ML083440386

Transcript the ACRS Plant License Renewal (Vogtle) Subcommittee on November 5, 2008, Pages 1-222 and Related Handouts

ML083440386
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Site:	Vogtle
Issue date:	11/05/2008
From:	Advisory Committee on Reactor Safeguards
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Brown, Chris 415-7111
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NRC-2523
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Official Transcript of Proceedings NUCLEAR REGULATORY COMMISSION Title: Advisory Comn1ittee on Reactor Safeguards Plant License Renewal Subcommittee Docket Number: (n/a)

Location: Rockville, Maryland Date: Wednesday, November 5,2008 Work Order No.: NRC-2523 Pages 1-157 NEAL R. GROSS AND CO., INC.

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

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

• DISCLAIMER UNITED STATES NUCLEAR REGULATORY COMNIISSION'S ADVISORY COMMITTEE ON REACTOR SAFEGUARDS November 5, 2008 The contents of this transcript of the proceeding of the United States Nuclear Regulatory Commission Advisory Committee on Reactor Safeguards, taken on No~ember 5,2008, as reported herein, is a record of the discussions recorded at the meeting held on the above date.

• .

This transcript has not been reviewed, corrected and edited and it may contain

.

maccuraCles.

• 1 1 UNITED STATES OF AMERICA

• 2 NUCLEAR REGULATORY COMMISSION 3 + + + + +

4 ADVISORY COMMITTEE ON REACTOR SAFEGUARDS 5 SUBCOMMITTEE ON PLANT LICENSE RENEWAL 6 + + + + +

7 VOGTLE ELECTRIC GENERATING PLANT 8 + + + + +

9 WEDNESDAY, NOVEMBER 5, 2008 10 + + + + +

11 The meeting came to order at 1:30 p.m.

12 ~n room T2B3 of Two White Flint, Rockville, 13 Maryland. John Sieber, Chairman, Presiding.

• 14 15 PRESENT:

JOHN D. SIEBER CHAIRMAN 16 GEORGE E. APOSTOLAKIS MEMBER 17 DENNIS C. BLEY MEMBER 18 MARIO V. BONACA MEMBER 19 CHARLES H. BROWN, JR. MEMBER 20 OTTO L. MAYNARD MEMBER 21 HAROLD B. RAY MEMBER 22 MICHAEL T. RYAN MEMBER 23 JOHN W. STETKAR MEMBER 24 JOHN J. BARTON CONSULTANT

• 25 CHRIS BROWN DESIGNATED FEDERAL OFFICIAL NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., NW.

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2 1 CONTENTS

• 2 PRESENTATION BY CHALMER MYER 7 3 PRESENTATION BY LEE MANSFIELD 35 4 REVIEW OF SCR 68 5 PRESENTATION BY DON ASHLEY 69 6 QUESTIONS BY CHAIRMAN SEIBER 139 7

8 9

10 11 12

• 13 14 15 16 17 18 19 20 21 22 23 24

• 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., NW.

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3 1 P-R-O-C-E-E-D-I-N-G-S

• 2 1:30 p.m.

3 CHAIRMAN SIEBER: The meeting will now 4 come to order. This is a meeting of the Plant 5 License Renewal Subcommittee. I am Jack Sieber, 6 Chairman of the Vogtle Electric Generating Plant 7 License Renewal Subcommittee. ACRS members in 8 attendance are Otto Maynard, myself, John Stetkar, 9 Bill Shack, Mario Bonaca, Mike Ryan, Harold Ray, 10 Charles Brown, and our Consultant John Barton.

11 I would point out that Mr. Barton has 12 submitted to us his consultants report dated 10/30 13 which was, to my knowledge sent to all the members.

• 14 15 I got copy of it.

There is a second report which I did not 16 get until today dated October 31st and that can be 17 made available to you during or after the meeting.

18 The purpose of this meeting is to review 19 the license renewal application for the Vogtle 20 Electric Generating Plant, the draft safety 21 evaluation report, and the associated documents.

22 We will hear presentations from 23 representations of the office of nuclear reactor 24 regulation and the applicant Southern Nuclear

• 25 Operating Company.

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4 1 The subcommittee will gather

• 2 information, analyze relevant issues and facts and 3 formulate proposed position and actions appropriate 4 for deliberation by the full committee.

5 The rules for participation in today's 6 meeting were announced as part of the notice of this 7 meeting previously published in the Federal Register 8 on October 22, 2008. We have received no written 9 comment or request for time to make oral statements 10 from members of the public regarding today's 11 meeting.

12 The transcript of the meeting is being

• 13 kept and will be made available as stated in the 14 Federal Register notice. Therefore we request that 15 participants in this meeting use the microphones 16 located throughout the meeting room when addressing 17 the subcommittee.

18 Participants should first identify 19 themselves and speak with sufficient clarity and 20 volume so that they may be readily heard. Each of 21 us has received an application, I think most of us 22 on a disk, but I got one as a printed version 23 probably due to my age and I have reviewed the 24 application and I found it pretty well done.

• 25 We also received the safety evaluation NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., NW.

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5 1 report from the staff. I would point out that the

• 2 safety evaluation report at this stage, at the 3 subcommittee meeting stage is a draft and actually 4 there are two parts. We've got one part on a disk, 5 the second part was sent to us by email.

6 And unfortunately it was beyond the time 7 for our ordinary review process which we expect to 8 improve on. And we also got three pages of comments 9 on our ACRS staff engineers.

10 The license application for renewal that 11 we are to discuss today will follow the requirements 12 of Title 10 Code of Federal Regulations Part 54 and 13 I would point out that the Vogtle Plant Unit 1 is

• 14 15 older than Unit 2 by two years. Unit 1 qualifies for the at least 20-year lifetime for application 16 for license renewal. Unit 2 does not and therefore 17 requires an exemption from Part 53 which I 18 understand the staff is suggesting be approved.

19 I would like to -- as I look around the 20 audience welcome members of the Beaver Valley Power 21 Station staff who are here to watch what happens to 22 Southern Nuclear Operating Company because I think 23 they are next up for license renewal. And so I 24 welcome the Beaver Valley staff to our meeting here.

• 25 I'd like to now proceed with the meeting NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., NW.

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6 1 and I call upon Brian Holian of the Office of

• 2 Nuclear Reactor Regulation to introduce both the 3 staff and the applicants presented, Brian.

4 MR. HOLIAN: Good afternoon, thank you 5 Jack. My name is Brian Holian, I'm the Director of 6 the Division of License Renewal. I'd like to make 7 some quick introductions of the staff and turn it 8 over licensee.

9 This is the third application from 10 Southern Company for license renewal. They 11 successfully received a license for Hatch Farley and 12 now coming before the staff for their final Plant, 13 Vogtle.

• 14 15 To my immediate right is Dave Pelton, the Branch Chief responsible for the Vogtle Plant.

16 To his right Dr. Sam Lee, the Deputy Director in 17 License Renewal. And to the far right Donnie 18 Ashley, the Senior Project Manager who has been in 19 charge of the License Renewal Application in house.

20 There's one other individual in from 21 Region II that I wanted to highlight in the back 22 row, and that's the Senior Reactor Engineer Louis 23 Lake from Division Reactor Safety in Region II 24 responsible for inspection of the Vogtle Plant.

• 25 You'll be hearing a lot more from both Donnie and NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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7 1 Louis after licensee's presentation. Now with that

• 2 I'd like to turn it over to Chalmer Myer, the 3 Project Manager for License Renewal for Southern 4 Company.

5 MR. MYER: Thank you Brian. As I said 6 I'm Chalmer Myer and we are here and we appreciate 7 the Chairman and ACRS members the opportunity to 8 present our application to you this afternoon.

9 To go over my agenda first one of the 10 things I want to do is introduce everybody from 11 Southern Nuclear that's here today and we'll be 12 providing a description Vogtle and a current 13 operating status.

• 14 15 I'll provide highlights of the license renewal project and how we apply the GALL process.

16 There were a couple of items that came up in Region 17 II that we are going to address what actions we're 18 taking and how these will be addressed during the 19 license renewal in the future as well as current 20 Plant operations.

21 For introductions I'd like the gentlemen 22 at the table to introduce themselves.

23 MR. MANSFIELD: My name is Lee 24 Mansfield, I'm the Engineering Support Manager of

• 25 Plant Vogtle.

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8 1 MR. TINER: My name is Todd Tiner, I'm

• 2 the Site Vice President at Plant Vogtle.

3 MR. MYER: In our audience we have 4 David Jones, David is our Vice President of 5 Engineering for Southern Nuclear, and Mark Ajiluni.

6 Mark is our Licensing Manager in Southern Nuclear.

7 And Todd Youngblood, Todd is the Engineering 8 Director at Vogtle. And Mike Macfarlane, Mike was 9 the previous Project Manager for License Renewal.

10 So we brought him in to answer any of the tough 11 questions.

12 And next to him is Wayne Lunceford, he's 13 our Mechanical Representative. Partha Ghosal,

• 14 15 Partha is our Civil Representative.

months ago he was the Chairman of the NEI Civil And until a few 16 Structural Working Group for License Renewal.

17 Cary Martin is our electrical 18 representative. John Hornbuckle is our PLAA 19 representative and KC Harriston is an Attorney 20 through Balch and Bingham who supports our project.

21 And Lou Bohn is another mechanical representative, 22 he's also up here running our backup slides. We 23 have a slide for our presentation.

24 Vogtle is located in Burke County,

• 25 Georgia near the Savannah River.

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9 1 unit site. They are essentially identical.

• 2 Westinghouse four Loop, PWR's they are currently 3 rated for 3625 megawatts electrical.

4 This represents a recent power uprate 5 for measurement and certainty recapture of 1.7 6 percent. Both units are at approximately 1,250 7 megawatts electric.

8 The ultimate heat sink for the plants 9 are the nuclear service cooling water towers. These 10 are seismic category one concrete structures with 11 basins that hold all the water necessary for failed 12 heat sink.

13 The Turbine Plant cycle cooling is

• 14 15 provided by natural draft hyperbolic cooling towers.

They make up for the - the hyperbolic towers is 16 from the Savannah River and make up to the ultimate 17 heat sink is through well water.

18 The Plant was originally licensed to 19 Georgia Power Company. But the current licensee and 20 operator is Southern Nuclear Operating Company.

21 Plant owners, primary owner being Georgia Power 22 Company and other owners are Oglethorpe Power 23 Corporations, the Municipal and Electric Authority 24 of Georgia, and the City of Dalton, Georgia.

• 25 The licensing history for Vogtle the key NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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10 1 elements. We have a construction permit in 1974 and

• 2 we received our operating license in 1987 for unit 3 1, in 1989 for unit 2. We implemented a stretch 4 power uprate of 4.5 percent in 1993 and as I stated 5 then we transferred the license to Southern Nuclear 6 Operating Company in 1997.

7 We submitted our license renewal 8 application in June of 2007. And while that 9 application was in review we submitted and received 10 approval for our measurement uncertainty recapture 11 uprate.

12 The current operating licenses will 13 expire in 2027 and 2029 for units 1 and 2

• 14 15 respectively. This is a two added year for Vogtle.

We completed our 14th refuel outage of unit 1 in 16 April of this year and just completed our 13th 17 refueling outage for unit 2 this last month.

18 MR. BARTON: How long were those 19 outages?

20 MR. MYER: Tom?

21 MR. MYNAN: The unit 1 outage was 22 approximately 40 days. Major drive over the unit 1 23 outage was the structural well overload project that 24 we completed on Vogtle unit 1.

• 25 Unit 2's outage, the counting is still NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., NW.

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11 l o u t on it but I think it was 37 days and five hours

• 2 was the duration of the Fall outage. The original 3 duration for the outage was approximately 28 days.

4 So we had some challenges with the outage.

5 MR. MYER: As I said, both units are 6 currently at 100 percent power. The 18 month 7 capability factor for unit 1 is 92 percent and a 8 little over 90 percent for unit 2.

9 Now, we'll present our license renewal 10 project. I really won't touch on the exemption for 11 5417 C since Dr. Seiber has already talked about 12 that.

I want to talk about a project team and

• 13 14 how the strength of the team has led to our success.

15 We did take advantage of our past experience with 16 Hatch and Farley. Then I'll give some highlights of 17 our scoping and AMR and AMP programs in how we apply 18 GALL to the programs.

19 I'll spend a little bit of time talking 20 about the types of exceptions we had to our Aging 21 Management Programs to help you understand those.

22 One area that's had a lot of discussion 23 I'm sure you're interested in is how we're 24 addressing the metal fatigue and time limit aging

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12 1 minutes. And then talk about how we're implementing

• 2 commitments to ensure that license renewal is 3 carried on beyond the period of extended operations.

4 As Dr. Seiber pointed out we received an 5 exemption from 10 CFR 54.17 C based on similarity 6 between unit 1 and unit 2. And unit 1 did have over 7 20 years of operation prior to the application being 8 submitted.

9 MEMBER MAYNARD: Can I ask why you felt 10 it necessary to apply before the unit 2 got into the 11 window there?

12 MR. MYER: Yes, we have a team that had 13 completed the Hatch and Farley and in order to keep

• 14 15 the team together we needed to move right into Vogtle. It would have been 2009 before we could 16 submit on unit 2. We didn't get an exemption. And 17 to keep the team together and apply that experience 18 we requested the exemption.

19 As I said our license renewal team 20 primarily consisted of personnel that had done 21 Farley, and also several had done Hatch. I don't 22 have the exact numbers on the ones that had worked 23 on Hatch. But about two-thirds of our team had 24 worked on Hatch and about 90 percent of the team had

• 25 worked on Farley.

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13 1 Somebody gave me a count today that

• 2 totaled license renewal experience at the point that 3 we submitted our application for Vogtle was a 140 4 years of license renewal experience on the team. So 5 there was considerable experience there.

6 We added Vogtle myself included in order 7 to apply the knowledge of Vogtle and ensure that the 8 Vogtle needs and plant processes were incorporated.

9 Not only did we bring in that experience at the end 10 of Farley we performed a self-assessment to identify 11 lessons learned or things that we'd like to do 12 better because Farley was a pretty great success/

13 but we didn't want to set on our laurels on that.

• 14 15 So we did self-assessment identified the number of improvements and moved on into Vogtle.

16 And on top of that recognized changes 17 going on and continually changing in license renewal 18 we have stayed abreast of what's going on in the 19 industry. We've had members on all of the Working 20 Groups that I pointed out that one of our members/

21 one of our team members was a chairmen/ I think 22 we've had others through the course of the recent 23 years that were chairmen on different committees.

24 I've been on the License Renewal Task

• 25 force and many of you may recognize me because I've NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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14 1 been to many of these meetings seeing what goes onto

• 2 make sure we were prepared.

3 Additionally, we participated in a 4 number of inspections and audits of our peer plants.

5 So we understood what the NRC was looking for when 6 they came out to do audits and inspections and we 7 supported peer reviews of numerous applicants in the 8 process of developing our applications.

9 So we knew what they were doing and knew 10 and went back and made certain we addressed the same 11 types of issues they were addressing.

12 In order to ensure that Vogtle was

• 13 brought into this process - and we have corporate 14 owners as well as site owners. We had program 15 owners all review their programs prior to submitting 16 the application. We received a number of comments 17 and incorporated them before the application went 18 in.

19 And the program owners were deeply 20 involved in all of the audits and inspections and 21 basically all the comments that came from the NRC 22 were responded to by program owners themselves so 23 they are brought into what's been going on in the 24 future.

• 25 We just wanted to highlight that we feel NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., NW.

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15 1 that all of these activities that we were doing to

• 2 keep our team strong were shown to be successful by 3 the fact that we've got a SER with no open items and 4 no performatory items. We worked very hard to 5 ensure that we respond to the NRC questions and 6 comments.

7 Scoping highlights, we performed our 8 scoping consistent with the NEI 9510 revision six.

9 And revision six was endorsed by the NRC in red 10 guide 1.188 revision one. We used a conservative 11 spaces approach A2 scoping which is consistent with 12 a lot of applicants, I'm not certain all.

13 But it's basic approach basically says

• 14 15 that any non-safety related components or structures located in a space for safety related components and 16 structures is included in the scope regardless of 17 relative location of it's components.

18 Space is defined as a area that is 19 bounded by walls, ceilings, and floors. One of the 20 lessons learned that we brought out of Farley was to 21 include A2 scoping on our mechanical number drawings 22 and in addition to A1 and A3. It helped us to 23 identify in scope components as well as assist with 24 the NRCS's review of scoping greatly because it was

• 25 all in one drawing.

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16 1 And another area of discussion that's

• 2 been pretty active recently has been station 3 blackout scoping. So I just wanted to address for 4 Vogtle, station blackout scoping or systems 5 structures and components is consistent with the 6 NRC's staff guidance and is consistent with the 7 revisions to the ISG's that are under review 8 currently.

9 MR. HOLIAN: Was it that way originally 10 or did you have some discussions?

11 MR. MYER: It's been that way every 12 since they submitted it. Our electrical engineers 13 saw what was happening and actually were in

• 14 15 agreement with the direction the staff was looking for Vogtle. So they implemented that originally.

16 MR. HOLIAN: Good.

17 MR. MYER: Aging management reviews, 18 again we followed the NEI 9510 guidance. We made 19 extensive use of GALL, that's something I didn't 20 mention earlier is that during the revision to GALL 21 our personnel were very deeply involved with it.

22 In fact, we had one who wrote the draft 23 of one of the sections of comments for NEI. And so 24 we were thoroughly familiar with it and made

• 25 extensive use of it. We also were very strict in NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., NW.

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17 l o u r application of whether we would call ourselves

• 2 consistent.

3 If we didn't force fit anything we ended 4 up with 86 percent consistency with GALL. The non-5 consistent items are primarily - we had material 6 environment and aging effects. Primarily 7 environment or aging effect is not in GALL.

8 Looking at these a lot of those will 9 probably be picked up in revision to GALL. But some 10 of them are just unique to Vogtle and I'm not 11 certain would warrant being picked up in GALL and I 12 think other applicants also will have unique 13 environments or aging effects that won't go into

• 14 15 GALL.

MR. HOLIAN: Well, what could have got 16 my curiosity is the nitride-induced stress corrosion 17 cracking from to exposure to auxiliary compound 18 cooling water. And I wonder if somebody could tell 19 me what's unique about your cooling water and this 20 whole phenomena which is a new one to me.

21 MR. MYER: Well, the interesting thing 22 is we are not unique except that we classified it as 23 stress induced IGSCC, that's easier for me to say 24 the letters.

• 25 It has occurred at other sites and they NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., NW.

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18 1 did not conclude that it was IGSCC but the

• 2 phenomenon was the same.

3 MR. HOLIAN: Well how did you finger the 4 nitride as the guilty party?

5 MR. MYER: There are some industry 6 papers that have been written on carbon steel IGSCC 7 and nitride has been the primary cause looking at 8 the various chemistries. I don't have all of the 9 background, it's been a long time since I read all 10 of the research.

11 But back when this was first happening I 12 was throughly familiar with it. And I went through 13 - the odd thing is I went through all of the

• 14 15 chemistry reports for unit 1 and unit 2 because this has only occurred on unit 2. Our chemistry has been 16 identical and we have actually had excellent 17 maintenance of our nitrates and nitrides on both 18 units.

19 So, that in itself would not have been 20 the cause. But there are other agents that feed 21 into this. One of them is an organic substance, 22 plus you have to have high temperature, plus you 23 have to have high stresses.

24 And we have not concluded as to what the

• 25 cause was. But something is unique in unit 2 where NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHoDE ISLAND AVE., NW.

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19 1 we have some organic products as well as all of the

• 2 others coming together.

3 And in particular it has been in high 4 temperature areas that this has occurred such as let 5 down heat exchange and down surge heat exchange. I 6 think there may have been a couple of others, but 7 it's typically going to be where the pipe is warmer 8 than other areas.

9 I won't name other Plants, but there 10 were other plants who have gone through the same 11 thing and replaced the pipe, replaced the components 12 and they just didn't call it this.

MR. HOLIAN: Do change material when you

• 13 14 replace the pipe?

15 MR. MYER: We don't change the material.

16 But we have instituted better weld control. A lot 17 of the problems have been on pipe welds where we 18 have backing rings. So the welding no longer 19 allowed backing rings.

20 We replaced the let down heat exchanger 21 and we went through a lot of stress relief on the 22 welds to ensure that their - the stresses were not 23 as high. So we're basically taking measures in our 24 construction processes to ensure that some of the

• 25 factors that feed into this aren't there.

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20 1 Our license renewal program resulted in

• 2 38 Aging Management Programs at Vogtle, 24 of these 3 were existing and 15 of those required enhancements 4 to meet license renewal requirements. We have 14 5 new programs at the Plant.

6 Of the 38 programs 27 of them have been 7 for GALL programs and those that were GALL programs 8 would have only minor exceptions and I'll talk about 9 those in a moment.

10 Of the 11 class specific programs to the 11 extent possible we still use GALL attributes and 12 defining them. But they were enough different from

• 13 GALL that we called them Plant specific.

14 Our exceptions fell typically into these 15 four areas. I think the first one has been commonly 16 brought up before the committee. The use of a 17 different code of standard. GALL currently 18 identifies specific revisions, specific code years 19 of various standards.

20 For example, the upper standard that we 21 use for stearn generators, they have a specific 22 revision. Inevitably, those standards are going to 23 evolve to incorporate lessons learned, new 24 technologies, and Vogtle's intent is to stay at the

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21 1 latest standards and the latest codes. In fact,

• 2 some of these are even mandated by the regulatory 3 requirements.

4 And so at the time we submitted the 5 application a number of these programs were using 6 later codes of standards than were called out in 7 GALL. They actually in many cases exceeded what was 8 called out in GALL, but they are exceptions.

9 We were fairly conservative in calling 10 out what were exceptions. If we exceeded GALL we 11 called it an exception. And a number of the things 12 I want to point out is where we exceeded what's 13 called out in GALL.

• 14 15 In the area of managed material or environment not in GALL this is specifically where 16 we identified exceptions that were beyond GALL. We 17 have stainless steel that we included in our very 18 piping program. The GALL program doesn't have 19 stainless steel in it.

