ML062900390

Transcript of ACRS Plant License Renewal Subcommittee, October 3, 2006 in Rockville, Md. Pages 1 - 232. with Related Documentation

ML062900390
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Site:	Oyster Creek
Issue date:	10/03/2006
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Official Transcript of Proceedings AC'-ST i%ýNUCLEAR REGULATORY COMMISSION Title: Advisory Committee on Reactor Safeguards Plant License Renewal Subcommittee Docket Number: (not applicable)

PROCESS USING ADAMS TEMPLATE ACRS/ACNW-005 SUNSI REVIEW COMPLETE Location: Rockville, Maryland Date: Tuesday, October 3, 2006 Work Order No.: NRC-1271.Pages 1-232 NEAL R. GROSS AND CO., INC.Court Reporte'rs and Transcribers 1323 Rhode I land Avenue, N.W.-Washingt6n, D.C. 20005 (202) 234-4433 OQflCAENAL"h-TOIý)I--

DISCLAIMER UNITED STATES NUCLEAR REGULATORY COMMISSION'S ADVISORY COMMITTEE ON REACTOR SAFEGUARDS October 3, 2006 The contents of this transcript of the proceeding of the United States Nuclear Regulatory Commission Advisory Committee on Reactor Safeguards, taken on October 3, 2006, as reported herein, is a record of the discussions recorded at the meeting held on the above date.This transcript has not been reviewed, corrected and edited and it may contain inaccuracies.

I 1 UNITED STATES OF AMERICA 2 NUCLEAR REGULATORY COMMISSION 3 +++++4 ADVISORY COMMITTEE ON REACTOR SAFEGUARDS (ACRS)5 MEETING OF PLANT LICENSE RENEWAL SUBCOMMITTEE 6 +++++7 TUESDAY, 8 OCTOBER 3, 2006 9 +++++10 The meeting was convened in Room T-2B3 of 11 Two White Flint North, 11545 Rockville Pike, 12 Rockville, Maryland, at 1:30 p.m., Dr. Otto Maynard, 13 Chairman, presiding.

14 MEMBERS PRESENT: 15 OTTO MAYNARD Chair 16 GRAHAM B. WALLIS Member 17 WILLIAM J. SHACK Member 18 SAID ABDEL-KHALIK Member 19 J. SAM ARMIJO Member 20 MARIO BONACA Member 21 OTTO L. MAYNARD Member 22 JOHN D. SIEBER Member 23 24 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 2 1 ACRS STAFF PRESENT: 2 LOUISE LUND 3 FRANK GILLESPIE 4 HANS ASHER 5 RICK SKELSKEY 6 DONNIE ASHLEY 7 MICHAEL MODES 8 JIM DAVIS 9 KEN CHANG 10 MIKE HESSLER 11 12 ALSO PRESENT: 13 MIKE GALLAGHER 14 PETE TAMBURNO 15 AHMED OUAOU 16 TERRY SCHUSTER 17 FRED POLASKI 18 PAUL GUNTER 19 RICHARD WEBSTER 20 21 22 23 24 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(2021 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 3 1 C-O-N-T-E-N-T-S 2 AGENDA ITEM PAGE 3 Opening Remarks ..............

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4 4 Staff Introduction

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6 5 Oyster Creek License Renewal Application 6 Michael Gallagher

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8 7 Fred Polaski .........

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..95 8 Tom Quintenz .........

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116 9 SER Overview 10 Donnie Ashley ........ ..............

122 11 Michael Modes ........ ..............

124 12 Aging Managment Program Review 13 and Audits .............

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125 14 Confirmatory Analysis of Drywell 15 Hans Asher .........

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145 16 Public Comments ..........

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184 17 Adjourn 18 19 20 21 22 23 24 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 4 1 P-R-O-C-E-E-D-I-N-G-S 2 1:32 P.M.3 CHAIRMAN MAYNARD: This meeting will now 4 come to order. This is a meeting of the Advisory 5 Committee on Reactor Safeguards, Plant License Renewal 6 Subcommittee.

I am Otto Maynard, Chairman for this 7 subcommittee meeting. ACRS members in attendance are 8 Graham Wallis, William Schack, Mario Bonaca, Jack 9 Sieber, Said Abdel-Khalik and Sam Armijo. Our ACRS 10 consultant, John Barton is also present. Cayetano 11 Santos with the ACRS staff, is a designated official 12 for this meeting.13 The purpose of this meeting is to discuss 14 the license renewal application for the Oyster Creek 15 Generating Station, the Associated Draft Safety 16 Evaluation Report and other related documents.

The 17 Subcommittee will gather information, analyze relevant 18 issues and facts and formulate proposed positions and 19 actions as appropriate for deliberation by the full 20 committee.

The rules for participation in today's 21 meeting were announced in the Federal Register on 22 October 2 nd, 2006. ACRS meetings are conducted in 23 accordance with the Federal Advisory Committee Act.24 They are normally open to the public and provide 25 opportunities for oral or written statements from NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com A

5 1 members of the public to be considered as part of the 2 Committee's information gathering process. I would 3 like to emphasize that these comments should be 4 limited to issues associated with the Oyster Creek 5 Generating Station License Renewal Application.

6 We will hear presentations from 7 representatives of the Office of Nuclear Reactor 8 Regulation, the Region 1 office, and the Amergen 9 Energy Company. We have also received requests for 10 time to make oral statements at today's meeting. Mr.11 Paul Gunter of the Nuclear Information Resource 12 Service and Mr. Richard Webster of the Rutgers 13 Environmental Law Clinic will make their statements 14 following the formal presentation by the Applicant and 15 staff.16 If anyone else in the audience would like 17 to make a statement, please notify Mr. Cayetano Santos 18 during the break and we will try to accommodate your 19 request during the public comment portion of the 20 agenda. We have received one written comment from a 21 member of the public regarding today's meeting. This 22 comment was provided by e-mail from Mr. Bill Hering, 23 dated October 3 rd, 2006. Copies have been distributed 24 to the subcommittee.

A transcript of the meeting is 25 being kept and will be made available as stated in the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 6 1 Federal Register notice. Therefore, we request that 2 participants in this meeting use the microphones 3 located throughout the meeting room when addressing 4 the subcommittee.

5 Participants should first identify 6 themselves and speak with sufficient clarity and 7 volume so that they can be readily heard. Due to the 8 number of people, we do have an overflow room next 9 door. The audience can see the slides in that room.10 So if seating is not available in here, next door 11 there should be some seating. Also due to a large 12 number of people, I request to turn your cell phones 13 off or at least put them on vibrate or your pagers on 14 vibrate to minimize disturbance in the meeting.15 I will now proceed with the meeting, and 16 I call upon Ms. Louise Lund of the Office of Nuclear 17 Reactor Regulation to begin.18 MS. LUND: Okay, thank you. Good 19 afternoon.

My name is Louise Lund. I'm the Branch 20 Chief of License Renewal Branch A in the Division of 21 License Renewal. Beside me is also Frank Gillespie, 22 our Director for the Division of License Renewal. The 23 staff has conducted a very detailed and thorough 24 review of the Oyster Creek Generating Station License 25 Renewal Application which was submitted in July of NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 7 1 2005. Mr. Donnie Ashley, here to my right, is the 2 Project Manager for this review. He will lead the 3 staff's presentation this afternoon on the Draft 4 Safety Evaluation Report. In addition, we have Mr.5 Michael Modes, who is our team leader for the Region 6 1 inspections that were conducted at Oyster Creek.7 We also have several members of the NRR 8 technical staff here in the audience to provide 9 additional information and answer your questions.

As 10 a result of the review, five open items were 11 identified which will be discussed in the 12 presentation.

This also resulted -- our review 13 resulted in the issuance of 108 formal requests for 14 additional information.

I know the ACRS has been 15 interested in the number of questions that have come 16 out in the reviews in the past. We believe part of 17 that reduction is as a result of the generic aging 18 lessons learned report. This application was 19 submitted using the draft GALL report that was issued 20 back in January 2005. However, it was reconciled with 21 a September 2005 version of the GALL report.22 The GALL has certainly helped with the 23 review by providing a roadmap. The staff at Oyster 24 Creek provided excellent support for onsite audits and 25 inspections that were conducted and also the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 8 1 headquarters review through the conference calls and 2 numerous meetings that we've had. And would you like 3 to make some opening remarks?4 MR. GILLESPIE:

Only what we tried to do 5 and you're going to see when Donnie comes on is we're 6 going to try to conserve the Committee's time so that 7 we can kind of focus on questions and answers. We do 8 have a large number of slides but we're going to try 9 to go through them on the staff presentation very 10 quickly and not duplicate what you're going to hear 11 from the licensee.

So we'll make some adjustments 12 because we know, at least in this case there's a 13 number of technical issues. This is the one plant 14 that's the first one to have us focus on this 15 containment shell question which is also a topic of 16 litigation.

17 So you'll also find the staff being very 18 careful and trying to be careful of their words at his 19 point relative to saying anything too definitive about 20 specific findings because this is not the final SE.21 This is the SE with open items. So with that, I'm 22 going to turn it over to Mike Gallagher from Exelon.23 MR. GALLAGHER:

Okay, good afternoon.

My 24 name is Mike Gallagher and I am the Vice President of 25 License Renewal Projects for Amergen and Exelon. For NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 9 1 your information Amergen is an Exelon company so 2 therefore, you'll hear both names today. Here with us 3 today we have Tim Rausch, our Site Vice President and 4 we also have a host of support personnel to answer any 5 questions that may come up. Presenting with me today 6 is Fred Polaski, our License Renewal Manager, tom 7 Quintenz, from Oyster Creek and John Hufnagel, our 8 Project Licensing Engineer.9 Next slide, Slide 3 shows our agenda for 10 today. Note that early in our presentation we will be 11 discussing the drywell corrosion issue. Fred?12 MR. POLASKI: Thank you. My name is Fred 13 Polaski, I'm Exelon's Manager for License Renewal.14 Oyster Creek is a BWR2 with a Mark 1 containment 15 located in Lacey Township, Ocean County, New Jersey.16 Barnegat Bay is the ultimate heat sink for the plant.17 Onsite spent fuel storage is provided in the fuel pool 18 and drycast storage. Current capacity enables onsite 19 storage to the current operating term with full core 20 offload capability.

21 We are currently planning an expansion of 22 the interim spent fuel storage facility to accommodate 23 additional fuel storage through the year 2020.24 MEMBER WALLACE: Is cold water involved, 25 salt water?NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com

• o 10 1 MR. POLASKI: Yes, we do have salt water 2 as the --3 MEMBER WALLACE: (Microphone is not on, 4 inaudible).

5 MR. POLASKI: The GALL does address salt 6 water environments, yes. Yes. Yes, okay, all right.7 An expansion of the spent fuel storage facility beyond 8 2020 could be pursued if it's warranted.

The Oyster 9 Creek PRA was updated in 2004. Our core damage 10 frequency and large early release frequency are shown 11 here on the slide. Next slide, please.12 This is an overhead picture of the Oyster 13 Creek site. Just to give you a point of reference, 14 north is to the top of the slide. The plant is 15 located west of Route 9. The Barnegat Bay is the body 16 of water on the right of the slide. East of Barnegat 17 Bay is the Island Beach State Park and east of that 18 would be the Atlantic Ocean. Water intake is provided 19 by the Forked River at the top of the slide and 20 discharges by Oyster Creek to the Barnegat Bay.21 MEMBER WALLACE: It's a very funny river.22 It goes in a circle. Does it have an end or a 23 beginning?

24 MR. POLASKI: That's not the original 25 river. There was a lot of changes made when this NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 11 1 plant was built to the original -- to the flow of the 2 river.3 MEMBER WALLACE: Where does it come in 4 from that land? Where is the fresh water? Back 5 there? Up there is the fresh water. So it's somehow 6 7 MR. POLASKI: Actually, there's three 8 branches to the Forked River. This is the north 9 branch, this is the middle branch and the lower 10 branch, this other branch is through here and so the 11 original flow of this would have been down here, so 12 this one the intake canal was drastically modified 13 during construction.

14 MEMBER WALLACE: Now, there's some sort of 15 flushing of all this by tides; is that how it works?16 MR. POLASKI: And actually, the flow 17 through the plant is greater typically than the flow 18 down the river, so any of the flow coming down the 19 Forked River then, flow comes through this way into 20 the plant and back out through Oyster Creek.21 And the last thing I'd like to point out 22 on the slide is the Forked River combustion turbines 23 which we'll be discussing later in the presentation, 24 are the station blockout owner of AC power source and 25 they're located adjacent to the switch yard for the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com

• o 12 1 plant.2 CHAIRMAN MAYNARD: And you'll be getting 3 into your agreement on the aging management program 4 for that in your presentation.

5 MR. POLASKI: Yeah, we're going to talk 6 about that later. Slide 6. Oyster Creek is currently 7 operating in the 2 0th operating cycle, a plant 8 transition at 24-month cycles in 1991 and the plant is 9 currently operating in end of cycle coast down.10 Oyster Creek is in the regulatory response column of 11 the NRC Regulatory Oversight Program with one white 12 finding in emergency preparedness.

This finding was 13 due to an event in August 2005 when plant operators 14 did not recognize that plant parameters met the 15 threshold for declaring an emergency action level.16 In addition, a substantive cross-cutting 17 issue in the area of human performance was identified 18 by the NRC staff and communicated in the recent mid-19 cycle performance review. One of the examples cited 20 was the white finding in emergency preparedness.

The 21 station has completed a thorough root cause analysis 22 of these issues and has continued to implement 23 corrective actions to improve performance in this 24 area.25 MEMBER SIEBER: This was a failure to NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 13 1 report or reporting the wrong action level?2 MR. POLASKI: It was a failure to respond 3 to plant conditions when the action level occurred.4 MEMBER SIEBER: Gotcha.5 MR. POLASKI: And actually the 6 declaration was made but it was made much too late for 7 the --8 MEMBER SIEBER: Gotcha, understand.

9 MR. POLASKI: Slide 7. Oyster Creek is one 10 of the 15 power reactors that were issued a 11 provisional operating license. This provisional 12 operating license was issued in 1969. Oyster Creek's 13 licensed thermo-power is 1,930 megawatts thermal. New 14 power uprates have been incorporated at the plant and 15 none are currently planned. Design electrical rating 16 is 650 megawatts electric.

The ownership of the plant 17 was transferred from GPU to Amergen in 2000 and the 18 current license expires April 9, 2009.19 MEMBER BONACA: Before you go forth, you 20 mentioned the emergency plan finding. That will be 21 essentially finding on a cornerstone.

22 MR. POLASKI: Yes.23 MEMBER BONACA: So where is the cross-24 cutting issue? Mean, what other items have been 25 brought up that combine together with this cornerstone NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com

• o 14 1 issue?2 MR. POLASKI: The cross-cutting issue 3 dealt with procedural compliance and procedural 4 adherence.

5 MEMBER BONACA: Yes, okay. And so you 6 have other examples of problems with procedural 7 adherence.

8 MR. POLASKI: Yeah, there were other green 9 findings in that quarter that were in the procedure 10 adherence hearing.11 MEMBER BONACA: In the procedural, okay, 12 thank you.13 MR. POLASKI: If there's no other 14 questions, I'm going to now turn it back to Mike 15 Gallagher to discuss the drywell corrosion issues.16 MR. GALLAGHER:

Okay, I will now give you 17 a brief history of the drywell corrosion at Oyster 18 Creek. The corrective actions that were implemented 19 and how we insured the corrective actions were 20 effective.

The presentation will describe how we 21 arrived at our overall conclusions which are the 22 corrective actions to mitigate drywell shell corrosion 23 have been effective, the drywell shell corrosion was 24 arrested in the sand bed region and continues to be 25 very low in the upper drywell elevations.

The service NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 15 1 life of the drywell shell extends beyond the year 2029 2 with margin. And also we have effective aging 3 management programs to insure continued safe 4 operation.

5 MEMBER WALLACE: Now, you said it was 6 arrested in the sandbed region. Is this because 7 you've excavated the whole sandbed area and you 8 checked the whole thing all around?9 MR. GALLAGHER:

Yeah.10 MEMBER WALLACE: And how often do you do 11 that?12 MR. GALLAGHER:

I think the rest of my 13 presentation will touch on all those details.14 MEMBER WALLACE: Will go into that, okay.15 MR. GALLAGHER:

We can go through that.16 CHAIRMAN MAYNARD: One other thing I'd 17 like to make sure you touch on in your presentation is 18 one of the observations from the inspection report 19 were found some water. It was emptied without 20 analysis and I think a number of the members have some 21 questions, so if you can work that into your 22 discussion, too.23 MR. GALLAGHER:

Okay, we will. Okay, just 24 to go through some background first, and I think this 25 will help us all. Slide 9, this is a cross section of NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 16 1 the drywell. Early in plant life during refueling 2 outages, water leaked through defects in the reactor 3 water and the reactor cavity liner which I depicted in 4 cross-hatched blue into the air gap which is depicted 5 in red between the drywell shell in the reactor 6 building, down to the sandbed region which is depicted 7 in the cross hatch purple.8 MEMBER SHACK: Now, is that really an air 9 gap or is that filled with this Firebar D?10 MR. GALLAGHER:

There is Firebar D in that 11 gap and then during the first operational or static 12 test it actually presses and compresses that Firebar 13 D. There an air gap in there.14 MEMBER SHACK: I see, so the concrete is 15 cast against it. It compresses and then you're left 16 with a gap.17 MR. GALLAGHER:

That's correct.18 MEMBER SHACK: And roughly what's the 19 dimensions?

20 MR. GALLAGHER:

Pete Tamburno?21 MR. TAMBURNO:

I'm Pete Tamburno, Senior 22 Mechanical Engineer Oyster Creek. That gap is 23 approximately three inches.24 MEMBER WALLACE: How does the gap get 25 created now, the concrete shrinks or something?

NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com

• o v 17 1 MR. GALLAGHER:

No. Pete, can you go into 2 that in detail?3 MR. TAMBURNO:

The gap was created by 4 first erecting the drywell vessel. Then they applied 5 this Firebar D to the drywell, and then they poured 6 the concrete around it.7 MEMBER WALLACE: And they -- what happened 8 to the stuff that was in between? It disappeared 9 somewhere?

10 MR. TAMBURNO:

No, it's still there.11 CHAIRMAN MAYNARD: When you do your 12 pressure test, is that when --13 MR. GALLAGHER:

Yes, Ahmed, could you --14 MEMBER WALLACE: So the gap is full of 15 something.

16 MR. GALLAGHER:

It was a foam. It was 17 foam and then during the hydrostatic test of the 18 drywell, you know, it compresses and then there's a 19 gap.20 MEMBER WALLACE: Okay.21 MR. GALLAGHER:

So I think what Pete's 22 referring to the whole gap, the whole gap --23 MEMBER WALLACE: It's the whole gap or --24 MR. GALLAGHER:

Yes.25 MEMBER WALLACE: -- it's the air plus this NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 18 1 other stuff?2 MR. GALLAGHER:

It's the air plus the 3 Firebar, yeah.4 MEMBER WALLACE: What do you call that 5 stuff?6 MR. GALLAGHER:

Firebar D.7 MEMBER WALLACE: Firebar D.8 MR. GALLAGHER:

It's the type of material.9 MEMBER WALLACE: Fire resistant, is that 10 what it is?11 MR. GALLAGHER:

It was a construction 12 material.13 MEMBER BONACA: Just a question still 14 regarding configuration.

So you're saying that --15 your postulation is that there are cracks in the liner 16 of the cavity and water will come through that down 17 this gap. Now, doesn't it defeat the design purpose 18 of the refueling seal to have those cracks?19 MR. GALLAGHER:

Yes, perhaps if I can go 20 to the next two slides, it will show closer cross 21 sections of this area and I'll answer that question 22 directly.23 MEMBER BONACA: That is a specific 24 question regarding the design. I thought that the 25 design of the seal was in fact, to prevent any water NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 19 1 penetration.

2 MR. GALLAGHER:

Yeah.3 MEMBER BONACA: And it seems to me that 4 the existence of these cracks in the liner by 5 definition, they're defeating the design purpose of 6 the seal, but anyway, so whenever you get there.7 MR. GALLAGHER:

I'll get there, I can get 8 there right now.9 MEMBER ARMIJO: Just to add one thing to 10 your list of questions, when you talk about the 11 leakage, would you address the issue of moisture geing 12 absorbed in that Firebar D and/or chemicals that leach 13 out of that material ultimately getting down into the 14 sandbar region and what that -- what your views are 15 concerning the chemistry and the corrosion you saw?16 MR. GALLAGHER:

Let me continue with the 17 background and we will get into that question also.18 MEMBER WALLACE: What makes the bubbles in 19 the foam?20 MR. GALLAGHER:

Excuse me?21 MEMBER WALLACE: What makes the bubbles in 22 the foam in the Firebar D? Is it some kind of gaseous 23 release by a chemical reaction or something?

What 24 makes the bubbles in the foam?25 MEMBER SIEBER: There are no bubbles in NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 20 1 the --2 MEMBER WALLACE: The foam must have 3 bubbles if it's a foam.4 MR. GALLAGHER:

I'm not aware of any 5 bubbles in the foam.6 MEMBER WALLACE: It's a foam, you said it 7 was a foam.8 MR. GALLAGHER:

It's a -- Ahmed, can you 9 answer that?10 MR. OUAOU: It's --11 CHAIRMAN MAYNARD: Excuse me, could you 12 state your name, please?13 MR. OUAOU: Ahmed Ouaou with the Oyster 14 Creek License Renewal Team. The Firebarrier, the 15 Firebar D material was put in place to prevent the 16 concrete from it being in contact with the shell and 17 later on that material was compressed with 40 psi 18 pressure and heat it to a temperature of 140 degrees 19 Fahrenheit to create a one-inch gap that's required 20 for seismic movements, for movements of the 21 containment shell. That was basically its purpose.22 It's a non -- a compressible material 23 beyond the one-inch --24 MEMBER WALLACE: I'm trying to find out 25 what it is, chemically and so on. Is it completely NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com W v 21 1 neutral in terms of corrosion properties or what is 2 it?3 MR. OUAOU: It has some chlorides.

4 MEMBER WALLACE: Chlorides.

5 MR. OUAOU: Yeah, the chlorides, however, 6 are not in the area of corrosiveness to the steel.7 MR. GALLAGHER:

Yes, specifically, your 8 question about the water, when the water did wash down 9 from this area, it does pick up -- it did pick up some 10 of these contaminants.

The water now that we've had 11 showed that the water met the criteria for you know, 12 non-aggressive to concrete and you know --13 MEMBER SHACK: Or steel.14 MR. GALLAGHER:

Or steel, yes. So the --15 I think we have some data on that matter, Pete, about 16 the chloride level is less than 1,000.17 MR. TAMBURNO:

Yeah, the sand was tested 18 and the ph limit for the leachate was 8.46. The --19 MEMBER SHACK: I thought that was a test 20 on the sand. Is that the sand after it's been 21 penetrated with the stuff or that's the acceptance 22 criteria for the sand that you're about to put in the 23 sand bag?24 MR. TAMBURNO:

No, the results of the 25 tests I'm giving you is the tests on the sand after --NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com v

22 1 that was removed, and the chlorides are 45 parts per 2 billion and sulfates are 17 parts per billion.3 MEMBER WALLACE: In that water that was 4 tested?5 MR. GALLAGHER:

Yes, in the leachate that 6 came from the sand.7 MEMBER WALLACE: Does the NRC know what 8 Firebar D is and what it's made out of and what's its 9 properties are?10 MEMBER SIEBER: Yeah, they do because it's 11 in the SER.12 MS. LUND: Hans Ashar is coming up to talk 13 about --14 MR. ASHER: Yeah, we're aware of the 15 particular type of insulation between the concrete 16 shield wall and steel and with the water coming out of 17 the refueling cavity in some places when a 18 accumulation in the same pocket area, it is 19 contaminated that sand with corrosive kind of 20 environment in the early days and afterwards, I 21 believe Oyster Creek owners at that time had done a 22 number of analysis that I recall. I don't remember all 23 the numbers but I have seen the chemical composition 24 and all those things. I have it in my folders but I 25 was not ready to talk about because I didn't know it NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 23 1 would come up at this time because they were taking 2 out the sand, but if you --3 MEMBER WALLACE: The Firebar is still 4 there, though, isn't it?5 MR. ASHER: Yes, the Firebar is still 6 there.7 MR. GALLAGHER:

And I think when we go 8 later through the presentation, we'll talk about, you 9 know, our program that monitors the corrosion in the 10 upper drywell and the results of that which are good.11 So I think that addresses the issue, what's actually 12 going on up there.13 MEMBER BONACA: I don't want you to forget 14 about my question.15 MR. GALLAGHER:

We're doing that right 16 now. If we could go to --17 MEMBER SIEBER: Well, we still don't have 18 the answer to Dr. Wallace's question as what the 19 material is. Is it a foam, is it a fiber?20 CHAIRMAN MAYNARD: I'd like to go ahead 21 and let the licensee go on. We can come back to that 22 if we've got it from somebody here' who's looking 23 after it.24 MR. GALLAGHER:

Yeah, and we can get that 25 specific information, also at a break.NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 24 1 Okay, so let me just continue with the 2 overhead.

We'll get to your question.

So attached to 3 the sandbed region are five drains designed to remove 4 any water from this region. The sandbed drains were 5 clogged and thus, prevented the sand from remaining 6 dry.7 MEMBER WALLACE: Say that again.8 MR. GALLAGHER:

The sandbed drains were 9 clogged and thus, prevented the sand from remaining 10 dry. This is, I'm talking about the -- you know, the 11 initiation of the event.12 CHAIRMAN MAYNARD: And this was back in 13 the '80s.14 MR. GALLAGHER:

This is in pre-mid-'80s.

15 So what I'm going through here now is, you know, the 16 complete history, so we're starting from the 17 identification of the problem. So I'm describing the 18 background and identification of the problem and then 19 we'll go through all the facets to our current aging 20 management.

21 MEMBER WALLACE: You say there were some 22 regions which were much more corroded than others.23 MR. GALLAGHER:

That's true.24 MEMBER WALLACE: That's going to be part 25 of our investigation, I think, as to how extensive is NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 25 1 this corrosion, how extensive

-- how well, if this is 2 something, tell us of the details of it all the way 3 around and help us.4 MR. GALLAGHER:

And we'll be getting into 5 that, yes.6 MEMBER WALLACE: Okay.7 MR. GALLAGHER:

Yes, sir. So, as I said, 8 this wet sand was in contact with the drywell shell 9 exterior and caused general corrosion of the shell in 10 the sandbed region. To a lesser extent, there was 11 also corrosion identified in the upper region of the 12 drywell as you had just questioned with the Firebar.13 The detection of water draining from the sandbed 14 drains and potential for drywell shell corrosion was 15 recognized and pursued in the mid-1980s.

So that's 16 the period of time we're talking about right now.17 MEMBER WALLACE: Well, I don't mean to go 18 on forever but to get corrosion, you need oxygen as 19 well as water and the worst condition which is 20 something that is damp and has air there. If it's 21 totally immersed, sometimes it's better off.22 MR. GALLAGHER:

That's true.23 MEMBER WALLACE: Well, you have a 24 condition where you've got air and water, so the 25 partly drained water and there's some sort of an NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 26 1 interface where things are really going on; is that 2 what you had there, something like that?3 MR. GALLAGHER:

Well, there is an air gap 4 there and so there is -- there was air or there is 5 air. If I go to Slide 10 and this will be hitting 6 into your questions.

Slide 10 is a close-up of the 7 cross-section of the sandbed. Your questions will be 8 answered in the next slide, but this shows the sandbed 9 area and the drain. The air gap is also shown and 10 that's the red at the top of the slide.11 MEMBER WALLACE: I understand.

The 12 sandbed is the blue and the red or -- it doesn't make 13 sense. Where is the sandbed in this picture? Where 14 is the torus?15 MR. GALLAGHER:

This might be a little bit 16 better figure for you. That is the sandbed area that 17 he's pointing to.18 MEMBER WALLACE: Okay.19 MR. GALLAGHER:

The cross hatch is the 20 shell itself.21 MEMBER WALLACE: Yeah, I thought it was.22 So what's this blue and red stuff?23 MR. GALLAGHER:

All right, on that slide 24 it didn't turn out well in this overhead because I 25 think the projector is --NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com

• .

27 1 MEMBER WALLACE: So it's labeled sandbed 2 but it isn't sandbed.3 MR. GALLAGHER:

Go back to that.4 MEMBER WALLACE: It's something inside.5 MR. GALLAGHER:

Let me explain to you.6 This light -- these lines are too light. This is 7 projected

--8 MEMBER WALLACE: Yes, the sandbed is in 9 there.10 MR. GALLAGHER:

This is the sandbed there.11 MEMBER WALLACE: And what's that red and 12 blue stuff and why is that highlighted?

13 MR. GALLAGHER:

The orange or --14 MEMBER WALLACE: Red on my slide.15 MR. GALLAGHER:

The orange, down here that 16 is the concrete in the inside of the containment.

17 There's actually -- it's a sawtooth arrangement in 18 that the -- you know, the curb is higher and then 19 lower a threat to the drywell. So the blue is 20 supposed to show you the top of the curb on the inside 21 of the drywell.22 MEMBER WALLACE: This is just a different 23 piece of concrete.24 MR. GALLAGHER:

Yes. Well, it's the same 25 form but it's -- it looks like a sawtooth pattern.NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com

• °v 28 1 The sandbed area is to the right of that, and that's 2 the white area, okay. The green is supposed to be --3 that's one of the down comers going to the torus. And 4 then the air gap is the red depicted at the top. It's 5 the same red on the previous slide and that goes all 6 the way around obviously, and so it connects to the 7 sandbed area.8 MEMBER WALLACE: And you're going to tell 9 us just where the corrosion is in here?10 MR. GALLAGHER:

Yes, yeah.11 MEMBER WALLACE: Can you point it out now?12 MR. GALLAGHER:

The corrosion is --13 MEMBER SHACK: You're better off with the 14 next slide.15 MR. GALLAGHER:

The next slide is about 16 the refueling seal.17 MEMBER SHACK: You have the line drawing 18 of this area.19 MR. GALLAGHER:

Okay, where you see the 20 shell --21 MEMBER WALLACE: Where's the corrosion?

22 Up there?23 MR. GALLAGHER:

The corrosion is in this 24 area here.25 MEMBER WALLACE: And not below that.NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 29 1 MR. GALLAGHER:

Well, it's all of this 2 area.3 MEMBER SHACK: It tapers off.4 MEMBER WALLACE: It doesn't go beyond 5 that. It's just -- how do you know what happens when 6 it goes into the concrete there?7 MR. GALLAGHER:

Into which area?8 MEMBER WALLACE: The bottom, the very 9 bottom. In there, what happens in there?10 MR. GALLAGHER:

And we'll1 be talking about 11 that also.12 MEMBER WALLACE: Oh, you're going to tell 13 us all these things.14 MR. GALLAGHER:

Yes, that's right.15 MEMBER WALLACE: Good.16 MEMBER SHACK: Just while we have this 17 drawing up, now, my understanding is you didn't have 18 a galvanized plate the way some people do to cover the 19 sandbed but is that a galvanized or is that some sort 20 of plate I see there in the drawing?21 MR. GALLAGHER:

This here, no, that's the 22 down comer.23 MEMBER SHACK: That's the down corner.24 MR. GALLAGHER:

Yes.25 MEMBER SHACK: And you don'It have the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 30 1 galvanized.

Yours is open to the --2 MR. GALLAGHER:

Ahmed, any galvanized 3 plate?4 MR. OUAOU: We do have a cover plate 5 around the vent header at the top of the sandbed 6 region.7 MR. GALLAGHER:

At the top.8 MR. OUAOU: There was one included in the 9 design.10 MEMBER SHACK: There wasn't?11 MR. OUAOU: There was.12 MEMBER SHACK: There was.13 MR. OUAOU: Yes.14 MEMBER ARMIJO: Just one last question;15 you said you had five drains. Were all of the drains 16 plugged or was just a couple of them so that you --17 MR. GALLAGHER:

They were all plugged.18 MEMBER ARMIJO: You have to assume that 19 the corrosion was generalized around the lower part of 20 this.21 MR. GALLAGHER:

That's correct.22 MEMBER WALLACE: There's a filter on top 23 of the drain pipe or something like that to prevent 24 the sand washing away?25 MR. GALLAGHER:

There is a filter, and NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 31 1 Ahmed, the filter?2 MEMBER WALLACE: That's what plugged?3 MR. GALLAGHER:

The filter.4 MR. OUAOU: As Mike mentioned previously, 5 the drain itself was full of sand as part of the 6 design to avoid --7 MEMBER WALLACE: It was filled with sand.8 MR. OUAOU: It was filled with sand to 9 avoid draining the sand from the sandbed region but as 10 a result of water intrusion in the area, you have 11 fines that mixed with the sand. You don't have the 12 drainage and that was why it was plugged.13 MR. GALLAGHER:

Okay, so to get to your 14 question on the next slide, which is Slide 12, excuse 15 me, Slide 11, this is the reactor cavity seal area.16 And this -- this shows a cross section of that. This 17 slide is useful to show the water leakage path. And 18 basically as we indicated, the water leakage was 19 through defects in the reactor cavity liner and worked 20 its way into the trough area. Again, this projector 21 is light but I think your slides are a little better.22 The water worked its way -- or leaked into 23 this trough area and some of this trough area there 24 was low spots originally in the trough area and so the 25 water which leaked through here, leaked down and NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com f

32 1 spilled over into the air gap.2 MEMBER BONACA: Now, two questions.

One, 3 how sure are you that that's the source of water since 4 this is being contested?

You've tested this water?5 MR. GALLAGHER:

We're very sure that 6 that's the source of the water. Other --7 MEMBER BONACA: That's an issue.8 MR. GALLAGHER:

Other -- during the 9 corrective action, early on, there was other sources 10 that were pursued such as the refueling seal and 11 things like that and it was determined that the 12 majority was through this other --13 MEMBER BONACA: And then the question I 14 had was, the seal is supposed to be preventing water 15 penetration but if you have cracks in the liner you 16 are defeating the design objective.

And the question 17 I'm raising is because whatever you do to control 18 corrosion, to do whatever you can do to monitor, you 19 still are defeating the design objective and fitting 20 water through that gap. I mean, is that an initiative 21 to try to fix those cracks or replace the liner?22 MR. GALLAGHER:

Absolutely, what we --23 MEMBER BONACA: Otherwise the root cause 24 of all this is not going to go away. And I mean, the 25 goal objective of inspecting those bellows and seals NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com

..

33 1 is defeated by definition.

Simply you have cracks and 2 they're allowing water to come down.3 MR. GALLAGHER:

When we go into our 4 program and talk about what we've done in the past and 5 what we're committing to do for the future, we put 6 strippable coating on the reactor cavity liner before 7 we fill it with water during refilling outages. And 8 that's been very, very effective to eliminate the 9 water from this air gap.10 MEMBER BONACA: You still have been 11 getting water in these containers.

12 MR. GALLAGHER:

Okay, we can talk about 13 the containers now, if that's --14 MEMBER BONACA: No, that's okay, you're 15 going to talk about it later.16 MEMBER SHACK: Well, let me go over this 17 strippable coating now. You have put this -- I mean, 18 every time you fill this with water, that's -- part of 19 your procedure is to apply the strippable coating 20 first?21 MR. GALLAGHER:

We have made a commitment 22 that going forward, every time we fill the reactor 23 cavity, we will put strippable coating.24 MEMBER SHACK: You haven't done that every 25 time since the problem started?NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 34 1 MR. GALLAGHER:

We've done it, I think, 2 every time except two outages. And --3 MEMBER SIEBER: The answer is, no, they 4 haven't done it every time.5 MEMBER BONACA: That's right.6 MEMBER ARMIJO: Was that just oversight or 7 error or was it a --8 MEMBER SHACK: A procedural failure?9 MR. GALLAGHER:

Pete, can you answer that 10 question?11 MR. TAMBURNO:

This is Pete Tamburno, 12 Senior Mechanical Engineer.

There were two outages 13 during the time frame that GPU owned the plant that 14 the strippable coating was not put on and I believe it 15 was during a time when the plant was announced to be 16 decommissioned.

