ML023540105
| ML023540105 | |
| Person / Time | |
|---|---|
| Site: | Davis Besse  |
| Issue date: | 12/05/2002 |
| From: | Advisory Committee on Reactor Safeguards |
| To: | |
| References | |
| NRC-576 ACRST-3224 | |
| Download: ML023540105 (166) | |
Text
Official Tianscript of Proceedings R
NUCLEAR ! LEGULATORY i>,A. COMMISSION i i! .
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Title:
4,dv,'isory Committee on Reactor Safeguards
,98th Meeting - OPEN SESSION PROCESS USING ADAMS TEMPLATE: ACRS/ACNW-005 Docket Number: 4(not'applicable) 1 -. 4---
Location: Rockville, Maryland I i
0 Date: ThuIsday, December m I
A t lI Work Order No. NRC-676 Pages 1-189/23U-319 I se II Ahj!e NEALR. GROSS AND CO., INC.
Cour *Reporters and Transcribers 1323 Rhode Island Avenue, 'N.w.i Washington, D.C. 20005!I 1: (202) -234-4433 A,' I I' V iu=ii ";
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1 1 UNITED STATES OF AMERICA 2 NUCLEAR REGULATORY COMMISSION 3 +++++
4 498th MEETING 5 ADVISORY COMMITTEE ON REACTOR SAFEGUARDS 6 (ACRS) 7 + + + + +
8 THURSDAY, 9 DECEMBER 5, 2002 10 + + + + +
11 ROCKVILLE, MARYLAND 12 +++++
13 The Advisory Committee met at the Nuclear 14 Regulatory Commission, Two White Flint North, Room 15 T2B3, 11545 Rockville Pike, at 8:30 a.m., Dr. George 16 Apostolakis, Chairman, presiding.
17 COMMITTEE MEMBERS:
18 GEORGE E. APOSTOLAKIS, Chairman 19 MARIO V. BONACA, Vice Chairman 20 F. PETER FORD, Member 21 THOMAS S. KRESS, Member 22 GRAHAM M. LEITCH, Member 23 DANA A. POWERS, Member 24 VICTOR H. RANSOM, Member 25 STEPHEN L. ROSEN, Member NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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2 1 COMMITTEE MEMBERS (CONT.)
2 WILLIAM J. SHACK, Member 3 JOHN D. SIEBER, Member 4 GRAHAM B. WALLIS, Member 5
6 ACRS STAFF PRESENT:
7 JOHN T. LARKINS, Executive Director 8 SHER BAHADUR, Associate Director 9 PAUL A. BOEHNERT 10 HOWARD J. LARSON, Special Assistant 11 12 ALSO PRESENT:
13 JACK GROBE, NRC 14 ART HOWELL, NRC 15 RALPH R. LANDRY, NRC 16 JIM MALLAY, Framatome ANP 17 LARRY O'DELL, Framatome ANP 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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3 1 C-O-N-T-E-N-T-S 2 Opening Remarks by the ACRS Chairman ..... ...... 5 3 Tribute to Paul A. Boehnert, Retiring .... ...... 6 4 ACRS Staff Member 5 Davis-Besse Lessons Learned Task Force ... ..... 7 6 Report and Status of NRC Oversight Panel's 7 Investigation of the Davis-Besse Event 8 Remarks by Subcommittee Chairman ..... ....... 7 9 Briefing by and discussions with the ... ..... 8 10 Chairman of the NRC Oversight (0350) 11 Panel regarding the status of investigation 12 of the Panel on the Davis-Besse reactor 13 vessel head degradation 14 Art Grobe, Region III Office, NRC 15 Briefing by and discussions with ... ....... .. 57 16 representatives of the NRC staff 17 regarding the findings, conclusions, 18 and recommendations of the Davis-Besse 19 Task Force on the reactor vessel head 20 degradation event at the Davis-Besse 21 Nuclear Power Station.
22 Art Howell, Region IV Office, NRC 23 Framatome ANP, Inc., S-RELAP5 Realistic . ... 116 24 Large-Break LOCA Code 25 Remarks by the Subcommittee Chairman . ... 116 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N W.
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4 1 C-O-N-T-E-N-T-S (CONT.)
2 Large-Break LOCA Code (cont.)
3 Briefing by and discussions with .. ...... 116 4 representatives of Framatome ANP, Inc.,
5 and the NRC staff regarding the S-RELAP5 6 Realistic large-break LOCA Code and the 7 associated NRC staff's draft Safety 8 Evaluation Report 9 Larry O'Dell, Project Leader, Framatome 116 10 Jim Mallay, Framatome .... ........... .. 154 11 Ralph Landry, Lead Engineer, NRC Staff 164 12 review of S-RELAP5 13 North Anna and Surry License Renewal . . .. 230 14 Application 15 Remarks by the Subcommittee Chairman 230 16 Briefing by and discussions with . . .. 231 17 representatives of the NRC staff and 18 Dominion regarding the license 19 renewal application for the North 20 Anna and Surry Power Stations and 21 the associated NRC staff's final 22 Safety Evaluation Report 23 24 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N W (202) 234-4433 WASHINGTON, D C. 20005-3701 WWW nealrgross corn
5 1 P-R-O-C-E-E-D-I-N-G-S 2 8:30 a.m.
3 CHAIRMAN APOSTOLAKIS: Good morning. The 4 meeting will now come to order.
5 This is the first day of the 498th meeting 6 of the Advisory Committee on Reactor Safeguards.
7 During today's meeting the Committee will consider the 8 following:
9 Davis-Besse Lessons Learned Task Force and 10 Status of NRC Oversight, 0350, Panel's Investigation 11 of the Davis-Besse Event.
12 Framatome ANP, Inc., S-RELAP5 Realistic 13 Large-Break LOCA Code.
14 Meeting with Mr. Lawrence Williams, the 15 United Kingdom.
16 North Anna and Surrey License Renewal 17 Application.
18 Status of Development of the Review 19 Standard for Power Uprates.
20 Supplementary Report on the Rod Bundle 21 Heat Transfer Experimental Program.
22 Proposed ACRS Reports.
23 Portions of this meeting have been closed 24 to discuss Framatome ANP, Inc., proprietary 25 information and the information provided in confidence NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE, N W.
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6 1 by a foreign source.
2 This meeting is being conducted in 3 accordance with the provisions of the Federal Advisory 4 Committee Act. Dr. John T. Larkins is the Designated 5 Federal Official for the initial portion of the 6 meeting.
7 We have received no written comments or 8 requests for time to make oral statements from members 9 of the public regarding today's sessions.
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 I have a few comments before we start on 16 an item of great current interest. Mr. Paul Boehnert, 17 ACRS staff thermal hydraulic expert, is retiring on 18 January 30th, 2003 after 30 years of dedicated service 19 to the Advisory Committee.
20 During his tenure with the ACRS, he 21 provided outstanding technical support to the ACRS in 22 reviewing highly-complex technical issues in numerous 23 areas as well as in thermal hydraulics (laughter) -
24 no, no, no -- numerous areas, most notably thermal 25 hydraulic codes, naval reactor submarine designs, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE, N W.
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7 1 severe accident issues, control room habitability 2 issues, resolution of several generic safety issues 3 and unresolved safety issues, revisions to Appendix K 4 to 10 CFR Part 50, and thermal hydraulic issues 5 associated with the Westinghouse AP600, Combustion 6 Engineering System AD-Plus, and General Electric ABWR 7 designs.
8 His dedication, hard work, and 9 contributions are very well appreciated by my 10 colleagues. We wish him a happy and healthy retired 11 life. We are planning to have a retirement party for 12 Paul in January, when the members will not be here 13 (laughter), but that will happen before he leaves.
14 So, Paul, we wish you happy retirement.
15 MR. BOEHNERT: Thank you very much.
16 (Applause.)
17 CHAIRMAN APOSTOLAKIS: Now we are ready to 18 start with the important business of the day, unless 19 a member has something to say or bring up.
20 (No response.)
21 Okay, the first item on the agenda is the 22 Davis-Besse Lessons Learned Task Force Report and 23 Status of NRC Oversight Panel's Investigation of the 24 this Event. The cognizant member is Dr. Ford.
25 MEMBER FORD: Thank you. We are going to NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N W.
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8 1 hear two topics related to Davis-Besse, both given by 2 staff members.
3 The first one is to do with the Inspection 4 Manual Chapter 0350, the Oversight Panel, relating to 5 the performance issues and restart issues for Davis 6 Besse.
7 The second topic is Davis-Besse Lessons 8 Learned Task Force Report, which has been completed.
9 It is an independent evaluation of the NRC regulatory 10 processes associated with the RPB integrity at Davis 11 Besse and plus recommendations. This is for 12 information only and no letter is being requested at 13 this time.
14 Jack, thank you for coming in on a day 15 like this, and I turn it over to you.
16 MR. GROBE: I appreciate that. Thank you 17 very much. I flew in last evening and the weather was 18 great.
19 (Laughter.)
20 My name is Jack Grobe. I'm in the Region 21 III office of the NRC in Chicago, Illinois, currently 22 assigned full time as the Chairman of the Davis-Besse 23 Oversight Panel. I'm happy to be here.
24 This is our third briefing of the 25 Committee on activities at Davis-Besse. The first NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE, N W.
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9 1 briefing was in April, when we presented the NRC's 2 Augmented Inspection Team findings, the facts and 3 circumstances surrounding the discovery of degradation 4 in the head of the reactor pressure vessel at Davis 5 Besse.
6 In June the Oversight Panel had been 7 chartered, and I appeared before you presenting the 8 charter for the Panel, the composition of the Panel 9 and its functions, as well as summarizing the 10 FirstEnergy's Return-to-Service Plan.
11 Next slide, please. My objectives today 12 are to update you on the activities of the Panel, to 13 summarize the results of recent inspections that we've 14 completed and describe several significant plant 15 equipment issues that Davis-Besse is attempting to 16 resolve.
17 Next slide, please. The guiding document 18 for the NRC's oversight of activities at Davis-Besse 19 is what we refer to as the "Restart Checklist." The 20 Checklist provides a focus for the inspection 21 activities at the site. It captures all safety issues 22 that require resolution for sustained safe operation 23 of the facility. The Checklist was issued in August 24 and updated most recently in October.
25 Next slide, please. There's six key areas NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE.. N W (202) 234-4433 WASHINGTON, D C 20005-3701 www nealrgross com
10 1 of concern that address people, programs, and 2 equipment at the facility. I'm going to get into each 3 of these in a little bit of detail, but they start 4 with the root causes of the event that occurred, as 5 well as addressing structures; as I mentioned, the 6 people, the organization, the management, the safety 7 culture, and licensing issues also.
8 MEMBER LEITCH: Jack, just for 9 clarification, is what you're describing, the 10 Oversight Panel, is that also the 0350 review -
11 MR. GROBE: Yes, I'm sorry.
12 MEMBER LEITCH: -- or is that something -
13 MR. GROBE: No, 0350 is a procedure 14 number. It's Manual Chapter 0350 -
15 MEMBER LEITCH: Right.
16 MR. GROBE: -- which describes the 17 function of an Oversight Panel.
18 MEMBER LEITCH: Okay, thank you.
19 MR. GROBE: The first item on the Restart 20 Checklist is the adequacy of the root cause 21 determination. There's two parts to that. One is the 22 hardware issues, which you heard a great deal about in 23 June. That is the cause of the cracking and the cause 24 of the corrosion.
25 The second area is what I call soft NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE. N W (202) 234-4433 WASHINGTON, D C. 20005-3701 www nealrgross com
11 1 issues. That's organizational issues, human 2 performance, supervision and management structure.
3 FirstEnergy has separated this into a number of 4 separate areas. They have separate causal analyses on 5 the organization, the engineering function, the 6 operations function, corporate oversight of the 7 facility, the function of the safety committees, and 8 a function of quality assurance. There were a number 9 of performance deficiencies in each of those areas, 10 and they did separate root cause analyses in each 11 area.
12 The second item on the Restart Checklist 13 is adequacy of structure, systems, and components.
14 That has a number of attributes under it.
15 First, of course, is the replacement of 16 the reactor pressure vessel head, the containment 17 restoration following movement of the new head into 18 containment and the old head out.
19 Structure, systems, and components inside 20 containment, that has several aspects to it. One is 21 the impact of the boric acid environment that was 22 inside containment. Second is operability of the 23 systems considering the organizational failures and 24 corrective action and design.
25 The third issue that has been identified NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE, N.W (202) 234-4433 WASHINGTON, D C. 20005-3701 www.nealrgross com
12 1 has to do with containment coatings. I have a later 2 presentation on that issue.
3 In addition, inside containment, the 4 licensee has chosen to make substantial modifications 5 to the sump, the emergency core cooling system and 6 containment spray sump, and I also have some 7 additional information on that later.
8 Systems outside containment, there are 9 some systems that do carry boric acid, water with 10 boric acid additive, and we're focusing on boric acid 11 aspects of those, as well as the operability of 12 systems.
13 The next slide, please. The safety 14 significant programs, each of these programs had some 15 contribution to the failures that occurred at Davis 16 Besse. FirstEnergy is doing detailed reviews of these 17 programs, and we are providing oversight of those 18 activities.
19 The final item on the list is the 20 Radiation Protection Program. There was a situation 21 that occurred in February involving occupational and 22 public radiation safety, which resulted in a number of 23 deficiencies being identified in the Radiation 24 Protection Program. Those have been added to the 25 Restart Checklist. Those aren't related to the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N W.
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13 1 reactor head degradation.
2 CHAIRMAN APOSTOLAKIS: Was there any 3 question ever whether the programs were adequate? My 4 understanding is that they were not implemented well.
5 MR. GROBE: Some of the programs did not 6 meet expectations. I'll present some details in the 7 findings of the AIT follow-up inspection.
8 CHAIRMAN APOSTOLAKIS: Okay, fine.
9 MR. GROBE: But you're correct, Dr.
10 Apostolakis, that many of the programs were adequate 11 as written and, had they been implemented correctly, 12 would have prevented the problems.
13 The next area on the Checklist -
14 CHAIRMAN APOSTOLAKIS: One other thing.
15 MR. GROBE: Sure.
16 CHAIRMAN APOSTOLAKIS: This is the NRC 17 oversight of the station. You have this Restart 18 Checklist, and so on. Are you doing something similar 19 through the NRC itself?
20 MR. GROBE: Yes, and I think that's what 21 Art is going to be talking about.
22 CHAIRMAN APOSTOLAKIS: Okay.
23 MR. GROBE: Dr. Ford, did you have a 24 question?
25 MEMBER FORD: Yes, I was about to say that NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N W (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross com
14 1 this is a checklist; you're going to go into some of 2 these deficiencies?
3 MR. GROBE: Yes.
4 MEMBER FORD: Okay.
5 MR. GROBE: And if I don't hit an issue -
6 Maggalean said I had 15 minutes.
7 (Laughter.)
8 And she's a pretty tough task master.
9 MEMBER FORD: I know.
10 (Laughter.)
11 MR. GROBE: So I am trying to get through 12 this quickly, just to give you a broad overview, and 13 I would be glad to answer any questions.
14 CHAIRMAN APOSTOLAKIS: To just do a 15 double-check, Art, are you going to need the full 16 time?
17 MR. HOWELL: I'm Art Howell. My 18 presentation is about 45 minutes.
19 CHAIRMAN APOSTOLAKIS: Okay.
20 MR. GROBE: The next area is 21 organizational effectiveness and human performance.
22 I separate this area into five categories. One is the 23 performance of the people. Second is performance of 24 the supervision and management. The third area is 25 organizational structure. Fourth is safety culture, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE, N W.
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15 1 and fifth is safety-conscious work environment.
2 FirstEnergy has initiated activities in 3 all of these areas, and we're providing oversight of 4 those activities.
5 CHAIRMAN APOSTOLAKIS: Now here is where 6 we're getting into soft territory.
7 MR. GROBE: Absolutely.
8 CHAIRMAN APOSTOLAKIS: Do we have any 9 criteria as to what is adequate? Or is it a matter of 10 judgment?
11 MR. GROBE: We don't have specific 12 criteria defined. As a matter of fact, last night I 13 read some work that was done by the ACRS in the area 14 of safety culture.
15 CHAIRMAN APOSTOLAKIS: And I'm sure that 16 did not enlighten you any more than you were already 17 enlightened.
18 MR. GROBE: It enlightened me on a lot of 19 work that's being done both in the United States and 20 internationally.
21 CHAIRMAN APOSTOLAKIS: Yes.
22 MR. GROBE: The impact of these activities 23 is observable in performance, particularly in the area 24 of safety culture and safety-conscious work 25 environment. In examining the implementation of the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE, N.W (202)
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16 1 Corrective Action Program, you can see the 2 organizational safety culture.
3 CHAIRMAN APOSTOLAKIS: The problem with 4 performance is that it may be too late then. If you 5 were waiting until you see the impact of performance 6 of a bad culture, it may be late.
7 But you're absolutely right. I mean, this 8 is an area where we really don't know what is good 9 enough or adequate, and so on. So I was curious how 10 your people are going to decide this. I guess it's 11 common industry practices perhaps? That's adequate?
12 The experience of people and saying, okay, if 13 everybody is doing this and it has worked for years, 14 it must be adequate?
15 MR. GROBE: Our judgment in this area is 16 primarily driven by performance. Prior to restart, we 17 have to have a change in the character of the safety 18 culture of the organization, and we're already seeing 19 that in how the organization performs.
20 Part of the Manual Chapter 0350 includes 21 continuation of the Panel well after restart, to 22 continue observing the performance of the facility to 23 ensure that the actions that were taken are lasting.
24 CHAIRMAN APOSTOLAKIS: Now "Panel," you 25 are referring to your Panel?
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17 1 MR. GROBE: That's correct.
2 CHAIRMAN APOSTOLAKIS: And your Panel will 3 have more authority than other panels?
4 MR. GROBE: No. The purpose of the Panel 5 -- I apologize, I should have stepped back -- the 6 purpose of the Panel is essentially to replace the 7 Routine Oversight Program. At Davis-Besse the Routine 8 Reactor Oversight Program is suspended, and the Panel 9 is comprised of both people from the Regional Office 10 as well as Headquarters. We assess all the findings 11 and define the Inspection Program.
12 CHAIRMAN APOSTOLAKIS: So this Routine 13 Oversight Program that you are referring to is the 14 new, revised oversight process?
15 MR. GROBE: That's correct.
16 CHAIRMAN APOSTOLAKIS: Is this statement 17 you just made consistent with statements we hear from 18 other groups of the staff, that this revised reactor 19 oversight process is a successful program? I mean, 20 you are suspending it.
21 MR. GROBE: Yes, it's suspended not 22 because -
23 CHAIRMAN APOSTOLAKIS: And yesterday we 24 were told it's successful.
25 MR. GROBE: It's not suspended because of NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE, N W (202) 234-4433 WASHINGTON, D C. 20005-3701 www nealrgross com
18 1 a lack of success. It's suspended because it's 2 constructed to deal with a routine reactor plant, and 3 the Davis-Besse organization has demonstrated that 4 they don't have the fundamental underpinnings that 5 resulted in formation or that were the foundation of 6 the Reactor Oversight Program, the Routine Reactor 7 Oversight Program. Because of that, different types 8 of inspection and oversight are necessary.
9 The Panel was put together to provide 10 guidance and oversight of that different type of 11 inspection program. We take the vast majority of the 12 guidance from the Routine Oversight Program to guide 13 the activities that we do. But, in addition to that, 14 all of these items on the Checklist are being followed 15 up in substantially more detail and depth than would 16 be dictated by the Routine Oversight Program.
17 CHAIRMAN APOSTOLAKIS: So at some point in 18 the future, then, based on your experience here, we 19 may expand the scope of the ROP to include some of the 20 issues that you're addressing here, like the adequacy 21 of root causes; I don't think they do that, do they?
22 MR. GROBE: Yes. Part of the Routine 23 Oversight Program is evaluating -
24 CHAIRMAN APOSTOLAKIS: It is done?
25 MR. GROBE: -- on a regular basis the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE, N W (202) 234-4433 WASHINGTON, D.C. 20005-3701 www nealrgross com
19 1 Corrective Action Program. But the group that Art 2 chaired was tasked with evaluating the effectiveness 3 of the Routine Oversight Program as well as many other 4 aspects of the agency. The Senior Management Review 5 Team, chaired by Carl Paperiello, is evaluating the 6 results of Art's group's findings right now. Art will 7 get into a lot more detail on it.
8 CHAIRMAN APOSTOLAKIS: Okay.
9 MEMBER LEITCH: Are these learned items 10 categorized as to which ones need to be completed 11 prior to restart versus some that may be gone and 12 continued after the plant is in operation?
13 MR. GROBE: The answer is yes to both of 14 those. All of these issues have to be addressed prior 15 to restart, such that we have adequate confidence that 16 the plant not only can be restarted safely, but will 17 continue operating safely.
18 Many of the activities will continue to be 19 implemented long after restart. One example is the 20 design reviews. FirstEnergy initially chose five 21 systems to do very detailed design reviews on an 22 additional 31 systems to do what I would call an 23 operational review. They're planning now, based on 24 their findings, of expanding the number of systems for 25 design review, but they're going to continue doing NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE, N.W.
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20 1 those design reviews after restart.
