ML102650333
| ML102650333 | |
| Person / Time | |
|---|---|
| Site: | 05000001, 05200010 |
| Issue date: | 09/09/2010 |
| From: | Advisory Committee on Reactor Safeguards |
| To: | |
| References | |
| NRC-409 | |
| Download: ML102650333 (380) | |
Text
Official Transcript of Proceedings NUCLEAR REGULATORY COMMISSION
Title:
Advisory Committee on Reactor Safeguards 575th Meeting: Open Session Docket Number: (n/a)
Location: Rockville, Maryland Date: Thursday, September 9, 2010 Work Order No.: NRC-409 Pages 1-276 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 DISCLAIMER 3
4 5 UNITED STATES NUCLEAR REGULATORY COMMISSIONS 6 ADVISORY COMMITTEE ON REACTOR SAFEGUARDS 7
8 9 The contents of this transcript of the 10 proceeding of the United States Nuclear Regulatory 11 Commission Advisory Committee on Reactor Safeguards, 12 as reported herein, is a record of the discussions 13 recorded at the meeting.
14 15 This transcript has not been reviewed, 16 corrected, and edited, and it may contain 17 inaccuracies.
18 19 20 21 22 23 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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2 1 UNITED STATES OF AMERICA 2 NUCLEAR REGULATORY COMMISSION 3 + + + + +
4 575TH MEETING 5 ADVISORY COMMITTEE ON REACTOR SAFEGUARDS (ACRS) 6 + + + + +
7 THURSDAY, SEPTEMBER 9, 2010 8 + + + + +
9 ROCKVILLE, MARYLAND 10 The Committee met at the Nuclear 11 Regulatory Commission, Two White Flint North, Room 12 T2B1, 11545 Rockville Pike, at 8:30 a.m., Said Abdel-13 Khalik, Chairman, presiding.
14 COMMITTEE MEMBERS:
15 SAID ABDEL-KHALIK, Chairman 16 J. SAM ARMIJO, Vice Chairman 17 JOHN W. STETKAR, Member-at-Large 18 SANJOY BANERJEE, Member 19 DENNIS C. BLEY, Member 20 MARIO V. BONACA, Member 21 MICHAEL L. CORRADINI, Member 22 DANA A. POWERS, Member 23 HAROLD B. RAY, Member 24 MICHAEL T. RYAN, Member 25 WILLIAM J. SHACK, Member NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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3 1 ACRS STAFF PRESENT:
2 EDWIN M. HACKETT, Executive Director 3 CHRIS BROWN, Designated Federal Official 4 NEIL COLEMAN, Designated Federal Official 5 TANNY SANTOS, JR., Designated Federal Official 6 BRUCE BAVOL 7 ILKA BERRIOS 8 LARRY CAMPBELL 9 AMY CUBBAGE 10 JAMES GILMER 11 CHRISTOPHER HOTT 12 JOHN LEHNING 13 JOHN McKIRGAN 14 KEVIN MORRISSEY 15 BILL RULAND 16 MICHAEL SCOTT 17 GEORGE THOMAS 18 DAVE TIKTINSKY 19 CHRISTOPHER TRIPP 20 HANRY WAGAGE 21 REX WESCOTT 22 23 24 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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4 1 ALSO PRESENT:
2 SVEN BADER, MOX Services 3 GARY BELL, MOX Services 4 JOHN BUTLER, NEI 5 JESUS DIAZ-QUIROZ, GEH 6 PAUL DUVAL, MOX Services 7 BOB FOSTER, MOX Services 8 DEATIS GWYN, MOX Services 9 BILL HENNESSY, MOX Services 10 WAYNE MARQUINO, GEH 11 TONY PIETRANGELO, NEI 12 SCOTT SALZMAN, MOX Services 13 BRIAN STONE, MOX Services 14 15 16 17 18 19 20 21 22 23 24 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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5 1 T A B L E O F C O N T E N T S 2 Opening Remarks 3 Said Abdel-Khalik, Chairman............. 4 4 Potential Approaches to Resolve Generic 5 Safety Issue (GSI)-191, Assessment of 6 Debris Accumulation on Pressurized Water 7 Reactor Sump Performance ..................... 5 8 Amendment to the DCD for the Certified Advanced 9 Boiling Water Reactor .................... 121 10 Long-Term Core Cooling Approach for the Economic 11 Simplified Boiling Water Reactor ............ 99 12 License Application for the MOX Fuel Fabrication 13 Facility and the Associated Safety 14 Evaluation Report .......................... 171 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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6 1 P-R-O-C-E-E-D-I-N-G-S 2 (8:29 a.m.)
3 CHAIRMAN ABDEL-KHALIK: The meeting will 4 now come to order. This is the first day of the 575th 5 meeting of the Subcommittee on Reactor Safeguards.
6 During today's meeting, the committee will 7 consider the following: 1) Potential approaches to 8 resolve generic safety issue 191 assessment of debris 9 accumulation on pressurized water reactor sump 10 performance; 2) amendment to the design control 11 document for the certified advanced boiling water 12 rector design; 3) long-term cooling approaches for 13 economic simplified boiling water reactor design; 4) 14 license application for the mixed oxide fuel 15 fabrication facility and the associated safety 16 evaluation report; 5) preparation of ACRS reports.
17 This meeting is being conducted in 18 accordance with the provisions of the Federal Advisory 19 Committee Act. Mr. Tanny Santos is the Designated 20 Federal Official for the initial portion of the 21 meeting.
22 Portions of the sessions dealing with the 23 amendment to the design control document for the 24 certified ABWR design, the long-term cooling approach 25 for the ESBWR design, and the license application for NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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7 1 the mixed oxide fuel fabrication facility may be 2 closed to protect proprietary and unclassified 3 safeguards information.
4 We have received no written comments or 5 request for time to make oral statements from members 6 of the public regarding today's sessions. There will 7 be a phone bridge line. To preclude interruption of 8 the meeting, the phone will be placed in a listen-in 9 mode during the presentation and committee discussion.
10 A transcript of portions of the meeting is 11 being kept and it is requested that the speakers use 12 one of the microphones, identify themselves, and speak 13 with sufficient clarity and volume so that they can be 14 readily heard.
15 We will now proceed to the first item on 16 the agenda, potential approaches to resolve GSI-919 17 and Dr. Banerjee will lead us through that discussion.
18 Dr. Banerjee.
19 MEMBER BANERJEE: Thank you, Mr. Chairman.
20 We will be hearing from the staff actually for about 21 one and a half hours and from NEI for half an hour.
22 So that is not explicitly shown in the agenda but that 23 is the plan.
24 In any case to give you a little 25 background, we will be hearing about the staff NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 1 response which was a policy paper to the Commission's 2 SRM which came out May 17, 2010. The SRM followed an 3 industry briefing to the Commission and as a result, 4 the Commission asked the staff to stay issuance of 5 letters to licensees under 10 C.F.R. 54(f). Right, 6 Mike? Okay. And submit a notation policy paper on 7 potential approaches to bring GSI-191 to closure.
8 At this point, note that 44 of 69 or 9 thereabouts PWR plants have been proceeding 10 systematically and you can see the sort of light at 11 the end of the tunnel there. Twenty-five plants or 12 there abouts which are high fiber plants are still 13 remaining and it is really with regard to them that 14 options are being explored.
15 And I am going to just turn it over to 16 Mike to take it on from there and stay roughly within 17 time, if you can, because this can go on forever.
18 MR. SCOTT: We will do everything within 19 our control to stay on time.
20 MEMBER POWERS: That was not the charter.
21 MR. SCOTT: Thank you, Dr. Banerjee. We 22 are pleased to be presenting this subject today as we 23 did to the subcommittee, the Thermal Hydraulic 24 Subcommittee two days ago.
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9 1 I think that it would be accurate to say that all of 2 the licensees are proceeding methodically to try to 3 get through this issue. As we all know, those of us 4 who have been involved with it, it has been an 5 extraordinarily challenging issue, both for the higher 6 fiber plants and for the less challenged plants. But 7 it has been challenging for all, including the in-8 vessel effects issue, which is still out there.
9 So they are all being methodical about it 10 but we are down to mostly roughly one-third of all the 11 PWRs who are most challenged by this issue, for 12 reasons that we will briefly talk about today.
13 And Chris Hott who is with me today will 14 be making the presentation. Chris is in the Division 15 of Safety Systems and is responsible, has been 16 responsible for the development of the SECY paper, 17 which I believe you have all, hopefully, had a chance 18 to read and which is the subject of our presentation 19 today.
20 So, Chris, over to you. Let's begin.
21 MR. HOTT: All right. Thanks. Good 22 morning. As Mike said, I am Chris Hott and today we 23 want to provide background information on the SECY 24 paper. We will give a status update on GSI-191 25 activities, discuss stakeholder views. We will brief NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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10 1 you on the approach used by the staff to respond to 2 the May 17th SRM and will provide the rationale for 3 the staff's recommendation in the SECY paper.
4 As most of us know here, GSI-191 focuses 5 on reasonable assurance that long-term core cooling 6 will be maintained in the presence of debris in the 7 containment sump following a loss-of-coolant accident.
8 Generic Letter 2004-02 requested licensees look into 9 whether their sumps would clog if a LOCA were to 10 happen and to tell the NRC how they evaluated the 11 issue and whether any plant changes, based on what 12 they found.
13 The letter requested that if modifications 14 were needed, that they would be completed by the end 15 of 2007. During this time, licensees believed, as did 16 most of us that near-term action to make PWR strainers 17 larger was the prudent thing to do. And as of today, 18 all licensees have increased their strainer sizes by 19 one to two orders of magnitude. However, some aspects 20 of the issue, things such as order of debris arrival 21 and thin-bed effect have been found to be more 22 significant than initially thought, which called into 23 question the assumption that large strainers would 24 always be enough to address the issue.
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11 1 of 69 have performed analysis and evaluation using 2 methods acceptable to the staff and 13 more plants 3 currently plan to do the same. That gives us a total 4 of 46 of 69 PWRs that have settled all test and 5 evaluation questions for sump clogging.
6 Most of the remaining 23 plants have 7 relatively large amounts of fibrous insulation and as 8 such, credited refinements the staff generally has not 9 accepted to main areas or in ZOI and settling credit.
10 MEMBER CORRADINI: You may have mentioned 11 this on Tuesday but I was listening on the phone so 12 maybe I missed it. So the BWRs from the standpoint of 13 this issue resolution are acceptable not in-vessel but 14 for some strainers.
15 MR. SCOTT: I would say it slightly 16 differently. GSI-191 pertains only to PWRs.
17 MEMBER CORRADINI: Okay.
18 MR. SCOTT: There was a question of the 19 impact of debris on BWR ECCS strainers, which was 20 resolved back in the 1990s.
21 MEMBER CORRADINI: That is what I 22 remember.
23 MR. SCOTT: But a lot of water under the 24 bridge since then and we have learned a lot as we have 25 gone through the PWR issues. And so we have asked the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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12 1 industry, the BWR side of the house to revisit the 2 analyses that were done for the BWRs to see whether it 3 would be appropriate to revisit that issue. And the 4 BWR owner's group is proactively evaluating the issues 5 and we kicked off last month a series of monthly 6 meetings to discuss the issue with them.
7 MEMBER CORRADINI: And there is a 8 reevaluation going on now.
9 MR. SCOTT: That is correct.
10 MEMBER CORRADINI: Okay.
11 MEMBER BANERJEE: And it is part of the 12 SRM issue. In a sense they need to be informed about 13 what is happening.
14 MR. SCOTT: Correct but that is the only 15 impact of it on the SRM and it is not addressing the 16 SECY.
17 MEMBER CORRADINI: Thank you. Thank you 18 very much.
19 MEMBER BANERJEE: No, it is not addressing 20 the SECY.
21 MR. HOTT: So --
22 MEMBER SHACK: Excuse me. When you say 23 fibrous insulation, is that a mix of CalSil and NUKON 24 type stuff? I'm sure there is a mix of everything but 25 lots of those are CalSil plants still?
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13 1 MR. SCOTT: Some plants. I don't know if 2 I would characterize it as a lot but there are some 3 plants out there that have CalSil. This is an 4 extremely plant-specific issue. There are different 5 types of fibrous insulation out there. There are some 6 that are even difficult to characterize as either 7 fibrous or particulate because they are mix of both.
8 It is just there is a wide variety.
9 MEMBER ARMIJO: What is the range, the 10 mass in these remaining plants, hundreds of pounds to 11 up to thousands of pounds? Just a scale.
12 MR. SCOTT: I guess I would be reluctant 13 to speculate. If John Lehning is here, perhaps he 14 might have an estimate for this.
15 MR. LEHNING: This is John Lehning from 16 the staff. It could be thousands of pounds.
17 MR. SCOTT: Okay. A lot.
18 MEMBER BANERJEE: John can you give us 19 roughly a range in the remaining plants?
20 MR. LEHNING: I can't give you a range off 21 the top of my head. I can say some of the remaining 22 plants, some of the ones we call high fiber, they 23 could be thousands, like a thousand or more cubic feet 24 or several thousand pounds of fiberglass. And then, 25 you know, hundreds or thousands of pounds of NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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14 1 particulate types of coating or other things like that 2 as well.
3 MEMBER CORRADINI: So this deviates a bit 4 but I remember on Tuesday there was a question about 5 the proper attribute to quote. So is mass the proper 6 attribute? Is volume the attribute?
7 If somebody were to say I am concerned 8 about this sort of insulation because it has these 9 attributes, what are those attributes?
10 MR. SCOTT: Well we don't address the 11 issue in terms of the amount of the material they 12 have. If they have just, you know, thousands of 13 pounds or thousands of cubic feet or whatever of this 14 material in this containment but they can demonstrate 15 that through the analyses that we have accepted, that 16 their strainer performs acceptably, then that is fine.
17 So we really don't go there. We go in 18 terms of it is sort of performance-based. If you use 19 the analyses and you run a test that shows that your 20 strainer passes adequate flow, then you are okay.
21 MEMBER CORRADINI: Okay. All right. So 22 you are saying only if something occurs -- I remember 23 before you had shown us a decision matrix, as I pass 24 through this decision matrix, if I get to a point 25 where I might have to be concerned, then you start NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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15 1 looking at these attributes.
2 MR. SCOTT: You consider where you might 3 get a break, find the worst case, run a strainer test 4 and, of course, this can't be done in the plant. You 5 run a strainer test in a remote facility, in a vendor 6 facility, and see what your head loss is. And if you 7 have adequate head loss, you know, not excessive head 8 loss, then you have shown acceptable performance. If 9 not, then you may have to make some type of plant 10 modification, either replace some of that problematic 11 insulation with some less problematic material or make 12 some other modification.
13 MEMBER CORRADINI: You have answered my 14 question. Thank you.
15 MR. SCOTT: Okay.
16 MEMBER CORRADINI: Thank you very much.
17 MEMBER BANERJEE: It could be protecting 18 the insulation as well.
19 MEMBER CORRADINI: Well the only reason I 20 asked it was you guys are starting to ask about mass 21 and then somebody quotes volume. I am not sure what I 22 should worry about relative to the attribute.
23 MR. SCOTT: I would suggest you wouldn't 24 need to worry about it either way. It is the end 25 result that is important.
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16 1 MEMBER CORRADINI: Thank you.
2 MR. HOTT: The last part of this slide 3 talks about new industry efforts to credit settling 4 and ZOI reductions that the staff plans to evaluate 5 and the bullet right above that notes that the staff 6 has accepted refinements in certain areas where we are 7 technically justified. One example is in debris 8 erosion.
9 Early in 2010 the staff determined that 10 refinements in critical areas like zone of influence 11 and settling credit were not likely to be successful 12 in the near term. So as Dr. Banerjee highlighted, the 13 staff was a path to issue 50.54(f) letters.
14 In that April 15 Commission brief, the 15 industry --
16 MEMBER BANERJEE: Could I add a little 17 something to this?
18 MR. HOTT: Yes.
19 MEMBER BANERJEE: The reason that changing 20 things like the zone of influence and so on is so 21 difficult is that the ACRS, for example, went through 22 an extensive review of this back in 2003 and looked at 23 all the tests that were done and Professors Wallis and 24 Ransom wrote extensive notes on these. They came to 25 the conclusion on the basis of all the testing, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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17 1 including MARVIKIN and all this stuff, that in some 2 cases it was conservative, in some cases it wasn't 3 necessarily conservative, the model.
4 So in fact, we sort of have implicitly 5 accepted this model as bringing some regulatory 6 certainty but it is neither conservative nor non-7 conservative. And ACRS has never really said it one 8 way or the other, except to point out some of the 9 difficulties.
10 So to try to change this is really 11 swimming uphill and it is not going to be very easy.
12 And that is why I think the staff correctly has sort 13 of been a little skeptical about these efforts, which 14 would drag on for 15 years before something comes out 15 of it.
16 MEMBER CORRADINI: So can I ask you a 17 question about that, since you brought up that?
18 With the pulling back of ANIS standard 19 58.2, does that change what you just said?
20 MEMBER BANERJEE: I don't think so. I 21 think that is for the staff to say but if the staff 22 accepted methodology --
23 MEMBER CORRADINI: Okay, fine.
24 MEMBER BANERJEE: -- whether it is in a 25 standard or not I think is irrelevant as far as we are NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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18 1 concerned. But that I think Mike can comment on.
2 MR. SCOTT: We understand that that 3 standard was not pulled back for lack of merit. It 4 was pulled back administratively. I think you had 5 asked that question and we sent you what information 6 we had on it. And we did not find that particular 7 circumstance to be of concern.
8 MEMBER CORRADINI: Well I mean from a 9 technical standpoint, the reason I ask it like that is 10 my understanding for the 58.2 was that it did not take 11 into effect initial shock loading and dynamic effects.
12 But my understanding the paper, the stuff you had 13 sent us from Dr. Wallis and Dr. Ransom did, relative 14 to this, I thought.
15 MEMBER BANERJEE: Well Vic Ransom pointed 16 out that the blast wave was not considered. But you 17 know, in some sense we went with the ZOI model even 18 without the blast wave. After all, to set up a blast 19 wave you really have to have an instantaneous double-20 ended guillotine rupture or an instantaneous rupture.
21 So leaving out the blast wave may not be 22 such a big deal.
23 MR. SCOTT: The other thing was that the 24 recent unsuccessful effort by the owners group to 25 justify reduced ZOI did elicit questions from the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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19 1 staff regarding blast wave. And so we have evaluated 2 that issue and it ended up being considered resolved.
3 Now we did not accept the reductions for a number of 4 other reasons, which are documented in a letter that 5 we sent to the owners group that I think you all have 6 a copy of. So we have considered that impact.
7 But we agree with what you said, Dr.
8 Banerjee, that we are not convinced one way or another 9 that there is a lot of gain to be had here in 10 reducing and justifying reduction in ZOI. The last 11 effort did not work out. The industry wants to try 12 another. We are willing to evaluate it but we are not 13 at all able to say that we think at this point that it 14 is likely to succeed.
15 MEMBER CORRADINI: Okay, thank you.
16 MR. HOTT: As I was saying, in the April 17 15th Commission brief, the industry expressed concerns 18 that the staff path for closure GSI-191 would yield 19 little safety benefit and a large radiation exposure 20 to workers. The industry highlighted their preferred 21 path was to use leak-before-break credit for sump 22 evaluations.
23 We also heard form the Union of Concerned 24 Scientists that sent us two letters. The first one 25 said that they felt the staff was on track to NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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20 1 successful issue closeout by not allowing leak-before-2 break credit and the second letter said that they 3 could support use of LBB credit under certain 4 circumstances, as long as leak detection systems could 5 be guaranteed to be reliable and that none of the 6 changes for GSI-191 would impact those leak detection 7 systems.
8 As already covered following the April 9 15th Commission meeting, the Commission issued an SRM.
10 A number of requirements for the staff to consider 11 are listed on this slide. In response to the SRM, the 12 staff took a comprehensive look at the issue and we 13 are here to brief you on a recommended path forward.
14 Okay, we just mentioned before that the 15 industry position was that there was little safety 16 benefit for additional changes for GSI-191. Part of 17 that is due to LOCAs being low probability, especially 18 larger breaks. However, some clogging is a high 19 consequence event and the inability of sumps to pass 20 adequate flow would likely lead to core damage and the 21 loss of the containment spray system, which is a 22 mitigation feature.
23 We have also seen that a small amount of 24 the right materials can cause clogging. LOCAs as 25 small as three inches have been determined to generate NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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21 1 enough debris to cause a challenge to some performance 2 --
3 MR. SCOTT: At some plants.
4 MR. HOTT: -- at some plants.
5 These make the uncertainties in sump 6 performance significant for high fiber plants that do 7 not have a defensible strainer test and the staff 8 believes it is not prudent to allow uncertainties to 9 continue indefinitely.
10 A source of uncertainty exists due to the 11 lack of realistic models in areas that can have large 12 impacts on sump performance, such as debris generation 13 and debris transport. The staff has a potion that the 14 current models used to analyze GSI-191 are 15 conservative, though not overly so. Industry, 16 however, believes the models are overly conservative 17 and as such, some licensees have tried to justify 18 refinements to those models.
19 MEMBER BANERJEE: Let me also make a 20 little comment on the last bullet that you have in the 21 previous slide which is the debris settlement 22 business. At the moment, correct me Mike if I am 23 wrong, but the staff essentially requires most of the 24 fine debris, fine particles and fibers to be 25 suspended in the tests. And that also agrees with NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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22 1 what we feel in that the scale effects are very, very 2 difficult to model because the Reynolds numbers in the 3 plant are very high, so you have very high degrees of 4 turbulence which, in a narrow flume or something is 5 difficult to reproduce. So we have always felt 6 strongly that the staff position was defensible 7 because it took a high turbulence sort of limit.
8 In a flume, of course, you can make it 9 quite low turbulence. Therefore, you can get 10 settling. You may not get that in the plant. And 11 that is really the issue that I don't know how you can 12 deal with because it is not easy to scale turbulence 13 unless you have the sort of dimensions of a plant.
14 So the staff position, I think, has been 15 pretty defensible, maybe a bounding position but it is 16 a defensible position.
17 MR. SCOTT: I think you have summarized 18 our concerns very well on that, Dr. Banerjee. This 19 has been attempted, this settlement credit. We have 20 discussed it with the vendor that has attempted to 21 credit it for a matter of years. We are still 22 discussing it with them.
23 We had reached a conclusion that there was 24 not likely a near-term success path in that area for 25 the reasons you cited and that is what led to the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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23 1 genesis of the 10 C.F.R. 50.54(f) approach.
2 We certainly accept that there would be 3 some settlement of debris and the heavier or larger 4 pieces are much more likely to settle than are the 5 smaller pieces or are the fines. The trick of course, 6 as you said, is to not overestimate the amount of 7 settlement that would occur.
8 So the easy way to avoid getting into that 9 is to stir it up and keep the debris in suspension so 10 that the fine debris reaches the strainer but the fine 11 debris turns out to be the most problematic debris for 12 head loss and so the licensees that have a large 13 amount of this material in the plant would like to be 14 able to take credit for settling. And this is a very 15 challenging effort and as we said a few minutes ago 16 for the ZOIs, we can't predict its success at this 17 point but discussions are ongoing.
18 MR. HOTT: In response to industry 19 estimates provided during the April 15th Commission 20 meeting as seen in this first bullet, a maximum of 600 21 rem and an average 200 rem to replace all fibrous 22 insulation. The staff went out to obtain data 23 samples, limited data samples, from some licensees 24 known to have performed insulation change outs. It is 25 also worth noting that some of these estimates are NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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24 1 being, I guess, modified as time goes on to better 2 estimate what those actual doses would be. We heard 3 from one plant two days ago that a 200 rem number is 4 now more likely to be around 80 rem for a full scale 5 replacement.
6 Now our limited survey indicates that 7 while the expected doses would still be significant, 8 five to 44 rem for the doses that were actually 9 received, we think that those doses are not out of 10 line with the safety benefit to be gained by closing 11 the issue. And it is in keeping with exposures 12 experienced for other larger scope maintenance 13 activities inside containment.
14 MEMBER BANERJEE: Is it in line with say 15 upper head and steam generator replacements or are 16 they on the --
17 MR. HOTT: Yes. Steam generator 18 replacement, I think we have seen, typically anywhere 19 from 40 to 60 rem per steam generator.
20 CHAIRMAN ABDEL-KHALIK: How much? I'm 21 sorry.
22 MR. HOTT: Forty to sixty.
23 MEMBER STETKAR: Per steam generator you 24 said?
25 MR. HOTT: Per steam generator.
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25 1 MEMBER STETKAR: So for a loop plant would 2 be, --
3 MR. HOTT: Could be up to 200.
4 MEMBER STETKAR: -- 150 to 200.
5 MEMBER CORRADINI: And from Tuesday I seem 6 to remember that there was a question about you had 7 data on partial removal but not total removal. And so 8 the estimate you just said is kind of extrapolating 9 what is seen for partial change out.
10 MR. SCOTT: That's accurate.
11 MEMBER CORRADINI: Okay.
12 MEMBER RYAN: I did a little bit of an 13 analysis on some of the data that was in our 14 background information. It is about 55 rem per 15 thousand linear feet of material moved. And that is 16 within a factor of about two of the very small data 17 set we had. So, that seemed to me to be somewhere as 18 a reasonable metric to kind of estimate. I would urge 19 that we think about how do we get a metric that will 20 help us --
21 MR. SCOTT: That's a good idea.
22 MEMBER RYAN: -- gauge that a little bit.
23 You know, that is in contrast to the very high 24 numbers we saw from some of the industry estimates up 25 to 600 rem. I just didn't see that supported by the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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26 1 data to date. There may be other plants that will be 2 higher but I would think that it will be helpful to 3 have a metric that people could use. And again, with 4 some error analysis in it as well but to really get at 5 what is the actual best estimate dose at this point.
6 MR. SCOTT: I would like to go back, if I 7 might, just to this last bullet on slide nine that 8 Chris didn't heavily emphasize.
9 We need to be careful not to have this 10 entire discussion in terms of we have got to take all 11 the insulation out. All the fiber has got to go 12 because first of all, there are a number of examples 13 of plants that have shown success in this issue 14 without removing it all. And we don't think the 15 licensees necessarily need to take that approach to 16 assume they are going to take it all out. What we 17 call it is test for success. Run your test with the 18 amount of debris you have, the insulation you have in 19 the plant, run your head loss test and see whether you 20 get a successful result. If you don't, then clean up 21 your test facility, model a smaller amount of 22 insulation in your test and run it again. And keep 23 doing that until you get a successful result. So you 24 find out incrementally how much material you need to 25 take out.
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27 1 So I just would not like the discussion to 2 be solely focused on the worst case, which is we have 3 to take it all out.
4 MEMBER BANERJEE: And you can protect it 5 as well.
6 MR. SCOTT: There is the possibility of 7 banding the material, rather than removing it, which 8 would reduce, though not eliminate the issue of dose.
9 MR. HOTT: Right. And some of that 10 material might not be located within a zone of 11 influence for the worst break location, so it would 12 also not need to be removed in that case.
13 This slide following our meeting two days 14 ago is a summary of the limited survey with linear 15 feet and doses per plant. It is worth noting this is 16 just for insulation replacements. It doesn't take 17 into account past modifications like increasing some 18 strainers. We do not have that data.
19 MEMBER BANERJEE: In the --
20 MR. SCOTT: Nor would that be particularly 21 instructive because a lot of times, the strainers 22 themselves are out in low dose areas.
23 MEMBER BANERJEE: In the NEI letter, which 24 we will talk to them about, obviously, in addition to 25 the dose estimates, which were the numbers you quote, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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28 1 they said that if you proceeded to make these 2 insulation modifications, it would double the cost of 3 what has already been spent, including increasing the 4 area of the strainers. Does that number have, as far 5 as the staff is concerned, have you looked at it and 6 is it true?
7 MR. SCOTT: We have not looked at it.
8 MEMBER BANERJEE: Because that is 9 explicitly in their letter.
10 MR. SCOTT: I understand it is in their 11 letter but we have not evaluated the cost of making 12 these changes. If the licensees have evaluated that 13 and determined that that is an accurate number, then 14 as far as I know, it is.
15 I guess I would doubt that one number fits 16 all for that kind of thing.
17 MEMBER BANERJEE: Right.
18 MR. SCOTT: And again, I would go back to 19 the assumption about you have got to take it all out, 20 versus you might really not have to do that. I don't 21 doubt that it is an expensive modification.
22 MEMBER BANERJEE: Thanks.
23 MR. HOTT: Excellent. All right so by now 24 most of us are familiar with the three options 25 presented in the SECY paper, two which have sub-NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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29 1 options.
2 Just to recap, the first option continues 3 the staff's current approach which involves extensive 4 plant-specific interactions, which end in an 5 integrated review of some performance in an attempt to 6 avoid over conservatism and staff determinations.
7 The sub-options to this first option 8 involve whether the NRC should establish a firm 9 schedule or not. The second option involves a new 10 effort by the staff to provide a risk-informed 11 approach for evaluating the quality potential of 12 larger less-likely LOCAs. And Option 3 would allow 13 leak-before-break credit to sump evaluations.
14 MEMBER BANERJEE: Now let me ask you about 15 Option 1.b. In some sense that is risk-informed, too.
16 Isn't it?
17 MR. HOTT: Yes, it is, in the sense that 18 the staff proposes to require a shorter time frame for 19 resolution for the smaller more likely loss of coolant 20 accidents and a larger or a longer time frame for the 21 larger, less likely LOCAs.
22 MEMBER BANERJEE: So just to clarify.
23 What would be the difference between say Option 1.b 24 and what you call 2.a, which was to increase the 25 guidance that you developed in your Section 6 of the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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30 1 SE to the NEI report of 2004, where you do allow some 2 sort of risk-informed look at the size of the breaks 3 and things? Can you clarify the difference between 4 those two options or will you do it as you go on?
5 MR. HOTT: The existing guidance also, 6 that risk informed guidance in Section 6 also applies 7 only to the larger loss of coolant accidents. It was 8 modeled after the version of 50.46a that was being 9 proposed back in 2004 when the staff issued a safety 10 evaluation.
11 So Option 2.a and 2.b are similar in that 12 they both only apply to the longer or larger break 13 LOCAs which we would be giving a longer time schedule 14 for.
15 MEMBER BANERJEE: Yes but I am asking in 16 comparison to 1.b what is the difference with 2.a?
17 MR. SCOTT: Option 1 is intended to focus 18 on the existing issue resolution process, the plant 19 specific process that we have been going through.
20 Left by itself, Option 1 is stay the course that the 21 staff is already on either with or without a deadline.
22 So the sub-options of Option 1 speak to deadlines for 23 the issue resolution process that we already have in 24 place. Option 2 is the risk-informed part of that.
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31 1 frames for small and large breaks, by implication, we 2 are risk-informing Option 1. But Option 1 is plant-3 specific issue resolution process. Option 2 is risk 4 informing the staff's path forward.
5 MEMBER BANERJEE: I can see the difference 6 between and I don't want to take the time of the 7 committee but between I can see that with 2.b for 8 example, you have got 50.46a there. And therefore for 9 the larger breaks, you can bring in equipment which is 10 not safety grade or whatever to cope with it, which 11 you could not do it under 1.b.
12 MR. SCOTT: You could do it under 1.b but 13 using the existing framework that Chris has talked 14 about, a licensee would need an exemption to use that 15 risk approach and they have chosen not to do that.
16 MEMBER BANERJEE: So I can see the 17 difference between 2.b and 1.b but what I can't see is 18 the difference between 2.a and 1.b. So 2.a is 19 essentially the licensee -- No. It is a serious 20 question because you have another option on the table.
21 Right? And under 2.a, the licensee also has to ask 22 for an exemption rate which they could do under 1.b.
23 MR. SCOTT: It is a matter of emphasis.
24 MEMBER BANERJEE: All right.
25 MR. SCOTT: See, the way we thought about NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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32 1 it and you are correct that there is some parallel 2 there, the way we thought about it, if Option 1 3 continues the way we are going and it continues the 4 state of licensees have chosen not to go to that risk-5 informed method that is available to them. So Option 6 2 says licensees have told us why they haven't done 7 that. And one of the things they recently put on the 8 table was we needed better implementing guidance. So 9 Option 2 would focus if the staff went down that road 10 without going the 50.46a route, then the staff would 11 consider whether additional implementation guidance 12 might be developed to allow licensees to use a method 13 they haven't previously used.
14 MEMBER BANERJEE: So it is the additional 15 guidance part of it.
16 MR. SCOTT: I would say that is accurate, 17 yes.
18 MEMBER BANERJEE: Okay.
19 CHAIRMAN ABDEL-KHALIK: Now if the amount 20 of debris that ultimately would be acceptable is 21 dictated by downstream effects, then this distinction 22 and risk-informing with regard to the size of the 23 break and timing of response is irrelevant.
24 MR. SCOTT: I would say that is not 25 necessarily the case because the amount of debris that NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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33 1 is instrument upon the strainer impacts the amount of 2 debris that goes downstream. So if licensees can use 3 -- For example, if they are able to use 50.46a to 4 revise the assumptions of how much debris is generated 5 and transported, and we described this to the 6 subcommittee as a possibility and we don't know it 7 would play out, but were they able to succeed with 8 that, then they could conclude that less gets into the 9 strainer and less gets into the core.
10 So these issues are all linked, which is 11 why we recommend not trying to extract them and 12 separate them out.
13 MEMBER BANERJEE: Well, I guess Professor 14 Abdel-Khalik is concerned that there could be a 15 situation where more debris gets to the core if less 16 debris gets to the screen because there could be a 17 filtering effect of having more debris, which prevents 18 some of the fine stuff. So there could be an optimum 19 amount, unfortunately.
20 MR. SCOTT: You are correct that making 21 your strainer larger or reducing the chance of having 22 a filtering bed could increase the amount of debris 23 going downstream. Again, the possibility is there.
24 As part of resolving in-vessel effects, 25 the licensees need to evaluate how much gets by the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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34 1 strainer, which will depend on factors such as those 2 you have sited. And again, it all goes back to we 3 need to resolve these issues simultaneously.
4 It is true that a plant could conclude 5 that hey, my straining performance has been shown to 6 be adequate and yet they don't pass the criterion for 7 the in-vessel, in which case they are going to have to 8 make modifications as necessary until both are met; 9 the strainer passes adequate flow and the core passes 10 adequate flow. It has all got to be looked at, 11 basically together.
12 MEMBER ARMIJO: Do we have enough 13 information, experimental information, or analytical 14 information that would allow us to make that 15 determination of what is sufficient with regard to the 16 core or the fuel? You know, it seems if you have 17 large strainers and very little debris, there will not 18 be a filtering bed developed and it will go into the 19 core.
20 MR. SCOTT: Correct.
21 MEMBER ARMIJO: And until you know, 22 exactly how each type of fuel performance, you recall 23 can't determine which option to pick, other than 24 remove it all.
25 MR. SCOTT: Well the option removing it NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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35 1 all, per se, is not here.
2 MEMBER ARMIJO: I know. I am just saying 3 that is going to be --
4 MR. SCOTT: But to answer your --
5 MEMBER ARMIJO: But until you know how 6 much debris, what the lower limit it, then you have 7 got to consider removing it all.
8 MR. SCOTT: Well the way that plays out, 9 is the industry, the PWR's owner's group has sponsored 10 an extensive testing and evaluation program on in-11 vessel effects. And they submitted a topical report 12 to us several years ago that has been under evaluation 13 by the staff and by the ACRS. That document and the 14 program that supports it includes testing of the type 15 you are describing. We are near the endpoint on that.
16 As we mentioned to the subcommittee this 17 week, there is a cross-test and actually the schedule 18 has been moved up. It is now this afternoon. There 19 will be a cross-test to validate whether staff has a 20 concern about whether the two fuel types are 21 exhibiting different behavior which they are because 22 of a design difference or because of testing 23 difference and cross-test is intended to resolve that.
24 And there are one or two more additional 25 tests scheduled for this month. At the end of that, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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36 1 then we believe that the owners will have done an 2 adequate testing campaign to provide the information 3 necessary for the licensees to determine whether they 4 are bounded by this testing that was done from an in-5 vessel effects perspective.
6 MEMBER CORRADINI: We're going to discuss 7 this later anyway. Right?
8 MR. SCOTT: We have a brief for the 9 subcommittee on this October 22nd, the Thermal 10 Hydraulic Subcommittee and then a full committee brief 11 in November on this subject, yes.
12 CHAIRMAN ABDEL-KHALIK: I guess presumably 13 you are providing these options to the Commission.
14 MR. SCOTT: Right.
15 CHAIRMAN ABDEL-KHALIK: And in the absence 16 of the information regarding downstream effects, how 17 can the Commission select from Options 1.b and 2?
18 MR. SCOTT: Well the point I am trying to 19 make is they will have that information. The testing 20 is wrapping up now. I mean, it is not wrapped up as 21 we sit here this morning but within a week or two, I 22 think it will be. And again, unless something 23 surprising, if the cross-test comes up with a 24 surprising result, then we are back to start. Not 25 that we have never had surprising results in GSI-191 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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37 1 before but if the test goes as we expect it will and 2 indicates that there is a design difference between 3 the two fuel types that has led to this problem, I 4 believe the Commission will have that information in 5 front of them. They didn't have it all in the SECY 6 paper but they are going to have it from the staff.
7 MEMBER ARMIJO: Well there clearly are 8 design differences, different fuel assemblies. All of 9 the different fuel manufacturers have their own design 10 for debris filters for burnout debris --
11 MR. SCOTT: Right.
12 MEMBER ARMIJO: -- protecting the fuel.
13 So I would be surprised if there would be some 14 differences. Whether they are server differences --
15 MR. SCOTT: Order of magnitude.
16 MEMBER ARMIJO: They are. Okay.
17 MR. SCOTT: At a certain flow. But then 18 they reduced the flow at our request and the fuel 19 types behaved more similarly. It wasn't an order of 20 magnitude anymore but there is a difference and we 21 will get in detail on October 22nd as to what those 22 differences are.
23 MEMBER BANERJEE: I think we should move 24 on because --
25 MR. SCOTT: We're moving.
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38 1 MR. HOTT: Okay, the staff is recommending 2 a combination of Options 1 and 2, with the risk-3 informed resolution schedule and we are not 4 recommending Option 3, for reasons we are about to 5 discuss.
6 General Design Criterion-4 requires system 7 structures and components be protected from the 8 dynamic effects of the LOCA. However, there is an 9 exception in GDC-4 related to LBB credit, leak-before-10 break. It allows licensees to disregard this design 11 requirement in cases where the probability of rupture 12 is extremely low.
13 This first bullet comes from the statement 14 of considerations for the rule that inserted that 15 exception and it was intended to credit removing pipe 16 with restraints to allow better inspections. You see 17 the sub-bullet there is LBB enhances safety through 18 the removal of barriers to inspection.
19 The next bullet here is that the staff 20 position is leak-before-break credit applies to local 21 effects only and not global dynamic effects.
22 MEMBER BANERJEE: In the document that we 23 have the Federal Register, the Commission notes that 24 there was an inconsistency under Issue 3, correct, in 25 their decision on this? I don't have the piece of NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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39 1 paper in front of me but they explicitly note that 2 there is an inconsistency.
3 MR. HOTT: This is an exception to the 4 requirement to protect it from these dynamic effects.
5 Right.
6 MEMBER BANERJEE: Right.
7 MR. HOTT: And the intent that you would 8 only use that exception in cases where it would 9 enhance safety.
10 MEMBER BANERJEE: Right.
11 MR. HOTT: The staff notes in this slide 12 there are benefits for allowing leak-before-break 13 credit. It would be reduced cost and dose for 14 industry, due to less insulation change outs for other 15 modifications needed to show compliance.
16 Plants that are already effectively done 17 would likely regain operational margin by applying 18 leak-before-break credit and it would simplify GSI-191 19 analysis and staff evaluations of those analyses 20 because for LBB qualified piping, no debris would be 21 assumed to be generated. However, the staff does not 22 believe that these benefits outweigh the costs.
23 Leak-before-break credit for GSI-191 would 24 decrease safety contrary to the intent of GDC-4, which 25 was to increase safety. While there may be a dose NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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40 1 benefit to not performing additional modifications, 2 the staff believes the doses involved are not out of 3 lie with other voluntary activities undertaken by 4 licensees and that the additional dose should be 5 incurred, if necessary, to resolve the issue.
6 Leak-before-break credit would allow large 7 amounts of problematic material to stay in containment 8 without being analyzed. And we also know from testing 9 experience that small amounts of the right debris can 10 result in some failure. Additionally, some failure 11 can cause failure of the ECCS system and the 12 containment spray system.
13 Another issue related with leak-before 14 break credited is associate with welds and Alloy 15 82/182 material known to be susceptible to primary 16 water stress corrosion cracking. The industry has 17 implemented guidance and programs such as augmented 18 examinations. This is an interim response for 19 evaluating PWSCC and standard review plan 3.6.3 does 20 not permit an act of deprivation mechanism like PWSCC.
21 And so the staff does not believe that expanding the 22 scope of GDC-4 until primary water stress corrosion 23 cracking is fully resolved would be appropriate.
24 MR. SCOTT: No question, we don't think it 25 would be appropriate to have any issue not resolved NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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41 1 but this is just another example.
2 MR. HOTT: The last bullet on that 3 previous slide was just to say that there are, you 4 know, not all piping is LBB qualified so licensees 5 would still have to evaluate pipes that were not able 6 to be qualified. And that could be problematic for 7 plants. It might still lead to some modifications, 8 though. Certainly if you are not analyzing the 9 largest pipes in your containment, the scope of those 10 modifications would be less.
11 Policy considerations for leak-before-12 break credit for GSI-191, this credit would be 13 inconsistent with defense-in-depth principles because 14 initiating events should not result in core damage in 15 the absence of additional protection system failures, 16 in the absence of any additional failures. A break in 17 LBB piping could result in some clogging and core 18 damage with no protection system failures.
19 It is also inconsistent with the 20 independence of prevention and mitigation principal 21 because both core cooling and containment spray would 22 be impacted by some clogging.
23 LBB credit would also be inconsistent with 24 the proposed 10 C.F.R. 50.46a risk-informed rule 25 making for ECCS requirements because licensees would NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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42 1 not need to consider how debris generated from breaks 2 in LBB piping would impact ECCS performance.
3 Therefore, licensees would not be required to 4 successfully mitigate the full spectrum of breaks.
5 Policy decision to expand GDC-4 to allow 6 credit for GSI-191 would include a Commission decision 7 that the change one, would not result in an 8 unacceptable reduction in defense-in-depth; it is 9 appropriate given there is no perceived safety 10 benefit; and that it would not result in unintended 11 consequences by setting a precedent for the use of LBB 12 for global effect.
