ML14363A351

Transcript of the Advisory Committee on Reactor Safeguards Plant License Renewal Subcommittee - December 3, 2014 Pages 1-192

ML14363A351
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Site:	Byron, Braidwood
Issue date:	12/03/2014
From:	Howard K L Advisory Committee on Reactor Safeguards
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NRC-1261
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Official Transcript of Proceedings NUCLEAR REGULATORY COMMISSION

Title: Advisory Committee on Reactor Safeguards (ACRS) Plant License Renewal Subcommittee

Docket Number: (n/a)

Location: Rockville, Maryland

Date: December 3, 2014

Work Order No.: NRC-1261 Pages 1-1

NEAL R. GROSS AND CO., INC.

Court Reporters and Transcribers 1323 Rhode Island Avenue, N.W.

Washington, D.C. 20005 (202) 234

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-3701 (202) 234-4433 UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION

+ + + + + ADVISORY COMMITTEE ON REACTOR SAFEGUARDS (ACRS) + + + + + PLANT LICENSE RENEWAL SUBCOMMITTEE

+ + + + +

WEDNESDAY DECEMBER 3, 2014

+ + + + +

ROCKVILLE, MARYLAND

+ + + + +

The Subcommittee met at the Nuclear Regulatory Commission, Two White Flint North, Room T2B1, 11545 Rockville Pike, at 8:30 a.m., Gordon R.

Skillman, Chairman, presiding.

COMMITTEE MEMBERS:

GORDON R. SKILLMAN, Subcommittee Chairman

RONALD G. BALLINGER, Member

DANA A. POWERS, Member

HAROLD B. RAY, Member

PETER C. RICCARDELLA, Member

JOHN W. STETKAR, Member 2 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 ACRS CONSULTANT:

JOHN J. BARTON DESIGNATED FEDERAL OFFICIAL:

KENT L. HOWARD, SR.

ALSO PRESENT:

JIM ANNETT, Exelon

JOHN BASHOR, Exelon

GARY BECKNELL, Exelon

ED BLONDIN, Exelon

STEVE BLOOM, NRR

DONALD BRINDLE, Exelon

EDWARD J. CARLY, Next Era Energy

PAUL CERVENICA, Exelon

DYLAN CIMOCK, Exelon

SAMUEL CUADRADO, NRR

HIAN DA, Exelon

JOHN DAILY, NFF

GEORGE DEMETRI, Exelon/Westinghouse

YOIRA DIAZ-SANABRIA, NRR

CLIFF DOUTT, NRR

DAN ENRIGHT, Exelon 3 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 W. JACK FEIMSTER, Exelon NESTOR J. FELIZ-ADORNO, III

DON FERRARO, Exelon

BARF FU, NRR

MIKE GALLAGHER, Exelon

LYNNE GOODMAN, DTE Energy

KIM GREEN, NRR

ETHAN HAUSER, DTE Energy

JOHN HILDITCH, Exelon

ALLEN HISER, NRR

MELVIN HOLMBERG, RIII

WILLIAM C. HOLSTON, NRR

CHRIS HOVANEC, NRR

JOHN HUFNAGEL, Exelon

KENDRA HULLUM-LAWSON, DTE Energy

CRAIG INGOLD, Exelon

TIM JOHNSON, Exelon

ROGER KALIKIAN, NRR

CHARLES KELLER, Exelon

CHRISTINE KINKEAD, Exelon

RALPH KOHN, Exelon

RAY KUYLER, Morgan Lewis

JUAN A. LOPEZ, NRR

MICHAEL MARSHALL, NRR 4 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 JOHN MATTHEWS, Exelon JAMES MEDOFF, NRR

DANEIRA MELENDEZ-COLON, NRR

NEAL MILLEN, Exelon

CHRIS MILLER, NRR

SONNY MIN, NRR

JEFFREY MITCHELL, NRR

DENNIS MOREY, NRR

CASEY MUGGLESTON, Exelon

ALBERT PIHA, Exelon

PHIL O'DONNELL, Exelon

ALOYSIUS O. OBODOAKO, NRR*

DOUGLAS P. OVERBECK, Exelon

ANDREW PRINARIS, NRR

TOM QUINTENZ, Exelon

PHILLIP J. RAUSH, Exelon

LINDSAY ROBINSON, NRR

PETE SHIER, Exelon

ANN MARIE STONE, RIII

PETER TAMBURRO, Exelon

GEORGE THOMAS, NRR

PAUL WEYHMULLER, Exelon

MARK YOO, NRR

MOHAMMED YOUSUF, Exelon 5 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 *Present via telephone

T A B L E O F C O N T E N T S Page Opening Remarks 6 Staff Introduction 8 Exelon Generation Station - Byron 10 Station, Units 1 & 2 and Braidwood Station,

Units 1 & 2 - BBS Introduction, Station Descriptions and

Overview, GALL Consistency and Commitments,

Discussion of SER Open Items, Items of

Interest from Region III Inspections and

Closing Remarks NRC Staff Presentation SER Overview 98 Overview of License Renewal Review,

Region III 71002 Inspection, 71002

Inspection Issues, Scoping and Screening

Review, Aging Management Review, Time

Limited Aging Analysis, Conclusion Subcommittee Discussion 139 Adjourn 6 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 P R O C E E D I N G S (8:31 a.m.) CHAIRMAN SKILLMAN: Ladies and gentlemen, good morning. This meeting will come to order. I=m Gordon Skillman. I

=m the Chairman of the Plant License

Renewal Subcommittee. The Subcommittee will review the combined license renewal application for the Byron

Station Unit 1 and 2 and Braidwood Station Units 1 and 2 Nuclear Plants.

ACRS members in attendance are Pete Riccardella, Harold Ray, Dana Powers, John Stetkar, ACRS Chairman, John Barton, our consultant, and Ron

Ballinger. Our Federal Official is Kent Howard.

I would like to make an opening comment.

This is an unprecedented review for the ACRS. This is a review of four units at two different sites. While the units are very similar, they are not identical.

So there are some issues of commonality and some issues

of difference that we hope to hear about today. I want to say up front we recognize the immense effort that Exelon has invested in this

application. And the investment that you=ve made to bring your team here today, we thank you for that.

And we look forward to a very constructive meeting.

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-3701 (202) 234-4433 This morning we will hear presentations from the Division of License Renewal, from Region III and the Exelon Generation Company regarding this

matter. The Subcommittee will gather information,

analyze relevant issues and facts and formulate proposed positions and actions as appropriate for

deliberation by the Committee.

The rules for participation in today

=s meeting have been announced as part of the notice of

this meeting previously published in the Fe deral Register. We have not received written comments or

requests for time to make oral statements from members

of the public regarding today=s meeting. The entire meeting will be open to public attendance. There will be a phone bridge line. To

preclude interruption of the meeting, the phone will

be placed in a listen

-in mode during the presentations

and the Committee discussion. A transcript of this meeting is being kept and will be made available as stated in the Federal

Register Notice. Therefore, I request that participants in this meeting please use the microphones

located throughout the meeting room when addressing

the Subcommittee. The participants are requested to 9 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 please identify themselves first and then speak with sufficient clarity and volume so that they can be readily heard. I also ask that you please silence all

of your electronic devices. We will now proceed with the meeting. And I call upon Chris Miller to begin the presentation.

Chris.

STAFF INTRODUCTION MR. MILLER: Thank you, Chairman Skillman.

We=re looking forward to the presentations today.

And staff looks forward to the interaction.

As stated, I=m Chris Miller, Director of the Division of License Renewal. I have with me at

the table Yoira Diaz, Branch Chief for Projects Branch

1. We also have in the audience our Branch Chiefs

Dennis Morey, Michael Marshall and Steve Bloom.

The staff=s Lindsay Robinson, our Safety PM, will make the staff=s presentation. She will be joined at the table by our Senior Technical A dvisor Dr. Allen Hiser, Region III Lead Inspector for Byron Mel Holmberg, and Region III Lead Inspector for

Braidwood Nestor Feliz

-Adorno and the Safety PM Daneira

Melendez.

When the staff makes its presentations, 10 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 we=ll introduce our members who will be making comments at the time. This is the ACRS Subcommittee Meeting

for the License Renewal Application of Byron Station Units 1 and 2 and Braidwood 1 and 2. The SER with open

items was issued on October 30, 2014 with two open items.

But its resolution will be documented in the Final

SER. The first item of the open items pertains to control rod drive mechanism penetration nozzle wear due to interactions with thermal sleeve centering tabs.

The second open item is in the same regard to

environmentally assisted fatigue in Class I components.

Both open items are summarized in the SER reviewed

by the ACRS members. Since the issuance of the SER with open items, the staff has been working very diligently on resolution of these items. In addition to these open items, the staff has been working closely with Region

III inspectors to resolve issues that arose as a result

of the 71002 inspections.

The staff will summarize its completed review of the open items and the issues from the

inspection in the Final SER and present its findings

to the ACRS full Committee. We look forward to the 11 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 discussion and the review today. I

=d like to turn it over to Mike Gallagher of Exelon for their presentation.

EXELON GENERATION COMPANY

- BYRON STATION, UNITS 1 AND 2, AND BRAIDWOOD STATION, UNITS 1 AND 2 - BBS MR. GALLAGHER: Okay. Thank you, Chris.

Good morning. My name is Mike Gallagher and I

=m the Vice President of License Renewal Projects at Exelon.

I have 33 years of nuclear power plant experience all at Exelon and have been working on our license renewal

project since 2006. I think we=ve seen us here from

time to time.

Before we begin the presentation, I

=d like to introduce the presenters. To my right is John Bashor

and John is the Braidwood Engineering Director. John has over 30 years of nuclear power plant experience

including the last four years at Braidwood.

To John=s right is Albert Piha. And Albert is our Mechanical Manager for the Byron

-Braidwood License Renewal Project. Albert has over 32 years of

nuclear power plant experience including working on

Exelon=s license renewal project since 2008.

To Albert

=s right is Ed Blondin. Ed is the Senior Manager of Design Engineering at Byron Station. Ed has 28 years of nuclear power plant 12 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 experience including over 24 years at Bryon. To my left is John Hufnagel. And John is our Project Licensing Lead. John has 35 years of nuclear power plant experience including working on

Exelon=s license renewal project since 2005.

In addition is our technical support personnel which you see here with us today. We have with us today Mark Kanavos. And Mike is our Site Vice President at Braidwood. And we have Russ Kearney. Russ is our Site Vice President at Byron. And we have Dan Enright.

And Dan is Senior Vice President of the Midwest Operations. Slide 2.

This slide shows our agenda for the presentation. We will present to you some background information on the stations and the highlights of our license renewal application. Then we

=ll present to you the open items in the SER and items of interest

that came from the Region III inspections.

We believe we

=ve developed a robust, high quality license renewal application. We

=ve developed

effective aging management programs to ensure the

continued safe operation of Byron and Braidwood. We

appreciate this opportunity to make this presentation and look forward to answering any questions you may 13 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 have. CHAIRMAN SKILLMAN: Mike, as you begin, may I ask you please to give my collea gues and me a thumbnail view of how you

=ve treated commonality versus

uniqueness from the four plants and two plants. CHAIRMAN SKILLMAN: Yes, Mr. Skillman.

So we approached our reviews on a per unit basis to ensure that we captured everything on a plant

-specific

basis including plant

-specific operating experience

and so on. And the stations are very, very common.

If I can, I didn

=t have it in our presentation, but I=d like to put a back-up slide we had, slide number 2. This slide is going to show you

our AMR line item line

-up for the Bryon

-Braidwood stations. When we say station, it

=s Bryon Station, Braidwood Station and then we have the two units, Unit

1 and Unit 2 of each one.

This slide is just an overview of the line item basis. I

=m going to ask Dylan Cimock of our project team to go over this. Essentially, we

=re trying to show that the sites are very, very common.

Dylan. MR. CIMOCK: Dylan Cimock, License Renewal Team. Just to expand on what Mike said, the way we 14 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 approached the scoping, screening, AMR, operating experience review was on a unit

-by-unit basis. We looked at the individual P&IDs, pipe and instrument

diagrams, for each individual unit, established our

scoping boundaries, accounted for each individual

component type, its functions, materials and

environments. Where differences appeared either between the units of a given station or between the stations themselves, we identified those in our scope

and descriptions usually with the Byron or Braidwood only parenthetical in our application. Same thing in

our aging management review tables. So this table that we have up here on the back-up slide, when we originally submitted the

application we had approximately 6400 individual AMR line items. Of those, approximately 86 pe rcent represented no differences between the two stations or units. Fourteen percent was either a station or unit difference. And looking at that, the vast majority of these were all related to two principal differences which were differences in the clea n water source or ultimate heat sink or due to replacement of

the steam generators on Byron and Braidwood Unit 1 that

was not done on Byron and Braidwood Unit 2.

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-3701 (202) 234-4433 MR. GALLAGHER: Thank you. MEMBER POWERS: When you say there were no differences, manifestly there are differences. So there is some criterion you used in the percentage of

no differences. But what are these? MR. CIMOCK: That would depend on the aspect of the project. From a scoping standpoint, we looked at the things that, yo u know, the systems,

structures, components that meet Part 54 rule. From

an aging management standpoint, we looked for

differences in component types, functions, materials,

environments. From the programmatic standpoint, we

looked at differences in operating experience and

design to identify when we evaluate our programs whether or not new enhancements or certain acceptance would

needed to be taken when comparing our programs against

the GALL or ISGs. MR. GALLAGHER: Yes. Dr. Powers, what we=re trying to show here when we say no differences

which is what your question is that

=s an AMR line item.

So it=s a material

-environment combination. We

looked at each unit specifically and identified that

those material and environment combinations were

identical for each.

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-3701 (202) 234-4433 MEMBER POWERS: Manifestly, they

re not identical environments. They=re shifted in space by some distance. So there has to be some criterion. MR. GALLAGHER: Right. But here it

s from the GALL as far as what the environment would be. You

know if it

=s indoor air or that type of thing. That

=s what we=re saying when we say consistent with GALL.

So this would be the line item consistency with the

GALL. And as Dylan said then we applied which then leads you to the aging management program to develop. And our intent is to have a common aging management program for the most part because the high number of line items are common that=s achievable.

Did we answer your question, Mr. Skillman? CHAIRMAN SKILLMAN: It did for me. Dr.

Powers? MEMBER POWERS: Well, the problem that I see is yes, this is inside. It

=s in the air and whatnot.

I=m sure that the temperature of the air it was exposed to was different. The air flow over it was different.

But there has to be some point at which you say those differences

-- maybe small

-- just didn

=t amount to anything significant.

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-3701 (202) 234-4433 MR. GALLAGHER: And I think the way that

=s borne out is in the operating experience. So we did a plant-specific operating experience review.

MEMBER POWERS: There you go.

MR. GALLAGHER: And then that

=s how we detected it.

MEMBER POWERS: So they

=re based on a combination of engineering judgment. Two

-tenths of

a degree just doesn=t make any difference.

MR. GALLAGHER: And our review of operating experience. MEMBER POWERS: We looked at the operating experience and we found out that the thing had screwed up in exactly the same way every time at the same place.

MR. GALLAGHER: And where there were differences in operating experience, we factored tha t

into our programs.

CHAIRMAN SKILLMAN: Thank you. Let

=s continue.

MR. GALLAGHER: So now let me turn the presentation over to John Bashor. John.

MR. BASHOR: Thank you, Mike. Slide 3 please. Good morning. My name is John Bashor. I=m

the Engineering Director at Braidwood Generating 18 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 Station.

Let me first explain our presentation

=s color coding. We have a gray highlighted header on slides we

=re presenting on information that is common to both stations. For Bryon

-only information, the

header or information is highlighted in green and for

Braidwood only blue.

Bryon and Braidwood Stations

= Units 1 and 2 are Westinghouse pressurized water reactor, four

-loop designs that are owned and operated by Exelon. The Bryon Generating Station is located in the State of

Illinois approximately 95 miles northwest of Chicago.

And the Braidwood Generating Station is located in the State of Illinois approximately 60 miles southwest

of Chicago. Slide 4 please. This slide shows an overview of the Byron Generating Station. On this slide, you can see the

containment structures, the auxiliary building and the turbine building which are located in the center of the picture. The circulating water cooling towers and

flume, the circulating water pump house, the

independent spent fuel storage installation, the 345 kV switchyard and the essential service water cooli ng towers which are the station=s ultimate heat sink.

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-3701 (202) 234-4433 CONSULTANT BARTON: May I ask you a question about the switchyard? Is a lot of the equipment in the switchyards for SBO and is maintenance

done in the switchyards?

I=m sure the plant staff is not doing the maintenance in the switchyard. Someone else is. And

who is that? MR. GALLAGHER: We have a person here, Doug Overbeck. Doug, you can answer that question.

MR. OVERBECK: Doug Overbeck, Braidwood Station Plant Engineering. The maintenance in the

switchyard is performed by Commonwealth Edison

personnel. MR. GALLAGHER: Is that microphone on?

Sorry. CONSULTANT BARTON: Thank you. Now my question is when those people want to go into the

switchyard and do work, how is the plant involv ed?

I know the plant has to oversee in some respect to that

work since it is vital to plant operation. MR. GALLAGHER: Yes, and Doug can tell you about the controls we have.

MR. OVERBECK: The process is that Commonwealth Edison submits work requests to t he 20 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 station and the station provides work orders and put it in our process. They

=re put in the schedule.

They=re evaluated for risk and time of execution.

Operations has to approve the work order. They also

approve access to the switchyard.

CONSULTANT BARTON: Thank you.

MR. GALLAGHER: Thank, Doug.

John.

MR. BASHOR: Slide 5 please. This slide shows an overview of the Braidwood Generating Station.

On the slide you can see the containment structures, the auxiliary building and the turb ine building which

are located in the center of the picture. The lake

screen house, the independent spend fuel storage installation, the 345 kV switchyard and the cooling

pond which contains the station

=s ultimate heat sink.

As you can see from these stat ion overviews with the exception of the cooling water source, the physical and design characteristics of the two stations

are essentially identical. Slide 6 please.

This slide provides an overview of Byron and Braidwood histories and some major station

improvements. Byron was initially licensed in 1994 for Unit 1 and 1986 for Unit 2. Braidwood was initially 21 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 licensed in 1986 for Unit 1 and 1987 for Unit 2. All four units were initially licensed for a rate of thermal

power of 3,411 megawatts thermal (MW t). A five percent increase in rated power on all four units was performed in 2001. In April of this

year a 1.63 percent measurement uncertainty recapture (MUR) power uprate was implemented which increased the thermal rating on each unit to their current rating of 3645 MW

t. Exelon has also continued to make substantial improvements to both Bryon and Braidwood units such as steam generator replacements on Byron Unit 1 and Braidwood Unit 1, emergency core cooling

system (ECCS) recirculation sump screen modifications, spent fuel rack replacements and independent spent fuel

storage installations (ISFSI).

Byron and Braidwood are operated on 18-month fuel cycles and ASCE factor for this year as of the third quarter is greater than 95 percent for

each station.

The renewal application was submitted on May 29, 2013. Our current license at Byron expires

on October 31, 2024 for Unit 1 and November 6, 2026 for Unit 2. Our current licenses at Braidwood expire

on October 17, 2026 for Unit 1 and December 18, 2027 22 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 for Unit 2. I will now turn it over to Albert Piha who will present to you the highlights of our license renewal application.

CHAIRMAN SKILLMAN: Before you change, keep that slide. John, go ahead.

CONSULTANT BARTON: You change out steam generators on Unit 1 at both sites. Unit 2 has the original steam generators. Is there any plan that you see now for replacement of steam generators in Unit

2 at both sites? MR. BASHOR: If you look at the long range plan, Mr. Barton, you will see steam generator replacement out in the out years.

CONSULTANT BARTON: We currently do not have active projects that are underway for either Byron

or Braidwood actively pursuing that. But we are

constantly monitoring the results of the inspections

we do on the steam generators at both Byron and

Braidwood. And we realize that if we run into a

situation where we see accelerated plugging of tubes

we may find ourselves in a situation where replacement

will be required in the future. CONSULTANT BARTON: Okay. You=

re kind of 23 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 lucky because I know a lot of plants have changed out Westinghouse steam generators.

MEMBER BALLINGER: You=re one of the two unusual ones. MR. GALLAGHER: The Unit 2 had better materials originally in the original construction.

The Unit 1 did not. And that

=s really the difference

there. CONSULTANT BARTON: Unit 1 was also B&Ws, right? MR. BASHOR: Unit 1s are B&W. They were all original Westinghouse.

CONSULTANT BARTON: Okay. I gotcha.

CHAIRMAN SKILLMAN: Let me ask my question please. Reviewing the AMPs and this is steam generator

program B.2.1.10 directed specifically at Bryon, the

wording in the inspector=s report is AFor the second

enhancement applicable to Byron Unit 1 steam generators, the existing AMP will be enhanced to

validate that the PWSEC of the tube sheet welds is not

occurring.@ That=s in the inspection report. I do not have the inspection report results for Braidwood Unit 1 which is also a B&W steam generator design. Is that same AMP applicable to Braidwood Unit 24 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 1? MR. BASHOR: Yes sir. Is the steam generator -- Where is that at?

CHAIRMAN SKILLMAN: That

=s what I=m asking. There

=s an enhancement on Byron 1 steam generators that I

=m wondering if that same enhancement

is applicable to Braidwood. MR. BECKNELL: I=

m Gary Becknell, License Renewal Project Team. The enhancement is applicable to both stations, Byron and Braidwood, for the

verification that water chemistry is controlling

primary water stress corrosion cracking.

CHAIRMAN SKILLMAN: Yes sir. Thank you.

Thank you, Mike.

MEMBER RICCARDELLA: Just another question.

What are your plans with respect to the reactor vessel

top heads at Byron and Braidwood? MR. BASHOR: Right now, we find ourselves in a unique situation, Dr. Riccardella. We have not replaced the heads at Byron or Braidwood. I would like

to have Jack Feimster stand up and give a summary of

what we=re doing in that area specifically looking at

a mitigation strategy we

=re putting in place in the

future.

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-3701 (202) 234-4433 MR. FEIMSTER: I=m Jack Feimster, Senior Engineering Manager at Byron Station. Currently, Exelon is pursuing a mitigation strategy for reactor vessel heads. Specifically in our particular case,

we=re pursuing peening of the affected area. The company we have chosen is AREVA. We

=re going to use what are

water jet cavitation peening.

MEMBER RICCARDELLA: Thank you.

MR. GALLAGHER: Thanks, Jack.

MR. BASHOR: I will now turn it over to Albert Piha who will present to you the highlights of

our license renewal application.

MR. PIHA: Thank you, John. Slide 7 please. Good morning. My name is Albert Piha and I am the Byron and Braidwood License Renewal and Mechanical Manager. I will discuss the highlights of

our license renewal application including the aging

management programs, commitments and an overview of

the two open items in the SER. Slide 8 please.

In preparing the application, Exelon used industry and NRC guidance to make the application as

consistent with the GALL as possible. Our submittal

was based on GALL Revision 2. There are 45 aging

management programs at Byron and 44 at Braidwood.

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-3701 (202) 234-4433 The difference in the number of the aging management programs is due to the fuse holder program which is applicable to Bryon only. They are

safety-related equipment found only at the Byron River screenhouse that required the application of this aging

management program.

Thirty-eight Byron programs and 37 Braidwood programs are consistent with the GALL. Seven programs at each station have exceptions to the GALL.

There are 47 license renewal commitments at Byron and 46 at Braidwood. Of these commitments, 45 at Byron

and 44 at Braidwood are associated with aging management

programs.

In addition, one common commitment at each station implements the operating experience program enhancements. The final commitment for each station

is to restore the out-of-service reactor vessel stud on Byron Unit 2 and on Braidwood Unit 2 no later than six months prior to entering the period of extended

operation.

These commitments will be captured within the license renewal UFSAR supplement and the Station

Commitment Tracking Database and managed in accordance with 10 CFR 50.59 and the Commitment Management Program 27 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 which is based on the NRC endorsed NEI 99-04 process.

CHAIRMAN SKILLMAN: Would you like to comment on Byron 2 stud 11 please? MR. PIHA: Yes. Byron Unit 2 stud was successfully removed last fall in October and a new stud was installed and all 54 studs are tensioned and

in service. CHAIRMAN SKILLMAN: Yes sir. So that leaves the one stud 35 on Braidwood 2 as a commitment

prior to PEO.

MR. PIHA: That=s correct.

CHAIRMAN SKILLMAN: Okay. Thank you.

CONSULTANT BARTON: While you

=re on it, do you currently have a plan of how you

=re going to

do stud 35 since it

=s not just threads that are messed

up. You have a larger hole on that head. MR. GALLAGHER: Yes, that

=s going to take us a little more work, Mr. Barton. What we=re doing

is next outage we

=re going to be taking

-- We attempted a repair in 2002 as you know.

CONSULTANT BARTON: Yes.

MR. GALLAGHER: And it was

-- There was a problem with the machine. And it was over bored at

the time.

28 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 CONSULTANT BARTON: Right. MR. GALLAGHER: So we want to take detailed measurements. We want to know exactly what

=s down there and develop a modification and in a subsequent

outage install it. Our commitment is to get it done before as Albert said six months before PEO. But we

=re making good progress already. We did the one at Byron

and we=re pursuing the one at Braidwood.

CONSULTANT BARTON: You=ve got until the license extension starts.

MR. GALLAGHER: Yes.

CONSULTANT BARTON: And in my mind when do you have that kind of thing planned out? Is it the

last outage before you go into

-- which takes it to the difficulty maybe? MR. GALLAGHER: No. Our intent is to move forward with this. And as I said, we did on Byron Unit

2. We took care of that.

CONSULTANT BARTON: Right. But that was a lot easier fix. MR. GALLAGHER: Yeah, but that was the one that had the aging management question because you had

the stud, partial stud, in there.

CONSULTANT BARTON: Right.

29 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 MR. GALLAGHER: And so getting it out was a big win. We were able to put a new one in. On Braidwood, we=ve got to get the measurements and the

design that we know is going to work and then move

forward with that.

MEMBER STETKAR: You don

=t have it scheduled.

MR. GALLAGHER: No, we

=ll get the measurements next outage. Then from there we

=ll plan what we need to do. Okay.

All right, Albert.

MR. PIHA: Slide 9 please. There are two open items in the Byron and Braidwood SER. Slide 10.

The first open item is associated with the screening methodology for environmentally assisted

fatigue (EAF) to determine leading locations Leading

locations are those locations which have been

determined to bound all other locations for

consideration of environmental fatigue.

Monitoring these locations for the period of extended operation will ensure no location will

exceed an environmental fatigue usage factor of 1.0.

This includes consideration of both the NUREG

-6260 locations to determine appropriate for a new 30 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 Westinghouse PWR and those locations determined could be more limiting than the 6260 locations.

Leading locations were determined by comparison of environmental fatigue experienced at locations in transient sections. A transient section is defined as a grouping of equipment or piping

experiencing the same transients.

The NRC staff has requested more information in three areas. The first area is

concerned with the staff

=s request for additional

justification that the leading material locations will

continue to bound eliminated locations after refined

analysis. Assessment of the relative differences in

screening environmental fatigue usage results, the

relative differences in the conservatism in a stress

analysis and the potential variation in the

environmental correction factor justified a determination of the leading material location. With

a refined analysis, leading locations are evaluated with both improved analysis techniques and a review

of their inputs.

Considering refined analysis, it was shown the leading locations will continue to bound the eliminated material locations. The result of this 31 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 analysis is the establishment of limits for the fatigue monitoring program to assure environmental fatigue is

managed during the period of extended operation.

For the second area, the staff requested justification why the Bryon and Braidwood Unit 1

replacement steam generator location was removed from consideration as a leading location when its screening environmental fatigue usage factor was higher than the

location selected as the leading location. Because of the conservatism in the stress analysis for this location, it was shown that the steam generator location has a screening environmental fatigue usage lower than

the leading location when it points similar

conservatism in the stress analysis.

In the third area, the staff requested identification of other instances where a component location was removed from consideration which had a

higher screening environmental fatigue usage factor

than the location selected to be the leading location.

Two other locations in the piping systems wer e

identified and had the same justification as the steam

generator location.

To resolve this issue, we have provided the additional information to the staff in a letter 32 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 dated November 25, 2014.

CHAIRMAN SKILLMAN: Albert, before you move from that slide, would you make a comment to my colleagues and me about what it actually takes for a

utility to do an environmental CUF calculations? Is this something that you do on your own? Is it something

you go out and buy a specialty contract for? How is

this work conducted and what

=s the impact on your staff?

MR. PIHA: For us, on this project, we did contract an outside consultant to do this work for us.

We have a TLAA engineer who is involved, interfaces

and reviews and comments on all the work that=s done

by the contractor. CHAIRMAN SKILLMAN: So it

=s really handled under the TLAA portion of license renewal.

MR. PIHA: That=s correct.

CHAIRMAN SKILLMAN: Thank you.

MEMBER RICCARDELLA: We just sat through a meeting yesterday on the revisions to Reg Guide 1.207

and the NUREG

-6909 which is changing these environmental things somewhat. I think in general they

become less onerous. But are there plans to

incorporate those new revisions in, too? MR. PIHA: I=

m going to let Tom Quintenz, 33 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 our TLAA engineer, speak to that.

MR. QUINTENZ: Tom Quintenz, License Renewal Project. I believe your question had to do with the new Reg Guide 1.207 that is in draft right

now. MEMBER RICCARDELLA: Yes.

MR. QUINTENZ: And I think you were asking about the encumbrance of the new draft guide.

MEMBER RICCARDELLA: Yes. Are you planning to address that?

MR. QUINTENZ: My understanding is that it=s employing NUREG-6909 as the guide for doing the

environmental fatigue. Basically, we

=ve done our

calculations for the nickel locations using 6909. So we have experience with that. MEMBER RICCARDELLA: But that

=s a 6909 Rev 1 that I=m thinking of.

MR. QUINTENZ: That

=s correct. That

=s still under review. We understand that.

MEMBER RICCARDELLA: Do you have future plans for that new methodology? MR. QUINTENZ: We would have to. We

=re a part of the industry comment on both of those items.

I think we would be awaiting to see what the results 34 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 of that would be.

MEMBER RICCARDELLA: Okay. Thanks.

MEMBER BALLINGER: When you said monitoring the fatigue locations, can you expand on

that just a little bit? MR. PIHA: I=

ll have Tom also answer that question.

MR. QUINTENZ: Tom Quintenz, License Renewal Project. This involves basically monitoring

the transients which are inputs to the fatigue analysis.

So when we say we are monitoring the location, we

=re actually monitoring the transients which were inputs

to the fatigue analysis for that location.

MEMBER BALLINGER: When you say monitoring, you mean measuring the temperature and

things like that or just. MR. QUINTENZ: Yes, we basically look for the transient and we characterize the temperature and pressure profiles to make sure that they agree with

the design inputs that were with the fatigue analysis.

MEMBER BALLINGER: When you say characterize, you mean measure it or calculate.

MR. QUINTENZ: Measure.

MEMBER BALLINGER: Okay.

35 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 CHAIRMAN SKILLMAN: Pete and Ron, are you good? MEMBER BALLINGER: Yes.

MEMBER RICCARDELLA: I=m good.

CHAIRMAN SKILLMAN: Go ahead, Mike. Or excuse me. Go ahead, Albert. MR. PIHA: Slide 11 please. The second open item involves the aging management of the control rod drive mechanism or CRDM housing for wear due to thermal sleeve rotation. The CRDM housing is man aged by the ASME Section XI, Subsections IWB/IWC/IWD Aging

Management Program.

The NRC staff has requested more information in two areas, the results of the CRDM

Housing Wear Analysis and also the CRDM Housing Wear

Acceptance Criteria. Our presentation will provide background information on the CRDM Housing wear and will address the areas where the NRC staff had requested

more information. The additional information will address this open item. It has been submitted to the NRC staff for their review in a letter dated November

24, 2014.

I will now turn the presentation over to Ed Blondin who will discuss the CRDM Housing wear.

36 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 MR. BLONDIN: Thank you, Albert. Slide 12 please. Good morning. My name is Ed Blondin. I

=m the Senior Manager of Design Engineering at Byron

Station. On this slide, a cross section of the reactor vessel head is shown with the control rod drive mechanism housings or CRDM housings shown in blue.

Inside these housings is a thermal sleeve which is

illustrated in green. At Byron and Braidwood, the

reactor vessel heads have thermal sleeves installed in 55 of the 78 CRDM housings. The CRDM housings are part of the reactor coolant pressure boundary and are

made of nickel alloy in the area of interest.

The thermal sleeve --

MEMBER BALLINGER: Six hundred or 625 or 690? What do you mean by nickel alloy?

MR. BLONDIN: Phil.

MR. O=DONNELL: Phil O

=Donnell, License Renewal Team. They=re at alloy 600.

MEMBER BALLINGER: Six hundred, okay.

MR. O=DONNELL: Yes.

MEMBER RICCARDELLA: That=

s related to my earlier question about the reactor vessel head. But this is a wear problem. This isn

=t a cracking problem.

37 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 MEMBER BALLINGER: Yes.

MR. BLONDIN: The thermal sleeves are loosely inserted into the CRDM housings a nd are not

physically attached. The thermal sleeves are approximately 60 inches in length. There are three centering tabs shown in black 120 degrees apart located

approximately 22 inches below the top of the thermal sleeve. The thermal sleeve centering tab material is

stainless steel.

Thermal sleeves are used to mitigate the effects of reactor coolant temperature in the upper

reactor vessel head region on the control rods. The thermal sleeves also provide a means of guiding the

control rods into the housing following refueling operations. Rotation of the thermal sleeves within

the CRDM housing occurs due to normal operation from

reactor coolant flow in this region. CHAIRMAN SKILLMAN: What is the propellant that causes the rotation? If you can describe the force diagram for us, that would help.

MR. BLONDIN: Go ahead, Phil.

MR. O=DONNELL: Phil O

=Donnell, License Renewal Team. Because it

=s a T-cold head, there is

a substantial amount of coolant flow, approximately 38 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 three percent, that e nds up going through that particular region. And since the thermal sleeves are

not fixed, they actually

-- the flow past them causes it to rotate.

MEMBER BALLINGER: How are the tabs attached? By welding?

MR. O=DONNELL: They are attached by welding. That is correct. MEMBER BALLINGER: And so then I come back to the alloy 600 issue. Is it thermally treated or

is it just a tubing that

=s extruded and no particular

heat treatment like you would have in a steam generator

tube? MR. O=DONNELL: I would have to get back to you on that.

MR. GALLAGHER: George, do you know?

MR. O=DONNELL: We can get back to you.

MEMBER BALLINGER: Because I

=d be more than worried about -- It=s not a stress component.

It=s not a pressure boundary. But that weld point is a point of high residual stress. And it goes all the

way around or is it just tabs.

MR. O=DONNELL: They=re just tabs.

MEMBER BALLINGER: They

=re just tabs, 39 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 okay. MR. O=DONNELL: Phil O

=Donnell, License Renewal Team. The tab is stainless steel.

MEMBER BALLINGER: Yes, but it

=s welded to the 600.

MR. O=DONNELL: No, no. The tab is on the thermal sleeve.

MR. BLONDIN: The thermal sleeve are stainless steel.

MEMBER BALLINGER: Oh, I thought I heard you tell me that the thermal sleeve was alloy 600.

MR. O=DONNELL: No, the housing. MEMBER BALLINGER: All right. Now I

=m oriented properly. MEMBER RICCARDELLA: And the cooling flow you=re referring to is in that annulus between the

thermal sleeve and the housing or no?

MR. O=DONNELL:

Phil O=Donnell, License Renewal Team. It is past the thermal sleeves. It is not going up into that region. It basically goes down

the head. CHAIRMAN SKILLMAN: So the rotating force is the friction from the T

-hot coming over the top of

the head.