2 MEMBER LEITCH: Is there a part of the 3 program related to measuring the effectiveness of 4 these corrective actions? In other words, oftentimes, 5 one needs to go back three months, six months, after 6 a corrective action has been taken and assess whether 7 that corrective action really solved the problem or 8 not.
9 MR. GROBE: Yes.
10 MEMBER LEITCH: Is that part of this 11 program?
12 MR. GROBE: Yes. Our inspections are 13 structured in a way that we go back many times. The 14 first step of the inspections is evaluating the root 15 cause analysis in each area. The next step is 16 evaluating the licensee's proposed actions and whether 17 or not they are likely to address that root cause.
18 Then we observe the implementation of 19 their actions. Then we perform independent 20 inspections of our own to ensure that those corrective 21 actions both were adequate in depth as well as we had 22 the appropriate extent of condition consideration.
23 So we look at each step. Some of the 24 effectiveness inspections have already been performed.
25 Particularly in the design area, we found that the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE, N W (202) 234-4433 WASHINGTON, D C 20005-3701 www nealrgross corn
21 1 corrective actions they were taking were well 2 implemented but not sufficient. The company is now 3 going back and broadening the scope of those actions.
4 MEMBER LEITCH: Is there a nexus or a 5 linkage between the corrective actions and the root 6 causes? In other words, can you look at the list of 7 causes and say these are the corrective actions that 8 address that?
9 MR. GROBE: Yes. That's one of the 10 expectations of the inspections.
11 MEMBER LEITCH: Okay.
12 MR. GROBE: Dr. Shack, did you have a 13 question?
14 MEMBER SHACK: You were implying that some 15 of the changes in organizational effectiveness were 16 reflected in the performance; you can see it. I was 17 just wondering what measures of performance you were 18 considering when you made that statement.
19 MR. GROBE: One of the areas that is 20 easiest to see that is in FirstEnergy's assessment of 21 Operations. They concluded that over the past three 22 to seven years the Operations leadership of the 23 organization was suppressed through a number of 24 activities, including behavior and performance of 25 management, expectations set by management, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N W.
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22 1 organizational silos, competing goals of different 2 parts of the organization.
3 The outcome of that was a significant 4 reduction in the Operations leadership of the 5 organization, which contributed to a loss of a safety 6 culture. So those are the types of issues.
7 Okay, next slide, please. Just prior to 8 restart -- I've had a number of experiences with these 9 types of plants. One of my experiences is that, when 10 you have a plant in long-term shutdown, you have to 11 spend a significant amount of effort towards the end 12 of that shutdown to make sure that you're ready for 13 restart.
14 So just prior to restart there will be a 15 series of inspections that will deal with systems 16 returned to service and, most importantly, it will 17 focus on operators, the operational organization and 18 their readiness to handle a plant in an operating 19 condition as contrasted with a shutdown condition.
20 So there will be some effort, several 21 weeks of inspection towards the end of the outage that 22 are focused in those areas. Of course, there will be 23 some different types of tests that are done just prior 24 to restart.
25 The licensee is planning a somewhat unique NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N W (202) 234-4433 WASHINGTON, D.C. 20005-3701 www nealrgross com
23 1 pressure test, and I will get into that in a little 2 bit more detail, of the reactor coolant system as well 3 as containment-integrated leak rate test.
4 MEMBER LEITCH: That operational readiness 5 will be heavily focused on simulator performance?
6 MR. GROBE: No. It will include round 7 the-clock observation of operators in the control room 8 and still occur after a great number of systems have 9 been returned to an operational condition where the 10 operators have to deal with day-in and day-out 11 maintaining the systems in a readiness state, dealing 12 with the normal types of corrective maintenance 13 activities that occur and plant activities that occur:
14 systems in and out of service, hanging outages, things 15 like that.
16 VICE CHAIRMAN BONACA: Was Operations 17 aware of the existence of those rust deposits on the 18 head?
19 MR. GROBE: Not according to the 20 licensee's root cause report, no.
21 VICE CHAIRMAN BONACA: So they were not 22 involved in the observations?
23 MR. GROBE: That is correct, they were not 24 involved. Part of that had to do with organizational 25 communications. Part of it had to do with an NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE, N.W (202) 234-4433 WASHINGTON, D.C 20005-3701 www nealrgross com
24 1 inappropriate emphasis on radiological controls.
2 VICE CHAIRMAN BONACA: That's interesting.
3 MEMBER LEITCH: Do you know, if you're not 4 looking at simulator performance, though, do you know 5 if the licensee intends to do some just-in-time 6 simulator training of the crews?
7 MR. GROBE: Yes, they do. I didn't mean 8 to imply that we weren't focused on simulator. I 9 wanted to make sure it was clear that we were focused 10 on what was going on in the plant.
11 MEMBER LEITCH: Right.
12 MR. GROBE: The company has continued its 13 full requalification training program throughout the 14 outage, and we continue to perform routine inspections 15 of that.
16 The final activity is licensing issues and 17 confirmatory action letter resolution. There remain 18 three limited ASME code relief requests regarding the 19 new head. None of those are particularly unique or 20 complicated. Then the licensee is required to meet 21 with the NRC publicly prior to restart to obtain 22 restart approval in accordance with the confirmatory 23 action review.
24 We have a number of inspections that have 25 either recently been completed or are still ongoing.
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25 1 As you will recall from my presentation on the 2 Augmented Inspection Team, that inspection was simply 3 fact-finding. We had to perform a follow-up 4 inspection to put those findings, those facts and 5 issues, into a regulatory context. I will go into 6 some detail on the findings that came out, the 7 regulatory findings that came out of that follow-up 8 inspection.
9 We have completed the reactor vessel head 10 replacement inspection. I will get into that.
ii We have completed the containment health 12 assurance. That's what the company calls the program 13 for examining systems inside containment.
14 The other three inspections are still 15 ongoing. System Health Assurance, that's the design 16 and operational review of the systems outside 17 containment; program effectiveness and the 18 organization and human performance inspections are 19 ongoing.
20 First, the Augmented Inspection Team 21 followup: There were a number of violations that came 22 out of that. All of these violations currently are 23 being handled as unresolved items because the 24 significance of the violations hasn't been determined.
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26 1 specifications do not permit pressure-boundary 2 leakage, and in this situation it is clear that there 3 was pressure-boundary leakage, and it was pressure 4 boundary leakage that the licensee clearly should have 5 known about. That's a violation of the technical 6 specifications.
7 There was a number of failures to 8 implement corrective actions in accordance with 9 Appendix B of 10 CFR Part 50. I have listed those 10 there.
11 I believe that all of these you're 12 familiar with. If anybody has a question on any of 13 these specific issues, I would be glad to address it.
14 MEMBER LEITCH: The significance of the 15 violations, it surprises me that these individual 16 violations are still being treated 'as unresolved 17 items. In a situation like this where there are a 18 number of violations, I mean I know we haven't 19 assigned a color to the overall event, but is it not 20 a relatively easy task to assess the individual 21 violations and assign a severity level to those?
22 MR. GROBE: Yes. We wouldn't assign a 23 severity level unless the violations -- well, there's 24 one area, and that's the final violation, which I will 25 get to, regarding completeness and accuracy of NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE, N W.
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27 1 information. But the rest of the violations, the 2 significance of them will be driven by the risk 3 significance of the outcome, which is the hole in the 4 head.
5 Each of these violations individually will 6 not be assessed a separate significance because each 7 of them contributed to the eventual outcome, the 8 degradation of the head.
9 MEMBER LEITCH: Okay. So all the 10 individual violations, then, are still in this 11 unresolved status until the overall issue is resolved?
12 MR. GROBE: That's correct, and I believe 13 that the way we'll handle this is one significance for 14 all the violations associated with the head 15 degradation.
16 CHAIRMAN APOSTOLAKIS: Why was the 17 installation of the service structure access 18 modification a violation? I mean, they decided to do 19 it themselves, didn't they?
20 MR. GROBE: It was part of the corrective 21 action for an identified deficiency.
22 CHAIRMAN APOSTOLAKIS: Was there a 23 commitment to the NRC that they would do this?
24 MR. GROBE: No. Within their Corrective 25 Action Program, I don't remember which year it was, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE, N W.
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28 1 but the engineers documented that they were unable to 2 completely clean and inspect the head.
3 CHAIRMAN APOSTOLAKIS: Right.
4 MR. GROBE: One of the corrective actions 5 for that was to install these openings, and the 6 company never did it. So it was a violation of the 7 Corrective Action Program. They never corrected the 8 deficiency of being able to -
9 CHAIRMAN APOSTOLAKIS: So there is a 10 requirement, then, somewhere that they have to have 11 access?
12 MR. GROBE: No, the requirement is to take 13 corrective actions for identified deficiencies. The 14 deficiency was -
15 CHAIRMAN APOSTOLAKIS: But why was it 16 deficient?
17 MR. GROBE: Because they couldn't 18 implement their Boric Acid Corrosion Management 19 Program.
20 CHAIRMAN APOSTOLAKIS: Okay.
21 MEMBER SIEBER: Do you believe that they 22 ultimately, the staff will ultimately determine the 23 significance of the agglomerated violations?
24 MR. GROBE: Yes. Yes, that's nearing 25 completion. Members of the public that are here that NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE, N.W (202)o 234-4433 WASHINGTON, D.C. 20005-3701 www nealrgross com
29 1 attend my other meetings know that I have said that on 2 several occasions, but, in fact, NRR, the Office of 3 Nuclear Reactor Regulation, is completing what we call 4 a Phase III Risk Analysis of the head degradation. I 5 expect to have that this week.
6 Once that's completed, we can develop the 7 significance evaluation. It will probably take 8 another four to six weeks to complete that, but we're 9 on the home stretch.
10 CHAIRMAN APOSTOLAKIS: That will be the 11 color for the ROP?
12 MR. GROBE: That's correct.
13 CHAIRMAN APOSTOLAKIS: Why? What use 14 would that have?
15 MR. GROBE: Well, one of the purposes is 16 communication. One of the reasons we put colors on 17 violations is to communicate effectively with the 18 public. Clearly, the public could infer that this is 19 a very significant issue based on the actions the 20 agency has taken.
21 But the second important reason is to 22 exercise the program and to make sure it works, and if 23 it doesn't work effectively, to be able to make 24 changes to it.
25 CHAIRMAN APOSTOLAKIS: I don't think it NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE, N W (202) 234-4433 WASHINGTON, D.C. 20005-3701 www nealrgross com
30 1 works. So the color is irrelevant to me. If it 2 didn't find something -- I mean, that's a personal 3 opinion -- it doesn't work.
4 MR. GROBE: I was specifically talking 5 about the significance determination process, whether 6 that works for the situation, and if it doesn't, 7 decide whether or not we should make changes.
8 CHAIRMAN APOSTOLAKIS: Yes. I mean, the 9 process requires some inputs, right?
10 MR. GROBE: I'm sorry?
11 CHAIRMAN APOSTOLAKIS: The process, for 12 the process to work, the SDP, you have to have the 13 inputs?
14 MR. GROBE: That's right.
15 CHAIRMAN APOSTOLAKIS: What was missing 16 here were the inputs. So it is not going to tell you 17 really whether the process works. It's going to tell 18 you whether we have a system in place that actually 19 gets those inputs in time. I don't know how you do 20 that. This is a cultural issue, an organizational 21 issue.
22 MEMBER SIEBER: Well, one of the problems 23 is -
24 VICE CHAIRMAN BONACA: It looks at the 25 right things.
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31 1 MEMBER SIEBER: One of the problems is 2 that the NRC has already acted as they would have 3 through the action of the action matrix. So it is 4 sort of predetermined, the color this ought to turn 5 out to be.
6 Now the question is, will the fact that 7 the Commission has acted and all this information has 8 come to light, will that have an influence on what 9 color the SDP finally determines this to be or will 10 there be a bias? And if there is, then you can't 11 establish that the SDP is actually doing its job.
12 MR. GROBE: And those are the issues that 13 we're working through right now.
14 MEMBER SIEBER: Okay. I anxiously await 15 the outcome.
16 MR. GROBE: So I'm invited back again?
17 (Laughter.)
18 MEMBER POWERS: Anytime you want to 19 appear, you're very welcome here.
20 MEMBER SIEBER: My term expires in August.
21 CHAIRMAN APOSTOLAKIS: Next time we have 22 a snowstorm.
23 (Laughter.)
24 MEMBER POWERS: Or even a heat wave.
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32 1 yes.
2 (Laughter.)
3 MR. GROBE: Next slide. The next 4 violation concerned the failure to have an adequate 5 Boric Acid Corrosion Management Program. The program 6 that was in place would have been sufficient, had it 7 been correctly implemented, but there were a number of 8 deficiencies in the program. I would call them more 9 administrative-type deficiencies of how the Boric Acid 10 Program interfaced with other plant programs and the 11 guidance that it provided.
12 There were a number of deficiencies in the 13 Corrosion Control Program. Of course, there was a 14 number of occasions where FirstEnergy failed to follow 15 both the Boric Acid Corrosion Control Program and 16 their corrective action procedures.
17 The final item, there were six examples 18 identified by the Augmented Inspection Team of failure 19 to provide complete and accurate information. This 20 included both information which was submitted to the 21 NRC as well as information that was contained in 22 required records; 10 CFR 50.9 addresses both of those 23 issues. There are a number of records as well as 24 submittals to the company that were not complete and 25 accurate.
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33 1 MEMBER WALLIS: Does this mean that they 2 did not supply the information or that they supplied 3 inaccurate information?
4 MR. GROBE: This primarily focuses on the 5 completeness and accuracy of the information they 6 provided.
7 MEMBER WALLIS: So it was omission that 8 you're after here or was it providing information 9 which was in some way misleading?
10 MR. GROBE: Yes, it's more of the second.
11 MEMBER WALLIS: More the second? Okay.
12 MR. GROBE: Yes, that the information that 13 was provided is not complete and could lead you to an 14 incorrect conclusion.
15 Again, I want to emphasize that this is 16 not just submittals to the NRC, but it's also internal 17 records.
18 MEMBER SIEBER: Was any of it under oath 19 and affirmation?
20 MR. GROBE: The submittals to the NRC I 21 believe were submitted under oath and affirmation.
22 Okay, the next slide. As I mentioned, we 23 have completed the reactor vessel head replacement 24 inspection.
25 MEMBER LEITCH: Jack, just before you get NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE, N W (202) 234-4433 WASHINGTON, D C 20005-3701 www nealrgross com
34 1 into -
2 MR. GROBE: Sure.
3 MEMBER LEITCH: -- the hardware side of 4 the issues there, I'm concerned that it appears to me, 5 and I have not been to the plant, but it appears to me 6 as though Operations was not really the driving force 7 as to what was occurring at the power plant -
8 MR. GROBE: Right.
9 MEMBER LEITCH: -- in the years prior to 10 this event. In all power plants there are a number of 11 organizations. But it seems to me that the plant 12 basically needs the attitude that Operations is in 13 control and that the rest of them are there, the rest 14 of the organizations are there in one way or another 15 to support the safe operation of the plant.
16 What are the actions that are being taken 17 to change that kind of a mindset, and how can you 18 determine when those actions have been successful? I 19 mean, in my mind, Operations has got to be in charge.
20 MR. GROBE: Absolutely.
21 MEMBER LEITCH: Apparently, that was not 22 occurring. I just wonder, what is the licensee doing?
23 How can we know when it's done? What are the measures 24 that we have in that area?
25 MR. GROBE: Thank you for that question.
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35 1 Let me give a few more details about revelations that 2 came through the FirstEnergy review of Operations.
3 This is one of the reasons they separated that out as 4 a separate causal analysis.
5 Operations in the late nineties was 6 characterized by a significant turnover in leadership.
7 The lack of support -- as a matter of fact, the 8 Operations Superintendent position, which reports to 9 the Plant Manager, was vacant, and the current Shift 10 Managers did not submit themselves for that promotion 11 opportunity because of their belief in the lack of 12 management support for Operations.
13 The Onsite Review Committee would be 14 conducted without an Operations representative. They 15 had a quorum requirement that didn't require 16 Operations. There's a number of other examples which 17 are clearly indicative that Operations wasn't playing 18 a leadership role in the day-to-day activities of the 19 plant.
20 The actions that the company has taken is 21 that there are required Operations representatives on 22 all the key committees, the Onsite Review Committee, 23 the Corrective Action Review Board, all of the key 24 committees that are ongoing.
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36 1 requirements that can't be substituted?
2 MR. GROBE: That's correct.
3 MEMBER LEITCH: You have to have those 4 folks there?
5 MR. GROBE: A Licensed Senior Reactor 6 Operator was added to the Health Physics Organization 7 and to what's commonly referred to as the "fix-it-now" 8 part of Maintenance, so that there's a clear 9 operational perspective in decisions that are made in 10 the radiological protection and the urgent maintenance 11 activities.
12 All of the Operations supervision and 13 management has been replaced. A number of those 14 people have come from outside the organization. They 15 were specifically selected for their leadership.
16 MEMBER LEITCH: This is the Shift Managers 17 you're referring to now?
18 MR. GROBE: No, above Shift Managers.
19 MEMBER LEITCH: Above Shift Managers, yes.
20 MR. GROBE: Not the licensed positions, 21 but the positions above that.
22 One of the other findings was that the 23 Shift Manager wouldn't attend the morning management 24 briefings.
25 So there were a number of indicators that NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N W (202) 234-4433 WASHINGTON, D C. 20005-3701 www nealrgross com
37 1 Operations was not playing the role that you would 2 expect. All of that is now observably changed.
3 The longer-term barriers that need to be 4 broken down are the organizational barriers to ensure 5 that Maintenance and Engineering and Radiological 6 Protection, in particular, are supporting Operations 7 and not any other type of hierarchy.
8 We have two Residents onsite. We'll 9 continue to observe these things on a day-to-day basis 10 as well as special inspections specifically focused in 11 this area.
12 MEMBER LEITCH: The Shift Managers, do 13 they get to be Shift Managers by virtue of a seniority 14 progression or is there other more stringent 15 qualifications?
16 MR. GROBE: I don't -
17 MEMBER LEITCH: Maybe that's not -- maybe 18 that's in the licensee's decisionmaking process?
19 MR. GROBE: Exactly. I think that is more 20 of a management decisionmaking process that they have, 21 and I don't have detailed knowledge on that.
22 MEMBER LEITCH: It's hard for me to 23 understand a Shift Manager not attending the morning 24 meeting. In fact, it's hard for me to imagine him not 25 chairing the morning meeting.
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38 1 (Laughter.)
2 VICE CHAIRMAN BONACA: Well, but the fact 3 that Operations was unaware of those photographs of 4 the head and the corrosion taking place up there, it 5 shows there was -- I mean, just it's unheard of. I 6 mean, where were they during the outage? How come 7 this information wasn't shared, I mean to the people 8 that run the plant?
9 MR. GROBE: Let me answer both your 10 questions. The flavor of the organization, the 11 organizational priorities, don't come from the Shift 12 Manager. They come from the senior executives and the 13 leadership at that level, and it's infused down 14 through the organization. That wasn't occurring.
15 That is what allowed this atrophication of support of 16 Operations, operations safety, to occur.
17 MEMBER WALLIS: Well, maybe it was 18 occurring, but the wrong kind of thing was occurring.
19 I mean, it was diffusing down through the 20 organization, but it was the wrong kind of directive.
21 MR. GROBE: If you looked at the paperwork 22 that existed, you would find many of the right words, 23 but the day-to-day behavior of the executives and 24 managers didn't support Operations leadership.
25 MEMBER FORD: Jack, could I ask, just in NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE, N W (202) 234-4433 WASHINGTON, D.C 20005-3701 www nealrgross com
39 1 the process of time, could you finish up within 10 2 minutes?
3 MR. GROBE: Sure.
4 MEMBER FORD: I recognize that you can't 5 control the questions.
6 MR. GROBE: I believe there was one other 7 question. That had to do -- I'm not sure who asked it 8 -- it had do with bench strength.
9 If you go back to the mid- to late 10 eighties, Operations had roughly 40 to 50 licenses, 11 and that was built to the early nineties up to about 12 100 licenses onsite. That's now back down, or had 13 been back down, to the level of on the order of 40 to 14 50 licenses. So there was less emphasis on licensed 15 operators in the organization and license operator 16 training.
17 MEMBER SIEBER: Isn't that an impediment 18 to already-licensed operators in radiation control and 19 work management and all these different places?
20 MR. GROBE: Yes, it is. One of my 21 experiences in an operations-driven organization is 22 that either you drive licensed operators from 23 operations into other organizations or you license in 24 other organizations, particularly engineering.
25 MEMBER SIEBER: Right. But that hasn't NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE, N W (202) 234-4433 WASHINGTON, D C 20005-3701 www nealrgross com
40 1 been happening in the recent pattern?
2 MR. GROBE: That's correct.
3 MEMBER LEITCH: I would just point out, 4 though, that too many licensed operators can also be 5 an impediment. I mean that can be a two-edged sword.
6 I think you want people migrating into these 7 organizations who have been previously licensed, but 8 sometimes maintaining the license can be a burden 9 because they have to go to requal. training; they have 10 to take exams.
11 I'm not sure the exam is focused on team 12 performance, but we always found it kind of difficult 13 to get a few people that weren't active operators 14 together in a control room to pass an exam because 15 they weren't used to working with one another.
16 So, I mean, the first reaction is the more 17 licenses, the better, and in general I agree with 18 that. But there's another side to that coin where you 19 can have too many licenses and it can be a burden and 20 make your licensee failure rate on exams look bad and 21 require a great deal of time for requalification, and 22 so forth.
