ML122830433
| ML122830433 | |
| Person / Time | |
|---|---|
| Site: | Davis Besse  |
| Issue date: | 09/19/2012 |
| From: | Kent Howard Advisory Committee on Reactor Safeguards |
| To: | |
| References | |
| NRC-1898 | |
| Download: ML122830433 (289) | |
Text
Offic ia l Tra ns c ript of Proc e e dings NUCLEAR REGULATORY COMMISSION Title: Advisory Committee on Reactor Safeguards Plant License Renewal Subcommittee Docket Number: (n/a)
Location: Rockville, Maryland Date: Wednesday, September 19, 2012 Work Order No.: NRC-1898 Pages 1-211 NEAL R. GROSS AND CO., INC.
Court Reporters and Transcribers 1323 Rhode Island Avenue, N.W.
Washington, D.C. 20005 (202) 234-4433
1 1 UNITED STATES OF AMERICA 2 NUCLEAR REGULATORY COMMISSION 3 + + + + +
4 ADVISORY COMMITTEE ON REACTOR SAFEGUARDS 5 (ACRS) 6 + + + + +
7 PLANT LICENSE RENEWAL SUBCOMMITTEE 8 + + + + +
9 WEDNESDAY 10 SEPTEMBER 19, 2012 11 + + + + +
12 ROCKVILLE, MARYLAND 13 + + + + +
14 The Subcommittee met at the Nuclear 15 Regulatory Commission, Two White Flint North, Room 16 T2B1, 11545 Rockville Pike, at 8:30 a.m., John D.
17 Sieber, Chairman, presiding.
18 19 COMMITTEE MEMBERS:
20 JOHN D. SIEBER, Chairman 21 J. SAM ARMIJO 22 HAROLD B. RAY 23 WILLIAM J. SHACK 24 GORDON R. SKILLMAN 25 JOHN W. STETKAR NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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2 1
2 CONSULTANT TO THE SUBCOMMITTEE:
3 JOHN J. BARTON 4
5 NRC STAFF PRESENT:
6 KENT HOWARD, Designated Federal Official 7 BART FU 8 MELANIE GALLOWAY 9 BRIAN HARRIS 10 ALLEN HISER 11 BILL HOLSTON 12 BENNY JOSE 13 JOHN LUBINSKI 14 JEFF POEHLER 15 ANN MARIE STONE 16 17 18 ALSO PRESENT:
19 BARRY ALLEN 20 RICHARD BAIR 21 DENNIS BLAKELY 22 JOE BRUNKHORST 23 KEN BYRD 24 DAVID CHEW 25 CHONG CHIU NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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3 1 CLIFF CUSTER 2 ALVIN DAWSON 3 STEVE DORT 4 TRENT HENLINE 5 LARRY HINKLE 6 JAKE HOFELICH 7 JON HOOK 8 ERIC JOHNSON 9 DON KOSLOFF 10 ALLEN McALLISTER 11 MARK RINCKEL 12 FRANK ZURVALEC 13 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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4 1 T-A-B-L-E O-F C-O-N-T-E-N-T-S 2 Opening Remarks, Jack Sieber.......................5 3 Staff Introduction, John Lubinski..................7 4 FirstEnergy Nuclear Operating Company (FENOC) -
5 Davis-Besse Nuclear Power Station (Davis-Besse) 6 Introduction 7 Ken Byrd........................................10 8 Presentation 9 Cliff Custer....................................12 10 Ken Byrd........................................16 11 NRC Staff Presentation SER Overview 12 Introduction 13 John Lubinski..................................158 14 Presentation 15 Brian Harris...................................159 16 Benny Jose.....................................161 17 Ann Marie Stone................................166 18 Brian Harris...................................175 19 Bill Holston...................................189 20 Bryce Lehman...................................191 21 Adjournment......................................211 22 23 24 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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5 1 P-R-O-C-E-E-D-I-N-G-S 2 8:28 a.m.
3 CHAIRMAN SIEBER: Good morning. The 4 meeting will now come to order. This is a meeting of 5 the Davis-Besse Nuclear Power Station Plant License 6 Renewal Subcommittee.
7 My name is Jack Sieber and I'm Chairman of 8 the Davis-Besse Plant License Renewal Subcommittee.
9 ACRS members in attendance are Bill Shack, John Stetkar, 10 Sam Armijo, Harold Ray and Gordon Skillman. Also with 11 us today is John Barton, who is a consultant to the ACRS.
12 Kent Howard of the ACRS staff is the Designated Federal 13 Official for this meeting.
14 The Subcommittee today will review the 15 license renewal application for Davis-Besse Nuclear 16 Power Station and the associated staff Safety Evaluation 17 Report with open items. I note that the current draft 18 of the SER contains four open items which must be 19 satisfactorily resolved prior to the hearing of this 20 application by the full ACRS Committee which is 21 currently scheduled for next March. These open items 22 relate to containment, concrete cracking issues, use 23 of operating experience to update the tests and 24 examinations that the licensee will perform during the 25 renewal period, and reactor vessel integrity issues.
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6 1 Today's agenda contains time also to discuss these 2 issues.
3 We will hear presentations from FirstEnergy 4 Nuclear Operating Company representatives, the NRC 5 staff, and other interested persons regarding this 6 matter.
7 We have not received written comments and 8 requests for time to make oral statements from members 9 of the public regarding today's meeting.
10 The entire meeting will be open to public 11 attendance.
12 The Subcommittee will gather information, 13 analyze relevant issues and facts, and formulate 14 proposed positions and actions as appropriate for 15 deliberation by the full Committee.
16 The rules for participation in today's 17 meeting have been announced as part of the notice of 18 this meeting previously published in the Federal 19 Register.
20 A transcript of this meeting is being kept 21 and will be made available as stated in the Federal 22 Register notice, therefore, I request that participants 23 in this meeting use the microphones located throughout 24 the meeting room when addressing the Subcommittee. The 25 participants are requested to please identify NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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7 1 themselves and speak with sufficient clarity and volume 2 so that they may be readily heard.
3 We will now proceed with the meeting, and 4 I call upon John Lubinski of the NRC staff to begin the 5 presentation. John?
6 MR. LUBINSKI: Thank you, Jack. As 7 stated, I'm John Lubinski. I'm the director of the 8 Division of License Renewal. I started in this position 9 last Monday. I have been with NRC for 22 years and most 10 recently was the deputy division director of our 11 Division of Inspection and Regional Support at NRR.
12 As stated, this is our ACRS Subcommittee 13 meeting on Davis-Besse license renewal application.
14 When the application was received, we initially 15 established a 22-month schedule. That was to 16 accommodate the concurrent review of the license renewal 17 application with plant outages and the ability to 18 support on-site audits.
19 Since that time we have modified the 20 scheduled twice. The first item was in December of 2011 21 where the schedule was moved out two months. And this 22 was due to delay in responses to RAIs, as well as a large 23 number of follow-up items and RAIs. The second time 24 was in March of this year where the schedule was delayed 25 by another four months. And this was to resolve at that NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 1 time 11 open items.
2 Since that time we have reached resolution 3 on 7 of those 11 items, but there are 4 open items still 4 in the application and the SER that was provided on July 5 30th of 2012. As stated, those four items are: The 6 shield building cracking, which we did allow extra time 7 in today's meeting for discussion; operating 8 experience, which is an item that the ACRS Subcommittee 9 and full Committee has seen previously in Limerick and 10 Columbia applications; and then the vessel integrity 11 issues related to pressure-temperature limits, as well 12 as the upper shelf energy. These four open items will 13 be the focus of the staff's discussion this afternoon.
14 15 This morning I'd like to introduce members 16 of our management team in DLR that are here today. To 17 my right is Melanie Galloway, the deputy director of 18 the Division of License Renewal. We also have several 19 branch chiefs in the division; Dennis Morey, Bo Pham, 20 Mike Marshall, and Raj Auluck. We also have the branch 21 chief from our Region III office, Ann Marie Stone.
22 When the staff does its presentation this 23 afternoon, I will introduce the specific members that 24 will be providing comments. We also have a large number 25 of our staff here in the audience today that can step NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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9 1 to the microphone and answer comments.
2 At this time what I'd like to do is turn 3 the presentation over to FENOC, and specifically Barry 4 Allen to introduce his folks.
5 MR. ALLEN: Thank you very much. Good 6 morning, Mr. Chairman and Committee Members. We're 7 very happy to be here this morning and we're looking 8 forward to just good discussion, healthy dialogue on 9 our license renewal application. We will provide you 10 a little bit of background information on Davis-Besse 11 for those of you who may not have been there before.
12 We'll provide an overview of our application and our 13 process that we've gone through. And as far as the four 14 Safety Evaluation Report open items, we have plenty of 15 information. Plan on having a good dialogue on that, 16 healthy discussion and a fairly long discussion on the 17 shield building laminar cracking to ensure that this 18 Committee has a good full understanding of that issue 19 as we do.
20 As I said, I'm Barry Allen and I'll let my 21 team up here with me introduce themselves.
22 MR. BYRD: I'm Ken Byrd, the director of 23 engineering at Davis-Besse.
24 MR. CUSTER: My name is Cliff Custer. I'm 25 the project manager for FENOC license renewal.
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10 1 MR. DORT: My name is Steven Dort. I'm a 2 license renewal project lead.
3 MR. ALLEN: We're looking forward to a very 4 healthy dialogue today and we're looking forward to 5 entertaining your questions and satisfying your needs.
6 And with that, I'll turn the presentation over to Mr.
7 Byrd.
8 MR. BYRD: All right. I'm going to start 9 out with a brief introduction of Davis-Besse. If you 10 can go to the next slide, please. So the Davis-Besse 11 site, we are located on the southwestern shore of Lake 12 Erie. We're in Ottawa County, Ohio. It's a 954-acre 13 site, and of that site 221 acres are for the plant 14 structures and equipment and the rest of the site is 15 a wildlife refuge.
16 So next slide, please. So a very quick 17 background on our plant. Davis-Besse is a pressurized 18 water reactor. We're a Babcock & Wilcox raised-loop 19 design, 2817 megawatts thermal. And we did do a 20 measurement uncertainly recapture power up rate in July 21 of 2008, and that was a 1.6 percent upgrade.
22 Our license is currently -- would expire on April 22nd, 23 2017. And as of today the plant's at 100 percent power 24 and we've been on the line for 98 days. That's following 25 our 17th refueling outage.
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11 1 Next slide, please. So we have had -- at 2 Davis-Besse we've had two outages in the last 12 months.
3 We did have a mid-cycle outage which we conducted last 4 October, and that was in order to replace the reactor 5 vessel head. Then we had a refueling outage this 6 spring. And in those two outages we made a number of 7 upgrades and did a number of inspections, and I'm going 8 to very briefly review some of the things we did to 9 improve the plant over those two outages.
10 Obviously, we replaced the reactor vessel 11 head, and that was the reason we shut down back in October 12 for the mid-cycle outage. We replaced selected power 13 cables during both of these outages. We replaced 14 selected service water piping as part of our ongoing 15 program to replaced service water piping. We replaced 16 both emergency diesel generator exhaust pipes. We did 17 some upgrades to prepare for our steam generator 18 replacement, which will be coming up in 2014 in our 18th 19 refueling outage. We upgraded the polar crane and we 20 installed a Palfinger crane. And we also did our 21 in-service inspection for the reactor vessel removal 22 core support with no unacceptable limitations. And we 23 performed an integrated leak rate test of the 24 containment.
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12 1 to Cliff Custer to provide an overview of the license 2 renewal.
3 MR. CUSTER: Thank you, Ken. The 4 application was developed with the FENOC core team 5 that's been involved in working on license renewals 6 since 2006. Davis-Besse program owners and subject 7 matter experts were involved in the development of the 8 application and the audit and inspection interviews, 9 NRC staff calls, RAI responses, and commitment 10 development. In addition AREVA supported us in 11 development of the application. During the time of the 12 development of the application we participated in NEI 13 working groups and industry peer reviews.
14 Next slide. The application was submitted 15 in August of 2010. It was developed using GALL Rev 1 16 standards, which were the standards at the time. There 17 are 43 aging management programs. Twelve are new, four 18 plant-specific. Thirty-one are existing, four are 19 plant-specific. The 49 license renewal commitments and 20 those commitments are included in the USAR Supplement, 21 which is Appendix A of the LRA.
22 MEMBER SHACK: And when your license 23 renewal application came in, you had 25 commitments.
24 MR. CUSTER: That's correct, and it jumped 25 to 49, which is a large increment.
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13 1 MEMBER SHACK: Is that -- what's the -- why 2 do you attribute that large number of changes in 3 commitments? I mean, was something incomplete about 4 the original application?
5 MR. CUSTER: The application, as I said, 6 was originally submitted to GALL Rev 1. GALL Rev 2 7 changes a lot of the additional specifics. A lot of 8 our RAI responses in fact were formulated based on GALL 9 Rev 2. A lot of those commitments came from that.
10 CHAIRMAN SIEBER: Would you conclude that 11 you now comply with all Rev 2, or are there exceptions?
12 MR. CUSTER: I would say that there are some 13 exceptions. There are -- we have eight programs with 14 exceptions. And I think the regulator this afternoon 15 will talk about he selectively reviewed application to 16 GALL Rev 2 during the audits and inspections.
17 CHAIRMAN SIEBER: Yes, will you present 18 want the character of those exceptions are today to us?
19 MR. CUSTER: I had not intended to. We 20 could respond to some of those questions as they come 21 through.
22 CHAIRMAN SIEBER: Okay.
23 MR. CUSTER: Yes.
24 CHAIRMAN SIEBER: Okay. So we'll see when 25 the time comes.
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14 1 MR. CUSTER: Okay.
2 CHAIRMAN SIEBER: Thank you.
3 MR. CUSTER: Our commitments will be 4 managed by the FENOC commitment tracking program.
5 Next slide. On this slide are listed the 6 audits and the inspections that were conducted. Our 7 RAIs and responses addressed the differences primarily 8 between GALL Rev 1 and GALL Rev 2, as I said. Our Safety 9 Evaluation Report with open items was issued on July 10 31st of this year.
11 Next slide. Our SER open items. As we 12 said, we have four SER open items. Reactor vessel 13 neutron embrittlement is one. Pressure-temperature 14 limits is another. The use of operating experience and 15 management of the shield building is the final one.
16 Next slide. With respect to neutron 17 embrittlement, the reactor vessel upper-shelf energy 18 evaluation, originally we chose a mean value of 70 19 foot-pounds in projection to the 52 effective full power 20 years upper-shelf energy. Based on questions from the 21 staff, we later chose to use equivalent margins analysis 22 to qualify our upper-shelf energy selections.
23 Next slide. The equivalent margin 24 analysis is as listed. And we provided the response 25 to the nozzle belt forging on June 14th. The NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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15 1 upper-shelf forging was addressed in the LRA. The 2 nozzle belt forging to the upper shelf circumferential 3 weld and lower shelf forging to the Dutchman forging 4 were just submitted September 14th. Those items are 5 under review by the staff.
6 With respect to pressurizer-temperature 7 limits, the staff had questions on the methodology used 8 to establish pressurizer-temperature limits. Appendix 9 G requires pressurizer-temperature limits to include 10 all ferritic materials of the boundary, include 11 discontinuities and nozzles, and evaluate non-beltline 12 components which may have RTNDT values that define a more 13 restrictive lowest operating temperature.
14 Next slide. In our response we reviewed 15 and provided our limits in accordance with 10 C.F.R.
16 Appendix G, Reg Guide 1.99 Rev 2, using the methods in 17 the approved topical report BAW-10046A.
18 And the bottom line is really on the next 19 slide, Steve, that the reactor vessel closure head 20 outlet nozzles and beltline region are the controlling 21 regulations that regulate the P-T limits. Our response 22 has been submitted and is under review by the staff.
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16 1 management programs, inform and enhance programs. We 2 reviewed the ISG, and our response brings us in 3 compliance. Our changes will be flag aging-related OE, 4 consideration of material, environment and aging 5 mechanisms. We will revise our OE and corrective action 6 programs to provide feedback to aging management program 7 owners, identify training needs. Those responses have 8 been submitted and we will be in alignment with the ISG.
9 At this point in time our commitment is by the end of 10 the year.
11 Next slide.
12 MR. BYRD: Okay. I'll be providing the 13 discussion on the open item B.2.34 for the shield 14 building. So what I'm going to do for this open item, 15 first I'll briefly walk through the function and design 16 of the shield building, talk about how we discovered 17 laminar cracking, review the investigation of the 18 cracking, describe how we went about doing the root 19 cause, corrective actions and then discuss the aging 20 management program that we've put in place.
21 MEMBER STETKAR: Ken, can I interrupt you 22 just for a second? I want to ask Jack something.
23 In terms of organizing the meeting, do you 24 want to go through all of the shield building first?
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17 1 to present in their formal slides here. You want to 2 get those out of the way first, or you want to go through 3 the shield building and then catch up on those after 4 the shield building?
5 CHAIRMAN SIEBER: I would prefer to discuss 6 the shield building now.
7 MEMBER STETKAR: Okay.
8 CHAIRMAN SIEBER: Because I think it's 9 going to take the longest --
10 MEMBER STETKAR: Yes, that's --
11 CHAIRMAN SIEBER: -- amount of time.
12 And --
13 MEMBER STETKAR: We have all -- I'm sure 14 John has some also, so --
15 CHAIRMAN SIEBER: -- there are still 16 significant questions. Okay. Just keep your 17 questions noted.
18 MEMBER STETKAR: Don't worry. I have --
19 CHAIRMAN SIEBER: Oh, that whole book?
20 MEMBER STETKAR: I have notes.
21 CHAIRMAN SIEBER: Okay.
22 MR. BYRD: Okay. Go to the next slide, 23 please. Okay. What this slide is intended to show is 24 the shield building, the annulus and the containment 25 vessel. And the important thing I wanted to -- point NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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18 1 I wanted to make here is our shield building at 2 Davis-Besse is a freestanding concrete structure. We 3 have a separate containment vessel that's shown in this 4 slide. The containment vessel is an inch-and-a-half 5 thick steel, and the function of the containment vessel 6 is to be able to withstand the pressure for the largest 7 postulated break we would have in the reactor coolant 8 system. We have a four-and-a-half-foot annulus between 9 the containment vessel and the shield building.
10 Go to the next slide, please.
11 MEMBER SHACK: While you're here, could you 12 just show me the geometry of the sand pocket?
13 MR. BYRD: Yes, the sand pocket would be 14 located in this area between the shield building and 15 the containment vessel. So it's down in this location 16 here.
17 MEMBER SHACK: And how big is it?
18 MR. BYRD: Well, the annulus itself is 19 approximately four-and-a-half feet across.
20 MEMBER SHACK: And the sand pocket goes 21 down how far?
22 MEMBER STETKAR: Ken, you have to speak 23 into the microphone.
24 MEMBER SHACK: You have to be a little bit 25 closer to the microphone.
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19 1 MR. BYRD: I'm sorry. The annulus is 2 four-and-a-half feet, and so the sand pocket would 3 encompass that. As far as the depth of the sand pocket, 4 maybe Mr. Hook could help me with that. Jon Hook, our 5 design engineer and manager.
6 MR. HOOK: Right, I'm Jon Hook, design 7 engineer and manager. So the sand pocket region is 8 approximately -- tapered. At the top it is 9 approximately 15 inches wide and at the bottom it's about 10 nine inches wide. It's about four feet deep.
11 The sand pocket, I just want to clarify, we call 12 it the sand pocket because at one time there was sand 13 in it, but the sand has been removed. But we still call 14 it the sand pocket area.
15 CHAIRMAN SIEBER: Have you found 16 accumulations of water in the annular space between the 17 building and the containment vessel?
18 MR. BYRD: We have. John, you want to 19 continue with answering that question, please?
20 MR. HOOK: Can you repeat that question for 21 me, please?
22 CHAIRMAN SIEBER: Have you found 23 accumulations of water between the shield building 24 structure and the containment vessel?
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20 1 coming up in that area. We've been monitoring that.
2 We look at it every refueling outage.
3 CHAIRMAN SIEBER: And is it enough water 4 so that the containment vessel is wetted most of the 5 time?
6 MR. HOOK: That access is -- that area is 7 only accessed to us during the refueling outage. So 8 we do take that opportunity at that time to go in and 9 inspect that area. And it is wetted, but the slope is 10 such that the water is -- flows away from the shield 11 building. So normally there's not water progressing 12 up against the metal.
13 DR. BARTON: Yes, but at one time there was, 14 right? Don't you have some corrosion down there?
15 MR. HOOK: Right, there is some minor 16 discoloration and corrosion down there.
17 DR. BARTON: What is minor? Have you done 18 UTs or anything like that?
19 MR. HOOK: We did extensive investigation 20 in 2002. We did UT readings back then and all the UT 21 readings were greater than the minimum thickness 22 required. And we've done -- like I said, we've done 23 inspections every refueling outage and there's no 24 significant change from 2002.
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21 1 access to the containment, the steel containment vessel 2 at the bottom, is there concrete or any kind of 3 obstruction in that area that would prevent you from 4 getting thickness measurements throughout the bottom 5 of the containment vessel?
6 MR. HOOK: Right, so when you look on the 7 drawing there, the bottom portion of the containment 8 vessel is encased in concrete on the top and on the bottom 9 of it.
10 CHAIRMAN SIEBER: And so how do you get 11 thickness measurements and defected --
12 MR. HOOK: Right, so --
13 CHAIRMAN SIEBER: -- limitations through 14 the concrete.
15 MR. HOOK: In 2002 we did UT readings down 16 at the sand pocket area.
17 CHAIRMAN SIEBER: Okay.
18 MR. HOOK: Those were the exposed shield 19 -- the exposed areas. We didn't do any excavation in 20 that area.
21 CHAIRMAN SIEBER: Okay. So you went down 22 from the four-foot space between the shield building 23 and the containment vessel, and around that curve made 24 measurements basically perpendicular to the lower 25 surface of the containment vessel?
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22 1 MR. HOOK: The areas that are inaccessible 2 due to concrete up against it we did not get UT readings.
3 But from the outside at the bottom of the sand pit we 4 could take UT readings. We had access to that area in 5 the sand pocket region.
6 MEMBER ARMIJO: It's my understanding 7 you're going to do some boring in the future --
8 MR. BYRD: That's correct.
9 MEMBER ARMIJO: -- to look for corrosion 10 of the containment vessel due to borated water seepage.
11 MR. BYRD: We have a commitment; that's 12 correct, to do a core bore, and that would be from the 13 inside down to the containment vessel. And so it'll 14 be from in here up to the --
15 MEMBER SHACK: It's at that little step, 16 the thinnest part there?
17 MR. BYRD: It would be -- I'm not sure 18 exactly. This is obviously --
19 MEMBER SHACK: Can't see where you're 20 pointing.
21 MR. BYRD: It would be in this region.
22 We'd be coming from down underneath the reactor going 23 down to the --
24 MEMBER STETKAR: Maybe you could use the 25 mouse? Yes, so everybody can see.
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23 1 MR. BYRD: So we'd be taking a core bore 2 from the region below the reactor vessel and going down 3 to access the containment vessel. So the core bore would 4 be going down through the concrete. And that's -- we 5 have that, and we're committed to performing that prior 6 to the 18th refueling outage in 2014.
7 MEMBER STETKAR: But that won't be at the 8 low point of the containment vessel.
9 MR. BYRD: That would be --
10 MEMBER STETKAR: That's about 30 inches 11 above the --
12 MR. BYRD: No, I'm not sure if it is. Maybe 13 -- it says 30 inches.
14 MEMBER STETKAR: Well, it is 30 inches.
15 MR. BYRD: I think we have -- Dick Bair can 16 answer that.
17 MR. BAIR: My name's Richard Bair. Work 18 in design engineering. Our plan is in the 18th 19 refueling outages to install the core bore through the 20 concrete in the under-vessel area to access the inside 21 base of the containment vessel for inspection for 22 potential boric acid effects. It will not be through 23 the -- necessarily through the lowest portion. The 24 least amount of concrete between the vessel that we can 25 go through is our containment sump that has a stainless NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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24 1 steel liner. We don't wish to perforate that, nor put 2 in this core drill. So we're going to be somewhat off 3 from that area going through approximately two feet of 4 concrete to access the inside face of the vessel for 5 inspection.
6 CHAIRMAN SIEBER: Now you have a history 7 of leaks that the reactor vessel had at the attachments 8 through the control rod drive mechanisms. Do you have 9 evidence on the concrete basemat of the containment that 10 borated water was able to leak down to that level in 11 the containment?
12 MR. BYRD: I'm not -- do we have a -- Mr.
13 Hook?
14 MR. HOOK: So we do do inspections in that 15 area and the leakage through the refueling canal, when 16 we have the refueling canal filled, it's relatively 17 minor. We do inspections and we have found no 18 deterioration at all in the concrete area.
19 CHAIRMAN SIEBER: Did you find evidence of 20 boric acid deposits there?
21 MR. HOOK: We have evidence of boric acid 22 deposits on the concrete. There's a few cracks where 23 it has come up.
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25 1 inspector.
2 What we've done is in past outages, or in 3 -- and in current outages now we do documented boric 4 acid inspections. When we go into containment when we 5 first start a refueling outage we do an as-found 6 inspection, take pictures, document that it in an 7 inspection report. We take -- when the canal is filled 8 after a few days, we go back in, do another as-found 9 inspection, do pictures and an inspection report.
10 Then when it is drained, we go in and decon 11 the area, clean it up and then do an as-left inspection, 12 take those pictures, document that. And then the next 13 outage when we come back, we do our initial as-found.
14 The pictures are compared, the documents are compared 15 to see if there's any changes. And in the past several 16 outages we haven't seen any changes, any further 17 degradation.
18 CHAIRMAN SIEBER: When was the -- when did 19 you last perform the integrated containment leak rate 20 test?
21 MR. BYRD: We performed an integrated 22 containment leak rate test during our last refueling 23 outage.
24 CHAIRMAN SIEBER: And what was your initial 25 result? Did you have to repair anything?
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26 1 MR. BYRD: Actually 2011 it was.
2 MR. ALLEN: It was 2011. It was the 3 mid-cycle outage. I'm sorry, the mid-cycle outage was 4 -- the mid-replacement outage.
5 CHAIRMAN SIEBER: Were you required to 6 repair anything to meet the requirements of that test?
7 MR. BYRD: Mr. Henline, Trent Henline, our 8 program supervisor can provide some more information 9 on that.
10 MR. HENLINE: My name's Trent Henline, 11 engineering program supervisor. And we provided our 12 integrated leak rate rest during the 17th mid-cycle in 13 November of 2011. And we passed that test on the initial 14 attempt with an approximately 80 percent margin. We 15 did not have to repair anything.
16 CHAIRMAN SIEBER: Okay. Thank you.
17 MEMBER STETKAR: Jack, I want to ask a 18 couple of questions, as long as you brought it up, on 19 the containment shell.
20 The water that you found in the annulus is 21 groundwater, is that correct?
22 MR. BYRD: That's correct.
23 MEMBER STETKAR: And you've got a fairly 24 aggressive groundwater chemistry at the site, as I 25 understand it.
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27 1 MR. BYRD: That's correct.
2 MEMBER STETKAR: I understand you've 3 inspected the parts of the shell that you can access 4 right at the interface there. What confidence do you 5 have that groundwater has not migrated to the bottom 6 part of that area and initiated corrosion from the 7 exterior part of the shell in an area -- what's the 8 surface area at the bottom of the containment shell that 9 you won't be able to access during that single core bore 10 from the interior? In other words, there's a big dish 11 there that water could be collected for some period of 12 time that you have no evidence of the status of the shell 13 in that area.
14 MR. BYRD: You're asking about water that 15 would be migrating from the sand pocket region --
16 MEMBER STETKAR: That's correct.
17 MR. BYRD: -- through the concrete?
18 MEMBER STETKAR: Well, or through -- it's 19 not air-tight. Through the gap between the concrete 20 and the shell.
21 MR. BYRD: Okay. I understand. I'll have 22 -- Jon Hook can address that issue.
23 MR. HOOK: Right. I'm Jon Hook, design 24 engineer and manager. I think your question is related 25 to corrosion on the underside of the containment vessel.
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28 1 MEMBER STETKAR: That's exactly right.
2 MR. HOOK: Right. So there is groundwater 3 infiltration. The foundation that we have underneath 4 there is a waterproof membrane, but obviously there's 5 either a tear or a rip in that. We've got water migrating 6 in that area. Again, we monitor that area. In the sand 7 pocket we take samples of the water every refueling 8 outage, and based on the samples of the water that we 9 have, we have very low iron content in there. The 10 concrete is a very high pH area and it's very passive 11 -- passivates any corrosion in that area. So based upon 12 that, we -- there is very little if any corrosion in 13 the inaccessible areas of the containment vessel.
14 MEMBER STETKAR: Well, you have drains in 15 that area.
16 MR. HOOK: We have two drains in the sand 17 pocket area, that is correct.
18 MEMBER STETKAR: How do you keep water out 19 from the bottom? I'm not very well versed in --
20 MR. HOOK: Right, so there is --
21 MEMBER STETKAR: I'm an engineer. The 22 bottom point of the --
23 MR. HOOK: There is a potential that we'll 24 have water between the concrete foundation and the 25 underside of the containment vessel.
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29 1 MEMBER STETKAR: Right.
2 MR. HOOK: Right. And then water would be 3 there and it migrates up through the interface between 4 the containment vessel to the sand pocket area.
5 MEMBER STETKAR: Yes.
6 MR. HOOK: But again, that's exposed to the 7 concrete that's there. Concrete is very passive to 8 corrosion. There's very little if any oxygen in that 9 area, so based upon the passive nature of the concrete, 10 low oxygen content and monitoring the water in the sand 11 pocket area, we have high confidence there is no 12 corrosion going on in the vessel.
13 MEMBER STETKAR: That's presuming the 14 water comes in from the low point and fills the entire 15 volume. Is that right? I mean, if the water's coming 16 in and flowing down, sampling the water in the sand 17 pocket gives you absolutely no indication of possible 18 corrosion products collected at the bottom.
19 MR. HOOK: Right, the water is coming up 20 between the containment vessel on the underside and 21 migrating up --
22 MEMBER STETKAR: Ah.
23 MR. HOOK: -- sand pocket area.
24 MEMBER STETKAR: Okay. And you know that?
25 MR. HOOK: We know that. That is for sure.
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30 1 Again, we go in there every refueling outage, or every 2 time we have an outage and then -- to verify that. The 3 sand pocket --
4 MEMBER SHACK: Seems that you've left all 5 the chlorides down somewhere in the -- all the -- the 6 chlorides come in somewhere. There's a conservation 7 of chloride going on somewhere here.
