ML14168A171
| ML14168A171 | |
| Person / Time | |
|---|---|
| Site: | Callaway  |
| Issue date: | 05/22/2014 |
| From: | Kent Howard Advisory Committee on Reactor Safeguards |
| To: | |
| Howard K | |
| References | |
| NRC-802 | |
| Download: ML14168A171 (208) | |
Text
Official Transcript of Proceedings NUCLEAR REGULATORY COMMISSION Title: Advisory Committee on Reactor Safeguards Plant License Renewal Subcommittee Callaway Plant, Unit 1 Docket Number: (n/a)
Location: Rockville, Maryland Date: Thursday, May 22, 2014 Work Order No.: NRC-802 Pages 1-208 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 UNITED STATES OF AMERICA 2 NUCLEAR REGULATORY COMMISSION 3 + + + + +
4 ADVISORY COMMITTEE ON REACTOR SAFEGUARDS 5 (ACRS) 6 + + + + +
7 PLANT LICENSE RENEWAL SUBCOMMITTEE 8 + + + + +
9 CALLAWAY PLANT, UNIT 1 10 + + + + +
11 THURSDAY 12 MAY 22, 2014 13 + + + + +
14 ROCKVILLE, MARYLAND 15 + + + + +
16 The Subcommittee met at the Nuclear 17 Regulatory Commission, Two White Flint North, Room 18 T2B1, 11545 Rockville Pike, at 1:30 p.m., Gordon 19 Skillman, Chairman, presiding.
20 COMMITTEE MEMBERS:
21 GORDON SKILLMAN, Chairman 22 RONALD BALLINGER, Member 23 STEPHEN P. SCHULTZ, Member 24 JOHN W. STETKAR, Member 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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2 1 ACRS CONSULTANT:
2 JOHN J. BARTON 3 DESIGNATED FEDERAL OFFICIAL:
4 KENT HOWARD 5
6 7
8 9
10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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3 1 T-A-B-L-E O-F C-O-N-T-E-N-T-S 2 Opening Remarks by Chairman Skillman...............4 3 Callaway Plant, Unit 1, License Renewal 4 Opening Remarks by John Lubinski.............5 5 Plant History and Background 6 by Dave Neterer..............................8 7 Major Modifications and Near Term 8 Plant Improvements by Roger Wink............16 9 License Renewal Application and Safety 10 Evaluation Report Open Items 11 by Sarah Kovaleski and Mike Hoehn...........30 12 Concluding Remarks..........................93 13 NRC Staff Presentation 14 Introduction by John Lubinski...............97 15 Onsite Inspection Results by Greg Pick.....102 16 Scoping and Screening Review 17 by John Daily..............................110 18 Aging Management Review by John Daily......117 19 Subcommittee Discussion..........................148 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 P-R-O-C-E-E-D-I-N-G-S 2 (1:27 p.m.)
3 CHAIRMAN SKILLMAN: This meeting will now 4 come to order. Good afternoon. I'm Gordon Skillman, 5 Chairman of the Plant License Renewal Subcommittee.
6 The subcommittee will review the license renewal 7 application for the Callaway Plant, Unit 1.
8 ACRS members in attendance are John 9 Stetkar, Ron Ballinger and Steve Schultz. Our ACRS 10 consultant, John Barton, is also in attendance. Kent 11 Howard of the ACRS staff is the designated federal 12 official for this meeting.
13 This afternoon we will hear presentations 14 from the Division of License Renewal and Ameren Missouri 15 regarding this matter. This subcommittee will gather 16 information, analyze relevant issues and facts and 17 formulate proposed positions and actions as appropriate 18 for deliberation by the committee.
19 The rules for participation in today's 20 meeting have been announced as part of the notice of this 21 meeting previously published in the Federal Register.
22 We have not received written comments or 23 requests for time to make oral statements for members 24 of the public regarding today's meeting. This entire 25 meeting will be open to public attendance.
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5 1 There will be a phone bridge line and to 2 preclude interruption of the meeting the phone will be 3 placed in a listen-in mode during the presentations and 4 committee discussion.
5 A transcript of this meeting is being kept 6 and will be made available as stated in the Federal 7 Register notice, therefore I request that participants 8 in this meeting use the microphones located throughout 9 the meeting room when addressing the subcommittee.
10 Participants are requested to please 11 identify themselves and speak with sufficient clarity 12 and volume so that they can be readily heard.
13 I request that attendees please silence 14 your electronic devices for the duration of the meeting.
15 We will now proceed and I call upon John 16 Lubinski to begin the presentation. John.
17 MR. LUBINSKI: Thank you, Chairman 18 Skillman, and welcome. Thank you, members of the ACRS.
19 I appreciate the opportunity to be here today.
20 With me I have Yoira Diaz sitting at the 21 table with me today as well as other members of the 22 Division of License Renewal, our management team, 23 technical staff project management team who are here to 24 support our presentations and answer questions.
25 As I said during our informational briefing NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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6 1 this morning, our last meeting with the ACRS was a full 2 committee meeting in February of 2013. We're looking 3 forward to a very productive discussion today about the 4 Safety Evaluation Report that was issued with open items 5 for Callaway Plant, Unit 1.
6 The staff issued the Safety Evaluation 7 Report with open items in April of 2013 and we had five 8 open items at that time. The reason we issued the 9 Safety Evaluation Report at that time is we were 10 scheduled at that time to have this meeting, the ACRS 11 Subcommittee Meeting, in May of 2013.
12 After we issued the Safety Evaluation 13 Report, Callaway had requested a postponement of the 14 meeting to deal with issues that they have from an 15 operational standpoint at the plant and requested 16 delaying the meeting.
17 We continued to work issuing RAIs and 18 getting responses with Callaway to address those 19 technical issues as we've continued to move forward 20 towards today's meeting.
21 We believe at this point we have 22 information from Callaway that they believe adequately 23 addresses all of the issues that they had as far as open 24 items and we're in the process of reviewing those 25 responses.
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7 1 We expect prior to coming back for a full 2 committee meeting that we will address all of those 3 satisfactorily and if not we'll get more information 4 from Callaway to do so before coming back for a full 5 committee meeting.
6 The five open items that are summarized in 7 the SER with open items will be presented today. They 8 have to do with the scope of the fire protection SSCs, 9 the reactor head closure studs, the pressure vessel 10 internals program, ASME code requirements for 11 small-bore socket welds and then environmentally 12 assisted fatigue on the reactor coolant pressure 13 boundary.
14 A few other issues also arose after issuing 15 the SER with open items as part of the review. We 16 outlined these additional items in addition to the first 17 five in a letter we issued to the ACRS on May 12th of 18 this year.
19 The staff is prepared to discuss these and 20 any other areas that the ACRS has questions or would like 21 to explore this afternoon.
22 What we'd like to do is start with having 23 Callaway have their presentation. So what I'd like to 24 do is turn it over to the site vice president, David 25 Neterer, so he can introduce his team and start the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 1 presentation.
2 MR. NETERER: Thank you. My name is Dave 3 Neterer. I'm the site vice president, Callaway Plant.
4 We really appreciate the opportunity to be here to talk 5 with you today on our license renewal application.
6 It's been a long journey. This is just one milestone 7 in the journey to extend the plant life.
8 I'd like to introduce our main team, front 9 team today, have them introduce themselves. Sarah.
10 MS. KOVALESKI: My name is Sarah 11 Kovaleski. I'm the director of design engineering.
12 MR. WINK: Roger Wink, supervising 13 engineer of our license renewal project.
14 MR. BLOCHER: Eric Blocher, STARS license 15 renewal.
16 MR. HOEHN: Mike Hoehn, supervising 17 engineer, engineering program within Ameren.
18 MR. BURGESS: And I'm Andrew Burgess, 19 license renewal project engineer.
20 MR. NETERER: Okay, with us today we have 21 many subject matter experts. I'd like our team to stand 22 up so those in the room can see who our team consists 23 of. So these are our subject matter experts that will 24 help us with this discussion today. Thanks, you guys.
25 MR. BARTON: Anybody left behind at the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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9 1 site?
2 (Laughter) 3 MR. NETERER: We have three times as many 4 at the site waiting on us.
5 MR. BARTON: You had me nervous there for 6 a minute.
7 MEMBER STETKAR: It's on auto.
8 MALE PARTICIPANT: Okay, go ahead.
9 MR. NETERER: So we're going to go through 10 today a little bit on plant history and background.
11 Roger Wink will talk about major modifications and Sarah 12 Kovaleski will talk about the license renewal 13 application and safety evaluation open items. Then 14 we'll have a few closing comments from our end.
15 The Callaway Plant received our initial 16 construction permit in April 1976, we received our 17 operating license in October 1984 and we went online, 18 commercial in December 1984.
19 We're licensed to 3,565 megawatts thermal.
20 Our rated output is 3,579 and the difference there is 21 reactor coolant pump thermal heat. We start our 20th 22 refueling in October this year.
23 We sit on about a 7,000-acre plateau. It's 24 about 300 feet above the Missouri River. We're a single 25 Westinghouse 4-loop PWR. We were part of the original NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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10 1 SNUPPS project back in the '70s, you know, late '60s, 2 early '70s.
3 We were going to be a two-unit site. Unit 4 2 was canceled in 1981 as a result of economic conditions 5 and Three Mile Island outfall and only two plants were 6 built, us and Wolf Creek in Kansas, so we're sister 7 plants.
8 We're the only two SNUPPS plants with the 9 exception of over in England one plant was built that's 10 similar to SNUPPS but they have four trains of 11 protection instead of two. Go ahead.
12 So give you an idea how we sit. You can see 13 the power block there right in the center of the photo.
14 In the lower right quadrant is our ultimate heat sink 15 pond. That's the pond that supports 30-day safe 16 shutdown.
17 In the foreground on the lower right 18 quadrant is our switchyard. We generated 25,000 volts.
19 We transmitted 345 volts. And we own and operate and 20 maintain the switchyard with our Ameren people and 21 procedures.
22 MR. BARTON: That's not the plant people?
23 This is your T&D people?
24 MR. NETERER: We, Ameren, maintain 25 everything in the switchyard with the exception of NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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11 1 relays. Relay services from St. Louis corporate 2 maintains that using our procedures and some 3 transformer work is done by our transformer group out 4 of our corporate in St. Louis using our procedures.
5 MR. BARTON: What role does the plant play 6 when they do maintenance in the switchyard? Does the 7 plant know what's going on? Does the plant have to 8 approve it, --
9 MR. NETERER: Yes, yes.
10 MR. BARTON: -- let people into the 11 switchyard or can those people just come in and start 12 working?
13 MR. NETERER: No, we have very strict 14 switchyard access controls. A senior reactor operator 15 has to allow permission and do a face-to-face brief 16 before any work is allowed.
17 Also operations does a walkdown of the work 18 area and, you know, make sure they have no vehicles, 19 nothing in the switchyard they don't need to have in 20 there.
21 They do work to our procedures under our 22 oversight and I'll give you an example. The relay work, 23 our planners plan that work and our electrical 24 department oversees that work.
25 MR. BARTON: Okay, thank you.
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12 1 MR. NETERER: You're welcome.
2 CHAIRMAN SKILLMAN: Dave, a follow on to 3 John's question. What role does your QA program and 4 specifically your corrective action program have for 5 activities in the switchyard?
6 MR. NETERER: That falls entirely under 7 our QA and corrective action program. We call them 8 CARs. Most plants call them CRs. Any activity that 9 does not meet standards or conditions goes in our 10 corrective action program in switchyard. It's 11 entirely under the CAR system, corrective action 12 program.
13 CHAIRMAN SKILLMAN: So for the transient 14 workers that come in from corporate to work on relays 15 and other gear, how do they know how to utilize your 16 corrective action program?
17 MR. NETERER: They are under direct 18 supervision of people that are qualified to use our 19 corrective action program. The relay services 20 supervisors have access and are qualified to use our 21 corrective action program.
22 CHAIRMAN SKILLMAN: Do they do it?
23 MR. NETERER: And they're trained. All 24 workers are trained, the general employee training, 10 25 CFR 50 Appendix B training, corrective action program.
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13 1 All employees that enter the plant are trained on that 2 also.
3 CHAIRMAN SKILLMAN: Do they do it?
4 MR. NETERER: Oh yes, sir. They may not do 5 it themselves, put their hands to the keyboard to put 6 in the document, but they report to a supervisor and 7 generally a supervisor will put that in the program.
8 CHAIRMAN SKILLMAN: Okay, thank you.
9 Thank you.
10 MR. NETERER: Let's move to the next slide.
11 Just to give you a perspective on where we are from where 12 we take our water from Missouri River. In the 13 foreground is the Missouri River and the river flow is 14 from left to right.
15 Right in the middle is our intake 16 structure. We have three intake pumps that pump water.
17 You see the cooling tower in the background and then the 18 power block. That's five miles as the crow flies. So 19 we pump water up the hill. That provides our essential 20 service water, emergency cooling, our normal service 21 water and our circ water.
22 MR. BARTON: Now is that a pipe, a conduit, 23 aqueduct? What travels the five miles across country 24 to get the --
25 MR. NETERER: It's underground piping.
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14 1 MR. BARTON: Underground piping?
2 MR. NETERER: Underground piping.
3 MR. BARTON: Have you ever had any problems 4 with leakage on that piping?
5 MR. NETERER: Up coming the hill? No.
6 MR. BARTON: Okay.
7 MR. NETERER: To the left there you'll see 8 another concrete road it looks like. That's our 9 unloading dock for when we do major component 10 replacement such as steam generators, transformers, 11 reactor vessel head. Things that we have to barge up 12 the Missouri River are unloaded there and then hauled 13 up to the plant.
14 MR. BARTON: Have you ever had any fouling 15 issues in that piping, the five-mile pipe on the intake?
16 MR. NETERER: What's that pipe made of?
17 It's not steel. It's --
18 MR. WINK: Supply piping from the intake 19 structure. I'm not exactly certain the material.
20 MR. NETERER: It's not a metal pipe. It's 21 a --
22 MR. BARTON: You got nothing that attacks 23 it, no growth, no --
24 MR. NETERER: No.
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15 1 that? You've had no problems with that piping?
2 MR. NETERER: No and it's a high-flow 3 piping so you don't get any microbiologically induced 4 corrosion or anything like that.
5 MR. BARTON: Okay, thank you.
6 MR. NETERER: You're welcome.
7 CHAIRMAN SKILLMAN: Speak to us please 8 about flooding on that intake structure.
9 MR. NETERER: Okay, flooding. 1993 was 10 what we called the 500-year flood in Missouri and the 11 river was the highest it's ever been. I've got that 12 number here. Let me find it. Thank you. In 1993 the 13 river was at 535.8 feet above sea level and the site sits 14 about 840 feet above sea level so we had lots of margin.
15 CHAIRMAN SKILLMAN: Well, to the site I'm 16 sure because you're 300 feet above the river, but the 17 question is that intake structure.
18 MR. NETERER: Yes. Yes, we had no 19 problems. It never threatened the intake structure at 20 all, that high water level and that's the highest we've 21 ever seen in Missouri since the plant's been in 22 operation.
23 CHAIRMAN SKILLMAN: Thank you.
24 MR. NETERER: You're welcome. Go on.
25 This is a map of the state of Missouri. The red dot is NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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16 1 Callaway Plant. So our nearest population center from 2 Callaway is Fulton, Missouri. That's about 12 miles 3 away from the plant.
4 The nearest large centers are St. Louis to 5 the east and that's about 80 miles and Kansas City to 6 the west, about 175 miles just to give a perspective 7 where we sit in the state of Missouri. And the capital 8 of Missouri is Jefferson City. It's about 30 miles 9 away.
10 Okay, I'm going to turn it over to Sarah 11 Kovaleski or, excuse me, Roger Wink to talk about some 12 major modifications we've done. You don't want to skip 13 you, do you?
14 MR. WINK: No, I'm ready. Good afternoon.
15 Andrew, take the next slide please.
16 On this slide we have a number of bullets 17 demonstrating -- didn't intend to go through each one 18 of these bullets. I certainly can. Just an indication 19 of the investment Ameren Missouri has made into the 20 plant and our commitment to hardening the plant as well 21 as, you know, being here for the long run.
22 I do want to talk about a couple of these 23 items. The very first bullet, replacing the main 24 condenser tube bundles.
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17 1 before and what did you change it to?
2 MR. WINK: We had copper-nickel tubes 3 before and we changed to a SEA-CURE material, stainless 4 steel material.
5 MR. BARTON: Reason being? Fouling?
6 MR. WINK: Steam generator performance 7 primarily, the copper carryover and what that 8 modification allowed us to do is raise our pH following 9 replacement of the condenser tubes which also lowered 10 our flow-accelerated corrosion issues in the secondary 11 so that provided a number of beneficial items for the 12 plant.
13 MR. NETERER: And, Roger, if I may, that 14 was a strategic replacement because the next refuel we 15 put new steam generators in and we didn't want to have 16 that copper carryover to the new steam generators when 17 we replaced them.
18 MR. BARTON: Okay, thank you.
19 MR. WINK: Another modification I'll bring 20 to your attention, midway in the screen there you'll 21 notice that we've replaced the majority of our essential 22 service water piping with high-density polyethylene 23 piping.
24 MR. BARTON: What's the difference between 25 that piping and the five-mile cooling tower blowdown NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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18 1 piping?
2 MR. WINK: The essential service water 3 piping is an ASME Safety Class 3 piping system, whereas 4 our blowdown piping from the circulating and service 5 water system is non- --
6 MR. BARTON: I just wondering why one was 7 -- Safety related because the system is safety related?
8 What's the difference between your regular --
9 MR. WINK: The material's the same. One's 10 safety grade, one's not.
11 MR. BARTON: Okay. The difference being 12 the spec requirement or something? One's from Home 13 Depot and one has got a spec that you actually had to 14 meet?
15 MR. WINK: The essential service water 16 piping went through some stringent quality assurance 17 qualification requirements, NDT methods, et cetera, 18 whereas the piping --
19 MR. NETERER: And the fusion process was 20 validated.
21 MR. WINK: Correct.
22 MR. BARTON: Okay, thank you.
23 MEMBER STETKAR: Roger, I haven't looked 24 forward in your slides so just tell me to be quiet and 25 we'll get to it but will you be able to give us an idea NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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19 1 of what fraction of all of your essential -- I know you 2 replaced the underground piping and the essential 3 service water system. Have you replaced any of the 4 other essential service water piping?
5 MR. WINK: Yes, sir. Of the buried piping 6 that's approximately 1,700 feet of HDPE piping. Inside 7 the power block itself we replaced approximately 3,500 8 feet of mostly four-inch carbon steel piping.
9 MEMBER STETKAR: Okay. I read those 10 numbers. Can you give me an idea of what fraction of 11 all of the essential service water piping is, I mean, 12 is it ten percent, is it -- It's hard to, you know --
13 MR. WINK: I do not have that percent 14 committed to memory.
15 MEMBER STETKAR: -- linear feet of 16 small-bore pipe is difficult.
17 MR. WINK: It's significant and the reason 18 -- It's a significant percentage. The reason those 19 four-inch lines were a challenge was we found 20 historically that our piping in the smaller piping 21 didn't receive the chemical treatment we necessarily 22 needed to keep the nodules from growing and pitting and 23 that sort of thing. The areas that get a lot of flow 24 are in very good shape.
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20 1 stainless or what did you replace it with inside the 2 building?
3 (Crosstalk) 4 MEMBER SCHULTZ: Roger, you've got those 5 couple of items identified as not in the license renewal 6 scope. Can you describe the difference between the 7 listings that you have, the other bullets, and those two 8 items as to why you designated those?
9 MR. WINK: The other items are in scope of 10 license renewal. I wanted to bring out the main 11 condenser tube bundle modification because it did have 12 a subsequent impact on other components that are in 13 scope.
14 MEMBER SCHULTZ: Okay. But they're all 15 part of the aging management program, GALL?
16 MR. WINK: Main condenser is not. The 17 other items are.
18 MEMBER SCHULTZ: Okay, thank you.
19 CHAIRMAN SKILLMAN: Why did you change the 20 heat exchangers on the emergency diesel generator?
21 MR. WINK: Performance testing showing 22 there's some pitting going on and having to tube some 23 plugs, plug some tubes, excuse me. It was a proactive 24 replacement with a corrosion-resistant material.
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21 1 coolers and the safety-related room coolers, were you 2 running at times inoperable on those heat exchangers, 3 on those coolers?
4 MR. WINK: No. Our original containment 5 coolers were not cleanable and that posed some issues 6 over time with maintaining enough flow. They've always 7 maintained operable but we were losing margin so we 8 proactively replaced those coolers with a cleanable 9 containment cooling design.
10 CHAIRMAN SKILLMAN: Okay, thank you.
11 MR. WINK: Andrew, next slide. On this 12 slide we have some near term plant improvements, 13 probably most notably in Refueling Outage 20 which is 14 coming up in October we are replacing our reactor vessel 15 head.
16 MR. BARTON: Is that a Davis-Besse follow 17 on or did you have some boric acid issues yourself?
18 MR. WINK: We had no issues. This is a 19 proactive replacement.
20 MR. NETERER: We're replacing it because 21 it does have susceptible material for stress corrosion 22 cracking.
23 CHAIRMAN SKILLMAN: Why aren't you 24 replacing your stud in that outage?
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22 1 replacement has been treated separately from removal of 2 the stud. That stud is still tensionable and it still 3 fully performs its function.
4 So we will, as we'll discuss later in the 5 presentation, we do have a commitment to remove that 6 stud fully before we enter the period of extended 7 operation.
8 CHAIRMAN SKILLMAN: So do you use it as a 9 guide stud?
10 MS. KOVALESKI: No, it is a functional 11 stud.
12 CHAIRMAN SKILLMAN: Oh, I understand that.
13 It's a functional stud that isn't supposed to be there 14 when all the other studs are removed.
15 MS. KOVALESKI: It is not removed, that's 16 true, with the other studs, yes.
17 CHAIRMAN SKILLMAN: I got that. Because 18 normally what you do is you remove your studs and you 19 put in guide studs and you put your head on those guide 20 studs.
21 MR. NETERER: We still have the three guide 22 pins to put, that ride down on the head, just not using 23 the guide stud.
24 CHAIRMAN SKILLMAN: Not using. It just 25 seems odd that you're going to do a head replacement and NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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23 1 with all of the work that will occur in and around that 2 area that this wouldn't have been a most convenient time 3 to address that stud. I understand that you can justify 4 its use and it's fully tensionable and it's within ASME 5 code. I understand that.