23 MR. GROBE: Yes. I think I was trying to 24 focus more on the fact that, with fewer licenses, 25 there's less ability to have turnover -
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41 1 MEMBER LEITCH: Right.
2 MR. GROBE: -- out of the operations 3 organization into other organizations. As a result of 4 that, you don't have an operational focus in those 5 other organizations.
6 The new reactor head, the replacement 7 reactor head, which has never been used, we have 8 concluded met, does continue to meet, the ASME Section 9 III requirements. We witnessed and evaluated the non 10 destructive examination of that head. A number of the 11 radiographs had to be reperformed because they were 12 not maintained, and baseline Section 11, ISI, was 13 performed on the penetrations and the welds. That all 14 has been accomplished successfully.
15 As I mentioned earlier, there's two 16 outstanding issues in this area. One is the reactor 17 coolant system pressure test and the containment 18 integrated leak rate test. Those will be performed 19 later at an appropriate time.
20 MEMBER SIEBER: Where is the head right 21 now?
22 MR. GROBE: It's inside containment on the 23 head stand.
24 MEMBER SIEBER: Okay.
25 MR. GROBE: There was quite a bit of -
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42 1 MEMBER SIEBER: At Davis-Besse?
2 MR. GROBE: Yes. There was quite a bit of 3 reconstruction work that had to be done, attaching the 4 service rupture, installing all the control rod drive 5 mechanisms, all of the support structures for that.
6 MEMBER SIEBER: And the Davis-Besse 7 containment is closed now?
8 MR. GROBE: Yes, it is.
9 MEMBER SIEBER: Okay, and will there be a 10 design pressure test in the containment prior to 11 start -
12 MR. GROBE: There will be a containment 13 integrated leak rate test, not a structural integrity 14 test.
15 MEMBER SIEBER: Okay. So what's the test 16 pressure for these? Would it be 10 pounds?
17 MR. GROBE: No, no. The containment, I 18 believe, Pat, the containment integrated leak rate 19 test pressure at Davis-Besse is at 42 pounds?
20 MR. McCLOSKEY: I don't have the figure 21 for that, but I think the question was whether a 22 design pressure test would be -
23 MEMBER FORD: You have to come to the 24 microphone.
25 MR. McCLOSKEY: Good morning. My name is NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N W.
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43 1 Pat McCloskey. I'm the Regulatory Affairs Manager for 2 Davis-Besse.
3 The question was in regards to the test 4 plan for the containment reactor building. We plan to 5 do an integrated leak rate test versus a design 6 testing. Integrated leak rate test, of course, is 7 similar to what we run as part of our 10-year in 8 service inspection requirements, and that has been 9 part of the plan of restoration all along.
10 MR. GROBE: The second inspection has been 11 completed.
12 The next slide is the containment health 13 assurance -- that's what the licensee calls it -- area 14 evaluation. The containment has been thoroughly 15 inspected. The evaluation of structure, systems, and 16 components inside containment has been adequate, based 17 on our inspections, and repair and refurbishment 18 activities in a number of systems are ongoing, most 19 notably the ventilation systems inside containment.
20 There was a substantial accumulation of 21 boric acid inside ductwork. That was the primary 22 impact of the boric acid, was on the ventilation 23 systems.
24 One of the outstanding -
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44 1 instrumentation as well?
2 MR. GROBE: The environmental 3 qualification requirements for equipment inside 4 containment include ability to resist a boric acid 5 environment, and their operators were opened; junction 6 boxes were opened. No significant findings of any 7 nature were -
8 MEMBER WALLIS: You just dust them off or 9 whatever, and they're okay inside?
10 MR. GROBE: In fact, there was little 11 penetration of any boric acid into those components.
12 There's an issue which I will get into in 13 more detail later on reactor pressure vessel bottom 14 head penetrations that needs to be resolved.
15 The next issue is completely unrelated to 16 the boric acid. During their inspections they 17 identified a cut in a splice, an electrical splice, 18 and that cut appeared to be an impact of maintenance 19 activities that were performed incorrectly. The 20 licensee is currently evaluating the extent and 21 condition of that, whether there was an impact or an 22 outcome of a routine activity replicated a number of 23 times or if it was an isolated issue.
24 The other interesting thing at Davis-Besse 25 is that the electrical conduits provide a ground path, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE, NW (202) 234-4433 WASHINGTON, D.C. 20005-3701 www nealrgross com
45 1 and there was some corrosion identified on the 2 conduits. The question concerns whether that 3 corrosion prohibits the function of the grounding 4 circuit of the conduits. So those are the three 5 outstanding issues in this unit.
6 System health assurance, as I mentioned 7 earlier, this was a detailed design review of selected 8 risk-significant systems and an operational review of 9 other systems. Our inspections concluded that the 10 review process and approach that the licensee was 11 taking was adequate.
12 They identified a number of design and 13 operational issues with several systems, including 14 some issues that were cross-cutting across a number of 15 systems. We performed an independent design 16 inspection of additional systems that they didn't 17 review and identified similar issues.
18 Davis-Besse is currently evaluating the 19 scope expansion that they believe is necessary to 20 address these issues.
21 The next slide is program effectiveness.
22 This inspection is in its early stages. That is 23 primarily because the licensee is in the early stages 24 of addressing this issue.
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46 1 programs that I identified earlier in the Checklist.
2 The review process they are using is adequate, but 3 they have not completed a significant number of these 4 programs yet. So our review is pacing with their 5 activities.
6 organizational human performance, we've 7 completed a review of the majority of the root cause 8 analyses. The licensee has initiated a broad spectrum 9 of corrective actions in a number of areas, including 10 safety culture and safety-conscious work environment.
11 Again, this instruction is fairly early on in its 12 implementation because the licensee's activities are 13 continuing.
14 CHAIRMAN APOSTOLAKIS: How are they doing 15 this? How does one inspect the safety culture?
16 MR. GROBE: Again, I don't know of a way 17 to directly inspect safety culture. There's no 18 standards.
19 What you do is you inspect the questioning 20 attitude of the individuals, how they evaluate 21 deficiencies that they come across, the depth of that 22 evaluation, the effectiveness of corrective actions.
23 Not only the identification of the action, has it been 24 identified correctly -
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47 1 though, that you have a Heisenberg effect here:
2 Because you are there, the process has been changed?
3 They know they are being -
4 MR. GROBE: I would say it differently.
5 I think, because of the revelations that this event 6 has occurred, FirstEnergy has become aware and has 7 taken significant actions. It's because of the 8 event -
9 CHAIRMAN APOSTOLAKIS: Yes.
10 MR. GROBE: -- that revealed these 11 deficiencies and a recognition on the part of 12 FirstEnergy executives and management that these 13 things have to be fixed if they're going to have an 14 asset that is valuable in the future.
15 MEMBER FORD: I'm sorry, but we must 16 finish by 25 past if Art is to have any adequate time.
17 MR. GROBE: Okay. Thank you.
18 MEMBER WALLIS: That's too bad because the 19 interesting part we haven't gotten to yet.
20 MR. GROBE: Let me get into several plant 21 equipment issues, first the bottom head issue. The 22 containment sump, an area in containment referred to 23 as the decay heat valve pit and the coating.
24 Next slide. This is a photograph of 25 penetration No. 1 on the bottom of the head. We're NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE, N.W.
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48 1 looking up at the bottom of the head. These are the 2 in-core nozzles for the detectors. They're very small 3 in diameter, about an inch diameter.
4 What you're seeing here, if you looked at 5 a number of photographs that we could have shown, but 6 on the side of the vessel you will see kind of a swath 7 of corrosion products coming down the side of the -
8 MEMBER WALLIS: Doesn't that represent a 9 leak to you?
10 MR. GROBE: Well, that's the issue.
11 MEMBER WALLIS: What else could it be?
12 MR. GROBE: Well, it came down, as I said, 13 on the side of the vessel. On the side of the vessel 14 you will see a swath of corrosion products that have 15 come down the vessel. As I mentioned, this is in the 16 center of the bottom of the head. So they all come to 17 a convergence there.
18 MEMBER WALLIS: Then they run down this 19 tube or something?
20 MR. GROBE: Yes. That's correct. That is 21 clearly part of what happened.
22 Also, there's a number of other 23 penetrations that have corrosion products on them.
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49 1 penetration.
2 FirstEnergy was not satisfied with the 3 simple answer that -
4 MEMBER WALLIS: Why is it drawn to the 5 penetration?
6 MR. GROBE: It is simply gravity. It 7 wasn't drawn to the penetration; it was running down 8 the vessel. As it intersected a penetration, it run 9 down the penetration.
10 MEMBER KRESS: It lost part of the head.
11 MR. GROBE: Yes. I'm sorry, let me 12 repeat. This is the penetration that is in the center 13 of the bottom of the head. So it's the lowest point 14 on the head.
15 FirstEnergy was not satisfied with the 16 easy answer, that this was simply corrosion that had 17 come down the head or had come down from the head.
18 They did chemical analyses, comparisons of this 19 material to the sides of the head, to the top of the 20 head, to the sides of the vessel and the top of the 21 head. That chemical analysis was inconclusive.
22 So what they have concluded, what they 23 have determined is an acceptable thing to do, and 24 presented this to us last week in a public meeting 25 here in Headquarters, is to do a pressure test where NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N W.
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50 1 they've cleaned the entire head, they're going to take 2 the reactor coolant system up to normal operating 3 temperature and pressure, keep it there for a period 4 of time, shut down, cool down, and then do a thorough 5 inspection of the bottom head. If there are through 6 wall cracks, they will be evident from boric acid 7 leakage.
8 MEMBER SIEBER: That means they have to 9 clean all this off?
10 MR. GROBE: It's already been cleaned.
11 MEMBER SIEBER: Okay.
12 MR. GROBE: Yes, this is a photograph 13 before it was cleaned.
14 MEMBER SIEBER: And on the pressure test 15 anything that leaks will immediately evaporate. So 16 you are really looking for residue again.
17 MR. GROBE: Exactly, and very, very small 18 leaks will result in easily-observable residue.
19 MEMBER LEITCH: Was there any degradation 20 of the material as a result of that boric acid running 21 down there?
22 MR. GROBE: No. There was no observed 23 degradation to the vessel metal.
24 MEMBER LEITCH: Okay.
25 MR. GROBE: Let's get into the next slide.
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51 1 Prior to this outage, the Davis-Besse sump had 2 approximately a 50-square-foot surface area screen.
3 That is characteristic of operating pressurized water 4 reactors. There were a number of deficiencies with 5 the screen, including the mesh size was incorrect. It 6 wasn't in accordance with design. There were some 7 gaps in the mesh.
8 There were some non-permanent 9 modifications. What I mean by that is there were some 10 gaps low in the mesh, and they simply stacked lead 11 bricks in front of the gaps.
12 The licensee has concluded that during 13 this outage they will substantially expand the surface 14 area of the screen to approximately 1200 square feet.
15 In this picture, this is the sump here.
16 This is the concrete structure that supports and 17 contains the reactor vessel itself. This is the 18 location of the original screen, which was 19 approximately 50 square feet. That is being replaced.
20 In addition, there's holes being punched 21 in the side of the sump. This plenum is being 22 installed, and then perforated pipe is being installed 23 down this staircase. This is the staircase that goes 24 into the in-core under-vessel area, and another plenum 25 with additional perforated pipe coming off of that NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE, N W.
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52 1 second plenum. This will substantially increase the 2 surface area, the suction surface area, for the sump 3 screen.
4 MEMBER WALLIS: Why is this being done?
5 MR. GROBE: It is being done right now.
6 MEMBER WALLIS: But why? Is it being done 7 because they found deposits on the screen or the 8 screen was blocked or there was a lot of junk down 9 there, or what?
10 MR. GROBE: I believe it is being done for 11 a couple of reasons. One is they are in extended 12 outage. The screen had deficiencies with it. Instead 13 of replacing it with the same type of design, they 14 decided to -
15 MEMBER WALLIS: But this is a tremendous 16 change. It is a change in area of 24 times.
17 MR. GROBE: That's correct.
18 MEMBER WALLIS: So this must indicate that 19 there was some real reason to do this work.
20 MEMBER KRESS: It has to do with the 21 blockage of the screen due -
22 MEMBER POWERS: The large-break LOCA.
23 MEMBER KRESS: -- large-break LOCA.
24 MEMBER WALLIS: It's like the flakes 25 coming off the containment walls, for instance?
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53 1 MEMBER KRESS: Yes.
2 MEMBER POWERS: Insulation mostly.
3 MEMBER WALLIS: Yes, right.
4 MR. GROBE: Let's move along. This next 5 photograph, this is actually right next to the sump 6 there's a pit. The original design of the plant was 7 that there's two suction valves. The decay heat 8 removal system suction valves are in this inside 9 containment. The original design was that those 10 should be submersible, qualified operators on those 11 valves. When the plant was constructed, they were not 12 submersible qualified.
13 To address that issue, the company chose 14 to seal the pit. See, this RTV. It was a very 15 difficult job to seal all of the openings at the top 16 of this pit. They simply used gobs of RTV to 17 accomplish that.
18 The company has chosen to engineer a 19 solution to this. Submersible operators are not 20 available. So they're lining the pit with stainless 21 steel. They're going to put a stainless steel cap on 22 it, and then gasketed and bolted openings in that cap.
23 This is a photograph on the next slide, 24 that's actually the side of the reactor pressure 25 vessel. It was a non-qualified coating on five large NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE, N W (202) 234-4433 WASHINGTON, D C. 20005-3701 www nealrgross.com
54 1 vessels, the reactor vessel and the four core flood 2 tanks, as well as coating problems on conduit, a 3 substantial number of square feet of coatings on 4 conduit where they applied the coating right over the 5 galvanized conduit without a primer. In addition to 6 that, there were coatings issues on the containment 7 walls and the dome.
8 MEMBER WALLIS: Does this have anything to 9 do with the event that initiated this whole thing?
10 MR. GROBE: No.
11 MEMBER WALLIS: So this is something else 12 which was a problem which had not been fixed?
13 MR. GROBE: That's correct. These are 14 issues that the company identified during the course 15 of doing their comprehensive inspections inside 16 containment, and they're fixing these.
17 MEMBER SIEBER: I have a question about 18 the coating on the reactor vessel. The reactor vessel 19 sits inside the neutron field tank, right?
20 MR. GROBE: It sits -- I'm sorry?
21 MEMBER SIEBER: Inside the neutron field 22 tank?
23 MR. GROBE: It sits inside a concrete 24 structure, but there's no liquid on the outside of it.
25 MEMBER SIEBER: Okay. Is it accessible?
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55 1 MR. GROBE: I'm not certain that this is 2 going to be replaced.
3 MEMBER SIEBER: Oh, okay.
4 MR. GROBE: Pat, do you have the specifics 5 on this specific location? The core flood tanks have 6 been cleaned and -
7 MR. McCLOSKEY: Yes, the core flood tanks 8 -- any of the unqualified coatings on the large 9 vessels have been removed, and plans are either to 10 analyze them and remain uncoated, which we believe a 11 lot of the vessels should have been and could have 12 been. The reactor vessel itself probably did not 13 require this coating.
14 The description of where it is located, it 15 is located within the concrete shielding as well as 16 behind significant vessel insulation as well. This 17 would have been our first opportunity since the 18 operation of the facility to actually see this side, 19 since the under vessel and its side vessel is not 20 routinely inspected.
21 So the determination was made at the point 22 in time that, while we're addressing coatings, remove 23 that and assess that. My belief is that we will not 24 reinstall that coating over the carbon steel.
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56 1 been cleaned, but it is not going to be recoated.
2 MEMBER SIEBER: Okay. So the coating is 3 gone now, because that looks like a sump clogger to 4 me.
5 MR. McCLOSKEY: Exactly.
6 MR. GROBE: Exactly.
7 MEMBER SIEBER: All right, thank you.
8 MR. GROBE: In conclusion, our oversight 9 activities are well underway. They are well organized 10 with a checklist, and our focus is good.
11 FirstEnergy's restart activities are well 12 underway, and they are showing progress. We have a 13 number of performance goals. There's one other 14 document that I gave you, and that's part of our 15 performance goals are to ensure that the public has 16 confidence that the NRC is a strong and credible 17 regulator. We continue to have a large amount of 18 interest both from members of the public as well as 19 elected officials.
20 I gave you another document that looks 21 like this. It is just for your reading pleasure. We 22 are issuing monthly updates or newsletters on 23 activities that are ongoing. This is a continuing 24 activity that we have to try to ensure that the public 25 is well-informed and, hopefully, retains that NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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57 1 confidence in a strong and credible regulator.
2 That completes my 15-minute presentation.
3 (Laughter.)
4 MEMBER FORD: Jack, thank you very much.
5 I am assuming that there are no other 6 major questions. I am also assuming that you will be 7 coming back to us again -
8 MR. GROBE: Whenever you would like.
9 MEMBER FORD: -- with more time available 10 for this important subject.
11 Art, I turn it over to you. We do have an 12 extension of 15 minutes to this section. So there is 13 a little bit of time up for you. So we will be 14 finishing this at half past 10:00.
15 MR. HOWELL: Thank you. My name is Art 16 Howell. I'm from the Region IV Office in Arlington, 17 Texas. I also served as the Team Leader for the NRC's 18 Davis-Besse Reactor Vessel Head Degradation Lessons 19 Learned Task Force.
20 Before I go any further, I would like to 21 recognize there are two Task Force members in the 22 audience, Tom Koshy from NRR and Joe Donoghue, also 23 from NRR.
24 What we would like to do today is provide 25 an overview of our report, which was already issued NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross com
1 58 1 back in October. It was made publicly available on 2 the 9th, I believe.
3 Skip two slides, not the next slide, but 4 the slide after that one.
5 Dr. Hackett, who is our Assistant Team 6 Leader, briefed the Committee on June 5th and 6th on 7 the charter. I just wanted to take a moment to touch 8 on those items, just to refresh folks' memories.
9 The purpose of the Task Force was to 10 conduct an independent evaluation, primarily a 11 retrospective look at our regulatory processes, to 12 identify recommendations for NRC and industry 13 improvement.
14 The charter had five broad areas.
15 Obviously, within these five areas we looked in detail 16 at a number of specific processes and programs.
17 For example, in the reactor oversight 18 process, we obviously looked at the inspection program 19 and implementation at Davis-Besse. We looked at the 20 plant performance assessment process.
21 We reviewed enforcement history. We also 22 reviewed enforcement history broadly across the board 23 generically in terms of enforcement actions involving 24 primary system leakage and boric acid corrosion. We 25 reviewed the allegation history, not only at Davis NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE, N W.
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59 1 Besse, but for the other FirstEnergy plants, going 2 back some 12 years.
3 The next slide, please. In terms of the 4 team composition, it was a multi-discipline team.
5 There was 10 of us total, including our Administrative 6 Assistant. We had representatives from Region IV, 7 Region II, NMSS, NRR, and Research.
8 An experienced team; we had both current 9 and former Senior Resident Inspectors at other Babcock 10 & Wilcox designed plants. We had Regional 11 Supervisors, Senior Licensing Project Managers, and 12 Senior Operations Engineers on the team. None of us 13 had any significant previous involvement with Davis 14 Besse in terms of inspection, enforcement, licensing.
15 We had a formal agreement with the State 16 of Ohio. They provided one observer to the team. She 17 primarily spent her time with us at Davis-Besse during 18 the fact-finding there. She also spent some time with 19 us here in Headquarters during the assessment phase.
20 We conducted two public meetings to 21 solicit input on our charter. One was near the plant 22 back in June, and the other one was here in 23 Headquarters, also in June. We did receive input, and 24 we factored that input into our detailed review plans.
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60 1 we used processes and techniques that were similar to 2 those used in past NRC incident investigation team and 3 diagnostic evaluation team reviews. This included the 4 construction of detailed review plans. We also had 5 prescripted interview questions for a number of folks 6 that we pre-identified to be interviewed. We formally 7 tracked our observations and interviews, and we also 8 used various root cause analysis techniques to sift 9 through all the data.
10 The team was broken down into two groups.
11 One primarily spent its time reviewing processes here 12 in Headquarters. The second was fact-finding at 13 Davis-Besse and the regions.
14 I just want to make it clear, we conducted 15 review activities at all four regions, either 16 telephonically or in person. It wasn't just in Region 17 III.
18 We, obviously, conducted document reviews 19 and interviewed personnel. I think somewhere on the 20 order of 100 NRC personnel were interviewed, about 40 21 or 50 Davis-Besse personnel, and we had 10 others from 22 various industry organizations, as well as French 23 regulators.
24 We were at Davis-Besse for a number of 25 periods during the summer to collect data. As I NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N W.
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61 1 mentioned, we were conducting reviews in all four 2 regions.
3 MEMBER FORD: Obviously, there's a fair 4 amount of overlap with the group that Jack was 5 heading. How did that take place, the communications?
6 Is it informal, formal communications?
7 MR. HOWELL: One of our charter elements 8 was to coordinate with the other reviews. So there 9 were periods during the summer in which the Task Force 10 provided in-progress status reports to Jack in person, 11 to the 0350 Panel, plus other ongoing reviews that 12 were in progress.
13 So, at the end, near the end of it, we 14 also provided background and clarified any questions 15 that we had on any of the Davis-Besse plant-specific 16 issues that are documented in Section 32 of the 17 report.
