ML17178A301
| ML17178A301 | |
| Person / Time | |
|---|---|
| Site: | Browns Ferry  |
| Issue date: | 06/07/2017 |
| From: | Advisory Committee on Reactor Safeguards |
| To: | |
| Wang W | |
| References | |
| NRC-3113 | |
| Download: ML17178A301 (219) | |
Text
Official Transcript of Proceedings NUCLEAR REGULATORY COMMISSION
Title:
Advisory Committee on Nuclear Safeguards Open Session Docket Number: N/A Location: Rockville, Maryland Date: June 7, 2017 Work Order No.: NRC-3113 Pages 1-182 NEAL R. GROSS AND CO., INC.
Court Reporters and Transcribers 1323 Rhode Island Avenue, N.W.
Washington, D.C. 20005 (202) 234-4433
1 1
2 3
4 DISCLAIMER 5
6 7 UNITED STATES NUCLEAR REGULATORY COMMISSIONS 8 ADVISORY COMMITTEE ON REACTOR SAFEGUARDS 9
10 11 The contents of this transcript of the 12 proceeding of the United States Nuclear Regulatory 13 Commission Advisory Committee on Reactor Safeguards, 14 as reported herein, is a record of the discussions 15 recorded at the meeting.
16 17 This transcript has not been reviewed, 18 corrected, and edited, and it may contain 19 inaccuracies.
20 21 22 23 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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1 1 UNITED STATES OF AMERICA 2 NUCLEAR REGULATORY COMMISSION 3 + + + + +
4 644TH MEETING 5 ADVISORY COMMITTEE ON REACTOR SAFEGUARDS 6 (ACRS) 7 OPEN SESSION 8 + + + + +
9 WEDNESDAY 10 JUNE 7, 2017 11 + + + + +
12 ROCKVILLE, MARYLAND 13 + + + + +
14 The Advisory Committee met at the Nuclear 15 Regulatory Commission, Two White Flint North, Room 16 T2B3, 11545 Rockville Pike, at 8:30 a.m., Dennis C.
17 Bley, Chairman, presiding.
18 COMMITTEE MEMBERS:
19 DENNIS C. BLEY, Chairman 20 MICHAEL L. CORRADINI, Vice Chairman 21 PETER RICCARDELLA, Member-at-Large 22 RONALD G. BALLINGER, Member 23 MARGARET CHU, Member 24 WALTER KIRCHNER, Member 25 JOSE MARCH-LEUBA, Member NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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2 1 DANA A. POWERS, Member 2 HAROLD B. RAY, Member 3 JOY REMPE, Member 4 GORDON R. SKILLMAN, Member 5 JOHN W. STETKAR, Member 6 MATTHEW W. SUNSERI, Member 7
8 DESIGNATED FEDERAL OFFICIAL:
9 CHRISTOPHER BROWN 10 11 ALSO PRESENT:
12 TONY AHN, KHNP 13 JIM ANDRACHEK, WEC/PWROG 14 DENNIS ANDRUROT, NRO 15 SURINDER ARORA, NRO 16 CLINTON ASHLEY, NRO 17 AYO AYEGBUSI, NRO 18 WILLIAM BAKER, TVA 19 DANIEL BARSS, NSIR 20 BEN BEASLEY, NRR 21 BRIAN BENNEY, NRR 22 STEVE BONO, TVA 23 MICHAEL BREACH, NRR 24 KATHRYN BROCK, NRR 25 MARK BLUMBERG, NRR NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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3 1 JOHN BUDZYNSKI, NRO 2 DENNY CAMPBELL, TVA 3 PAUL CLIFFORD, NRR 4 MATTHEW DEGONISH, WEC 5 JOE DEMARSHALL, NRO 6 ANTONIO DIAS, NRO 7 MICHAEL DICK, TVA 8 THINH DINH, NRO 9 STEPHEN DINSMORE, NRR 10 PETE DONAHUE, TVA 11 GERALD (GERRY) DOYLE, TVA 12 RAY DREMEL, Enercon 13 ASHLEY FERGUSON, NRO 14 CJ FONG, NRR 15 VIJAY GOEL, NRR 16 ANNE-MARIE GRADY, NRO 17 DAN GREEN, TVA 18 SYED I. HAIDER, NRO 19 STEPHEN HAMBRIC, Penn State University*
20 CHARLES HARBUCK, NRR 21 MICHELLE HART, NRO 22 RUSS HASKELL, NRR 23 ALFRED HATHAWAY, NRR 24 TREY HATHAWAY, RES 25 MICHELLE HAYES, NRO NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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4 1 RAUL HERNANDEZ, NRO 2 VICTORIA HUCKABAY, NRR 3 DANIEL (LANG) HUGHES, TVA 4 SCOTT HUNNEWELL, TVA 5 SEOKHWAN HUR, KEPCO E&C 6 ATA ISTAR, NRO 7 DIANE JACKSON, NRO 8 HYEOK JEONG, KEPCO E&C 9 JOSHUA S. KAISER, NRR 10 SANGHO KANG, KEPCO E&C 11 JUNGHO KIM, KHNP 12 TAE HAN KIM, KEPCO E&C 13 YUNHO KIM, KHNP 14 MYUNGRO KIM, KEPCO 15 LARRY KING, GE-Hitachi*
16 MICHAEL LAPRESTI, WEC 17 HIEN LE, NRO 18 SANYUM LEE, KHNP 19 JEFFERY LEWIS, TVA 20 CHANG-YANG LI, NRO 21 DAEHEON LIM, KEPCO E&C 22 KWANGIL LIM, KEPCO E&C 23 ROY LINTHICUM, PWROG 24 MARK LINTZ, NRO 25 CHRISTIANA LUI, ACRS NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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5 1 SARA LYONS, NRR 2 GREG MAKAR, NRO 3 DAVID MCBURNEY, AREVA/TVA 4 MIKE MCCOPPIN, NRO 5 ALAN MEGINNIS, AREVA/TVA 6 DAMIAN MIRIZIO, PWROG 7 SHANDETH MONTGOMERY, ACRS 8 CHING NG, NRR 9 JIYONG (ANDY) OH, KHNP 10 ERIC OESTERLE, NRR 11 NGOLA OTTO, NRR 12 MATHEW PANICKER, NRR 13 DAN PAPPONE, GE-Hitachi 14 CHAN EOK PARK, KEPCO E&C 15 SUNWOO PARK, NRO 16 HANH PHAN, NRO 17 SHEILA RAY, NRR 18 MUHAMMAD RAZZAQUE, NRR 19 JAMES ROSS, AECOM/KHNP 20 GREGORY ROZGA, Enercon 21 FARIDEH SABA, NRR 22 AHSAN SALLMAN, NRR 23 JASON SCHAPEROW, NRO 24 ED SCHRULL, TVA 25 VIKRAM SHAH, Argonne National Lab*
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6 1 SIMON SHENG, NRR 2 ROB SISK, WEC 3 JAMES STECKEL, NRO 4 GREG STOREY, TVA 5 COURTNEY ST. PETERS, NRO 6 ANGELO STUBBS, NRO 7 ED STUTZCAGE, NRO 8 FRANCIS TALBOT, NRO 9 GETACHEW TESFAYE, NRO 10 MATT THOMAS, NRO 11 BOYCE TRAVIS, NRO 12 IAN TSENG, NRR 13 JESSICA UMANA, NRO 14 ANDREA D. VEIL, Executive Director 15 ROBERT VETTORI, NRO 16 HANRY WAGAGE, NRO 17 DAVE WAGNER, AECOM 18 GEORGE WANG, NRO 19 BILL WARD, NRO 20 SUNIL WEERAKKODY, NRR 21 WANG WEIDONG 22 BILL WILLIAMSON, TVA 23 ROBERT WOLFGANG, NRR 24 TAO WU, GE-Hitachi*
25 AARON WYSOCKI, ORNL NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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7 1 ZUHAN XI, NRO 2 JINKYOO YOON, KEPCO E&C 3 SAMIR ZIADA, McMaster University*
4 5 *Present via telephone 6
7 8
9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 1 T-A-B-L-E O-F C-O-N-T-E-N-T-S 2
3 Opening Remarks by ACRS Chairman 4 Dennis Bley.................................... 10 5 Advanced Power Reactor 1400 (APR1400) 6 Remarks by the Subcommittee Chairman 7 Ronald Ballinger............................... 12 8 Briefing and Discussion by Korea Hydro & Nuclear 9 Power 10 Yunho Kim...................................... 12 11 Briefing and Discussion by NRC staff 12 Bill Ward...................................... 70 13 Jessica Umana.................................. 75 14 Getachew Tesfaye............................... 92 15 James Steckel.................................. 94 16 Browns Ferry Extended Power Uprate Application 17 Remarks by the Subcommittee Chairman 18 Briefings by and discussion with representatives 19 of the NRC staff and Tennessee Valley Authority 20 regarding the safety evaluation associated with 21 the Browns Ferry EPU 98 application 22 Public Comment.................................. 126 23 Westinghouse Generation III Shutdown Seal........167 24 Staff Evaluation Overview....................... 168 25 Assessment of Topical Report.................... 167 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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9 1 PWR Owners Group Overview....................... 173 2 Public Comment.................................. 182 3
4 5
6 7
8 9
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10 1 P-R-O-C-E-E-D-I-N-G-S 2 8:30 a.m.
3 CHAIRMAN BLEY: The meeting will now come 4 to order. This is the first day of the 644th meeting 5 of the Advisory Committee on Reactor Safeguards.
6 Before we get to today's business, it's my 7 pleasure to welcome Ms. Shandeth Montgomery to the 8 ACRS staff as a program assistant. She joined the NRC 9 back in 2008 and brings her extensive background in 10 agency administration to the Committee. Her most 11 recent assignment was in the Human Resources Office.
12 Welcome, Shandeth.
13 (Applause.)
14 CHAIRMAN BLEY: During today's meeting the 15 Committee will consider the following: (1) Advanced 16 Power Reactor 1400, the APR1400, the Browns Ferry 17 extended power uprates, the Westinghouse proprietary 18 topical report on PRA model for the Generation III 19 Westinghouse shutdown seal, and preparation of ACRS 20 reports.
21 The ACRS was established by statute and is 22 governed by the Federal Advisory Committee Act. That 23 means the Committee can only speak through its 24 published letter reports.
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11 1 support our deliberations. Interested parties who 2 wish to provide comments can contact our offices 3 requesting time after the Federal Register notice 4 describing the meeting is published. That said, we 5 will also set aside 10 minutes for spur-of-the-moment 6 comments from members of the public attending or 7 listening to our meetings. Written comment are also 8 welcome.
9 Mr. Christopher Brown is the designated 10 federal official for the initial portion of this 11 meeting.
12 Portions of the sessions on the APR1400, 13 Browns Ferry extended power uprates and the 14 Westinghouse proprietary topical report may be closed 15 in order to discuss and protect information designated 16 as proprietary.
17 The ACRS section of the U.S. NRC public 18 web site provides our charter, bylaws, letter reports 19 and full transcripts of all Full and Subcommittee 20 meetings including all slide presentations at the 21 meetings.
22 We have received no written comments or 23 requests to make oral statements from members of the 24 public regarding today's sessions.
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12 1 preclude interruption of the meeting the phone will be 2 placed in a listen-in mode during presentations and 3 committee discussions.
4 A transcript of portions of the meeting is 5 being kept and it is requested that speakers use one 6 of the microphones, identify themselves and speak with 7 sufficient clarity and volume to be readily heard.
8 At this time we'll take up the issue of 9 the APR1400 and I'll turn the meeting over to 10 Professor Ballinger.
11 Ron?
12 MEMBER BALLINGER: Thank you, Mr.
13 Chairman.
14 Today we will hear presentations by KHNP 15 and the staff on Chapters, 6, 12, 13, 14, 16, 17 and 16 19. The schedule has evolved a little bit. Right now 17 there will be no closed session. Everything will be 18 open so that if it comes to a question or answer that 19 involves proprietary information, the presenters will 20 have to let us know so that we can make adjustments to 21 the audience, if need be.
22 But now I'll turn it over to Bill Ward.
23 CHAIRMAN BLEY: Okay. And we'll hold 24 those to the end of the session. If we need to go 25 into closed session --
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13 1 MEMBER BALLINGER: Okay.
2 CHAIRMAN BLEY: -- we'll do it at that 3 time.
4 MEMBER BALLINGER: Okay. Fine.
5 Bill?
6 MR. WARD: Yes, thank you. The staff is 7 happy to present to the Full Committee here. We're 8 very anxious to keep moving. We have a 42-month 9 schedule and everything's moving along pretty well.
10 We think we have a short, but good presentation for 11 today and we hope that we can answer all your 12 questions. And thank you again.
13 MEMBER BALLINGER: Okay. So KHNP?
14 MR. Y. KIM: Yes, thank, Mr. Chairman and 15 Mr. -- Dr. Ballinger for -- also for your review of 16 all the ACRS members.
17 Today I am going to present for Chapter 6, 18 12, 13, 14, 16, 17 and 19. So let me start on Chapter 19 6 about engineer safety feature. So engineer safety 20 feature materials are selected for compatibility with 21 core cooling components and containment spray 22 solution. The list of material is in the Table 6.1-1 23 and 2. The protective coating of APR1400 is listed in 24 the Table 6.1-3 and they then meet Reg Guide 1.54.
25 For the containment system the containment NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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14 1 of APR1400 is prestressed concrete with a cylindrical 2 shell and dome. It is designed such that peak 3 pressure is less than design pressure and well below 4 half of the peak pressure within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after the 5 accident. The leakage of containment is also below 6 the design leakage rate.
7 For the APR1400 containment pressure and 8 temperature analysis GOTHIC is used with assumption 9 and initial conditions to maximize the containment 10 peak pressure and the temperature. The analysis are 11 performed for a total of LOCA and steam line break 12 case feature selected for sensitivity study on 13 barriers, break size and power levels.
14 For the containment sub-compartment 15 analysis we analyzed at the place with use of COMPARE-16 MOD1A in response to high energy line break in each 17 sub-compartment. Through the analysis we also 18 performed the map.
19 The structure test is based on ASME CC-20 6000 and the leak-tight test is based on Reg Guide 21 1.163.
22 The containment heat removal system 23 reduces pressure and the transient following steam 24 line break and LOCA and the remove fission product 25 from containment atmosphere following LOCA.
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15 1 The function of combustible gas control in 2 containment is to control the hydrogen concentration 3 in containment and IRWST below 10 percent by volume 4 during severe accident with PARs and igniters.
5 Let's move next, please. For the safety 6 injection system this system consist of four 7 independent trains and two diagonal trains. Trains 1 8 and 3 or trains 2 and 4 are required to mitigate the 9 loss of coolant accident. APR1400 safety injection 10 tank without fluidic device to eliminate the low 11 pressure safe injection pump by extending the 12 discharge time. KHNP got approval for the fluidic 13 device topical report recently. The operability of 14 safety injection system is checked through Tech Spec 15 3.5.1 through 5.
16 For the hability system the APR1400 are 17 designed to allow control room operators to remain in 18 the control room envelope and take action to operate 19 the plant safely under normal and maintain it in a 20 safe condition under design-basis accident conditions.
21 And the APR1400 hability system protect control room 22 operator from outside airborne radioactivity.
23 MEMBER POWERS: I am still unsure how you 24 look at the dispersion under DBA conditions of 25 radioactivity.
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16 1 MR. Y. KIM: Could you -- I cannot hear 2 you. Could you --
3 MEMBER POWERS: I am still unclear exactly 4 how you calculate the dispersion of radioactivity 5 under DBA conditions to the main control room.
6 MR. KANG: My name is Sangho Kang, KEPCO 7 E&C In the DCD Section 2.3.4 we calculated the on-site 8 dispersion of the LOCA condition of radioactive 9 material, so based on the ARCO 96 model, which is 10 developed by U.S. NRC, the concentration at the intake 11 location of the main control room is calculated.
12 MR. Y. KIM: Yes. Now let me continue.
13 So the exposure to MCR personnel meet the occupation 14 dose limit of 50 millisievert. That is page 17 and 15 Reg Guide 1.183.
16 Go to next, please. The APR1400 17 engineered safety features filter system are designed 18 to mitigate the consequence of postulated accident by 19 filtering radioactive particulate and iodine from air 20 and meet the requirement of Reg Guide 1.52, and ASME 21 N509, and ASME AG-1.
22 The filter system include control room 23 emergency makeup air cleaning system, auxiliary 24 building controlled air emergency exhaust system and 25 the fuel handling area emergency exhaust system.
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17 1 For the containment spray system TSPs 2 stores at the holdup volume tank that enabled the 3 IRWST remains above pH 7 during 30 days in LOCA 4 condition.
5 MEMBER POWERS: I am not sure why I should 6 be confident that the pH will remain above 7 for 30 7 days. Why are we confident of that?
8 MR. KANG: I think the -- our program's 9 calculation to see the capability to maintain the pH 10 of greater than seven was performed -- the purpose of 11 this calculation to estimate the time to reach the pH 12 greater than seven. But during the staff's review we 13 got the comments that the -- can we make sure that the 14 pH value can last for the whole duration of the 15 accident? That's why we performed the analysis and 16 the -- we performed that the pH value of greater than 17 seven is maintained during the 30 days after the loss 18 of coolant accident. It was responded by our RAI 19 response to the staff's issue.
20 VICE CHAIR CORRADINI: Can we get the RAI 21 number that we can just at least look at that?
22 MR. KANG: I don't remember now, but --
23 VICE CHAIR CORRADINI: That's fine.
24 MR. KANG: -- we can get it.
25 VICE CHAIR CORRADINI: If we can get it.
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18 1 MEMBER POWERS: I would be interested in 2 things like what you used for G values for nitric acid 3 formation, G values for cable insulation 4 decomposition, and especially how you treat phosphate 5 precipitation by interaction with containments coming 6 into the IRWST.
7 MR. KANG: So in order to calculate the pH 8 value we have considered the adverse effect from the 9 Hypalon which is the material of the cable. Also the 10 HECR and nitric acid which comes from the composition 11 material of the containment, inside the containment.
12 We take into account all of this adverse impact 13 materials.
14 MEMBER POWERS: Do you treat the 15 conversion of organic contaminants to carboxylic acids 16 like were seen in the RTF tests in Canada?
17 MR. KANG: I'm not familiar with that one.
18 So we can back to you.
19 MEMBER POWERS: I would appreciate it.
20 MR. Y. KIM: Yes, I think RA number is 21 found. So --
22 MR. OH: Yes, this is Andy Oh, KHNP 23 Washington office. I think associated RAI number is 24 362-8445, question No. 31st.
25 MR. Y. KIM: Okay. Yes. In our LOCA NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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19 1 analysis the credit for aerosol and iodine --
2 elemental iodine removal by spray and for aerosol 3 removal by natural deposition in containment business 4 was credit.
5 Would you move next, please? For the in-6 containment water storage system that is consist of a 7 storage tank and holdup volume tank and the cavity 8 flooding system. The IRWST is protect, reliable and 9 safety-related source of borated water for containment 10 spray system and the shutdown cooling system and the 11 safety injection system. The IRWST is also used to 12 prepare the refueling pool in support of refueling 13 operation.
14 Holdup volume tank collect and store 15 coolant during the accident condition.
16 The function of a cavity flooding system 17 is to flood the reactor cavity in the event of a 18 severe accident.
19 And IRWST have minimum level of IRWST to 20 support safety injection and containment spray pump 21 operation during the accident condition.
22 MEMBER REMPE: Excuse me. When we discuss 23 Chapter 19 we learn that even though you have this 24 cavity flooding system, you did not take credit for 25 it. You assumed the vessel failed to be conservative.
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20 1 And it's still unclear to me how much you didn't take 2 credit for it. In the PRA do you assume that the 3 water still goes to the cavity instead of whether --
4 you know, when it's injected, even though you didn't 5 take credit for the vessel to fail, did you assume 6 good heat transfer from the vessel to the water? It 7 wasn't clear how this evaluation was done.
8 And I believe when we discussed Chapter 9 19, you indicated, well, when we do severe accident 10 management guidance, that will be something the COL 11 applicant will take care of. So it -- that -- how the 12 COL applicant will look at the certified design and 13 take care of what actions should be considered is 14 unclear to me. Could you give me any clarification on 15 that interface?
16 MR. Y. KIM: Yes, let me check -- let me 17 put it to our --
18 (Simultaneous speaking.)
19 MR. OH: This is Andy Oh, KHNP Washington 20 office. I think we have a two feature of the 21 mitigation feature. I think, Member Rempe, you 22 mention that the thing is not that CF is -- cavity 23 flooding system. That is IVREVC, in-vessel retention 24 ex-vessel cooling system.
25 MEMBER REMPE: Yes, right.
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21 1 MR. OH: That we didn't credit it, so it's 2 a COL action item. COLAs, they will develop their 3 strategy to implement that system, however, cavity 4 flooding system is certified severe mitigation 5 strategy. So it is included in our design.
6 MEMBER REMPE: So the PRA takes credit for 7 that the water would be injected. And so what I'm 8 kind of -- there's sometimes unintended concerns about 9 external reactor vessel flooding. For example, if you 10 don't take credit for it, do the staff still review to 11 make sure that the structures are robust to withstand 12 what would be needed for external reactor vessel 13 cooling?
14 And so this interface puzzles me because 15 if you say, well, we don't take credit for it, then 16 you don't have to worry about is the insulation strong 17 enough to withstand that chugging that would occur?
18 When the APR1000 or the AP600 was looking at this, 19 they had to consider how it operated.
20 And maybe this is also something the staff 21 would clarify, but I'm just not sure how carefully the 22 flooding system was reviewed and the strategy was 23 reviewed, because you actually could have less heat 24 transfer from the vessel.
25 MR. OH: Yes, all that is relevant to NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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22 1 support IVREVC, not the CFS system. But I --
2 MEMBER REMPE: What is the cavity flooding 3 system for?
4 MR. OH: Cavity flooding system is just to 5 open a valve from the holdup volume tank and provide 6 water to the cavity. Probably it's a depth about five 7 feet or six feet. But the difference from the IVREVC 8 is IVREVC, we have to inject the water through the --
9 using a shutdown cooling to the cavity. And the flood 10 level, probably it's more than 14 and 16, 17 feet. I 11 should be covered. The bottom of the reactor vessel.
12 So those two strategies totally different.
13 MEMBER REMPE: Okay. So I should have 14 held my question until Chapter 19 then.
15 MR. OH: Okay.
16 MEMBER REMPE: But I will have that 17 question when you get to Chapter 19 even though it's 18 not in your slides how did you look at that? I 19 understand now that it's a depth thing, but please 20 clarify that when you get to Chapter 19.
21 MR. OH: Thank you.
22 MR. Y. KIM: This is end of the Chapter 6.
23 In-containment water system we have a swing panel.
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23 1 protect overpressure and the vacuum of IRWST. Two 2 swing panels per overpressure protection and one swing 3 panel for vacuum protection. The right side -- the 4 left -- to the right side figure shows the 5 overpressure protection and the vacuum protection 6 panel.
7 Those same panels are self-actuated by 8 IRWST pressure and provided for hydrogen venting 9 during the severe accident also. Those same panel 10 also prevent vacuum in the IRWST during ECCS and the 11 containment space inflation.
12 For the functionality of IRWST swing 13 panels we got some request for additional information, 14 so KHNP is trying to provide a response for this 15 issue. So we are working on it.
16 VICE CHAIR CORRADINI: If I might ask --
17 I just want to make sure I understand the operation.
18 So there's -- the one set of panels pull out inflow.
19 Sorry. Thought it was on.
20 Let me just ask, I thought it was -- there 21 is panels to the left of your mechanical drawing to 22 allow inflow and then a different set to allow 23 outflow. So does that mean one or both panels are 24 always open?
25 MR. Y. KIM: Usually just they're slightly NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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24 1 -- slight close, but the mechanic can --
2 (Simultaneous speaking.)
3 VICE CHAIR CORRADINI: So what's the need 4 of the panels at all if you're allowing both for in 5 and outflow? I might be missing something about the 6 function. Can you help me?
7 MR. Y. KIM: Yes, if you --
8 (Simultaneous speaking.)
9 VICE CHAIR CORRADINI: -- in and outflow 10 by two different sets of panels.
11 MR. Y. KIM: Yes, you can --
12 MR. SISK: Rob Sisk, Westinghouse. Just 13 to refresh on the panels, the primary reason for those 14 panels of course is debris mitigation to the tanks 15 itself and also concern for the condensation from the 16 tank. So you want to keep the panels basically 17 closed, but you don't want to have pressure 18 differentials between containment and into the tank.
19 VICE CHAIR CORRADINI: So this is for 20 water management then?
21 MR. SISK: Tank management, call it that 22 if you will. You don't want debris and stuff going 23 into your tank. You don't want condensation.
24 VICE CHAIR CORRADINI: Okay. I couldn't 25 remember that.
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25 1 MR. SISK: Yes.
2 VICE CHAIR CORRADINI: Okay. Thank you 3 very much.
4 MR. Y. KIM: And then the next chapter is 5 Chapter 12. I report it to Mr. Kang.
6 MR. KANG: Morning. My name is Sangho 7 Kang, KEPCO E&C. I'm going to briefly talk about the 8 overview of Chapter 12.
9 In order to ensure that the occupation 10 radiation exposure ALARA APR1400 provides a structure 11 to effectively implement radiation protection policy 12 for any review that are consistent with the 13 operational and maintenance requirement to Reg Guide 14 1.8, 1.33, 8.8 and 8.10.
