ML102590478
| ML102590478 | |
| Person / Time | |
|---|---|
| Site: | Palo Verde  |
| Issue date: | 09/08/2010 |
| From: | Advisory Committee on Reactor Safeguards |
| To: | |
| howard k | |
| References | |
| NRC-416 | |
| Download: ML102590478 (216) | |
Text
Official Transcript of Proceedings NUCLEAR REGULATORY COMMISSION Title: Advisory Committee on Reactor Safeguards Plant License Renewal Subcommittee Docket Number: (n/a)
Location: Rockville, Maryland Date: Wednesday, September 8, 2010 Work Order No.: NRC-416 Pages 1-156 NEAL R. GROSS AND CO., INC.
Court Reporters and Transcribers 1323 Rhode Island Avenue, N.W.
Washington, D.C. 20005 (202) 234-4433
1 1
2 DISCLAIMER 3
4 5 UNITED STATES NUCLEAR REGULATORY COMMISSIONS 6 ADVISORY COMMITTEE ON REACTOR SAFEGUARDS 7
8 9 The contents of this transcript of the 10 proceeding of the United States Nuclear Regulatory 11 Commission Advisory Committee on Reactor Safeguards, 12 as reported herein, is a record of the discussions 13 recorded at the meeting.
14 15 This transcript has not been reviewed, 16 corrected, and edited, and it may contain 17 inaccuracies.
18 19 20 21 22 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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2 1 UNITED STATES OF AMERICA 2 NUCLEAR REGULATORY COMMISSION 3 + + + + +
4 ADVISORY COMMITTEE ON REACTOR SAFEGUARDS 5 (ACRS) 6 SUBCOMMITTEE ON PLANT LICENSE RENEWAL 7 + + + + +
8 WEDNESDAY 9 SEPTEMBER 8, 2010 10 + + + + +
11 ROCKVILLE, MARYLAND 12 + + + + +
13 The Subcommittee met at the Nuclear 14 Regulatory Commission, Two White Flint North, Room 15 T2B1, 11545 Rockville Pike, at 1:30 p.m., Mario V.
16 Bonaca, Chairman, presiding.
17 COMMITTEE MEMBERS:
18 MARIO V. BONACA, Chairman 19 J. SAM ARMIJO, Member 20 SAID ABDEL-KHALIK, Member 21 MICHAEL T. RYAN, Member 22 WILLIAM J. SHACK, Member 23 JOHN W. STETKAR, Member 24 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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3 1 ACRS CONSULTANT:
2 JOHN J. BARTON 3
4 ACRS STAFF PRESENT:
5 MICHAEL BENSON, Designated Federal 6 Official 7 EVELYN GETTYS 8 ALLEN HISER 9 BRIAN HOLIAN 10 WILLIAM HOLSTON 11 KENT HOWARD 12 NAEEM IQBAL 13 JAMES MEDOFF 14 NEIL O'KEEFE 15 GREG PICK 16 LISA REGNER 17 ABDUL SHEIKH 18 SIMON SHENG 19 DAVID WRONA 20 21 22 23 24 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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4 1
2 ALSO PRESENT:
3 ERIC BLOCHER, APS 4 WINSTON BORRERO, APS 5 DOUG COXON, APS 6 TOM GRAY, APS 7 JOHN HESSER, APS 8 MARK HYPSE, APS 9 MOHAMMAD KARBASSIAN, APS 10 ANGELA KRAINIK, APS 11 DONALD LYNCH, APS 12 REX MEEDEN, APS 13 GLENN MICHAEL, APS 14 SHABBIR PITTALWALA, APS 15 MARK RADSPINNER, APS 16 RICH SCHALLER, APS 17 KEN SCHRECKER, APS 18 19 20 21 22 23 24 25 26 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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5 1 P R O C E E D I N G S 2 1:27 p.m.
3 CHAIRMAN BONACA: The meeting will now 4 come to order. This is a meeting of the Plant License 5 Renewal Committee. I am Mario Bonaca, Chairman of 6 the Subcommittee meeting. ACRS members in attendance 7 are Said Abdel-Khalik, Sam Armijo, John Stetkar, 8 Michael Ryan and Bill Shack.
9 ACRS consultant John Barton is also 10 present. Michael Benson of ACRS staff is the federal 11 official for this meeting. At this meeting, we review 12 the license renewal application for the Palo Verde 13 Nuclear Generating Station, and the associated safety 14 evaluation report with an open item.
15 We will hear presentations from Arizona 16 Public Service Company representatives, NRC staff and 17 other interested persons regarding this matter. We 18 have received a comment from a member of the public, 19 Mr. Bob Leyse, challenging the technical phases of 20 Part 54 for reactors.
21 There were no requests for time to make 22 oral statements from members of the public regarding 23 today's meeting. The entire meeting will be open to 24 public attendance. The Subcommittee will gather 25 information, analyze relevant issues and facts, and NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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6 1 formulate proposed positions and actions appropriately 2 for deliberation by the full Committee.
3 The rules for participation in today's 4 meeting have been announced as part of the notice of 5 this meeting, previously published in the Federal 6 Register.
7 A transcript of this meeting is being kept 8 and will be made available, as stated in the Federal 9 Register notice. Therefore, we request that 10 participants in this meeting use the microphones that 11 are located throughout the meeting room when 12 addressing the Subcommittee.
13 The participants should first identify 14 themselves and speak with sufficient clarity and 15 volume so that they can be readily heard. Before I 16 proceed with the meeting and pass on the meeting to 17 Mr. Holian, I would like to ask him to, during the 18 meeting at your convenience, it would be of interest 19 to the Committee to hear about what the plans of the 20 NRC are for handling changes to license applications 21 that may occur in the next, for example in the case of 22 Palo Verde, 15 to 17 years from now.
23 Given the time is so long, there is an 24 interest in knowing how do we handle events, 25 significant issues, operating experience and reflect NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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7 1 those necessary changes to the commitments. I mean is 2 it going to happen the way that we have seen today, or 3 do you have any perspective on that? That would be of 4 interest to us. With that, I'll pass on the meeting 5 to you.
6 MR. HOLIAN: Thank you, Chairman, and good 7 afternoon ACRS members. My name is Brian Holian. I'm 8 the Director of the Division of License Renewal. I'll 9 just briefly touch on the agenda and introductions 10 today.
11 The agenda is we are here to discuss the 12 draft safety evaluation report for the Palo Verde 13 units. The agenda for today is we need to do brief 14 introductions. I'll turn it over to the licensee for 15 their lengthy presentation, we'll take a break and 16 then again the staff will follow.
17 NRC staff that are here, just some that 18 I'll mention right now. To my right is the Branch 19 Chief in Projects for License Renewal, and it has the 20 Palo Verde units, among others, Mr. Dave Wrona. To 21 his right is Lisa Regner. She's the senior project 22 manager and has had Palo Verde for the extent of this 23 review, and you'll be hearing from her later.
24 Behind me is a senior reactor inspector 25 from the region, Mr. Greg Pick. He'll be presenting NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 1 the inspection findings, and his boss is here also, 2 Mr. Neil O'Keefe, the Branch Chief from the Division 3 of Reactor Safety, Region IV.
4 Just a comment on the draft safety 5 evaluation that you've seen. There's one open item on 6 metal fatigue. The members have probably seen it's 7 not related to the normal Westinghouse issue that's 8 been an open item on a lot of the Westinghouse-type 9 plants.
10 It's still metal fatigue, but it's a 11 series of questions we had kind of related to their 12 background, their FSAR and how they were doing in some 13 of their calculations.
14 So I know both the licensee and I will get 15 into that. But it's different than the old regulatory 16 issues summary we had on Westinghouse plants. I just 17 wanted to highlight that, but still similar-type 18 questions from the staff. There's also several 19 confirmatory items that I know will be addressed 20 today.
21 Chairman, regarding your question, I'll 22 address that just briefly now and then maybe again, 23 right before the staff's presentation. It's 24 historically now we've had some plants that have come 25 in 10 to 15 to 20 years before their licenses, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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9 1 original license expires.
2 So that question is very relevant for how 3 do you progress now and in the next 15 years with 4 lessons learned in aging management programs as it is.
5 Well one, the rule allows the licensee to come in 20 6 years in advance. So the rule allows that, and we do 7 our review to the best up to that point.
8 The rule, I think, was originally written 9 with the idea that enough operating experience is 10 present to understand the type of aging management 11 issues that are present and could therefore formulate 12 a good staff review. That's some of the theory behind 13 the rule, as I've had to answer that in other public 14 sessions.
15 The question of applying operating 16 experience, assuming they get a license and then in 17 the period before their extended period goes on, is an 18 item we've worked with particularly close with the 19 region, and our other Part 50 people. I've often 20 said, you know, a lot of people will say, even 21 sometimes in this committee we'll hear "Well that's a 22 Part 50 question" or "That's a Part 54 question."
23 In reality, my answer is always "they 24 overlap." I can -- a lot of Part 50 questions that 25 are current day issues have an aging management issue, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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10 1 and if they do, I incorporate them in our review, and 2 so that's why we often -- and yet this Committee often 3 asks how are you doing, what are you doing on that for 4 current day plants.
5 Then we'll answer that, because a lot of 6 times we work with our other tech review branches and 7 do that. On this question of applying operating 8 experience, we work closely with the regions. The 9 best hammer or review I have is the inspection that we 10 do again with the regions, right before, the year or 11 so before the period of extended operation.
12 We expect that their aging management 13 programs are living documents, that when I give the 14 license, the GALL says it's a ten element program.
15 The tenth element is operating experience.
16 So we trust that a plant will learn from 17 the operating experience, from the time they receive 18 their license until the time of end of the period of 19 extended operation, and we'll inspect that for their 20 aging management programs, before they go into the 21 period of extended operations.
22 That's a quick answer. I'll develop that 23 a little bit more before the NRC presentation. But I 24 just wanted to touch on that now.
25 CHAIRMAN BONACA: Okay.
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11 1 MR. HOLIAN: With that, I'll turn it over 2 to the licensee and John, Mr. John Hesser, Vice 3 President for Nuclear Engineering at Palo Verde.
4 MR. HESSER: Thank you, Mr. Holian. Good 5 afternoon. On behalf of the Palo Verde staff and its 6 owners, it's -- we appreciate the opportunity to 7 discuss with you, Mr. Chairman and the distinguished 8 members of the ACRS, our license renewal application 9 and our draft safety evaluation report.
10 My name is John Hesser. I am the Vice 11 President of Nuclear Engineering and the executive 12 sponsor for Palo Verde's license extension. Here with 13 us today in attendance we have Mr. Bob Bement, our 14 site Vice President of Nuclear Operations. Seated 15 here at the table I have Mr. Mo Karbassian. He's our 16 Director of Nuclear Engineering; Ms. Angie Krainik.
17 She's our manager of License Renewal.
18 Eric Blocher; he's our project manager for 19 our license renewal application at Palo Verde. Glenn 20 Michael, seated down here, our lead licensing engineer 21 for license renewal; and Rich Schaller. He's our 22 Metal Fatigue lead.
23 In addition, we've brought several 24 personnel with us, both leaders and front-line 25 personnel from Palo Verde, to discuss various topics NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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12 1 in anticipation of your questions of our application.
2 The people with us today are knowledgeable 3 in aging management programs, engineering programs.
4 We have folks from Operations, our Probabilistic Risk 5 Assessment area, Environmental, Radiation Protection; 6 also Engineering Design.
7 Also with us to be recognized is two folks 8 from our STARS Center of Business, Mr. Tony Harris and 9 Chalmer Myer. The Center of Business was established 10 to establish a format, a consistency for the seven 11 Westinghouse plants that will apply for license 12 renewal, so we give you a standard application, apply 13 operating experience and lessons learned for the 14 quality of those applications.
15 In addition, Palo Verde has brought along 16 seven new members of our staff that represent 17 Operations, Maintenance, Engineering, Licensing and 18 Chemistry. These folks are new hires to Palo Verde.
19 They're new to the industry.
20 Mr. Chairman, you asked the question about 21 sustainability. We brought these folks along as part 22 of a knowledge transfer and learning, to learn the 23 ACRS process and what license renewal is all about.
24 They represent the future staff at Palo Verde who will 25 own the plant and own the responsibility to operate it NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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13 1 safely as those of us who age and leave the business.
2 So we brought them along for that learning 3 experience.
4 Here's the agenda for our presentation 5 today. I will give you a brief plant history and 6 background. Mr. Karbassian will talk just briefly 7 about major improvements and long-range planning, how 8 we're taking care of our plant and plant equipment.
9 Ms. Krainik and our staff will talk about 10 the license renewal application, our open item in 11 metal fatigue and our confirmatory items, mention some 12 of the regional inspection items and, if time allows, 13 I'll make some concluding remarks.
14 Our mission in Palo Verde, which was 15 established in 2007, prior to our license renewal 16 application in December 2008, was to safely and 17 efficiently generate electricity for the long term.
18 As you can tell by the underscored words, we put 19 strong emphasis on safely generating for the long 20 term.
21 With regards to license renewal, we feel 22 it's important that for the long term, we establish 23 good, solid programs. We've already begun to 24 implement those programs at Palo Verde. We are not 25 waiting until we get near the end of the license NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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14 1 period, but we've begun to implement some of those 2 programs, and again by evidence of bringing new staff, 3 it's important that the people are there and 4 knowledgeable about the designed licensing basis and 5 requirements of the plant to operate it safely.
6 CHAIRMAN BONACA: You used the word 7 "implementing." So you're not only developing the 8 program. But on some occasions you do implement them 9 now?
10 MR. HESSER: Yes. When we get to Ms.
11 Krainik's presentation, she will illustrate exactly 12 the progress we have made to date and what progress we 13 still have to go. But yes, we are intending to 14 implement several aspects now into our current 15 programs.
16 CHAIRMAN BONACA: Good.
17 MR. HESSER: Okay. So Palo Verde, the 18 initial construction permit was issued in May of 1976.
19 The initial full power operating licenses are listed 20 here in '85, '86 and '87. This represents 72 years of 21 reactor operating experience.
22 Each unit at Palo Verde is rated 23 approximately 3990 megawatts thermal and 1390 24 megawatts electrical. At Palo Verde, we use reclaimed 25 waste water for our condenser cooling cycle. We have NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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15 1 no lake, no ocean and no river that we sit on, and we 2 use spray ponds as our ultimate heat sink.
3 Palo Verde was designed and built on the 4 emphasis that is three units of common design. We 5 have common operating procedures, common design and 6 licensing basis, and we try to maintain the 7 configuration as close as possible with each other.
8 That's why you have one licensing submittal 9 application for all three units.
10 With regards to aging management though, 11 there are differences in the plant, and we want to 12 illustrate that, that the differences in the plant 13 pertain to things like type supports, electrical 14 conduit supports. When a plant is built, you do field 15 routing and there's common design criteria and 16 requirements that these supports are built to, and in 17 one case in the SER, it's noted that we have things 18 like drain valves that were put in that were used for 19 things like maintenance or special testing that was 20 done.
21 So you will find some minor differences.
22 But as far as significance in the systems, there are -
23 - we maintain commonality. Our nuclear steam supply 24 system is a combustion engineering system 80 design.
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16 1 Electric. Bechtel Power was our general contractor 2 and architect. They built Palo Verde.
3 Again, we have a large water reclamation 4 facility and we take the secondary treated reclaimed 5 water, and remove hardness and store it for the plant.
6 We have our plant picture coming up to illustrate 7 that for you, and of course we're a zero liquid 8 discharge plant, not again having the river or ocean 9 lake. We discharge to evaporation ponds, and I'll 10 show you that in a second.
11 Just to give you a sense or feel for what 12 Palo Verde is in relationship to the state of Arizona.
13 We're approximately 26 miles from the western edge of 14 metropolitan Phoenix. We're about 57 miles from 15 downtown Phoenix and we're in the Sonoran Desert.
16 Palo Verde has seven owners. There are 17 seven licensees. The number in parentheses underneath 18 the names of the owners represents the percent of 19 ownership. Arizona Public Service is the largest 20 owner. We are the operating agent and we are listed 21 as applicant in the license renewal application.
22 Here's the aerial view. I'll just touch 23 on this real quickly, to give you a feel. The 24 property of Palo Verde is over 4,000 acres. It's a 25 large plot of land that the numbers encircled here on NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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17 1 the slide represent the three units, Unit 1, 2 and 3.
2 You can tell the little rectangular 3 circles there represent the spray ponds, the ultimate 4 heat sink, down to the lower, your lower right-hand 5 corner would be the water reclamation facility, where 6 the reclaimed water comes to the plant.
7 It is treated and then put in the 8 reservoirs that are listed there. There's an 85 acre 9 reservoir and a 45-acre reservoir, and then as it goes 10 through and cycles through the condenser cooling cycle 11 and we discharge out from the sedimentation basin 12 over to the evaporation ponds. We have three 13 evaporation ponds.
14 Just to point out a little bit different 15 coloration of the evaporation ponds. We have made, 16 increased the capacity of those for future growth of 17 the plant, the long-term operation of the plant by 18 adding Evaporation Pond No. 3, and also in the 19 reservoir. We used to have the 85-acre reservoir. We 20 added recently the 45 acre reservoir for the long term 21 operation.
22 MR. BARTON: The source of your water 23 reclamation facility, what's the water sourcing?
24 Where does it come from?
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18 1 purchase the Water from -- actually the metropolitan 2 area of Phoenix. There are seven cities, Phoenix 3 being one of them and some other local communities.
4 Recently, we just renegotiated a contract that extends 5 beyond what would be the 60 year life of Palo Verde if 6 we were granted a license extension, sir.
7 MR. BARTON: Thank you.
8 MR. HESSER: You're welcome. Yes.
9 MEMBER STETKAR: On that, I think I read 10 somewhere that that water comes through this like 35-11 mile pipeline? It supplies the water to the site.
12 MR. HESSER: Your information is fairly 13 correct. It's actually 37 miles.
14 MEMBER STETKAR: I didn't want to seem 15 that precise. It's kind of an off the top --
16 (Laughter.)
17 MEMBER STETKAR: I have 37 written down.
18 MR. HESSER: 37 miles.
19 MEMBER STETKAR: I know that's your normal 20 cooling water supply. What's the capacity of your 21 reservoirs? In other words, how long can you operate?
22 Suppose that water supply disappears, like the pipe 23 disappeared?
24 MR. HESSER: If ever we would have a 25 trouble with either the water reclamation facility or NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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19 1 the pipeline that supplies it, our reservoir, 2 depending upon the time of year of course, it's 3 probably about 13 to 16 days of operation that we can, 4 which gives us ample time --
5 MEMBER STETKAR: It would be April through 6 October when it's 100 plus?
7 MR. HESSER: When it's hotter, it's the 8 lower number, yes.
9 MEMBER STETKAR: So about two weeks 10 roughly?
11 MR. HESSER: Yes, roughly two weeks.
12 MEMBER STETKAR: And who controls that 13 water pipeload, the aging of that water pipeline? Who 14 monitors, who owns that pipeline?
15 MR. HESSER: Well, we actually own the 16 pipeline and we have a right-of-way across the 37 17 miles that it spans across, and we maintain it, and 18 actually we have quite a history of maintaining that 19 pipe. We have PM programs and we have a long-range 20 plan where we go out and almost every time we have a 21 refueling outage in the units, where the water demand 22 goes low, we actually do work on that pipeline. We go 23 out and do inspection and repair.
24 MEMBER STETKAR: Is that, I didn't check.
25 Is that pipe in scope for your license renewal?
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20 1 MR. HESSER: No sir, it is not in scope 2 for license renewal.
3 MEMBER STETKAR: Thank you.
4 MR. HESSER: All right. So this slide 5 here is just to give you the information that today at 6 Palo Verde, all three units are operating at 100 7 percent power, and you can tell here that Unit 1 and 8 Unit 2 is in its 16th operating cycle. Unit 3 is in 9 its 15th operating cycle and we're excited to have it 10 slated, scheduled to have a refueling outage starting 11 on the 1st of October in Unit 3.
12 So we do two refueling outages a year.
13 We're on an 18-month cycle. With that, I will turn it 14 over to Mr. Karbassian, who will talk about major 15 improvements in long-range planning. Thank you.
16 MR. KARBASSIAN: Mr. Chairman, members of 17 the Committee, I would like to take this opportunity 18 to go over examples of the improvements that we've 19 made at Palo Verde. Then I'll cover our long-range 20 planning process and our top ten process, that helps 21 us in identification and resolution of our technical 22 issues.
23 Here are some of the improvements that 24 we've made at Palo Verde. These improvements are 25 either equipment reliability related. Some of them NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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21 1 are improvement in efficiency, and some of them help 2 with reduction in overall plant risk.
3 An example of the improvements that we've 4 made on equipment within the scope of the licensing 5 renewal are replacement of our steam generators, our 6 replacement of reactor vessel heads as well as our 7 management of Alloy 600 and similarly developed 8 metals.
9 Relative to replacement of the steam 10 generators, we replaced them to gain efficiency, 11 improve reliability and resolve operating experience 12 with Alloy 600. Our new steam generators have Alloy 13 690 and tube material, as well as a divider plate.
14 We've replaced our reactor head and we've 15 replaced our reactor heads in Unit 1 and 2, and we 16 will be replacing it in Unit 3 coming this fall.
17 MEMBER STETKAR: Was that -- did you have 18 cracking, or you just did that as a proactive measure?
19 MR. KARBASSIAN: We did that as a 20 proactive measure, sir. Once the reactor heads are 21 replaced, then we will have replaced or mitigated 22 susceptible components in our high temperature 23 application.
24 MEMBER STETKAR: You don't have instrument 25 nozzle penetrations or something like that still left?
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22 1 MR. KARBASSIAN: We have replaced our 2 instrument nozzles in high temperature application.
3 Relative to our site top ten process, it's designed to 4 involve personnel from each department to identify and 5 prioritize their technical or equipment reliability 6 issues.
7 For example, replacement of the feed 8 waters steam admission valve was identified by our 9 Operations, by our Maintenance, as well as Engineering 10 Department, in their department top ten. Once it was 11 identified, then it went, rolled over to the site top 12 policy process, and then we replaced the valve from 13 solenoid-operated to a motor-operated, to improve 14 reliability.
