ML15037A719
| ML15037A719 | |
| Person / Time | |
|---|---|
| Site: | Sequoyah  |
| Issue date: | 02/06/2015 |
| From: | Kent Howard Advisory Committee on Reactor Safeguards |
| To: | Advisory Committee on Reactor Safeguards |
| Howard K | |
| References | |
| NRC-1196 | |
| Download: ML15037A719 (129) | |
Text
UNITED STATES NUCLEAR REGULATORY COMMISSION ADVISORY COMMITTEE ON REACTOR SAFEGUARDS WASHINGTON, DC 20555 - 0001 February 6, 2015 MEMORANDUM TO: ACRS Members FROM: Kent Howard, Senior Staff Engineer /RA/
Technical Support Branch, ACRS
SUBJECT:
CERTIFICATION OF THE MINUTES OF THE SEQUOYAH NUCLEAR PLANT, UNITS 1 AND 2 PLANT LICENSE RENEWAL SUBCOMMITTEE HELD ON NOVEMBER 5, 2014 The minutes for the subject meeting were certified on February 4, 2015. Along with the transcripts and presentation materials, this is the official record of the proceedings of that meeting. A copy of the certified minutes is attached.
Attachment:
As stated cc: E. Hackett M. Banks
UNITED STATES NUCLEAR REGULATORY COMMISSION ADVISORY COMMITTEE ON REACTOR SAFEGUARDS WASHINGTON, DC 20555 - 0001 MEMORANDUM TO: Kent Howard, Senior Staff Engineer Technical Support Branch, ACRS FROM: Gordon R. Skillman, Chairman Plant License Renewal Subcommittee
SUBJECT:
CERTIFICATION OF THE MINUTES OF THE SEQUOYAH NUCLEAR PLANT, UNITS 1 AND 2 PLANT LICENSE RENEWAL SUBCOMMITTEE HELD ON NOVEMBER 5, 2014 I hereby certify, to the best of my knowledge and belief, that the Minutes of the subject meeting held on November 5, 2014, are an accurate record of the proceedings for that meeting.
/RA/ 02/04/15 Gordon R. Skillman, Chairman Date Plant License Renewal Subcommittee
Certified by: Gordon R. Skillman Certified on: February 4, 2015 ADVISORY COMMITTEE ON REACTOR SAFEGUARDS MINUTES OF SEQUOYAH NUCLEAR PLANT, UNITS 1 AND 2 NOVEMBER 5, 2014 The ACRS Plant License Renewal Subcommittee held a meeting on November 5, 2014 in Room T2B3, 11545 Rockville Pike, Rockville, Maryland. The meeting convened at1:30 p.m.
and adjourned at 3:13 p.m. The entire meeting was open to the public. Kent L. Howard, Sr.
was the Designated Federal Official for the meeting.
ATTENDEES ACRS MEMBERS/CONSULTANTS Gordon Skillman, Member Ronald Ballinger, Member Dana Powers, Member Harold B. Ray, Member Peter Riccardella, Member Michael T. Ryan, Member Stephen Schultz, Member John Stetkar, Member NRC Staff Emmanuel Sayoc, NRR/DLR Joel Rivera-Ortiz, NRC Region II (via Bridgeline)
Lindsay Robinson, NRR/DLR Daneira Melendez, NRR/DLR Roger Kalikian, NRR/DLR Andrew Pinaris, NRR/DLR Seung Min, NRR/DLR Mark Yoo, NRR/DLR Juan Lopez, NRR/DLR Michael Marshall, NRR/DLR William Holston, NRR/DLR Bill Rogers, NRR/DLR Giovanni Facco, NRR/DLR Allen Hiser, NRR/DLR John Daily, NRR/DLR Kimberly Green, NRR/DLR Mohammad A. Sadollah, NRR/DLR James Medoff, NRR/DLR Chris Miller, NRR/DLR Yoira Diaz, NRR/DLR 1
OTHER ATTENDEES David M. Spears, Tennessee Valley Authority (TVA)
Joy Williams, TVA Kelli Yates, TVA Kylie Loomis, TVA Harold Williams, TVA Michael McBreasty, TVA Raymond Hicks, FirstEnergy Nuclear Operating Company (FENOC)
Cliff Custer, FENOC Lynn Goodman, DTE Electric Marc A. Brooks, DTE Electric Randy Breymaier, DTE Electric Bruce Cummings, DTE Electric Chris Wilson, Exelon
SUMMARY
The purpose of the meeting was to review the license renewal application (LRA) for the Sequoyah Nuclear Plant, Units 1 and 2 (Sequoyah)) and the draft Safety Evaluation Report (SER) with open items. The briefing was provided by representatives from the NRC staff and the applicant, Tennessee Valley Authority (TVA). The meeting transcripts are attached and contain an accurate description of each matter discussed during the meeting. The presentation slides and handouts used during the meeting are attached to these transcripts.
The following table lists the significant issues that were discussed during the meeting with the corresponding pages in the transcript.
SIGNIFICANT ISSUES Reference Pages Issue in Transcript Chairman Gordon Skillman opened the meeting. 4 Chairman Skillman inquired about the equipment reliability index between 12 the two units. TVA responds TVA discussed near term and future plant improvements 17 Chairman Skillman inquired about cathodic protection of buried piping.
18 TVA responds.
2
TVA stated that the LRA was developed using GALL Rev. 2. 23 TVA reviewed 4100 Aging Management Review (AMR) line items 23 TVA stated that 43 aging management programs are required to manage the effects of aging for the period of extended operation. There are 31 existing programs and 12 new. Twenty programs are consistent with 23-24 GALL. Rev 2. Three programs were identified as not being consistent with GALL during the process and required enhancements. One of those programs required enhancements (Fire Water Systems).
TVA stated that there are Forty-three commitments associated with the aging management programs, and one associated with the operating 24 experience program (44 commitments total).
Chairman Skillman inquired about scoping. TVA responds. 25-29 Member Schultz inquired about what is meant by an informal Operating Experience Report, and to put it in the context of what is meant by doing 30-31 things in advance of fleet procedural guidance? TVA responds.
Chairman Skillman and Member Schultz inquired is anyone (TVA) 31-36 considering Subsequent License Renewal. TVA responds.
TVA states that the Safety Evaluation Report contains one open item, two 36 license conditions, and no confirmatory items.
TVA discusses the open item (Reactor Vessel Internals Program, 36-43 specifically dealing with neutron fluence at the Upper Core Plate).
TVA concludes their portion of the meeting. 43-44 Chairman Skillman inquired about verification of CRD and nozzle thickness 46-48 and nozzle wear. TVA responds Member Ballinger inquires about VT3 inspections. TVA responds 51 ACRS Chairman Stetkar inquires about Underground Medium Voltage 52-57 Cable failures and sump pump problems at Sequoyah. TVA responds TVA responds to question concerning plan for inspection of the Upper Core 58 Plate.
Manny Sayoc, Project Manager from Division of License Renewal (DLR) for 59 Sequoyah begins DLR presentation.
During AMR audit, 35 reviewers examined TVA programs and 61-62 documentation.
DLR staff completed initial review of Sequoyah LRA, and issued the SER 62 with one open item on September 29, 2014 3
Member Schultz inquired about NRC staff participation in the Region II 62-63 inspections. DLR responds.
Joel Rivera-Ortiz of Region II begins his presentation 63-67 Chairman Skillman inquired about the adequacy of inspecting the Essential Raw Cooling Water (ERCW) system as opposed to selecting other critical 67-68 systems. Region II responds.
Member Schultz inquires about containment walkdowns. Region II 68-70 responds.
ACRS Chairman Stetkar inquires about the ERCW piping condition and 71-73 problems.
DLR reported that, on the basis of its review, 17 programs were consistent with GALL Rev. 2, Twenty-four programs are consistent with 74 enhancements, one was consistent with enhancements and exceptions, one was plant specific.
DLR discusses open item. 74-77 DLR determined that TVA has provided an accurate list of Time Limited 77 Aging Analyses as required by 10 CFR 54.21C1.
Member Riccardella inquires about the open item response received from 78-81 TVA on estimated fluence for Upper Core Plate. DLR responds.
Chairman Skillman adjourned the meeting at 3:13 p.m. 83 Action Items Reference Pages Action Items in Transcript TVA and DLR final documentation have to agree on final count for AMPs 23-24 and 74 Documents Provided to the Subcommittee
- 1. Sequoyah Nuclear Plant, Units 1 and 2, License Renewal Application (Package), dated January 7, 2013 (ML130240007).
- 2. Safety Evaluation Report with Open Items Related to the License Renewal of Sequoyah Nuclear Plant Units 1 and 2, dated September 2014 (ML14266A033).
4
- 3. NRC Aging Management Programs Audit Report Regarding the Sequoyah Nuclear Plant Units 1 and 2, dated June 13, 2013 (ML13141A320).
- 4. NRC NUREG 1801, Revision 2, Generic Aging Lessons Learned (GALL) Report, dated December 2010 (ML103409041).
- 5. NRC NUREG-1800, Revision 2, Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants (SRP-LR), dated December 2010 (ML103409036).
- 6. Scoping and Screening Methodology Audit Report regarding the Sequoyah Nuclear Plant Units 1 and 2, dated May 16, 2013 (ML13119A135).
- 7. NRC Regulatory Guide 1.188, Revision 1, Standard Format and Content for Application to Renew Nuclear Power Plant Operating Licenses, dated September 2005 (ML082950585).
- 8. Sequoyah Nuclear Plant Units 1 and 2- NRC License Renewal Inspection, Inspection Report 05000327/2013012 AND 05000328/2013012, dated January 31, 2014 (ML14031A291).
5
Official Transcript of Proceedings NUCLEAR REGULATORY COMMISSION Title: Advisory Committee on Reactor Safeguards Plant License Renewal Subcommittee Docket Number: (n/a)
Location: Rockville, Maryland Date: November 05, 2014 Work Order No.: NRC-1196 Pages 1-84 NEAL R. GROSS AND CO., INC.
Court Reporters and Transcribers 1323 Rhode Island Avenue, N.W.
Washington, D.C. 20005 (202) 234-4433 6
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 WEDNESDAY 10 NOVEMBER 5, 2014 11 + + + + +
12 ROCKVILLE, MARYLAND 13 + + + + +
14 The Subcommittee met at the Nuclear 15 Regulatory Commission, Two White Flint North, Room 16 T2B3, 11545 Rockville Pike, at 1:30 p.m., Gordon 17 Skillman, Chairman, presiding.
18 COMMITTEE MEMBERS:
19 GORDON R. SKILLMAN, Chairman 20 RONALD BALLINGER, Member 21 PETER RICCARDELLA, Member 22 HAROLD B. RAY, MEMBER 23 MICHAEL T. RYAN, Member 24 STEPHEN SCHULTZ, Member 25 JOHN W. STETKAR, Member NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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2 1 DESIGNATED FEDERAL OFFICIAL:
2 KENT HOWARD 3 ALSO PRESENT:
4 JOHN CARLIN, TVA 5 DARREN BOEHM, TVA 6 DENNIS DIMOPOULOS, TVA 7 ERIN HENDERSON, TVA 8 MIKE HENDERSON, TVA 9 ADAM KEYSER, TVA 10 HENRY LEE, TVA 11 DENNIS LUNDY, TVA 12 WILLIAM PIERCE, TVA 13 PAUL SIMMONS, TVA 14 CHRIS WEBB, TVA 15 NRC STAFF:
16 ALLEN HISER, NRR/DLR 17 ROGER KALIKIAN 18 CHRIS MILLER, NRR/DLR 19 JOEL RIVERA-ORTIZ, RII (by teleconference) 20 EMMANUEL SAYOC, NRR/DLR 21 22 23 24 25 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 Welcome 3 by Gordon Skillman, Chairman.................4 4 Staff Introduction 5 by Chris Miller, Dir. DLR/NRR................6 6 Tennessee Valley Authority B Sequoyah Nuclear Plant, 7 Units 1 and 2 8 by John Carlin, TVA and team.................8 9 NRC Staff Presentation Opening Remarks 10 by Chris Miller, Dir. DLR/NRR...............60 11 NRC Staff Presentation SER Overview 12 by Emmanuel Sayoc, PM.......................60 13 14 15 16 17 18 19 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 (1:13 p.m.)
3 CHAIRMAN SKILLMAN: Good afternoon.
4 Welcome. I'm Gordon Skillman, Chairman of the Plant 5 License Renewal Subcommittee. The subcommittee will 6 review the license renewal application for the Sequoyah 7 Nuclear Plant Units 1 and 2.
8 ACRS members in attendance are Harold Ray, 9 Ron Ballinger, Steve Schultz, Dana Powers, Mike Ryan.
10 We anticipate John Stetkar, the ACRS chairman. The 11 designated federal official is Kent Howard.
12 This afternoon we will hear presentations 13 from the Division of License Renewal from Region II.
14 And from Tennessee Valley Authority regarding this 15 matter, this subcommittee will gather information, 16 analyze relevant issues and facts and formulate 17 proposed positions and actions as appropriate for 18 deliberation by the committee.
19 The rules for participation in today's 20 meeting have been announced as part of the notice of 21 this meeting previously published in the Federal 22 Register.
23 We have not received written comments or 24 requests for time to make oral statements from members 25 of the public regarding today's meeting. The entire NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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5 1 meeting will be open to public attendance.