13 Technical basis for expanding GDC-4 in the 14 presence of PWSCC would need to be approved. An 15 application of GDC-4 to GSI-191 would require revising 16 the Statement of Considerations for the rule itself or 17 issuing exemptions.
18 MR. SCOTT: Just a footnote to add here.
19 This issue of global versus local effects, the 20 industry disagrees with our interpretation of that, as 21 you will hear from NEI, I believe, this morning.
22 MR. HOTT: To summarize, the staff does 23 not recommend leak-before-break credit for GSI-191 24 because it would be inconsistent with GDC-4 itself, 25 defense-in-depth principles, and the proposed 50.46a NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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43 1 risk-informed rule making. LBB credit for a global 2 effect might seta precedent for other areas of plant 3 design. And PWSCC concerns for LBB piping have not 4 been fully resolved yet.
5 MEMBER BANERJEE: I am a little puzzled.
6 The Commission says the proposed allows the removal of 7 plant hardware which it is believed negatively affects 8 plant performance, while not affecting emergency core 9 cooling systems containment and environmental 10 qualification of mechanical and electrical equipment.
11 It is a specific safety.
12 So if you do something that effects the 13 performance of the emergency core cooling system, I 14 don't see where it comes from. They would have to 15 change their policy statement.
16 MR. SCOTT: You weren't expecting 17 disagreement from us on that, were you?
18 MEMBER BANERJEE: I'm just saying --
19 MR. SCOTT: You are in agreement.
20 MEMBER BANERJEE: Yes, it is explicitly 21 stated.
22 MR. SCOTT: We agree fully.
23 MEMBER BANERJEE: It would need a policy 24 change.
25 MR. SCOTT: Yes and I think that was the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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44 1 last bullet that Chris had on slide 18. We agree.
2 MR. HOTT: Okay. Let's see. Are we done 3 with this one? We are on 20 now.
4 Okay, this slide highlights what a risk-5 informed resolution of GSI-191 would look like using 6 current staff guidance, which are contained in Reg 7 Guide 1.174. You see here that there are some 8 guidelines here for acceptable delta risk, maintenance 9 of defense-in-depth, safety margins, and a monitoring 10 program.
11 The second part of the slide notes that 12 application of risk-informed methods is difficult for 13 GSI-191 due to a lack of phenomenological modeling for 14 key aspects of the issue.
15 Because of uncertainty in the 16 phenomenological models, a realistic of probability of 17 some clogging is not feasible but bounding estimates 18 can be used. As seen here on this slide, medium 19 breaks, based on their initiating event frequency 20 would not satisfy the delta risk criterion in Reg 21 Guide 1.174.
22 The key point of this slide is that for 23 risk-informed resolution, defense-in-depth philosophy 24 also needs to be met, even if the delta-risk criterion 25 is met. So, for very large breaks where just the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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45 1 initiating event frequency alone meets the delta risk 2 criterion, you still need to meet defense-in-depth.
3 Now it would not be met in the case for 4 this issue because of single, the initiating event by 5 itself could lead to core damage and also effect 6 containment spray.
7 10 C.F.R. 50.46a is the proposed risk-8 informed effort for the ECCS regulations and it 9 represents the current staff thinking. It defines a 10 transition break size, which is the largest LOCA that 11 has to be analyzed as a design basis accident.
12 Typically, for most plants, that is about 14 inches.
13 It is the largest attached pipe to the main coolant 14 system, the main loop system.
15 For breaks above the TBS that are no 16 longer design-based accidents, licensees who credit 17 50.46a if approved can credit offsite power, no single 18 failure, and non-safety equipment. And they also have 19 to perform analysis that they enable changes, have a 20 very small risk impact.
21 For GSI-191, the proposed 50.46a would 22 provide some flexibility for the largest breaks, 23 mainly in the use of, or the potential use of non-24 safety systems. There might also be some limited 25 benefit for debris source term. But as Dr. Banerjee NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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46 1 already mentioned and we talked about, it is highly 2 uncertain how much benefit is to be gained in that 3 area.
4 MEMBER BANERJEE: The first bullet there, 5 under Section 6 with an exemption, can they already do 6 that?
7 MR. SCOTT: Yes, with an exemption and of 8 course they need to show that it works but yes.
9 MEMBER BANERJEE: But they would have to 10 show it works here, too.
11 MR. SCOTT: Right, yes. But I mean, that 12 is not a trivial point because backflush has to be 13 shown to keep the head loss down and also not result 14 in unacceptable downstream effects.
15 MEMBER BANERJEE: Right.
16 MR. SCOTT: So it is far from a certainty 17 to say that if we get backflush, even without an 18 exemption being required, that that will result in 19 success for us. It would be a plant-specific 20 demonstration, which would be complex. Because again, 21 you can't test it in the plant so you would have to 22 somehow test it in your vendor facility which, in the 23 past, has led to all kinds of questions.
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47 1 potentially get some relaxations in the requirements 2 for actually making a demonstration. But how that 3 would pay out is difficult to say.
4 I imagine that the industry will weigh in 5 when they talk to you this morning about how much 6 value they think this would really be to them. We put 7 it on the table as it is available. We don't have 8 high visibility on this point on how we would work 9 with regard to this second bullet. We have already 10 started thinking about it and we are going to engage 11 the industry and see where that will go. We don't 12 know at this point.
13 MEMBER CORRADINI: But just to say it 14 another way as I heard on Tuesday, this beyond the 15 transition break size allows for non-safety grade 16 equipment to be used in some manner where prior this 17 could only have been done by exemption.
18 MR. SCOTT: You are correct.
19 MEMBER CORRADINI: And that is the key 20 change here, if accepted.
21 MR. SCOTT: You could use the non-safety 22 system and potentially you could have a less rigorous 23 analysis to show that it works.
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48 1 there. What do you mean by less rigorous?
2 MR. SCOTT: Right now, when we speak in 3 terms of the amount of debris that is generated and 4 the amount of debris that is transported, because of 5 the lack of realistic models that Chris talked about a 6 few minutes ago, the expectation is that bounding 7 numbers will be used. It is possible that a more best 8 estimate number could be developed. I say possible.
9 We don't know.
10 MEMBER CORRADINI: Okay. Now I get it.
11 Thank you.
12 MR. SCOTT: Okay.
13 CHAIRMAN ABDEL-KHALIK: But a less 14 ambiguous non-safety system perhaps would allow for 15 people to refill the RWST and, therefore, eliminate 16 the need for recirculation altogether.
17 MR. SCOTT: That of course was evaluated 18 and has been implemented by some plants as an interim 19 compensatory measure. It is not without cost, of 20 course. You would have to evaluate for the impact on 21 containment of continuing to --
22 CHAIRMAN ABDEL-KHALIK: Dump water into 23 it.
24 MR. SCOTT: Yes. There is potential 25 there.
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49 1 MR. HOTT: Additionally, that non-safety 2 system might not need to be redundant because there is 3 also the single.
4 MEMBER ARMIJO: Could you move back to 5 slide 23? Now by accepting the transition break size, 6 14-inch pipe or 16, whatever is the largest in a PWR, 7 you basically exempt the big pipes, hot leg and 28-8 inch pipes. But what about those bigger pipes?
9 MR. SCOTT: I wouldn't say you exempt 10 them. They fall under the heading of you still have 11 to evaluate the break in those pipes but under these 12 less rigorous criteria. That is the difference between 13 this and the LBB situation.
14 MEMBER ARMIJO: That is what I was trying 15 to get at. Is there a logic problem between your 16 opposition to LBB and your kind of treating the big 17 pipes as something special that won't break?
18 MR. SCOTT: I wouldn't say there is. What 19 we are saying, our view is the larger pipes are a 20 smaller risk consideration because of their low 21 probability of occurrence but for the reasons that we 22 have documented here, they largely focus on defense-23 in-depth. We don't think it is appropriate to just 24 say well, it is not going to happen so I am not going 25 to evaluate it.
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50 1 We consider okay, it might happen but all 2 breaks must be mitigated and so we are going to 3 address those too. So no, I don't think --
4 MEMBER ARMIJO: Okay. I just wanted to 5 make sure that they weren't being, basically, taken 6 off the table as a problem.
7 MR. SCOTT: Not using the 50.46a approach.
8 With LBB, they would be off the table.
9 MEMBER ARMIJO: No, I understand that.
10 MR. SCOTT: Now licensees of course could 11 choose to do some type of mitigation but it would be 12 completely outside the regulatory framework for LBB as 13 is currently there.
14 MEMBER ARMIJO: Okay.
15 MR. HOTT: The second half of this slide 16 is really just to show that breaks all the way up to 17 the transition break size would still need to be 18 evaluated using traditional methods and might still 19 drive licensees to make some changes. So that is the 20 second part of this slide. Okay, so we are on 25.
21 The final rule for 50.46a is due to the 22 Commission this December. The staff estimates it will 23 take 12 months to generate implementing guidance as 24 soon as the Commission approves the rule. Licensees 25 must demonstrate that the rule applies to them, that NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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51 1 the guidelines in 1.174 are met and that their leak 2 protection system is adequate.
3 One important thing to note here at the 4 bottom of this slide is that injection phase models 5 and analyses are not impacted by 50.46a application to 6 GSI-191.
7 MR. SCOTT: The reason we bring this slide 8 up is there has been a point of view expressed that 9 implementation of 50.46a for this sump issue would be 10 onerous and difficult for licensees. We are trying to 11 make the point here that we don't think it is 12 necessarily going to be all that onerous.
13 MEMBER CORRADINI: It is voluntary.
14 MR. SCOTT: It is voluntary, yes. It 15 would be voluntary.
16 MEMBER CORRADINI: This option would be 17 voluntary.
18 MR. SCOTT: Right.
19 MEMBER CORRADINI: Yes, that is what I 20 wanted to understand.
21 MR. SCOTT: That is true, too.
22 MEMBER SHACK: I mean, if you had an 23 Option 3,a, which is leak-before-break with mitigation 24 demonstrated, these would be very close. The only 25 real difference would be that, in this case, your NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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52 1 applicability for the underlying basis is a more 2 rigorous treatment under 50.46a, whereas in the Option 3 3.a it would be leak-before-break.
4 MEMBER CORRADINI: I don't understand what 5 you just said. I'm sorry.
6 MEMBER SHACK: Well, I mean, you can look 7 at these things as there are sort of two processes 8 that goes on here. One is to decide which class of 9 pipes you consider and in the 50.46a it was decided 10 that leak-before-break was not a sufficient condition 11 for getting you out of a design basis condition. You 12 have a more rigorous treatment of what is and what is 13 not susceptible. So that is one set of differences, 14 if you just looked at them between 2.a and 3.
15 One is you demonstrate your specialness by 16 leak-before-break one in a more rigorous process than 17 the other. The other one is that you have a 18 mitigation requirement in 2. You could modify 3 to 19 require mitigation. At that point, it would look an 20 awful lot like 2.
21 MR. SCOTT: So then you would have to ask 22 yourself, I would think, okay I have this one approach 23 where the NRC staff has worked for a period of about a 24 half dozen years or more to come up with what the 25 right answer looks like. So do we throw that out and NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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53 1 start over?
2 MEMBER SHACK: I don't know that I need a 3 50.46 light. I agree. All I am saying is that once 4 you introduce mitigation, these look --
5 MEMBER CORRADINI: Very similar.
6 MEMBER SHACK: -- very similar.
7 MEMBER CORRADINI: I see. Okay.
8 MEMBER SHACK: So the real question is 9 whether you are going to require a demonstration of 10 mitigation.
11 CHAIRMAN ABDEL-KHALIK: Except that for 12 the leak-before-break, the transition point is up to 13 the applicant as to which pipe size has been qualified 14 for leak before break.
15 MEMBER CORRADINI: But what I am just 16 brainstorming, you could use the criteria from 2 to 17 determine the boundary and demand smaller than 18 something is very deterministic and larger.
19 MR. SCOTT: One more point to make. One 20 of the advantages that the industry has portrayed for 21 case three or LBB is that it would be a fast path to 22 resolution of this issue. The discussion that just 23 occurred leads me to believe it would not be a fast 24 path to resolution.
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54 1 to agreement on what mitigation is.
2 MR. SCOTT: Exactly. And I think that 3 would be --
4 MEMBER SHACK: That would be equally 5 onerous in 2 or 3.a.
6 MR. SCOTT: Yes, and it is almost like 7 starting over on a 50.46a approach. And I just do not 8 believe that would be a quick resolution of GSI-191.
9 MR. RULAND: Mr. Chairman, I would like to 10 just add one thought.
11 CHAIRMAN ABDEL-KHALIK: Yes, sir.
12 MR. RULAND: The reason -- and this is 13 Bill Ruland from staff. The reason we are 14 recommending 50.46a is because it is the considered 15 opinion of a number of ACRS meetings, of several 16 commissions, staff since 2003 about how to risk inform 17 the ECCS acceptance criteria. Whatever that is, the 18 Commission hasn't approved it and we don't know what 19 the Commission's final decision is going to be on 20 that. But what our collective judgment is is this in 21 fact represents the collective judgment of lots of 22 folks in thinking about how to risk inform the ECCS 23 criteria. And that, fundamentally, that is why we are 24 going this way, rather than kind of a band-aid 25 approach using leak-before-break which, in its time, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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55 1 was the appropriate thing to do back in the early 2 '80s. But we believe the current 50.46a, as it is 3 currently proposed, is the right way to go and that is 4 why we are recommending.
5 MR. HOTT: That's a great lead-in, Bill.
6 Thank you.
7 50.46a represents the current staff 8 thinking on risk-informing ECCS requirements. It 9 would provide flexibility for analyzing larger breaks 10 and would not be overly burdensome for licensees to 11 adopt.
12 The current rule-making schedule also 13 supports use for GSI-191, though it is dependent upon 14 Commission approval.
15 MEMBER BANERJEE: So what would this to do 16 closure of this issue? Let's say the Commission 17 approves it, let's assume, within a certain time 18 scale. What is that time scale?
19 MR. SCOTT: Well that would be, it would 20 be early next year. If we get it up to them in 21 December or next year as is proposed and they take a 22 typical amount of time to review it, then you are 23 looking at spring next year.
24 So then at that point, and presumably they 25 will have guided us or directed us on how to make all NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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56 1 this work for 191, in terms of wait on that, allow 2 sufficient time for guidance to be developed. So what 3 we would then do is correspond with the affected 4 licensees. And if this approach is used, we basically 5 say it is time with the deterministic evaluation to 6 show compliance for the breaks below the TBS. And so 7 get back with us within X amount of time as to when 8 you are going to do that. And the industry 9 presentation to the subcommittee indicated no 10 disagreement with that point that we need to go ahead 11 and resolve the smaller breaks deterministically. So 12 we would have a schedule for that that would involve 13 discussions with the staff, I would assume, in 14 calendar year 2011, including potential testing by 15 those plants, additional testing using the staff 16 accepted ZOI and settlement or lack of settlement 17 criteria, followed by two cycles to make any changes 18 needed. That is for the small breaks, any plant 19 changes needed.
20 For the larger breaks, we would probably 21 start a clock in spring 2011 for about one year to 22 allow the implementing guidance to be developed for 23 50.46a to be used for this purpose and then we would 24 have the same sort of thing as I described a minute 25 ago for small breaks with the potential for an NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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57 1 additional round of testing, maybe, maybe not, and the 2 potential for modifications, maybe, maybe not.
3 You know, there is a downside to this for 4 the licensees as well and for us, in that it makes the 5 regulatory framework for resolution more complex 6 because we have divided it into two pieces. It would 7 be voluntary for the licensees to go that approach.
8 They could choose to do the whole thing 9 deterministically up front, which of course the 25, 10 some fraction of that 25 had chosen not to do because 11 of the amount of materials they have in the plant and 12 the concerns about what the demonstration would look 13 like. But they could choose to go that route. They 14 could say okay, the staff has said 50.46a is it. If 15 the commission agrees with that, then that is the way 16 the NRC has come down. And so either 50.46a works for 17 us and we will risk-inform or it is not worth the 18 trouble and we will go ahead and do a deterministic 19 evaluation now.
20 MEMBER BANERJEE: All of this might be 21 purely academic in view of in-vessel effects.
22 MR. SCOTT: But they will know. My point 23 is, they will know. The testing is happening now to 24 support in-vessel effects.
25 MEMBER BANERJEE: Right.
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58 1 MR. SCOTT: They will know how it plays 2 out.
3 MEMBER BANERJEE: Yes but this would 4 basically extend the schedule by about a year, 5 compared to 1.b. Is that what I am hearing?
6 MR. SCOTT: I believe that would be 7 accurate, yes.
8 MEMBER BANERJEE: Compared to 1.b, which 9 also in some sense risk-informs.
10 MR. SCOTT: Wait a minute. Now I am going 11 to get mixed up again.
12 MEMBER BANERJEE: It is when you allow 13 easier and more extended treatment of the large 14 breaks.
15 MR. SCOTT: No. No, it changes the 16 schedule.
17 MEMBER BANERJEE: The schedule. Yes, 18 that's all.
19 MR. SCOTT: In either case, in either case 20 we are assuming development of implementation guidance 21 would be -- No. That is just the risk part of it.
22 MR. RULAND: That is just the risk part of 23 it.
24 MR. SCOTT: Yes, you are correct.
25 MEMBER BANERJEE: Extended by the --
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59 1 MR. RULAND: In 1.b we would be allowing 2 licensees to take advantage of refinements --
3 MR. SCOTT: Correct.
4 MR. RULAND: -- and other additional 5 analyses that may reduce the zone of influence. And 6 where for 1.a we are saying let's go with what we have 7 and do a test and take out the insulation or whatever.
8 MR. SCOTT: But our assumption about that, 9 and you are absolutely correct, Bill, our assumption 10 about 1.b is that to sort out the latest efforts at 11 settlement and ZOI are probably going to take anywhere 12 from a year to a year and a half from right now.
13 MR. RULAND: Right.
14 MEMBER SHACK: And you are asking for a 15 design-basis level of rigor for --
16 MR. SCOTT: Yes.
17 MEMBER SHACK: -- the settlement and the 18 ZOI --
19 MR. RULAND: That is correct.
20 MEMBER SHACK: -- for the 1.b, where you 21 might have a slightly different measure of success 22 under Option 2.
23 MR. RULAND: Yes.
24 MR. SCOTT: Perhaps.
25 MEMBER SHACK: Ah, perhaps.
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60 1 MEMBER BANERJEE: Perhaps.
2 MEMBER SHACK: If you can slice the 3 bologna that thin.
4 MR. SCOTT: That would be interesting.
5 MR. RULAND: That metaphor breaks down at 6 a certain level.
7 MEMBER POWERS: I think that level right 8 there is where it breaks down.
9 MR. RULAND: Yes. But we understand that 10 it is not an easy thing to do.
11 MEMBER BANERJEE: But you can still, under 12 1.b or 2.a get exemptions if you want to go ahead and 13 use some of your non-safety grade equipment.
14 MR. SCOTT: Licensees, of course, could 15 seek exemptions now, could have sought them associated 16 with this issue, but have not. And again, of course 17 the criteria for exemptions are not trivially easy to 18 meet either, which is part of why they probably have 19 not come in with that but they could.
20 MR. RULAND: Generally for exemptions the 21 Commission and the staff have frowned on use of 22 exemptions generally speaking. However, in some 23 specific cases, we have given them. A schedule of 24 exemptions I think for the latest security rules, 25 where licensees really didn't have any choice, they NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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61 1 really couldn't make those modifications.
2 So there are, of course, criteria in 3 50.12, I believe it is, 10 C.F.R. 50.12 for 4 exemptions.
5 MEMBER BANERJEE: For example, but let's 6 be concrete. Say a licensee wanted to replace a check 7 valve and set it up so that he could do backflushing, 8 let's just say. And they came with an exemption. You 9 would, of course, examine it and this that and the 10 other. But in the end, if it worked, if the 11 backflushing worked, and I am talking about not 12 leading to downstream effects which would be 13 deleterious, then that would probably be a way for 14 them to deal with high fiber plants, which might 15 produce the means to reduce. They could ask for that 16 exemption. Whether they would give it or not is a 17 separate issue.
18 MR. SCOTT: Yes, the exemption would be 19 focused on the use of a non-safety system that is non-20 redundant. That sort of thing.
21 MEMBER BANERJEE: Yes, and you would 22 probably have a higher bar for that than under 50.46a 23 is what you are saying.
24 MR. SCOTT: It might get to the same 25 place.
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62 1 MR. SCOTT: I mean, 50.46a removes the 2 need for the exemption.
3 MEMBER BANERJEE: Yes.
4 MR. SCOTT: Now, if somebody came in with, 5 let's just say that 50.46a did not exist, and somebody 6 came in with an exemption request that closely 7 parallels what 50.46a gives them, as Bill Ruland said, 8 that 50.46a represents the current staff thinking 9 about what is appropriate for a risk-informing ECCS.
10 So I mean, they already have a foot in the door with 11 that. So, they might well succeed with it. We have 12 to look at the specifics of what would be applied for.
13 MEMBER BANERJEE: All right. I think we 14 will carry on.
15 MR. SCOTT: Okay.
16 MR. HOTT: This slide is for in-vessel 17 effects. And the staff conclusion is that in-vessel 18 effects should not be separated from a resolution of 19 GSI-191. I think we discussed the time frames noted 20 on this slide.
21 MEMBER BANERJEE: I am a little concerned 22 about this cross test. Maybe you can clarify this.
23 Even if the cross test shows, let's say, 24 that -- Let's say in the cross test both vendors on 25 this equipment that is being used to do the test have NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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63 1 similar behavior, it is still an issue as to why the 2 other piece of equipment or the test grid showed such 3 a difference.
4 MR. SCOTT: You have very well described, 5 from our perspective, the worst-case outcome of the 6 cross test. Remember that what we are talking about 7 here is one vendor's fuel in their own test rig showed 8 a factor of ten greater propensity to clog than did 9 the other one.
10 So we reviewed extensively and observed 11 the testing. We reviewed the test procedure. We 12 looked at the test rigs at the two vendors, found them 13 to be substantially identical and could not attribute 14 the difference in observed behavior to a test 15 difference between the two test facilities.
16 However, wanting a larger degree of 17 assurance because of our past track record with GSI-18 191 of unexpected results, the staff has requested 19 and, after due deliberation, the industry has agreed 20 to perform a cross test where they are taking today, 21 this afternoon, they are taking an AREVA test 22 assembly, putting it in the Westinghouse facility and 23 running the same kind of test that Westinghouse ran on 24 Westinghouse's fuel.
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64 1 staff's view, is that in all likelihood, the 2 difference in behavior is in fact due to a design 3 difference. In one case the debris tends to 4 accumulate on the first grid. In the other case, it 5 tends to distribute over more grids, which then 6 results in not as impervious a bed.
7 So the expectation is that the cross test 8 will show that the AREVA fuel behaves in the 9 Westinghouse facility as it did in the AREVA facility.
10 That is a good result from the standpoint of 11 certainty in moving on on this issue.
12 If on the other hand, the AREVA fuel 13 behaves more like the Westinghouse fuel and 14 Westinghouse facility, which is what you referred to, 15 we are back to start from the perspective that we 16 would not understand why that had occurred. We would 17 have to figure it out.
18 MEMBER ARMIJO: Mike, just on the issue of 19 those tests, whether it is in the AREVA loops or the 20 Westinghouse loops, how reproducible are these tests?
21 You know, just do the same test over two or three 22 times. Do you get a lot of variability in either of 23 these test loops? You know, do you have a test 24 variability problem as opposed to a real design 25 difference?
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65 1 MR. SCOTT: We have not observed a 2 variability problem. There is, of course, always 3 variability.
4 MEMBER ARMIJO: Yes, but -- I know this 5 is complicated.
6 MR. SCOTT: There have been a significant 7 number of tests and the trend is relatively clear.
8 MEMBER ARMIJO: So you are not concerned 9 about reproducibility under identical conditions --
10 MR. SCOTT: No. No, we are not.
11 MEMBER ARMIJO: -- in either of these 12 tests.
13 MR. SCOTT: That is correct. We have 14 asked them to do additional testing to make sure that 15 we can accept the results.
16 MEMBER BANERJEE: I think we should move 17 on because we need to wrap up in about ten minutes.
18 MR. HOTT: Recommended approach by the 19 staff provides near-term resolution for more 20 significant smaller LOCAs, while allowing additional 21 time for industry to justify evaluation refinements 22 like zone of influence reductions and settling credit.
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66 1 both in the implementation schedule and the analysis 2 of larger, less-likely LOCAs.
3 The staff would continue the holistic 4 review process that has been successful for about two-5 thirds of all PWRs, which the balance has known 6 conservatisms against uncertainties to avoid over-7 conservatism.
8 The implementation schedule also takes 9 into account the amount of effort and planning 10 necessary for licensees to plan and execute additional 11 modifications, if needed, using ALARA methods to 12 reduce radiation exposures.
13 The staff recommends continuing the 14 integrated review process for remaining plants and 15 setting a near-term resolution schedule for smaller 16 LOCAs and a longer-term resolution schedule for larger 17 LOCAs. The staff would revisit risk tools for 18 evaluating larger breaks consistent with the longer 19 schedule.
20 Staff thinks in-vessel effects should be 21 resolved as part of GSI-191 and the staff does not 22 recommend expanding leak-before-break credit. Thank 23 you.
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67 1 comment about cost. We did get direction from the 2 Commission to go back to the CRGR, Committee to Review 3 Generic Requirements, to revisit whether the various 4 exceptions to the backfit rule continue to apply, 5 which is, of course, occasioned by cost 6 considerations, among other things. And the CRGR 7 concluded that the staff can and should proceed on 8 this issue, using the compliance exception to the 9 backfit rule, which means that we are not doing a 10 detailed cost-benefit analysis to support this issue 11 resolution because it is a compliance issue and is a 12 compliance issue with an important safety-related 13 rule. So that is why we haven't gone down the cost 14 route.
15 MEMBER BANERJEE: Okay, that is fair 16 enough. And that was in the SRM.
17 MR. SCOTT: It was in the SRM to do it and 18 it is addressed in the SECY paper.
19 MEMBER BANERJEE: Yes. Okay, I think if 20 the Committee has any further questions, we have until 21 10:30. So now we are going to have NEI.
22 MR. RULAND: I'm sorry, Mr. Chairman, 23 MEMBER BANERJEE: Yes.
24 MR. RULAND: Could I just make one final 25 comment?
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68 1 MEMBER BANERJEE: Go ahead.
2 MR. RULAND: We appreciate the Committee's 3 really long-standing comments about this issue. This 4 has been a long, arduous path to approach resolution 5 of this matter and I just wanted to acknowledge both 6 the Committee's interest in this matter and, frankly, 7 I want to acknowledge the cooperation, really, we have 8 had with the long technical discussions with both 9 licensees and NEI.
10 While we disagree about how this ought to 11 be resolved, both parties want to see this resolved in 12 as timely a manner as possible. So, we really have 13 had extraordinary cooperation from the industry. If 14 you think about the long phone calls that really the 15 multi-million dollar modifications licensees have 16 done, with really no what I would say overt regulatory 17 pushback. They have really debated us and talked to 18 us, really on a technical level. And really the 19 cooperation we have had, in spite of our disagreements 20 has been extraordinary. So I just wanted to 21 acknowledge that. Thank you.
22 MEMBER BANERJEE: Thank you, Bill and 23 thanks, Mike and Chris for a very illuminating 24 presentation. You will be sticking around.
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69 1 from NEI to present the NEI options to us and their 2 views on this. John are you around?
3 MR. BUTLER: Yes.
4 MEMBER BANERJEE: You are going to make 5 the presentation and --
6 MR. BUTLER: Tony's going to make a couple 7 of introductory remarks.
8 MEMBER BANERJEE: Do we have STP today as 9 well or not?
10 MR. BUTLER: No.
11 MEMBER BANERJEE: Okay.
12 MR. PIETRANGELO: Well good morning. Some 13 of you were actually on the committee when we started 14 working on this issue. I think Dr. Bonaca down here 15 and Dana and --
16 MEMBER POWERS: Why is it Dr. Bonaca 17 instead of Dana?
18 MR. PIETRANGELO: Dr. Powers.
19 We have been working on this as an 20 industry for a long time. This is not just an NEI 21 presentation. This is an industry presentation. Make 22 no mistake about that.
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70 1 a great deal of coordination and interchange between 2 the industry and the staff, PWR owners groups, the 3 individual utilities.
4 The reason I wanted to come and say a few 5 remarks here is we are down to decision points with 6 this issue that are very important, okay, and just to 7 provide kind of an overall perspective on this.
8 Major mods have been made to each 9 facility, each PWR in the United states, beyond just 10 enlarging the strainers. There has been operational 11 changes. There has been other hardware changes for 12 downstream effects on valves. There has been buffer 13 changes and there has been mitigative actions put in 14 place to address this issue, that were not mentioned 15 in the application of LBB before.
16 So a lot has been done on this already.
17 And now we are at a point where what else do we need 18 to do with this issue. And what I come back to is 19 this issue is a commercial for risk-informed 20 regulation. How long do you want to taste the tails 21 of the distributions on what might happen? Where does 22 reasonable assurance stop an absolute guaranteed start 23 in the probabilistic world? That is the policy 24 question on the table. Do we continue to chase this 25 at the expense of other issues? This is not unlimited NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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71 1 resources that are expended by either the agency or 2 the industry with a focus on safety. I have got to 3 tell you, there is a lot better things we could do 4 with the money that could be used to remove all this 5 insulation and soak up dose than doing that.
6 So that is where we are at with this 7 issue. I think it has been --
8 MEMBER POWERS: Let me understand. There 9 is something that you can do that is better than 10 assuring that you don't melt down the core of the 11 plant?
12 MR. PIETRANGELO: I think there are 13 equipment issues that are always out there and the 14 material condition of the plant. That all contributes 15 to that, Dr. Powers.
16 MEMBER POWERS: Containment over pressure, 17 credit, something like that.
18 MR. PIETRANGELO: There are other issues.
19 MEMBER POWERS: Yes, there are other 20 things to use but this is a non-trivial issue. So 21 let's not downplay the importance of the issue that 22 you are addressing.
23 MR. PIETRANGELO: And I would assert that 24 our actions demonstrate this as a non-trivial issue 25 over the last seven years.
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72 1 MEMBER POWERS: Your actions demonstrate 2 that. It is your words I am a little worried about 3 here.
4 MR. PIETRANGELO: Well I am worried about 5 additional beyond what we have already done, based on 6 what. Okay?
7 I mean, we knew 25 years ago that the 8 probability of breaks for large pipes was 9 infinitesimally small. That was corroborated through 10 extensive --
11 MEMBER POWERS: So you are finding here 12 that even 14 inch pipes connected to those large pipes 13 breaking can cause us a headache.
14 MR. PIETRANGELO: Absolutely and those 15 would still be included. That is why I am saying 16 there is enough conservatism remaining to deal with 17 this issue. Okay? But again, we are going to impose 18 actual dose here. We are going to worry about some 19 postulated dose later. Is that the right thing to do?
20 Again, where does reasonable assurance 21 end? There are other threats to core damage I would 22 argue, that are much more significant than what we are 23 chasing here with this.
24 MEMBER POWERS: Well, good. I would like 25 to get that list.
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73 1 MR. PIETRANGELO: So, I mean, that is the 2 perspective I want to provide. It is not that -- We 3 have cooperated with the staff. There have been 4 disagreements on the levels of conservatism and the 5 assumptions in the analysis and the testing we have 6 done. Okay?
7 But at what point? I mean, we would 8 recommend all three of the options. You should risk-9 inform not only the time it takes, focus on the small 10 breaks first but I think Dr. Shack pointed out there 11 is not much difference between Option 3 and Option 12 2.a, except for the mitigation piece. It is founded 13 on the same --
14 MEMBER SHACK: That is my question to you.
15 I mean, do you find it acceptable not to be able to 16 mitigate a large break? You know, design basis aside, 17 to me the real question is as we do 50.46a as Bill was 18 pointing out, the whole concern all along has been how 19 much assurance of mitigation do we provide for that 20 largest break, even if we make it a non-design basis 21 accident.
22 And I look at Option 3 as the way the 23 staff has presented it and the way you have presented 24 it, as a no-mitigation option. And if you do 25 introduce mitigation with some confidence, then it NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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74 1 looks an awful lot like Option 2 and, you know, why do 2 I need to make --
3 MR. PIETRANGELO: You are absolutely 4 right.
5 MEMBER SHACK: -- a different set?
6 MR. PIETRANGELO: Yes, so --
7 MEMBER SHACK: So I mean, all to me the 8 objections to GD application GDC-4 and adoption of 9 50.46a make any sense. Of course they are almost 10 exactly the same thing and they are based on the same 11 risk insights.
12 MEMBER CORRADINI: But then just to get 13 back to his question, so you do support Option, I get 14 all these options mixed up, --
15 MEMBER SHACK: 2.b.
16 MEMBER CORRADINI: You do support applying 17 GDC-4 with mitigation.
18 MR. PIETRANGELO: You could. In fact, you 19 could look at the analyses --
20 MEMBER CORRADINI: Not could. You do 21 support or don't support. It's a yes or no here.
22 MEMBER SHACK: Yes. Do we look for a 23 reasonable assurance of a capability to mitigate large 24 breaks under your version of Option 3 --
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75 1 so unlikely we don't worry about it?
2 MEMBER CORRADINI: Right. That is what, I 3 guess, we are trying to understand.
4 MR. BUTLER: I will say we agree but the 5 qualifier I will add is what do we mean by 6 demonstrating mitigation capability. And when we get 7 into the discussion of 50.46a and what it means in 8 that context, I will point out the problem we see with 9 50.46a and the difficulty in doing that.
10 We have no problem with the concept of 11 demonstrating mitigation capability. How do you do 12 that in the context of 50.46a? How do you do that in 13 the context of GDC-4 and LBB is what needs to be 14 discussed.
15 MEMBER CORRADINI: Okay. That's fine.
16 MR. PIETRANGELO: Why don't we let John do 17 the specifics and then we can come back to this at the 18 end.
19 MR. BUTLER: All right. Thank you. My 20 name is John Butler of NEI. I gave a little bit 21 longer version of this presentation to the 22 subcommittee and I am going to try my best to 23 abbreviate. So I have cut out a number of slides, a 24 number of points that I felt were necessary for the 25 subcommittee. It would have been nice to have given a NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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76 1 longer version here but time is what it is.
2 This slides shows the three options that 3 are presented in the SECY paper. I will not go 4 through those in any kind of detail. I am presuming 5 that everybody is fully aware of those.
6 The staff recommendation in the SECY paper 7 was, in sort, Option 1.b in combination with Option 2.
8 I think the key point on this slide is that the 9 industry recommendation is generally in line with 10 that, in that we recommend Option 1.b in combination 11 with either Options 2 or Options 3. We feel it is 12 appropriate to bring the risk-informed options, make 13 them all available to plants to use. And I will get 14 into this in a little bit more detail but which option 15 a particular licensee chooses will vary. There are 16 particular drivers for using 50.46a for a particular 17 licensee that are unrelated to GSI-191.
18 Use of Option 3 LBB may be of particular 19 interest to someone who has already closed the issue 20 but feels that their margin, because of the way that 21 they have, what they have had to do to close this 22 issue, the operability margin is somewhat compressed 23 and they would like a way to kind of regain some of 24 that margin.
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77 1 these options. So in general, I think all the options 2 should be pursued and I will get through what I see as 3 some of the concerns that we have with some of the 4 options that are being proposed by the staff.
5 MEMBER ARMIJO: John, as you go through 6 this thing, would you try and explain exactly how you 7 would use or propose to use Option 3? Because since 8 you are in agreement with the staff on Option 1.b and 9 Option 2 at the top level but where the difference is 10 is the industry's view that Option 3 is, you know, 11 bad. I would like to know exactly what you would 12 propose to do.
13 MR. BUTLER: All right. Well, let me pan 14 Option 2 first, before I --
15 MEMBER ARMIJO: Okay.
16 MR. BUTLER: So again, we recommend 17 Options 1.b in combination with the risk-informed 18 options, which are both Options 2 and Options 3.
19 I will emphasize this. We agree with the 20 staff in that the more likely spectrum of breaks, the 21 small breaks, but it is really small and medium breaks 22 and some large breaks, should be met using the 23 deterministic criteria that the staff finds 24 acceptable.
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78 1 the schedule for doing that should try to accommodate 2 some of the ongoing activities, which include the in-3 vessel effects testing and some credit and strainer 4 testing and refined ZOI values, if it can. You know, 5 but the intent is these are ongoing test programs that 6 would benefit the activities to demonstrate compliance 7 for the smaller breaks.
8 Now the risk-informed options, we think 9 they all should be pursued. The advantages and 10 disadvantages of each of the options vary and I will 11 get into that in a little bit of detail.
12 Option 2.a which was an expansion of the 13 Section 6 guidance IN 04-07 share some of the 14 disadvantages we see with 50.46a in that it is 15 difficult to define what relaxations you would be 16 allowed to employ beyond what you are required to do 17 for the small breaks.
18 I have characterized it as unless you can 19 have separation in your analysis methods for the 20 larger breaks from what you apply to the smaller 21 breaks, there is really no advantage to pursuing that 22 option.
23 Section 6, without an exemption really 24 relies upon using some relaxation on the criteria of 25 the methods. Primarily right now, that is limited to NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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79 1 more realistic treatment of MPSH calculations. There 2 is really no reduction in how you treat any of the 3 debris generation transport, strainer testing, 4 downstream effects. There is no relaxation in those 5 areas to speak of.
6 So that is why the industry hasn't pursued 7 this because the lack of that relaxation and the 8 difficulty, perceived difficulty in applying any kind 9 of exemptions to the current regulations.
10 CHAIRMAN ABDEL-KHALIK: But that may not 11 be the same for 50.46a.
12 MR. PIETRANGELO: Yes, it would.
13 MR. BUTLER: It would. It would. And 14 this is not the staff's fault but the difficulty we 15 have with any kind of relaxation on the methods is you 16 really should have some basis to quantify what that 17 relaxation should be. And at present, all the testing 18 and evaluations have been done on a bounding set of 19 conditions to support the deterministic methods.
20 So you know what that bounding set of 21 conditions and phenomena give you, the level of 22 conservatism will continue to be argued between the 23 industry and the NRC but it is agreed that is a 24 conservative bounding set of conditions. Now when you 25 relax that, how do you quantify what that relaxation NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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80 1 should be, without a lot of additional testing and 2 research?
3 So you know, --
4 MEMBER BANERJEE: The problem you are 5 facing is there is no best estimate --
6 MR. BUTLER: Correct.
7 MEMBER BANERJEE: -- method here. Because 8 the phenomena are complex and we stopped doing 9 research quite a long time ago.
10 MR. BUTLER: Right. And it is more than, 11 you know, you are trying to bound a range of designs 12 out there. Even within a particular design, you are 13 trying to bound a range of potential conditions and 14 you are trying to bound a time scale where you are 15 trying to compress it down to a single test and you 16 are trying to avoid performing dozens of tests because 17 these are expensive tests. So you again bound a range 18 of conditions.
19 So we have imposed upon ourselves in the 20 testing a level of conservatism that could be relaxed 21 if you were to go back and do a lot more testing.
22 But we are where we are.
23 MEMBER CORRADINI: I appreciate what you 24 are saying but I guess I am still back with Sanjoy.
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81 1 estimate, then all you can do is look at the bound and 2 by either a combination of analysis with experiment or 3 just pure empirical experimentation, reduce that 4 bound.
5 So jumping to Option 3 doesn't get you 6 anything, other than saying I can't do it so I want 7 this approach out. And I don't see how that benefits 8 safety. That is where I am struggling with what I 9 heard by phone conference on Tuesday.
10 MR. BUTLER: When we get to the discussion 11 of Option 3, I will hopefully address that point.
12 MEMBER BANERJEE: Isn't in any case sort 13 of thing that we do for say loss of coolant accidents 14 for the clad temperatures where we have best estimate 15 methods of uncertainty. This is also a very complex 16 phenomena. It takes 20, 25 years to reach that point 17 but we reached that point.
18 MEMBER CORRADINI: And one hell of a lot 19 of experimentation.
20 MEMBER BANERJEE: Yes but we are there.
21 So it can be done but it just takes a lot of work.
22 MR. BUTLER: Right. I think I covered 23 this. I mean, part of the difficulty with Section 6, 24 if we were trying to use it, it would be an attempt 25 to, I guess, provide a little bit more refinement of NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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82 1 it or maybe even try to provide that separation that 2 we are looking for but it will take time and I am 3 skeptical of how successful we will be in actually 4 getting the true separation in the criteria.
5 I am going to be truthful. We like 50.46a 6 but it was developed from the start to be applied to 7 in-vessel traditional LOCA analysis. That is where 8 you get the benefit. That is where the value for this 9 comes from. It was never looked at as a means to 10 risk-inform the long-term cooling criteria of 50.46.
11 So there are difficulties in trying to force fit its 12 application to resolve GSI-191. It was not intended 13 there. The benefit you get in applying to it just a 14 GSI-191 we see as somewhat problematic.
15 However, there are values with 50.46a in 16 the broader sense for 50.46. Plants who see that 17 value may have a desire to pursue it broadly and apply 18 it to GSI-191 as part of their overall application of 19 50.46a.
20 MEMBER BLEY: What do you think might have 21 been different in the way it evolved if it had 22 originally been aimed at GSI-191?
23 MR. BUTLER: If it had specifically been 24 aimed at GSI-191? I don't know.
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83 1 I am a little stuck with where you started on this 2 one.
3 MR. BUTLER: The acceptance criteria we 4 are trying to meet is demonstrated long-term cooling.
5 That is a performance-based criteria. It would be in 6 how you meet that or how you demonstrate that 7 criterion but specifically what that would mean in 8 terms of regulations it is hard to say.
9 The other point here is that there is an 10 uncertainty in how long it would take to develop the 11 implementation guidance for 50.46a in general. And 12 the specific GSI-191 guidance, that is going to take 13 some time. I am not as optimistic as the staff in the 14 schedule required to do that.
15 Option 3, we see this as a means to 16 provide, to address the unlikely breaks in a risk-17 informed matter that is consistent with the current 18 regulations.
19 The point raised earlier on reduction in 20 defense-in-depth, there are ways to address that.
21 Plants have performed a number of actions, starting 22 with the response to the Bulletin 2003-01 to provide 23 means to address blockages should it occur that ranges 24 from simple actions of starting to refill their RWST 25 to provide a capability to continue that injection NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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84 1 source, should the recirculation capability be 2 blocked.