15 The design policy of the APR1400 is to 16 implement the ALARA velocity during the early stage of 17 the design. The APR1400-specific ALARA design guide 18 specify the approach, method and implementation guides 19 for the designers to take into account. In the design 20 of equipment the ALARA design guidelines applies to 21 easy removal of contamination, enhancement of 22 reliability to reduce maintenance and minimization of 23 corrosion. And the layout design of the ALARA design 24 guide requires to separate the radioactive equipment 25 from the non-radioactive equipment and to provide NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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26 1 sufficient areas for inspection and maintenance.
2 As for the radioactive source term, the 3 reactor core fission products are estimated using 4 ORIGEN-S computer code based on the thermal power of 5 102 percent. The source term of spent fuel is 6 calculated based on 100-hour decay time before the 7 movement from the core.
8 The reactor coolant system fission product 9 source terms provided in Chapter 12 are determined 10 based on the fuel defect rate of 0.25 percent using 11 DAMSAM code and used for the design of shielding and 12 ventilation. The CVCS source terms are calculated 13 using SHIELD-APR computer program assuming that the 14 gas stripper is not operated to maximize the gaseous 15 sources.
16 The source terms of the shutdown cooling 17 systems are calculating assuming that the systems stop 18 operation at four hours after shutdown. The design 19 base source system in the spent fuel pool water is 20 determined assuming that the primary cooling water is 21 mixed with spent fuel pool water after 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> of 22 shutdown cooling operation.
23 The source term in the leakage waste 24 management system are determined using DIJESTER 25 computer code. The build-up activity in the gaseous NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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27 1 radioactive system is calculated using the inflow from 2 the CVCS tanks and the gas stripper. The solid waste 3 such as spent-resins, filters, sludge are generated in 4 the CVCS liquid waste management system, spent fuel 5 pool cooling and clean-out system and steam generator 6 blowdown systems.
7 The airborne activity in the 8 radiologically-controlled area is calculated assuming 9 maximum leakage of the radioactive components. The 10 accident source terms which are used for post-accident 11 shielding design and equipment qualification are 12 determined by Regulatory Guide 1.183 which assumes a 13 significant core melt.
14 The APR1400 design incorporates ALARA 15 principles in accordance with Reg Guide 8.8 and 8.10.
16 These principles apply to various areas of plant 17 design. Design criteria for shielding as specified in 18 Reg Guide 8.8, 40 CFR 190, GDC 19 and 10 CFR 50.34.
19 The shielding analysis are performed using 20 several computer codes such as ANISN, MCNP and 21 MICROSHIELD. The RUNT-G code is used to determine the 22 post-accident shielding rulemakings. The shielding 23 analysis produce design-basis drawings including 24 radiation zone maps and the minimum required shield 25 thicknesses.
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28 1 The ventilation flows are provided to 2 ensure the airborne contamination is maintained less 3 than some of the DAC fractions. These air flows are 4 designed to flow from the lower to higher contaminated 5 areas so that the spread of contamination is 6 minimized. In addition, the continuous air monitoring 7 by effluent and area radiation monitors ensure the 8 detection of the airborne contamination level change 9 within 10 DAC-hours as is specified in the SRP 12.3.
10 Area radiation monitoring systems are 11 provided to ensure to protect plant personnel from the 12 unusual radiological events and monitor post-accident 13 radiation levels. Some of the area radiation 14 monitoring system provides balance of ESF, actuation 15 signal.
16 In accordance with Reg Guide 8.19 the 17 occupational radiation exposure for APR1400 was 18 estimated based on the measurement data for operating 19 1,000 megawatt PWR in Korea. And this exposure data 20 was increased taking into account the power ratio of 21 APR1400. The resultant occupation exposure was 22 estimated to be 585 person-millisievert per year or 23 58.5 man-ram per year.
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29 1 access areas. The exposure dose to the plant personnel 2 who takes emergency action satisfied the regulatory 3 limit of 15 millisieverts.
4 10 CFR 20.1406 requires to minimize 5 contamination of facility and the environment and to 6 minimize generation of radioactive waste. The 7 detailed guidance in implement 10 CFR 20.1406 are 8 provided in Reg Guide 4.21. To fulfill this 9 requirement APR1400 design established several design 10 objectives. Under these objectives the APR1400 design 11 was reviewed and evaluated in accordance with the 12 guidance in Reg Guide 4.21. As a result, an extensive 13 list of design features are identified and provided in 14 the DCD.
15 That's all for Chapter 12. If you don't 16 have any more questions, I'll turn it over to Mr. Kim 17 again.
18 MEMBER KIRCHNER: I have a question. So 19 you went through all this. Based on your operating 20 plants did you make any significant changes in 21 material selection for corrosion or layout for 22 maintenance or any other changes that might further 23 your ALARA objectives?
24 MR. KANG: For this design of DC 25 application the APR1400 design was based on the Shin NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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30 1 Kori Units 3 and 4. It's the first unit of APR1400.
2 But the first Shin Kori design for the -- with respect 3 to ALARA, the design for DC application is not so 4 different from the Shin Kori example. But the Shin 5 Kori 3 and 4 is quite different from the previous 6 OPR1000 design with respect to the reduction of the 7 corrosion and the layout of the plant. So all of 8 these design features are provided in the Chapter 12.
9 MEMBER KIRCHNER: Okay. Thank you.
10 MEMBER BALLINGER: So to sort of clarify 11 that in my mind, the exposure was based on the 1000 12 megawatt reactor, an OPR reactor?
13 MR. KANG: That's correct.
14 MEMBER BALLINGER: And those plants had 15 different materials; in particular steam generator 16 tubing material, those kinds of things, from the Shin 17 Kori plants?
18 MR. KANG: Right.
19 MEMBER BALLINGER: And so why was there a 20 correct -- why not use the Shin Kori plants as the 21 basis for the ALARA as opposed to the OPR1000?
22 MR. KANG: Because the Shin Kori 3 and 4 23 didn't start operation yet.
24 MEMBER BALLINGER: Okay. All right. So 25 that's that point.
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31 1 MR. KANG: Okay.
2 MEMBER BALLINGER: Okay.
3 MR. KANG: All right.
4 MEMBER BALLINGER; So it didn't -- now, is 5 there a plan to --
6 MR. KANG: Yes.
7 MEMBER BALLINGER: -- check it out?
8 MR. KANG: Sure. Sure. Once it's --
9 (Simultaneous speaking.)
10 MEMBER BALLINGER: To see if you're right.
11 MR. KANG: Yes, that's what we are waiting 12 for.
13 MEMBER BALLINGER: Okay. Thank you.
14 MR. KANG: Okay. Thank you.
15 MEMBER SUNSERI: I have one other 16 question. During our -- I get the chapters mixed up 17 a little bit, but during our Subcommittee discussion 18 we had a question regarding manual drawing of post-19 accident samples and whether or not those highly 20 radioactive samples would be sufficiently shielded to 21 keep the dose rates to the personnel acceptable. And 22 it seems like that question was left hanging. So did 23 you look into that and can you confirm that personnel 24 are able to take the post-accident samples without 25 undue radiation exposure?
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32 1 MR. KANG: I think that question was not 2 raised during the Chapter 12 Subcommittee meeting. I 3 think some other chapter. But I think I can answer 4 that question.
5 For the post-accident sampling we had 6 special shielding design sampling. So we got the 7 sample behind the shielding wall. So it's not the 8 scope of the architect engineering design. That is 9 provided by the vendor. And the sampling of the 10 primary side or coolant is protected with respect to 11 the radiation. So we take into account when we do --
12 when we calculate the vital area dose because the 13 sampling area is one of the vital areas we need to 14 take some -- the operator to take action. So when we 15 calculate the dose to the operator for the sampling --
16 so we take that into account.
17 MEMBER BALLINGER: To expand on that 18 again, have you considered related to Fukushima and 19 their radiation doses in the post-accident sampling 20 process and shielding here?
21 MR. KANG: Because we -- in our original 22 design we already take into account the post-accident 23 sampling during entry and exit for the sampling 24 action, so we do calculate the dose to the operator 25 during his passes and entry and coming back to the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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33 1 MCR. So all of the information was provided in 2 Chapter -- Section 12.4.
3 MEMBER BALLINGER: Yes.
4 MR. KANG: So, because it is required by 5 the TMI action items.
6 MEMBER BALLINGER: Yes, but there's 7 additional information from Fukushima.
8 MR. KANG: I think --
9 MEMBER BALLINGER: I think. Joy?
10 MEMBER REMPE: Ron, there were hydrogen 11 explosions at Fukushima. They were BWRs. They were 12 different power levels. I'm not sure that that would 13 be relevant to this design.
14 MEMBER BALLINGER: But you have failed 15 fuel?
16 MEMBER REMPE: Yes, they definitely had 17 failed fuel, but again it's a lot different to going 18 into those plants than what would be considered here.
19 MR. Y. KIM: I think because when we 20 calculated the sampling dose, the post-accident 21 sampling dose, we assume a significant core melt. And 22 the IRWS is contaminated significantly. We take that 23 into -- conservatively we calculate the dose.
24 MEMBER BALLINGER: Thank you.
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34 1 13. So conduct of operation. Chapter 13 consists of 2 seven sections relating to conduct of operation. Most 3 of Chapter 3 -- 13 are COL items. And the 13.6 is 4 about physical security, which is SGI information, so 5 we don't discuss today.
6 This chapter provide information related 7 to preparation and the plan for the design, 8 construction and operation of APR1400. Its purpose is 9 to provide adequate assurance that COL applicant 10 establish, maintain staffs of adequate size and 11 technical competence. And this chapter shows that 12 operating plant followed by license -- licensee 13 adequate to protect public health and safety.
14 So let me just go the table. Proposed 15 Section 13.1 is about organizational structure and 16 applicant -- this is a COL item. And .2 is plant 17 staff training. Also COL item. .3 about emergency 18 plan. .4 is about operational program implementation.
19 13.5 is about administrative and operating procedure.
20 14.3 describe the physical security design piece of 21 APR1400. The related information is in our security 22 vault. So that is SGI information, so we cannot 23 discuss that. Section 13.7 is about fitness-for-duty 24 programs. Most of these are COL items.
25 Let me move to Chapter 14. Chapter 14 is NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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35 1 about Verification Program. Chapter -- APR1400 2 Initial Test Program is developed to meet the Reg 3 Guide 1.68. The test period is from the completion of 4 construction to the power ascension test.
5 Chapter 14.3. ITAAC is not discussed 6 today's meeting. That will be presented in the Phase 7 5.
8 The test phase divide into four different 9 phase. Phase I is for pre-operation test. Phase II 10 is about fuel loading and the pre-core hot function 11 test. Phase III is criticality and the low-power 12 physics test. Phase IV is a power ascension test.
13 Total number of test we have 178.
14 Could you move next, please? For Chapter 15 16, that is about Tech Spec. Tech Spec of APR1400 are 16 developed based on NUREG-1432. APR1400 is not applied 17 risk informed tech spec. Unique design feature of 18 APR1400 were reviewed for applicability of NUREG-1432 19 to APR1400. And related technical report was 20 submitted to NRC.
21 The major deviation is APR1400 design 22 adopt POSRV and the four safety injection trains 23 rather than two trains and IRWST. And we have 24 auxiliary feed water system with the turbine. And we 25 have -- for the -- regarding electrical system, we NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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36 1 have a four EDG rather than three EDG. So that is a 2 major deviation, so that is incorporated in our tech 3 spec.
4 The tech spec number is specified in my presentation.
5 For Chapter 17, Quality Assurance Program.
6 Chapter 17 is composed of six section, Section 1, 2, 7 3 and 5 are about Quality Assurance Program. Section 8 4 is related to the Reliability Assurance Program, 9 RAP. Section 6 is handling about the maintenance 10 rule. KHNP is prepared to submit and submitted a QA 11 Program to NRC as the form of a topical report. This 12 comprise with all the regulatory requirements such as 13 Part 50, Appendix X, Part 21 and ASME NQA-1. This QA 14 Program is implemented and improved according to 15 corrective action in KHNP.
16 Move next slide. As an applicant KHNP has 17 the final responsibility to design control. KHNP 18 delegated the design activity to three design 19 suppliers: KEPCO E&C for balance of plant and NSSS 20 design; KEPCO NF for fuel and core design; DOOSAN for 21 NSSS component design.
22 To oversee the delegate design activity 23 KHNP are doing five kind of major activity. First, 24 KHNP evaluate, select and qualify supplier and seal 25 the contract with them only. Second, KHNP receive, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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37 1 review, approve the design product from design 2 supplier and the NRC. Third, KHNP control RAI and all 3 the related change in the design process. Fourth, 4 KHNP preside committee related to design change, 5 interface and the project measurement meeting. Fifth, 6 KHNP does QA inspection internally and externally to 7 check the implementation status and to improve QA 8 Program as a part of corrective action.
9 Let's move to RAP requirements. This 10 slide is about RAP. The design, construction and the 11 operation are consistent with risk insight and they 12 key assumption from PRA. The programmatic control 13 ensure that RAP list is appropriately developed and 14 maintained and communicated to the related 15 organization. QA Program oversee activity of 16 affecting RAP SSC quality.
17 The RAP is implemented during operation 18 phase via Maintenance Rule Program, QA program and the 19 various test and maintenance programs. Design RAP 20 should therefore align for a seamless transition to 21 these programs.
22 So maintenance rule --
23 MEMBER SKILLMAN: So back up on, please.
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38 1 the leadership that is involved causes it to be 2 seamless. Those of us who have been through this know 3 that this is an effort that takes an enormous focus by 4 many people. And so I would ask even though this plan 5 is many years in the future, what KHNP's vision is of 6 how this seamless transition will be ensured.
7 MR. Y. KIM: Yes, usually in Korea we have 8 very many operate -- conceptualization project during 9 the last more than 20 years. So in our project is 10 three organization. KEPCO E&C, DOOSAN, and KEPCO NF 11 and the KHNP work together every project for reports 12 and the Kori unit that we have ability accumulate the 13 experience to work together. So we have -- each 14 company has their own energy expert. So through the 15 many meeting with expert panel -- so we are going to 16 update the RAP SSC. So probably we can do the 17 seamless transition. So from the design -- I'm not 18 sure that help you.
19 MEMBER SKILLMAN: That's in the right 20 direction. Thank you.
21 MR. Y. KIM: So Maintenance Rule Program 22 is also described in SRP 17.6 that is required by Part 23 50.65. The detailed procedure and the implementation 24 will be the responsibility of the COL applicant. We 25 are going to seamless transition to this program.
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39 1 We have to move to Chapter 19, PRA.
2 Chapter 19.1 covers the APR1400 PRA. Shown on this 3 slide are the scope of PRA by the operation mode and 4 the hazard. Note that seismic evaluation was 5 performed using PRA-based seismic margin assessment 6 and we applied a bounding approach for the level 2 7 internal flooding at low power and the shutdown mode.
8 This slide highlight the key approach for 9 PRA modeling and quantification. The PRA use a linked 10 fault tree method to ensure that initiate and support 11 system impact on the front line mitigation system are 12 considered. Common-cause failure was considered for 13 the intra-system SSC. Additionally, inter-system CCF 14 modeled between containment spray and the shutdown 15 cooling pump because the pumps are identical.
16 Human error probability initially set 17 artificially high to ensure dependent operator 18 accidents are not prematurely truncated prior to 19 application of a dependent HEP barriers.
20 Quantification is performed using truncation value 10 21 to minus 13 for the CDF; 10 to minus 14 for the LRF 22 quantifications.
23 Uncertainty analysis contains three part:
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40 1 of a selected uncertainty case. Parametric 2 uncertainty use the state of correction to estimate 3 the mean barrier of a CDF from point estimate produced 4 by PRA quantification. Modeling assumptions were 5 identified and evaluated for the potential impact on 6 the conclusion. For sensitivity case two for CCF, two 7 for HEP were quantified.
8 Let's move to next, please. Key design 9 improvement from risk insight include original two 10 EDG design change to four EDG. AAC, we change from 11 diesel generator to gas turbine generator. Also we 12 increased capacity for 125-volt DC battery. Also, 13 Tech Spec 3.6.7 is revised for the equipment hatch 14 closure in Mode 5. Also, the protection of cable from 15 fire damage is the same.
16 Let's move next, please. Other 17 application in DC Phase include also design RAP, SAMDA 18 and the input to human factor engineering and the 19 physical security. Operational Phase would include 20 operational RAP, ROP, CVTR determination process and 21 the maintenance rule.
22 The next slide shows that the overall risk 23 profile from PRA. The result show that no one hazard 24 or operating mode dominate the risk. Internal 25 flooding risk is very low due to the design feature of NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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41 1 the plant.
2 Next slide.
3 MEMBER STETKAR: Let me stop you there.
4 It's my understanding that we had several questions 5 about the PRA during the Subcommittee meeting and we 6 were informed at that time that KHNP is updating the 7 PRA to include several what I'd call substantive 8 changes. I know that you're proposing to revise the 9 models for reactor coolant pump seal failures. I 10 think we were told that you're reviewing all of the 11 operator actions in both the full power and shutdown 12 models to ensure consistency in the treatment because 13 then they'd be treated differently in different parts 14 of the models. And there were several other items of 15 varying potential importance to the overall risk and 16 the distribution that you show on this slide.
17 Is that still true? Are you planning a 18 substantive update to the PRA?
19 MR. Y. KIM: Yes, we are working -- still 20 working on it. And could you help me with that?
21 MR. ROZGA: This is Greg Rozga from 22 Enercon and the simple answer to your question is yes, 23 we are working on that. We are at this point --
24 MEMBER STETKAR: Greg, get real close to 25 that mic.
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42 1 MR. ROZGA: We are at this point complete 2 with the Level 1, and the Level 2 changes are going in 3 now.
4 MEMBER STETKAR: Okay.
5 MR. ROZGA: And we -- for Level 1 we still 6 have to do the dependency analysis, but we want to 7 make sure that we get the dependency analysis between 8 Level 1 and level 2, so we're kind of waiting --
9 MEMBER STETKAR: When you say "dependency 10 analysis," you mean --
12 MEMBER STETKAR: HEP dependency?
13 MR. ROZGA: Correct.
14 CHAIRMAN BLEY: Okay.
15 MR. ROZGA: Correct. So those actions in 16 Level 2 we want to make sure if there's any dependency 17 with the Level 1 actions that we capture that.
18 MEMBER STETKAR: You also -- when you say 19 Level 1, you mean both full power and shutdown --
20 (Simultaneous speaking.)
21 MR. ROZGA: Correct.
22 MEMBER STETKAR: Because that was one of 23 the bigger areas that you were concerned about.
24 MR. ROZGA: Yes. And then the --
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43 1 answer. When?
2 MEMBER STETKAR: Well, I'm assuming that 3 will require an update to the DCD.
4 MR. Y. KIM: Yes, we are going to provide 5 that soon, so we will try very hard.
6 MEMBER STETKAR: Try very hard.
7 MR. Y. KIM: Okay.
8 MEMBER STETKAR: Well, we'll try very hard 9 to review it in a timely manner then.
10 VICE CHAIR CORRADINI: So can I ask a 11 question on that, John? Or, Ron, I should say.
12 Excuse me.
13 So once this is done for Chapter 19, are 14 we going to come back and have a Subcommittee meeting 15 or wait until the DCD is presented to staff and staff 16 has to -- what I'm trying to understand is the process 17 at this point. I understand the process.
18 MEMBER BALLINGER: The current answer is 19 no, that the next time we would see this would be in 20 Phase V.
21 VICE CHAIR CORRADINI: Which is 18?
22 MEMBER BALLINGER: Yes. At which time 23 people just take their chances that it'll work.
24 That's the current -- and Bill can correct me if I'm 25 wrong, but I think that's the current answer.
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44 1 MR. WARD: That's the current answer as I 2 understand it. I've had discussions with KHNP and at 3 this point they didn't want to go forward with a 4 second Subcommittee meeting.
5 MR. Y. KIM: Yes, I think that there is 6 most organized, and so you are going to close all the 7 organized probably.
8 MEMBER REMPE: So during our discussion we 9 learned that the PRA said that bypass failures 10 dominate core damage frequency. And when we started 11 delving into that, we learned that you based your 12 conditional probability for consequential steam 13 generator tube rupture on work that was done for a 14 Westinghouse plant. And there has been a more recent 15 report done by the staff where they evaluated a CE 16 geometry and a Westinghouse geometry and they found an 17 order of magnitude higher for that consequential steam 18 generator tube rupture. So that's an example of 19 something that I think might be a significant change.
20 And during our discussion I believe KHNP 21 responded that wasn't available when we did the PRA.
22 And this is a new document. It was -- the draft is 23 publicly available and they would look into it. Have 24 you guys looked into it and said, well, maybe we 25 should use a geometry that's more appropriate for CE NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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45 1 design?
2 MR. DREMEL: Ray Dremel from Enercon. We 3 have not been able to incorporate that at this -- as 4 of yet into the model. We talked earlier. That 5 document came out after we had started down Revision 6 0. We need to look into whether we can incorporate 7 that and how that will be incorporated into the 8 next --
9 (Simultaneous speaking.)
10 MEMBER REMPE: That might be a good 11 example of something that might make a significant 12 difference. And it would be nice to see that result.
13 That you are planning to do that, is what I'm hearing.
14 MR. DREMEL: We will look into 15 incorporating it. I'm not going to make commitments 16 for KHNP on what they will or will not do, but that is 17 something we need to consider.
18 MEMBER REMPE: Okay. Thank you.
19 MEMBER KIRCHNER: I'd like to ask a 20 different line of questioning. I've always felt that 21 the most value of the PRA is to insight it gives, not 22 the numbers. So if I just look at your graph, it 23 looks like half -- and I'll use the term loosely, half 24 of your risk almost is due to fire and over half of 25 the risk is at low power. So what are you doing --
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46 1 MEMBER POWERS: With all plants.
2 MEMBER KIRCHNER: I know. I know. So my 3 question is you have this information. Now what do 4 you do with it? Are you content with this or do you 5 then look at your operating procedures or your fire 6 protection programs and look at where the 7 vulnerabilities are here? How do you -- what are you 8 using this for that improves your design?
9 MR. DREMEL: This is Ray Dremel with 10 Enercon again. And roughly -- as you say, roughly 11 half the risk is due to fire, but the total risk for 12 APR1400 is fairly low.
13 MEMBER KIRCHNER: Right.
14 MR. DREMEL: So this is a big piece of a 15 small pie.
16 MEMBER KIRCHNER: I just --
17 MR. DREMEL: And we have looked at -- as 18 Mr. Kim mentioned earlier, there are certain cables 19 that if we -- if they are protected and they're put in 20 as a whole item, that greatly reduces risk.
21 We did use the results to -- what are the 22 vulnerable -- what are the big contributors to risk?
23 We eliminated -- we did make COLA commitments to 24 reduce that risk. Now we're down to the -- the risk 25 is fairly well balanced across things. There's not NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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47 1 one --
2 MEMBER KIRCHNER: Dominant?
3 MR. DREMEL: There's not a silver bullet.
4 There's -- as this chart shows, the risk is fairly 5 well distributed across all modes and all events.
6 Flooding risk is low because there's just no flood 7 sources in the aux building.
8 MEMBER STETKAR: Just for clarification 9 for the members here, that's internal flooding.
10 One thing I wanted to mention on the 11 record is that this profile that we see here does not 12 include risk from seismic events which are not 13 quantified, nor does it include the risk from the so-14 called other external events categories. For example, 15 high winds, tornadoes, external flooding and so forth.
16 If those were included in the PRA, they might somewhat 17 alter this profile. We don't -- there's no way of 18 knowing that until the site-specific PRA is done with 19 their hazard and winds and flooding and so forth. So 20 this is the part of the picture that they can show at 21 this point for the certified design.
22 MEMBER KIRCHNER: Thank you.
23 CHAIRMAN BLEY: I didn't attend the 24 Subcommittee meetings, but one thing I've seen in 25 other design certifications is for the kinds of NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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48 1 locale-specific events that Mr. Stetkar just 2 described. They often used a surrogate seismic source 3 and surrogate water designs and then said at the COL 4 stage you have to ensure you're less vulnerable than 5 that surrogate or you have to do more work at that 6 stage. Is that the same thing done here or did you 7 just not consider those kinds of events at this point?
8 And if that second one is true, what 9 direction is there for the COL when you actually know 10 what the site-specific issues would be?
11 MR. DREMEL: There were screening analyses 12 done for certain external events like high winds. It 13 showed that we expect those based on conservative 14 criteria to be a negligible contributor to overall 15 risk. For seismic events we can't -- you can't really 16 do a seismic PRA because you don't have a plant to 17 look at. You don't know what specific make and model 18 of components were done.
19 So if there is a COL item, the licensee 20 would have to do a full seismic PRA before fuel load.
21 Certain external events like external flooding are 22 left to the COL applicant to show that they are within 23 the constraints we've assumed in their screening 24 analyses.
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49 1 time to look at those and I hope should there ever be 2 one, we actually do that.
3 MEMBER STETKAR: There is just -- again 4 for the other Committee members, like as you're aware, 5 I took a pretty good look at what they've done. They 6 do have a -- I would call it a more robust PRA model-7 based seismic margin analysis than we've seen in other 8 design certifications. They do not have quantified 9 seismic risk values, either core damage frequency or 10 release frequencies. They have done a -- I'd call it 11 a limited conditional quantitative evaluation where 12 they've ranked seismic contributors by running a 13 nominal seismic event through their PRA models, which 14 is a little bit more than we've seen in other studies.
15 CHAIRMAN BLEY: That helps, but given what 16 was just said, when the staff comes up, I'd be 17 interested in their expectations for the COLA PRA.
18 MEMBER BALLINGER: This overall risk 19 profile includes FLEX, or whatever you're calling it?
20 MR. DREMEL: No, we took no credit in this 21 PRA for FLEX.
22 MEMBER STETKAR: Be careful. You took 23 credit for some FLEX-y stuff, so you took credit for 24 the --
25 (Laughter.)