40 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 MR. O=DONNELL: It=s actually T-cold.

CHAIRMAN SKILLMAN: T-cold.

MR. O=DONNELL: Yes.

CHAIRMAN SKILLMAN: So it

=s a friction on the -- What=s it called?

MR. BLONDIN: The thermal sleeve.

CHAIRMAN SKILLMAN: The thermal sleeve.

MR. O=DONNELL: Yes.

CHAIRMAN SKILLMAN: And it

=s just the turbulent flow on the top of the head that=s causing

these things to rotate.

MR. O=DONNELL: That is correct.

CHAIRMAN SKILLMAN: Is this a phenomenon that is common to the four LOOP Westinghouse plants?

MR. O=DONNELL: This is common to Westinghouse plants.

MR. PIHA: We

=re going to discuss about a report that=s been completed. And it was done for

participating utilities in the industry for the same

situation. CONSULTANT BARTON: This is the first time I think we=ve heard this problem though.

CHAIRMAN SKILLMAN: It

=s the first time I=ve heard of it.

41 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 CONSULTANT BARTON: Yes.

CHAIRMAN SKILLMAN: It could be others have heard of it. But I certainly haven=t. CONSULTANT BARTON: I mean as far as seeing other plant renewals, Westinghouse units, this has not come up. CHAIRMAN SKILLMAN: I don

=t remember this from the last meeting.

MEMBER BALLINGER: Now these are T

-cold heads, all of them. So that puts the susceptibility

to J-groove problems way, way down.

CONSULTANT BARTON: Yes, it drops the temperature. Except they=ve had a few leaks here at

a couple of these plants. MEMBER BALLINGER: I know. That was my next question. CONSULTANT BARTON: Relatively few. It=s some of them are from that unique Cuban mater ial that

has unusual susceptibility.

CHAIRMAN SKILLMAN: Let me ask this. Is this a phenomenon that began --

MEMBER RICCARDELLA: Right. They hadn=t had the cracks. I=m sorry. I misspoke.

CHAIRMAN SKILLMAN: Is this a phenomenon 42 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 that has occurred since you did your power upgrades?

Did it exist before then or is it new after the power

upgrade? MR. GALLAGHER: The phenomenon is believed to have existed --

CHAIRMAN SKILLMAN: From the very beginning?

MR. GALLAGHER:

-- from the very beginning. The reason that there

=s information on this

now and that there

=s an industry initiative to

investigate this is because when you do the J-groove

weld inspections you can see in the ones that are at

the center, the centering tabs are near the J-groove

weld. So you can see this scratching pattern.

CHAIRMAN SKILLMAN: Right.

MR. GALLAGHER: So that

=s why it=s come up fairly recently in the industry. And as Albert said,

there=s a PWR owners group analysis. George Demetri is here. He=

s the Westinghouse author of the analysis.

And we=re going to go through the details for you here with what we

=re trying to show you and

I hope we corrected your mental image. MEMBER BALLINGER: I thought somebody said alloy 600 for the sleeve.

43 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 MR. GALLAGHER: Yes. If we could just go to the next slide for a minute because we have a closer thing in here. Yes, just for clarity, the thermal sleeve is stainless steel. The tab is on the thermal sleeve and it wears on the nozzle. And Ed will get

into the rest of this. MEMBER RICCARDELLA: The wear is in the alloy 600. MR. GALLAGHER: Yes. And that=

s the area that is a pressure boundary. And that=s why we have

reviewed this and have this analysis.

MEMBER BALLINGER: So the required under head inspection plan when you get that tab very close to the top of the J

-groove walls at the center, is that

looked at as a possible initiation point for cracking?

The stresses from the J

-groove weld might get far

enough above so that they

=re in a region where that

wear pattern might influence things.

MR. GALLAGHER: George can answer that.

MR. DEMETRI: George Demetri with Westinghouse Electric Company. We don

=t consider

that. It

=s considered, we analyze it as a wear phenomenon and we did account for stre ss concentration,

stress intensification there.

44 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 MEMBER BALLINGER: On the initial of the alloy 600?

MR. DEMETRI: Yes, that=s correct.

MEMBER BALLINGER: Okay.

MEMBER RICCARDELLA: How close does it get to the J-groove weld on the top dead center?

MR. DEMETRI: It could be

-- It could actually span the top of the J-groove weld. MEMBER BALLINGER: Okay. So that=

s right in the region. MEMBER RICCARDELLA: But it could be in the residual stress weld.

MR. DEMETRI: Residual stress in that weld. MEMBER RICCARDELLA: But I mean they

=re inspecting for cracks.

MEMBER BALLINGER: Yes, but there

=s an under head inspection plan.

MEMBER RICCARDELLA: Right.

CHAIRMAN SKILLMAN: I think we

=re going to hear more about that in a few minutes. MR. GALLAGHER: Yes. So at this point and basically to fast forward a little bit what we

=re trying

to show here is that you can wear the complete thickness 45 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 of the tab and it

=s still acceptable. And Ed will get into the details. Ed.

MR. BLONDIN: Okay. So as we started to talk about, it is common to the Westinghouse PWR design

and it=s been recently evaluated by Westinghouse for

the PWR owners group using finite element analysis. MEMBER STETKAR: Ed, if we could before you get into the analysis, to follow up on something John raised, are Byron and Braidwood the first plants to observe this wear? I mean I

=m curious why we haven

=t heard about it in any of the others. We heard about

license renewals for several Westinghouse plants over

the last seven years I

=ve been in the Committee. This is the first one where it=s come up. MR. BLONDIN: Phil, do you know what other plants? MR. O=DONNELL: This is Phil O

=Donnell, License Renewal Team. Actually, in the last one that

you did with TVA, that was also in the SER.

MEMBER STETKAR: It was. I missed it.

MR. O=DONNELL: Yes.

MEMBER STETKAR: But it wasn

=t challenged by anybody in the review.

MR. O=DONNELL: That=s correct.

46 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 CHAIRMAN SKILLMAN: But before then it was not a -- At least it was not communicated.

MR. O=DONNELL: It was not communicated because they were also I believe going --

MR. GALLAGHER: There=s difference here, Mr. Skillman. We don

=t want to talk about other plants.

CHAIRMAN SKILLMAN: Right. I understand.

I was just curious. That

=s why I asked Westinghouse.

MR. GALLAGHER: Some of the plants with newer heads don

=t have the phenomenon because there are some design differences.

CHAIRMAN SKILLMAN: Okay.

MR. GALLAGHER: So it

=s not -- it=s basically we have this and many other plants have it. But we can=t go on a case-by-case basis.

CHAIRMAN SKILLMAN: All right. Thank you. MR. BLONDIN: I

=ll continue. The analysis examined the impact of the hypothetical maximum wear depth on the integrity of the CRDM

housings.

CHAIRMAN SKILLMAN: And the maximum wear depth is the entire thickness of that tab into the

primary coolant system pressure boundary ID.

47 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 MR. BLONDIN: That is correct. And I=ll talk more about that in a moment.

CHAIRMAN SKILLMAN: Okay. MR. BLONDIN: Based on the analysis, it was it was also determined that if the maximum

hypothetical wear depth is assumed the CRDM housings

will continue to meet the ASME Code requirements and

the current licensing basis.

MEMBER BALLINGER: Okay. I

=ll keep harping on this. But at the maximum depth, you have margin on crack growth if you initiate a stress

corrosion crack growth rate. Or are you just saying

AWe=re not going to initiate a crack growth because

we=re going to peen it or something@?

MR. DEMETRI: George Demetri, Westinghouse Electric. We just analyzed it as a wear

phenomenon, but we have not looked at it from the

standpoint of crack growth.

MEMBER BALLINGER: I think somebody should. CHAIRMAN SKILLMAN: Let=s proceed.

MR. BLONDIN: Okay. Details are further explained on the next slide, slide 13 please. The

expanded view of the CRDM housing area prone to wear 48 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 was shown is shown in the detail on this slide. When the thermal sleeve rotates within the CRDM housing the centering tabs again shown in black r ub against the CRDM housing and cause wear at the centering tabs and the housing. The wear is not evenly distributed within

the inside diameter of the CRDM housing due to the flow

induced vibration on the thermal sleeves.

The hypothetical maximum possible wear depth of the CRDM housing at the thickness of the

centering tab is 0.1075 inch. Assuming that the

maximum possible wear depth was to occur, the CRDM

housing thickness would be reduced from the original

0.625 inch to 0.517 inch. However, based on t he similarity and hardness of the metals with the nickel

alloy housing and the stainless steel centering tabs the CRDM housing and the thermal sleeve tabs will both experience wear. Therefore, the actual wear on the

CRDM housing is expected to be substantially less than

this worst case assumption. Slide 14 please.

The detailed ASME Code evaluation which includes finite element analysis and stress

calculations was performed by Westinghouse that considered the effects of the maximum wear depth on

the integrity of the CRDM housing. As stated earlier, 49 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 several Westinghouse PWRs have discovered similar wear indications on the CRDM housings.

Primary stress evaluations were performed using classical stress equations. Primary plus

secondary stress integrity ranges and fatigue usage factors were determined by finite element analysis.

The CRDM housings were evaluated for the design, normal,

upset, emergency, faulted and test conditions as

required by the ASME Code. The evaluations also

considered the UFSAR design requirements with respect to transients, loading and allowable stresses. The

analysis demonstrated that the CRDM housing with the maximum possible wear group depth of 0.1075 inch

satisfies all of the allowable stress and fatigue limits

for Section III, Subsections NB-3221 through NB-3226

of the ASME Code.

Since the analysis considered a conservative set of enveloping mechanical loads and pressure and thermal transients as well as a highly

unlikely wear group depth of 0.1075 inch, the CRDM housing with inside surface wear is acceptable.

Additionally, the Byron and Braidwood 40 year design basis transients were analyzed to determine if the number of cycles was bounding for the 60 year period.

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-3701 (202) 234-4433 Based on the review, the 60 year design basis transients set for the period of extended operation is bounded by this CRDM housing analysis. Slide 15

please. In summary, the applicable ASME Code limits for Class 1 for reactor coolant pressure bounded components have been utilized in our analysis. And the CRDM housing was evaluated as acceptable for the period of extended operation. As the Byron and Braidwood 40 year design basis transients have been

shown to be bounding for the 60 year design basis transient set, then this analysis is also valid for the period of extended operation.

The CRDM housing wear acceptance criteria as prescribed in ASME Section III, including the fatigue analysis, have been met for the impact of the

hypothetical maximum tab wear on the inside of the CRDM

housing. No additional actions are required for aging

management of the CRDM housing wear. This concludes our presentation for the CRDM housing wear open item.

At this time, I would like to turn the presentation over to Albert Piha to introduce our items

of interest from the Region III inspections.

CHAIRMAN SKILLMAN: Before we change the 51 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 slide on that third bullet, those words after the parenthesis, A no additional aging management

activities,@ does that communicate no inspections?

MR. PIHA: That=s correct.

CHAIRMAN SKILLMAN: Is that your intent not to look at it?

MR. PIHA: That=s correct.

CHAIRMAN SKILLMAN: Don

=t you think at some point in the future you ought to take a look to

confirm?

MR. PIHA: Today there isn=t a qualified technique to look at this area. But this analysis says that we could have full wear depth and we meet all code

limits and acceptance criteria.

CHAIRMAN SKILLMAN: Is the process to inspect the pressure housing portion of the stump of

the control rod drive extension a process the requires removal of the control rod drive and then removal of

the sleeve? Is that what it takes to do that

inspection? MR. PIHA: George, do you have an answer?

MR. DEMETRI: Yes, George Demetri, Westinghouse. You would definitely need to remove the

thermal sleeve to do that inspection.

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-3701 (202) 234-4433 CHAIRMAN SKILLMAN: But does a thermal sleeve withdraw if the mechanism is removed? Or is it blocked because of its geometry below the inside

portion of the --

MR. DEMETRI: Yes, it

=s blocked because of the funnel.

CHAIRMAN SKILLMAN: So it really cannot be pulled through.

MR. DEMETRI: That=s correct.

MEMBER RICCARDELLA: Let=

s talk about the ones that are near top dead center that are close to

the J-groove weld. When you inspect the J

-groove weld,

you don=t remove the sleeve, right? You have something

that goes in the annulus I believe. So for at least those penetrations you can get in the vicinity of this

wear, right?

MR. DEMETRI: Phil, can you answer?

MR. O=DONNELL: Phil O

=Donnell, L icense Renewal Team. Yes, basically when they do the J

-groove weld inspections they have a probe that goes up between

the thermal sleeve and the CRDM housing to look at that.

But what they have found though is that there is not

a qualified method right now to determine the wear depth

of any crack beyond that particular point.

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-3701 (202) 234-4433 MEMBER RICCARDELLA: I understand that, but to address the concern that Ron brought up is if you=re getting any stress corrosion cracking around

here at least on those penetrations I think you would see it. And my understanding is those inspections,

are they every outage for these because you

=ve had cracking?

MR. O=DONNELL: Phil O

=Donnell, License Renewal Team. For three of the plants it is because of the cracking of the J

-groove welds. They actually

do the inspections once per cycle. Braidwood Unit 2

is not currently

-- has no signs of cracking yet. So it=s every three to four to five cycles right now.

MEMBER BALLINGER: So these are being --

Those areas that you=re going to --

MEMBER RICCARDELLA: Are being inspected for stress corrosion cracking and crack growth. And there have been crack growth analyses done to support

those inspections.

MR. GALLAGHER: Oh yeah.

MEMBER RICCARDELLA: Of the J

-groove welds. Well, also the tubes in the vicinity of the

J-groove wells and at the top of the J-groove welds.

The only question I think that Ron raises is should 54 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 you consider the effect of this wear on those crack growth analysis. You know you

=ve got a 10 percent loss

of -- MEMBER BALLINGER: It=

s not so much crack growth as it is initiation. You know the wear affects

the initiation time.

MEMBER RICCARDELLA: Yes.

CHAIRMAN SKILLMAN: Please proceed.

Thank you. MR. PIHA: Slide 16 please. So there are three items of interest that were realized during the Region III inspections at Byron and Braidwood. These items are being discussed to acknowledge the issues that were raised and to provide reassurance that

effective aging management activities will be performed

on these in

-scope components during the period of

extended operation.

The items of interest are visual examination of concrete containment structures

applicable to both Byron and Braidwood Stations, the

CRDM seismic support assembly aging mana gement applicable to both Byron and Braidwood stations and

also the Braidwood Flux Thimble Tube Inspection

Program. Slide 17 please.

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-3701 (202) 234-4433 CONSULTANT BARTON: Let me ask you. Can I ask you a question on this concrete thing? You did repair the dome. That has been repaired. The concrete and the drainage issue on the dome has been repaired.

MR. PIHA: Yes.

CONSULTANT BARTON: Now how are you observing the repair of the dome? I can understand

when you=ve got it below the dome. You can whatever

.

But what are you doing for inspection of the dome to

make sure that you don

=t initiate additional issues

on the dome?

MR. PIHA: I

=ll have either Jim or Tim.

Tim Johnson. MR. JOHNSON: My name is Tim Johnson, Braidwood Engineering Programs. To review repair on

the dome, the classification is this is the dome

surface, correct?

CONSULTANT BARTON: Correct.

MR. JOHNSON: At Braidwood.

CONSULTANT BARTON: Right.

MR. JOHNSON: The repairs we

=ve done on those about 10 years ago were cosmetic. Where was no

reinforcing steel, we basically patched them and recoated them with epoxy. We monitor them every year 56 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 and to this point they

=re performing very well. No problems.

CONSULTANT BARTON: Thank you.

MR. PIHA: The first topic I

=ll address is associated with th e visual examination of the

concrete containment structures under the ASME Section

XI, Subsection IWL, Aging Management Program.

During the NRC Region III inspection, the inspection team sought additional clarification

regarding what visual resolution capability will be

used to sufficiently quantify degradation to compare

against the quantitative acceptance criteria described

in Chapter 5 of ACI 239.3R.

To ensure that sufficient visual resolution capability will be used during the direct

and remote visual examination of concrete surfaces of

containment structures, Enhancement 4 of the ASME

Section XI, Subsection IWL Aging Management Program has been revised to update IWL implementing procedures to require that the visual resolution capabilit y be sufficient to detect concrete degradation at the levels

described in Chapter 5 of ACI 349.3R. CHAIRMAN SKILLMAN: Albert, would you tell us what you

=re doing to accomplish that? Is this a 57 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 lens system that has greater magnification and some form of calibration? Or using sonar device?

MR. PIHA: Yes, we=re using a telescope.

MR. GALLAGHER: Tim.

MR. JOHNSON: I didn=t hear that.

MR. GALLAGHER: Tim, the question Mr.

Skillman had is how do we actually do inspections?

CHAIRMAN SKILLMAN: How do you really do this to make sure it=s done properly?

MR. JOHNSON: Yes, Tim Johnson, Engineering Programs Braidwood. The enhancement

basically incorporates something we

=ve done since the

inception of IWL.

The first inspection we did was

>01. And what we did because it was basically a new requirement was the industry went down to EPRI. And EPRI sponsored and recommended the use of Meade 10

-inch telescope that was capable of resolution of the character card letters

on the test card of the code.

What we did was physically went to the top of the containment. Braidwood and Byron are very

inspection friendly if you will. There are many galleries and rooms and areas where you can get close up inspection. What we did was go up to the second 58 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 gallery which just below it is the most limiting area from a distance perspective for inspection.

What we did is actually went up and measured cracks, crack widths, put simulated lines in there, measured them. There is some indication such as form ties, nails, form nails, that type of thing and actually identified those, physically measured them. We put the telescope down from different distances and angles to make sure we understood the limitations of the

equipment and resolved those indications. That

=s we=ve done it for the three inspections that we

=ve done.

And any other equipment we used, binoculars, we would do the same thing where we don

=t have the limiting factors as much as we did with the telescope. We were

able to resolved those characters. Then when we did the inspections, we could conservatively size what we saw if you will. So we

have a good baseline and a good repeatability through the inspections from an aging management perspective.

CHAIRMAN SKILLMAN: How are those records protected? Are they images? MR. GALLAGHER: He wants to have a record for our specs.

MR. JOHNSON: The records are kept with 59 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 the surveillance. We

=ve got the original with the inspection procedures. We also have

-- Because you

=re doing on a different frequency, a five

-year frequency,

if you will, we

=ve got photographic evidence of the indications of interest if y ou will that we can do

comparisons to for the next inspection.

CHAIRMAN SKILLMAN: Thank you.

MR. JOHNSON: You=re welcome.

MR. PIHA: This additional information has been provided to the NRC staff in a letter submitted

on November 21, 2014.

CONSULTANT BARTON: The NRC inspection talked about the evidence of water seepage through

concrete and concrete leaks, concrete cracks, etc.,

etc. And it said that through discussion with the

Applicant the staff learned that this has been since

initial plant construction. The question I

=ve got is do we still have water leakage in this concrete causing additional cracks. Or is this one thing that happened during plant construction and never again is occurring

or what?

MR. GALLAGHER: I think what

=s being referred to there is the tendons tunnels at Byron.

CONSULTANT BARTON: Byron, yes.

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-3701 (202) 234-4433 MR. GALLAGHER: Okay. And basically there were some improvements that were made in the grading in those areas. So the water runoff is better

from the containment out.

CONSULTANT BARTON: Better as in?

MR. GALLAGHER: Improved.

CONSULTANT BARTON: Has it been eliminated or? MR. GALLAGHER: There is still some water that gets into the tendons tunnels. But the corrective action greatly reduced that. So t hat=s monitored as part of the structural monitoring program.

CONSULTANT BARTON: Okay.

MEMBER BALLINGER: So you think the tendons are okay.

MR. GALLAGHER: Yes.

MEMBER BALLINGER: You=

re not having more problems. MR. GALLAGHER: No, the tendons are fine

.

MEMBER BALLINGER: Okay.

CONSULTANT BARTON: Thank you, Mike.

CHAIRMAN SKILLMAN: Please proceed.

MR. PIHA: Slide 18 please. The second topic I will address is aging management of the CRDM 61 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 seismic support assembly. During the NRC Region III inspection at Byron Station, discussions were held with the NRC staff regarding the CRDM seismic support

assemblies which were not within the scope of the ASME

Section XI, Subsection IWF Aging Management Program

as part of the license renewal application. As a follow

-up to the inspection, the CRDM seismic support assembly was added to the scope of the

IWF program. Slide 19. This slide shows a sketch of the assembly called the Integral Head Assembly which includes the

CRDM seismic support assembly as a sub-element. The reactor vessel head is at the bottom of the sketch.

The items that comprise the CRDM seismic

support assembly are highlighted in green. The CRDM

seismic support assembly consists of the shield

assembly, the connecting lift rod assemblies, and

seismic tie rod assemblies.

At Bryon and Braidwood, the integral head assembly which was supplied by Westinghouse is a large mechanical assembly which sits on top of the reactor

vessel head and combines all of the equipment on top of the reactor head into an efficient, one

-package

reactor vessel head design. During plant operation, 62 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 the integral head assembly is braced to the wall of the refueling cavity by the seismic tie rod assemblies.

Slide 20.

The CRDM seismic support assembly is a sub-element of the integral head assembly. All

elements and sub

-elements of the integral head assembly were evaluated for aging management in the original

license renewal application. The External Surfaces

Monitoring and Boric Acid Corrosion Aging Management

Programs were credited in the LRA for visual inspections

of all of the elements of the integral head assembly including the CRDM seismic support assembly as a

sub-element.

During the NRC Region III inspection at Bryon, the NRC staff questioned the aging management of the CRDM seismic support assemblies which were not

within the scope of the IWF program as part of the

license renewal application. After discussions with the NRC staff, Exelon determined it was appropriate to add the CRDM seismic support assembly to the scope

of the IWF program for license renewal aging management.

As a result, the CRDM seismic support assembly consisting of the shield assembly, three lift rod assemblies and six seismic tie rod assemblies was 63 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 added to the scope of the IWF program. The external surfaces monitoring, boric acid corrosion and the IWF

programs well address aging of the CRDM seismic support

assembly. Under the IWF program, a visual VT3 examination of the CRDM seismic support assembly will be performed. Exelon has provided this information

to the staff to address this issue in a letter submitted

on August 29, 2014. The staff also asked if high strength bolts were used for the CRDM seismic support assembly.

Exelon has confirmed that there is no high strength

bolting installed and has provided this information

to the staff in a letter submitted October 16, 2014.

Slide 21.

At this time, I would like to turn the presentation over to John Bashor for the discussion of the third and final topic, the Braidwood Flux Thimble

Tube Inspection Program. MR. BASHOR: Thank you, Albert. This it em of interest comes from the difficulties Braidwood has experienced in obtaining any current data on the flux

thimble tubes during planned evolutions in recent refueling outages. The NRC reviewed this operating

experience during the September 2014 Region III 64 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 inspection at Braidwood and captured it as an item of interest. This issue was only applicable to Braidwood

since Byron has not experienced similar difficulties

in obtaining any current test data. Before I begin discussing the issue, I will first present a description of the flux thimble tube

arrangement. Slide 22 please. The flux thimble tubes are part of the in-core flux monitoring system and provide a dry tube

which allows a movable in

-core neutron detector to be

periodically inserted into the reactor core without

directly exposing the detector to reactor coolant environment. The retractable flux thimble tube is

inserted into the reactor core through the seal table, the guide tube, the reactor vessel penetration, the

lower reactor vessel internals and into a designated fuel bundle. A high pressure seal provides the pressure boundary between the flux thimble tube and

the seal table.

The flux thimble tube is a semi

-flexible, stainless steel tube sealed on one end and with an

outside diameter of 0.3 inch and an inside diameter of 0.2 inch. The length of the flux thimble tube can vary between approximately 109 feet to 125 feet 65 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 depending on core location.

There are 58 flux thimble tube core locations. The flux thimble tubes establish part of the reactor coolant boundary and are classified as

instrumentation for the ASME Code. Slide 23.

Recently, Braidwood has experienced difficulties in obtaining flux thimble tube eddy current test data due to increased resistance or restriction when inserting the eddy current probes.

This issue has been entered into the corrective action

program for resolution. To this issue, a team has been established to determine the cause of the issue and has developed

actions to prevent future recurrence. Possible causes include presence of moisture in the tube from the cleaning process, changes to the current eddy test

equipment or deformation or blockage of the tube.

To resolve the potential for residual moisture in the flux thimble tubes, the need for tube cleaning prior to eddy current testing will be evaluated. The current testing practice includes flux thimble tube cleaning, but this process may provide

a source of moisture that may in turn lead to hydraulic

block when attempting to insert the eddy current probe.

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-3701 (202) 234-4433 Industry peers with similar designs have been benchmarked. And it has been determined that cleaning may be unnecessary. A mock

-up will be created using a spare flux thimble tube to simulate the

as-installed configuration. Testing of the mock

-up will then be performed to determine the cause of the

restriction or to identify if there is an issue with the eddy current probe being able to pass through the

tube. Also a controlled extraction of a flux thimble tube would be performed if future eddy current

testing attempts are unsuccessful. The removed flux thimble tube will then be examined to identify the cause of the restriction. In addition to determining the cause of this issue, the use of improved eddy current

testing equipment has been pursued.

One improvement in the testing equipment is to use a more rigid drive cable to insert the eddy current probe into the flux thimble tube. Based on

the current process, a dummy probe is fully inserted

into the flux thimble tubes after cleaning but before eddy current testing. The dummy probe has the same

outside diameter as the eddy current probe, but it=s

driven into the flux thimble tube utilizing the more 67 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 rigid drive cable.

This dummy probe has been successful when inserted into the flux thimble tubes in recent outages.

Therefore, a more rigid drive cable from the current eddy probe may allow for full insertion of the probes.

Second improvement to the testing equipment is to use a smaller eddy current probe. An

eddy current probe with a smaller outside diameter

rather than the current 0.188 inch is being evaluated.

The smaller eddy current probe will be tested in a

spare flux thimble tube to verify that this approach

will be effective.

The final contingency corrective action is to evaluate replacing the flux thimble tubes at the larger diameter tube. A flux thimble tube with a larger diameter tube would provide additional clearance.

Slide 24 please.

Eddy current testing to monitor for wear of the flux thimble tubes has been performed since 1989 when the program was implemented at Braidwood. The frequency of the eddy current testing is based on

plant-specific testing data and is set such that no flux thimble tube is predicted to incur wear that

exceeds the acceptance criteria before this next 68 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 scheduled test.

Conservative projections of future wear are performed to determine if the flux thimble tubes remain satisfactory for continued service. This

methodology is in accordance with the NRC Bulletin 88-09 and is consistent with the WCAP

-12866 and the GALL

report. Although recent test data has not been obtained, sufficient data exists to project future wear

until the next tests which are scheduled for the spring

2015 refueling outage for Unit 1 and the fall 2015 refueling outage for Unit 2. If flux thimble tube cannot be tested and cannot be shown by analysis to

be satisfactory for continued service, then the tube

is conservatively removed from service by either

capping or replacing the tube. This approach is

consistent with the GALL report for flux thimble tubes

where eddy current testing data is not obtained.

During the most recent refueling outages, two Unit 1 flux thimble tubes were conservatively capped

and five Unit 2 flux thimble tubes were conservatively replaced because eddy current testing data was not obtained and projected wall loss was not satisfactory

for continued service until the next scheduled test.

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-3701 (202) 234-4433 For the remaining in

-service flux thimble tubes, the highest projecte d wall loss due to wear for each unit at the next scheduled test is less than 60 percent. The WCAP-12866 determined that flux thimble tubes remain functional with up to 85 percent wall loss.

And since no tubes are projected to have a wall loss

greater th an 60 percent, adequate margin exists to ensure flux thimble tube integrity is maintained until

the next scheduled test.

This issue has not affected the performance of core flux mapping. In order to provide more

assurance that the program will remain effe

ctive, Exelon has added a commitment to replace flux thimble tubes if the eddy current testing data is not obtained as required. The slide summarizes this replacement

commitment. Slide 25 please. MEMBER RICCARDELLA: Excuse me before you get off this slide. So when you say on Unit 2 seven

completed, those aren

=t seven exams. Those are seven

replacements.

MR. GALLAGHER: Yes, that

=s the replacements. That=s correct, replacements.

MEMBER RICCARDELLA: When you do replace them, do you look at the old ones that you took out 70 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 to see if there

=s been wear, see how much wear there

=s been? Do you do destructive analysis?

MR. GALLAGHER: Yes, Dr. Riccardella.

MEMBER RICCARDELLA: John.

MR. BASHOR: I will tell you it=s a very difficult process because you pull that section of the tube out. You clip it off. You pull a section of tube out. Clip it off. Very highly irradiated material

typically put in a bucket.

So you know one of the things we will be doing going forward is if we find ourselves in a situation where we have to do a destructive examination

is figuring out how we will label each piece of tube

so that we know exactly what location in the dry tube

was located. MEMBER RICCARDELLA: But the primary plan is to get to the point where you can do the eddy test.

MR. BASHOR: That=s correct.

MEMBER RICCARDELLA: Understand.

MR. BASHOR: Okay. Slide 25. In conclusion, the current implementation of the flux

thimble tube inspection program will ensure the

integrity of all in-service flux thimble tubes until the next scheduled test. In order to provide more 71 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 assurance that the program will remain effective, Exelon has added a commitment to replace flux thimble tubes if the required eddy current testing data is not

obtained.

Corrective actions have been identified and are in progress to resolve this issue. Additional

information on this item of interest has been provided to the NRC staff and letters submitted on October 31,

2014 and November 22, 2014.

I will now turn the presentation over.

CHAIRMAN SKILLMAN: John, let me ask a question. What role does the flux mapping or the

thermal couple play in your accident response

procedures? Is there any role whatever from the information from the problems that are in the thimbles?

MR. GALLAGHER: Craig, could you answer that? Did you hear the question?

CHAIRMAN SKILLMAN: What

=s the role of this in accident management? MR. INGOLD: My name is Craig Ingold. I

=m a former shift manager and senior reactor operator at

Braidwood. There is no role for import thimble flux

mapping in post-accident response. CHAIRMAN SKILLMAN: Did you look at the 72 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 thermal couples that in here, in the system, for any?

MR. INGOLD: For core exit, we used core exit thermal couples. We don

=t use the in

-core system for any exit response.

CHAIRMAN SKILLMAN: Okay. Thank you.

MEMBER STETKAR: Before you switch gears, John, I have a couple of questions. This is also Braidwood 2. The operating experience shows that

you=ve had some unexpected wear rates on a couple of

flux thimbles. One was a new one that was installed

in I think the fall of -- I=m reading notes here. So

bear with me

-- 2009. And the first inspection showed a 35 percent wear that increased to 41 percent in 2002

which is kind of an unexpected wear rate. The other one was an original flux thimble that had apparently 36 percent wear in 2008 and it increased to 57 percent in 2011 which seemed a rather

dramatic increase in the wear rate compared to the

previous ones. I=m assuming you inspected those in both the fall and the spring 2014 outages. What were

the observed wear on those two outages, the most two

recent inspections?

CHAIRMAN SKILLMAN: Gary or John.

PARTICIPANT: Give me a minute. I have 73 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 to look up that.

CHAIRMAN SKILLMAN: Okay. You can look it up. You also said the exact cause of the higher anticipated wear rates has not been determined. Do

you have any guess of why they=re wearing like that?

MR. BECKNELL: Gary Becknell, License Renewal Project Team.

The flux thimble tube inspection program is for monitoring of wear due to flow induced

vibration. And flow induced vibration is a specific aging mechanism which provides a more predictable wear

rate. Wear can also be caused by other event-driven type issues such as foreign material or

improper installation or maintenance activities. So without doing a post mortem of the tube, the actual

cause of the increased wear has not been determined. MEMBER STETKAR: I can understand perhaps installation on the new one. Actually, I=m a little more curious about why the original one suddenly showed

an increase which could be foreign material.

MR. BECKNELL: Right. That

=s sort of where we=re speculating. Now with the recently

installed one what we saw was it was installed and ran

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-3701 (202) 234-4433 which you expect to see a lot of wear during the first cycle. MEMBER STETKAR: You expect to see, yes, some wear. MR. BECKNELL: Well, the highest wear rate would happen in the first cycle as it sort of wears

itself in.

MEMBER STETKAR: Right.

MR. BECKNELL: Whereas in the past when we would install a new one, we wouldn

=t necessarily

inspect it for maybe a couple of cycles.

MEMBER STETKAR: Okay.

MR. BECKNELL: Spread it out over two or three cycles to wear rate might tie in. MEMBER STETKAR: Yes. So the average wear rate. MR. GALLAGHER: So the staff in the application and in the SER they use our words that come from the corrective action. And the corrective action

reports were written as higher than expected wear.

MEMBER STETKAR: Sure.

MR. GALLAGHER: When you really look at it, for a first cycle operations, it

=s really not higher

than expected.

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-3701 (202) 234-4433 MEMBER STETKAR: I may give you that on the first one.

MEMBER STETKAR: The one you

=re talking about. MEMBER STETKAR: The original one I

=m curious about. And also if you can find the results, I=m just curious. Apparently, they weren=t replaced because you would have said immediately AOh we replaced those, too.@ MR. GALLAGHER: Yeah. Which unit was that on? MEMBER STETKAR: Braidwood Unit 2. If you don=t have it readily available you can get back to

us. CHAIRMAN SKILLMAN: It gives me some comfortable to watch you scramble through.

MEMBER STETKAR: They=re so smooth doing this. You have to have --

(Simultaneous speaking.)

MR. GALLAGHER: We

=ll get you that when we come back from the break.

CHAIRMAN SKILLMAN: That is a drill that we went through on our review trying to figure out which is which here. I understand you

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-3701 (202) 234-4433 with that. MR. GALLAGHER: Yes, we can get them that specifically. CHAIRMAN SKILLMAN: Then let

=s proceed and when that information is available we=ll speak about it then. Thank you.

MR. GALLAGHER: Okay.

With that point, we=ve finished the discussion on the flux thimbles and

just turning it back to me to conclude.

CHAIRMAN SKILLMAN: Before we conclude, let=s -- John and I had some questions.

(Simultaneous speaking.)

MR. GALLAGHER: And that=s just where we are. We=ve finished our presentation. And are there

any other questions you have?

CONSULTANT BARTON: My questions have to do with tanks onsite. We

=ve had some experience where

we=ve seen that tanks have not been inspected but

promised to do one before I go into operation and we

=ve seen some where we experienced some leakage. And I

looked at your tanks and I don=t have a feel for how you inspect them or when you inspect them. The refueling water storage tank, the description is a

stainless steel liner within a reinforced concrete 77 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 enclosure. Now does that have some kind of an inspection program? How do you inspect it? It just seems like a configuration that

=s looking for a way

to get looked at. MR. GALLAGHER: Why don

=t Jim or Ed a nswer that question? Jim.

MR. ANNETT: My name is Jim Annett. I=m on the License Renewal Project Team. The fuel storage tank is a concrete tank with a stainless steel liner.

So it=s more than just being inside a concrete

enclosure.

CONSULTANT BARTON: Is there any inspection program for that? Have you inspected it

since initial operation? MR. ANNETT: The aging management for the liner is we use the water chemistry program. So this is similar as what is done for the spent fuel pool and

the configuration for the liner uses the same details

as we use for the spent fuel pool.

MR. GALLAGHER: So there isn

=t an inspection per se. CONSULTANT BARTON: Is the old fall

-back. I=m going to use the chemistry.

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-3701 (202) 234-4433 MR. GALLAGHER: The water chemistry and we maintain the water chemistry.

CONSULTANT BARTON: Okay. Your condensate storage tanks are similar to some other sites where they

=re resting on a concrete doughnut that

=s filled with compacted sand. And we have seen some

experience where tanks with this configuration have developed leaks. I wonder what your experience is. Do you have an inspection program for them?

