ML110530294

Transcript of the Advisory Committee on Reactor Safeguards Plant License Renewal Subcommittee - Diablo Canyon - February 9, 2011 (Open). Pages 1-145

ML110530294
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Site:	Diablo Canyon
Issue date:	02/09/2011
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NRC-698
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Official Transcript of Proceedings NUCLEAR REGULATORY COMMISSION Title: Advisory Committee on Reactor Safeguards Plant License Renewal Subcommittee

Docket Number:

(n/a)

Location: Rockville, Maryland

Date: Wednesday, February 9, 2011

Work Order No.:

NRC-698 Pages 1-145

NEAL R. GROSS AND CO., INC.

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

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

(202) 234-4433 WASHINGTON, D.C. 20005

-3701 www.nealrgross.com 1 1 2 DISCLAIMER 3 4 5 UNITED STATES NUCLEAR REGULATORY COMMISSION'S 6 ADVISORY COMMITTEE ON REACTOR SAFEGUARDS 7 8 9 The contents of this transcript of the 10 proceeding of the United States Nuclear Regulatory 11 Commission Advisory Committee on Reactor Safeguards, 12 as reported herein, is a record of the discussions 13 recorded at the m eeting. 14 15 This transcript has not been reviewed, 16 corrected, and edited, and it may contain 17 inaccuracies.

18 19 20 21 22 23 24 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 2 UNITED STATES OF AMERICA 1 NUCLEAR REGULATORY COMMISSION 2 + + + + + 3 ADVISORY COMMITTEE ON REACTOR SAFEGUARDS 4 (ACRS) 5 + + + + + 6 PLANT LICENSE RENEWAL SUBCOMMITTEE 7 DIABLO CANYON POWER PLANT 8 + + + + + 9 WEDNESDAY 10 FEBRUARY 9, 2011 11 + + + + + 12 ROCKVILLE, MARYLAND 13 + + + + + 14 The Subcommittee met at the Nuclear 15 Regulatory Commission, Two White Flint North, 16 Room T2-B1, at 1:30 p.m., Dennis C. Bl ey, 17 Chairman, presiding.

18 19 COMMITTEE MEMBERS:

20 DENNIS C. BLEY Chairman 21 SAID ABDEL

-KHALIK Member 22 J. SAM ARMIJO Member 23 SANJOY BANERJEE Member 24 MICHAEL L. CORRADINI Member 25 26 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 3 HAROLD B. RAY Member 1 MICHAEL T. RYAN Member 2 WILLIAM J. SHACK Member 3 JOHN D. SIEBER Member 4 JOHN W. STETKAR Member at Large 5 6 ACRS CONSULTANTS PRESENT:

7 JOHN J. BARTON 8 9 NRC STAFF PRESENT:

10 NATHANIEL FERRER, NRR 11 MELANIE GALLOWAY, NRR/DLR 12 STAN GARDOCKI, NRR/DSS 13 ALLEN HISER, NRR/DLR 14 BRIAN HOLIAN, NRR/DLR 15 WILLIAM HOLSTON, NRR/DLR 16 JAMES MEDOFF, NRR/DLR 17 NEIL O'KEEFE 18 GREG PICK, Region IV 19 JEFF POEHLER, NRR/DSI 20 DAVE WRONA, NRR/DLR 21 MICHAEL BENSON, Designated Federal Official 22 23 24 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 4 ALSO PRESENT FROM PG&E 1 MICHELLE ALBRIGHT 2 CHRIS BEARD 3 JIM BECKER 4 DAVID GERBER, Structural Integrity 5 Associates 6 DAVID GONZALEZ 7 JOE GORYANCE 8 LEE GOYETTE 9 TERRY GREBEL 10 DANIEL HARDESTY 11 MARK MAYER 12 DAVE MIKLUSH 13 CHALMER MYER 14 LOREN SHARP 15 MIRANDA TAN 16 RYAN WEST 17 DAVID WONG 18 MIKE WRIGH T 19 20 21 22 23 24 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 5 TABLE OF CONTENTS 1 AGENDA ITEM PAGE 2 Opening Remarks, Dennis Bley, ACRS 6 3 Staff Introduction, Brian Holian 7 4 PG&E Company

- Diablo Canyon Power Plant:

5 Introductions; Site & Station 13 6 Descriptions, Jim Becker 7 History/Major Improvements, Loren Sharp 18 8 License Renewal Application; Open 20 9 and Confirmatory Items, Terry Grebel 10 Flux Thimble Tube Inspection Program 29 11 (Open Item), Mike Wright 12 Flaw Growth Evaluation for RHR (Open 39 13 Item), Dave Gonzalez 14 Scoping and Scree ning (Open Items);

55 15 Buried Piping and Tanks Inspection 16 Program (Open Item), Dave Miklush 17 TLAA Identification and Metal Fatigue 66 18 (Open Items), Michelle Albright 19 NRC STAFF: Nathaniel Ferrer, Greg Pick 20 SER Overview and Scoping and 81 21 Screening Results; Onsite Inspection Results 22 Aging Management Review; and 102 23 Time Limited Aging Analyses 24 Subcommittee Discussion 141 25 26 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 6 P-R-O-C-C-E-D-I-N-G-S 1 Time: 1:30 p.m.

2 CHAIRMAN BLEY: The meeting will now 3 come to order. This is a meeting of the Plant 4 License Renewal Subcommittee of the Advisory 5 Committee on Reactor Safeguards.

6 I am Dennis Bley, Chairman of the 7 Subcommittee. ACRS Members in attendance today 8 are Bill Shack, Mike Ryan, John Stetkar, Said 9 Abdel-Khalik, Sam Armijo, Harold Ray and Jack 10 Sieb er. 11 We have Tom Barton as our consultant, 12 and Michael Benson is the Designated Federal 13 Official for this meeting.

14 The Subcommittee will review the 15 License Renewal Application of the Diablo Canyon 16 Power Plant, Units 1 and 2, and the associated 17 SER with open items. We will hear presentations 18 from the NRC staff and Pacific Gas and Electric, 19 PG&E. 20 We have received no written comments 21 or requests for time to make oral statements from 22 members of the public regarding today's meeting.

23 I will mention that th e next-door conference 24 room is also following this meeting on the TV 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 7 screens. There is an overflow audience today.

1 The entire meeting will be open to 2 public attendance. The Subcommittee will gather 3 information, analyze relevant issues and facts, 4 and formulate proposed positions and actions, as 5 appropriate, for deliberation by the full 6 Committee.

7 The rules for participation in today's 8 meeting have been announced as part of the Notice 9 of this meeting previously published in the 10 Federal Register.

11 A transcript of the meeting is being 12 kept, and will be made available as stated in the 13 Federal Register Notice. Therefore, we request 14 that participants in this meeting use the 15 microphones located throughout the meeting room 16 when addressing the Subcommittee. T he 17 participants should first identify themselves and 18 speak with sufficient clarity and volume so that 19 they may be readily heard.

20 We will now proceed with the meeting, 21 and I call upon Brian Holian to begin.

22 MR. HOLIAN: Thank you, Chairman, and 23 thank yo u -- Good afternoon, Subcommittee. My 24 name is Brian Holian. I am the Director of the 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 8 Division of License Renewal, and we are here 1 today for the Diablo Canyon Subcommittee meeting.

2 I will make brief introductions and 3 then quickly go over the agenda and turn it over 4 to the licensee for their part of the 5 presentation.

6 To my left is Melanie Galloway, the 7 Deputy Director for Division of License Renewal.

8 Behind us

-- I will just make a couple of 9 introductions, and we will repeat a few and add a 10 few for when our people come to the table, but I 11 wanted to mention that Dave Wrona is the Branch 12 Chief for Diablo Canyon sitting over there behind 13 the stanchion.

14 The Project Manager, you will hear 15 more from later, is Nate Ferrer, and we do have 16 two individuals who escaped Region IV and a 17 quarter-inch of snow or whatever they got. The 18 office is closed today, but they got out 19 yesterday on a plane, and that is Mr. Greg Pick, 20 the Senior Inspector from Region IV

-- the 21 Committee has seen him before; he had 22 presentations

-- and Neil O'Keefe, his Branch 23 Chief. So I welcome them in from the cold of 24 Dallas. 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 9 The agenda today, as I mentioned, is 1 to look at Diablo Canyon, the third STARS plan to 2 come in for an application for a license renewal.

3 We had Wolf Creek several years ago, and then 4 Palo Verde, and the full committee will be 5 hearing from Palo Verde tomorrow morning for 6 their final SER and the closure of their open 7 items. 8 I mention that, because, in 9 particular, some of the items you will see both 10 in Diablo's presentation and the staff's. We 11 have a couple of open items that are still 12 related to scoping, and the Subcommittee might 13 wonder about that.

14 We did see some issues on Palo Verde's 15 scoping, if you remember back on draft SER, and 16 so I just highlight that. The S TARS -- The 17 alliance, the STARS group, was learning from the 18 Palo Verde. Folks are here in the audience from 19 Palo Verde for tomorrow, and we know that, 20 through our license renewal quarterly meetings, 21 those lessons learned get passed on, but their 22 application was already in, and our audits were 23 already going when you see a lot of those RAIs.

24 So I think the Applicant will speak to that a 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 10 little bit, but I wanted to mention that.

1 The second item that I wanted to 2 really mention overall for the Committee

-- the 3 Committee is probably aware of it from general 4 correspondence, but I just wanted to highlight it 5 here at the opening. Diablo, being in 6 California, seismic issues are of concern to the 7 local population there and, of course, the staff 8 also. 9 Last year, as the application came in 10 for Diablo, we got several letters in to the 11 staff requesting a delay, requesting more 12 information be done first. Even the State of 13 California was interested, besides local 14 interested stakeholders, on new information on 15 potential faults or differences in the design 16 basis. 17 I just wanted to highlight that to the 18 Committee. We addressed that in a July letter 19 from the Director of NRR to the stakeholders, 20 saying that those issues would be best dealt with 21 under Part 50. They are c urrent issues. Right 22 now, their current licensing basis is

-- although 23 there might be questions on it

-- not called into 24 effect. 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 11 The staff even looked at a new 1 potential fault back in the '09 time frame. That 2 was the subject. So I just wanted to make the 3 Committee aware that we and the Region have had 4 several public meetings out in the California 5 area to address that potential stakeholder item.

6 So you will see correspondence on that as you 7 look through the docket, but we consider it a 8 Part 50 issue.

9 If at anytime that design basis 10 changes, we would be able to either

-- if it 11 happened during the license renewal, be able to 12 supplement an SER, if that was needed to be, or 13 after the fact still do it under Part 50 14 processes to address their licensing ba sis. 15 With that, I will turn it over to the 16 Applicant, who has the first part. Go ahead.

17 MEMBER SHACK: Can I ask you a generic 18 question. I was looking. You know, they came in 19 with the usual language about PWR internals, and 20 I was trying to remember.

I saw Ginna submitted 21 an inspection plan. Was that approved?

22 MR. HOLIAN: Allen Hiser, I will have 23 address that during

-- or Jim Medoff, if you want 24 to wait for our staff presentation.

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-3701 www.nealrgross.com 12 MEMBER SHACK: Yes.

1 MR. HOLIAN: During our staff 2 presentation, we will address that. I know it 3 has come up recently in the GALL.

4 MEMBER SHACK: Yes. The GALL actually 5 has guidance, and that was the next question, is 6 when were you expecting licensees to actually 7 pick up that GALL guidance and incorporate it in 8 their documents?

9 MR. HOLIAN: Yes. We have been

-- I 10 will address that more in depth in our 11 presentation, but in general, Diablo has come in 12 here, and now there are seven to nine open items.

13 I know the committees have seen us recently 14 taking our time and asking additional questions 15 to get plants that are in

-house up to the 16 significant items of GALL, Rev. 2, which we 17 issued last December.

18 The staff did a kind of an in depth 19 look through the significant items in there, and 20 for the plants in

-house, we th ought it most 21 appropriate, while we have the SERs in process, 22 to ask those additional requests for information, 23 even if they submit it under GALL Rev 1. We just 24 thought it is the right thing to do.

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

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-3701 www.nealrgross.com 13 Utilities have responded well to that.

1 So in general, we have done that, bringing all 2 the plants in

-house up to that. So I will 3 address it in particular on the MRP and internals 4 during our presentation.

5 With that, I will turn it over to Mr.

6 Jim Becker, the site VP for Diablo Canyon.

7 MR. BECKER: Thank you, Mr. Holian.

8 So I am Jim Becker. I am the site Vice President 9 at Diablo Canyon, and on behalf of the STARS and 10 PG&E team, it is our pleasure to be here today.

11 We look forward to a good presentation and some 12 good questions and answers, and that is our 13 purpose here today.

14 I would like to start off with some 15 introductions. As I said, I am Jim Becker, the 16 site Vice President.

17 MR. SHARP: I am Loren Sharp, Senior 18 Director of Technical Services.

19 MR. WRIGHT: Mike Wright, Mechanical 20 Systems Engineer ing Manager.

21 MR. GREBEL: Terry Grebel, License 22 Renewal Project Manager.

23 MR. BECKER: Thank you. And in 24 addition to the folks up here in front of you, we 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 14 have a fairly large contingent that has come out 1 to Washington, D.C., with us, and those are 2 members both of the STARS Center of Business and 3 of our own plant staff, and they have been very 4 instrumental in preparing the application, 5 responding to the requests for information, and 6 will assist us in our presentation and answering 7 questions here today.

8 Our agenda for the day: We are going 9 to start off with Loren and I giving the 10 Subcommittee an overview of the site, our 11 history, major improvements, etcetera, that have 12 occurred at the site.

13 Then Terry Grebel will briefly cover 14 GALL consistency and commitments, and with that 15 complete, we are then going to go into some more 16 detailed presentation about the open items, and 17 those are the items you see in front of you there 18 on the agenda.

19 Then when we are done with that, I 20 will have some brief concluding remarks. So that 21 is the agenda that we have planned for you today.

22 This slide shows a site description, 23 and I thought it would be good for the 24 Subcommittee to review with us some basic facts 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 15 about the site.

1 Diablo Canyon is located on the 2 central California coast. It is about halfway 3 between Los Angeles and San Francisco. What you 4 see here is the coastline at the site. Miranda 5 has highlighted the Diablo Canyon site itself 6 there. 7 There are about 13,000 acres in the 8 Diablo Canyon lands that PG&E now owns, and the 9 boundary for the company owned property is shown 10 as the dark black line there. The closest town 11 of any size is the town of Avila Beach, and 12 Miranda is now highlighting that.

13 That is a quick overview of our 14 location on the central coast of California.

15 DR. BARTON: What is the population of 16 Avila Beach?

17 MR. BECKER: As a resident of Avila 18 Beach, I will tell you that the population is, I 19 believe, three to four thousand people. It has 20 grown a fair amount in recent years into the 21 hillsides outside the direct village.

22 Okay. Moving on to this site 23 description slide, this is an aerial photograph, 24 and I thought it would be worthwhile to review 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 16 the basic layout of the site here.

1 So what you see here are the 2 containment structures, Units 1 and 2. Unit 1 3 lies to the north. They share a common turbine 4 building that you see laid out there in the 5 picture. 6 We take suction at the intake, and the 7 units share a common intake structure, and they 8 also share a common discharge structure that you 9 see in the picture. Of course, we have an 10 administration building.

11 Most of the make

-up water to the plant 12 -- Actually, all the make

-up water to the plant 13 flows through the raw water reservoirs, which are 14 on the hill to the east of the plant, and we 15 recently began dry cast storage operations. So 16 the ISFSI, or interim spent fuel storage 17 installation, pad is just to the south of the raw 18 water reservoirs. We have completed two ISFSI 19 campaigns thus far, one for each unit.

20 Now a brief station description.

So 21 there are two units at Diablo. They share a 22 common operating set of procedures and design.

23 The units are not identical, but they are highly 24 similar. They are both 4 loop Westinghouse units 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 17 with a core rating of 3411 megawatts thermal.

1 PG&E was the architect/engineer for 2 Diablo Canyon. We were assisted in the latter 3 stages of the construction time period by 4 Bechtel, and that got us to the point of an 5 actual operating license.

6 It is a once

-through cooling facility.

7 Each unit has two circ water pumps. At full 8 power, we pump about 1.5 million gallons per 9 minute of ocean water through the condensers and 10 then back out through that common discharge 11 structure that I showed you earlier.

12 Our containments are free standing, as 13 you see on that slide, steel-lined, reinforced 14 concrete buildings. PG&E is the sole owner and 15 operator for Diablo Canyon.

16 I mentioned that the plant is on the 17 central California coast. We are at the southern 18 end of the PG&E electric service territory. We 19 do own and operate the switchyards and the high 20 voltage transmission system. PG&E's service 21 territory extends from the Oregon border down to 22 about 50 miles south of where Diablo Canyon is 23 located. 24 So that competes my overview of the 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 18 facility. 1 MEMBER RAY: Did you say a nything 2 about the California ISO?

3 MR. BECKER: We are subject to

-- Our 4 generation is subject to the jurisdiction and 5 regulation of the California Independent System 6 Operator, as has been the case for a bit over 10 7 years now.

8 MR. SHARP: Thanks, Jim. I am Loren 9 Sharp. I also welcome the opportunity to appear 10 in front of you to talk about license renewal 11 today. I am the Senior Director of Technical 12 Services, and I will discuss some of the STARS 13 Center of Business, plant history and major 14 improvements at Diablo Canyon.

15 Slide 9. So the Center of Business 16 was created to form a format of consistency for 17 the seven PWR plants that are getting ready to 18 apply or have applied for license renewal.

19 Therefore, we are providing a standard 20 application with additional quality stemming from 21 applying our operating experience, lessons 22 learned from the other STARS plants.

23 Diablo Canyon personnel have 24 consistently provided oversight, leadership and 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 19 ownership of the licensing renewal process, as 1 well as the implementation of that process 2 continuing into the future.

3 Slide 10. Unit 1 was issued an 4 operating power license in 1984, with Unit 2 in 5 1985. There was a change to increase power for 6 Unit 1 to 3411, so that both units are 7 essentially equal, and that is one of the reasons 8 why we have a common license renewal application 9 for both units. We have

-- Currently, license 10 expires in 2024 and 2025.

11 Slide 11. 12 DR. BARTON: What is the status of the 13 two plants today? Both at 100 percent power?

14 MR. BECKER: Yes. Bo th units today 15 are at full power.

16 MR. SHARP: For the Slide 11, we have 17 done a number of major improvements. I won't go 18 through the list in total, but I would say we 19 have done significant improvements to make sure 20 we maintain our facility. I will dis cuss just 21 the steam generators and reactor heads that were 22 recently completed to make sure we have the 23 quality of plant that we need as we go into 24 license renewal as well as the continued 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 20 operation of our current license.

1 Now I would like to turn it over to 2 Terry Grebel, our Diablo Canyon License Renewal 3 Project Manager to discuss GALL consistency and 4 some of the commitments made at Diablo Canyon.

5 MR. GREBEL: Thank you, Loren. Good 6 afternoon. My name is Terry Grebel. I am the 7 Diablo Canyon License Renewal Project Manager.

8 My portion of the presentation today covers the 9 highlights of our license renewal application, 10 including the aging management programs, 11 commitments, open items and confirmatory items.

12 Slide 13, please. In preparing our 13 license renewal application, we used the GALL 14 Rev. 1 and NEI 95

-10 Rev. 6 guidance with the 15 goal of making the application as consistent with 16 this guidance as possible.

17 In addition, as Brian talked about 18 earlier, the staff has recently asked several 19 RAIs based on recent operating experience. We 20 have been responding to these RAIs as well.

21 We have a total of 42 aging management 22 programs, 31 of which are existing. Nine are 23 new, and we have two plant specific programs.

24 Our aging evaluations are greater than 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 21 93 percent consistent with GALL Rev 1 (standard 1 notes A through E).

2 We have 64 license renewal 3 commitments, and these commitments are being 4 tracked through our Diablo Canyon commitment 5 tracking system, which implements the guidance of 6 NEI 99-04. 7 Slide 14, please. 8 MEMBER SHACK: There is only 55 9 commitments listed in the SER. Are these new?

10 MR. GREBEL: These reflect the latest 11 updated members' responding to the

-- 12 MEMBER SHACK: RAIs.