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50 1 MEMBER STETKAR: -- whatever you call the 2 -- I've always forgotten the acronym, the truck that 3 sprays the containment.
4 MR. DREMEL: Yes. Yes, the --
5 (Simultaneous speaking.)
6 MEMBER STETKAR: And that's kind of a 7 FLEX-Y sort of thing.
8 MR. DREMEL: Yeah. So any credit would be 9 minimal. As Mr. Stetkar said, it would be the 10 external -- ESCBS.
11 MEMBER STETKAR: Yes.
12 MR. DREMEL: External containment spray --
13 PARTICIPANT: ECSBS.
14 MR. DREMEL: ES -- yeah. So we hook up a 15 fire truck to an extra header in the containment to 16 reduce containment pressure. But as far as the 17 Fukushima modifications we -- the PRA took no 18 credit --
19 (Simultaneous speaking.)
20 MEMBER STETKAR: Yes, the other parts that 21 -- we'll hear about some of those I think in 19.3.
22 MEMBER BALLINGER: I'm cautioned by Mr.
23 Stetkar about comparing to other plants because 24 everything's different, but I have the risk poster for 25 another CE, the System 80 plant.
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51 1 MEMBER STETKAR: It's irrelevant.
2 MEMBER BALLINGER: That's what he cautions 3 me on.
4 (Laughter.)
5 MEMBER BALLINGER: But I'll say it anyway.
6 The fire risk is the same. The total fire 7 contribution for that plant is pretty much the same as 8 this.
9 MEMBER STETKAR: The fractional 10 contributions here though at a high level are not 11 unusual for a broad spectrum of plant designs, whether 12 they're PWRs or BWRs or the country of origin or 13 anything. This is not an unusual risk profile. And 14 typically it will change somewhat once the seismic 15 risk is quantified.
16 MR. Y. KIM: Then let me move to next 17 chapter. Chapter 19.2 is severe accident evaluation.
18 17 -- 19.2 describe severe accident evaluation.
19 APR1400 is designed to meet the related criteria such 20 as Part 50.34 and Part 52.47, and the SECY-93-087, and 21 the Reg Guide 1.216.
22 Comprehensive analysis of in and ex-vessel 23 severe accident progression are made with conservative 24 approach to cope the uncertainty. First, for the 25 hydrogen there's -- hydrogen concentration inside the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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52 1 containment is lower than 10 percent by large free 2 volume of containment and PAR and igniters. So the 3 hydrogen combustion risk can be eliminated, can be 4 minimized.
5 For the molten core concrete interaction 6 this mid-line can maintains its leak-tightness by 7 using cavity flooding system.
8 Could you move to next slide? For high 9 pressure melt ejection and the direct containment 10 heating reactor coolant system pressure at the reactor 11 vessel failure can be low by rapid depressurization 12 system and the possibility of containment failure from 13 direct containment heating can be minimal.
14 For the fuel-coolant interaction reactor 15 vessel and the cavity structure integrity is 16 confirmed.
17 For the containment performance Reg Guide 18 1.216 Position 2 related with the combustible gas 19 control and the Position 3 for more likely severe 20 accident challenge are confirmed.
21 Accordingly, the analysis result indicate 22 containment and the severe accident mitigation 23 features of APR1400 meet the severe accident 24 requirements.
25 MEMBER REMPE: So, excuse me. I think NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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53 1 this is the time to re-ask my question about the in-2 vessel retention system and the fact that it exists, 3 but no credit was taken for it and the fact that we 4 were told that that will be left to the COLA 5 applicant.
6 My question is really at a higher level is 7 -- this interface about how if an applicant came in, 8 how they would extract what's need for the severe 9 accident management strategies. Earlier in your 10 slides today you said we are preparing the severe 11 accident management strategies. Do they consider the 12 in-vessel retention system? And is it in the PRA even 13 though you don't take credit for it? Did the staff 14 review the robustness of that system and what the 15 effects are with water addition in their accident 16 management strategies?
17 MR. OH: Yes, this is Andy Oh, KHNP, 18 Washington office. And that matter is -- actually in-19 vessel is not credited as a mitigating feature for the 20 APR1400 due to the uncertainty surrounding associated 21 phenomena. For example, steam explosion or something.
22 And along with the operator's action, for example for 23 the shutdown cooling, have to operate the cavity 24 flooding system.
25 So the position for the KHNP is for the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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54 1 SAM, severe accident mitigate -- management system is 2 when develop the COL applicant, they have to consider 3 both the negative impact and the positive impact 4 together. If they think it's for -- positive impact 5 is more than negative impact, they can implement in 6 their SAM, those severe accident management system.
7 However, for APR1400 is -- this feature is already 8 implemented in our design. We are not obligated for 9 the COL applicant have to use this features their --
10 the SAM, severe accident management. So that is our 11 position.
12 So probably in a COL applicant they can 13 evaluate more of the steam explosion or other 14 associated phenomena for the negative impact to that 15 in-vessel, especially the strategy. If they think is 16 more -- positive impact is more than the negative, 17 they can implement that strategy to their management 18 system.
19 MEMBER REMPE: Thank you. So now what I'm 20 hearing is that it's an optional system at the -- and 21 I'm wondering now; and maybe I should ask the staff, 22 but did they review an optional system for robustness 23 and possible adverse effects? And if they -- again, 24 when this comes up with the applicant, it used to be 25 clearly documented at this optional system wasn't NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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55 1 considered in the review and if they want to 2 implement, then they need to have it reviewed by the 3 staff because it could have some negative impacts.
4 And I guess I didn't get that from our earlier 5 discussion or my review of the Chapter 19 --
6 (Simultaneous speaking.)
7 MR. OH: And also it's clearly described 8 in the DCD and also in the PRA as in-vessel. Ex-9 vessel is not included in -- for PRA or de rigueur.
10 It is also -- we just did the sensitivity study when 11 it -- it is taken into account for the PRA how much 12 the risk gain can be achieved or not. We just show 13 them to -- but we didn't take into account for the 14 system for credit, give the credit to our PRA model.
15 MEMBER REMPE: Okay.
16 MEMBER STETKAR: By the way, just for the 17 record, for the other Committee members, this 18 discussion has perhaps given people the implication 19 that this is some separate system. It's a pipe with 20 two valves in it that provides a water flow path from 21 one train of the combined safety injection and 22 shutdown cooling system return line into the reactor 23 coolant system. Or you can align that line also to 24 the boric acid makeup pumps, I believe. So it's not 25 a separate stand alone system. It's a pipe with two NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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56 1 valves in it. It's a flow path.
2 MEMBER REMPE: So --
3 MR. WAGAGE: This is Hanry Wagage from the 4 staff. We have not reviewed the system because the 5 applicant did not take credit for the system. In the 6 PRA applicant did not take credit, but when we were 7 reviewing steam explosion ex-vessel, we asked the 8 question what would happen if the system failed and 9 much larger melt pours in -- much larger diameter melt 10 pours in the cavity and cavity would have much higher 11 water level than steam explosion loading will be 12 higher.
13 Then applicant proposed COLA item. That 14 is -- for the COL applicant is to evaluate the 15 effectiveness of ex-vessel cooling system. We have 16 not reviewed this system so far because applicant need 17 not take credit. However, there is an open item. We 18 have an open item under that we are discussing with 19 the applicant. It's not close yet.
20 MEMBER REMPE: So this fuzzy line of where 21 the -- of what will be done will be clearly documented 22 and what the staff finally produces to say we've not 23 considered the adverse effects. If they want -- if an 24 applicant does come in and says I'm going to try and 25 invoke this, that brings in a bunch of analysis about NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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57 1 steam explosions and possible adverse effects, the 2 robustness of the insulation that would -- or the 3 system that would have to allow water to come in, 4 etcetera, near the vessel.
5 MR. WAGAGE: Right now that's the 6 position. We have not reviewed. And that's what 7 applicant is proposing, a COL information item. But 8 that's still under review.
9 MEMBER REMPE: Okay.
10 MR. PHAN: Good morning. My name is Hanh 11 Phan, the senior lead, PRA and severe accident 12 reviewers. Yesterday the reviewers and the senior 13 management, we had a meetings to discuss and come up 14 with the possible resolution to address this issue.
15 We decide that we will ask the applicant to send us 16 their analysis, any assessment they performed to 17 certify that the operation of the system would not 18 impact the containment or any consequences to the 19 plant. We will have another discussion with the 20 applicant and we would ask them to send us their 21 assessments. And the staff will reviews that.
22 MEMBER REMPE: Okay. Thank you.
23 MR. Y. KIM: So we are 25. So we are 24 moving to 19.3 for the beyond-design-basis external 25 event. APR1400 FLEX strategy was developed -- ELPA NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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58 1 concurrent with loss of ultimate heat sink in 2 accordance with EA 12-049 and 12-051 and NEI 12-06.
3 In order to implement the FLEX strategy, 4 APR1400 design has various FLEX equipment such as 5 three secondary pumps for cooling, two high-head pumps 6 for reactor coolant system makeup, one pump for spent 7 fuel pool makeup and another one pump for spent fuel 8 pool spray. Also we have two FLEX pump for emergency 9 core secondary bypass system, ECSBS, and two 480-volt 10 portable GTG to restore one of the Class 1 E bus.
11 On-site resource include large amount of 12 cooling water and a fuel oil source that will be used 13 for 14 days and 30 days, respectively.
14 For the off-site resource we assume 4.16 15 kilovolt portable AC power and indefinite amount of 16 cooling water and the fuel oil resource available.
17 MEMBER STETKAR: Mr. Kim, before we leave 18 this slide, there's -- I want a couple clarifications.
19 The second sub-bullet under FLEX says two primary low-20 head pumps. That's different from Rev 0 of the DCD, 21 isn't it? Rev 0 of the DCD only said one primary low-22 head pump. I believe that's correct --
23 MR. Y. KIM: Yes, and let me just --
24 (Simultaneous speaking.)
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59 1 just trying to find out where there's a change from 2 what we saw previously in Rev. 0 of the DCD.
3 MR. OH: Yes, and this is Andy Oh, KHNP 4 Washington office. And NEI 12-06 required n plus one 5 requirement. That's for the -- in actual the strategy 6 we used one, however, we prepare n plus one so that's 7 -- two is the correct number.
8 MEMBER STETKAR: Two is the correct 9 number? And also that's -- the same is true for the 10 ECSBS pumps?
11 MR. OH: Yes, and per the previous ECSBS 12 we prepared one.
13 MEMBER STETKAR: Yes.
14 MR. OH: And during a conversation with 15 NRC after ACRS we corrected it to that.
16 MEMBER STETKAR: Yes, I just wanted --
17 okay. So I wanted clarification, because in my notes 18 from Rev 1 of -- Section 19.3.1 only listed one 19 primary low-head pump and one ECSBS pump. So that you 20 are now committing to two of each of those?
21 MR. OH: Yes.
22 MEMBER STETKAR: Thank you. And this by 23 the way is why I said ECSBS is FLEX-y-type stuff, 24 because it is the -- of these pumps, the equipment on 25 this slide, the PRA does include credit for ECSBS; NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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60 1 and, Greg, you'll have to correct me if I misspeak, 2 and only ECSBS from this inventory. Is that right?
3 MR. OH: Yes, this is Andy Oh, KHNP 4 Washington office. Originally ECSBS is not prepare 5 for the FLEX equipment. That's originated based on a 6 SECY-93-0178.
7 MEMBER STETKAR: Andy, I don't want to 8 split hairs in terms of the name of the stuff. The 9 pumps that are called ECSBS on this slide that has a 10 FLEX heading on it are included in the PRA, is that 11 correct?
12 MR. OH: Yes, correct.
13 MEMBER STETKAR: Okay.
14 MR. Y. KIM: Let's move next slide. Core 15 cooling strategies at power operation is divide into 16 three phases. In Phase 1 reactor coolant system hot 17 standby condition is maintained with no operator 18 action. Phase 2, reactor coolant system is a cool 19 down to around the shutdown cooling system entry 20 condition using installed or proxy. In Phase 3 21 reactor coolant system control state is maintained 22 with the same strategies in Phase 2 and but using off-23 site resource.
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61 1 is applied after waiting until reactor coolant system 2 heat up to hot standby condition.
3 For low mode operation with steam generate 4 not available during Phase 1 decay heat is removed by 5 reactor coolant system inventory boil-off. And in 6 Phase 2 feed and bleed operation is applied using low-7 head FLEX pump. In Phase 3 the operator can resume 8 shutdown cooling system operation or continue the same 9 strategies as in Phase 2 using off-site water and fuel 10 oil source. The detailed procedure will be developed 11 by COL applicant.
12 MEMBER STETKAR: Mr. Kim, on this slide my 13 notes say you've listed -- for at-power the Phase 1 14 coping time is eight hours. For shutdown modes my 15 notes indicate that the Phase 1 coping time is three 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br />. Is that correct?
17 MR. OH: This is Andy Oh, KHNP Washington 18 office. For the beyond-design-basis external even 19 strategy we -- initially we developed the low-power 20 shutdown strategy, however during the RAI process the 21 staff request to the applicant for the portion of low-22 power shutdown strategy that should be into the COL 23 action totally. So --
24 MEMBER STETKAR: What? Okay. We'll talk 25 to the staff about that. Just for the record, Andy, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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62 1 are you saying that the staff asked you to remove that 2 from the DCD?
3 MR. OH: No, and for -- removed this --
4 not the -- ask removed the DCD. That's NEI 12-06 in 5 Revision 3 based on that for document and for low-6 power shutdown strategy can be deeper to the COL 7 applicant. There's several requirement based on that 8 revision because the --
9 (Simultaneous speaking.)
10 MEMBER STETKAR: We'll try to get 11 clarification from the staff on this. I'm really 12 confused because quite honestly; this is my personal 13 opinion, I was quite pleased to show -- to see in the 14 DCD that you had addressed strategies for shutdown 15 conditions explicitly, which most people have ignored.
16 So I was quite pleased.
17 And in fact the strategies show that there 18 are different time windows and different things to do 19 during shutdown. That's why I brought up this three-20 hour versus eight-hour. It's the three-hour only for 21 the condition when you're at reduced inventory and the 22 steam generators are not available. That's a minor --
23 it's an important but it's a detailed nuance.
24 And now I'm hearing that that may be 25 removed because of some interaction with the staff.
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63 1 So I'll be real curious to see how the staff addresses 2 this. Thank you.
3 MR. Y. KIM: Yes, for the maintain 4 containment function containment analysis results show 5 that containment is maintained well below design 6 pressure and EQ temperature limit for 16 days. In 7 addition, ECSBS is available to manage the containment 8 condition after reaching design pressure.
9 For the spent fuel pool cooling decay heat 10 is removed by spent fuel pool inventory boil-off 11 during Phase 1, but in Phase 2 and 3 the operator 12 needs to make up spent fuel pool inventory using FLEX 13 pump and the water it was from raw water -- raw water 14 tank. And two channels level instrument -- with the 15 two-channel level instrument the operator can monitor 16 the spent fuel pool water level in MCR during the 17 event.
18 Let's move to next slide. Next slide 19 about loss of large area. The APR1400 design was 20 buried in accordance with SRP 19.4 and NEI 06-12.
21 Those strategies in NEI 06-12 are considered to 22 maintain the spent fuel pool and the core cooling 23 capability. Phase 1 LOLA event evaluation focused on 24 the operational response to explosion or fire.
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64 1 organizations, planning and the preparation activity 2 and the developing procedure and the training for the 3 event will be addressed by the COL applicant.
4 For the Phase 2 LOLA event we have -- it 5 have -- we have to focus on mitigating on the event 6 involving the spent fuel pool. APR1400 design adopt 7 internal and external spent fuel pool makeup and the 8 spray strategies.
9 For Phase 3 LOLA event evaluation focused 10 on maintaining command and control, physical writer, 11 and alternative mitigation strategy is develop to 12 perform key safety functions.
13 MEMBER STETKAR: Now during the 14 Subcommittee meeting we had some discussions about 15 I'll call it coordination of the information in 16 Chapter 19.3 and Chapter 19.4. We noted some 17 discrepancies in for example different capacities, 18 flow capacities that were listed for the same 19 functional pumps in those two sections. And it was 20 noted at that time that while 19.3 addresses guidance 21 in one NEI document and 19.4 addresses guidance in a 22 different NEI document, we have not yet reviewed 23 Revision 1 of the DCD.
24 Have you done anything to resolve those 25 discrepancies? I'm doing -- for example, I'm looking NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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65 1 at 1,000 gpm flow capacity required for a certain pump 2 versus I think it was 750 gpm. And different pump 3 names and different inventories of pumps. Have you 4 done anything to integrate that, because the -- I'll 5 ask staff about this when they come up -- the pending 6 regulations in 10 CFR; I always get it wrong, 50.155, 7 I think it is, the mitigation strategies, indicates 8 applicants and licensees should be integrating all of 9 these strategies, not having the kind of diverse 10 separate approach to life. So can you comment on that 11 at all? And no is a possible answer.
12 MR. SISK: This is Rob Sisk, Westinghouse.
13 I think the best we can say at this point is we're 14 taking a lot of notes on what we are hearing over the 15 ACRS Subcommittee meetings and the Full Committee 16 meetings.
17 MEMBER STETKAR: Okay.
18 MR. SISK: We are -- as you've noted, 19 we've issued Rev 1 of the DCD.
20 MEMBER STETKAR: Yes.
21 MR. SISK: There will be additional 22 revisions as we close out confirmatory items and 23 looking at things like consistency of language and 24 such.
25 MEMBER STETKAR: Okay.
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66 1 MR. SISK: So we hear it and we consider 2 it as we go forward with the next revisions of the 3 DCD.
4 MEMBER STETKAR: I personally would hope; 5 and again I'll ask the staff about this because 6 they're reviewing it, that by the time the final DCD 7 is issued that there is more of a sense of and 8 integration between 19.3 and 19.4.
9 MR. SISK: And we've captured that and 10 we'll be looking into that.
11 MR. Y. KIM: Yes, the final section is 12 about the aircraft impact assessment. Aircraft impact 13 assessment of APR1400 was performed in accordance with 14 Reg Guide 1.217 and NEI 07-13. The integrity of the 15 containment and the spent fuel pool is maintained for 16 all strikes to meet the AIA requirement. The heat 17 removal assessments demonstrate that at least one 18 division of core cooling is available for all strikes.
19 Regarding the key design enhancement, we 20 have reinforcement and local strengthening measures 21 are taken to protect critical hallways and penetration 22 into containment. Physical separation of MCR and the 23 remote shutdown room and on-site power resource such 24 as EDJ and AEACEs are adopted in our design.
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67 1 due to aircraft impact, three hour late fire failure 2 and the high PSI barrier are incorporate in our 3 APR1400 design.
4 Let's move to next slide. Regarding the 5 assessment result, first one is core cooling 6 capability. Reactor cooling boundaries are not 7 perforate and protect all internal safety system. And 8 the integrity of a polar crane is maintained. And 9 critical hallways and the containment penetration are 10 physically protected. And the safety system in at 11 least one quadrant will remain functional for all 12 strike scenarios.
13 With respect to integrity of the spent 14 fuel pool, spent fuel pool is protected from direct 15 strike and the spent fuel pool wall and the support 16 structure will survive secondary impact if external 17 walls are perforate. And so spent fuel pool will 18 survive secondary missile from above if external wall 19 are perforated. And spent fuel pool will survive the 20 roof collapse if the external walls above spent fuel 21 pool are perforate.
22 So in conclusion, APR1400 meet 10 CFR Part 23 50.150. So we -- this AIA result shows that the cool 24 -- core cooling capability and the integrity of the 25 spent fuel pool. That is my end of presentation.
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68 1 MEMBER STETKAR: Can I come back to those 2 FLEX strategies, because I took a -- it's slide No. 3 27 --
4 MR. Y. KIM: Twenty-seven.
5 MEMBER STETKAR: -- where I asked about 6 the coping time for the low power. I just pulled up 7 that section of Revision 1 of the DCD. And indeed, 8 that information is still in there. The Phase 1 9 coping time is listed as three hours. And as we 10 become familiar -- in Section 19.3.2.3.1.3, for the 11 record -- so that it still is included in the DCD as 12 part of the strategy.
13 MR. Y. KIM: Yes, but we also provide the 14 separate technical document through the NRC. So there 15 was a -- could you help me?
16 MR. OH: Yes, for the -- when I checked 17 for 19.3 for the shutdown strategy for -- I corrected 18 my statement. I told that all the strategy is 19 eliminated, and that's not correct. It's for -- yes, 20 for some modification is done based on --
21 (Simultaneous speaking.)
22 MEMBER STETKAR: Yes, I -- so I see change 23 bars in the margin and I can't read very quickly and 24 speak and listen at the same time, but I did at least 25 confirm that Phase 1, 0 to 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br />; Phase 2, 3 to 72 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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69 1 hours1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />; and Phase 3, after 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> is still listed 2 explicitly in the DCD. As I mentioned, I personally 3 an happy to see that. And I'm glad to see that it was 4 not removed. Details of the changes we can review 5 when we see Rev 1 of the DCD. I just wanted to get 6 that on the record while we have you here to see if 7 you wanted to comment further.
8 MR. OH: Yes, there's some modification 9 has been done for that strategy according to the COL 10 action item.
11 MEMBER STETKAR: Okay. Thank you.
12 MEMBER BALLINGER: Finished?
13 MR. SISK: This is Rob Sisk, Westinghouse 14 again. And that does conclude our presentation on the 15 Chapters 6, 12, 13, 14, 16, 17 and 19 for today, 16 unless there are any other questions from the 17 Committee.
18 MEMBER BALLINGER: Mr. Chairman, I would 19 propose a --
20 CHAIRMAN BLEY: Yes, we will do a --
21 MEMBER BALLINGER: -- break until 10:15.
22 CHAIRMAN BLEY: We're in recess for 15 23 minutes until 10:17 by that clock.
24 (Whereupon, the above-entitled matter went 25 off the record at 10:01 a.m. and resumed at 10:17 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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70 1 a.m.)
2 CHAIRMAN BLEY: Meeting will come back to 3 order, please.
4 Dr. Ballinger, back to you.
5 MEMBER BALLINGER: Is the staff ready to 6 roll? That's a local term.
7 (Laughter.)
8 MEMBER BALLINGER: Bill, it's up to you.
9 MR. WARD: Thank you. We have the staff 10 presentation now. It's going to be done by the 11 chapter project managers and myself, and we're going 12 to defer to the tech staff and the audience for the 13 tough questions. So that's why we have them all here.
14 So we're going to cover all the chapters.
15 We're going to cover them by project manager. And I 16 have a few early slides.
17 As you know we've completed all the SERs, 18 so we're through Phase 2 with open items. All the 19 SERs have been submitted to the Committee. We are in 20 the process of completing Phase 3. We have one more 21 Subcommittee meeting with Chapters 7 and 18 in a 22 couple weeks.
23 As I said, we've issued all the SERs.
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71 1 essentially seven chapters. And we have more Full 2 Committee meetings scheduled in the future with 3, 4, 3 9 and 15, and then later 7 and 18.
4 We have issued SERs with no issues for the 5 -- three of the topical reports, and two more are 6 still in process. And I know one of the topical 7 reports is QAPD, which will come up later. Another 8 one KHNP has already issued the accepted version of 9 that. And they're working on a second one, so we're 10 making progress on topical reports as well. And those 11 are included in the future scheduling.
12 So the first presentation is on Chapter 13 13, which is conduct of operations. I will present 14 that. It has seven sub-sections. For the most part 15 Chapter 13 is the conduit for the applicant to pass on 16 how they expect operations -- operational programs, 17 etcetera, to be conducted and provide any information.
18 So 13.1 provides for the organizational structure of 19 the applicant and it requires that they develop the 20 management and organizational structure, including 21 design, construction, operating, and maintenance 22 responsibilities. This includes qualification 23 requirements such as education, training, and 24 experience. There were COL items in this section. We 25 reviewed the COL items. We had no issues or technical NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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72 1 challenges in that section.
2 13.2 is specifically on training. Again, 3 it provides a number of COL items. There were no 4 technical challenges there. There was one issue where 5 the COL item made the wrong reference and we asked and 6 RAI and corrected that, so there were no major issues 7 on 13.2.
8 13.3 is emergency planning. There were no 9 technical challenges there. There's a lot more to 10 review in 13.3 in the Technical Support Center size 11 and location. Descriptions were acceptable. The 12 interfaces between emergency planning and various 13 other parts of the DCD were reviewed in accordance 14 with the SRP and it was determined that they were 15 acceptably discussed in the other sections of the DCD.
16 13.4 is the operational program 17 implementation. This is all pretty much COL 18 requirements. We have a SECY paper, an SRM that give 19 the guidance for the staff as to how to approach this.
20 So this was reviewed in accordance with that paper.
21 The COL item was found acceptable.
22 13.5 is plant procedures. Again, it 23 contains COL items. The applicant briefly described 24 admin and operating procedures for all operational 25 modes and is scheduled for preparing the procedures.
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73 1 This is also where the applicant, DCD applicant 2 provides Emergency Operating Guidelines.
3 We reviewed the COL items. We found that 4 they were adequate and acceptable. Some of those are 5 -- were being edited. There was some question about 6 some wording. So we're waiting to confirm the 7 confirmatory actions on those.
8 The Emergency Operating Guideline were 9 found to be technically adequate and acceptable for 10 the COL to use as a basis for procedure development.
11 And we also reviewed a technical report, "Best 12 Estimate Analyses for Operational Transients and 13 Accidents for APR1400 EOGs," and found that it was 14 acceptable. And as KHNP discussed earlier, 13.6 is 15 physical security and 13.7 is fitness for duty, and 16 those were not presented to ACRS, but they've been 17 reviewed.