And has it found any thinning of the tank bottoms if

that=s what you

=re doing? Have you done any UTs on

the tank bottoms on those tanks? MR. GALLAGHER: Maybe we can ask Paul Weyhmuller to answer that question. Paul.

MR. WEYHMULLER: Paul Weyhmuller, Exelon License Renewal Team. The tanks, the CSTs, both at Byron and Braidwood are constructed of aluminum. And as of this time, they ha ve not been inspected, the

bottoms, through a UT process.

CONSULTANT BARTON: Well, there has been some experience with tanks in this configuration that

have thin bottoms. So my concern would be if you

haven=t looked at it since initial p lant operation,

maybe it=s due for inspection.

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-3701 (202) 234-4433 MR. WEYHMULLER: Braidwood Station actually raised the walls of their tanks and with that they removed a new section of the tank bottom on the perimeter where the wall came down on top of it. And

at that time the inspections did not find any issues with wall loss. That

=s the information we have so far

on tank bottoms for CST.

CONSULTANT BARTON: Is there any plan to do inspections of the tank bottoms between now and

extended operation? CONSULTANT BARTON: The above ground tank program is a new program. The tank bottoms will be

inspected five years prior to PEO which will include ultrasonic examination as well as because of water

chemistry. There

=s one time inspection program. We

will also perform the internal visual inspections at

that time as part of that program.

CONSULTANT BARTON: Okay. Thank you.

MEMBER STETKAR: You

=re going through another tank or something else, John.

CONSULTANT BARTON: Diesel oil storage tanks. MEMBER STETKAR: Let me follow up on the CSTs.

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-3701 (202) 234-4433 CONSULTANT BARTON: Okay. This is the insulation problem.

MEMBER STETKAR: Yes. You=re going to do it? CONSULTANT BARTON: Yes. I=ll finish up on that.

MEMBER STETKAR: Okay, you can do it. CONSULTANT BARTON: The NRC reporte d I think in an inspection report that the insulation on the CST had slipped down. So part of the tanks are exposed. In addition, Braidwood Unit 2 CST above the water line has an indication. Has it been looked at?

Evaluated engineering wise? It

=s an indication

there=s a detection in the tank wall. What have you done about the insulation that has slipped down on those

tanks? MR. GALLAGHER: Okay. I think we need Paul again to help. MEMBER STETKAR: I was hoping he wouldn

=t sit down.

MR. WEYHMULLER: Paul Weyhmuller, Exelon License Renewal Team. So the first question on the

insulation that is from Byron Station. Both Units 1

and 2, the insulation has moved down approximately one 81 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 and a half inches on Unit 2 and slightly less on Unit

1. It=s in the planning process now to restore that

area so that the insulation does go all the way back

up to the roof.

It is thought it

=s due to the stainless steel banding clamps that go around the circumference of the tank that hold the lagging in place. There is some looseness in some of the straps which allow it

to slide down that distance.

CONSULTANT BARTON: Well since the insulation has dropped, there has been exposure to the

environment. And you can get water down between the

tank itself and the insulation since the tank is not

completely covered. MR. WEYHMULLER: The tank group overhangs the side wall of several inches, but with blowing rain there could be that possibility. When it was being reviewed as far as the issue from the access ladder

a visual observation was made of the tank wall in that area. In comparing it to the tank roof, the tank roof

is made of the same material, aluminum, and it is not insulated or coated in any way. And the surface

condition was found to be similar to that of the --

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-3701 (202) 234-4433 water trapped between the insulation and tank. Since you had a gap, you could get rain sometimes coming in parallel. You could get water on the tank surface down

between that and the insulation. And that=

s what I=m concerned about. What about the tank surface below

inside the insulation below?

MR. WEYHMULLER: Our aging management program will remove insulation in 25 different areas,

one square foot areas. In particular, we have

committed to do at least four areas where there have

been penetrations of possibility of water intrusion

to inspect that area both visually and with a exam for

cracking. CONSULTANT BARTON: Has that been done yet or is that down in the future sometime? MR. WEYHMULLER: That is out in the future at this time.

CONSULTANT BARTON: So you don

=t really know what the condition is right now of those tanks. MR. WEYHMULLER: The roof of the tank itself is exposed to the weather. So we can see that

as well as the inner welds.

CONSULTANT BARTON: That=s different. The roof is exposed to the environment. How about 83 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 what=s trapped between the insulation and the tank wall is what I=m concerned about.

MR. WEYHMULLER: There

=s not been any examinations under the insulation at this time. The

tank material though is --

CONSULTANT BARTON: Aluminum, right?

MR. WEYHMULLER: Yes. That is correct. And it is of a grade that is not susceptible to cracking.

We have committed to do the inspection for cracking

as part of our aging management program. CHAIRMAN SKILLMAN: What is the chemistry of the insulation? What=s the insulation?

MR. WEYHMULLER: That

=s why we did make the commitment. The bottom section, the bottom two to four feet, is made of foam glass material. And it was found that it was halide chloride-free. The upper regions of the tank we could not find the paperwork that would satisfy that it was halide or chloride

-free. So therefore we conservatively said there was a possibility it could contain one or more of those

materials. And therefore we put in that we would

inspect for cracking on the tank walls.

MEMBER BALLINGER: How tight is the insulation?

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-3701 (202) 234-4433 MR. WEYHMULLER: How tight is it?

MEMBER BALLINGER: Yes.

MR. WEYHMULLER: It has a c orrugated lagging cover and then stainless steel banding straps.

MEMBER BALLINGER: On the interface between the aluminum and the insulation, how tight is

that? MR. WEYHMULLER: It=s pulled up tight to the tank.

MEMBER BALLINGER: So it

=s real good crevice.

MR. WEYHMULLER: Yes.

MEMBER BALLINGER: That=s the good news.

That=s also the bad news.

CHAIRMAN SKILLMAN: It

=s a 34 inch belt loop for a size 36 pants.

MEMBER BALLINGER: I

=ve been inspecting it for pitting and other kinds of things.

MR. WEYHMULLER: Right.

MEMBER BALLINGER: And I don=t know what the aluminum alloy is. Does anybody know the

designation? MR. WEYHMULLER: I can find that. I have that.

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-3701 (202) 234-4433 MEMBER BALLINGER: Because some of these materials are --

MR. WEYHMULLER: Very susceptible.

MEMBER BALLINGER: And chloride can come from just about anywhere. MR. GALLAGHER: But I think as Paul indicated we do have it in our corrective action

program. CONSULTANT BARTON: You haven

t looked at this. So there

s a possibility it could have something

going on with the aluminum.

MEMBER BALLINGER: It

=s a lot easier to see pitting and stuff like that than it is to see

cracking. CONSULTANT BARTON: Right. I guess our concern is are you going to --

MEMBER POWERS: Depends on the crack.

MR. GALLAGHER: Yes. The assessment was done at the top of the tank and our aging management will address the full tank. So that

=s a challenge to

say should we be looking at this sooner than later.

MEMBER POWERS: Exactly.

MR. GALLAGHER: And we

=ll take that challenge.

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-3701 (202) 234-4433 MEMBER BALLINGER: Okay. MEMBER STETKAR: Don=t sit down. I

=m not done. MEMBER BALLINGER: Is the inspection going to be from the inside of the outside?

MR. WEYHMULLER: The inspection is done from the outside of the tank. We have to remove the

lagging and insulation. MEMBER BALLINGER: You have to remove the lagging.

MR. WEYHMULLER: Yes, that=s correct.

MEMBER STETKAR: A couple of questions. One is just for clarification because I

=m not capable

of reading everything that=s sent to us. I did find

something that was quoted in the SER as part of a response to an RAI. So I have to qualify it that way.

It=s perhaps thirdhand information.

You mentioned inspection of 25 locations being in at least what I read said 25 locations for both tanks combined per site which could mean 12 on

one and 13 on another. Are you actually going to

inspect 25 locations on each tank?

MR. WEYHMULLER: No, the inspection programs, because the tanks are right next to one 87 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 another, you would take one of the tanks for each evolution.

MEMBER STETKAR: But we

=ve already now confirmed that they

=re not identical because they had different wetting histories. And indeed the license

renewal guidance, I was going to ask the staff about

this because they accepted it. But the guidance says each tank. It doesn=t say tanks that are close to one another and mostly the same. But you do clarify that it

=s not 25

per tank. So we=ll ask the staff about that. The other question I had is you discovered this slipped down insulation in August of 2012 and you

said you=re still planning on how to repair it. Why does it take more than two and a half years to figure out how to repair this? And don

=t tell me you have

to do it during an outage because I can stand there and look at the outside of the tank. So why is it taking

and why are you still planning this?

MR. GALLAGHER: Yes. I think our assessment was that because the configuration we have

on the bottom insulation and the inspections that we re done where the gap is and the overhang and the condition

of the roof that it

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-3701 (202) 234-4433 on at this point. And we just have to -- CONSULTANT BARTON: So it has low priority in your corrective action system.

MR. GALLAGHER: Well, it=

s a activity that we have to prioritize with all the other activities that we have. And we do have it in our aging management

program that will be done on an ongoing basis.

MEMBER STETKAR: Yes, but that=s in like 2026. MR. GALLAGHER:

Well, the five years before PEO.

MEMBER STETKAR: I mean 2021.

CHAIRMAN SKILLMAN: I guess I

=m surprised that A&I and the boiler machinery inspection hasn

=t forced this a long, long time ago. I can recall being

forced to do tank bottom inspections much against my

will. You=

ve got a submarine and you

=re going to look

at tanks. But it was really A&I and the boiler machinery inspection portion of our insurance policy that forced us to do that. These are big machines with real consequences. I=

m surprised that that hasn

=t been an action item for the site based on your A&I policy.

MR. GALLAGHER: For the safety tank 89 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 bottoms, yes.

CHAIRMAN SKILLMAN: Yes. But hey. I=ll leave that as it is. John or other John, Chairman, any further questions?

MEMBER STETKAR: No, no, I=m done on the CSDs. We=ll give it back to John.

CONSULTANT BARTON: The only other thing I had the same question on diesel oil storage tank, the 50,000 gallon tanks that are in the auxiliary

building. Is there some kind of inspection program for them? Are they freestanding? Are they buried in concrete in the auxiliary building? I mean, what

=s the configuration of them and have they been looked

at? MR. GALLAGHER: Paul.

MR. WEYHMULLER: Paul Weyhmuller, Licen se Renewal. There

=s two 25,000 gallon tanks on Unit 1

and a 50 on Unit 2 for both stations. They

=re freestanding tanks sitting on a concrete pedestal or slab. They are inspected on a 10 year frequency.

They=re drained, cleaned and then a visual inspect ion is performed. So they have been inspected.

CONSULTANT BARTON: Thank you.

CHAIRMAN SKILLMAN: John.

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-3701 (202) 234-4433 CONSULTANT BARTON: I

=ve got some other items. CHAIRMAN SKILLMAN: When you

=re done I

=ve got a couple more. We=ve got a few more minutes.

CONSULTANT BARTON: All right. Other than Braidwood essential service cooling pump, I couldn=t find any reference to looking at the retaining

dike. Did it ever get looked at because of the

materials of the dike around the pond? Is it e ver inspected? Have you looked for degradation of the

materials that make up that dike? MR. GALLAGHER: This is the dike around the whole pond. CONSULTANT BARTON: Around the whole pond.

Is that ever looked at?

MR. GALLAGHER: Paul Cervenica.

MR. CERVENICA: My name is Paul Cervenica.

I=m a member of the License Renewal Team. The dike

surrounding the pond is inspected every three months by the site and they look for general condition degradation. And on a 12th month basis, a professional

engineer comes in and does a survey and reports on the

condition. CONSULTANT BARTON: Thank you, Paul. Now 91 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 the essential service cooling pond has a triangular excavated area within the cooling pond itself. And

it=s the ultimate heat sink for the plant. Is it e ver looked at? Does anybody ever go down and look at the

structure of it? MR. GALLAGHER: I think that

=s Paul again on that one. MR. CERVENICA: Paul Cervenica, member of the License Renewal Team. There are soundings done on the essential service water cooling pond. Soundings

at the bottom and the slope walls in order to confirm that the volume required by tech specs is maintained.

That=s done every 18 months.

CONSULTANT BARTON: Thank you, Paul.

The next area that is cathodic protectio

n. It was noted that the system has improved, but there

=s less than 50 percent of the site adequately protected.

And experience has shown that at both sites corrosion has occurred due to the lack of protective coating.

I think you people said that you=re going to improve the cathodic protection system. Is that now complete?

Is it functioning? And how effective is it?

MR. GALLAGHER: Dylan.

MR. CIMOCK: Dylan Cimock, License Renewal 92 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 Team. The cathodic protection system is improving and plans are in place that includes investigation of means

by which to improve it which includes replacement of existing anodes and insulation of new anode beds. The configuration of how to do that and the exact means is still being investigated. But that is our intent.

It=s to improve the overall coverage cathodic

protection of the station.

CONSULTANT BARTON: Since you don=t have a lot of piping covered by it, what

=s your schedule

to complete it and get a system operating so you can

assess the effectiveness of it? MR. CIMOCK: The intent would be to complete that hopefully five years prior to the period

of extended operation which would be consistent with

allowances provided in the ISG.

CONSULTANT BARTON: In the meantime, do you do any piping inspections that=s not covered?

MR. CIMOCK: Yes, significant piping inspection have been performed. And while it might be characterized as not protected, it does receive some protection. It just may not be meeting established

acceptance criteria. That criteria is applied

universally to all piping.

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-3701 (202) 234-4433 MEMBER BALLINGER: That=s the minus 830.

MR. CIMOCK: Eight fifty, correct.

MEMBER BALLINGER: Eight fifty.

MR. CIMOCK: Right. So it is possible to achieve adequate protection without that negative 850.

So that is something that is being investigated as well. While we had seen some degradations, it has been

quite minor I would characterize it as. CONSULTANT BARTON: How do you do it?

When you=re doing some maintenance and you

=re digging a hole and you look at the piping? Or is there anything

planned to go and look at specific areas of the piping

in the plant? MR. CIMOCK: Yes. Both stations are implementing the NEI 09

-14 initiative on buried piping.

So they have strengthened their piping. Excava ted significant portions, approximately like 300 feet for example of condensate piping at the Braidwood Station

has been excavated. Approximately 300 feet at Bryon

Station for service water. CONSULTANT BARTON: How aggressive is the soil at the site?

MR. CIMOCK: Not very aggressive from the soil samples that have been taken.

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-3701 (202) 234-4433 MEMBER BALLINGER: Can you interrogate your cathodic protective system? I presume that most of the piping is coated.

MR. CIMOCK: That=s correct.

MR. JOHNSON: And so can you interrogate your protective system based on the current that

=s being supplied to identify potential sources where you

think you

=re providing protection and it

=s not working

anymore? MR. CIMOCK: Yes, we do maintenance and surveillance on rectifier availability so we can

identify where rectifiers are out of service and not providing adequate protection. But the stations have

also done alternative cathodic protection assessments.

It=s called an APEC survey, aerial potential earth

current.

MEMBER BALLINGER: Yes.

MR. CIMOCK: And that has shown there are areas that I guess are more or better protected than

others. MEMBER BALLINGER: So you can rank order.

You have rank ordered systems in terms of susceptibility which then allows you to establish what

to do next.

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-3701 (202) 234-4433 MR. CIMOCK: Yes.

CONSULTANT BARTON: You

=ve got some unprotected carbon steel piping embedded in concrete

at the service water structure. Now do you ever go look at the piping internally? I know you can

=t look at it externally because it

=s in concrete. Do you ever

go look inside and see if there

=s anything going on

in that piping?

MR. GALLAGHER: Dylan.

MR. CIMOCK: Dylan Cimock, License Renewal Team. Piping is not inspected internally and as you

point out it can

=t be gotten to externally as well.

They do other surveillances because it

=s safety-related

piping like flow and pressure tests on the piping.

And any leaks that would arise you would see based on the pressure of the system. And that=s

not been seen eith er. And flow rates have been adequate. They have done external excavations of that

reinforced concrete section. You can

=t get to the

pipe, but you can inspect its backfill. And they

inspected that and found that to be fine as well. MEMBER BALLINGER: B ut again that pipe is also wrapped. CONSULTANT BARTON: No, it

=s in concrete.

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-3701 (202) 234-4433 It=s unwrapped carbon steel pipe inside concrete.

CHAIRMAN SKILLMAN: Inside pipe. It

=s embedded piping.

CONSULTANT BARTON: Embedded piping in concrete. And how do you know w hat=s going on inside that piping?

MEMBER STETKAR: Part of it below groundwater level.

CONSULTANT BARTON: Pardon?

MEMBER STETKAR: Part of it below groundwater level.

CONSULTANT BARTON: Right.

MEMBER BALLINGER: Well, you could pig it to see it effectively.

MR. CIMOCK: That

=s been investigated.

Right now, they

=re trying to find means by which to

do because it

=s a very long length of piping with obstructions along the way that would prevent that.

So it is being investigated as part of their NEI initiative and they=re trying to find a way of doing that under the mitigative actions performed in that

piping. CONSULTANT BARTON: I=

ve got one other one here. The inaccessible power cables not subject to 97 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 50.59 environmental qualification. At Byron Unit 2 based on the site history, especially cable bolt OB 2 at Byron Station. What is the status of work that

was planned to limit surface water intrusion into that

wall? MR. GALLAGHER: John Hilditch.

MR. HILDITCH: John Hilditch, License Renewal Project. That particular wall had water intrusion from a hand hole. That hand hole was modified

back in July to make it more water resistant. The ground was graded. So the water wouldn

=t flow on top

of there. And there

=s been some significant rain

storms since. And the water intrusion problem is no

longer there.

CONSULTANT BARTON: How do you know? Do you now periodically inspect?

MR. HILDITCH: Yes.

CONSULTANT BARTON: Okay.

MR. HILDITCH: And the scoping is inspected periodically.

CONSULTANT BARTON: I think that=s it.

CHAIRMAN SKILLMAN: Thank you, John. I=d like to ask a few more questions. I realize we

=re over our break time. But I think when I

=m completed we

=ll 98 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 be done with this portion of the session.

Bolting integrity program, it=s B.2.1.9.

There are three enhancements on Byron and two enhancements on Braidwood. And I

=m wondering why there is a difference in enhancements for bolting integrity

between the two stations please.

MR. TAMBURRO: Pete Tamburro, License Renewal Team. The difference in enhancements is because some of the submerged bolting that are required

to be -- that will be inspected there were no existing activities to inspect them. So we had to initiate

existing activities to inspect those submerged bolting s

at Braidwood. CHAIRMAN SKILLMAN: Thank you, Pete.

Okay. I=ve got one or two more. This has to do with reactor vessel surveillance and this is at Braidwood.

The second enhancement will test on specimen capsule

that has been irradiated to a neutron fluence of one to two times the projected peak neutron fluence at the

end of the PEO and will submit a summary technical report

to the NRC for each reactor vessel within one year of

the receipt of the renewed license.

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-3701 (202) 234-4433 for that information in a timely fashion. At least, that=s the way I

=m internalizing the way this inspection

is written. It seems like we=re really not going to

do it until we have the license. And when we have the license only then we

=ll go ahead and expose the surveillance specimen to the levels that we need to

to predict the 20 year future.

MR. TAMBURRO: On that, Mr. Skillman, we had in our current licensing basis, the 40 year lice nse life, done all the testing necessary for it.

CHAIRMAN SKILLMAN: The 40 year license.

MR. TAMBURRO: Yes. And those specimens actually for each unit, for each of the four units,

were exposed to the one to two times the exposure levels

and were removed and are currently sitting in the spent

fuel pool at the four stations. We thought when we put our application in that we would then just need to test them before we

entered the period of extended operation. The staff

pointed out to us that it could be interpreted that in the Appendix H provisions. Once you get a renewed

license those specimens would be required specimens.

They weren

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-3701 (202) 234-4433 license they are. MR. GALLAGHER: And then you

=re on the one year time clock unless you get a schedule change from the director of NRR. We took a look

-- We didn=t view it that way when we put the application in. We took

a look at the staff

=s position and agreed with them that that was correct. So we made that commitment.

So it was very clear that we would follow Appendix H and get those testing done within a year of getting

the license.

Now we=re not waiting for that obviously because these tests take some time. And we actually have a contract already cut and it

=s to Westinghouse.

Those activities are going to start beginning of next year 2015. And throughout 2015, those four samples

would be tested.

We don=t anticipate getting our license until the end of 2015. So we would be well completed

before it=s needed. CHAIRMAN SKILLMAN: Thank you, Mike.

That concludes my questions. Let me -- MR. GALLAGHER: I think we have the answer to Mr. Stetkar=s question on the wear.

CHAIRMAN SKILLMAN: Okay.

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-3701 (202) 234-4433 MEMBER STETKAR: I knew we could drag it on long enough for you to find it.

MR. MATTHEWS: Sorry. John Matthews, Braidwood Station Plant Engineering. So the question was in Unit 2 there was an original thimble that had

higher than expected wear rates that showed up. And the question was what happened subsequent to that

inspection.

The following inspections showed that cycle to cycle wear had gone back to its normal rate at three percent. However, that was capped out and

replaced at later outages. MEMBER STETKAR: Okay. So that one=

s been capped and replaced. How about the new one?

MR. MATTHEWS: The new one, subsequent eddy current testing showed that the wear rate had

stabilized. MEMBER STETKAR: Wear rate is stabilized.

Thank you.

CHAIRMAN SKILLMAN: Okay. For this portion of the meeting, let me check with my colleagues.

Dr. Riccardella, any further comments? MEMBER RICCARDELLA: No further comments.

Excellent presentation.

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-3701 (202) 234-4433 CHAIRMAN SKILLMAN: Okay. Dr. Ray? Dr.

Powers? John Stetkar? John?

MEMBER STETKAR: Nothing.

CHAIRMAN SKILLMAN: With that, I=m going to claim a 14 minute break. Please return at 10:30

a.m. on that clock. Off the record.

(Whereupon, the above

-entitled matter went off the record at 10:17 a.m. and resumed at 10:31 a.m.)

CHAIRMAN SKILLMAN: On the record.

Ladies and gentlemen, we

=re back in session. And for

this portion of the meeting, I

=m going to call on Lindsay

Robinson, our project manager. Lindsay.

NRC STAFF PRESENTATION SER OVERVIEW MS. ROBINSON: Great. Thank you, Chairman. Committee Chairman, Members of the ACRS, my name is Lindsay Robinson. I

=m the Project Manager

for the License Renewal of Byron Station Units 1 and

2 and Braidwood Station Units 1 and 2.

Before I get started, I

=d like to introduce the people at my right and left. Nestor Feliz

-Adorno, he was the lead for the Braidwood 71002 inspection.

He=s a Region III Senior Reactor Inspector. I have

Mel Holmberg. He was the lead for the Byron 71002

inspection. He is also a Region III Senior Reactor 103 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 Inspector. He had Dr. Allen Kiser. He is DLR

=s Senior Technical Advisor. And then we have Daneira Melendez.

She=s a Project Manager. She will be assisting me

with the slides today.

We=re here today to discuss the review of the Byron and Braidwood License Renewal Application as documented in a safety evaluation report with open items which was issued on October 30, 2014. Seated in the audience are members of the technical staff who

participated in the review of the license renewal application and conducted the onsite audits. Next

slide. We=ll begin the presentation with the general overview of the staff

=s review. Next, Mel and Nestor will both present the activities and inspection

observations from the 71002 inspections for Byron

Station and Braidwood Station. We will also discuss some issues that arose during the 71002 inspection that are not reflected in the SER open items. These issues and their resolutions

will both be documented in the final SER. We will then present the main sections of the SER and any associated item. Next slide.

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-3701 (202) 234-4433 The Byron

-Braidwood License Renewal Application is a dual site application consisting of four reactors in two geographical locations.

Considering the scope of the review, the staff found very few technical differences between the two sites.

And where those differences did occur in either the site and/or unit the staff made a point to clearly

identify where those applicable differences were per

that site and/or unit.

The staff did conduct several onsite audits and inspections at each site. During the scoping and

screening methodology audit, the audit team reviewed

the Applicant

=s administrative controls governing the

scoping and screening methodology and the technical

basis for selected scoping and screening results.

The staff also reviewed selected examples of component material and environmental combinations,

reviewed information contained in the Applicant

=s corrective action program relevant to plant

-specific,

age-related degradation and reviewed quality practices

applied during development of the LRA and the training of personnel who participated in the development of the LRA. There was also the audit where it documented

in a report dated March 14, 2014.

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-3701 (202) 234-4433 During the aging management program audit, the audit team examined the Applicant

=s aging management programs and related documentation to verify

that the Applicant

=s claims of consistency with the

corresponding AMP in the GALL report. The staff

reviewed 45 aging management programs and documented

the results in a report dated March 13, 2014.

Mel and Nestor will discuss the activities of the 71002 inspection in a few minutes. Next slide.

In addition to the audits and inspections already mentioned, the staff conducted in

-depth technical reviews and issued requests for additional

information or RAIs. The staff performed its review of the Byron and Braidwood license renewal application and issued the safety evaluation re port with open items on October 30, 2014. Pending the resolution of the open items and outstanding RAIs, our plan is to issue

the Bryon and Braidwood final SER in April of 2015. We will now direct the presentation to Mel and Nestor to discuss the Region III 71002 inspection.

Next slide.

MR. HOLMBERG: Thank you, Lindsay. Good morning. My name is Mel Holmberg. I

=m a Senior

Inspector in the Division of Reactor Safety in our 106 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 Region III office. That

=s in Lisle, Illinois. And I was also the lead for the Byron inspection.

MR. FELIZ

-ADORNO: Good morning. I

=m Nestor Feliz

-Adorno. I was the Team Leader for the

Braidwood inspection.

MR. HOLMBERG: So for the inspections we conducted, this is done under our Inspection Procedure

71002. The purpose is to verif y that the Applicant has adequate programs that either planned or in place to implement age management of the structures, systems and components within the scope of the rule. And our inspection is done to confirm that these components

will be adequately maintained consistent with existing

safety evaluations in the license renewal program.

The specific scope that we conducted at Byron included review of 36 of the 45 age management

programs. Twenty-four of these were based on existing

programs. Twelve were new. We also looked at four

of the five regulated events, four of the non-safety

systems that were scoped out of the rule.

Turning to Braidwood, our inspection scope was 31 of the 44 age management programs. Twenty

-three of those were existing programs and eight were new.

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-3701 (202) 234-4433 and three non

-safety systems, structures or components that were scoped out of the rule.

Each of our inspections comprised of two weeks of onsite inspection. And our teams reviewed the site documents related to the regulated events and

including at the non

-safety related structures or

components whose failure could potentially affect

safety-related components. And this review was done

to confirm the Applicant had applied the required

scoping and screening methodology.

At each site, we also completed walkdowns on over two dozen systems, structures or components

within the scope of license renewal. And these were

done to assess the adequacy of the license renewal

boundaries that have been established, evaluate the

material condition and conformance with their

application and GALL. This activity enabled us to

evaluate if the AMPs would be successful in managing

the aging effects for systems, structures and

components within the scope of the rule.

The inspections are Byron and Braidwood were done in series. This enabled the region to assess each plant individually and then allowed us to increase the number of programs reviewed. And then issues 108 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 identified at one site were assessed for applicability to the other site. Our final exit meeting was conducted following the end of the second onsite inspection which

was Braidwood. Next slide please.

Based on the inspections of the various areas that we were able to observe during our inspection time onsite and these were areas that included both units at each side, we concluded the overall material

condition of the structures, systems and components

we observed was good. CONSULTANT BARTON: I=

m glad you addre ssed that. This is the first time I

=ve ever had to ask you

that question of the 60 something plants I reviewed.

(Laughter.)

CHAIRMAN SKILLMAN: How do you define good please? (Laughter.)

MR. HOLMBERG: Actually, we do have a way to assess that. During our inspections, issues that

are of any type that we can across that looked like

conditions adverse to quality, the licensee promptly put into their corrective action program. Issues were

considered minor in nature if they didn

=t rise to th e

level of concern that prompted operability evaluations.

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-3701 (202) 234-4433 And so you

=ve got an initial swag on things as to whether or not they

=re significant if they don

=t prompt

some sort of concern for operability right off the bat.

So you=ve got a rough guide.

But other than because our focus was on license renewal, we were making sure we were not seeing

things that we expected them to pick up in their normal

routine programs. CHAIRMAN SKILLMAN: Thank you. I asked that question because in my experience the turbine building is normally clean and shiny. The

radiologically controlled areas are generally clean

and shiny. The entrance.

MR. HOLMBERG: The epoxy floor plant and all that.

CHAIRMAN SKILLMAN: Epoxy floor plant, lots of light. A lot of dazzle. But when you take

the time to go to the turbine building sump or the auxiliary fuel handling building sumps or the areas that are less traveled, very often you find a very

different physical condition, material condition.

CONSULTANT BARTON: Out

-buildings is a good example. That is also. CHAIRMAN SKILLMAN: And so my question is 110 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 as you get further out into the areas that are not as keenly maintained did you find, if you will, an

increasing number of the need for entrances into the

corrective action program.

MR. HOLMBERG: The total I believe was a little over a dozen condition reports for Byron. I

don=t recall --

MR. FELIZ

-ADORNO: Similar for Braidwood.

MR. HOLMBERG: Braidwood. So just to give you a sense of the numbers as to their locations, they

varied. I would say your general sense is correct.

Obviously, the areas that are easy to travel and well traveled are generally the ones that you expect and do not see the types of issues that you can find in

the other areas.

I guess I don

=t have a good answer off the cuff for you on that. CHAIRMAN SKILLMAN: Circ water pump house and the cooling pond pump house would be areas that

I would be curious about whether they were clean and neat, whether they were rusting apart or whether they looked like they really looked like they got some

preventive maintenance. MR. HOLMBERG: Yeah, we did have a couple 111 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 of issues and I=ll have to look up the specific ones I believe from one of those areas. And I can get back

to you with the specific item we identified in those

areas. I have five team members working for me.

So out of those areas we walked down, I have a lot of other eyes out there. Some of it I don

=t have direct

observations to rely back to you.

CHAIRMAN SKILLMAN: I don

t need any additional information. You pretty much answered my question. What you

re saying is what is inspected and what is seen on a regular basis is in pretty good shape.

As you get further and further away from the main

tourist paths, things are not as highly maintained. MR. HOLMBERG: I would say that

=s a correct assessment.

CHAIRMAN SKILLMAN: That

=s fair enough.

Okay. Thank you.

MR. HOLMBERG: During our inspections, we did identify issues of concern with respect to current

and planned programs. These resulted in application changes for some of the AMPs. For example, during our Byron inspection, the team identified some issues that prompted the application revisions to four of the AMPs, 112 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 including the ASME Section XI, ISI AMP.

For this particular AMP, the Applicant=s description contained in Appendix A -- that=s the UFSAR supplement -- did not include inspections of small bore lines subject to thermal fatigue. And what I

=m talking about is the MRP

-146 program. That

=s an industry

program that was not included in their description and

is used to manage thermal fatigue.

Additionally, Appendix B did not identify the 10 CFR 55a limitations, modifications and augmentations that go along with Section XI. So that was another issue that was identified for that program.

CONSULTANT BARTON: That protection system aging management program, I don=t know if you look at that. But in reading the AMP, the Applicant

=s application for license renewal, I wasn

=t thrilled about the extent of that program. Subsequently, I saw that the Applicant submitted a letter that included

14 enhancements to that program. Is the NRC now satisfied with that program?

MR. HOLMBERG: I think I=m going to turn that to Lindsay. Is this something that was an RAI? CONSULTANT BARTON: I didn

=t mean to catch you off guard.

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-3701 (202) 234-4433 MR. HOLMBERG: I

=m sorry. Was this in response to our inspection?

CONSULTANT BARTON: No, this was the application. I read the aging management program on that system. All right. And I was not too happy that that was an adequate program that was presented. And then I found in further review of the documents produced

by NRC that you received a letter on August 2014 that the Applicant had described 14 enhancements to that

program. So I guess my question is --

MS. ROBINSON: Mr. Barton, we actually have Bill Holston who can answer. CONSULTANT BARTON: Are you now satisfied with that AMP? MR. HOLSTON: Yes. My name is Bill Holston. I

=m a Reviewer in the Division of License

Renewal. And the aging management program originally

submitted was reasonably typical of the plants prior

to the issuance of ISG

-2012-02. With the issuance of

ISG-2012-02, that raised the necessity for a lot of

extra enhancements. Basically what we did was we went into NFPA-25 which is the inspection standard for fire water systems, selected about 16 inspections and tests that 114 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 we felt were representative of tests and inspections that were revealed, issues of loss material flow blockage. So that=

s why the extra enhancements. And

we are, yes, at this time satisfied with the

enhancements they=ve put in that program.

CONSULTANT BARTON: Thank you.

MEMBER STETKAR: Let me ask. I was going to wait, but since you mentioned an ISG. This is sort of a general question. Anybody up there can field it.

I guess I was surprised at the number of RAIs that were issued as a result of the audits and inspection s

on these units given the time we are into the license

renewal process.

This is more recent ones that we=ve seen that have been fairly minor in terms of audit inspection

-- I don=t want to call them findings

-- RAIs resulting from those activities. And I know this was done under GALL Rev 2, but GALL Rev 2 has been out since 2010 and

people knew what was coming well before that. So it

can=t be GALL Rev 2.

Is it primarily due to the additional clarifications from interim staff guidance that was

issued since GALL Rev 2 in the 2011-2012 time frame?

Or do you have any sense of that?

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-3701 (202) 234-4433 MS. ROBINSON: Sir, I=d just like to get a little more clarification on your question that you

=re trying to ask. MEMBER STETKAR: Okay. What I

=m trying to ask is if I look at these audits and inspections compared to other audits and inspections that we

=ve seen over the last two or three years for license

renewals those other audits and inspections typically

identify some issues that are raised in the SER to the

level of RAIs, but only a relatively small number.

Byron and Braidwood in comparison has quite a large

number of them.

And I=m curious why. Is it because the Applicant --

Is it something that the Applicant wasn

=t doing or is it something that they didn=t understand

in terms of evolving staff guidance?

MS. ROBINSON: So I can actually discuss the portion of actual RAIs following audits and

inspections. I can tell you that based on the RAIs

--and the Applicant has discussed those issues that

came out of the inspection --

I would say yes. That

=s not as typical as what we

=ve seen in other applications.

I would actually though say that the number of RAIs that came out of the audits -- and we had to 116 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 do that both at Bryon and at Braidwood

-- in terms of that reference we are looking at the two different geographical locations. And to some degree that

=s another reason why maybe you might have seen there are

more RAIs. But if we look at it from the perspective of we had to do two audits, one at Byron and one at Braidwood, then we had to do two inspections. And then

-- I am acknowledging that, yes, the number of the RAIs in the inspection is not as common.

But I actually was looking at other applications. And the fact that we had four units I

actually saw that we were on par, if not slightly less,

than some other applications.

MEMBER STETKAR: Okay.

CONSULTANT BARTON: RAIs per unit.

MEMBER STETKAR: RAIs per unit. What was your sense, John? CONSULTANT BARTON: There=

s a lot of them.

MEMBER STETKAR: There are a lot of them and a lot of them were issued

-- But a lot of them there was a single RAI that was issued for all units. So

if I count RAIs per unit, that=s four.

MS. ROBINSON: I=m not looking at an RAI 117 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 per unit perspective because I do agree that the majority of the RAIs that were issued were applicable

to all four units. I

=m looking at it from the

perspective of other audits that have, you know, the AMP audits that occur typically you come out of those

AMP audits with 100, slightly more than 100, RAIs.

You look at the number of RAIs that came out of us following the Byron audit which was the first

AMP audit that we conducted and we did not have close

to 100 RAIs.