3 Plants have investigated what they have in 4 terms of a backflush capability. And a number of them 5 have a capability to either through a pumped backflush 6 or through a gravity drain from the RWST to put some 7 backflush capability on their strainers. The 8 difficulty will be in what it means to demonstrate 9 that capability.
10 What I am fearful of is that in a 50.46a 11 fashion in demonstrating that backflush capability, we 12 will be trying to bound the worst case of the worst 13 case of the worst case. Now I have no doubts that you 14 can lock up a strainer so hard that any backflush 15 capability would fail. How likely it would be to lock 16 it up in that condition is probably infinitesimally 17 small but it is our tendency in GSI-191 to bound all 18 perceived combinations of conditions and that is I am 19 afraid that is where we would go. So the difficulty 20 with demonstrating a backflush capability I see as 21 problematic.
22 But there is a backflush capability that 23 exists at a number of plants. Those plants that don't 24 have it currently because of a check valve, there are 25 capabilities to modify the design to allow some NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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85 1 backflush capability. But again, my concern is 2 demonstrating that. There needs to be some latitude 3 given to demonstrating that capability or the 4 viability of that capability --
5 MEMBER CORRADINI: So can I ask --
6 MR. BUTLER: -- to cover some of the more 7 realistic scenarios.
8 MEMBER CORRADINI: Can I just go back? So 9 leave that example but you had the example of the 10 RWST. How is that no different than Option 2? Which 11 is I have some sort of break size that is relatively 12 deterministic. Now at larger break sizes, I allow for 13 other actions that would, as Said was suggesting would 14 be that I refill the RWST. So it is in the framework 15 of Option 2 and it is a potential way to mitigate. It 16 is a different way but it still a potential way.
17 Once, I guess I am back to the way Dr.
18 Shack suggested it. Once you cross that boundary and 19 say if I am going to create latitude but I will 20 mitigate, then they get very fuzzy. So I think all 21 your suggestions with the RWST is fitting within 22 Option 2. That is what I am struggling with.
23 MR. BUTLER: I guess my concern, main 24 concern with that -- You are right. There is 25 demonstrating litigation capability can come in NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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86 1 different forms and different sizes.
2 What I am concerned with within the 3 framework of 50.46a I think there is going to be a 4 high bar set on how you demonstrate mitigation 5 capability. It is going to effectively be a design 6 basis analysis for the beyond design basis events.
7 CHAIRMAN ABDEL-KHALIK: But that is not 8 the intent.
9 MEMBER BANERJEE: It could be a best 10 estimate for some certainty.
11 MEMBER CORRADINI: You would just have to, 12 to follow that point, at least my impression was, 13 staff would be totally fine with a best estimate but 14 you would have to show by a combination of experiment 15 analysis that it is a best estimate and know the 16 uncertainty.
17 MEMBER BANERJEE: Otherwise, what can you 18 do?
19 MEMBER CORRADINI: Right. I mean, that is 20 -- unless I misunderstand.
21 MEMBER BANERJEE: There are options.
22 MEMBER CORRADINI: Unless I am 23 misunderstanding the staff's point.
24 MR. BUTLER: The measures you would take 25 to provide some mitigation capability are the same NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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87 1 between Options 2 and 3. The difference is probably 2 going to be in that level of rigor that would be 3 required to support it.
4 CHAIRMAN ABDEL-KHALIK: Wait a minute.
5 Are you now saying that you have sort of gone along 6 with the idea of having mitigation capabilities 7 associated with Option 3?
8 MR. BUTLER: I have no problem with that, 9 yes. Now how each individual plant --
10 CHAIRMAN ABDEL-KHALIK: So there is 11 essentially very limited distinction between Option 12 3.a and Option 2.b, except for the break size at which 13 you would provide these mitigation capabilities.
14 MR. BUTLER: Well there are a number of 15 differences in how you would apply those two options.
16 Yes, I don't think that you would propose, for 17 example, to put the equipment in the tech specs. You 18 might not agree to the 14 days cumulative. There is a 19 lot more that you --
20 MEMBER SHACK: I think that is my point is 21 that if you are going to agree to mitigation 22 capabilities in Option 3, then there has to be some 23 set of controls. And again, as we said, we have 24 argued this over for 50.46a for umpteen years. I 25 don't know that we want to reargue it again --
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88 1 CHAIRMAN ABDEL-KHALIK: For GDC-4.
2 MEMBER SHACK: -- for, as I say, a 50.46a 3 light just for, you know, some recirculation. You 4 know, if we are going to agree that we are going to 5 have mitigation, then it really ought to look like 6 50.46a would be my, you know, that is --
7 MR. BUTLER: Well again, how you 8 demonstrate that mitigation capability or demonstrate 9 the effectiveness is really probably the key 10 distinction between what we are talking about and what 11 Option 3 with some mitigation capability and Option 2.
12 Currently plants actions they take to 13 refill the RWST, that is all proceduralized. You 14 know, they will follow the procedures. Does it need 15 to be in tech specs? I don't think so. My view would 16 be that having it proceduralized and having the 17 capability demonstrates that they have an ability to 18 implement those procedures under the right conditions 19 is appropriate for this level of risk that we are 20 talking about.
21 MR. PIETRANGELO: I would also argue that 22 if you accept it will leak before it will break, I 23 would argue that you are bounded by other piping you 24 are going to consider with a spherical ZOI, than you 25 would for that leak from the big breaks, not the 32-NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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89 1 inch double-ended. I think that is the difference.
2 You are bounded by a different set. You either accept 3 it is going to leak before it breaks or you don't.
4 MEMBER SHACK: But then you are giving up 5 the mitigation for the big break.
6 MR. PIETRANGELO: No, I am saying we have 7 already taken other actions to mitigate.
8 MEMBER CORRADINI: What are those?
9 MR. PIETRANGELO: When you get to that 10 independence versus, the global versus local effect, 11 John has gone through some of the other mitigative 12 strategies we have already put in place that we would 13 like to get credit for in this. It is not like there 14 is no mitigation whatsoever. But I would argue that 15 you are really trying, by risk-informing it, you are 16 trying to focus more on what is more likely to happen 17 that I think would bound the larger piping, if you 18 accept it is going to leak before it breaks. And it 19 could be a pretty big leak and still be bounded by 20 some of that other pipe.
21 MR. BUTLER: Part of the discussion at 22 this meeting I have avoided --
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90 1 down.
2 MR. PIETRANGELO: Right. We have done 3 leakage monitoring all over the place. We have 4 qualified all the piping. We have enhanced our 5 efforts on PWSCC and we are not getting any credit for 6 it in this issue.
7 MR. BUTLER: I've avoided in all our 8 discussions getting into the arguments that we have 9 continued to have with staff on the level of 10 conservatism in our methods. I have brought with me 11 but I didn't bring to the table, you know, the 12 stainless steel jacketing that is on the NUKON 13 insulation, ZOIs for NUKON insulation give no credit 14 for the stainless steel jacketing on the insulation.
15 Now the reason for that is, you know, I understand is 16 because you can orient that insulation, that jacketing 17 which is hefty jacketing but you can orient where the 18 seam can be caught by a jet and blown off. But it is, 19 you know, what you are assuming now that all breaks, 20 all seams would be pointed exactly to the jet to where 21 they are all going to be blown off.
22 You know, my expectation is that that is 23 not going to be the case for any postulated breaks.
24 So there are conservatisms that we know are out there 25 that can't be quantified. So there is a level of NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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91 1 reasonableness that needs to be brought into this at 2 some point as to how you treat the highly unlikely 3 leak-before-breaks. But let me continue.
4 You know, the staff had five or six slides 5 on why they don't like GDC-4 and I will avoid quoting 6 Shakespeare about protesting too much but you know, 7 the rule is --
8 MEMBER POWERS: You should never avoid 9 William Shakespeare.
10 MR. BUTLER: Some key points --
11 MEMBER BANERJEE: There is also making 12 assurance doubly sure, if you want to quote 13 Shakespeare.
14 MR. BUTLER: There is no doubt that debris 15 generation is a direct consequence of the local 16 dynamic effect. Now where the staff seemed to point 17 to is that they feel that it is also a global effect 18 or has a global effect. I would point you back to the 19 rule itself and in the statements of consideration of 20 where they specifically identify what are considered 21 local dynamic effects and this qualifies, and 22 specifically identify what they mean by the global 23 phenomenon, global effects that they retain with the 24 rule change. And those are identified as it relates 25 to ECCS, the ECCS flow, you know, capability, heat NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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92 1 removal capability of ECCS for containment pressure at 2 lower pressure temperature, EQ, its humidity. These 3 are identified.
4 CHAIRMAN ABDEL-KHALIK: This argument of 5 local versus global is, in my view, just a red 6 herring. The main point is whether this is consistent 7 with the intent of GDC-4, which is enhancement of 8 safety.
9 MR. BUTLER: And I am going to get to that 10 point.
11 Now the enhancement of safety coming from 12 the GDC-4 rule was that it allowed the removal of the 13 pipe whip restraints impingement shields. In doing 14 so, they allowed that by excluding the local dynamic 15 effects. So the safety benefit came from allowing 16 removal of those materials and allowing increased 17 inspection. They avoided significant worker dose from 18 those inspections and there is a perceived safety 19 benefit from increasing the inspections. All right?
20 That is a safety benefit. It has never been a 21 requirement to demonstrate additional safety benefit 22 in applying GDC-4 rule. That has not been the case in 23 applying it to -- in any case. I mean, it has not 24 been part of the review criteria to demonstrate a 25 safety benefit for an application of the rule. The NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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93 1 safety benefit came from the rule itself that allowed 2 you to exclude those local dynamic effects and remove 3 the pipe whip restraints.
4 CHAIRMAN ABDEL-KHALIK: With all due 5 respect, that is a lawyer's interpretation of words.
6 MR. BUTLER: It is the reality. Was there 7 a safety benefit in allowing a plant to exclude local 8 dynamic effects for breaks impinging upon their 9 strainer? I will argue that no there is not a safety 10 benefit. Does it have an impact on ECCS? Yes, it has 11 an impact on ECCS.
12 But as was pointed out earlier, there is 13 an acknowledged inconsistency in the rule in that it 14 has an effect on ECCS in that you're excluding local 15 dynamic effects which can impact ECCS. That is 16 acknowledged in the rule.
17 MEMBER SHACK: But that was one of the 18 reasons that it was sort of acceptable is that it was 19 only locally effective. You know, I think the staff's 20 argument is, okay, maybe if you were wrong, you know, 21 and the pipe whip did take out a piece of equipment, 22 it took out a local piece of equipment. In this case 23 when we blocked the sump, it doesn't matter how much 24 more equipment you have got left. You know, you are 25 dog meat.
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94 1 MR. BUTLER: Okay, the break that directly 2 impinges on the strainer takes out the strainer. A 3 pipe whip that takes out a train of ECCS, and that was 4 one of the scenarios that was considered, it takes out 5 a train of ECCS, the other train is out because of 6 your single failure criterion.
7 MEMBER SHACK: No, I agree. In a design -
8 basis world, none of this works. We are at a design-9 basis place.
10 MR. BUTLER: LBB is applied for in-vessel 11 in-core and so there is a single point, a single 12 failure point there. So it is clearly a point to be 13 argued between the staff and the industry.
14 So, I guess getting down to the bottom 15 line is has the safety significance of GSI-191 been 16 adequately addressed? We feel that through the design 17 modifications that we have already completed and these 18 are design modifications that have been attempting to 19 meet the full spectrum of breaks and we are just 20 arguing about how well we are doing that, we can 21 clearly agree that for the more likely spectrum of 22 breaks that the deterministic methods should be met.
23 So we are really getting down for the less 24 likely spectrum of breaks. How do you best close 25 those out in an expedient fashion? We think that NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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95 1 Option 3 provides a way to acknowledge the minimal 2 safety impact of the spectrum of breaks, has the least 3 impact on worker dose, cost and we are willing to 4 consider reasonable ways to address defense-in-depth 5 mitigation measures that can be implemented as part of 6 an Option 3 application.
7 Thank you.
8 MEMBER BANERJEE: Thanks. Do we have any 9 questions?
10 MEMBER ARMIJO: I still don't know with 11 Option 3, is there a pipe size that you would stop at 12 and say okay, we will apply leak-before-break for 13 pipes smaller than the transition break size down to a 14 certain size? You know, I just am trying to figure 15 out exactly how you would use it and why you favor it.
16 MR. BUTLER: The piping systems that are 17 LBB qualified, you know, they are already LBB 18 qualified so we are not talking about qualifying new 19 piping. For each plant, each plant has a certain set 20 of piping that is qualified to LBB and they go through 21 all the review of that. It varies from plant to plant 22 but generally, all PWRs have their main loop piping 23 qualified as LBB. Some plants have gone further and 24 been able to qualify the pressurizer surge line and 25 RHR piping but that varies, again, from plant to NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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96 1 plant.
2 MEMBER ARMIJO: Okay and all that piping 3 is bigger than the transition break size. Right?
4 MR. BUTLER: I think generally we are 5 talking about plants, smallest of LBB piping for most 6 plants doesn't go below 12 inches that I am aware of 7 but generally it is 14 to 16 inches, the smallest 8 piping if they have been able to qualify beyond main 9 loop piping.
10 MEMBER ARMIJO: Okay.
11 MEMBER BANERJEE: Do you have any comment 12 on the USC letter which you undoubtedly have a copy 13 of.
14 MR. BUTLER: The first or second?
15 MEMBER BANERJEE: Either or both.
16 MR. BUTLER: The first letter was 17 promoting the staff's previous direction which is 18 involving the 50.54(f) letters. I wasn't in favor of 19 that process so I wasn't in favor of the UCS letter 20 there.
21 The second USC letter seemed to have some 22 openings for use of LBB provided that there was 23 sufficient leakage protection capability and I can't 24 disagree. And I think generally the plants have 25 adequate leakage detection measures. In fact, there NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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97 1 have been some industry actions to improve those 2 leakage detection methods and applications and 3 applying a PWR owner's group methodology.
4 MEMBER BANERJEE: One of the letters, I 5 forget which one, they sort of were concerned that 6 plants will not shut down when leaks were detected.
7 MR. BUTLER: I can't comment. I am not 8 familiar with the specific instances.
9 MEMBER BANERJEE: Well they gave a couple 10 of instances where plants had, I think, stalagmites, 11 they said hanging from, I forget the exact wording, 12 without being shut down. And therefore, the sort of 13 leak-before-break or whatever the --
14 MR. PIETRANGELO: Well, all plants have to 15 comply with their tech specs. That is addressed in 16 their tech specs. And if they don't, I think the 17 consequences are pretty serious for the NRC.
18 MEMBER BANERJEE: Right. But I guess 19 their concern was that it might be that plants are 20 leaking away and operating. That is the way it read, 21 that if plants were truly shut down as soon as the 22 leaks were detected, that would be one thing but some 23 plants operated with ongoing leaks for quite a while.
24 I mean, that was the gist of that letter.
25 Right?
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98 1 MR. BUTLER: Well plants will, once they 2 identify the leaks, some plants will, depending upon 3 where the leak is coming from, it makes sense to not 4 shut down right away to address a leak in a non-5 consequential part of the plant. But the regulations, 6 the requirements, the tech specs that are directed to 7 address that will be followed.
8 MEMBER BANERJEE: Right but that was --
9 Anyway, I don't want to belabor it because they are 10 not here to say anything about it but their letter was 11 sort of not in support of this, at least one letter, 12 because they felt that plants were not being shut down 13 when they leak. That was --
14 MR. BUTLER: I think the characterization 15 of the second letter was that they were not -- If it 16 was pursued, they would like to see some additional 17 measures taken to ensure that the leakage detection 18 actions were properly addressed.
19 MEMBER BANERJEE: Okay well let's move on.
20 Any other questions? Yes, Bill.
21 MR. RULAND: May I, Mr. Chairman? Just a 22 couple of things. First of all, David Lochbaum from 23 UCS is going to be at the committee meeting. So he 24 will be able to voice whatever the current opinion is.
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99 1 the Commission meeting. So he will have some views 2 that he will bring forward.
3 The second question and looking at your 4 last slide, John, I see something here that I just 5 need a little clarification on. You say credits 6 defense-in-depth measures already taken by plants for 7 leak-before break. Are you suggesting the licensees 8 would be willing to add to their licensing bases the 9 commitments that they have made for compensatory 10 measures for GSI-191? They would then suggest or not?
11 MR. BUTLER: That is what that is 12 suggesting. Again, I can't speak to specifics but you 13 know, the measures that were taken that were 14 identified in Bulletin 2003-01, plants are continuing 15 to follow those measures. So if it is a matter of 16 documenting them in some fashion and continuing them, 17 I don't see that as a problem.
18 MR. RULAND: Yes, it is just a 19 clarification. I just wanted to know what you meant 20 by credits.
21 And the final thing is just for the full 22 Committee's information, today is Mike Scott's, my 23 distinguished colleague to my right, it is his last 24 ACRS meeting as the GSI-191 Branch Chief. I would 25 just like to acknowledge Mike's really outstanding NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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100 1 performance in his role. I think you obviously have 2 recognized that and I am deeply grateful for his 3 performance as is the other staff in the whole NRC.
4 So thank you.
5 (Applause.)
6 MEMBER BANERJEE: And we would also to 7 acknowledge an outstanding performance.
8 MEMBER SHACK: So where are you going to 9 reemerge?
10 MR. SCOTT: I am going to be the Chief of 11 the New and Advanced Reactor's Branch in the Office of 12 Research.
13 MEMBER BANERJEE: Okay, I will hand the 14 meeting back to you, Mr. Chairman.
15 CHAIRMAN ABDEL-KHALIK: Thank you.
16 MEMBER BANERJEE: Thank you.
17 CHAIRMAN ABDEL-KHALIK: At this time, we 18 will take a break until 10:45.
19 (Whereupon, the foregoing meeting went off the record 20 at 10:30 a.m. for a closed session and 21 went back on the record at 1:14 p.m.,
22 continuing the open session.)
23 CHAIRMAN ADBEL-KHALIK: We're back in 24 session. At this time, we will move to Item 4 on the 25 agenda, Long-Term Core Cooling Approach for the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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101 1 Economic Simplified Boiling Water Reactor Design, and 2 Dr. Corradini will lead us through that discussion.
3 MEMBER CORRADINI: Thank you, Mr. Chairman.
4 So, let me give a little bit of background to the 5 members about this. The Commission wrote a letter in 6 2008, an SRM, excuse me, directly staff to, 7 essentially -- I keep on thinking that everything is 8 like us, they write a letter. An SRM directing --
9 MEMBER SHACK: It's a little different 10 impact.
11 MEMBER CORRADINI: Yes, good point.
12 Directing the staff to look at each of the new 13 advanced reactor designs, and verify that all those 14 designs can successfully maintain long-term cooling 15 under all circumstances. We had a series of meetings 16 going back -- for ESBWR, we had a series of meetings 17 going back in October and November of 2009, and most 18 recently in July of 2010 to review this for the ESBWR 19 design.
20 This is now -- this presentation, I should 21 say, is specifically addressing long-term cooling, so, 22 essentially, this SRM by the Commission, and we're 23 going to be writing a letter on this one narrow aspect 24 of the ESBWR. So, with all due respect to the 25 Members, if you stray, I will keep you -- I will get NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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102 1 us back on track, because next month we have the joy 2 of the complete ESBWR review with closed items for 3 ESBWR. So, with that, I'll ask Mr. Marquino to lead 4 us off. Is Jesus on the line?
5 MR. MARQUINO: Yes, I believe so. Jesus, 6 are you there?
7 MR. DIAZ-QUIROZ: Yes, I'm on the line.
8 MR. MARQUINO: My name is Wayne Marquino.
9 I work for GE Hitachi. The presentation was prepared 10 by myself and Jesus Diaz-Quiroz. And there was a 11 meeting in December of 2009 on this long-term cooling 12 --
13 MEMBER CORRADINI: November.
14 MR. MARQUINO: November Subcommittee and 15 then December full Committee. GE presented to the 16 full Committee, but for this meeting we were asked to 17 come back and mainly talk about debris and how we're 18 addressing debris in the ESBWR. So, I have one slide 19 on long-term core cooling, and then we'll go into the 20 debris topic.
21 MEMBER CORRADINI: May I interject one 22 thing? So, just to remind the Members that were here, 23 we had a -- Wayne corrected me that we did have a 24 presentation back in December on long-term cooling, 25 generally, and this was mainly containment response, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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103 1 because ESBWR does not uncover the fuel under any 2 circumstance under any DBA, so all the calculations 3 we've seen to date have been both applicant 4 calculations and NRC staff audit calculations looking 5 at the containment response. And I asked GE to 6 specifically address things that are typically talked 7 about, long-term cooling and other designs to make 8 sure we cover the waterfront. So, go ahead, I'm 9 sorry.
10 MEMBER BANERJEE: Mike, did you have a 11 Subcommittee meeting on this issue on the debris 12 aspects?
13 MEMBER CORRADINI: No.
14 MEMBER BANERJEE: You have not.
15 MEMBER CORRADINI: It's been asked in the 16 Subcommittee meetings with our consultants, Dr.
17 Wallace and Dr. Kress, over three different meetings, 18 but we've never had a meeting strictly on debris.
19 MR. MARQUINO: As you said, ESBWR does not 20 uncover fuel. Even in the worst LOCA we have more 21 than half meter of collapsed water level above the 22 fuel at the time the level reaches its minimum. Also, 23 the core does not dry out or heat up in an ESBWR LOCA, 24 so the peak clad temperature is the initial 25 temperature.
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104 1 The containment pressure remains below the 2 design pressure for 72 hours using the passive 3 systems, and then at 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />, we achieve a pressure 4 reduction by operating fans in the vent line from the 5 passive containment cooler that cycle non-condensables 6 out of condenser, and that increases its capability, 7 brings non-condensables back from the wet well and 8 reduces the containment pressure. So, the passive 9 systems provide cooling for 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> followed by a 10 depressurization by a PCCS vent fan, which is a RTNSS 11 category system.
12 So, the rest of the presentation goes from 13 those passive systems into how we would use active 14 systems, and how they could be affected by debris.
15 MEMBER CORRADINI: So, if I might, maybe 16 you're going to say this, but I want to make sure that 17 everybody remembers. So, under all DBA analysis, and 18 under their to be written procedures, passive systems 19 are the first line in all response to all of these 20 design-basis accidents. Is that correct?
21 MR. MARQUINO: Yes.
22 MEMBER CORRADINI: Okay.
23 MR. MARQUINO: The safety-related cooling 24 is provided by a gravity drain cooling system. Its 25 cooling inventory for core coverage is in GDCS pools, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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105 1 and the injection drain those pools into the vessel.
2 And then blow off from the core is made up by the 3 condensate from the PCCS. That circulation loop does 4 not use pumps. It's a safety-related source, and it's 5 not in a flow path which would be affected by debris 6 during the LOCA.
7 Additionally, we have equalizing lines in 8 the pools which would open if the water level dropped 9 below or approached the core. However, in the 72-hour 10 coping period, and during the 30-day RTNSS period, 11 those lines are not required to open. So, we provide 12 short and long-term cooling through a passive GDCS 13 system, and passive containment cooling system.
14 CHAIRMAN ADBEL-KHALIK: Are the pools 15 themselves covered so that no debris would fall into 16 the pools?
17 MR. MARQUINO: Yes, there is a plate that 18 closes off the GDCS pool from the drywell. It's 19 perforated to prevent debris from entering the pool.
20 And in the blow down phase of the LOCA, there's not --
21 that compartment is part of the drywell, so there 22 isn't a differential pressure driving debris into the 23 GDCS compartment, as there would be between the 24 drywell and wet well.
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106 1 sketch, because I can't recall the details, since I 2 haven't been on this Committee for a long time, so we 3 know where things are.
4 MS. CUBBAGE: This is Amy Cubbage. I 5 believe if you look at the staff slides, we have a 6 figure.
7 MEMBER BANERJEE: Which one?
8 MS. CUBBAGE: It's not very detailed, but 9 the staff slides, Figure 9.
10 MEMBER BANERJEE: Figure 9.
11 MEMBER CORRADINI: Slide 9.
12 MEMBER BANERJEE: Yes, that's fine.
13 MS. CUBBAGE: The GDCS is covered from 14 above, and the vertical connection where the GDCS air 15 space and the drywell communicate.
16 MEMBER BANERJEE: So, the GDCS pool is 17 covered at the top?
18 MEMBER CORRADINI: Yes.
19 MR. MARQUINO: So, it's enclosed, it's some 20 sort of a gap that's about .8 meters, and the gap is 21 covered by a perforated plate.
22 MEMBER CORRADINI: Does that make sense, 23 Sanjoy?
24 MEMBER BANERJEE: Yes. I think so. It 25 would be nice to see a picture of what it looks like.
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107 1 MEMBER CORRADINI: I'll look for one. When 2 GEH and the staff's contractor did the analysis, there 3 was a scaled -- they both are scaled models for the 4 TRACG and the MELCOR, but it's not in these handouts.
5 I can get you one.
6 MEMBER BANERJEE: And the GDCS pool does 7 not accumulate any float offs like you find in the 8 pores of BWRs and things like that.
9 MR. MARQUINO: Well, the -- it's stainless 10 steel lined. It won't be subject to corrosion. We 11 don't expect to have to go into that pool for 12 maintenance activities.
13 MEMBER SHACK: And the holes in the 14 perforated plate will be smaller than the orifice 15 holes in the fuel support castings.
16 (Off mic comment.)
17 MEMBER CORRADINI: We're getting ahead of 18 you, but we're anticipating the next question, just in 19 case.
20 MR. MARQUINO: Okay. So, that's the 21 passive systems, but we do have active defense-in-22 depth systems. We can cool the suppression pool using 23 the fuel and auxiliary pool cooling system. We could 24 do that during normal operation. We also have a 25 reactor water cleanup shutdown cooling system, and NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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108 1 that has a cross-tie to the FAPCS system.
2 MEMBER BANERJEE: So, where does the debris 3 in this case end up, both the latent and debris 4 generated during the -- say, if I was looking at this 5 picture.
6 MR. MARQUINO: Yes.
7 MEMBER BANERJEE: Where would it end up?
8 MR. MARQUINO: Okay. The most likely 9 places for debris to end up are at the lowest point in 10 the reactor building, which is the lower drywell, and 11 the bottom of the suppression pool. So, during a LOCA 12 blowdown, there will be a flow path from the drywell 13 through the vents to the suppression pool that could 14 carry the debris through there, or if it's blown loose 15 and it doesn't make it to the suppression pool vent, 16 it would go down into the lower drywell.
17 MEMBER BLEY: But when it's in the 18 suppression pool, at least at first, it's going to be 19 well agitated and mixed up.
20 MR. MARQUINO: Yes.
21 MEMBER BLEY: Not on the bottom of the 22 suppression pool, at least for some time, maybe a long 23 time.
24 MR. MARQUINO: Right. And we have some 25 information about how -- it's on the settling time in NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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109 1 the suppression pool, but the question was where will 2 the debris be, and those are the two most likely areas 3 for debris. It's not much of a concern in the lower 4 drywell, because we're not taking a suction source on 5 the lower drywell, so the suppression pool is the area 6 of concern.
7 MEMBER BANERJEE: So, what happens --
8 MR. MARQUINO: Well, from --
9 MEMBER BANERJEE: Imagine that this debris 10 doesn't settle, stays there. Let's postulate --
11 MEMBER CORRADINI: Is that one of your 12 slides?
13 MEMBER CORRADINI:
14 MR. MARQUINO: Yes. We have a slide 15 showing the suction strainer that we've provided for 16 the debris. I'll get to that in the --
17 MEMBER BANERJEE: Okay. It would be nice 18 to have a few slides. I mean, pictures instead of 19 words here, because I can't tell what all this means.
20 MEMBER CORRADINI: He's getting there.
21 MEMBER BANERJEE: He's getting there.
22 MEMBER CORRADINI: But just so I make sure 23 I understand your question, you're saying first you 24 have to assume that the PCCS doesn't function.
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110 1 to understand where the debris is.
2 MEMBER CORRADINI: Okay. I misunderstood.
3 MEMBER BANERJEE: Where it's going, and 4 where it's getting caught. I mean, if you just give 5 us a picture showing the fate of the debris, this 6 would be very useful.
7 CHAIRMAN ADBEL-KHALIK: Now, it is possible 8 for the debris, obviously, to accumulate on the cover 9 of the GDCS pool. And you have holes in that cover, 10 and let's say it's not going to through the holes, but 11 it's going to plug the holes. Does that prevent 12 drainage of the GDCS pools?
13 MR. MARQUINO: No, and the --
14 MR. DIAZ-QUIROZ: This is Jesus Diaz from 15 GEH. As far as the number of holes on the perforated 16 plate, there's not a lot that's needed for proper 17 drainage to occur.
18 CHAIRMAN ADBEL-KHALIK: Okay. Because you 19 do need communication between the free surface and the 20 drywell.
21 MR. DIAZ-QUIROZ: Right. So, when we look 22 at where is it that we need to locate the holes so we 23 can provide proper drainage, we can put these holes in 24 areas where it's not in the direct line of any jet 25 impingement that would actually force debris onto that NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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111 1 plate. You would end up getting a place where you have 2 no holes, and then you would have some holes where you 3 wouldn't have direct line of sight to those areas that 4 would create jet impingement.
5 CHAIRMAN ADBEL-KHALIK: That's fine. Thank 6 you.
7 MR. MARQUINO: So, going through active 8 systems that we could apply, we have a high-pressure 9 injection system. In a LOCA, that might operate early 10 on, but it does isolate automatically at a point to 11 prevent excessive water addition to the containment, 12 which has an adverse effect on the containment 13 pressure.
14 We also have a low-pressure injection 15 function provided by the FAPCS system, or a cross-tie 16 to the shutdown cooling system. And that can take 17 water from the suppression pool, or the condensate 18 storage system and pump it into the reactor. Operator 19 action is required to initiate the low-pressure 20 cooling injection system.
21 So, given that we have an active system 22 that would be used, defense-in-depth, to pump from the 23 suppression pool into the reactor, what are the 24 possible sources of debris that could be pumping, or 25 drawing on? Possibly insulation, but we have NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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112 1 committed to only use reflective metal insulation.
2 There won't be any fibrous insulation in ESBWR.
3 Degraded coatings, but we committed to use only 4 qualified coatings that meet Reg Guide 1.54, and ASTM 5 D 5144.
6 We don't expect rust particle loading, 7 because we will use approved coatings on the metal 8 surfaces. We have the potential for dirt and dust, 9 and random fibrous material, like rags left in the 10 drywell. We have considered that in sizing the 11 suction strainer.
12 MEMBER BLEY: And the coatings, I would 13 guess, could get eroded by the jet impingement, so you 14 could have some of the coatings that you're putting on 15 there ending up in that mix.
16 MR. MARQUINO: Yes, but from local 17 abrasion, possibly some limited extent. Jesus, do you 18 want to comment on what we assumed in terms of coating 19 load?
20 MR. DIAZ-QUIROZ: Right. So, as far as the 21 way the debris strainer was sized, we looked at what 22 were the possible debris sources for ESBWR, and then -
23 - to make sure we had a robust design, we looked at 24 existing BWRs, as far as what the criteria they used 25 to design their strainers, so we ended up using a more NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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113 1 bounding debris load, which did use large coatings, 2 fibrous debris, and various other source terms in a 3 typical BWR.
4 MEMBER RAY: What about jet impingement on 5 concrete from broken pipe?
6 MR. DIAZ-QUIROZ: So, as far as jet 7 impingement on concrete, you have where just about 8 everything inside containment is covered with 9 stainless steel liners, like in the pools or carbon 10 steel liners in the rest of the walls, so you have 11 limited possibility that you will actually get bare 12 concrete. For instance, the GDC has walls themselves 13 which provide a lot of surface area, are covered by 14 steel, and then the diaphragm floor, which is a sort 15 of sandwich-type composite, that's also covered by 16 carbon steel. So, there's a lot of coverage with steel 17 liners to prevent the spalding action you would get 18 through the jet impingement.
19 MEMBER BANERJEE: The GDCS pools are 20 stainless steel lined.
21 MR. DIAZ-QUIROZ: Yes, right --
22 MEMBER CORRADINI: I think he's talking the 23 outside wall.
24 MR. DIAZ-QUIROZ: The outside walls are 25 covered with steel, as well.
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114 1 MEMBER BLEY: Wayne, before you get too far 2 from your previous slide, I wanted to ask you a 3 question. I know from a safety analysis point of view 4 all you need are passive systems for the first 72 5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />. Will there be a prohibition against operators 6 using available active systems? Might the procedures 7 have them go through high-pressure injection and then 8 low-pressure injection, or might they decide that on 9 their own?
10 MR. MARQUINO: Right. We don't want to 11 restrict the operator from using these active systems.
12 MEMBER BLEY: So, they could get started 13 pretty early pumping from the suppression pool, if 14 they so decided.
15 MR. MARQUINO: Right. Now, we haven't 16 worked through the emergency procedures.
17 MEMBER BLEY: I know.
18 MR. MARQUINO: But I expect I'll have some 19 involvement in that. And in the five minutes that the 20 reactor is blowing down, that might be a good time to 21 just stand back and monitor, and assess the situation.
22 MEMBER BLEY: I like that. Can you imagine 23 what the environment is like when you're getting 24 blowdown on the system? That's probably all you can 25 do is stand back.
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115 1 MR. MARQUINO: So, we have the systems. We 2 don't need them during that period, so I expect the 3 emergency procedures would direct the operator, if ADS 4 has just been initiated, don't initiate low pressure 5 injection for five minutes, or ten minutes, because 6 it's not needed for core cooling in that kind of --
7 MEMBER BLEY: And we know it's not needed 8 even longer, but I suspect this stuff will remain 9 suspended for a lot longer than five or ten minutes.
10 So, they could, but you haven't talked about the 11 strainers yet, so if they do, you think you're 12 covered, anyway.
13 MR. MARQUINO: Yes.
14 MEMBER BLEY: Go ahead.
15 MEMBER ARMIJO: Wayne, where are the 16 strainers located on --
17 MEMBER CORRADINI: I think he's leading 18 into your next slide.
19 MR. MARQUINO: Yes, I hope. And we don't -
20 - okay. So, this is what a strainer looks like. We 21 call this stacked disk strainer. It's similar to 22 those used in the operating BWRs. As Jesus said, 23 we're using an operating plant debris source, even 24 though we've taken more counter measures against 25 debris that aren't practical for them to backfit.
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116 1 It's a Quality Group 1 component, and a Seismic 2 Category 1 component. It has a hole size of 2-1/2 3 millimeters, and the seismic category in hole size 4 will be performed by ITAAC.
5 MEMBER BANERJEE: Can you show us how this 6 strainer works?
7 MR. MARQUINO: Yes. Jesus, we don't have a 8 picture showing the location of the strainer in the 9 suppression pool.
10 MEMBER BANERJEE: But even this strainer, I 11 mean looking at this picture, I have no idea how it 12 works. It doesn't --
13 MR. DIAZ-QUIROZ: Right. So, if you're 14 looking at the right side of that picture there, the 15 pipe would actually be connected to that hole you see, 16 so that's the flange end of the strainer. So, then 17 flow would be, if you look at the left, flow would be 18 coming in from the top, and in from the sides. So, 19 then there's plates, it's covered, the cone shape is 20 plates that's perforated. So, you have these disks 21 that provide, I guess, additional stability, but also 22 prevent some of the larger pieces of debris from 23 getting to the perforated plate. So, that's how you 24 would have flow go through those strainers.
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117 1 a perforated plate?
2 MR. DIAZ-QUIROZ: Right.
3 MEMBER CORRADINI: Like an inverted 4 spaghetti strainer.
5 MR. DIAZ-QUIROZ: Right.
6 MEMBER BANERJEE: But that doesn't help me.
7 MEMBER CORRADINI: That's what it looks 8 like.
9 (Simultaneous speaking.)
10 MEMBER ARMIJO: You say -- repeat that, 11 what you just said.
12 MR. DIAZ-QUIROZ: Right. So, the right 13 picture there, the bottom of it is where -- that's 14 where you would have the flange. That's the flange 15 area, so the pipe would actually be connected there.
16 MEMBER STETKAR: And, Jesus, the right side 17 just for Sanjoy's edification, the right picture does 18 not show the interior solid plate thing with holes in 19 it.
20 MR. DIAZ-QUIROZ: No, it --
21 MEMBER STETKAR: That's the assembly that 22 slides over it, basically.
23 MEMBER BANERJEE: Thank you. That was very 24 illuminating. Really, because I didn't see at all 25 what the hell the two were. Okay.
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118 1 MEMBER ARMIJO: They're two different views 2 of the same thing, aren't they?
3 (Simultaneous speaking.)
4 MEMBER CORRADINI: The spaghetti thing is 5 not inside the right one.
6 MR. DIAZ-QUIROZ: It is. It's tilted up in 7 the disk.
8 MEMBER STETKAR: No, it's not, Jesus, 9 because if you look through it, you see the edges of 10 the plates.
11 MEMBER BANERJEE: That helps a lot. Now, 12 you -- this inverted cone or whatever has little holes 13 in it. And those holes are these 2.5 millimeter 14 holes?
15 MR. DIAZ-QUIROZ: Yes.
16 MEMBER BANERJEE: Why is it conical? I 17 mean, is there a reason to make it conical?
18 MR. DIAZ-QUIROZ: There's many reasons, but 19 there are other strainer designs.
20 MEMBER BANERJEE: I have not asked any more 21 questions. Carry on. That's fine. Presumably, 22 you've tested these things, and they work. Have you 23 tested them?
24 MR. DIAZ-QUIROZ: Right. These are 25 installed, and they've been tested extensively, yes.
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119 1 MEMBER BANERJEE: Okay.
2 MEMBER ARMIJO: And where are they located 3 in the suppression pool?
4 MR. DIAZ-QUIROZ: Right. So, I'm sorry you 5 don't have a picture to look at, but if you were to 6 look from the top down, top into the containment, and 7 you would be looking at the top of the suppression 8 pool, you have X-quenchers that surround most of the 9 outer radius of that wall inside the suppression pool.
10 There's a total of 10 quenchers, and then there's 12 11 actually horizontal bands. And then if you were to 12 look at, say, superimpose looking at the reactor where 13 all of the steam lines run out to one side of 14 containment, well, if you look at that exit and go 180 15 around that circle, and then you would see two spots 16 where you would have quenchers where we don't have 17 quenchers, since there's only 10 of them. So, there's 18 two spots there, so the strainer could be located in 19 either one of those spots right now. I don't know if 20 that's really how the picture --
21 MEMBER ARMIJO: Very hard. It really would 22 be nice to have a picture.
23 MEMBER CORRADINI: So, can I say back at 24 you, and then ask a question to clarify. So, you're 25 saying that in places where there would have been NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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120 1 quenchers, you put in the suctions, are they standing 2 up from the floor? And, if so, how much are they 3 standing up from the floor of the suppression pool?
4 MR. DIAZ-QUIROZ: Right.
5 MEMBER CORRADINI: Or are they on the side?
6 MR. DIAZ-QUIROZ: No. So, they're inside 7 the suppression pool, and so -- and I can't recall off 8 the top of my head, but say they're about half a meter 9 off the floor, and then there's a few meters below the 10 surface level. And there's various reasons why you'd 11 want to locate it suspended, you might say, in the 12 pool right off the wall.
13 MEMBER CORRADINI: Okay. So, they're 14 suspended off the wall. That's what I was trying to 15 get at.
16 MR. DIAZ-QUIROZ: Right. So, they stick out 17 a little bit a ways from the wall, not much, because 18 you need to support them.
19 MEMBER CORRADINI: So, this is --
20 MR. DIAZ-QUIROZ: Also, sit above the 21 floor, as well.
22 MEMBER CORRADINI: So, we've got a cartoon 23 on Slide 10 of the staff that we can come back to that 24 shows it.
25 MEMBER ARMIJO: Slide 10?
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121 1 MEMBER BANERJEE: You know what would 2 really help is to have a picture of how these are 3 located in the suppression pool. At the moment, I'm 4 trying to draw this picture in my mind, as we speak, 5 without success.
6 MS. CUBBAGE: If you look at the staff's 7 Slide 10 on the lower left, that's depicting the 8 suppression pool, and it's showing the strainer off 9 the side of the wall.
10 MEMBER ARMIJO: Where are you looking, Amy?
11 (Simultaneous speaking.)
12 MEMBER BLEY: So, actually, you aligned it 13 horizontally with the suction pipe going out in a 14 horizontal direction.
15 MEMBER CORRADINI: Right. It's not coming 16 from the bottom, it's coming from the side. That was 17 what I was trying to get at. And it's about a half a 18 meter up, Jesus. Is that correct?
19 (Simultaneous speaking.)
20 MEMBER CORRADINI: Jesus, I just want to 21 repeat what you said. It's horizontal and sitting 22 about half a meter up, a few meters from the contact 23 surface. Right?
24 MR. DIAZ-QUIROZ: Right. The cool surface, 25 right.
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122 1 MEMBER CORRADINI: Sorry, cool surface.
2 Sorry.
3 MEMBER BLEY: Amy, this is kind of a PNID 4 flow chart kind of thing. Are the dimensions of the 5 strainer roughly the way they look here in this 6 picture?
7 MS. CUBBAGE: You'd have to ask GE. And 8 for your benefit, Jesus, this is a figure from the DCD 9 of the FAPCS system that we're looking at, that I 10 believe-- I don't know if it's --
11 MR. DIAZ-QUIROZ: Right.
12 MEMBER STETKAR: I think it's Figure 262-1, 13 I believe.
14 MR. DIAZ-QUIROZ: Right. And there was an 15 RAI which we sent in, where we would be placing these 16 strainers. And if I can find that RAI, but there's 17 also another figure in Chapter 5 of the DCD which 18 shows the quencher arrangement in the suppression 19 pool. And we could easily point out where that would 20 exist. If you could give me a few minutes, I don't 21 know if we can send something to Wayne so he can put 22 it up, or not, a better picture.
23 MEMBER BANERJEE: Can we just ask for a 24 picture that we can understand to scale.
25 MR. DIAZ-QUIROZ: Okay.
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123 1 MEMBER BANERJEE: Preferably an isometric 2 view. If you cannot provide isometric view of plant 3 and elevations, so we can see --
4 MEMBER CORRADINI: Let's move on, and we'll 5 get that. Okay?
6 MEMBER BANERJEE: Yes.
7 MEMBER POWERS: Dr. Corradini, can I ask a 8 question of -- mostly out of curiosity.
9 MEMBER CORRADINI: Go ahead, Dr. Powers.
10 MEMBER POWERS: I wonder if you could give 11 me an order of magnitude feel of the amount of cable -
12 - insulated cable exposed to the post accident 13 environment in your containment structure?