17 MR. GALLAGHER:

But, you know, for 18 clarity, we have made a commitment and we put that in 19 our license renewal application that we will put the 20 strippable coating on.21 MEMBER SHACK: Now, when you --22 MEMBER BONACA: Yeah, go ahead.23 MEMBER SHACK: When you have the 24 strippable coating in place and you're -- I trust 25 you're still monitoring for leakage, do you get any NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 35 leakage with the strippable coating in place? You're still getting leakage?MEMBER BONACA: Yes, they do.MR. GALLAGHER:

We have had -- when we went through our commitments on this -- the current commitments, current licensing basis commitments, we couldn't find any current documentation on the monitoring of the water leakage. We've talked with people that have been in the sandbed and they have said that, you know, there is no water in the sandbed when they go in there to do the visual inspections on the coating. So we believe that our corrective actions have been effective, which I'll go in to tell you what we've done comprehensively to insure that the water is going down the trough drain and not into the air gap.CHAIRMAN MAYNARD: I'd like for us to let the licensee go ahead, I think trying to give a history and --MR. GALLAGHER:

Yeah, we have a pretty good presentation.

CHAIRMAN MAYNARD: We can come back to these -- anything that is not answered, we can come back to but I want to leave time for us to do that.MR. GALLAGHER:

And I think we'll hit on NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 36 1 all your issues.2 Okay, if we can skip through Slide 12, 3 Slide 12 is basically the words that I just talked to.4 Okay, going to Slide 13, okay, so just to frame this 5 again, where I'm at is we've discovered the problem 6 and now we're determining what the problem is and the 7 extent of it. So in the 1986 time frame, the initial 8 corrosion monitoring program was initiated utilizing 9 ultrasonic thickness measurements in order to 10 determined

--11 MEMBER WALLACE: Taken from the sandbed 12 side?13 MR. GALLAGHER:

This is comprehensively 14 for the drywell.15 MEMBER WALLACE: On the sandbed side.16 MR. GALLAGHER:

From inside the drywell.17 MEMBER WALLACE: From inside not from the 18 sandbed side, from inside.19 MR. GALLAGHER:

This is a comprehensive 20 program to look for -- to evaluate the --21 MEMBER WALLACE: It's taken from inside.22 MR. GALLAGHER:

So in order to determine 23 the --24 MEMBER SHACK: But when you take that from 25 inside, you're going through the concrete and you look NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com

.o 37 1 for a reflection off the inside wall and outside wall?2 MR. GALLAGHER:

No, the inside is just the 3 liner itself. The concrete is on the outside.4 MEMBER WALLACE: There's concrete there, 5 isn't there?6 MEMBER BONACA: He's not talking about the 7 bottom.8 MR. GALLAGHER:

Yeah, I'm talking the 9 accessible shells --10 MEMBER SHACK: The portion of the sandbed 11 region.12 MEMBER WALLACE: Well, you said concrete 13 on there, so how do you do take it when you've got 14 concrete on top of the steel?15 MR. GALLAGHER:

If I can, what I'm trying 16 to describe here first is, our monitoring.

17 MEMBER WALLACE: This seems to be 18 important as to how good are the measurements.

19 MR. GALLAGHER:

That's right, that's 20 right. And --21 MEMBER WALLACE: You show there's concrete 22 on top of the steel in that region?23 1 MR. GALLAGHER:

What I'm talking about now 24 is to determine the appropriate monitoring locations 25 to measure the --NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 38 1 MEMBER SHACK: What you're saying is 2 you've taken a thousand measurements in the sandbed 3 region and we're asking --4 MR. GALLAGHER:

I didn't say that.5 MEMBER WALLACE: We're asking how you did 6 it.7 MR. GALLAGHER:

I didn't say that. If I 8 can describe --9 MEMBER SHACK: The UT is in the sandbed 10 region at least some of the one thousand.11 MR. GALLAGHER:

These one thousand 12 measurements were throughout the drywell in order to 13 determine

--14 MEMBER WALLACE: That's misleading then.15 They're not in the sandbed region. What did you do in 16 the sandbed region?17 MR. GALLAGHER:

It says approximately a 18 thousand UT measurements were taken to identify the 19 finished location --20 MEMBER WALLACE: How does measuring 21 somewhere else measure what's happening in the 22 sandbed?23 MR. GALLAGHER:

-- in the sandbed region 24 and the upper elevations of the drywell. What we're 25 trying to say, we comprehensively took measurements NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 39 1 throughout the dry well to identify the extent of the 2 problem, okay.3 MEMBER WALLACE: We're asking you how you 4 did it in the sandbed.5 MR. GALLAGHER:

Okay, so in the sandbed 6 region, let me turn that over to Pete and you can go 7 into the specifics on that.8 MR. TAMBURNO:

Okay, this is in the early 9 '80s before we had access to the sandbed. At that 10 time, we did not have access to get into the sandbed 11 so we did a sweep, 360 degrees on drywell vessel 12 inside the drywell, that was accessible.

We did not 13 look at portions underneath the concrete, only the 14 portions of the vessel that were accessible.

There's 15 a --16 MEMBER WALLACE: So you've got no 17 measurements in the sandbed region?18 MR. TAMBURNO:

No, no, there are portions 19 of the sandbed which are accessible from the inside.20 MEMBER WALLACE: Some parts.21 MR. TAMBURNO:

Yes, sir.22 MEMBER WALLACE: But there are other parts 23 that are not.24 MR. TAMBURNO:

There are other parts that 25 are not accessible.

NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 40 1 MEMBER WALLACE: I presume we knew nothing 2 about what was happening there.3 MR. TAMBURNO:

Well, shortly after we 4 reported that information to the NRC, they questioned 5 about what about underneath the concrete, at which 6 point we removed a portion of the concrete in two 7 sections and investigated the vessel in those two 8 portions.

Our conclusions were that the information 9 on the accessible regions were representative of the 10 corrosion when we looked at the portions of the vessel 11 that were underneath the concrete.12 MEMBER WALLACE: That's where you found 13 the minimum thickness that we're going to hear about?14 MR. TAMBURNO:

Yes, sir.15 MEMBER WALLACE: And how big was the 16 minimum thickness?

17 MR. TAMBURNO:

At that time, there were --18 the numbers varied anywhere between 1.1 which is what 19 the vessel was originally delivered and to 0.5 inches 20 thickness.

21 MEMBER WALLACE: 0.5 inches thickness.

22 That's the thinnest I've heard yet.23 MR. TAMBURNO:

Excuse me, excuse me, 24 that's incorrect, 0.85, I'm very sorry.25 MEMBER WALLACE: Why did I see .603 in the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com

• ° 41 1 report?2 MR. TAMBURNO:

At the time that we did our 3 original investigation, we did not see the .603. That 4 was later on when we gained access to the outside of 5 the drywell by removing the sand.6 MEMBER WALLACE: I'm asking all this 7 because I'm not sure from what I've read, what the 8 thinnest part of this drywell is, how thin it is, how 9 extensive it is. I don't get that from the report.10 I get these numbers thrown out. We measured 0.85 then 11 we found .603 but how big is it and what about the 12 places where you didn't measure? All that stuff, I 13 don't know. Are you going to clarify all that?14 MEMBER BONACA: The .8 is referenced as an 15 average.16 MR. GALLAGHER:

Yeah, there's actually two 17 criterion we -- if I can briefly, there's different 18 plates in the drywell and shell, as you know. So 19 there's a different minimum thickness for each one.20 Sandbed, just talking sandbed, there's actually two 21 criterion.

Okay, one is for the minimum average.22 Okay, and that number is 0.736. And the other is for 23 a minimum local, which is .49. So the measurements 24 need -- you know, the criterion is to meet those. In 25 all the areas of the sandbed, we meet those criterion.

NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 42 1 MEMBER WALLACE: In all areas. So you've 2 got how many measurements around to make sure that you 3 cover all areas?4 MR. GALLAGHER:

So specifically, what 5 we're talking about here is there was an investigation 6 that was done to identify the areas to monitor for 7 corrosion, okay. When I say these thousand points, 8 it's throughout the drywell. Basically the bottom 9 line is to get to your question, is that these were 10 used to identify the thinnest areas, biased to the 11 thinnest areas. We then set up -- there's 19 12 monitoring locations that are on the interior of the 13 sandbed area that are like a grid, you know, and those 14 are to determine the data points and they are 360 15 degrees around there.16 So they are representative of the 17 condition of the sandbed. Those particular points, 18 there's a grid that's established.

It's a 49-point 19 array. Those 49 points in each of the 19 locations 20 were taken and they were bounced off this criteria of 21 the minimum general being the .736 and then the 22 minimum local being the .49.23 MEMBER ARMIJO: Do you have a little 24 picture or graph showing all of the UT measurement 25 points taken around the circumference in the sandbed NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.neafrgross.com 43 1 region that you could show --2 MEMBER WALLACE: That would help a lot.3 MEMBER ARMIJO: You know, that would save 4 a lot of questions, because I think that's our -- all 5 of us have looked for this information.

6 MEMBER WALLACE: Right.7 MR. GALLAGHER:

We can easily -- we don't 8 have that in an overhead.

We can provide that. But 9 these 19 locations are throughout the 360 degree of 10 the sandbed region.11 MEMBER WALLACE: Now in the torus, you've 12 got pits. I mean, how would you find pits if you're 13 only just looking in a few places here? You don't 14 find pits in the drywell? You find pits in the torus.15 MR. GALLAGHER:

The torus?16 MEMBER WALLACE: You could have a pit in 17 the drywell, couldn't we here, that's bigger than 18 these average of thicknesses?

19 MR. GALLAGHER:

So is your question about 20 the torus or about the --21 MEMBER WALLACE: Well, I find there are 22 pits in the torus because you could see the torus.23 MR. GALLAGHER:

Right.24 MEMBER WALLACE: We found pits. I just 25 want to be somehow assured that there aren't pits in NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 44 1 the drywell, which wouldn't show up in these random 2 measurements.

3 MR. GALLAGHER:

Let me turn that question 4 over to Ahmed.5 MR. OUAOU: Ahmed with Exelon. The 6 corrosion sandbed region after we removed sand and 7 cleaned up the sandbed region, we noted that the 8 corrosion is primarily general corrosion.

There were 9 some --10 MEMBER WALLACE: But you were able to look 11 up the whole region.12 MR. OUAOU: Absolutely.

13 MEMBER WALLACE: You didn't see pits.14 MR. OUAOU: Well, there were localized 15 areas and that's what this local criteria for 16 acceptable thickness is for.17 MEMBER WALLACE: You looked at part of the 18 drywell and there was general corrosion.

19 MR. OUAOU: We looked at the entire 20 surface of --21 MEMBER WALLACE: Entire surface.22 MR. OUAOU: -- of the sandbed region and 23 the --24 MR. GALLAGHER:

From the exterior.25 MR. OUAOU: From the exterior after the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 45 1 sand was removed in '92 which I believe is going to 2 come up in some slides but the corrosion is general 3 corrosion, not pitting.4 MEMBER WALLACE: You see, it would help 5 really if you ask yourself the questions instead of us 6 asking the questions.

We asked these questions, this 7 is how we answered them instead of us sort of having 8 to drag it out of you. It would help.9 MR. GALLAGHER:

Okay.10 MEMBER WALLACE: Maybe you could do that 11 later on in your presentation.

12 MR. GALLAGHER:

We will.13 MEMBER WALLACE: Okay.14 MR. GALLAGHER:

Okay, so at this point, in 15 the program, I'm telling you about how many UT points 16 were developed in order to determine which monitoring 17 points should be monitored.

We also took core samples 18 of the drywell shell to confirm these UT measurements.

19 These core samples also confirmed that the degradation 20 was general corrosion.

At this point, in response to 21 an NRC staff concern regarding whether the inspection 22 locations represented the condition of the entire 23 drywell, in 1990 Oyster Creek prepared a new random UT 24 inspection plan designed to address the concern.25 Inspection results using the new random NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com

• o 46 1 inspection plan confirmed the previous locations were 2 representative of the thinnest locations in the 3 drywell. One location at elevation 60 foot 10 inches 4 which is in the upper drywell, was also added to the 5 program to expand the monitoring of the thinnest 6 locations.

The NRC staff accepted this program in an 7 SER dated November i't, 1995. Next slide.8 At this point, I'm talking to you about 9 the corrective actions. Corrective actions were then 10 developed and implemented in order to address the 11 ongoing shell corrosion.

First, the containment 12 pressure analysis was revised to establish additional 13 shell thickness margin for the upper drywell. The 14 original primary containment design pressure of 62 15 psig --16 MEMBER WALLACE: I'm sorry, I have another 17 question because in reading these, I see that the 18 basic approach was a buckling evaluation.

Buckling to 19 me means collapse by having a vacuum in the vessel.20 And yet, this is talking here about containment peak 21 pressure.

It seems that the concern is that it would 22 collapse due to a vacuum rather than it would burst 23 due to a pressure.24 MR. GALLAGHER:

Yeah, the upper drywell 25 actually the controlling mechanism is membrane NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 47 1 stressors.

Below it it's buckling, in the sandbed 2 region below it's buckling.

So we had to --3 MEMBER WALLACE: Don't you have vacuum 4 breakers or something to prevent this kind of a vacuum 5 forming in the drywell?6 MR. GALLAGHER:

Ahmed?7 MR. OUAOU: The cause of buckling in this 8 case is the refueling water. During outages, the 9 cavity is full of water. It's actually the dead load 10 that's imposed on the shell and not the vacuum.11 MEMBER WALLACE: No, it's not a vacuum 12 inside.13 MR. OUAOU: We do have vacuum breakers but 14 that's not the type of buckling.15 MEMBER WALLACE: So it's not a vacuum, 16 it's a dead load of water.17 MR. OUAOU: That's right. It's a dead 18 load of water plus the dead load of whatever else is 19 attached to the containment.

20 MR. GALLAGHER:

Okay, so as I said, the 21 original analysis had a design pressure of 62 psig and 22 it was generic to a GE Mark 1 containment design and 23 included a 10-pound margin. Analyses were then 24 performed to re-evaluate the drywell design pressure 25 for the Oyster Creek drywell. Analysis demonstrated NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 48 1 that following worst case design basis, loss of 2 coolant accident, the peak drywell pressure would not 3 exceed 38.1 pounds.4 Additional margin was added to establish 5 a design pressure of 44 pounds and this change was 6 approved as Amendment 165 to the Oyster Creek 7 technical specifications in September of 1993. The 8 revised containment pressure was later utilized to 9 determine the minimum acceptable drywell thickness and 10 establish additional shell thickness margins for an 11 area above the sandbed region. A detailed analysis 12 was performed to determine the minimum acceptable 13 drywell, shell thickness.

The results of the analysis 14 show that the minimum general thickness required to 15 satisfy the ASME code above the sandbed region is 16 controlled by membrane stresses, as I said, and 17 buckling controls the minimum drywell shell thickness 18 in the sandbed region.19 The analysis used 0.736 inches general 20 thickness in the sandbed region which satisfied the 21 ASME stress requirements for all design based load 22 combinations and applicable ASME safety factors. All 23 actual general thickness measurements have met this 24 criterion as I've said before. The focus of the 25 remaining corrective actions to prevent water NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 49 1 intrusion into the sandbed region, and to eliminate 2 the ongoing corrosion.

Activities such as applying 3 sealing tape and strippable coating to the reactor 4 cavity liner during refueling outages and improving 5 the reactor cavity trough drain were performed.

The 6 sandbed region drains were cleared to improve draining 7 at this time.8 Originally the sandbed region was 9 inaccessible.

Access to the sandbed region was gained 10 by creating access ports through the surrounding 11 concrete structure.

The sand was then permanently 12 removed from the sandbed region since this was 13 determined to be acceptable by the containment 14 analysis.

The corrective actions also included the 15 removal of corrosion from the drywell exterior surface 16 and the application of a protective epoxy coating on 17 the drywell exterior surface.18 MEMBER WALLACE: So there's no sand there 19 now.20 MR. GALLAGHER:

Excuse me?21 MEMBER WALLACE: There's no sand there 22 now.23 MR. GALLAGHER:

There's no sand there now.24 MEMBER WALLACE: So the function of the 25 sand is no longer being performed.

NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 50 1 MR. GALLAGHER:

Ahmed, if you could 2 explain the original function and why that was 3 acceptable to remove.4 MR. OUAOU: The BWR Mark 1 containments 5 had a sandbed region to transition from the embedded 6 region into the cantilevered portion free-standing 7 region basically to reduce the stresses.

It's a 8 cushion. And the analysis that was done in 1991 and 9 '92 time frame, concluded that it's not required.

The 10 shell by itself can handle the stresses.

And for that 11 reason, it was removed.12 MEMBER ARMIJO: A quick question, are the 13 access ports to the sandbed region still open that you 14 can go in there and inspect?15 MR. GALLAGHER:

Pete, if you can just 16 describe the access ports.17 MR. TAMBURNO:

The access ports are man 18 ways in the concrete.

They're approximately six feet 19 long and we've installed boron bags when we're at 20 operation.

When we do our coating inspection we 21 remove the bags and we send a man through the man way 22 to do the inspections.

23 MEMBER ARMIJO: So is there one or many?24 MR. GALLAGHER:

There's 10.25 MEMBER ARMIJO: So you can do a 360-degree NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 51 1 visual inspection.

2 MR. GALLAGHER:

Yes, sir. Again, I'm 3 talking about corrective actions here in the early 4 '90s. The corrective actions also included the 5 removal of corrosion from the drywell exterior surface 6 and the application of protective epoxy coating on the 7 drywell exterior surface in the sandbed region. The 8 concrete surface below the sandbed was shaped and 9 coated with an epoxy coating to --10 MEMBER WALLACE: Well, if it was 1.1 11 inches originally and it went down to .75 or 12 something, there must have been about half an inch of 13 rust on there.14 MR. GALLAGHER:

Yeah, the 1. minimum is .8 15 inches is where we are not.16 MEMBER WALLACE: But the rust is bigger 17 than the original steel, so there's 18 MR. GALLAGHER:

There was corrosion 19 products there.20 MEMBER WALLACE: A large amount.21 MR. GALLAGHER:

Which probably contributed 22 to the clogging in the sand. The concrete surface 23 below the sand I'm talking about now, that was shaped 24 and coated with an epoxy coating to assure that any 25 inadvertent leakage would flow towards each of the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com

• ° 52 1 five sandbed drains. The drywell shell at the 2 juncture, and this gets to some of your questions 3 about the embed, of the concrete floor was sealed with 4 silicon to prevent --5 MEMBER WALLACE: When you took the rust 6 off, did you get a smooth surface or did you have to 7 sandblast it or something to get a smooth surface that 8 you could coat? Was it kind of pockmarked or how was 9 it?10 MR. GALLAGHER:

Pete, can you answer the 11 question?12 MR. TAMBURNO:

This is Pete Tamburno 13 again. The area was not smooth. There was pockmarks.

14 Certain areas were more -- had more general corrosion 15 and some areas were better.16 MEMBER WALLACE: So you cleaned off the --17 smoothed it off?18 MR. TAMBURNO:

Yes, we cleaned off all the 19 corrosion by-products using hand tools and we also 20 inspected

--21 MEMBER WALLACE: That's grinding is it?22 MR. TAMBURNO:

No, sir, we used hand 23 tools.24 MEMBER WALLACE: Brushes?25 MR. TAMBURNO:

Brushes and that type of NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 53 1 thing and that was required because for the coating 2 application.

We also did some inspection

-- we did 3 inspections of all the areas that were noted to be 4 deep.5 MEMBER ARMIJO: Did you keep photographic 6 documentation of the area after it was all cleaned up 7 so somebody could actually look at those pictures?8 MR. GALLAGHER:

Pete, photographic 9 documentation?

10 MR. TAMBURNO:

Yes, we have some 11 photographs of the condition of the coating. We have 12 a video which we have presented to the NRC and we do 13 have some pictures from our most recent inspection 14 which was 2004.15 CHAIRMAN MAYNARD: I think you were asking 16 a question about pictures of corrosion.

17 MEMBER ARMIJO: Yeah.18 CHAIRMAN MAYNARD: You said pictures of 19 the coating.20 MEMBER ARMIJO: Yeah, I just want to say, 21 when they did the cleanup and everything was all nice 22 and --23 MR. GALLAGHER:

Precoating?

24 MEMBER ARMIJO: Yeah, precoating, they 25 document that and then --NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com

..

54 1 MR. GALLAGHER:

Precoating, Pete?2 MR. TAMBURNO:

We do have a few pictures 3 of the vessel after cleaning of the corrosion 4 byproducts but before coating.5 MEMBER ARMIJO: Okay, so there's some.6 MR. GALLAGHER:

So the embed area is what 7 we're talking about now. As I said --8 MEMBER WALLACE: This is what you used to 9 convince the NRC that using some sort of average was 10 okay and that the pock marks weren't too deep and all 11 that kind of stuff? These photographs are what you 12 used?13 MR. GALLAGHER:

Well, there was some data 14 from the outside, Pete, the exploratory data from the 15 outside?16 MR. TAMBURNO:

We took the inspection

--17 after we removed the corrosion byproducts, we 18 performed a visual inspection of 100 percent of the 19 sandbed region and then we inspected through UT 20 measurements, the thinnest we found. We then 21 evaluated those thinnest areas in a calculation and 22 compared them to the results of the GE analysis.23 MR. GALLAGHER:

So the embed, the drywell 24 shell at the juncture of the concrete floor was sealed 25 with a silicone to prevent water intrusion going NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 55 1 forward into the embedded drywell shell. The 2 potential for corrosion of the inaccessible embedded 3 shell prior to this corrective action has also been 4 assessed.

The water that was in the sandbed region is 5 not aggressive to concrete.

Therefore, our assessment 6 is that the corrosion of the inaccessible embed shell 7 is not significant, since it is protected by the high 8 alkalinity in concrete.9 MEMBER WALLACE: Well, it was corrosive to 10 steel. So once it got in there, it's going to eat its 11 way in further, isn't it?12 MR. GALLAGHER:

Ahmed.13 MR. OUAOU: The embedded shell is 14 protected by the alkaline environment in concrete and 15 that --16 MEMBER WALLACE: And that counteracts the 17 corrosive activities of the water?18 MR. OUAOU: That does not counteract the 19 corrosivity of water. The water was not corrosive.

20 In order for water to be --21 MEMBER WALLACE: I think it was corrosive 22 because the shell corroded.23 MR. GALLAGHER:

Yeah, we're talking about 24 the area at the concrete interface and below.25 MEMBER WALLACE: It's the bottom of --NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 56 MR. GALLAGHER:

Yeah, and -- yeah, but --MEMBER WALLACE: Explain why this corrosion couldn't go any further.MR. GALLAGHER:

Right, where it was corroded was above that area where the wet sand was in contact with --MEMBER WALLACE: didn't go any further.MR. GALLAGHER:

You're convincing us it That's correct, not significantly.

MEMBER WALLACE: You're convincing us not significantly or no?MR. GALLAGHER:

No.MEMBER WALLACE: It doesn't go --MR. GALLAGHER:

That the corrosion would not be significant.

MEMBER WALLACE: Verbal arguments or something else?MR. GALLAGHER:

This is consistent with the GALL of embedded --MEMBER WALLACE: GALL says it doesn't corrode?MR. GALLAGHER:

Embedded seal in concrete.If you meet certain criteria of the water not being aggressive to the concrete, it does.NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 57 1 CHAIRMAN MAYNARD: Okay.2 MR. TAMBURNO:

Can I just to make a 3 comment, certainly the embedded portion -- do you have 4 the slide with the embedded shell, John, please?5 MR. GALLAGHER:

We have a cross-section of 6 that area, showing the embed and a skirt, the drywell 7 skirt that's below it.8 MR. TAMBURNO:

What this slide shows is 9 the sandbed, the area where we applied seal after 1992 10 and that shows, you know, the portion of the shell 11 that's embedded in the concrete and then you have a 12 skirt which is a support for the shell under 13 construction.

Certainly, we really can't say that 14 there's no corrosion in the embedded shell. There 15 could be corrosion.

What we maintain is that the 16 corrosion should be less than in the sandbed region 17 because of the protection that the alkaline 18 environment provides for the steel.19 But in the case of the embedded shell, if 20 you look at the elevation 8 foot 3 and the bottom of 21 the sandbed is 8 foot 11, the corrosion should be 22 limited to that area, and of course, the skirt could 23 have some corrosion, but the skirt is not relied upon 24 as a support after the concrete was poured.25 MEMBER SIEBER: So this skirt goes 360 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 58 1 degrees around solid, so moisture would have to drill 2 through that skirt to go under --3 MR. GALLAGHER:

That's one of the points 4 we were trying to make is that the skirt does provide 5 a barrier and if you look at the plate thicknesses, 6 the plate thickness above, you know, where the skirt 7 is and in sandbed regions is the 1.159 and then below 8 that is where -- it's the thinner skirt, so we think 9 that the -- because of, you know, the concrete as we 10 described, that the corrosion in that area would be 11 less significant than the corrosion that was 12 experienced in the sandbed region and then we did the 13 analysis assuming that plate was at a uniform 14 thickness of .736. So we feel that's covered.15 MEMBER ARMIJO: Just one thing; when you 16 inspected that area right down where, you know, if you 17 could install a seal, the silicone seal, you must have 18 looked at it and was the corrosion worse or equivalent 19 in that region right close to the concrete or was it 20 less?21 MR. GALLAGHER:

Yes, Pete can answer that 22 question.23 MR. TAMBURNO:

We did inspect that area 24 during the repair activities in there and the 25 corrosion in that area was no worse than -- than the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 59 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 worst areas above it.MEMBER WALLACE: That doesn't say very much.MR. TAMBURNO:

So it was no better.MEMBER WALLACE: It was no better, right?MR. GALLAGHER:

Yeah, so it was the same.But there you would expect it to be similar because the sand, the wet sand -- there was sand throughout so the sand was contacting that. What we're saying is below that interface, it would be less -- the corrosion should be less significant because of the concrete that's embedded in it.MEMBER ARMIJO: And that's a debate, right? That's an ongoing debate.MR. GALLAGHER:

Well, we think we're consistent with the guidance that's in the GALL and --MEMBER WALLACE: You replaced the seal, did you?MR. GALLAGHER:

We put that seal in.MEMBER WALLACE: You put it in afterwards.

MR. GALLAGHER:

Yes, this is the corrective action.MEMBER WALLACE: Okay.CHAIRMAN MAYNARD: I'd like to move on with the presentation.

NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.WASHINGTON, D.C. 20005-3701 (202) 234-4433 www.nealrgross.com 60 1 MR. GALLAGHER:

Yes, sir.2 MEMBER SIEBER: I'd like to ask, beyond, 3 in our package the last slide you have is Slide 28.4 You're referring to backup slides which should be made 5 part of the record. So -- okay.6 MR. GALLAGHER:

Yeah, any slide we show, 7 we'll put in.8 MEMBER SIEBER: Okay, we'll I'd like to 9 have copies of this.10 CHAIRMAN MAYNARD: Yeah, I want to remind 11 everybody, we still have the staff's presentation 12 after this and we also have public comment time. I 13 want to make sure we get a chance to get through this 14 and we'll see where we need to come back to.15 MEMBER WALLACE: I'm sorry, Mr. Chairman, 16 I'm responsible for this. I want to really know 17 what's going on though, I'm afraid, so I have to ask 18 these questions, because the presentation doesn't tell 19 me unless I ask them, but I'll try to be brief.20 MR. GALLAGHER:

Okay, so leaving the 21 embed, the drywell shell in the sandbed region was 22 then coated. The coating that was applied was 23 application of a three-coat epoxy coating system 24 consisting of one coat of primer and two coats of 25 epoxy coating. Each coat was visually examined and NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 61 1 dry film thickness measurements were taken to assure 2 the proper coating thickness was achieved.

The 3 coating is a two-part 100 percent solid epoxy coating 4 which is less susceptible to the degradation and moist 5 environments.

The coating was tested to qualify for 6 emersion surface coating applications such as tank 7 linings. The surrounding environment has stable 8 temperature conditions resulting in lower thermal 9 stresses being applied to the coating and therefore, 10 provides close to an ideal service environment which 11 will result if a very long service life.12 MR. BARTON: Do you have any idea how long 13 that coating would be good for, the epoxy coating?14 MR. GALLAGHER:

We can have Ahmed answer 15 that question.16 MR. OUAOU: There were some estimates done 17 by our engineering and it varied from 10 years to 20 18 years. Recently we spent a lot of time talking to the 19 vendor about the qualification of the coating and the 20 feedback we're getting is that there is no guarantee 21 for that coating, whether it is 20 years, 15 years, 22 whatever.

However, you can rely on your inspections 23 to give you an indication whether you're approaching 24 the end life of the coating. So the rigor inspection 25 is the gauge as to when we think that coating is to NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com

% I v 62 1 get replaced or repaired.2 MR. BARTON: And the inspections are how 3 frequent, every 10 years?4 MR. OUAOU: The inspection, we inspect 5 every fueling outage. We look at it basically every 6 refueling outage.7 MR. OUAOU: Every other refueling outage.8 MR. GALLAGHER:

Our current program, and 9 I'll go into this, our current program which we do --10 there's 10 bays. We do two of the 10 bays every other 11 refueling outage and going forward, we're going to 12 insure we do 100 percent of the bays every 10 years.13 MEMBER SIEBER: And what's your cycle 14 length, two years?15 MR. GALLAGHER:

Two-year refueling.

16 MEMBER ARMIJO: So it's every four years 17 you inspect two out of 10 bays?18 MR. GALLAGHER:

That's the current 19 program. Going forward, it will be a minimum of three 20 every other outage to insure that we cover the you 21 know, 10 bays.22 CHAIRMAN MAYNARD: Do you have a criteria 23 that when you find degradation that you expand or you 24 increase your frequency or expand the number you look 25 at?NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 63 1 MR. GALLAGHER:

Yes, Ahmed?2 MR. OUAOU: Yes, in the future, we'll be 3 performing the ASME IEE inspections for the coating.4 Which requires that if you perform an automatic 5 inspection, you look at the coating and you find 6 defects, you have to assess the other areas that you 7 looked at if you're doing a sampling.

So if we do 8 find degradations, we would look at other areas in 9 accordance with our corrective action process.10 CHAIRMAN MAYNARD: And you have a criteria 11 as to what constitutes degradation?

12 MR. GALLAGHER:

Yes, in the inspection 13 program.14 MR. OUAOU: This is Ahmed. We do have 15 criteria.

We're using the criteria right out of the 16 WE that's looking for blistering and flaking and 17 cracking, et cetera, degradation of the coating.18 MEMBER WALLACE: This slide would benefit 19 from numbers. If the first bullet said .74 and the 20 second bullet said .69 or something, it would help.21 MEMBER SIEBER: Yeah, it sure would.22 MEMBER WALLACE: Can you tell us what 23 those numbers are, what the shell thickness needs to 24 be and what it is? Are you going to tell us the 25 numbers?NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com v

64 1 MR. GALLAGHER:

I told -- I said there's 2 various limits throughout for each plate and 3 specifically for the sandbed region, the minimum 4 thickness was .736 inches and the minimum -- that's 5 the minimum general. The minimum local is .49 inches 6 and we need those criteria.

There's -- every plate 7 has a --8 MEMBER WALLACE: By how much do you meet 9 them?10 MR. GALLAGHER:

The margins?11 MEMBER WALLACE: Yeah.12 MR. GALLAGHER:

Pete, if you can answer 13 the margin question.14 MR. OUAOU: This is Ahmed. Let me try to 15 answer the question.

I think giving you a number 16 would be not easy and the reason for that is, is that 17 there is a cylindrical region has a different 18 thickness in the sphere than the sandbed regions.19 MEMBER WALLACE: Let's just talk about the 20 sandbed.21 MR. OUAOU: The sandbed region, the 22 original thickness is 1.154 inches. The UT 23 measurements indicate that we have minimum of .80 24 inches and --25 MEMBER WALLACE: Average, yeah.NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 65 1 MR. OUAOU: Average, and the required for 2 stress to meet ASME requirements is .736. Now, I 3 remind you that those type of measurements are in two 4 bays. It does not reflect the entire sandbed region.5 MEMBER WALLACE: Okay.6 MEMBER ARMIJO: You guys could really help 7 us a lot. You submit good information in some of your 8 documents.

On page 5 of your June 2 0th submittal, you 9 have a very good chart showing all the numbers for all 10 the regions of the design thickness, minimum measured 11 thickness, required thickness and margin. You know, 12 maybe you've got a chart like that in your backup 13 slides but it would save a lot of time if we just had 14 those numbers.15 MR. GALLAGHER:

Yeah, we're sorry, we 16 didn't present the numbers on the graph. We had, you 17 know, provided all those to the staff and they 18 reviewed those in detail. So we were trying to just 19 give a summary.20 MEMBER WALLACE: I'm really puzzled when 21 I read the document though, because here it says, "The 22 analysis conservatively assumed that the shell 23 thickness in the entire sandbed region has been 24 reduced uniformly to a thickness of .736 inches.25 MR. GALLAGHER:

That's correct.NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com

.o v 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 66 MEMBER WALLACE: Well, that's less than the .80 inches you said.MR. GALLAGHER:

Right, that's --MEMBER WALLACE: Since we're just teetering on the edge of what you need to make that thing pass the code.MR. GALLAGHER:

The .736 is what the analysis was run at so that's the minimum and the .8 is the lowest point we have. And so that's 64 mils --MEMBER WALLACE: The words say that you assumed it had been reduced to this thickness.

MR. GALLAGHER:

What was the input to the analysis to come up with --MEMBER SHACK: That's sort of a limit to find out how low they could go.MR. GALLAGHER:

That's correct.MEMBER WALLACE: That's what it means.MR. GALLAGHER:

That's what it means.MEMBER SHACK: You start with the 44 --MEMBER WALLACE: What I assumed it meant was that you measured .8 and you assumed to be conservative, that it really could be .736. That's not what you mean by this statement.

MEMBER SHACK: No, it means with a 44 psi design pressure, he needs .736.NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com

• ° 67 1 MR. GALLAGHER:

Right, right.2 MEMBER WALLACE: That's what it means, 3 okay. It was confusing to me.4 MR. GALLAGHER:

And then the other point 5 I was trying to make about, you know, most of the 6 locations are well above that .8 and many of them are 7 close to the original plate thickness.

8 Again, I apologize for not providing that 9 table, but --10 MEMBER WALLACE: It's very strange that 11 you assume the answer. You assume .736 and then do 12 a study. I think you deduce .736 from the study.13 MR. GALLAGHER:

That was an input to the 14 analysis.15 MEMBER WALLACE: And it showed everything 16 was okay?17 MR. GALLAGHER:

And then we showed that we 18 had the proper safety margins.19 MEMBER WALLACE: But it doesn't down that 20 .70 might be okay, too, mightn't it?21 MR. GALLAGHER:

It could be, could be.22 MEMBER WALLACE: Well, why didn't you vary 23 the thing and see where you get into trouble? Well, 24 you did. That's the .49 is that?25 MR. GALLAGHER:

.49 is a local minimum.NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 68 1 MEMBER WALLACE: Okay, how thin does it 2 have to be before we get into real trouble?3 MR. GALLAGHER:

How low can we go below 4 .736 average?5 MEMBER WALLACE: Yes, yes.6 MR. GALLAGHER:

We have not analyzed that.7 MEMBER WALLACE: You don'It know? It might 8 be .735 or something.

I mean, these are obvious 9 things to do.10 MEMBER SHACK: No, no, he has to go back 11 and redo his design pressure calculations again, but 12 for 44 psi he can go to 736.13 MEMBER WALLACE: He doesn't say that. He 14 said he assumed the answer and then said it was okay.15 That's different from deducing it.16 MR. GALLAGHER:

It's probably poorly 17 worded, but the -- that's --18 MEMBER WALLACE: .736 was deduced from the 19 design pressure?20 MR. GALLAGHER:

That's the way we did the 21 analysis and Ahimed, he can --22 MR. OUAOU: If I may, this is Ahmed. I'd 23 like to explain how that .736 came about.24 Essentially, the time that the analysis was done, the 25 measured thickness was .80 and because at that time --NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 69 1 this is back in '81, sand has not been totally 2 removed, there was an estimate as to how much 3 corrosion we're going to have between now and when the 4 analysis run --5 MEMBER WALLACE: Yes.6 MR. OUAOU: -- and somebody came up with 7 the idea, well, if we use .736 we ought to be 8 conservative.

9 MEMBER WALLACE: Yes.10 MR. OUAOU: And that value was used to 11 come up with stresses and that satisfied ASME 12 requirements.