20 We also included aluminum and elastomers 21 in our external surfaces monitoring program that 22 were not in the GALL program.

23 The amp scope differences. There were a 24 number of types of amp scope differences. Again,

• 25 some times it was beyond the requirements of GALL.

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22 1 Our floor accelerated corrosion program we include

• 2 locations that can't be modeled in that program 3 which is beyond GALL.

4 We also include locations that are 5 subject to wear by methods other than fact in our 6 fact program. One area that we have less scope is 7 that we didn't include our main steam nozzles 8 because of the high sink quality in our sink 9 generators.

10 Then the last was the use of alternative 11 inspection methods. A couple of examples of this, 12 our FAC program allows for opportunistic visual 13 inspections to identify areas where FAC is occurring

• 14 15 that may not have been identified otherwise.

If they open up a valve and see where 16 the downstream of the valve and it's not in the FAC 17 program or it's not subject to inspections in this 18 term they will factor that back into the inspection 19 program. That's actually in - consistent with 20 inset guidance for the FAC program.

21 Another area was our selective leaching 22 program. Recognizing that this is an area where a 23 lot of technology could be developed in the future.

24 We have maintained the ability to implement new

• 25 methods as technology develops in the future.

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23 1 is an area where EPRI is working pretty vigorously

• 2 on for the industry right now.

3 MR. BARTON: I have a question on 4 starting any measurement programs. The section on 5 loss and materials due to pitting and corrosion, 6 partially encased, enclosed stainless steel tanks 7 with exposure to oil or water. I understand your 8 construction to stainless steel line tanks within 9 concrete.

10 But, the question I've got is is there 11 any Aging Management Program in place for the 12 internals of those things, diagrams, etcetera. I

• 13 couldn't find that?

14 MR. MYER: Could you address that. I 15 believe the diaphragms were 16 MR. MANSFIELD: I thought I saw them. I 17 think we have a program for the diaphragms.

18 MR. MYER: We have a program, but I 19 don't -

20 MR. BARTON: Okay.

21 MR. MYER: - but I don't think it's in 22 license renewal, because were they short term?

23 MR. BORN: The tank diaphragms are 24 included in the periodic surveillance and

• 25 preventative maintenance activities.

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24 1 MR. MYER: Okay, all right.

• 2 MR. BORN: As far as the tank internals 3 we got water chemistry, off the top of my head 4 that's all I remember right now. I'd have to look 5 at the specifics.

6 MR. MACFARLANE: This is Mike Macfarlane 7 from Southern Nuclear. The tank diaphragms was 8 actually a lesson learned out of Farley.

9 In fact, that came up in our regional 10 inspection and we carried that forward into Vogtle.

11 Including that was actually something that was added 12 a little later in the game on Farley. Not all tanks 13 have the diaphragm though, so there's

• 14 15 MR. BARTON:

MR. MACFARLANE:

I understand that.

Okay.

16 MR. MYER: As I noted, the time limit on 17 aging analysis for metal fatigue has gotten a lot of 18 attention lately. There's a draft risk on the 19 street that addresses a methodology that uses a 20 single stress tensor versus the six stress tensors 21 that would typically be applied by the code.

22 Vogtle currently uses FatiguePro which 23 was developed by EPRI. And this is a piece of 24 software that does use a single stress tensor. It

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25 1 primarily would be needed when we enter the period

• 2 of extended operation and we would have to apply 3 environmentally assisted fatigue.

4 At this point in time we can do our 5 fatigue management by counting cycles to the design 6 base of cycles and evaluating what effect that has 7 on fatigue. But basically keeping CUF below one.

8 Looking at what's going on in the 9 industry, the technology that we have currently. I 10 know that EPRI is considering upgrading FatiguePro.

11 There's other software out there currently that does 12 use six stress tensors. And we're looking at 18 13 years before we have to have it in place, or

• 14 15 actually 16 since we made a commitment - no it would be 18 because it will be 20 years from now, to 16 have it in place for our period of extended 17 operations.

18 Instead of trying to defend the current 19 version of FatiguePro we've committed to implement a 20 software that will be benchmarked using six stress 21 tensors, or even later technology that's developed 22 at that point. Computers are probably going to be 23 faster and able to do more than they currently can.

24 But we will implement software that is

• 25 endorsed by the NRC or at least meets their NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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26 1 expectations with regards to appropriate stress

• 2 tensors and bench marking.

3 MR. HOLIAN: Using that single compound 4 that is no more correct today than it will be when 5 you renew your license. How large are your margins 6 to your current?

7 MR. MYER: We did some base lining and 8 it was - the factor I believe it was two or three 9 times more conservative than what we were using.

10 But we don't - like I said at this point in time 11 we're not using it as stress based -

12 MR. HOLIAN: You're just counting

• 13 cycles?

14 MR. MYER: We're just counting cycles.

15 We had actually moved in a couple of locations to 16 stress based because we thought that would be 17 appropriate. But we can use cycle counting so we're 18 moving back to cycle counting under our current 19 vices and approach because we're within the bounds 20 of our current design on all of our locations.

21 MEMBER STETKAR: With respect to that 22 though, I had a question because it came up during 23 the staff audit the way that you're projecting 24 cycles for the charging nozzles and let down.

• 25 You're using kind of a creative way of counting long NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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27 1 term operating experience and weighting it basically

• 2 one-fourth of shorter term operating experience.

3 If I understand that's the way you're 4 doing and then projecting, or counting up a number 5 of sort of weighted cycles and then projecting from 6 that.

7 Could you explain a little bit the 8 rationale behind that, because I didn't understand 9 why the specific weighting factors and what the 10 relevance of that whole process is. I mean I 11 understand the results that come out from it, but 12 I'm not compelled by the numbers.

MR. MYER: Well the intent was - and

• 13 14 there was a lot of discussion going on at the time 15 that we submitted our application. But the intent 16 is to write a projection of where the fatigue will 17 be at, in this case year 60 and we're going to be 18 calculating that number at the end of each cycle and 19 if it ever projects based on that algorithm to be 20 greater than one at year 60 then we'll start taking 21 corrective action when it projects at that point.

22 MEMBER STETKAR: I understand, but what 23 I'm asking is what's the basis for that algorithm.

24 That's what's the basis for arbitrarily saying I'm

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28 1 cycles apparently and weight those one-fourth of

• 2 in that algorithm/ weight them one-fourth compared 3 to this other relatively small number of cycles just 4 by virtue of time -

5 MR. MYER: I think part of what you're 6 talking about is the original operation of Plant we 7 went through a number of cycles that we now have 8 modified our operating methods and won't repeat.

9 But Jon Hornbuckle could probably provide more 10 detail.

11 MR. HORNBUCKLE: I'm Jon Hornbuckle/

12 Southern Nuclear. I'm not exactly sure I understand

• 13 what your question is. But if I understand 14 correctly the various locations that we project CDF 15 for we had to go back and back calculate a 16 projection of what the fatigue was up to the time we 17 had data.

18 And then from the time we had data on 19 we've got a calculated CUF and then our projections 20 more heavily rely upon the period of time since we 21 have data.

22 MEMBER STETKAR: That's true/ but my 23 question was in particular/ for some let down line 24 transience your old data are weighted very, very

• 25 low. In some cases they are weighted zero.

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29 1 basically discount the stuff. And the question is

• 2 why I you know what's the basis for that.

3 What's the justification for it because 4 you have a general algorithm that says before the 5 time you had l let me call it relevant operating 6 experience I you generally weight that one-fourth and 7 from whatever that l was that 1995 or I can't 8 remember the year -

9 MR. HORNBUCKLE: Yes l '95 was when we 10 started collecting data.

11 MEMBER STETKAR: --'95 and '98 or 12 something like that. And you wait to post that date 13 three-fourths except in a few cases where you take

• 14 15 the earlier experience and just basically discount it and throw it away I it's weighted zero.

16 And it didn't strike me - I'd like to 17 understand the basis for doing it.

18 MR. HORNBUCKLE: I think l I can't be a 19 100 percent sure without spending a lot of time 20 looking back at the data to understand. But as best 21 I can recall the case you're talking about is the 22 loss of let down cycles where we had maybe 20 times 23 as many during that period of time before we had 24 data as we've had since.

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30 1 had to learn to how operate the Plant and we had a

• 2 lot of those events and we don't have very many of 3 them anymore. And so for as far as projecting the 4 rate of accumulation of cycles since we have data 5 seems like a much more reasonable means of making 6 that projection.

7 And we're not throwing out the others, 8 we're keeping them in our base events in our base of 9 our current CUF. We're just not using them to 10 project how much CUF we're going to accumulate In 11 the future.

12 MR. MYER: Specifically, if we started 13 experiencing more of those events currently we're

• 14 15 projecting a small number because we know that operations has been changed and they aren't 16 occurring.

17 If we started having more events the 18 algorithm would immediately project more events in 19 the future. It would take the recent events and 20 project those as being probable in the future.

21 So, unless we change our current 22 performance the projection really is consistent with 23 what we'd expect in the future. Whereas if it does 24 change, because we're using the heavy weighting on

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31 1 projection plan.

• 2 MEMBER STETKAR: I guess I didn't, ln 3 the things I read I didn't -- you mentioned a couple 4 of times you changed operations performance and that 5 might be a real forcing function for why the 6 frequency is different.

7 In the things I read it more seemed to 8 rely on the fact that you didn't really know how to 9 categorize the previous events that - I didn't read 10 in anything that said that there was a fundamental 11 way, different way of doing operations. It seemed 12 more of a data characterization problem and you

• 13 decided to characterize it as not counted.

14 MR. MYER: I think in the cases of loss 15 of let down there - while we don't have a specific 16 change of procedures the fact that we have a lot of 17 events early on and the events have gone away and 18 also we've had industry experience that pointed to 19 the fact that we needed to cut down the cycles on 20 the let down and charging nozzles we recognized that 21 we successfully, with recent history reduced them.

22 But even if you looked at the algorithm, 23 the one you're talking about one-quarter versus a 24 larger number or three-quarters for the recent

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32 1 events both if the number of events increases or if

• 2 the number of events decreases.

3 MEMBER STETKAR: I understand that, 4 except that that algorithm is applied differently 5 MR. MYER: Right, I understand.

6 MEMBER STETKAR: in a few cases.

7 And the three-quarter weighting is adjusted.

8 MR. MYER: It was basically that when we 9 looked at data that just didn't meet the normal 10 pattern we thought through it and said it doesn't 11 make sense to apply it.

12 MEMBER STETKAR: You changed the

• 13 algorithm?

14 MR. MYER: That's right.

15 CHAIRMAN SIEBER: But, it appeared to me 16 though that the choices you made as to how you would 17 distribute the data was sort of arbitrary.

18 MEMBER STETKAR: That's what more I was 19 getting to is why was the algorithm changed in 20 particular for those 21 CHAIRMAN SIEBER: Yes, I understand the 22 theory.

23 MR. MYER: It was basically an 24 engineering judgement by the stress experts that

• 25 were doing this.

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33 1 CHAIRMAN SIEBER: As engineering

• 2 judgements?

3 MR. MYER: That's right.

4 MEMBER STETKAR: Thanks.

5 CHAIRMAN SIEBER: You did not attempt to 6 go back to the operating history of the Plant logs 7 and so forth?

8 MR. MYER: In order to develop the 9 existing usage yes, we've gone through all the Plant 10 logs and when we first implemented FatiguePro 11 Westinghouse went through all of their Plant logs 12 and identified the number of cycles that they had 13 gone through.

• 14 15 In many cases -

CHAIRMAN SIEBER: But they do have a 16 handle on how many you had?

17 MR. MYER: Yes, we do. In many cases, 18 and this also applies back to that, because we were 19 working off of Plant logs and not actual 20 temperatures we took a conservative view of every 21 one that occurred prior to implementing the 22 software.

23 CHAIRMAN SIEBER: The full cycle.

24 MR. MYER: That's right.

• 25 CHAIRMAN SIEBER:

NEAL R. GROSS Okay.

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34 1 MR. MYNAN: Just so that maybe -- when

• 2 we talk about this operations procedures or how we 3 operate the plant the fundamental difference that 4 came out several years after we went commercial was 5 that we as a station did not understand that when 6 you lost let down our operating principle was to 7 isolate charging.

8 That was what we would do. And what 9 would happen is the charging nozzle of course would 10 be hot, you lose the let down, it cools off and if 11 you isolate the charging distance proximity to the 12 loops it would heat back up and then you put 13 charging back in and it cools back down and then you

• 14 15 put let down in and it heats back up.

So you almost go through three cycles 16 the way for one event. And so we changed our 17 operating procedures on how we address a loss of let 18 down to leave about five to ten gallon minutes of 19 charging above seal injection that we can handle 20 with our excess let down that keeps the nozzle cool 21 so we don't go through two more cycles.

22 That was the predominant driver that 23 allowed us to eliminate a lot of the cycles that we 24 were taking on the nozzles.

• 25 MR. MYER: We have identified 39 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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35 1 commitments that have been made to enhance aging

• 2 management at Vogtle. These commitments were 3 entered in our Vogtle commitment tracking program.

4 This is a database that's fleet wide 5 database used at all three sites and it linked 6 action items, work orders, commitments, and we will 7 also issue a program manual that will link all of 8 these documents so that we have a strong basis to 9 ensure that future owners of the programs know what 10 their commitments are, know what actions need to be 11 taken to make sure that we implement the programs as 12 we enter the period of extended operation.

13 with that I'm going to ask that Lee

• 14 15 Mansfield talk about the results of the Region II site inspection.

16 MR. MANSFIELD: Thank you, Chalmer. We 17 had two inspections in 2008 at Plant Vogtle by the 18 Region. One was during our refueling outage in the 19 Spring on unit 1. One was a team inspection, a 20 license renewal inspection in the Summer in May and 21 June.

22 Out of that came two enhancements to two 23 existing programs. One was the boric acid corrosion 24 control program. One was the full box monitoring

• 25 program. I'll talk a bit about those.

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36 1 The boric acid corrosion control program

• 2 specifically the inspectors, concluded that the 3 program would adequately manage the boric acid 4 corrosion, if any boric acid corrosion issues we 5 might have.

6 However, they did notice, the inspectors 7 noticed a non-boric acid residue in containment 8 deposits on different components that could 9 potentially mask boric acid leaks and boric acid 10 corrosion.

11 This was principally a result of our 12 essential cooling water system, nuclear service 13 cooling water system having a lot of condensation in

• 14 15 containment.

The containment temperatures typically 16 around 100 degrees, this system runs anywhere from 17 65 to 80 depending on the time of year. So the 18 temperature difference results in this uninsulated 19 pipe quite a bit of condensation.

20 And the actual material that we're 21 talking about is trolytriazole which is a corrosion 22 inhibitor that we put in this nuclear service 23 cooling water system. MR. BARTON: So that's the 24 white film that they saw?

• 25 MR. MANSFIELD:

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37 1 white film sir.

• 2 MR. BARTON: That was internal. So 3 unless that leaks in that system?

4 MR. MANSFIELD: That's correct, when you 5 have leaks, you know be they small or large then 6 this condensation which is occurring on, you know 7 like 3,600 or so lanyard feet of pipe spreads it 8 out. So that was the cause, you know it was small 9 leaks and then getting distributed by this 10 condensation.

11 MR. BARTON: How come you guys didn't 12 clean it up before the NRC found it?

13 MR. MANSFIELD: Well, we actually have

• 14 15 been cleaning it up. We have a program in place -

we know coming into outages where we want to go work 16 on our clean up and repair and painting.

17 We also do inspections to see what's new 18 and we re-prioritize it as we come into an outage.

19 So right now it's an ongoing recovery process.

20 We've done it the last several outages. In fact, 21 I've got a picture coming up here I'll show you what 22 we know we can do as far as recovering the piping.

23 I'll go ahead and tell you the 24 corrective actions. Some implemented and some being

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38 1 every outage, cleaning, repainting. And I'll tell

• 2 you our inspections are at the beginning of the 3 outage and then at the end of the outage.

4 MR. HOLIAN: And the leaks are from 5 valve packing or something?

6 MR. MANSFIELD: Valve packing, it could 7 be from a flange connection. It could be minor 8 leaks over the years from our containment coolers 9 that our service water passes through.

10 So, there's nothing real prevalent about 11 what the leak is. But any time it happens it's got 12 this material in it. It's out in the atmosphere and 13 it turns white.

• 14 15 MEMBER MAYNARD: And the coolers themselves, don't they have a drain system through 16 the -

17 MR. MANSFIELD: Yes sir, the coolers 18 have a collection system that's part of our textbook 19 monitoring for containment leakage. And but the 20 collection system is really centered under the two 21 bundles and not on the ends. And when we've had 22 leaks they've been on the ends coolers.

23 So that collection system wasn't telling 24 us, it doesn't tell us through the cycle that we've

• 25 got, you know leakage on those coolers.

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39 1 have any leakage on those coolers right now. We

• 2 have over the years, but we've also had, you know 3 minor leaks and packing of flanges etcetera.

4 We have made procedure changes to ensure 5 that in our boric acid corrosion control program 6 that, you know the owners and the site personnel 7 recognize that, you know because of this 8 configuration and the potential for leaks there 9 could be some masking. So, we don't want them to 10 get complacent about what this white material is.

11 We've also done, we've also done enhanced 12 communication with out personnel through briefings

• 13 during the outage, through communications, you know 14 electronic communications.

15 We've also, we are also putting in our 16 training programs specific issues, you know specific 17 topics about this because as we go through this 18 recovery period we want to make sure no one ignores 19 any of these locations.

20 On our boric acid corrosion control 21 program now that really wasn't necessarily focused 22 on this before is clearly looking at all of those 23 issues when their looking for boric acid leaks only 24 to make sure that we don't confuse two and ignore

• 25 the wrong one.

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40 1 This first photo is just an example of

• 2 what this white material looks like. You know boric 3 acid is white and crystally. And at a distance this 4 staining looks like it could possibly be the second.

5 And you see some corrosion there on the bulking 6 materials.

7 MEMBER STETKAR: Back up, what are we 8 looking at. I recognize the pipe but, it looks like 9 we're looking at the bottom side of some concrete.

10 It's an eye beam, it's hard to figure out how 11 leakage from pipes get under the bottom side of an 12 eye beam.

MR. MANSFIELD: Well are we looking down

• 13 14 or are we looking up?

15 MR. MYER: It drips down and hangs there 16 and then evaporates and then you leave the deposit.

17 MEMBER STETKAR: So the leaking pipe is 18 somewhere out of site above the eye beam?

19 MR. MANSFIELD: Yes, I mean there's 20 as I said there's a tremendous amount of this pipe 21 and this piping goes through a lot of components and 22 containment.

23 The next picture is just an example 24 though of how we're -- where the process of recovery

• 25 area is. We attacked the most prevalent issues and NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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41 1 the ones most likely to mask boric acid corrosion.

• 2 And we clean, we repaint, we replace materials as we 3 need to.

4 CHAIRMAN SIEBER: What you are doing is 5 cleaning up and painting things, but the leaks are 6 still there. And what are you doing to fix the 7 leaks?

8 MR. MANSFIELD: Well I tell you, there's 9 two things. We're evaluating, insulating all of 10 that piping which is a big job and a big deal. But 11 we have that in -

12 CHAIRMAN SIEBER: What will that do, 13 mask the leaking?

• 14 15 insulation?

MR. BARTON: Collect the leakage in the 16 CHAIRMAN SIEBER: Right.

17 MR. MANSFIELD: Just to keep the 18 condensation from occurring on the piping. Not to 19 stop the leakage out of the system. All right, the 20 leakage out of the system is you know part of our 21 normal inspection and maintenance.

22 MEMBER MAYNARD: Minimizes the spread of 23 24 MR. MANSFIELD: That's exactly right.

• 25 MEMBER MAYNARD:

NEAL R. GROSS

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42 1 eliminate it.

• 2 CHAIRMAN SIEBER: Well, the basic 3 problem is this leak, okay. And the problem that 4 appears on the surface is you've got a lot of 5 residue, okay.

6 So you're cleaning up the residue, but 7 what I want to know about is how you're fixing the 8 basic problem?

9 MR. MANSFIELD: The - you want to add 10 to this Tom?

11 MR. MYNAN: Yes, the biggest issue that 12 we have with this particular system is the 13 dissimilar metals that we have on the coolers

• 14 15 themselves. The header joints are made of stainless steel while the tubing is made out of cooper.

16 And the braising of the tubes to the 17 distribution header, the braising is coming loose.

18 Now the tubes are flared inside the header. So as 19 long as the system remains pressurized the flair 20 kind of seals it off and the leaks appear to go 21 away.

22 The problem is when we get to outages or 23 what not if we shut the train down and the internal 24 pressure reduces inside these coolers they have a

• 25 tendency to leak when we start the system back up.

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43 1 We have a long range plan for

• 2 replacement of all of these coolers with an 3 alternative type to get rid of the dissimilar metal 4 welds. It is a tremendous job in that we have eight 5 containment coolers and two aux coolers and I think 6 on each containment cooler we have 16 sub-coolers.

7 So, in the interim, as we kind of rank 8 the level of leakage of the coolers from 9 unacceptable to we can tolerate and replacing them 10 with the existing designs if we have spares. And in 11 the long range plan we intend to go replace these 12 coolers with an alternative type to eliminate the

• 13 issue.

14 So, but it's a dissimilar weld issue.

15 They are on the ends. They are not in the 16 collection tank. And, you know this particular 17 issue is a lot more prevalent if you look at the 18 joints up on the tubes themselves. So that's my 19 understanding of where we're at.

20 The reason I know about this is that 21 when this came up in the Spring my organization took 22 this very seriously and I personally went in and 23 looked at all of the issues inside unit 1 and make 24 sure I understood the magnitude of the issue.

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44 1 got with our engineering director Todd Youngblood

• 2 and with Lee and said what are the different issues 3 here, what are we looking at, what do we do going 4 forward and you know we came up with a pretty 5 aggressive plan to clean up, insulate, and then 6 integrate into the plan the replacement of these 7 coolers over the long range life of the plan.

