ML18340A040
| ML18340A040 | |
| Person / Time | |
|---|---|
| Issue date: | 11/15/2018 |
| From: | Kent Howard Advisory Committee on Reactor Safeguards |
| To: | |
| Howard K | |
| References | |
| NRC-3984 | |
| Download: ML18340A040 (160) | |
Text
Official Transcript of Proceedings NUCLEAR REGULATORY COMMISSION Title: Advisory Committee on Reactor Safeguards Plant License Renewal Subcommittee Docket Number: (n/a)
Location: Rockville, Maryland Date: Thursday, November 15, 2018 Work Order No.: NRC-3984 Pages 1-160 NEAL R. GROSS AND CO., INC.
Court Reporters and Transcribers 1323 Rhode Island Avenue, N.W.
Washington, D.C. 20005 (202) 234-4433
1 1
2 3
4 DISCLAIMER 5
6 7 UNITED STATES NUCLEAR REGULATORY COMMISSIONS 8 ADVISORY COMMITTEE ON REACTOR SAFEGUARDS 9
10 11 The contents of this transcript of the 12 proceeding of the United States Nuclear Regulatory 13 Commission Advisory Committee on Reactor Safeguards, 14 as reported herein, is a record of the discussions 15 recorded at the meeting.
16 17 This transcript has not been reviewed, 18 corrected, and edited, and it may contain 19 inaccuracies.
20 21 22 23 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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1 UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION
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ADVISORY COMMITTEE ON REACTOR SAFEGUARDS (ACRS)
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PLANT LICENSE RENEWAL SUBCOMMITTEE
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THURSDAY NOVEMBER 15, 2018
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ROCKVILLE, MARYLAND
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The Subcommittee met at the Nuclear Regulatory Commission, Three White Flint North, Room 1C3 & 1C5, 11601 Landsdown Street, at 8:30 a.m., Gordon R. Skillman, Chairman, presiding.
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2 COMMITTEE MEMBERS:
GORDON R. SKILLMAN, Chairman MICHAEL L. CORRADINI, Member RONALD G. BALLINGER, Member DENNIS C. BLEY, Member*
CHARLES H. BROWN, JR., Member WALTER KIRCHNER, Member JOY L. REMPE, Member PETER RICCARDELLA, Member MATT SUNSERI, Member ACRS CONSULTANT:
STEPHEN SCHULTZ DESIGNATED FEDERAL OFFICIAL:
- Present via telephone NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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3 C-O-N-T-E-N-T-S Opening Remarks Gordon Skillman..............................4 Staff Remarks Joseph Donoghue..............................7 Applicant Remarks Eric McCartney...............................9 NextEra Presentation..............................16 NRC Staff Presentation SER Butch Burton & Nik Floyd....................60 Subcommittee Discussion Gordon Skillman............................103 Public Comment...................................113 Adjourn..........................................118 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 (8:29 a.m.)
3 CHAIRMAN SKILLMAN: Ladies and gentlemen, 4 good morning. This meeting will come to order. This 5 is a meeting of the Plant License Renewal Subcommittee 6 of the Advisory Committee on Reactor Safeguards. I'm 7 the Chairman of the Subcommittee.
8 ACRS members in attendance are Dr. Ronald 9 Ballinger, Dr. Peter Riccardella, Dr. Walt Kirchner, 10 Mr. Matt Sunseri, Dr. Joy Rempe, Dr. Michael Corradini.
11 We expect Mr. Charles Brown. We may have Dr. Dennis 12 Bley on the bridge line. Dr. Stephen Schultz is our 13 consultant for this meeting. Mr. Kent Howard of the 14 ACRS staff is the designated federal official for this 15 meeting.
16 The purpose of this meeting is for the staff 17 and NextEra Energy Seabrook to brief the Subcommittee 18 on the Seabrook Station Unit 1 license renewal 19 application.
20 I pause here. We had a meeting on October 21 31st on one topic regarding Alkali Silica Reaction.
22 Today's meeting is not that meeting. Today is the 23 actual license renewal meeting for this nuclear power 24 plant. And the last meeting we had on this action was 25 July 10, 2012.
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5 1 The Subcommittee will gather information, 2 analyze relevant issues and facts, and formulate a 3 proposed position, as appropriate, for deliberation 4 by the full Committee if needed.
5 I remind everyone here, this is a 6 Subcommittee meeting. Members are free to ask 7 questions as they wish. Then the Subcommittee makes 8 a recommendation to the full Committee. And that full 9 Committee is in two weeks. And it is from the full 10 Committee meeting that the origin of the letter report 11 will come.
12 We welcome Charlie Brown. Charlie, 13 welcome.
14 The ACRS was established by statute, and 15 is governed by the Federal Advisory Committee Act, FACA.
16 That means that the Committee can only speak through 17 its published letter reports. We hold meetings to 18 gather information to support our deliberations.
19 The ACRS full Committee reviews and advises 20 the Commission with regard to the licensing and 21 operation of production and utilization facilities, 22 and related safety issues, the adequacy of proposed 23 reactor safety standards, technical and policy issues 24 related to the licensing of evolutionary and passive 25 plant designs, and other matters referred to it by the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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6 1 Commission.
2 The ACRS section of the US NRC public 3 website provides our Charter, our By-Laws, our letter 4 reports, and full transcripts of all full and 5 Subcommittee meetings, including slides presented at 6 the meetings. That is a fact, except for where there 7 is proprietary information.
8 The rules for participation in today's 9 meeting were announced in the Federal Register. The 10 meeting was announced as open. But portions can be 11 closed as needed to protect information proprietary 12 to NextEra or its vendors, pursuant to 5 U.S.C.
13 552(b)(c)(iv).
14 We have received written comments from 15 members of the public regarding today's meeting. But 16 we have not received a request for time to make oral 17 statements in advance of today's meeting.
18 A transcript of the meeting is being kept, 19 and will be made available, as stated in the Federal 20 Register notice. Therefore, we request that 21 participants in this meeting use the microphones 22 located throughout the meeting room when addressing 23 the Subcommittee.
24 Participants should first identify 25 themselves, and speak with sufficient clarity and NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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7 1 volume, so that they can be readily heard.
2 A telephone bridge line has been 3 established for this meeting. We have several members 4 of the public, and an ACRS member listening in on the 5 public bridge line. To preclude interruption of the 6 meeting, please mute your individual lines during the 7 presentations and during the Committee discussions.
8 And for all individuals in the room we ask that you 9 please silent your electronic devices.
10 As a matter of administration we have 11 scheduled this meeting without breaks. We commonly 12 have breaks through the meeting. We're not doing that 13 today. We're going to march on through this. And so, 14 we're going to ask you to please excuse yourself quietly 15 when you wish, and return quietly.
16 For the sake of brevity of the meeting, 17 for the potential for those who might wish to travel 18 as early as they can at the end of the meeting, we thought 19 it prudent to not schedule breaks.
20 We will now proceed with the meeting. And 21 I call upon Joe Donoghue to please make introductory 22 remarks.
23 MR. DONOGHUE: Good morning, and thank 24 you, Subcommittee Chairman Skillman, and members of 25 the ACRS License Renewal Subcommittee. I'm Joe NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 1 Donoghue. I'm the Deputy Director of the Division of 2 Materials and License Renewal in NRR.
3 We thank the Subcommittee for the 4 opportunity to present the results of the staff's review 5 of the license renewal application for Seabrook Station 6 Unit 1.
7 This review began over eight years ago.
8 The primary contributor to the length of the review 9 was the identification of the alkali silica reaction 10 affecting concrete structures, and the development of 11 methods for assessing and managing this phenomenon as 12 part of the aging management program at Seabrook.
13 On October 31st, as Chairman Skillman 14 mentioned, the Subcommittee heard a detailed 15 presentation by the applicant, and another presentation 16 by the staff on ASR. And we do not plan to revisit 17 that issue today during our formal presentation.
18 Instead, we'll focus on the resolution and 19 closure of the remainder of the open items from the 20 2012 SER with open items that was presented to the 21 Subcommittee.
22 The license renewal presentation will be 23 led by Butch Burton, the license renewal project manager 24 for this review. Part of the management team that are 25 here with me today are Dr. Allen Hiser, Senior Technical NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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9 1 Advisor for License Renewal, Eric Osterle, Chief of 2 the projects branch in our division. And in the 3 audience are other managers from our divisions, and 4 from NRR who contributed to the review.
5 We also have in the audience, and on the 6 phone other NRR staff who supported the review, as well 7 as Region I staff, who performed the facility 8 inspections in support of license renewal.
9 We look forward to a productive discussion 10 today with the Subcommittee. And as always, we'll 11 address any questions on our review that you may have.
12 At this time I'd like to turn the presentation over 13 to the NextEra team, and their Regional Vice President 14 of the Northern Region, Mr. Eric McCartney. Thank you.
15 MR. McCARTNEY: Thank you, Mr. Donoghue.
16 Good morning. My name is Eric McCartney. As Mr.
17 Donoghue mentioned I'm the Regional Vice President for 18 NextEra Energy. I have responsibility for the Duane 19 Arnold Station in Iowa, Point Beach Station in 20 Wisconsin, and the Seabrook Station in New Hampshire, 21 which we're here to talk about today.
22 If I could go to the next page, Ken? Many 23 of the discussion points that I covered last, two weeks 24 ago when we were here, I want to focus again. This 25 is our Nuclear Excellence Model. And this is what sets NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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10 1 the framework for everything we do, and how we've 2 approached the license renewal program, and how we 3 manager our fleets and our station.
4 And one of the key areas that I'll speak 5 to is that the top values are a deep respect for, 6 demonstration of a respect for all activities, with 7 a deep respect for nuclear safety.