6 MR. NETERER: Yes, and we'll follow up 7 about it little more later but really was a learning for 8 us on aging management. That's an uninspectable area, 9 area of thread engagement, and that's why we chose to 10 replace it at a future date. We're not geared up to do 11 it this refuel. We don't have everything set up to do 12 it and do it right.
13 MR. BARTON: But you're doing it prior to 14 license approval, right?
15 MR. NETERER: Yes, sir. We tentatively 16 have it scheduled about four and a half years out.
17 CHAIRMAN SKILLMAN: Okay, thank you.
18 Okay.
19 MR. WINK: Also note that on this slide we 20 do have two of our motor-driven auxiliary feedwater pump 21 coolers. Those are scheduled for replacement in 22 upcoming outages and that's part of our long-term 23 process for maintaining maximum operability of our room 24 coolers.
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24 1 bullets there, cathodic protection system 2 modification. I read the inspection report and the 3 other data about your cathodic protection system. What 4 is protecting your underground tanks and buried piping 5 right now?
6 MR. WINK: We have a cathodic protection 7 system installed right now. It --
8 CHAIRMAN SKILLMAN: But is it fully 9 functional or is it doing what it's supposed to be doing?
10 MR. WINK: The current NACE criteria 11 requires a current of negative 850 millivolts. And the 12 NACE criteria also acknowledges other acceptable means 13 of protection. We do meet those other means of NACE 14 protection. Going forward we do plan to upgrade our 15 system so we get the full 850 millivolts.
16 MR. BARTON: Is it in service at least 95 17 percent of the time?
18 MR. WINK: I'd like to ask Neil Fisher to 19 help.
20 MR. FISHER: Any particular system?
21 MALE PARTICIPANT: Yes.
22 MALE PARTICIPANT: Name, Neil.
23 MR. BARTON: Your cathodic protection 24 system.
25 MR. FISHER: I'm sorry.
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25 1 MR. BARTON: Overall, do you do a --
2 MALE PARTICIPANT: He has to identify 3 himself.
4 MR. FISHER: I'm sorry. Neil Fisher.
5 MALE PARTICIPANT: That's all right.
6 MR. FISHER: System engineer, Callaway, 7 cathodic protection.
8 MR. BARTON: Cathodic protection system, 9 what's its availability number? Is it greater than 90 10 percent or is it up and down, a lot of maintenance 11 required or what?
12 MR. FISHER: Overall, all of the in-scope 13 piping, we're about 88 percent availability over the 14 past ten years.
15 MEMBER BALLINGER: Is it active or is it 16 passive?
17 MR. FISHER: It's active.
18 MEMBER BALLINGER: It's active?
19 MALE PARTICIPANT: Okay, thank you.
20 MALE PARTICIPANT: Thank you, Neil.
21 MALE PARTICIPANT: Thanks, Neil.
22 MR. WINK: Andrew, next slide.
23 MEMBER BALLINGER: Oh, wait. I have a 24 question.
25 MR. WINK: I'm sorry. Go ahead.
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26 1 MEMBER BALLINGER: Can we back up one?
2 MR. WINK: Absolutely.
3 MEMBER BALLINGER: You say PWSCC 4 mitigation of reactor nozzle and bottom mounted 5 instrumentation tubes. What's happening with the 6 bottom mounted instrumentation tubes?
7 MR. WINK: In refuel 21 we're planning on 8 mitigation of the bottom mounted instrumentation tubes 9 as well as our eight --
10 MEMBER BALLINGER: Which is what 11 technique?
12 MR. WINK: We're looking at doing the water 13 jet peening process.
14 MEMBER BALLINGER: Okay, so peening from 15 the inside?
16 MR. WINK: Correct.
17 MEMBER BALLINGER: Okay.
18 MR. HOEHN: Well, and this is Mike Hoehn, 19 supervising engineer, we're also pursuing water jet 20 peening of the actual J-welds outside of the actual 21 tubes as well. They're both Inconel base material.
22 MR. BARTON: I want to go back an item.
23 You put a manhole sump in to keep your area where your 24 cables are running dry, right? You had a flood in 2007 25 that the cables were submerged. Did you have any of NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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27 1 those cables fail upon testing or just fail during 2 normal operation?
3 MR. WINK: Ken Sandstedt, could you please 4 help with this? We had no failures and Ken can explain 5 the modifications we performed.
6 MR. SANDSTEDT: I'm Ken Sandstedt, cable 7 engineer. Can you restate the question please?
8 MR. BARTON: Yes, you had a flood in your 9 manholes in 2007. You committed to do something about 10 putting in dewatering, keep them dry or whatever. You 11 finally in 2013 installed a pump, a sump pump in the 12 manhole to keep it from collecting water, drain water 13 or whatever.
14 MR. SANDSTEDT: Yes.
15 MR. BARTON: Did you have any cables that 16 failed from the submergence issue?
17 MR. SANDSTEDT: No, we've not had any 18 cables fail.
19 MR. BARTON: You haven't had any of those 20 cables that failed?
21 MR. SANDSTEDT: No.
22 MR. BARTON: Okay. All right, thank you.
23 MR. WINK: This is a correction. In 2007 24 when you say flood, we did not have a flood at the site.
25 We did have maybe a lot of rain but --
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28 1 MR. BARTON: It said all the cables in the 2 manholes were submerged. That's what I read. Okay.
3 CHAIRMAN SKILLMAN: Talk to us a little bit 4 about the independent spent fuel storage installation.
5 This is a new build or a new construct? Will it be built 6 and then entered into service or built and waiting for 7 service later with a fuel offload? Tell us a little 8 more about this please.
9 MR. WINK: The modification is underway 10 right now. We plan on 2015 starting to move some of the 11 spent fuel assembly canisters into that ISFSI in the 12 year 2015. We lose full core offload capability in the 13 year 2020 so we're doing that modification to make some 14 room in our spent fuel pool.
15 MEMBER SCHULTZ: That's after outage 21 16 that you'll be moving the fuel?
17 MR. WINK: Next year. It'll be before.
18 MEMBER SCHULTZ: Before outage 20?
19 MR. WINK: Correct.
20 MEMBER STETKAR: You're on an 18-month 21 cycle?
22 MR. WINK: Yes, sir.
23 MEMBER STETKAR: Thanks.
24 CHAIRMAN SKILLMAN: And if we look at the 25 image from, looks like maybe 900 feet. That is your NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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29 1 opening image that shows your site. Where will the 2 ISFSI be please?
3 MR. NETERER: Let's go back to the slide so 4 I can explain that to you.
5 (Off microphone discussion) 6 MR. NETERER: Okay, see the power block and 7 up to the upper left quadrant it looks green. That's 8 actually the Unit 2 excavation. At the time this 9 picture was taken, there was water in the bottom of it.
10 We kept that water pumped out to a low level. We are 11 filling that hole.
12 And the ISFSI project, the spent fuel 13 storage project, will go in the plant, the north end of 14 that to the right. And then our Fukushima FLEX storage 15 building will be in the southern end of that pond area.
16 CHAIRMAN SKILLMAN: Thank you. Thank 17 you.
18 MALE PARTICIPANT: We're back to 13.
19 MALE PARTICIPANT: Thank you.
20 FEMALE PARTICIPANT: Thank you.
21 MR. WINK: Andrew, go ahead and next slide 22 please. Turn this over to Sarah Kovaleski to continue 23 discussion about the license renewal application.
24 MS. KOVALESKI: Thank you. Callaway's 25 license renewal team has been working on this since NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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30 1 2007. We are the fifth of the STARS license renewal 2 applications, that's Strategic Teaming and Resource 3 Sharing alliance.
4 One of the things that we have made a 5 priority throughout this project is maintaining 6 involvement with the industry as well as our STARS 7 peers.
8 And we've utilized the NEI working groups, 9 industry peer review process and we've made a 10 significant effort to incorporate these lessons learned 11 into our application.
12 CHAIRMAN SKILLMAN: Sarah, who are the 13 other, not participants. What are the other plants 14 that are involved here please?
15 MS. KOVALESKI: The other plants in the 16 STARS alliance?
17 CHAIRMAN SKILLMAN: Yes, of these five.
18 MS. KOVALESKI: Of these five Wolf Creek 19 was the first to submit, followed by Palo Verde. The 20 next two were Diablo Canyon and South Texas and Callaway 21 is the fifth.
22 CHAIRMAN SKILLMAN: Thank you.
23 MS. KOVALESKI: You're welcome. Next 24 slide. We submitted our application to the NRC on 25 December 15, 2011. We are a Generic Aging Lessons NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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31 1 Learned, or GALL, Rev 2 application.
2 We have 42 aging management programs in our 3 license renewal application. This involves over 3,900 4 aging management review lines and we are 98.8, so nearly 5 99 percent consistent with GALL Rev 2.
6 CHAIRMAN SKILLMAN: What does that really 7 mean? What does the percentage mean?
8 MS. KOVALESKI: It refers to the number of 9 exceptions to GALL. It means that for the recommended 10 material and environment combination we 98.8 percent of 11 the time follow the recommended aging management 12 program.
13 CHAIRMAN SKILLMAN: So for the 1.2 percent 14 where you do not, what is the remedy?
15 MS. KOVALESKI: Those exceptions are not 16 -- They are both positive and negative. It does not 17 necessarily imply that a remedy is required but it is 18 an exception and Eric Blocher can explain some of the 19 details for those.
20 MR. BLOCHER: Yes, if I could have backup 21 Slide 39 or 36, excuse me.
22 MR. BURGESS: 36?
23 MR. BLOCHER: 37, sorry, 37. The lines 24 that we're talking about involve Notes F through J and 25 those, as Sarah indicated, don't necessarily require a NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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32 1 remedy. Those lines simply aren't in GALL.
2 For example, the lines that are labeled as 3 Note F, they're not in for material considerations.
4 Like, for example, two of those lines are the cellulose 5 silica cement splash panels on the cooling tower. That 6 material just simply is not in GALL.
7 Another one is the fiberglass reinforced 8 plastic for the cooling tower fan stacks. Again, that 9 material simply is not in GALL so we had to come up with 10 an acceptable aging management evaluation that staff 11 evaluated and approved, both in terms of the aging 12 effect and aging management program.
13 Similarly, for the other ones, Note G is 14 environments, are not within GALL. Note H is our aging 15 effects that are not within GALL. Note I are the aging 16 effect that is not applicable in GALL, and those are used 17 primarily for electrical items to review. And Note J 18 is where the component material environment is not in 19 GALL at all.
20 CHAIRMAN SKILLMAN: Thank you, Eric.
21 Thank you. Okay.
22 MS. KOVALESKI: Slide 16 please. The 23 other aspect that I'd like to point out with our 24 application is the incorporation of the license renewal 25 interim staff guidance documents. In our application, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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33 1 we addressed eight of these ISGs. That's seven final 2 issued ISGs and one draft.
3 The commitments in our license renewal 4 application will be included in our FSAR supplement and 5 they are found in Appendix Alpha of our license renewal 6 application.
7 These commitments will be managed by our 8 commitment tracking system at Callaway which is 9 consistent with the NEI 99-04 guidelines.
10 MEMBER SCHULTZ: Sarah, are you expecting 11 any license conditions at this point in time or are you 12 trying work those through so that they become 13 commitments?
14 MS. KOVALESKI: We have tried to work 15 everything through but through discussions with the 16 staff we understand that the removal of our stuck stud 17 and the other associated commitment to do inspections 18 of the stud holes may be a license condition.
19 MEMBER SCHULTZ: Thank you.
20 MS. KOVALESKI: Next slide please. Of the 21 42 aging management programs that I mentioned, 32 are 22 existing programs and ten are new. Of the 42 in total, 23 there are 16 enhancements and five exceptions.
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34 1 throughout this process, that it's very important to be 2 focused on implementation while we're preparing the 3 license renewal application. It isn't something to 4 pick up later on down the road.
5 So through this we have designated specific 6 program owners and maintained a license renewal staff 7 on site. We continue to participate within the various 8 working groups and benchmark others in the industry.
9 One of the ISGs that we incorporated was 10 2011-05 for the ongoing review of operating experience, 11 and I wanted to highlight this because this is one of 12 the ISGs that we thought we would benefit from by 13 implementing immediately.
14 Specifically we improved our operating 15 experience program and procedures to focus on aging 16 management issues and we now have the written guidance 17 to our entire site so that when aging management topics 18 are identified, whether it's internal operating 19 experience or external operating experience, it is 20 consistently entered into our corrective action program 21 so that we can evaluate it.
22 The other piece of that is our operating 23 experience coordinator on site has been trained on aging 24 management and also keeps an eye on Callaway internal 25 operating experience to ensure that we're sharing that NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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35 1 with the industry if it's related to aging or aging 2 management issues.
3 MEMBER SCHULTZ: Sarah, the slide's 4 labeled Implementation and Sustainability.
5 MS. KOVALESKI: Yes.
6 MEMBER SCHULTZ: So you characterize then 7 the program owners as the sustainability part of the 8 program?
9 MS. KOVALESKI: That is certainly a part of 10 it but another piece is making sure that aging 11 management practices are proceduralized and that way if 12 we do experience turnover we, just like many in the 13 industry, expect that that's going to happen over the 14 future years, the next generation of employees who come 15 in have, there's no question as to what those aging 16 management practices are.
17 MR. NETERER: And it's embedded in our 18 knowledge retention and transfer and training programs.
19 MEMBER SCHULTZ: The license renewal 20 staff, is this programmatic now that you've entered into 21 this process and program? You're years before you get 22 into the implementation period but so, therefore, 23 there's going to be some continuity after you get the 24 license renewal approval?
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36 1 haven't made those transitions yet but what we found is 2 that by having a staff on site when the specific license 3 renewal application efforts draw to a close we have that 4 embedded knowledge and we can move those people on to 5 work on implementation issues.
6 MEMBER SCHULTZ: Good. Thank you.
7 MS. KOVALESKI: Next slide please. Thank 8 you. At this --
9 CHAIRMAN SKILLMAN: Before we do that let 10 me ask a question. We've touched on Appendix B and 11 we've touched on corrective action couple times so far.
12 Could you please explain to us the degree 13 of senior management involvement in discussions about 14 emerging CARs, corrective action items, whatever 15 they're called at your site, and the degree to which the 16 senior leadership becomes directly involved and how 17 quickly?
18 MR. NETERER: Every day. We have a 19 meeting every morning and all the senior leaders, the 20 directors, Sarah and above and VPs attend that meeting 21 and we review every CR or corrective action document 22 that was written and screened the previous day.
23 And the purpose of that, first of all, is 24 keep us in the loop, keep us tuned in and also do we agree 25 with the significance level of the issue. And we do, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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37 1 we do on occasion go back and ask that the significance 2 level be elevated if we don't feel it's getting the 3 proper attention.
4 CHAIRMAN SKILLMAN: Okay. And for those 5 items that are deemed to be more important or that 6 require a root cause, what is the extent of senior 7 leadership involvement in understanding, if you will, 8 the accuracy of the root cause, the lessons learned from 9 the root cause, the conclusion of the root cause?
10 MR. NETERER: Every CR of that level has a 11 director assigned to it as the sponsor. Also our 12 corrective action review board is made up of directors 13 and there are directors from the corrective action 14 review board assigned to monitor the progress of that 15 root cause or, you know, to determine if the causes are 16 correct.
17 Then, is the extended condition correct?
18 Do the corrective actions line up with the causes? And 19 then the effectiveness review, does it make sense and 20 does it line up with what we're trying to achieve going 21 forward? And are the effectiveness reviews extensive 22 enough to ensure what Sarah talked about before, 23 sustainability?
24 CHAIRMAN SKILLMAN: Okay, thank you.
25 Let's proceed on Slide 19. Thank you.
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38 1 MS. KOVALESKI: All right. At this point 2 we'd like to transition to discuss the open items in the 3 Safety Evaluation Report.
4 As John noted in his introduction, there 5 are five open items and they're listed here. There were 6 also several other open, I'm sorry, issues that arose 7 after the SER with open items was published.
8 The first open item has to do with scoping 9 of fire protection systems, structures and components.
10 This open item really consisted of two parts. The first 11 part had to do with exclusion of certain portions of the 12 turbine building from the scope of license renewal.
13 Callaway resolved this issue by returning 14 to license renewal scope the fire suppression systems 15 located in the three locations listed there, the 16 auxiliary boiler room and turbine bearings and other 17 locations.
18 We did, following that, have our NFPA 805 19 license amendment request approved. That amendment 20 request was approved in January of this year and we 21 subsequently removed the auxiliary boiler room fire 22 suppression system from scope based on the new 805 23 licensing basis.
24 MR. BARTON: But you maintained the 25 turbine building locations and turbine bearings area?
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39 1 There were three parts to this as I remember, auxiliary 2 boiler room, the turbine building various locations and 3 then turbine bearings area.
4 And I see that you removed from the scope 5 the auxiliary boiler room suppression system. I don't 6 know anything about the other two. Are they still 7 maintained in scope?
8 MS. KOVALESKI: Understand. I'd like 9 Mike Fletcher to elaborate a bit on the scope.
10 MR. FLETCHER: My name's Mike Fletcher. I 11 was part of the NFPA 805 transition team and, yes, the 12 main turbine bearings suppression system has remained 13 in scope.
14 MR. BARTON: And were there some other 15 areas in the turbine building because there was a 16 turbine area various location description that wasn't 17 very specific and I picked it up as something other than 18 just the turbine bearings. Is it more than the turbine 19 bearings area included?
20 MR. FLETCHER: Essentially all of the 21 turbine hall main floor suppression systems stay in 22 scope.
23 MR. BARTON: Okay. That's included?
24 MR. FLETCHER: That's correct.
25 MR. BARTON: Okay. The only thing is NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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40 1 auxiliary boiler room taken out. I got you.
2 MALE PARTICIPANT: Got to look at hydrogen 3 and all that kind of stuff.
4 MALE PARTICIPANT: Everywhere hydrogen is 5 you better have it.
6 MR. BARTON: Yes, that's what I'm 7 thinking. All right. So it's all included except the 8 auxiliary boiler room.
9 MR. FLETCHER: Correct.
10 MR. BARTON: Okay, thank you.
11 MS. KOVALESKI: Thank you, Mike.
12 CHAIRMAN SKILLMAN: Quick question before 13 you change.
14 MS. KOVALESKI: Yes.
15 CHAIRMAN SKILLMAN: Excuse me, John.
16 MEMBER STETKAR: No, you were first off the 17 block.
18 CHAIRMAN SKILLMAN: Okay, at the end of the 19 write-up here for this open item, staff -- I'm going to 20 read this so I will be accurate in what I say.
21 "The staff finds that the applicant should 22 not perform a gap analysis of LRA Tables 2.3.3-20 and 23 so on based on a draft NFPA 805 LAR SER. The staff finds 24 that the gap analysis should be based on a final NFPA."
25 Is there a date? Is this done? What's the status?
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41 1 MS. KOVALESKI: Yes, it is done. We 2 worked with the staff. At one point during the review 3 of our application we had discussed performing a gap 4 analysis on the draft that was available at that time 5 and then through future discussions we determined that 6 it was most appropriate to wait until the license 7 amendment was finalized.
8 So with the license amendment being 9 finalized in January of this year, we used that as the 10 basis to submit both the gap analysis and then amend the 11 LRA as appropriate.
12 CHAIRMAN SKILLMAN: Thank you.
13 MS. KOVALESKI: You're welcome.
14 MEMBER STETKAR: Sarah, I've got a 15 question. Doesn't have to do with scoping but I just 16 stumbled across something that was curious to me.
17 There's a discussion about testing frequency for fire 18 hoses.
19 And apparently if I walk up to a fire hose 20 in the plant, that fire hose is either, knows that it's 21 a fire brigade hose or it knows that it's an interior 22 fire hose because if the hose is a fire brigade it's 23 tested every year and if it's an interior fire hose it's 24 only tested every three years.
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42 1 hose, I don't know what it was, it probably knew what 2 it was, when it was charged for fire brigade training.
3 So my question is if I have a fire, how do 4 the fire hoses know that they ought to be a fire brigade 5 hose and that's a really good hose and that if I run up 6 to a fire hose reel in the plant I better not use that 7 hose because it might not work? I mean, I don't 8 understand this distinction. It's the first time I've 9 ever seen it in any of the plants that we've looked at.
10 MS. KOVALESKI: I understand your question 11 is about the distinction between fire brigade hoses and 12 installed hoses.
13 MEMBER STETKAR: Right, yes and the 14 testing.
15 MS. KOVALESKI: Lee Eitel I think can 16 address that.
17 MR. EITEL: Lee Eitel, supervisor, systems 18 engineering. The fire brigade hose is specifically 19 placed on our fire trucks and in locations that only the 20 fire brigade uses. The hose stations are distinct 21 locations in the plant so they are completely separated 22 and distinct fire hoses.
23 MEMBER STETKAR: Okay. Now if I am an 24 operator or maintenance person or somebody who normally 25 lives in the power plant and a fire starts and I run up NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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43 1 to some hose reel that's there and it's got a sign, it's 2 painted red and all that good kind of stuff, and I grab 3 that hose, it's most likely not going to be tested at 4 an annual frequency. It's most likely going to be one 5 of the secondary type hoses that may or may not work.
6 I just don't understand that rationale.
7 MR. EITEL: The hoses that are permanently 8 installed are for backup. The fire brigade always 9 bring their own hoses to a fire scene and use those hoses 10 via -- The hoses that are installed on the racks are 11 replaced new every five years and that's why we do not 12 perform as periodic of testing in compliance with code.
13 MEMBER STETKAR: Is that, because if I read 14 things it says interior fire hose, meaning the second 15 tier, is tested five years from installation and every 16 three years thereafter. But if you're saying you 17 replace them every five years, then they never get a 18 chance to be --
19 MALE PARTICIPANT: Three year tested.
20 MEMBER STETKAR: -- tested, three-year 21 tested. In fact, they never get a chance to be tested 22 --
23 MS. KOVALESKI: Five years.
24 MEMBER STETKAR: -- you know, after 25 installation. Is that true? You actually do replace NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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44 1 all of them every five years?