8 MR. HOOK: That is correct. We have high 9 chlorides in that area.
10 MEMBER SHACK: Well, that's not a good 11 thing.
12 MEMBER STETKAR: And from what you're 13 saying, that must be continuously wetted then.
14 MR. HOOK: There are some regions 15 -- there's five small areas that have some seepage in 16 that area. So the far majority of that area is dry.
17 MEMBER STETKAR: Now that's where you see 18 -- I'll use the term --
19 MR. HOOK: Migrating to the top.
20 MEMBER STETKAR: -- migrating to the 21 -- thank you -- migrating to the -- I was going to use 22 the term bubbling up, but migrating to the top. But 23 what confidence do you have that the vast majority of 24 the lower portion of that shell is not continuously 25 wetted? Just because you see it in five locations NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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31 1 doesn't necessarily mean that that's -- you know, that 2 there are little rivulets coming up or something.
3 MR. HOOK: So there is a potential that a 4 large area could be in contact with the water. But 5 again, that large area is in contact with the concrete 6 with a high pH. Very, very low oxygen content in that 7 area. So based upon those items, corrosion's not taking 8 place.
9 MEMBER SHACK: Those are good things, but 10 then the high chloride's --
11 MEMBER STETKAR: Doesn't make you feel 12 good.
13 MEMBER SHACK: -- not a good point.
14 MR. HOOK: Right, so there is chlorides in 15 the groundwater. So --
16 MEMBER SHACK: It is apparently collecting 17 since you're not seeing it in the stuff that's coming 18 up. You told me that was low chloride. Un-aggressive, 19 right?
20 MR. HOOK: There is chlorides in the water 21 that we have sampled. And as the water comes up, there 22 could be some evaporation and then concentration of the 23 water that's in there. So the part that we see and we 24 tested could be a concentrated area.
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32 1 -- you said five drains or something? Where are they 2 located?
3 MR. HOOK: No, there's two drains.
4 DR. BARTON: Pardon?
5 MR. HOOK: There's two drains --
6 DR. BARTON: Where are they located and how 7 big are they?
8 MR. HOOK: I think they're four-inch drains 9 and they are located approximately on each side of the 10 fuel transfer tube area.
11 DR. BARTON: In what amount?
12 MR. HOOK: And the sand pocket area is 13 sloped to the floor drains.
14 DR. BARTON: Now can you get access through 15 the drain lines with a boroscope or something and get 16 down there and see what you got on the bottom?
17 MR. HOOK: The floor drains are accessible.
18 They're on the bottom of the sand pocket.
19 MEMBER STETKAR: But they're just normal.
20 I mean, it's a big annulus so there are just floor drains 21 in there to collect leakage from pipes that come through 22 and -- they're just floor drains.
23 DR. BARTON: Well, I'm just looking at 24 access to the bottom of the --
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33 1 out. It hits the interface and that's it, yes. All 2 right.
3 CHAIRMAN SIEBER: It has to go to a sump.
4 MEMBER STETKAR: Yes, they'll go out --
5 CHAIRMAN SIEBER: It's all underground.
6 MEMBER STETKAR: Yes, they'll go to a floor 7 drain.
8 MEMBER ARMIJO: Well, you know, it would 9 be helpful if we could get -- and I know this isn't the 10 main shield building issue, but it's going -- we're going 11 to come to that. That's one of the RAIs. We can 12 probably hear more about that in future meetings. But 13 the source of the infiltration of the water, if it's 14 coming in through the bottom of the concrete -- you know, 15 water normally doesn't flow up hill, so I don't know 16 how it gets up to the sand pocket region unless it's 17 leaking in near the sand pocket region.
18 MR. HOOK: The sand pocket area is 19 approximately -- well, there's approximately 25 foot 20 of head on the groundwater. So that's why the sand 21 pocket --
22 MEMBER STETKAR: The normal groundwater 23 level is 570, and this is 5 --
24 MR. HOOK: Five-forty-five.
25 MEMBER STETKAR: -- 545.
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34 1 MEMBER ARMIJO: So that's leads to, not a 2 conclusion, but a suspicion that there's plenty of 3 water, I mean, in between the steel and the concrete.
4 MEMBER STETKAR: Right. Yes.
5 MEMBER SHACK: It's a question of how 6 benign that environment is --
7 MEMBER ARMIJO: Yes, right.
8 MEMBER SHACK: -- with the concrete.
9 MEMBER ARMIJO: Right. Right, right, 10 right. So that's the -- we got to get at that at some 11 point in more detail to understand the chemistry.
12 MR. HOOK: Well, so one of the things that 13 -- when -- Dick Bear talked about that. During the next 14 refueling outage we're going to take a core bore at the 15 bottom. And to get to the bottom of the containment 16 vessel, we'll do new UT readings and at the bottom.
17 Then we'll absolutely be able to determine the thickness 18 as well.
19 MEMBER ARMIJO: So when you bore it, do your 20 core bore, then you'll get -- do a UT and you'll get 21 thickness at the location of where --
22 MR. HOOK: That is correct.
23 MEMBER ARMIJO: A low location? Not --
24 MEMBER SHACK: A low location. Thirty 25 inches off the --
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35 1 MEMBER ARMIJO: Not the absolute bottom.
2 MEMBER SHACK: Right. Right. But it will 3 be low.
4 MEMBER STETKAR: It'll be low enough to see 5 this effect from the groundwater.
6 MEMBER SHACK: I would think.
7 MEMBER STETKAR: You would think.
8 MEMBER ARMIJO: Well, this is something in 9 a future presentation more detailed on how that's put 10 to bed.
11 MEMBER RAY: How is the containment vessel 12 supported? Is it just supported at the bottom by its 13 embedment in the concrete, or is there any other support 14 provided to the containment vessel above the sand 15 pocket?
16 MR. HOOK: Yes, again, I'm Jon Hook, design 17 engineer and manager. The containment vessel and the 18 shield building are two separate complete structures.
19 There's no interaction except for at the base. They 20 share the same common foundation. And the containment 21 vessel has concrete on the bottom, a significant mass 22 of 15 feet of concrete at the bottom. It is a 23 cantilevered structure.
24 MEMBER RAY: Okay. So it's freestanding 25 above the foundation?
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36 1 MR. HOOK: That is correct.
2 MR. BYRD: Okay. Any further questions on 3 this before I move on?
4 (No response.)
5 MR. BYRD: Okay. I'll move on now to talk 6 a little bit about the shield building.
7 So the shield building itself if a -- it's 8 a 30-inch concrete structure. And the purposes of the 9 shield building, there's really three primary purposes:
10 One is biological shielding. Secondly, it provides 11 environmental protection for the containment vessel.
12 I mean by that protection from various different kind 13 of missiles. And then it allows for a controlled 14 release of the annulus under accident conditions. And 15 we do have a ventilation system which can take a suction 16 on the annular area and provide us with a negative 17 pressure in that area.
18 Next slide.
19 DR. BARTON: I understand there's no 20 waterproof membrane on the exterior of the shield 21 building below grade.
22 MR. BYRD: That is not correct. There 23 actually is a waterproof membrane on the shield building 24 below grade. There is not a waterproof membrane on it 25 above grade. It was constructed with a waterproof --
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37 1 DR. BARTON: I must have read that wrong.
2 All right.
3 CHAIRMAN SIEBER: But you doubt the 4 integrity of the waterproof membrane below grade, right?
5 Did I hear you say that before?
6 MR. BYRD: I didn't say that. I mean, I 7 don't know that we've done -- I think, Joe Brunkhorst, 8 maybe you could provide a little bit more information 9 on that.
10 MR. BRUNKHORST: Joe Brunkhorst, 11 structures monitoring program owner. As far as the 12 waterproof membrane below grade, there is obvious 13 evidence that there may be a nick or flaw or in the 14 membrane, but it covers substantial surface area for 15 below-grade shield building.
16 DR. BARTON: Well, if you're getting water 17 into the concrete below grade, how do you know the 18 condition of that concrete? You got to address the 19 water down there.
20 MR. BRUNKHORST: That's correct. We 21 haven't seen any signs of any sort of degradation, 22 spalling from what has been accessible. I mean 23 opportunistic inspections of the area has not shown any 24 signs of any sort of aggressive groundwater attack on 25 the concrete.
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38 1 CHAIRMAN SIEBER: Have you had 2 opportunistic inspection opportunities --
3 MR. BRUNKHORST: I can --
4 CHAIRMAN SIEBER: -- down below the -- on 5 the curvature of the base of the shield building?
6 MR. BRUNKHORST: I do not believe so. We 7 have not had any specific on the shield building itself, 8 no.
9 CHAIRMAN SIEBER: Okay. Thank you.
10 MR. BYRD: Okay. Moving on, please, to the 11 next slide. So the purpose of this slide is to provide 12 you with a little bit of information on some of the terms 13 we're going to be using here to describe the shield 14 building cracking issue.
15 First of all, the shield building wall, as 16 I've mentioned before, it is 30 inches thick. There's 17 two mats of primary reinforcement bar on the shield 18 building, an inner and outer mat. And those are No.
19 11 rebar horizontally, which is one-and-three-eighths 20 inches, and No. 10 vertically.
21 We also have these -- eight of these flutes, 22 which are labeled on this picture around the perimeter 23 of the shield building. And around each flute we have 24 two of what we have -- we call a flute shoulder. Now 25 these three shoulders, the dimensions, it's NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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39 1 approximately -- on the inside that's about 18 inches.
2 And the flute shoulder has its own reinforcement, as 3 you can see in the diagram. That's No. 8 rebar, one-inch 4 diameter. And that rebar is -- it attaches to the main 5 rebar in two locations on each end of the flute shoulder.
6 7 And the dimension between the two points 8 of the rebar is -- it's about -- between 11 and 12 inches.
9 We took quite a bit of -- 11 and 12 feet, rather. We 10 took quite a bit of radar, ground-penetrating radar 11 measurements of that during our evaluation of the 12 condition.
13 CHAIRMAN SIEBER: What's the purpose of the 14 flute?
15 MR. BYRD: The flute is only intended 16 -- it's an architectural feature. It's only for 17 aesthetics.
18 CHAIRMAN SIEBER: It's only for --
19 DR. BARTON: To make the building look 20 pretty.
21 MR. BYRD: That's correct.
22 DR. BARTON: That's what it is.
23 CHAIRMAN SIEBER: Yes, that caused me to 24 scratch my head.
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40 1 buildings.
2 MR. BYRD: And actually the next slide --
3 MEMBER ARMIJO: Before you do that, I just 4 want to make sure, the only thing that hooks that 5 shoulder to the rest -- to the structural part of the 6 shield building are these rebar that comes through the 7 wall, those --
8 MR. BYRD: Those -- on each end of the -- on 9 each end those hooks. That is correct.
10 MEMBER ARMIJO: And down the length of the 11 flute there's hooks?
12 MR. BYRD: This rebar is spaced every 12 13 inches horizontally, so you have a hook every 12 inches.
14 But that's one of the factors I'll be discussing, 15 because that was one of the contributing issues we had 16 lack radial reinforcement on these flute shoulders.
17 MEMBER ARMIJO: Okay.
18 MR. BYRD: If you go to the next slide, it 19 provides a little bit better information on the function 20 of these flute shoulders.
21 So this is a picture of a flute shoulder 22 taken up close. This is actually from the roof of our 23 auxiliary building. And the interesting thing to note 24 here is that the flute shoulder ends at the roof of the 25 building. Actually only 3 of our flute shoulders out NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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41 1 of 16 actually go down to ground level. All the rest 2 of them are truncated like this one at various different 3 roof levels. So this makes it pretty apparent that this 4 was intended as an -- for aesthetic purposes. In our 5 evaluation of the capability of the shield building, 6 we don't take any credit for the flute shoulders. We 7 do evaluate them as a dead load in our analysis.
8 The other interesting thing I just want to 9 point out on this picture, you can see a lot of blue 10 dots on the concrete there. That is the -- and I'll 11 be talking about this a little bit more. That's the 12 grid we laid out for the impulse response testing we 13 did on the shield building. We actually laid out over 14 60,000 of those points. That's on a one-foot square.
15 The other thing of interest there, you can 16 see in the middle of the flute on the upper left-hand 17 side of this picture there's a red circle there, a little 18 red dot. That's actually a plug. We did a core bore 19 in that area and that's one of the plugs we use protect 20 the core bores.
21 So next slide, please.
22 MEMBER ARMIJO: Just to make sure I 23 understand. Now, the shoulders don't actually -- do 24 not -- there's no shoulders, let's say in the protected 25 areas? Let's say the -- with the auxiliary building NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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42 1 the shoulders don't go down to there?
2 MR. BYRD: They don't go down. What you're 3 --
4 MEMBER ARMIJO: Or the turbine building.
5 They just stop?
6 MR. BYRD: They stop at the -- what you're 7 -- what we're standing -- on this particular picture 8 here, you're -- we're standing on top of the main steam 9 line rooms at Davis-Besse. And if you go down 10 underneath, there is no shoulder down there. This 11 actually several feet above the roof line. And it does 12 that everywhere where there's a building adjacent to 13 the shield building. So there's actually only three 14 flute shoulders which go down to ground level.
15 MEMBER ARMIJO: Okay. Thanks.
16 MR. BYRD: Okay. Next slide, please. So 17 very briefly, we discovered this issue on October 10th.
18 We were performing hydro-demolition. That was part 19 of creating a construction opening for our head 20 replacement. Upon discovery of the condition, we did 21 notify the Nuclear Regulatory Commission resident, 22 wrote a condition report and we placed a restraint on 23 the restart. And then we put together a team of experts 24 to investigate the issue. And for that we mobilized 25 various different consultants. We also brought in NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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43 1 experts from FirstEnergy.
2 MEMBER SHACK: Hydro-demolition, is that 3 just a water jet cut?
4 MR. BYRD: That's the -- yes, 5 hydro-demolition is the method we use. That's where 6 we us 20,000 pounds per square inch water pressure to 7 cut through the concrete.
8 Next slide, please. So one of the methods 9 we use to investigate this condition was the methodology 10 called impulse response, which is a non-destructive 11 methodology that can be used in concrete. And the way 12 this works is you have an instrumented hammer. And in 13 this picture you can see the individual who is performing 14 this testing. He has that hammer in his right hand.
15 And they have a geophone then which they use to monitor 16 the response, which in this case he has in his left hand.
17 So what he'll do is he'll strike the wall at one of 18 those blue dots which were gridded out. And then these 19 -- the hammer and the geophone are both linked to a 20 portable field computer which collects the data. And 21 that information then is -- that data is processed to 22 obtain a parameter that's called mobility, and that 23 mobility can then be related to the structure thickness.
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44 1 actually a couple different campaigns. We did some 2 impulse response testing in 2011 until the weather got 3 -- you know, towards the end of the year. Then this 4 summer we completed the rest of the building. We did 5 about 60,000 individual points in the building with this 6 methodology.
7 CHAIRMAN SIEBER: When you perform this 8 test what frequency range are you intending to receive 9 in the microphone-type device in the workman's left 10 hand?
11 MR. BYRD: I couldn't answer that question.
12 I don't believe I have anyone here that could answer 13 that. That would be something I'd have to refer -- we 14 used Construction Technology Laboratories. That's the 15 organization in Chicago who performed this testing.
16 So I'm not familiar with the specific frequency that 17 was being --
18 CHAIRMAN SIEBER: And so what you're 19 looking for is the reflections from the cracked surface, 20 if any?
21 MR. BYRD: That's correct.
22 CHAIRMAN SIEBER: And how do you determine 23 how deep the crack is?
24 MR. BYRD: The way you determine; I'm going 25 to show that on the next page, you have to do a core NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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45 1 bore, because impulse response testing cannot give you 2 the depth of the crack. What can tell you is you have 3 an area of high mobility, and then we would investigate 4 those areas further using core bores.
5 CHAIRMAN SIEBER: Okay. So all this does 6 is tell you where the cracks are? It doesn't 7 characterize them in any way?
8 MR. BYRD: That is correct. Well 9 actually, if you do a lot of this -- we could tell by 10 looking at this -- and I -- it's not quantitative, but 11 you could look at the results and say I know you have 12 some cracking in this region. I mean, after we'd done 13 this over the entire building, we gained a lot of 14 experience. And obviously the Construction Technology 15 people are very experience at this, but in order to 16 validate this information, we used core bores.
17 MEMBER ARMIJO: What is the definition of 18 "mobility?" What are you actually measuring?
19 MR. BYRD: It's the -- it's really a -- it's 20 a measure of the structure. It's related to -- the 21 structure thickness is what you're getting. So you can 22 detect if you have a crack or a laminar -- delamination 23 in that area.
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46 1 these data points, can you get a map of where this 2 discontinuity --
3 MR. BYRD: Yes, and I'll be showing you a 4 slide later which shows you the mobility mapping we did 5 for the entire shield building.
6 MEMBER ARMIJO: Okay.
7 CHAIRMAN SIEBER: Now, from this portion 8 of the test you cannot tell anything about the geometry 9 of the crack?
10 MR. BYRD: That is correct.
11 CHAIRMAN SIEBER: For example, direction, 12 depth, width. Those just do not appear in the test 13 result?
14 MR. BYRD: That is correct. And I'll be 15 talking a little bit more about that in my next slide, 16 how we gained that information.
17 CHAIRMAN SIEBER: Well, I'll let you go 18 a little further before I ask the next question.
19 MR. BYRD: All right. Very good. Thank 20 you, sir.
21 Then go to my next slide where I talk a 22 little bit about the other methodology we used. We used 23 core bores extensively to investigate the condition.
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47 1 in width, depending on what we were attempting to do.
2 They could be from 8 to 28 inches deep.
3 And there was really four reasons we used 4 to do core bores. And first of all; and we discussed 5 this, we used these to validate the impulse response 6 data. And I might point out we did find that the impulse 7 response data was very accurate. What we would 8 frequently do, or we tried to as much as possible, is 9 use pairs of core bores. So when we'd get to an area 10 where the mobility told us that cracking was extended, 11 we would put core bores as close together as a foot and 12 we could get cracked and not cracked. So we could 13 validate that the impulse response data was valid. And 14 it was very accurately able to do that.
15 The second purpose of these was to establish 16 the crack depth. Again, impulse response couldn't tell 17 us how deep the crack was, but we could actually go down 18 with the boroscope and we could look and see where the 19 crack existed and measure the crack depth.
20 We could measure the crack width using the 21 -- and we did that with the crack comparator, and I'll 22 show you that on the next slide how we did that.
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48 1 about the root cause.
2 CHAIRMAN SIEBER: Now this design is unique 3 to the architect engineer for this facility?
4 MR. BYRD: The design of the shield 5 building?
6 CHAIRMAN SIEBER: Yes.
7 MR. BYRD: It was unique for this -- there 8 are other -- when I say "this design," there are several 9 other plants that have freestanding shield buildings, 10 but I'm not sure if any of them were precisely the same 11 as Davis-Besse.
12 CHAIRMAN SIEBER: That have flutes?
13 MR. BYRD: There are other designs with 14 flutes, but again not -- they're all a little different.
15 There are some other plants that do have flutes that 16 I'm aware of.
17 CHAIRMAN SIEBER: Has any other licensee 18 with a containment building design like this found 19 similar effects?
20 MR. BYRD: No, they have not, and 21 -- although we have talked to some of them and some of 22 them were actually up at Davis-Besse while we were doing 23 the investigation. But when I get to the root cause, 24 when I'm going to -- when I explain to you what caused 25 this, there's a number of -- a series of what I would NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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49 1 consider rather unique conditions that needed to occur 2 in some of the other plants, for example, that may be 3 in the South where we don't get the cold weather and 4 some other things that may have had an impact on that.
5 So at this point none of the other ones have observed 6 this condition.
7 CHAIRMAN SIEBER: Yes, well cracking in a 8 containment building is not a unique phenomenon.
9 MR. BYRD: Understand that. We'll 10 -- again, when I get into the root cause, I can talk 11 about what we --
12 CHAIRMAN SIEBER: Okay.
13 MR. BYRD: -- obtained from operating 14 experience.
15 DR. BARTON: But their rebar design may 16 have been different also.
17 MR. BYRD: That's possible, too.
18 DR. BARTON: Different designer.
19 MR. BYRD: Right.
20 CHAIRMAN SIEBER: Well, it can have -- it 21 can be a design issue, it could be a concrete mix issue.
22 MR. BYRD: Right.
23 CHAIRMAN SIEBER: Or chemical reaction, or 24 weather conditions, or -- there's a variety of things 25 that can cause these.
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50 1 MR. BYRD: Right, and we'll talk a little 2 bit more about that. I'll get to the root cause portion.
3 MEMBER ARMIJO: When you pulled out the 4 core when you were doing this core boring in a region 5 where you had these cracks, did they come out where they 6 actually came out in two pieces?
7 MR. BYRD: Yes, they would.
8 MEMBER ARMIJO: Okay.
9 MR. BYRD: When they were cracked, they 10 would come out in two pieces. But really the way to 11 measure the crack was actually going to the core bore 12 and look in the bore itself.
13 MEMBER ARMIJO: After they were done?
14 MR. BYRD: After they were taken out, 15 right. Sometimes you'd get them cracked where there 16 wasn't a crack just trying to get out -- if you had a 17 long core bore you're trying to pull out, it may crack.
18 19 MEMBER SHACK: Now I see Kewaunee and 20 Prairie Island have similar constructions. At least 21 they're still cylinders with concrete shield buildings 22 that have your kind of weather.
23 MR. BYRD: Yes, I'm not sure either of them 24 have flutes either though. I know there are flutes at 25 some plants, and I'm not -- those two don't come to my NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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51 1 mind as one that are fluted.
2 Okay. Going to the next slide, I can 3 summarize now where we saw the cracking. So the drawing 4 you see on this slide depicts the primary region where 5 we saw cracking. So what we determined was that 6 cracking is -- can be found in the flute shoulders.
7 And I say it's generic. We found it -- it could be found 8 at various different elevations in the flute shoulders.
9 It was observed to be more prevalent and actually much 10 -- significantly more prevalent -- and I'll show the 11 map of the completed impulse response testing later on 12 the south side of the building.
13 We did identify that the cracks were located 14 in, as shown on this picture, near the outer reinforcing 15 mat. There were no cracks observed on the inner mat.
16 And to investigate the inner mat, first of all we had 17 the construction opening. When we cut it, we had a 18 25-foot by 35-foot opening. We did inspect the 19 perimeter. We did have a cracking on the outside. In 20 fact, the picture here shows where the boundary of the 21 construction up here was. So we actually cut right 22 through the flute shoulder. We had no cracking observed 23 on the inner mat. It was all on the out outer mat.
24 We also further validated that. We did 25 eight deep core bores. So we did eight core bores and NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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52 1 then all the way through to the inner rebar mat. And 2 in none of those core bores did we find any cracking 3 in the inner rebar.
4 CHAIRMAN SIEBER: Did any of the cracking 5 appear on the surface where it --
6 MR. BYRD: No, it did not. This cracking 7 was contained inside as shown on this picture in that 8 inner mat of rebar. When I say "in the inner," it was 9 in the vicinity of the inner rebar mat. It did not have 10 any of the cracking that appeared on the surface. There 11 was no way through a visual inspection we had this line 12 in the cracking.
13 CHAIRMAN SIEBER: Okay. So you saw no 14 spalling, no cracks on either side of the containment?
15 MR. BYRD: We saw no spalling or cracking 16 that was associated with this laminar cracking. I mean, 17 there was none.
18 Okay. Moving onto the next slide, so we 19 also identified that we had some cracks in the top 20 20 feet of the shield building outside of the flute shoulder 21 region. The way it appeared is it appeared 22 -- and this is in -- and I'll -- this will be more obvious 23 when I show you the map of the total cracking, the cracks 24 had spilled out of the shoulders in the top 20 feet.
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53 1 adjacent to the main steamline penetration block-outs 2 where we also found similar cracking. Now the main 3 steamline penetration block-outs are actually the areas 4 that are right adjacent; and again, the drawing will 5 show that more clearly -- are adjacent to the regions 6 where -- and in the shoulders.
7 And finally, we identified the cracks are 8 very tight. And the method we used to measure crack 9 width -- again, that was something we had to with the 10 core bores. And we use the -- a core bore and we use 11 crack width comparitor. And the picture you see here 12 shows us with a -- measuring the width of the crack.
13 And we photographed these using the boroscope. This 14 particular crack we measured at 0.005 inches. So again, 15 it's a very tight crack. All of the cracks except one 16 were less than 0.01 inches. We did have one crack that 17 was 0.013 inches. That was the only case we had that 18 was greater than 0.01.
19 Okay. Next slide, please. So that really 20 very briefly summarizes the condition that we 21 identified. So I'll talk a little bit about -- next 22 about the evaluation we did to determine that this -- the 23 shield building was structurally adequate to restart 24 the plant.
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54 1 design is -- it's pretty conservative. It was 2 constructed with significant reinforcement and there 3 was a significant of margin. We had -- the maximum 4 vertical stress on the rebar was only 32 percent of 5 maximum in the vertical and about 50 percent 6 horizontally. So there was considerable amount of 7 margin.
8 So the concern we had though with these 9 laminar cracks is a concern about the potential effect 10 of the bond strength between the rebar and the concrete.
11 Obviously that was because we had identified that the 12 cracking was in the rebar mat. And in particular there 13 was a concern where we had laps on the rebar, whether 14 or not we'd have sufficient capability for those 15 splices.
16 MEMBER SHACK: Do you know how long those 17 laps are?
18 MR. BYRD: Yes, we do. The laps are in the 19 lower portion of the building. The laps are 79 inches.
20 That's the specification. And in the upper part of 21 the building, they're 120 inches.
22 MEMBER SHACK: Now is that consistent with 23 current code requirements? Three eighteen --
24 MR. BYRD: That would be --
25 MEMBER SHACK: -- for lap for that size bar?
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55 1 MR. BYRD: That would be larger than the 2 current code. I think Jon Hook could tell me what the 3 current code is. I think that's significantly larger.
4 MR. HOOK: Right, the -- it's either 5 consistent with or more conservative than the existing 6 code. And on the original AE, Bechtel was conservative 7 when they came up with a 120-inch splice up on top.
8 MEMBER SHACK: Thank you, John.
9 MEMBER STETKAR: Before you switch, I don't 10 do conversions from Richter to acceleration all that 11 well, as can nobody. Six to 6.5 Richter, are you saying 12 it's about --
13 MR. BYRD: I can give you the acceleration.
14 That's 0.08 g. That's maximum probable. Maximum 15 possible is 0.15.
16 MEMBER STETKAR: 0.15?
17 MR. BYRD: 0.15. That's correct.
18 MEMBER STETKAR: Thank you.
19 MR. BYRD: Okay. Going to the next slide, 20 please. So we understood that with these cracks in the 21 rebar that would be a concern with the bond between the 22 rebar and the margin. We also recognize with the very 23 tight cracks, there probably was a considerable amount 24 of bond strength, but we didn't have a method to quantify 25 it. We didn't have any specific testing that could tell NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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56 1 us what bond strength was left. So therefore we -- in 2 our analysis we performed prior to restarting we 3 conservatively treated all of the rebar in the shoulder 4 areas, in affected areas of the top 20 feet, and in these 5 main steamline penetration areas as non-existent in the 6 analysis. So we performed calculations to prove they 7 provide bounding evaluation.
8 And if you go onto the next page, the result 9 of that was that the -- even with these very conservative 10 assumptions of the lack of -- or not effectiveness of 11 the rebar in these regions, we didn't meet our 12 requirements with traditional margins of safety. So 13 that was the process we used to demonstrate that the 14 shield building was capable of performing its safety 15 functions.
16 If we can go to the next slide, please --
17 CHAIRMAN SIEBER: Now, its only safety 18 function is to provide shielding as opposed to 19 containing the pressure of the accident?
20 MR. BYRD: That is correct. It is not 21 designed to contain the pressure of the accident. It 22 does provided, as I mentioned before in the functions, 23 we do have the annulus base which we can take a suction 24 on with our ventilation, so it does provide a function 25 of being able to provide that controlled release of the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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57 1 annulus.
2 CHAIRMAN SIEBER: And so as part of the 3 original design you have the ability to have a controlled 4 release of gaseous material in the annular space between 5 the containment pressure vessel and the containment 6 shield building?
7 MR. BYRD: Correct.
8 CHAIRMAN SIEBER: Okay.
9 MEMBER STETKAR: The safety analysis 10 accounts for that, the availability of that interstitial 11 ventilation filtering system, or not?
12 MR. BYRD: I would have to ask Dennis 13 Blakely to respond to that question. He's our analysis 14 supervisor.
15 MR. BLAKELY: Dennis Blakely, engineering 16 analysis supervisor. The LOCA analysis does credit the 17 ability to take suction on the annular space through 18 our emergency ventilation system. It filters the 19 release prior to going to the environment.
20 MEMBER STETKAR: Thank you. Some do.
21 Some don't. That's why I asked. Thank you.
22 CHAIRMAN SIEBER: Well, the purpose of my 23 question is to establish clearly just what the function 24 of the building is, the structure is. And that 25 -- because it's different than other types of large dry NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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58 1 containers.
2 MR. BYRD: Okay. Next I'm going to talk 3 about the root cause. And while we were in the process 4 of doing the investigation that I just described, we 5 had established an independent root cause team which 6 was evaluating the root cause. And so what I'm going 7 to talk about here, I'll talk a little bit about the 8 team, the establishment of the team, talk about how we 9 put together our failure- modes analysis, discuss a 10 little bit of the testing we did, some of the concrete 11 testing analysis, and then explain what our root cause 12 was.
13 So the next slide, please. So early in the 14 process we did get Performance Improvement 15 International involved. And I'm sure that you're 16 -- most of you are familiar with Performance Improvement 17 International. They are very experienced. They've 18 performed over 500 root causes. But what was 19 particularly beneficial for us is they had done the root 20 cause on Crystal River, and as a result of doing that 21 root cause on the containment, they had developed 22 expertise in analytical methods for concrete, and they 23 also had a lot of expertise in concrete testing. So 24 that was very beneficial to us in getting our root cause 25 moving in a fairly expeditious manner.
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59 1 We also supplemented the Performance 2 Improvement International with other industry experts 3 and we used our on FENOC engineering as well. And we 4 did follow our own FENOC root cause process.
5 CHAIRMAN SIEBER: Crystal River is a 6 post-tension concrete vessel --
7 MR. BYRD: That's correct.
8 CHAIRMAN SIEBER: -- which is 9 substantially different in structural design from the 10 Davis-Besse containment building. And so the root 11 cause at Crystal River is not applicable here.