18 MEMBER FORD: Okay, but just enlighten us 19 all. You're far more specific on Davis-Besse, you're 20 specific on Davis-Besse as it applies to the rest of 21 the industry and how the NRC regulates -
22 MR. HOWELL: Correct.
23 MEMBER FORD: -- as a whole?
24 MR. HOWELL: Correct.
25 MEMBER FORD: Not just Davis-Besse?
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62 1 MR. HOWELL: Now you will see in our 2 report there is one section of our report that deals 3 entirely with Davis-Besse plant-specific issues.
4 MEMBER FORD: Right.
5 MR. HOWELL: And those were coordinated 6 with Jack and the Oversight Panel.
7 MEMBER FORD: Okay, good.
8 MR. HOWELL: The next slide on reports.
9 It is just to indicate where you can find the report, 10 either in ADAMS or on the web page. As I just 11 mentioned, there was coordination with plant-specific 12 issues.
13 MR. GROBE: It is on the web page. So you 14 can find it.
15 MEMBER POWERS: He didn't put the clause 16 "easily" in there. He just he could find it.
17 (Laughter.)
18 MR. HOWELL: It is conceptually possible 19 to find it.
20 (Laughter.)
21 Next slide. Overall conclusions:
22 Fundamentally, we concluded that the industry and the 23 NRC recognized the potential for the Davis-Besse event 24 some 10 years ago, following the identification of 25 cracking at the French plant Bugey in 1991.
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63 1 This type of event was analyzed, and it 2 was concluded that, although there was a potential for 3 corrosive attack of the head, that the leak would be 4 detected long before any significant corrosion would 5 occur. This was predicated on the notion that the 6 identified leaks would likely be axial in nature, 7 wouldn't result in a catastrophic failure of the 8 nozzles. Therefore, any ensuing corrosion from the 9 leaking primary coolant would be detected by boric 10 acid corrosion walkdowns under the General Letter 11 88-05 program.
12 There was some recognition that some small 13 percentage of small leaks would not be detected. So 14 there was some discussion back in the early nineties 15 about the insulation of enhanced leakage detection 16 systems and the efficacy of those systems. That 17 system, obviously, is not installed at Davis-Besse or 18 elsewhere.
19 In addition, we identified that the NRC 20 and Davis-Besse failed to learn key lessons from past 21 boric acid-induced degradation events. Specifically, 22 the one that is important is that there were a number 23 of events, if you look at the raw operational data, if 24 you look at some of the events that have been captured 25 by generic communications in the past, there are a NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N W.
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64 1 number of events where there were primary leaks in 2 which corrosion rates were underpredicted and, 3 therefore, the damage was more significant than what 4 was expected.
5 This is important because what we found, 6 not only at Davis-Besse, but elsewhere, is that there 7 has been a tendency, at least at many places, where 8 these leaks are actually identified, then there are 9 some conscious decisions being made to defer the 10 repair of these leaks because of the underlying 11 assumption that the corrosion rates will be 12 insignificant. So in some cases these deferrals have 13 lasted more than a year until the next refueling 14 outage.
15 VICE CHAIRMAN BONACA: Now in other 16 countries, like France, they took a different path, 17 right?
18 MR. HOWELL: Correct.
19 VICE CHAIRMAN BONACA: So you will talk 20 about that experience later on?
21 MR. HOWELL: Yes, yes.
22 VICE CHAIRMAN BONACA: And was there 23 sufficient comparison of these decisions by the NRC, 24 by the industry? I mean, was this evaluated as a 25 significant input, the fact that in countries like NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N W (202) 234-4433
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65 1 France that took a completely different direction in 2 that sense, and they decided that they would have 3 volumetric inspections, prevent leakage, and then, 4 ultimately, that led to replacing the heads much ahead 5 of time?
6 MR. HOWELL: Right. I was going to 7 address that in a couple of minutes, if that's 8 sufficient.
9 VICE CHAIRMAN BONACA: Okay, you will?
10 That's fine.
11 MR. HOWELL: Fundamentally, the Task Force 12 was focused on understanding why the event wasn't 13 prevented. So, therefore, it was more of a 14 retrospective look. That explains why, for example, 15 we didn't touch on things about the ongoing 16 significance determination process, reviews, and 17 things of that nature that were post-discovery.
18 We concluded primarily that there were 19 three main contributing causes. They are here, and I 20 am going to go through each one of these in detail in 21 the succeeding slides, but -
22 MEMBER FORD: Excuse me. You are going to 23 go through these in detail?
24 MR. HOWELL: Yes, in turn, right. Then 25 there's a number of subelements under each of these.
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66 1 MEMBER FORD: Okay, good.
2 MR. HOWELL: So I won't spend any time 3 here.
4 Next slide. We also found some -
5 MEMBER WALLIS: I just noticed, I have to 6 notice that you have "NRC failed" for something just 7 as frequently as you have "DBNPS failed" to do 8 something in your slides. The statement the "NRC 9 failed" to do something occurs just as frequently as 10 the statement "DBNPS failed" to do something. I just 11 can't help pointing that out.
12 MEMBER FORD: And the reason for that will 13 be discussed in a minute?
14 MR. HOWELL: Yes.
15 CHAIRMAN APOSTOLAKIS: But if I were to 16 select one bullet of all of these and say, well, boy, 17 this was really the problem, I mean, I would be 18 inclined to select the second bullet on slide 7.
19 Would I be wrong?
20 MR. HOWELL: No. I mean I think, clearly, 21 fundamentally, the primary responsibility rested with 22 the licensee to -
23 CHAIRMAN APOSTOLAKIS: The previous slide, 24 Sherry.
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67 1 or detected this issue in its incipient phases much 2 earlier.
3 CHAIRMAN APOSTOLAKIS: Yes. The judgment, 4 I think, was not an immediate safety concern. Is that 5 the No. 1 problem? No? What was it? I mean, they 6 knew about it. They didn't know about it?
7 MR. HOWELL: Well, they didn't know or 8 recognize that the nozzle itself was leaking.
9 CHAIRMAN APOSTOLAKIS: But it seems to me 10 that the issue that is not -
11 MR. HOWELL: I'm not saying they shouldn't 12 have known, but I'm saying -
13 CHAIRMAN APOSTOLAKIS: Right. Let's clear 14 it up because -
15 VICE CHAIRMAN BONACA: Well, the fact that 16 they decided it was an immediate safety concern, I 17 think we all could agree with that conclusion. The 18 word "immediate" is important.
19 CHAIRMAN APOSTOLAKIS: Right.
20 VICE CHAIRMAN BONACA: If it isn't 21 immediate, but it could be a future safety concern.
22 So how come -- I'm trying to understand, you know, I 23 mean personally, how come we protracted these 24 inspections? How come we made the decisions that led 25 to waiting for circumferential cracks before we took NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N W.
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68 1 some actions there?
2 It seems to me that is an important 3 thought process that took place in the industry and 4 the NRC versus the thought processes that took place 5 in other countries. I quoted France because we just 6 compared with them our experience recently, and there 7 is a significant divergence there. So I am trying to 8 understand how we got there.
9 MR. HOWELL: Well, based on our review, I 10 mean, clearly, if you look back to the early nineties 11 and you look before then into the eighties, you will 12 see that most of the instances of identified nozzle 13 cracking -- and I'm not just talking about VHPs; I'm 14 talking about other instrument nozzles in the reactor 15 coolant system -- virtually all of them were axial.
16 Now what we found was that the condition 17 identified at Bugey both involved axial and 18 circumferential cracking. Some of that was 19 communicated back in the early nineties to the staff, 20 but perhaps not, well, in fact, not all the details 21 were well-recognized or understood. That may have 22 been a contributing factor as to why the potential for 23 circumferential cracking was not emphasized at that 24 time.
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69 1 early nineties that nozzle cracking would be axial, 2 that this axial cracking would not result in 3 catastrophic failure of the nozzles, that any leaks 4 that ensued would be detected in due time before 5 significant degradation.
6 As a result of that, further work became 7 protracted. I mean, there was work by the industry to 8 perform some pilot, non-visual examinations at plants 9 in the mid-nineties, continuing reviews by the staff.
10 This continued on, and before you know it 10 years 11 elapsed before the Oconee experience.
12 CHAIRMAN APOSTOLAKIS: So that would seem 13 to be a key element.
14 MR. HOWELL: It is a key element. So 15 that's why we highlighted it upfront.
16 MEMBER SIEBER: But the emphasis has 17 always been on cracking as opposed to corrosion of the 18 ferritic material.
19 MR. HOWELL: Right.
20 MEMBER SIEBER: And I don't think that 21 anybody realized that the extent of corrosion that did 22 occur would occur until the day this Besse situation 23 arose.
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70 1 occur because it would be detected long before there 2 was significant degradation.
3 VICE CHAIRMAN BONACA: Well, how would it 4 be detected?
5 MR. HOWELL: By visual exams during 6 outages.
7 CHAIRMAN APOSTOLAKIS: Which were not 8 taking place.
9 MR. HOWELL: Or inadequate, whatever, not 10 comprehensive, yes.
11 CHAIRMAN APOSTOLAKIS: Sure.
12 MR. HOWELL: And that was one of the 13 underlying notions that was not verified. That 14 assumption was not verified because, in reality, what 15 was happening is that this was a voluntary program 16 that was being implemented by licensees, and it was 17 not being inspected by the NRC. There was no 18 independent verification by us that these programs 19 were effective over the course of 10 years.
20 CHAIRMAN APOSTOLAKIS: Now what was the 21 role of our inspectors there?
22 MR. HOWELL: Well, I was going to get to 23 that.
24 CHAIRMAN APOSTOLAKIS: Okay, okay.
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71 1 that's the third bullet there. We collectively, the 2 NRC, knew about some of the symptoms and indications 3 of the reactor coolant system unidentified leakage.
4 So I'm clear, not about the nozzle leakage, obviously, 5 but about ongoing, unidentified RCS leakage.
6 There was also some knowledge about boric 7 acid deposits on the head during the 2000 refueling 8 outage timeframe.
9 CHAIRMAN APOSTOLAKIS: Now further reviews 10 became protracted. Not only the reviews, but I mean 11 there were decisions made, as Jack told us earlier, to 12 ease the access to the top of the head, so that 13 inspection would take place, and that was postponed 14 for a number of years, right?
15 MR. HOWELL: Correct.
16 CHAIRMAN APOSTOLAKIS: I'm just curious, 17 the Safety Board, they must have a visiting Safety 18 Board.
19 MR. HOWELL: They do.
20 CHAIRMAN APOSTOLAKIS: Or the INPO guys -
21 MR. HOWELL: They do.
22 CHAIRMAN APOSTOLAKIS: Nobody noticed that 23 and asked, "Why are you doing this?" or everybody 24 says, "Well, that's okay."?
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72 1 record indicates. With respect to the Safety Board, 2 there was, in the 2001 timeframe, there was discussion 3 between the Safety Board and the plant staff that 4 there was obviously active reactor coolant system 5 leakage that was ongoing, and it had not been 6 identified, and -
7 CHAIRMAN APOSTOLAKIS: Yes.
8 MR. HOWELL: -- that the efforts to date 9 had not been successful in identifying that leak.
10 That's about as far as we could piece together the 11 story there.
12 I mean, it was obvious that there was 13 ongoing leakage that had been identified.
14 CHAIRMAN APOSTOLAKIS: Yes.
15 MR. HOWELL: Then, in terms of other third 16 party reviews, clearly, a message was sent that they 17 had a chronic problem with not fixing known primary 18 system leaks. That was documented in reviews that 19 were conducted in the 1997-98 timeframe.
20 There was also some documentation, both by 21 the NRC and INPO, regarding a particularly egregious 22 leak involving the pressurizer spray valve that ate 23 away some of the fasteners because carbon steel 24 fasteners were replaced instead of stainless steel 25 fasteners.
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73 1 CHAIRMAN APOSTOLAKIS: There were two 2 things here then. One is the actual performance-based 3 failure to do something, like they were losing 4 inventory. But the second, you know, the mere fact 5 that they were deferring this action from year to 6 year, I mean, even if they were not losing inventory, 7 shouldn't somebody ask the question, "Why?" Why did 8 they decide to -- how many years did they defer it?
9 For 10 years?
10 MR. HOWELL: Eleven years. Actually, it 11 was deferred once again. If you count it all up, it 12 wasn't going to be installed until 2004. So it would 13 have been 13 years.
14 CHAIRMAN APOSTOLAKIS: Thirteen years, and 15 nobody asked, you know, "Why are we doing this for 13 16 years," deferring it from year to year to year?
17 MR. HOWELL: Well, it was deferred.
18 Actually, it was closed at one point and then reopened 19 again because of the ongoing nature of the problem, 20 and then deferred again subsequently.
21 We interviewed members, some of the 22 members, who were involved in that decision. Those 23 members, their view was that this was not an immediate 24 safety issue. They realized that there was boric acid 25 on the head, but it had been on the head for quite NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N W.
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74 1 some time, and they hadn't identified any significant 2 degradation.
3 CHAIRMAN APOSTOLAKIS: Let me understand 4 the meaning of the word "immediate." If something is 5 not immediately a safety concern in 1991, so we'll do 6 something about it in the future. Then in the year 7 2001 we still say it is not an immediate safety 8 concern? That means it is never going to be an 9 immediate safety concern, right?
10 It's like the fusion thing; every day it's 11 50 years from now. Time doesn't seem to flow. I 12 mean, 20 years ago fusion was going to be a reality 50 13 years from that time. Now it's 50 years from today.
14 So it is not an immediate concern, and 15 that statement is independent of time. That's 16 essentially what you are saying. You can say that 17 anytime and defer -- I mean, I'm not blaming you, 18 obviously.
19 MR. HOWELL: No, I understand.
20 CHAIRMAN APOSTOLAKIS: I'm trying to 21 understand what the word "immediate" means.
22 MEMBER WALLIS: Well, global warming is a 23 better example than fusion, I think.
24 (Laughter.)
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75 1 time.
2 MEMBER SHACK: How many B&W plants made 3 the modification that was needed so that they could 4 look at everything?
5 MR. HOWELL: I need to answer that in two 6 parts because they implemented these modifications 7 over time.
8 MEMBER SHACK: Right.
9 MR. HOWELL: At the time that some of the 10 deferrals were going on Davis-Besse, I believe that 11 there was at least one other B&W plant that had not, 12 at that time during this 10-year timeline, 13-year 13 timeline, at that point in the late nineties, had not 14 made the modification yet. I understand now that that 15 modification has subsequently been performed.
16 MEMBER SHACK: So by the late nineties all 17 but two had made the modification?
18 MR. HOWELL: That's my understanding, yes.
19 CHAIRMAN APOSTOLAKIS: What does that 20 mean? What do I learn on that?
21 MEMBER SHACK: Well, that they could at 22 least follow the requirement that they were able to 23 see what was happening.
24 CHAIRMAN APOSTOLAKIS: Who is "they?"
25 VICE CHAIRMAN BONACA: The licensees.
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76 1 MEMBER SHACK: The licensees.
2 VICE CHAIRMAN BONACA: The other 3 licensees.
4 CHAIRMAN APOSTOLAKIS: No, but what does 5 it mean for Davis-Besse? You know, the years pass.
6 We recognized at the beginning it was not an immediate 7 safety concern, and other licensees are doing it, and 8 we still say, no, it's not immediate. What does that 9 mean?
10 VICE CHAIRMAN BONACA: It seems to me that 11 it means the requirement should have been there, it 12 seems to me, not a voluntary initiative, but realizing 13 that it is not an immediate safety concern, you then 14 say, however, it may be a future safety concern, and 15 therefore, the inspection is required, is a needed 16 thing to do. Therefore, at some point some 17 modifications had to be done to be able to inspect.
18 I mean, it has to be -
19 MR. HOWELL: We made a recommendation to 20 address that very point.
21 MEMBER SHACK: Wouldn't the Boric Acid 22 Corrosion Program under the Generic Letter say' that 23 you have to be able to inspect that?
24 MR. HOWELL: Yes.
25 MEMBER SHACK: So they were in violation?
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77 1 MR. HOWELL: Clearly, the intent was that 2 they inspect it. There was no detailed guidance in 3 the procedures to perform a head inspection, but the 4 intent was there. The intent was to identify all 5 potential leakage sources and inspect them.
6 MR. GROBE: The licensees themselves 7 specifically identified that they could not implement 8 their procedure for the head because they could not 9 thoroughly inspect and clean all areas of the head, 10 and wrote that up in the CR, in the Condition Report.
11 That's why their failure to implement these 12 modifications was a violation.
13 CHAIRMAN APOSTOLAKIS: Now when the other 14 plants actually implemented, did they find anything 15 that was worth communicating to Davis-Besse, that 16 maybe the statement that it is not an immediate safety 17 concern is not very valid anymore? Did they find 18 anything? Did they find any cracks that were unusual 19 or anything or did they just -
20 MR. HOWELL: There have been cracks at all 21 the other B&W plants, as of late 2001. So we have to 22 be clear about the time period.
23 CHAIRMAN APOSTOLAKIS: Yes.
24 MEMBER SHACK: Nobody else found hundreds 25 of pounds of boric acid though.
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78 1 MR. HOWELL: True. Right.
2 CHAIRMAN APOSTOLAKIS: Did they find 3 circumferential cracks?
4 MR. HOWELL: Yes.
5 MR. GROBE: Not during the timeframe that 6 these decisions on deferral were to be made.
7 MR. HOWELL: Right, right. This was late 8 in the game, you know, 2001.
9 MEMBER FORD: Could I return to the 10 immediate question that we had on that slide there?
11 In your conclusions you made the recommendation, you 12 make the correct observation we should take more 13 account of what is happening overseas, France.
14 MR. HOWELL: Yes.
15 MEMBER FORD: When you were discussing 16 this immediate aspect, did it never occur to anybody 17 that the French were at least seven-eight years in 18 front of us in terms of coming up with remedial 19 actions, changing their tech. specs. for leakage 20 rates, et cetera? Did no one here within the NRC or 21 within our industry in this country wonder why the 22 French were doing this, and they had exactly the same 23 phenomena, starting with Bugey and then a whole lot of 24 other reactors?
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79 1 we talked to a number of folks here on the staff. We 2 also talked to some French regulators. We got a range 3 of views. Some were under the impression that their 4 corrective actions were largely economic in nature.
5 MEMBER FORD: The French -
6 MR. HOWELL: Yes, in terms of head 7 replacements, and that there's others who, at least 8 until the Davis-Besse event, would have told you prior 9 to that point that they thought that the French 10 corrective actions were an overreaction because of the 11 belief that there would be axial cracking and that 12 these would be detected, these leaks would be detected 13 in time.
14 MEMBER FORD: But they had circumferential 15 cracks?
16 MR. HOWELL: Correct, and the extent of 17 staff awareness of the Bugey circumferential cracking 18 was not widespread. Part of that may be, I think at 19 least in part, the manner in which this information is 20 shared with us, how much we knew, how much was 21 provided, how was it was internally disseminated.
22 It was a number of years ago; there's 23 staff turnover. There's a lot of reasons for it, but 24 there was some awareness, but it didn't translate into 25 any action in terms of addressing circumferential NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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80 1 cracking by means of generic communications until the 2 Oconee event.
3 MEMBER FORD: It wasn't pure insularity?
4 MR. HOWELL: Right. Now there was some 5 mention of circumferential cracking in Generic Letter 6 97-01. So there clearly was some recognition, but, 7 again, the predominant view was, and operating 8 experience indicated, that axial cracking was 9 predominant -
10 MEMBER FORD: I must admit we're jumping 11 the gun a little bit, and I'm sure you may come to it.
12 In your recommendation you say you should take into 13 account other experience, worldwide experience. How 14 are you going to accomplish that?
15 MR. HOWELL: Well, we had a program and we 16 actually do have a program. What we are saying is 17 that there are some changes to the processes by which 18 we obtain and internally assess and disseminate 19 foreign operating experience back in the 1999 20 timeframe, and what we are recommending is that we 21 assess the whole operating experience review program 22 and look at that particular aspect to make sure that 23 it is functioning well.
24 Slide 8, overall conclusions: There were 25 some other contributing factors. Guidance and NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE, N.W.
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81 1 requirements, I am going to talk about these as well; 2 staffing and resources; EVS communications, that's 3 really written communications primarily, and licensing 4 processes and implementation of those processes.
5 Next slide. Okay, with respect to the NRC 6 and industry review and assessment, and followup of 7 operating experiences, there are a number of topical 8 areas in the report that are addressed.
9 I want to start out by saying that the 10 Task Force conducted its own independent assessment of 11 the reported data on primary system leakage from 1996, 12 I mean 1986, all the way up to the time of the Davis 13 Besse event. So that covered about 16 years.
14 So we looked at LERs, Licensee Event 15 Reports, as our source of data. We analyzed this 16 data. What we found is that there are many, many 17 boric acid corrosion events, many nozzle leakage 18 events. Obviously, none of the nozzle leakage events 19 were not -- did not result in a degradation to the 20 same degree that occurred at Davis-Besse, but, 21 nevertheless, there were a number of reported events 22 involving instrument nozzles primarily and pressurizer 23 heater sleeves.
24 What we found is that essentially there's 25 two plants, two types of plants, NSSS designs that are NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N W.
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82 1 outliers, B&W and Combustion Engineering, in terms of 2 the total number of events.