2 MR. EITEL: We do replace all of them.
3 That is in compliance with code. The manufacturer 4 tests them prior to --
5 MEMBER STETKAR: Thanks. The replacing 6 them every five years solves my concern.
7 MR. EITEL: Okay.
8 MEMBER STETKAR: Thank you.
9 MS. KOVALESKI: Thank you. All right, 10 next slide please. We touched on this a little bit.
11 The second part of this open item had to do with the 12 changes to license renewal scope that occur with the 13 NFPA 805 transition.
14 To provide a bit of context, the license 15 renewal application was prepared with our previous 16 current licensing basis or previous licensing basis for 17 fire protection. That's the more traditional 18 licensing basis.
19 And it wasn't until January of this year 20 that we were approved for the NFPA 805 licensing basis.
21 The license renewal application has been amended to 22 update the license renewal scope so that it is now 23 consistent with the NFPA 805 licensing basis.
24 In addition, the gap analysis that we 25 prepared and provided to the staff helps to explain the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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45 1 changes for components that were either removed from 2 scope of license renewal or added into the scope of 3 license renewal and the basis for that and where it can 4 be found in the NFPA 805 licensing basis.
5 MEMBER STETKAR: Just out of curiosity 6 since I'm interested, put it that way, in NFPA 805, on 7 a net basis, I mean, you mentioned that the auxiliary 8 boiler fire protection system was removed. Did you 9 wind up adding more equipment in scope as a result of 10 NFPA 805 or did you wind up removing more?
11 MS. KOVALESKI: It was more or less even.
12 MEMBER STETKAR: Was it?
13 MS. KOVALESKI: Mike Fletcher could 14 elaborate on that.
15 MR. FLETCHER: Again, it's Mike Fletcher.
16 Look, just let's say specific to suppression systems we 17 ended up pulling in eight suppression systems and there 18 were six that were moved so then that change was a plus 19 two.
20 MEMBER STETKAR: Okay. Was it? Okay, 21 okay. Yes, and that's big-picture stuff. That's all.
22 Thank you. I was just curious.
23 MS. KOVALESKI: Next item please. The 24 next open item pertain to the reactor head closure 25 studs. The question posed by the staff was that the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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46 1 program may not be adequate to detect future wear, loss 2 of materials, or assure that allowable stresses are not 3 exceeded during the period of extended operation.
4 The specific concern related to the stuck 5 stud, Stud Number 18. And as previously mentioned, we 6 have a commitment to ensure that that stud is removed 7 prior to the period of extended operation.
8 The other concern presented to us that we 9 understand is that with that stud stuck in the position 10 that it's in, the areas of thread engagement cannot be 11 directly visually inspected and that there could be 12 degradation going on within the threads of the reactor 13 vessel flange that we're not able to detect right now.
14 So the second part of that commitment is to 15 inspect the six stud holes that have the greatest amount 16 of previous thread damage with a laser profiling 17 technique so that we can determine if there has been any 18 ongoing degradation.
19 The thread damage that previously occurred 20 was not a result of aging but rather a result of poor 21 stud handling practices and foreign material controls 22 very early in plant operation.
23 It is not indicative of our current stud 24 handling practices and we've not seen any sort of 25 recurrence of this issue.
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47 1 MR. BARTON: I'm glad you're using laser 2 instead of the old thread plug we used to use in the old 3 days where you put a tap in there and clean up the 4 threads.
5 MS. KOVALESKI: Like a go gauge kind of 6 thing? Yes, yes.
7 MEMBER STETKAR: How many studs do you 8 have?
9 MS. KOVALESKI: Fifty-four.
10 MEMBER SCHULTZ: Sarah, in the various 11 reports, the SER, 2013 SER and then in the written 12 dialogue going back and forth related to request for 13 additional information and so forth and the staff's 14 inspection, there were a number of different stud 15 locations that were identified.
16 You've indicated that these are the six 17 with potentially the most damage and I was curious as 18 to how that was determined. I mean, the numbers went 19 from, I think you said six and they had a number that 20 identified perhaps 10, 12, 13 locations and it seems to 21 have been resolved to come back to six locations with 22 the most thread damage.
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48 1 comprehensive inspection campaign?
2 MS. KOVALESKI: I think I understand your 3 question. Andrew, Slide 49 please. We're going to 4 bring up a table that shows the stud, 49 please. Thank 5 you. This table shows the areas in the flange where we 6 did have to remove and perform a Section 11 repair of 7 the stud hole threads.
8 As you can see on this table, several of 9 these locations are missing one or fewer threads and 10 with that small number those have been excluded from the 11 future inspection.
12 But the Stud Hole Number 2 missing 13.1 and 13 Stud Hole Number 9 missing 15.12, at that point we really 14 want to be monitoring that.
15 MEMBER SCHULTZ: Okay, that helps a lot.
16 I appreciate that level of detail. Thank you.
17 CHAIRMAN SKILLMAN: Talk to us a little bit 18 about the poor work practices that are identified on 19 that slide.
20 MS. KOVALESKI: Certainly. Andrew, go to 21 Slide 23. That's the next one that we would have pulled 22 up. There were two issues that were going on 23 concurrently. The handling practices had to do with 24 the weighting of the stud and whether the weight was 25 distributed onto the stud.
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49 1 And concurrently there were four material 2 issues. At the time that Stud Number 18 was stuck, 3 there was an entry in our corrective action program 4 indicating that overhead work had been dropping debris 5 into that location.
6 And while we had inspected the stud before 7 it was installed and it was a satisfactory inspection, 8 it would appear that some sort of foreign material was 9 introduced into the stud hole or on the stud at the time 10 it was installed.
11 MR. BARTON: So you don't put covers on?
12 When you remove the studs, you don't put covers over 13 those holes?
14 MR. NETERER: Yes, we do. We do.
15 MR. BARTON: You do now?
16 MR. NETERER: Yes.
17 MR. BARTON: But when all this debris and 18 stuff got in there, was that still your practice or, 19 because I'm trying to figure out how this debris got in 20 there. Overhead work, fine. But if you took the studs 21 out and you had your covers on, how did debris get in 22 there? That's what I was struggling with right there.
23 MS. KOVALESKI: I don't know the answer to 24 that.
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50 1 stud hole covers but I can't commit to going back to 2 Refuel 1 on that.
3 MR. BARTON: That's what I'm looking at, 4 yes.
5 MR. NETERER: Yes. I can't answer when 6 we, if we did always or started using them. David, do 7 you know?
8 MR. GROSS: This is David Gross. I'm a 9 consultant with Dominion Engineering and we've been 10 working with Callaway on their reactor stud issues going 11 back to 1987 and if Walt is on the phone he may also be 12 able to address this.
13 But I believe the issues that happened in 14 the 1990 time frame were more related to poor cleaning 15 of thread lubricant in the holes and lessons learned 16 about what good thread lubricants to use and what good 17 cleaning procedures to use and just thread cleanliness 18 on the female hole wasn't what it became in subsequent 19 outages.
20 MS. KOVALESKI: Thank you, David. Let's 21 pull up Slide 50 please. You had asked about the stud 22 hole covers and I'm not in a position to elaborate on 23 it right now. We could get more information on it. But 24 there were some issues with the effectiveness of the 25 stud hole covers.
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51 1 Really the cleanliness issue, presence of 2 foreign material, the lubrication issue and the detail, 3 the level of detail associated with the procedures that 4 were used were all not today's standards.
5 MR. BARTON: So it sounds like at the first 6 refueling your work practices weren't up to snuff or 7 what they needed to be and you messed up your threads.
8 MS. KOVALESKI: That's --
9 MR. BARTON: What it sounds like to me.
10 That about it?
11 MS. KOVALESKI: That's pretty much it, 12 yes.
13 MR. NETERER: Yes, we did do a root cause 14 on that 1996 and changed our stud handling practices and 15 stud hole cleaning practices.
16 MEMBER SCHULTZ: Okay. Is that what this 17 reflects? You feel that this slide captures the 18 results of the root cause in 1996?
19 MR. NETERER: Yes, yes.
20 MEMBER SCHULTZ: Thank you.
21 CHAIRMAN SKILLMAN: Let me ask this. It's 22 easy to confuse proper cleanliness with ensuring that 23 that stud hole's been chased properly with a deburring 24 tool normally run by hand. It's where an individual 25 takes it, drives all the way to the bottom, drives all NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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52 1 the way back up and then vacuums and then might put in 2 a very light film of oil or something just to protect 3 what could be bare metal surfaces.
4 Were you able to determine it truly was 5 foreign material as opposed to a potential cross thread 6 or a potential ding in the thread that resulted from, 7 if you will, the stud insertion crew not knowing how 8 careful they need to be when they feed those first one 9 or two threads?
10 MS. KOVALESKI: When Stud 18 became stuck, 11 we actually had found a small burr on two of the threads 12 prior to that installation. We did remove the burr.
13 We fully examined the stud threads as well as the stud 14 hole threads, again prior to its installation, and did 15 not identify any damage.
16 When the stud was inserted, it did turn 17 freely past the locations where the removed burr had 18 been located and that would be our evidence that the stud 19 had been treated and inspected properly. That's for 20 Stud 18.
21 As far as the damage that occurred earlier 22 in plant life, we did after that implement stricter 23 procedural instructions and guidance for stud and stud 24 hole and nut cleaning, inspecting and lubrication.
25 CHAIRMAN SKILLMAN: Thank you.
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53 1 MALE PARTICIPANT: Okay.
2 CHAIRMAN SKILLMAN: Thanks. Back to 23.
3 MS. KOVALESKI: All right, thank you. And 4 next slide please. At this point I'd like to ask Mike 5 Hoehn to discuss the open item related to reactor vessel 6 internals and the MRP-227-Alpha report.
7 MR. HOEHN: Thank you. The next few 8 slides we'll go over the licensee action items under 9 MRP-227-Alpha which is associated with the reactor 10 vessel internals program at Callaway.
11 This first topic, demonstrate MRP, which 12 stands for material reliability program under Electric 13 Power Research Institute, 227-Alpha bases/assumptions 14 are applicable and bounding for design of Callaway 15 reactor vessel internal components.
16 The 227 approach was intended to be a 17 generic bounding approach for the U.S. fleet and we were 18 required to ensure that we were bounding and that we were 19 consistent with the recommendations and the guidelines 20 within 227-Alpha and specifically MRP-191 which was the 21 screening categorization and ranking of reactor 22 internal components.
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54 1 verified we were consistent.
2 We also incorporated considerations for 3 atypical fuel design and ensured that our procedures are 4 appropriate to ensure that that atypical fuel design 5 does not occur in the future.
6 CHAIRMAN SKILLMAN: Say that again please.
7 MR. HOEHN: We ensured, our core design 8 procedures, we have procedure requirements in there now 9 that we don't, when we do a design change that we are 10 consistent with our, specifically the, we put the new 11 fuel in the center and put the older fuel on the outside 12 which is our standard core design practices so --
13 CHAIRMAN SKILLMAN: Had you been doing it 14 differently in earlier fuel cycles?
15 MR. HOEHN: We were consistent with the 16 design in/out practices as documented MRP-2013-025.
17 CHAIRMAN SKILLMAN: Thank you.
18 MEMBER SCHULTZ: Perhaps it's just the 19 phrasing here, consistent with atypical fuel design 20 parameters. Are you talking about core loading?
21 MR. HOEHN: Correct. Yes, we don't use 22 the atypical fuel design parameter. We are consistent 23 with the in/out method, new fuel in the center and the 24 previously used fuel is placed on the outside. We're 25 consistent with that approach.
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55 1 MEMBER SCHULTZ: Okay. So the procedure 2 is to ensure that you don't use atypical?
3 MR. HOEHN: Correct. There was an 4 administrative measure to ensure that we don't do it in 5 the future, that sustainability action moving forward.
6 MEMBER SCHULTZ: Okay, thank you.
7 CHAIRMAN SKILLMAN: So do your procedures 8 for your reloads preclude something different than 9 in/out?
10 MR. BLOCHER: Eric Blocher, STARS. If I 11 can supplement Mr. Hoehn's answer, the MRP that's 12 referenced up there, the 2013-025, has three fuel design 13 parameters that are essential in the fuel design for 14 limiting, if you will, potential for degradation in the 15 core internals.
16 And those three parameters are for the 17 active core plate distance. It has to be greater than 18 12.2 inches, and this is for Westinghouse plants now.
19 And the average core density has to be less than 124 20 megawatts per cubic centimeter and the heat generation 21 figure of merit has to be less than or equal to 68 watts 22 per cubic centimeter. And those parameters have all 23 been added in to the fuel design procedure.
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56 1 this has to be applicable for your final 30 years of 2 operation.
3 So those procedures were modified and as 4 you're probably aware from the timing that Mr. Neterer 5 presented in his opening remarks to the presentation, 6 we are in Year 30 of plant operations so that was done 7 just in time for the last few years --
8 CHAIRMAN SKILLMAN: Okay thank you, Eric.
9 Got it. Understand. Thank you.
10 MEMBER SCHULTZ: But it doesn't mean that 11 you've been operating with atypical fuel design 12 approaches.
13 MR. BLOCHER: Correct. As Mr. Hoehn 14 indicated, we use an in/out core loading sequence.
15 MR. HOEHN: Next slide. This next 16 licensee action item associated with measurement 17 techniques for our reactor vessel internals hold-down 18 spring height.
19 This specific issue is only for Type 304 20 stainless steel hold-down springs. We have Type 403 21 stainless steel springs and, thus, this issue is not 22 applicable to Callaway. That's been resolved. Next 23 slide.
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57 1 loss of fracture toughness due to thermal and 2 irradiation embrittlement for reactor vessel internal 3 components, specifically CASS, cast austenitic 4 stainless steel, martensitic or precipitate-hardened 5 steel, if our inspections are adequate.
6 We looked at MRP-191 and 227-Alpha. We 7 worked with our NSSS again and found no additional 8 components for Callaway.
9 We did identify two locations with CASS 10 components, bottom mounted instrument column 11 cruciforms, a small section at the top, and one offset 12 instrument column cruciform bolted to the underside of 13 the lower core plate and those will be addressed with 14 our current 227 inspection approach. Next slide.
15 This topic is associated with our 16 cumulative usage factors, our fatigue analysis for our 17 reactor vessel. We do have a section, ASME Section III 18 NG, reactor vessel and internal set, and as a result we 19 do have cumulative usage factors for the reactor vessel 20 internals.
21 We were requested how, we needed to 22 demonstrate how we're going to address that for the 23 period of extended operation and we have committed to 24 monitor and manage those cumulative usage factors and 25 the fatigue usage on those locations into the period of NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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58 1 extended operation under our existing fatigue 2 management program.
3 CHAIRMAN SKILLMAN: Explain to us what 4 actions you might take to manage the fatigue.
5 MR. HOEHN: Right now the approach for 6 managing the fatigue into the period of extended 7 operation, basic fatigue monitoring, counting of 8 transient cycle counting we believe at this point in 9 time based on our projections will be sufficient to 10 demonstrate that the current internal set of fatigue 11 analysis is appropriate into the period of extended 12 operation.
13 If we were to get into issues where the 14 transient accumulation or the transient severity was 15 outside of our original design basis, we would either 16 have to do a refined fatigue analysis or we would have 17 to look at a more drastic measure of replacement or in 18 accordance with ASME Section XI, for example.
19 CHAIRMAN SKILLMAN: How do you know your 20 cycle counting process is accurate?
21 MR. HOEHN: Understand. How do I know 22 that our cycle counting process is accurate? We have 23 a fatigue monitoring program, software installed at 24 Callaway, FatiguePro. We actually had that system 25 installed back in 1995 and we were one of the first NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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59 1 plants to have that system installed.
2 To support that input, we did a systematic 3 review of our historical plant transients prior to 1995 4 in coordination with Westinghouse at the time. In 5 support of the license renewal application, we 6 rebaselined the entire fatigue transients to date and 7 revisited that pre-1995 fatigue usage projections.
8 And, again, with Westinghouse structural 9 integrity internal plant staff we went through that in 10 systematic means and ensured that our cycle counting 11 today is accurate.
12 And moving forward, it's automated from our 13 plant computer system into our FatiguePro software and 14 then if a bad day were to happen, the plant computer were 15 to go down, we obviously have operator logs, the 16 corrective action program and other entries like that 17 that we can fill in the gaps if that were to happen.
18 CHAIRMAN SKILLMAN: So as you begin what 19 would be Day 1 of your PEO, your additional 20 after 20 2024, what will your CUF be approximately at that point?
21 MR. HOEHN: What will our CUF be at 22 approximately --
23 CHAIRMAN SKILLMAN: When you begin your 24 PEO.
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60 1 internals specifically?
2 CHAIRMAN SKILLMAN: Yes. You going to be 3 at 0.8 or 0.999, 0.99999?
4 MR. BARTON: Well, that's for the boron 5 injection nozzle. They're already there.
6 CHAIRMAN SKILLMAN: Well, let's let him 7 answer the question.
8 MR. BARTON: Is that the same as one? It's 9 --
10 MALE PARTICIPANT: No, no. You're going 11 to start your --
12 MALE PARTICIPANT: Obviously you hope to 13 start your PEO --
14 MR. HOEHN: It will be less than one.
15 CHAIRMAN SKILLMAN: And you would like to 16 start your PEO with some margin to get to the end of that 17 20 years. So where are you going to be approximately 18 on your internals when you begin Day 1 of your PEO, 19 right, and you support --
20 MR. LYNCH: Hi. My name's Brett Lynch 21 with WorleyParsons. We assisted with the license 22 renewal, license amendment request as well as the 23 baseline.
24 For these internal components, we can't 25 give you a specific valuation on that specific day. We NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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61 1 still rely on the design CUFs.
2 What we do know is that you're less than 3 your allowed number of transients so the amount of 4 margin wouldn't be on the CUF. It would be on the margin 5 to your design number of transients.
6 CHAIRMAN SKILLMAN: That translates into 7 your CUF.
8 MR. LYNCH: Yes.
9 CHAIRMAN SKILLMAN: Right. Understand.
10 So you're saying, hey, we think we got some running room 11 based on not having utilized all of our cycles.
12 MR. LYNCH: Correct.
13 CHAIRMAN SKILLMAN: Got you. All right, 14 thank you. Understand.
15 MEMBER SCHULTZ: So just let me add on a 16 question. So the analysis that has been done has not 17 taken credit for actual operation for the last 20 years?
18 MR. LYNCH: That is correct. It's based 19 only on design transients, not actual operation.
20 MEMBER SCHULTZ: Still. Okay.
21 MR. HOEHN: Correct and we have committed 22 to manage this, the internal set of cumulative usage 23 factors under a fatigue monitoring program into the 24 period of extended operation to ensure that we're 25 appropriate into future plant operations.
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62 1 MEMBER SCHULTZ: On the basis of that 2 approach versus taking credit for actual operation and 3 --
4 MR. HOEHN: Agreed. Yes, correct.
5 MEMBER STETKAR: When you did your 6 transient counts, and I didn't look at all the RAIs so 7 I don't know. That's why I'm asking. I'm assuming you 8 did a linear projection out to 60 years. Is that right?
9 MR. HOEHN: Correct.
10 MEMBER STETKAR: Okay. That's what most 11 people do. Did you develop any kind of histogram to 12 show historically how those transients, I mean, does it 13 look like linear projection is accurate or did you have 14 a lot more transients early in life?
15 MR. HOEHN: Yes.
16 MEMBER STETKAR: Do you have that 17 information?
18 MR. HOEHN: We had to develop histograms as 19 part of our baseline report and justify the linear 20 projection moving forward. And as is typical with most 21 plants, most of these transients occur early in plant 22 life.
23 MEMBER STETKAR: Most. Occasionally we 24 see that things are a little more flat. That's why I 25 was just curious.
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63 1 MR. HOEHN: Correct, yes.
2 MEMBER STETKAR: But you had that 3 information?
4 MR. HOEHN: Correct.
5 MEMBER STETKAR: Did you submit it to the 6 staff? Was it requested or not? I was just curious 7 because --
8 MR. HOEHN: I do not know that offhand. I 9 know it was, we did provide that during one of the 10 inspections. We discussed it.
11 MEMBER STETKAR: Okay, great. Thank you.
12 MR. HOEHN: Thanks.
13 MS. KOVALESKI: All right thank you, Mike.
14 The next open item pertains to ASME Code Class 1, 15 small-bore socket welds. This open item is frankly a 16 disappointment to us. We --
17 MR. BARTON: I'd like to meet the person 18 that did the counting from 2 to 19 to 77 to 23 to some 19 other number. Did he use common core math for this or 20 what?
21 (Laughter) 22 MR. BARTON: I'm totally confused how that 23 progression grew and I don't even know what the final 24 number is.
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64 1 socket welds.
2 MR. BARTON: Eighty?
3 MS. KOVALESKI: Yes.
4 MR. BARTON: Wow. A new number.
5 MEMBER STETKAR: A different number.
6 (Laughter) 7 MR. BARTON: Okay.
8 MALE PARTICIPANT: I gave up.
9 MS. KOVALESKI: Yes. This was a result of 10 miscommunication between the license renewal team and 11 our subject matter expert. We did not clearly 12 communicate that the scope of this program is piping 13 that is less than four inches and greater than or equal 14 to one inch.
15 And when the counting was first performed, 16 we used an ISI database, and due to the filtering on that 17 database, it excluded a number of one-inch welds and 18 that was the first number that we submitted, was 19.
19 During one of the on-site audits, one of our 20 staff engineers identified some welds that appeared to 21 be part of the scope and when we checked against our 22 original number we realized they weren't there. That 23 was when we first identified the program, I'm sorry, the 24 problem.
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65 1 on site for the audit and we told them we found four more.
2 That's how we get to 23. That was not a formally 3 communicated number. That was the point of discovery 4 on that.
5 We went back and recounted and then did an 6 independent validation of that count and ultimately we 7 ended up at our final number of 80.
8 MR. BARTON: You're going to inspect eight 9 of them?
10 MS. KOVALESKI: Correct. Correct. We 11 did take this error very seriously. It is in our 12 corrective action program. We performed an extended 13 condition review and as a result of that extended 14 condition review we did adjust the number of butt welds 15 also in this program.
16 MEMBER STETKAR: That's what I was going to 17 ask. How confident am I in, well, a number that I can 18 read on my screen here of 340 butt welds? Is that --
19 MS. KOVALESKI: I am 100 percent confident 20 in that number. The reason for that --
21 MEMBER STETKAR: That's good.
22 MS. KOVALESKI: The reason for that is our 23 extended condition review, we looked at the entire 24 application to determine where we had generated a sample 25 population and that narrowed it down to these two NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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66 1 categories.
