ML20115E451
| ML20115E451 | |
| Person / Time | |
|---|---|
| Issue date: | 04/08/2020 |
| From: | Advisory Committee on Reactor Safeguards |
| To: | |
| Burkhart, L, ACRS | |
| References | |
| NRC-0871 | |
| Download: ML20115E451 (306) | |
Text
Official Transcript of Proceedings NUCLEAR REGULATORY COMMISSION
Title:
Advisory Committee on Reactor Safeguards Open Session Docket Number: (n/a)
Location: teleconference Date: Wednesday, April 8, 2020 Work Order No.: NRC-0871 Pages 1-189 NEAL R. GROSS AND CO., INC.
Court Reporters and Transcribers 1323 Rhode Island Avenue, N.W.
Washington, D.C. 20005 (202) 234-4433
1 1
2 3
4 DISCLAIMER 5
6 7 UNITED STATES NUCLEAR REGULATORY COMMISSIONS 8 ADVISORY COMMITTEE ON REACTOR SAFEGUARDS 9
10 11 The contents of this transcript of the 12 proceeding of the United States Nuclear Regulatory 13 Commission Advisory Committee on Reactor Safeguards, 14 as reported herein, is a record of the discussions 15 recorded at the meeting.
16 17 This transcript has not been reviewed, 18 corrected, and edited, and it may contain 19 inaccuracies.
20 21 22 23 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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1 1 UNITED STATES OF AMERICA 2 NUCLEAR REGULATORY COMMISSION 3 + + + + +
4 672ND MEETING 5 ADVISORY COMMITTEE ON REACTOR SAFEGUARDS 6 (ACRS) 7 + + + + +
8 OPEN SESSION 9 + + + + +
10 WEDNESDAY 11 APRIL 8, 2020 12 + + + + +
13 TELECONFERENCE 14 + + + + +
15 The Advisory Committee met via 16 teleconference at 8:30 a.m., Matthew Sunseri, 17 Chairman, presiding.
18 19 COMMITTEE MEMBERS:
20 MATTHEW W. SUNSERI, Chairman 21 JOY L. REMPE, Vice Chairman 22 WALTER L. KIRCHNER, Member-at-Large 23 RONALD G. BALLINGER, Member 24 DENNIS BLEY, Member 25 CHARLES H. BROWN, JR. Member NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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2 1 VESNA B. DIMITRIJEVIC, Member 2 JOSE MARCH-LEUBA, Member 3 DAVID A. PETTI, Member 4 PETER RICCARDELLA, Member 5
6 DESIGNATED FEDERAL OFFICIAL:
7 MIKE SNODDERLY 8 LARRY BURKHART 9
10 ALSO PRESENT:
11 PAUL AITKEN, Dominion 12 BRUCE BAVOL, NRR 13 ERIC BLOCHER, Dominion 14 ANNA BRADFORD, NRR 15 BEN BRISTOL, NuScale 16 SARAH BRISTOL, NuScale 17 SARAH FIELDS, Public Participant 18 LAUREN GIBSON, NRR 19 ANNE-MARIE GRADY, NRR 20 ALLEN HARROW, Dominion 21 ALLEN HISER, NRR 22 MARY JOHNSON, NRR 23 MEGHAN McCLOSKEY, NuScale 24 LOUIS McKOWN, Region II 25 FRED MLADEN, Dominion NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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3 1 SCOTT MOORE, Executive Director, ACRS 2 TONY NAKANISHI, NRR 3 MICHAEL NELSON, NuScale 4 QUYNH NGUYEN, ACRS 5 REBECCA NORRIS, NuScale 6 ERIC OESTERLE, NRR 7 JIM OSBORN, NuScale 8 PAUL PHELPS, Dominion 9 MARIE POHIDA, NRR 10 MATTHEW PRESSON, NuScale 11 JEFF SCHMIDT, NRR 12 DINESH TANEJA, NRR 13 GETACHEW TESFAYE, NRR 14 CARL THURSTON, NRR 15 CHARLES TOMES, Dominion 16 ANGELA WU, NRR 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 1 C-O-N-T-E-N-T-S 2 PAGE 3 Opening Remarks by ACRS Chairman . . . . . . 5 4 Surry Power Station Subsequent License Renewal 5 Remarks by Subcommittee Chairman . . . 9 6 Briefing and discussion . . . . . . . . 12 7 NuScale Chapter 15, Boron Dilution, Return to 8 Criticality, Probabilistic Risk Analysis, and Hydrogen 9 Oxygen Monitoring . . . . . . . . . . . . . . . . 65 10 Adjourn . . . . . . . . . . . . . . . . . . . . 189 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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5 1 P R O C E E D I N G S 2 8:38 a.m.
3 CHAIRMAN SUNSERI: The meeting will now 4 come to order. This is the first day of the 672nd 5 Meeting of the Advisory Committee on Reactor 6 Safeguards.
7 I am Matthew Sunseri, Chair of the 8 meeting. And at this time, I'm going to take a roll 9 call of the members to confirm their attendance.
10 Members, please acknowledge when I call your name.
11 Ron Ballinger?
12 MEMBER BALLINGER: I'm here.
13 CHAIRMAN SUNSERI: Dennis Bley?
14 MEMBER BLEY: Here.
15 CHAIRMAN SUNSERI: Charles Brown?
16 MEMBER BROWN: I'm here.
17 CHAIRMAN SUNSERI: Vesna Dimitrijevic?
18 MEMBER DIMITRIJEVIC: I'm here.
19 CHAIRMAN SUNSERI: Walt Kirchner?
20 MEMBER KIRCHNER: Here.
21 CHAIRMAN SUNSERI: Jose March-Leuba?
22 MEMBER MARCH-LEUBA: Present.
23 CHAIRMAN SUNSERI: Dave Petti?
24 MEMBER PETTI: Here.
25 CHAIRMAN SUNSERI: Joy Rempe?
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6 1 VICE CHAIR REMPE: I'm here.
2 CHAIRMAN SUNSERI: Pete Riccardella?
3 MEMBER RICCARDELLA: Present.
4 CHAIRMAN SUNSERI: And Matt Sunseri. I 5 note that we have a quorum.
6 The ACRS was established by Atomic Energy 7 Act and is governed by the Federal Advisory Committee 8 Act. The ACRS section of the U.S. NRC public website 9 provides information about the history of the ACRS and 10 provides documents such as our bylaws, charter, 11 Federal Register notice for meetings, letter reports 12 and transcripts of all full and subcommittee meetings, 13 including all slides presented at the meeting. The 14 Committee provides its advice on safety matters to the 15 Commission through its publicly available letter 16 reports.
17 The Federal Register notice announcing 18 this meeting was published on March 30th, 2020, and 19 provides and agenda and instructions for interested 20 parties to provided written documents or request the 21 opportunity to address the Committee.
22 The Designated Federal Official for this 23 meeting is Mr. Mike Snodderly.
24 During today's meeting, the Committee will 25 consider the following: Item No. 1, Surry Power NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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7 1 Station Subsequent License Renewal.
2 Item No. 2, NuScale: Chapter 15, Boron 3 Dilution, Return to Criticality, Probabilistic Risk 4 Analysis, and Hydrogen and Oxygen Monitoring.
5 And Item No. 3, Preparation of ACRS 6 Reports.
7 As reflected in the agenda, portions of 8 the NuScale session may be closed in order to discuss 9 and protect information designated as sensitive or 10 proprietary information.
11 A bridge line has been opened up to allow 12 members of the public to listen in on the 13 presentations and Committee discussion. We have 14 received no written comments or requests to make oral 15 statements from members of the public regarding 16 today's session. There will be an opportunity for 17 public comment and we have set aside time in the 18 agenda for comments from members of the public 19 attending or listening to our meeting. Written 20 comments may be forwarded to Mr. Mike Snodderly, the 21 Designated Federal Official.
22 A transcript of the open portion of the 23 meeting is being kept and it is requested that the 24 speakers use your microphones, identify yourself, and 25 speak with sufficient clarity and volume so that we NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 1 can be readily heard. Otherwise, speakers and all 2 participants should be muting their microphones when 3 not speaking.
4 So, before we begin the first 5 presentation, I want to acknowledge the support that 6 we've gotten from our staff, the applicants, and the 7 NRC staff to conduct this meeting via a virtual 8 meeting process.
9 Due to the actions necessary to protect 10 the public health from the coronavirus, we are 11 following the federally promulgated guidance to avoid 12 in-person social interactions. By my review, this 13 will be our first such meeting, out of 671 prior 14 meetings where we have met face-to-face.
15 We are well-prepared. Nonetheless, I am 16 sure that there may be unanticipated challenges. So 17 I ask in advance for your understanding, patience, and 18 support as we through this process.
19 There are two key behavior that I want to 20 emphasize for the participants today. First and 21 foremost, if you are not talking or engaging in the 22 conversation, mute your microphone.
23 Number two, for the presenters. Please 24 take frequent pauses in your presentation to allow 25 members to ask questions or provide input. When you NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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9 1 run for long periods of time without stopping to take 2 a breath, it makes it hard to break in. So we will 3 not be successful if we don't get the member 4 participation that has been a hallmark of the 5 effectiveness of this Committee.
6 So, that concludes my opening remarks.
7 Our first agenda item is the Surry Subsequent License 8 Renewal. And at this point, I'd like to turn to Anna 9 Bradford for any opening remarks.
10 MS. BRADFORD: Thank you, Chairman 11 Sunseri. Can you please confirm that you can hear me?
12 CHAIRMAN SUNSERI: Yes, you're loud and 13 clear.
14 MS. BRADFORD: Great. Thank you. As you 15 mentioned, my name is Anna Bradford. I'm the Director 16 of the Division of New and Renewed Licenses in NRR.
17 We sincerely appreciate the opportunity 18 today to present to ACRS the results of the staff's 19 review of the third application for subsequent license 20 renewal. We especially appreciate the ACRS' 21 flexibility in doing business in a new way during 22 these unusual times.
23 This application was submitted by Dominion 24 Energy Virginia, or Dominion, for the Surry Power 25 Station Units 1 and 2 located near Surry, Virginia.
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10 1 By way of background, Surry Units 1 and 2 received 2 approval for their initial renewed licenses from the 3 NRC on March 20th, 2003. The NRC review at that time 4 was performed using guidance developed prior to the 5 issuance of a Generic Aging Lessons-Learned Report, or 6 the GALL Report.
7 The NRC guidance for license renewal over 8 the years has evolved through enhancements and 9 improvements based on lessons learned from NRC reviews 10 of both domestic and international industry operating 11 experience.
12 The GALL Report went through two revisions 13 and additional Interim Staff Guidance was issued 14 following Revision 2. The guidance for subsequent 15 license renewal contained in GALL SLR built upon the 16 previous guidance and included additional focus and 17 enhancements where necessary on aging management and 18 time limited aging analyses for operation in the 60-19 to 80-year period.
20 In the staff presentation today, you will 21 hear about some of these specific SLR issues as 22 applied to the Surry review. The NRC project manager 23 for the Surry subsequent license renewal application 24 review are Ms. Angela Wu and Ms. Lauren Gibson.
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11 1 or addressing questions regarding the staff's review 2 of the Surry subsequent license renewal application.
3 Part of the management team on the phone 4 today are Mr. Eric Oesterle, Chief of the License 5 Renewal Project Branch. And in the audience are 6 members of the division and other NRR technical review 7 branches. We also have with us a representative from 8 Region II, Mr. Louis McKown, Senior Resident Inspector 9 at the Surry Power Station.
10 The staff will provide an overview of its 11 safety review as documented in the Final Safety 12 Evaluation Report which was provided to the ACRS on 13 March 9, 2020.
14 Following the staff's presentation, Dr.
15 Allen Hiser, Senior Technical Advisor, Division of New 16 and Renewed Licenses, will discuss the disposition of 17 different views from technical staff who submitted 18 non-concurrences on the SLR.
19 Finally, we will address any questions you 20 may have on the staff's presentation. We look forward 21 to a productive discussion today with the ACRS.
22 At this time, I'd like to turn the 23 presentation over to Mr. Paul Phelps, Dominion 24 director for subsequent license renewal, to introduce 25 his team and commence our presentation. Thank you.
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12 1 MR. PHELPS: Can everyone hear me?
2 CHAIRMAN SUNSERI: Yes, Paul.
3 MR. PHELPS: Thank you, Anna, and good 4 morning. My name is Paul Phelps and I am the 5 engineering director responsible for the Surry Power 6 Station subsequent license renewal, or SLR, project.
7 We appreciate the opportunity to speak 8 with the Advisory Committee on Reactor Safeguards, 9 ACRS, Full Committee today on Dominion Energy's 10 application for subsequent license renewal. This is 11 a very important day and we appreciate the support and 12 look forward to presenting the SLR application 13 highlights to the Committee.
14 By way of my background, I have been in 15 the nuclear industry for nearly 30 years. I am 16 responsible for various SLR-related projects that are 17 currently under development in Virginia. We have 18 stood up an organization not only to perform the 19 requisite work for relicensing the station, but we 20 also have a larger organization that is currently 21 working on projects to improve the safety, 22 reliability, and aging management for Surry Power 23 Station through various modifications.
24 I want to take the time to introduce the 25 team assembled on the call present to present the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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13 1 Surry SLR application. Paul Aitken, who is the 2 engineering manager responsible for the development of 3 the Surry SLR application. Paul was also involved in 4 a leadership role in all of Dominion Energy's first 5 license renewal projects.
6 Next is Eric Blocher. Eric has been 7 involved in various first license renewal applications 8 in the industry. He brings an extensive knowledge to 9 the team and has been deeply involved in the 10 development of the General Aging Lessons-Learned, 11 GALL, SLR, not only on behalf of Dominion Energy but 12 for the nuclear industry.
13 Lastly, I would like to recognize Fred 14 Mladen who is also on the call. Fred, is the site 15 vice president at Surry Power Station.
16 Next slide, please. I am on Slide 2.
17 I want to cover the agenda for today's 18 meeting. We will discuss the station overview 19 performance, SLR application development, GALL-SLR 20 consistency, SLR aging management programs, technical 21 topics, and closing remarks.
22 Next slide, please. I am on Slide 3.
23 Surry Power Station is located in Surry 24 County, Virginia, on the south side of the James 25 River, approximately 25 miles upstream of the point NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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14 1 where the river enters the Chesapeake Bay. The area 2 includes both populated industrialized areas as well 3 as expansive rural areas and spans from the Northern 4 Neck area of Virginia into North Carolina, and from 5 the Eastern Shore over to our state capital, Richmond, 6 in Central Virginia. Included in this area are many 7 military installations and airports providing 8 international travel.
9 Next slide, please. I am on Slide 4.
10 Surry is a Westinghouse three-loop 11 pressurized water reactor with an output net capacity 12 of nearly 1,700 megawatts. Together, these two units 13 produce approximately 15 percent of Virginia's 14 electricity needs. Unit 1 started commercial 15 operation in 1972 and Unit 2 started commercial 16 operation in 1973.
17 The independent spent fuel storage 18 installation facility was one of the first in the 19 country and will have the capacity to store the fuel 20 required for 60 years of operation. A 4.3 percent 21 stretch power uprate was implemented in 1995 prior to 22 the initial license renewal.
23 The renewed licenses for Surry and North 24 Anna Power Stations were issued in March of 2003.
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15 1 in 2012 and 2013 for Units 1 and 2, respectively.
2 Next slide, please. I'm on Slide 5.
3 Here's an aerial view of the station. I 4 will highlight some of the more significant features.
5 Again, the orientation of the site and the river flow 6 are from west to east, or upstream James River around 7 Hog Island, a state-designated wildlife management 8 area, to downstream James River towards the Chesapeake 9 Bay.
10 Features from the plant I'd like to point 11 out include the intake canal that provides the 12 ultimate heat sink from the James River. The 13 discharge canal back into the James about six miles 14 upstream from the intake. A unique feature of Surry 15 is that the water from the James River is pumped into 16 the intake canal, and the water flows over a mile and 17 is gravity-fed through the plant without any pumps.
18 Also depicted are the Unit 1 and 2 reinforced concrete 19 containment structures in the turbine building in the 20 light blue.
21 The switch yard is across the property on 22 the other side of the intake canal. The 23 administrative building located on the bottom of this 24 picture is where many of the plant's staff work.
25 Next slide, please. I'm on Slide 6.
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16 1 Here's some of the high level information 2 on the performance of Surry. To note, Surry operates 3 on an 18-month refueling frequency. The plant 4 capacity factor has been very good, as reflected in 5 the bullets. As far as the regulatory oversight 6 process, Surry is in Column 1 and has been there since 7 2007.
8 Next slide, please. I am on Slide 7.
9 There has been nearly one billion dollars 10 in capital investments made to Surry since the first 11 renewed license was issued in 2003. As I mentioned in 12 my opening remarks, Dominion Energy will continue to 13 invest in Surry to maintain safety and plant 14 reliability for the current and subsequent period of 15 operation.
16 Here is a partial list of some of the 17 major projects that have been completed at Surry since 18 the first license renewal. I would like to highlight 19 a few.
20 Dominion Energy was very proactive replace 21 the reactor vessel heads at both North Anna and Surry 22 Power Station. In addition, Surry has replaced or 23 scheduled to replace all of the high voltage 24 transformers.
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17 1 polymer installation is one of the first projects that 2 the SLR team implemented at Surry to address 3 longstanding aging management of large bore 4 circulating water and service water piping.
5 Let me pause and ask if there are any 6 questions before I turn over the presentation to Paul 7 Aitken.
8 (Pause.)
9 MR. AITKEN: Okay. Thanks, and good 10 morning. Again, my name is Paul Aitken and I am the 11 engineering manager responsible for the development of 12 the Surry Subsequent License Renewal Application. We 13 are now on Slide 8.
14 I'll be providing an overview of the SLR 15 application development process and other 16 considerations for the ACRS Committee today. The 17 Dominion Energy team has worked closely with various 18 research organizations and utility-sponsored groups to 19 collectively represent the industry when working with 20 the NRC during the development of the GALL-SLR. We 21 supported several public meetings over the last couple 22 of years to finalize the GALL-SLR, as well as 23 spearheading the industry guidance for SLR, as 24 reflected in NEI Guide 17-01.
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18 1 the benefit from the industry engagement and used 2 those insights in the development of the Surry 3 application. We also reviewed previously issued RAIs 4 to incorporate additional lessons learned from the 5 more recent first license renewal applicants and SLR 6 applicants.
7 Dominion Energy participated in the peer 8 reviews for Turkey Point and Peach Bottom. We were 9 able to provide feedback on their respective 10 applications while also incorporating insights that we 11 learned during the interactions. We also conducted an 12 industry peer review using the NEI license renewal 13 civil, mechanical, and electric working groups and 14 other SLR applicants.
15 Dominion Energy had a pre-submittal 16 meeting with the NRC on the safety portion of the 17 application. The meeting provided a public forum that 18 allowed additional clarifications and questions to be 19 asked between Dominion Energy and the NRC staff.
20 These insights were beneficial during the development 21 of the application.
22 In the end, Dominion Energy submitted a 23 high quality application, as reflected by fewer RAIs 24 as compared to Dominion Energy's first license renewal 25 applications, and a Safety Evaluation Report with no NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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19 1 open items or confirmatory items.
2 Next slide, please. Now I'm on Slide 9.
3 I wanted to provide a brief summary of the 4 differences between first license renewal and 5 subsequent license renewal with respect to the 6 integrated plant assessment. With scoping and 7 screening there were no changes in the overall process 8 approach. This is primarily because the established 9 industry criteria hasn't changed very much from first 10 license renewal.
11 We needed to address any physical 12 modifications for the facility since the last license 13 renewal. Another area that we expected to have 14 adjustments was related to scoping and screening by 15 altitude. That's not safety-related, but it can 16 affect safety-related equipment. This was due to the 17 criteria and guidance evolving since first license 18 renewal.
19 Surry is a plant like the previous two SLR 20 applicants, so we are in the same situation of the 21 methodology and scoping in additional systems. In the 22 area of aging management reviews, the expansion and 23 the number of aging effects we have to address 24 significantly increase through the events of the 25 previous application and the evolution of the GALL NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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20 1 over the years.
2 The biggest difference was in aging 3 management programs. Currently, for first license 4 renewal, we have 25 aging management programs. Moving 5 into subsequent license renewal, there are 47 going to 6 be aging management programs.
7 Activities from first license renewal have 8 been addressed in subsequent license renewal. Eric 9 Blocher will provide some additional information on 10 the aging management program. The Surry subsequent 11 license renewal application has reassessed the 12 existing licensing basis TLAAs. There was only one 13 new TLAA identified since this license renewal, and 14 that was dispositioned as acceptable for 80 years.
15 Next slide, please.
16 CHAIRMAN SUNSERI: Before you move on, I 17 have a question. This is Matt Sunseri. Can you hear 18 me?
19 MR. AITKEN: Yeah, I can.
20 CHAIRMAN SUNSERI: On the differences 21 between your first license renewal and your subsequent 22 license renewal, are there any aging management 23 activities from the first license renewal that didn't 24 carry over into the subsequent renewal?
25 (Off-microphone comments.)
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21 1 (Simultaneous speaking.)
2 MR. AITKEN: There's a little feedback 3 there. Can you repeat that? Are there any first 4 license renewal activities that are not being 5 addressed in subsequent license renewal?
6 CHAIRMAN SUNSERI: That's correct, yeah.
7 I hear the feedback. Somebody is not muting their 8 microphone. So, all participants that aren't engaged 9 in the conversation, please mute your microphone 10 unless you're trying to talk.
11 MR. AITKEN: So, yeah, to answer that 12 question, all first license renewal activities are 13 going to carry forward into subsequent license 14 renewals. Eric is going to talk to that very point as 15 he gets into his slides.
16 CHAIRMAN SUNSERI: Okay. Thank you.
17 MR. AITKEN: Okay. So, now we are on 18 Slide 10. Our alignment with GALL-SLR was over 99 19 percent. As discussed at the ACRS subcommittee 20 meeting in February, the high degree of alignment to 21 the GALL-SLR is the result of the efforts by the NRC 22 staff and the industry to broaden the GALL, to capture 23 the additional materials, environment, and aging 24 combinations that were identified during the first 25 license renewal applications.
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22 1 In terms of commitments, we have a total 2 of 47. These are primarily on an AMP-by-AMP basis and 3 are reflected in Appendix A of the Final Safety 4 Evaluation Report. These commitments will be captured 5 in the Surry FSEAR qualifications issued for the 6 renewed license. These commitments will also be 7 managed within the Dominion Energy commitment tracking 8 system, which is based on NRC-endorsed NEI 99-04 9 guidelines for managing NRC commitments.
10 I will leave you with a sense that these 11 commitments were discussed with the station team and 12 agreed upon current limitation. Some commitment items 13 have already been addressed. And Dominion Energy will 14 ensure the proper time, talent, and resources are in 15 place to implement the commitments as required.
16 That is all I have for my portion of the 17 presentation. Are there any further questions for me 18 before I hand it over to Eric Blocher?
19 CHAIRMAN SUNSERI: Members, any questions?
20 MEMBER MARCH-LEUBA: No questions from me.
21 CHAIRMAN SUNSERI: Go ahead, Eric.
22 MR. BLOCHER: Can you confirm that you 23 hear me?
24 CHAIRMAN SUNSERI: Yeah, I got you, Eric.
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23 1 and good morning. My name is Eric Blocher and I am 2 the SLR technical lead responsible for the technical 3 content and assembly of the Surry SLR application.
4 By way of background, I have been in the 5 nuclear industry for 43 years. As Paul Phelps noted 6 earlier, I was previously involved in numerous 7 industry license renewal projects. I will be 8 providing an overview of the aging management programs 9 described in the SLR application for the full 10 Committee today.
11 As part of our engagement with industry, 12 several Surry SLR project team members have held 13 leadership roles on NEI task forces and working 14 groups. Other members collaborated with EPRI on 15 activities such as guidance for aging management of 16 alkali-silica reaction, concrete irradiation 17 evaluations, and reactor internals inspections. And 18 others have participated in PWR Owners Groups reactor 19 vessel integrity and time-limited aging analysis 20 generic report projects.
21 Project team participation not only 22 benefitted the Surry application but provided guidance 23 and technical reports that include several reports 24 with NRC safety evaluations that are generically 25 applicable to other SLR applications. Review and NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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24 1 incorporations of operating experience was performed 2 for a ten-year period to inform the aging management 3 programs.
4 As Paul Aitken just mentioned, the Surry 5 team also reviewed recent license renewal applications 6 RAIs associated with the Turkey Point and Peach Bottom 7 applications, as well as more recent first license 8 renewal projects. Our project team also participated 9 in the Turkey Point and Peach Bottom industry peer 10 reviews to provided insights and share constructive 11 comments.
12 Prior to submittal of the application, the 13 effectiveness of the aging management activities was 14 addressed using the evaluation elements identified in 15 NEI 14-12 Aging Management Program Effectiveness 16 guidance document.
17 Next slide, please. Slide 12 provides a 18 breakdown of the aging management programs that were 19 developed in support of subsequent license renewal.
20 Just to close the loop with Matt Sunseri's question, 21 all first license renewal aging management activities 22 were carried forward from first license renewal into 23 subsequent license renewal. None were deleted.
24 If you look at the left column, there are 25 40 existing AMPs that resulted from the combination NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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25 1 and some subdivision process of the first license 2 renewal AMPs. The SLR existing AMPs are augmented by 3 seven new AMPs. The remainder of the columns provide 4 perspectives on GALL-SLR AMP consistency.
5 Approximately one-quarter of the 47 AMPs are 6 consistent with GALL without enhancements.
7 Approximately half of the 47 AMPs are consistent with 8 enhancement. Approximately one-quarter of the SLR 9 AMPs are consistent with one or more exceptions.
10 Next slide, please. We're now on Slide 11 13. First license renewal AMPs have been, and will 12 continue to be, assessed for AMP effectiveness. The 13 Surry effectiveness reviews assessed first license 14 renewal activities and included a detailed review of 15 inspection schedules, results, and data, as well as a 16 review of relevant operating experience within the 17 corrective action program.
18 All first license renewal programs were 19 determined to be effectively implemented. A summary 20 of each review is found is in Appendix Bravo of the 21 subsequent license renewal application for each aging 22 management activity.
23 Program owners receive periodic training 24 and are required to complete AMP effectiveness reviews 25 every five years, as well as perform systematic NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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26 1 operating experience reviews on an ongoing basis to 2 inform AMP and augment AMP effectiveness.
3 As an indication of regulatory 4 acceptability of the Dominion Energy aging management 5 programs, the IP 71003 Phase 4 NRC inspection 6 identified no findings or concerns in the third 7 quarter of 2019.
8 That is all I had for the AMP portion of 9 the presentation. Are there any questions for me 10 before I start the next portion of the presentation on 11 technical topics?
12 (No response.)
13 MR. BLOCHER: Next slide, please. We're 14 now on Slide 14. On Slide 14, in the subcommittee 15 meeting, we presented in some detail how Dominion 16 addressed the four technical topics reflected on the 17 slide related to concrete and containment degradation, 18 reactor vessel internals, reactor vessel support 19 steel, and reactor vessel embrittlement.
20 To summarize, we have developed our 21 various aging management programs to be consistent 22 with GALL-SLR guidance. There has been no loss of 23 license renewal intended functions due to concrete 24 aging since entering the period of the extended 25 operation.
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27 1 As we are all aware, an industry concern 2 related to alkali-silica reaction was identified in 3 the GALL-SLR. Dominion Energy has proactively 4 addressed this concern by implementing the EPRI 5 alkali-silica reaction inspection guides. This 6 guidance was developed, in part, by members of the SLR 7 team. The guidance uses identification of leading 8 indicator structures, conduct of augmented 9 examinations for pattern cracking, and detection of 10 water ingress, as well as identification of structural 11 misalignment. No effects of alkali-silica reaction 12 have been identified at Surry based on inspections, to 13 date.
14 Next, the concrete biological shield wall 15 gamma and neutron radiation remains conservatively 16 below GALL-SLR radiation exposure levels throughout 17 the subsequent period of extended operation. Also, 18 recent examinations of the containment liner to 19 concrete slab interface in October 2016 for Unit 1 and 20 May 17 for Unit 2 have not identified any degradation.
21 (Simultaneous speaking.)
22 MR. BLOCHER: Can somebody mute the --
23 (Telephonic interference.)
24 CHAIRMAN SUNSERI: Okay. Eric, you're 25 muted.
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28 1 MR. BLOCHER: What was the last subject I 2 was talking to? The concrete?
3 CHAIRMAN SUNSERI: I believe that's right.
4 MR. BLOCHER: Okay. I'll pick up with 5 reactor vessel internals. Surry will manage the 6 reactor vessel internals consistent with MRP 227, Rev.
7 1A inspection and evaluation guidance that was issued 8 in December 2019. We have worked closely with the 9 various industry groups and the NRC staff to identify 10 the requisite inspections for the subsequent period of 11 operation.
12 For reactor vessel support steel, Dominion 13 Energy determined that peak stresses for design basis 14 loads associated with the Unit 1 and Unit 2 reactor 15 vessel support assemblies are below the critical 16 stress limits calculated through wall and/or surface 17 flaws based on projected fracture toughness through 18 the subsequent period, satisfying evaluated reactor 19 pressure vessel material properties for 80 years. And 20 we'll remove and test surveillance capsule for each 21 unit during the subsequent period of extended 22 operation.
23 The applicability of the existing heatup 24 and cooldown curves can be extended to expected full-25 power years based upon using our updated material NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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29 1 property data and application of the K1c methodology 2 which is currently included in the ASME code.
3 I'll pause to see if there are any 4 questions on these topics.
5 MEMBER BALLINGER: Yes, this is Ron 6 Ballinger. I wanted to confirm what I think I heard 7 during the Subcommittee meeting with regard to the 8 pressure vessel embrittlement issue. You folks, I 9 assume, are aware of the sort of impending changes 10 that may happen to Reg Guide 1.99. Do those changes, 11 if you were to look at those, affect the extrapolation 12 out to 80 years for embrittlement?
13 MR. BLOCHER: Chuck Tomes, would you like 14 to provide some details to Mr. Ballinger?
15 MR. TOMES: Yes, this is Chuck Tomes from 16 Dominion Energy. We've looked at the projections 17 going forward for Surry Nuclear Plant. And we're 18 confident that, while the projects will change, we 19 will be able to maintain all of the safety margins for 20 heatup and cooldown curves, LTOP, PTS, for the Surry 21 subsequent licensing period for Unit 1 and Unit 2.
22 MEMBER BALLINGER: Thanks.
23 MR. TOMES: You're welcome.
24 MR. BLOCHER: Are there any additional 25 questions?
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30 1 (No response.)
2 MR. BLOCHER: That's fine. I will now 3 turn the presentation back to Paul Aitken for closing 4 remarks.
5 MR. AITKEN: Okay. Thank you, Eric. So 6 it's around 9:15. So, on behalf of Dominion Energy, 7 I'd like to recognize the NRC staff for the 8 thoroughness of the safety review performed on the 9 Surry application. I want to reiterate that Dominion 10 Energy has been engaged in many ways with regards to 11 moving on our SLR issuance. We have been heavily 12 invested with a lot of others in the industry over the 13 last couple of years to ensure we have the appropriate 14 guidance and have explored avenues for optimization 15 with the NRC staff based on the vast experiences 16 during the first license renewals.
17 Dominion Energy has developed a high 18 quality SLR application that benefitted from the GALL-19 SLR and SRP as well as various industry support.
20 Dominion Energy will continue to invest in site 21 optimization, as Paul noted, now and into the future 22 to ensure the continued safety and reliable operation 23 during the subsequent period of operation.
24 Mr. Chairman, this ends our presentation.
25 Are there any further questions?
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31 1 VICE CHAIR REMPE: Matt, this is Joy. I 2 have a question for Dominion.
3 CHAIRMAN SUNSERI: Go ahead, Joy.
4 VICE CHAIR REMPE: I know the staff is 5 going to talk about the fire protection piping issue.
6 But I had a question for Dominion on the status of 7 their efforts regarding updating the AMP. Is this 8 just a project that's been authorized? Is it underway 9 now? Where are they with respect to the status of 10 these efforts?