18 In summary, all the regulatory 19 requirements for Chapter 13 have been satisfied.
20 And if there are any questions, I'll 21 attempt to answer them for you.
22 (No audible response.)
23 MR. WARD: Okay. Next is Chapter 14 -- or 24 I'm sorry, 17. Seventeen is quality assurance and 25 reliability assurance.
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74 1 I'll be presenting that. Sections are 2 provided. There was a Quality Assurance program 3 description, QAPD, topical report submitted at the 4 very beginning of the project, actually in 5 preapplication. And that was reviewed and approved, 6 and it's up to I believe Revision 5 now. That report 7 provides the requirements for the QA sections, which 8 are 17.1, 2 and 3 and 17.5. That report and the 9 review of those sections shows that all the regulatory 10 requirements of Appendix B to Part 50 have been 11 satisfied. There are some COL items in Sections 17.2, 12 17.3 and 17.5, and those were found acceptable.
13 QA inspections have been performed. One 14 was performed a year ago; another one was completed 15 recently. And you'll have to look for the reports for 16 those as that's not really our realm to discuss.
17 Staff did review the D-RAP, Design 18 Reliability Assurance Program, ITAAC and compared the 19 list with PRA results. And that program was found to 20 be insufficient primarily because the applicant used 21 old guidance. And an RAI was issued and new guidance 22 was -- is being used for them to update their list.
23 And when that's completed we'll be able to complete 24 the review of that list.
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75 1 change after they change the PRA, or it could change 2 after they change the PRA again.
3 MR. WARD: That is correct.
4 MEMBER STETKAR: Okay.
5 MR. WARD: And there will be more 6 discussion in 19.
7 The maintenance rule section and the COL 8 item were reviewed and found to be acceptable.
9 That's all we have on Chapter 17. Any 10 questions on 17?
11 (No audible response.)
12 MR. WARD: Okay. Chapter 6.
13 MS. UMANA: Good morning. I'm Jessica 14 Umana. I'm the project manager for Chapter 6, which 15 is engineered safety features. The staff's areas of 16 review for Chapter 6 covered materials for engineered 17 safety features, containment systems, the safety 18 injection system, habitability systems, fission 19 product removal and control systems, in-service 20 inspections of Class 2 and 3 components, and in-21 containment -- I believe that should be in-containment 22 refueling water storage system.
23 Most of the regulatory requirements for 24 Chapter 6 have been satisfied.
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76 1 I've listed there and I'm going to briefly provide you 2 some information on the items that are listed there.
3 To start with, the staff is working and 4 communicating frequently with the applicant to develop 5 a path forward and bring closure to these items.
6 In the Subcommittee there was a question 7 about the swing panels. The staff has issued and RAI 8 requesting the applicant to provide information 9 describing whether or not the IRWST swing panels are 10 required to function properly and need to be included 11 in the tech specs in order to ensure continued 12 operability of the ECCS.
13 Moving on combustible gas control in 14 containment, which is Section 6.25 in the DCD. There 15 was a question that Dr. Rempe had from the 16 Subcommittee, and I believe the question is what is 17 the basis for the staff's satisfaction with MELCOR 18 containment nodalization.
19 The staff provided a response to Dr. Rempe 20 on May 8th. Containment modeling is addressed in many 21 -- contained in MELCOR reports where various 22 nodalization schemes have been shown to produce 23 results consistent with large experimental programs 24 such as NUPEC, HDR, and CVTR. These nodalization 25 schemes appropriately reflected both the openness and NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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77 1 complexity of the internal geometry of the specific 2 containments.
3 APR1400 has a large dry open containment.
4 The APR1400 nodalization both in the applicant's MAAP 5 4 and the staff's MELCOR model reflects openness of 6 the containment design as well as the locations and 7 elevations of the PARs and hydrogen igniters.
8 In summary, because the nodalization 9 scheme used to evaluate the mixing of containment for 10 APR1400 is sufficiently similar to the nodalization 11 for similar containment designs previously approved.
12 The staff's confirmatory calculation included more 13 nodes in the upper containment dome region than the 14 applicant's, and both the applicant and the staff's 15 results were within reasonable agreement with the 16 APR1400 results. The staff concluded that further 17 sensitivity was not necessary.
18 Moving onto boron recycling. The staff is 19 engaged with -- in discussions with the applicant.
20 The applicant will provide a discussion addressing how 21 the APR1400 design will control boron-10 concentration 22 in the IRWST, the safety injection tanks and the spent 23 fuel pool since APR1400 has the capability of 24 recycling boron. Currently the applicant has proposed 25 adding a tech spec or surveillance requirement for NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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78 1 boron-10 control, however, we're still in the draft 2 stages and don't have much more information to provide 3 on that front.
4 For the remaining issues the -- I'm sorry, 5 the last issue, which is containment structure and 6 mass and energy release, which I believe is Section 7 6.211 and 6.213 and 6.214 in the DCD, nothing has 8 changed since the Subcommittee. We are also engaged 9 in back and forth exchange with the applicant to bring 10 resolution to the open items for those sections.
11 And that's it for Chapter 6.
12 MEMBER POWERS: In the applicant's 13 presentation he assures us that in the post-accident 14 environment the IRWST water will remain at pH 7 or 15 higher throughout a 30-day period. Were you able to 16 confirm that conclusion, and how did you go about 17 doing that?
18 MS. UMANA: This is for the swing panels.
19 I believe you had the question on the swing panels 20 last time or --
21 VICE CHAIR CORRADINI: I'm the swing panel 22 person. He's the pH person.
23 MS. UMANA: Okay.
24 (Laughter.)
25 VICE CHAIR CORRADINI: Sorry.
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79 1 MEMBER POWERS: The swinger and the 2 stable --
3 (Laughter.)
4 MEMBER POWERS: -- sane individual.
5 MEMBER STETKAR: The old acidic guy.
6 MS. UMANA: The -- I don't think I have --
7 I know who this question is for and I don't think he's 8 here. Andrew Yeshnik's not in the crowd, is he? Or 9 was it Greg Makar? No. I'll have to take your 10 question back and provide you --
11 MEMBER POWERS: Yes, that's fine.
12 MS. UMANA: -- a response at a later date.
13 MEMBER POWERS: That's fine. I mean, just 14 point me in the right direction.
15 MS. UMANA: Okay.
16 MEMBER POWERS: Thank you a lot.
17 MS. UMANA: I didn't anticipate that 18 question. How's that?
19 (Laughter.)
20 MEMBER POWERS: Well, similarly in this; 21 I'm in Chapter 6, and kind of in Chapter 2 they look 22 at the dispersion of radioactivity toward the main 23 control room. How did you look at that?
24 (No audible response.)
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80 1 which I suspect one has to do fairly simply because I 2 don't think you can do it phenomenologically correct.
3 MR. WARD: You're asking about the 4 dispersion of radioactivity in the main control room?
5 MEMBER POWERS: Yes, around the intakes 6 and things like that.
7 MR. WARD: In any particular condition, or 8 just --
9 MEMBER POWERS: Post-accident.
10 MR. WARD: Oh, post-accident?
11 MEMBER POWERS: Yes.
12 MR. STECKEL: This is Jim Steckel. We do 13 have a discussion of that in Chapter 15 with regard to 14 the opening and closing of the vents. And we did have 15 several questions to iron out with KHNP.
16 MEMBER STETKAR: Jessica, in -- I was just 17 reviewing my notes from the Subcommittee meeting and 18 we had some discussions about whether or not the 19 applicant includes credit for what's euphemistically 20 known as containment accident pressure. I just pulled 21 up Rev 1 of Chapter 6 of the DCD and I note that they 22 do consistently with currently operating plants --
23 that they account for pressure equivalent to the 24 saturation pressure for the temperature of the IRWST 25 water. So for example, if the IRWST is at 110 degrees NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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81 1 C, they'll account for that amount of overpressure in 2 the containment to maintain net positive suction head 3 for the pumps. Has the staff reviewed any of that, 4 those analyses?
5 MS. UMANA: I do not know.
6 MEMBER STETKAR: Okay.
7 MS. UMANA: And again, I --
8 MEMBER STETKAR: There was some -- my 9 notes during the Subcommittee meeting, there was --
10 MS. UMANA: I recall the discussion, 11 but --
12 MEMBER STETKAR: -- some discussion about 13 whether or not the pumps would survive if the 14 containment were open to the environment. And there 15 seemed to be some people saying yes they would. Other 16 people -- but Rev 1 of the DCD seems to clearly 17 indicate -- it says for higher IRWST sump fluid 18 temperatures the containment pressure is assumed to 19 equal the saturation pressure corresponding to the 20 sump water temperature.
21 MS. UMANA: I think we may have an answer 22 for you, right?
23 MR. TRAVIS: So this Boyce Travis, the NRC 24 staff. The treatment we discussed in the Subcommittee 25 meeting is consistent with the description in Rev 1 of NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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82 1 the DCD. Those are just RAI responses to update. The 2 analyses do assume that the pressure credit for NPSH 3 assumed in the vapor pressure cancels out with the 4 saturation pressure of the fluid, as you stated.
5 In the event that -- so beyond the design-6 basis, an event that -- a loss of containment pressure 7 would result in flashing of the steam and the -- if 8 you look at our table, the margin they have available 9 in the post-accident condition versus the condition 10 that you're describing, that Dr. Corradini has the 11 slide available that I presented at the Subcommittee 12 meeting, they -- we didn't review that case 13 specifically because that's outside the design-basis 14 of the plant.
15 I'll state that based on the information 16 they provided the expectation is the same amount of 17 margin would be available in the case with atmospheric 18 containment pressure. If you open it instantaneously 19 versus the case -- the post-accident case where 20 they're crediting the vapor pressure up to the 21 saturation temperature of the fluid in the IRWST.
22 MEMBER STETKAR: Well, it can't be the 23 same margin available. The question is is adequate 24 margin available?
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83 1 reaches 212, based on how their analyses are credited, 2 the same margin is available from that point on 3 because they're crediting only the saturation pressure 4 associated with the temperature of the IRWST fluid.
5 They don't credit additional pressure in containment 6 beyond the saturation temperature of the fluid.
7 MEMBER STETKAR: Beyond the pressure for 8 the saturation temperature?
9 MR. TRAVIS: That's correct.
10 MEMBER STETKAR: So if the fluid was at 11 250 degrees Fahrenheit, the saturation pressure is --
12 I don't know what it is. Thermal-hydraulic people can 13 tell me what it is.
14 MR. TRAVIS: Call it 35 psi, something 15 like that.
16 MEMBER STETKAR: Yes. They account for 17 that?
18 MR. TRAVIS: That's correct.
19 MEMBER STETKAR: Okay.
20 MR. TRAVIS: But no higher than that.
21 MEMBER STETKAR: But no higher than that.
22 Right. I'm not arguing about no higher than that. On 23 the other hand, if I make 35 psi -- I don't know 24 whether you want to talk atmosphere or gauge, because 25 I don't remember -- if I make it 0 psi gauge, that NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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84 1 will reduce their margin if the temperature is 250 2 degrees Fahrenheit.
3 MEMBER MARCH-LEUBA: But in that case; 4 just to help you, in that case you can not maintain 5 250 --
6 MEMBER STETKAR: Correct.
7 MEMBER MARCH-LEUBA: -- because you will 8 flash and cool off the --
9 (Simultaneous speaking.)
10 MEMBER STETKAR: That's right, but you'll 11 flash first at the eye of the pump and it will 12 cavitate.
13 MEMBER MARCH-LEUBA: It's a complicated 14 calculation.
15 MEMBER STETKAR: It is a complicated 16 calculation. That's why pump manufacturers don't like 17 you to be in that -- I'm just trying to make sure that 18 I understand what is in the DCD, and I think I do now.
19 MR. TRAVIS: Okay.
20 MEMBER STETKAR: Thanks.
21 MR. TRAVIS: Do you require any further 22 clarification? Should I stay up here I guess is the 23 question I'm asking.
24 VICE CHAIR CORRADINI: Well, since you 25 brought up your presentation, remind me, since I NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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85 1 remember you explained it; now I can't remember, I 2 didn't write notes myself, the duration is actually 3 fairly short with holdup. So remind me what with 4 holdup means again?
5 MR. TRAVIS: So that analysis is not 6 specific to the APR1400. That --
7 VICE CHAIR CORRADINI: I understand that.
8 MR. TRAVIS: Okay.
9 VICE CHAIR CORRADINI: It was -- but you 10 wanted to explain to us --
11 MR. TRAVIS: Sure. So the analyses in the 12 DCD do not account for holdup of water in other 13 locations. It's a single containment node, so all of 14 the hot water goes instantly to the sump. In reality 15 some of that hot water is going to be held up in for 16 instance the holdup volume tank, various dead end 17 compartments in the steam generator rooms. And so 18 that hot water is going to act to reduce the sump 19 temperature and therefore shorten the duration that 20 the sump is above 212 degrees Fahrenheit.
21 VICE CHAIR CORRADINI: Thank you.
22 MR. TRAVIS: No problem.
23 MEMBER REMPE: So are you -- do you have 24 another comment?
25 MR. TRAVIS: No problem.
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86 1 MEMBER REMPE: Okay. No, I was talking to 2 Mike Corradini. His hand was up and I thought he 3 wanted to talk more. But it's gone now.
4 I wanted to thank you for your response 5 back on the hydrogen nodalization.
6 MS. UMANA: Okay.
7 MEMBER REMPE: And I appreciate it and I 8 don't need any further clarification, but I would like 9 to mention that there is an ongoing effort to get --
10 I may be saying it incorrectly, but the HYMERES 11 facility where they're getting CFD quality 12 experimental data to reevaluate this issue if the 13 nodalization is correct. And I believe research has 14 started in an effort with Caltech to try and evaluate 15 that. So might want to think about it in the future, 16 but I don't know the timing. And so again, I think 17 it's fine for what we're doing today. We don't have 18 additional knowledge yet, but there might be in the 19 future.
20 MS. UMANA: You said HYMERES?
21 MEMBER REMPE: It's H-Y-M-E-R-E-S. I may 22 be mispronouncing it. Do you know how to pronounce it 23 better?
24 MS. GRADY: This is Anne-Marie Grady and 25 I'm the staff that provided the response. And thank NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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87 1 you for that reference to HYMERES.
2 MEMBER REMPE: Okay. Thank you.
3 MS. GRADY: And I will look into that.
4 MEMBER REMPE: Okay. Thanks.
5 MR. WARD: Any other questions on Chapter 6 6?
7 MS. UMANA: I'm sorry, do you want to go 8 back to Chapter 6 and attempt to address --
9 MR. McCOPPIN: I think you asked the 10 question -- this is Mike McCoppin -- the question 11 about the dispersion in the main control room.
12 Michelle Hart's here, and she might be able to address 13 that question.
14 (Pause.)
15 MS. HART: I just got here.
16 MR. McCOPPIN: Yes, Michelle just got 17 here. She'd like the question repeated, if she could.
18 MEMBER POWERS: Oh, okay. Michelle, what 19 I'm interested in is how we calculate the dispersion 20 of radioactivity around the main control room in the 21 Technical Support Center.
22 MS. HART: Are you talking about within 23 the control room?
24 MEMBER POWERS: No, no.
25 MS. HART: To the control room?
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88 1 MEMBER POWERS: To them.
2 MS. HART: We used the RCON 96 computer 3 code, and it is based on hourly data for a year, much 4 like we do for the off-site analysis, but it does 5 include building wake effect. And if there's a lot of 6 heat behind it, it does include lofting. But this 7 plan there's not that --
8 MEMBER POWERS: Didn't find any --
9 MS. HART: And there's no effect from 10 being released from a stack either.
11 MEMBER POWERS: Oh, okay. As long as I've 12 got you here, in their assertion of pH 7 what kinds of 13 things did we look at to make sure that they 14 maintained a pH of 7 in the IRWST for 30 days?
15 MS. HART: Well, I do have to admit I did 16 not look at that analysis. That was somebody from the 17 Chemical Engineering Branch.
18 MEMBER POWERS: Oh, okay. Okay. Fine.
19 MS. UMANA: Any other questions related to 20 Chapter 6?
21 (No audible response.)
22 MR. WARD: Okay. We'll move onto to 23 Chapter 16.
24 MS. UMANA: I also have Chapter 16, which 25 is the generic tech specs. Yes, it's my favorite.
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89 1 That's quasi-true.
2 (Laughter.)
3 MS. UMANA: The tech specs are based on 4 combustion engineering standard tech specs, NUREG-5 1432, Revision 40. The difference between the 6 combustion engineering tech specs and the generic tech 7 specs are based on design variations unique to 8 APR1400.
9 A review of the generic tech specs has 10 been conducted resulting the safety evaluation chapter 11 that includes open items in the following areas:
12 Adequacy of requirements during reduced RCS inventory, 13 requirements to prevent inadvertent reactor coolant 14 boron dilution, AFW required actions and completion 15 times appropriate to the APR1400 design, CRHS required 16 actions and surveillances, accident monitoring 17 instrumentation requirements, and application of LCO 18 criteria, TSTF disposition and COL action items.
19 Regarding the application of LCO selection 20 criteria, the applicant did not use a systemic process 21 of evaluating the safety analysis and SSCs against the 22 criteria, but relied on evaluating applicability of 23 combustion engineering standard tech spec's LCOs to 24 APR1400 SSCs in applying engineering judgment.
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90 1 consider additional measures to ensure the criteria is 2 satisfied; that is, that the tech specs include LCOs 3 for all SSCs, parameters and initial conditions that 4 satisfy their criteria.
5 The open items are being discussed. We 6 have continuous back and forth exchange with the 7 applicant in coordination with other branches for 8 closure to the open items related to Chapter 16.
9 One thing I did want to mention before 10 concluding this presentation for Chapter 16 -- I 11 wanted to talk about requirements for mitigating 12 shutdown risk. They have been included and go beyond 13 requirements in the standard tech specs.
14 In the Subcommittee presentation given in 15 March of this year there was a question about the role 16 of risk insights into the development of the tech 17 specs. It's correct to say that the tech specs are 18 not risk-informed and that significant risk-informed 19 initiatives have not been incorporated. However, LCO 20 3.0.8, which is based on TSTF Traveler 372 and relates 21 to inoperable snuffers and LCO 3.0.9, which is based 22 on TSTF Traveler 427 and relates to inoperable 23 barriers, require risk insights for adoption. These 24 risks are presented in the form of generic risk 25 evaluations which are included with the travelers.
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91 1 The applicant provided an equivalent evaluation for 2 LCO 3.0.8 and is considering providing an evaluation 3 for LCO 3.0.9.
4 And finally, pending resolution of the 5 open items verification of compliance with the 6 regulations is not yet quite complete.
7 MEMBER STETKAR: I would just --
8 MS. UMANA: Any questions?
9 MEMBER STETKAR: No.
10 MS. UMANA: I know you have questions.
11 MEMBER STETKAR: No, I don't actually. I 12 was just going to make a statement. That being said, 13 there's this -- for the benefit of the other Committee 14 members, there's this notion of are the tech specs 15 risk-informed? And they're not risk-informed 16 according to the process related connotation of risk-17 informed.
18 However, as Jessica noted, the tech specs 19 do have specific LCOs in them in particular for 20 shutdown, which she mentioned, that evolved from 21 information that came out of the risk assessment. So 22 the applicant used the risk assessment and insights 23 from the risk assessment to establish conditions in 24 their tech specs despite the fact that they are not, 25 quote/unquote, "risk-informing" their completion times NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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92 1 or their surveillance intervals. I hope that's 2 accurate.
3 MS. UMANA: If there are no other 4 questions for Chapter 16, I'm going to turn it over to 5 the next presenter.
6 MR. WARD: The next chapter will be 7 Chapter 12.
8 MR. TESFAYE: Good morning. My name is 9 Getachew Tesfaye. I'm the project manager for 10 Chapters 12 and 14. I have a couple of staff member 11 here to support me if there are any questions.
12 Chapter 12, radiation protection. The 13 Subcommittee presentation was on February 24. We 14 looked -- the staff looked at various sections. The 15 first one is ensuring that occupational radiation is 16 ALARA. Section 12.2, radiation source. Section 12.3 17 and 12.4, radiation protection design features, 18 including dose assessments. And the last section is 19 Operational Radiation Protection Program.
20 For Section 12.1 and 12.5 all the 21 regulatory requirements have been met. There are no 22 open items. For Sections 12.2, 12.3 and 12. 4 and --
23 I repeated 12.5 here again, so I apologize for that.
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93 1 in Sections 12.2 and nine open items in Section 12.3 2 and 12.4.
3 So the staff has been working on these 4 open items. There are no show stoppers. We have to 5 complete our Phase 4 review of Chapter 12 soon and be 6 able to present the completed SER with no open items 7 in Phase 5.
8 That's all I have. Any questions for 9 Chapter 12?
10 (No audible response.)
11 MR. WARD: The next chapter is Chapter 14.
12 MR. TESFAYE: Chapter 14 is kind of 13 complicated. We've done 14.1 and 14.2 in Phase 2, and 14 we deferred 14.3, the ITAAC for Phases 4 and 5. In 15 Section 14.1 of course there's no open items. In 16 Section 4.2 staff looked at the four phases: pre-17 operational testing, fuel loading and post-core hot 18 functional tests, initial criticality and low-power 19 physics tests, and power ascension tests. The number 20 of tests in each category may increase as a result of 21 response to open items.
22 Currently for Phase 2 we have 16 open 23 items in Section 14.2. And again, 14.3 is -- the 24 whole section is an open item that will be addressed 25 in Phase 4.
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94 1 That's all I have for Chapter 14. Any 2 questions?
3 MEMBER KIRCHNER: Yes. So the open items 4 included things like steam generator blowdown, 5 hydrogen mitigation, liquid and gaseous waste 6 management, etcetera. Is this because the COLA will 7 address those items, or why are they -- I'm just 8 curious. Why did they remain open at this phase?
9 MR. TESFAYE: Well, they're open because 10 the applicant needs to provide more information, 11 whether this is going to be a COLA item or the 12 laboratory test to this chapter. So it's pending the 13 applicant's response.
14 MR. WARD: Any other questions?
15 (No audible response.)
16 MR. WARD: Was that response satisfactory?
17 MEMBER KIRCHNER: Yes, thank you.
18 MR. WARD: Okay. All right. We'll move 19 onto Chapter 19. This is going to be 19, 19.3, 19.4 20 and 19.5. And it's Jim Steckel.
21 MR. STECKEL: Thank you.
22 CHAIRMAN BLEY: Why don't I sneak in the 23 question I asked the applicant earlier?
24 From what they told us this time around 25 when we get to the COLA stage they're saying the COLA NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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95 1 PRA will need to do a seismic PRA and things 2 associated with local water conditions and events. Is 3 that your understanding as well? I mean, the past 4 other applicants have done kind of a surrogate for 5 those things and then only required at the COLA stage 6 that people show they're better than the surrogate.
7 We don't have that this time, so it sounds like 8 they're doing it what I would call the right way this 9 time.
10 MR. STECKEL: I'm going to -- this is Jim 11 Steckel. I'm going to defer to one of the reviewers.
12 Hanh, can you answer that?
13 MR. PHAN: Hello, Hanh Phan, the lead 14 reviewer for PRA.
15 So far the applicant provides us the PRA 16 page SMA. And according to the staff guidance that is 17 acceptable for the DC applicant. With that we would 18 not ask them to further perform any analysis or 19 address any CDF or error now at this point. However, 20 there is a clear COL information items asking the COL 21 applicant to perform a full-scale PRA, seismic PRA 22 when they have the site-specific information.
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96 1 contribute much to the staff positions regarding their 2 application.
3 CHAIRMAN BLEY: I can't say that I 4 understood that answer. I don't. And it -- the whole 5 process doesn't seem consistent with what we've done 6 elsewhere. So the applicant said people doing the COL 7 will have to do a -- those site-specific analyses.
8 And it sounds like you said no they don't.
9 MR. PHAN: Yes. Yes, they will do.
10 CHAIRMAN BLEY: That's what you said?
11 MR. PHAN: It's the other applicants --
12 (Simultaneous speaking.)
13 CHAIRMAN BLEY: Okay. I misunderstood 14 what you said.
15 MEMBER STETKAR: Let me, because I'm 16 confused again. Let me ask you a very specific yes/no 17 question.
18 Will the COL applicant's submittal to the 19 NRC for the COL review contain a risk assessment that 20 includes quantification of the seismic risk? That's 21 a yes or no question.
22 MR. PHAN: No.
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97 1 from seismic events be expected from someone who will 2 eventually operate one of these plants?
3 MR. PHAN: Before the 103 filing.
4 MEMBER STETKAR: Well, since --
5 PARTICIPANT: Before fuel load.
6 MEMBER STETKAR: Thank you for putting 7 that into English. Before fuel load?
8 MR. PHAN: Yes.
9 MEMBER STETKAR: Okay. Thank you. That's 10 on the record now from the staff.
11 MR. PHAN: May I be clear by saying a 12 little bit more? In the COL phase there are RCOL 13 applicants and SCOL applicants. For the R, the 14 reference COLs, they can -- under Part 52 they can 15 submit their application early using DC information.
16 By that, they can use the information in the DCD 17 Chapter 19 to justify the risk, but however they have 18 to do more by performing the PRA, seismic PRA to 19 identify the risk.
20 MEMBER STETKAR: I'm sorry, you said the 21 words "seismic PRA," so I will ask you a specific 22 question. Will they submit a risk assessment at the 23 COL? Since you want to differentiate between RCOL and 24 SCOL, will an RCOL applicant be expected to submit a 25 risk assessment that quantifies the risk from seismic NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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98 1 events? Again, yes or no?