8 But you also see in the core principles 9 that effective long range planning is a key element 10 of how we manage our station, and our fleet going 11 forward.
12 Today I have the team here with me. Mr.
13 Mike Collins, he's our engineering director. Ed Carley 14 is our license renewal program manager. And Mr. Ken 15 Brown is our licensing manager.
16 Mike will discuss the current plant status, 17 the things that we've done over the last several years 18 to improve the plant reliability, major plant equipment 19 improvements, and how our engineering programs have 20 set ourselves up for continued long term investment 21 in the operation of the Seabrook facility.
22 And Ken and Ed will discuss the license 23 application, and the activities that we've gone 24 through. I want to keep my remarks brief so that we 25 can focus on the important points of discussion today.
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11 1 So, thank you, Mr. Chairman.
2 CHAIRMAN SKILLMAN: Eric, before you pass 3 the baton, let me ask you two questions. A critical 4 lesson we all learned out of TMI-2 is respect for this 5 technology, just understanding what it is we're dealing 6 with.
7 And one of the lessons I learned in the 8 years that followed was how, is how important it is 9 for the senior exec who casts the shadow at the site, 10 executes Appendix B to 10 C.F.R. 50, all 18 points as 11 a collage and framework for the site and for the 12 operation.
13 Would you please give us a minute of your 14 understanding, and your philosophy of how you intend 15 to execute the quality assurance program at Seabrook 16 Unit 1?
17 MR. McCARTNEY: Well, Mr. Chairman, as you 18 know the Appendix B program has a large footprint.
19 I spend quite a bit of time engaged in all of the elements 20 of our Appendix B program, from my work order close 21 out, or work order documentation, quality of records.
22 We have an audit program I follow-up 23 actually on a daily basis. We have metrics to assess 24 the quality of how we complete our records program, 25 our records management.
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12 1 We have our quality control program that 2 we have, that actually is housed on site by reports 3 independently around me, straight to the Chief Nuclear 4 Officer.
5 We do audits of that process. I have daily 6 pull ups with our quality assurance program. We do 7 specific monitoring. And I do personal monitoring of 8 the quality control inspections.
9 We look in our, we have a very robust work 10 activity risk management process. And one of the key 11 areas that we look for are quality control hold points, 12 and quality control checkpoints that we do in all 13 evolutions, whether it be maintenance, modifications, 14 operations activities, especially during our outage, 15 where a number of those activities could create the 16 possibility for latent conditions, that we want to make 17 sure that we detect on a personal basis.
18 We also, one of our key activities is, of 19 course, our Corrective Action Program. I chair, or 20 my plant manager chairs at each of the sites our 21 Corrective Action Program, Daily Management Review 22 Committee. We screen on a daily basis every AR that's 23 written.
24 I review every single log entry, both in 25 the operator logs, the chemistry logs, the engineering NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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13 1 logs, to make sure that there's not a condition that's 2 been documented somewhere that's not been captured in 3 the Corrective Action Program that needs to be captured.
4 And we have a tremendous oversight of how 5 the Corrective Action Program is executed with 6 assessments. We have, I think the last time I spoke 7 to you about a self-assessment program.
8 We use Level 1 assessments, which are done 9 at the site, to be very focused very quickly, to see 10 how effective our Corrective Action Program is, and 11 how corrective, and how timely that Corrective Action 12 Program is. We have a number of metrics that monitory 13 and measure that.
14 And I have direct oversight of those for 15 not only the Seabrook Station, but for all of my 16 stations.
17 We're also, of course, through the 18 engineering program there's a tremendous amount of 19 quality controls that we want to put in place, in terms 20 of managing the risk and the quality of modifications.
21 We have not only our onsite review group.
22 We have a safety review group that reviews of all 23 modifications, plant changes, critical evolutions.
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14 1 risk assessment of every evolution that we do, that 2 fits into that category.
3 And then we deploy and enterprise risk 4 process under the learnings from IER 1420, where we 5 take on some projects. For example, at Seabrook we 6 replaced all four feed reg valves in one outage.
7 And we elevated that into our enterprise 8 risk process, to make sure that we had the right third 9 party reviews, engineering validations, and functional 10 validations, to make sure that that process was going 11 to be safe.
12 CHAIRMAN SKILLMAN: Eric, you've 13 explained that you have a strong Corrective Action 14 Program. What is the strength of the link between your 15 Corrective Action Program and your Work Management 16 Program?
17 And I ask that question because in Update 18 60 of the, of your license renewal application you're 19 now carrying 91 action items. And my question is, 20 what's the link between what you have in corrective 21 action, and what you have in work management, to make 22 sure that work gets completed the way it is committed 23 to be completed?
24 MR. McCARTNEY: So, every, our process 25 starts with a single, what we call a single point entry.
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15 1 So, every condition that requires addressing goes into 2 the single point Corrective Action Program addition.
3 If it gets rolled to a work order, or a 4 work is the right vehicle to correct that condition 5 there's a reference tie in the corrective action 6 document to reference the work order.
7 So, those are tied programmatically. So, 8 the action can't be closed until the work order is 9 closed. And then, we have a follow-up to make sure 10 that those actions are closed as appropriately.
11 And then, there's a closeout mechanism that 12 validates. When we get ready to close that AR, that 13 action request, it validates that the work order has 14 been completed, and the post maintenance testing has 15 been done to ensure that condition has been corrected.
16 CHAIRMAN SKILLMAN: Thank you. Please 17 proceed.
18 MR. McCARTNEY: Thank you. And I'd like 19 to now turn the presentation over to Mr. Brown.
20 MR. BROWNE: Thank you, Eric. Good 21 morning. I am Ken Browne, licensing manager for 22 NextEra Seabrook. I've been at Seabrook for 23 approximately 28 years, beginning in the Operations 24 Department as a non-licensed operator, and then as a 25 license senior reactor operator, working in the control NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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16 1 room at various control room positions, including shift 2 manager, and ultimately operations manager.
3 I've also held the position of training 4 manager for accredited programs, and most recently as 5 licensing reg compliance manager, and sponsor for the 6 station's ASR programs for the past three years.
7 Since Seabrook's last visit to ACRS 8 Subcommittee the station has continued to engage in 9 learning from the industry's best practices, and 10 developing our existing engineering programs, as well 11 as enhancing our aging management plans, to ensure 12 Seabrook is maintained to the highest level of safety 13 and material standards.
14 As the Committee is aware, and as Chairman 15 Skillman mentioned, at our last visit there were a 16 number of remaining open items from our license renewal 17 application. And during this session we are pleased 18 to present the closure of these items. And we welcome 19 the questions from the Subcommittee.
20 You'll note in the chairs we've also 21 brought a number of our program owners from the station, 22 as well as our corporate offices. And we're proud to 23 demonstrate that NextEra Engineering has a healthy 24 blend of experienced program owners, as well as a number 25 of new, enthusiastic new owners that have ownership NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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17 1 in recent years.
2 Again, we look forward to your questions.
3 And I'm going to turn the panel over to Mike Collins, 4 the engineering director, and also Rudy Gil, who has 5 joined us from fleet program engineering.
6 MR. COLLINS: Good morning. My name is 7 Mike Collins. I'm the Engineering Director at Seabrook 8 Station. Thirty-seven years in the industry, 17 years 9 prior to my employment with NextEra with Sonestra 10 (phonetic) Engineering, New Build in continuing 11 services, and then 20 years with NextEra Energy. The 12 last five as Engineering Director.
13 Brief overview of our agenda today. I'll 14 start out with a background discussion. I will make 15 that brief, because all the ACRS panel members are the 16 same members that I reviewed these items with on 10/31.
17 We'll go over most importantly the license 18 renewal project overview. Ed Carley will go through 19 our open actions, and discuss closure of previous safety 20 evaluation report open items.
21 And then we'll present concluding remarks, 22 which will communicate that NextEra Energy Seabrook 23 has met the requirements of 10 C.F.R. 54 for issuance 24 of a renewed license for Seabrook Station Unit 1.
25 Next slide, please. Again, I'll be brief.
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18 1 Seabrook background. We are a single unite 2 Westinghouse 4-loop pressurized water reactor, with 3 a General Electric turbine generator.
4 Our reactor's housed in a steel lined, 5 reinforced concrete containment structure, which is 6 enclosed by a reinforced concrete containment enclosure 7 structure. Presently rated at 36487 megawatts thermal 8 power, 1250 net megawatts electric.
9 Next slide, please. Again, aerial photo 10 of our plant footprint As we discussed on the 31st, 11 construction of Seabrook Station Unit 2 was terminated 12 in 1984. And its construction permit expired in 13 October 1988.
14 The protected area does not include any 15 items, any other properties from Unit 2. It's 16 specifically Unit 1 components. Next slide, please.
17 Again, overall licensing history.
18 Construction permit July 1976. Our full power 19 operating license March 15th, 1990. We did do a Zero 20 Power Recapture in December 2005.
21 The NRC issued an amendment to the Seabrook 22 facility operating license, extending our expiration 23 date from October 17th, 2026 to March 15th, 2030. Our 24 license renewal application was submitted May 25th, 25 2010. And our present operating license expires March NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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19 1 15th, 2030.
2 Next slide, please. Our present plant 3 status, we just recently completed our latest refueling 4 outage on October 29th of this year. Overall capacity 5 factor, 15 of our 19 cycles has a capacity factor greater 6 than 94 percent. Overall lifetime capacity factor 87 7 percent.
8 As you can see, for cycle 16 through 19, 9 Seabrook has had an excellent operating history over 10 the last cycles. Our next refueling outage is spring 11 2020, which is the end of present operating cycle 20.