13 MR. GREBEL: -- to the open items.

14 MEMBER SHACK: The open items. Okay.

15 Thank you.

16 MR. GREBEL: We have

-- Diablo Canyon 17 SER has eight open items and two confirmatory 18 items. PG&E has submitted responses to all open 19 and confirmatory items. As Brian talked about 20 earlier, the staff is in the process of reviewing 21 these responses.

22 The eight open items will be discussed 23 further by the other members of the Diablo Canyon 24 team. 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 22 MEMBER STETKAR: Terry, I know you are 1 going to discuss the open items. I would like to 2 ask you a couple of questions about confirmatory 3 items, if I could.

4 MR. GREBEL: I was going to jump into 5 that next.

6 MEMBER STETKAR: Oh, were you? Okay, 7 I didn't see a slide. Go on. I'm sorry.

8 MR. GREBEL: The first item dealt with 9 the confirmatory to change our cable testing 10 frequency from 10 years to six years. This 11 aligns it with the GALL Rev 2.

12 The second item dealt with our spent 13 fuel pool leak chase. We have a leak in Unit 2, 14 a minor leak. We have done some inspections of 15 the leak chases, and we have committed to do 16 another inspection.

17 The staff had asked

-- We said we 18 would do that during the period of extended 19 operation. The staff asked that, to be in the 20 one-year prior, the period of extended operation, 21 and we have since made that commitment.

22 MEMBER STETKAR: Now my questions.

23 Start from the back first then. Have you made

-- 24 You have not made any commitments to do any 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 23 inspections, at least from what I have read in 1 the SER, of the Unit 1 spent fuel pool leak 2 chase. 3 Now I recognize you don't have any 4 identified leakage, but you don't have any 5 identified leakage. So are you confident that 6 indeed the Unit 1 spent fuel pool leak chase is 7 open? I don't know how you measure the flow, 8 through drains or whatever

-- that they are 9 indeed open?

10 In other words, what I am concerned 11 about is do you have leakage that you don't know 12 about and haven't confirmed that indeed your 13 monitoring systems are available over on Unit 1?

14 MR. GREBEL: We are prepared to 15 address that. Mike, could you address that 16 question, please?

17 MR. WRIGHT: Sure, Terry. Mike 18 Wright, Engineering.

19 Both units leak chase systems were 20 visually inspected in the 2006

-2007 time frame 21 area, and both units' leak chase valves are 22 opened weekly to verify that we measure the flow, 23 if there is any leakage past the spent fuel pool 24 liners. 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 24 Both units' leak chase systems were 1 verified to be free of boron clogging. There was 2 no evidence of blockage on either unit at that 3 time. 4 MEMBER STETKAR: I know that the 5 amount of leakage on Unit 2 is pretty small, and 6 the amount of leakage, at least what I read on 7 Unit 1, is yet much smaller. But when you open 8 the Unit 1 valves, do you get

-- 9 MR. WRIGHT: You get nothing.

10 MEMBER STETKAR:

-- any flow? 11 MR. WRIGHT: No, sir. When we open 12 the Unit 1 valves on a weekly basis, we get zero 13 flow. 14 MEMBER STETKAR: You know those lines 15 are open? 16 MR. WRIGHT: Yes. We inspected them 17 in 2006 time frame with boroscope.

18 MEMBER STETKAR: With boroscope?

19 Okay. Thanks. That's what I was looking for.

20 On the cables, I know that you have 21 committed

-- With that confirmatory of the six

-22 year testing, you are essentially consistent with 23 GALL Rev 2, I think, with the exception that you 24 are not doing inspections based on event driven 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 25 events. If I recall correctly, just you said 1 that there was no evidence of event driven water 2 accumulation. So I believe you took an exception 3 to that element of the inspection program.

4 I guess my question was: You have had 5 water accumulation in the past, years back. I 6 recognize not in recent years. What was the 7 source of that water, if it wasn't event driven?

8 MR. WRIGHT: I think, in general, I 9 would like to ask my Engineering Manager, Ryan 10 West, to address that question.

11 MR. WEST: Ryan West, Engineering 12 Manager, Diablo Canyon.

13 In the early Nineties, we identified 14 that our pull boxes were full of water resulting 15 in submergence of the cables. The causes that 16 were identified were basically that our pull box 17 drains and sump pumps were not being maintained 18 adequately, resulting in rainwater backing up in 19 th e boxes. 20 MEMBER STETKAR: So it was rainwater?

21 MR. WEST: That is correct. It was 22 rainwater. We have not seen any evidence of 23 groundwater leaking into the pull boxes.

24 MR. WRIGHT: Ryan, could you address 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 26 the inspection frequency?

1 MR. WEST: Yes.

Right now, we have a 2 bi-monthly inspection of the pull boxes looking 3 for evidence of water in the pull boxes. So it 4 is not quite event driven, but during the rainy 5 season we do look in the boxes on a bi

-monthly 6 frequency. We have the ability to defer th ose 7 once we get out of the rainy season and we are 8 not getting rain.

9 MEMBER STETKAR: So in a sense, you do 10 some -- if I understand what you just said, you 11 do inspections more frequently in the rainy 12 season. 13 MR. WEST: That is correct.

14 MEMBER STETKAR:

Okay, thanks. I had 15 one other question on cables, which

-- I have too 16 many notes here. Oh, I just wanted to confirm.

17 Do all of your underground cable ducts, conduit 18 runs -- I don't know what the configuration is 19 there -- including whatever low voltage cables 20 that are now in scope, positively drain to low 21 points where you have sump pumps installed?

22 What I am asking is: Are you 23 confident that you don't have any intermediate 24 low points where water can collect and remain 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 27 stagnant without positively draining to some 1 location that you can either inspect or have an 2 installed sump pump?

3 MR. WEST: So our operating experience 4 has identified that we have some low points in 5 our conduits. Here on Slide 78 is a general 6 layout of our conduit arrangement where there are 7 drains that drain from pull box to pull box to a 8 low point out to a sump area which is drained out 9 to the building sumps.

10 We have identified dips in the pull 11 boxes. We have done

-- We are in the process of 12 completing all of them, but we are do ing 13 inspections of the accessible portions of the 14 underground loops. We are also removing the 15 seals at the buildings, and it is promoting air 16 flow through the conduits, which is also helping 17 to keep the conduits free of water, and we are 18 going back after we have done all the inspections 19 in the locations that were identified as 20 containing water, we will verify that we are not 21 getting any in

-leakage from damage in the 22 conduits. 23 MEMBER STETKAR: Thank you. One last 24 question. In your Generic Letter 2007

-1 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 28 response, you identified a number of cable 1 failures due to water in

-leakage. Now I 2 understand that since then you have replaced, I 3 think it said, all of the in

-scope medium voltage 4 cables. Have you experienced any underground 5 cable failures since 2007, in other words since 6 that report was filed?

7 MR. WEST: We have experienced 8 degradation on underground medium voltage cables 9 that had not been replaced. Of the replaced 10 cables, we have not seen any repeat degradation 11 or failures.

12 MEMBER STETKAR: Thank

s. 13 MEMBER ABDEL

-KHALIK: The degradation 14 that you referred to was measured by, what, the 15 10 delta test?

16 MR. WEST: Seven of the 11 identified 17 degradations or failures were identified by 18 ground alarms. We have a high resistance 19 grounding system. So we have a single phased 20 ground fault. So it was identified, and the 21 equipment was removed from service, and then 22 subsequently we verified through high

-pots that 23 the cable was degraded.

24 MEMBER ABDEL

-KHALIK: Are you sure it 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 29 is cable degradation versus a connection 1 degradation?

2 MR. WEST: Can you clarify that a 3 little bit for me?

4 MEMBER ABDEL

-KHALIK: The connections 5 between cable segments

-- Are you sure that, 6 really, the problem is with the cable segments 7 themselves or with the connections between 8 segm ents? 9 MR. WEST: So we are confident it was 10 the cables themselves. We don't typically have 11 splices in the underground portions of the 12 cables. So we are able to isolate and validate 13 that it is the cable itself.

14 MEMBER ABDEL

-KHALIK: Okay, thank you.

15 MR. SHARP: So, Mike Wright is the 16 next presenter on flux thimble tube.

17 MR. WRIGHT: Thank you, Loren. Good 18 afternoon, Mr. Chairman, Committee members. My 19 name is Mike Wright, Mechanical System 20 Engineering Manager at Diablo Canyon. I have 21 been at the plant for 22 years and in Engineering 22 for the last 10, for 10 years.

23 I will be presenting some background 24 information on a flux thimble tube leak that 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 30 occurred in 2006, a status one open item 1 associated with flux thimbles.

2 Slide 16, please. Unit 2 th imble tube 3 L-13 leaked approximately four months following 4 refueling outage 2R

-13 in 2006. The tube had 5 been in service for a little more than three 6 cycles. This graphic depicts the approximate 7 location of thimble tube L

-13, and the magenta 8 boxed area would be the approximate location.

9 Historically, L

-13 was capped in 1990 10 following refueling outage 2R

-3, remained out of 11 service for over 10 years until it was replaced 12 in 2001 with a tube having a 15

-inch chrome band 13 designed to be centered around the hi ghest wear 14 location, which is the bottom nozzle of the fuel 15 assembly. 16 Slide 17, please. More history: In 17 2004, 2R-12, we measured approximately 47 percent 18 wear outside of the chrome band of this thimble 19 tube, approximately five feet below the bottom 20 nozzle, and the tube was pulled out five inches 21 to relocate the wear spot.

22 Again in 2006, the subsequent outage, 23 2R-13, we measured 44 percent wear in the same 24 thimble tube in a similar location, and the tube 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 31 was pulled out an additional five inches, again 1 to move the wear spot.

2 These two pulls resulted in exposing 3 the non-chrome plated portion of the thimble tube 4 to be bottom nozzle, the higher wear area of the 5 fuel assembly. Approximately four months 6 following 2R

-13, L-13 leaked. The leakage was 7 isolated by closing a valve at the seal cable.

8 Slide 18, please. Now I will address 9 the open item. There are two aspects of the open 10 item, the first being that the Diablo acceptance 11 criteria does not specifically include a value 12 for instrument and wear scar uncertainty. We 13 were asked to verify that we have the appropriate 14 margin to account for them.

15 Resolution: Diablo wear methodology 16 was compared to the Westinghouse industry 17 standard, the WCAP

-12866 or thimble tube eddy 18 current testing using our site sp ecific wear 19 data. The result of that analysis is that Diablo 20 wear projection methodology was slightly more 21 conservative than the WCAP.

22 The Westinghouse war projection 23 methodology acceptance criteria is 80 percent, 24 which does include instrument uncertainty, and 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 32 currently our wear projection methodology or 1 acceptance criteria is 68 percent, which does not 2 include uncertainty.

3 The difference between those two is 4 17.5 percent, more conservative than the 5 Westinghouse industry standard. Typical values 6 used for uncertainty are 10 percent. We believe 7 our 17.5 percent margin from the industry 8 standard represents adequate margin to account 9 for instrument and wear scar uncertainties.

10 As a result of the L

-13 cause 11 analysis, again from cycle 14, we have added 12 additional nonlinear wear acceptance criteria 13 that I will describe in a couple of slides. In 14 total, we believe that the combination of the 68 15 percent wear in addition to the nonlinear 16 acceptance criteria is both conservative and 17 comprehensive.

18 MEMBER STETKAR: Mike, let me just 19 make sure I understand this slide, and from what 20 I read in the SER.

21 You are now proposing a 68 percent 22 wear acceptance criteria, and is that

-- I know, 23 from what I read, you used to have that, and then 24 the WCAP was issued, and it sounded like you had 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 33 increased it to

-- I don't know whether it was 78 1 percent or 80 percent or something like that.

2 As a resolution of the open item, you 3 are now dropping back to the 68 percent. Is that 4 correct? 5 MR. WRIGHT: No, sir. We have had 68 6 percent the entire time. We got the WCAP in the 7 Nineties, which said 80 percent. We did not 8 adopt that number.

9 MEMBER STETKAR: Oh, I guess I 10 misunderstood what I read in the SER, because it 11 sounded like you had increased that limit, and 12 that is what the staff was concerned about, that 13 that 80 percent wear limit did not adequately 14 account for the uncertainties, but you have

-- 15 MR. WRIGHT: We have got the 68 16 percent number. What we did do was remove the 17 uncertainty penalty, and that is the area that we 18 are still working with the staff to -- 19 MEMBER STETKAR: So you are actually 20 still negotiating with the staff over this. It 21 is still an open item.

22 MR. WRIGHT: Still working with the 23 staff to get a resolution.

24 MEMBER STETKAR: Thank you. That 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 34 he lps. 1 MR. WRIGHT: Slide 19, please. The 2 second aspect of the open item requests the 3 additional information on the L

-13 cause 4 evaluation and corrective actions.

5 In 2R14, L

-13 was removed from the 6 plant in 2$14 following eddy current testing 7 examination. There were two high wear locations 8 that were identified greater than 90 percent on 9 the L-13 with eddy current examinations.

10 One was in the highly radioactive 11 region at the bottom nozzle of the fuel assembly, 12 and the other about five feet below the low er 13 core plate in the vicinity of the previously 14 identified wear.

15 When we cut the tube out to remove it 16 from the plant, we inspected both portions, the 17 highly radioactive one by video camera since it 18 was highly radioactive, the other one by touch, 19 by feel. Due to the feel of the tube at the 20 location five feet below the lower core plate, we 21 felt that was the wear or the through

-wall leak, 22 and that is the piece that we sent off to 23 Westinghouse to be examined by destructive 24 testing. 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 35 During that examination by 1 Westinghouse, it was determined that the three

-2 foot section we sent to them did not contain the 3 throughwall leak. However, it did contain the 90 4 percent wear location leak as well as both the 47 5 and 44 percent wear location.

6 The signatures on the ed dy current 7 test of both the 90 percent, the graded 90 8 percent locations, were similar, and the cause of 9 the wear of the tube that we did send to 10 Westinghouse was determined to be flow induced 11 wear. 12 Based on this determination and the 13 similarity of the two 90 percent wear locations 14 of the tube and previous Diablo tube violations 15 that we had sent back to Westinghouse

-- we sent 16 tubes back to them in the early Nineties in the 17 development of the WCAP

-12866 -- the cause was 18 determined to be flow induced wear and plant 19 practices that allowed multiple repositioning of 20 thimble tubes.

21 Repositioning of L

-13 exposed the non

-22 chrome plated portion of the tube to the bottom 23 nozzle, and then we have been doing eddy current 24 testing since 1R3, 2R3, and in all that time f low 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 36 induced wear is the only degradation mechanism 1 found at Diablo. Cracking has not been 2 identified in any of the eddy currents 3 examinations performed.

4 Slide 20, please. In resolution, this 5 is the slide that I referred to previously. The 6 corrective actions to prevent reoccurrence from 7 the root cause evaluation resulted in additional 8 acceptance criteria to address the non

-linear 9 wear. They include: A thimble must be removed 10 from service or repositioned if we experience 11 greater than 25 percent wear per year, or a tube 12 has two wear scars greater than 40 percent.

13 Additionally, a tube may only be 14 repositioned six inches, and they may only be 15 repositioned once. I note that each of

-- 16 MEMBER ABDEL

-KHALIK: If the mechanism 17 is indeed flow induced wear, do you have any idea 18 what the extent of your lower plenum anomaly is?

19 MR. WRIGHT: Well, we detect the 20 degradation through 100 percent eddy current 21 testing. So we know the status of

-- 22 MEMBER ABDEL

-KHALIK; Lower plenum 23 flow anomaly was in the core.

24 MR. WRIGHT: I'd like to get some help 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 37 from Mr. Mark Mayer, please.

1 MR. MAYER: My name is Mark Mayer. I 2 am at the Diablo Canyon staff.

3 We have some information on the lower 4 plenum anomaly, but we do not really see any 5 indications of a strong lower plenum anomaly, and 6 we can get you additional information, if you 7 would like that.

8 MEMBER ABDEL

-KHALIK: And what would 9 be your indications that you are looking for?

10 MR. MAYER: I would have to get back 11 to you on that particular question.

12 MR. SHARP:

The current charts we do 13 have that shows the number of them that are still 14 at that same -- 15 MR. BECKER: Yes. I think that would 16 give you some information about it.

17 MR. WRIGHT: Miranda, if you could 18 move to slide Number 70. Slide 70 depicts the 19 current status of all 58 thimble tubes in both 20 units. It represents that approximately half of 21 the thimble tubes in both units are original, 22 non-chrome plated thimble tubes with minimal wear 23 located in various locations, and the remaining 24 half are locations where we have replaced them 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 38 with either 15

-inch chrome plated thimble tubes 1 or a full 12

-foot chrome plated thimble tube, and 2 then 11 of the tubes, total tubes, are either 3 capped or the guide tube is attached.

4 So the flows vary in the lower portion 5 of the lower internals. Again, essentially we 6 used our eddy current testing to determine the 7 locations where we need to put the hardened 8 outside thimble tubes.

9 I would like to go back to Slide 20, 10 please, Miranda. In addition, the

-- Each of 11 these four acceptance criteria individually would 12 have resulted in removing thimble tube L

-13 from 13 service in 2R13.

14 Since application of these new non

-15 linear acceptance criteria, 31 tubes have been 16 removed from service in the last five refueling 17 outages. Of these 31 tubes, 67 percent were due 18 to this exceeding the non

-linear wear criteria.

19 So the message here is the additional criteria we 20 put in place has been effective in identifying 21 tubes to replace.

22 When we do replace them, we replace 23 them with Westinghouse supplied 12

-foot chrome 24 plated band to cover the entire area in the lower 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 39 head up through the bottom nozzle.

1 Diablo Canyon, again, has not observed 2 any wear in a chrome plated portion of thimble 3 tubes. 4 Slide 21, please. In conclusion, PG&E 5 is confident that the 68 percent acceptance 6 criteria, in combination with the additional non

-7 linear acceptance criteria, is both comprehensive 8 and conservative.

9 MR. SHARP: the next presenter is 10 David Gonzalez, my ISI supervisor at Diablo 11 Canyon. 12 MR. GONZALEZ: Good afternoon. My 13 name is David gonzalez, and I am the ISI 14 Supervisor at Diablo Canyon. Today I am going to 15 discuss the open item addressing the 1997 flaw 16 analysis for Unit 1 piping weld, and the reason 17 that this flaw analysis did not address the 18 stress corrosion cracking.

19 In support of this discussion, I will 20 present PG&E's basis for concluding that this 21 flaw was not service related and, hence, did not 22 need to be analyzed for a stress corrosion 23 cracking flaw growth.

24 Please note that we had previously 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 40 submitted and discussed additional information 1 regarding this open item.

2 MEMBER ARMIJO: This is a stainless 3 steel pipe?

4 MR. GONZALEZ: Yes, and I will discuss 5 the characteristics and the isometric drawing.

6 MEMBER ARMIJO: And what grade of 7 stainless steel is this?

8 MR. GONZALEZ: It is 304, and that 9 will be depicted on the following slide. So 10 first I would like to describe this piping 11 system. Miranda, Slide 24, please.

12 So this line is the residual heat 13 removal system, stainless steel pipe, 12 in ches 14 diameter, and about .4 inches thick. The 15 specific weld I am addressing is identified as 16 WIC-95, and is pipe to tee weld and as shown on 17 this isometric drawing, Miranda is highlighting 18 that location now.

19 It is located in our auxiliary 20 building in ou r 100-foot penetration room. This 21 RHR's line's function is to supply flow to the 22 reactor coolant system, hot legs 1 and 2, in the 23 event it is needed post

-accident.

24 This line would not normally see flow, 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 41 as it is not a standard at

-power or refueling 1 outage alignment. I would only see check valve 2 testing operations, and that is typically one 3 time per outage.

4 A routine ISI

-- ultrasonic 5 examination in 1997 discovered an indication in 6 this weld. The indication was ultrasonically 7 dimensioned as approximately .4 inches long and 8 approximately .2 inches in through

-wall 9 dimension, and it was plotted to be in close 10 proximity to the ID of the pipe.

11 Slide 25, please. This slide is a 12 graphic representation of the pipe to tee 13 configuration and the location of the indication 14 I am discussing.

15 So in answer to your question, sir, 16 the tee is 403 wrought 304 stainless steel. So 17 it a wrought tee, and the pipe is also, as 18 depicted there on the righthand side. That is a 19 12 inch Schedule

-40 stainless steel, also 304, 20 and the weld material would be our ER 308.