3 A lot of this information was known by the 4 industry and the staff. It resulted in, since 1986, 5 17 separate generic communications by the NRC. I 6 think there was a similar number from INPO. Yet, in 7 spite of that, this event still occurred. So the 8 question is, why? Why didn't the process serve as a 9 catalyst to ensure that something this bad didn't 10 happen?
11 What we found was that there's a number of 12 issues here, but some of the relevant information was 13 perhaps not known. You can see that when you analyze 14 the data, that there was gaps in periods where there 15 were events being reported about instrument nozzle 16 leaks, for example, at CE plants, and there was no 17 generic communication that occurred during that 18 period.
19 But, also, we found that one of the things 20 that we hadn't done well as an agency was to 21 independently verify that these programs were being 22 effectively implemented, specifically with respect to 23 the Boric Acid Corrosion Program that is governed by 24 Generic Letter 88-05. We had an inspection procedure, 25 but it was a voluntary inspection procedure. It was NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N W.
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83 1 never implemented at Davis-Besse, and it was rarely 2 implemented nationwide at the other plants.
3 So we never verified the underlying 4 assumption that these types of programs would be 5 effective in identifying nozzle leaks in a timely 6 manner to prevent significant degradation of the head.
7 Similarly with Generic Letter 97-01 on 8 axial cracking of vessel head penetration nozzles, 9 there was no independent verification of those 10 activities by the staff.
11 So there's a number of issues with the 12 implementation of the Generic Communications Program.
13 So it's a mixed story. We knew a lot. We put out a 14 lot to the industry. Yet, in spite of that, there's 15 some things that either we didn't fully appreciate or 16 fully assess or didn't take action on to verify.
17 Generic Issues Program, there was no 18 generic issue previously identified for either boric 19 acid corrosion solely. There was one in the early 20 eighties that pertained in part to boric acid 21 corrosion in fasteners, stemming from an event at Fort 22 Calhoun station, nor was there one that pertained to 23 stress corrosion cracking of nozzles.
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84 1 had good exchange with the French that provided some 2 information as to the basis for some of the French 3 decisions about corrective action.
4 What they essentially told us was that at 5 the time of the Bugey experience that they recognized 6 the potential for two failure modes, catastrophic 7 failure of the nozzle from circumferential cracking 8 and also significant degradation of the vessel head 9 from a leaking nozzle. That is why they embarked on 10 the course of action they did in terms of mandating 11 non-visual examinations of the penetrations.
12 It was difficult for us to piece together 13 how much of that was known or recognized by the staff.
14 Again, there was a range of views about why the 15 corrective actions were what they were pertaining to 16 the French reactors.
17 MEMBER WALLIS: Once someone had decided 18 that it didn't apply to us, then, presumably, the 19 interest in Bugey was dropped? That may have been 10 20 years ago?
21 MR. HOWELL: Well, yes, if I can expand on 22 that, there was some further review. There was a 23 NUREG published in the mid-nineties timeframe that did 24 some comparisons between French operating experience 25 versus experience -- I believe the plant may have been NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE. N W.
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85 1 Point Beach -- at one U.S. plant. There was a number 2 of differences identified. It was on the basis of 3 those differences that reinforced the notion that it 4 wasn't a problem with U.S. reactors at that time.
5 That is pretty clear from reading that NUREG.
6 MEMBER FORD: Back in July of last year, 7 at the ACRS meeting, we asked a very specific 8 question: Why we weren't taking into account -- this 9 is last year -- into account the foreign experiences, 10 specifically French? The answer we had was, hey, the 11 French operate their reactors, they also design their 12 reactors, in a completely different way to ours, and 13 therefore, their experience is of little value. Do 14 you still have that opinion?
15 MR. HOWELL: Well -
16 MEMBER FORD: This was the opinion given 17 by the utilities.
18 MR. HOWELL: I mean, there are -
19 MEMBER FORD: I'm sorry, the operators, 20 the OEMs.
21 MR. HOWELL: Well, clearly, there are some 22 differences, but, ultimately, there was stress 23 corrosion cracking there and here. So we need to 24 appreciate that. There were some similarities, too, 25 in our view. So it would be hard for me to agree with NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N W.
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86 1 that notion that all these differences would explain, 2 with the benefit of hindsight, why more action wasn't 3 taken.
4 Now, having said that, action was being 5 taken. It was just protracted. I mean, there's a 6 clear recognition that circumferential cracking could 7 occur, and then if it did, it needed to be looked at, 8 because that was a serious issue.
9 In terms of assessment and verification of 10 industry technical information, I mentioned one, but, 11 essentially, in the early nineties, when the 12 conclusion was made that these leaks would be detected 13 in a timely manner, there were some fundamental 14 assumptions that essentially weren't verified.
15 First and foremost was the Generic Letter 16 88-05 programs, their implementation effectiveness had 17 never been verified. I won't say never. Had not, 18 typically, routinely been verified at the time.
19 Also, there was some, at least for the B&W 20 plants, there was some expectations that enhanced 21 visual inspections of the vessel heads would be 22 conducted because of the design of the CRDMs with the 23 flanges and the history of the leaking flanges and the 24 fact that boric acid deposits from the leaking flanges 25 could be deposited on top of the head.
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87 1 Yet, these enhanced visual inspections 2 were not conducted at Davis-Besse. There was no 3 verification of that.
4 There was also a belief that undetected 5 leaks would not be significant in terms of degradation 6 in one cycle. If you had an incipient failure that 7 wasn't detected at the start of or during the 8 refueling outage, and then became a leak at the start 9 of an operating cycle, the view was that such a leak 10 would not result in significant degradation.
11 It is not clear to the Task Force how much 12 was known about the different tests and experiments 13 that were conducted to identify what these corrosion 14 rates could be. What we found is that on the high end 15 that these corrosion rates could be in excess of 4 16 inches per year.
17 So at Davis-Besse they have a two-year 18 operating cycle. So you could have significant 19 degradation in one or two cycles, which I believe is 20 what occurred.
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88 1 operating experience.
2 The reason I bring this up is that, prior 3 to that reorganization, there were some reviews, 4 assessments done of the agency's operating experience 5 review programs, but they were primarily focused on 6 efficiency. So we looked at this, and the Task Force 7 believes that, given all the changes that have 8 occurred in that program and how much of this relates 9 to the Davis-Besse event, that one of our 10 recommendations was to go back and do an effectiveness 11 review of our entire program in that area.
12 Next slide, please.
13 MEMBER POWERS: The previous slide, which 14 I really don't need to see, delineates a set of 15 plausibility arguments that were advanced at various 16 points in time, plausibility that the French 17 experience doesn't apply, plausibility the corrosion 18 rates are not excessive, and things like that.
19 Those kinds of arguments appear in front 20 of this Committee a lot, and whatnot. Based on what 21 you are finding, is there any generic advice that can 22 be formulated considering plausibility arguments?
23 MR. HOWELL: Well, to answer your 24 question, of course, we looked only at Davis-Besse.
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89 1 plants to try to get some sense for how these programs 2 were implemented there.
3 But one of the reasons we looked at 4 operating experience holistically as it relates to 5 these two technical issues was to get some generic 6 sense for how well the industry was doing relative to 7 these two areas. On that basis, we felt that to get 8 a better handle on just how well these plausibility 9 arguments, as you indicated, are being implemented, 10 that perhaps we ought to go back and review a sample 11 of other generic issues that past acti'ons have been 12 identified and supposedly taken, to get some sense for 13 how well the implementation effectiveness is being 14 addressed.
15 MEMBER POWERS: I understand.
16 The Committee members will note that I 17 think on Friday we are going to listen to a protracted 18 plausibility argument concerning the quality of PRAs 19 and want to bear in mind the adequacy of plausibility 20 arguments.
21 MR. HOWELL: The next slide. With respect 22 to contributing factors involving Davis-Besse 23 performance, we have five major areas that are 24 documented in the report.
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90 1 leakage symptoms and indications, this has been 2 discussed by Jack and others. The licensee failed to 3 promptly identify and correct known leaks, not only 4 with CRDM flanges, but also primary system valves, and 5 also reactor coolant system instrument thermal welds 6 over a long period of time.
7 We also identified that there was a 8 pattern of behavior in which the symptoms of this 9 leakage in terms of fouling of containment air 10 radiation monitors and the containment air coolers was 11 the licensee's primary focus, was to address the 12 symptoms. What was absent was objective, rigorous 13 information to support activities to get to the root 14 of the problem, either through the root causes 15 analyses of the various condition reports that had 16 been written over the years or during outages, when 17 there was an opportunity to actually identify the leak 18 sources.
19 In terms of the Boric Acid Corrosion 20 Control Program and implementation, I don't want to 21 rehash what's been covered, but we found that the 22 program, or at least we concluded that the program was 23 both inadequate and was not implemented as written.
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91 1 pertains to enhanced visual inspections. Other 2 guidance put out by various industry groups, EPRI and 3 the B&W Owners Group, were either not verified to be 4 implemented -- there was no mechanisms at the site to 5 ensure that these actions would be implemented.
6 Some of the guidance, arguably, is 7 incomplete. So there were some contributions to the 8 lack of identification of the problem in that.
9 Internal and external operating experience 10 awareness, there were numerous other boric acid 11 corrosion events involving plant components at Davis 12 Besse. One of them, in particular, involved the 13 pressurizer spray valve. This leaking valve was 14 identified in 1998. It was the subject of a special 15 inspection by the NRC in 1999.
16 The lessons learned for that event I 17 think, with one possible exception, are the same 18 lessons learned for the RPV head event. So one has to 19 ask why the actions weren't effective.
20 What we found was that some of the 21 identified actions were not fully implemented, and, 22 arguably, some of the identified actions were not 23 timely.
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92 1 Besse organization regarding decisions not to inspect 2 the head or postpone the inspections?
3 MR. HOWELL: I'm trying to just mentally 4 sort through all the interviews we conducted. What we 5 found was, that there was a varying level of -- there 6 was a difference in view about the status of head 7 cleaning activities at the plant.
8 What we found was that a number of 9 managers and engineers and others clearly knew that 10 the plant was being restarted from successive 11 refueling outages with large boric acid deposits on 12 the head. Others believed that the head, especially 13 by the 2000 timeframe, had been completed cleaned. In 14 part, we think that to be the case because of some of 15 the internal documents that Jack made reference to 16 that were available to the staff, to the licensee 17 staff, for review.
18 So is that responsive? I mean, that's 19 what we found.
20 VICE CHAIRMAN BONACA: I'm just wondering, 21 I mean, if everybody within the Davis-Besse 22 organization agreed that there was no concern and they 23 could restart, or was there somebody who raised issues 24 regarding, for example, the clogging of the filters 25 and things of that kind? Was there any record of NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE, N W.
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93 1 that?
2 We are talking about safety culture, and 3 I think it is -
4 MR. HOWELL: Right. As Jack alluded to, 5 there were a number of individuals involved in head 6 cleaning activities that were concerned, clearly, that 7 the program procedure could not be implemented, that 8 there were deposits on the head. There were others 9 who believed that -- and this goes back to one of the 10 past lessons that wasn't learned -- was that these 11 deposits would be dry deposits.
12 They wouldn't be highly corrosive.
13 They've been there for a while. They haven't caused 14 a problem yet and are not likely to cause a problem 15 other than some operational problems with the rad 16 monitors or the containment air coolers, which were, 17 at least in their view, being addressed.
18 So, yes, some thought that the head needed 19 to be thoroughly clean and inspected. Others thought 20 that, yes, they are going to do as much as they can, 21 given the design of the service structure, but, by and 22 large, these deposits would not be harmful.
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94 1 a number of areas. I will just go through these real 2 quickly:
3 Inappropriate focus on production; 4 accepting longstanding problems; lack of management 5 involvement, questioning attitude; lack of management 6 involvement, head-cleaning activities; lack of 7 engineering rigor was evident by a number of work 8 products that we reviewed; instances of procedural 9 non-compliance. I mentioned symptom-based repairs to 10 the containment air radiation monitors.
11 I will just point out this system is 12 designed to detect RCS leaks. So they were performing 13 symptom-based repairs to the very system that was 14 designed to detect leaks.
15 Not internalizing lessons learned from 16 past boric acid corrosion events; not fully assessing 17 operating experience; inadequate and untimely 18 corrective actions, and then implementation weaknesses 19 with their employees' concerns program -- that relate 20 or bear on the underlying technical issues.
21 CHAIRMAN APOSTOLAKIS: So when you say, 22 "management," how far down do you go?
23 MR. HOWELL: We talked to folks from the 24 supervisory level all the way up to the Site VP level.
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95 1 were aware of the boric acid deposits on the head.
2 Some of the folks had not availed themselves of 3 reviewing the videotapes which graphically depict the 4 extent and condition. Some of those were aware of it, 5 but, again, were under the belief that these deposits 6 would be benign.
7 There was a lot of turnover with the 8 Systems Engineers over the course of three outages 9 involved in the cleaning of the head. So there was 10 perhaps some communication handoffs that didn't occur 11 that should have.
12 But the knowledge of the head conditions, 13 at least in a general sense, were known all the way up 14 to the VP level. But the activity to clean the head 15 was primarily at the contractor and system engineer 16 level almost entirely, as far as we could reconstruct.
17 MEMBER WALLIS: There's nobody who said, 18 "How come we think these deposits are dry when the 19 video shows that they were flowing?"
20 MR. HOWELL: Again, they thought that the 21 deposits were from the leaking CRDM flanges. Then I 22 believe that the AIT followup performed by the Region, 23 as well as our own review, indicated that there's some 24 evidence that should have clearly suggested to them 25 that the flanges were not leaking in the 2000 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE, N W.
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96 1 timeframe and were not the source -
2 MEMBER WALLIS: Even if it was the flanges 3 that were leaking, as long as those deposits are 4 liquid and at the right temperature and the right 5 acidity concentration, they can corrode the heads 6 severely.
7 MR. HOWELL: Correct, and that's one of 8 the lessons that was not learned. I mean, the whole 9 notion that it is acceptable to have leaking deposits 10 on the head -- I mean the Turkey Point event, the 11 Besnow event, the Salem event, and Calvert Cliffs 12 events clearly indicate that even from the surface 13 corrosion can be much more significant than 14 anticipated. That condition, in and of itself, should 15 not have been viewed as acceptable. That lesson was 16 either not learned or forgotten.
17 MR. GROBE: There were two specific events 18 at Davis-Besse. Art already mentioned the pressurizer 19 spray valve which was of a different character. But 20 there was also a leak on the head vent to the steam 21 generator, where the penetration to the steam 22 generator, there was a crack in that line and a 23 leakage, and approximately an inch of steam generator 24 metal had corroded away around that penetration. So 25 it is clear that lessons had not been learned.
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97 1 MEMBER SIEBER: What timeframe did that 2 occur?
3 MR. GROBE: I believe it was in the mid 4 nineties.
5 MR. HOWELL: Which event are you referring 6 to?
7 MR. GROBE: It was a crack on the head 8 vent to the steam generator line.
9 MR. HOWELL: That was the 1992-93 10 timeframe. Again, that was a case where the leak was 11 identified in 1993, but not repaired -- 1992, I'm 12 sorry, but not repaired until the following outage in 13 1993 because of the notion or belief that the 14 corrosion rates would not be extensive.
15 All right, next slide. The next slide 16 deals primarily with NRC performance. In terms of 17 reactor coolant leakage -
18 MEMBER WALLIS: I'm sorry, when these 19 folks gave you their rationale for ignoring all these 20 symptoms, is there evidence that their rationale for 21 ignoring the symptoms was at the time that they were 22 aware of them? In other words, is there a written 23 record? Or is this something they made up to 24 rationalize their behavior when they came before you?
25 MR. HOWELL: Yes and no, and the reason I NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W (202) 234-4433 WASHINGTON, D C 20005-3701 www.nealrgross.com
98 1 say that is that, clearly, there's documentation to 2 suggest that they believe that the leakage, that boric 3 acid deposits being found on the head were from 4 leaking CRDM flanges.
5 There's also one document in the 2000 6 timeframe that indicates -- and it's vague or arguably 7 vague -- that the leakage may be from some other 8 source; namely -- there's not too many other sources 9 -- namely, a nozzle. That's the inference. Yet, 10 there's no documentation that explicitly dispositions 11 that passage in the condition report.
12 MR. GROBE: There was extensive dialog 13 between the resident staff and regional supervisors 14 and the licensee. I believe, was it five successive 15 Resident Inspection Reports? That's a 30-week period 16 of time where it is documented that we were having 17 dialogs with them and addressing this issue.
18 MR. HOWELL: And that's really the next 19 point. Reactor coolant system leakage assessment, 20 this is what the NRC reviewed.
21 What we found, as Jack indicated, that 22 there was a -- the symptoms of the RCS unidentified 23 leakage were well-known at the plant. Consequently, 24 they were well-known by the inspection staff, and 25 there was inspection followup of the symptoms. What NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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99 1 I am talking about specifically are the rad monitoring 2 fouling and containment air cooler fouling, in 3 particular. This was in the 1999 timeframe.
4 What we found was that the followup, as 5 Jack indicated, was of a more routine nature. What we 6 didn't see was any focused effort on the part of the 7 NRC to try to bore in on the source of the 8 unidentified leakage.
9 Now I view that as a missed opportunity.
10 It is not clear at all that, had that been done, that 11 it would have helped us get to the problem sooner or 12 get to the problem in terms of the NRC identification, 13 but it was an opportunity to have done so.
14 In addition to that, what we found is that 15 there were some actions indicated by the licensee to 16 try to get to the source of this unidentified leakage 17 in the 2000 refueling outage, and that was documented 18 in the Inspection Report.
19 We could find no solid, hard information 20 from the licensee that that rigorous leak hunt ever 21 occurred during that outage, nor was there any NRC 22 followup of that activity to determine that at the 23 time.
24 There was also knowledge on the part of 25 the NRC staff that there were boric acid deposits on NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE, N W.
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100 1 the head in the 2000 refueling outage. Some of the 2 condition reports that documented the condition were 3 reviewed, but there was no followup of that 4 information, nor was that information communicated to 5 the inspector's supervisor as far as we could tell.
6 When we talked to the former inspector 7 about the rationale for that, what we learned was that 8 this particular inspector was involved with the 9 special inspection of the pressurizer spray valve that 10 occurred in the 1999 timeframe, a year before. So he 11 was very familiar with the deficiencies that were 12 identified in the Boric Acid Corrosion Program, and he 13 was also very familiar with the corrective actions 14 that were to be implemented to address those 15 deficiencies.
16 So it was on that basis that he believed 17 that, because of the corrective actions that should 18 have been put in place, that the licensee would have 19 fully assessed and evaluated any potential for 20 corrosion on the head, would have cleaned all the 21 boric acid off, because that was one of the findings, 22 and made an assessment. So it was on that basis that 23 there was no detailed inspection followup of boric 24 acid being found on the head during the spring 25 refueling outage.
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101 1 There were some other less-direct 2 opportunities for the NRC to have identified this 3 issue through both licensing and inspection 4 activities. For example, the licensee processed a 5 tech. spec. amendment to relax the requirements, tech.
6 spec. requirements, the allowed outage times for the 7 containment air radiation monitors because they were 8 fouling so frequently in the 1999 timeframe due to the 9 boric acid deposit buildup and iron oxide.
10 There was some knowledge of that symptom 11 by the licensing staff, or at least one member, but 12 there was no description of that issue found in the 13 licensee's submittal about the operational problems 14 that the system was experiencing during that 15 timeframe.
16 So, anyway, that amendment request was 17 processed. So the licensee got some relief, which is 18 one of the symptom-based repairs that I made mention 19 of earlier.
20 There were also some other inspections in 21 which we had opportunities to perhaps visually see the 22 deposits on the head during the 1998 and 2000 23 refueling outages through the conduct of routine 24 inspections.
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102 1 implementation, we also found some gaps where there 2 were either requirements or implementation issues -
3 either the guidance could have been clarified or we 4 didn't implement the guidance. I mentioned the RC2 5 event. There was no closeout of the escalated 6 violation by the NRC. In other words, there was no 7 followup of the corrective actions pertaining to the 8 boric acid corrosion problems associated with the RC2 9 event.
10 There was some followup of a material 11 control problem in which the wrong bolts got 12 installed, and there were some other activities in 13 which we had opportunities to sample some of the 14 condition reports through routine corrective action 15 inspections, where the summaries of the Condition 16 Reports documenting the problems with the boric acid 17 on the head were provided to us, but they weren't very 18 detailed.
19 So, in reviewing those three CRs in a list 20 of thousands, they weren't picked for samples. So 21 there's things of that nature.
22 In terms of integration and assessment of 23 performance data, as Jack indicated, we knew quite a 24 bit about the fouling of the rad monitors. What we 25 didn't piece together was that symptomatic repairs NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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103 1 were occurring to the system over a period of a couple 2 of three years.
3 With respect to the failing of the rad 4 monitors, there was some installation of HEPA filters.
5 There was a changing of the rad monitor sample points, 6 so they wouldn't foul as fast. There was a relaxation 7 of the tech. spec. requirement, so they wouldn't be 8 continually in the tech. spec. LCO. They were in this 9 LCO, just to give you some idea, hundreds of times in 10 the period of, I think, 1999, hundreds of times, 300 11 times, I think.
12 And there was a bypassing of the iodine 13 filter through a temp. modification because that 14 particular filter was saturating more quickly than the 15 other filters in that system for the other two 16 detectors.