12 Our capacity factor performance is representative of 13 our solid equipment reliability, and material 14 condition.
15 Next slide, please. In order to continue 16 to maintain high capacity factors, Seabrook continues 17 to improve equipment reliability and material 18 condition. Recent station improvements include 19 replacement of our safety related vital batteries, 20 replacement of our safety related vital converters.
21 Our three generator step-up transformers 22 have been replaced. And we have completed our 23 mechanical stress improvement process. Has been 24 completed for all of our reactor vessel nozzles.
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20 1 issue to replace all above ground piping with high alloy 2 AL6XN. We had no issues on our last operating cycle 3 with any leakages, or any pressure boundary concerns 4 on our service water system.
5 We've upgraded our in-core detector 6 system. Our process control circuit cards have been 7 fully replaced, 159 single point vulnerability circuit 8 boards have been replaced. And our solid state 9 protection system circuit cards, 133 cards have all 10 been replaced with new upgraded circuit boards.
11 Two outages ago we sent out our rod control 12 motor generator sets for a full reconditioning and 13 refurbishment. And lastly, our present reactor 14 coolant pumps have installed the shutdown reactor 15 coolant pump seals.
16 MEMBER REMPE: Excuse me.
17 MR. COLLINS: Sure.
18 MEMBER REMPE: Could you elaborate a 19 little bit more on what you did with the in-core 20 detectors?
21 MR. COLLINS: We replaced the, oh, the 22 whole system with new in-core detectors. And we also 23 replaced the seal table assemblies that we had had 24 issues with leakage on, with an upgrade design, to make 25 sure we don't have any further concerns during our NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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21 1 cycles with leakage.
2 MEMBER REMPE: And the detectors? They 3 were SPNDs? Or what were they? And you kept the same 4 type of detectors?
5 MR. COLLINS: Yes, we did.
6 MEMBER REMPE: Okay. Thank you.
7 DR. SCHULTZ: Is it a fixed detector system 8 now only?
9 MR. COLLINS: Correct. It is no longer, 10 original design was movable. That's been abandoned.
11 And we now are purely fixed. We withdraw them, 12 certainly, during the outage, for our core alterations.
13 But it is a fixed system.
14 DR. SCHULTZ: And at this point all of the 15 detectors are operational?
16 MR. COLLINS: There is one detector that 17 we had an issue with leakage on, that we cut and capped 18 the cycle. All the other detectors are operable.
19 DR. SCHULTZ: So, how many do you have out 20 of how many that are operational now?
21 MR. COLLINS: Fifty-six out of 57.
22 Fifty-six out of 57.
23 DR. SCHULTZ: Understood. Thank you.
24 MR. COLLINS: At this time I will turn over 25 the discussion to Mr. Ed Carley.
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22 1 CHAIRMAN SKILLMAN: Before you do that, 2 let me go through a number of items. Because you're 3 kind of in the, if you go back to the previous slide 4 you're kind of in the hardware, and here's our machine 5 --
6 MR. COLLINS: Yes, sir.
7 CHAIRMAN SKILLMAN: -- discussion. And 8 so, I've gone through 887 pages of the SER, and pulled 9 out a couple of things I'd like to ask you about, and 10 get on the record.
11 MR. COLLINS: Very good.
12 CHAIRMAN SKILLMAN: Talk to us for two 13 minutes about external flooding, and the NextEra vision 14 regarding sea level rise over the next 20 years?
15 MR. COLLINS: Very good. So, we've always 16 had a flooding analysis at Seabrook Station, certainly 17 after the Fukushima event. We went through all the 18 required regulatory reviews and inspections. And 19 also, that rolled into our, certainly our flex 20 improvements that we made at the station.
21 Presently, with margin, looking at our 22 flooding conditions, we have no issues with entrance 23 of, at that point, seawater into any of our structures.
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23 1 the station, with regards to extreme weather events, 2 as far as precipitation.
3 But again, we are two and a half miles back 4 from the Atlantic Ocean. We have marsh out in front 5 of the station. But with regards to maximum flooding 6 criteria for the station, there's presently margin 7 within our design for that.
8 CHAIRMAN SKILLMAN: Michael, what has your 9 experience been? We saw in the storm that come up the 10 East Coast, brought Oyster Creek to within inches of 11 being flooded.
12 And Exelon thought that they were well 13 protected. And they learned on a huge storm surge they 14 were not as well protected as they thought they were.
15 What has the experience been up on your part of the 16 Atlantic coast relative to strong storm driven 17 flooding?
18 MR. COLLINS: So, in my experience, I've 19 been at the station for 20 years now. We do go water 20 solid in the marsh area around the station itself.
21 But our grade is at 20 foot above sea level. And there's 22 been no impact or fear of impact of storm surge that 23 would impact the station.
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24 1 leakage. This is a cousin of the ASR discussion. But 2 it really gets to, the plant was designed so that there 3 would not be water ingress. But there is.
4 MR. COLLINS: Yes, sir.
5 CHAIRMAN SKILLMAN: What happened?
6 MR. COLLINS: So, original design of the 7 station was to be built on bedrock. During original 8 construction we did have dewatering pumps running all 9 the time. The design of the station was to put a 10 membrane around our concrete structures, and then to 11 backfill around our structures to the present grade.
12 Obviously that membrane has failed in 13 several areas around the station. That has allowed 14 the ingress of water through our concrete structures, 15 into our lower level elevations. We had a good 16 discussion on what the issues with that were on October 17 31st.
18 We do have active dewatering wells running 19 at the station. Certainly not to the extent that we've 20 dried the station out completely. But we have made 21 improvements with the ingress of water into the station.
22 And we are committed to continue to explore 23 ways to continue to minimize the ingress of water into 24 our lower level concrete structures.
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25 1 feedwater pump house. The text in the SER communicates 2 the emergency feedwater pump house heating system is 3 designed to maintain the pump house at or above 50 4 degrees Fahrenheit when the outside temperature is zero 5 degrees Fahrenheit or above. Sounds okay. What 6 happens when it's below zero degrees Fahrenheit?
7 MR. COLLINS: Certainly with the operator 8 rounds, and us monitoring the station for required, 9 temperature requirements for any area, whether it's 10 emergency feedwater control room, battery rooms.
11 If in fact we do, the heating system can't 12 maintain that, which obviously is a possibility, then 13 certainly at that point we would add augmented heat, 14 if required, through our formal process.
15 That would be considered a temporary 16 modification, which goes through the 50.59 process.
17 And we would manage that to keep that system operable, 18 but degraded.
19 CHAIRMAN SKILLMAN: Fair enough. Okay.
20 Canopy welds. These inspections include robotic bare 21 metal examination at the top of the head, and a robotic 22 ultrasound examination of the J groove welds in the 23 penetration tube between the bottom of the head.
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26 1 an acceptable or unacceptable indication is, and what 2 the current status is of canopy welds?
3 MR. COLLINS: And I'll have Rudy Gil to 4 answer that question.
5 CHAIRMAN SKILLMAN: Rudy, good to see you 6 again.
7 MR. GIL: Thank you, Gordon. Yes. Rudy 8 Gil. And since I hadn't had a chance to introduce 9 myself, I'm the fleet programs engineering manager.
10 Forty years' experience in nuclear power. Probably 11 about half of it in design, the other half in programs 12 area. So, the, I run the fleet organization where we 13 have the majority of the programs for the site.
14 So, the question that you were asking 15 related to the reactor vessel head penetrations. So, 16 the last inspection that we performed was in 2014.
17 And that is performed with ultrasonic methods. And 18 we had no indications of any degradation on the 19 penetrations. Our next inspection is planned for our 20 next outage in 2020.
21 CHAIRMAN SKILLMAN: Thank you, Rudy.
22 Next question has to do with liner inspections. There 23 was a moisture barrier on concrete floor issue. What's 24 the current status of your liner inspections, please?
25 This is also codified in your Commitment 50.
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27 1 MR. COLLINS: Do you want to take that?
2 MR. GIL: Yes. I can cover that also.
3 Rudy Gil. Yes. So, that, those inspections have been 4 incorporated into our IWE program. We had identified 5 the issue that you mentioned several years back. We 6 have since come back and performed another inspection 7 in that area.
8 During those inspections we were able to 9 perform inspections of the liner areas that would be 10 affected. Found no issues associated with it. And 11 basically, the, not finding anything is part of it.
12 But also understanding why it is that we're not finding 13 anything.
14 And based on the conditions that the, that 15 those plates are in, even with the water that was found, 16 the chemistry associated with it would not be conducive 17 to degradation of the liner plate. But those are now 18 part of our program. And we would on a periodic basis 19 come back and inspect those.
20 CHAIRMAN SKILLMAN: Okay. Thank you, 21 Rudy. Reactor vessel studs. Understand, I'm going 22 through the aging management reviews, and the AMP work 23 that was done.
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28 1 information. What's the current status of your 54 2 studs? Are they all in place? Are any degraded?
3 And for the elongation issue, was that a 4 stud tensioner issue? Was that an operator error 5 issue? Was it a, you didn't, someone didn't read the 6 pressure on the stud tensioner accurately?
7 So, two questions. What's the current 8 status of your 54 studs? And number 2, for the 9 elongation issue, what happened?
10 MR. GIL: I'm not familiar with the 11 elongation issue.
12 MR. COLLINS: Yes. The present condition 13 of -- This outage we had -- So this, all our reactor 14 studs are intact. This outage we had no issues with 15 disassembly and reassembly. As a matter of fact, we 16 replaced our vessel studs with newly refurbished studs 17 this outage.