21 So the indication we are discussion as 22 at approximately 90 degrees on the pipe side of 23 the tee, on the pipe side of the weld. This 12 24 inch line would eventually tie into the 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 42 containment flow path and into the loop 1 and 2 1 hot legs. 2 So at the time of the indication's 3 discovery, Diablo Canyon's UT level 3s compared 4 the recorded dimensions of this reflector to ASME 5 Section 11 Code acceptance criteria.

6 MEMBER ARMIJO: Now that flaw was not 7 detected during post

-fabrication inspection?

8 MR. GONZALEZ: Actually, there was 9 flaws, and I will discuss that also. There was 10 flaws detected for insufficient penetration 11 during the initial construction radiography, and 12 there was notes that there had been repairs on 13 that weld for insufficient penetration, and that 14 factored into similar confusion regarding the 15 nature of this flaw.

16 So when the dimensions of the 17 reflector were compared to the ASME Section 11 18 Code acceptance criteria, it was found not to be 19 within the standard code table acceptance limit.

20 At this time, supplementary ultrasonic and 21 radiographic examination techniques were applied 22 to attempt to ascertain the size and the nature, 23 the character, of this reflector.

24 Construction period radiographs were 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 43 also reviewed. As I had noted, there had been 1 repairs on this weld during construction for 2 insufficient penetration. However, we were not 3 able to positively match up the RT number belt 4 locations and the repairs to this reflector that 5 we had recently recorded.

6 This information was immediately 7 entered into our corrective action program, and 8 an engineering analytical evaluation, as allowed 9 by ASME code, was performed. This evaluation 10 considered relevant material properties, 11 operating loads, and degradation mechanism s using 12 fatigue as a dominant driver.

13 The result of this assessment was that 14 the weld was suitable for continued service. As 15 part of the evaluation actions, Engineering 16 stipulated a repeat UT examination during the 17 next refueling outage.

18 In 1999, the first follow

-up UT exam 19 was performed, and no flaw growth was measured.

20 This was also entered into our corrective action 21 program. Again, in the next refueling outage in 22 the year 2000, another successive UT exam was 23 performed, and no flaw growth was measu red. 24 Note that ASME Code rules for this 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 44 Class II system would have only required one 1 single follow

-up examination, but we have 2 performed two.

3 MEMBER SHACK: What is the exact UT 4 method you used?

5 MR. GONZALEZ: This was sheer wave

-- 6 At the time of its initial examination, a 7 performance demonstration initiative or PDI, 8 Appendix -- Section 11, Appendix 8, requirements 9 were not in effect. So it was standard appendix 10 3 flaw sizing rules. However, at that time, we 11 used what we considered state of the ar t 12 techniques, which were the Appendix 8 techniques 13 with multiple search units and multiple mode of 14 propagation.

15 Miranda, would you put on Slide 66, 16 please. This is just a graphic representation of 17 some of the UT techniques we applied at that time 18 over a period of a few days, trying to 19 characterize that indication. So we did not rely 20 solely on the specified ASME techniques.

21 We used what we considered state of 22 the art with qualified UT examiners. So you can 23 see, we used 70 sheer waves, 60 degree L

-wa ves, 24 etcetera, focused dual

-element transducers, 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 45 creeping longitudinal waves. We threw everything 1 we had at it, trying to characterize it.

2 MEMBER SHACK: And in the subsequent 3 exams? 4 MR. GONZALEZ: At that time, PDI 5 requirements were in effect. So we used PDI 6 qualified procedures, including PDI qualified 7 examination of personnel. Yes.

8 MEMBER ABDEL

-KHALIK: Is there any 9 vibration monitoring of this line?

10 MR. GONZALEZ: Not to my knowledge. I 11 would expect not, and I would be correct. No, 12 sir. This line, as I noted earlier, would not 13 normally see flow. It would only be used after a 14 post-accident or to flow RHR into loop 1 and 2 15 hot leg, and that is an evolution that would not 16 occur for a number of hours after an accident.

17 MEMBER ARMIJO: So during normal 18 operation then, is that a dead leg? Is there

-- 19 MR. GONZALEZ: During normal 20 operation, that would not see any flow, and 21 actually, that would be at ambient temperatures 22 with no elevated temperatures and no flow and no 23 pressure or minimal pres sure, if any.

24 MEMBER ABDEL

-KHALIK: But during 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 46 periodic testing of the pumps, would this line be 1 vibrating?

2 MR. SHARP: No. During non

-outage 3 situations, we run the RHR pump on recirculation.

4 So it wouldn't see flow, and during outages we 5 mostly flow into the cold legs, not so much the 6 hot legs. So typically, no flow period in those 7 -- in the RHR hot leg line.

8 MR. GONZALEZ: So the fracture 9 mechanics analysis conducted in 1997 considered 10 fatigue as a degradation mechanism. The 11 ultrasonic examination had concluded that this 12 flaw did not have the nature of stress corrosion 13 cracking due to the characteristics of the UT 14 signal envelope and, as had we illustrated, we 15 applied various UT techniques in trying to 16 ascertain the reflector's attributes.

17 So the multiple UT techniques and 18 precisely aligned radiography shots that we 19 employed to characterize this flaw, and in 20 concert with each other, they had concluded the 21 reflector was not stress corrosion cracking.

22 This was a degradation mechanisms that we had 23 reported to Engineering for their flaw analysis 24 was that it was not stress corrosion cracking.

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-3701 www.nealrgross.com 47 The UT exams had plotted the position 1 of this flaw to be at or near the ID of the pipe.

2 The proximity rules for flaw sizing in ASME 3 Section 11 Code required it to be considered 4 surface connected at this point, regardless of 5 whether it had an actual opening to the ID of the 6 pipe or not. So by default, this placed the 7 reject criteria in the more conservative column 8 of a surface connected flaw for Section 11.

9 Due to the configuration of the piping 10 system, however, there was no practical method 11 for examining the ID of the weld to determine if 12 it actually was or was not open to the surface.

13 Slide 23, please.

14 MEMBER SIEBER: This is a low pressure 15 line. Right

? 16 MR. GONZALEZ: It would see maximum 17 RHR pressure, which would be approximately

-- 18 MR. SHARP: In piggyback mode, less 19 than that, 350 pounds, yes.

20 MR. GONZALEZ: So normally, it would 21 not see extreme pressures, yes.

22 MEMBER SIEBER: Right.

23 MR. GONZALEZ: And normally

-- excuse 24 me. It would see a maximum pressure as 350.

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-3701 www.nealrgross.com 48 MEMBER SIEBER: Schedule 4, right?

1 MR. GONZALEZ: That is correct, 12 2 inch diameter, .4 inches thick, and UT 3 measurements actually measure it slightly thicker 4 than .4 inches t hick. 5 So we are back on Slide 23. So a new 6 Engineer analysis has recently been performed on 7 this flaw using both stress corrosion cracking 8 and fatigue as a degradation mechanism. These 9 results continue to find the flaw is currently 10 acceptable.

11 An ISI exam scheduled for the Unit 1 12 refueling outage in 2012 will determine if this 13 indication has experienced any growth. If growth 14 is detected, this information will be immediately 15 entered into our corrective action program system 16 for disposition in accordance with ASME Code 17 requirements.

18 MEMBER ARMIJO: How did you conclude 19 that the -- if the stress corrosion cracking 20 evaluation was acceptable, because of the low 21 temperature of the environment or some other?

22 MR. GONZALEZ: The new engineering 23 analysis, and if we want some detail, I will ask 24 for some assistance on this. But the new 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 49 engineering analysis used the material properties 1 and the time at temperature that this would 2 typically see during a normal operating cycle, 3 and it used those inputs to determi ne what the 4 propagation rate would be for stress corrosion 5 cracking and when we would achieve unacceptable 6 progress. 7 MEMBER ARMIJO: So you had very 8 limited time at temperature.

9 MR. GONZALEZ: That is correct.

10 MEMBER ARMIJO: And you used the crack 11 growth correlation.

12 MR. GONZALEZ: That is correct.

13 MEMBER SHACK: And the crack growth 14 correlation came from what?

15 MR. GONZALEZ: Let me ask Mr. Lee 16 Goyette, who has been very much involved with the 17 fracture mechanics analysis to discuss that.

18 MR. GOYETTE: I am Lee Goyette. I am 19 with PG&E, and we have the calculation done 20 according to

-- by Structural Integrity 21 Associates, and they used the latest criteria 22 that was available in the literature for crack 23 growth rates under stress corrosion crackin g 24 concerns. 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 50 So there is quite a bit of discussion 1 over the crack growth rates that were appropriate 2 in this situation, and

-- 3 MEMBER SHACK: Yes, I can imagine.

4 MR. GOYETTE: Yes. And the fellows 5 that did the analysis sit on the code committees, 6 and they are aware of the latest what is the best 7 stuff to use. So the analysis was done in a 8 conservative way at the high temperature, the 9 highest temperature that we determined the system 10 to be operating at for a limited time during each 11 refueling outage, and we turned out to have 12 acceptable results, and we will look at the 13 indication again during the next outage and 14 confirm. 15 MR. GONZALEZ: So the information that 16 we have gathered indirectly via the ultrasonics, 17 and using the signal envelope characteristi cs 18 that are mentioned, that are noted in the PDI 19 approved procedures are used to determine the 20 nature of the flaw, and a linear rise and fall 21 rate, nonspecular reflection, very uniform 22 positioning of the ultrasonic responses, all tell 23 us that it is not stress corrosion cracking.

24 As I had noted earlier, we have done 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 51 some specifically aligned radiography to look at 1 this flaw. Aside from the construction period 2 radiography, we have done some specifically 3 aligned radiography to see if we could see a flaw 4 there, and we saw nothing, also telling us that 5 it could be nothing but either lack of fusion or 6 lack of penetration.

7 My experience in construction 8 industry, a repair on a weld

-- sometimes they do 9 get the flaw. They do get all the insufficient 10 penetration out or lack of fusion out, and 11 sometimes they will leave a little residual bit 12 of it, but the subsequent radiography will accept 13 it. So it is not uncommon to see a reflector in 14 a previously repaired area.

15 MEMBER ARMIJO: Now you did have 16 instances of IGSEC in your plant early on, 1987, 17 and in your LRA you mentioned some accumulator 18 nozzles, again signature 304 conventional carbon, 19 high carbon. So you detected that by your ISI 20 program? 21 MR. GONZALEZ: Yes, actually, it was 22 spotted visually, and then we had -- WE have 23 implemented a long term program where we 24 ultrasonically examined these accumulator 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 52 nozzles, and we were able to see incipient 1 cracking in these accumulator nozzles.

2 A mechanism there was different.

3 Metallurgy found there was considerabl e 4 contaminants, and we determined that it was due 5 to the original manufacturer.

6 MEMBER ARMIJO: Was that furnace 7 sensitized or heat treated with any other 8 components?

9 MR. GONZALEZ; I believe those nozzles 10 were installed

-- and I will be corrected if I am 11 wrong. Those nozzles had been installed prior to 12 the heat treat of the accumulators, and that was 13 a contributor to their cracking.

14 MEMBER ARMIJO: And what did you 15 replace them with?

16 MR. GONZALEZ: With a partial fillet 17 weld accumulator nozzle. They were bored up.

18 These had been full penetration fillet welds on 19 both sides in the accumulators, and we replaced 20 them with a partial penetration fillet weld, and 21 the material is

-- I am going to have to ask 22 Chris Beard, who is our Materials Engineer, al so 23 of the ISI group.

24 MR. BEARD: Yes. My name is Chris 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 53 Beard. I work for PG&E, and we replaced them 1 with 304 L

-grade stainless steel.

2 MR. GONZALEZ: And our subsequent 3 exams on those accumulator nozzles have not found 4 any repeat incidences of cracking, and it appears 5 we are over the curve where we saw a lot of 6 cracking early on in these accumulator nozzles, 7 but subsequent examinations have found those, and 8 we actually do those early in every outage.

9 MEMBER ARMIJO: Okay. thank you.

10 MR. GONZALEZ:

Non-replaced outage

-- 11 non-replaced nozzles only.

12 MEMBER ARMIJO: Right. You still 13 monitor the non

-replaced. 14 MR. GONZALEZ: That is correct.

15 MEMBER ARMIJO: But you don't have to 16 do it with the 304 L

-grade? 17 MR. GONZALEZ: That is correct.

18 MR. WRIGHT: We monitor them with 19 visual inspection only. Yes, sir?

20 MEMBER ABDEL

-KHALIK: I understand 21 that this pipe is essentially empty during normal 22 operation and refueling.

23 MR. WRIGHT: No, it would remain full.

24 MEMBER ABDEL

-KHALIK: I mean there is 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 54 no flow. Excuse me. So what is the state of 1 stress on this pipe, first under normal 2 conditions when there is no flow, and in the 3 event that flow is started?

4 MR. GONZALEZ: I will have to ask Mr.

5 Goyette to answer that.

6 MR. GOYETTE: Lee Goyette.

Well, the 7 state of stress during normal plant operation 8 would be dead weight and whatever temperature 9 effects, and in a design seismic event. So a 10 very low state of stress, plus pressure.

11 With the system in service, during an 12 accident mode, normal

-- emergency and faulty 13 conditions, it would be at temperature for long 14 term cooling.

15 MEMBER ARMIJO: Do you put in a weld 16 residual stress into your stress analysis when 17 you evaluate for stress corrosion cracking?

18 MR. GOYETTE: Weld residual stress? I 19 think not.

20 MEMBER ARMIJO: That is typically the 21 initiators of stress corrosion cracking compared 22 to dead weight load, but these cracks haven't 23 grown. You have monitored them.

24 MR. GONZALEZ: That is correct. We 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 55 have had two subsequent examinations.

There has 1 been no measurable change in growth

-- in size, 2 excuse me.

3 Continuing on: So the ISI examination 4 that is scheduled for the next refueling outage 5 in 2012 will monitor this flaw for any change in 6 dimensions. If growth is detected, this 7 information will be immediately entered into our 8 corrective action system for disposition in 9 accordance with the current code requirements.

10 If no growth is experienced, this weld 11 will revert to the standard ASME inspection 12 frequency, as specified by the ISI pro gram which 13 will require an examination every 10 years, and 14 examination results from those future inspections 15 will be evaluated against the existing code 16 requirements at those times.

17 So this concludes my presentation on 18 the WIC-95. 19 MR. SHARP: Next pres entation is by 20 Dave Miklush of our License Renewal Project.

21 MR. MIKLUSH: My name is Dave Miklush, 22 and I am a member of the Diablo Canyon License 23 Renewal Team. I will be presenting the open 24 items for the scoping and screening portion of 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 56 our submittal.

1 Slide 27, please. The first open item 2 deals with non

-safety related fluid

-filled piping 3 near safety related systems.

4 In our first series of walkdowns, we 5 missed two things. One was we didn't look hard 6 for rainwater entry at the systems, and the 7 second one was the proximity of low pressure 8 piping near a safety system, specifically in the 9 Turbine Building.

10 So we instituted another set of 11 walkdowns, and found that our HVAC ducting, 12 exhaust ducts from Unit 2's 480V switchgear room 13 had an outlet that was oriented upward that could 14 collect rainwater. So it looked like it might be 15 a problem, but when we inspected it further, we 16 found out there were drain holes inside.

17 However, there was some rusting going on where 18 the water had been collecting.

19 So we have elected to add more drain 20 holes in there. I would point out that we have 21 never had a water problem getting into our 480V 22 switchgear rooms from the ventilation system.

23 The second two items had to do with 24 firewater piping near control pressurization, 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 57 pressurization fan controls. On our first 1 walkdown, we saw this piping. It was low 2 pressure, and it wasn't very close.

3 After the RAI, we went out and 4 recalibrated our walkdown and said, if we could 5 see low pressure piping within line of sight, we 6 will add it into scope, and that resulted in 7 these two items that we added into scope on the 8 control pressurization fans and on the exhaust 9 opening for the 4kV switchgear rooms, which had 10 firewater and domestic water pipes within 50 or 11 60, again line of sight, of the equipment.

12 Slide 28. slide 28 had to do with the 13 electrical pull boxes and whether or not the pull 14 boxes had pressurized piping going through the 15 pull boxes.

16 Now Ryan West earlier talked to you a 17 lot about the configuration of the drainage and 18 the gravity drains and the external sumps, and we 19 have just confirmed here that there are no 20 pressurized sump pump piping returning into the 21 pull box, electrical pull box. So that was a 22 clarification on that one.

23 Slide 29. Slide 29, in another 24 walkdown we found water trapped in the instrument 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 58 air system that was near the exhaust ducting of 1 the fuel handling building supply fans.

2 Although the instrument air system is 3 a very dry system and it is monitored for dew 4 point, we have elected to keep the inlet valve to 5 that water trap closed, because the valve that it 6 supplies is a heating steam valve to the flow 7 handling, and we have never used the system and 8 don't expect to ever use it in the future. So 9 that is how we resolve that one.

10 Slide 30 is a different topic. It is 11 the scope boundary between non

-safety related and 12 safety related instrument air tubing. Again, 13 this is a clarification that our scope boundary 14 extends beyond the safety related to non

-safety 15 related isolation device to the solenoid valve or 16 check valve into the non

-safety related tubing at 17 the first seismic anchor or equivalent seismic 18 anchor. 19 That has been noted on the instrument 20 air system drawings for license renewal scope 21 boundary. That explains to future engineers 22 where the scope boundary ends for the safety 23 related instrument air tubing.

24 Slide 31. This issue had to do with 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 59 the pressure boundary status of the air start 1 compressor unloader line, which connects the air 2 compressor directly to the instrument air 3 receiver. The diesels are air start. Motors air 4 start, air receiver.

5 The line as non

-safety related, very 6 small line, quarter inch in diameter. In the 7 past, it had been evaluated as acceptable as is, 8 meaning if it had failed, the air receiver could 9 still do its duty.

However, in an effort to 10 clean up this design situation, we have rerouted 11 this unloader line upstream into the non

-safety 12 related portion of the system, upstream of the 13 safety related isolation device.

14 That modification work has been 15 completed on Unit 1.

All three diesels are 16 complete. One Unit 2, one diesel is complete, 17 and two more to go, and that will complete in 18 April of this year.

19 Slide 32 is two items concerning 20 buried valves and piping. The first one had to 21 do with copper valves in the makeup water system 22 that are in contact with soil, and the question 23 that was asked is how we aging manage those 24 valves, and our answer is we will be using the 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 60 Buried Pipe and Tank Program to aging manage 1 those copper valves.

2 The second item had to do with the 3 branch line off our raw water reservoir line 4 coming into the plant. There is a branch line 5 that feeds industrial buildings. No safety 6 systems on that branch, and to limit the scope of 7 our license renewal program, we have elected to 8 revise operating procedures to isolate valves to 9 the branch line in case of a branch line leak or 10 the raw water reservoirs are aligned for long 11 term cooling, then we will go out and close those 12 valves to preserve the water supply in the raw 13 water reservoirs.

14 In that way, we have taken that branch 15 line out of scope.

16 DR. BARTON: Do you have cathodic 17 protection on your buried piping?

18 MR. MIKLUSH: There is some cathodic 19 protection on the aux saltwater system. We do 20 not have any on the make

-up water system.

21 DR. BARTON: And what is its 22 availability?

23 MR. MIKLUSH: Its availability is very 24 good. I don't have the exact

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

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-3701 www.nealrgross.com 61 DR. BARTON: What is very good?

1 Ninety, 95 percent?

2 MR. SHARP: Mr. Lee Goyette, could you 3 answer that?

4 MR. GOYETTE: Lee Goyette with PG&E.

5 The availability of cathodic protection is 6 monitored monthly, and it is over 90 percent, 7 according to the NACE standards.

8 MEMBER STETKAR: Before you leave, if 9 you are the cathodic protection person, the 10 staff's inspection report noted that you have 11 recently -- that is the term they used

-- 12 upgraded cathodic protection system. If that is 13 the case, when was that upgrade performed?

14 I understand you are now claiming it 15 is 90 percent available today, but what has it 16 been historically, and if it was indeed impr oved, 17 when were the improvements made?

18 MR. GOYETTE: That is a good question.

19 MEMBER STETKAR: I thought so.

20 MR. MIKLUSH: The cathodic protection 21 system was installed approximately 1995.

22 MEMBER STETKAR: Installed?

23 MR. MIKLUSH: The aux saltwate r 24 system. 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 62 DR. BARTON: The original or the 1 upgrades? 2 MR. MIKLUSH: It was installed on the 3 entire supply system from the intake to the 4 turbine building, including the bypass section, 5 which was new pipe at the time, and the old pipe 6 that remained in service. The old pipe was above 7 the ocean tide level.