2 At that point, when we revalidated the 3 number, we went back to the original design drawings and 4 performed a manual count on those. We did identify a 5 few more.
6 The reason the butt weld number was 7 adjusted is because the drawings had been updated 8 because there were plant modifications and so on and we 9 did add those into our ISI database. Although they are 10 outside of the scope for the ISI program, if ever we are 11 to reuse that database for this purpose, we want them 12 to match.
13 However, we recognize that the right thing 14 to do was to go back to the design drawings and we have 15 even gone so far as to document a formal engineering 16 evaluation so that if we ever have to develop this 17 population again there is a methodology that is written 18 there and that it has been independently validated and 19 we will not repeat this error again.
20 MEMBER STETKAR: Three hundred forty 21 versus 342 doesn't affect, for example, the 25 but it 22 could affect, you know, the information about the exact 23 locations of those welds could affect your sampling 24 criteria which is more what I'm, you know, which 25 are 25 you going to sample in terms of your estimated NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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67 1 susceptibility to failure?
2 MS. KOVALESKI: That's correct.
3 MEMBER STETKAR: So that's what I'm more 4 concerned with that about.
5 CHAIRMAN SKILLMAN: Sarah, let me pull 6 this string just a little bit more. You said you 7 finally went back to the design drawings. I can 8 appreciate the spirit behind that. Wouldn't you have 9 been better off going back to the as-builts?
10 MS. KOVALESKI: We did look at the full 11 population of drawings available to us to validate these 12 numbers and Jerry Doughty, our ISI engineer, I think can 13 elaborate a bit on the drawings reviewed.
14 MR. DOUGHTY: I'm Jerry Doughty, the 15 in-service inspection program owner. We did go back to 16 the construction drawings, the fabrication drawings to 17 confirm that count. Thank you.
18 CHAIRMAN SKILLMAN: Did you have images, 19 photographs that you could verify against your 20 drawings?
21 MR. DOUGHTY: No, I didn't run across any 22 photographs.
23 CHAIRMAN SKILLMAN: Thank you. Please 24 proceed. Thank you.
25 MS. KOVALESKI: All right, thank you.
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68 1 Next slide please. And Mike Hoehn will address the open 2 item related to RCS environment effect on fatigue.
3 MR. HOEHN: Thank you. This next topic is 4 associated with environmentally assisted fatigue 5 screening and how we address environmentally assisted 6 fatigue for the period of extended operation.
7 From GALL Rev 1 to GALL Rev 2, there was some 8 wording changes in the section around environmentally 9 assisted fatigue where we were required to demonstrate 10 that the NUREG/CR-6260 locations were bounding at 11 Callaway for the period of extended operation.
12 At that point in time, there was no 13 systematic means in existence to perform that 14 systematic screening of the components.
15 We, Callaway, worked with the Electric 16 Power Research Institute to develop a technical report, 17 a technical approach to screen our reactor coolant 18 system pressure boundary locations and come up with a 19 bounding set of sentinel locations that we could enter 20 into our fatigue monitoring program managed into the 21 period of extended operation. That technical report is 22 1024995.
23 This approach, some of the benefits of this 24 approach is it utilizes fatigue curves for each 25 material. It has a same level of rigor. We need to NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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69 1 make sure that the same level of rigor is applied 2 throughout the CUF locations, the locations being 3 managed.
4 An example of that would be making sure that 5 if you have an elastic-plastic and you have a linear 6 elastic on a component, that they're basically brought 7 down to the same level of rigor, that you compare them 8 both on a linear elastic approach.
9 Any transient lumping needs to be broken 10 down or reconciled in the screening process so, again, 11 you're consistent and you're uniform in your approach.
12 And we also wanted to evaluate each thermal 13 zone on its own merit. For example, our chemical and 14 volume control system contains multiple thermal zones.
15 You have the letdown, you have the alternate charge, you 16 have a normal charge, you have an auxiliary spray which 17 you can see unique transient sets.
18 We wanted to evaluate each of those 19 distinct thermal zones and come up with a bounding 20 sentinel location that we could manage into the period 21 of extended operation.
22 We went through the process with this 23 consideration here, which was in the original EPRI 24 report. We later backed off of this approach, but all 25 materials are evaluated on their own merit.
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70 1 One material in one thermal zone will not 2 bound another material in the same thermal zone and one 3 material in a thermal zone will not bound another 4 material in another thermal zone, so each of the 5 materials are evaluated on their own merit.
6 We came up with 22 locations, which is more 7 than the original NUREG/CR-6260 locations, and we will 8 be managing that into the period of extended operation.
9 In addition, when we refine our analysis, 10 when we review baseline, when changing evaluations are 11 performed, we revisit this analysis to ensure that those 12 22 locations are still bounding and we can manage those 13 into the period of extended operation.
14 CHAIRMAN SKILLMAN: Thank you for that 15 explanation. Let me ask a question. Sarah identified 16 Wolf Creek, Palo Verde, Diablo Canyon and South Texas 17 as other plants that you have been dealing with for life 18 extension. At least I believe that's --
19 MS. KOVALESKI: Those are --
20 CHAIRMAN SKILLMAN: It's the fifth STARS 21 plant for renewal. Would those plants have the same, 22 approximately the same number of sentinel locations?
23 Are you an outlier with those four other plants?
24 MR. HOEHN: Again, we're the first to apply 25 this methodology to evaluate the bounded nature of the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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71 1 NUREG/CR-6260 locations so --
2 CHAIRMAN SKILLMAN: So they'll probably 3 come looking to you to figure out what you did.
4 MR. HOEHN: And we had shared this 5 information with the industry in multiple fatigue 6 presentations in the industry and we're actively 7 engaged in the material liability to share the operating 8 experience.
9 Again, we're unique in the sense that we 10 were a rep to PWR and we were required to demonstrate 11 the bounding nature and we know that with our approach, 12 our 22 locations, we, per the process, we felt it was 13 appropriate to include all the NUREG/CR-6260 locations 14 so those are conservatively included. Some of those 15 could have screened out based upon the methodology but 16 we included that in that 22 count and will manage that 17 moving forward.
18 CHAIRMAN SKILLMAN: Thank you.
19 MEMBER SCHULTZ: Michael, I want to 20 appreciate the timing here. Was this work done in 21 response to a question from the staff or are you 22 providing this explanation as a result of the question 23 and --
24 MR. HOEHN: This approach was we felt we 25 needed, as a result of GALL NUREG-1801, we needed to NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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72 1 demonstrate to ourselves and to the regulator that we 2 had a bounding set of transients we could manage into 3 the period of extended operation. So we developed this 4 approach with EPRI in a proactive fashion to address 5 GALL Rev 2.
6 MEMBER SCHULTZ: Thank you. Appreciate 7 that.
8 CHAIRMAN SKILLMAN: Please proceed.
9 Thank you.
10 MS. KOVALESKI: Next slide please. At 11 this point we're transitioning somewhat. The next four 12 slides cover issues that have come up since issuance of 13 the SER with open items.
14 The first topic has to do with operating 15 experience related to clevis bolts. The request from 16 the staff was for us to address the similarity of 17 Callaway design to reported failures at another 18 domestic Westinghouse-designed PWR in 2010.
19 This operating experience did become 20 available to us a couple years ago and we did enter in 21 our corrective action program and had evaluated it.
22 Our design is different from the plant that experienced 23 the failures although the materials used are similar.
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73 1 identified any degradation or damage. We did provide 2 that information to the staff for their review. Next 3 slide.
4 CHAIRMAN SKILLMAN: Do you assign the 5 geometrical difference to basis, why you have not had 6 problems and others have?
7 MS. KOVALESKI: Mike, could you address 8 that?
9 MR. HOEHN: Your question is related to do 10 we attribute our lack of degradation to the geometry?
11 CHAIRMAN SKILLMAN: That's kind of what 12 that first bullet infers, clevis insert assembly 13 geometry different from design of plant with failures.
14 MR. HOEHN: Andrew, pull up Slide --
15 MALE PARTICIPANT: 116.
16 MR. HOEHN: 116 if you could.
17 MR. BURGESS: 116?
18 MR. HOEHN: Correct. Short answer, it was 19 a factor and the difference and we saw the degradation 20 if you know. This is our configuration. The clevis 21 bolts are on the interior of the clevis location.
22 The plant in question where the OE was 23 generated from, the clevis bolts are actually on the 24 outside face of the clevis. It's a completely 25 different configuration. The bolting pattern is NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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74 1 different and how the radial support key would contact 2 the clevis insert location where it would slide into 3 that is unique so the stresses would be different as a 4 result of our unique geometry.
5 CHAIRMAN SKILLMAN: Thank you.
6 MR. HOEHN: And, again, we did provide 7 inspections in last refueling outage, 2013, and saw no 8 degradation or damage.
9 CHAIRMAN SKILLMAN: Okay, thank you.
10 Back to 30 please.
11 MS. KOVALESKI: Next slide please. The 12 next three topics cover generic questions, also cover 13 generic questions asked of applicants.
14 This one has to do with an ISG-2012-02 which 15 covered aging management of internal surfaces, fire 16 water systems, atmospheric storage tanks and corrosion 17 under insulation.
18 We implemented this ISG. Some of the 19 changes that we've made is that we recognize that 20 additional aging management is needed for recurring 21 internal corrosion in raw water environments.
22 We have also recognized that the fire water 23 aging management program will be revised to be 24 consistent in applicable portions to NFPA 25 25 requirements.
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75 1 We'll be making some changes, we did make 2 some changes to our aboveground metallic tanks aging 3 management program and outdoor insulated components and 4 indoor insulated components that are exposed to 5 condensation will have that insulation removed so that 6 we can perform inspections of that external surface.
7 This ISG has been implemented and we have provided that 8 to the staff for their review.
9 CHAIRMAN SKILLMAN: Okay, and this is 10 insulation removed for inspection and then replaced to 11 maintain insulation?
12 MS. KOVALESKI: That's correct. It's for 13 inspection purposes only.
14 MR. BARTON: I have a question on your fire 15 water storage tank. I think you had some internal 16 problems with that. I can't think of that right now.
17 But the concern I have is it apparently is 18 set on a sand base. The bottom of the tank is set in 19 sand. I've had experience with tanks like that that 20 develop leakage, I mean, because there's something 21 that's in the sand eats through, whatever. Have you 22 ever done a UT inspection of the bottom of that tank?
23 MS. KOVALESKI: I think Lee Eitel could 24 address that please.
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76 1 engineering. We have not performed a ultrasonic test 2 to date. However, later this year we will be recoating 3 the interior of those fire water tanks and as a part of 4 that work evolution we will be performing some 5 ultrasonic testing of that fire water tank.
6 MR. BARTON: Thank you.
7 MEMBER BALLINGER: That kind of leakage, 8 corrosion from the bottom is very common in the oil 9 industry.
10 MR. BARTON: Yes.
11 MEMBER BALLINGER: One of the most common 12 problems with tanks.
13 MR. BARTON: Right, because use oil-based 14 sand. It's something in the --
15 MEMBER BALLINGER: Yes, yes.
16 MR. BARTON: That eats through the bottom.
17 MEMBER STETKAR: While we're on fire 18 systems, might as well get a couple of off-the-wall 19 questions out of the way and I'll try to keep them short.
20 There's some discussion of -- and obviously 21 there have been problems with the fire water systems.
22 It was noted that in flow tests that you did in 23 2009/2011, you initially didn't pass the flow tests but 24 you managed to be able to sharpen your pencils enough 25 and check off the box and, indeed, you passed those tests NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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77 1 which you didn't have to sharpen your pencil before that 2 so that's indication of degradation.
3 You've committed, I believe, to instead of 4 doing the testing at three-year intervals to perform the 5 tests every two years to see if there's any trend going.
6 The thing I wanted to ask about though is 7 at least the information I could read said that the next 8 flow test, again from the documentation I have, is 9 scheduled for 2013. So I'm curious. How did you do in 10 2013 with your flow test?
11 MS. KOVALESKI: Lee.
12 MR. EITEL: Yes, Lee Eitel again. We did 13 have some reduced flow in the 2013 test as well. The 14 next test for the two-year frequency will be next year 15 in 2015. We do still have margin with our flow results, 16 even with the results we received in 2013.
17 MEMBER STETKAR: I don't know how one does 18 the pencil sharpening for the calculations so did you 19 have to sharpen the pencil more than you did in 2011 to 20 show that you passed or -- in other words, apparently 21 in 2009/2011 you had to get a bit creative in terms of 22 defining what success was. Did you keep the same 23 definition of success and still meet the criteria or did 24 you have to get more creative in 2013?
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78 1 2013. The original change --
2 MEMBER STETKAR: But showed reduced margin 3 compared to 2011?
4 MR. EITEL: Correct. Correct.
5 MEMBER STETKAR: Okay, okay. That's not 6 necessarily okay but at least I understand.
7 MS. KOVALESKI: The next issue that we'd 8 like to cover is issuance of draft ISG-2013-01. This 9 covered loss of coating integrity for Service Level III 10 and other coatings.
11 Through RAIs the majority -- I'm sorry.
12 This draft ISG has been implemented into our license 13 renewal application. We will be visually inspecting 14 in-scope coatings that are installed in accessible 15 interior surfaces and have criteria established for 16 modifying that inspection frequency based on the 17 results of those inspections.
18 The inspection of coatings will be 19 performed by trained and qualified personnel in 20 accordance with ASTM standards that are endorsed in Reg 21 Guide 1.54.
22 MR. BARTON: Service Level III, does that 23 include the containment liner or not?
24 MS. KOVALESKI: Containment coatings are 25 Service Level I.
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79 1 MR. BARTON: All right. Okay. Question 2 on that is you have experienced during outages 3 inspection of that liner some coating failures. Now, 4 I don't know whether that's in certain areas or whether 5 it's random around the surface of the containment.
6 Which is it?
7 The reason I'm asking, it appears that you 8 haven't done anything with it except scrape off the 9 loose paint or something so I'm trying to figure out 10 what's your program on maintaining the integrity of the 11 containment liner, the painting?
12 MS. KOVALESKI: Justin Stollhans is our 13 coatings engineer. He can elaborate a bit on our 14 containment coatings inspections.
15 MR. STOLLHANS: This is Justin Stollhans.
16 I'm the coating engineer. We do perform a coatings 17 inspection of the containment liner every refueling 18 outage. We do identify locations in which the coating 19 has been degraded. We remove those coatings and we do 20 not repair them. We remove the coatings and --
21 MR. BARTON: Well, what do you find?
22 Bubbles or paint flaking off, peeling or what's the 23 nature of the deficiency?
24 MR. STOLLHANS: They're normally, the 25 indications are long striations approximately the width NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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80 1 of a pencil or your pinky finger, very linear.
2 MR. BARTON: How long?
3 MR. STOLLHANS: They depend. Some are 4 couple inches. Some may be few feet.
5 MR. BARTON: May be what?
6 MR. STOLLHANS: May be a few feet.
7 MR. BARTON: Few feet. Now, do you have a 8 program for repairing these at some point or what's the 9 program? You look at these things and do what? You put 10 them down in a log someplace and say I found some more 11 during this outage?
12 MR. STOLLHANS: Yes, we --
13 MR. BARTON: What's your program for 14 maintaining the proper painting integrity of the liner?
15 MR. STOLLHANS: We would track them and 16 then reinspect them on our inspection every refuel and 17 then we have yet to see any degradation in these 18 locations.
19 MR. BARTON: You do what?
20 MR. STOLLHANS: We have yet to see any 21 degradation on these locations of the liner.
22 MR. BARTON: So you don't have any paint 23 flaking off?
24 MR. STOLLHANS: The paint, yes, the paint.
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81 1 shiny carbon steel or whatever?
2 MR. STOLLHANS: In most cases --
3 MR. BARTON: Or is it all rusted? What's 4 the condition of the liner now?
5 MR. STOLLHANS: It is not rusted. In most 6 cases the primer is still intact.
7 MR. BARTON: The primer is intact?
8 MR. STOLLHANS: Yes.
9 CHAIRMAN SKILLMAN: Have you found where 10 the primer is not intact?
11 MR. STOLLHANS: I am not aware of any 12 indication, so.
13 CHAIRMAN SKILLMAN: Are those indications 14 in your corrective action program?
15 MR. STOLLHANS: Yes.
16 CHAIRMAN SKILLMAN: Each one has a serial 17 number or has a name tag?
18 MR. STOLLHANS: We do not track them 19 individually, no.
20 CHAIRMAN SKILLMAN: So how do you know that 21 one from one outage to the next hasn't grown or changed?
22 MS. KOVALESKI: The results of the 23 inspections are we don't log each individual occurrence 24 but we'll enter one corrective action program entry for 25 those inspection results and then during the subsequent NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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82 1 inspections those previous images are printed out.
2 I have observed our coating engineers 3 preparing for those inspections and they go print out 4 the previous pictures of the indication so that they can 5 have them with them during those inspections.
6 CHAIRMAN SKILLMAN: So they do have a 7 unique ID so that an individual can go back to that same 8 place and understand what has changed?
9 MS. KOVALESKI: Yes, they are logged. I 10 couldn't speak to exactly how they are ID'd and logged 11 but, yes, we have a way of tracking based on the 12 position, the azimuthal position within the containment 13 and height as to which indication is which.
14 CHAIRMAN SKILLMAN: My expectation is 15 driven by having been at a number of plants where each 16 and every spot of boric acid or each and every coating 17 deficiency has its own unique ID.
18 And then an engineer, the program engineer 19 is then accountable to keep track of each and every one 20 of those until the boric acid is no longer there or until 21 the holiday in the coating has been repaired. So I'm 22 assuming you must have something similar to that.
23 MS. KOVALESKI: We'll have to get back to 24 you with our exact tracking of it.
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83 1 think John Barton's question's a very good question.
2 MS. KOVALESKI: Yes, we'll get back to you 3 with that.
4 CHAIRMAN SKILLMAN: Thank you. Okay.
5 MEMBER STETKAR: As long as we're on the 6 liner, your good news is you don't have to inspect the 7 moisture barrier seal at the liner penetration of the 8 concrete in the containment floor because you don't have 9 a moisture barrier seal. Do you have any pictures in 10 your backup slides of that gap or that configuration?
11 The basic question is if you don't have a 12 moisture barrier seal, how do you know you don't have 13 corrosion occurring in that area below the concrete 14 floor in the liner?
15 MR. BARTON: They said they have a fill 16 plug or something which I don't understand.
17 MEMBER STETKAR: Oh, I didn't see a fill 18 plug.
19 MR. BARTON: Where did I see that?
20 MEMBER STETKAR: Where did you find that?
21 MR. NETERER: We do have a photo we're 22 going to pull up for you.
23 MS. KOVALESKI: Yes we do. Yes we do.
24 (Off microphone discussion) 25 MALE PARTICIPANT: Okay, there we go.
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84 1 MR. JOHNSON: Hi, I'm Jim Johnson. I'm 2 the lead engineer and I can speak to this. This is a 3 picture of the interface between the liner and the 4 concrete slab.
5 MEMBER STETKAR: Good.
6 MR. JOHNSON: You can see there, there 7 isn't a moisture barrier but there is no gap.
8 MEMBER STETKAR: That's what I was looking 9 for. Is that inspected every refueling outage to make 10 sure that there hasn't been, you know, swell type 11 openings of a gap?
12 MR. JOHNSON: There are actually three 13 different aging management programs that look at that 14 interface. Monitoring looks at the concrete, IDBE 15 looks at the liner and the coatings inspection every 16 outage looks at the coatings.
17 MEMBER STETKAR: Fine. Thank you.
18 (Crosstalk) 19 MALE PARTICIPANT: Yes, you don't want me 20 to take up more time anyway, so.
21 CHAIRMAN SKILLMAN: Is that a fire line?
22 MALE PARTICIPANT: Pardon me?
23 CHAIRMAN SKILLMAN: Is that a fire line?
24 MS. KOVALESKI: In the photo it is conduit.
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85 1 picture.
2 CHAIRMAN SKILLMAN: Okay, thanks.
3 MR. JOHNSON: This was during an outage.
4 We think that red one is some kind of a temporary water 5 area or something for an outage. It looks like 6 electrical conduit as best we can determine.
7 CHAIRMAN SKILLMAN: Okay, thank you. All 8 right.
9 MS. KOVALESKI: All right. Thank you, 10 Andrew. Moving on to the next slide.
11 CHAIRMAN SKILLMAN: 33, okay.
12 MS. KOVALESKI: Slide 33, yes. This topic 13 has to do with submerged bolting and the request from 14 the staff was for us to identify our method of detecting 15 loss of material and loss of preload in submerged 16 bolting.
17 For Callaway this affected five systems, 18 essential service water where we will be inspecting our 19 stainless steel bolts on a six-year sample basis and 20 testing quarterly for pump performance, our emergency 21 diesel generators where the fuel oil transfer pump bolts 22 will be inspected on a ten-year sample basis and also 23 tested periodically, the service water pump bolting 24 which is replaced entirely during pump refurbishment on 25 a six-year basis and waste water pump bolting. There NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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86 1 are two systems in there, oily waste system and our floor 2 and equipment drain systems and that bolting will be 3 inspected on a six-year sample basis.
4 MR. BARTON: Is this bolting underwater, 5 it needs a diver to work on it? Or is it all above water, 6 or what? DSW and service water pump bolting?
7 MS. KOVALESKI: Eric, could you please 8 elaborate on the details?
9 MR. BLOCHER: Yes, the ESW bolting are on 10 the ESW pumps, which are submerged pumps in the intake 11 bay. The diesel generator fuel oil are pumps that are 12 submerged in the fuel storage tanks.
13 And service water pump is similar to the ESW 14 pump, only it's on the non-safety service water system.
15 And the waste water pumps, for the most part they're 16 submerged. That varies with the sump level and the 17 waste water.
18 CHAIRMAN SKILLMAN: For the bolting that 19 is in the intake bay, I assume that the surrounding water 20 is the Missouri River? That accurate?
21 MR. WINK: For our central service water 22 system, it sits in our ultimate heat sink water, which 23 ultimately is clarified Missouri River water.
24 MALE PARTICIPANT: He asked about the 25 intake, though.
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87 1 CHAIRMAN SKILLMAN: Eric said it's at the 2 intake structure.