MEMBER STETKAR: Well, when you say typically, yes. When I joined the Committee seven

years ago, there were a lot issued. But I=m talking about the more recent experience over the past two or three years as things have stabilized quite a bit and as people have become more familiar with the guidance in GALL Rev 2. A lot of the early ones was the guidance, GALL was in the state of transition. So the staff was asking RAIs about kind of looking forward to where Rev

1 was transitioning into Rev 2. So I used to see a lot related to those types of issues. But GALL has not been stable.

MS. ROBINSON: Right. And I think a lot of the RAIs that we had coming out of the AMP audit 118 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 were to a large degree clarification RAIs, you know, basing information that was in the LRA.

MEMBER STETKAR: Well, you haven

=t answered my question. But thanks.

MS. ROBINSON: Okay.

MEMBER STETKAR: We should go on in terms of getting into the more technical things.

CONSULTANT BARTON: But you=re right.

The interim staff guidance has got a bunch of --

MEMBER STETKAR: The interim staff guidance, what I

=m trying to push at is are we now in

an evolving second range. Five years ago we used to see a lot of RAIs that were kind of hunting for the

transition between GALL Rev 1 and GALL Rev 2.

CONSULTANT BARTON: Two, right.

MEMBER STETKAR: My sense quite honestly is now we

=re in a range where the licensees are hunting

for the transition between GALL Rev 2 and GALL Rev 3

as embodied by evolving interim staff guidance. And

I=m trying to get a sense of where the staff is on that.

MS. DIAZ: Yoira Diaz. What is meant by the difference between ISGs and in these is we had

several ISGs that evolved from the GALL Rev 2 and were

each in between these plans that you

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-3701 (202) 234-4433 latest. And some of these ISGs that we re in the draft form they were finalized by the time that Byron and Braidwood was issued, the LRA was issued. So some of

these IRAs could have come from the amount of ISGs that

we had as we evolve from Rev 2 and the subsequent

guidance that the staff has issued.

MEMBER STETKAR: Thank you. That helps.

That at least gets it on the record.

MR. HOLMBERG: Okay. I

=m basically almost done with my part. I was in the middle of the second bullet there. We were just finishing up

application changes.

CONSULTANT BARTON: All right. Sorry we messed you up.

MR. HOLMBERG: Applicant changes to some of the AMPs that were prompted by inspection. Those have been addressed. The Applicant has submitted

changes to the LRA for those.

I=m going to turn it over next to Nestor who will be discussing additional inspection concerns

that prompted further staff reviews.

MR. FELIZ

-ADORNO: Thank you, Mel. The team identified three issues requiring further NRR review. With the respect to the first item, the te am 120 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 found that the CRDM seismic supports were not included in the scope of the AMP. The Applicant subsequently revised the LRA to include the CRDM seismic support assemblies in scope and included the CRDM support components in the aging management review t able 3.5.2

tab 3. However, during the Headquarters= review, the staff identified concerns with the bolts which Lindsay will discuss later in this presentation. And

this issue applies to both Byron and Braidwood.

The second bullet refers to additional inspections of areas of concrete deterioration.

Specifically, during the Byron inspection and confirmed

during the Braidwood inspection, the inspectors noted

the Applicant planned to inspect for concrete deterioration at a distance with the use of a telescope

. The inspection team expressed concern regarding the Applicant

=s visual resolution capability to be used during the period of extended operation to

quantify degradation based on the quantitative acceptance criteria described in Chapter V of ACI

349.3R. This issue applies to all four units at

Braidwood and Byron.

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-3701 (202) 234-4433 thimble inspection. During the inspection at Braidwood, the team identified the Braidwood Applicant

had not completed the eddy current examinations on any

of the 58 tube loops at Braidwood Unit 1 during the

September 2013 outage and only complete seven of the

58 flux thimble tubes at Braidwood Unit 2 during the

May 2014 outage.

The staff was not aware of the extent of the Applicant

=s deficiencies during the review of this AMP. We communicated this to NRR and currently the

Applicant=s actions to address this issue are being assessed by the staff. This issue pertains only to

the Braidwood Station.

The three examples demonstrate the benefit of the 71002 inspection to verify the programs described by the Applicant in their application recommendation which are consistent with the existing plant programs.

It also emphasizes the strong and important

coordination between Headquarters and the region in

this review process. Next slide please.

In summary, both teams concluded the Applicant performed the scoping and screening in accordance with the rule. Inspectors also found

information was easily retrievable and verified the 122 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 programs were generally effective in managing aging effects.

The teams also verified that Applicant has the tools to track the completion of enhancements and the development of new programs. Lastly, based on the

results of these inspections, the inspectors have

reasonable assurance that the programs will manage the aging effects and ensure the intended safety functions

of SSCs within the rule will be maintained if it is

determined that as described in the application with

the proposed enhancements and supplemented through the

Applicant=

s responses to request for additional

information and inspection or observations. Thank you. Now I

=ll turn the presentation back to Lindsay. CHAIRMAN SKILLMAN: Nestor, let me ask you a question please. I

=m reading above ground metall ic tank program B.2.17 and I find that the Byron and the

Braidwood 71002 inspection report-out have identical text. And I=m curious. Is that because this is a new

program for each site or is this an administrative

cleverness on the part of the inspection team?

MR. FELIZ

-ADORNO: It

=s a new program.

There=s no unique differences between the two sites.

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-3701 (202) 234-4433 It was inspected by the same inspector. So naturally he will have the same input. CHAIRMAN SKILLMAN: Identical same input.

MR. FELIZ-ADORNO: Yes.

CHAIRMAN SKILLMAN: Okay. Thank you.

Lindsay.

MS. ROBINSON: All right. We=

re on slide 8. Thank you, Mel and Nestor. We will now discuss each of the issues identified during the 71002

inspection.

As previously stated, the Applicant subsequently revised the LRA to include the CRDM seismic support assemblies and scope and included the CRDM

support components and AMR table 3.5.2-3. The staff

noted that the Applicant

=s LRA revision did not state

what type of bolts were used for the CRDM seismic

supports.

In a letter dated October 9, 2014, the staff issued RAI B.2.1.31 Tab 4, requested information to whether or not high strength bolts in sizes greater than one inch were used in CRDM supports. And, if so,

the staff requested the Applicant provide additional

information on the type and grade of the material to

determine whether the bolts will be managed for cracking 124 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 due to stress corrosion cracking. In a letter dated October 16, 2014, the Applicant responded to the staff

=s request by stating that there were no high strength bolts in sizes greater than one inch used in the CRDM seismic supports which

addressed the staff

=s concern. This issue and its closure will be addressed in the final SER and discussed

during the full Committee meeting. Next slide.

This next issue involves the Applicant=s procedure to conduct visual inspections of areas of concrete deterioration remotely with the use of an optical aid. The inspection team expressed concern

regarding the Applicant

=s visual resolution capability to be used during the period of extended operation to

quantify degradation based on quantitative acceptance

criteria described in Chapter 5 of ACI 349.3R. This issue applies to both Byron and Braidwood Stations,

Units 1 and 2. By letter dated November 6, 2014, the staff issued RAI 3.2.1.30

-6 requesting that the Applicant

provided information to verify that sufficient visual

resolution capability will be used during visual

examinations of concrete surfaces of containment

structures to detect and quantify forms of degradation 125 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 for comparison against quantitative acceptance criteria based on Chapter 5 of ACI349.3R.

By letter dated November 21, 2014, the Applicant provided its response to the RAI. The response is currently under staff review. This issue

and its closure will be addressed in the final SER and discussed during the full Committee meeting. Next

slide. By letter dated May 19, 2014, the staff issued RAI E.2.1.24

-1 requesting additional

information regarding higher than expected wear rates in flux thimble tubes at Braidwood Units 1 and 2. In addition, the staff also questioned the adequacy of

the program because it was not able to perform

examinations on a few of the tubes. By letter dated June 9, 2014, th e Applicant provided a response to the staff

=s RAI. In response, the Applicant discussed high wear rate issues and its

failure to obtain data on a few tubes based on outage inspections from 2007 to 2012 for both Braidwood Unit 1 and Unit 2. The Applicant also stated that several corrective actions were being implemented to address

the issues related to completing eddy current

examinations.

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-3701 (202) 234-4433 One corrective action was to increase the inspection frequency to perform examinations every outage. The staff closed the issue based on the

Applicant=s response.

During the NRC 71002 inspection at Braidwood, the staff discovered that the Applicant was not able to complete planned eddy current examinations on any of the 58 tubes at Braidwood Unit 1 dur ing the September 2013 outage and only partially completed

seven of 58 flux thimble tubes at Braidwood Unit 2 during

the May 2014 inspection.

The GALL AMP for flux thimble tube inspection implements the recommendations of NRC

Bulletin 88

-09 which established a program to monitor thimble tubes through periodic inspections. The staff was concerned that the program may not be adequate if tube wear examinations are not performed as scheduled

and therefore issued an RAI on October 10, 2014.

By letter dated October 31, 2014, the Applicant responded to the staff

=s RAI, but did not

identify the causes of the problem or provide corrective actions sufficient to address the problem. By letter

dated November 22, 2014, the Applicant supplemented

its response further by providing additional 127 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 information and license renewal commitments.

The staff is currently reviewing the Applicant=

s supplemental response and the adequacy of the Applicant

=s aging management program. This issue

will remain open until it

=s adequately resolved. This

issue and its closure will be addressed in the final SER and discussed at the full Committee meeting. Next

slide. We now shift our focus to the SER. SER Section 2 describes the scoping and screening of

structures and components subject to aging management review. The staff reviewed the Applicant

=s scoping

and screening methodology, procedures, quality controls of the LRA development and training of its project personnel. The staff also reviewed the various

summaries of the s afety-related systems, structures

and components, non

-safety systems, structures and

components affecting the safety

-related components and

systems, structures and components relied upon to

perform functions in compliance with the Commission

=s regulations for fire protection, environmental qualification, station blackout, pressurized thermal

shock and anticipated transients without scram. Based on the review, the results from the 128 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 scoping and screening audit and additional information provided by the Applicant, the staff concludes that

the Applicant

=s scoping and screening methodology was consistent with the standard review plan and the

requirements of 10 CFR Part 54. Next slide.

SER Section 3 covers the staff

=s review of the Applicant=s aging management programs. For a given aging management review, the staff reviewed the item to determine whether it is consistent with the GALL report. Section 3.1 through 3.6 include the aging management review items in each of the general system

areas within the scope of license renewal.

If the aging management review was not consistent with the GALL, then the staff conducted a

technical review to ensure adequacy. Next slide.

The Applicant submitted 45 aging management programs in the application. What I have before you is actually a table. And what it identifies how it was dispositioned in the LRA. And then the other

side actually dispositions how the review identified

it in the SER with open items. Next slide.

SER Section 3 contained one open item.

Open Item 3.0.3.1.3

-1 pertains to wear in the

Applicant=s CRDM penetration nozzles. During the AMP 129 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 audit, the staff noted operating experience which indicated that the Applicant

=s CRDM penetration nozzles

have wear near the J

-groove valve due to interact ions with CRDM thermal sleeves centering tabs.

The Applicant has not proposed any examinations to monitor the wear during the period of

extended operation but determine continued

acceptability of the defect. In response to the

staff=s RAIs, the Applicant stated that it is

participating in the Westinghouse owner group project which is expected to provide a detailed analysis

confirming that the nozzles will continue to perform

their intended pressure boundary functions through the

end of the renewed license despite the wear.

The Applicant indicated that if the analytical results do not justify continued operation

of the nozzles during the period of extended operation or if the staff finds the analysis unacceptable, then

the Applicant will provide a commitment to repair or

replace the CRDM nozzles that are affected.

MEMBER STETKAR: Lindsay, has that analysis been submitted? It has? MS. ROBINSON: I=

m actually going to cover that right now.

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-3701 (202) 234-4433 MEMBER STETKAR: Sorry.

MS. ROBINSON: Not a problem. The Applicant provided a brief summary of the results of

that analysis on November 24, 2014. The Applicant=s response states that it needs to perform further

evaluations to determine if the LRA needs to be revised

as a result of the analysis. The staff is currently reviewing the Applicant

=s response and also review any

additional information which the Applicant provides

as a result of the continued evaluation.

In terms of the analysis itself, we have not received the complete analysis from the Applicant.

But the Applicant did say that they would be providing

that to us.

MEMBER STETKAR: Okay.

MEMBER BALLINGER: But we had a presentation a little while ago that basically

discussed the analysis. Am I right?

MEMBER STETKAR: No. Not the analysis.

CHAIRMAN SKILLMAN: Not the analysis. We had presentations discussing what they

=re going to do.

MEMBER RICCARDELLA: They said there was a full section to the analysis that justified integrity

of the pressure boundary with this wear.

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-3701 (202) 234-4433 CHAIRMAN SKILLMAN: Yes, Ron

=s question or Ron made the statement that we had a presentation on the analysis. We had a presentation on the wear

and a discussion of what they are going to do.

MEMBER STETKAR: But there

=s some stuff saying preliminary information from the analysis.

That could lead you to the conclusion that they

presented.

MEMBER BALLINGER: My words were not sufficiently accurate. CHAIRMAN SKILLMAN: I understood what you meant. MEMBER RICCARDELLA: My impression is the analysis has been done. It just hasn

=t been submitted.

That=s my understanding.

MEMBER STETKAR: Lindsay.

MS. ROBINSON: We can actually have the reviewer who is handling this one. We did get the

response and again the response was dated November 24,

2014. So the staff is currently evaluating the response that was provided. But Roger here can provide

maybe a little more insight. MR. KALIKIAN: Yes. Hi. I

=m Roger Kalikian and I

=m the reviewer for the exam. They did 132 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 provide a summary of the analysis. They did s ay they completed the analysis. And they also mentioned that

they are continuing to evaluate to see how the analysis will impact the LRA. And they would submit that

information to us when it

=s completed. But we just

got a brief summary and nothing else.

CHAIRMAN SKILLMAN: Please continue, Lindsay. Thank you. MS. ROBINSON: The results of the staff

=s review will be documented in the final SER and discussed

during the full Committee meeting. Next slide.

SER Section 4 identifies Time Limited Aging Analysis or TLAAs. Section 4.1 documents the staff

=s evaluation of the Applicant

=s identification of applicable TLAAs. The staff evaluated the Applicant

=s basis for identifying those plant

-specific or generic

analysis that needed to be identified as TLAAs and determined that the Applicant has provided an accurate

list of TLAAs as required by 10 CFR 54.21(c)(1).

Sections 4.2 through 4.7 document the staff=s review of the applicable Byron and Braidwood TLAAs as shown. Based on its review of t he information

provided by the Applicant and pending the resolution

of one open item, the staff concludes that the TLAAs 133 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 were either (a) remain valid for the period of extended operation; (b) have been projected to the end of the

period of extended operation; or (c) the effects of

aging on those intended functions will be adequately

managed for the period of extended operation as required by 10 CFR 54.21(c)(1)(I), (ii) or (iii) respectively.

Next slide. CHAIRMAN SKILLMAN: Let=

s just hold on for a second here.

MS. ROBINSON: Yes.

CHAIRMAN SKILLMAN: Ron, did you want to ask a question about 4.5 on that slide.

MEMBER BALLINGER: This is the tendon pre-stress analysis. I was concerned about what

happened at North Anna where you ended up with a tendon getting blown up basically by hydrogen embrittlement and releasing a tension. And it

=s because the grease

that=s in that conduit in the tendon is a high pH grease

that=s designed to absorb moisture to maintain the pH

high enough.

There=s a replacement. You

=re supposed to inspect and replace that grease. So I was concerned

and just wondering if there=s a program in place to do that inspection and replace that grease. A lot of 134 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 times folks don

=t do it. It

=s pretty onerous and ugly and difficult and dirty and everything else.

But you=re required to have X number of those tendons in place for containment pressure

maintaining. And if all of a sudden one of those

tendons goes, the shock to the system, I=m wondering

whether or not t here=s a danger. We

=ve seen these separations of concrete, the layers of concrete, around

the rebar. I

=m just curious as to how that

=s being handled. MS. ROBINSON: Is anybody from Exelon able to address that? MR. GALLAGHER: Yes, we can answer that question. Jim Annett.

MR. ANNETT: My name is Jim Annett. I=m on the License Renewal Team. I think you had a couple questions in there. I

=ll first talk about the grease in the tendons. The grease used at Byron and Braidwood

is like the P

-4 version of the grease versus like the

P-0. And that starts with a higher alkalinity level.

So our acceptance criteria is a higher alkalinity level at Byron and Braidwood. So the grease level is always maintained at a higher alkalinity level at Byron and Braidwood. And when they do the sampling, 135 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 it=s supposed to

-- They have done grease replacements at Byron and Braidwood also. But they

ve never gotten to essentially like a zero level. MEMBER BALLINGER: Okay. So it

s part of the aging management program to maintain that high pH.

MR. ANNETT: Yes, it is.

MEMBER BALLINGER: Okay.

CHAIRMAN SKILLMAN: Dr. Ballinger, you

=re good. MEMBER BALLINGER: Yes. Good.

CHAIRMAN SKILLMAN: Okay. Lindsay, go ahead. Thank you. MS. ROBINSON: Thank you. Next slide.

We=re on slide 16. Section 4 contains one open item.

Open Item 4.3

-1 is related to environmentally assisted

fatigue locations for reactor coolant pressure boundary

components. The Applicant performed a review of all four units of all applicable reacto r coolant pressure boundary components with a Class 1 fatigue analysis

to determine the plant-specific leading locations to be monitored by the fatigue monitoring program for EAF.

However, the Applicant did not demonstrate that its

methodology for selecting those locations provided assurance to the location that the locations were 136 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 bounding.

In the Applicant

=s methodology, the staff identified the following issues: (a) the Applicant=s justification for selecting one material to bound other

materials and (b) the Applicant

=s basis for screening out a component with a higher environmentally assisted

cumulative usage factor value than the leading

location. By a letter dated October 28, 2014, the staff issued a follow

-up RAI for the Applicant to demonstrate the specific components would not need to

be monitored for EAF in the period of extended

operation.

By letter dated November 25, 2014, the Applicant provided its response to the RAI. The response is currently under staff review. The staff

=s conclusion will be documented in the final SER and discussed in the full Committee meeting. Next slide.

The staff

=s conclusion will be provided in the final SER. Pending a satisfactory resolution

of the open items and inspection issues, the staff will determine whether the requirements of 10 CFR 54.29(a)

have been met for the renewal of Byron Station Units

1 and 2 and Braidwood Station Units 1 and 2.

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-3701 (202) 234-4433 This concludes our staff presentation.

And we will now be available for any further questions.

CHAIRMAN SKILLMAN: Thank you, Lindsay. Colleagues, may I ask if you have questions for the NRC staff please? MEMBER STETKAR: Yes. I have a couple. One is back to the condensate storage tanks. We heard from the Licensee that they plan to inspe ct the total of 25 locations distributed between the two CSTs at each unit; whereas, the guidance now, interim staff

guidance, specifically says for each outdoor insulated

tank. And I

=m curious why the staff accepted this

notion of AWell, I can look at 12 on one of them and 13 on the other and 25 between the two them is good enough. Or if I have maybe 15 tanks, perhaps I could

look at one on each one of them or a couple on each

one of them and somehow count up to 25 that way.

@ I=m curious why you accept this sort of notion of

distributed inspections when you know we

=ve pretty

already established that the tanks are not identical

in terms of their life history.

MS. ROBINSON: We can have the reviewer, Mr. Holston, come in and respond to your question.

MR. HOLSTON: Yes, this is Bill Holston, 138 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 Technical Reviewer for the Division of License Renewal.

We accepted the 25 total per site. Because when we

were writing the interim staff guidance, a typical plant

has six outdoor tanks, usually two fuel tanks, maybe

even more than that, two fire water tanks, two

condensate storage tanks.

In the case of both Byron and Braidwood, they only had two outdoor tanks. They don

=t have fire

water storage tanks. The diesel storage tanks are

inside. So a sample population of 25 is adequate.

The sample population of 25 is consistent with other aging management programs such as the

internal surfaces program, the one

-time inspection program and selective leeching program. A total

population of 25 establishes reasonable assurance.

All four of the tanks, the final point is that all four of the tanks were susceptible to water underneath the

lagging in the license renewal application operating experience examples for all four of them. So we

considered that the environmental conditions between the insulation and the tank sides were representative

amongst the four tanks. MEMBER STETKAR: I guess I still don

=t understand your rationale. For the record I=ll read 139 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 into Section (e)(iii)(c) of the License Re newal ISG-2012-

02. It states AFor each outdoor insulated tank and indoor insulated tanks exposed to condensation because the in

-scope component is being operated below

the dew point, GALL report AMP XI.M

-29 was revised to recommend removal of insulation from either 25 one square foot sections or 20 percent of the surface area and inspecting the exterior surface of the tank.

@ That doesn=t say we sort of sample 25 somewhere around the total portion of the site. It says I look at each tank.

MR. HOLSTON: That=s correct. And I was actually the author of that interim staff guidance.

MEMBER STETKAR: Good.

MR. HOLSTON: And an interim staff guidance just like the GALL report is a set of

recommendations. It=s not a set of requirements. The applicant can take exception to that and in this case

the applicant stated that they wanted to do 25 total

inspections at the site. And we found that 25 given

the reasons I just explained at the beginning of the

response was adequate in this situation.

Where you used an example of what is the plant had 16 tanks. Well, we would have come to a different conclusion if the plant had 16 tanks. In 140 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 fact, this plant has two outdoor tanks.

MEMBER STETKAR: Okay. Thank you. The only other one that I had and I

=ll ask the staff about this. I

=m going to ask the licensee,

but we=re good on time. In their program for monitoring

neutron-absorbing material in the fuel pool, the report

noted that the -- I=ll probably get the terminology wrong. So just bear with me here

-- placement of the coupons, the coupons are supposed to be placed in the middle of the most recently renewed fuel. So they would

get the highest irradiation. And yet the experience

has been that they haven

=t always done that or I don

=t know whether it=s haven=t always or perhaps never. And now they

=ve committed

-- It says, AThe Applicant stated that prior to the period of extended

operation an enhancement will be implemented to maintain the coupon exposure such as bounding for the

raw material and spent fuel rods.

@ In other words, sometime before 2026, they=re actually going to make

sure they do this right.

Have they started to do it right now? I mean, how do we know that the coupons provide a bounding

assessment of that material for the next 15 years?

MS. ROBINSON: I believe we have a reviewer 141 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 who is on the line.

MEMBER STETKAR: Good. MS. ROBINSON: Who may be able to address that. Is it still on listening mode?

PARTICIPANT: It=s open.

MS. ROBINSON: It is. Aloysius.

MR. OBODOAKO: Yes, this is Aloysius Obodoako in the Division of Engineering. I reviewed this program. Well, I supported the review of this

program during the audit and also the aging management

program. I

=m currently looking for the response to that through my documents. It looks like I

=ll have to get back to you about that response.

MEMBER STETKAR: Okay. I

=m not sure.

I=m more concerned about how are they monitoring it

currently which is really more an issue of a current

licensing rather than with the period of extended

operation. MS. ROBINSON: I think Exelon actually

-- There=s somebody that can address that.

MR. GALLAGHER: Yes, Dylan Cimock can answer that question. MR. CIMOCK: Dylan Cimock, License Renewal Team for Exelon. Just to clarify, Byron and Braidwood 142 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 did implement an accelerated irradiation schedule at the beginning of the installation of the racks which

includes surrounding the coupon tree on all sides with freshly discharged fuel for the first five cycles.

So that was an importance of the manufacturer

=s recommendations and both stations did satisfy that

initial requirement.

We received an additional RAI asking how we will ensure that going forward. So we enhanced our

program to state that we will maintain those coupons in that configuration going forward prior to testing.

MEMBER STETKAR: You said during the first

-- When did you rerack the pools?

MR. CIMOCK: Byron and Braidwood, it was approximately 2000-2001.

MEMBER STETKAR: Okay. So you had the accelerated irradiation through let

=s say 2005-2006-2007 time period, right?

MR. CIMOCK: Yes.

MEMBER STETKAR: The first five years roughly. But since then they

=ve not been in that

configuration. Is that correct?

MR. CIMOCK: That is correct.

MEMBER STETKAR: Okay. B ut going forward 143 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 from now or going forward from 2026, you=re going to ensure that they

=re in an accelerated irradiation.

In other words, that they received the highest

performance.

MR. CIMOCK: The manufacturer

=s recommendation was for the initial five cycles which would ensure that they were bounding for the duration of the racks which we assume for the existing license

they would remain bounding.

MEMBER STETKAR: Okay.

MR. CIMOCK: Now going forward they are currently in a bounding condition. We are committing

to maintaining those in a bounding condition through

the PEO.

MEMBER STETKAR: Thank you. That clarified. Thanks. That helps.

CHAIRMAN SKILLMAN: Colleagues, any additional questions for the NRC staff please?

Hearing none, are there individuals in the audience that would like to ask a question or make a

statement please?

Hearing none on the telephone line that is now open, are there any members of the public or

others that would like to make a statement or ask a 144 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 question please?

If you=re out there, would you please acknowledge your presence?

(No response.) Thank you. Hearing no comments, would you please close the line?

SUBCOMMITTEE DISCUSSION CHAIRMAN SKILLMAN: As a final activity here from my colleagues around the table, do you have

any questions either for the staff or for the Applicant

for these four units at two sites?

MEMBER RICCARDELLA: I don

=t have any further questions. Thank you.

MEMBER RAY: No.

MEMBER POWERS: No.

MEMBER BALLINGER: No.

MEMBER STETKAR: Mr. Chairman, I just want to congratulate the staff. I think you guys did really

well actually on the audits and inspections. It

=s pretty onerous to try to get f our units, your hands

around four units, with differences and similarities.

I was actually really impressed with the review effort.

I just wanted to make that statement. MEMBER POWERS: I think the Applicant did 145 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 good because the project leader here is a graduate of my course.

MS. ROBINSON: Yes, that is absolutely correct.

MEMBER POWERS: That=s what led to --

MEMBER STETKAR: Yet again in your debt, Dr. Powers.

(Laughter.)

CONSULTANT BARTON: I think the Applicant did a terrific job of putting this whole thing together.

It was a real good presentation.

CHAIRMAN SKILLMAN: I want to echo that.

I want to thank the Exelon team, the Byron team, the

Braidwood team. This has been an enormous amount of

work and we understand that it has been.

And it=s been an enormous amount of work for the staff, for the region

and for the team here in Rockville. Thank you.

MEMBER POWERS: I would say let

=s encourage them not to do this again. There are too

many points at one time.

CHAIRMAN SKILLMAN: Those of us who did the reviews were juggling four units, two sites, permutations and combinations, what are the AMPs, where do they overlap, where are they separate, why are they 146 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 separate. And you=ve done a great job in clarifying those distinctions and differences. So I thank you

very much.

With that, I

=m going to wish all safe travels and I

=m going to stop this meeting. We are

adjourned. Thank you.

(Whereupon, at 11:25 a.m., the above-entitled matter was concluded.)

ACRS Subcommittee Presentation December 03, 2014 License Renewal Application Braidwood Byron Introductions Byron and Braidwood Stations, Units 1 and 2 1

AgendaByron and Braidwood Stations, Units 1 and 2 2

3 Byron and BraidwoodStations, Units 1 and 2 Byron and Braidwood Station Locations Byron and Braidwood Stations, Units 1 and 2 4Byron StationIndependent Spent Fuel Storage Installation (ISFSI) 345 kV Switchyard Essential Service Water Cooling Towers (Ultimate Heat Sink)Circulating Water Pump HouseCirculating Water Flume Byron and Braidwood Stations, Units 1 and 2 5Braidwood StationCooling Pond (Ultimate Heat Sink)

Lake Screen HouseIndependent Spent Fuel Storage Installation (ISFSI) 345 kV Switchyard Station OverviewByron and Braidwood Stations, Units 1 and 2 6

GALL Revision 2 Consistency and License Renewal CommitmentsByron and Braidwood Stations, Units 1 and 2 7

GALL Consistency and CommitmentsByron and Braidwood Stations, Units 1 and 2 8ByronBraidwoodTotal AMPs 4544AMPs Consistent with GALL 3837AMPswith Exception to GALL 77Commitments 4746 Open ItemsByron and Braidwood Stations, Units 1 and 2 9

Open Item 10Byron and Braidwood Stations, Units 1 and 2Byron and Braidwood Stations, Units 1 and 2 10 Open Item

11Byron and Braidwood Stations, Units 1 and 2Byron and Braidwood Stations, Units 1 and 2 11 Overview of CRDM Housing Wear 12Byron and Braidwood Stations, Units 1 and 2Overview of CRDM Housing Wear CRDM Housing Wear Details 13Byron and Braidwood Stations, Units 1 and 2 CRDM Housing Analysis

-

-14Byron and Braidwood Stations, Units 1 and 2CRDM Housing Wear Analysis

15Byron and Braidwood Stations, Units 1 and 2Summary and Conclusions Items of Interest from Region III InspectionsByron and Braidwood Stations, Units 1 and 2 16 Item of Interest -

Visual Examination of Concrete Containment Structures

-

Byron and Braidwood Stations, Units 1 and 2 17 Item of Interest -CRDM Seismic Support Assembly Aging Management18Byron and Braidwood Stations, Units 1 and 2Byron and Braidwood Stations, Units 1 and 2 18 CRDM Seismic Support Assembly Aging Management19Byron and Braidwood Stations, Units 1 and 2Byron and Braidwood Stations, Units 1 and 2 19 CRDM Seismic Support Assembly Aging Management---

--

20Byron and Braidwood Stations, Units 1 and 2Byron and Braidwood Stations, Units 1 and 2 20

Byron and Braidwood Stations, Units 1 and 2 21Item of Interest -

Braidwood Flux Thimble Tube Inspection Program In-Core Flux Monitoring SystemByron and Braidwood Stations, Units 1 and 2 22

---

Byron and Braidwood Stations, Units 1 and 2 23Corrective Actions

-

-Byron and Braidwood Stations, Units 1 and 2 24Basis for Adequacy of Current ProgramSpring2014Spring 2015Fall 2015Fall 2016Spring 2017OngoingUnit 11741Every 3 Refuel OutagesUnit 27Completed2922

Byron and Braidwood Stations, Units 1 and 2 25Conclusion ClosingByron and Braidwood Stations, Units 1 and 2 26 ACRS Subcommittee Presentation December 03, 2014 License Renewal Application Braidwood Byron Advisory Committee on Reactor Safeguards License Renewal Subcommittee Byron Station, Units 1 and 2, and Braidwood Station, Units 1 and 2 (BBS) Safety Evaluation Report (SER) with Open Items Lindsay Robinson, Project Manager Office of Nuclear Reactor Regulation 1

Presentation Outline Overview of BBS license renewal review Region III License Renewal Onsite Inspection 71002 Inspection Issues SER Section 2, Scoping and Screening Review SER Section 3, Aging Management Review SER Section 4, Time-Limited Aging Analyses 2

License Renewal Review (Audits and Inspections) Scoping and Screening Methodology Audit Byron: July 29 - August 2, 2013 Braidwood: December 2-4, 2013 Aging Management Program (AMP) Audit Byron: August 19-30, 2013 Braidwood: October 30-31, 2013, and Dec 2-6, 2013 Environmental Audit Byron: September 17-19, 2013 Braidwood: November 18-20, 2013 Region III 71002 Inspection (Scoping and Screening & AMPs) Byron: August 4-8, 2014, and August 18-22, 2014 Braidwood: Sept 15-26, 2014 3 SER Overview SER with Open Items (OIs) was issued October 30, 2014 BBS SER contains 2 OIs: OI 3.0.3.1.3-1 CRDM Nozzle Wear OI 4.3-1 Environmentally Assisted Fatigue (EAF) in Class 1 Components The final SER is scheduled for publication April 2015 4

71002 Inspections Scope Regulated Events Non-Safety Systems affecting Safety Systems Aging Management Programs Byron Inspection Aug. 2014: Team Inspection (6 inspectors) on-site for 2 weeks Braidwood Inspection Sept. 2014: Team Inspection (5 inspectors) on-site for 2 weeks 5

6 Overall Inspection Results Material condition of SSCs Good Application changes to some AMPs Identified issues for further review: XI.S3 ASME Section XI, Subsection IWF XI.S2 ASME Section XI, Subsection IWL XI.M37 Flux Thimble Tube Inspection 71002 Inspections 71002 Inspections

Conclusions:

Scoping and screening performed in accordance with 10 CFR 54 Information used to prepare the license renewal application was retrievable, auditable, and consistent with 10 CFR 54 Existing programs are generally effective in managing aging effects Actions to address enhancements and new programs are being tracked for completion Reasonable assurance that aging effects will be managed and intended functions maintained, subject to satisfactory resolution of open issues 7

71002 Inspection Issue CRDM Seismic Support Assembly Bolting Issue: LRA revised to include CRDM Seismic Support Assemblies but did not specify whether the assemblies included high-strength bolting Concern: Aging management of high-strength bolting Applicant responded that there is no high-strength bolting used in CRDM seismic supports This issue is resolved 8 71002 Inspection Issue IWL Visual Examinations Issue: Currently, visual inspections of some areas of concrete deterioration are conducted remotely with the use of an optical aid.

Concern: Visual resolution capability of optical aids to detect and quantify degradation for comparison against quantitative acceptance criteria described in ACI 349.3R

. 9 71002 Inspection Issue Flux Thimble Tube Inspection Issue: The applicant failed to complete inspections at Braidwood Units 1 and 2 during the most recent outages.

Concern: AMP may be inadequate 10 SER Section 2 Summary Structures and Components Subject to Aging Management Review Section 2.1, Scoping and Screening Methodology Section 2.2, Plant-Level Scoping Results

Sections 2.3, 2.4, 2.5 Scoping and Screening Results 11 SER Section 3: Aging Management Review Section 3.0 Aging Management Programs Section 3.1 Reactor Vessel, Internals, and Reactor Coolant Systems Section 3.2 Engineered Safety Features Systems Section 3.3 Auxiliary Systems Section 3.4 Steam and Power Conversion Systems Section 3.5 Containments, Structures, and Component Supports Section 3.6 Electrical and Instrumentation and Controls Systems 12 SER Section 3 LRA identified: 13 new programs 11 consistent 2 consistent w/ exceptions 32 existing programs 9 consistent 18 consistent w/ enhancements 5 consistent w/ enhancements and exceptions : 13 new programs 11 consistent 2 consistent w/ exceptions 32 existing programs 6 consistent 21 consistent w/ enhancements 5 consistent w/ enhancements and exceptions 13 3.0.3 Aging Management Programs SER Section 3 Open Item OI 3.0.3.1.3-1 CRDM Nozzle Wear:

Issue: CRDM penetration nozzle wear not managed.

Open Item: Applicant to confirm CRDM penetration nozzle wear will be adequately managed.

14 4.1 Identification of TLAAs 4.2 Reactor Vessel Neutron Embrittlement Analysis 4.3 Metal Fatigue 4.4 Environmental Qualification of Electric Equipment 4.5 Concrete Containment Tendon Prestress Analyses 4.6 Containment Liner Plate, Metal Containments, and Penetration Fatigue Analyses 4.7 Other Plant-Specific TLAAs SER Section 4: TLAA 15 SER Section 4 Open Item OI 4.3-1 Environmentally Assisted Fatigue in Class 1 Components: Issue: Insufficient justification for selecting leading locations how one material bounds other materials basis for comparison of CUFen values Open Item: Applicant did not demonstrate why specific components would not need to be monitored for EAF 16 Conclusion Pending satisfactory resolution of the open items and inspection issues, the staff will determine whether the requirements of 10 CFR 54.29(a) have been met for the license renewal of Byron Station, Unit 1 and Unit 2, and Braidwood Station, Unit 1 and Unit 2.