8 MEMBER ARMIJO: On this chart about

-- 9 MEMBER STETKAR: Hold on a second. I 10 don't think I got the answer to my question. I 11 heard when it was installed. I asked had it been 12 upgraded at sometime since it was installed, and 13 when was that upgrade performed or was the 14 installation considered an upgrade, going from 15 zero to something?

16 MR. MIKLUSH: When the insulation went 17 in in 1995, that was the upgrade at the cathodic 18 protection system on the aux saltwater system.

19 Now the plant has had other non

-safety related 20 cathodic protection systems in service since the 21 early Eighties, and we have had a surveillance 22 program written for those cathodic protection 23 systems for the entire life of the plant.

24 MEMBER STETKAR: Okay, I guess I will 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 63 wait and ask the staff.

1 MEMBER SHACK: We have a commitment 2 here to install cathodic protection for the ASW 3 discharge piping.

4 MR. MIKLUSH: There is a portion of 5 the discharge pipe from the turbine building to 6 the intake that is in contact with soil that does 7 not have cathodic protection on it, and

-- 8 MEMBER SHACK: So that will be an 9 upgrade when it is installed.

10 MR. MIKLUSH: That will be an upgrade.

11 MEMBER SHACK: And that is going to 12 happen when? Prior to the peri od of extended 13 operation?

14 MR. MIKLUSH: Prior to the period of 15 extended operation. That is right.

16 MEMBER ARMIJO: Now your makeup water 17 system, you said, is not covered by your cathodic 18 protection, or is?

19 MR. MIKLUSH: No, it is not.

20 MEMBER ARMIJO: It is not? Now a 21 copper valve -- I have never heard of such a 22 thing, but there may be. But are these bronze or 23 brass or are they truly copper valves?

24 MR. MIKLUSH: I am not sure of the 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 64 exact alloy that they are made of.

1 MEMBER ARMIJO: Maybe some of your 2 people could say. And are they attached to 3 carbon steel piping, bolted or something like 4 that? 5 MR. MIKLUSH: The piping and the 6 firewater makeup water system is concrete 7 asbestos piping..

8 MEMBER ARMIJO: Concrete?

9 MR. MIKLUSH: Concrete asbestos 10 reinforced.

11 MEMBER ARMIJO: With copper valves 12 attached to that?

13 MR. MIKLUSH: And where

-- Well, most 14 of the valves in the system are carbon steel.

15 There's a few valves that are copper or bronze 16 material, and those were these three valves that 17 were part of the RAI.

18 MEMBER ARMIJO: so you wouldn't have 19 any galvanic corrosion, because these are 20 concrete that they are attached to, because 21 copper and steel

-- 22 MR. MIKLUSH: There is not a piping 23 issue, but there is an issue with the metals that 24 are in the ground. So every valve location, 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 65 there is a question of long term performance. So 1 those will have to be managed in the inspection 2 program. 3 MEMBER STETKAR: Someplace in the SER 4 I read that you have had problems with some 5 leakage in gray cast iron buried piping in the 6 firewater system, and apparently the corrective 7 actions have been to replace the piping with

-- 8 to replace the piping.

9 Do you still have buried gray cast 10 iron firewater piping on site or has all of that 11 been replaced?

12 MR. SHARP: Lee Goyette, could you 13 answer that?

14 MR. GOYETTE: Yes, sir. The majority 15 of the underground firewater piping is asbestos 16 concrete, and the risers that go to the hydrants, 17 those are gray cast

-- 18 MEMBER STETKAR: Okay. So it is only 19 the risers

-- 20 MR. GOYETTE:

-- and they are being 21 replaced with ductile iron.

22 MEMBER STETKAR: They are being 23 replaced? 24 MR. GOYETTE: Yes, sir, they are.

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-3701 www.nealrgross.com 66 MEMBER STETKAR: But you also have PVC 1 piping in the firewater system. Right?

2 MR. GOYETTE: We do have PVC piping in 3 the firewater system. Yes.

4 MEMBER STETKAR: So you said it was 5 concrete. So it is both.

6 MR. GOYETTE: Both.

7 MEMBER STETKAR: Is one a replacement 8 for the other or you use them in different

-- 9 MR. GOYETTE: Don't know. I cannot 10 answer that question.

11 MR. SHARP: I can say that the 12 majority, 95+ percent of the buried pipe in the 13 fire protection system is the asbestos concrete 14 pipe. As Lee said, some of the risers have the 15 cast iron that we are replacing with ductile 16 iron. There are small segments of PVC, but 17 primarily the asbestos

-- ACP pipe. 18 MR. MIKLUSH: That concludes my 19 presentation.

20 MR. SHARP: The next speaker is 21 Michelle Albright.

22 MS. ALBRIGHT: Mr. Chairman and 23 members of the Committee, good afternoon. I am 24 Michelle Albright, and I am part of the Diablo 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 67 Canyon License Renewal Team, and I will be 1 discussing the two open items that we have TLAAs.

2 The first one that I will discuss is 3 on TLAA identification, which consists of two 4 RAIs. Secondly, I will be discussing the o pen 5 item on metal fatigue, which is on nine RAIs.

6 Responses to all of these RAIs have 7 been submitted to the staff. We believe that we 8 have provided adequate responses to address the 9 staff's concerns, but they still are under 10 review. 11 Slide 34, please.

Open item 4.1

-1 is 12 on two topics. The first of these is on the 13 design codes for the reactor coolant pressure 14 boundary valves, and secondly is the managing of 15 the baffle and former bolts.

16 To address the first open item, we 17 reverified that the design cod es for our reactor 18 coolant pressure boundary valves do not require a 19 fatigue or any time dependent analyses, and we 20 clarified it in the response to the staff.

21 Secondly, for the baffle and former 22 bolts, we revised the license renewal application 23 to choose Option III, which is to use an aging 24 management program to manage the potential aging 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 68 of those baffle and former bolts, and that is the 1 Reactor Vessel Internals Program.

2 MEMBER SIEBER: Do we have any 3 evidence of baffle jetting?

4 MR. SHARP: The answer is yes. We 5 have two over the time frame. We did have 6 evidence of baffle jetting, and that has been 7 remedied with modifications performed

-- upflow 8 modifications performed in the last five to 9 eight years.

10 MEMBER SIEBER: And that is replace 11 bolts modification?

12 MR. SHARP: It was to cut some holes 13 in the upper portion of the baffle.

14 MEMBER SIEBER: So you lowered the 15 pressure differential?

16 MR. SHARP: Yes, sir.

17 MEMBER SIEBER: Does that reverse the 18 flow? Does that reverse the baffle flow?

19 MR. SHARP: It does in some cases, 20 yes. Dan Hardesty, could you please come to the 21 microphone and answer that question.

22 MR. HARDESTY: My name is Dan 23 Hardesty, Primary Systems Engineering. In 2R10 24 we performed what is called an upflow mod to the 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 69 internals, lower internals and upper internals of 1 the reactor for Unit 2, and that corrected

-- It 2 lowered the pressure in the inside of the baffles 3 so that it would jet in the opposite direction.

4 Westinghouse designed and performed 5 the modification.

6 MEMBER S IEBER: Did you have fuel 7 damage associated with the baffle flow?

8 MR. HARDESTY: Yes, sir, we did. In 9 the Nineties we had some damage.

10 MEMBER SIEBER: That is why you did 11 the mod, but the mod did not change the bolting.

12 What it did was reverse the fl ow. 13 MR. HARDESTY: That is correct.

14 MEMBER SIEBER: Thank you.

15 MS. ALBRIGHT: Slide 35, please.

16 There are nine RAIs associated with 17 open item 4.3

-1. For the purposes of discussion 18 today, we categorized the resolution of these 19 nine RAIs into four common areas to give you a 20 feel for the types of responses that we had to 21 these RAIs.

22 The first of these areas would be 23 items that required additional information. For 24 example, in our license renewal application we 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 70 provided the conclusions that the repla cement 1 reactor vessel head replacement CRDMs and the 2 replacement CETNAs were good past the period of 3 extended operation. However, we did not provide 4 the actual cumulative usage factor values in the 5 application to demonstrate that.

6 So in response to the RAI we merely 7 provided those CUF values, which showed that we 8 had adequate margin.

9 In the second group we provided 10 clarifying information based on four RAIs that we 11 received. An example here is a clarification for 12 the metal fatigue program. Basically, we 13 clarified that we were going to be using the FSAR 14 number of transients in our metal fatigue 15 program. These are lower numbers than are used 16 in the analyses for the upper and lower core 17 plate. So they are more conservative to count 18 to. 19 In the next group of RAIs, we will be 20 enhancing our current licensing basis.

21 MEMBER STETKAR: Before we go to the 22 enhancement, have you completely updated Table 23 4.3-2 in the license renewal application, because 24 all I have is the table from the original LRA, 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 71 and looking at the responses to some of the RAIs 1 and the numbers in that table, there are a number 2 of instances where I couldn't make numbers add 3 up. 4 So, for example, your example on 5 charging cycle estimates for auxiliary spray 6 during plant cooldown, in the SER it is noted 7 that -- I have to find my notes; bear with me 8 here -- that there would be

-- You are counting 9 two of those events per cooldown, and that 10 resulted in an estimate of 146 occurrences for 11 Unit 1 and 102 occurrences for Unit 2. But if I 12 use the number of cooldown events tabulated at 13 least in the license renewal application for Unit 14 1, I count 176, because there are

-- I'm sorry, 15 174 -- I can't read my own writing

-- because 16 there are 87 cooldown events projected for Unit 17 1, and 63 for Unit 2, which gives me 126.

18 So I am curious how you got 146 and 19 102. Is it a big deal? Are you close to the 20 margin? I am just interested in multiplying X 21 times 2 and being able to understand how that 22 counting is done.

23 MS. ALBRIGHT: I understand. i would 24 like to ask Mr. Chalmer Myer to address that 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 72 question. 1 MR. MYER: This is Chalmer Myer with 2 the Star Center of Business. We are going to 3 need to take it offline and respond later, 4 because it is going to take some review, but we 5 will get you an answer.

6 MEMBER STETKAR: There were some 7 others. In the interest of time, I would 8 encourage you and also the staff when they come 9 up to look at things like consistency. If you 10 are using 2 times X, make sure that X and 2 times 11 X are equivalent numbers. There are a number of 12 those things that I have come across.

13 As I said, in the grand scheme of 14 things, you are well below the margins, but I am 15 talking about consistency, because you are using 16 methods to develop those cycle counts. Thank 17 you. 18 MS. ALBRIGHT: Thank you.

For the 19 next group of RAIs, we will be enhancing our 20 current licensing basis and, namely, this is the 21 FSAR. For example, the staff questioned why our 22 FSAR didn't provide the technical basis for us 23 not counting load

-following transients. While 24 they agreed with the technical basis of why we 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 73 aren't counting them, we didn't have that 1 actually documented in our FSAR. So we will be 2 updating our FSAR, and committed to do so in our 3 response. 4 The last category here is on 5 environmentally

-assisted fatigue. For o ur 6 license renewal application, we performed the 7 environmentally

-assisted fatigue analyses per 8 NUREG/CR-6260 using the locations for an older 9 vintage Westinghouse plant.

10 The staff did question why we did not 11 consider other locations than those originally in 12 our application. After discussions with them, we 13 did agree that it would be

-- that we would 14 commit to review our existing fatigue analyses to 15 determine if the analyses that we performed for 16 environmentally

-assisted fatigue are limiting for 17 the Diablo Canyon reactor cooling environment.

18 Through those evaluations, if we do 19 find more limiting locations, then the most 20 limiting component will be evaluated for 21 environmentally

-assisted fatigue through our 22 metal fatigue program, and we will be doing that 23 prior to the period of extended operation.

24 This concludes the presentation on 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 74 TLAA open items.

1 MEMBER SIEBER: Have you had any 2 issues with control rod drive mechanism tube 3 split pins that hold the tubes in place within 4 the control rod drive?

5 MR. GREBEL: Dan Hardesty, have we had 6 a previous history with split pins? Dan, could 7 you answer that?

8 MR. HARDESTY: Sorry, I didn't catch 9 the question all the way.

10 MEMBER SIEBER: The question is: In 11 your class of plants around the time this plant 12 was built, there was an issue of cracking of 13 split pins that hold the control rod drive 14 mechanism tubes at the top of the core plate into 15 position so that you would not delay the dropping 16 of the control rod during a reactor SCRAM.

17 Have you examined your split pins or 18 have you replaced them?

19 MR. HARDESTY: We replaced our split 20 pins. I believe we have two different 21 replacements at different times, but the last one 22 was in 2R10 when we did the upflow mod. We took 23 advantage at the time and replaced the split pi ns 24 with the new versions.

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-3701 www.nealrgross.com 75 MEMBER SIEBER: And so baffle jettings 1 issue solution is pretty recent?

2 MR. HARDESTY: It was a convenient 3 time to do it, because we had

-- 4 MEMBER SIEBER: So you did split pins 5 -- some split pins and baffle jetting, flow 6 reversal at the same time, same outage?

7 MR. HARDESTY: Yes.

8 CHAIRMAN BLEY: Any other questions?

9 Yes? Go ahead.

10 MEMBER STETKAR: Thank you. A couple 11 of quick ones. You have apparently had some 12 problems out in the intake structure, because it 13 is a pretty harsh environment on the coast there, 14 and I have noted that it was placed into a higher 15 category of attention with the plans for 16 remediation because of deterioration, I guess, in 17 the structural concrete and things like that.

18 According to the SER anyway, it said 19 that the Applicant had developed a repair plan to 20 return the intake structure to A2 inspection 21 status under the maintenance program by 2010, 22 which implies that it should now be in much 23 better shape. Is it?

24 MR. SHARP: I would say

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-3701 www.nealrgross.com 76 preemptive comment, and then I will let David 1 Wong answer.

2 We have indeed done repairs on the 3 intake structure to take it back to a better 4 condition. We had some additional degradations 5 identified as we were making those repairs, and 6 so there has been a little bit of delay. That 7 won't be completed now until this spring in 2011.

8 MEMBER STETKAR: Thanks. One more.

9 Let me just make a note on that. This, again

-- 10 You apparently in Unit 2 during RO

-15 identified 11 -- they are characterized as gaps between the 12 concrete floor and the steel liner in the 13 containment, and apparently you have made a 14 commitment to seal the gaps.

15 The way I read the material, it 16 sounded to me as if there had never been any 17 sealant in the gaps. Is that true?

18 MR. SHARP: Yes. The Diablo Canyon 19 design does not include a moisture barrier 20 component seen in other plants. The concrete 21 runs up to the containment liner at the base of 22 containment.

23 MEMBER STETKAR: A couple of 24 questions. If you have now made the decision to 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 77 seal the gaps, does that mean you are only going 1 to seal the places where you found the gaps or 2 are you going to actually install circumferential 3 moisture barrier?

4 MR. WONG: This is David Wong, Civil 5 Engineering Supervisor. We are intending to seal 6 only the gaps at this time. The concrete is very 7 hard pressed up against the liner. We inspect 8 them every outage. We have a couple of programs 9 that look at that every outage, our Coatings 10 Monitoring Program, and also the Civil 11 Maintenance Rule Program.

12 DR. BARTON:

How do you know you have 13 never had any leakage between the concrete and 14 the liner or there is any corrosion down 15 underneath the floor?

16 MR. WONG: We have never seen any 17 leakage or any signs of degradation of the 18 concrete, any kind of degradation which w ould re-19 collect through the liner as popping and spalling 20 the concrete or cracking it.

21 MEMBER STETKAR: Thanks. I am 22 finished. 23 CHAIRMAN BLEY: Any other questions?

24 DR. BARTON: Yes.

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-3701 www.nealrgross.com 78 CHAIRMAN BLEY: Yes, John?

1 DR. BARTON: The Appendix A, your 2 final safety analysis supplement and also Append 3 B, aging management program, when you talk about 4 your one-time inspection of code Class 1 small 5 bore piping, I don't get what your final 6 commitment is on volumetric testing of socket 7 welds. 8 MR. SHARP: Chris Beard, could you 9 please respond to that?

10 MR. BEARD: Chris Beard. Our final 11 commitment, as responded to in our latest request 12 for additional information, is: Diablo Canyon 13 will volumetrically examine 10 percent with a 14 maximum of 25 welds of each weld type socket and 15 butt welds for ASME Class 1, less than four 16 inches. That is our final commitment.

17 DR. BARTON: Okay. I didn't get that.

18 So I am glad to hear you committed to do that.

19 Also, you have got an opening in 20 containment where you had strain gauges installed 21 for initial structure integrity tests, and those 22 openings are still there on both units. How do I 23 know that you don't have environment gotten into 24 there, and you have got rebar, concrete 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 79 degradation enclosed in your environment?

1 MR. SHA RP: David Wong, could you 2 respond to that?

3 MR. WONG: This is David Wong. These 4 strain gauge boxes

-- Yes, they were originally 5 installed during construction to monitor the 6 strain on the rebar. They are thin gauge 4 x 4 7 by 4 inch in depth thin gauge c arbon steel boxes 8 embedded on the exterior part of the containment 9 structure.

10 They were banded in place after 11 testing. The strain gauge access boxes, which 12 were called openings, are actually covered with 13 plastic covers and sealed around with caulking.

14 Due to the age weathering effects, we 15 have seen some damage. Either the covers are 16 missing or they are broken, and we plan on 17 repairing those thin gauge boxes that we find 18 damaged in our next containment exterior concrete 19 inspections.

20 DR. BARTON: Ho w do you know you 21 haven't had any corrosion since then, since you 22 know that you are really not sealed right now?

23 MR. WONG: We would see signs of the 24 concrete spalling or cracking, which we have not 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 80 seen. 1 CHAIRMAN BLEY: No further questions?

2 Thank you very much for your presentations. I 3 think we will take a break now, and I would ask 4 everybody to be back at 3:15. We will recess 5 now. 6 (Whereupon, the foregoing matter went 7 off the record at 2:57 p.m. and went back on the 8 record at 3:15 p.m.)

9 CHAIRMAN BLEY: The meeting will come 10 back to order, please. Brian, back to you.

11 MR. HOLIAN: Thank you. Sorry.

12 Waiting for the rest of the NRC staff. This is 13 Brian Holian, Director of License Renewal.

14 Our staff did take good notes during 15 some of the questions there. I know Mr. Shack 16 had a question early on about MRP. Let me just So we will be addressing those as part of our 18 staff response to the SER and the open items.

19 Once again, up at the table we have 20 Stan Gardocki. Stan is one of our members from 21 another technical region, DSS, Division of Safety 22 Systems, and he helps out a lot of scoping.

23 You have heard from him before from 24 the floor on this particular plant. We had 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 81 issues with the plant walkdowns, and Stan is here 1 to support our discussi on of that.

2 Bill Holston, a senior engineer in 3 License Renewal, there for the buried piping 4 issues. You have heard him on previous plants.

5 Alan Hiser, a senior level advisor in 6 Division of License Renewal, will be talking to 7 some of the metal fatigue items there, thimble 8 tube issues.

9 Greg Pick, I mentioned, a senior 10 inspector from Region IV, and Nate Ferrer, our 11 Project Manager. With that, I will turn it over 12 to Nate. 13 MR. FERRER: Thanks, Brian. Good 14 afternoon. As Brian said, I am Nate Ferrer.

I 15 am the Project Manager for the Diablo Canyon 16 License Renewal Review, and I am pleased to have 17 the opportunity to present the staff's review, as 18 documented in our Safety Evaluation Report or SER 19 with open items.

20 Before I actually get into the 21 presentation, Allen will address the question 22 that we had earlier on the vessel internals.

23 DR. HISER: I guess, Bill, could you 24 restate the question?

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-3701 www.nealrgross.com 82 MEMBER SHACK: Two things. One, I 1 know Ginna submitted an inspection plan, and I 2 never saw whether you guys accepted it or not.

3 Since MRP 227 is all over GALL, I assume it was 4 finally accepted, but I haven't really seen that.

5 Then just since you now have the 6 guidance, you have presumably got somebody who 7 had one inspected. When are we going to see 8 people coming in with inspection plans rather 9 than, you know, we are going to follow the 10 industry sort of thing that we see standard here.