17 But none of that was brought together to 18 paint a picture of a pattern of behavior that was 19 clearly based on addressing symptoms.
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104 1 actions, employee concerns and safety-conscious work 2 environment.
3 There were some staffing and resource 4 challenges within the Region during the period in 5 which the symptoms were becoming prevalent. There was 6 a period of high turnover in the Region at the time.
7 I think three, maybe four, 0350 Panels that were going 8 on at other plants within the Region, including the 9 organizational unit, the regional organization unit 10 that had responsibility for Davis-Besse.
11 So there was a number of challenges in 12 terms of maintaining the staffing plan at the site.
13 That's not a direct contributor. We can't really say 14 that this contributed to our failure to find this 15 sooner, but it certainly didn't help the situation.
16 As Jack indicated, we also found some 17 instances in which there was some inaccurate 18 information, Davis-Besse plant information, some of 19 it, as Jack indicated, internal documents as well as 20 information provided to the staff through either 21 bulletin submissions or presentations made to various 22 members of the staff that either contributed to, or 23 had the potential to cause, missed opportunities for 24 us to have identified the problem later in the 2001 25 timeframe.
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105 1 Then we found a number of licensing 2 process issues. There was a period of high Licensing 3 Project Manager turnover at the plant. There were 4 infrequent site visits by the Project Managers. Only 5 one Project Manager was aware of some of the symptoms, 6 even though there was these daily calls that occurred 7 with the site.
8 I mentioned the tech. spec. issue. I 9 mentioned that there was some operating experience in 10 service inspection reports that could have been 11 reviewed that weren't reviewed. Also, the basis for 12 the decision to accept continued operation of Davis 13 Besse beyond December 31st up to February 16th wasn't 14 well-documented. So there were a number of ancillary 15 issues.
16 In terms of recommendations, these are 17 just categories of recommendations. There are 10 18 broad areas: inspection guidance -- I won't go 19 through all of this, but we made recommendations to 20 address guidance in a number of areas, both the 21 underlying technical areas as well as in the cross 22 cutting areas, as well as other areas.
23 Operating experience -
24 MEMBER LEITCH: There's an appendix in the 25 report that lists all the recommendations.
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106 1 MR. HOWELL: Yes.
2 MEMBER LEITCH: I think there must be 3 about 50 of them.
4 MR. HOWELL: Fifty-one, yes.
5 MEMBER LEITCH: Okay, and I'm wondering, 6 is there some -- well, first of all, have these 7 recommendations been accepted, and if so, is there a 8 schedule and a prioritization for implementation?
9 MR. HOWELL: The agency approach for 10 addressing the recommendations is kind of a two-phase 11 report. We did our review and made the 12 recommendations, and then a senior group of NRC 13 managers was put together. Carl Paperiello was the 14 head of that group.
15 They have recently gone through all the 16 recommendations and have provided a report to the EDO 17 -- I believe it was issued on November 26th -- that 18 provides an assessment of the recommendations. If my 19 memory serves me correctly, I believe all but two of 20 the recommendations were accepted.
21 They were categorized into four broad 22 areas, and those areas pertain to the assessment of 23 stress corrosion cracking. That's one of the four 24 areas. The next area is the assessment and the 25 integration of operating experience. The third is NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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107 1 inspection assessment and project management guidance, 2 and the fourth is the assessment of barrier integrity 3 requirements.
4 So they blend all 51 recommendations into 5 those four areas. They accepted all but two. They 6 clarified a number of them. They consolidated a 7 number of them. A number of them they internally 8 flagged as high-priority items and others as medium 9 and low-priority items.
10 In a number of cases, at least I think for 11 the high-priority items, in most, if not all, cases 12 the idea is that a detailed action plan would be put 13 together to provide resources and schedules to 14 implement those actions. That has not yet been done, 15 since the report was just issued.
16 DR. ROSEN: Is that November 26th report 17 on the website?
18 MR. HOWELL: I don't know if it has been 19 -- Mag says it hasn't been released yet, but I think 20 the intent is clearly to make it publicly available.
21 DR. ROSEN: It's not now public?
22 MR. HOWELL: I don't know. I don't know 23 the status. I just got my copy.
24 MS. WESTON: Yes, it is not on the website 25 as of yesterday.
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108 1 MR. GROBE: It's not currently public.
2 There is a scheduled Commission meeting, though, 3 January 21st to discuss the results of that.
4 CHAIRMAN APOSTOLAKIS: Coming back to the 5 recommendations, I think we all agree, and during 6 Jack's presentation we also saw it, that we really 7 don't understand what an adequate safety culture is 8 and how to measure. What are the good indications?
9 We don't know. I don't think anyone knows.
10 Some of my colleagues with long experience 11 at nuclear plants tell me they walk into a facility 12 and 10 minutes later they know whether they have a 13 good culture there, but they can't tell me why. Now 14 given that these people are very few, we cannot afford 15 to have them go to all the plants and turn in a report 16 of that. So that is one element.
17 The second point here is that for the last 18 20-25 years this agency has started research projects 19 on organizational/managerial issues that were very 20 abruptly and rudely stopped right in the middle 21 because, if you do that, the argument goes, regulation 22 follows. So we don't understand these issues because 23 we never really studied them.
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109 1 important, but we are not going to have any indicators 2 for it because, again, we don't know what they are, 3 but, fundamentally, if there is a problem, we will see 4 it in the performance of the equipment.
5 I was wondering why, after this incident 6 and all the stuff that has happened in association 7 with it, you are not recommending that the agency 8 undertake some sort of a program to try to understand 9 these things better. Or is research something that 10 you don't think is needed in this area?
11 MR. HOWELL: Well, we didn't make a 12 specific recommendation about research, but we did 13 make a number of specific recommendations that 14 certainly touch on the characteristics and attitudes 15 of safety culture. Maybe it is a packaging issue, but 16 I think there is clearly some recognition by all who 17 have looked at the Davis-Besse event that there are 18 safety culture issues that need to be looked at.
19 So, to that extent, we did make 20 recommendations involving an Employee Concerns Program 21 and safety-conscious work environment and 22 understanding the influences of schedule and other 23 factors on decisions about work scope and things of 24 that nature.
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110 1 Commissioners, after they look at your report, they 2 will say, "Aha, so we really have to do something 3 about it. Mr. Thadani, do something about it."? Is 4 that clear from your recommendations?
5 MR. HOWELL: Again, the Senior Management 6 Review Team has reviewed all the recommendations and 7 has, in turn, endorsed them, and so noted in their 8 report to the EDO. You know, I don't know how clear 9 it is.
10 I guess, clearly, if you read Section 3.2 11 of our report, I can't answer the question what an 12 adequate safety culture is, either, any better than 13 anybody else in this room, but, clearly, there's 14 issues there. I think those issues are causing all of 15 us to go back and revisit some of our past -
16 CHAIRMAN APOSTOLAKIS: There is a 17 reluctance on the part of decisionmakers in this 18 agency to get into these things. These things get us 19 into trouble all the time. Let me give you an 20 example.
21 I think Mr. Grobe mentioned that the 22 organization did not appear to learn from its own 23 experience and other people's experience. I think you 24 also touched upon it.
25 Well, I found out the last year or so in NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE, N W.
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iii 1 another context there's vast literature out there by 2 people who are not engineers who studied how 3 organizations learn. I will be the very first one to 4 admit that, if we think that we are going to find the 5 solutions to our problems by looking at that 6 literature, that's a very naive approach because we've 7 got similar problems with psychology and management 8 science, and so on.
9 But it is interesting, though, that there 10 is this whole literature there, and we don't seem to 11 be taking advantage of it by having our own engineers 12 and researchers look at it and say, "A, B, F, and G 13 are really applicable to us. Let's see how we can "14 make it real in our environment."
15 There is an extreme reluctance to do that.
16 I don't understand why not. I was hoping that some of 17 these reports with all these recommendations were 18 going to say, hey, go out and study these things a 19 little more, and it is just not happening.
20 VICE CHAIRMAN BONACA: If I could make a 21 comment also about the safety culture, Mr. Grobe, you 22 showed before that you are evaluating whether or not 23 the plant is ready to restart. One thing that 24 concerns me goes back to the question I asked before
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112 1 these events that were taking place, the clogging, et 2 cetera, et cetera?
3 If I had known that there was different 4 opinions at the technical level, strong differing 5 opinions, I would feel better about the culture of the 6 organization. You know, differing opinions may be 7 overridden by management, and then you may find that 8 there is a management problem. So to change 9 management is a solution there in that case which is 10 pretty obvious.
11 But when you have an organization that 12 seems to be walking in lockstep, where everybody gets 13 convinced very easily, and there is this refuting on 14 a daily basis of indications, which are the most 15 important thing that the operators have -- all you 16 have is indications, and you have to believe those 17 indications, not to cancel the indication. You can't 18 just continuously cancel the indication.
19 That gives me some real concern. Are you 20 looking at that as part of the restart evaluation and 21 the safety culture? I mean, are you looking back at 22 what was available, what transpired from meetings?
23 That is central to the issue of the culture of the 24 organization and how recoverable it is.
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113 1 memory the information that existed in the 2 organization. I think there is only one example of a 3 differing view, and that was the fact that the 4 Condition Report was initiated in the early nineties 5 to install these modifications in the service 6 structure. That modification was cancelled in the 7 early-mid-nineties; I think it was 1993 or 1994. It 8 was initiated again during the next outage. So that 9 would be an indication in my mind of a differing view 10 on the part of the system engineers responsible for 11 the head inspection.
12 My appreciation of what was going on in 13 the organization is that the knowledge of head, of the 14 materials on the head throughout the mid- and late 15 nineties was very limited to a few people. The 16 Operations organization was clearly not aware of the 17 corrosion that was observed in the 2000 outage, 18 running out of the mouse holes and pooling around the 19 head studs.
20 Clearly, the system engineer and some rad 21 protection people were well aware of it, but there did 22 not seem to be a broad awareness of that level of 23 corrosion products on the head. So I am not sure it 24 is a matter so much of a lack of differing views or 25 suppressed differing views as it is a lack of NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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114 1 knowledge.
2 VICE CHAIRMAN BONACA: I was referring 3 mostly about the filter cloggings. Those were daily 4 events almost taking place. I mean, didn't somebody 5 scratch their head and say, "What's going on? Why are 6 we overriding these indications?"
7 MR. HOWELL: Well, they knew they had a 8 leak. They just didn't know the source, and some had 9 convinced themselves that there was two or three 10 different leak sources over a period of about two or 11 three years, including the flanges and also the 12 pressurizer spray valve tailpipe that had been 13 disconnected from the quench tank.
14 MR. GROBE: There was a substantial action 15 plan developed to get to the bottom of the leakage.
16 There was not a belief that it was coming from the 17 head. There is a violation in the AIT follow-up 18 report for failure to implement corrective actions.
19 The final stage of that was a 20 comprehensive at-temperature and pressure inspection 21 of the reactor coolant system pressure boundary at the 22 beginning of the next refuel outage. That was not 23 accomplished. That corrective action was cancelled.
24 But I believe that at the time that they 25 were dealing, as Art indicated, with the symptoms, and NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N W.
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115 1 not identifying the root issue, there was a 2 significant cultural problem at the station that was 3 focused on production and cost savings over getting to 4 the bottom of these types of issues. It was because 5 they didn't believe there was a safety issue, a 6 significant safety issue.
7 MEMBER FORD: Art, would you like to 8 finish up?
9 MR. HOWELL: That is really all I had.
10 MEMBER FORD: Any concluding remarks? No?
11 MEMBER WALLIS: Just, Mr. Chairman, before 12 we go to the break, I would like to assure the next 13 presenters that they will be given the time allotted.
14 CHAIRMAN APOSTOLAKIS: Yes.
15 MEMBER FORD: Art, Jack, thank you very 16 much, indeed.
17 MR. GROBE: Thank you.
18 CHAIRMAN APOSTOLAKIS: Thank you, 19 gentlemen.
20 We will recess until -- what?
21 DR. LARKINS: I was just going to say, 22 George, before you recess, we want to let everybody 23 know that, due to conditions beyond my control, the 24 Christmas party will be deferred until tomorrow.
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116 1 over the weather? For heaven's sake, Executive 2 Director.
3 (Laughter.)
4 Okay, so we will recess until five minutes 5 after 11:00.
6 (Whereupon, the foregoing matter went off 7 the record at 10:46 a.m. and went back on the record 8 at 11:07 a.m.)
9 CHAIRMAN APOSTOLAKIS: The next item is 10 Framatome S-RELAP5 Realistic Large-Break LOCA Code.
11 Professor Wallis, it's yours.
12 MEMBER WALLIS: I think the Committee 13 knows perfectly well what this is all about and you've 14 gotten some previous information. I don't think you 15 need any further introduction. We are a bit behind 16 schedule. Let's go right to it.
17 MR. O'DELL: Good morning. I'm Larry 18 O'Dell with Framatome. I am the Project Leader at 19 Framatome for the development of the realistic large 20 break LOCA methodology.
21 I wanted to quickly go through today, and 22 I will try, since this is behind, to move along fairly 23 quickly through some of these first slides, but my 24 objective is to give you an overview of the complete 25 methodology, demonstrating how we conform to the CSAU NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N W.
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117 1 approach in the development of that methodology, and 2 then to show some selected examples with respect to 3 what analysis we did and how those analyses actually 4 compare to the data we were comparing it to.
5 But I have laid out my presentation along 6 the same lines as the CSAU, which is consistent with 7 the way it was reviewed in the SE. I will go through 8 the requirements and capabilities, CSAU Element 1, 9 Steps 1 through 6, and I will go through these fairly 10 rapidly and my couple of a slides; go ahead and go 11 through the assessment and ranging of parameters, CSAU 12 Element 2, Steps 7 through 10; go through some 13 sensitivity and uncertainty analysis, CSAU Element 3, 14 and that's Steps 11 through 14.
15 On these I will move through these two 16 fairly quickly, if it will stay on the machine there.
17 The first one, CSAU Element 1, there's six 18 steps, as I indicated.
19 Step 1 is to specify the scenario. We 20 have obviously specified the large-break LOCA 21 scenario.
22 Step 2, select the plant types. We've 23 selected the Westinghouse 3 four-loop and CE 2x2 24 plants.
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118 1 identification and ranking, the PIRT. We've developed 2 that. The process we used was to start with basically 3 the compendium, the peer reviews on that, come up with 4 our own revisions to the compendium, PIRT, and 5 finalize that PIRT, and it is presented in our 6 documentation.
7 The next step, CSAU Step 4, is to identify 8 selected versions of the Code. We identified and used 9 the RODEX3 Code, which is our own internal fuel rod 10 code, to describe our fuel, and the S-RELAP5 Code. I 11 should also mention that within the S-RELAP5 Code we 12 have incorporated the ICECON Code, so we have a direct 13 relation between the systems calculation and the 14 containment back pressure.
15 MEMBER WALLIS: Now you say it is a frozen 16 code? That means that -- how far is it frozen? I 17 think that you actually did do comparisons with data 18 which led you to find some biases in the code, which 19 you then corrected for?
20 MR. O'DELL: Right.
21 MEMBER WALLIS: So it is not frozen in the 22 sense that you aren't allowed to correct for bias, but 23 it is frozen in terms of the rest of the structure?
24 MR. O'DELL: Correct.
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119 1 coefficients in it or something to correct for bias?
2 MR. O'DELL: Right. When we went through 3 and did a lot of the sensitivity and calculations, we 4 had to implement a number of biases in the code in 5 order to perform those sensitivity analyses, and we 6 ended up with a version of code which had those 7 multipliers in the code.
8 Okay, the next step, CSAU Step 5, has to 9 do with the development of the documentation. We 10 develop models, correlations, programmers, and input 11 manuals for all of the codes used.
12 The next step was determine code 13 applicability. We went through the applicability 14 step, demonstrated that the code was applicable to the 15 selected scenario, large-break LOCA, and the various 16 plant types that we had selected.
17 Now moving to CSAU Element 2, the first 18 step of that is CSAU Step 7, which is to identify 19 assessment matrix for the analysis. We identified 15 20 separate effect test facilities that we used, and we 21 evaluated 130 tests within that set of facilities. We 22 also identified two integral test facilities, and we 23 evaluated six tests within that facility.
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120 1 nodalization, initial nodalization, based on our own 2 experience in applying the code. Then we performed a 3 series of plant studies, modified that nodalization, 4 then had a peer review where we sat down and presented 5 the nodalization we had come up with. As a result of 6 that, we went off and did additional plant model 7 studies where we finally came up with a final plant 8 model that we used in the assessment evaluations.
9 MEMBER WALLIS: You did sensitivity 10 studies of the nodalization?
11 MR. O'DELL: Yes. We looked at a series 12 of nodalization studies in the core, the downcomer, 13 upper head, and upper plenum area, and lower plenum 14 area. So we did a fairly extensive set of 15 nodalization studies.
16 MEMBER WALLIS: And these sensitivity -
17 what do these show?
18 MR. O'DELL: Well, with relationship to 19 the downcomer, it showed that there was a tradeoff 20 there between basically code run time and matching the 21 data. Going with a simpler nodalization improved the 22 code run, obviously, and gave slightly conservative or 23 somewhat conservative answers. We went with that 24 nodalization.
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121 1 plenum. The core we found, looking at 10, 20, and 40 2 nodes, axial nodes, within the core region, that 20 3 was basically adequate. We selected a 20.
4 MEMBER WALLIS: You mentioned a tradeoff 5 with run time. Were you restricted on the kinds of 6 computers you could use by law?
7 MR. O'DELL: Well, we're restricted on a 8 number -- on the qualification of the code on a 9 computer, okay? Obviously, if we moved the code to 10 another computer system, then we have to go through a 11 complete new qualification of that, too.
12 MEMBER WALLIS: But this means you were 13 restricted from using what might be much more rapid -
14 MR. O'DELL: Yes.
15 MEMBER WALLIS: -- and capable computers 16 because of something in the regulations?
17 MR. O'DELL: Right. Again, the computers 18 are evolving so rapidly that, you know, we started 19 this in 1997 and basically froze the code versions.
20 To move it to another version, rerun all the analysis 21 and everything, would have been a fairly major 22 undertaking.
23 MEMBER WALLIS: So these computers weren't 24 as out-of-date as they might have been if you had 25 frozen it earlier?
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122 1 MR. O'DELL: Exactly.
2 (Laughter.)
3 MEMBER SHACK: But that means you are 4 stuck with 1997-vintage computers then? Is that the 5 statement?
6 MR. O'DELL: Unless we move the codes and 7 then qualify them by Appendix B to the new set of 8 computer systems, yes.
9 MEMBER WALLIS: Was this 1997-vintage 10 computers or was this the qualification? So it is 11 actually an older vintage than 1997?
12 MR. O'DELL: No, it is actually somewhat 13 newer than 1997. We started in 1997. We did a lot of 14 preliminary work then and actually froze the codes in 15 about the 1999 timeframe.
16 MEMBER WALLIS: I think in the 17 Subcommittee meeting, when there was some mention of 18 some codes being restricted to run on VAXes, that 19 seemed somewhat preposterous. That didn't apply to 20 you though?
21 MR. O'DELL: No, that doesn't apply to us.
22 We're running on HP workstations; Hewlett-Packard 23 workstations we're running on. We would like to be 24 able to run on a Linux-Dell cluster.
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123 1 we ended up with 2D components for the downcomer core 2 and upper plenum, which we found was necessary to 3 catch phenomenon.
4 The next step was code and experimental 5 accuracy calculations that we did. In this, what we 6 did is we went through and determined the code model 7 biases and uncertainties by comparing them to various 8 separate effect tests and experiments.
9 We started off looking at 23 phenomena 10 from the PIRT. This was everything ranked five or 11 higher in the PIRT. Based on sensitivity studies that 12 we did on that, we ended up with 13 phenomena that we 13 were treating statistically, and 10 of the phenomena 14 that we found were either unimportant, actually 15 unimportant in the LOCA calculation, or modeled 16 conservatively.
17 We then went through a step to confirm 18 those biases and uncertainties by going through on 19 independent sets of data on the separate effects test 20 and integral tests where we applied the biases and 21 uncertainties and looked at the effects of those on 22 this independent dataset. The purpose here was 23 basically to validate the biases and uncertainties 24 that we detect.
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124 1 tests. This was the highest-powered LOFT LOCA test, 2 which is LOFT out the LP-LB-1. What is shown here is 3 the data, showing the range on the data with the 4 uncertainties in the data.
5 The solid line is the calculation we did 6 where we had removed none of the biases from the 7 computer code models. We then went in and applied the 8 biases we had determined from the other separate 9 effects test, not the uncertainties, just the biases.
10 What it did is it moved the calculation 11 down to better agreement with the data pretty much 12 across the whole axial range. Now this demonstrated 13 to us that the biases at least were behaving in an 14 expected fashion.
15 MEMBER POWERS: Is this the peak clad 16 temperature that you are applying here?
17 MR. O'DELL: Right, this is the peak 18 cladding temperature at any axial location at any time 19 during the -
20 MEMBER POWERS: So it is not a temperature 21 of a particular place in the core?
22 MR. O'DELL: Right.
23 MEMBER POWERS: It is just whatever is the 24 highest at that particular place?
25 MR. O'DELL: That point, yes.
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125 1 MEMBER POWERS: Do you have a similar plot 2 of the temperatures at a particular place?