12 MR. BYRD: The root cause was completely 13 different --
14 CHAIRMAN SIEBER: Right.
15 MR. BYRD: -- I would agree, at Crystal 16 River. What was helpful to us however was having --
17 CHAIRMAN SIEBER: The analytical 18 techniques.
19 MR. BYRD: -- the analytical techniques, 20 the experience in testing concrete, some of that other 21 -- that was what helped with us.
22 CHAIRMAN SIEBER: Now as part of your root 23 cause analysis did you look into any aspect of the 24 composition of the concrete that was used as it came 25 from the batch plant and, for example, reactions within NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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60 1 the concrete such as was found at Seabrook?
2 MR. BYRD: Yes, we looked at that 3 extensively. In fact, Mr. Hook is going to be able to 4 explain that you.
5 MR. HOOK: Right, I think you're referring 6 to alkali-silica reaction.
7 CHAIRMAN SIEBER: That's right.
8 MR. HOOK: Right, so as part of our root 9 cause; and Ken will get to that in a little bit though, 10 we took over -- we took 90 core bores. Thirty-six of 11 those core bores we sent out to independent 12 laboratories. We used several laboratories to do that.
13 And that's one of the things they specifically looked 14 for, is chemical reaction. They did petrograph 15 examination and all of those tests came back as being 16 negative, meaning we had no indications of alkali-silica 17 reaction.
18 And so we also -- all the aggregate for the 19 shield building came from the same quarry as we used 20 for all the other concrete on the site. So we have no 21 indications of chemical reactions. So we have high 22 confidence that ASR is not an issue at Davis-Besse.
23 CHAIRMAN SIEBER: Okay. Now when 24 Davis-Besse was constructed, I presume you had your own 25 concrete batch plant?
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61 1 MR. HOOK: Right, we had a batch plant on 2 site. That's right.
3 CHAIRMAN SIEBER: Yes, you don't look old 4 enough to remember that, but I do.
5 MR. HOOK: I have seen pictures. But, 6 right. In fact, we had our own batch plant on site, 7 a central batch plant. And so all the concrete on site 8 was batched from that batch plant.
9 CHAIRMAN SIEBER: And you poured samples 10 daily --
11 MR. HOOK: Absolutely.
12 CHAIRMAN SIEBER: -- from the batch plant 13 and typically from each truckload as it was delivered 14 from the batch plant to the building construction site, 15 is that correct?
16 MR. HOOK: That's right. And as part of 17 our root cause investigation, we do look at the batch 18 records. We looked at QC reports. The sequencing of 19 the pours. The shield building was poured as slip form.
20 So we looked at all those construction records. We 21 looked at the 28-day concrete strengths that we did, 22 and the 90-day strengths. And they -- our design is 23 based on a 4,000-psi concrete, and the average 28-day 24 strength was about 5,800. So we had high concrete 25 strength.
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62 1 CHAIRMAN SIEBER: Yes, typically you can 2 meet the strength requirements. On the other hand, 3 typically the data that you get from the blocks that 4 you pour for testing do not contain chemistry data.
5 Do you have any chemistry data that corresponds to the 6 blocks that were tested for your concrete mixture as 7 it was put in place with the removable --
8 MR. HOOK: Right, so part of the mix design 9 process -- so we did evaluate the chemical and the 10 -- well, the coarse aggregate and the fine aggregate 11 met the ASTM requirements at the time.
12 CHAIRMAN SIEBER: Okay. And the water 13 content and the water purity was off the -- you have 14 records of those?
15 MR. HOOK: Right. It's all potable water, 16 correct.
17 CHAIRMAN SIEBER: And you verified that 18 those met the ACI standards at the time?
19 MR. HOOK: They met the ACI and the American 20 Society for Testing Materials standards. That is 21 correct. And as spelled out in our specifications for 22 that, correct.
23 CHAIRMAN SIEBER: Okay. Thank you.
24 MR. BYRD: Okay. Let's go to the next 25 slide, please. So this slide shows the fault tree of NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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63 1 failure modes that we used to investigate the condition.
2 So we had 45 failure modes and we grouped these into 3 three different categories. Those were design issues, 4 construction and fabrication issues, and then 5 operational phase issues. So each of these issues was 6 worked through methodically and we either eliminated 7 them or determined we needed to have additional 8 evaluation. So what you can see from this slide, the 9 ones that are circled in blue, those are the one that 10 were eliminated. And the one which are reddish or 11 orange, those were the issues that we performed 12 additional investigation on.
13 The next slide, please. So in order to do 14 the root cause we did extensive testing of the concrete.
15 We sent 36 core bores for testing at six different 16 locations. They subjected it to a number of different 17 tests. Tested for concrete properties, tensile 18 strength, compressive strength. They looked at thermal 19 properties of the concrete. And we also looked at some 20 of the issues which we were -- if there were chemical 21 attack. We looked for issues of micro-cracking. So 22 quite a bit of work was done. The tests came back 23 indicating, however, that the concrete quality was good, 24 conformed to our mix design, and the compressive and 25 tensile strength exceeded the minimum design NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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64 1 requirements.
2 So I'm not going to go talk about each of 3 these concrete tests we did, but there was there tests 4 I want to talk about that were maybe somewhat revealing 5 with regards to the root cause that we ended up coming 6 to.
7 So the first one; if go to the next slide, 8 was the manner in which the concrete fractured and 9 through the aggregate. And the picture you see here 10 is a piece of the concrete that we picked up in the area 11 of where we were doing the hydro-demolition. And as 12 you can see the surface of the crack is smooth. It 13 actually sheared through the coarse aggregate. And 14 that told us several things. We also saw this in the 15 core bore samples we took, which --
16 MEMBER ARMIJO: This is -- the crack's face 17 is in a vertical --
18 MR. BYRD: That's correct. The vertical 19 is the crack face. And you can see it goes through the 20 aggregate. It's very, very smooth. It told us several 21 things. It told us first of all that there was a -- a 22 considerable force was required to -- for that crack.
23 Our aggregate is not -- it is strong. We don't have 24 a problem with the aggregate. It told us we had good 25 bond between the aggregate and the paste. What that NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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65 1 told us, that this crack occurred in mature concrete.
2 This obviously wasn't something that occurred early 3 in the process before the concrete had time to gain its 4 strength.
5 Next slide, please. Another test that was 6 revealing is the inspection for micro-cracking. And 7 the slide here is a cross-section of the concrete sample 8 that was used to do an inspection for micro-cracking.
9 So we found no evidence of micro-cracking in the areas 10 near the laminar cracks. There was no sign of a cyclic 11 loading mechanism or a freeze-thaw mechanism. And what 12 this suggested to us, there was no indication of a 13 fatigue or an age-related event.
14 Now to be clear, there was in some of the 15 reports micro-cracking identified. That 16 micro-cracking was near the surface. So surface 17 cracking was identified. But in the vicinity of these 18 laminar cracks, which was really the area of interest, 19 we did not identify micro-cracking.
20 MEMBER ARMIJO: I just want to make sure.
21 Were these cracks just -- was it a one-planar crack, 22 or were there a number of just parallel cracks along 23 this?
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66 1 in the rebar, but I wouldn't say there was just one crack.
2 It was -- in some places --
3 MEMBER ARMIJO: So it's a zone where there 4 might be --
5 MR. BYRD: Yes, it might. And it might 6 meander around a bit. And then we would -- what we 7 concluded, the cracking was generally in a plane around 8 the inner -- outer rebar mat. But not to say that we 9 wouldn't have --
10 MEMBER ARMIJO: Yes, something --
11 MR. BYRD: Yes, like you're describing it.
12 CHAIRMAN SIEBER: But it was really 13 circumferentially as opposed to radially?
14 MR. BYRD: I'm sorry, sir?
15 CHAIRMAN SIEBER: It was oriented -- the 16 cracks were oriented circumferentially rather than 17 radially.
18 MR. BYRD: That's correct. That is 19 correct.
20 Okay. The next slide, please. The final 21 test I want to talk about is carbonation. And actually 22 we had a lot of evidence without actually testing the 23 concrete that carbonation was not the issue. And it 24 becomes -- first of all, it was the particular location 25 where we found the cracks. The cracks were -- as I NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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67 1 mentioned before, they were primarily in the outer 2 -- well, pretty much all in the outer rebar mat and mostly 3 in the shoulder region. The shoulder region is an area 4 where we actually have quite a bit of concrete cover.
5 On the thick side, you have almost 20 inches of concrete 6 cover. So that would suggest that carbonation was not 7 an issue.
8 Additionally, we had no evidence of degradation of the 9 rebar. We did inspect rebar that we removed in the area 10 where we had the construction opening. And we had no 11 indication, as I mentioned before, of surface spalling 12 in these areas that were cracked. All that suggested 13 that carbonation was not an issue.
14 However, I wanted to discuss this testing 15 because carbonation was discussed a lot and it was -- and 16 it's an aging mechanism. So what you can see here on 17 this picture, there's a dye. And the areas that are 18 pink are the non-carbonated areas. But the surface of 19 this concrete sample which was exposed to the atmosphere 20 you can see is the carbonated area. We found that in 21 general, average it was about a third of an inch we'd 22 get carbonation. Maximum, about a half of an inch.
23 And we have the three-inch cover over the outer rebar 24 mat, so that was sufficient for a -- of course this is 25 in -- in 40 years we had this much carbonation, so this NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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68 1 should not be an issue for the duration of the plant 2 through its extended life.
3 MEMBER ARMIJO: I may be the only guy in 4 the room that doesn't know what carbonation is, but could 5 you tell me what that is?
6 MR. BYRD: Sure. Carbonation is a process 7 where carbon dioxide in the air reacts with calcium 8 hydroxide, the lime in the concrete, and that forms 9 calcium carbonate. And it's not really a problem in 10 concrete. Actually it makes the concrete, if anything, 11 a little stronger. But the issue is is concrete 12 normally has a pH which tends to inhibit corrosion in 13 the areas where you have rebar. And carbonation will 14 actually affect the pH of the concrete. So if you were 15 to -- normally, if you were -- carbonation damage, what 16 would happen is you'd get carbonation that would go deep 17 enough so it gets to the point where you have your rebar 18 mat. At that point you're affecting the pH. Then you'd 19 get corrosion of your rebar. Then you'd see the rebar 20 would start expanding. You'd see spalling and cracking 21 in the concrete. I mean, that's typically what you 22 would you see for carbonation damage.
23 MEMBER ARMIJO: All right.
24 MR. BYRD: So as I mentioned before, we 25 didn't see any spalling, any damage to the rebar.
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69 1 Additionally, we've got maximum half an inch with 2 three-inch cover, so it's really not a concern.
3 MEMBER ARMIJO: Okay. Great.
4 MR. BYRD: Okay. Next slide, please. So 5 to summarize what we saw with our concrete, so the crack 6 passed through coarse aggregate and that told us we had 7 a strong bond between the paste and the aggregate and 8 the crack occurred in mature concrete. It also told 9 us we had to have a pretty large force to initiate that 10 crack.
11 CHAIRMAN SIEBER: So you had evidence that 12 the aggregate itself had cracked and split?
13 MR. BYRD: Oh, absolutely. The aggregate 14 -- the crack went right through the aggregate. That 15 shear picture you saw, you know, if you see it close, 16 you would see the aggregate was actually sheared 17 straight through. And as I said before, our aggregate 18 is local limestone. It's reasonably hard and it's -- so 19 it was a considerable force.
20 So we also identified no micro-cracks in 21 the vicinity's laminar crackings that would indicate 22 freeze-thaw or cyclic event.
23 Chemical properties, as I mentioned, we did 24 carbonation. And as Mr. Hook mentioned, we also looked 25 for alkali-aggregate reaction. We looked for sulfate NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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70 1 attack and any kind of acid damage. We didn't see any 2 indication of chemical attack. So based on that we were 3 able to rule out concrete as an initiating or a 4 contributing cause. We also gained some additional 5 information. We pretty much told us this appeared to 6 be an event that had occurred which had caused this 7 crack, rather than some kind of a cyclic or a 8 fatigue-type of a mechanism.
9 CHAIRMAN SIEBER: Okay. And Lake Erie is 10 a freshwater lake, right?
11 MR. BYRD: Lake Erie is a freshwater lake.
12 That is correct.
13 CHAIRMAN SIEBER: And can we conclude that 14 atmospheric conditions do not contain any unusual 15 chemistry that you might find near a seashore? For 16 example, industrial plants sometimes emit things that 17 can deposit on concrete and changes its physical and 18 chemical characteristics. You have no industrial 19 plants close to Davis-Besse?
20 MR. BYRD: Where we are -- as I mentioned, 21 we're in a wildlife refuge, so there's really no 22 -- there's no industrial plants. They would -- you 23 would have to be 30 miles away to Toledo, or it's probably 24 50 miles or 60 miles to Cleveland. So we're not in an 25 area that's --
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71 1 CHAIRMAN SIEBER: My recollection is that 2 the closest coal-fired power plant is about 30 miles 3 away, 35 miles away.
4 MR. BYRD: About that, that's correct.
5 CHAIRMAN SIEBER: Okay. And I don't 6 recall any others along Lake Erie until you get to the 7 area where Perry is.
8 MR. BYRD: That's correct.
9 CHAIRMAN SIEBER: Okay. Thank you.
10 MR. BYRD: Okay. Next slide, please. So 11 the next thing we looked at was shield building 12 configuration. And actually looking at the 13 configuration of the cracks did provide some pretty 14 valuable insight. And I mentioned before, cracking is 15 predominantly located in the shoulder areas in the top 16 20 feet and in the main steamline penetration 17 block-outs, and it was concentrated on the southern 18 exposures. So as we looked at the crack locations and 19 looked at the details which I previously described to 20 you of the shield building, several things became fairly 21 apparent. One is that the shoulder areas are regions 22 of discontinuity. In other words, we have these 23 shoulders built on. And there was -- and was pointed 24 out, there's limited radial reinforcing steel in those 25 areas. So based on that we decided that was an area NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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72 1 that we'd want to investigate further.
2 Another thing we noticed is the top 20 feet 3 of our shield building has more horizontal 4 reinforcement. The horizontal reinforcement, which is 5 this No. 11 rebar, is every since 6-inch spacing until 6 you get to the top 20 feet and then it goes to -- I'm 7 sorry, it's 12-inch spacing, thank you, until we get 8 to the top 20 feet in which it goes to 6-inch spacing.
9 And actually we noticed in some of our 10 impulse response testing the really good correlation 11 we got. Up above into the higher-density rebar we start 12 seeing laminar cracking outside of the shoulders. So 13 we decided that obviously the density of the rebar was 14 something that would be -- warrant further 15 investigation.
16 And we also were aware that around the main 17 steamline penetration block-outs there's another area 18 where we have dense rebar around the block-outs.
19 Because the cracking we saw around the block-outs, 20 within the block-out itself there was no cracking at 21 all. In fact, we could actually use an impulse 22 response. We could trace the block-out itself. But 23 we find the cracking was actually occurring around the 24 edge of the block-out. We could actually see the 25 corners of the block-out in the impulse response NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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73 1 testing, which was quite remarkable. So that told us 2 there was again -- appeared to be a correlation between 3 rebar density and the cracking we were observing. And 4 then finally there was clearly this south versus north 5 orientation. That was something else we needed to do 6 some further investigation of.
7 MEMBER ARMIJO: And you'll get into that 8 when you get to your root cause --
9 MR. BYRD: Yes, I will.
10 MEMBER ARMIJO: -- to show why south?
11 MR. BYRD: I will.
12 MEMBER ARMIJO: Why top 20?
13 MR. BYRD: Absolutely.
14 CHAIRMAN SIEBER: Rebar density in a 15 containment design like Davis-Besse is far less than 16 those where the containment building is actually a 17 pressure barrier. Is that not correct?
18 MR. BYRD: That would be correct.
19 Okay. So we -- going onto the next slide, 20 please. So we did a number of detailed analysis to 21 better understand -- and again, I mentioned the shoulder 22 areas appeared to be a discontinuity and something to 23 further investigate. So we did a number of very 24 detailed analysis to understand how these shoulder areas 25 responded to various loading conditions. And the first NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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74 1 area that we really looked at seriously was thermal 2 conditions. Looked at -- and to do this we evaluated 3 32 different thermal conditions. In other words, 4 winter, summer, various different combinations of 5 inside and outside temperatures. Did screening on 32 6 of those. And then we did a more detailed evaluation 7 on the most -- the top six events. And then for those 8 events we combined the thermal stresses with stresses 9 caused by dead weight and wind.
10 And the results of all of this though was 11 that the radial stresses -- well, first of all, the 12 radial stress was maximized in summer conditions, hot 13 summer conditions. But when we combined the thermal 14 stress with the dead weight and wind loads, we didn't 15 come up with stresses that were nearly sufficient to 16 create the kind of cracking we saw. The maximum was 17 about 300 pound per square inch. That's about half of 18 the -- what would be required to create the cracking.
19 So the other thing we looked at was unusual 20 events that have occurred. And we did have a tornado.
21 It was a category 2 tornado which had been in the 22 vicinity of the plant; I don't believe it actually struck 23 the shield building, and that was in 1998. We did 24 evaluate wind loads. Wind loads based on this model 25 were not even -- very insignificant for those kind of NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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75 1 wind conditions. So we'd eliminated thermal 2 conditions, which actually when we first looked at this 3 was very suggestive on the south side, and eliminated 4 the tornado, determined those weren't sufficient for 5 cracking.
6 Next slide, please. So what we had is we 7 understood that we had an event, as I said before, from 8 the concrete. This was a event-driven event. So at 9 this point we did research into additional industry 10 experience to determine if there was other similar 11 conditions.
12 So if we'd go to the next slide, I'll talk 13 a little bit about the operating experience we 14 identified. Okay. As I mentioned before, for 15 operating experience we had Performance Improvement who 16 had performed the root cause on the Crystal River laminar 17 cracking. However, it was also pointed out here 18 previously, the Crystal River really didn't apply to 19 Davis-Besse. They have a post-tension containment.
20 We have a freestanding containment. The conditions, 21 they had some concrete quality issues. And as I 22 mentioned before, we didn't appear to have any concrete 23 quality issues. So really there was not any correlation 24 we could get between Crystal River and Davis-Besse.
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76 1 experience from the Ontario Ministry of the Environment.
2 They'd done a study of above-ground water tanks up in 3 Ontario and the conditions that they'd found was that 4 the water tanks -- in the winter you would have the -- the 5 water would penetrate the concrete on the inside of the 6 tank. And then when you got very cold weather, the 7 moisture in the concrete on the inside was expanding.
8 The cold weather was also causing the exterior to 9 contract and that was creating high radial stresses in 10 these tanks and actually was causing laminar cracking 11 in the tanks. So that suggested to us another possible 12 failure, which could be moisture penetration and 13 freezing.
14 Now obviously Davis-Besse is not a water 15 tank, and so we were looking at it really from the other 16 way around, having water penetrating from the outside 17 and then having very cold temperatures. So we 18 considered some potential for water penetration, and 19 it appeared the most probable cause would be high wind 20 and rain that could cause water penetration.
21 So going to the next slide, please. So we 22 investigated potential conditions where we could have 23 had water penetration in the shield building followed 24 by extreme cold. And the most significant 25 environmental condition was in the winter of 1978, which NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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77 1 also was the worst environmental condition in recorded 2 Ohio history in terms of moisture, temperature, wind 3 and duration.
4 If you'd go to the next slide. So on 5 January 25th through 27th of 1978, it rained several 6 days and we had -- actually the temperatures were in 7 the 40s during that period. There were high sustained 8 winds. There were gusts of over 100 miles an hour in 9 the vicinity of the plant. We had very low 10 temperatures. Temperatures then dropped down to 11 approximately 0 degrees Fahrenheit. We had sustained 12 low-temperature conditions for several days. So those 13 really are the conditions that occurred in '78.
14 So if you go to the next slide. So the 15 scenario for the event that we proposed was if we had 16 heavy rains preceding a blizzard and that caused 17 moisture to penetrate the exterior surface of the 18 concrete, and we had a drop in temperature to well below 19 freezing and that would freeze -- and strong winds, that 20 would freeze the outer concrete, the moisture in the 21 outer concrete. And then with no radial reinforcing 22 in the shoulder areas, the radial stresses that we were 23 developing in the building were exceeding the capability 24 of the concrete, tensile capability of the concrete.
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78 1 All right. So next slide, please. So in 2 order to demonstrate that this was in fact a credible 3 theory, we did develop a computer model of the shield 4 building to evaluate the condition. Used thermal 5 properties from the concrete which we used from some 6 of these core tests that we'd performed. There were 7 laboratory tests performed which demonstrated that 8 moisture infiltration could be up to four inches for 9 the particular wind duration and strength that we had 10 during this storm. What the model did show is that our 11 maximum radial stress is approximately 550 pounds per 12 square inch. And as you can see from this picture, the 13 radial stress was concentrated precisely in the area 14 where we saw -- primarily we saw the cracking. So again, 15 this was consistent with what we saw in the root cause.
16 We also -- I just want to make a point here.
17 We did look at other events other than the storm of 18 1978. We did look at some of the other significant 19 storms we've had and we didn't find any other storm.
20 We actually evaluated -- I think the second worst was 21 in 1977. We didn't find another storm that had the right 22 combination of rain, cold and duration to create this 23 event. So that's why we believe this occurred in 1978 24 and not at another period of time.
25 Okay. So that explained -- at least this NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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79 1 created for us in our minds a plausible explanation for 2 the cracking we saw in the flute shoulders. We still 3 also had the other issue with the cracking in the 4 high-density rebar areas. So here we did a computer 5 model to do a sensitivity analysis of cracking in 6 high-density rebar. And this evaluation demonstrated 7 that the laminar cracks are more likely to occur in 8 regions where we have closely-spaced rebar. We did an 9 analysis with 12-inch versus 6-inch rebar. And so that 10 established that the rebar spacing was a probable 11 contributing factor. And what we believe occurred was 12 that the cracking would have been initiated in the 13 shoulders and then propagated into some of these areas 14 where it's more -- where it's more likely in the 15 high-density rebar areas. And we think that occurred 16 both in the shoulders and in the main steamline 17 penetration block-out areas.
18 Okay. To summarize what we got from the 19 analysis. So to summarize, the normal temperature 20 -- when I say "normal," the extreme temperature 21 conditions weren't sufficient to create radial stresses 22 that could cause cracking. We did not find sufficient 23 -- any -- high-wind was not sufficient. We did find 24 though that this moisture freezing could cause stresses 25 in the shoulder areas that could result in the cracking.
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80 1 So that appeared to be a plausible event that occurred.
2 We also found that the closely-spaced reinforcing steel 3 was a -- could be a contributor to the laminar cracking.
4 5 And then finally, the observed cracking.
6 And this is very important what we actually saw, and 7 I'll show it in a few slides from now, the picture of 8 our impulse response testing. What we found in the 9 cracking very much coincides with the areas of high 10 stress. The cracking was in the flute shoulders, in 11 the areas of high-density rebar, and it was also 12 concentrated on the southern exposure, which would have 13 been the direction we would have had the storm coming 14 from and the moisture penetration. So again, it had 15 good correlation with this theory with the actual facts 16 we'd obtained from investigating the shield building.
17 MEMBER ARMIJO: That southern exposure 18 argument sure doesn't really tell me much, because 19 that's a big storm. The whole plant's affected.
20 Moisture's -- I'm sure it didn't rain just on one side 21 of the building.
22 MR. BYRD: No, it rained, but the southern 23 exposure -- the issue is the direction of the wind, 24 because the wind was an important -- would have been 25 an important in providing the force for the moisture NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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81 1 penetration in the shield building. And as you can see 2 from the picture, it isn't that there's not cracking 3 on the northern side. It's just there is more extensive 4 cracking on the southern side of the building.
5 So finally, to go to our root cause, really 6 there was many things, or several things acting together 7 that caused cracking to occur. So we had the 8 discontinuity on the shoulders with the lack of radial 9 reinforcing rebar. We had the areas of high-density 10 rebar. Then we had the particular storm with high 11 moisture, severe winds and very low temperatures.
12 However, for us to establish -- for our process and root 13 cause it had to be something that we could eliminate 14 to prevent recurrence. So we identified the root cause 15 for our -- to be a lack of water sealant on the exterior 16 of the building.
17 If you'd go to the next slide, please.
18 DR. BARTON: I've got a question on it.
19 MR. BYRD: Yes?
20 DR. BARTON: So you're going to seal the 21 building?
22 MR. BYRD: We are in the process of doing 23 that now. That's correct.
24 DR. BARTON: The question I've got is how 25 do you know that there's no water trapped inside this NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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82 1 concrete before you're sealing it?
2 MR. BYRD: Well, there probably is some.
3 We have taken samples very recently. Mr. Hook, can 4 you talk about the samples we took of the concrete?
5 MR. HOOK: Right, so there is some moisture 6 in the concrete always. It's not like bone, bone dry.
7 But part of the root cause investigation and the 8 sensitivity analysis that we needed to have, we need 9 to have high moisture content in the concrete for this 10 -- for the freezing and expansion to occur. That was 11 in the area of 90-plus percent of concrete. So concrete 12 breathes and normally the concrete that's out there is 13 in the range of 40 to 60 percent. So those moisture 14 levels are well below the threshold that's needed to 15 cause any expansion. So when we paint the building, 16 whatever moisture is there, it has no effect at all.
17 And also keep in mind though the inside of the wall 18 is not painted. So that's also an opportunity for the 19 concrete to breathe on the inside in the annulus area.
20 DR. BARTON: So you've looked at -- even 21 though you've got some moisture in there, you've looked 22 at weather conditions, severe weather conditions, and 23 you're convinced that that won't cause cracking to 24 expand?
25 MR. BYRD: That's correct. And then we're NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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83 1 following the manufacturer's instructions on how to 2 paint the concrete. And so you need to have certain 3 humidity and temperature requirements. And obviously 4 you can't paint the concrete when it's wet. So we are 5 following all of those requirements as well.
6 DR. BARTON: Thank you.
7 CHAIRMAN SIEBER: As part of your overall 8 investigation, I notice the slide which shows the map 9 and the path of the storm of January 1978 is pretty 10 extensive. It covers the entire state of Michigan from 11 Central Illinois to Gary, Indiana and about half of the 12 State of Indiana and reaches to Toledo and appears to 13 be on the edge of the excessive area appears to be where 14 the Davis-Besse appears. Did anyone look at other news 15 stories or event reporting from that storm to determine 16 whether other structures were damaged by any kind of 17 a phenomenon that you believe occurred here at the 18 Davis-Besse plant?
19 MR. BYRD: Well, if your question is did 20 we have -- did we find any other evidence of laminar 21 cracking caused by moisture penetration, the answer 22 would be no. The only -- and we looked pretty 23 extensively through operating experience and what we 24 found was this Ontario Ministry -- the information we 25 found on the water tanks was actually online. So we NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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84 1 did not find evidence specifically of cracking that was 2 attributed to this storm.
3 CHAIRMAN SIEBER: Well, most industries 4 don't have a reporting structure similar to that --
5 MR. BYRD: And we understand that and 6 that's why we looked extensively. We didn't find the 7 Ontario Ministry of Hydro through the normal reporting 8 structures. Obviously it would be difficult, and as 9 I mentioned in our root cause, there were some unique 10 characteristics of Davis-Besse; the flute design and 11 so forth, that along with this storm contributed to the 12 laminar cracking. So -- and but there was certainly 13 a lot of news. The storm of 1978 was a very significant 14 event in the Midwest. So obviously at the time there 15 was a lot of news coverage, but I don't believe there 16 was any trouble with laminar cracking.
17 CHAIRMAN SIEBER: All right. Thank you.
18 MEMBER ARMIJO: How does your root cause 19 explain the absence of cracking at the surface? Visible 20 cracking. In other words, all the cracking is inside 21 in this -- between the shoulder and the -- you know, 22 the outer steel. But the cracks don't penetrate to 23 let's say the notch.
24 MR. BYRD: No, and the reason --
25 MEMBER ARMIJO: And they -- you know, so NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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85 1 what's the explanation for that?
2 MR. BYRD: If we could go back to the slide 3 that shows the rebar design of the shoulder. I'm not 4 sure which number it is.
5 CHAIRMAN SIEBER: Way back.
6 MR. BYRD: It's pretty far back. I can 7 explain that.
8 MEMBER ARMIJO: Twenty-one?
9 MR. BYRD: That's correct.
10 MEMBER ARMIJO: Where the hooks are?
11 MR. BYRD: Yes, the explanation is, as I 12 mentioned, the crack occurred and it was stopped before 13 it got to those -- that inner -- or the radial reinforcing 14 rebar on the inside. And actually on some of these 15 shoulders we drilled on the shoulder four core bores 16 on the same -- at the same horizontal plane. And if 17 you could point with your mouse, we did one core bore 18 on the shoulder on the outside of the rebar there.
19 MEMBER ARMIJO: Yes.
20 MR. BYRD: And one on the insider. It 21 shows we did one right here. We managed to get a core 22 bore in there. And we do the core bore on the other 23 side. Well, I'm sorry, we did one core bore up adjacent 24 to the rebar here and we found we did not have cracking 25 up beside the rebar. Then we went over. We found NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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86 1 cracking. So the crack was actually stopped by the 2 rebar. Then on the other side we drilled the same thing.
3 We drilled a core boring here and we found no cracking 4 right adjacent to the radial reinforcement. So we were 5 able to demonstrate with our core bores that actually 6 that radial reinforcement was in areas out -- like it's 7 up on the 20 feet. The cracking would be restricted 8 between that area. Then on the top 20 feet we found 9 that we did have some cracking that would go outside 10 through this area. But it didn't go beyond these hooks 11 on the inside.
12 MEMBER ARMIJO: But you would have expected 13 that the water penetration would be greater in near the 14 surface?
15 MR. BYRD: That's correct.
16 MEMBER ARMIJO: And in that corner notch 17 where you have a stress concentration, plenty of access 18 to water. Yet it didn't crack there.
19 MR. BYRD: It didn't crack there except on 20 the -- in the -- some areas in the top 20 feet we found 21 cracking. But again, that cracking was along the -- in 22 this rebar mat and again there's still a cover of 23 concrete on that as well. So it was actually in the 24 -- it was always covered with concrete on the cracking.
25 And that's actually -- you know, we did not -- in the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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87 1 carbonation samples we took we didn't find extensive 2 carbonation in the crack regions either. So that would 3 indicate that these cracks had been -- not been exposed 4 to the air.
5 MR. ALLEN: What's unique about the design 6 here is that if the shoulders were not present, even 7 with the moisture, the wind, we would have had no 8 cracking.