8 MR. BARTON: Notice of violation always 9 got my attention too.

10 MR. MYNAN: You know its, you know when 11 I went in and looked at it, I mean I go into 12 containment every outage. I've looked at it a 13 thousand times and it just didn't strike me as an

• 14 15 issue and it's because you live it day in and day out.

16 When you have an external person come in 17 and point it out it's like hey, and ask that 18 question and a light bulb goes on. You know it took 19 us all back and said whoa, you know we need to go 20 after this.

21 And I did go in and inspect level two in 22 the Fall outage. So I understand the issue and I 23 assure you that we've got money and plans in place 24 to address this issue.

• 25 MEMBER MAYNARD:

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45 1 around the cooler itself. But if you were

• 2 considering insulating a lot of pipe, which to me 3 indicates that you also must be having some leakage, 4 I won't call it significant, but you must have 5 leakage in other locations.

6 And if were just right at the cooler it 7 looks like you would be able to isolate that in ways 8 easier than insulating all of your piping area.

9 MR. MANSFIELD: I mean we do have and 10 have had leaks on valves, packing leaks, gwinet 11 leaks, etcetera on that essential cooling water 12 system that is away from the cooler. So the answer 13 to your question is yes.

• 14 15 And it's not that there is a particular problem there, it's such a big system with so many 16 components and is in so much of containment that 17 when there is a leak in these coolers as Tom said, 18 there's so many of them and they are spread allover 19 and there's leakage from a cooler and then you know 20 it can be spread a lot of different ways on the way 21 down.

22 CHAIRMAN SIEBER: Do you think 23 insulating pipes will mask the leakage so that you 24 have nice clean looking insulation going on

• 25 underneath?

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46 1 MR. MYER: This is stainless steel pipe.

• 2 And so we wouldn't be masking going on inside. And 3 in fact the purpose of the insulation as I said, 4 stops the condensation so that there is no spread.

5 If we have leaking valves and other 6 leaking components that's picked up as part of the 7 normal inspections of the system.

8 MR. MYNAN: The piping that we have the 9 biggest problem with - which our contractors like, 10 is we actually pipe in chill water into our 11 containment during the fueling outages and basically 12 air conditioned containment.

13 And it goes to one specific cooler and

• 14 15 it's at the highest elevation in containment and but it's also the largest. And that particular 16 piping is the one that sweats the most and it's 17 during the refueling outage.

18 And it looks really bad because of the 19 measures we've got to take to try to collect all the 20 condensation that drips down to the lower levels of 21 containment and the spread of contamination.

22 So, that's the one we want to go after 23 first, although we do see issues I would see when 24 it's hot out and it gets cold out and the

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47 1 some evidence on all the other piping as well.

• 2 But I don't think that's as big an issue as this 3 chill water piping.

4 MR. MANSFIELD: I agree, I agree.

5 CHAIRMAN SIEBER: Well I lived in 6 Augusta for a couple of years, I know it gets hot.

7 MEMBER STETKAR: Let me ask you one 8 thing. I think you took an exception to visual 9 inspection of the reactor vessel at boric acid 10 corrosion because of stainless insulation or 11 something like that, accessibility for high dose or 12 something like that, is that correct.

• 13 I was curious as to what fraction or 14 where -- you know what fraction of the service area 15 and here that insulation was. The sense that I had 16 it was some sort of localized area.

17 MR. LUNCEFORD: Wayne Lunceford, 18 Southern Nuclear. The situation is that there's 19 less than one percent of the head that you cannot 20 see if you do not remove the reflective metal 21 insulation on the top head.

22 And so there's about, I believe a ten 23 man room of dose that's required to access this.

24 Less than one percent of the head and you can see

• 25 360 degrees around every head penetration, you can.

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48 1 And so the less than one percent is away

• 2 from those areas where the leakage would initiate.

3 And so that was a relaxation from the older 4 requirements.

5 MEMBER STETKAR: I just wanted to -

6 thanks.

7 MR. MANSFIELD: The second issue brought 8 up by the inspection was the water fountain in the 9 pull box. We have - our in scope median voltage 10 cables at Vogtle are all in tunnels and aren't 11 subject to getting water in them or near them with 12 one exception and that's where this pull box came

• 13 into play.

14 We have non-safety related 4 KV cables 15 that run out to our high voltage switch yard for 16 switching that supports station black out. In fact 17 Lou, if you'll put that picture up there.

18 Here we go. I'm going to step up here 19 because our pointer is not working too well.

20 MR. MYER: You can't do that Lee. You 21 need to stay here where the mic is.

22 MR. MANSFIELD: All right.

23 MR. MYER: I'll point to it.

24 MR. MANSFIELD: There you go. What

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49 1 to our left looking at the picture and our low

• 2 voltage switch yard is to the right. So the Plant 3 is to the right.

4 We have a two feeder cables coming from 5 unit 1 and unit 2 that come out from right to left 6 on this picture and come out to that pull box that 7 has the four cones on it. Then those two cables 8 come over and feed these two 4160 to 480 volt 9 transformers and then the power is fed out to the 10 high voltage switch art for switching operations.

11 Water was found in the pull box there 12 with the cones on it. And our corrective action for 13 that is we now have a quarterly inspection pump out

• 14 15 if necessary of that pull box. We also are trending the results from that and that's really to make sure 16 that quarterly is often enough.

17 MR. BARTON: That program has been 18 implemented?

19 MR. MANSFIELD: The program is in place 20 now.

21 MR. BARTON: Thank you.

22 MR. MANSFIELD: Yes sir.

23 MEMBER STETKAR: You're still doing 24 though just the ten year insulation check on those

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50 1 need to increase the frequence of the insulation?

• 2 MR. MYER: No, at this time -- this 3 would be consistent with what other plants have 4 found, because these are non-safe related they are 5 in station blackout. So we implement the testing, 6 ten year testing as part of license renewal as we 7 prepare for licensee period.

8 Now there's no expectation right now 9 that they have any problems based on industry 10 experience. But we are - knowing that these 11 emergents would be questionable in the future we're 12 going to work to keep them dry.

13 MEMBER MAYNARD: What's the source of

• 14 15 the water.

MR. MANSFIELD: I'm going to ask for our 16 support. I don't believe that we have, that we know 17 for sure that the source of the water other than 18 ground water leaking into the box.

19 We don't believe it's leaking in from 20 the top through rain water. Would you like to add 21 to that?

22 MR. MARTIN: Cary Martin with the 23 Electrical Group. The water that's coming into 24 those boxes is ground water. Those boxes were not

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51 1 proofing on them.

• 2 They are just concrete boxes and ground 3 water can seep into them. Many of them have little 4 one by one sumps to collect the water at the bottom 5 and let it drain away. But this one is not working 6 and we're going to work on it.

7 MEMBER STETKAR: You mentioned and the 8 inspection report also mentioned that the safety 9 related cables are in tunnels and therefore they are 10 not susceptible to water intrusion. There is actual 11 operating - you don't find any water in those 12 tunnels at all, drains.

• 13 MEMBER MAYNARD: These particular cables 14 - I believe that they were providing power to the 15 switch house to support switching when you need to 16 recover your off site power.

17 MR. MANSFIELD: That's correct.

18 MEMBER MAYNARD: They are not 19 instrumentation type cables that are actually 20 providing some power. But it is not a main power 21 cable.

22 CHAIRMAN SIEBER: You don't happen to 23 have a drawing of your switch art schematic?

24 MR. MANSFIELD: We have it in the cable.

• 25 It's 2.1 -

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52 1 MR. MYER: It's really hard to see

• 2 CHAIRMAN SIEBER: yes, I know. I 3 brought this. So 2.1-17, that's even harder to see.

4 I take it you have two off site power sources?

5 MR. MYER: That's correct. Cary, you 6 want to -

7 CHAIRMAN SIEBER: One goes to Clark Hill 8 Reservoir through Augusta and the other goes to 9 South West of the Plant. Is that correct?

10 MR. MYER: I believe that's correct.

11 That's - I can't remember the name of the line now, 12 but yes.

CHAIRMAN SIEBER: When you define the

• 13 14 scope of station blackout, saying the scope of 15 license renewal where on that chart do you say is in 16 scope and - you know I see the dividing line that 17 is the theoretical dividing line between the high 18 voltage and the plant type switch gear.

19 But I'd like to know where your 20 restoration circuit is for station black out on that 21 chart.

22 MR. MARTIN: Cary Martin again. It goes 23 all the way out to the power circuit breakers. The 24 230 kV power circuit breakers.

• 25 CHAIRMAN SIEBER:

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53 1 there and go through it because there is a bunch of

• 2 3 MR. MARTIN: It's a red color and the 4 feeder cable goes in between two 230 kV breakers and 5 we actually included both of those breakers in the 6 scope because there wasn't a preferred line up. So 7 we actually have both of these are in and then this 8 is the other source.

9 It comes up here and again it's between 10 two 230 kV power circuit breakers. So we included 11 both of those. So we actually have four breakers.

12 CHAIRMAN SIEBER: And so you're looking 13 -- you're Aging Management Program for that is the

• 14 15 passive parts of it.

MR. MARTIN: That's correct.

16 CHAIRMAN SIEBER: The foundations and 17 support -

18 MR. MARTIN: The breakers are in scope, 19 but they are screened back.

20 CHAIRMAN SIEBER: Okay, I can see why I 21 couldn't find it on here because yours is colored.

22 This one is not, okay. Could you, while you're 23 relaxing back here take a pencil or something and 24 color that in for me.

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54 1 colored copy.

• 2 CHAIRMAN SIEBER: Even larger, okay. I 3 would take a regular full sized.

4 MR. MYER: We actually will give you a 5 copy of this drawing at the completion of this. We 6 have one of the handouts. Anything we've shown you 7 on this screen we're going to have you a copy of.

8 So you'll have that one.

9 CHAIRMAN SIEBER: Well, you can see the 10 source of my confusion.

11 MR. MYER: Yes, now I understand.

12 CHAIRMAN SIEBER: Okay.

13 MR. MYER: In summary, we had -

• 14 15 MR. BARTON:

MR. MYER: Yes.

I have a question.

16 MR. BARTON: It's on the inspection 17 report items. Your inspection report talks about a 18 past of numerous leaks in varied fire protection 19 piping.

20 Now, my question to you is what's the 21 cause, poor insulation, unstable ground, whatever.

22 But what are you doing to ensure that you have 23 reliability of your underground buried fire 24 protection piping, because the question I got after

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55 1 do I know that this piping isn't going to fall apart

• 2 because of poor insulation or whatever.

3 Whatever the root cause of all of these 4 leaks is. I don't understand. Can you tell me, 5 talk about that a little bit?

6 MR. MANSFIELD: We have a buried piping 7 program in place right now where we used to do 8 inspections on a number of systems including fire 9 protection. So that's in place as we speak.

10 We do periodic pressure testing of the 11 system. I don't know, and I'll ask for some help if 12 anyone knows. I don't know if we have a root cause

• 13 for the leakage other than it's carbon steel piping 14 buried underground. I'm sorry, cast iron piping.

15 MR. MYER: Going back through the 16 history of the Plant I guess initially there were 17 probably a number of poor insulation items that came 18 up and were fixed early on.

19 A lot of the art is not in the seismic 20 backfill and so there is some amount of settling 21 that's going to be expected as you have in about any 22 kind of mechanical cast iron joints.

23 And so periodically we have some leakage 24 of them. I know that we - the complainant

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56 1 identify them when their small leaks. But any leaks

• 2 that would start to have an impact on the system 3 shows up through the jockey pump coming on more 4 frequently or running continuously.

5 And all of those monitorings will drive 6 them to start searching for leks. There is 7 technology out there now and I know the Plant has 8 used it to go out and find leaks that are not 9 showing up above ground. And they are doing that.

10 They are pretty aggressive in keeping the system.

11 MR. BARTON: Do you really monitor the 12 fire protection planting which has a history of 13 reflecting leaks. Do you view their program and are

• 14 15 satisfied that they are doing an adequate program on fire protection planting. You made an issue in your 16 reflection report of various leaks in the piping 17 system over a long period of time. SOl I don't 18 where you guys stand on it.

19 MR. LAKE: My name is Louis Lake l I was 20 the lead inspector for the NRC inspection. We 21 looked at their Aging Management Program and their 22 current programs in monitoring the fire protection 23 and we find that the programs are adequate.

24 We actually did do a visual inspection

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57 1 protection piping to look at the condition internal

• 2 in the pipe separate from the mechanical connections 3 of the cast iron.

4 And the condition -- internal condition 5 of fire protection piping at the site was, it almost 6 looked pristine as if it was brand new. So, there 7 - as far as looking for leaks as a result of failed 8 piping aside from the mechanical connections I think 9 their program that they have identified in their 10 Aging Management Program and their current fire 11 protection program surveillances are adequate in 12 identifying any problems with the fire protection 13 system.

• 14 15 MR. MYNAN: I would just add, in this particular area we have a fairly, we've had a number 16 of issues is we've had the main header that goes all 17 the way around the perimeter of the power bar. But 18 then we have a number of lines that tape off and go 19 to remote locations within the owner patrolled area.

20 The main one, that's the long one goes 21 out to our fire training facility which is almost a 22 mine through the pine trees and all the way out 23 there.

24 What we have observed is when we start

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58 1 water hammer that occurs down on that end of the

• 2 piping which is where most of the leaks, in fact we 3 just had a pretty significant one here a few months 4 back that actually caused a big sink hole in the 5 parking lot. But that's where we're seeing the 6 issues when we talk about the majority of the leak 7 issues that we have.

8 The reason we're kind of trying to 9 manage our way through it a little bit more rather 10 than just fixing a piece at a time and not fix the 11 bigger issue is we're trying to work through the 12 interface with a potential for new units because 13 this line goes right across the foot print for the

• 14 15 new operating units.

So we're trying to decide does that, do 16 we need something separate or do we want to put 17 something interim in to try to manage this issue and 18 then meet the needs for potential units on Vogtle 19 three and four, so that's my understanding of the 20 biggest issue we have with underground piping.

21 MEMBER MAYNARD: Okay, do you have the 22 ability to isolate that fire?

23 MR. MYNAN: Yes, we do. But when we do 24 it we take a hit on our insurance because it also

• 25 goes to our warehouse.

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59 1 MEMBER MAYNARD: I understand, but I'm

• 2 worried about the impact on Plant fire protection.

3 MR. MYNAN: Yes, we can isolate it and 4 we don't have - in fact, this recent one we had 5 outside the gate we were in a 24-hour shut down 6 until we could get the line isolated and then 7 recover the line piping within the power block.

8 So, but we have several post indicator 9 valves that we can isolate and isolate that section 10 of the piping. But as I mentioned we don't like to 11 leave it isolated because it's an issue of 12 insurance.

MEMBER MAYNARD: Looks like it's

• 13 14 important to resolve that for both the commercial 15 and safety standpoint.

16 MEMBER MYNAN: Yes, yes I agree with 17 you.

18 CHAIRMAN SIEBER: I have a couple of 19 more questions to ask. One of them relates to 20 license renewal and one is a result of curiosity.

21 Relating to license renewal, underneath 22 your Plant is about a thousand foot thick lens of 23 sand down to bedrock. What steps do you take to 24 measure the settlement of Plant buildings

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60 1 up with stresses and stains from piping and conduit

• 2 and so forth that go from building to building?

3 MR. MYER: We've got a pretty extensive 4 monitoring program. We've got about 160 points that 5 we monitor. They've been monitoring them since day 6 one. I believe now all but 16 of them are on a five 7 year cycle because settlement has reduced to a level 8 that we've got approval for five years and 16 are 9 still on a one year cycle.

10 CHAIRMAN SIEBER: But you have seen 11 settlements since the Plant was built?

12 MR. MYER: Yes, and as would be expected 13 early on it was significant and it's leveled off.

• 14 15 And like I say, most locations it's now been so quiet that we've gone onto a five year cycle.

16 CHAIRMAN SIEBER: You do that with 17 surveying instruments or highway survey type 18 instruments?

19 MR. MYER: I'm not sure if it's highway, 20 but it's Georgia Power Company does it, yes.

21 CHAIRMAN SIEBER: Right, it's highway.

22 I would presume that the settlements that you 23 measure are relative to some base point in the 24 Plant?

• 25 MR. MYER: That's right, we'll measure a NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., NW.

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61 1 base point and then we'll use targets on buildings

• 2 that are built off that one base point. And that 3 base point, it's relative location does tend to some 4 times bury from measurement to measurement with the 5 overall site. But all of the readings are off the 6 one base point.

7 CHAIRMAN SIEBER: That would be my 8 concern.

9 MR. MYER: Right.

10 CHAIRMAN SIEBER: And the other concern 11 is the frequency with which you measure because it 12 does impact the structures.

MR. MYER: Right.

• 13 14 CHAIRMAN SIEBER: And you -- I'm sure 15 you have from seismic reconstruction -- separation 16 between buildings with the seal in between?

17 MR. MYER: In all the locations we have 18 allowable differential settlement all redefined 19 based on the stressing in the piping. It's been a 20 couple of years since I looked at the data, but we 21 really haven't had much relevant settlement.

22 But there were only a handful that the 23 stresses were even to 50 percent of the allowable 24 for the differential that we had.

• 25 CHAIRMAN SIEBER:

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62 1 on to all the other stresses.

• 2 MR. MYER: Yes, that was 50 percent of 3 what we allowed in settlement which is a small 4 margin of the stresses we have -

5 CHAIRMAN SIEBER: Of the total stresses 6

7 MR. MYER: Right.

8 CHAIRMAN SIEBER: piping can take.

9 Now my curiosity question is, the picture the 10 planter I take it's a submerged right behind the 11 cooler point?

12 MR. MYER: That's correct.

• 13 CHAIRMAN SIEBER: And behind the - or 14 beyond East of the Savannah River is the Savannah 15 River Plain with the Department of Energy?

16 MR. MYER: That's correct.

17 CHAIRMAN SIEBER: And on the horizon 18 there I can see a white building?

19 MR. MYER: That is the cooling tower for 20 the K-reactor.

21 CHAIRMAN SIEBER: Is that a hazard 1n 22 your emergency plan?

23 MR. MYNAN: No, it was never placed in 24 operation.

• 25 CHAIRMAN SIEBER:

NEAL R. GROSS Okay.

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63 1 MR. MYNAN: They spent $300 million

• 2 dollars and then cancelled the production program.

3 CHAIRMAN SIEBER: It actually doesn't 4 operate that way?

5 MR. MYNAN: No.

6 CHAIRMAN SIEBER: Okay, thank you, I've 7 also been there and I thought that's what it was but 8 I didn't know whether it was operation or not. But 9 you're supposed to take into account hazards that 10 are close to your Plant and or nearby on 11 transportation. Savannah River doesn't have a lot 12 of transportation, so -

MR. MYNAN: No, we actually meet with

• 13 14 them every six months with their emergency response 15 team is pretty interesting mainly because of the 16 number of deer hunters that they have over there and 17 how they can manage it.

18 But when we meet with them actually the 19 hazardous material to have over there doesn't really 20 pose any sort of large area release threat to our 21 station.

22 Believe it or not, I know it's kind of 23 surprising the first time they told me, it's because 24 of all the tension on the ground, you know we

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64 1 we meet with them.

• 2 CHAIRMAN SIEBER: Your emergency plan 3 coordinated so that the incident that your plant you 4 notify them?

5 MR. MYNAN: Yes, yes.

6 CHAIRMAN SIEBER: And they take action, 7 okay.

8 MR. MYNAN: Like I said we drill with 9 them at least once a year. But then we also 10 interface with them twice a year, once at our site, 11 and then we actually meet at their emergency 12 response. All of the emergency directors go over 13 and meet with them at their response center.

• 14 15 CHAIRMAN SIEBER:

35 miles to the Northeast?

Now, Barnwell is about 16 MR. MYNAN: Well, yes.

17 CHAIRMAN SIEBER: Okay, thank you.

18 MR. MYER: In summary, as I shared we 19 had a very experienced team that created a high 20 quality license renewal application. We made 21 extensive use of the GALL and we're very familiar 22 with it.

23 We had what I would consider thorough 24 and successful audits and inspections of the Plant.

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65 1 license and renewal team was highly responsive to

• 2 the NRC and I think that was exemplified by us not 3 having any open items or confirmatory items. And we 4 believe that Vogtle is prepared to manage aging 5 beyond 40 years, thank you.

6 MR. BARTON: I have a question.

7 MR. MYER: Yes.

8 MR. BARTON: You had a chemistry upset 9 or something with steam generators a while back. I 10 don't remember the details of that, but do you still 11 have the original steam generators or have you 12 changed them out?

13 MR. MANSFIELD: No, we still have the

• 14 15 original steam generators.

MR. BARTON: So have them for another 16 okay, no reason to change them as you see in the 17 future?

18 MR. MANSFIELD: There may be a change 19 out in the future, but we don't anticipate it at 20 this point based on the degradation we're seeing on 21 the tubes and on the structure.

22 MR. BARTON: All right, I just wondered 23 with the chemistry upset whether it was some long 24 term damage and you saw a need to replace it. Okay,

• 25 thanks.

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66 1 MR. HOLIAN: Do you use sink injections?

• 2 MR. MANSFIELD: We do.

3 MR. HOLIAN: And you've been doing that 4 for a long time?

5 MR. MANSFIELD: What the last cycle of 6 the generator, is that about -

7 MR. MYNAN: We did mid-cycle injection 8 because of issues we saw with AOA if we tried to do 9 beginning of cycle. This recent core design on 10 Vogtle one we started zinc injections at the 11 beginning of cycle and we started zinc injections on 12 unit 2 as well so we could get full cycles since 13 injection on primary side. So, these would be the

• 14 15 first operating cycles that we've full cycle zinc injections.

16 MR. MACFARLANE: Just to touch on your 17 question about steam generators. Now this is Mike 18 MacFarlane with Southern Nuclear. And we did do a 19 chemical cleaning on the secondary side of that 20 generator, those generators.