14 MR. MARQUINO: I don't have that number 15 offhand, but we did commit to an upper limit in the PH 16 evaluation for fission product retention. So, we do 17 have an upper bound on the exposed chloride content 18 cable insulation.
19 MEMBER POWERS: And, when you do that 20 analysis, what kind of doses are you taking? You do 21 King's doses, or --
22 MR. MARQUINO: We took the alternate source 23 term dose, and --
24 MEMBER POWERS: Calculated from the 25 alternate source term --
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124 1 MR. MARQUINO: Yes, it was tied to the 2 alternate source term. I don't remember the details 3 about how much of that was assumed to be in the 4 suppression --
5 MEMBER POWERS: Really what I wanted to 6 know is whether you're using the King's analysis, 7 which is tied to the GID source term, or you did your 8 own with the ASD source term.
9 MR. MARQUINO: We used ASD source term.
10 MEMBER POWERS: I just looked at what the 11 chloride did, and you assumed that was just uniform, 12 or did you have an exponential decay on the generation 13 rate. That may be too detailed.
14 MR. MARQUINO: I don't know.
15 MEMBER POWERS: I'll look in the document, 16 itself. That's too detailed. I understand what you 17 did.
18 MR. MARQUINO: It's in the fission product 19 retention NED report that's referenced from Section 20 15.4.
21 MEMBER POWERS: Good. Thank you.
22 MR. MARQUINO: Okay.
23 MEMBER POWERS: My curiosity is satiated, 24 sir.
25 MR. MARQUINO: Okay.
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125 1 MEMBER CORRADINI: Go ahead.
2 MEMBER BANERJEE: Just to ask this 3 question, suppose you had some latent debris in 4 containment, how much of it would end up in the 5 suppression pool in the early stages?
6 MR. MARQUINO: It depends on where the 7 break is relative to the main vent openings in the 8 drywell. So, we have a --
9 MEMBER BANERJEE: Let's say I postulate you 10 have 200 pounds of latent fibrous debris in 11 containment. How much would end up in the suppression 12 that --
13 MEMBER CORRADINI: You don't have to agree 14 to 200 pounds.
15 MEMBER BANERJEE: No, I'm just postulating 16 that. He picks a number.
17 MR. MARQUINO: So, back on Slide 16 in the 18 backup slides. These are the debris source terms that 19 were used to determine the plugging of the strainer, 20 and the increase in pressure drop on the strainer.
21 MEMBER BANERJEE: So, this was what ended 22 up in the suppression pool, or what you postulated 23 ended up in the suppression pool.
24 MR. MARQUINO: Yes.
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126 1 of fibrous debris?
2 MR. DIAZ-QUIROZ: Wayne, if I may add, this 3 is Jesus Diaz again from GEH. There was an RAI, RAI 4 6.2-123 of Supplement One, which described the 5 analysis we went through on the debris strainer. And 6 even though we used this one cubic foot of fibrous 7 debris, we did look at the effects of fiber from all 8 points, thin fiber effect, and also you have more --
9 so, it turns out that through our analysis that the 10 thin fiber effect was more limiting as far as the 11 strainer was concerned. And those are the results, I 12 believe, that are presented in one of the slides that 13 Wayne is going to go through here in a minute.
14 MEMBER BANERJEE: Well, I guess the issue 15 here is we're not very concerned about your strainer.
16 It's what passes through the strainer.
17 MR. DIAZ-QUIROZ: That is true.
18 MEMBER BANERJEE: And, I guess, when we 19 came to look at the ABWR, we -- if I'm not mistaken, 20 that had a clean containment, but had quite a bit 21 higher fibrous debris that we had to consider in 22 latent. I don't know the number. Perhaps, Professor 23 Abdel-Khalik will know, because this is --
24 CHAIRMAN ADBEL-KHALIK: It wasn't that 25 much, because it was mostly rags left in containment.
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127 1 MEMBER BANERJEE: Right. Yes, but it --
2 MEMBER SHACK: I thought a cubic foot was -
3 - I think it's a cubic foot.
4 MEMBER BANERJEE: Was it a cubic foot?
5 MEMBER SHACK: Yes.
6 MEMBER BANERJEE: Okay.
7 MR. McKIRGAN: If I could, this is John 8 McKirgan from the staff. Yes, the South Texas 9 assumption is also one cubic foot, I believe.
10 MEMBER BANERJEE: So, this is consistent 11 with that. And you tell us how much of it gets 12 through.
13 MEMBER CORRADINI: He's on his way to that.
14 MEMBER BANERJEE: Okay.
15 MEMBER CORRADINI: He's working towards 16 that. We alerted him you'd be present at the meeting.
17 MR. MARQUINO: So, now with that 18 MEMBER BANERJEE: Paying you back for not 19 being here yesterday.
20 MEMBER CORRADINI: I know. I know. I'm 21 sorry.
22 MR. MARQUINO: With that debris loading on 23 the strainer, we look at the net positive suction head 24 margin on the pump, so we've evaluated the FAPCS pump 25 in low-pressure injection mode. We don't take any NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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128 1 credit for containment overpressure. And we've looked 2 at a number of different pool temperatures. What is 3 being presented here is the minimum and maximum pool 4 temperatures. And we -- this evaluation covers the 5 shutdown cooling pumps, as well. They're at the same 6 elevation as the FAPCS pumps.
7 MEMBER BANERJEE: Are these head losses 8 based on experiments?
9 MR. MARQUINO: Let's see. Some of the head 10 losses are based on the elevations, and --
11 MEMBER BANERJEE: I mean, the total debris 12 head loss.
13 MEMBER CORRADINI: He's asking about the 14 debris head loss column.
15 MR. MARQUINO: Yes. Jesus, is the debris 16 based on a correlation, or experiment?
17 MR. DIAZ-QUIROZ: Right. The debris head 18 losses were calculated using correlations that were 19 based on testing, yes.
20 MEMBER BANERJEE: Whose correlations are 21 these?
22 MEMBER ARMIJO: Was that testing done with 23 a kind of mix of materials that are in your Slide 16?
24 MR. DIAZ-QUIROZ: Yes. Right. So, since 25 that was expedient, you might say, for us to use a NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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129 1 bounding debris source term, because that's what the 2 BWR, typical BWRs go analyze to, so that was what 3 they'd have to do as far as coming at derivations of 4 the correlations.
5 MEMBER BANERJEE: So, who did these tests, 6 and whose correlations are these?
7 MR. DIAZ-QUIROZ: I'd have to go back and 8 look through the analysis to be able to answer that 9 question.
10 MEMBER CORRADINI: But can -- as we put 11 that aside to be answered later, is this part of the 12 BWR Owner's Group testing that's back from the `90s?
13 That's what I assumed.
14 MR. DIAZ-QUIROZ: I'd have to look again 15 through the analysis.
16 MEMBER CORRADINI: Okay.
17 MR. DIAZ-QUIROZ: I want to give you an 18 answer.
19 MEMBER CORRADINI: Thank you.
20 MEMBER BANERJEE: And we need an answer on 21 that. But more the point, how do you know how much 22 passed through? Was that also tested for?
23 MEMBER ARMIJO: Probably not.
24 MR. DIAZ-QUIROZ: No, that was not.
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130 1 actually go do that, and also quantify how much debris 2 gets in the reactor in the typical BWR reactors.
3 MEMBER ARMIJO: You don't have much head 4 loss, where else is it going to go?
5 MR. MARQUINO: Okay. So, you can see that 6 we have a large MPSH margin with this debris loading 7 on the strainer. Now, suppose the debris gets through 8 the strainer? The earliest time that we could -- we 9 can't draw in debris if the pump can't overcome the 10 vessel injection pressure. So, there's a time in the 11 LOCA before which we can't reasonably be injecting 12 debris. And that pressure is 290 psi. The time the 13 vessel would reach that pressure in a LOCA is 150 14 seconds. Now, that does allow considerable time for 15 settling in the suppression pool.
16 MEMBER BANERJEE: Settling of the RMI.
17 MR. MARQUINO: Settling of the RMI. Right.
18 MEMBER BANERJEE: Nothing else.
19 MEMBER STETKAR: Wayne, is that 150 seconds 20 based on the ADS timing, or is that --
21 MR. MARQUINO: Yes, that's based on the ADS 22 time.
23 MEMBER STETKAR: So, for a larger LOCA, you 24 could get down more quickly, couldn't you?
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131 1 number, I believe, is for the minimum water level 2 break, so it's specific to the scenario that we 3 evaluated for blockage. A higher -- a larger break 4 would possibly depressurize faster, but the higher 5 breaks also provide more water over the core. So, we 6 selected the minimum water level break for this 7 blockage evaluation. IC injection.
8 MEMBER BANERJEE: So, if we sort of look at 9 the situation and say that -- let's just assume that 10 RMI settles, but all the other stuff is in suspension.
11 How many -- what fraction of the volume of the 12 suppression pool gets injected before your long-term 13 GDCS or whatever comes in? Is it half the volume, 14 one-quarter of the volume, the whole volume?
15 MR. MARQUINO: I don't have a feel for 16 that.
17 MEMBER BANERJEE: All right. Just putting 18 what fraction of the debris which is suspended, if I 19 assume it's all suspended except RMI gets injected.
20 MR. MARQUINO: Well, it's a big suppression 21 pool, and this pump has a small flow rate relative to 22 the suppression pool.
23 MEMBER BANERJEE: Yes. It pumps long 24 enough it will pump it all out.
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132 1 has got to be distributed in the suppression pool, so 2 it would take on the order of many minutes for the 3 debris to collect at the pump suction, and be pumped 4 into the vessel.
5 MEMBER BANERJEE: So, that's the question 6 I'm asking you.
7 MR. MARQUINO: Yes. Numerically, I can't -
8 -
9 MEMBER BANERJEE: I don't want a 10 qualitative answer, I want a quantitative answer.
11 MR. MARQUINO: I can't give you a number.
12 MEMBER CORRADINI: What are you asking, 13 though? I'm --
14 MEMBER BANERJEE: How much of the debris 15 gets injected into the pool, into the core, assuming -
16 - let's say that some part of it passes through the 17 strainers. It's a simple question.
18 MR. MARQUINO: Right. Okay. Well, going 19 back, let me try and lay out the big picture basis for 20 you. We have a debris source that was established for 21 operating BWRs, and we have a fuel plugging fraction 22 which is established for operating BWRs. And in these 23 plants, their primary safety system is these ECCS 24 pumps that take suction through the strainers and are, 25 potentially, pumping debris into the vessel. So, the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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133 1 ESBWR basis for blockage fraction in the core is based 2 on the operating plants.
3 MEMBER BANERJEE: Yes, except that we, as 4 you know, are reevaluating in-vessel effects right 5 now. And in-vessel effects have been found relatively 6 recently. And what implications they'll have on the 7 operating BWRs we don't know at the moment. They 8 certainly have implications on the operating PWRs.
9 So, leaving aside what is happening with the operating 10 BWRs, I'm simply asking the question, how much debris 11 is getting into the core? Can you give me an estimate 12 of that?
13 MR. MARQUINO: We -- in terms of the 14 percent blockage, I can you tell that we --
15 MEMBER BANERJEE: I don't need the -- I 16 just need to know how much.
17 MR. MARQUINO: In terms of what fraction of 18 that total source is getting into the core, we have 19 not quantified that.
20 MEMBER BANERJEE: Well, that -- I mean, how 21 did you get blockage if you don't know how much gets 22 in?
23 MEMBER ARMIJO: You consumed a lot of that 24 stuff to create the blockage, and the difference has 25 to go to the core, settle out.
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134 1 MS. CUBBAGE: This is Amy Cubbage. I'd 2 just like to first say that the staff shared your 3 concerns with the potential for debris to be injected 4 into the core in the event that non-safety systems 5 were used. And, basically, to bound the situation, GE 6 went with a conservative debris loading based on the 7 operating units, even though they have been 8 demonstrated to commit to lower debris sources. And 9 they tried to figure out how much debris actually 10 would go into the core, they conservatively assumed a 11 large amount of debris would be injected. And if 12 you'll let Wayne continue, he'll explain the analysis 13 that was done to satisfy the staff that in the event 14 that non-safety systems were used, the ESBWR core 15 would remain cool.
16 MEMBER BANERJEE: That's fine.
17 MS. CUBBAGE: Okay.
18 MEMBER BANERJEE: I'd still like to know 19 how much gets into the core.
20 MS. CUBBAGE: Well, that may not be 21 relevant, if we can finish the presentation. Go 22 ahead, Wayne.
23 MEMBER ARMIJO: Well, one thing I'd like to 24 know is the bulk of your -- except for the RMI, the 25 mass, the largest mass is iron oxide in a sludge or NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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135 1 particulate. Is there any -- do you have a size, 2 particle sizes that you expect this to be? I would 3 expect it to be pretty tiny, and it will shoot right 4 through your strainers, and right into the core, shoot 5 right through the fuel, but I don't know.
6 MR. MARQUINO: Right. I wouldn't expect 7 that material to plug the fuel.
8 MEMBER ARMIJO: How about the debris 9 filters at the bottom of --
10 MR. MARQUINO: The debris filters can grab 11 things on the size of a wire, so material that goes 12 through the strainer would be stopped at the debris 13 filters.
14 MEMBER ARMIJO: You don't see plugging of 15 the debris filters themselves, have the potential --
16 MR. MARQUINO: Well, that's where it --
17 MEMBER CORRADINI: I think that's where we 18 may see a bounding analysis.
19 MR. MARQUINO: Sludge would go through the 20 debris filter, but say fibers would probably stop at 21 the debris filter.
22 MEMBER ARMIJO: Okay.
23 MR. MARQUINO: So, we've postulated 24 blockage of the fuel. I want to note that we looked 25 at blockage at the upper tie plate, but realistically NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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136 1 in ESBWR we don't expect that, because we don't have 2 injection sources that put water into the shroud from 3 on top. All the water goes into the downcomer, and it 4 has to go through the lower plenum, and come up from 5 the bottom.
6 We used our TRACG code to analyze the 7 blockage fraction used by the BWR Owner's Group. We 8 looked at the limiting water level break, the IC line, 9 drain line break, and even with 75 percent blockage at 10 a spacer at the bottom of the fuel channel, we did not 11 see heat up of the fuel, so after the initial 12 transient that there's no heat up from a pump trip or 13 dry out, initially. We depressurize, we establish a 14 water level, and we can tolerate 75 percent blockage 15 at the inlet.
16 We can tolerate 100 percent blockage at 17 the lower tie plate, but that credits the lower tie 18 plate holes which would allow flow to come in from the 19 bypass, so that's how we're able to say if that 20 particular location was 100 percent blocked, we 21 wouldn't heat up, but we would still be getting flow 22 in through another path.
23 MEMBER BANERJEE: So, have you done any 24 experiments on this at all?
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137 1 to your question about what the -- how much is pumped 2 through the strainer and ends up on the fuel, I 3 believe the Owner's Group will conduct experiments 4 that will include GE 14 fuel. Our fuel has the same 5 geometry in the debris filter and spacers, so we would 6 be covered by those experiments.
7 MEMBER BANERJEE: The issue here, which 8 Professor Wallis brought up was that in your 9 situation, you are basically having boil off. So, 10 whatever gets into the channel eventually accumulates 11 in the region of the boiling front, wherever that it 12 is.
13 MEMBER CORRADINI: But there is no boiling 14 front here, though.
15 MEMBER BANERJEE: Well, I think, 16 eventually, there is, because you have to form steam, 17 which then condenses and comes back. Right? If you 18 don't form steam, how do you get long-term cooling?
19 So, once stuff gets into the core, you have to have 20 boiling. Right? Otherwise --
21 MEMBER CORRADINI: But there's no boiling 22 front. The whole core is still covered, and boiling 23 across its whole length.
24 MEMBER BANERJEE: Whatever, but there is 25 steam being generated. Right? So, if you --
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138 1 MEMBER ARMIJO: Top of the pool.
2 MEMBER BANERJEE: Yes, if you got water 3 there and the debris is in the water, where does it 4 end up? It's a question. As you evaporate the steam 5 and it goes back, what happens to it? I mean, I don't 6 know where it would go. This is a question you guys 7 have to answer.
8 MEMBER ARMIJO: Well, it either stays 9 suspended in the water, or comes out as a sludge 10 somewhere, or deposits on a hot surface.
11 MEMBER BANERJEE: I don't know. I'm just 12 asking the --
13 MEMBER CORRADINI: I guess what I'm -- I 14 understand what you're getting at. So, you're saying 15 you create some sort of sludge at the interface, but 16 the interface is way above the active core.
17 MEMBER BANERJEE: Well, it depends where 18 this is. Is there steam generation in the core?
19 MEMBER CORRADINI: Sure. I'm sure there 20 must be.
21 MEMBER BANERJEE: Yes, so if there's steam 22 generation in the core, then depending on the 23 conditions you're going to get concentration wherever 24 steam is being generated.
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139 1 fight back a bit here, I thought Graham's point was 2 that in other designs, other reactors, that level is 3 inside the core. The level here where I'm separating 4 the steam from the water is a meter or more above the 5 active core, so all the gook would be there, not in 6 the core.
7 MEMBER BANERJEE: Graham's point was not 8 where the two-phase level was, necessarily. Because a 9 two-phase level could be above, and would be above the 10 core.
11 MEMBER CORRADINI: Right. And it always is 12 in this --
13 MEMBER BANERJEE: If it isn't, you're in 14 deep trouble, anyway.
15 MEMBER ARMIJO: We've had this in operating 16 plants. If you have boiling in water that's got a lot 17 of iron sludge, it'll deposit, and you can get local 18 burnout.
19 MEMBER BANERJEE: Right.
20 MEMBER ARMIJO: Okay. But here, the 21 boiling is really at the top -- this water, steam 22 interface at the very top, and some of that stuff is 23 probably going to glomerate --
24 (Simultaneous speaking.)
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140 1 you. I'm simply asking the question.
2 MEMBER ARMIJO: How do they treat it?
3 MEMBER BANERJEE: Where does this go?
4 MEMBER ARMIJO: Yes.
5 MEMBER BANERJEE: You know, it could be 6 that you're right, that it forms a scum at the top, or 7 whatever, or it could be depositing in the region 8 where the steam is being formed. It's a question.
9 MEMBER ARMIJO: Well, unless it's washed 10 out through the break, it's going to stay in the core 11 somewhere.
12 MEMBER BANERJEE: There is no washout in 13 this case. Right?
14 MR. MARQUINO: But these are low -- we're 15 down to a low heat flux. You're describing things 16 that operationally are a concern if we want to use 17 this fuel again, but in terms of --
18 (Simultaneous speaking.)
19 MR. MARQUINO: -- causing it to reach 2200 20 degrees Fahrenheit and damage the clad, we've got a 21 lot of margin.
22 MEMBER BANERJEE: So, you can show us to 23 our satisfaction at some point, you haven't yet, that 24 this material will not form a region that will be 25 starved of cooling sufficiently that the temperature NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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141 1 can rise to levels which we are concerned about.
2 MR. MARQUINO: It's not going to cause a 3 plug in the fuel channel.
4 MEMBER BANERJEE: And this is based on what 5 experiments? Because what we're seeing with the PWRs 6 is that this is not the case. So, how is it that you 7 are able to stick handle around this, is it that your 8 shield design is so different, and your experiments 9 show it's so different?
10 MR. MARQUINO: Well, we're stabilized with 11 the water above the core. We're down at a low heat 12 flux, and --
13 MEMBER BANERJEE: Everybody is.
14 MR. MARQUINO: And, again, this is the 15 backup system, so the -- this is not the primary 16 safety-related scenario that we're discussing.
17 MEMBER BANERJEE: I missed that.
18 MEMBER CORRADINI: This is not the design 19 basis accident.
20 MEMBER STETKAR: But it might be the 21 operational results of that initiator.
22 MEMBER SHACK: Yes, go over again how this 23 system works. I mean, you have the passive systems, 24 and we're discussing now the non-safety systems. But 25 I'm assuming that the automatic signals will trip the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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142 1 passive system, and the operator can then make the 2 choice whether he wants to throw these systems in or 3 not.
4 (Simultaneous speaking.)
5 MEMBER BLEY: If he keeps his hands in his 6 pockets, I think there isn't much question that you're 7 all right for some time, but if he doesn't, all these 8 things come up. And what we've been seeing in the 9 PWRs is pretty --
10 MEMBER BANERJEE: Scary.
11 MEMBER BLEY: Different, yes.
12 MEMBER ARMIJO: But I don't think the PWRs 13 use this particular mix of debris. They have a lot 14 more of the fibrous stuff.
15 MR. MARQUINO: Yes, and our chemistry is 16 considerably different. They have an acid chemistry.
17 MEMBER ARMIJO: And TSPs, some of them take 18 it out, so they have a different kind of --
19 MEMBER BANERJEE: Well, the concern is not 20 with the sump screen blockage, it's with the in-vessel 21 effects, which --
22 MR. MARQUINO: Right, but they're -- so, 23 they have a sump that is very limited in volume. We 24 have a big suppression pool.
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143 1 is what I calculate.
2 MR. MARQUINO: They have very low potential 3 for anything to settle out before it's pumped into the 4 vessel.
5 MEMBER BLEY: They're not using the sump 6 any more. They're using the whole bottom of the 7 containment.
8 MR. MARQUINO: Some of them? Okay.
9 MEMBER CORRADINI: I think we've got to --
10 I guess I want to call a time out in the sense that 11 we're starting to compare -- and I don't think it's --
12 we can argue about it privately, but I'm not sure 13 it's appropriate with the applicant to argue about 14 this design versus that design.
15 MEMBER BLEY: It's not so much this design 16 versus that one, it's why do we have confidence in 17 what we're hearing, I think is the --
18 MEMBER BANERJEE: Well, if you have done 19 some experiments, especially because you don't have 20 cross-flow, you know, you've got channels, then that 21 would maybe set our fears to rest.
22 MEMBER CORRADINI: I didn't understand your 23 last point.
24 MEMBER SHACK: We have handcuff the 25 operators.
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144 1 CHAIRMAN ADBEL-KHALIK: I mean, if the 2 operators were instructed not to do anything for --
3 MEMBER BANERJEE: You don't have cross-flow 4 because you have channels. You can block the channel, 5 and you don't have --
6 MEMBER CORRADINI: I guess we're doing too 7 many things. I guess just let Said talk. I'm sorry.
8 CHAIRMAN ADBEL-KHALIK: I was saying, if 9 the operators were instructed not to do anything for 10 an hour or two, all these questions would disappear.
11 CHAIRMAN ADBEL-KHALIK:
12 MR. MARQUINO: And let me follow-up on 13 that. Okay? We have procedures that are very much 14 practical advice to the operator. They look at what's 15 the quality of your injection source? I don't want to 16 inject in pure water, if I have pure water inject.
17 What's happening in the core? Am I trying to keep the 18 core covered at all costs, or can I wait? These are 19 the considerations that go into making up the 20 emergency procedures, so knowing that we have --
21 operating plants have much higher debris source, they 22 have procedures that say -- and their safety systems 23 draw on the suppression pool and pump it into the 24 vessel. So, how we can be so far off in ESBWR from 25 having a backup system that can pump water into the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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145 1 vessel? So, if the tests that are done for the 2 operating BWRs or ABWR, which has active pumps drawing 3 on the suppression pool turn up a problem, we'll write 4 into our procedures wait for this period of time 5 before you pump from the suppression pool into the 6 vessel.
7 MEMBER BANERJEE: When are these 8 experiments supposed to be done?
9 MEMBER CORRADINI: I don't think they've 10 ever said. That's a leading question.
11 MEMBER BANERJEE: Well, he said that the 12 BWR Owner's Group --
13 MR. MARQUINO: The Owner's -- Jesus, do you 14 know anything about a schedule for Owner's Group 15 tests?
16 MR. DIAZ-QUIROZ: From what I've seen in 17 talks, I believe they mentioned 2010, 2011. We're 18 well past 2010 here, so it's -- I guess it's a 19 negotiation in progress as to when they're going to 20 get conducted. But I believe they say they will --
21 they have presented their analysis using TRACG, as 22 well, but, of course, testing came up, and I believe 23 they committed, but I don't think they settled on a 24 schedule.
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146 1 these analyses is two years ago we were presented with 2 analyses not with TRACG, but with something equivalent 3 for another system, not yours, which we were very 4 skeptical about, and asked them to go and do 5 experiments. Sure enough, the experiments showed, 6 unfortunately, that the analysis was not defensible.
7 MEMBER CORRADINI: I don't know about this 8 other analysis. Was this 100 percent blockage?
9 MEMBER BANERJEE: It was 99 percent, or 10 something. I've forgotten the number, but it's the 11 same vein, you know.
12 MEMBER CORRADINI: But if I might just 13 argue back briefly, but we have to have -- what I 14 thought Wayne was saying is you don't go below active 15 fuel. You have, essentially, his 100 percent is 16 16 channels, so you have, essentially, down flow from the 17 other channels and a common communication above this 18 pool. So, I thought that was the reason why they're 19 not -- why they compute it to not be --
20 MEMBER BANERJEE: In the other case, it was 21 cross-flow. So, there's always arguments.
22 MEMBER CORRADINI: Okay.
23 MEMBER BANERJEE: Unfortunately, 24 experiments are better than analysis.
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147 1 from you.
2 MEMBER BANERJEE: Yes, always. And you 3 believe that. When are these experiments due, 2011?
4 MR. MARQUINO: Yes, that's what Jesus Diaz 5 said.
6 MEMBER CORRADINI: Wayne, do you want to 7 wrap up?
8 MR. MARQUINO: I do. In summary, we have 9 passive systems that provide core cooling for 72 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br />, and keep the containment below it's design 11 pressure. After 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />, we have RTNSS systems that 12 can reduce the containment pressure. And we've 13 considered debris that might be injected through 14 backup systems. We have a suction strainer in the 15 backup system that's based on bounding debris loading, 16 and we'll provide adequate MPSH. And we've evaluated 17 what the effect of blockage would be by debris that's 18 pumped into the vessel on heat up, so we have a design 19 that provides long-term adequate core cooling with 20 margin.
21 MEMBER BANERJEE: So, if you go back to 22 that slide which you have, if you have 100 percent 23 blockage at the lower tie plate, then you say you can 24 have adequate cooling due to flows that come from 25 elsewhere somehow.
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148 1 MR. MARQUINO: Yes, holes that bring water 2 from the bypass into the fuel rod area.
3 MEMBER BANERJEE: And if you had 100 4 percent blockage at spacer number one, what happens at 5 that point?
6 MR. MARQUINO: Well, if you block spacer 7 number one, you're sealing off the bottom of the 8 channel box. Right? And then you're boiling, you'd 9 be boiling water there, and you'd have to have CCFL 10 breakdown to allow water to come in from the top. We 11 didn't evaluate that situation.
12 MEMBER BANERJEE: And the reason you think 13 100 percent blockage at the lower tie plate is more 14 likely is because the holes are smaller.
15 MR. MARQUINO: Yes. The debris filter is --
16 so, we have a debris filter that's trying to stop 17 things from getting into the fuel, so if it is being 18 swept up from the lower plenum, it's most likely to 19 get stopped at the debris filter.
20 Now, you probably won't like this answer, 21 but we have over 1,000 fuel bundles, so this debris is 22 not all going to accumulate at one bundle, or 16 23 bundles, as we assumed, it would be distributed.
24 MEMBER ARMIJO: But your orificed, right?
25 MR. MARQUINO: Right.
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149 1 MEMBER ARMIJO: So, some of the assemblage 2 will get more flow than others.
3 MR. MARQUINO: Yes.
4 MEMBER ARMIJO: So, those would be the ones 5 that would be more vulnerable. That would have been 6 the high-power assemblies.
7 MR. MARQUINO: The high-power -- yes, I 8 would say it's more than the high-power assemblies are 9 going to be drawing more flow in. Yes.
10 MEMBER BANERJEE: But you've taken the 11 debris, and you've assumed that it's only going to go 12 to 16 bundles, instead of --
13 MEMBER CORRADINI: Well, he didn't 14 transport the debris. I'm going to just interject, 15 because we have to move on. He didn't transport 16 debris, he just blocked 16 channels.
17 MEMBER BANERJEE: If I needed to block the 18 channels, what fraction of the debris?
19 MR. MARQUINO: So, again, we're tying back 20 to the operating plants which have this blockage on a 21 channel as their basis.
22 MEMBER BANERJEE: Well, I guess, Mike, you 23 can move on, but there are a lot of unanswered 24 questions here.
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150 1 have their time. I think we're a bit over, and I want 2 to hear what their view of this is.
3 MEMBER BANERJEE: Right.
4 MEMBER SHACK: Well, can I just ask one 5 more question, and it's the low-pressure injection. It 6 says it can take it from the suppression pool, or the 7 condensate storage. So, is the suppression pool the 8 third source? I mean, I do the passive system first, 9 then the condensate storage, then the suppression 10 pool?
11 MR. MARQUINO: For -- yes, from a purity 12 standpoint. However, as I mentioned, we have to look 13 at the containment pressure. And if we keep pumping 14 water in from condensate storage, and particularly if 15 we rely on the passive systems, that's not going to 16 work, so --
17 MEMBER CORRADINI: But how long can you do 18 it? I think that's part of what he's asking.
19 MR. MARQUINO: Well, for HPCRD, which has a 20 pretty low flow rate, I think it's like half an hour 21 we could use it.
22 MEMBER CORRADINI: From which tanks?
23 MR. MARQUINO: From an outside --
24 (Simultaneous speaking.)
25 MEMBER STETKAR: It's one scenario.
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151 1 MEMBER SHACK: It says low-pressure 2 injection can come from condensate storage. That's 3 what it says on the slide.
4 MR. MARQUINO: Right. So, that would --
5 MEMBER SHACK: I mean, you said you 6 wouldn't draw from the -- how -- what would be the 7 earliest that you'd be drawing from the suppression 8 pool, I guess is the question?
9 MEMBER BANERJEE: He said 150 seconds.
10 MEMBER SHACK: No, no, no. That's when the 11 pressure lets him do it.
12 MEMBER BANERJEE: Okay.
13 MEMBER SHACK: He has to make a decision to 14 do it at any time.
15 MR. MARQUINO: Okay. So, your question is 16 --
17 MEMBER SHACK: Yes, I want to stop drawing 18 from the suppression pool, so I can --
19 MR. MARQUINO: Okay. I understand your 20 point. I understand your point, but I think there 21 would be a decision made to transfer over to the 22 suppression pool just from the standpoint of 23 containment pressure. In other words, if I have my 24 reactor water level under control, and now I can 25 probably throttle back, and that would be the time I NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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152 1 want to look into -- another thing I didn't mention is 2 -- well, I don't want to get into too much of the 3 staff's time.
4 MEMBER CORRADINI: No, you don't.
5 MR. MARQUINO: We had -- we marked up the 6 DCD drawing showing the different flow paths. That 7 was a request from the Committee. And in terms of 8 when we would transfer over, if you had the water 9 level under control in the reactor, you would go into 10 suppression pool cooling mode to remove heat from the 11 containment. And you'd be circulating water from the 12 pool back to the pool, rather than from the pool into 13 the vessel.
14 MEMBER SHACK: But you don't have a time 15 for that.
16 MR. MARQUINO: And that's, actually, in 17 Chapter 6, where we said in terms of containment 18 cooling, we'll do that at like 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> to decrease 19 containment pressure.
20 MEMBER CORRADINI: I'm sorry, Sam. So, to 21 answer Bill's question, at this point, one would have 22 to think about, and answer this question about the 23 minimum time before you had to switch over.
24 MEMBER SHACK: He said 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.
25 MS. CUBBAGE: There's no requirement to NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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153 1 switch over. The design basis does not require use of 2 any -
3 MEMBER CORRADINI: I understand that. I 4 didn't mean to imply that. I meant more to clarify 5 what you were asking.
6 MEMBER SHACK: Well, I'm still not -- yes, 7 because I can do this, it's still not clear to me at 8 all when I start throwing these other systems.
9 MR. MARQUINO: I'm not required to inject 10 with these systems. If the other system -- if there 11 are multiple failures and the other systems didn't 12 work, then I'm going to inject as long as I need to 13 get water over the core. When I have water over the 14 core, now I can think, okay, what am I going to do?
15 Do I want to cool the pool now, and only make up as 16 needed to keep level over the core? That's where the 17 emergency procedures will provide guidance.
18 MEMBER ARMIJO: Okay. I just have one -- a 19 different kind of blockage. I just wanted to ask if 20 you evaluated the GDCS plate that you have these holes 21 in the steel plate in order for the GDCS to drain 22 properly. Have you evaluated the potential for 23 blockage of those holes, so your GDCS doesn't work the 24 way it's supposed to? Is that totally out of the 25 question?
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154 1 MR. MARQUINO: So, we're keeping the debris 2 out of the GDCS compartment with this perforated plate 3 that we discussed. And there isn't a strainer on the 4 GDCS from the pool, and that -- the purpose --
5 intentionally, so we don't want things that got 6 through those small holes blocking up another strainer 7 inside the GDCS --
8 MEMBER ARMIJO: I'm not talking about 9 blocking those holes, so that --
10 CHAIRMAN ADBEL-KHALIK: We talked about 11 that earlier, Sam, and they said they are going to 12 place the holes in such a way that they would not be 13 blocked. I asked that question earlier on.
14 MR. DIAZ-QUIROZ: Right.
15 MEMBER ARMIJO: I was following up on your 16 question. I guess I didn't understand. They said 17 there were very few holes, and they were going to 18 locate them somewhere that's favorable --
19 MEMBER SHACK: Very few holes needed.
20 MR. MARQUINO: Right. And they won't be in 21 the zone of influence of main steam line break, for 22 example.
23 MEMBER ARMIJO: Okay. Thank you.
24 MEMBER CORRADINI: Thank you.
25 MEMBER STETKAR:
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155 1 MR. MARQUINO: All right. Thank you.
2 MEMBER CORRADINI: And we will now have the 3 staff. Amy, do you want to say anything to prepare 4 us?
5 MS. CUBBAGE: I think they're just going to 6 go ahead and start.
7 MEMBER CORRADINI: Okay.
8 MS. CUBBAGE: Would you like them to do an 9 accelerated presentation to stay on your --
10 CHAIRMAN ADBEL-KHALIK: Right now we're 11 scheduled to end at 2:45, but I think we can go until 12 3.
13 MEMBER CORRADINI: Good.
14 MS. CUBBAGE: Okay.
15 MR. BAVOL: My name is Bruce Bavol. I'm the 16 Chapter PM for this issue, and we'll get right to it.
17 This is Henry Wagage. We have James Gilmer, and 18 George Thomas, who's going to be presenting. And 19 we've got about eight slides to present to you.
20 MR. WAGAGE: My name is Henry Wagage. We 21 are here to present how the staff reviewed the 22 evaluation of ESBWR long-term cooling following a loss 23 of coolant accident.
24 We had several interactions with the ACRS 25 on this topic. In December of last year, we made a NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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156 1 detailed presentation to the full Committee on 2 containment long-term cooling. We were unable to 3 close this issue at that time. The reason was that we 4 did not have results of GEH final calculation 5 reflecting the assumptions as described in the DCD.
6 Later we received the GEH TRACG results consisting of 7 description of the plant as described in the DCD.
8 After reviewing GEH long-term containment cooling 9 evaluation, the staff accepted the GEH evaluations, 10 and the issue is now closed.
11 In July of this year, we made a 12 presentation to the ESBWR Subcommittee on closing of 13 long-term containment cooling issue. These are the 14 regulatory criteria applicable to ESBWR long-term 15 cooling. Using the next two slides, I'll be 16 discussing long-term containment cooling. After that, 17 George Thomas and Jim Gilmer will be discussing long-18 term core cooling.
19 MR. BAVOL: I'd also like to inject, this 20 is Bruce Bavol. On the slides, you'll be noticing 21 that on the bottom it says "Official Use Only, 22 Proprietary Information," that information has been 23 verified by GEH not to be proprietary. The whole 24 presentation, that's just for the benefit of everybody 25 else who's in the room.
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157 1 MR. WAGAGE: The staff based its acceptance 2 of GEH containment, at least in part, on our 3 confirming the calculation done with MELCOR computer 4 code. This plot shows an enlarged view of events 5 occurring during the first 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> for main steam 6 line break bounding analysis. Seventy-two hours 7 correspond to the highest peak on this red curve. The 8 events shown here from left to the right, top vent 9 opening releasing steam and uncontrolled gases from 10 the drywell to the wet well, isolation of the reactor 11 pressure vessel, initiation of GDCS flow to the 12 vessel, in break actuation sending some of the non-13 condensable gases and steam back to the wet well. The 14 assumption of boiling in the reactor pressure vessel, 15 and PCCS start up, and starting of PCCS vent fans at 16 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.
17 The next slide I'm comparing MELCOR 18 component analysis results for dry well pressure to 19 the GEH TRACG results. TRACG is shown here for 20 analysis using the conditions and assumptions as 21 described in the ESBWR DCD. We have a fairly good 22 agreement between MELCOR and TRACG results for the 23 first 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. Immediately after 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />, when vent 24 fans start increasing the heat transfer rate from the 25 PCCS, resulting in rapid drop of containment pressure.
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158 1 MELCOR predicts lower pressure drop than TRACG. This 2 difference can result from differences in heat 3 transfer caused by deviations in distribution of non-4 condensable gas in the PCCS tubes, as calculated by 5 the two codes.
6 Following the pressure drop after 72 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br />, MELCOR results show steady pressure, and TRACG 8 results show gradually decreasing pressure. Apart 9 from the pressure drop at 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />, MELCOR and TRACG 10 results have reasonably good agreement. Both MELCOR 11 and TRACG results are below the containment design 12 pressure. Based on the staff review of TRACG 13 evaluation, and staff's confirmatory MELCOR 14 calculations, the staff determined that GEH long-term 15 containment cooling evaluation acceptable.
16 Next, George Thomas will discuss ESBWR 17 long-term core cooling.
18 MR. THOMAS: My name is George Thomas. I 19 want to talk about the core cooling water. First, I 20 want to talk about the GDCS pool. We've got stainless 21 steel liner and the top, the ceiling between the top 22 wall on the ceiling is very small, and there is a 23 small opening there, call it perforated steel, and got 24 a very small -- small size of only 1.5 inches. So 25 there is no --
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159 1 MEMBER BLEY: I thought they said it was .8 2 meters above?
3 MR. THOMAS: Yes, I said --
4 MEMBER CORRADINI: No, but you've got .8 5 feet.
6 MR. THOMAS: Yes, in feet.
7 MEMBER CORRADINI: Well, is it meters or 8 feet? I think is what --
9 MEMBER BLEY: They said meters earlier.
10 MR. THOMAS: Okay. I will check that.
11 MEMBER CORRADINI: You need a little --
12 MEMBER SHACK: How about the holes in the 13 perforated plate at 1-1/2 inches?
14 MR. MARQUINO: I defer to the staff. I was 15 going by their slide when I incorrectly remembered it 16 as meters, not feet.
17 MEMBER CORRADINI: Okay. Let's try the 18 other dimension before you leave that microphone.
19 MR. MARQUINO: Okay. The 2.5 millimeter 20 was on a GE slide.
21 MEMBER CORRADINI: Well, I think what we're 22 trying to make sure about is just to be consistent.
23 It's .8 feet is the clearance into the region of the 24 drywell where the GDCS pool is located. That's 25 correct. Are we correct in assuming that?
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160 1 MR. MARQUINO: Yes, and I'll check on both 2 of those numbers for you.
3 MEMBER CORRADINI: Thank you.
4 MR. THOMAS: The copy of the 4.4-23 and 5 they show the number, .804 feet and 1.5 inches right 6 here.
7 MEMBER CORRADINI: Okay. Thank you.
8 MR. THOMAS: Okay. Now, because of this, 9 we think there is no potential for significant 10 accumulation of debris into the GDCS pool. Okay. Now 11 I want to talk about the suppression pool. This also 12 -- stainless steel liner, and you've got the strainer 13 for the pump system, and there is a periodic cleanup 14 of the suppression pool by the pump system. So, 15 normally, the water quality of the suppression pool 16 will be much better than in the current operating 17 plants. Okay.
18 Now I want to talk about the alternate 19 sources other than these two pools. The CRD pump, you 20 can inject into the reactor. It's about 1,000 gpm, and 21 the tank's typically about 300,000 gallons normally, 22 so it's a big pool of water, very clean demineralized 23 water is available. And it is located outside the 24 containment. Also there is a connection between the 25 fire system and the FAPCS, so as a last resort you can NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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161 1 even inject water through to the reactor.
2 So now Jim Gilmer will talk about the core 3 cooling aspect of this issue.
4 MR. GILMER: Good afternoon. I was lead 5 reviewer for the downstream fuel effects for the 6 ESBWR, as well as TRACG computer code.
7 Staff, basically, agrees with GEH that the 8 water level for any design basis accident will always 9 be above the top of active fuel independent of debris 10 blockage. And the staff did have a concern of -- a 11 couple of concerns. One was what is the effect on the 12 critical pole through the limiting bundle. There was 13 actually a calculation that GEH performed that is not 14 mentioned earlier, which developed a plug for in that 15 orifice blockage or percent blockage versus -- for the 16 inlet orifice, and for the lower tie plate. I did not 17 include that as a slide, because it was proprietary --
18 19 MEMBER BANERJEE: The third bullet here, 20 are you going to speak to that?
21 MR. GILMER: Yes.
22 MEMBER CORRADINI: So you can't, or you 23 didn't show it because of proprietary nature, but can 24 you say again what you reviewed? I didn't completely 25 understand.
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162 1 MR. GILMER: Yes. We asked in I believe 2 several, not one, of RAI 4.423 to provide staff a 3 curve of what percent blockage could, or what -- would 4 be for various percent blockages.
5 MEMBER CORRADINI: Okay.
6 MS. CUBBAGE: That RAI response was 7 provided to Chris, and we could show you at the break.
8 MR. GILMER: Right. There are actually --
9 the original RAI 4.423, as well as four supplements.
10 And I believe you have all of those.
11 Mr. Marquino mentioned earlier that the 12 outcome of that -- demonstrated that you could take up 13 to about 75 percent blockage of the limiting bundle, 14 and still have acceptable mixture. So, that was the 15 first calculation, and then the second one, Mr.