18 CHAIRMAN SKILLMAN: And the new studs meet 19 the maximum 150 ksi tensile requirements?
20 MR. COLLINS: I, Chairman, I don't know 21 that specifically off the top of my head. But I've 22 heard no issues with regards to design. I will take 23 a follow-up after this.
24 (Simultaneous speaking) 25 MR. CARLEY: I can answer that question.
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29 1 CHAIRMAN SKILLMAN: Go ahead, Ed.
2 MR. CARLEY: We do have one stud that we 3 are tracking that does not meet that requirement. I 4 cannot tell you if that stud is currently installed 5 or not. But we do have an action item to remove that 6 stud prior to PEO.
7 CHAIRMAN SKILLMAN: I saw that. Okay.
8 Thank you. That's sufficient. Michael, you don't 9 have to follow-up. I made my point.
10 MR. COLLINS: Understood.
11 CHAIRMAN SKILLMAN: Divider plate.
12 Divider state in your steam generator inspections.
13 What's the status?
14 MR. GIL: So, the divider plate 15 inspections, we perform a visual inspection of that 16 divider plant every time we go in and do a primary side 17 steam generator inspection.
18 We have completed the evaluations through 19 the EPRI work that was done. And that work envelopes 20 the conditions in our steam generators. So, basically 21 our commitment going forward is to perform the visual 22 inspections.
23 And that, of course, is not, we're not 24 waiting for a period of extended operation for that.
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30 1 primary side of the steam generators.
2 CHAIRMAN SKILLMAN: Rudy, what is the 3 frequency of inspecting on primary, on the steam 4 generator?
5 MR. GIL: The allowed, from a technical 6 specification standpoint, is the, basically every other 7 outage would be the maximum allowed for our steam 8 generators.
9 CHAIRMAN SKILLMAN: Okay. Thank you.
10 All right. One or two more. Spent fuel pool leakage.
11 You made two commitment in 67 and 68. Those 12 commitments were completed.
13 And that basically involved assessing the 14 concrete. And I'm just curious, how can assessing the 15 concrete assure no further leakage of the pool? How 16 do you confirm your pool is not leaking?
17 MR. COLLINS: That's done routinely with 18 the telltale drains. And the chemistry samples that 19 water on a routine basis, to make sure we don't have 20 any spent fuel pool water exiting the pool itself.
21 CHAIRMAN SKILLMAN: Fair enough. Okay.
22 This question has to do with the TLAA, time limit aging 23 analysis, on the hot leg surge nozzle, and the hot leg.
24 And you might, if you understand the acronyms, HLSN, 25 and the PSL.
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31 1 So, it's the hot leg, and it's the nozzle.
2 And it is the question about the cumulative usage 3 factor for that nozzle. And my question is, what's 4 the status?
5 MR. COLLINS: I'll turn it over to Dave 6 --
7 CHAIRMAN SKILLMAN: I'd be glad to take 8 a follow-up on this one.
9 MR. COLLINS: Dave Gerber. Actually, 10 Dave Gerber can come up to the microphone, he'll answer 11 that question for you, sir.
12 MR. GERBER: Hello. I'm Dave Gerber from 13 Structural Integrity Associates. And I've worked on 14 this TLAA. The hot leg surge nozzle we've determined 15 is the critical location for cumulative usage factor.
16 And we've done several analyses. Some, 17 one more refined than the other. And we've discovered 18 that the, well, the CUF itself is below one.
19 CHAIRMAN SKILLMAN: It's currently below 20 one, projected to potentially be higher than one.
21 MR. GERBER: The CUF is designed for, is 22 analyzed to be below one at 60 years. The CUREN, on 23 the other hand, is going to exceed one at the current 24 analysis. And more refined analysis is committed to 25 there.
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32 1 CHAIRMAN SKILLMAN: Dave, thank you for 2 your input. When will the additional analysis be 3 provided to NextEra?
4 MR. GERBER: We have not been engaged to 5 do that yet. But it, the commitment, 44, I believe 6 it is 44.
7 CHAIRMAN SKILLMAN: Yes. I apologize if 8 that sounded like a commercial move. That isn't --
9 MR. GERBER: Yes.
10 CHAIRMAN SKILLMAN: -- what I was trying 11 to communicate. My real question is, what's the CUF 12 going into the PEO? And what is the assurance that 13 NextEra has that this nozzle is either good to go for 14 20, or it can be monitored progressively to ensure that 15 it stays where it should be, in terms of CUF?
16 MR. GERBER: The CUF is already been 17 evaluated. This is the non environmental CUF, which 18 is what is required --
19 CHAIRMAN SKILLMAN: Okay.
20 MR. GERBER: -- prior to PEO. That is 21 already been determined to be below one for --
22 CHAIRMAN SKILLMAN: For the --
23 MR. GERBER: -- 60 years.
24 CHAIRMAN SKILLMAN: -- plus 60? For the 25 plus 20?
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33 1 MR. GERBER: Yes.
2 CHAIRMAN SKILLMAN: Okay. That's 3 silence. That's enough. Thank you.
4 MR. GERBER: All right. Thank you.
5 CHAIRMAN SKILLMAN: It's on the record.
6 MR. GERBER: Thanks.
7 CHAIRMAN SKILLMAN: Thank you for your 8 patience with my questions. Let me ask my colleagues.
9 I know that a number of my colleagues were going through 10 detailed technical issues. Let me see if they might 11 wish to ask a question at this point in the meeting.
12 We have time. Colleagues, anybody have any technical 13 comments for the NextEra team?
14 DR. SCHULTZ: Dick, I have a general 15 question related to the equipment, and the commitments.
16 It probably is good to ask it here. And it's really, 17 the general question is, there are, as you said earlier, 18 Nik, 91 commitments that are part of the program at 19 this time.
20 And as one goes through those commitments, 21 at least it seems to me that there are several specific, 22 and some general areas where one might -- Well, let 23 me back up. There's only a few of the commitments that 24 are marked completed. The remain, most of the 25 remainder of the commitments are marked, will implement NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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34 1 this prior to 2030.
2 There are some of the commitments that seem 3 to me to be ones that I would have put into the Corrective 4 Action Program for, not necessarily immediate 5 attention, but certainly to get them into the Seabrook 6 program sooner than in the next ten years.
7 Just one example is, there's several 8 commitments associated with the fire water system.
9 And the guidance that is driving that is more than five 10 years old. Your program plan associated with license 11 renewal is more than five years old.
12 It would seem to me that some of the 13 commitments that you have to implement later on could 14 certainly have been implemented either prior to today, 15 or should be implemented soon, sooner than in the next 16 ten years.
17 Because they're, it seems to me they're 18 fundamental improvements that you know well, and would 19 in fact be program improvements that have been 20 recognized in the industry. And certainly have been 21 implemented at sites where their license renewal 22 program is already in play.
23 So, the general question is, and maybe 24 we'll get to this later in the presentation. But in 25 these areas is your implementation program really that NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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35 1 you're going to hold on all of these commitments until 2 2029? Or do you have a plan that's active, and 3 connected into your Corrective Action Program today?
4 MR. CARLEY: So, in that regard all of 5 those enhancements, program enhancements have been 6 entered into the Corrected Action Program. Many have 7 been incorporated into the programs.
8 We have not officially called them closed 9 in the commitment list because we have not done the 10 validation that all the exceptions and enhancements 11 for each individual program have been implemented.
12 So, we are actively tracking those.
13 We are actively still engaged in making 14 those changes in the program proactively at this point 15 in time. Of those 91 commitments we do consider ten 16 of those closed, eight of which we've formally 17 communicated to the staff. We have two that are 18 recently been identified that could be closed.
19 There are 56 that are program enhancements, 20 as you had talked about. None of those are officially 21 closed. But as you said, many of them have been 22 implemented into the programs. And as we go through 23 the implementation project plan we will validate that 24 the documentation is in place that would officially 25 close those.
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36 1 DR. SCHULTZ: Thank you. Appreciate the 2 status.
3 CHAIRMAN SKILLMAN: Please proceed.
4 MR. COLLINS: At this point I'm at the end 5 of my discussion. I'm sorry. Apologize. At this 6 point I'll turn the program over to Ed Carley.
7 MEMBER BALLINGER: I have another 8 question. I've been paging through things here. The 9 nozzle that's, the subject nozzle with the fatigue usage 10 factor that Dick Skillman mentioned --
11 CHAIRMAN SKILLMAN: That's the hot leg 12 surge nozzle.
13 MEMBER BALLINGER: It's the hot leg surge 14 line. Has that had mechanical stress improvement?
15 Because one of the slides says mechanical stress 16 improvement process completed on all reactor vessel 17 nozzles. Is that one of them? Okay. So, that one 18 has had a mechanical stress improvement?
19 MR. CARLEY: Yes. So, the one that is 20 identified in the application originally with the flaw 21 was the first one that was done. And then, NextEra 22 proactively, at a later outage, did the remaining seven.
23 MEMBER BALLINGER: Okay. So, the answer 24 to that question is yes, right?
25 MR. CARLEY: Correct.
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37 1 MEMBER BALLINGER: That's --
2 MEMBER RICCARDELLA: Let me --
3 MEMBER BALLINGER: -- what I'm trying to 4 get at. What's the answer to the question?
5 MEMBER RICCARDELLA: Let me, I think we 6 have a miscommunication. You're talking reactor 7 vessel --
8 MEMBER BALLINGER: Yes. The specific 9 nozzle --
10 MEMBER RICCARDELLA: Now --
11 MEMBER BALLINGER: I'm sorry.
12 MEMBER RICCARDELLA: And the question had 13 to do with hot leg surge nozzle.
14 MEMBER BALLINGER: Hot leg surge nozzle.
15 MR. GIL: Yes. So, the hot leg surge 16 nozzle. What I'd like to do is have Scott Boggs, from 17 our programs group. And he can specifically answer 18 that question.