11 DR. HISER: A number of plants have 12 come in with inspection plans, because they have 13 already entered the extended period of opera tion, 14 and those plans are generally due two years ahead 15 of that time.

16 I am not sure of the status of the 17 Ginna plan, but

-- 18 MEMBER SHACK: Okay, but you have 19 accepted other plans then.

20 DR. HISER: I don't

-- I am not sure 21 that we have accepted any.

There were some 22 plants -- for example, Calvert Cliffs had 23 proposed specific inspections in their initial 24 application, and so they do not have that type of 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 83 commitment and do not owe us a plan.

1 So I will verify the status of Ginna 2 and some of the other plants. I am not aware, 3 though, that we have approved any MRP 227. The 4 SER has not been issued yet, but that will be 5 forthcoming.

6 MEMBER SHACK: Well, GALL

-2, as I read 7 it, it seems to imply that you accept that 8 guidance. GALL

-2 incorporates a lot of 9 information from MRP 227, the recommendations 10 that are in that report, but also some additional 11 items that the staff thinks is necessary for 12 applicants. There is no a GALL section for it.

13 DR. HISER: Yes, that is correct, and 14 after probably the current set of plants, we will 15 expect plants to come in with a GALL consistent 16 program. Once we finalize the SER for MRP 227, 17 we may modify the GALL program to be consistent 18 with the staff positions that come out of that 19 review. Jeff?

20 MR. POEHLER: Jeff Poehle r, Materials 21 Engineer from the Vessel Integrity Branch, 22 Division of Component Integrity.

23 We have not issued an SER or an SE on 24 any of the plant specific reactor vessel 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 84 internals inspection plans. We have accepted for 1 review quite a few of them. I can't tell you the 2 exact number. So it is basically waiting on the 3 SE for MRP 227 Rev 0, which is the basis for all 4 these inspection plans, which is supposed to be 5 issued in the next month or so.

6 DR. HISER: Is that the final SER?

7 MR. POEHLER: Correct.

8 MEMBER SHACK: So soon.

9 DR. HISER: But there will be a point 10 at which the commitment is no longer an 11 acceptable method to demonstrate aging management 12 for vessel internals. That answers my question.

13 Thank you.

14 MEMBER SHACK: That answers my 15 question. Thank you.

16 MR. FERRER: Getting back to the 17 presentation for today, I will begin with an 18 overview of the Diablo Canyon review, and I will 19 keep it brief, since this information was 20 previously discussed by the applicant.

21 We will then follow the basic 22 structure of the SER, covering topics of interest 23 and open items on each section. Greg Pick will 24 be presenting the license renewal regional 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 85 inspection, as Brian mentioned, and we will try 1 not to repeat all of the information that the 2 applicant has presented. We just intend to 3 ensure that you receive adequate information 4 associated with the staff's review and findings, 5 and as always, feel free to ask questions at 6 anytime. 7 This slide just provides the general 8 details of the license renewal application. T he 9 applicant has previously covered all this. So 10 unless there are any questions, I will move on at 11 this time.

12 Staff review teams conducted audits 13 and inspections of the application during the 14 period shown on the slide. I will highlight that 15 issues raised and discussed during the scoping 16 and screening methodology audit led to two LRA 17 amendments related to scoping and screening 18 submitted in the summer of 2010.

19 They provided the applicant's 20 additional scoping and screening evaluations for 21 various plant systems, structures and components.

22 San Gardocki will be covering these topics in 23 more detail during the discussion of Section 2.

24 In preparing the Safety Evaluation 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 86 Report and in addition to the audits and 1 inspections already mentioned, the staff 2 conducted in depth technical reviews. We issued 3 approximately 200 Requests for Additional 4 Information to which the applicant responded.

5 The SER was issued to the applicant on 6 January 10, 2011, and contains eight open items 7 and two confirmatory items. The fi rst three open 8 items relate to scoping and screening, which Stan 9 will cover in his discussion of Section 2.

10 Two open items relate to aging 11 management programs. Allen Hiser will cover one, 12 and Bill Holston will be covering the other in 13 discussion of Section 3. The last three open 14 items relate to time limited aging analyses, and 15 Allen Hiser will be covering those in our 16 discussion of Section 4.

17 Two confirmatory items also relate to 18 aging management programs, and again we will 19 cover those in Section 3.

20 CHAIRMAN BLEY: Have you had time to 21 review the responses to these issues?

22 MR. FERRER: We have.

23 CHAIRMAN BLEY: So that is included?

24 MR. FERRER: Yes. We will be 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 87 discussing those once we get into more detail on 1 each one. 2 Moving on to Section 2 of the SER.

3 This section concerns structures and components 4 subject to aging management review. The staff 5 has completed its review of scoping and screening 6 methodology and results, with the exception of 7 the open items mentioned earlier.

8 I will now hand it over to Stan 9 Gardocki to discuss the open items and other 10 items of interest from this section.

11 MR. GARDOCKI: Good afternoon. Stan 12 Gardocki. I work in the Balance of Plant 13 Section, Division of Safety Systems, as Senior 14 Reactor System Engineer. I have been involved 15 with the scoping of the plants, and I was on site 16 with the audit conducted in March.

17 The staff reviewed the applicant's 18 scoping and screening methodology and 19 implementation utilizing the resources in the 20 application, the drawings, and the staff 21 augmented that with a physical walkdown of the 22 plant systems during the scoping and screening 23 audit done in March of 2010.

24 During the on

-site audit, the staff 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 88 walked down selected non

-safety areas where the 1 plant people identified where the applicant said 2 there was no or limited safety related 3 components. The staff focused mainly on non

-4 safety related Turbine Building to verify whether 5 there was any additional safety related 6 components in this area.

7 The staff also walked down the safety 8 related areas, mainly the emergency diesel 9 generator rooms, the component cooling heat 10 exchanger room, and the auxiliary building, to 11 verify whether there were any unidentified non

-12 safety related components in these areas that 13 could potentially adversely affect the safety 14 related components.

15 The staff identified several instances 16 where the applicant's scoping of these components 17 did not align with the proposed methodology.

18 In the non

-safety related Turbine 19 Building, the staff identified additional safety 20 related components that did not have an adequate 21 evaluation or 10 CFR 54.4(a)(2) for potential 22 adverse effects from the failure of nearby non

-23 safety related components.

24 The additional safety related 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 89 components identified in the Turbine Building 1 included control room pressurization system and 2 exhaust ducts for the switchgear HVAC system.

3 Additionally, the staff looked at the safety 4 related cables in the Turbine Building where the 5 applicant credited its mitigation of the conduit, 6 but that was only for the low and medium line 7 breaks, but they didn't evaluate for high energy 8 line breaks.

9 In the safety related areas, the staff 10 identified additional non

-safety related 11 components in the vicinity of the safety related 12 components that did not have an adequate (a)(2) 13 evaluation. Some of these examples were inside 14 the Diesel Room and the component cooling heat 15 exchanger room. There were overhead drain lines, 16 and there was additional service water lines in 17 the diesel room.

18 Outside in the yard there were 19 underground vaults and electric pull boxes, which 20 the staff identified sumps and pumps that didn't 21 have an adequate (a)(2) evaluation.

22 In the auxiliary building there was 23 water traps and compressed air system near safety 24 related components. The staff also identifi ed 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 90 instances where the applicant did not include 1 into scope non

-safety related piping that was 2 directly attached to safety related components 3 past the safety/non

-safety related boundary up to 4 the first qualified anchor and, as the applicant 5 said, these were mostly in suppressed gas systems 6 to clean the air, and the nitrogen systems.

7 The staff also identified instances 8 where the applicant stopped its (a)(1) scoping at 9 the code class break on safety related piping at 10 an open valve. The failure of the downs tream 11 piping could result in loss of the pressure 12 boundary of the safety related system.

13 One instance of this that was 14 mentioned is the EDG air start system where the 15 unloader line transitted back from the safety 16 related air receiver back to the non

-safe ty 17 related air compressor.

18 After the site out was completed in 19 March of 2010, the staff issued about 17 RAIs to 20 the applicant. The applicant's preliminary 21 response indicated that additional systems 22 components, especially in the Turbine Building, 23 would have to be added to the scope of license 24 renewal. As Nate said, there were two responses, 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 91 LER and maintenance.

1 Later, the applicant submitted the 2 changes to the application to include these 3 components in the scope of license renewal, and 4 after reviewing the additional material, the 5 staff was able to resolve all the issues except 6 for three open items identified in the SER.

7 The staff has received the applicant's 8 responses to these open items on January 12, 9 2011. The applicant has already described thei r 10 proposed resolutions. In conclusion, the staff 11 has reviewed those and their responses, and has 12 now the necessary information from the applicant 13 to satisfactorily resolve these three open items 14 in the final safety evaluation.

15 Do you have any questions on this 16 matter? 17 CHAIRMAN BLEY: I am just curious.

18 When staff does the walkdown you describe, would 19 you consider it a spot check or would you 20 consider it a thorough walkdown?

21 MR. GARDOCKI: We systematically look 22 at the application, look at areas of interest.

23 In this particular application, we looked at they 24 excluded the Turbine Building, and they said 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 92 there was nothing safety related in there. so we 1 would focus on something like that.

2 We always walkdown general areas where 3 we find deficiencies in the application, EDG 4 rooms, and we identified some

-- 5 CHAIRMAN BLEY: So the areas that drew 6 your interest, you did a pretty thorough 7 walkdown? 8 MR. GARDOCKI: Oh, absolutely, and you 9 can tell from the level of detail that we 10 identified quite a significant amount of 11 components.

12 DR. BARTON: What is your assessment 13 of the material condition of the parts of the 14 plant that you looked at in detail?

15 MR. GARDOCKI: The material condition 16 was very good. We walked down the aux building, 17 turbine buildings, and everything had a good coat 18 of paint. We didn't see any spalling or dirt 19 conditions. There were some areas we tried to 20 get around in the aux building to the back of the 21 containment to look at some penetrations, and we 22 just couldn't get to it. So

-- 23 MEMBER ARMIJO: In the SER there was a 24 mention of a removal of cracked coating on the 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 93 liner, and it is a small area, but apparently 1 about two square feet were not re

-coated after 2 this repair. I just wondered what the logic was 3 for that. Are you familiar with that?

4 MR. GARDOCKI: I cannot address that 5 matter. 6 MEMBER ARMIJO: Maybe the

-- I will 7 read it to you: Defect areas were cleaned and 8 coated at the end of cycle 15, 1R15 and 2R15, 9 total of three square foot cluster; liner plate 10 coatings was found cracked and delaminated at the 11 185 foot and 195 foot elevations. The loose 12 coatings were removed without repair. Two square 13 feet of the three square foot area were left as 14 bare steel after cleaning. This area will 15 require continuous monitoring.

16 I agree with all of that, and I know 17 it is a small area, but I don't understand the 18 logic of not repairing it.

19 DR. HISER: I am not sure that we can 20 address why they didn't repair it.

21 MEMBER ARMIJO: Why does the staff 22 think that is okay?

23 DR. HISER: Well, from our 24 perspective, as long as they ensure that it 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 94 doesn't degrade, then we are

-- As long as there 1 is aging management program in place to address 2 that and to monitor that, then I think we are 3 satisfied.

4 CHAIRMAN BLEY: I think Diablo Canyon 5 wanted to say something.

6 MEMBER ARMIJO: Does the applicant 7 have a response?

8 MR. WRIGHT: I will start off. This 9 is Mike Wright from Diablo. We do have an aging 10 management program for containment coatings.

11 There are

-- Part of that program is to identif y 12 all degraded coatings at the start of the outage, 13 and we have remedied as much as possible during 14 that refueling outage, and then we identify 15 coatings that would have to be subsequently re

-16 coated in the following outage.

17 So that will be a remedy. It j ust 18 wasn't fixed at

-- 19 MEMBER ARMIJO: So it was just an 20 interim problem?

21 MR. WRIGHT: Yes, sir, that is 22 correct. 23 MEMBER ARMIJO: Oh, okay. I just 24 thought it was some experiment you were running 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 95 or something else, and up at that elevation it 1 may not be the most convenient place to repair 2 it. I don't know. Okay, you answered my 3 question. 4 MEMBER STETKAR: Staff, in the SER 5 there are statements like "the applicant applied 6 its evaluation of non

-safety related SCs 7 inconsistently throughout the LRA." Quite 8 honestly, there are more RAIs issued and more 9 applicant responses to those RAIs regarding 10 scoping and screening than I have seen in the 11 last two or three years of license renewal 12 applications.

13 Since your walkdowns

-- As you said, 14 the areas that you walk down are pretty thorough, 15 and those resulted in rather extensive RAIs that 16 were focused on the areas you looked at. But 17 since there are only selected areas, how do we 18 have confidence in the areas that you didn't 19 walkdown, that there aren't similar k ind of 20 scoping and screening issues; and when you found 21 the relatively large number of issues, at least 22 by counting RAIs and looking at the responses to 23 those RAIs

-- for example, in the Turbine 24 Building -- did you make any conscious effort to 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 96 expand the scope of your samples and audits and 1 walkdowns to inspect other areas to see whether 2 or not it simply was focused out in the Turbine 3 Building and that the scoping and screening of 4 (a)(2) type issues in other parts of the plant 5 had, in fact, been done?

6 MR. GARDOCKI: Okay, I will try it.

7 We looked for

-- like if you got the aux 8 building, they say everything in the aux building 9 is in scope of license renewal.

10 MEMBER STETKAR: Okay, that is pretty 11 easy. 12 MR. GARDOCKI: So that was a pretty 13 easy area. So we go in there, and we walkdown 14 something just to make sure scoping values were 15 correct. We were trying to find some 16 penetrations of the makeup water system going 17 through there. We are limited to the 18 radiological areas, and we couldn't access 19 anymore than we could.

20 There was an area between

-- Now the 21 areas that stand out is what we have tried to 22 focus on in this very limited time we were out 23 there, and between the aux building and Turbine 24 Building there is another building in between it.

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-3701 www.nealrgross.com 97 So we asked them, do you classify it 1 as the aux building or do you classify it as the 2 Turbine Building? So those are the areas we kind 3 of focus on and try to clarify that area: Do you 4 classify it as aux building? Everything in 5 scope. For the Turbine Building, nothing in 6 scope. 7 Then we refocus our review when we get 8 back to the office to see if there is anything in 9 that area that has particular interest. So we 10 follow to the main steam piping out there. We 11 asked some RAIs to clarify the boundaries on 12 those. 13 The Turbine Building, when they said 14 they excluded it initially, I mean, we focused 15 right on that area to see if there was anything 16 else in that area, and we found some safety 17 related in there. And if you didn't scope it 18 initially, you don't have any basis t o evaluate 19 to. So we had to wait for that additional 20 scoping to come in.

21 Then we focused on the particular 22 lines they called conduit with safety related.

23 They said, well, we use the conduit for 24 mitigation, but then you didn't use it for all 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 98 mitigations. So then you had to scope the entire 1 Turbine Building for high pressure piping.

2 So there was a very substantial amount 3 of additional components put in scope after our 4 audit. So we focused our audits mainly on areas 5 where we would think we would find some problems, 6 based on previous audits where we find problems.

7 Then those areas that stand out, like here the 8 Turbine Building or that building between the aux 9 buildings, or if they have main steam piping and 10 feedwater piping that is routed outside of the 11 aux building to go into containment, we would 12 walk those particular areas down to see how they 13 are managed for aging management, or in scope.

14 MR. HOLIAN: This is Brian Holian. I 15 wanted to add to the question maybe and the 16 answer. On the question, it is a question we ask 17 during review, branch chief review and senior 18 management review of the SER for that purpose.

19 Staff -- We are still pushing the 20 staff. But when you ask an RAI on an item, get 21 that right, but ask the Part B to the RAI, which 22 is: We found this one or think we found this 23 one; give us some assurance that you have sampled 24 other areas or you have gone there.

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-3701 www.nealrgross.com 99 I think we are pretty good on doing 1 that in RAIs. Sometimes we don't also translate 2 that to the SER write

-up that says that we kin d 3 of asked that second part of the question or 4 during discussions, it had that.

5 So I don't see it all the time in the 6 SER write-up that we are asking the extent of 7 condition question of them to also do that. Stan 8 and -- you know, even in the past week sitting in 9 here, as I have looked back this year

-- kind of 10 reiterated that some of those items

-- you know, 11 the very specific ones, caused other issues to be 12 found by them as part of that extended condition.

13 So a lot of the detail items came out 14 of that type of questioning, but I agree with you 15 that the staff can be even more overt in 16 translating it into the SER. I have told them to 17 tell the story a bit better about what did you 18 find, and then what did the applicant have to do.

19 MEMBER STETKAR: That helps. Thanks, 20 Brian, because the way I read the SER is there 21 was a large number of individually identified, as 22 you said, focused items, a large number of which 23 were resolved by very focused responses of a 24 handful or whatever, which are still being 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 100 discussed, and then there is the overall 1 conclusion that says, with the exception of this 2 handful, everything is fine.

3 MR. HOLIAN: That is right, and it 4 leaves out the in between. Why did the staff 5 have a good feeling that we didn't need to go do 6 a second audit. But we ask ourselves those 7 questions.

8 MEMBER STETKAR: Thank you.

9 DR. BARTON: Along those same lines, 10 in the SER it talks about the external surface 11 monitoring program, and the inspection team noted 12 that the training program for the personnel 13 performing these inspections did not meet the 14 commitment the applicant made for training. So I 15 wonder if the people that the applicant had out 16 there doing external surfaces monitoring weren't 17 probably trained.

18 How was this ever resolved? Did these 19 guys get requalified? Did you guys go look at 20 that? 21 MR. PICK: As an inspection team, 22 during our interviews the system engineers and 23 the people doing aging management

-- they had a 24 lot of criteria for what was aging management, 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 101 but they weren't comfortable that they had enough 1 background. They were using common sense and 2 their procedures, which were quite good, and they 3 all commented to the external surfaces program 4 reviewer that they would like more training.

5 When we brought that to the 6 applicant's attention, they went and did their 7 own survey, and I will let them respond to what 8 they found.

9 MR. WRIGHT: This is Mike Wright from 10 Diablo. We agreed with the Region IV inspection 11 team. We have committed to doing extensive 12 training for all system engineers prior to the 13 December of this year to close the gap on 14 training, and for sustainability, include that 15 training as part of the qualification for system 16 engineers.

17 DR. BARTON: Thank you.

18 MR. GARDOCKI: Well, if there's no 19 more further questions, that concludes my 20 presentation.

21 MR. FERRER: Thank you, Stan. I would 22 like to highlight just one item on open item 23 2.3.3.14-1. The topic of this item actually 24 became an inspection finding, as documented in an 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 102 inspection report dated September 9, 2010.

1 I just highlight that, because just to 2 show sometimes when we are doing the license 3 renewal reviews, we find things that we can pass 4 on to regional staff or residents in current 5 operating space.

6 With that, I would pass it on to Greg 7 Pick from Region IV.

8 MR. PICK: Thanks, Nate. Good 9 afternoon, members of the ACRS Committee.

10 I led the inspection team, and we 11 conducted an extensive review using one of our 12 most experienced teams. The six inspectors 13 shared 170 years of inspection experience. We 14 looked at 60 percent of the aging management 15 programs, instead of the nominal 40 to 50 16 percent. 17 We reviewed 24 of the 40 aging 18 management programs that were in existence at 19 that time, and this included six of the nine new 20 aging management programs.

21 We evaluated whether the applicant 22 properly scoped non

-safety related structures, 23 systems and components that could affect safety 24 related structures, systems and components, and 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 103 whether they developed aging management programs 1 consistent with the GALL report.

2 We focused on the conditions that 3 existed at the plant and how the applicant 4 implemented their existing programs that were 5 going to be aging management programs, and their 6 plans for implementing their new aging management 7 programs. 8 We also performed a vert ical slice 9 evaluation of three systems to assess whether the 10 identified aging management programs could be 11 expected to effectively manage the effects of 12 aging. 13 We also looked at the applicant's 14 treatment of latest industry aging issues and 15 several site specific issues. Next slide.

16 During our reviews, we looked at the 17 conditions of the structures, systems and 18 components needed to withstand a seismic event.

19 These included the supports and restraints, the 20 applicant's program for evaluating the effects of 21 non-safety related equipment affecting safety 22 related equipment and their Class 2 equipment, an 23 the structural inspector also considered the 24 seismic design in his review of the walls

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-3701 www.nealrgross.com 104 design information.