15 We've completed several of these 16 departmental and site top ten issues, and we have 17 several planned. Intended in this was to show our 18 approach in resolving the equipment issues, not to 19 list every one of the site top ten's.
20 MEMBER STETKAR: Are you going to talk 21 later about the spray ponds and their condition, or is 22 this the time to ask about those?
23 MR. HESSER: We did not have any planned 24 part of our presentation, but we are prepared to talk 25 about it if you'd like to. Anything in particular?
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23 1 MEMBER STETKAR: Yes. Two questions came 2 up. Apparently you had some chemistry problems in the 3 spray ponds. I haven't found the point in my notes 4 here, so I can't cite the specific dates.
5 MR. HESSER: A few years ago.
6 MEMBER STETKAR: A few years ago, 2005, 7 2006 time frame, I believe. What were they, and what 8 -- are there any lingering effects from whatever those 9 problems were in terms of piping systems or heat 10 exchangers that are connected to the spray pond water?
11 MR. KARBASSIAN: I'd like to ask Mark 12 Radspinner, our System Engineering section lead, to 13 address it.
14 MR. RADSPINNER: Hi. My name is Mark 15 Radspinner. I'm in System Engineering at Palo Verde.
16 I'm not in the Chemistry Department, so I'm not going 17 to get into great detail on the chemistry aspects.
18 MEMBER STETKAR: That's okay. I'm not a 19 chemist, so I wouldn't know what you were saying 20 anyway.
21 MR. RADSPINNER: The following issues and 22 the chemistry problems we did have was as a result of 23 the combinations of chemicals that we would use to --
24 MEMBER STETKAR: There's one over here.
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24 1 on?
2 MR. RADSPINNER: Okay. As I indicated, 3 the combination of chemicals that we were using to 4 treat the spray ponds did result in a fouling 5 mechanism.
6 It did affect our heat transfer capability 7 in our essential cooling water heat exchangers.
8 Extensive evaluation was performed and those have all 9 been corrected. The performance of the essential 10 cooling water heat exchangers has returned to normal.
11 MEMBER STETKAR: It was a fouling. It 12 wasn't, it didn't enhance corrosion?
13 MR. RADSPINNER: The chemistry, of course, 14 was intended to prohibit the corrosion, but it had a 15 side effect that has since been corrected.
16 MEMBER STETKAR: Okay, and what about -- I 17 don't know if you're the appropriate person while 18 you're up there. There apparently is some evidence 19 of, and I don't know whether it's spalling or cracking 20 on the spray pond concrete itself.
21 MR. KARBASSIAN: Yes. Mr. Ken Schrecker 22 will address the cracking of the concrete.
23 MEMBER STETKAR: Okay.
24 MR. SCHRECKER: Ken Schrecker, Palo 25 Verde. I'm with system engineering and I have NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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25 1 responsibility for spray pond component monitoring.
2 Yes, there is evidence of some cracking above the 3 water line on our spray ponds, both vertical and 4 horizontal, but by far the vast majority of the 5 cracking is horizontal.
6 The top layer of reinforcing steel, that 7 has had the least amount of concrete depth, of 8 concrete overage is, experienced some corrosion from 9 the chemicals in the spray pond water. It's non-10 structural degradation at this time, and as was shown 11 on our slide for the top ten program, we do have plans 12 on making those concrete repairs by 2015. That's one 13 of our commitments in the draft SER.
14 MEMBER STETKAR: Do you have any evidence 15 of below-water line cracking or any evidence of 16 leakage? I mean it's pretty dry there. You can see 17 if it leaks; grass will grow.
18 (Laughter.)
19 MR. SCHRECKER: Below the water line, 20 based on our last underwater inspection, nearly all of 21 the cracking is -- we have this very hairline, just 22 hairline cracking below the water line.
23 We really don't have the degradation 24 mechanism below the water line. Above the water line, 25 it's really the wet-dry issues, and we don't have the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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26 1 oxygen below the water line to promote the 2 degradation.
3 We do have one crack on each spray pond.
4 It's a vertical crack below the water line. It's in a 5 very -- it's in the same location of each one of the 6 six ponds. We don't have -- I don't have a good 7 explanation as to why, but we monitor that crack.
8 That crack has been repaired in all six ponds. In 9 fact, we just had to repair one again earlier this 10 year the Unit 3 spray pond.
11 MR. BARTON: That was a through-wall 12 crack, wasn't it? That was a through-wall crack, the 13 one you're talking about?
14 MR. SCHRECKER: It's -- you see, concrete 15 is not -- I can't say that it's watertight. Water is 16 going to meander through concrete and maybe seep, 17 okay. So I would -- I would classify this as seepage.
18 MEMBER STETKAR: Do you have the -- a 19 question I was going to ask later, but I might as well 20 while you're up. It's less of a concern on concrete 21 but it is on rebar. The soils at the site are fairly 22 aggressive, caustic soils. My basic concern about 23 water leakage is related to interaction with the 24 soils, and then getting into rebar and structural 25 members.
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27 1 So the question is do you have any 2 evidence of external seepage from the spray ponds?
3 MR. SCHRECKER: From the spray ponds? We 4 have, we have no evidence of -- well, we've had 5 occasions where we've seen minor seepage, and 6 especially this one vertical crack that I've 7 mentioned. We have no other evidence of seepage below 8 the water lines from the spray ponds.
9 MEMBER STETKAR: Okay.
10 MR. KARBASSIAN: All right, thanks. Going 11 through, relative to our long-range planning, we've 12 institutionalized this process to help us lay out a 13 ten-year look-ahead at overall major modifications and 14 maintenance activities that we need to do to keep Palo 15 Verde operating safely and efficiently for the long 16 term.
17 What you're looking at is some of the 18 examples of items that are identified in our long 19 range plan. Once again, the intent is not to show all 20 of our long range plan, but just to show the overall 21 approach on resolving equipment issues. I'd like to 22 turn --
23 MEMBER SHACK: The high pressure turbine 24 will be associated with the power-up rate?
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28 1 turbine is a replacement for long range, that's 2 correct. I'd like to turn it over to Angie Krainik, 3 Department lead of License Renewal.
4 MS. KRAINIK: Thank you. Mr. Chairman and 5 members of the ACRS, I'd like to provide an overview 6 of the Palo Verde license renewal application.
7 We submitted our application in December 8 of 2008. The Palo Verde application was prepared, was 9 the second one prepared by the STARS Center of 10 Business, which is a consortium of the seven plants 11 that John mentioned earlier, and we created the Center 12 of Business in order to create the license renewal 13 applications.
14 One of the things that we've learned 15 throughout our evaluation, based on staff input and 16 feedback, is we are providing those kind of lessons 17 learned for some of the other applications that are 18 prepared by the Center of Business as well, and I'll 19 talk about some of those as we go forward.
20 We're actively involved with the NRC in 21 the industry as we go through things that are being 22 modified. The generic aging lessons learned report, 23 we were -- started from Rev 0 through Rev 1 and are 24 actively involved in Revision 2 that's ongoing right 25 now.
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29 1 Some of the recent industry items that 2 we're addressing through our application right now is 3 things such as the low voltage cabling, which we're in 4 the process of evaluating and adding to our 5 inaccessible cables program, as well as some 6 additional requirements for our buried piping and 7 tanks program.
8 Throughout the submittal, development, 9 review and then supporting the staff review, Palo 10 Verde has maintained the ownership of the application 11 all the way through, and as we work towards 12 implementation, which I'll talk a little bit further 13 about in a moment, we will continue to maintain that 14 ownership throughout.
15 This provides an overview of the basic 16 process that we followed using Part 54 and the 17 guidance of NEI 95-10. We started with the scoping 18 and screening of the Palo Verde systems, structures 19 and complements, using the design basis documents and 20 information. The aging management review was then 21 performed following that, and evaluated against not 22 only the generic aging lessons learned, but also Palo 23 Verde operating experience.
24 In that -- in informing our aging 25 management programs, we included over 13 years of Palo NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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30 1 Verde operating experience, which also includes 2 industry operating experience, as well as a review of 3 the generic communications from the NRC documentation.
4 As a result, our AMR lines show a pretty 5 high degree of consistency with the generic aging 6 lessons learned report.
7 Moving on, this is an overview of the time 8 limited aging analysis section of our application. We 9 have evaluated the analyses at Palo Verde for those 10 that are at time dependency, and could be affected by 11 operation beyond four years, and they're presented in 12 this portion of the application.
13 I will be discussing, we will be 14 discussing the metal fatigue open item just briefly 15 later in the discussion.
16 Moving on, there was a question earlier 17 talking about the implementation of the aging 18 management program.
19 MEMBER SHACK: I had a particular 20 question, since you're not going to really discuss 21 these in any details. You have this half nozzle 22 repair to the Alloy 600 material in the reactor 23 coolant hot leg, and there's always --
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31 1 seems to mention stress corrosion possibilities in 2 this Alloy 600 and the hot leg. I was just curious as 3 to why that's not considered in the TLAA.
4 MS. KRAINIK: Richard, could you respond?
5 MR. SCHALLER: Yes, I can.
6 MS. KRAINIK: Let me turn it over to Rex 7 Meeden for staff.
8 MR. MEEDEN: Rex Meeden, Palo Verde 9 Engineering. I understand the question is with 10 respect to our pressurizer small bore penetration 11 repairs we've done, in consideration of stress 12 corrosion cracking.
13 MEMBER SHACK: Right. The TLAA just talks 14 about fatigue, and there's no discussion of PWSCC.
15 It's in the hot leg, so I assume the temperature is 16 high enough.
17 MR. MEEDEN: Yes. Are you talking about 18 the -- specifically about the remnant original Alloy 19 600 material that was left in place?
20 MEMBER SHACK: I assume that's what it is.
21 I have no real notion of exactly what it is. I'm 22 just assuming --
23 MR. MEEDEN: Okay.
24 MEMBER SHACK: 4.741 in the SER.
25 MR. MEEDEN: Similar to -- you're correct, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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32 1 and on the hot leg, when we did the small bore 2 penetrations in that location and it's the INCONEL 3 600, Alloy 600 issue. We did address stress corrosion 4 and cracking on the inside surface of the hot leg, and 5 we also did, take a look at stress corrosion cracking 6 for the places where it was applicable on the 7 pressurizer.
8 The reason I say "the places where it was 9 applicable" was on the lower head of the pressurizer, 10 we did heater sleeve repairs where we left a section 11 of Alloy 600 in place. Whereas in the mid-90's, we 12 actually did a full nozzle replacement and removed the 13 original Alloy 600 material in its entirety, that were 14 --
15 MEMBER SHACK: So that's what I'm looking 16 at here, is the half nozzle repair means there's some 17 Alloy 600 left?
18 MR. MEEDEN: Yes. If you would point me 19 to which specific drawing you're looking at?
20 MEMBER SHACK: It just says for the half 21 nozzle repair of the Alloy 600 nozzles in the hot leg, 22 there was a flaw removal and successive inspection 23 requirements in 1992. Then you're doing fatigue 24 analysis. Is this material still in contact with the 25 coolant?
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33 1 MR. MEEDEN: Yes, it is on the hot leg, 2 and on the pressurizer, if I can ask, if I can be 3 allowed to pull up a backup slide to speak to?
4 MEMBER SHACK: Sure.
5 MR. MEEDEN: Brian, could we please pull 6 up Slide 63? This sketch here reflects the bottom 7 head of the pressurizer, and this is one heater sleeve 8 penetration. And to address the question 9 specifically, the section on the inside surface of the 10 pressurizer depicted in red there is a section of 11 Alloy 600 material that was left in place. It was 12 originally a pressure boundary welded on the inside 13 surface.
14 The repair of this was actually an 15 external pad repair depicted in gray on the lower 16 surface of the vessel. There was a weld prep that was 17 there and then a new Alloy 690 sleeve depicted in 18 blue, with a fill-up weld establishing the new 19 pressure boundary.
20 MEMBER ARMIJO: So it has no function 21 anymore? That 600 is just there?
22 MR. MEEDEN: That's correct. However, the 23 point I'd like to make is Mr. Shack is correct, in 24 that we did look at crack propagation with respect to 25 that, to show that was left in place.
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34 1 MEMBER SHACK: Okay. But it's not the 2 pressure boundary any longer?
3 MR. MEEDEN: That's correct.
4 MEMBER SHACK: Okay, and just another 5 topic. One of the confirmatory items, again since you 6 don't seem to be discussing it anywhere, was 7 essentially erosion/corrosion possibilities in the 8 steam generator. You talked about the feed ring being 9 a resistant material.
10 Now is that genuinely a resistant material 11 or is this one of these things where you're depending 12 on trace amounts of chromium to give you some 13 resistance?
14 MR. RADSPINNER: Yes. Mark Radspinner 15 from Palo Verde. That is a chromoly.
16 MEMBER SHACK: That is chromoly?
17 MR. RADSPINNER: It's chromoly, yes.
18 MEMBER ARMIJO: And is it half chromoly, 19 two and a quarter chromoly? How much?
20 MR. RADSPINNER: Do you recall the 21 percentage? One and a quarter.
22 (Off mic comment.)
23 MEMBER SHACK: And just again, on this 24 operating experience, one of the things I noticed in 25 one of the inspection reports is you were still using NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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35 1 a lubricant on your bolts that had molydisulfide. And 2 again, 25 years now of experience says that's not a 3 thing to do.
4 I just, is that a conscious decision on 5 Palo Verde's part, or is that somehow an oversight 6 that you didn't know that you had molydisulfide in 7 that lubricant?
8 MS. KRAINIK: I'd like to go ahead and ask 9 Vincent Guerrero to respond please.
10 MR. GUERRERO: Vincent Guerrero, Design 11 Engineering, Palo Verde, and you're correct. We're 12 still utilizing molydisulfide on the reactor vessel, 13 and the reason for it is because that is the best 14 product for --, and that was what was recommended and 15 endorsed by the NRC in the early 70's.
16 We have committed to removing the use of 17 that lubricant, and switching a graphite-based 18 lubricant. We did some evaluations and we do have 19 enough control that we don't have to worry about 20 stress, corrosion or cracking.
21 MEMBER SHACK: Okay. So that was a 22 conscious decision to continue using the 23 molydisulfide, despite the experience of the early 24 80's, that sort of said it wasn't a good idea?
25 MR. GUERRERO: Yes sir, and we did it in NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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36 1 the guidance of our corrective action process.
2 MEMBER ARMIJO: But you never had any 3 cracking problems with that lubricant?
4 MR. GUERRERO: That is correct, sir.
5 MEMBER ARMIJO: Okay.
6 MS. KRAINIK: So these are the type of 7 things that we just talked about here, as far as 8 operating experience, that you know, we're going to 9 continue to gather as a result of our aging management 10 programs that we've developed as part of our license 11 renewal application, and then moving on into the 12 actual programs, the procedures, the station 13 procedures that we'll -- we will use to implement the 14 aging management programs.
15 So the question that came up earlier about 16 starting, having, using the aging management program, 17 starting to gather information even before we're 18 required to, is part of our process of starting, 19 because there is information that we will learn, as we 20 gather information about aging management, that we 21 will factor back into the program.
22 So we intend to start using it, and then 23 factoring it into the programs going forward. So out 24 of the 59 procedures that we already have on site that 25 we are using, we have incorporated a number of the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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37 1 aging management program requirements into those.
2 That status is provided as well as six new procedures 3 that we're halfway completed on those. So we're just 4 kind of -- from a matter of accounting, out of the 11 5 new procedures, six of those are -- go into one actual 6 procedure.
7 CHAIRMAN BONACA: I have some questions 8 about your management programs, but I believe we have 9 an opportunity later for discussing those, right?
10 MS. KRAINIK: Yes. I'm going to discuss 11 commitment management.
12 CHAIRMAN BONACA: That's right. So maybe 13 I'll raise that issue later.
14 MS. KRAINIK: Okay. Let's go right into 15 that now then.
16 CHAIRMAN BONACA: Huh?
17 MS. KRAINIK: I'll just go right into it 18 now then.
19 CHAIRMAN BONACA: Okay.
20 MS. KRAINIK: So the procedures that I 21 mentioned earlier are the process by which we are 22 incorporating the requirements of the aging management 23 programs and the commitments that we have made into 24 the station procedures.
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38 1 have made as a result of the license renewal 2 application in our regulatory commitment tracking 3 system. It's the same system that we use or have been 4 using for years to track all the other NRC commitments 5 that we have made, and the purpose of that obviously 6 is to make sure that, as time marches on, changes are 7 made to procedures and documents, that we'll continue 8 to make sure that we maintain those commitments.
9 In addition to the procedures I mentioned 10 that are in our regulatory commitment tracking system, 11 also future actions that we've made as a result of the 12 application as in there as well. Things like the 13 update of the equipment qualification binders and some 14 future inspection commitments that we've made, we've 15 captured those in our regulatory commitment tracking 16 system.
17 Between that system and the change 18 management system for procedures, that will help 19 ensure that as changes are made to those procedures, 20 the commitments that we have made are evaluated 21 against those changes.
22 Moving on to the piece of implementation 23 and sustainability, we're already starting with that.
24 We have implementation staff that we are filling 25 positions at Palo Verde to do that. We'll continue to NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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39 1 be engaged in the industry. The NEI License Renewal 2 Working Group for implementation, we are engaged with 3 that.
4 You know, as others before us work through 5 their implementation, we intend to stay engaged with 6 them as well, and also following backup on the STARS 7 Alliance and sharing experience, operating experience 8 in particular across all the seven stations.
9 Moving on, I'd like to transition to a 10 discussion of the open item in the Palo Verde SER with 11 open items. The issue has to do with metal fatigue, 12 and as Brian mentioned earlier, our -- the open item 13 that we have is comprised of the 18 most recently 14 received RAIs on Section 4.3 or Metal Fatigue.
15 Responses to these RAIs have been 16 submitted to the staff, and I believe they are under 17 review at this point.
18 I want to just kind of provide an overview 19 of our application, and in particular metal fatigue.
20 We had a number of feedback questions and concerns 21 expressed by the staff. As a result of that, we 22 recognized that we needed to fundamentally rewrite 23 that section to make it clearer and provide 24 clarification that was not originally there.
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40 1 it together, we had used a peer review process before 2 we submitted it. But we even look back on that and 3 realize that we had not given them all the information 4 they needed to help us end up having a more effective 5 review, and ultimately a better product.
6 So we continue to take those as a type of 7 lessons learned, to make sure that future applications 8 have that incorporated in.
9 Some of the actual changes that we had to 10 make as a result of our application were things like 11 more common terminology. When we prepared our 12 original application, we did not use in some cases the 13 exact same terminology that we have in our current 14 licensing basis or our UFSAR. We went back and 15 provided that clarification, so there was a clear 16 alignment between the way it's described in the UFSAR 17 and then our application.
18 Another example is our transient count.
19 When we originally provided the application, we had 20 done a transient recount for Units 1 and 2, and 21 provided that in the application. After we had 22 provided the application, we completed the review for 23 Unit 3 as well. That also was included in some of our 24 amendments.
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41 1 details on the fatigue analysis as well. As the staff 2 asked questions, we realized that we didn't have the 3 level of detail that the staff needed. We've provided 4 that as well.
5 So we do appreciate the support and the 6 questioning on the part of the staff, and do believe 7 that we ended up with a much better application and a 8 metal fatigue monitoring program than what we 9 originally had to start with.
10 As I mentioned, I think that one of the 11 largest substantial changes that we made as a result 12 of it was to more clearly talking about and describing 13 the fatigue monitoring program during the period of 14 extended operation, and demonstrating that that is 15 essentially an extension of our existing fatigue 16 monitoring program that's in play today.
17 I'd like to turn it over to Rich Schaller, 18 our metal fatigue lead, and he'll provide more 19 discussion about the fatigue monitoring program for 20 the period of extended operation and further 21 discussion of the open item itself.
22 MR. SCHALLER: Mr. Chairman and members of 23 the Committee, good afternoon. I'll be covering three 24 topics related to metal fatigue. The first of the 25 three topics will be metal fatigue program, both the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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42 1 current and the enhanced program and going over the 2 changes that we're making.
3 Also, I'll be discussing the three 4 commitments in the LRA that are related to metal 5 fatigue topics, and finally we talk about the one SER 6 open item. I'd like to take this opportunity to echo 7 what Angie said, that the comments that we received 8 from the staff were very helpful as far as improving 9 our application and improving our program, and we 10 found that to be very constructive.
11 This next slide here really is the heart 12 of my discussion about the metal fatigue program.
13 What this shows you is the attributes of the program 14 and how they fit into the current program and the 15 enhanced program.
16 The first three attributes there, as you 17 can see, describe the bulk of our current program.
18 Our current program fully meets our current licensing 19 basis, and the changes that we are making, which are 20 highlighted there in the lower right-hand corner in 21 those green shaded boxes, those enhancements are 22 necessary to meet the requirements of NUREG 1801, 23 Generic Aging Lessons Learned, going into the period 24 of extended operation, and do not reflect upon the 25 adequacy of the current program. For the --
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43 1 MEMBER SHACK: Why do you feel that you 2 had to -- you seemed to miss the mark. Is the 3 industry guidance, the NRC guidance lacking, or 4 somehow that -- what was the problem?
5 MR. SCHALLER: When we wrote the original 6 application, and I was involved in that from really 7 day one, we allowed ourselves to fall into the trap of 8 describing really how the FatiguePro package worked, 9 instead of --
10 We lost sight of the fact that this is a 11 basis document, to show how we meet current licensing 12 basis, and we had a very technical discussion of 13 basically how FatiguePro worked. We used a lot of the 14 terminology from FatiguePro that really wasn't 15 commonly accepted. Like instead of the cycle 16 counting, we used a thing called "global monitoring."
17 We used a bounding approach.
18 So really when we wrote it, we wrote it 19 around FatiguePro, and that was one of the central 20 comments that we received from the staff, is that show 21 me how you're meeting your current licensing basis, 22 and that was really at the heart of the rewriting of 23 the section that we did this spring.