11 MR. AITKEN: Okay. Joy, I'm going to turn 12 to Allen Harrow, who's our site engineering manager, 13 to give you an update on where we are.
14 MR. HARROW: Okay. Can everyone hear me?
15 VICE CHAIR REMPE: Yes.
16 MR. HARROW: Okay. My name is Allen 17 Harrow. I work for Dominion Energy. I'm the site 18 engineering manager at Surry Power Station.
19 Currently, we are continuing with Phase 1 of our fire 20 protection project to excavate and remove piping based 21 on the priorities that we identified when we 22 originally had an issue in July of 2019 with the fire 23 protection guard loop.
24 We are continuing to work through Phase 1.
25 We have dug up approximately 89 feet of additional NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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32 1 piping and removed the piping. As we have identified 2 previously, in order to evaluate if corrosion concerns 3 exist with the piping, the piping has to be 4 sandblasted.
5 We have partially sandblasted 89 feet that 6 has been dug up. We have identified that, so far, we 7 have not seen additional through-wall corrosion 8 through the piping that has been dug up. The piping 9 itself is roughly a half-inch in thickness. And the 10 most significant depth of the corrosion we've seen so 11 far is about one-half of the thickness of the pipe.
12 We have also taken samples of that pipe 13 and we've sent them off for lithoscopic examination.
14 That was just done yesterday, so we don't have the 15 results for that. And we've also taken soil samples 16 that we have sent off for analysis. We don't have the 17 analysis of that yet.
18 However, the fact that the piping that we 19 have dug up that was done after the original piping 20 repairs, the fact that it is -- is a positive 21 indication. But we're continuing with Phase 1 of the 22 project.
23 Are there any other questions?
24 MEMBER BALLINGER: Yes, this is Ron.
25 VICE CHAIR REMPE: If I were NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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33 1 characterizing that, I'd say you're in the initial 2 phases of this effort. Is that how you would 3 characterize it?
4 MR. HARROW: I would. We originally 5 identified four phases of the project. This is Phase 6 1. We do have a project manager onsite. And the 7 project manager reports out weekly to the station 8 management team and provides updates.
9 VICE CHAIR REMPE: Thank you.
10 MEMBER BALLINGER: This is Ron Ballinger.
11 There are a number of selective leeching models out 12 there that purport to predict the amount of 13 penetration as a function of the various chemistry 14 parameters. And I believe there's an EPRI task force 15 -- if that's how you want to call it -- that's 16 addressing selective leeching going forward.
17 Have you folks -- do you folks have enough 18 data on the pipes that you've dug up so that you can 19 actually compare what you see with what these models 20 might predict given your chemistry?
21 MR. HARROW: So, I do not believe I can 22 answer that question fully at this time. I will say 23 that Surry did send off samples of piping from the 24 original pipes that were excavated after the original 25 July 2019 break. And we sent those to EPRI to help NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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34 1 them with part of the study that I believe you're 2 referring to. At this point, I'm not able to fully 3 answer that question.
4 MEMBER BALLINGER: Thanks. I mean, I just 5 think that you're going to have some data going 6 forward, and there are maybe some issues with folks 7 saying that you need to dig up more pipe or not, that 8 having comparison and alignment with various -- with 9 a model might allow you to project a little bit 10 forward on where the issues might be before they 11 happen.
12 MR. HARROW: I do appreciate that input, 13 and we will be working hand-in-hand with EPRI to 14 determine what additional analysis will help us as we 15 move forward with the project.
16 MEMBER BALLINGER: Thank you.
17 CHAIRMAN SUNSERI: Any other questions 18 from the members?
19 (No response.)
20 CHAIRMAN SUNSERI: I have one kind of 21 follow-up from the Subcommittee meeting that we had 22 back in February. I was reading back through the 23 transcript, and I thought I understood the soil 24 sampling program. But maybe I'm confused on that.
25 So, you dig a hole for excavation and you NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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35 1 sample the soil. You dig some exploratory wells. I 2 think you sample the soil. But could you just re-3 summarize what your soil sampling program is? Or 4 maybe not program, but your approach to the soil 5 sampling to pinpoint the corrosion mechanism?
6 MR. BLOCHER: This is Eric Blocher. Can 7 everybody hear me?
8 CHAIRMAN SUNSERI: Yes, we can hear you.
9 MR. BLOCHER: Thank you. The soil survey 10 program used is consistent with GALL. Specifically, 11 it's consistent with soil sampling requirements in 12 ASTM 41. The soil characteristics that we look for in 13 each of the samples are resistivity, pH, redox 14 potential, sulfites, chlorides, and soil consortia, 15 which is a measure of bacteria activity in the soil.
16 We use the EPRI reports 300, 200, 5294 17 scaling evaluations to determine the corrosivity of 18 the soil. So, there's four levels of corrosivity. A 19 level that scores between 0 and 10 is considered mild 20 to moderate corrosive. Above 10 to 15 is 21 appreciatively corrosive. Greater than 15, it's 22 severely corrosive.
23 The piping within the scope of license 24 renewal, based on our 2018 soil survey results at the 25 site, were in areas that scored 10 or less. So it's NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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36 1 mildly to moderately corrosive at the station.
2 Did that answer your question, Chairman 3 Sunseri?
4 CHAIRMAN SUNSERI: In part, it did. So, 5 what is the sampling -- I'll call it frequency, or 6 what drives you to sample a soil? What's your 7 criteria?
8 MR. BLOCHER: The way our program is 9 structured, there's a soil survey performed on a 10 frequency of approximately ten years. We're actually 11 sampling more frequent than that. The original 12 baseline was conducted in 2012. The last follow-up 13 survey was done in 2018.
14 In addition, whenever a pipe is excavated, 15 soil survey samples are taken to assess that in 16 comparison with the baseline and most recent results.
17 CHAIRMAN SUNSERI: And when you excavate 18 a portion of pipe, and you see or you don't see water 19 at the pipe level, what is your action?
20 MR. BLOCHER: Well, I believe you're 21 referring to part of the corrective actions that are 22 put in place from a result of our recent fire water 23 event, fire water piping event, that Mr. Harrow spoke 24 to. Normally, there's some moisture in the soil. But 25 we typically do not see groundwater. As a result of NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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37 1 that event, that was one of the corrective actions to 2 be sensitive to groundwater presence in that area.
3 Groundwater monitoring is an altogether different 4 program, and there's a series of groundwater wells 5 that are sampled throughout the site.
6 Most of the fire water piping that we're 7 doing with in the event, I believe, is buried six to 8 eight feet below the soil surface level.
9 Allen, can you confirm that for me?
10 MR. HARROW: That is correct, Eric.
11 MR. BLOCHER: Thank you.
12 CHAIRMAN SUNSERI: And one last question.
13 Of the 89 feet that you recently removed, was there 14 any -- was the groundwater at the pipe or was it dry?
15 MR. BLOCHER: Allen, could you assist with 16 that response?
17 MR. HARROW: Yeah. So, this is Allen 18 Harrow again. So, when we removed the 89 feet of 19 piping that we've removed since the July event, we did 20 identify a couple of areas where there was some 21 stormwater leakage that was essentially coming into 22 the area where we were excavating piping. We entered 23 that into our corrective action process to repair 24 those leaks. I would say, other than that, we did not 25 see signs of groundwater intrusion.
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38 1 CHAIRMAN SUNSERI: Okay. I appreciate 2 your patience with my questions. Thank you. I have 3 no more questions. Any other members?
4 MEMBER KIRCHNER: Matt, this is Walt.
5 This is for Paul or Allen. As you replace the 12-inch 6 piping, are you going back to the same cast iron 7 bituminous coating? Or have you new piping that 8 you're using for the replacement?
9 MR. HARROW: This is Allen Harrow. We are 10 currently replacing the piping with ductile iron 11 piping and not cast iron piping. We are also 12 considering, as we move forward, the use of high 13 density polyethylene material as a consideration.
14 CHAIRMAN SUNSERI: Thank you. Any other 15 questions?
16 Okay. Well, we appreciate the 17 presentation from the Dominion folks. Thank you for 18 that information. At this point, we can turn to the 19 staff presentation. And I believe Angela Wu will be 20 leading that.
21 MS. WU: Hi, yes, I am. This is Angela.
22 MEMBER MARCH-LEUBA: This is Jose. May I 23 suggest a five-minute break for everybody to go get a 24 cup of coffee or something?
25 CHAIRMAN SUNSERI: I was going to ask NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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39 1 Angela if she's going to need any transition time 2 here. But let's go ahead and take a five-minute break 3 while the staff brings up their presentation. So, we 4 will resume this. We will reconvene at 25 before the 5 hour5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />. Thank you.
6 (Whereupon, the above-entitled matter went 7 off the record at 9:27 a.m. and resumed at 9:35 a.m.)
8 CHAIRMAN SUNSERI: All right. Well, it's 9 25 to the hour, so we are reconvening here. I wonder 10 if I need to do a roll call just to make sure all the 11 members are back? Let me do that real quick.
12 So, just to make sure we have all the 13 members back on the server that dropped out, I'm going 14 to do a quick roll call. So, members, please 15 acknowledge when I call your name. Ron Ballinger?
16 (No response.)
17 CHAIRMAN SUNSERI: Dennis Bley?
18 MEMBER BLEY: I'm here. It took about 19 three times to get back on.
20 CHAIRMAN SUNSERI: Yeah. Charles Brown?
21 (No response.)
22 CHAIRMAN SUNSERI: Vesna Dimitrijevic?
23 (No response.)
24 CHAIRMAN SUNSERI: Walt Kirchner?
25 MEMBER KIRCHNER: Present.
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40 1 CHAIRMAN SUNSERI: Jose March-Leuba?
2 (No response.)
3 CHAIRMAN SUNSERI: Dave Petti?
4 (No response.)
5 CHAIRMAN SUNSERI: Joy Rempe?
6 VICE CHAIR REMPE: I'm here.
7 CHAIRMAN SUNSERI: Pete Riccardella?
8 (No response.)
9 CHAIRMAN SUNSERI: Well, we only have 10 four. So we need to try to get some others back.
11 Okay. It looks like Pete is -- Pete, you there?
12 MEMBER RICCARDELLA: Yes, we can hear you.
13 CHAIRMAN SUNSERI: Pete, can you hear?
14 MR. NGUYEN: Yeah, it doesn't look like 15 his mic is working. So, yeah, I'll help troubleshoot.
16 VICE CHAIR REMPE: Chairman, can we go 17 through again and see some of them have joined?
18 CHAIRMAN SUNSERI: Yeah. So, Jose March-19 Leuba, are you there?
20 MR. NGUYEN: Court Reporter, if you're 21 there, could you please acknowledge you're on the 22 line?
23 COURT REPORTER: I'm here. I don't know 24 if anyone can hear me. I've been trying to answer.
25 MR. NGUYEN: We can hear you loud and NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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41 1 clear.
2 COURT REPORTER: Okay.
3 MR. NGUYEN: And Member Petti needs to 4 reboot the Skype meeting.
5 MEMBER MARCH-LEUBA: The all is on hold 6 and you have to unhold it. Somebody has that 7 somewhere. So they probably having the same problem 8 I was having.
9 (Whereupon, the above-entitled matter went 10 off the record at 9:38 a.m. and resumed at 9:41 a.m.)
11 CHAIRMAN SUNSERI: So, members, please 12 acknowledge when I call your name. Charles Brown?
13 MEMBER BROWN: I'm here.
14 CHAIRMAN SUNSERI: Vesna Dimitrijevic?
15 MEMBER DIMITRIJEVIC: I am here.
16 CHAIRMAN SUNSERI: Walt Kirchner?
17 MEMBER KIRCHNER: Present.
18 CHAIRMAN SUNSERI: Jose March-Leuba?
19 MEMBER MARCH-LEUBA: Up and running.
20 CHAIRMAN SUNSERI: Dave Petti?
21 MEMBER PETTI: I'm only on the phone.
22 Skype isn't working.
23 CHAIRMAN SUNSERI: Are you trying to get 24 your Skype reconnected?
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42 1 anything.
2 CHAIRMAN SUNSERI: Okay. You might have 3 to reboot everything. Joy Rempe?
4 Say again, Joy. You broke up.
5 VICE CHAIR REMPE: I am here, and I'll 6 talk a bit longer to make sure that it's working.
7 CHAIRMAN SUNSERI: Yeah. No, you're loud 8 and clear now. Pete Riccardella?
9 MEMBER RICCARDELLA: Present.
10 CHAIRMAN SUNSERI: And Matt Sunseri. So 11 we have all members attending, with the exception of 12 Petti who does not have the Skype connection, but he's 13 got audio. So we'll reconvene at this point in time 14 and we are ready for Angela to provide the staff 15 presentation. Angela, it's all yours.
16 MS. WU: Hi, this is Angela. Can everyone 17 hear me?
18 CHAIRMAN SUNSERI: Yeah, you're loud and 19 clear.
20 MS. WU: Great. Can everyone see my 21 presentation?
22 CHAIRMAN SUNSERI: Presentation is on the 23 screen.
24 MS. WU: Okay. Great. I'll go ahead and 25 get started, then. Good morning, Chairman Sunseri and NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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43 1 members of the ACRS. My name is Angela Wu, and I am 2 one of the project managers for the review of the 3 Surry Power Station Units 1 and 2 Subsequent License 4 Renewal Application, or SLRA.
5 As you heard from Anna Bradford, we are 6 here today to discuss the NRC staff safety review of 7 the Surry SLRA as documented in the Safety Evaluation 8 Report, or SER, that was issued on March 9th, 2020.
9 Joining me at the virtual table today are 10 Lauren Gibson, the second safety project manager for 11 the Surry SLRA; Louis McKown, Senior Resident 12 Inspector at Surry Power Station Region II; and Dr.
13 Allen Hiser, Senior Technical Advisor for License 14 Renewal Aging Management, Division of Materials and 15 Renewed Licensing. Also joining on the phone are 16 members of the technical and regional staff who 17 participated the review and conducted on it.
18 So, during the presentation I will be 19 pausing momentarily after each slide to see if there 20 are any questions from the members. But since this is 21 just the title slide, we'll move on to Slide 2, the 22 presentation outline.
23 We will begin today's presentation with an 24 overview of the safety review of the Surry SLRA before 25 moving on to the SER. Section 2, scoping and NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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44 1 screening review. Section 3, the aging management 2 review. And Section 4, the time-limited aging 3 analyses. Then you'll hear from Region II on 4 inspections and plant material conditions before 5 sharing the conclusions of the differing views as 6 related to the Surry SLRA review.
7 Okay. We're ready to move on to Slide 3.
8 Surry Units 1 and 2 were initially 9 licensed in May 1972 and January 1973. In May 2001, 10 the applicant, Virginia Electric & Power Company, or 11 Dominion, submitted the initial license renewal 12 application. The initial renewal licenses were issued 13 March 2003, extending the expiration date to May 2032 14 and January 2033 for Units 1 and 2, respectively.
15 On October 15, 2018, Dominion submitted an 16 SLRA for Surry Units 1 and 2. The application was 17 accepted for review on December 10, 2018. And the 18 Draft Safety Evaluation Report was issued on December 19 27, 2019 with no open or confirmatory items. On March 20 9, 2020, the NRC issued the Final Safety Evaluation 21 Report.
22 Moving on to Slide 4. The Surry review is 23 the third safety review performed by the staff using 24 the GALL-SLR and SRP-SLR guidance to their issuance in 25 2017. For the review, we conducted a total of three NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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45 1 audits as identified on the slide.
2 During the operating experience audit, the 3 staff performed an independent review of plant-4 specific operating experience to identify pertinent 5 examples of age-related degradation as documented in 6 the applicant's corrective action program database.
7 During the interoffice audit, the audit 8 team 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, or AMRs; and time-limited aging analyses, or 12 TLAAs.
13 And onsite audit limited to those 14 technical areas that needed further review following 15 the interoffice audit was conducted at the Surry Power 16 Station Units 1 and 2 in Surry County, Virginia and 17 Dominion headquarters in Innsbrook, Virginia.
18 Okay. Moving on to Slide 5, the SER 19 overview. So, Surry Draft SER was issued no open or 20 confirmatory items on December 27th, 2019. On March 21 9th, 2020, the Dinal SER was issued. During the 22 staff's in-depth review, a total of 71 requests for 23 additional information were issued.
24 Okay. We're moving on to Slide 6. In the 25 next few slides, I will present the results of the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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46 1 staff's safety review as described in the SER. SER 2 Section 2 describes the scoping and screening of 3 structures and components subject to aging management 4 review. The staff reviewed the applicant's scoping 5 and screening methodology, procedures, and results.
6 The staff also reviewed the various 7 summaries of the safety-related systems, structures, 8 and components, or SSC; nonsafety-related SSCs 9 affecting safety functions; and SSCs relied upon to 10 perform functions in compliance with the Commission's 11 regulations for fire protection, environmental 12 qualification, station blackout, anticipated 13 transients without scram, and pressurized thermal 14 shock.
15 Based on the review, the results from the 16 audit, and additional information provided by the 17 applicant, staff concluded that the applicant's 18 scoping and screening methodology and implementation 19 were consistent with the criteria of the SRP-SLR and 20 requirements of 10 CFR Part 54.
21 Okay. We're moving on to Slide 7. SER 22 Section 3 and it's subsections cover the staff's 23 review of the applicant's programs for managing the 24 effects of aging in accordance with 10 CFR 25 54.21(a)(3).
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47 1 Section 3.1 to 3.6 includes the AMR items 2 in each of the general system areas within the scope 3 of subsequent license renewal, as shown on the slide.
4 For a given AMR item, the staff reviewed the item in 5 accordance with the criteria in the SRP-SLR to 6 determine whether it is consistent with the GALL-SLR.
7 For items not consistent with the GALL-8 SLR, the staff reviewed the applicant's evaluation to 9 determine whether the applicant had demonstrated that 10 there is reasonable assurance that the effects of 11 aging will be adequately managed so that the intended 12 function will be maintained consistent with the 13 current licensing basis for the subsequent period of 14 extended operation.
15 Based on the audits and additional 16 information provided by the applicant, the staff 17 concluded that the applicant's aging management review 18 activities and results were consistent with the 19 criteria of the SRP-SLR and the requirements of 10 CFR 20 Part 54.
21 Okay. We're moving on to Slide 8 now.
22 The SLRA described a total of 47 AMPs: 7 new and 40 23 existing. This slide identifies the applicant's 24 written disposition of these AMPs as stated in the 25 SLRA in the left column and final disposition as NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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48 1 documented in the SER on the right column. All of the 2 AMPs were evaluated for consistency with the GALL-SLR.
3 As a result of the staff's review, the applicant made 4 one change to the disposition of the AMPs.
5 Based on the review, the results from the 6 audit, and additional information provided by the 7 applicant, the staff concluded the applicant's aging 8 management program activities and results were 9 consistent with the criteria of the SRP --
10 (Whereupon, the above-entitled matter went 11 off the record at 9:52 a.m. and resumed at 10:01 a.m.)
12 MS. WU: Okay, great, I'll go ahead and 13 get started again. All right, so Paragraph 1, Slide 14 9, which is the SER Section 4, hopefully those who 15 cannot see the actual type can follow along the 16 presentation I shared in advance 17 (Telephonic interference) -- Section 4 18 identifies five independent analyses or TLAA. Section 19 4.1 documents the fast evaluation of the applicant's 20 identification of applicable TLAA.
21 The Staff evaluated the Applicant's cases 22 for identifying those plant specific or generic 23 analyses that need to be identified as TLAAs and 24 determine that the applicant has provided an accurate 25 list of TLAAs, as required 10 CFR 54.10.
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49 1 Section 4.2 through 4.7 document the 2 Staff's review of the applicable TLAAs to the areas 3 shown on this slide. Based on its review and the 4 information provided by the applicant.
5 The Staff concludes that each TLAA is 6 classified as required by 10 CFR 54.21(c)(1) and 7 either I, the analysis remains valid in the subsequent 8 period of expanded operations, II, the analysis has 9 been projected to the end of the subsequent period of 10 extended operations, or III, the effects of aging on 11 the (telephonic interference) will be adequate managed 12 (telephonic interference) here.
13 From a literate view, the results from the 14 audit and additional information provided by the 15 applicant has included that the Applicant's TLAA 16 activities and results were consistent with the 17 criteria of SRP/SLR and the requirements of 10 CFR 54.
18 I will -- Louis, are you on?
19 MR. MCKOWN: Yes, I am on.
20 MS. WU: Great, thank you.
21 MR. MCKOWN: Good day all. I am Louis 22 McKown, I am the senior resident inspector at the 23 Surry Power Station, Region IV.
24 Thanks for your time. I am on Slide 10, 25 titled, Aging Management Program Inspections.
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50 1 In accordance with the Inspection 2 Procedure 71003, the regions conduct a (telephonic 3 interference) sort of a face forward section, five to 4 ten years into the initial period of expanded 5 operation.
6 During August of 2019, for the Surry 7 inspection, the nine aging management programs, shown 8 on this slide, were selected for a review using the 9 criteria provided within the inspection procedure.
10 For each program the inspectors reviewed 11 the licenses implementation by selecting the sample of 12 systems, structures and components within the scope of 13 the new program and finding the agent of the selected 14 items was being managed.
15 Based upon this inspection, the team 16 identified no findings. This provided reasonable 17 assurance that the list was appropriately admitting 18 the selected agent management programs.
19 Any questions? Next slide please. I'm on 20 Slide 11 titled July 2019 Fire Loop Pipe Rupture.
21 In July 2019 two failures occurred in the 22 varied fire protection piping at the west end of the 23 power block below the road leading to the turbine 24 building track bay. The installed Surry fire 25 protection water suppression loops (telephonic NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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51 1 interference) six feet below the grade throughout the 2 site.
3 As seen in the picture in the lower pipe 4 here, the first structure was a ten foot long 5 longitudinal crack along the bottom surface of the 6 pipe. The second failure was a circumferential crack 7 on an adjacent piping section. Which cannot be seen 8 here.
9 As the last year's Phase 4 license renewal 10 inspection was in progress at the same time that the 11 meeting was in the process of casual analysis and 12 immediate corrective actions to excavate and replace 13 the effected piping, a focused problem identification 14 resolution inspection was scheduled to fall off in the 15 first quarter of 2020.
16 In the meantime, Dominion completed casual 17 analyses and engineering evaluations which identified 18 that longstanding exposure to moist or wetted soil had 19 resulted in a reduction in wall thickness at several 20 locations due to acidic corrosion or selected 21 leaching. Which in turn led to pipe failure during 22 pumps test.
23 Two out of three soil samples taken at 24 other locations along the firewater piping identified 25 similar type conditions. All fire assessment of soil NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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52 1 conditions at Surry identified that the soil was 2 homogeneous while draining throughout the site.
3 As to the information in October, Dominion 4 documented that the loss of reasonable assurance of 5 continued reliability of the installed firewater 6 suppression system and established a number of 7 compensatory actions to restore compliance.
8 Next slide. I'm on Slide 12, Focused PIR 9 inspection.
10 Region II inspectors performed the focus 11 (telephonic interference) solutions during the week of 12 February 24th, 2020 in accordance with inspection 13 procedure 71152 (telephonic interference), resolution, 14 Section 03.03 annual follow-up and selected issues.
15 This inspection included development of a 16 sequence of events that led to the installed fire 17 suppression water system being declared not 18 functional, the determination of the current SAFDL and 19 corrective actions (telephonic interference) help 20 installed pressure water system, their view of 21 (telephonic interference) and documented, and 22 associated documents related to the Surry corrective 23 action program, fire protection program and 24 underground piping and integrity program and determine 25 the programmatic requirements that were from the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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53 1 actions taken by the licensee since the prior 2 protection loop piping failures.
3 And it also included a verification that 4 the Agency were in accordance with the associated 5 regulatory requirements were acceptable and mattered.
6 As a result of this inspection, no findings were 7 identified.
8 However, the inspectors have (telephonic 9 interference) captured observation on the status of 10 (telephonic interference) This is fire protection 11 loop piping failures.
12 In order to provide a point of reference 13 for future NRC oversight and inspections the 14 inspectors will be continuing these observations in 15 the 2020 corrective (telephonic interference) for the 16 baseline inspection report.
17 Next slide please. I'm on Slide 13, 18 Focused PIR Inspection, Timeline of Status of 19 Corrective Actions.
20 This diagram provides a timeline of events 21 from the initial loop piping ruptures last July to the 22 firewater suppression system being declared 23 nonfunctional in October.
24 To date, the primary administrative 25 actions take place in the replacement of the ductile, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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54 1 the failed ductile iron casting, sorry, failed cast 2 iron piping ductile iron and equivalent. And the use 3 of compensatory measures, including the establishment 4 of a backup firewater suppression system using the 5 staged diesel driven pump at the discharge canal 6 routed back to the main firewater header.
7 These compensatory actions remain in place 8 until reasonable assurance of functionality can be 9 restored to the installed fire suppression water 10 piping. Dominion believes that restoring a system to 11 a functional status will be accomplished through a 12 combination of equipment repair and/or replacement, in 13 addition to completion to a broader extensive 14 condition evaluation, which includes invasive piping 15 inspections throughout the site.
16 During the PIR inspection, Dominion 17 identified that while the ultimate completion of their 18 extensive condition investigation is scheduled for the 19 end of December of 2021, their success path continues 20 to be informed by the data gained in the field, as 21 well as industry operator experience.
22 They believe that in the long run this 23 will help them pull up their decision making and in 24 turn, establish a more definitive long-term action 25 plan for restoring the firewater suppression system NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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55 1 health.
2 With respect to the issue and the Surry 3 aging management programs, the event was too recent of 4 the time of the license renewal Phase 4 inspection to 5 observe the licensee's integration of this new 6 information into the buried piping and valve 7 inspection program.
8 During the PIR inspection, the inspectors 9 have noted that while a great deal of action had been 10 taken with respect to the event, the action to 11 incorporate this information into Dominion's buried 12 piping and valve inspection program were extended from 13 February till late April, nine months after the 14 initiating event.
15 As a number of aspects are discreetly 16 identified under a current licensing basis, and the 17 action was established and extended in accordance with 18 Dominion's corrective action program. The delays and 19 incorporation do not represent a specific performance 20 deficiency.
21 However, I would like to note that we were 22 informed by the site engineering, via email late last 23 night, that the associated corrective action to 24 incorporate this information in Dominion's buried 25 piping and valve inspection program, was closed NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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56 1 yesterday late afternoon.
2 That said, the scope of this condition and 3 the breadth of regulatory oversight and programmatic 4 impact afforded the Agency the opportunity to exercise 5 a wide-variety of tools, at least once, if not 6 multiple times, during the baseline inspection process 7 over the next few years.
8 Including, but not limited to, equipment 9 alignment (telephonic interference) fire protection 10 triennial team inspection, maintenance effectiveness 11 reviews for our new passive long lived system 12 structure and component aging management inspections 13 tools reside, maintenance risk assessment and a 14 merchant work control assessments, functionality 15 assessments, plant modification, surveillance testing 16 reviews, as well as additional prominent 17 identification of resolution of annual samples and 18 follow-up by the biennial team inspection.
19 In short, the plant impact and broad 20 inspection opportunities ensure that the Region will 21 maintain appropriate oversight of the corrective 22 actions associated with the firewater buried piping 23 aging management challenges.
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57 1 move onto the Region's final thoughts on Surry's aging 2 management programs.
3 Okay, next slide please. And I'm on Slide 4 14, Region II Plant Material Condition and 5 Conclusions.
6 Overall, for a plant that's in its first 7 period of extended operation the material condition is 8 generally acceptable. Licensee has been successful at 9 completing large capital improvement projects that 10 maintain or improve material of its SSCs.
11 And the license renewal program 12 inspections did identify any substantial weaknesses in 13 the stations performance in managing the effects of 14 aging at the site. The inspectors will continue to 15 inspect and assess the alleged ability to manage the 16 effects of aging through the NRC's baseline inspection 17 program.
18 Are there any questions?
19 MEMBER KIRCHNER: Louis, I had one.
20 MR. MCKOWN: Yes.
21 MEMBER KIRCHNER: This is Walt Kirchner.
22 I'm just looking at the phraseology chosen in the 23 first bullet. What does generally -- just acceptable?
24 MR. MCKOWN: I don't believe we 25 distinguish anything between generally acceptable.
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58 1 MEMBER KIRCHNER: Okay. I'm sure there 2 wasn't some subtle (telephonic interference) that we 3 might miss. (Telephonic interference) just word 4 choice.
5 MEMBER BROWN: Is that, this is Charlie 6 Brown. I'm done now.
7 MR. MCKOWN: If there are no additional 8 questions, I'll hand the presentation back to Angela.
9 Thank you so much.
10 MS. WU: Thank you, Louis. We're moving 11 on to Slide 15, the SLRA.
12 In conclusion, for the SLRA safety review, 13 the Staff finds the requirements of 10 CFR 54.29 14 (telephonic interference) substantive license renewal 15 for Units 1 and 2. We'll hear from Dr. Allen Hiser 16 (telephonic interference) the evaluation of the 17 differing views. Slide 16.
18 MR. HISER: Thank you, Angela. And good 19 morning. My name is Allen Hiser, I'm with the 20 division of new and renewed licensee (telephonic 21 interference) NRC.
22 Differing views focused on the treatment 23 in the subsequent license renewal application of the 24 July 2019 fire pipe rupture. Along with several other 25 issues.
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59 1 The evaluation of the differing views 2 concluded that reliance on the Applicant's corrective 3 action program is consistent with placing renewal 4 safety principles. Specifically that the ongoing 5 regulatory process is adequate to ensure plant safety.
6 In addition, other issues cited in the 7 differing views were adequately addressed in the 8 subsequent license renewal application. As a result, 9 the evaluation of the differing views, it was 10 concluded that no additional actions are necessary to 11 the aging management programs at this time, beyond 12 what the Applicant has supplemented as part of the 13 SLRA.
14 However, pending the outcome of the 15 Licensee's complete evaluation, the aging management 16 programs may or may not be revised in the future.
17 Further, this site safety evaluation report adequately 18 reflects the basis for a reasonable assurance finding 19 if the Applicant's program is adequate for the 20 subsequent period of extended operation and no changes 21 to the safety evaluation report are necessary based on 22 the evaluation of the differing views.
23 Thus, the subsequent renewed license can 24 be issued consistent with 10 CFR Part 54. And with 25 that, Angela, I'll turn it back to you.
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60 1 MEMBER BALLINGER: This is Ron Ballinger, 2 I have a question about this. After reading the two 3 versions of the DPO, is it my understanding that there 4 still exists the difference of opinion?
5 MR. MOORE: This is Scott Moore, may I 6 come in for a minute?
7 This slide on use of the term, differing 8 views, does that indicate that with regard to any 9 formal agency processes that the agency, any agency 10 processes are not yet completed?
11 MS. BRADFORD: So this is Anna Bradford, 12 I'm the director of the division of new and renewed 13 licenses. Let me explain a little bit.
14 So, we do have two different (telephonic 15 interference) process. And this was the 16 nonconcurrence process (telephonic interference) DPO 17 process (telephonic interference).
18 So, these were post, run through the 19 nonconcurrence process. They are currently closed in 20 terms of nonconcurrences were filed, the process was 21 followed (telephonic interference) nonconcurrence, 22 which is all included in the paper, and no changes 23 were made to the SE as a result. So that's kind of 24 how the nonconcurrence was closed.
25 So as of right now, there is no, I'll call NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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61 1 them open differing views, in terms of the process.
2 Now, if the staff was not satisfied with where we 3 ended up they could go to the next process, which is 4 the DPO.
5 So, for right now this is, process-wise, 6 this is considered closed.
7 MEMBER BALLINGER: Now, I apologize for 8 using the word DPO, I should have used the word 9 nonconcurrence. Thank you.
10 MS. BRADFORD: Sure.
11 CHAIRMAN SUNSERI: Any other comments, or 12 questions I should say, from the Members?
13 MEMBER KIRCHNER: Yes. This is Walt 14 Kirchner. Matt, I'm looking at my notes from the 15 February presentations and I note one of the issues 16 that came up during the discussion of the differing 17 views was corrosion of tie rods.