17 Official Transcript of Proceedings NUCLEAR REGULATORY COMMISSION

Title: Advisory Committee on Reactor Safeguards (ACRS) Plant License Renewal Subcommittee

Docket Number: (n/a)

Location: Rockville, Maryland

Date: December 3, 2014

Work Order No.: NRC-1261 Pages 1-1

NEAL R. GROSS AND CO., INC.

Court Reporters and Transcribers 1323 Rhode Island Avenue, N.W.

Washington, D.C. 20005 (202) 234

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-3701 (202) 234-4433 UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION

+ + + + + ADVISORY COMMITTEE ON REACTOR SAFEGUARDS (ACRS) + + + + + PLANT LICENSE RENEWAL SUBCOMMITTEE

+ + + + +

WEDNESDAY DECEMBER 3, 2014

+ + + + +

ROCKVILLE, MARYLAND

+ + + + +

The Subcommittee met at the Nuclear Regulatory Commission, Two White Flint North, Room T2B1, 11545 Rockville Pike, at 8:30 a.m., Gordon R.

Skillman, Chairman, presiding.

COMMITTEE MEMBERS:

GORDON R. SKILLMAN, Subcommittee Chairman

RONALD G. BALLINGER, Member

DANA A. POWERS, Member

HAROLD B. RAY, Member

PETER C. RICCARDELLA, Member

JOHN W. STETKAR, Member 2 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 ACRS CONSULTANT:

JOHN J. BARTON DESIGNATED FEDERAL OFFICIAL:

KENT L. HOWARD, SR.

ALSO PRESENT:

JIM ANNETT, Exelon

JOHN BASHOR, Exelon

GARY BECKNELL, Exelon

ED BLONDIN, Exelon

STEVE BLOOM, NRR

DONALD BRINDLE, Exelon

EDWARD J. CARLY, Next Era Energy

PAUL CERVENICA, Exelon

DYLAN CIMOCK, Exelon

SAMUEL CUADRADO, NRR

HIAN DA, Exelon

JOHN DAILY, NFF

GEORGE DEMETRI, Exelon/Westinghouse

YOIRA DIAZ-SANABRIA, NRR

CLIFF DOUTT, NRR

DAN ENRIGHT, Exelon 3 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 W. JACK FEIMSTER, Exelon NESTOR J. FELIZ-ADORNO, III

DON FERRARO, Exelon

BARF FU, NRR

MIKE GALLAGHER, Exelon

LYNNE GOODMAN, DTE Energy

KIM GREEN, NRR

ETHAN HAUSER, DTE Energy

JOHN HILDITCH, Exelon

ALLEN HISER, NRR

MELVIN HOLMBERG, RIII

WILLIAM C. HOLSTON, NRR

CHRIS HOVANEC, NRR

JOHN HUFNAGEL, Exelon

KENDRA HULLUM-LAWSON, DTE Energy

CRAIG INGOLD, Exelon

TIM JOHNSON, Exelon

ROGER KALIKIAN, NRR

CHARLES KELLER, Exelon

CHRISTINE KINKEAD, Exelon

RALPH KOHN, Exelon

RAY KUYLER, Morgan Lewis

JUAN A. LOPEZ, NRR

MICHAEL MARSHALL, NRR 4 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 JOHN MATTHEWS, Exelon JAMES MEDOFF, NRR

DANEIRA MELENDEZ-COLON, NRR

NEAL MILLEN, Exelon

CHRIS MILLER, NRR

SONNY MIN, NRR

JEFFREY MITCHELL, NRR

DENNIS MOREY, NRR

CASEY MUGGLESTON, Exelon

ALBERT PIHA, Exelon

PHIL O'DONNELL, Exelon

ALOYSIUS O. OBODOAKO, NRR*

DOUGLAS P. OVERBECK, Exelon

ANDREW PRINARIS, NRR

TOM QUINTENZ, Exelon

PHILLIP J. RAUSH, Exelon

LINDSAY ROBINSON, NRR

PETE SHIER, Exelon

ANN MARIE STONE, RIII

PETER TAMBURRO, Exelon

GEORGE THOMAS, NRR

PAUL WEYHMULLER, Exelon

MARK YOO, NRR

MOHAMMED YOUSUF, Exelon 5 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 *Present via telephone

T A B L E O F C O N T E N T S Page Opening Remarks 6 Staff Introduction 8 Exelon Generation Station - Byron 10 Station, Units 1 & 2 and Braidwood Station,

Units 1 & 2 - BBS Introduction, Station Descriptions and

Overview, GALL Consistency and Commitments,

Discussion of SER Open Items, Items of

Interest from Region III Inspections and

Closing Remarks NRC Staff Presentation SER Overview 98 Overview of License Renewal Review,

Region III 71002 Inspection, 71002

Inspection Issues, Scoping and Screening

Review, Aging Management Review, Time

Limited Aging Analysis, Conclusion Subcommittee Discussion 139 Adjourn 6 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 P R O C E E D I N G S (8:31 a.m.) CHAIRMAN SKILLMAN: Ladies and gentlemen, good morning. This meeting will come to order. I=m Gordon Skillman. I

=m the Chairman of the Plant License

Renewal Subcommittee. The Subcommittee will review the combined license renewal application for the Byron

Station Unit 1 and 2 and Braidwood Station Units 1 and 2 Nuclear Plants.

ACRS members in attendance are Pete Riccardella, Harold Ray, Dana Powers, John Stetkar, ACRS Chairman, John Barton, our consultant, and Ron

Ballinger. Our Federal Official is Kent Howard.

I would like to make an opening comment.

This is an unprecedented review for the ACRS. This is a review of four units at two different sites. While the units are very similar, they are not identical.

So there are some issues of commonality and some issues

of difference that we hope to hear about today. I want to say up front we recognize the immense effort that Exelon has invested in this

application. And the investment that you=ve made to bring your team here today, we thank you for that.

And we look forward to a very constructive meeting.

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-3701 (202) 234-4433 This morning we will hear presentations from the Division of License Renewal, from Region III and the Exelon Generation Company regarding this

matter. The Subcommittee will gather information,

analyze relevant issues and facts and formulate proposed positions and actions as appropriate for

deliberation by the Committee.

The rules for participation in today

=s meeting have been announced as part of the notice of

this meeting previously published in the Fe deral Register. We have not received written comments or

requests for time to make oral statements from members

of the public regarding today=s meeting. The entire meeting will be open to public attendance. There will be a phone bridge line. To

preclude interruption of the meeting, the phone will

be placed in a listen

-in mode during the presentations

and the Committee discussion. A transcript of this meeting is being kept and will be made available as stated in the Federal

Register Notice. Therefore, I request that participants in this meeting please use the microphones

located throughout the meeting room when addressing

the Subcommittee. The participants are requested to 9 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 please identify themselves first and then speak with sufficient clarity and volume so that they can be readily heard. I also ask that you please silence all

of your electronic devices. We will now proceed with the meeting. And I call upon Chris Miller to begin the presentation.

Chris.

STAFF INTRODUCTION MR. MILLER: Thank you, Chairman Skillman.

We=re looking forward to the presentations today.

And staff looks forward to the interaction.

As stated, I=m Chris Miller, Director of the Division of License Renewal. I have with me at

the table Yoira Diaz, Branch Chief for Projects Branch

1. We also have in the audience our Branch Chiefs

Dennis Morey, Michael Marshall and Steve Bloom.

The staff=s Lindsay Robinson, our Safety PM, will make the staff=s presentation. She will be joined at the table by our Senior Technical A dvisor Dr. Allen Hiser, Region III Lead Inspector for Byron Mel Holmberg, and Region III Lead Inspector for

Braidwood Nestor Feliz

-Adorno and the Safety PM Daneira

Melendez.

When the staff makes its presentations, 10 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 we=ll introduce our members who will be making comments at the time. This is the ACRS Subcommittee Meeting

for the License Renewal Application of Byron Station Units 1 and 2 and Braidwood 1 and 2. The SER with open

items was issued on October 30, 2014 with two open items.

But its resolution will be documented in the Final

SER. The first item of the open items pertains to control rod drive mechanism penetration nozzle wear due to interactions with thermal sleeve centering tabs.

The second open item is in the same regard to

environmentally assisted fatigue in Class I components.

Both open items are summarized in the SER reviewed

by the ACRS members. Since the issuance of the SER with open items, the staff has been working very diligently on resolution of these items. In addition to these open items, the staff has been working closely with Region

III inspectors to resolve issues that arose as a result

of the 71002 inspections.

The staff will summarize its completed review of the open items and the issues from the

inspection in the Final SER and present its findings

to the ACRS full Committee. We look forward to the 11 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 discussion and the review today. I

=d like to turn it over to Mike Gallagher of Exelon for their presentation.

EXELON GENERATION COMPANY

- BYRON STATION, UNITS 1 AND 2, AND BRAIDWOOD STATION, UNITS 1 AND 2 - BBS MR. GALLAGHER: Okay. Thank you, Chris.

Good morning. My name is Mike Gallagher and I

=m the Vice President of License Renewal Projects at Exelon.

I have 33 years of nuclear power plant experience all at Exelon and have been working on our license renewal

project since 2006. I think we=ve seen us here from

time to time.

Before we begin the presentation, I

=d like to introduce the presenters. To my right is John Bashor

and John is the Braidwood Engineering Director. John has over 30 years of nuclear power plant experience

including the last four years at Braidwood.

To John=s right is Albert Piha. And Albert is our Mechanical Manager for the Byron

-Braidwood License Renewal Project. Albert has over 32 years of

nuclear power plant experience including working on

Exelon=s license renewal project since 2008.

To Albert

=s right is Ed Blondin. Ed is the Senior Manager of Design Engineering at Byron Station. Ed has 28 years of nuclear power plant 12 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 experience including over 24 years at Bryon. To my left is John Hufnagel. And John is our Project Licensing Lead. John has 35 years of nuclear power plant experience including working on

Exelon=s license renewal project since 2005.

In addition is our technical support personnel which you see here with us today. We have with us today Mark Kanavos. And Mike is our Site Vice President at Braidwood. And we have Russ Kearney. Russ is our Site Vice President at Byron. And we have Dan Enright.

And Dan is Senior Vice President of the Midwest Operations. Slide 2.

This slide shows our agenda for the presentation. We will present to you some background information on the stations and the highlights of our license renewal application. Then we

=ll present to you the open items in the SER and items of interest

that came from the Region III inspections.

We believe we

=ve developed a robust, high quality license renewal application. We

=ve developed

effective aging management programs to ensure the

continued safe operation of Byron and Braidwood. We

appreciate this opportunity to make this presentation and look forward to answering any questions you may 13 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 have. CHAIRMAN SKILLMAN: Mike, as you begin, may I ask you please to give my collea gues and me a thumbnail view of how you

=ve treated commonality versus

uniqueness from the four plants and two plants. CHAIRMAN SKILLMAN: Yes, Mr. Skillman.

So we approached our reviews on a per unit basis to ensure that we captured everything on a plant

-specific

basis including plant

-specific operating experience

and so on. And the stations are very, very common.

If I can, I didn

=t have it in our presentation, but I=d like to put a back-up slide we had, slide number 2. This slide is going to show you

our AMR line item line

-up for the Bryon

-Braidwood stations. When we say station, it

=s Bryon Station, Braidwood Station and then we have the two units, Unit

1 and Unit 2 of each one.

This slide is just an overview of the line item basis. I

=m going to ask Dylan Cimock of our project team to go over this. Essentially, we

=re trying to show that the sites are very, very common.

Dylan. MR. CIMOCK: Dylan Cimock, License Renewal Team. Just to expand on what Mike said, the way we 14 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 approached the scoping, screening, AMR, operating experience review was on a unit

-by-unit basis. We looked at the individual P&IDs, pipe and instrument

diagrams, for each individual unit, established our

scoping boundaries, accounted for each individual

component type, its functions, materials and

environments. Where differences appeared either between the units of a given station or between the stations themselves, we identified those in our scope

and descriptions usually with the Byron or Braidwood only parenthetical in our application. Same thing in

our aging management review tables. So this table that we have up here on the back-up slide, when we originally submitted the

application we had approximately 6400 individual AMR line items. Of those, approximately 86 pe rcent represented no differences between the two stations or units. Fourteen percent was either a station or unit difference. And looking at that, the vast majority of these were all related to two principal differences which were differences in the clea n water source or ultimate heat sink or due to replacement of

the steam generators on Byron and Braidwood Unit 1 that

was not done on Byron and Braidwood Unit 2.

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-3701 (202) 234-4433 MR. GALLAGHER: Thank you. MEMBER POWERS: When you say there were no differences, manifestly there are differences. So there is some criterion you used in the percentage of

no differences. But what are these? MR. CIMOCK: That would depend on the aspect of the project. From a scoping standpoint, we looked at the things that, yo u know, the systems,

structures, components that meet Part 54 rule. From

an aging management standpoint, we looked for

differences in component types, functions, materials,

environments. From the programmatic standpoint, we

looked at differences in operating experience and

design to identify when we evaluate our programs whether or not new enhancements or certain acceptance would

needed to be taken when comparing our programs against

the GALL or ISGs. MR. GALLAGHER: Yes. Dr. Powers, what we=re trying to show here when we say no differences

which is what your question is that

=s an AMR line item.

So it=s a material

-environment combination. We

looked at each unit specifically and identified that

those material and environment combinations were

identical for each.

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-3701 (202) 234-4433 MEMBER POWERS: Manifestly, they

re not identical environments. They=re shifted in space by some distance. So there has to be some criterion. MR. GALLAGHER: Right. But here it

s from the GALL as far as what the environment would be. You

know if it

=s indoor air or that type of thing. That

=s what we=re saying when we say consistent with GALL.

So this would be the line item consistency with the

GALL. And as Dylan said then we applied which then leads you to the aging management program to develop. And our intent is to have a common aging management program for the most part because the high number of line items are common that=s achievable.

Did we answer your question, Mr. Skillman? CHAIRMAN SKILLMAN: It did for me. Dr.

Powers? MEMBER POWERS: Well, the problem that I see is yes, this is inside. It

=s in the air and whatnot.

I=m sure that the temperature of the air it was exposed to was different. The air flow over it was different.

But there has to be some point at which you say those differences

-- maybe small

-- just didn

=t amount to anything significant.

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-3701 (202) 234-4433 MR. GALLAGHER: And I think the way that

=s borne out is in the operating experience. So we did a plant-specific operating experience review.

MEMBER POWERS: There you go.

MR. GALLAGHER: And then that

=s how we detected it.

MEMBER POWERS: So they

=re based on a combination of engineering judgment. Two

-tenths of

a degree just doesn=t make any difference.

MR. GALLAGHER: And our review of operating experience. MEMBER POWERS: We looked at the operating experience and we found out that the thing had screwed up in exactly the same way every time at the same place.

MR. GALLAGHER: And where there were differences in operating experience, we factored tha t

into our programs.

CHAIRMAN SKILLMAN: Thank you. Let

=s continue.

MR. GALLAGHER: So now let me turn the presentation over to John Bashor. John.

MR. BASHOR: Thank you, Mike. Slide 3 please. Good morning. My name is John Bashor. I=m

the Engineering Director at Braidwood Generating 18 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 Station.

Let me first explain our presentation

=s color coding. We have a gray highlighted header on slides we

=re presenting on information that is common to both stations. For Bryon

-only information, the

header or information is highlighted in green and for

Braidwood only blue.

Bryon and Braidwood Stations

= Units 1 and 2 are Westinghouse pressurized water reactor, four

-loop designs that are owned and operated by Exelon. The Bryon Generating Station is located in the State of

Illinois approximately 95 miles northwest of Chicago.

And the Braidwood Generating Station is located in the State of Illinois approximately 60 miles southwest

of Chicago. Slide 4 please. This slide shows an overview of the Byron Generating Station. On this slide, you can see the

containment structures, the auxiliary building and the turbine building which are located in the center of the picture. The circulating water cooling towers and

flume, the circulating water pump house, the

independent spent fuel storage installation, the 345 kV switchyard and the essential service water cooli ng towers which are the station=s ultimate heat sink.

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-3701 (202) 234-4433 CONSULTANT BARTON: May I ask you a question about the switchyard? Is a lot of the equipment in the switchyards for SBO and is maintenance

done in the switchyards?

I=m sure the plant staff is not doing the maintenance in the switchyard. Someone else is. And

who is that? MR. GALLAGHER: We have a person here, Doug Overbeck. Doug, you can answer that question.

MR. OVERBECK: Doug Overbeck, Braidwood Station Plant Engineering. The maintenance in the

switchyard is performed by Commonwealth Edison

personnel. MR. GALLAGHER: Is that microphone on?

Sorry. CONSULTANT BARTON: Thank you. Now my question is when those people want to go into the

switchyard and do work, how is the plant involv ed?

I know the plant has to oversee in some respect to that

work since it is vital to plant operation. MR. GALLAGHER: Yes, and Doug can tell you about the controls we have.

MR. OVERBECK: The process is that Commonwealth Edison submits work requests to t he 20 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 station and the station provides work orders and put it in our process. They

=re put in the schedule.

They=re evaluated for risk and time of execution.

Operations has to approve the work order. They also

approve access to the switchyard.

CONSULTANT BARTON: Thank you.

MR. GALLAGHER: Thank, Doug.

John.

MR. BASHOR: Slide 5 please. This slide shows an overview of the Braidwood Generating Station.

On the slide you can see the containment structures, the auxiliary building and the turb ine building which

are located in the center of the picture. The lake

screen house, the independent spend fuel storage installation, the 345 kV switchyard and the cooling

pond which contains the station

=s ultimate heat sink.

As you can see from these stat ion overviews with the exception of the cooling water source, the physical and design characteristics of the two stations

are essentially identical. Slide 6 please.

This slide provides an overview of Byron and Braidwood histories and some major station

improvements. Byron was initially licensed in 1994 for Unit 1 and 1986 for Unit 2. Braidwood was initially 21 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 licensed in 1986 for Unit 1 and 1987 for Unit 2. All four units were initially licensed for a rate of thermal

power of 3,411 megawatts thermal (MW t). A five percent increase in rated power on all four units was performed in 2001. In April of this

year a 1.63 percent measurement uncertainty recapture (MUR) power uprate was implemented which increased the thermal rating on each unit to their current rating of 3645 MW

t. Exelon has also continued to make substantial improvements to both Bryon and Braidwood units such as steam generator replacements on Byron Unit 1 and Braidwood Unit 1, emergency core cooling

system (ECCS) recirculation sump screen modifications, spent fuel rack replacements and independent spent fuel

storage installations (ISFSI).

Byron and Braidwood are operated on 18-month fuel cycles and ASCE factor for this year as of the third quarter is greater than 95 percent for

each station.

The renewal application was submitted on May 29, 2013. Our current license at Byron expires

on October 31, 2024 for Unit 1 and November 6, 2026 for Unit 2. Our current licenses at Braidwood expire

on October 17, 2026 for Unit 1 and December 18, 2027 22 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 for Unit 2. I will now turn it over to Albert Piha who will present to you the highlights of our license renewal application.

CHAIRMAN SKILLMAN: Before you change, keep that slide. John, go ahead.

CONSULTANT BARTON: You change out steam generators on Unit 1 at both sites. Unit 2 has the original steam generators. Is there any plan that you see now for replacement of steam generators in Unit

2 at both sites? MR. BASHOR: If you look at the long range plan, Mr. Barton, you will see steam generator replacement out in the out years.

CONSULTANT BARTON: We currently do not have active projects that are underway for either Byron

or Braidwood actively pursuing that. But we are

constantly monitoring the results of the inspections

we do on the steam generators at both Byron and

Braidwood. And we realize that if we run into a

situation where we see accelerated plugging of tubes

we may find ourselves in a situation where replacement

will be required in the future. CONSULTANT BARTON: Okay. You=

re kind of 23 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 lucky because I know a lot of plants have changed out Westinghouse steam generators.

MEMBER BALLINGER: You=re one of the two unusual ones. MR. GALLAGHER: The Unit 2 had better materials originally in the original construction.

The Unit 1 did not. And that

=s really the difference

there. CONSULTANT BARTON: Unit 1 was also B&Ws, right? MR. BASHOR: Unit 1s are B&W. They were all original Westinghouse.

CONSULTANT BARTON: Okay. I gotcha.

CHAIRMAN SKILLMAN: Let me ask my question please. Reviewing the AMPs and this is steam generator

program B.2.1.10 directed specifically at Bryon, the

wording in the inspector=s report is AFor the second

enhancement applicable to Byron Unit 1 steam generators, the existing AMP will be enhanced to

validate that the PWSEC of the tube sheet welds is not

occurring.@ That=s in the inspection report. I do not have the inspection report results for Braidwood Unit 1 which is also a B&W steam generator design. Is that same AMP applicable to Braidwood Unit 24 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 1? MR. BASHOR: Yes sir. Is the steam generator -- Where is that at?

CHAIRMAN SKILLMAN: That

=s what I=m asking. There

=s an enhancement on Byron 1 steam generators that I

=m wondering if that same enhancement

is applicable to Braidwood. MR. BECKNELL: I=

m Gary Becknell, License Renewal Project Team. The enhancement is applicable to both stations, Byron and Braidwood, for the

verification that water chemistry is controlling

primary water stress corrosion cracking.

CHAIRMAN SKILLMAN: Yes sir. Thank you.

Thank you, Mike.

MEMBER RICCARDELLA: Just another question.

What are your plans with respect to the reactor vessel

top heads at Byron and Braidwood? MR. BASHOR: Right now, we find ourselves in a unique situation, Dr. Riccardella. We have not replaced the heads at Byron or Braidwood. I would like

to have Jack Feimster stand up and give a summary of

what we=re doing in that area specifically looking at

a mitigation strategy we

=re putting in place in the

future.

25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 MR. FEIMSTER: I=m Jack Feimster, Senior Engineering Manager at Byron Station. Currently, Exelon is pursuing a mitigation strategy for reactor vessel heads. Specifically in our particular case,

we=re pursuing peening of the affected area. The company we have chosen is AREVA. We

=re going to use what are

water jet cavitation peening.

MEMBER RICCARDELLA: Thank you.

MR. GALLAGHER: Thanks, Jack.

MR. BASHOR: I will now turn it over to Albert Piha who will present to you the highlights of

our license renewal application.

MR. PIHA: Thank you, John. Slide 7 please. Good morning. My name is Albert Piha and I am the Byron and Braidwood License Renewal and Mechanical Manager. I will discuss the highlights of

our license renewal application including the aging

management programs, commitments and an overview of

the two open items in the SER. Slide 8 please.

In preparing the application, Exelon used industry and NRC guidance to make the application as

consistent with the GALL as possible. Our submittal

was based on GALL Revision 2. There are 45 aging

management programs at Byron and 44 at Braidwood.

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-3701 (202) 234-4433 The difference in the number of the aging management programs is due to the fuse holder program which is applicable to Bryon only. They are

safety-related equipment found only at the Byron River screenhouse that required the application of this aging

management program.

Thirty-eight Byron programs and 37 Braidwood programs are consistent with the GALL. Seven programs at each station have exceptions to the GALL.

There are 47 license renewal commitments at Byron and 46 at Braidwood. Of these commitments, 45 at Byron

and 44 at Braidwood are associated with aging management

programs.

In addition, one common commitment at each station implements the operating experience program enhancements. The final commitment for each station

is to restore the out-of-service reactor vessel stud on Byron Unit 2 and on Braidwood Unit 2 no later than six months prior to entering the period of extended

operation.

These commitments will be captured within the license renewal UFSAR supplement and the Station

Commitment Tracking Database and managed in accordance with 10 CFR 50.59 and the Commitment Management Program 27 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 which is based on the NRC endorsed NEI 99-04 process.

CHAIRMAN SKILLMAN: Would you like to comment on Byron 2 stud 11 please? MR. PIHA: Yes. Byron Unit 2 stud was successfully removed last fall in October and a new stud was installed and all 54 studs are tensioned and

in service. CHAIRMAN SKILLMAN: Yes sir. So that leaves the one stud 35 on Braidwood 2 as a commitment

prior to PEO.

MR. PIHA: That=s correct.

CHAIRMAN SKILLMAN: Okay. Thank you.

CONSULTANT BARTON: While you

=re on it, do you currently have a plan of how you

=re going to

do stud 35 since it

=s not just threads that are messed

up. You have a larger hole on that head. MR. GALLAGHER: Yes, that

=s going to take us a little more work, Mr. Barton. What we=re doing

is next outage we

=re going to be taking

-- We attempted a repair in 2002 as you know.

CONSULTANT BARTON: Yes.

MR. GALLAGHER: And it was

-- There was a problem with the machine. And it was over bored at

the time.

28 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 CONSULTANT BARTON: Right. MR. GALLAGHER: So we want to take detailed measurements. We want to know exactly what

=s down there and develop a modification and in a subsequent

outage install it. Our commitment is to get it done before as Albert said six months before PEO. But we

=re making good progress already. We did the one at Byron

and we=re pursuing the one at Braidwood.

CONSULTANT BARTON: You=ve got until the license extension starts.

MR. GALLAGHER: Yes.

CONSULTANT BARTON: And in my mind when do you have that kind of thing planned out? Is it the

last outage before you go into

-- which takes it to the difficulty maybe? MR. GALLAGHER: No. Our intent is to move forward with this. And as I said, we did on Byron Unit

2. We took care of that.

CONSULTANT BARTON: Right. But that was a lot easier fix. MR. GALLAGHER: Yeah, but that was the one that had the aging management question because you had

the stud, partial stud, in there.

CONSULTANT BARTON: Right.

29 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 MR. GALLAGHER: And so getting it out was a big win. We were able to put a new one in. On Braidwood, we=ve got to get the measurements and the

design that we know is going to work and then move

forward with that.

MEMBER STETKAR: You don

=t have it scheduled.

MR. GALLAGHER: No, we

=ll get the measurements next outage. Then from there we

=ll plan what we need to do. Okay.

All right, Albert.

MR. PIHA: Slide 9 please. There are two open items in the Byron and Braidwood SER. Slide 10.

The first open item is associated with the screening methodology for environmentally assisted

fatigue (EAF) to determine leading locations Leading

locations are those locations which have been

determined to bound all other locations for

consideration of environmental fatigue.

Monitoring these locations for the period of extended operation will ensure no location will

exceed an environmental fatigue usage factor of 1.0.

This includes consideration of both the NUREG

-6260 locations to determine appropriate for a new 30 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 Westinghouse PWR and those locations determined could be more limiting than the 6260 locations.

Leading locations were determined by comparison of environmental fatigue experienced at locations in transient sections. A transient section is defined as a grouping of equipment or piping

experiencing the same transients.

The NRC staff has requested more information in three areas. The first area is

concerned with the staff

=s request for additional

justification that the leading material locations will

continue to bound eliminated locations after refined

analysis. Assessment of the relative differences in

screening environmental fatigue usage results, the

relative differences in the conservatism in a stress

analysis and the potential variation in the

environmental correction factor justified a determination of the leading material location. With

a refined analysis, leading locations are evaluated with both improved analysis techniques and a review

of their inputs.

Considering refined analysis, it was shown the leading locations will continue to bound the eliminated material locations. The result of this 31 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 analysis is the establishment of limits for the fatigue monitoring program to assure environmental fatigue is

managed during the period of extended operation.

For the second area, the staff requested justification why the Bryon and Braidwood Unit 1

replacement steam generator location was removed from consideration as a leading location when its screening environmental fatigue usage factor was higher than the

location selected as the leading location. Because of the conservatism in the stress analysis for this location, it was shown that the steam generator location has a screening environmental fatigue usage lower than

the leading location when it points similar

conservatism in the stress analysis.

In the third area, the staff requested identification of other instances where a component location was removed from consideration which had a

higher screening environmental fatigue usage factor

than the location selected to be the leading location.

Two other locations in the piping systems wer e

identified and had the same justification as the steam

generator location.

To resolve this issue, we have provided the additional information to the staff in a letter 32 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 dated November 25, 2014.

CHAIRMAN SKILLMAN: Albert, before you move from that slide, would you make a comment to my colleagues and me about what it actually takes for a

utility to do an environmental CUF calculations? Is this something that you do on your own? Is it something

you go out and buy a specialty contract for? How is

this work conducted and what

=s the impact on your staff?

MR. PIHA: For us, on this project, we did contract an outside consultant to do this work for us.

We have a TLAA engineer who is involved, interfaces

and reviews and comments on all the work that=s done

by the contractor. CHAIRMAN SKILLMAN: So it

=s really handled under the TLAA portion of license renewal.

MR. PIHA: That=s correct.

CHAIRMAN SKILLMAN: Thank you.

MEMBER RICCARDELLA: We just sat through a meeting yesterday on the revisions to Reg Guide 1.207

and the NUREG

-6909 which is changing these environmental things somewhat. I think in general they

become less onerous. But are there plans to

incorporate those new revisions in, too? MR. PIHA: I=

m going to let Tom Quintenz, 33 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 our TLAA engineer, speak to that.

MR. QUINTENZ: Tom Quintenz, License Renewal Project. I believe your question had to do with the new Reg Guide 1.207 that is in draft right

now. MEMBER RICCARDELLA: Yes.

MR. QUINTENZ: And I think you were asking about the encumbrance of the new draft guide.

MEMBER RICCARDELLA: Yes. Are you planning to address that?

MR. QUINTENZ: My understanding is that it=s employing NUREG-6909 as the guide for doing the

environmental fatigue. Basically, we

=ve done our

calculations for the nickel locations using 6909. So we have experience with that. MEMBER RICCARDELLA: But that

=s a 6909 Rev 1 that I=m thinking of.

MR. QUINTENZ: That

=s correct. That

=s still under review. We understand that.

MEMBER RICCARDELLA: Do you have future plans for that new methodology? MR. QUINTENZ: We would have to. We

=re a part of the industry comment on both of those items.

I think we would be awaiting to see what the results 34 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 of that would be.

MEMBER RICCARDELLA: Okay. Thanks.

MEMBER BALLINGER: When you said monitoring the fatigue locations, can you expand on

that just a little bit? MR. PIHA: I=

ll have Tom also answer that question.

MR. QUINTENZ: Tom Quintenz, License Renewal Project. This involves basically monitoring

the transients which are inputs to the fatigue analysis.

So when we say we are monitoring the location, we

=re actually monitoring the transients which were inputs

to the fatigue analysis for that location.

MEMBER BALLINGER: When you say monitoring, you mean measuring the temperature and

things like that or just. MR. QUINTENZ: Yes, we basically look for the transient and we characterize the temperature and pressure profiles to make sure that they agree with

the design inputs that were with the fatigue analysis.

MEMBER BALLINGER: When you say characterize, you mean measure it or calculate.

MR. QUINTENZ: Measure.

MEMBER BALLINGER: Okay.

35 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 CHAIRMAN SKILLMAN: Pete and Ron, are you good? MEMBER BALLINGER: Yes.

MEMBER RICCARDELLA: I=m good.

CHAIRMAN SKILLMAN: Go ahead, Mike. Or excuse me. Go ahead, Albert. MR. PIHA: Slide 11 please. The second open item involves the aging management of the control rod drive mechanism or CRDM housing for wear due to thermal sleeve rotation. The CRDM housing is man aged by the ASME Section XI, Subsections IWB/IWC/IWD Aging

Management Program.

The NRC staff has requested more information in two areas, the results of the CRDM

Housing Wear Analysis and also the CRDM Housing Wear

Acceptance Criteria. Our presentation will provide background information on the CRDM Housing wear and will address the areas where the NRC staff had requested

more information. The additional information will address this open item. It has been submitted to the NRC staff for their review in a letter dated November

24, 2014.

I will now turn the presentation over to Ed Blondin who will discuss the CRDM Housing wear.

36 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 MR. BLONDIN: Thank you, Albert. Slide 12 please. Good morning. My name is Ed Blondin. I

=m the Senior Manager of Design Engineering at Byron

Station. On this slide, a cross section of the reactor vessel head is shown with the control rod drive mechanism housings or CRDM housings shown in blue.

Inside these housings is a thermal sleeve which is

illustrated in green. At Byron and Braidwood, the

reactor vessel heads have thermal sleeves installed in 55 of the 78 CRDM housings. The CRDM housings are part of the reactor coolant pressure boundary and are

made of nickel alloy in the area of interest.

The thermal sleeve --

MEMBER BALLINGER: Six hundred or 625 or 690? What do you mean by nickel alloy?

MR. BLONDIN: Phil.

MR. O=DONNELL: Phil O

=Donnell, License Renewal Team. They=re at alloy 600.

MEMBER BALLINGER: Six hundred, okay.

MR. O=DONNELL: Yes.

MEMBER RICCARDELLA: That=

s related to my earlier question about the reactor vessel head. But this is a wear problem. This isn

=t a cracking problem.

37 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 MEMBER BALLINGER: Yes.

MR. BLONDIN: The thermal sleeves are loosely inserted into the CRDM housings a nd are not

physically attached. The thermal sleeves are approximately 60 inches in length. There are three centering tabs shown in black 120 degrees apart located

approximately 22 inches below the top of the thermal sleeve. The thermal sleeve centering tab material is

stainless steel.

Thermal sleeves are used to mitigate the effects of reactor coolant temperature in the upper

reactor vessel head region on the control rods. The thermal sleeves also provide a means of guiding the

control rods into the housing following refueling operations. Rotation of the thermal sleeves within

the CRDM housing occurs due to normal operation from

reactor coolant flow in this region. CHAIRMAN SKILLMAN: What is the propellant that causes the rotation? If you can describe the force diagram for us, that would help.

MR. BLONDIN: Go ahead, Phil.

MR. O=DONNELL: Phil O

=Donnell, License Renewal Team. Because it

=s a T-cold head, there is

a substantial amount of coolant flow, approximately 38 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 three percent, that e nds up going through that particular region. And since the thermal sleeves are

not fixed, they actually

-- the flow past them causes it to rotate.

MEMBER BALLINGER: How are the tabs attached? By welding?

MR. O=DONNELL: They are attached by welding. That is correct. MEMBER BALLINGER: And so then I come back to the alloy 600 issue. Is it thermally treated or

is it just a tubing that

=s extruded and no particular

heat treatment like you would have in a steam generator

tube? MR. O=DONNELL: I would have to get back to you on that.

MR. GALLAGHER: George, do you know?

MR. O=DONNELL: We can get back to you.

MEMBER BALLINGER: Because I

=d be more than worried about -- It=s not a stress component.

It=s not a pressure boundary. But that weld point is a point of high residual stress. And it goes all the

way around or is it just tabs.

MR. O=DONNELL: They=re just tabs.

MEMBER BALLINGER: They

=re just tabs, 39 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 okay. MR. O=DONNELL: Phil O

=Donnell, License Renewal Team. The tab is stainless steel.

MEMBER BALLINGER: Yes, but it

=s welded to the 600.

MR. O=DONNELL: No, no. The tab is on the thermal sleeve.

MR. BLONDIN: The thermal sleeve are stainless steel.

MEMBER BALLINGER: Oh, I thought I heard you tell me that the thermal sleeve was alloy 600.

MR. O=DONNELL: No, the housing. MEMBER BALLINGER: All right. Now I

=m oriented properly. MEMBER RICCARDELLA: And the cooling flow you=re referring to is in that annulus between the

thermal sleeve and the housing or no?

MR. O=DONNELL:

Phil O=Donnell, License Renewal Team. It is past the thermal sleeves. It is not going up into that region. It basically goes down

the head. CHAIRMAN SKILLMAN: So the rotating force is the friction from the T

-hot coming over the top of

the head.

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-3701 (202) 234-4433 MR. O=DONNELL: It=s actually T-cold.

CHAIRMAN SKILLMAN: T-cold.

MR. O=DONNELL: Yes.

CHAIRMAN SKILLMAN: So it

=s a friction on the -- What=s it called?