3 MR. O'DELL: Right, that is the next 4 slide. We went through, and what we did here is, 5 again looking at the biases and uncertainties, here 6 what we did is we went through and we applied the 7 biases and the uncertainties where we could identify 8 them for the LOFT experiment.
9 What you see is the data at the PCT node.
10 This is the PCT node, again showing the variations 11 around the data.
12 The top calculation, of the 59 13 calculations we did for the statistical analysis, that 14 was the run that had the highest PCT in it. The other 15 one is the one that had the lowest PCT in it.
16 So that is how we picked through the 17 comparisons. If you plot all 59 of them on here, you 18 can't see anything.
19 There were ranges of the calculations 20 which agreed very well with that temperature plot, but 21 these obviously haven't quenched yet. That is because 22 in our model we do have a conservative T-min model 23 which restricts the quench time. So we tend to quench 24 later than the -
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126 1 if this is supposed to be a realistic code? It would 2 seem to me you ought to be realistic about the 3 quenching, too.
4 MR. O'DELL: I would agree with that. We 5 went through a set of analysis based on a series of 6 data, and we came up with a conservative treatment for 7 a T-min value. That was based on basically stainless 8 steel, electrode heater-type rods. That is known to 9 be conservative relative to the other data. At the 10 time we didn't really have other data that we thought 11 we could use to do that.
12 You want to be realistic, but being 13 realistic means that I have to begin with uncertainty, 14 which means I have to have a sufficient amount of data 15 to do that. If I don't have sufficient amount of data 16 to do it, then I end up taking a somewhat more 17 bounding approach to it.
18 MEMBER WALLIS: Well, I guess you claim, 19 then, you don't really care what happens because the 20 PCT is long over, and PCT is the criterion. So it 21 doesn't matter too much to get it right after, say, 70 22 seconds or do you have to get it right between 10 and 23 50 seconds?
24 MEMBER POWERS: But isn't there an eight 25 second criteria concerning hydrogen production? And NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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127 1 if I predict the cooling is slow, then I don't have 2 any possibility of predicting thermal shock to the 3 oxide that is on the cladding? And if I don't 4 thermally shock the oxide on the cladding in my 5 calculations but do in reality, won't I underestimate 6 the hydrogen production?
7 MR. O'DELL: I would think you 8 overestimate the hydrogen production because I am 9 spending more time at higher temperatures. So I am 10 generating more -
11 MEMBER POWERS: If I shock my clad oxide 12 and spall it off?
13 MR. O'DELL: Well, eventually, though, I 14 will quench out here, will quench when the 15 temperatures get down into the 10 criteria. When it 16 does quench, then I get the same thermal-shocking-type 17 effect, but I have spent more time at temperature. So 18 I will have more oxide.
19 MEMBER POWERS: Since the oxide grows as 20 a square root of T, I would think that shock spall and 21 reoxidize would give you a lot more oxide.
22 MEMBER KRESS: But wouldn't that require 23 a different oxidation model than they have in the 24 code?
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128 1 is realistic, yes.
2 MEMBER KRESS: Well, I think, what do you 3 have, Cathcart-Pawel?
4 MR. O'DELL: Cathcart-Pawel is what we are 5 using.
6 MEMBER KRESS: And it probably doesn't 7 include -
8 MEMBER POWERS: Assuredly, it does not.
9 MEMBER WALLIS: It doesn't include oxide 10 spalling, does it?
11 MR. O'DELL: No.
12 MEMBER WALLIS: So I think Dr. Powers has 13 pointed out there is some physical phenomena here 14 which really do affect what happens which are not 15 modeled in the code.
16 MEMBER KRESS: And the only way you 17 uncover that is by experiment, I think.
18 MEMBER WALLIS: Which do affect one of the 19 criteria rather than just what happens, and the degree 20 of hydrogen production, the degree of oxidation is one 21 of the evaluation criteria. If it is affected by the 22 spalling of this layer, then here's a physical 23 phenomenon which is not presently modeled in the code, 24 which affects one of the evaluation criteria.
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129 1 benign thermal shock to me in the test data. I'm not 2 so sure that would spall an oxide layer on a clad.
3 MEMBER WALLIS: Maybe we will ask the 4 staff what they conclude from this.
5 MEMBER KRESS: I don't know what the 6 thermal shock is. All I have done is temperature 7 versus time. I don't know what that means in delta T 8 across the clad oxide layer, but -
9 MEMBER POWERS: I don't either, but I 10 guess from previous presentations I am not willing to 11 simply say, well, that is reasonable.
12 MEMBER KRESS: No, it is certainly part of 13 a potential possibility, I think, yes.
14 MR. O'DELL: This was something that 15 wasn't identified in the PIRT process, I mean the 16 process that we went through.
17 MEMBER WALLIS: You should put Dr. Powers 18 on your PIRT team.
19 MEMBER KRESS: Where you would see that 20 would be in comparison in the hydrogen generated with 21 what you calculate, I think would be one way to look 22 at it.
23 MEMBER SHACK: Is that a thermal hydraulic 24 problem or is that a cladding problem?
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130 1 thermal hydraulics because we have put in -- thermal 2 hydraulic codes include the heat-generating sources.
3 Part of that is the oxidation.
4 MEMBER RANSOM: Has that phenomenon ever 5 been observed in any of the experiments with fuel 6 where you get spalling of the oxide when you place the 7 fuel and increase hydrogen production?
8 MEMBER POWERS: The problem is that I 9 don't know that we have done any experiments with 10 fuels that have experienced the levels of burnup that 11 we are now taking fuels to.
12 MEMBER KRESS: It has certainly been 13 observed with some of the air experiments, some of the 14 air oxidation experiments.
15 MEMBER POWERS: Oh, yes, but then you are 16 talking about some serious oxidation there. It is 17 really a question of what happens if you get up close 18 to this 17 percent limit. If you are going to have a 19 thin oxide that is basically epitaxial, it doesn't 20 shock. But if you get up close to your 17 percent 21 limit-, then I think you would have at least some 22 potential of shocking the oxide.
23 MEMBER KRESS: That is a pretty thick 24 layer, isn't it?
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131 1 100-micron layer, but then we have seen fuels taken 2 to, re-Zircaloy clads taken to 50- and 60-gigawatt 3 days per ton that will start off with oxides that are 4 pretty thick.
5 I mean the one thing you know is that 6 unstabilized Zirconia is one of the shockier ceramics.
7 Now there is a figure of merit that you can use for 8 looking at thermal shock. Kendurgy has published it.
9 He developed that based on Zirconia. So it is 10 probably a pretty decent one to use, though it is not 11 exactly for this geometry. But it might be fun to go 12 through and see what kind of delta T Tom was talking 13 about would require to shock it and see if you were 14 getting anything close to that.
15 MEMBER WALLIS: Well, Dana, I think later 16 on Framatome is going to argue that the degree of 17 oxidation is actually very low, so they don't have 18 much of a layer, nowhere near 17 percent.
19 MEMBER POWERS: Well, it depends on how -
20 I mean, if you burn the fuel up, you start off with an 21 oxide.
22 MEMBER WALLIS: I don't know that that's 23 actually considered in these codes at all really, 24 initial oxide layer.
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132 1 calculation of the transient-induced oxidation. I 2 think we do look at the time in cycle statistically as 3 you are going through it. So we do look at various 4 fuel, but in general the highly-burnt fuel is 5 operating more out on the periphery of these cores, 6 and, consequently, are at very low powers. So they 7 are not -
8 MEMBER POWERS: I guess I am a little bit 9 of a victim of the preceding presentation that told me 10 not to accept plausibility arguments. I would really 11 rather see someone address the issue if we are going 12 to do something that's called realistic.
13 MEMBER RANSOM: Larry, one other question.
14 Is the reason that you did not quenchen those runs the 15 fact that you have used a conservatively low T-min?
16 MR. O'DELL: Yes, that is why we haven't.
17 It hasn't got down to the quench temperature yet. We 18 selected it, you know, the timeframe over which we 19 were running the 59 cases, to basically bound when the 20 experimental data got to quench. As I indicated, 21 there's a number of these runs, the 59 we made, that 22 reached quench and quenched reasonably close to the 23 actual data's time.
24 But we are bearing a lot of things here 25 with the heat transfer effects and this type of thing.
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133 1 MEMBER KRESS: Dana, if you ran this 2 calculation with the Baker-Just model, would that 3 bound the issue you are dealing with? I thought the 4 Baker-Just was looking at fresh Zircaloy, so it didn't 5 have much of an oxide layer on it.
6 MEMBER POWERS: Yes.
7 MEMBER KRESS: That might be one way to 8 bound it, bound it by calculation.
9 MEMBER POWERS: Yes, but, I mean, that's 10 kind of -
11 MEMBER WALLIS: Well, maybe we can 12 identify someone in the staff or the research part of 13 the NRC who knows the answers to your question.
14 MEMBER POWERS: There has been some French 15 work -- I will have to admit I can't even understand 16 the paper, let alone say what it does -- looking at 17 the issue of when you can fracture of these oxides off 18 the cladding, but I'm just not familiar with it.
19 But, as you go from using Baker-Just-type 20 kinetics, the more realistic kinetics and thermal 21 hydraulics, I mean it seems to me you have to 22 recognize the phenomena that you were deliberately 23 skirting when we decided to go with Baker-Just 24 kinetics.
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134 1 out, it is a clean fuel. So if you spall off the 2 oxide layer, doesn't it just become clean again, and 3 it goes back to what you would get if you assumed it 4 was coming from the start?
5 MEMBER POWERS: Well, if you are using 6 Baker-Just kinetics, it is not quite as -- I mean, 7 quite frankly, those are the complexities that people 8 would be saying, okay, well, we'll just use this 9 demonstrably conservative kinetics and maybe that will 10 cover it up.
11 Don't you have to look at those kinds of 12 -- I mean I don't know. I just don't know.
13 MR. O'DELL: Yes, I think when I get a 14 little further along in the presentation, as Dr.
15 Wallis indicated, I will show you basically what we 16 were predicting for at least the three-loop sample 17 problem in the way of oxidation. We are significantly 18 away from the 17 percent limit.
19 I don't really believe that -- I think you 20 will hit the 2200-degree F limit a long time before 21 you hit the oxidation limits in these calculations, 22 based on the Appendix K analysis that we have done for 23 years -
24 MEMBER WALLIS: So could we move on and 25 maybe we will get back to that one?
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135 1 MR. O'DELL: Sure.
2 MEMBER SHACK: Can I just ask a quick 3 question?
4 MEMBER WALLIS: Okay.
5 MEMBER SHACK: On the previous slide, you 6 said something, 23 phenomena valuated, 13 treated 7 statistically, 10 found. What do you mean 8 statistically? You actually found biases and 9 uncertainties in a statistical sense for those?
10 MR. O'DELL: Yes.
11 MEMBER SHACK: Then 10 phenomena were 12 either unimportant, you didn't care whether you 13 modeled those well -
14 MR. O'DELL: Right. Basically, what we 15 showed there -- and I will get to a slide on that, too 16 -- where we went through these sensitivity analyses 17 and then we looked at a very simple square root of the 18 sum of the squares type of an effect to see what kind 19 of estimate of what the effect would be, you find that 20 by the time you get down to about 50 degrees, it is 21 only a couple of degrees in PCT as far as the impact 22 goes.
23 MEMBER POWERS: Let's see, you make 24 assumptions that these statistical variations are 25 additive independent? Do you have to assume Gaussian?
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136 1 MR. O'DELL: With respect to 2 distributions, we use a series of distributions. We 3 use uniform distributions. In some cases if we can 4 demonstrate that is normal, we do that. If it is with 5 respect to the plant parameters, we usually try to go 6 get plant data as to actually how they operate and 7 then weight those distributions based on how the 8 actual plant operates.
9 MEMBER RANSOM: One more quick question, 10 Larry. On your T-min correlation on that previous 11 slide, where you showed the LOFT LP-LB-I data and you 12 showed your adjusted or with the biases in it, is that 13 including the T-min that you would use, then, for the 14 next series of calculations?
15 MR. O'DELL: Yes.
16 MEMBER RANSOM: So the T-min you are using 17 is your best estimate from the separate effects test 18 then?
19 MR. O'DELL: Yes, recognizing that -
20 MEMBER RANSOM: Or realistic?
21 MR. O'DELL: Yes, recognizing that it is 22 conservative because of its stainless steel electrode 23 heater.
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137 1 is the scalability of the tests, and the other is the 2 scalability of the code models.
3 We went through and basically demonstrated 4 that the tests were scalable and that the code was 5 scalable. For the cases where it wasn't scalable, we 6 used -- it was really the downcomer-type areas, we 7 used the full-scale UPTF test to validate the code on 8 those.
9 MEMBER WALLIS: Now the nodalization is 10 also tested in the scalability?
11 MR. O'DELL: Yes. We have consistently 12 developed the model for the plant and then applied it 13 to the assessments.
14 MEMBER WALLIS: Because when you scale up, 15 this is a balance of phenomena that changes a bit.
16 The min-noding doesn't always catch the same balance 17 of phenomena if you fix the noding geometrically, but 18 as long as you do some sensitivity tests, you probably 19 will pick that up.
20 MR. O'DELL: Right, and I think that was 21 part of the thing we were looking for when we did the 22 analysis for Semiscale LOFT and CCTF. We looked at a 23 range of scales there, and we demonstrated that the 24 biases and uncertainties that we generated matched 25 this additional data. That data was not the same as NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE, N W.
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138 1 used to drive the biases and uncertainties.
2 MEMBER RANSOM: Larry, in the nodalization 3 studies you did, did they show substantial 4 convergence, and that as you reduced -- or increased 5 the fineness of the nodalization, show a tendency to 6 converge to a fixed answer?
7 MR. O'DELL: I would say, in general, yes.
8 I mean, when we went to the nodalization of the core, 9 we went 10, 20, and 40.
10 MEMBER RANSOM: Right.
11 MR. O'DELL: We also looked at it on some 12 of the FLECHT SEASET tests with that same type of 13 nodalization approach. Basically, we didn't see much 14 difference in the result for any of those three nodes 15 as such.
16 So what we decided to do was go with the 17 20, which allowed us to match up uniquely with the 18 spacer locations in the core and also would support 19 the matching up with the intermediate flow mixes that 20 some of the fuel designs had.
21 Moving now to the final CSAU element, 22 that's Element 3, the next step, CSAU Step 11 is to go 23 through and develop reactor input parameters and state 24 list. We went through the tech. specs. and FSARs to 25 develop that list. In the reactor we had a customer NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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139 1 working with us through that part of the process, so 2 that they helped us identify that parameter list.
3 Step 12 is to do a series of sensitivity 4 studies. We ran over 250 different sensitivity 5 studies where we looked at plant parameters and 6 phenomena-ranked five or higher, as I previously 7 indicated. The results tended to confirm the PIRT 8 rankings and defined the important PIRT parameter or 9 plant parameters, and the plant parameters which we 10 found to impact the PCT we then included in this 11 statistical analysis.
12 MEMBER WALLIS: I want to go back to this 13 noding business, the question about whether or not or 14 how noding scales and how you evaluate whether noding 15 scales. I am trying to get it clear just what you 16 did.
17 Usually, I think CSAU advises that you fix 18 the noding, that you do some noding and you experiment 19 with all kinds of noding until you can level the 20 scaled tests and everything, and then you fix that 21 noding when you go to the real -
22 'MR. O'DELL: Correct.
23 MEMBER WALLIS: And this would prevent you 24 from picking up differences which were scale 25 dependent. If it turned out that, because of the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE, N W.
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140 1 phenomena, the balance of the phenomena at full scale 2 is somewhat different physically, the noding doesn't 3 capture that, you could test this by doing, 4 presumably, noding experiments at subscale and at full 5 scale and comparing the results of the noding tests of 6 the two scales.
7 Did you go that far?
8 MR. O'DELL: No. Okay, basically, what we 9 did is we did all of our nodalization studies on the 10 plants, plant models, initial ones anyway. Then we 11 went through and looked at LOFT, Semiscale -- or not 12 the Semiscale -- LOFT CCTF, FLECHT SEASET tests, and 13 UPTF tests. We looked at those with the nodalization 14 that we got out of the plant studies.
15 MEMBER WALLIS: You fixed it now?
16 MR. O'DELL: Yes, it was a fixed 17 nodalization.
18 MEMBER WALLIS: So it is geometrically 19 fixed? If you have 10 nodes in the downcome, you 20 still have 10?
21 MR. O'DELL: Right, and that was how we 22 performed it.
23 MEMBER WALLIS: So it wasn't, then, what 24 I tried to indicate, maybe not very well, that the way 25 to try to evaluate whether the balance of the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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141 1 phenomena changes as you go to different scales by 2 changing the noding -
3 MR. O'DELL: No, we did not -
4 MEMBER WALLIS: They' re still arguing that 5 the node is bigger than the reactor even though it is 6 the same fraction of the height; therefore, the 7 bubbles take longer to traverse the node, and so on.
8 So something is changing in some of these.
9 MR. O'DELL: Right, but what we did 10 maintain, when we went through this -- for example, if 11 you look at the LOFT test, it is a shorter core. We 12 maintained the node size in that case. So if we would 13 normally have 20 nodes in the reactor core, then we 14 cut it down to maintain the six-inch node in the -
15 MEMBER WALLIS: Okay, so now you are 16 balancing the bubble thing, but you are not balancing 17 the geometrical similarity of the nodes anymore? It's 18 a tradeoff?
19 MR. O'DELL: There's a tradeoff, yes, and 20 we felt that, at least from our perspective, when we 21 were doing the nodalizations, we wanted to maintain 22 the node size.
23 MEMBER WALLIS: It is a bit difficult if 24 you have a node which is two feet long in the core and 25 you go to a really small experiment.
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142 1 (Laughter.)
2 MR. O'DELL: Basically, our guidelines 3 that we put together for developing that called for 4 approximately six-inch nodes to match up with space 5 and location and in an intermediate flow that existed.
6 MEMBER RANSOM: What do you mean by the 7 term scalability? Generally, we use that to indicate 8 similarity. There are geometric scales. There are 9 Reynolds number or Nusselt number scales. Similarity 10 would require that all of these non-dimensional 11 parameters be the same. So I am kind of wondering, 12 what you mean by similarity -- I mean scalability?
13 MR. O'DELL: Well, from the standpoint of 14 scalability, what we were meaning is that it is the 15 ability of the code to scale across the ranges of 16 tests and the ability of the tests to scale up -
17 MEMBER RANSOM: Do you mean to get good 18 agreement -
19 MR. O'DELL: Right.
20 MEMBER RANSOM: -- at different tests at 21 primarily, I guess, different geometric scales? Is 22 that right?
23 MR. O'DELL: Right.
24 MEMBER RANSOM: Length scales?
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143 1 found is that you really can't volume weight the 2 downcomer. Where they have done that in experiments, 3 they got poor results.
4 So what we did in that case is make sure 5 that we had UPTF tests in there which were basically 6 full-scale-type tests to demonstrate that the code was 7 behaving properly in the place they needed to behave 8 properly.
9 MEMBER WALLIS: So it probably means that 10 when you go to these realistic codes, you have to do 11 more of the sensitivity experimentation to satisfy 12 yourself that you're capturing different ways in which 13 the code could give uncertain answers.
14 MR. O'DELL: Right, and I think that is 15 part of going through the PIRT process and then the 16 development of the assessment matrix, is to try to 17 cover the issues of scalability.
18 MEMBER WALLIS: And if you ran on the most 19 up-to-date computers, it really wouldn't be very 20 difficult to change the nodes.
21 (Laughter.)
22 Most CFD codes, you just have a subroutine 23 that sets meshes and nodes, and you can just, with the 24 touch of a button, change the nodalization and run it 25 again.
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144 1 MR. O'DELL: Yes, we recently moved our 2 CFD code to a Linux cluster, and it went from like 3 eight hours to run a case to 55 minutes.
4 (Laughter.)
5 So there's a significant change there.
6 MEMBER POWERS: You need a bigger cluster.
7 MR. O'DELL: Pardon?
8 MEMBER POWERS: You need a bigger cluster.
9 (Laughter.)
10 MR. O'DELL: This is our first step.
11 MEMBER POWERS: You tend not to do that.
12 You tend to keep the run time still at 55 minutes; you 13 just increase the density of nodes in the thing.
14 MR. O'DELL: The problem is bigger.
15 (Laughter.)
16 MEMBER SHACK: But you're still running 17 the data hourly.
18 (Laughter.)
19 MR. O'DELL: This was, again, what I 20 alluded to earlier, where we have gone through and 21 just listed a series of the parameters. We looked at 22 the total of 44, 23 for the PIRT and 21 various plant 23 parameters.
24 What is shown here is basically the 25 sensitivity we got out of the study and then the total NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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145 1 tolerance, which is just the square root of the sum of 2 the squares and then the difference or the change in 3 that tolerance.
4 Again, this is just an approximation to 5 get a feeling for what's going on. As I indicated 6 earlier, as you get down to about 50 degrees, you are 7 within about a 3-degree effect on the PCT.
8 MEMBER WALLIS: Now these are all the 9 parameters that you could change or that you 10 considered to change?
11 MR. O'DELL: Right. Well, this is a 12 partial list. It actually goes on for about three 13 slides.
14 MEMBER WALLIS: I guess thinking about our 15 discussion last month, core interface friction is one 16 of the terms, affects one of the terms in this 17 momentum balance that we talked about for some hours.