21 And also the Vogtle has the monolyth 22 generator which has the thoroughly treated 600 tubes 23 and stainless steel support plates. And so it is a 24 little bit of a generation beyond what the early

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67 1 CHAIRMAN SIEBER: Not good enough.

• 2 MR. MACFARLANE: Well I understand that, 3 but that's why at this time it still hasn't had the 4 problems that some of the others have had yet.

'5 MEMBER MAYNARD: Are all the tubes 6 thermally in yield?

7 MR. MACFARLANE: That's correct.

8 MEMBER MAYNARD: Well some of the 9 earlier ones -

10 MR. MACFARLANE: They are thermally 11 treated as opposed to mechanical yield. I mean the 12 term for those tubes would be thermally treated.

CHAIRMAN SIEBER: Any other questions

• 13 14 from the committee members?

15 (No response.)

16 CHAIRMAN SIEBER: If not we'll rule a 17 bit early, but the chance are we may finish early.

18 So, I'll like to take a break until five minutes 19 after 3:00 p.m.

20 (Whereupon, off the record from 2:43 21 P . m. until 3: 0 5 p. m. )

22 CHAIRMAN SIEBER: I'd like you all to 23 take your seats so that we can continue our 24 meeting. And I'd like to return to Brian to say

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68 1 review of the SCR. Brian?

• 2 MR. HOLIAN: Good, thank you. Just a 3 couple of items before I turn it over to Don 4 Ashley, the Senior PM in charge of Vogtle.

5 One is really I wanted to commend 6 Donnie also as he's here as we've had Plants 7 extend into ASOB proceedings and the like, 8 Donnie's had not only Vogtle application but 9 also the Oyster Creek application. So you know, 10 a lot of work on his plate and I just wanted to 11 highlight that to the committee.

12 MEMBER MAYNARD: Did he deserve all that 13 punishment.

• 14 15 MR. HOLIAN:

with that, how about that.

And he's coping just fine The other thing I wanted 16 to mention and I did mention the staff here and I 17 just wanted to mention we do have a lot of technical 18 members from the staff, both branch chiefs and 19 technical members from the technical divisions also.

20 I won't mention them.

21 But just remind them as they get up and 22 answer questions to make sure you give your name and 23 division for the record.

24 The other item I wanted to mention was,

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69 1 even on the licensee slides they mentioned 39

• 2 commitments and you might notice from our list in 3 Appendix A there's 41 numbered there.

4 Most of you probably caught that there 5 were two numbers missing. So really technically 6 there's only 39 there, numbers through 41 and that's 7 part of the tech editing that we still picked up 8 that you didn't see, but we are finalizing and 9 picking up those kinds of corrections. So, the 10 commitments do match 39 and I just want to just 11 mention that.

12 And finally, I did want to highlight to 13 the committee you do have us back again tomorrow for

• 14 15 a license renewal status update.

just the program in general.

We'll be covering Things like the IG 16 report, things like the GALL update where we're 17 going with that, license renewal guidance documents, 18 how we're updating that for both us and the industry 19 and also touching on schedules and what we have in 20 house. So we look forward to that tomorrow 21 afternoon also.

22 And with that I'll turn it over to 23 Donnie Ashley.

24 MR. ASHLEY: Thank you sir, good

• 25 afternoon, my name is Donnie Ashley.

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70 1 Manager for the Vogtle Electric Generating Plant

• 2 license renewal project.

3 I along with other members of the staff 4 will discuss our review of the Vogtle license 5 renewal application as documented in the draft SER 6 which you've been provided.

7 I'll begin with a brief overview of the 8 application itself and the renewal effort followed 9 by the scoping and straining review results. The 10 audit inspections, the audit and inspections will be 11 discussed next. Mr. Louis Lake who you've met 12 already is a lead inspector for the Region II 13 Inspection Team and he's here to discuss that

• 14 15 inspection result. I'll then continue with the discussion of the SER audits and results of sections 16 three and four of the SER.

17 The renewal application was submitted in 18 June of 2007. As was mentioned earlier the unit 2 19 Vogtle only had 18 years experience and the reg's do 20 indeed require 20. The applicant requested and was 21 granted an exemption in January 2007 to that 22 requirement or prior to the submittal of the 23 application for both units.

24 The application was accepted in August

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71 1 at that time. Subsequent to the receipt of the LRA

• 2 the measurement uncertainty recapture that Mr. Myer 3 spoke of earlier was granted and that changed the 4 power level from what was shown in the application 5 from 3565 megawatts thermal to 3625.

6 On the safety evaluation report the 7 staff was aided with audit reviews and additional 8 information provided by the applicant in response to 9 87 RAI items, and a 173 audit questions from the 10 audit itself.

11 These audit questions make up the Q&A 12 database which was included in the audit summary

• 13 report that was provided to you.

14 When considering notes A through E of 15 the AMR line items we've got approximately 87 16 percent of the line items as being consistent with 17 GALL.

18 The information collected from the audit 19 and RAI responses were used extensively in the 20 development of the draft SER. And as Brian 21 mentioned, in actuality of the 39 commandments the 22 applicants did not use two numbers when the 23 application was submitted.

24 We changed Appendix A in our working

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72 1 number ten and commitment number 22 were not used at

• 2 Vogtle. The SER contained no open items and no 3 confirmatory items.

4 MR. BARTON: I have a question, does SER 5 section 33225 talk about hardening and loss of 6 strength due to elastomer degradation. And there's 7 a discussion in there and I thought I read the SER 8 was issued, had been issued without this item being 9 resolved and yet I only find the open line. Was 10 this issue resolved?

11 MR. ASHLEY: It came up as a RAI during 12 the audits and at the time that the draft was made 13 that had not been finished. But subsequently, the

• 14 15 next paragraph -

MR. BARTON: Okay, because I kept 16 looking for an open item. This stated that this was 17 not resolved at the time, all right. But it is 18 resolved?

19 MR. ASHLEY: It is now sir.

20 MR. BARTON: Okay.

21 MR. ASHLEY: As Brian mentioned and as 22 part of the comments that you had provided back on 23 review of some of the staff you did see some editing 24 remarks in the draft and those have subsequently

• 25 been removed and corrected.

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73 1 MR. BARTON: Thank you, that's half the

• 2 one I listed comments against you guys. But, since 3 you said you've taken care of all of that I guess I 4 won't bore you with them later and they will remain 5 in my report because I won't take it -

6 MR. ASHLEY: It just gives you room for 7 others. The specific audit -- excuse me, I'm on the 8 wrong slide here. In the audit and review, the 9 audit summary report, I'm sorry was made publicly 10 available in September of '08 and it includes the 11 review results, the Q&A database, and the list of 12 the documents that were reviewed by the team.

13 MR. BARTON: Did your summary report

• 14 15 have any meat in it or was it just 62 pages of things that you reviewed, but did not get the whole 16 report?

17 MR. ASHLEY: The Q&A database was the 18 vast part of it. It's a little different than what 19 you probably have seen in the past. It's now a 20 summary report and I believe that Brian will 21 probably be talking about those later on rather than 22 a input directly to the SCR that you -

23 MR. BARTON: I just wanted to know value 24 it was because all I got was 62 pages with a lit of

• 25 all the documents you reviewed at the site.

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74 1 don't know what value this is.

• 2 MR. MEDOFF: To address your comment, 3 this is Jim Medoff of the staff, I'm acting brand 4 chief for Jerry Dozer today whose the branch priest 5 for the technical review staff. And I'm also the 6 senior technical reviewer for Vogtle.

7 With respect to the audit summary report 8 we did it a little bit of different for Vogtle 9 because we were changing our process to the new 10 processes so that it's commending with the Beaver 11 Valley application.

12 So for vogtle, for the audit report the decision was made to only list give you a list of

• 13 14 the documents we looked at and to include the 15 question list that we sent to the applicant and put 16 their responses that they submitted back to us in 17 the audit report.

18 And then to address the questions that 19 we asked during the audit we wrote them up in the 20 SCR product. So, any of the questions that you see 21 in the database should be written up in the SCR.

22 MR. ASHLEY: Section 2 of the SCR 23 discusses structures and components subject to the 24 aging management review. It has to do specifically

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75 1 application and it covers the plant level scoping

• 2 results of the relevant systems and structures.

3 The staff found the results by the 4 Applicant also meet the review criteria in the 5 standard of view plan and in accordance with the 6 agency.

7 In the structures and components section 8 for 2.3 there was 98 mechanical systems, 34 of which 9 were balance of plant systems. The staff believes 10 that the available guidance that the applicant used 11 in identifying such components is adequate.

12 There was three opponents added to the 13 system. The non-ESF, Exhaust Fan Housing, and unit

• 14 15 heaters were added as a missile barrier function to make up air duct for the electrical vent system has 16 an A-2 scoping issue. And the chiller compressor 17 components, housing filters and dryers were added to 18 the scope as a result of RAI's.

19 In Section 2.4 in scoping and screening 20 there was no emissions of structural components 21 within the scope of license renewal. 2.5 and 22 electrical instrumentation and control we again saw 23 no emission of electrical and instrumentation 24 components that we didn't scope.

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76 1 go ahead and discussion the inspections.

• 2 MR. LAKE: My name is Louis Lake, I'm a 3 Senior Reactor Inspector from Region II of the 4 division of reactor safety. And I was the 5 inspection team leader for the on-site inspections 6 for license renewal.

7 MR. BARTON: I have a question, the 8 cover letter on the inspection report stated the 9 Plant equipment was being maintained adequately.

10 MR. LAKE: Yes.

11 MR. BARTON: My question is, and I'm not 12 trying to be smart here. Does that mean the 13 equipment is being maintained in accordance with

• 14 15 your expectations or barely satisfactory?

MR. LAKE: No, it was in accordance with 16 our expectations.

17 MR. BARTON: Now, the reason I ask you 18 that is because on page two of the report they say 19 the Plant equipment is being maintained adequately 20 "in most of the Plant."

21 MR. LAKE: Yes.

22 MR. BARTON: What does that mean?

23 MR. LAKE: Well, we went on further to 24 clarify that due to the results of previous NRC

• 25 inspections inside containment that resulted in the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., NW.

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77 1 notice of violation that the condition of the

• 2 components inside containment weren't necessarily 3 something that we could ignore and we felt we had to 4 address.

5 Now, the reaction by the licensee 6 satisfied our concerns and the corrective actions 7 that he is taking also satisfied what our 8 expectations were.

9 MR. BARTON: So it was really pertaining 10 to the issue you found with the white stuff in the 11 container?

12 MR. LAKE: That's correct.

13 MR. BARTON: All right, because I was

• 14 15 wondering -- I wanted to make sure you weren't talking about, you know like out buildings or 16 auxiliary buildings other than the main power block 17 that you didn't find conditions there to your 18 expectations. I just wanted to make sure that's not 19 the issue.

20 MR. LAKE: That is not the issue.

21 MR. BARTON: Okay.

22 MR. LAKE: This slide is kind of left 23 over from some previous, older presentations and 24 it's geared towards ACR's members who may remember

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78 1 when we did our onsite inspections.

• 2 And basically they have been revised and 3 our scope for the onsite inspections were reduced 4 when it came to reviewing the components that 5 belonged in the license renewal program.

6 We used to almost duplicate what NRR did 7 in identifying components. And since then the 8 manual chapters 2516 has been revised. It was about 9 three or four years ago. And we now concentrate and 10 put our focus on 10 CFR 54.482 situations which are 11 specifically, we are non-safety related components 12 that could effect safety the way the equipment

• 13 functions.

14 We put our resources towards that 15 review. And again, this may be a slide that has 16 fulfilled it's purpose up to this point in time. I 17 think most of the CRS members probably remember the 18 revision in this scoping, but that was the intent of 19 this slide.

20 NRC inspection manual chapter 2516, it 21 provides the policy and the guidance for the review 22 and inspection activities associated with license 23 renewal inspections. And the NRC staff verifies the 24 accuracy of the license Aging Management Program

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79 1 renewal under 10 CPR part 54.

• 2 Now, the inspections that are referenced 3 ln the manual chapter are conducted in accordance 4 with inspection procedure IP 71002. And it's to 5 verify that the applicants license renewal program 6 including the support activities are implemented 7 consistent with the requirements of 10 CFR part 54.

8 This includes the guidance that requires 9 us to prepare and submit an inspection plan. We 10 also schedule our inspections to support the NRR 11 review in a culmination of a draft SER.

12 The resources that we use consist of a 13 team typically of five members. However, I was

• 14 15 fortunate in having the support of seven inspectors and the reason for this is that it facilitated the 16 training of new license renewal inspectors and also 17 the sharing of inspections between regions.

18 The team included one inspection from 19 Region I and one inspector from Region III. Also 20 included in our team was a member of the ACR staff 21 who not only observed our activities but also 22 participated by conducting some of the inspections.

23 I'd like to thank Chris Brown for his 24 excellent support during the inspections. The

• 25 objective of these inspections are focused on the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., NW.

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80 1 Aging Management Programs and it's to confirm that

• 2 the existing Aging Management Programs are working 3 well and also to examine the applicants plans for 4 establishing new Aging Management Programs and/or 5 enhancing existing ones.

6 The inspection is typically two weeks in 7 length and those two weeks are separated by a week 8 back at the regional headquarters in Atlanta where 9 we review what we had found up to that point in 10 time. And also maybe revise our plans for the 11 remaining inspections.

12 We review the 100 percent of the 13 applicants Aging Management Programs. The

• 14 15 inspection requirements and the inspection procedure requires that the sample programs, that we had 16 enough staff and resources and time that we did all 17 38 management programs.

18 And we did that to verify that the aging 19 effects will be managed so that there is reasonable 20 assurance that the intended function would be 21 maintained consistent with the current licensing 22 basis throughout the period of extended operation.

23 We also interviewed personnel and we 24 examined records. The records of past tests,

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81 1 actions from the existing Aging Management Programs.

• 2 Also, we examined implementation plans 3 for existing programs new and expanded Aging 4 Management Programs. We verified the inclusion of 5 future tasks were included and established in site 6 task commitment tracking systems.

7 We also verified material conditions of 8 the plant was being adequately maintained by 9 conducting plant walk downs, including walk downs of 10 the containment during outages when the containment 11 was open.

12 Now the containment was not open during 13 our inspection, it was only open that -- by

• 14 15 refueling outage prior to our inspection for unit 1 and unit 2 was after our inspection. I'll go 16 through that discussion later.

17 The Aging Management Program inspection 18 was conducted on site from May 19th to June 6, 2008.

19 As I said before with the week in Atlanta for 20 documentation review and analysis.

21 The inspection team concluded that 22 existing programs are generally functioning well at 23 the aging management portions of the license renewal 24 activities were conducted as described in the

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82 1 that aging effects would be properly managed

• 2 throughout the period of extended operation.

3 In walking down Plant systems and 4 examining Plant equipment the inspectors found no 5 significant adverse conditions except for some 6 degradation noted in material condition of surfaces 7 inside containment due to general corrosion that 8 I'll cover in more detail later. It appears plant 9 equipment was being adequately maintained.

10 The applicant had established 11 implementation plans in the action requests system 12 to track the committed future actions for license 13 renewal to ensure that they are completed.

• 14 15 We concentrated heavily on that issue because their extended period of operation is so far 16 away you're talking about 2027, and you know this 17 system needs to be very comprehensive and be able to 18 track that, you know they do what they said they 19 were going to do when the time comes.

20 We did not have an observation on that 21 and recommended that they do make some enhancements 22 in that and be clearer on what they put in their 23 implementation program.

24 Region II will follow up with future

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83 1 and we'll be using inspection procedure 7003 and

• 2 inspection scheduled after license application 3 approval and just prior to the period of extended 4 operations.

5 MEMBER STETKAR: In the SER you mention 6 only, back to the cable issue again, you mention 7 only the two year inspection requirement for the 8 underground cable. I looked for - since the 9 applicant apparently made a commitment to change 10 their inspection philosophy I looked to see how that 11 was referenced in the SER and it isn't.

12 The SER talks only about ten year

• 13 inspection events, you know testing of insulation 14 and the standard two year inspection. Under the 15 discussions of operating experience, under 16 discussions of inspection results and things like 17 that.

18 I was curious why that information 19 didn't filter into the SER for that particular 20 program?

21 MR. ROGERS: May I help with that one?

22 MR. LAKE: Sure.

23 MR. ROGERS: I'm bill Rogers, I'm in the 24 division of license renewal in the interim review

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84 1 extensively by the staff and we really have it

• 2 divided up into two areas.

3 The current Plant operation which is 4 currently in the part 50 basement, also under 5 license renewal. And it's being addressed in both 6 areas. If the inspection team is doing inspections 7 to find the adverse conditions that might be 8 addressed by the region during current operation.

9 In addition, at headquarters the 10 division of engineering, the electrical branch, is 11 also issued some generic communications in this area 12 related to water in the manhole and cable conditions 13 in general.

• 14 15 One of those is generic letter 200701 which was inaccessible or underground power cable 16 failures that disabled accident mitigation systems 17 or caused plant transients. And that was issued on 18 February 7, 2007. And that generic letter requested 19 of the licensee's was to provide us information 20 specifically to cable failures. And part of that 21 would be due to significant moisture or submergence.

22 The licensee's have all responded to 23 that generic letter, that information is being 24 gathered, it's currently under review by a division

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85 1 position on, I guess on our analysis and review of

• 2 that.

3 Now, in license renewal space for part 4 54 the staff has addressed the water in the manhole 5 issue and the corresponding raceways in the GALL 6 report which is Section 1183 which relates to 7 inaccessible cables.

8 And part of that section requires that 9 if you are to use that program that you do the two 10 testing points which one is prior to the point of 11 extended operation and one is to follow-up ten years 12 later during the period of extended operation.

13 So, the three points of 1183 requires,

• 14 15 as I said the cable tested prior to the period of extended operation to determine functionality. And 16 it's significant moisture determined during the 17 required periodic inspections of the manholes.

18 Then the period of this inspection would 19 be required to be increased accordingly. And the 20 corrective actions would expect to be taken to 21 remove the water when discovered.

22 So that is our staff's position on the 23 two different periods of operation. Does that help?

24 MEMBER STETKAR: partly except that the

• 25 SER makes no mention of a variable inspection NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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86 1 frequency for water accumulation as a function of

• 2 operating experience. It just says the inspection 3 team looked at the operating experience and the 4 staff has found the two year inspection frequency to 5 be acceptable.

6 MR. ROGERS: Okay, maybe I can get 7 someone else to address that specifically.

8 MR. LAKE: Just to elaborate on that too 9

10 MEMBER STETKAR: I understand the 11 difference between current operations. But I'm 12 looking at this document which is, you know SER MR. LAKE: I was going to say that -

• 13 14 MEMBER STETKAR: - 19 years from now or 15 whatever it is supposed to apply to.

16 MR. LAKE: - I was going to say in our 17 inspection report itself I think we refer to them 18 going to a quarterly frequency. And then if 19 conditions permit they can then go to the two year.

20 MEMBER STETKAR: And I guess my 21 curiosity is why that didn't get reflected back into 22 the SER, because as I read the SER I could have 23 taken verbatim what they had in the license renewal 24 application and pasted it in here and it's pretty

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87 1 which I think is useful information.

• 2 MR. ASHLEY: Part of that is timing.

3 During the issuance of the inspection report and the 4 creation of the draft. Also, Roy Mathew -

5 MR. MATHEW: This is Roy Mathew from 6 Electrical Grants. When I was in the license 7 renewal branch I did review this program. During 8 our audit we looked at the two cables that was in 9 the scope of this program.

10 During that time frame we didn't see any 11 water. So you didn't reflect anything in the AeR.

12 But if you look at the AMP, Aging Management Program they have to inspect

• 13 you see they had to maintain 14 the manholes for a period of at least a minimum of 15 two years and their collective action is supposed to 16 take care of the frequency. If the applicant finds 17 water in the manhole they have to adjust the 18 frequency accordingly.

19 So the water issue was not discussed in 20 the SER because at that time we didn't have any 21 information or the operating experience that 22 reviewed suggest that they had water. So, the 23 Region subsequently they did the inspection. They 24 found they identified the water issue.

• 25 MR. HOLIAN: This is Brian Holian, I'd NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.w.

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88 1 expect, other than the timing issue, that we could

• 2 pick that up in the SER and make it complete story 3 of it. So I accept that -

4 MEMBER STETKAR: It is truly a timing 5 issue, although there is 6 MR. HOLIAN: -- I accept that. You 7 know, that shows that coordination I think it's 8 known to the staff. But for completeness we'll take 9 that comment. I agree in expanding that inspection.

10 MEMBER STETKAR: I find the inspection 11 is really, really useful. But I hope that the 12 results from those inspections and commitments based 13 on those instructions are actually folded back into

• 14 15 the SER.

MR. MATHEW: But, I want to make a 16 point. Inspections are identifying issues with the, 17 you know manholes that's being in the water. We are 18 from the electrical branch part of part 50 19 activities. The licensees are expected to maintain 20 the cable qualification to the environment that they 21 are ~n.

22 So, part of the part 15 regulatory 23 requirements they ask supposed to qualify those 24 cables for that, if it is finished under subversive

• 25 conditions.

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89 1 MR. HOLIAN: This Brian Holian again.

• 2 Billy Rogers mentioned that and the staff sometimes 3 tries to cut it between part 50 and part 54. And I 4 think what the committee is looking for is a, you 5 realize that might be acceptable according to the 6 GALL criteria, but put reality and truth into what 7 their program is like at the site. So, you know we 8 can expand that.

9 MR. LAKE: Okay, during our inspections 10 you identified some enhancements I'd like to 11 discuss, at least two of those enhancements and 12 they've been discussed at length earlier by the 13 licensee, but I'd just like to give you our

• 14 15 inspection results as we saw them.

And specifically the AMP, the Aging 16 Management Program for medium voltage non-safety 17 related cables it's a new program that commits the 18 licensee to establish a program to take periodic 19 actions to prevent normally energized medium voltage 20 underground cable from a manning submerged in water 21 for a long period of time.

22 At this point I'd like to say that the 23 cable that was used for these 4 kV lines, the two 4 24 kV lines in question was not designed for

• 25 continually being submerged.