24 And again, because of that major rewrite, 25 we realized that we impacted the staff and one of the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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44 1 major reasons that we had these 18 RAIs that are not 2 closed yet is because they received that last spring 3 and needed time to look at it.
4 So if, we go back to the table here, the 5 current program is basically a cycle counting program.
6 There's one location, the pressurizer spray nozzle 7 that we perform a usage factor calculation on using 8 cycle-based fatigue. And as you can see there going 9 forward, we will retain all those attributes. We'll 10 continue to have a cycling counting program. We'll 11 continue to monitor that location.
12 But when you go down to the action limits, 13 you start to see the differences between the current 14 program and the enhanced program. In the current 15 program, we have a generic, 90 percent of design 16 cycles is our action limit. We also have, as 17 specified in our UFSAR, a .65 cumulative usage factor 18 limit on our pressurizer spray nozzles. So that's 19 specified right in the FSAR.
20 Going forward, we will have specific 21 limits tailored to the individual transients, rather 22 than a 90 percent across the board as a trigger, and 23 we will have component-specific limits for those 24 components that we monitor by cumulative usage factor.
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45 1 program today, the procedure tells the individual that 2 if you reach the action limit, to initiate a 3 corrective action program document we call PVAR, Palo 4 Verde Action Request. That's the first step in our 5 process.
6 Then that would go to probably one of 7 these gentlemen over here at this table. That's our 8 metal fatigue experts and they would, based on their 9 skill and experience, they would do an evaluation and 10 resolve the issue.
11 Going forward, we'll still use the 12 corrective action program, but we're providing some 13 predetermined guidance of specific things to look at, 14 to help them with that evaluation and give them some 15 more structure.
16 The next attribute is the NUREG 6260 17 locations. That is not a current licensing basis 18 issue, so we don't have any environmentally assisted 19 fatigue monitoring going on right now. Going forward, 20 for our 6260 locations, we will monitor those by a 21 combination of methods. Cycling counting for a very 22 low usage factor location on our reactor vessel, and 23 the rest of them will be monitored with cumulative 24 usage factor calculations, either cycle-based fatigue 25 or stress-based fatigue.
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46 1 And the final attribute is the fatigue 2 monitoring software package, and we will use two 3 fatigue monitoring software packages. The first one 4 we will use will be FatiguePro, and FatiguePro will 5 provide us with three functions. First of all, 6 FatiguePro, because it's tied into the plant computer, 7 will automatically identify transients and count 8 those. Not all of them; they'll still be some manual 9 supplementary actions to be done to cover all the 10 transients.
11 Next, it will provide our cycle based 12 fatigue calculations, and finally it has a projection 13 module in it that will allow us to project ahead and 14 see if we're approaching our action limits.
15 The second software package we'll have is 16 a yet-to-be determined. But it will be a six element 17 stress tensor model that we will apply to our stress-18 based fatigue locations. All of these enhancements, 19 in fact, all of these attributes are covered in 20 Commitment 39 in the LRA.
21 We have three fatigue commitments.
22 Commitment 39, which I basically discussed in the last 23 table there are a result of the attributes of the 24 enhanced program. And then we have Commitment 57 and 25 58. Commitment 57 and 58 resulted from discussions NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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47 1 with the staff, when we had done some screening of 2 locations for environmentally-assisted fatigue.
3 We performed some calculations for both 4 environmental factor and environmentally-assisted 5 fatigue, using some what turned out to be dated 6 methods that had been used in the industry, but had 7 since been superseded by a NUREG that was actually 8 issued for new plant guidance.
9 After discussion with the staff, we agreed 10 that it would be appropriate for us to go back and re-11 perform those calculations prior to the period of 12 extended operation, to confirm the conservatism of 13 the calculation we did or, if necessary, to redo the 14 environmentally-assisted fatigue calculation using 15 that approach.
16 Finally, I'd like to talk about the open 17 item in the SER. The open item is one open item, 18 based on 18 RAIs, and these RAIs are not based on 19 areas that we're necessarily in disagreement with the 20 staff, although they haven't completed their review 21 yet.
22 It's basically the timing, and it goes 23 back to the discussion that I had about our rewriting 24 of Section 4.3 in the spring of this year. The 25 responses to those 18 RAIs have all been submitted, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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48 1 and they were submitted on the dates that you see 2 there, June 29th and August the 12th.
3 For the purpose of discussion today here 4 with the Committee, Palo Verde's group goes into three 5 categories to give you some feel for what was covered 6 in those. The first of those would be items for 7 clarification, and as an example of that, let me guide 8 you to 4.3-10. 4.3-10 was a question received from 9 the staff.
10 When they reviewed our cycle counting, we 11 had very low accumulated cycles for our primary system 12 leak rate test, and they expected to see more, since 13 as you saw, we're in our 16th operating cycle in Unit 14 1 and 2, and they saw low numbers like 5 and 4 and 2 15 for the units.
16 Since the staff quite correctly identified 17 that we do that test after refueling, they wondered 18 why the count was so low. The reason the count is 19 there is because the way we actually perform that test 20 in the plant is we do it in parallel with the normal 21 heat-up and pressurization.
22 So we don't double-count the test. The 23 counts that are in there are from pre-operational 24 days, when we actually heated the plant up to do 25 system leak tests. But once we began operation, it NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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49 1 became part of our normal recovery after a refueling 2 outage. So rather than count, double-count a 3 transient improperly and with more usage than you 4 actually incurred, you count the heat-up and 5 pressurization transient.
6 The second group there is additional 7 technical information. There are really two examples 8 I would give you there: 4.3-3, 4.3-18, and they're 9 related. They both refer to a stress calculation that 10 we performed on a plastic piping.
11 By going an extra 20 years of operation, 12 we increased the number of cycles on sampling system 13 and steam generator downcomer piping, and we had to go 14 back and do some stress range reduction factor 15 calculations to show that we could go the extra 20 16 years.
17 We presented the conclusions of that 18 analysis to the staff, and the staff said to us that's 19 good, but we want to see the actual numbers. So we 20 provided the stress range numbers to the staff, and we 21 also provided some information on equations that we 22 used as far as what part of the code we were using, to 23 go back as a reference.
24 The final grouping would be those that --
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50 1 discussions with the staff. One of those I've already 2 discussed on the previous slide, that's related to 3 Commitment 57 and 58, where we agreed that we would go 4 back and use the methodology in NUREG 6909 for nickel 5 alloy environmental factors and recalculate that.
6 The other one is related to 4.3-13, which 7 is our steam generator tube fatigue calculations. We 8 had initially taken the position that our replacement 9 steam generators have a fatigue calculation where the 10 stress range is less than the endurance limit. So the 11 cumulative usage factor reported in the design report 12 is zero, and we said if it's zero, then it doesn't 13 need to be TLAA.
14 We discussed it with the staff, and we 15 agreed that well, it may be zero but there is analysis 16 there and the guidance says if you have the analysis, 17 then it's a TLAA. So we agreed to change our position 18 on that, make it a TLAA, and then we just positioned 19 it with validation, single i.
20 So in conclusion, I'd like to say that we 21 have provided all the information that's been 22 requested for these 18 items, and the staff has it now 23 for review.
24 CHAIRMAN BONACA: So you have an answer to 25 the question that I had in my mind, which is explain NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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51 1 why the coolant usage factor for the instrument 2 nozzles in Unit 1 and 2, or Unit 1, are five times 3 greater than Unit 2 and Unit 3?
4 MR. SCHALLER: It's basically due to 5 analysis differences, and we brought a gentleman that 6 can address that today, Mr. Brett Lynch.
7 MR. LYNCH: Hi. Brett Lynch, speaking for 8 Palo Verde. The question was what's the difference 9 between the Unit 1 instrument nozzles versus Unit 2 10 and 3. The difference in the modeling was mostly due 11 to how it was dealt with -- excuse me -- how it dealt 12 with vortex shedding.
13 MEMBER ARMIJO: Is that the answer? You 14 know --
15 MR. LYNCH: Excuse me. Would you like me 16 to elaborate?
17 MEMBER ARMIJO: Yes. Why isn't the vortex 18 shedding the same in Units 2 and 3? I mean if it's 19 the same design, there's got to be more to it than 20 that.
21 CHAIRMAN BONACA: Unit 1, five times 22 higher.
23 MR. LYNCH: Well, can you please clarify 24 the question?
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52 1 you. It says explain why the cumulative usage factors 2 for the instrument nozzles of Unit 1 are five times 3 greater than Units 2 and 3.
4 MR. LYNCH: All right. The reason why the 5 Unit 1 was vortex shedding. The engineer decided to 6 analyze each vibration caused by flow as a cycle, 7 which caused a large increase in the number of cycles, 8 which drove the usage factor higher.
9 MEMBER ARMIJO: So why wasn't that 10 applied, that same analysis applied to the other units 11 for consistency? If these are identical units --
12 MEMBER SHACK: At least the two guys talk 13 to each other and figured out which analysis was 14 correct.
15 MEMBER ARMIJO: Well, if they resolved it 16 that way, that's fine. But I'm just trying to find 17 out is this a real difference, or is this among the 18 three plants --
19 MR. SCHALLER: There are no differences as 20 far as material or design between the plants. When we 21 looked at this, and we kind of scratched our heads 22 ourselves when we saw this, both of these are valid 23 ASME Class 1 fatigue analyses. They're differences 24 that were made in the assumptions between analysts.
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53 1 under a quality assurance program.
2 Differences are there. They're just --
3 come down to a difference in analyst assumptions.
4 MEMBER ARMIJO: It can be very satisfying, 5 you know. The materials are the same, the design's 6 the same, the plants have operated pretty much the 7 same, and you have a factor of five difference in the 8 usage factors. Something is wrong. Something has got 9 to be closer to right than --
10 MEMBER SHACK: One is more right than the 11 other.
12 MR. RADSPINNER: Mark Radspinner from 13 System Engineering, Palo Verde. Again, we don't have 14 the luxury of having the two analysts here. But it is 15 clear from that the Unit 1 analysis, the analyst who 16 performed that was, wanted to make sure he had a 17 conservative treatment of vortex shedding and the 18 method that he used to superimpose those mechanical 19 excitations onto the thermal fatigue cycles, he tried 20 to do that in the most conservative manner that he 21 could do that.
22 MEMBER ARMIJO: So with the management of 23 the three units, have you applied the more 24 conservative analysis to all three units?
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54 1 management, again, we managed to the thermal cycles 2 that go into that analysis. We don't attempt to 3 monitor the mechanical excitations of vortex shedding.
4 That aspect is treated in the analyses. We monitor 5 the thermal fatigue cycles that go into those 6 analysis.
7 MEMBER SHACK: Yes, but if the usage is 8 real, which one is the controlling one?
9 MR. RADSPINNER: And it's less than 1.0, 10 and would -- and as long as we stay below the design 11 values that go into those reports, we would continue 12 to be less than or equal to the calculated 13 projections.
14 MEMBER ARMIJO: I guess what I'm trying to 15 get to is let's say you're getting to an action limit 16 in Unit 1, because the CUF is five times greater than 17 the other units. Would that -- wouldn't you say "Well 18 boy, I must have -- to be conservative, I'll assume 19 that Units 2 and 3 are the same and I apply the same 20 action" --
21 (Simultaneous discussion.)
22 MEMBER ARMIJO: That's your --
23 MR. RADSPINNER: Yes, I understand your 24 question would be if we reach an action limit, how 25 would we treat the differences between the two NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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55 1 analyses of record. Yes, and at that point, we would 2 have to reconcile the differences, and we would most 3 likely go back to Combustion Engineering or 4 Westinghouse and get an analysis that would still be 5 bounding and conservative, and still be able to 6 demonstrate that we're below the 1.0 cumulative usage 7 factor.
8 We would have to do that the first time we 9 reaction an action limit that influences that 10 particular analysis of record.
11 MEMBER SHACK: Yes, but I heard you say 12 that you were counting only thermal cycles, not usage 13 factor for this particular nozzle. Did I understand 14 that correctly?
15 MR. RADSPINNER: Yes, that's correct, and 16 --
17 MEMBER SHACK: So that would mean that you 18 sort of ignore this factor of five difference, since 19 they're not due to thermal cycles?
20 MR. RADSPINNER: Well no. I guess I would 21 convey it, and I appreciate the question. But the 22 analysis of record basically sets aside the fatigue 23 effects for the vortex shedding, and then the various 24 thermal cycles that go into it, the design cycles 25 divided by the allowable cycles, each one of those NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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56 1 make up the rest of the fatigue usage.
2 And so the mechanical excitation is 3 allocated. We would, as soon as we reach an action 4 limit for any single transient that feeds into that 5 cumulative usage factor, we would then be in a 6 reconciliation mode on how are we going to make sure, 7 and of course, that action limit would be most 8 applicable to Unit 1, because that's the analysis that 9 is the most conservative.
10 We would then have to demonstrate that 11 with this action limit, let's just say it's heat up 12 and cool downs that we reach the action limit on, we 13 would then have to project forward and reconcile how 14 is the analysis of record going to be demonstrated to 15 still stay below 1.0?
16 MEMBER ARMIJO: I guess I'm going to have 17 the same series of questions for the staff when they 18 come up, to see if they can explain why all three 19 units don't have the same -- if you assume the designs 20 are the same, materials are the same, environment's 21 the same. It's kind of strange.
22 (Off mic comments.)
23 MEMBER STETKAR: We're doing okay for 24 time.
25 CHAIRMAN BONACA: That's right.
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57 1 MEMBER STETKAR: And since you bought up 2 cycle count, I like counting things. As I went 3 through your table of -- it's Table 4.3-3 of transient 4 cycles, I understand that you've reconstituted that, 5 the information prior to 1996. A couple of things.
6 Except, I guess, before or for six types 7 of transients, that you still use the original 25 8 percent of design numbers, and I know the staff had a 9 question about which particular six. I could guess 10 which six, but that's really not my question.
11 The question was actual operating 12 experience for the units. A couple of transients that 13 I've kind of stumbled over was, one of them is Item 14 No. 31 in the table. It's arbitrary load rejection 15 from 100 percent to 15 percent power shows Unit 3 has 16 had 14 of those events.
17 That's a pretty substantial load 18 rejection, compared to six for Unit 1 and seven for 19 Unit 2. What's going on with Unit 3? How come you've 20 had more than, twice as many load rejections on Unit 21 3? You're just unlucky?
22 MR. RADSPINNER: No. I think in some 23 respects, that there is a tendency to conservatively 24 account whenever we -- because our design has a 25 reactor power cutback and a driven runback feature NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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58 1 that a lot of plants don't have, and so --
2 MEMBER STETKAR: Can you accept 100 3 percent load reject?
4 MR. RADSPINNER: Yes.
5 MEMBER STETKAR: Okay. That explains 6 another question that I had, because you had zero 7 events.
8 MR. RADSPINNER: And then, and also in 9 Unit 3, in some of our earlier start-up days, we did 10 have a series of --
11 MEMBER STETKAR: Okay. So there really 12 was -- okay. The one that was a much larger 13 difference, I have no idea. Sam, you'll have to tell 14 me, because I don't understand materials. Item No.
15 37, charging cycles during an extended loss of letdown 16 lists 64 events for Unit 1, one event for Unit 2 and 17 two events for Unit 3. That's a really big 18 difference.
19 MR. RADSPINNER: Yes.
20 MEMBER STETKAR: Now I know in early 21 years, people didn't control their charge in the let 22 down systems, you know, as well as they do now, but 23 the age of the three units really isn't substantially 24 different. So why, why 60 times as many events?
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59 1 in Unit 1, we had an extended loss of let down 2 duration, where we had a petite failure of a pipe 3 support that impacted the integrity of the let down 4 line. So it was taken out of service for a 5 substantial amount of time, and during that time, the 6 charging pump had to cycle on and off to make --
7 MEMBER STETKAR: Okay. So that's 8 essentially the result of a single operational event?
9 MR. RADSPINNER: Yes. Okay.
10 MR. HESSER: Mr. Stetkar, Mr. Doug Coxon 11 from our Operations Group would like to provide some 12 clarity, I believe.
13 MR. COXON: Yes sir. Doug Coxon, Palo 14 Verde Operations. Yes sir, we did have an issue in 15 Unit 1 that resulted in an extended loss or let down, 16 and that route, by our procedures and processes, we're 17 allowed to basically whatever result cycling, charging 18 off and on for periods of time.
19 MEMBER STETKAR: Yes, yeah, yeah. Okay.
20 That explains -- that certainly explains that 21 difference. Thank you.
22 CHAIRMAN BONACA: I have a couple of 23 questions on your problems, and I think since you're 24 closing, your presentation is nearing close, I would 25 like to ask now. The first one is on structural NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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60 1 monitoring problem. There is a discussion in this 2 inspection report regarding the monitoring that you 3 have done.
4 Essentially the requirement seems to be 5 that internal containment and external surfaces should 6 be inspected once every five years, and internal 7 surfaces should be inspected every ten years. But 8 really what was done was that you inspected only part 9 of the internal after ten years, and then another part 10 of Unit 2 after ten years.
11 Then in 30 years, you haven't got a full 12 plant inspected. You provide an explanation for that.
13 But then the text is moot regarding the five year 14 inspection to the internals, your containment, okay, 15 which has never happened.
16 Could you explain to me what you're going 17 to do about this? I mean what's the frequency, what 18 plant is going to be done and how would you justify 19 considering the three units identical to one, and 20 inspecting just part of each one of them? I'm trying 21 to understand the logic.
22 MS. KRAINIK: Let me start with it. This 23 came up during, this is part of our current design 24 basis, and we originally had, as you described, a 25 provision by which we would look at a representative NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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61 1 unit every ten years.
2 CHAIRMAN BONACA: Yes.
3 MS. KRAINIK: As a result of the 4 inspection, the regional inspection, we did get 5 feedback on that, had a good discussion with them, 6 talked about where the rest of the industry was as 7 well.
8 So we have made a commitment to change the 9 way that we do our structures monitoring program, so 10 that between now and when we started our period of 11 extended operation, we will complete two full 12 inspections of the full scope of the structures 13 monitoring program for each unit.
14 CHAIRMAN BONACA: Fifteen years is a long 15 time, and the time we're talking about here is ten 16 years in inspections. So I would like to know how 17 soon you think you're going to inspect this plant in 18 the near future?
19 MS. KRAINIK: Let me ask Ken Schrecker to 20 give you that. He is the program owner for the 21 structures monitoring program, and we've had some very 22 good discussions about scheduling.
23 CHAIRMAN BONACA: I would like to know 24 about the five-year inspection, because that's moot in 25 the inspection report, and there is almost an NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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62 1 expectation that you would provide the information, 2 but it hasn't been provided to us.
3 MS. KRAINIK: Okay.
4 MR. SCHRECKER: Okay. Ken Schrecker, 5 Palo Verde, System Engineering. I think I understand 6 the question to be to talk about the periodicity of 7 our structural monitoring program for the current 8 licensing period?
9 CHAIRMAN BONACA: Yes. What I'm trying to 10 understand is, you know, you recognize that they 11 should have done more than what you have done, and 12 you're doing it. The question is what you're doing 13 and by when will it be done. Then considering that 14 this instrument is issued, it attaches on the 15 commitments in the current period of operation.
16 MR. SCHRECKER: Okay. What we're doing 17 is by 2015, we're going to complete the first pass-18 through, the inspection of all Palo Verde structures 19 that are included in the monitoring program for all 20 three units.
21 CHAIRMAN BONACA: Okay.
22 MR. SCHRECKER: And then between 2015 and 23 2025, the period of extended operation, we'll do 24 another complete inspection of the entire plant.
25 CHAIRMAN BONACA: Okay. What about the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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63 1 five-year inspection of the internal containment?
2 MR. SCHRECKER: Are you referring to the 3 containment liner?
4 CHAIRMAN BONACA: Yes.
5 MR. SCHRECKER: Inspection program?
6 CHAIRMAN BONACA: Well, I'm referring to 7 the inspection report of, I think that's what is 8 meant, in fact, the internal surface of the 9 containment.
10 MR. SCHRECKER: We will be -- we will be 11 looking at -- the structural monitoring program looks 12 at all the internal structures, separate from the IWE 13 program for the liner. We will again finish all that 14 by -- actually, I can say that the internal structures 15 of all three units' containments have already been 16 looked at, as part of the monitoring program.
17 But we will be looking at it again, 18 between now and 2015, and then --
19 CHAIRMAN BONACA: In five years or ten 20 years?
21 MR. SCHRECKER: We are going to be 22 inspecting structures on a ten year periodicity in the 23 current license.
24 CHAIRMAN BONACA: Because I mean what is 25 confusing is that, you know, we have a special report.
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64 1 It raises an issue and says if they do this, it's 2 okay. Well, that's why I'm asking if you are going to 3 do that, in determining on my own whether or not 4 that's okay, and you know, they refer specifically to 5 the five-year inspection for internal containment.
6 But you're not talking about that. You're 7 talking about a ten-year inspection.
8 MR. SCHRECKER: Yes. We're talking about 9 a ten-year inspection between now and the period of 10 extended operation, and once we get to the period of 11 extended operation, we are going to a five-year 12 period, five-year periodicity for primary containment, 13 all the exterior of our safety-related structures, as 14 well as our essential spray pumps.
15 CHAIRMAN BONACA: So they're going to do 16 that?
17 MR. SCHRECKER: Yes.
18 CHAIRMAN BONACA: Okay, thank you. All 19 right. The other question I had was regarding the 20 inaccessible cables. In the inspection report, again 21 it points out that you've had watering manholes that 22 you have checked, and that you have started a program 23 now to monitor, and to -- although you have no 24 failures yet. You never had a failure of tables.
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65 1 going to have an inspection every ten years, and then 2 that was not sufficient. So therefore you agreed to 3 do it every two years. But the question I have is if 4 you find water in the manhole, okay, why would you 5 consider two years acceptable for the next time you 6 look at it?
7 MS. KRAINIK: Let me go ahead and ask Mark 8 Hypse, who is the Aging Management Program owner for 9 the inaccessible cables program, and answer your 10 question sir.