16 Marquino also talked about the concern of the blocked 17 channel group, the 16 bundles, what happens with the 18 spill flow from the top from the counter current flow, 19 so the TRACG calculation shows that actually the peak 20 clad temperature is the initial temperature. Okay?
21 And that was on a previous slide presented in the GH--
22 MEMBER BANERJEE: So, how much material is 23 required to form this blockage? One of the issues 24 that arises with BWRs is it needs very, very little to 25 completely block a channel.
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163 1 MEMBER CORRADINI: Say again, Sanjoy.
2 MEMBER BANERJEE: How much material is 3 required to block? I mean, that's the estimate I've 4 been trying to find.
5 MR. GILMER: We did not quantify that. We 6 just assumed the loading channel group, and block it 7 100 percent.
8 MEMBER BANERJEE: Right. As you know, 9 downstream effects in the core are very complex.
10 Sometimes you see blockage at several levels, and 11 sometimes you see it at one level. Sometimes you see 12 it at the inlet, sometimes you see it up in the 13 channel.
14 MEMBER CORRADINI: Sanjoy, if -- -
15 MEMBER BANERJEE: I'm asking how much is 16 needed to block one of the channels.
17 MEMBER CORRADINI: I don't think they know.
18 CHAIRMAN ADBEL-KHALIK: If one were to do a 19 simple calculation, and assume that you 1,000 gpm 20 water coming in, and that water is coming down the 21 downcomer and up through the core and lower plenum, 22 the average inlet velocity in the core is less than 23 one centimeter per second. And, therefore, I would 24 suspect that anything suspended within that water 25 that's coming in would, ultimately, settle in the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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164 1 lower plenum, rather than accumulating on the filters.
2 The velocity is just way too low.
3 MR. GILMER: Actually, ESBWR is better in 4 that regard than conventional BWRs because the upward 5 velocity would be like a factor of four lower than --
6 MEMBER BANERJEE: So, the upward velocity 7 would be what, centimeter per second?
8 MR. GILMER: Approximately. And keep in 9 mind that it would be mostly RMI shards, which 10 probably gravity would offset the upward flow, so most 11 of it would tend to accumulate in the --
12 MEMBER BANERJEE: And there wouldn't be 13 much fiber?
14 MR. GILMER: Well, it was limited to, I 15 believe, one cubic foot consistent with the Owner's 16 Group --
17 MEMBER BANERJEE: So, there's one cubic 18 foot in the core, I mean, in the vessel. Where is 19 that one cubic foot?
20 MEMBER SHACK: In containment.
21 MEMBER BANERJEE: In the containment. So, 22 very little of that is in the vessel, itself.
23 MR. GILMER: Some fraction of it will be --
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165 1 blocked the limiting bundle.
2 MEMBER CORRADINI: I think your question, 3 the initial question you were asking cannot be 4 answered, which is a correlation between how much is 5 there to block what it was assumed, which I think is 6 where you started.
7 MR. GILMER: And GEH has committed the 8 Owner's Group test program, which also is 2011, and 9 because the -- is virtually identical -- well, it is 10 identical for the lower top region, in that orifice, 11 and the grid spacers, we believe that any indication 12 or conclusions from those tests would be applicable to 13 the ESBWR, or would bound the ESBWR because of other 14 reasons, such as this design does not uncover the 15 core. And you have only RMI, some latent debris, and 16 the upper velocity is low compared to conventional 17 BWRs. And, also very limited access pathway into the 18 GDCS pool.
19 Now, I believe Supplement Three of the RAI 20 423 did actually consider inadvertent actuation of the 21 -- motor -- and there's, again, sequence in there. I 22 think Mr. Marquino mentioned that, effectively, we 23 would not inject into the core until about 150 seconds 24 -- when the vessel pressure drops down to the point 25 when the pumps can offset it.
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166 1 So, basically, on that bullet in the 2 slide, staff concluded that core cooling can be 3 maintained even with the limiting bundles between the 4 block. The TRACG calculation did actually consider 5 the up flow of the blow off and then the down flow 6 from the upper plenum from unblocked bundles -- and, 7 also, the same TRACG was used for the model we --
8 limiting steam break -- the confirmatory calculations 9 that have already been discussed.
10 So, in conclusion, we believe the ESBWR 11 design is acceptable for the GSI-191 concern with 12 considering the commitment of the future Owner's 13 Group.
14 MEMBER BANERJEE: So, suppose instead of 15 the lower tie plate, the first spacer was 100 percent 16 blocked, would you come to that same conclusion?
17 MR. GILMER: I believe yes because if the 18 bundle is blocked from the bottom at any location, you 19 will still get cascade flow from the top, from --
20 MEMBER BANERJEE: Well, the first spacer is 21 100 percent blocked.
22 MR. GILMER: Yes.
23 MEMBER BANERJEE: Would you still think it 24 would be --
25 MR. GILMER: We have not done a detailed --
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167 1 model for that specific scenario.
2 MEMBER BANERJEE: Did you do any 3 confirmatory analysis of this?
4 MR. GILMER: No, we're relying on the GE 5 calculation. Now our Office of Research did do some 6 Trace confirmatory calculations, and one of the 7 Subcommittee meetings we -- they presented the --
8 comparison of the -- versus the built-in correlations 9 in Trace. And I didn't bring it, but that was not for 10 a blockage scenario.
11 MEMBER CORRADINI: Sanjoy.
12 MEMBER BANERJEE: I feel uneasy about this 13 whole thing.
14 MEMBER CORRADINI: I sense that.
15 MEMBER BANERJEE: Yes. I mean, it's not --
16 I was hoping it would be put to bed.
17 MEMBER CORRADINI: I want to make sure that 18 first we ask -- make sure the staff, if we ask 19 questions of the staff, and then we can either take 20 the time now or later when we discuss where to go with 21 this. But do we have questions for the staff? John?
22 MEMBER STETKAR: Not for the staff. I have 23 a clarification from GE.
24 MEMBER CORRADINI: Well, Wayne. Staff can 25 stay, Wayne get to a mic. Sorry, please get to a mic.
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168 1 MEMBER STETKAR: Dr. Shack raised the 2 question, and we had some discussion about timing and 3 operator proprieties, and things. And your Slide 5 4 says "fuel in auxiliary pool cooling system RWCU can 5 provide low-pressure injection from either the 6 suppression pool, or the condensate storage system."
7 I didn't remember an injection suction line from the 8 condensate storage system, and I've been looking for 9 one for the past 10 minutes, and I can't find one.
10 Can you tell me how you can line up low-pressure 11 injection from the condensate storage system through 12 either RWCU or fuel in auxiliary pool coolant?
13 MR. HAWKINS: Let me look on the --
14 MEMBER STETKAR: I know CRD. You mentioned 15 CRD, but that's a small capacity --
16 MEMBER CORRADINI: So, that's a point --
17 that's a question he's going to have to investigate.
18 MEMBER STETKAR: That's a question for 19 clarification, only because -- but it could be an 20 issue in terms of looking at how the operators would 21 align things.
22 MEMBER CORRADINI: Other questions for the 23 staff while Wayne researches John's question?
24 MEMBER BANERJEE: I actually have a 25 question for Wayne.
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169 1 MEMBER CORRADINI: Go ahead, Sanjoy.
2 MEMBER BANERJEE: Wayne, the question I 3 asked, maybe I didn't get a clear answer was, suppose 4 we had 100 percent blockage at the first spacer, then 5 would you be able to meet cooling requirements, or 6 not? Maybe you answered that question.
7 MR. MARQUINO: It would depend -- well, I 8 didn't give you a yes or no answer. I said it would 9 depend on CCFL breakdown at the -- for the water 10 coming in from the top, and that depends on the 11 timing, also. Because you progress out in time, your 12 power generation in the channel is dropping, and your 13 steam generation is dropping, and it's possible to get 14 that flow back in the top. So, we have not done an 15 evaluation of what time in the LOCA you could tolerate 16 100 percent blockage somewhere in the bottom of the 17 fuel channel.
18 MEMBER BANERJEE: So, if this was a very 19 short time, it would set my mind somewhat at rest. If 20 it was a long time, the condition continued, that 21 would be a different matter.
22 MEMBER CORRADINI: I want to understand 23 your thinking process. You're thinking about if you 24 had a blockage, and then you have counter current flow 25 that would replenish the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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170 1 MEMBER BANERJEE: Oh, no.
2 MEMBER CORRADINI: Oh.
3 MEMBER BANERJEE: He's explained it very 4 well, actually, because there is no exact answer to my 5 question. But after that time when you are in 6 trouble, and when you're out of trouble, how long, is 7 it minutes, is it seconds? That's what I don't know, 8 is it an hour?
9 MR. MARQUINO: I can't guess at it.
10 MEMBER BANERJEE: Yes. So, I think that is 11 sort of the issue. It would be different if it was a 12 couple of minutes, instead of three hours, or 13 something. All right. I think you have tried to 14 answer it, but there is no clear answer.
15 MEMBER CORRADINI: Other questions for 16 staff? And we have a couple of clarifications for 17 John, and I think, Sanjoy, you had one relative to --
18 I have written it down somewhere, but I think John's 19 clarification we have yet to get. Right?
20 MEMBER BANERJEE: Well, other than just to 21 know how much would pass through the --
22 MEMBER CORRADINI: I'm sorry. And there's 23 -- I don't think there's going to be a clear answer 24 for that here. There is no experiment to answer that 25 question.
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171 1 MEMBER BANERJEE: On these filters.
2 MEMBER CORRADINI: On these filters.
3 MEMBER BANERJEE: Yes, but there are 4 answers for other types of filters.
5 MR. MARQUINO: There was an RAI asked by 6 the staff that I can refer you to with more details on 7 the debris loading on the suction strainer.
8 MEMBER CORRADINI: Is this RAI 4.4023 as 9 we've gotten some supplements of it, Wayne?
10 MS. CUBBAGE: 6.2173?
11 MR. MARQUINO: It was 6.2173, I think. And 12 Part J of it included the suction strainer MPSH 13 pressure drop from debris.
14 MEMBER BANERJEE: That was based on these 15 old experiments you referred to. Right?
16 MR. MARQUINO: Yes.
17 MEMBER BANERJEE: So, at that point, there 18 was no measurements made of what went through, as 19 well.
20 MR. MARQUINO: Yes, the focus is on 21 blocking the strainer, and the pressure drop caused by 22 that. Yes.
23 MEMBER BANERJEE: All right.
24 MEMBER CORRADINI: If you want that, 25 Sanjoy, we have it for you, if you want to look at it, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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172 1 the RAI which he spoke of.
2 MEMBER BANERJEE: No, I'm not concerned. I 3 think the pressure losses are not going to be very 4 bad.
5 MEMBER CORRADINI: Thank you very much to 6 the staff. I'm going to turn it back almost on time 7 to the Chairman.
8 CHAIRMAN ADBEL-KHALIK: That's okay. Thank 9 you. Well, at this time, we will take a 15-minute 10 break. We will reconvene at 3:15 to go to Item 5 on 11 the agenda.
12 (Whereupon, the above-entitled matter went 13 off the record at 2:58 p.m., and went back on the 14 record at 3:12 p.m.)
15 CHAIRMAN ABDEL-KHALIK: We're back in 16 session. At this time we will go to Item No. 5 on the 17 agenda, License Application for the Mixed Oxide (MOX) 18 Fuel Fabrication Facility and the Associated Safety 19 Evaluation Report. And Dr. Powers will lead us 20 through this.
21 MEMBER POWERS: At this point, we're going 22 to switch gears rather radically to go to a completely 23 different facility licensed under a completely 24 different set of regulations. And that's going to 25 pose a bit of a challenge to the Committee and to our NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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173 1 presenters because whereas some members of the 2 Committee were present when this facility first came 3 to us for the construction from that. Most of the 4 members this is all going to be very new to you.
5 What we are discussing is the MOX Fuel 6 Fabrication Facility and as many of you undoubtedly 7 know this is a facility to fabricate mixed oxide fuel 8 for use in commercial reactors where the plutonium 9 content of that fuel comes from the nation's weapons 10 grade plutonium stockpile. And the facility is to 11 purify that plutonium and then convert and make the 12 mixed oxide fuel.
13 It is a relatively small system. It 14 requires -- The process does require that the 15 plutonium be purified but not purified as you would 16 spent fuel. It is purified of a small amount of 17 americium contamination and perhaps some gallium 18 contamination, relatively small, maybe a few other 19 things. It's not a complete fission product load like 20 you would in the case of reproduced fuel and a 21 relatively small amount is going to be processed 22 something along the order of a little over 30 metric 23 tons.
24 Consequently, it is a relatively simple 25 purification step. The fuel fabrication step is not NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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174 1 wildly different than you are familiar with for most 2 fuel fabrication plants.
3 The facility is patterned I would say 4 after a facility that has been operational for spent 5 fuel fabrication in France or maybe patterned is not 6 the right word but inspired by the French facility.
7 So it is not like it's an ad hoc sudden appearance of 8 a processing facility out of nothing. It in fact has 9 somewhat of a pedigree.
10 The waste from the facility will in fact 11 be transmitted and given to the Department of Energy.
12 So our concerns over waste coming from the fuel 13 processing facility is somewhat limited.
14 The challenges that the facility posed, of 15 course, are like many fuel reprocessing facilities.
16 There are issues of criticality and there are issues 17 of fire. Criticality is, of course, a disciplined 18 field and many of the criticality concerns can be 19 handled in a conventional field. The one exception to 20 that I think is the issue of plutonium hydroxide 21 precipitation in the process.
22 Fire, the potentials for fire in this 23 facility arise because it's a solvent extraction 24 process so that it has a hydrocarbon that's 25 combustible. Many of you are familiar with the red NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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175 1 oil issue. Some are familiar with hydroxylamine 2 nitrate issues. Ammonium nitrate. There is potential 3 for cladding metal fires. Hydrogen azides.
4 These and many of the other issues were 5 raised when the Committee first looked at it at the 6 construction permit side and we asked the applicant to 7 address those issues. We held a subcommittee meeting 8 in which the applicant went through in some detail on 9 how he had addressed those issues.
10 What our objective today is in fact to 11 review the staff's SER of what they're doing for the 12 licensee for this facility. However, the licensing 13 process is a little strange here in that it seems to 14 go on forever and licensing is not immanent here.
15 This is a critical part in the process. I think what 16 we should look for is making a judgment of whether 17 this facility can be constructed and operated with no 18 undue risk to the public health and safety.
19 Now public health and safety is a 20 complication. The facility is being located on the 21 Savannah River site which means a member of what we 22 generally consider of the public is displaced a 23 substantial distance from the facility. But for the 24 purpose of this I think it's useful to consider the 25 employees at the Savannah River site not directly NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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176 1 involved in this facility to be the public.
2 Okay. As I've said, this is radically 3 different from a reactor. It's a license under a 4 radically different regime. I have asked the staff 5 and the licensee to come and give us more, a fairly 6 high level of background issue presentation here.
7 I've asked them to cram ten pounds of information into 8 a five pound time slot and given them also no guidance 9 on how to do that.
10 And so I hope the Committee with bear with 11 them. They've done the best they can under an 12 impossible situation. With that, let me turn to the 13 staff. Is there -- Did you want to make some 14 introductory stuff?
15 MEMBER RAY: Who's the applicant?
16 MEMBER POWERS: Well, the applicant is --
17 MEMBER RAY: I read the logo.
18 (Laughter.)
19 MEMBER POWERS: I'll let the applicant 20 explain.
21 MEMBER RAY: Is it supposed to be a secret 22 or what?
23 MEMBER POWERS: I will let the applicant 24 explain all this. It is -- The facility is being 25 developed for the Department of Energy under a NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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177 1 consortium of individuals.
2 Did you want to make some opening 3 comments?
4 MR. CAMPBELL: I'll make it. This is 5 Larry Campbell. I'm the Branch Chief of the Mixed 6 Oxide and Deconversion Branch and Fuel Cycles. To 7 answer your question, MOX Services is the applicant 8 and MOX Services will be making a presentation today.
9 First of all, a lot of time, a lot of 10 effort, both by MOX Services and the staff over the 11 last several years. As a matter of fact, I can 12 remember not even being in NMSS and assisting on 13 preparing the review plan about ten years ago when it 14 started.
15 So today we hope to answer all your 16 questions and at the end of presentations we hope that 17 the Committee has a very warm feeling that our SER and 18 our conclusions we've reached that they are 19 appropriate. And with that I guess MOX Services will 20 make a presentation followed by the staff.
21 And again we had two days of presentations 22 before the Subcommittee. We addressed several areas.
23 And I feel that was successful and hopefully we will 24 get the Committee's approval to proceed with the 25 issuance of the SER today keeping in mind that the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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178 1 security portion will not be discussed here in this 2 presentation.
3 Thank you.
4 MEMBER POWERS: An additional 5 introduction, the regulations require the ACRS to 6 review the safety issues of that and because of the 7 context of the wording and whatnot I've kind of made a 8 judgment that we're looking not at the security 9 issues, but really the safety, classic safety, issues 10 of that.
11 With that, I think we can -- Sven, are you 12 going to start us off?
13 MR. GWYN: I'm going to introduce things 14 and then Sven and Scott and Bill are actually going to 15 do all the real work here.
16 MEMBER POWERS: All right.
17 MR. GWYN: My name is --
18 MR. HENNESSY: Before we get started, MOX 19 Services is an LLC consisting of mostly two-thirds 20 Shaw owned, Shaw Group, the old Stern Webster 21 organization, and one-third AREVA organization.
22 MEMBER RAY: Thank you. That's what I was 23 looking for. How long has it existed?
24 MR. HENNESSY: Since the beginning of the 25 project 1999.
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179 1 MR. GWYN: My name is Deatis Gwyn. I'm 2 the Licensing Manager. For our portion today, we're 3 going to go over an overview of the MOX facility.
4 Sven Bader is going to go over the aqueous polishing 5 part of the facility. Scott Salzman is going to go 6 over the MP. Bill Hennessy is going to give you a 7 very high level overview of the process we use to 8 develop the Integrated Safety Analysis. And as sort 9 of alluded to earlier, there was some issues or 10 questions at the CAR and we're going to provide sort 11 of a capsule summary of some of those at the end.
12 Sven and Scott are going to do that.
13 With that, I'm going to turn it over to 14 Sven Bader to go over the AP process.
15 MR. BADER: I'm Sven Bader. I've been on 16 the project since its inception in 1999. Had a lot of 17 hair at the beginning. A little less now.
18 (Laughter.)
19 The AP process is probably the most 20 interesting portion of the whole facility, but it 21 takes up a very small fraction. It's represented by 22 the tank blocks. The next slide, Deatis.
23 The overall outline of the MOX process is 24 basically we start off with the PuO2 which is from two 25 feet stocks of the PDCF, pit disassembly and NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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180 1 conversion assembly, and the alter feedstock. The pit 2 disassembly and conversion facility --
3 MEMBER POWERS: You may want to explain 4 that pit facility is a DOE facility that supplies this 5 material and not a part of this application.
6 MR. BADER: Right. And it's not built 7 yet. So we're working from an alternate feedstock to 8 start with. It's material that DOE has on the shelf 9 that we feel is capable of being processed through our 10 facility.
11 The PuO --
12 MEMBER SHACK: Could you handle real MOX?
13 I mean, real MOX. You know a feedstock coming from 14 a light water reactor fuel.
15 MR. BADER: No, not right now because we 16 don't have any design for fission products.
17 MEMBER SHACK: Okay. I mean you were --
18 There's no cooling tanks for fission. There's no 19 chopping unit.
20 MR. BADER: No.
21 MEMBER POWERS: This is very substantially 22 simplified relative to handling fission product laden 23 material.
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181 1 that we would need for fission products. But we just 2 don't have the front end of that process that they 3 have at La Hague.
4 PARTICIPANT: Reactor grade.
5 MR. BADER: The PuO2 will then be 6 dissolved --and I'll go through these in a little more 7 detail -- through a nitric acid bath in an 8 electrolyzer. Then we'll purify to remove the 9 americium and gallium principally and then separate 10 the uranium in another step.
11 Then we'll convert it from P. nitrate to 12 P. oxalate. And then the Pu oxide in a CalSil 13 furnace. From there we'll get powder. And then it 14 goes into the boring MP process which Scott will 15 discuss here in a little bit. We can go to the next 16 one.
17 This is an overlay. Why don't you go to 18 the next one. We're going to keep that slide up over 19 here. So I'm going to walk through this while Deatis 20 tries to keep up with the process description.
21 We start up in the upper lefthand block here 22 which is the dechlorination and dissolution and the 23 slides in the middle describe the dechlorination and 24 dissolution. Basically, the feedstock comes in. We 25 pour it into an electrolyzer and depending on the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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182 1 contents which we've analyzed up front you know we 2 don't let the PuO2 until it meets our specs into the 3 process.
4 Once it meets the specs, we know the 5 chlorine content. It dictates what the next steps 6 are. If there's a high chlorine content, we'll put it 7 into the dissolver. Before we add any silver, we will 8 run the electrolyzer to remove the chlorine through 9 the dissolution process.
10 Then we'll add the silver nitrate, 11 continue the electrolyzer and eventually we're putting 12 the Pu into solution. And it becomes Pu6 valance 13 state nitrate.
14 The chlorine that is removed from the 15 process gets treated and in the end comes out as 16 sodium chloride. The plutonium that's been dissolved 17 with the silver gets adjusted with hydrogen peroxide.
18 The hydrogen peroxide will reduce the Pu from six to 19 four valance state and the silver from two to one.
20 And principally the silver reduction is for corrosion 21 reason, to minimize corrosion. All this equipment up 22 to this point is made out of titanium.
23 The uranium isotopics are then adjusted 24 for criticality reasons for the down process when 25 uranium gets separated from the plutonium.
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183 1 From there -- again switch slides -- we go 2 to the purification process which is the most 3 interesting portion of the whole facility when the 4 main chemistry occurs. The plutonium and uranium are 5 first extracted in pulse columns. They're what we 6 call raffinates which is the gallium and the americium 7 and the other material that we don't want in the Pu 8 field, the MOX fuel in the end. The plutonium and 9 uranium and I'm following the main blocks here. This 10 is the main plutonium feeds path. The plutonium is in 11 scrub from aluminum nitrate, complexing fluorides that 12 might have been extracted. Plutonium is then 13 stripped. This is where we separate the uranium from 14 the plutonium. We add a hydronium nitrate solution to 15 the process putting the plutonium into the aqueous 16 phase.
17 The plutonium is then -- and we're 18 changing the valance state there from four to three.
19 We then come to the plutonium stripper column. Sorry.
20 That is the stripper column. Then we go to the 21 uranium scrubbing column which will be used for 22 certain alternate feed that has a lot of uranium in 23 it. This is basically another organic scrubbing here.
24 We then convert the plutonium from valance 25 state, oxidize it from valance state three back to NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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184 1 valance state four. Still in an aqueous solution.
2 And then subsequently there was the conversion unit.
3 The next slide.
4 We're first going to check to make sure 5 that we have reduced the plutonium and that we've 6 removed all the reducing agents, the hydrazoic acid, 7 the HAN, and that we don't have Pu(VI).
8 We then add oxalic acid to the process.
9 We're converting the Pu from Pu nitrate to Pu oxalate.
10 It's then going through a rotating filter with the 11 oxalate itself. It's been described as yogurt type 12 texture. It's now collected by the filter and then 13 dropped into the furnace.
14 The furnace then as far as the oxalate ion 15 it's got an oxide feed to it and oxidizing plutonium 16 to a Pu oxide. From there, we then go to the canning 17 unit, the homogenizer, where we sample to make sure we 18 have the correct material and make sure the moisture 19 content is correct for criticality reasons in a 20 storage unit downstream from that.
21 There are some support units as well.
22 Then we'll go to Scott's unit. We'll talk about that 23 in a minute. But I wanted to cover a couple of 24 support units because these are kind of important in 25 some latter discussions we'll have regarding red oil.
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185 1 We had a solvent recovery unit. We don't 2 use the solvent once. We do recycle in the process.
3 And to do that, we need to remove all the degradation 4 products that have occurred from the radiolytic 5 decomposition.
6 So we treat this in the solvent recovery 7 unit. It's mixer/settler with several stages. And I 8 should point out the uranium has already been 9 separated as well here. There's a uranium stripping 10 column here. So basically this unit, this display, 11 here is this unit right here. Uranium is removed with 12 a dilute acid solution and put into the aqueous phase 13 and then that's sent off to a waste unit.
14 The solvent treatment unit goes through 15 mixer/settler -- go back one, Deatis -- where we're 16 going to end up removing these degradation products 17 and those include the aside ions and the dibutyl 18 phosphate and monobutyl phosphate and then everything 19 that falls below that. And the hydrazoic acid itself 20 is treated, converted into sodium azide and then it's 21 treated into the waste unit.
22 From the conversion unit, we also have a 23 unit that's recovering any excess acid that came out 24 of that unit. And the reason we're talking about this 25 unit is there's an evaporator in this unit. And so NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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186 1 later on when we talk about red oil this is one of the 2 eight areas where there's a concern because this is an 3 elevated temperature unit. The bottom line here is we 4 have sampled up front to make sure the organic doesn't 5 reach her, this change in strategy from what we had in 6 the construction authorization to what we have now in 7 the IC summary.
8 This unit basically is destroying the 9 oxalic ions. The concentrates where any plutonium 10 that might have leaked through are sent back to the 11 front end of the purification cycle, back to the 12 extraction. The distillates are basically acid and 13 they're sent to the acid recovery unit which I believe 14 is the next slide.
15 The acid recovery unit is kind of a 16 collect-off of acids from various units in the 17 process. The main feeds though are from the 18 purification process. This is where the raffinates 19 have gone, so the gallium and the americium. And then 20 also the distillates from the oxalic mother liquor 21 recovery unit.
22 In this unit, what we're doing is we're 23 recovering nitric acid to recycle it back into the 24 process. And we do this through three stages, two 25 evaporators and one rectification column. Excess acid NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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187 1 from this unit would be sent off to the waste unit.
2 Another important unit related to venting 3 is our offgas unit. This unit is a continuously 4 operating unit supported with diesels. It is very 5 highly instrumented to make sure our pressures are low 6 in the process equipment. You know the philosophy on 7 the confinement is basically wherever we have the 8 plutonium the pressure is the lowest. And that way 9 all the flows are inward and not outward. The KWGs I 10 believe draws the strongest vacuum in the facility and 11 the debate is if the glove box units draw a stronger 12 vacuum.
13 The unit has got several IROFS. Those are 14 our important items relied on for safety. Sorry. So 15 I think it's different than what you're used to in the 16 reactor world. And as well as providing this low 17 pressure we're also cleaning the off-gases to remove 18 any kind of NOx fumes that are coming off our 19 dissolution units principally. Also describe any kind 20 of plutonium that might have been entrained in the 21 release of the gases.
22 And then finally we have our waste unit.
23 We have -- It's one main waste unit. It has three main 24 liquid streams: the high alpha waste which is where 25 the americium and the gallium have gone, the stripped NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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188 1 uranium which is basically the uranium that was in the 2 original feed that was diluted in the dissolution unit 3 and then separated in the purification process and 4 then low level waste which is a collection of 5 different waste streams from the labs principally and 6 it's mostly from rinsing areas.
7 So these terms, low level waste, we don't 8 actually do any classification or categorization of 9 the waste in our facility. They are all sent to the 10 Department of Energy through a waste acceptance 11 criteria.
12 I think that's --
13 MEMBER RYAN: Just for clarity, I think 14 it's fair to say that those definitions don't 15 necessarily line up with 10 CFR 61 or other NRC 16 classifications.
17 MR. BADER: Correct. Correct.
18 MEMBER RYAN: Okay. Thanks.
19 MR. BADER: And I think that's it.
20 MR. SALZMAN: We're on the dry side of the 21 process. My name is Scott Salzman. I work in the 22 Nuclear Safety Group.
23 A general block diagram here just to give 24 you an idea of our work areas here. We have a 25 receiving, a powder area, a pellet and assembly, rod NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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189 1 assembly areas. So what we do we receive plutonium 2 oxide and depleted uranium dioxide. We down-blow the 3 plutonium to a given percentage. We press out 4 pellets, load them in a rod and assemble that together 5 in assembly, package it up and send it out. And I'll 6 go through each one of these areas as we go along.
7 As I think somebody already said, our 8 reference facility is a MELOX facility over in France.
9 So we're kind of patterned after the MELOX facility.
10 Receiving area, we'll start there. We 11 receive depleted uranium dioxide and plutonium dioxide 12 from offsite. We store those. We empty those -- We 13 store those containers, empty those containers, get 14 ready to make powder. 3013 cans, we store those, 15 assay those, get ready in preparation for making 16 powder and go onto the --
17 Here's a little block diagram of our 18 receiving work unit. Our transportation come in. We 19 receive depleted uranium dioxide in 55 gallon drums.
20 It comes in and stored in our secured warehouse.
21 We move that as we need it from our 22 secured warehouse over to the main building. It's 23 stored in a buffered storage near the drum emptying 24 unit. Those cans are then opened in the drum opening 25 unit, introduced to flood boxes and are introduced to NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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190 1 powder area.
2 The plutonium dioxide comes in on SST, 3 safety secured transports. They're in 9975 shipping 4 packages and they're in a DOE 3013 container.
5 We bring those into the main building. We 6 unload the shipping packages, bring those on in to the 7 PuO2 receiving area. There we unload the cargo 8 restraint transports. Take these 9975s. We unpackage 9 those, unbolt those and remove the nested containers.
10 Remove the 3013 package. That's put on a conveyor 11 and run into the 3013 storage there. And it's a 12 storage area where we assay those cans, do some 13 calorimetry and some gamma counting. And we get ready 14 to introduce those in the AP process down there in the 15 aqueous polishing.
16 Bypass the aqueous polishing which we just 17 did we take our polished plutonium oxide powder. That 18 goes into PuO2 buffer storage. It's in two and a half 19 kilogram reusable cans at this point. It's stored in 20 our buffer storage and then we'll transport -- we'll 21 move those over into the powder area to start making 22 our powder.
23 Our powder area main functions we see the 24 uranium dioxide and plutonium dioxide powder and 25 produce a mixture of plutonium content suitable for NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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191 1 whatever campaign we're running. We blend that down 2 to 46 percent depending on what we need to do there.
3 Powder block diagram. From the receiving 4 area, we shuttle the reusable cans. Two and a half 5 kilogram cans of plutonium dioxide go to can emptying.
6 We remove the tops and we put those on a tilter.
7 They get dumped into a dosing hopper into primary 8 dosing.
9 The primary dosing also received depleted 10 uranium dioxide and some scraps as we recycle those 11 from the facility. We blend those into primary dosing 12 to about a 20 percent plutonium dioxide percentage.
13 That's our master mix.
14 All these units in the powder area sit 15 outside in big jar storage units. It's a big storage 16 unit where we have 80 kilogram, 60 kilogram, jars.
17 They're criticality safe jars and they run on 18 conveyors in and out of the jar storage of these 19 primary units on each side.
20 So once we get down-blend to 20 percent, 21 we also add some zinc stearate in the primary dosing 22 for pellet presses. It's a lubricant for pellet 23 presses.
24 We go to balling milling next. These J60 25 jars or 60 kilogram jars are attached to the ball NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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192 1 miller and we mill the plutonium to get the proper 2 grade characteristics. It's depleted uranium mill 3 balls. It comes back out of there and into final 4 dosing.
5 Final dosing we blend more scraps and 6 uranium dioxide to get down to our final plutonium 7 dioxide content, our final plutonium content. At that 8 point, we're back in the jar storage and then onto 9 homogenizing pelletizing. At homogenizing pelletizing 10 we add a pore former. We do a final homogenization of 11 powder and that's fed to the pellet presses where we 12 punch out green pellets. Those are loaded onto 13 molybdenum boats to get ready for centering to pass on 14 the pellet area.
15 The scraping processing, the scrap 16 milling, the scrap processing box where we process 17 scraps. We can crush rejected pellets. Those will 18 get milled to the proper frame characteristics and 19 then those are added back into the process. Okay.
20 So once we have our powder, our pellets 21 pressed out, we have several storage areas. We sinter 22 those pellets. We inspect the pellets and store them 23 to get ready to make rods.
24 Pellet block diagram. It's -- This 25 process area rotates around three storage areas.
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193 1 Green pellets storage, sintered and then ground and 2 sorted. So coming in from the powder area over here 3 on our left, they go to green pellet storage in 4 molybdenum boats. Those boats are fed into -- We have 5 two lines of sintering.
6 They're introduced into a sintering 7 furnace where they go into a preheat section about 950 8 degrees. Basically, removes the organics into a 9 sintering section about 1700 degree where we --
10 They're in a reducing atmosphere about four to five 11 percent hydrogen and then argon and a cool down 12 section.
13 We cool down out of the end of the 14 furnace, in the sinter pellet storage, then onto 15 grinding. There's a sinter grinding wheel where the 16 pellets are ground down to their required diameters 17 and on into the ground pellet storage where we do some 18 -- There's inspection and sorting units where we 19 inspect the surface and diameters and lengths. And 20 then there's a quality control where we actually 21 sample some of the pellets for plutonium 22 concentrations and other pellet ceramic 23 characteristics.
24 Once we have good pellets, ground and 25 sorted pellets, we come out and go to the rodding NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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194 1 area. At any point in this process where we reject 2 pellets, we come back to the scrap pellet storage and 3 those pellets go on back to the powder processing 4 area, that scrap processing, that little box, where 5 they can be crushed and recycled back into the 6 process.
7 Onto the rod area, we load our pellets 8 into a rod. Their end fittings are attached. We weld 9 them up and evacuate and fill them with helium.
10 The rod block diagram, from the pellet 11 area, we have rod cladding and decontamination. This 12 is where we bring the trays in and it's all in glove 13 boxes. They introduce the rod blanks. We bring the 14 pellets in the pellet trays and they form a stack and 15 line up the rod. The stack is pushed into the rod.
16 Then we take that rod and we install end fitting and 17 spring and goes to a welding glove box where we weld 18 the end fitting on.
19 Then we do a seal weld where we evacuate 20 the rod and backfill with helium and a little seal 21 weld is made. It goes onto a decon and contamination 22 checking where we clean up the rod. Once we verify 23 that it's free of contamination, the rods come out of 24 the glove box. This rod tray loading, we load the 25 rods on the rod trays and they go into the storage NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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195 1 area.
2 Now working in and out of the storage 3 area, we have several test units. We have a helium 4 leak test where we load the rods into a pressure 5 chamber. We evacuate the pressure chamber and check 6 for helium which gives us an indication we have a leak 7 in rod.
8 Then we go to an x-ray inspection. They 9 basically x-ray the rod and make sure the pellet stack 10 is correct, the spring is in there, the seal welds are 11 good, plume length. Everything is good.
12 It goes to rod scanning where they scan 13 the rod for plutonium content and make sure that's all 14 squared away. And then it goes to a rod inspection.
15 There are some laser inspections there and some visual 16 inspections.
17 And once we clear the rods, we're back 18 into the rod storage area. These are all in big rod 19 trays moved around as one tray, 32 rods to a tray.
20 We're onto the assembly area. The 21 assembly area is where we take all our individual rods 22 and assemble them into a fuel assembly. That's where 23 we receive the rods, put them altogether with assembly 24 components, inspect them, storage them, package them 25 up and ship them out.
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196 1 Assembly block diagram. From the rod area 2 we go to assembly mockup loading. That's where we 3 based on our run sheet and our campaign we bring in 4 rod trays to make up an assembly. Those rods are 5 pulled into a mockup. It's basically a 17 X 17 grids 6 where we load the rods into a mockup.
7 The mockup is then moved up to an assembly 8 table where on a big jig we have the grids all locked 9 in place on these assembly table. Fingers go through 10 and pull these individual rods from the mockup in 11 through the grids.
12 On the assembly table and assembly 13 fabrication unit once all the assemblies are pulled 14 through we pull the keys on the grids, attach the end 15 fittings top and bottom. And we up-end the completed 16 fuel assembly. And they move around on an overhead 17 trolley by this big assembly area.
18 We up-end that thing and we carry it over 19 to dry cleaning where we lower it into a pit. And 20 high pressure air blows any contamination or any small 21 filings we would have from the pulling process. Those 22 are cleaned out there.
23 We bring it back out of there. We go to a 24 couple inspection areas. The assembly dimensional 25 inspection we check for verticality, parallelism, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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197 1 envelope length, water gaps. They have some gauges 2 that they use there. There are some mechanical 3 sensors and some lasers do all the acceptance checks 4 on the assembly.
5 Then it goes for a visual inspection where 6 an operator with a camera inspects the assembly.
7 There's an IAEA plutonium probe that gets inserted at 8 that point for IAEA accounting purposes.
9 Once we have the fuel assembly inspected 10 and cleared it goes into an assembly storage and we 11 have areas where we store these rods. And as needed 12 we pull them out of storage.
13 They're brought in on the same monorail 14 into the assembly packaging area. We have a big 15 turntable that sits vertically and there's a strong 16 back on that turntable and a position for three 17 assemblies. We bring an assembly up to the strong 18 back, lock it in place and turn it and we load three 19 rods that same way. Once the strong back is loaded, 20 we down-end the strong back.
21 It gets slide horizontally into a shipping 22 package. The shipping package is then bolted up and 23 we install impact limiters and load that onto a truck 24 and onto the reactor.
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198 1 didn't remember hearing you talk about in the 2 subcommittee. Although NRC will be issuing you the 3 license, you also have IAEA safeguards on the 4 facility.
5 MR. SALZMAN: Yes. There's an IAEA 6 representative.
7 MEMBER POWERS: And we have not -- As you 8 know, we have not explored that aspect at the 9 facilities.
10 MEMBER BLEY: And other facilities we have 11 don't. I don't know what kind of an agreements exist 12 that don't come under IAEA. We do it ourselves. But 13 here we're doing it.
14 MEMBER POWERS: Well, we do get 15 inspections from the IAEA for nuclear facilities and 16 process facilities. In fact, I believe Calvert Cliffs 17 is undergoing its IAEA inspection this year or in the 18 next 12 months or something like that. But we don't 19 ordinarily don't get into that.
20 MEMBER BLEY: But we don't have the 21 safeguards and all of that stuff and on reactors.
22 MEMBER POWERS: Yes. And on this facility 23 we have not looked at that aspect of the problem.
24 MR. CAMPBELL: Yes, this is Larry 25 Campbell. Under PART 75 it's not unusual to have IAEA NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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199 1 at more and more facilities. As a matter of fact, I 2 think we're in the process of a PART 50 plant will 3 have an IAEA observation there for a considerable 4 amount of time. So for fuel fab facilities I think 5 the regulation is PART 75.
6 MEMBER BLEY: Okay. But this -- Well, we 7 haven't looked into it, but just for information.
8 This will be kind of the standard IAEA safeguards 9 monitoring full-time.
10 MR. CAMPBELL: For MOX I'm not aware. I 11 can't answer that question.
12 MEMBER BLEY: Okay. That's all right.
13 It's not crucial to what we're doing.
14 MR. SALZMAN: We have officers and an 15 office. We've provided an office for IAEA.
16 MR. BELL: My name is Gary Bell. I'm with 17 MOX Services. The IAEA inspection is primarily for 18 validation of the bilateral agreement with the Soviet 19 Union. So it's not their full IAEA service. They do 20 it in a normal MOX plant.
21 MEMBER BLEY: Okay. So you don't have all 22 instrumentation and the cameras and all that kind of 23 stuff.
24 MR. BELL: Just to confer our meeting of 25 the bilateral agreement with the Russian Federation.
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200 1 MEMBER BLEY: Okay. Thank you. Go ahead.
2 I'm sorry.
3 MR. HENNESSY: Next, integrated safety 4 analysis process. I'm Bill Hennessy, Manager of the 5 Nuclear Safety Group. And we do an integrated safety 6 analysis because that's what's required by the 7 regulation, 10 CFR 70. And that provides a systematic 8 approach to identifying all relevant hazards that 9 could result in unacceptable consequences. And MOX 10 being basically a chemical facility, we use a lot of 11 the chemical industry guidelines and procedures for 12 safety analysis, preliminary hazards analysis, hazops 13 and what ifs.
14 And the purpose is again to conservatively 15 evaluate the hazards and identify appropriate 16 protective measures. And these are what we call 17 IROFS, items relied on for safety. It could be safety 18 systems or components or could be administrative 19 procedures that are around safety.
20 The ISA is also as we've done is an also 21 very comprehensive process. Now we started up from 22 bottoms up, a broad based PHA, preliminary hazards 23 analysis, and look at everything we could possibly 24 find as a potential hazard. As the design matured and 25 we had more detailed design documents, say, PNIDs, we NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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201 1 did things like hazops and what ifs to a great extent.
2 These are very intense team efforts. Maybe 3 participate in the hazops -- a dozen guys, experts on 4 the technology and safety, and it lasts for two to 5 three weeks.
6 And I just want to mention that we've 7 spent over $80 million doing this ISA. Now it's 8 roughly equivalent of say 45 full-time equivalents 9 over ten years, and we still maintain it. We'll 10 maintain it for the life of the facility. So it's a 11 very extensive effort.
12 We've evaluated hundreds of glove boxes in 13 Scott's area, the MP area, and hundreds of vessels in 14 the AP area, columns and some -- all kinds of things.
15 And we --
16 MEMBER RYAN: Bill, I'm sorry. I just 17 want to ask you. As you go through on our earlier 18 two-day meeting, you pointed out several choices and 19 decisions you had made along the way based on some of 20 that ISA work, you know, picking this over that and 21 this component over that. If you could maybe just 22 highlight those, I think it would help the Committee 23 understand how you've applied it in this case. So 24 just a thought.
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202 1 when Scott talks about their specific issues.
2 MEMBER RYAN: That's where I remember it.
3 MR. HENNESSY: Yes.
4 MEMBER RYAN: I think it's helpful just to 5 have those --
6 MR. HENNESSY: Right. A list that's set 7 up, a hierarchy, yes.
8 MEMBER RYAN: -- examples where you pick 9 one over the other.
10 MR. HENNESSY: Priorities, right.
11 MEMBER RYAN: Thank you.
12 MR. HENNESSY: And during the hazop what 13 if process, we looked at many thousands of events 14 scenarios and process deviations is a very extensive, 15 broad-based approach to safety. We really left no 16 stone unturned for doing the hazard analysis for this 17 facility.
18 The ISA is required by 10 CFR 70.62 to 19 demonstrate compliance with the performance 20 requirements of 70.61. And these are three bullets 21 there, high consequence events are made highly 22 unlikely, intermediate are made unlikely, criticality 23 events are prevented.