MR. BLONDIN: The thermal sleeve.

CHAIRMAN SKILLMAN: The thermal sleeve.

MR. O=DONNELL: Yes.

CHAIRMAN SKILLMAN: And it

=s just the turbulent flow on the top of the head that=s causing

these things to rotate.

MR. O=DONNELL: That is correct.

CHAIRMAN SKILLMAN: Is this a phenomenon that is common to the four LOOP Westinghouse plants?

MR. O=DONNELL: This is common to Westinghouse plants.

MR. PIHA: We

=re going to discuss about a report that=s been completed. And it was done for

participating utilities in the industry for the same

situation. CONSULTANT BARTON: This is the first time I think we=ve heard this problem though.

CHAIRMAN SKILLMAN: It

=s the first time I=ve heard of it.

41 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 CONSULTANT BARTON: Yes.

CHAIRMAN SKILLMAN: It could be others have heard of it. But I certainly haven=t. CONSULTANT BARTON: I mean as far as seeing other plant renewals, Westinghouse units, this has not come up. CHAIRMAN SKILLMAN: I don

=t remember this from the last meeting.

MEMBER BALLINGER: Now these are T

-cold heads, all of them. So that puts the susceptibility

to J-groove problems way, way down.

CONSULTANT BARTON: Yes, it drops the temperature. Except they=ve had a few leaks here at

a couple of these plants. MEMBER BALLINGER: I know. That was my next question. CONSULTANT BARTON: Relatively few. It=s some of them are from that unique Cuban mater ial that

has unusual susceptibility.

CHAIRMAN SKILLMAN: Let me ask this. Is this a phenomenon that began --

MEMBER RICCARDELLA: Right. They hadn=t had the cracks. I=m sorry. I misspoke.

CHAIRMAN SKILLMAN: Is this a phenomenon 42 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 that has occurred since you did your power upgrades?

Did it exist before then or is it new after the power

upgrade? MR. GALLAGHER: The phenomenon is believed to have existed --

CHAIRMAN SKILLMAN: From the very beginning?

MR. GALLAGHER:

-- from the very beginning. The reason that there

=s information on this

now and that there

=s an industry initiative to

investigate this is because when you do the J-groove

weld inspections you can see in the ones that are at

the center, the centering tabs are near the J-groove

weld. So you can see this scratching pattern.

CHAIRMAN SKILLMAN: Right.

MR. GALLAGHER: So that

=s why it=s come up fairly recently in the industry. And as Albert said,

there=s a PWR owners group analysis. George Demetri is here. He=

s the Westinghouse author of the analysis.

And we=re going to go through the details for you here with what we

=re trying to show you and

I hope we corrected your mental image. MEMBER BALLINGER: I thought somebody said alloy 600 for the sleeve.

43 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 MR. GALLAGHER: Yes. If we could just go to the next slide for a minute because we have a closer thing in here. Yes, just for clarity, the thermal sleeve is stainless steel. The tab is on the thermal sleeve and it wears on the nozzle. And Ed will get

into the rest of this. MEMBER RICCARDELLA: The wear is in the alloy 600. MR. GALLAGHER: Yes. And that=

s the area that is a pressure boundary. And that=s why we have

reviewed this and have this analysis.

MEMBER BALLINGER: So the required under head inspection plan when you get that tab very close to the top of the J

-groove walls at the center, is that

looked at as a possible initiation point for cracking?

The stresses from the J

-groove weld might get far

enough above so that they

=re in a region where that

wear pattern might influence things.

MR. GALLAGHER: George can answer that.

MR. DEMETRI: George Demetri with Westinghouse Electric Company. We don

=t consider

that. It

=s considered, we analyze it as a wear phenomenon and we did account for stre ss concentration,

stress intensification there.

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-3701 (202) 234-4433 MEMBER BALLINGER: On the initial of the alloy 600?

MR. DEMETRI: Yes, that=s correct.

MEMBER BALLINGER: Okay.

MEMBER RICCARDELLA: How close does it get to the J-groove weld on the top dead center?

MR. DEMETRI: It could be

-- It could actually span the top of the J-groove weld. MEMBER BALLINGER: Okay. So that=

s right in the region. MEMBER RICCARDELLA: But it could be in the residual stress weld.

MR. DEMETRI: Residual stress in that weld. MEMBER RICCARDELLA: But I mean they

=re inspecting for cracks.

MEMBER BALLINGER: Yes, but there

=s an under head inspection plan.

MEMBER RICCARDELLA: Right.

CHAIRMAN SKILLMAN: I think we

=re going to hear more about that in a few minutes. MR. GALLAGHER: Yes. So at this point and basically to fast forward a little bit what we

=re trying

to show here is that you can wear the complete thickness 45 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 of the tab and it

=s still acceptable. And Ed will get into the details. Ed.

MR. BLONDIN: Okay. So as we started to talk about, it is common to the Westinghouse PWR design

and it=s been recently evaluated by Westinghouse for

the PWR owners group using finite element analysis. MEMBER STETKAR: Ed, if we could before you get into the analysis, to follow up on something John raised, are Byron and Braidwood the first plants to observe this wear? I mean I

=m curious why we haven

=t heard about it in any of the others. We heard about

license renewals for several Westinghouse plants over

the last seven years I

=ve been in the Committee. This is the first one where it=s come up. MR. BLONDIN: Phil, do you know what other plants? MR. O=DONNELL: This is Phil O

=Donnell, License Renewal Team. Actually, in the last one that

you did with TVA, that was also in the SER.

MEMBER STETKAR: It was. I missed it.

MR. O=DONNELL: Yes.

MEMBER STETKAR: But it wasn

=t challenged by anybody in the review.

MR. O=DONNELL: That=s correct.

46 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 CHAIRMAN SKILLMAN: But before then it was not a -- At least it was not communicated.

MR. O=DONNELL: It was not communicated because they were also I believe going --

MR. GALLAGHER: There=s difference here, Mr. Skillman. We don

=t want to talk about other plants.

CHAIRMAN SKILLMAN: Right. I understand.

I was just curious. That

=s why I asked Westinghouse.

MR. GALLAGHER: Some of the plants with newer heads don

=t have the phenomenon because there are some design differences.

CHAIRMAN SKILLMAN: Okay.

MR. GALLAGHER: So it

=s not -- it=s basically we have this and many other plants have it. But we can=t go on a case-by-case basis.

CHAIRMAN SKILLMAN: All right. Thank you. MR. BLONDIN: I

=ll continue. The analysis examined the impact of the hypothetical maximum wear depth on the integrity of the CRDM

housings.

CHAIRMAN SKILLMAN: And the maximum wear depth is the entire thickness of that tab into the

primary coolant system pressure boundary ID.

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-3701 (202) 234-4433 MR. BLONDIN: That is correct. And I=ll talk more about that in a moment.

CHAIRMAN SKILLMAN: Okay. MR. BLONDIN: Based on the analysis, it was it was also determined that if the maximum

hypothetical wear depth is assumed the CRDM housings

will continue to meet the ASME Code requirements and

the current licensing basis.

MEMBER BALLINGER: Okay. I

=ll keep harping on this. But at the maximum depth, you have margin on crack growth if you initiate a stress

corrosion crack growth rate. Or are you just saying

AWe=re not going to initiate a crack growth because

we=re going to peen it or something@?

MR. DEMETRI: George Demetri, Westinghouse Electric. We just analyzed it as a wear

phenomenon, but we have not looked at it from the

standpoint of crack growth.

MEMBER BALLINGER: I think somebody should. CHAIRMAN SKILLMAN: Let=s proceed.

MR. BLONDIN: Okay. Details are further explained on the next slide, slide 13 please. The

expanded view of the CRDM housing area prone to wear 48 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 was shown is shown in the detail on this slide. When the thermal sleeve rotates within the CRDM housing the centering tabs again shown in black r ub against the CRDM housing and cause wear at the centering tabs and the housing. The wear is not evenly distributed within

the inside diameter of the CRDM housing due to the flow

induced vibration on the thermal sleeves.

The hypothetical maximum possible wear depth of the CRDM housing at the thickness of the

centering tab is 0.1075 inch. Assuming that the

maximum possible wear depth was to occur, the CRDM

housing thickness would be reduced from the original

0.625 inch to 0.517 inch. However, based on t he similarity and hardness of the metals with the nickel

alloy housing and the stainless steel centering tabs the CRDM housing and the thermal sleeve tabs will both experience wear. Therefore, the actual wear on the

CRDM housing is expected to be substantially less than

this worst case assumption. Slide 14 please.

The detailed ASME Code evaluation which includes finite element analysis and stress

calculations was performed by Westinghouse that considered the effects of the maximum wear depth on

the integrity of the CRDM housing. As stated earlier, 49 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 several Westinghouse PWRs have discovered similar wear indications on the CRDM housings.

Primary stress evaluations were performed using classical stress equations. Primary plus

secondary stress integrity ranges and fatigue usage factors were determined by finite element analysis.

The CRDM housings were evaluated for the design, normal,

upset, emergency, faulted and test conditions as

required by the ASME Code. The evaluations also

considered the UFSAR design requirements with respect to transients, loading and allowable stresses. The

analysis demonstrated that the CRDM housing with the maximum possible wear group depth of 0.1075 inch

satisfies all of the allowable stress and fatigue limits

for Section III, Subsections NB-3221 through NB-3226

of the ASME Code.

Since the analysis considered a conservative set of enveloping mechanical loads and pressure and thermal transients as well as a highly

unlikely wear group depth of 0.1075 inch, the CRDM housing with inside surface wear is acceptable.

Additionally, the Byron and Braidwood 40 year design basis transients were analyzed to determine if the number of cycles was bounding for the 60 year period.

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-3701 (202) 234-4433 Based on the review, the 60 year design basis transients set for the period of extended operation is bounded by this CRDM housing analysis. Slide 15

please. In summary, the applicable ASME Code limits for Class 1 for reactor coolant pressure bounded components have been utilized in our analysis. And the CRDM housing was evaluated as acceptable for the period of extended operation. As the Byron and Braidwood 40 year design basis transients have been

shown to be bounding for the 60 year design basis transient set, then this analysis is also valid for the period of extended operation.

The CRDM housing wear acceptance criteria as prescribed in ASME Section III, including the fatigue analysis, have been met for the impact of the

hypothetical maximum tab wear on the inside of the CRDM

housing. No additional actions are required for aging

management of the CRDM housing wear. This concludes our presentation for the CRDM housing wear open item.

At this time, I would like to turn the presentation over to Albert Piha to introduce our items

of interest from the Region III inspections.

CHAIRMAN SKILLMAN: Before we change the 51 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 slide on that third bullet, those words after the parenthesis, A no additional aging management

activities,@ does that communicate no inspections?

MR. PIHA: That=s correct.

CHAIRMAN SKILLMAN: Is that your intent not to look at it?

MR. PIHA: That=s correct.

CHAIRMAN SKILLMAN: Don

=t you think at some point in the future you ought to take a look to

confirm?

MR. PIHA: Today there isn=t a qualified technique to look at this area. But this analysis says that we could have full wear depth and we meet all code

limits and acceptance criteria.

CHAIRMAN SKILLMAN: Is the process to inspect the pressure housing portion of the stump of

the control rod drive extension a process the requires removal of the control rod drive and then removal of

the sleeve? Is that what it takes to do that

inspection? MR. PIHA: George, do you have an answer?

MR. DEMETRI: Yes, George Demetri, Westinghouse. You would definitely need to remove the

thermal sleeve to do that inspection.

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-3701 (202) 234-4433 CHAIRMAN SKILLMAN: But does a thermal sleeve withdraw if the mechanism is removed? Or is it blocked because of its geometry below the inside

portion of the --

MR. DEMETRI: Yes, it

=s blocked because of the funnel.

CHAIRMAN SKILLMAN: So it really cannot be pulled through.

MR. DEMETRI: That=s correct.

MEMBER RICCARDELLA: Let=

s talk about the ones that are near top dead center that are close to

the J-groove weld. When you inspect the J

-groove weld,

you don=t remove the sleeve, right? You have something

that goes in the annulus I believe. So for at least those penetrations you can get in the vicinity of this

wear, right?

MR. DEMETRI: Phil, can you answer?

MR. O=DONNELL: Phil O

=Donnell, L icense Renewal Team. Yes, basically when they do the J

-groove weld inspections they have a probe that goes up between

the thermal sleeve and the CRDM housing to look at that.

But what they have found though is that there is not

a qualified method right now to determine the wear depth

of any crack beyond that particular point.

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-3701 (202) 234-4433 MEMBER RICCARDELLA: I understand that, but to address the concern that Ron brought up is if you=re getting any stress corrosion cracking around

here at least on those penetrations I think you would see it. And my understanding is those inspections,

are they every outage for these because you

=ve had cracking?

MR. O=DONNELL: Phil O

=Donnell, License Renewal Team. For three of the plants it is because of the cracking of the J

-groove welds. They actually

do the inspections once per cycle. Braidwood Unit 2

is not currently

-- has no signs of cracking yet. So it=s every three to four to five cycles right now.

MEMBER BALLINGER: So these are being --

Those areas that you=re going to --

MEMBER RICCARDELLA: Are being inspected for stress corrosion cracking and crack growth. And there have been crack growth analyses done to support

those inspections.

MR. GALLAGHER: Oh yeah.

MEMBER RICCARDELLA: Of the J

-groove welds. Well, also the tubes in the vicinity of the

J-groove wells and at the top of the J-groove welds.

The only question I think that Ron raises is should 54 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 you consider the effect of this wear on those crack growth analysis. You know you

=ve got a 10 percent loss

of -- MEMBER BALLINGER: It=

s not so much crack growth as it is initiation. You know the wear affects

the initiation time.

MEMBER RICCARDELLA: Yes.

CHAIRMAN SKILLMAN: Please proceed.

Thank you. MR. PIHA: Slide 16 please. So there are three items of interest that were realized during the Region III inspections at Byron and Braidwood. These items are being discussed to acknowledge the issues that were raised and to provide reassurance that

effective aging management activities will be performed

on these in

-scope components during the period of

extended operation.

The items of interest are visual examination of concrete containment structures

applicable to both Byron and Braidwood Stations, the

CRDM seismic support assembly aging mana gement applicable to both Byron and Braidwood stations and

also the Braidwood Flux Thimble Tube Inspection

Program. Slide 17 please.

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-3701 (202) 234-4433 CONSULTANT BARTON: Let me ask you. Can I ask you a question on this concrete thing? You did repair the dome. That has been repaired. The concrete and the drainage issue on the dome has been repaired.

MR. PIHA: Yes.

CONSULTANT BARTON: Now how are you observing the repair of the dome? I can understand

when you=ve got it below the dome. You can whatever

.

But what are you doing for inspection of the dome to

make sure that you don

=t initiate additional issues

on the dome?

MR. PIHA: I

=ll have either Jim or Tim.

Tim Johnson. MR. JOHNSON: My name is Tim Johnson, Braidwood Engineering Programs. To review repair on

the dome, the classification is this is the dome

surface, correct?

CONSULTANT BARTON: Correct.

MR. JOHNSON: At Braidwood.

CONSULTANT BARTON: Right.

MR. JOHNSON: The repairs we

=ve done on those about 10 years ago were cosmetic. Where was no

reinforcing steel, we basically patched them and recoated them with epoxy. We monitor them every year 56 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 and to this point they

=re performing very well. No problems.

CONSULTANT BARTON: Thank you.

MR. PIHA: The first topic I

=ll address is associated with th e visual examination of the

concrete containment structures under the ASME Section

XI, Subsection IWL, Aging Management Program.

During the NRC Region III inspection, the inspection team sought additional clarification

regarding what visual resolution capability will be

used to sufficiently quantify degradation to compare

against the quantitative acceptance criteria described

in Chapter 5 of ACI 239.3R.

To ensure that sufficient visual resolution capability will be used during the direct

and remote visual examination of concrete surfaces of

containment structures, Enhancement 4 of the ASME

Section XI, Subsection IWL Aging Management Program has been revised to update IWL implementing procedures to require that the visual resolution capabilit y be sufficient to detect concrete degradation at the levels

described in Chapter 5 of ACI 349.3R. CHAIRMAN SKILLMAN: Albert, would you tell us what you

=re doing to accomplish that? Is this a 57 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 lens system that has greater magnification and some form of calibration? Or using sonar device?

MR. PIHA: Yes, we=re using a telescope.

MR. GALLAGHER: Tim.

MR. JOHNSON: I didn=t hear that.

MR. GALLAGHER: Tim, the question Mr.

Skillman had is how do we actually do inspections?

CHAIRMAN SKILLMAN: How do you really do this to make sure it=s done properly?

MR. JOHNSON: Yes, Tim Johnson, Engineering Programs Braidwood. The enhancement

basically incorporates something we

=ve done since the

inception of IWL.

The first inspection we did was

>01. And what we did because it was basically a new requirement was the industry went down to EPRI. And EPRI sponsored and recommended the use of Meade 10

-inch telescope that was capable of resolution of the character card letters

on the test card of the code.

What we did was physically went to the top of the containment. Braidwood and Byron are very

inspection friendly if you will. There are many galleries and rooms and areas where you can get close up inspection. What we did was go up to the second 58 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 gallery which just below it is the most limiting area from a distance perspective for inspection.

What we did is actually went up and measured cracks, crack widths, put simulated lines in there, measured them. There is some indication such as form ties, nails, form nails, that type of thing and actually identified those, physically measured them. We put the telescope down from different distances and angles to make sure we understood the limitations of the

equipment and resolved those indications. That

=s we=ve done it for the three inspections that we

=ve done.

And any other equipment we used, binoculars, we would do the same thing where we don

=t have the limiting factors as much as we did with the telescope. We were

able to resolved those characters. Then when we did the inspections, we could conservatively size what we saw if you will. So we

have a good baseline and a good repeatability through the inspections from an aging management perspective.

CHAIRMAN SKILLMAN: How are those records protected? Are they images? MR. GALLAGHER: He wants to have a record for our specs.

MR. JOHNSON: The records are kept with 59 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 the surveillance. We

=ve got the original with the inspection procedures. We also have

-- Because you

=re doing on a different frequency, a five

-year frequency,

if you will, we

=ve got photographic evidence of the indications of interest if y ou will that we can do

comparisons to for the next inspection.

CHAIRMAN SKILLMAN: Thank you.

MR. JOHNSON: You=re welcome.

MR. PIHA: This additional information has been provided to the NRC staff in a letter submitted

on November 21, 2014.

CONSULTANT BARTON: The NRC inspection talked about the evidence of water seepage through

concrete and concrete leaks, concrete cracks, etc.,

etc. And it said that through discussion with the

Applicant the staff learned that this has been since

initial plant construction. The question I

=ve got is do we still have water leakage in this concrete causing additional cracks. Or is this one thing that happened during plant construction and never again is occurring

or what?

MR. GALLAGHER: I think what

=s being referred to there is the tendons tunnels at Byron.

CONSULTANT BARTON: Byron, yes.

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-3701 (202) 234-4433 MR. GALLAGHER: Okay. And basically there were some improvements that were made in the grading in those areas. So the water runoff is better

from the containment out.

CONSULTANT BARTON: Better as in?

MR. GALLAGHER: Improved.

CONSULTANT BARTON: Has it been eliminated or? MR. GALLAGHER: There is still some water that gets into the tendons tunnels. But the corrective action greatly reduced that. So t hat=s monitored as part of the structural monitoring program.

CONSULTANT BARTON: Okay.

MEMBER BALLINGER: So you think the tendons are okay.

MR. GALLAGHER: Yes.

MEMBER BALLINGER: You=

re not having more problems. MR. GALLAGHER: No, the tendons are fine

.

MEMBER BALLINGER: Okay.

CONSULTANT BARTON: Thank you, Mike.

CHAIRMAN SKILLMAN: Please proceed.

MR. PIHA: Slide 18 please. The second topic I will address is aging management of the CRDM 61 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 seismic support assembly. During the NRC Region III inspection at Byron Station, discussions were held with the NRC staff regarding the CRDM seismic support

assemblies which were not within the scope of the ASME

Section XI, Subsection IWF Aging Management Program

as part of the license renewal application. As a follow

-up to the inspection, the CRDM seismic support assembly was added to the scope of the

IWF program. Slide 19. This slide shows a sketch of the assembly called the Integral Head Assembly which includes the

CRDM seismic support assembly as a sub-element. The reactor vessel head is at the bottom of the sketch.

The items that comprise the CRDM seismic

support assembly are highlighted in green. The CRDM

seismic support assembly consists of the shield

assembly, the connecting lift rod assemblies, and

seismic tie rod assemblies.

At Bryon and Braidwood, the integral head assembly which was supplied by Westinghouse is a large mechanical assembly which sits on top of the reactor

vessel head and combines all of the equipment on top of the reactor head into an efficient, one

-package

reactor vessel head design. During plant operation, 62 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 the integral head assembly is braced to the wall of the refueling cavity by the seismic tie rod assemblies.

Slide 20.

The CRDM seismic support assembly is a sub-element of the integral head assembly. All

elements and sub

-elements of the integral head assembly were evaluated for aging management in the original

license renewal application. The External Surfaces

Monitoring and Boric Acid Corrosion Aging Management

Programs were credited in the LRA for visual inspections

of all of the elements of the integral head assembly including the CRDM seismic support assembly as a

sub-element.

During the NRC Region III inspection at Bryon, the NRC staff questioned the aging management of the CRDM seismic support assemblies which were not

within the scope of the IWF program as part of the

license renewal application. After discussions with the NRC staff, Exelon determined it was appropriate to add the CRDM seismic support assembly to the scope

of the IWF program for license renewal aging management.

As a result, the CRDM seismic support assembly consisting of the shield assembly, three lift rod assemblies and six seismic tie rod assemblies was 63 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 added to the scope of the IWF program. The external surfaces monitoring, boric acid corrosion and the IWF

programs well address aging of the CRDM seismic support

assembly. Under the IWF program, a visual VT3 examination of the CRDM seismic support assembly will be performed. Exelon has provided this information

to the staff to address this issue in a letter submitted

on August 29, 2014. The staff also asked if high strength bolts were used for the CRDM seismic support assembly.

Exelon has confirmed that there is no high strength

bolting installed and has provided this information

to the staff in a letter submitted October 16, 2014.

Slide 21.

At this time, I would like to turn the presentation over to John Bashor for the discussion of the third and final topic, the Braidwood Flux Thimble

Tube Inspection Program. MR. BASHOR: Thank you, Albert. This it em of interest comes from the difficulties Braidwood has experienced in obtaining any current data on the flux

thimble tubes during planned evolutions in recent refueling outages. The NRC reviewed this operating

experience during the September 2014 Region III 64 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 inspection at Braidwood and captured it as an item of interest. This issue was only applicable to Braidwood

since Byron has not experienced similar difficulties

in obtaining any current test data. Before I begin discussing the issue, I will first present a description of the flux thimble tube

arrangement. Slide 22 please. The flux thimble tubes are part of the in-core flux monitoring system and provide a dry tube

which allows a movable in

-core neutron detector to be

periodically inserted into the reactor core without

directly exposing the detector to reactor coolant environment. The retractable flux thimble tube is

inserted into the reactor core through the seal table, the guide tube, the reactor vessel penetration, the

lower reactor vessel internals and into a designated fuel bundle. A high pressure seal provides the pressure boundary between the flux thimble tube and

the seal table.

The flux thimble tube is a semi

-flexible, stainless steel tube sealed on one end and with an

outside diameter of 0.3 inch and an inside diameter of 0.2 inch. The length of the flux thimble tube can vary between approximately 109 feet to 125 feet 65 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 depending on core location.

There are 58 flux thimble tube core locations. The flux thimble tubes establish part of the reactor coolant boundary and are classified as

instrumentation for the ASME Code. Slide 23.

Recently, Braidwood has experienced difficulties in obtaining flux thimble tube eddy current test data due to increased resistance or restriction when inserting the eddy current probes.

This issue has been entered into the corrective action

program for resolution. To this issue, a team has been established to determine the cause of the issue and has developed

actions to prevent future recurrence. Possible causes include presence of moisture in the tube from the cleaning process, changes to the current eddy test

equipment or deformation or blockage of the tube.

To resolve the potential for residual moisture in the flux thimble tubes, the need for tube cleaning prior to eddy current testing will be evaluated. The current testing practice includes flux thimble tube cleaning, but this process may provide

a source of moisture that may in turn lead to hydraulic

block when attempting to insert the eddy current probe.

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-3701 (202) 234-4433 Industry peers with similar designs have been benchmarked. And it has been determined that cleaning may be unnecessary. A mock

-up will be created using a spare flux thimble tube to simulate the

as-installed configuration. Testing of the mock

-up will then be performed to determine the cause of the

restriction or to identify if there is an issue with the eddy current probe being able to pass through the

tube. Also a controlled extraction of a flux thimble tube would be performed if future eddy current

testing attempts are unsuccessful. The removed flux thimble tube will then be examined to identify the cause of the restriction. In addition to determining the cause of this issue, the use of improved eddy current

testing equipment has been pursued.

One improvement in the testing equipment is to use a more rigid drive cable to insert the eddy current probe into the flux thimble tube. Based on

the current process, a dummy probe is fully inserted

into the flux thimble tubes after cleaning but before eddy current testing. The dummy probe has the same

outside diameter as the eddy current probe, but it=s

driven into the flux thimble tube utilizing the more 67 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 rigid drive cable.

This dummy probe has been successful when inserted into the flux thimble tubes in recent outages.

Therefore, a more rigid drive cable from the current eddy probe may allow for full insertion of the probes.

Second improvement to the testing equipment is to use a smaller eddy current probe. An

eddy current probe with a smaller outside diameter

rather than the current 0.188 inch is being evaluated.

The smaller eddy current probe will be tested in a

spare flux thimble tube to verify that this approach

will be effective.

The final contingency corrective action is to evaluate replacing the flux thimble tubes at the larger diameter tube. A flux thimble tube with a larger diameter tube would provide additional clearance.

Slide 24 please.

Eddy current testing to monitor for wear of the flux thimble tubes has been performed since 1989 when the program was implemented at Braidwood. The frequency of the eddy current testing is based on

plant-specific testing data and is set such that no flux thimble tube is predicted to incur wear that

exceeds the acceptance criteria before this next 68 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 scheduled test.

Conservative projections of future wear are performed to determine if the flux thimble tubes remain satisfactory for continued service. This

methodology is in accordance with the NRC Bulletin 88-09 and is consistent with the WCAP

-12866 and the GALL

report. Although recent test data has not been obtained, sufficient data exists to project future wear

until the next tests which are scheduled for the spring

2015 refueling outage for Unit 1 and the fall 2015 refueling outage for Unit 2. If flux thimble tube cannot be tested and cannot be shown by analysis to

be satisfactory for continued service, then the tube

is conservatively removed from service by either

capping or replacing the tube. This approach is

consistent with the GALL report for flux thimble tubes

where eddy current testing data is not obtained.

During the most recent refueling outages, two Unit 1 flux thimble tubes were conservatively capped

and five Unit 2 flux thimble tubes were conservatively replaced because eddy current testing data was not obtained and projected wall loss was not satisfactory

for continued service until the next scheduled test.

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-3701 (202) 234-4433 For the remaining in

-service flux thimble tubes, the highest projecte d wall loss due to wear for each unit at the next scheduled test is less than 60 percent. The WCAP-12866 determined that flux thimble tubes remain functional with up to 85 percent wall loss.

And since no tubes are projected to have a wall loss

greater th an 60 percent, adequate margin exists to ensure flux thimble tube integrity is maintained until

the next scheduled test.

This issue has not affected the performance of core flux mapping. In order to provide more

assurance that the program will remain effe

ctive, Exelon has added a commitment to replace flux thimble tubes if the eddy current testing data is not obtained as required. The slide summarizes this replacement

commitment. Slide 25 please. MEMBER RICCARDELLA: Excuse me before you get off this slide. So when you say on Unit 2 seven

completed, those aren

=t seven exams. Those are seven

replacements.

MR. GALLAGHER: Yes, that

=s the replacements. That=s correct, replacements.

MEMBER RICCARDELLA: When you do replace them, do you look at the old ones that you took out 70 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 to see if there

=s been wear, see how much wear there

=s been? Do you do destructive analysis?

MR. GALLAGHER: Yes, Dr. Riccardella.

MEMBER RICCARDELLA: John.

MR. BASHOR: I will tell you it=s a very difficult process because you pull that section of the tube out. You clip it off. You pull a section of tube out. Clip it off. Very highly irradiated material

typically put in a bucket.

So you know one of the things we will be doing going forward is if we find ourselves in a situation where we have to do a destructive examination

is figuring out how we will label each piece of tube

so that we know exactly what location in the dry tube

was located. MEMBER RICCARDELLA: But the primary plan is to get to the point where you can do the eddy test.

MR. BASHOR: That=s correct.

MEMBER RICCARDELLA: Understand.

MR. BASHOR: Okay. Slide 25. In conclusion, the current implementation of the flux

thimble tube inspection program will ensure the

integrity of all in-service flux thimble tubes until the next scheduled test. In order to provide more 71 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 assurance that the program will remain effective, Exelon has added a commitment to replace flux thimble tubes if the required eddy current testing data is not

obtained.

Corrective actions have been identified and are in progress to resolve this issue. Additional

information on this item of interest has been provided to the NRC staff and letters submitted on October 31,

2014 and November 22, 2014.

I will now turn the presentation over.

CHAIRMAN SKILLMAN: John, let me ask a question. What role does the flux mapping or the

thermal couple play in your accident response

procedures? Is there any role whatever from the information from the problems that are in the thimbles?

MR. GALLAGHER: Craig, could you answer that? Did you hear the question?

CHAIRMAN SKILLMAN: What

=s the role of this in accident management? MR. INGOLD: My name is Craig Ingold. I

=m a former shift manager and senior reactor operator at

Braidwood. There is no role for import thimble flux

mapping in post-accident response. CHAIRMAN SKILLMAN: Did you look at the 72 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 thermal couples that in here, in the system, for any?

MR. INGOLD: For core exit, we used core exit thermal couples. We don

=t use the in

-core system for any exit response.

CHAIRMAN SKILLMAN: Okay. Thank you.

MEMBER STETKAR: Before you switch gears, John, I have a couple of questions. This is also Braidwood 2. The operating experience shows that

you=ve had some unexpected wear rates on a couple of

flux thimbles. One was a new one that was installed

in I think the fall of -- I=m reading notes here. So

bear with me

-- 2009. And the first inspection showed a 35 percent wear that increased to 41 percent in 2002

which is kind of an unexpected wear rate. The other one was an original flux thimble that had apparently 36 percent wear in 2008 and it increased to 57 percent in 2011 which seemed a rather

dramatic increase in the wear rate compared to the

previous ones. I=m assuming you inspected those in both the fall and the spring 2014 outages. What were

the observed wear on those two outages, the most two

recent inspections?

CHAIRMAN SKILLMAN: Gary or John.

PARTICIPANT: Give me a minute. I have 73 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 to look up that.

CHAIRMAN SKILLMAN: Okay. You can look it up. You also said the exact cause of the higher anticipated wear rates has not been determined. Do

you have any guess of why they=re wearing like that?

MR. BECKNELL: Gary Becknell, License Renewal Project Team.

The flux thimble tube inspection program is for monitoring of wear due to flow induced

vibration. And flow induced vibration is a specific aging mechanism which provides a more predictable wear

rate. Wear can also be caused by other event-driven type issues such as foreign material or

improper installation or maintenance activities. So without doing a post mortem of the tube, the actual

cause of the increased wear has not been determined. MEMBER STETKAR: I can understand perhaps installation on the new one. Actually, I=m a little more curious about why the original one suddenly showed

an increase which could be foreign material.

MR. BECKNELL: Right. That

=s sort of where we=re speculating. Now with the recently

installed one what we saw was it was installed and ran

for I believe it was one cycle. Then we measured it 74 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 which you expect to see a lot of wear during the first cycle. MEMBER STETKAR: You expect to see, yes, some wear. MR. BECKNELL: Well, the highest wear rate would happen in the first cycle as it sort of wears

itself in.

MEMBER STETKAR: Right.

MR. BECKNELL: Whereas in the past when we would install a new one, we wouldn

=t necessarily

inspect it for maybe a couple of cycles.

MEMBER STETKAR: Okay.

MR. BECKNELL: Spread it out over two or three cycles to wear rate might tie in. MEMBER STETKAR: Yes. So the average wear rate. MR. GALLAGHER: So the staff in the application and in the SER they use our words that come from the corrective action. And the corrective action

reports were written as higher than expected wear.

MEMBER STETKAR: Sure.

MR. GALLAGHER: When you really look at it, for a first cycle operations, it

=s really not higher

than expected.

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-3701 (202) 234-4433 MEMBER STETKAR: I may give you that on the first one.

MEMBER STETKAR: The one you

=re talking about. MEMBER STETKAR: The original one I

=m curious about. And also if you can find the results, I=m just curious. Apparently, they weren=t replaced because you would have said immediately AOh we replaced those, too.@ MR. GALLAGHER: Yeah. Which unit was that on? MEMBER STETKAR: Braidwood Unit 2. If you don=t have it readily available you can get back to

us. CHAIRMAN SKILLMAN: It gives me some comfortable to watch you scramble through.

MEMBER STETKAR: They=re so smooth doing this. You have to have --

(Simultaneous speaking.)

MR. GALLAGHER: We

=ll get you that when we come back from the break.

CHAIRMAN SKILLMAN: That is a drill that we went through on our review trying to figure out which is which here. I understand you

=re going to come back 76 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 with that. MR. GALLAGHER: Yes, we can get them that specifically. CHAIRMAN SKILLMAN: Then let

=s proceed and when that information is available we=ll speak about it then. Thank you.

MR. GALLAGHER: Okay.

With that point, we=ve finished the discussion on the flux thimbles and

just turning it back to me to conclude.

CHAIRMAN SKILLMAN: Before we conclude, let=s -- John and I had some questions.

(Simultaneous speaking.)

MR. GALLAGHER: And that=s just where we are. We=ve finished our presentation. And are there

any other questions you have?

CONSULTANT BARTON: My questions have to do with tanks onsite. We

=ve had some experience where

we=ve seen that tanks have not been inspected but

promised to do one before I go into operation and we

=ve seen some where we experienced some leakage. And I

looked at your tanks and I don=t have a feel for how you inspect them or when you inspect them. The refueling water storage tank, the description is a

stainless steel liner within a reinforced concrete 77 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 enclosure. Now does that have some kind of an inspection program? How do you inspect it? It just seems like a configuration that

=s looking for a way

to get looked at. MR. GALLAGHER: Why don

=t Jim or Ed a nswer that question? Jim.

MR. ANNETT: My name is Jim Annett. I=m on the License Renewal Project Team. The fuel storage tank is a concrete tank with a stainless steel liner.

So it=s more than just being inside a concrete

enclosure.

CONSULTANT BARTON: Is there any inspection program for that? Have you inspected it

since initial operation? MR. ANNETT: The aging management for the liner is we use the water chemistry program. So this is similar as what is done for the spent fuel pool and

the configuration for the liner uses the same details

as we use for the spent fuel pool.

MR. GALLAGHER: So there isn

=t an inspection per se. CONSULTANT BARTON: Is the old fall

-back. I=m going to use the chemistry.

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-3701 (202) 234-4433 MR. GALLAGHER: The water chemistry and we maintain the water chemistry.

CONSULTANT BARTON: Okay. Your condensate storage tanks are similar to some other sites where they

=re resting on a concrete doughnut that

=s filled with compacted sand. And we have seen some

experience where tanks with this configuration have developed leaks. I wonder what your experience is. Do you have an inspection program for them?

And has it found any thinning of the tank bottoms if

that=s what you

=re doing? Have you done any UTs on

the tank bottoms on those tanks? MR. GALLAGHER: Maybe we can ask Paul Weyhmuller to answer that question. Paul.