13 MEMBER WALLACE: So you did not deduce it 14 from a design pressure.

You assumed it and found it 15 was okay.16 MR. OUAOU: Well, yeah.17 MEMBER WALLACE: So it may be that .65 is 18 okay. You just don't know.19 MR. GALLAGHER:

The minimum thickness 20 could be lower.21 MEMBER WALLACE: I'm really puzzled. You 22 would really reassure the public if you would say, 23 "We've done the analysis and we show that this would 24 be good all the way down to .4". That would be great.25 MEMBER SHACK: You mean with a 44 psi NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com v

70 1 design pressure I could go lower is what you're 2 saying.3 MR. OUAOU: Not in the sandbed region, we 4 just said in sandbed region buckling controls so you 5 reduce the pressure to 44 or whatever number, that 6 will not change that. If the pressure had control, 7 that's true, but since the buckling controls --8 MEMBER SHACK: Okay, that controls the 9 thickness of --10 MR. OUAOU: Exactly, exactly.11 MR. GALLAGHER:

That's the way the 12 analysis was done. We could -- you know, we could 13 continue to do an analysis --14 MEMBER WALLACE: The bottom line, they've 15 got to get this straight, because this is your case, 16 isn't it? You say we assume .736 to be conservative 17 and we do an analysis at the reduced pressure for the 18 containment.

19 MR. GALLAGHER:

Right, but like Ahmed said 20 it--21 MEMBER WALLACE: And then we show that 22 it's okay.23 MR. GALLAGHER:

Right, but like Ahmed said 24 the --25 MEMBER WALLACE: You have no idea how far NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 71 1 you are from it being not okay.2 MR. GALLAGHER:

Well, we know where we are 3 as far as the measurements we have and we have 64 mils 4 of margin to that .736.5 MEMBER WALLACE: Well, when you do that 6 analysis, you come up with some critical stress or 7 something, X. And that's less than Y where it has to 8 be.9 MR. GALLAGHER:

Uh-huh.10 MEMBER WALLACE: You must know something 11 about how different those are.12 MR. GALLAGHER:

We have the safety 13 factors, Ahmed?14 MR. OUAOU: With that stress analysis and 15 as far as the sandbed region, the .736 is minimum 16 because using that thickness, using that thickness 17 stress limits you get in shell are those allowed by 18 the --19 MEMBER WALLACE: Now, they're just on the 20 borderline.

21 MR. OUAOU: They're very close.22 MEMBER WALLACE: Okay, so you just 23 happened to hit the borderline.

24 MR. OUAOU: With the applicable safety 25 factors, exactly.NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com

• ° 72 1 MEMBER WALLACE: That would help if you 2 had said that in the beginning.

Okay.3 MEMBER ABDEL-KHALIK:

What is the 4 certainty band on the .8 inch measured value?5 MR. GALLAGHER:

Pete?6 MR. TAMBURNO:

Whenever we take the data, 7 we do make some uncertainty calculations based on the 8 number of data points. Typically, the uncertainties 9 on those numbers are somewhere approximately between 10 plus or minus 10 mils.11 MEMBER ABDEL-KHALIK:

Is this a 95 percent 12 confidence level?13 MR. TAMBURNO:

Yes, sir, with 95 percent 14 confidence.

15 MEMBER WALLACE: Would it be true to say 16 you have no margin then? You had .8 and then you 17 said, "Well, to be sure we'll assume it could be .736, 18 and when we calculate that, the stresses are found to 19 be right on the borderline of acceptability." That 20 means there's no margin except in this .736 being less 21 than .8. There's no margin in the calculated stress.22 MR. GALLAGHER:

The margin that we're 23 saying we have is 64 mils.24 MEMBER WALLACE: Say that again, 64 mils?25 MR. GALLAGHER:

64 mils.NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com

.o 73 1 MEMBER SHACK: The difference between .8 2 and 736.3 MEMBER SIEBER: You arrived at that by 4 assuming a future corrosion rate.5 MEMBER WALLACE: Well, that'Is what I said, 6 if you have these slides that talk about thickness 7 with margin, unless you tell us what the margin is, we 8 don't know anything at all.9 MR. GALLAGHER:

Right.10 MEMBER WALLACE: That's why I'm being so 11 insistent about that.12 MR. GALLAGHER:

At this point in the 13 presentation, we're talking about the corrective 14 actions.15 MEMBER WALLACE: Yeah, I know, but --16 MR. GALLAGHER:

And what I'm saying is 17 going forward in the sandbed region, we've determined 18 that the corrosion was arrested and so -- and we put 19 the coating on. So the visual inspections we 20 performed on the coating verified that no ongoing 21 corrosion is taking place. So we are, you know, f lat-22 lined in the sandbed region as far as corrosion and 23 just, you know --24 MEMBER WALLACE: I have to decide whether 25 or not deducing stresses which are on the borderline NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.neafrgross.com 74 1 of acceptability is okay? Is that what I'm asked to 2 decide?3 MR. GALLAGHER:

I guess I don't understand 4 your concern because --5 MEMBER WALLACE: Well, I understand it 6 very well.7 MR. GALLAGHER:

The -- as with any 8 analysis, you have -- you determined what the minimum 9 and there will be safety factors with that. So with 10 the appropriate safety factors, we're saying we need 11 to be above .736. We've said that --12 MEMBER WALLACE: You just make it, right?13 MR. GALLAGHER:

Well, there's 64 mils of 14 margin and the corrosion has been arrested.15 MEMBER WALLACE: 64 mils of margin, that's 16 pretty --17 MR. GALLAGHER:

The corrosion has been 18 arrested and it's coated --19 MEMBER WALLACE: Because it's .8, okay.20 MR. GALLAGHER:

And it's coated.21 MEMBER WALLACE: Well, I thought you were 22 saying .8 might not be really accurate, so we'd assume 23 it's .736. Okay.24 CHAIRMAN MAYNARD: Well, the code has some 25 conservatism in it, too, does it not?NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 75 1 MR. GALLAGHER:

Yes, the safety factors 2 that we have in there.3 MEMBER BONACA: Yeah, the concern I have 4 is not the specifically but at some point you'll 5 address it too, I imagine. You made other commitments 6 regarding corrective actions and mitigative actions 7 and so on as a -- and then, you know, at the same time 8 as you make these commitments in writing and that are 9 reported in the SER, you had water in jugs out there 10 and you didn't even test it as you were supposed to 11 do. Could you tell us about that? I mean, I'm still 12 left with this question, are we talking about 13 hypothetical things or are we talking about what's 14 happening out there? How can we trust a program that 15 you claim was in place since 1990s and then it wasn't 16 in place when the inspection occurred?17 MR. GALLAGHER:

Yeah, do you want me to 18 address that issue right now?19 CHAIRMAN MAYNARD: Might as well, yes.20 MR. GALLAGHER:

Okay, so as far as the 21 water in the bottles, let's step back and talk about 22 that for a minute. First of all, our overall program 23 which I haven't got into yet on the initial aging 24 management program, relied on monitoring UT's in the 25 drywell area for the corrosion rate, to determine the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com

• .

76 1 corrosion rate and we determined these corrosion rates 2 were very low and then our ongoing coding inspections.

3 So we have, you know, fulfilled our commitments 4 associated with managing the aging and the drywell.5 Now, the water monitoring, we should have 6 been performed more rigorous water monitoring and one 7 of the things we identified when we were developing 8 our commitments for implementation for the license 9 renewal application, was that we had not been 10 rigorously performing the water monitoring.

In March 11 of this year, when we did a walk-down of the torus rim 12 from those sandbed drains, as we described there's 13 five sandbed drains. There's tubing that goes from 14 those sandbed drains to these water jugs, they're like 15 five-gallon water jugs. There was some water in 16 there. We believe that water is very old and we 17 believe that if there was any active leak, which we 18 verified at the time that there was no active leak, 19 the tubing was dry and that type of thing, if there 20 was an active leak, incidental observation would have 21 identified that as a concern and then we would have 22 taken corrective action.23 MEMBER BONACA: But you have no --24 MR. BARTON: But you're telling us that 25 nobody observed water that's been there for a long NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 77 1 time in the torus area that's collecting water from 2 the sand pocket drains, right, and nobody paid 3 attention to that or said, "Why is there water in 4 here"? I mean, you're saying it's old water. So for 5 a long time nobody gave a hoot about this commitment.

6 MEMBER BONACA: And what bothers me is 7 here you have, you know, the shell is down to minimum 8 margin, okay, and I grant it from you. I'm not going 9 to question this point. And so you would want to see 10 most aggressive actions to preserve the margin which 11 means delivering only commitments which says if there 12 is water, we're going to remove it within three months 13 and so on and so forth.14 Furthermore, I mean, you don't have record 15 of whether or not used a strippable tape. So you're 16 still not dealing with the source of the whole problem 17 which is these cracks up there in the refueling 18 cavities.

So I'm saying, since you haven't done it 19 yet, why am I to believe that you'll do it in the 20 future once we -- once you get to the operating 21 license for 20 more years? I mean, that's an 22 important issue.23 MR. BARTON: And also, isn't it standard 24 practice if you see water someplace in a container on 25 the floor or something that you sample it and see NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com v

78 1 where the hell the source is from before you throw it 2 away?3 MR. GALLAGHER:

That would have been 4 helpful. In this case --5 MR. BARTON: Would have been helpful? It 6 should have been required.

I mean, what kind of 7 practices do we got at this site these days where you 8 have something like that and people get rid of it and 9 nobody cares about what it is or where it came from.10 That doesn't tell me a hell of a lot about what's 11 going on at this site cultural-wise.

12 MR. GALLAGHER:

Yeah, the thought process 13 behind removing the water was to determine if there 14 was actively leakage going on. As far as commitments, 15 I can give you to Tim Rausch, he's our Site Vice 16 President and later on in our presentation, we do have 17 how we've, you know, tracked commitments, what we do 18 now, and how we insure they get done. Tim?19 MR. RAUSCH: Yes, good afternoon.

I'm Tim 20 Rausch, Site Vice President.

In response to the 21 question regarding the commitments and the integrity 22 of meeting those commitments, there was a period of 23 time in a transition of the station, in terms of 24 ownership and the commitments were not rigorously 25 upheld during that period of time.NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com

..w 79 1 MR. BARTON: They weren't what?2 MR. RAUSCH: They were not followed 3 through on.4 MR. BARTON: You make a commitment to the 5 NRC. You've got a commitment tracking system and you 6 ignored it.7 MR. RAUSCH: Yes, the commitment tracking 8 system for the particular commitment regarding the 9 water into the bottles and the monitoring of that was 10 a deficiency on our part in terms of the performance 11 and we acknowledge that in the exit -- of that AMP 12 exit that was conducted several weeks ago. So the 13 commitment that we have going forward is this company 14 has a formal commitment tracking system. It's 15 automated with backup barriers to insure that those 16 commitments are, in fact --17 MR. BARTON: Is that a brand new system?18 MR. RAUSCH: Well, it's not brand new but 19 it is an excellent system that is being implemented.

20 MR. BARTON: What happened to the old GPU 21 commitment tracking system? Did you throw that out?22 MR. RAUSCH: No, sir.23 MR. BARTON: Well, wasn't it in that 24 commitment system was well?25 MR. GALLAGHER:

This -- if I can answer NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.neairgross.com 80 1 that, Mr. Barton, the specific commitment was in 2 correspondence.

3 MR. BARTON: Right.4 MR. GALLAGHER:

And we have not found any 5 specific implementation document that implemented that 6 commitment from after it was made by GPU in the early 7 '90s.8 MR. BARTON: So nobody took that 9 correspondence from the NRC and put it in the 10 commitment tracking system.11 MR. GALLAGHER:

That's what it looks like 12 and now, we know that it was done and it was done by 13 the project personnel assigned to that and it was done 14 for a long period of time. I think it was one of 15 those things that was owned by, you know, high 16 ownership and they just did it but it was not embedded 17 in any, you know, rigorous process. Right now, we 18 have it as a specific preventative maintenance task 19 specifically scheduled and it will get done and it's 20 been done five times to date and there's been no water 21 detected in those drains.22 MEMBER BONACA: Well, I mean but, you 23 know, the commitments report in the SER were in 24 response from you on June 2 0th of this year and the 25 findings from the inspections that defeat those NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 81 1 commitments were in September.

2 MR. GALLAGHER:

The inspection actually 3 was in March and we had, ourself, identified this 4 water issue in the bottles.5 MEMBER BONACA: All right, I didn't --6 MR. GALLAGHER:

And it was during the 7 inspection in March also and the inspection exit was 8 not until September.

9 MEMBER BONACA: All right.10 CHAIRMAN MAYNARD: I know the questions 11 are important.

I would like for you to go ahead and 12 get through your presentation.

We also have the staff 13 to question on a number of these things as to why do 14 they find some of these things acceptable and if need 15 be, we can bring the licensee back up here and --16 MEMBER WALLACE: Let me tell you what I'm 17 thinking.

I've asked myself the question, are these 18 folks ready to go forward to the full committee.

They 19 don't always do that. This is a subcommittee, right?20 CHAIRMAN MAYNARD: Right.21 MEMBER WALLACE: We don' t always recommend 22 that they are ready to go forward. It's not as if the 23 schedule has to be always met. So you have to develop 24 some credibility.

So I guess that's what I'm after 25 here is getting enough credibility to go forward.NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 82 1 That's why I'm asking these questions.

2 CHAIRMAN MAYNARD: And I fully understand.

3 MEMBER WALLACE: If I don't have it, I'm 4 going to have to say, I'm going to have to have 5 another meeting or something.

So that's why I'm 6 asking.7 CHAIRMAN MAYNARD: I fully understand that 8 and that may be one of the options, you know. Again, 9 we won't end this meeting until we've either got the 10 questions answered or that we --11 MEMBER WALLACE: Yeah, you want to see 12 more of what they have to say.13 CHAIRMAN MAYNARD: Right, or we may very 14 well determine that we need another subcommittee 15 meeting before trying to go to the full committee.

I 16 would not recommend going to the full committee until 17 we've --18 MEMBER WALLACE: I've looked at the rest 19 of the slides. I think they can move quickly.20 CHAIRMAN MAYNARD: Yeah, if we can get 21 through theirs and also the staff's and hear the 22 public, then I think we'll be in a better position to 23 make some of those determinations.

24 MR. RAUSCH: Mr. Chairman, may I just 25 finish the comment in terms of the commitment.

The NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 83 1 company of Exelon/Amergen understands how the 2 commitment was met at this time and it has taken 3 corrective actions to insure that doesn't happen again 4 in terms of addressing the question of how can we feel 5 confident going forward that we won't have a similar 6 occurrence.

Thank you.7 MR. GALLAGHER:

Okay. I believe we're on 8 Slide 15 now, which --9 MEMBER SIEBER: Before you escape from 10 this slide, I do have a question.

You talk about 11 taking UT measurements, thickness measurements of the 12 shell. And it was stated that the corrosion of the 13 shell was not uniform and, therefore, when you take 14 individual point measurements, even in a grid or the 15 thousand measurements that you talked about on the 16 previous slide, there is some probability that there 17 is a thinner place than what you've measured.

And so, 18 you can't just assume that here's the minimum 19 thickness I can tolerate to withstand the pressure of 20 the -- the accident pressure.

You have to have some 21 margin that's statistically based between your minimum 22 measured thickness and the minimum or the minimum 23 allowed thickness for the pressure.

Have you done 24 that work and has the staff reviewed it?25 MR. GALLAGHER:

Pete?NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 84 1 MR. TAMBURNO:

Yes, we've done that work.2 We've taken the data for the upper regions and applied 3 a 95 percent confidence intervals on the data and also 4 in the sandbeds.5 MEMBER ABDEL-KHALIK:

How about the 6 embedded region?7 MR. TAMBURNO:

The embedded region has not 8 been inspected.

9 MEMBER ABDEL-KHALIK:

So do you have 10 confidence that the thickness in that region will be 11 greater than .8 inches?12 MR. OUAOU: This is Ahmed with Exelon. We 13 have confidence that the corrosion incentive bed 14 region and the embedded region it will not be greater 15 than the sandbed region itself. And since we use the 16 same analysis and the same minimum thickness, we 17 believe that balance the potential of having corrosion 18 in the embedded region. And --19 MEMBER ABDEL-KHALIK:

Where does your 20 confidence come from?21 MR. OUAOU: We have consulted with 22 corrosion experts. We looked at the environment that 23 the embedded shell is going to be subjected to. Based 24 on that, our consultants indicated that the corrosion 25 in the embedded shell will not be greater, should not NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 85 1 be greater than the sandbed region area.2 MEMBER SHACK: Well, that's certainly true 3 from when you had active ongoing corrosion in the 4 sandbed. You know, I'd fully accept that argument 5 that it would be less. Now, that you've arrested the 6 corrosion in the sandbed, what's your assurance of the 7 environment within there. That really comes down to 8 the integrity of the silicon seal.9 MR. OUAOU: And in response to that 10 question, we agree with you. The fact that the seal 11 itself now protects the embedded shell. We inspect 12 the seal with we inspect the coating mixture of that 13 it is not cracked or it is not damaged such that any 14 potential moisture will get in the embedded shell.15 MEMBER SHACK: And there's no other access 16 path for water to that embedded region.17 MR. OUAOU: No.18 MEMBER WALLACE: This 95 percent 19 confidence seems to me an important issue. If you do 20 a statistical analysis, it should be part of your 21 presentation.

It's a good piece of evidence and it 22 should be there. We shouldn't have to drag it out of 23 you and it should be explained fully so we know what 24 it was. Is it a confidence that the thickness is 25 bigger than .736 where there's 95 percent probability NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 86 1 and blah, blah, blah, or is it bigger than .72 or what 2 it is? Give us the numbers, otherwise it's all vague.3 MEMBER ARMIJO: Well, I'd like to add that 4 your Table 1 in your June 2 0th letter to the NRC shows 5 that in the embedded region you have almost three 6 times as much margin for the lower sphere even if you 7 assume that that region which you couldn't inspect, 8 corroded down to .8 inches. And you know, again, 9 beating a dead horse on this table, but this table is 10 very informative.

I got a lot out of it. I wish we 11 could all have had it in the presentation.

12 MR. GALLAGHER:

Okay, a point well-taken.

13 We'll -- I again apologize for not having that in 14 there.15 Okay, if we could move onto Slide 15 then, 16 which at this point in the presentation we've put the 17 corrective actions in place and then after the 18 corrective actions were implemented, the effectiveness 19 was then determined.

And we took UT thickness 20 measurements in 1992 and again, in 1994 in the sandbed 21 region and confirmed that the corrosion in the sandbed 22 region had been arrested.

UT measurements were also 23 taken in 1996. However, there were some anomalies in 24 this data. In some cases, the values were greater 25 than previously measured.NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 87 1 We investigated this and determined that 2 the most likely contributor is attributed to not 3 removing a protective grease coating prior to taking 4 the measurements.

Corrective actions are in place to 5 prevent this from happening in the future. These 6 sandbed UT measurements will be performed in the 7 refueling outage that begins this month.8 Also at this time to verify the 9 effectiveness, we did the coating inspections of the 10 applied coating to the sandbed region and that was 11 visually examined and determined to be acceptable.

If 12 we go to Slide 16, so now we're at the stage of our 13 initial aging management program. And the initial 14 aging management program that was established 15 primarily consisted of the upper drywell UT 16 measurements and the sandbed region coating 17 inspections.

The UT measurements in the sandbed 18 region were discontinued because the corrosion was 19 determined to be arrested and since the sandbed region 20 was now accessible, the visual inspections of the 21 coating were determined to be a more effective 22 inspection.

23 Every other refueling outage, the upper 24 elevation UT measurements have been performed.

These 25 measurements are verified to be greater than the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 88 1 minimum required plate thickness and a corrosion rate 2 is projected to verify the acceptability of continued 3 operation.

The results indicate that there's no 4 ongoing corrosion at the two elevations and that the 5 corrosion rate for the other three elevations are less 6 than one mil per year. The service life of the 7 drywell extends well beyond 2029 with margin.8 MEMBER WALLACE: Is this all based on some 9 sort of statistics or just measurements?

10 MR. GALLAGHER:

Pete?11 MR. TAMBURNO:

It's based on the 95 12 percent confidence intervals around the curve fit of 13 the data.14 MR. GALLAGHER:

Since the exterior surface 15 of the supper drywell is not accessible, these UT's 16 were continued.

Additionally since the exterior 17 surface of the drywell shell above the sandbed region 18 is not epoxy coated, the corrosion rates identified 19 are the leading indicators of corrosion overall in the 20 drywell. The coating applied to the sandbed region of 21 the drywell shell exterior has also been visually 22 examined, two of the 10 bays have been examined every 23 other refueling outage. Some of the bays have been 24 examined multiple times because those bays contain the 25 thinnest shell locations.

NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 89 1 A total of five of the 10 bays have been 2 inspected to date. All coding inspection results have 3 been satisfactory.

When we get into our future 4 program I'll show you that we are going to look at 5 those other five bays and then again all 10 bays every 6 10 years. Next slide.7 As part of the preparation of the license 8 renewal application and subsequent NRC review, the 9 drywell shell aging management program has been 10 enhanced.

The following are the key elements of our 11 aging management program. Amergen will continue to 12 apply the strippable coating on the reactor liner, 13 reactor cavity liner each refueling outage prior to 14 filling the reactor cavity with water. We will also 15 insure that the reactor cavity trough drains are 16 clear. These actions will eliminate water intrusion 17 into the sandbed region.18 Sandbed drain leakage monitoring is 19 performed quarterly during non-outage periods and will 20 be performed daily during the refueling outage when 21 the reactor cavity is filled with water. These are 22 the more rigorous inspections that I'm telling you we 23 have now through our preventative maintenance tasks.24 Corrective actions will be taken if further water 25 leakage is identified.

The upper drywell shell UT's NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 90 1 will continue to be taken every other refueling 2 outage. Again, these measurements are the leading 3 indicator of -- for corrosion, overall corrosion in 4 the drywell.5 Amergen will perform periodic confirmatory 6 UT inspections of the drywell shell in the sandbed 7 region. The UT measurements will be taken prior to 8 entering the period of extended operation and then 9 after four years. After confirming that the sandbed 10 region corrosion continues to be arrested, the 11 frequency would then be extended to 10 years 12 thereafter.

The NRC will be notified within 48 hours2 days <br />0.286 weeks <br />0.0658 months <br /> 13 of any unexpected results and corrective actions will 14 be taken.15 MEMBER SIEBER: If the coating fails right 16 after you do an inspection, how long will it take for 17 corrosion to take you below min wall, four years, or 18 have you done that?19 MR. GALLAGHER:

Pete, did you get the 20 question?21 MR. TAMBURNO:

This is Pete Tamburno.

At 22 the current projected corrosion rates that we've seen 23 in the upper regions, a four-year

-- it would take 24 much longer than four years.25 MEMBER SIEBER: Even uncoated?NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com

• .

91 1 MR. TAMBURNO:

Yes, sir.2 MEMBER BONACA: How do you justify 10 3 years?4 MR. GALLAGHER:

The 10-year inspection 5 rule for the coating?6 MEMBER BONACA: Yeah.7 MR. GALLAGHER:

Ahmed?8 MR. OUAOU: The 10-year inspection of the 9 coating is based on ISI ASME Section 11 but I think 10 one thing that's important to mention is that we are 11 actually doing or staggering the inspections during 12 refueling outages such that we've been looking at 13 three, I believe --14 MR. GALLAGHER:

Right, a minimum of three 15 bays every other outage.16 MR. OUAOU: -- minimum of three bays every 17 other outage.18 MR. GALLAGHER:

For the sandbed region 19 coating prior to the period of extended operation 20 Amergen will perform a visual inspections of epoxy 21 coating of the five bays that have yet to be 22 inspected.

23 MEMBER SHACK: I hate to interrupt.

How 24 extensive is this inspection going to be before you 25 enter the period of extended operation?

You look at NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 92 1 all the bays?2 MR. GALLAGHER:

There's five bays that we 3 have not yet inspected.

We were going to look at all 4 five of those and -- with our inspection program.5 MR. BARTON: This outage?6 MR. GALLAGHER:

We are doing them this 7 outage. The commitment is prior to the period of 8 extended operation.

9 MR. BARTON: So not much time.10 MR. GALLAGHER:

We have to start this 11 month.12 MEMBER BONACA: So, really, I mean, you 13 have some substance there. I mean, you don't know 14 what you're going to find.15 MR. GALLAGHER:

We've -- based on the 16 inspections we've done before, the coating has been 17 you know, satisfactory.

In addition, as I said, we'll 18 inspect 100 percent of the epoxy coating every 10 19 years during the period of extended operation.

So 20 Slide 18.21 So our overall conclusions on the drywell 22 corrosion at Oyster Creek are, the corrective actions 23 to mitigate the drywell shell corrosion have been 24 effective, the drywell shell corrosion was arrested in 25 the sandbed region and continues to be very low in the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 93 1 upper drywell elevations.

The service life of the 2 drywell shell extends beyond the year 2029 with 3 margin. And we have an effective aging management 4 program to insure continued safe operation.

5 MR. BARTON: This every 10 years is only 6 going to get you one inspection during your extended 7 period of operation.

8 MR. GALLAGHER:

For which --9 MR. BARTON: In drywell region, drywell 10 coating visual every 10 years, it gets done in 2009, 11 are you going to do in 2019, 2029, you're done, you 12 weren't going to do one anyhow. So you're going to do 13 one of them in 20 years.14 MR. GALLAGHER:

Are you talking about the 15 coating inspection, sir?16 MR. BARTON: That's what is says here.17 MR. GALLAGHER:

Okay, what we're doing is, 18 Ahmed had mentioned, we are staggering the 19 inspections, so every other outage, we're going to do 20 at least three bays.21 MR. BARTON: And every 10 years, you're 22 going to have done --23 MR. GALLAGHER:

100 percent, yes.24 MR. BARTON: -- 360 degrees.25 MR. GALLAGHER:

That's correct. So we'll NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com

• o 94 1 do it twice in the period of extended operation.

2 MR. BARTON: I gotcha now.3 MR. GALLAGHER:

Okay.4 MEMBER WALLACE: I think it's flexible.5 If you found some problem with the three bays, you 6 might then go back and inspect some more bays.7 MR. GALLAGHER:

That's correct. If we 8 find a problem, we would have to do an extended 9 condition and we would increase our inspections.

10 CHAIRMAN MAYNARD: That's what I'd asked 11 about earlier is criteria for if we find something, 12 expand and more frequent --13 MR. GALLAGHER:

We've also -- I've just 14 given you some of the key issues -- key commitments in 15 our aging management program. There's also other ones 16 particularly if we did find water say in the water 17 drains, we would do further inspections of the 18 coatings from those bays. So there's other features 19 in our program you know, to insure that issues that 20 are not expected are pursued and evaluated.

21 This slide, Slide 19, shows the five open 22 items from the Draft Safety Evaluation Report and to 23 close the first item we are committing to additional 24 inspection locations at the two plate transitions on 25 the shell and so this will be a total of four. We had NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 95 1 one inspection for each of these transition plates.2 We are going to increase that to four locations at 3 each of these two plate transitions and we will be 4 submitting additional correspondence on this issue.5 Based on discussions with the NRC staff, 6 we believe no additional information is needed from 7 Amergen on the other four items. So that concludes 8 the drywell corrosion.

Are there any more questions 9 on the drywell corrosion before we go onto the rest of 10 the presentation.

I'll ask the Chairman if --11 CHAIRMAN MAYNARD: We may have some more 12 questions.

What I'd like to do is get through the 13 presentation.

We'll have a number of questions for 14 the staff, and I'm -- as long as Amergen is staying 15 here, then after the presentations, if we have 16 additional questions at that time, we can come back to 17 some issues.18 MR. GALLAGHER:

Okay. All right, so I'll 19 now turn it over to Fred Polaski who will discuss some 20 of the key historical equipment issues and how they're 21 addressed and the results of our license renewal 22 application.

23 MR. POLASKI: Thank you, Mike. I'd like 24 to briefly discuss the history and status of other 25 significant plant equipment problems that have NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com

..

96 1 occurred at Oyster Creek. All of these issues are 2 well-understood and ongoing activities monitor these 3 issues as part of the Oyster Creek Corrective Action 4 Process. First of all, what I'd like to talk about is 5 the core shroud. In 1994, a significant 6 circumferential crack was identified in the H4 weld.7 Ten tie rods were installed to provide full structural 8 repair for the horizontal welds. Since then 9 inspections have not detected any significant 10 indications or cracking in the shroud.11 In 1978 a crack was identified in one of 12 the core spray spargers.

In the upper sparger there 13 was a 180-degree crack around the circumference of the 14 pipe. A mechanical clamp was installed.

In 15 subsequent refueling outages multiple indications were 16 observed and nine additional clamps were installed for 17 a total of 10. And of these 10 four of them were on 18 all of the T boxes and they're all clamped.19 Subsequent inspections and testing indicated there 20 really are only two confirmed indications that result 21 in leakage through the dispargers.

The root cause was 22 determined to be high residual stress from 23 installation of dispargers.

24 In 1991 a crack was observed in the top 25 guide of the reactor vessel. Subsequent inspections NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 97 1 identified further cracking and in 1996, a 100 percent 2 UT examination was performed of the top guide and 3 confirmed that there's six cracks in the top guide.4 Metal samples confirmed that the reason for the 5 cracking was a radiation assisted stress corrosion 6 cracking.

These cracks are monitored during refueling 7 outages and no new growth has been observed since the 8 year 2000.9 MEMBER SHACK: And your water chemistry 10 is?11 MR. POLASKI: The chemistry is good and 12 it's hydrogen water chemistry since 1992.13 MEMBER SHACK: With noble metal or just --14 MR. POLASKI: Noble metals in 2002.15 MEMBER ARMIJO: Do you attribute the lack 16 of new IGSCC cracks to the water chemistry?

17 MR. POLASKI: Water chemistry is a major 18 influence on IGSCC cracking.

With the proper water 19 chemistry you shouldn't have any IGSCC. And getting 20 ahead a little bit but I'll cover this, that the 21 hydrogen water chemistry implemented at Oyster Creek 22 is greater than 99 percent availability during the 23 last cycle. The injection rates are such that they 24 obtain a molar ratio of four to one. BWR VIP 25 recommends at least three to one, so four to one is NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 99 1 and no additional growth in the last -- you know, 2 since 2000.3 MEMBER ARMIJO: Do you have a noble metal 4 monitoring system?5 MR. POLASKI: Noble metals are injected in 6 2002. There is a hydrogen water chemistry monitoring 7 system.8 MEMBER ARMIJO: So you measure potential 9 and --10 MR. POLASKI: Yeah, you measure potential 11 to keep your minus or less than minus 230 millivolts.

12 The next thing I wanted to discuss was CRD 13 stub tubes. Two of them were found to be leaking in 14 2000. They were repaired by -- and this was observed 15 during the hydrostatic tests at the end of the 16 refueling outage. They were repaired by performing a 17 roll expansion of the CRD housing. They're inspected 18 every outage when the drywall is accessible and no 19 subsequent leaks have been observed.20 MEMBER SHACK: Just my own curiosity and 21 how reliable is your ECP measuring system? What's its 22 online availability?

23 MR. POLASKI: I'm going to ask Marsha or 24 Terry Schuster to answer that.25 MR. SCHUSTER:

Terry Schuster, Chemistry NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com

• o 100 1 and Environmental Manager for Oyster Creek Station.2 The ECP probes are continually available in the Bravo 3 recirculation loop. Our measured millivolt reading is 4 minus 400 millivolts for the ECP probes and that is 5 lower than the expected minimal value of minus 230 6 millivolts and that has been consistently the case for 7 the entire cycle.8 MEMBER SHACK: This is copper, copper 9 oxide?10 MR. SCHUSTER:

I'm sorry, I don't know the 11 makeup of the probe but it is available and it 12 measures good results continually.

13 MR. POLASKI: The other reactor vessel and 14 thermo component I just wanted to briefly discuss was 15 the steam dryer. I know that's been an issue in 16 previous license renewal applications.

Oyster Creek 17 inspections have identified some minor cracking.18 However, it's not been extensive and been repaired.19 The Oyster Creek steam dryers are a different design 20 than the one at Quad Cities and Dresden. It's a more 21 robust design. There have been no power uprates 22 performed at Oyster Creek and none are intended so we 23 don't have any of the flow problems and vibration 24 problems that they had at Quad Cities and we don't 25 believe it's going to be an issue for license renewal.NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 101 1 MEMBER SIEBER: Is it in scope?2 MR. POLASKI: Yes, it's in scope. And we 3 will be implementing the BWR VIP inspections on it but 4 don't expect any problems with it right now. The 5 other thing is too, and I already talked about 6 hydrogen water chemistry in noble metals. In 7 implementing inspection procedures for the reactor 8 vessel internals are all done in accordance with the 9 BWR VIP program, so we're following that program.10 The next thing I wanted to talk about, a 11 total different subject, medium voltage electrical 12 cables. There have been a history of failures of 13 these cables in wetted environments at Oyster Creek.14 Most was determined to be susceptible cables due to 15 design insulation type and manufacturing issues.16 Presently replacement cables that we're using are 17 Okenite EPRI cables which are designed for wetted 18 environment conditions.

We've had no failures of 19 these type cables since they've been installed.

20 And in the refueling outage later this 21 fall, the four known susceptible cables are going to 22 be replaced with Okenite EPRI cables.23 MR. BARTON: And this cable can withstand 24 a wet environment, the new one?25 MR. POLASKI: The new ones, let me just NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 102 1 double-check, Dan Barnes or Debby, are these in wetted 2 environments?

Yes, the answer is that these four are 3 in wetted environments.

4 MEMBER BONACA: They're qualified for it.5 MR. POLASKI: Pardon?6 MEMBER BONACA: The replacements are 7 qualified for wetted environment.

8 MR. POLASKI: Yes, they're designed for 9 wetted environments.

10 We've performed continuing testing of 11 cables and we have two types of testing we do. For 12 accessible shielded cables, we do online partial 13 discharge testing. And for cables that are either 14 unshielded or not accessible to be tested while 15 they're online, we do step voltage and power factor 16 testing when the lines can be determinated.

17 CHAIRMAN MAYNARD: I noticed, it looked 18 like for your inaccessible or underground medium 19 voltage cable, you were committing to a test 20 methodology that hasn't been approved yet but you 21 anticipate it being approved before the period of 22 extended operation.

23 MR. POLASKI: What we committed to in the 24 application was an aging management program that's 25 consistent with the GALL program. We have a vendor NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com v

103 1 that we've been using for several years to do testing 2 and that methodology has been submitted to IEEE and is 3 going through reviews right now. We believe it's 4 going to be an acceptable method to go forward in the 5 period of extended operation and we've used it and it 6 has indicated degradation of cables and that's been 7 confirmed in one or two cases when the cables have 8 been replaced.9 CHAIRMAN MAYNARD: I'll save the rest of 10 mine for the staff when they get to acceptability.

11 MR. BARTON: Has there been any work done 12 on site to either minimize or eliminate the water 13 intrusion into the conduct system?14 MR. POLASKI: Well, one thing that has 15 been done is some of the cables have been rerouted so 16 they're not in locations that would be susceptible to 17 water and that's really about the only thing you can 18 do where you've got cable that's in conduit 19 underground.

I mean, there's no way to prevent water 20 from getting into that conduit.21 MR. BARTON: So you have rerouted some of 22 those.23 MR. POLASKI: We have rerouted some of 24 those, but not all of them.25 MR. BARTON: Do you intend to reroute the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com

• o 104 1 rest of them or are you going to rely on the Okenite 2 cable?3 MR. POLASKI: Right now, the plan is to 4 rely on mainly the Okenite and the ongoing testing 5 where we should be able to detect any degradation, I 6 mean, because this cable testing is designed to look 7 for water issues and detect it, see it coming and be 8 able to replace it in time before it would fail.9 MR. BARTON: Or it bows, okay, thank you.10 MR. POLASKI: Any other questions on that?11 Okay. The next topic, I'd like to discuss is 12 underground piping. There have been leaks in 13 underground piping at Oyster Creek due to salt water 14 corrosion from the inside of the pipe after failure of 15 the internal coatings.

We've not have any failures 16 from age-related degradation of the external coatings 17 of this piping.18 MR. BARTON: Wait a minute, hasn't there 19 been any failures of water piping from coatings 20 deteriorated during installation?