19 MR. BOGGS: Good morning. My name's Scott 20 Boggs. I work in the Fleet Programs Engineering Group.
21 I have been doing that for 32 years. I work in reactor 22 vessel integrity, alloy 600, and material degradation 23 programs.
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38 1 vessel inlet and outlet nozzles, all eight of those 2 nozzles. The hot leg surge nozzle that you're asking 3 about is a stainless to stainless --
4 MEMBER RICCARDELLA: Okay.
5 MR. BOGGS: -- connection. No MSI, or 6 mechanical stress improvement has been performed on 7 that nozzle.
8 MEMBER RICCARDELLA: Okay. Thank you.
9 CHAIRMAN SKILLMAN: Ed, go ahead. Thank 10 you.
11 MR. CARLEY: Good morning. I'm Edward 12 Carley. I'm the license renewal supervisor at NextEra 13 Seabrook. I'm a 35 year veteran of Seabrook Station, 14 holding various positions in several organizations, 15 including quality assurance, maintenance, projects, 16 licensing, and engineering.
17 In 2008 I joined the team tasked with 18 developing the Seabrook license renewal application 19 as the time limit and aging analysis and environmental 20 lead.
21 The license renewal application was 22 prepared onsite by Seabrook Station personnel. The 23 project team included a number of long time site 24 employees, like myself, having system engineering, 25 design engineering, and license operating experience NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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39 1 at the plant, and who were familiar with the plant 2 history.
3 Contractors experienced in license renewal 4 all met with the project staff, along with a number 5 of retirees familiar with the history and construction 6 of the station. The application was prepared utilizing 7 the guidance of the standard review plan, NEI-95-10 8 and NUREG-1801, commonly referred to as the GALL.
9 NextEra corporate fleet support the 10 project with experienced people, and provided our 11 oversight. Members of the benchmarked sites to gain 12 from their experience, both in preparing the license 13 renewal application and writing this for 14 implementation.
15 Our technical leads participated in, and 16 hosted industry working groups, meetings at Seabrook 17 Station. Quality assurance audits were conducted 18 during the course of the project to confirm we were 19 following the defined processes.
20 Industry peers reviewed both our technical 21 reports, and assembled the application to assure we 22 were aligned with current standards. A review of GALL 23 Rev 2 was performed, and changes made to the LRA where 24 appropriate.
25 Since submittal of the application more NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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40 1 than 62 supplements, and eight annual updates were 2 provided to address staff REIs and proactive changes 3 related to the application, and to address deltas from 4 GALL Rev 1, and the issuance of interim staff guidance 5 documents.
6 Next slide, please. The first phase in 7 the development of the station's license renewal 8 application was the scoping and screening of components 9 subject to aging management review.
10 Utilizing the extent of design and 11 component records of the site scoping was performed 12 to the criteria of 10 C.F.R. 54(a)(i) for safety related 13 structure and system components, (a)(ii) for 14 non-safety-related structure system components 15 affecting safety-related functions, and (a)(iii) for 16 regulated events related to environmental 17 qualification, station blackout, pressurized thermal 18 shock, and anticipated transients without scram.
19 Next slide, please. Seabrook also 20 addressed analysis that were time limited, once again 21 utilizing Seabrook's comprehensive searchable records 22 on our licensing basis. Key word searches were 23 performed on this to ensure we identified any potential 24 TLAAs.
25 We also reviewed design calculations and NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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41 1 other plant submittals, interviewed site engineers.
2 Seabrook also benchmarked TLAAs against 19 other 3 applications. Overall, Seabrook looked at 69 4 potential TLAAs in this application by review of recent 5 PWR and common architect engineer submittals.
6 In regards to neutron fluence, fluence for 7 the vessel shells and welds was determined for 60 years 8 of operation. We evaluated and identified materials 9 in the extended beltline.
10 The upper shelf energy was determined to 11 exceed the minimum accepted limit of 50 foot pounds.
12 The lowest was identified as 59.5 foot pounds. For 13 pressurized thermal shock limits were below the 14 allowable screening criteria, with the highest level 15 being 123.3 degrees Fahrenheit.
16 Next slide, please. Okay. The list 17 represents consistency with the GALL Revision 2, as 18 finally documented in the safety evaluation report.
19 As shown here, Seabrook has had 20 existing programs, 20 and 15 new programs. We do have six slight, six plant 21 specific programs, as listed here, two of which we 22 discussed back on October 31st for ASR and building 23 deformation.
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42 1 ago, Seabrook has developed a project plan for 2 implementation, and has comprehensive fleet level 3 processes and procedure for AMP implementation, and 4 managing the aging effects up to and through the period 5 of extended operation.
6 Next slide, please. As discussed, the SER 7 was issued September 28th, 2018. The current SER has 8 no open items, and no confirmatory items. The next 9 few slides I'll just give a high level overview of how 10 we closed the original open items from the SER in 2012.
11 CHAIRMAN SKILLMAN: Before you do that let 12 me --
13 MR. CARLEY: Certainly.
14 CHAIRMAN SKILLMAN: I was going to ask this 15 question to the staff. But in a prior slide you kind 16 of tripped my switch. So, let me ask this question, 17 and it might come back to Michael.
18 This has to do with A1 and A2 structures.
19 Intake transition structure. Now, this plant has an 20 engineering marvel. You have your intake tunnels that 21 go deep into the Atlantic Ocean. They go out quite 22 a ways.
23 But there's an intake transition 24 structure. This non seismic Category 1 structure 25 provides seawater to the service water pump house, and NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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43 1 the circulating water pump house from the Atlantic Ocean 2 and intake tunnel.
3 In addition, it serves as a surge chamber.
4 It stabilizes changing water levels. So, it's not 5 Seismic 1. What role does this have in your ultimate 6 heat sink?
7 MR. COLLINS: We assume that with regards 8 to everyday operation of the station, certainly 9 circulating water and service water goes through that 10 structure.
11 If we were to have a seismic even that did 12 in fact fail our tunnels coming in from the ocean, then 13 we'd rely solely on our safety related seismic 14 mechanical force draft cooling tower, our standby 15 cooling tower, as we know it at the station.
16 CHAIRMAN SKILLMAN: Thank you. Thank 17 you. Okay.
18 MR. CARLEY: Okay. The first item related 19 to our steam generator tube integrity program. In the 20 original license renewal application operating 21 experienced the potential for degradation of the steam 22 generator tube to tube sheet welds that could impact 23 the program for adequately managing aging effects 24 during the period of extended operation.
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44 1 result of the concern the management of the degradation 2 of those welds was unclear.
3 In addition, the staff requested NextEra 4 address foreign operating experience, and where primary 5 water stress corrosion and cracking have been 6 identified in steam generator divider plate assemblies 7 made with alloy 600.
8 NextEra submitted license amendment 9 request, Amendment 131 for Seabrook, which provided 10 permanent application of the steam generator tube 11 alternate repair criteria.
12 In addition, Seabrook submitted a response 13 to the, excuse me, a supplement to the license renewal 14 application, which incorporated recurring inspections 15 of the divider plate assembly in the steam generating 16 AMP, in accordance with the inspection guidelines of 17 ISG-2016.01.
18 MEMBER BALLINGER: I should probably 19 remember this. But how are the tubes inserted into 20 the tube sheet? How are they, are they rolled? Are 21 they hydraulically expanded? How are they put in 22 there?
23 MR. GIL: Rudy Gill, with NextEra Energy.
24 I don't have those specifics. Kester Thompson, who's 25 our steam generator program owner, will come up to the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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45 1 podium and address that question.
2 MR. THOMPSON: Good morning. My name is 3 Kester Thompson. I'm the steam generator program 4 owner. And I'm also the aging management program owner 5 for steam generators for Seabrook Station, and for the 6 fleet.
7 With regards to how the tubes are placed 8 in the tubes, they are hydraulically expanded.
9 MEMBER BALLINGER: Hydraulically 10 expanded?
11 MR. THOMPSON: Yes.
12 MEMBER BALLINGER: Thank you.
13 MEMBER RICCARDELLA: They meet the 14 criteria? Excuse me. While you're still there. And 15 they do meet all the criteria associated with the 16 alternate repair criteria, in terms of --
17 MR. THOMPSON: Yes. With regards to 18 alternate repair criteria, or H_STAR, yes.
19 MEMBER RICCARDELLA: Thank you.
20 MR. CARLEY: Next slide, please. In 21 regards to the pressure temperature limits. At the 22 time of the application NextEra had submitted a license 23 amendment request in accordance with 10 C.F.R. Part 24 50, Appendix Golf.
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46 1 temperature limits did not consider ferritic 2 non-beltline materials in the reactor vessel.
3 Since this open item was issued NextEra 4 has addressed the staff's concerns with two separate 5 license amendment requests, which address the 6 non-beltline materials.
7 The latest license amendment request, 8 Amendment 151, approved P-T limits consistent with 9 Appendix Golf for 10 C.F.R. 50, for 55 effective years, 10 which covers the period of extended operation.
11 MEMBER RICCARDELLA: Just for my, just out 12 of curiosity, you mentioned 123 degree is the maximum 13 end of life. But is that in a beltline region, or 14 non-beltline?
15 MR. GIL: Rudy Gil. NextEra Energy. I 16 will have Scott Boggs, who is our program owner, come 17 to the podium to answer that question. Thank you.