9 MEMBER ARMIJO: Oh, I agree with you there.
10 11 MR. ALLEN: But discontinuity Ken talked 12 about, rather than a right circular cylinder which can 13 expand and contract uniformly, it's sitting there 14 essentially shrugging with those shoulders as it's 15 moving. And you have to have that stress concentration 16 plus the moisture and freezing for it to be an issue.
17 And then it propagates.
18 MEMBER ARMIJO: You know, the argument 19 -- I'm just -- I'm skeptical about the moisture and 20 freezing part of your root cause. The thermal analysis 21 surprised me, that that didn't provide sufficient 22 stress. Just -- it's a -- looks like a design flaw.
23 Not the shield building integrity, but the flute 24 attachments. You know, I think -- and if it isn't 25 related to moisture, then painting isn't going to do NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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88 1 any good.
2 MR. ALLEN: Well, first of all, maybe Dr.
3 Chiu could discuss that a little bit more from 4 performance improvement and what we did for evaluating 5 thermal versus moisture.
6 DR. CHIU: What was the question? Can you 7 repeat that question?
8 MEMBER ARMIJO: Yes, you know, why isn't 9 this -- why do you need the moisture from one event, 10 one storm caused all this damage as opposed to it just 11 being a design flaw and the thermal stresses over time 12 just simply created cracks without the need for any kind 13 of moisture?
14 DR. CHIU: I think the reason for that is 15 because the -- as you look at a corner, we have water 16 penetrated on both directions, goes through the 17 crystallization of concrete, would generate a lot more 18 expansion than thermal. It's almost a factor of three.
19 So with the water crystallization-induced expansion, 20 it's lot more severe than thermal. You can imagine if 21 the thermal is -- in Arizona we have so much hot weather, 22 120 degree Fahrenheit, the fluting didn't report an 23 crack. And we just finish another analysis at another 24 power plant in the south that has flute. But you just 25 look at thermal, it not going to have any laminar crack.
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89 1 So you really need both, very high thermal expansion 2 -- I mean, crystallization-induced expansion.
3 MEMBER ARMIJO: Okay. Well, near the 4 surface I would expect more water, more crystallization 5 so that cracks should penetrate to the surface at those 6 notches and elsewhere, but in every case, at least the 7 way it's been described, the cracking is varied inside.
8 It doesn't penetrate to the surface. So I'm just 9 -- can't understand.
10 MEMBER SHACK: It needs constraint. It's 11 free to expand at the outer surface.
12 MEMBER ARMIJO: Right.
13 MEMBER SHACK: You know, so he has to build 14 up constraint before he can build up some force. So 15 I can understand that you wouldn't see cracking at the 16 surface. I'd have to be somewhere underneath where I 17 have enough restraint so I can build up a radial stress.
18 You know, in plane it's going to be compressive as it 19 expands. And at the outer surface it's going to be free 20 to expand. Somewhere in the middle, things are going 21 to go wrong.
22 But I was -- My question is do you actually 23 -- did you do measurements of the expansion of 24 water-saturated concrete as it freezes, or is this some 25 model, or you just put in enough expansion to get NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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90 1 whatever you needed?
2 DR. CHIU: We did a test. We did a test.
3 As you know, that only this type of concrete -- certain 4 type of concrete, when the water diffuse into concrete, 5 it can cause the crystallization-induced --
6 MEMBER SHACK: Yes, when you say "cause 7 crystallization," are we talking about water freezing 8 and expanding, or we're talking about a change in the 9 concrete property?
10 DR. CHIU: Water.
11 MEMBER SHACK: Water?
12 DR. CHIU: Water.
13 MEMBER SHACK: Okay. So the --
14 DR. CHIU: And the critical point is void 15 fraction. For typical concrete, like household, your 16 house. The void fraction is very, very high, probably 17 four percent, five percent. When water diffuse into 18 the concrete, it's sort of goes away. You don't have 19 that expansion. But when the nuclear grade, we have 20 very, very tight void. We control the quality very 21 well. The void fraction is like three percent, two 22 percent. Then we have water diffuse into concrete.
23 You would expect.
24 So what we did is we did a test at the 25 University of Colorado by Dr. Xi and reproduced this NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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91 1 -- I call it crystallization-induced expansion. And 2 we really reproduced that. As you drop the temperature, 3 the thermal expansion coefficient, you will -- the 4 concrete will shrink. By the certain temperature and 5 certain void fraction of that concrete the -- absolutely 6 the thermal coefficient will turn around. When that 7 turn around, that is the problem.
8 MEMBER ARMIJO: Well, I think we'd like 9 -- I'd like to see that test result and the analysis.
10 Because, you know, what you're saying may be fine, but 11 it just seems that the denser concrete, smaller void 12 fractions, the penetration rate of the water would be 13 slowed down just doesn't seem to hang together. But 14 maybe if I read the report, I'll understand it better.
15 MEMBER SHACK: Well, did you actually try 16 tests with different void fractions of concrete?
17 DR. CHIU: No, we only test this concrete.
18 MEMBER SHACK: This concrete?
19 DR. CHIU: But in the Canadian paper they 20 do alluded to that was their test with high-void fraction 21 concrete. They don't have that denominator.
22 MEMBER ARMIJO: Okay.
23 DR. CHIU: Only in certain concrete.
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92 1 during that storm?
2 MR. BYRD: That was the conclusion of our 3 root cause. That is correct.
4 MEMBER ARMIJO: Okay.
5 MR. BYRD: This was an event we believe that 6 occurred during the storm.
7 MEMBER ARMIJO: And it wasn't detectable 8 because it didn't -- never penetrated to the outside?
9 MR. BYRD: It was -- it never penetrated 10 to the outside and it --
11 MEMBER ARMIJO: That's the thing that 12 bothers me the most.
13 MR. BYRD: And it did not -- in our previous 14 construction opening we had cut in 2002 or 2003, we did 15 not cut that -- because we actually cut that construction 16 open entirely within the confines of our -- the original 17 construction opening, and that is not an area where we 18 had any evidence of this kind of cracking.
19 And to further comment on your -- because 20 what your insight was, when I first this I was completely 21 convinced this was thermal.
22 MEMBER ARMIJO: I'm still convinced, but 23 it's --
24 MR. BYRD: Well, because it was on the south 25 side and I saw it there and that was what I thought.
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93 1 You know, I'll have to admit it took awhile for me to 2 come around to this, but the very strong -- actually, 3 I mentioned before on the -- this is no evidence of any 4 kind of a cyclic or a fatigue-type of an event. So this 5 occurred as one event. And that's based on actually 6 the concrete. So not only do we have the analysis that's 7 aligned with what we observed with the concrete -- so 8 I just want to point that out that it appeared to be 9 an event with enough force to have created this, and 10 which would have been a pretty significant amount of 11 force.
12 MEMBER ARMIJO: Okay. Well, I still would 13 like to get a copy of that report, if it's available.
14 CHAIRMAN SIEBER: Yes, there is a root 15 cause report.
16 MEMBER ARMIJO: Yes. Yes, particularly 17 that test that Dr. Chiu --
18 MEMBER STETKAR: You're looking for the 19 University of Colorado test?
20 MEMBER ARMIJO: Yes.
21 CHAIRMAN SIEBER: Yes, that's different.
22 That's not in the report.
23 MR. BYRD: Okay. If I could move on, 24 unless there's another question. I believe we're on 25 slide No. 50.
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94 1 Okay. So we had identified the root cause 2 to be a lack of concrete sealer. And for that particular 3 root cause there was really one practical corrective 4 action that we could take to prevent recurrence, and 5 that was to coat the exterior of the building. And as 6 I mentioned before, that coating is in progress right 7 now. In fact, the photograph we have here shows some 8 of the recent coating activities. We're at this point 9 approximately 75 percent complete with our project to 10 coat the entire shield building.
11 CHAIRMAN SIEBER: Yes, what's the coating 12 material?
13 MR. BYRD: So the walls are going to be a 14 latex acrylic primer and a styrene acrylic top coat.
15 And the dome is a polyurethane.
16 CHAIRMAN SIEBER: Okay. So you're 17 painting it?
18 MR. BYRD: That's correct.
19 CHAIRMAN SIEBER: Okay.
20 MR. BYRD: Next slide, please. So we also 21 identified several additional corrective actions as a 22 result of our root cause. And those corrective actions 23 included completing the impulse response examinations 24 of the shield building wall. They included performing 25 impulse response mapping of another structure which was NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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95 1 in this case the auxiliary building to confirm the 2 assumptions of the analysis. We did also developed and 3 implemented a test program to establish the capability 4 of the bond between the rebar and the concrete in the 5 area of the laminar cracks, and we developed a long-term 6 monitoring program. So I'll briefly describe each of 7 these corrective actions and what we're doing in these 8 areas.
9 MEMBER SHACK: Just a quick question on the 10 analysis again. You said you gave up on all the regions 11 of cracking on the lap strength.
12 MR. BYRD: That's correct.
13 MEMBER SHACK: Now, I mean, you did a full 14 -- I mean, we keep seeing pictures of membrane-kind of 15 regions here. Do you -- but you did a full stress 16 analysis including the bending regions. I mean, that's 17 why I have dense rebar at the top is I've got flexural 18 strength up there.
19 MR. BYRD: That's correct.
20 MEMBER SHACK: And you do that -- even with 21 the zero lap strength, you can still meet all your design 22 requirements?
23 MR. BYRD: That is correct. That is 24 correct. The pictures I've been showing here were done 25 as part of the root cause, and that was done NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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96 1 independently of the analysis done for the -- to 2 determine flexural integrity.
3 Okay. So I'll go to the next slide, which 4 will be No. 52. So we did complete the impulse response 5 testing on the shield building this summer. So we did 6 all accessible areas of the shield building wall, and 7 that was over 60,000 individual points. So you can see 8 the work going in progress with a couple of scaffolds 9 up on the building. And actually in this picture you 10 can see our most recent construction opening directly 11 under that one scaffold.
12 So what the -- going onto the next slide, 13 please. What this impulse response testing did, it 14 validated the original assumption that laminar cracking 15 was generally confined to the shoulder areas, top of 16 the building and regions of the main steamline, and it 17 was more concentrated on the southern part of the 18 building.
19 We also validated this by doing impulse 20 response testing on an independent site structure and 21 we selected a portion of the auxiliary building. And 22 the portion we did had some of the susceptible 23 characteristics. It was -- actually we did an area 24 above a large opening. It was above the train bay door 25 on the auxiliary building on the southwest side of the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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97 1 building. However, the auxiliary building has -- it 2 has a coating -- it has had a coating put on it for the 3 life of the building. And we did not detect laminar 4 cracking on the auxiliary building.
5 So the next slide, finally we get to this 6 impulse response mapping -- testing map that I've been 7 talking about. And there are a couple areas I want to 8 point out. First of all, the magenta areas on this are 9 areas of the building which are areas of higher mobility, 10 and that would suggest that we have laminar cracking 11 in those regions. And you can see that the laminar 12 cracking is generally confined to the shoulders. YOU 13 can see how it's going down on the shoulders. You also 14 see it spilling out into the top 20 feet. And if you 15 look on the lower left-hand side, you can see the azimuth 16 down there. You see zero azimuth. That's north. And 17 so you notice on the north side we have relatively 18 limited cracking on the north side of the building as 19 opposed to what we see on the south side of the building.
20 So again, the -- what we had identified here is 21 consistent with what we saw during the -- consistent 22 with what we developed in the root cause.
23 Okay. The next slide, please. So as I'd 24 previously described in our analysis we did, we 25 considered the reinforcement to be non-existent in NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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98 1 regions of laminar cracking. And although we're aware 2 that there was probably a considerable amount of 3 concrete to bond strength in those areas, so we did 4 develop testing at two universities, and these were 5 developed by professors who are experts and members of 6 the American Concrete Institute. The picture you see 7 here is a test that's ongoing at -- that was ongoing 8 at one of the universities. That's about a 40-foot beam 9 there. That beam has two -- actually it has four pieces 10 of No. 11 rebar imbedded in it and they're spliced in 11 the center of the beam. And you can see there's 12 hydraulic rams on either side of that beam and they're 13 putting the -- applying force to that beam until it 14 fails.
15 The next slide, please. So the two 16 universities used two different methods to create the 17 laminar cracks. At one university they used a -- they 18 cast the beam in two halves. So we had a cold joint, 19 or actually a weak joint down the middle on the plane 20 of the splices on the rebar. The other university, they 21 applied the force until they got a crack and then they 22 relieved the force and then they reapplied force to crack 23 it. The picture you see here is the second method, and 24 you can see that the crack that was created is 0.02 25 inches, which is greater than any crack we saw in the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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99 1 shield building.
2 Next slide. So the results of the 3 cracking, both universities demonstrated that in the 4 area of the longer lap splices, the 120-inch lap slices 5 on the top portions of the building, we got full 6 capability from the rebar. In the areas where we had 7 the shorter lap splices, the 79-inch, the results 8 differed slightly depending on the method. At one 9 university we got full capability. The other was very 10 close to full.
11 So in conclusion, what we could determine 12 was -- first of all, we did testing at two different 13 sites using two different methodologies that were 14 independently developed so we had very confidence in 15 the results of what we'd obtained. Tests demonstrated 16 that there was considerable bond strength remaining 17 between the concrete and the rebar in these regions of 18 cracking. And the testing was also conservative and 19 the -- as I mentioned before when we created this beam 20 we had two lap splices right in the area where we were 21 applying the stress. The way the building was actually 22 designed these were staggered, so you have a lap splice 23 and you have a -- then you have rebar that's continuous.
24 So the results we have are conservative actually to 25 the actual design of the building.
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100 1 All right. Finally, I'll go to my last 2 slide here for the shield building, we established a 3 long-term monitoring program. Now as I mentioned 4 before, we had concluded that the laminar cracking is 5 based on an event rather than an aging mechanism and, 6 you know, that conclusion is supported by the concrete 7 testing we performed. It's also supported by the 8 analysis. However, you know, we've also monitored the 9 shield building. We've monitored the shield building 10 cracks now three times. We've monitored existing core 11 bores three times since we started up back in December 12 and we've noticed no change in either un-cracked or 13 cracked core bores that we've investigated.
14 So though we don't expect this cracking to 15 propagate, we do -- we are putting in place a long-term 16 monitoring program and that building will -- and that 17 program rather will inspect existing core bores for 18 crack propagation. So we'll be inspecting core bores 19 that are cracked to determine if the cracks changes and 20 we'll also being inspecting core bores that are 21 un-cracked and generally we're inspecting ones that are 22 adjacent to each other so we could see if there was any 23 change. We're also inspecting the integrity of the 24 shield building coatings and inspecting the integrity 25 of the coatings of other safety-related buildings.
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101 1 And our picture here shows a couple of our 2 engineers who are monitoring an existing core bore for 3 any change that we would see in the cracking or the 4 monitoring of the boroscope.
5 So that would complete my discussion on the 6 shield building. Unless there's any further questions, 7 I will turn it back over to Mr. Custer here.
8 MR. CUSTER: Yes, and as Ken had said, the 9 essence of the program is as he described; monitoring 10 more cracking in the core bores and looking at the 11 protective coating. That aging management program has 12 been submitted to the staff for review.
13 So in summary, the application's been 14 reviewed, in many cases reviewed to NUREG-1801 Rev 2.
15 There are 43 aging management programs that have been 16 identified, 49 commitments, site owners and subject 17 matter experts have been involved in the development 18 of the application, inspections and audits and 19 responses, all of the SER open items are currently under 20 review by the NRC staff, and the proposed programs 21 address the aging management of Davis-Besse for the 22 period of extended operations.
23 DR. BARTON: Let me ask you a question.
24 You're within the five-year window of license extension.
25 MR. CUSTER: That's correct.
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102 1 DR. BARTON: There's a lot of the aging 2 management programs that say within five years, within 3 six years we're going to implement this program. How 4 many of those have you implemented?
5 MR. CUSTER: Well, actually we just got our 6 final SER in July. Okay? So certainly this program 7 on the shield building --
8 DR. BARTON: I'm not clear that one.
9 MR. CUSTER: Okay.
10 DR. BARTON: All the other ones that fall 11 within this five or six-year window.
12 MR. CUSTER: None of the new programs have 13 been implemented as --
14 DR. BARTON: None of them? So you got a 15 whole bunch of programs within that window that you got 16 to do?
17 MR. CUSTER: That's correct. That's 18 correct.
19 DR. BARTON: Well, good luck.
20 CHAIRMAN SIEBER: That's rather typical of 21 license renewal activities and licensees use the time 22 between the granting of the reviewed license and the 23 start of the extended period. That's their time to 24 prepare these programs and get them started, that they 25 must be established by the time of the extended period NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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103 1 of operation.
2 I'd like to take this time to ask the members 3 if they have additional questions. John, you indicated 4 that you had some?
5 MEMBER STETKAR: Yes, I do. I have a 6 number though, Jack, and it may be better for us to take 7 a break and come back and address those other issues.
8 CHAIRMAN SIEBER: Okay.
9 MEMBER STETKAR: Because if I start asking 10 questions, we'll --
11 CHAIRMAN SIEBER: We won't get a break.
12 MEMBER STETKAR: You know me well enough 13 by now.
14 CHAIRMAN SIEBER: We'll be broken.
15 MEMBER STETKAR: And I think John has some 16 also.
17 CHAIRMAN SIEBER: Okay. And actually I 18 think that's a pretty good idea. According to my watch, 19 why don't we -- according to the clock on the wall, we'll 20 come back at quarter to 11:00. So we're in recess now.
21 (Whereupon, the above-entitled matter went 22 off the record at 10:24 a.m. and resumed at 10:44 a.m.)
23 CHAIRMAN SIEBER: Okay. At this time 24 we'll resume our session with the applicant for 25 Davis-Besse. And we were at the point where we were NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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104 1 inviting questions from ACRS members. John?
2 MEMBER STETKAR: Yes, I'm just going to 3 walk through there. There's no real rhyme or reason, 4 because I just wrote these down as I went through the 5 reports.
6 In the scoping analysis you have some 7 safety-related equipment out in the turbine building, 8 and what I focused on in particular were the start-up 9 feedwater pump control valves, I guess. And arguments 10 were -- this is regarding effects of non-safety 11 equipment located in the vicinity of safety-related 12 equipment.
13 CHAIRMAN SIEBER: 2 over 1.
14 MEMBER STETKAR: 2 over -- seismic 2 over 15 1 or, you know, leaks or what -- any kind of impacts 16 that you could think about. The argument was made that 17 those valves failed in the open position and therefore 18 no damage from non-safety equipment could prevent them 19 from performing that function. I have no idea how your 20 start-up feedwater system is designed. I didn't have 21 enough time to do that level of research. If those 22 valves are failed open and you can't close them, how 23 do you prevent overfilling your steam generators and 24 isolating a lot of other things like auxiliary feedwater 25 or whatever you call it?
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105 1 MR. BYRD: Well, first of all, I think the 2 valves you're referring to -- you've mentioned these 3 start-up feedwater. That is -- you're probably meaning 4 the motor-driven feed pump, I believe.
5 MEMBER STETKAR: I don't know. It's only 6 -- in what I read, it was characterized as the start-up 7 --
8 MR. BYRD: We had a start-up feed pump that 9 -- and we had a motor-driven feed pump which would have 10 a level control valve. That start-up feed pump though 11 is not a pump that's going to be starting. That's a 12 manually-started valve pump, so the --
13 MEMBER STETKAR: Let me help. Before you 14 -- because I'll tell you entirely the sum contents of 15 what I know. And this was a quote that I read actually 16 in the SER, so it's a paraphrase from I guess a response 17 to an RAI. For your reference, it's RAI 2.1-1. And 18 it says the safety-related components of the start-up 19 feedwater pump and auxiliary system that are located 20 in the turbine building are the position controllers 21 for control valves DBFV-6459 and DBFV-6460 shown on 22 license renewal drawing LRMO-06D. These control valves 23 fail open and the valve position controller is energized 24 to close the valves so the associated control valve opens 25 on a loss of signal from the controller. That's all NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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106 1 I know.
2 From that context it sounds like those 3 valves are safety-related valves that are designed to 4 fail -- control valves that are designed to fail open.
5 I don't know exactly if they are directly associated 6 with the start-up feedwater pump. It's just the context 7 of that quote led me to believe that they are. And I 8 know some plants actually have qualified their start-up 9 feedwater pump as a safety-related source of water 10 supply. As I said, I have no idea how your plant is 11 designed.
12 And the question I had is if those valves 13 indeed do fail open, what protection do you have against 14 overfill of the steam generator? And if the steam 15 generator does overfill, does that also isolate 16 safety-related water -- other safety-related water 17 supplies, or the only safety-related water supplies?
18 In other words, is the closure function of those valves 19 also required?
20 CHAIRMAN SIEBER: Yes, I might point out 21 that in some plants the start-up feed up is also an 22 alternate auxiliary feed pump.
23 MEMBER STETKAR: Yes, that's -- I've seen 24 that. That's -- yes.
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107 1 in the case of Davis-Besse whether the start-up feed 2 pump is used in that capacity or not.
3 MR. BYRD: So we have a -- we do have a 4 start-up feed pump which is not used in that capacity.
5 We also have a motor-driven feed pump which is used 6 as an alternate auxiliary feedwater pump, however, it 7 is a -- it is only manually initiated. So in other words, 8 it's the -- our steam feed rupture control system would 9 only manually initiate our two steam-driven auxiliary 10 feedwater pumps. Now the two auxiliary -- the two 11 steam-driven auxiliary feedwater pumps are actually 12 located in the auxiliary building. They're located in 13 -- they have their own room, which is actually accessed 14 through the turbine building, but it is a part of the 15 auxiliary building. So the particular valves which 16 would be controlling from the auxiliary feedwater pumps 17 would be contained with the auxiliary building.
18 MEMBER STETKAR: Well, I guess my question 19 is then is there a concern with these two particular 20 valves that I've cited, because as I said, the only thing 21 that I've read leads me to believe that for some reason 22 they're safety-related valves. And not having a flow 23 diagram of your systems, I couldn't go find out what 24 those valves --
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108 1 issue, if I could have Dennis Blakely, our analysis 2 supervisor -- I think he could provide a little bit more 3 of that, how we analyzed the overfill.
4 MEMBER STETKAR: By the way, if you don't 5 have a quick answer, we're here all day. You know, you 6 can do some homework over lunch.
7 MR. BYRD: That's right. Just trying to 8 understand the question.
9 MR. BLAKELY: I'm Dennis Blakely, the 10 engineering analysis supervisor. The auxiliary 11 feedwater pumps, as Ken said, are located in a separate 12 -- or separate rooms of the auxiliary building and they 13 have level control valves associated with them and they 14 are protected -- they are within those auxiliary feed 15 pump rooms.
16 The valves you're referring to are 17 associated with the motor-driven feed pump, which is 18 a manually started pump. And the boundary for the 19 system would include check valves that would prevent 20 overfeed.
21 Now, the operators also have the capability 22 to shut off the motor-driven feed pump if those valves 23 would fail open, if they had started it. Okay?
24 MEMBER STETKAR: If they had -- but --
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109 1 relied upon within the safety analysis for the 2 mitigation of accidents. So those valves are also not 3 relied upon.
4 CHAIRMAN SIEBER: Is that pump used during 5 normal operation?
6 MR. BLAKELY: It's used for -- in normal 7 operations for plant start-up and shutdown. But in that 8 case it's a line to the main feedwater system rather 9 than to the auxiliary feedwater system, so it's going 10 in the main feedwater headers of the steam generators 11 rather than the auxiliary feedwater header.
12 CHAIRMAN SIEBER: And when you get to a 13 certain power level that pump just shuts down?
14 MR. BLAKELY: Once the main feed pumps are 15 started up and supporting plant operations, the 16 motor-driven feed pump is shut down and realigned to 17 the auxiliary feedwater pump so that it's available for 18 the operator should they need it.
19 CHAIRMAN SIEBER: And that occurs at what, 20 20 percent power? Is that about --
21 MR. BLAKELY: Approximately. Yes, sir.
22 CHAIRMAN SIEBER: Okay.
23 MEMBER STETKAR: Okay. Thank you. That 24 solves my question about that.
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110 1 bear with me because in the interest of time I'll try 2 to do some screening.
3 The bolting integrity program. There's 4 some discussion in the SER and responses to RAIs about 5 your examination program for high-strength bolting.
6 And the response that I read said the applicant further 7 stated in response to RAI B.2.4-1, that volumetric or 8 surface examinations are not currently conducted to 9 detect stress corrosion cracking on bolts; these are 10 high-strength bolts, since no instances of failed 11 bolting of bolted connections due to stress corrosion 12 cracking had occurred at Davis-Besse. Applicant stated 13 that visual examinations of structural components will 14 detect corrosion or corrosive environment that leads 15 to stress corrosion cracking.
16 I'm not a materials person; I may need help 17 from our materials people here, but it seems to me just 18 because you haven't had any fails -- failures doesn't 19 provide me a lot of confidence that you shouldn't check 20 for conditions that might cause cracking. And I know 21 that your reactor vessel head closure studs are high 22 strength material. What other bolts in the plant are 23 those high-strength materials?
24 MR. BYRD: I'll ask my core team. Do we 25 have a response to that that we can provide right now?
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111 1 MR. KOSLOFF: Don Kosloff with the core 2 team. I'm the civil structural lead.
3 I've looked at several drawings and we have 4 quite a few structural bolts that are high- strength.
5 MEMBER STETKAR: That are high-strength?
6 MR. KOSLOFF: It would be difficult to give 7 a list --
8 MEMBER STETKAR: Okay.
9 MR. KOSLOFF: -- of how many there are, but 10 there are quite a number of them.
11 MEMBER STETKAR: Let me ask our other two 12 -- Dr. Armijo and Dr. Shack, because I am now well past 13 anything that I know anything about. Are surface visual 14 inspections adequate?
15 MEMBER ARMIJO: Have to be pretty severe.
16 MEMBER STETKAR: I mean, the Yale report 17 recommends volumetric examination.
18 MEMBER ARMIJO: Yes. Yes.
19 MEMBER STETKAR: That's --
20 MEMBER ARMIJO: Sometimes people do 21 penetrating exams.
22 MEMBER STETKAR: Yes.
23 MEMBER ARMIJO: But, no, if you really 24 thought you had a cracking thing potential --
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112 1 it failed.
2 MEMBER ARMIJO: That's right. Right, 3 they're not --
4 MEMBER STETKAR: Oh, but they're just 5 volumetric. They're proposing simple, right, you know, 6 visual --
7 MR. BYRD: I think we have our bolting 8 engineer here. I turn -- I'm sorry, Jake Hofelich?
9 MR. HOFELICH: Jake Hofelich, ISI program 10 owner. Some of the bolting is examined ultrasonically.
11 The bolting within the section 11 ISI program, the 12 reactor head closure studs in particular, each stud is 13 examined each 10-year --
14 MEMBER STETKAR: Yes, I read that.
15 MR. HOFELICH: And also the other systems, 16 class 1, 2 and 3 systems are pressure tested and we look 17 for any evidence of degradation or any leaks that would 18 be a result of any cracking in the bolting.
19 MEMBER STETKAR: Yes, but that's after the 20 failure has occurred.
21 MR. HOFELICH: Correct.
22 MEMBER ARMIJO: What's your history with 23 those bolts?
24 MR. HOFELICH: We have not had any cracking 25 indications in the record at closure sites.
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113 1 MEMBER ARMIJO: I saw the magic words "moly 2 disulfide" somewhere. I keep wondering. I thought 3 that disappeared when I was a young man, younger than 4 you.
5 MR. HOFELICH: The lubricant that we 6 previously used contained molybdenum disulfide. And 7 one of the commitments in our license renewal 8 application is to preclude the use of that reactor head 9 closure studs.
10 MEMBER ARMIJO: Better late than never.
11 MEMBER STETKAR: I'll have to think about 12 that one. Buried piping. I understand that your diesel 13 fuel oil piping is cathodically protected, right? And 14 you're upgrading that system, is that correct?
15 MR. BYRD: That's correct.
16 MEMBER STETKAR: And you're going -- are 17 you going to protect -- provide cathodic protection for 18 the service water piping?
19 MR. BYRD: To discuss our buried piping, 20 we have our program owner Frank Zurvalec here.
21 MR. ZURVALEC: My name is Frank Zurvalec.
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114 1 to go. Currently the diesel fire pump piping, buried 2 piping is cathodically protected. That was installed 3 either this year or last year.
4 DR. BARTON: How effective is the cathodic 5 protection system that you do have installed? I know 6 you're still working on it, that you've got some 7 installed. How effective is it?
8 MR. ZURVALEC: We monitor it for the base 9 guidelines monthly voltage current readings and also 10 yearly ground potential readings.
11 DR. BARTON: Ninety, ninety-five percent 12 effective, or --
13 MR. ZURVALEC: I don't have that number.
14 The cathodic protection engineer is back at our site, 15 but I would argue at least 99 percent.
16 MEMBER STETKAR: I'm not sure you answered 17 my question. I was asking you about the service water 18 piping.
19 MR. ZURVALEC: Service water? I thought 20 diesel fire pump.
21 MEMBER STETKAR: No, I --
22 MR. ZURVALEC: Our service water piping 23 that's been scoped is cathodically protected at this 24 time.
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115 1 not in the past, is that correct?
2 MR. ZURVALEC: The service water cathodic 3 protection was reestablished again either this year or 4 last year reestablished.
5 MEMBER STETKAR: Oh, it did have cathodic 6 protection in -- at --
7 MR. ZURVALEC: At one time it did. It had 8 fallen into a state of disrepair.
9 MEMBER STETKAR: Okay.
10 MR. ZURVALEC: But our plans are to 11 cathodically protect all of the buried lines within the 12 protected area. All of the pipes, all of the buried 13 lines within the scope of the license renewal are 14 currently cathodically protected.
15 CHAIRMAN SIEBER: How long in the history 16 of Davis-Besse did the plant go without serviceable 17 cathodic protection?
18 MR. ZURVALEC: I would argue the vast 19 majority of time. I do not have those details, but 20 originally after construction and start-up the cathodic 21 protection system fell into disarray and was not 22 maintained properly. Through industry discussions and 23 the shared operating experience at the license renewal, 24 I think the industry has embraced the idea that cathodic 25 protection is an integral part of the health of the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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116 1 buried piping system and must be reestablished and 2 maintained.
3 CHAIRMAN SIEBER: So you probably got 25-30 4 years of issues with the buried piping where you did 5 not have protection established?