2 There will be a phone bridge line. To 3 preclude interruption of the meeting, the phone will 4 be placed in a listen in mode during the presentations 5 and the committee discussion.
6 A transcript of this meeting is being kept 7 and will be made available as stated in the Federal 8 Register notice.
9 Therefore, I request that participants in 10 this meeting use the microphones located throughout the 11 meeting room when addressing the subcommittee.
12 The participants are also requested to 13 please identity themselves and to please speak with 14 sufficient clarity and volume so that they can be 15 readily heard.
16 I also ask that all attendees silence their 17 electronic devices. We will now proceed with the 18 meeting, and I call upon Chris Miller to begin the 19 presentation.
20 (Simultaneous speaking) 21 MALE PARTICIPANT: I just had him a minute 22 ago. He's on his way over.
23 CHAIRMAN SKILLMAN: Okay. We'll wait. We 24 will wait.
25 (Whereupon, the above-entitled matter NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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6 1 went off the record at 1:16 p.m. and resumed at 1:19 2 p.m.)
3 CHAIRMAN SKILLMAN: Ladies and gentlemen, 4 we're back in session. I had gotten to the point of 5 the script where I was going to ask Chris Miller, 6 welcome Chris, to please proceed from here.
7 (Simultaneous speaking) 8 MR. MILLER: My calendar said 1:30, so --
9 CHAIRMAN SKILLMAN: I don't know where the 10 error came. We had been at 1300 for the last two 11 months, so I don't know where the 30 minute change came.
12 MR. MILLER: Yes, I'm not aware either, but 13 I think we can go ahead and get started.
14 (Simultaneous speaking) 15 MR. MILLER: Thank you. Whatever the 16 discrepancy was, I apologize.
17 CHAIRMAN SKILLMAN: Thank you everybody for 18 your patience. Thank you. Chris, go ahead.
19 MR. MILLER: Thank you, Mr. Chairman. I'm 20 Chris Miller, Director of Division of License Renewal.
21 With me here I have Yoira Diaz, and she's the Chief of 22 Projects, Branch 1.
23 We have a number of our members in the room, 24 and I won't introduce them all, but we'll introduce most 25 as they come up. I think we have Joel Rivera on the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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7 1 phone. Can we just test that?
2 CHAIRMAN SKILLMAN: On the bridge line, 3 anyone that's there, please speak up.
4 MALE PARTICIPANT: I don't know that it's --
5 MR. MILLER: I'm told they're still trying 6 to get that, so we'll work to get him in.
7 CHAIRMAN SKILLMAN: Okay.
8 MR. MILLER: He's our lead inspector, and 9 he's in Region II. So hopefully we'll be able to make 10 that tie in. And our presentation will be done by Mr.
11 Emmanuel Sayoc, our Safety PM.
12 And also our Senior Technical Advisor, Dr.
13 Allen Hiser, he's right there. And as I mentioned, 14 after the presentation we'll introduce one by one.
15 Thank you.
16 This is our ACRS subcommittee meeting for the 17 license renewal application of the Sequoyah Nuclear 18 Power Units 1 and 2. The SER will, with open items was 19 issued on September 29, 2014 with one open item.
20 And its resolution will be documented in the 21 final SER. The one open items is regarding the reactor 22 vessel internals program related to the materials 23 reliability program, MRP 227, Action Item 1.
24 It is summarized in the SER reviewed by the 25 ACRS members. Since the issuance of the SER with open NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 1 items, the staff has been working diligently to try to 2 get resolution on this item.
3 The staff will summarize its completed 4 review in the final SER and present its findings in the 5 ACRS to the full committee.
6 At this time I'd like to turn the 7 presentation over the Tennessee Valley Authority and 8 the Site Vice President, John Carlin to introduce his 9 people and commence the presentation.
10 MR. CARLIN: Thanks, Chris. Mr. Chairman, 11 I'm John Carlin. I'm the Site Vice President at 12 Tennessee Valley Authority's Sequoyah Nuclear Plant.
13 We really appreciate the opportunity to be 14 here with you today to review the license application 15 for the Sequoyah Plan.
16 This has been a long four year journey, and 17 it's been a very, very important journey for the 18 station. And we look forward to discussing Sequoyah 19 with you.
20 To start mainly, the members of the team at 21 the table to introduce themselves.
22 MR. SIMMONS: Paul Simmons, I'm the station 23 plant manager.
24 MR. PIERCE: William Pierce, the site 25 engineer and director at the station.
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9 1 MR. DIMOPOULOS: Dennis Dimopoulos from 2 engineering.
3 MR. HENDERSON: Michael Henderson, 4 engineering programs manager.
5 MS. HENDERSON: I'm Erin Henderson. I'm 6 the site licensing manager.
7 MR. LEE: Henry Lee, licensing.
8 MR. CARLIN: Today we also have brought with 9 us a team of subject matter experts. I'd like the 10 entire group to stand as a group.
11 CHAIRMAN SKILLMAN: The center of gravity in 12 the room tilts.
13 MR. CARLIN: If you feel the building tilt, 14 back up. Thank you very much. We really appreciate 15 the men and women who have joined us today and their 16 support.
17 We also have other people on the telephone 18 bridge listening in to provide additional technical 19 support to your discussions today.
20 Paul Simmons will briefly discuss Sequoyah's 21 plant history and background. Paul is a long tenured 22 person, previously a senior reactor operator at the 23 facility.
24 William Pierce will talk about the major 25 modifications. Dennis Dimopoulos and Erin Henderson NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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10 1 will talk about the license renewal application as well 2 as the safety evaluation.
3 And Michael Henderson will discuss our open 4 item. Again, we thank you for meeting with us today, 5 and that concludes my comments.
6 MR. SIMMONS: Thanks, John. Okay. We'll 7 go to Slide 7. The Sequoyah Unit 1, 2 units are located 8 on a 525 acre plot adjacent to the Chickamauga reservoir 9 on the Tennessee River, approximately 18 miles 10 northeast of Chattanooga, Tennessee.
11 Sequoyah supplies approximately 8 million 12 people through 158 distributors in the Tennessee Valley 13 area. Our plant is a two unit Westinghouse 4-loop 14 pressurized water reactor.
15 The generator output capability of each unit 16 at Sequoyah is 1199 megawatts of output rated core 17 power. The Sequoyah containment is a freestanding 18 steel vessel with an ice condenser and separate 19 reinforced concrete shield building.
20 We have two natural draft cooling towers used 21 in helper mode as required to maintained the Tennessee 22 River and environmental commitments that we've made for 23 operating the plant.
24 We have two switchyards on the facility that 25 you can see on the overhead view, 161-KV switchyard and NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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11 1 a 500-KV switchyard.
2 The Unit 1 output goes to the 500-KV 3 switchyard, and the Unit 2 output goes to the 161 4 switchyard. And both those switchyard are 5 interconnected through transformers.
6 We'll go to Slide 9. Slide 9 slows where the 7 station is located relative to the city of Chattanooga, 8 Tennessee.
9 In Slide 10, a little bit more of the 10 background. The construction permit for Sequoyah was 11 issued in May 1970. Our operating license for Unit 1 12 was issued September 17, 1980. For Unit 2, it was 13 issued September 15, 1981.
14 And commercial operation for Unit 1 15 commenced July 1, 1981 and for Unit 2, June 1, 1982.
16 We did do a power upgrade of approximately 44 megawatts 17 thermal on both units in 2002.
18 And we replaced steam generators on Unit 1 19 in 2003 and most recently on Unit 2 in 2013. And today 20 we've had very good operational performance out of 21 these steam generators on both units.
22 Our current status, Sequoyah Unit 1 and Unit 23 2 are operating at 100 percent power. Sequoyah Unit 24 1 is at 100 percent on our INPO Index, and Sequoyah Unit 25 2 is 100 percent on the INPO index.
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12 1 It gets top quartile performance, 97.5. Our 2 equipment reliability index for Unit 1 is at 97 percent, 3 and at Unit 2 it's at 98 percent. And our next 4 refueling outage for Unit 1 is April 2015, and for Unit 5 2 it's November 2015.
6 CHAIRMAN SKILLMAN: Paul, those are 7 admirable numbers. What is the difference, if it's 8 worth talking about, the equipment reliability index 9 between the two units.
10 MR. SIMMONS: This is a slight difference in 11 the index, Mr. Chairman, of 1 percent. And typically 12 what that has been for us has been some unplanned LCOs 13 that we're working through over the last year that have 14 slightly differed between Unit 1 and Unit 2.
15 CHAIRMAN SKILLMAN: Thank you.
16 MR. SIMMONS: Mr. Chairman, that completes 17 my plant overview presentation pending any questions.
18 I'll turn it over to William Pierce.
19 MR. PIERCE: Good afternoon. My name is 20 William Pierce, and this afternoon I will be going over 21 major modifications and near-term improvements that 22 have been conducted at the station.
23 The first item that I'll be going over, which 24 is listed on Page, Slide 13 includes installing full 25 strength weld overlays on pressurizer locations on Unit NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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13 1 1 in 2007, and we installed four structure weld overlays 2 on pressurizer locations on Unit 2 in 2006.
3 There were two purposes for installing full 4 strength weld overlays on these locations. The first 5 purpose was for volumetric inspection purposes, and the 6 second purpose was for primary water stress corroding, 7 cracking resistance.
8 The second item that was listed there far as 9 major modifications that have been completed at 10 Sequoyah includes replacing portions of, balance the 11 plant side piping with flow accelerated corrosion 12 resistant piping.
13 The material of choice that we've chosen to 14 use at the station has been two and a quarter chrome, 15 1 percent moly, which is for accelerated corrosion 16 resistance.
17 As Paul mentioned earlier, we did replace 18 steam generators on Unit 1 in 2003 and then on Unit 2 19 in 2013. And the tubing material that we currently use 20 for our steam generators is alloy 69.
21 MEMBER BALLINGER: Is that thermally 22 treated?
23 MR. PIERCE: Yes, sir. That is correct, 24 thermally treated alloy 69. In addition, we have 25 replaced main condenser tube bundles with titanium NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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14 1 tubes. And we also have titanium clad tube sheets.
2 Also, we replaced portions of our carbon 3 steel sacrilated raw water piping. Currently we have 4 replaced piping this physical year in 2014.
5 We do have funding scheduled in the out years 6 for 2015, 2016 and 2017 for piping replacements. In 7 addition, we replaced fire protection pumps, tanks and 8 changed water source from raw water to potable water.
9 And to close out this slide, we replaced 10 containment spray heat exchanger 1B and component 11 cooling water heat exchangers.
12 CHAIRMAN SKILLMAN: Let me ask you a 13 question on that issue. I see in the SER the 14 description that you're now taking suction from, one 15 each, from your 300,000 gallon potable water tanks.
16 And those are fed by a municipal utility. To 17 what extent is this unit dependent upon other municipal 18 utilities for services such as that?
19 MR. DIMOPOULOS: With respect to the fire 20 water system, we do take, I'm sorry. I'm Dennis 21 Dimopoulos from engineering, Tennessee Valley 22 Authority.
23 The potable water system that we use to 24 supply our fire header system does come from a local 25 utility and has an additional back up onsite. We could NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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15 1 use raw water from the river associated with that.
2 CHAIRMAN SKILLMAN: Okay. That's half my 3 question. The other half is to what extent are you 4 depending on offsite municipal utilities for services 5 such as that. So water is coming in from an offsite 6 vendor --
7 MR. DIMOPOULOS: Right.
8 CHAIRMAN SKILLMAN: -- for instance. Are 9 there are dependencies like that associated with the 10 unit that are substantive, that we should talk about?
11 MR. DIMOPOULOS: Mr. Chairman, I cannot 12 think of any other outside sources but do note the 13 potable water, and we recognize that's a possibility 14 that we could lose that.
15 And we do design around it such that we have 16 onsite backup, so we do not depend on a municipality.
17 MR. SIMMONS: Mr. Chairman, the other piece 18 that we do have services from is for our sewage 19 treatment. We use that with the local municipality.
20 So that's the other interface that we have with the 21 local Soddy-Daisy city.
22 CHAIRMAN SKILLMAN: Okay. Does that, 23 should we interpret then you don't have a sewage plant 24 onsite, and you do not have sewage operators on site?
25 MR. SIMMONS: That's correct.
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16 1 CHAIRMAN SKILLMAN: Yes, sir. I 2 understand. Paul, thank you. Dennis, thank you.
3 MR. SCHULTZ: William, on the slide that 4 we're discussing here in the last three bullets here, 5 has there been equal treatment on both units in regard 6 to these modifications?
7 MR. PIERCE: Yes, that is correct, Mr.
8 Schultz.
9 MR. SCHULTZ: Thank you.
10 CHAIRMAN SKILLMAN: Let me ask one more 11 somewhat related, Paul, to your comment. One of the 12 portions of the SER communicates regarding station 13 drainage. And I'll read the text so you can understand 14 why I'm asking the question.
15 The license renewal application, Section 16 2.3.3.8 states the purpose of the station drainage and 17 sewage systems is to provide drainage for various 18 equipment and buildings and to collect and process 19 sewage from the plant facilities.
20 The station drainage system collects 21 building roof and floor drains, equipment drains, yard 22 drainage from the entire site, with the exception of 23 the reactor building and auxiliary building, which use 24 the waste disposal system for drainage collection.