21 MR. POLASKI: There was one with a problem 22 with installation problem of the coating but none of 23 that's been age related where it's degraded over time.24 And that one was fully investigated and it was 25 determined to be an installation problem that NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com f

105 1 occurred.2 MR. BARTON: And hopefully that's the only 3 installation problem that -- that piping coating was 4 damaged, all right.5 MR. POLASKI: The only way to determine if 6 there's any other ones is to dig it all up and look.7 MR. BARTON: I know you can't do that, I 8 understand that.9 MR. POLASKI: That probably would cause 10 more problems than if you'd just leave it alone.11 MR. BARTON: I understand that. In your 12 underground piping program, though, is the diesel 13 transfer piping from the main storage tank to the 14 diesel generator building included in that program, 15 because I couldn't find reference that that was or 16 that fire protection piping was included?17 MR. POLASKI: I'm going to ask Pete 18 Tamburno to answer that question.19 MR. BARTON: The one that had a leak in it 20 years ago.21 MR. TAMBURNO:

This is Pete Tamburno.22 We're replacing the diesel fuel transfer line 23 presently.

Right now, the project is about 70 percent 24 due and -- 70 percent complete and it should be done 25 by the end of the year. The fire protection system NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 106 1 has been added to the program and will be inspected as 2 part of our license renewal commitments.

3 MR. POLASKI: Thank you, Pete. What I 4 wanted to continue on was the site has an existing 5 ongoing underground piping program that was in place 6 before we started to prepare the license renewal 7 application, where they've looked at all the 8 underground piping and which is the most significant 9 and risk impact to the plant. They have replaced 50 10 percent of the underground safety-related emergency 11 service water piping and the remainder will be 12 replaced prior to entering the period of extended 13 operation.

The non-safety related service water 14 piping is being replaced with a phased plan as part of 15 this underground piping program.16 And the aging management programs in place 17 at the plant that enhanced as part of the license 18 renewal process to inspect all the in-scope buried 19 piping before we enter the period of extended 20 operation.

In summary, we believe that our existing 21 aging management programs have been successful in 22 managing aging for these issue and will be continued 23 into the period of extended operation and will be 24 successful for the next 20 years.25 Slide 21. Our license renewal application NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 107 1 was submitted July 2 2 nd, 2005. In the time period 2 when we were preparing that license renewal 3 application, I realized in my work with NEI licensure 4 task force and interfacing with the NRC that the NRC 5 was revising the Standard Review Plan in the GALL 6 report and that the new versions of that would be 7 issued in September 2005 and would be used by the 8 staff for their review of the application.

And I was 9 concerned that if we prepare the application using rev 10 0 of the GALL and standard review plan, which were 11 approved in 2001, that there would be a large number 12 of differences identified during the review by the 13 staff.14 So we discussed this issue with the staff 15 and obtained their concurrence that for preparation of 16 the Oyster Creek application, we would use the draft 17 revision 1 of the GALL and the Standard Review Plan 18 which were issued in January of 2005 and the NRC 19 expected that there would be few changes between the 20 draft and the final versions of rev 1. We also, in 21 preparation of the application, used NEI 95-10, the 22 guidance document and we used the latest revision on 23 that. Ultimately, we're using rev 6, which was issued 24 in June of 2005.25 This approach worked well for us and for NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 108 1 the NRC. After rev 1 was issued, we performed a 2 reconciliation of the final version versus the draft.3 We looked for changes and additions to aging 4 management programs.

We looked at the GALL line items 5 to determine if there were any of those that changed 6 from the ones we'd used for Oyster Creek, any had been 7 deleted or whether there was any new line items that 8 we would have used if it had been available when we 9 prepared the application.

10 The result of that, we identified that 11 four new inspections or enhancements to existing 12 inspections were needed. There was five new 13 exceptions to programs which we reconciled and 14 actually two of the exceptions we had identified in 15 the application was eliminated because of the update 16 to the application.

So overall, very few changes were 17 needed as a result of going to the new version of GALL 18 and Standard Review Plan.19 The last thing I'd like to mention in this 20 area is that the NRC's schedule and process for review 21 of our application consists of two audits on site but 22 the License Renewal Group, one for aging management 23 programs and one for aging management reviews. During 24 the first audit in October of 2005, it was recognized 25 by the NRC and Amergen that the backup information NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 109 1 that we had available for review by the NRC was not in 2 a format that facilitated an efficient review by the 3 staff. We made a decision then we would prepare basis 4 document notebooks similar to those used by other 5 applicants to support the future reviews and the 6 audits were held successfully in January and February 7 of 2006.8 Slide 22. We identified for Oyster Creek 9 in our application 57 aging management programs, 50 of 10 those that align with the GALL programs and seven were 11 plant specific.

Of the GALL programs, 32 were 12 existing programs, 14 of which required some 13 enhancements and we had 18 new programs.

I'd like to 14 mention about that 18 just a little bit that it's a 15 lot larger number than you would typically see, I 16 think, in recent applications, the reason being is 17 that our Forked River Combustion Turbines which are 18 alternate AC power supply with station blackout were 19 in scope of the rule. We prepared aging management 20 programs specifically for them that were separate and 21 different than the corresponding programs to the 22 plant. For example, in the cooling water aging 23 management program we have one for the Oyster Creek 24 plant. We have a different one for Forked River 25 Combustion Turbine.NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 110 Why was that separate and 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MR. BARTON: submitted late?MR. POLASKI: I was going to get to the point of late. I'll get to that in just a minute when I get into combustion turbines.

The reason we did it separate, I'll get to that whole thing in a minute, yeah.MR. BARTON: Okay, that's fine.MR. POLASKI: So 11 with Forked River and one also dealt with our meteorological tower and the reasons I'll get to in a second.MR. BARTON: Okay.MS. POLASKI: And seven plant specific, four existing and three new, again one with the Forked River Combustion Turbines.MEMBER SIEBER: Who is going to do the programs for the combustion turbine?MR. BARTON: He's going to get to that later.MR. POLASKI: I'm going to get -- Slide 23, the next slide.MEMBER SIEBER: First Energy, right, how are you going to make First Energy do it?MR. POLASKI: Okay, so for everybody's understanding, Forked River Combustion Turbines are NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com ill 1 two peaking combustion turbines rated at 30 megawatts 2 each. They were installed by GPU in 1989 in the 3 Oyster Creek Substation.

As a result of having to 4 comply with the station blackout rule, in 1992, these 5 were credited as the alternate AC power supply.6 Breakers were installed and transmission conductors 7 will be able to tie those into the plant. I will note 8 that only one of the two is needed to meet the station 9 blackout design.10 MEMBER SIEBER: Is one of the two 11 committed to the SBO or are they both committed?

12 MR. POLASKI: They're both committed to 13 station blackout but they have to make sure that one 14 is always available and one would be provided during 15 station blackout conditions.

16 MEMBER SIEBER: Okay. In reality, even 17 though they're 38 megawatts, I think our transformer 18 limitation is something like four megawatts we could 19 take off of those. So we only really need and could 20 only use one of them. They are currently owned and 21 operated by First Energy. So that -- you know, the 22 question is, how are we going to maintain them? They 23 are covered by the Maintenance Rule and surveillance 24 testing programs and as part of the station blackout 25 design, we monitor reliability of the those.NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 112 1 On Slide 24 --2 MR. BARTON: That means you've got a 3 systems engineer that makes sure everything First 4 Energy does is in accordance with your maintenance 5 rule?6 MR. POLASKI: That is correct.7 MEMBER SIEBER: Or doesn't do.8 MR. BARTON: Or doesn't do, yeah.9 MR. POLASKI: Well, it does to it. The 10 reliability is greater than 99 percent. In fact, I 11 think the number is like 99.92 percent for the last 12 100 starts. So that reliability has been very good on 13 this and that formed our basis for our initial aging 14 management strategy.

The licensure application 15 included these and credited the reliability monitoring 16 as I said, but after discussions with the NRC, we 17 elected to establish multiple GALL based aging 18 management programs to manage specific long-lived 19 passive components similar like we would do in the 20 plant.21 Now, so what does that program mean? In 22 some areas, the civil structural inspections, we will 23 continue to do that by Amergen as part of the 24 structural monitoring program. Electrical testing 25 will be done by Amergen personnel because it's non-NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com

• o 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 113 intrusive.

You can do it with equipment online or it's visual. The mechanical inspections, in large part, are going to be performed by First Energy and we are currently working with them to build those into their ongoing maintenance practices.

MEMBER SIEBER: If you have a loss of the grid, which has happened --MR. POLASKI: Yes.MEMBER SIEBER: And you use one of the combustion turbines as a station blackout combustion turbine, it will be running at around 10 percent load.MR. POLASKI: Yes.MEMBER SIEBER: Is this stable at 10 percent?MR. POLASKI: I'm going to ask Rick Skelskey from the station to answer that question.MEMBER SIEBER: Usually their more stable with a bigger load.MR. POLASKI: I understand.

MR. SKELSKEY:

Rick Skelskey, Engineering Manager Oyster Creek. So at 10 percent where it's about 20 percent load, it is stable at that and actually does run very well at those loads. And we test that every refueling outage. We bring combustion turbines on to the plant and assume the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 114 1 loads through our transformer.

2 MEMBER SIEBER: So you've tried.3 MR. SKELSKEY:

Yes, we do them. We do 4 test that and it is in our surveillance program and 5 that is performed every refueling outage.6 MEMBER SIEBER: Okay, thank you.7 MR. POLASKI: Any other questions on the 8 combustion turbines?9 MR. BARTON: Yeah, one other thing. Do 10 you have the agreement that they can't take it out for 11 maintenance, for instance, you can't take it out for 12 maintenance without getting your approval up front and 13 you can't -- they can't tag it out without going 14 through your control room or something like that?15 MR. POLASKI: I'm going to let Rick 16 discuss the details of that.17 MR. SKELSKEY:

Rick Skelskey again. On 18 the CT maintenance, for planned maintenance, we do get 19 their buy-in ahead of time and for unplanned 20 maintenance, something happens to the CT, the unit 21 does not start, our control room operators do get a 22 call and we enter those into our corrective action 23 process to monitor that. And we also -- we do get 24 reports of their starting so start demands and when 25 they actually start. We get that on a monthly basis NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com v

115 1 from them and then --2 MR. BARTON: If you want to bring GE into 3 doing overhaul on one of the units, how do you know 4 that?5 MR. SKELSKEY:

We work with First Energy.6 We have regular meetings with them and they schedule 7 that through us when they want to do that maintenance.

8 MR. BARTON: Okay.9 MR. SKELSKEY:

So, like I said, for 10 planned maintenance, that is scheduled with us.11 MR. BARTON: Thank you.12 MR. POLASKI: On Slide 25, discussed 13 briefly our commitment management process for license 14 renewal. There are 65 commitments that are listed in 15 Appendix A of the license renewal application which 16 will go into the FSAR. Fifty-seven of those are for 17 aging management programs and then there's eight 18 stand-alone commitments.

We have a -- generated a 19 passport commitment tracking number for license 20 renewal commitments.

Our passport system is a data 21 base system that we use at the plant at Oyster Creek 22 and also throughout Exelon for work management, 23 corrective action process, commitment tracking and 24 many other facets of things that go on at the plant 25 and so we've got a license renewal commitment number NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 116 1 you know, for license renewal commitments.

2 Then for that, we have an associated 3 action that contains the details for each of the 65 4 commitments and each of the implementing procedures 5 that we use to implement these aging management 6 programs as annotated to provide the linkage back to 7 the commitments and to preserve the details of the 8 commitment.

This process is controlled by the Exelon 9 commitment management procedures and processes.

10 If there's no questions on that, I'm going 11 to turn the presentation over to Tom Quintenz.

He's 12 going to provide a status on program implementation at 13 the site.14 MR. QUNITENZ:

Thanks, Fred. We should be 15 on Slide 26. Good afternoon, my name is Tom Quintenz.16 I'm the Oyster Creek Site License Renewal Engineer.17 I've been assigned to this project from the beginning 18 to the present time. My responsibilities are to 19 assure the proper level of site involvement throughout 20 the project including input to the LRA and through 21 implementation.

I'm here today to tell you about the 22 implementation of our aging management programs.23 The programs have generated 368 activities 24 to be performed prior to the period of extended 25 operation; 257 of these are new activities and 111 are NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 117 1 enhancements to ongoing existing activities at the 2 site. Each of the activities have been assessed to 3 determine the appropriate time for implementation.

4 Each of the --5 MEMBER WALLACE: If you could just explain 6 this, these numbers don't mean much by themselves, but 7 257 new activities.

8 MR. QUNITENZ:

That's correct.9 MEMBER WALLACE: And the obvious question 10 is why weren't they done before? What's different now 11 than before? Why are they done now?12 MR. QUNITENZ:

These are new activities 13 that were generated as a result of our review of the 14 GALL and producing the aging management programs that 15 we have.16 MR. BARTON: These are like one-time 17 inspections people say they have to do before an 18 extended period of -- I think that's the kind of thing 19 Tom's talking about.20 MEMBER WALLACE: That's the kind of thing 21 he's talking about.22 MR. QUNITENZ:

The new activities, as John 23 indicated, were activities that come out of our one-24 time and periodic inspections.

25 MEMBER WALLACE: You didn't look at the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 118 1 buckets before and now you're going to look at the 2 buckets. It's not that kind of thing.3 MR. QUNITENZ:

No, no, it's not.4 MEMBER WALLACE: Okay, it's inspections 5 that you have to do because of the aging.6 MR. QUNITENZ:

Right, and this was a 7 result of also pulling in non-safety related systems 8 that had the potential for interaction with safety 9 related systems in the plant that were not previously 10 at this level of inspection.

The following is a 11 breakdown of when we intend to implement each of these 12 activities.

Thirteen percent of the total will be 13 implemented in our upcoming refueling outage in 2006.14 A significant portion of these activities are 15 associated with inspections that we will be doing with 16 the drywell and --17 MEMBER WALLACE: I have no idea how to 18 evaluate this. I mean, if I saw 500 up there, it 19 wouldn't make a difference to me.20 MR. BARTON: Yeah, you probably couldn't 21 do them all.22 MR. QUNITENZ:

I'd have to say that first 23 of all, I'd have to talk about our work management 24 system. We've planned and schedule each year on the 25 order of 15,000 activities relative to operating the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 119 1 station. So these numbers to us are well manageable.

2 MEMBER WALLACE: It's not a huge new 3 workload for you?4 MR. QUNITENZ:

I would say that, as I 5 indicated before, there are new activities in here and 6 basically we have the capability to manage those. I 7 know Tim Rausch is here and we've discussed that with 8 him relative to that implementation as well.9 MEMBER ABDEL-KHALIK:

Was there a 10 prioritization process to decide which of these should 11 be done now and which should be done two years later?12 MR. QUNITENZ:

Yeah, basically

--13 MEMBER ABDEL-KHALIK:

How was that done?14 MR. QUNITENZ:

Yes. Basically we took all 15 of the activities that we committed to that were 16 implementing our commitments and we reviewed each of 17 them to determine what the appropriate time was to do.18 Did we have to have the unit off-line in order to 19 implement the activity or could we do that while we 20 were operating?

So we went through each activity to 21 make that determination.

We also organized a team of 22 people to take a look at the activities to see which 23 ones would be more appropriately a fit into our 24 refueling outage in this October as opposed to next 25 October or next year and when to schedule.NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 120 1 MEMBER ABDEL-KHALIK:

So it's a matter of 2 convenience rather than a matter of significance?

3 MR. QUNITENZ:

I think both weigh into 4 that determination.

For example, in terms of 5 significance, we rolled all of the drywell inspection 6 activities into this because we thought that that was 7 a significant item that we needed to really take care 8 of all the commitments relative to the drywell this 9 outage rather than waiting till the next outage. So 10 from a significance perspective, that did weigh into 11 this also.12 As indicated on the slide, 19 percent of 13 the total will be implemented during our refueling 14 outage in 2008. The remainder, 68 percent of the 15 total, will be implemented during plant operation 16 while we're online. A significant amount of these 17 activities will be done between the two refueling 18 outages. The completion of this work effort will 19 assure all required inspections have been completed 20 prior to the period of extended operation.

In 21 addition, all documents credited for implementing 22 license renewal commitments will be annotated 23 specifically with those commitments.

And this 24 assures continued implementation of our aging 25 management programs through the period of extended NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 121 1 operation.

2 Are there any questions or comments?

I'll 3 now turn it back over to Mike Gallagher.

4 MR. GALLAGHER:

Okay, so just to 5 summarize, we -- Slide 27, we have established the 6 aging management programs to insure continued safe 7 operation for the period of extended operation.

We've 8 also clearly identified and will implement all the 9 license renewal commitments as expected and we are on 10 track for completing the activities needed prior to 11 entering the period of extended operation.

That 12 concludes our presentation and we're open to any other 13 questions.

14 CHAIRMAN MAYNARD: What I'd like to do at 15 this point is first go ahead and take a break. I'd 16 like to get the staff's presentation, public comments.17 We may or may not call you back up at that time and 18 ask some additional questions at that time. So with 19 that, it's 20 till. Let's take a break and be back 20 here at five till.21 (A brief recess was taken at 3:43 p.m.)22 CHAIR MAYNARD: We will resume the 23 meeting. I'll turn it over to Mr. Ashley to present 24 the NRR.25 MR. ASHLEY: Thank you, Mr. Chairman.

My NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com

.o 122 1 name is Donnie Ashley. I am the Project Manager, 2 Staff Review of the Oyster Creek License Renewal 3 application.

Joining me today is Steve Tenien who is 4 the Scoping and Screening Team Leader, Michael Modes 5 from Region I. He was our Inspection Team Leader on 6 the project. Michael and I will be presenting the 7 results of our staff's review. Roy Matthews is with 8 us. He's the Audit Team Leader and he's present to 9 respond to any question that you may have concerning 10 the audits.11 MR. BARTON: You have three hours to 12 figure out what firebar D is taken. Can you tell us 13 that right up front?14 (Laughter.)

15 MR. ASHLEY: I'm still worrying about the 16 phone. Hans Asher is also here and he is to brief the 17 Committee on a confirmatory analysis that we did and 18 that we're in the process of conducting now on the 19 drywell and supporting all of us are the technical 20 reviewers in the audits to answer the questions that 21 you're going to have.22 Just a general overview, I won't repeat a 23 lot of the information other than to let you know that 24 there were the five items that the Applicant did 25 mention. There were 108 RAIs in this review and 366 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 123 1 audit questions and in all of those cases we got good 2 responses back from the Applicant and they were all in 3 a timely fashion. We had one major component that the 4 Applicant talked about as far as the fork driven 5 combustion turbine and if I go too fast, stop me and 6 we'll talk.7 CHAIR MAYNARD: No. I think the main 8 thing we want to be able to get into is the basis that 9 the staff has used to draw conclusions on the 10 acceptability of the drywell and some of the other 11 technical issues.12 MR. ASHLEY: Absolutely we'll do that.13 This is a listing again of our audits and inspections 14 that we conducted.

As far as the scoping and 15 screening in the back of your package are extra slides 16 that you can take a look at if you want to look at the 17 specific mechanical systems, the containment systems 18 and the electrical components and commodity groups.19 But the scoping and screening results included all the 20 SSCs that were within the scope of license renewal and 21 subject to aging management review. The one 22 additional that we had was I believe on met tower 23 equipment.

24 Michael Modes, if he's here, if he could 25 discuss the inspection that was conducted.

NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com

• ° 124 1 (Discussion off the microphone.)

2 MR. MODES: So we did a few week 3 inspection.

Next slide. No, that one.4 CHAIR MAYNARD: You're going to need to 5 make sure you use a microphone.

6 MR. MODES: Yes, I'm sorry. We did a two-7 week onsite inspection March 1 3 th to March 1 7 th and 8 March 2 7 th to March 3 1 st. These were scheduled to 9 nominally support the NRR reviews. The schedule calls 10 for about an eight-month window. We tried to jump in 11 between the audits and the SER.12 We had a team and this one was a large 13 inspection because we thought we needed to cover an 14 awful lot of ground and we also needed to have 15 specialists paying attention to special areas. So we 16 had eight inspectors covering all the disciplines and 17 one of those inspectors spent an entire one week 18 period doing nothing but walking down the plants. He 19 has about 30 years experience in the 20 operationalization aspects. He did a 54-A2 nonsafety 21 effect safety inspection.

22 And one of the inspectors spent the entire 23 two weeks onsite plus the week in between doing 24 nothing but looking at the drywell data, all the 25 videos, interviewing all the individuals, going NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 125 1 through all the historical records and going through 2 all the analysis that was performed.

The inspection 3 was performed in accordance with Procedure 71002.4 Next slide.5 The scoping and screening portion as I 6 said concentrated on the nonsafety systems whose 7 failure would impact safety systems. The guy who did 8 that emphasized physical walkdowns.

He did over a 9 dozen systems. He choose and did over a dozen 10 systems, but that means that he did way more 11 intersecting.

I don't think he spent more than an 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> each day with us debriefing when he was off 13 running around the plant trying to figure out whether 14 he could find weaknesses in their 54-A2 programs.

We 15 concluded that the methodology was adequate and it was 16 consistently applied. Next one.17 Aging management program. We did 30 18 programs and you've heard me say it before from the 19 bottom up starting with the implementing procedures, 20 the work orders, all the information at the plant that 21 gets you to understand what aging they're trying to 22 deal with and whether or not the procedures and 23 programs they're proposing will in fact manage what we 24 see or what we think will occur. This time we did 25 something a little creative and we took one risk NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 126 1 significant system, the isolation condenser, rather 2 than grinding through all these programs again. What 3 we did was we took the isolation condenser which is 4 risk significant but does not contribute to ECCS, so 5 it's safety related but not safety and it gets very 6 fuzzy but it's risk significant.

It contributes 7 substantially to the plant configuration post-accident 8 and what we did there was we looked at the program 9 that being applied to the aging of that risk 10 significant system and it was quite illustrative of 11 trying to do this thing from the back forward using 12 one system. We concluded that the Applicant 13 implemented the existing aging management programs as 14 they had described them in the application and that 15 acceptable enhancements, etc. were made. Next one.16 In response to NRC identified 17 inconsistencies, the Applicant revised the application 18 or entered those inconsistencies.

We generated a lot 19 of corrective actions as a consequence.

20 The Applicant provided assurance that 21 properly updated its current licensing basis in 22 accordance with 54.21b and the Applicant provided 23 assurance that the systems, structures and components 24 will perform the intended function, aging management 25 programs are adequate for the period of extended NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 127 1 operation.

Overall Oyster Creek's implementation of 2 aging management programs will be sufficient for the 3 extended period.4 MR. BARTON: I got a question.

You were 5 talking about iso-condenser and some of the exceptions 6 they took or whatever.

They took exception to the use 7 of ASME Code Class I small bore piping program and 8 they proposed to inspect one small socket weld off the 9 iso-condenser and the NRC bought that as acceptable.

10 Now I would like to understand why. Maybe you're not 11 the guy to ask but I had that question.12 MR. MODES: I'm not the guy.13 MEMBER WALLIS: I picked that up as well.14 I wondered about that.15 MR. BARTON: Can anybody answer that?16 CHAIR MAYNARD: Donnie, do you have 17 anybody in the staff?18 MR. ASHLEY: That did come up during the Roy, if you would come up to the microphone.

Roy 20 Matthew, the Team Leader.21 MEMBER WALLIS: The rationale was it's a 22 sampling process, but it's unusual that the sampling 23 of one is adequate.24 MR. DAVIS: I'm Jim Davis on the Audit 25 Team. We've accepted this at other facilities doing NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com

• ° 128 1 one socket weld as representative as under four inch 2 pipe and we've consistently used this because socket 3 welds are small enough that they're not normally 4 inspected.

5 MR. BARTON: I understand that. That's 6 why I wondered why one was acceptable as a sample. So 7 this is your standard.

One is good enough.8 MR. DAVIS: Yes, because they're not 9 normally even inspected other than by a system 10 walkdown.11 MR. BARTON: Yes, but they do end up 12 cracking.13 MR. DAVIS: Well, we're asking for a 14 destructive examination of the socket weld to make 15 sure that there's no degradation that's not visible.16 MR. BARTON: But it may or may not be in 17 this one socket weld and you're happy.18 MR. DAVIS: With one we're happy because 19 it's not normally included in the program. It's more 20 than is normally required.

But we feel that they have 21 to look at least one socket weld to see if they're 22 okay.23 MR. CHANG: Ken Chang, the Branch Chief -24 MEMBER WALLIS: As long as they claim 95 25 percent confidence from one socket weld.NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com

.o 129 1 MR. CHANG: Ken Chang, the Branch Chief 2 for the Audit branch License Renewal. We're not just 3 arbitrarily accepting the one socket weld. Although 4 it's difficult to inspect we want to inspect one of 5 the possible worst cases. In other words, you pick a 6 biased sample as one of the worst cases. You're not 7 picking along a continuous pipe. You're picking on a 8 fitting, on a reducer, on a socket weld, on something.

9 So that should represent a reasonably bad conditions.

10 If anything should happen, that should happen to that 11 component and also the welders went through the same 12 qualifications.

So if you pick one of the worst cases 13 of socket welding inspected, it would give you a 14 reasonable assurance that it's done correctly.

15 MR. BARTON: I'm just not sure that one 16 welded at every socket weld at Oyster Creek.17 MR. CHANG: But if you have 300 socket 18 welds, you cannot inspect all 300 socket welds.19 MR. BARTON: I don't think 300, but I was 20 just wondering why one was enough.21 MEMBER SIEBER: Well, the issue I think in 22 small bore piping, particularly socket welds, is they 23 do fail and they fail with greater frequency than 24 large bore pipe does.25 MEMBER WALLIS: Right.NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 130 1 MEMBER SIEBER: And usually they fail 2 because of vibration.

So how do you go and pick the 3 one that represents the worst case?4 MR. BARTON: I'm not sure this one 5 vibrates very much.6 MR. CHANG: No, this for vibration, this 7 socket weld you select on the basis of similar 8 fatigue. For vibration, there are other criteria to 9 evaluate the stresses and select the potential 10 location of failure. It's like amplitude and 11 frequency.

12 MEMBER SIEBER: Yes.13 MR. CHANG: Now that's different.

You do 14 it by walkdown.

You observe where you can see the 15 vibration amplitude is bigger than in other places.16 There are typical examples, typical procedures, by 17 every site to select the location and systems that are 18 susceptible to vibration.

19 MR. BARTON: I just don't see this one as 20 vibrating.

I don't know.21 PARTICIPANT:

It's not a vibration 22 problem.23 MR. BARTON: It sits at a dead lang off an 24 iso-condenser which only gets turned on if we really 25 need it during a event. Right?NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 131 1 MEMBER SIEBER: Right.2 MR. BARTON: So that's why I wondered why.3 MEMBER SIEBER: You can't also observe.4 MR. BARTON: What are you going to 5 observe? You're going to be there when the event 6 happens and see if it shakes.7 MEMBER SHACK: That's why he's inspecting 8 it because there is nothing to observe.9 MR. BARTON: Ah, yes. Why couldn't I have 10 figured that out?11 (Laughter.)

12 MEMBER SIEBER: You still have to pick the 13 one you're going to inspect.14 MEMBER SHACK: He's tried to, I think, 15 pick one with a certain consideration critique 16 potential and --17 MEMBER SIEBER: Right. I got it.18 CHAIR MAYNARD: Okay. Could we move on.19 MR. ASHLEY: Moving right along.20 MR. MODES: Any questions?

21 Okay. You guys are always interested in 22 the current performance of the facility.

So the 23 licensee is in regulatory response column two. If you 24 note they have one white in emergency preparedness 25 because they failed to recognize they were in an usual NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com

.o 132 1 condition during a grassing event. We have 2 subsequently done an inspection and did not fully 3 concur in their root cause analysis because it didn't 4 address fully the human performance element in the 5 white finding. So as a consequence, this remains 6 open.7 In addition, they do have one crosscutting 8 issue in the area of human performance which was 9 discussed at the midyear mid-cycle review with them 10 and it should surprise you absolutely not that the 11 crosscutting is failure to adhere to procedures.

12 MR. BARTON: Why shouldn't that surprise 13 us?14 MR. MODES: Well, you did ask a lot of 15 questions about how come they emptied the bottle and 16 as a matter of fact, you reflected exactly the 17 somewhat irritated remarks I had when I was told about 18 it. Any questions?

19 MR. BARTON: Nothing.20 MR. MODES: Thank you, gentlemen.

21 MR. ASHLEY: Thank you, Michael. Under 22 the aging management programs they happened to talk 23 about the 57 AMPs and again there are listings of the 24 amps that are in your package of slides if you'd like 25 to take a look at those.NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 133 1 This is an example of the aging management 2 on protective coatings and monitoring and maintenance 3 program that was evaluated in Section 3. This one 4 particularly has to do with the inspection of torus 5 bays and in subsection IWE of ASME Section 11.6 The structure's monitoring program is 17 7 commitments identified for that program. It also 8 includes structures for the station blackout system.9 Ten additional commitments for the station blackout 10 for the Forked River combustion turbines as the 11 Applicant discussed with you.12 In the aging management review overview 13 the soliciting of what the team looked at, the numbers 14 of systems, structures and components.

The aging 15 management specifically on the drywell talks about --16 MEMBER WALLIS: So let me ask you 17 inspection of 100 percent of the sandbed region epoxy 18 coating, is that just looking at it or is that 19 scratching it or pulling it?20 MR. ASHLEY: Which slide are you on, sir?21 MEMBER WALLIS: Well, I think I'm -- Am I 22 ahead of you or something?

23 PARTICIPANT:

Sixteen.24 MEMBER WALLIS: Am I ahead of you?25 MR. BARTON: What number are you on, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 134 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 Graham?MR. CHANG: Sixteen.MEMBER WALLIS: Sixteen. Aging management example. Am I ahead of you?MEMBER SIEBER: Yes.MEMBER WALLIS: I'm ahead of you. I'm sorry.(Several speaking at once.)MEMBER BONACA: You are behind because you're only on three or four.MEMBER WALLIS: You're ahead of us. It says 100 -- What does that mean?PARTICIPANT:

It's a visual inspection.

MEMBER WALLIS: They do do it to inspect samples.MR. ASHLEY: Jim Davis on the Audit Team.MR. DAVIS: It follows the ASTM recommendations for inspecting coatings which is a visual inspection.

If you find something, then you have to do something additional.

MEMBER WALLIS: So if it looks funny, it's blistered or something.

MR. DAVIS: Blistered or cracked or peeling.MEMBER WALLIS: You don't have to scratch NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.WASHINGTON, D.C. 20005-3701 www.nealrgross.com (202) 234-4433 135 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 it or pull it.MR. DAVIS: No.MEMBER WALLIS: Or do anything to it physically.

MR. DAVIS: No, that's not what the ASTM recommends.

MEMBER WALLIS: If it's right, then it's okay.MR. DAVIS: Yes. That's the normal way.I've talked to the industry expert, the Chairman of D-33, the protective coating committee.

MEMBER WALLIS: If it's falling off it's not okay, but if it's there, it's okay.MR. DAVIS: If it's cracked or if it's blistered or if it's --MEMBER WALLIS: Rust streaks or anything.CHAIR MAYNARD: Isn't there a criteria or a qualification for the individuals doing the visual inspection on this?MR. DAVIS: Yes, he's qualified.

CHAIR MAYNARD: It's not just anybody that can walk in there and take a look and make a decision.MR. DAVIS: Yes, you have to be a certified coating inspector and they actually put them upside-down in the sand bed region. It's 18 inches NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com

• o 136 1 wide. I don't think I'd fit in there, but they 2 actually do a very good visual inspection.

3 But having had some experience looking at 4 coatings, you can tell when they're going bad and then 5 there are other ASTM tests that can conduct such as a 6 cross hatch test or an adhesion test. So far to date, 7 they haven't had to do any of that.8 MEMBER WALLIS: I'm just thinking about my 9 experience with my vehicles or my house or something.

10 Sometimes the paint looks fine, but it's rotting 11 underneath.

12 MR. DAVIS: That's not normally the case 13 with these epoxy type coatings on metal, on steel.14 I'm a member -- I was a member of the ASTM D-33 15 Committee and we had tons of discussions on this and 16 actually Reg Guide 1.54 Rev 1 goes through the ASTM 17 requirements if you're interested.

18 MEMBER WALLIS: There's a lot of technical 19 evidence behind this.20 MR. DAVIS: Yes.21 MEMBER WALLIS: Okay. Thank you.22 MR. ASHLEY: Slide 19. This is a listing 23 again of the systems that were subject to the aging 24 management review.25 MEMBER WALLIS: All these numbers, what do NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 137 1 they mean? Does this mean this is typical plant or 2 it's exceptional or what?3 MR. ASHLEY: It's fairly typical for this 4 kind of plant.5 MEMBER SHACK: I think two of them.6 MEMBER WALLIS: Of this type of plant?7 It's typical of this type of result or license 8 renewal. You get this sort of numbers.9 MR. ASHLEY: Yes, the other plants do have 10 similar numbers.11 MEMBER WALLIS: It doesn't mean anything 12 to just have a list of numbers there.13 MR. ASHLEY: It's just to tell you how 14 much this --15 (Several speaking at once.)16 MEMBER WALLIS: -- in context or 17 something.

It doesn't mean any --18 MR. ASHLEY: The aging management program 19 for the drywell shell as was discussed earlier as far 20 as the protective monitoring coating, excuse me, the 21 protective coating monitoring and the Magnets Program.22 MEMBER BONACA: Again I have been 23 questioning this issue of preventative actions. Again 24 I mean everything stems from the fact that water is 25 leaking from that refueling cavity and there has to be NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com

.° 138 1 some design requirements there that are being violated 2 by the leakage and there has been some commitment to 3 use this steel tape, but it doesn't cure the whole 4 problem. I mean it has not cured it in the past. I 5 still wonder. To me it should be a central issue 6 regarding the leakage of the water.7 MR. BARTON: I think what we heard was 8 that there were two outages in succession.

When they 9 went through that decommissioning plan, they didn't do 10 that strippable coating and we all noticed cracks in 11 the liners.12 MEMBER BONACA: Yes.13 MR. BARTON: And the water in the bolus 14 was old. Is it that old?15 MEMBER BONACA: Yes. If I have confidence 16 that if you really do apply that tape properly.17 MR. BARTON: If you apply the strippable 18 coating, if coating has been applied in other outages 19 20 MEMBER BONACA: And is effective.

21 MR. BARTON: I guess they haven't seen any 22 leakage, have they? I don't know. Ask the licensee.23 Have you guys seen any leakage if you did put the 24 strippable coating on during a refuel outage?25 MR. TAMBURNO:

This is Pete Tamburno.

In NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 139 1 the past two outages where we've used the strippable 2 coatings, we haven't seen any leakage from above.3 MEMBER BONACA: Then it should be part of 4 the commitment.

Right? Do you have a commitment as 5 part of all this?6 MR. TAMBURNO:

Yes.7 MR. ASHLEY: This is a listing of the 8 commitments that the Applicant had made in various 9 documents that had been sent to us and if you'll see 10 here, the strippable coating will be applied directly 11 to the line.12 MEMBER BONACA: So that's a commitment.