18 So, I just wanted to ask how that 19 particular item was being addressed. Much like I 20 asked about the replacement piping.
21 MR. HISER: This is Allen Hiser, the Staff 22 again. Let's see. A corrective action assessment 23 that supports piping replacement should also ensure 24 that the necessary associated elements, such as the 25 tie rods, will continue to serve their necessary NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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62 1 design function to support the piping.
2 That was the conclusion in the 3 nonconcurrence evaluation. My understanding is that 4 that would be subject to the oversight process as 5 well. They (telephonic interference) implemented 6 appropriately.
7 MEMBER KIRCHNER: Thank you.
8 MS. WU: Do we have any additional 9 questions at this time? Hearing none, I turn the 10 presentation back to you, Chairman Sunseri.
11 CHAIRMAN SUNSERI: Thank you, Angela, and 12 thanks to your staff for a nice presentation.
13 At this point I'd like to, this is a 14 little awkward but we would normally ask for public 15 comments from members in the room, or of the public in 16 the room, so I will break this up into two parts.
17 I'll break it up for members of the public 18 participating in the on the phone line. So, at this 19 point are there any, is there anybody on the Skype 20 session that would like to make a comment?
21 And while we're waiting, if I can ask 22 Thomas to open the public phone line too.
23 PARTICIPANT: Copy that.
24 CHAIRMAN SUNSERI: Okay, there is no 25 comments coming in from Skype. So Thomas, just NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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63 1 confirm when you have the public line open. Can you 2 hear me, Thomas?
3 PARTICIPANT: Yes, loud and clear.
4 CHAIRMAN SUNSERI: Do we have the public 5 line open? Bridge line. Let me try it this way.
6 PARTICIPANT: We are unmuted.
7 CHAIRMAN SUNSERI: You are unmuted now?
8 PARTICIPANT: That is correct.
9 CHAIRMAN SUNSERI: Okay. If there are any 10 members of the public on the public bridge line and 11 you wish to make a statement or provide a comment, 12 please do so now.
13 Could anyone on the public line at least 14 acknowledge by saying something that the line is open?
15 PARTICIPANT: The line is open.
16 (Simultaneous speaking.)
17 PARTICIPANT: -- public line.
18 CHAIRMAN SUNSERI: Okay. So one more 19 opportunity for members on the public line to make a 20 comment. Okay, Thomas, we can close the public line.
21 At this point on our agenda I would like to go into 22 report preparation. (Telephonic interference) report.
23 We will need some transition time to do 24 that so I'm going to call for a ten minute break at 25 this time to allow us to transition to the report NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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64 1 preparation phase. And we will resume, let's call it 2 about, let's call it 25 before the hour. So, 25 3 before the hour we will resume with report 4 preparation. We are recessed until then.
5 (Whereupon, the above-entitled matter went 6 off the record at 10:23 a.m. and resumed at 1:02 p.m.)
7 CHAIRMAN SUNSERI: All right. 1302, we 8 are reconvening the full committee meeting. I will 9 begin with a roll call of the members. Members, 10 please acknowledge when I call your name. Ron 11 Ballinger?
12 MEMBER BALLINGER: I'm here.
13 CHAIRMAN SUNSERI: Dennis Bley?
14 MEMBER BLEY: Here.
15 CHAIRMAN SUNSERI: Charles Brown has 16 acknowledged already. Vesna Dimitrijevic?
17 MEMBER DIMITRIJEVIC: I'm here.
18 CHAIRMAN SUNSERI: Walt Kirchner?
19 MEMBER KIRCHNER: Here, Matt.
20 CHAIRMAN SUNSERI: Jose March-Leuba?
21 MEMBER MARCH-LEUBA: Present.
22 CHAIRMAN SUNSERI: Dave Petti?
23 MEMBER PETTI: Present.
24 CHAIRMAN SUNSERI: Joy Rempe?
25 VICE CHAIR REMPE: Present.
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65 1 CHAIRMAN SUNSERI: Pete Riccardella? Pete 2 Riccardella? I see he's on but muted his mic. Can 3 you unmute your mic? Are you there? All right, 4 Quinn, can you try to reach out to Pete?
5 I'm Matt Sunseri, I'm here. We have a 6 forum. We have one member who looks like might be 7 stuck.
8 At this point we will proceed with the 9 meeting. The item for this afternoon is NuScale 10 Chapter 15, Boron Dilution, Return to Criticality, 11 Probabilistic Risk Analysis and Hydrogen Oxygen 12 Monitoring.
13 Walt Kirchner will lead this session. And 14 at this point, I will turn it over to Walt for any 15 remarks and get this session moving. Thank you.
16 MEMBER KIRCHNER: Thank you, Chairman. I 17 have no further remarks to make so I think --
18 AUTOMATED MESSAGE: You've been muted. To 19 unmute yourself press *6.
20 MEMBER KIRCHNER: -- and I'll turn to 21 Matthew Presson.
22 MR. PRESSON: Thank you, Walt, I 23 appreciate it. And I appreciate everyone's time this 24 afternoon.
25 I'm Matthew Presson with NuScale and today NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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66 1 we'll be talking about, we'll have a couple 2 presentations, but this first presentation is on 3 Chapter 15 and its related topics.
4 Moving to Slide 2. Our presenters for 5 today are myself, Matthew Presson, licensing project 6 manager. We also have Ben Bristol, supervisor of 7 system thermal hydraulics. Meghan McCloskey, thermal 8 hydraulic analyst. And Paul Infanger, licensing 9 specialist.
10 I'll be the primary presenter to keep this 11 tele-presentation simple, but if there are any 12 questions this will be our primary discussees.
13 Slide 3 covers our agenda. We will be 14 discussing our principle design criteria, 27, boron 15 transport. As well as changes from the FSAR Revision 16 2 to FSAR Revision 4.
17 Which incorporates a couple of items. Our 18 NRELAP5 updates, minor module model updates, DHRS 19 actuation logic changes, as well as overall changes in 20 Chapter 15 analysis results.
21 All right. Moving to Slide 4. Kind of a 22 background on our PDC 27. Principle Design Criteria 23 27.
24 So, the NuScale DCBA includes an exemption 25 request from GDC 27, the NuScale power modes goal NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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67 1 design aligns with precedent based compliance, or GDC 2 27, due to the lack of a second safety related 3 reactivity control system.
4 So, to cover that we follow a principle 5 design criteria 27. It is our passive equivalent for 6 GDC 27. It ensures that safety related reactivity 7 control system is designed to achieve and maintain a 8 sub-critical core and ensures fuel integrity for an 9 extended overcooling in combination with a partial 10 failure of a reactivity system. Such as a stuck rod.
11 CHAIRMAN SUNSERI: Hey, Matt, let me 12 interrupt you for just a second.
13 MR. PRESSON: Yes.
14 CHAIRMAN SUNSERI: Will all participants 15 that are not speaking please mute your mic. There is 16 background noise that come over these very sensitive 17 microphones, so disrupt, please mute your lines if 18 you're not talking.
19 Thanks, Matt, you can continue.
20 MR. PRESSON: All right, I appreciate it.
21 Moving on to Slide 5. We discuss a little bit of our 22 compliance with this principle design criteria.
23 Before that, our immediate shutdown is 24 sufficient to protect the reactor coolant pressure 25 boundary as well as SAFDLs with March included for the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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68 1 worst rod stuck out of the core.
2 Cold shutdown is achieved with all control 3 rods fully inserted. And if there were to be an issue 4 with that, for example, having that worst rod stuck 5 out.
6 So, also shutdown marching consequences 7 are fairly benign. They were evaluated with the 8 single-highest worst control rod, fully worst control 9 rod and the critical power level does not challenge 10 either our DHRS or ECCS heat removal systems or 11 SAFDLs.
12 In addition to that, the probability of 13 the accommodation of commissions which would result in 14 this loss of shutdown, return to power with a single 15 rod stuck out of the core is very small.
16 Slide 6.
17 MEMBER KIRCHNER: Matthew? This is Walt.
18 MR. PRESSON: Yes.
19 MEMBER KIRCHNER: When you say very small, 20 had you quantified that number in any, or at least can 21 you provide an order of magnitude estimate of what you 22 call very small in your sense?
23 MR. PRESSON: Yes. Ben Bristol, would you 24 be about to speak to that number precisely? I do not 25 have it off the top of my head.
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69 1 Or we can get back to that. It is 2 described in the FSAR Chapter 15. So once we, someone 3 has the time to grab that, I can get back to you with 4 that number.
5 MEMBER KIRCHNER: Thank you.
6 MR. PRESSON: Yes.
7 MEMBER KIRCHNER: Matthew, I was just more 8 interested in you entering that into the transcript on 9 the public record.
10 MR. PRESSON: Yes, absolutely. And once 11 we have the time to get that exact number for you I'm 12 more than happy to get that on the record.
13 All right, Slide 6 covers the results for 14 that return to power analysis. Our ECCS tooling is 15 most limiting when, sorry, we are most challenged with 16 ECCS cooling with an equilibrium power limited to 17 around one to two percent of reactor power. So that 18 is the highest that we would expect to see.
19 Our core temperatures must be less than 20 200 degrees Fahrenheit for re-criticality. So you 21 have to be fairly cold.
22 And with increasing cold temperatures we 23 see a decrease in the magnitude of that return to 24 power with a 140 degree Fahrenheit pool precluding a 25 re-criticality. Even in the Chapter 15 scenarios.
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70 1 For NuScale calculations the earliest re-2 criticality determined, could occur approximately 40 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> post-scram. Our minimum CHFR for the most 4 limiting results are not limiting relative to our 5 other FSAR events. Our other Chapter 15 events.
6 All other AOO acceptance criteria are met 7 and our other SAFDLs are demonstrated with the 8 overcooling return to power conditions. And they are 9 bounded by existing analyses developed for the DCA.
10 And to get back to that value, FSAR 1506 11 cites that probability of this occurring as being less 12 than 1e to the negative 6 per reactor year.
13 MEMBER KIRCHNER: Thank you.
14 MR. PRESSON: Yes. All right, and that 15 is, that wraps up our summary on GDC 27. Are there 16 any questions before we move onto boron 17 transportation?
18 All right.
19 MR. SNODDERLY: I'm sorry, Matthew. This 20 is Mike Snodderly. If I could just interrupt for one 21 second.
22 I understand from members of the public 23 that the public bridge line is not working. So, if 24 Thomas can confirm that we're hooked up to that and we 25 could troubleshoot that. Thank you.
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71 1 MR. PRESSON: Got you. Yes, that's a good 2 point to pause for that.
3 MR. SNODDERLY: Perhaps if I could ask, 4 Thomas, could you please open the public bridge line 5 and let's ask if there is anyone from the public on 6 there and see if that's working?
7 MS. FIELDS: Oh hi. That was probably my 8 error. This is Sarah Fields calling in. When I put 9 in the wrong connection number, so yes, the bridge 10 line does work.
11 MR. SNODDERLY: Okay, thank you. Thank 12 you, Sarah, we just wanted to make sure. So, Thomas, 13 if you could please mute the public bridge line. And, 14 Matthew Presson, please continue. Thank you.
15 MR. NGUYEN: Done.
16 MR. PRESSON: Sounds good. And I 17 appreciate it.
18 All right. So, starting on Slide 7. Our 19 ECCS boron transportation. A little bit of context 20 for our boron transport analysis.
21 So, as boron accumulates within the core 22 and rides a region, the boron concentration in 23 containment and downcomer decreases. This is based on 24 a scenario where ECCS is already actuated, so you have 25 water in the containment, downcomer and core riser NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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72 1 areas.
2 Boron precipitation analysis was performed 3 as part of the ECCS long-term cooling analysis and 4 determined that it was not a concern for the MBM.
5 Boron dilution analysis was performed to 6 evaluate a potential for a lower boron concentration 7 fluid in core or near the core inlet. So basically 8 we're looking to ensure that for the, for any of the 9 analyses that we're performing that boron 10 concentration does not decrease within the core or 11 riser region.
12 We are also looking to confirm the 13 appropriate step, return to power analysis, by 14 demonstrating that this core region concentration 15 remains above that initial concentration. And the 16 full details on that analysis are provided in the 17 NuScale response to RAI-8930. With the bulk of that 18 being in supplement to that response.
19 Boron transport is governed by boiling in 20 the core. And condensation within the containment 21 vessel.
22 All right, Slide 8 goes into a little bit 23 of our method. So, our summary for dilution analysis, 24 our long-term cooling PERT had a higher ranked 25 phenomena of a second boron transport as evaluated.
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73 1 We used a control volume approach to 2 analyze the transport between those regions. That 3 core, downcomer and containment region.
4 NRELAP5 is used to provide logging fluid 5 masses and flow rates. Which we use as input for our 6 boron transport calculation. Volatility and 7 entrainment are calculated separately.
8 And this calculation is performed separate 9 from NRELAP5. And as part of that we conservatively 10 model the transport between those regions. We use 11 those factors to minimize the boron transport into the 12 core and maximize boron transport out of that core hot 13 region so that we show as little boron flowing into 14 the core as we can.
15 And we demonstrate that, that RCS hot 16 region concentration remains above the initial 17 concentration.
18 Heat areas for NRC review are looking into 19 the treatment of boron volatility. As well as mixing 20 within the core, downcomer and containment. So we 21 have some additional discussion of that provided for 22 in our closed session slides.
23 The results for our CCA analyses focus on 24 boron transport evaluation during ECCS cooling. Those 25 results are summarized in RAI-8930. And they show NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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74 1 that our core boron concentration does remain above 2 that initial concentration. So no net core boron 3 dilution is expected, even with those biased transport 4 assumptions.
5 So, a more realistic analysis of that 6 boron transport indicates that our concentrations in 7 the core region are two to three times above the 8 initial concentration at 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> and that they can 9 see turning above initial concentrations for at least 10 seven days.
11 So, realistically, long-term high boron 12 concentration is expected to be seen within that RCS 13 hot region with a low concentration in the RCS cold 14 region and containment as that boron transports into 15 the core.
16 To address some concerns that were brought 17 up. When we do look to recover posts in ECCS 18 actuation or DHRS actuation, when we move back to, 19 towards node 3 or some other defined node, it does 20 take multiple deliberate operator actions following 21 the appropriate procedures.
22 Part of that is shown, it would be a 23 deliberate choice with a lot of steps along the way to 24 make sure that no errors were made. And procedures 25 are developed on a site-specific basis for that NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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75 1 recovery time period. Which are laid out in the NRC 2 law commitments, 13.5-2 and 13.5-7.
3 MEMBER MARCH-LEUBA: Yes, this is Jose.
4 MEMBER KIRCHNER: Matthew? Jose, you want 5 to go, go first, Jose.
6 MEMBER MARCH-LEUBA: It's okay, you can.
7 I can wait. Go for it.
8 MEMBER KIRCHNER: I am curious, Matthew, 9 why you say site specific basis. Why wouldn't these 10 be generic?
11 MR. PRESSON: So, they are not generic 12 because the DOL controls and procedures for that 13 applicant would be the one who --
14 MEMBER KIRCHNER: No, I understand that, 15 but what I don't understand is why, at this juncture, 16 you can't define a path to recovery that has nothing 17 to do with the site.
18 MR. PRESSON: Yes. So we can do that.
19 And we have looked at that to make sure that we 20 understand what kind of reactions you would be looking 21 at and would be taking. It's just that we would not 22 be forcing that specific procedure.
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76 1 attention to during recovery.
2 MEMBER KIRCHNER: So this feels more to me 3 like a tech spec issue than it does a procedure issue.
4 I mean, and then the procedure to implement makes sure 5 you don't violate tech specs, but.
6 I mean, this is something that's more 7 within the reactor vendor, NuScale's purview than 8 necessarily just site developed operating procedures.
9 MR. PRESSON: Yes.
10 MR. BRISTOL: This is Ben Bristol, can you 11 hear me?
12 MEMBER KIRCHNER: Yes.
13 MR. BRISTOL: This is Ben Bristol with 14 NuScale. I think what we were trying to allude to 15 there is the specifics about numbering schemes are 16 real plant specific processes that would go into 17 writing that procedure.
18 In general, the recovery action I think 19 could be written generically. And certainly, the 20 acknowledgments of demonstrating that shutdown margin 21 is reached would be part of exiting any LP into, back 22 into normal operation modes.
23 And I think what we're trying to do 24 address there is the specific system designs and 25 latent schemes that may be plant specific.
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77 1 MEMBER KIRCHNER: And that I understand, 2 but I think the general approach to successfully 3 recovering and establishing Mode 3 would, in my mind, 4 be a generic one given the MBM design.
5 MR. BRISTOL: Understood.
6 VICE CHAIR REMPE: Well, wasn't it Matthew 7 you said, guidance will be provided? Where is that 8 guidance? Is it part of the DCA submittal?
9 MR. PRESSON: It is not part of the DCA 10 submittal. It would likely be captured in GTGs or 11 some other guidance. Again, assuming an applicant 12 came to NuScale. That is the other fun little nuance 13 there. Assuming that they --
14 MEMBER MARCH-LEUBA: This is Jose. You 15 mentioned the GTGs, generic technical guidelines. Are 16 those not part of the submittal?
17 MR. PRESSON: They were provided as part 18 of the submittal to, and I was not part of that so I'm 19 not one to speak --
20 MEMBER MARCH-LEUBA: Yes, I --
21 MR. PRESSON: -- but, yes, they were 22 looked at. They were provided to show that we 23 understood what the format of those would look like 24 and what we would want to provide at the fuel up 25 stage, but they were not reviewed and approved as part NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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78 1 of DCA.
2 MEMBER MARCH-LEUBA: Yes. I guess what 3 we're trying to say is even the really bad 4 consequences of doing it wrong, which is also why this 5 is not covered on the GTGs, or whatever you want to 6 cover it.
7 But it is kind of assumed that the field 8 applicant will do it right. It really, as I say in 9 the Subcommittee, the cat is out of the bag, or 10 however the expression goes, and nobody is going to 11 forget to do this right. Okay.
12 But you really should (telephonic 13 interference) saying, hey, go into Mode 3 requirement, 14 making sure you don't, I mean, you know what they 15 mean, it used to do that.
16 MR. PRESSON: Yes, I understand that 17 point. And again, as if not a reviewed and approved 18 document that is, even if we did add them it would not 19 necessarily provide anything more at the DCA stage.
20 But your point on providing that guidance, making sure 21 that that is out there for people to use is taken and 22 understood.
23 MEMBER MARCH-LEUBA: Yes.
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79 1 engineering, about errors of co-mission. And clearly 2 this is something you want to prevent. And so, you 3 were, as Jose is saying and the GTGs are, wherever is 4 the appropriate vehicle, this is something that should 5 be clearly spelled out.
6 MR. PRESSON: Yes. And let me move to the 7 next slide. Slide 10. Which covers a bit of an 8 update regarding our commission report that we were 9 looking at.
10 I will say that figuring out the best way 11 to describe that need for an action is being 12 considered within this overall response. So figuring 13 out how to place that meaningfully within the DCA 14 space we are looking into that. And we are working 15 with the NRC to make sure that that fits and is 16 captured and does still work within that DCA space.
17 MEMBER MARCH-LEUBA: Okay. I have to be 18 careful --
19 MR. PRESSON: So, it's a little bit of 20 ongoing work, but -- Yes.
21 MEMBER MARCH-LEUBA: I have to be careful, 22 Matt, because I have read the proprietary 23 presentation, but here you do mention the design 24 change in the last bullet.
25 MR. PRESSON: Yes.
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80 1 MEMBER MARCH-LEUBA: Is there something 2 that you can put on the record, on the open session, 3 about what the design change is and what is the 4 schedule?
5 Because it's likely it won't affect, and 6 this is what ACRS has done in potential letters. I 7 mean, the dates I'm seeing there may affect our 8 timeline.
9 But is there something you can put on the 10 record, on the open session, about this?
11 MR. PRESSON: Yes. I can say that we are, 12 we are implementing a design change for the DPA, FSAR 13 in regards to ECCS actuation.
14 So we are working through that. That is 15 an in-process design change that is looking to actuate 16 ECCS earlier in order to preclude the conditions that 17 we identified back in March.
18 In terms of schedule, I am not sure what 19 is in-prop and what is a non-prop space, but we are 20 looking at a schedule sometime in May, to get that 21 back to you. I can at least say that much.
22 MEMBER MARCH-LEUBA: Okay, thank you. I 23 just wanted you to say something in the record.
24 MR. PRESSON: Yes.
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81 1 Nelson, manager of license with NuScale. So we did 2 have a scheduling commission in closed session, and I 3 think Matthew characterized it correctly.
4 As the work with the DCA changes we will 5 work with the staff and the ACRS regarding downstream 6 schedule. So we'll be getting back to you fully on 7 that so you can make an effort by case. That's all, 8 thanks.
9 MR. PRESSON: Yes. But we did want to 10 include this in the open session to discuss because it 11 is, you know, it is an update to the design that we 12 are working on so we wanted to make sure that was 13 available for public discussion.
14 MEMBER MARCH-LEUBA: So, let me put also 15 something on the open record. I have looked at the 16 proprietary record, which I cannot tell you about, but 17 I like the changes and I think it speaks, very likely, 18 to fix the problem.
19 But we're eagerly waiting all those 20 calculations to assure that it did address, okay. But 21 in principle I like the modification. It makes sense.
22 MR. NELSON: So, to confirm that you will 23 be talking about it in the closed session? The design 24 changes.
25 MR. PRESSON: Correct.
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82 1 MEMBER MARCH-LEUBA: Yes.
2 MR. PRESSON: We will discuss those.
3 MR. NELSON: Okay, got you.
4 MEMBER MARCH-LEUBA: Yes. But I wanted to 5 put in the record for the public that we have reviewed 6 it. We have access to the proprietary information.
7 In my opinion, it fixes the problem.
8 MR. PRESSON: Yes. And all that 9 information will be going into the public record once 10 it is finalized and approved. And all that is simply 11 in process at this point in time.
12 MEMBER BLEY: Excuse me, this is Dennis 13 Bley. I lost my line for the middle of that 14 discussion. This is the design change, it will be 15 incorporated before the design cert application is 16 approved, is that right?
17 MR. PRESSON: Correct. We did feel that 18 it was important to include this within the DCA.
19 MEMBER BLEY: Okay.
20 MR. PRESSON: So I wanted to get that in.
21 Yes. All right, any other questions for Slide 10.
22 Okay.
23 Okay. Moving on to Slide 11. Our 24 conclusions for boron transport is that a lot of the 25 inherent design characteristics within the MPM NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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83 1 provides ample safety.
2 We have low core power, we have a large 3 RCS inventory. We have a small high-pressure 4 containment and a large ultimate heat sink.
5 Compliance with in sent of GDC is 6 demonstrated for reactivity control systems. We 7 provide conservative analysis of low probability of 8 return to power condition. And that analysis 9 demonstrates some of that safety margin.
10 MEMBER MARCH-LEUBA: My, sorry to 11 interrupt. Can you move the slide to Slide 11?
12 Because we don't turn them.
13 MR. PRESSON: Got you. It is --
14 MEMBER MARCH-LEUBA: You're talking about 15 11.
16 MR. PRESSON: Yes.
17 MEMBER MARCH-LEUBA: My scale is frozen 18 then, sorry.
19 MR. PRESSON: Yes. Let me re-present 20 that. See if that fixes it. I've seen several other 21 people who have that. All right, it should be 22 presenting Slide 11 now.
23 MEMBER MARCH-LEUBA: I can see my Slide 24 11.
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84 1 on the second bullet. Our compliance with the intent 2 of GTCs is demonstrated for reactivity control systems 3 by showing that the conservative analyses are low 4 probability, return to power conditions filled in the 5 safety margin.
6 And for that last bullet, boron 7 redistribution is reevaluated and demonstrated to not 8 be a safety topic. We naturally accumulate boron 9 within the core. It adds to shutdown margin for 10 design basis events as well as severe accidents.
11 Moving on to Slide 12. This kind of 12 begins our section discussing Chapter 15 changes from 13 FSAR Revision 2 to Revision 4.
14 Revision 2 was the FSAR revision that the 15 NRC right there, Chapter 15 Phase 2, I see against.
16 And Revision 4 is the revision that we submitted in 17 December.
18 And kind of following along with that, the 19 results from FSAR Revision 2 were presented to ACRS in 20 June and July of 2019 in subcommittee and full 21 committee meetings.
22 Changes from that to FSAR Revision 3 23 included an update from NRELAP Version 1.3 to Version 24 1.4. It also updated the NRLEP5 base model input.
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85 1 placed in some cases. Our THRS actuation signal saw 2 not a large effect of change but the details of how it 3 actuated were changed via the addition of a secondary 4 side isolation signal. And ECCS actuation signals 5 were changed.
6 And changes in Rev 4 were primarily 7 focused on ECCS IAB threshold and release pressure 8 changes.
9 Slide 13 covers our NRELP5 Version 1.4.
10 As we went from 1.3 to 1.4 a lot of those changes were 11 made due to routine code maintenance.
12 We had 26 specific code fixes, which are 13 documented with the three most notable being a 14 condensation correlation error correction, a 15 correction to the choking model quality factor as well 16 as updating the executable to 64-bit.
17 We also added five new features, none of 18 which impact DCA calculations. Including proprietary 19 classifications, expand a number of elements allowed 20 on the water property file and circulation update for 21 CHF correlation.
22 Adding a warning message to users. If the 23 math error stop one percent is disabled and removal of 24 developmental options from user access.
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86 1 included, well, Jeff says that overall Revision 0 was 2 released in December of 2015, Revision 1 was released 3 in August of 2017 and Revision 2 was released in 4 January of 2019. So that Revision 2 was associated 5 with the FSAR Revision 3 submittal.
6 It removed the ECCS actuation on the RCS 7 riser level signal as well as minor RCS flow loss 8 updates. And a couple of minor geometry error 9 connections.
10 For Revision 3, the DHRS actuation changes 11 probably drove most of the changes we saw in Chapter 12 15. A summary of that change is that we added a 13 secondary side isolation actuation for a range of 14 signals that indicate upset and normal secondary side 15 cooling conditions.
16 And then we took the DHRS signal and had 17 that actuation limited to a subset of those signals, 18 which indicated insufficient secondary site cooling.
19 So DHRS now actuates the following secondary side 20 isolation.
21 The purpose of that change was to support 22 expected plant startup progressions. And the effect 23 of that change on the transient analyses was that heat 24 up events, no change was expected to DHRS, actuations 25 on high pressure, pressurizer pressure or high RCS hot NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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87 1 temperature.
2 For cool down events our secondary side 3 isolation may be actuated first with the ACRS then 4 actuating afterwards on high steam pressure. And for 5 reactivity events, inventory increase and inventory 6 decrease events, we did not see them significantly 7 impacted.
8 So, conclusions overall from our summary 9 presentation today, our revised return to power 10 analyses shows the ECCS cooling conditions result in 11 the equilibrium power, at most, around one to two 12 percent.
13 ECCS boron transport analysis demonstrates 14 that core boron concentration remains higher than 15 initial concentration. And that will be maintained 16 with the new design change.
17 Changes incorporated into FSAR Revision 3 18 included minor changes to NRELAP5 code. And the MPM 19 plant base model as well as DHRS and ECCS actuation 20 changes.
21 IAB changes were incorporated into FSAR 22 Revision 4, which opened up the range of the IAB. And 23 the Chapter 15 limiting transient events were 24 consistent between Revision 2 and Revision 4.
25 And the overall summary is that Chapter 15 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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88 1 for our DCA shows that we demonstrate margin to all of 2 our acceptance criteria.
3 Slide 17 is an acronyms page. And Slide 4 18 is just a little closing. Any questions for 5 Chapter 15?
6 MR. NELSON: This is Mike Nelson with 7 NuScale. Just one clarifying note.
8 We did present scheduling information in 9 public slides, in a public meeting with the NRC. So 10 it is on the record back on April 1st, which wasn't 11 that long ago.
12 So we do have scheduling information 13 there. I added a follow-up transient (telephonic 14 interference) DCA for (telephonic interference). So 15 I wanted to make sure I clarified that. Thanks.
16 MR. PRESSON: Okay, thanks, Mike.
17 MEMBER KIRCHNER: Is there any further 18 questions from Members?
19 Matthew, I'm not hearing any further 20 questions from Members so we can transition to the 21 next NuScale presentation.
22 MR. PRESSON: All right, that it sounds 23 good. All right, I believe that is Jim Osborn. Feel 24 free to correct me if I'm wrong?
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89 1 correct, Matthew.
2 MR. PRESSON: Okay, let me stop presenting 3 and you should be able to press the presentation.
4 MR. OSBORN: All right, let me know if you 5 can see the presentation?
6 VICE CHAIR REMPE: It's on.
7 MR. OSBORN: I'm sorry?
8 VICE CHAIR REMPE: We can see it.
9 MEMBER KIRCHNER: Jim, this is Walt 10 Kirchner, it's showing.
11 MR. OSBORN: Okay, good. Good.
12 MEMBER KIRCHNER: Please proceed.
13 MR. OSBORN: All right, so, this is the 14 full committee presentation having to do with the 15 hydrogen and oxygen monitoring topic. The presenters 16 are listed as Matthew and myself, Jim Osborn.
17 So this will be a very brief presentation.
18 We're just providing a summary of what we presented in 19 the subcommittee.
20 So, this is my summary and conclusion 21 slide from the subcommittee meeting. You might 22 recognize it a lot.
23 But it's, you know, NuScale has not 24 changed any of its positions since the subcommittee 25 meeting. So, as a recap of the presentation in the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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90 1 subcommittee we first discussed the overall paradigm 2 of actual amounts as it relates to differences between 3 design basis and beyond design accidents.
4 And the rules that the industry applies as 5 it relates to accident mitigation. So, and we talked 6 about how non-safety SSCs can be used and credited for 7 mitigation of beyond design basis accidents, but not 8 for design basis accidents in general.
9 We also explained that the low frequency 10 of the NuScale core damage accident is due to the fact 11 that it requires multiple failures of safety and non-12 safety related equipment. For example, some sequences 13 involve multiple failures involving highly reliable DC 14 power system in conjunction with multiple failures of 15 the safety related ECCS, EPCS system.
16 So, second, we discussed the timing 17 aspects of combustible gases inside containment. And 18 then a bounding analysis shows that there is a minimum 19 of 72 hours before detrimental combustible gas 20 mixture, remember, detrimental means a gas mixture 21 that could result in containment failure.
22 And then third, we discussed the risk-23 informed decision process in which operators would 24 utilize in taking the hydrogen monitoring system into 25 service.
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91 1 We discussed that there is sufficient time 2 for the operators to inspect and verify that the 3 hydrogen monitoring system is indeed intact and 4 available for use. And if the system does develop a 5 leak, the operator must isolate the system and repair 6 as needed.
7 Regarding the radiation protection, the 8 NRC stated there is insufficient design information to 9 perform a offsite dose analysis or operator dose 10 analysis from the leaking monitoring system and 11 therefore created a card valve so that this topic can 12 be resolved in a future date.
13 And then we discussed the hydrogen 14 monitoring pathway is capable of withstanding a 15 combustion event, like the containment is.
16 And then lastly we talked about 17 containment mixing and ensuring that we have 18 representative monitoring. And that NuScale and the 19 Staff agree that we accounted for this.
20 MEMBER MARCH-LEUBA: You just mentioned 21 that the piping can withstand an explosion, the same 22 as a containment. Is that the requirement? Is that 23 specified in the DCA?
24 MR. OSBORN: So yes. The monitoring 25 pathway, the valve side containment, the pressure NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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92 1 boundary is required to, and this is stated in the 2 DCA, that it has to withstand a combustion event just 3 like containment does.
4 MEMBER MARCH-LEUBA: Okay. And you can 5 specify in DCA?
6 MR. OSBORN: It is specified in Table, DCA 7 Table 3.2-1.
8 MEMBER MARCH-LEUBA: Perfect. That's what 9 I was looking for. Thank you.
10 MR. OSBORN: Yes, sir.
11 MEMBER MARCH-LEUBA: Now while I have, I 12 have the microphone on, I'm primary concern with the 13 way we are doing it is being able to obtain a 14 representative something, this is your last bullet, on 15 that piping.