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17 1 together provide the sanitary water services for the 2 plant. I'm presuming that your roof drains and other 3 yard drains are separated from sewage.
4 And your sewage is dedicated to your offsite 5 vendor, whereas the yard drains and other find their 6 way back into the Chickamauga reservoir or whatever it 7 is. Is that accurate?
8 MR. SIMMONS: That's correct, Mr. Chairman.
9 CHAIRMAN SKILLMAN: Okay. Thank you.
10 Please proceed.
11 MR. PIERCE: Moving to Slide 14, on Slide 14 12 I'll be talking about the near term and future plant 13 improvements. The first item I'll be going over is 14 items that we have scheduling for our upcoming 15 refueling outage, which is in the spring, which is April 16 2015.
17 We have plans to replace approximately ten 18 thimble tubes. In addition, we plan on replacing the 19 containment spray heat exchanger in 1A.
20 For the fall refueling outage on Unit 2, we 21 will be replacing approximately ten thimble tubes on 22 that particular unit also.
23 As far as the outyears as far as plan 24 improvements, as mentioned earlier, we'll continue to 25 replace portions of carbon steel and safety-related raw NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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18 1 water piping.
2 And also, we have begun to design and began 3 installing cathodic protection. And as far as 4 cathodic protection, we're looking to start the design 5 in 2015 and complete design as far as implementation 6 in 2017.
7 MEMBER BALLINGER: Cathodic protection of 8 what?
9 MR. PIERCE: Cathodic protection of buried 10 piping.
11 MEMBER BALLINGER: Oh, buried pipe?
12 MR. PIERCE: Yes.
13 CHAIRMAN SKILLMAN: What is the status of 14 cathodic protection today?
15 MR. PIERCE: Mr. Chairman, the current 16 status of cathodic protection today, as I mentioned in 17 my slide, we have started the design which will start 18 in 2015.
19 We will have full implementation in 2017, and 20 we do have the high pressure fire protection tank that 21 has cathodic protection. And that is the current 22 status as of today, Mr. Chairman.
23 CHAIRMAN SKILLMAN: So one tank or two tanks 24 and that's it today?
25 MR. SIMMONS: Two tanks.
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19 1 CHAIRMAN SKILLMAN: The two 300,000 gallon 2 tanks, and that is the extent of your --
3 MR. PIERCE: Yes, sir.
4 CHAIRMAN SKILLMAN: -- cathodic protection.
5 How then do you know that for all of those years, with 6 all of that buried piping, your buried piping is okay?
7 MR. PIERCE: Mr. Chairman, I'm going to ask 8 Mr. Kyle Loomis to speak to your question.
9 MR. LOOMIS: Kyle Loomis, engineering 10 programs. Mr. Chairman, we have implemented a buried 11 piping program at the site. It's based on the NEI 09-14 12 initiative and milestones.
13 During this time period we have done both 14 proactive and opportunistic inspections on the buried 15 piping at the plant.
16 CHAIRMAN SKILLMAN: Would that same program 17 be applied through your buried tanks also?
18 MR. LOOMIS: Not for our seven day tanks.
19 That's a separate program from what the UPTI program, 20 as we call it, under piping and tanks integrity 21 initiative.
22 MR. DIMOPOULOS: Mr. Chairman, if I may, 23 this is Dennis Dimopoulos. The only, we do not have 24 buried tanks for the Sequoyah Nuclear Plant with the 25 exception of the diesel generator seven day tanks.
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20 1 CHAIRMAN SKILLMAN: Thank you.
2 MR. PIERCE: And to conclude, the last item 3 I will be discussing as far as multi year projects is 4 that we will continue to replace CRD and auxiliary HVAC 5 cooling coils.
6 And that ends my presentation, Mr. Chairman.
7 Now, I'll be turning over to Erin Henderson who will 8 go over our license renewal application preparation.
9 MS. HENDERSON: Thanks William. My name's 10 Erin Henderson. I'm the site licensing manager, and 11 I'm going to talk about how we developed our license 12 renewal application.
13 As John mentioned, this has been a few years 14 in the making here. We began the process of developing 15 our application and assembling our team in 2010.
16 At that time we put together a team of 17 experienced individuals that had been involved in 18 several other successful license renewal projects, and 19 they provided us the support in developing our 20 application.
21 They brought along with the their proven 22 processes and procedures. Most of the key players that 23 were involved in that application are here in the room 24 today and were previously introduced when John had 25 everybody stand up.
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21 1 Our qualified site program owners and system 2 engineers were trained in the license renewal process.
3 Over the past few years they've provided the reviews 4 of aging management reports and the program evaluation 5 report.
6 And their knowledge and feedback is really 7 key to this process and is really especially evident 8 in the operating experience portion of the application.
9 CHAIRMAN SKILLMAN: Erin, may I ask you to 10 describe briefly the type of training, the content of 11 the training for those individuals, please?
12 MS. HENDERSON: I'm going to have Dennis 13 Lundy speak to that.
14 MR. LUNDY: My name is Dennis Lundy for the 15 license renewal project. The training we conducted is 16 a fairly standard page developed by Altran. It's 17 covering the capital systems, electrical systems, 18 civil structures.
19 It talks about aging effects, managing those 20 aging effects, how to detect aging effects when you're 21 walking through the plant. It's to help the team 22 develop that understanding.
23 CHAIRMAN SKILLMAN: Thank you.
24 MEMBER POWERS: Tell us what it does with 25 respect to coatings?
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22 1 MR. LUNDY: I'm sorry.
2 MEMBER POWERS: Could you tell us what it 3 does with respect to coatings?
4 MEMBER POWERS: Did the training include 5 coatings? The training did not include coatings.
6 (Simultaneous speaking) 7 CHAIRMAN SKILLMAN: Erin, please continue.
8 MS. HENDERSON: Thanks. We've had a lot of 9 very experienced individuals review, provide reviews 10 and comments on the technical reports, and that 11 supported the application.
12 The project members have been engaged in NEI 13 working groups, and so the project has been represented 14 along with, in the civil, mechanical and electrical 15 working groups as well.
16 We did an industry peer review of the 17 application, and that resulted in over 300 comments 18 that we individually dispositioned. Dennis 19 Dimopoulos is going to provide some more insights into 20 the outcome of the application.
21 MR. SCHULTZ: When was the industry peer 22 review conducted?
23 MS. HENDERSON: Dennis Lundy will --
24 MR. LUNDY: Would you repeat the question, 25 please?
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23 1 MR. SCHULTZ: When was the industry peer 2 review conducted?
3 MR. LUNDY: In the summer of 2012.
4 MR. DIMOPOULOS: Okay. We're on Slide 18 5 right now, and I'll talk a little bit about the 6 application details. It was submitted in January 7 2013. It was developed using the latest provision of 8 the NUREG-1801 or the GALL report. That's Rev 2.
9 We used NEI 95-10 for the scope and guidance 10 and the aging management review details, and we did have 11 extensive peer reviews, over 15 peer reviews, as we went 12 through the process.
13 Additionally, along with this latest 14 revision of the GALL, we did address six interim staff 15 guidance documents and two more interim staff guidance 16 documents that came up during the REI process.
17 In all, there was 4100 aging management 18 reviewed line items. That's looking at component, 19 environment and developing those aging management 20 programs.
21 And all 43 aging management programs are 22 required to manage the effects for the period of 23 extended operation, 31 existing and 12 new.
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24 1 reviews in relation to the GALL.
2 So for our application we identified 20 3 programs that we felt were consistent with the GALL and 4 following the SER issuance. We've got a very good, 5 rigorous region review and inspections and NR review 6 through our process.
7 And you'll notice the delta with the SER. We 8 had three programs that during that process were not 9 consistent with the GALL and required enhancements.
10 And one of those required exceptions. And that one was 11 associated with the fire water system.
12 So moving on to Slide 20, license renewal 13 commitments. It is included, that the commitments 14 will be included in FSAR supplement, which is Appendix 15 A of the license renewal application.
16 It will be tracked and managed through our 17 commitment tracking system and our corrective action 18 program. In all, 44 commitments associated with aging 19 management programs, 43 associated with aging 20 management programs and one associated with the 21 operating experience program, excuse me.
22 Slide 21 we'll talk about implementation.
23 So as we're moving through our issuance of the SER, and 24 we're focusing, shifting from application development 25 to implementation of commitments.
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25 1 So we have Michael Henderson to my right. He 2 is participating in the NEI implementation working 3 group. Additionally, the site has selected a 4 permanent license renewal coordinator, and that is Joy 5 Williams who is here with us today.
6 And she is presently engaged in a review of 7 operating experience for aging management program 8 impacts and implementation efforts.
9 CHAIRMAN SKILLMAN: Before you change, this 10 is probably the best place to fit in my next question, 11 and it had to do with scoping.
12 In the status report that the staff provided 13 to the ACRS for the ACRS review for this meeting, the 14 wording is as follows.
15 The audit team determined that the 16 applicant's scoping methodology was generally 17 consistent with 10 CFR 54.
18 However, the audit team determined that 19 additional information was required in order for staff 20 to complete its review.
21 And the three bullets are the methods used 22 and the basis for any conclusions in which components 23 identified as safety-related in the plant equipment 24 database were not included in the scope for license 25 renewal.
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26 1 The second bullet, methods used and basis for 2 conclusions in which Category 1 structures were not 3 included in the scope for license renewal.
4 And the third bullet, methods used and basis 5 for conclusions in which non safety-related structures 6 adjacent to Category 1 safety-related structures were 7 not included in the scope. Would you please speak to 8 that?
9 MR. DIMOPOULOS: Mr. Chairman, I'm going to 10 ask Mr. Lundy to provide some additional details.
11 MR. LUNDY: My name is Dennis Lundy with the 12 license renewal project. On the first category used, 13 there's, in our equipment database at Sequoyah in some 14 cases we have conservatively classified the components 15 of safety-related.
16 One example would be our fifth diesel 17 building. It was a, as part of the original plant 18 design along about the first or second year there's 19 going to be a new diesel building built.
20 And the components inside that building, 21 although they were never put in service, they were still 22 classified in the database as safety-related.
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27 1 intended function for license renewal.
2 So that is an example. There are several of 3 those like that. The equipment database was 4 classified conservatively by a management decision and 5 left that way.
6 We went through each one of those. We 7 through the whole database with the staff, reviewed 8 each one of the items identified and developed the 9 understanding of why those were there. We made no 10 changes as a result of that.
11 The second two items, I think, if you would 12 repeat that question. Make sure I answer it --
13 (Simultaneous speaking) 14 CHAIRMAN SKILLMAN: The first category was 15 category where there were safety-related items in the 16 plant database that were not included in the scope of 17 license renewal.
18 MR. LUNDY: Okay. That's what I just did.
19 CHAIRMAN SKILLMAN: And I can understand 20 that. As long as none of those were credited for any 21 license or design basis issue.
22 MR. LUNDY: Yes, sir.
23 CHAIRMAN SKILLMAN: The second category is 24 Category 1 structures not included within the scope for 25 license renewal. Might that be the building in which NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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28 1 that engine was located or something such as that?
2 MR. LUNDY: Again, we have, one example is 3 our waste processing building. That particular 4 building in SAR is classified as a Category 1 structure.
5 However, there is no safety-related components inside 6 that building.
7 So we had classified that as basically an 8 alpha-2 structure, and assessment of the staff, and we, 9 they concurred with our classification that it was not, 10 even though it was a Category 1 structure, it didn't 11 need to be in the rule as a Category 1 structure.
12 CHAIRMAN SKILLMAN: I see.
13 MR. LUNDY: The last one dealt with our 14 service building. Our service building is adjacent to 15 our control building, auxiliary building.
16 With the initial scoping it was not in scope.
17 We did questioned on that by the staff. At one time 18 we had an analysis that said that building will not fall 19 on the control building, auxiliary building under a 20 seismic event.
21 After reviewing those, that documentation we 22 felt the station made the decision that is the right 23 thing to go ahead and bring that particular facility, 24 the service building into scope.
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29 1 that it can't fall on the adjacent building?
2 MR. LUNDY: It is not seismic, but we brought 3 that into, that building will now be monitored as part 4 of a structure monitoring program just like a Category 5 1 structure.
6 So we're given the confidence that it will 7 perform its function. It will not fall on that, the 8 adjacent building. Yes, sir.
9 CHAIRMAN SKILLMAN: You've given 10 approximately four examples. Is that the totality of 11 this particular issue, or is there more that we need 12 to hear about?
13 MR. LUNDY: That's all that I can think of 14 right now, Mr. Chairman.
15 CHAIRMAN SKILLMAN: That's the whole story 16 as far as you can tell?
17 MR. LUNDY: Yes, sir.
18 CHAIRMAN SKILLMAN: Thank you. Please 19 proceed.
20 MR. DIMOPOULOS: Okay. We're still on 21 Slide 21, so basically our Sequoyah program owners, 22 many of whom you see here today, they are engaged in 23 the review of our license renewal implementation issues 24 and will guide implementation of the commitments in 25 regard to their specific programs as we move forward.
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30 1 MR. SCHULTZ: Dennis, before you move on, 2 could you elaborate on the third bullet there?
3 Describe what is meant by an informal OE review and put 4 that in the context of what you mean by doing things 5 in advance of a fleet procedural guidance.