3 MR. BLOCHER: The ESW is as Mr. Wink has 4 described.
5 CHAIRMAN SKILLMAN: Okay. What I was 6 going to ask is is the chemistry of the Missouri River 7 adverse to that bolting?
8 MR. BLOCHER: It's not in scope.
9 MS. KOVALESKI: The bolting that is in the 10 scope of this program is not at our intake structure at 11 the river. Mr. Blocher, I think, was referring to where 12 our central service water pumps are installed, the 13 bolting at the intake of those pumps.
14 CHAIRMAN SKILLMAN: I see, so it's up at 15 the site at the pond --
16 MR. NETERER: The ultimate heat sink pond.
17 CHAIRMAN SKILLMAN: -- at the heat sink 18 pond?
19 MR. NETERER: Correct.
20 CHAIRMAN SKILLMAN: Okay.
21 MR. BLOCHER: Eric Blocher, that's one 22 clarification we want to make. Early on there may have 23 been some confusion where we're talking about the river 24 intake structure. That structure is not within scope 25 of license renewal.
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88 1 MR. BARTON: So that means what, you don't 2 look at it or you don't care, or what? You have to have 3 some kind of thought about it. What's in the intake 4 structure that you got to worry about? What 5 equipment's in there?
6 MR. BLOCHER: It would probably be good to 7 go back to the site picture and explain the ESW intake 8 structure and the 30 day water supply that is used.
9 MALE PARTICIPANT: Slide 8 I think.
10 MR. NETERER: Okay, let me explain this.
11 The river picture that we showed you, that is not in 12 scope. That draws water up to the plant. It goes 13 through a water treatment system.
14 And that water goes to the cooling tower, 15 and it also can be used for make up to the alternate heat 16 sink pond. The intake that he, that Mr. Blocher was 17 talking about is a pump house on the ultimate heat sink 18 pond. Those are in scope. And that's the bolting we're 19 talking about here.
20 MR. BARTON: Okay.
21 MR. NETERER: Okay? And we did change 22 those out from carbon steel to stainless steel several 23 years ago for AG management purposes.
24 CHAIRMAN SKILLMAN: We worked at a plant 25 where the intake structure problem was the spiders.
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89 1 The spiders could eat the bolts. The spiders needed 2 name tags. They were visiting on the Susquehanna 3 River. So we've got some real understanding about risk 4 phenomenon. Okay, next slide, please?
5 MS. KOVALESKI: All right. Next slide, 6 please. At this point, I would like to turn it over to 7 Mr. Neterer for closing remarks.
8 MEMBER SCHULTZ: Before we do that, I did 9 want to go back to one question associated with the 10 bolts, the stud work. And then we heard that it would 11 most likely be planned, or is planned to be done in 12 refueling out as 23, is that what it says? Four and a 13 half years you mentioned, Dave.
14 MS. KOVALESKI: Excuse me, you're talking 15 about the reactor height closure studs, stud 18?
16 MEMBER SCHULTZ: Stud 18, stud 18.
17 MS. KOVALESKI: Okay, okay. Okay, not 18 submerged bolting.
19 MEMBER SCHULTZ: Back to that issue.
20 MS. KOVALESKI: I understand.
21 MEMBER SCHULTZ: That's correct. And I 22 was wondering whether the stud holes were going to be 23 inspected at that same time?
24 MS. KOVALESKI: The stud holes are 25 inspected every outage.
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90 1 MEMBER SCHULTZ: The six that we were 2 talking about --
3 MS. KOVALESKI: They are all inspected --
4 MEMBER SCHULTZ: -- the detailed 5 inspection.
6 MS. KOVALESKI: They are visually 7 inspected --
8 MEMBER SCHULTZ: Right.
9 MS. KOVALESKI: -- every outage. And they 10 are also in the scope of our RSI program. The laser 11 mapping will be performed at the same time that we remove 12 the stud so that we can also inspect the stud that's 13 being removed.
14 MEMBER SCHULTZ: Have the equipment there 15 to do the work --
16 MS. KOVALESKI: That's right.
17 MEMBER SCHULTZ: -- at that time.
18 MS. KOVALESKI: That's right.
19 MEMBER SCHULTZ: I appreciate that. And I 20 also recall hearing earlier in the presentation that 21 this was not considered to be an aging problem because 22 it happened early in the life of the plant.
23 But I think in the spirit of aging 24 management license renewal, that it's good to get this 25 taken care of, moving forward. So I appreciate that, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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91 1 thank you.
2 MS. KOVALESKI: Thank you, we agree. That 3 was an important learning for us during this process.
4 CHAIRMAN SKILLMAN: Dave, back to you.
5 MR. NETERER: Thank you, Mr. Chairman.
6 Callaway plant is a learning organization. One of the 7 key learnings in the last seven years going through this 8 process is we must learn to operate the plant 9 differently for the next 30 years than we have the 10 previous 30 years, particularly in the area of aging 11 management.
12 We have institutionalized and internalized 13 the aging management concept and principles through 14 several things like training, corrective action 15 program, operating experience, and our strong program 16 owners. They've really grown into this aging 17 management concept.
18 You can see our subject matter experts, a 19 lot of these folks here are really new to Callaway in 20 that last seven year period. So we've got a lot of 21 younger people coming in.
22 And for them, aging management's not a new 23 program. It's a way of life for them to help carry that 24 on in the next 30 years of operation. So it's really 25 good to see these young folks getting involved in this.
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92 1 So I would just like to thank the committee, 2 thank you Mr. Chairman for listening to our 3 presentation. And thanks for the challenges. You 4 gave us a couple things to go back and prove our programs 5 on aging management to think about today.
6 CHAIRMAN SKILLMAN: Thank you.
7 Colleagues, any other questions?
8 MR. BARTON: I've got a question.
9 CHAIRMAN SKILLMAN: Yes sir, John?
10 MR. BARTON: Fuel oil chemistry program, 11 in your response to an RAI regarding inability to drain 12 and clean the diesel generator, fire pump, oil day tank, 13 and the security diesel generator, fuel oil day tank due 14 to limited access, do you propose to periodically 15 sample, you didn't say what frequency, the tanks to 16 ensure there's no evidence of corrosion.
17 Question I got, if you can't drain and clean 18 these tanks, how do you change the oil in them? Or don't 19 you?
20 MR. BLOCHER: I just want to clarify, to 21 clean the tanks requires physical access into the tanks.
22 And the biggest opening, I believe, on the security tank 23 is the order of magnitude of, like, a one inch or two 24 inch connection. The piping would have to be removed 25 from it.
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93 1 MR. BARTON: Right. Okay.
2 MR. BLOCHER: So we physically cannot get 3 in there. Many of the tanks do have connections that 4 would allow draining down to the bottom of the tank. But 5 again, that physical access for physical cleaning of the 6 tank is not possible.
7 MR. BARTON: So you have the ability to 8 drain and put oil in, but you can't get access to inspect 9 it or clean it?
10 MR. BLOCHER: Correct.
11 MR. BARTON: Okay. That's about it.
12 CHAIRMAN SKILLMAN: John? Ron?
13 MEMBER BALLINGER: Good 14 CHAIRMAN SKILLMAN: Steve?
15 MEMBER SCHULTZ: No, thank you.
16 CHAIRMAN SKILLMAN: Ladies and gentlemen, 17 we will take a 15 minute break. We will resume at 3:30, 18 15:30 on that clock.
19 (Whereupon, the foregoing matter went off 20 the record at 3:12 p.m. and went back on the record at 21 3:29 p.m.)
22 CHAIRMAN SKILLMAN: We are back in 23 session. Ladies and gentlemen, Ameren has a response 24 from some questions that we asked, and I would like to 25 give them an opportunity please to respond, to take one NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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94 1 or two minutes here, please.
2 MR. WINK: Yes, my name is Roger Wink, 3 supervising engineer of the license renewal project. We 4 had a question earlier about our containment coatings 5 and how we track those individual items.
6 We do not assign specific location IDs to 7 the defects that we may find in our containment liner.
8 They are entered in our corrective action system. They 9 are identified by location and height off the floor as 10 met the around containment such as that.
11 And they are also tracked in the specific 12 job that we would write against those location and also 13 the program notebook for our coatings program.
14 CHAIRMAN SKILLMAN: Thank you.
15 MR. WINK: Yes.
16 CHAIRMAN SKILLMAN: Thank you very much.
17 That ends that portion of our business. I now call upon 18 John Lubinski to lead the NRC portion, please.
19 MR. LUBINSKI: Thank you, Chairman. What 20 we hope to cover this afternoon is our portion of the 21 review. As I said earlier, the SER with open items was 22 issued in April of 2013. We did have a May 12th memo 23 this year that discussed the status of the open items, 24 as well as some additional issues that we were 25 addressing.
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95 1 Let me introduce the NRC staff that will 2 address these this afternoon. John Daily is the 3 Project Manager for Callaway. He will be doing our 4 presentation this afternoon.
5 He is assisted at the front table by Dr.
6 Allen Hiser, our Senior Level Adviser and Daneira 7 Melendez who is our Project Manager within our division.
8 And we have other folks in the audience who will help 9 participate.
10 We do have on the phone line, and I'm going 11 to do a check here, Greg Pick at Region IV. Greg, did 12 you join us on the phone line? Okay, we still have a 13 problem locating Greg. What we'll do is when we get to 14 that --
15 MR. PICK: John.
16 MR. LUBINSKI: Greg, you're there.
17 MR. PICK: I have been here.
18 MR. LUBINSKI: Great, okay. Welcome.
19 You've been here already. So when we get to your part, 20 you'll hear John Daily introduce you. Thank you. With 21 that, I would like to turn it to John Daily and have him 22 do the presentation.
23 MR. DAILY: Thank you, John. Good 24 afternoon Chairman Skillman and members of the ACRS 25 License Renewal Subcommittee. My name's John Daily, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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96 1 I'm the License Renewal Project Manager for Callaway 2 Plant Unit 1 license renewal safety review.
3 We're here today to discuss the review of 4 the Callaway license renewal application as documented 5 in the Safety Evaluation report with open items issued 6 in April of 2013.
7 And John Lubinski already introduced 8 everyone so we can skip with that part. And of course, 9 we have other staff members and reviewers in the 10 audience which might be able to shed some light on things 11 as we progress. Next slide.
12 Today we will present a general overview of 13 the staff's review and then we'll discuss the main 14 sections and the issues presented in the staff's SER as 15 shown here. Greg Pick, in a few minutes, will present 16 the results from the Region 4 on site inspection. Next 17 slide.
18 This slide's provided for information 19 only. The applicant has covered all the points that are 20 presented here. And we also discussed what led us up 21 to a May 2014 Subcommittee date.
22 I know there were several schedule changes.
23 During those schedule changes however, the staff has 24 continued to work on the open items and the other issues 25 as they have arisen.
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97 1 We have been issuing requests for 2 additional information, holding conference calls with 3 the applicant, and receiving supplemental information 4 from them on these issues in order to make sure that we 5 have resolution paths for each one of them. Next slide.
6 The staff conducted several on site audits 7 and inspections for the application as shown here on the 8 slide. During the scoping and screening methodology 9 audit, the audit team reviewed the applicant's 10 administrative controls governing the scoping and 11 screening methodology and the technical basis for 12 selected scoping and screening results.
13 The staff also reviewed selected examples 14 of component material and environment combinations, 15 reviewed information contained in the applicant's 16 corrective action program that was relevant to plant 17 specific age related degradation, reviewed quality 18 practices that were applied during the development of 19 the application, and reviewed the training of personnel 20 who participated in the development of the LRA.
21 During the aging management program audit, 22 a team of over 35 reviewers examined Ameren Missouri's 23 aging management programs and related documentation to 24 verify applicant claims of consistency with the 25 corresponding AMPs in the GALL report.
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98 1 The staff reviewed 42 AMPs and documented 2 the results in an audit report that was dated August 9th, 3 2012. And I believe you have a copy of that, Mr.
4 Chairman, that we provided earlier.
5 Finally, Region IV conducted its regional 6 inspection from September 10th, 2012 through November 7 7th, 2012. And as we said, we'll present those results 8 here shortly. Next slide.
9 In addition to the audits and inspections 10 already mentioned, the staff conducted in depth 11 technical reviews and issued requests for additional 12 information, or RAIs. Staff completed its initial 13 review of the Callaway license renewal application with 14 the exception of five open items and issued the Safety 15 Evaluation report with open items on April 23rd, 2013.
16 Subsequent to issuing the SER with open 17 items, some other items did arise, and we'll deal with 18 those towards the end of the slide presentation.
19 CHAIRMAN SKILLMAN: John, let me just 20 exercise a little bit of prickliness here. Would it be 21 accurate to say that those several items that came on 22 to our agenda were really known before the SERI was 23 issued? Our belief is that they probably were.
24 MR. DAILY: Well I can't speak directly to 25 that, Mr. Chairman, because I wasn't project manager at NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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99 1 the time. But I do know that within our division, 2 generally speaking, issues like this arise as an issue 3 at one or two plants first, then we notice that it's 4 something that needs to be developed generally.
5 And then at some point we decide to develop, 6 for example interim staff guidelines. During that 7 process, which was happening at the same time the SER 8 with open items was prepared, there are times when 9 information comes in after a cutoff date.
10 And I believe that was the case in at least 11 two of these items. Now the third one actually resulted 12 because of components that were added in August of 2013, 13 which about four months after the SER with open items 14 was issued.
15 So as things are going through the process, 16 there is a cutoff date that we have to do in order to 17 present information in the SER. So I'm pretty sure that 18 those particular ones with the two ISGs probably evolved 19 in that fashion.
20 CHAIRMAN SKILLMAN: Thank you.
21 MR. DAILY: Thank you. So as we 22 mentioned, two of the items that were the other ones that 23 arose, they came about as the result of this interim 24 staff guidelines.
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100 1 about, the submerged bolting which the applicant had 2 already initially covered, that actually came up as new 3 components that were added to the scope of license 4 renewal after the SER was issued. So that's one of the 5 reasons why it comes up the way it did.
6 Pending resolution now of these open items 7 and the outstanding RAIs, our plan as a staff is to issue 8 Callaway's final SER in September of this year, and in 9 order to support, you know, the remaining parts of the 10 schedule.
11 Let's now turn the presentation over to 12 Greg Pick, the Region IV Inspection Team Leader on the 13 phone. And Greg will discuss the license renewal 14 inspection. Greg?
15 MR. PICK: Thank you, John. Can everyone 16 hear me?
17 MR. LUBINSKI: Yes, we can hear you loud 18 and clear.
19 MR. PICK: Good afternoon members of the 20 subcommittee. As an overview of the inspection, we had 21 five --
22 MR. LUBINSKI: Hey Greg? Greg?
23 MR. PICK: Yes?
24 CHAIRMAN SKILLMAN: Greg, this is Nick 25 Skillman. We can hear you loudly and clearly. Would NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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101 1 you please back away from your microphone or from 2 whatever instrument you're using because we're getting 3 a double take and you're cutting out.
4 MR. PICK: Is this any better?
5 CHAIRMAN SKILLMAN: It is.
6 MR. PICK: I'll just talk normal then.
7 CHAIRMAN SKILLMAN: Thank you.
8 MR. PICK: Five inspectors had experience 9 and expertise related -- mechanical systems and 10 components -- electrical systems and components --
11 CHAIRMAN SKILLMAN: Greg, you're still 12 breaking up. Are you on a speaker phone?
13 MR. PICK: Not anymore.
14 CHAIRMAN SKILLMAN: That's better.
15 MALE PARTICIPANT: That's much better.
16 CHAIRMAN SKILLMAN: Just speak in normal 17 tone, I think you'll be all right.
18 MR. PICK: The scoping inspection was 19 concerned with reviewing for proper disposition of 20 components included in scope, and review of the excluded 21 items to verify appropriate determination of non-safety 22 related components affecting safety related 23 components.
24 The aging management programs inspected, 25 we reviewed seven new programs and 16 existing programs.
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102 1 Next slide, please.
2 The team identified several issues, and 3 these are all discussed in our inspection report. Some 4 of the more significant ones are presented here to 5 illustrate. For the condensate storage tank, the team 6 identified that two of ten installed inaccessible 7 anchor bolts did not have minimum thread engagement in 8 accordance with ANCB 11 and the Callaway bolting manual.
9 The applicant demonstrated that the 10 condensate storage tank could perform its design 11 function with only 37 of the 56 bolts installed, and this 12 lack of thread engagement did not render the tank 13 inoperable.
14 The applicant planned to upgrade the 15 cathodic protection sections for the buried piping in 16 2015 as they've already discussed. They would complete 17 this modification nine years prior to entering the 18 period of extended operation.
19 Their coatings and backfill were in good 20 condition and consistent with the GALL report 21 recommendations. This reduces the number of buried 22 piping excavations to a single inspection each ten year 23 period.
24 For the emergency fuel oil storage tank, 25 plan operating experience described coating blisters in NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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103 1 the Train A tank. However, from review of the 2 inspection records, the team determined that the 3 applicant did not know the exact number or location, and 4 had not tracked or trended whether these blisters had 5 grown.
6 Following questions from the team, the 7 applicant committed to repair and evaluate the blisters 8 in the Train A tank during their next ten year 9 inspection, which will occur prior to entering the 10 period of extended operation, and the licensee 11 submitted a revision to their license renewal 12 application.
13 CHAIRMAN SKILLMAN: Greg, let me ask you a 14 question. I'm on your inspection report, your Page 24.
15 To what extent, when you found this item relative to the 16 blisters in the fuel oil storage tank, did you chase the 17 licensee's actions relative to the fuel oil filters, and 18 what did they find?
19 MR. PICK: We did not address the fuel oil 20 filters. So I cannot answer the question. But nothing 21 in their corrective action program indicated they had 22 any problems with their fuel oil filters. We did look 23 through their corrective action program documents.
24 CHAIRMAN SKILLMAN: I'm thinking blisters 25 is probably material wastage? And the consequence of NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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104 1 the wastage is some form of buildup on the filters, 2 unless of course the filters are changed out once a year 3 or once every six months or on some frequency that 4 precludes any buildup from effecting operability of the 5 diesel engines.
6 MR. PICK: Along those lines, and they 7 would better be able to address this, but during our 8 discussion on site, they believed the blisters were due 9 to original application of the coating and poor 10 adhesion. But they couldn't prove that to the 11 inspection team.
12 So when they go in and inspect it, they're 13 going to remove the blisters to see if it was an adhesion 14 problem, and then do a repair.
15 CHAIRMAN SKILLMAN: Thank you, Greg.
16 MR. PICK: Related to the buried piping, 17 there were several, I'm going to use the phrase 18 deficiencies as an inspector. But there were 19 enhancements required for their procedures.
20 Their buried and piping program engineers 21 collected a soil sample as required. They did not keep 22 it cool, so the bacteria would not remain alive for 23 testing. That was a recommendation, to cool the 24 samples when you take them.
25 Some other identified recommendations, the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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105 1 low voltage holiday testing on newly applied coatings.
2 There were inconsistencies on the environmental 3 conditions, when to apply a primer related to the 4 temperatures when you did the inspection.
5 One part of the procedure said below 6 freezing, one part of the procedure said ten degrees 7 Fahrenheit. They got with the vendor and corrected 8 that in their procedure. It's any temperature below 40 9 degrees.
10 And at that time, the coatings engineer was 11 not always called out to do an inspection. Now the 12 coatings engineer will be called out to do a visual 13 inspection versus sent photographs a couple days later.
14 Because of the long delay, I've already reviewed the 15 procedure and they've already implemented these 16 enhancements. Next slide, please.
17 MR. BARTON: Hey Greg. Well hold up, hey 18 Greg? John Barton here.
19 MR. PICK: Yes, sir.
20 MR. BARTON: On piping, buried piping 21 procedure, in your inspection report it was noted, 22 "Photographs of buried piping showed that pipe 23 wrappings were not adhered to some piping. The 24 applicant stated that had it been safety related piping, 25 they would have replaced the wrapping."
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106 1 Now I don't know if you are familiar with 2 that, what the piping was. My concern is I don't care 3 whether it's safety related or not, but I'm going for 4 another 20 more years and I've got buried piping that's 5 not protected, I would probably worry about that and do 6 something about it.
7 But I don't know what the system is. Do 8 you? Is that familiar with you? It was in your 9 inspection report.
10 MR. PICK: If I recall, it was a fire water 11 piping. And it was fire water piping going to a 12 building outside the protected area fence.
13 MR. BARTON: So I don't care about that, 14 right?
15 MR. PICK: That's correct.
16 MR. BARTON: Okay.
17 MR. PICK: That is in fact clear in the 18 report, but that's the point being made.
19 MR. BARTON: So if that piping develops a 20 leak, it doesn't affect the rest of the fire protection 21 system? That piping can burst open and there's no 22 problem?
23 MR. PICK: If it had burst open and they had 24 a fire and needed to fight the fire, the furthest away 25 sprinkler they have sufficient capacity.
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107 1 MR. BARTON: Okay. All right, that 2 answers my concern. Thank you.
3 MR. PICK: You're welcome. So for my 4 final slide, Slide 8 please. The inspection concluded, 5 the team concluded they would properly scope a 6 non-safety structure system and components in the 7 application of the aging management programs to those 8 structure system and components were acceptable. So in 9 all locations, non-safety would not affect safety.
10 And the team concluded that reasonable 11 assurance existed that aging effects will be managed and 12 attended functions maintained for the period of 13 extended operation. This concludes my formal 14 presentation. Any additional questions?
15 MR. BARTON: Yes, this is John Barton 16 again. Your team did inspect certain areas of the site 17 and certain buildings. I always ask this question and 18 you guys don't like it. But what's your assessment of 19 material condition of the site?
20 MR. PICK: John, we love hearing that 21 question.
22 MR. BARTON: Thank you. Some guys, you 23 know, have a problem with that question.
24 MR. PICK: For the period of time that we 25 were on the site for this inspection, knowing that you NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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108 1 do ask this question, we made sure we covered every 2 square inch of the site we could to be able to give you 3 the most reasonable answer.
4 The condition of the concrete, the piping, 5 the coatings that we could see, that site is in very good 6 condition, in the team's opinion.
7 MR. BARTON: I appreciate that, thank you.
8 MR. PICK: You're welcome. I'm going to 9 turn it back over to you, John Daily.
10 CHAIRMAN SKILLMAN: Thank you, Greg.
11 MR. DAILY: Thank you, Greg. Next slide.
12 Let's now move on to Section 2 which describes the 13 scoping and screening of structures and components that 14 are subject to aging management review.