MR. WEYHMULLER: Paul Weyhmuller, Exelon License Renewal Team. The tanks, the CSTs, both at Byron and Braidwood are constructed of aluminum. And as of this time, they ha ve not been inspected, the

bottoms, through a UT process.

CONSULTANT BARTON: Well, there has been some experience with tanks in this configuration that

have thin bottoms. So my concern would be if you

haven=t looked at it since initial p lant operation,

maybe it=s due for inspection.

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-3701 (202) 234-4433 MR. WEYHMULLER: Braidwood Station actually raised the walls of their tanks and with that they removed a new section of the tank bottom on the perimeter where the wall came down on top of it. And

at that time the inspections did not find any issues with wall loss. That

=s the information we have so far

on tank bottoms for CST.

CONSULTANT BARTON: Is there any plan to do inspections of the tank bottoms between now and

extended operation? CONSULTANT BARTON: The above ground tank program is a new program. The tank bottoms will be

inspected five years prior to PEO which will include ultrasonic examination as well as because of water

chemistry. There

=s one time inspection program. We

will also perform the internal visual inspections at

that time as part of that program.

CONSULTANT BARTON: Okay. Thank you.

MEMBER STETKAR: You

=re going through another tank or something else, John.

CONSULTANT BARTON: Diesel oil storage tanks. MEMBER STETKAR: Let me follow up on the CSTs.

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-3701 (202) 234-4433 CONSULTANT BARTON: Okay. This is the insulation problem.

MEMBER STETKAR: Yes. You=re going to do it? CONSULTANT BARTON: Yes. I=ll finish up on that.

MEMBER STETKAR: Okay, you can do it. CONSULTANT BARTON: The NRC reporte d I think in an inspection report that the insulation on the CST had slipped down. So part of the tanks are exposed. In addition, Braidwood Unit 2 CST above the water line has an indication. Has it been looked at?

Evaluated engineering wise? It

=s an indication

there=s a detection in the tank wall. What have you done about the insulation that has slipped down on those

tanks? MR. GALLAGHER: Okay. I think we need Paul again to help. MEMBER STETKAR: I was hoping he wouldn

=t sit down.

MR. WEYHMULLER: Paul Weyhmuller, Exelon License Renewal Team. So the first question on the

insulation that is from Byron Station. Both Units 1

and 2, the insulation has moved down approximately one 81 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 and a half inches on Unit 2 and slightly less on Unit

1. It=s in the planning process now to restore that

area so that the insulation does go all the way back

up to the roof.

It is thought it

=s due to the stainless steel banding clamps that go around the circumference of the tank that hold the lagging in place. There is some looseness in some of the straps which allow it

to slide down that distance.

CONSULTANT BARTON: Well since the insulation has dropped, there has been exposure to the

environment. And you can get water down between the

tank itself and the insulation since the tank is not

completely covered. MR. WEYHMULLER: The tank group overhangs the side wall of several inches, but with blowing rain there could be that possibility. When it was being reviewed as far as the issue from the access ladder

a visual observation was made of the tank wall in that area. In comparing it to the tank roof, the tank roof

is made of the same material, aluminum, and it is not insulated or coated in any way. And the surface

condition was found to be similar to that of the --

CONSULTANT BARTON: I

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-3701 (202) 234-4433 water trapped between the insulation and tank. Since you had a gap, you could get rain sometimes coming in parallel. You could get water on the tank surface down

between that and the insulation. And that=

s what I=m concerned about. What about the tank surface below

inside the insulation below?

MR. WEYHMULLER: Our aging management program will remove insulation in 25 different areas,

one square foot areas. In particular, we have

committed to do at least four areas where there have

been penetrations of possibility of water intrusion

to inspect that area both visually and with a exam for

cracking. CONSULTANT BARTON: Has that been done yet or is that down in the future sometime? MR. WEYHMULLER: That is out in the future at this time.

CONSULTANT BARTON: So you don

=t really know what the condition is right now of those tanks. MR. WEYHMULLER: The roof of the tank itself is exposed to the weather. So we can see that

as well as the inner welds.

CONSULTANT BARTON: That=s different. The roof is exposed to the environment. How about 83 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 what=s trapped between the insulation and the tank wall is what I=m concerned about.

MR. WEYHMULLER: There

=s not been any examinations under the insulation at this time. The

tank material though is --

CONSULTANT BARTON: Aluminum, right?

MR. WEYHMULLER: Yes. That is correct. And it is of a grade that is not susceptible to cracking.

We have committed to do the inspection for cracking

as part of our aging management program. CHAIRMAN SKILLMAN: What is the chemistry of the insulation? What=s the insulation?

MR. WEYHMULLER: That

=s why we did make the commitment. The bottom section, the bottom two to four feet, is made of foam glass material. And it was found that it was halide chloride-free. The upper regions of the tank we could not find the paperwork that would satisfy that it was halide or chloride

-free. So therefore we conservatively said there was a possibility it could contain one or more of those

materials. And therefore we put in that we would

inspect for cracking on the tank walls.

MEMBER BALLINGER: How tight is the insulation?

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-3701 (202) 234-4433 MR. WEYHMULLER: How tight is it?

MEMBER BALLINGER: Yes.

MR. WEYHMULLER: It has a c orrugated lagging cover and then stainless steel banding straps.

MEMBER BALLINGER: On the interface between the aluminum and the insulation, how tight is

that? MR. WEYHMULLER: It=s pulled up tight to the tank.

MEMBER BALLINGER: So it

=s real good crevice.

MR. WEYHMULLER: Yes.

MEMBER BALLINGER: That=s the good news.

That=s also the bad news.

CHAIRMAN SKILLMAN: It

=s a 34 inch belt loop for a size 36 pants.

MEMBER BALLINGER: I

=ve been inspecting it for pitting and other kinds of things.

MR. WEYHMULLER: Right.

MEMBER BALLINGER: And I don=t know what the aluminum alloy is. Does anybody know the

designation? MR. WEYHMULLER: I can find that. I have that.

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-3701 (202) 234-4433 MEMBER BALLINGER: Because some of these materials are --

MR. WEYHMULLER: Very susceptible.

MEMBER BALLINGER: And chloride can come from just about anywhere. MR. GALLAGHER: But I think as Paul indicated we do have it in our corrective action

program. CONSULTANT BARTON: You haven

t looked at this. So there

s a possibility it could have something

going on with the aluminum.

MEMBER BALLINGER: It

=s a lot easier to see pitting and stuff like that than it is to see

cracking. CONSULTANT BARTON: Right. I guess our concern is are you going to --

MEMBER POWERS: Depends on the crack.

MR. GALLAGHER: Yes. The assessment was done at the top of the tank and our aging management will address the full tank. So that

=s a challenge to

say should we be looking at this sooner than later.

MEMBER POWERS: Exactly.

MR. GALLAGHER: And we

=ll take that challenge.

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-3701 (202) 234-4433 MEMBER BALLINGER: Okay. MEMBER STETKAR: Don=t sit down. I

=m not done. MEMBER BALLINGER: Is the inspection going to be from the inside of the outside?

MR. WEYHMULLER: The inspection is done from the outside of the tank. We have to remove the

lagging and insulation. MEMBER BALLINGER: You have to remove the lagging.

MR. WEYHMULLER: Yes, that=s correct.

MEMBER STETKAR: A couple of questions. One is just for clarification because I

=m not capable

of reading everything that=s sent to us. I did find

something that was quoted in the SER as part of a response to an RAI. So I have to qualify it that way.

It=s perhaps thirdhand information.

You mentioned inspection of 25 locations being in at least what I read said 25 locations for both tanks combined per site which could mean 12 on

one and 13 on another. Are you actually going to

inspect 25 locations on each tank?

MR. WEYHMULLER: No, the inspection programs, because the tanks are right next to one 87 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 another, you would take one of the tanks for each evolution.

MEMBER STETKAR: But we

=ve already now confirmed that they

=re not identical because they had different wetting histories. And indeed the license

renewal guidance, I was going to ask the staff about

this because they accepted it. But the guidance says each tank. It doesn=t say tanks that are close to one another and mostly the same. But you do clarify that it

=s not 25

per tank. So we=ll ask the staff about that. The other question I had is you discovered this slipped down insulation in August of 2012 and you

said you=re still planning on how to repair it. Why does it take more than two and a half years to figure out how to repair this? And don

=t tell me you have

to do it during an outage because I can stand there and look at the outside of the tank. So why is it taking

and why are you still planning this?

MR. GALLAGHER: Yes. I think our assessment was that because the configuration we have

on the bottom insulation and the inspections that we re done where the gap is and the overhang and the condition

of the roof that it

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-3701 (202) 234-4433 on at this point. And we just have to -- CONSULTANT BARTON: So it has low priority in your corrective action system.

MR. GALLAGHER: Well, it=

s a activity that we have to prioritize with all the other activities that we have. And we do have it in our aging management

program that will be done on an ongoing basis.

MEMBER STETKAR: Yes, but that=s in like 2026. MR. GALLAGHER:

Well, the five years before PEO.

MEMBER STETKAR: I mean 2021.

CHAIRMAN SKILLMAN: I guess I

=m surprised that A&I and the boiler machinery inspection hasn

=t forced this a long, long time ago. I can recall being

forced to do tank bottom inspections much against my

will. You=

ve got a submarine and you

=re going to look

at tanks. But it was really A&I and the boiler machinery inspection portion of our insurance policy that forced us to do that. These are big machines with real consequences. I=

m surprised that that hasn

=t been an action item for the site based on your A&I policy.

MR. GALLAGHER: For the safety tank 89 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 bottoms, yes.

CHAIRMAN SKILLMAN: Yes. But hey. I=ll leave that as it is. John or other John, Chairman, any further questions?

MEMBER STETKAR: No, no, I=m done on the CSDs. We=ll give it back to John.

CONSULTANT BARTON: The only other thing I had the same question on diesel oil storage tank, the 50,000 gallon tanks that are in the auxiliary

building. Is there some kind of inspection program for them? Are they freestanding? Are they buried in concrete in the auxiliary building? I mean, what

=s the configuration of them and have they been looked

at? MR. GALLAGHER: Paul.

MR. WEYHMULLER: Paul Weyhmuller, Licen se Renewal. There

=s two 25,000 gallon tanks on Unit 1

and a 50 on Unit 2 for both stations. They

=re freestanding tanks sitting on a concrete pedestal or slab. They are inspected on a 10 year frequency.

They=re drained, cleaned and then a visual inspect ion is performed. So they have been inspected.

CONSULTANT BARTON: Thank you.

CHAIRMAN SKILLMAN: John.

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-3701 (202) 234-4433 CONSULTANT BARTON: I

=ve got some other items. CHAIRMAN SKILLMAN: When you

=re done I

=ve got a couple more. We=ve got a few more minutes.

CONSULTANT BARTON: All right. Other than Braidwood essential service cooling pump, I couldn=t find any reference to looking at the retaining

dike. Did it ever get looked at because of the

materials of the dike around the pond? Is it e ver inspected? Have you looked for degradation of the

materials that make up that dike? MR. GALLAGHER: This is the dike around the whole pond. CONSULTANT BARTON: Around the whole pond.

Is that ever looked at?

MR. GALLAGHER: Paul Cervenica.

MR. CERVENICA: My name is Paul Cervenica.

I=m a member of the License Renewal Team. The dike

surrounding the pond is inspected every three months by the site and they look for general condition degradation. And on a 12th month basis, a professional

engineer comes in and does a survey and reports on the

condition. CONSULTANT BARTON: Thank you, Paul. Now 91 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 the essential service cooling pond has a triangular excavated area within the cooling pond itself. And

it=s the ultimate heat sink for the plant. Is it e ver looked at? Does anybody ever go down and look at the

structure of it? MR. GALLAGHER: I think that

=s Paul again on that one. MR. CERVENICA: Paul Cervenica, member of the License Renewal Team. There are soundings done on the essential service water cooling pond. Soundings

at the bottom and the slope walls in order to confirm that the volume required by tech specs is maintained.

That=s done every 18 months.

CONSULTANT BARTON: Thank you, Paul.

The next area that is cathodic protectio

n. It was noted that the system has improved, but there

=s less than 50 percent of the site adequately protected.

And experience has shown that at both sites corrosion has occurred due to the lack of protective coating.

I think you people said that you=re going to improve the cathodic protection system. Is that now complete?

Is it functioning? And how effective is it?

MR. GALLAGHER: Dylan.

MR. CIMOCK: Dylan Cimock, License Renewal 92 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 Team. The cathodic protection system is improving and plans are in place that includes investigation of means

by which to improve it which includes replacement of existing anodes and insulation of new anode beds. The configuration of how to do that and the exact means is still being investigated. But that is our intent.

It=s to improve the overall coverage cathodic

protection of the station.

CONSULTANT BARTON: Since you don=t have a lot of piping covered by it, what

=s your schedule

to complete it and get a system operating so you can

assess the effectiveness of it? MR. CIMOCK: The intent would be to complete that hopefully five years prior to the period

of extended operation which would be consistent with

allowances provided in the ISG.

CONSULTANT BARTON: In the meantime, do you do any piping inspections that=s not covered?

MR. CIMOCK: Yes, significant piping inspection have been performed. And while it might be characterized as not protected, it does receive some protection. It just may not be meeting established

acceptance criteria. That criteria is applied

universally to all piping.

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-3701 (202) 234-4433 MEMBER BALLINGER: That=s the minus 830.

MR. CIMOCK: Eight fifty, correct.

MEMBER BALLINGER: Eight fifty.

MR. CIMOCK: Right. So it is possible to achieve adequate protection without that negative 850.

So that is something that is being investigated as well. While we had seen some degradations, it has been

quite minor I would characterize it as. CONSULTANT BARTON: How do you do it?

When you=re doing some maintenance and you

=re digging a hole and you look at the piping? Or is there anything

planned to go and look at specific areas of the piping

in the plant? MR. CIMOCK: Yes. Both stations are implementing the NEI 09

-14 initiative on buried piping.

So they have strengthened their piping. Excava ted significant portions, approximately like 300 feet for example of condensate piping at the Braidwood Station

has been excavated. Approximately 300 feet at Bryon

Station for service water. CONSULTANT BARTON: How aggressive is the soil at the site?

MR. CIMOCK: Not very aggressive from the soil samples that have been taken.

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-3701 (202) 234-4433 MEMBER BALLINGER: Can you interrogate your cathodic protective system? I presume that most of the piping is coated.

MR. CIMOCK: That=s correct.

MR. JOHNSON: And so can you interrogate your protective system based on the current that

=s being supplied to identify potential sources where you

think you

=re providing protection and it

=s not working

anymore? MR. CIMOCK: Yes, we do maintenance and surveillance on rectifier availability so we can

identify where rectifiers are out of service and not providing adequate protection. But the stations have

also done alternative cathodic protection assessments.

It=s called an APEC survey, aerial potential earth

current.

MEMBER BALLINGER: Yes.

MR. CIMOCK: And that has shown there are areas that I guess are more or better protected than

others. MEMBER BALLINGER: So you can rank order.

You have rank ordered systems in terms of susceptibility which then allows you to establish what

to do next.

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-3701 (202) 234-4433 MR. CIMOCK: Yes.

CONSULTANT BARTON: You

=ve got some unprotected carbon steel piping embedded in concrete

at the service water structure. Now do you ever go look at the piping internally? I know you can

=t look at it externally because it

=s in concrete. Do you ever

go look inside and see if there

=s anything going on

in that piping?

MR. GALLAGHER: Dylan.

MR. CIMOCK: Dylan Cimock, License Renewal Team. Piping is not inspected internally and as you

point out it can

=t be gotten to externally as well.

They do other surveillances because it

=s safety-related

piping like flow and pressure tests on the piping.

And any leaks that would arise you would see based on the pressure of the system. And that=s

not been seen eith er. And flow rates have been adequate. They have done external excavations of that

reinforced concrete section. You can

=t get to the

pipe, but you can inspect its backfill. And they

inspected that and found that to be fine as well. MEMBER BALLINGER: B ut again that pipe is also wrapped. CONSULTANT BARTON: No, it

=s in concrete.

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-3701 (202) 234-4433 It=s unwrapped carbon steel pipe inside concrete.

CHAIRMAN SKILLMAN: Inside pipe. It

=s embedded piping.

CONSULTANT BARTON: Embedded piping in concrete. And how do you know w hat=s going on inside that piping?

MEMBER STETKAR: Part of it below groundwater level.

CONSULTANT BARTON: Pardon?

MEMBER STETKAR: Part of it below groundwater level.

CONSULTANT BARTON: Right.

MEMBER BALLINGER: Well, you could pig it to see it effectively.

MR. CIMOCK: That

=s been investigated.

Right now, they

=re trying to find means by which to

do because it

=s a very long length of piping with obstructions along the way that would prevent that.

So it is being investigated as part of their NEI initiative and they=re trying to find a way of doing that under the mitigative actions performed in that

piping. CONSULTANT BARTON: I=

ve got one other one here. The inaccessible power cables not subject to 97 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 50.59 environmental qualification. At Byron Unit 2 based on the site history, especially cable bolt OB 2 at Byron Station. What is the status of work that

was planned to limit surface water intrusion into that

wall? MR. GALLAGHER: John Hilditch.

MR. HILDITCH: John Hilditch, License Renewal Project. That particular wall had water intrusion from a hand hole. That hand hole was modified

back in July to make it more water resistant. The ground was graded. So the water wouldn

=t flow on top

of there. And there

=s been some significant rain

storms since. And the water intrusion problem is no

longer there.

CONSULTANT BARTON: How do you know? Do you now periodically inspect?

MR. HILDITCH: Yes.

CONSULTANT BARTON: Okay.

MR. HILDITCH: And the scoping is inspected periodically.

CONSULTANT BARTON: I think that=s it.

CHAIRMAN SKILLMAN: Thank you, John. I=d like to ask a few more questions. I realize we

=re over our break time. But I think when I

=m completed we

=ll 98 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 be done with this portion of the session.

Bolting integrity program, it=s B.2.1.9.

There are three enhancements on Byron and two enhancements on Braidwood. And I

=m wondering why there is a difference in enhancements for bolting integrity

between the two stations please.

MR. TAMBURRO: Pete Tamburro, License Renewal Team. The difference in enhancements is because some of the submerged bolting that are required

to be -- that will be inspected there were no existing activities to inspect them. So we had to initiate

existing activities to inspect those submerged bolting s

at Braidwood. CHAIRMAN SKILLMAN: Thank you, Pete.

Okay. I=ve got one or two more. This has to do with reactor vessel surveillance and this is at Braidwood.

The second enhancement will test on specimen capsule

that has been irradiated to a neutron fluence of one to two times the projected peak neutron fluence at the

end of the PEO and will submit a summary technical report

to the NRC for each reactor vessel within one year of

the receipt of the renewed license.

And my question is why does it take the provision of the renewed license to trigger the need 99 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 for that information in a timely fashion. At least, that=s the way I

=m internalizing the way this inspection

is written. It seems like we=re really not going to

do it until we have the license. And when we have the license only then we

=ll go ahead and expose the surveillance specimen to the levels that we need to

to predict the 20 year future.

MR. TAMBURRO: On that, Mr. Skillman, we had in our current licensing basis, the 40 year lice nse life, done all the testing necessary for it.

CHAIRMAN SKILLMAN: The 40 year license.

MR. TAMBURRO: Yes. And those specimens actually for each unit, for each of the four units,

were exposed to the one to two times the exposure levels

and were removed and are currently sitting in the spent

fuel pool at the four stations. We thought when we put our application in that we would then just need to test them before we

entered the period of extended operation. The staff

pointed out to us that it could be interpreted that in the Appendix H provisions. Once you get a renewed

license those specimens would be required specimens.

They weren

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-3701 (202) 234-4433 license they are. MR. GALLAGHER: And then you

=re on the one year time clock unless you get a schedule change from the director of NRR. We took a look

-- We didn=t view it that way when we put the application in. We took

a look at the staff

=s position and agreed with them that that was correct. So we made that commitment.

So it was very clear that we would follow Appendix H and get those testing done within a year of getting

the license.

Now we=re not waiting for that obviously because these tests take some time. And we actually have a contract already cut and it

=s to Westinghouse.

Those activities are going to start beginning of next year 2015. And throughout 2015, those four samples

would be tested.

We don=t anticipate getting our license until the end of 2015. So we would be well completed

before it=s needed. CHAIRMAN SKILLMAN: Thank you, Mike.

That concludes my questions. Let me -- MR. GALLAGHER: I think we have the answer to Mr. Stetkar=s question on the wear.

CHAIRMAN SKILLMAN: Okay.

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-3701 (202) 234-4433 MEMBER STETKAR: I knew we could drag it on long enough for you to find it.

MR. MATTHEWS: Sorry. John Matthews, Braidwood Station Plant Engineering. So the question was in Unit 2 there was an original thimble that had

higher than expected wear rates that showed up. And the question was what happened subsequent to that

inspection.

The following inspections showed that cycle to cycle wear had gone back to its normal rate at three percent. However, that was capped out and

replaced at later outages. MEMBER STETKAR: Okay. So that one=

s been capped and replaced. How about the new one?

MR. MATTHEWS: The new one, subsequent eddy current testing showed that the wear rate had

stabilized. MEMBER STETKAR: Wear rate is stabilized.

Thank you.

CHAIRMAN SKILLMAN: Okay. For this portion of the meeting, let me check with my colleagues.

Dr. Riccardella, any further comments? MEMBER RICCARDELLA: No further comments.

Excellent presentation.

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-3701 (202) 234-4433 CHAIRMAN SKILLMAN: Okay. Dr. Ray? Dr.

Powers? John Stetkar? John?

MEMBER STETKAR: Nothing.

CHAIRMAN SKILLMAN: With that, I=m going to claim a 14 minute break. Please return at 10:30

a.m. on that clock. Off the record.

(Whereupon, the above

-entitled matter went off the record at 10:17 a.m. and resumed at 10:31 a.m.)

CHAIRMAN SKILLMAN: On the record.

Ladies and gentlemen, we

=re back in session. And for

this portion of the meeting, I

=m going to call on Lindsay

Robinson, our project manager. Lindsay.

NRC STAFF PRESENTATION SER OVERVIEW MS. ROBINSON: Great. Thank you, Chairman. Committee Chairman, Members of the ACRS, my name is Lindsay Robinson. I

=m the Project Manager

for the License Renewal of Byron Station Units 1 and

2 and Braidwood Station Units 1 and 2.

Before I get started, I

=d like to introduce the people at my right and left. Nestor Feliz

-Adorno, he was the lead for the Braidwood 71002 inspection.

He=s a Region III Senior Reactor Inspector. I have

Mel Holmberg. He was the lead for the Byron 71002

inspection. He is also a Region III Senior Reactor 103 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 Inspector. He had Dr. Allen Kiser. He is DLR

=s Senior Technical Advisor. And then we have Daneira Melendez.

She=s a Project Manager. She will be assisting me

with the slides today.

We=re here today to discuss the review of the Byron and Braidwood License Renewal Application as documented in a safety evaluation report with open items which was issued on October 30, 2014. Seated in the audience are members of the technical staff who

participated in the review of the license renewal application and conducted the onsite audits. Next

slide. We=ll begin the presentation with the general overview of the staff

=s review. Next, Mel and Nestor will both present the activities and inspection

observations from the 71002 inspections for Byron

Station and Braidwood Station. We will also discuss some issues that arose during the 71002 inspection that are not reflected in the SER open items. These issues and their resolutions

will both be documented in the final SER. We will then present the main sections of the SER and any associated item. Next slide.

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-3701 (202) 234-4433 The Byron

-Braidwood License Renewal Application is a dual site application consisting of four reactors in two geographical locations.

Considering the scope of the review, the staff found very few technical differences between the two sites.

And where those differences did occur in either the site and/or unit the staff made a point to clearly

identify where those applicable differences were per

that site and/or unit.

The staff did conduct several onsite audits and inspections at each site. During the scoping and

screening methodology audit, the audit team reviewed

the Applicant

=s administrative controls governing the

scoping and screening methodology and the technical

basis for selected scoping and screening results.

The staff also reviewed selected examples of component material and environmental combinations,

reviewed information contained in the Applicant

=s corrective action program relevant to plant

-specific,

age-related degradation and reviewed quality practices

applied during development of the LRA and the training of personnel who participated in the development of the LRA. There was also the audit where it documented

in a report dated March 14, 2014.

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-3701 (202) 234-4433 During the aging management program audit, the audit team examined the Applicant

=s aging management programs and related documentation to verify

that the Applicant

=s claims of consistency with the

corresponding AMP in the GALL report. The staff

reviewed 45 aging management programs and documented

the results in a report dated March 13, 2014.

Mel and Nestor will discuss the activities of the 71002 inspection in a few minutes. Next slide.

In addition to the audits and inspections already mentioned, the staff conducted in

-depth technical reviews and issued requests for additional

information or RAIs. The staff performed its review of the Byron and Braidwood license renewal application and issued the safety evaluation re port with open items on October 30, 2014. Pending the resolution of the open items and outstanding RAIs, our plan is to issue

the Bryon and Braidwood final SER in April of 2015. We will now direct the presentation to Mel and Nestor to discuss the Region III 71002 inspection.

Next slide.

MR. HOLMBERG: Thank you, Lindsay. Good morning. My name is Mel Holmberg. I

=m a Senior

Inspector in the Division of Reactor Safety in our 106 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 Region III office. That

=s in Lisle, Illinois. And I was also the lead for the Byron inspection.

MR. FELIZ

-ADORNO: Good morning. I

=m Nestor Feliz

-Adorno. I was the Team Leader for the

Braidwood inspection.

MR. HOLMBERG: So for the inspections we conducted, this is done under our Inspection Procedure

71002. The purpose is to verif y that the Applicant has adequate programs that either planned or in place to implement age management of the structures, systems and components within the scope of the rule. And our inspection is done to confirm that these components

will be adequately maintained consistent with existing

safety evaluations in the license renewal program.

The specific scope that we conducted at Byron included review of 36 of the 45 age management

programs. Twenty-four of these were based on existing

programs. Twelve were new. We also looked at four

of the five regulated events, four of the non-safety

systems that were scoped out of the rule.

Turning to Braidwood, our inspection scope was 31 of the 44 age management programs. Twenty

-three of those were existing programs and eight were new.

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-3701 (202) 234-4433 and three non

-safety systems, structures or components that were scoped out of the rule.

Each of our inspections comprised of two weeks of onsite inspection. And our teams reviewed the site documents related to the regulated events and

including at the non

-safety related structures or

components whose failure could potentially affect

safety-related components. And this review was done

to confirm the Applicant had applied the required

scoping and screening methodology.

At each site, we also completed walkdowns on over two dozen systems, structures or components

within the scope of license renewal. And these were

done to assess the adequacy of the license renewal

boundaries that have been established, evaluate the

material condition and conformance with their

application and GALL. This activity enabled us to

evaluate if the AMPs would be successful in managing

the aging effects for systems, structures and

components within the scope of the rule.

The inspections are Byron and Braidwood were done in series. This enabled the region to assess each plant individually and then allowed us to increase the number of programs reviewed. And then issues 108 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 identified at one site were assessed for applicability to the other site. Our final exit meeting was conducted following the end of the second onsite inspection which

was Braidwood. Next slide please.

Based on the inspections of the various areas that we were able to observe during our inspection time onsite and these were areas that included both units at each side, we concluded the overall material

condition of the structures, systems and components

we observed was good. CONSULTANT BARTON: I=

m glad you addre ssed that. This is the first time I

=ve ever had to ask you

that question of the 60 something plants I reviewed.

(Laughter.)

CHAIRMAN SKILLMAN: How do you define good please? (Laughter.)

MR. HOLMBERG: Actually, we do have a way to assess that. During our inspections, issues that

are of any type that we can across that looked like

conditions adverse to quality, the licensee promptly put into their corrective action program. Issues were

considered minor in nature if they didn

=t rise to th e

level of concern that prompted operability evaluations.

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-3701 (202) 234-4433 And so you

=ve got an initial swag on things as to whether or not they

=re significant if they don

=t prompt

some sort of concern for operability right off the bat.

So you=ve got a rough guide.

But other than because our focus was on license renewal, we were making sure we were not seeing

things that we expected them to pick up in their normal

routine programs. CHAIRMAN SKILLMAN: Thank you. I asked that question because in my experience the turbine building is normally clean and shiny. The

radiologically controlled areas are generally clean

and shiny. The entrance.

MR. HOLMBERG: The epoxy floor plant and all that.

CHAIRMAN SKILLMAN: Epoxy floor plant, lots of light. A lot of dazzle. But when you take

the time to go to the turbine building sump or the auxiliary fuel handling building sumps or the areas that are less traveled, very often you find a very

different physical condition, material condition.

CONSULTANT BARTON: Out

-buildings is a good example. That is also. CHAIRMAN SKILLMAN: And so my question is 110 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 as you get further out into the areas that are not as keenly maintained did you find, if you will, an

increasing number of the need for entrances into the

corrective action program.

MR. HOLMBERG: The total I believe was a little over a dozen condition reports for Byron. I

don=t recall --

MR. FELIZ

-ADORNO: Similar for Braidwood.

MR. HOLMBERG: Braidwood. So just to give you a sense of the numbers as to their locations, they

varied. I would say your general sense is correct.

Obviously, the areas that are easy to travel and well traveled are generally the ones that you expect and do not see the types of issues that you can find in

the other areas.

I guess I don

=t have a good answer off the cuff for you on that. CHAIRMAN SKILLMAN: Circ water pump house and the cooling pond pump house would be areas that

I would be curious about whether they were clean and neat, whether they were rusting apart or whether they looked like they really looked like they got some

preventive maintenance. MR. HOLMBERG: Yeah, we did have a couple 111 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 of issues and I=ll have to look up the specific ones I believe from one of those areas. And I can get back

to you with the specific item we identified in those

areas. I have five team members working for me.

So out of those areas we walked down, I have a lot of other eyes out there. Some of it I don

=t have direct

observations to rely back to you.

CHAIRMAN SKILLMAN: I don

t need any additional information. You pretty much answered my question. What you

re saying is what is inspected and what is seen on a regular basis is in pretty good shape.

As you get further and further away from the main

tourist paths, things are not as highly maintained. MR. HOLMBERG: I would say that

=s a correct assessment.

CHAIRMAN SKILLMAN: That

=s fair enough.

Okay. Thank you.

MR. HOLMBERG: During our inspections, we did identify issues of concern with respect to current

and planned programs. These resulted in application changes for some of the AMPs. For example, during our Byron inspection, the team identified some issues that prompted the application revisions to four of the AMPs, 112 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 including the ASME Section XI, ISI AMP.

For this particular AMP, the Applicant=s description contained in Appendix A -- that=s the UFSAR supplement -- did not include inspections of small bore lines subject to thermal fatigue. And what I

=m talking about is the MRP

-146 program. That

=s an industry

program that was not included in their description and

is used to manage thermal fatigue.

Additionally, Appendix B did not identify the 10 CFR 55a limitations, modifications and augmentations that go along with Section XI. So that was another issue that was identified for that program.

CONSULTANT BARTON: That protection system aging management program, I don=t know if you look at that. But in reading the AMP, the Applicant

=s application for license renewal, I wasn

=t thrilled about the extent of that program. Subsequently, I saw that the Applicant submitted a letter that included

14 enhancements to that program. Is the NRC now satisfied with that program?

MR. HOLMBERG: I think I=m going to turn that to Lindsay. Is this something that was an RAI? CONSULTANT BARTON: I didn

=t mean to catch you off guard.

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-3701 (202) 234-4433 MR. HOLMBERG: I

=m sorry. Was this in response to our inspection?

CONSULTANT BARTON: No, this was the application. I read the aging management program on that system. All right. And I was not too happy that that was an adequate program that was presented. And then I found in further review of the documents produced

by NRC that you received a letter on August 2014 that the Applicant had described 14 enhancements to that

program. So I guess my question is --

MS. ROBINSON: Mr. Barton, we actually have Bill Holston who can answer. CONSULTANT BARTON: Are you now satisfied with that AMP? MR. HOLSTON: Yes. My name is Bill Holston. I

=m a Reviewer in the Division of License

Renewal. And the aging management program originally

submitted was reasonably typical of the plants prior

to the issuance of ISG

-2012-02. With the issuance of

ISG-2012-02, that raised the necessity for a lot of

extra enhancements. Basically what we did was we went into NFPA-25 which is the inspection standard for fire water systems, selected about 16 inspections and tests that 114 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 we felt were representative of tests and inspections that were revealed, issues of loss material flow blockage. So that=

s why the extra enhancements. And

we are, yes, at this time satisfied with the

enhancements they=ve put in that program.

CONSULTANT BARTON: Thank you.

MEMBER STETKAR: Let me ask. I was going to wait, but since you mentioned an ISG. This is sort of a general question. Anybody up there can field it.

I guess I was surprised at the number of RAIs that were issued as a result of the audits and inspection s

on these units given the time we are into the license

renewal process.

This is more recent ones that we=ve seen that have been fairly minor in terms of audit inspection

-- I don=t want to call them findings

-- RAIs resulting from those activities. And I know this was done under GALL Rev 2, but GALL Rev 2 has been out since 2010 and

people knew what was coming well before that. So it

can=t be GALL Rev 2.

Is it primarily due to the additional clarifications from interim staff guidance that was

issued since GALL Rev 2 in the 2011-2012 time frame?

Or do you have any sense of that?

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-3701 (202) 234-4433 MS. ROBINSON: Sir, I=d just like to get a little more clarification on your question that you

=re trying to ask. MEMBER STETKAR: Okay. What I

=m trying to ask is if I look at these audits and inspections compared to other audits and inspections that we

=ve seen over the last two or three years for license

renewals those other audits and inspections typically

identify some issues that are raised in the SER to the

level of RAIs, but only a relatively small number.

Byron and Braidwood in comparison has quite a large

number of them.

And I=m curious why. Is it because the Applicant --

Is it something that the Applicant wasn

=t doing or is it something that they didn=t understand

in terms of evolving staff guidance?

MS. ROBINSON: So I can actually discuss the portion of actual RAIs following audits and

inspections. I can tell you that based on the RAIs

--and the Applicant has discussed those issues that

came out of the inspection --

I would say yes. That

=s not as typical as what we

=ve seen in other applications.

I would actually though say that the number of RAIs that came out of the audits -- and we had to 116 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 do that both at Bryon and at Braidwood

-- in terms of that reference we are looking at the two different geographical locations. And to some degree that

=s another reason why maybe you might have seen there are

more RAIs. But if we look at it from the perspective of we had to do two audits, one at Byron and one at Braidwood, then we had to do two inspections. And then

-- I am acknowledging that, yes, the number of the RAIs in the inspection is not as common.

But I actually was looking at other applications. And the fact that we had four units I

actually saw that we were on par, if not slightly less,

than some other applications.

MEMBER STETKAR: Okay.

CONSULTANT BARTON: RAIs per unit.

MEMBER STETKAR: RAIs per unit. What was your sense, John? CONSULTANT BARTON: There=

s a lot of them.

MEMBER STETKAR: There are a lot of them and a lot of them were issued

-- But a lot of them there was a single RAI that was issued for all units. So

if I count RAIs per unit, that=s four.

MS. ROBINSON: I=m not looking at an RAI 117 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 per unit perspective because I do agree that the majority of the RAIs that were issued were applicable

to all four units. I

=m looking at it from the

perspective of other audits that have, you know, the AMP audits that occur typically you come out of those

AMP audits with 100, slightly more than 100, RAIs.

You look at the number of RAIs that came out of us following the Byron audit which was the first

AMP audit that we conducted and we did not have close

to 100 RAIs.