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90 1 information from the licensee.

• 2 And there are only two underground 3 cables in the scope of the program that run from the 4 turbine building to the 4 kV switch yard as was 5 presented earlier.

6 Those cables go through three pull 7 boxes. I know that they showed you one, that was 8 the one that probably had the most water in it.

9 But, there were two others that did have water in 10 it. And we identified those and these tables are 11 needed as they stated for recovery from loss of off 12 site power.

13 And originally the applicant had

• 14 15 established a once every four year preventative maintenance task of pumping any existing water from 16 electrical cables outdoor pull boxes. I know that, 17 you know we identified that this four year 18 frequency, when it came to the Aging Management 19 Program was revised to two years. And Plant records 20 show that cable pull boxes at this Plant are often 21 found with various amounts of water. That the three 22 that contained the 4 kV cables in the scope of the 23 licensee renewal program were just pumped in June of 24 2007 and again during our inspection in 2008.

• 25 And Plant records reflect a history of NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., NW.

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91 1 repeated attempts at establishing different measures

• 2 to prevent pull boxes from flooding or to 3 periodically remove water.

4 The applicant enhanced their program and 5 the Aging Management Program to initially inspect 6 the pull boxes as we stated before on a quarterly 7 basis. And to consider modifications to prevent 8 continual unacceptable flooding.

9 MEMBER STETKAR: In your inspection 10 report I thought it mentioned that you though, or at 11 least there was some indication that it was actually 12 rain water initiated because the covers on the pull

• 13 boxes weren't water tight.

14 MR. LAKE: And they aren't.

15 MEMBER STETKAR: But you didn't say it 16 was groundwater related. There are different 17 implications there.

18 MR. LAKE: There are, and their pull 19 boxes, the covers to those pull boxes are not 20 sealed, they are not water tight. However, I think 21 the way they are designed, the amount of rain water 22 that can get in will be minimal.

23 But it doesn't totally exclude it. And 24 I think that was the intent of making that statement

• 25 in the inspection report.

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92 1 MEMBER RAY: Well wait a minute. If it

• 2 is groundwater what's the relevance of how often 3 they pump it out. Let's suppose you pump it out 4 once a month and it fills it back up the next day 5 until whatever the groundwater level is.

6 What's there's nothing to answer the 7 question how long the cables are sitting in water 8 here. Just because you pump it out once a month, 9 once a year, once every two years, once - what 10 difference does it make?

11 MEMBER BROWN: It seems to me in fact 12 that the cables should be qualified for immersion 13 because it is frequently found immersed in water.

• 14 15 MEMBER RAY:

hours after you pump it out.

Yes, it may be immersed six What-16 MEMBER BONACA: And furthermore, I mean 17 even if we recognize this as a part of a license 18 renewal program the question I have is will you do 19 something about it now in this current 20 years of 20 operation. I mean that's the best practice I would 21 expect, you know if the program is unacceptable as 22 is, when you go to license renewal you've found that 23 it probably is unacceptable now.

24 MR. LAKE: We asked that question during

• 25 our inspection and they have -

NEAL R. GROSS yes Chalmer?

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93 1 MR. MYER: I need to interject because

• 2 Cary in using the term -- this is Chalmer Myer and 3 Cary Martin had used in the term groundwater was 4 really referring to water that goes into the ground 5 from rain.

6 The groundwater level at vogtle is not 7 that high. So this is not normal groundwater that 8 we're not going to have the pull box refilling 9 everyday from groundwater. But his terminology was 10 getting to the top when you have a heavy rain just 11 the ground itself is soaked, it's going to come into 12 the pull box.

13 MEMBER BROWN: Did you inspect it

• 14 15 everyday for months to make sure that's the circumstance, you just saying the groundwater is not 16 -- you know it's below the bottom of the pull boxes 17 MR. MYER: We do know the groundwater 18 I don't have the water level at the site. But we do 19 know it's well below that level, yes.

20 MEMBER BONACA: We have been told in 21 previous meetings on the same issue that the concern 22 here is the wetting and drying. Okay, and the 23 frequency of wetting and drying which means your 24 challenge is the cable because of this condition.

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94 1 immersion. And here you have the condition where

• 2 you are likely to have the sequence of the wetting 3 and drying the cable.

4 MR. LAKE: Perhaps my presentation might 5 lead you to believe that they always find these 6 cables emerged. What we intended to present was 7 that the pull boxes have water in them, not 8 necessarily submerging the cables every time it's 9 inspected.

10 However, it was -- one of the pull 11 boxes, the one that they put up in the picture when 12 we did the inspections, the cables were submerged.

13 As far as we could tell that was the

• 14 15 only time in looking at previous results of their inspections that the cables actually were submerged.

16 But, as part of that corrective action 17 what they are doing is more frequently looking at 18 the pull boxes for evidence of water. The cables 19 that were in the pull boxes where they weren't 20 submerged looked, from a visual inspection because 21 we were able to look at them, as being in good 22 condition. It didn't seem like they were constantly 23 being wetted and dried and wetted and dried.

24 However, the fact that there was some

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95 1 some action.

• 2 CHAIRMAN SIEBER: Well with the number 3 of times that this has come up, now I think we're 4 dealing with a generic issue as much as we are a 5 Vogtle issue. I also think we're dealing with a 6 current operation issue as much if not more so than 7 license renewal.

8 I think the staff is working on this, 9 but my concern is, most of what I keep hearing 10 relative to inspections and things don't really 11 address how often in the wetting and drying of the 12 cable and stuff. If we look once a month we really

• 13 don't know what happened in the meantime there.

14 I think part of the staffs pursuit in a 15 -- first of all we need to determine what is the 16 safety significance of this. And then the other is 17 what programs are really needed in the collective 18 and then taking care of it because I haven't heard 19 anything that convinces me from any of the Plants 20 that the inspection period -- you know how do we get 21 to that and assure ourselves that that inspection 22 period is adequate. I haven't heard anything yet, 23 so I'll -- I do have as much of a generic issue as 24 anything.

• 25 MR. HOLIAN: It is, NEAL R. GROSS this is Brian Holian COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., NW.

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96 1 again in license renewal. I'm aware of a couple of

• 2 items. This has come up at previous meetings here.

3 George Wilson, the branch chief for electrical is 4 not here. But Sheila Raz is back, but two things, I 5 know that we're working a draft generic letter on 6 this. I know they've got NEI's attention. So we 7 are looking at it as a part 50 issue. Go ahead.

8 MR. MATHEW: Okay, we are going to issue 9 generic letter, response summary report. That will 10 be issued within a week or so. That will capture 11 some of the recommendations the staff has.

12 Based on the research we found there are 13 286 failures and these failures have been increased,

• 14 15 the 20th going up. So, the staff is planning to issue a regulatory guide that stipulates the 16 attributes for a condition monitoring program for 17 cables.

18 So, this will address - right now there 19 are no guidance in the industry to provide what 20 consists of a good cable monitoring program. So 21 that's one recommendation that we have.

22 The second recommendation that we have, 23 we are planning to revise the technical oversight 24 process procedures to provide additional guidance to

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97 1 manholes, how they deal with -- if they found water

• 2 in the manholes and the cable qualifications.

3 The third thing we are trying to do lS 4 we are going to advise the region staff to continue 5 issuing enforcement, part of the part 50 6 regulations. Interesting regulations occurs, 7 licensees to maintain their qualifications to 8 cables.

9 So, there are regulations that are 10 occurred to be followed under the current licensing 11 term. So these are some of the recommendations and 12 you will be seeing the report most likely within a 13 week.

• 14 15 MEMBER RYAN: One of the things that I think is important is to maybe think of this from a 16 geo-sciences perspective as well as the engineering 17 perspective.

18 We've used a lot of terms like 19 groundwater rain water, infiltration, saturated 20 zone, aquifer and all of that. And all of those are 21 in different places in Vogtle I'm sure.

22 So, I think it's important for the staff 23 to work with the licensees that have these issues 24 and really come to a dictionary that you can all

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98 1 say x, whatever x might be like groundwater.

• 2 I know a little bit about the 3 groundwater in that part of the country from being 4 in South Carolina at Ten Nuclear for about almost 15 5 years.

6 A one inch rain, a five inch rain, and a 7 ten inch rain, and a 17 inch rain which I monitored 8 once all have different impacts on these kind of 9 near surface systems and containments.

10 So, a single rain event doesn't trigger 11 it. A half inch rain event may not be important.

12 But a three inch rain event may be important, or a 13 cumulative rain event over a month of some number

• 14 15 versus some other number. Those kind of things I think you need to think carefully about because just 16 going out and saying monthly and doing an inspection 17 may be meaningless to really understanding trends, 18 because the trend is not based on the calendar. The 19 trend is based on water falling out of the sky.

20 So, I think, I just offer you that 21 insight that some of the geo-sciences folks that may 22 be in the other branches or, you know you can call 23 on, I would say particularly the low-level waste 24 branch there with a few folks that might be helpful

• 25 to give this problem a little shape so that the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., NW.

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99 1 licensees can say, oh if we do these types of things

• 2 we can really, you know understand what's physically 3 happening in the system.

4 And I guess I leave you with that 5 thought. What you really want to find here is 6 what's the system you're trying to understand the 7 behavior of. And it's a little bit more complicated 8 than just a monthly inspections of is there water in 9 the sump or not.

10 MR. MATHEW: Actually what we had 11 planned to do is the engineering staff is working 12 with the research staff to come up with the regulatory guidance. We expect to issue this by

• 13 14 the end of the next year, that's the plan.

15 We have obtained the necessary feedback 16 on the guidance we're going to issue. Again, the 17 concern the staff has if a cable is submerged and if 18 the cable is not qualified for that environment the 19 cable can deteriorate with an inadequate monitoring 20 program you cannot tell how the cable is going to 21 perform.

22 MEMBER RYAN: And again, that's kind of 23 the engineering side of if it's wet is that a safety 24 significant issue and how much and what were the

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100 1 something that's of interest to the staff.

• 2 And then how do you get measurables or 3 indicators that really tell you we've got a huge 4 problem, a little problem or a episodic issue that 5 we can deal with in some simple way. That's really 6 when you get to define how the system is behaving 7 and it's not just the matter of annual rain fall.

8 It's even driven.

9 Whether or not a basin fills up is based 10 on has it been dry for six months and now we have 11 three inches of rain or we had three inches of rain 12 every month for the last six months. That's a big 13 difference in how these sumps are going to respond

• 14 15 in terms of filling or not filling.

So, I just offer that insight to maybe 16 give you some things to think about as you begin to 17 study the problem and come up with measurable that 18 will be meaningful to the staff and understandable 19 for the licensee.

20 MEMBER RAY: The pull boxes isn't 21 necessarily the only point that water can accumulate 22 the conduits between the pull boxes fill up with, 23 water and you never see it in the pull boxes.

24 In the case of Vogtle do we know if

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101 1 MEMBER STETKAR: Yes, they are because

• 2 the screening criteria requires them to only look -

3 in scope has to be energized greater than 25 percent 4 of the time.

5 MR. MATHEW: But, actually for license 6 renewal purpose the scope of cables are really 7 limited. In case of Vogtle not only two cables in 8 the scope of license renewal.

9 MEMBER RAY: And I understood that part, 10 but I just wondered if these are normally energized?

11 MR. MATHEW: Yes, these are normally 12 energized because these are the power supply to all 13 the control circuits, or you know the model upright

• 14 15 disconnectors and 480 volt control panels in the search yard. So they are all energized all the 16 time.

17 MEMBER RAY: So, it's better in that 18 they normally energized than that they are not 19 energized obviously?

20 MR. MATHEW: Right.

21 CHAIRMAN SIEBER: I'm confident this 22 will be resolved by 2027 when they -

23 MR. HOLIAN: Well you're a confident guy 24 are you.

• 25 MEMBER STETKAR:

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102 1 I haven't seen the -- I haven't read the generic

• 2 letter I listed here. When you asked the licensees 3 for their experience you mentioned 200 some odd 4 number of cable failures.

5 What was the scope of information that 6 you were asking for. Was it safety related cables, 7 was it cables that are normally energy, you know -

8 MR. MATHEW: We asked the licensees to 9 provide information of the power cables where all 10 tech categories, you know, AC, DC , all outages.

11 Within the scope of maintenance rule. That was the 12 criteria that we used.

So, if a cable is occurred to me a

• 13 14 safety function or some function part of the 15 maintenance rule then they have to look at those 16 cables. So, it went beyond the safety letters.

17 MEMBER STETKAR: Okay, thanks.

18 MEMBER BROWN: This is they are 19 separated by being underground and buried or over 20 head -

21 MR. MATHEW: No, these are all 22 underground, all buried, right.

23 MR. LAKE: The next item that I wanted 24 to discuss was what was again was discussed by the

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103 1 containment.

• 2 I can start out with the boric acid 3 program. In doing so I'd like to pass these two 4 photos around. There's a photo and a angle globe 5 valve showing what that white residue looks like on 6 a component. And the second photo really is a gate 7 valve where you do you have boric acid leaking, 8 however minor you have it leaking from the packing 9 and that's to represent how you could easily 10 mistaken boric acid in this residue.

11 Now during the past unit 1 refueling 12 outage which occurred before our inspection NRC

• 13 walked down the containment, identified a white 14 crystalline coating in significant portions of the 15 containment.

16 This condition was also identified on 17 unit 2 during a recent NRC inspection, but that was 18 conducted subsequent to our license renewal 19 inspection.

20 The coating was found on an emergency 21 core cooling accumulators. The coating was also on 22 the containment decking, on valves, piping supports, 23 bolting, electrical boxes. It was on pretty much 24 anything you could see in the containment and these

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104 1 is typical in both containments.

• 2 The white residue is similar to boric 3 acid residue in that it diminishes the ability to 4 detect boric acid leaking as previously described 5 and discussed at some length by the licensee.

6 But, also what we'd like to discuss is 7 we identified general corrosion caused by large 8 amounts of condensation from chiller leaks. Chill 9 water piping as discussed previously during outages 10 sweat quiet a lot and do cause a lot of corrosion in 11 containment. And the corrosion can be seen on 12 structural steel, grading, on valves, bare piping, 13 piping supports, bolting, electrical cable, junks

• 14 15 and boxes as represented by the photos that I'm passing around.

16 Now, as a result of the white residue 17 and it's interference with our boric acid 18 inspections there was a, what's termed a green non 19 sited violation for inadequate procedures in the 20 boric acid program. That was issued and it was 21 incorporated into our inspection report for that 22 outage.

23 Now, this type of violation is very low 24 safety significance and mainly we determine that

• 25 because they do do chemical sampling on the white NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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105 1 residue to determine it's not boric acid and we

• 2 haven't identified any real corrosion as a result of 3 the white residue.

4 Also, they have long term improvement 5 plan as mentioned previously. They have assigned a 6 manager to a project. They are creating the 7 repetitive task to identify corrosion issues in the 8 containment. They are issuing the communications to 9 the Plant on the issue.

10 They gradually are performing corrective 11 maintenance on the areas of the corrosion as 12 presented earlier. And they are going to determine 13 techniques to remove the film if they can.

• 14 15 I know that they are looking into that.

They don't want to go ahead and just abrasively 16 remove this film because you could do more damage 17 trying to remove the film than not. And I we 18 determine that trying to remove the film does 19 require a lot of evaluation to determine the right 20 way to do it.

21 And they are also developing designs to 22 insulate the piping that's causing all the 23 condensation during outages and prevent sweating of 24 that piping.

• 25 CHAIRMAN SIEBER:

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106 1 found, I think according to the applicant was due to

• 2 an additive that they are adding to the cooling 3 water?

4 MR. LAKE: That's correct, the chiller 5 system has a chemical additive and apparently when 6 that does leak and evaporates it leaves this white 7 crystalline coating.

8 CHAIRMAN SIEBER: I should perhaps -

9 MR. LAKE: That's not easily removed 10 unfortunately.

11 CHAIRMAN SIEBER: Yes, I should have 12 probably asked the applicant this question. But is 13 there some other chemical additive you can use to

• 14 15 accomplish the same purpose that doesn't leave the film?

16 MR. LAKE: I've seen other chemicals 17 used at other Plants, but I think we'll ask if the 18 applicant has considered other chemicals.

19 MR. MYER: I think first of all this 20 treatment is highly successful in doing what it'S 21 supposed to do and the residue in the containment as 22 Louis pointed out -

23 CHAIRMAN SIEBER: Do two things 24 successfully.

• 25 MR. MYER: But it also is -- it has not, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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107 1 it doesn't have a corrosive effect in the

• 2 containment. It does have the problem of appearing 3 to be boric acid which actually based on our 4 corrective action just makes more work for us to 5 address it as if it is boric acid instead of 6 treating it as if it's not.

7 But, I don't know that we're prepared 8 right now to make a commitment to look at other 9 chemicals because this primary function is a system, 10 as an inhibitor is there are a lot of chemicals you 11 might use that may not be as effective as that.

12 CHAIRMAN SIEBER: Yes, on the other hand 13 if it's causing you the problem you may want to just

• 14 15 think about that and maybe do something about it.

MEMBER MAYNARD: Is the corrosion that 16 we're seeing being caused by this or just because 17 water is getting -

18 MR. MYER: The pictures you've got with 19 corrosion in other areas is primarily the 20 condensation because there is a tremendous amount of 21 condensation 22 MEMBER MAYNARD: Well changing chemical 23 wouldn't really change that.

24 MR. MYER: That's correct.

• 25 CHAIRMAN SIEBER:

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108 1 the other question. In your inspection report on

• 2 paragraph eight you talk about coatings, you know 3 like protective coatings like paint and so forth.

4 What is the current condition of 5 protective coatings in containment and then outside 6 of containment. I mean are they postured where 7 chemical attack can have raw metal to work on?

8 MR. LAKE: I going by the inspection 9 report of a inspectors that 10 CHAIRMAN SIEBER: It doesn't really say.

11 MR. LAKE: Yes, going by the inspection 12 report of inspectors that did the walk down during 13 the refueling outages the corrosion that you're

• 14 15 seeing they saw.

in those pictures are representative of what 16 They did not see a lot of peeling, they 17 did not see a lot of coating, degradation aside from 18 the corrosion you're looking at.

19 CHAIRMAN SIEBER: Okay.

20 MR. BARTON: The question is one picture 21 nuke services close cooling water valve. It looks 22 like the packing gland is completely corroded and 23 won't move.

24 MR. LAKE: I'm sorry?

• 25 MR. BARTON: Am NEAL R. GROSS I looking at a COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., NW.

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109 1 completely corroded packing gland and packing nuts

• 2 that looks like it was corroded and were never 3 moved. What am I looking at here?

4 CHAIRMAN SIEBER: That's not boric acid.

5 The other one is boric acid.

6 MR. BARTON: No, I know but I'm looking 7 at the condition of the pack plant because the 8 material condition -- I don't get you. That to me 9 looks like it's a completely corroded packing liner.

10 And the other valve has got a chain on 11 running through the yoke of the valve. What's the 12 chain there for. Is that normal Plant practice to 13 run a chain through the yoke of the valve, or I

• 14 15 don't get it.

pictures.

I have problems with both of those 16 MR. LAKE: I don't have an answer as to 17 what the common practice is for that chain going 18 through the yoke.

19 MR. BARTON: But what about the packing 20 liner. That's a material condition issue in my 21 mind.

22 MR. LAKE: I don't specifically know 23 MR. BARTON: I don't even see the 24 threads on the -- am I looking at the threads to

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110 1 left. What am I looking at. I'm just wondering how

• 2 good you painted material condition of the Plant and 3 then you hand out pictures like this for us to look 4 at which are terrible.

5 MR. LAKE: Well, again, that particular 6 valve is being corroded as a result of the 7 condensation -

8 MR. BARTON: I don't care what's causing 9 it. I'm just looking at material conditions of the 10 valve. But can I adjust the backing on this valve 11 and I would say hell no. But yet you don't make 12 issues of - I don't know.

13 I just don't know what you're coming

• 14 15 from material condition I think that's not a good material condition issue. I don't know how many 16 more there are in the Plant like that that you guys 17 found or didn't find. So I don't really know what 18 to think about your inspection report now.

19 CHAIRMAN SIEBER: I guess that in every 20 Plant that I have been a number of them and I don't 21 recall seeing in these Plants that I've been in this 22 coating from the additive.

23 MR. LAKE: That was the first time I 24 came across it as well.

• 25 MEMBER STETKAR:

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111 1 and I'll ask the licensee, I've heard several things

• 2 here with additives and some people talk about 3 chilled water systems with condensation on the 4 chilled water piping and additives to chilled water 5 systems. Other people have talked about leaks on 6 nuclear service cooling water connections to large 7 numbers of coolers in the containment with 8 condensations on piping.

9 What system, is it chilled water or is 10 it nuclear service cooling water has the additive 11 and where is the additive coming from. Is it the 12 chilled water system or is it the nuclear service

• 13 cooling water system.

14 MR. MYNAN: This is Tom Mynan, what we 15 do during normal Plant operations we supply 16 containment with nuclear service cooling water where 17 we shut down for refueling outage we have one aux 18 cooler that normally gets nuclear service cooling 19 water that we isolate and we flange in this spool 20 pieces chilled water to that cooler and during 21 outage operation that cooler gets chilled water.

22 And there is a flushing procedure and 23 other things that we go through so as to not to mix 24 the different chemicals between the two close loop

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112 1 water uses the nitrite treatment. Does that answer

• 2 your question?

3 MEMBER STETKAR: I think so.

4 MR. MYNAN: It's the same pipe but it 5 serves two purposes online and offline.

6 MR. HOLIAN: This is Brian Holian again, 7 maybe we could get the committee some more 8 information on you know vice one inspection report, 9 that kind of accumulation. You'll be getting a few 10 slides here in a minute about plan indicators. I 11 just looked ahead you see a lot of green indicators 12 on this Plant.

13 So there are other inspection reports I

• 14 15 think that would tend towards looking for some of the aspects of performance that might show up if you 16 had inoperable valves or maybe a performance 17 indicator that might turn white. It doesn't look 18 like it's at that, but we could probably get the 19 committee some more information on an assessment of 20 reports including, you know maintenance inspection 21 reports.