13 MR. ASHLEY: And it is one of the 14 commitments.

15 MEMBER ARMIJO: Is it possible that you 16 could put a strippable coating on that was flawed and 17 you wouldn't know it or will you have some other 18 detector for water, either look at the drain lines to 19 see if this coating still is working?20 MR. ASHLEY: They, in fact, have a 21 commitment here for monitoring daily those leakages 22 during the outages. Yes sir. It appears that that's 23 where the leakage was occurring during those periods 24 of times.25 MEMBER ARMIJO: I thought that might.NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 140 1 CHAIR MAYNARD: One of the -- When they 2 had the leakage before, it wasn't going in the drain 3 like it was supposed to if it got passed that point 4 and from what the licensee said, it sounded like they 5 had changed that where it no longer has the low point 6 where it would drain down by the liner. It would go 7 down that drain so they could tell if they were 8 getting some leakage in that area.9 MR. ASHLEY: They would be able to tell, 10 yes sir, at that point.11 CHAIR MAYNARD: And my question is of the 12 staff the level of confidence that from what, you said 13 as an individual for at least three weeks going 14 through the data and talking to people about the 15 drywell and different things and other inspection team 16 members here, the confidence level that the strippable 17 tape and that the actions that they're taking will 18 prevent leakage and identify it if for any reason it 19 does occur?20 MR. ASHLEY: Yes sir. With the look that 21 was given this entire system and the history of the 22 system, the inspections that were conducted, the 23 audits that were done, although we'll talk in just a 24 minute about TLAAs and all of the open items are 25 linked to the TLAAs and that's in Section 4.7 of the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com

• o 141 1 Safety Evaluation Report.2 In addition to that, these other programs 3 on the monitoring, on the coatings programs, were also 4 reviewed by the audit teams in Section 3 as well. So 5 it got a very, very exhaustive look and in a little 6 while I'll bring Hans Asher and we'll talk to you 7 about where we're going from this point to further 8 verify.9 It's also my understanding that the 10 coatings inspections that are going to be done this 11 outage in the U2 testing also figure in too. That's 12 the reason we have the open items. It's because we 13 don't have complete information yet. So once we get 14 that information from the outage I think we'll be able 15 to say with confidence that we --16 MEMBER WALLIS: Do you monitor the leakage 17 by having buckets at the end of the drains and the 18 leakage only occurs during an outage when you're 19 refueling?

20 MR. ASHLEY: That's where the original 21 leakage was identified as --22 MEMBER WALLIS: So you identify the 23 leakage by looking at the buckets at the end of the 24 drains. That doesn't tell me whether the leakage 25 didn't come down and evaporate on the way down or NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 142 1 something.

I mean it doesn't have to go all the way 2 down to the bucket, does it?3 MR. ASHLEY: If it evaporates, it's gone.4 MEMBER WALLIS: Yeah, but it still shows 5 there's been a leak.6 MR. ASHLEY: It would be a very minor leak 7 at that point.8 MEMBER WALLIS: I don't know because a 9 damp surface can corrode quite nicely.10 MR. ASHLEY: But with the temperatures 11 that occur during normal operation

--12 MEMBER WALLIS: It would evaporate.

13 MR. ASHLEY: -- the water doesn't have 14 time to --15 MEMBER WALLIS: -- or just --16 MR. BARTON: That's secondary normal 17 operation you're leaking when you shut down/cool down.18 MEMBER WALLIS: That's when they leak.19 Right.20 MEMBER SIEBER: Yes.21 MR. ASHLEY: We don't feel like there's a 22 leakage that we've seen -23 MEMBER WALLIS: Don't feel like. That's 24 not good enough.25 MR. ASHLEY: -- was not operation leak.NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com

..w 1 2 3 4 5 6 7 8-9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 143 MEMBER WALLIS: So you're assured from some analysis that if there were a leak it would show up in the bucket and not be evaporated somewhere or just leave something else damp which might then do something later on.MR. ASHLEY: I don't know how to answer your question.MEMBER WALLIS: Or leave a puddle at the bottom of the --MS. LUND: Hans Asher is going to address that.(Off the record comments.)

MR. BARTON: I don't know if it would leave a puddle, Graham, because what they did when they went in there and they sloped the floor and put epoxy on it so it seals.yes.MEMBER WALLIS: It could be a damper.MR. BARTON: There could be a damp spot, (Off the record comments.)

MEMBER WALLIS: Certainly if there was the sand could gather the water and --MEMBER SIEBER: Yes, there's more sand.sand there, You're right.MEMBER WALLIS: That's good then because NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.WASHINGTON, D.C. 20005-3701 (202) 234-4433 www.nealrgross.com 144 1 previous the sand could stay damp and that's what 2 happened.

That's how you got the corrosion without 3 necessarily draining at all.4 MEMBER SIEBER: That's right.5 MR. ASHER: I will address your question 6 about the operation of water. We've heard about this 7 a long time back even during the Dresden containments 8 and we asked the same questions that you are asking to 9 the applicants.

Okay. And the general answer was 10 that it will operate and it won't corrode anything.11 I said no. I'm not ready to believe that. So what we 12 resulted that did, the earlier one, and I saw a 13 separate case too that we asked them to do the UT 14 measurements from upper areas through which the water 15 is continuing to the sand bed area. Okay. And a 16 number of applicants said unless they see no activity 17 of water at all during the entire life, then we will 18 say that is not necessary.

But that we have seen any 19 water leakage from their refueling cavity or any other 20 areas collected in the sand bed area, then the whole 21 spherical area and cylindrical area are suspect. In 22 this case also, at Oyster Creek also, they are 23 required to do the UT in the upper area of the shaft.24 MEMBER WALLIS: So the UT is the real 25 check rather than looking in the buckets.NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 145 1 MR. ASHER: Correct. UT is the real 2 check.3 MR. ASHLEY: Thank you, Hans. This is a 4 slide that discusses the aging management, the in-5 scope inaccessible concrete and that would be in the 6 structures system. The time limited aging analysis 7 sections 4. These are the TLAAs that were reviewed 8 and accepted by the teams.9 And if I could, I would like to go ahead 10 onto the 4.72 and talk about drywell corrosion.

I 11 know that's of interest to the subcommittee unless you 12 have specific questions about an item here that you 13 would like to talk about before I jump to the drywell.14 CHAIR MAYNARD: Go ahead.15 MR. ASHLEY: Give me just a second to get 16 there.17 (Off the record comments.)

18 MR. ASHLEY: We also have with us --19 MR. ASHER: Jason Petty.20 MR. ASHLEY: -- Jason Petty from Sandia 21 National Labs. So I'll turn it over to Hans to 22 discuss this.23 MR. ASHER: In case you ask me very 24 difficult questions, he's here to help me.25 MEMBER WALLIS: Okay.NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 146 1 MR. ASHER: Well from this slide, the only 2 thing I want to point out are two things, the load 3 that we have considered which are -- Okay. Let me 4 first start with --5 CHAIR MAYNARD: Can we wait just a minute 6 here? Do we have this slide?7 MR. ASHLEY: Yes sir. They should be in 8 the back of your handout. There should be several 9 slides there, the last four I think, the last four or 10 five.11 (Off the record comments.)

12 CHAIR MAYNARD: Thank you. I have it.13 MR. ASHER: Do you have it everybody?

The 14 first thing I want to explain, the reason why we 15 embarked on this particular plant for analysis 16 purposes, we have not done this kind of analysis on 17 other plants, containments, because in all of them 18 they have certain corrosion but the corrosion was 19 within certain limits and it never compromised the 20 minimum required thickness from the design point of 21 view. In this particular case, the degradation is 22 quite severe in many ways of the same bucket area and 23 we wanted to comfort ourselves that is this degraded 24 containment be able to perform its function in the 25 next 20 years. This was our aim.NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 147 1 So though we are depending quite a bit on 2 the commitments that the Applicant has made, but this 3 is something that we want to make sure ourselves that 4 this particular degraded containment is able to 5 withstand the loads it is designed for.6 MEMBER WALLIS: Did they do a similar 7 analysis or did you do it?8 MR. ASHER: Yes, in 1992-1993 time frame, 9 General Electric had done an analysis and that is what 10 you were talking about before, 0.732 ages and all 11 that.12 MEMBER WALLIS: Okay.13 MR. ASHER: That came from an General 14 Electric analysis.

Okay. On this slide, I want to 15 point out only two items. General loads, loads that 16 we have considered are the normal operating loads as 17 well as the seismic load. Seismic load we have 18 considered the static coefficient from SFAR which I 19 think are bounding because subsequent to the basic 20 load that are used in the SFAR, Oyster Creek have done 21 other detailed analysis.

But this load we consider 22 our bounding one.23 MEMBER WALLIS: This is a dead load.24 There are also pressure loads from --25 MR. ASHER: Yes. The next items, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 148 1 controlling load pieces. There are controlling LOCAs 2 that we have considered and truly the LOCAs that we 3 have considered are close to 10 to 12. Out of that, 4 we selected three of them which are going to control 5 certain aspects of the design.6 The first one is a refueling.

Refueling 7 is basically during the shutdown.

It is water in the 8 refueling cavity that puts weight on the drywell shell 9 and the buckling is a possibility under that load and 10 particularly for the containment we ought to look for 11 those things.12 The second is a design basis accident with 13 earthquake which is a part of LOCA, normal LOCA 14 calculations.

Post accident flooding with earthquake 15 that is also part of our LOCA calculations in SRP and 16 everywhere else. So these are the three.17 Now other two items, model geometry and 18 modeling corrosion.

I want to explain to you by 19 sketch rather than by speaking it out. Can you go to 20 the first sketch?21 (Off the record comments.)

22 MR. ASHER: Okay. Sandia National Lab has 23 done the full analysis.

In the case of General 24 Electric, what General Electric had done was take a 36 25 degree splice which is one-tenth of the total. We did NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.neafrgross.com 149 1 here because we know have computer capabilities to 2 completely do the final analysis of the entire shaft.3 So we used that particular technique and Sandia was 4 also in earlier in the degraded containment research 5 and they produced a couple of reports on this 6 particular aspect. So we hope that Sandia will be 7 able to do justice to this type of problem that we are 8 encountering in Oyster Creek. And in my opinion when 9 I read the draft report that they gave to me, it's 10 like poetry to a structural engineer.11 (Laughter.)

12 Here they modeled the personal lock 13 equipment edge which I don't think were separately 14 modeled in the case of General Electric.

Then there 15 are ten vents around here which are connected to the 16 torus and generally in the vent header area, but in 17 the second one -- Here. I just wanted to show the 18 spring that we have attached to here just to be more 19 realistic about the flexibility of the vent to move 20 around. These two springs were attached, the Sandia 21 computer separately from this particular model 22 analysis and inserted those springs into the model.23 Apart from that, Sandia has considered the stiffeners 24 and all the beams and all the details that are 25 necessary, Sandia National Lab has considered in this NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 150 1 particular model.2 Second, I want to show you the degradation 3 that we used in our analysis.

From cylindrical we 4 have used T equal to 85 is after the 0.406 is the as-5 built thickness.

Then 0.0075 is the one that 6 Applicant has computed from the 1980s to 2004 the kind 7 of readings that they have from the upper area.8 MEMBER WALLIS: I'm sorry. I'm trying to 9 10 MR. ASHER: These are corrosion rate.11 MEMBER WALLIS: These thicknesses are --12 MR. ASHER: 0.406.13 MEMBER WALLIS: -- measured values or --14 MR. ASHER: 0.604 is an as-built.15 MEMBER WALLIS: No. It's ASME as-built 16 before corroded, before corrosion.

17 MEMBER ARMIJO: No, the nominal thickness 18 -- Well, we have a conflict with the Amergan 19 submittal and your name there. Their table shows a 20 nominal design thickness as 0.640 and the minimum 21 measured thickness as 0.604.22 MR. ASHER: Okay. 0.604 minus we took the 23 25 years off extended period of operation.

24 CHAIR MAYNARD: The actual 0.604 is the 25 minimum measured.NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com v

151 1 MR. ASHER: Yes, because we are to 2 extrapolate to 20 more years. So it's a hypothetical 3 in that sense. But that is what's likely to occur.4 That's what we are considering.

So we used 0.585 over 5 there. Then in the upper sphere there was no 6 indication of any particular corrosion.

The knuckle 7 area did not seem to be -- And even if there is slight 8 closing, the knuckle area, it would not affect the 9 analysis too much and middle sphere, again we had 10 corrosion rate available that we used, 0.678 minus 11 circular point. That's what we used as a thickness.

12 Now in the sand bed area, I think I would 13 like to go to the next slide. No, let me go back to 14 explain something more. I want you to realize here 15 this is bay that we have considered, bay. It's the 16 red line here. There are one bay, two bays, three 17 bays are shown here. Each bay has an area of 18 approximately 50 square feet and the corroded area 19 that we say we computed the amount of --20 MEMBER WALLIS: Can I go back? The reason 21 the steel is so much thicker down there is because of 22 these pipes coming in.23 MR. ASHER: Well, a number of things.24 First thing, it is the bottom of the shell. So it 25 needs the more bearing.NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 152 1 MEMBER SIEBER: That's where all the 2 weight is.3 MR. ASHER: So right from this area, it's 4 1.54 inches. Up above there, thinner.5 MEMBER WALLIS: It's big jump from 0.65.6 MR. ASHER: Yes, it is. And that is where 7 some of the disconnected stresses do build up too.8 We'll talk about that a little later, but right now 9 what I want to consider is only the model of the --10 Okay. This one. Here if you see, these are the 11 thicknesses we -- Let me give you where we got these 12 readings from. We got these readings from the 1992, 13 I think, before Oyster Creek applied epoxy coating.14 They took the readings in each and every bay to see 15 how much is corroded and where to grind it out and, 16 you know, you asked a number of questions on those 17 things. So you know that. So that time they had 18 taken the readings in a very detailed manner.19 We had those tabulated everywhere and so 20 what we used was an average thickness of those 21 readings that came out of the 1992, I believe. Was it 22 1992?23 PARTICIPANT:

Yes, it was 1992 when it was 24 --25 MR. ASHER: Taken from outside.NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 153 1 MR. ASHLEY: I'm sorry. Ahmed, I'd like 2 you to use the mike.'3 MR. WO: Ahimed Wo with Exelon. In 4 response to your question, Hans, it's 1992 that we 5 took UT measurements from the outside.6 MR. ASHER: Okay, and this is what we --7 MEMBER WALLIS: So it seems bigger than 8 the 0.8 to the 0.764 or whatever it was we talked 9 about earlier.10 MR. ASHER: I will come to that. Just a 11 moment. I'm coming to that.12 MEMBER WALLIS: Okay.13 MR. ASHER: I want to emphasize one thing 14 that we tried to compute the corroded area versus the 15 bay area. The bay area is typically 50 square feet in 16 area, okay, one bay that I'm showing you here, this 17 bay, based on one bay, nine bay, that approximately 50 18 square feet in area. The most corroded areas are bays 19 13 and 1. Isn't it, Jason?20 PARTICIPANT:

Yes, at their center spot.21 MR. ASHER: Bay one and bay 13 is the 22 worst case area. In that area, the square feet area 23 covered by the serious corrosion is close to about 24 four square feet or so. Okay. So what comes out is 25 the area corroded in the whole bay is 10 percent of NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.neafrgross.com 154 1 the total area.2 MEMBER WALLIS: Why did it corrode in 3 those places?4 MR. ASHER: Yeah.5 MEMBER WALLIS: You have this leaking 6 water running down the side of this thing and certain 7 places it's very preferentially corroded.8 MR. ASHER: Yes, the logical explanation 9 that I can figure out was that this is quite a steep 10 area. Let's go back to the earlier slide. Yes, 11 that's good enough. From here, this area is very easy 12 for water to pass through. When there is sand there, 13 it passes through the sand and accumulates at the 14 bottom area, but the bed of the sand bed area and that 15 is where it stays stagnant for a long period of time.16 That is where most of the corrosion is located. In 17 each and every bay, that's the way what we noted.18 MEMBER WALLIS: Why is bay one so much 19 worst than the other one?20 MR. ASHER: Because my --21 MR. BARTON: Because that's where the 22 cracks are in the liner.23 MEMBER SIEBER: That's where the leak was.24 MR. ASHER: Where the leak concentrated.

25 The leak was not uniform all around this area.NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 155 1 MEMBER WALLIS: It was up above somewhere 2 and it ran down into the --3 MR. BARTON: The liner. It comes from the 4 top up in the cavity where the liner is.5 MR. ASHER: From the fueling cavity.6 Starts from the top.7 MR. BARTON: And the liner has cracks and 8 the cracks are not in all one spot. They're around 9 the liner. So I guess where the biggest cracks in the 10 liner are is where the most water comes in.11 MEMBER WALLIS: But cracks, this was 12 general corrosion right over the whole surface. It's 13 not --14 PARTICIPANT:

No.15 MEMBER WALLIS: From the top.16 (Several speaking at once.)17 MR. ASHER: There are no cracks. There 18 are no cracks anywhere.

They found general corrosion.

19 I want to correct this.20 (Several speaking at once.)21 MEMBER WALLIS: Cracks in the liner.22 MR. BARTON: Cracks in the liner. The 23 liner in the cavity.24 CHAIR MAYNARD: Talk -- Let's be careful.25 MR. ASHER: Oh, there are stainless steel NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 156 1 liner cracks. I agree.2 MEMBER SIEBER: There you go.3 MR. ASHER: But the cracks in the drywell 4 are a different problem all together.5 MEMBER WALLIS: That's why the bucket was 6 filling. The bucket was filling from bay one and not 7 from the other ones. You have five drains or 8 something here, don't you?9 MR. ASHER: Yeah, there are ten drains and 10 the buckets were filling down even after the --11 MEMBER WALLIS: And there's a place where 12 the water was found.13 MR. ASHER: After they put the epoxy 14 coating in.15 MEMBER WALLIS: And the place where the 16 water was found is consistent with the place where the 17 corrosion was found.18 MR. ASHER: Normally so but I have to ask 19 Applicant where it is, that particular question.

The 20 question is whether the latter on whatever water 21 collection was found was in those particular bays or 22 they were normally in any bays. Any idea?23 MR. TAMBURNO:

This is Pete Tamburno.

In 24 general we saw more water in bays one, 19 and 13.25 MR. ASHER: One, 19 and 13.NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 157 1 MEMBER WALLIS: There was water elsewhere 2 too.3 MR. TAMBURNO:

Yes sir.4 MR. ASHER: That could be. I mean that's 5 anybody's guess.6 MEMBER SHACK: He has corrosion 7 everywhere.

8 MR. BARTON: Yes, you had corrosion.

9 MR. ASHER: Corrosion is in all bays to 10 some extent, but these two bays were serious corrosion 11 and that's why we took that slice we are showing.12 This is the area where we took the lowest reading to 13 see the structure discontinuity effect of the thicker 14 part here with this thinner here.15 MEMBER WALLIS: You took a certain amount 16 of square feet and said that's thinner than everything 17 else.18 MR. ASHER: Yes. Exactly. And this is 19 the thinnest area, 0.705 which is the thickest and up 20 above we took 0.618 is the thinnest to see how it 21 behaves in analysis.22 MEMBER ARMIJO: Now those are different 23 than the numbers presented in other submittals.

24 MR. ASHER: Yes.25 MEMBER ARMIJO: They are actually less NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com

.o 158 1 than what seems to be later data. Am I confused?2 MR. ASHER: No, this is really the earlier 3 data but why this? Because 0.998.4 PARTICIPANT:

Some of these averages 5 question how you've done the average here.6 MEMBER ARMIJO: Just go ahead, but I don't 7 want to quibble. But there's an inconsistency between 8 this table and that chart and somewhere along the line 9 --10 MR. BARTON: Were they done the same time?11 This is '92. What's that date?12 MEMBER ARMIJO: It doesn't say, but just 13 somewhere along the line, sort that out. Your 14 approach is what I'm interested in.15 CHAIR MAYNARD: But are these numbers 16 though from a measured value and that you took off an 17 estimated corrosion rate to get to these numbers or 18 are these the actual measures?19 MR. ASHER: For the upper part of the 20 drywell, yes that's what we did. For the lower part 21 of the drywell, we used a measure. We did not 22 extrapolate them because the Applicant is insisting 23 that there's not going to be any more corrosion in 24 this area from now on. So we have not calculated any 25 corrosion rate at this time, but we have used what NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 159 1 they have given to us.2 MEMBER WALLIS: The problem we have is 3 that the table in the supplemental gives numbers 4 different from the numbers you used.5 MR. ASHER: Yes.6 MEMBERWALLIS:

We don't quite know what's 7 going on.8 MR. GILLESPIE:

Hans, let me. You 9 described it earlier and you just may need to step 10 back and describe it again. These numbers are not the 11 Applicant's numbers. These are numbers that the 12 analysis, the analysts at Sandia, came up with given 13 that the major corrosion area in each of the 50 square 14 feet was actually only about four square feet and you 15 said that.16 MR. ASHER: I said that.17 MR. GILLESPIE:

And so these are numbers 18 that came from the NRC supported analysis, not from 19 the licensee.20 MR. ASHLEY: Did the Sandia folks start 21 with a measured UT data and then treat them in some 22 way that converted them into these numbers?23 MR. GILLESPIE:

Yes and that's the key and 24 Hans and Jason can probably go through that if you 25 want to hear that detail.NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., NKW.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 160 1 MEMBER WALLIS: They start with the UT 2 data.3 MR. GILLESPIE:

Yes, they started with the 4 UT data.5 MEMBER WALLIS: Okay.6 MR. GILLESPIE:

But then they had to do 7 something with this four square feet over --8 MEMBER WALLIS: They made it thinner in 9 places.10 MR. GILLESPIE:

Yes, because they had to 11 average it over the 50 square foot pie-shaped segment 12 in order to get the analysis done.13 MEMBER WALLIS: Got it.14 MR. GILLESPIE:

So it's an averaging 15 process they use in the analysis.16 MEMBER WALLIS: But it would help. Sam 17 asked earlier for sort of a matrix of where the 18 measurements were so you could see what was actually 19 done and you could get some idea how it was averaged 20 and all that.21 MR. GILLESPIE:

Yes.22 MEMBER WALLIS: That would be very helpful 23 if we're going to really dig into this.24 MR. GILLESPIE:

And this I think you'd 25 find -- We haven't distributed it because Hans has a NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com

.o 161 1 draft NUREG CR but I think we can share that later 2 with the Committee.

3 MR. ASHER: I will say when I come to the 4 results I want to emphasize the preliminary results.5 We are still doing some studies and it might change 6 from what I said.7 MEMBER WALLIS: So this is a draft NUREG 8 CR. Is the NUREG CR going to be available before we 9 look at the final SER on this thing?10 MR. ASHER: We plan to -- I can provide 11 you with a copy of a draft report if you want to look 12 at it.13 MEMBER WALLIS: But the final is going to 14 be available?

15 CHAIR MAYNARD: Aren't you waiting from 16 some of the inspection results from this outage to see 17 if there are any adjustments that are needed in this?18 MR. ASHER: We are planning that. But in 19 case studies, if there are very large differences in 20 the thickness measurements that we see in the October 21 outage, then we will have to make adjustments and 22 recalculate the same stresses review. We are planning 23 that yes.24 MR. GILLESPIE:

But if the licensee -- As 25 Hans said, the ingoing assumption on the part of NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 162 1 Oyster Creek was that the coating has arrested because 2 it eliminates the oxygen. So the expectation is that 3 the current measurements should be within some 4 uncertainty.

5 MEMBER WALLIS: Nothing has happened for 6 ten years.7 MR. GILLESPIE:

That nothing has happened 8 for ten years. Hans is only suggesting that if 9 there's a significant difference that we'd have to 10 eyeball it again.11 MEMBER SHACK: Since you're doing a finite 12 element analysis, why do you have to do the averaging?

13 MR. ASHER: Well, because the rest, except 14 the thin area I'm showing you, in each bay the areas 15 are much thinner, much smaller, than this area that 16 I'm showing you here and the rest of the bay is 17 originally 1.152 inch more or less thickness.

There 18 might be some isolated pits in one place or the other, 19 but as far as the very serious corrosion like this --20 MEMBER WALLIS: Only in a few places.21 MR. ASHER: -- it's in those places. No, 22 in each and every base at the bottom, there is some 23 corrosion.

But these are the controlling corrosions.

24 (Several speaking at once.)25 MEMBER SHACK: But you're saying you're NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 163 1 averaging over the bay and I'm saying you have this 2 thing into umpty-dump finite elements.

Why not each 3 finite element?4 MR. ASHER: Jason, do you want to address 5 this question?6 PARTICIPANT:

For the analysis that we're 7 doing it's really not practical to build in that 8 topology of the point to point throughout space.9 There needs to be some sort of an averaging process 10 for it to be practical.

I don't have corrosion data 11 that specific to do that for one. Two, the elements 12 we're using --13 MEMBER SHACK: But I mean you can make it 14 as refined, obviously you can't as refined as your 15 corrosion data.16 PARTICIPANT:

Obviously with enough time 17 and enough data if it was specific enough, we could do 18 that. Yes. But it's really not practical.

19 CHAIR MAYNARD: From what you have seen, 20 do you think that would make any difference in your 21 results?22 PARTICIPANT:

What we do is we're trying 23 to have the numbers shaded on the conservative side 24 obviously so that we're covering any of those arms.25 MEMBER SHACK: That's what I was losing NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 164 1 whether you were averaging the thin area over the 2 whole bay which didn't seem conservative or you made 3 the whole bay correspond to the thin area.4 PARTICIPANT:

Now my understanding is that 5 the source that we've taken these values from were 6 thinner points that were shown by visual inspection.

7 They were visually inspected and then measured at the 8 thin locations.

9 MEMBER SHACK: And then you assign that 10 now to the whole bay.11 PARTICIPANT:

There were points throughout 12 a certain region and then that was averaged and 13 assigned uniformly to the whole bay. So, yes, within 14 that bay there are thinner regions and thicker 15 regions. That's why those two smaller regions that 16 Hans had mentioned were added in for us to capture 17 some of the effects of what if there's a smaller 18 region that's much, much thinner that's not captured 19 in this averaging process that we've done.20 MEMBER WALLIS: I think it would be much 21 clearer if all this were spelled out, you sort of 22 showed there 150 measurements, this is how they 23 scatter statistically and what did you do in terms of 24 averaging, did you average the low ones, did you 25 average the whole thing, were there lots of them NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 165 1 showing no corrosion at all and a few showing -- We 2 could see it. That would give a picture.3 MR. ASHER: The report will explain those 4 things for sure.5 MEMBER WALLIS: There is some work.6 MR. ASHER: Yes.7 MEMBER SHACK: Let me just see if I have 8 it in my mind though.9 MR. ASHER: We will make sure that we 10 explain this a little more.11 PARTICIPANT:

Yes, we'll have to.MEMBER 12 SHACK: You have an average for the bay now and then 13 you put in a local average for these low spots.14 MR. ASHER: Low areas, yes.15 MEMBER SHACK: Okay. Got it. So you're 16 probably conservative.

17 MR. ASHER: Because this is what we are 18 afraid of, the structure discontinuity and of course 19 because of the thickness differences.

We wanted to 20 see what kind of effect it has.21 MEMBER WALLIS: First it was the stuff 22 that shows the variation of the thicknesses and what 23 are the actual reportings in thickness?

24 (Of f the record comments.)

25 MEMBER SIEBER: I guess I have a couple of NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 166 1 questions.

When you consider the corrosion of the 2 drywell shells that changes the mass of the system and 3 your infinite element analysis takes into account the 4 fact that that mass is changed. From a seismic 5 standpoint, it changes the vibration mode, frequencies 6 and response, amplitudes.

7 (Two conversations going on at once.)8 MEMBER SIEBER: And you also took that 9 into account. How did you take into account the fact 10 that the sand pocket was removed because that also was 11 a cushioning effect and the support for the drywell.12 PARTICIPANT:

It has no support.13 MEMBER SIEBER: But it said in your 14 assumptions that you just used the coefficients from 15 the FSAR which reflect the fact that the sand pocket 16 was there. Right? Go ahead. I just need for you to 17 clarify what's going on here.18 MR. ASHER: Yes. Let me explain two 19 things separately.

Okay? For seismic loads, what we 20 have done is we have taken the upper bound values that 21 were being computed by the Applicant.

That was done 22 during the construction.

Since that time, the 23 Applicant had done a number of other analyses to 24 reduce the loads on certain supports and certain 25 piping supports and everything, the sophistical NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com W

167 1 analysis in 1993 for example. And I had reviewed that 2 in 1993. So I know that they had done that.3 Now I asked them a question as to these 4 values are bounding values or they are the one some 5 other analysis were bounded and I was told that no 6 they are the maximum that you can get out of -- these 7 valuesare the ones that are good values.8 Now how we have applied the seismic load 9 here, that is important here from what you are telling 10 me. The way we have applied seismic load here is at 11 the bottom there is a static load. There is no 12 dynamic analysis here. It's a moment. It does not 13 have the dynamic seismic analysis where we would put 14 damping and we take the -- We have not done that 15 because we felt that we wanted to concentrate much 16 more on the drywell corrosion.

But at the same time, 17 I agree that we ought to have a representative seismic 18 load and --19 MEMBER SIEBER: The degradation and the 20 modifications that they made change the seismic 21 response and I'm wondering did you take it into 22 account, yes or no, and if you didn't, how do you know 23 you're still conservative as far as overall strength 24 of the drywell is concerned in these three cases?25 MR. ASHER: Jason, do you want to say NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 168 1 anything?

Okay. This is what we have used, but we 2 can --3 MEMBER WALLIS: I'm looking at the 4 original report and you have the measurements in 5 higgly-piggly in fashion. There isn't a pattern that 6 makes any sense and the numbers vary a lot. Rather 7 than use this average, you have to do some sensitivity 8 study where you say suppose we put in something like 9 my colleague Bill Shack suggests, some sort of a 10 distribution of thickness or something and does it 11 make a difference.

12 CHAIR MAYNARD: Wait. We can't be trying 13 to answer three or four questions at once. We have 14 one question right now.15 MR. ASHER: And Mike Hessler from Sandia 16 wants to.17 MR. HESSLER: This is Mike Hessler from 18 Sandia. I supervise the work, the analysis, that 19 Jason did. The question as I understand it was that, 20 and we agree with you, that the changes in the 21 geometry due to the degradation, due to the removal 22 from the sand from the sand pocket, would affect the 23 seismic loads.24 For the analysis, the approach that we 25 took here, we knew we didn't have enough information NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com

• o 169 1 to do the rigorous level of analysis that GE had done.2 We don't know what the piping is. We don't know all 3 the equipment weights. So we had to utilize 4 information that was published in the FSAR. I think 5 the emphasis that we tried to do is to look at what, 6 not so much the absolute values, but the changes due 7 to the degradation.

We were concerned early on that 8 even if we did a detailed analysis of the undergraded 9 shell we would not get exactly the same numbers that 10 GE did just because of the difference in the modeling 11 and the uncertainty in the loads.12 So I think one critical aspect of the 13 analysis that we did was to do an analysis initially 14 with this three dimensional model with all the same 15 assumptions of the undergraded drywell shell and then 16 apply the degradation to that and see how that changed 17 the factors of safety for both stresses and buckling 18 for the three load cases that we had. So I wanted to 19 emphasize that I think that's a critical element of 20 this because we had to rely on incomplete information 21 on all of the loads. We didn't go back and do a time 22 history analysis to get the seismic response of the 23 shell. Obviously, we could given the time and 24 resources, but the emphasis as we understood it here 25 was to really understand what the effects of the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 170 1 degradation are.2 MEMBER SIEBER: Okay. What you did is 3 what I thought you did and probably what I would have 4 done. My follow-on question would be how do you know 5 that's conservative with regard to whether the 6 containment will fail or not under these cases up 7 there.8 MR. HESSLER: How do I know it's 9 conservative.

I have to rely on the fact that the 10 original design was reviewed and approved and 11 reflected all of the loads. We used the same loading 12 information that GE used in their analysis.

We just 13 applied it to this three dimensional model. Again, I 14 15 MEMBER SIEBER: I'm really going to have 16 to think about that.17 MR. HESSLER: But I just wanted to make 18 sure you understood.

19 MEMBER SIEBER: I'm a slower thinker than 20 some people.21 MR. HESSLER: I just wanted to make sure 22 you understood what we did and also --23 MEMBER SIEBER: Be patient. I think I do.24 MR. HESSLER: -- the focus that we really 25 thought we needed to look at was is the effect of the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 171 1 degradation significant rather than looking at the 2 absolute numbers in all cases.3 MEMBER WALLIS: And you found that they 4 were.5 MEMBER SIEBER: I'm interested in whether 6 it fails or not. To me, that's specific.7 MR. HESSLER: I understand.

I'm just 8 clarifying the scope of the work.9 MR. GILLESPIE:

I think -- Sandia only 10 really did the tasks that we asked them to do and 11 remember this is a confirmatory measurement.

We're 12 not designing a plant and we're confirming the 13 projection made by the licensee and a 1991-1992 GE 14 calculation.

And the question on the table for us was 15 because that calculation showed a very small margin 16 existed given it's a small margin let's have an 17 independent group take the best data we have available 18 which was limited data and do an independent 19 calculation to confirm the size of that margin. So I 20 think they've done what we asked them to do. But this 21 was not a de facto re-initial licensing review or 22 design review. So there were limitations of what we 23 asked them to do and I think they did exactly what we 24 asked them to do and that's why it's by difference.

25 MR. ABDEL-KALIK:

The analysis assumes NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 172 1 that the locally-thinned areas are the same location 2 as the vent lines. In fact, they are right above the 3 midplane of the vent lines in bays one and 13. Is 4 this really the most limiting location for these 5 locally-thinned areas?6 PARTICIPANT:

That picture is a little 7 misleading.

It's actually just below the vent lines.8 MR. ABDEL-KALIK:

Yes, but they have the 9 same azimuthal location angle wise. Is that the most 10 limiting azimuthal location for those locally-thinned 11 areas?12 MR. ASHER: That is true. The early 13 question was asked as to why all the corrosion took 14 place at the bottom of the, at the sand bed area and 15 that is where the serious corrosion is concentrated.

16 MR. ABDEL-KHALIK:

So you're saying that 17 the location was not selected based on where it would 18 be most limiting, but based on actual observation.

19 MR. ASHER: Actual observation.

20 MR. BARTON: Where it was, yes.21 MR. ABDEL-KHALIK:

Okay. Thank you.22 MEMBER WALLIS: But you've said that this 23 is sensitive to modeling and this business of 24 averaging and putting things in certain places gives 25 you a result. If you put the thin areas somewhere NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 173 1 else and you'd average in a different way, you'd get 2 a different answer and Frank Gillespie just said that 3 you're worried about having very low margin. So it 4 seems to me that you have to pretty thorough about 5 doing your sensitivity analysis.

Saying suppose we 6 did it a different way. What difference would it 7 make?8 MR. ABDEL-KHALIK:

Intuitively this is not 9 the most limiting location for the locally-thinned 10 area.11 MR. ASHER: Well for locally-thinned area 12 what we did was we looked at the results of that 1992 13 observations that UT results were done because that 14 time they truly went inside everywhere and took the UT 15 results right from where the corrosion is occurring at 16 that time and measured the metal thicknesses.

To us 17 it was very reliable measurements and based on that, 18 we made certain assumptions and that's why we are 19 saying the assumptions we made.20 You are quite right. To somebody else, 21 some other analysts can make some different 22 assumptions.

They come out with it different.

But 23 the way we have done it, we are going to the 24 conservation site and wherever we had the readings, 25 where we had a particular doubt or something, we erred NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 174 1 on the conservative side. So that's the way we have 2 done the analysis considering the measurements that 3 were taken during that time.4 CHAIR MAYNARD: I think it would be a 5 different situation if you still had active corrosion 6 going on.7 MR. ASHER: Right.8 CHAIR MAYNARD: And I think it would be 9 more important to go for the potentially worst case.10 Where you have a defined scope, you know what the 11 situation is and you have a mechanism in place that's 12 supposed to stop additional corrosion, that's a little 13 different situation.

14 MR. ASHER: Yes.15 MR. ABDEL-KHALIK:

I mean that would be 16 true if we really knew the topology of the surface and 17 knew exactly where the thinned areas are to a high 18 level of confidence.

I'm not sure that we do.19 MEMBER WALLIS: I thought the question was 20 even with no corrosion is it safe now, even with no 21 more corrosion.

Isn't that the question we're asking 22 you?23 MR. ASHER: Yes. Let's see the slide on 24 approximate safety factors. Again, I want to 25 emphasize these are the initial preliminary results.NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 175 1 So don't count on the numbers. But the degradation, 2 these are the values. You can see the difference on 3 the refueling load combination for example. The 4 safety factor again is buckling.

If it is not 5 degraded with same taken out, the SF itself would be 6 3.85. Now with degradation, it comes out to be 2.15.7 So you can see right away the impact of degradation 8 here.9 MEMBER WALLIS: But that means that it's 10 twice as strong as it needs to be to avoid collapse.11 Is that what a safety factor of two means?12 MR. ASHER: Yes.13 MEMBER SIEBER: That's the typical code 14 requirement.

15 MR. ASHER: There's a code requirement.

16 Two is the minimum code requirement.

They are at 17 margin 2.15. Now sometimes you can have 1.5 safety 18 factor. It doesn't mean it's going to buckle right 19 away.20 MEMBER WALLIS: Right.21 MR. ASHER: But still it doesn't meet the 22 code requirement.

