarms monitored by Operations Personnel, provide for detection of water level on an on-going basis.
Corrective actions are taken when an alarm is received which includes manual pumping of the manhole as needed. In cases where it can be determined that cables have not been subjected to significant moisture, manhole inspections will be performed on a five-year frequency when structural inspections are performed.
Following event driven occurrences, inspections and subsequent pump outs, as needed, will be performed when level instrumentation has detected increasing water levels.
E3B - I&C Cables E3C - Low Voltage Cables
RPV Embrittlement
- 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 Peach Bottom Atomic Power Station, Units 2 and 3 19 SLRA Sections Addressing GALL-SLR Recommendations Reactor pressure vessel neutron embrittlement at high fluence 3.1.2.2.3 Loss of Fracture Toughness Due to Neutron Irradiation Embrittlement 3.1.2.2.13 Loss of Fracture Toughness due to Neutron Irradiation or Thermal Aging Embrittlement 4.2 Reactor Vessel and Internals Neutron Embrittlement Analyses A.2.1.20 Reactor Vessel Material Surveillance A.3.1.2 Neutron Fluence Monitoring
IASCC of Reactor Vessel Internals (RVI)
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 Peach Bottom Atomic Power Station, Units 2 and 3 20 SLRA Sections Addressing GALL-SLR Recommendations IASCC of reactor internals and primary system components 3.1.2.2.12 Cracking Due to Irradiation-Assisted Stress Corrosion Cracking 4.2.1.2 Reactor Vessel Internals Neutron Fluence Analyses 4.2.14 First License Renewal Application Core Shroud IASCC and Embrittlement Analysis A.2.1.7 BWR Vessel Internals A.3.1.2 Neutron Fluence Monitoring
Concrete and Containment Degradation
- 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 Peach Bottom Atomic Power Station, Units 2 and 3 21 SLRA Sections Addressing GALL-SLR Recommendations Concrete and containment degradation 3.5.2.2.1 Pressurized Water Reactor and Boiling Water Reactor Containments 3.5.2.2.2 Safety-Related and Other Structures and Component Supports 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
Electrical Cable EQ and Condition 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)
Peach Bottom Atomic Power Station, Units 2 and 3 22 SLRA Sections Addressing GALL-SLR Recommendations Electrical cable qualification and condition assessment 3.6.2.2.1/4.4.1 Environmental Qualification of Electric Equipment A.2.1.37 through 41 Cable and Connection Insulation Programs A.3.1.3 Environmental Qualification of Electric Equipment