18 There are other terms in that momentum balance which 19 are also uncertain. You don't have any multipliers on 20 them.
21 So one thing which one could recommend is 22 that this list isn't as complete as it might be, 23 doesn't sort of encompass perhaps all the things you 24 are uncertain about, and it might be worth introducing 25 some other ones as they are identified.
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146 1 MR. O'DELL: Yes, the list that we put 2 together followed, again, the CSAU approach, which was 3 to go through the PIRT process, and the PIRT process 4 identifies the phenomena. Then we tried to go 5 through, based on that, and come up with our 6 sensitivity -
7 MEMBER WALLIS: The thing is, if no expert 8 has ever tried to put these multipliers on a term and 9 see their effect, they don't have much basis for 10 deciding whether or not they matter.
11 MR. O'DELL: A good point.
12 MEMBER SHACK: When you range the values 13 over the range, you get a change of 181 degrees? Is 14 that what this is telling me?
15 MR. O'DELL: Right. That is basically -
16 what we did is take an up-skewed and a bottom-skewed 17 axial shape, and the variation we got on that kind of 18 variate calculation was 181 degrees. We went through 19 and were doing the same sort of things. Like on Fq, 20 we said, where did the plant expect to operate 21 nominally with that Fq, and then what is the tech.
22 spec. limit? We looked at what the effect of Fq was.
23 So there's two things in here. One of 24 them is the sensitivity to that particular parameter, 25 but also coupled with that is what you assume the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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147 1 range is relative to those particular parameters.
2 MEMBER POWERS: And you've done these 3 things all one variation at a time?
4 MR. O'DELL: Yes.
5 MEMBER POWERS: Are there synergistic 6 effects of any significant magnitude?
7 MR. O'DELL: We didn't get into it in this 8 type of a study because we were planning on using the 9 non-parametric statistical approach where we vary all 10 the parameters at the same time. So any synergistic 11 effects get captured in the approach.
12 MEMBER POWERS: Sure.
13 MEMBER RANSOM: But these are generated 14 one at a time?
15 MR. O'DELL: Yes.
16 MEMBER RANSOM: You use the multipliers or 17 some variation on the particular parameter, like 18 single or interface drag, and then those are the 19 effect on the P-clad temperatures, I guess, right?
20 MR. O'DELL: Yes. Yes, throughout we used 21 the P-clad temperature as really the governing 22 decision parameter.
23 Okay, the next step, CSAU Step 13, is to 24 use the uncertainties developed from the assessment as 25 input for the analysis. Here, as I just indicated, we NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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148 1 differed here from the CSAU. They used a response 2 surface technique that limits the number of parameters 3 that one can use. So, instead, we have used non 4 parametric statistics.
5 It propagates the uncertainties directly 6 using the code, allows the statistical treatment of a 7 large number of variables, provides a 95/95 PCT and 8 associated maximum nodal and total core oxidation. It 9 relies on the execution of 59 cases to determine the 10 95/95 limit.
11 Each case, as I indicated, is defined by 12 randomly varying each parameter within that case. So 13 if you look at -
14 MEMBER WALLIS: Including the break size?
15 MR. O'DELL: Including the break size, 16 yes.
17 If you look at just a schematic, basically 18 a list of parameters, and generate the 59 cases, under 19 Case 1 there would be Al, Bl, Cl; Case 2, B2. So you 20 are ranging there and directly propagating any co 21 dependence and just do the calculation.
22 Okay, with respect to CSAU Step 14 -
23 MEMBER POWERS: You treat all of your 24 parameters as being independent?
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149 1 developing the biases and uncertainties, yes.
2 MEMBER POWERS: I mean, I haven't gone 3 through and looked at them in detail, but is that a 4 reasonable thing to do?
5 MR. O'DELL: In looking at the analysis, 6 we didn't try to go through and see if there was some 7 interdependencies or separate out any 8 interdependencies. Obviously, when you get into like 9 the heat transfer coefficients, we couldn't separate 10 the individual heat transfer coefficients out because 11 we couldn't find sufficient data for it. So we did 12 the uncertainties on the total heat transfer 13 coefficients.
14 So you sort of get into that with the 15 compensating air question. There probably is some, 16 but the idea is to demonstrate that it is adequate 17 over the range that we are applying it.
18 MEMBER WALLIS: If I look at your list of 19 parameters, there's a very few that might be 20 interdependent, but one might say that a core 21 interface friction maybe is in some mechanistic model, 22 which also affects the heat transfer coefficient. So 23 the two are not completely independent perhaps then.
24 MR. O'DELL: Right.
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150 1 core power are very highly correlated.
2 MEMBER RANSOM: Probably like Rawl's 3 analogy says that friction and heat transfer are 4 related. So they would be to a degree.
5 MR. O'DELL: Okay, and the final step of 6 the CSAU approach is Step 14. That is to provide a 7 total uncertainty for the analysis. We provided two 8 sample problems, the four-loop and the three-loop 9 sample problem.
10 For the four-loop sample problem, the 11 limiting case was Case 22 out of the 59 we ran. For 12 95/95 PCT, it was 1686 degrees F. The maximum level 13 of oxidation, .8 percent. The maximum core oxidation, 14 .02 percent, and we reported the 50/50 PCT out of this 15 as just a comparison. The 1375 to 1686 would be about 16 a 300-degree difference.
17 The three-loop case, Case 41, was the 18 limiting case, PCT 18, 153 degrees F, 1.2 percent on 19 the maximum nodal oxidation, and the maximum core 20 oxidation, .04 percent. We had 1500 degrees F on the 21 50/50 PCT.
22 MEMBER POWERS: And these oxidations were 23 all incremented from what you started with to what you 24 had at the end of the calculation, right?
25 MR. O'DELL: Yes.
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151 1 The next slides show where we went through 2 and basically bend the 59 calculations for the three 3 loop sample problem, and a four-loop sample problem 4 gives you similar-type results. What this shows is 5 basically what the calculations gave us in the way of 6 PCTs, the limiting PCT being the one at 1853 out 7 there, shown in the 1850-to-1900 bin.
8 You can see from comparison to this that 9 the 2200 one, as we scaled, they were reasonably close 10 to that.
11 MEMBER WALLIS: And the peak at 900 is 12 probably due to some physics which says that you can't 13 get below a certain value, and certain things combine 14 to make it like a slight pileup of data down there.
15 MR. O'DELL: Well, there's that, and 16 there's also, you're seeing there's the effect of 17 modeling those split and guillotine breaks in here.
18 So some of these lower ones down here can fall out of 19 your spectrum.
20 Okay, the next slide shows, again, just a 21 comparison three-loop sample problem, the peak local 22 oxidation. Again, it's got a limit of 17 percent, and 23 we're significantly away from that at the 1853. We 24 also ran a series of calculations where we just 25 physically drove the power up until we got up to about NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE, N.W (202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross com
152 1 2200. We are in the 5 or 6 percent range compared to 2 the 17 percent range at that point in time.
3 So what you conclude from that is that we 4 probably aren't going to ever hit the oxidation limits 5 and not have already exceeded PCT limits.
6 MEMBER WALLIS: So you are invoking one of 7 those clauses in the regulations which says you don't 8 have to do a full statistical analysis which meets 95 9 percent certainty on all three of these criteria.
10 MR. O'DELL: Exactly, yes.
11 MEMBER WALLIS: So that if you can show 12 that PCT by itself is such a dominating criteria, all 13 the others are then going to be met with I think it's 14 high probability or some term like that.
15 MR. O'DELL: Right.
16 MEMBER WALLIS: It's so vague in the 17 regulations.
18 MR. O'DELL: Right.
19 MEMBER WALLIS: Therefore, you're okay.
20 You just need to focus on PCT. Everything else will 21 be okay?
22 MR. O'DELL: Right, and we've gone through 23 a statistical analysis where we took this three-loop 24 sample problem that I am showing here, the results of 25 the four-loop sample problem, and the results of the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE, N.W.
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153 1 three-loop sample problem driven up to 2200, and we 2 have done a statistical evaluation of that. We will 3 be using that to justify -
4 MEMBER WALLIS: So for those who insist on 5 at least providing some probability, rather than a 6 plausibility argument, you could provide the number?
7 MR. O'DELL: Exactly.
8 MEMBER WALLIS: Now is that, let's see 9 now, I guess it is okay as long as things are sort of 10 well-behaved. If it turns out that local peak 11 oxidation, nothing much happens until you get up to 12 2000, and then all of a sudden it takes off, then you 13 would have some different conclusion perhaps.
14 MR. O'DELL: Well, and that's why we ran 15 the three-loop case up to 20 -- actually, we ran it 16 up; we approximated it kind of in the PCT we got out 17 of the 59 cases on there; it was actually around 2300.
18 MEMBER WALLIS: That is probably a wise 19 thing to do, is to see if there isn't some cliff that 20 you fall off -
21 MR. O'DELL: Right.
22 MEMBER WALLIS: -- with the other 23 variables.
24 MR. O'DELL: Exactly.
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154 1 a brief overview of the complete methodology. We have 2 demonstrated how we used the CSAU methodology elements 3 and steps. I believe we have demonstrated and proved 4 statistically treatment through the use of the non 5 parametric statistics which allow us to treat a large 6 number of parameters, and we didn't end up having to 7 determine some delta penalties.
8 We used the SET experiments that we had to 9 remove the biases actually from the code models and to 10 determine the uncertainties. Then we evaluated those 11 biases and uncertainties on a separate database to 12 determine that they, in fact, scaled across the -
13 they were going to be fine.
14 MEMBER POWERS: Let me be clear on your 15 non-parametric statistics. You did that just 16 conventional Monte Carlo? You didn't do a Latin, 17 limited Latin Hypercube sampling?
18 MR. O'DELL: No, we didn't do Hypercube 19 sampling.
20 MEMBER POWERS: Just a straight Mon te 21 Carlo? Good man.
22 (Laughter.)
23 MEMBER WALLIS: Is Jim Mallay going to 24 make a statement now?
25 MR. O'DELL: Yes, I think Jim has a -
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155 1 MEMBER WALLIS: Any more questions for Mr.
2 O'Dell?
3 (No response.)
4 Thank you very much, Larry.
5 MR. MALLAY: Thanks, Larry.
6 I just wanted to make a couple of 7 statements here. First of all, I wanted to 8 acknowledge the participation of Carolina Power and 9 Light, now known as Progress Energy. They have 10 participated with us through this entire process, the 11 development of the methodology, doing some of the peer 12 reviews, and they have been very supportive.
13 Obviously, they have an objective here because we have 14 a contractual commitment to use the realistic LOCA for 15 their plants, but I think it is significant that this 16 utility has taken considerable part.
17 The second thing I wanted to acknowledge 18 is we have here with us today Darren Gale, who was 19 brave enough to come in through the storm this 20 morning. He's our Vice President of Fuels Engineering 21 and Sales. Therefore, he is going to be a primary 22 user of this methodology.
23 The other remark I wanted to make is about 24 our documentation. I want to take just a minute to go 25 through some of the background here.
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156 1 During the last few discussions we have 2 had with the ACRS Subcommittee on Thermal Hydraulic 3 Phenomena, the Subcommittee has encouraged us to 4 examine what I will call the nature of our 5 documentation.
6 Frankly, when this subject first came up 7 a couple of years ago, we were a bit puzzled as to why 8 they were making this remark fairly insistently, 9 because the feedback we had gotten consistently from 10 the NRC staff was that our documentation was 11 exceptionally technically clear and complete, and we 12 appreciate those comments.
13 However, at the last Subcommittee meeting, 14 which we held about three weeks ago on the 14th of 15 November, we arrived at a common understanding.
16 Although our documents might be clear to people who 17 understand the RELAP set of codes and how they are 18 applied in LOCA analysis, much of the terminology and 19 the approaches we used to apply the simplified forms 20 of very complex equations could be confusing and 21 mystifying to those who are schooled in thermal 22 hydraulics, but not this specific type of application.
23 Specifically, we were being asked by the 24 Subcommittee to speak to a reader who has expertise in 25 thermal hydraulic phenomena, but not necessarily the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N W.
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157 1 narrow application to the LOCA analyses. Therefore, 2 our documents, they felt, needed to lay a better 3 groundwork, if you will, for this specific methodology 4 and to help the reader understand how the model 5 relates to the physical layout of a PWR and how the 6 fundamental equations are made to successfully 7 simulate complex thermal hydraulic behavior, and 8 specifically how these models can be successful 9 through the adjustment of a few key parameters, some 10 of which Larry mentioned here this morning, and 11 specifically loss factors.
12 In any event, we at Framatome have 13 committed to reformat our theory manual, so that an 14 expert reader, albeit uninitiated in RELAP, can 15 understand what we have done. We have hesitated to 16 expand and reformat this document because it will be 17 seen only by a very limited audience. These 18 documents, as you can appreciate, are proprietary and, 19 therefore, can be read by only a few people, those who 20 need to understand the models, such as the regulator, 21 the NRC, and perhaps some of our customers, but we are 22 going to do that.
23 To give you another piece of background, 24 the NRC will be seeing our S-RELAPS model again. The 25 application you have in front of you is for PWRs of NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N W.
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158 1 the non-B&W design. We plan to expand the use of 2 S-RELAP5 to all of our thermal hydraulic analyses.
3 The next step is to apply the model to BWR non-LOCA 4 safety analysis, and the second step after that is we 5 plan to apply this model to BWR LOCA analyses.
6 In any event, we will revise the theory 7 manual well in advance of our next submittal of 8 S-RELAP5, and we plan to show it to the NRC staff to 9 gain its concurrence that the rewrite is a clear 10 exposition of the model. Our goal is to present the 11 equations actually used, including loss factors that 12 contribute so significantly to the success of the 13 model and how two-phased flows are handled, for 14 example.
15 We will explain the conversion of complex 16 geometries to a one-dimensional straight-line 17 approach, which is actually used in most of the RELAP 18 codes. Other similar changes will be made to help the 19 reader understand the implementation of the model. So 20 I just wanted to make that public, that we intend to 21 work with the staff in reformatting our documentation.
22 MEMBER WALLIS: You have put a certain 23 slant on this discussion that we had, and that was 24 that the theory is fine, and it is just that outside 25 experts don't understand what you did.
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159 1 MR. MALLAY: Correct.
2 MEMBER WALLIS: I think we have a slightly 3 different slant on it, that we are trying to figure 4 out if you understand what you did.
5 (Laughter.)
6 And if you understand the implications and 7 the uncertainties and possibly not perhaps errors but 8 causes of, well, the uncertainty we were just talking 9 about, the way in which you formulate these equations; 10 it is not just the way in which you tweak the 11 coefficients, but the way in which you formulate the 12 equations themselves leads to predictions which are 13 not as good as they might be. That needs to be 14 understood.
15 MR. MALLAY: Yes, that is certainly true.
16 We are neglecting a lot of things in the formulation 17 of the equation itself.
18 MEMBER WALLIS: Right, and I think the 19 code does have to -- the documentation does have to 20 stand on its own and be convincing. After all, you 21 are the experts, so you ought to be able to give the 22 impression that you really do understand what you are 23 doing.
24 MR. MALLAY: Right.
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160 1 across not just in the documentation, but also in the 2 presentations you make to the Subcommittee, or 3 whatever it is.
4 So I suggest that you go back and read the 5 transcript of our meeting and ask yourselves what kind 6 of impression you made in terms of convincing us that 7 you understood what you were doing, and that next time 8 the transcript reads somewhat differently.
9 MR. MALLAY: Uh-hum, I appreciate that.
10 Yes, in fact, Larry O'Dell and I had a conversation 11 just in the last couple of days about that situation.
12 I guess being the pure engineers that we are, maybe we 13 don't make as good of salesman as possibly we should 14 be.
15 MEMBER WALLIS: No, that is not an excuse 16 though. I mean, I am tired of hearing that, because 17 we are engineers, we can get away with stuff which you 18 wouldn't get away with otherwise. That sounds like, 19 because we are lawyers, we don't have to do some of 20 the things other people do or something. That is not 21 a good reason. Engineers have to do what's the right 22 thing for the purpose. It doesn't mean that we have 23 to be finicky, sort of academically perfect, and all 24 that, but it has to be good enough.
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161 1 this model.
2 MEMBER WALLIS: In fact, in some ways that 3 is a bigger challenge, to know it is good enough for 4 ensuring purposes, than to just stick to some kind of 5 scientific rigor. I mean, it is not always 6 appreciated by the public, but it is not an excuse, 7 just because it is engineering, that you can be vague.
8 In a way, you've got to be more rigorous -
9 MR. MALLAY: True.
10 MEMBER WALLIS: -- but in a different way.
11 MR. MALLAY: Uh-huh, right. Well, we are 12 very proud of the model, especially after we went 13 through these 139, or whatever it was, validation 14 cases.
15 MEMBER WALLIS: Yes, the statistical 16 treatment was very nice, yes. I guess our discussion, 17 the trouble we have with your documentation was with 18 other parts of it.
19 MR. MALLAY: Yes.
20 MEMBER WALLIS: And I've got one final 21 remark. I think you have been very lucky that you are 22 relying to a large extent on 30 years of experience 23 with the RELAP-type codes, which have evolved and have 24 been shown to be useful. Therefore, one could perhaps 25 say, well, why do we have to go back and re-examine NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N W.
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162 1 the roots of them? But I think you are lucky in that 2 way, that if you came in with a new code and said, 3 "This is the way we treat things. We don't have 30 4 years of experience, but whatever we did it seems to 5 work," you would be in much more trouble, I think.
6 MR. MALLAY: Uh-hum. Thank you. Again, 7 I appreciate the support of the Subcommittee and also 8 the time of the full Committee.
9 MEMBER RANSOM: I would like to offer one 10 comment that has to do with, I think some of these 11 questions could be answered easily by proper choice of 12 simple problems that you might run that demonstrate 13 the characteristics of not only the basic equations 14 you are using, but the final product, which is the 15 code. These would be things like variable area and 16 passage of Ts, where the momentum flux terms and their 17 treatment has been questioned.
18 In those cases I think it is a way of 19 showing that the code is or is not reasonable in 20 idealized problems. A manometer is another example, 21 as a matter of fact. You get the frequency correct 22 and the amplitude correct. These can go a long ways 23 towards proving not only the basic formulation, but 24 the numerics and the way it is implemented finally, 25 and nodalization, as a matter of fact, can be NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N W (202) 234-4433 WASHINGTON, D.C. 20005-3701 www nealrgross com
163 1 addressed in those kinds of problems, too.
2 I don't think that is an awful lot of 3 work. It may be some, but it is a way of showing in 4 fairly, idealized problems that you do get the correct 5 behavior or you don't.
6 MEMBER WALLIS: I think if I were a 7 manager, I would require that my engineers do this 8 with simple problems before they launched off and 9 solved reactor problems.
10 MR. MALLAY: Thank you.
11 MEMBER WALLIS: Thank you very much.
12 Are there any other points or questions 13 from the Committee? We seem to have caught up on time "14 maybe.
15 MEMBER SHACK: If you were to requalify 16 this on a different platform, do I run the 59 cases?
17 Is that what I run?
18 MR. O'DELL: This is Larry O'Dell with 19 Framatome.
20 No, you actually are, I think, requalified 21 on another platform. As a minimum, you would have to 22 convince yourself that what you have done for the 23 uncertainties and bias generation was correct. I 24 would say you would have to rerun those. You would 25 have to basically rerun at least a subset of all of NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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164 1 the assessments to show that the new platform or the 2 new compiler and what it had done with the code didn't 3 surprise you in some fashion.
4 Basically, running all those cases isn't 5 the real problem. The real problem is then I have to 6 document them all and I have to QA them all, so that 7 I've got an Appendix B-qualified trail as I moved.
8 MEMBER WALLIS: Any more questions for 9 Framatome?
10 (No response.)
11 We move ahead to a presentation by the 12 staff. I notice there is kind of a reversal of the 13 roles. Usually, industry comes in with beautiful 14 colored slides, and the staff comes in with something 15 more primitive, but here it seems to be the other way 16 around.
17 MR. LANDRY: The wonders of modern 18 technology.
19 MEMBER POWERS: They can run on clusters.
20 (Laughter.)
21 MR. LANDRY: Thank you, Dr. Wallis. My 22 name is Ralph Landry. I am the lead engineer on the 23 staff of the review of S-RELAP5.
24 This morning -- no, it is this afternoon 25 now -- this afternoon I would like to go over a little NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N W.
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165 1 bit of what the staff did and review the code and what 2 we have put into the SER, how we structured our SER.
3 What I thought I would do is very briefly 4 discuss a couple of the milestones in the review and 5 mention who the review team is and some of the review 6 results and our conclusions.
7 The team was five people: myself and 8 Sarah Colpo, Tony Attard, Yuri Orechwa on the staff, 9 and Lynn Ward at ISL Laboratories. The others aren't 10 here. They managed to get out of town and are all on 11 travel today.
12 (Laughter.)
13 Whether that is a good thing or not, it 14 remains to be seen because they are all in Canada.
15 (Laughter.)
16 They are all at the Chalk River, and it 17 was snowing at Chalk River in September.
18 (Laughter.)
19 MEMBER POWERS: It's a permanent state, I 20 think.
21 (Laughter.)
22 MR. LANDRY: That's like upper Minnesota; 23 they have 11 months of winter and 1 one month of bad 24 sledding.
25 (Laughter.)
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