23 MEMBER WALLIS: The more confident you are 24 the less safety factor you need.25 MR. ASHER: Absolutely yes.NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 176 1 MEMBER SIEBER: That's why it's two.2 MR. ASHER: The accident condition, there 3 is no question of buckling there. It's mainly the 4 tension stresses and memory stresses and post accident 5 load case, all stresses are within level D 6 requirements and buckling you can see the safety 7 factor again 3.65, 2.74 with degradation.

So you can 8 see the effect of degradation here.9 MEMBER WALLIS: I think you have a kind of 10 engineering judgment and even if you fiddle around 11 with the way you put these various thin regions you 12 get a safety factor of around two.13 MR. ASHER: Right. Two. Exactly. That's 14 what we are looking at.15 MEMBER SHACK: Now did you take this all 16 the way to failure to see just what the ultimate load 17 was?18 MR. ASHER: No, I think because we were 19 working with the load combinations that are designed 20 load combinations.

21 MEMBER SHACK: So you're only looking at 22 design loads.23 MR. ASHER: Yes, we did not go all the 24 way.25 MEMBER SHACK: Not 67.06.NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 177 MR. ASHER: Internal pressure you are thinking about. Right?MEMBER SHACK: Yes.MR. ASHER: No, we didn't do that.MEMBER SHACK: Right.MR. ASHER: We held on that for Peach Bottom. Sandia National Lab has done that for Peach Bottom all the way up to internal pressure going on to collapse, not collapse, but up to certain staid limit.PARTICIPANT:

Predictively.

MR. ASHER: Predictively.

MEMBER SHACK: I mean you did for 67.06 you did ultimate loads.MR. ASHER: Yes. And we've done that for other plants, but not for Oyster Creek.MEMBER WALLIS: It says in your figure refueling buckling location.

That seems to indicate to me that you have buckling.MR. ASHER: Well, again, I have to explain this to you. Because of the stresses that are developed, higher stresses in that area, so the likelihood that the buckling will occur if surely the loads are much more than this, they will buckle in those areas. That's what we are showing. It's not that it's a buckled area.NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 178 1 MEMBER WALLIS: If it fails by buckling by 2 the steel detaching itself from the concrete into the 3 well, is that what happens because you would think the 4 concrete would give it some stiffness if it tries to 5 buckle outwards?6 MEMBER SIEBER: It's a weight load from 7 the refueling.

8 MEMBER WALLIS: Doesn't that buckle it 9 outwards?10 MEMBER SIEBER: It can go either way. If 11 it's constrained by the concrete then it's going to go 12 in.13 MR. ASHER: Yes, it can go in.14 MEMBER SIEBER: It is stronger in that 15 configuration where it's forced to go in. But it can 16 still go in. There is a lot of weight there.17 MR. BARTON: Damn right.18 MR. ABDEL-KHALIK:

So if the locally 19 thinned area is azimuthally shifted to that location, 20 would it be possible for the safety factor to be less 21 than the code requires it?22 MR. ASHER: When we tried to locate this 23 locally thin area where several corrosion has been 24 recorded, why should I put it in a different place?25 I have no reason to do that.NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 179 1 MEMBER ARMIJO: Well, you might if you 2 hadn't sampled every area. So if your sampling 3 skipped large areas and you have no data.4 MR. ASHER: No, but in other bays, we had 5 the other bays too. We took one and 13 bays because 6 they had the worst corrosion.

We could have taken the 7 thin area in each and every bay and it would be much 8 smaller than this. Okay. This was about four square 9 feet or so. We could have taken two square feet, a 10 small area, with thinning not as much as this, the 11 other way, but that would not have made any difference 12 in understanding the mechanism of buckling.13 MEMBER WALLIS: Where's the thin area?14 MR. GILLESPIE:

Yes, I think again this is 15 a confirmatory licensing calculation.

This is not for 16 us a research project where we're actually going to 17 look at -- We are trying to confirm the licensee's 18 assertion on their margin. We are actually not trying 19 to independently establish the margin ourselves.

So 20 this whole analysis was done you might say on the as-21 found condition in 1992 of that shell as best we can 22 judge from all the inspection information, etc. But 23 I think structurally a small hole is not our interest 24 here. It was broad degradation that would affect this 25 kind of safety margin. So a small thin spot wasn't NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 180 1 going to matter.2 Again we're confirming their number.3 --We're not trying to independently calculate something 4 that's totally ours.5 CHAIR MAYNARD: Can we go on?6 MR. ASHER: Thank you very much. I want 7 to talk a little about commitment in the open items.8 I want to just point out a few things in the open 9 items.10 (of f the record comments.)

11 CHAIR MAYNARD: Okay. Could we pay 12 attention here? Okay. Go ahead.13 MR. ASHER: Yes. These are the five open 14 items we have right now and during the Applicant's 15 presentation, it said that the first open item is the 16 one that they are working on and they are going to put 17 in stove one, they are going to put four probes which 18 results in the area of the drywell shell and they say 19 that other four are accepted by NRCI. I disagree with 20 that. The 01 on the embedded shell is not something 21 that we have completely zeroed in on because 22 quantitatively the Applicant provided a pretty 23 convincing response qualitatively that it is a 24 concrete environmient and it is a new chance of having 25 oxygen getting into that area and at the most what it NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 181 1 can do is not less than 0.732 or whatever they had 2 shown in there. That was their argument and 3 qualitatively I tend to agree with that argument.4 But I do feel that they should show some 5 maybe chipping concrete in a particular area where the 6 damage had been the most, for example, in the sand bed 7 area to show that there's no corrosion here or there's 8 a minimum corrosion.

Something has to be done in that 9 area.10 We also provided an NXER report that the 11 Office of Research had developed earlier where they 12 can really find the thickness of the matter between 13 the embedded shell. These are guided but they are 14 more experimental in nature. I did request the 15 Applicant to explore some of them to see if they can 16 find something, to see if the metal thickness can be 17 measured somehow.18 So embedded shell is still the annoying 19 one. It's very difficult to -- Qualitatively as I say 20 I agree with their arguments, but quantitatively I 21 don't have anything to go by.22 The other three I agree with the 23 Applicant's conclusion that we have taken care of 24 through commitments and everything else.25 MEMBER ARMIJO: I think -- I keep going NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 182 1 back to this one table in that June 2 0th letter. I 2 think it was a response to a request for additional 3 information.

The Applicant submitted data showing the 4 margin for the lower sphere which I presume is the 5 embedded part of the containment.

Is that correct?6 MR. ASHER: No, the lower sphere includes 7 the sand bed area.8 MEMBER ARMIJO: They have a separate line 9 for sand bed than they have for the lower sphere. But 10 you're saying the lower sphere is let's say below the 11 equator. Is that --12 MEMBER SIEBER: Below the knuckle.13 MEMBER ARMIJO: Below the knuckle. All 14 right. I understand now.15 MR. ASHLEY: Thank you Hans. Which brings 16 up to our conclusion.

The staff has concluded that 17 the depending resolution of the open items that there 18 is reasonable assurance that the activities authorized 19 by the renewed license will continue to be conducted 20 in accordance with the current licensing basis; that 21 any changes made to the Oyster Creek current licensing 22 basis in order to comply with 10 CFR 5429(a) or in 23 accordance with the Act and the Commission's 24 regulations.

25 CHAIR MAYNARD: Appreciate it. I would NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 183 1 just like to make sure everybody realizes that that's 2 the conclusion that you're presenting.

That's not the 3 ACRS conclusion at this point. The ACRS has not made 4 any conclusion and still has quite a bit more to take 5 a look at. So I want to make sure that people 6 understand that's not an ACRS conclusion.

7 With that, I'd like to -- I believe that 8 we have -- That does complete the NRC staff's 9 presentation.

10 MR. GILLESPIE:

Yes.11 MEMBER WALLIS: Can I say something about 12 this? I've been looking at the original data here 13 from GPU and trying to figure it out and trying to see 14 how on earth it's related to the stuff that was 15 displayed in the Sandia study and it looks very 16 interesting and I think they need to be put side by 17 side so someone can explain to me how you go from the 18 measurements and the places where it was measured to 19 the actual numbers that were put into the computer 20 program so we can understand that process and it's a 21 believable one. Otherwise, there are just too many 22 ifs and it may well be it's right. It looks to me 23 looking at it superficially as if someone has made an 24 effort to be conservative and take the lowest value 25 and all that but it needs to be clearly spelled out.NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 184 1 MR. ASHLEY: In the final SER.2 MEMBER WALLIS: Yes, and in the 3 _ presentations I think too so that it's clear.4 CHAIR MAYNARD: Yes, I think at some point 5 the ACRS is going to have to have that information.

6 That's something that we're going to have to be taking 7 a look at before we're going to be able to make a 8 determination and I don't think you're prepared to do 9 that today.10 MR. ASHLEY: No sir. I don't think so.11 CHAIR MAYNARD: So with that, we'll -- I'm 12 sorry. Did you want to make any concluding?

13 MR. GILLESPIE:

No. I mean we'll make all 14 the reports and everything that we have available and 15 if there's a desire for us to come back or meet with 16 a couple of the members and go through the matching of 17 how we did the, how the Sandia staff did the Sandia 18 report, we'll be more than happy to do that.19 CHAIR MAYNARD: Okay. With that, it 20 brings us to the next agenda item which is Public 21 Comments and first on the list here is Paul Gunter 22 from the Nuclear Information Resource Service. And 23 I'll apologize to you for running late, but we can 24 certainly give you your time here.25 MR. GUNTER: Thank you. My name is Paul NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 185 1 Gunter. I'm Director of the Reactor Watchdog Project 2 for Nuclear Information and Resource Service. My 3 remarks are going to be very brief, just opening and 4 then an introduction to Richard Webster who will 5 conduct the presentation.

6 Nuclear Information and Resource Service 7 first got involved with this when we looked at the 8 Applicant's application and we were surprised that so 9 much credit was being taken for the epoxy coating on 10 the severely coated region and began our investigation 11 which led to the filing of the single contention on 12 November 14, 2005 before the Atomic Safety and 13 Licensing Board with regard to an inadequate 14 application in addressing the age management review of 15 the drywell age management review process.16 So essentially, six groups, five from the 17 state of New Jersey and ourselves, intervened on this 18 single contention and Rutgers Environmental Law Clinic 19 has reviewed the contention and the filings of our 20 experts and took the challenge up. With that, I would 21 like to turn what presentation we're going to make 22 today over to Richard Webster who is a staff attorney 23 with the Rutgers Environmental Law Clinic in Newark, 24 New Jersey. He has a BA in Physics at Oxford 25 University, a Masters in Engineering in Hydrology from NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 186 1 Imperial College in London and a JD from Columbia Law 2 School.3 MR. WEBSTER: Thank you Paul and first of 4 all, I would like to thank the panel for the 5 opportunity to present here today. I don't see how I 6 can do. I need to swallow the microphone here for a 7 second.8 CHAIR MAYNARD: We make them short so you 9 have to lean in.10 MR. WEBSTER: It's hard to watch the 11 computer and do the microphone at the same time here.12 But I can chew gum and rub my stomach at the same 13 time. So that's okay.14 So what we've heard today has been very 15 interesting and it's been very interesting to watch 16 your reaction because your reaction has mirrored our 17 reaction over the time. It's sort of this very slow 18 revealing of information and each bit of information 19 that you get actually adds to your concerns and the 20 conclusion that we've come to now is that there are 21 some very serious identified concerns.

They cover 22 both the current condition of the containment as well 23 as the whether the containment could go beyond safety 24 margins during any extended licensing period.25 We characterize the process here as NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 187 1 putting the cart before the horse because if you don't 2 know what the current margins are it's pretty hard to 3 design an adequate program to figure out whether those 4 margins are being maintained and at the moment, all 5 we've heard from the Applicant is what we already knew 6 which is that the monitoring has not been a time 7 sequence and it has not been adequate in terms of 8 space to really allow you to draw any definitive 9 conclusions about the current margins.10 Now let me just come through in more 11 detail and I'm going to start with the embedded region 12 because that's simpler because simply there's really 13 no data. So we don't have to worry too much about the 14 data there because there is none. And again our 15 concern is about the current state of the embedded 16 region and it's about the potential state of the 17 embedded region during any extended licensing period.18 And similar concerns for the sand bed region. It's 19 whether it meets safety margins now and whether any 20 significant degradation in the future would be 21 detected before safety margins are violated and that's 22 actually, that fourth item, is the subject of our 23 contention as well. So there is a limited scope of 24 litigation here and that's what we're litigating as 25 well.NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 188 1 So I think you've seen the diagrams.

This 2 is a bit of a bigger diagram of the containment and 3 just to be clear then, this is the sand bed region.4 CHAIR MAYNARD: I'm sorry.5 MR. WEBSTER: Paul will point.6 CHAIR MAYNARD: Stay at the microphone.

7 MR. MAYNARD: Paul will point to the sand 8 bed region and then the embedded region is right below 9 that. So we're talking about a small portion of a 10 very large structure here, but a very significant 11 portion.12 Now normally our temporal look at this 13 really starts and ends in 1992 because in 1992, they 14 took the sand out. They couldn't look at the region 15 very comprehensively before 1992 because the sand was 16 there and there's that large concrete curb on the 17 inside covering around two-thirds of the sand bed. So 18 from the inside, all they really do is look at the top 19 third and that led to the erroneous conclusion that 20 this was called at the time a bathtub ring of 21 corrosion.

Actually, it wasn't a bathtub ring of 22 corrosion.

It was a bathtub ring of monitoring.

23 So then when they got in there in '92 and 24 scrubbed it down, we did get a look at what was 25 happening in there and what was found was very NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 189 1 concerning.

In terms of embedded region, the sand bed 2 floor was unfinished, water had ponded on the floor, 3 the floor had deep craters which is so far 4 unexplained, but we think they are potentially due at 5 least to corrosion or rebar in that concrete.6 Until '92, there was no seal present 7 between the shell and the concrete to reduce 8 penetration of water in the gaps. Remember we have 9 ponded water in this area. The fact that there's a 10 seal there at all now tends to indicate there was a 11 gap. So it seems highly likely that that water has 12 penetrated into that gap and into the embedded region.13 MEMBER WALLIS: Now this water that has 14 ponded on the floor, that's inside the containment.

15 MR. WEBSTER: No, that's outside.16 MEMBER WALLIS: Outside. When you say 17 ponded, you mean outside.18 MR. WEBSTER: I mean the outside floor by 19 the drain stem.20 MEMBER ARMIJO: You mentioned deep crater.21 Could you be more quantitative?

22 MR. WEBSTER: No, that's just taken from 23 documents that we've seen.24 MEMBER ARMIJO: You don't have any --25 MR. WEBSTER: Paul, why don't you look up NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com v

190 1 those while I'll continue?

I'll get back to you. I 2 think they're in terms of feet rather than inches.3 MEMBER ARMIJO: In area?4 MR. WEBSTER: In area.5 MEMBER BONACA: And this is once you 6 remove the sand. Therefore, it's a surface.7 MR. WEBSTER: Right. This is the surface 8 that's found once the -- Here we are. Here's the 9 quote. Once the sand is removed, it reveals the 10 concrete surface which has hitherto been covered up 11 and it says the floor was cratered with some craters 12 adjacent to the shell. A few craters were big, about 13 12 to 13 feet long and 12 to 20 inches deep and 8 to 14 10 inches wide.15 MEMBER WALLIS: Twenty inches deep?16 MR. WEBSTER: Yes.17 MR. WEBSTER: And it says concrete 18 reinforcement bars could be seen bare in many bays. So 19 this certainly seems indicative that something's going 20 on in this embedded region.21 Now the other thing thinking about the 22 sources of water, we've heard that there's quite a lot 23 of wet areas in this plant affecting the wires and so 24 forth. It hasn't been ruled out yet but some of this 25 water down at the bottom could be from groundwater and NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 191 1 we think that's a potential source of water that so 2 far needs to be eliminated and we haven't seen 3 anything that eliminates that.4 Now corrosion is possible contrary to what 5 the Applicant would like to believe. Our expert has 6 assessed what the Applicant has put forward. He 7 states the statement that the concrete generates a 8 high pH environment, a pH of 12 to 13, and 9 thermodynamic calculations reveal no corrosion of iron 10 above 10 room temperature.

11 The latter statement is patently wrong.12 Thermodynamics clearly demonstrate that iron can 13 interact with water over the entire pH range even more 14 in the presence of oxygen. The rate of the reaction 15 is governed by the protectiveness of the corrosion 16 product layer. So from what we've seen and we've been 17 provided with absolutely no expert evidence whatsoever 18 from the Applicant about this issue and I don't know 19 if the NRC has had expert evidence on this issue, but 20 from what we've seen there absolutely is no 21 justification whatsoever for an assumption that no 22 corrosion could occur in the embedded region. In 23 fact, the opposite it appears that it was wet, that 24 there's at least some oxygen present at the top and 25 therefore also the visual observation which we didn't NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 192 1 know about until today is that the corrosion was just 2 as bad at the bottom as it was at the top if not 3 worse.4 MEMBER WALLIS: Are you saying partly that 5 if there are these craters in the concrete then the 6 concrete will no longer protect the steel? Is that 7 part of your contention?

8 MR. WEBSTER: No, what we're really saying 9 is that the craters may have resulted from rebar 10 corrosion and then once the rebar corrosion started to 11 happen, that provides a way for the water to seep down 12 into the --13 MEMBER WALLIS: It provides channels for 14 the water.15 MR. WEBSTER: Right.16 MEMBER WALLIS: Okay.17 MR. WEBSTER: So the effects of sand 18 removal ironically may have actually made this area 19 worse. There's a phenomenon called differential 20 aeration where actually in a crevice situation you 21 don't need oxygen present to have corrosion occurring 22 because electrons can be supplied through conductants 23 of the surface and so actually you can get 24 preferential corrosion of oxygen starved areas under 25 certain circumstances.

And it appears that that is NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com I f v 193 1 possible here, but of course, it's never been 2 verified.3 So we're not saying it's certainly 4 happening but it's certainly a possibility and it's a 5 possibility that needs to be eliminated before any 6 conclusions can be drawn about what's happening in 7 this embedded region and what has happened in this 8 embedded region prior to 1992 and in the 14 years 9 since 1992. It actually astonishes us that this 10 situation has gone unaddressed by the NRC for this 11 long.12 MEMBER WALLIS: Where does this 0.33 come 13 from?14 MR. WEBSTER: 0.33 is what was measured in 15 the sand bed region. You're skipping ahead. It was 16 what was measured in the sand bed region prior to the 17 sand being removed. There has been no corrosion rate 18 established.

So we decided we would use that 19 corrosion rate.20 MEMBER WALLIS: For a year or just the 21 total?22 MR. WEBSTER: This is per year.23 MEMBER WALLIS: For a year?24 MR. WEBSTER: Per year. That was the 25 maximum.NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 194 1 CHAIR MAYNARD: Did you get that from 2 taking what the original thickness was and what the 3 measured thickness was?4 MR. WEBSTER: Right.5 CHAIR MAYNARD: That's how you generated 6 your --7 MR. WEBSTER: Right.8 MEMBER WALLIS: That happened in a year.9 MR. WEBSTER: There were certain areas 10 over time that that happened.

That's the worst case 11 and what we're saying is until a rate is established 12 let's assume the worst case. I mean the Applicant it 13 seems has the duty to establish a corrosion rate.14 They haven't done that yet. They've had this problem 15 for -- They've known about this problem for at least 16 14 years and so far have done absolutely nothing about 17 it.18 So the steel thickness in the very lower 19 region is 0.676 as we've seen. The thickness at the 20 top is higher. It's 1.154 and just to be clear the 21 corrosion rates in the sand bed region do not bound 22 the corrosion rates in the embedded region because of 23 this differential aeration phenomenon.

24 MEMBER SIEBER: Can I conclude from this 25 that in two years you are corroded all the way NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 195 1 through?2 MR. WEBSTER: If that corrosion rate 3 applied. We're not saying that corrosion rate does 4 apply. We're saying the corrosion rate is unknown.5 So I don't think it surprises you that we 6 think some action is required here. We think there 7 needs to be a comprehensive check of current thickness 8 of metal in the embedded region. I'm very happy to 9 hear Hans Asher suggest that the analyses does want 10 some measurement of that region because that's 11 certainly news to us as of today. But we think that 12 the analyses has to be comprehensive.

Looking at this 13 problem though a keyhole is not going to produce the 14 answer.15 Second, I think this is very obvious.16 They need to monitor for wet conditions in the 17 embedded region using electronic detectors.

From what 18 our expert tells us, it's quite possible to insert 19 electronic detectors down there that register spacial 20 resistance and that would actually give you some idea 21 about whether the area is wet or not and it would 22 actually bolster up the Applicant's aging inspections 23 of this seal. I mean it's one thing to look at the 24 seal, but what the Applicant said with regard to the 25 component that was cracked is that visual inspection NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 196 1 identified one crack and then 100 percent UT 2 identified six cracks. That shows that visual 3 inspection doesn't give you the whole answer. It 4 gives you part of the answer. Once you see some 5 concerns, it's time to go and do some real 6 measurements and we have serious concerns already. So 7 we think it's time to go and do some real measurements 8 here. Let's just not sit around and argue about it on 9 an academic position when there's a real problem out 10 there and it needs to be solved and it needs to be 11 solved urgently.12 And finally, the Applicant needs to 13 establish acceptance criteria for the measurements 14 that they're going to take.15 MEMBER WALLIS: You'd be in trouble using 16 academic in a perjority.

17 MR. WEBSTER: I'm using it not in a 18 perjority sense but merely in the sense that it's 19 theoretical I should say. Remember I'm from Rutgers 20 Law School. So we do have some claims of academia 21 ourselves actually.22 MEMBER WALLIS: Sometimes academic studies 23 are better.24 MR. WEBSTER: Absolutely.

25 MEMBER WALLIS: Thank you.NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 197 1 MR. WEBSTER: But they're not known for 2 their urgency generally.

3 CHAIR MAYNARD: All right. Go ahead.4 MR. WEBSTER: So now moving on to the sand 5 bed. So that was basically a quick overview.

I'm 6 trying to move quickly here. So if you have 7 questions, I know it's been a long afternoon, so if 8 you have questions please stop me and ask me. But I 9 want to move through this fairly quickly because it's 10 getting to 5:00 p.m.11 CHAIR MAYNARD: I think you've seen that 12 the Committee is not shy.13 MR. WEBSTER: Okay. So as we've heard in 14 general in the sand bed, the most critical constraint 15 is buckling.

The modeling actually established three 16 criteria and I was surprised to hear only two 17 mentioned.

There's one on the uniform basis. There's 18 0.736 inches of wall thickness.

Of course, that's not 19 very useful because the wall thickness isn't uniform.20 So it's kind of hard to apply.21 There's a single point criterion which is 22 no point should be less than 0.49 inches. Again, it 23 comes back to a point made. I think --24 MEMBER WALLIS: If it's seven inches 25 buckling, it's not a point phenomenon.

NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 198 1 MR. WEBSTER: That's right. That's 2 actually a pressure bound phenomenon I think.3 MEMBER WALLIS: Thank you.4 MR. WEBSTER: But somebody made the point 5 earlier that you can't just take the single worst 6 measurement and say that's it. You have to do some 7 extreme valuable statistics to actually figure out 8 what the measurements are showing you. It could be 9 the worst point value and actually we have done that 10 for the Applicant because we're such nice guys. We 11 decided to give them a little free work, a little free 12 consulting work. So we've actually already done that 13 for one small portion of the data just to illustrate 14 the concept and show that it needs to be done more 15 comprehensively.

16 And then originally this was all based on 17 modeling of 36 degree slices of the shell. So there 18 are ten bays, 36 degree slices and the problem with 19 that is that there are two assumptions there. One is 20 actual symmetry and the second was a spherical shape 21 and it seems like now we have the Sandia study we've 22 just heard about which is the first that we heard 23 about it too has discarded the actual symmetry 24 assumption to some extent but it does appear to retain 25 the spherical shape assumption.

NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 199 1 MEMBER WALLIS: Your concern is that if 2 it's slightly off spherical that makes a difference.

3 MR. WEBSTER: Yes. So as I said, these 4 are the problems with the established criteria.

The 5 sand bed is far from uniform as I said. It's actually 6 described, the surface was described in the report, 7 reporting the 1992 results as a golfball with dimples 8 going in and out.9 According to our structural experts who 10 have again done some good free work for the Applicant, 11 the symmetry assumption prevents the simulating anti-12 symmetric buckling.

They actually said that it's 13 possible that the bounding criteria is a combination 14 of symmetric and anti-symmetric buckling, but a 15 symmetric model can't model that. But I assume the 16 Sandia model can. So I guess when we all hear all 17 these caveats about what the Sandia model doesn't do 18 I guess we're wondering which model does do what the 19 Sandia model didn't do.20 And finally the derivation of the small 21 area criteria was not rigorous because, and I think 22 the same problem actually applies to the Sandia study, 23 you have to look at different geometries.

Assuming a 24 square area is not -- I mean it gives you some 25 information but it doesn't tell you what the smallest NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 200 1 area below a certain thickness could be to define the 2 safety criteria.

It appears that a horizontal gash 3 for instance could be smaller but lead to a more 4 stringent criterion although that's really just 5 speculation.

I mean nobody as far as I know has done 6 any modeling to look at the effects of these 7 geometries.

But it just seems unlikely that a perfect 8 square is the most bounding geometry.

It seems much 9 more likely that's been selected as a modeling 10 assumption rather than based on some sort of review of 11 what would be bounding.12 Okay. So that's the first point then.13 The first point is that the established criteria 14 really aren't rigorous.

So we don't have any rigorous 15 criteria for this shell as of now. That's the first 16 problem because you keep asking me about the margin.17 I'm going to try and get to the margin but it's very 18 hard to get to the margin when we don't even have 19 acceptance criteria.20 So the next problem is what about the 21 measured results. The last measurements that were not 22 in question were taken in '92. They were taken 23 actually from the inside and from the outside. As 24 we've seen, the inside results are very limited 25 because they're limited to the top one-third of the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 201 1 sand bed. The problem with the outside results --2 Well, let me give you what the results 3 are. The smallest measure of result was 0.603 inches 4 from the inside and 0.618 from the outside. So it's 5 why I have an issue with the Sandia results is they 6 don't even, let along extreme value statistics, 7 represent what was measured and the second issue that 8 results with those that results is of course there are 9 error bars in those results. I mean that's what the 10 result is but that doesn't show you what the worst 11 could be. It's actually around five percent of all 12 thickness error bar. So it's 0.03 for each single 13 measurement just straightforwardly but the extreme 14 value analysis should pull that through. But it 15 hasn't been done yet.16 And now the GE study looked at how 17 assuming a 0.736 thickness shell could certain areas 18 be below 0.736? Obviously the way it worked really in 19 history is that the Applicant thought there weren't 20 any errors less than 0.736 initially.

So they modeled 21 0.736. But then of course some monitoring showed up 22 some measurements less than 0.736 and then they 23 started to say what can we do about that. And what GE 24 did was they cut a square foot and took it down to 25 0.576 I think and had a look at that and what they NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 202 1 found was as long as the area below 0.736 was less 2 than one square foot in each bay, you could maintain 3 the safety criteria.

But if it went above one square 4 foot, well, I'm not sure they actually tested it 5 above. That's basically the limit of their conclusion 6 that provided the area less than 0.736 was less than 7 one square foot you would be okay.8 Now I wasn't quite sure when Hans said 9 four square feet because the Applicant's number that 10 they quoted for the area below 0.736 is 0.68 square 11 feet. The problem with that number is they haven't 12 really measured this parameter at all. The 13 measurements from the outside as we've just heard just 14 took the thinnest spot. They didn't make an attempt 15 to measure the area below 0.736 and the measurements 16 on the inside cover around three square feet. There 17 are 12 6"X6" areas being measured.

So that covers 18 three square feet.19 Now we've put out the numbers that the 20 total area was 300 square feet. In fact, we've heard 21 from Hans today that actually the total area is 500 22 square feet. So from the inside, they are measuring 23 less than one percent of the area. So they simply 24 don't have any measurement of the area below 0.736 and 25 that was something that was a bounding result in the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 203 1 modeling.

So somewhere along the line, this 2 acceptance criterion got lost and at the moment, I 3 would like to -- I don't want to mischaracterize what 4 Hans said, but it's startlingly worrying to me like 5 the NRC believes that the area below 0.736 in bays one 6 and 13 could be greater than one square foot. If 7 that's true, we would be beyond the safety margins 8 already.9 MEMBER ARMIJO: I have a quick question 10 for you.11 MR. WEBSTER: Sure.12 MEMBER ARMIJO: You say the smallest 13 measured results was 0.603 from the inside and 0.618 14 from the outside. Now are those numbers that you took 15 for the sand bed region?16 MR. WEBSTER: Yes, these are all --17 Everything relates to the sand bed region.18 MEMBER ARMIJO: And this is an individual 19 measurement not an average.20 MR. WEBSTER: This is an individual 21 measurement not an average. Just to take it up on the 22 averaging, if you look into the averaging you'll find 23 all sorts of problems there. I'll allude to them 24 later but the statistical treatment of these results 25 is a complete mess.NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 204 1 So the problem is each measurement is 2 uncertain by about 0.03 inches and just to show you 3 that the Applicant is fully aware of the extent of the 4 error they actually accepted results that showed 5 growth of, I said growth, in metal of 0.05 inches over 6 two years. It was only when we analyzed the results 7 and showed that that growth was systematic throughout 8 the results and therefore could not be a result of 9 random error but had to be the result of systematic, 10 that the Applicant suddenly turned around and decided 11 that there was an anomaly in those results. And 12 actually the anomaly doesn't actually just extend 96.13 It also extends to 94 because that was done with the 14 same methodology.

15 So these are quotes from Dr. Hausler who 16 is our expert who you can imagine was kind of amazed 17 to discover this. The general thickness for each grid 18 decreases from 92 to 94. So you know first of all 19 there's a claim that corrosion has been arrested.20 That wasn't what the 92 and 94 result showed. If 21 those 94 results are valid, it actually shows some 22 degree of corrosion even immediately after the coating 23 was placed upon there.24 The '96 results are the ones that 25 Applicant relied upon to draw a conclusion of no NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 205 1 corrosion.

But those results systematically showed 2 metal growth and Dr. Hausler coins this was of course 3 physically impossible.

Metal does not simply 4 spontaneously get thicker and the Applicant has now 5 agreed with him. But Amergan on June 20, 2006 6 admitted that the 1996 results were anomalous and as 7 I said, the 1994 results are still not validates.

The 8 SER basically concludes that you can't rely on the '94 9 results either. As I say, if you could rely on the 10 '94 results, the conclusion would be the corrosion was 11 ongoing. So we really don't have any spatial tracking 12 here of what corrosion is doing in the sand bed 13 region. We might get some in October but at the moment 14 the proposal as I'll show you later is very limited.15 I'm trying to stick right now to what we know about 16 this thing right now. Is within safety margins right 17 now?18 So let's look at the margins that were 19 established in 1992. Now remember this is 14 years 20 ago. So we have serious concerns that you can't draw 21 conclusions about the current situation based on these 22 results. I mean it's been 14 years and we know that 23 in 14 years at least over some periods of time water 24 has been coming down this component.

Again it's 25 something that we recently found out.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 So the single point margin was over 2 estimated at 0.11 inches by the operator.

Reanalyzing 3 using extreme value statistics, the margin has been 4 estimated by Dr. Hausler and this is based on '02 data 5 which is a limited dataset. So I'm not touting this 6 as the be-all and end-all of analysis.

I'm just 7 touting this as a starting point where we need to go 8 and again you see that it comes to around 0.26 inches 9 significantly less than had been estimated by the 10 Applicant.

11 The small areas margin was estimated at 12 0.07 inches by the operator.

Again, the problem with 13 that is that he didn't look at the area below 0.736.14 That area is very sensitive to corrosion because the 15 slope between the thin area and the thick area is 16 relatively small and so a small amount of corrosion at 17 the edge can cause a considerable expansion in the 18 area. So based on an assumption of linearity and the 19 transition between the thin area and the thick area, 20 Dr. Hausler comes up with a margin of around 0.03 21 inches.22 MEMBER WALLIS: What is the transition 23 like between the thin and the thick area?24 MR. WEBSTER: Well, we don't have that 25 much information.

I've seen a few very fuzzy photos 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 that look sort of like moon shot photos and they seem 2 to be sort of round, sort of like soup bowls they look 3 like on the photo, but maybe the Applicant can 4 elucidate on that a little more.5 MR. ABDEL-KHALIK:

What does this number 6 pertain to, 0.07 or 0.03? Is this the margin?7 MR. WEBSTER: This is the margin between In other words, this is an estimate of the amount of 9 corrosion that would be needed to push the component 10 beyond the code based on the current acceptance 11 criteria which remember we don't think are actually 12 correct. But they are the only criteria we have so we 13 might as well use them just to scope out the problem 14 and again I alluded to this before. The inadequate 15 spatial scope, basically the curbs on the inside of --16 MEMBER WALLIS: The basis of these claims 17 he hasn't done a buckling analysis.18 MR. WEBSTER: No, what he's doing is he's 19 looking at -- He's taking the buckling analysis that 20 GE did and he's looking at the criteria that they 21 generated.

22 MEMBER WALLIS: Uncertainties or something 23 and the statistics and all that stuff.24 MR. WEBSTER: The statistics, he's looking 25 at the measurements that Amergan have produced or at NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com

.o 208 1 least the ones that they've released to us and is then 2 running them through.3 MEMBER WALLIS: But their analysis was 4 correct.5 MR. WEBSTER: No. He's taking their raw 6 results and then rerunning the statistics.

7 MEMBER WALLIS: But he's assuming that 8 they're mechanistic.

Their stress analysis was 9 correct.10 MR. WEBSTER: Yes. I mean we don't think 11 all of it is correct. We dispute. In fact, we think 12 it is incorrect nonetheless because it fails to take 13 into account some important phenomena.

But 14 nonetheless in the absence of any other, unlike the 15 Applicant, we don't really have the funding to 16 commission Sandia Labs to do a large study for us. So 17 unlike the Applicant, we're just going to start with 18 looking at what they have said would meet the safety 19 requirements and then see how close they are and 20 they're very close, very, very close. Although let's 21 put it this way. They were very close in 1992. We 22 don't know where they are now.23 Remember each result has an uncertainty 24 around 0.03. So you can see it's very hard to design 25 a program and this is why we say it's the cart before NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 209 1 the horse because it's very hard to design a program 2 to measure thicknesses to this kind of tolerance going 3 forward. If you don't know that you need to do that, 4 then it's very hard to know whether the program is 5 acceptable and that's why we really can't understand 6 at the moment how NRC staff are drawing their 7 conclusions about the acceptability of the program in 8 terms of aging management.

9 Let me go over this. Basically, we've had 10 consulting from stress engineers.

What they've said 11 is and I think what's coming out of this Sandia study 12 which is that there isn't enough UT data to really do 13 a good model on what's going on in this sand bed 14 region. What they've said to us is it's routine these 15 days in the oil industry to do a comprehensive scan of 16 the whole vessel. When you get to close to margin, you 17 do a comprehensive scan of the whole vessel, have 18 thickness measurements for the whole vessel, measure 19 the shape of the vessel and then actually use the 20 finite element model as you were suggesting over here, 21 actually put the numbers that you measure into the 22 finite element model and then actually model the real 23 situation and then you can start to look at margin by 24 changing the amount, the thicknesses, of various areas 25 where you suspect or you have some concerns that NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 210 1 corrosion could occur and you see whether or how 2 robust the vessel is. When you get close to this 3 degree of margin, we fail to understand why do the 4 most accurate techniques should not be used.5 So here is the famous table. This is what 6 I call the simplistic treatment of acceptance.

You 7 take all these results, you actually throw a few away 8 in the statistical analysis because they don't meet 9 normal statistics, you sort of fudge it around a 10 little bit and then you compare what you label the 11 current thinnest is, but actually isn't the current 12 thinnest at all. It's some sort of average of thick 13 and thin over a quarter of a square foot area and you 14 compare it with a uniform criteria when the service is 15 not uniform. This is absolutely not acceptable as a 16 way to look at acceptance and this is what they're 17 still doing.18 Let me hasten to add this was taken from 19 an old document, but this is still the process that 20 the Applicant is using. So --21 MEMBER WALLIS: Does this chart go back to 22 GPU?23 MR. WEBSTER: It does but it's the same 24 numbers that are in Table 1 of the response that has 25 been so much debated.NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 211 1 MEMBER ARMIJO: Actually they're 2 different, but not all that different.