6 MR. ZURVALEC: That's a good estimate, but 7 again with our buried pipe program we are doing 8 inspections of the line that we have, opportunistic 9 inspections. I do not see a degraded condition. As 10 long as the coating is intact, we did not have to rely 11 upon the cathodic protection system. It's only when 12 that coating has been degraded or damaged that will cause 13 a problem, and that's what that cathodic protection 14 system is for.
15 CHAIRMAN SIEBER: Okay. That's 16 degradation from the exterior of the pipe?
17 MR. ZURVALEC: That's correct.
18 CHAIRMAN SIEBER: Have you done 19 examinations of -- other than opportunistic where you 20 actually physically go down and make measurements on 21 the pipe in the -- including wall thickness and --
22 MR. ZURVALEC: Yes, sir.
23 CHAIRMAN SIEBER: -- the interior surface?
24 MR. ZURVALEC: Direct examinations.
25 We've performed direct examinations of our -- some of NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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117 1 our service water piping, various pipings. And the 2 coating that I've seen has all been intact. It's not 3 delaminated. It's not cracking. We have removed some 4 coating to perform ultrasonic examinations. Then we 5 establish that coating again. But there has been -- the 6 pipe that I've inspected is in new condition.
7 MEMBER STETKAR: It's also service water?
8 I mean, there's a lot of focus on --
9 MR. ZURVALEC: It includes portions of the 10 service water system.
11 MEMBER STETKAR: Okay. Okay.
12 MR. BYRD: Just to make sure you 13 understand, the main service water discharge and supply 14 headers are actually in a tunnel, so they're not buried.
15 16 MEMBER STETKAR: So it's an underground?
17 MR. BYRD: It's underground, but it's in 18 a tunnel. Okay?
19 MEMBER STETKAR: Okay. Thank you. Let me 20 make a note here.
21 Kind of following up, the -- I couldn't 22 follow the story -- there's a story about materials in 23 your firewater system that are copper alloy with zinc.
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118 1 in one of the programs. I don't have my whole list here.
2 It was in one program, but the staff had questions about 3 it. You said, well, we'll take it out of the program.
4 And then it kind of popped up in another one and it 5 was taken out of there. I can't find now any --
6 DR. BARTON: It's in an aging --
7 MEMBER STETKAR: Now we're --
8 DR. BARTON: It's in aging management 9 program now, fire --
10 MEMBER STETKAR: Where? Well, but not -- I 11 don't think for these alloys.
12 DR. BARTON: Oh, no, it's --
13 MEMBER STETKAR: That's -- what I want 14 -- the whole key, I think, is, as I finally walk my way 15 through all of this, in an initial response it says the 16 applicant also stated that they could not verify the 17 absence of ammonia in it's raw water source to be below 18 a threshold concentration in which cracking would not 19 be a concern. There are several negatives there, but 20 basically it says you couldn't -- you thought there might 21 be enough ammonia to cause cracking. And then as I 22 understand it, all of the following discussions wherever 23 it pops up and questions were asked, you finally said 24 that operating experience did not identify ammonia or 25 ammonium salt in the raw water or cracking of comparable NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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119 1 alloys in the associated system. Do you know that you 2 don't have raw water chemistry that would facilitate 3 cracking in that material?
4 MR. BYRD: We have Alvin Dawson here, our 5 chemistry manager who can --
6 MEMBER STETKAR: Beyond a shadow of a 7 doubt?
8 MR. DAWSON: Alvin Dawson, chemistry 9 manager. In answer to your question, yes, we know.
10 We drew samples on our raw water system both going in 11 and going out after that question was raised. All those 12 samples were sent out for analysis and we have no ammonia 13 --
14 MEMBER STETKAR: Okay.
15 MR. DAWSON: -- in our raw water system.
16 MEMBER STETKAR: Thank you. Ground water.
17 Asked a little about groundwater earlier with regard 18 to the containment shell and I wanted to follow up on 19 a couple of other things.
20 You've committed to sample the groundwater 21 system during a period of extended operation at least 22 once every five years. Do you have in place and have 23 you had during the operating history of Davis-Besse a 24 groundwater sampling program? In other words, you've 25 committed to something. Sample every five years means NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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120 1 you get three or four during the period of extended 2 operation to look for trends in the groundwater 3 chemistry. Do you have any idea about past trends in 4 the groundwater chemistry?
5 MR. BYRD: Yes, we do and Alvin Dawson here 6 would be able to explain that.
7 MR. DAWSON: Again, Alvin Dawson, 8 chemistry manager. We have had a groundwater system 9 -- a groundwater sampling system in place at Davis-Besse 10 for a number of years. In 2007, when NEI 07-07 came 11 out, we instituted a more rigid groundwater sampling 12 program. Right now we sample groundwater every six 13 months for tritium and hard gamma emitters and different 14 species that we're interested in. We sample every six 15 months and if --
16 MEMBER STETKAR: Do you sample for 17 chloride, sulfates and pH? I'm not interested in 18 sampling for radionuclides. I'm interested in sampling 19 for water chemistry, aggressive water chemistry.
20 MR. DAWSON: Oh, you're referring to the 21 five-year commitment for water chemistry?
22 MEMBER STETKAR: That's -- yes.
23 MR. DAWSON: We do -- on that five-year 24 basis we sample for -- we do sample for pH on a regular 25 basis, but for chlorides and sulfates we do sample every NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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121 1 five years.
2 MEMBER STETKAR: Has that been done in the 3 past during the last 35 years of operation, or is that 4 just something you're going to start in 2017?
5 MR. BYRD: Alvin, I think Donald has 6 something to add to that. Don Kosloff?
7 MR. KOSLOFF: Yes, there's a bit of 8 confusion in the SER.
9 MEMBER STETKAR: Okay.
10 MR. KOSLOFF: Donald Kosloff, license 11 renewal core team, structural civil engineer. We 12 followed GALL Rev 1 in our application, which required 13 sampling of groundwater if the groundwater is 14 non-aggressive. It had no requirement for sampling if 15 the water was determined to be aggressive. We 16 determined that the groundwater was aggressive and we 17 did not commit to sample groundwater. We committed to 18 sample raw water; i.e., lake water because the lake water 19 is non-aggressive and we want to monitor that to make 20 sure that it doesn't become aggressive.
21 MEMBER STETKAR: That's -- I didn't want 22 to bring that up, but I saw the commitment to sample 23 raw water and I thought that might have been a typo.
24 Apparently it's not. Apparently that response was 25 very carefully worded.
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122 1 So you're not actually going to sample 2 groundwater to determine its chemistry?
3 MR. KOSLOFF: There is no plan at this time 4 to sample groundwater for sulfates, chlorides or pH.
5 MEMBER STETKAR: Okay. So you're just 6 going to rely on your basic opportunistic inspections 7 of below-grade structures whenever they're exposed.
8 And as I -- and I wanted to ask you about -- I know you're 9 going to take a couple of core bores --
10 MR. KOSLOFF: Right.
11 MEMBER STETKAR: -- from the turbine 12 building and the ECCS pump room, I guess. Let me ask 13 about the core bores. The groundwater level, as I 14 understand it, nominal is about 570 feet, is that right?
15 MR. KOSLOFF: That's correct. Dick Bair 16 of our structural engineering group can provide a more 17 detailed answer on that.
18 MEMBER STETKAR: Okay.
19 MR. BAIR: Richard Bair, design 20 engineering. As you stated, we are planning on taking 21 two of the core bores; one in our turbine building, one 22 in our ECCS pump room, which is in the auxiliary 23 building. Those cores will be taken deep into the 24 structure so we can access the portion of the concrete 25 most likely to potentially be affected by the aggressive NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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123 1 groundwater. We will be testing that in concrete and 2 our commitment -- we have a license renewal commitment 3 to perform these two initial core bores by the end of 4 2014. And we have additional commitments to perform 5 core bores in the future if groundwater infiltration 6 persists. I plan on entering the information from these 7 core bores into our corrective action program for 8 tracking and that will also allow us to initiate any 9 additional corrective actions that may be necessary for 10 this condition.
11 MEMBER STETKAR: Thank you. You said the 12 core bores are going to be deep. Any estimate of 13 -- because you're boring from the interior going out, 14 you'd expect the problem if there is any to be 15 progressing from the exterior in. So will they go 16 completely through wall, or --
17 MR. BAIR: No, we're not planning on going 18 completely through wall. We're planning on going to 19 approximately the lowest -- in the case of the ECCS pump 20 room, we'll be going through the actual foundation mat 21 of the auxiliary building. So we'd be going to 22 approximately the depth of the bottom rebar mat. And 23 in the turbine building it would be on walls, so we would 24 be core boring approximately to the location of the outer 25 rebar mat, which would be -- leave a couple inches of NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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124 1 concrete in each one of those locations.
2 MEMBER STETKAR: Okay. Bear with me here.
3 I've got one more question. I'm a slow writer.
4 One last simple question: And in the 5 turbine building, at least again from what I've read 6 said that the core bore would be at the turbine building 7 condenser pit at approximately elevation 573, which as 8 I understand is about 3 feet above groundwater level.
9 Why not below groundwater level in the turbine 10 building, or is that a typo?
11 MR. BAIR: Offhand I'm not sure how we 12 selected that specific elevation. We will be taking 13 one at a sufficiently low elevation to ensure that we're 14 getting a portion of the structure that potentially had 15 been affected by the aggressive groundwater.
16 MEMBER STETKAR: Okay. You may want to 17 check that. I pulled that out --
18 MR. BAIR: Okay.
19 MEMBER STETKAR: It's in the SER. It could 20 be a typo. I recognize -- we don't get all of the RAIs 21 and the responses, nor do we want them. We have enough 22 to read.
23 MR. BAIR: Right.
24 MEMBER STETKAR: And sometimes things get 25 paraphrased a little bit.
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125 1 MR. BAIR: As I prepare the engineering 2 change package for these core drills, I will double check 3 that. I will be sure it's --
4 MEMBER STETKAR: Yes, it's just --
5 MR. BAIR: -- sufficiently low to capture 6 the zone affected by the aggressive groundwater.
7 MEMBER STETKAR: Okay. Thank you. Two 8 more: You've had some slope slippage -- or I'm not a 9 geotechnical engineer, so I don't know the correct terms 10 -- in your intake canals. Can you tell us -- and I know 11 you've done a bunch of analyses that -- you had divers 12 go down. They say the tow hasn't come out. apparently 13 a couple of geotechnical analyses came back. As I 14 understand, it was sort of differing opinions about 15 the current condition of the intake canal. Can you show 16 us -- there was one photograph. What's the extent of 17 that area that slipped --
18 MR. BYRD: Do we have --
19 MEMBER STETKAR: -- in terms of --
20 MR. BYRD: We have --
21 MEMBER STETKAR: Yes, that's the 22 photograph I was looking --
23 MR. BYRD: -- Joe Brunkhorst here who can 24 explain this for us.
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126 1 structures monitoring program owner. Would you like 2 me to come up front and point --
3 MEMBER STETKAR: It would help. I mean, 4 if you have a -- but the problem is you have to be near 5 a microphone or a --
6 MR. BRUNKHORST: I understand.
7 CHAIRMAN SIEBER: Yes, you may want to do 8 it with a mouse.
9 MR. BRUNKHORST: Okay. So the intake 10 canal entire length is approximately 2,700 feet, and 11 the Q-safety-related forebay is about 700 foot long from 12 the face of the intake structure. So approximately 13 right where the hand is there's an area -- two areas 14 that are side by side that equal approximately 150 feet 15 where this localized settlement is taking place.
16 MEMBER STETKAR: And then we say -- when 17 you say "localized settlement," is it an actual slip, 18 or is it a -- what's the configuration?
19 MR. BRUNKHORST: It's more -- it's a shelf.
20 It's more --
21 MEMBER STETKAR: Okay.
22 MR. BRUNKHORST: It's created more of a 23 shelf and it's actually settled down more between the 24 top of the bank and the edge of the water. That's what 25 the diver confirmed with the tow of the --
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127 1 MEMBER STETKAR: So you actually haven't 2 seen a slip?
3 MR. BRUNKHORST: There has been some minor 4 slippage into the canal. We had a slope stability study 5 recently finalized where they had installed two sloping 6 inclinometers into two of the cores that were installed 7 and they over a six-month period saw minimal movement 8 in a magnitude of approximately a quarter of an inch.
9 So what that did though confirm is where exactly that 10 failure plane was in the canal.
11 MEMBER STETKAR: So you have confidence and 12 you understand where the failure point is?
13 MR. BRUNKHORST: Yes. Yes.
14 DR. BARTON: Do you have some work 15 scheduled to do in the intake canal in that area?
16 MR. BRUNKHORST: Yes. Yes, we're 17 currently putting together the engineering change 18 package to make a repair to that area.
19 MEMBER STETKAR: Do you know what you're 20 going to do with it?
21 MR. BRUNKHORST: The current repair option 22 that's being pursued to actually install sheet pile in 23 the area.
24 MEMBER STETKAR: Okay.
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128 1 now while you're -- want me throw it in here? The 2 description says you have water protection dikes that 3 are seismic class 2 earthen dikes constructed of 4 topsoil. My question is, you know, what prevents 5 washout of the topsoil in the event of severe wave action 6 in your intake? What am I missing here?
7 MR. BRUNKHORST: The entire length of the 8 canal is protected by riprap. I mean, as far as 9 wash-away from normal erosion factors, I mean, it's 10 protected by armor stone riprap. Yes, on both sides 11 of the canal, both sides of the dike.
12 DR. BARTON: So that's protecting this 13 topsoil from getting washed out, the riprap on the side?
14 15 MR. BRUNKHORST: Right.
16 DR. BARTON: Got you. All right. That 17 was it, John.
18 MEMBER STETKAR: Good, John? I only have 19 one more. For your environmentally-adjusted usage 20 factors in your fatigue monitoring program, I understand 21 how you -- first of all, I understand that you're 22 basically using a counter, a count -- a cycle counting 23 process primarily to -- as the primary means of keeping 24 track of this. And I read, you know, how you 25 extrapolated the past operating experience linearly to NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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129 1 come up with your number -- projected number of cycles 2 of 60 years, except for the pressurizer surge line, which 3 has an environmentally-adjusted cumulative usage factor 4 of 0.996, I believe. And what I've read is -- said, 5 well, with the nominal number of heat-up/cool-down 6 cycles of 128, which is projected just using a linear 7 extrapolation from the historical data you couldn't meet 8 the project cumulative usage factor of less than 1.0.
9 As it's characterized at least in the SER summary of 10 the RAI, it says that the applicant stated that 11 alternatively it used a best estimate 60-year projected 12 cycle for heat-up/cool-down cycles which is based on 13 more recent operating experience compared to the entire 14 operation history of the plant. This resulted in a best 15 estimate 60-year projected cycles of 114 cycles for the 16 heat-up/cool-down transients.
17 My background is risk assessment and 18 uncertainty analysis, so I'll cast it in this context:
19 when I think of a best estimate analysis, I think of 20 -- some people think of median, some people of means, 21 but it's something that I've done an analysis, looked 22 at variability and uncertainty and derived a value that 23 I feel is my best estimate.
24 Could you explain to me; and probably not 25 in this venue -- what I'm interested in is what is the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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130 1 extent of your more recent operating experience and what 2 analyses did you use to actually derive this best 3 estimate which miraculously just gets you below 1.0?
4 MR. CUSTER: I ask my team member Larry 5 Hinkle to --
6 MEMBER STETKAR: Because that's just 7 really, really surprising that it would just get you 8 below 1.0 if it's a best estimate.
9 MR. CUSTER: 0.998?
10 MEMBER STETKAR: 0.996 I think it is, not 11 0.988. It's 0.996. They gave them --
12 MR. HINKLE: I'm Larry Hinkle with the 13 license renewal project team. That was based on cycles 14 accrued since approximately 2008 -- excuse me, accrued 15 since approximately 2000 up to present day. When we 16 say "best estimate," it was based on the rate of 17 occurrence since that time frame. And there's a slight 18 bit of margin added in there --
19 MEMBER STETKAR: Okay.
20 MR. HINKLE: -- but the most part it was 21 a -- it was just based on the rate of occurrence.
22 MEMBER STETKAR: We'll do this as a 23 take-away. What I'd like to see is your historical plot 24 or tabulation of number of heat-up and cool-down cycles 25 per year over the entire life of the plant so that I NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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131 1 can see what the slopes look like. And if you have 2 documentation of how you did that extrapolation, what 3 margins, I'd be interested in that. It's just really 4 surprising to me that it worked out to this miraculously 5 getting you just below the limit. Oftentimes when you 6 look at variability and uncertainty, you know, if you 7 included one more year in the experience, you might not 8 have had that.
9 MR. HINKLE: Understood.
10 MEMBER STETKAR: So I'd really like to see 11 what those slopes look like and how you did that.
12 MR. HINKLE: Okay. At the time that this 13 occurred AREVA was performing the evaluations for us, 14 and they contacted me personally. I was the TLAA lead.
15 And basically they told me -- well, they told me the 16 number of cycles it would take to be able to pass this 17 say under 1.0. However, from there, right, I went in 18 and I personally looked at the cycles that occurred from 19 2000 up to present day at that time of the phone call, 20 which was a couple years ago here now.
21 MEMBER STETKAR: Yes.
22 MR. HINKLE: We looked at those cycles.
23 And then from there I determined that I could even come 24 up with a lower number than what they needed. And so 25 I added some margin back in just to account for some NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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132 1 unknowns and things that might occur down the way that 2 we didn't anticipate.
3 MEMBER STETKAR: The only -- and in some 4 sense this is a bit of a moot point because I understand 5 you're just setting a speed limit for yourself and 6 essentially it's -- on my street the speed limit is 30 7 and on the next street a block over it's 35, and you're 8 monitoring your performance so that you're not passing 9 a speed limit of 30, you know, for this particular 10 failure mechanism. The thing that I'm hanging up on 11 is -- the use of the term "best estimate" in the world 12 these days really means something. It's not just 13 setting a nominal speed limit. And indeed, if you're 14 characterizing that as a best estimate, I wonder -- I 15 want to understand why it is that. If it's just simply 16 the number of cycles such that the value is less than 17 1.0, that's not necessarily a best estimate. It's an 18 arbitrary speed limit.
19 MR. HINKLE: No, this is -- this number of 20 cycles was based on the rate of occurrence --
21 MEMBER STETKAR: Okay.
22 MR. HINKLE: -- since the year 2000. And 23 so when I -- and I came up with the term "best estimate."
24 I thought that was the best term I could come up with.
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133 1 the other 60-year projections we had performed.
2 MEMBER STETKAR: Well, I'd like to see how 3 you did that.
4 MR. HINKLE: Okay.
5 MR. CUSTER: We can provide that, Mr.
6 Stetkar.
7 MEMBER STETKAR: Thank you.
8 MEMBER SHACK: Just a quick follow-up on 9 that. All those CUFs are based on ASME-type code 10 calculations? You haven't done a -- you haven't redone 11 the stress analysis to get those numbers lower?
12 MR. RINCKEL: Mark Rinckel with the AREVA 13 license renewal team. Yes, they're based on ASME code 14 calcs, or the original stress analysis. So there hasn't 15 been anything --
16 MEMBER SHACK: Any reanalysis?
17 MR. RINCKEL: No, not for the NUREG-6260 18 locations.
19 MEMBER SHACK: Now you're going to do more 20 locations, right?
21 MR. RINCKEL: Yes, we identified 22 additional ones, so that's a commitment.
23 MEMBER SHACK: Yes, it's the highest one 24 for each material type?
25 MR. RINCKEL: That is correct.
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134 1 MEMBER SHACK: But that hasn't been done 2 yet?
3 MR. RINCKEL: That's beyond the NUREG-6260 4 locations. Yes, that's correct.
5 MEMBER STETKAR: I don't have anymore.
6 CHAIRMAN SIEBER: Okay.
7 MEMBER STETKAR: I don't know if John has 8 any.
9 DR. BARTON: Yes. I couldn't find in your 10 small bore piping, class 1 piping inspection what you 11 committed in regards to inspection of socket welds.
12 Can you help me out here? Do you have a number? A 13 percentage?
14 MR. BYRD: I'll let Jake Hofelich, our 15 small bore piping inspection lead --
16 MR. HOFELICH: I'm Jake Hofelich. I'm the 17 small bore piping program owner. The inspections are 18 10 percent of the weld population, or maximum 25 for 19 each weld type, socket welds and full penetration welds.
20 Our sock weld population is approximately 437, so we'll 21 be performing 25 of those. Alternatively, we can 22 perform 13 destructive examinations if a qualified 23 ultrasonic technique is --
24 DR. BARTON: Got you. I understand.
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135 1 population is like 180 or so, right?
2 MR. HOFELICH: The full penetration weld 3 is approximately 180, yes.
4 DR. BARTON: Right. Okay. I've got a 5 question on tanks in general. Your water storage tank, 6 diesel oil tanks and your borated water storage tank 7 could determine whether caulking at the interface at 8 the tank to the foundation is required on these tanks.
9 And if so, is it installed? Because you had an 10 experience several years ago where the diesel oil 11 storage tank had rust and corrosion at the base flange 12 and corroded bolts at the lower access plate at the tank 13 base.
14 Now have you fixed that? And do you have 15 these tanks insulated at the foundation to the lower 16 tank flange on these things?
17 MR. CUSTER: I think the history on that, 18 we'll have to get back to you at lunch time. Right now 19 we don't -- we don't have anybody who can answer that 20 question with us right now.
21 DR. BARTON: Well, I'm concerned because 22 I have some experience of tanks that get corroded in 23 the bottom, start leaking, etcetera. And it looks, from 24 what I read your, history is maybe that you've got some 25 of that going on. And I'd like to know the status of NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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136 1 -- do you require insulation at that interface at not?
2 3 And also, you said that you're going to look 4 at the initial tank bottom inspection of firewater 5 storage tank, you know, some 40-45 years after it was 6 installed. And that tank, according to what I read, 7 does not have any sealing material. And I question, 8 you know, doing an initial inspection on a tank that 9 is not insulated from this foundation after that many 10 years. So that's a concern I've got. MR.
11 ALLEN: With respect to the firewater tank, I think 12 Donald can talk to that once we fix this.
13 MR. KOSLOFF: I dropped my microphone ball.
14 15 The firewater storage tank was replaced -- I 16 believe it was about 20 years ago. I don't -- somebody 17 in design remember when that was done?
18 MR. HOFELICH: Yes, the firewater storage 19 tank I believe was replaced in the 1980s.
20 MR. KOSLOFF: That's addressed in the 21 application in the operating experience discussion.
22 I believe it's for firewater system.
23 MEMBER STETKAR: But the bottom edge of 24 that tank is not sealed --
25 MR. KOSLOFF: That is correct.
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137 1 MEMBER STETKAR: -- to the foundation.
2 MR. KOSLOFF: That is correct. The 3 firewater storage tank is a concrete ring foundation 4 with a oil/sand base. And that's also discussed in the 5 --
6 DR. BARTON: Well, I know it's on an 7 oil/sand base, but I've known tanks on oil/sand bases 8 that have also had problems, leakage problems.
9 MR. KOSLOFF: Right. And --
10 DR. BARTON: So if it's on that, it does 11 not preclude any problems with that tank, so --
12 MR. KOSLOFF: And we're going to inspect 13 that tank periodically.
14 DR. BARTON: How about the other ones? Do 15 they require insulation around there or not?
16 MR. KOSLOFF: The only thank in the 17 above-ground tanks program that's insulated in the 18 borated water storage tank. The other two tanks -- or 19 the other tank and the borated water storage tank, which 20 would be the diesel oil storage tank and the borated 21 water storage tank, require a caulk seal at the base.
22 DR. BARTON: And that is installed as far 23 as you know?
24 MR. KOSLOFF: As far as I know. Yes, sir.
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138 1 on switchyard work. Trying to find out what your 2 relationship here to -- I know you need the switchyard 3 for off-site -- loss of off-site power, but I read in 4 one of the inspection reports the -- there was a question 5 on the status of some concrete repairs that needed to 6 be done on switchyard tower foundations which were 7 identified in station condition reports. A work order 8 was submitted to the FirstEnergy switchyard people and 9 it turns out that the work order and condition reports 10 were closed out by the switchyard department responsible 11 for the work with no work being done and no reasons given.
12 My question is, you know, what relationship 13 do you have with FirstEnergy's switchyard people and 14 do you understand why the work wasn't done, or was it 15 just okay they closed it out?
16 MR. BYRD: So the relationship we have is 17 obviously we do not at this point do the maintenance 18 on the switchyard.
19 DR. BARTON: I understand that.
20 MR. BYRD: We did actually until fairly 21 recently, but we turned that over to the transmission.
22 We do provide oversight over that work, however, and 23 that's done by our electric shop which provides 24 oversight whenever we have ongoing work in the 25 switchyard.
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139 1 With regards to the transmission tower 2 concrete, Mr. Hook, if you could provide us with an 3 update on that?
4 MR. HOOK: Jon Hook, design engineering 5 manager. So for the transmission foundations, there 6 are caissons going down to bedrock and there's been some 7 degradation underneath the base plate. We have done 8 repairs of that in the past. That's where most of the 9 material is -- degradation is associated with brick down 10 to the base plate.
11 We did take a look at that. There's ample 12 margin in the design for that. And there is some 13 spalling along the exposed concrete caissons that come 14 up, and that's all surface. It's not structural.
15 DR. BARTON: So the fact the work wasn't 16 done, you've agreed with -- you've looked at that and 17 you've agreed it wasn't required, or what? It just --
18 MR. HOOK: It is required to prevent 19 further degradation. So that's part of our maintenance 20 rules for structures during our walk-downs. We go 21 through that and inspect it and identify it. If it's 22 appropriate, we either write a notification to get it 23 fixed or a condition report.
24 DR. BARTON: So in this case how did this 25 end up?
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140 1 MR. HOOK: The current condition right now 2 is acceptable.
3 DR. BARTON: It's acceptable?
4 MR. HOOK: Right. It's just minor, minor 5 surface spalling and degradation. Not a structural 6 concern at this time.
7 MEMBER STETKAR: John, you're asking about 8 a specific event, right?
9 DR. BARTON: Yes, what I want to know is 10 they didn't do the work, returned the work order or 11 whatever with no reason why they didn't do the work.
12 And that's what bothers me.
13 MEMBER STETKAR: Okay.
14 MR. BYRD: I don't have the details of 15 why --
16 DR. BARTON: This was in an NRC inspection 17 report is where I got this.
18 MR. BYRD: Right, and I don't --
19 DR. BARTON: And that was due to looking 20 at the paper and talking to people while they were doing 21 the inspection.
22 MR. BYRD: So I don't --
23 DR. BARTON: And that's the problem I've 24 got.
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141 1 of that specific issue. We can follow up with that.
2 DR. BARTON: Okay. I appreciate that.
3 MR. BYRD: And I'm sure there's more 4 history to that.
5 DR. BARTON: You have inaccessible 6 medium-voltage cables not subject to 50.59 EQ 7 requirements. I noticed that you've got water problems 8 in manholes and cables wetted, etcetera. You had stated 9 that you were going to improve the water quality removal 10 capability of the sump pumps. Has that been done?
11 MR. BYRD: I we have Eric Johnson here to 12 provide some additional information on that.
13 MR. JOHNSON: Eric Johnson, electrical 14 programs at Davis-Besse.
15 Yes, we did have water problems in a manhole 16 that supplies -- for our station blackout diesel 17 generator cables. And we did put a sump pump in that 18 manhole approximately one year ago. We have two other 19 manholes associated with cables that go to the 20 switchyard relay house that has some drainage issues.
21 And we have an engineering change package that will 22 be scheduled to be implemented next spring that will 23 provide drainage to an adjacent manhole that has a sump 24 pump.
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142 1 you doing to exclude water? More inspections or pumping 2 it out manually? What are you doing in the interim until 3 you implement that work order?
4 MR. JOHNSON: We just submitted a change 5 request to the PM program to inspect that -- those 6 manholes every 30 days --
7 DR. BARTON: Every 30 days?
8 MR. JOHNSON: -- or as required.
9 DR. BARTON: Now do you also require 10 inspections in severe weather conditions? You got rain 11 that comes down, it pours for three or four days and 12 does that tick off something that says we ought to go 13 look in the manholes?
14 MR. JOHNSON: That's in our aging 15 management program. We haven't determined what the 16 event is yet or how to quantify that.
17 DR. BARTON: So in the meantime you have 18 a heavy rain, you don't do anything different other than 19 inspect every 30 days or whatever?
20 MR. JOHNSON: That's correct.
21 DR. BARTON: Okay. I'm not okay about, but 22 I understand what you said.
23 Question on the makeup purification system.
24 I read where you every seventh refueling cycle replace 25 your letdown coolers, and I've looked at other plants NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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143 1 and I don't recall other plants having to change out 2 letdown coolers every seven cycles because they can't 3 repair them. There's got to be a root cause for this 4 problem and I'd like to know if you've looked at it and 5 determined what the root cause is, and why did you select 6 replacing your letdown coolers every 14 years. I don't 7 understand why you can't fix the problem that causes 8 letdown coolers to degrade to the point where you have 9 to buy new ones every 14 years.
10 MR. BYRD: I know our letdown coolers are 11 somewhat a unique helical-type design, but I don't 12 really have the answer to your question. We'll have 13 to follow up with that, unless someone anyone else on 14 our --
15 MR. ALLEN: Allen, would you like to 16 comment on that?
17 MR. McALLISTER: Allen McAllister, license 18 renewal team. Yes, our letdown coolers, they're a 19 helicoil design. That design of coolers throughout the 20 world, whether it's in the Navy, whether it's in the 21 nuclear industry, have a high-cycle fatigue problem.
22 Basically the spiral tries to un-spiral so you're 23 creating these stresses in there. To take them apart 24 to do a detailed failure analysis, it's a high dose item.
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144 1 try to do something different. We've made progress as 2 an industry. Various plants that used to replace their 3 coolers every three years got them up to five years.
4 The plant that actually had the worst history has now 5 got theirs up to 20 years.
6 So in the time being we have our PM in place 7 so that we have spare coolers so that if the thing starts 8 to leak, we'll pick that up in the chemistry analysis 9 and replace the coolers. But at this point just based 10 on the design, based on industry experience, world 11 experience, Navy experience, there's not a clear success 12 path other than at some point you're going to have to 13 replace these.
14 DR. BARTON: Nothing like a different 15 design cooler will work?
16 MR. McALLISTER: Essentially the place 17 -- the people that use this design was space 18 considerations, which is why we used them in the Navy, 19 why they were copied and put in our plant.