16 To do that you will have to establish flow 17 on that pipe. A non-tribute flow. And just something 18 not liking to establish sufficient flow.
19 So, you something that has to be able to 20 withstand the coordination, it has to work.
21 MR. OSBORN: Sure.
22 MEMBER MARCH-LEUBA: I don't see anywhere, 23 any requirement that says it must work. That would be 24 my complaint for months now.
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93 1 subcommittee that we do committee to, what was it, 2 ANSI 13.1. That number may not be right, but there is 3 an ANSI standard that we are committee to that 4 requires that the monitoring and sampling that we do 5 be representative. And so, that will, that is 6 required.
7 And if, you know, so the system will have 8 to do that. I mean, that's just a, that's a 9 requirement that we have stated in the FSAR.
10 MEMBER MARCH-LEUBA: I can design one that 11 works. It will require an addition pump to start this 12 flow through the pipe.
13 And the (telephonic interference) that you 14 are going to be, that's only opening in containment, 15 but you're circulating the containment atmosphere 16 through the extent of a pipe (telephonic 17 interference). That's my complaint, okay.
18 To make it work, you have to circulate the 19 containment atmosphere through all this piping. You 20 just, it doesn't look like a optimal solution. And 21 I'll stop there.
22 MEMBER KIRCHNER: Okay. And the other 23 concern, I think one of the other concerns we had, 24 Jim, was -- this is Walt Kirchner -- that the standard 25 reference is, really, isn't that for large bore stacks NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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94 1 sampling out of the, like in a fossil plant, from the 2 significant diameter chimney?
3 MEMBER BALLINGER: Yes.
4 MEMBER KIRCHNER: I don't know how, 5 quote/unquote, representative that is of the kind of 6 unique system and design that NuScale has.
7 MEMBER BALLINGER: Yes. This is Ron 8 Ballinger. Again, a number of us went out and got the 9 standard and read it. It's quite a stretch, quite a 10 stretch.
11 MR. OSBORN: So, this external hydrogen 12 monitoring system is not, I mean, that's -- we're not 13 the first to have that kind of system.
14 There are other plants in the country that 15 have a hydrogen -- either a recombiner or a hydrogen 16 monitoring system that is outside of containment and 17 takes (telephonic interference) and then, returns it 18 back to containment.
19 So, I'm not sure why this would be 20 different from any other similar design. And we've 21 employed, I can't remember the name of the company, 22 but we've employed or consulted with a company that 23 has done this kind of design for these systems across 24 the country.
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95 1 think if we've designed a system that doesn't work, 2 then we couldn't move forward, right? It has to be 3 representative, in my understanding.
4 MEMBER KIRCHNER: Members, any further 5 questions of Jim?
6 MR. OSBORN: So, I have one more slide.
7 MEMBER KIRCHNER: Go ahead, Jim.
8 MR. OSBORN: All right. So, relative to 9 the risk, NuScale has looked at various containment 10 bypass scenarios in Chapter 19.
11 And while we did not look specifically at 12 the risk of performing hydrogen monitoring, there is 13 an evaluation in Chapter 19 that looks at a 14 containment bypass event that involves a potential 15 failure, for example, of a containment evacuation 16 system isolation valve, the potential failure of that 17 that leads to a release.
18 So, this evaluation in Chapter 19 will 19 include the fuel coolant interaction event, which is 20 assumed to lead to a containment failure. In reality, 21 it does not actually lead to a containment failure, 22 but we looked at the consequences as if it did.
23 So, in this evaluation, the earliest 24 possible time that this event would occur and the 25 containment failure is assumed is at 6.8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> post-NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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96 1 accident.
2 So, the analysis shows that during this 3 6.8-hour period, there is sufficient deposition of the 4 airborne aerosols in the containment atmosphere that 5 the containment release through the bypass does not 6 amount to a large release.
7 So, to reiterate, the actual Chapter 19 8 analysis does not result in containment failure, but 9 we looked at the release as if it did.
10 And so, therefore, if the hydrogen 11 monitoring system breaks off completely, with a 12 containment isolation valve open, it is reasonable to 13 conclude that this release would not result in a large 14 release or threaten public safety. This is further 15 evidence, this is a scenario that is (telephonic 16 interference).
17 MEMBER MARCH-LEUBA: This is Jose again.
18 MEMBER KIRCHNER: The pressure in the 19 containment, what would the pressure be in the 20 containment at 6.8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />?
21 MR. OSBORN: So, well, again, so, they 22 wouldn't open the containment isolation unless the 23 pressure was below, I think it's 250 pounds. So --
24 MEMBER KIRCHNER: I think the concern would 25 be, if you have significant pressure and you NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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97 1 unisolate, then this fraction of volatile fission 2 product aerosols that could be swept out with the 3 blowdown of the containment.
4 MR. OSBORN: Well, so, I think that's the 5 point, that at 6.8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />, there's enough deposition of 6 that material that what is swept out does not 7 constitute a large release.
8 MEMBER KIRCHNER: So, the timing of a 9 release isn't a fuel coolant interaction? I'm a 10 little confused on what the scenario is there that 11 you're talking about.
12 MR. OSBORN: Yes. So, it's a fuel coolant 13 interaction, so you get a pressure pulse from steam 14 expansion, right? So, it's a large pressure event, 15 but -- and it doesn't result in containment failure.
16 However, we looked at it as if it did and at 6.8 17 hours1.967593e-4 days <br />0.00472 hours <br />2.810847e-5 weeks <br />6.4685e-6 months <br />, there was enough aerosol deposition that the 18 release did not constitute a large release from a risk 19 standpoint.
20 MEMBER KIRCHNER: Okay. So, a fuel coolant 21 interaction is really a mechanism of (telephonic 22 interference)?
23 COURT REPORTER: Hello, this is the court 24 reporter, I'm having difficulty understanding the 25 person who just spoke.
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98 1 CHAIRMAN SUNSERI: Yes, I'm having a hard 2 time hearing as well.
3 MEMBER KIRCHNER: The fuel coolant 4 interaction is just the means by which you transport 5 material from the reactor coil to the containment?
6 MR. OSBORN: Yes. It -- yes. Like I said, 7 we did not look at hydrogen monitoring failures, per 8 se, right?
9 So, we've drawn an analogy using this even 10 in Chapter 19 that shows that even if, in this coolant 11 interaction event, that it does not, the bypass would 12 not result in a large release. This is all intended 13 to address the -- we didn't look at the risk of 14 hydrogen monitoring failures.
15 MEMBER MARCH-LEUBA: This Chapter 19 event 16 that you described, the containment failure, typically 17 we would see take credit for the pool, that it will 18 release into the pool. Whereas, if the CES is the one 19 that fails, you would be releasing on the floor 20 upstairs. This analysis assumes that the proper 21 discharge path --
22 MR. OSBORN: Yes.
23 MEMBER MARCH-LEUBA: (Telephonic 24 interference.)
25 MR. OSBORN: Yes, no, I don't think the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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99 1 discharge from this containment bypass was released 2 under water, I think it was released above water.
3 MEMBER MARCH-LEUBA: Okay.
4 MR. OSBORN: Because that's where all the 5 containment isolation valves are. So that's all I 6 had, if there's any other questions?
7 MEMBER KIRCHNER: Members, any further 8 questions of Jim?
9 CHAIRMAN SUNSERI: Walt, this is Matt, I 10 don't have any questions.
11 MEMBER KIRCHNER: Any other members?
12 Hearing none, then, I think we can transition to the 13 next NuScale presentation. I think that will be PRA, 14 if I have that correct.
15 MS. NORRIS: This is Rebecca Norris. Yes, 16 that was the -- we are the next scheduled 17 presentation, PRA.
18 MEMBER KIRCHNER: Okay. Rebecca, as soon 19 as we have the slides up, then we can turn it over to 20 you.
21 CHAIRMAN SUNSERI: Okay. Walt, we've been 22 at this almost an hour, why don't we take a five-23 minute break here and reconvene at 14:00 Eastern 24 Daylight Time, if that's okay with you?
25 MEMBER KIRCHNER: Yes. Okay.
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100 1 CHAIRMAN SUNSERI: All right. We'll take 2 a short recess here, five-minute bio break, and we'll 3 resume at 14:00. Thank you.
4 (Whereupon, the above-entitled matter went 5 off the record at 1:55 p.m. and resumed at 2:00 p.m.)
6 MEMBER KIRCHNER: So, we're turning now to 7 Rebecca Norris and the topic is PRA.
8 MS. NORRIS: Yes, this is Rebecca Norris, 9 would you like me to begin?
10 MEMBER KIRCHNER: Yes, go ahead, Rebecca.
11 MS. NORRIS: All right, perfect. Good 12 afternoon. As he said, I am Rebecca Norris. I would 13 like to start by sincerely thanking everyone for still 14 giving us the opportunity to make these presentations.
15 I know this is a very complicated time and I hope 16 everyone is safe and healthy.
17 My presentation today is for the ACRS full 18 committee on the Phase 5 focus area, Probabilistic 19 Risk Assessment, or PRA. The PRA is integrated into 20 all concerns in a nuclear design and NuScale has 21 interacted with ACRS in numerous aspects as part of 22 the design certification process.
23 The primary topic remaining for ACRS 24 discussion is related to ECCS valve operation, as 25 indicated in our most recent ACRS interaction on the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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101 1 March subcommittee meeting. From that meeting, 2 NuScale identified two questions from the members that 3 we wish to follow up with additional information.
4 The PRA's perspective on the other topics 5 discussed today were discussed within those 6 presentations, but obviously, we have the support 7 personnel online, so if you need to ask questions, 8 then we are here to support them.
9 I am Rebecca Norris, Licensing Project 10 Manager for both PRA and for FSAR Chapter 6, which 11 covers the mechanical design of ECCS, or the emergency 12 core cooling system. Our expert on PRA to answer 13 technical questions is Sarah Bristol, NuScale's PRA 14 Supervisor.
15 We thought -- this is Slide 3, for those 16 who do not have access to the Skype video. We thought 17 we would begin this presentation with a history of 18 ACRS interactions in PRA to give context to our 19 meetings on ECCS valves and the risk assessment models 20 that we used on them. Note that a reference for the 21 presentation is used in those discussions is provided 22 in the parentheses.
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102 1 on this slide.
2 So, in 2018, we had a overview of the 3 NuScale PRA for selected members. This included 4 methods, quality processes, process feature, modeling, 5 human error, and multi-module risk.
6 In May through June of 2019, we had the 7 official DPA FSAR Chapter 19 subcommittee and full 8 committee. This covered multiple topics, including 9 the passive system reliability.
10 In July of last year, we also had a 11 special meeting in Corvallis with select ACRS members 12 that included multiple topics. And it was during our 13 testing of the ECCS valves, so we still owed some 14 followup on the final products in the ECCS valve 15 testing.
16 Between July 2019 and March of this year, 17 NuScale completed the intermediate round of testing, 18 and thus, the NRC staff was able to issue a Phase 4 19 Safety Evaluation Report with no open items.
20 And then, as mentioned before, in March of 21 this year, we had the subcommittee meeting on this 22 topic. This focused on ECCS operations.
23 The March subcommittee meeting covered the 24 following topics, ECCS mechanical configuration, the 25 valve and the inadvertent actuation block, or IAB, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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103 1 operation, the testing that had been completed so far 2 on the valve, the valve failure modes and probability, 3 the logic, including a sample of fault trees, and 4 also, a new sensitivity study completed to address 5 questions specific to these valves brought up by the 6 committee. This new sensitivity study evaluated the 7 impact of valve reliability on selected support 8 systems.
9 There were two outstanding questions from 10 the committee in the March meeting. One was an 11 inquiry on units in the sample fault tree, whether it 12 was per year, day, et cetera. This was per year, to 13 answer that question.
14 The other was a request for NuScale to 15 provide specific values for the auxiliary sensitivity 16 study listed in the last slide. The insights from our 17 sensitivity study are provided here.
18 If the committee would like additional 19 detailed discussion, NuScale is prepared to address 20 both of these questions in the closed session, because 21 much of the data is proprietary.
22 And that is all I have to present today.
23 Thank you for your time and please let us know if you 24 have any questions.
25 MEMBER KIRCHNER: I'll turn first to Vesna.
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104 1 Vesna, have you any questions of Rebecca?
2 MEMBER DIMITRIJEVIC: No, I'm good.
3 MEMBER KIRCHNER: Thank you. Any other 4 members?
5 CHAIRMAN SUNSERI: This is Matt. I don't 6 have any specific, but in the same interest of 7 getting, seeking our expert, does Dennis have any 8 specific comments or questions?
9 MEMBER BLEY: No, I don't, thanks.
10 MEMBER KIRCHNER: Well, then, Matthew, at 11 this point, then, I think we're ready to transition to 12 the staff presentations.
13 MR. SNODDERLY: Could we ask that Bruce 14 Bavol ask for control of the -- or share his desk 15 screen? Thank you.
16 MR. BAVOL: Yes, this is Bruce. I'll be 17 taking control here in a second. Mike, can you see 18 the slides?
19 MR. SNODDERLY: Yes, I can.
20 MR. BAVOL: Okay. If Jeff and Carl are 21 standing by, I'd like to begin?
22 MEMBER KIRCHNER: Go ahead. Go ahead, 23 Bruce.
24 MR. BAVOL: Thank you. Okay. My name is 25 Bruce Bavol, I'm a Project Manager for the Nuclear NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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105 1 Regulatory Commission. I'm currently reviewing, in 2 the process of reviewing, design certification for the 3 NuScale design.
4 On Slide 2, the agenda was reused from the 5 subcommittee, but what you're going to find out is 6 we've significantly condensed a lot of the discussion 7 and brung out the key points for the ACRS full 8 committee members.
9 Moving to Slide 3, the NRC staff team, 10 review team, there's a significant list of people who 11 were involved with the development and review of 12 Chapter 15. And today, though, the presenters will be 13 Jeff Schmidt, followed by Carl Thurston.
14 And I'd also like to mention the Branch 15 Chief overseeing this particular review, Becky Patton, 16 who is the Branch Chief for the Nuclear Method, 17 Systems, and New Reactors.
18 So, with that, I'd like to turn it over to 19 Jeff.
20 MR. SCHMIDT: All right, thank you, Bruce.
21 This is Jeff Schmidt, NRR Reactor Systems.
22 As Bruce mentioned, these are really just 23 condensed slides from the subcommittee. There are 24 some new slides and new material that we'll discuss 25 and I'll try to highlight those when I get to those NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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106 1 slides.
2 This is pretty much the subcommittee 3 slide, which was on the closure of unclear open items.
4 So, on July 10, 2019, the Phase 3 Chapter 15 ACRS 5 meeting discussed the status of the Chapter 15 review.
6 Out of that, we listed 11 unclear open 7 items. The following presentation kind of walks 8 through those open items. You'll see that usually in 9 parentheses as we go through. Some of the selected 10 Phase 2 OIs, or open items, are also included in this 11 presentation.
12 Some were not necessarily in the Chapter 13 15 subcommittee meeting, some were brought out in the 14 ACRS February 19, 2020, LOCA topical report meeting, 15 and that was the NRELAP Version 1.4, and also, Open 16 Item 1502-4, which was a open item related to the 17 steam generator heat transfer uncertainty. That was 18 discussed at the February 19, 2020 ACRS subcommittee 19 meeting on the non-LOCA topical report. Next slide, 20 Bruce.
21 So, this is Slide Number 5. Again, this 22 is from the subcommittee meeting, the return to power 23 and the exemption from GDC-27.
24 The staff took a position in the pre-25 application that reliably controlling reactivity in NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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107 1 GDC-27 means shutdown is the final end state, when 2 considering the totality of the NRC regulations 3 regarding reactivity control.
4 Following an initial shutdown, the NuScale 5 reactor can return to power and maintain criticality 6 during a cooldown on safety-related passive heat 7 removal systems, the decay heat removal system, and 8 the ECCS system, under certain conditions.
9 Staff drafted SECY-18-0099, which 10 established three return to power criteria, to ensure 11 public health and safety. And these are summarized 12 below.
13 SAFDLs are met upon a return to power.
14 Return to power is not expected to occur in the 15 lifetime of the module. And the incremental risk from 16 the multi-module of the site does not impact 17 Commission's goals related to frequencies of core 18 damage or large releases.
19 So, those are the three criteria that 20 we're using to judge the exemption to GDC-27. NuScale 21 submitted an exemption and requested approval of a 22 principal design criteria, PDC-27. Next slide, Bruce.
23 So, NuScale revised, this is the revised 24 PDC-27, this was an open item, in DCD Section 3.1.3.a.
25 It's basically, the first part of that sentence is the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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108 1 same as GDC-27, about reliably controlling reactivity 2 during postulated accidents with appropriate margin 3 for stuck rods, that the core capability, the 4 capability to cool a core is maintained.
5 The second sentence, following a 6 postulated accident, the control rods shall be capable 7 of holding the reactor core subcritical under cold 8 conditions with all rods fully inserted, is the 9 addition to the GDC-27 that composes this PDC-27.
10 We moved the discussion of maintaining the 11 SAFDLs under AOO and postulated accidents into the 12 DCD. So, NuScale revised DCA Chapter 15 Tables 15.0-13 2, 15.0-3, and 15.0-4 acceptance criterion to ensure 14 that the capability to cool a core is maintained.
15 And that refers to meeting the specific 16 acceptable fuel design limits, or SAFDLs, including 17 margin for stuck rod for all design-basis events.
18 Next slide.
19 So, we are on Slide 7 now. And I just 20 wanted to recap the return to power scenarios, we're 21 going to be talking about those in a little more depth 22 coming up. Three scenarios can potentially lead to 23 return to power.
24 Decay heat removal cool down with DC power 25 available. Here, RPV level remains above the riser or NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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109 1 it could drop below the riser, depending on 2 conditions.
3 And then, the decay heat removal cool down 4 without DC power. ECCS would actuate at the IAB 5 setpoint, going on ECCS cooling mode.
6 And then, just a -- actual actuation of 7 the ECCS signal and a ECCS cooldown. These can occur 8 as a result of most Chapter 15 AOOs and postulated 9 accidents.
10 The key assumptions in the return to power 11 scenarios and analysis was no operator action, only 12 safety-related equipment is used to mitigate, and the 13 worst stuck rods is assumed out, consistent with the 14 GDCs.
15 Return to power is possible at EOC 16 conditions, but not when significant RCS boron exists, 17 such as at BOC or MOC conditions. Next slide, please, 18 Bruce.
19 EOC return to power analysis results for 20 the decay heat removal system cooldown, assuming riser 21 remains covered and ECCS cooldown, a return to power 22 is possible. Return to power is less than two percent 23 rated thermal power, significant critical heat flux 24 margin exists, and General Design Criteria 10 is met.
25 In other words, fuel remains intact.
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110 1 The decay heat removal system cooldown 2 with water level dropping below the riser or riser 3 uncovered remains subcritical due to sufficient decay 4 heat, at least to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.
5 Staff's independent confirmatory analysis 6 yielded similar results to the applicant's and the 7 staff recommended approving the exemption to GDC-27.
8 Next slide, Bruce.
9 So, there are -- as the previous slides 10 described, there's certainly a condition at EOC where 11 a return to power is possible. Since excess 12 reactivity is greater early in the cycle, we wanted to 13 make sure that the EOC was truly the bounding case, so 14 we looked at return to power potentials at what I call 15 non-EOC conditions.
16 The loss of soluble boron in the core 17 during cooldown could cause a criticality similar to 18 the EOC, ECCS cooldown scenario, obviously depends on 19 the distribution of boron throughout the RPV and CNV.
20 Core boron can be reduced by flashing or 21 liquid discharge, entrainment, boron volatility, core 22 and riser boron gradient, and diluted CNV water 23 entering the core. So, this is what NuScale evaluated 24 and the staff reviewed as the mechanisms for a 25 potential redistribution of boron. Next slide, Bruce.
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111 1 Staff reviewed, documented in SER Section 2 15.6, staff conducted a detailed audit and numerous 3 public meetings on the topic.
4 A control volume method was used in NRELAP 5 to calculate the fluid transport. Boron transport is 6 effectively informed by the fluid transport that is 7 derived from the NRELAP code.
8 Methodology uses conservative assumptions 9 to minimize boron concentration in the core. Boron 10 mass is removed by conservative treatment of certain 11 physical phenomenon. And boron mass is artificially 12 removed to ensure overall method conservatism.
13 Determination of boron loss using NRELAP 14 5 information included flashing, liquid discharge, 15 entrainment, boron volatized and redeposited outside 16 the core, and CNV level.
17 Riser and boron gradient was evaluated 18 based on NIST test data and VEERA test data. Next 19 slide, Bruce.
20 So, the staff's findings regarding 21 potential return to power during non-EOC conditions.
22 Staff agrees that boron will concentrate in the core 23 riser region due to boiling. Staff concluded that 24 boron loss terms informed by NRELAP are conservative.
25 Staff concluded that assuming the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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112 1 elimination of the downcomer and lower plenum boron 2 mass is conservative with regard to the core boron 3 concentration.
4 Boron volatility correlation was 5 reasonable, based on NuScale's operating conditions 6 and conservative by not including any boron that could 7 be rewet and returned to the core.
8 VEERA test data demonstrates that the core 9 boron is uniform once saturated boiling conditions are 10 reached. The applicant also performed an evaluation 11 with a fully diluted water mass entering the core 12 below the saturated boiling core elevation to 13 demonstrate that the core remained subcritical.
14 NIST-1 test data from their long-term 15 cooling test, we examined the core exit flow data to 16 demonstrate that two-phase mixing would occur, which 17 would promote riser and core mixing, so we wouldn't 18 have too adverse a gradient between the core and the 19 riser.
20 Staff concluded that the final boron 21 concentration at 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> is greater than the initial 22 core RCS boron concentration, thereby maintaining 23 subcriticality.
24 And then, as NuScale talked earlier, the 25 staff is aware of a condition report, written by NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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113 1 NuScale, dealing with steam space LOCAs.
2 VICE CHAIR REMPE: Jeff, this slide talks 3 about things being conservative --
4 MR. SCHMIDT: Yes.
5 VICE CHAIR REMPE: -- in several places.
6 How much are things conservative? Are you ten 7 percent, 50 percent, 80 percent?
8 VICE CHAIR REMPE: Yes, they're pretty 9 conservative. I think we can go into details in the 10 prop discussion, where I can give specific numbers.
11 But I think as you walk through those 12 numbers, you will see that -- for example, one of the 13 modeling assumptions is not to include the boron mass 14 that exists in the downcomer, in this analysis. That 15 mass of boron effectively just goes away, doesn't 16 exist in the problem. And that's a large mass that is 17 conservative assumption in this analysis.
18 So, we can walk through the specific 19 numbers and I think I could give you a better feel, 20 but that's just one of the areas that the overall 21 methodology shows significant conservatism. But there 22 are a number of conservatisms I think we can talk in 23 the proprietary section.
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114 1 will be.
2 MR. SCHMIDT: Yes, there was conservatisms 3 taken in many aspects of this modeling, whether it be 4 a boron loss below certain elevations and containment, 5 some of that never recirculates back in. So, there 6 are a number of conservatisms here.
7 VICE CHAIR REMPE: Thank you.
8 MR. SCHMIDT: Okay. Slide 12, please, 9 Bruce. So, this is a new slide relative to the 10 subcommittee meeting. NuScale kind of alluded to 11 this.
12 There's a condition report for steam space 13 LOCA, with DC power available. The current CNV level 14 setpoint may cause a diluted water slug to quickly 15 enter the core upon ECCS actuation due to a RPV and 16 CNV water level difference. And that's what their 17 revised setpoints are attempting to correct.
18 An additional source of diluted water in 19 the downcomer beyond that from the CNV could be 20 created if a water level drops below the riser due to 21 the break inventory loss.
22 The decay heat removal system, which is 23 expected to be operating, could condense that diluted 24 steam into the RPV downcomer.
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115 1 or a combination of the CNV or downcomer could lead to 2 a potential reactivity event.
3 NuScale is examining new CNV level 4 setpoints and additional ECCS actuation logics to 5 minimize a large RPV and CNV level difference, 6 precluding a rapid diluted water slug from entering 7 the core.
8 Right now, we're under an audit plan is in 9 place for the staff to review the revised ECCS 10 actuation setpoints. Staff will engage NuScale to 11 ensure impacted FSAR sections and analyses are updated 12 as necessary.
13 MEMBER MARCH-LEUBA: Jeff, can I ask you?
14 So, I understand from this that the condition report 15 has been finalized, meaning that it has been closed?
16 MR. SCHMIDT: It has been issued, I don't 17 think it's right to characterize it as closed.
18 MEMBER MARCH-LEUBA: Yes, issued. So, I 19 mean, all of the analyses have been finalized and --
20 MR. SCHMIDT: Yes.
21 MEMBER MARCH-LEUBA: -- they have concluded 22 and I do have it here, the organization, that they're 23 going to change some setpoints to minimize. What is 24 the plan, I mean, you plan to audit this as they do 25 the -- because this is going to affect a number of the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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116 1 event calculations. You're going to have to update 2 some FSAR sections.
3 MR. SCHMIDT: That's correct.
4 MEMBER MARCH-LEUBA: So, you're going to be 5 reviewing them online, I mean, in parallel as they do 6 them?
7 MR. SCHMIDT: Yes. We're under an audit 8 plan and we'll be reviewing documents as they place 9 them in the electronic reading room.
10 MEMBER MARCH-LEUBA: Okay. And one thing 11 I want you to, I'm begging you to do is, the law of 12 unintended consequences. This looks like a great 13 idea, it looks like the right thing to do, but let's 14 make sure we're looking around to make sure we didn't 15 mess something else up. So, you need to keep an eye 16 for the law of unintended consequences.
17 MR. SCHMIDT: Yes, I agree with you. I 18 mean, we are trying to look at non-LOCA events and how 19 that changes things, and even non-LOCA events. That 20 is certainly actively under discussions.
21 We are also, and I think coming up in some 22 other slides, we're looking at some other potential 23 dilution scenarios that maybe weren't examined as 24 thoroughly. So, we will be looking at the setpoint 25 change and I think we'll be looking at some other NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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117 1 things.
2 MEMBER MARCH-LEUBA: Yes. Because if I 3 have a dollar for every time I made a change in a 4 software line and it looked like a good idea and I see 5 the consequences, mess up something completely 6 different.
7 MR. SCHMIDT: Yes.
8 MEMBER MARCH-LEUBA: Let's make sure we 9 review everything carefully.
10 MR. SCHMIDT: I agree with your concern.
11 Is there any more question on this slide, since it was 12 new? Okay. Hearing none, let's go to Slide 13.
13 The staff also looked at the non-EOC 14 potential for return to power out to seven days. The 15 staff considered the NuScale capability to cope with 16 the boron redistribution without the need for 17 additional non-safety-related equipment for a period 18 of seven days, consistent with SECY-96-120.
19 Staff reviewed NuScale's calculations, 20 including the initial (telephonic interference) and 21 results. Staff agrees that there is sufficient decay 22 heat removal and the core would remain subcritical 23 throughout the seven-day period.
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118 1 in the core, as long as it's not displaced from the 2 core, you will remain shutdown. Next slide, Bruce.
3 So, this slide will have some new 4 additions. This is staying on the decay heat removal 5 system for a long period of time or long-term 6 operation.
7 The decay heat removal system is a safety-8 related heat removal system used to mitigate non-LOCA 9 transients.
10 RPV level may drop below the riser 11 elevation following a reactor trip and subsequent 12 cooldown from an AOO or postulated accident. Without 13 makeup, the water level will drop below the riser 14 within three to six hours, depending on the initial 15 conditions and the core decay heat.
16 Staff asked if adequate cooling is 17 maintained when the riser becomes uncovered and if a 18 return to power is possible? The applicant 19 demonstrated that adequate residual heat removal is 20 maintained and a return to power does not occur within 21 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.
22 And that was the original staff finding 23 related to riser uncovery, but as we've discussed some 24 of these newer issues, especially related to downcomer 25 dilution, I think the staff has realized that the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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119 1 original applicant response did not address the 2 potential for dilution of the downcomer when the riser 3 becomes uncovered for an extended decay heat removal 4 system operation.
5 The staff was originally focused on 6 adequate cooling and potential for return to power at 7 these lower temperatures, but is now focusing on the 8 dilution of the downcomer as well.
9 Staff requested the applicant to evaluate 10 the potential of downcomer dilution leading a return 11 to power during extended decay heat removal operation 12 as part of resolving this CR.
13 So, this is, it's staying on the decay 14 heat removal system for a long period of time and the 15 potential for almost like a diluted slug entering the 16 core under this operating condition.
17 MEMBER MARCH-LEUBA: Yes, Jeff, this is 18 Jose again. What reports are you following for this?
19 Is this, again, the audit?
20 MR. SCHMIDT: Yes.
21 MEMBER MARCH-LEUBA: Because we basically 22 have the SER issued.
23 MR. SCHMIDT: Yes.
24 MEMBER MARCH-LEUBA: Are you issuing new 25 RAIs or just talking to the applicant?
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120 1 MR. SCHMIDT: We're addressing this under 2 the same CR that the LOCA ECCS setpoint change.
3 MEMBER MARCH-LEUBA: So, the same audit 4 plan applies to this?
5 MR. SCHMIDT: That is correct.
6 MEMBER MARCH-LEUBA: Yes. See, because my 7 real goal is the operators in the control room are 8 trained that whenever you uncover the riser, you have 9 to treat the downcomer as if it was poisonous. I 10 don't know what happened to it, let's assume the 11 worst. And as long as that training happen, 12 everything will work.
13 MR. SCHMIDT: Well, okay, let me be clear 14 here, Jose, is that we're -- I'll have a slide coming 15 up on the recovery aspect.
16 But we're actually looking at the 17 potential for a diluted downcomer and recriticality 18 within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />, without operator action. In other 19 words, this is of the normal scope of Chapter 15.
20 You're referring to the recovery, where they would add 21 mass, which is also a concern, but this is a related 22 but separate concern.
23 MEMBER MARCH-LEUBA: Yes. That's because 24 we want to take it as a full operator activation, but 25 in real life, the operator will be in the control room NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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121 1 and be looking over the shoulder and they will prevent 2 -- in real life, the operator will help.
3 I know we need to analyze Chapter 15 as if 4 he was not there, but in real life, the operator will 5 be there. And the most important, the most critical 6 thing we can do is make sure the operator is aware of 7 the problem. I see what you're doing, you have to 8 analyze the reactor they send you, which is a passive 9 one.
10 MR. SCHMIDT: That's right. And we have to 11 evaluate this potential issue to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> without 12 operator action, as you said, under Chapter 15 13 assumptions.
14 MEMBER MARCH-LEUBA: Okay.
15 MR. SCHMIDT: Yes, I think I get to your 16 issue, I think, maybe in the next slide. Let's go to 17 Slide 15, Bruce. So, this is recovery after long-term 18 decay heat removal operation. So, this is, I think, 19 what you're referring to, is that correct, Jose?
20 MEMBER MARCH-LEUBA: Yes.
21 MR. SCHMIDT: Okay.
22 MEMBER MARCH-LEUBA: And in addition, you 23 can have an actuation of things, like CVCS, that will 24 raise the levels.
25 MR. SCHMIDT: Right.
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122 1 MEMBER MARCH-LEUBA: Of course, that 2 actuation has a very low probability of happening.
3 MR. SCHMIDT: Right, right. Yes. So, this 4 could apply if they took actions to mitigate during 5 the event as well.
6 So, and this is, again, in a riser 7 uncovered scenario, some water vapor will condense on 8 the steam generator tubes, the ones that are -- the 9 surface area that's exposed.
10 This has the potential to dilute the 11 downcomer over a long period of time, as water vapor 12 is assumed to have negligible boron concentration.
13 The rate of the downcomer dilution is limited by the 14 fraction of the steam generator surface area 15 uncovered.
16 Boron volatility entrainment and rewetting 17 may help limit downcomer dilution, but are not 18 quantified.
19 A potential exists that reestablishing 20 single-phase natural circulation could transport 21 diluted downcomer to the core, causing a potential 22 recriticality.
23 Reestablishing RPV level above the riser 24 after extended decay heat removal system operation 25 requires the operator to initiate action to recover NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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123 1 the module through the addition of water.