2 MR. PHAN: Not the quantification risk.
3 MEMBER STETKAR: Thank you. That's what 4 I consider risk. Anything else is not a risk 5 assessment.
6 MR. PHAN: Thank you.
7 CHAIRMAN BLEY: I'd offer two things, and 8 I hope the staff thinks about this long and hard: The 9 previous design certs included a section in Chapter 19 10 that essentially bracketed these environmental events 11 and showed they were I'll just say okay under those 12 specific conditions, which then a COL applicant had to 13 show that they met that list of conditions to avoid 14 doing -- including those in their COL PRA. That isn't 15 true this time, so I think you ought to think about 16 this a bit.
17 And secondly, there ought to be no 18 distinction between an RCOLA and SCOLA because every 19 site's different. Enough said for now.
20 MR. STECKEL: Is there another question?
21 (No audible response.)
22 MR. STECKEL: If not --
23 CHAIRMAN BLEY: From me? No.
24 MR. STECKEL: Okay. We'll move on.
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99 1 shown there. The probabilistic risk assessment and 2 severe accident sections take up 19.1, 19.2. 19.3 is 3 beyond-design-basis external events; 19.4, loss of 4 large areas; and 19.5, aircraft impact assessment.
5 Next slide, please? So concerning PRA the 6 areas of review are considering the scope, techniques, 7 level of details and technical adequacy: Internal 8 events Levels 1 and 2, at-power and during low power 9 and shutdown; internal fire Levels 1 and 2, at-power 10 and during low power and shutdown; internal floods 11 Levels 1 and 2, at power and during low power and 12 shutdown; PRA-based seismic margin assessment; and 13 other external events. And we also did key 14 assumptions and risk insights; PRA maintenance and 15 update; uses and applications of APR1400 design-16 specific PRA.
17 Next slide, please? So the main focus 18 areas here are: The PRA model conversion from SAREX 19 to CAFTA, which is ongoing; PRA peer review findings 20 and resolution; digital I&C modeling; seismic 21 assessment during low power and shutdown; PRA update; 22 consistency between the DCD and supporting information 23 such as the PRA notebooks; sensitivity studies, risk 24 insights, update of PRA input to other DCD chapters 25 and programs; and RAI reconciliation.
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100 1 If there are no questions on 19.1, we'll 2 move to 19.2, severe accident evaluation.
3 MEMBER STETKAR: The fifth bullet under 4 there says PRA update. What are you going to do about 5 that? I know you've done audits for the I'll call the 6 Rev 0, Rev 1 version of the PRA. Are you planning to 7 do additional audits after they change the models and 8 have evaluation?
9 MR. STECKEL: We -- this is an area of 10 discussion we're having right now, and an area where 11 we'll need to engage again with ACRS to determine 12 their agreeability to have additional review.
13 MEMBER STETKAR: Okay. So it's still a 14 work in progress?
15 MR. STECKEL: It's still a work in 16 progress --
17 MEMBER STETKAR: Thank you.
18 MR. STECKEL: -- at this point.
19 And, Hanh, did you need to mention 20 anything more?
21 MR. PHAN: Yes, I have further 22 clarification regarding APR1400 PRA models.
23 Right now the applicants, they do have 24 three models. The original model in the original 25 submittals using the SAREX software. During the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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101 1 review they told us that they convert their models 2 into another software, CAFTA. During that conversions 3 they incorporate the -- some of the staff findings, 4 some of the peer review findings and their self-5 assessment, the type of methods in their original 6 models.
7 With that, last year they present to us 8 the quantification of the CAFTA models and they told 9 us that complete this, but we have not seen that model 10 yet. We only saw their presentation. Right now they 11 told us that they finished with that conversion and 12 they are working on the update.
13 The update means that they're going to 14 incorporate all the findings from the peer review, 15 from the staff RAIs and any comments from that ACRS.
16 That model would not be complete until September, so 17 staff will have another reviews of that latest PRA 18 model in the future, near future.
19 MEMBER BALLINGER: Now I'm confused again.
20 And that is I heard the words "further engagement with 21 the ACRS." And that is, at least the way I interpret 22 those words, inconsistent with what Bill has said.
23 MR. WARD: I'll answer that.
24 Yes, I was checking with staff in the 25 break and there is an interest in providing in a NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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102 1 meeting of some sort some information prior to the 2 actual Phase 5 Subcommittee, Full Committee meetings.
3 Exactly what form that would take or what -- how much 4 would be provided or when -- well, what's provided is 5 going to depend on when, but there is an interest in 6 some sort of meeting to provide you some advance 7 information before we get to that point in Phase 5.
8 MEMBER BALLINGER: Okay. So that's a 9 change?
10 MR. WARD: It has recently been proposed 11 from staff, yes.
12 MEMBER STETKAR: Sounds like we're --
13 basically it's a work in progress at this snapshot in 14 time.
15 MR. WARD: I think the goal is to provide 16 you as much information as we can because we don't 17 want to have surprises. Nobody does. But it's really 18 hard to manage it with the schedule and the timing of 19 the information coming in.
20 MR. PHAN: Hello, this is Hanh Phan again.
21 Base on the comments from the ACRS the staff proposed 22 that upon ACRS approvals that in Phase 5 we're going 23 to have two presentations. One in the early of Phase 24 5 and one at the end of Phase 5. The early 25 presentation would be sent to the Subcommittees on PRA NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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103 1 regarding the staff observation on their latest PRA 2 information. And then at the end of Phase 5 we will 3 come back and present to you the staff accept the 4 evaluation report without open items and including any 5 comments, any feedback from the Subcommittee, ACRS 6 Subcommittee on their PRA models. But that upon the 7 ACRS approval.
8 MEMBER BALLINGER: I guess this is 9 definitely a work in progress. So we'll have to deal 10 with that, not here.
11 MR. WARD: I agree.
12 MEMBER BALLINGER: Not today, anyway.
13 MR. WARD: I agree.
14 MEMBER SUNSERI: And, Bill, that proposal 15 that's been laid out, I presume that does not include 16 at this time engagement with KHNP or any of their PRA 17 folks. Is that correct?
18 MR. WARD: Not as I understand it.
19 MR. STECKEL: It could change. I think we 20 can move onto 19.2, severe accident evaluation. These 21 were the areas of review: accident prevention; 22 accident mitigation, MELCOR confirmatory analysis; and 23 containment performance capability.
24 An area that is still ongoing and is a 25 strong focus area is the MAAP analysis of mid-loop NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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104 1 accidents. There are -- there's calculations that 2 we're doing, confirmatory calculations. And we're 3 still working with KHNP to complete those. And the 4 structural analysis of ex-vessel steam explosion --
5 (Simultaneous speaking.)
6 VICE CHAIR CORRADINI: So, Jim, can you 7 explain the last bullet? I'm not sure what that 8 means.
9 MR. STECKEL: I am going to get an expert 10 so that I don't --
11 (Laughter.)
12 MR. STECKEL: -- misstate a thing.
13 So if the reviewer is available on this?
14 Hanry? Hanry Wagage.
15 MR. WAGAGE: My name is Hanry Wagage.
16 Applicant has presented results from --
17 MR. STECKEL: I think you need to get 18 closer, Hanry. Kiss that mic, so to speak.
19 (Laughter.)
20 MR. WAGAGE: Hi, this is Henry Wagage.
21 The applicant has presented results of structure 22 analyses performed for preference plant, similar 23 plant. So we have been reviewing these result. We 24 were -- we had some questions. For example, how the 25 applicant attenuated the pressure calculated from NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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105 1 steam explosion, how they attenuated the pressure and 2 applied on the tops of walls. That's one example.
3 So we had questions like that that the 4 applicant has to address those questions. There's an 5 open item because of that, how the applicant performed 6 structurally.
7 VICE CHAIR CORRADINI: Okay. So it's --
8 the analysis is underway that you get to review?
9 MR. WAGAGE: That's right.
10 VICE CHAIR CORRADINI: Okay. All right.
11 Thank you.
12 MEMBER REMPE: So I'd like to also chime 13 in about some of this. The Subcommittee meeting we 14 learned about the document the staff had prepared with 15 the MELCOR confirmatory calculations. And so after 16 that we had the opportunity to review it and we 17 discussed some of those calculations with the staff.
18 This has been an accelerated schedule for review. At 19 the time the staff did those calculations, they had 20 some differences in their assumptions regarding the 21 plant. And maybe they didn't pick the sequence of 22 most interest.
23 We've heard today earlier that there may 24 be some differences in the risk assessment results.
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106 1 steam generator tube rupture effects might be 2 different when one looks at the natural circulation 3 for a CE plant-specific configuration based on CFD for 4 a CFD -- a CE plant versus a Westinghouse plant that 5 was assumed.
6 It seems to me that the staff may want to 7 look at the results from the revised risk assessment.
8 They may even want to say I want to try and run a 9 different case for a confirmatory calculation. Those 10 kind of issues, are they still on the table or are we 11 going to at least -- if they don't run additional 12 analyses are we going to have some confidence that we 13 believe that the confirmatory MELCOR calculations that 14 were performed give us confidence about what may be 15 very important with respect to the risk assessment?
16 MR. STECKEL: Just let me mention before 17 Jason begins that this was a rather long RAI with many 18 questions associated with it. Not all of them were 19 specific. Many of them were we've noticed this in 20 this limited number of things we've looked at. These 21 things needs to be looked for in many other areas.
22 And so that is still an ongoing process, but we'll get 23 further clarification from Jason Schaperow.
24 MR. SCHAPEROW: Yes, this is Jason 25 Schaperow of the staff. With regard to the steam NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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107 1 generator tube rupture observation, as you mention, 2 Dr. Rempe, the latest NRC report on that shows the 3 likelihood of steam generator tube rupture for a CE 4 plant of roughly 0.25 given a core melt accident for 5 a CE plant, whereas for a Westinghouse plant it's 6 about a factor of 10 lower.
7 The MELCOR confirmatory calculations that 8 we're doing won't really shed any light on that 9 because the analysis that was done for steam generator 10 tube rupture is a combination of a materials 11 evaluation of the tubes and the MELCOR calculations.
12 And we're not going to be redoing that for this 13 particular plant specifically.
14 With regard to your question about the 15 tube rupture probability that was previously thought 16 to be based on NUREG-1570, the numbers in there -- if 17 I recollect correctly, were for Westinghouse-style 18 plants were on the order of 0.25. So my understanding 19 is that basically the numbers stay kind of the same 20 from back in 1998 to now for -- except for the 21 Westinghouse numbers got smaller. The original 22 analysis ones for Westinghouse --
23 MEMBER REMPE: It would be good to see 24 that --
25 (Simultaneous speaking.)
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108 1 MR. SCHAPEROW -- 0.25.
2 MEMBER REMPE: I guess I'd like --
3 MR. SCHAPEROW: That's my understanding of 4 it.
5 MEMBER REMPE: -- that because again, I 6 thought the CFD analyses that were done for the 7 Westinghouse plant -- let's see that documented and 8 let me explore that more, because that would be good 9 to see.
10 But the other question is for the analyses where 11 you had different decay heats and things like that, 12 there may be some differences in geometry. Do you 13 feel like you'll have confidence in what they produce 14 finally?
15 MR. SCHAPEROW: So for the at-power 16 scenarios we believe we have reasonable agreement with 17 the MAAP results. For the shutdown scenarios, the 18 mid-loop calculation particularly, we've identified 19 some issues we think with their calculations. And 20 they're redoing those calculations now and they're 21 redoing the documentation. So we're waiting to see 22 what the new documentation says about their updated 23 MAAP calculations. And theoretically that would also 24 be reflected in our updated PRA.
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109 1 need to do any sort of revised MELCOR analyses?
2 MR. SCHAPEROW: We are in a position that 3 we could do some more, but again I would wait to see 4 what they come up with before we start spending effort 5 to redoing any MELCOR calculations at this time.
6 MEMBER REMPE: So if you do that, if it --
7 you make that decision to do that, which again it may 8 not be necessary; no one wants to waste money, there 9 were some calculations done in a separate SORCA 10 evaluation for Korea. And so my understanding is 11 there might be a better model to start with for the 12 MELCOR calculations. Have you -- are you aware of 13 what I'm talking about --
14 MR. SCHAPEROW: I --
15 MEMBER REMPE: -- that there might be such 16 a model --
17 MR. SCHAPEROW: I have --
18 MEMBER REMPE: -- that would start with a 19 plant that might be --
20 MR. SCHAPEROW: Yes, I've heard of --
21 MEMBER REMPE: You might want to compare 22 those plant models, at least.
23 MR. SCHAPEROW: I'll need to check with 24 Research on that. I think they may know more about 25 that than I.
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110 1 MEMBER REMPE: Okay. It might be good to 2 do that.
3 Then the last thing I'd like to talk about 4 is this thing about in-vessel retention and this 5 optional system, or option, and what's -- where -- how 6 much was the staff reviewing it? Because if you don't 7 take credit for that system, there's a heat transfer 8 coefficient from the vessel. What was assumed? I 9 mean, it seems like that you've got this system in 10 there and you said, well, okay, we didn't take credit 11 for it, so we're going to let the vessel fail. But 12 then in reality are there some unintended effects by 13 making that observation we're not going to evaluate 14 it?
15 MR. WAGAGE: Actually -- this is Hanry 16 Wagage from the staff. The applicant did not take 17 credit for this system for steam explosions. They did 18 not take credit. Because of that there is no reason 19 for the staff to look at how good the heat transfer 20 coefficient, how well is going to cool.
21 Staff's concern was that it was different.
22 If the vessel is -- if the cavity is flooded covering 23 part of the vessel, if by using the system, if the 24 melt freezes and -- at the bottom and vessel is 25 failing at the site on the top by metallic layer, then NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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111 1 much larger melt core would occur. That's the concern 2 staff had, not that how well the system worked, 3 because the applicant did not take credit for the 4 system.
5 VICE CHAIR CORRADINI: So, Hanry, since 6 you brought it up; it's your fault, I thought APR1000 7 went through all of this in -- back in -- 20 years 8 ago. So staff was okay with it then. What changed?
9 All of this in terms of the physics and the situation 10 geometrically are quite similar.
11 MR. WAGAGE: Thanks for the question.
12 VICE CHAIR CORRADINI: No problem.
13 MR. WAGAGE: APR1000 --
14 (Laughter.)
15 MR. WAGAGE: -- during the review of 16 APR1000 staff had the same concern. Then applicant 17 for APR1000 argued that kind of much larger melt core 18 would not occur.
19 VICE CHAIR CORRADINI: Right.
20 MR. WAGAGE: However, staff raised an 21 issue that there are so much uncertainty. Then the 22 applicant went ahead and did structural analyses to 23 show that with much larger melt core there will be 24 much larger energy generation by steam explosion.
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112 1 would stay intact.
2 VICE CHAIR CORRADINI: Okay. So your --
3 MR. WAGAGE: So that's how it is you close 4 for APR1000.
5 VICE CHAIR CORRADINI: So your point is 6 that analysis is yet to be done, but you don't need to 7 do it simply because applicant is not offering this as 8 the base design? This is -- we'll call it an optional 9 addition in the design?
10 MR. WAGAGE: That's right.
11 VICE CHAIR CORRADINI: Okay. Fine.
12 MEMBER REMPE: But before you went with 13 the APR1000 folks, you first of all had a bunch of 14 questions about how robust is this cavity cooling 15 system. Will it withstand the event? Basically you 16 made them reinforce it so that it could always have 17 water come in and the steam could be generated 18 externally. Those kind of calculations or evaluations 19 or will not be done if you say, okay, we're not going 20 to take credit for it. It doesn't matter.
21 Furthermore, someone has in their MAAP 22 evaluation made certain assumptions about the heat 23 transfer from the vessel. Now you've got an isolated 24 volume. If you don't take credit for it, what did you 25 assume -- I mean, you have this insulation, so you NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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113 1 have a gap. And so you have less heat coming out of 2 the vessel than you would if you did not have that 3 system there. There is that system there that could 4 actually fall into the vessel, that could even make 5 the situation worse.
6 And so those kind of discussions are not 7 occurring because we're not taking credit for it. And 8 so maybe that's fine. You throw it off to the COL 9 applicant, but then somebody, if they ever want to 10 take credit for it, needs to realize that it's going 11 to be a lot more evaluations that have to be 12 performed. And that's what I'm trying to argue for 13 with all these questions today.
14 VICE CHAIR CORRADINI: They didn't want 15 air-conditioning so they're not going to evaluate air-16 conditioning.
17 MEMBER REMPE: Yes. But then -- but there 18 are some adverse effects. And so, and that ought to 19 be documented in the staff draft SE or in the -- in 20 the whatever that we -- we're assuming this didn't 21 exist and they need to verify that the applicant truly 22 did assume it didn't exist and considered the fact 23 that there's something in there that they're not 24 evaluating, and they properly considered that. And 25 then say if you ever want to come in and take that NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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114 1 option, you got to do a lot of analyses.
2 MR. WAGAGE: I agree, because the 3 applicant needs to take credit for this system. Staff 4 heard that applicant has to show how good the system 5 works. Right at this stage there is very little 6 information provided in the DCD. In one place it's 7 mentioned there are insulations around the vessel at 8 the bottom, that there is no -- not much information.
9 Just one sentence.
10 So how was -- staff didn't have any 11 concern about that, because there is no reason how 12 well the system works. But opposite if the system 13 does not work. If the system is operating and 14 unintended consequence happens, like larger melt core.
15 That's what the staff was focused on.
16 MEMBER REMPE: Yes, okay. So I think 17 we're communicating, and it's just another issue. If 18 we have another interaction before -- what was it 19 called, Rev 5 or whatever --
20 PARTICIPANT: Phase 5.
21 MEMBER REMPE: -- Phase 5 is occurring, it 22 would be something I'd like to see included in the 23 discussion.
24 MR. STECKEL: We'll take that under 25 consideration.
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115 1 MEMBER REMPE: Thank you.
2 MR. STECKEL: We can move onto the next 3 slide. Beyond-design-basis external event. These 4 were the areas of our review: The external hazards; 5 core cooling; containment; spent fuel pool cooling; 6 ventilation; water and fuel supplies; FLEX equipment 7 and off-site resources; power supply; shutdown ops; 8 protection of equipment; mechanical equipment 9 capability; programmatic controls and procedures; and 10 COL information items.
11 To summarize in the next slide, we found 12 the applicant's approach consistent with applicable 13 guidance and to be acceptable and subject to the 14 verification of our confirmatory items and our DCD --
15 and the DCD and technical report modifications 16 specified in the RAI responses.
17 Questions?
18 (No audible response.)
19 MR. STECKEL: Moving onto 19.4, loss of 20 large areas. These are the areas of our review: DCD 21 enhancements addressing 50.54(hh)(2) for firefighting, 22 actions to minimize fuel damage, and actions to 23 minimize radiological release; and review for 24 conformance with NEI 06-12 and the guidelines in 25 Revision 3 including firefighting, measures to NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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116 1 mitigate damage to fuel in the spent fuel pool, 2 measures to mitigate damage to the fuel in the reactor 3 vessel, and to minimize radiological release. We had 4 -- I believe we had one RAI involved in this. It was 5 answered. There are no open items.
6 And the next slide shows a quick 7 discussion on mitigative strategy. Applicant 8 addressed each item in the mitigative strategy table 9 and identified those considered COL items and those 10 provided as design enhancements. And our conclusion 11 is with incorporation of the confirmatory items in the 12 next DCD revision staff will be able to conclude that 13 the LOLA DCD section includes the necessary 14 information to find that design enhancements conform 15 to the guidance in NEI 06-12.
16 MEMBER STETKAR: Jim, as I mentioned when 17 the applicant was up, when I read Section 19.3 and 18 Section 19.4 of the DCD and read the corresponding 19 sections of the staff's safety evaluation, they read 20 as if they are submittals for an apple and a review of 21 an apple and submittals for a tractor and review of a 22 tractor. I'm trying to emphasize the fact that these 23 are not integrated at all.
24 Your slides confirm that. You said you've 25 reviewed this against 10 CFR 50.54(hh)(2), which will NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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117 1 disappear. It won't be existing anymore if indeed the 2 Commission approves 10 CFR 50.155. It's integrated 3 into the new rulemaking. There is any number of 4 different NEI reports that you can cite that have 5 different numbers and different revisions. There's 6 Interim Staff Guidance.
7 My basic question is how is the staff 8 going to resolve the intent of the proposed rulemaking 9 and its regulatory guidance and Revision 2? If you 10 want to get into Interim Staff Guidance, JLB-ISG-2012-11 01, the intent of that for an applicant to integrate 12 their mitigating strategies. How are you going to 13 review that before we finally have an accepted DCD?
14 Because right now it doesn't do it in an integrated 15 manner.
16 MR. DIAS: Good morning. This is Antonio 17 Dias from NRO. I believe I can answer partial -- part 18 of your question.
19 It is true there are many, many guidances, 20 and everyone is aware that there's a rule that is 21 about to be issued. We just don't know when. So when 22 we were looking at the application, we just made sure 23 that the application made reference to the current 24 guidance at the time.
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118 1 from KHNP, the one that was at the time was the ISG 2 Rev 1 that references NEI Rev 2. That was issued in 3 January of 2016. There's a new revision to the ISG, 4 which is dated February 17. And that's already 5 addressing NEI, endorsing NEI Rev 4. I just opened --
6 I went up. There's a 4. NEI is very prolific with 7 their guidances. Okay?
8 So, yes. So it's very confusing. And I'm 9 going to say the question that you pose also is 10 applicable to even to some of the ones already issued.
11 And JLD is taking the role -- the group, the Special 12 Office JLD is taking the role of how to actually 13 perhaps convert some of the license requirements and 14 how that's going to be brought back into a rule once 15 the rule is issued.
16 But the problem with KHNP is that we 17 cannot wait and see exactly how the rule is going to 18 be issued and when, so we are basically moving forward 19 with guidance that currently existed. In the case of 20 KHNP, because the latest revision of the ISG came in 21 after the report, we are not going to ask them to go 22 back and address that revision to the NEI, or the 23 revision to the ISG. So it's kind of a little bit of 24 a who-goes-first situation.
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119 1 discrepancies between 19.3 and 19.4, that's a very 2 good point, and I think we should take a look at this.
3 MEMBER STETKAR: I know you have a 4 dilemma. On the other hand, the applicant ostensibly 5 is one organization and the NRC is ostensibly one 6 organization. And if I look at things in a DCD that 7 have a functional capability and in one section of the 8 DCD where that functional capability is specified as 9 having -- I can't find it in my notes, so I'll make up 10 numbers -- 750 gpm. And in the next section of the 11 DCD the same functional pump is specified as having a 12 capacity of a 1,000 gpm, it strikes me as an anomaly.
13 And that in the sense of integrating these 14 mitigating strategies somebody ought to identify the 15 fact that that pump in the certified design ought to 16 have a specified capacity. I don't care whether it's 17 750 or 1,000. The capacity ought to be based on 18 functional requirements and whether that pump is used 19 for an administrative licensing requirement in Section 20 19.4 or whether it's used for the administrative 21 requirement in Section 19.3. We ought to have clarity 22 on what the pump is so that when the COL applicant 23 goes out to buy a pump, he doesn't have to buy two and 24 he doesn't have to figure out whether it ought to be 25 somewhere halfway between 750 and 1,000 gpm.
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120 1 MR. DIAS: Right. I understand.
2 MEMBER STETKAR: So I don't know where --
3 and that I thought was the intent of the rulemaking, 4 to integrate the mitigating strategies for all of 5 this.
6 MR. DIAS: You're correct.
7 MEMBER STETKAR: It's why 50.54(hh)(2) was 8 rolled into the new rule.
9 MR. DIAS: That's correct.
10 MEMBER STETKAR: So from that perspective, 11 from that technical functional perspective why isn't 12 the staff asking these questions about -- in 19.4 why 13 does the same pump have a different functional 14 capacity than in 19.3? It seems you could do that 15 without pointing to --
16 MR. DIAS: This is --
17 MEMBER STETKAR: -- specific guidance, 18 because the guidance doesn't necessarily tell you how 19 many gpm --
20 MR. DIAS: This is a little bit -- this is 21 -- the fact is that -- first, I can tell you 19.4 was 22 reviewed by the staff, by a separate staff member --
23 MEMBER STETKAR: I -- that's why --
24 MR. DIAS: -- way before 19.3. This is 25 not the correct answer.
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121 1 MEMBER STETKAR: That's why I said 2 ostensibly.
3 MR. DIAS: This is not even an excuse.
4 It's the truth.
5 MEMBER STETKAR: Okay. I hope then --
6 MR. DIAS: We are going to look into this.
7 MEMBER STETKAR: -- before Phase 5 and the 8 final version of the DCD and the final version of the 9 SER we come to some sort of convergence here on these 10 two sections, because I think that they can be made 11 consistent, at least from a functional perspective, 12 despite the morass of regulatory guidance that we're 13 in right at the moment.
14 MR. DIAS: Okay.
15 MEMBER STETKAR: Okay. Thanks.
16 MR. DIAS: Thank you.
17 MEMBER STETKAR: And thanks for being 18 honest about the different reviewers.
19 MR. STECKEL: We're moving in that 20 direction. We're not quite there yet.
21 MEMBER STETKAR: I just wanted to get it 22 on the record because it is frustrating given the 23 intent of what the agency and the industry in the 24 United States have been trying to do since Fukushima 25 to try to integrate a lot of these bits and pieces NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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122 1 that have evolved over the last almost 20 years now.
2 MR. STECKEL: Understood.
3 MR. WARD: Yes, we -- I'm taking notes.
4 We'll review the record after this to make sure we 5 include those in our Phase 5 meeting.
6 MR. STECKEL: Move onto 19.5, aircraft 7 impact assessment. These are examples of the key 8 design features: Reactor containment; building 9 design; design and location of spent fuel pool; 10 physical separation of Class 1E emergency diesel 11 generators and the alternate AC source; physical 12 separation and design of the emergency core cooling 13 and support systems; pressure-related and non-14 pressure-related fire barriers.