22 CHAIRMAN SIEBER: Well, I guess I can 23 conclude something from all of this. From what 24 we've seen and what we've read it looks like there's

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113 1 used.

• 2 And it has an effect on the material 3 condition of the Plant. The Plant is only 20 years 4 old. We're asking -- or the applicant is asking for 5 permission to run the Plant for twice as long as 6 it's already run and so if you don't have a good 7 corrective action and stop this, you know there's 8 some place along the line there's going to be 9 serious problems.

10 And I think if the Aging Management 11 Program in order to correct this condition to me 12 does not seem aggressive enough to solve the 13 problem. And I think that that should result in

• 14 15 additional attention by the staff.

MR. LAKE: The staff I'm sorry, sorry 16 to interrupt. No, the Region II staff is monitoring 17 all the follow-up that their conducting for this 18 project that they started. We know that there is 19 some short-term things that they are doing such as 20 attacking the various areas in containment to 21 improve the material condition.

22 But even in doing long term fixes as 23 well as trying to insulate the lines that are 24 causing all the condensation and containments. And

• 25 we do monitor that. We monitor that by the resident NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., NW.

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114 1 inspectors and we also monitor that every time we go

• 2 out during refueling outages to do walk downs up at 3 containment and other areas of the Plant.

4 So, we are monitoring and following 5 their progress along these corrective actions.

6 CHAIRMAN SIEBER: Well, the hopeful 7 thing would be that there is progress. But right 8 now it seems like the corrective actions are not 9 adequate to reverse the direction or the trend that 10 we apparently see.

11 And like I say the Plant is 20 years 12 old. The average between the two plants and their 13 asking to run it an additional 40 years and a lot

• 14 15 can happen in that amount of time.

what their doing now is adequate and it continues in And if we say 16 the vein that it's progressing at this moment then I 17 think that there's a problem someplace ahead due to 18 corrosion.

19 MR. BARTON: Also, I'm sure inspectors 20 go into containment each time there's a refueling 21 outage and do an inspection in containment or 22 walkthrough, right?

23 MR. LAKE: They do.

24 MR. BARTON: All right, now this stuff

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115 1 inspection report somewhere I read that this has

• 2 been since the Plant started operating.

3 Now, why wasn't this a big deal before 4 your inspection report because I think some damage 5 has been done to Plant equipment in there as a 6 result of this and this has been a long standing 7 issue at this site.

8 Your inspection report even says that 9 inspectors noted or something that this has been 10 like this since the initial operation.

11 MR. LAKE: And as I stated before we do 12 interview personnel during these inspections and in 13 interviewing those personnel they indicated that

• 14 15 there has been a long standing condition that they have gotten used to seeing. And I think Mike had 16 also presented that.

17 MR. BARTON: Well, that hasn't done a 18 job either because they should have notified - I 19 mean they should have made an issue of this thing 20 long before it got this bad.

21 So, I just question what's really going 22 on there, how adequate is the inspection program 23 going and you know if there are issues like this in 24 the plant. I mean this is a material - I think is

• 25 a serious material condition issue.

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116 1 the adequacy of the inspection program and why you

• 2 guys were even looking out when you've been 3 containment each refueling outage.

4 CHAIRMAN SIEBER: Any other comments on 5 Plant area review one?

6 MR. HOLIAN: This is Brian Holian, you 7 know we will take that comment and work with the 8 region, but also with the division for monitoring 9 the rack oversight process. And you know look at 10 whether I know on an annual basis they'll re 11 baseline.

12 And I don't know if ACRS gets briefed on 13 that for are we spending inspection resources in

• 14 15 areas that aren't having benefits.

report back to the committee on whether they have And we can 16 looked at general corrosion aspects and are we doing 17 enough on regular routine inspections.

18 MR. LAKE: The next share is a slides 19 where we represent the current performance in ERO 20 space and as it's presented in our performance 21 grading. And as you can see all of the areas for 22 the cornerstones of the ROP are all in green which 23 indicate that the licensee is performing in 24 accordance with the requirements.

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117 1 matrix they would stay in what's known as the

• 2 licensee's action column as opposed to additional 3 columns. If performance is unacceptable they would 4 go into various columns where they would get greater 5 attention by the NRC.

6 I don't know if you want me to go 7 through the details of the current performance 8 indicators. But, the fact that they are all green 9 right now and they are performing well the grey 10 ones mean that that's no 11 MR. BARTON: There's no findings except 12 there's two green findings. That's what they are 13 telling you.

• 14 15 MR. LAKE: But they're still -- I didn't realize that when it was put up there.

MR. PELTON: This is Dave Pelton, the 16 17 brace chief under license renewal. Under the 18 reactive oversight program which you are probably 19 all well aware the performance indicators that are 20 green by definition meet the NRC's requirements.

21 However, findings that are green 22 indicate that they do not meet NRC expectations and 23 so let's just keep that in mind as you -

24 CHAIRMAN SIEBER: Green means there is a

• 25 finding. Grey means there isn't one?

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118 1 MR. PELTON: That's correct.

• 2 CHAIRMAN SIEBER: Okay, and so you've 3 got two findings both of which were low safety 4 MR. LAKE: Very low safety, that's 5 correct.

6 CHAIRMAN SIEBER: One in barrier 7 integrity and the other one in mitigating systems?

8 MEMBER BROWN: And what's the nature of 9 the finding?

10 MR. LAKE: I'm sorry?

11 MEMBER BROWN: What is the nature of the 12 findings?

MR. LAKE: The findings that were green

• 13 14 consisted of one violation of 10 CFR 50 Appendix B 15 criteria. And 11 for failure to establish adequate 16 test control measures for text spec surveillance.

17 There was another one in the capability 18 of the aux sea water system to meet the design and 19 licensing requirements. That was also a green 20 finding.

21 There was a NCV, a non-site evaluation 22 for, as we stated the boric acid -- identification 23 of the boric acid. On unit 2 that was on unit 24 one. On unit 2 there was one NCV, non-site

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119 1 transient combustibles.

• 2 There was another NCV for violation 3 again of Appendix B criteria 10 for failure to 4 establish adequate testing control measures similar 5 to the one that they found on unit 1 was common.

6 Capability of aux water system to meet 7 design. Again, that was also identified on unit 2.

8 There was a safety shut down practice not consistent 9 with the analysis that was identified as a NeV, non-10 site evaluation.

11 Then there was one more non-site 12 evaluation that had to do with emergency lights not 13 installed as required in a fire protection program.

• 14 15 Any other questions?

(No response.)

16 CHAIRMAN SIEBER: Thank you, thank you 17 very much. Appreciate it.

18 MR. ASHLEY: Section three of the SER, 19 Section 3.01 talks about the format of the 20 application and then the staff review process in 21 Section 3.0.2.

22 Section 3.0.3 has to do with Aging 23 Management Programs. Mr. Myer talked about the 24 numbers of programs that they had that were Plant

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120 1 are associated with -- that are consistent with

• 2 GALL.

3 MEMBER BONACA: Going back to the slide 4 from before. You told us that there was going to be 5 seven percent consistency with GALL.

6 MR. ASHLEY: That's when you look at the 7 individual line items. These are the programs that 8 contain the line items.

9 MEMBER BONACA: Okay.

10 MR. ASHLEY: So we didn't look at it 11 consistent from a program aspect. We drilled down 12 to look at the line items.

MEMBER BONACA: So if you have a program

• 13 14 which has exceptional enhancements do you consider 15 it consistent with GALL. I'm trying to understand 16 how to relate these numbers to those line items.

17 MR. ASHLEY: It's difficult.

18 MEMBER BONACA: Yes, right.

19 MR. ASHLEY: It's difficult to relate 20 them to the line items themselves. You have to go 21 in and look at each individual line item to get that 22 consistency percentage.

23 MEMBER BONACA: Okay.

24 MR. ASHLEY: This is strictly from the

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121 1 you has to do with our listing of the systems that

• 2 were reviewed.

3 In all cases the reviewers, when they 4 went through all of these systems looked at the 5 cumulative fatigue damage, loss of materials, 6 reduction in heat transfer, stress corrosion 7 cracking, and quality assurance for AG management.

8 And Section 3.1 covered the reactor 9 vessel and reactor coolant system. 3.2 covered the 10 engineering safety feature systems. 3.3 was aging 11 management auxiliary systems. And part of the 12 additional information that you were given was 13 specifically on 3.3.2.2 which consisted of AMR

• 14 15 16 results that were consistent with GALL for which further evaluation is recommended. Those systems were reviewed and then provided to you in a separate 17 package.

18 They also looked at cumulative fatigue 19 damage, reduction of heat transfer due to fouling, 20 cracking due to SCC, and hardening and loss of 21 strength due to elastomer degradation. The loss of 22 materials were also considered for each of the 23 systems.

24 The steam and power conversion systems

• 25 were reviewed as well. And one thing that's a NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., NW.

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122 1 little different in this particular system, the

• 2 condensate system was reviewed as part of the feed 3 water system rather than a separate system.

4 Aging management of containment 5 structures and component supports in Section 3.5 was 6 reviewed. One of the things of interest has been 7 the in scope inaccessible concrete. And we wanted 8 to make sure that we provided you with the specific 9 information from this section.

10 The substance criteria for pH chlorides 11 and sulfates were met in all situations and there 12 was two tests performed in 2005 and 2007. They both 13 did meet the acceptance criteria.

• 14 15 Section 3.6, aging management electrical and instrumentation and control systems. This also 16 included the inaccessible medium voltage cables.

17 And we had -- in the review of this section and the 18 other section we had several RAIs that they 19 applicant responded to that were specifically 20 addressed for elastomers.

21 MR. BARTON: I have a question a second.

22 In the -- as I review it it looks like there were 23 four programs listed that managed aging effects, 24 electrical, and INC system components. I can only

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123 1 programs, loosening and bolted connections.

• 2 Now, was I missing another page or 3 something, because I only saw you discussing one of 4 the four programs?

5 MR. ASHLEY: We should have covered them 6 all. And they should be within that section.

7 MR. BARTON: Maybe you want to look 8 because I saw one. I'm talking about page 3.5.18 in 9 your SER.

10 MR. ASHLEY: I'll have to go back and 11 look sir.

12 MR. BARTON: Okay.

MR. ASHLEY: I will verify that.

• 13 14 MR. BARTON: All right, thank you.

15 MR. ASHLEY: Before I get into Section 4 16 on the time limited aging analysis I'd like to ask 17 Dave Pelton if he would address the subcommittee.

18 MR. PELTON: Hi, this is Dave Pelton, 19 branch chief license renewal. I just wanted to 20 bring a relatively, well somewhat recent issue to 21 the attention of the committee.

22 Staff has been taking a look at 23 operating experience related to the use of Boral and 24 spent fuel pools. As you mayor may not know there

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124 1 degradation, but also with some blistering or

• 2 swelling with boral.

3 What we've done and in specific with 4 Vogtle is we took a look at, there's been fuel 5 pools. Unit 1 fuel pool does include boral 6 material. And their criticality analysis for that 7 pool takes credit for the boral.

8 Our SER documents the Aging Management 9 Program for that material and it does it in kind of 10 a three part method. It looks at the water 11 chemistry control that's applied. It also looks at 12 corrective action program for the licensee to 13 identify any issues and take action. And then it

• 14 15 also requires the licensee to consider operating experience and take action as appropriate. And also 16 you may note that commitment 37 also requires 17 license or reinforces the need to do that.

18 What we're going to -- what the staff 1S 19 doing is with all of these recent Palisades issue 20 with some more blistering. We're going to look at 21 that, not only generically, but also specific to 22 Vogtle to make sure that the Aging Management 23 Program that we currently -- that's currently in the 24 SER continues to meet staff expectation given some

• 25 of the more recent experience.

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125 1 And then as appropriate or if necessary

• 2 we have the request for additional information 3 process we can use to ask additional questions of 4 the licensee and make sure that we're satisfied that 5 the program is adequate.

6 MR. MEDOFF: Let me just expand on that.

7 Al Heizer is running division of component 8 integrity, steam generator integrity and chemical 9 engineering branch, and they are considering putting 10 out an ISG on Boral degradation. So, that may come 11 forth in the near future.

12 So, that's an additional measure that 13 we're taking to address operating experience with

• 14 15 Boral.

CHAIRMAN SIEBER: Do you get blistering 16 mainly from chemistry and I presume when there's 17 neutron gorging generating heating and gas which 18 should be at a very low level at a spent fuel 19 outage.

20 MR. MEDOFF: Emma, would you like to 21 address that please. This is Emma Wong of the 22 division of component integrity.

23 MS. WONG: Could you repeat the 24 question. I could barely hear it.

• 25 CHAIRMAN SIEBER:

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126 1 more of a comment. But, the major cause of

• 2 blistering in Boral is water chemistry to my 3 understanding.

4 But, if there is significant neutron 5 fields you generate helium and gas that is within 6 the matrix of the material which can collect them 7 also cause blistering. I presume that this is all a 8 water chemistry problem in a spent fuel pool, 9 because the activity in the spent fuel pool should 10 be neutron activities and should be pretty low. Is 11 that correct?

12 MR. MEDOFF: Emily, is he on the money?

MS. WONG: Yes, he's correct.

• 13 14 MR. MEDOFF: Okay.

15 CHAIRMAN SIEBER: Now, I guess my other 16 comment is that this is generic to -- this has been 17 around for a long time. This is generic to Plants 18 that use Boral.

19 So, my question is is it part of license 20 renewal or is a generic issue that needs to be dealt 21 with soon, but outside of license renewal process?

22 MR. PELTON: I think right now we're 23 trading right now we're looking at it -- well 24 there's a I'll let Alan Hiser talk first and then

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127 1 least recently.

• 2 MR. HISER: Alan Hiser from the chemical 3 engineering branch, NRR. We're taking a look at 4 that now because clearly there's nothing that 5 changes magically with license renewal.

6 So, we're taking a look at the impacts 7 on the current licensing periods for Plants as well.

8 We don't have anything at this point on an 9 assessment of that.

10 CHAIRMAN SIEBER: Let me ask another 11 sort of mechanistic question. When you get the 12 blisters do the blisters break and falloff and you 13 lose the Boral. Does it lose it's structural

• 14 15 integrity or does it just look bad?

MR. MEDOFF: That I can't answer.

16 MR. HISER: That's again something that 17 we would take a look at. Just understand what the 18 overall impacts are.

19 CHAIRMAN SIEBER: It's long term.

20 MR. PELTON: That's right, and as with 21 any, you know kind of, as you said this isn't 22 necessarily a brand new issue. But how we're 23 looking at it and how it relates to license renewal 24 we're just taking another look at it.

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128 1 couple of weeks working closely with Alan's group.

• 2 And we just want to make sure that we get our arms 3 around it and fully understand it if any impact at 4 all on Vogtle and then also generically.

5 So, we just wanted to make sure you 6 folks were aware that it was something we were going 7 to look at and mayor may not come up - well we'll 8 probably - we will readdress it at the full 9 committee meeting so we can give you what we 10 concluded.

11 CHAIRMAN SIEBER: Yes, well we need to 12 decide amongst ourselves whether it's a license 13 renewal issue or not because it impacts the kind of

• 14 15 report that I write.

MR. MEDOFF: We've had a -

16 CHAIRMAN SIEBER: I think I'll wait to 17 the full committee meeting and spend the entire 18 night writing the report.

19 MR. MEDOFF: We have had other emerging 20 issues in the past where they've put it into current 21 operating space. A good example is when we had the 22 nickel alloy cracking issues initially break out we 23 put that in current operating space.

24 But since that time we've had some new

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129 1 requirements to update the GALL report and the GALL

• 2 update.

3 So, when we get emerging issues like 4 this it may very well be that we put it into current 5 operating space. And once something gets 6 established we'll use it to update the GALL report.

7 CHAIRMAN SIEBER: Thank you very much.

8 MR. ASHLEY: Section 4 of the SER 9 contains the Time Limited Aging Analysis. The TLAA 10 are Plant specific safety analysis that involved 11 time limited assumptions defined by the current 12 operating term.

13 The staff reviewed the information in

• 14 15 the LRIA to determine whether the applicant has provided sufficient information according to 54.21 16 C1 and C2.

17 The applicant evaluated it's 18 calculations and analysis against the six criteria 19 specified in 54.3. The TLAA criteria involves SSC's 20 within the scope of license renewal, considers it's 21 aging effect. It involves time limited assumptions 22 defined by the current operating term. It's 23 determined to be relevant by the applicant making it 24 safety determination.

• 25 It involves conclusions and provides the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., NW.

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130 1 basis for conclusions related to the capability of

• 2 the sse's to perform the intended functions. And 3 finally, are contained or incorporated by reference 4 into the current licensing basis.

5 In the TLAA's that were reviewed, we'll 6 go over each of these as we go over through this 7 section. The reactor vessel neutron embrittlement 8 analysis, Section 4.2 of the SER, there were five 9 reviews performed to evaluate the consequences of 10 the neutron embrittlement as documented in the SER.

11 These are neutron fluence, adjusted 12 reference temperature, pressurized thermal shock, 13 and pressure temperature limits, and upper shelf

• 14 15 energy.

The staff reviewed the license 16 information and found only a statement that the 17 fluence calculations adhered to the guidance and the 18 regulatory guide 1.190.

19 The staff felt that that was not 20 adequate and to conclude adherence to the reg guide, 21 or whether the values listed actually accounted for 22 the previously approved power uprate and the 23 applicable number of the effective full power years 24 of the calculated fluence values.

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131 1 the review the staff calculated fluence values and

• 2 the staff requested one reference to the 3 calculations, two clarification for the listed 4 fluence values as to whether they include the power 5 uprate, and three clarification of the applicable 6 EFP wise for the listed fluence values.

7 The applicants response provided the 8 requested information and the staff concludes that 9 the reactor neutron embrittlement analysis meet the 10 review criteria in the standard review plan and in 11 accordance with the rules.

12 The tables that we'll be looking at in

• 13 the slides, the next slides are for 56.3 EFPY to 14 account for the recent power uprate in the 15 measurement uncertainty recovery.

16 While the w-cap values that are normally 17 used are calculated for 57, this is acceptable 18 because the 56.3 EFPY are still conservative with 19 respect to expected values.

20 This graph represents the upper shelf 21 energy decrease. The UOL use acceptance criteria is 22 greater than 50 foot pounds. And if you'll note 23 that Vogtle unit 1 is at 61 and unit 2 is at 56 24 which meets the criteria.

• 25 CHAIRMAN SIEBER:

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132 1 chart properly where we're supposed to take column

• 2 three number which is 70 and move it one case to 3 track 12 and then up to 61?

4 MR. MEDOFF: That is 12 percent of the 5 emission.

6 CHAIRMAN SIEBER: Got you.

7 MR. ASHLEY: Did you hear the 12 8 percent?

9 CHAIRMAN SIEBER: Yes.

10 MR. ASHLEY: Okay, on reference 11 temperature calculations again the screening 12 criteria is less than 270 degrees and unit 1 1S at 13 123.3, unit 2 at 134.2 degrees.

• 14 15 The additional TLAs on metal fatigue analysis and the applicant discussed her cycle 16 counting. And John Fair, did you have additional 17 information for metal fatigue other than what's in 18 the SER?

19 MR. FAIR: No, what's in the SER -- I'm 20 sorry, no all I have is what's in the SER.

21 MR. ASHLEY: Were there any questions 22 form that?

23 MR. ASHLEY: Section 4.4 of 24 environmental qualification of electrical equivalent

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133 1 containment liner plate, metal containment and

• 2 penetration fatigue.

3 Okay, Section 4.7 consists of Plant 4 specific TLA's. And this shows the listing there.

5 The Section 4.7.5 on under clad cracking of reactor 6 pressure vessel. This was amended and added in a 7 letter of March 20th for the closure head dome 8 flanges. The primary inlet nozzles, primary outlet 9 nozzles, and the RPV flanges.

10 These are SA 508 class two forgings 11 whose internal cladding was welded using a high 12 temp, excuse me high heat submerged art weld 13 process.

• 14 15 MR. HOLIAN: How is the -- there's sort of a reference to a WCAP report for the week before 16 break analysis. What are the assumptions in that 17 week before break analysis that you use. Is there 18 - do you do an inspection or do you have a 19 postulated crack?

20 MR. MEDOFF: The issue with the leak 21 before break analysis is on the cast materials. If 22 you get thermal aging they 23 MR. HOLIAN: I was thinking with 182.

24 MR. MEDOFF: 182, my understanding I

• 25 that the pervious office directors has put that as NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., NW.

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134 1 an emerging issue to assess the impact of the SCC on

• 2 the -- when the leak before break analysis and 3 that's being handled by the division of component 4 integrity. So, I think we're going to have to go 5 back and find out where they stand on that issue.

6 MR. ASHLEY: Did you have a follow-up, 7 sir?

8 MR. MEDOFF: The officer director put it 9 in current operating space so we're going to have to 10 go back to them on that matter.

11 MR. ASHLEY: On the basis of this review 12 the staff determines that the requirements of 10 CFR 13 5429 A have been met.

• 14 15 Future commitments have been identified and a schedule is documented in the SCR such that 16 there is reasonable assurance that the activities 17 approved by the license renewal will continue to be 18 conducted in course with the current licensing basis 19 and changes associated with license renewal.

20 With that sir, it is my 21 CHAIRMAN SIEBER: I see the last slide 22 is the same three license conditions that has a 23 memory license renewal.

24 MR. ASHLEY: Yes sir, those are the

• 25 standard license renewals.

NEAL R. GROSS That's the backup slide.

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135 1 CHAIRMAN SIEBER: Thank you.

• 2 MR. LAKE: If I may, could I maybe 3 provide some clarifications on the photos showing 4 that globe valve and the extensive corrosion that's 5 shown on the bolting and the tacking plan. And also 6 on the gape value showing the boric acid and 7 leakage.

8 Now the intent of these photos was to 9 show that you really have a hard time distinguishing 10 between boric acid. But more importantly, where I 11 got these photos from this is a licensee photo. It 12 was actually identified. I'm looking at the back of 13 it now. It was actually identified in 2006 as part

• 14 15 of the boric acid program walk down where they identified these problems and took corrective 16 action.