11 CHAIRMAN BONACA: Okay.
12 MR. HYPSE: My name is Mark Hypse, Palo 13 Verde Electrical Engineering. I understand the 14 question to be what do we do when we find water --
15 MR. HESSER: Mark, Mark. Would you turn 16 the microphone down so they can hear you please?
17 Thank you.
18 MR. HYPSE: Oh. Mark Hypse, Palo Verde 19 Electrical Engineering. I understand the question is 20 what do we do when we find water in manholes and the 21 cables submerged?
22 CHAIRMAN BONACA: Yes.
23 MR. HYPSE: Okay. We do a few things. We 24 issue a condition report, and Engineering -- well 25 first of all, let me say the water's pumped out of the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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66 1 manholes, okay. We issue a condition report.
2 Engineering goes out and does an inspection of the 3 cables and the manholes.
4 We also have a PM program that has two 5 components to it. The first component is a periodic 6 inspection, which inspects the manholes on a six-month 7 and a two-year frequency. We also have an element of 8 the manhole inspections that's event-based. We 9 essentially inspect all the manholes when it rains .3 10 inches in a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> period.
11 So when we find water in a manhole where 12 it's submerged the cables, we will move that manhole 13 to a more frequent inspection, to ensure that the 14 water doesn't accumulate -- the water doesn't 15 accumulate in the manhole and does not submerge the 16 cable.
17 MEMBER ARMIJO: Okay. What's the source 18 of the water in your manholes for most of these 19 events? Is it rainwater?
20 MR. HYPSE: I believe it to be rain. You 21 go in and inspect the manholes, we see water stains, 22 water stains on the rings of the manholes coming from 23 the lids.
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67 1 there's any tritium or radionuclides of interest in 2 it?
3 MR. HYPSE: I'd like to turn that over to 4 Tom.
5 MEMBER STETKAR: Mark, before you sit 6 down, let me ask you. Are you currently performing 7 this PM program with the kind of graded inspections?
8 MR. HYPSE: Yes, it is in place working 9 right now.
10 MEMBER STETKAR: Okay, thanks.
11 MR. GRAY: Okay. Tom Gray, Palo Verde 12 Radiation Protection, and I understand your question 13 was do we analyze for tritium --
14 MEMBER RYAN: Or other radionuclides.
15 MR. GRAY: Yes. If it is in the 16 radiological controlled area yard, then the protocol 17 is for the sample to be delivered to radiation 18 protection so we can analyze it for tritium.
19 MEMBER ARMIJO: And what are the results?
20 It's a range or are they positive or all negative?
21 MR. GRAY: I do not have that information 22 currently.
23 MEMBER RYAN: Okay. Does anybody know 24 what the ranges are?
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68 1 knowledge?
2 MR. HYPSE: I didn't hear the question.
3 CHAIRMAN BONACA: Tritium.
4 MEMBER ARMIJO: What I asked.
5 MR. HYPSE: No, I do not know of any 6 results of any tritium in that water.
7 CHAIRMAN BONACA: You spoke to the 8 interval as one every two years and one six months?
9 MR. HYPSE: Yes.
10 CHAIRMAN BONACA: Would you tell me the 11 difference between the two, what triggers one or the 12 other?
13 MR. HYPSE: Yes. Engineering keeps a 14 database of inspections of manholes, and we look at 15 the history of water intrusion into those manholes.
16 Based on that history, we put it into the frequency of 17 inspections. So the water, so the manholes that have 18 been the most vulnerable to water are the most 19 frequent, inspection frequency.
20 The six month frequency of inspection 21 actually has all the manholes that are in the, what we 22 call the "rain PM." That's the PM that inspects when 23 it rains. That's to ensure that those manholes are 24 always inspected, because Palo Verde being in the 25 desert, we have long periods of time when there's no NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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69 1 rain. So we'll inspect it at the six month frequency.
2 The two year inspection frequency are manholes that 3 have been dry.
4 CHAIRMAN BONACA: Okay.
5 MR. HYPSE: That's not explained, I'm 6 sorry.
7 MEMBER RYAN: And I guess, is that 8 difference based on topography or have you tried to 9 sort out why some are wet at the six month interval 10 and others are right on the two year interval and the 11 rainfall is pretty much the same on all of them at the 12 same time, I guess?
13 MR. HYPSE: It does have to do with 14 topography.
15 MEMBER RYAN: Yes.
16 MR. HYPSE: You know, I've gone out there 17 when it rains, and tried to, you know, catch them when 18 water's flowing, and last year we found a manhole 19 where essentially when it rained there was a stream 20 above it, and we corrected that, and that's part of 21 our work is looking at all these manholes and trying 22 to find where the source of the water is.
23 CHAIRMAN BONACA: Is this program what you 24 had regionally or something you had have modified now 25 because of the preparation for license renewal?
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70 1 MR. HYPSE: Could you repeat the question?
2 CHAIRMAN BONACA: Yes. I'm saying is this 3 the program that you used to have before license 4 renewal, or is it the program that you have because of 5 license renewal?
6 MR. HYPSE: We had it before license 7 renewal. It's been enhanced over the years, but we 8 had it before license renewal.
9 CHAIRMAN BONACA: Yes. There's no 10 description in your Appendix B of the details. That's 11 why we end up with the observation of the inspection 12 and we have to rely on those observations to deliver 13 our conclusions. But I appreciate your presentation.
14 Thank you.
15 MEMBER RYAN: Just one follow-up question.
16 You mentioned radiological areas weren't really 17 focused. Have you done any work at all looking for 18 environmental radioactivity or tritium or do you have 19 any more that are outside of the radiological areas 20 that are on your property?
21 MR. GRAY: Again, Tom Gray, Palo Verde 22 Radiation Protection. The question is have you done 23 any more looking for radioactivity in water on site at 24 Palo Verde, and the answer to that question is yes, we 25 have done quite a bit of work at Palo Verde.
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71 1 As we pointed out earlier, we are a zero 2 liquid release facility, and so we release tritium 3 through the airborne pathway, and we do that by 4 operating the boric acid concentrator in the release 5 mode and we release that as a vapor.
6 That prevents or represents a couple of 7 challenges, and that is that you don't release during 8 periods of rain, and we know by our operating 9 experience, we learned that to not operate the VAC and 10 release during a period of rain to prevent washout 11 from occurring.
12 In addition, you can have reentrainment of 13 tritium in other systems as well, and a good example 14 is in our circulating water system and our cooling 15 towers, we can have some reentrainment of tritium.
16 The NRC staff has acknowledged that in 17 Regulatory Issues Summary 2008-03 for the return reuse 18 of radioactive effluents, that it is okay to have that 19 radioactivity in those systems, as long as they meet 20 certain concentrations and you don't have to consider 21 that as a new release pathway.
22 MEMBER RYAN: Okay, and you had -- I'm 23 going to guess you had pretty good experience meeting 24 those requirements, as specified by the NRC?
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72 1 some reentrainment in some of the systems for more 2 airborne releases, yes.
3 MEMBER RYAN: Okay, okay.
4 MR. GRAY: We have also had other 5 instances. In February of 2006, we discovered some 6 tritium in some subsurface area of the plant, 7 specifically Unit 3 and Unit 2. It was in a 8 relatively shallow area, less than 15 feet in depth, 9 confined to a shallow basin area around hard packing 10 piping.
11 In this case, it was around the spray pond 12 pipes. We pressure-tested piping systems in that 13 area, identified no active leaks in that area, and the 14 water was estimated to be somewhere between 800 and 15 1,000 gallons, a relatively small amount confined to a 16 shallow basin area.
17 So that cause was attributed to past 18 practice of operating the VAC and releasing during 19 periods of rain. As I said, we do not do that 20 anymore.
21 MEMBER RYAN: Okay.
22 MR. GRAY: Also, we had some condensation 23 leakage from the ventilation system under the wall, 24 and we've made improvements there as well. We have 25 installed a drainage system for the ventilation NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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73 1 system, and also humidity monitoring, so we don't 2 release when it's greater than 80 percent humidity.
3 MEMBER RYAN: Have you seen the 4 environmental levels go down because of the 5 improvements you have made --?
6 MR. GRAY: We've established welds in all 7 three yards, in Units 3, 2 and 1, and we have seen the 8 levels of radioactivity change. We also did some 9 improvements. We re-asphalted and sealed the area 10 behind the water intrusion, and that kind of changed 11 the dynamics.
12 MEMBER RYAN: Yes.
13 MR. GRAY: So we did have some changes in 14 the levels of --
15 MEMBER RYAN: For 2008 and 2009, that's a 16 fairly recent change, so you'll need to see how that 17 behaves over time, I guess.
18 MR. GRAY: That is correct. We are 19 continuing to monitor that as time goes by, yes.
20 MEMBER RYAN: Okay, great. Thanks a lot.
21 MR. GRAY: You're welcome.
22 MR. BARTON: Can I piggyback about the 23 electrical question that Mario raised? You found in 24 your medium voltage cables some low negative readings, 25 where you had water in your splices. Now what was the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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74 1 root cause of that, leaving water in the manhole? I 2 mean what was the root cause of those low negative 3 readings, the water in the splices?
4 MR. HYPSE: Mark Hypse, Palo Verde 5 Electrical Engineering. The root cause, the formal 6 root causes were not done on those splices. However, 7 the field engineering reported back that they felt 8 that these were heat-shrinkable tubing type splice, 9 that it was not sealed completely.
10 MR. BARTON: Any recent occurrences of 11 that?
12 MR. HYPSE: No.
13 MR. BARTON: Okay. Have you had any 14 failed medium voltage cables?
15 MR. HYPSE: We have not had any failed 16 medium voltage cables underground at Palo Verde.
17 MR. BARTON: Thank you.
18 MEMBER STETKAR: It was reported generic 19 letter 2007-1 that you have two failed 480 volt cables 20 though?
21 MR. HYPSE: And just to clarify on that, 22 those were mega-installation resistance --
23 MEMBER STETKAR: Yes. They were not --
24 they were testing failure?
25 MR. HYPSE: That's correct.
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75 1 MEMBER STETKAR: Were those the same ones 2 for the splices, or were those different?
3 MR. HYPSE: Different cables.
4 MEMBER STETKAR: Different cables 5 MR. HYPSE: Yes.
6 CHAIRMAN BONACA: Okay. Let's proceed.
7 MS. KRAINIK: Very good. I would like to 8 discuss briefly two of the five confirmatory items 9 that we have in the SER with open items. In 10 particular, the first one on the list having to do 11 with the application of the scoping criteria for the 12 spray chemical addition tanks.
13 We had scoped the spray chemical addition 14 tanks. It's a subsystem within our containment spray 15 system. We had originally scoped it into the scope of 16 license renewal and removed it as we had, it was an 17 abandoned system. It's a system that had been cut and 18 capped. So as we did our review, we had assumed that 19 We recently became aware that there was a 20 small amount of liquid that still remained in those 21 subsystems. So we made a commitment, as a result of 22 our license renewal application, to have that 23 completed, and we are on track to having that 24 completed now by November 30th of this year.
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76 1 to August to do that.
2 MS. KRAINIK: We're going there. But yes, 3 we did.
4 MR. BARTON: All right. I beat you to the 5 punch.
6 (Laughter.)
7 MS. KRAINIK: We did. But we did --
8 you're correct, and I was going to explain that we 9 originally had made a commitment to have it completed 10 by August 30th, and we've continued to do our review 11 of the work to do it.
12 The actual fluid, it's a relatively small 13 amount of fluid that's in the system, is a dilute 14 hydrazine. So in doing our planning and review, we 15 identified that we needed some additional time to 16 complete the review. Again, to complete the review 17 and the planning for the activity.
18 So we, as I've mentioned, we now have a 19 commitment for the end of November, and we will -- we 20 are going to start completing the work this month and 21 plan to have it completed prior to that, which is 22 prior to the final issuance of the SER, which is 23 currently scheduled for mid-December.
24 MEMBER STETKAR: This was originally 25 identified in October of 2009? It was.
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77 1 MS. KRAINIK: Yes, I think so. I was 2 thinking --
3 MEMBER STETKAR: I'm just curious why it 4 takes more than a year to figure out how to drain the 5 tank?
6 MS. KRAINIK: Well, we're doing the 7 scoping of the work, and as I mentioned --
8 MEMBER STETKAR: I understand, I 9 understand. Just move on.
10 MS. KRAINIK: Okay. The other items, as 11 well as this one that we have provided all the 12 information that the staff requested on the docket for 13 these additional confirmatory items.
14 MEMBER STETKAR: Okay. Flow-accelerated 15 conversion program. You've removed from scope the 16 high pressure safety injection system piping for all 17 three units, where you've had flow-accelerated 18 corrosion through all leaks, because now you're going 19 to -- now you said you're going to replace that piping 20 every seven and a half years. So it's a replaceable 21 item.
22 That's a strange way to kind of get around 23 solving the problem, isn't it?
24 MS. KRAINIK: Let me first start with it 25 is within the scope of license renewal certainly. But NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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78 1 you're right, in that the fact that we are doing 2 routine replacements of it, you don't have the aging 3 effects of it because we're evaluating the cavitation 4 itself, and resolving it --
5 MEMBER STETKAR: What analyses have you 6 done to show that those are the only sections of pipe 7 that are susceptible to this type of flow-accelerated 8 corrosion or erosion, whatever you want to call it?
9 MS. KRAINIK: We'll go ahead and ask Mark 10 Radspinner to address that please.
11 MR. RADSPINNER: Yes. Mark Radspinner, 12 Palo Verde System Engineering. I understand that the 13 question is what extent of condition evaluations have 14 we done with respect to the --
15 MEMBER STETKAR: Other systems.
16 MR. RADSPINNER: Other systems, yes.
17 MEMBER STETKAR: Because it's unusual to 18 have that extent of --
19 MR. RADSPINNER: Okay. Initially, when 20 this occurred in our Unit 1, we did an immediate 21 transportability extended condition to the other 22 units, and then we extended that evaluation using 23 EPRI methodology for anticipating, damaging or 24 incipient cavitation, and we extended that to the 25 primary side safety-related systems.
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79 1 That evaluation did not identify any other 2 locations that were particularly susceptible to 3 cavitation damage of that nature. As a result of this 4 exercise, the license renewal, the question was asked 5 well, what about in scope systems on the secondary 6 side?
7 So we have done an initial evaluation of 8 the condensate storage tank transfer system, the 9 auxiliary free water system and the main steam system, 10 and that evaluation, as indicated, that there are 11 often no areas that would be susceptible to that, and 12 we expect to document all that in an engineering 13 evaluation.
14 MEMBER STETKAR: Okay.
15 MEMBER ARMIJO: On that subject, I'm a 16 little confused. In the SER, there is a discussion of 17 a through-wall leak in a stainless steel high pressure 18 safety injection system. But you're talking here 19 about cavitation in carbon steel piping. Are these 20 two different incidents, or is it -- or is one 21 incorrect and one's correct?
22 MR. RADSPINNER: That's no. I just, I 23 threw in a curve ball. I brought in the stainless 24 steel.
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80 1 about two different things here?
2 MEMBER SHACK: There's a disagreement 3 between the slide and what the SER is saying.
4 (Simultaneous discussion.)
5 MEMBER ARMIJO: The actual confirmatory 6 item is indeed on the stainless steel.
7 MS. KRAINIK: It is an extended -- they 8 are connected. It is, as described earlier, the 9 original cavitation was in our operating experience.
10 As we did our review for the aging management program, 11 got captured in from the stainless steel.
12 So the question here with regard to 13 cavitation in stainless steel, as Mark described, was 14 the addition extension oft he evaluation that we did 15 from -- into the stainless steel or carbon steel 16 systems within the scope of license renewal. So this 17 confirmatory item here had to do with the evaluation 18 of the carbon steel systems within the scope of 19 license renewal.
20 MEMBER ARMIJO: Okay, and the stainless 21 steel systems that have suffered cavitation, erosion 22 or whatever, those are just dealt with by replacement, 23 period replacement?
24 MR. RADSPINNER: Yes.
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81 1 solution than that?
2 MR. RADSPINNER: Yes. Our evaluation, it 3 is very localized, immediately downstream of a heavily 4 throttled valve on our pump recirculation line. The 5 alternate fix would have been --
6 MEMBER ARMIJO: Some sort of design 7 change?
8 MR. RADSPINNER: Yes. A drag valve that's 9 particularly, specifically designed for, to prevent 10 that cavitation. Our evaluation concluded that it was 11 an appropriate response to simply cut it out and 12 replace it. You know, it was done very quickly. It's 13 not a difficult job. We feel we can establish a very 14 conservative frequency, and our evaluation was that 15 that was an appropriate way to deal with that.
16 MEMBER ARMIJO: So how conservative do you 17 think your frequency is between having a structural 18 problem?
19 MR. RADSPINNER: Yes. We attempted to 20 develop a wall loss rate, based on the operating 21 experience, and we applied a conservative factor. I 22 believe it was a factor of two on top of that and then 23 rounded it down to the next operating cycle.
24 Then in this first interval, we also took 25 half of that and inserted an inspection interval. So NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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82 1 we'll be doing volumetric inspection one-half of the 2 time by which we expect to do the replacement.
3 MEMBER ARMIJO: Okay, thank you.
4 MR. RADSPINNER: Okay.
5 CHAIRMAN BONACA: A question on the small 6 bore piping. If you can go to the previous -- this 7 was supposed to be a one-time inspection, because you 8 did not expect to have problems. But you found two 9 welds which have failed, and now you have an 10 inspection of ten percent of those welds which are 11 committed to.
12 Is it going to be a one-time inspection of 13 the ten welds, or is it going to be a periodic 14 inspection?
15 MS. KRAINIK: At this time, the plan is to 16 do the inspection during, as a one-time inspection.
17 CHAIRMAN BONACA: Just one.
18 MS. KRAINIK: And depending on the results 19 of that, then as a result of that and we identify 20 aging management, then we make the evaluation and 21 determine whether you need to include it in the period 22 of extended operation.
23 CHAIRMAN BONACA: Would you give me a 24 feeling for what is the number of ten percent of the 25 socket welds?
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83 1 MS. KRAINIK: The socket welds that we 2 have per unit that fit within this category, in the 3 neighborhood of about 320 per unit. So the ten 4 percent would be about -- would be 32 welds?
5 CHAIRMAN BONACA: So it's a sizeable 6 sample. Thank you.
7 MS. KRAINIK: Moving onto a discussion of 8 our, of the regional inspection. During the regional 9 inspection conducted in February, the inspection team 10 identified two items for additional review, classified 11 as unresolved items. Both of these items have been 12 closed by the region in August.
13 The first item had to do with the staff 14 review of the operating experience for a -- review our 15 investigation for Palo Verde Unit 1. We had a unit 16 trip following a water intrusion and subsequent 17 flashover in a metal-enclosed bus during a severe 18 storm in March. The staff performed their review and 19 concluded that there were no additional aging effects 20 identified as a result of the event.
21 The second item we talked about just 22 briefly with regard to the structures monitoring 23 system program, pardon me, and we addressed both 24 aspects of it that we've talked about previously, one 25 of which being the fact that we are going to conduct NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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84 1 two complete inspections prior to the period of 2 extended operation.
3 The second one had to with the frequency 4 of the inspections themselves during the period of 5 extended operation and our ACI-349.
6 MEMBER STETKAR: Your metal-included 7 buses. I've read a couple of things about that.
8 Number one, during the walk-down, the staff apparently 9 saw a crack in one of the bellows connections. You 10 did have the unit crypt, and apparently you were 11 already doing augmented inspections of the buses due 12 to a previously-identified insulation problem.
13 Yet in your license renewal program, 14 you're just committing to one inspection every ten 15 years. Could you briefly explain to me why the plant-16 specific operating experience doesn't justify a more 17 frequent inspection interval than once a year, every 18 ten years, given the fact that you know you have 19 problems?
20 MS. KRAINIK: Let me start it a little bit 21 and then go to Mark. We'll go back to the event 22 itself. We did --
23 MEMBER STETKAR: Well, this is kind of the 24 -- I'm looking at the cumulative evidence of operating 25 experience. You have apparently some problem with a NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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85 1 particular type of insulation, that has prompted, I 2 guess, an increased -- I don't know whether it's a 3 preventive maintenance or some sort of inspection 4 program. Mark can probably elaborate on that, and you 5 did have a flashover event.
6 MS. KRAINIK: Uh-huh.
7 MEMBER STETKAR: Which is relatively 8 unusual. There aren't too many plants that have 9 flashovers in their bus ducts. So I'm curious why 10 looking at the operating experience, you still take 11 sort of the generic approach in saying well, we're 12 just the same as everybody else, and we can inspect 13 our bus ducts once every ten years, which is pretty 14 much what everybody else does who hasn't any problems 15 with their bus ducts.
16 MS. KRAINIK: Mark.
17 MR. HYPSE: Mark Hypse, Palo Verde 18 Electrical Engineering. I guess to answer your 19 question, I need to elaborate a little bit on the 20 fault itself. I think that would help.
21 MEMBER STETKAR: Well, the fault, but also 22 what was -- apparently, maybe I've misread the 23 history, but were you doing -- I read something here 24 that says you were doing thermography already on 25 portions of the bus ducts and transformer connections NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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86 1 every six months, because of previously-identified 2 problems and ground faults that had occurred.
3 Maybe not necessarily on every specific 4 section of bus duct that you've identified as in 5 scope, but bus ducts.
6 MR. HYPSE: In those thermography 7 inspections, we were looking at overheated 8 connections. Really, that was the primary purpose of 9 that. At this point Glenn, I'd like to pull up Slide 10 No. 80, and maybe if I go through this real briefly 11 and tie this into our inspection program, it will come 12 together what we're doing.
13 When the root cause team took a look at --
14 well, this is a graphical depiction of the Calvert bus 15 section that had the fault in it, and when the root 16 cause team looked at this Calvert bus, they found open 17 bolt holes; they found a gasket, like a seal that was 18 missing, and they found an indication of water inside 19 the Calvert bus, corrosion that had occurred, and they 20 could track -- by following the corrosion, they could 21 track the water through the bus.
22 Up at the top of the bus on the horizontal 23 section there, there's the first arrow shows the 24 pooling, where they found pooling of water. Then the 25 black arrows are is how the water flowed down to each NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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87 1 one of the bus supports.