24 Now the consequence definitions or terms 25 here are all defined by the regulations. They're NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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203 1 defined in terms of radiological limits. It's 100 rem 2 to the facility worker for highly unlikely, 25 rem to 3 the public, and also some chemical limits. We use 4 TEEL limits as a criteria. There's a radium intake 5 limit and also an environmental limit where you 6 compare our releases to Part 20 limits, not limits, 7 but the values presented in Part 20.
8 The frequency terms, a highly unlikely 9 definition is not defined by Part 70. It's left up to 10 the applicant to define that and he can define that in 11 a quantitative manner or qualitative manner. And we 12 define it in a qualitative manner. And we define 13 highly unlikely as event scenarios that have to meet 14 the following set of criteria for a set of IROFS 15 applied to that event scenario.
16 And these are the criteria that we define 17 for highly likeliness. Now the IROFS have to meet the 18 single failure criteria or double contingency. They 19 have to meet our QA program which is based on Part 50 20 as well as NQA-1, on an Application of Industry Codes 21 and Standards, ASME and IEEE and a set of management 22 measures. Most importantly to us is the surveillance 23 of the IROFS so we can provide failure detection and 24 repair of an IROFS if it goes down.
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204 1 contingency is very important except potentially 2 against single failure vulnerabilities.
3 Implementation of the 18 point criteria in our QA 4 program ensures reliability of IROFS now from the 5 design process through procurement, fabrication, 6 installation and operation.
7 Application of industry codes and 8 standards ensures that the IROFS will perform its 9 safety function. For example, IEEE 384 protects the 10 power cables from faults. And management measures 11 ensure availability and reliability of IROFS. It's 12 not only surveillance, but also involved procedures 13 and training and so forth that go into that. But it 14 also ensures availability and reliability of IROFS by 15 verifying that the IROFS are operable. You know, 16 going through this regular periodic surveillance 17 process to ensure that your IROFS are functional. And 18 this also reduces the probability or frequency of the 19 event occurring.
20 ISA methodology major steps, obviously you 21 know you need to determine the hazards. You know 22 internal to the facility we start out like I said with 23 broad base PHA, look at a wide range of IROFS or 24 hazards AICHE checklist approach. This is done on 25 unit by unit basis and we're looking for fissile NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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205 1 material naturally but also other radioactive 2 materials and americium specifically.
3 You're also looking at chemistry, the 4 chemical limits associated with the regulations. You 5 also want to know where the locations of these hazards 6 are and these energy sources.
7 As I mentioned as the design matures we 8 went into more detailed design information. So we did 9 more detailed safety analysis using hazops and what-10 ifs. This is really the heart of our ISA process.
11 Like I said, these are very intense workshops, unit by 12 unit, where we had roughly a dozen design people as 13 well as our safety people and also operation 14 experienced people from MELOX and La Hague just 15 marching through the facility going through thousands 16 of potential process deviations and upset conditions.
17 MEMBER STETKAR: Bill, I didn't make it to 18 the subcommittee meeting. So I don't know if this 19 came up. You mentioned a systematic process going 20 through unit by unit. How does the ISA look at 21 integrated effects across the whole facility? Your 22 second bullet there mentioned natural phenomena. But 23 I'm think about the effects of storm, seismic events, 24 perhaps fires, perhaps other types of hazards that 25 could affect operations among several constituent NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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206 1 units.
2 MR. HENNESSY: Right.
3 MEMBER STETKAR: Simultaneously.
4 MR. HENNESSY: Right. Well, I'm just 5 talking about internal hazards first there.
6 MEMBER STETKAR: Okay.
7 MR. HENNESSY: And I haven't gotten to the 8 next two tick marks yet.
9 MEMBER STETKAR: I'll let you.
10 MR. HENNESSY: Obviously, we do look at 11 natural phenomena. We look at seismic. That's an 12 input to not solely for the structure, but also all 13 our IROFS are considered for design earthquake 14 condition. If they had to operate after or during the 15 earthquake, they're designed for the full earthquake 16 condition.
17 We also look -- We followed the staff reg 18 guides on natural phenomenon hazards and we looked at 19 the wind load, of flooding and so forth just sort of 20 as the standard nuclear facility would look at it as 21 well as external manmade hazards. We look at the 22 potential explosions offsite for example. So it's all 23 worked into the design of the facility and design of 24 the structure as well as the IROFS themselves.
25 During the hazops, we develop potential --
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207 1 we develop the event scenarios for the causes of the 2 hazard and this provides us a basis to determined the 3 consequence and assessing or likelihood of potential 4 events. So then we just march through and come up 5 with consequence and likelihood of the event.
6 If the result is unacceptable, if we see 7 unmitigated circumstances, if the result is 8 unacceptable, if we see 100 rem to the worker, then we 9 apply IROFS to the event to make it highly unlikely.
10 Not only IROFS but there are four criteria that we 11 apply with the IROFS to make the event highly 12 unlikely. To provide also the IROFS safety function 13 for the design people to properly spec out the IROFS.
14 Then we demonstrate that the IROFS will 15 perform its intended safety function when necessary 16 and we march through the 70.61 performance criteria 17 and we march through those four design criteria of 18 single failureness and double contingency and also 19 ensure the availability and reliability through those 20 other design criteria.
21 And the ISA is a never-ending process. You 22 know we still have a large team that we look at 23 potential changes to the facility as we go. Look at 24 -- working heavily these days with the operators, 25 develop procedures and develop essentially we don't NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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208 1 call it tech specs but essentially what's called, what 2 is, tech specs. And this will go on for the life of 3 the facility and to the operation and also the 4 decommissioning process.
5 MEMBER RAY: A comment on inspection and 6 enforcement.
7 MR. HENNESSY: Say it again.
8 MEMBER RAY: Could you comment on 9 inspection and enforcement?
10 MR. HENNESSY: In what respect?
11 MEMBER RAY: Well, you talked about the 12 requirements that were established and normally when 13 you have requirements there's somewhat of inspection 14 that enforces the requirements on the operator.
15 MR. HENNESSY: Well, on the operator, do 16 you mean by the staff's inspection?
17 MEMBER RAY: The licensee. What?
18 MR. HENNESSY: It's a staff inspection 19 enforcement process. Right now, we have regular 20 inspections but by Region II. They come out and --
21 MEMBER RAY: Okay. That's all. Just a 22 regular. Same thing as a power reactor.
23 MR. HENNESSY: Absolutely. We have site -
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209 1 every other week and does inspections.
2 MEMBER RAY: When I first asked the 3 question, it sounded like you hadn't experienced that.
4 But that's not the case. You're like anybody else 5 who is a licensee which is inspected and enforced.
6 MR. HENNESSY: There is something --
7 MEMBER ARMIJO: But they inspect against 8 what? Your ISA summary or some other. That's all you 9 submit, right? You submit a summary to the staff and 10 they inspect to the --
11 MR. HENNESSY: The license -- I'll let the 12 staff. This is different.
13 MR. TIKTINSKY: Dave Tiktinsky with the 14 staff here at Headquarters, the project manager.
15 Region II has got an extensive inspection enforcement 16 program. There is specific procedures that are laid, 17 inspection procedures of what they'll look at during 18 construction and during the life of the facility.
19 It's similar to all other fuel facilities that are 20 subject to an inspection enforcement.
21 So as they're constructing, we have 22 resident inspectors. There are teams of inspections 23 looking at components, looking at vendors, looking at 24 receipts of items and all of the aspects of quality 25 assurance. So that's been ongoing for multiple years.
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210 1 It will go through construction, through operator 2 readiness. There will be inspections related to that 3 for they would eventually allow to operate and then 4 during the whole life of the facility.
5 MEMBER BLEY: But the ISA is not part of 6 the license.
7 MR. TIKTINSKY: And as of right now they 8 have a construction authorization. So what the 9 inspection is against is against what's in the 10 construction authorization, so the aspects that have 11 to be from that that are in that document as well as 12 the requirements of NQA-1.
13 MEMBER BLEY: How about when they become 14 operational?
15 MR. TIKTINSKY: When they receive a 16 license, it will be inspected against whatever 17 conditions are set in the license. So the license 18 application, Part 70 is unique because there is a 19 license application, an ISA summary. The ISA summary 20 although it is required to be submitted is not part of 21 the license application, so the license application 22 itself which contains the commitment.
23 So if you read the license application, it 24 would say they're going to meet a code, a standard.
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211 1 the enforceable document after we issue a license.
2 MEMBER BLEY: And just for others who have 3 said you have a summary, if you haven't read it, the 4 ISA summary is some 4,000 pages long.
5 MEMBER POWERS: And really, really boring.
6 MEMBER BLEY: One could say that.
7 (Laughter.)
8 MR. GWYN: That wasn't intentional.
9 They were trying to make your question 10 harder earlier, but if so as Bill mentioned, we have 11 two full-time resident inspectors on site.
12 MEMBER BLEY: I heard that.
13 MR. GWYN: And we had 12 other inspection 14 teams during this past year that ranged from three to 15 eight members during those inspections.
16 MEMBER RAY: You're located in the wrong 17 spot.
18 MEMBER ARMIJO: Since your -- Just in 19 passing, since your owner or client who is DOE, do 20 they do any kind of inspection or they're just 21 programmatic? Are you on schedule and on budget or do 22 they do anything related to safety at all?
23 MR. BADER: They do quite regular -- They 24 don't call them inspections. They call them 25 assessments, but they do quite -- they do regular NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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212 1 assessments both for the project and also for our 2 vendors also.
3 MEMBER ARMIJO: Okay. That's good.
4 MR. BADER: Dr. Stetkar, sorry if I 5 butchered your name, but I think you asked a question 6 about these global -- We do have fire hazard analysis 7 as well.
8 MEMBER STETKAR: You do?
9 MR. BADER: A seismic safe shutdown 10 analysis and --
11 MEMBER STETKAR: Does the fire hazards 12 analysis -- And forgive me for being completely 13 uninformed. Does the fire hazards -- What I was more 14 concerned about was do those analyses look at the 15 entire facility in some sort of integrated sense such 16 that you look at a fire or a seismic event or a 17 natural phenomenon or something like that would 18 simultaneously perhaps affect process flow streams 19 within multiple units or whatever you call the various 20 --
21 MR. BADER: Yes.
22 MEMBER STETKAR: Rather than individually 23 saying "Okay. This unit is fine. It's protected 24 against fire." And not necessarily looking at some 25 sort of integrated sense.
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213 1 MR. BADER: From a fire standpoint, Scott 2 will be the expert. But we compartmentalize our 3 fires. We have very small fire areas in our facility.
4 But we do have a fire safe shutdown analysis that 5 we've done because we do have IROFS and common areas 6 and we look at the impact of a fire on those.
7 And then during the hazops another 8 difficult with the -- with doing this on a 9 compartment, unit-by-unit basis is the interface is 10 between the units. And we also have -- You know when 11 we did the evaluations of the hazops, we specifically 12 brought in the next unit people at the end of the 13 hazop to look at the interface issues in that way.
14 MEMBER STETKAR: Okay.
15 MR. BADER: We weren't losing those as 16 well. So you'll have events produced one -- You know 17 you'll have a deviation of one unit that will cause an 18 event downstream.
19 MEMBER STETKAR: Okay.
20 MR. BADER: A good example of that would 21 be that uranium that we add up in the dissolution unit 22 here which has put a criticality down here. And 23 that's actually a very large gap in the units there.
24 MEMBER STETKAR: Good. Thanks.
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214 1 fires in the woods that come not too far away from the 2 site and could that lead to any problems with these 3 wind takes and the like? I'm not sure we clarified 4 that completely at the last meeting.
5 MEMBER STETKAR: I'm thinking also I have 6 no idea how the power distribution network. I'm 7 assuming these are not independent in terms of an 8 electric power supply and that sort of stuff.
9 MR. BADER: Do you want to address that 10 one?
11 MEMBER STETKAR: No, keep you on schedule.
12 MR. BADER: Okay. All right.
13 MEMBER POWERS: In your absence, we did 14 explore this fairly thoroughly.
15 MEMBER STETKAR: Good.
16 MEMBER POWERS: And I mean their fire 17 hazards analysis was reasonably classic in its nature.
18 Their electrical supplies are diverse. I mean there 19 was nothing.
20 MEMBER STETKAR: It's not a reactor and 21 it's not a reprocessing plant that has all this waste 22 that needs cooling. So mostly if you can turn things 23 off you're home free.
24 MR. BADER: Yes. It's process flow 25 streams I think is probably more --
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215 1 MEMBER POWERS: I would say -- I mean one 2 of the aspects of this facility that's really unusual 3 so that they have to account for interruptions in the 4 processing. Interruptions can occur both in the feed 5 in and on the waste receipt end and that probably is 6 the most striking feature about this facility relative 7 to most and I think they've done a pretty good job.
8 I mean they're not idiots. They 9 recognized that this was going to happen and they've 10 handled it with basically a strategy of clean the 11 system up if they have a protracted shutdown. I mean 12 it's done pretty well I think. I mean it's as good as 13 you can do I think on handling that aspect of a 14 problem.
15 MR. BADER: And we'll actually address 16 that. That's just two slides we have on that.
17 MEMBER POWERS: Yes. I mean it's really 18 the unusual feature of this thing and you just have to 19 take into account because stuff happens in this world.
20 MR. BADER: During the construction 21 authorization, a letter was written to the ACRS and 22 there were several concerns that were shared with 23 them. One of them was red oil. In addition, there 24 was DPOs out there for red oil. And what I've thrown 25 up here is just a real brief synopsis of the things we NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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216 1 had from about 100 odd slides that could get presented 2 if you really want to listen to details about red oil.
3 But the bottom line is red oil is a result 4 I believe of an organic nitrate acid interaction and 5 it's been characterized as what's left over after you 6 had the explosion. So you clearly do not want to have 7 red oil in our facility. It's not something red that 8 we're pouring into the process.
9 What we did is we shifted from what we had 10 in the construction authorization to the ISA summary 11 to this strategy here and the shift was really a 12 product of not being able to simulate what we thought 13 we could do during the construction authorization.
14 Basically, modeling a full evaporator, an eight meter 15 tall evaporator full of organic, and then also 16 instrument it as well so that it's reacting for a 17 temperature ramp increase which will happen during 18 start up and shutdown. Start up only. Sorry. Not 19 shutdown.
20 It was just too difficult to implement 21 effectively. So what we did was we went back, looked 22 at the DNFSB letters, Defense Nuclear Facilities 23 Safety Board letter on red oil, and looked at La Hague 24 and the way they implemented strategies against this 25 event. And what we have here reflects that NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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217 1 essentially.
2 So there are three principal strategies 3 and fortunately this figure is still up. The areas 4 that are dashed -- I failed to point this out -- are 5 organic. So we do have organic flowing throughout our 6 process. In those areas, what we have applied is 7 known as a heat transfer strategy. Basically, we have 8 organic in here that has a fairly, a relatively low 9 flammability limit and 60 degree C, 55 degree C.
10 And so if you look at red oil phenomena, 11 it is generally witnessed to be above temperatures of 12 120 degrees C. One hundred and thirty degrees is what 13 the DNFSB said. We can debate that number later.
14 So wherever we have organic we're 15 essentially limited in temperature already by existing 16 process controls for this solvent issue of lower 17 flammability limit (LFL). And we have sufficient 18 cooling on the vessels from the geometry of these 19 vessels just from the room air. We make sure we don't 20 ramp up the temperatures in that above 60 or in the 21 neighborhood of 100 degrees C.
22 In addition, for those areas where I was 23 just talking about this eight meter evaporator, it's 24 in the acid recovery unit. You see we don't have any 25 dashed lines going there and that's intentional. We NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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218 1 don't want to put organic into these evaporators. Now 2 we can't preclude that organic from going there 3 because organic is soluble in the aqueous phase up to 4 about 200 milligram per liter. And if you let it run 5 in this evaporator forever it will start accumulating 6 over time or could accumulate over time depending on 7 how you run the evaporator and you're emptying it and 8 so forth.
9 So what we have done is we precluding 10 organic from reaching here as best we can by sampling 11 the solution as it's moving from what we call in the 12 purification process to the acid recovery unit as well 13 as in the Pu conversion unit so that we don't have --
14 There's another evaporator in the oxalic mother liquor 15 unit.
16 And since we can't eliminate it all, you 17 know, our sampling limit is 50 milligram per liter.
18 La Hague sees about 20 milligram per liter in the 19 aqueous phase maximally. Our safety limit is 50. We 20 will periodically clear out all the equipment that 21 we're precluding any accumulation of the organic in.
22 Right now, it's bi-annually minimally.
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219 1 historically are it's the accumulation of the material 2 that kills you on this red oil issue. I mean it's 3 another piece of empirical evidence, but it's one I 4 don't think the DNFSB has given enough emphasis to.
5 MR. BADER: Yes, in the DNFSB to their 6 credit did also emphasize don't put it any 7 concentrated acid in and we heeded their advice. So 8 since this is our acid recovery unit we are getting 9 concentrated acid here. So it really is up to us to 10 make sure that we don't put organic in there.
11 Now there's also a philosophy that if you 12 have a vent that's of the right size you can put 13 whatever quantity of organic in there. And the 14 problem with that if you do get a runaway reaction 15 you're getting a lot of volatiles that have very low 16 flashpoints and flammability limits, the butanyls for 17 instance. So we are not relying on that strategy at 18 all.
19 MEMBER BLEY: Well, but you are 20 maintaining the vent capability.
21 MR. BADER: We are a defense in depth 22 which will be clear on the next slide. Yes, we 23 didn't abandon the philosophy. But from a 24 demonstration standpoint we think it's a lot better to 25 do the prevention process from an IROFS standpoint.
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220 1 This last strategy, the evaporative 2 cooling is actually -- is probably really the issue as 3 well with the evaporator. We're going to limit this 4 organic quantity to 34 liters maximally in any single 5 vessel. And even with 34 liters you could have a 6 runaway.
7 So what we have is put in some features to 8 make sure that if the temperature starts rising above 9 a certain level that we have actions either automatic 10 or operator actions to take place. And the reason we 11 have potentially operator actions is because it's a 12 very slow phenomena. We have a model for this. We've 13 done extensive modeling based on a lot of lab data 14 that's out there.
15 So it's not a new phenomenon. It's been 16 around for quite a long time. In fact, I believe the 17 first event was in the '50s. Every decade they have 18 one of these events. India was the last.
19 And so we had these operators take action 20 because it's such slow event. And when I say slow 21 we're talking six hours minimal probably up to 22 hundreds of hours potentially.
23 The last point here is that we really felt 24 that everything we have applied in this facility meets 25 or exceeds anything that the DNFSB had written up for NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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221 1 red oils in the DOE facilities. And we have to 2 remember that the DNFSB was kind of back-fitting. So 3 we had the privilege to be designing a facility so we 4 can put all these back-fits into the front end of 5 this.
6 What I want to show here and it was kind 7 of hard to condense everything and I apologize for all 8 the wordiness. But we don't rely solely on IROFS 9 here. The process is designed to ensure that IROFS 10 are not challenged. So you really would have to have 11 a normal process deviations and several process 12 deviations in most case occur before you can challenge 13 an IROFS.
14 We have the philosophy that failure of a 15 normal system is likely. So the way we define likely 16 Bill alluded to and I'm not going to go there.
17 The three different strategies are listed 18 here. Basically, we have a diluent wash column 19 wherever we are preventing organic from going to a 20 tank that's about to be sampled and then downstream to 21 an evaporator. We have diluent wash columns which are 22 instrumented. They have interface controls. They 23 have flow controls to make sure that the diluent is 24 coming in and removing any kind of entrained organics.
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222 1 numerous normal controls in the process. It's a very 2 heavily instrumented process. And there are also 3 pressure controls to make sure we're not building up 4 any pressure in the process.
5 For the evaporative cooling, again we have 6 another diluent wash column in front of these 7 evaporators and then in the same type of controls that 8 we have for prevention.
9 We have redundancy in our IROFS. We put 10 the sample there for prevention. The density is also 11 there for prevention. These are redundant density 12 transmitters located above an intake. So as the tank 13 level is decreasing and you're trying not to send or 14 you're preventing organic from going up the intake 15 line, the density transmitters would trip that flow 16 prior to the level reaching down below. It was also 17 trip once it becomes uncovered.
18 There are temperature credited throughout.
19 Those are mostly for the LFL issues. And then we 20 have vents and level measurements to ensure that we 21 don't have less than a one-to-one ratio in the organic 22 and aqueous for the evaporative cooling strategy which 23 we didn't really talk about. It's one of the IROFS in 24 that section.
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223 1 and the IROFS fail then we have a fourth layer of 2 protection here which is dependent on the strategy.
3 But for the prevented units where we're trying to 4 prevent organic from going down to there are one of 5 several factors involved there. There's either no 6 heat source in the vessels or there's no concentrated 7 acid in the vessels and/or you can credit the organic 8 from potentially being steam stripped on the way down 9 to the evaporators.
10 For the heat transfer and the evaporative 11 cooling, as Dr. Bley alluded to, we still credit 12 venting. So for the creditable quantities, organic 13 that can reach these vessels. We did not assume that 14 they were fully organic though. That if we did get 15 the creditable quantity and it did run away, we are 16 still vessel vented through the vessel a vent line to 17 the off-gases to which I described earlier.
18 Finally, if all that fails, we have the 19 robust confinement barriers. These tanks are all 20 located in process cells, inaccessible rooms, foot 21 thick walls that have their own separate ventilation 22 system which goes through HEPA filtration unit. And 23 that's all for red oil.
24 MEMBER POWERS: One of the issues we did 25 not cover that we probably should have covered a NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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224 1 little bit is the issue of ammonium nitrate.
2 MR. BADER: Yes, I'm trying to -- Paul, do 3 you want to speak to that? We had a separate 4 discussion about this one.
5 MR. DUVAL: Paul Duval, Chemical Safety.
6 Ammonium nitrate is found as very, very small 7 subcomponent that happens as a result of hydroxylamine 8 nitrate and nitric acid actually bypassing, going 9 through one another in REDOX reaction going all the 10 way to exact extremes on the oxidation states. And so 11 they're an exceeding small part of what you get in 12 normal REDOX reactions.
13 MEMBER POWERS: The trouble is it goes up 14 and accumulates in the venting lines over a protracted 15 period of time. And so you worry about its 16 accumulation in your vent systems and things like 17 that.
18 MR. BADER: And the only defenses I have 19 for the vent systems themselves is they're all slopes.
20 So there's no pockets and liquids to gather. And all 21 the gases are drawn out by the ventilation system 22 itself or by the IROFS exhausters which are controlled 23 by the IROFS pressure monitors.
24 MEMBER POWERS: They're going to 25 accumulate on your HEPAs as particulate.
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225 1 MR. BADER: It's particulate. Oh, on the 2 HEPA filters?
3 MEMBER POWERS: Yes.
4 MR. BADER: And then we -- Okay. So in 5 that case from a HEPA filter standpoint if we do get 6 accumulation there I'm not sure what the event is that 7 we're exactly worried about.
8 MEMBER POWERS: Ignition.
9 MR. BADER: Ignition. Yes, we do have 10 redundant HEPA filters in separate fire areas. So you 11 know that would be -- Brian.
12 MR. STONE: This is Brian Stone. Sven, 13 you might want to mention about the design of the 14 ventilation and the demisters and the decon that we 15 have on that system.
16 MR. BADER: Okay. Each vented tank before 17 the gases can go to the off-gas system it has to go 18 through a demister. The demisters are periodically 19 cleaned with decon solution to sent anything back into 20 the process that might have been captured by the 21 demister that did not drain immediately from the 22 demister. The demisters are each drained back to the 23 process.
24 MEMBER RAY: What does a demister do?
25 What does it take out?
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226 1 MR. BADER: It's basically a -- it 2 depends. They're -- they have odd geometries. But 3 it's a layer of trays and as the gas comes through 4 we're basically looking for the impact on the surface 5 and condensate anything that might have been 6 entrained. And they all slope. So when you get a lot 7 of collection it will start draining down to the 8 bottom of the demister which is -- it's hard to give 9 you a generic description because it's all unique.
10 MR. FOSTER: This is Bob Foster, MOX 11 Services. A typical demister is like a flat box for 12 criticality reasons. Inside that flat box are veins.
13 I would call them veins and so as the gas is coming 14 up it hits the vein and the intention is to --
15 MEMBER ARMIJO: Like a steam dryer.
16 MR. FOSTER: -- separate the --
17 MR. BADER: A good analogy is to a steam 18 dryer.
19 MEMBER ARMIJO: Okay.
20 MR. FOSTER: So it's a separator.
21 MEMBER ARMIJO: Yes. Got it. And you 22 collect the stuff that comes off and you worry about 23 criticality and --
24 MR. BADER: Because it could plutonium 25 that might be entrained.
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227 1 MEMBER POWERS: The trouble with demisters 2 of course is that they're meant for relatively large 3 droplets on the order of 20 to 50 microns. Whereas 4 the ammonium nitrate particles are going to be around 5 0.1 microns. And they're just going to go right 6 through it.
7 MR. BADER: And I haven't gotten to the 8 other stuff that's out there.
9 MEMBER POWERS: Like weight.
10 MR. BADER: From there the gases then go 11 depending if it's a NOX would go to a NOX scrubbing 12 column which is basically a dilute nitric acid spray 13 on the solution. If there's not NOX which is where 14 the ammonium nitrate is going to be forming, not the 15 NOX areas, those will -- Actually the demister --
16 Those will go to a gas scrubbing column which is also 17 one of the acid NOX scrubbing columns.
18 MEMBER POWERS: And that will get your 19 ammonium nitrate.
20 MR. BADER: And then from -- That all 21 drains down to the KPC unit for reprocessing, 22 recycling. I'll avoid the reprocessing. Sorry. And 23 then from there --
24 MR. HENNESSY: Let me emphasize it a 25 little bit. I mean we do have two HEPAs in series.
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228 1 Both IROFS to both --
2 MEMBER POWERS: You just don't want 3 ammonium nitrate to get there. This gas handling is 4 the stuff that will do it for you.
5 MR. BADER: And just before I get to the 6 HEPAs, yes, there's another demister and there's a 7 condenser. Sorry, a condenser and then a demister.
8 And then go through a heater and then finally get to 9 the HEPA filters and we have four sets. You know 10 they're in parallel, two sets in parallel, before we 11 get to the stack. So it's actually a long run of pipe 12 that goes to the MP side of the facility where the 13 stack is located at.
14 MEMBER ARMIJO: Is the MELOX facility have 15 a similar type of gas treatment system?
16 MR. BADER: I have to distinguish. Scott 17 mentioned that MP was designed after the MELOX. The 18 AP is actually designed after La Hague.
19 MEMBER ARMIJO: Whatever the French 20 experience.
21 MR. BADER: Yes, there are a lot of 22 similarities. One thing that's dissimilar is that the 23 French rely on natural convection drawing. I mean 24 they have exhausters, but they're not safety 25 exhausters like we have because they're relying on the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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229 1 stack and then on natural draw, natural circulation, 2 out of their process.
3 MEMBER POWERS: This is a better system.
4 MR. BADER: We hope so.
5 Okay. All right. Hydroxylamine nitrate.
6 Another exciting explosion. This is an autocatalytic 7 event. Again we shifted the safety strategy here. In 8 this case, we did a very extensive analysis. I think 9 this is where Bill probably wants me to go through 10 example of what you were looking for, Dr. Ryan, with 11 respect to the hazop.
12 What we do is produce a model here based 13 on the extensive laboratory data that's out there.
14 It's a very elaborate model of all the reaction rates, 15 the kinetics going on in this and actually 16 thermodynamics as well. And during our hazops, we 17 would go through and we would assume everything is 18 unmitigated. So we assumed deviations in the process 19 fluid entries, rates, loss of flows, etc.
20 And from that if we were to add conditions 21 that were susceptible to an autocatalytic reaction we 22 then made an action item which would go to the model.
23 The model would go, produce the results, come back to 24 us, say this is what you need to limit. And the next 25 slide will show the limits.
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230 1 But before we go there you know it was an 2 integrated system. So we were making sure that 3 everything we were identifying during the hazops is 4 addressed in the code modeling. And then the code 5 modeling would tell us what are the limits we had at 6 our IROFS. So we had controls on HAN concentration, 7 nitric acid concentration, flow rates and 8 temperatures. Those are the four principal 9 parameters. And then in the areas where we don't 10 expect plutonium we also credited the plutonium 11 separation.
12 Go ahead to the next one. So for this 13 area the deviation from the construction authorization 14 was in the construction authorization we corrected or 15 credited hydrazine in the process. We had a couple 16 deviations where we could conceivably have used up all 17 our hydrazine. It's never been seen before at La 18 Hague, but it is from our hazop a conservative 19 approach in our hazops. We had certain process 20 deviations that could sit there and eat up our 21 hydrazine. They were mostly static conditions.
22 If the hydrazine is not removed from the 23 process, you will not have any chance of getting 24 hydroxylamine nitrate autocatalytic reaction because 25 basically what the hydrazine is it's taking any NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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231 1 nitrous acid, an excess nitrous acid in the process 2 and reacting with it and creating hydrogen aside or 3 hydrazoic acid which begets a whole other problem we 4 dealt with separately. So for our first layer now 5 which is non IROFS is where you could credit the 6 hydrazine in the process.
7 From there you go to the normal process 8 controls. So you're where we have IROFS temperature 9 controls, we have normal process temperature controls 10 before that would trip before the IROFS would trip.
11 So you'd have to a loss of hydrazine and a loss of 12 these normal controls before you can even get to our 13 IROFS.
14 So the IROFS themselves are redundant. So 15 they provide the third and fourth leg.
16 And then again the fifth leg is all this 17 equipment is in process cells so that in the highly 18 unlikely case all these -- or it could be probably 19 defined as non credible case -- but in the highly 20 unlikely case if all these controls failed, the 21 process cell barriers would probably confine any 22 explosion. And then we'd be relying on our process 23 cell ventilation system to filter any release.
24 MEMBER ARMIJO: Is that really a probably 25 confined or have you designed it with the intention to NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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232 1 confine an explosion?
2 MR. BADER: We have not gone through that 3 demonstration because it's very difficult because of 4 the number of process cells we have. We've done some 5 initial studies. The initial studies all found that 6 this is going to work.
7 But the problem is you have a very 8 demanding path before you get to these final filters.
9 What we're worried about is blowing out the final 10 filters. We're not worried about blowing out the walls 11 in the room. There's just not enough energy in these 12 rooms because the tanks aren't huge.
13 MEMBER ARMIJO: Okay.
14 MR. BADER: But from a criticality 15 standpoint the tanks are pretty small because of the 16 high Pu content.
17 MEMBER ARMIJO: Okay.
18 MEMBER POWERS: Your treatment of HAN has 19 looked at HAN runaway reactions in the process stream 20 itself. When I look at the relatively recent history 21 of industrial problems with HAN I find most of the 22 recent issues that have arisen with the HAN feedstock.
23 How are you handling that issue?
24 MR. BADER: In those areas, we don't have 25 IROFS because we don't have any plutonium in those NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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233 1 areas and we don't have any -- We have the fire 2 barriers which are so robust. But it doesn't mean we 3 don't look at it. I mean we've clearly looked at it.
4 We have the same type of controls there. We have 5 temperature controls. There's no heated actions up 6 there. There are no catalysts up there which is --
7 MEMBER POWERS: Emits the iron problem.
8 MR. BADER: You're right. There is the 9 potential for iron from the corrosion of the stainless 10 vessels. Again we've done an assessment of that 11 because the process has the same characteristics, the 12 same material tanks. So I would say that bounds it in 13 that sense.
14 And then there's -- What else? There's 15 really not any other issue there that I can see.
16 MEMBER POWERS: I mean temperature and 17 control of the catalysts are the only things you can 18 do there.
19 MR. BADER: Yes.
20 MEMBER POWERS: Because that's all that 21 causes the problem. It seems to me that what I would 22 do if I had to worry about this and I would worry 23 about it because some of those events have been fairly 24 specular is that I'd look at the residuals in my tanks 25 every once and a while to see if I was accumulating NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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234 1 any iron.
2 Temperature control, yes. I mean you've 3 thermometers. I mean what else can you do.
4 MR. BADER: And we have no heat. You know 5 there's no reason to heat anything in that area.
6 MEMBER POWERS: That's right. But it's 7 just -- Am I getting corrosion where I didn't expect 8 it and getting iron into the solution there? And if I 9 am --
10 MR. BADER: Fix it. Right. And we do --
11 before we send the stuff to the process we do sample 12 it. And part of the sampling I think it's there --
13 MEMBER POWERS: And that's probably the 14 best thing you can do right there is just simply your 15 process -- on sampling.
16 MR. BADER: And again, these tanks are not 17 all that large either.
18 MEMBER POWERS: Right.
19 MR. BADER: Even the -- and they're 20 located on the fourth or fifth floor in general. So 21 the plutonium is on the first, second and third 22 floors.
23 MEMBER POWERS: Yes. Well, like you said, 24 it's -- in the storage facilities.
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235 1 the reactant units, too. I should have mentioned 2 that. So it's not that we've concentrated only on the 3 plutonium areas. We've also looked at the other 4 areas.
5 MEMBER POWERS: I mean some of -- I mean I 6 think in many cases they haven't actually figured out 7 why they got blow ups in the storage units.
8 MR. BADER: Yes. Scott Barney is not here 9 and he's probably be the one to debate that since he's 10 the resident expert.
11 MEMBER POWERS: Okay.
12 MR. BADER: I'm not going to even 13 challenge that.
14 MEMBER POWERS: I'll defer to him because 15 I mean mine is mostly an anecdotal notice of this.
16 But HAN is a real problem.
17 MR. BADER: Waste streams, okay. There is 18 -- As Dr. Power has alluded to earlier, one of the 19 issues we have is potentially from the process down --
20 One of the causes for that is losing our ability to 21 remove our waste from our facility and send it to the 22 DOE complex. There is -- The waste streams that we 23 send to the DOE complex are going to a waste 24 solidification building which is getting built right 25 now. And from there they get treated. They will dry NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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236 1 up.
2 Some of it goes to an effluent building.
3 The low level waste will go to an effluent building 4 that meets certain criteria.
5 MEMBER BLEY: But that's not part of your 6 facility.
7 MR. BADER: That's not part of our 8 facility, right.
9 MEMBER BLEY: Or part of this license.
10 MR. BADER: Right. And what I really 11 should point out is that because it's out of our 12 control it could be that it's not available to us.
13 And so what we've done is we've done an assessment.
14 This is one of these more global impact assessment of 15 what happens if I'm not capable of removing waste from 16 our facility.
17 So we did an evaluation of the whole AP 18 process to look at the impacts and the immediate 19 issues that we found were related to high alpha waste.
20 There's three streams I mentioned earlier, the 21 stripped uranium, the low level waste and high alpha 22 stream.
23 The stripped uranium is uranium for a low 24 dose conversion factor. So you don't get much dose 25 from that. So a significant accumulation at the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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237 1 facility can be held at our tanks. We have very large 2 tanks in this area relative to the rest of the process 3 that can handle three months worth of backup in our 4 facility.
5 Low level waste, they're almost seasonal.
6 They depend on what part of the operating phase we're 7 in. If we've finished a campaign, that's probably 8 when we accumulate the most low level waste from 9 deconning glove boxes and so forth.
10 But in the high alpha waste unit what 11 we're worried about is overfilling our tanks. And 12 this is high alpha waste going to areas that we don't 13 want it. And so this is americium principally. High 14 dose conversion factor. So immediate concerns to 15 mainly the facility worker, the guy inside the 16 facility.
17 So what we've done is we have gone 18 through, implemented an IROFS to shut down the process 19 once our tanks in the high alpha waste unit reach a 20 critical volume. And this volume is not full. This 21 is a volume that allows us to empty the rest of the 22 process because there's another concern. If I leave 23 the plutonium with the organic for prolonged periods 24 of time there's degradation going on through 25 radiolysis.
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238 1 And so what we've designed this IROFS for 2 is to allow us to separate the plutonium from the 3 organic just by running the rest of the process 4 through and empty all the process then of all the 5 solution and send all the organic to the solvent 6 recovery unit which I've described earlier as an 7 important unit because it's cleaning up the organic, 8 removing the degradation products, and then it's also 9 cooling the organic. So it's going to go into a tank 10 where it's cool.
11 MEMBER RYAN: And one other follow-up 12 questions, have you matched up the waste processing 13 solidification I guess you said it is and their 14 acceptance rate on their product efficiency and with 15 your rates of -- at your facility?
16 MR. BADER: Absolutely. Yes.
17 MEMBER RYAN: You have some margin there 18 in case they say they can --
19 MR. BADER: There is margin. I haven't 20 even talked about the margin. We store -- I'm trying 21 to remember the exact number. Brian, can you help me 22 with that one? Do you remember the exact number of 23 months that we can store a high alpha waste when we're 24 running the full blower?
25 MR. STONE: Assuming we were empty.
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239 1 MR. BADER: Yes.
2 MR. STONE: We didn't have anything in the 3 tanks I think it was 29 weeks I believe.
4 MR. BADER: Twenty-nine weeks.
5 MR. STONE: Yes.
6 MR. BADER: So we keep our largest tank 7 empty because that's the tank we're going to end up 8 sampling and make sure we meet the waste acceptance 9 criteria before we actually send it. So we have 10 essentially a whole tank, a 10,000 liter tank. You 11 have to remember the process tanks are all about 100 12 liters. They're smaller. So there's a lot of volume 13 there.
14 And we expect about five transfers a year 15 to the waste solidification building. That's about 16 7,000 liters or 8,000 liters per transfer.
17 MEMBER RYAN: So they've got everything --
18 They've got a couple of months to process 7,000 liters 19 or get them somewhere else.
20 MR. BADER: Right. And we don't know 21 right now if they have excess tank capacity themselves 22 so that they could take more from us.
23 MEMBER RYAN: Yes. I mean their ultimate 24 ability to do what I guess they have engineered to do 25 is really going to have a potential impact on you if NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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240 1 for whatever reason they say they can have the flow 2 rate out their door compared to what you can do.
3 MR. BADER: Right. And ultimately if we 4 run into trouble we'll shut our process down in an 5 orderly manner. We're not going to --
6 MEMBER RYAN: You made that clear in the 7 last meeting.
8 MR. BADER: The layers of protection here 9 basically the lines themselves, the waste lines that 10 connect our facility to the waste solidification 11 building are double lined. They're IROFS. They're 12 seismically qualified. They're buried under at least 13 three feet of soil. They are stainless steel. If the 14 inner annulus leaks it leaks to the outer annulus 15 which leaks back to our facility to a leak detection 16 pot. So we would be able to identify if there's a 17 leak anywhere in the piping going from our facility to 18 the waste solidification building. And then our 19 process is designed to meet the waste acceptance 20 criteria that the WSB has set up for us.
21 The next layer is basically we have an 22 extreme amount of excess capacity in this area. Then 23 we have an IROFS admin controls to shut down the 24 process. Surveillance is also listed there and I 25 probably should mention that one as well. We do like NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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241 1 HAN control nitric acid.
2 Well, we allow HAN to sit in one spot for 3 a prolonged period with nitric acid, there's a 4 potential for (1) the hydrazine to get all used up and 5 (2) for the process solution to start concentrating.
6 So we do surveillance those tank where we had an IROFS 7 sample applied to that tank to ensure its safety.
8 Then the actual other issues associated 9 with the safety events basically I mentioned this high 10 level that could cause not only overflow into a 11 reagent unit, but also could overpressurize our tanks.
12 These are very robust tanks. You know the steel is -
13 - I can't remember exactly -- about a half inch thick 14 at least and a lot of the tanks are lined with a 15 separate layer for protection.
16 The reagent tanks themselves where the 17 back flow would be that's usually a 18 foot head that 18 would have to be overcome. So you would probably be 19 backing up in the process as opposed to backing up in 20 the reagents.
21 The organic itself is sent to KPB unit.
22 Sorry. I left an acronym in there that wasn't 23 defined. That is the solvent treatment unit which 24 will wash the degradation process and be able to store 25 the organic.
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242 1 And then ultimately we had no ignition 2 sources. We don't credit that. But all our flow 3 rates for organics are meeting limits such that we 4 don't build up any static electricity. All our tanks 5 are grounded so that there's really no ignition 6 sources anywhere in the process.
7 And then for the events themselves that 8 require the surveillance from concentrations it's not 9 like we're blowing a tremendous air across these 10 tanks. There is some air going through to remove 11 hydrogen from radiolysis. But basically there's not a 12 tremendous amount of entrainment going on to reduce 13 the volume in our tank. And the process temperatures 14 would basically revert to room temperatures. So the 15 evaporation rate is not very high. It's very low.
16 And then thick robust confinement areas 17 again.
18 MEMBER ARMIJO: You have electric motors 19 that run pumps and things like that. Are those not --
20 MR. BADER: Those are on glove boxes.
21 Yes, anything electrical is not in the process cells.
22 In process cells, we do have piping that goes 23 underneath the tanks that allows us to put a probe in 24 there, a radiation probe to look at maybe hold up in 25 the tank or something to that effect.
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243 1 MEMBER ARMIJO: Yes.
2 MR. BADER: But the pipe itself is not 3 exposed to the atmosphere and the process cell. There 4 is no electronics in the process cells. You know the 5 pumps themselves are all in glove boxes and that 6 allows us to be able to do maintenance on them as 7 necessary.
8 MEMBER ARMIJO: Okay. Do you want to move 9 on, Scott?
10 MR. SALZMAN: Okay. One of the other 11 issues was fire along with explosions, energetic 12 event, potential dispersed material. So you want to 13 take a look at that and its effects on our confinement 14 systems. Unlike some of our DOE counterparts, we 15 don't have a sand filter for our facilities. So we're 16 looking at HEPA filters and we need to make sure --
17 MEMBER POWERS: Be very happy you don't 18 have sand filters.
19 (Laughter.)
20 MR. SALZMAN: They work pretty good in 21 fire.
22 MEMBER POWERS: They work well for soot.
23 MR. SALZMAN: So we spent a lot of time 24 and effort evaluating fires and I wanted to go over a 25 fire in one of our process areas. This is an area NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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244 1 where we would have powder or other plutonium and 2 material inside of glove boxes in one of our process 3 rooms. The process rooms are in a separate 4 confinement area, a C3 confinement area. And outside 5 that, we have our hallways and corridors are C2.
6 These are just definitions on the 7 potential for contamination. They're a classification 8 for our confinement zones. Each one of these 9 confinement zones is on a separate ventilation system.