17 MR. BARTON: So the two year old picture 18 has been corrected or is it still there after two 19 years?

20 MR. LAKE: Well based - I'm not going 21 to positively say it has been corrected except to 22 say what that program would require. And their 23 program these pictures require just to be put into 24 their boric acid corrective action program and you

• 25 correct these prior to them going back up in power.

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136 1

• 2 So, this is from back, you know years 3 ago. It doesn't necessarily represent what's out in 4 the containment today on these two pictures.

5 Now the other pictures don't have any -

6 what's that?

7 CHAIRMAN SIEBER: It could be worse.

8 MR. LAKE: Oh.

9 CHAIRMAN SIEBER: Any other additional 10 comments or statements from the staff?

11 MEMBER MAYNARD: I'm not sure - I 12 appreciate you bringing the pictures and showing 13 them and I would hate to leave the impression we

• 14 15 have where people won't bring us something.

would be nice if some of these could be put in It 16 better perspective.

17 MR. LAKE: That's true.

18 MEMBER MAYNARD: But I do appreciate you 19 bringing the pictures and showing them to us. And I 20 think that it's more than one inspection that ends 21 up forming an overall basis of material condition 22 and other things.

23 So I'll just pass that out. It would be 24 nice to -- when bad pictures shown and can be put

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137 1 whether that's an out liar or whatever it is.

• 2 MR. HOLIAN: We agree.

3 MEMBER BONACA: The question I have is 4 are we aware of similar conditions in other Plants?

5 MR. LAKE: I have not read any 6 inspection reports that identify similar conditions 7 nor have I observed similar conditions.

8 MR. BARTON: Have you seen inspection 9 reports that identified the condition you found 10 during this outage which has been here since day one 11 or since the Plant started operating?

12 MR. LAKE: The inspection reports that I 13 have read, I've been with the NRC about three and a

• 14 15 half years go back maybe two or three years ago.

That's what I prepared in preparation for this 16 license renewal inspection I went and read through 17 these inspection reports.

18 MEMBER BONACA: I mean it was best to go 19 back to get your position. It means some emphasis 20 since then.

21 MR. PELTON: This is Dave Pelton again, 22 you know Brian and I were just talking and you know 23 he and I spent a lot of time up in Region I and have 24 visited all of those sites and probably most of the

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138 1 think we characterize that as a typical condition.

• 2 We certainly appreciate the view that 3 you know our inspection conclusions are based on a, 4 you know a mosaic of opportunities to review and 5 inspect identify issues. And we also appreciate the 6 need to you know if we're going to bring pictures 7 in to make sure it tells a good story and that it 8 captures, you know what message are we trying to 9 send.

10 And you know what we're going to do, you 11 know we'll make sure that we'll bring to you when we 12 go over the final SER is just put everything in the 13 perspective that it was intended to be and make sure

• 14 15 that we tell the right story because we certainly don't want to leave you the impression that, you 16 know that we're walking away from material condition 17 issues that don't meet expectations or NRC 18 requirements.

19 But we can certainly put it in the right 20 perspective for you and will do that.

21 MR. BARTON: This raises the question 22 about the IPC inspection program and also material 23 condition in the Plant and what the corrective 24 action programs are. I mean you saw something like

• 25 this and it just opens up.

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139 1 MR. PELTON: And we appreciate that and

• 2 we'll make sure we'll cover that for you.

3 CHAIRMAN SIEBER: Any additional 4 questions from the members?

5 (No response.)

6 CHAIRMAN SIEBER: Well if not I'd like 7 to ask each member a few questions and this will be 8 complicated because it's a complicated way of doing 9 business and the LROA review and approval process.

10 The first question I'd like the members 11 to consider is do we need an interim order and just 12 for information an interim order would tell the 13 applicant or the staff or both if the ACRS

• 14 15 subcommittee has identified one or more significant items not evaluated properly or corrective actions 16 not identified or insufficient.

17 I think another reason for an interim 18 letter would be deviation of the applicant or the 19 staff from the requirements of 5054. And I think we 20 write an interim letter this coming meeting that we 21 would need an additional subcommittee meeting to 22 determine that the issues that we raised in the 23 interim letter if any are resolved.

24 Now, the answer to that probably one is

• 25 no, we don't need an interim letter.

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140 1 to ask ourselves a second question and I would like

• 2 each of you to address this. Do we have enough 3 review material, and since some of it's late and 4 came in pieces we may not have been able to assemble 5 it all in our minds to make a final subcommittee 6 finding and do - if the answer to that is no, do we 7 need another subcommittee meeting in order to be 8 able to make such a finding and provide me with the 9 advice that I would need in order to write a letter 10 report appropriate for the full committee.

11 Now, the answer to one and two are both 12 nay, no then I would like you to give me your 13 comments as to the adequacy of the process in the

• 14 15 case of Plant Vogtle and any issues that you believe should be included in the letter that the 16 subcommittee would write and endorse and give it to 17 the full committee for it's review and approval.

18 So, there's three things that I'm 19 asking. Okay, do we need an interim letter, do we 20 need additional time to review the material that 21 we've gotten already since it came late and came in 22 pieces, and lastly if you're satisfied with the 23 material that you got the presentations today are 24 there significant items that should be in our letter

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141 1 material and it's okay.

• 2 MEMBER MAYNARD: First of all we can't 3 write a letter unless we have a portion of it set in 4 the agenda for the full committee meeting.

5 CHAIRMAN SIEBER: Well, yes -

6 MEMBER MAYNARD: So it couldn't be this 7 one.

8 CHAIRMAN SIEBER: But it's not going to 9 be this meeting. It is going to be some meeting, 10 okay when it comes up on the schedule. It will 11 probably come up in March.

12 MEMBER MAYNARD: Jack, I'm just a little 13 confused on your second item there and you stated it

• 14 15 different. One you asked if we had enough material to draw a conclusion. The subcommittee does not 16 have to draw a final conclusion. We will have a 17 meeting at the full committee where we will discuss 18 items that haven't been fully resolved or issues and 19 stuff.

20 CHAIRMAN SIEBER: Well, I think that we 21 can go to the full committee with that. But in 22 order for me to properly present the review of this 23 material you need to identify the items to which we 24 don't agree.

• 25 MEMBER MAYNARD:

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142 1 CHAIRMAN SIEBER: Or, with which we

• 2 disagree among ourselves.

3 MEMBER BONACA: You would want more 4 material only in case the answer to the first 5 question was yes, right?

6 CHAIRMAN SIEBER: I don't expect 7 additional material. But what we got was in pieces 8 and not timelY. And so the question is, have you 9 had an opportunity to - prior to this meeting and 10 the information that you gathered during this 11 meeting to be able to draw a conclusion.

12 And the answer is not what is your 13 conclusion, but yes or no. George?

• 14 15 MR. APOSTOLAKIS:

CHAIRMAN SIEBER:

I'll pass.

Okay,-

16 MEMBER STETKAR: I don't think we need 17 an interim letter.

18 CHAIRMAN SIEBER: Okay.

19 MEMBER STETKAR: If I could answer that 20 question. I've received enough information and I 21 guess I'd like to hear other members of the 22 committee about whether they whether there is any 23 consensus about any significant items to be 24 included. I don't want to be conclusive at this

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143 1 at this point.

• 2 CHAIRMAN SIEBER: Okay, thank you.

3 MR. HOLIAN: I agree, I don't think we 4 need an interim letter. I - the areas, you know my 5 primary interest - if there was enough information 6 available than what I have to look through perhaps a 7 little more information at the full committee 8 presentation on specific programs would be helpful 9 to the full committee.

10 But, at the moment I -

11 CHAIRMAN SIEBER: Could you describe -

12 it would help both the applicant and the staff for

• 13 you to tell us what you'd like to hear more about.

14 MR. HOLIAN: Okay, I'd like to hear more 15 about the cable program in particular.

16 CHAIRMAN SIEBER: We're going to do the 17 members first and then I ' l l get to you, okay.

18 MR. HOLIAN: Jim sort of gave me a hint 19 and in fact I shouldn't have stopped reading in the 20 SER. I read the test from the SER and now I come to 21 commitment 36 which says once the NRC has decided on 22 a process to address this problem the licensee will 23 do it.

24 Well, I guess I can't really expect the

• 25 licensee to do much until you tell them what to do.

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144 1 So, he's gone about as far as he can go at the

• 2 moment.

3 So, I'm -- Commitment 36 is what?

4 MR. HOLIAN: This is a new commitment 5 and it's once an onsite audit question 4.701. Once 6 the NRC has adopted a process or accepted a process 7 for addressing PWSCC at alloy 82 welds and all of 8 the devaluations they'll do it.

9 CHAIRMAN SIEBER: Sounds good to me.

10 MR. HOLIAN: Sounds good to me.

11 MEMBER BLEY: Nothing new from me.

12 CHAIRMAN SIEBER: Dennis?

13 MR. RYAN: I just picked up on John

• 14 15 Stetkar's comment. I think there's a more generic issue on how water gets into these piping systems 16 whether it's ground water or rain water or both and 17 what measurables and metrics are going to be 18 important for the NRC to develop and to convey the 19 licensee so they make a meaningful measurements on 20 how the behavior of the system is progressing with 21 time.

22 CHAIRMAN SIEBER: It's rain water 23 because the manhole covers and there's no seal.

24 MR. RYAN: Usually.

• 25 CHAIRMAN SIEBER:

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145 1 them off.

• 2 MR. RYAN: That's part of it, but the 3 other part of it is, you know three inches of rain 4 over a month versus three inches of rain in an hour 5 kind of have different impacts on loading that 6 system with water and I take the other point that 7 was made earlier that some times it's in the pipes 8 and not in the conduits and you know you've got to 9 really think through the whole problem as a system.

10 So, I think there's a bigger issue there for the 11 staff to think about.

12 CHAIRMAN SIEBER: I think there's a 13 different issue too. A lot of the people look at

• 14 15 the cable itself and say it can stand this kind of environment for this length of time and remain 16 qualified and forget about this place. The reason 17 why your pull box is either to pull or to splice 18 something.

19 And you have to - the splices are made 20 on the job and you have to pay attention to how -

21 MEMBER RYAN: And I think that's exactly 22 the point. You know there's an engineering part of 23 the problem and then there's a geo-sciences part of 24 the problem, you have to put it all together.

• 25 MEMBER RAY: Well Jack, this is the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., NW.

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146 1 discussion I was eluding to and I thought we might

• 2 have. You used the word qualified just then and I 3 just wanted to point out that these are not required 4 to be qualified.

5 And so part of my issue here is that I'd 6 like us to discuss a little bit more is the function 7 itself. I think Otto asked what's the safety 8 function. I would echo that.

9 CHAIRMAN SIEBER: The control cables for 10 breakage.

11 MEMBER RAY: Well I know, but the need 12 for them to function is in the recovery from the

• 13 loss of offsite power event. And I need to 14 understand what the safety implications of that 15 particular step are. I think I know, but I don't.

16 This is not the place to get into that I think.

17 MEMBER STETKAR: I think there's a 18 couple of things here that we have to be careful 19 with. Specifically at Vogtle there are these two 20 cables involved that are the offsite power recovery 21 issue.

22 We've had other license renewal 23 applicants come in where they have had similar 24 problems with water accumulation for safety related

• 25 cables that are not qualified.

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147 1 related equipment cables that are not qualified to

• 2 be used under water.

3 MEMBER RAY: No it isn't, no it isn't.

4 MEMBER STETKAR: No, no not at Vogt1e.

5 But other license renewals. In a generic sense this 6 covers a broad spectrum of possible types of cables, 7 possible types of applications, and different Plant 8 specific configurations.

9 For this subcommittee today we're only 10 interested in what's the problem at Vogtle. The 11 generic sense is the bigger picture.

12 CHAIRMAN SIEBER: Let's be clear about

• 13 the importance of the cables if they are control 14 cables that offer breakers.

15 MEMBER RAY: These are power. I 16 understand that, that's why I asked if they were 17 energized.

18 MEMBER STETKAR: No, these are 4 kV 19 power cables.

20 MEMBER RAY: That's right, 480 volt.

21 MEMBER STETKAR: But we've had for other 22 license renewal applications, vogtle not 23 withstanding -

24 MEMBER BROWN: The last thing we talked

• 25 about, the last Plant we talked about had 4 kV power NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., NW.

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148 1 cables. But they were qualified. They said they

• 2 were safe to work in stations like that.

3 MR. BLEY: I passed, but I had a generic 4 issue since you brought up the generic side. Two 5 comments, but it's not, I don't think it's a local 6 issue, it's more general.

7 One is, we've heard a little bit about 8 the issue of wetting and drying and wetting and I 9 know there's work going on I think we need to 10 understand what works going on and what applies.

11 Second, although I would have agreed 12 with you a month ago that the reason there is a full 13 boxes for a splice we'd see at least one with no

• 14 15 splice in it. And maybe it's a long pull I'm not sure why it's that way. But, it's not always that 16 there is a splice in there.

17 CHAIRMAN SIEBER: You need a place to 18 pull it from. Okay, is it Otto's turn now?

19 MEMBER MAYNARD: It was a while ago too.

20 CHAIRMAN SIEBER: Yes, right you're 21 going to have your turn.

22 MEMBER MAYNARD: I don't think there's a 23 need for an interim letter and I think we have 24 enough information to go ahead here.

• 25 I believe that the majority of the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., NW.

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149 1 issues that are really being discussed are generic

• 2 issues and I think that they are current operating 3 issues as opposed to license renewal. Maybe if you 4 want to touch on it and stuff.

5 I do think they are important issues. I 6 think we have to sort out as to what do we put as 7 part of license renewal. And I really believe that 8 this cable vaulting water and stuff I think is a 9 current operating issue and I think it is a generic 10 issue that none of us have our hands around as to 11 the overall safety significance and what are the 12 requirements and what really needs to be done.

13 And I certainly don't think that any of

• 14 15 the monitoring programs that I've seen to date corne anywhere close to -- if it is a safety problem I 16 haven't seen any indication that the monitoring 17 programs are really adequate for that right now.

18 But again/ I think these are generic 19 issues and I think we have to sort out as to what do 20 we put into the license renewal review.

21 CHAIRMAN SIEBER: Yes/ but just so they 22 are given something about generic issues.

23 MEMBER MAYNARD: I think as far as for 24 the next presentation and stuff I do think that

• 25 since we walked about material conditions I think it NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., NW.

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150 1 would be good for the staff to come and write a

• 2 little bit more information on the overall material 3 condition.

4 CHAIRMAN SIEBER: Probably in inside 5 containment particularly.

6 MEMBER RAY: Is license renewal Otto or 7 is a current issue?

8 MEMBER MAYNARD: Both.

9 MEMBER RAY: Well, I understand, he 10 should say yes. But I just want to hear him.

11 MEMBER MAYNARD: Yes, and also because 12 it's something, either way it's something that we 13 put on the public record that I think is kind of

• 14 15 left hanging a little bit there that I think needs to be tied up a little better for the public record.

16 CHAIRMAN SIEBER: Yes?

17 MEMBER MAYNARD: Yes.

18 MEMBER BROWN: Two things, as an 19 electrical guy I don't like cables under water. I 20 was -

21 CHAIRMAN SIEBER: You were in the Navy.

22 MEMBER BROWN: It's been a long time.

23 MR. BLEY: You're not touching those.

24 MEMBER BROWN: You're not immersed in

• 25 water. So, pertaining to -- so under water we don't NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., NW.

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151 1 worry about it. It's the ultimate heat sink result.

• 2 So, I've been surprised in two meetings 3 now that there has been less information -- less -

4 I don't -- this sounds negative and I didn't mean it 5 to. But, I would have had personally I would 6 have had more curiosity as to source, that's why I 7 asked the question visa vie your point.

8 You know is it just stuff oozing up and 9 it's -- they inspect it, suck it out and nobody 10 looks at it for two months and then they see some 11 more, then well that to me you ought to know how 12 facts does it come back and what are the 13 environmental conditions. We ought to know were

• 14 15 it's coming from wand what's going on.

CHAIRMAN SIEBER: Yes, one day I pump it 16 up.

17 MEMBER BROWN: I didn't answer your 18 other question first. Maybe you ought to have a 19 pump there all the time. I don't like water in my 20 basements. So the sumps pup 21 CHAIRMAN SIEBER: A couple of hundred -

22 MEMBER BROWN: No, I don't think there's 23 a interim letter. I agree that this is more of a 24 generic type issue than it is a licensing issue.

• 25 So, I piggy back on Otto's.

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152 1 those. But I'm a little surprised at the lack of

• 2 curiosity, not meant to be negative, there's no 3 spears being fired here. I mean it's just I like to 4 know where stuff comes from.

5 And the material condition thing is 6 interesting. If we had seen one of our Plants in 7 that condition the CO would have been ripped off the 8 ship. The plant would have been shut down and we 9 would have gone - now, all we did was see these 10 pictures. So I have - there's no context at all 11 other than those what was done, when they were 12 taken, where there mitigation things done and what 13 have you.

• 14 15 It's just - you don't - and we've got 40 more years that we're predictably looking at 16 taking care of this. Now, are there mitigating 17 actions you can take, yes. Can you replace stuff 18 yes, but some of those are huge structures, tanks.

19 It's not easy to do.

20 So, is that a licensing issue. I don't 21 know, I don't have enough experience to being a 22 newbie here for five months or whatever it is to say 23 that I'm just disturbed by the expanse of those 24 pictures. But the context is not there and so it's

• 25 hard for me to make a judgement.

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

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153 1 So that's -- I would like to have

• 2 somebody present to us a general context over a 3 chronology of that as it gradually built the stuff.

4 For instance, if you looked at that 5 valve was that - you went back and looked at it 6 today is it pristine and pretty. We don't know.

7 MR. BARTON: Well you have to wait until 8 the next refueling outage.

9 MEMBER BROWN: Yes, so any way that's my 10 comment. I don't know how the old - I'd like some 11 more advice form you with more experience in these 12 commercial civilian plans than I have because I -

13 we wouldn't have put up with that in a Naval Plant.

• 14 15 We had a lot of salt water we deal with and so we try to keep them so we can see what's 16 going on.

17 MEMBER BONACA: I agree with everybody 18 for no interim letter. I don't see any need for an 19 interim letter and I think there is enough review 20 material as Otto pointed out to deal with this 21 issue.

22 I believe that the full committee would 23 be interested in both issues that were discussed 24 here. The splicing and the water standing, and the

• 25 deposits and containment. The effect of that NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., NW.

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154 1 presence of deposits on the model casting problem.

• 2 So, I think that we need to bring that 3 issue. I think that there are generic -- the first 4 one there are no cables. Its' a generic issue right 5 now. We always find it and what we heard often 6 times is that simply we will not rest the frequency 7 of inspections, that will do nothing.

8 I mean to go from two years to six 9 months doesn't tell me anything about what's 10 happening in between the drying and the wetting 11 issue, it's a fundamental issue and how do you 12 monitor that. How do you prevent that. So, that's

• 13 pretty much it.

14 CHAIRMAN SIEBER: I still like Mike's 15 ideas to figure out why it's getting in there. When 16 do you know when to pump it out, know when to 17 inspect and when to pump it out. If you have a hot 18 dry summer, you don't have to pump.

19 Okay, John?

20 MR. BARTON: I think Otto and Josh 21 covered what I was going to - I don't think you 22 need a letter to be written.

23 I think somebody needs to look at the 24 SER and try to find out if they said there were a

• 25 lot of issues with the SER that would - and as far NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., NW.

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155 1 as the another issue I have is what is the real

• 2 overall condition of the Plant material conditional 3 that I can look back through on the inspections and 4 you know why wasn't this stuff picked up because 5 it's in the same condition in unit 2, you know 6 what's the effect on the corrective action program 7 and things like this.

8 That's about the only issue I can come 9 up with.

10 CHAIRMAN SIEBER: Okay, well thank you 11 very much. I think that it might be a good idea to 12 address two things from the same point of the

• 13 applicant and the staff.

14 One of them is the water in the manhole 15 issue. You may have some new ideas about - after 16 the four hours of discussion some new ideas about 17 how you want to deal with it.

18 The other one is a trio condition in 19 containment. I may have some new ideas about that 20 and the third one would be, I think from the staff.

21 Let's take a look through the inspection 22 reports to try and get a better handle on material 23 condition so that we can make a judgement on this to 24 whether to the Plant is to grading and we'll grade

• 25 seriously by the Sergeant license renewal or not.

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156 1 MR. BARTON: I understand.

• 2 CHAIRMAN SIEBER: You need to cut her an 3 assessment for overall material conditions.

4 MEMBER BROWN: I understand.

5 CHAIRMAN SIEBER: So, in addition to 6 giving the broad over view like you are giving here 7 for the record then we'll have less time, we're only 8 going to have about an hour and a half or two hours.

9 We'd like you to touch on those three subjects and 10 for the applicant to touch on two of those three.

11 So, with that being done let's finishing exactly on 12 time.

MEMBER RAY: We are and I'm not going to

• 13 14 delay us Jack, but I wanted to make one comment and 15 that is - there's been all this rhetoric about 16 material conditions. Just remember, ALARA is a 17 issue whenever you talk about having material 18 condition Christine you're also got to demonstrate 19 that it was consistent with ALARA.

20 CHAIRMAN SIEBER: One of the things I 21 learned working in Power Plants for 38 years was if 22 you have a clean plant it sort of goes a long way.

23 MEMBER RAY: Well, inside containment is 24 a different story.

• 25 CHAIRMAN SIEBER:

NEAL R. GROSS Okay.

COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., NW.

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157 1 MEMBER RAY: Say one more time, ALARA is

• 2 important. I didn't hear it mentioned. I think it 3 should be mentioned.

4 CHAIRMAN SIEBER: Okay, with that thank 5 you very much both Southern Nuclear and the staff.

6 This meeting is adjourned.

7 (Whereupon, the meeting was 8 adj ourned at 5: 02 p. m. )

9 10 11 12

• 13 14 15 16 17 18 19 20 21 22 23 24

• 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., NW.