2 Post-accident monitoring recovery is not 3 required to be evaluated in Chapter 15 design basis.
4 And that's kind of why I separated out the two issues, 5 because the one of diluted downcomer does have to be 6 evaluated under Chapter 15. So, this is -- we're kind 7 of parsing it recovery versus no operator action in 8 the stylistic manner of Chapter 15.
9 MEMBER MARCH-LEUBA: Yes, I understand what 10 you're trying to say. We've talked about this for the 11 last several months.
12 MR. SCHMIDT: Right.
13 MEMBER MARCH-LEUBA: So, this is all.
14 MR. SCHMIDT: Yes, okay, thank you. All 15 right. Bruce, Slide 16, please. Okay. So, this is 16 recovery, long-term decay heat removal operation 17 recovery continued.
18 As indicated, the modules following 19 extended decay heat removal system operation will be 20 procedurally controlled. Plant procedures are not 21 part of the DCA review. Procedures will be developed 22 by the COL applicant or holder. Chapter 13 COL item 23 addresses the development of operating procedures.
24 The staff believes procedures should be 25 developed to adequately address recovery from this NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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124 1 condition. Plant design allows for the following 2 operational strategies that could address recovery 3 from this condition.
4 Mixing the core and downcomer boron 5 concentration by simultaneous injection and letdown, 6 preserving RCS level, where the RCS level would be 7 below the riser.
8 Downcomer and core boron concentration 9 sampled to ensure adequate mixing before single-phase 10 natural circulation is reestablished.
11 Confirming adequate shutdown margin before 12 restoring level above the riser. Okay. Bruce, Slide 13 17, please.
14 MEMBER KIRCHNER: Jeff, this is Walt.
15 MR. SCHMIDT: Yes?
16 MEMBER KIRCHNER: Going back to my line of 17 questioning of NuScale. It seems to me that this 18 scenario of downcomer dilution somehow should be 19 governed by tech specs.
20 MR. SCHMIDT: We have had, recently have 21 had numerous discussions with NuScale of how we're 22 going to capture this. We have not reached conclusion 23 in those discussions.
24 I think NuScale could speak to the tech 25 spec aspect, that has been brought up. I think they NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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125 1 have a reasonable answer to that.
2 We are looking at maybe other means of 3 capturing that and I think, in the future, I think 4 we'll be able to speak to it more. Like I said, we 5 haven't reached conclusions on how we're going to 6 capture this event.
7 MEMBER KIRCHNER: I'm not trying to drive 8 the answer, but I will draw an analogy for you. And 9 the reason I'm falling back on tech specs as one way 10 to deal with this.
11 Procedures aside, it's -- if you think 12 about your operating envelop under tech specs, 13 temperature and pressure and so on, this is similar in 14 a sense.
15 In other words, once that riser is 16 uncovered, you're in a different place, where you 17 don't want to be, obviously, if you can avoid it, 18 because it opens up the potential of, in your 19 preceding slides, of a slug of diluted water going in 20 and perhaps causing a recriticality.
21 So, it seems to me that somehow this is a 22 candidate that is a little bit more stringent 23 requirement than just, well, we'll take care of it in 24 terms of procedural space. That's just one member's 25 opinion.
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126 1 MR. SCHMIDT: So, we are looking, I'm not 2 sure I can speak to just anything beyond procedures, 3 but we are looking to capture this concern and this 4 phenomenon better documented, so either it can be 5 addressed by potential design change and/or operating 6 procedures at the COL stage.
7 Is that -- we haven't finalized anything, 8 so I can't speak too much more to it, but we are in 9 active discussion with NuScale.
10 MEMBER KIRCHNER: Thank you.
11 MR. SCHMIDT: I'm not sure I'm answering 12 your question, though.
13 MEMBER KIRCHNER: Not really, in the sense 14 that you're going ahead now and doing a design 15 certification. So, you identified a potential, let me 16 parse my words carefully, scenario with the design 17 that could lead to a potential recriticality of some 18 extent.
19 And that's, to me, not a space that you 20 really want to be in without having -- again, I go 21 back to my analogy. You have an operating window for 22 pressure and temperature, and that's for good 23 purposes, like fracture of the reactor vessel.
24 Well, here, you have something that my 25 mind is an analogous issue. And so, I just -- this NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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127 1 idea that procedures will be developed by a COL 2 applicant, rather -- I don't want to say kicks the can 3 down the road, because, obviously, both you and 4 NuScale are addressing the issue.
5 But it just doesn't seem strong enough, if 6 you will, in terms of when the DCA is issued, that you 7 really put a bound on this particular problem.
8 MR. SCHMIDT: So, would you be, then, 9 suggesting it would be analyzed, the recovery worst 10 case scenario analyzed?
11 MEMBER MARCH-LEUBA: I would -- definitely 12 a yes, definitely a yes. But I'm with Walt, I would 13 love, you know I care about this issue, I would love 14 to see on tech specs an LCO, limited condition for 15 operation, the moment you uncover the riser, you enter 16 an LCO. And that tells the operator, you have 17 problem, you have to do something.
18 And that would be a perfect way to do it.
19 You uncover the riser, you are in LCO, and here are 20 your procedures to get out of it. You don't have to 21 develop the procedures now --
22 MR. SCHMIDT: Right.
23 MEMBER MARCH-LEUBA: -- but it's -- I don't 24 know.
25 MR. SCHMIDT: Thank you. I think that NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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128 1 clarifies what Walt was I think alluding to. I 2 understand now. Okay. Yeah, I think, you know, we're 3 in active discussion with NuScale of how we're going 4 to proceed with this issue. I think we recognize that 5 I am certainly not in a position to commit one way or 6 the other of how this would be resolved, but it is 7 certainly almost a daily discussion item at this 8 point.
9 MR. PRESSON: Hey, and this is Matthew 10 Presson with NuScale, if I may jump in?
11 Okay, our -- we are aligned with making 12 sure that this is captured within DCA space somehow.
13 The main issues with tech specs being -- that that's 14 what provides the boundary for our events leading into 15 a Chapter 15 event. But we understand and we limit 16 what could be considered with those deterministic 17 assumptions. Once you are into -- you've gone and 18 tripped, you know, you aren't technically within tech 19 spec space anymore, so it wouldn't be very useful 20 within that space.
21 And that's kind of the issue that we've 22 been seeing with this is figuring out the proper place 23 to document it without it like tech specs not being 24 particularly applicable or, you know, if you did see 25 that you'd already be out of that and into either NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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129 1 abnormal procedures or other procedures. So figuring 2 out how to address the fact that you will be in this 3 procedural space, handling it with operators, but 4 still capturing that in DCA.
5 MR. MOORE: This is Scott Moore, the 6 Executive Director, and just a note for the staff and 7 NuScale and anybody else that's on the line, you're 8 going to get comments and questions about any of the 9 presentations, but I just remind everybody that's 10 listening and presenting that the committee speaks 11 through its letters and letter reports. And so the 12 committee speaks as a whole, and that's what you 13 really need to pay attention to, the full committee's 14 presentation in its letter reports. Thank you.
15 MEMBER KIRCHNER: Jose, I think you were 16 going to say something?
17 MEMBER MARCH-LEUBA: Basically the same 18 thing you said. That is -- individual members wishes 19 -- the desire to be helpful.
20 MEMBER KIRCHNER: Thank you.
21 MR. SCHMIDT: Okay, I guess can we proceed 22 at this point?
23 MEMBER KIRCHNER: Go ahead, Jeff.
24 MR. SCHMIDT: Okay. Thank you. Slide 17.
25 So this describes an ATWS scenario where you can NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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130 1 basically lose inventory through the safety relief 2 valve and be in a situation where you would have a 3 potentially diluted water slug inside of containment 4 as well.
5 To be clear though, that ATWS is not 6 considered a design basis event due to the design of 7 the reactor trip system within the MPS, lowering the 8 probability of occurrence to one times ten to the 9 minus five per reactor year, and hence it's not 10 evaluated in Section 15.8 of the DCA.
11 Let's go to the next slide.
12 So ATWS mitigation scenarios. You know, 13 if the operator has recognized that an ATWS has 14 occurred, if they control -- if they insert the 15 control rods early in the transient, it effectively 16 becomes like any other cool-down event. If operators 17 delay or take no action to mitigate the ATWS, 18 operators will probably have to be careful in how they 19 restore or get back to a normal operating mode 20 following the ATWS. If it's left alone, our ATWS 21 analysis has indicated that the reactor stays in a 22 safe, stable state, and basically water remains above 23 the top of the active fuel.
24 Let's go to the next slide, Bruce?
25 Again, as I mentioned, if the operators NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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131 1 insert the control rods early in the event, CNV level 2 reaches -- before the CNV reaches the lowest ECCS set 3 point, recovery would be very similar, the same as a 4 design basis decay heat removal cooldown. Staff's 5 conservative analysis demonstrates the lowest CNV 6 level was reached approximately within one hour.
7 The likelihood of operators failing to 8 insert control rods within that one hour is highly 9 unlikely. If the operator could not insert control 10 rods before reaching the lowest CNV level, ECCS set 11 point, additional analysis may be needed to determine 12 the appropriate operator actions.
13 ATWS mitigation procedures are dependent 14 obviously on the specific ATWS event and available 15 equipment. Operator actions to recover the plant 16 following a beyond design basis are not within the 17 scope of the DCA review and are developed by the COL 18 applicant are older.
19 Again, Chapter 13 has a COL item which 20 addresses the development of operating procedures 21 similar to the design basis event discussion we had 22 earlier.
23 Next slide, please.
24 So we're switching gears here a little 25 bit. This was one of the unclear open items regarding NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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132 1 rod ejection or return to power from rod -- the 2 potential for return to power from rod ejection. DCA 3 does not address the potential return to power 4 following a postulated rod ejection. Rod ejection is 5 evaluated for short term reactivity response only.
6 This is consistent with the requirement in GDC 28 and 7 the guidance in SRP 15.4(a) to appropriately limit the 8 rate of reactivity increases associated with 9 postulated reactivity accidents including ejected 10 rods.
11 Primarily a check -- the rod ejection 12 accident is primarily a check of the loading pattern 13 and control rod design such that a coolable geometry 14 is maintained. The staff determined that the 15 provisions in GDC 27 for evaluating design basis 16 accidents in the long term are met for the NuScale 17 design because the control rod ejection accident need 18 not be considered in the long term, due to the robust 19 design of the control rod housing -- drive housing.
20 The staff evaluated the control rod housing design in 21 SER section 3.9. Can't actually see the last number 22 there, so.
23 Any questions on this slide?
24 Okay, Bruce, next slide.
25 Long term cooling analysis, there's two NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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133 1 long term cooling situations evaluated by NuScale.
2 One is we've talked to already, the decay heat removal 3 system, and the other is the ECCS cooling. Staff 4 review is documented in SER section 15.0.5 and 15.6.5.
5 Long term cooling methodology is 6 documented in the technical report, incorporated by 7 reference into DCD Chapter 1. There's long term 8 cooling technical report addresses the ECCS cooling 9 after recirculation is established. Long term cooling 10 methodology assumes sub-criticality. Return to power 11 is addressed in DCD Section 15.0.6.
12 Phase 2 SER included open item 15.0.5-2 as 13 the long term cooling technical report had stated that 14 cooling was demonstrated to 30 days. NuScale revised 15 the statement, and staff SER documents the review to 16 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.
17 A figure of merit for the long term 18 cooling analysis include the minimum collapsed level, 19 minimum RPV temperature to preclude boron 20 precipitation and maximum clad temperature. All 21 figures of merit met acceptance criteria for the long 22 term cooling analysis.
23 Next slide.
24 Okay, I'm going to turn it over to Carl 25 Thurston for the rest of the presentation. Thank you.
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134 1 MR. THURSTON: Okay. I hope everyone can 2 hear me. So this is Carl Thurston, Reactor Systems 3 Branch, New Reactors. I'm going to speak about the 4 staff's review of analysis for Chapter 6 and Chapter 5 15 for phase 4.
6 So as NuScale reviewed earlier, there were 7 changes made from RELAP 5 Version 1.3 to 1.4. There 8 was updates to the NPM model for I will say rather 9 miscellaneous changes. The biggest change again was 10 related to the condensation modeling and some other 11 smaller changes.
12 Staff looked at the ECCS logic changes.
13 There were two open items associated with that change.
14 There were changes in IAB release set point, so 15 initially the IAB setpoint was at 1100 plus or minus 16 100. I guess some of those may be proprietary. So 17 the changes -- the IAB settings are reduced.
18 Additionally, as NuScale has indicated 19 rather significant changes to DHRS logic. That change 20 affected primarily non-LOCA analyses. So staff 21 reviewed the updated analyses and results for impacted 22 events in DCD Rev. 3.
23 So next slide, Bruce, slide 23.
24 Okay. So, again, NuScale -- the code 25 changes again and the modeling changes were NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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135 1 incorporated into Rev. 3 of the DCD, and staff 2 reviewed those changes. Staff presented details of 3 the code for the local topical report that was 4 presented on February 19th to the subcommittee.
5 For the ECCS changes, as we indicated, 6 NuScale reviewed -- removed the actuation on riser 7 level, riser low level, so now the actuation is based 8 on loss of DC power or high CNV level or low AC 9 voltage after 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> and conditions. There will be 10 a new logic or logic added per the NuScale condition 11 report.
12 Also, we'd like to highlight that 13 initially NuScale had increased the level set point 14 for the water level in the CNV, and now that will be 15 changed again per the condition report.
16 So here is a review of the IAB logic 17 changes. The release set points changed, and the 18 block set point has changed. The block set point has 19 very little impact on safety analysis events.
20 For the DC DHRS logic changes, NuScale 21 split the signal into two signals, one for DHRS 22 activation and another for secondary side isolation.
23 The direct DHRS actuation inputs now are reduced from 24 13 inputs to four input signals, and those are high 25 RCS pressure, high RCS temperature, high steam NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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136 1 pressure, and low AC voltage to the batteries. So the 2 functions of the DHRS actuation is essentially all the 3 same as the SSI except that it also opens up the DHRS 4 valves for the heat exchangers to cool the steam 5 generators. So this allows for better operation --
6 operational controls and reduces the frequency of DHRS 7 activation.
8 For transient analysis, it delays DHRS 9 activation until much later into the transient, but as 10 far as the figure of merit for Chapter 15, it had very 11 minimal effect on pressure and temperatures and those 12 key values for accepting for the figure of merit 13 margins.
14 Okay, next slide, Bruce, 24.
15 So here we look at selected LOCA analyses 16 and Chapter 6 analyses. So for 15-65 LOCA analysis, 17 you can see that there's a slight reduction in minimum 18 CHFR. There is a rather large increase in minimum 19 collapsed liquid level, and this was due to a 20 methodology change by the applicant in the way that 21 the minimum collapsed level was calculated.
22 For 15-66, inadvertent opening of reactor 23 valve which is an AOO event. The changes were 24 primarily related to treatment of the core. I don't 25 have the value listed for the Rev. 2 DCD, but it's NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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137 1 higher so the new value for Rev. 3 is a lower value, 2 but it still meets the acceptance criteria as 3 indicated.
4 The minimum collapsed liquid level is not 5 limiting for the IORV event, so, in general, after 6 ECCS opens and the module transitions to long-term 7 cooling, you will reach about ten foot of collapsed 8 liquid level in the core above the top of active fuel.
9 So that's consistent with what we have been seeing for 10 many other events.
11 Next, we'll talk about Chapter 6.2, 12 containment design. That pressure increased rather 13 significantly, and this in large part is due to 14 changes and more conservative treatment of non-15 condensables and a little bit related to the code 16 change from version 1.3 to 1.4. But as you can see, 17 they still have adequate margin to the acceptance 18 criteria of 1,050 psia. And also for the containment 19 temperature, they have adequate margin.
20 The adjectives indicate that these 21 analyses all will need to be evaluated for impact of 22 the ECCS set point change for the condition report.
23 These analyses and potentially other Chapter 15 events 24 will require re-analysis for long-term cooling for 25 this set point change to confirm the boron NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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138 1 redistribution issue as it remains bounding based on 2 the previous results for the RAI 89-30.
3 Okay, next slide, Bruce.
4 Next, we will look at non-LOCA transients, 5 15-15 which is steam line break transient. As you can 6 see there, very minimal difference in the key 7 parameters of minimum CHFR for pressure slightly more 8 conservative results for Rev. 3 of the DCD. For steam 9 pressure, again, similar results as being slightly 10 more conservative. For control rods, missed 11 operation, there's a rather significant drop in 12 minimum CHFR, and that's primarily related to the core 13 treatment. They used more conservative power 14 assumptions, and so that resulted in a lower minimum 15 CHFR, and similar for 15-47.
16 So here, we've highlighted that more than 17 likely the steam line break 15-15 will need to be 18 reviewed for the ECCS set point change.
19 Okay, next slide.
20 Next, we will review some of the 21 committee's questions related to Chapter 6.3, ECCS 22 design. So there were some issues related to water 23 hammer and to make sure that the hydraulic lines and 24 the ECCS valve set ups were functioning properly, were 25 not impeded by water hammer or other phenomena. So NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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139 1 different trip valve hydraulic line lengths for each 2 valve, so the staff wanted NuScale to consider that.
3 And we realized that flow inside the lines can 4 experience two-phase flashing when the trip valve 5 opens. Staff requested a full scale high temperature 6 and high pressure test to confirm no water hammer 7 occurred.
8 NuScale stated that the temperature of the 9 ECCS valves and their hydraulic lines will remain 10 above the precipitation temperature for boron during 11 the plant's operation, and NuScale plans to flush the 12 ECCS valves and their hydraulic lines during each 13 refueling outage to remove particulates that may 14 accumulate during operations.
15 Next slide, 27.
16 So this is the last slide of the staff's 17 presentation, and it involves the CNV and RPV level 18 instrumentation. So NuScale uses this new radar 19 technology. I understand there are four strips in the 20 CNV and four strips in the RPV, and they are separated 21 into three different spans. First, for the 22 containment water level, the sensor spans from the top 23 of the RRV to the top of the containment, to the 24 inside of containment, and that's about 684 inches.
25 And the span is 0 to 100 percent.
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140 1 So this means that for levels below the 2 RRV, the operators would not have an indication until 3 the level increases above the RRV, but of course, they 4 will know via the pressure, that the containment 5 pressure will increase if there is a leak inside of 6 containment.
7 The next span is for the pressurizer 8 level, and so that goes from the inside of the 9 pressurizer plate to the top of the pressurizer, and 10 that's about 131 inches, and that span is also from 0 11 to 100 percent.
12 And lastly, the RPV riser level spans from 13 the top of the core to the top of the pressurizer. So 14 in fact, it's the same sensors that provide the 15 pressurizer level reading as provided the RPV level 16 reading. And NuScale has removed that indication from 17 ECCS activation, so now it's only used for post-18 accident monitoring.
19 Also, we note that at the top for the 20 pressurizer level, it indicates 264 to 300 inches to 21 activate ECCS, and of course, that level is being 22 revised. It's going to be reduced based on the 23 preliminary values that NuScale has given the staff 24 for the new ECCS settings per the condition report.
25 MR. NGUYEN: There has been a request to NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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141 1 say what slide we're on.
2 MR. THURSTON: Twenty-seven.
3 VICE CHAIR REMPE: So, Carl, can I -- okay 4 to ask a question or is there a problem?
5 MR. THURSTON: Yes.
6 VICE CHAIR REMPE: This is Joy. The span 7 for actuation has decreased, and is there a discussion 8 occurring about the need to reduce the uncertainty in 9 this radar-based sensor because it looks like you 10 might want to have a more accuracy since you've 11 reduced the span for actuation.
12 MR. THURSTON: So the span of the signals, 13 and I don't know if we have any Chapter 7 staff on the 14 line, but the --
15 MR. TANEJA: I'm here.
16 PARTICIPANT: Dinesh is here.
17 MR. TANEJA: Yes.
18 MR. THURSTON: So the spans haven't 19 changed. You can chime in, Dinesh.
20 MR. TANEJA: Yeah, span is the same. It's 21 just the set point is lower.
22 VICE CHAIR REMPE: Okay, you're right.
23 It's the set point, that you had a broader range where 24 you could have it actuate. What I was trying to say 25 was the range for actuation has decreased. That's NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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142 1 true, right, Dinesh?
2 MR. TANEJA: Yeah. It's tighter.
3 VICE CHAIR REMPE: So wouldn't we want to 4 have a tighter accuracy because the uncertainty of 5 this radar-based sensor was pretty large, previously.
6 Is that --
7 MR. TANEJA: Right.
8 VICE CHAIR REMPE: I'm not sure anymore 9 about what's proprietary or not so I don't want to 10 give the numbers right out unless you can verify that 11 it's okay to say them.
12 MR. TANEJA: So one of the things that we 13 are expecting in the Electronic Reading Room is the 14 technical report on the sensors, the Advanced Sensor 15 Technical Report. That has been identified as one of 16 the potential documents that's been revised due to 17 this change.
18 VICE CHAIR REMPE: Oh, good.
19 MR. TANEJA: So I'm expecting to see the 20 calculation in the set point methodology and the 21 technical report for the sensors to see how they're 22 treating this uncertainty.
23 VICE CHAIR REMPE: Thank you. That's good 24 to hear.
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143 1 for -- Joy, if you could refresh me. I had a call 2 from the home that I had to take, and I missed part of 3 this discussion on the sensors that you were excited 4 about. Could you just give me a quick comment on 5 that?
6 VICE CHAIR REMPE: Okay, so you are 7 looking at slide -- help me, I don't see --
8 MEMBER BROWN: I'm on -- I've got Slide 9 27.
10 VICE CHAIR REMPE: Twenty-seven and you 11 can see that the actuation range is now shown as 264 12 to 300 inches.
13 MEMBER BROWN: Yes, I see that.
14 VICE CHAIR REMPE: That's a much tighter 15 range than what it used to be. And so my question 16 pertained to the fact, and, again, I don't have in 17 front of me what is proprietary or not, but if you 18 will recall, there was a large amount of uncertainty 19 allowed in the accuracy of this radar-based sensor.
20 And my question is it seems like you would want to 21 have tighter accuracies on the sensor now.
22 And I think Dinesh said yeah, they're 23 looking at that, and they said they're going to be 24 updating the sensor report. If you remember there's 25 like a -- is it a technical report that's on that NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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144 1 topic, and we'll see something coming out soon.
2 MEMBER BROWN: Okay, well, one of the 3 reasons for tightening the bands frequently is that 4 you have a less accurate sensor that you're dealing 5 with. Therefore, you tighten it up so that less 6 accuracy doesn't drive you outside what you can accept 7 one way or the other. I mean this is a pretty tight 8 band.
9 VICE CHAIR REMPE: Yeah, and with that 10 sensor, as you'll recall, it was allowing a lot of 11 uncertainty in their measurements.
12 MEMBER BROWN: Yeah, and I can see why 13 they would tighten it up as opposed to a wider band 14 because you couldn't depend on a tight -- a better 15 accuracy out of the sensors.
16 VICE CHAIR REMPE: Yeah.
17 MEMBER BROWN: As we discussed many times.
18 VICE CHAIR REMPE: You bet.
19 MEMBER BROWN: Okay, thank you. I'm 20 sorry, I was -- I'm sorry I missed a few slides. I 21 apologize for that. I had another issue I had to take 22 care of.
23 VICE CHAIR REMPE: And you can call me 24 later if you want to walk about it.
25 MEMBER BROWN: Yeah, I will. I've got the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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145 1 picture. That's all I need right now. Thank you.
2 MR. THURSTON: Yes, we have one additional 3 slide at the end but it's just a figure to illustrate 4 the location of the various signals.
5 So, Bruce, if you go to slide 28 we can --
6 we can wrap things up. So the figure to the right, we 7 can see the pressurizing level and we can see the RPD 8 level, and as Joy indicated, the uncertainty for the 9 signals are being reduced and so that will be reviewed 10 again as a part of the Chapter 7 technical reviews.
11 If you look at the figure to the right, it 12 shows the span for the containment level, again, 13 spanning from the top of the RVV to the inside top of 14 the containment. So that's about 904 inches for zero 15 to 100 percent water level.
16 MEMBER BROWN: Are you talking about the 17 left hand figure? You said --
18 MR. THURSTON: The left hand signal shows 19 the containment level and the right hand signal --
20 MEMBER BROWN: Yes, you said right -- you 21 said right hand figure.
22 MR. THURSTON: I am sorry. I am sorry.
23 MEMBER BROWN: Okay. You confused me.
24 Thank you.
25 MR. THURSTON: Sorry.
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146 1 MEMBER BROWN: Go ahead.
2 MR. THURSTON: Yeah. So I think it's very 3 self-explanatory. So if there are any additional 4 questions from the -- from the committee, from any of 5 the Chapter 15 analyses.
6 If not, I'll turn it over to Bruce.
7 CHAIRMAN SUNSERI: So, Bruce, I guess you 8 can proceed to the next topic.
9 MEMBER KIRCHNER: I think we are changing 10 now from Chapter 15 to page 202 and post-accident 11 monitoring. Okay.
12 PARTICIPANT: Yeah. Okay.
13 MR. TESFAYE: Yes. Thank you. This is 14 Getachew. Bruce, please go to the next slide, please.
15 Good afternoon. My name is Getachew 16 Tesfaye. Can you hear me, first?
17 PARTICIPANT: Yes, we can hear you.
18 MR. TESFAYE: Thank you.
19 Again, my name is Getachew Tesfaye. I am 20 the NRC project manager for NuScale verification FFR 21 Chapters 9, 11, 12, and 16 and also the topical 22 reports for accident source damage.
23 The hydrogen-oxygen post-accident 24 monitoring issue that we will be addressing this 25 afternoon in both FSAR Chapter 9 of NRC systems and NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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147 1 Chapter 12, radiation protection, as well as the 2 accident source and topical report.
3 The principal technical reviewers for this 4 issue are Anne-Marie Grady and certification with 5 Michelle Hart. Anne-Marie will be presenting staff a 6 high level summary of the presentation we gave at the 7 security meeting in March of this year. This is the 8 introduction and I will ask Anne-Marie to take over 9 from here starting with the next slide.
10 MS. GRADY: Thank you, Getachew. This is 11 Anne-Marie Grady and like the earlier presenters I am 12 going to be rereviewing what was presented to the 13 subcommittee at a high level. There's no new material 14 that's going to be presented and I welcome the 15 questions.
16 CHAIRMAN SUNSERI: Hey, Anne-Marie. This 17 is Matt. Could you introduce the slide number as you 18 walk through your deck?
19 MS. GRADY: I'd be happy to do it but I 20 can't see it.
21 CHAIRMAN SUNSERI: You're on number three 22 right now, I believe.
23 MS. GRADY: Okay. So I am on slide number 24 three. Thank you, Matt.
25 First of all, this slide addresses the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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148 1 need for long-term post-accident hydrogen and oxygen 2 monitoring, and the basis of the need is that it 3 informs the timing of the following actions either to 4 inert the containment atmosphere with nitrogen using 5 the CDCS and the nitrogen distribution system, or 6 venting the containment during that set of conditions 7 routing the gas either to the plant exhaust stack and 8 the reactor building ventilation system or to the 9 gaseous waste -- gaseous rad waste system.
10 It also -- the long-term post-accident 11 monitoring confirms the success of the above to 12 mitigating actions. They are also used, the 13 information, to inform the actions in EOPs and the 14 SAMGs, and, Bruce, if you could go to slide number 15 four.
16 The need for post-accident monitoring is 17 also to have information to avoid either risking an 18 impulse pressure to the inside of the containment 19 vessel, which in 45 days would be approximately double 20 the impulse pressure at 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />, and as I know the 21 members have heard me say before and NuScale as well, 22 the containment has been shown to be able to withstand 23 an impulse pressure from a detonation event in the 24 first 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. So the entire discussion is beyond 72 25 hours2.893519e-4 days <br />0.00694 hours <br />4.133598e-5 weeks <br />9.5125e-6 months <br />.
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149 1 And an impulse pressure beyond 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> 2 could lead to -- could lead to the CRDM access flange 3 bulk load exceeding the as used service level 4 restrained limits.
5 Now, for 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> that was not the case.
6 It was close to the limit, but the containment was 7 configured to be intact. And if there were CRDM 8 access bulk load exceeded and it were to fail, it 9 would be risking an uncontrolled release to the 10 public.
11 Please, if you'd go to slide five. Okay.
12 The capability of the design for accurate long-term 13 post-accident hydrogen and oxygen monitoring. The 14 flow path, as we've described before has been 15 established by first making sure the containment 16 pressure was below 250 pounds, which is very different 17 than expected to be, unisolating the containment 18 evacuation system and the containment flooding and 19 drain system CIVs, and creating a flow path from the 20 containment atmosphere via the CTS through the post 21 process sampling system sample pump and in-line gas 22 monitors and funnel to the containment vessel 23 atmosphere via the containment flooding and drain 24 system. The flow path, except for the CIVs, is non-25 safety related and is acceptable for equipment NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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150 1 specifically used for mitigating a severe accident.
2 Bruce, if you'd go to the next slide, 3 which I think is seven.
4 Okay.
5 CHAIRMAN SUNSERI: It's slide six.
6 MS. GRADY: Oh, thank you, Bruce. Or 7 Matt, I guess.
8 To address comments that have been made in 9 an ACRS December letter, that one of the comments was 10 that there were weeks available before post-accident 11 monitoring information was needed to inform any 12 mitigating actions, and I would like to elaborate that 13 that's true if you're talking about the time that the 14 containment atmosphere, conditions that would support 15 combustion, which is essentially oxygen being 5 16 percent, that would occur by about 14 days. I am 17 sorry, 45 days. NuScale calculated that. We have a 18 confirmatory analysis that agrees with that number.
19 The minimum concentration of 4 percent, which on some 20 occasions has been shown to support combustion, would 21 occur at about 30 days.
22 Prior to reaching combustible mixtures 23 when the oxygen concentration is about 3 percent would 24 occur in about 15 days. Now, that is -- that 3 25 percent is a value that was taken from the GTGs, which NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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151 1 is when NuScale decided that that would be a prudent 2 wait time to take action to vent a containment.
3 So there aren't really weeks to decide to 4 -- what action to be taken. It's really much, much 5 shorter. And another comment that was made in the 6 ACRS letter was that there are other indications that 7 would be available to follow the severe accident 8 progression such as pressure, what temperature, and 9 that they are not -- they do not provide the 10 information as to the potential for the combustion of 11 gases.
12 Bruce, if you'd go to the next slide.
13 ACRS comments have also been that they were reluctant 14 to contemplate the idea after -- in a severe accident 15 that the containment would be unisolated, and the 16 actions that have been described prior to this venting 17 or the inerting absolutely require unisolating the 18 containment.
19 However, either by injecting nitrogen and 20 inerting it or venting the containment to the stack.
21 However, there have been no alternatives provided or 22 identified by NuScale or derived -- proposed by staff 23 that would allow us to gain the information on 24 combustible concentrations and containment without 25 unisolating the containment.
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152 1 Okay. If you'd go to the next slide, 2 please. Okay. I was just summarizing the slide I 3 discussed previously, and this was in response to the 4 comment that a risk evaluation should be considered or 5 was suggested to be considered, and the operator 6 actions that are in the -- in the first column would 7 either be to vent the containment via using the CVS 8 and the reactor building ventilation system.
9 If the operator took action at 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />, 10 as early as 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />, or as late as 15 days, the 11 hydrogen and oxygen monitoring path could be isolable, 12 could prevent the DDT pressure pulse, and opening --
13 the result would be the containment opening would not 14 lead to the large release.
15 Similarly, on the second or the third row, 16 inerting the containment using the CVCS and nitrogen 17 distribution system in the same time frame, around 72 18 hours2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br /> or less than 15 days, the path would still be 19 isolable. You'd still prevent the DDT pressure pulse 20 and the containment wouldn't lead to a large release.
21 However, taking no action there's no time 22 for operator action at all because you're not going to 23 do anything. The containment is not -- it's not 24 applicable to isolate the containment because it 25 hasn't been opened and it would not prevent the DDT NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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153 1 pressure pulse from occurring in the containment and 2 there is a potential that there could be a CRDM access 3 flange bolt failure after 15 days.