6 So is the fleet procedural guidance holding 7 anything up for Sequoyah?
8 MR. DIMOPOULOS: No, sir. Mr. Schultz, one 9 of the commitments that we made was to the operating 10 experience program.
11 And we're going to revise that program along 12 with some other station procedures to put the permanent 13 hooks and I say the culture into the station to address 14 things from a license renewal perspective.
15 So it goes further than the program owners 16 we see here today that we've trained, so it becomes 17 sustained long-term.
18 Until those procedures get implemented, we 19 have basically a gap measure that we've closed to 20 establish a person in the interim until all those 21 procedures and the commitments, some of them include 22 training for our initial and continuing training 23 programs, et cetera.
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31 1 triggers that may cause revisions to the aging 2 management programs.
3 MR. SCHULTZ: Okay. And you've identified 4 that individual in addition to the aging management 5 coordinator?
6 MR. DIMOPOULOS: That is the aging 7 management coordinator.
8 MR. SCHULTZ: That is the individual.
9 Okay. I appreciate that. Thank you.
10 CHAIRMAN SKILLMAN: Let me build on Dr.
11 Schultz's question just for a second. Here you are 12 asking for a future license extension of 20 years.
13 You're not going to use this for a couple of years.
14 It's going to take awhile to get it. Once 15 you have it you're not going to use it immediately.
16 You're only going to use it once your current license 17 expires on Unit 1 and then on Unit 2.
18 If I can be so bold, in the answer that you 19 gave to Dr. Schultz, what might you be thinking about, 20 preparations today, for a subsequent life renewal?
21 So you run this plant from 40 to 60. Is 22 anybody thinking 60 to 80 at this point in your 23 considerations?
24 MR. DIMOPOULOS: Mr. Chairman --
25 CHAIRMAN SKILLMAN: John --
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32 1 (Simultaneous speaking) 2 CHAIRMAN SKILLMAN: We're interested in 3 that because steps that you take today, particularly 4 preservation steps that you take today, have some real 5 long implications.
6 MR. CARLIN: One of the things that, and I 7 appreciate that question for a number of different 8 levels. We've really been focused on making 9 improvements to Sequoyah that are long-term, 10 sustainable improvements.
11 We have made major modifications to our 12 switchyards, to our electrical systems. The 13 implementation of the Appendix R mods at Sequoyah was 14 much more extensive than most places.
15 We replaced miles of cable with the idea of 16 preparing for a long-term. Our focus on how we're 17 managing drainage and how we're managing our up cable 18 tunnels were all set up for long-term.
19 So while we have not embarked on the 60 year 20 plus initiative, our preparations have always focused 21 on that. Same thing goes with coatings.
22 Going in and looking with protective 23 coatings, long-term strategies in terms of digital 24 replacement, all of those things are focused on a 25 long-term traffic for rad monitors for other, equal 21, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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33 1 other systems that we have in the plant, our rot control 2 systems.
3 All of those things are all focused with a 4 long-term view, with the long view. It isn't just to 5 get to the period of extended operation, but it is a 6 much longer view.
7 And I think the Tennessee Valley Authority 8 has made a commitment to nuclear. I mean it is a big 9 part of our, we've increased it. We have shut down a 10 number of our cold plants.
11 So strategically, the 60 year plus 12 initiative will really be brought to the floor sooner 13 than later. Our Unit 1 at Browns Ferry just entered 14 the period of extended operation.
15 And then obviously we'll be in that situation 16 right around 2020 time frame. So again, we have a 17 strong corporate commitment to nuclear, and we're going 18 to do that.
19 So concrete management, impact the fluence, 20 looking at temperature impacts, those sorts of things, 21 and we're closely monitoring what they're doing at 22 Ginna in terms of their evaluation of the concrete 23 structures, looking at some of the challenges.
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34 1 have a formal program for beyond 60, but we're making 2 efforts. And our view is a long view of 40 years more 3 of operation.
4 CHAIRMAN SKILLMAN: Thank you. Okay.
5 MR. SCHULTZ: Let me back up to Dennis.
6 John, you made some good comments about the physical 7 improvements that you've made to the facility. And 8 then you mentioned 2020.
9 As the Chairman has indicated, that's in the 10 future, but it's not very far away. And my reaction 11 is somewhat affected by the choice of the word initiated 12 informal OE review.
13 And Dennis you brought up the issues 14 associated here about how we would move forward with 15 the overall aging management program, all of which is 16 very important.
17 So I think you're in the right place. But 18 when you make a major improvement to facility, one of 19 the cultural aspects of that is well, we've done it.
20 We've made these improvements. And now 21 we've got license renewal, and we're all set to go. We 22 don't have to worry about these things.
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35 1 management. And it is a continuous process.
2 MR. CARLIN: I appreciate your challenge, 3 Dr. Schultz, about the cultural impact. It is.
4 Having led a plant through the period of, into the 5 period of extended operation, the first BWR to do it.
6 MR. SCHULTZ: At Browns Ferry.
7 MR. CARLIN: No, at the PWR was Ginna.
8 MR. SCHULTZ: Oh, Ginna.
9 MR. CARLIN: So I was the site vice president 10 of Ginna and setting up your programs, making sure 11 they're robust and long-term, also changing the mindset 12 of people because if you entered that period of extended 13 operation, the paradigm shifts.
14 There are new tests that have to be run.
15 There's a different way of viewing things from an aging 16 management perspective, and that is a big part of what 17 we'll be doing subsequent to this meeting, is 18 continuing down that path.
19 We started a journey in 2010. But we won't 20 finish it in 2020. It will go for the life of the plant, 21 and it really does require a different way of thinking 22 about the plant on the other side of that.
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36 1 practice it before then.
2 MR. SCHULTZ: Thank you. I appreciate you 3 putting that on the record. Thank you.
4 CHAIRMAN SKILLMAN: Thank you, John.
5 Dennis, please proceed.
6 MR. DIMOPOULOS: Okay. We're on Slide 22 7 here. So the Safety Evaluation Report contains one 8 open item. Michael Henderson is going to talk about 9 that in the next slide.
10 It contains no confirmatory items and 11 contains two license conditions, and there are the 12 standard license conditions. One is to include the 13 FSAR supplement in the next update.
14 And the next one is to ensure implement our 15 new programs and enhancements six months prior to PEO.
16 So with that, I'd like to turn it over to Michael 17 Henderson who will talk about the SER open item.
18 MR. HENDERSON: Okay. Thanks, Dennis.
19 Good afternoon. I'm Michael Henderson, engineering 20 programs manager. As we've discussed, we do have one 21 open item in our safety evaluation report.
22 And that open item deals with the reactor 23 vessel internals program and specifically deals with 24 neutron fluence at the upper core plate.
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37 1 kind of orient ourselves with the component we're 2 talking about.
3 The figure on the left is just the overall 4 schematic of our reactor vessel, and the upper core 5 plate is located just above the fuel region. It's 6 about a foot above the fuel.
7 And the figure on the right, it's just a 8 cutaway of the figure on the left. And the upper core 9 plate is in a red box there, so that's the component 10 we're talking about.
11 CHAIRMAN SKILLMAN: These are two different 12 reactor vessels, or those are not the same internal.
13 MR. HENDERSON: They're pictures taken from 14 two different locations. The one on the right is 15 supposed to be taking some of the objects out so you 16 can see the upper core plate.
17 But yes, all the components are not there.
18 They're not the same in the two figures, but the only 19 intent is to show location.
20 CHAIRMAN SKILLMAN: I understand the 21 cartoon, but I'm making the point what you have on the 22 left is an upper plenum. It's clamped by the head with 23 a lower bridge arrangement.
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38 1 member. I don't know if you can see it. I can see it.
2 MR. HENDERSON: Okay. The only intent was 3 to show --
4 CHAIRMAN SKILLMAN: Those are cartoons, 5 okay.
6 MR. HENDERSON: Yes, sir.
7 CHAIRMAN SKILLMAN: And the real point is 8 the upper core plate is that lower red member that 9 you're pointing to?
10 MR. HENDERSON: Correct.
11 CHAIRMAN SKILLMAN: Okay.
12 MR. HENDERSON: So going back to the 13 previous slide, we'll step through the open item 14 itself. So we received this RAI in September. We 15 responded on October 22nd, and that response is in 16 review.
17 The RAI really had two issues. The first was 18 to describe the fluence methodology that was used to 19 calculate the fluence at the upper core plate, and the 20 answer to that was pretty straightforward.
21 We used the same methodology that we've 22 always used. It's consistent with the reg guide, and 23 it's consistent with staff-approved methods that our 24 NSSS vendors use.
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39 1 open item is the fact that the value we calculated for 2 the underside of the upper core plate is above a 3 threshold for a radiation embrittlement.
4 So the underside, obviously closer to the 5 fuel, more fluence. Now with that being said, being 6 above that threshold doesn't change the overall 7 categorization of the upper core plate.
8 It remains an expansion item with respect to 9 MRP guidance, and the reason for that is that it's still 10 not a leading indicator of any degradation within the 11 reactor vessel.
12 So with that being said, what Sequoyah has 13 done and what we are committing to doing is enhancing 14 our VT3 visual exam procedures so that when we do our 15 Section 11 inside the vessel visual exams, we'll take 16 a look at the underside of that upper core plate with 17 a VT3.
18 CHAIRMAN SKILLMAN: How do you do that?
19 MR. HENDERSON: Excuse me?
20 CHAIRMAN SKILLMAN: How do you do that?
21 That upper core plate is resting on the springs of the 22 fuel assemblers. It's clamped in place.
23 The head pushes it down, pushes the assembly 24 in place. The only way to see that is to pull that 25 plenum out and to view it from outside.
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40 1 MR. HENDERSON: That would be the way to do 2 it, yes. It would only be when it's removed.
3 CHAIRMAN SKILLMAN: Okay.
4 MR. HENDERSON: It's not intended to be an 5 every outage type of commitment.
6 CHAIRMAN SKILLMAN: What does the program 7 require?
8 MR. HENDERSON: The ISI in-service 9 inspection program --
10 CHAIRMAN SKILLMAN: You're committing to a 11 visual for this particular open item. What is the 12 program that you are committing to?
13 MR. HENDERSON: As far as reactor vessel 14 internals, MRP 227. There are no requirements other 15 than an expansion item for this component. It would 16 only be examined if we found degradation elsewhere. So 17 this is more than what the MRP would require for this 18 item.
19 MR. SCHULTZ: What is the examination going 20 to look for?
21 MR. HENDERSON: The VT3 would be looking for 22 mechanical deformation, any sort of gross degradation 23 that may be present that could potentially serve as a 24 crack initiator. It will obviously not be looking for 25 cracking.
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41 1 MEMBER BALLINGER: That concerns me a little 2 bit because if you're concerned about IASCC, which is 3 what the issue is, you can get, you don't have to see 4 distortion and stuff like that to have cracks.
5 I mean if you're looking for distortion or 6 whatever as a precursor or an indicator that you may 7 have cracks, that's not going to be enough. I mean you 8 can get cracks long before you get anything like that.
9 MR. HENDERSON: I'd like Randy Lott from our 10 NSSS vendor.
11 MR. LOTT: Hi. I'm Randy Lott. I'm from 12 Westinghouse, and we helped put together both this 13 response and the response to that triple core plate.
14 The answer to your question is there are 15 actually no cracking mechanisms that were screened in.
16 The threshold for radiation embrittlement is somewhat 17 lower than the threshold for IASCC within our screening 18 process.
19 So there was no fatigue. There was no IASCC 20 or SCC concern identified in the upper core plant.
21 There was in radiation embrittlement requirement.
22 MEMBER BALLINGER: So it's a toughness 23 issue?
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42 1 tolerate or when you get to the actual slot analysis.
2 But in terms of what to inspect for, I agree 3 with you. We're inspecting only in an abundance of 4 caution to make sure that we're able to withstand any 5 loss of toughness in the material.
6 MEMBER BALLINGER: So how does the 7 inspection verify that?
8 MR. LOTT: Well, the inspection is just 9 verifying that there's not a flaw that would challenge 10 the toughness of the material.
11 MR. SCHULTZ: So what type of inspection are 12 you going to do --
13 (Simultaneous speaking) 14 MR. LOTT: The recommendation for that was 15 a VT3S. The upper internals are pulled out. That's 16 basically, as you said, that's the unit face to the 17 fuel. So to get to the fuel, that's got to come out.
18 It's either got to be examined in transition 19 or as it's sitting on the stand during the rest of the 20 exam. It's just simply a visual examination.
21 We believe because barely, the evaluation 22 we've gone through says that the threshold, the bottom 23 surface of this component might exceed the threshold 24 for a irradiation embrittlement.
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43 1 not have enough radiation to be embrittled. We do a 2 scan, basically 1 DPA standard.
3 MEMBER BALLINGER: Yes, that's what I was 4 just going to say. It's the 1 DPA standard.
5 MR. LOTT: Yes, that's basically, in fact 6 it's 1.5 DPA for the things other than casting. But 7 it's below that. That's what the screening criteria 8 basically told us was it's below that 1 DPA level at 9 the top surface.