15 And we've concluded Section 19.5 meets 10 16 CFR 50.150(b) due to these reasons: Adequate 17 description of key design features and functional 18 capabilities; adequate description of how the key 19 design features meet the assessment requirements; and 20 the applicant has developed a reasonable formulated 21 assessment and it was performed by qualified 22 individuals.
23 And as a final note the next page, just to 24 let everyone know that the AIA inspection for APR1400 25 is scheduled for next month. Any additional NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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123 1 questions?
2 MR. WARD: Okay. That completes our 3 presentation. I did want to bring up a couple of 4 questions that came up earlier, one a question about 5 main control room ventilation, dose considerations.
6 And I know Jim mentioned there was some discussion in 7 Chapter 15. I was just scanning the SER and there 8 appears to be an open item related to some questions 9 in that area. So we'll look into that some more, but 10 it may not be resolved it.
11 And I think we have somebody else here to 12 help answer the question on pH of seven.
13 MS. UMANA: That was Mr. Powers' question.
14 MR. MAKAR: This is Greg Makar from the 15 staff. I didn't hear the question.
16 (Laughter.)
17 MR. MAKAR: I'm sorry. I apologize.
18 MEMBER POWERS: The staff -- the applicant 19 has insisted that his IRWST will remain at a pH 20 greater than 7 throughout the 30-day period following 21 a design-basis accident. And I'm wondering how do we 22 know that?
23 MR. MAKAR: The reviewer in this case 24 looked at the applicant's calculation of the pH over 25 that 30-day period accounting for the change from NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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124 1 acidification primarily from hydrochloric acid and 2 nitric acid generated by radiolysis of air and water 3 and cable insulation and jacketing. There's also a 4 base from cesium hydroxide, but the main contributors 5 to the pH change are the acids.
6 So looking at the total volume and the 7 acid that is generated, base generated and the 8 buffering capacity of the tech spec amount of 9 trisodium phosphate -- those are the main parts of 10 that calculation.
11 MEMBER POWERS: The questions are in the 12 details here. I mean, there are a couple of other 13 questions that are not so much detail, but where do I 14 see what G values they used for the radiolysis 15 components on this, how they handled HCL production 16 from the cable insulation and things like that?
17 MR. MAKAR: It's in -- there is a 18 calculation that was submitted. I think it's part of 19 the RAI response. And I think that identifies the G 20 values, which are taken from a NUREG/CR. I'm sorry I 21 don't remember the number of that report, but 22 that's --
23 (Simultaneous speaking.)
24 MEMBER POWERS: In other words, something 25 I have not seen? I guarantee you I haven't seen it.
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125 1 The other question that comes up is do 2 they account for carboxylic acid formation from any 3 organic contaminants? And we've certainly seen that 4 in the RTF tests done in Canada. We know that 5 happens. We know that by experiment and we know that 6 by theory.
7 MR. MAKAR: Probably not.
8 MEMBER POWERS: And do we account for 9 precipitation of phosphates due to contaminants coming 10 in to the IRWST? Any calcium, iron, zinc, something 11 like that.
12 MR. MAKAR: So a loss of phosphate that's 13 assumed to be present for the buffering?
14 MEMBER POWERS: Yes.
15 MR. MAKAR: I don't --
16 MEMBER POWERS: And if you drop it at a 17 solution then it's not buffering anything.
18 MR. MAKAR: Probably -- that's probably 19 not counted.
20 MEMBER POWERS: Well, it would still be 21 good to see the calculations.
22 MR. WARD: We'll look up those references 23 and provide those to Chris Brown to make sure --
24 (Simultaneous speaking.)
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126 1 you could. I mean, I don't know that there's anything 2 wrong with it, but Id' sure like to see it. Because 3 for instance, just in the area of G values on Hypalon 4 I know of three measurements. They only differ by a 5 decade. And one of them is -- in fact has a 6 qualitatively different progression of HCL production.
7 Similar differences on nitric acid formation rates.
8 MR. WARD: Okay. We'll get you those 9 references.
10 Any other questions?
11 (No audible response.)
12 MR. WARD: Well, this concludes our 13 presentation for today. Thank you.
14 MEMBER BALLINGER: Well, thank you. I 15 think now it's appropriate to take public comments 16 since we're finished. And so, I would ask if there 17 are -- is anybody in the room that would like to make 18 a public comment?
19 (No audible response.)
20 MEMBER BALLINGER: And we're trying to get 21 the -- is it open? So are there -- is there -- are 22 there any people out on the line that would like to 23 make a public comment?
24 (No audible response.)
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127 1 need to have -- ask if there's any other Committee 2 discussion.
3 (No audible response.)
4 MEMBER BALLINGER: That not being the 5 case, I turn it back over to the Chairman.
6 CHAIRMAN BLEY: Thank you. Before we 7 recess for lunch, you need some work on the letter 8 before we go through it?
9 MEMBER BALLINGER: We have the letter. We 10 have a draft letter. Based on some discussions that 11 we've had here, it would be a good idea to get another 12 crack at doing it, but we could do that either offline 13 or --
14 CHAIRMAN BLEY: I think that's probably a 15 good idea, so I don't think we'll read it at this 16 time.
17 Okay. We will recess until 1:00 when we 18 will take up the next item on the agenda.
19 (Whereupon, the above-entitled matter went 20 off the record at 11:35 a.m. and resumed at 1:00 p.m.)
21 CHAIRMAN BLEY: The meeting will come to 22 order. At this time, we're going to take up the issue 23 of Browns Ferry extended power uprate, and I will turn 24 the meeting over to Dr. Rempe.
25 MEMBER REMPE: Thank you, Mr. Chairman.
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128 1 So on May 3rd, our Power Uprates Subcommittee reviewed 2 the extended power uprate license amendment request 3 for Browns Ferry Units 1, 2, and 3, and the associated 4 draft -- the NRC staff's draft safety evaluation 5 report. And at the end of the meeting, our 6 subcommittee recommended that this LAR be presented to 7 the Full Committee.
8 Several aspects of this EPU request are of 9 special interest. The three BWRs are Browns Ferry 10 have relatively high power levels. Each unit is a GE 11 BWR/4 housed within a Mark I containment. Previously, 12 Browns Ferry has been approved to use AREVA ATRIUM 10 13 and 10XM fuels, and in this request, the licensee, 14 Tennessee Valley Authority, has proposed to eliminate 15 the reliance on containment accident pressure. And 16 prior to implementation of the EPU, TVA will install 17 a new replacement steam dryer in each unit.
18 Today, we are going to hear from TVA, NRC 19 staff, and possibly some of their consultants. Part 20 of the presentations will be closed in order to 21 discuss information that is proprietary, and before I 22 start by turning this over to Kathryn Brock of the NRR 23 management, we need to have a special statement by our 24 member, Jose March-Leuba.
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129 1 to say that I am conflicted on this topic because I 2 helped the staff work on it before I came into the 3 ACRS, so I will restrain myself from doing any 4 deliberations.
5 MEMBER REMPE: Thank you. So Kathryn?
6 MS. BROCK: Thank you. Well, my name is 7 Kathryn Brock. I am the Deputy Director in the --
8 oops. My name is Kathryn Brock. I am the Deputy 9 Director in the Division of Operating Reactor 10 Licensing in the Office of Nuclear Reactor Regulation.
11 The objective of today's discussion is to 12 present the ACRS a request by the Tennessee Valley 13 Authority to perform extended power uprates at each of 14 the three units at the Browns Ferry Nuclear Plant. We 15 feel we had a successful subcommittee meeting, and we 16 appreciate the opportunity to brief the Full Committee 17 on this important licensing action.
18 Attendees today do include NRC staff and 19 contractors, TVA staff, and TVA contractors and 20 vendors, and for the first portion, members of the 21 public. We welcome all of you and thank you for 22 joining us.
23 Next slide, please. As was mentioned, all 24 three units at the Browns Ferry are General Electric 25 boiling water reactors of BWR/4 design with Mark I NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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130 1 containments. Browns Ferry is located on the 2 Tennessee River in northern Alabama. Each unit has 3 received a renewed license with a license expiration 4 date in the 2030s.
5 The proposed EPU power level of 3952 6 megawatts thermal represents an increase of 7 approximately 14 percent above the current license 8 thermal power level, and approximately 20 percent 9 above the original license thermal power level. The 10 review of the EPU license amendment request has 11 involved over 25 technical staff from 14 different NRR 12 branches, so it's a big effort.
13 The NRR document RS-001 provides guidance 14 for performing reviews of EPU applications. TVA 15 followed the format and guidance delineated in RS-001 16 in the safety analysis reports contained in the EPU 17 application. The NRC staff review also followed this 18 guidance, as well as applicable regulations, 19 regulatory guides, and the Standard Review Plan. I 20 thank the staff and the contractors for their thorough 21 and timely review of this important amendment request.
22 After this extensive review, there are no 23 open items, so the NRC staff recommends approval of 24 TVA's extended power uprate amendment request. And to 25 give you the details of the staff review, I turn the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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131 1 presentation over to Farideh Saba, the NRC project 2 manager responsible for this review.
3 MS. SABA: Good afternoon. My name is 4 Farideh Saba. I am the Regulatory Licensing Project 5 Manager for Browns Ferry Nuclear Plant Units 1, 2, and 6 3 in the Office of Nuclear Reactor Regulation, 7 Division of Operator Reactor Licensing.
8 TVA submitted the proposed Browns Ferry 9 EPU in September of 2015. The NRC staff accepted the 10 application for detailed technical review in a -- a 11 letter dated January 11th, 2016. The NRC staff has 12 planned for completion of the review in July of 2017, 13 which supports TVA EPU implementation plans during the 14 refueling outages in spring of 2018 for Unit 3, in 15 fall of 2018 for Unit 1, and in the spring of 2019 for 16 Unit 2.
17 Next one? With respect to the agenda, 18 during the open sessions, TVA will provide an EPU 19 background presentation of the planned modifications 20 associated with the EPU, an overview on elimination of 21 credit for containment accident pressure (CAP), and an 22 overview of the steam dryer replacement RSD.
23 Following TVA's presentation, the NRC staff will 24 present staff's review and conclusions regarding fuel 25 and reactor system analysis, review of elimination of NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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132 1 CAP credit, and review of replacement steam dryer 2 analysis. The staff presentation will be closed to 3 the public due to proprietary nature of the 4 information that will be discussed.
5 If there are no further questions, I would 6 like to turn it over to Mr. Ed Schrull of --
7 MEMBER KIRCHNER: I have a --
8 MS. SABA: -- TVA.
9 MEMBER KIRCHNER: -- question, if I may?
10 MS. SABA: Sure, yes.
11 MEMBER KIRCHNER: I am just noticing that 12 your presentations -- TVA's will be open, but your 13 presentations will be closed. Is there some summary 14 of your evaluation that you can make it an open 15 session that the public can participate in? I believe 16 that -- I think it was Dr. Powers pointed out, I think 17 he used the word, you know, is this EPU prudent in 18 light of Fukushima? So it would seem to me that you 19 should present something about your SER in an open 20 session.
21 MS. SABA: I understand your point, and 22 actually, when we were planning, the reason we did it 23 like that, because some of the review done by the 24 staff is proprietary. So we planned it that way, that 25 any question that public can hear can be asked during NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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133 1 TVA presentation, and either TVA provide the response 2 or staff will help. Anything also that is asked 3 during TVA presentation that we see that as 4 proprietary, they can refer it back to the time that 5 we are doing the NRC members, they are doing it. This 6 way, we are separating proprietary information from 7 public information, because also, we have very short 8 period of time. It's not like -- it wasn't like 9 subcommittee.
10 MEMBER REMPE: Before -- again, I think I 11 would like to talk about your response to your 12 question, but let's let the member of the -- is -- did 13 you have a question, too?
14 MS. SABA: He is Ed Schrull. He is coming 15 after me.
16 MEMBER REMPE: Oh, okay. So I think you 17 have heard them say there are no open items, and they 18 are recommending that it move forward, and I think 19 that as you go -- I mean, you were there in the 20 subcommittee meeting, and so they -- yes. So I think 21 that that is sufficient, in my judgment, but if there 22 is something that you would like to -- that you 23 believe is open that should be said, why don't you 24 tell us, if there is something that you really wanted 25 to have said?
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134 1 CHAIRMAN BLEY: Or you could revisit just 2 before we go into closed session.
3 MS. SABA: Right.
4 MEMBER REMPE: Okay?
5 MS. SABA: That is exactly what was 6 planned. Thank you very much for your question.
7 Thank you.
8 So I -- I would like to turn it over to 9 Mr. Ed Schrull of TVA for an overview of the EPU for 10 Browns Ferry.
11 MR. SCHRULL: Thank you, Farideh. My name 12 is Ed Schrull. I am the TVA Corporate Fleet Licensing 13 Manager. For major projects such as the Browns Ferry 14 Extended Power Uprate Program, TVA forms a dedicated 15 site team that exists for the duration of the project.
16 TVA corporate then performs an oversight function for 17 the project.
18 So I would like to introduce the members 19 of the Browns Ferry EPU leadership team that are 20 seated at the front table. Starting from our right to 21 left: on the right side there is Mr. Dan Green, who is 22 a Senior Licensing Manager of the EPU project; next to 23 Dan is Mr. Gerry Doyle, the Director of the EPU 24 project; and next to Gerry is Mr. Pete Donahue, the 25 Senior Engineering Manager of the EPU project. All NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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135 1 three of these gentlemen have been with the Browns 2 Ferry EPU project since its inception. Next to Pete 3 is Mr. Lang Hughes, the Browns Ferry General Manager 4 of Site Operations; and next to Lang is Mr. Steve 5 Bono, the Browns Ferry Site Vice President.
6 At this time, I will turn it over to Mr.
7 Gerry Doyle, the Director of Extended Power Uprate 8 Project.
9 MR. DOYLE: Thank you, Ed. I appreciate 10 that.
11 Thank you, and good afternoon, Mr.
12 Chairman, ACRS Committee members, Director Brock, and 13 the NRC staff, good morning -- or, sorry, excuse me, 14 good afternoon. My name is Gerry Doyle, and I am the 15 Director of the EPU project. I wanted to introduce 16 and provide the background of our team and to share 17 the project goals we established early on to work 18 effectively with the NRC staff.
19 As part of our preparation, we performed 20 extensive benchmarking of previous EPUs, including 21 Grand Gulf, Monticello, Nine Mile Point, and Peach 22 Bottom, including attending both Peach Bottom ACRS 23 committee meetings. Our EPU project team is comprised 24 of personnel having extensive boiling water reactor 25 plant experience and specific EPU experience.
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136 1 Our team includes dedicated project and 2 plant TVA staff; major vendors, including GE-Hitachi 3 and AREVA; as well as experienced specialty 4 contractors. We were fortunate in that we were able 5 to take full advantage of a wealth of industry 6 operating experience and experienced, qualified, and 7 talented experts. We feel we have assembled the 8 industry's best and expect to demonstrate that today.
9 Next slide, please.
10 One of the first things we did was align 11 our project on high-level team goals, recognizing the 12 need to work closely with the NRC -- with our NRC 13 counterparts and demonstrate we were committed to 14 implementing an industry-best EPU, specifically, to 15 present the NRC, Nuclear Regulatory Commission, with 16 a high-quality license amendment request consistent 17 with RS-001 standards. To that end, we have worked 18 closely with Farideh and the technical reviewers to 19 ensure we were providing the necessary information 20 that they needed for their review in a timely manner:
21 to resolve containment accident pressurization issues, 22 which Pete Donahue will discuss further along in the 23 presentation; to install replacement steam dryers for 24 all three units, again, a separate discussion by Dan 25 Pappone of GE as part of this presentation; and NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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137 1 finally, I wanted to ensure we provided a smooth 2 transition to EPU for plant operations, such as there 3 were no surprises or issues in running or maintaining 4 the plant. Those are our high-level team goals.
5 With that introduction, I would like to 6 turn it over to our Site Vice President, Mr. Steve 7 Bono.
8 MR. BONO: Good afternoon. I want to 9 thank the Committee for the opportunity to present our 10 EPU project today.
11 Much of my slide has been presented, so in 12 fairness to Committee time, I will just give a quick 13 summary. But all three units are BWR/4 GE models with 14 a Mark I containment. You can see our original 15 operating license dates, and you can see where we 16 renewed that license. So all three units today 17 currently operate under a period of extended 18 operation. We did implement a stretch uprate of 105 19 percent original licensed thermal power, and what we 20 are requesting today is a proposed 120 percent of the 21 original licensed thermal power limit.
22 And with that, I am going to turn it over 23 to our General Manager of Site Operations, who is 24 going to go through some of the design changes and 25 modifications that we implemented to implement the EPU NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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138 1 project.
2 MR. HUGHES: Okay. Good afternoon. My 3 name is Lang Hughes. I am the General Manager of Site 4 Operations at Browns Ferry. I will go through some of 5 the modifications, many of which have already been 6 completed across all three units to support the 7 extended power uprate.
8 As you can see on the slide that is 9 currently on the screen, many of the modifications 10 that we have with these circles that are colored in 11 have already been completed. Included in this are the 12 replacement of the original design pumps for the 13 condensate booster and the reactor feed pumps. We 14 have the -- the EPU pumps installed. The Unit 1 and 15 2 pumps have all been installed in operation since 16 2007, but we completed installation of the condensate 17 booster pumps and the reactor feed pumps on Unit 3 in 18 the spring outage of 2016.
19 Many of these major modifications our 20 operators have been trained on for some time. You 21 know, it is nothing new with regard to individual 22 component operation for them. This is something that, 23 you know, we feel strongly about is the operator 24 training piece, and having these pumps in service for 25 some time has been able to let us run through EPU NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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139 1 scenarios on the simulator with this installed 2 equipment and so forth to get our team ready for full 3 implementation.
4 Next slide, please. I won't go through 5 and talk about all the modifications. A couple of 6 them that I will mention, we will talk later about the 7 replacement stream dryer. As far as the mods, you can 8 see them listed on the slide there. Really, these are 9 all -- for the most part will be transparent to the 10 operators. Main generator hydrogen pressure, we will 11 operate at a higher pressure. One thing that we are 12 doing with this modification in addition to assist the 13 operators is automatic hydrogen pressure control, and 14 remove the need to manually make up the hydrogen 15 pressure in a normal band. It will be controlled for 16 them, and they will have the ability to control 17 manually if there is an issue with the automatic 18 control system.
19 Next slide. Other modifications, the 20 hardened wetwell vent modification, we have completed 21 the installation on both Units 1 and 2. Unit 3 will 22 be installed in the spring outage of 2018. The other 23 one that I will address will be the alternate leakage 24 treatment pathway. That is -- you know, for us, it is 25 something that, you know, we are at a non-conforming NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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140 1 condition with respect to the alternate leakage 2 treatment pathway, and we do have designs completed.
3 They will be installed in the upcoming EPU outages.
4 Unit 3 will be the first in the spring. These will 5 install air-operated valves that will fail open, as 6 required.
7 We're all installing a new valve in the 8 main steamline drain system as well as replacing four 9 motor-operated valves with air-operated valves, also 10 in the steamline drain system. So this will remove 11 the non-conforming condition prior to EPU 12 implementation, and also, for this, this is currently 13 an operator workaround that we have in place for the 14 steamline drain system, which we'll move that as well 15 in the Unit 1 and Unit 2 outages to follow. Next 16 slide.
17 For the next slide, a couple things I will 18 say with respect to the instrumentation and for the 19 control room operators. We will be, you know, making 20 some changes to that associated with set points and 21 respanning the instrumentation. The control room, for 22 the operators, what they see, it will be transparent 23 to them. They are going through now and looking at 24 all of the new EPU conditions on the simulator as far 25 as, you know, what these changes will be.
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141 1 The one thing that we are going to do as 2 far as modifications to really assist our operating 3 crews is we're going to install a new condenser vacuum 4 instrumentation. Right now, you know, we have 5 condenser vacuum indication, but we're going to go for 6 each individual condenser to where the operators will 7 have, you know, specific points to monitor for each 8 individual condenser. Air condensers are designed a 9 little bit different than some plants. They have a 10 common area, but they also have three separate water 11 boxes, either one of which can provide a turbine trip 12 signal, so this installed upgraded instrumentation 13 will give them exact indication on each individual 14 water box. This is something that the operators have 15 asked for, that it's important to them, so we will be 16 doing these implementation modifications in the Unit 17 3 outage and each succeeding EPU outage to follow.
18 So pending any questions, this completes 19 my overview for the modification summary.
20 MEMBER SKILLMAN: Yes. I would ask this:
21 with the condenser pressure model, with the higher 22 flow rates, are you going to be pushing those 23 condensers to where they are in fact a trigger for 24 your higher power conditions?
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142 1 will be some, you know, change with respect to 2 condenser vacuums, specifically in the summertime, 3 when we have elevated cooling water temperatures.
4 Now, the one thing about it as far as, you know, our 5 procedural requirements for, you know, turbine loading 6 and power for condenser vacuum, those will not change.
7 You know, we still have trigger values in our 8 procedures and so forth.
9 The other thing that we have done, not 10 really associated with EPU, but for margin purposes, 11 is, you know, over the last couple years, we have 12 started the condenser cleaning -- or chemical cleaning 13 of condensers, which we, you know, did some industry 14 benchmarking and started that, which has really 15 improved our margin with respect to condenser vacuum.
16 What this does is give the operators a better 17 indication for each water box, which actually assists 18 them for their trigger values in accordance with our 19 procedures. But as far as, you know, operating 20 margins, those will not change.
21 MR. HUGHES: Okay. The reason for my 22 question was are you actually pushing yourself into a 23 condition where you're more likely to get trips, 24 particularly when the -- when the Tennessee River is 25 running at its warmest?
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143 1 MR. DONAHUE: We performed analysis, both 2 pre-EPU and -- and EPU. Another modification that we 3 will be performing is that we're -- we're changing the 4 alarm set point, and also the -- the trip set point 5 through GE analysis for those -- those alarm and trip 6 set points, and when you look at both of them 7 together, we will actually be at a similar position 8 that we are today. So the EPU does affect condenser 9 vacuum. However, the alarm and trip set points offset 10 that.
11 MEMBER SKILLMAN: Okay. Thank you.
12 MR. DONAHUE: So I am Pete Donahue. I am 13 the Senior Engineering Manager for EPU. I will be 14 presenting elimination of -- of credit for containment 15 accident pressure.
16 So I am on Slide 15. Slide 15 shows a 17 general diagram of the -- the terms that go into 18 determining the available net positive suction head so 19 that we can compare them to the required net positive 20 suction head to ensure that we -- we are not taking 21 any credit for containment accident pressure. Next 22 slide.
23 MEMBER REMPE: Pete?
24 MR. DONAHUE: Yes.
25 MEMBER REMPE: I know you said it during NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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144 1 our subcommittee meeting, but just to make sure that 2 every member here has it and that I have it correct, 3 you indicated during the subcommittee meeting that the 4 current analysis relies on the maximum CAP credit of 5 3 psg for about 80 minutes during LOCAs, is that a 6 true statement?
7 MR. DONAHUE: That is, it is 80 minutes 8 for the long-term, and about 10 minutes for the short-9 term, so a total of like 88 to --
10 MEMBER REMPE: Okay.
11 MR. DONAHUE: -- to 90 minutes.
12 MEMBER REMPE: Thanks.
13 MR. DONAHUE: So Slide 16 goes over the --
14 some background for containment accident pressure.
15 What we did is we took -- we took the opportunity to 16 eliminate crediting containment pressure during --
17 during an accident or an event, and there's really two 18 types of events, right? There's special events and 19 there's design basis accident types of events. So --
20 so we -- we performed our analysis to -- to ensure 21 that we're not crediting containment accident 22 pressure. As a matter of fact, we're going to update 23 both our design and our licensing basis to show that 24 we do not credit containment accident pressure, and 25 that statement will also show up in our technical NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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145 1 specifications.
2 So -- so this -- we -- we used the -- the 3 current guidance, that is, SECY-11-0014, to perform 4 this analysis. Next slide. The -- the -- this slide 5 shows -- this Slide 17 shows some of the -- the 6 aspects of -- of the analysis that we performed in 7 order to eliminate crediting containment accident 8 pressure and some actions that we have taken. The --
9 the first shows that we did perform a number of 10 comprehensive containment analyses using a program 11 that some of you may be familiar with, SUPERHEX, 12 analysis to perform containment accident pressure.
13 SUPERHEX really just gives us the 14 temperature in which we will evaluate the vapor 15 pressure term for the net positive suction head, so we 16 have done a number of analyses, you can imagine, with 17 different initial conditions and different events, so 18 there is -- there is -- and with different flow rates.
19 We also increased the -- what is called 20 the -- the heat -- the heat exchanger K-value, and if 21 you're not familiar with this heat exchanger K-value, 22 it is -- it is really a factor that you use in doing 23 the -- the containment -- heat transfer analysis, 24 where you can apply this factor to the difference 25 between the hot side and the cold side, inputs to the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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146 1 heat exchanger. So this K-value is no more than that, 2 but -- but there's a pretty complicated formula to 3 determine that --
4 CHAIRMAN BLEY: So is this analysis or 5 physical change?
6 MR. DONAHUE: This is analysis.
7 CHAIRMAN BLEY: Analysis? Okay.
8 MR. DONAHUE: The -- so -- so in order to 9 ensure that we maintain that -- that K-value, we are 10 putting that information on performance of our heat 11 exchangers into technical specifications to ensure 12 that we -- we both perform the -- the heat exchanger 13 performance testing on -- on a given frequency and 14 that we maintain the -- the K-factor that is in our 15 design basis.