4 And the next slide, please. Okay. This 5 is more or less the information that was provided by 6 the Chapter 12 reviewers. I can go over it unless Mr.
7 Tesfaye would prefer to.
8 Hearing not --
9 MR. TESFAYE: Okay, Anne-Marie. Go ahead, 10 please.
11 MS. GRADY: Okay. Okay. They had -- the 12 staff believed that the information obtained from 13 monitoring is beneficial and would sustain the 14 operators making decisions following an accident. The 15 staff does not currently have enough information from 16 NuScale on the post-accident monitoring flow path 17 design such as flow rate, leakage rate, volumes with 18 the specifics of the piping, the sizes, the equipment, 19 to be able to estimate the dose to an individual 20 performing actions to reisolate the systems and that 21 would be -- reisolating the system would be one of the 22 actions that would be taken if in fact this monitoring 23 flow path were to develop leakage.
24 Therefore, the staff believes that at this 25 stage of licensing the best path forward is to retain NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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154 1 the rulemaking carve out, and I believe that's the 2 last slide. And if anybody has any questions I'd be 3 glad to answer them.
4 MEMBER KIRCHNER: Anne-Marie, this is Walt 5 Kirchner.
6 MS. GRADY: Yes, Walt?
7 MEMBER KIRCHNER: I don't think from the 8 get-go we have disagreed with the logic and what you 9 propose here. I think our problem has been one of the 10 design and the size of the piping that would be 11 unisolated to make this to be able to sample, and 12 secondly, how representative the sample actually would 13 be.
14 And therein lies at least this member's 15 concerns and since we are not in the position to 16 suggest redesign of the -- of the system, that, at 17 least for this member, has been a concern from the 18 get-go.
19 But not -- we believe with you, yes, this 20 information is beneficial. So that has not been an 21 issue for us. But, again, the size of the piping 22 that's unisolated and how representative the sample 23 would be has been of continuing concern, and as you 24 point out, we really do not have a lot of information 25 about what downstream of the isolation valves this NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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155 1 system would look like and, hence, how much -- risk is 2 not the right word to use but how much inventory may 3 be in play as a result of unisolating the containment.
4 MS. GRADY: I agree with you. We don't 5 have that design information yet and we are not 6 expecting it in the DC review stage. So being able to 7 say that we have reviewed information would show that 8 a representative sample would be provided is at this 9 stage a design commitment. But it's not been 10 demonstrated.
11 MEMBER KIRCHNER: Other members?
12 David, do you have any specific comments, 13 or Jose, or Dennis or any member?
14 MEMBER BLEY: None from Dennis.
15 MEMBER MARCH-LEUBA: This is Jose. I was 16 trying to unmute. I'll second -- I think, Walt, you 17 and I are thinking basically in the way of independent 18 individuals so having different opinions. But my 19 point -- I think this is -- I agree with the staff 20 that you need a hydrogen-oxygen monitor.
21 My complaint is if you need one make sure 22 you have one that works, and I am not convinced that 23 this one works. So but the thing I am convinced is 24 that eventually when the COL comes with a new one 25 there will be one that works. So I am not really NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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156 1 concerned about it. But if you are going to have one, 2 have a good one.
3 MS. GRADY: Agreed. I agree.
4 MEMBER KIRCHNER: Any other questions or 5 comments from members?
6 Thank you, Anne-Marie. Oh, there's David.
7 Go ahead, David.
8 MEMBER PETTI: I just wanted to make sure 9 I am remembering correctly. In terms of the 10 assessment and the radiolysis, is that a conservative 11 calculation in terms of how much radiolysis occurred 12 and there's no consideration of all the hydrogen 13 that's around that can act to push the reaction in the 14 opposite direction? Is that true?
15 MS. GRADY: The amount of hydrogen that 16 had been produced from the zirc -- the cladding of the 17 -- deoxidation of the cladding could vary from a small 18 amount to a large amount prior -- in the 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> and 19 that would certainly change the time frame at which 20 radiolysis would produce enough oxygen to threaten the 21 containment.
22 As far as the radiolysis being generated, 23 both NuScale and the confirmatory calc means the 24 guidance of SRP 625 in Reg Guide 1.7. So it's -- in 25 other words, the production radiolysis by itself is a NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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157 1 standard calculation.
2 MEMBER PETTI: Okay. I am just trying to 3 understand what the (telephonic interference) hydrogen 4 to make sure the radiolysis stays in check. So I am 5 (telephonic interference) correlation have that built 6 in.
7 MS. GRADY: That's correct.
8 MEMBER PETTI: Does the correlation that 9 you use have that phenomena in it? Do you know?
10 MS. GRADY: No, the correlation -- the 11 correlation just addressed the fact that there would 12 be potential hydrogen in the containment initially 13 when the radiolysis started. It wasn't -- it wasn't 14 used to suppress it.
15 MEMBER PETTI: Okay. But, I mean, in the 16 actual situation the presence of the hydrogen in the 17 core, not in the containment, right?
18 MS. GRADY: The contribution from the 19 dissolved hydrogen in the accident was credited as 20 having been released into the containment. Is that 21 your question?
22 MEMBER PETTI: No, not exactly. You know, 23 there's a rate of formation from radiolysis in the 24 core. But if there's a lot of hydrogen around the 25 reaction gets pushed back in the opposite direction.
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158 1 And so I am trying to understand if that effect has 2 been considered in the rate that we are calculating 3 because there's a lot of hydrogen around many 4 reactors. So there should be.
5 MS. GRADY: Yes.
6 MEMBER PETTI: So I am trying to get a 7 sense of if that was in there or not. My main 8 question is how conservative the calculation is if 9 that is not in there.
10 MS. GRADY: I don't recall if suppressing 11 the rate of radiolysis was credited as being affected 12 by the concentration -- the initial concentration of 13 hydrogen in the containment atmosphere.
14 MR. OSBORN: Anne-Marie, this is Jim, if 15 I could help you.
16 MS. GRADY: Yes?
17 MR. OSBORN: Yeah, this is Jim Osborn.
18 So I think you're correct that the large 19 quantity of hydrogen will suppress the radiolysis of 20 oxygen. It'll drive the reaction to the left, right, 21 and so you will not produce as much oxygen as the 22 model or the calculation assumes. So the suppression 23 of the radiolysis of oxygen is suppressed by a large 24 amount of hydrogen and that is not how we modeled it.
25 Like Anne-Marie said, we used the Reg.
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159 1 Guidance on this and it has a standard oxygen 2 production through radiolysis. It does not credit the 3 suppression due to the large amount of hydrogen.
4 MEMBER PETTI: Okay. Great. That's what 5 I just needed. Thanks.
6 MEMBER KIRCHNER: Members, any further 7 questions on this topic?
8 Hearing none, were you finished, Anne-9 Marie, at this --
10 MS. GRADY: Yes. Yes, I am, Walt. Thank 11 you.
12 MEMBER KIRCHNER: Thank you very much for 13 your presentation.
14 Mr. Chairman, I would suggest before we 15 transition to the next topic, which I believe will be 16 the staff on PRA, that we take a break.
17 CHAIRMAN SUNSERI: I agree. We have been 18 at this a little more than an hour and a half. Let's 19 take a break until quarter til the hour. Is that 20 sufficient?
21 MEMBER KIRCHNER: Yes. Thank you. That 22 will work.
23 CHAIRMAN SUNSERI: Quarter til the hour we 24 will all resume with the next presentation. So --
25 (Whereupon, the above-entitled matter went NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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160 1 off the record at 3:33 p.m. and resumed at 3:45 p.m.)
2 CHAIRMAN SUNSERI: So let me do a quick 3 roll call of the members. Members, please acknowledge 4 when you hear your name.
5 Ron Ballinger?
6 MEMBER BALLINGER: Here.
7 CHAIRMAN SUNSERI: Dennis Bley?
8 MEMBER BLEY: Here.
9 CHAIRMAN SUNSERI: Charles Brown?
10 Charles Brown?
11 Vesna Dimitrijevic?
12 MEMBER DIMITRIJEVIC: Here.
13 CHAIRMAN SUNSERI: Walt Kirchner is here.
14 MEMBER KIRCHNER: Here.
15 CHAIRMAN SUNSERI: Jose March-Leuba?
16 Jose March-Leuba?
17 MEMBER MARCH-LEUBA: I am here.
18 CHAIRMAN SUNSERI: Dave Petti?
19 MEMBER PETTI: Yeah.
20 CHAIRMAN SUNSERI: Joy Rempe?
21 VICE CHAIR REMPE: I am here.
22 CHAIRMAN SUNSERI: Pete Riccardella?
23 MEMBER RICCARDELLA: I am here.
24 CHAIRMAN SUNSERI: And myself. So the 25 only one missing is Charles Brown. He's been dealing NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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161 1 with a number of distractions today. So we have a 2 quorum. I suggest we move forward then.
3 MEMBER KIRCHNER: Okay. Thank you, Mr.
4 Chairman.
5 We are now turning to the staff's 6 presentation on probabilistic risk assessment.
7 MS. JOHNSON: Yeah. Good afternoon. This 8 is Mary Ruiz Johnson. We are going to present today 9 the probabilistic risk assessment. The presenters are 10 Marie Pohida and Tony Nakanishi.
11 Next slide, please. Today we are going to 12 present the PRA review status and a summary of the 13 March 3rd subcommittee meeting including the DC PRA 14 use limitations. ECCS model sensitivity and 15 uncertainty analysis in the reactor building crane 16 operations.
17 Now I am going to turn it over to Marie 18 Pohida, please.
19 MS. POHIDA: Thank you, Mary Ruiz. Can 20 you please advance to slide three, please?
21 Thank you. This is Marie Pohida of the 22 PRA branch in NRR APLC and I'd like to provide a 23 status, an updated PRE review status.
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162 1 from the anticipated design changes from boron 2 redistribution issues and events leading to riser 3 uncovery. And the PRA staff, we will finalize our 4 findings on the NuScale PRA after evaluation of the 5 submitted DCA changes.
6 And with that, I'll break and answer any 7 questions that anybody might have.
8 MEMBER MARCH-LEUBA: Yes, Marie. What 9 type of timing are you thinking about this? Because 10 we were supposed to finalize the ACRS review anytime 11 now. We need to plan ahead.
12 MS. POHIDA: I understand. We are 13 participating in the same audit with reactor systems 14 and as design changes and assessments come in we are 15 monitoring those for PRA impacts and it's -- I think 16 I'd like to just state that it's under staff 17 evaluation.
18 MEMBER MARCH-LEUBA: But to this -- for 19 planning purposes we can assume it would be late May 20 as to the other topic?
21 MS. POHIDA: Yes.
22 MEMBER MARCH-LEUBA: Okay. Thank you.
23 MEMBER BLEY: Marie, this is Dennis Bley.
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163 1 to be reflected in a recalculation of the PRA?
2 MS. POHIDA: I think I would just like to 3 state at this period of time that it's -- that this is 4 under staff evaluation. We are still waiting for 5 NuScale PRA staff to give us information that we would 6 be looking at.
7 MEMBER BLEY: Okay.
8 MS. POHIDA: Are there any more questions, 9 please?
10 With that, I would ask we advance to slide 11 four and that Tony Nakanishi will continue the 12 discussion. Thank you.
13 CHAIRMAN SUNSERI: This is Matt. Before 14 Tony begins, I note that there are many people that 15 have their microphone unmuted. So please, if you're 16 not the presenter mute your microphone. There is a 17 little bit of background noise coming through. Thank 18 you.
19 MR. NAKANISHI: Okay. Good afternoon. My 20 name is Tony Nakanishi and I am with the Division of 21 Risk Assessment along with Marie Pohida.
22 What I'd like to do is to summarize the 23 topics that were reviewed during the March 24 subcommittee meeting and the way we structured those 25 topics were based on feedback we received from the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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164 1 ACRS members including the ECCS modeling sensitivity 2 and uncertainty analyses and reactor building crane 3 operations.
4 But before we got into the specifics, we 5 wanted to clarify staff, you know, expectations 6 relative to design certification PRAs. So consistent 7 with commission policies and guidance, we -- our 8 expectation from ECPRA is to be used to identify risk-9 informed insights at the design certification stage.
10 So design and operational insights that would inform 11 the design.
12 The quantification aspect is relied upon 13 to support the consistent -- design's consistency with 14 respect to commission goals. But, you know, the 15 staff's focus really was to ensure that the 16 appropriate insights were identified through the use 17 of the PRA and that they support programs such as 18 regulatory treatment of nonsafety systems, reliability 19 assurance programs, operation of human factors 20 programs, and so forth.
21 So some of the staff's review at the DC 22 stage is to ensure that the PRA is adequate to support 23 the uses. So if you could go to the next slide, Mary 24 Ruiz, and we are on slide five now.
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165 1 at the DC stage, you know, we have information that is 2 not available where we need to rely upon assumptions 3 and this chart shows how the PRA would progress under 4 the Part 52 framework.
5 So at the DC and COL application stages 6 there are many, you know, detailed design information 7 that's not -- that's not known. Procedures are not 8 available and but certainly there's, you know, a 9 regulatory framework that will -- that requires PRAs 10 to be upgraded -- updated or maintained and upgraded 11 per regulatory requirements in 50.71(h).
12 And so the key takeaway here is really 13 that at the DC stage we rely upon assumptions and so 14 we want those to be adequately documented.
15 Next slide, please.
16 MEMBER DIMITRIJEVIC: Can we question on 17 these slides? This is Vesna Dimitrijevic.
18 MR. NAKANISHI: Yes?
19 MEMBER DIMITRIJEVIC: When we have a -- in 20 your opinion, when will COL items be addressed?
21 MR. NAKANISHI: So COL items are -- by 22 definition it's a COL applicant's action and the staff 23 would review the COL applicant as part of the 24 application to make sure that the COL applicant as 25 addressed the COL item. And so --
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166 1 MEMBER DIMITRIJEVIC: See, I want to 2 really -- I would like you to differentiate for me 3 because I get confused with exactly the difference 4 between COL applicant and COL holder. Even COL holder 5 in one moment with COL applicant.
6 So this is why I am asking you 7 specifically do you believe that COL items will be 8 addressed in your second column before too long? When 9 do you think the COL items will be addressed and what 10 type of review would you have?
11 MR. NAKANISHI: So the COL items -- the 12 staff expectation is that, you know, the COL applicant 13 -- so it's really the first column. So they would --
14 they would submit an application addressing the COL 15 item and, you know, the expectation --
16 MEMBER DIMITRIJEVIC: So let me then ask 17 you how would -- a lot of this -- one of the COL items 18 in the PRAs to confirm all the assumptions that 19 obviously in your first column you will not have any, 20 you know, like -- you know, you would not have a 21 completed design or anything. You would not have a 22 procedure.
23 MR. NAKANISHI: That's correct. So --
24 MEMBER DIMITRIJEVIC: How would they 25 address the COL items in the COL application?
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167 1 MR. NAKANISHI: So the expectation is that 2 the COL applicant would address them and evaluate 3 them. For the PRA that's supporting the COL 4 application. So, you know, the findings that we would 5 be making at the COL application has to be supported 6 by the COL application PRA.
7 If they -- if they elect to use the PRA in 8 a more sophisticated manner, then we would expect a 9 more detailed, you know, review of those assumptions 10 and their impacts on the application.
11 MEMBER DIMITRIJEVIC: Then we are --
12 extend them because that's the procedure which was 13 then supposed to control some of these boron 14 dilutions, which we just discussed will not be 15 available if the COL application is submitted. Then, 16 obviously, you cannot address this in the first column 17 of this table.
18 MR. NAKANISHI: So, again, we would have 19 to make sure -- so the, you know, PRA findings that we 20 make at the COL application stage is fairly similar to 21 the DC application findings. So we could do that and 22 --
23 MEMBER DIMITRIJEVIC: Then you would be --
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168 1 enveloping. But nothing else. You don't have a 2 design yet. You don't have the procedures. You have 3 -- the cables have not been lie out. The equipment 4 cannot be, you know, procured.
5 So therefore, everything which we 6 discussed now when you say COL applicant we actually 7 mean COL holder in the -- in the report. So I don't 8 know why we even use the COL applicant. The only 9 difference would be site information.
10 Why don't we say COL holder and everyone 11 would understand we are talking, you know, before the 12 -- long time in the future. Not an event. We are 13 talking before the -- there is not any review 14 scheduled.
15 So that's why I have to say it was very 16 important for me to discuss this with my colleagues 17 before this week because we have not really planned 18 reviews after procedures are written, for example.
19 MR. NAKANISHI: Right. So I agree. So, 20 you know, a lot of the assumptions -- the important 21 aspect is to document those assumptions so that it'll 22 carry forward.
23 For COL applicants, you know, we want to 24 make sure that those assumptions are still appropriate 25 for the COL application.
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169 1 Now, if you go further to fuel load then, 2 you know, there are some upgrade requirements and so 3 our expectation is to, you know, have -- you know, 4 have the appropriate acceptability for those phases.
5 But those assumptions being documented is an important 6 aspect.
7 MEMBER DIMITRIJEVIC: Well, this is 8 because we just had today discussions about how are 9 you going to handle these dilutions and everybody says 10 operating procedure. Which operating procedures will 11 we finish in your second column? There is not a new 12 schedule for anything in that column.
13 MR. NAKANISHI: So what we would say to 14 that is as Marie Pohida indicated, we are involved in 15 these daily audit calls with the applicant and we are 16 interested in and we have requested, you know, the 17 applicant to address the redistribution issue for 18 impact on PRA. And so we are waiting for that 19 information.
20 MEMBER KIRCHNER: Tony? Tony, this is 21 Walt Kirchner.
22 MR. NAKANISHI: Yes?
23 MEMBER KIRCHNER: May I interrupt a little 24 bit and just follow up on Vesna's line of questions?
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170 1 this condition report whether there will be, 2 quote/unquote, additional carve outs in the rule. But 3 we know already there are commitments with regard to 4 the steam generator, as an example.
5 And so under -- and I am not an expert or 6 a practitioner in this area. Under the COL 7 application are you going to expect that the PRA that 8 is currently adequate for its purposes would be 9 updated as part of a COL application to address any 10 issues with regard to steam generator or this post-11 accident monitoring system?
12 MR. NAKANISHI: So what we would say to 13 that is if the -- if the risk -- so updating the PRA 14 is something that, you know, would have to be 15 evaluated based on -- so I guess, you know, what we 16 would -- for boron distribution issue, for example, we 17 are -- you know, we think that's important enough to 18 ensure that we address the impact on PRA at this stage 19 and the steam generator issue we might -- you know, 20 based on the -- again, the assumptions around the 21 steam generator, you know, there's some failure 22 probabilities that we assume there and the applicant 23 provided some sensitivity analyses as to the impact of 24 potential to failures and things like that. So we 25 think there's -- you know, we can move forward, I NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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171 1 think, with the steam generator issue at the DC stage.
2 The boron distribution issue we are 3 currently evaluating, as Marie Pohida indicated, and 4 the hydrogen issue, as Anne-Marie presented, you know, 5 we don't believe that that issue will result in a 6 large release. So from that standpoint we think -- we 7 think we can move forward.
8 So I guess the question of whether the PRA 9 needs to be updated that would actually have to come 10 into play when we discuss what we are using the PRA 11 for.
12 MEMBER KIRCHNER: And I just wanted to 13 understand, much like Vesna pointed out, you've got on 14 your left hand column of the slide you have the DC 15 application and a reference to the CFR, and then the 16 COL application, another CFR reference. But other 17 than site information, as Vesna has pointed out, it 18 doesn't sound like there's any difference between the 19 PRA for the DCA or the COL. Am I missing something?
20 MR. NAKANISHI: No, you're correct, for 21 the most part. There may be additional design, you 22 know, evolution between DC and COL application. But 23 it's probably not going to be significant. A lot of 24 the -- a lot of the PRA information at the COL 25 application stage is referenced -- you know, it's IDR, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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172 1 if you will, was it --
2 MEMBER KIRCHNER: That's what I would 3 expect. I would expect that it would reference the 4 NuScale PRA.
5 MR. NAKANISHI: Right. So but I guess the 6 point I want to make here is that, you know, that's 7 why the assumptions are very important and that would 8 provide a basis for further evaluation further in the 9 licensing and operations stage.
10 MEMBER BLEY: This is Dennis Bley. I got 11 knocked off Skype for a couple minutes when Walt was 12 asking questions. So forgive me if you've already 13 addressed this.
14 But all of those carve outs that exist are 15 going to have to be completed in the review of the COL 16 application -- your first column. If any of them 17 affect the PRA then you ought to be looking at those.
18 MR. NAKANISHI: Yes.
19 MEMBER BLEY: And the applicant should be 20 addressing it.
21 MR. NAKANISHI: Yes, the applicant should 22 address it and, you know, the staff should question 23 it. But, again, you know, there's some level of 24 evaluation that we could -- we could do.
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173 1 I don't know that -- the specifics with respect to the 2 steam generator issue. But from the standpoint of, 3 you know, potential two failures and, you know, maybe 4 increased transient frequency, I think for the -- for 5 the typical uses of the PRA at the COLA stage, we are 6 probably in a position to be able to move forward. It 7 all depends on what the applicant -- the COL applicant 8 decides to use the PRA for.
9 You know, they could -- they could try to 10 apply the PRA for other applications. You know, risk-11 informed tech specs or other things, and if they do 12 that then we will certainly have to do a more detailed 13 review of the assumptions.
14 MEMBER BLEY: I am just telegraphing at 15 least my thoughts if we should schedule a COL 16 applicant. If there are things we learned when those 17 carve outs are closed, change -- we could change 18 substantively the design cert PRA results. They 19 really have to be addressed, though, in the COL 20 application.
21 MR. NAKANISHI: I agree. Thank you.
22 MS. POHIDA: May I add a clarification to 23 this discussion? This is Marie Pohida. Okay.
24 MEMBER KIRCHNER: Yes. Go ahead, Marie.
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174 1 for COL applications says is that the applicant in 2 52.79(d)(1), it says the applicant is supposed to use 3 the PRA developed for design certification and it's 4 supposed to be updated for site-specific features and 5 design departures.
6 MEMBER BLEY: One -- this is Dennis again.
7 These carve outs are different. There's no finality 8 on the design cert in those areas. So you'd have to 9 get finality during the COL application review.
10 MEMBER DIMITRIJEVIC: These can be --
11 these can be completed in design structure. You know, 12 maybe that's what they have in mind. I mean, if 13 something changes from what the assumptions were.
14 But in addition to these carve outs, which 15 are just one small category because there is only a 16 couple of them and we have all of these COL items 17 which are depending on operating procedures which were 18 not being completed until they -- before long.
19 So we have different categories. We have 20 a carve out, which is the main region supposed to be 21 addressed during the COL application, and then we have 22 what we just discussed about boron dilution, this --
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175 1 will be designed before the full load.
2 So there is a lot of things we hear -- I 3 mean, we are just guessing. You know, we don't have 4 a clear picture between COL applicant and the COL 5 holder and when is this happening and what is the 6 review status.
7 So in my opinion, not too much is going to 8 happen in COL. In my opinion and in my experience, 9 because we can report COL applications with EPR, 10 nothing is basically happening in the COL application 11 in relation to the PRA other than adding the site-12 specific information.
13 You know, you also have experience with 14 AP1000. So AP1000 was reviewed in design 15 certification phase and in the COLA phase. I don't 16 see any review explained before the full load if 17 AP1000 doesn't apply to some risk-informed 18 application.
19 So I think in this moment, whatever the 20 COL items related to procedure or design or layout of 21 agreements and tables, that would not be reviewed if 22 not -- they don't apply to risk-informed applications.
23 MR. NAKANISHI: Correct. We wouldn't --
24 we can't really verify those until the plant is built 25 and, you know, and same with the operating experience.
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176 1 We are not going to have surveillance, you know, data 2 coming in.
3 So, again, what we can do, though, is to 4 make sure those important assumptions are documented 5 and if the PRA is going to be used in a way that's 6 more quantitative, if you will, then those will be 7 appropriately evaluated. The assumptions have to be 8 -- to be valid -- well, the impact of the assumptions 9 have to be -- impact on the decisions that you're 10 making have to be evaluated.
11 MS. POHIDA: Tony, may I offer a 12 clarification?
13 MR. NAKANISHI: Yes, please.
14 MS. POHIDA: Thank you. To address 15 Vesna's concerns. And regarding the boron 16 redistribution issue, we are evaluating that for 17 potential PRA impacts at design stage. Regarding the 18 carve outs, because they do not have finality, we will 19 be looking at those for -- at the COL application 20 stage. Okay.
21 Once the -- once you have -- you have a 22 holder, okay, if they state design changes to tier one 23 and tier two information that meets criterion -- that 24 meets the change of criteria for prior staff approval 25 in a LAR, when a COL -- I mean, a COL holder submits NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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177 1 a LAR there is often an assessment of the impact on 2 the PRA and we review that.
3 For example, when AP 1000 submits a LAR, 4 there is often assessment of whether there are any 5 impacts on the PRA. Does this help?
6 MEMBER DIMITRIJEVIC: I mean, we are 7 familiar with this. I just want to say that we -- it 8 is very important for our clarification in this 9 process that we shouldn't be expecting reviews of 10 anything related for completing design and procedures 11 because that's my opinion. There will not be upcoming 12 reviews for that.
13 MEMBER BLEY: Vesna, this is not for 14 discussion with the committee than for -- on 15 interaction with the staff. But the experience with 16 completed COL applications is pretty minimal and if we 17 have significant concerns about specific things that 18 aren't yet clarified even at the COL stage, there is 19 nothing that prevents us from writing our letter to 20 the commission asking them to suggesting that they 21 have us follow up on some of those items later in the 22 review. Just something they can talk about later.
23 MR. NAKANISHI: So, yeah, I agree with 24 everything that's being said. I guess one thing I 25 would add regarding these COL items and the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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178 1 assumptions, what that does, I think, is it provides 2 guidance to the applicant as well as the staff to --
3 you know, to make sure they look at the right things 4 and make sure they are still appropriate for the COL 5 phase.
6 Now, when you get to the holder phase, we 7 -- unless there's an application to the PRA, there 8 really isn't a trigger for, you know, a detailed staff 9 review. You know, you get into how operating reactors 10 use the PRA for risk-informed applications and that 11 gets into, you know, Reg Guide 1-200, peer review 12 process, and things like that.
13 MEMBER BLEY: I have a question here for 14 you. This is Dennis. Because we have never had a 15 Part 52 operating license holder coming up to the fuel 16 load place so we have absolutely zero experience in 17 that step of this whole process.
18 What is the staff's intent at this point 19 in time? You were hinting at it. But is that really 20 being thoroughly considered by the staff, because this 21 would be the -- well, there is a first time coming up 22 but we don't have one yet -- on what kind of look 23 staff ought to do with that fuel load PRA.
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179 1 of look over that peer review or what issues that you 2 might have flagged earlier that you want to make sure 3 are covered in that PRA you plan to look at?
4 MR. NAKANISHI: Right. Those are very 5 good questions and, like you said, we really don't 6 have experience. So we are -- I think we have to sort 7 of, you know, create the guidance for that, you know, 8 maintenance rule implementation as one -- you know, 9 one potential event where we may get into looking at 10 the PRA.
11 But with Vogtle, we will have -- we will 12 have to be, you know, prepared for that. So I think 13 there's additional homework we have to do there.
14 MEMBER DIMITRIJEVIC: And if I can 15 mention, there is very clear guidance versus you have 16 ITAAC guidance. Before they go to the logged, every 17 ITAAC item has to be closed and reported to be 18 submitted to the regulator.
19 So ITAAC items have a very clear closure 20 part. COL items, they are not going to be closed in 21 the COL. Most of those that I saw in the -- I mean, 22 in PRA, so the thing is that we don't even have a 23 similar guidance to the -- for the other things which 24 we say COL applicant and then when we say COL 25 applicant in a lot of cases it's not really applicant.
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180 1 It's the holder almost 99 percent of the time.
2 MR. NAKANISHI: Correct. Correct. And 3 ITAAC has a lot more -- a lot stronger regulatory 4 force, if you will.
5 MEMBER KIRCHNER: Tony, do you have any 6 further slides?
7 MR. NAKANISHI: Well, I do. But I'll go 8 real quick. So if we could go to the next slide.
9 So the only point here that I'd like to 10 make, we evaluated the ECCS model with the 11 understanding that there's no operating experience but 12 we -- you know, so there's modeling uncertainties 13 associated with that. But we -- you know, we 14 addressed this with -- through, you know, sensitivity 15 studies and things like that, and one thing I would 16 mention here is that, you know, the ECCS saturation 17 logic is something that we are looking at closely for 18 a potential impact here, particularly relative to any 19 increase in incomplete ECCS saturation because that 20 could potentially change that risk profile.
21 So next slide, please. Seven. And 22 sensitivity and uncertainty analyses, we -- again, you 23 know, many of the assumptions that could affect the 24 design certification stage findings we believe the 25 applicant provided a sufficient analysis here.
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181 1 But, again, relative to the, you know, 2 potential impacts due to the boron redistribution, we 3 are -- I guess we are not done yet. We are just -- we 4 are monitoring, you know, the assessment from NuScale 5 and then we would -- we would conclude accordingly.
6 So and with that, I am going to turn it 7 back over to Marie just for the reactor building crane 8 discussion that she was the lead reviewer in that 9 area.
10 MS. POHIDA: Thank you, Tony. May we 11 proceed to slide eight, please?
12 Thank you. This is basically the same 13 slide that I presented to the subcommittee regarding 14 reactor building crane operations. The calculated 15 drop probability is dominated by operator errors, of 16 commission, over speed, over race, over travel, and 17 failure of instrumentation. That's in interlocks or 18 switches to provide a safety stop.
19 In revision four of the DCA key assumption 20 was added for the shutdown PRA that movement of the 21 reactor building crane is modeled as being operator 22 controlled and that administrative controls will 23 ensure that reactor building safety features such as 24 limit switches and interlocks that prevent undesired 25 movement are functional during module movement.
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182 1 The validity of these assumptions in the 2 DCA and crane data supporting the PRA will be 3 confirmed by the COL applicant per COL Action Item 4 19.1-8.
5 The reactor building crane is within the 6 scope of the human factors process during COL per the 7 human factors engineering design implementation plan 8 and the risk significance of the crane has resulted in 9 additional ITAACs.
10 So that is the end of my slide -- I'll 11 stop -- and the end of our presentation. So I'll stop 12 here.
13 MEMBER DIMITRIJEVIC: This is a very good 14 example of this COL Item 19.1-8 application to RFDC.
15 There will not be any changes. RDC will not be -- you 16 know, have the design in the COL application. That 17 will happen really before they are logged.
18 So why don't we say here the COL applicant 19 -- it's not applicant. It's COL holder. Happens much 20 later in the -- in the life and that, similarly, the 21 entrance to the -- you know, that there is nothing 22 else right now on this in the process. So --
23 MEMBER BLEY: Is that true? I was under 24 the impression from our subcommittee meeting that this 25 would be addressed in the COL application. So --
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183 1 MEMBER DIMITRIJEVIC: Well, that is 2 implementation-based -- implementation plan.
3 MEMBER BLEY: That was really for the 4 staff.
5 MS. POHIDA: Oh, excuse me. When we 6 reviewed the reactor building crane notebook, we 7 understood from NuScale that the reactor building 8 crane is evolving and that we understood that COL 9 application that we would have more design details.
10 MEMBER BLEY: That's what I understood and 11 I understood it to mean both -- I thought it was in 12 your SER but also I thought that the applicant had 13 talked about that as well and that their crane vendor 14 would have completed that design and the human factors 15 analysis to support it by the time of the COL 16 application.
17 MEMBER DIMITRIJEVIC: Yeah, but the only 18 difference is site so I don't know what is obligating 19 the -- what the COL applicant -- how is the COL 20 applicant obligated to do that. It's not.
21 MEMBER BLEY: It's obligated in the SER 22 and I thought it was, and two, I thought I heard 23 NuScale say they -- that would be in place and they 24 were moving ahead with that line. NuScale and the 25 staff ought to speak to that.