10 So we're not worried about the things above 11 it. That's a part of our concern.
12 CHAIRMAN SKILLMAN: So Dr. Ballinger, you 13 good?
14 MEMBER BALLINGER: Yes.
15 CHAIRMAN SKILLMAN: Okay, Dennis, you can 16 proceed. Excuse me, Mike.
17 MR. HENDERSON: I'll give it back to Dennis 18 for some concluding remarks.
19 MR. DIMOPOULOS: We're on Slide 26. So in 20 conclusion, the Sequoyah license renewal application 21 has followed the latest revision of the NUREG, the 22 latest revision of the GALL, with the only exception 23 such that it with the fire water system.
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44 1 and the operating experience program that was 2 previously discussed.
3 During our application, the Sequoyah aging 4 management program owners and subject matter experts 5 have been involved with the development of the 6 application, the technical reports, the walk downs, 7 inspections, RAI responses and commitment development.
8 The programs and program enhancements are 9 defined for managing aging effects for Sequoyah for the 10 period of standard operation.
11 As John and Paul and William have discussed, 12 we made some significant investments to the plant 13 modifications over the years for the continuing safe, 14 reliable operation through the extended period of 15 operation.
16 So with that, we'll move on to questions and 17 comments.
18 MEMBER POWERS: It's always a curious 19 subject and interest to me. You made about a 40 percent 20 increase in the workload for aging management. How do 21 you do that? Go to the aging manager, and tell him 22 you're screwing up his weekends.
23 MR. SIMMONS: I would.
24 MEMBER POWERS: Me, too.
25 (Simultaneous speaking)
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45 1 MR. SIMMONS: So as I understand your 2 question, Mr. Powers, is the workload associated with 3 the aging management, how are we prepared to deal with 4 that?
5 MEMBER POWERS: Yes.
6 MR. SIMMONS: So we have a very strong 7 management program at Sequoyah that integrates the 8 aging management process into those aspects of how 9 we're going about doing our preventative maintenance, 10 the other corrective actions, work activities that we 11 need to have.
12 One of the things that John and I do on a very 13 frequent basis is review our current stacking against 14 the work that we have, and we make adjustments as 15 required to accommodate for those needs based on the 16 workload that we have and we project that we'll have 17 over the next one to three years for that.
18 MEMBER POWERS: I've got to give you credit.
19 I ask this question pretty routinely of people, and 20 that's the best answer I've gotten.
21 I mean that's the right thing. You need more 22 people, you need more people. But that doesn't mean 23 that it's not proportional to the increase in workload 24 necessarily.
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46 1 on what the nature of the job is.
2 CHAIRMAN SKILLMAN: I got a question, CRD 3 and nozzle wear. Got some interesting information in 4 the SER on this topic. Let me just read two sections 5 and then ask you to please respond.
6 In addition, the applicant stated that the 7 amount of wear, excuse me, this is from the status 8 report. No, it's the safety evaluation.
9 The applicant stated that with the amount of 10 wear, the remaining wall thickness of the CRD and 11 nozzles is sufficient to perform as designed function.
12 The applicant stated that all of the stress 13 intensity and fatigue usage factor limits used in the 14 design of the Unit 1, Unit 2 CRD and nozzles as specified 15 in the applicable ASME code editions remain satisfied 16 with the incorporation of the reduced CRD and nozzle 17 thickness.
18 The question is how has that thickness been 19 verified.
20 MR. PIERCE: Mr. Chairman, I'm going to ask 21 Mr. Adam Keyser to speak to your question.
22 CHAIRMAN SKILLMAN: Yes, sir. Thank you.
23 MR. KEYSER: Good afternoon. My name is 24 Adam Keyser. I'm the ASME Section 11 Program Manager.
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47 1 spring, we were able to use our vendor and their NDE 2 techniques to take UT thickness measurements in those 3 locations.
4 CHAIRMAN SKILLMAN: Yes, sir. Thank you.
5 Let me ask one more, I think, if you want to stand by.
6 In response to thermal nozzles not located in the outer 7 two most concentric rows so on and so forth, the 8 applicant stated this inspection did not identify any 9 cracking with the thermal sleeves.
10 And Nozzles 20, 39, 40, 45, 47, 51, 53, 57 11 were noted as having the most wear. The applicant 12 further stated that the maximum wear was identified on 13 CRDM thermal sleeve Nozzle 20.
14 Here comes my question. In addition, the 15 applicant stated that its engineering evaluation 16 included a comparison of the observed wear of Unit 1 17 Nozzle 20 with the wear observed at another facility.
18 The applicant stated that the observed wear 19 of Nozzle 20 was less than the wear at the other 20 facility. And on this basis, the most significant 21 measured wear at the other facility was conservatively 22 used to evaluate the remaining service life of the 23 applicant's thermal sleeves.
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48 1 somebody else who's worse than you, and you claim that 2 as the worst. And you march on. How is that 3 justified?
4 MR. KEYSER: The easy answer to that 5 question is since the time that examination was 6 performed, we have actually taken physical thickness 7 measurements.
8 The initial findings associated with the 9 technical bulletin were based on visual examination 10 results, and we didn't have a tool capable of physically 11 measuring the wear in this location.
12 So we utilized photographs taken during the 13 J-groove weld examinations performed at our plant and 14 compared them against photographs taken during the same 15 exam performed by the same vendor at the comparison 16 plant.
17 And at the time, that was the best data we 18 had to go on. Since then we have performed UT thickness 19 measurements.
20 CHAIRMAN SKILLMAN: Thank you.
21 MEMBER BALLINGER: I have another question.
22 Reading through the SER, the section on materials, 23 there were a number of cases where you thought one 24 material was there, but it was a different material when 25 you actually looked at it.
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49 1 Are you sure that you have a direct 2 correlation? You know what materials you actually 3 have of the core structural materials, because that was 4 the issue between cast and rot materials in a number 5 of places. So you're sure now of the materials that 6 are present?
7 MR. SIMMONS: Mr. Ballinger, I'm going to 8 request that Mr. Chris Webb speak to your question.
9 MR. WEBB: Hi. I'm Chris Webb with 10 engineering programs. I understand you're asking 11 about the reactor vessel internals components --
12 MEMBER BALLINGER: Right.
13 MR. WEBB: -- that were originally 14 identified as rot --
15 (Simultaneous speaking) 16 MR. WEBB: Based on a review of CMTRs we 17 conservatively assume that they were cast also mixed 18 in with steel. We could not verify that they were one 19 or the other, so we conservatively assumed that they 20 were.
21 And that started with the CRGT byparts. And 22 we've since identified three other components and also 23 from that category, and that's the final number.
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50 1 embrittlement or aging.
2 MR. WEBB: Correct.
3 MEMBER BALLINGER: And so you factor that 4 in, okay. So where you couldn't determine, you've 5 assumed the worst case?
6 MR. WEBB: Correct.
7 CHAIRMAN SKILLMAN: Ron, thank you.
8 MR. SCHULTZ: I have a couple of questions.
9 CHAIRMAN SKILLMAN: Steve.
10 MR. SCHULTZ: First for you Mike, the 11 question I have is, and you may have covered this, and 12 I might have missed it, you talked about the inspection 13 program related to the open item.
14 But what is the earliest commitment date for 15 that inspection, and is it going to be a continuing 16 process? You said well, we don't have to do this all 17 the time. But is there a program plan that will 18 reevaluate, reinspect during the extension period?
19 MR. HENDERSON: You're referring to the VT3 20 exam --
21 MR. SCHULTZ: Yes.
22 MR. HENDERSON: -- that we will be doing.
23 MR. SCHULTZ: When is it going to be done?
24 MR. HENDERSON: It's going to be consistent 25 with the ten year ISI schedule.
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51 1 MR. SCHULTZ: Okay.
2 MR. HENDERSON: So it'll be on that same 3 frequency.
4 MR. SCHULTZ: And when will that happen 5 first?
6 MR. HENDERSON: I don't have the exact date, 7 but I can get you the date when it'll happen first.
8 MR. SCHULTZ: Okay. Thank you. I 9 appreciate it.
10 MEMBER BALLINGER: I guess I have another 11 sort of companion question. That's a complicated 12 structure, a lot of holes and all kinds of things.
13 Are you sure that the VT3 would find what 14 you're looking for? It's not a flat plate that's easy 15 to get access to. It's a complex part, so have you done 16 anything to verify that the VT3 would actually work?
17 MR. HENDERSON: To this point, no. Again, 18 the VT3 would be above what's required by the MRP. It's 19 still an expansion item in the MRP document.
20 MR. SCHULTZ: And my other question is for 21 you, Erin. You mentioned in your presentation, and we 22 learned it was in 2012 that you had the industry peer 23 review done.
24 And it was also mentioned that there were 300 25 open items, 300 items that were identified, and I NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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52 1 presume they became open items in some list.
2 Were all of those elements, items closed 3 before the submittal, or how have those items been 4 tracked as you've gone forward with the application and 5 then with the subsequent interaction with the staff, 6 the industried items.
7 MS. HENDERSON: Dennis Lundy will talk a 8 little bit about that.
9 MR. LUNDY: My name is Dennis Lundy with the 10 license renewal project. Each one of those open items 11 were tracked in a database with an assigned owner.
12 Entergy, our primary contractor, put the 13 database together. Each individual question had a 14 defined answer that TVA reviewed and concurred with.
15 So they were tracked to closure. They were all closed 16 before it was submitted.
17 MR. SCHULTZ: Thank you.
18 MEMBER STETKAR: I apologize for coming in 19 late, so I hope, I don't think any of this was covered 20 beforehand. Somebody talk to me about underground 21 cables. So get your appropriate person ready.
22 Sequoyah's had a long history of problems 23 with water accumulation underground, buried in 24 underground, I'm going to need both of those because 25 I'm not quite sure what configurations you have, both NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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53 1 actual functional failures and cables and degraded 2 cables identified by testing.
3 As I read through the RAI responses and the 4 SER, first of all, because my last data comes from the 5 generic letter 2007 of one response. The last failure 6 I know about was in 2005.
7 What's your operating experience been from 8 2005 through 2014 in terms of underground cables? Have 9 you had any additional failures?
10 MR. DIMOPOULOS: Mr. Stetkar, I'm going to 11 ask Darren Boehm from our electrical design 12 organization answer that.
13 MR. BOEHM: Yes, my name is Darren Boehm from 14 site engineering. You were asking about failures post 15 the response to the generic letter 2007.
16 MEMBER STETKAR: That's the first question, 17 yes.
18 MR. BOEHM: We have had a test failure on a 19 diesel generator cable feed. I can get the exact date 20 on that.
21 MEMBER STETKAR: That date, I don't care.
22 MR. BOEHM: And we've also had one more 23 failure on a cooling tire lip pump cable. I think that 24 was approximately 2011.
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54 1 find it, water draining?
2 MR. BOEHM: That was a VLF test, very low 3 frequency.
4 MEMBER STETKAR: Water draining or the --
5 MR. BOEHM: We did not send that test away 6 for sampling, but we were seeing the indication of a 7 strong voltage dependence.
8 MEMBER STETKAR: Okay. In at least the SER 9 it notes that you'd had problems with, it identifies 10 Manhole 31, wherever that is.
11 And you were going to complete some regrading 12 of the surface to try to get, reduce the amount of water 13 intrusive of that manhole.
14 It was supposed to be completed by the end 15 of September of this year. Did you finish it?
16 MR. BOEHM: Yes, we have.
17 MEMBER STETKAR: Good, excellent. You've 18 also had problems, apparently, with sump pumps not 19 working and piping problems with the sump pumps. And 20 I guess you're on track for September of next year to 21 get those corrected. How are you doing there?
22 MR. BOEHM: I believe we have resolved that 23 commitment with preparing all of these acceptable sump 24 pumps and discharge pipe, safety-related manholes.
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55 1 inspection to look for water accumulation?
2 MR. BOEHM: It's past on a four week PM. I 3 do not have the most recent, but as of September all 4 of our safety-related manholes were at acceptable 5 levels except for one, which is still documented in our 6 corrective action program.
7 We're still trying to resolve the issues with 8 that. That was in the scope of, we have gone into that 9 manhole, and apparently we didn't resolve the issue 10 fully. It's still in process to repair that one 11 remaining manhole.
12 MEMBER STETKAR: I came on the committee in 13 2007. We were talking about this issue in 2007. It's 14 seven years, not at Sequoyah but the industry in general 15 has been, it's just surprising that we're still talking 16 about it to this extent where you still have problems 17 in late 2014. I'll just make that as a comment.
18 MR. SIMMONS: Mr. Stetkar, I will comment on 19 that. Our standard at Sequoyah is we don't want any 20 water in our manholes, and that's what we're driving 21 to.
22 And we have put forth a lot of effort over 23 the last couple of years in regrading areas of our plant 24 to improve our drainage.
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56 1 replaced numerous sump pumps and addressed piping 2 issues. We do have one issue that he spoke to that 3 we're not satisfied with the current inspections that 4 we were seeing.
5 And we are taking action with our maintenance 6 organization to go and resolve that. And we're not 7 going to accept that for our plant.
8 MEMBER STETKAR: Yes, I understand the 9 commitments that you've made in terms of license 10 renewal. You're committing to all of the things in 11 GALL rev 2.
12 So I get that. I'm just trying to understand 13 where you are, where you've been in the past, where you 14 are now and develop some sort of confidence going 15 forward.
16 MR. CARLIN: Going back to Dr. Schultz's 17 comment, this is one of those, and the question was 18 posed by Mr. Skillman, we're committed to the long haul 19 on this.
20 And this isn't, so we need to fully resolve 21 this issue. We've had, we fully and readily admit that 22 we have not been good stewards at different times of 23 that.