16 MEMBER REMPE: So Pete, just to clarify a 17 couple of things, first of all, this response to 18 Dennis's question, it is analysis, but isn't it based 19 on fouling factors that were measured? So before you 20 justified this K-value, you actually had some data to 21 support it?
22 MR. DONAHUE: Oh yes, yes.
23 MEMBER REMPE: Okay.
24 MR. DONAHUE: We validated the -- the 25 fouling factors with performance tests on all 12 of NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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147 1 our heat exchangers.
2 MEMBER REMPE: And then to respond to 3 Member Kirchner's question, I don't think it is 4 proprietary to say that this technical specification 5 was a result of interactions with the staff and that 6 they -- because they want to make sure they have 7 confidence in the analysis, that they have imposed 8 this --
9 MR. DONAHUE: Absolutely.
10 MEMBER REMPE: -- upon the licensee.
11 MR. DONAHUE: Right.
12 The next thing we did was we increased the 13 boron-10 enrichment during the anticipated transient 14 without scram special event to ensure that we had 15 adequate margin for containment accident pressure in 16 that event.
17 MEMBER SKILLMAN: Pete, you didn't include 18 at this bullet that you increased the flow rate for 19 the --
20 MR. DONAHUE: We also, in the technical 21 specifications, there is a specification for where 22 flow rate is an element of determining the 23 acceptability of -- of the ATWS and the injection 24 rate. I am not sure we had a bullet for -- for it.
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148 1 communicated, but you did in fact increase the flow 2 rate to --
3 MR. DONAHUE: Right.
4 MEMBER SKILLMAN: -- achieve what 774 --
5 MR. DONAHUE: Right.
6 MEMBER SKILLMAN: -- ppm in the time 7 requirement for the 1 percent shutdown.
8 MR. DONAHUE: Right.
9 MEMBER SKILLMAN: Okay. Thank you.
10 MR. DONAHUE: And we also used the -- the 11 vendor supply net positive suction head curves where 12 our design basis didn't have that information 13 previously before we performed this analysis in 14 changing our design basis, and we utilized -- for 15 initial conditions, we utilized all technical 16 specification initial conditions with the exception of 17 the fire special event, where we used nominal values 18 in accordance with the SECY guides.
19 MEMBER REMPE: Pete, again, just to make 20 sure that we have it clear, when Member Skillman said 21 you increased the flow rate, he means in the analysis.
22 My understanding is that you used a more realistic 23 evaluation of what the flow rate would be. You didn't 24 actually increase the flow rate, you increased it in 25 the analysis --
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149 1 MR. DONAHUE: Oh yes, absolutely --
2 MEMBER REMPE: -- okay?
3 MR. DONAHUE: -- the pumps didn't change.
4 MEMBER REMPE: Is that understood? Okay.
5 Thank you.
6 MR. DONAHUE: Okay.
7 And then finally, on Slide 18, the 8 analysis did demonstrate that we did not need to 9 credit any containment pressure as a result of an 10 accident or the event. That's it, I think. Any 11 questions?
12 (No audible response.)
13 MR. DONAHUE: All right. I will turn it 14 over to Dan to talk about the replacement steam dryer.
15 MR. PAPPONE: I am Dan Pappone. I am GE-16 Hitachi, and I have been -- for lack of a better word, 17 I have been kind of the principal investigator for the 18 steam dryer issues since the first indications of 19 failures at Quad Cities following their power uprate 20 in 2002.
21 Next slide, please. So it has been a long 22 trip, but the replacement steam dryers we're putting 23 in in Browns Ferry is really the end product of all of 24 that research and development that we have done. They 25 are based on the curved hood prototype replacement NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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150 1 dryer that we put into a BWR/4 reactor for their 2 extended power uprate about ten years ago, now, so we 3 have had a lot of operating experience with the 4 design.
5 The design itself, what we found coming 6 out of the Quad Cities was that these fatigue 7 stresses, the flow-induced vibration, were really 8 tight on that with the original dryer designs, and we 9 basically had to refine our steam dryer design because 10 of that. Because of that, the -- these replacement 11 dryer designs are much -- much more robust than the 12 original dryers. The original dryers, the fatigue --
13 fatigue stresses were believed to be negligible, and 14 we did have some cracking initially, and that was 15 patched. It went on, but when we started doing the 16 extended power uprates, we found -- we found we were 17 right up against the structural limits, so that is 18 basically what has driven the industry to replacement 19 or -- or extensive modifications.
20 Key to that is -- key to being able to do 21 those design analyses is developing the acoustic load 22 pressure methodology for putting on the structure in 23 order to do those predictive structural analyses to be 24 able to do a design efficiently, and the method that 25 we have come up with, we take measurements -- for a NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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151 1 plant going in, we will take measurements from the 2 main steam lines, basically using the main steam lines 3 like stethoscopes to listen in and develop -- capture 4 the frequencies that are actually loading the dryer, 5 and then using that to develop the acoustic load 6 definition that we then put on a structural model.
7 And methodology that we developed, we used 8 that full methodology end-to-end on the previous 9 replacement dryer project. The results of that were 10 good, and we have also captured that process as part 11 of the ESBWR design certification documentation. So 12 we have captured that methodology. It has been 13 reviewed and accepted by the NRC on those projects.
14 And then of course, we have always 15 analyzed the dryers for the primary structural loads 16 to make sure that the dryers maintain their structural 17 integrity, don't generate any of those parts during 18 normal operation transient and then accident events.
19 Next slide.
20 MR. RICCARDELLA: Which plant was the 21 prototype BWR for?
22 MR. PAPPONE: Those were the Susquehanna 23 dryers.
24 MR. RICCARDELLA: Thank you.
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152 1 world, we have replaced the stream dryers for Quad 2 Cities Units 1 and 2 and then used that same design on 3 the Dresden's Units 2 and 3. The next -- next EPU 4 application was really modifications that we did to 5 Vermont Yankee where we put the repair modifications 6 that we had developed on the original Quad Cities and 7 Dresden dryers while we were going through the 8 replacement dryer design process, we had put that set 9 of repairs on Vermont Yankee. Those repairs performed 10 successfully for the EPU life of the plant with no 11 issues.
12 We went back to the curved hood dryer --
13 basic curved hood dryer design for the Susquehanna 14 replacement dryers partly because of fabrication 15 issues. Complexity of the designs we used for Quad 16 Cities and Dresden, we had a lot of castings and the 17 like. We wanted to move away from that and get back 18 to simpler fabrication techniques.
19 And then Grand Gulf was the next step, 20 again with the curved hood dryer. So in each of these 21 steps, we are taking whatever lessons learned, folding 22 those into the next design. And Browns Ferry is -- is 23 taking advantage of all of this experience in their 24 replacement dryer designs. Next slide.
25 So we did have some -- some changes to the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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153 1 -- from prototype design when we went to Browns Ferry.
2 We did have -- because of the hold down differences, 3 the dryer hold downs, in Unit 1 versus Units 2 and 3, 4 we did have to accommodate those differences and come 5 up with a slightly different mechanism for holding the 6 dryer down in the event of a steamline break accident 7 that would push the dryer up, and we wanted a single 8 design that would accommodate all three units.
9 We did fold in the operating experience 10 and lessons learned from the previous analyses, both 11 in the operating world and in the fabrication world.
12 And we went through a couple of design iterations 13 specifically for Browns Ferry. First is when we put 14 the specific load definition on, we see what parts of 15 the dryer are responding to the frequencies that we're 16 experiencing, take care of any amplified structural 17 response we may see, do some design changes to -- to 18 address those, and then with the Browns Ferry project 19 schedule, we had the time to do a full second design 20 iteration where we were able to go through the whole 21 structure, even out the load paths, even out the 22 stresses, and bring in as much margin as we could into 23 the design.
24 And next slide. This flow chart gives an 25 overview of the analysis approach. We've got two NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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154 1 finite element models: one for the acoustics where we 2 have modeled the steam dome cavity with the dryer in 3 -- in the steam dome, and that is the tool that we use 4 for developing the acoustic load definition and 5 projecting the loading onto the dryer surfaces. We've 6 got a second finite element, ANYSYS model of the dryer 7 structure itself, basically a shell model, and that is 8 the primary analysis for generating the -- generating 9 the stresses, calculating the stresses.
10 The one we do take going in, because we 11 don't have on-dryer measurements of the acoustic 12 loading for Browns Ferry, we are starting with the 13 steamline measurements as a basis for our load 14 definition. We -- the one key load component that is 15 not present at the current power is if there is an --
16 if there is an acoustic resonance in the safety relief 17 valve standpipe that may come as we raise -- increase 18 power, we don't have -- we may not have the 19 measurement of that today. We have to go through, 20 look at the characteristics, the geometry of the 21 steamline, what we're seeing in the actual acoustic 22 signature in the steamline measurements we have taken, 23 and predict whether or not we will -- we have the 24 possibility of the resonance coming up, and if so, 25 what frequency, what amplitude.
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155 1 We go through that process and factor that 2 into our acoustic load definition that we're putting 3 on the structure. Take -- come up with the -- we also 4 go and project the amplitude growth for the loading 5 when we get up to EPU, take all of that information 6 for the load definition, put that on the structural 7 model, run that -- run that analysis, get the raw 8 stresses, then go through several stress adjustment 9 factors, scaling the stresses up to EPU. We have bias 10 and uncertainties that we apply to the raw results 11 coming from the benchmarking where we benchmark 12 methodology against instrumented dryer structural 13 response, so we factor that -- that in.
14 There are operating conditions that may 15 increase the stresses from non-acoustic sources: vane 16 passing frequency from the recirculation pumps can 17 drive structural vibrations that carry into the dryer 18 and increase the stresses by a small but non-19 negligible amount. And then that -- that will give us 20 our final flow-induced vibration fatigue stresses. We 21 compare that against the ASME code fatigue allowance 22 limit. We are looking at the far end of the fatigue 23 curve because we are basically designing assuming 24 we've got those loads acting for the whole time -- for 25 the remaining life of the plant, and that then NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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156 1 determines how much margin we have to the fatigue 2 limit.
3 Those fatigue analysis results also get 4 carried into the acceptance criteria for the -- for 5 the limit curves for power ascension, and the analysis 6 itself is part of the framework that we use for 7 monitoring -- predicting and monitoring the dryer 8 stresses as we're coming up on power ascension. The 9 -- those results are also fed over into the primary 10 stress analysis for the normal upset faulted condition 11 primary structural analyses, and then we compare those 12 results against the ASME code acceptance criteria for 13 those conditions.
14 Next slide. So when we got through the 15 fatigue analysis, we were basically at a factor of two 16 margin to the code limit for the -- for the fatigue 17 limit. We've got one component that was just a hair 18 under two, and so that was successful. That design is 19 successful. It's nice going into the power ascension 20 with this kind of margin. Yes?
21 MR. RICCARDELLA: So as I understand it, 22 this factor of two applies to the initial analysis up 23 to EPU conditions prior to the benchmarking, and then 24 once you do the -- and then benchmarking, you're 25 allowed to reduce that to one. Just out of curiosity, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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157 1 on the Susquehanna plant, how much of that difference 2 between two and one was used up with the bias, the new 3 bias in uncertainty factors?
4 MR. PAPPONE: By the time we got -- got 5 all the way through -- through the -- through the 6 process, we were still -- we were still above the 7 limit. There was also some history in there in that 8 when we discovered errors and had gone back and 9 checked to confirm the operability for the previous 10 analyses, that -- but we're still above that -- above 11 the ASME limit.
12 MR. RICCARDELLA: Yes, but it was at 1.01, 13 or 1.1?
14 MR. PAPPONE: I don't remember --
15 MR. RICCARDELLA: Ballpark?
16 MR. PAPPONE: I don't remember -- well, it 17 was about 1.3 when we were done with the power 18 ascension.
19 MR. RICCARDELLA: Okay, okay.
20 MR. PAPPONE: But that -- in that case, we 21 were going in almost with -- with a blind set of 22 analysis tools because that was really the first time 23 we had gone through that process.
24 MR. RICCARDELLA: Yes. So we should do 25 better on --
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158 1 MR. PAPPONE: We should be doing -- we did 2 --
3 MR. RICCARDELLA: -- on this one.
4 MR. PAPPONE: We did quite a bit better on 5 Grand Gulf, so --
6 MR. RICCARDELLA: And for the record, that 7 ASME code limit has a factor in it, a factor of two in 8 it also, right?
9 MR. PAPPONE: Yes.
10 MR. RICCARDELLA: Thank you.
11 MR. PAPPONE: Actually, it's all of this 12 margin that we're putting in at the beginning that is 13 driving the replacement dryer, because we do have 14 dryer -- we do have plants that were -- had gone up to 15 EPU before with the original dryers with no 16 modifications, and there haven't been any issues 17 there. But it is the analysis, predictive analysis 18 world in the margin that is -- that is driving us to 19 this kind of a robust design, and the fact that we 20 don't want to have another Quad Cities.
21 So next slide, please. Now for the 22 primary stress evaluations, these are straightforward.
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159 1 plenty of margin for the fatigue. Well, things have 2 kind of flipped a little. Now that we have gone and 3 put in all of this additional margin for the fatigue, 4 we've got plenty of margin for the accident 5 conditions.
6 And we'll go through the process. And 7 dryer is not a safety-related item. It has no active 8 safety function. We just need to make sure that 9 during an event, it maintains its structural 10 integrity, it doesn't generate any of those parts.
11 And then it's not a code component, it's not of course 12 a core component, but we're -- for all intents and 13 purposes, we are designing it as if it were a code 14 component.
15 Next slide. The power ascension 16 monitoring process we have also worked out over the 17 replacement dryer projects, and the process is 18 similar. For the lead unit, both the replacement 19 dryer and the steamlines will be instrumented, and as 20 we come up in power, we will be able to do the 21 benchmarking, the Browns Ferry-specific benchmarking, 22 of the analysis, come up with Browns Ferry-specific 23 bias and uncertainty factors that will then fold into 24 the power -- the limit curve monitoring and also into 25 the follow-on units.
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160 1 The power ascension limit, the power 2 ascension limits for lead unit will be on the dryer 3 instrumentation, and when we do it, the main steamline 4 will be backed up in case we -- in the event that if 5 we lose too many instruments on the dryer, we will be 6 able to continue. And that brings -- that gets us to 7 the point of the factor of two that you had mentioned.
8 If we get through that Browns Ferry-specific 9 benchmarking, at that point, we will be working with 10 a benchmark model at that point, the power ascension.
11 CHAIRMAN BLEY: The Browns Ferry units, I 12 don't remember. I thought they were built at somewhat 13 different times.
14 Is the piping identical as you go from 15 unit to unit?
16 MR. PAPPONE: It's virtually identical.
17 There is one safety ruling valve standpipe that's in 18 a little bit different position.
19 But they're virtually identical as far as 20 the loads. And that shows up -- going into the 21 design, we had measures in all three units. And they 22 are quite similar.
23 CHAIRMAN BLEY: Thank you.
24 MR. PAPPONE: When we get up to -- when we 25 get up to the fully computed power in the lead unit, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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161 1 we'll be performing -- taking data and performing 2 benchmarking there.
3 And performing a full scope, confirmatory 4 structural analysis for the FIB loads. And that 5 analysis will then be the basis -- used as the basis 6 for the follow on units for the limit curve 7 development.
8 The follow on units will only have the 9 main steam lines instrumented. It will be matching --
10 essentially matching the signatures going up on that 11 and addressing and using the differences in those 12 signatures to account for any response differences we 13 may be seeing.
14 And then when you get up to the fully 15 fueled for on the follow on units, we'll go through a 16 structural evaluation to confirm that each of those 17 dryers is also meeting the limits.
18 The extent of that, the follow on 19 evaluation will depend on how close the signatures are 20 to the lead unit.
21 CHAIRMAN BLEY: I'm curious. You gave us 22 a little history of how the designs evolved from plant 23 to plant.
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162 1 from the first unit to the others?
2 MR. PAPPONE: It did. In fact PPL, the 3 two unit case we had before, where we were going 4 through in this level of detail was for the 5 Susquehanna. The two units in Susquehanna.
6 And we went through and did the power 7 ascension for the lead unit. PPL basically did the 8 power ascension for the follow on unit.
9 CHAIRMAN BLEY: Um-hum.
10 MR. PAPPONE: So -- and they did track 11 quite well.
12 CHAIRMAN BLEY: Okay.
13 MEMBER SKILLMAN: Dan, let me ask this.
14 The information on this stream dryer appears very 15 convincing. And I just wonder, can this create a 16 false sense of security?
17 And are you asking yourselves, what can go 18 wrong?
19 MR. PAPPONE: Well, I don't think it's a 20 false sense of security. Because we have put in so 21 many over -- so many replacement dryers over the time 22 period.
23 And we just -- we have not been having any 24 issues showing up. The -- and also go back to the 25 operating history for the original steam dryers, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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163 1 really it's been Quad Cities -- the Quad Cities in 2 Dresden that were in a way an outlier --
3 MEMBER SKILLMAN: They were the outliers.
4 MR. PAPPONE: Because of the specific 5 conditions for those plants. And partly, you know, 6 the -- partly the dryer design would push -- that 7 particular dryer design did have a limit.
8 Those dryers work fine for 30 years until 9 we raised the power. And the weak points showed up.
10 MEMBER RICCARDELLA: Also as I understand 11 it, there's plans for inspections on the first couple 12 of refueling outages to confirm that they're having 13 problems or not.
14 MR. DONAHUE: Also during start up, we do 15 have level one and level two criteria. Where we look 16 forward, project the readings that we do get at one 17 power level to the readings that we hope to get at the 18 next power level.
19 So, that will help us also to make sure 20 that we're not going to get into a power level that we 21 can't -- where we exceed the criteria.
22 MEMBER SKILLMAN: Thank you. Thanks.
23 MR. PAPPONE: All right. So the next 24 slide. The next slide is well, during the power 25 ascension we do have hold points for NRC review.
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164 1 When we get to today's current power, 2 we'll be base lining the methodology on Browns Ferry 3 specific bias and uncertainties. And there's a ten 4 day hold period for NRC in review of that 5 benchmarking.
6 And then a five percent power increments.
7 Going up we'll have four day hold points. This is the 8 same power ascension review plan that's been licensed 9 conditions for most of the replacement dryer projects.
10 Follow on units will follow the same basic 11 process. It will be a smaller scope because we won't 12 have -- won't be doing the same benchmarking.
13 It means we won't have the on dryer 14 instrumentation. Then once each of the units have --
15 reaches the fully queued power, they'll be a full 16 scope inspection for the following two cycles.
17 And that's also the same approach we've 18 been using in the other projects. After that long 19 term, the inspection plan lines up with the industry 20 guidance.
21 Then with that, any other questions?
22 MEMBER REMPE: But this part is the end of 23 the open part of the meeting. And I think we need to 24 ask if there's any members of the public at this point 25 that want to make a comment?
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165 1 Or if there's any in the room as well as 2 on the line. And I believe the lines are open.
3 (No response) 4 MEMBER REMPE: I see no one in the public 5 or in the audience here who wants to make a comment.
6 And we don't -- I believe we confirm the line is open?
7 MEMBER STETKAR: Just ask.
8 MEMBER REMPE: Is the line open? And are 9 there any comments?
10 (No response) 11 MEMBER REMPE: While we're waiting to do 12 that, it might be good -- I believe we're going to 13 switch out, right? And so you could go ahead and do 14 the switch out if you wanted to.
15 (Off record comments) 16 MEMBER REMPE: Well, the public may --
17 should I close it before I let the public have their 18 chance to have comments? I think we need to let them 19 confirm there's no public --
20 (Off record comments) 21 MEMBER STETKAR: Mr. Brown, it sounds like 22 things are coming online rather than going off. Is 23 the line open?
24 MR. BROWN: No. The public is closed and 25 closed the lines open now.
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166 1 MEMBER REMPE: Okay. So were there any 2 members of the public out there when I was calling for 3 it? Was it open?
4 MR. BROWN: It was open.
5 MEMBER REMPE: It was open. Okay. So at 6 this point, we are going to close the open session.
7 And I don't have a gavel. Okay.
8 (Whereupon, the above entitled matter 9 went off the record at 1:51 p.m. and 10 resumed at 3:16 p.m.)
11 CHAIRMAN BLEY: We are back in open 12 session with a new topic. Westinghouse shutdown seal.
13 So I turn the meeting over to Mr. Stetkar.
14 MEMBER STETKAR: Thank you Mr. Chairman.
15 I will first announce that we are going to run this 16 session similarly to the one that we just had.
17 We will have a rather short open session 18 where the staff will provide an overview of their 19 review. And Westinghouse or the PWR Owners Group will 20 provide a brief introduction.
21 And then we will go into closed session 22 because we need to hear details of the seal design and 23 the topical report and so forth that has proprietary 24 information in it.
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167 1 the subcommittee meeting a little bit of the 2 background. The NRC staff back in, I don't recall, 3 earlier, has approved the use of the so called 4 Generation III shutdown seal for use in applications 5 of the flex mitigation strategies.
6 Saying that, the staff did not approve any 7 models for numerical data for failures of the seal for 8 use in any risk analysis that might support those 9 evaluations that are done in response to the orders.
10 PWR Owners Group has submitted a topical 11 report that contains information about the logic 12 structure, the PRA models, the success criteria, 13 consequences from success or failure of the seals, and 14 numerical values to be used for failure rates for the 15 seals.
16 That is what we're talking about today.
17 That topical report on the PRA models and failure 18 rates for the seals. And that's what the SER has 19 written against.
20 So it's not necessarily the design of the 21 seal itself. Although we obviously have to understand 22 how it works. But, I just wanted to make that clear 23 for the record.
24 As I said, we had a subcommittee meeting 25 on February 6 where we had pretty extensive NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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168 1 discussions about the topical report, the seals.
2 Since the subcommittee meeting, the Owners 3 Group has submitted a supplement to the topical 4 report. Which I understand will be included in the 5 approved version of the topical report after the 6 safety evaluation is issued.
7 So that what we're actually reviewing 8 today is the Rev 1 of the topical report that we had 9 available for the subcommittee meeting. Which 10 document has not changed, plus the supplemental 11 information that we've received about a month or so 12 ago now.
13 And with that, I have a couple of other 14 things to say once we go into closed session. But 15 let's proceed with the open session. And ask Sunil 16 Weerakkody from the staff to start. Sanil?
17 MR. WEERAKKODY: Yes. Thank you John.
18 Sanil Werrakkody. I'm the Acting Deputy Director in 19 the Division of Risk Assessment. And I really look 20 forward to this opportunity.
21 As John mentioned, you know, the 22 licensees, a number of licensees have already 23 installed the Gen III, what we call the Gen III 24 shutdown seals. And we are of the opinion that when 25 these seals operate as designed and as expected, the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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169 1 core damage frequencies of these plants reduce. And 2 in some cases, significantly.
3 Because of that, we are very supportive of 4 efforts on the part of the licensees to implement this 5 modification at their plants. So, when NRC completes 6 the approval of this topical report, the licensees 7 will have and what I would call an acceptable method 8 for crediting these seals when they do their PRAs and 9 certainly their results to us in their risk-informed 10 applications.
11 So during the last three years, and that's 12 how long we have been developing this topical report, 13 the staff from the Division of Risk Assessment and the 14 Division of Engineering have expended a significant 15 amount of resources to provide a very thorough review 16 of this report. Which included multiple rounds of 17 REIs, numerous meetings, visits to Westinghouse test 18 specialty, and observing post-operational testing.
19 Then as John mentioned, this year, on 20 February 6, we briefed the ACRS subcommittee. We 21 provided a draft SER. And Westinghouse provided 22 significant details of the design and some of the old 23 designs.
24 And we received very valuable feedback 25 from the subcommittee. Even though the failure NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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170 1 probability numbers did not change significantly, I 2 could say that based on the feedback from the 3 subcommittee and the number of meetings we had with 4 Westinghouse, I believe we have a draft SER. Which is 5 of, you know, higher quality. Which is more 6 comprehensive.
7 And as John mentioned, also on the part of 8 Westinghouse, they sent a supplemental -- they sent 9 supplemental information which became the basis for us 10 to revise our safety evaluation.
11 So we really want to thank you, thank the 12 subcommittee for their feedback. And we really look 13 forward doing this particular case. I'm not sure 14 whether the process requires that or not.
15 But, speaking for the staff, we really 16 look forward to a letter from the full committee after 17 this meeting. That's all I have to say. Thank you 18 and John, I think we go to the staff now.
19 MEMBER STETKAR: Yes. Please. And by the 20 way, we -- subject to approval by the full committee, 21 we are planning to write a letter on this topical 22 report and the SER.
23 MS. LYONS: Good afternoon. My name is 24 Sara Lyons. I'm a Reliability and Risk Analyst in the 25 Office of Nuclear Reactor Regulations, Division of NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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171 1 Risk Assessment.
2 And I'm here with two of my colleagues, 3 Ching Ng to my left is also with the Division of Risk 4 Assessment. And Bob Wolfgang is with the Division of 5 Engineering.
6 The three of us have been the primary 7 reviewers on this topical report. And so I'll discuss 8 the publically available information briefly here.
9 But before I get into that, I just wanted 10 to indicate, you know, as Sanil mentioned, this 11 topical report did come to us on July 2014. And we've 12 had a number of, you know, regulatory and technical 13 issues that we've had to work through during that 14 time.
15 So I'd like to acknowledge some of the 16 other areas where we had insight from the staff.
17 Including our division of Policy and Rulemaking, where 18 they've been helping with project management type of 19 support.