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184 1 MS. POHIDA: Yes. For details I would 2 like to defer to NuScale on this -- on this issue, 3 please.
4 MS. NORRIS: This is Rebecca Norris with 5 NuScale. I am sorry. We are having some connectivity 6 issues on our end and we are collecting our thoughts.
7 Can we get back to this in a few minutes?
8 MEMBER BLEY: Okay by me. This is Dennis.
9 MEMBER DIMITRIJEVIC: Okay by me, too.
10 MS. BRISTOL: The is Sarah Bristol. Can 11 you hear me?
12 MS. POHIDA: Yes. Yes, Sarah. You're a 13 little quiet but we can hear you.
14 MS. BRISTOL: Yes. It's NuScale's 15 expectation that the -- as you have mentioned, the 16 crane is being -- is continuing to be designed, and we 17 believe that at the COL stage there will be additional 18 information and that will be part of the additional 19 design information that will be included in the COL 20 PRA as we reevaluated consistent with COL Item 19-1-8 21 risk assumption.
22 Since we do have the assumption associated 23 with crane operation and operator action, we believe 24 that the crane tech will be addressed at the COL 25 application stage.
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185 1 MEMBER BLEY: Thanks. That was my 2 expectation. You --
3 MEMBER KIRCHNER: Members, any further 4 questions?
5 Hearing none, I think this is -- I believe 6 we are at the end of our open presentations. So we 7 need to ask for public comment. But before we do 8 that, any further comments by members?
9 CHAIRMAN SUNSERI: Walt, this is Matt. I 10 have no other questions or comments.
11 MEMBER KIRCHNER: Anyone else?
12 Hearing none -- Mike Snodderly, can we 13 turn to the opening of the public line?
14 MR. SNODDERLY: Yes, Thomas can assist us 15 with that, and if someone from the public could let us 16 know.
17 MS. FIELDS: This is Sarah Fields. I do 18 not have any comments at this time. Thank you.
19 MEMBER KIRCHNER: Thank you, Sarah. Is 20 there -- are there any other members of the public who 21 wish to make a comment? If so, identify yourself and 22 please make your comments.
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186 1 closed session with NuScale through a bridge line. I 2 recommend that you just mute your Skype control panel 3 and leave it connected, and then when we finish with 4 the closed session we can come back to consideration 5 of letter writing.
6 MR. SNODDERLY: Thank you, Walt, and I had 7 two other things to add. One is that this would be a 8 good time for a break because Thomas -- now that we 9 couldn't initiate the bridge line so we ended the 10 public bridge line.
11 So we need about five minutes to get that 12 up and running and let people call in. But once we --
13 once the chairman ends this open session, yes, we will 14 proceed with the NuScale bridge line to conduct the 15 closed session.
16 I remind all members to look at the email 17 I sent you yesterday evening at 6:29 p.m. That has 18 the slides that we will be -- that we will be 19 discussing.
20 And then the only other thing I had to add 21 was for everyone to be aware that all four commission 22 TAs requested the closed bridge line and I expect them 23 to be on. So just as a heads up.
24 That's all I have.
25 MEMBER BROWN: Mike? Mike?
NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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187 1 MR. SNODDERLY: Yes?
2 MEMBER BROWN: I thought your email said 3 that we were supposed to exit Skype and then go to the 4 bridge line whereas Walt just commented we should just 5 minimize --
6 MR. SNODDERLY: I was -- yes, Charlie, if 7 I could speak to that. That was my direction 8 yesterday evening but after talking to the members and 9 I think Chairman Sunseri was exactly right. Just 10 leave Skype up and running. Just put it on mute and 11 that way we don't have to go through the hassle of 12 rephoning back in.
13 MEMBER KIRCHNER: We need to be sure 14 everybody puts it on mute so that we don't have public 15 access to it.
16 MR. NGUYEN: So I am going to interrupt.
17 So what we are doing is we are making most of the 18 individuals except the Skype team and the ACRS 19 leadership as presenters. Once everyone is on 20 attendee and once the chairman gives the go ahead, we 21 will mute the entire attendees.
22 MEMBER BROWN: Do we go -- are we supposed 23 to mute or not?
24 MR. NGUYEN: You should. But as an extra 25 safeguard, we will mute all attendees, which means you NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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188 1 cannot unmute yourself until we -- until we hear from 2 the chairman to release it.
3 MEMBER BROWN: Okay.
4 MEMBER BLEY: Quynh, this is Dennis Bley.
5 Even the presenters we ought to mute because if 6 anybody slips up and leaves it open we have got a 7 public connection.
8 MR. NGUYEN: I understand. But it's --
9 yeah. Yeah. We are going to mute, too. But we can't 10 put a lock on presenters because we need the authority 11 rights to do what we do.
12 MEMBER BLEY: Okay. As long as you keep 13 watching.
14 MR. NGUYEN: Right. If we -- if we hear 15 something, we are just going to interrupt right away 16 so you can stop talking.
17 MEMBER MARCH-LEUBA: Just so you know, I 18 am going to hang up the phone call because it only 19 takes a key join to go back in. So you won't see me 20 there.
21 MR. NGUYEN: Okay. So the closed bridge 22 line is now open. I am going to lock all the 23 attendees now so you can't unmute yourselves.
24 (Whereupon, the above-entitled matter went 25 off the record at 4:32 p.m. and resumed at 4:33 p.m.)
NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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189 1 CHAIRMAN SUNSERI: At this time, we are 2 going into the closed session.
3 (Whereupon, the above-entitled matter 4 concluded at 4:33 p.m.)
5 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.
(202) 234-4433 WASHINGTON, D.C. 20005-3701 (202) 234-4433
Surry Power Station Units 1 and 2 Subsequent License Renewal Application ACRS Full-Committee Meeting April 8, 2020
Agenda Station Overview/Performance SLR Application Development GALL SLR Consistency SLR Aging Management Programs Technical Topics Closing Remarks 2
Surry Power Station 3
Station Overview Unit 1 Unit 2 Full Power License - 2,441 MWt May 25, 1972 January 29, 1973 (Operating (Operating License Issued) License Issued)
Independent Spent Fuel Storage 1986 Installation (ISFSI), Pads 1 & 2 4.3% Power Uprate to 2,546 MWt 1995 First License Renewal Approval 2003 1.6% MUR to 2,587 MWt 2010 Entered Period of Extended Operation May 25, 2012 January 29, 2013 Current License Expiration May 25, 2032 January 29, 2033 4
Station Overview 5
Surry Performance Surry operates on an 18-month refueling frequency Plant Capacity Factor:
- 2017: U1 - 102.35% U2 - 94.18%
- 2018: U1 - 89.39% U2 - 90.69%
- 2019: U1 - 90.48% U2 - 102.59%
Regulatory Status
- ROP Actions Matrix Column 1
- All ROP Indicators are Green 6
Significant Plant Modifications Surry Unit 1 Unit 2 Flux Thimble Replacement 2001 2011 Reactor Vessel Head Replacement 2003 2003 FAC Pipe Replacement N/A 2005 Ultrasonic Feedwater Flow Installation 2009 2011 Reactor Coolant Pump Main Flange Bolt Replacement 2009 2009 Steam Generator Feed Ring Replacement 2010 2011 Isolated Phase Bus Duct Replacement 2010 2011 Fire Detection System Replacement 2012 2012 Main and Station Service Transformer Replacement 2015 2005 Carbon Fiber Reinforced Polymer (CFRP) Installation 2016 2016 Reserve Station Service Transformers (RSST) Replacement 2019 2020 7
SLR Application Development Dominion Energy staff integrally involved in the development of the GALL SLR/SRP Followed NUREG-2191 (GALL-SLR) and NUREG-2192 (SRP-SLR) to the greatest extent possible Followed SLR industry guidance in NEI 17-01 Reviewed RAIs from the most recent first license renewal applications Conducted Industry Peer Reviews Conducted a Safety pre-application meeting with the NRC Staff in April 2018 to discuss SLRA content and obtain insights 8
SLR Application Development Deltas between First License Renewal (FLR) and SLR Scoping & Screening
- Updated for plant modifications
- Updated to NEI 17-01 guidance
- Some updates required to address 10 CFR 54.4(a)(2)
Aging Management Reviews
- Surry FLR was pre-GALL, additional aging effects required disposition based on NUREG-2191 (GALL-SLR)
Aging Management Programs
- Existing TLAAs Re-assessed
- One new TLAA identified - S/G AVB Tube Wear
- TLAAs analysis dispositioned as acceptable for 80 years 9
GALL Consistency Submittal consistent with GALL-SLR High AMR Consistency (99.6% Notes A thru E)
License Renewal Commitments
- 47 Aging Management Programs
- UFSAR Supplement (Appendix A)
- Managed by the Dominion Commitment Tracking System based on NEI 99-04, Guidelines for Managing NRC Commitment Changes Implementation activities have begun and will continue following anticipated issuance of renewed license 10
Surry SLR AMP Considerations NEI involvement, collaboration with EPRI, and PWROG participation informed AMPs with New Industry Guidance and R&D products Incorporation of operating experience (OE):
- Industry and plant specific OE reviewed for a 10-year period
- Participation in Industry Peer Reviews
- SLR Lead Plant Alignment AMP Effectiveness Reviews performed on all first license renewal AMPs using elements of NEI 14-12 11
Surry SLR - 47 GALL-AMPs Consistent With With Exception Plant with Enhancement Exception and Specific GALL-SLR Enhancement Existing 40 6 24 1 9 0 New 7 5 0 2 0 0 Total 47 12
FLR AMPs are Effective in Managing Aging
- Periodic AMP effectiveness reviews are required to be completed by the program owners every 5 years
- OE is systematically reviewed on an on-going basis
- Training is conducted periodically for program owners
- IP 71003 Phase 4 inspection identified no findings or concerns in 3Q19 13
Technical Topics Concrete and RV Support RV Containment RV Internals Steel Embrittlement Degradation 14
Dominion Energy SLR Summary Surry SLR met the expected norms established with the most recent industry LR/SLR applications Surry had a high degree of consistency with GALL-SLR, which resulted in a high quality SLR Application AMPs will effectively manage the effects of aging to provide reasonable assurance for the SLR period Dominion Energy has committed future investments in people, program enhancements and equipment modifications for the SPEO 15
Advisory Committee on Reactor Safeguards Surry Power Station, Units 1 and 2 Subsequent License Renewal Application (SLRA)
Safety Evaluation Report (SER)
April 8, 2020 Angela Wu, Project Manager Lauren Gibson, Project Manager Office of Nuclear Reactor Regulation
Presentation Outline
- Overview of Safety Review of Surry SLRA
- SER:
- Section 2: Scoping and Screening Review
- Section 3: Aging Management Review
- Section 4: Time-Limited Aging Analyses
- Inspections and Plant Material Conditions
- Conclusion on Surry SLRA Review
- Conclusion on Differing Views on Surry SLRA Review 2
Surry, Units 1 & 2:
License Renewal Initial License Renewal Initial Initial License Renewed Expiration Unit License Renewal Application License Date 1 5/25/1972 5/29/2001 3/20/2003 5/25/2032 2 1/29/1973 5/29/2001 3/20/2003 1/29/2033 Subsequent License Renewal Application Submitted 10/15/2018 Acceptance Determination 12/10/2018 Draft Safety Evaluation Report with 12/27/2019 No Open or Confirmatory Items Final Safety Evaluation Report 3/9/2020 3
Audits Audits Dates Location Operating December 6 - 19, 2018 Rockville, MD Experience In-Office February 4 - 28, 2019 Rockville, MD Surry Power Station, Units 1 and 2 (Surry County, VA)
On-Site April 22 - 25, 2019 Dominion HQ (Innsbrook, VA) 4
SER Overview
- Draft SER with No Open or Confirmatory Items:
December 27, 2019
- Final SER: March 9, 2020
- Requests for Additional Information (RAIs): 71 5
SER Section 2 Structures and Components Subject to Aging Management Review (AMR)
- Section 2.1 - Scoping and Screening Methodology
- Section 2.2 - Plant Level Scoping Results
- Sections 2.3, 2.4, 2.5 - Scoping and Screening Results 6
SER Section 3 Aging Management Review (AMR)
- 3.0 - Use of the Generic Aging Lessons Learned Report
- 3.1 - Reactor Vessel, Internals, and Reactor Coolant System
- 3.2 - Engineered Safety Features
- 3.3 - Auxiliary Systems
- 3.4 - Steam and Power Conversion Systems
- 3.5 - Containment, Structures and Component Supports
- 3.6 - Electrical and Instrumentation and Control Commodities 7
SER Section 3 3.0.3 - Aging Management Programs (AMPs)
SLRA - Original Disposition of AMPs SER - Final Disposition of AMPs o 7 new programs o 7 new programs
- 5 consistent
- 5 consistent
- 2 consistent with exceptions
- 2 consistent with exceptions o 40 existing programs o 40 existing programs
- 7 consistent
- 6 consistent
- 33 consistent with
- 34 consistent with enhancements and/or enhancements and/or exceptions exceptions 8
SER Section 4 Time-Limited Aging Analyses (TLAAs)
- 4.1 - Identification of TLAAs
- 4.2 - Reactor Vessel and Internals Neutron Embrittlement Analyses
- 4.3 - Metal Fatigue Analyses
- 4.4 - Environmental Qualification of Electric Equipment
- 4.5 - Concrete Containment Tendon Prestress Analysis
- 4.6 - Primary Containment Fatigue Analysis
- 4.7 - Other Plant-Specific TLAAs 9
Region II:
AMP Inspections AMPs Reviewed During 71003 Phase 4 Inspection
- Augmented Inspection Program (Existing)
- Buried Piping and Valve Inspection Program (New)
- Chemistry Control Programs for Primary Systems (Existing)
- Chemistry Control Program for Secondary Systems (Existing)
- Civil Engineering Structural Inspection Program (Existing)
- General Condition Monitoring Program (Existing)
- Non-EQ Cable Monitoring Program (Existing)
- Tank Inspection Program (New)
- Work Control Process (Existing) 10
July 2019 Fire Loop Piping Rupture 11
Focused PI&R Inspection
- Inspector: Steven Downey
- Dates: February 24 - 28, 2020
- Procedure: IP 71152, Problem Identification and Resolution
- Activities:
- Developed timeline of events that lead to fire suppression water system nonfunctional declaration
- Determined the current status and path forward for corrective actions intended to restore the health of the fire water suppression system
- Determined the programmatic requirements that govern the actions taken by the licensee since the fire protection loop piping failures occurred
- Verified that actions taken by the licensee were in accordance with the applicable regulatory requirements and self-imposed programmatic requirements
- Result: No Findings Identified
- Observation on status of corrective actions included in IR 2020-001 12
Focused PI&R Inspection:
Timeline + Status of Corrective Actions 13
Region II: Plant Material Condition + Conclusion
- Plant material condition is generally acceptable and meets regulatory requirements for systems, structures, and components.
- The inspectors found that the AMPs were being implemented in accordance with the license condition.
- The NRC will continue to monitor AMPs using the baseline Reactor Oversight Process.
14
SLRA Review Conclusion On the basis of its review of the SLRA, the staff determined that the requirements of 10 CFR 54.29(a) have been met for the subsequent license renewal of Surry Power Station, Units 1 and 2.
15
Conclusion on Differing Views
- Focused on the July 2019 fire pipe rupture
- Evaluation concluded:
- Reliance on applicants correct action program is consistent with license renewal safety principles
- Other issues adequately addressed in application
- No changes needed to the SER
- The renewed license can be issued consistent with 10 CFR Part 54 16
LO-0420-69574 April 6, 2020 Docket No.52-048 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 Entitled ACRS Full Committee Presentation - NuScale FSAR Topic: Chapter 15, PM-0420-69573, 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 April 8, 2020. The materials support NuScales presentation of NuScale Chapter 15.
The enclosure to this letter is the nonproprietary presentation entitled ACRS Full Committee Presentation - NuScale FSAR Topic: Chapter 15, PM-0420-69573, Revision 0.
This letter makes no regulatory commitments and no revisions to any existing regulatory commitments.
If you have any questions, please contact Matthew Presson at 541-452-7531 or at mpresson@nuscalepower.com.
Sincerely, Zackary W. Rad Director, Regulatory Affairs NuScale Power, LLC Distribution: Robert Taylor, NRC, OWFN-8H12 Michael Snodderly, NRC, OWFN-8H12 Christopher Brown, NRC, OWFN-8H12 Gregory Cranston, NRC, OWFN-8H12 Michael Dudek, NRC, OWFN-8H12 Bruce Bavol, NRC, OWFN-8H12
Enclosure:
ACRS Full Committee Presentation - NuScale FSAR Topic: Chapter 15, PM-0420-69573, Revision 0 NuScale Power, LLC 1100 NE Circle Blvd., Suite 200 Corvallis, Oregon 97330 Office 541.360-0500 Fax 541.207.3928 www.nuscalepower.com
LO-0420-69574
Enclosure:
ACRS Full Committee Presentation - NuScale FSAR Topic: Chapter 15, PM-0420-69573, Revision 0 NuScale Power, LLC 1100 NE Circle Blvd., Suite 200 Corvallis, Oregon 97330 Office 541.360-0500 Fax 541.207.3928 www.nuscalepower.com
NuScale Nonproprietary ACRS Full Committee Presentation NuScale FSAR Topic:
Chapter 15 April 8, 2020 1
PM-0420-69573 Revision: 0 Copyright 2020 by NuScale Power, LLC.
Template #: 0000-21727-F01 R6
Presenters Matthew Presson Licensing Project Manager Ben Bristol Supervisor, System Thermal-Hydraulics Meghan McCloskey Thermal-Hydraulic Analyst Paul Infanger Licensing Specialist 2
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Agenda
- Principle Design Criteria 27
- Boron Transport
- Incorporates NRELAP5 v1.4
- Minor module model update
- DHRS actuation logic changes
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Principle Design Criteria 27
- DCA includes an exemption request from GDC-27
- NPM design aligns with precedent based compliance for GDC-27 due to lack of second safety reactivity control system
- Principle Design Criteria 27
- Passive reactor GDC-27 equivalent
- Ensures the safety related reactivity control system is designed to achieve and maintain subcritical core
- Ensures fuel integrity for an extended overcooling in combination with a partial failure of reactivity system (stuck rod) 4 PM-0420-69573 Revision: 0 Copyright 2020 by NuScale Power, LLC.
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Compliance with PDC-27
- Immediate shutdown is sufficient to protect RCPB and SAFDLs with margin for the worst rod stuck out of the core
- Cold shutdown is achieved with all control rods fully inserted
- Loss of Shutdown Margin Consequences Benign
- Evaluated with single highest worth control rod fully withdrawn
- Critical power level does not challenge DHRS or ECCS heat removal or SAFDLs
- Probability of the combination of conditions that results in a loss of shutdown return to power with a single rod stuck out of the core is small 5
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Results - Return to Power Analysis
- Core temperature must be <200°F for recriticality
- Increased pool temperature decreases the magnitude of the return to power, with 140°F precluding a recriticality
- Earliest recriticality determined to occur approximately 40 hours4.62963e-4 days <br />0.0111 hours <br />6.613757e-5 weeks <br />1.522e-5 months <br /> post-scram
- MCHFR for most limiting results non-limiting relative to other events
- Other AOO acceptance criteria met
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ECCS Boron Transport - Context Context for ECCS boron transport analysis:
- As boron accumulates in the core/riser region, boron concentration in the CNV and DC decreases Boron precipitation analysis performed as part of ECCS long term cooling analysis
- Boron dilution analysis performed to:
Evaluate potential for lower boron concentration fluid in core or near core inlet Confirm appropriate scope of return to power analysis by demonstrating that core region concentration remains above initial concentration Response to RAI 8930 Boron transport governed by:
- boiling in the core
- condensation in the containment vessel 7
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- Method summary for dilution analysis:
- LTC PIRT high ranked phenomena affecting boron transport evaluated
- Control volume approach to analyze transport between regions
- NRELAP5 used to provide volume fluid masses, flow rates as input for boron transport calculation
- Volatility, entrainment calculated separately
- Boron transport calculation performed separate from NRELAP5
- Conservatively model transport between regions:
Boron distribution factors applied to minimize boron transport in, maximize boron transport out of RCS hot region
- Demonstrate that RCS hot region concentration remains above initial concentration
- Key areas of NRC review:
- Treatment of boron volatility
- Mixing
- Additional discussion in closed session 8
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ECCS Boron Transport - Results
- Results summarized in RAI 8930 show core boron concentration remains above initial concentration
- No net core boron dilution is expected even with biased transport assumptions
- More realistic analysis of boron transport indicates boron concentration in RCS core region is 2-3 times the initial concentration at 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.
Core boron concentration remains above initial concentration for at least 7 days.
- Realistically, long term, high boron concentration expected in RCS hot region, with low concentration in RCS cold region, containment
- Recovering the riser and establishing Mode 3 conditions will take multiple deliberate operator actions following appropriate procedures
- Procedures are developed on a site-specific basis (COL commitments 13.5-2 and 13.5-7.)
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- Status Update:
- In March 2020, NuScale determined under certain conditions, ECCS actuated later than expected, which could result in a higher containment water level accumulation than is considered in the RAI 8930 response basis.
- Resolution and Design Change to ECCS Actuation:
- NuScale is implementing a design change to ECCS actuation, which will be modified to actuate earlier and eliminate this potential for containment water level accumulation and downcomer dilution.
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Conclusions
- Inherent design characteristics provide ample safety
- Low core power, large RCS inventory, small high pressure containment, and large ultimate heat sink
- Compliance with intent of GDCs is demonstrated for reactivity control systems
- Conservative analysis of the low probability return to power condition demonstrates safety margin
- Boron redistribution is evaluated and demonstrated to not be a safety topic
- Naturally accumulating boron in the core adds to shutdown margin for design basis event and severe accidents.
11 PM-0420-69573 Revision: 0 Copyright 2020 by NuScale Power, LLC.
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Ch 15 Changes FSAR Rev. 2 to Rev. 4
- Results from FSAR Rev. 2 presented to ACRS in June, July 2019 in subcommittee and full committee meetings for Chapter 15
- Changes in FSAR Rev. 3 include
- Update from NRELAP5 v1.3 to v1.4
- Updated NRELAP5 base model input
- More conservative core design input in some cases
- DHRS actuation signal changes, addition of secondary side isolation signal
- ECCS actuation signal changes
- Changes in FSAR Rev. 4 include
- ECCS IAB threshold/release pressure changes 12 PM-0420-69573 Revision: 0 Copyright 2020 by NuScale Power, LLC.
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NRELAP5 v1.4
- Modifications made from v1.3 to v1.4 were due to routine code maintenance
- 26 specific code Fixes (documented in error reports) with most notable being:
- Condensation correlation error corrections
(< 2 psi increase in CNV pressure calculations)
- Correction to choking model quality factor (little to no impact)
- Updated Windows executable to 64-bit version (not used for production calculations)
- 5 new Features - None of which impact DCA calculations
- Added proprietary classifications marking to source files
- Expanded number of elements allowed in water property file (no water property file update)
- Interpolation update for CHF correlation not used in DCA calculations
- Added warning message to users if mass error stop (1%) is disabled
- Removal of Developmental Options from user access 13 PM-0420-69573 Revision: 0 Copyright 2020 by NuScale Power, LLC.
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NRELAP5 Base Model
- Revision 0 released 12/2015 (DCA submittal 12/2016)
- Revision 1 released 8/2017
- Updates for design consistency
- Minor geometry changes based on drawing updates
- Minor RCS flow loss updates (changes in best estimate values)
- Updates for analysis consistency and ease of downstream use
- Minor nodalization changes to match LOCA model
- Added passive heat structures defined in LOCA model
- Other changes
- Change from elevation based to volume based calculation of collapsed liquid level
- Error correction when specifying lower CNV material (had been previously corrected in impacted analysis calculations)
- Revision 2 released 01/2019 (FSAR Rev. 3 submittal 8/2019)
- Removed ECCS actuation on RCS riser level signal
- Minor RCS flow loss updates
- Minor geometry error corrections 14 PM-0420-69573 Revision: 0 Copyright 2020 by NuScale Power, LLC.
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DHRS Actuation Changes
- Summary of change:
- Add secondary side isolation actuation for range of signals that indicate upset in normal secondary side cooling conditions
- DHRS actuation limited to subset of signals indicating insufficient secondary side cooling
- DHRS actuated following secondary side isolation
- Purpose of change: Support expected plant startup progressions
- Effect of change on transient analyses:
- Heatup events - No change to expected DHRS actuations on high pressurizer pressure or high RCS hot temperature
- Cooldown events - Secondary side isolation may be actuated first; DHRS actuated afterwards on high steam pressure
- Reactivity events, inventory increase, inventory decrease events not significantly impacted 15 PM-0420-69573 Revision: 0 Copyright 2020 by NuScale Power, LLC.
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Conclusions
- Revised return to power analysis shows ECCS cooling conditions result in equilibrium power at 1-2% RTP
- ECCS boron transport analysis demonstrates that core boron concentration remains higher than initial concentration
- Changes incorporated into FSAR Revision 3:
- Several minor changes in NRELAP5 code, NPM plant base model
- DHRS, ECCS actuation changes
- FSAR Ch 15 analysis results demonstrate margin to acceptance criteria 16 PM-0420-69573 Revision: 0 Copyright 2020 by NuScale Power, LLC.
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Acronyms AOO - Anticipated Operational Occurrences LTC- Long Term Cooling MCHFR - Minimum Critical Heat Flux Ratio CHF - Critical Heat Flux MTC - Moderator Temperature Coefficient CNV - Containment Vessel NPM - NuScale Power Module COL - Combined License OCRP - Overcooling Return to Power PDC - Principal Design Criteria COLR - Core Operating Limits Report PIRT - Phenomena Identification and Ranking Table CRDM - Control Rod Drive Mechanism RCPB - Reactor Coolant Pressure Boundary RCS - Reactor Coolant System CVCS - Chemical and Volume Control System REA - Rod Ejection Accident DC - Downcomer SAFDL - Specified Acceptable Fuel Design Limits DHRS - Decay Heat Removal System SDM - Shutdown Margin WRSO - Worst Rod Stuck Out DTC - Doppler Temperature Coefficient ECCS - Emergency Core Cooling System EOC - End of Cycle GDC - General Design Criteria IAB - Inadvertent Actuation Block LCO - Limiting Condition for Operation LOCA - Loss of Coolant Accident 17 PM-0420-69573 Revision: 0 Copyright 2020 by NuScale Power, LLC.
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Portland Office Richland Office 6650 SW Redwood Lane, 1933 Jadwin Ave., Suite 130 Suite 210 Richland, WA 99354 Portland, OR 97224 541.360.0500 971.371.1592 Charlotte Office Corvallis Office 2815 Coliseum Centre Drive, 1100 NE Circle Blvd., Suite 200 Suite 230 Corvallis, OR 97330 Charlotte, NC 28217 541.360.0500 980.349.4804 Rockville Office 11333 Woodglen Ave., Suite 205 Rockville, MD 20852 301.770.0472 http://www.nuscalepower.com Twitter: @NuScale_Power 18 PM-0420-69573 Revision: 0 Copyright 2020 by NuScale Power, LLC.
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LO-0420-69519 April 6, 2020 Docket No.52-048 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 Entitled ACRS Full Committee Presentation: NuScale Topic - Hydrogen/Oxygen Monitoring, PM-0420-69518, 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 April 8, 2020. The materials support NuScales presentation of hydrogen/oxygen monitoring.
The enclosure to this letter is the nonproprietary presentation entitled ACRS Full Committee Presentation: NuScale Topic - Hydrogen/Oxygen Monitoring, PM-0420-69518, Revision 0.
This letter makes no regulatory commitments and no revisions to any existing regulatory commitments.
If you have any questions, please contact Matthew Presson at 541-452-7531 or at mpresson@nuscalepower.com.
Sincerely, Zackary W. Rad Director, Regulatory Affairs NuScale Power, LLC Distribution: Robert Taylor, NRC, OWFN-8H12 Michael Snodderly, NRC, OWFN-8H12 Christopher Brown, NRC, OWFN-8H12 Gregory Cranston, NRC, OWFN-8H12 Michael Dudek, NRC, OWFN-8H12 Getachew Tesfaye, NRC, OEFN-8H12
Enclosure:
ACRS Full Committee Presentation: NuScale Topic - Hydrogen/Oxygen Monitoring, PM-0420-69518, Revision 0 NuScale Power, LLC 1100 NE Circle Blvd., Suite 200 Corvallis, Oregon 97330 Office 541.360-0500 Fax 541.207.3928 www.nuscalepower.com
LO-0420-69519
Enclosure:
ACRS Full Committee Presentation: NuScale Topic - Hydrogen/Oxygen Monitoring, PM-0420-69518, Revision 0 NuScale Power, LLC 1100 NE Circle Blvd., Suite 200 Corvallis, Oregon 97330 Office 541.360-0500 Fax 541.207.3928 www.nuscalepower.com
NuScale Nonproprietary ACRS Full Committee Presentation NuScale Topic Hydrogen/Oxygen Monitoring April 8, 2020 1
PM-0420-69518 Revision: 0 Copyright 2020 by NuScale Power, LLC.
Template #: 0000-21727-F01 R6
Presenters Matthew Presson Licensing Project Manager Jim Osborn Licensing Engineer 2
PM-0420-69518 Revision: 0 Copyright 2020 by NuScale Power, LLC.
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Summary and Conclusions
- Core damage accident is a beyond design basis accident
- Consistent with industry practice, allows nonsafety-related SSCs
- A NuScale core damage accident is low frequency
- Bounding analyses shows there is a minimum of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> before containment can be threatened
- Decision to place system into service would include precautions and follow RG 1.7 risk-informed process
- There is sufficient time to inspect and evaluate system condition
- If leaks develop, can isolate and repair
- Monitoring path can withstand combustion events
- Containment is well-mixed and representative sampling is required 3
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Containment Isolation Failure
- Chapter 19 documents an assessment of whether a severe core damage event with a containment failure could lead to a large release
- The conclusion is that at the earliest possible time of fuel-coolant interaction (FCI), the airborne fraction of volatile fission product aerosols is less than the calculated threshold for a large release.
- 6.8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> is the earliest possible time of FCI for intact containment accidents
- Under the bounding assumption that the containment evacuation system (CES) piping were to be completely sheared at the time of unisolation, it is reasonable to conclude this event would not result in a large release or threaten public safety 4
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Portland Office Richland Office 6650 SW Redwood Lane, 1933 Jadwin Ave., Suite 130 Suite 210 Richland, WA 99354 Portland, OR 97224 541.360.0500 971.371.1592 Charlotte Office Corvallis Office 2815 Coliseum Centre Drive, 1100 NE Circle Blvd., Suite 200 Suite 230 Corvallis, OR 97330 Charlotte, NC 28217 541.360.0500 980.349.4804 Rockville Office 11333 Woodglen Ave., Suite 205 Rockville, MD 20852 301.770.0472 http://www.nuscalepower.com Twitter: @NuScale_Power 5
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LO-0420-69560 April 3, 2020 Docket No.52-048 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 Entitled ACRS Full Committee Presentation: NuScale Topic - Probabilistic Risk Assessment, with a Focus on Emergency Core Cooling System Analysis, PM-0420-69559, 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 April 8, 2020. The materials support NuScales presentation of the probabilistic risk assessment.
The enclosure to this letter is the nonproprietary presentation entitled ACRS Full Committee Presentation: NuScale Topic - Probabilistic Risk Assessment, with a Focus on Emergency Core Cooling System Analysis, PM-0420-69559, Revision 0.
This letter makes no regulatory commitments and no revisions to any existing regulatory commitments.
If you have any questions, please contact Rebecca Norris at 541-602-1260 or at RNorris@nuscalepower.com.