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57 1 fully functional.
2 And we have made modifications to our cable 3 bolts to ensure that we can access them and quickly pump 4 any water that's discovered in them if we have sump pump 5 failures or something like that and also provide better 6 capability in terms of determining the level in those 7 at any time.
8 So we're continuing to invest, but it's set 9 up for the long haul. This is not just, you know, we're 10 just worrying about getting the sump pumps replaced and 11 saying okay, we've got a checkmark in a box. That 12 wasn't how we were going to approach this at all.
13 MEMBER STETKAR: And did I hear, you said 14 it's on a four week PM? You're --
15 (Simultaneous speaking) 16 MR. CARLIN: You're absolutely correct.
17 We're going to aggressive stewards going forward.
18 MEMBER STETKAR: Thank you.
19 CHAIRMAN SKILLMAN: Dr. Riccardella has 20 joined us. Pete, welcome. Colleagues, Dr. Ryan, any 21 questions for the TVA team?
22 MEMBER RAY: No.
23 CHAIRMAN SKILLMAN: Dr. Powers?
24 MEMBER POWERS: No.
25 CHAIRMAN SKILLMAN: Harold?
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58 1 MEMBER RAY: No.
2 CHAIRMAN SKILLMAN: John, any further 3 comments?
4 MEMBER STETKAR: No.
5 CHAIRMAN SKILLMAN: Steve?
6 MR. SCHULTZ: No.
7 CHAIRMAN SKILLMAN: TVA team, thank you very 8 much. What we're going to do is take a 15 minute break, 9 and then we're going to call the NRC staff to the table.
10 (Whereupon, the above-entitled matter 11 went off the record at 2:24 p.m. and resumed at 2:41 12 p.m.)
13 CHAIRMAN SKILLMAN: Ladies and gentlemen, 14 we are back in session, and before we begin the NRC 15 presentation, I'm going to call upon Allen Henderson, 16 I'm sorry, Michael Henderson to speak into the record 17 the issue of the plan for inspection for the upper core 18 plate, please.
19 MR. HENDERSON: The question was when is the 20 next ten year ISI for Sequoyah Unit 1 and Unit 2. That 21 next ten year ISI is in 2015, and we plan to do that 22 inspection at that time.
23 CHAIRMAN SKILLMAN: Thank you.
24 MR. HENDERSON: Thank you.
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59 1 call on Manny Sayoc of the NRC staff to take the meeting 2 from here, please. Manny, go ahead.
3 MR. SAYOC: Good afternoon, Chairman 4 skillman and members of the license renewal 5 subcommittee. My name is Emmanuel Sayoc, and I am --
6 MALE PARTICIPANT: Chris wants to make sure 7 --
8 MR. SAYOC: Chris, I'm sorry.
9 CHAIRMAN SKILLMAN: We are now calling upon 10 Chris Miller.
11 (Off record comments) 12 CHAIRMAN SKILLMAN: We're going to call upon 13 Chris Miller to make some opening comments.
14 MR. MILLER: Thank you, Chairman. We are 15 pleased to be presenting before you. A lot of work went 16 into this application review. What we hope to cover 17 this afternoon is the staff's review.
18 As I said earlier, the SER with open items 19 was issued September 20, 2014, transmitted via memo to 20 the ACRS on October 9th. I want to introduce Mr. Manny 21 Sayoc who's our technical lead PM for the safety side 22 of the review.
23 He is also joined by Lindsay Robinson who is 24 also our project manager on safety and Dr. Allen Hiser.
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60 1 who worked on this and did a lot of work.
2 And they're supporting us today, so I just 3 want to let you know who's here. Thank you, and I'll 4 turn it over to Manny.
5 MR. SAYOC: Thank you, Chris. I didn't mean 6 to steal your thunder. Okay, so good afternoon 7 Chairman Skillman and members of the license renewal 8 subcommittee.
9 My name is Emmanuel Sayoc, and I'm the 10 license renewal project manager for the Sequoyah 11 Nuclear Power Plant Units 1 and 2, ISS renewal safety 12 review.
13 We are here today to discuss the review of 14 the Sequoyah license renewal application as documented 15 in the safety evaluation report with open items, which 16 we issued on September 29, 2014.
17 Joining me here at the table, as you said, 18 is Dr. Allen Hiser. He's a technical advisor for the 19 division of license renewal, and Ms. Lindsay Robinson, 20 visual license renewal safety project manager, who will 21 be running the slides.
22 Seated in the audience are members of the 23 technical staff who have participated in a review of 24 the license renewal application and/or worked parts of 25 the audits conducted at the point.
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61 1 Mr. Joel Rivera-Ortiz is our senior 2 inspector at Region II and is joining us via telephone.
3 Next slide.
4 Today we'll present a general overview of the 5 staff's review and then discuss the main sections and 6 issues presented in the staff safety evaluation report 7 as shown here.
8 Joel will present the results from the Region 9 II onsite inspection. Next slide. The staff 10 conducted several outside audits and inspections for 11 the application as shown on this slide.
12 During the scoping and screening methodology 13 audit, the audit team reviewed applicant's 14 administrative controls governing the scoping and 15 screening methodology and the technical basis for 16 selected scoping and screening results.
17 The staff also reviewed selected examples of 18 component material environmental combinations, 19 information contained in applicant's corrective action 20 relevant to the plant-specific age related degradation 21 and reviewed quality practices applied during 22 development of the LRA and the training of personnel 23 who participated in the review of the LRA.
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62 1 Authority or TVA's aging management programs and 2 related documentation to verify applicant's claims of 3 consistency with the corresponding AMPs in the GALL 4 report.
5 The staff will use AMPs and documented the 6 results in the report dated June 12, 2014. Next slide.
7 Region II conducted its regional inspection 8 as shown a slide Joel will be presenting. We'll 9 present the inspection results shortly.
10 In addition to the audits and inspections 11 already mentioned, the staff conducted in depth 12 technical reviews and issued requests for additional 13 information or RAIs.
14 The staff completed its initial review of the 15 safety Sequoyah license renewal application with the 16 exception of one open item and issued in a safety 17 evaluation report with open items on September 29, 18 2014.
19 The staff will continue to review the open 20 item and associated outstanding RAI. Our plan is to 21 issue Sequoyah's final SER in January 2015. Now I'll 22 turn the presentation over to Joel of Region II.
23 MR. SCHULTZ: Manny, before you leave that, 24 I wanted to make sure. It looks like you had the Region 25 II inspection, and I just wanted to understand in those NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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63 1 inspections what was the participation?
2 That is, you have the Unit 1 containment 3 walkdown. That was just Unit 2, excuse me, Region II 4 personnel that participated in that? You have a team 5 inspection listed after that.
6 Any headquarters' staff participate in 7 either of those?
8 MR. SAYOC: Yes, sir. Mr. Schultz, thank 9 you for the question. For Region II, that was 10 primarily region personnel. Headquarters' staff 11 participated in any scoping and screening audit and the 12 aging management program audit.
13 MR. SCHULTZ: Okay. So that team 14 inspection was handled by Region II?
15 MR. SAYOC: Yes, sir.
16 MR. SCHULTZ: Thank you.
17 MR. SAYOC: Okay. I think we were about to 18 call Joel on the line here to go over the Region II 19 inspections. Joel.
20 MR. RIVERA-ORTIZ: Thank you, Manny. Good 21 afternoon, Chairman Skillman and members of the 22 subcommittee. We are on Slide Number 5 of the 23 presentation.
24 My name is Joel Rivera. I'm a senior reactor 25 inspector in Region II and a team leader for the license NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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64 1 general inspection of Sequoyah. This inspection was 2 conducted last year in accordance with NRC inspection 3 procedure 710002.
4 We completed an inspection in two places, and 5 to clarify the previous question asked about the 6 composition of the teams.
7 We conducted a walkdown of the Unit 1 8 containment performed by Region II inspection staff 9 including the October 2013 refueling outage because 10 that was the only opportunity available around that 11 time to inspect the containment because they were on 12 refueling outage.
13 And after the outage was completed, we 14 conducted a team inspection in November of 2013. The 15 team consisted of five inspectors from Region II and 16 one materials engineer from NRR.
17 So to answer the previous question, there was 18 one member from NRR participating in the inspection.
19 The team conducting inspection activities in the three 20 specific areas shown on the slides as directed by the 21 inspection procedure.
22 For the inspection of scoping and screening 23 methodology, the teams selected the essential raw 24 cooling water system to verify on a sampling basis that 25 the system was scoped and the applicable aging NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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65 1 management reviews were performed in accordance with 2 Part 54.
3 The team also interviewed plant personnel 4 and conducted walkdowns on portions of the system to 5 verify that scoping and screening results were 6 consistent with the application.
7 For the inspection of aging management 8 programs, the teams selected all programs described in 9 the application. The team interviewed plant 10 personnel, reviewed program implementing procedures 11 and samples of inspection, testing and surveillance 12 results to assess the implementation of existing 13 programs.
14 Additionally, the team conducted walkdowns 15 of plant areas to assess of existing programs, based 16 on the current material conditions and verify that 17 applicable aging effects had been accurately 18 identified in the application.
19 The team discussed with the applicant their 20 planned activities to enhance and develop new programs 21 and the evaluation of industry operating experience 22 used to prepare the application.
23 And last, for the review of updates to the 24 application and open items, the team discussed with the 25 applicant any potential material changes to the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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66 1 application, such as planned modifications or changes 2 to the current licensing basis, verify that the 3 applicant was planning to revise the application in 4 accordance with Part 51.
5 Prior to a team inspection, the team 6 consulted with NRR to identify any items of interest 7 that require further inspection. And last, the team 8 verified that official administrative controls were in 9 place to ensure that commitment tasks were being 10 tracked to completion prior to the period of extended 11 operation. Next slide, please.
12 Part of the conclusions of the inspection, 13 on the basis of the sample selected for review, the team 14 concluded that the applicant performed aging 15 management reviews in accordance with Part 54.
16 Based on the sample of plant areas visually 17 inspected and the review of program documents, the team 18 concluded that the existing programs were being 19 effective in managing aging effects for plant 20 structures and equipment within the scope of license 21 renewal.
22 The plant walkdowns show that structures, 23 systems and components were being maintained in good 24 condition and aging effects were being identified, 25 monitored and corrected to maintain the system NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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67 1 functions.
2 The team confirmed that the applicant had 3 plans to implement the enhancements described in the 4 applications and develop new aging management programs 5 in accordance with the applications and the 6 commitments.
7 Additionally, the team confirmed that the 8 information used to prepare the application was 9 retrievable, auditable and consistent with Part 54.
10 The team finally determined that the 11 proposed aging management programs, when implemented 12 in accordance with the application, the regulatory 13 commitment and applicable quality assurance measures 14 will provide regional assurance that the aging facts 15 will be managed to maintain the function of applicable 16 structures, system and components. That concludes my 17 part of the presentation.
18 CHAIRMAN SKILLMAN: Joel, this is Dick 19 Skillman. I have one question I would like to ask, 20 please. Can you hear me?
21 MR. RIVERA-ORTIZ: Yes, I can hear you 22 clearly.
23 CHAIRMAN SKILLMAN: I would like to know the 24 basis upon which you would conclude that inspecting 25 just the essential raw cooling water system is NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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68 1 sufficient.
2 I'm going to guess that Sequoyah's got 200 3 and some systems of those. There are probably 35 or 4 40 that are critical systems. You've chosen just one 5 of the critical systems, and I'm curious why one is 6 sufficient, please.
7 MR. RIVERA-ORTIZ: Okay. Well, we selected 8 the, when we are putting inspection plans together we 9 wanted to select a comprehensive, a large system that 10 covers multiple areas of the plant and interfaces with 11 multiple components.
12 And that's why we selected the essential raw 13 cooling water system. In addition to that, we wanted 14 to use risk insights to select a system that was 15 significant in risk for plant safety.
16 And we used that. We believe that the 17 essential raw cooling water was a good sample, 18 representative of the methodology that the licensee 19 used for similar systems for system insight.
20 CHAIRMAN SKILLMAN: Thank you, Joel. I 21 appreciate the answer. Thank you.
22 MR. SCHULTZ: Joel, this is Steve Schultz.
23 Thank you for your presentation. Two questions, both 24 related. You did the walkdown of the containment for 25 Unit 1 during the refueling outage in 2013 and then had NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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69 1 a subsequent inspection of November.
2 I presume that the team inspection looked at 3 both units.
4 MR. RIVERA-ORTIZ: Yes, that's correct.
5 The scope of inspection, the team inspection in 6 November was a programmatic, was a review of the 7 programs. And we look at both units.
8 MR. SCHULTZ: Okay. And was there anything 9 identified in the containment walkdown for Unit 1 that 10 would suggest that you would like to perform a similar 11 walkdown for Unit 2 in the upcoming outage?
12 MR. RIVERA-ORTIZ: At the time of that 13 walkdown, I don't recollect of any significant issues 14 that require a walkdown in the other unit.
15 In addition to that, we routinely walkdown 16 the containment during the baseline inspection program 17 that we implement.
18 MR. SCHULTZ: Right.
19 MR. RIVERA-ORTIZ: So at that time we didn't 20 identify any significant in regions that required a 21 similar walkdown in the Unit 2.