20 DR. BARTON: Did you replace them this 21 often when you were in the Navy?
22 MR. McALLISTER: Actually it was I believe 23 every 10 years. I remember when my sub was at the 24 Portsmouth Naval Shipyard that that's one of the 25 activities that we did. I think that was a 10-year NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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145 1 frequency.
2 DR. BARTON: All right. So it's an 3 industry problem and you're going along with the 4 industry and changing them out every so many cycles?
5 MR. McALLISTER: Yes, I mean, we're seeing 6 what we could learn. You know, I don't want to drop 7 their name, but you know, one plant has gone from 8 basically a three-year life expectancy to a 20-year life 9 expectancy. So we're seeing what we can learn from 10 them, what they changed, what they did different or the 11 same to see what we can do to increase the livelihood.
12 DR. BARTON: All right. Thank you. I 13 just -- it just seemed strange that instead of trying 14 to get to the root cause of a problem you keep changing 15 them out. So I understand.
16 In-service inspection program, IWF. I 17 noticed that you have operating experience that showed 18 you had rusted areas on I-beam supporting the service 19 water piping, which appears to be from condensation on 20 the service water piping dripping onto the I-beams.
21 Your corrective action evaluation on this deficiency 22 determined there was no action required. You know, that 23 tells me you're willing to continue with this condition 24 for an extended operating period of 20 more years instead 25 of insulating the service water piping. What am I NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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146 1 missing?
2 MR. HOFELICH: I'm Jake Hofelich. I'm the 3 IWF program owner. Those supports were examined in 4 accordance with ASME section 11 and found to be 5 acceptable within the acceptance criteria.
6 DR. BARTON: I'm sorry, I didn't hear the 7 end of that.
8 MR. HOFELICH: They were -- the supports 9 were examine in accordance with ASME section 11.
10 DR. BARTON: Right.
11 MR. HOFELICH: And as part of the 12 acceptance criteria the design engineering group took 13 a look at it and saw it could fulfill its function as 14 it and it was found to be acceptable.
15 DR. BARTON: So you're going to continue 16 with the problem?
17 MR. HOFELICH: It's found to be acceptable.
18 19 MR. BYRD: Jon Hook, can you add anything 20 to that from the structural side?
21 MR. HOOK: We continue to monitor those 22 pipe supports, and there's ample margin inside the 23 calculation and ample thickness such that any 24 degradation in there is not a concern and --
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147 1 so you're going to live with it? Is that the answer?
2 MR. HOOK: We're inspecting it and managing 3 it.
4 DR. BARTON: I understand.
5 MR. HOFELICH: It should also be pointed 6 out that these are periodic inspections, so hangers are 7 continually looked at and -- hangers in that tunnel, 8 and usually the same hangers are looked at again at the 9 next interval. So will continue to monitor those 10 hangers and the adjacent hangers in the service water 11 tunnel.
12 DR. BARTON: Open cycle cooling water 13 system.
14 MR. BYRD: Excuse me, Mr. Barton?
15 DR. BARTON: Yes?
16 MR. BYRD: I believe Mr. Blakely --
17 DR. BARTON: We got something else? All 18 right.
19 MR. BLAKELY: Dennis Blakely, engineering 20 analysis supervisor.
21 With respect to correcting the condition 22 of the condensation, that interplays with the Appendix 23 R fire protection program because the type of insulation 24 material that would be used. There's a significant fire 25 load on the spaces. And that's the reason that we're NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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148 1 not addressing the condensation and taking the approach 2 of managing this.
3 DR. BARTON: So all anti-sweat insulation 4 gives you an Appendix R problem?
5 MR. BLAKELY: The types that we use in our 6 plant; yes, sir.
7 DR. BARTON: Isn't there other types that 8 wouldn't give you an Appendix R problem?
9 MR. BLAKELY: I've not heard of others that 10 would address the issue.
11 DR. BARTON: Open cycle cooling water. In 12 operating experience you mentioned in 2008 that you 13 found a silt layer in the piping between two valves 14 related to auxiliary feedwater system and you flushed 15 it and got rid of the silt.
16 My question is how do you know that you don't 17 have recurrence of this issue, and how would impact the 18 operation of the auxiliary feedwater system if it did 19 recur?
20 MR. CUSTER: Can you restate that question?
21 DR. BARTON: You got silt between two 22 valves in the auxiliary feedwater system.
23 MR. CUSTER: Okay.
24 DR. BARTON: You flushed it out and got rid 25 of the silt. That's end of story. Now I'm saying, well, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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149 1 how do you know that you're not going to get silt 2 accumulated again? If you do get a bunch of silt between 3 the two valves, how will that affect the auxiliary 4 feedwater system if you got to operate these valves and 5 it goes to a pump or -- I know what these valves do.
6 So, yes, how do you know that you solved the problem 7 long term?
8 MR. BYRD: I believe we do periodic 9 flushing, and that's something we'll have to verify and 10 get back with you on. I don't have any information with 11 me right now.
12 MEMBER STETKAR: Just for clarification, 13 when I read that, if you could clarify, it was assuming 14 that's an alternate suction from your raw water system.
15 MR. BYRD: That's an alternate suction from 16 the raw water system to auxiliary feedwater. It's a 17 stagnant line.
18 MEMBER STETKAR: Yes.
19 MR. BYRD: And my recollection is; and I 20 need to verify this, that we do periodic flushing of 21 that as a result of this issue. But I need to verify 22 that.
23 MEMBER STETKAR: Okay.
24 DR. BARTON: Okay. Thanks.
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150 1 proposed actions was to replace -- you thought these 2 graphoil washers may be the source of the leakage.
3 And my question is since this condition has 4 been going on for several years I wondered if you have 5 replaced these washers. And if you did, has it affected 6 your leakage rate?
7 MR. BYRD: We have David Chew here as our 8 program owner.
9 MR. CHEW: My name is David Chew. I'm the 10 refueling canal system engineer. We haven't done 11 anything with the washers themselves. When we first 12 identified the issue, we looked into using an epoxy liner 13 in 2005 to seal the canal. We applied that at the end 14 of the outage. When we went into the refueling outage 15 in 2006, the liner started to de-laminate and it didn't 16 serve its purpose, so we were going forward. We thought 17 maybe it was a condition we didn't apply the liner 18 correctly. So in the next refueling outage we had a 19 corrective action established to reline the system, or 20 the refueling canal.
21 Based on -- in that time frame we found some 22 operating experience that the epoxy we were using in 23 the industry wouldn't hold up. So since then I've been 24 working as a system engineer. We've been doing some 25 research in the industry, looking at operating NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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151 1 experience. And I've developed a plan based off of 2 Prairie Island's. And we're going to cap and seal-weld 3 all of those nuts. And we're also going to seal-weld 4 along all the penetrations in the refueling canal coming 5 up in 2014, our 18th refueling outage.
6 DR. BARTON: Okay. Thank you.
7 MR. CUSTER: I believe Mr. Henline has 8 something to add to that.
9 CHAIRMAN SIEBER: All right.
10 MR. HENLINE: I've got a response for your 11 previous question, John, about the silting that was 12 observed in the service water system. We have a PM that 13 every outage we open the valve to flush that system and 14 that commitment's in line with Generic Letter 89-13.
15 DR. BARTON: Thank you.
16 MR. HENLINE: You're welcome.
17 MR. CUSTER: Thank you, Trent.
18 DR. BARTON: One other one. Maintenance 19 Rule inspection. This goes back a ways. You noted 20 there were some areas indicating concrete spalling on 21 the shield building. And we didn't talk about that when 22 went through the shield building earlier. There was 23 a maintenance order pending repair of the spalled 24 concrete. And was that repaired, or do you still have 25 that problem, or --
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152 1 MR. CUSTER: Let Jon Hook answer that 2 question.
3 MR. HOOK: Jon Hook, design engineering 4 manager. The areas that you're referring to were the 5 spalled concrete that's directly above the original 6 construction opening. During the original 7 construction they -- part of the pour-back for that area 8 there are imbedded pipes to allow the concrete to be 9 injected in that area. And so there's been some surface 10 spalling in that. We've identified that.
11 Now, part of our corrective actions for the 12 shield building painting is to repair those areas.
13 DR. BARTON: Okay.
14 MR. HOOK: And that has already been done.
15 DR. BARTON: Thank you. That's all I've 16 got, Jack.
17 CHAIRMAN SIEBER: Okay. Harold, do you 18 have any questions? Harold?
19 MEMBER RAY: No, I have none.
20 CHAIRMAN SIEBER: Sam?
21 MEMBER ARMIJO: No.
22 CHAIRMAN SIEBER: Okay. Well, it's pretty 23 close to 12:00 and our schedule calls for the staff to 24 go over their SER for their portion of the meeting.
25 And I propose that we recess for lunch until 1:00.
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153 1 1:30? Okay. Until 1:30. Thank you.
2 (Whereupon, the above-entitled matter went 3 off the record at 11:46 a.m., and resumed at 1:28 p.m.)
4 5
6 7
8 9
10 11 12 13 14 15 16 A-F-T-E-R-N-O-O-N S-E-S-S-I-O-N 17 1:28 p.m.
18 CHAIRMAN SIEBER: We will renew the 19 Subcommittee meeting on Davis-Besse Nuclear Power 20 Station license renewal application.
21 Again I would point out that it would appear 22 that not everyone here has signed in on the rosters that 23 are in the back of the room. And if you haven't done 24 so, perhaps at the break you could do so, so we have 25 an accurate record of who is here.
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154 1 And secondly, before we begin with the staff 2 presentation, the applicant would like to answer some 3 questions that they had resolved during the lunch 4 period. So I call upon the applicant to do that.
5 MR. HINKLE: Larry Hinkle with the 6 Davis-Besse license renewal team.
7 As related to the earlier question we had 8 on best estimate cycles, in response to RAI 4.3-9 9 submitted under Letter L-11-203 dated 6/17/2011, we've 10 provided a plot of the heat-up events versus years of 11 service. And in that plot you can see that the rate 12 of occurrence in the last 10 years of operation has been 13 about 1.5 cycles per year.
14 MEMBER STETKAR: And we'll get that from 15 the staff directly, so thank you.
16 MR. CUSTER: The response to the second 17 open question I'd like Trent Henline to speak to, please.
18 MR. HENLINE: Trent Henline, engineering 19 program supervisor. I wanted to clarify the storage 20 tank question concerning sealant. So our diesel oil 21 storage tanks or tank does have sealant at the interface 22 and it is raised five inches above grade. Our borated 23 water storage tank does have a sealant around the 24 foundation and it's raised approximately a foot above 25 grade. Our firewater storage tank, as mentioned NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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155 1 before, does not have sealant. It's on a sand/oil bed.
2 It's raised approximately six inches above grade and 3 is internally inspected every five years with the last 4 inspection being performed in 2009.
5 DR. BARTON: Thank you.
6 CHAIRMAN SIEBER: Is that it, Cliff?
7 MR. CUSTER: That's all we have.
8 CHAIRMAN SIEBER: Okay. Thank you very 9 much. Next I'd like to call on John Lubinski to 10 introduce presenters for the staff.
11 MR. LUBINSKI: Thank you, Mr. Sieber.
12 Appreciate it.
13 This afternoon I'd like to introduce our 14 four presenters who are up at the front table. We have 15 Brian Harris, our safety project manager; Bryce Lehman, 16 a structural engineer, DLR; Allen Hiser, who's our 17 senior level advisor; and Benny Jose, who's a Region 18 III inspector. We also have other members of the staff 19 ready to answer questions including our project manager 20 Sam Cuadrado.
21 I would also like to invite the 22 Subcommittee. There were many questions you had of the 23 licensee this morning. If you would like the staff's 24 perspectives on those, please ask. May not be people 25 at the table. People in the audience may be able to NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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156 1 address and provide some further information. And 2 there are a couple of issues that may not show up in 3 the slides, but we'll be responding to your questions 4 this morning in a more proactive manner with respect 5 to some of those.
6 So with that, I'd like to turn it over t 7 Brian.
8 CHAIRMAN SIEBER: Okay. Thank you.
9 MR. HARRIS: Thank you, John. My name is 10 Brian Harris. I'm the safety project manager of the 11 Davis-Besse license renewal application.
12 So I'll begin by providing a brief overview 13 of the LRA and the staff's review, and I'll discuss 14 section 2 of the SER. Then I'll turn it over to Mr.
15 Benny Jose, the Region III inspector who will discuss 16 his license renewal inspection. Then I'll discuss 17 sections 3 and 4 of the SER.
18 So this is a slide that was mentioned 19 earlier that we'll skip because the applicant has 20 already given you the background information to.
21 So we'll go to the next slide, please. NRC 22 review teams conducted two audits and one regional 23 inspection at the Davis-Besse Nuclear Power site during 24 the periods listed on the slide here. The staff started 25 the on-site review with the scoping and screening NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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157 1 methodology audit towards the end of January, the aging 2 management program audits in mid-February. Region III 3 conducts its inspections in April and May, 2011 to review 4 Davis-Besse scoping and screening of the aging 5 management programs. An addition week of regional 6 inspections were held in August of 2011 to review the 7 differences associated with Revisions 1 and 2 of the 8 GALL report and the applicant's license renewal 9 application.
10 So moving onto section 2 of the SER, section 11 2 discusses structures and components subject to aging 12 management review, which is shown on this slide.
13 Next slide. During the scoping and 14 screening methodology audit the staff's review resulted 15 in additional SSCs being included within the scope of 16 license renewal in accordance with 10 C.F.R. 54.4(a)(2).
17 The applicant took appropriate actions to evaluate 18 additional SSCs which were then included into the scope 19 of license renewal. Based on review of the LRA and 20 additional information submitted as a result of requests 21 for additional information, the staff concluded that 22 the applicant's methodology is consistent with the 23 requirements of 10 C.F.R. 54.4 and 54.21(a)(1).
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158 1 of his inspection.
2 MR. JOSE: I'm Benny Jose. I was the lead 3 inspector for the 71002 inspection that we did during 4 April, May and August time.
5 During the April-May inspections we started 6 off with scoping and screening. And overall the scoping 7 and screening were acceptable, however, we did -- our 8 inspections did result in changes to the -- a few changes 9 to the license renewal application. I will give you 10 a few examples here.
11 Some of the out-of-scope systems and 12 non-safety-related systems were -- in their application 13 were not clarified to say why they were not -- why they 14 were truly out of scope. For example, demineralizer 15 system, control rod drive system, you would think they 16 would -- you know, there are several demineralizer 17 systems and also control rod drive system has a pressure 18 boundary function. So the clarification was to add the 19 pressure retaining components of those systems will be 20 in license renewal scope.
21 There was another open item for -- there 22 was no license renewal -- in the license renewal 23 application there was no age management program was 24 assigned to head lift lugs -- head lifting lugs. So 25 those were type of things that we identified during the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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159 1 scoping and screening inspections.
2 Moving on to the --
3 MEMBER STETKAR: Benny?
4 MR. JOSE: Yes, sir?
5 MEMBER STETKAR: Before you move on, I 6 noticed reading through your inspection report 7 comparing to a lot of the inspection reports we've seen 8 let's say in the last couple of years or so you seem 9 to have many more questions about scoping and screening.
10 Is that simply because of the original vintage of this 11 application?
12 MR. JOSE: No, it's the particular style 13 the applicant used.
14 MEMBER STETKAR: Okay.
15 MR. JOSE: Like I was trying to explain the 16 out-of-scope systems, that's one place we concentrate 17 on --
18 MEMBER STETKAR: Sure.
19 MR. JOSE: -- are the truly out-of-scope 20 systems. And when you see things like control rod drive 21 system, it's out of scope. And you tend to think that's 22 got a pressure-retaining function. You know, why is 23 it out of scope? So they had to add clarification.
24 So there were several instances of that. That's why 25 we had more questions on scoping and screening.
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160 1 MEMBER STETKAR: Okay. Thank you.
2 MR. JOSE: The aging management portion of 3 the inspection, in the previous slides, and the licensee 4 also alluded to this, that originally the application 5 was submitted in August 2010 to Revision No. 1 of the 6 GALL. And subsequently in December of 2010 NRC issued 7 Revision 2 of the GALL. And during the NRR's 8 inspections, as well as our first round of inspections, 9 we also came up with several questions to the differences 10 between Rev 1 and Rev 2.
11 So because of the outstanding number of 12 RAIs, we decided to go back to re-look at some of the 13 programs, especially seven or eight programs were 14 completely revised. So that's the reason we had to go 15 back in August for another week of inspection.
16 For the aging management programs, at the 17 time we did the inspection there were 40 aging management 18 programs the licensee had, and we sampled 28 of them.
19 And how we sample or how we select those programs is 20 based on what we look at to see if they are a new program 21 or an existing program, or you know, is it consistent 22 -- you know, looking through that application we can 23 figure out whether it's really consistent with GALL or 24 does it have exceptions identified? And programs 25 -- some programs are controlled by other regulations NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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161 1 like ISI programs. So we tend to not look at those 2 because we will be going back during our next phase to 3 look at those. So that's the reason we selected 28 of 4 the programs that we looked at. Again, examples, like 5 above-ground steel tanks, air quality monitoring 6 systems, boron monitoring. Those are some examples of 7 those. After the inspection they added three more 8 programs. That's why I keep bringing that up we had 9 40 programs at the time.
10 Based on our inspection there were several 11 license renewal application as well as amendments to 12 the application as well as the -- some program procedure 13 changes. To give you some flavor of that, for example, 14 the electrical cables and connections not subjected to 15 10 C.F.R. 50 -- you know, 49. The cables that are in 16 localized -- adverse localized alignments. The GALL 17 required that they looked at all the cables, they 18 inspected all the cables, but the application said the 19 applicant said they will do a representative sample.
20 So we questioned that. So they had to revise the LRA 21 to include that. External surfaces monitoring, you 22 know, there were specific acceptance criteria involved 23 in Rev 2 that you have to inspect components once per 24 fuel cycle. So licensee went about and made changes.
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162 1 out specific commitments, but they did have a local 2 database called an open item number. Several open item 3 numbers were open based on our inspection.
4 Fuel oil chemistry program also had a 5 requirement to look for microbiological activity once 6 ever quarter, that the licensee has taken an action to 7 do that. These are a few examples, or several more 8 examples.
9 Next slide, please. Okay. Now coming to 10 the results. We said before the scoping of SSCs, we 11 did not find any adverse problems, so we did find them 12 to be acceptable with the changes that we brought about.
13 And the documentation supporting the application was 14 audit-able under the rule, and those were all reports, 15 2010-10 and 2011-12. Those were two reports that we 16 documented our inspections results.
17 Any additional questions for me?
18 (No response.)
19 MR. JOSE: In addition, some of the 20 discussion this morning, we could look to some 21 additional information. I would invite my branch chief 22 Ann Marie to talk about the intake now. We have some 23 additional information on that.
24 MS. STONE: Yes, good afternoon. My name 25 is Ann Marie Stone. I'm the branch chief in Region III.
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163 1 I am responsible for license renewal and also 2 responsible for the ultimate heat sink inspections and 3 the component design basis inspections.
4 In July 2011, during the ultimate heat sink 5 inspection, my inspectors walked down -- and I also 6 walked down the intake canal. We were able to get, you 7 know, our eyes on the situation.
8 There's actually two issues with the intake 9 canal. The first is a slope issue. The slope of the 10 walls are not in accordance with the licensing regs and 11 so they are operable but non-conforming with the 12 license. So that is something that the licensee has 13 to fix. But that's already in the Part 50 as a Part 14 50 requirement.
15 The other is, as the licensee, or as the 16 applicant has talked about, is two areas that are 17 actually sinking. It's not that this material slid into 18 the intake canal. It appears that it's just sinking 19 down. And that again is something that they have had 20 contractors -- as they talked about, contractors take 21 a look at that. We as a regional office looked at it 22 from an operability standpoint and we believe that 23 -- again that it is operable, but in a non-conforming 24 condition. We also --
25 CHAIRMAN SIEBER: Are there --
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164 1 MS. STONE: I'm sorry?
2 CHAIRMAN SIEBER: Are there any active 3 mines in the area? I know that further east they mine 4 salt along the Lake Erie shores. Are you aware of --
5 MS. STONE: I am not --
6 CHAIRMAN SIEBER: -- anything that's going 7 on sub-surface?
8 MS. STONE: I am not aware of anything.
9 I do not have that information.
10 CHAIRMAN SIEBER: Okay.
11 MS. STONE: When my inspectors took a look 12 at it back in July, we did ask questions with respect 13 to were there an earthquakes, minor earthquakes, 14 fracking, you know, anything like that going on. And 15 there was some, but very, very minor. We're also trying 16 to figure out what -- you know, change analysis. What 17 is different now than it -- you know, prior to that, 18 prior to the identification of that.
19 MEMBER STETKAR: Has the settling -- do you 20 have any idea whether it's an emergent issue, or is it 21 -- has it been occurring gradually over the 35-year life 22 of the facility?
23 MS. STONE: My understanding is that the 24 license identified it back in 2007. In 2011, as we were 25 doing our inspection; as I said, we walked it down, our NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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165 1 communication, our interview with the system engineer 2 at that time was that basically it did change from 2007 3 to 2011. And I was actually out there back in August 4 of this year, so I saw a slight change between 2011, 5 2012. My inspectors are following up on that. But at 6 this point we're not questioning operability on the --
7 MEMBER STETKAR: Right, I understand.
8 DR. BARTON: Well, didn't this site 9 experience any of that earthquake that went up the East 10 Coast that North Anna felt went up into Ohio?
11 MEMBER STETKAR: It's too far west, I 12 think.
13 DR. BARTON: It was in Ohio. I know Ohio 14 felt some of it. I didn't know whether this site was 15 affected or not.
16 CHAIRMAN SIEBER: They may have had some 17 seismic instrument response here, but I'm not aware of 18 that. But in the 1980s there was a seismic event further 19 east along Lake Erie that was recordable at least 100 20 miles away.
21 MS. STONE: And I guess the other thing I'd 22 like to just add is that I think this was an excellent 23 example of how the license renewal for us here in 24 headquarters as well as the license renewal and those 25 doing Part 50 inspections. And the region worked NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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166 1 together to come to a common understanding of what the 2 issue is and how to proceed from a -- basically on how 3 to fix the issue.
4 MR. JOSE: I would like to touch upon two 5 more items that was brought up during the morning 6 session.
7 The switchyard degradation of foundation.
8 Our teams very specifically noticed that and asked 9 questions of the licensee. The licensee had taken a 10 special -- a specific open item No. 383 to either repair, 11 evaluate the condition and evaluate the process for 12 addressing degradative conditions in the switchyard.
13 And that's where we left it off.
14 And the second issue has to do with the --
15 CHAIRMAN SIEBER: Yes, I'd like to ask the 16 licensee a question there. In a lot of plants that I'm 17 familiar with, in recent years the switchyard -- custody 18 of the switchyard has been divided, and particularly 19 when transmission companies differ from the operator, 20 or the plant operating company. Is that the case at 21 Davis-Besse? In other words, are there items in the 22 switchyard that actually do not fall under the custody, 23 the cognizance of the plant folks?
24 MR. BYRD: So to understand your question, 25 you're asking who is responsible for the maintenance NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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167 1 of the switchyard?
2 CHAIRMAN SIEBER: That's right.
3 MR. BYRD: So the actual work, the 4 activities, the work activities are performed by the 5 Western District of transmission and distribution, 6 however, we do preventative maintenance for activities 7 in the switchyard. In this specific case though the 8 issue you're talking about, you know, we did some 9 research on that. And in this particular activity, this 10 order that was voided by the transmission and 11 distribution apparently, you know, this was done back 12 in 2008. And there was knowledge of that by 13 engineering. At least the plant engineering has the 14 responsibility for monitoring the switchyard. They 15 were aware of that. However, we need to follow and 16 understand how that was -- some of the other implications 17 of voiding that order.
18 CHAIRMAN SIEBER: Well, is there a 19 difference in the standards used by the switchyard -- and 20 I'll use the word "owner" for back of a better word 21 engineering and operating standards that differ from 22 those that one would expect from a nuclear power plant 23 operating equipment? In other words, is there a 24 difference in quality level and timeliness, 25 responsiveness and, you know, procedures and practices?
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168 1 MR. BYRD: We attempt to control that by 2 having -- first of all, we do have a -- oversight of 3 the switchyard by our own electrical maintenance 4 personnel. So whenever we're having switchyard work 5 being performed, we do maintain oversight of that work 6 with our nuclear staff. And in the case of Davis-Besse, 7 until pretty recently the actual switchyard work was 8 in fact performed in house. So we do have a quite of 9 bit of knowledge in house amongst -- with that kind of 10 activity.
11 CHAIRMAN SIEBER: But that's not the case 12 today, right?
13 MR. BYRD: As of today that has been 14 transitioned over to the Western District, that 15 activity, but we do maintain oversight. Whenever 16 they're in the yard, we have personnel in the yard 17 maintaining oversight.
18 CHAIRMAN SIEBER: But it's still under the 19 control of FirstEnergy Corporation?
20 MR. BYRD: That is correct.
21 CHAIRMAN SIEBER: Okay.
22 MEMBER STETKAR: Do you operate the 23 breakers in the switchyard from the owner, or does 24 somebody else operate the actual operation of the 25 breakers?
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169 1 MR. BYRD: The operation of the switchyards 2 in the -- I'm sorry, breakers in the switchyard would 3 be from the unit.
4 MEMBER STETKAR: From the unit?
5 MR. BYRD: That's correct.
6 MR. JOSE: The second item I wanted to talk 7 about was a discussion about manholes and the water.
8 And we were specifically looking at, you know, 9 medium-voltage cables, inaccessible cables, 10 specifically safety-related cables that went through 11 manholes. We asked them to open up a couple of manholes 12 and we only identified one of a few cables that were, 13 you know, going through that particular manhole. And 14 we did find water. So we wanted to see. So they opened 15 it up for us. And there was water in there. And based 16 on that, we asked our question, you know, how are you 17 going to get rid of the water? There were actually -- it 18 was configured as four manholes side-by-side. Two of 19 them had sump pumps installed in them. The initial 20 reaction or people thought that the other two manholes 21 were supposed to drain into the two with sump pumps.
22 And the second round, that's why when we 23 went back in August, we opened that and saw water was 24 still there. It wasn't draining. So at that point they 25 initiated a notification to engineering -- design NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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170 1 engineering to prepare a modification package to install 2 sump pumps. And that's also documented in our second 3 report.
4 CHAIRMAN SIEBER: Okay.
5 MEMBER STETKAR: Benny, I forgot to ask the 6 applicant, is the water -- do you know; and it's probably 7 easier to ask the applicant, but because you've looked 8 at the stuff, is it event-driven or is it groundwater?
9 Are the bottoms of the manholes below 570 where the 10 nominal water table is?
11 MR. JOSE: I don't recall the exact 12 elevation, but it was during rainy season that we there, 13 you know, May, June, as well as August time frame. There 14 was rain in between. But the two of the sump pumps had 15 -- I mean, two of the manholes did have sump pumps and 16 the other two did not.
17 MEMBER STETKAR: And they're installing 18 sump pumps or --
19 MR. JOSE: Right.
20 MEMBER STETKAR; -- or at least making sure 21 the manholes drain to someplace that does have a sump 22 pump?
23 MR. JOSE: Right. And we also noted that 24 the sump pumps would be charging right next to the sump 25 pits. It's true. It pumps right back into that. I NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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171 1 mean, that's -- well, it could be sealed, too. But the 2 modification was supposed to have those things extended 3 out also.
4 CHAIRMAN SIEBER: And the ones where sump 5 pumps were dry?
6 MR. JOSE: Yes.
7 CHAIRMAN SIEBER: Okay. So they were 8 operating the sump pumps?
9 MR. JOSE: Yes.
10 DR. BARTON: I don't remember. Were the 11 cables actually submerged?
12 MR. JOSE: The cable was, yes. The 141-60 13 cable, yes.
14 With that, I'll turn over to Brian.
15 MR. HARRIS: All right. Thanks. Thanks, 16 Benny.
17 So this slide details section 3 of the SER 18 with the following subsection as shown on the slide here.
19 So I won't cover each subsection, but will touch on 20 those which either have an open item or an item of 21 interest.
22 Establish and issue the SER open items of 23 July 31st of 2012. There are four open items related 24 to the shield building crack, operating experience, 25 pressure-temperature limits and upper shelf energy.
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172 1 There are no confirmatory items.
2 CHAIRMAN SIEBER: And responses to all four 3 of these have been submitted to the staff for review?
4 MR. HARRIS: That is correct.
5 CHAIRMAN SIEBER: They're under review 6 right now?
7 MR. HARRIS: Right. So we'll touch on 8 that. In the SER the staff had an open item related 9 to the laminar cracking in the shield building. As the 10 applicant noted, the cracking was observed in multiple 11 locations and the applicant concluded that the cracking 12 was caused by rapid freezing of significant moisture 13 driven into the concrete during an extreme blizzard of 14 1978. Although the root cause determined the initial 15 cracking was event-driven, the staff believes the 16 degradation could continue to grow. Therefore, it 17 should be monitoring a period of extended operation.
18 To address this, the applicant submitted a 19 plant-specific AMP shield building monitoring program 20 to monitor the cracking. The staff reviewed the 21 submittal and required additional information in order 22 to complete its review.
23 Move onto the next slide. So the areas 24 identified on this slide represent the status of the 25 issue at the time the SER with open items was prepared.
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173 1 So since that time the applicant has submitted an 2 updated AMP and additional information which addressed 3 some of these points and which the staff us currently 4 reviewing.
5 The staff's review of the applicant's 6 original submittal identified several areas where 7 additional information is necessary. Specifically, 8 the staff required additional information regarding the 9 adequacy of crack monitoring, the proposed coating and 10 the scope of the program. The staff asked the applicant 11 to explain why non-destructive examination techniques 12 were not going to be used to verify the extent of cracking 13 of 100 percent of the accessible shield building 14 surface.
15 As the applicant noted in its presentation, 16 it has since completed impulse response mapping of the 17 entire accessible surface.
18 The staff also requested more information on how 19 selected core bores would adequately represent the 20 cracked areas throughout the building. For the coating 21 the staff requested more information on the adequacy 22 of the coating that was going to be selected, how the 23 coating would be inspected or when or if it would be 24 reapplied.
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174 1 indicated the cracking occurred as a result of a blizzard 2 which affected the entire site, the staff requested 3 information on why similar cracking did not occur 4 throughout the site and how other concrete structures 5 within the scope of license renewal would be monitored 6 for this type of cracking. And as noted earlier, the 7 staff is evaluating the updated AMP and RAI responses 8 and resolution of the open items pending completion of 9 our review.