2 At the bottom bus support is where the 3 failure occurred, between the Alpha bus section and 4 the enclosure. What the root cause team found was the 5 inspections that we're doing, that you're referring to 6 were pretty much focusing on the Noryl, cracks in the 7 Noryl, the industry experience with Noryl. There 8 wasn't a lot of focus in maintaining the weather-tight 9 design of the metal-enclosed bus.
10 What they also found was they saw on that 11 support a bus where the failure occurred. They saw 12 some minor indications of cracking up there, and they 13 found that really to have this fault, you needed both 14 the water and the cracking of the Noryl. So even 15 though the lower support there was damaged so 16 significantly, they didn't have any evidence the Noryl 17 left.
18 It was pretty clear that there had to have 19 been some minor cracking there. As I spoke before, 20 the root cause was that the -- those inspections that 21 we were doing were not focusing on -- were only 22 focusing primarily on the NOryl, not on maintaining 23 that weather-tight design.
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88 1 and they close it back up, it's back to design 2 configuration and it's weather-tight. The other thing 3 --
4 MEMBER STETKAR: How frequently are you 5 doing those inspections now, with the enhancements?
6 MR. HYPSE: Right now it -- this 7 particular bus is a 13.8 bus. That's being inspected 8 at a 2C inspection frequency. The 4 kV buses are 9 being inspected as a 6C, I mean six cycle inspection 10 frequency.
11 But the other part of the -- one of the 12 corrective actions out of this was to get all the 13 Noryl replaced, and we've written CMs to do that.
14 Those are being planned and outages accordingly.
15 MR. HESSER: CMs are corrective 16 maintenance work orders, just for people to know.
17 MEMBER STETKAR: Thanks. It also helps 18 the transcript.
19 MR. BARTON: Is this the March 7th Unit 1 20 trip that --
21 MR. HYPSE: Yes, it is.
22 MR. HESSER: Yes.
23 MR. BARTON: The NRC's inspection report 24 wrote that up as a loose cover or missing gasket or 25 something like that. My question is who, when you do NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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89 1 this inspection, who's doing it, plant people or 2 switchyard people?
3 MR. HYPSE: The plant people are doing it, 4 our electrical maintenance team.
5 MR. BARTON: Electric maintenance people 6 are doing it?
7 MR. HYPSE: Yes.
8 MR. BARTON: Good.
9 MR. HYPSE: These buses are not in the 10 switchyard.
11 MR. BARTON: Okay. So this is a work 12 control issue within the Maintenance Department?
13 MR. HYPSE: It's a maintenance issue.
14 MEMBER STETKAR: Thanks.
15 MS. KRAINIK: I'd like to turn it over to 16 John Hesser for some concluding remarks.
17 MR. HESSER: So this right here just 18 depicts the current license end of period for Palo 19 Verde, to give you a reference of 2025, 26 and 27 for 20 Unit 1, 2 and 3 respectively. If granted license 21 renewal, there would be the period of extended 22 operation to 2045, 46, 47.
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90 1 application, have the opportunity to answer your 2 questions. And again, I'd like to recognize, as there 3 has been, the hard work and rigorous review of the NRC 4 staff.
5 We believe being a learning organization 6 is important. Palo Verde has come a long way to where 7 we are today from where we've been in the last few 8 years. We are committed to the long term safe 9 operation of Palo Verde, and with that, I'll turn it 10 back to you, Mr. Chairman, in case you have any other 11 questions you'd like to ask us that we didn't get a 12 chance to cover.
13 CHAIRMAN BONACA: Any questions?
14 MR. BARTON: Yes, I've got one. During 15 the NRC, one of the NRC inspection programs, it was 16 during their audit program, they found condition 17 report requests on a leakage in the spent fuel pool 18 water, through these TellTale drain valves being 19 closed and backed up, and you had water leaking, I 20 think, through the concrete.
21 MR. HESSER: Yes. Actually --
22 MR. BARTON: The question I have is we 23 inspected the concrete and said there's no damage.
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91 1 for, I think, a couple of years these TellTale valves 2 were closed or something? How long?
3 MS. KRAINIK: Five months.
4 MR. BARTON: How much?
5 MS. KRAINIK: Five months, sir.
6 MR. BARTON: Okay. Well, was the rebar 7 looked at for any degradation due to the boric acid 8 soaking?
9 MS. KRAINIK: Yes, it was. Would you like 10 further --
11 MR. BARTON: All right. That's all. It 12 was looked at. That's okay, all right.
13 MS. KRAINIK: Yes sir.
14 MR. BARTON: All right.
15 MEMBER STETKAR: Before you close, and 16 this is going to be quick, when did you replace the 17 bunch of fire protection piping? When did you do 18 that?
19 MR. HESSER: We can --
20 MEMBER STETKAR: Or has that been a 21 continuing process, or was it --
22 MR. HESSER: Yes, it's ongoing. Actually, 23 Pittalwala, would you come to the podium please? We 24 have a slide here we can actually illustrate what 25 we've done and what we currently plan to do.
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92 1 MR. PITTALWALA: Shabbir Pittalwala for 2 Palo Verde, Lead Piping team. We did it in two 3 phases. Our first phase was around 2002, and then our 4 second phase was, I believe we completed that in 2009.
5 MEMBER STETKAR: Have you replaced -- all 6 is a big word, but I'll use it. Have you replaced all 7 of the underground buried fire protection piping?
8 MR. PITTALWALA: No sir. We have replaced 9 approximately 11,000 feet out of the 18,000 feet of 10 the main header.
11 MEMBER STETKAR: 11,000 feet of 18,000 12 feet?
13 MR. PITTALWALA: Of the main header.
14 MEMBER STETKAR: All right. What are you 15 doing about the other 7,000 feet, which --
16 MR. PITTALWALA: We have a field approach.
17 We have it in the long-term plan. There are plans to 18 go and look at that. We focused on the ones that had 19 most degradation.
20 MEMBER STETKAR: Okay. But there is a 21 plan to monitor and/or replace it, and you replaced it 22 with fiberglass pipe?
23 MR. PITTALWALA: Fiberglass reinforced 24 plastic pipe, yes sir.
25 MEMBER STETKAR: It was scheduled?
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93 1 MR. PITTALWALA: It's a UL listed bond 2 strand of pipe manufactured by Ameron. It beats the 3 NFPA requirements and our design criteria.
4 MEMBER STETKAR: Okay, thanks. Yes, there 5 was a rather confusing sentence in the SER about the 6 7,000 feet.
7 You've done the remote eddy current 8 testing and it says that several sections had 9 localized degradation in excess of the minimum wall 10 thickness. That didn't sound too good, but I assume 11 it meant it had degradation that reduced you to 12 somewhere below the minimum wall thickness?
13 MR. PITTALWALA: Yes sir. We did remote 14 eddy current testing in the year 2000. That was the 15 first application of RFEC within the industry, and the 16 indication showed us that we had several locations 17 where we had exceeded minimal degradation, and in some 18 cases through wall, although the interior concrete 19 lining and the exterior earth pressure held it. There 20 were no leaks in those locations.
21 Up until then, we had been able to manage 22 all these for isolating sections of the piping, 23 because we have post isolation valves in-stream. So 24 we took the decision for actively going and replace 25 those sections.
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94 1 MR. BARTON: Okay. I guess I want to ask 2 you, why do you think that replacing with fiberglass 3 is the best option, because if you look at what's 4 going on in the industry, failed buried piping also 5 includes fiberglass piping as failed.
6 MR. PITTALWALA: Let me address that. My 7 understanding is that you're asking why we chose 8 fiberglass piping. At the time when we made the 9 decision, we wanted to go use material that is 10 corrosion-resistant, and we looked at two materials.
11 One was high density polyethylene, and we looked at 12 fiber-reinforced plastic.
13 Both of them had to meet the NFPA 14 requirements, National Fire Protection Association 15 requirements and had to be UL-listed. Both did.
16 However, the high density polyethylene did not meet 17 our pressure requirements because of downgrading it 18 for pressure, because of our high temperatures in our 19 fire protection tank.
20 MR. BARTON: Okay.
21 MR. PITTALWALA: That's the reason we 22 chose fiberglass reinforced plastic.
23 MR. BARTON: Thank you.
24 CHAIRMAN BONACA: Any other questions?
25 (No response.)
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95 1 CHAIRMAN BONACA: I thank you for the 2 presentation. We'll take a break now until 3:35.
3 (Whereupon, a short recess was taken.)
4 CHAIRMAN BONACA: Okay. So let's resume 5 the meeting and now we have the presentation of the 6 NRC.
7 (Off mic comment.)
8 CHAIRMAN BONACA: What?
9 (Off mic comment.)
10 CHAIRMAN BONACA: Okay. So the 11 presentation by the NRC.
12 MR. HOLIAN: Good, thank you. Thank you, 13 Chairman and my name's Brian Holian again. I'd just 14 add a couple of introductions and then I had a couple 15 of other follow-ons on your original question 16 Chairman, that I'll take now and we can either discuss 17 that now or if the members have questions on that 18 later.
19 I wanted to mention other introductions.
20 I mentioned Greg Pick. He's the senior reactor 21 inspector. Lisa Regner is the senior PM. Also at the 22 table is Evelyn Gettys. She's currently the project 23 manager for Columbia Station and is there assisting 24 Lisa, and Dr. Allen Hiser, our senior level advisor on 25 materials and other structures, is also at the table.
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96 1 I would also like to introduce Dr. Don 2 Naus, one of our contractors from Oak Ridge. He's 3 sitting behind the Chairman there. He's in. He's 4 also participated in the audit out at Palo Verde and 5 looked at a lot of the structure issues. He looked at 6 the spray ponds when he was out there. So I want to 7 highlight his attendance here today.
8 Just back on that original question you 9 had, Chairman. I said I might expand on it and 10 that's the question of, you know, a plant coming in so 11 early for license renewal and how you're sure or how 12 the staff kind of verifies operating experiences 13 incorporated as the years ago on, even before PEO.
14 I did mention that Part 50 and Part 54 15 overlap, and you know, Part 50, the maintenance rule, 16 covers a lot of these systems, and then Part 54 and 17 our aging management programs pick up on other areas 18 that the maintenance rule might not cover.
19 You know, I mentioned the overlap is 20 something that I think is good personally and, you 21 know, honestly sometimes the industry will complain of 22 that overlap a little bit. I'll get questions of, you 23 know, isn't that a current licensing issue and maybe 24 not a license renewal issue.
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97 1 because license renewal sometimes leads in the issues, 2 because we have a licensing issue in front of us in-3 house. So we do take the time to get as best of a 4 commitment that we can out of an issue, and get in our 5 safety evaluations.
6 Sometimes that even causes delays in the 7 application process, and the industry normally hasn't 8 complained too much about that, you know. What's a 9 couple of month delay in a couple year process?
10 An example of that is even currently now 11 on buried piping. We are still upgrading commitments 12 that were made even a couple of years ago. I might 13 even have a couple of supplemental SERs for a couple 14 of the older plants that are still in-house that 15 haven't been issued yet. But I'll issue an updated 16 commitment and we're still working with those plants 17 on upgrading those commitments.
18 So that's the plants that are still in-19 house I'm able to do that. Your question went 20 further, and what happens when a license is issued and 21 you've got such an extended period, say 15 years, 22 before the plant goes into PEO.
23 I mentioned the 7103 inspection. I just 24 wanted to highlight that again. That's the number 25 designation that we use for that inspection. We've NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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98 1 done maybe eight of those or so now, you know. It 2 started with Oyster Creek and we do those before, the 3 outreach before they go into the extended period.
4 We look at the commitments, a large 5 majority of the commitments. We only just recently, 6 within license renewal, kind of collated all those 7 findings from those inspections, just to trend to see 8 how well the plants are picking up on those 9 commitments. We have quarterly meetings with the 10 industry and we give them that feedback.
11 One of them I'll highlight was out of 12 Region III at the Dresden plant. There were a couple 13 of ROP findings, green findings in the 7103 inspection 14 that fed back into the ROP program and into the 15 corrective action process. So we haven't often talked 16 about that follow-on license renewal inspection.
17 It does occur before they go into PEO, 18 and we have the option of following up after their 19 NPEO also, with an aspect of that inspection, that 20 Oyster Creek is still being held this fall on a 21 follow-up to their original 7103 inspection. So I 22 wanted to highlight that as an option.
23 There's one other way Part 50 and 54 24 overlap. I think we've talked about an open item on a 25 couple of plants that the Committee might remember.
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99 1 It's not on this plant. Boral is an issue that plants 2 using their spent fuels, a lot of plants used, and 3 there has been some degradation in that type issue.
4 As a matter of fact. Dr. Heiser's been 5 tracking that for license renewal. But that's an area 6 where we do send out. We sent out a new interim staff 7 guidance on that issue, and for the license renewal 8 plants to realize that this is area, I think.
9 Under Part 50, we've also sent out generic 10 correspondence on that, and we work with the Division 11 of Engineering in NRR to apply that, not only plants 12 that have been renewed but these are plants that are 13 in Part 50 that haven't come in yet on that aging 14 issue.
15 So I wanted to expand on those options, 16 you know. It's kind of like a multi-pronged fork. We 17 have to ensure that corrective actions are maintained 18 in these aging management programs. How well we do 19 that is, you know, is a good question, and we 20 interface routinely with the regions on that.
21 The last item I'll mention is we actually 22 keep what we call a hot list of topics that we give to 23 the regions when they go out on that 7103. Here are 24 some items in the last four or five years that have, I 25 think we've highlighted in our SERs that we want you NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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100 1 to check on previous plants. So I wanted to highlight 2 that information and we can come back to that later if 3 the Committee members have additional questions.
4 CHAIRMAN BONACA: Thank you.
5 MR. HOLIAN: Okay. With that, I'll turn 6 it over to Lisa Regner, senior project manager.
7 MS. REGNER: Thank you, Brian. I'd like 8 to recognize the staff, the review staff in the 9 audience here today. I will probably call on them as 10 the presentation progresses. I'm very pleased to be 11 presenting to you today.
12 As Brian said, my name is Lisa Regner.
13 I'm the project manager for the Palo Verde Nuclear 14 Generating Station license renewal application, and 15 I'm going to discuss today the staff's findings 16 associated with the review of this license renewal 17 application, as presented in the staff's safety 18 evaluation report with open items.
19 Feel free to ask questions at any time, 20 but as a preview here are the main topics I plan to 21 discuss. I'll try not to repeat information that's 22 already been covered by the Palo Verde staff. They've 23 covered a good bit of information, so maybe my 24 presentation will only be two or three minutes.
25 (Laughter.)
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101 1 MS. REGNER: Let's see. I do want to 2 ensure that you receive adequate information 3 associated with the staff's review and findings so 4 far. The overview will be brief, since this 5 information was previously discussed. I'll then 6 follow the basic structure of the safety evaluation 7 report and cover topics of interest in each section.
8 Mr. Greg Pick will also discuss the license renewal 9 inspections and findings.
10 So starting with the overview, the only 11 points that I do want to add, beyond what Palo Verde 12 covered, is that the application was not initially 13 accepted for review by the staff, as it lacked 14 complete information on cumulative usage factors for 15 certain ASME Class 1 valves.
16 Once the applicant submitted a supplement 17 with this information in April, the staff then began 18 its review.
19 And the second point I do want to make is 20 associated with the power-up rates. The applicant had 21 requested two separate smaller, you know, about two 22 percent power-up rates for a total of five percent 23 above the original license thermal power, and the 24 staff did evaluate the effects of the steam generator 25 replacement and power-up rate on several time-limited NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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102 1 aging analyses, such as the reactor vessel neutron 2 embrittlement analysis, leak before break analysis, 3 and the ASME-3 fatigue analysis of Class 1 vessels, 4 piping and components.
5 The staff review, the staff's review 6 included two audits and one inspection. The license 7 renewal staff audits and regional staff inspections 8 are designed to minimize duplication of efforts.
9 While common were identified by both 10 license renewal and regional staff during the Palo 11 Verde assessments, staff communicated frequently to 12 share information and worked collaboratively to ensure 13 a comprehensive review.
14 And two areas where staff worked well 15 together were issues identified with fire zone scoping 16 and structural monitoring program issues, which Mr.
17 Pick will discuss shortly in his presentation.
18 The staff completed its review of 19 information submitted by the applicant by July 9th of 20 this year, and we issued the safety evaluation report 21 with open item in August. One open item remains 22 outstanding, related metal fatigue. There are also 23 five confirmatory items.
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103 1 the applicant. But I can certainly answer additional 2 questions and we'll cover those very briefly.
3 MEMBER STETKAR: Lisa, before -- could you 4 explain to me what the rationale is for calling 5 something an open item versus a confirmatory item?
6 MS. REGNER: Sure.
7 MEMBER STETKAR: On this particular 8 application, there were at least three things that are 9 classified as confirmatory items, that seem to say 10 "Gee, we have this question and we're waiting for a 11 response, and depending on whether or not the response 12 is acceptable, we deem this to be a confirmatory 13 item," where that's usually --
14 MS. REGNER: An open item.
15 MEMBER STETKAR: An open item.
16 MS. REGNER: Absolutely.
17 MEMBER STETKAR: So --
18 MS. REGNER: Absolutely, and you're 19 correct. Confirmatory items are the applicant and the 20 staff have agreed on a resolution, and we're merely 21 waiting for the documentation, the formal 22 documentation of that resolution. So in all five of 23 those confirmatory item cases, we did have a clear 24 path forward, and it was merely a matter of Palo Verde 25 submitting --
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104 1 MEMBER STETKAR: Okay, because that 2 doesn't really come across in the SER, because I read 3 things saying, you know, "pending review of the 4 applicant's responses, the staff finds this 5 acceptable," which to me sounds a bit --
6 MS. REGNER: Right, and that's also kind 7 of leaving us open to the idea that it's not official 8 until it's official.
9 MEMBER STETKAR: I understand something 10 like a commitment to drain a tank, you know. That I 11 can understand.
12 MS. REGNER: Yes, yes.
13 MEMBER STETKAR: But okay.
14 MS. REGNER: That's true, and actually --
15 MEMBER STETKAR: The first one I've come 16 across, where there seemed to be sort of questions 17 about which side of that nebulous line, something --
18 MS. REGNER: And an open item is somewhat 19 tricky as well, the idea of calling it one open item 20 versus --
21 MEMBER STETKAR: And no. I understand the 22 bundling of the metal fatigue. That's okay. I was 23 just --
24 MR. HOLIAN: This is Brian Holian. The 25 only other thing I'd add, since I don't see the OGC NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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105 1 lawyer in the room yet, is I'll blame that wording on 2 them. But that might be part true on the conclusion 3 aspect of it. You know, we need to do a final review.
4 But it is as Lisa mentioned. Sometimes I read them 5 and I say this is almost an open item.
6 MEMBER STETKAR: I mean in principle, I'm 7 left to say that if their response was not 8 satisfactory, what happens then? A confirmatory item 9 becomes an open item?
10 MR. HOLIAN: Becomes an open item then, 11 and yeah, we'd get back to you or we'd tell you that 12 if that --
13 MEMBER STETKAR: Okay.
14 MR. HOLIAN: If we actually did some more 15 work on this, then we'd highlight that to you.
16 MEMBER STETKAR: Okay, thanks.
17 MS. REGNER: Section 2 of the SER concerns 18 structures and components subject to aging management 19 review. During its review, staff identified several 20 scoping concerns which resulted in amendments.
21 For example, during a material and 22 environmental audit, staff noted an error in the 23 material for the Deville generator system pre-lube oil 24 pump, and staff -- that was as a direct result of 25 staff walking out into -- this was a new audit that NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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106 1 staff implemented, and they identified the pump was, 2 pump casing was carbon steel versus stainless steel, 3 as identified in the LRA.
4 And I also wanted to point out that as a 5 result of staff reviews of license renewal drawings, 6 plant walk-downs, over 50 aging management review 7 items were added to the license renewal application.
8 The majority of those were in the balance of plant 9 systems.
10 In the area of scoping, one confirmatory 11 item remains outstanding. We discussed what, how we 12 define confirmatory item. The applicant did discuss 13 that that has to do with the draining of the 14 containment spray chemical addition tanks. New 15 information has emerged since we issued the SER. The 16 applicant changed their date, their commitment date to 17 November 30th.
18 Concerning Section 2, once the 19 confirmatory item associated with the containment 20 spray chemical addition tanks is resolved, the staff 21 will be able to make its finding concerning Section 2.
22 I'll now turn the presentation --
23 MEMBER STETKAR: Lisa, before you turn it 24 over.
25 MS. REGNER: Uh-huh.
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107 1 MEMBER STETKAR: A couple of probably 2 small items, but maybe it can help with some confusion 3 that I had. The applicant screened out fire 4 protection systems for a number of in-scope outdoor 5 transformers, high voltage transformers, even medium 6 voltage transformers.
7 And apparently, and it was a response to 8 an RAI on that, and apparently the response said well 9 because these transformers are located more than, I 10 don't know what it is, 50 feet away from something 11 else or they have a fire barrier with a rating of 12 three hours, we don't have to protect them against 13 fire. Even though they're in-scope transformers. In 14 other words, they provide an in-scope power station 15 blackout recovery function.
16 MS. REGNER: Uh-huh.
17 MEMBER STETKAR: It struck me as rather 18 odd. Essentially you're saying it's okay to burn them 19 up, but I can't have an electrical fault on them or I 20 can't have some structural failure of them. Can you 21 explain why it's okay to not include the fire 22 protection for those transformers?
23 MS. REGNER: I've got my technical 24 reviewer, who just walked in, and I will turn it over 25 to Mr. Naeem Iqbal.
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108 1 MR. IQBAL: I'm Naeem Iqbal with the Fire 2 Protection Branch, NRR. The Palo Verde outdoor 3 transformers are not in the scope because they are 50 4 feet away from the circulated area. So that's a 5 requirement for the ground technical provision that 6 Palo Verde has. The fire protection system, dilute 7 system for transformers is only for the insurance 8 processes.