22 MR. SCHULTZ: And you had the ability 23 matched up with the traditional walkdowns that you do 24 during outages.
25 MR. RIVERA-ORTIZ: Yes.
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70 1 MR. SCHULTZ: Thank you.
2 CHAIRMAN SKILLMAN: Joel, Dick Skillman, I 3 have one more question, please. You mentioned that as 4 you were preparing for this inspection, you asked 5 headquarters if there were any areas that headquarters 6 would like you to inspect.
7 MR. RIVERA-ORTIZ: That's correct.
8 CHAIRMAN SKILLMAN: What were those areas, 9 please?
10 MR. RIVERA-ORTIZ: It was one particular 11 item that the NRR asked us to take a second look at.
12 And there was an indication on a concrete wall in the 13 turbine building that the technical reviewers wanted 14 the region's opinion on the licensee's actions to 15 manage aging of that turbine building wall.
16 CHAIRMAN SKILLMAN: And what did you find in 17 that inspection, please?
18 MR. RIVERA-ORTIZ: The assessment of one of 19 the civil engineers in the group was that the condition 20 had been identified and been monitored and it did not 21 impact the structural integrity of the wall in the 22 turbine building.
23 And licensee had been monitoring the 24 condition, and in addition to that, had been well 25 capturing the request for additional information from NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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71 1 the staff.
2 And my understanding is that the licensee has 3 a specific commitment to take additional actions prior 4 to pure start up operation to address that condition.
5 CHAIRMAN SKILLMAN: Thank you, Joel. Thank 6 you.
7 MR. RIVERA-ORTIZ: You're welcome.
8 MEMBER STETKAR: Joel, this is John Stetkar.
9 I had to keep you on the hook here, but it's the price 10 you pay. You guys walked down the ERCW system, right?
11 MR. RIVERA-ORTIZ: That's correct.
12 MEMBER STETKAR: And I noticed the buried 13 and underground piping and tanks inspection program is 14 characterized as a new program for Sequoyah.
15 And as is sometimes the case on these new 16 program, when they look at operating experience they 17 say well, this is a new program. We don't have the 18 operating experience that's relevant to a new program.
19 Well, okay, but the plant has been operating 20 now for quite some number of years. What was the 21 condition, and I don't know the configuration? Could 22 you actually look at, is there ERCW piping, is it 23 underground, or is buried?
24 MR. RIVERA-ORTIZ: For this, the --
25 MEMBER STETKAR: Both?
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72 1 MR. RIVERA-ORTIZ: -- good expand of the 2 piping is buried.
3 MEMBER STETKAR: Is buried, below? Do you 4 know if they had any, did you come across when you were 5 there at the site any experience of leakage of problems 6 with that piping?
7 MR. RIVERA-ORTIZ: No, the result of the 8 walkdown identified that at least the accessible 9 conditions were well maintained. There was no 10 observable leakage from the components.
11 We did a walkdown from ERCW, essential raw 12 cooling water pumping station, all the way to a number 13 of heat exchangers and components. And we didn't 14 identify any active leaks in those components.
15 In our walkdown we talked to system 16 engineers. They discussed with us, he was very 17 knowledgeable, history of the system.
18 And that operating experience had been 19 captured in the operating experience review for the 20 system and the program. So to answer your question, 21 we did not see any active leakage in our walkdown of 22 the areas that we sampled.
23 MEMBER STETKAR: Good, and no evidence of 24 significant adverse operating experience when you 25 talked to the systems engineer?
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73 1 MR. RIVERA-ORTIZ: No, that's our 2 understanding.
3 MEMBER STETKAR: Yes, great. Thank you.
4 CHAIRMAN SKILLMAN: Joel, I would be remiss 5 if I didn't convey a compliment to you and your 6 inspection team. Several of the members used your 7 inspection report as significant basis for their review 8 and found your report to be very well done, very 9 thorough and extremely helpful in preparation for this 10 engagement with the licensee. So, thank you.
11 MR. RIVERA-ORTIZ: I appreciate that 12 comment. Thank you.
13 MR. SAYOC: Okay, Emmanuel Sayoc, I'll 14 continue the presentation. Thank you, Joel. Now 15 let's move to Section 3: The Aging Management Review 16 Results.
17 Section 3.0 covers the staff's review of the 18 applicant's aging management programs. Section 3.1 to 19 3.6 covers aging management review items in each of the 20 general system areas within the scope of license 21 renewal.
22 For a given aging management review, the 23 staff reviewed the items to determine whether it was 24 consistent with the GALL report. If an aging 25 management review was not consistent with the GALL NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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74 1 report, the staff conducted a technical review to 2 ensure accuracy.
3 The one open item in the SER is related to 4 an aging management program in Section 3.0 and will be 5 discussed shortly. Next slide.
6 The applicant submitted 43 aging management 7 programs in the application, 31 of which are existing 8 and 12 of which are new. One plant-specific AMP was 9 provided.
10 All within the exception of the 11 plant-specific AMP were evaluated by the staff for 12 consistency with the GALL report.
13 On the basis of its review, the AMPs 14 evaluated against the GALL report, the staff concluded 15 that 17 were consistent, 24 were consistent with the 16 enhancements, one was consistent with enhancements and 17 exceptions and one was plant-specific.
18 Let's now cover the open item related to the 19 aging management programs. Next slide. The 20 applicant's PWR vessel internals program implements 21 the guidance provided by EPRI's material reliability 22 program, MRP 227A, entitled PWR Reactor Internal 23 Inspection and Evaluation Guideline, which is dated 24 January 9, 2012.
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75 1 to action items, conditions and limitations which were 2 identified in the staff's safety evaluation report or 3 MRP 227.
4 Staff safety evaluation identified a number 5 of applicant/action items that each applicant's team 6 was responsible to address related to its 7 plant-specific design and operating history.
8 MRP issued EPRI letter number MRP 2013-25 9 dated October 2013 in order to provide an applicant with 10 the basis for responding to applicant's RAIs on Action 11 Item 1 and a method that could be used to determine 12 whether the technical assumptions in MRP 227 would be 13 bound for the design operations for the reactor vessel 14 internal for components at the facilities.
15 The EPRI letter MRP 2013-25 stated that if 16 an applicant's units did not maintain a minimum 17 distance of 12.2 inches between the top of the active 18 fuel and the bottom of the surface of the upper core 19 plate for a period extending two effective full power 20 years, then applicants will be required to provide 21 additional evaluations to assure applicability of MRP 22 227A to its design and operating history.
23 In its response to Action Item 1, the 24 applicant stated that neither of its units meet the MRP 25 screening criteria.
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76 1 That applicant stated that the maximum fast 2 neutron fluence for components above the upper core 3 plate is projected to be below the screening criteria 4 for irradiation embrittlement.
5 The staff noted that MRP 227A identifies an 6 irradiation assisted stress corrosing cracking or 7 IASCC and irradiation embrittlement, or IE, as aging 8 mechanisms that could employ Westinghouse designed 9 upper core plates.
10 The staff also noted the applicant's 11 response to RAI B.1.34-9 did not provide sufficient 12 information for the staff to review the applicant's 13 plant-specific evaluation.
14 Therefore, the staff issued follow up RAI 15 B.1.34-9A requesting the applicant to provide 16 additional information. Number 1, they were requested 17 to provide a brief description of the analysis and 18 methodology used to determine that projected fluence 19 after 60 years of operation will be below the threshold 20 limit.
21 Number 2, the neutron fluence values that are 22 used as the lower bound neutron fluence threshold for 23 IE at the core plate, and Number 3, the projected 24 neutron fluence values for the upper core plates 25 through 60 years of licensed operation for both units.
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77 1 The applicant provided the response to 2 staff's RAI following issuance of the SER with open 3 items. The staff is currently reviewing the 4 information provided and applicant's response and 5 expects to complete its review and document its 6 findings in the final SER.
7 We will present these findings in the final, 8 I'm sorry, in the ACRS full committee. Okay, next 9 slide.
10 Now moving to SER Section 4, which covers 11 time limited aging analysis or TLAA, Section 4.1 12 documents the staff's evaluation of the applicant's 13 identification of applicable TLAAs.
14 The staff evaluated applicant's basis for 15 identifying those plant-specific or generic analysis 16 that needed to be identified as TLAAs and determine that 17 TVA has provided an accurate list of TLAAs as required 18 by 10 CFR 54.21C1.
19 Section 4.2 to 4.7 documented the staff's 20 review of the applicable Sequoyah TLAAs as shown.
21 Based on its review and the information provided by the 22 applicant, the staff concluded that the TLAAs will 23 Number 1, remain valid for the period of standard 24 operation to the TLAAs have been projected to the end 25 of the period of extended operation, or Number 3, the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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78 1 effects of aging on those intended functions will be 2 adequately managed for the period of extended operation 3 as provided by 10 CFR 54.21 CI, II and III.
4 Next slide. The staff's conclusion will be 5 provided in a final safety evaluation report at the 6 conclusion of the staff's evaluations.
7 Pending satisfactory resolution of the open 8 item, the staff will be able to determine whether the 9 requirements of 10 CFR 54.29(a) will have been met for 10 the renewal of Sequoyah's Nuclear Power Plant's Units 11 1 and 2.
12 This concludes the staff presentation, and 13 now we'll be available to answer any further questions 14 from the subcommittee.
15 CHAIRMAN SKILLMAN: Thank you, Manny.
16 Colleagues, do any of you have a question for the NRC 17 staff? Pete.
18 MEMBER RICCARDELLA: On the open item, 19 you've received their response?
20 MR. SAYOC: Yes, sir. We received a 21 response in late October. I believe it was the last 22 week of October. The staff is currently reviewing 23 those responses.
24 MEMBER RICCARDELLA: And what are the --
25 (Simultaneous speaking)
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79 1 MR. SAYOC: I'm sorry, the question was?
2 MEMBER RICCARDELLA: The responses that 3 they submitted.
4 MR. SAYOC: I'll call on our staff member to 5 supply that information. Roger Kalikian.
6 MR. KALIKIAN: This is Roger Kalikian from 7 the NRC staff. The fluence they estimated for the 8 upper core plate, so part of the upper core plate is 9 going to have, Slide 3 about the embrittlement special 10 which was, trying to figure out --
11 MR. HISER: Page 3, Roger.
12 MR. KALIKIAN: Oh, Page 3? Yes, I'm on Page 13 3. I'm just, it was going to be 1.87 times 10 to the 14 21 for Unit 1 and 1.82 times 10 to the 21 for Unit 2.
15 And that would've been above.
16 MEMBER BALLINGER: It's roughly 1 DPA.
17 MR. KALIKIAN: I'm sorry, yes.
18 MEMBER BALLINGER: Roughly 1 DPA, and the 19 limit is what? I thought I heard somebody say 0.5.
20 MR. KALIKIAN: I'm sorry.
21 MEMBER BALLINGER: I thought it was one, but 22 I thought I heard somebody saying it was 0.5 DPA was 23 the threshold.
24 MR. KALIKIAN: No, 0.5 wasn't part of the 25 answer. Maybe, I have to think that it wasn't, but I NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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80 1 think for that area that was the fluence threshold.
2 MEMBER BALLINGER: Is it 1.5 DPA?
3 (Simultaneous speaking) 4 MR. LOTT: The screening criteria --
5 CHAIRMAN SKILLMAN: Please identify 6 yourself.
7 MR. LOTT: Randy Lott, Westinghouse, the 8 screening criteria that was used in MRP 227A as far as 9 radiation embrittlement of rocks and steel was 1.5 DPA.
10 The values, I think, the question about the values of 11 what was used for casting is where the other values came 12 in.
13 MEMBER BALLINGER: I can do this. Once you 14 get a mental conversion between fluence and DPA, which 15 to me is 1 DPA, but the threshold is 1.5. So why are 16 we, it's not above the threshold.
17 MR. HISER: Actually, the 1.87 is equivalent 18 to about 1.2 or so DPA. I'm sorry, 2.5 DPA.
19 MEMBER BALLINGER: Oh, okay. So I'm off by 20 one digit. My conversion factor was not good enough.
21 MR. HISER: It's a little bit higher.
22 MEMBER BALLINGER: Okay.
23 MR. HISER: And also that was on the lower 24 surface of the upper core plate. At the top surface 25 it's a bit lower, 6.39 times 10 to the 20th, which is NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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81 1 just below 1 DPA, and then 6.22 for Unit 2.
2 MEMBER BALLINGER: Okay.
3 MEMBER RICCARDELLA: So is there an 4 evaluation that's going to be performed?
5 MR. HISER: Yes, the staff, as Manny said, 6 the staff will evaluate the response, and if we find 7 it acceptable we'll write it up in the final SER.
8 Otherwise, if we have any additional questions, we'll 9 go back to the applicant with RAIs.
10 MR. MILLER: Mr. Chairman, just as far as the 11 record goes, I'm not sure if any of that information 12 is proprietary, its fluence.
13 MALE PARTICIPANT: No, none of it is 14 proprietary.
15 MR. LOTT: Those numbers were in the 16 non-proprietary version.
17 MR. MILLER: Thank you.
18 CHAIRMAN SKILLMAN: Staff, thank you.
19 Pete, thank you. Any other questions? Again, around 20 the table. Any of the members, Thomas, Harold?
21 MEMBER RAY: No.
22 CHAIRMAN SKILLMAN: Ron?
23 MEMBER BALLINGER: No.
24 CHAIRMAN SKILLMAN: John?
25 MEMBER STETKAR: No.
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82 1 CHAIRMAN SKILLMAN: Dr. Powers?