10 CHAIRMAN SIEBER: Did you get responses to 11 each of these RAIs?
12 MR. HARRIS: Yes. Yes, we did.
13 CHAIRMAN SIEBER: Okay.
14 MEMBER ARMIJO: Has the staff concluded it 15 agrees with the root cause identified by the applicant, 16 that it was event-driven, or are you not sure?
17 MR. HARRIS: For that one, Bryce Lehman?
18 MR. LEHMAN: Yes, the Region concluded -- I 19 mean, did an inspection of the root cause report and 20 they concluded that it was a reasonable explanation of 21 how the cracking occurred. And I think our focus is 22 also on -- in license renewal on monitoring the cracking 23 and making sure that we understand how it's going to 24 grow or lead to additional degradation.
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175 1 analysis that the structural integrity is satisfactory 2 with the extent of cracking that's now present?
3 MR. LEHMAN: Yes, that's correct.
4 CHAIRMAN SIEBER: Okay. Thank you.
5 MR. HARRIS: Okay. Moving onto the next 6 slide. Open B.1.4-1 is related to the applicant's 7 consideration of aging-related operating experience 8 during the term of the new license. Now this issue h 9 been discussed with the ACRS and previous subcommittees, 10 most notably the Limerick Generating Station. During 11 its review the staff issued the final license renewal 12 ISG-2011-05 entitled, "Ongoing Review of Operating 13 Experience." This writing emphasizes that operating 14 experience is a key feedback mechanism used to ensure 15 the continued effectiveness of the aging management 16 programs and its activities. A summary of the operating 17 experience review framework described in the ISG is 18 presented on the slide here today.
19 In response to the staff's RAIs, the 20 applicant has described the activities it will us to 21 review operating experience related to aging. The 22 staff is completing its review of these activities in 23 accordance with the framework set forth in the Interim 24 Staff Guidance. Resolution of this open item is pending 25 completing of the staff's review.
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176 1 Next slide, please. So section 4 of the 2 SER contains the staff's review of time-limited aging 3 analysis, or TLAA. TLAAs are certain plant-specific 4 safety analyses that involved time-limited assumptions 5 defined by the current operating term and must be listed 6 by section 54.21(c)(1) and any plant-specific 7 TLAA-based assumptions per 54.21(c)(2). The staff 8 reviewed information in the LRA to determine whether 9 the applicant has provided sufficient information 10 pursuant to 54.21(c)(1) and (c)(2).
11 So open item 4.2.4-1, this addresses the 12 methods and bases that will be used to generate the 13 applicant's P-T limit curves for the period of extended 14 operation when submitted in accordance with the tech 15 spec section 5.6.4 requirements for P-T limit curve 16 provisions. Reactor vessel extended belt line 17 components, including nozzles will pass a neutron 18 fluence exposure of 1 times 10 to the 17th neutrons per 19 centimeter squared during the period of extended 20 operation. Therefore, the applicant must consider the 21 effects of neutron embrittlement on P-T limits for these 22 extended belt line components.
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177 1 extended operation. The applicant has provided a 2 response to this RAI and the staff is currently reviewing 3 the response.
4 All right. Moving on to the next open item, 5 open item 4.2-1 addresses the applicant's upper shelf 6 energy calculations for the LRA. The rule requires that 7 the USE value for ferritic components in the belt line 8 region of the reactor vessel must be at least 50 9 foot-pounds at the end of the licensing operating term.
10 This applies to the expiration of the period of extended 11 operation for plants that have been granted license 12 extensions based on the 60-year fluence projections for 13 the belt line components. This is why the LRAs include 14 TLAAs on the USE analysis. If the applicant cannot 15 demonstrate that the end-of-life USE value for the belt 16 line component would be greater than or equal to 50 17 foot-pounds, the rule allows licensees to demonstrate 18 acceptable resistance to fractures through an 19 equivalent margin analysis.
20 The applicant used a generic USE value of 21 70 foot-pounds for the Linde 80 reactor vessel welds 22 to project the USE for the period of extended operation.
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178 1 80 -- Linde 80 welds. The use of an average value is 2 not a conservative approach as opposed to, for example, 3 a lower bounding or a mean minus two standard deviation 4 value.
5 In lieu of justifying that the 70 foot-pound 6 initial upper shelf energy the applicant's RAI response 7 includes an equivalent margins analysis for the Linde 8 80 welds. The staff is currently reviewing these 9 analyses to determine whether they meet the regulatory 10 requirements of 10 C.F.R. Part 50 Appendix G for the 11 period of extended operation.
12 MEMBER SHACK: When you're dealing with 13 something like this where you don't have data on the 14 specific weld, would you accept the lowest value if the 15 mean minus two standard deviations was lower?
16 MR. HARRIS: Dr. Hiser, would you --
17 MEMBER SHACK: I mean, this is -- you know, 18 it's a question of sample-bound versus population-bound 19 there.
20 DR. HISER: Yes, I guess a short answer is 21 it's case-dependent. I mean, we would have to look at 22 all of the data and the justification. In general, I 23 think that probably is something that we would find favor 24 with, using the lowest value.
25 MEMBER SHACK: Oh, using the lowest value?
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179 1 Even if the mean minus two is lower?
2 DR. HISER: We'd have to look at all the 3 data. I mean, again, if it's three data points, then 4 that might create a difficulty. But in this case they 5 were able to us copper fluence correlation for fracture 6 toughness to do the EMA. So the --
7 MEMBER SHACK: Yes.
8 DR. HISER: -- initial upper shelf 9 energy --
10 MEMBER SHACK: Becomes a moot point, right.
11 Well, I guess I just don't see why you'd find that 12 acceptable. I mean, why would I take a sample-bound 13 rather than population-bound?
14 DR. HISER: As I said, it would be 15 case-by-case. I think in general we do like --
16 MEMBER SHACK: I'll be asking this question 17 quite often.
18 MR. HARRIS: The SER also included on 19 proposed license condition related to inspecting 20 inaccessible portions of the steel containment vessel.
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180 1 inaccessible areas at the bottom of the steel 2 containment vessel. If the water is in contact with 3 the vessel, it could cause corrosion which would remain 4 undetected during the period of extended operation.
5 To address this concern staff has proposed 6 a license condition requiring the applicant to remove 7 concrete from a low point of the containment in order 8 to inspect the inside surface of the containment vessel.
9 If leakage is not successfully stopped or if the initial 10 inspection identifies water, the inspection will be 11 repeated during the period of extended operation.
12 These inspections will provide reasonable assurance 13 that any degradation to the imbedded portions of the 14 containment vessel will be identified. The staff 15 believes this issue is appropriate as a license 16 condition because it affects containment, and without 17 these inspections the areas identified would not 18 normally be inspected. It is possible that the 19 degradation of the containment vessel could be occurring 20 without an adequate method of detection.
21 MEMBER STETKAR: Brian, before you switch 22 slides, I have a couple of questions. The first one 23 is; and we asked the applicant, this -- as I understand 24 it, they're going to take their core bore at a location 25 that's about 30 inches above bottom dead center of the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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181 1 reactor -- of the containment shell. How does an 2 inspection at that location provide confidence that 3 indeed you have not had a fairly large area of 4 boric-acid-containing water in contact with that steel 5 shelf within that 30-inch-deep hemisphere? Or -- it's 6 not a hemisphere, but --
7 MR. HARRIS: Bryce, do you have --
8 MR. LEHMAN: Yes, I think -- I mean, you're 9 right they're not taking it from the --
10 MEMBER STETKAR: I mean, you know, I could 11 look at the side of the -- vertical side of the 12 containment also and, you know, it wouldn't give me much 13 confidence about that. So I'm really curious about what 14 -- if you don't find anything there, what does that tell 15 you about the status of the shell at the low point?
16 Because if you do find something, obviously it's a 17 problem.
18 MR. LEHMAN: Yes. Here's where they're 19 proposing to take the cores. So even that I think was 20 about 30-inch delta there.
21 MEMBER STETKAR: That's what it said in the 22 SER, yes.
23 MR. LEHMAN: And I guess ideally dead 24 center would be the best, but I think we felt that this 25 would be a good indication of -- you know if there's NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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182 1 an issue with borated water pooling there --
2 MEMBER STETKAR: If there is, that's true.
3 If there's not, how do you have confidence that indeed 4 five inches below that area there isn't an issue? I 5 mean, if you do find it there, that's certainly an 6 indicator.
7 MR. LEHMAN: That's a good question. I 8 think we can take that and look at it some more detail 9 and see if it's appropriate, but I think our logic was 10 that the odds were if it's been pooling there throughout 11 the --
12 MEMBER STETKAR: We asked the applicant and 13 they -- you know, why they weren't boring bottom dead 14 center and they said, well, they don't want to cut a 15 hole in their sump liner. You know, people understand 16 how to weld, so that's okay. I'm just curious about 17 that.
18 MR. LEHMAN: Yes, I think that's a good 19 question. We can take that and look at it in more detail.
20 MEMBER STETKAR: And since you have this 21 nice picture here, I'm going to come back to my 22 groundwater question, the staff has basically accepted 23 the applicant's program that says, well, we're going 24 to make sure that the drains in the sand pocket area 25 are open. We're going to -- if we can collect any water NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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183 1 from those drains, we're going to monitor that water 2 for chemistry, as I understand it. And, you know, we'll 3 inspect the area that's accessible there at the 4 interface. How does that give us confidence that we 5 don't have corrosion from the exterior of the shell 6 bottom dead center?
7 MR. LEHMAN: Following up on what we just 8 discussed, I think that's a good point. We'll take it 9 as feedback and go back and look at it. But they do 10 have a commitment to take UT measurements at the five 11 locations where they've seen the groundwater coming into 12 the sand region.
13 MEMBER STETKAR: But that's way up --
14 MR. LEHMAN: That's right.
15 MEMBER STETKAR: -- and that's way up at 16 the interface there.
17 MR. LEHMAN: Yes, I thought we had the 18 closeup of that area.
19 MEMBER STETKAR: We have handouts that show 20 that actually.
21 MR. LEHMAN: Okay. Okay.
22 MEMBER STETKAR: But again, in some sense 23 that's relatively high. It's still below groundwater 24 level, I guess, depending on where you are, but it's 25 still relatively high in elevation.
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184 1 MR. LEHMAN: And that's correct. But I 2 guess there we'll have he -- that's where you're going 3 to see the wetting and drying and replenishment of oxygen 4 in that area.
5 MEMBER STETKAR: You're relying on the 6 argument that it's a low-oxygen environment and not 7 conducive to corrosion.
8 MR. LEHMAN: That's part of it, but then 9 also the other -- the license condition we'll be 10 -- they'll be doing UTs from the inside which would 11 identify degradation.
12 MEMBER STETKAR: That's certainly -- yes, 13 I mean, the 30-inch area is certainly below the 14 groundwater level, so that should -- that one, 15 regardless of where they do that bore, ought to give 16 them some indication.
17 MR. LEHMAN: Yes.
18 MEMBER STETKAR: Okay. I was just curious 19 because you were so active in following on the boric 20 acid corrosion, you know, having a license condition 21 for them to do a core bore from the inside, you seem 22 to pretty much accept the groundwater issue from the 23 exterior.
24 MR. LEHMAN: But again, I think that 25 license condition, it wasn't laid out that way in the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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185 1 SER, but that does support --
2 MEMBER STETKAR: Yes, it does.
3 MR. LEHMAN: -- with the UT measurements, 4 yes.
5 MEMBER STETKAR: Thanks.
6 MR. HARRIS: Any other questions while this 7 slide is up, or should I go back?
8 (No response.)
9 MR. HARRIS: Yes, I guess before we get to 10 the conclusions, there were a few items of interest in 11 this morning's session. And if I can have Bill Holston 12 from the staff come forward and discuss --
13 MR. HOLSTON: Bill Holston from the DLR 14 staff. There were two open questions on areas that I 15 have oversight on, buried piping and underground tanks.
16 The question was whether their program was consistent 17 with GALL Rev 3. And I had verified that during the 18 process of evaluating the LRA --
19 DR. BARTON: We only have 2 on GALL, I 20 think.
21 MR. HOLSTON: Say again?
22 DR. BARTON: We only have 2 on GALL, I 23 think.
24 MR. HOLSTON: What did I say?
25 DR. BARTON: You said Rev 3.
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186 1 MR. HOLSTON: Sorry. Rev 2.
2 DR. BARTON: No wonder none of this makes 3 sense, you know? I'm going to spin my head around a 4 few more times if there's another one out.
5 MR. HOLSTON: So, yes, it is consistent 6 with Rev 2 of the GALL, and I believe that's the only 7 outstanding question on the buried piping.
8 On the above-ground tanks program --
9 MEMBER SHACK: No, no, no, no, no.
10 MR. HOLSTON: Okay. Sorry.
11 MEMBER SHACK: Why not make it consistent 12 with the ISG?
13 MR. HOLSTON: With the ISG we will be 14 evaluating that, and so --
15 MEMBER SHACK: It's 03. You're making 16 them consistent with 05.
17 MR. HOLSTON: Correct. Yes, the ISG, we 18 need to look at -- there are several plants we have to 19 look at that are currently in process. The ISG just 20 got issued, you know, right in August. So we'll be doing 21 that and issuing it -- as necessary, issuing separate 22 RAIs. This suspects several claims will have RAIs, but 23 we need to talk that over with DLR management.
24 Any other questions on buried pipe?
25 (No response.)
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187 1 MR. HOLSTON: Okay. On above-ground 2 tanks, the diesel fuel storage tank was a tank that had 3 -- in 2002 had some degradation that was noted that was 4 repaired at that time. In 2008, they did a follow-up 5 examination. They just found minor chips in the 6 painting that, you know, could have been just some 7 -- from some mechanical damage, but no further evidence 8 of corrosion in that area.
9 And then other question of course was the 10 GALL Rev 2 question, and the above-ground tanks program 11 was consistent with GALL Rev 2.
12 Any other questions on the above-ground 13 tanks program?
14 DR. BARTON: Thank you. No.
15 MR. HOWARD: Thank you, Bill.
16 MR. HARRIS: And also I would like to have 17 Bryce add a few items towards the groundwater issue as 18 discussed this morning.
19 MR. LEHMAN: Yes, I guess there was also 20 a question about the sampling of the groundwater for 21 aggressiveness. I should have addressed that earlier.
22 I went back and looked at the SER when we 23 were discussing it earlier this morning and it's clear 24 that it's unclear in the SER that the staff was -- we 25 knew when we were reviewing it that their enhancement NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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188 1 was sampling raw water, but I think the wording does 2 -- is confusing, so we'll definitely go back and take 3 a look at straightening that out. But I think the key 4 with the aging management was that they had admitted 5 from the very beginning that they had aggressive 6 groundwater, so there wasn't an issue with continuing 7 to sample to prove whether or not it was aggressive.
8 They were assuming it was aggressive moving forward.
9 And to address that they were suggesting a one-time 10 inspection, basically with two core bores from the 11 locations of known groundwater leakage.
12 MEMBER STETKAR: And also opportunistic, 13 as I understand it.
14 MR. LEHMAN: Yes. Yes, the opportunistic.
15 That's correct.
16 MEMBER STETKAR: Okay.
17 MR. LEHMAN: So, does that kind of answer 18 the question a little bit?
19 MEMBER STETKAR: Yes, it does. I mean, I 20 was -- I did get confused because it said well water.
21 And I thought, well, maybe their groundwater is mostly 22 Lake Erie or something like that. But that clears it 23 up. Thank you.
24 MR. HARRIS: All right. Thank you, Bryce.
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189 1 energy --
2 DR. HISER: I want another crack at that 3 answer. In the distribution of data, for the lower 4 bound to be below the lowest data point with any 5 reasonably sized data set, the deviations have to be 6 on the high side. So if I have real high values that 7 are skewing the standard deviation to be very large, 8 that's probably about the only case where you would end 9 up with the mean minus two sigma being below all of the 10 data. And we went through a case with another plant 11 recently on license renewal where they actually were 12 mixing upper shelf data with some transition data and 13 had a very high deviation, standard deviation. I guess 14 I'd fall back to my first answer that it would be 15 case-by-case, but I think that would be the kind of thing 16 that we would want to look at as we evaluate each 17 individual data set.
18 MEMBER SHACK: Well, I can understand you 19 might want to understand whether the data looked normal 20 that you distributed or not, but I've sort of convinced 21 myself that it would be normally distributed. I still 22 don't see why I wouldn't take the two sigma answer over 23 the sample lower bound.
24 DR. HISER: I don't know, Jeff Poehler, do 25 you have any thoughts on that from the PE perspective?
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190 1 Mean minus two sigma versus the lowest value?
2 MR. POEHLER: Jeff Poehler, senior 3 materials engineer in the Vessel Integrity Branch in 4 Division of Engineering.
5 I don't really have any input other than 6 yours. I think -- I mean, going back to -- the question 7 was -- I'm not -- I think the question was --
8 MEMBER SHACK: My question is when I'm 9 dealing with a population and I'm dealing with a sample, 10 how do I choose a population bound? And you gave me 11 two answers. And I didn't like one of them.
12 MR. POEHLER: Well, I think Dr. Hiser's 13 answer was a good one. I think -- I mean, normally -- you 14 know, normally the two sigma is not going to be below 15 the --
16 MEMBER SHACK: Well --
17 MR. POEHLER: -- middle of the data set, 18 but --
19 MEMBER SHACK: I mean, I always just think 20 we ought to be keeping in mind that we're generally 21 thinking about looking for populations from samples.
22 And as long as you take that into consideration when 23 you come up with the answer, I'm fine. But I've seen 24 too many people draw a lower bound between the lowest 25 data point they happen to have at the moment, and that NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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191 1 just sort of doesn't fly.
2 MR. POEHLER: Well, I guess as Dr. Hiser 3 said, we would have to look at each case individually, 4 but we would have to make sure that the value we picked 5 really was conservative.
6 MEMBER SHACK: Well, with an EMA, there's 7 no --
8 MR. POEHLER: And it -- yes, exactly. At 9 any rate --
10 MEMBER SHACK: It's moot.
11 MR. POEHLER: At any rate, it's not an issue 12 for this one, so --
13 MR. HARRIS: Thank you. The staff's 14 conclusion will be documented in the final SER. On the 15 basis of its review and pending satisfactory resolution 16 of the open items, the staff will be able to determine 17 that the requirements of 10 C.F.R. 54.29(a) have been 18 met for the renewal of Davis-Besse Nuclear Power Station 19 operating license.
20 This concludes our presentation.
21 CHAIRMAN SIEBER: Okay. Do you require 22 any additional information at this point from the 23 applicant with the SER?
24 MR. HARRIS: We are in the process of 25 reviewing --
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192 1 CHAIRMAN SIEBER: Okay. So you don't --
2 MR. HARRIS: -- responses to --
3 CHAIRMAN SIEBER: You don't know whether 4 you need more information or not?
5 MR. HARRIS: That is correct.
6 CHAIRMAN SIEBER: Okay.
7 MR. HARRIS: So we are in that process of 8 reviewing those RAI responses at this time.
9 CHAIRMAN SIEBER: Okay. But right now the 10 applicant is up to date with responses so far?
11 MR. HARRIS: That is correct.
12 CHAIRMAN SIEBER: Okay. Well, thank you 13 very much. Appreciate it.
14 MEMBER STETKAR: Actually I have a question 15 for Allen only because I can't not ask him a question 16 at one of these things.
17 In the small bore piping --
18 DR. HISER: Yes?
19 MEMBER STETKAR: -- program the 20 applicant's operating experience listed two failures.
21 And I'm fine. There was one -- there was drain line 22 weld failure, which is not something that we're 23 particularly interested in, I think, because they do 24 monitor it and they've done weld overlays.
25 The other one that caught my attention; and NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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193 1 I've just lost the page here, was a failure of -- it 2 says that a metal pipe in the reactor vessel closure 3 gasket leakage monitoring line. Applicant performed 4 an evaluation and determined it was stress-corrosion 5 cracking mainly caused by chloride residue left after 6 water evaporated in the line. Their solution was they 7 replaced the line and they now drain and flush the line 8 after it's used to eliminate chloride residue. And the 9 determination was, well, they basically fixed the 10 problem, so therefore it's not relevant going forward.
11 12 How did they get chlorides in that line?
13 Did you ask at all? I mean, I wouldn't expect chlorides 14 to be in a vessel head leak-off drain line unless it 15 came from the vessel.
16 MR. HARRIS: Yes, Bart Fu is --
17 MR. FU: I didn't quite get your question.
18 MEMBER STETKAR: Okay. There is -- I'm 19 reading from the SER. It says discussing the failure.
20 In the first case the applicant detected a crack in 21 the pipe metal in the reactor vessel closure gasket 22 leakage monitoring line --
23 MR. FU: Right.
24 MEMBER STETKAR: -- during an inspection 25 in 2002. The applicant performed an evaluation and NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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194 1 determined that it was stress corrosion cracking mainly 2 caused by chloride residue left after water evaporated 3 in the line.
4 My question is how did you get chlorides 5 in that leakage monitoring line unless it came from the 6 reactor coolant system, which is somewhat troublesome?
7 MR. FU: You're probably right. You know, 8 they used the line mainly during the outage. But based 9 on the OE, my understanding is when you left some of 10 the remaining water in it and then through operation 11 it could vaporize. And then whatever, you know, 12 residual that got left there, maybe there's some 13 concentration. That's what we understand of the OE.
14 And then the concentration could be a chloride or some 15 induced stress corrosion factor.
16 MS. GALLOWAY: Does the applicant have any 17 further information on that?
18 MEMBER STETKAR: Thanks.
19 MR. HOFELICH: I'm Jake Hofelich. I'm the 20 ISI program owner.
21 The issue with the line is when we flooded 22 up the refueling canal and when we drained it out after 23 refueling, we didn't drain this line. So the line was 24 full of the refueling canal water and when it dried up, 25 it concentrated the chlorides at the bottom of it and NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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195 1 caused the cracking.
2 MEMBER STETKAR: Where's the chlorides in 3 that water coming from? That's supposed to be really 4 nice clean water.
5 CHAIRMAN SIEBER: Yes, because that has a 6 steel liner presumably.
7 MR. DAWSON: Alvin Dawson, chemistry 8 manager at Davis-Besse. I can tell you that we analyze 9 for chlorides in all conditions and -- all conditions 10 in the system, both in the reactor cooling system and 11 in the fueling canal, and at no time do we have chlorides 12 that exceeded our limits, which are less than our tech 13 spec limits. So it -- I can't -- that's all I can speak 14 to, is that we don't -- we wouldn't not have -- we did 15 not have any chlorides that exceeded our limits, which 16 are less than the tech spec limits.
17 MEMBER STETKAR: Do you think this was an 18 accumulation over time just basically because water 19 evaporating in that line --
20 MR. DAWSON: At first glance it would 21 appear to be so.
22 MEMBER STETKAR: Okay.
23 MEMBER ARMIJO: Was that actually measured 24 chloride, or was that just somebody saw some deposits 25 and said that must have been chloride?
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196 1 MEMBER SHACK: They saw a crack and said 2 it must be chloride.
3 DR. HISER: This is a concern we've had 4 going back to Calvert Cliffs, the very first license 5 renewal application, and this was the position that we 6 -- I think they may have had the same operating 7 experience with cracking, and that was where we'd 8 established the position that flushing the line after 9 refueling outages would help to eliminate any 10 contaminants and eliminate the crack concern. So I 11 think it -- I don't know --
12 MEMBER STETKAR: This predates my time, so 13 -- and this is my first chance --
14 DR. HISER: But I think the conclusion at 15 that point was that it was accumulation over a number 16 of refueling cycles where they would have water in there, 17 it would flask to steam, leave deposits and just would 18 slowly accumulate to a level that could cause cracking.
19 MEMBER STETKAR: Thanks.
20 MR. FU: Oh, I just want to elaborate a 21 little bit. Since that OE, I think during the review 22 we asked some specific items, like Limerick, from then 23 on Grand Gulf, you know, make sure they include it in 24 the aging management program. You know, and the 25 -- based on the OE what specific procedures do they have, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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197 1 like, you know, drain line during the outage, things 2 like that. And we learned from the OE.
3 MEMBER STETKAR: Thank you.
4 CHAIRMAN SIEBER: Do any of the 5 Subcommittee Members have questions they would like to 6 ask? John, you usually do. Do you have any additional 7 questions?
8 MEMBER STETKAR: No, I'm pretty happy now.
9 I asked Allen a question.
10 CHAIRMAN SIEBER: Okay. Bill?
11 MEMBER SHACK: No, Jack.
12 MEMBER ARMIJO: Yes, I'm still perplexed 13 with our root cause on your shield building cracking.
14 I think it doesn't explain a lot of the observations 15 and I wonder why the staff has agreed that it's 16 event-driven versus design-driven. But I'm looking 17 forward to reading the report that the applicant's going 18 to send me. I think the important thing is that the 19 conclusion is that that building is structurally sound.
20 That's a more important thing. I agree with that.
21 But what bothers me is that if you don't really nail 22 the root cause, you may not fix the problem. And, you 23 know, I think that what's being done is a good thing 24 to do, but not necessarily the root cause of the problem.
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198 1 perspective of the license renewal review we use things 2 like that that are part of the current licensing basis.
3 And if the staff has made a determination of what's 4 acceptable, then we just go forward with that looking 5 at the condition and likely degradation would occur up 6 to PEO and then during PEO and ensure adequate aging 7 after that.
8 MEMBER ARMIJO: Yes, and I think --
9 DR. HISER: We don't question that 10 decision.
11 MR. LUBINSKI: If I could basically add is 12 in looking, as we said -- number one, this is an open 13 item and we appreciate the input today. And I think 14 what's important, as you said, is we have made a 15 determination today, or I should say the licensee has 16 made a determination it's structurally sound, and we 17 agree with that.
18 In moving forward, if it's structurally 19 sound today, we need to, as part of our aging management 20 programs, have the licensee monitor moving forward the 21 condition. And that's one of the key points that we 22 did have in our open item and asking questions. And 23 we are going to be reviewing moving forward so that we 24 can still make that same determination during the 25 extended period of operation.
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199 1 From a Part 50 standpoint, as Ann Marie 2 Stone said, we do coordinate these issues very close, 3 whether it's a Part 50 issue or Part 54 issue. So this 4 is not something where we're just waiting until the 5 extended period for operation. We will be continuing 6 to look at this during the current 40 years as well.
7 MS. GALLOWAY: And just to clarify a little 8 bit further, too, we don't just accept blindly the 9 outcome of root cause analyses. There are other pieces 10 of information that might come about as part of the Part 11 50 review. To the extent that we need to have an 12 understanding to appropriately define and have 13 reasonable assurance of the aging management programs 14 in the PEO, we do need to assure ourselves that the 15 correct starting point is being established in order 16 to have that determination appropriately defined for 17 the PEO.
18 I think Bryce did indicate that we had also 19 looked at the root cause evaluation and we felt 20 comfortable that it was appropriate and that we could 21 use that then as a basis to define that aging management 22 program.
23 MEMBER ARMIJO: Yes, well, you know, the 24 point I'm trying to make is if after everything you do; 25 the painting, the ceiling, and in your future monitoring NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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200 1 you see those cracks are still growing, that meant you 2 didn't get the root cause because the event didn't 3 happen. The water doesn't get through there anymore.
4 So that means it must have been some other root cause.
5 My opinion is it was simpler than the one that's been 6 proposed, and it still won't do any harm. But, you know, 7 there could be situations where if you don't nail the 8 root cause very well, you put a fix in that doesn't really 9 fix anything and you find out after a long time.
10 MR. LUBINSKI: We appreciate those 11 insights and as we move forward looking at this open 12 item, we will be considering that. And just in a general 13 statement, as -- if a licensee were to put in a -- you 14 know, based on root cause what they looked at as 15 corrective actions and in your example here, if the 16 cracks were to go, we would be back looking into 17 determining whether or not the root cause was adequate 18 at that point. Still could be maybe there's something 19 else with the fix or contributing causes that we would 20 need to look at.
21 MEMBER ARMIJO: Okay. Thank you.
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201 1 on that specific root cause, then you could have a 2 problem. And in this case, that doesn't mean to be --
3 MEMBER ARMIJO: No, it's a general --
4 MR. LUBINSKI: At this point our questions 5 are all on monitoring crack growth, not just on 6 monitoring --
7 MEMBER ARMIJO: The effectiveness of the 8 paint.
9 MR. LUBINSKI: -- the corrective action of 10 the paint. That's correct.
11 CHAIRMAN SIEBER: Any additional 12 questions, Sam? Harold, do you have any questions?
13 MEMBER ARMIJO: Well, I do. You know, I 14 really would like to learn more about that containment, 15 this water coming up through the bottom around the 16 containment, getting up into that pocket. I've always 17 -- that bothers me particularly that there doesn't seem 18 to be much you can do about it.
19 MEMBER SHACK: Think of it as treated 20 water, Sam. It's been filtered through concrete.
21 MEMBER ARMIJO: Bill, I -- that's a torture 22 -- well, you know, I just would like to have the staff 23 think about it a little bit more. If it's a 24 high-chloride water coming up through that interface 25 between the --
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202 1 MEMBER SHACK: Well, that's why they need 2 that sample with the UT working on both sides of it.
3 MEMBER STETKAR: And it's regardless of 4 where they take that --
5 MEMBER SHACK: It will at least tell them 6 what's going on on the exterior.
7 MEMBER ARMIJO: That -- you're right. If 8 the exterior is being badly corroded, that one 9 measurement should pick it up because it's coming up.
10 MEMBER STETKAR: Yes.
11 MEMBER ARMIJO: All right.
12 MEMBER STETKAR: It should be reasonably 13 uniform and --
14 MEMBER ARMIJO: Anyway, next time you 15 present, if you could get --
16 MR. LUBINSKI: I appreciate that. And as 17 Bryce said, in general, looking at our conclusion, we 18 believe today that the information we had that the open 19 items are the only issues we had out there. We are -- we 20 heard some very good questions this morning and the staff 21 is going to go back and reconfirm. We still have that 22 position with respect to those questions with respect 23 to that issue. If we still have the same conclusion, 24 you will be hearing more at the final Committee meeting.
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203 1 John Barton, do you have any questions or comments?
2 DR. BARTON: No, I don't have -- yes, I got 3 some comment. I don't have any questions on the staff's 4 presentation. I thought it was pretty good.
5 In looking at the root cause, you know, I 6 went through that root cause analysis a couple times 7 and I think that they did a real good job. And from 8 the applicant's presentation this morning, if it's not 9 -- if they didn't identify the root cause, then, you 10 know, I'd be surprised. It appears to be the right root 11 cause.