9 MEMBER STETKAR: Well, that's what 10 confuses me, because these transformers are in scope 11 for other elements of the license renewal process.
12 MR. IQBAL: For the fire protection 13 system, the dilute system is only for the loss 14 prevention purposes, not the regulatory, you know, 15 purposes.
16 MEMBER STETKAR: So it's okay to burn them 17 out, but I can't electrically fault them or I can't 18 trip them over because of structural failure?
19 MR. IQBAL: Because 50 feet away, the 3R 20 fire barrier in the terminal building. So there's no 21 requirement for the fire protection program.
22 MEMBER STETKAR: Apparently you're not 23 picking up on the irony. These transformers are 24 required to be in scope to restore off site power.
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109 1 structural components must be intact. They must 2 electrically be there, meaning things like electrical 3 insulation must be intact, and I would assume that 4 they must be there not a molten pile of burned up 5 stuff.
6 MR. IQBAL: Right.
7 MEMBER STETKAR: I'm curious if they have 8 to be there physically and electrically, why only 9 because of insurance purposes don't they have to be 10 there in terms of not being consumed by fire?
11 MR. IQBAL: But if they have the system 12 there, right? They have the system but not in the 13 scope, the fire protection system not in the scope 14 because of the --
15 MEMBER STETKAR: I can rest that fire 16 system, I can plug it up so that it never works.
17 MR. IQBAL: I don't think so, because they 18 already have maintenance program there. They're 19 looking at it, so --
20 MEMBER STETKAR: But there's no guarantee 21 under their aging management programs that that system 22 remains intact.
23 MR. O'KEEFE: I think I can answer this 24 question. This is Neil O'Keefe. I'm the branch chief 25 for not only license renewal in Region IV but fire NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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110 1 protection.
2 The question you're asking is mixing 3 initiating events. If you had a fire in one of these 4 transformers, then a plant has the ability to power 5 the equipment they need to safely shut down the plant.
6 So it doesn't matter, as long as that fire doesn't 7 spread to other stuff, you're okay. So it's just a --
8 MEMBER STETKAR: That may be a good 9 answer. However, I've seen, I believe, in other 10 license renewals, where the fire protection for the in 11 scope transformers is in scope. That's really the 12 reason I raised this.
13 MR. O'KEEFE: The spatial relationship.
14 Fire protection always about spatial relationships.
15 MEMBER STETKAR: Okay.
16 MR. HOLIAN: And this is Brian Holian.
17 The only thing to add on some licensees putting it in 18 scope, makes sense from a logic standpoint, not this 19 irony aspect. I think they just volunteered to put it 20 in scope for their own methods or ease of --
21 MEMBER STETKAR: I'm just saying if you 22 justify it from the sort of multiple initiators, 23 perhaps I can rationalize that way.
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111 1 know, it might cause the plant to shut down. You 2 know, if it's not needed for plant shutdown, sorry.
3 MEMBER STETKAR: Okay, thanks.
4 MS. REGNER: Thank you.
5 MEMBER STETKAR: One other question I had 6 on scoping and screening, and this is probably -- this 7 is more a question for the licensee or applicant.
8 The compressed air system is -- most of 9 the system is not in scope for license renewal, as 10 it's currently characterized. Exceptions being parts 11 of the system that are required for containment 12 isolation functions, those containment isolation 13 valves, for example.
14 However, it's noted that -- and it's sort 15 of noted briefly that compressed air is a support 16 system for fire protection pre-action deluge spray 17 valves that are definitely in scope for license 18 renewal.
19 If you look at the -- some them are in, 20 some of them are not in. Not the transformers; these 21 are other in-plant. The question is is air pressure 22 required to operate? Is clean actual pressure 23 required to operate those valves?
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112 1 in scope fire protection valves? So as I said, it's 2 probably more a question for the applicant.
3 MS. REGNER: I certainly will have to let 4 the applicant answer that one, if they're willing.
5 MEMBER STETKAR: I'm sure they're willing.
6 It's whether they're able.
7 (Laughter.)
8 MR. COXON: Doug Coxon, Palo Verde 9 Operations, and the question was is compressed air 10 air-support the deluge system? Primarily the answer 11 is no. It's there from a supervisory standpoint, to 12 get line function to stop there.
13 (Simultaneous discussion.)
14 MEMBER STETKAR: Okay, understand. I just 15 wanted to make, confirm, because I couldn't tell from 16 the drawings. Thanks.
17 MS. REGNER: Okay. So I'll turn it over 18 to Mr. Greg Pick, the Region IV lead inspector, who 19 will discuss the license renewal inspection planning.
20 MR. PICK: Thanks, Lisa. Good afternoon 21 members of the ACRS Subcommittee, applicant personnel 22 and members of the public, and fellow NRC personnel.
23 As was described earlier, we performed our inspection 24 in February of this year. The inspection team 25 consisted of two generalists, an electrical engineer, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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113 1 a civil engineer and a mechanical engineer. Next 2 slide please.
3 This was the second plant review whose 4 application was processed by the STARS Center of 5 Business. Our on-site inspection team reviewed 26 of 6 the aging management programs, which included five of 7 the new aging management programs.
8 When we conduct our inspections, we walk-9 down the structures and the components in-field. We 10 review the relevant programs and process documents if 11 they've been developed. In this instance, there were 12 a lot of documents that allowed for a thorough review.
13 We consider operating experience and we interview the 14 program owners.
15 Our inspections focused on conditions at 16 the plant and how they have implemented the existing 17 aging management programs. We also performed a 18 vertical slice evaluation. What I mean by that, we 19 kind of took the whole application on three systems, 20 and looked to see if they had considered proper 21 environments and the materials similar to what the 22 aging management review and aging management program 23 of headquarters does. But it's from an implementation 24 viewpoint.
25 MR. BARTON: And what was your conclusion?
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114 1 MR. PICK: For the systems we selected?
2 MR. BARTON: Uh-huh.
3 MR. PICK: That they had properly 4 included, considered the appropriate environments, 5 assigned the appropriate AMPs and had the proper 6 material, based on the records we reviewed.
7 There were outstanding questions related 8 to structures monitoring and the scope, and right 9 after we left site, they had that bus duct failure.
10 We decided we needed to look at the root cause. Next 11 slide, please.
12 We found their scoping of structures and 13 components thorough and generally accurate. The 14 drawings were well-developed, clearly identified what 15 was included for A-1, A-3 and A-2. As inspectors, the 16 applicant used a fire zone approach and a mitigative 17 method, as allowed by NEI 9510, to exclude some 18 components from the aging management review.
19 When you use a mitigative method, you have 20 to have a thorough evaluation for any component in the 21 area, so that you can exclude it. During our field 22 walk-downs, we found some pressure transmitters and 23 other items that they had no evaluation for, and had 24 not included in their review.
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115 1 was to just fall back on the preventive approach and 2 include them all in the scope of aging management 3 review. Any questions?
4 In the area of aging management programs, 5 for structures, they already described that they had a 6 30-year period where they were going to look at a 7 representative unit. If they found in a problem in 8 one unit, they would have looked at the same locations 9 in the other unit, to try to find out what the cause 10 was.
11 In my experience in maintenance rule, many 12 plants look at their structures every five years. So 13 that seemed to be a long period of time, and I 14 challenged it from their maintenance rule aspect. In 15 response to that, for license renewal, as they said, 16 they're going to follow the ACI standard and all of 17 its periodicities for Category 1 structures.
18 For the current license basis, as they 19 said, they'll have two complete 100 percent 20 inspections prior to entering the period of extended 21 operation. We found that response, for both license 22 renewal and the current period of operation, 23 satisfactory.
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116 1 cranes, they properly included all of their cranes.
2 For the 25-ton diesel crane, they did not have a PM 3 developed. So they had, I cannot say they had not 4 inspected; they did not have an existing PM.
5 They promptly initiated a corrective 6 action document, began developing a PM and they're 7 going to include the aging management aspects of 8 monitoring for rust and corrosion on the I-beam and 9 the trolley wheels.
10 For inaccessible medium voltage cables, as 11 the applicant said, the large -- most of the water 12 source is following rainfall. They had a typo in 13 their procedure, where they needed three inches in a 14 24-hour period before they would begin their -- but 15 that was not conservative. It was really .3 inches.
16 So it's really not very much rain for the desert, and 17 they're going to start looking for water in their 18 electrical manholes.
19 Similar to the questions by the ACRS 20 Subcommittee, they had an error in their application 21 related to selective leaching. It was a wording 22 error. They were going to credit their review of 23 selective leaching monitoring beginning now, and going 24 up to the PEO.
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117 1 but the GALL requires that within ten years of their 2 period of extended operation, so you have more 3 operating history. You'll start crediting those to 4 figure out what you're going to do in the area of 5 selective leaching, and whether you needed a program.
6 Once we pointed that out to them, they 7 promptly corrected that.
8 MEMBER STETKAR: Greg, they mentioned, I 9 don't know, this selective leaching or just general 10 corrosion. But they mentioned problems with the fire 11 water, fire protection system in replacing pipe. Do 12 they have any other in-scope cast iron or that type of 13 pipe that would be --
14 MR. PICK: By the material. I don't know 15 the answer to that question.
16 MEMBER STETKAR: Do you have any other 17 varied in-scope cast iron piping?
18 MR. HESSER: Mr. Pittalwala will address 19 your question.
20 MR. PITTALWALA: Shabbir Pittalwala, Palo 21 Verde. Yes sir. The balance of the portion of the 22 fire protection system that is not replaced is ductile 23 cast iron.
24 MEMBER STETKAR: Got that. Any other in-25 scope systems?
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118 1 MR. PITTALWALA: Not to my knowledge.
2 MEMBER STETKAR: Okay, thanks. That's 3 what I was asking. Thanks.
4 MR. HOLIAN: We've got one other 5 clarification. Bill Holston, the senior reviewer, has 6 a clarification.
7 MR. HOLSTON: There is a portion of the 8 make-up water system that's got ductile cast iron in 9 it also, that's in scope.
10 MEMBER STETKAR: Any enhanced inspections 11 planned for that?
12 MR. HOLSTON: We would, and actually it's 13 domestic water, I'm sorry. We've evaluated their 14 buried pipe program in relation to the current OE out 15 there, and compared it to the GALL AMP that we were 16 developing, AMP 41.
17 Because that's non-safety related piping, 18 it would be in scope for preventive measures, but we 19 would not require inspections of that piping.
20 MEMBER STETKAR: I'm not quite sure I 21 understood all of that, though. It's in scope for --
22 I understand it's not safety-related piping. Is it in 23 scope for license renewal?
24 MR. HOLSTON: Yes. There is a portion 25 that's in scope for license renewal.
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119 1 MEMBER STETKAR: Under --
2 MR. HOLSTON: As I recall, that's -- it's 3 either A-2 or A-3.
4 MEMBER STETKAR: It's A-2 or A-3. Yes, it 5 would have to be.
6 MR. HOLSTON: That is correct, and what I 7 was saying is the applicant committed to meet GALL AMP 8 M-34. We've gone to all the current applicants and 9 asked them to look at their plant-specific operating 10 experience, industry operating experience, and look at 11 augmenting their programs as necessary to account for 12 that.
13 MEMBER STETKAR: Uh-huh, okay.
14 MR. HOLSTON: And so we've been evaluating 15 each plant on an individual basis, but using the new 16 AMP 41 as kind of a philosophical basis for that 17 evaluation of each of these plants that are Revision 1 18 GALL plants but not Revision 2. In Revision 2 of the 19 GALL, which will be AMP 41 for buried piping, non-20 safety-related piping, you have to implement the 21 preventive measures.
22 So we want to see cathodic protection. We 23 want to see coding. We want to see backfill. But we 24 don't require inspections of non-safety-related 25 piping.
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120 1 MEMBER STETKAR: Got you, okay.
2 MR. HOLSTON: We focused our inspections 3 on -- piping.
4 MEMBER STETKAR: Okay, okay. But you do 5 require -- that explains the preventive measures.
6 Thanks.
7 MEMBER ARMIJO: Yes. I noticed that you, 8 there was a lot of cathodic protection applied to the 9 buried piping and maybe some other components. But I 10 was wondering how effective that is in a desert 11 environment where there's no electrolyte. Is that 12 just belt and suspenders, or is it something that's 13 really effective?
14 MR. VALLE: Dean Valley, Division of 15 Component Integrity. Cathodic protection is a very 16 effective means of preventing corrosion in buried 17 systems.
18 Properly designed, you will either have 19 good current good voltage of conditions, or in a very, 20 very, very dry environment, where you may have 21 difficulty in achieving those potentials because of a 22 lack of electrolyte, you'll have very, very little 23 corrosion due to the, again, lack of the electrolyte.
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121 1 either the reasons of being effective or because the 2 environment is not sufficiently moist to cause a 3 problem.
4 MEMBER ARMIJO: Okay, thank you.
5 MR. PICK: The other unresolved item in 6 the inspection report dealt with review of their bus 7 duct failure, from review of the root cause. I agreed 8 that it was a maintenance-related failure, and you 9 needed the cracking of the Noryl. The purpose of the 10 unresolved item was to see if the event would cause 11 them to revise their AMP, since the cracking of the 12 Noryl was the condition.
13 We were looking at the bus ducts at many 14 facilities, it added no new information. That 15 satisfied us. Next slide, please.
16 The applicant remains in the licensee 17 response column of the NRC action matrix of the 18 reactor oversight process. They did exit Column 4 the 19 first quarter of 2009. When we were on site, they 20 were still implementing some of the corrective actions 21 from their site improvement program. That was an ROP 22 finding, that allowed them to leave that Column 4.
23 Being in the licensee response column, in 24 the column Inspection Findings and Performance 25 Indicators, are of very low safety significance.
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122 1 While we were on site, we performed many walk-downs of 2 the structure systems and components, particularly the 3 Ultimate heat sink, building and tank exteriors, 4 station blackout turbine generator. We found those 5 items to be in good condition.
6 We have some minor items identified in the 7 report, where there were some dirt in pull boxes and 8 lack of gaskets. We identified that to them. They 9 wrote a corrective action document and put them in 10 their work control process and were having those items 11 replaced.
12 We did not have an opportunity to go 13 inside the containment. I talked to a former resident 14 and called the residents. They find the interior of 15 the containment to be in good condition; no major, no 16 spalling, no rust and no delamination of the coatings.
17 MEMBER ARMIJO: Is that the result of just 18 the casual observations, or is it a formal inspection?
19 MR. PICK: They were casual observations.
20 MEMBER ARMIJO: Okay.
21 MR. PICK: They did not go into the 22 containment looking for those sort of things.
23 MEMBER ARMIJO: Okay.
24 MR. PICK: Next slide, please. So the 25 conclusions from the inspections was we found the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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123 1 scoping of non-safety structures, systems and 2 components and application of the AMP to those 3 components acceptable, after the one item was 4 corrected.
5 Reasonable assurance exists and aging 6 effects will be managed and intended functions 7 maintained during the period of extended operation, 8 and for the structures monitoring, we feel that the 9 applicant established a schedule for structural 10 inspections to provide data for comparison prior to 11 entering the period of extended operation.
12 Unless there's any questions, I'm going to 13 turn the lectern back over to Lisa.
14 MS. REGNER: Thanks, Greg. Moving onto 15 Section 3, Aging Management Review Results, Section 3 16 covers the staff's review of the applicant's aging 17 management programs and aging management reviews, 18 evaluated against the criteria in the GALL report.
19 For a given aging management review, the 20 staff reviewed the intended function material 21 environment aging effect requiring management, and 22 delegated aging management program combination for a 23 particular system component type, whether it aligned 24 again with the GALL report AMRs.
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124 1 not align or was not addressed in the GALL report, the 2 staff conducted a full technical review to ensure 3 adequacy. The staff reviewed 40 AMPs and over 2,500 4 aging management review items. This included 29 5 existing programs and 11 new programs.
6 MEMBER STETKAR: Lisa, before we get to 7 the confirmatory items, I don't need the body count 8 there, I had a question. There was one issue. In 9 fact, it was the subject of an Information Notice 10 2009-04, regarding -- I can't read my own typing here 11 reduced support force in main steam line supports in 12 each unit.
13 There were questions that you raised about 14 that. The original Information Notice identified the 15 cause of this problem as due to wear caused by cyclic 16 loading and vibration, which was characterized as an 17 age-related degradation mechanism.
18 The applicant apparently concluded that it 19 was not age-related. It was a design problem.
20
Conclusion:
Design issue involving configuration of 21 the structural supporting members. This problem was 22 identified after about 22 or 23 years' worth of 23 operation.
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125 1 know, if the thing is installed and it had been 2 working fine for 20 years, apparently not so fine, 3 wearing out, just because somebody said well, this is 4 a problem with the original design, that's 5 justification for not enhancing the inspection of that 6 or similar items?
7 That bothered me a little bit, because it 8 says pretty much anything that I can say well, it was 9 part of the original design, even though it failed 10 after 30, you know, 57 years, but wasn't at all age-11 related.
12 MS. REGNER: Uh-huh, and I assume you're 13 talking about the small bore piping --
14 MEMBER STETKAR: No, no, no. I'm talking 15 about supports for the main steam line piping.
16 MS. REGNER: Okay.
17 MEMBER STETKAR: We'll talk about the 18 socket welds later, because the design issue is also 19 invoked under that. It's a completely different 20 topic.
21 MS. REGNER: Okay.
22 DR. HISER: Well, I think one could claim 23 everything in the plant, that it is -- it's a design 24 problem. You used the wrong material, the wrong 25 stresses.
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126 1 MEMBER STETKAR: It wore out. I should 2 have used a better one.
3 DR. HISER: Right. But I think --
4 MEMBER STETKAR: If corroded, I should 5 have used more corroded resistance.
6 DR. HISER: I think the one distinction 7 that we make is that if the plant makes design changes 8 as a result of the finding, you know, they redesign 9 the supports, they use new material, they do something 10 that's different and they take remedial actions for 11 similar locations, then the conditions are different 12 in those locations.
13 Now presumably one would go to the similar 14 locations and they would do an examination.
15 MEMBER STETKAR: Well, and yeah.
16 DR. HISER: The same problem exists there.
17 If that same problem exists, then they would do a 18 repair, some sort of -- and along with the design 19 change. So that from that perspective, if one has 20 changed the conditions, then one could look at it as 21 no longer an aging-related failure but one that has 22 been fixed through a modification.
23 In this specific case, I'm not sure 24 exactly what Palo Verde did. Maybe Palo Verde or our 25 structural reviewer could comment on the specifics.
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127 1 MR. SHEIKH: Abdul Sheikh, NRC staff. I 2 looked at this thing and the reason appears to be the 3 design error, because it's the cyclical loading which 4 caused that problem, and that -- because the same kind 5 of supports didn't fail in other areas. You know, 6 they are hundreds of spring hangars of the similar 7 characteristics in the plant. But only have those 8 steam line supports failed.
9 And that happened because of the cyclical 10 loading. So, and they have redesigned the system 11 there.
12 MEMBER STETKAR: So that those supports 13 won't fail?
14 MR. SHEIKH: Correct. This has happened 15 in some other plants also, because when the steam line 16 comes out in that area, there is dynamic loads which 17 cause those spring hangars to fail.
18 MEMBER STETKAR: I just thought that there 19 may be a rationale for any individual repair, 20 redesign, new installation that you want to call it.
21 But it strikes me that at some point in time, you 22 know, as I said if these things had been discovered 23 during the second or third year of operation or the 24 first inspection, fine. I understand that.
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128 1 operation, and at some point, it strikes me that the 2 line between well, it was a design problem so we're 3 going to replace it in year 59, versus it really was a 4 cumulative -- yeah, perhaps the design should have 5 been better, but that was a cumulative effect of aging 6 and fatigue.
7 But I think, I think what you really need 8 to look at is what do you do going forward? I mean 9 once you have identified that the purpose of aging 10 management is to try to capture things before you get 11 failures, before you impact plant safety. If you've 12 identified the problem, you know, hopefully you 13 haven't caused an accident or anything like that.
14 But once you've identified it and you have 15 taken corrective actions, you've taken maybe 16 preventative actions, mitigative actions, design 17 changes, presumably you've restored the condition, and 18 you have improved the situation. Now there may be 19 additional monitoring in the short term as necessary, 20 with -- Lisa mentioned socket welds. That's one of 21 the things -- with plants.
22 But when they make changes, they'll go in 23 and they will do some periodic inspections to ensure 24 that the, you know, cycles, the amplituder cycles have 25 been dampened, things like that, to ensure that the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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129 1 design change has really taken care of the conditions 2 that led to the problem.
3 So I think maybe looking forward is really 4 more important as opposed to, you know, is it a design 5 change or aging management overall.
6 MEMBER STETKAR: Okay, thanks.
7 MR. HOLIAN: This is Brian Holian. It's 8 Brian Holian. Just to add, that question is very good 9 and it sits there maybe without proper definition by 10 us in our standards, but it's clearly something we 11 think about on all the operating experience issues.
12 We wonder whether the industry, you know, tends to not 13 call them age-related, to get out of that designation 14 of op experience.
15 We wonder that. We talk about that with 16 our regional people. They bringing up small bore 17 piping because in an example, that was a case where we 18 were head to head with the industry on that. They 19 said no and it's no aging issue here, and you can see 20 both sides of the coin sometimes.
21 But I'm just trying to say that we are 22 trying to push that line, to include it from the 23 staff's perspective, where you can into an aging 24 management program. I don't know if that helps, but -
25 -
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130 1 MEMBER STETKAR: That helps.
2 MR. HOLIAN: I mean you know we can talk 3 about individual examples and things like that, but --
4 MEMBER STETKAR: Okay, thank you.
5 MS. REGNER: All right. so as you know, 6 there is an open item related to metal fatigue in 7 Section 4. The open item is linked to Section 3, 8 since the staff discusses it in its review of the 9 metal fatigue AMP. However, I would like to wait 10 until Section 4 and discuss that open item in just a 11 moment.
12 There are four confirmatory items in 13 Section 3. the applicant did cover most of these, but 14 I'll go ahead and go over them. Cavitation erosion of 15 infrequently used high pressure safety injection 16 minimum flow piping resulted in questions concerning 17 the extent of condition analysis and other 18 infrequently operated systems that could be 19 susceptible to the same aging effect.