20 And other offices, Office of the General 21 Counsel, the Office of New Reactors, and the Office of 22 Nuclear Regulatory Research, where they provided some 23 insight for technical consistency. As well as the 24 Reliability and PRA Subcommittee.
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172 1 we did get some valuable insight there. It made 2 changes to our SER as a result of that input. And 3 even added an extra limitation to our SER and are able 4 to bring a higher quality product to the full 5 committee today.
6 So on slide two, the topics that we're 7 going to discuss are the purpose of the review, the 8 background, the scope of the review, and the PRA model 9 review as well as staff conclusions.
10 So on slide three, the purpose of this 11 review again, as was stated earlier, it was to review 12 the probabilistic risk assessment model. Which will 13 allow licensees to credit their shutdown seal in risk-14 informed activities.
15 The installation of the shutdown seal is 16 an important safety improvement that can mitigate 17 reactor coolant system inventory losses through the 18 reactor coolant pump seals. And a need for reactor 19 coolant system makeup to achieve a stable state.
20 So on slide four, here's a little bit more 21 background. A loss of seal coolant -- I'm sorry. A 22 seal loss of coolant accident or seal LOCA can occur 23 when the thermal barrier heat exchanger cooling and 24 the seal injection both fail.
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173 1 the leakage could range from 21 to 480 gallons per 2 minute per pump. And when that shutdown seal is 3 installed and operates as it is intended to, the 4 leakage would reduce to less than one gallon per 5 minute for up to 168 hours0.00194 days <br />0.0467 hours <br />2.777778e-4 weeks <br />6.3924e-5 months <br />.
6 Which can provide a significant reduction 7 in core damage frequency for some plants. It's really 8 plant specific. But it can provide, as was indicated 9 in an industry study referenced here, up to 50 percent 10 reduction in core damage frequency.
11 So on slide five, the PRA -- the scope of 12 the review included the PRA model. The topical report 13 PWR Owners OG-14001, Revision One, was submitted for 14 review and approval.
15 Which described the PRA model. But also 16 referenced a lot of the qualifications, testing 17 information that was provided in a separate document 18 previously, TR-FSE-14-1, Revision One.
19 The testing information was provided to 20 the NRC staff in response to the Order EA-12049 for 21 mitigating strategies. And the staff had previously 22 endorsed the use of the shutdown seal for the extended 23 loss of AC power evaluations that were performed in 24 accordance with that Order.
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174 1 approval of installation. That's going to be through 2 other -- performed through other processes such as 10 3 CFR 50.59.
4 And the plant specific considerations will 5 need -- there are plant specific considerations that 6 will be addressed in future license amendment requests 7 that weren't -- it wasn't appropriate to cover here 8 because it was very topical, a generic evaluation.
9 MEMBER SKILLMAN: Sara, on your third 10 bullet, are you communicating that 50.59 may not be 11 used? Or that the topical report is not approving 12 installation and that if a licensee wants to, the 13 licensee may use 50.59?
14 MS. LYONS: Right. The second one.
15 MEMBER SKILLMAN: The latter?
16 MS. LYONS: That latter one. And I think, 17 you know, a lot of plants have already installed 18 these.
19 MEMBER SKILLMAN: Under 50.59?
20 MS. LYONS: Under 50.59.
21 MEMBER SKILLMAN: Okay. Thank you.
22 MS. LYONS: Um-hum. So, on slide six, the 23 major PRA model review areas included consideration of 24 the Generation I and II shutdown seals, adequacy of 25 the qualification testing, statistical analysis of NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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175 1 shutdown seal failure modes, common cause failure, 2 human reliability analysis, inadvertent actuation of 3 the shutdown seal, and performance monitoring.
4 And we'll go into more detail on those in 5 the closed session. And our conclusion, based on our 6 evaluation of PWR Owners Group 14001, Revision One, as 7 supplemented and various supplements referenced in the 8 AIC.
9 And used in accordance with the 10 limitations and conditions, we've concluded that the 11 safety eval -- I'm sorry. That the document is 12 acceptable.
13 And that licensees always have an option 14 of choosing to model their shutdown seal in a 15 different manner. But they would need to justify any 16 differences or deviations from what is approved and 17 their specific risk-informed license amendment 18 request.
19 MEMBER SKILLMAN: So let me go back to 20 slide five just so it's clear in my mind. You've 21 communicated that a licensee can implement this change 22 through 50.59.
23 But in the next bullet, you say that plant 24 specific considerations are in a license amendment 25 request. Well, what 50.59 does is it makes the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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176 1 licensee determine whether or not a licensed amendment 2 request is needed or not.
3 MS. LYONS: Okay. So what I meant by the 4 last bullet wasn't really related to the installation.
5 I can see how that's a little misleading the way we 6 have it on the slide there.
7 But, the last bullet was really related to 8 the implementation in the PRA. There is some 9 considerations on how the shutdown seal failure is 10 modeled in their PRA.
11 But it really needs to be handled on a 12 site specific basis.
13 MEMBER SKILLMAN: So a hardware mode can 14 be evaluated through 50.59 and successfully 15 implemented as a modification. But the PRA 16 implications come out through the LAR.
17 MS. LYONS: Right.
18 MEMBER SKILLMAN: Understand. Thank you.
19 Thank you. All right.
20 MS. LYONS: And that's all we have today.
21 So if there's any questions.
22 MEMBER STETKAR: Any questions for the 23 staff that pertain to something that we can discuss in 24 the open session?
25 (No response)
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177 1 MEMBER STETKAR: Okay. If not, we'll have 2 the Owners Group come up and give us an introduction 3 to the topic.
4 MR. LINTHICUM: I'm all set. Good 5 afternoon. Once again, similar to the staff, we 6 appreciate the opportunity to come back and discuss 7 our topical report with you.
8 And explain how we're planning on modeling 9 the shutdown seals in the PRA model. My name is Roy 10 Linthicum. I'm Chairman of the Risk Management 11 Committee within the PWR Owners Group.
12 We've actually been working on this 13 topical report longer then the staff has been 14 reviewing it. And we are very anxious to get an SE.
15 A lot of our members really are relying on 16 the SE to be able to move forward with some very 17 important risk informed licensing requests.
18 Next to me is Matt Degonish. He is -- is 19 that one? There we go. Matt is our primary PRA lead 20 for development of the model.
21 When we met here on February 6, Matt was 22 unable to attend. He's a new father. So we dragged 23 him away from his family to come down here today.
24 And Mike LaPresti is here. And he's one 25 of the principal design engineers responsible for the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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178 1 shield.
2 My presentation will be even shorter than 3 the staff's until we get into the closed session. So, 4 just a quick overview.
5 The shutdown seal was developed by 6 Westinghouse to limit the leak rate from the RCPs 7 following a loss of all seal cooling. It allows us to 8 respond to a wide range of events such as station 9 blackout and things that would disrupt the power 10 supplies and cause a loss of all cooling.
11 The important thing in my mind is not only 12 do we get a significant benefit in our PRA models, 13 where we're talking orders of magnitude benefit in the 14 probabilities of seal leakage, but more importantly, 15 we don't challenge the operators as much when we have 16 the seal in place.
17 Because they don't have to worry about a 18 LOCA going on concurrent with the loss of offsite 19 power station blackout event. And that's probably the 20 most important element.
21 And with that said, we also want to make 22 sure we take credit for the PRA models that were 23 modeled in the plant. As closely as built as operated 24 as possible.
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179 1 seal will change their PRA models to credit the seal.
2 It's a fairly simple change to the model.
3 Once we agree on the failure 4 probabilities, it's an add onto the WOG2000 model, 5 which the staff described. Or any other model that we 6 may have.
7 We are actually looking at a possible 8 change to the WOG2000 model that will address some 9 things that aren't covered in that original model.
10 But that's not part of this discussion.
11 But, we wanted to make sure the SE was 12 written so we could -- that the report was written so 13 we can take advantage of those future models as well.
14 And once again, once you integrate it into 15 the PRA model, you do get a significant decrease in 16 core damage frequency. And if we go the next. I'm 17 actually just going to skip the next slide.
18 So, We're actually seeing over 50 percent 19 reduction of core damage frequency. Typically on the 20 order of 60 to 70 percent reduction.
21 Seal LOCAs have been probably the biggest 22 thorn in our side as far as the PRA modeling, as far 23 as our sequences that are concerned. So this really 24 does provide us a tremendous benefit.
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180 1 on the open session.
2 MEMBER SKILLMAN: Roy, why do you show 3 PWRA and PWRB?
4 MR. LINTHICUM: Those are just -- those 5 are two different plants.
6 MEMBER SKILLMAN: It just shows that for 7 two different plants that they're P's -- there's a 8 huge reduction.
9 MR. LINTHICUM: There's a huge reduction.
10 Right. They're slightly different designs. But 11 they're still -- there's still a huge reduction 12 regardless of what type of plant.
13 If you have a Westinghouse RCP pump, 14 regardless of whether or not you're a Westinghouse 15 plant, there's actually some BNW plants with 16 Westinghouse RCPs involved.
17 MEMBER SKILLMAN: Yes.
18 MR. LINTHICUM: Regardless of the plant 19 design, you get a very large reduction.
20 MEMBER SKILLMAN: Okay. You're saying if 21 it's a P and has a seal, that's what happens.
22 MR. LINTHICUM: That's what happens.
23 MEMBER SKILLMAN: Makes no difference 24 whether it's a --
25 MR. LINTHICUM: Correct.
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181 1 MEMBER SKILLMAN: BNW or a --
2 MR. LINTHICUM: Correct.
3 MEMBER SKILLMAN: Westinghouse origin or 4 what's in origin.
5 MR. LINTHICUM: Yes. Well, I don't know 6 of any combustion plants that have Westinghouse pumps 7 that would have the seal design that are in the 8 WOG2000.
9 But there are some that may have.
10 MEMBER SKILLMAN: Is it strongly 11 influenced by whether it's a Byron Jackson pump or one 12 of the other --
13 MR. LINTHICUM: This seal only applies to 14 Westinghouse pumps.
15 MEMBER SKILLMAN: Only to Westinghouse 16 pumps.
17 MR. LINTHICUM: Only Westinghouse pumps, 18 right.
19 MEMBER SKILLMAN: Got it.
20 MR. LINTHICUM: The Byron Jackson pumps 21 that are in like the CE plants, have a different seal 22 design. And there's actually an approved topical on 23 the PRA model for those seals as well.
24 MEMBER SKILLMAN: And the Bingham pumps?
25 MR. LINTHICUM: That's all -- all the CE NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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182 1 pumps are covered under that topical report on the CE 2 plants.
3 MEMBER SKILLMAN: Thank you Roy.
4 MR. LINTHICUM: Okay.
5 MEMBER STETKAR: Anything else for the 6 Owners Group in open session?
7 (No response) 8 MEMBER STETKAR: If not, are there any 9 people in the room who would like to make a comment 10 during the open session? If so, come up to the mic.
11 And I'll ask if there are any members of the public on 12 the bridge line who would like to make a comment.
13 Please identify yourself and make a comment, please.
14 MR. BROWN: Bridge open.
15 MEMBER STETKAR: Thank you. Hearing none, 16 We will now close the session and close the 17 transcript. If you could bang the gavel.
18 (Whereupon, the above-entitled matter went 19 off the record at 3:37 p.m.)
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ACRS Full Committee Meeting NRC Staff Review of Extended Power Uprate for Browns Ferry Nuclear Plant Units 1, 2, and 3 June 7, 2017 1
Opening Remarks Kathryn Brock Deputy Director Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation 2
Background
- Browns Ferry Proposed EPU:
3458 to 3952 Megawatts Thermal 14.3% increase from Current Licensed Thermal Power
- EPU Review done using Extended Power Uprate Review Standard, RS-001
- No open items in draft safety evaluation 3
Introduction Farideh Saba Senior Project Manager Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation 4
Review Schedule
- September 21, 2015 - Application submitted to NRC.
- January 11, 2016 - Application accepted by NRC for review.
- May 3, 2017 - ACRS Subcommittee meeting
- NRC forecast for review completion July 2017
- TVA planned implementation dates:
Unit 3 in Spring 2018 Unit 1 in Fall 2018 Unit 2 in Spring 2019 55
Agenda OPEN SESSIONS TVA Presentations:
- Background
- Summary of Plant Modifications
- Overview of Elimination of Credit for Containment Accident Pressure (CAP)
- Overview of Replacement Steam Dryer CLOSED SESSIONS NRC staff Presentations:
- Review of Fuel and Reactor System
- Review of CAP Credit Elimination
- Review of Replacement Steam Dryers 6
Browns Ferry Nuclear Plant Extended Power Uprate License Amendment Request Advisory Committee on Reactor Safeguards June 7, 2017
Introductions
Browns Ferry Nuclear Plant Extended Power Uprate Gerry Doyle Director, Extended Power Uprate and Ed Schrull TVA Corporate Fleet Licensing Manager Browns Ferry EPU ACRS l 2
BFN EPU ACRS - Introductions Agenda Introductions E. Schrull/G. Doyle Overview Background S. Bono Modifications Summary L. Hughes Elimination of credit for Containment Accident P. Donahue Pressure (CAP) in Net Positive Suction Head (NPSH) evaluations for Emergency Core Cooling System (ECCS) pumps Replacement Steam Dryer (RSD) Overview D. Pappone Browns Ferry EPU ACRS l 3
BFN EPU ACRS - Introductions Key Team Members Present Steve Bono - Browns Ferry Nuclear Plant (BFN) Site Vice President Lang Hughes - BFN General Manager, Site Operations Gerry Doyle - Director, Extended Power Uprate (EPU)
Scott Hunnewell - BFN Director, Site Engineering Pete Donahue - EPU Senior Engineering Manager Denny Campbell - BFN Nuclear Plant Shift Operations Manager Bill Baker - EPU Senior Operations Manager Ed Schrull - Tennessee Valley Authority Corporate Fleet Licensing Manager Dan Green - EPU Senior Licensing Manager Michael Dick - EPU Project Engineer Greg Storey - EPU Project Engineer Jeff Lewis - EPU Project Bill Williamson - BFN Reactor Engineer Browns Ferry EPU ACRS l 4
BFN EPU ACRS - Introductions Key Team Members Present (continued)
Dan Pappone - General Electric - Hitachi (GEH)
Don Sampson- GEH David McBurney - AREVA Alan Meginnis - AREVA Browns Ferry EPU ACRS l 5
BFN EPU ACRS Subcommittee - Introductions BFN EPU Team The EPU Project Team is staffed with personnel having extensive Boiling Water Reactor (BWR) plant and EPU experience TVA
- Combination of dedicated project and plant resources GEH (Nuclear Steam Supply System)
AREVA (Fuels)
Industry EPU experienced specialty contractors Browns Ferry EPU ACRS Subcommittee l 6
BFN EPU ACRS Subcommittee - Introductions BFN EPU Project Team Goals Present Nuclear Regulatory Commission (NRC) with a high quality License Amendment Request (LAR) consistent with RS-001 Standards Resolve Containment Accident Pressurization (CAP) credit issues Install Replacement Steam Dryers (RSD) for all three units Provide smooth transition to EPU for Plant Operations Browns Ferry EPU ACRS Subcommittee l 7
Overview Browns Ferry Nuclear Plant Extended Power Uprate Steve Bono Browns Ferry Nuclear Plant Site Vice President and Lang Hughes Browns Ferry Nuclear Plant General Manager, Site Operations Browns Ferry EPU ACRS l 8
Background
BFN General Electric Boiling Water Reactor (BWR)/4 Mark I Containment Operating Licenses issued Unit 1 - 12/20/1973, Unit 2 - 8/20/1974, Unit 3 - 8/18/1976 Commercial Operation commenced Unit 1 - 8/1/1974, Unit 2 - 3/1/1975, Unit 3 - 3/1/1977 Renewed Licenses issued 5/4/2006 (Units 1, 2, and 3)
Licensed Thermal Power History Original Licensed Thermal Power (OLTP) - 3293 MWt Stretch Uprate (105% OLTP) - 3458 MWt
- Units 2 and 3 - 9/8/1998, Unit 1 - 3/6/2007 Proposed EPU (120% OLTP, 14.3% CLTP) - 3952 MWt Browns Ferry EPU ACRS l 9
BFN EPU ACRS - Overview Modifications Summary U1 Feed Water Pump High Pressure Turbine Condensate Pumps Condensate Booster Pumps Browns Ferry EPU ACRS l 10
BFN EPU ACRS - Overview Modifications Summary Remaining Modifications Replacement Steam Dryer
- New steam dryers to be installed to increase structural design margin to accommodate EPU operation High Pressure Turbine Replacement
- High pressure rotors to be replaced with rotors designed for increase flow associated with EPU Feedwater Heaters
- Tube bundle and channel head to be replaced in the number 4 Feedwater Heaters with design less susceptible to flow-induced vibration Main Generator Hydrogen Pressure
- Main generator hydrogen pressure to be increased to support EPU operation Browns Ferry EPU ACRS l 11
BFN EPU ACRS - Overview Modifications Summary Remaining Modifications (continued)
Standby Liquid Control (SLC) System
- Increase Boron-10 enrichment from 63 to 94 atom percent in SLC Storage Tank solution to lower power faster during Anticipated Transient Without Scram (ATWS)
Hardened Wetwell Vent (HWWV)
- Modify HWWV, as part of modifications for compliance with the Order on Reliable Hardened Containment Vents, to provide capacity of HWWV that is one percent of EPU thermal power Self-Excited Generator Excitation System
- Modify excitation system to a self-excited shaft driven alternator and modify the Automatic Voltage Regulator to address a transient stability issue resulting from increased electrical generation at EPU conditions (North American Electric Reliability Corporation issue)
Alternate Leakage Treatment Pathway
- Modify the Alternate Leakage Treatment Pathway design to be consistent with the existing licensing basis dose calculations performed at EPU conditions Browns Ferry EPU ACRS l 12
BFN EPU ACRS - Overview Modifications Summary Remaining Instrumentation Changes to support EPU Technical Specification Instrumentation Respan/Recalibration
- Turbine first stage pressure scram bypass permissive setpoint to be recalibrated
- Main steam line high flow isolation channel to be respanned
- Average Power Range Monitor flow biased and setdown instrumentation to be respanned and setpoints recalibrated Condenser Instrumentation Upgrade
- Install nine new condenser vacuum pressure transmitters per unit (three on each condenser) and provide signals to electro-hydraulic control (EHC) system
- Move condenser A/B/C low vacuum alarm, low vacuum turbine trip and low vacuum bypass trip functions to EHC logic
- Perform hardware and software changes to EHC system to support alarm and trip functions Browns Ferry EPU ACRS l 13
Elimination of Credit for Containment Accident Pressure in Net Positive Suction Head Evaluations for Emergency Core Cooling System Pumps Pete Donahue Extended Power Uprate Senior Engineering Manager Browns Ferry EPU ACRS l 14
BFN EPU ACRS - Elimination of credit for CAP in NPSH Evaluations for ECCS pumps Browns Ferry EPU ACRS l 15
BFN EPU ACRS - Elimination of credit for CAP in NPSH Evaluations for ECCS pumps
Background
Opportunity to improve margins and address industry concerns associated with CAP credit One of the EPU Project Team Goals Used guidance provided in SECY-11-0014, Use of Containment Accident Pressure in Analyzing Emergency Core Cooling System and Containment Heat Removal System Pump Performance in Postulated Accidents EPU NPSH evaluations for ECCS pumps demonstrate credit for CAP is NOT required Browns Ferry EPU ACRS l 16
BFN EPU ACRS - Elimination of credit for CAP in NPSH Evaluations for ECCS pumps Actions to Eliminate CAP Credit Performed comprehensive analyses of accidents and special events Increased Residual Heat Removal (RHR) Heat Exchanger factor (K-value) for all events Validated acceptability of increased RHR Heat Exchanger K-value by performing RHR Heat Exchanger Performance Tests on all 12 RHR Heat Exchangers at BFN (4 per unit)
To ensure that this level of RHR Heat Exchanger performance is maintained, a Technical Specification for the RHR Heat Exchanger Performance Monitoring Program will be added Increased SLC System Boron-10 enrichment for ATWS event Used Vendor supplied NPSH curves (NPSHr 3% curves)
Used Technical Specification values for initial conditions in Design Basis Accident (DBA) Loss of Coolant Accident (LOCA) and Special Events analyses Except for Fire Event
- SECY-11-0014 allows use of nominal values for Special Events Browns Ferry EPU ACRS l 17
BFN EPU ACRS - Elimination of credit for CAP in NPSH Evaluations for ECCS pumps Results For all events Net Positive Suction Head Available (NPSHa) is greater than Effective Net Positive Suction Head Required (NPSHreff)
No CAP credit required No additional operator actions required Browns Ferry EPU ACRS l 18
Replacement Steam Dryer (RSD) Overview Dan Pappone GE - Hitachi Nuclear Energy Browns Ferry EPU ACRS l 19
BFN EPU ACRS - RSD Overview Summary Based on the curved hood six bank prototype replacement dryer first used in a BWR/4 reactor Design is significantly more robust than the original steam dryer it replaces BFN acoustic load definition developed using Main Steam Line (MSL) acoustic pressure measurements taken at the three BFN units The Flow Induced Vibration (FIV) fatigue evaluation and primary stress methodologies used for BFN RSD analysis has been reviewed in detail on BWR/6 RSD and Economic Simplified Boiling Water Reactor projects Analyzed for the applicable primary structural loads for normal operation and for transient and accident conditions Browns Ferry EPU ACRS l 20
BFN EPU ACRS - RSD Overview EPU RSD Experience Successful operating history for RSDs at EPU conditions Quad Cities Units 1 and 2 RSDs Dresden Units 2 and 3 RSDs Vermont Yankee original dryer with modifications Susquehanna Units 1 and 2 RSDs Grand Gulf RSD Browns Ferry EPU ACRS l 21
BFN EPU ACRS - RSD Overview BFN RSD Design Changes to prototype dryer design Dryer/vessel interface changes Address Operating Experience lessons learned Refine design details to reduce stresses Browns Ferry EPU ACRS l 22
BFN EPU ACRS - RSD Overview BFN RSD Analysis Vessel Acoustic FE Obtain Plant MSL Acoustic Model Data for Dryer Load Fluctuating Pressure Load Evaluation Definition (PBLE) for FIV Analysis at CLTP Develop SRV Screen for Potential SRV Trend and Project FIV Acoustic Resonance Acoustic Resonances Loads to EPU Characteristics Steam Dryer Structural FE Model Stress Adjustments to EPU including SRV Resonance, FIV Stress Analysis at CLTP VPF, and Bias and Primary Stress Analysis Uncertainty Steam Dryer Structural FE ASME Acceptance Criteria Model FIV Acceptance Criteria Limit Curves & Power Ascension Monitoring Browns Ferry EPU ACRS l 23
BFN EPU ACRS - RSD Overview BFN RSD FIV Analysis BFN RSD Finite Element Model (FEM)
Used to develop BFN-specific design improvements FIV stress adjustments applied to FEM results BFN RSD Fatigue Analysis Results BFN RSDs satisfy the NRC recommended minimum alternating stress ratio of 2.0 for all practical purposes Browns Ferry EPU ACRS l 24
BFN EPU ACRS - RSD Overview BFN RSD Primary Stress Evaluation RSD is a non-safety related item Classified as an Internal Structure as defined in American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code,Section III, Subsection NG, Paragraph NG-1122 RSD is not an ASME Code component BFN RSD Primary Stress Results RSD was evaluated for Normal, Upset, Emergency and Faulted conditions Stresses for each load combination were compared to ASME Code,Section III, NG stress limits for all RSD components The stresses for all structural components are below the ASME Code allowable limits at EPU operating conditions Browns Ferry EPU ACRS l 25
BFN EPU ACRS - RSD Overview BFN RSD Power Ascension Monitoring Power ascension monitoring process similar to previous RSD projects Addressed in BFN License Conditions BFN Lead Unit Both RSD and MSLs instrumented Monitor using strain gauges, on-dryer pressure transducers, and accelerometer Confirmatory structural analysis for lead unit at EPU based on on-dryer measurements Follow-on Units MSLs instrumented Confirmatory structural evaluation based on MSL measurements Browns Ferry EPU ACRS l 26
BFN EPU ACRS - RSD Overview BFN RSD Power Ascension Monitoring (continued)
BFN License Conditions address BFN Lead Unit Test Plan, including hold points for NRC review of data and evaluations BFN Follow-on Units Test Plan, including hold points for NRC review of data and evaluations BFN RSD Inspection Plan consistent with industry guidance Browns Ferry EPU ACRS l 27
- ASME - American Society of
- FIV - Flow Induced Vibration Mechanical Engineers
- GEH - General Electric - Hitachi
- HWWV - Hardened Wetwell Vent
- LOCA - Loss of Coolant Accident
- AVS - Acoustic Vibration Suppressors
- BFN - Browns Ferry Nuclear Plant
- BLEU - Blended Low Enriched
- MWt - Megawatts Thermal Uranium
- NPSH - Net Positive Suction Head
- BWR - Boiling Water Reactor
- NPSHa - Net Positive Suction Head
- CAP - Containment Accident Pressure Available
- CCW - Condenser Circulating Water
- NPSHreff - Effective Net Positive Suction
- CLTP - Current Licensed Thermal Head Required Power
- NRC - Nuclear Regulatory Commission
- DBA - Design Basis Accident
- OLTP - Original Licensed Thermal Power
- ECCS - Emergency Core Cooling
- PBLE - Plant Based Load Evaluation System
- EHC - Electro-hydraulic Control
- RSD - Replacement Steam Dryer
- EPU - Extended Power Uprate
- F - Fahrenheit
- FE - Finite Element
- VPF - Vane Passing Frequency
BFN EPU ACRS - Questions/Comments Browns Ferry EPU ACRS l 29