15 The staff reviewed the applicant's scoping 16 and screening methodology procedures and quality 17 controls applicable to the license renewal application 18 development, as well as the training of project 19 personnel. We mentioned this a little earlier.
20 Staff also reviewed the various summaries 21 of the safety related systems, structures, and 22 components, or SSCs, non-safety SSCs effecting safety 23 related components and SSCs relied upon to perform 24 functions in compliance with the Commission's 25 regulations for fire protection, environmental NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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109 1 qualifications, station blackout, pressurized thermal 2 shock, and anticipated transience without scram.
3 Based on these reviews on the results from 4 the scoping and screening audit, and on additional 5 information provided by the applicant, the staff 6 concludes with the exception of one open item that the 7 applicant's scoping and screening methodology was 8 consistent with the standard review plan and the 9 requirements of 10 CFR Part 54.
10 If there are no real questions on this 11 slide, we'll turn to the next one which will discuss the 12 open item associated with scoping and screening.
13 CHAIRMAN SKILLMAN: John, let me ask this 14 question on that slide.
15 MR. DAILY: Yes, sir.
16 CHAIRMAN SKILLMAN: The processes that are 17 employed for scoping and screening really constitute 18 the IPA under 54, NCFR 54. Is that accurate?
19 MR. DAILY: Well, Bill Rogers may want to 20 step up to the mic.
21 DR. HISER: Yes, scoping and screening are 22 part of the IPA. The IPA includes how are you going to 23 manage aging effects. So that's the part, scoping and 24 screening is the --
25 CHAIRMAN SKILLMAN: Front end.
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110 1 DR. HISER: -- the part where you identify 2 components that are within the scope and are screened 3 in because they're long lived and passive, then you need 4 to do the aging management review.
5 And then the aging management 6 determination, how will you manage the aging effects 7 that require management. So just to express that 8 equivalence, that scoping and screening equals IPA is 9 not correct. So the screening is a portion.
10 CHAIRMAN SKILLMAN: It's a portion, it's 11 the front end.
12 MR. DAILY: Right. In essence it is the 13 front end. And the first thing that we look at under 14 this section is the actual methodology that is used to 15 establish the scoping and the screening. And then we 16 also do samples of the actual results. And that's done 17 during the audit, which you know, our audit team leader 18 leads and then writes a report on.
19 But yes, that's the front end. Aging 20 management review and the final determination of the 21 3,900 line items, you know, the 42 programs and so forth, 22 this then becomes the integrated plan assessment, the 23 entire book or the license renewal application on the 24 safety side.
25 CHAIRMAN SKILLMAN: Thank you.
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111 1 MR. DAILY: Okay, you're welcome. Let's 2 see, where were we here? So we're going to go to the 3 next slide and we'll talk about the open item associated 4 with scoping and screening.
5 Open item 2.3.3.20-1 is related to the 6 scoping of fire protection structure systems and 7 components. The staff's initial review of the 8 applicant's compliance with the fire protection rule 9 included reviewing the documents as listed in the 10 Callaway license and the then current final safety 11 analysis report, which represents Callaway's licensing 12 basis at that time.
13 This open item involved two aspects of the 14 scoping and screening of these fire protection SSCs. For 15 the first aspect that was based on its review, it was 16 not clear to the staff whether the fire suppression SSCs 17 in the auxiliary boiler room, the turban building, 18 hydrogen seal oil unit, and condenser pit were within 19 the scope of license renewal.
20 The applicant's initial response was that 21 these fire suppression components were not within the 22 scope because they were not required for safe shutdown.
23 Staff found that this was contrary to the applicant's 24 current licensing basis which did include these SSCs as 25 necessary for compliance with the fire protection rule.
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112 1 The staff noted that without additional 2 justification, these SSCs should not be excluded from 3 the scope. And by letter late in April, basically at 4 the end of April 2013, Ameren Missouri added these areas 5 and SSCs back into the scope of license renewal and 6 resolved the staff's concerns.
7 And of course, as mentioned earlier, and 8 we'll go on into the second aspect, that was under the 9 traditional, what I would call a more traditional fire 10 protection program based upon the deterministic fire 11 protection programs at 50.48.
12 However, the second aspect which involved 13 conversion over to the NFPA standard, NFPA 805, 14 regarding this aspect now backtracking just a little 15 bit.
16 In August of 2011, so just shortly before 17 the license renewal application was submitted, the 18 applicant had submitted a license amendment request to 19 transition its existing program to a risk informed 20 performance based program based upon NFPA standard 805.
21 Therefore, these two amendment request 22 reviews were essentially running in parallel with each 23 other during this period of time. It was unclear to the 24 staff then during the safety review for license renewal 25 as to which fire protection program modifications were NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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113 1 going to be planned for the transition to NFPA 805, which 2 might in turn effect the existing fire protection 3 program SSCs within the scope of license renewal.
4 The staff requested Ameren Missouri to 5 identify and discuss any of the changes associated with 6 this NFPA 805 transition. The applicant ultimately 7 committed to provide a gap analysis upon issuance of the 8 final license amendment for the NFPA transition.
9 So the NRC staff issued this then as a 10 license amendment to Ameren Missouri in January of this 11 year, January 2014. And that granted the approval and 12 the authorization to change over to the NFPA 805 based 13 program.
14 The applicant then submitted a gap analysis 15 to the staff for this open item in February, so shortly 16 after that of this year. The staff's initial review 17 found that this February submittal lacked some 18 sufficient details in order to be able to reach 19 conclusions to the adequacy of the analysis and the 20 changes.
21 Through some follow up requests for 22 information and conference calls, the applicant agreed 23 and has subsequently submitted a supplement to this gap 24 analysis, which now provides the staff with the desired 25 level of detail.
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114 1 The staff expects to close this open item 2 pending completion of its review. Final resolution 3 will be documented in the final SER and presented to the 4 ACRS full committee.
5 One thing I might add on this, I know there 6 was some discussion during the applicant's presentation 7 of why not submit that while the review was ongoing.
8 And of course, our license renewal review is based upon 9 what we call the current licensing basis.
10 At that time, before the amendment was 11 granted, it was the traditional basis. And so 12 therefore, there was some time lapse involved in order 13 to get this settled so that the new licensing basis could 14 then be addressed. And that's what they addressed in 15 their gap analysis. And the staff therefore expects to 16 be able to close this open item.
17 CHAIRMAN SKILLMAN: Thank you.
18 MEMBER SCHULTZ: John, then at this point 19 in time you're not anticipating the need for further 20 interaction with the applicant? You feel that the 21 responses that you have received recently have 22 addressed your issues. But you need to finalize your 23 review of what you now have?
24 MR. DAILY: Yes sir, that's our caveat.
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115 1 when you're writing your final input and you're crossing 2 your t's and dotting your i's, something might come up.
3 MEMBER SCHULTZ: But you're not waiting 4 for anything.
5 MR. DAILY: We're not waiting for anything 6 right now. We have that information in hand and 7 therefore we can say we expect to close this. We're 8 pretty confident.
9 MEMBER SCHULTZ: Thank you.
10 MR. DAILY: Next slide. Let's now move on 11 to Section 3, Aging Management Review Results. Section 12 3.0 of this section covers the staff's review of the 13 applicant's aging management programs, or AMPs.
14 Sections 3.1 through 3.6 cover the aging 15 management review items for each of the general system 16 areas within the scope of license renewal. For a given 17 aging management review, the staff reviews the item to 18 determine whether it's consistent with the GALL report.
19 If an aging management review is not 20 consistent with the GALL report, then the staff conducts 21 a technical review in depth in order to ensure adequacy 22 of managing the effects of aging for that particular 23 component material and environment condition.
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116 1 and discuss those here in the next slides. Next slide.
2 As Ameren had presented, 42 aging 3 management programs are presented in the license 4 renewal application. Thirty two of them are existing, 5 ten are brand new. There was some back and forth 6 related to how many would wind up being fully consistent 7 with the GALL report and how many might have exceptions 8 or enhancements.
9 Bottom line following the review and the 10 adjustments that the applicant has made to them, the 11 staff concluded that 23 AMPs are consistent with the 12 GALL report and 19 are consistent with enhancements 13 and/or exceptions. And there were no plant specific 14 aging management programs for this review. Next slide.
15 The first of the three open items 16 associated with the AMPs, open item B2.1.3-1 is related 17 to the reactor head closure studs and associated reactor 18 vessel flange threads.
19 On multiple occasions starting with 20 Callaway's first refueling outage in 1986, the 21 applicant has experienced difficulties either 22 inserting or removing its reactor vessel head closure 23 studs. In addition, multiple closure studs have been 24 stuck at one time or another.
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117 1 corresponding reactor pressure vessel flange hole 2 threads have been damaged in a total of ten out of the 3 54 locations.
4 MEMBER STETKAR: John, just for the 5 record, at one time or another was before 1992, right?
6 MR. DAILY: Yes.
7 MEMBER STETKAR: 1996 was number --
8 MR. DAILY: The single one, number 18.
9 MEMBER STETKAR: Eighteen. Nothing since 10 '96.
11 MR. DAILY: And nothing as far as we can 12 tell in the record that we have, right.
13 MEMBER STETKAR: Thank you.
14 MR. DAILY: Nothing beyond 1996. I 15 believe 1992, we have some backup information, but I 16 think 1992 was the last time that five of them were 17 stuck. And they were subsequently able to free and, you 18 know, do their repairs and examinations.
19 MEMBER STETKAR: Okay, thank you.
20 MR. DAILY: The damaged stud hole threads 21 were not repaired by means of thread inserts, but 22 instead were either machined down or ground off.
23 Therefore, several of these flange locations have less 24 than a full complement of threads.
25 The majority of the flange holes with NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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118 1 multiple missing threads are located basically in one 2 quadrant if you were to look at the circumference from 3 above. Most of the thread hole damage is located with 4 flange holes down in one quadrant. Not all of them, 5 there's a few that are in the other peripheries.
6 CHAIRMAN SKILLMAN: Have you explored why 7 that pattern exists?
8 MR. DAILY: We did actually, I believe.
9 During the AMP audit there was some dialogue back and 10 forth. We've got Roger Kalikian who is the reviewer for 11 that. And I believe he may be able to shed some light 12 on this for us.
13 MR. KALIKIAN: Yes hi, my name is Roger 14 Kalikian. I'm the primary reviewer. And when we 15 looked into it we were interested in why they were in 16 that quadrant.
17 Apparently when they were testing it before 18 initial fuel up, there were some issues with a tight fit.
19 So they were go gauging the holes and the gauger got 20 stuck. So they had difficulty removing the gauger out 21 of number 12.
22 And they decided not to gauge the rest of 23 them. They just happened to be in that area. So out 24 of the five that got stuck, four of them were not gauged.
25 CHAIRMAN SKILLMAN: Thank you.
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119 1 MR. DAILY: The staff noted that the 2 applicant's aging management program as proposed, which 3 is basically it was based upon the GALL report AMP, may 4 not be adequate for monitoring and managing degradation 5 of the reactor vessel flange hole threads and based upon 6 the applicant's plant specific conditions.
7 Now one of the reasons behind that is 8 because the GALL report AMP more or less assumes rather 9 normal studs, threads, and holes, and operating 10 experience. This is, I guess in my experience this is 11 a unique situation, this particular plant, you know, and 12 the experiences that they've had. So the staff had some 13 real concerns in that area as to whether this is really 14 going to have enough adequate controls for them.
15 Furthermore, one stud, number 18 as had 16 been mentioned before, became stuck during its 17 installation in the 1996 refueling outage at 2.625 18 inches withdrawn. This stuck stud has not been removed 19 since during any subsequent inspections our outages.
20 The applicant stated that it performed an 21 engineering evaluation and determined that the stuck 22 stud has sufficient thread engagement to be fully 23 tensioned. And they reported that they've been able to 24 fully tension and de-tension that stud from 1996 on up 25 to present.
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120 1 The staff was concerned that the existing 2 reactor head closure stud bolting program here in this 3 instance may not be adequate to detect future wear or 4 loss of material to ensure that the appropriate 5 acceptance of this criteria would continue to be met, 6 and that the allowable stresses under the ASME code are 7 not exceeded during the period of extended operation.
8 And so this became the two portions 9 involved in this particular open item, the multiple 10 stuck studs and then aging management, you know, in the 11 future for stud number 18.
12 In order to address the staff's concerns, 13 the applicant proposed two commitments. The first 14 commitment would perform a one time inspection no later 15 than six months prior to PEO for the six flange stud hole 16 locations with the highest amounts of missing threads.
17 Each of these locations has more than one 18 thread circumference missing, basically from four to 15 19 missing equivalent 360 degree threads. The proposed 20 inspection method would use a laser inspection to 21 provide accurate determination of whether wear or loss 22 of material for the existing threads has occurred.
23 This inspection would be similar to, as 24 reported by the applicant, would be similar to the 25 original inspections that the applicant performed in NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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121 1 1989 and '92 in order to determine the number of fully 2 engaged threads for each location with these damaged 3 threads.
4 Staff believes that this inspection method 5 should be able to provide an accurate evaluation such 6 that if wear or loss of material in these locations is 7 present, it could be detected and measured.
8 In addition, the results from prior 9 inspections, if they are used as a baseline, a wear or 10 a loss rate could potentially be calculated and 11 projected then to the end of the period of extended 12 operation. The staff believes that this inspection is 13 necessary to verify that for these locations, 14 appropriate acceptance criteria will be met.
15 The second commitment that the applicant 16 has proposed would remove stud number 18 and inspect or 17 replace it no later than six months prior to the period 18 of extended operation.
19 Since the stud has been stuck since 1996 and 20 the number of engaged threads are close to the 21 applicant's minimum acceptance criteria, the staff 22 believes that this action for stud number 18 is 23 essential in order to establish that the appropriate 24 acceptance criteria will be met and that the allowable 25 stresses under the SME code for stud number 18 are not NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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122 1 exceeded throughout the period of extended operation.
2 The staff's conclusion is that with these 3 changes added to the applicant's program as noted above, 4 there's reasonable assurance that the aging effects 5 that are associated with the reactor head and closure 6 studs will be adequately managed. The staff will, 7 however, consider whether to use a licensed condition 8 in this regard.
9 The staff does expect to close this open 10 item in the final SER, and the details of that closure 11 and the results will be presented to the ACRS full 12 committee.
13 CHAIRMAN SKILLMAN: John, you're wording 14 was remove stud 18, Commitment number 2, remove stud 18 15 and inspect or replace it. Did you mean remove the 16 remnant of 18 if it needs to be cut off, and replace 18 17 with a brand new 18 with good threads, is that what you 18 meant to say?
19 MR. DAILY: I would love for that to be the 20 case.
21 CHAIRMAN SKILLMAN: Is that what you 22 intend the applicant to do?
23 MR. DAILY: I think maybe, you know, as far 24 as the staff intent, our basic thing while Roger's 25 coming up to the phone, we just don't think it's NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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123 1 appropriate to continue to operate with a questionable 2 stud and we're concerned about PEO.
3 MR. KALIKIAN: Yes, the stud most likely, 4 we don't know what the condition is. They never tried 5 to remove it, so it may end up coming out. When it went 6 in, it had just a few burrs on it. It buffed it out.
7 I think most likely it's going to be 8 destructively removed, so it would be a new stud. And 9 they have plenty of new studs, I think, from a unit that 10 never got constructed.
11 CHAIRMAN SKILLMAN: Thank you.
12 MR. DAILY: Yes, I'm sure that the actual 13 language, as we look at any licensing decision, that 14 language is going to be important. But that's kind of 15 the staff's position is we think that there needs to be 16 a new stud there.
17 CHAIRMAN SKILLMAN: Do you feel like the 18 commitment that the applicant has made is a sufficient 19 commitment to solve the concern that you have?
20 MR. DAILY: Well, there is a discussion on 21 that. I mean, commitment, the language of a 22 commitment, a license condition which would become an 23 obligation. And I think that's still something that 24 we're talking about as a division internally.
25 MR. LUBINSKI: And if I could add to that, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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124 1 I think your question is do we believe that the 2 commitment that they've provided at this point is 3 adequate. And what we've looked at is the commitment 4 itself of what they plan to do, I'll say what their plans 5 are for addressing the issue is adequate.
6 To be able to say they have to put a new stud 7 in, that would be, you know, beyond what the current 8 commitment is because if the stud is appropriate, if 9 they're able to inspect the threads and the threads are 10 fine and they're able to implement the aging management 11 program, we're good.
12 The second part of the question of whether 13 it becomes a license condition, as John said, that's 14 something we may want to consider and we are considering 15 with the idea being that if they want to vary from that, 16 it would require an amendment to the program, and that's 17 the reason we would want to require it as a license 18 condition, if they wanted to vary in any way.
19 CHAIRMAN SKILLMAN: Well I guess what I'm 20 trying to communicate is I listen to the licensee say 21 we're going to fix this. We'll fix it in the future.
22 We've got reasons we don't want to do it right now.
23 We've already got our outage for 2014 set, so this is 24 not a good time, but we will take care of it before six 25 months before the PEO.
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125 1 And I think it is appropriate that we take 2 them at their word. My question is is their word good 3 enough for you? They said they're going to fix it.
4 MR. LUBINSKI: I think when you say their 5 word, as part of the application is, when we talk about 6 the license condition, the license condition is if they 7 decide to vary from that at all. And this would be if 8 they were going to vary because again, it's not that they 9 would just blow off the commitment and that's not what 10 we're saying.
11 It's they might want to do it by an 12 alternate method than what they're doing because again, 13 between now and the time they enter PEO, there's a period 14 of time. If they want to vary and do something 15 different, we want to make sure that we have a chance 16 to review what that difference is, and that would be the 17 reason for the license condition.
18 Not that we don't think they'll do it, it's 19 just the manner in which they do it may change and we 20 would want to review that new manner.
21 MR. DAILY: Right. And the reason that I 22 pause, I'm not a lawyer. So you know, I think there are 23 some things when you get into talking about obligation 24 and trusting their word and things, I do take them at 25 their word, I think this is a serious business.
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126 1 But on the other hand, again since I'm not 2 a stud engineer and since we're not necessarily there 3 when it happens, we might have to allow the possibility 4 that stud removal is successful, you know, however large 5 or small that probability might be. And therefore, it 6 think we need to leave a certain amount of decision into 7 the applicant's hands in that regard.
8 MR. BARTON: I mean, this is just big 9 enough, why wouldn't you want to be there when it 10 happens?
11 MR. DAILY: Well, that's a very good point.
12 And I think probably at least one of the inspectors of 13 the region probably will be there.
14 MR. BARTON: Will be there.
15 MR. DAILY: Because, you know, we're 16 talking about the reactor vessel. That's the heart of 17 the plant.
18 CHAIRMAN SKILLMAN: We're talking about 19 reactor coolant system pressure boundary protection.
20 DR. HISER: And this would be an atypical 21 evolution, unusual activity.
22 CHAIRMAN SKILLMAN: Well, there have been 23 other utilities in other reactor plants, smaller, that 24 have found a way to cut them out, skin them out, shine 25 them up and put in a new stud and be as good as you can NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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127 1 be, although not as new. And it works, it works very 2 well. People know how to do that.
3 MR. DAILY: And I do believe that, and I 4 would have to defer to Callaway on this, but I do believe 5 that they did have some destructive removals of some of 6 the other studs and were successful in reusing those 7 holes.
8 MR. DAILY: Sure.
9 CHAIRMAN SKILLMAN: So, you know, we have 10 to allow all of those possibilities. We just don't want 11 the status quo to continue. I guess, I think we would 12 be safe in saying that.
13 MR. DAILY: I'm certainly not 14 communicating any thought on my part that the applicant 15 should destroy the lower flange heads, threads in order 16 to do this. There is a way to get the stud out that will 17 not hurt those threads, I understand that.
18 MR. KALIKIAN: Yes, in the past they 19 haven't reused any of these stock studs. So they have 20 always been replaced --
21 CHAIRMAN SKILLMAN: Oh yes, I would think 22 the stock stud's got to go.
23 MR. DAILY: Right.
24 MR. KALIKIAN: And their practice has been 25 if they have a flange hole that has some damaged threads, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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128 1 they make sure the stud has zero damage on it.
2 MR. DAILY: This has been a pretty 3 complicated issue. But I have faith in what the staff 4 is doing and our conclusions. And I think that the 5 applicant is serious about what they are doing. So I'm 6 pretty confident that we are going to be able to come 7 to a successful resolution for this particular stud just 8 like, you know, the others have been.
9 CHAIRMAN SKILLMAN: Okay.
10 MEMBER SCHULTZ: John, the applicant 11 presented earlier the detailed information that they 12 that they had associated with the stud holes, and as a 13 way to justify their choice of the worst conditions, the 14 six worst that they were going to inspect.
15 And I presume that the staff's had an 16 opportunity to review all of that material and conclude 17 that their program for inspection is appropriate. Is 18 that true?
19 MR. KALIKIAN: This is Roger Kalikian 20 again. Yes, those six locations are the worst one.
21 All the other ones have minor damage.
22 MEMBER SCHULTZ: So you're good with the 23 program as it's proposed?
24 MR. KALIKIAN: Yes.
25 MR. DAILY: And I believe that diagram NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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129 1 showing the stud alignment is a diagram that was 2 supplied as one of the responses to our RAIs. Is that 3 --
4 MR. KALIKIAN: No, actually that was 5 earlier response. Back when they got stuck, they 6 provided some evaluations to us back in '87.
7 MR. DAILY: '87?
8 MEMBER SCHULTZ: Thank you.
9 CHAIRMAN SKILLMAN: The duration of this 10 small discussion indicates that the concern that the 11 subcommittee has. And so the transcript will show that 12 we are concerned. But I will also offer, I heard the 13 licensee speak the same type of concern. Thank you.
14 Okay.
15 MR. DAILY: Yes sir, you're welcome. Next 16 slide. Open item B2.1.6-1 is related to the 17 applicant's reactor vessel internal's program for 18 pressurized water reactors, or PWRs. This AMP is based 19 upon conformance with both the GALL report AMP and the 20 EPRI report MRP-227A, which again Ameren Missouri had 21 referred to in their presentation.
22 This MRP report provides the PWR industry's 23 recommended inspection and evaluation guidelines for 24 PWR design, reactor vessel internal components, and was 25 endorsed for use by the NRC and the safety evaluation NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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130 1 that the staff produced dated in December of 2011.