20 We did also ask the same question that I 21 believe Mr. Stetkar, Dr. Stetkar, I apologize.
22 MEMBER STETKAR: No, it's Mister.
23 MS. REGNER: Mister, sorry, about effects 24 on other materials as well, not limiting -- not 25 limiting the material to stainless or carbon steel.
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131 1 Other concerns, another confirmatory item 2 concerns the sample size and statistical justification 3 of the one-time inspection of small bore piping socket 4 welds.
5 MR. BARTON: Well haven't they come 6 forward and agreed to do ten percent of all the socket 7 welds on each unit, which is going to be, you know --
8 DR. HISER: Yes. That's part of the 9 confirmatory item, that we're reviewing their 10 submission.
11 MR. BARTON: Oh, you're reviewing that?
12 DR. HISER: Yes, to see whether that --
13 well, that's a lot more than anybody else has 14 committed to, so it ought to be all right. The number 15 of welds that they have and the number that they will 16 inspect are fairly significant, and that's why it's 17 found -- that's why we found it --
18 MR. BARTON: A lot of people are arguing 19 over one weld, so you know.
20 DR. HISER: Correct.
21 MEMBER STETKAR: Let me ask something 22 different, because this is something I've been asking 23 sort of in several, and Brian knows what's coming.
24 There's kind of consistency in the staff's approach to 25 this issue across the different applicants.
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132 1 For example, in this particular case, 2 you've accepted a fairly large sample of volumetric 3 examinations, but only in terms of a one-time 4 inspection. In other current license renewal 5 applications that are in progress right now, you've 6 pressed quite strongly for going forward periodic 7 volumetric programs.
8 Perhaps a smaller sample, and in some 9 cases it's a risk-informed sample, but the sense is 10 that this is not a one-time inspection process, that 11 there is -- staff feels that it's important that it 12 should be an ongoing periodic inspection activity.
13 So I'm curious about why on this one, even 14 though it might be a large sample, that a one-time 15 inspection is adequate, where for other applicants, 16 apparently a one-time inspection, regardless of the 17 sample size, is not adequate?
18 DR. HISER: In general, it comes down to 19 the plant operating experience, and plants that have 20 had a history of failures --
21 MEMBER STETKAR: They've had two failures 22 here.
23 DR. HISER: They had two failures, three 24 design changes. They have been remediated. One of 25 the reasons, one of the reasons that we have balanced NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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133 1 the ten percent, the large sample size at one time is 2 that they will examine a lot of the welds, ten percent 3 of the welds overall. If they do find problems in 4 those 100 inspections, then they will go -- they will 5 revert to a periodic inspection program.
6 MEMBER STETKAR: I guess I'm thinking 7 going forward to the next applicant, what is my 8 expectation when I read their proposal, to give me a 9 level of comfort or to give them a level of comfort 10 that they're going to satisfy what the expectations 11 are?
12 MR. HOLIAN: I don't worry about their 13 level of comfort. I'm just kidding you, but --
14 (Simultaneous discussion.)
15 MR. HOLIAN: It's the complaint I get.
16 This is Brian Holian. On a couple of these evolving 17 issues, I'll call them evolving issues, if we had that 18 word there, and small bore piping is one of them. We 19 do have a table in-house.
20 MEMBER STETKAR: You do? Okay.
21 MR. HOLIAN: Just to satisfy you with how 22 we're addressing all 15 plants in-house, and there is 23 some variability. Dr. Hiser brought up one. We won't 24 trade off a larger sample now for maybe less. Here's 25 where we'll then credit, okay, your corrective action NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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134 1 program, your Appendix B program.
2 We will expect that if you find some on 3 these samples, that my inspectors or my Region IV 4 inspectors go out and see that you had some and you 5 didn't follow on with some progressive inspection, you 6 know, come up with a corrective action finding in that 7 case.
8 But to answer why I don't have it 9 satisfied in stone here, is I don't have the Rev 2 of 10 the GALL out yet. I don't, I can't kind of officially 11 tie them to the new buried piping AMP that you heard 12 us in Part 41. So I'm getting a little bit of 13 variance in the in-house ones.
14 But as Dr. Hiser said, you know, kind of 15 we are trying to balance what operating experience 16 this plant has had compared to the industry 17 experience.
18 MEMBER STETKAR: Is there -- Brian, is 19 there a reasonably settled set of internal, I don't 20 know if criteria is probably too strong a word, but 21 internal guidance that you use, so that a particular 22 applicant, through discussions with you, can 23 understand what the expectation may be?
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135 1 through subtle iterations of RAIs and confirmatory 2 items or open items, if I had some better confidence 3 going forward.
4 MR. HOLIAN: The GALL serves that purpose 5 when we get it solidified again. But in the meantime, 6 we do rely on rating the RAIs of other plants and our 7 acceptance. I mean they --
8 MEMBER STETKAR: Yes, but I mean I've been 9 doing that, and I'm confused.
10 MEMBER ARMIJO: For this component, there 11 is no volumetric inspection that's qualified?
12 DR. HISER: Well, yeah. I think we 13 discussed during Kewaunee that if EPRI has a technique 14 that they developed for one plant, for one socket weld 15 geometry. They're looking at expanding that to a 16 broader sample. You know, the use of the word 17 "qualified" may not be the right word. I mean I think 18 the wording we like is one that's demonstrated capable 19 of detecting the conditions that you're worried about.
20 MEMBER ARMIJO: But given that, that the 21 technology isn't really ready for wide use --
22 DR. HISER: Not for today.
23 MEMBER ARMIJO: Not for today, given that, 24 but then you're going with a visual inspection, and it 25 would seem to me that what Palo Verde's going to do is NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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136 1 preferable, because since it's a visual inspection, 2 I'd rather have. What are you going to look for?
3 You're going to look for leakage or any indication.
4 I think a large sample now is better than 5 periodic samples over a longer period of time, to 6 understand where you are in the plant. So I think 7 this is a good inspection. In fact, I would prefer it 8 over, you know, an even larger sample taken over a 9 longer period of time.
10 But they're going to do a one-time early 11 inspection and then periodics. I think it's --
12 MR. BARTON: As long as you don't find a 13 lot of failures.
14 MEMBER ARMIJO: Well, if you find a lot of 15 failures, that's what you -- then you're better off to 16 find them now than later.
17 MEMBER STETKAR: I think Allen, aren't 18 they committing to a ten percent volumetric 19 examination?
20 DR. HISER: That's correct, yes.
21 (Simultaneous discussion.)
22 MEMBER ARMIJO: No, I think it was just 23 visual. They were going to do it if a qualified or --
24 MEMBER STETKAR: That was the Kewaunee.
25 DR. HISER: That was Kewaunee.
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137 1 MEMBER ARMIJO: Then I misread the --
2 MEMBER SHACK: Kewaunee and then --
3 (Simultaneous discussion.)
4 MS. REGNER: That was their original 5 commitment, and they've updated. They've changed that 6 commitment.
7 MEMBER STETKAR: This is the most 8 aggressive one-time inspection, I think, that we've 9 seen --
10 (Simultaneous discussion.)
11 MEMBER ARMIJO: That we've seen so far.
12 MEMBER STETKAR: --of massive weld 13 material.
14 DR. HISER: The number of welds, I think, 15 at Palo Verde is maybe much larger than other plants 16 have had. So the number of welds they're going to 17 sample --
18 DR. HISER: That was 40 socket welds, I 19 think, they said.
20 MR. BARTON: Yes. So about 1,000. So 21 about 100 overall between the three units.
22 MEMBER ARMIJO: Allen, set me straight.
23 They're going to use some sort of a UT volumetric 24 inspection on these socket welds?
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138 1 yes.
2 MR. HOLIAN: As volumetric, so and it may 3 be --
4 MEMBER ARMIJO: Well, I guess you can X-5 ray it, but I don't think you would want to --
6 MEMBER SHACK: Presumably it's UT, but 7 it's certainly volumetric.
8 DR. HISER: But I think our, the NRC's 9 expectation is that within a couple of years, there 10 will be an industry-accepted UT technique that will be 11 available for everyone to use.
12 MEMBER SHACK: Okay, okay.
13 DR. HISER: So a lot of the prior 14 applications that have said things along the lines 15 that we'll use UT if it's available or do destructive, 16 you know, our expectation is that those are going to 17 default to UT.
18 MEMBER ARMIJO: Yes, okay.
19 MS. REGNER: Okay. The staff also 20 requested confirmation that the steam generator feed 21 rings are not susceptible to flow-accelerated 22 corrosion. Finally, information was requested to 23 confirm that aging from loss of material and 24 degradation were going to be adequately managed for 25 PVC and elastomer-lined piping in raw water NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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139 1 environments.
2 I've received the information on all four 3 of those confirmatory items.
4 Okay. Section 4. This section contains 5 the staff's review of time-limited aging analysis.
6 The staff's review is complete for all sections except 7 4.3, Metal Fatigue Analysis, which contains an open 8 item. Concerning the metal fatigue analysis open 9 item, how did we get here?
10 As stated previously, the initial license 11 renewal application review was stopped in February and 12 resumed in April, due to incomplete cumulative usage 13 factor information for Class 1 valves. Following 14 acceptance review, the original staff concerns were 15 covered well by Palo Verde, and they were related to 16 design basis information inconsistencies; also 17 inconsistencies between the metal fatigue subsections 18 in the license renewal application, and also 19 disposition issues.
20 The staff conducted ten conference calls.
21 We held a public meeting in May with the applicant, 22 and we've issued a total of 70 questions in all 23 related to metal fatigue to resolve these issues. In 24 addition, seven amendments were associated with the 25 metal fatigue unlimited aging analyses.
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140 1 As stated, the applicant has submitted 2 answers to all of the staff's current questions, 3 issued questions. The staff's original concerns have 4 largely been resolved and the remaining areas of 5 concern can be classified into slight variations from 6 how the applicant classified them.
7 We classified them into three areas such 8 as cycle counting issues, fatigue analysis, 9 disposition and environmental factors. The applicant 10 submitted the last two amendments related to metal 11 fatigue at the end of June and in August, to answer 12 these questions and staff has not fully completed its 13 review yet.
14 The issuance of the SER, and we'll cover 15 these in the issuance of the SER scheduled for 16 December of this year. If there are no questions on 17 Section 4, I can discuss the additional -- okay.
18 MEMBER ARMIJO: I have a question. Lisa, 19 you heard the discussion earlier related to Dr.
20 Bonaca's question on the, why the cumulative usage 21 factors for the instrument nozzles in Unit 1 were five 22 times greater than Units 2 and 3.
23 MS. REGNER: Uh-huh.
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141 1 for the three plants.
2 MS. REGNER: Uh-huh.
3 MEMBER ARMIJO: And I still don't 4 understand why it's okay to have this discrepancy, if 5 in fact the plants operate in the similar way, the 6 designs are similar or identical, and the materials 7 were identical. I wondered how the staff explains 8 this inconsistency?
9 MS. REGNER: We don't yet. We have that 10 in question. We're still evaluating, and Dr. Hiser, 11 do you want to talk to that?
12 DR. HISER: This is one of the items that 13 is still open, and we haven't completed our review of 14 what they've submitted. But from the discussion 15 earlier, my guess is they just use different 16 assumptions, and they have a sharper pencil.
17 MEMBER ARMIJO: Well, I heard in Unit 1, 18 the analyst treated vortex shedding, whereas in the 19 other two units, that wasn't considered. Well, if 20 it's a real mechanism of fatigue, it should have been 21 treated the same in all three units.
22 DR. HISER: We will do a detailed review 23 of that response, and if we need to follow up with 24 them.
25 MEMBER ARMIJO: Okay.
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142 1 MEMBER ABDEL-KHALIK: I have a more 2 general question. If you have three units, single 3 application, can you have different analyses of 4 record?
5 DR. HISER: They have three separate 6 licenses.
7 MEMBER ABDEL-KHALIK: But in this case, 8 it's a single application. I mean where do you allow 9 differences? The methodology is the same, but the 10 data used in the methodology is different, depending 11 on the unit, or do you allow completely different 12 methodologies, given the fact that they have a single 13 application?
14 MS. REGNER: It's a single license renewal 15 application. However, there are three separate 16 licenses for each unit.
17 DR. HISER: And I think in this case, 18 there's three separate licensing bases for this 19 calculation. So from a CLB perspective, they're all 20 equally valid.
21 Now since we're reviewing the license 22 renewal application, we want to -- it would be nice if 23 we, those three analyses could be brought together, so 24 that they -- you know, there really is one analysis.
25 That's partly what we will take a look at in our NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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143 1 review.
2 MEMBER ABDEL-KHALIK: Okay.
3 DR. HISER: The Unit 1 analysis really is 4 the more technically defensible one, and we will --
5 MEMBER ABDEL-KHALIK: But is the only case 6 where the analyses of record are dramatically 7 different?
8 DR. HISER: I'm not sure from other. I 9 know we have seen differences.
10 (Simultaneous discussion.)
11 MR. HOLIAN: This is a little unusual, 12 because the plants are so close together in age to 13 have a difference. So it makes the staff wonder, you 14 know, was there an issue on Unit 1 that needed, you 15 know, a different calculation and why would that be.
16 So that's the question we're asking. But 17 your general question, we see differences in plants, 18 licensing basis, especially if they're several years 19 apart for one reason or another.
20 That one plant, it had analysis done, you 21 know, at a different time frame, that would cause a 22 different set of assumptions to be made. It's a 23 little more unusual here on these three units.
24 MEMBER ABDEL-KHALIK: Okay.
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144 1 Section 4?
2 (No response.)
3 MS. REGNER: Okay. I'd like to cover the 4 two additional issues. They were discussed briefly 5 previously. The first involves inaccessible low 6 voltage power cables. The applicable GALL report 7 aging management program specifies medium voltage 8 cables, that if energized and subjected to significant 9 moisture, could be susceptible to failures.
10 This position was consistent with industry 11 operating experience identified up through 2005, the 12 2005 time frame, when Revision 1 to the GALL was 13 issued. Subsequent to Revision 1, Generic Letter 14 2007-1, which is inaccessible or underground power 15 cable failures that disable accident mitigation 16 systems or cause plant transience, requested licensee 17 to provide additional information on cable failures 18 over a wider range.
19 Licensees' responses to this generic 20 letter identified cable failure events at lower 21 voltages and, as a result, the staff determined that 22 lower voltage power cables should also be part of the 23 aging management program.
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145 1 currently under review, the staff is questioning those 2 plants on how they're going to address this operating 3 experience, and if they've had plant-specific 4 operating experience as well.
5 MEMBER STETKAR: We've --
6 MS. REGNER: I'm sorry?
7 MEMBER STETKAR: I'm trying to phrase a 8 question here.
9 MS. REGNER: Okay.
10 MEMBER STETKAR: When you say "plants 11 currently under review," right at the moment, we have 12 two other applicants that we've had our Subcommittee 13 meetings for the SER with open items.
14 MS. REGNER: They are included.
15 MEMBER STETKAR: The low voltage cables 16 are for those other applicants? So that has happened 17 between the time that we had those Subcommittee 18 meetings and today?
19 MS. REGNER: The staff is evaluating those 20 plans.
21 MEMBER STETKAR: You should expect for 22 those applicants --
23 MS. REGNER: You're talking Vermont Yankee 24 and --
25 MEMBER STETKAR: No. I'm talking about NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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146 1 Cooper. In fact, I'm talking about three. Cooper, 2 Kewaunee and Duane Arnold.
3 MR. PICK: Cooper already received the RAI 4 and responded.
5 MEMBER STETKAR: So when we hear the 6 presentation in a full committee meeting in October, a 7 month from now on Duane Arnold and Cooper, we'll hear 8 about low voltage cables?
9 MR. HOLIAN: Yes. That's the intent.
10 This is Brian Holian. They have things to send to 11 staff on a couple of issues on the new GALL, low 12 voltage cable, buried piping, small bore --
13 MEMBER STETKAR: The small bore and the 14 buried piping were what we saw. This is a new 15 wrinkle.
16 MR. HOLIAN: It is, it is, and we think 17 it's a relatively easy fix for the units to add in low 18 -- they're already doing medium voltage, their low and 19 medium voltage.
20 MEMBER STETKAR: Some units may have a 21 relatively large number of those 480 volt cables, 22 though.
23 MR. HOLIAN: Yes.
24 MEMBER STETKAR: So --
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147 1 GALL is picking it up. The industry has seen the new 2 GALL since January of this year. So I mean they -- at 3 least out in draft format. So in general, the 4 industry is accepting that. They realize a good aging 5 management program should include -- there's some 6 failures on low, so go ahead and include it.
7 They are arguing a little bit with maybe 8 my timing. Brian, do you need -- it may be causing me 9 some pain in my license renewal by adding it in now.
10 Our answer has been yeah. It's, we think it's the 11 right thing to do to get the SERs as current as 12 possible, you know, for issuing them now.
13 We expect -- this goes back to the initial 14 discussion, that were Cooper to go out and it not be 15 in there, we would expect their corrective action 16 program to pick it up. But --
17 MEMBER STETKAR: I was going to say, 18 that's the way you've got to handle all pre-approved -
19 -
20 MR. HOLIAN: Pre-approved, that's right, 21 and inspect them and look at that. And you know, I do 22 have Part 50 backfit, because the public's asking me 23 these same questions now on several plants that are 24 out there, and you know, if it's a significant safety 25 issue, can I go through my backfit process, to make NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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148 1 sure I get it in to previous plants earlier?
2 Yes, I have that available also. But if 3 it doesn't hit that threshold, I will be using a 4 corrective action process in my inspections to ensure 5 that their aging management programs keep abreast of 6 operating experience.
7 MEMBER ABDEL-KHALIK: How about the 7103 8 inspections that they have already completed?
9 MR. HOLIAN: Yes. Oh, they've already 10 been completed. Well, good. I can pick it up in a 11 maintenance rule inspection. I can pick it up in a 12 regular ROP corrective action inspection. So I have 13 the ability, and I'm talking with my ROP inspectors, 14 counterparts, to ensure that their sample size, that 15 the inspectors.
16 As you see here, the branch chief of 17 License Renewal is the branch chief for Fire 18 Protection. He's the branch chief that does 19 maintenance rule inspections. He can pick from a 20 sample size of any commitments on inspections from 21 here on out. That's how we approach that.
22 MS. REGNER: Any other questions on low 23 voltage, inaccessible low voltage power cables? The 24 second and final additional issue has to do with 25 buried piping and tanks inspection program, also NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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149 1 related to recent industry operating experience.
2 Staff is entrusted in efforts to 3 incorporate operating experience into plant programs.
4 Palo Verde has revised their AMP to include 15 5 excavated visual inspections of pipe. The applicant 6 has not yet addressed hazardous material piping 7 inspections or details on backfill.
8 So the staff still has unresolved 9 questions and plans to issue an RAI on this additional 10 issue.
11 MEMBER RYAN: I think in some discussions 12 at a break, I also heard they have some information 13 about radiological constituents. So I guess I look 14 forward to them doing that.
15 MS. REGNER: You're not talking -- you 16 want the applicant to provide additional information.
17 MEMBER RYAN: Yes.
18 MS. REGNER: Okay. Should I conclude 19 mine, my presentation, or do you want to go ahead and 20 let them speak on this topic?
21 MEMBER RYAN: No. They'll have to provide 22 some documents.
23 MR. HOLIAN: It's outside this meeting, 24 yes.
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150 1 were saying you wanted them to speak now.
2 MEMBER RYAN: No. Thank you.
3 MS. REGNER: Okay, uh-huh. Any other 4 questions on buried piping and tanks? Okay. You'll 5 note that the staff normally presents slide on reactor 6 vessel neutron embrittlement and groundwater 7 chemistry.
8 Neither of these issues was of concern to 9 the staff, since groundwater levels in the Sonoran 10 Desert, where Palo Verde is located, are 20 feet below 11 the level of building foundations and dropping.
12 Also, there's significant margin in the 13 reactor vessel neutron embrittlement analyses.
14 However, I can show you that slide if you do want to 15 see the margin. I'd be happy to do that.
16 MEMBER ARMIJO: Sure, I'd like to see it.
17 MS. REGNER: Okay.
18 MEMBER ARMIJO: I always like margin.
19 MS. REGNER: All right, right. Slide 25 20 please. Okay. So here, Section 4.2 of the SER covers 21 reactor vessel neutron embrittlement analyses. There 22 were three reviews performed to evaluate neutron 23 embrittlement, as documented in the SER. Neutron 24 effluents and adjusted reference temperature, upper 25 shelf energy and pressure temperature limits. Yes, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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151 1 pressure temperature limits review, and the staff 2 concludes that neutron embrittlement analyses exceed 3 the review criteria as specified in the standard 4 review plan for license renewal, and in accordance 5 with the rules. Staff has no concerns, as stated.
6 Any questions?
7 MEMBER SHACK: Well, since we brought up 8 the vessel; I was going to let it go. I was just 9 curious. You're going to make them withdraw the 10 remaining capsules at an exposure not exceeding 72 11 effective full power years, as expected, for a 12 possible 80 year second period of extension.
13 Why don't you let them exceed it, just in 14 case they want to go to 100 years? Because I was 15 worried about that.
16 MS. REGNER: Simon? Mr. Sheng. Do you 17 need the question repeated?
18 MR. SHENG: I think I understand the 19 question.
20 MEMBER SHACK: My question is just how 21 you're going to sort of look at surveillance capsule 22 withdrawals, as people look forward to extended life 23 beyond 60, I guess, is really a general question. But 24 --
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152 1 think we allowed them to put from their withdrawal, 2 you know, in accordance with GALL requirements, and 3 the reason is that because now we take a look at all 4 the PW RPVs, and though -- oh sorry, sorry.
5 This is Simon Sheng from the Department of 6 Component Integrity, and nowadays we surveyed a lot of 7 RPVs, and we found out a lot of capsules has been 8 withdrawn at a certain fluents level. They are not 9 very uniform. So for -- according to current 10 assessment, that the some, some capsules has been 11 withdrawn at a certain fluents level, with certain 12 embrittlement, and some in other points is integrated 13 together.