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• CERTIFICATE This is to certify that the attached proceedings before the United States Nuclear Regulatory Commission in the matter of:

Name of Proceeding: Advisory Committee on Reactor Safeguards Docket Number: nla Location: Rockville, MD

• were held as herein appears, and that this is the original transcript thereof for the file of the united States Nuclear Regulatory Commission taken by me and, thereafter reduced to typewriting by me or under the direction of the court reporting company, and that the transcript is a true and accurate record of the foregoing proceedings.

c.-" Mdri~ I 1__ d "'---~

Eric Official Reporter Neal R. Gross & Co., Inc.

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

(202) 234-4433 WASHINGTON, D.C. 20005*3701 www.nealrgross.com

• * *

~U.S.NRC United States Nuclear Regulatory Commission Protecting People and the Environment Advisory Committee on Reactor Safeguards (ACRS)

License Renewal Subcommittee Vogtle Electric Generating Plant (VEGP)

Safety Evaluation Report (SER)

November 5, 2008 Donnie J. Ashley, Project Manager Office of Nuclear Reactor Regulation 1

• * *

~U.S.NRC Introduction United States Nilcleat Regulatory Commission Protecting People and the Environment

• Overview of VEGP license renewal review

• SER Section 2: Scoping and Screening review results

• License Renewal Audit and Inspection

• SER Section 3: Aging Management review results

• SER Section 4: Time-Limited Aging Analyses (TLAAs) 2

• * *

~U.S.NRC Overview (LRA)

United States Nuclear Regulatory Commission Protecting People and the Environment

• License Renewal Application (LRA) submitted June 2007

- Located 26 miles southeast of the Augusta, Georgia, in Burke County, Georgia

- Westinghouse PWRs, carbon steel-lined concrete (DRYAMB) containment

- Each Unit rated at 3565 megawatt thermal, 1208 megawatts electric (prior to MUR uprate.)

- Unit 1 Facility Operating License Number NPF-68 expires January 16, 2027

- Unit 2 Facility Operating License Number NPF-81 expires February 9, 2029 3

• * *

~U.S.NRC United States Nuclear RegulatOry Commission Protecting People and the Environment Overview (SER)

• Safety Evaluation Report (SER) issued to the applicant

- 87 RAI items issued

- 173 Audit Questions

- AMR line items ~87°Jb Consistent With GALL Report, Revision 1

- 41 Commitments

- Additional Components Brought Into Scope

- No Open Items (Ols)

No Confirmatory Items 4

• * *

~U.S.NRC United States Nuclear Regulatory Commission Protecting People and the Environment Audits and Inspections

• Scoping and Screening Methodology Audit 9/17 - 9/21,2007

• Aging Management Program (AMP) Audit 10/15 - 10/19, 2007

• Aging Management Review (AMR) Audit 12/9 - 12/14, 2007

• Region II Inspection (Scoping and Screening & AMP) 5/19/ - 06/06, 2008 .

5

• * *

~U.S.NRC Audit and Review United States Nuclear Regulatory Commission Protecting People and the Environment

• Audit Summary (ADAMS Accession No. ML080430373)

- Publicly Available, Issued on September 30, 2008

- Audit Summary Includes:

• Audit and Review Results

• Audit and Review Q&A Database

• List of Documents Reviewed by the Audit and Review Team 6

• * *

~U.S.NRC SER Section 2: Structures and United States Nucleat Regulatory Commission Protecting People and the Environment Components Subject to Aging Management Review Section 2.1 Scoping and Screening Methodology

• Staff's audit and review concluded that the applicant's methodology is consistent with the requirements of 10 CFR 54.4 and 54.21.

Section 2.2 Plant-Level Scoping Results

• Consistent with 10 CFR 54.4, the staff found no omission of plant-level scoping systems and structures within the scope of license renewal.

7

• * *

~U.S.NRC SER Section 2: Structures and United States Nuclear Regulatory Commission Protecting People and the Environment Components Subject to Aging Management Review Section 2.3 Seoping and Screening Results: Mechanical Systems 98 Mechanical Systems

-34 BOP

• 100% Reviewed

- Based on RAls, three ventilation components were added to the scope 8

• * *

~U.S.NRC SER Section 2: Structures and United States Nuclear Regulatory Commission Protecting People and the Environment Components. Subject to Aging Management Review Section 2.4 Scoping and Screening Results:

Structures No omission of structural components within the scope of license renewal 9

• * *

~U.S.NRC SER Section 2: Structures and United States Nuclear Regulatory Commission Protecting People and the Environment Components Subject to Aging Management Review Section 2.5 - Electrical and Instrumentation and Control Systems

• No omission of electrical and instrumentation and control system components within the scope of license renewal 10

• * *

~U.S.NRC United States Nuclear Regulatory Commission Protecting People and the Environment License Renewal Inspections Louis Lake Region II Inspection Tearn Leader 11

• * *

~U.S.NRC United States Nuclear Regulatory Commission Protecting Peopk and the Environment License Renewal Inspections

• Scoping and Screening Inspection

• Objective

• Focus 12

• * *

~U.S.NRC United States Nuclear Regulator}' Commission Protecting People and the Environment License Renewal Inspections Program Implementation

• License renewal chapter - Me 2516

• License renewal inspection procedure IP 71002 13

• * *

~U.S.NRC United States Nuclear Regulatory Commission Protecting Peopk and the Environment Aging Management Programs (AMPs) Implementation

• Objective

• Examine records 14

• * *

~U.S.NRC United States Nuclear Regulatory Commission Protecting People and the Environment Aging Management Programs (AMPs) Implementation

• Examine implementation plans

• Verify material condition of plant was adequately maintained 15

• * *

~U.S.NRC United States Nuclear Regulatory Commission Protecting People and the Environment License Renewal Inspection

• AMP inspection May 19 - June 6, 2008

• Inspection concluded that existing programs for license renewal are generally fu nctioning well.

16

• * *

~U.S.NRC United States Nuclear Regulatory Commission Protecting Peopk and the Environment License Renewal Inspection

• Inspectors identified enhancements

- Manhole flooding with Medium Voltage Non Safety Related Cable

- Condition inside containments 17

• * *

~U.S.NRC United States Nuclear Regulatory Commission Protecting People and the Environment License Renewal Inspection

• Applicant had established AMP implementation plans

• Region II will follow up on these issues during a future IP 71003 inspection 18

• * *

~U.S.NRC United States Nuclear Regulatory Commission Protecting People and the Environment Current Performance

• Green Pis & Findings

• Mid-Cycle Performance Review 19

• VEGP Units 1 and 2 Performance Indicators

• Reactor Safety

~~

Radiation Safety [

Safeguards

- T T Occupational Public Initiating Events --. Mitigating Systems f--J Barrier Integrity Emergency Preparedness Radiation Safety Radiation Safety Security Performance Indicators Last Modified: October 23, 2008 20

• *

• VEGP Unit-1 Findings Reactor Safety

~~

Radiation Safety [

Safeguards T

Occupational TPublic Initiating Mitigating Barrier Emergency Events ~ Systems ~ Integrity Preparedness Radiation Radiation Security Safety Safety Most Significant Inspection Findings 3Q12000 2Q12000 1Q12000 4Q12007 21

• *

• VEGP Unit-2 Findings Reactor Safety

~

Radiation Safety [

Safeguards

'P T T fmtiating Events -. Mitigating Systems r--. Barrier fntegrity Emergency Preparedness Occupational Radiation Safety Public Radiation Safety Security Most Significant Inspection Findings 3Q12008 2Q12008 1Q12008 4Q12007 22

• * *

~U.S.NRC Inspection Results United States Nuclear Regulatory Commission Protecting People and the Environment

• No violations identified

• Inspection findings:

- Condition of coatings inside containment

- Manhole flooding 23

• * *

~U.S.NRC SER Section 3: Aging Management United States Nuclear Regulatory Commission Protecting Peopk and the Environment Review Results Section 3.0.3 Aging Management Programs (AMPs) evaluated in the SER .

Plant specific Consistent With With With with GALL exception enhancement exception &

enhancement Existing 6 5 3 5 5 New 5 3 6 a a 24

• * *

~U.S.NRC Section 3.1 Aging Management of United States Nuclear Regulatory Commission Protecting People and the Environment Reactor Vessel, Reactor Vessel Internals, and Reactor Coolant System

• reactor vessel

• reactor vessel internals

• ReS and connected lines (includes the reactor coolant pumps)

• pressurizer

• SGs 25

• * *

~U.S.NRC Section 3.2 Aging Management of United State5 Nuclear Regulatory Commi5sion Protecting People and the Environment Engineered Safety Features System

• containment spray system

• emergency core cooling system 26

• * *

~U.S.NRC 3.3 Aging Management of Auxiliary United States Nuclear Regulatory Commission Protecting People and the Environment Systems

• fuel storage racks - new and spent fuel

• ventilation systems - miscellaneous

• spent fuel cooling and purification system

• ventilation systems - radwaste buildings

• overhead heavy and refueling load handling systems

• fire protection systems

• nuclear service cooling water systems

• emergency diesel generator system

• component cooling water system

• demineralized water system auxiliary component cooling water system

• hydrogen recombiner and monitoring

• turbine plant cooling water system system

• river intake structure system

• compressed air systems

• drain systems chemical and volume control and boron

• potable and utility water systems recycle systems

• radiation monitoring system

• ventilation systems - control building (CB)

• reactor makeup water storage tank and

• ventilation systems - auxiliary building degasifier system (AB)

• ventilation systems - containment building

• sampling systems (CTB)

• auxiliary gas systems

• ventilation sbstems - fuel handling

• chilled water systems building (FH )

• ventilation systems - diesel generator

• waste management systems building

• thermal insulation

• ventilation systems - auxiliary feedwater

• miscellaneous leak detection systems pumphouse 27

• * *

~ D.S.NR C 3.4 Aging Management of Steam and United States Nuclear Regulatory Commission ProtectingPeopkandtheEnvironment Power Conversion Systems

• main steam system

• feedwatersystem

• SG blowdown processing system

• auxiliary feedwater system

• auxiliary steam system 28

• * *

~U.S.NRC 3.5 Aging Management of United States Nuclear Regulatory Commission Protecting People and the Environment Containments, Structures, and Component Supports

• containment structures

• auxiliary, control, fuel handling and equipment buildings

• emergency diesel generator structures

• turbine building

• tunnels and duct banks

• NSCW structures

• concrete tank and valve house structures

• switch yard structures

• fire protection structures

• radwaste structures

• auxiliary feedwater pump house structures

• component supports and bulk commodities 29

• * *

~U.S.NRC Section 3.5 Aging Management

~~;:c::;~:;;~a::~;~;~~i::::; of In-Scope Inaccessible Concrete Testing performed in November 2005 and May 2007 found:

Acceptance VEGP (2005-2007)

Criteria .

min max pH >5.5 5.77 8.24 Chlorides (ppm) <500 1.95 8.71 Sulfates (ppm) <1500 2.9 12.5 30

• * *

~U.S.NRC 3.6 Aging Management of Electrical United States Nuclear Regulatory Commission Protecting People and the Environment and Instrumentation and Controls System

• cable connections (metallic parts) not subject to 10 CFR 50.49 EO requirements

• conductor insulation for electrical cables and connections not subject to 10 CFR 50.49 EO requirements

• conductor insulation for inaccessible medium-voltage cables not subject to 10 CFR 50.49 EO requirements

• connector contacts for electrical connectors exposed to borated water leakage not subject to 10 CFR 50.49 EQ requirements

• fuse holders (not part of a larger assembly): insulation not subject to 10 CFR 50.49 EQ requirements

• fuse holders (not part of a larger assembly): metallic clamps

• high voltage insulators

• switchyard bus and connections

• transmission conductors and connections 31

• * *

~U.S.NRC SER Section 4: Time-Limited Aging United States Nuclear Regulatory Commission Protecting People and the Environment Analyses

• 4.1 TLAA Process

• 4.2 Reactor Vessel Neutron Embrittlement

• 4.3 Metal Fatigue

• 4.4 Environmental Qualification of Electrical Equipment

• 4.5 Concrete Containment Tendon Prestress

• 4.6 Containment Liner Plate Metal Containments and Penetration Fatigue

• 4.7 Other Plant Specific TLAA 32

• * *

~U.S.NRC Section 4.2 Reactor Vessel United States Nuclear Regulatory Commission Protecting People and the Environment Neutron Embrittlement Analyses Reviews were performed to evaluate reactor vessel neutron fluence and the corresponding vessel embrittlement in terms of adjusted reference temperature (ART) and:

- Upper-shelf energy

- Pressurized thermal shock

- Pressure-temperature limits The staff concludes that the reactor vessel neutron embrittlement analyses meet the review criteria in the Standard Review Plan.

33

• * *

~U.S.NRC Upper Shelf Energy (USE)

United States Nuclear Regulatory Commission Protecting Peopk and the Environment Decrease Reactor vessel Fluence Unirradiated Predicted 56.3 EFPY EOl USE limiting X10 19 USE USE Projected Acceptance material n/cm2 (ft-Ib) Decrease USE Criteria (E>1.0 (10CFR50 (ft-Ib) (ft-Ib) apdx. G.,

MeV)

%)

Unit 1 Nozzle 0.0532 70 12 61 > 50 to-I ntermediate Shell Plate Circumferential weld 103-21 Unit 2 Shell 0.0455 64 11 56 > 50 Course Weld 105-121A 34

• * *

~U.S.NRC Reactor Vessel RT PTS United States Nuclear Regulatory Commission Protecting People and the Environment 60 calendar years RT pTS 56.3 EFPYs 10 CFR 50.61

.

Unit 1 / Unit 2 screening.

Fluence 3.2x1 0 19 n/cm 2 / 3.02x1 0 19 n/cm 2 -

E > 1.0 MeV Calculated RT PTS 123.3°F /134.2°F < 270°F

• The limiting reactor vessel material is Intermediate Shell Plate Heat Number 88805-2 for Unit 1 and Nozzle Shell Course R3-3 for Unit 2.

• The calculational fluence methodology adheres to the guidance of RG 1.190.

35

• * *

~U.S.NRC United States Nuclear Regulatory Commission Protecting Peopk and the Environment Additional TLAAs

• 4.3 Metal Fatigue Analyses

• 4.4 Environmental Qualification of Electrical Equipment

• 4.5 Concrete Containment Tendon Prestress

• 4.6 Containment Liner Plate Metal Containments and Penetration Fatigue 36

• * *

~U.S.NRC United States Nuclear Regulatory Commission Protecting People and the Environment 4.7 Other Plant Specific TLAA

• 4.7.1 Leak Before Break Analysis

• 4.7.2 Fuel Oil Storage Tank Corrosion Allowance

• 4.7.3 Steam Generator Tube, Loss of Material

• 4.7.4 Cold Overpressure Protection System

• 4.7.5 Underclad Cracking of Reactor Pressure Vessel 37

• * *

~U.S.NRC Conclusion United States Nuclear Regulatory Commission Protecting People and the Environment On the basis of its review, the staff determines that the requirements of 10 CFR 54.29(a) have been met.

38

• * *

/

7

. .

.

• United States Nuclear Regulator)r Commission Protecting People and the Environment 39

• * *

~U.S.NRC United States Nuclear Regulatory Commission Protecting People and the Environment License Conditions

• The first license condition requires the applicant to include the UFSAR supplement required by 10 CFR 54.21 (d) in the next UFSAR update, as required by 10 CFR 50.71 (e), following the issuance of the renewed license.

• The second license condition requires future activities identified in the UFSAR supplement to be completed prior to the period of extended operation.

• The third license condition requires that all capsules in the reactor vessel that are removed and tested meet the requirements of American Society for Testing and Materials (ASTM) E 185-82 to the extent practicable for the configuration of the specimens in the capsule. Any changes to the capsule insertion and withdrawal schedule, including use of spare .

capsules, must be approved by the staff prior to implementation. All capsules placed in storage must be maintained for future insertion. Any changes to storage requirements must be approved by the staff, as required by 10 CFR Part 50, Appendix H.

40

e'

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• Agenda SOUTHERN A COMPANY

• Introductions

• Description of VEGP and Current Status

• License Renewal Project

• Inspection Results (NRC Region II)

• Summation and Questions 2

VEGP Representatives SOUTHERN A COMPANY

• Tom Tynan, Site Vice President

• Lee Mansfield, Engineering Support Manager

• Chalmer Myer, License Renewal Project Manager 3

Site Description SOUTHERN A.

COMPANY

• Westinghouse (NSSS), Bechtel (AE)

• Two 4 Loop PWR Units e 3625 MWt e 1250 MWe

• Ultimate Heat Sink - NSCW Forced Draft Cooling Towers and Basins

• Turbine Cycle Cooling Provided By Natural Draft Towers 4

SOUYHERNA Ownership COMPANY

• Plant Licensee and Operator e Southern Nuclear Operating Company

• Plant Owners e Georgia Power Company (45.7%)

e Oglethorpe Power Corporation (30 % )

e Municipal Electric Authority of Georgia (22.7 % )

e City of Dalton, Georgia (1.6%)

5

Licensing History SOUTHERN A COMPANY Unit 1 Unit 2

• Construction Permit June 1974

• Operating License Jan 1987 Feb 1989

• Stretch Power Uprate (4.5%) March 1993

• License Transfer to SNC March 1997

• LRA Submitted June 2007

• MUR Power Uprate (1.70/0) January 2008

• Operating License Expires Jan 2027 Feb 2029 6

~

Current Plant Status SOUTHERN A COMPANY

• Unit One e Completed refueling outage 14 in April 2008 e 18 month average Capability Factor 92%

• Unit Two e Completed refueling outage 13 in Oct. 2008 e 18 month average Capability Factor 90%

7

• • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • , ****

SOUIHERNA VEGP License Renewal Project COMPANY

• VEGP License Renewal e 10 CFR 54.17(c) Exemption e Project Team e Scoping Highlights e Aging Management Reviews e Aging Management Programs e VEGP AMP Exceptions e Time Limited Aging Analyses e Commitments 8

VEGP License Renewal Project SOUTHERN COMPANY A

.10 CFR 54.17(c) Exemption e NRC granted VEGP an exemption to 10 CFR 54.17(c) to submit Vogtle Unit 2 License Renewal Application prior to reaching 20 years remaining on the operating license

• Basis: Unit 2 is the same design and construction as Unit 1 9

• • • • • • • • • • • • • • • • • • • • • \ **************** " **** 1 SOUIHERNA.

VEGP License Renewal Project COMPANY

• License Renewal Project Team

• In house project team

• Core team from Hatch/Farley LR

• Vogtle experience added for VEGP LR

• Expanded on success of previous applications

• LR Team engaged with the industry

• Working groups (NEI, EPRI)

• Participated in audits/inspections of peer plants

• Supported LR peer reviews

• Site program owners involved in process

• No SER open items 10

• *******************************************

VEGP License Renewal Project SOUTHERN A COMPANY

• Seoping Highlights e Performed consistent with NEI 95-10 Rev 6 e Conservative spaces based approach used for (a)(2) scoping for spatial interaction e Mechanical boundary drawings included (a)(1), (a)(2) and (a)(3) scoped components e SSO - Scoping of switchyard SSCs consistent with NRC Staff Guidance 11

• • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • "....

VEGP License Renewal Project SOUTHERN A COMPANY

• Aging Management Reviews e Followed NEI 95-10 guidance for AMRs e Made extensive use of GALL

• 86% of AMR items consistent with GALL

• Non-GALL items primarily material, environment or aging effect not in GALL 12

• • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • " ****

-~

VEGP License Renewal Project SOUTHERN A COMPANY

• Aging Management Programs e 38 Aging Management Programs

• 9 existing programs with no change

• 15 existing programs with enhancements

• 14 new programs e 27 GALL Programs

• Only minor exceptions

• Plant specific programs incorporated GALL attributes where possible 13

• • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • "....

SOUIHERNA VEGP License Renewal Project COMPANY

• VEGP AMPs - Typical Exceptions to GALL e Use of a different version of a code or standard (consistent with VEGP CLB) e Manages material/environment not in GALL e AMP scope differences e Use of alternative inspection methods 14

VEGP License Renewal Project SOUTHERN A COMPANY

• Metal Fatigue e VEGP program currently uses FatiguePro e VEGP has committed to implement benchmarked software to manage fatigue prior to the period of extended operation.

15

• • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • "....

VEGP License Renewal Project SOUTHERN A COMPANY

• Commitment Management

_ 39 commitments made to enhance aging management at VEGP

_ Commitments are tracked through Vogtle Commitment Tracking Program r-

--License -nuatwitHtnk- ---I AMPs and commitments 16

• • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • "....

Inspection Results SOUTHERN A COMPANY

• Region II Site Inspection e Performed walkdown of Boric Acid Corrosion Control Program during 1R14 (April 2008) e Team on site for two weeks in May/June 2008

-

e VEGP enhancedtwD existing programs as a result of comments from the inspectors 17

• • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • "....

sourHERNA Inspection Results COMPANY

• Boric Acid Corrosion Control Program (SACCP)

• Inspection concluded BACCP would adequately manage boric acid corrosion

• However inspector noted non boric acid deposits from NSCW system condensation that could mask BAC eCorrecttv-e actions to be implemented

• Systematic inspection, cleaning and repainting program

• Procedure changes and enhanced communication

• Evaluate system improvements to control condensate 18

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Inspection Results SOUTHERN COMPANY A

• Medium Voltage Cables

• In scope medium voltage cables at VEGP are located in tunnels and not subject to submergence, with one exception

• Non-safety related 4kV feeders to high voltage switchyard switch house

• Inspection found water in pull box near switch house

• Corrective action - implemented LR aging management program

• Quarterly inspection

• Trending of results 21

• • • • • • • • • • • • • • • • • • • • • ,****************"....

Summary SOUTHERN A COMPANY

• Experienced team created high quality LRA

• Extensive use made of GALL

• Thorough and successful audits and inspection of the LRA and programs

• VEGP responsive to NRC through out review

• VEGP is prepared to manage aging beyond 40 years 22