Sincerely, Zackary W. Rad Director, Regulatory Affairs NuScale Power, LLC Distribution: Robert Taylor, NRC, OWFN-8H12 Michael Snodderly, NRC, OWFN-8H12 Christopher Brown, NRC, OWFN-8H12 Gregory Cranston, NRC, OWFN-8H12 Michael Dudek, NRC, OWFN-8H12 Marieliz Johnson, NRC, OWFN, 8H12
Enclosure:
ACRS Full Committee Presentation: NuScale Topic - Probabilistic Risk Assessment, with a Focus on Emergency Core Cooling System Analysis, PM-0420-69559, Revision 0 NuScale Power, LLC 1100 NE Circle Blvd., Suite 200 Corvallis, Oregon 97330 Office 541.360-0500 Fax 541.207.3928 www.nuscalepower.com
LO-0420-69560
Enclosure:
ACRS Full Committee Presentation: NuScale Topic - Probabilistic Risk Assessment, with a Focus on Emergency Core Cooling System Analysis, PM-0420-69559, Revision 0 NuScale Power, LLC 1100 NE Circle Blvd., Suite 200 Corvallis, Oregon 97330 Office 541.360-0500 Fax 541.207.3928 www.nuscalepower.com
NuScale Nonproprietary ACRS Full Committee Presentation NuScale Topic Probabilistic Risk Assessment, with a Focus on Emergency Core Cooling System Analysis April 8, 2020 1
PM-0420-69559 Revision: 0 Copyright 2020 by NuScale Power, LLC.
Template #: 0000-21727-F01 R6
Presenters Rebecca Norris Licensing Project Manager Sarah Bristol Probabilistic Risk Assessment Supervisor 2
PM-0420-69559 Revision: 0 Copyright 2020 by NuScale Power, LLC.
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ACRS Interactions
- March and October 2018 - Overview of NuScale PRA for selected members (Ref. LO-1018-62248, 10/30/18)
- PRA methods, quality process, passive features modeling, human error, multi-module risk
- May-June 2019 -FSAR Chapter 19 Subcommittee and Full Committee (Ref. LO-0519- 65373, 5/09/19; LO-0519-65769, 5/31/19)
- Multiple topics including full committee discussion of passive system reliability
- July 2019 -NuScale site (Corvallis, OR) meeting.
- Multiple topics including results of intermediate ECCS valve testing
- March, 2020 - Phase 5 focus area Subcommittee (Ref. LO-0220-69047, 2/28/20)
- Discussion of ECCS operation 3
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Focus Area Review Topics
- ECCS mechanical configuration
- ECCS valve and inadvertent actuation block (IAB) operation
- ECCS valve testing
- ECCS valve failure modes and probability
- ECCS logic
- ECCS valve generic data sensitivity
- Evaluated the impact of ECCS reliability on select support systems 4
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Outstanding Subcommittee Questions
- Units in sample fault trees (Ref. slide ECCS Valve Logic (Spurious Opening)) are per year
- Fussell-Vesely values (Ref. slide Generic Data Sensitivity): In a sensitivity study including generic data for ECCS valves, there were no new support system risk insights, including consideration for human action risk significance (i.e., FV importance measures)
Reference slides are contained in the presentations submitted as LO-0220-69047, 2/28/20 5
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Acronyms ACRS Advisory Committee on Reactor Safeguards DCA Design Certification Application ECCS emergency core cooling system FSAR Final Safety Analysis Report FV Fussell-Vesely IAB inadvertent actuation block NRC Nuclear Regulatory Commission PRA probabilistic risk assessment 6
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Portland Office Richland Office 6650 SW Redwood Lane, 1933 Jadwin Ave., Suite 130 Suite 210 Richland, WA 99354 Portland, OR 97224 541.360.0500 971.371.1592 Charlotte Office Corvallis Office 2815 Coliseum Centre Drive, 1100 NE Circle Blvd., Suite 200 Suite 230 Corvallis, OR 97330 Charlotte, NC 28217 541.360.0500 980.349.4804 Rockville Office 11333 Woodglen Ave., Suite 205 Rockville, MD 20852 301.770.0472 http://www.nuscalepower.com Twitter: @NuScale_Power 7
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From: mshd.resource@nrc.gov To: Gurr, Amee
Subject:
General Form Submission (30346) Received Date: Friday, April 3, 2020 9:25:15 AM The NRC received your General Form submission on: 04/03/2020 at 12.25 PM. It is being tracked as submission ID# 30346.
If it is a 'Publicly Available' submission after 6 work days from today the submission's attached document(s) will be available for viewing and download from the Agency's Public Web Based ADAMS website (https://adams.nrc.gov/wba) by searching for the following document accession number(s): [ML20094H674]. If this is a 'Non-Public Available' submission the submission's attachment(s) will be retained in NRC's document management system (ADAMS) and will not be published to the public website.
Should you have questions about this submission please contact our Help Desk by phone at 866-672-7640 or by e-mail at Meta_System_Help_Desk.Resource@nrc.gov. When doing so, please refer to the Submission ID# shown above.
Note: The Help Desk is staffed daily from 9:00AM to 6:00PM Eastern Time Monday through Friday (except for Federal holidays)
Chapter 15, Transient and Accident Analyses" Focus Areas on: Boron Redistribution/Return to Power and ECCS NuScale Design Certification Application ACRS Full Committee Meeting April 8, 2020 Non-Proprietary
Agenda
- NRC Staff Review Team
- Long-Term Cooling
- Closure of Unclear Open Items
- Changes to Selected Analyses in Phase 4
- Return to Power
- IORV Analysis
- Boron Redistribution
- Peak Containment Pressure
- Recovery from certain DHRS and ATWS scenarios - Steam System Piping Failure Inside/Outside Containment
- Changes to Design in Phase 4 - Control Rod Misalignment
- NRELAP5 v1.4 - Inadvertent Loading of an
- ECCS Actuation Logic Assembly
- IAB block/release pressure
- ECCS Design
- DHRS Logic
- CNV and RPV Level Instruments
- LOCA Non-Proprietary 2
NRC Staff Review Team
- Chapter 15 Technical Reviewers:
- Antonio Barrett, NRR/DANU - Jeff Schmidt, NRR/DANU
- Andrew Bielen, RES/DSA - Alex Siwy, NRR/DSS
- Tim Drzewiecki, NRR/DANU - Ray Skarda, RES/DSA
- Michelle Hart, NRR/DANU - Jason Thompson, RES/DSA
- Andrew Ireland, RES/DSA - Boyce Travis, NRR/DANU
- Shanlai Lu, NRR/DSS - Carl Thurston, NRR/DSS
- Ryan Nolan, NRR/DSS - Chris Van Wert, NRR/DANU
- Syed Haider, NRR/DSS - Tom Scarbrough, NRR/DEX (containment peak pressure) (ECCS valves)
- Peter Yarsky, RES/DSA (ATWS) - Dinesh Taneja, NRR/DEX (I&C)
Non-Proprietary 3
Closure of Unclear Open Items
- July 10, 2019, Phase 3 Chapter 15 ACRS meeting discussed status of Chapter 15 review
- Listing of 11 Unclear Open Items provided
- The following presentation notes these OI numbers as each is discussed
- Selected additional Phase 2 OIs are also included
- Discussed in February 19, 2020, ACRS SC on LOCA topical report
- OI 15.0.2-4, unclear portion of OI related to staff review of the steam generator heat transfer uncertainty
- Discussed in February 19, 2020, ACRS SC on Non-LOCA topical report Non-Proprietary 4
Return to Power:
GDC 27 Exemption
- Staff took the position in the pre-application Gap 27 letter (ML16116A083) that reliably controlling reactivity in GDC 27 means shutdown as the final state when considering the totality of NRC regulations regarding reactivity control
- Following an initial shutdown, the NuScale reactor can return and maintain criticality during a cool down on the safety-related, passive heat removal systems (DHRS and ECCS) under certain conditions
- Staff drafted SECY-18-0099 which established three return to power criteria to ensure public health and safety
- SAFDLs are met upon a return to power
- Not expected to occur in the lifetime of the module
- The incremental risk to public health and safety from the hypothesized return to criticality at a NuScale facility with multiple reactor modules does not impact Commission goals related to frequencies of core damage or large releases
- NuScale submitted an exemption to GDC 27 and requested approval of a principle design criteria, PDC 27 Non-Proprietary 5
- The reactivity control systems shall be designed to have a combined capability of reliably controlling reactivity changes to assure that under postulated accident conditions and with appropriate margin for stuck rods the capability to cool the core is maintained. Following a postulated accident, the control rods shall be capable of holding the reactor core subcritical under cold conditions with all rods fully inserted
- NuScale revised DCA Chapter 15, Tables 15.0-2, 15.0-3 and 15.0-4 acceptance criterion to ensure that capability to cool the core is maintained refers to meeting the specific acceptable fuel design limits (SAFDLs), including margin for a stuck rod, for all design basis events (DBEs)
Non-Proprietary 6
Return to Power Scenarios
- Three scenarios can potentially lead to a return to power
- DHRS cooldown with dc power (EDSS)
- RPV water level remains above the riser
- RPV water level drops below the riser
- DHRS cooldown without dc power (EDSS)
- ECCS actuation at IAB setpoint
- ECCS cooldown
- Key assumptions in the return to power scenarios
- No operator action
- Only safety-related equipment is used to mitigate the event
- The worst stuck rod is assumed stuck out consistent with GDCs
- A return to power is possible at EOC conditions, but not when significant RCS boron exists (e.g., BOC and MOC conditions)
Non-Proprietary 7
EOC Return to Power Analysis Results
- DHRS cooldown, assuming riser remains covered, and ECCS cooldown return to power
- Return to power is less than 2% rated thermal power
- Significate MCFHR margin exists
- General Design Criterion 10 met
- DHRS cooldown with water level dropping below the riser (riser uncovered) remains subcritical due to sufficient decay heat at 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> (UOI: OI 15.0.5-1)
- Staffs independent confirmatory analysis yielded similar results
- Staff recommended approving the Exemption to GDC 27 Non-Proprietary 8
Potential Non-EOC Return to Power (UOI: OI 15.0.6-5)
- Excess reactivity controlled by soluble boron
- Loss of soluble boron in the core during a cooldown could cause a recriticality similar to the EOC ECCS cooldown scenario
- Core boron can be reduced by:
- Flashing/Liquid Discharge
- Entrainment
- Boron volatility
- Core and riser boron gradient
- Diluted CNV water entering the core Non-Proprietary 9
Return to Power at Non-EOC Analysis Methodology
- Staff review documented in SER Section 15.0.6
- Staff conducted detailed audit and numerous public meetings on topic
- Control volume method using NRELAP5 to calculate fluid transport
- Boron transport informed by NRELAP5 fluid transport
- Methodology uses conservative assumptions to minimize core boron concentration
- Boron mass is removed by conservative treatment of physical phenomenon
- Boron mass is artificially removed to ensure overall methodology conservatism
- Determination of boron loss using NRELAP5 information include:
- Flashing/Liquid discharge
- Entrainment
- Boron volatized and redeposited outside the core
- CNV level
- Riser and core boron gradient evaluated based on NIST-1 and VEERA test data Non-Proprietary 10
Staff Findings Non-EOC Analysis Methodology
- Staff agrees that boron will concentrate in the core/riser region due to boiling
- Staff concluded that boron loss terms informed by NRELAP5 are conservative
- Staff concluded that assuming the elimination of the downcomer and lower plenum boron mass is conservative with regard to core boron concentration
- Boron volatility correlation was reasonable based on the NuScale operating conditions and conservative by not including boron rewetting and return to core
- VEERA test data demonstrates that core boron is uniform once saturated boiling conditions are reached
- Evaluation of a fully diluted water mass (0 ppm) below the saturated boiling core elevation demonstrated the core remained subcritical
- NIST-1 long-term cooling core exit void test data demonstrated that enough two-phase mixing would occur to promote riser and core mixing
- Staff concluded that final core boron concentration at 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> is greater than the initial core RCS boron concentration, maintaining subcriticality
- Staff is aware of a Condition Report written by NuScale dealing with steam space LOCAs Non-Proprietary 11
NuScale Condition Report
- For a steam space LOCA, with DC power available, the current CNV level setpoint may cause a diluted water slug to quickly enter the core upon ECCS actuation due to RPV and CNV water level differences
- An additional source of diluted water in the downcomer, beyond that from the CNV, could be created if the water level drops below the riser due to break inventory loss
- The DHRS, which is expected to be operating, would condense diluted steam into the downcomer
- A diluted water slug from either the CNV, or some combination of CNV and downcomer, could lead to a potential reactivity event
- NuScale is examining new CNV level setpoints and additional ECCS actuation logic to minimize a large RPV and CNV level difference precluding a rapid diluted water slug from entering the core
- An audit plan is currently in place for the staff to review the revised ECCS actuation setpoints
- Staff will engage NuScale to ensure any impacted FSAR sections and analyses are updated as necessary Non-Proprietary 12
Return to Power at Non-EOC 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> 7 days
- Staff considered NuScale capability to cope with potential boron redistribution without the need for additional nonsafety-related equipment for a period of 7 days consistent with SECY-96-128 (RTNSS B).
- Staff reviewed NuScale calculation initial conditions, assumptions, and results.
- Staff agrees there is sufficient decay heat removal and the core would remain subcritical throughout the 7-day period.
- Boration from the CVCS is not required in the first 7 days.
Non-Proprietary 13
Long Term DHRS Operation
- The DHRS is a safety-related heat removal system used to mitigate non-LOCA transient events
- RPV water level may drop below riser elevation following a reactor trip and subsequent cooldown from an AOO or postulated accident
- Without makeup, water level will drop below the riser within 3-6 hours depending on initial conditions and core decay heat
- Staff asked if adequate cooling is maintained when the riser becomes uncovered and if a return to power is possible
- The applicant demonstrated that adequate residual heat removal is maintained and a return to power does not occur within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />
- The original applicant response did not address the potential for dilution of the downcomer when the riser becomes uncovered during extended DHRS operation
- Staff has requested the applicant to evaluate the potential of downcomer dilution leading to a return to power during extended DHRS operation while resolving its CR Non-Proprietary 14
Long Term DHRS Operation Recovery
- In a riser uncovered scenario, some water vapor will condense on the exposed steam generator tubes
- This has the potential to dilute the downcomer over a long period of time as water vapor is assumed to have a negligible boron concentration
- The rate of downcomer dilution is limited by the fraction of steam generator surface area uncovered
- Boron volatility, entrainment and rewetting may help limit downcomer dilution but are not quantified
- Potential exists that reestablishing single-phase natural circulation could transport the diluted downcomer to the core causing a potential re-criticality
- Reestablishing RPV water level above the riser after extended DHRS operation requires the operator to initiate action to recover the module through the addition of water
- Post-accident module recovery is not required to be evaluated in Chapter 15 design basis review Non-Proprietary 15
Long Term DHRS Operation Recovery (cont)
- NuScale has indicated the recovery of an NPM following extended DHRS operation will be procedurally controlled
- Plant procedures are not part of the DCA review
- Procedures would be developed by the COL applicant or holder
- Chapter 13 COL item addresses the development of operating procedures
- Staff believes procedures could be developed to adequately address recovery from this condition
- Plant design allows for the following operational strategies that could address recovery from this condition:
- Mixing core and downcomer boron concentration by simultaneous injection and letdown preserving RCS level
- Downcomer boron concentration sampled to ensure adequate mixing before single-phase natural circulation is reestablished
- Confirming adequate shutdown margin before restoring level Non-Proprietary 16
ATWS Scenario
- Loss of A/C causes the feedwater pump and turbine to trip.
- Control rods are assumed to fail to insert.
- RPV pressure increases due to loss of heat sink.
- High RPV pressure trips the DHRS to activate
- RPV inventory is lost by lifting the RSVs and discharging into containment
- ATWS is not considered a design basis event (DBE) due to the design of the reactor trip system within the MPS lowering the probably of occurrence below 1.0E-5 per reactor year (see SER Section 15.8)
Non-Proprietary 17
ATWS Mitigation
- Two ATWS scenarios are possible:
- Operators insert control rods early in the event
- Operators delay or take no action to mitigate the ATWS
- In both cases, the RSVs relieve pressure and discharge into containment
- If operators insert the control rods early in the transient as expected, the ATWS event progression resembles the long term DHRS cooldown scenario with the riser potentially becoming uncovered
- If operators delay or take no actions to insert the control rods, enough RPV inventory is lost, the level drops below the riser -
breaking natural circulation and establishing a new equilibrium power.
- A safe state is reached and collapsed liquid level remains above the top of the active fuel Non-Proprietary 18
ATWS Mitigation and Recovery
- If operator acts to insert rods before CNV inventory reaches the lowest CNV level ECCS setpoint, the event recovery would be the same as a DBE DHRS cooldown
- Staffs conservative analysis demonstrates the lowest CNV level is reached in approximately 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />
- The likelihood of operators failing to insert the control rods within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> is highly unlikely
- If the operator could not insert control rods after reaching the lowest CNV level ECCS setpoint additional analysis maybe needed to determine the appropriate operator actions
- Operator actions to recover the plant following a beyond design event are not within the scope of the DCA review and are developed by the COL applicant or holder
- Chapter 13 COL item addresses the development of operating procedures Non-Proprietary 19
Return to Power with Ejected Rod (UOI: OI 15.0.6-6)
- DCA does not address the potential return to power following a postulated rod ejection
- Rod Ejection is evaluated for the short term reactivity response only
- Consistent with the requirement in GDC 28 and the guidance in SRP 15.4.8 to appropriately limit the rate of reactivity increases associated with certain postulated reactivity accidents, including rod ejection
- Primarily a check of loading pattern and control rod design such that a coolable geometry is maintained
- The staff determined that the provisions in GDC 27 for evaluating DBAs in the long term are met for the NuScale design because:
- Control rod ejection accident need not be considered in the long term due to the robust design of the control rod drive housings
- The staff evaluated the control rod housing design in SER Section 3.9.4 Non-Proprietary 20
Long-Term Cooling Analysis
- Two LTC situations evaluated by NuScale
- DHRS and ECCS cooling
- Staff review documented in SER Section 15.0.5 and 15.6.5
- LTC methodology documented in technical report incorporated by reference into DCD Chapter 1
- LTC technical report methodology addresses the ECCS cooling after recirculation is established
- LTC methodology assumes subcriticality; return to power addressed in DCD Section 15.0.6
- Phase 2 SER included OI (UOI:15.0.5-2) as LTC technical report had stated cooling was demonstrated to 30 days
- NuScale revised statement and staff SER documents review to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />
- FOM include minimum collapsed level, minimum RPV temperature, to preclude boron precipitation, and maximum cladding temperature
- All FOM met acceptance criteria Non-Proprietary 21
Changes to Design in Phase 4
- Staff reviewed impact of design/method changes on Chapters 6 & 15 during Phase 4
- NRELAP5 v1.4 & NPM Model Rev. 2 (UOI: OI 15.0.2-1)
- ECCS Actuation Logic (UOI: OIs 15.0.0.4-1, 15.6.5-1)
- IAB block/release pressure
- DHRS Logic (UOI: OIs 15.0.0.4-1, 15.6.5-1)
- Updated analysis results provided for impacted events in DCD Rev. 3
- Staff audited revised calculations Non-Proprietary 22
Changes to Design in Phase 4 NRELAP5 and NPM Base Model changes (NRELAP5 v1.4, Base Model Rev. 2)
- Reviewed by staff in LOCA topical report during Feb. 19, 2020 ACRS subcommittee meeting ECCS Logic changes
- Removed actuation on riser low level
- Actuation only on either loss of DC power, high CNV water level, or low AC voltage after 24 hrs, or new added logic per NS cond. Report
- CNV water level ECCS trip increased by 24 but now decreased per cond. Report IAB Block/Release Pressure changes
- IAB release 950 psid (+/-50 psi), IAB blocks 1300 psid DHRS Logic changes
- DHRS signal split into two signals (DHRS actuation and Secondary isolation (SSI))
- Direct DHRS actuation inputs reduced from 13 to 4 signals, high (1) RCS press, (2) temp, (3) steam press, and (4) low AC voltage to batteries, function opens DHRS valves and closes primary and secondary MSIV and bypass, MFIVs and MFRVs
- Allows better operator control at startup, reduce frequency of actuation
- Delays DHRS actuation until much later in transient; min change to Chapter 15 FOM margins Non-Proprietary 23
Changes to Selected LOCA Analyses DCA Rev. 2 DCA Rev. 3 Acceptance Chapter Event Figure of Merit Value Value Criteria Limit 15.6.5 (LOCA-DBE)** MCHFR 1.80 1.72 1.29 Min CLL (ft) 0.14 1.7 >TAF 15.6.6 (IORV-AOO)** MCHFR - 1.32 1.13 Min CLL (ft) - 10.2 >TAF Peak Pressure 6.2 (Cont. Design)** 951 994 1050 (RRV) (psia)
Peak Temperature - 526 550 (Inj line brk) (°F)
Changes to Selected Non-LOCA Analyses DCA Rev. 2 DCA Rev. 3 Acceptance Chapter Event Figure of Merit Value Value Criteria Limit MCHFR 1.861 1.866 AOO: 1.284*
15.1.5 - Steam Line Break Maximum RCS AOO: 2310*
2156 2081 (PA)** Pressure (psia) PA: 2520 Maximum SG Pressure AOO: 2310*
1346 1495 (psia) PA: 2520 15.4.3 - Control Rod Misoperation MCHFR 2.509 1.437 1.284 (Misalignment) (AOO) 15.4.7 - Inadvertent Loading and Operation of a Fuel Assembly in MCHFR 1.916 1.437 1.284 an Improper Position (AOO)
- Although a steam line break is a postulated accident, it meets the AOO acceptance criteria.
- To be evaluated for impact of ECCS setpoint change Non-Proprietary 25
ECCS Design: Water Hammer &
follow-up testing
- ECCS Valves Trip Valve Hydraulic Line
- 1. Different trip valve hydraulic line length for each valve
- 2. Fluid inside the lines experiences two-phase flashing
- 3. Staff requested full scale, high temperature and high pressure tests to confirm no water hammer effects
- NuScale has stated that the temperature of the ECCS valves and their hydraulic lines will remain above the precipitation temperature of boron during plant operation.
- NuScale plans to flush the ECCS valves and their hydraulic lines during each refueling outage to remove any particulates that might unexpectedly accumulate during plant operations.
Non-Proprietary 26
CNV and RPV Level Instruments Level Transmitter Indicated Range Nominal Function Safety & Risk (Span) (100% RTP) Classification
[Process Range]
Containment 0 to 100% 0% ECCS Actuation A1 Water Level (683.5 Inches) 264 to 3002 High Level
[approx. 220 to 903.5 Inches1] L-1 Interlock
>540 & RT-1 active (Reactor Trip Breakers Open)
PAM Variable Type B, C, D Pressurizer Level3 0 to 100% 50% Reactor Trip A1 (130.1 Inches) 80% High Level
[Full height of PZR] 35% Low Level Secondary Sys Isolation 20% Low-Low Level Containment Sys Isolation 20% Low-Low Level Demin Water Sys Isolation 80% High Level 35% Low Level CVCS Isolation 80% High Level 20% Low-Low Level Pressurizer Heater Trip 35% Low Level L-2 Interlock
>20% & T-3 active (RCS Thot <350F)
RPV Riser Level 0 to 100% 100% PAM Variable B24 (554.9 Inches) Type B, C, D
[Top of upper core plate to top of PZR]
[1] Levels are reported in terms of module elevation with the global zero elevation at the bottom of the reactor pool.
[2] The ranges allow +/-18" from the nominal ECCS level setpoint of 282 TBD based on cond. report
[3] Common Level Transmitter is used for Pressurizer Level and RPV Riser Level
[4] Common Level Transmitter is used for Pressurizer Level and RPV Riser Level. However, function of RPV Riser Level is classified as B2 Non-Proprietary 27
CNV and RPV Level Non-Proprietary 28
- AC alternating current
- MCHFR minimum critical heat flux ratio
- MOC middle of cycle
- MPS module protection system
- MFIV main feedwater isolation valve
- BOC beginning of cycle
- CLL collapsed liquid level
- MSIV main steamline isolation valve
- COL combined license
- NPM NuScale Power Module
- CNV containment vessel
- OI open item
- CVCS chemical and volume control system
- PA Postulated Accident
- DBA design basis accident
- PDC principal design criteria
- DBE design basis event
- PZR pressurizer
- DCA design certification application
- DHRS decay heat removal system
- RSV reactor safety valve
- EDSS highly reliable dc power system
- RTP rated thermal power
- EOC end of cycle
- RTNSS regulatory treatment of non-safety systems
- FOM figure of merit
- SAFDL specified acceptable fuel design limits
- FSAR final safety analysis report
- SER safety evaluation report
- GDC general design criteria
- IAB inadvertent actuation block
- SRP standard review plan
- IORV inadvertent opening of a RPV valve
- TAF top of active fuel
- LOCA loss of coolant accident
- UOI unclear open item
- LTC long term cooling Non-Proprietary 29
Presentation to the ACRS Committee NuScale Power, LLC (NuScale)
Design Certification Application Review Safety Evaluation with No Open Items:
H2 and O2 Post-accident Monitoring 8 April 2020
Technical Reviewers:
Anne-Marie Grady, NRR/DRA/APLC Edward Stutzcage - NRR/DRA/ARCB Michelle Hart, NRR/DANU/UART Project Managers:
Greg Cranston - Lead Project Manager Getachew Tesfaye - Chapter Project Manager April 8, 2020 2
Focus Area - ACRS AST letter Need for long-term post-accident H2 and O2 monitoring.
Informs the timing of the following actions:
Inert the containment atmosphere with nitrogen via CVCS and DNS or Vent the containment during accident conditions (i.e., routing the gas either to the plant exhaust stack (RBVS) or to the gaseous radwaste system (GRWS).
Confirms success of above mitigating actions Inform the actions in the EOP and the severe accident management guidelines (SAMG) 3
ACRS AST letter and related topics Need for long-term post-accident H2 and O2 monitoring.
Informs the timing of operator action to avoid:
Risking an impulse pressure to the inside of the CNV, which, at 45 days:
would be approximately double the impulse pressure at 72 hrs, and could lead to CRDM access flange (CNV25) bolt load exceeding the ASME Service Level D strain limits Risking an uncontrolled release to the public.
April 8, 2020 4
Focus Area - ACRS AST letter Capability of the design for accurate long-term post-accident H2 and O2 monitoring.
The H2 and O2 monitoring closed loop flowpath is established by:
Confirming CNV pressure is < 250 psig (design pressure of CES, PSS, and CFDS)
Unisolating the CES and the CFDS CIVs Creating a flow path from the CNV via CES through the PSS sample pump and in-line gas monitors, and returning to the CNV via CFDS.
This flowpath, except for the CIVs, is non-safety related, as is acceptable for equipment specifically used for mitigating a severe accident, per SECY-90-016, Equipment survivability.
April 8, 2020 5
Focus Area - ACRS AST letter Comments about the rationale for long-term post-accident H2 and O2 monitoring in 20 December 2019 ACRS letter (Item b):
Weeks are available before monitoring information is needed to inform mitigating actions.
Staff elaboration:
Combustible mixtures (5% O2) would occur by 45 days post-accident The minimum concentration (4% O2) would occur by 30 days Prior to reaching combustible mixtures (O2 > 3%) would occur in 15 da (Item d):
other pressure, temperature and radiation sensors available to follow severe accident progression None of these components indicates potential for combustion of gases.
April 8, 2020 6
Focus Area - ACRS AST letter ACRS comments about alternatives to long-term post-accident H2 and O2 monitoring that dont unisolate the containment The options for actions which prevent combustible/detonable conditions in containment all include reopening isolation valves:
Inerting by injecting N2 into the containment via the CVCS or Venting the containment by using the CES system and directing the gas to the RBVS stack or the GRWS No alternatives have been provided or identified by NuScale to obtain the concentration in containment of the combustibles, H2 and O2 without unisolating the CNV.
April 8, 2020 7
Focus Area Topics Post-accident monitoring of O2 and H2 risk evaluation Operator action to Time for operator H2O2 monitoring Prevent DDT prevent H2 Result action path isolable? pressure pulse combustion DDT Opening CNV will vent CNV via 3days< t <15 days yes yes not lead to large CES+RBVS release Opening CNV will inert CNV via 3days< t <15 days yes yes not lead to large CVCS+DNS release potential failure of CRDM access take no action N/A N/A no flange bolts after 15 days April 8, 2020 8
Focus Area - ACRS AST letter The staff believes that the information obtained from monitoring is beneficial in assisting operators in making decisions following an accident.
The staff does not currently have enough information from NuScale such as system flow rate, system leakage rate, ventilation flow rate, room volumes, the specifics of the piping and equipment, etc., to be able to estimate the dose to an individual performing actions to re-isolate the systems.
Therefore, the staff believes that at this stage of licensing the best path forward is to retain the rulemaking carveout.
April 8, 2020 9
Probabilistic Risk Assessment NuScale Design Certification Application ACRS Full Committee Meeting April 8, 2020
Topics
- PRA review status
- Summary of March 3, 2020 Meeting
- ECCS model
- Sensitivity and uncertainty analyses
- Reactor building crane operations 2
PRA Review Status
(1) anticipated design changes for boron redistribution issues (2) events leading to riser uncovery
- PRA Staff will finalize its findings on the NuScale PRA after evaluation of the submitted DCA changes.
3
- Verify applicant documented risk-informed insights
- The designs robustness, levels of defense-in-depth, and tolerance of severe accidents initiated by either internal or external events
- The risk significance of potential human errors associated with the design
- Determine how risk compares against Commissions goals of less than 1x10-4 per year for CDF and less than 1x10-6 per year for LRF.
- Use results and insights to support programs such as RTNSS, ITAAC, RAP, TS, COL action items, and interface requirements.
- Staff findings are made to support Commissions objectives for use of PRA in design.
4
Availability of Information at Various Licensing Stages Licensing Stage DC Applications 52.47(27) COL Holders 50.71(h)(1) COL Holders 50.71(h)(2)
COL Applications 52.79(46) fuel load PRA 1st four-year update Information Availability
- Layout, cable routing, equipment capacities Not fully known Known Known
- Plant-specific None Available Available operating guidance
- Plant operating None None Available experience
- Trainers or operations staff with plant- None None Available specific experience
- Walkdowns Not possible Possible Possible PRA acceptability
- RG 1.200, as modified by
- RG 1.200 guidance DC/COL-ISG-028
- Portions of DC/COL-ISG-
- DC/COL-ISG-028 not 028 are still relevant applicable 5
ECCS Model
- Assumptions are used to address issues associated with level of detail, completeness, and data
- System/component reliability data is uncertain due to unavailability of design-specific operating experiences
- Staff evaluated assumptions for impact on safety findings made for the DCA
Sensitivity and Uncertainty Analyses
- Sensitivity and uncertainty analyses have been performed to support regulatory findings
- NuScale identified important SSCs, operator actions, and risk insights to support programs such as DRAP and human factors engineering
- Additional analyses will consider additional risk insights and inputs to operational programs expected at DC stage, if any 7
Reactor Building Crane Operations Calculated drop probability dominated by:
Operator errors (over speed, over raise, etc.)
AND Failure of instrumentation (interlocks/switches) for safety stop Key Assumptions for the LPSD PRA added to DCA, Rev 4, Table 19.1-71
- 1. Movement of the RBC is modeled as being operator controlled
- 2. Administrative controls will ensure that RBC safety features (e.g., limit switches, interlocks to prevent undesired movement) are functional during module movement Validity of RBC assumptions in DCA and crane data supporting the PRA will be confirmed by COL applicant per COL item 19.1-8 RBC is within scope of human factors process during COL per Human Factors Engineering Design Implementation Plan (Report RP-0914-8544)
Risk significance of RBC resulted in additional ITAACs 8
Abbreviations
- ASME - American Society of
- EPZ - emergency planning zone Mechanical Engineers
- ITAAC - Inspection, Test, Analysis, and
- CDF - core damage frequency Acceptance Criteria
- CIV - containment isolation valve
- ISG - Interim Staff Guidance
- COL - combined license
- LPSD - low power and shutdown
- CVCS - chemical and volume control
- LRF - large release frequency system
- DC - design certification
- RAP - Reliability Assurance Program
- DCA - design certification application
- RBC - reactor building crane
- DHRS - decay heat removal system
- RG - Regulatory Guide
- DRAP - Design Reliability Assurance
- RSV - reactor safety valve Program
- SER - safety evaluation report
- ECCS - emergency core cooling
- SRP - standard review plan system
- TS - Technical Specification 9