2 MEMBER POWERS: No.
3 CHAIRMAN SKILLMAN: Michael?
4 MEMBER RYAN: No.
5 CHAIRMAN SKILLMAN: On the bridge line, and 6 while we're waiting for the bridge line, does anyone 7 in the room have comments, please?
8 Everybody stand by. Let's make sure our 9 phone line is open, and we'll find out if there's 10 anybody out on the phone line that has comments or 11 questions.
12 OPERATOR: The line is open.
13 MEMBER STETKAR: For those of you who don't 14 participate, we'll square you away. This is one of the 15 highest technology we're ever doing.
16 CHAIRMAN SKILLMAN: If there's anyone out 17 there, could you please say something so we can confirm 18 that the line is open?
19 OPERATOR: The line is open.
20 CHAIRMAN SKILLMAN: Thank you. For those 21 who would be online, are there any questions or any 22 comments, please? I'll ask one more time. Any 23 questions or comments?
24 Hearing none, closing comments colleagues?
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83 1 would have? Let me first say thank you very much to 2 the NRC staff for your work, your presentation, for 3 getting us to this point.
4 Let me also thank the TVA team for all the 5 work that they have done to bring this presentation to 6 us and to give us a good briefing today. If there are 7 no more comments or questions, this meeting is 8 adjourned.
9 (Whereupon, the above-entitled matter 10 went off the record at 3:13 p.m.)
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Sequoyah Nuclear Plant ACRS Subcommittee Meeting November 05, 2014
Agenda
- Introductions John Carlin
- Plant History and Background Paul Simmons
- Major Modifications and Near Term Plant Improvements William Pierce Sequoyah ACRS Subcommittee
- License Renewal Application Project Erin Henderson
- License Renewal Application Results Dennis Dimopoulos
- Safety Evaluation Report Open Item Mike Henderson
- Concluding Remarks Dennis Dimopoulos 2
John Carlin Site Vice President
Introductions
Sequoyah ACRS Subcommittee 3
Representing Sequoyah Nuclear Plant
- Paul Simmons - Plant Manager
- William Pierce - Director, Site Engineering
- Dennis Dimopoulos - Manager, Engineering
- Michael Henderson - Manager, Engineering Programs Sequoyah ACRS Subcommittee
- Erin Henderson - Manager, Sequoyah Licensing 4
Personnel In Attendance ISI Programs Chemistry Programs Reactor Vessel Programs Adam Keyser/Jason Barrick Bruce Vogel Chris Webb/Dave Lafever Fire Protection/Appendix R Inaccessible Electrical Cable Steam Generators David Sanders/Robert Egli Darren Boehm Jeremy Mayo Ed Turner/Joy Williams/Jim Grant Structures Monitoring Flow Accelerated Corrosion Buried Piping Sequoyah ACRS Subcommittee Tyler Haraway David Spears Kyle Loomis Fuels Coatings Instrumentation Programs Fuels/Neutron Monitoring Kelli Yates Gary Tiner David Brown Chemical Monitoring Service Water Program Overhead Handling Harold Williams Ed Craig Brookes Bacon LR Project Contractor Fatigue Management WestinghouseRVI Alan Cox/Reza Ahrabli Dennis Lundy Randy Lott David Wootten/Roger Rucker 5
Paul Simmons Plant Manager Plant History and Background Sequoyah ACRS Subcommittee 6
Sequoyah Nuclear Plant Site Sequoyah ACRS Subcommittee 7
Plant Overview
- Sequoyah Units 1 and 2 are located on 525 acres beside the Chickamauga Reservoir on the Tennessee River, approximately 18 miles northeast of the city center of Chattanooga, Tennessee
- Sequoyah supplies electricity to approximately 8.3 million people through 158 distributors in the TVA service area Sequoyah ACRS Subcommittee
- Sequoyah is a two unit Westinghouse 4loop PWR
- Generator output for each Sequoyah unit is 1199 MWe for rated core power
- Each Sequoyah containment is a freestanding steel vessel with an ice condenser and separate reinforced concrete shield building
- Two natural draft cooling towers used in helper mode as required for NPDES limits 8
- 161KV and 500KV switchyards
Site Location 9 Sequoyah ACRS Subcommittee
History and Background
- Construction Permit - May 1970
- Operating License
- Unit 1 September 17, 1980
- Unit 2 September 15, 1981 Sequoyah ACRS Subcommittee
- Commercial Operation
- Unit 1 July 1, 1981
- Unit 2 June 1, 1982
- 1.3 % Measurement Uncertainty Recapture Uprate (44MWt)
- Unit 1 and 2 2002
- Steam Generator Replacement
- Unit 1 - 2003 / Unit 2 2013 10
Current Status
- Current Plant Status - November 5, 2014
- INPO Index of 100% on both units (Top Quartile 97.5%)
- Unit 1 97% Equipment Reliability Index Sequoyah ACRS Subcommittee
- Unit 2 98% Equipment Reliability Index
- Next Refueling Outage
- Unit 1 - Refueling Outage 20 - April 2015
- Unit 2 - Refueling Outage 20 - November 2015 11
William Pierce Engineering Director Major Modifications and Near Term Improvements Sequoyah ACRS Subcommittee 12
Major Modifications Completed or In Progress
- Installed pressurizer PWSCCresistant full strength weld overlays (U12007, U22006)
- Replaced portions of secondary side piping with FAC resistant material (began in 1990s and ongoing)
- Replaced steam generators (U12003; U2 2013)
Sequoyah ACRS Subcommittee
- Replaced main condenser tube bundles (titanium tubes; titanium clad tube sheets) - U21996, U11997
- Replaced portions of carbon steel service/raw water piping (2014)
- Replaced fire protection pumps/tanks and changed water source from raw water to potable water (1998)
- Replaced containment spray HX 1B (1998) and component cooling water HXs (1993) 13
Near Term/Future Plant Improvements Refueling U1 Outage 20 (April 2015)
- Replacing ~10 thimble tubes
- Replacing containment spray heat exchanger 1A Sequoyah ACRS Subcommittee Refueling U2 Outage 20 (November 2015)
- Replacing ~10 thimble tubes 2015 and 2016
- Replacing portions of carbon steel service/raw water piping
- Designing and begin installing cathodic protection (complete 2017)
Erin Henderson Licensing Manager License Renewal Application Preparation Sequoyah ACRS Subcommittee 15
License Renewal Application - Project
- Application Development
- LR Project Team assembled - 2010
- Experienced Team selected
- Sequoyah Program Owners and System Engineers - early and continuous involvement Sequoyah ACRS Subcommittee
- Technical Documents (Reports/RAIs) review/concurrence by SMEs and Program Owners
- Utilized reviews by industry experienced personnel
- Industry Interaction
- NEI Working Group involvement (Contractor/TVA)
- Industry peer review
Dennis Dimopoulos Engineering Manager License Renewal Application Results Sequoyah ACRS Subcommittee 17
License Renewal Application Details
- Application Details
- Submitted application January 7, 2013
- Followed scoping guidance of NEI 9510 Industry Guideline for Implementing the Requirements of 10CFR54The License Sequoyah ACRS Subcommittee Renewal Rule Rev 6
- Conducted Aging Management Review (AMR) per NEI 9510 and industry guidance documents
- Addressed six License Renewal (LR) ISG documents in the LRA and two LR ISG documents in RAI responses
- Completed ~4100 AMR line items
Aging Management Program (AMP) Summary 43 AMPs Credited Consistent Consistent Consistent with Plant Specific Total with GALL with Enhancements Sequoyah ACRS Subcommittee Enhancement and Exceptions LRA 20 22 0 1 43 SER 17 24 1 1 43 with Open Item 19
License Renewal Application (LRA)
Commitments
- License Renewal Commitments
- Managed by Sequoyah Commitment Tracking System and Corrective Action Program (CAP)
Sequoyah ACRS Subcommittee
- Total of 44 commitments
- 43 associated with AMPs
- 1 associated with the Operating Experience (OE) program 20
Implementation
- Participating in NEI LR Implementation Working Group
- Selected permanent Aging Management Coordinator
- Initiated informal OE review for impacts to AMPs in advance of revision to fleet procedural guidance Sequoyah ACRS Subcommittee
- Initiated work to address commitments
- Sequoyah AMP Owners will guide the implementation effort assisted by experienced implementation contractor 21
Safety Evaluation Report (SER) with Open Item
- Sequoyah SER contains one Open Item
- Sequoyah SER contains no confirmatory items
- Sequoyah SER contains two License Conditions
- License Condition 1 Sequoyah ACRS Subcommittee
- Include 10 CFR 54.21 (d) UFSAR supplement in the next UFSAR update
- Evaluate changes to UFSAR supplement per 10 CFR 50.59
- License Condition 2
- Implement new programs and enhancements six months prior to the PEO
- Perform inspections and testing before the end of the last RFO prior to the PEO or six months prior to the PEO, whichever occurs later 22
Michael Henderson Engineering Programs Manager SER Open Item Sequoyah ACRS Subcommittee 23
SER - Open Item B.1.349c RAI Request
- Provide description of the methodology used to project the 60 year fluence at the Reactor Vessel Internal (RVI) upper core plate (UCP)
- Provide the projected 60 year fluence at the UCP compared to the screening threshold fluence for Irradiation Embrittlement (IE)
Resolution Sequoyah ACRS Subcommittee
- Provided the methodology used for the fluence projections as well as the 60 year projected fluence at the bottom of the UCP
- Neutron transport method meets RG 1.190
- Methodology described in NRC approved WCAPs 14040A and 16083NPA
- Provided the basis for the conclusion that MRP227A inspection protocols for RVIs remain valid for Sequoyah U1 and U2
- Responses prepared by the PWROG and approved by TVASQN Status 24
- Response submitted
Reactor Vessel Internals Upper Core Plate Sequoyah ACRS Subcommittee 25
Concluding Remarks
- Sequoyah LRA based on NUREG1801, Rev. 2 with exceptions only in the Fire Water Program for LRISG201202
Sequoyah ACRS Subcommittee
- Development of the application, technical reports, audit & inspection interviews, RAI responses and commitment development
- Programs and program enhancements defined for managing aging effects at Sequoyah for the PEO
- Invested in plant modifications for continuing safe, reliable extended operation 26
Comments and Questions?
27 Sequoyah ACRS Subcommittee
Advisory Committee on Reactor Safeguards License Renewal Subcommittee Sequoyah Nuclear Plant, Units 1 and 2 Safety Evaluation Report (SER) with Open Items November 5, 2014 Emmanuel Sayoc, Project Manager Office of Nuclear Reactor Regulation 1
Presentation Outline
- Overview of Sequoyah license renewal review
- Region II License Renewal Onsite Inspection
- SER Section 2, Scoping and Screening Review
- SER Section 3, Aging Management Review
Audits and Inspections
- Scoping and Screening Methodology Audit
- March 11-14, 2013
- Aging Management Program (AMP) Audit, weeks of
- March 18, 2013, and March 25, 2013
- Environmental Audit
- April 8-12, 2013
- Region II Inspection (Scoping and Screening & AMPs), weeks of
- October 21, 2013 - Unit 1 Containment Walk-down
- November 18, 2013 and December 2, 2013 - Team Inspection 3
Overview (SER)
- Safety Evaluation Report (SER) with Open Items issued September 29, 2014
- OI B.1.34-1: Reactor Vessel Internals Program
- The final SER is scheduled for publication January 5, 2015 4
Region 2 Inspections Inspection Overview:
- Inspection Procedure IP71002 completed in 2013 o Oct. 2013 - Containment walk-down during Unit 1 refueling outage o Nov. 2013 - Team Inspection (5 inspectors and 1 NRR materials engineer) on-site for 2 weeks
- Inspection Scope:
o Scoping and Screening Methodology of SSCs o Aging Management Programs for In-scope SSCs o Updates to the License Renewal Application and Open Items Inspection 5
Region 2 Inspections
==
Conclusions:==
- Scoping and screening performed in accordance with 10 CFR 54
- Existing programs were effective in managing aging effects
- Plans existed to implement enhancements and new programs
- Information used to prepare the license renewal application was retrievable, auditable, and consistent with 10 CFR 54
- Reasonable assurance that aging effects will be managed and intended functions maintained 6
Section 3: Aging Management Review
- Section 3.0 - Aging Management Programs
- Section 3.1 - Reactor Vessel & Internals, Reactor Coolant System
- 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 7
SER Section 3 3.0.3 - Aging Management Programs
- 43 Aging Management Programs presented by applicant and evaluated in the SER
- 31 Existing and 12 new
- Consistent - 17
- Consistent with Enhancements - 24
- Consistent with Enhancements and Exceptions - 1
- Plant Specific - 1 8
SER Section 3 Open Item OI B.1.34-1: Reactor Vessel Internals Program
- Issue: The applicants response to A/LAI No. lacked information on projected fluence values for upper internals and upper core plate.
- Staff issued RAI B.1.34-9a, requesting the applicant demonstrate 60-year fluence below embrittlement threshold
- Resolution of OI B.1.34-1 is pending staffs review of the applicants response 9
- 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 10
Conclusion Pending satisfactory resolution of the open item, 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 Sequoyah Plant, Units 1 and 2 11