2 The scope of the AMP includes the 3 applicant's bases for resolving what are called the 4 applicant/licensee action items that were identified in 5 the NRC safety evaluation and any applicable generic or 6 plant specific operating experience.
7 The safety evaluation contains eight of 8 these action items, one through eight, with action item 9 eight being subdivided further into five separate 10 sub-parts. The applicant's program as originally 11 proposed did not address all of the applicable action 12 items, therefore the staff sought further information.
13 Ameren Missouri's initial action item 14 responses resolved most of the action items with the 15 exception of items 1, 5, 7 and 8 sub-part 5. So four 16 things were left open.
17 The applicant also needed to address the 18 generic clevis insert bolt cracking experience that was 19 identified in another PWR which had occurred in 2010, 20 and to assess whether that operating experience should 21 result in a change to the frequency of it performing its 22 own ASME in-service inspections for the clevis insert 23 bolts at Callaway.
24 We included this clevis insert bolt 25 basically under the umbrella in our reviews of the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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131 1 review for the reactor vessel internals. I noticed the 2 applicant had split it out. It's the same issue, we're 3 just kind of grouping it a little differently.
4 The applicant has resolved the action items 5 that remained open and the clevis insert bolt experience 6 by submitting various RAI responses provided to the 7 staff over the period of May 2013 until the present. So 8 the staff expects to close this particular open item in 9 the final SER and will present it to the ACRS full 10 committee.
11 CHAIRMAN SKILLMAN: Okay, thank you.
12 MR. DAILY: Next slide. Open item 13 B2.1.20-1 is related to Callaway's ASME code Class 1 14 small-bore socket welds. The original application 15 states that Callaway has 19 ASME code Class 1 small-bore 16 piping socket welds less than 4 inches and greater than 17 or equal to one inch nominal pipe size.
18 Based on its experience with previous LRA 19 reviews of similar PWRs, staff noted that this 20 population seemed considerably smaller than the typical 21 quantity of in scope socket welds. Therefore, during 22 the AMP audit, the staff requested the applicant to 23 explain the reason for this low count.
24 The applicant stated that it had recounted 25 the number of socket welds subsequent to submitting the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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132 1 application, and now finds 23 Class 1 small-bore socket 2 welds within the scope of the particular AMP. That AMP 3 title is one time inspection of ASME code Class 1 4 small-bore piping program.
5 The staff noted that even this new number 6 of 23 still was considerably low based on prior audit 7 experience. Staff continued to pursue the issue of 8 ascertaining a correct number of small-bore socket 9 welds at Callaway and issued an RAI requesting a 10 recount.
11 In response to the staff's RAI, the 12 applicant did another recount and revised the number of 13 socket welds this time to 77. In light of these events, 14 population basically going from 19 to 23 to 77, the staff 15 also requested a confirmation that similar errors had 16 not occurred elsewhere in the license renewal 17 application.
18 So the staff also noted that at that time 19 the issue had not been entered into the applicant's 20 corrective action program. So the staff issued an RAI 21 to address those items.
22 In an August 2013 response, the applicant 23 explained that the erroneous counts occurred 24 essentially due to incorrect queries or filters as was 25 described of its database, that it had entered this NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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133 1 issue into its corrective action program and that as a 2 result of the extent of condition reviews, it had 3 identified one other occurrence of this miscount, and 4 that was with the small-bore butt weld population.
5 The applicant stated that in conducting 6 these thorough re-verifications, it also supplemented 7 the searches with drawing reviews to arrive at final 8 within scope counts of 80 for the small-bore socket 9 welds and 343 for the small-bore butt welds.
10 The staff's concerns therefore were 11 resolved. Staff expects to close this open item in the 12 final SER and will present the item again to the ACRS 13 full committee. Next slide.
14 Moving on now to SER Section 4. This 15 particular section covers the time limited aging 16 analyses or TLAAs. Section 4.1 documents the staff's 17 evaluation of the applicant's identifying of all the 18 applicable TLAAs for its facility.
19 The staff evaluated the applicant's basis 20 for identifying those plan specific or generic analyses 21 that need to be identified and determined that Ameren 22 Missouri has provided an accurate list of TLAAs as 23 required by 10 CFR 54.21 C1.
24 Sections 4.2 through 4.7 document the 25 staff's review of applicable Callaway TLAAs as shown.
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134 1 Based on its review and the information provided by the 2 applicant, the staff concludes with the exception of one 3 open item that the TLAAs will satisfy one of the three 4 requirements in 10 CFR 54.21C, that is they'll either 5 remain valid for the period of extended operation or 6 they have been successfully projected to the end of the 7 period of extended operation, or as in III, the effects 8 of aging for those intended functions will be adequately 9 managed for the period of extended operation.
10 And so that corresponds to the I, II, and 11 III criteria for TLAAs in the rule. Section 4.3 12 contains the TLAA open item which is 4.3.4-1. And so 13 we'll go to that now here in the next slide. Next slide.
14 Open item 4.3.4-1 is related to the effects 15 of environmentally assisted fatigue on reactor coolant 16 pressure boundary components. This open item is 17 similar to previous open items that the ACRS has seen 18 in past meetings related to environmentally assisted 19 fatigue or EAF.
20 As part of its evaluation of the effects of 21 this on the fatigue life of reactor coolant pressure 22 boundary piping and components, Ameren Missouri 23 performed a review of all the applicable reactor coolant 24 pressure boundary components with a class one fatigue 25 analysis to show that the locations identified in staff NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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135 1 guidance are bounding. And that staff guidance 2 primarily begins with a document called new reg/CR6260.
3 In addition, the applicant stated that it 4 reviewed its components to also identify whether there 5 were also other more limiting plant specific components 6 to be evaluated for EAF.
7 However, the staff identified additional 8 information that was needed on the applicant's approach 9 that it took in its screening of EAF for these reactor 10 coolant pressure boundary components.
11 The applicant stated that it performed a 12 systematic review to determine the locations to be 13 monitored by the fatigue monitoring program. This 14 review involved identifying appropriate locations 15 which need management for environmentally assisted 16 fatigue.
17 However, in justifying its review, Ameren 18 Missouri did not demonstrate that its methodology for 19 identifying these EAF locations was appropriate and 20 conservative for Callaway Unit 1.
21 The staff identified the following types of 22 issues. A, questions in the applicant's underlying 23 assumptions which required additional information 24 about the consistency in the level of rigor for these 25 fatigue calculations, B, questions on how EAF NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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136 1 cumulative usage fatigue factors were compared, and C, 2 questions on the validity of comparing EAF across 3 multiple systems and components.
4 Ameren Missouri's responses in April and 5 August of 2013 provided additional information 6 regarding these particular assumptions and 7 demonstrated that its evaluations for EAF were 8 sufficiently rigorous and appropriate for Callaway.
9 In addition, it enhanced its fatigue 10 monitoring program to ensure that EAF susceptible 11 locations are updated appropriately and remain bounded 12 consistent with any updated or refined analysis.
13 Therefore, the staff concludes that the 14 applicant has justified its approach and the locations 15 that require monitoring for environmentally assisted 16 fatigue during the period of extended operation. The 17 staff expects to close this open item in the final SER 18 and will present it to the ACRS full committee. Next 19 slide.
20 Since the issuance of the SER with open 21 items in April of 2013, several other issues have also 22 arisen in the meantime. And of course we have discussed 23 these in some part, but we'll just kind of go through 24 them here. In these particular cases, the staff issued 25 RAIs to address them for the applicable license renewal NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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137 1 application reviews and received the following 2 responses.
3 Now we plan on presenting today three of the 4 items in discussion here because they are a little more 5 significant in terms of impact in the scope. The staff 6 is also prepared to discuss any of the other items during 7 the question and answer session if the subcommittee so 8 desires.
9 Two of them, as we had mentioned earlier, 10 are related to new staff, interim staff guidelines that 11 were produced after the SER with open items was issued.
12 One is related to new components which the applicant 13 added to the scope of license renewal in an amendment 14 submitted in August of 2013, which is about four months 15 after the SER was published.
16 These issues and resolutions will be 17 documented in the final SER and presented to the full 18 committee. Next slide.
19 Loss of coating integrity of internal 20 coatings. Based on recent industry operating 21 experience, the staff identified issues related to 22 managing the loss of coating integrity due to 23 blistering, cracking, flaking, peeling, or physical 24 damage of service level three or augmented coatings.
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138 1 problems for the components which are internally 2 coated, coating fragments which break free can foul or 3 damage downstream components as well. And that's where 4 the primary concern here is internally, internal 5 coatings.
6 Ameren Missouri responded to the original 7 RAIs and the follow ups providing responses that 8 included such things as the following, revising 9 multiple AMPs to include all the internally coated in 10 scope components, incorporating periodic visual 11 inspections for these coatings, incorporating coating 12 acceptance criteria into the relevant programs, 13 establishing personnel qualifications and testing 14 methods consistent with regulatory guide 1.54 which is 15 titled the service level 1, 2, and 3 protective coatings 16 applied to nuclear plants.
17 The staff is reviewing supplemental 18 information in these regard, and expects to close this 19 issue in the final SER. We will be presenting the 20 resolution of course to the ACRS full committee.
21 CHAIRMAN SKILLMAN: John, this new 22 information was communicated in a letter to Dr. Hackett 23 on May 12th.
24 MR. DAILY: Yes, sir.
25 CHAIRMAN SKILLMAN: That doesn't give the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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139 1 ACRS a whole lot of review time, but I think we're an 2 able crew, and we reviewed this information and we 3 understand what you're saying. But if you're going to 4 have real information for the full committee, we request 5 that we have ample review time, please.
6 MR. DAILY: We do, and we apologize for the 7 late breaking of these informations. We actually were 8 working all the way up until late April in order to even 9 make a decision as to whether everything was sufficient 10 to go forward with the subcommittee.
11 And as project manager, I was trying to push 12 folks along towards that but understanding the safety, 13 you know, we still need it. But we know that this was 14 a short turnaround. And we do apologize for that.
15 CHAIRMAN SKILLMAN: Thank you.
16 MR. LUBINSKI: Excuse me, Mr. Chairman.
17 If I could just ask --
18 CHAIRMAN SKILLMAN: Sure.
19 MR. LUBINSKI: To make sure that we meet 20 the needs for the ACRS moving forward. These will all 21 be addressed in the final SERs, as John said, that will 22 be provided. Normally we provide that a month in 23 advance of the meeting.
24 MR. DAILY: Thirty days.
25 MR. LUBINSKI: Would you be requesting NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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140 1 additional time?
2 CHAIRMAN SKILLMAN: No.
3 MR. LUBINSKI: Or is 30 days sufficient?
4 There you go, thank you.
5 CHAIRMAN SKILLMAN: Yes, yes. Let's keep 6 it 30 days or more.
7 MR. LUBINSKI: Thank you.
8 CHAIRMAN SKILLMAN: Thank you. Okay.
9 MR. DAILY: Next slide. Internal 10 surfaces corrosion and corrosion under insulation.
11 Based on recent operating experience and staff reviews, 12 the staff identified several issues which existing 13 guidance at the time did not cover related to aging 14 management of internal surfaces of components and 15 atmospheric storage tanks.
16 Some examples include things like the 17 following, recurring internal corrosion, flow 18 blockages whether from corrosion, silt buildup, or 19 other mechanisms in fire water system piping, corrosion 20 underneath insulation, and degradation of tanks and 21 coatings near atmospheric pressure tanks.
22 This was all covered then in license 23 renewal interim staff guideline 2012-02, and this was 24 issued in November of 2013 to containing the updated 25 staff guidance and details. So the staff issued RAIs NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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141 1 to all of our current applicants as applicable, 2 including Ameren Missouri in order to address these 3 issues from the ISG.
4 Callaway responded to the original and the 5 follow up RAIs in addressing the staff concerns, and 6 included such items or examples as the following, which 7 we see up here on the slide.
8 They added several tests and inspections 9 for detecting internal corrosion and flow blockages, 10 they augmented tests and inspections for wetted but 11 normally dry piping which cannot be easily drained.
12 And of course this is one, kind of the fire water system 13 that can be particularly problematic, especially as 14 you've eluded to, when you've got river water as your 15 source of water supply.
16 In addition to, they're also going to be 17 incorporating periodic inspections of the fire water 18 system tank coatings and the base material of that tank 19 if that tank based material has been exposed.
20 Its added and revised periodic inspections 21 of outdoor insulated and indoor insulated components 22 that are operated below the dew point, and having 23 sampling locations based upon the likelihood of 24 corrosion underneath insulation occurring.
25 Also, several AMPs were modified or NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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142 1 enhanced to incorporate items resolving staff concerns.
2 This actually touched several aging management 3 programs, and I think was a pretty extensive review, you 4 know, based on our experience that we've had from 5 applicants in responding to these RAIs.
6 The staff is reviewing all the applicant's 7 responses and we expect to close this issue in the final 8 SER. We will also be presenting this to the full 9 committee in the fall.
10 MR. BARTON: John, a question that this 11 brings up. The water that's in the fire water storage 12 tank, is that river water? Is that water that's been 13 treated once it came in before it's pumped into the fire 14 water storage tank?
15 MR. DAILY: It might be best to let Ameren 16 speak to that.
17 MR. BARTON: I'm not asking, I'm asking 18 just for whoever knows the answer.
19 MR. DAILY: Okay.
20 MR. EITEL: Lee Eitel, Supervising 21 Engineer, Systems Engineering. The water comes from a 22 well, it does not come from the river. It's in the fire 23 water system.
24 MR. BARTON: All right, thank you.
25 MR. DAILY: So from a deep well, okay. Any NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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143 1 other questions then on this issue?
2 CHAIRMAN SKILLMAN: Yes. May I ask you to 3 please come back to the microphone? What do we know of 4 the chemistry of the water from that well, please.
5 MR. EITEL: The water does have some levels 6 of mineral deposits. If I can refer to my colleague 7 here, Joe Howard.
8 MR. HOWARD: Joe Howard, Chemistry 9 Supervising Engineer. It is typical well water for 10 mid-Missouri. It has some iron content, which is the 11 predominant issue that we've had. It's got about one 12 ppm iron content. It also has some minimal content for 13 calcium carbonate and magnesium.
14 CHAIRMAN SKILLMAN: Thank you. Okay, 15 please proceed. Thank you, John.
16 MR. DAILY: Thank you. Next slide.
17 Inspection of submerged bolting. The applicant's 18 license amendment number 26, which was submitted to the 19 staff in August of 2013, added AMR line items for 20 submerged carbon steel and stainless steel closure 21 bolting associated with pumps in the central service 22 water, service water, emergency diesel engine fuel oil 23 storage and transfer pumps, the oily waste, and the 24 floor and equipment drain systems.
25 The applicant stated that the bolting is NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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144 1 managed for loss of material and loss of pre-load.
2 Given the inaccessibility of the normally submerged 3 bolted connections, it was not clear to the staff what 4 parameters would be monitored, what inspection 5 techniques would be used, and/or the frequency of the 6 inspections that would be used to detect aging effects 7 on these bolts.
8 So we issued some RAIs in order to clarify 9 these concerns. Ameren Missouri responded to the 10 staff's RAIs most recently in April of this year. The 11 RAI responses include adding in the inspections of bolt 12 heads during dewatering of the environment, inspection 13 of the bolt threads during disassembly and maintenance, 14 and monitoring of pump performance.
15 Pending completion of the reviews of this 16 information, the staff expects to resolve this issue in 17 the final SER and will be presenting it to the ACRS full 18 committee.
19 The staff's conclusion will be provided in 20 the final safety evaluation report at the conclusion of 21 staff evaluations, which as we had mentioned we are 22 targeting for September of this year. Pending the 23 satisfactory resolution of the open items, the staff 24 will be able to determine whether the requirements of 25 10 CFR 54.29A have been acceptably met for the renewal NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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145 1 of Callaway plant Unit 1.
2 This concludes now the written portion of 3 our staff presentation. So now we'll be available for 4 any further questions from the subcommittee.
5 CHAIRMAN SKILLMAN: John, let me ask this 6 key question relative to schedule. What confidence do 7 you have that you will have your SER completed timely?
8 MR. DAILY: I'm pretty confident right 9 now, Mr. Skillman because we already have a lot of our 10 SER input written. Now there's other reviews, you 11 know, there's an assembly that takes place.
12 But one of the reasons why we've set it up 13 the way we have is in order to give us, you know, to give 14 me some assurance basically as the schedule developer 15 that we can get there. And I believe we can.
16 CHAIRMAN SKILLMAN: Thank you.
17 Appreciate your input. To my colleagues around the 18 table, gentlemen, does any of you have a comment or 19 question, please?
20 MEMBER SCHULTZ: Yes, I have a comment both 21 of the staff and for the applicant. Appreciate the 22 presentations by the staff. And I particularly wanted 23 to remark on the information that we heard but is also 24 provided to us related to the inspections and audits.
25 I think the report we've heard was very NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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146 1 helpful today, but also the overall program review 2 clearly has gained a high degree of credibility 3 associated with the audits and the inspections that the 4 staff has done, that the region has done, associated 5 with this program.
6 That, in combination with the 7 comprehensive technical review by the staff has really 8 brought this overall program together. You know, a lot 9 of good information was gained by both parts of that 10 process, the comprehensive review of the technical 11 review, in combination with the audit inspection. So 12 I think that speaks well to the thoroughness of the 13 overall review.
14 And then I just wanted to come back and 15 comment to the applicant that Dave Neterer's remarks and 16 his conclusions, really did appreciate his remarks that 17 this overall program for license renewal and what they 18 have done associated with aging management as a learning 19 organization, that that has really helped them to bring 20 together programmatically in a way to integrate the 21 overall programs that the site already has ongoing, that 22 that's been an opportunity for you to really provide a 23 learning experience for the site, to think about the 24 site not only as a 40 year plant, but a 60 year program, 25 and that involving the management, training the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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147 1 personnel.
2 And we've seen today a very comprehensive 3 and thorough presentation by the applicant about their 4 lessons learned associated with this program. So I 5 appreciated that overview, as well as the details that 6 we've learned today. Thank you.
7 CHAIRMAN SKILLMAN: Thank you, Steve.
8 John?
9 MEMBER STETKAR: I would like to echo some 10 things that Steve said. And I apologize, I had to duck 11 out for another meeting, so I missed the first part of 12 the staff's presentation.
13 But as I read through the SER and the 14 inspection audit reports, I think the staff did a really 15 good job on this one. It seemed to be one that was a 16 bit more challenging in the sense of interactions 17 compared to several others that I've seen over the last 18 six, seven years.
19 And I think you did a really, really good 20 job on tracking down issues and making sure that they 21 were closed out to your satisfaction. So I would just 22 like to add that.
23 MR. DAILY: This truly is a big team 24 effort. And on behalf of the staff team, I'm sure John 25 would echo, they all appreciate that. We do appreciate NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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148 1 that. But it is a team effort. There's so much that 2 goes into it.
3 CHAIRMAN SKILLMAN: Thank you. John 4 Barton?
5 MR. BARTON: For all the information that 6 I received, including all the stuff from our last 7 meeting which we didn't have, and all the material that 8 Kent's been sending me over the past year window, and 9 the presentations that I heard today, I have no concerns 10 about proceeding with license extension at this point 11 from what I heard, from where I am.
12 CHAIRMAN SKILLMAN: Thank you, John.
13 Ron?
14 MEMBER BALLINGER: Great presentation.
15 I'm going to try to follow with interest the corrosion 16 issues related to the service water piping systems and 17 things.
18 CHAIRMAN SKILLMAN: I thank you very much, 19 both to the staff and to the licensee for a couple of 20 things, the comprehensiveness of the review, the 21 thoroughness of the presentation. It is clear that the 22 applicant spent a lot of dry run time preparing for this.
23 Thank you.
24 And I particularly appreciate the 25 precision of the answers. I also appreciate the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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149 1 thoroughness of Mr. Pick's review, that's the 71001 and 2 the 71003 review. That I found very enlightening the 3 degree to which his team detailed every piece of that 4 review, so I give them a commendation. It was really 5 good.
6 So thank you to each of you. Let me now 7 communicate that the bridge line is open. And is there 8 anyone on the bridge line that would like to make a 9 comment, please? If anyone is on the bridge line, would 10 you please identify yourself?
11 Thank you. If any members of the public or 12 anyone in the audience, would you like to make a 13 statement or a comment, please?
14 MR. LUBINSKI: Mr. Chairman, if I may.
15 CHAIRMAN SKILLMAN: Yes sir, John.
16 MR. LUBINSKI: I just want to thank the 17 subcommittee for the comments that you made in closing 18 here. Appreciate it. And I will echo what John Daily 19 said is from the NRC standpoint, it's definitely been 20 a team effort.
21 And as you mentioned, the region is also 22 part of that team. And we appreciate their inspections 23 and the coordination as well. And the team is not just 24 in the division of license renewal, it's across the 25 entire NRC. So I echo John's comment. My compliments NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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150 1 to them and my thanks to them, and thank you for your 2 recognition.
3 CHAIRMAN SKILLMAN: Okay. To all, thank 4 you very much. Safe travels and safe holiday. We're 5 adjourned.
6 (Whereupon, the meeting in the 7 above-entitled matter was concluded at 4:40 p.m.)