18 MR. BOGGS: Scott Boggs, again. Yes, that 19 is in a beltline. It's a limiting plate material.
20 MEMBER RICCARDELLA: Okay. So, the 21 extension to non-beltline materials was not --
22 MR. BOGGS: We prepared a nozzle beltline, 23 or nozzle extended beltline curves, and demonstrated 24 that they were to the left and above the P-T limit 25 curves. So, they were non limiting.
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47 1 MEMBER RICCARDELLA: Thank you.
2 MR. CARLEY: Okay.
3 CHAIRMAN SKILLMAN: I think we're on Slide 4 18. There you go.
5 MR. CARLEY: Yes. Next slide, please.
6 Thank you. In relation to the open item related to 7 treated borated water, GALL Revision 1 and 2 did not 8 recommend one-time inspections to detect potential 9 degradation in the stainless steel components exposed 10 to treated borated water, because it was believed that 11 boron would mitigate potential aging effects for 12 stainless steel components.
13 Post submittal of the Seabrook license 14 renewal application the staff issued ISG 2011-01, aging 15 management of stainless steel structures and components 16 in treated borated water, and opened the associated 17 open item to address the staff's concern that the 18 original basis stated in the GALL was inadequately 19 supported.
20 NextEra evaluated the changes recommended 21 in the ISG, and revised its associated items requiring 22 aging management review to include a one-time 23 inspection to detect potential loss of material, 24 cracking, or reduction of heat transfer for stainless 25 steel components exposed to treated borated water.
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48 1 Next slide. Next item was related to the 2 bolting integrity program. After the submittal of the 3 Seabrook license renewal application a seal cap 4 enclosure was installed on a safety injection check 5 valve during a mid-cycle forced outage, due to system 6 leakage from the valve.
7 The open item addressed that once a seal 8 cap enclosure is installed the bolting component 9 external surfaces within the enclosure are no longer 10 visible for direct inspection.
11 At the time Seabrook had one seal cap 12 enclosure that was used to surround a pressure retaining 13 bolts of a check valve, to encapsulate the water 14 leakage.
15 To resolve the open item Seabrook removed 16 the seal cap enclosure in 2012, and performed a 17 replacement of the valve to address system leakage.
18 Removal of the seal cap's enclosure restored the 19 original configuration.
20 With the removal of the seal cap enclosure 21 the existing aging management program is sufficient 22 to age manage the bolting and components of external 23 surfaces.
24 CHAIRMAN SKILLMAN: And was that the 25 single and only instance where this action was taken?
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49 1 MR. CARLEY: Yes. It was the only seal 2 cap enclosure we had installed.
3 CHAIRMAN SKILLMAN: Thank you.
4 MEMBER KIRCHNER: Just for the record, Ed.
5 So, you corrected the problem of leakage with the 6 valve?
7 MR. CARLEY: Correct.
8 MEMBER KIRCHNER: Okay.
9 MR. CARLEY: Yes. The valve was cut out 10 and replaced.
11 MEMBER KIRCHNER: Okay. Fine. And the 12 new one doesn't leak?
13 MR. CARLEY: That is correct.
14 CHAIRMAN SKILLMAN: Which valve --
15 MEMBER KIRCHNER: Thank you.
16 CHAIRMAN SKILLMAN: -- was that?
17 MR. CARLEY: It's a safety injection check 18 valve. Next open item to discuss is a open item related 19 to operating experience. The license renewal 20 application did not initially have a detailed 21 discussion of how OE would be used continually to 22 identify aging issues, evaluate them, and as necessary 23 enhance AMPs, or develop new AMPs.
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50 1 review of operating experience. The ISG also provided 2 us a framework to ensure operating experience review 3 activities will adequately address operating 4 experience concerning age related degradation and age 5 management during the term of the renewed license.
6 To resolve this open item Seabrook license 7 application was updated to document program aspects 8 of evaluating aging related OE in accordance with the 9 ISG.
10 CHAIRMAN SKILLMAN: And let me ask this 11 question. It's not intended to be pejorative. But 12 I need to ask it. Within the population of plants in 13 the country there are some that were described as mom 14 and pop operations.
15 Those were plants that were a large 16 distance from their headquarters. And the staffs at 17 those plants, in some cases, made it up as they went 18 along. And they got sorted out in the course of time 19 through a number of tools.
20 But one of the hallmarks of those plants 21 was that they did not adhere, or didn't even pay 22 attention to operating experience. It was as if that 23 was somebody else's problem, and it can't happen here, 24 and certainly not on my watch. Is that what happened 25 here? And if that is what happened, what made it NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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51 1 change?
2 MR. COLLINS: I'd guess I'd ask for a 3 clarification as far as what are you related to as what 4 happened here?
5 CHAIRMAN SKILLMAN: Operating experience.
6 The issue here was that operating experience was not 7 being incorporated. That suggests that perhaps the 8 plant staff was not really alert to what was going on 9 outside. Or if they were, they weren't doing anything 10 with that information. It was as if that's somebody 11 else's problem. That can't happen here.
12 And if you look at the plants that have 13 fallen in the 95-002,95-003, and particularly the ones 14 that went into 0350, not taking into consideration 15 operating experience was a common factor.
16 The folks just weren't keeping track of 17 what else was going out, and going on in the industry.
18 Of if they did know what was going on in the industry 19 they weren't being introspective, asking, can that 20 happen to me too?
21 So, I'm just kind of trying to get a sense 22 of perhaps the change in your site culture between 2012 23 and 2018. And what might have created this open item 24 back in 2012? Because that's where this came from.
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52 1 to clarify that when the open issue was that our AGL 2 application in aging management program did not 3 properly reflect how we were addressing OE. From the 4 station and the fleet we had a very robust operating 5 experience program that's tied to our Corrective Action 6 Program.
7 And it was well implemented, to the point 8 we were probably a little blind to the fact that it 9 wasn't a solid program that was in place for the station, 10 and did not need to be further discussed or repeated 11 in the application. But based on the guidelines of 12 the ISG we did incorporate it.
13 CHAIRMAN SKILLMAN: So, you're saying this 14 was primarily and administrative issue?
15 MR. CARLEY: Yes, I am.
16 CHAIRMAN SKILLMAN: Fair enough. Thank 17 you. Please proceed.
18 MR. CARLEY: Okay. Sorry. Next item is 19 related to the IWE program. This was related to the 20 accumulation of water in the annulus area, and 21 potentially degrading the containment liner.
22 And as we discussed earlier before, to 23 address this item Seabrook performed ultrasonic testing 24 in 2014 of the moist, area above the moisture barrier.
25 Results documented no sign of degradation of the liner.
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53 1 Ultrasonic testing is also scheduled to be performed 2 again in 2021.
3 In addition, a recurring maintenance 4 activity has been established in the site's 5 preventative maintenance program to inspect the annulus 6 area on a weekly basis, to verify it's kept in the 7 dewatered state.
8 Next slide. And just for completeness of 9 the, all of the open items, the last relates to the 10 structure's monitoring program. And this was related 11 to ASR in its aging management program, which was 12 discussed on October 31st.
13 CHAIRMAN SKILLMAN: I would like to ask 14 one question that emerged as I was reading the safety 15 evaluation, and the AMPs, and the application. To what 16 extent will the BDM, the building deformation 17 management program understand differential building 18 movement?
19 I searched on movement. I searched on that 20 word. And my presumption is it's addressed. But I 21 was not able to find it. Can you speak to that for 22 a minute, please? I'm concerned with, concern is not 23 the right word.
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54 1 centimeters, and an adjacent building that has 2 penetrations, or electrical conduit, or piping that 3 might be in shear as a consequence of that differential 4 movement 5 And I was trying to satisfy myself that 6 that was addressed in the text. And I was not able 7 to find that.
8 MR. CARLEY: Okay. So, in regards to a 9 monitoring program for that. We do a, every two year 10 walkdown to determine if there is equipment that has 11 been affected by deformation. And we look for, you 12 know, changes to the seismic gap seal, misaligned 13 piping, flex conduits, which we had shown in the 14 pictures, all of which are indications.
15 Also too, each building has gone through 16 a very comprehensive susceptibility evaluation, which 17 identifies the areas that we should be monitoring from 18 a structural standpoint, which are the most susceptible 19 to review, to movement that we should concentrate on.
20 But there is also just a overall walkdown that's 21 performed every two years.
22 CHAIRMAN SKILLMAN: Okay. Thank you.
23 MR. CARLEY: On that, I'll turn the slide 24 back over to Mr. Browne for concluding remarks.
25 PARTICIPANT: Mike Collins.
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55 1 MR. CARLEY: Oh, Mike Collins. Okay.
2 Sorry.
3 MR. COLLINS: With regards to concluding 4 remarks, Seabrook is committed to continuous material 5 and equipment reliability improvement in long term 6 operation of the unit.
7 Seabrook will manage the effects of aging 8 in accordance with 10 C.F.R. 54.21(a)(i). Seabrook 9 has evaluated time limited aging analysis that require 10 evaluation under 10 C.F.R. 54.218.
11 In closing, NextEra Energy Seabrook has 12 demonstrated compliance with the requirement of 10 13 C.F.R. 54 for issuance of a renewed license for Seabrook 14 Station, Unit 1. Thank you for your time this morning.
15 CHAIRMAN SKILLMAN: NextEra team, thank 16 you very much. Colleagues, do you have any questions 17 for the NextEra team, before we change out to the NRC 18 team?
19 MEMBER KIRCHNER: Dick, I have one.
20 CHAIRMAN SKILLMAN: Yes, sir. Go ahead, 21 Walt.
22 MEMBER KIRCHNER: It's a follow on to 23 Steve's question. When I look at the license renewal 24 commitment list there are quite a few significant 25 activities completed. And then there are a number of NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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56 1 items that to me maybe it ties back to operational 2 matters that --
3 Let me pick one, so that I can focus my 4 question. It was the, let's see, just bear with me 5 a moment. A little bit further down. It had to do 6 with the diesel generators and the air, auxiliary air 7 system and compressors.