MEMBER STETKAR: Well, when you say typically, yes. When I joined the Committee seven

years ago, there were a lot issued. But I=m talking about the more recent experience over the past two or three years as things have stabilized quite a bit and as people have become more familiar with the guidance in GALL Rev 2. A lot of the early ones was the guidance, GALL was in the state of transition. So the staff was asking RAIs about kind of looking forward to where Rev

1 was transitioning into Rev 2. So I used to see a lot related to those types of issues. But GALL has not been stable.

MS. ROBINSON: Right. And I think a lot of the RAIs that we had coming out of the AMP audit 118 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 were to a large degree clarification RAIs, you know, basing information that was in the LRA.

MEMBER STETKAR: Well, you haven

=t answered my question. But thanks.

MS. ROBINSON: Okay.

MEMBER STETKAR: We should go on in terms of getting into the more technical things.

CONSULTANT BARTON: But you=re right.

The interim staff guidance has got a bunch of --

MEMBER STETKAR: The interim staff guidance, what I

=m trying to push at is are we now in

an evolving second range. Five years ago we used to see a lot of RAIs that were kind of hunting for the

transition between GALL Rev 1 and GALL Rev 2.

CONSULTANT BARTON: Two, right.

MEMBER STETKAR: My sense quite honestly is now we

=re in a range where the licensees are hunting

for the transition between GALL Rev 2 and GALL Rev 3

as embodied by evolving interim staff guidance. And

I=m trying to get a sense of where the staff is on that.

MS. DIAZ: Yoira Diaz. What is meant by the difference between ISGs and in these is we had

several ISGs that evolved from the GALL Rev 2 and were

each in between these plans that you

=ve seen in the 119 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 latest. And some of these ISGs that we re in the draft form they were finalized by the time that Byron and Braidwood was issued, the LRA was issued. So some of

these IRAs could have come from the amount of ISGs that

we had as we evolve from Rev 2 and the subsequent

guidance that the staff has issued.

MEMBER STETKAR: Thank you. That helps.

That at least gets it on the record.

MR. HOLMBERG: Okay. I

=m basically almost done with my part. I was in the middle of the second bullet there. We were just finishing up

application changes.

CONSULTANT BARTON: All right. Sorry we messed you up.

MR. HOLMBERG: Applicant changes to some of the AMPs that were prompted by inspection. Those have been addressed. The Applicant has submitted

changes to the LRA for those.

I=m going to turn it over next to Nestor who will be discussing additional inspection concerns

that prompted further staff reviews.

MR. FELIZ

-ADORNO: Thank you, Mel. The team identified three issues requiring further NRR review. With the respect to the first item, the te am 120 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 found that the CRDM seismic supports were not included in the scope of the AMP. The Applicant subsequently revised the LRA to include the CRDM seismic support assemblies in scope and included the CRDM support components in the aging management review t able 3.5.2

tab 3. However, during the Headquarters= review, the staff identified concerns with the bolts which Lindsay will discuss later in this presentation. And

this issue applies to both Byron and Braidwood.

The second bullet refers to additional inspections of areas of concrete deterioration.

Specifically, during the Byron inspection and confirmed

during the Braidwood inspection, the inspectors noted

the Applicant planned to inspect for concrete deterioration at a distance with the use of a telescope

. The inspection team expressed concern regarding the Applicant

=s visual resolution capability to be used during the period of extended operation to

quantify degradation based on the quantitative acceptance criteria described in Chapter V of ACI

349.3R. This issue applies to all four units at

Braidwood and Byron.

The last bullet pertains to the flux 121 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 thimble inspection. During the inspection at Braidwood, the team identified the Braidwood Applicant

had not completed the eddy current examinations on any

of the 58 tube loops at Braidwood Unit 1 during the

September 2013 outage and only complete seven of the

58 flux thimble tubes at Braidwood Unit 2 during the

May 2014 outage.

The staff was not aware of the extent of the Applicant

=s deficiencies during the review of this AMP. We communicated this to NRR and currently the

Applicant=s actions to address this issue are being assessed by the staff. This issue pertains only to

the Braidwood Station.

The three examples demonstrate the benefit of the 71002 inspection to verify the programs described by the Applicant in their application recommendation which are consistent with the existing plant programs.

It also emphasizes the strong and important

coordination between Headquarters and the region in

this review process. Next slide please.

In summary, both teams concluded the Applicant performed the scoping and screening in accordance with the rule. Inspectors also found

information was easily retrievable and verified the 122 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 programs were generally effective in managing aging effects.

The teams also verified that Applicant has the tools to track the completion of enhancements and the development of new programs. Lastly, based on the

results of these inspections, the inspectors have

reasonable assurance that the programs will manage the aging effects and ensure the intended safety functions

of SSCs within the rule will be maintained if it is

determined that as described in the application with

the proposed enhancements and supplemented through the

Applicant=

s responses to request for additional

information and inspection or observations. Thank you. Now I

=ll turn the presentation back to Lindsay. CHAIRMAN SKILLMAN: Nestor, let me ask you a question please. I

=m reading above ground metall ic tank program B.2.17 and I find that the Byron and the

Braidwood 71002 inspection report-out have identical text. And I=m curious. Is that because this is a new

program for each site or is this an administrative

cleverness on the part of the inspection team?

MR. FELIZ

-ADORNO: It

=s a new program.

There=s no unique differences between the two sites.

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-3701 (202) 234-4433 It was inspected by the same inspector. So naturally he will have the same input. CHAIRMAN SKILLMAN: Identical same input.

MR. FELIZ-ADORNO: Yes.

CHAIRMAN SKILLMAN: Okay. Thank you.

Lindsay.

MS. ROBINSON: All right. We=

re on slide 8. Thank you, Mel and Nestor. We will now discuss each of the issues identified during the 71002

inspection.

As previously stated, the Applicant subsequently revised the LRA to include the CRDM seismic support assemblies and scope and included the CRDM

support components and AMR table 3.5.2-3. The staff

noted that the Applicant

=s LRA revision did not state

what type of bolts were used for the CRDM seismic

supports.

In a letter dated October 9, 2014, the staff issued RAI B.2.1.31 Tab 4, requested information to whether or not high strength bolts in sizes greater than one inch were used in CRDM supports. And, if so,

the staff requested the Applicant provide additional

information on the type and grade of the material to

determine whether the bolts will be managed for cracking 124 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 due to stress corrosion cracking. In a letter dated October 16, 2014, the Applicant responded to the staff

=s request by stating that there were no high strength bolts in sizes greater than one inch used in the CRDM seismic supports which

addressed the staff

=s concern. This issue and its closure will be addressed in the final SER and discussed

during the full Committee meeting. Next slide.

This next issue involves the Applicant=s procedure to conduct visual inspections of areas of concrete deterioration remotely with the use of an optical aid. The inspection team expressed concern

regarding the Applicant

=s visual resolution capability to be used during the period of extended operation to

quantify degradation based on quantitative acceptance

criteria described in Chapter 5 of ACI 349.3R. This issue applies to both Byron and Braidwood Stations,

Units 1 and 2. By letter dated November 6, 2014, the staff issued RAI 3.2.1.30

-6 requesting that the Applicant

provided information to verify that sufficient visual

resolution capability will be used during visual

examinations of concrete surfaces of containment

structures to detect and quantify forms of degradation 125 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 for comparison against quantitative acceptance criteria based on Chapter 5 of ACI349.3R.

By letter dated November 21, 2014, the Applicant provided its response to the RAI. The response is currently under staff review. This issue

and its closure will be addressed in the final SER and discussed during the full Committee meeting. Next

slide. By letter dated May 19, 2014, the staff issued RAI E.2.1.24

-1 requesting additional

information regarding higher than expected wear rates in flux thimble tubes at Braidwood Units 1 and 2. In addition, the staff also questioned the adequacy of

the program because it was not able to perform

examinations on a few of the tubes. By letter dated June 9, 2014, th e Applicant provided a response to the staff

=s RAI. In response, the Applicant discussed high wear rate issues and its

failure to obtain data on a few tubes based on outage inspections from 2007 to 2012 for both Braidwood Unit 1 and Unit 2. The Applicant also stated that several corrective actions were being implemented to address

the issues related to completing eddy current

examinations.

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-3701 (202) 234-4433 One corrective action was to increase the inspection frequency to perform examinations every outage. The staff closed the issue based on the

Applicant=s response.

During the NRC 71002 inspection at Braidwood, the staff discovered that the Applicant was not able to complete planned eddy current examinations on any of the 58 tubes at Braidwood Unit 1 dur ing the September 2013 outage and only partially completed

seven of 58 flux thimble tubes at Braidwood Unit 2 during

the May 2014 inspection.

The GALL AMP for flux thimble tube inspection implements the recommendations of NRC

Bulletin 88

-09 which established a program to monitor thimble tubes through periodic inspections. The staff was concerned that the program may not be adequate if tube wear examinations are not performed as scheduled

and therefore issued an RAI on October 10, 2014.

By letter dated October 31, 2014, the Applicant responded to the staff

=s RAI, but did not

identify the causes of the problem or provide corrective actions sufficient to address the problem. By letter

dated November 22, 2014, the Applicant supplemented

its response further by providing additional 127 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 information and license renewal commitments.

The staff is currently reviewing the Applicant=

s supplemental response and the adequacy of the Applicant

=s aging management program. This issue

will remain open until it

=s adequately resolved. This

issue and its closure will be addressed in the final SER and discussed at the full Committee meeting. Next

slide. We now shift our focus to the SER. SER Section 2 describes the scoping and screening of

structures and components subject to aging management review. The staff reviewed the Applicant

=s scoping

and screening methodology, procedures, quality controls of the LRA development and training of its project personnel. The staff also reviewed the various

summaries of the s afety-related systems, structures

and components, non

-safety systems, structures and

components affecting the safety

-related components and

systems, structures and components relied upon to

perform functions in compliance with the Commission

=s regulations for fire protection, environmental qualification, station blackout, pressurized thermal

shock and anticipated transients without scram. Based on the review, the results from the 128 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 scoping and screening audit and additional information provided by the Applicant, the staff concludes that

the Applicant

=s scoping and screening methodology was consistent with the standard review plan and the

requirements of 10 CFR Part 54. Next slide.

SER Section 3 covers the staff

=s review of the Applicant=s aging management programs. For a given aging management review, the staff reviewed the item to determine whether it is consistent with the GALL report. Section 3.1 through 3.6 include the aging management review items in each of the general system

areas within the scope of license renewal.

If the aging management review was not consistent with the GALL, then the staff conducted a

technical review to ensure adequacy. Next slide.

The Applicant submitted 45 aging management programs in the application. What I have before you is actually a table. And what it identifies how it was dispositioned in the LRA. And then the other

side actually dispositions how the review identified

it in the SER with open items. Next slide.

SER Section 3 contained one open item.

Open Item 3.0.3.1.3

-1 pertains to wear in the

Applicant=s CRDM penetration nozzles. During the AMP 129 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 audit, the staff noted operating experience which indicated that the Applicant

=s CRDM penetration nozzles

have wear near the J

-groove valve due to interact ions with CRDM thermal sleeves centering tabs.

The Applicant has not proposed any examinations to monitor the wear during the period of

extended operation but determine continued

acceptability of the defect. In response to the

staff=s RAIs, the Applicant stated that it is

participating in the Westinghouse owner group project which is expected to provide a detailed analysis

confirming that the nozzles will continue to perform

their intended pressure boundary functions through the

end of the renewed license despite the wear.

The Applicant indicated that if the analytical results do not justify continued operation

of the nozzles during the period of extended operation or if the staff finds the analysis unacceptable, then

the Applicant will provide a commitment to repair or

replace the CRDM nozzles that are affected.

MEMBER STETKAR: Lindsay, has that analysis been submitted? It has? MS. ROBINSON: I=

m actually going to cover that right now.

130 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 MEMBER STETKAR: Sorry.

MS. ROBINSON: Not a problem. The Applicant provided a brief summary of the results of

that analysis on November 24, 2014. The Applicant=s response states that it needs to perform further

evaluations to determine if the LRA needs to be revised

as a result of the analysis. The staff is currently reviewing the Applicant

=s response and also review any

additional information which the Applicant provides

as a result of the continued evaluation.

In terms of the analysis itself, we have not received the complete analysis from the Applicant.

But the Applicant did say that they would be providing

that to us.

MEMBER STETKAR: Okay.

MEMBER BALLINGER: But we had a presentation a little while ago that basically

discussed the analysis. Am I right?

MEMBER STETKAR: No. Not the analysis.

CHAIRMAN SKILLMAN: Not the analysis. We had presentations discussing what they

=re going to do.

MEMBER RICCARDELLA: They said there was a full section to the analysis that justified integrity

of the pressure boundary with this wear.

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-3701 (202) 234-4433 CHAIRMAN SKILLMAN: Yes, Ron

=s question or Ron made the statement that we had a presentation on the analysis. We had a presentation on the wear

and a discussion of what they are going to do.

MEMBER STETKAR: But there

=s some stuff saying preliminary information from the analysis.

That could lead you to the conclusion that they

presented.

MEMBER BALLINGER: My words were not sufficiently accurate. CHAIRMAN SKILLMAN: I understood what you meant. MEMBER RICCARDELLA: My impression is the analysis has been done. It just hasn

=t been submitted.

That=s my understanding.

MEMBER STETKAR: Lindsay.

MS. ROBINSON: We can actually have the reviewer who is handling this one. We did get the

response and again the response was dated November 24,

2014. So the staff is currently evaluating the response that was provided. But Roger here can provide

maybe a little more insight. MR. KALIKIAN: Yes. Hi. I

=m Roger Kalikian and I

=m the reviewer for the exam. They did 132 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 provide a summary of the analysis. They did s ay they completed the analysis. And they also mentioned that

they are continuing to evaluate to see how the analysis will impact the LRA. And they would submit that

information to us when it

=s completed. But we just

got a brief summary and nothing else.

CHAIRMAN SKILLMAN: Please continue, Lindsay. Thank you. MS. ROBINSON: The results of the staff

=s review will be documented in the final SER and discussed

during the full Committee meeting. Next slide.

SER Section 4 identifies Time Limited Aging Analysis or TLAAs. Section 4.1 documents the staff

=s evaluation of the Applicant

=s identification of applicable TLAAs. The staff evaluated the Applicant

=s basis for identifying those plant

-specific or generic

analysis that needed to be identified as TLAAs and determined that the Applicant has provided an accurate

list of TLAAs as required by 10 CFR 54.21(c)(1).

Sections 4.2 through 4.7 document the staff=s review of the applicable Byron and Braidwood TLAAs as shown. Based on its review of t he information

provided by the Applicant and pending the resolution

of one open item, the staff concludes that the TLAAs 133 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 were either (a) remain valid for the period of extended operation; (b) have been projected to the end of the

period of extended operation; or (c) the effects of

aging on those intended functions will be adequately

managed for the period of extended operation as required by 10 CFR 54.21(c)(1)(I), (ii) or (iii) respectively.

Next slide. CHAIRMAN SKILLMAN: Let=

s just hold on for a second here.

MS. ROBINSON: Yes.

CHAIRMAN SKILLMAN: Ron, did you want to ask a question about 4.5 on that slide.

MEMBER BALLINGER: This is the tendon pre-stress analysis. I was concerned about what

happened at North Anna where you ended up with a tendon getting blown up basically by hydrogen embrittlement and releasing a tension. And it

=s because the grease

that=s in that conduit in the tendon is a high pH grease

that=s designed to absorb moisture to maintain the pH

high enough.

There=s a replacement. You

=re supposed to inspect and replace that grease. So I was concerned

and just wondering if there=s a program in place to do that inspection and replace that grease. A lot of 134 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 times folks don

=t do it. It

=s pretty onerous and ugly and difficult and dirty and everything else.

But you=re required to have X number of those tendons in place for containment pressure

maintaining. And if all of a sudden one of those

tendons goes, the shock to the system, I=m wondering

whether or not t here=s a danger. We

=ve seen these separations of concrete, the layers of concrete, around

the rebar. I

=m just curious as to how that

=s being handled. MS. ROBINSON: Is anybody from Exelon able to address that? MR. GALLAGHER: Yes, we can answer that question. Jim Annett.

MR. ANNETT: My name is Jim Annett. I=m on the License Renewal Team. I think you had a couple questions in there. I

=ll first talk about the grease in the tendons. The grease used at Byron and Braidwood

is like the P

-4 version of the grease versus like the

P-0. And that starts with a higher alkalinity level.

So our acceptance criteria is a higher alkalinity level at Byron and Braidwood. So the grease level is always maintained at a higher alkalinity level at Byron and Braidwood. And when they do the sampling, 135 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 it=s supposed to

-- They have done grease replacements at Byron and Braidwood also. But they

ve never gotten to essentially like a zero level. MEMBER BALLINGER: Okay. So it

s part of the aging management program to maintain that high pH.

MR. ANNETT: Yes, it is.

MEMBER BALLINGER: Okay.

CHAIRMAN SKILLMAN: Dr. Ballinger, you

=re good. MEMBER BALLINGER: Yes. Good.

CHAIRMAN SKILLMAN: Okay. Lindsay, go ahead. Thank you. MS. ROBINSON: Thank you. Next slide.

We=re on slide 16. Section 4 contains one open item.

Open Item 4.3

-1 is related to environmentally assisted

fatigue locations for reactor coolant pressure boundary

components. The Applicant performed a review of all four units of all applicable reacto r coolant pressure boundary components with a Class 1 fatigue analysis

to determine the plant-specific leading locations to be monitored by the fatigue monitoring program for EAF.

However, the Applicant did not demonstrate that its

methodology for selecting those locations provided assurance to the location that the locations were 136 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 bounding.

In the Applicant

=s methodology, the staff identified the following issues: (a) the Applicant=s justification for selecting one material to bound other

materials and (b) the Applicant

=s basis for screening out a component with a higher environmentally assisted

cumulative usage factor value than the leading

location. By a letter dated October 28, 2014, the staff issued a follow

-up RAI for the Applicant to demonstrate the specific components would not need to

be monitored for EAF in the period of extended

operation.

By letter dated November 25, 2014, the Applicant provided its response to the RAI. The response is currently under staff review. The staff

=s conclusion will be documented in the final SER and discussed in the full Committee meeting. Next slide.

The staff

=s conclusion will be provided in the final SER. Pending a satisfactory resolution

of the open items and inspection issues, the staff will determine whether the requirements of 10 CFR 54.29(a)

have been met for the renewal of Byron Station Units

1 and 2 and Braidwood Station Units 1 and 2.

137 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 This concludes our staff presentation.

And we will now be available for any further questions.

CHAIRMAN SKILLMAN: Thank you, Lindsay. Colleagues, may I ask if you have questions for the NRC staff please? MEMBER STETKAR: Yes. I have a couple. One is back to the condensate storage tanks. We heard from the Licensee that they plan to inspe ct the total of 25 locations distributed between the two CSTs at each unit; whereas, the guidance now, interim staff

guidance, specifically says for each outdoor insulated

tank. And I

=m curious why the staff accepted this

notion of AWell, I can look at 12 on one of them and 13 on the other and 25 between the two them is good enough. Or if I have maybe 15 tanks, perhaps I could

look at one on each one of them or a couple on each

one of them and somehow count up to 25 that way.

@ I=m curious why you accept this sort of notion of

distributed inspections when you know we

=ve pretty

already established that the tanks are not identical

in terms of their life history.

MS. ROBINSON: We can have the reviewer, Mr. Holston, come in and respond to your question.

MR. HOLSTON: Yes, this is Bill Holston, 138 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 Technical Reviewer for the Division of License Renewal.

We accepted the 25 total per site. Because when we

were writing the interim staff guidance, a typical plant

has six outdoor tanks, usually two fuel tanks, maybe

even more than that, two fire water tanks, two

condensate storage tanks.

In the case of both Byron and Braidwood, they only had two outdoor tanks. They don

=t have fire

water storage tanks. The diesel storage tanks are

inside. So a sample population of 25 is adequate.

The sample population of 25 is consistent with other aging management programs such as the

internal surfaces program, the one

-time inspection program and selective leeching program. A total

population of 25 establishes reasonable assurance.

All four of the tanks, the final point is that all four of the tanks were susceptible to water underneath the

lagging in the license renewal application operating experience examples for all four of them. So we

considered that the environmental conditions between the insulation and the tank sides were representative

amongst the four tanks. MEMBER STETKAR: I guess I still don

=t understand your rationale. For the record I=ll read 139 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 into Section (e)(iii)(c) of the License Re newal ISG-2012-

02. It states AFor each outdoor insulated tank and indoor insulated tanks exposed to condensation because the in

-scope component is being operated below

the dew point, GALL report AMP XI.M

-29 was revised to recommend removal of insulation from either 25 one square foot sections or 20 percent of the surface area and inspecting the exterior surface of the tank.

@ That doesn=t say we sort of sample 25 somewhere around the total portion of the site. It says I look at each tank.

MR. HOLSTON: That=s correct. And I was actually the author of that interim staff guidance.

MEMBER STETKAR: Good.

MR. HOLSTON: And an interim staff guidance just like the GALL report is a set of

recommendations. It=s not a set of requirements. The applicant can take exception to that and in this case

the applicant stated that they wanted to do 25 total

inspections at the site. And we found that 25 given

the reasons I just explained at the beginning of the

response was adequate in this situation.

Where you used an example of what is the plant had 16 tanks. Well, we would have come to a different conclusion if the plant had 16 tanks. In 140 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 fact, this plant has two outdoor tanks.

MEMBER STETKAR: Okay. Thank you. The only other one that I had and I

=ll ask the staff about this. I

=m going to ask the licensee,

but we=re good on time. In their program for monitoring

neutron-absorbing material in the fuel pool, the report

noted that the -- I=ll probably get the terminology wrong. So just bear with me here

-- placement of the coupons, the coupons are supposed to be placed in the middle of the most recently renewed fuel. So they would

get the highest irradiation. And yet the experience

has been that they haven

=t always done that or I don

=t know whether it=s haven=t always or perhaps never. And now they

=ve committed

-- It says, AThe Applicant stated that prior to the period of extended

operation an enhancement will be implemented to maintain the coupon exposure such as bounding for the

raw material and spent fuel rods.

@ In other words, sometime before 2026, they=re actually going to make

sure they do this right.

Have they started to do it right now? I mean, how do we know that the coupons provide a bounding

assessment of that material for the next 15 years?

MS. ROBINSON: I believe we have a reviewer 141 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 who is on the line.

MEMBER STETKAR: Good. MS. ROBINSON: Who may be able to address that. Is it still on listening mode?

PARTICIPANT: It=s open.

MS. ROBINSON: It is. Aloysius.

MR. OBODOAKO: Yes, this is Aloysius Obodoako in the Division of Engineering. I reviewed this program. Well, I supported the review of this

program during the audit and also the aging management

program. I

=m currently looking for the response to that through my documents. It looks like I

=ll have to get back to you about that response.

MEMBER STETKAR: Okay. I

=m not sure.

I=m more concerned about how are they monitoring it

currently which is really more an issue of a current

licensing rather than with the period of extended

operation. MS. ROBINSON: I think Exelon actually

-- There=s somebody that can address that.

MR. GALLAGHER: Yes, Dylan Cimock can answer that question. MR. CIMOCK: Dylan Cimock, License Renewal Team for Exelon. Just to clarify, Byron and Braidwood 142 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 did implement an accelerated irradiation schedule at the beginning of the installation of the racks which

includes surrounding the coupon tree on all sides with freshly discharged fuel for the first five cycles.

So that was an importance of the manufacturer

=s recommendations and both stations did satisfy that

initial requirement.

We received an additional RAI asking how we will ensure that going forward. So we enhanced our

program to state that we will maintain those coupons in that configuration going forward prior to testing.

MEMBER STETKAR: You said during the first

-- When did you rerack the pools?

MR. CIMOCK: Byron and Braidwood, it was approximately 2000-2001.

MEMBER STETKAR: Okay. So you had the accelerated irradiation through let

=s say 2005-2006-2007 time period, right?

MR. CIMOCK: Yes.

MEMBER STETKAR: The first five years roughly. But since then they

=ve not been in that

configuration. Is that correct?

MR. CIMOCK: That is correct.

MEMBER STETKAR: Okay. B ut going forward 143 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-4433 WASHINGTON, D.C. 20005

-3701 (202) 234-4433 from now or going forward from 2026, you=re going to ensure that they

=re in an accelerated irradiation.

In other words, that they received the highest

performance.

MR. CIMOCK: The manufacturer

=s recommendation was for the initial five cycles which would ensure that they were bounding for the duration of the racks which we assume for the existing license

they would remain bounding.

MEMBER STETKAR: Okay.

MR. CIMOCK: Now going forward they are currently in a bounding condition. We are committing

to maintaining those in a bounding condition through

the PEO.

MEMBER STETKAR: Thank you. That clarified. Thanks. That helps.

CHAIRMAN SKILLMAN: Colleagues, any additional questions for the NRC staff please?

Hearing none, are there individuals in the audience that would like to ask a question or make a

statement please?

Hearing none on the telephone line that is now open, are there any members of the public or

others that would like to make a statement or ask a 144 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

(202) 234

-4433 WASHINGTON, D.C. 20005

-3701 (202) 234-4433 question please?

If you=re out there, would you please acknowledge your presence?

(No response.) Thank you. Hearing no comments, would you please close the line?

SUBCOMMITTEE DISCUSSION CHAIRMAN SKILLMAN: As a final activity here from my colleagues around the table, do you have

any questions either for the staff or for the Applicant

for these four units at two sites?

MEMBER RICCARDELLA: I don

=t have any further questions. Thank you.

MEMBER RAY: No.

MEMBER POWERS: No.

MEMBER BALLINGER: No.

MEMBER STETKAR: Mr. Chairman, I just want to congratulate the staff. I think you guys did really

well actually on the audits and inspections. It

=s pretty onerous to try to get f our units, your hands

around four units, with differences and similarities.

I was actually really impressed with the review effort.

I just wanted to make that statement. MEMBER POWERS: I think the Applicant did 145 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 good because the project leader here is a graduate of my course.

MS. ROBINSON: Yes, that is absolutely correct.

MEMBER POWERS: That=s what led to --

MEMBER STETKAR: Yet again in your debt, Dr. Powers.

(Laughter.)

CONSULTANT BARTON: I think the Applicant did a terrific job of putting this whole thing together.

It was a real good presentation.

CHAIRMAN SKILLMAN: I want to echo that.

I want to thank the Exelon team, the Byron team, the

Braidwood team. This has been an enormous amount of

work and we understand that it has been.

And it=s been an enormous amount of work for the staff, for the region

and for the team here in Rockville. Thank you.

MEMBER POWERS: I would say let

=s encourage them not to do this again. There are too

many points at one time.

CHAIRMAN SKILLMAN: Those of us who did the reviews were juggling four units, two sites, permutations and combinations, what are the AMPs, where do they overlap, where are they separate, why are they 146 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 separate. And you=ve done a great job in clarifying those distinctions and differences. So I thank you

very much.

With that, I

=m going to wish all safe travels and I

=m going to stop this meeting. We are

adjourned. Thank you.

(Whereupon, at 11:25 a.m., the above-entitled matter was concluded.)

ACRS Subcommittee Presentation December 03, 2014 License Renewal Application Braidwood Byron Introductions Byron and Braidwood Stations, Units 1 and 2 1

AgendaByron and Braidwood Stations, Units 1 and 2 2

3 Byron and BraidwoodStations, Units 1 and 2 Byron and Braidwood Station Locations Byron and Braidwood Stations, Units 1 and 2 4Byron StationIndependent Spent Fuel Storage Installation (ISFSI) 345 kV Switchyard Essential Service Water Cooling Towers (Ultimate Heat Sink)Circulating Water Pump HouseCirculating Water Flume Byron and Braidwood Stations, Units 1 and 2 5Braidwood StationCooling Pond (Ultimate Heat Sink)

Lake Screen HouseIndependent Spent Fuel Storage Installation (ISFSI) 345 kV Switchyard Station OverviewByron and Braidwood Stations, Units 1 and 2 6

GALL Revision 2 Consistency and License Renewal CommitmentsByron and Braidwood Stations, Units 1 and 2 7

GALL Consistency and CommitmentsByron and Braidwood Stations, Units 1 and 2 8ByronBraidwoodTotal AMPs 4544AMPs Consistent with GALL 3837AMPswith Exception to GALL 77Commitments 4746 Open ItemsByron and Braidwood Stations, Units 1 and 2 9

Open Item 10Byron and Braidwood Stations, Units 1 and 2Byron and Braidwood Stations, Units 1 and 2 10 Open Item

11Byron and Braidwood Stations, Units 1 and 2Byron and Braidwood Stations, Units 1 and 2 11 Overview of CRDM Housing Wear 12Byron and Braidwood Stations, Units 1 and 2Overview of CRDM Housing Wear CRDM Housing Wear Details 13Byron and Braidwood Stations, Units 1 and 2 CRDM Housing Analysis

-

-14Byron and Braidwood Stations, Units 1 and 2CRDM Housing Wear Analysis

15Byron and Braidwood Stations, Units 1 and 2Summary and Conclusions Items of Interest from Region III InspectionsByron and Braidwood Stations, Units 1 and 2 16 Item of Interest -

Visual Examination of Concrete Containment Structures

-

Byron and Braidwood Stations, Units 1 and 2 17 Item of Interest -CRDM Seismic Support Assembly Aging Management18Byron and Braidwood Stations, Units 1 and 2Byron and Braidwood Stations, Units 1 and 2 18 CRDM Seismic Support Assembly Aging Management19Byron and Braidwood Stations, Units 1 and 2Byron and Braidwood Stations, Units 1 and 2 19 CRDM Seismic Support Assembly Aging Management---

--

20Byron and Braidwood Stations, Units 1 and 2Byron and Braidwood Stations, Units 1 and 2 20

Byron and Braidwood Stations, Units 1 and 2 21Item of Interest -

Braidwood Flux Thimble Tube Inspection Program In-Core Flux Monitoring SystemByron and Braidwood Stations, Units 1 and 2 22

---

Byron and Braidwood Stations, Units 1 and 2 23Corrective Actions

-

-Byron and Braidwood Stations, Units 1 and 2 24Basis for Adequacy of Current ProgramSpring2014Spring 2015Fall 2015Fall 2016Spring 2017OngoingUnit 11741Every 3 Refuel OutagesUnit 27Completed2922

Byron and Braidwood Stations, Units 1 and 2 25Conclusion ClosingByron and Braidwood Stations, Units 1 and 2 26 ACRS Subcommittee Presentation December 03, 2014 License Renewal Application Braidwood Byron Advisory Committee on Reactor Safeguards License Renewal Subcommittee Byron Station, Units 1 and 2, and Braidwood Station, Units 1 and 2 (BBS) Safety Evaluation Report (SER) with Open Items Lindsay Robinson, Project Manager Office of Nuclear Reactor Regulation 1

Presentation Outline Overview of BBS license renewal review Region III License Renewal Onsite Inspection 71002 Inspection Issues SER Section 2, Scoping and Screening Review SER Section 3, Aging Management Review SER Section 4, Time-Limited Aging Analyses 2

License Renewal Review (Audits and Inspections) Scoping and Screening Methodology Audit Byron: July 29 - August 2, 2013 Braidwood: December 2-4, 2013 Aging Management Program (AMP) Audit Byron: August 19-30, 2013 Braidwood: October 30-31, 2013, and Dec 2-6, 2013 Environmental Audit Byron: September 17-19, 2013 Braidwood: November 18-20, 2013 Region III 71002 Inspection (Scoping and Screening & AMPs) Byron: August 4-8, 2014, and August 18-22, 2014 Braidwood: Sept 15-26, 2014 3 SER Overview SER with Open Items (OIs) was issued October 30, 2014 BBS SER contains 2 OIs: OI 3.0.3.1.3-1 CRDM Nozzle Wear OI 4.3-1 Environmentally Assisted Fatigue (EAF) in Class 1 Components The final SER is scheduled for publication April 2015 4

71002 Inspections Scope Regulated Events Non-Safety Systems affecting Safety Systems Aging Management Programs Byron Inspection Aug. 2014: Team Inspection (6 inspectors) on-site for 2 weeks Braidwood Inspection Sept. 2014: Team Inspection (5 inspectors) on-site for 2 weeks 5

6 Overall Inspection Results Material condition of SSCs Good Application changes to some AMPs Identified issues for further review: XI.S3 ASME Section XI, Subsection IWF XI.S2 ASME Section XI, Subsection IWL XI.M37 Flux Thimble Tube Inspection 71002 Inspections 71002 Inspections

Conclusions:

Scoping and screening performed in accordance with 10 CFR 54 Information used to prepare the license renewal application was retrievable, auditable, and consistent with 10 CFR 54 Existing programs are generally effective in managing aging effects Actions to address enhancements and new programs are being tracked for completion Reasonable assurance that aging effects will be managed and intended functions maintained, subject to satisfactory resolution of open issues 7

71002 Inspection Issue CRDM Seismic Support Assembly Bolting Issue: LRA revised to include CRDM Seismic Support Assemblies but did not specify whether the assemblies included high-strength bolting Concern: Aging management of high-strength bolting Applicant responded that there is no high-strength bolting used in CRDM seismic supports This issue is resolved 8 71002 Inspection Issue IWL Visual Examinations Issue: Currently, visual inspections of some areas of concrete deterioration are conducted remotely with the use of an optical aid.

Concern: Visual resolution capability of optical aids to detect and quantify degradation for comparison against quantitative acceptance criteria described in ACI 349.3R

. 9 71002 Inspection Issue Flux Thimble Tube Inspection Issue: The applicant failed to complete inspections at Braidwood Units 1 and 2 during the most recent outages.

Concern: AMP may be inadequate 10 SER Section 2 Summary Structures and Components Subject to Aging Management Review Section 2.1, Scoping and Screening Methodology Section 2.2, Plant-Level Scoping Results

Sections 2.3, 2.4, 2.5 Scoping and Screening Results 11 SER Section 3: Aging Management Review Section 3.0 Aging Management Programs Section 3.1 Reactor Vessel, Internals, and Reactor Coolant Systems Section 3.2 Engineered Safety Features Systems Section 3.3 Auxiliary Systems Section 3.4 Steam and Power Conversion Systems Section 3.5 Containments, Structures, and Component Supports Section 3.6 Electrical and Instrumentation and Controls Systems 12 SER Section 3 LRA identified: 13 new programs 11 consistent 2 consistent w/ exceptions 32 existing programs 9 consistent 18 consistent w/ enhancements 5 consistent w/ enhancements and exceptions : 13 new programs 11 consistent 2 consistent w/ exceptions 32 existing programs 6 consistent 21 consistent w/ enhancements 5 consistent w/ enhancements and exceptions 13 3.0.3 Aging Management Programs SER Section 3 Open Item OI 3.0.3.1.3-1 CRDM Nozzle Wear:

Issue: CRDM penetration nozzle wear not managed.

Open Item: Applicant to confirm CRDM penetration nozzle wear will be adequately managed.

14 4.1 Identification of TLAAs 4.2 Reactor Vessel Neutron Embrittlement Analysis 4.3 Metal Fatigue 4.4 Environmental Qualification of Electric Equipment 4.5 Concrete Containment Tendon Prestress Analyses 4.6 Containment Liner Plate, Metal Containments, and Penetration Fatigue Analyses 4.7 Other Plant-Specific TLAAs SER Section 4: TLAA 15 SER Section 4 Open Item OI 4.3-1 Environmentally Assisted Fatigue in Class 1 Components: Issue: Insufficient justification for selecting leading locations how one material bounds other materials basis for comparison of CUFen values Open Item: Applicant did not demonstrate why specific components would not need to be monitored for EAF 16 Conclusion Pending satisfactory resolution of the open items and inspection issues, the staff will determine whether the requirements of 10 CFR 54.29(a) have been met for the license renewal of Byron Station, Unit 1 and Unit 2, and Braidwood Station, Unit 1 and Unit 2.

17