3 MR. WEBSTER: They're similar. They're 4 similar in the common sense of the word. So in 5 summary, we don't know what the current margins are.6 In fact, we don't even know if there are current 7 margins. The acceptance criteria has not been 8 updated. We know now that water has been draining 9 from the sand bed at some time over the last eight 10 years. Of course, we don't know when because the 11 Applicant didn't actually do his monitoring as 12 required and we don't actually know where the water 13 came from because the Applicant threw it away before 14 they got the chance to sample it and there is some 15 suspicion that the water could be coming up from 16 below.17 MEMBER ARMIJO: I'd like to hear more why 18 you think that's possible.19 MR. WEBSTER: Well, we don't have a lot of 20 data on that. I'm throwing that out as a possibility.

21 I'm really throwing it out to be refuted by the 22 Applicant.

What we know is that the groundwater at 23 this site is high, that this is at the bottom of the 24 site, but I don't have a good view of what the 25 relative elevations are between the wet areas and the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com

• o 212 1 non-wet areas. I would be very interested

-- In the 2 EPRI document that the Applicant has tried to rely 3 upon but it's not a gold document, I think it's a EPRI 4 document for their argument about the embedded region, 5 it says that you should eliminate groundwater as a 6 source of water and the Applicant actually hasn't done 7 that. So if they're attempting to rely upon that 8 document, they should at least do what it says in that 9 document.10 MR. ABDEL-KHALIK:

But the elevation at 11 that point is 8'11" or so.12 MR. WEBSTER: Of the embedded region.13 MR. ABDEL-KHALIK:

Right.14 MR. WEBSTER: I'm not quite sure what the 15 relative dating is on that. Is that --16 MR. ABDEL-KHALIK:

Wouldn't that be sea 17 level?18 MR. WEBSTER: I don't know. I mean I 19 don't know. I'm throwing that out as a possibility to 20 be refuted.21 CHAIR MAYNARD: I think your point is that 22 you don't have evidence that it is groundwater, but 23 you haven't seen any analysis or enough information to 24 rule it out.25 MR. WEBSTER: That's right. We're saying NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 213 1 it's a cause that they should rule out. It's sort of 2 illustrative that a root cause analysis is woefully 3 inadequate or at least somebody should have looked at 4 those elevations and figured it out.5 Visual monitoring of the epoxy coat, again 6 this is according to our expert the epoxy coat visual 7 inspection is really not sufficient.

He says that 8 visual examination needs to be augmented by more 9 quantitative assessment.

Holidays and pinholes in the 10 coatings cannot be addressed by visual examination.

11 The coatings industry have developed methodology which 12 can more accurately establish the integrity of 13 coatings and he actually references four methodologies 14 that are designed to analyze the integrity of 15 coatings.16 Of particular important is integrity of 17 the putty. This is the seal in the embedded region.18 Water leakage in the crevice will further stimulate 19 corrosion below the sand bed and floor. We think the 20 coating should be inspected quarterly while wet 21 conditions prevail and at the onset of moisture being 22 detected.23 Now I was astonished today to hear that 24 half of the bays haven't been inspected at all. When 25 GPU Nuclear applied that coating they estimated its NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 214 1 useful life was ten years. We're now 14 years later.2 So what that means is we're four years beyond the 3 estimated life and half the bays are not being 4 inspected at all. We've heard that the corrosion is 5 quite heterogeneous, that what happens in one way 6 doesn't tell you what's happening in another bay. So 7 if that's the case I don't see any justification at 8 all for the failure to monitor five bays to date.9 And so finally -- Oh yes. The UT measured 10 area was not adapted to thin areas at the edges. So 11 in other words, when they did their 6"x6" area if the 12 areas at the edges were thinner than 0.736 they didn't 13 then expand the area and keep going to define the area 14 that was thinner than 0.736. They just stopped there.15 And as we know, they didn't measure known 16 areas that are thinner than 0.736. That scatter plot 17 that I think, Dr. Wallis, you were looking at from the 18 1992, I should have put that on my slides, assessment 19 shows a scatter of thin areas all over the shell and 20 there was no effort to measure the area of those thin 21 areas. The only measurement was the thinnest spot on 22 those areas which I think was -- I mean I don't know 23 exactly the temporal sequence but certainly once the 24 GE modeling was available for those small areas, I 25 think it behooved someone in either the NRC or the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 215 1 operator to go out and measure those areas because 2 those could be absolutely critical.3 My clients are amazed here of the 4 oversight situation of this reactor. We have a 5 situation and we really have no idea right now what 6 the situation is, what the margins are and whether 7 they're meeting the code or not. As far as my client 8 is concerned, that's really not remotely acceptable.

9 So single UT measurement uncertainty is 10 very close to the margin. So the operation fails to 11 fully account for uncertainty and finally, there is 12 insufficient data therefore to calculate the area 13 below 0.736.14 So that's what we don't know about the 15 current situation really. So given what we don't know 16 about the current situation it's pretty hard to 17 predict what we're going to be able to do in the 18 future. At best we can say that the predictions of 19 the future are highly uncertain and that to determine 20 the appropriate monitoring in terms of spatial scope 21 and the required accuracy, we need to know the current 22 margin to a high degree of certainty and the only way 23 we're going to know is that we're going to use the 24 most accurate techniques as proposed by Stress 25 Consulting.

NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 wwwnealrgross.com 216 1 And to determine the monitoring frequency 2 we need to look in a very systematic way at corrosion 3 conditions.

Let me come through these in more detail.4 We need to estimate the worst case corrosion rate 5 which we had some questions about before. We're using 6 a very high corrosion rate. I probably don't think 7 that's realistic.

8 MEMBER WALLIS: This is your 0.33 inches 9 per year.10 MR. WEBSTER: Right. I don't think that's 11 realistic but I don't think there's any other number 12 out there. So you want to take the biggest one and 13 again it's a question of should this be a process of 14 elimination as far as we're concerned.

Let's start 15 with the worst case assumption and work our way in;16 whereas the Applicant has done absolutely the 17 opposite.

They've started with the best case 18 assumption, zero corrosion, and said can we show zero 19 corrosion is okay. They're struggling to show that.20 So the proposed program is inadequate.

21 What they proposes for the next outage is that they 22 will measure or at least what they proposed in writing 23 in their June 2 0th commitment is that they will 24 measure the areas from the inside that they measured 25 before. So it will twelve 6"X6" areas in the top area NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 217 1 of the drywell, of the sand bed region of the drywell, 2 totally inadequate to even compare to the current 3 acceptance criteria.4 The statistical techniques as I said 5 before using the data analysis are completely flawed 6 and I will go into more detail on that. The coating 7 integrity as I said hasn't been adequately maintained.

8 There are tests out there. They should be done both 9 immediately after it's applied. I was again 10 interested to hear that again one reason that there 11 wasn't an aging problem was because it was an 12 installment problem. For this coating, I mean we 13 don't know whether it was an aging problem or an 14 installation problem because they didn't properly 15 measure it after they installed it and they haven't 16 measured it since. So I don't know how splitting the 17 hairs about which kind of problem it is doesn't mean 18 it's not a problem. The fact is they haven't looked, 19 they haven't made sure this installation was done 20 properly and they haven't looked systematically at 21 whether it continues to be functional.

In fact they 22 haven't looked at all in half the bays about whether 23 it continues to be functional.

24 And then finally, the initial UT 25 monitoring proves it every four years. I don't know NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com v

218 1 how anybody came up with four years. I mean if you're 2 going to have any kind of corrosion rate I don't 3 understand how you can calculate four years. The idea 4 that the upper region bounds the corrosion rate is 5 completely wrong. The temperatures are much higher in 6 the upper region. That means that it's less likely to 7 be wet or at least the moisture will evaporate more 8 quickly and then there's this firebard D stuff in the 9 upper region which isn't present in the sand bed 10 region. So I don't think the results in the upper 11 region, they are always much smaller in the sand bed 12 region, the corrosion rate there. So it's a datapoint 13 out there, but it certainly doesn't bound the sand bed 14 region in any way at all. And I'm amazed that that 15 would even be put forth as an idea. It doesn't seem 16 to make sense to me.17 So finally, we must build in fail-safe 18 checks. What we've seen from the Applicant's failure 19 to meet its commitments is that when you just rely on 20 one commitment for safety if they miss on that 21 commitment, you have a safety problem or you 22 potentially have a safety problem at least. We 23 strongly believe that there have to be fail-safe 24 checks, multiple systems in place, to make sure that 25 if we have a margin on this drywell that it's NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 219 1 maintained.

2 Okay. I think X'I1 skip over that one.3 Statistical techniques, there was some interest in 4 that. The first problem is that the potential for 5 future corrosion is not estimated when no corrosion is 6 measured.

It's just an assumption that we didn't see 7 any corrosion in the past. It won't happen in the 8 future. I've never seen any justification for that.9 So I'm sure now we know given the error bars that it 10 could be it's a sampling artifact that you see no 11 corrosion or it could be that the conditions could 12 change in the future. So the past conditions are not 13 indicative of future conditions necessarily.

So you 14 have to really look at the propagating error bars 15 going forward to see what's happening even when you 16 see no corrosion.

17 MEMBER WALLIS: These are two measurements 18 side by side.19 CHAIR MAYNARD: Wait. Listen to the 20 remarks here.21 MEMBER WALLIS: I'll talk to him.22 MR. WEBSTER: So secondly -- Do you want 23 me to continue?

Secondly there's an erroneous 24 assumption of linearity over time. In fact, it's 25 quite possible for pit corrosion to accelerate over NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 220 1 time. So this projection of linearity again no 2 justification again whatsoever for that.3 Again there's an erroneously assumption of 4 unchanged conditions.

I mean if you're monitoring 5 every ten years but the corrosion could happen in four 6 years or three years or two years, then the monitoring 7 every ten years is inadequate and at the moment, we 8 think it's possible that the corrosion could happen 9 very quickly especially in the crevice corrosion of 10 the embedded region. And there is just absolutely no 11 data out there on it. So we think you have to be 12 conservative.

Once every ten years doesn't seem very 13 conservative to us.14 This 95 percent confidence interval, this 15 is again another mystery. I mean this means that 16 basically there's a potential violation of the safety 17 margin one and 20 times for this kind of confidence 18 interval.

Now we've seen no analysis of how that 19 projects forward into a safety calculation and I think 20 if you're going to accept that kind of low bound of 21 certainty for a safety significant component, you 22 really have to show rigorously that it doesn't 23 translate into some kind of safety problem and that 24 just simply hasn't been done. As far as we can tell, 25 somebody got their statistics textbook out, saw 95 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 221 1 percent as a standard interval and just started 2 messing around with that.3 Confirming that view, somebody tried to 4 use normal statistics.

The problem with normal 5 statistics of course is it's generally two-sided and 6 there are various assumptions built in. Here you 7 really need a one-sided distribution and our expert 8 has recommended a couple of distributions that might 9 be more appropriate.

The fact that the normal 10 distribution is not appropriate was really found by 11 the Applicant.

They kept analyzing the results and 12 checking that the normal distribution was right and 13 finding it wasn't. So their response instead of 14 saying we go the wrong distribution here was to 15 discard data and to divide the data into different 16 subsets in a desperate attempt to fit the data back to 17 a normal distribution.

When any reasonable 18 statistical view would have been this distribution is 19 not working. Let's change distributions.

You really 20 can't -- You have to really see what the data is 21 telling you and just cherry-picking the data to fit 22 into a distribution doesn't seem as of our expert to 23 be a very rigorous scientific approach.24 They failed to look systematically

-- Yes, 25 I mentioned the data filtering.

I want to emphasize NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 222 1 that again. In certain cases, we see data being 2 discarded, pits being taken out because they don't fit 3 normal. In fact our expert is saying that's precisely 4 what you expect to see when corrosion is happening.

5 Certain pits go very deep and they are way beyond 6 three standard deviations.

But those pits are 7 precisely the ones you have to worry about most not 8 the ones you should throw away when you're doing your 9 data analysis.10 MEMBER WALLIS: These are pits in the 11 shell.12 MR. WEBSTER: Yes, they are pits in the 13 shell. Yes.14 MEMBER WALLIS: Not pits in the --15 MR. WEBSTER: No, they are pits in the 16 shell.17 So they fail to look systematically at 18 uncertainties in the measurements.

When you see an 19 estimate about the square footage of area below 0.736, 20 you really have to ask yourself what is the 21 uncertainty.

Given the uncertainty on each individual 22 measurement, the uncertainty on that is very likely to 23 be high and we think that the modeling needs to 24 reflect that worst case assumptions, i.e., what could 25 be the case right now. We really think on a modeling NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 223 1 study what you need to do is to look at what could be 2 the case right now given the variation, given the 3 uncertainty in the results and then what could be the 4 case in the future given the time intervals and the 5 potential corrosion rate. So far, nothing like that 6 has been done.7 And again, we keep coming back to this.8 We were been unable to estimate a corrosion rate right 9 now because we really have one datapoint in the sand 10 bed region since the sand was removed. That's in 1992 11 It's very hard to get a rate out of one point. And 12 the problem -- Well, when next results we'll have two 13 points, but the problem is because there's been no 14 monitoring conditions during the time that the two 15 points have been occurring we really have no idea how 16 the conditions will translate into a corrosion rate.17 And we would like to see a corrosion rate under wet 18 conditions, a corrosion rate under coating failure 19 conditions and so forth. We just don't have the data 20 to even approach thinking about that kind of approach.21 So here we are. This is an emphasis on 22 maintaining coating integrity.

I think I've said 23 this. Basically, visual inspections as the Applicant 24 itself has admitted today misses a lot of details.25 It's quite possible for pinholes and holidays to NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 224 1 occur. Water gets in behind those. You get corrosion 2 happening behind those and actually then the coat can 3 mask that corrosion is occurring.

4 And again because it's so close to margin 5 you don't need a whole lot of corrosion to get to be 6 on the margin. So we believe that visual inspection 7 must be augmented by the industry standard objective 8 measurements.

We believe that when wet conditions 9 prevail the monitoring frequency must increase to at 10 least quarterly until more certainty prevails.

And we 11 believe that a response to coating failure must be a 12 complete renewal of the coating and comprehensive UT 13 measurements within a quarter.14 At the moment, they're proposing if they 15 see a small area of coating degradation they will 16 basically fix that area, but not fix the other areas 17 and it seems to us that once the coating starts to go 18 that's indicative of the whole coating needs to be 19 renewed.20 MEMBER SHACK: Just the statement was made 21 that the ASTM standard calls for visual examination.

22 What industry standard are you referring to?23 MR. WEBSTER: Let me just check for you.24 National Association of Corrosion Engineers 25 International Standard Test Method TM00384, Holiday NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 225 1 Detection of Internal Tubular Coatings of 2.5 2 micrometers film thickness.

Again, National 3 Association of Corrosion Engineers Standard No. --4 MEMBER SHACK: What was that standard 5 number again?6 MR. WEBSTER: TM00384.7 MEMBER WALLIS: Could you explain what a 8 holiday is?9 MR. WEBSTER: A holiday, I don't think 10 it's used in the English sense. I think it's a small 11 hole. It's a place where the coating didn't apply in 12 other words. I think it's a place here the coating, 13 when you are brushing the coating on or however you're 14 applying it, you missed a spot. The brush sort of 15 took a holiday.16 MEMBER WALLIS: It didn't stick.17 MR. WEBSTER: It didn't stick. Your brush 18 was on holiday for that particular spot.19 I can give you these codes later. They're 20 all in Dr. Hausler's

--21 CHAIR MAYNARD: If you could give him 22 those codes later. I am giving you extra time.23 MR. WEBSTER: Yes.24 CHAIR MAYNARD: We do need to move along.25 MR. WEBSTER: Let me wrap up then. So the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com

• ° 226 1 monitoring for water, at the moment as we said, as 2 Amergan said, you know they promise they're going to 3 look at these drains in the future although they 4 didn't the past and what we're saying is you know 5 there are electronic water detection systems out 6 there. They would give you a lot more detail about 7 where the water is, when it starts to happen and for 8 how long it happens. You actually end up with an 9 objective measure. You end up with a log and you get 10 just a lot more information out of this. Again I 11 don't quite understand why this hasn't already been 12 proposed.

When you're this close to margin and with 13 a component of this significance, it seems to us that 14 you should do the best you can not just try and get 15 away with the least and I'll let you slide by me.16 Monitoring frequency basically at the 17 moment, it's really very hard to know what the 18 monitoring frequency would be appropriate because the 19 safety margins are not established and the worst case 20 corrosion rates are not known. So as I said we 21 advocate conservative assumptions.

And again we 22 strongly believe that we must have fail-safe 23 intervals.

We must have fail-safe systems all around 24 because we cannot just rely on this Applicant meeting 25 all of its commitments all the time.NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 227 1 Finally, and importantly, Dr. Hausler 2 raised another possible failure mechanism, chloride 3 induced fatigue cracking and suggested that that must 4 be examined and ruled out and as far as we know, 5 nothing has become of this suggestion.

6 Oh, I should mention. This information 7 Dr. Hausler provided was provided directly to the NRC.8 It wasn't provided as part of the litigation.

So this 9 is -- Actually, strike that. I think that's 10 incorrect.

That was provided as part of litigation.

11 MEMBER ARMIJO: Do you have any 12 literature, documents, that cite chloride stress 13 corrosion cracking in carbon steels?14 MR. WEBSTER: I haven't seen any. I will 15 certainly ask Dr. Hausler that question if you would 16 like me to.17 MEMBER SIEBER: What's the pathway for the 18 introduction of chlorides?

Where does it come from?19 MR. WEBSTER: I'm not sure at this point.20 I can again check for you. So the Chairman will be 21 pleased to see that this slide is labeled conclusions.

22 MEMBER WALLIS: You keep referring to 23 Hausler's report. Has this been given to the NRC?24 MR. WEBSTER: These have all been filed 25 with the Atomic Safety and Licensing Board.NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com W

228 1 MEMBER WALLIS: Has NRC seen this work 2 yet?3 MR. WEBSTER: I believe they have.4 MEMBER WALLIS: They have. Okay.5 CHAIR MAYNARD: It was filed as part of 6 litigation.

7 MR. WEBSTER: Some of the memos have been 8 filed as litigation and some of the memos because we 9 were actually prevented from raising the issue of 10 embedded corrosion in the litigation we've actually 11 filed these separately to the staff just in order to 12 help their review.13 MR. GUNTER: I just wanted to say that I 14 apologize but we did provide all of Hausler's memos 15 last week. So I don't know if you've actually had a 16 chance to review those materials yet. But the ACRS 17 does have them.18 MEMBER WALLIS: No, absolutely not.19 MEMBER SIEBER: Filled up a section of my 20 hard drive.21 MEMBER WALLIS: We have a lot of other 22 things going on too.23 MR. WEBSTER: I'm sure you do. My hard 24 drive has been filling up too. So in summary at the 25 moment we don't have a current reasonable assurance of NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 229 1 safety. I think that's hard to dispute. We know that 2 the proposed monitoring program is inadequate.

There 3 are more measurements scheduled this month and if they 4 were comprehensive they could answer many of the 5 questions that have been raised here. The problems is 6 at the moment they're not comprehensive.

7 At best the conclusions about future 8 safety of the shell and the SER and the inspection 9 port are premature.

I mean at a minimum we have to 10 wait for these results, but the problem with the 11 results is that because they're not comprehensive, 12 they really won't solve most of these problems.

So 13 what we need to do here, what's happening really in 14 this problem, when you look at it from stance of 15 what's really happened is that a whole bunch of 16 assumptions have accumulated over time, sort of 17 cluttered up the thinking on this program over time.18 People kept going back and saying the NRC accepted 19 this before so it must be okay and then tried to use 20 what has been accepted before as a guide to what will 21 be done in the future.22 And the reality is we have serious 23 questions about what was acceptable before should have 24 been accepted before. What we know is it's certainly 25 unacceptable going forward. Until we get a rigorous NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 230 1 quantitative analysis based on comprehensive data and 2 careful consideration on certainly, we strongly 3 believe we encourage the ACRS to wait on this 4 application until you really see and are really 5 satisfied that this problem has been addressed in a 6 very rigorous manner. I think any careful analysis of 7 the data will show you right now that the analysis 8 that's been done is far from rigorous, is far from 9 adequate and we end up in a situation now where 10 elected officials have written to the NRC last week 11 asking how the NRC can conclude that this reactor has 12 a reasonable assurance of safety and that's all I have 13 to say. Thank you very much for your time.14 CHAIR MAYNARD: I really appreciate your 15 comments and the ACRS I assure you has not come to 16 conclusions on this. I think you can tell from our 17 questions and we will be using your comments and 18 information that you've provided here. We'll be 19 factoring that into our future evaluation, 20 deliberation, of this particular license renewal 21 application and take that in conjunction with other 22 information that we have and I'll assure you that the 23 ACRS will not make a decision or recommendation until 24 we have answers to the significant questions that we 25 still have outstanding too. I appreciate your NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com 231 1 comments there.2 MR. WEBSTER: Thank you very much.3 MEMBER BONACA: I have a question that I 4 would like to ask.5 CHAIR MAYNARD: Okay.6 MEMBER BONACA: It has to do with do you 7 know specific techniques that could be suggested to do 8 the direct measurements of the embedded thickness, 9 metal thickness?

10 MR. WEBSTER: The short answer is no. I 11 mean it seems that there are some research reports out 12 there that the NRC has cited and the other approaches 13 that chip out the concrete and get down there. Beyond 14 that there's nothing really. There's no magic bullet 15 out there as far as we know.16 CHAIR MAYNARD: What I would like to 17 recommend to the subcommittee here if I could have 18 your attention here. It is getting late. I believe 19 that we still have a number of questions, a number of 20 unanswered questions.

I'm not sure that it would do 21 any good to bring the licensee back up here and the 22 staff and reask a lot of the same questions.

I think 23 we need to take a look.24 I would recommend that tonight we give 25 this some thought. We have an open meeting session NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com

• ° 232 1 tomorrow of subcommittee time and I think at that time 2 we can discuss what we believe our next step should 3 be. There are several options available, another 4 meeting, request additional information, define what 5 needs to be provided or whatever but unless somebody 6 objects to that I would recommend we give it some 7 thought overnight and discuss it in open meeting 8 tomorrow under subcommittee report as to what our next 9 step is.10 I believe I'm safe in saying that we all 11 still have a number of questions that we don't have 12 answers to yet. Right?13 MEMBER BONACA: I do.14 CHAIR MAYNARD: Okay. With no objections, 15 that's it.16 MEMBER WALLIS: That's the end. No more 17 presentations.

18 CHAIR MAYNARD: We have no more 19 presentations and we're out of time. So with that, I 20 would like to express my appreciation to all the 21 presenters and everybody that participated and I 22 appreciate your patience and we will conclude this 23 meeting. The meeting is adjourned.

Off the record.24 (Whereupon, at 6:11 p.m., the above-25 entitled matter was concluded.)

NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com CERTIFICATE This is to certify that the attached proceedings before the United States Nuclear Regulatory Commission in the matter of: Name of Proceeding:

Advisory Committee on Reactor Safeguards Plant License Renewal Subcommittee Docket Number: n/a Location:

Rockville, MD were held as herein appears, and that this is the original transcript thereof for the file of the United States Nuclear Regulatory Commission taken by me and, thereafter reduced to typewriting by me or under the direction of the court reporting company, and that the transcript is a true and accurate record of the foregoing proceedings.

ChalesMorison Official Reporter Neal R. Gross & Co., Inc.NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com v

From: Bill Hering <bill.hering@smelectric.com>

To: "'cxs3@nrc.gov'" <cxs3@nrc.gov>

Date: 10/03/2006 11:09:36 AM

Subject:

OYSTER CREEK Gentlemen, Thank's for the opportunity to comment on the Oyster Creek license application regarding the meeting in Rockville this afternoon.

My history with Oystercreek goes back many years, and briefly, my background is 40 years active in the IBEW construction trades -Current today LU 164 Jersey City -and I am a professional Occupational Safety & Health Trainer with the US Department of Labor both Mine Safety and Health Administration and OSHA -Past President of the American Society of Safety Engineers New Jersey Chapter 1999 / 2000, and I was the Project Manager 15 years ago when we built the Nuclear Simulator at Oyster Creek, and the Safety Manager overseeing the Homeland Security upgrade with the electrical contractor, two years ago, at the Oyster Creek facility.My Comments are first 100% in favor of License Renewal, based on every single thing I had the opportunity to see and be part of with this facility.Yes, it's the oldest facility, but gentlemen, the safety record based on industry standards is impeccable.

For that matter, the Nuclear Industry has had a fabulous record in the entire country, thanks to the oversight by the NRC and committee's as your's.If the various components of this plant are meeting these industry standards and with new technology constantly at our doorstep to enhance these safety benchmarks, we need to have a common sense approach to these re-newals for this industry.

Various opponents to this application and other plants operations seem to have a mission which is either to far right or to far left... I'll leave that to your judgment.. .in short this plant is a safe reliable source of 650 megawatts of clean electrical energy that is in dire demand in our state.The license process by statue is 20 years -HOWEVER -I believe that perhaps in 5 years or so, a new type reactor will be finalized and hopefully replace older reactors on all Nuclear sites in the future in our great nation.Another very interesting point is that recent polls concerning the license renewal of Oyster Creek have shown independently over 80 % of those from 5 miles, 10 miles and the State as a whole have registered IN FAVOR of the plants license renewal.As far as homeland security, this plant has the latest in technology as I witnessed it being built and certified.

The spent fuel is on site either way, so again -common sense -let's keep the plant running as the spent fuel will be there anyway for some time until all the bug's are cleared with YUCCA Mountain and security will need to remain in tact.I think I've said enough. Gentlemen, PLEASE TAKE ALL THESE POINTS INTO CONSIDERATION AND UNDERSTAND THAT THE NEGATIVE COMMENTS SEEM TO ONLY REPRESENT A SMALL MINORITY OF OUR POPULATION, WE NEED NOT ONLY RELICENSE EXISTING, BUT BUILD MORE NUCLEAR Facilities ASAP AS THE NEED FOR CLEAN ENERGY IS RISING RAPIDLY Nuclear Power is a super high priority in this unstable energy market world.Give this plant a chance to continue to be a viable producer in this essential energy market and the electrical grid in general.Thank's again for your accepting my comments, William E. Hering 1005 Peaksail Point Lanoka Harbor, NJ 08734 609 971 0930 CC: "'laceyclerk@comcast.net'" <laceyclerk@comcast.net>

AmerGensm An Exelon Company Oyster Creek License Renewal Presentation to ACRS Subcommittee October 03, 2006 3 AmerGens An Exelon Company AmerGen Representatives

• Michael Gallagher, Vice President, License Renewal Projects* Timothy Rausch, Vice President, Creek Oyster* Fred Polaski, L* Tom Quintenz, icense Renewal Manager Site Lead License Renewal Engineer* John Hufnagel, Licensing Lead 2 I, 3 3 AmerGen, An Exelon Company Agenda* Description of Oyster Creek* Current Plant Status* Operating History* Drywell Corrosion* NRC Open Items* License Renewal Methodology

& Results* Commitment Management" Status of Program Implementation

• Summary 3_3)I, AmerGen,.An Exelon Company Description of Oyster Creek e Located in Lacey Township, Ocean County, NJ 9 Barnegat Bay is Ultimate Heat Sink" GE BWR 2 with Mark I Containment

• Interim Spent Fuel Storage established onsite" Overall CDF-Internal events: 1.1 E-05/year-LERF: 5.8E-07/year 4 J 9 J AmerGen S An Exelon Company 5 0 AmerGen M An Exelon Company Current Plant Status e Operating in 20th cycle* Transitioned to 24 month cycles in 1991 coast* Currently operating in down end-of-cycle

• Regulatory Oversight Program (ROP) status 6 j I, j AmerGen, M An Exelon Company Operating History" Full (Original)

Design Power Level -1930 MWth" Commercial Operation-April 1969 Provisional Operating License (POL) issued-Aug 1969 Authorized to 1600 MWth-Dec 1970 Authorized to 1690 MWth" Current Licensed Thermal Power 1930 MWth-Authorized in November 1971-No power uprates performed or planned-Design electrical rating 650 MWe* Full Term Operating License-Issued July 1991-Expires April 09, 2009 7 AmerGen An Exelon Company Drywell Corrosion* Background" Initial Corrective Actions" Verification of effectiveness" Initial Aging Management Program" Enhanced Aging Management

• Conclusion 8

Background

REFUELINIlG CA \/I T)AmerGenSM An Exelon Company Ii I t-EQUIP POOL SPENT FUEL POOL-i1 HI 3"-~ -...' -.1," 'I -.: "- .'". " 9)

AmerGen.An Exelon Company Sand Bed Area Torus Downcomer 10.)

AmerGensm An Exelon Company Reactor Cavity Seal Area* .: * .BELLOWS~DRYWEL E L TR OUG H .-.. ',

DETAIL "A" TROUGH DRAIN 11 AmerGen.An Exelon Company Liner Corrosion Identified Mid 1980s" Water leakage into the sand bed region was identified during refueling outages.* The source was determined to be from the reactor cavity through the gap between the drywell and the reactor building, down to the sand bed region within the reactor building.* The sand bed drains were clogged.12) 3 J AmerGen..An Exelon Company Initial Corrosion Monitoring Activities Post Mid 1980s" Approximately 1000 UT Measurements taken to identify thinnest locations in sand bed region and upper elevations" Core samples were taken to confirm UT measurements

-Also confirmed that the mechanism is general corrosion* Random UT Inspection Plan was implemented to verify adequacy of measurement locations" Staff accepted the program in November 1, 1995 SER 13)j AmerGenSM An Exelon Company Corrective Actions Implemented Early 1990s" Containment Peak Pressure was reanalyzed to establish additional shell thickness margin* The minimum acceptable shell thickness was determined" UT measurements were taken to verify minimum thickness with margin* Water leakage source was reduced* The sand was removed from the sand bed region* The sand bed drains were cleared* The drywell shell in the sand bed region was coated 14 3 3 AmerGen.An Exelon Company Corrective Actions Determined to be Effective 1994* UT Measurements in 1992 and 1994 confirmed that the corrosion was arrested in the sand bed region* 1996 UT measurements contain uncertainties

-UT in 2006 will again confirm corrosion arrested* Visual inspections of the coating were also performed 15 AmerGen~.An Exelon Company Initial Aging Management Program Established in Early 1990s" Upper drywell UT measurements taken every other refueling outage* Visual inspections of the sand bed region drywell shell coating performed every other refueling outage 16 9)

AmerGen M Aging Management Program An Exeon Company Enhanced in 2006" Strippable coating for Reactor cavity" Monitoring for water leakage" Upper Drywell Shell UT measurements every other Refueling Outage-Leading corrosion indicator* Sand bed region Drywell Shell UT measurements before PEO, then after 4 years and then every 10 years-NRC will be notified within 48 hours2 days <br />0.286 weeks <br />0.0658 months <br /> of any deviations outside expected.

results* Sand bed region Drywell Shell coating visual inspections before PEO and 100% every 10 years 17 AmerGen m M An Exelon Company Conclusion-Drywell Corrosion" The corrective actions to mitigate drywell shell corrosion have been effective." The drywell shell corrosion was arrested in the sand bed region and continues to be very low in the upper drywell elevations." We have an effective aging management program to ensure continued safe operation.

18 D 2 )

AmerGen M An Exelon Company NRC SER Open Items* Adequacy of sample size for UTs at drywell shell plate thickness transitions

• Potential corrosion of embedded shell* Impact of corrosion on strength of drywell shell related to buckling analysis* Use of ASME III Subsection NE-3213.10 for analysis of (localized) thin shell areas* Extent of follow-up exams of coated sand bed surfaces if leakage is detected 19 D.)

AmerGen An Exelon Company Operating History" Reactor Vessel Internals-Core shroud-Core Spray spargers-Top Guide-Control Rod Drive Stub Tube* Electrical cable" Underground piping 20 3' 3 AmerGen M An Exelon Company License Renewal Methodology" LRA submitted July 22, 2005" NEI 95-10 Rev. 6 Standard Format* Prepared using NUREG 1800 (SRP) and NUREG 1801 (GALL) January 2005 draft revisions* AmerGen prepared a reconciliation document comparing the Oyster Creek LRA to NUREGs 1800 and 1801 Rev. 1.* A third AMP/AMR audit week was added to the review 21 3 D'j AmerGen, m Aging Management Programs 50 GALL programs-18 existing-14 existing requiring enhancements

-18 new (11 associated with Forked River An Exelon Company Combustion Turbines and 1 with Meteorological Tower)* 7 Plant specific programs-2 existing-2 existing requiring enhancements

-3 new (1 associated with Forked River Combustion Turbines)22 3 J 3 AmerGenSM An Exelon Company Forked River Combustion Turbines (FRCTs)* The FRCTs are 2 peaking combustion turbines, 38 MWe each, installed in 1989* Owned and operated by First Energy* Credited as the Alternate AC power supply for SBO in 1992* Covered by Maintenance Rule and Surveillance Testing Programs 23 3 AmerGen.An Exelon Company FRCTs* Demonstrated high reliability

(>99%) formed basis for initial aging management strategy* LR application credited reliability monitoring as the aging management program* After discussions with NRC, AmerGen elected to establish multiple GALL-based AMPs to manage aging of long-lived, passive components 24 3 j AmerGens.Commitment Management An Exelon Company* All 65 commitments are listed in Appendix A of the application.

• A Passport commitment tracking number has been issued for license renewal commitments

• An associated action containing the details was issued for each of the commitments

• Each implementing procedure is annotated to provide linkage to and preserve the details of the commitment

• Process controlled by the commitment management procedure 25) 3 I)

AmerGen, M An Exelon Company Status of Program Implementation

• 257 new and 111 enhanced implementation activities identified

-13% in 2006 refueling outage scope-19% in 2008 refueling outage scope-68% to be performed on-line 26 3)3 AmerGen, m Summary An Exelon Company* Aging Management Programs are established to ensure safe operation for period of extended operation* License renewal commitments are tracked and will be implemented as expected* On track for completing activities prior to entering period of extended operation 27 AmerGenSM An Exelon Company Questions?

28 I, I 4 REG&0. Advisory Committee on Reactor Safeguards (ACRS) License Renewal Subcommittee

• • • • 4' Generating Station~~~~~7- 71 Z .-- --------------VSafety Evaluation Report with Open Items October 3, 2006 Donnie J. Ashley, Project Manager Office of Nuclear Reactor Regulation

.. .) 3J I ntroduction

• UOverview" Section 2: Scoping and Screening Review" License Renewal Inspections" Section 3: Aging Management Review Results m Section 4: Time-Limited Aging Analyses (TLAAs)m Confirmatory Analysis of Drywell October 3, 2006 ACRS Subcommittee .Meeting -Oyster Creek Generating Station 2 3)3

.77 Overview-Status m LRA submitted by letter, dated July 22, 2005-LRA based on January 2005 GALL" Reconciliation document submitted* Reconciled to September 2005 GALL and SRP*NUREG1800 and 1801* SER issued August. 18, 2006* Five Open items and no Confirmatory

• 3 license conditions Items* 108 RAIs.issued, 366 audit questions* One major component had expanded level of Forked River Combustion Turbine (FRCT)detail -01 Cond October 3, 2006 ACRS Subcommittee Meeting -Oyster Creek Generating Station 3 3.3 Overview Audits and Inspections

• Scoping and Screening Methodology Audit* September 15 -19, 2005* AMP GALL Audit (started)m October 3, 2005* AMP/AMR GALL Audit* January 23, February 13, and April 19, 2006.-Regional Inspection m March 13- 17 and March 27- 31, 2006 October 3, 2006 ACRS Subcommittee Meeting -Oyster Creek Generating Station 4 3 3

'7 Section 2: Scoping and Screening Review Section 2.1 -Scoping and Screening Methodology Section 2.2 Section 2.3-Plant-Level Scoping-Mechanical Systems -Containment, Structures, and Section 2.4 Supports sr Section 2.5 -Electrical Components and.Commodity Groups October 3, 2006 ACRS Subcommittee Meeting -Oyster Creek Generating Station 5-)

Section 2: Scoping and Screening Conclusion

• Scoping and screening results included all SSCs within the scope of license renewal and subject to AMR October 3, 2006 ACRS Subcommittee Meeting -Oyster Creek Generating Station 6 J pgRE(V Renewal Inspections 6, Michael Modes Region I I S -6 TA~'t~""~'~

t-t-~rtt-%x~tVA..fl'rtr~

~

License Renewal Inspections

• Two-week onsite inspection during March 13 to March 17 and March 27 to March 31, 2006* Scheduled to support NRR reviews m Team of eight inspectors m Inspection performed in accordance, with NRC Inspection Procedure 71002 October 3, 2006 ACRS Subcommittee Meeting -Oyster Creek Generating Station 8 j j.