8 It's eluding me. Here it is, 61, 9 compressed air monitoring program. I was surprised 10 to see this on the list. I just would expect you would 11 be doing this anyway. This one refers to, replace 12 flexible hoses associated with diesel generator air 13 compressors on a frequency of every ten years.
14 I would just expect that that would be an 15 ongoing operating maintenance issue, not a license 16 renewal issue, per se. I'm thinking of my own vehicles, 17 and such, where you, that frequency you start worrying 18 about whether your radiator hoses and such are holding 19 up.
20 So, it's an observation. It's not a 21 criticism. It just strikes me though, something like 22 that is what you would expect in the normal operation 23 in the plant, and not to be flagged at the same level 24 as, I'll pick something, reactor vessel integrity 25 program. So, just an observation.
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57 1 MR. COLLINS: With regards to that, you 2 are correct. On a daily basis our monthly operability 3 runs of the engines. I don't know the specific, why 4 we specifically committed to that.
5 But to answer your question is, again, 6 monthly surveillances of the engines. Our air 7 receivers need to be at a certain pressure in order 8 to roll the engine. Those are maintained. Operators 9 watch that pressure. So the answer to your question 10 is, yes, we do watch those on a daily basis.
11 MEMBER KIRCHNER: Thank you.
12 CHAIRMAN SKILLMAN: Walt, I appreciate 13 your reason and comment. But I want to challenge the 14 idea that there are some things that are important, 15 and some that are not important.
16 MEMBER KIRCHNER: No. I didn't want to 17 imply that at all.
18 CHAIRMAN SKILLMAN: I look at this and I 19 see 4160. I see ECCS emergency core cooling electrical 20 power. So, this is as important as anything in the 21 plant. This is very important.
22 MEMBER KIRCHNER: Yes. Okay.
23 Inversely, that's my point.
24 CHAIRMAN SKILLMAN: Fair enough. Okay.
25 Thank you, Walt. Colleagues, any other questions?
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58 1 Roland? Charlie? They replaced a whole bunch of 2 electrical stuff. No watch dog timers, in other words?
3 MEMBER BROWN: It's a standard combination 4 of logic solid state stuff, not microprocessor based.
5 So, it's kind of like the old stuff mimicking it, doing 6 the same thing.
7 CHAIRMAN SKILLMAN: Okay.
8 MEMBER BROWN: At least based on my 9 understanding.
10 CHAIRMAN SKILLMAN: Thanks, Charlie.
11 Matt? Nothing?
12 MEMBER BROWN: Am I wrong? They're just 13 solid state cards, right? There's no microprocessor?
14 That's the flavor I got. Thank you.
15 PARTICIPANT: I was primarily interested 16 in the materials program. And they look like they've 17 done a good job.
18 CHAIRMAN SKILLMAN: Pete?
19 MEMBER RICCARDELLA: Well, of course my 20 primary of interest are the materials aging and 21 degradation programs. I have to, first I have to recuse 22 myself from any considerations on the fatigue 23 evaluations. But the other program, and I'm going to 24 rely on my colleagues to provide a comprehensive review 25 of those.
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59 1 The other materials aging issues that I've 2 reviewed, PWFCC, RPV, neutron embrittlement, steam 3 generator integrity, and of course on October 31st the 4 ASR program, appear to be well addressed by the 5 applicant's TLAAs and AMPs.
6 CHAIRMAN SKILLMAN: Thank you, Pete.
7 Mike Corradini?
8 MEMBER CORRADINI: I'm fine.
9 CHAIRMAN SKILLMAN: Joy?
10 MEMBER REMPE: No comment.
11 CHAIRMAN SKILLMAN: Walt?
12 MEMBER KIRCHNER: No thank you.
13 CHAIRMAN SKILLMAN: And Steve?
14 DR. SCHULTZ: No further comment. I 15 thought on the operating experience implementation, 16 which in fact goes way back, that item was closed in 17 2012 I believe.
18 I'm interested in getting the staff's 19 perspective on their take on how Seabrook has over the 20 last several years implemented the operating 21 experience, not only from the fleet, but also the 22 national experience.
23 CHAIRMAN SKILLMAN: Steve, thank you.
24 With this pause here I want to thank Eric McCartney 25 and his team, Rudy, Michael, Ed, and Ken. Thank you.
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60 1 You've been thorough. You've answered our questions.
2 We're going to do a team change out, and 3 ask Butch and Eric, or whoever will take the stand for 4 the NRC. If those of you would like to take a five 5 minute bio break, maybe this would be a good time.
6 And we'll start up in just several minutes.
7 (Whereupon, the above-entitled matter went 8 off the record at 9:42 a.m. and resumed at 9:49 a.m.)
9 CHAIRMAN SKILLMAN: Ladies and gentlemen, 10 let's begin. We are back in session. And we turn the 11 podium over to the NRC staff. Butch, go ahead.
12 MR. BURTON: All right. Thank you. Good 13 morning, Chairman Skillman and members of the License 14 Renewal Subcommittee. My name is Butch Burton, and 15 I'm the project manager for the staff safety review 16 of the Seabrook Station, Unit 1 license renewal 17 application.
18 We're here today to discuss the staff's 19 review of the Seabrook license renewal application as 20 documented in the safety evaluation report, or SER, 21 issued on September 28, 2018. Joining me here today 22 at the table are Dr. Allen Hiser, senior technical 23 advisor in NRR's Division of Materials and License 24 Renewal, and Mr. Niklas Floyd, senior reactor inspector 25 from Region I.
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61 1 In addition, we have a number of technical 2 staff in the audience and on the phone who were involved 3 in the resolution of the open items that we'll be 4 discussing later today.
5 In addition, we pulled together many of 6 the staff who were involved in the review beyond the 7 resolution of the open items. And I will note, it being 8 back in the 2010/2011 timeframe, there are a number 9 of staff who are no longer here. And I hope to think 10 that it wasn't because of the review. But we do have 11 people, hopefully, that can answer any questions that 12 you may have beyond the open items.
13 I'll begin the presentation with a general 14 overview of the staff's review. Nik will then present 15 the 71002 license renewal inspection results. I'll 16 then present the main sections of the staff's safety 17 evaluation report and the staff's resolution of the 18 remaining open items.
19 On May 25th, 2010, NextEra Energy Seabrook 20 submitted an application for renewal of the Seabrook 21 operating license for an additional 20 years, or until 22 March 15th, 2050. For the review of the Seabrook 23 license renewal application, the following audits and 24 inspections were conducted onsite.
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62 1 conducted an audit to review the applicant's 2 administrative controls governing the scoping and 3 screening methodology and the technical basis for the 4 scoping and screening results. The staff documented 5 the scoping and screening methodology audit in a report 6 dated February 4th, 2011.
7 Second, during two weeks in October 2010, 8 the staff audited the applicant's aging management 9 programs, or AMPs, and related documentation to verify 10 the applicant's claim that the programs were consistent 11 with those described in the NRC's generic aging lessons 12 learned, or GALL report, and, considering any 13 enhancements or exceptions to the AMPs, whether the 14 programs were adequate to manage aging during the period 15 of extended operation.
16 The staff considered plant conditions and 17 operating experience during the audits and documented 18 the results in a report dated March 21st, 2011.
19 Third, during the three weeks in March and 20 April 2011, Region I inspectors conducted a 71002 21 inspection in support of the review of the Seabrook 22 license renewal application and documented the results 23 in a report dated May 23rd, 2011.
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63 1 on aging management programs for concrete structures 2 affected by alkali-silica reaction, known as ASR.
3 Region I documented the results of this focused 4 inspection in a report dated August 10th, 2018. And 5 this issue was discussed with the subcommittee at its 6 October 31st meeting.
7 In June 2012, the staff issued a safety 8 evaluation report for the Seabrook license renewal 9 application with seven open items which are listed on 10 this slide.
11 In September 2018, the staff issued a 12 second safety evaluation report which resolved the 13 seven open items. Today, we'll discuss the staff's 14 resolution of the first six of these seven open items.
15 The staff's resolution of the seventh open item was 16 discussed previously with the subcommittee at its 17 October 31st meeting.
18 I'll now turn the presentation over to Nik 19 Floyd.
20 MR. FLOYD: Thanks, Butch. Good morning, 21 everyone. My name is Nik Floyd. I am the senior 22 reactor inspector from Region I office. My branch is 23 the one responsible for performing license renewal 24 inspections. The 71002 license renewal inspection 25 reviews the scoping and screening of components for NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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64 1 10 CFR 54.4(a)(2).
2 For Seabrook, this inspection involved a 3 team of four experienced regional inspectors with 4 expertise in civil, electrical, nuclear, and mechanical 5 engineering that was onsite for three weeks. Among 6 other things, this team reviewed ten of the 13 new aging 7 management programs and nine of the 29 existing aging 8 management programs.
9 The team also walked down numerous 10 accessible systems, structures, and components, or 11 SSEs, to assess the adequacy of the applicant's license 12 renewal application boundaries, materials condition, 13 and conformance with the application and the GALL 14 report.
15 Next slide please. During the course of 16 the inspection, the team made several observations.
17 I'll cover a few of them. This pertains to the 2011 18 inspection. Overall, the walk-downs, the team 19 determined the material condition of the facility was 20 good with the exception of the below-grade areas such 21 as in the residual heat removal vaults.