14 So now that the -- I don't know whether 15 it's because of NRC encouragement or it's because of 16 the industry's initiative. A lot of plants are now 17 participating in the industry's integrated 18 surveillance program, and they try to basically have 19 a balanced situation, so that we have information at 20 kind of an evenly distributed embrittlement, so we can 21 get information.
22 MEMBER SHACK: I just sort of wonder 23 whether current regulations are interfering with that 24 ability to do that, is sort of my concern.
25 MR. SHENG: That's right. The current is.
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153 1 However, we are revising the GALL and try to reflect 2 on that philosophy. Thank you.
3 MEMBER SHACK: Okay.
4 DR. HISER: I think, Dr. Shack, that for 5 60 years, if there's a limit of 72, if they want to go 6 to higher fluents, or if they're more out in the 7 years, say if they're 100 years, they can always 8 reinsert the capsules and bump up fluents.
9 MEMBER SHACK: Not if they've -- oh.
10 DR. HISER: Presumably they're not --
11 well, it just says "withdraw the capsule."
12 MEMBER SHACK: Yes.
13 DR. HISER: Well withdraw, but not 14 necessarily capped. So if they withdraw it and if 15 they can reinsert it. The other thing that it gains 16 the advantage of is some of the exposure then is using 17 the fuel management that's in place at that point in 18 time. So it's not all, you know, the first 20 years' 19 worth of fuel management operations.
20 MR. MEDOFF: May I make a clarification?
21 This is Jim Medoff of the Division of License Renewal, 22 but I used to do pressure temperature limits and 23 neutron embrittlement assessments for the Division of 24 Component Integrity, including Appendix H surveillance 25 capsules scheduled review.
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154 1 If you'll look at the requirement for the 2 final capsules pulls in those reviews, they're 3 required to pull them at fluents that's been one and 4 two times the projected end of life, 40 year life 5 fluents for the plant. So depending on when they pull 6 them, they may cover the fluents at 60 years or even 7 80 years. That's one thing.
8 So it may already be accounted for in the 9 capsule schedule. The other thing, as Al said, in the 10 all -- in Rev 1 of the GALL, we had provisions that 11 even if they had pulled some capsules that for license 12 renewal they were supposed to put those capsules in 13 storage and there's a license condition that we've 14 been imposing on the applications.
15 So if they need to cover that fluents of 16 your concern, they have the ability to reconstitute 17 the capsules and reinsert them so they can pull them 18 out, and then do an amendment of their capsule 19 schedule. So I think that should address your 20 concern.
21 MS. REGNER: Thank you. Other questions 22 on neutron embrittlement? Okay. Back to Slide 22, 23 okay.
24 CHAIRMAN BONACA: Any questions?
25 (No response.)
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155 1 MS. REGNER: And the staff's conclusions 2 will be presented in the SER in December, scheduled 3 for December.
4 CHAIRMAN BONACA: Thank you for a very, 5 very informed presentation, and we're going to go 6 around the table now and see if there are any points 7 that the members want to make. Bill? Mike?
8 MEMBER RYAN: No. No additional comments, 9 Mr. Chairman. Thank you.
10 MEMBER STETKAR: Nothing additional. I'd 11 like to thank both the applicant and staff. I thought 12 you came very, very well prepared.
13 CHAIRMAN BONACA: Sam?
14 MEMBER ARMIJO: Yes. I echo what Mark 15 said. Very good presentations, well-prepared, covered 16 everything. The only thing remaining is the 17 resolution of the open item.
18 CHAIRMAN BONACA: Said?
19 MEMBER ABDEL-KHALIK: I have no additional 20 questions.
21 CHAIRMAN BONACA: Okay, John?
22 MR. BARTON: Good job by all. Of course, 23 the open item on the wheelbarrow full of RAIs on 24 fatigue --
25 (Simultaneous discussion.)
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156 1 MR. BARTON: And I just want to say one 2 thing. The socket welds, you know, you talked about 3 it before with Brian, and I think that's something 4 we've got to come to grips with, because we've been 5 all over the field with it. Now we come in with ten 6 percent, so I think somewhere we've got to -- because 7 this comes up every, every time.
8 So I think in some way we've got to come 9 to closure on that one.
10 MEMBER SHACK: But actually I think this 11 is historic. I mean when we started license renewal, 12 small bore piping wasn't one inch socket welds. It 13 was --
14 MR. BARTON: Yes, right.
15 MEMBER SHACK: So that we resolved that 16 one as we went along, and now we've -- I mean it just 17 keeps getting better as far as I'm concerned.
18 MR. HOLIAN: It keeps getting better, and 19 we'll take more where they proffer more. But I 20 understand that comment, and we're working on 21 consistency in GALL. Thank you. Thank you, 22 Committee.
23 MR. BARTON: That's all I have.
24 CHAIRMAN BONACA: Okay. I agree with the 25 comments being made. I think it was a good NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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157 1 application, practical questions on that issue of 2 fatigue.
3 MEMBER STETKAR: Is there -- this is a 4 leading question, but in terms of our planning our 5 activities, is there reasonable confidence that that 6 open item will be resolved, and if scheduled for a 7 full committee meeting in December that we won't need 8 another short perhaps, but focused Subcommittee 9 meeting to --
10 MS. REGNER: The correct answer is yes.
11 MEMBER STETKAR: Okay.
12 CHAIRMAN BONACA: Yes what?
13 MS. REGNER: The answer is yes.
14 MEMBER STETKAR: There's good confidence 15 that we will not need a --
16 CHAIRMAN BONACA: We will not. Be 17 thankful. I would like to conclude on that base, on 18 the feedback I got from the members. We do not need 19 any letter to the full committee. Well thank you 20 everybody, and is there any other questions from the 21 public?
22 (No response.)
23 CHAIRMAN BONACA: If none, the meeting is 24 adjourned.
25 (Whereupon, at 4:52 p.m., the meeting was NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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158 1 adjourned.)
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Palo Verde Nuclear Generating Station ACRS License Renewal Subcommittee Meeting September 8, 2010 1
John Hesser Vice President Nuclear Engineering 2
Palo Verde Nuclear Generating Station Personnel In Attendance
- Bob Bement - Vice President, Nuclear Operations
- Mohammad Karbassian - Director, Nuclear Engineering
- Angie Krainik - Department Leader, License Renewal
- Eric Blocher - Project Manager, STARS
- Glenn Michael - Licensing Engineer
- Rich Schaller - Metal Fatigue Lead SAFELY and efficiently generate electricity for the long term 3
Palo Verde Nuclear Generating Station Personnel In Attendance (continued)
Metal Fatigue / TLAA Operations
- Mark Radspinner
- Doug Coxon
- Rex Meeden Electrical
- Gene Montgomery
- Mark Hypse
- Winston Borrero
- Doug Berg Probabilistic Risk Assessment
- Curt Carney
- Zouhair Elawar
- Dave Gerber Environmental /
Civil / Structural Radiation Protection
- Ken Schrecker
- Tom Gray
- Chris Wandell
- Harvey Lesan Engineering Programs Support
- Doug Steinsiek
- Ron Barnes
- Doug Hansen
- Mike Green
- Mark Fallon Buried Piping
- Shabbir Pittalwala STARS
- Tony Harris
- Chalmer Myer SAFELY and efficiently generate electricity for the long term 4
Agenda
- Plant History and Background
- Major Improvements and Long-Range Planning
- Safety Evaluation Report Open and Confirmatory Items
- Regional Inspection Items
- Concluding Remarks SAFELY and efficiently generate electricity for the long term 5
Our Mission SAFELY and efficiently generate electricity for the long term.
6
Plant History and Background
- Initial Construction Permit May 1976
- Operating Licenses for:
- Unit 1: June 1, 1985
- Unit 2: April 24, 1986
- Unit 3: November 25, 1987
- 3990 MWt / 1390 MWe per Unit
- Reclaimed Wastewater Utilized for Condenser Cooling No Lake, Ocean or River Available
- Essential Spray Ponds are Dedicated Ultimate Heat Sink SAFELY and efficiently generate electricity for the long term 7
Station Description
- Three Common-Design Units
- Common Operating Procedures
- Maintain Common Design
- Combustion Engineering System 80 Nuclear Steam Supply System
- General Electric Turbine Generator
- Bechtel Power Corporation Architect and General Contractor
- Water Reclamation Facility
- Zero Liquid Discharge Plant SAFELY and efficiently generate electricity for the long term 8
Approximately 26 miles from the Phoenix Metro Area, in the Sonoran Desert 9
Palo Verde Owners Salt River Project (17.49%)
Arizona Public Service Palo Verde Operator (29.1%)
Southern California Edison (15.8%)
Los Angeles Department of Water & Power (5.7%)
Southern California Public Power Authority (5.91%) El Paso Electric (15.8%)
Public Service Company of New Mexico (10.2%)
SAFELY and efficiently generate electricity for the long term 10
W S N E
Evaporation Pond #3 180 Acres Evaporation Pond #1 250 Acres 3
2 Spray Ponds 1
Evaporation Pond #2 220 Acres Water Reclamation Facility Reservoirs 11
License Renewal Unit 1 Unit 2 16th Operating Cycle 16th Operating Cycle Unit 3 15th Operating Cycle SAFELY and efficiently generate electricity for the long term 12
Mohammad Karbassian Director Nuclear Engineering 13
Major Improvements
- Steam Generator Replacement
- Power Uprate (5% total)
- Low Pressure Turbine Rotor Replacement
- Digital Feedwater Control System
- Core Protection Calculator (CPC)
Replacements
- Reactor Vessel Head Replacement
- Unit 3 in Fall 2010
- Alloy 600 Replacement / Dissimilar Metal Weld Management
- Evaporation Ponds, Reservoirs SAFELY and efficiently generate electricity for the long term 14
Equipment Reliability
- Site Top 10 Process
- Completed
- Auxiliary Feedwater Pump Steam Admission Bypass Valve Replacement
- Control Room Chart Recorders
- Planned
- Essential Spray Pond Chemical Addition
- Charging Pump Reliability
- MSIV/FWIV Accumulator Margin
- Essential Spray Pond Repairs SAFELY and efficiently generate electricity for the long term 15
Long-Range Planning
- Main Generator Stator and Rotor Rewinds
- High Pressure Turbine Upgrades
- Cooling Tower Life Cycle Management
- Transformer Refurbishment / Replacement
- Large Motor Refurbishment / Replacement
- Polar Crane Modifications SAFELY and efficiently generate electricity for the long term 16
Angie Krainik Department Leader License Renewal 17
License Renewal Application STARS Center of Business
- Strategic Teaming and Resource Sharing (STARS) Alliance Center of Business
- Seven large PWR stations in Region IV
- Center of Business created to prepare License Renewal Applications for the member utilities
- Involved with Generic Aging Lessons-Learned Report (GALL) Updates (Rev 0, Rev 1 and Rev 2)
- Leadership, Oversight and Ownership by Palo Verde Personnel Throughout the Development and Review Phases, Continuing Through Implementation SAFELY and efficiently generate electricity for the long term 18
License Renewal Application Development
- Scoping and Screening
- Consistent with 10 CFR Part 54 and NEI 95-10
- Utilized site component design databases, controlled drawings, design and licensing documents
- In-scope structures, systems and components screened to determine if Aging Management Review required
- Aging Management Review
- Consistent with 10 CFR Part 54 and NEI 95-10
- Utilized GALL Report (Revision 1) and other industry reports
- Incorporated Operating Experience
- Plant-specific (13+ years)
- Industry (NRC Generic Communications)
- Results are greater than 94% consistent with GALL Report SAFELY and efficiently generate electricity for the long term 19
Time-Limited Aging Analyses (TLAAs)
- Reactor Vessel Neutron Embrittlement
- Metal Fatigue Analysis
- Environmental Qualification
- Concrete Containment Tendon Pre-stress
- Containment Liner Plate and Penetrations
- Plant-specific TLAAs
- Cranes, Lifts and Fuel Handling Equipment
- Corrosion Allowance - Pressurizer Nozzle Repairs
- Building Settlement SAFELY and efficiently generate electricity for the long term 20
License Renewal Program Status
- Aging Management Programs
- 29 existing
- 11 new
- 65 Procedures Required to Implement Aging Management Programs
- 59 existing procedures
- 45 currently revised
- 12 revisions in progress
- 2 revisions yet to start
- 6 new procedures
- 3 complete
- 3 in final review SAFELY and efficiently generate electricity for the long term 21
License Renewal Commitments
- Tracked in Palo Verde Regulatory Commitment Tracking System (RCTS)
- Tracked Commitments Include:
- Current ongoing programs and procedures credited for License Renewal implementation
- Future actions to be completed prior to and during the period of extended operation
- RCTS and Procedural Controls
- Ensures changes to Implementing Procedures and Programs are reviewed for License Renewal impact SAFELY and efficiently generate electricity for the long term 22
Implementation and Sustainability
- Implementation Staff
- Participating in NEI License Renewal Implementation Working Group
- Benchmarking Others in the Industry
- Lessons-learned captured
- Leveraging STARS Alliance Knowledge and Experience
- Self-assessments
- Audits
- Share Operating Experience SAFELY and efficiently generate electricity for the long term 23
Safety Evaluation Report Open Item
- Metal Fatigue
- The staff requires further information to reach a conclusion on the proposed metal fatigue analysis as discussed in detail in SER Section 4.3.
- Clarification of Metal Fatigue Analysis
- Common terminology with Current Licensing Basis and Updated Final Safety Analysis Report transients
- Transient cycle count updates
- Details of fatigue analysis
- Metal Fatigue Aging Management Program is an Extension of the Existing Fatigue Monitoring Program SAFELY and efficiently generate electricity for the long term 24
Rich Schaller Metal Fatigue Lead 25
Metal Fatigue Topics
- Current and Enhanced Metal Fatigue Program Attributes
- Commitments
- Program enhancements (Commitment 39)
- RAI response related (Commitments 57 and 58)
- SER Open Item 4.3-1
- Status of responses
- Palo Verdes grouping of request for additional information (RAI) responses SAFELY and efficiently generate electricity for the long term 26
Program Enhancements Commitment 39 ATTRIBUTE CURRENT PROGRAM ENHANCED PROGRAM UFSAR 3.9.1 Transient Cycle Counting (CC) No Change Counting Pressurizer Spray Nozzle Cycle-based Fatigue (CBF)
Cumulative Usage Factor No Change Partial Cycle (CUF) Calculation Class 2 and 3 Components with Class 1 Fatigue CC No Change Analysis Monitoring 90% of Design Cycles Specific to Design Cycles Action Limits and 0.65 CUF for and Component CUF Pressurizer Spray Nozzle Corrective Actions Evaluation (CAP) Predetermined (CAP)
NUREG/CR-6260 Location CC, CBF and Not Required CUF Monitoring Stress Based Fatigue Fatigue Monitoring NO YES Software SAFELY and efficiently generate electricity for the long term 27
Metal Fatigue Commitments
- Commitment 39
- Implement enhancements to Metal Fatigue of Reactor Coolant Pressure Boundary Program
- Commitment 57 and 58
- Confirm conservatism of nickel alloy environmental factor using NUREG/CR-6909 methods and use appropriate value to evaluate pressurizer heater penetration weld environmental fatigue usage SAFELY and efficiently generate electricity for the long term 28
Metal Fatigue Requests for Additional Information (RAIs)
- Responses to the 18 RAIs on Metal Fatigue Were Provided in Correspondence
- June 29, 2010 and August 12, 2010
- Palo Verde Grouped RAIs into Three Categories:
- Clarification
- Additional technical information
- Alternate approach
- Palo Verde Has Provided Information Requested SAFELY and efficiently generate electricity for the long term 29
Angie Krainik Department Leader License Renewal 30
Safety Evaluation Report Confirmatory Items / Submittal Dates
- Application of the Scoping Criteria
- Spray Chemical Addition Tank Draining / August 27, 2010
- Flow-Accelerated Corrosion Program
- Cavitation in Carbon Steel Piping / September 3, 2010
- Small Bore Socket Weld Inspections / September 3, 2010
- Wall Thinning Due to Flow-Accelerated Corrosion
- Steam Generator Feedring Material / July 30, 2010
- Elastomeric Components in Auxiliary Systems / July 30, 2010 SAFELY and efficiently generate electricity for the long term 31
Regional Inspection Unresolved Items
- Unresolved Items Closed NRC Inspection Report Number 2010010, Dated 8/5/2010
- Impact of Recent Operating Experience on Metal-Enclosed Bus Program (2010007-01)
- Structures Monitoring Frequency and Scope (2010007-02)
SAFELY and efficiently generate electricity for the long term 32
John Hesser Vice President Nuclear Engineering 33
License Renewal 2046 2045 2047 2026 2025 2027 Unit 1 Unit 2 Unit 3 SAFELY and efficiently generate electricity for the long term 34
Our Mission SAFELY and efficiently generate electricity for the long term.
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Advisory Committee on Reactor Safeguards License Renewal Subcommittee Palo Verde Nuclear Generating Station Safety Evaluation Report with Open Item September 8, 2010 Lisa Regner, Project Manager Office of Nuclear Reactor Regulation
Introduction
- Overview
- Section 2: Scoping and Screening Review
- License Renewal Inspections
- Section 3: Aging Management Program and Review Results
- Section 4: Time-Limited Aging Analyses (TLAAs) 2
Overview
- LRA Submitted by letter dated December 11, 2008, as supplemented on April 14, 2009
- Power Uprates - 5 percent from original licensed thermal power
- Operating licenses expire:
- Unit 1: June 1, 2025
- Unit 2: April 24, 2026
- Unit 3: November 25, 2027
- Located about 26 miles west of Phoenix, AZ 3
Overview
- Scoping and Screening Methodology Audit
- October 19 - 23, 2009
- Aging Management Programs (AMP) Audit
- December 7 - 11, 2009
- Regional License Renewal Inspections
- February 1 - 5, 2010
- February 22 - 26, 2010 4
Overview Safety Evaluation Report with Open Items was issued August 6, 2010
- 1 Open Item
- 5 Confirmatory Items
- 2 Additional Items 5
Section 2: Structures and Components Subject to Aging Management Review Section 2.1 - Scoping and Screening Methodology Section 2.2 - Plant-Level Scoping Results Section 2.3 - Scoping and Screening Results:
Mechanical Systems Section 2.4 - Scoping and Screening Results:
Structures Section 2.5 - Scoping and Screening Results:
Electrical and Instrumentation & Control Systems 6
Section 2: Structures and Components Subject to Aging Management Review Confirmatory Item
- Containment Spray Chemical Addition Tanks
- Piping cut, capped and abandoned in place
- Not verified dry, found to contain liquid hydrazine
- Applicant committed to drain by August 30
- Modified the commitment to drain by November 30 7
Section 2: Structures and Components Subject to Aging Management Review Staff concludes that, pending resolution of the confirmatory item, the applicant has appropriately identified the systems, structures, and components in accordance with 10 CFR 54.4(a), and those subject to an AMR in accordance with 10 CFR.54.21(a)(1).
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License Renewal Inspections Greg Pick Region IV Inspection Team Leader
Regional Inspections Overview
- Five Inspectors for 2 weeks
- Scoping & Screening Inspection
- Aging Management Programs Inspection
- Follow-up In-office Inspection 10
Regional Inspections Inspection Results
- Scoping of nonsafety-related systems
- Aging Management Programs
- Structural Monitoring 11
Regional Inspections Plant Performance
- Licensee Response Column
- Good material condition 12
Regional Inspections Inspection Conclusions
- Reasonable assurance exists that aging effects will be managed and intended functions maintained.
- Applicant established a schedule for structural inspections to provide data for comparison prior to entering the PEO.
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Section 3: Aging Management Review Results
- Section 3.0 - Aging Management Programs
- Section 3.1 - Reactor Vessel & Internals
- Section 3.2 - Engineered Safety Features
- Section 3.3 - Auxiliary Systems
- Section 3.4 - Steam and Power Conversion System
- Section 3.5 - Containments, Structures and Component Supports
- Section 3.6 - Electrical and Instrumentation and Controls System 14
Section 3: Aging Management Review Results Section 3.0.3 - 40 AMPs Evaluated With With With Plant Consistent exception &
Specific with GALL Exception Enhancement enhancement Existing 1 9 5 10 4 29 New 0 7 4 0 0 11 15
Section 3: Aging Management Review Results Confirmatory Items
- Cavitation Erosion
- Small Bore Piping Socket Welds
- Aging Management of PVC Piping and Elastomer-Lined Piping 16
Section 4: Time-Limited Aging Analysis
- 4.1 Introduction
- 4.2 Reactor Vessel Neutron Embrittlement
- 4.3 Metal Fatigue Analysis
- 4.4 Environmental Qualification of Electrical Equipment
- 4.5 Concrete Containment Tendon Prestress Analysis
- 4.6 Containment Liner Plate, Equipment Hatch and Personnel Air Locks, Penetrations, and Polar Crane Brackets
- 4.7 Other Plant-Specific TLAA 17
Section 4: Time-Limited Aging Analysis Metal Fatigue Review
- Original LRA Incomplete
- Numerous Follow-up Discussions
- Public Meeting, May 6, 2010
- 7 LRA Amendments 18
Section 4: Time-Limited Aging Analysis Metal Fatigue TLAA Open Item
- Cycle Counting Issues
- Fatigue Analyses Disposition
- Environmental Factors 19
Additional Issue Inaccessible Low Voltage Power Cables (Non-EQ)
- GL 2007-01 indicated low-voltage cables have aging-related failures (480V - 2KV)
- Staff concern that inaccessible low-voltage cables need to be part of an AMP
- Staff plans to issue RAI to the applicant 20
Additional Issue Buried Piping and Tanks Inspection Program
- Given recent industry OE related to leaks from buried and underground piping, staff is interested in efforts to incorporate OE into AMPs
- Staff issued an RAI, applicant responded
- Applicant revised AMP for visual inspections
- Staff plans to issue follow-up RAI for details 21
Conclusions The staffs conclusion regarding the LRA for PVNGS will be provided in the SER scheduled to be issued in December of 2010.
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