1 We looked at the buried pipe program 2 with a focus on environmental monitoring. We 3 looked at inaccessible medium voltage cables, 4 because the plant had documented aging experience 5 problems with those cables, and we looked at 6 their metal enclosed bus program because they had 7 experienced bus part failures in their past.

8 Next slide.

9 Related to scoping, when we arrived on 10 site the applicant was in the process of 11 incorporating lessons learned related to scoping 12 from a previous STARS plant, similar to the 13 scoping team.

14 IN addition, I had talked with Stan in 15 detail prior to going to the site to see how I 16 might assist him in getting eyes on some of the 17 requests for additional information responses and 18 verify the information being provided.

19 The items that we assisted 20 headquarters reviewers in resolving included: We 21 verified the configuration of non

-safety related 22 service water cooling piping that went into the 23 room; we verified that no safety related electric 24 cables were present in the oily waste sump room.

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-3701 www.nealrgross.com 105 We verified that the water spray from 1 a service cooling water pump in the Turbine 2 Building would not have affected the control room 3 pressurization system components. We verified 4 the physical configurations reflected in their 5 Turbine Building reviews, that in fact the cables 6 were in conduits, the safety related cables for 7 the high energy line break.

8 During our vertical slice review of 9 the compressed air system, we identified examples 10 of items that had not been considered for aging 11 management.

12 The unloader valves for the diesel 13 generator air compressors

-- they were made of 14 two materials, stainless steel and copper, and we 15 asked how they monitored for aging effects.

16 Well, they did, in fact. They have a five

-year 17 PM, and they have a line item to look for 18 evidence of corrosion when they do that five-year 19 PM. But they had not included it in their 20 evaluation in their license renewal application.

21 So they updated that.

22 The other one was they had flexible 23 hoses attached to their back

-up nitrogen bottles.

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-3701 www.nealrgross.com 106 drawings when, in fact, it was flexible hoses, 1 and they put that in a 10

-year PM. 2 In regard to the aging management 3 programs, we already discussed that training was 4 required for the system engineers. We also 5 discussed the one instance related to ag e related 6 degradation of the silicon seal for the abandoned 7 containment screening stage cover plate, which 8 allowed rain to enter the metal box.

9 We identified this through review of 10 test reports where they did a containment 11 integrated leak rate test in the inspections.

12 They took photographs of the abnormal conditions 13 and had it included as part of the report. So we 14 asked, what are you doing as far as aging 15 management of this, and they have agreed to 16 monitor it, seal them, and then eventually 17 perform a plant modification to seal the metal 18 boxes. 19 For the inaccessible medium voltage 20 cables in the cable vaults, they were routed on 21 supports. They didn't have any criteria when we 22 were on site for looking at the support 23 structures for the cables. So they i ssued a 24 corrective action document to add that to their 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 107 structures monitoring program anytime the vaults 1 are opened.

2 MEMBER STETKAR: Greg, when you did 3 the inspection

-- I don't have my notes here 4 complete -- did you actually look in some of 5 those? 6 MR. PICK: We did not look in the 7 vaults. 8 MEMBER STETKAR: Didn't look in any of 9 them? 10 MR. PICK: But we gave the residents 11 criteria, and they agreed to look in the vaults.

12 MEMBER STETKAR: But you didn't 13 actually? 14 MR. PICK: But we did not put eyes on 15 them, no. 16 MEMBER ABDEL

-KHALIk: What is the span 17 over which the cables were supported?

18 MR. PICK: It appeared to be about 19 four feet. I am not sure. But the droop based 20 on the span couldn't be anymore than 12 inches.

21 The electrical inspector determined that.

22 The last one, the location selected 23 for fouling: For the closed cooling water 24 inspection criteria, they selected two valves to 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 108 look for fouling, because we already had a PM 1 when they opened it.

2 We asked the question, is that a low 3 flow area, because when you read all their 4 experience, they were about closing in the low 5 flow areas. They wrote a notification, took a 6 look, discovered it is not a low flow area. So 7 they are looking for alternate locations as a 8 result of it being in their corrective action 9 program. 10 We also found a couple of minor 11 procedure issues. With their heat exchanger 12 program, right now Generic Letter 13 allows you 13 to do maintenance and did not require heat 14 exchanger testing, but their license renewal 15 application said we will do heat exchanger 16 testing. 17 Their procedure said it was prudent.

18 Well, the fixes are going to take out the option 19 of it being a prudent test, and it is now a 20 required test.

21 The second one was they do predictive 22 maintenance thermography of the ir metal enclosed 23 bus stops. Well, predictive maintenance isn't 24 required. It is something that they do, but 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 109 again the license renewal application said we 1 will do this as our way of monitoring aging. So 2 they now have to keep them as records. They are 3 required, versus being an option of keeping those 4 records. 5 DR. BARTON: Don't most people do that 6 anyhow? 7 MR.PICK: They do the thermography for 8 other plants. I can't answer whether they keep 9 them as quality records. That is why it is 10 minor. They might keep the record, but they are 11 not required to.

12 DR. BARTON: I got you.

13 MR. PICK: Next slide. Overall, we 14 also found that the plant had good material 15 condition. We would go in one of the diesel fuel 16 vaults. Didn't find any issues with that.

17 The applicant had developed procedures 18 for many programs, and it had initiated plans to 19 incorporate aging management evaluations into 20 their day to day activities.

21 They are developing a long term plan 22 that looks to be implemented over the next 23 several years. By the time they get to the 24 period of extended operations, it will just be 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 110 part of their routine way of doing business, and 1 the procedures were drafted when we were there.

2 So as inspectors, we had lots of information to 3 review where we could make dec isions and comment 4 on whether we thought it would do

-- the 5 procedure would accomplish what was expected of 6 it. 7 They already identified that they had 8 replaced several major components, and 9 essentially resets the clock on aging. And you 10 already discussed the intake structure. They 11 also replaced some high voltage insulators on 12 their station blackout lines. Yes, sir?

13 MEMBER SIEBER: What was the reason 14 that they replaced insulators? Was it

-- Some 15 insulators have manufacturing

-- 16 MR. PICK: I do not

-- It may have 17 been cracking, but I do not recall.

18 MEMBER SIEBER: Another thing is that 19 plants that are located at salt water collect 20 salt on the insulators.

21 MR. PICK: I know they do. They do 22 spray on their insulators, but I believe they

-- 23 MEMBER SIEBER: I would sure like to 24 know what steps you go through periodically to 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 111 make sure the insulators are not building up salt 1 and capable of flashovers.

2 MR. GORYANCE: My name is Joe 3 Goryance, Diablo Canyon License Renewal, 5R kV, 4 230 kV system engineer and supervisor.

5 Our program is based on General Order 6 95, which is a California order. We have to, by 7 California law, inspect our insulators. Based on 8 our local climate, we have

-- We are at a high 9 salt spray area, being close to the ocean, high 10 winds. So we have an inspection program for 11 that. 12 For our 5R kV insulators, we do a hot 13 wash every six weeks. Based on rainfall, we can 14 defer that if we get one inch of rain in a 24

-15 hour period. So that is our program.

16 During the inspection part, we noticed 17 that we started having some rust. The 18 galvanizing on porcelain insulators was starting 19 to show signs of rust. So then we replaced that 20 string of insulators on the 5R kV system, and our 21 230 kVs also have been replaced.

22 MEMBER SIEBER: Thank you

. 23 MEMBER ABDEL

-KHALIK: You mentioned 24 you do hot wash on the 500 kV, and that is what I 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 112 read in the report. I didn't hear anything about 1 hot washing the 230 kV. Do you do that?

2 MR. GORYANCE: Our 230 kV are polymer 3 insulators. They are not porcelain. So we can't 4 wash those. The polymer types have a better 5 creepage distance. So they are not required.

6 MEMBER ABDEL

-KHALIK: Thanks.

7 MR. PICK: Thank you. The scoping of 8 -- Our overall conclusions from the inspection:

9 The scoping of non

-safety structures, systems and 10 components and the application of the aging 11 management programs to those structures, systems 12 and components were acceptable.

13 Applicant personnel had incorporated 14 actions to manage their aging effects into their 15 programs, and reasonable assurance exists that 16 aging effects will be managed and intended 17 functions maintained.

18 With that, I am going to turn this 19 back over to Nate, unless there are any 20 additional questions.

21 MEMBER STETKAR: Yes, Greg. Since I 22 beat up the applicant, I might as well beat you 23 up. The inspection report says the team 24 determined that the applicant had recently 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 113 upgraded the cathodic protection system and 1 programs. 2 Words like recently always send a flag 3 forme, especially because your inspection was 4 done in 2010. What does that phrase mean, since 5 you guys did the inspection? Was the recent 6 upgrade the actual 1995 installation, 15 years 7 before you did the inspection?

8 MR. PICK: I do not know the exact 9 time frame reflected in that phrase.

10 MEMBER STETKAR: You want to ask 11 Diablo. You heard the answer that, well, they 12 installed it in 1995, and its current reliability 13 is 90 percent or better or whatever the 14 requirements are. But this seems to imply that 15 the inspection team discovered something that had 16 been done, quote, "recently," which implies that, 17 before recently, whenever that was, it wasn't so 18 good. 19 DR. BARTON: Depends what you timing 20 is. Is 15 years recent?

21 MEMBER STETKAR: Yes, recent in 22 geologic time perhaps.

23 MR. HOLIAN: Bill, do you want to 24 an swer? 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 114 MR. HOLSTON: Yes. I was just waiting 1 for the discussion. Yes, the applicant had noted 2 corrosion in their aux salt water system that was 3 down in the lower basin. So in that mid

-late 4 Nineties, they bypassed a whole lot of that 5 piping, put new piping in, upgraded the cathodic 6 protection system to ensure that they would 7 protect the newly installed piping.

8 There were some other modifications, 9 too. They had some corrosion of diesel fuel 10 piping. Now instead of cathodically protecting 11 that, they replaced that diesel fuel piping and 12 ran it in underground vaults. So now it is 13 exposed to air. So that is what they have done.

14 Currently, their cathodic protection 15 system is available greater than 90 percent of 16 the time. They conduct annual NACE testing to 17 ensure that the system is effective by measuring 18 the pipe-to-soil potentials.

19 MEMBER STETKAR: Right. I read and 20 heard, and I understand all of that. The 21 question, I guess, then is still: Is 1995 the 22 recent upgrade, and indeed has the cathodic 23 protection system, if that is the recent upgrade, 24 been available 90 percent of the time or better 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 115 since 1995 then?

1 MR. HOLSTON: That is my 2 understanding. Yes, sir. And that is from 3 talking to the applicant, working through the 4 request for additional information. I am not 5 aware of any period of time where, once they put 6 the new cathodic protection system in, which 7 again was mid

- kind of like '95

-'96 or it might 8 have been '94, that they had a period where it 9 went out of effective monitoring.

10 MEMBER STETKAR: I am just triggering 11 on the word recently, you know. That, to me, 12 implies maybe in the last year or two rather than 13 15 years ago. So, thanks.

14 I actually know how some of the people 15 prepare for the license renewal applications, and 16 recent sometimes means six months ago. Thanks.

17 MR. PICK: Any other questions?

18 MR. FERRER: Thanks, Greg. I will now 19 move on to Section 3, Aging Management Review 20 results. 21 Section 3.0 covers the staff's review 22 of the applicant's aging management programs. I 23 will just note that the open and confirmatory 24 items in Section 3 are all discussed in this 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 116 section. 1 Sections 3.1 through 3.6 cover aging 2 management review items, and each of the systems 3 within the scope of license renewal. For a given 4 aging management review, the staff reviewed the 5 items to determine whether it was consistent with 6 the GALL report and, if an aging management 7 review is not consistent, then the staff 8 conducted a technical review to ensure adequacy.

9 As the applicant previously stated, 10 they submitted 42 aging management programs, and 11 there were approximately 3,000 aging management 12 review items. Of the 42 aging management 13 programs, 31 were existing, nine are new, and two 14 plant specific.

15 As I noted earlier, there are two open 16 items related to aging management programs.

17 Allen Hiser will discuss the open item related to 18 the flux thimble tube inspection program at this 19 time. 20 DR. HISER: Thanks, Nate. The flux 21 thimble tube inspection program is a GALL 22 program. During the staff's review, the o ne item 23 that really stuck out to us was the operating 24 experience at Diablo Canyon.

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-3701 www.nealrgross.com 117 I don't want to rehash much of what 1 the applicant provided earlier, but a lot of the 2 RAIs in the open item relate back to that 3 finding. The one area I guess I did want to 4 highlight was the concern that the staff has that 5 the wear rate projection methodology employed by 6 the applicant may be nonconservative.

7 So it may not give conservative 8 estimates of wear that would be measured after 9 the current operating cycle, and that is one area 10 that we still have the open item that we will 11 review applicant's response to, and we will reach 12 a determination on the acceptability of the 13 program based on that review.

14 MEMBER STETKAR: Allen, the way at 15 least I read the SER, the concern seemed to be 16 focused on the thinning threshold, and I was 17 under the impression it was different from what 18 Diablo said, that they are using 68 percent 19 rather than 80 percent.

20 What is the real concern? Is it the 21 methodology on how they project the rate or that 22 actual acceptance criterion

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-3701 www.nealrgross.com 118 of all pieces. The project methodology does not 1 incorporate explicit uncertainty considerations.

2 MEMBER STETKAR: Let me ask you then 3 what is different in Diablo's methodology 4 compared to other previously approved license 5 renewal applications that indeed have used an 80 6 percent thinning acceptance criterion?

7 DR. HISER: Jim Medoff is here.

8 MEMBER STETKAR: Is their methodology 9 different?

10 DR. HISER: The main reviewer on a lot 11 of this. 12 MR. MEDOFF: This is Jim Medoff of the 13 staff. I was the peer reviewer for the flux 14 thimble tube inspection program for Diablo 15 Canyon. 16 The big difference is some of the 17 other applicants have adopted the WCAP 12866 18 methodology. So their acceptance criteria is set 19 to 80 percent on that basis, and then the 20 Westinghouse methodology included uncertainty to 21 derive that 80 percent through

-wall wear 22 acceptance criteria.

23 For Diablo Canyon, it is a little bit 24 different. They have a certain procedure that 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 119 refers to a different Westinghouse plant specific 1 calculation for them, and that calculation set 2 the acceptable wear criterion to 68 percent 3 through wall, including uncertainty.

4 Then later on, the applicant had done 5 a 50.59 to that Westinghouse methodology to 6 remove the uncertainty based on a comparison to 7 the WCAP methodology, even though it is not 8 really part of their licensing basis.

9 CHAIRMAN BLEY: Compared to the new 10 WCAP methodology?

11 MR. MEDOFF: Yes. Yes. So th at is 12 what we are trying to figure out, whether that is 13 an acceptable basis or not, and we are looking 14 that over.

15 The other matter is the wear 16 projections, including whether it should have 17 uncertainties in it, and to figure out whether 18 the way they do w ear projection is conservative.

19 Their current program does wear projections on a 20 linear basis, but some of the wear history that 21 we have audited for the program may indicate that 22 they are getting some non

-linear wear, and we are 23 wondering whether the line ar basis is 24 conservative at this point.

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-3701 www.nealrgross.com 120 They have given us access to some non

-1 docketed information that we are doing sort of an 2 informal audit of now to see whether we can 3 accept their projected basis. So it is under 4 review right now.

5 MEMBER STETKAR:

Is that non

-linear 6 wear history specifically focused on that L

-3 7 flux thimble tube?

8 MR. MEDOFF: I think there are two 9 others that may have non

-linear basis, and that 10 is why we are checking the data right now.

11 MEMBER STETKAR: I will tell you, I 12 plotted out the actual wear history on that tube 13 and, although it is not a perfectly straight 14 line, it is pretty doggone close to a straight 15 line. So a linear projection didn't look too bad 16 to me at least

-- well, and the four years of 17 data they had.

18 DR. HISER: But those are three 19 different areas that have worn. It is not the 20 same area.

21 MR. MEDOFF: And the other thing is 22 that the one outage that they had some wear, they 23 have not stated in their slide projection. They 24 had replaced that tube in outage 10, and they had 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 121 a certain amount of wear in outage 11. They 1 didn't do any corrective action, because it was 2 so low, and then the subsequent outage, they 3 found even more wear. So it went from like 16 4 percent up to somewhere in the thirties or 5 forties. Then they repositioned the first time.

6 DR. HISER: And then it went up to 7 about 46 percent in the third year, which is 8 another 16 percent.

9 MR. MEDOFF: So this tube was a real 10 anomaly, I think, for the facility. We are 11 looking at some of the other tube da ta to see if 12 this is happening in other tubs.

13 MEMBER STETKAR: My only concern in 14 terms of consistency in these reviews is that I 15 recognize they had a failure which was an 16 anomaly. You wouldn't have expected a failure 17 after that short a period of time.

18 I hope the staff is not overreacting 19 to that singular event and applying consistent 20 criteria for these programs across the entire 21 fleet, because the small sample that I took 22 seemed to be

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-3701 www.nealrgross.com 122 that is the concern, because the way I read the 1 SER, it was strictly on the acceptance criterion, 2 whether or not you have applied uncertainties on 3 it. To me, a 68 percent wear without uncertainty 4 probably adequately applies -- you know, covers 5 uncertainty up to an 80 percent that probably 6 does include uncertainties.

7 DR. HISER: Yes. I guess the one 8 concern was the inconsistency within their 9 procedures. The procedure referred to a 10 calculation that said 68 percent, and included 10 11 percent uncertainty. They were not including the 12 10 percent uncertainty, and that basis was what 13 we were seeking.

14 MEMBER STETKAR: So you would have 15 expected them to use 58 percent?

16 DR. HISER: Well, that is what their 17 calculation would have indicated, that that is 18 what they should have used.

19 MEMBER STETKAR: Well, had you earlier 20 looked at the 59.59 that, I think, I heard 21 changed that?

22 DR. HISER: No.

23 MR. MEDOFF: No, and we may

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-3701 www.nealrgross.com 123 but it is under review, at least on the 1 uncertainty. The projection

-- The wear 2 projection methodology is something we are going 3 to have to look in a little bit deeper, based on 4 the inspection data that they have given us 5 access to.

6 DR. HISER: I didn't mean to indicate 7 that we overreacted to the one tube that leaked, 8 but we do want to understand from their 9 comprehensive data whether their wear projection 10 methodology is conservative of nonconservative, 11 and just to ensure that they do get conservative 12 projections.

13 MEMBER ABDEL

-KHALIK: Now you stated 14 that this is unusual OE. If that is the case, 15 and if the cause is flow induced wear, has the 16 staff asked what would be the possible 17 implication beyond just the impact on wear of the 18 flux thimble tubes?

19 The example would be does that mean 20 that the lower plenum anomaly in this particular 21 plant may be much more severe than what is 22 predicted by the scaled experiments performed by 23 Westinghouse, so that there may be an impact on 24 core design calculations?

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-3701 www.nealrgross.com 124 MR. MEDOFF: May I address that, 1 Allen? One of the reasons the GALL program is 2 written the way it is, is back for a previous 3 application they did apply the Westinghouse

-- 4 they were applying the Westinghouse methodology, 5 and I reminded the applicant that the bulletin 6 has directed that you are supposed to use your 7 own plant specific data in coming up with your 8 wear projections and setting your acceptance 9 criteria. 10 MEMBER ABDEL

-KHALIK: I think that you 11 and I are talking about different W estinghouse 12 data. 13 DR. HISER: Let me take a crack at 14 that. The excessive accelerated wear in this 15 thimble tube, the applicant has indicated through 16 their failure analysis was due to the tube being 17 repositioned outside of the chrome band, and I 18 think that is the cause of the failure.

19 I am not aware that any lower plenum 20 anomaly would have impacted that. Since that 21 tube was capped, as far as we know, there has not 22 been any other excessive wear locations 23 identified.

24 MEMBER ABDEL

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-3701 www.nealrgross.com 125 localized phenomenon.

1 DR. HISER: Yes.

2 MEMBER ABDEL

-KHALIK: So if that is 3 the case, could be some sub

-assemblies that would 4 be relatively starred for flow at the inlet to 5 the core? 6 DR. HISER: I am not that familiar 7 with the thermal hydraulic

s. 8 ME. MEDOFF: Yes. To get into that, 9 we would have to go back to some of the guys at 10 Division of Systems here at DSS and talk to them 11 about that.