10 Okay. As I said, potential for 11 dispersion, unmitigated consequences are high to the 12 public and operator. And our safety strategy was to 13 limit the size of the fire and subsequently limit the 14 size of the soot and associated effects on the final 15 HEPA filters.
16 Taking a look at the -- Well, in doing 17 that, so we have fire prevention features that 18 including use of noncombustible construction and 19 controls on transient combustibles and ignition 20 sources. That's sort of our prevention look at this 21 fire to prevent the fire from initiating in the first 22 place.
23 We have IROFS clean agents suppression 24 systems in our areas with dispersible material to 25 suppress a fire. Those are automatic suppression NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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245 1 systems.
2 We have the ability to isolate these 3 fires. We have over 300 fire areas. So what we've 4 done is we have a lot of small fire areas. The fire 5 areas are bound by fire barriers, concrete 6 construction in the walls, fire penetration seals, 7 fire doors and fire dampers in our ventilation system.
8 So we do have the ability to close up these fire 9 areas to allow post fire cooling.
10 And in the end we may -- We do have the 11 ability. We have the ability to apply small amounts 12 of water in specific areas by our fire department if 13 the need arises.
14 So take a look at my layers of protection.
15 It's sort of our defense-in-depth design principle.
16 As I was saying, our first layer of defense there is 17 basically preventive. And so we have non-combustible 18 construction, control of ignition sources at 19 combustible loadings. We do have nitrogen ventilated 20 glove boxes and you have UL listed equipment.
21 The second layer is fire detection 22 suppression. In these areas where we have dispersible 23 material we have IROFS detection suppression. Clean 24 agents are discharged in these areas to suppress a 25 fire. There is also fire detection in each glove box.
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246 1 And we have the ability to manually inject CO2 into 2 any given glove box to suppress a fire. We also have 3 other standard Class A portable fire extinguishers in 4 the process rooms to allow manual firefighting 5 activities.
6 To contain our fires like I said we have 7 many small fire areas. Our fire barriers and our 8 confinement system make up these fire areas. So VHB 9 is our exhaust system for our glove boxes. It's an 10 independent exhaust system that exhausts the static 11 through redundant heat filters.
12 The high depressurization exhaust, that's 13 our exhaust system for our process rooms, the C3 14 confinement areas. It's an independent system. It 15 exhausts through redundant heat filters.
16 Then our process offgas -- that shouldn't 17 -- Okay. That's our -- For our process cells, that 18 should be process cell exhaust system. I think that's 19 a little typo there. In our process cells, we also 20 have an independent exhaust system that exhausts the 21 process cells to redundant heat filters.
22 Once we get out of the process room into 23 our C2 areas that would be the corridors, the 24 stairways, and your access to the various process 25 rooms, we have another medium depressurization exhaust NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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247 1 system. That exhausts through redundant HEPA filters.
2 And our fifth layer, we have the Savannah 3 River site fire department. They're tied right into 4 our fire control panel. An alarm at our facility 5 alarms at the fire department. They can be there and 6 ready to go in about 15 minutes. They're right down 7 the road and they'll be operational at the site. That 8 fire department will be -- We'll have a prefire 9 response plans that will be put in place that dictate 10 how they go through the scrub at the facility and the 11 location of hazardous materials, fission materials, 12 radiological materials. They'll dictate what 13 personnel protection is required, whether it's SCBAs 14 or other clothing. What fire suppression types will 15 be allowed when we go down through the facility and it 16 discusses communications, rally points, so on and so 17 forth to sort of coordinate the Savannah River site 18 fire department.
19 MEMBER ARMIJO: Do you have in your 20 analysis ever had a situation where you may have to 21 evacuate let's say a chemical process area because of 22 a fire? And is there a time that you can be away from 23 this process where things remain stable and you need 24 to have a lot of margin there where you can basically 25 bail out of those areas and be okay without people NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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248 1 having to do something special?
2 MR. BADER: For the AP process there is no 3 human interface required.
4 MEMBER ARMIJO: Okay.
5 MR. BADER: And so it could continue. But 6 it really depends on where the fire is at. I mean the 7 fire if it damages an IROFS for instance we have 8 buttons to shut down process unit in the control room.
9 I guess my point really is that we really don't have 10 people in there and they might be doing surveillances.
11 Actually, we do have surveillances. So, yes, they 12 would be evacuated.
13 MEMBER ARMIJO: But they're not really 14 needed there except through a control room.
15 MR. BADER: From a process safety 16 standpoint, they are not needed there.
17 MEMBER ARMIJO: Okay.
18 MR. BADER: An ultimate is a safe shutdown 19 system which is basically a system that puts all IROFS 20 in their fail safe position.
21 MEMBER ARMIJO: Okay.
22 MEMBER BLEY: Sven, you mentioned earlier.
23 People are going to hate me, but I have to ask this.
24 You've done a detailed fire hazard analysis.
25 Something that's creating a lot of headaches in the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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249 1 commercial business, fire analyses these days, is the 2 evaluation of so-called spurious actuations or hot 3 shorts or whatever jargon you have heard them called.
4 In other words, a fire in an instrumentation control 5 system that doesn't cause an open circuit or a failure 6 of something that is operating.
7 MEMBER BLEY: Immediately.
8 MEMBER STETKAR: What?
9 MEMBER BLEY: Immediately.
10 MEMBER STETKAR: Immediately. Something 11 that might cause a valve to open that's supposed to 12 remain closed or that might maintain a piece of 13 equipment operating or cause unexpected types of 14 control or actuation signals. Have you looked at or 15 thought about those types of fire induced control 16 system faults or could be protection? Could be 17 control?
18 MR. BADER: I'm going to leave this to 19 Scott. But let me answer in one way because in our 20 hazops we assumed flows from unexpected areas. If 21 there was a pipe connected to a tank we assumed a flow 22 there inadvertently. When the tank is at its worst 23 conditions you suddenly add something else. So from a 24 process standpoint, from a red oil explosion or 25 something, we would have addressed it.
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250 1 But now you're actually talking --
2 MEMBER STETKAR: I can tell you. I'm 3 talking about control room and spurious operational.
4 MEMBER BLEY: Well, there's even --
5 There's a little nasty niche to this because 6 eventually these will end up as open circuits. So 7 they could get a short long enough to open a valve and 8 then the circuit is open and you can't reclose it.
9 (Simultaneous speaking.)
10 MEMBER BANERJEE: Hazop would consider 11 that, wouldn't it?
12 MR. BADER: The hazop looks at spurious 13 operation. It does --
14 MEMBER STETKAR: Assuming you can put it 15 back to normal or not.
16 MR. BADER: No, not necessarily.
17 MEMBER STETKAR: It just says if this 18 happens.
19 MR. BADER: The reason I had the qualifier 20 is because it depends if it's an IROFS or not.
21 MEMBER STETKAR: Okay.
22 MR. BADER: If it's a normal process we 23 assumed it. If it's an IROFS we have an redundant one 24 and from a hot short standpoint I don't know if you 25 want to bail my butt out a little bit here because I'm NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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251 1 not a hot short expert.
2 MR. SALZMAN: We have taken a look at hot 3 shorts, fire induced spurious actuations and our main 4 defense against hot shorts is our separation of 5 trains.
6 MEMBER STETKAR: Okay.
7 MR. SALZMAN: And so what we're doing as 8 we're taking a look as we identify IROFS we take a 9 look at the effects of a hot short and we'll have 10 these trains separated. We meet the IEEE -- what it 11 is -- 364. Yes, we're meeting the -- We're going to 12 meet the requirements of IEEE 384 for separation.
13 MR. GWYN: Rex wants to say something.
14 MR. WESCOTT: Hi, I'm Rex Wescott, Fire 15 Protection Engineer for staff. And, yes, I think what 16 Sven said is it probably has been looked at in hazops 17 analyses, at least, to a point. Looking at spurious 18 actuations is a criteria for the fire hazardous 19 analysis. It's set down in the SAP.
20 And it think what we're expecting -- Well, 21 when I reviewed the fire hazard analysis, there really 22 -- at least I couldn't see any analysis of spurious 23 actuations in there. Of course, we really didn't 24 expect any because we didn't think there was a 25 potential.
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252 1 But I think what MOX is going to do and 2 has made a commitment to us to do is to go back and 3 look at what they've probably done so far in their 4 hazops and also where they may find areas where they 5 haven't specifically looked at this and I think carry 6 it forward into the fire hazard analysis or at least 7 that's what we're looking for. We haven't got a 8 specific commitment yet. But I think that's what 9 we're going to finally look for is to see the spurious 10 actuations carried forward in the fire hazard analysis 11 where they can put in the context of combustible 12 loading and suppression and that type of.
13 MEMBER STETKAR: What I was looking for 14 was to see if -- There's in the commercial nuclear 15 plant licensing process there's a regulatory guide, 16 Reg. Guide 1189, that basically says you have to 17 demonstrate a safe shutdown capability given a fire in 18 any fire location or zone. And the assumption is that 19 that fire can produce any number of spurious 20 actuations. And as long as you have adequate 21 separation, adequate protection, of that safe shutdown 22 capability and whether that same type of thought 23 process had been exercised when you did your fire 24 hazards analysis and set up your fire zones.
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253 1 here because usually in the reactor world I believe if 2 you impact something that's safety related it has an 3 impact over the whole plant. Whereas if you impact 4 something safety related for here it's very 5 compartmentalized. You're only affecting one part of 6 the process.
7 And just to be clear about what I was 8 saying, if it's a non IROFS, we assume it's failure in 9 the hazops. If it's IROFS, then basically what Scott 10 says is we're relying on the separation of the two 11 trains.
12 MEMBER STETKAR: And that's exactly --
13 That's sort of the analogy that I'm talking about is 14 making sure that if it's an IROFS and you're relying 15 on that redundancy and separation that indeed --
16 MR. BADER: Right. And you don't assume 17 that --
18 MEMBER STETKAR: You've done that and 19 you've assumed the failure modes in the IROFS that 20 accounted also for spurious signals.
21 MR. BADER: Yes.
22 MEMBER STETKAR: You know they protected 23 against those types of --
24 MR. BADER: I mean that's part of the 25 common mode issue, right.
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254 1 MR. SALZMAN: We had a slide at the 2 subcommittee and we discussed that. So I mean the 3 example I brought up when it came to those IROFS that 4 we use for isolation we use air operated isolation 5 valves in a lot of places. And basically they are 6 fail close valves. You lose air. You lose power.
7 They go to their isolate position.
8 But what we did since we realized that a 9 hot short could keep one of those valves open and 10 although that we didn't require IROFS power to those, 11 we went and put them on our trained -- We went and 12 powered those valves up through our trained buses 13 which then put in requirements to the separation 14 requirements and not just threw them on a normal bus 15 that didn't not require any train. So for a lot of 16 those, that's one example of hot shorts.
17 MEMBER STETKAR: Good. Okay. Thanks.
18 MEMBER BANERJEE: I'm sorry I missed the 19 first part of your presentation because I had to be 20 somewhere else. But did you mention whether you did a 21 hazops, an operation hazops?
22 MR. BADER: It essentially was an 23 operations hazops. We don't have operations yet in 24 HAN. So I can't tell you.
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255 1 everything yet.
2 MR. BADER: As part of a continuous ISA 3 process.
4 MEMBER BANERJEE: Right.
5 MR. BADER: Once the operations become 6 clear. Yes, we have general layout because we have 7 existing facilities in La Hague that our plant is 8 fabricated after. So we had actual knowledgeable 9 operators from La Hague in our hazops that said, "Oh 10 no. That can't happen." And then we'd say, "Okay.
11 What safety system is preventing that?" And then they 12 would say "Well, it's normal process. We failed it 13 right away which usually antagonized the operator."
14 But we did it and that way we could find out what is 15 safety related.
16 MEMBER BANERJEE: And you will do an 17 operation hazops.
18 MR. BADER: We had done one with the 19 outlined operations that we have and then as more 20 operations become available, yes. I mean we'll 21 continue to update what we have. It's a vicious 22 cycle. As detailed information becomes more available 23 the process of updating our documents continues.
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256 1 currently. We still have the AP units, but we're 2 working through that process right now.
3 MEMBER BANERJEE: Are aspects of this 4 batch or is it all continuous?
5 MR. BADER: It depends on the unit. The 6 dissolution process is batch. The purification 7 process is continuous and the rest, the nitric acid, 8 is continuous essentially five days a week. It varies 9 between process unit. The offgas system is continuous 10 365 days a year.
11 MEMBER POWERS: Got to close out on this.
12 MR. GWYN: We're finished.
13 MEMBER POWERS: Thank you a lot.
14 MR. BADER: Turn it back over to Larry.
15 MEMBER POWERS: Larry and his team will 16 tell us about the safety evaluation report here.
17 MR. CAMPBELL: At this time, we're going 18 to give you an overview of how we reviewed the 19 application, all the interactions we had and Dave 20 Tiktinsky is the Senior Project Manager for the review 21 of the submittal. And I'm going to turn it over to 22 Dave at this time.
23 MR. TIKTINSKY: Thank you, Larry. I'm 24 going to go over a little bit today just the purpose 25 of what our presentation I'm making to you is, a NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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257 1 little bit of the background, go back through the 2 whole licensing process, where we've been for the MOX 3 facility and where we're going in the future.
4 And how I've broken this out since if 5 you've looked at their SER it's 600 pages. We spent 6 two full days in subcommittee and we could have spent 7 weeks going over all the details. So in order to kind 8 of give you a flavor of what we did overall in the 9 process and then we're going to go through a couple of 10 examples of how we did some particular reviews so you 11 can get a feel for how the staff made its conclusions 12 on individual items.
13 The purpose of the presentation is for 14 seeking the ACRS' endorsement of the draft safety 15 evaluation of the LA to actually be able to complete 16 and finalize it. A more planned schedule is to 17 complete it by December. Again it depends upon what 18 the response from the ACRS in terms of the letter.
19 A little bit of the process. I may as 20 well just go back to where we started from where the 21 ACRS had before. Back in 2005, the staff had prepared 22 a safety evaluation report on the construction 23 authorization request. We issued the construction 24 authorization.
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258 1 full committee meeting, back in February 2005. A 2 letter was received as MOX Services talked about some 3 of the items that were in the letter. So that was 4 received and the SER was issued.
5 The license application and ISA summary 6 were initially issued in September of 2006. So there 7 is somewhat of a gap in between there when the 8 document was being developed. The staff accepted that 9 document for review and in December of that year we 10 began our technical review.
11 So a lot of what you're hearing here is 12 the results of three and a half plus years of staff 13 review. It was a very intensive review. A lot of 14 very good staff and very knowledgeable staff involved 15 with it.
16 We prepared the draft SER in June. We 17 have no open items in there. And just to clarify one 18 thing that you heard before talking about the 19 commitments related to spurious actuations. The MOX 20 Services even though you won't currently find that 21 commitment of what to do in the LA, they have 22 submitted some information to say that they will 23 include it in the updates. So they will update their 24 license application and ISA summary basically based 25 after the results of this meeting and any changes that NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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259 1 have to be made. So that commitment is made and will 2 be made in the license application.
3 Additionally on a side note this 4 particular licensing action is in litigation with the 5 Atomic Safety and Licensing Board. It is a two-step 6 process. The first part was the construction 7 authorization. The second part when the license 8 application was submitted there was opportunity for 9 petitioners to send in contentions. One was accepted.
10 And so there will a licensing board hearing on that 11 contention sometime after the completion of the SER.
12 There also is some other contentions that have been 13 submitted that will be dealt with through the ASLB.
14 Another part I just want to bring up 15 quickly is an interesting part that's unique to only 16 plutonium processing facilities in the regulations, 17 what are called principal structure system and 18 components. Those were identified in the construction 19 authorization. There were 53 of them that you saw in 20 the construction authorization request. And that was 21 the basis of the staff's evaluation when we issued the 22 construction authorization.
23 The regulations say that we have, the NRC 24 staff has, to verify construction of those PSSCs as 25 determined before we issue a license. So those PSSCs NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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260 1 of which are varied greatly in terms of what they are, 2 but a lot of them are the structure, their parts of 3 it, their ventilation systems, the criticality 4 systems, for example, those as they're being 5 constructed now and as they're continued through 6 construction estimated through around 2014, as those 7 PSSCs are constructed, the staff is in a verification 8 process. And we will complete that verification 9 process after those are done and issue that -- the 10 plant would be issued a license some time after that 11 step is done.
12 So that's unique. Other facilities do not 13 have that requirement.
14 After we have that, we'll issue the 15 license to possess and use radioactive material. We'll 16 also still have some conditions in it related to 17 operational readiness. So the PSSC verification 18 relates to construction. And then there will be an 19 operational readiness piece before the facility will 20 be allowed to operate. And then hot start up will be 21 with actual material.
22 MEMBER STETKAR: Just I know nothing about 23 this process nor do I know what a PSSC is. Are all of 24 the PSSCs also considered IROFS in the --
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261 1 are a unique breed. They go -- They vary from things 2 like criticality controls is a PSSC. But also the 3 transport package for spent for the fresh fuel is a 4 PSSC. I mean some of them are administrative 5 controls. It kind of varies.
6 Some of them are. They're designed at the 7 system level. So IROFS are at component levels. So 8 you think there's kind of a hierarchy of them.
9 MEMBER ARMIJO: Is the building a PSSC?
10 MR. TIKTINSKY: The building is a PSSC.
11 But also certain pieces of the building are also 12 PSSCs. Process cells are PSSCs.
13 MR. MORRISSEY: Ventilation.
14 MR. TIKTINSKY: Yes, the various 15 ventilation systems. The emergency generators.
16 MR. MORRISSEY: Glove boxes.
17 MR. TIKTINSKY: Glove boxes. They're 18 PSSCs. So you can say a glove box. Well, glove boxes 19 are IROFS as a category. But you can go to one of the 20 specific glove boxes that are in the design and that 21 is an IROFS. So you also can think of you get PSSCs 22 kind of the IROFS groups which would be things like 23 glove boxes to specific component IROFS which is the 24 actual thing that they order and build.
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262 1 I got it.
2 MR. TIKTINSKY: Okay. As part of our SER 3 development we have for reviewing MOX our own standard 4 review plan. That was developed prior to the standard 5 review plans for all fuel cycle facilities. It's 6 NUREG 1718. So that was the basis for both the 7 construction authorization request review and the 8 operating license review.
9 I'll talk a little bit about just kind of 10 in general what the staff did. And as I mentioned 11 I'll get a little more into the details for some 12 specific cases. But we did what we call in-office 13 reviews. As you've heard there was an ISA summary 14 which is 4,000 pages or so. All the detailed 15 documents that back that up that the regulations don't 16 require to be submitted including nuclear safety 17 evaluations, calculations, all kinds of things, the 18 staff needed to look at that to come to its 19 conclusions. So we did what's called in-office 20 reviews. Basically we met with the applicant looking 21 at those documents, reviewing them.
22 We had other discussions with the 23 applicant. We had initially from kick-off meetings 24 going through to make sure there was a good 25 understanding of the technical aspects of the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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263 1 facility. For specific issues that we looked at we 2 had meetings for things like you've heard for red oil 3 and HAN. There were numerous meetings related to 4 discussing the technical details of those.
5 We had a request for additional 6 information after we did our review. And I'll go 7 through a little bit more of the process there for 8 what we did for request for additional information.
9 Needless to say we had substantial 10 communications between the staff and the applicant.
11 The approach we tried to take is to make sure. We 12 didn't want to just go back and forth and ask 13 questions. We wanted to make sure there was good 14 understanding on all sides of what our issues were, 15 what the applicant's positions were and made sure 16 there was a good meeting of the minds of what we did.
17 As part of the review in each individual 18 technical discipline where it was needed, some 19 confirmatory calculations were done. Again this is 20 very specific to particular technical disciplines.
21 And what the staff determined they needed to come up 22 with their conclusions.
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264 1 about there was a varying of events. I recall they 2 were broken up into criticality and non criticality, 3 things like explosions, loss of confinement events, 4 load handling events. The staff looked at all of the 5 non criticality type events to some extent.
6 But events like red oil and HAN which has 7 been mentioned are vertical slices. We went very deep 8 into looking at those trying to understand exactly 9 what was there, looking at the documents, and doing 10 our review.
11 The other thing is we looked at as you've 12 heard the applicant has determined events. The staff 13 looked at all the events that the applicant came up 14 with us. But we didn't limit ourselves just to that.
15 We wanted to make sure that there were other events 16 that should have been considered in the ISAs that 17 hadn't. And there's actually a couple events that 18 determined through the three and a half review that 19 were added from the initial submittal and the ISA 20 summary. So you try and emphasize what the applicant 21 has done. But we don't -- It's a trust but verify.
22 We also considered the items that were in 23 the ACRS letter from the construction authorization as 24 the applicant has gone through. In our SER we have 25 not identified any open items.
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265 1 Just real quickly this organization of the 2 SER we're following the NUREG 1718. I won't talk 3 about all these different areas. But we covered all 4 the major of the big player. You know, fire, chem, 5 crit. This is basically a chemical facility. So as 6 you'd expect, we emphasize a lot of the activities and 7 review activities related around that. But we've 8 covered everything.
9 The Chapter 11, Plant Systems, that you 10 see this is a very broad thing varying from the 11 confinement systems, the civil structural design, load 12 handling. So that contains a lot of different things 13 in that chapter. So we've gone through extensively in 14 the review. But like I said, I'll just touch on a 15 little bit of what we've actually done, some specific 16 areas.
17 To kind of give you an idea of what we did 18 over the last three and a half years, I put this table 19 together which is over the next two pages to kind of 20 lay out each specific discipline, number of meetings.
21 And meetings would be one, two, three day durations 22 between applicant and the staff. The in-office reviews 23 as I explained, you know, the applicant had actually 24 set up a local office where documents were available 25 for the staff to review and RAIs. The next one.
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266 1 You kind of see the whole thing and then 2 kind of in summary of this over the three and a half 3 year period you know we held about 70 different 4 meetings and all these technical disciplines. There 5 was around 100 different in-office reviews. And there 6 were about 600 RAIs generated. As you can see, just 7 to get a flavor, the staff has done very extensive 8 review of this application.
9 The RAI process itself, we did it on a 10 discipline specific basis. Each of these areas, even 11 though they're integrated, and we made sure we handled 12 areas that are integrated, looking at things like fire 13 events and explosion events. For specific disciplines 14 like chem safety, we did reviews of chem safety 15 aspects.
16 After we looked at the actual documents, 17 performed the in-office reviews, did whatever 18 confirmatory calculations, had our different meetings 19 with the applicant to make sure we fully understood 20 what was in there, we developed our request for 21 additional information.
22 But again the idea of trying to have a 23 good communicative process, we didn't want to just 24 send a bunch of questions out. We wanted to make sure 25 that the applicant fully understood where the staff NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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267 1 was coming from. So the approach we took is we had 2 meetings to discuss what our questions were before we 3 issued them to make sure that the applicant understood 4 what they were. And also when the applicant prepared 5 their responses before they officially sent responses 6 in we had sometimes -- we had at least one but 7 sometimes more than one meeting along the way to make 8 sure they were actually hitting the mark for what the 9 staff had requested.
10 Following that interaction, the applicant 11 formally responded to the RAI, revised the LA and ISA 12 summaries as appropriate. And one of the keys as was 13 mentioned a little earlier in this process of Part 70 14 the license application is what contains the 15 commitment. So the staff was very careful to make 16 sure that the things that we needed to make our safety 17 case those commitments were made in the LA. That will 18 be the enforceable document throughout after a license 19 is issued. And as I said we had issued over 600 RAIs.
20 Just kind of to give you the flavor of the 21 details of the review, the applicant talked about 22 their strategy related to red oil. So I'll talk a 23 little bit about how we came to our conclusions 24 related to the red oil event.
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268 1 know, a lot of staff effort was spent on this. A lot 2 of reviews of documents, multiple meetings trying to 3 make sure there was a full understanding of exactly 4 what the applicant had done before from the 5 construction authorization, what they were planning in 6 the stage, what their strategies were.
7 The kinds of documents that we looked at, 8 of course, we looked at the LA and the ISA summary.
9 We looked at the commitments in the LA. The nuclear 10 safety evaluations which are the first layer below the 11 ISA summary. You kind of think of these documents.
12 You think of an onion. You know the LA and ISA 13 summary are kind of the skin and the first layers of 14 the onion. But in order to have the true 15 understanding of everything that's in there, you have 16 to peel down and really all these other documents that 17 we looked at were really peeling down into the onion 18 to make sure we have full understanding of that.
19 We also for red oil looked at the Defense 20 Nuclear Facilities Safety Board recommendations 21 related to red oil. We looked at international 22 reports including other experiences internationally, 23 the French since these facilities are modeled after 24 French facilities. What the French regulator looked 25 at in terms of red oil.
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269 1 The staff reviewed the previous incidents.
2 As Sven had mentioned, there had been some previous 3 red oil incidents back in the '50s. And there were 4 lessons learned that came out of that. So the staff 5 looked back at those incidents to see what those 6 lessons learned were, to see how they were integrated 7 into the current strategies.
8 We reviewed the applicant's calculations 9 on various things like the venting and other things 10 that they had in there. Additionally for red oil 11 there was an independent evaluation that was done by 12 Brookhaven National Labs to kind of look at the red 13 oil phenomenon from a different angle. So that was 14 part of what the staff looked at the results of that 15 also.
16 And how did we come to our conclusion. We 17 looked at the applicant's strategies versus the DNFSB 18 and all the other information of the French and other 19 operating facility experiences. We looked at the 20 safety of origins that they had in there, the 21 redundant IROFS, the numbers of IROFS. As they 22 mentioned, they are layers of protection. Those are 23 the kind of things that we looked at.
24 We looked at in terms of the ISA structure 25 of the four pillars of how the IROFS were identified, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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270 1 how they incorporated management measures, QA and 2 codes and standards. And then, of course, we looked 3 at the lessons learned from previous red oil events.
4 And in the case of red oil the staff agreed that after 5 the IROFS are applied and all the other pillars of the 6 ISA process were implemented then the red oil is 7 highly unlikely.
8 For my second example I tried to use 9 something that was a little bit different. So I chose 10 criticality. If you look at the different events like 11 loss of confinement and explosion, they are all fairly 12 well defined as a relatively small number of event 13 groups even though there are a lot of groups of events 14 there.
15 For criticality, it's different. There is 16 a lot of events. There is in the 1,000 of events.
17 There is many. I believe where there was I believe 18 nine nuclear safety evaluations there is in the range 19 of 48 nuclear criticality safety evaluations on each 20 process unit. So the staff couldn't look at 21 everything and all of them. So we looked at safety 22 basis documents and we developed a very detailed 23 methodology for how we would do our vertical slice for 24 criticality.
25 So we looked at the ISA summary. And then NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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271 1 we looked at again, peeled down the onion and looked 2 at the NCSEs, the many calculations, things like the 3 piping instrumentation diagrams, other documents that 4 were available, the different drawings of the facility 5 to make sure we had a good understanding of it, a 6 system design description of the process, the hazard 7 analysis and the technical. So there's a lot of 8 information underlying what you see in the ISA summary 9 related to criticality.
10 And for our vertical slice, since there is 11 as I mentioned, 53 criticality control units, our 12 reviewers determined that we were going to look at 13 certain ones and the ones we chose were ones based on 14 the highest potential for criticality. So it's the 15 form and quantity and material. So things that were 16 in the aqueous stage we looked at those as being 17 something that was more significant than some of the 18 powder areas that were more understood.
19 So we tried to break out our vertical 20 slice into areas that we thought basically the more 21 bang for the buck. We looked at the type and 22 complexity of systems, things that were relatively 23 straightforward compared to some things that were 24 fairly complex in terms of what needed to go on, what 25 kind of parameters and strategy the applicant was NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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272 1 using for each of these particular areas, how much 2 redundancy, how much they're counting on 3 administrative controls. Also in terms of 4 integrating, we looked at the significance from one 5 unit to another, you know, particularly areas in tanks 6 where it went from criticality safe geometry to areas 7 that are not criticality safe geometry. So those are 8 areas of particular concern.
9 We looked at the safety of origins in 10 terms of determining our vertical slice. And also 11 since the French facilities were designed as was based 12 on we looked at deviations from the referenced French 13 facility design. Also the criticality reviewers did 14 an in-office review basically at the French facilities 15 to make sure they understood what actually happened in 16 the operating facilities at La Hague and MELOX.
17 So we didn't limit ourselves just to 18 looking at documents. We actually looked at the 19 actual facilities that were operating and talked to 20 the individuals that were more involved in that design 21 in France.
22 And how did the staff come to its 23 conclusion for criticality. We reviewed the 24 applicant's methodology for highly unlikely and 25 compliance with double contingency. We performed some NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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273 1 confirmatory calculations as we determined was 2 appropriate.
3 Kind of our conclusions here where the 4 staff has in place, that the applicant has in place, 5 the staff qualified to do an NCS program, a 6 criticality safety program. The applicant conduct 7 operations based on technical practices, has 8 established safety limits and controls, the processes 9 are subcritical and under normal and abnormal 10 conditions and adhere to double contingency principle.
11 The SRP laid out many, many things that 12 the applicant needed to do and part of the details of 13 that is making sure they had met all the ANSI guidance 14 related to criticality, that they actually did it and 15 that they committed to doing all the things that we 16 felt were necessary for a criticality safety program.
17 One thing that was a little bit different 18 in the criticality write-up. There is some 19 discussions related to things that needed to be done 20 during PSSC verification. It's a little different 21 than the other chapters. As I had mentioned before we 22 can issue a license we have to go through a process of 23 PSSC verifications. Criticality safety is a PSSC. So 24 anything that we talk about verifying that will be 25 done prior to issuance of license. That's why we NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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274 1 didn't consider any of those things open items because 2 that PSSC verification process is something that's 3 going on for all the systems that you see in the SER.
4 And just kind of a conclusion for 5 criticality, the staff has reasonable assurance that 6 the applicant's implementation of the ISA will meet 7 the requirements of Part 70 and provide and ensure 8 protection of the public health and safety including 9 worker's environment basically agreeing with the 10 applicant's termination of highly likely for various 11 criticality events.
12 And just kind of in conclusion again the 13 staff is requesting the ACRS endorsement of the SER.
14 The license will not be issued until we've completed 15 our PSSC verification. So there is opportunities to 16 complete what's required in the regulation and make 17 that these items are better related or completed and 18 constructed properly. And the staff in the SER 19 concluded that the license application meets the 20 requirements in Part 70 as we documented in the SER.
21 MEMBER POWERS: Wonderful. That was 22 really good. I like that. Wanted it at high level 23 and wanted to know exactly what the staff had done and 24 I think you did -- you hit my nail on the head. Let's 25 see if the members' nails were hit on the head. Are NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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275 1 there any questions to staff.
2 MEMBER BONACA: You have --
3 MEMBER POWERS: Understand, of course, 4 that you just got a quick tour of the two days of 5 detail and many thousands of pages.
6 MEMBER BONACA: I have a question.
7 PARTICIPANT: Five hundred and sixty eight 8 in the SER.
9 MEMBER BONACA: I had a question on page 10 14. You have a statement there that says "Deviations 11 for referenced French facility design." Were there 12 many of those? And were they significant?
13 MR. TIKTINSKY: Chris Tripp who is our 14 criticality reviewer would you like to answer that?
15 MR. TRIPP: I would say there weren't a 16 lot of changes. There may be a handful. I think half 17 a dozen or so are mentioned specifically in the SER.
18 One particular change is that in France they've 19 basically credited the normal process PLC as a safety 20 control. In the U.S. facility they don't take credit 21 for that. That still exists. That's being used as 22 defense-in-depth. But they credit two redundant 23 safety PLCs instead. So that's one change.
24 There are other changes concerning in 25 France they have a lot of radiation detectors that are NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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276 1 used basically to indicate that you're starting to 2 have a mass buildup. Whereas in the U.S. facility in 3 some cases they're going to be used to actually 4 correlate to the mass to plants with a mass limit.
5 That was another case. So there are things of that 6 nature, a lot of which has to do with the different 7 isotopics, the reactor grade versus the pure plutonium 8 in the U.S. facility.
9 MEMBER BONACA: Thank you.
10 MR. TRIPP: We tried summarize those in 11 the SER because we did put a lot of emphasis on the 12 operating history in making our conclusion.
13 MEMBER BONACA: Thank you.
14 MEMBER POWERS: Any other comment?
15 (No response.)
16 Well, thank you very much.
17 MEMBER ARMIJO: Dana, before you go, I 18 just want to say I attended the subcommittee meeting.
19 I didn't participate in the early construction stuff.
20 But it was an impressive amount of work that's been 21 done by the applicant and clearly by the staff. The 22 thing that really bothers me is something that's 23 probably above your pay grade and mine. But I'll 24 speak to it anyway.
25 (Laughter.)
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277 1 And that is the vulnerability of this 2 facility to an external threat that apparently is not 3 in the regulations and that is what we're doing for 4 new reactors today in doing aircraft impact 5 assessments. And I know this is not a reactor. I 6 know it's not a high energy facility. But it does 7 have tons of plutonium in a variety of forms, liquid 8 and powder and everything else. And it seems to me 9 there's a lack of consistency in the safety 10 requirements for a threat that's credible enough to 11 apply to new nuclear plants. But why isn't it applied 12 to this facility? And I'll leave it at that just as a 13 comment for the record.
14 MEMBER POWERS: Now we'll go back to 15 thanking you all for you did what I didn't think was 16 possible. But you gave us a good thumbnail sketch on 17 what the facility is and how you happened things and 18 an excellent summary of all the work that the staff 19 did. It was quite impressive.
20 And with that, I'll turn it back to you, 21 Mr. Chairman.
22 CHAIRMAN ABDEL-KHALIK: Thank you. At 23 this time we will take a break, and we will come back 24 in session with this clock at 5:50 p.m.
25 (Whereupon, the above-entitled matter went NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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278 1 off the record at 5:32 p.m.)
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GE Hitachi Nuclear Energy ESBWR Long Term Core Cooling Advisory Committee on Reactor Safeguards Jesus Diaz-Quiroz Wayne Marquino September 9, 2010 Copyright 2010, GE-Hitachi Nuclear Energy Americas LLC All Rights Reserved
GEH Agenda
- ESBWR Core Cooling
- ESBWR Containment Cooling
- ESBWR Debris 2
ESBWR Long Term Core Cooling Core does not uncover in the worst break, considering uncertainties.
- More than 0.5 m margin at time of minimum level Core does not dryout or heatup in ESBWR
- PCT=Initial temperature Containment Pressure remains below design pressure for 72 h
- Post 72 h RTNSS system, PCCS vent fans employed to maintain pressure at a reduced level
==
Conclusion:==
Passive systems provide core cooling for 72h, followed by depressurization from RTNSS PCCS vent fan 3
ECCS Safety-related core cooling is provided by GDCS Injection Lines and PCCS
- Coolant inventory required for core coverage and cooling inside containment - GDCS pools
- GDCS injection lines drain pools into vessel and boil off is condensed by PCCS and returned via GDCS injection lines RG 1.82 Rev. 3 Not Applicable to ESBWR
- GDCS and PCCS do not utilize pumps
- Safety-related source for coolant in GDCS pools
- GDCS equalizing lines not required to open for LOCA scenarios as identified in DCD Chapter 6 Short and long term core cooling provided by GDCS Injection Lines and PCCS can be sustained 4
Defense-in-Depth Suppression Pool Cooling
- Cooling automatically provided by Fuel & Auxiliary Pool Cooling System (FAPCS) during normal operation to maintain pool temperature
- Reactor Water Clean Up (RWCU)/Shutdown Cooling (SDC) can also be used through a cross-tie with FAPCS High Pressure Injection
- High Pressure CRD makeup source of coolant comes from the Condensate Storage System (isolates in a LOCA)
Low Pressure Injection
- FAPCS or RWCU/SDC through cross-tie can provide low pressure makeup with source of coolant from the suppression pool or the Condensate Storage System
- Operator action is required to initiate FAPCS or RWCU/SDC in low pressure injection mode 5
Sources of Debris to FAPCS/SDC
- Insulation
- Insulation is restricted to reflective metal insulation (RMI) inside containment.
- Unqualified coatings are not allowed in the containment.
- The coating systems applied inside containment meet the regulatory positions of RG 1.54 and the standards of ASTM D 5144.
- Other
- Rust particles are minimized by use of approved coatings.
- Drywell rust particles, dirt and dust, operational fibrous (e.g. rags) debris
- Sludge (pools)
- Suppression pool sludge is minimized by the use of stainless steel liners 6
FAPCS Suppression Pool Suction Strainer
- FAPCS suppression pool suction strainer is a Quality Group B and Seismic Category I component.
- It has perforated plate hole sizes of < 2.508 mm (0.0988 inches)
- Both seismic category and hole size are required to be confirmed by ITAAC.
Prototypical BWR Suction Strainer 7
NPSH Margins FAPCS in low pressure injection mode with suppression pool as source analyzed
- No credit for Containment Overpressure
- Assumed debris types and amounts expected for a current operating BWR plant
- Analyzed at minimum and maximum pool temperatures
- FAPCS RWCU/SDC pumps are located below the suppression pool floor (both at same level)
Temperature NPSH NPSH Total Debris NPSH Available Required Head Loss Margin oF (oC) ft ft ft ft 110 (43.3) 71.4 16.4 19.26 35.74 169 (76.1) 60.6 16.4 12.27 31.93 NPSH Margin = (NPSH Available) - (NPSH Required) - (Total Debris Head Loss) 8
Debris Transported to Reactor Vessel
- The earliest possible injection to the RPV is limited by the maximum injection pressure of the FAPCS in LPCI mode.
- 290 psi is the potential maximum pressure the system can provide (DCD Table 9.1-8, tube side maximum pressure for FAPCS heat exchanger).
- Postulated earliest time for injection after a LOCA is 150 seconds which provides ample time for RMI to settle in suppression pool.
- The low end settling velocity for RMI is 0.39 ft/s and suppression pool high water level is 18 ft, which results in settling time of about 46 seconds.
- The FAPCS suppression pool suction strainer limits the debris sizes to diameters of less than 0.0988 inches.
- WROG Blockage fractions have been applied to ESBWR
- GE14E lower bundle geometry included
- Lower ESBWR debris source, and larger number of bundles.
9
Postulated Fuel Blockage
- Fuel blockage cannot occur from debris entering top of bundles since debris injection into the RPV can only occur outside the shroud and then path available to enter bundles is through bottom of core plate.
- Route for debris to enter bundles is through fuel support orifices.
- Analyzed fuel blockage for ESBWR using TRACG analysis follows the NRC/BWROG presentation, BWR LOCA Long Term Cooling Fuel Effects to Debris Blockages.
- Limiting RPV water level (IC drain line) LOCA was analyzed.
- No heat up from initial temperature
- For 100% blockage of lower tie plate, lower tie plate holes provide cooling ESBWR Fuel Blockage Results 10
Summary
- Passive systems provide core cooling for 72h, followed by depressurization from RTNSS PCCS vent fan
- Debris considered from the backup injection systems
- Suction strainer designed with bounding source
- Blockage will not cause fuel over-heating ESBWR design provides Long Term adequate Core Cooling with margin 11
Backup Material 12
Chimney Water Level - IC Drain Line Break LOCA 24 22 Chimney 2-Phase Level 20 Top of Active Fuel Level Position (mVesselZero)
Static Head Inside Chimney 18 Top of Chimney Partitions 16 Top of Chimney Partition 14 12 10 8
Top of Active Fuel 6
4 0 200 400 600 800 1000 1200 1400 1600 1800 2000 Time (s) 13
Containment Pressures (30-Day LOCA) 14
Debris Generation Zone of Influence, Reflective Metal Insulation (RMI)
- High energy line break selection is restricted to systems with piping at or above the containment drywell diaphragm floor.
- The entrance to the vertical vents (debris transport path to the suppression pool) is located at the same elevation as the diaphragm floor.
Systems Break Locations Main Steam Piping, 30 Sch. 80 Pipe end at the RPV nozzles (Outside of the annulus)
Feed Water Piping at Nozzle, 12 Sch. 80 Pipe end at the RPV nozzle located inside the annular space between the RPV and Shield wall Isolation Condenser Piping (supply to Pipe end at the RPV nozzle located inside the isolation condensers), 18 Sch. 80 annular space between the RPV and Shield wall Head Vent1, Sch. 2 At RPV
- Main steam line break has the highest potential for generating most debris since it has the largest zone of influence.
- Main steam line break will have the highest water level in the reactor pressure vessel (RPV) when compared to other LOCAs.
15
Generation and Transport of Debris to Suppression Pool Latent debris and transported debris is calculated using methodology in NEDO-32686, Revision 0, "Utility Resolution Guidance for ECCS Suction Strainer Blockage," (URG).
Material Expected to be Entrained in Suppression Pool During a LOCA Debris Type Source Amount Iron Oxide Sludge2 Suppression Pool 600 lbm RMI4 Drywell 4244 ft2 Inorganic Zinc (IOZ) Drywell 47 lbm IOZ Top Coated with Epoxy Drywell 85 lbm Rust Particles Drywell 50 lbm Drywell Dirt and Dust Drywell 150 lbm Operational Fibrous Debris3 (2.4 lbm/ft3) Drywell 1 ft3
- 1. Debris types and amounts are from topical report NEDO-32686, Revision 0, Utility Resolution Guidance for ECCS Suction Strainer Blockage, (URG).
- 2. Sludge already in suppression pool. The URG specifies 300 lbs/year for plants that do not conduct a plant specific analysis of sludge. ESBWR is expected to operate on 24 month fuel cycles.
- 3. Operation fiber is based on engineering judgment and is not provided in the URG.
- 4. Calculated from Main Steam Line break.
16
Operator Actions
- Emergency Procedures will determine appropriate conditions for FAPCS/SDC operation considering:
Core water level Suppression pool temperature Pool and containment levels Radiation levels (FAPCS/SDC vs. FAPCS)
Pressure vs. time (debris settling in suppression pool)
- Initiate suppression pool cooling then low pressure injection mode to bring the vessel to cold shut down 17
Containment/Core cooling Flow paths from containment Described below, with excerpts from the DCD 5.4.8.2.1 Describes the post LOCA RWCU/SDC function with FAPCS cross tie Figure 2.6.2-1. Fuel and Auxiliary Pools Cooling System schematic is marked up with flow paths , starting with the suppression pool suction strainer on the lower left the flow path is outlined in magenta. The flow path continues horizontally changes to red on the diagram to the FAPCS pumps and heat exchangers. The red flow path shows return flow to the reactor vessel. Returns flow can also be directed to the suppression pool for pool cooling, that path is shown in green.
The FAPCS pump and heat exchangers are in the fuel building which is outside the reactor building.