12 Now if Sam's water running uphill changes 13 that, I'll stand to be corrected, but I think it was 14 a good root cause analysis and I think the staff and 15 the applicant made a good presentation of it this 16 morning. So I'm satisfied with the root cause analysis 17 of the cracking.
18 Generally, an overview of the application, 19 the staff pointed out some issues this morning regarding 20 scope issues and some questions on RAIs on what they 21 saw. And I thought for, you know, where we were -- some 22 of that I attributed to maybe GALL 1 and GALL 2, but 23 wasn't too sure if that was really the issue, and I don't 24 think it really was.
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204 1 received over the years, you know, I'm a little 2 disappointed in this, in the thoroughness of the 3 application. I am -- in recent memory can't remember 4 so may RAIs on a section of this application that didn't 5 change between GALL 1 and GALL 2, which is the TLAAs.
6 There were 53 RAIs just on TLAAs, and I think that is 7 the result of a poor job on the part of the applicant 8 in this presentation on TLAAs. And I was disappointed.
9 But this -- I guess that's the -- my main concern with 10 this application.
11 And I know at this point issuing a license 12 extension is not for this Subcommittee to recommend one 13 way or the other, but I think we got some open items 14 plus we're still looking -- the staff's still looking 15 at the root cause.
16 MEMBER RAY: John, why did you say the water 17 was running uphill?
18 DR. BARTON: Oh, I think that was Sam's --
19 MEMBER ARMIJO: No, that was referring to 20 the containment.
21 MEMBER RAY: Water seeks a level, I mean, 22 you know?
23 DR. BARTON: Well, it had nothing to do with 24 the cracking. This is Sam's issues.
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205 1 -- to the sand pocket.
2 MEMBER RAY: Yes, but I mean, the grade 3 level's way up here.
4 MEMBER ARMIJO: It's not running uphill.
5 It's --
6 MEMBER RAY: It's coming up the gap.
7 MEMBER ARMIJO: I know that.
8 MEMBER RAY: Okay. But it's not going 9 uphill in the sense that --
10 MEMBER ARMIJO: Well, it wasn't coming in 11 this way. That's what it is.
12 MEMBER RAY: No. Okay. That's fine.
13 But it's not -- it's only coming to whatever level the 14 groundwater level is, right? It's not migrating above 15 the groundwater level.
16 MEMBER ARMIJO: I just thought that's 17 initially whatever level the groundwater is.
18 MEMBER RAY: It's trying to reach the water 19 --
20 MEMBER SHACK: I think it can throw a fair 21 chunk of --
22 MEMBER ARMIJO: Right, I understand that.
23 MEMBER RAY: Oh, okay. All right. Well, 24 I just couldn't understand the water going uphill 25 comment.
NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com
206 1 MEMBER ARMIJO: But that had nothing to do 2 with the root cause issue.
3 DR. BARTON: No, not at all.
4 MEMBER RAY: I didn't imagine it did.
5 DR. BARTON: No.
6 MEMBER RAY: I just thought maybe --
7 DR. BARTON: Wondering how water runs 8 uphill. I'm sorry I --
9 MEMBER RAY: I thought it was a --
10 MEMBER ARMIJO: Oh, no, no, no.
11 MEMBER RAY: It seemed pretty obvious to 12 me that unless the membrane has 100 percent integrity, 13 which I don't see how it could, you're going to get water 14 coming up there and there isn't going to be anything 15 you're going to do to stop it.
16 DR. BARTON: And we know the membrane is 17 not 100 percent. We know that.
18 That's all I've got, Jack.
19 CHAIRMAN SIEBER: Okay. Thank you very 20 much. Again, at this point I'd like to thank both the 21 applicant and the staff for well-done presentations and 22 a thorough job.
23 I'd also invite at this time any comments 24 from the audience if you would wish to make any.
25 (No response.)
NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com
207 1 CHAIRMAN SIEBER: Seeing none, I think 2 -- and again, thank you for all of your hard work and 3 your responses today. And this meeting is adjourned.
4 (Whereupon, the above-entitled matter went 5 off the record at 2:35 p.m.)
6 7
8 9
10 11 12 13 14 15 16 17 18 19 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com
TM Davis-Besse Nuclear Power Station License Renewal Application Advisory Committee on Reactor Safeguards License Renewal Subcommittee Meeting September 19, 2012
AGENDA Introductions & Opening Remarks
Background
License Renewal Application Overview SER Open Item Review Summary TM Davis-Besse ACRS Subcommittee Presentation 2
Introductions
Barry Allen - Site Vice President Ken Byrd - Director, Site Engineering Cliff Custer - Fleet Project Manager Steve Dort - Project Lead / Coordinator License Renewal Core Team Members Aging Management Program Owners and Subject Matter Experts TM Davis-Besse ACRS Subcommittee Presentation 3
Background - Site Davis-Besse Site
- Southwestern shore of Lake Erie in Ottawa County, Ohio
- 954 Acre Site
- 733 acres leased to US Government as wildlife refuge
- 221 acres for Plant structures & equipment TM Davis-Besse ACRS Subcommittee Presentation 4
Background - Plant Design
- Pressurized Water Reactor
- Babcock & Wilcox nuclear steam supply system with raised-loop design
- 2817 Megawatts thermal / 908 Megawatts electrical rating
- Measurement uncertainty recapture (MUR) power up-rate of 1.6% implemented July 2008
- Bechtel Engineering construction management
- Facility Operating License expires April 22, 2017 Currently operating at 100% reactor power 98 Days On-Line TM Davis-Besse ACRS Subcommittee Presentation 5
Background - Upgrades/Inspections Equipment Improvements/Verifications
- Replaced Reactor Head
- Replaced selected power cables
- Replaced selected Service Water piping
- Replaced Emergency Diesel Generator exhaust piping
- Polar Crane upgrade and insulation replacement
- Palfinger Crane installation
- Completed Reactor Vessel removable core support structure Inservice Inspection -
No unacceptable indications
- Performed Integrated Leak Rate Test of Containment TM Davis-Besse ACRS Subcommittee Presentation 6
License Renewal Application - Project Application Development
- FENOC core team since 2006
- Davis-Besse Program Owners and Subject Matter Experts
- Development of application; audit & inspection interviews; NRC Staff conference calls; RAI responses; and, Commitment development Industry Interaction
- NEI Working Group involvement
- Industry Peer Review Process TM Davis-Besse ACRS Subcommittee Presentation 7
License Renewal Application - Details Application Details
- Application submitted in August 2010
- Developed using NUREG-1801 (GALL) Revision 1
- 43 Aging Management Programs (AMPs)
- 12 New (4 are plant-specific)
- 31 Existing (4 are plant-specific)
License Renewal Commitments
- 49 Commitments
- Included in USAR Supplement (Appendix A of the LRA)
- Managed by FENOC Commitment Tracking Program TM Davis-Besse ACRS Subcommittee Presentation 8
License Renewal Application - Review Audits, Inspections, and Requests for Additional Information (RAIs) based on NUREG-1801 Rev 2
- RAIs & responses addressed differences between GALL Rev 1 & Rev 2
- Audit Schedule (2011)
- Scoping & Screening January 24-28
- Aging Management Program Review February 14-25
- IP 71002 Inspection Schedule (2011)
- Week 1 Inspection April 25-29
- Week 2 Inspection May 9-13
- Week 3 Inspection August 22-26
- Safety Evaluation Report w-Open Items July 31, 2012 TM Davis-Besse ACRS Subcommittee Presentation 9
SER Open Item Review OI 4.2.-1 Reactor Vessel (RV) Neutron Embrittlement OI 4.2.4-1 Pressure-Temperature (P-T) Limits OI B.1.4 Operating Experience (OE)
OI B.2.39 Shield Building TM Davis-Besse ACRS Subcommittee Presentation 10
OI 4.2-1: RV Neutron Embrittlement RV Beltline Upper-shelf Energy (USE) Evaluation
- Generic mean value of 70 ft-lb used to project 52 EFPY USE not statistically-conservative (mean value minus two standard deviations or lowest value)
- Selection of lowest value resulted in 52 EFPY USE of
< 50 ft-lb
- 10 CFR 50 Appendix G requires end-of license USE to be no less than 50 ft-lb, unless it is demonstrated that lower values of USE will provide margins of safety against fracture, equivalent to those required by Appendix G of Section XI of the ASME Code FENOC Response
- In accordance with 10 CFR 50 Appendix G, FENOC elected to qualify welds by equivalent margins analysis (EMA)
TM Davis-Besse ACRS Subcommittee Presentation 11
OI 4.2-1: RV Neutron Embrittlement (cont.)
EMA status for the RV beltline welds
- Nozzle Belt Forging to Bottom of RV Inlet/Outlet Nozzle Forging Welds
- EMA submitted by letter dated June 14, 2012
- Upper Shell Forging to Lower Shell Forging Circumferential Weld (WF-182-1)
- EMA was addressed in the LRA
- Nozzle Belt Forging to Upper Shell Forging Circumferential Weld and Lower Shell Forging to Dutchman Forging Circumferential Weld
- EMA submitted by letter dated September 14, 2012 Open Item Status
- Response to RAI 4.2.2-4 under review by NRC TM Davis-Besse ACRS Subcommittee Presentation 12
OI 4.2.4-1: P-T Limits RAI 4.2.4-1 Request
- Describe how the P-T limit curves to be developed for use in the period of extended operation, and the methodology used to develop these curves, considered all RV materials (beltline and non-beltline) and the lowest service temperature of all ferritic RCPB materials
- 10 CFR 50 Appendix G requires P-T Limits to be developed for all ferritic materials of reactor coolant pressure boundary (RCPB)
- RV nozzles, penetrations & other discontinuities may exhibit significantly higher stresses that potentially result in more restrictive P-T Limits
- Non-beltline components may have initial RTNDT values that define a more restrictive lowest operating temperature TM Davis-Besse ACRS Subcommittee Presentation 13
OI 4.2.4-1: P-T Limits (cont.)
FENOC Response
- Davis-Besse P-T Limits generated in accordance with 10 CFR 50 Appendix G and R.G. 1.99 Rev. 2 using methods described in approved topical report BAW-10046A
- BAW-10046A considered all ferritic materials (beltline & non-beltline material)
- The RV outlet nozzle, due to consideration of loading conditions, is more limiting relative to stress than any of the Class 1 ferritic branch connections (e.g., hot leg surge nozzle),
the large bore RCS piping, or the primary nozzles of the steam generator TM Davis-Besse ACRS Subcommittee Presentation 14
OI 4.2.4-1: P-T Limits (cont.)
- BAW-10046A considered all ferritic materials (beltline & non-beltline material) (cont.)
- Initial RTNDT of all RCPB ferritic items were considered when establishing P-T Limits and the lowest service temperature
- Reactor vessel closure head region, outlet nozzles, and beltline region are controlling locations that regulate P-T Limits Open Item Status
- Response to RAI 4.2.4-1 is under review by NRC TM Davis-Besse ACRS Subcommittee Presentation 15
OI B.1.4: Operating Experience (OE)
OE review should consider aging management
- Interim Staff Guidance LR-ISG-2011-05 issued in March 2012
- Address age-related degradation and aging management
- Inform/enhance aging management programs OE Program changes
- Revise OE and Corrective Action Programs
- Flag aging-related OE
- Consideration of material, environment, aging effects &
mechanisms, and aging management program TM Davis-Besse ACRS Subcommittee Presentation 16
OI B.1.4: Operating Experience (OE) (cont.)
- Revise OE and Corrective Action Programs (cont.)
- Provide feedback to aging management program owners
- Provide significant OE on aging to the industry
- Identify training needs Aligned with LR-ISG-2011-05
- Responses to RAIs B.1.4-2 and B.1.4-4 are under review by NRC TM Davis-Besse ACRS Subcommittee Presentation 17
OI B.2.34 Shield Building Describe how sub-surface laminar cracking in the Shield Building will be managed for aging Function & Design of Shield Building Discovery of Laminar Cracking Investigation & Extent of Condition Root Cause Corrective Actions Aging Management Open Item Status TM Davis-Besse ACRS Subcommittee Presentation 18
Shield Building TM Davis-Besse ACRS Subcommittee Presentation 19
Shield Building (cont.)
Purpose of Shield Building
- Biological shielding
- Environmental protection for Containment Vessel
- Controlled release of Annulus atmosphere under accident conditions TM Davis-Besse ACRS Subcommittee Presentation 20
Shield Building Flutes/Shoulders TM Davis-Besse Update Davis-Besse ACRS Subcommittee Presentation 21
Shield Building Flute Shoulders Architectural Feature Shield Building
- The flute shoulders are a part of the Shield Building; concrete for shoulders and building shell was placed concurrently
- Evaluation of structural capacity of Shield Building does not credit flute shoulders
- Evaluated as a dead load Auxiliary in structural analysis Building Roof TM Davis-Besse ACRS Subcommittee Presentation 22
Discovery Cracking found on October 10, 2011, during hydro-demolition NRC resident notified Condition Report written Restraint on restart established Team of experts to investigate issue mobilized TM Davis-Besse ACRS Subcommittee Presentation 23
Investigation Impulse Response (IR) testing methodology used to investigate extent of crack TM Davis-Besse ACRS Subcommittee Presentation 24
Investigation (cont.)
Core bores taken to validate IR testing results, to determine crack depth and to determine crack width Investigation results were documented in the corrective action process, and the NRC was promptly notified of findings TM Davis-Besse ACRS Subcommittee Presentation 25
Summary of Shield Building Condition Cracking is generic to flute shoulder regions and can be assumed to be present at any elevation in the flutes shoulders; cracking was observed to be more prevalent on the south side of the building Cracks are located near the outer reinforcing mat; no cracking observed in interior reinforcing mat Left boundary of RVCH opening TM Davis-Besse ACRS Subcommittee Presentation 26
Summary of Shield Building Condition (cont.)
Cracking exists at the top 20 feet of the Shield Building wall outside the flute shoulder region Two small regions adjacent to the Main Steam Line penetration have similar cracks
- The extent of these regions is localized and unique to these particular penetrations Cracks are very tight TM Davis-Besse ACRS Subcommittee Presentation 27
Structural Evaluation Original Shield Building design
- Building designed and constructed with significant reinforcement
- Significant margin under design basis loads
- Design Basis
- Earthquake 6-6.5 on Richter magnitude scale
- Tornado winds of 300 miles per hour
- Tornado depressurization and missiles Impact of laminar cracks on original design
- Potentially reduce the bond strength between concrete and reinforcing steel
- Cracks of little impact unless reinforcing bars are spliced in the cracked region TM Davis-Besse ACRS Subcommittee Presentation 28
Bounding Building Analysis Bond strength of reinforcement lap splices with adjacent cracks could not be quantified and were conservatively treated as non-existent in analysis Calculations performed to provide a bounding evaluation of the effect of cracking
- Vertical and horizontal reinforcement assumed ineffective for strength in flute shoulders, two steam line penetration areas and in regions at top of shield building.
Any bond between reinforcement and concrete in crack regions provides additional margin TM Davis-Besse ACRS Subcommittee Presentation 29
Summary of Calculation Results Shield Building meets strength requirements Any bond between the concrete and reinforcement in cracked regions would be an additional margin of safety Shield Building is capable of performing all safety functions with margin TM Davis-Besse ACRS Subcommittee Presentation 30
Root Cause Overview Established independent team of experts Established a comprehensive Failure Modes Analysis Investigated the design, materials, construction methods, and present day operational conditions Performed concrete tests Performed analyses Identified root cause TM Davis-Besse ACRS Subcommittee Presentation 31
Root Cause Overview (cont.)
Performance Improvement International (PII)
- The PII team are experts in root cause investigation
- Team consist of Professional Engineers, PhDs, and university professors
- Performed more than 500 root causes Industry experts as well as assistance from FENOC Engineering Followed our established and proven root cause process TM Davis-Besse ACRS Subcommittee Presentation 32
Shield Building Root Cause Fault Tree TM Davis-Besse ACRS Subcommittee Presentation 33
Shield Building Concrete Concrete was subjected to a series of tests 36 concrete cores from the Shield Building tested Concrete properties were determined Test results confirmed the concrete is sound and can be ruled out TM Davis-Besse ACRS Subcommittee Presentation 34
Shield Building Concrete (cont.)
Typical concrete sample showing the laminar crack sheared the coarse aggregate Therefore, laminar crack occurred after the concrete achieved it strength TM Davis-Besse ACRS Subcommittee Presentation 35
Shield Building Concrete (cont.)
No evidence of micro cracks No signs of cyclic load mechanism No cyclic freeze-thaw mechanism No indication of fatigue or age related events Magnification at 100 Times TM Davis-Besse ACRS Subcommittee Presentation 36
Shield Building Concrete Tests (cont.)
16 samples were tested for carbonation
- Average depth of carbonation is 8.57 mm (0.337 inches)
- Maximum average 11.7 mm ( 0.46 inches)
- Typical for concrete 40 years old TM Davis-Besse ACRS Subcommittee Presentation 37
Shield Building Concrete - Conclusion Crack passed through the course aggregate
- Strong bond between the cement paste and the coarse aggregate; therefore, initial placement concerns can be ruled out
- Large tensile force is required to initiate the crack No micro cracks identified that would indicate freeze-thaw or cyclic events Chemical properties, carbonation, corrosion, etc, were all acceptable Based on the above, concrete can be ruled out as an initiating or contributing cause TM Davis-Besse ACRS Subcommittee Presentation 38
Shield Building Configuration Cracking is predominantly located in the shoulder areas, the top 20 feet of the Shield Building, and near the Main Steam Line penetration block-outs; cracking concentrated on southern exposures Shoulder areas are regions of discontinuity Limited radial reinforcing steel in the shoulder areas High rebar density (6 spacing) located at the top of the Shield Building and around the Main Steam Line penetration construction block-outs Conclusion
- There is a correlation between the crack locations and the physical layout of the reinforcing steel that needed to be investigated TM Davis-Besse ACRS Subcommittee Presentation 39
Shield Building Analytical Analyses Numerous computer analyses were performed for normal design conditions
- Self weight, wind loads
- Thermal analyses (summer hot and winter cold conditions)
- Fujita Category 2 tornado Stresses were significantly below the normal tensile capacity of the concrete TM Davis-Besse ACRS Subcommittee Presentation 40
Shield Building Analytical Analyses (cont.)
Analysis showed:
- Design stresses can not initiate the laminar crack
- Significant stresses beyond what is normally analyzed would be required to crack the concrete Investigate industry experience for similar conditions TM Davis-Besse ACRS Subcommittee Presentation 41
Industry Experience with Laminar Cracks Ontario Ministry of the Environment study on 50 above ground water tanks in Ontario Water migrated into the concrete from the inside
- Inner layer of the wall freezes and expands
- Outer layer of wall contracts
- Creates high radial stress
- Results in laminar cracking
Conclusion:
Laminar cracking as a result of water freezing is a real potential TM Davis-Besse ACRS Subcommittee Presentation 42
Shield Building Investigation into Water Intrusion/Freezing The effects of moisture intrusion and sub freezing temperatures was investigated as a possible cause The review of severe environmental conditions that the plant was exposed to was performed The most significant event recorded at the site and also in Ohio history was the storm of January 25-27, 1978 TM Davis-Besse ACRS Subcommittee Presentation 43
Moisture Intrusion and Low Temperatures January 25-27, 1978, was the worst in terms of:
- Moisture
- Winds
- Temperature
- Duration
- Pressure TM Davis-Besse ACRS Subcommittee Presentation 44
Moisture Intrusion and Low Temperatures (cont.)
Scenario:
- Temperature near zero
- Sustained strong winds
- Moisture penetrated the Shield Building
- Moisture trapped in the outer layer of concrete crystallized
- Concrete expansion exceeded the tensile capacity of the concrete and propagated the crack TM Davis-Besse ACRS Subcommittee Presentation 45
Moisture Intrusion and Low Temperatures (cont.)
A complex computer model of the Shield Building was developed Concrete properties from the concrete core tests were used Laboratory tests showed moisture infiltration up to four inches Maximum radial stress in the shoulder area were approximately the tensile capacity of the concrete High stresses were located in areas of observed cracking Max 550 psi TM Davis-Besse ACRS Subcommittee Presentation 46
Sensitivity Analysis - High Density of Rebar A complex computer model evaluated the affects of rebar spacing to determine the potential for developing cracks Evaluation showed laminar cracks could:
- Form in regions of closely spaced rebar and
- Less likely in areas were the rebar is spaced at 12 inches This analysis establishes that rebar spacing is a probable contributing factor TM Davis-Besse ACRS Subcommittee Presentation 47
Summary of Analyses Normal design conditions result in low stresses which could not cause cracking Moisture and freezing could cause high stresses in the shoulder areas that results in cracking Analysis shows closely spaced reinforcing steel can be a contributor to laminar cracking Observed cracking coincides with the locations of high stress in the shoulder areas and in the areas of high density of rebar; cracking concentrated on southern exposures TM Davis-Besse ACRS Subcommittee Presentation 48
Shield Building Root Cause Root Cause:
- Lack of water sealant on the concrete exterior Contributing Causes:
- Shoulder reinforcing details (discontinuity and no radial rebar)
- High density of rebar spacing
- High moisture, severe wind, and low temperature conditions TM Davis-Besse ACRS Subcommittee Presentation 49
Shield Building - Preventive Action Root Cause
- Lack of concrete sealant Preventive Action to Prevent Recurrence
- The exposed exterior surfaces of the Shield Building will be sealed
- Contractor has started and is expected to be completed this year TM Davis-Besse ACRS Subcommittee Presentation 50
Shield Building - Additional Actions The Root Cause has established several additional Corrective Actions
- Complete Impulse Response (IR) examinations on the Shield Building wall
- Perform IR mapping on another structure (Auxiliary Building) to confirm assumptions of our analyses
- Develop and implement a test program to establish capacity in an area of laminar cracks
- Develop a Long-Term Monitoring program TM Davis-Besse ACRS Subcommittee Presentation 51
Additional Actions - IR Mapping Complete IR examinations on the Shield Building wall and an independent structure
- All accessible areas of the Shield Building wall were mapped
- Over 60,000 individual readings were obtained to fully characterize the condition of the building TM Davis-Besse ACRS Subcommittee Presentation 52
Additional Actions - IR Mapping (cont.)
The IR validated our original assessment that the laminar cracks are generally confined to:
- The shoulder areas
- Top of the Shield Building
- Near one corner of the Main Steam Line penetration
- Southern exposure Impulse Response reading on an independent site structure validated that laminar cracks are not present TM Davis-Besse ACRS Subcommittee Presentation 53
Additional Actions - IR Mapping (cont.)
TM Davis-Besse ACRS Subcommittee Presentation 54
Additional Actions - Testing Tests were developed and conducted at two nationally recognized universities Professors are industry experts and are American Concrete Institute (ACI) Committee members TM Davis-Besse ACRS Subcommittee Presentation 55
Additional Actions - Testing (cont.)
Two different methods were used to create laminar cracks in the samples to be tested Results were independently verified TM Davis-Besse ACRS Subcommittee Presentation 56
Additional Actions - Testing (cont.)
Testing results
- Full capability of reinforcement is maintained in regions with longer splice lengths (upper portion of Shield Building)
- Results showed near to full capability of reinforcement in regions with shorter splice lengths Testing conclusions
- The tests provide high confidence of the capability of the rebar located in regions of laminar cracking
- Testing confirms the assumptions made in structural calculation prior to restart were very conservative TM Davis-Besse ACRS Subcommittee Presentation 57
Additional Actions - Long Term Monitoring Establish a Long-Term Monitoring Program
- FENOC has established a long-term monitoring plan that includes:
- Monitoring existing core bores for crack propagation
- Inspection of the integrity of the Shield Building coatings
- Inspection of the integrity of other safety related building coatings TM Davis-Besse ACRS Subcommittee Presentation 58
License Renewal Application Summary Application has been reviewed to NUREG-1801, Rev. 2 43 Aging Management Programs identified 49 Commitments Site Program Owners and Subject Matter Experts involved in:
- Development of application; audit & inspection interviews; conference calls with NRC; RAI responses; and, Commitment development SER Open Item responses under review by NRC staff Proposed programs address aging management at Davis-Besse for the period of extended operation TM Davis-Besse ACRS Subcommittee Presentation 59
Advisory Committee on Reactor Safeguards License Renewal Subcommittee Davis-Besse Nuclear Power Station Safety Evaluation Report with Open Items September 19, 2012 Brian K. Harris, Project Manager Office of Nuclear Reactor Regulation
Introduction
- Overview
- Section 2: Scoping and Screening Review
- License Renewal Inspections
- Section 3: Aging Management Program (AMP) and Review Results
- Section 4: Time-Limited Aging Analyses (TLAAs) 2
Overview
- LRA Submitted by letter dated August 27, 2010
- Pressurized Water Reactor (PWR),
Babcock & Wilcox nuclear steam supply system
- Operating license for NPF-3 expires April 22, 2017
- Located approximately 20 miles east of Toledo, OH 3
Overview contd
- Scoping and Screening Methodology Audit
- Jan 24-28, 2011
- Aging Management Programs Audit
- Feb. 14-25, 2011
- Regional License Renewal Inspections
- April 25-29, 2011
- May 9-13, 2011
- Aug 22-26, 2011 4
Section 2 - Structures and Components Subject to Aging Management Review
- Section 2.1 - Scoping and Screening Methodology
- Section 2.2 - Plant-Level Scoping Results
- Section 2.3 - Scoping and Screening Results Mechanical System
- Section 2.4 & 2.5 - Scoping and Screening Results Structural & Electrical 5
Section 2 - Structures and Components Subject to Aging Management Review
- The staff determined through a review of documents, discussions and plant walkdowns:
- nonsafety-related pipe attached to safety-related pipe had not been included within the scope of license renewal to ensure structural integrity
- equipment that was no longer required had been placed in an abandoned state
- nonsafety-related domestic water valve and other nonsafety-related fluid filled SSCs, which could potentially impact safety-related SSCs through spray or leakage, had not been included within the scope of license renewal.
6
71002 Inspection Summary
- 54.4 Scoping & Screening SSCs
- Reviewed 28 of 40 AMPs during April-May 2011
- Operating Experience Review 7
71002 Inspection Results
- Inspection results support a conclusion there is reasonable assurance that the effects of aging will be adequately managed
- Scoping of SSCs was acceptable
- Documentation supporting the application was auditable & retrievable
- Reports 05000346/2011010 &
Section 3 - Aging Management Review
- Section 3.0 - Aging Management Programs
- Section 3.1 - Reactor Vessel & Internals
- Section 3.2 - Engineered Safety Features
- Section 3.3 - Auxiliary Systems
- Section 3.4 - Steam and Power Conversion System
- Section 3.5 - Containments, Structures and Component Supports
- Section 3.6 - Electrical and Instrumentation and Controls System 9
Safety Review Results
- Safety Evaluation Report with Open Items was issued July 2012
- 4 Open Items OI-3.0.3.2.15-1 Shield Building Cracks OI-B.1.4-1 Operating Experience OI-4.2.4-1 Pressure-Temperature Limits OI-4.2-1 Upper Shelf Energy 10
Shield Building Laminar Cracks Open Item 3.0.3.2.15-1
- Cracks observed in multiple locations
- Cracking event driven
- Additional information required on how the applicant will age manage the laminar cracks in the concrete shield building 11
OI 3.0.3.2.15-1: Information Required
- Cracking
- Justify not verifying extent of cracking with NDE techniques
- Justify adequacy of the core bore inspection sample size, distribution, and inspection frequency
- Describe acceptance criteria and inspector qualifications
- Coating
- Describe inspection methods and acceptance criteria
- Scope of Proposed AMP
- Explain how degradation will be prevented or 12 identified in other structures
Operating Experience for Aging Management Programs (OI B.1.4-1)
- Clarify how operating experience review will address aging to ensure continued effectiveness of AMPs or develop new AMPs
- Final License Renewal Interim Staff Guidance, LR-ISG-2011-05, Ongoing Review of Operating Experience, issued in March 2012
- Screening and identification of incoming operating experience items for potential aging impacts
- Inclusion of AMP findings, GALL Report revisions, and guidance as sources of operating experience
- Consideration of materials, environments, aging effects, aging mechanisms, and AMPs in operating experience evaluations
- Training on aging for personnel that implement AMPs and process operating experience
- Incorporate guidelines for reporting plant-specific operating experience on 13 aging to the industry
Section 4 - Time-Limited Aging Analysis
- Section 4.1 - Introduction
- Section 4.2 - Reactor Vessel Neutron Embrittlement of the Reactor Pressure Vessel and Internals
- Section 4.3 - Metal Fatigue
- Section 4.4 - Environmental Qualification of Electrical Equipment
- Section 4.5 - Concrete Containment Prestress
- Section 4.6 - Fatigue of Primary Containment, Piping, and Components
- Section 4.7 - Other Plant-Specific TLAA 14
Pressure-Temperature Limits Open Item 4.2.4-1
- LRA did not adequately describe how P-T limit curves would be generated for the PEO (§54.(c)(1)(iii))
- Ferritic components of the reactor coolant pressure boundary, including discontinuities such as nozzles, must be considered as potentially limiting components for the generation of P-T curves 15
Upper Shelf Energy (USE)
Open Item 4.2-1
- Applicant must demonstrate a USE value of at least 50 ft-lb for all RV beltline welds at end of life or submit an equivalent margins analysis to demonstrate equivalent margins of safety against fracture.
- The applicant did not provide an acceptable basis for using generic initial value of 70 ft-lbs in developing its USE for the Linde 80 RV beltline welds.
16
Proposed License Condition Containment Vessel Inspection
- Operating experience with borated water leakage migrating through concrete structures inside containment
- Possibility that leakage has come into contact with inaccessible portions of the steel containment vessel causing corrosion
- Staff has proposed a license condition to remove concrete and inspect a normally inaccessible portion of the vessel 17
Conclusion On the basis of its review and pending satisfactory resolution of the open items, the staff will be able to determine that the requirements of 10 CFR 54.29(a) have been met for the license renewal of Davis-Besse Nuclear Power Station 18
19 R-III Summary Site License Renewal Date Extended Period Braidwood 1 & 2 Byron 1 & 2 Clinton Davis-Besse Dresden 2 & 3 Oct-04 Dec-09; Jan-11 Duane Arnold Dec-10 D. C. Cook 1 & 2 Aug-05 Fermi 2 Kewaunee Feb-11 LaSalle 1 & 2 Monticello Nov-06 Sept-10 Palisades Jan-07 Mar-11 Perry Point Beach 1 & 2 Dec-05 Oct-10 (U1)
Prairie Island 1 & 2 Jun-11 Quad Cities 1 & 2 Oct-04 20
Containment Elevation 21