12 MEMBER ABDEL

-KHALIK: You promised to 13 give us some information later on. so we will 14 wait for you infor mation then.

15 MR. MEDOFF: He has that information 16 now. 17 MEMBER ABDEL

-KHALIK: You do? Well, 18 thank you. Please.

19 CHAIRMAN BLEY: We will let Diablo 20 Canyon tell it.

21 MR. MAYER: My name is Mark Mayer. We 22 checked back with our people back at the plant , 23 and we have had an evaluation performed by 24 Westinghouse, and the conclusion was that our 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 126 internals are not susceptible to the phenomenon 1 known in the industry as lower plenum anomaly.

2 What we do have is a fair amount of 3 cross-flow like at the entrance of the core, 4 which does result in some excitation of the flux 5 thimble tubes.

6 MEMBER ABDEL

-KHALIK: And that would 7 be the cause of the wear?

8 MR. MAYER: That is correct. Going 9 back to your other half of your question, the 10 indications that we would see for lower plenum 11 anomaly would be a combination of sudden changes 12 in core exit thermocouple indications in 13 conjunction with step changes in the indicated 14 RCS flow. 15 MEMBER ABDEL

-KHALIK: You could 16 resolve lower plenum anomaly with core exit 17 thermocouples?

18 MR. MAYER: They correlate.

19 MEMBER ABDEL

-KHALIK: Thank you.

20 CHAIRMAN BLEY: Said, you accept that, 21 do you? 22 MEMBER ABDEL

-KHALIK: No, I don't, but 23 it is not important to this.

24 MR. FERRER: If there is no other 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 127 questions, we will move on. Bill Holston will be 1 discussing the buried piping and tanks inspection 2 program open item.

3 MR. HOLSTON: So we discussed some of 4 this in standard pieces throughout the 5 presentation, but to summarize it all, without 6 going through how the applicant adjusted their 7 program based on recent operating experience, 8 they have confirmed that their backfill won't 9 damage coatings or the piping.

10 Steel piping is coated. The soil 11 conditions are acceptable for no coatings on 12 their stainless, their copper, and their asbestos 13 c oncrete pipe.

14 We have already discussed that they 15 have cathodically protected the steel piping, 16 with the exception of 40 feet of the salt water 17 piping. That is going to be cathodically 18 protected by the period of extended operation 19 and, given that it is not currently cathodically 20 protected, they are augmenting their number of 21 inspections from one to four for that system 22 until it is cathodically protected.

23 Overall, they increased the number of 24 inspections from originally proposed, which was 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 128 two over the 30-year period, to 12 inspections.

1 The two items that were still open at 2 the time of the SER, we have talked about, and 3 that was the resolution of where the copper 4 valves in scope are not copper alloy, the bronze 5 valves, and the steel piping that was in the 6 makeup system that was buried, and the applicant 7 talked about how they changed their isolation 8 point and less their boundary of the license 9 renewal such that the steel piping was no longer 10 in scope. They appropriately modified their 11 operating procedures to use that as a boundary 12 valve. Are there any other questions?

13 MEMBER STETKAR: Yes. Simple. I 14 couldn't follow all the bits and pieces. So let 15 me just ask you: Rev 2 of the GALL report has 16 fairly detailed tabulations of the number of 17 inspections and the types of inspections as a 18 function of all of the different parameters you 19 have mentioned, backfill, cathodic protection 20 type of pipe, etcetera, etcetera.

21 With the exception of the current 22 issues that are under discussion, is Diablo's 23 proposed inspection program consistent with those 24 recommendations?

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-3701 www.nealrgross.com 129 MR. HOLSTON: Yes, sir, it is. And 1 including the 40 feet of piping that is not 2 cathodically protected.

3 MEMBER STETKAR: I just couldn't

-- I 4 didn't know the piping lengths. Fine. That is 5 all. Yes is a good answer. Thank you.

6 MR. FERRER: Thanks, Bill. I will now 7 cover the two confirmatory items. Confirmatory 8 item 3.0.3.2.14

-1 relates to the inaccessible 9 medium-voltage cables not subject to 10 CFR 10 50.49, Environmental Qualification Requirem ents 11 Program. 12 The staff requested additional 13 information on how the program would account for 14 recent operating experience. In is response, as 15 the applicant stated previously, they increased 16 the scope of the program, removed the significant 17 voltage screening criteria, and increased their 18 manhole inspections to one year.

19 The staff had identified that we 20 needed clarification on the applicant's 21 justification for not performing the event

-driven 22 inspections as well as the use of the 10

-year 23 testing frequency, and since then the applicant 24 has, as they stated, submitted a response by 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 130 letter dated January 7th. They have provided the 1 additional details, and the staff believes we 2 will be able to close it.

3 Are there any additional questions on 4 this? 5 The structures monitoring program 6 confirmatory item: Again, to recap a little bit, 7 the staff noted that the Unit 2 spent fuel pool 8 has the persistent but minor leakage. As part of 9 the response, the applicant clarified that the 10 leakage is contained within the leak chase 11 system, and that they were inspected in March 12 2010 and were not blocked.

13 Then they initially committed to 14 perform that follow

-up inspection, and our 15 concern was about the timing. They have since 16 then submitted their commitment to perform the 17 inspection one year to prior to entering the 18 period of extended operation. So the staff 19 believes it will be able to close this item as 20 well. 21 Are there any questions on that?

22 DR. BARTON: The structures 23 monitoring: Is there any example of exterior 24 containment cracking at the site?

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-3701 www.nealrgross.com 131 MR. FERRER: Abdul Sheikh can speak to 1 that. 2 MR. SHEIKH: This is Abdul Sheikh on 3 the NRC staff. When we did the audit, we looked 4 at this closely, and the first thing we noticed 5 was the applicant's program for inspection, an d 6 we found that they were inspecting the concrete 7 every 10 years instead of the requirement of five 8 years. So we discussed this with the applicant, 9 and the applicant has changed their procedures, 10 and they are inspecting every five years.

11 Then we looked at their criteria for 12 inspection on how they record the degradation of 13 concrete, and we found that it was not consistent 14 with the industry criteria, which is ACI

-349. So 15 we asked the applicant about it, and applicant 16 has agreed to change their procedures t o inspect 17 it according to the industry criteria.

18 Then we asked them to look at all the 19 discrepancies they have for spalling and 20 degradation in concrete which they have recorded 21 based on the new criteria, and their engineers 22 have looked at it and found all of them are 23 accepted within the criteria.

24 DR. BARTON: Thank you. The reason I 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 132 bring that is, in the SER Structures Monitoring 1 Program, the operating experience section of that 2 describes instance of concrete delamination, 3 spalling exterior containment, corrosion of 4 containment and liner, cracking at Turbine 5 Building concrete piers to the turbine pedestal, 6 and conditions of the concrete intake structure.

7 I guess my overall question is: Does 8 the staff feel that the applicant has got all 9 this under control or is the plant crumbling 10 around it?

11 MR. PICK: During our on

-site 12 inspection, looking at that same inspection 13 report where we noticed the strain gauge boxes, 14 there were also photographs of cracks on the 15 exterior of the containment, but they were

-- 16 Many of them did not have a gauge to figure out 17 how wide they were, but a couple of them showed a 18 pop-out the size of an eighth of an inch.

19 So there is some small cracking on the 20 exterior of the containment. But the answer of 21 the concern of whether it is falling down around 22 us, the staff felt that the material condition of 23 the areas that we reviewed looked good.

24 DR. BARTON: That section just 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 133 describes a lot of misery in inspector concrete 1 cracks and stuff like that, not just in the 2 containment but turbine piers at a pedestal and 3 stuff like that. So just wonder whether you guys 4 looked at all that and you've got some concern 5 about those areas, or not. That is all I am 6 asking. 7 MR. PICK: Our structural inspector 8 also looked at the base of many of the tanks, 9 even up to the raw water ponds. Basically, 10 everywhere that he could physically walk and 11 access, he did, and he reported back that he did 12 not have any concerns with the concrete.

13 MR. FERRER: Any other questions? We 14 will now move on to SER Section 4, which contains 15 the staff's review of time

-limited aging 16 analyses. In this section, we will focus mainly 17 on the three open items and any additional items 18 of interest.

19 Section 4.2 of the SER documents the 20 staff's review of the reactor vessel neut ron 21 embrittlement time limited aging analyses. With 22 regard to the pressurized thermal shock, Diablo 23 Canyon has one insensible weld not meeting the 10 24 CFR 50.61 pressurized thermal shock screening 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 134 criteria, and this slide provides the information 1 on the Unit 1 lower shell longitudinal weld noted 2 up there. 3 The applicant stated that it would 4 either implement 10 CFR 50.61(a) at least three 5 years prior to exceeding the PTS screening 6 criteria or, if it cannot meet that, it would 7 implement alternate options, such as flux 8 reduction.

9 So unless there are any questions, 10 Allen Hiser will now discuss the three open 11 items. 12 MEMBER SHACK: Is this the first time 13 that they have asked for 50.61(a)?

14 DR. HISER: I believe it is the first 15 time any applicant has asked fo r it. 16 MEMBER SHACK: Has Beaver Valley come 17 back? I mean, they had sort of committed to 18 something like flux reduction. Right?

19 DR. HISER: I am not sure what their 20 measures are. Within the 54.21(c)(iii) EV 21 management, they have a variety of options t hat 22 they could implement.

23 MEMBER SHACK: But they haven't come 24 back for them?

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-3701 www.nealrgross.com 135 DR. HISER: No, I don't believe so at 1 this point. And, generally, they would have 2 flexibility within the PTS rule, for example, to 3 wait until three years before they would exceed 4 the PTS screening criteria before they would have 5 to identify to the staff additional actions that 6 they were going to take.

7 During the staff's review of Section 4 8 on time-limited aging analyses, the staff 9 identified two TLAAs that the applicant h ad 10 indicated that there was no TLAA, the first area 11 on reactor coolant pressure boundary valves.

12 The staff routinely reviews the 13 application and the design codes that are cited 14 in the application to ensure that there are no 15 TLAAs that relate to those analyses. In the case 16 of this application, there was insufficient 17 information for the staff to do that review, and 18 at this point that is still an open item.

19 We have received a response, but we 20 have not completed our review of that response.

21 On the baffle and former bolts, there 22 is an existing ASME Section 3 cumulative usage 23 factor calculation on fatigue. The applicant 24 indicated that that was not a TLAA, because they 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 136 would be providing aging management using MRP

-227 1 inspection criteria.

2 Although that is technically one way 3 to manage fatigue, it is not consistent with the 4 Section 3 requirements that you maintain your 5 design basis and maintain a cumulative usage 6 factor. The applicant has provided a response, 7 and again we are evaluating the acceptability o f 8 that response.

9 If we move to the next slide, metal 10 fatigue is another area where the staff 11 identified the need for additional information.

12 Even after reviewing that additional information, 13 we ended up with an open item, 4.3

-1. It had 14 several parts to it. 15 We have binned those, as indicated 16 here, under cycle counting, environmentally 17 assisted fatigue, and cumulative usage factors.

18 I believe the applicant did a fairly thorough 19 review of the various pieces of this open item.

20 So I don't want to go into anymore detail than 21 that. 22 We have received the open item RAI 23 response, and we are still reviewing that.

24 If there are no other questions?

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-3701 www.nealrgross.com 137 MEMBER STETKAR: Yes. Let me ask you 1 about cycle counting, because I got a chance to 2 ask Diablo. In the SER, Diablo used some sort of 3 methodology to infer the number of feedwater 4 cycle events, I guess, going to hot shutdown or 5 at hot shutdown transients based on the number of 6 pressurizer heat

-up events. So there was some 7 sort of inferred correlation there.

8 I didn't quite understand how they did 9 that, because when I

-- this again is a 10 consistency issue, because when I project the 11 number of pressurizer heat

-ups using the 12 correlation that I thought they did, I come up 13 with a different number of projected feedwater 14 transients. So I am not quite sure what they 15 did. Do I care? Yeah, I do, for consistency.

16 They are well in the margin, but I 17 like consistent numbers. However, I noted in the 18 SER it says the staff also independently 19 confirmed that the applicant's basi s yields a 20 projected feedwater cycling event value of 685 21 events for Unit 1

-- yada, yada, yada.

22 In a separate paragraph, the staff has 23 independently calculated the number of feedwater 24 initiating events to be 685 initiations. Well, I 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 138 could independently calculate those, because I 1 can multiple 14 times X and get those numbers.

2 Is that the independent calculation that you did 3 to confirm that 14 times X is

-- 4 MR. MEDOFF: We take the data they 5 give us, because they are doing

-- 6 MEMBER STETKAR: It is n ot an 7 independent calculation, is it? It is a sort of 8 can I multiply check. I am led to infer that you 9 had some other data and did some different type 10 of analysis on that.

11 MR. MEDOFF: We use the cycle counting 12 data they provide for us.

13 MEMBER STETKAR: So you check whether 14 their calculator could multiply. Thanks. I get 15 concerned about independently verified or 16 independently calculated numbers versus audited 17 their calculation and indeed confirmed that they 18 multiplied correctly.

19 MR. MEDOFF: But th is is similar to 20 what we do for the PTS assessment that we gather 21 data. 22 MEMBER STETKAR: Well, but in some 23 cases, for example, in other parts of the reviews 24 and audits that the NRC staff does, they actually 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 139 run separate, independent analyses; for example , 1 thermal hydraulic analyses or things like that, 2 that are actually independent calculations to 3 confirm an applicant's projections or analysis.

4 MR. MEDOFF: This is more of an 5 independent verification.

6 MEMBER STETKAR: Okay, thanks. I just 7 wanted to make sure I wasn't missing something.

8 DR. HISER: Okay, we are ready for the 9 next slide. Open item 4.7.5

-1 covers the RHR 10 piping weld that the applicant described earlier.

11 During the staff's review, the staff 12 noted that the applicant did follow ASME co de 13 requirements and that the location of the flaw 14 that they identified met the proximity rule 15 requirements of IWA 3300 of the ASME code and, 16 therefore, in their fracture stability 17 calculation they assumed that it was a 18 throughwall flaw.

19 The staff felt that it was 20 inconsistent then for the applicant to not use

-- 21 or not assume a stress corrosion cracking or a 22 water environment for that flaw, and asked the 23 applicant to justify its position. As indicated 24 by the applicant, they have gone ahead and done 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 140 the stress corrosion cracking calculation and had 1 submitted that to the staff. We have not 2 completed our review of that, but will do so and 3 we will document that in the final SER.

4 So that is the open item related to 5 the RHR weld.

6 MR. FERRER: In closing, t he staff is 7 working to resolve the open items and, pending 8 resolution of these items, the staff is working 9 to issue the SER. Again, thank you for the 10 opportunity to discuss the staff's review of the 11 Diablo Canyon license renewal application.

12 CHAIRMAN BLEY: Anymore questions from 13 the Committee? Thank you very much for the 14 presentations.

15 At this point, Diablo Canyon has some 16 answers to questions we had asked earlier.

17 MR. SHARP: Loren Sharp from Diablo 18 Canyon. If I could have David Gerber answer t he 19 question on cycles.

20 MR. GERBER: My name is Dave Gerber.

21 I am with Structural Integrity Associates, and I 22 am on the Diablo Canyon License Renewal Team.

23 The question, as I understood it, is 24 why is the baseline number of the aux spray 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 141 during plant cooldown events not two times the 1 number of plant cooldown events?

2 MEMBER STETKAR: Yes.

3 MR. GERBER: The answer is that we 4 took two different periods of time to make this 5 evaluation. The first period of time there was 6 no -- The plant data available to do counting was 7 not available. The second period of time, the 8 plant's data was available.

9 For the first period, we applied the 10 two times rule, aux spray during plant cooldown 11 equals two times plant cooldown. For the second 12 period we actually counted both plant cooldowns 13 and aux spray during plant cooldowns. Thus, the 14 projection could and did divert.

15 MEMBER STETKAR: Thanks. Thank you.

16 MR. SHARP: Thank you. I believe that 17 answers all, but we still owe you one, I believe.

18 CHAIRMAN BLEY: At this time, I would 19 ask if there are any comments from the public 20 attending the meeting.

21 I would like to go around and have 22 members of the Committee provide any comments on 23 what we have heard today, and then we get our 24 consultant after that. So if we can start with 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 142 Jack Sieber.

1 MEMBER SIEBER: I think that the level 2 of review and the quality application is 3 consistent with most of the plants that we have 4 reviewed. I think there are unanswered questions 5 and, obviously, there are open items, RAIs that 6 we will have to look at before we get to the 7 final meeting, but I think the actions taken for 8 the issues that I am concerned about are 9 consistent with the ways that industry has 10 basically solved the problems at hand, and I 11 think that the applicant is basically aware of 12 the issues that exist with this type of plant and 13 this environment.

14 So I am reasonably satisfied that 15 progress is being made.

16 CHAIRMAN BLEY: Thank you. Harold?

17 MEMBER RAY: I don't have anything to 18 add. 19 CHAIRMAN BLEY: Sam?

20 MEMBER ARMIJO: Yes. I thought it was 21 a very good presentation. I think the plant, 22 based on the inspection results and all the 23 information provided, is in good shape. The 24 arguments about the weld flaw and what it means 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 143 and whether it is going to grow are very 1 persuasive to me, particularly when the 2 temperatures are as low as they are, but the UT 3 examination technique, I thought, was very good.

4 So I don't think that is a big concern.

5 Although it wasn't presented, I did 6 review the material on the water chemistry and 7 the material degradation in the plant over the 8 lifetime. I think, based on that information, it 9 has been excellent, and I think the very few 10 stress corrosion cracking events attest to that 11 very good control of the operating environment, 12 and I think that will continue during the period 13 of extended operation.

14 So overall, I think it is in very good 15 shape. 16 CHAIRMAN BLEY: Thank you.

17 MEMBER ABDEL

-KHALIK: I have no 18 additional remarks.

19 CHAIRMAN BLEY: John?

20 MEMBER STETKAR: Nothing. Nothing at 21 all. I think the staff did a really good review.

22 So I congratulate them on another good job well 23 done. 24 MEMBER RYAN: I second what has been 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 144 said before, and I also appreciate the applicant 1 bringing, I think, promising weather from the 2 plant here today.

3 CHAIRMAN BLEY: There is nothing in 4 the store, Mike. Come on.

5 MEMBER RYAN: I appreciate the fact 6 that you brought everybody here to answer any 7 question we might have. Thank you.

8 CHAIRMAN BLEY: Bill?

9 MEMBER SHACK: Nothing additional.

10 CHAIRMAN BLEY: Mike?

11 MEMBER CORRADINI: Nothing additional.

12 CHAIRMAN BLEY: Nothing more from me, 13 although just to check my counting on the 14 questions that Jack raised, did I count right?

15 Are there only two open items left that still 16 need resolution, the flux thimbles and the stress 17 corrosion cracking?

18 MR. FERRER: Also, the TLAA 19 identification of metal fatigue, we are still 20 reviewing those as well.

21 DR. HISER: We just have not completed 22 our reviews of those items, the TLAA.

23 CHAIRMAN BLEY: Did we have a phone 24 line open? I don't think so.

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-3701 www.nealrgross.com 145 MR. BENSON: Yes, we did have some 1 people call in.

2 CHAIRMAN BLEY: Want to open it up and 3 see if we have public comments from them? Can we 4 do that? 5 CHAIRMAN BLEY: Oh, I am sorry. John 6 Barton. I forgot. I just slid right by.

7 Please. You should have yelled at me.

8 DR. BARTON: I usually don't give out 9 kudos, but I got to give that to the staff. I 10 mean, after seeing the number of RAIs, follow

-up 11 RAIs, conference calls

-- I mean, it had to get 12 pretty tough.

13 You know, we are doing

-- this is 62, 14 63, somewhere in there, in license

-- 15 CHAIRMAN BLEY: Sixty

-three. 16 DR. BARTON: And I guess I have looked 17 at about 42 of them. This application looked 18 like it was the initial plants when GALL was out, 19 before NEI came on board, and I just thought it 20 was not very good quality.

21 I feel a lot better today after 22 hearing the applicant's presentation and the 23 staff's work that they have done in reviewing 24 this thing. But I just expected at this stage of 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 www.nealrgross.com 146 the process a l ot better application than what 1 you people received, and I think those are

-- I 2 don't see any major issue that says that this 3 plant doesn't deserve license extension after all 4 the issues are resolved. It just didn't look 5 good from the get

-go. That is all I am going to 6 say. 7 CHAIRMAN BLEY: Thank you, John.