18
Cooling Flow paths (contd) 6.3 In the DBA LOCA, there is no fuel heatup or damage, the above flow paths could be used without spreading contamination. If there were fuel damage and contamination the flow would be constrained to the reactor building. From the suppression pool suction strainer, it would leave the FAPCS system
( magenta down arrow on diagram) and connect to the RWCU/SDC system.
Figure 5.1-4. Reactor Water Cleanup/Shutdown Cooling System Schematic shows the connection from FAPCS Suppression Pool suction at the center of the schematic, (upward pointing magenta arrow, flow enter ing from the FAPCS system ), the flow through the RWCU non-regenerative heat exchanger, and the flow through the RWCU pumps. The flow from the pumps and heat exchangers can be directed to the reactor (red arrow pointing left) Flow can also be directed to the suppression pool (magenta arrow pointing right), returning via the suppression pool flow path shown on Figure 2.6.2-1.
6.2.1.1.3.5.1 describes the use of the FAPCS/RWCU/SDC system in post LOCA cool down (assuming fuel damage) . Figure 6.2-14e11&12. Post-LOCA Containment Cooling and Recovery, shows the containment pressure
& temperature Response - operating first in pool cooling mode, then in vessel injection mode.
19
NRC STAFF REVIEW OF THE APPLICATION FOR A LICENSE TO POSSESS AND USE RADIOACTIVE MATERIAL AT THE MIXED OXIDE FUEL FABRICATION FACILITY (MFFF)
Presentation to ACRS September 9, 2010 David Tiktinsky, FCSS/NMSS 1
OUTLINE FOR DISCUSSION
- Purpose of presentation
- Licensing process and Safety Evaluation Report (SER) development
- Examples of detailed staff review 2
Purpose of Presentation
- Seek ACRS endorsement of the staffs evaluation of the LA for the MFFF
- Final SER planned to be completed by December 2010 3
Licensing Process (Background)
- Staff SER on Construction Authorization Request and Construction Authorization issued (March 2005) (previously reviewed by ACRS)
- License Application (LA)/Integrated Safety Analyses Summary (ISAS) submittal (September 2006)
- Staff acceptance of LA for docketing (12/06)
- Technical review (12/2006-2010)
- Draft SER on LA prepared with no open items (6/2010)
- Licensing in litigation with Atomic Safety and Licensing Board (ASLB)
(one contention accepted)
- Hearing after completion of final SER
- Principal Structure System and Component (PSSC)(identified in CAR) verification (2014 estimated completion)
- License will not be issued until this step is completed
- Issuance of license to possess and use radioactive material
- Operational readiness review
- Hot startup 4
SER Development
- Staff used Standard Review Plan for MOX (NUREG-1718)
- Staff review included:
- In-office reviews
- Discussions with applicant
- Requests for Additional Information (RAI)
- Substantial communications between staff and applicant
- Performing confirmatory calculations (if needed)
- Detailed vertical slice review
- Looked at events identified by applicant and verified that other events were adequately considered
- Considered items identified in ACRS on Construction Authorization Request (CAR) SER letter
- No open items identified 5
SER Organization
- Outline of SER
- Chapter 1 - General Information
- Chapter 2 - Financial Qualifications
- Chapter 3 - Protection of Classified Matter
- Chapter 4 - Organization and Administration
- Chapter 5 - ISA
- Chapter 6 - Criticality
- Chapter 7 - Fire Protection
- Chapter 8 - Chemical Safety
- Chapter 9 - Radiation Safety
- Chapter 10 - Environmental Protection
- Chapter 11 - Plant Systems
- Chapter 12 - Human Factors
- Chapter 13 - Safeguards and Security
- Chapter 14 - Emergency Management
- Chapter 15 - Management Measures
- Chapter 16 - Authorizations and Exemptions 6
Technical Review Summary REVIEW AREA MEETINGS IN-OFFICE RAIs HELD REVIEWS GENERATED Civil/Structural 1 3 2 Criticality Safety 5 13 95 Chemical 8 39 125 Processing Classified 2 1 25 Matter Handling Confinement 4 4 39 Fire Protection 5 7 13 ISA 7 1 29 Electrical/ 5 17 38 Instrumentation and Control 7
Review Summary (cont)
REVIEW AREA MEETINGS IN-OFFICE RAIs HELD REVIEWS GENERATED Radiation 3 24 Protection Emergency 4 5 Planning Environmental 2 1 Protection Mechanical/Fluid 2 5 17 Human Factors 4 2 31 Material Control 6 1 142 and Accounting Management 3 7 59 Measures Physical Protection 4 1 24 8
RAI Process Used in the Review
- Prepared on discipline specific basis
- Staff performed document reviews, in-office reviews, confirmatory calculations, etc.
- Staff met with applicant to assure understanding of Staffs concern
- Applicant prepared response and meets with staff prior to officially responding
- Applicant formally responds to RAI and revises LA/ISA summary as appropriate
- Over 600 RAIs were prepared 9
Detailed Technical Review Example (Red Oil)
- Topic - Red Oil explosion event
- What the staff did:
- Performed extensive in-office reviews
- Held multiple meetings with applicants experts
- What the staff reviewed
- LA and ISA Summary
- Nuclear Safety Evaluations
- DNFSB/TECH-33 report
- International reports
- Previous incident reports
- Applicants calculations
- Independent evaluation reports prepared by Brookhaven National Laboratories 10
Detailed Technical Review Example (Red Oil)-
Continued
- How did the staff come to its conclusion?
- Compared applicant safety strategies with applicable DNFSB, French, and other operating facility experiences
- Evaluated safety margins
- Evaluated applicants IROFS selected to make red oil event highly unlikely
- Incorporation of lessons learned from previous red oil events
- Staff agrees that after IROFS are applied, then a red oil explosion event is highly unlikely 11
Detailed Technical Review Example (criticality)
- Nuclear Criticality Safety
- Review Strategy
- Safety Basis Documents Reviewed
- Vertical Slice Review 12
Detailed Technical Review Example (criticality)
(continued)
- Documents reviewed:
- ISA Summary
- ISA Documents
- Nuclear Criticality Safety Evaluations (NCSEs)
- Calculation documents
- Piping & instrumentation diagrams
- Drawings
- Other:
- System description documents (SDDs)
- Process hazards analyses (PrHAs)
- Technical notes 13
Detailed Technical Review Example (criticality)
(continued)
- Vertical Slice selection
- Ranking for detailed vertical slice review (of 53 criticality control units) based on criticality potential based on form and quantity of special nuclear material
- Type and complexity of control systems
- Diversity of parameters and strategy
- Redundancy (especially administrative)
- Significance to downstream units
- Safety margin
- Deviations from reference French facility design 14
Detailed Technical Review Example (criticality)
(continued)
- How did the staff come to its conclusion?
- Reviewed the applicants implementation of ISA methodology (highly unlikely and compliance with double contingency principal)
- Performed confirmatory calculations as appropriate
- The staff determined:
- The applicant has in place a staff qualified for a NCS program
- The applicant can conduct its operations based on technical practices sufficient to ensure that licensed material will be possessed, stored, and used safely according to the requirements of 10 CFR Part 70;
- The applicant has established safety limits and controls sufficient to ensure subcriticality, including an appropriate margin of subcriticality for safety for all credible events
- All processes are subcritical under normal and abnormal conditions and will adhere to the double contingency principle 15
Detailed Technical Review Example (criticality) (continued)
- The staff has reasonable assurance that the applicants implementation of its ISA will meet the applicable requirements of 10 CFR 70.66(a) and will ensure protection of public health and safety, including workers and the environment 16
Conclusion
- License will not be granted until after PSSC verification completed
- Staff concluded that the MFFF License application meets the requirements of 10 CFR Part 70 as documented in the SER 17
Presentation to the Advisory Committee on Reactor Safeguards Full Committee ESBWR Long-term Cooling Hanry Wagage George Thomas James Gilmer September 9, 2010
Long-term Cooling
- Previous ACRS interactions
- December 3, 2009, ACRS Full Committee meeting
- July 13, 2010, ACRS ESBWR Subcommittee meeting
- Regulatory Criteria: 10 CFR 50.46(b)(5) and GDC 10 and 50 of 10 CFR 50 Appendix A September 9, 2010 2
Figure 1. Drywell pressure predicted by MELCOR for MSLB (bounding case)
September 9, 2010 3
5 DCD Rev. 7 MELCOR Constant 10" Submergence TRACG No PCC pool level control Design 4
Drywell Pressure (bar) 3 2
1 0 72 144 216 288 360 432 504 576 648 720 time (hr)
Figure 2. Drywell pressure predicted by MELCOR and TRACG (DCD Rev. 7) for MSLB (bounding case)
September 9, 2010 4
Core Cooling Water Sources
- GDCS Pool
- Stainless steel liner
- Gap between the top of the wall and the drywell ceiling (0.804 ft) is protected by shield and covered with a perforated plate with holes of diameter of less than 1.5 inches
- No significant accumulation of debris in GDCS pool
- Suppression Pool (Beyond DBA or manual action)
- Stainless steel liner
- Strainer
- Suppression pool cleanup during normal operations (Mode of FAPCS - Fuel and Auxiliary Pools Cooling System)
September 9, 2010 5
Alternate injection sources
- Control Rod Drive pumps taking suction from Condensate Storage Tank
- Demineralized water
- Water source outside containment
- Fire Protection System through Fuel and Auxiliary Pools Cooling System (FAPCS) provide cooling from 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> to 7 days
- Water source outside containment September 9, 2010 6
Core Cooling
- Debris is not expected to reach the core for DBA
- Cooling provided by closed loop
- No recirculation of water in drywell
- Staff concern regarding possible introduction of debris from non-safety injection sources
- Down stream effects
- GEH calculations show that boiling transition is not expected even if significant portion of the flow areas in the inlet orifice and lower tie plate are blocked
- Submitted in response to RAI 4.4-23
- Conclusion - core cooling is maintained September 9, 2010 7
Long-term Cooling:
Conclusion
- ESBWR design-basis LOCA containment long-term pressure response calculated by TRACG, which is confirmed by staffs MELCOR analysis, is below the containment design pressure and is acceptable.
- Long term core cooling has been demonstrated September 9, 2010 8
Schematic of ESBWR containment (DCD Figure 6.2-15)
September 9, 2010 9
Fuel and Auxiliary Pools Cooling System (FPACS)
September 9, 2010 10
Closure Options for Generic Safety Issue 191, PWR Sump Performance Presented by:
Christopher Hott/Michael Scott Office of Nuclear Reactor Regulation Presented to:
Advisory Committee on Reactor Safeguards September 9, 2010 1
Purpose of Presentation
- Provide background/context for SECY-10-0113
- Discuss current status of resolution of sump performance issue
- Discuss views of stakeholders
- Provide overview of SECY-10-0113
- Discuss staffs recommendations 2
Background
- Generic Safety Issue (GSI) 191 involves demonstration that emergency core cooling system (ECCS) strainers will perform acceptably after a loss-of-coolant accident (LOCA)
- Early on, NRC staff concluded and ACRS supported that near-term action to make PWR strainers larger was prudent
- Issue has evolved as understanding has improved regarding various aspects of the problem since Generic Letter (GL) 2004-02 was issued
- Each licensee has made a major effort to resolve the issue (strainer sizes increased by 1-2 orders of magnitude), but licensees and staff have been repeatedly challenged by emergent issues 3
Issue Resolution Status
- 33 of 69 PWRs have already performed analysis and strainer testing using methods acceptable to the NRC staff -13 more plan to do the same
- Most of the 23 remaining plants have relatively large amounts of fibrous insulation
- Attempts to credit test and evaluation refinements have not generally succeeded
- Debris generation/zone of influence (ZOI) reductions
- Debris settling credit
- Staff has accepted testing that credits reduced debris erosion
- Industry planning new efforts to credit settling and ZOI reductions - staff will evaluate 4
Commission Brief April 2010
- Staff planned in early 2010 to push toward final near-term resolution via 10 CFR 50.54(f) letters
- In April 15 Commission brief, industry stakeholders expressed concerns about staff path forward
- Little safety benefit
- Large radiation exposure to workers
- Union of Concerned Scientists letters
- Staff on track to successful issue closeout
- Could support LBB under specified circumstances 5
Staff Requirements Memorandum (SRM) May 2010
- Staff should not issue letters under 10 CFR 50.54(f) pending further Commission direction
- Staff should report to Commission by 8/27/2010 on potential approaches to closure, including:
- Realistic ZOI
- Application of General Design Criterion (GDC) 4 (LBB)
- In-vessel effects of different fuels
- Risk-informed resolution (e.g., proposed 10 CFR 50.46a)
- Alternative regulatory treatment of in-vessel effects
- Dose impact of resolution options
- Consult with the Committee to Review Generic Requirements to ensure closure approaches comply with backfit requirements 6
GSI-191 - Safety Issue?
- LOCAs of low probability, particularly large breaks
- Inability of sumps to pass adequate flow could lead to core damage and loss of mitigation system (containment spray)
- Uncertainties in sump performance, particularly for high-fiber plants, are significant absent a defensible test
- Prudent to not allow uncertainties to continue indefinitely 7
How Much Debris Reaches the Strainers?
- Lack of realistic models in areas critical to sump performance is the source of large uncertainty
- Bounding models are used to determine:
- How much debris is generated
- How much debris transports to the strainer
- The staff position is that these models are conservative, though not overly so
- Industry believes models are overly conservative, and some licensees have tried to justify refinements in key areas of debris generation and transport
- Reduced ZOIs
- Debris settlement credit 8
Dose Impacts
- Stakeholders indicated doses of up to 600 Rem and average of 200 Rem to replace all fibrous insulation
- Staff obtained data samples from a limited number of licensees who have replaced some insulation in containment - doses ranged from 5 to 44 Rem with an average of 19 Rem
- Staff data likely not bounding of worst case
- Some plants might not need to remove all fibrous insulation 9
Dose Impacts (contd)
Actual Plant Doses Scope of Insulation Work Performed (person-rem)
Plant 1 6 411 linear feet replaced on RCS,SG,FW piping Plant 2 8.9 2,319 linear feet replaced near SGs in loop rooms Plant 3 35.9 5,799 linear feet replaced/repaired near SGs in loop rooms, basement, annulus areas Plant 4 4.4 20 linear feet replaced on regen heat exchanger Plant 5 21 Unknown amount replaced on SGs, PZR head, spray line, PZR valves, SG drains, blowdown lines Plant 6 4.7 60ft3 removed/replaced, also added banding to several hundred linear feet small bore piping Plant 7 19.6 400 linear feet replaced and insulation on 3 SGs Plant 8 43.9 1300 linear feet replaced and insulation on 3 SGs Plant 9 23.6 1666ft3 replaced on SGs, PZR, and Rx head. All SG bay work treated as asbestos area 10
Options Discussed in SECY-10-0113
- Option 1: Current holistic integrated approach, with or without firm schedules
- Option 2: Develop additional risk-informed guidance
Staff-Recommended Options
- Combination of Options 1 and 2
- Near-term resolution schedule for smaller LOCAs, and longer-term schedule for the less-likely larger LOCAs
- Revisit risk tools for GSI-191
- Existing alternate methodology in 2004 safety evaluation
- Proposed 10 CFR 50.46a
- Option 3 not recommended for reasons discussed in this presentation 12
GDC-4 Rule: Statement of Considerations
- LBB credit enhances safety through the removal of plant hardware (i.e., the removal of pipe whip restraints and jet impingement barriers) that negatively affects plant performance, while not affecting ECCS, containments, and environmental qualification of mechanical and electrical equipment.
- LBB enhances safety through the removal of barriers to inspection
- LBB applies to local, not global, dynamic effects
- LBB removes the requirement to consider jet impingement forces on adjacent components, decompression waves within the intact portion of the piping system, and dynamic pressurization in cavities, subcompartments, and compartments 13
Application of LBB to GSI-191
- If GDC-4 is permitted to be applied to GSI-191
- Might eliminate the need for additional insulation change-outs at some affected plants - thereby reducing worker radiation exposure
- Would likely reduce the scope and number of needed insulation change-outs at affected plants
- Might eliminate need for additional strainer testing for some affected plants
- Licensees who have already shown satisfactory strainer performance could potentially recover operational margins
- Could simplify assumptions in GSI analysis and staff review for GSI-191 14
Disadvantages
- Inconsistent with intent of GDC-4 because there would be no benefit for reactor safety
- Large reduction in defense-in-depth (DID)
- LBB credit could allow large amounts of potentially problematic materials to remain in containment
- If an LBB pipe ruptures, despite being a low-probability event, it would cause debris generation that would be unevaluated for impact on ECCS strainer performance
- Small amounts and combinations of debris have been shown in testing to cause sump failure
- Sump failure following a LOCA in LBB piping would likely cause loss of the ECCS core cooling (a prevention feature) and also result in loss of the containment spray system (a mitigation feature) without any additional protection system failures 15
Disadvantages (Contd)
- Primary water stress corrosion cracking (PWSCC)
- LBB piping typically contains welds with Alloy 82/182 material which is susceptible to PWSCC
- Industry has implemented guidance and programs to minimize the impact of PWSCC such as augmented examination
- Some mitigation measures such as weld overlays and stress improvement have been implemented by some licensees
- Additional analyses would be needed prior to applying GDC-4 to GSI-191
- SRP 3.6.3 does not permit an active degradation mechanism (e.g., PWSCC). Increased inspections are an interim response relating to LBB piping
- LOCAs outside scope of LBB would be unaffected by this credit and could be problematic for some plants
- LBB has not been approved for less than 6-inch pipe 16
Policy Considerations
- Initiating event for accidents included in a plants licensing analyses should not result in core damage in the absence of additional independent failures
- Independence of prevention and mitigation - should minimize likelihood that a single cause results in failure of a prevention and mitigation feature
- Approving LBB for GSI-191 would be inconsistent with the proposed 10 CFR 50.46a regarding ECCS performance
- 10 CFR 50.46a requires ECCS to have capability to mitigate the full spectrum of LOCAs as directed by the Commission in SRM dated July 1, 2004 related to SECY-04-0037
- Allowing LBB to be used as the basis for not further modifying sump screens or for not removing sources of debris may prevent the ECCS system from performing its design function, which is contrary to licensees being able to successfully mitigate the full spectrum of LOCAs 17
Policy Considerations (Contd)
- Policy decision to expand GDC 4 to allow credit for GSI-191 would presumably include a Commission decision that the change:
- would not result in an unacceptable reduction in DID
- is appropriate even though there is no perceived safety benefit
- would not result in unintended consequences (e.g.,
unacceptable precedent for the use of LBB)
- Technical basis for expanding GDC-4 in the presence of PWSCC would need to be approved by the Commission
- Application of GDC-4 to GSI-191 would require revising the Statement of Considerations for GDC-4, revising the rule, and/or issuing exemptions 18
Recommendation
- Staff does not recommend that GDC-4 (LBB) be applied to sump evaluations to resolve the GSI-191 issue for the following reasons:
- Large reduction in DID for ECCS system performance that is inconsistent with DID principles
- Inconsistent with the intent of GDC-4 because there would be no corresponding safety benefit and the concern of local versus global dynamic effects
- LBB credit for a global effect might set a precedent for other areas of plant design
- PWSCC concerns in LBB piping
- Inconsistent with risk-informed ECCS rulemaking of 10 CFR 50.46a that represents current NRC staff thinking on risk-informing ECCS regulations 19
Risk-Informed Resolution of GSI-191
- Reg Guide 1.174 guidelines specify that a risk-informed resolution should have
- Acceptable delta risk
- Maintenance of sufficient DID
- Safety margins
- Monitoring program
- Application of risk-informed methods is complicated by current limitations in phenomenological modeling
- Key phenomenological models are either simplified and bounding (e.g., debris generation and transport) rather than realistic, or do not exist (e.g., debris bed head loss) 20
Change in Risk
- Bounding estimates indicate significant risk contribution for plants with high fiber or thin bed potential and unproven strainer capability:
- Medium (2 - 6 inch) break probability ~ 5x105/year
- Recirculation required
- Bounding sump clogging probability = 1.0
- Recovery options limited (backflush, extended injection)
- Current limitations in phenomenological modeling make development of realistic probability of clogging model infeasible
- Medium breaks do not satisfy risk criterion 21
Defense in Depth
- Loss-of-coolant accidents (LOCAs) of all sizes must be mitigated per regulation
- Sufficient DID would not be maintained with unrecoverable sump failure rate of 1.0 even if risk criterion is met
- Protection would be solely based on initiating event not occurring
- Loss of systems that prevent core damage and degradation of systems that mitigate consequences (containment spray) would result 22
10 CFR 50.46a Overview
- Proposed rule represents current staff thinking on risk-informing ECCS regulation
- Single-sided area of largest attached pipe (transition break size) is largest LOCA analyzed as a design basis accident (DBA)
- Mitigation analysis for larger LOCAs up to the double-ended break of the largest pipe is still required but can assume:
- Offsite power
- No single failure
- Non-safety equipment
- Enabled changes to licensing bases must be risk-informed with very small risk impact 23
Impact on GSI-191
- Affords flexibility of using nonsafety systems (e.g., backflush) for beyond-DBA LOCAs
- Potential (limited) benefit for debris source term
- Less rigor for analysis beyond DBA
- Refined test approaches (zone of influence, settling credit) and/or insulation replacements still likely needed for some plants
- Breaks below transition break size unaffected by proposed rule and potentially problematic for some plants
- Could reduce scope of insulation changeout for plants limited by larger breaks 24
Implementation of 50.46a for GSI-191 Only
- Final rule due to Commission this December
- Implementing guidance 12 months after Commission approval of rule
- Licensee must demonstrate
- Applicability of underlying basis for rule
- Risk-informed criteria must be met (~ RG 1.174)
- Leak detection system adequacy
- Add technical specifications to identify any non-safety equipment relied upon to mitigate beyond-DBA LOCAs
- Injection phase ECCS models and analyses not impacted by 50.46a application to GSI-191 25
Summary of 10 CFR 50.46a Option
- Represents current staff thinking on risk-informing ECCS requirements and is consistent with RG 1.174
- Would provide flexibility in resolving larger-break LOCAs but is not an analysis only solution
- Implementation for GSI-191 is not overly burdensome and would not affect injection phase analyses
- Schedule for rulemaking supports recommended option for GSI-191 closure but is dependent on Commission approval of 10 CFR 50.46a 26
In-Vessel Effects
- Industry planning cross test for September 2010
- Draft safety evaluation (SE) to be issued by September 2010
- ACRS review October/November 2010
- Final SE early 2011
- Staff view - strainer performance and in-vessel effects closely linked
- Resolving strainer issue in absence of consideration of in-vessel effects could lead to a strainer that would not clog and a core that would 27
Advantages of Recommended Approach
- Reasonably near-term resolution of an issue the staff sees as significant
- Allows time for additional attempts to refine evaluation methodology
- Maintains sufficient DID
- Incorporates available risk insights into evaluations and resolution schedule
- Continues demonstrably successful issue resolution process
- Contains checks and balances to reduce likelihood of staff requiring excess conservatism
- Implementation schedule is risk-informed and takes into account the amount of planning and effort required for licensee implementation 28
Conclusion
- Staff-recommended approach for issue resolution
- Maintain current integrated review process
- Revisit GSI-191 risk tools for evaluating larger LOCAs
- Set near-term resolution schedule for smaller LOCAs, and longer-term schedule for the less likely larger LOCAs
- Resolve in-vessel effects as part of GSI-191
- Staff does not recommend expanding LBB credit to GSI-191 29
Acronyms DBA design basis accident DID defense in depth ECCS emergency core cooling system FW feedwater GDC General Design Criterion GL Generic Letter GSI Generic Safety Issue LBB leak before break LOCA loss-of-coolant accident PZR pressurizer PWR pressurized water reactor PWSCC primary water stress corrosion cracking RCS reactor coolant system Rx reactor SE safety evaluation SG steam generator ZOI zone of influence 30
GSI-191 RESOLUTION OPTIONS John Butler, NEI jcb@nei.org September 9, 2010
SECY-10-0113 RESOLUTION OPTIONS Option 1 - Maintain the current holistic integrated resolution process for remaining plants including evaluating new refinement models a) Set near-term schedule for licensees to address the full spectrum of LOCAs b) Set near-term schedule for smaller LOCAs, and set longer term schedule for the less likely LOCAs c) Do not set a schedule for licensees to address remaining issues Option 2 - Develop additional risk-informed implementing guidance for GSI-191 a) Expand limited risk-informed guidance in Section 6 of the SE for NEI 04-07 b) Generate new guidance assuming the that proposed 10 CFR 50.46a is approved Option 3 - Application of the GDC-4 exclusion of jet effects to debris generation NRC staff recommends Option 1.b in combination with Option 2 The industry recommends Option 1.b in combination with Options 2 and 3 2
Industry Recommendations The industry recommends Option 1.b in combination with Options 2 and 3 Industry agrees that design basis for more likely breaks should be met using deterministic criteria and methods acceptable to the NRC
- Schedule should accommodate ongoing efforts to refine ZOI values, settlement credit in strainer testing and in-vessel effects 3
Industry Recommendations All risk-informed options should be pursued (available) to address low-likelihood breaks
- Expand risk-informed guidance in current SE on Section 6 of NEI 04-07 (Option 2a)
- Pursue approval of 10 CFR 50.46a and generate new guidance (Option 2b)
- Allow application of GDC-4 (Option 3) 4
Industry Recommendations Option 2a - Expansion of NEI 04-07 Section 6
- Section 6 in place currently with limited relaxation of known conservatisms
- Future value dependent on separation between guidance applied to small breaks and large breaks
- Schedule for development and application of expanded guidance unknown 5
Industry Recommendations Option 2b - Pursue approval of 10 CFR 50.46a and generate new guidance
- Greatest value in 10 CFR 50.46a comes from risk-informed changes enabled by rule that are not related to GSI-191
- The perceived value and subsequent plant interest varies by plant
- Significantly extends schedule for closure 6
Industry Recommendations Option 3 - Allow application of GDC-4
- Provide means to address unlikely breaks in manner that is risk-informed and complies with regulatory requirements
- Application by plants considered closed permits recovery of operational margins
- Guidance currently available and enables quick staff review and closure 7
Option 3 Allow application of GDC-4 Debris generation is a direct consequence of local dynamic effects excluded from postulated breaks in LBB qualified piping Debris generation is not a global phenomenon as defined by rule Safety benefit of GDC-4 rule change addressed worker safety and plant safety benefits associated with removal of pipe whip restraints and jet impingement shields The industry and NRC have made significant progress in resolving PWSCC in PWRs Mitigation efforts include installing weld overlays and mechanical stress improvements Utilities implemented PWROG enhanced leakage monitoring methods 8
Reasonable Assurance vs. Absolute Assurance Safety significance of GSI-191 has been adequately addressed
- Design modifications (completed)
- Application of conservative deterministic methods to more likely spectrum of breaks (Option 1b)
Application of GDC-4 (Option 3) enables closure of GSI-191 in an expedient manner that
- Acknowledges minimal safety impact
- Reduces costs and worker impact
- Credits defense-in-depth measures already taken by plants 9
GSI-191 RESOLUTION OPTIONS John Butler, NEI jcb@nei.org September 9, 2010
SECY-10-0113 RESOLUTION OPTIONS Option 1 - Maintain the current holistic integrated resolution process for remaining plants including evaluating new refinement models a) Set near-term schedule for licensees to address the full spectrum of LOCAs b) Set near-term schedule for smaller LOCAs, and set longer term schedule for the less likely LOCAs c) Do not set a schedule for licensees to address remaining issues Option 2 - Develop additional risk-informed implementing guidance for GSI-191 a) Expand limited risk-informed guidance in Section 6 of the SE for NEI 04-07 b) Generate new guidance assuming the that proposed 10 CFR 50.46a is approved Option 3 - Application of the GDC-4 exclusion of jet effects to debris generation NRC staff recommends Option 1.b in combination with Option 2 The industry recommends Option 1.b in combination with Options 2 and 3 2
Industry Recommendations The industry recommends Option 1.b in combination with Options 2 and 3 Industry agrees that design basis for more likely breaks should be met using deterministic criteria and methods acceptable to the NRC
- Schedule should accommodate ongoing efforts to refine ZOI values, settlement credit in strainer testing and in-vessel effects 3
Industry Recommendations All risk-informed options should be pursued (available) to address low-likelihood breaks
- Expand risk-informed guidance in current SE on Section 6 of NEI 04-07 (Option 2a)
- Pursue approval of 10 CFR 50.46a and generate new guidance (Option 2b)
- Allow application of GDC-4 (Option 3) 4
Industry Recommendations Option 2a - Expansion of NEI 04-07 Section 6
- Section 6 in place currently with limited relaxation of known conservatisms
- Future value dependent on separation between guidance applied to small breaks and large breaks
- Schedule for development and application of expanded guidance unknown 5
Industry Recommendations Option 2b - Pursue approval of 10 CFR 50.46a and generate new guidance
- Greatest value in 10 CFR 50.46a comes from risk-informed changes enabled by rule that are not related to GSI-191
- The perceived value and subsequent plant interest varies by plant
- Significantly extends schedule for closure 6
Industry Recommendations Option 3 - Allow application of GDC-4
- Provide means to address unlikely breaks in manner that is risk-informed and complies with regulatory requirements
- Application by plants considered closed permits recovery of operational margins
- Guidance currently available and enables quick staff review and closure 7
Option 3 Allow application of GDC-4 Debris generation is a direct consequence of local dynamic effects excluded from postulated breaks in LBB qualified piping Debris generation is not a global phenomenon as defined by rule Safety benefit of GDC-4 rule change addressed worker safety and plant safety benefits associated with removal of pipe whip restraints and jet impingement shields The industry and NRC have made significant progress in resolving PWSCC in PWRs Mitigation efforts include installing weld overlays and mechanical stress improvements Utilities implemented PWROG enhanced leakage monitoring methods 8
Reasonable Assurance vs. Absolute Assurance Safety significance of GSI-191 has been adequately addressed
- Design modifications (completed)
- Application of conservative deterministic methods to more likely spectrum of breaks (Option 1b)
Application of GDC-4 (Option 3) enables closure of GSI-191 in an expedient manner that
- Acknowledges minimal safety impact
- Reduces costs and worker impact
- Credits defense-in-depth measures already taken by plants 9
26A6642AR Rev. 07 ESBWR Design Control Document/Tier 2 Sampling probes are located in the inlet header and in each effluent line of the two demineralizer units. Sample lines from each probe are routed to the sample station.
5.4.8.2 Shutdown Cooling Function The normal shutdown cooling function is performed by the RWCU/SDC system.
The preferred post-LOCA shutdown cooling function is performed by the FAPCS. In the unlikely event that there is fuel damage, the RWCU/SDC system will perform the post-LOCA shutdown cooling function.
5.4.8.2.1 Design Bases Safety Design Bases Refer to Subsection 5.4.8.1.1 for the safety design bases.
Power Generation Bases The shutdown cooling mode of the RWCU/SDC system is designed to:
- Remove decay heat during normal plant shutdowns;
- Remove the core decay heat, plus overboard the CRD cooling flow after approximately one-half hour following control rod insertion and assuming either the main condenser or ICS is available for initial cooldown; and
- With loss of preferred off-site AC power, bring the plant to cold shutdown in 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> in conjunction with the ICS, assuming the most restrictive single active failure.
The RWCU/SDC shutdown cooling function modes are interlocked with reactor power operation to prevent increase in core reactivity (Subsection 5.4.8.1.1).
Post-LOCA Bases In the unlikely event that fuel damage has occurred, the post-LOCA shutdown cooling mode of the RWCU/SDC system is designed to:
- Bring the plant to cold shutdown, and maintain cold shutdown conditions, through realignment of the intersystem cross connection and the applicable intrasystem cross-connections to the FAPCS;
- Achieve and maintain plant cold shutdown conditions through the suppression pool cooling (with support of portions of the FAPCS), and the mid-vessel injection modes of operation; and
- With the support of portions of the FAPCS, deliver cooled water for drywell spray, GDCS pools makeup, or suppression pool makeup.
The RWCU/SDC system is not intended to satisfy GDC 38 requirements. The GDC 38 functional requirements are met by the containment PCCS heat exchangers for the first 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.
After the first 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />, refilling of the PCCS pools and the PCCS Vent Fans maintain stable shutdown conditions, indefinitely.
5.4-30
26A6642AR Rev. 07 ESBWR Design Control Document/Tier 2 5.4.8.2.2 System Description In conjunction with the heat removal capacity of either the main condenser and/or the isolation condensers, the RWCU/SDC system can reduce the RPV pressure and temperature during cooldown operation from the rated design pressure and temperature to below boiling at atmospheric pressure in less than one day (see Table 5.4-3). The system is also designed to control the reactor temperature reduction rate.
The system can be connected to nonsafety-related standby AC power (diesel-generators),
allowing it to fulfill its reactor cooling functions during conditions when the preferred power is not available.
The shutdown cooling function of the RWCU/SDC system provides decay heat removal capability at normal reactor operating pressure as well as at lower reactor pressures.
The redundant trains of RWCU/SDC permit shutdown cooling even if one train is out of service; however, cooldown time is extended when using only one train.
In the event of loss of preferred power, the RWCU/SDC system, in conjunction with the isolation condensers, is capable of bringing the RPV to the cold shutdown condition in a day and a half, assuming the most limiting single active failure, and with the isolation condensers remove the initial heat load. Refer to Subsection 5.4.8.1.2 for a description of the RWCU/SDC pump motor ASD and its operation for shutdown cooling.
In the event of a severe accident resulting in fuel failure, train A of the RWCU/SDC system can be cross-connected to the FAPCS suppression pool suction and the FAPCS containment cooling line to provide containment cooling capabilities. This will allow containment cooling while maintaining the contaminated water inside the reactor building. In this condition the RWCU/SDC system has the capability to return cooled suppression pool water to the reactor vessel through the RWCU mid-vessel suction to preclude using the feedwater injection flowpath, which exits the reactor building.
System Operation The modes of operation of the shutdown cooling function are described below:
Normal Plant Shutdown The operation of the RWCU/SDC system at high reactor pressure reduces the plant reliance on the main condenser or ICS. The entire cooldown is controlled automatically. During the initial phase of reactor shutdown, the RWCU/SDC pumps operate at reduced speed with the pumps and system configuration aligned to provide a moderate system flow rate and control the cooldown rate to less than the maximum RPV cooling rate allowed.
One or both trains of RWCU/SDC may be operated during the early phase of reactor shutdown and cooldown. As cooldown proceeds and RWCU/SDC removes a larger portion of the reactor decay heat, , total RWCU/SDC system flow is increased.
In each RWCU/SDC train, the bypass line around the RHX, and the bypass line around the demineralizer are opened to permit increased pump speed and obtain the quantity of system flow required to achieve the process state needed during the shutdown cooling mode. Flow continues through each in-service RWCU/SDC NRHX, with the capability of controlling the RCCWS inlet valve to increase, or decrease cooling water flow as necessary.
5.4-31
26A6642AT Rev. 07 ESBWR Design Control Document/Tier 2 A loss of all power generation buses is not the limiting assumption and the effects of continued feedwater injection is more limiting, as it can potentially add water to the wetwell and compress the wetwell air space. The ESBWR design incorporates features that mitigate this challenge by isolating reactor inventory sources outside of containment and provides a method of GDCS initiation based on LOCA condition detection. These features ensure that containment remains within design pressure for the entire 72-hour event duration. These features also ensure acceptable performance for the full spectrum of LOCA events within containment, with or without the assumption of loss of external injection capability. Additionally, although power generation buses are considered available to add feedwater or High Pressure Control Rod Drive (HP CRD) injection, no credit is given for heat removal systems powered by these buses. Table 6.2-7h shows the sequence of events for the Main Steam Line Break with failure of one SRV and with offsite power available. Figures 6.2-14j1 through 6.2-14m3 show the pressure, temperature, DW and GDCS airspace pressure responses and PCCS heat removal for this analysis. The noncondensable mass and the void fraction in the DW and GDCS are presented in Figures 6.2-14n1 through 6.2-14o3. The detailed discussion on the chronology of progression is given in Appendix 6E.5. The cases analyzed without offsite power and water addition assume higher initial pressure, and result in higher pressure as shown in Table 6.2-5. The highest value of Maximum DW Pressure in Table 6.2-5 is the calculated peak containment internal pressure for the design basis loss of coolant accident.
6.2.1.1.3.5.1 Post-LOCA Containment Cooling and Recovery Analysis For post-LOCA containment cooling and recovery, Main Steam Line Break scenarios selected are one SRV failure and one DPV failure. The analysis with PARs and 4 of the 6 PCCS vent fans uses the failure with one SRV and the analysis with RWCU/SDC in suppression pool cooling mode followed by shutdown cooling mode uses the failure with one DPV. The post 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> analysis results are not sensitive to the event selection (failure of one DPV versus one SRV) due to the fact that these two cases are nearly the same in transient responses up to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> and the containment pressure and temperature are rapidly reduced upon the activation of the nonsafety-related Structure, System, or Components (SSC).
After the first 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> of the accident, the following nonsafety-related SSCs are utilized to keep the reactor at safe stable shutdown conditions, to rapidly reduce containment pressure and temperature to a level where there is acceptable margin, and then to maintain these conditions indefinitely:
(1) SSCs to refill the IC/PCCS pools; (2) PCCS Vent Fans; (3) Passive Autocatalytic Recombiner System (PARS); and (4) Power supplies to the PCCS Vent Fans and the IC/PCCS pool refill pumps.
Once a state of safe, stable reactor shutdown is reached, containment pressure and temperature are maintained with sufficient margin to containment design limits for a long period of time.
Figure 6.2-14e1 through Figure 6.2-14e10a show key parameters for the long term pressure reduction and maintenance phase. PARS function at 72 hrs and 4 of 6 PCCS vent fans are credited in the calculation.
6.2-12
26A6642AT Rev. 07 ESBWR Design Control Document/Tier 2 The containment pressure is reduced and is maintained at a reduced pressure after the 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> peak. Other non-safety related, non-Regulatory Treatment of Non-safety Systems (RTNSS)
SSCs can be placed in service to bring the reactor to cold shutdown conditions and to further reduce the containment pressure and temperature. These SSCs include the FAPCS as the preferred method, and the RWCU/Shutdown Cooling (SDC) system in the unlikely event there is fuel damage (Subsections 9.1.3 and 5.4.8, respectively). The RWCU/SDC and the FAPCS system are not part of the primary success path for post-LOCA containment cooling.
Calculations of RWCU/SDC performance are provided here to show its ability to cooldown the reactor and containment. In the unlikely event of fuel damage, where the RWCU/SDC system is used, the Reactor Building HVAC Accident Exhaust Filter Units are a required support system for limiting onsite and offsite dose.
Containment pressure and temperature responses which represent a postulated accident recovery evolution, with RWCU/SDC (fuel damage assumed) providing the cold shutdown function are shown in Figures 6.2-14e11 and 6.2-14e12. These response curves are based on the RWCU/SDC operating in suppression pool cooling mode for 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, beginning seven days after a LOCA, followed by vessel injection via the normal RWCU/SDC midvessel suction line, with suction from the suppression pool. The heat removal for this mode of RWCU/SDC operation is provided by the non-regenerative heat exchanger (NRHX). A conservative heat exchanger capacity was assumed which is well within the capability of the RWCU/SDC NRHX.
Table 6.2-48 lists the RWCU/SDC NRHX data used in the analysis. There is no requirement to start the recovery actions at seven days, since the reactor is already in a safe stable shutdown condition, and containment pressure and temperature are in a non-upward trending state, with sufficient margin to containment design limits.
The accident recovery analysis shows that after being in suppression pool cooling for 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> and then injecting into the reactor vessel for approximately 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br />, the suppression pool has equilibrated with the reactor bulk water temperature at cold shutdown conditions.
6.2.1.1.4 Negative Pressure Design Evaluation During normal plant operation, the inerted WW and the DW volumes remain at a pressure slightly above atmospheric conditions. However, certain events could lead to a depressurization transient that can produce a negative pressure differential in the containment. A DW depressurization results in a negative pressure differential across the DW walls, vent wall, and diaphragm floor. A negative pressure differential across the DW and WW walls means that the RB pressure is greater than the DW and WW pressures, and a negative pressure differential across the diaphragm floor and vent wall means that the WW pressure is greater than the DW pressure. If not mitigated, the negative pressure differential can damage the containment steel liner. The ESBWR design provides the vacuum relief function necessary to limit these negative pressure differentials within design values. The events that may cause containment depressurization are:
- Post-LOCA DW depressurization caused by the ECCS (for example, GDCS) flooding of the RPV and cold water spilling out of the broken pipe or cold water spilling out of broken GDCS line directly into DW.
- The DW sprays are inadvertently actuated during normal operation or during post-LOCA recovery period.
6.2-13
26A6641AB Rev. 08 ESBWR Design Control Document/Tier 1 Figure 2.6.2-1. Fuel and Auxiliary Pools Cooling System 2.6-33
26A6642AR Rev. 07 ESBWR Design Control Document/Tier 2 Figure 5.1-4. Reactor Water Cleanup/Shutdown Cooling System Schematic 5.1-7
26A6642AT Rev. 07 ESBWR Design Control Document/Tier 2 450 Design DW and WW Pressure 400 350 300 Drywell Pressure (Level 34, Ring 5)
Pressure (kPa) 250 Wetwell Pressure (Level 31, Ring 7)
RPV Pressure (Level 21, Ring 1) 200 Design Pressure 150 0-3 days, DCD R5 Passive 3-7 days, RAI 6.2-139, Refill PCC Pools, 6 PCC Vent fans 100 7-8 days, Suppression Pool Cooling 8-10 days, Suppression Pool suction, 50 cooling, return to RPV 0
0 24 48 72 96 120 144 168 192 216 240 Time (hr)
Figure 6.2-14e11. Containment Pressure Response -
Post-LOCA Containment Cooling and Recovery 200 Drywell Gas Temp (Level 34, Ring 5) 180 Wetwell Gas Temp (Level 31, Ring 7) 160 Sup. Pool Temp (Level 29, Ring 7) 140 120 Temperature (C) 100 80 60 0-3 days, DCD R5 Passive 3-7 days, RAI 6.2-139, Refill PCC Pools, 6 PCC Vent fans 40 7-8 days, Suppression Pool Cooling 8-10 days, Suppression Pool suction, 20 cooling, return to RPV 0
0 24 48 72 96 120 144 168 192 216 240 Time (hr)
Figure 6.2-14e12. Containment Temperature Response -
Post-LOCA Containment Cooling and Recovery 6.2-305