8 9
10 11 12 13 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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Callaway Plant Unit 1 ACRS Subcommittee Meeting - License Renewal 05/22/2014
Dave Neterer Site Vice President 05/22/2014 Plant History and Background
REPRESENTING CALLAWAY PLANT
- Dave Neterer - Site Vice President
- Sarah Kovaleski - Director, Design Engineering
- Roger Wink - Supervising Engineer, Plant Life Extension
- Andrew Burgess - Project Engineer, Plant Life Extension
- Michael Hoehn II - Supervising Engineer, Engineering Programs
- Eric Blocher - Project Manager, STARS Alliance 3 Callaway ACRS Subcommittee - License Renewal
PERSONNEL IN ATTENDANCE Operations Engineering Programs Chemistry Fred Bianco Greg Kremer Joe Howard Steam Generators & Electric Cable & Civil/Structural RVI Cathodic Protection Kenneth W. Blair Jr. Ken Sandstedt Landon Bodenschatz Neil Fisher NFPA 805/Fire STARS Alliance LR Team Protection/PRA Tony Harris Sharon Merciel Mike Fletcher Jim Johnson Dave Shafer Lee Eitel Ken Bryant Justin Hiller Reactor Head Studs Inservice Inspection Metal Fatigue/TLAA David Gross Jerry Doughty Dave Gerber Buried Piping and Open Cycle Cooling Flow Accelerated Coatings Systems Corrosion Justin Stollhans Tarang Parashar Jeremy Claunch 4 Callaway ACRS Subcommittee - License Renewal
AGENDA
- Plant History and Background
- Major Modifications and Near Term Plant Improvements
- Safety Evaluation Report Open Items
- Concluding Remarks 5 Callaway ACRS Subcommittee - License Renewal
PLANT HISTORY AND BACKGROUND
- Initial Construction Permit - April 16, 1976
- Operating License - October 18,1984
- Generation output:
- Licensed output is 3,565 MWth
- Rated output is 3,579 MWth
- Refueling Outage 20 begins October 2014 6 Callaway ACRS Subcommittee - License Renewal
PLANT OVERVIEW - BASIC DESCRIPTION
- Callaway Unit 1 is situated on a 7,354 acre site, with the power plant site area containing approximately 2,765 rural acres on a plateau
~300 feet above the Missouri River (located 5 miles south)
- Callaway is a single unit Westinghouse 4-loop PWR
- Bechtel was the Primary A/E
- Daniel International was the constructor
- SNUPPS design (sister plant to Wolf Creek) 7 Callaway ACRS Subcommittee - License Renewal
CALLAWAY PLANT UNIT 1- PLANT SITE 8 Callaway ACRS Subcommittee - License Renewal
CALLAWAY PLANT UNIT 1- RIVER INTAKE STRUCTURE 9 Callaway ACRS Subcommittee - License Renewal
LOCATION OF PLANT SITE Kansas City St. Louis St. Louis Approximately 80 miles from the St. Louis Metro Area Approximately 175 miles from the Kansas City Metro Area 10 Callaway ACRS Subcommittee - License Renewal
Roger Wink Supervising Engineer, License Renewal 05/22/2014 Major Modifications and Near Term Plant Improvements
MAJOR MODIFICATIONS COMPLETED
- Replaced Main Condenser tube bundles (2004) *
- Replaced Steam Generators (2005)
- Pressurizer PWSCC-Resistant Full Structural Weld Overlays (2007)
- Replaced ~5 miles of Cooling Tower Blowdown Piping with High Density Polyethylene (HDPE) (2008)*
- Majority of buried Essential Service Water (ESW) piping was replaced with safety related HDPE piping (2008 to 2009)
- Replaced all Emergency Diesel Generator heat exchangers (2010 to 2011)
- Installed electrical cable manhole sump pumps (2013)
- Replaced all containment coolers and 5 of 11 safety related room coolers
- not in LR scope 12 Callaway ACRS Subcommittee - License Renewal
NEAR TERM PLANT IMPROVEMENTS Refueling Outage 20 (October 2014)
- Reactor Vessel Head Replacement
- Replacing A Train Motor Driven Auxiliary Feedwater Pump room cooler 2015 & 2016
- Cathodic Protection System Modification
- PWSCC mitigation of reactor vessel nozzle and bottom mounted instrumentation tubes
- Replacing B Train Motor Driven Auxiliary Feedwater Pump room cooler
- Independent Spent Fuel Storage Installation 13 Callaway ACRS Subcommittee - License Renewal
Sarah Kovaleski Director, Design Engineering 05/22/2014 License Renewal Application
LICENSE RENEWAL APPLICATION - PROJECT
- Application Development
- Callaway License Renewal Team active since 2007
- Callaway Program Owners and Subject Matter Expert ownership
- Fifth STARS License Renewal Application prepared as part of STARS Alliance
- Industry Interaction
- NEI Working Group Involvement
- Industry Peer Review Process
- Incorporated Industry Lessons Learned 15 Callaway ACRS Subcommittee - License Renewal
LICENSE RENEWAL APPLICATION - DETAILS
- Application Details
- Application submitted on December 15, 2011
- Developed using NUREG-1801 (GALL) Revision 2
- Incorporated 8 License Renewal Interim Staff Guidance documents
- 42 Aging Management Programs
- 3919 Aging Management Review (AMR) lines
- 98.8% consistent with GALL
- License Renewal Commitments
- Included in FSAR Supplement (Appendix A of LRA)
- Will be managed by Callaway Commitment Tracking System consistent with NEI 99-04 Guidelines
- Total of 46 commitments
- 34 associated with aging management programs (AMPs)
- 11 commitments completed/closed 16 Callaway ACRS Subcommittee - License Renewal
AGING MANAGEMENT PROGRAM (AMP)
SUMMARY
42 AMPs Evaluated Plant Consistent With With With Specific with GALL Exception Enhancement Exception &
Enhancement Existing 32 0 15 1 14 2 New 10 0 8 2 0 0 Total of 16 enhancements and 5 exceptions.
17 Callaway ACRS Subcommittee - License Renewal
IMPLEMENTATION & SUSTAINABILITY
- Designated Program Owners and License Renewal Staff
- Participation in NEI License Renewal Implementation Working Group
- Benchmarking others in the Industry
- Leveraging STARS Alliance knowledge and experience
- Self-assessments
- Audits
- Share Operating Experience
- Implementation of LR-ISG-2011-05 for ongoing review of operating experience 18 Callaway ACRS Subcommittee - License Renewal
SAFETY EVALUATION REPORT (SER) - OPEN ITEMS
- Callaway SER contains 5 Open Items
- Scoping of Fire Protection SSCs/NFPA 805
- Reactor Head Closure Studs
- Materials Reliability Program (MRP)-227-A Report Applicant/Licensee Action Items (A/LAIs)
- ASME Code Class 1 Small-Bore Socket Welds
- Effects of the Reactor Coolant System Environment on Fatigue Life of Piping and Components
- Other issues that arose after the SER with Open Items
- LR-ISG-2012-02, Aging Management of Internal Surfaces, Fire Water Systems, Atmospheric Storage Tanks, and Corrosion Under Insulation
- Draft LR-ISG-2013-01, Aging Management of Loss of Coating Integrity for Internal Service Level III (Augmented) Coatings
- Submerged Bolting 19 Callaway ACRS Subcommittee - License Renewal
SER- OPEN ITEM 2.3.3.20-1 Scoping of Fire Protection SSCs Topic (Part 1)
Provide justification for excluding portions of the Turbine Building from the scope of LR Resolution Fire suppression systems added to LR scope:
Auxiliary Boiler Room Turbine Building Various Locations Turbine Bearings Considerations Auxiliary Boiler Room suppression system was subsequently removed from scope by NFPA 805 Status Submitted 20 Callaway ACRS Subcommittee - License Renewal
SER- OPEN ITEM 2.3.3.20-1 Scoping of Fire Protection SSCs Topic (Part 2)
Discuss the changes associated to the LR scope that will occur with the NFPA 805 transition and provide a gap analysis Resolution LRA Amendment updated the LR scope to be consistent with NFPA 805 A Gap Analysis was provided which described the changes to the LRA based on components added/removed from Fire Protection Program scope as a result of the transition to NFPA 805 Considerations The NRC approved the NFPA 805 amendment for Callaway on January 13, 2014 Status Submitted 21 Callaway ACRS Subcommittee - License Renewal
SER- OPEN ITEM B2.1.3-1 REACTOR HEAD CLOSURE STUDS Topic
- Program may not be adequate to detect future wear, loss of materials, or assure that allowable stresses are not exceeded during the PEO Resolution
- Commitments made to:
- Remove Stud #18 prior to PEO
- Inspect stud holes (6) with previous thread damage prior to PEO Considerations
- There have been no RPV stud issues since 1996
- Stud #18 is fully tensioned & proof tested each cycle in the tensioning process Status
- Resolved 22 Callaway ACRS Subcommittee - License Renewal
CALLAWAY REACTOR VESSEL STUD #18
- Fall, 1996 (Refuel 8) - Stud #18 became stuck 2.625 withdrawn during installation.
- The cause for Stud #18 becoming stuck is debris in the stud hole.
- Current thread engagement:
6.505.
- Minimum required thread engagement based on ASME Section III, Division 1 -
Subsection NB is 5.54.
- Stud #18 is fully tensioned and proof tested each cycle.
23 Callaway ACRS Subcommittee - License Renewal
SER- OPEN ITEM B2.1.6-1 MRP-227-A REPORT APPLICANT/LICENSEE ACTION (A/LAI) ITEMS Topic A/LAI No. 1, Demonstrate that the MRP-227-A bases and assumptions are applicable and bounding for the design of Callaway Reactor Vessel Internal components Resolution MRP-191 & MRP-227-A are directly applicable to Callaway NSSS supplier verified all RVI components, as applicable for the design, are included directly in the MRP-191 component lists Considerations Callaway is consistent with MRP-2013-025 atypical fuel design parameters Core design procedures revised to include MRP-2013-025 parameters Plant Specific material fabrication and design are consistent with MRP-191 for cold-worked materials.
Status:
Submitted 24 Callaway ACRS Subcommittee - License Renewal
SER- OPEN ITEM B2.1.6-1 MRP-227-A REPORT APPLICANT/LICENSEE ACTION (A/LAI) ITEMS Topic A/LAI No. 5, Define physical measurement techniques that will be used to determine Reactor Vessel Internals hold-down spring height Resolution Callaway Reactor Vessel Internals hold-down spring is fabricated with type 403 stainless steel that is not subject to stress relaxation Considerations MRP-227-A physical measurements specifically apply to type 304 stainless steel hold-down springs Status
- Resolved 25 Callaway ACRS Subcommittee - License Renewal
SER- OPEN ITEM B2.1.6-1 MRP-227-A REPORT APPLICANT/LICENSEE ACTION (A/LAI) ITEMS Topic
- A/LAI No. 7, Determine if inspections for loss of fracture toughness due to thermal & irradiation embrittlement apply to Reactor Vessel Internals components fabricated from cast austenitic stainless steel (CASS),
martensitic stainless steel, or precipitation hardened, martensitic stainless steel Resolution
- MRP-191 & MRP-227-A are directly applicable to Callaway.
- No additional components were identified for Callaway Considerations
- Callaway has two Reactor Vessel Internals CASS component groups:
- Bottom mounted instrument column cruciforms
- One offset instrument column cruciform bolted to the underside of the lower core plate Status
- Resolved 26 Callaway ACRS Subcommittee - License Renewal
SER- OPEN ITEM B2.1.6-1 MRP-227-A REPORT APPLICANT/LICENSEE ACTION (A/LAI) ITEMS Topic A/LAI No. 8, Item (5), Address those Cumulative Usage Factor (CUF) analyses for RVI components that are TLAAs for the impact of reactor coolant on metal fatigue Resolution The fatigue monitoring program will evaluate the effects of the reactor coolant system water environment on the RVI components with existing fatigue CUF analyses Status
- Resolved 27 Callaway ACRS Subcommittee - License Renewal
SER- OPEN ITEM B2.1.20-1 ASME CODE CLASS 1 SMALL-BORE SOCKET WELDS Topic Number of ASME Code Class 1 Small-Bore Socket Welds in LR scope Resolution Original count did not include welds on 1 piping 1 weld exams not required for ISI Program Detailed recount performed with independent verification of results by ISI Program Owner to confirm final population of in scope socket welds ISI database updated to identify small bore socket welds in the scope of this AMP Considerations Extent of Condition review performed
- Confirmed ASME Code Class 1 Small-Bore Butt Weld population Status Resolved 28 Callaway ACRS Subcommittee - License Renewal
SER- OPEN ITEM 4.3.4-1 EFFECTS OF THE RCS ENVIRONMENT ON FATIGUE LIFE OF PIPING AND COMPONENTS Topic
- Justify the ranking and comparison used to determine that sentinel locations were appropriate for Callaway.
Resolution
- Same fatigue curve for each material was used for the analyses
- The analyses have been performed using the same level of rigor
- Any transient lumping used in the various analyses have not skewed the screening and ranking results
- The comparison of Cumulative Usage Factors across multiple zones is valid Considerations
- Revised CUF and Fen screening process to not allow: One material in a Thermal Zone to bound other materials in the same Thermal Zone and one material in a Thermal Zone to bound other materials in another Thermal Zone Status
- Resolved 29 Callaway ACRS Subcommittee - License Renewal
ISSUES SINCE SER W/ OPEN ITEMS - CLEVIS BOLTS Topic
- Address similarity of Callaway design to reported failures at one domestic Westinghouse-designed PWR in 2010 Resolution
- Clevis insert assembly geometry differs from design of plant with failures
- Materials used are similar
- Multiple inspections showed no degradation or damage
- Existing ASME Section XI Inservice Inspection program is capable of detecting cracking Status
- Submitted 30 Callaway ACRS Subcommittee - License Renewal
ISSUES SINCE SER W/ OPEN ITEMS - LR-ISG-2012-02 Topic
- Aging Management of Internal Surfaces, Fire Water Systems, Atmospheric Storage Tanks, and Corrosion Under Insulation Resolution
- Plant specific operating experience was reviewed & confirmed the need for additional aging management of recurring internal corrosion in raw water environments
- Fire Water AMP will be consistent with NFPA 25 requirements
- Aboveground Metallic Tanks AMP revised to be consistent with ISG criteria
- Fire Water Storage Tanks now managed by Fire Water AMP
- Outdoor insulated components & indoor insulated components exposed to condensation will have insulation removed to inspect for external surface degradation Status
- Submitted 31 Callaway ACRS Subcommittee - License Renewal
ISSUES SINCE SER W/ OPEN ITEMS -
DRAFT LR-ISG-2013-01 Topic
- Loss of Coating Integrity for Service Level Ill and Other Coatings Resolution
- Visually inspect in-scope coatings installed on accessible interior surfaces
- Coatings with no degradation or with cracking/flaking evaluated as acceptable, will have inspections performed every six years
- Coatings with blisters, peeling, delaminations or rusting determined not to require remediation, will have inspections performed every four years
- Training & qualification in accordance with ASTM Standards endorsed in RG 1.54 including supplemental staff guidance Considerations
- Scope: 6 heat exchangers, 5 strainers, 2 tanks, Circulating & Service Water pipe Status
- Submitted 32 Callaway ACRS Subcommittee - License Renewal
ISSUES SINCE SER W/ OPEN ITEMS -
SUBMERGED BOLTING Topic
- Method of detecting loss of material & loss of preload in submerged bolting Resolution
- ESW pumps stainless steel bolts inspected on a 6 year sample basis &
tested quarterly for pump pressure/flow/vibration
- Emergency Diesel Generator fuel oil transfer pump bolts inspected on a 10 year sample basis and tested periodically for pump pressure/flow
- Service water pump bolting is replaced during pump refurbishment (6 year basis)
- Waste water pump bolting inspected on a 6 year sample basis, visually inspected opportunistically during maintenance, & functionality verified each shift during operator rounds Status
- Submitted 33 Callaway ACRS Subcommittee - License Renewal
CONCLUDING REMARKS In anticipation of extended operation, Ameren Missouri has:
- Improved our Operating Experience program to identify, learn from, and share information on plant aging
- Invested in plant hardening initiatives
- Selected plant modifications for safe, extended operations 34 Callaway ACRS Subcommittee - License Renewal
COMMENTS AND QUESTIONS?
35 Callaway ACRS Subcommittee - License Renewal
Advisory Committee on Reactor Safeguards License Renewal Subcommittee Callaway Plant, Unit 1 Safety Evaluation Report (SER) with Open Items May 22, 2014 John Daily, Sr. Project Manager Office of Nuclear Reactor Regulation 1
Presentation Outline
- Overview of Callaway license renewal review
- Region IV License Renewal Onsite Inspection
- SER Section 2, Scoping and Screening Review
- SER Section 3, Aging Management Review
- SER Section 4, Time-Limited Aging Analyses
- Issues that arose after the SER with Open Items 2
Facility Facts
- License Renewal Application (LRA) submitted December 15, 2011
- Applicant: Union Electric Company (Ameren Missouri)
- Facility Operating License Nos. NPF-30
- Current License Expiration Date: October 18, 2024
- Approximately 25 miles east-northeast of Jefferson City, Missouri
- PWR (Westinghouse) with a carbon steel-lined, concrete structure containment 3
Audits and Inspections
- Scoping and Screening Methodology Audit
- April 16-19, 2012
- Aging Management Program (AMP) Audit
- April 30-May 10, 2012
- Environmental Audit
- May 22-24, 2012
- Region IV Inspection (Scoping and Screening & AMPs)
- September 10-November 7, 2012 4
Overview (SER)
- Safety Evaluation Report (SER) with Open Items issued April 23, 2013
- Scoping of Fire Protection SSCs
- Reactor Head Closure Studs
- PWR Vessel Internals Program Applicant/Licensee Action Items (A/LAIs)
- ASME Code Class 1 Small-Bore Socket Welds
- Environmentally Assisted Fatigue on the Reactor Coolant Pressure Boundary
- Other issues arose after the SEROI was issued
- Related to recently-issued LR-ISGs and some recently-added SSCs
- The final SER is scheduled for September 2014 5
Regional Inspections Overview Five inspectors for 2 weeks Scoping inspection Aging management programs inspection 6
Regional Inspections Inspection Results Condensate Storage Tank: Lack of thread engagement for some accessible CST anchor bolts Cathodic protection for buried piping: Needs upgrade to be consistent with GALL Report recommendations Emergency fuel oil storage tank: Coating blisters not adequately tracked/managed Buried piping procedures: Improper exams, insufficient guidance in several cases The applicant initiated plans and corrective actions to address these items 7
Regional Inspections Inspection Conclusions Scoping of non-safety SSCs and application of the AMPs to those SSCs were acceptable Reasonable assurance exists that aging effects will be managed and intended functions maintained 8
SER Section 2 Summary Structures and Components Subject to Aging Management Review
- Section 2.1, Scoping and Screening Methodology
- Section 2.2, Plant-Level Scoping Results
- Sections 2.3, 2.4, 2.5 Scoping and Screening Results 9
SER Section 2 Open Item Open Item 2.3.3.20-1: Scoping of Fire Protection SSCs
- Issue:
- Some SSCs incorrectly omitted from Scope
- Changes to LRA due to NFPA 805 Amendment request unclear
- Applicant added SSCs back into scope
- Applicant provided gap analysis details for NFPA 805 impacts
- Responses were over the period April 2013 - April 2014
Section 3: Aging Management Review
- 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 11
SER Section 3 3.0.3 - Aging Management Programs
- 42 Aging Management Programs (AMPs) presented by applicant and evaluated in the SER
- 32 existing AMPs, 10 new AMPs
- 23 AMPs consistent with the GALL Report (i.e., without enhancements and/or exceptions)
- 19 AMPs consistent with enhancements and/or exceptions
- No plant-specific AMPs 12
SER Section 3 Open Items Open Item B2.1.3-1: Reactor Head Closure Studs
- Issue:
- Thread damage in 10 RV flange hole locations out of 54
- One closure stud stuck partially inserted since 1996
- Applicant proposed 2 commitments to resolve:
- to inspect flange holes with worst thread damage
- to remove stuck stud
- Staff finds the changes to the program acceptable
- Staff will consider whether to use a license condition
SER Section 3 Open Items Open Item B2.1.6-1: Reactor Vessel Internals (PWR)
- Issue: Complete responses to MRP 227-A needed
- Applicant/Licensee Action Items not complete
- Address clevis insert bolts Operating Experience
- Applicant initially proposed to address before PEO:
- Applicant has agreed to address in LRA and has provided additional information
SER Section 3 Open Items Open Item B2.1.20-1: ASME Code Class 1 Small-Bore Socket Welds
- Issue: Large discrepancy among successive population counts of small-bore socket welds
- Also confirmation that counting errors not encountered elsewhere
- Applicant conducted several counts, eventually confirming
- 80 small-bore socket welds
- 343 small-bore butt welds
- 4.1 Identification of TLAAs
- 4.2 Reactor Vessel Neutron Embrittlement Analysis
- 4.3 Metal Fatigue
- 4.4 Environmental Qualification of Electric Equipment
- 4.5 Concrete Containment Tendon Prestress Analyses
- 4.6 Containment Liner Plate, Metal Containments, and Penetration Fatigue Analyses
- 4.7 Other Plant-Specific TLAAs 16
SER Section 4 Open Item Open Item 4.3.4-1: Environmentally Assisted Fatigue (EAF) in Reactor Coolant Pressure Boundary components
- Issue: Staff identified questions on methodology
- Underlying assumptions
- How various EAFs were compared
- Validity of comparing EAF for multiple systems/components
- Applicant supplied additional information in April 2013 and August 2013 responses
Issues Identified Since SER with Open Items Several issues arose between issuance of the SER with Open Items and this ACRS Subcommittee meeting.
Staff issued RAIs to address these and received responses.
The issues and resolutions will be documented in the final SER and presented to the ACRS full committee.
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Loss of Coating Integrity -
Internal Coatings Loss of coating integrity of internal coatings
- Can expose the base material and foul downstream components
- Applicant Response
- Revised multiple AMPs
- Incorporated periodic inspections of internal coatings
- Added acceptance criteria for coatings
- Clarified personnel training
- Staff is reviewing supplemental information from the applicant and expects to close this in the final SER.
- Resolution will be presented to the ACRS full committee 19
Internal Surfaces Corrosion and Corrosion under Insulation Recurring internal corrosion, flow blockages in fire water systems, corrosion under insulation
- Issues arising in recent OE, not addressed by (then) existing staff guidance
- Response included (examples):
- Additional/augmented tests/inspections for fire water systems
- Tests/inspections for flow blockages of wetted piping
- Periodic inspections of outdoor insulated and indoor insulated components
- Staff is reviewing applicant submittals and expects to close the issue in the final SER
- Resolution will be presented to the ACRS full committee 20
Inspection of Submerged Bolting Bolting associated with submerged pumps and normally inaccessible for inspection
- LRA amendment added bolting on submerged pumps in several systems
- Staff concerns regarding parameters monitored, inspection methods, and inspection frequencies
- Applicant response
- Condition monitoring of bolt heads when accessible during dewatering, and of threads during disassembly
- Performance monitoring of associated pumps
- Staff is reviewing applicant submittals and expects to close the issue in the final SER
- Resolution will be presented to the ACRS full committee 21
Conclusion Pending satisfactory resolution of the open items, the staff will render its decision in the final SER on meeting the requirements of 10 CFR 54.29(a) for the license renewal of Callaway Plant Unit 1 22