8 I think the phone line is open now.

9 If anybody is on the phone, please just say a 10 word so we know you are there, hello or 11 something. Oh, there is somebody there. So if 12 anyone listening in on the phone line cares to 13 make a comment, we would be glad to entertain 14 that at this point in time. Identify yourself 15 and make your comments, please. I take nobody 16 wants to.

17 I want to thank the applicant and the 18 staff for very good presentations and 19 discussions. We appreciate it a lot, and this 20 meeting is adjourned.

21 (Whereupon, the foregoing matter went 22 off the record at 4:31 p.m.)

23 24 25 DIABLO CANYON POWER PLANTLICENSE RENEWAL 2Jim BeckerSite Vice President 3DIABLO CANYON POWER PLANTPERSONNEL IN ATTENDANCEJim Becker, Site Vice PresidentLoren Sharp, Senior Director Technical ServicesMike Wright, Engineering ManagerTerry Grebel, License Renewal Project ManagerSTARS Center of Business and Plant Staff 4AGENDAIntroductions Site and Station Description Plant History Major Improvements GALL Consistency and Commitments Safety Evaluation Report Open and Confirmatory Items

-Flux Thimble Tube Inspection Program

-Flaw Growth Evaluation for RHR

-Scoping and Screening

-Buried Piping and Tanks Inspection Program

-TLAA Identification

-Metal FatigueConcluding Remarks 5SITE DESCRIPTION 6SITE DESCRIPTIONISFSIRaw Water ReservoirsUnit 2Unit 1Turbine BuildingDischargeIntakeAdmin Building 7STATION DESCRIPTIONTwo Units-Common operating procedures/design4 loop Westinghouse NSSS 3411 MWtPG&E was architect/engineer with Bechtel supportOnce-through coolingContainment

-free standing, steel

-lined, reinforced concrete building PG&E owner and operatorPG&E owns and operates the switchyards and the high voltage transmission system 8Loren SharpSenior Director, Technical Services 9STARS CENTER OF BUSINESSStrategic Teaming and Resource Sharing (STARS) Alliance Center of Business

-Seven large PWR stations in Region IV

-Center of Business created to prepare license renewal applications for the member utilitiesLeadership, oversight and ownership by Diablo Canyon personnel through the License Renewal development and review phases, continuing through implementation 10PLANT HISTORYUnit 1 full power operating license issued November 2, 1984Unit 2 full power operating license issued August 26, 1985October 2000, Unit 1 increased licensed power to 3411 MWtUnit 1 operating license expires November 2, 2024Unit 2 operating license expires August 26, 2025 11MAJOR IMPROVEMENTSSteam Generators replacedReactor Heads replacedAuxiliary Saltwater System piping bypassDiesel Fuel Oil tanks replacedLow Pressure Turbine rotors replaced4 kV cables replaced6thEmergency Diesel Generator addedMain Generator Rotors replacedFeedwater heaters/MSR copper tubes replaced with stainless steelMain Bank and Start

-up Transformers replacedAnalog to Digital Control Systems upgradedExtensive FAC piping replacements 12Terry Grebel License Renewal Project Manager 13GALL CONSISTENCY AND COMMITMENTSTotal Aging Management Programs Existing Programs New Programs Plant Specific

-2Aging evaluations are greater than 93% consistent with GALL Rev 1 (standard notes A through E)License Renewal commitments

-64License Renewal commitments managed through the DCPP commitment tracking system which implements the guidance of NEI 99-04, Revision 0, "Guidelines for Managing NRC Commitment Changes" 14SAFETY EVALUATION REPORTOPEN ITEMS Flux Thimble Tube Inspection Program

-Flaw Growth Evaluation for RHR

-Scoping and Screening (3 Open Items)

-Buried Piping and Tanks Inspection Program

-TLAA Identification

-Metal FatigueCONFIRMATORY ITEMS Cable Testing 6 Years Frequency

-Spent Fuel Pool Leak Chase Inspection Schedule 15Flux Thimble Tube Inspection ProgramMike Wright Engineering Manager 16DCPP THIMBLE TUBE BACKGROUND 17DCPP THIMBLE TUBE L

-13 HISTORY 18FLUX THIMBLE TUBE INSPECTION PROGRAMOI 3.0.3.2.12 RAI B2.1.21

-1Issue: -Based on Unit 2 thimble tube L

-13 operating experience, justify an appropriate margin to account for NDE measurement and wear scar uncertaintiesResolution:

-DCPP wear projection methodology was compared to Westinghouse WCAP-12866 using site

-specific wear data

-WCAP methodology acceptance criteria is 80% wear (including uncertainties)

-DCPP acceptance criteria is 68% wear (17.5% margin from WCAP)

-DCPP acceptance criteria is conservative and comprehensive 19FLUX THIMBLE TUBE INSPECTION PROGRAM OI 3.0.3.2.12 RAI B2.1.21

-2Issue: -Additional information regarding L

-13 FTT failure causes and corrective actions2R14 (2008) L

-13 actions & cause determinationCause of Failure:

-L-13 thimble tube failure caused by flow

-induced wear and plant practices that allowed multiple repositioning of thimble tubes

-Repositioning practices exposed non

-chrome plated portion of the thimble tube to the bottom nozzle

-No cracking has been identified in any thimble tube eddy current examinations 20FLUX THIMBLE TUBE INSPECTION PROGRAMOI 3.0.3.2.12 RAI B2.1.21

-2Resolution: Non

-Linear Wear

-Procedure acceptance criteria revised to require capping or replacing tubes:> 25% wear per year, orAny tube with multiple wear scars, any two of which measured > 40% wear

-In addition:Tube may only be repositioned 6 inches, andTube may only be repositioned once

-Replacement thimble tubes are supplied by Westinghouse with a 12 foot chrome plated band 21FLUX THIMBLE TUBE INSPECTION PROGRAMCONCLUSIONPG&E is confident that the 68% acceptance criteria in combination with the additional procedural acceptance criteria is comprehensive and conservative 22Flaw Growth Evaluation for RHR Piping WeldDavid GonzalezISI Supervisor 23Flaw Growth Evaluation for RHR Piping Weld WIC

-95 OI 4.7.5-1 -SER 4.7.5Issue:-PG&E's basis for concluding that the flaw in Unit 1 RHR piping weld WIC

-95 is not service-related -PG&E's flaw analysis for this weld did not address stress corrosion cracking (SCC)

Background:

-Evaluated the characteristics of the flaw as non

-service induced

-Fatigue crack growth evaluated with acceptable results

-Subsequent 2000 UT inspection result consistent with non

-service induced (no growth)Resolution:

-SCC evaluation performed with acceptable results

-Confirmatory UT inspection of WIC

-95 during the 2012 outage 24Flaw Growth Evaluation for RHR Piping Weld WIC

-95 25Flaw Growth Evaluation for RHR Piping Weld WIC

-95 26Dave MiklushDiablo Canyon License Renewal Project 27SCOPING AND SCREENINGOI 2.1-1 -SER 2.1.4.1.2Issue: -NSR fluid-filled components in the vicinity of SR components(1) Rainwater entering HVAC ducting to vital 480V switchgear room(2) Firewater piping in the vicinity of the Control Room Pressurization System I&C(3) Firewater piping and domestic water piping in the vicinity of HVAC exhaust openings to 4kV switchgear roomResolution: (1) Enhanced water drainage provisions in Unit 2 HVAC exhaust ducting (2) Include in scope firewater piping under 10 CFR 54.4(a)(2)

(3) Include in scope firewater and domestic water piping under 10 CFR 54.4(a)(2) 28SCOPING AND SCREENING OI 2.1-1 -SER 2.3Issue: -NSR fluid-filled components leaking or spraying onto SR cables in electrical pull boxesResolution:

-Pull boxes drain to building sumps or in

-ground sumps

-In-scope pull boxes are physically separated from the sumps and from the pumps and discharge piping 29SCOPING AND SCREENINGOI 2.1-1 -SER 2.3.3.7.2Issue: -NSR fluid-filled water traps spraying onto SR componentsResolution:

-This portion of system is not used

-Commitment to close the upstream isolation valves and drain any contained water from the traps 30SCOPING AND SCREENINGOI 2.3-1 -SER 2.3Issue: -NSR tubing directly attached to SR solenoid valves in the compressed air systemResolution:

-All NSR tubing directly attached to SR solenoid valves in the compressed air system is included in scope up to the first seismic or equivalent anchor on the NSR side of the code break 31SCOPING AND SCREENINGOI 2.3.3.14 SER 2.3.3.14.2Issue: -Scoping methodology of Diesel Generator compressor unloader line endpoint for pressure boundary functionResolution:

-Design change relocates unloader tubing to the compressor discharge piping upstream of the pressure boundary isolation check valve

-After design change unloader line is no longer in

-scope-Completed on Unit 1; Unit 2 scheduled for April 2011 32BURIED PIPING AND TANKS INSPECTION PROGRAM OI 3.0.3.2.8 SER 3.0.3.2.8Issue:-Management of aging effect for buried copper valves in the Makeup Water System

-Clarification of in

-scope steel pipe in the Makeup Water SystemResolution:

-Buried copper valves will be managed by the Buried Piping and Tanks Inspection Program

-Commitment to enhance operating procedure to close Makeup Water System isolation valve in event of a pressure boundary failure and removed steel piping and components from scope 33Michelle AlbrightDiablo Canyon License Renewal Project 34TIME-LIMITED AGING ANALYSES IDENTIFICATION OI 4.1-1RAIs:-Reactor coolant pressure boundary valves

-Baffle and former boltsResolution:

-Confirmed DCPP design codes for the reactor coolant pressure boundary valves do not require a fatigue analysis

-Fatigue of the baffle and former bolts is managed by the Reactor Vessel Internals AMP 35METAL FATIGUEOI 4.3-1Additional information

-Replacement reactor head CUF values

-AMR revisions for piping system cumulative fatigue damage Clarification

-Cycle counting for upper and lower core plates

-Cycle estimates for the "Auxiliary Spray during Plant Cooldown" transient

-Charging system cycle estimate methodology during unmonitored periods

-Electrical raceway seismic evaluation requirementsFSAR/CLB enhancement

-Load-following transients used in design analyses and the FSAR

-Monitoring transients in non

-CUF type analysesEvaluate DCPP Environmentally

-Assisted Fatigue analyses 36Concluding RemarksJim BeckerSite Vice President 66 Flaw Growth Evaluation for RHR Piping Weld WIC-95 70 FLUX THIMBLE TUBE 44 Needed for Tech Spec Flux Map 50 54 UseableThimble Tube RemovedN/A 1 (L-13)Guide Tube CappedScheduled for Replacement in 2R16, May 2011 None Observed 7 4 Capped Minimal (Outside Chrome Band)10 21Chrome: 12 Feet No Wear on Chrome Band Minimal (Outside Chrome Band)7 9Chrome: 15 Inches Minimal 33 24 Original (No Chrome)NotesWear Potential Unit 2 Unit 1 78 CONDUIT LAYOUT (SECTION VIEW) 1Safety Evaluation Reportwith Open ItemsFebruary 9, 2011Nate Ferrer, Project ManagerOffice of Nuclear Reactor RegulationAdvisory Committee on Reactor SafeguardsLicense Renewal Subcommittee Diablo Canyon Nuclear Power Plant, Units 1 and 2

Presentation OutlineOverview of DCPPLicense Renewal ReviewSER Section 2, Scoping and Screening reviewRegion IV License Renewal InspectionsSER Section 3, Aging Management Programs and Aging Management Review ResultsSER Section 4, Time

-Limited Aging Analyses 2

Overview of LRALicense Renewal Application submitted November 23, 2009

-Applicant: Pacific Gas and Electric Company

-Facility Operating Licenses DPR

-80 and DPR

-82 expire November 2, 2024, and August 26, 2025, respectivelyApproximately 12 miles west southwest of San Luis Obispo, CA in Avila Beach, CADCPPunits are Westinghouse four loop PWRs 3 Audits and InspectionsScoping and Screening Methodology Audit

-March 15-18, 2010-Led to submittal of 2 LRAamendments related to scoping and screeningAging Management Program Audits

-April 12-15, 2010-April 26-29, 2010-Over 20 technical reviewers, including contractors from ANL and ORNLRegion IV Inspection

-August/September 2010 4

Overview of SERSafety Evaluation Report with Open Items issued January 10, 2011 SER contains 8 Open Items:

1.10 CFR54.4(a)(2) evaluations for nonsafety-related, fluid

-filled structures and components (SCs) in the vicinity of safety

-related SCs(Open Item 2.1-1)2.10 CFR54.4(a)(2) evaluations for nonsafety-related piping directly attached to safety

-related components (Open Item 2.3

-1)3.Endpoint for the diesel air start unloaderline (Open Item 2.3.3.14

-1)5 Overview of SER (cont.)SER contains 8 Open Items (cont.)

4.Buried Piping and Tanks Inspection Program (Open Item 3.0.3.2.8

-1)5.Flux Thimble Tube Inspection Program (Open Item 3.0.3.2.12

-1)6.TLAAIdentification (Open Item 4.1

-1)7.Metal Fatigue (Open Item 4.3

-1)8.Flaw Growth Evaluation for RHRpiping Weld (Open Item 4.7.5

-1)6 Overview of SER (cont.)SER contains 2 Confirmatory Items 1.Inaccessible Medium

-Voltage Cables Not Subject to 10 CFR50.49 Environmental Qualification Requirements Program (Confirmatory Item 3.0.3.2.14

-1).2.Structures Monitoring Program (Confirmatory Item 3.0.3.2.18

-1)7 SER Section 2 SummaryStructures and Components Subject to Aging Management Review

-Section 2.1, Scoping and Screening Methodology (open item)

-Section 2.2, Plant

-Level Scoping Results

-Section 2.3, Scoping and Screening Results

-

Mechanical (open items)

-Section 2.4, Scoping and Screening Results

-

Structures

-Section 2.5, Scoping and Screening Results

-

Electrical 8

SER Section 2 Open Items10 CFR54.4(a)(2) evaluations for nonsafety-related, fluid

-filled components in the vicinity of safety

-related components, Open Item 2.1 control room pressurization system/HVAC exhaust ducts

-electrical pull boxes

-compressed air system water traps10 CFR54.4(a)(2) evaluations for nonsafety-related piping directly attached to safety

-related components, Open Item 2.3-1-compressed gas systems10 CFR54.4(a)(1) evaluations for scoping boundary of safety-related piping, Open Item 2.3.3.14 EDGair start system

-unisolatedunloaderline from air receiver back to the air compressorApplicant has submitted additional informationStaff is finalizing its review of the response 9

Regional Inspection

-License Renewal Inspections Program ImplementationGreg PickRegion IV Inspection Team Leader10 Regional Inspection OverviewSix inspectors for 2 weeksScoping & screening inspectionAging management programs inspectionSeveral focus areas 11 Regional Inspection Focus AreasSSCs needed to withstand a design basis seismic eventSSCs and programs that prevent leaks to the environmentTreatment of the latest industry aging concernsPrior site

-specific aging issues12 Regional Inspection ResultsScoping of nonsafety-related systems

-Spatial interaction issues

-Some material types incorrect or omitted Aging management programs

-Training required

-Degraded silicon seal

-Reviewed electrical vaults

-Location selected for fouling

-Procedures developed but some errors13 Regional Inspection ObservationsOverall, good material conditionProcedures developed for the programs reviewedMajor component replacements

-230 kV & 500 kV insulators

-Intake structure14 Regional Inspection ConclusionsScoping of non

-safety SSCs and application of the AMPs to those SSCs were acceptableApplicant personnel had incorporated actions to manage aging effects into their programsReasonable assurance exists that aging effects will be managed and intended functions maintained15 Section 3: Aging Management ReviewSection 3.0

-Aging Management Programs (2 open items & 2 confirmatory items)Section 3.1

-Reactor Vessel & InternalsSection 3.2

-Engineered Safety FeaturesSection 3.3

-Auxiliary SystemsSection 3.4

-Steam and Power Conversion SystemSection 3.5

-Containments, Structures and Component SupportsSection 3.6

-Electrical and Instrumentation and Controls System16 SER Section 33.0.3 -Aging Management Programs42 aging management programs (AMPs) presented by applicant and evaluated in the SER17Consistent with GALLConsistentwith exceptionConsistentwith enhancementConsistent with exception & enhancement Existing(31)16 5 5 5New (9)5 4N/AN/APlant-specific(2)N/AN/AN/AN/A SER Section 3 Open ItemsFlux Thimble Tube Inspection Program, Open Item 3.0.3.2.12 Justification for not including measurement and wear scar geometry uncertainties

-Wear rate projection methodology and the capability of program to detect degradation in a flux thimble before the occurrence of a through

-wall failure

-Applicant has submitted additional information

-Staff is reviewing the response18 SER Section 3 Open ItemsBuried Piping and Tanks Inspection Program, Open Item 3.0.3.2.8 Staff requested additional information on how the program would account for recent operating experienceBackfill is acceptableCathodicprotection providedCoatings utilizedIncreased inpsections

-Applicant's initial response did not provide details for:Management of buried copper and steel valves and piping in the makeup water systemAlternate methods used for inspections

-Applicant has submitted additional information

-Staff is finalizing its review of the response19 SER Section 3 Confirmatory ItemInaccessible Medium

-Voltage Cables Not Subject to 10 CFR50.49 Environmental Qualification Requirements Program, Confirmatory Item 3.0.3.2.14 Staff requested additional information on how the program would account for recent operating experience

-Applicant's initial response did not provide sufficient details for absence of event

-driven inspections or use of a 10-year testing frequency

-Applicant has submitted additional information

-Staff is finalizing its review of the response 20 SER Section 3 Confirmatory ItemStructures Monitoring Program, Confirmatory Item 3.0.3.2.18 Applicant initially committed to perform video inspection of the Unit 2 spent fuel pool leak chase during the period of extended operation but did not specify the timing of the inspection

-Applicant revised its commitment to perform the inspection within 1 year prior to the period of extended operation

-Staff is finalizing its review of the response 21 SER Section 4:

Time-Limited Aging AnalysesSection 4.1

-Identification of Time

-Limited Aging Analyses (1 open item)Section 4.2

-Reactor Vessel Neutron EmbrittlementSection 4.3

-Metal Fatigue (1 open item)Section 4.4

-Environmental Qualification of Electrical EquipmentSection 4.5

-Concrete Containment Tendon PrestressSection 4.6

-Containment Liner Plate, Metal Containments, and Penetrations Fatigue AnalysisSection 4.7

-Other Plant

-Specific Time

-Limited Aging Analyses (1 open item)22 SER Section 4SER Section 4.2.2: Pressurized Thermal Shock Limiting Beltline Material

-Unit 1 lower shell longitudinal (axial) weld 3

-442C23%CU%NiEOLEFluence(E>1 MeV)1019 (n/cm 2)Initial Charpy RT NDT 0 F RT PTS 0 FAcceptance Criterion per 10 CFR 50.61 0 F0.2031.0182.04-56280.4<270 o FThe applicant stated in that it will implement 10 CFR 50.61a at least three years prior to exceeding the PTS screening criteria of 10 CFR 50.61. In the event that the provisions of 10 CFR 50.61a cannot be met, PG&E will implement alternate options, such as flux reduction, as provided in 10 CFR 50.61.

SER Section 4 Open Items TLAAIdentification, Open Item 4.1 Justification for absence of TLAAsfor:Reactor coolant pressure boundary valvesBaffle and former bolts

-Applicant has submitted additional information

-Staff is reviewing the response24 SER Section 4 Open ItemsMetal Fatigue, Open Item 4.3 Issues related to Metal Fatigue TLAAsCycle countingEnvironmentally

-assisted fatigueCumulative usage factors

-Applicant has submitted additional information

-Staff is reviewing the response25 SER Section 4 Open Items Residual Heat Removal Piping Weld WIC

-95 Flaw Evaluation TLAA, Open Item 4.7.5 Applicant did not consider the potential of stress corrosion cracking for a flaw that may be connected to pipe inside surface

-Applicant has submitted additional information

-Staff is reviewing the response26 ConclusionThe staff is continuing review to resolve the open and confirmatory items regarding the LRAfor DCPP. Pending resolution of the open and confirmatory items, the staff is working towards issuing the SER.27