License Renewal Inspections U Scoping and Screening.Concentrated on non-safety systems whose U-failure could impact safety systems* Emphasized physical walk downs of the plant Conclusion

-Methodology was adequate and. consistently applied October 3, 2006*ACRS Subcommittee Meeting -Oyster Creek Generating Station 9)

License Renewal Inspections

• Aging Management

• 30 aging management programs plus 2 time-limited aging analyses* Focused on one system: Isolation Condenser* Conclusions

• Applicant implemented existing aging management programs as described in the application m Applicant provided acceptable enhancements and exceptions to the GALL report and captured them in the Oyster Creek commitment tracking system* In response to NRC identified inconsistencies, the Applicant revised the application or entered the inconsistencies into the corrective action program October 3, 2006 ACRS Subcommittee Meeting -Oyster Creek Generating Station 10 j Inspection Conclusion

• Overall, the inspection results support a conclusion that the proposed activities will reasonably manage the effects of aging in.the systems, structures, and components identified in the application.

• The documentation supporting the an auditable and retrievable form application was in October 3, 2006 ACRS Subcommittee Meeting -Oyster Creek Generating Station 11 3)3)3 4 ?Current Performance

• Licensee is in the Regulatory Response Column (Column 2) of the NRC's Action Matrix" The Licensee continues to follow the Revised Reactor Oversight Process* One cross-cutting issue in the area of human performance (personnel).

October 3, 2006 ACRS Subcommittee Meeting -Oyster Creek Generating Station 12 j 3, Performance.

Indicators Reactor Safety Eents Sstems Integrity Preparedness I Performance Indicators Ur~pJa~d 1 I: I.I IMtbL~1 unpi~j~ne'~pqwer1

~C1an~i~)

1[~X~ef~ 1 1Faff~(~)[4> '~Ut$~]IH~a~P~v~i 1 ISIsi~W~~

I 7]I R4AAa~Ie~t~

[C~o1jnQ Water L --~12~ ~ I~~q'EI~J~

F3EY$IODCM I____________

_____________

J ____________

ot8~jI~w 1 I ~W~&1 ~ -[~V~ :L j List Modified:

August 2, 2006)3)

Inspection Findings Emergency Preparednss Most Significant Inspection Findings IQf2006 z~Additional Inspection

& Assessment Information

-0 Assessment Reports/Inspection Plans: 2Q/2006 1Q02006 4 Q/2005 3 Q/2005-Cross Reference Of Assessment Reports-List of Inspection Reports List of Assessment Letters/Inspection Plans. Baseline Inspection Completion Information Lgasthlodified:

Awg-wst 2, 2006 jI~

Section 3: Aging Management Programs (AMPs)* 57 AMPs w36 existing AMPs m 21 new AMPs (includes 11 new AMPs for. the FRCT)m GALL Consistency m 12 Consistent with GALL Report* 38 Consistent with GALL exceptions/enhancements

• 7 Plant Specific October 3, 2006 ACRS Subcommittee Meeting -Oyster Creek Generating Station 15 Section 3- Aging Management Example* Protective Coating Monitoring and Maintenance Program* Existing plant program -Consistent with GALL AMP XI.S8,"Protective Coating Monitoring and Maintenance Program"* Credited for Drywell and Torus aging management" -The inspection of 100% of the sandbed region epoxy coating before the PEO and every 10 years during the period of extended operation.

Inspections will be staggered such that at least three bays will be examined every other refueling outage." The inspection of all 20 torus bays at a frequency of every other refueling outage for the current coating system. Should the current coating system be replaced, the inspection frequency and scope will be re-evaluated.

Inspection scope will meet the requirements of ASME Section XI, Subsection IWE.October 3, 2006 ACRS Subcommittee Meeting -Oyster Creek Generating Station 16 j j Section 3 Aging Management Example.Structures Monitoring Program m Existing program credited m 17 Commitments identified

• The program includes elements of the Masonry Wall Program and the RG 1.127, Inspection of Water-Control Structures Associated With Nuclear Power Plants Program..This program also includes structures for Station Blackout system, phase bus enclosure assemblies, and fire protection Communication System structures (Met-Tower)

October 3, 2006 ACRS Subcommittee Meeting -17 Oyster Creek Generating Station j j Section 3- Aging Management Example m Periodic Monitoring of Combustion Turbine Power Plant -Station Blackout -FRCT* 10 Commitments to implement the Aging Management programs.October 3, 2006 ACRS Subcommittee Meeting -Oyster Creek Generating Station 18 3)3 j U U U U U U V Section 3: Aging Management Review Overview 3.1 3.2 3.3 3.4 3.5 3.6 3.7 Reactor Vessel, Internals and Coolant System 6 systems Engineered Safety Features 3 systems Auxiliary Systems 41 systems Steam and Power Conversion Systems 7 systems Containments, Structures, and Component Supports 19 structures Electrical and I&C Components 8 groups Station Blackout System (Forked River Combustion Turbines), Radio Communications System, and Meteorological Tower (Met Tower was added to scope)October 3, 2006 ACRS Subcommittee Meeting -Oyster Creek Generating Station 19 3 3 Aging Management-Drywell Shell* Three Aging Management Programs* ASME Section Xl, Subsection IWE* Protective Coating Monitoring and Maintenance Program* 10 CFR 50 Appendix J Programs n UT of sand-pocket region performed in 1992 and 1994 determined that corrosion rates had been arrested.* Water leakage monitoring program (each refueling) m refueling seal* drywell air gap drains n sand pocket drains n 11 Commitments for Drywell Corn jIS October 3, 2006 ACRS Subcommittee Meeting -Oyster Creek Generating Station 20.1)

('4 U 3ection 3-Aging Management of In-Scope I naccessible Concrete Acceptance Criteria OCGS pH >5.5 5.6 -6.4*Chlorides

<500 ppm 3-138 Sulfates <1500 ppm 7 -73 I* Below-grade environment is for fresh water pump-house non-aggressive except* Periodic testing of ground water will be performed for Structures Monitoring Program October 3, 2006 ACRS Subcommittee Meeting -Oyster Creek Generating Station 21 3j

.' ...LL; ;U¸%, ':". T .U! , U,,, " U', L'Section 4 Time-Limited Aging Analyses (TLAA)4.1 4.2 4.3 4.4 4.5 4.6 4.7 TLAA Process Neutron Embrittlement of the RPV and Internals Metal Fatigue Environmental Qualification of Electrical Equipment Loss of Prestress in Concrete Containment Tendons (N/A)Fatigue Analysis of Primary Containment Plant Specific TLAAs* 4.7.1 Crane Load Cycle Limit* 4.7.2 Drywell Corrosion* 4.7.3 Equipment Pool/Reactor Cavity Wall Rebar Corrosion* 4.7.4 Reactor Vessel Weld Flaw Evaluations

• 4.7.5 CRD Stub Tube Flaw Analysis October 3, 2006 ACRS Subcommittee Meeting -Oyster Creek Generating Station 22 3 d: Section 4.2 Neutron Embrittlement Reactor Vessel Upper Shelf Energy. (USE) -Analysis Summary:OCGS Reactor Ves Percent USE Reduction Evaluation Result.Material Reductio'n -of Accepta..nce.-C Criterion.

Reactor Vessel" Material.Limiting Plate 29% USE drop must be Acceptable pursuant 564-03D, E, F < 29.5% to 10 CFR 54.21 (c)(1 )(ii)Limiting Weld 32% -USE drop must be Acceptable pursuant 86054B & 1248 < 39% to 10 CFR 54.21 (c)(1)(ii)

• acceptance criteria established per BWRVIP-74.

October 3, 2006 ACRS Subcommittee Meeting -Oyster Creek Generating Station 23 j ,

Section 4.2.4 Reactor Vessel Circumferential Weld Examination Relief RV Circumferential Weld Relief/ RV Axial Weld Probability of Failure Analyses RV Material TLAA Basis Acceptance OCGS Value (TF)__Criterion (TF)Limiting Circ. BWRVIP-05

<128.5 9.8 Weld Mean RTNDT Value (°F)Limiting Axial BWRVIP-05

<114 50.3 Weld Mean RTNDT Value (TF)-TLAAs for the Circ. Weld and Axial Weld Mean RTNDT values were acceptable pursuant to 10 CFR 54.21 (c)(1)(ii)

October 3, 2006 ACRS Subcommittee Meeting -Oyster Creek Generating Station 24 jI)3)

Section 4.3: Metal Fatigue" Cumulative Usage Factor is projected to be less than ASME Code limit of 1.0 for components based on a 60-year life.-Monitored by the Fatigue Monitoring Program m Staff accepted the evaluations October 3, 2006 ACRS Subcommittee Meeting -Oyster Creek Generating Station 25 33.

Section 4.4 Environmental Qualification (EQ) of Electrical Equipment-Applicant's EQ Program consistent with GALL AMP X.E1, "Environmental Qualification of Electrical Equipment"* Staff concluded the EQ Program is adequate to manage the effects of aging on the intended function of electrical components October 3, 2006 ACRS Subcommittee Meeting -Oyster Creek Generating Station-26 J J j Section 4.6 Fatigue Analysis of Primary Containment

• Staff accepted the evaluations in accordance with 10 CFR 54.21 (c)(1)(i)October 3, 2006 ACRS Subcommittee Meeting -Oyster Creek Generating Station.27-p J)

Section 4.7.5 CRD Stub Tube Flaw Analysis m Staff accepted the evaluations in accordance with 10 CFR 54.21 (c)(1)(i)October 3, 2006 ACRS Subcommittee Meeting -Oyster Creek Generating Station 28 TLAA Summary* 10 CFR 54,3 -TLAA is list adequate* 10 CFR 54.21 (c)(2) -no plant-specific exemptions October 3, 2006 ACRS Subcommittee Meeting -Oyster Creek Generating Station 29 I. 7'-,.f Section 4.7.2 Drywell Corrosion* On the basis of its review, the staff concludes that, pending resolution of Ols 4.7.2-1.1,.4.7.2-

.1.2, 4.7.2-1.3, 4.7.2-1.4, and 427.2-3, the applicant has demonstrated, that for the drywell corrosion TLAA, the effects of aging on the intended function(s) will be adequately managed for the period of extended operation.

October 3, 2006 ACRS Subcommittee Meeting -Oyster Creek Generating Station 30 j ConfirmatoryAnalysis Oyster Creek Drywell-,..- -.- ii,. : Hans Ashar NRR Sandia 3) 3 )

Conclusions n The staff has concluded that pending resolution of the open items, there is reasonable assurance that the activities authorized by the renewed license will continue to be conducted in accordance with the CLB, and that any changes made to the OCGS CLB in order to comply with 10 CFR 54.29(a) are.in accord with the Act and the Commission's regulations.

October 3, 2006 ACRS Subcommittee Meeting -Oyster Creek Generating Station 32 3 I, 3 j 5 open items: e 01 4.7.2-1.1:

Drywell Corrosion Sampling in the transition area.Question on the appropriate number of locations on the drywell for periodic ultrasonic testing* 01 4.7.2-3: Questions about the implementation of the Protective Coating Monitoring and Maintenance Program. The extent of inspections of epoxy-coated drywell surfaces e 01 4.7.2-1.2:

Drywell Corrosion Inaccessible areas embedded concrete.

the possibility of corrosion of drywell liner plates embedded in concrete between the containment floor and foundation

• 01 4.7.2-1.3:

Buckling Analysis.

the appropriateness of certain technical assumptions in AmerGen's analysis of the potential for"buckling," of the drywell shell S01 4.7.2-1.4:

Drywell Shell Thickness and the Minimum Available Thickness Margin. The use of an ASME Code provision to simulate the behavior in thinned areas Go to 3.5 Go to 4.7.2)I, j2 License Conditions." The first license condition requires the applicant to include the UFSAR supplement required by 10 CFR 54.21 (d) in the next UFSAR update, as required by 10 CFR 50.71 (e), following the issuance of the renewed license." The second license condition requires future activities identified in the UFSAR supplement to be completed prior to the period of extended operation." The third license condition requires all surveillance capsules placed in storage to be maintained for future insertion.

Any changes to storage requirements must be approved by the staff as required by 10 CFR Part 50, Appendix H.

FRCT New AMPs and Commitments Bolting Integrity Closed Cycle Cooling Water System Above Ground Steel Tanks Fuel Oil Chemistry One Time Inspection Selective Leaching of Materials Buried Piping Inspection Periodic Monitoring of FRCT -Electrical Inspection of Piping and Ducts Lubricating Oil Analysis Program Periodic Inspection B.1.12A B.1.14A B.1.21A B.1.22A B.1.24A B.1.25A B.1.26A B.1.37 B.1.38A B.1.39A B.2.5A I -1 TLAA Criteria Time-limited aging analyses, for the purposes of this part, are those licensee calculations and analyses that: (1) Involve systems, structures, and components within the scope of license renewal;(2) Consider the effects of aging;(3) Involve time-limited assumptions defined by the current operating term, for example, 40 years;(4) Were determined to be relevant by the licensee in making a safety determination; (5) Involve conclusions or provide the basis for conclusions related to the capability of the system, structure, and component to perform its intended functions, as delineated in § 54.4(b); and (6) Are contained or incorporated by reference in the CLB.3 3- -

Uý2-Z'Scoping and Screening Systems Reactor Vessel, Internals, and Reactor Coolant System (8)* Control Rods Fuel P" Nuclear Boiler Instrumentation React* Reactor Pressure Vessel React.Engineered Safety Features Systems(4)" Automatic Depressurization System Conta" Standby Gas Treatment System (SGTS)Auxiliary Systems (41)" "C" Battery Room Heating & Ventilation 4160%-Battery and MG Set Room Ventilation Chlori" Containment Inerting System Conta" Control Room HVAC Crane" Emergency Diesel Generator

& Aux Sys Emerc" Fuel Storage and Handling Equipment Harde" Hydrogen & Oxygen Monitoring System Instrui" Misc.Floor and Equipment Drain System Nitrog" Post-Accident Sampling System Proce" Radwaste Area Heat&Vent System React ,ssemblies or Head Cooling System or Recirculation System inment Spray System Switchgear Room Ventilation nation System inment Vacuum Breakers s and Hoists gency Service Water System ned Vent System ment (Control)

Air System en Supply System ss Sampling System or Building CCWater System or Water Cleanup System ce Water System.by Liquid Control System d Poison System)le Building CCW System ensate Transfer System Generator and Auxiliary System Isolation Condenser System Reactor Internals Core Spray System 480V Switchgear Room Ventilation Circulating Water System Control Rod Drive System Drywell Floor and Equipment Drains Fire Protection System Heating & Process Steam System Main Fuel Oil Storage & Transfer sys Noble Metals Monitoring System Radiation Monitoring System Reactor Building Floor and Equipment Drains Roof Drains and Overboard Discharge Shutdown Cooling System Water Treatment

& Distribution System Feedwater System Main Steam System.3 N U Reactor Building Ventilation System Sanitary Waste System Spent Fuel Pool Cooling System X .Traveling In-Core Probe System N Steam and Power Conversion Systems (7)* Condensate System" Main Condenser" Main Turbine and Auxiliary System React Servic Stand (Liqul Turbir Condi Main October 3, 2006 ACRS Subcommittee Meeting -Oyster Creek Generating Station-m-t J E Structures in Scope Structures" Primary Containment" Condensate Transfer Building" Emerg Diesel Generator Building* Fire Pumphouses Reactor Building Dilution Structure Exhaust Tunnel Heating Boiler House Miscellaneous Yard Structuf Office Building Ventilation Stack Chlorination Facility Fire Pond Dam'es Oyster Creek Substation U U U Intake Structure and Canal (Ultimate Heat Sink)New Radwaste Building Turbine Building Component Supports Commodity Group In its responses dated October 12, November 11, and December 9, 2005, and May 18 and June 7, 2006, the applicant stated that it had determined that the repeater located at the Meteorological Tower (Met Tower) is credited for communication capabilities for some 10 CFR Part 50, Appendix R, scenarios.

Therefore, the repeater and associated support equipment, including the backup gas (propane) engine generator located at the Met Tower, are now within the scope of license renewal and subject to an AMR.Electrical Systems and Electrical Commodity Group" Credit for STATION BLACKOUT EQUIPMENT" In LRA Table 2.5.1.19, the ACC combustion turbines are identified as one combustion turbine power plant unit within the scope of license renewal and subject to an AMR. As described in SER Section 2.5.5.2, in its response to RAI 2.5.1.19-1, the applicant stated that it had revised the combustion turbine power plant unit scoping and screening methodology.

Mechanical, electrical, and structural component types were itemized in detail consistent with scoping and screening methodology for other the other license renewal systems and structures.

October 3, 2006 ACRS Subcommittee Meeting -Oyster Creek Generating Station 3 I, 3 V Consistent with GALL 12 out of 57* Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless Steel (CASS) (B.1.10) -New* Flow-Accelerated Corrosion (B.1.11)* Compressed Air Monitoring (B.1.17)*] One-Time Inspection (B.1.24) -New* Selective Leaching of Materials (B.1.25) -New*] 10 CFR Part 50, Appendix J (B. 1.29)*] Masonry Wall Program (B.1.30)*] Protective Coating Monitoring and Maintenance Program (B.1.33)*] Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements (B.1.34) -New*] Inaccessible Medium-Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements (B.1.36) -New* Environmental Qualification (EQ) Program (B.3.2)*] Electrical Cable Connections

-Metallic Parts -Not Subject to 10 CFR 50.49 Environmental Qualification Requirements (B.1.40) -New October 3, 2006 ACRS Subcommittee Meeting -Oyster Creek Generating Station al' -M i J 3 J Consistent With Exceptions/Enhancements

.ASME Section Xl Inservice Inspection, Subsections IWB, IWC, and IWD (B.1.1)-Water Chemistry (B.1.2)

• Reactor Head Closure Studs (B.1.3)0 BWR Vessel ID Attachment Welds (B.1.4)

• BWR Feedwater Nozzle (6.1.5): BWR Control Rod Drive Return Line Nozzle (B.1.6)

• BWR Stress Corrosion Cracking (B.1.7)* BWR Penetrations (B.1.8) -BWR Vessel Internals (B.1.9)Bolting Integrity (B.1.12)

• Open-Cycle Cooling Water System (B.1.13)9 Closed-cycle Cooling Water System (B.1.14)

• Boraflex Rack Management Program (B.1.15), Inspection of Overhead Heavy Load and Light Load (Related to Refueling)

Handling Systems (B.1.16)" BWR Reactor Water Cleanup System (B.1.18)

• Fire Protection (B.1.19).Fire Water System (*.1.20) .Above Ground Outdoor Tanks (B13.21)* Fuel Oil Chemistry (B13.22)

• Reactor Vessel Surveillance (B.1.23).One Time Inspection (81.24) -Selective Leaching of Materials(B1.25)

• Buried Piping Inspection (B.1.26)

• Buried Piping and Tank Inspection (MetTower B1.26B)* ASME Section Xl, Subsection IWE (B.1.27) -ASME Section XI, Subsection IWF (6.1.28), Structures Monitoring Program (B.1.31) .° Inspection of Water-Control Structures (B.1.32), Electrical Cables and Connections Not Subject to E.Q. Used in Instrument Circuits (B.1.35)* Metal Fatigue of Reactor Coolant Pressure Boundary (B.3.1)" Bolting Integrity

-FRCT (B.1.12A)

-New

• Aboveground Steel Tanks -FRCT (B.1.21A)

-New , Closed-cycle Cooling Water System -FRCT (B.1.14A)

-New -Fuel Oil Chemistry

-FRCT (B.1.22A)

-New: One-Time Inspection

-FRCT (B.1.24A)

-New

• Buried Piping Inspection

-FRCT (B.1.26A)

-New o Selective Leaching of Materials

-FRCT (B.1.25A)

-New* Periodic Monitoring of Combustion Turbine -FRCT(B.1.37A)

-Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components

-FRCT (B.1.38A)

-New o Lubricating Oil Analysis Program -FRCT (B.1.39) -New* Buried Piping and Tank Inspection-Met Tower Repeater Engine Fuel Supply (B.1.26B)

-New October 3, 2006 ACRS Subcommittee Meeting -Oyster Creek Generating Station J, Plant-Specific (7 out of 57)e Periodic Testing of Containment Spray Nozzles (B.2.1)" Lubricating Oil Monitoring Activities (B.2.2)" Generator Stator Water Chemistry'Activities (B.2.3)* Periodic Inspection of Ventilation Systems (B.2.4)* Periodic Inspection Program (B.2.5) -New* Wooden Utilitv Pole Proaram (B.2.6) -New* Periodic...og...J -- -" (B.2... -New inspection Program -FROT (B.2.7) -New October 3, 2006 ACRS Subcommittee Meeting -Oyster Creek Generating Station= i 3.-_)

Drywell Commitments

• Ultrasonic Testing (UT) thickness measurements of the drywell shell in the sand bed region will be performed once prior to the PEO another four years later and then a frequency of every 10 years* Consistent with current practice, a strippable coating will be applied to the reactor cavity liner to prevent-water intrusion into the gap between the drywell shield wall and the drywell shell during periods when the reactor cavity is flooded.* The reactor cavity seal leakage trough drains and the drywell sand bed region drains will be monitored for leakage.-The sand bed region drains will be monitored daily during refueling outages.* Prior to the period of extended operation, AmerGen will perform additional visual inspections of the epoxy coating that was applied to the exterior surface of the Drywell shell in the sand bed region, such that the coated surfaces in all 10 Drywell bays will have been inspected at least once._) 3)

Drywell Commitments

• Prior to the period of extended operation, AmerGen will perform additional visual inspections of the epoxy coating that was applied to the exterior surface of the Drywell shell in the sand bed region, such that the coated surfaces in all 10 Drywell bays will have been inspected at least once.* A visual examination of the drywell shell in the drywell floor inspection access trenches will be performed to assure that the drywell shell remains intact." Conduct UT thickness measurements in the upper regions of the drywell shell every other refueling outage at the same locations as are currently measured.* During the next UT inspections to be performed on the drywell sand bed region, an attempt will be made to locate and -evaluate some of the locally thinned areas identified in the 1992 inspection from the exterior of the drywell.jD 3 Drywell Commitments

• Conduct UT thickness measurements on the 0.770 inch thick plate at the junction between the 0.770 inch thick and 1.154 inch thick plates, in the lower portion of the spherical region of the drywell shell.* Conduct UT thickness measurements in the drywell shell "knuckle" area, on the 0.640 inch thick plate above the weld to the 2.625 inch thick plate.* .When the sand bed region drywell shell coating inspection is performed, the seal at the junction between the sand bed region concrete and the embedded drywell shell will be inspected per the Protective Coatings Program.* The reactor cavity concrete trough drain will be verified to be clear from blockage once per refueling cycle.4 6- M-- -3 I_

Sandia Analysis Modeling Assumptions Model Geometry* 360 model of drywell and vent lines* Torus not modeled modi* Equipment Hatch and 10 vent lines are modeled General loads 0 Model includes gravity and dead loads* other dead loads were taken from previous GE analysis* Seismic loads included with static coefficients from FSAR Controlling Load Cases* Refueling° Design Basis Accident with Earthquake" Post Accident Flooding with Earthquake Modeling Corrosion mod2* Cylinder, upper sphere, and middle sphere assigned uniform thicknesses 0 Thickness is based on extrapolated UT measurements" Lower sphere assumed 10 regions" Each region assigned thickness based on average of UT data points 3 3 Sandia Analysis Preliminary Results* Refueling Load Combination (dead + live + seismic+ refueling loads)-All stresses within ASME Service Level B requirements

-Sandbed buckling (factor of safety of 2.00 required in ASME -284)* With no degradation

• With degradation SF=3.85 SF=2.15* Accident Load (dead + internal pressure + thermal + seismic loads)-All stresses within ASME Service Level C requirements Buckling is not controlling

• Post-Accident Load Case-All stresses within ASME Service Level D requirements

-Sandbed buckling (factor of safety of 1.67 required in ASME -284)* With no degradation" With degradation SF=3.65 SF=2.74 J)

Oyster Creek Drywell Model Elevation 107'-9"...................................

Upper Sphere L -2700 Azimuth-Middle Sphere ,-Personnel Lock&-Equipment Hatch Ventlines~/(10 at 360)(1 Ventlines End atVentline Header (Springs Attached)JVWr Bottom Sphere " (Embedded in Concrete)3 3 Oyster Creek Drywell Model -Assumed Thickness Cylinder t = 0.585" (0.604"-0.00075x25)

Knuckle, t 2.54" Upper Sphere, t = 0.676 Middle Sphere t =0.670" (0.678"-0.0003*25)

Lower Sphere & Sandbed t = see next figure Bay 3 Bay 1 Bay 19-7 Estimated Thicknesses in the Lower Sphere Ventline positions Local Bay 13, 0.618" Refueling Buckling Location 0.0.857" 0.894" 0.858" Local Bay 1, 0.705" j Oyster Creek Nuclear Generating Station License(Extension: "Dryell Shell Corrosion t I.7 ',~ -kV te J j Oyster Creek Containment Corrosion DRYWELL *..4 13~~VjkhULA t tftt ( IAV0 V h0A 1.44 rEL.'~ 23'.. _ __ __aJTA TYOs A"CIO A, TIT-L ~ fl~rol,2.I. ,s Arc..D wS l w0 2ýa w %( l Oyster Creek Containment Corrosion S5 M fOF4R OUTAGE UT

__(TAKEN FROM INSIDE DRYWELL)Vessol Thickness (inches)Drywell As Minimum Currant Previous Region Designed Required at Thinnest T"tinnest 1.1 Smc (12/92) (7/91)(inches) (inches) (inches) (Inches)Cylinder 0.640 0.580 0.614 0.612 Upper Sphere 0.722 0.650 0.691 0.695 (El. 51' to 65')Middlo Sphere 0.770 0.670 0.743 0.745 (El. 23' to 51')Sand Bed 1.154 0.736 0.800 0.803 j 1)

Identified Concerns* Possible corrosion in the embedded region-concern covers both current safety and potential for future undetected degradation

• Sandbed region-whether the drywell liner meets safety margins now; and, if so-whether any significant degradation in the future would be detected before safety margins are violated -subject of contention C C C Oyster Creek Containment Corrosion I L 9- 11I'/A*" T " i Z,- 1. ; 1, 1 WYE D R EA 1 ,-V tL EL 2, r,6 ILL. IOL~r EL 84 A T M1thjk rCr*LL VENT) -P~~&g COGS caSF'ECTiON OF: DRYWVELL TORUS 3 J Embedded Region in 1992" When sand was removed in 1992 the sand bed floor was unfinished, water had ponded on the floor, and the floor had deep craters, probably due to corrosion of rebar° Until 1992 no seal was present between the shell and the concrete to reduce penetration of water into gaps" Moisture from groundwater has not been ruled out (7 C C Corrosion Possible* Conditions in the embedded region from the early 60s through to 1992 were favorable for crevice corrosion, which could then self-accelerate" Since 1992, it has been assumed, but not verified that the elastomer seal has kept the embedded region dry* Assumption of dry conditions since 1992 not valid because seal could be leaking and water could be coming from below j Effect of Sand Removal" Removal of sand could have accelerated corrosion in the embedded region because of differential aeration, if wet conditions persisted" Corrosion rates in the sandbed region do not bound corrosion rates in the embedded region" Steel thickness in the lower embedded region was nominally 0.676 inches and corrosion rates could be up to 0.33 inches per year Necessary Actions* Comprehensively check current thickness of metal in the embedded region* Monitor for wet conditions in the embedded region using electronic detectors* If water is present, must sample and trace source* Need to establish acceptance criteria and an adequate aging. management program, need objective data where experts disagree_)

Sandbed Established Safety-based Acceptance Criteria* Most critical constraint is buckling* Uniform criterion

-0.736" wall thickness* Single point criterion than 0.49 inches-no point should be less 0 Small area criterion-one square foot per bay may be greater less than 0.736 inches, but must be than 0.536 inches e All based on modeling of 36 degree slices of shell that inherently assumed axial symmetry and spherical shape.C Problems With Established Criteria" Sandbed is far from uniform, some bays were much more corroded than others with a dimpled"golf ball" surface° Symmetry assumption prevented model simulating anti-symmetric buckling* Assumption of spherical shape not justified

-shell was welded together in situ in the 1960s, could be far from spherical* Derivation of the small area criterion was not rigorous -did not see if shapes other than a square could be more critical -e.g. horizontal gash_)

Measured Shell Thickness* Last UT measurements taken with procedures that are not in question were carried out in 1992* Results taken from both inside and outside" Smallest measured result was 0.603 inches from inside and 0.618 inches from the outside* Area that is less than 0.736 inches recently estimated at 0.68 ft. sq., but no account taken of uncertainty or failure to measure all thin areas* Each measurement is uncertain by 0.03 inches.AmerGen accepted results that showed up to 0.05 inches increase in thickness (I C C AmerGen Accepted "Anomalous" UT Measurements

• May 3, 2006, Dr. Rudolf Hausler: The AMGT (average minimal general thickness) for each grid decreases from 1992 to 1994, but then increases in 1996. "This is of course physically impossible; metal simply does not spontaneously get thicker."° Hausler, "I interpret this as a systematic error in the UT methodology employed."° June 20, 2006, AmerGen admits that 1996 UT results were anomalous. "in at least one case, the increase is as much as 50 mils in a two year period." 1994 results not validated

-were similar problems with procedures

° AmerGen relied in part on the 1994 and 1996 results to claim corrosion in sandbed was zero 3 1) j Margins Established in 1992° Single point margin overestimated at 0.11 inches by operator* Single point margin around 0.06 inches* Small areas margin estimated by Dr. Hausler at overestimated at 0.07 inches by operator e Small areas margin estimated at around 0.03 inches by Dr. Hausler based on possible expansion of area thinner than 0.736 inches (I C C',

Inadequate Spatial Scope Hausler, June 23, 2006 -Much of sandbed is inaccessible from inside:-Initial investigations before sand removed measured shell from the inside shell "at lowest accessible locations"-Interior concrete floor & curb 2 ft. higher than exterior floor leaving about 213 of sandbed region not tested.Interior floor removed in 2 bays & found similar thinning below floor level confirming area should not be omitted from UT* Both Hausler and Stress believe much more spatially comprehensive UT thickness measurements are needed to accurately represent current state of vessel j Simplistic Treatment of Acceptance

-$UMMMYO1ALQEJ4HQI A EMUTTH IE-CJ MEB- A,!R E MEN._(TAKEN FROM INSIDE DRYWELL)Vessel Thickness (inches)Drywall As Minimum Currant Previous Region Designed Required at Thinnest Ti.lnnest 1.1 Smc (12/92) (7/91)(inches) (inches) (inches) (Inches)Cylinder 0.640 0.500 0.614 0.612 Upper Sphere 0.722 0.650 0.691 0.695 (El. 51' to 65')Middle Sphere 0.770 0.670 0.743 0.745 (El. 23' to 51')Sand Bed 1.154 0.736 0.800 0.803 C Current Margins Unknown* Acceptance criteria not updated yet* Recently discovered that water has been draining from the sandbed over the last eight years" Visual monitoring of epoxy coat is inadequate to detect small pinholes, coat could mask corrosion, and coat is beyond its anticipated life* UT measured area was not adaptive to thin areas at edges, not representative, is only 3 sq. ft. out of 300 sq.ft., and misses known areas less than 0.736 inches* Single UT measurement uncertainty is very close to margins, but operator failed to fully account for uncertainty

• Insufficient data to calculate area below 0.736 inches I~ j j-d w Predictions About The Future* Present situation very poorly defined" Predictions about the future are therefore highly uncertain* To determine appropriate monitoring for the future in terms of spatial scope and required accuracy need to know current margin to a high degree of certainty

-must use most accurate techniques as proposed by Stress° To determine monitoring frequency need to adequately monitor conditions, estimate worst-case corrosion rate, and account for uncertainty C C (I Proposed UT Program Is Inadequate

• Spatial scope too small -areas of the shell less than 0.736 inches thick would not be systematically identified and tested* Statistical techniques used in data analysis are flawed,* Coating integrity not adequately maintained

• Monitoring for water is inadequate

• Initial UT monitoring frequency is too low if corrosive conditions are present* Must build in fail-safe checks Inadequate Spatial Scope Hausler, June 23, 2006: " AmerGen proposes to measure the same locations measured in 1992, 1994, 1996* Many areas below 0.736 inches are not proposed to be monitored at all" AmerGen must devise a systematic approach to identify and measure all areas thinner than 0,736 inches C C C Proposed Statistical Techniques Are Flawed* Potential for future corrosion not estimated when no corrosion measured° Erroneous assumption of linearity over time. Even under constant conditions pit corrosion can accelerate

• Erroneous assumption of unchanged conditions" Use of 95% confidence interval -no justification for the assumption that failing to detect violation of safety margins 1 in 20 times is adequate -must do analysis of safety significance" Erroneous use of normal statistics and data filtering" Failed to look systematically at uncertainties in measurements" Unable to estimate worst-case corrosion rate due to lack of data Maintaining Coating Integrity* Visual examination may miss small holidays and pinholes* Visual examination must be augmented by industry standard objective measurements

• When wet conditions prevail, monitoring frequency must increase to at least quarterly until more certainty prevails* Response to coating failure must be complete renewal of coating and comprehensive UT measurements within one quarter C C C Monitoring For Water Is Inadequate

• Recent announcement that operator failed to monitor sandbed drains for 8 years and then dumped collected water without testing dramatically illustrates problems with a purely visual approach* Now no way of knowing when the leakage occurred, exactly which areas of the shell were wet, or where the water came from* Having moisture monitored electronically provides verifiable records that show moisture variation in space and time* Detection of water must trigger comprehensive checks of coating integrity within a quarter-~ -J, UT Monitoring Frequency" Cannot decide on UT monitoring frequency until safety margins and worst case corrosion rates are known" Must make conservative assumptions, and assume other programs are missing something* Recent experience shows that we cannot rely only on committed inspections alone to drive UT monitoring.

Must have fail safe intervals.

C C Second Possible Failure Mechanism Hausler, June 23, 2006 points out: " Chloride induced fatigue cracking is possible* It will be necessary to examine both the corroded areas and susceptible areas for the existence of stress corrosion cracks in the drywell liner* Nothing yet proposed to resolve this issue Conclusions

• Not even a current reasonable assurance of safety" Know that the proposed monitoring program is inadequate" More measurements are currently scheduled this month.If they were comprehensive, many of the current safety questions could be answered" At best, conclusions about future safety of the shell in the SER and the inspection report were premature" Need to discard all the invalid assumptions that have accumulated and conduct an analysis that is as rigorous and quantitative as possible based on comprehensive data and careful consideration of uncertainty C (C amM Sand Bed Region An Exelon Company SAND BED AREA DRYWELL SHELL-EL. 11'-O" I z V V BOTTOM OF SANDBED Ct 4" DRAIN PIPE)2)

AmnerGen.Lower Drywell Shell SAND BED REGION (SAND REMOVED) METAL 2-7/8" THK PLATE MCEASLE TOP OF SANDBED (EL. 12'-3")___..........'PLATE LOWER CURB (EL. 11'-0") / /- /DRYWELL FLOOR (EL. 10'-3") 1.154" THK PLATE ,. .'EL 8'-11 2511.BOTTM-OF SANDBED EL. 8-3" EL 6-1 5 6" .-.I .,,2:---EL. 6'-10 5/16" -. 4 DRAIN PIPE , _.,,,-z'-

 :"(5 PLACES)0.676" THK PLATE .:-(5'PLACES)

@ DRYWELL BOTTOM, 7 -. 2'-3" 1/2" PLATE EL".. 2-3"DRYWELL SKIRT EL. 0'-l" SECTIONAL VIEW OF SAND BED REGION , ,K?