22 Based on the team's review of the 23 supporting documents and its walk-downs of the 24 facility, it was apparent that NextEra had allocated 25 resources to enhance the physical plant procedures and NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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65 1 processes.
2 For example, NextEra had embarked on a 3 multi-year program to overhaul the cathodic protection 4 system to bring it into conformity with the GALL 5 guidance in support of the varied piping and tanks 6 inspection program. They upgraded the cathodic 7 protection system to be consistent with the GALL by 8 the time the application was submitted.
9 Another observation, the team identified 10 an issue where the lubricating oil and hydraulic fluids 11 for a particular charging pump were not being tested 12 for water content, despite being water cooled. The 13 applicant issued a condition report to correct this 14 issued and enhance the program to provide the frequency 15 and sample requirements for all pumps.
16 A third observation, the team identified 17 a discrepancy in the original license renewal 18 application regarding the materials used in the 19 firewater piping. The applicant corrected this via 20 a supplement to its license renewal application.
21 Regarding the ASME Section 11, subsection 22 IWL program for containment inspections and the 23 structures monitoring program, the team noted that a 24 technically acceptable training system was not 25 implemented to establish the status of observed cracks NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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66 1 and that the qualification and certification of 2 inspectors and examiners was not explicitly established 3 and documented to ensure the assignment of qualified 4 individuals for the inspections.
5 In response, NextEra enhanced its 6 implementing procedures to include a commitment 7 clarifying the definition of responsible engineer.
8 In addition, the team reviewed photographs 9 of pattern cracking on the primary containment wall 10 in the annulus region. The annulus region appeared 11 to have approximately six feet of water for an extended 12 period of time due to ground water infiltration.
13 NextEra implemented work orders to keep the area drained 14 and committed to maintain the area in a de-watered 15 state.
16 The team also identified that NextEra's 17 program for managing the effects of ASR on concrete 18 structures was incomplete. The resolution of this 19 issue was discussed previously with the subcommittee 20 meeting at its October 31st meeting.
21 Next slide please. In summary, the team 22 concluded that NextEra had performed its license 23 renewal scoping and screening in accordance with the 24 license renewal rule. The team found that the 25 necessary information was easily retrievable, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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67 1 auditable, and consistent with the rule.
2 The team verified that the implementation 3 of existing programs, with the exception of ASR, was 4 effective in managing aging, and that the new and 5 existing programs provided reasonable assurance that 6 aging effects will be managed.
7 The team also verified that NextEra had 8 a process to track the completion of enhancements and 9 developments of new programs.
10 Based on the inspection results, the team 11 determined that the programs in place or planned, as 12 described in NextEra's application, will manage the 13 aging effects and ensure the maintenance of intended 14 safety functions of systems, structures, and components 15 within the scope of the rule.
16 Next slide. The NRC conducted a second 17 71002 license renewal inspection during the week of 18 April 30th, 2018, to determine whether the actions taken 19 by NextEra since the previous 71002 inspection in 2011 20 were adequate to manage the aging and concrete 21 structures affected by ASR.
22 As discussed in detail during the October 23 31st subcommittee meeting, the team determined that 24 there was reasonable assurance that the effects of aging 25 due to ASR will be managed through the period of extended NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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68 1 operation.
2 If there are no further questions, I will 3 turn the presentation back to Butch.
4 DR. SCHULTZ: Nik, I've got one question.
5 And we can talk about it later if that makes more sense.
6 But it again goes back to operating experience. And 7 I'm going to the first inspection in 2011.
8 The conclusion of that inspection was that 9 everything was okay except for ASR issues that were 10 identified. Then we had open items identified a year 11 later associated with operating experience.
12 And my question is wouldn't that have been 13 an issue that would have been identified during 14 inspection? Or was the inspection focused on the 15 technical condition of the plant?
16 Because the conclusion of the 2011 17 inspection, I know this goes back probably before your 18 time, at least in your position, but the conclusion 19 was everything looks good. But in fact, if operating 20 experience wasn't being taken into account with regard 21 to the overall program plan for license renewal, 22 something was missing. And that fact was identified 23 the next year. But can you respond now, and then we 24 can come back to it later on the closure of the open 25 items.
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69 1 MR. FLOYD: I can give you a partial 2 response now. Also with me on the telephone is the 3 senior reactor inspector who conducted that inspection 4 back in 2011.
5 DR. SCHULTZ: Great.
6 MR. FLOYD: So he could probably provide 7 more detailed information on the specific operating 8 experience elements that were inspected per the AMPs.
9 But the inspection in 2011, being the 71002, the 10 primary focus was just on the scoping and screening, 11 and then the AMPs as a whole for managing aging effects.
12 How they incorporated the operating experience, I'll 13 defer to Michael Modes. He's on the telephone.
14 In terms of the current license and what's 15 conducted at the site, we the NRC, specifically the 16 resident inspectors, they review the CAP process every 17 day. And I know you spoke about the license and all, 18 but I'll talk about the process up to and including 19 the second inspection.
20 DR. SCHULTZ: I appreciate getting that 21 on the record.
22 MR. FLOYD: Yes. So the resident 23 inspectors, they review the CAP process every day.
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70 1 implement and to input different sorts of operating 2 experience from the industry, also the NRCs generic 3 communications. And the residents will review that 4 and then basically conduct a review at that time.
5 That's one piece of operating experience.
6 The other part that we look at is if there's 7 any kind of materials failures or even a pump. It 8 doesn't have to be materials, it could be even an active 9 component failure.
10 At that time, what we'll do at the NRC 11 regional office is we'll conduct an inspection, be it 12 a problem identification resolution sample, an 13 operability sample, and we'll look at past performance 14 of the licensee.
15 And one of those aspects is operating 16 experience, was it within their ability to foresee and 17 correct? And part of that's operating experience.
18 Is there anything that they should have had knowledge 19 wise to prevent that failure?
20 So we have performed the review to look 21 at past experience back to the 2010 timeframe. There 22 were no significant issues that I could identify that 23 would indicate a deficiency in the operating experience 24 area, if that answers your question.
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71 1 elements that are available to NextEra, they've 2 indicated that they've got a strong program associated 3 with sharing their fleet experience with the Seabrook 4 Station. In your review, can you validate that that 5 is, in fact, the case?
6 MR. FLOYD: I do. And I have reviewed the 7 operating experience procedure. I can't speak to the 8 specifics of their interaction between the fleet and 9 the site. I know that doesn't answer your question.
10 I'll defer to Dr. Hiser.
11 MR. HISER: This is Allen Hiser, the staff 12 Allen. I think the open item was not so much a perceived 13 efficiency at Seabrook in terms of any of their 14 procedures. It was the fact that we just wanted more 15 information on the docket in their application to 16 describe how they would use future OE, whether it's 17 from the plant, from sister plants within the NextEra 18 fleet, but also industry-wide experience and how that 19 would be back-feed into the aging management programs.
20 So it wasn't a deficiency in their existing 21 program or the current activities that they had. It 22 was more looking forward for the future.
23 DR. SCHULTZ: And what you've just said 24 is that the concern was focused particularly on aging 25 management experience.
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72 1 MR. HISER: Correct.
2 DR. SCHULTZ: And does that include in 3 terms of application as well as, you know, the going 4 forward implementation? In other words, did they look 5 --- was the concern did they look deeply enough at the 6 other applications associated with aging management 7 programs?
8 MR. HISER: Yeah. I think when we get to 9 the slide on this ---
10 DR. SCHULTZ: Go ahead.
11 MR. HISER: -- we also wanted him to 12 address how they had incorporated OE for their existing 13 programs as described in the application but also to 14 ensure that, for new programs, that they accounted for 15 all of the OE that was relevant, both from onsite and 16 from the industry.
17 DR. SCHULTZ: Good, thank you. I'll wait 18 for the rest at the time we talk about that slide later.
19 Thank you.
20 MR. BURTON: All right. We are on Slide 21 9. In the next few slides, I'll present the results 22 of the staff's review of the Seabrook license renewal 23 application as described in the staff safety evaluation 24 report.
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73 1 describes the scoping and screening of systems, 2 structures, and components subject to aging management 3 review, or AMR, during the audit in 2010, the staff 4 review of NextEra scoping and screening methodology, 5 procedures, quality controls applicable to the 6 development of the license renewal application, and 7 training of project personnel.
8 The staff also reviewed the various 9 summaries of the safety related SSEs, non-safety 10 related SSEs affecting safety functions, and SSEs 11 relied upon to perform functions applicable to Seabrook 12 in compliance with the Commission's regulations for 13 fire protection, environmental qualification, station 14 blackout, pressurized thermal shock, and anticipated 15 transients without SCRAM.
16 Based on its review, results from the 17 scoping and screening audit, and additional information 18 provided by NextEra, the staff concludes that the 19 applicant's scoping and screening methodology and its 20 implementation were consistent with the standard review 21 plan, or SRP, for license renewal and the requirements 22 of 10 CFR 54.4(a).
23 Section 3 of the safety evaluation report 24 covers the staff's review of NextEra's AMR items for 25 managing aging in accordance with 10 CFR 54.21(a)(3).
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74 1 Sections 3.1 through 3.6 include the AMR items in each 2 of the general system areas within the scope of license 3 renewal.
4 It should be noted that NextEra prepared 5 its license renewal application in accordance with 6 Revision 1 of the Standard Review Plan and Revision 7 1 of the GALL report which were the guidance documents 8 in place at the time that the license renewal 9 application was developed.
10 However, revisions to these guidance 11 documents were issued in December 2010. As a result, 12 the staff reviewed the Seabrook license renewal 13 application in accordance with the updated Revision 14 2 of the SRP and the GALL report.
15 Where Revision 1 and Revision 2 guidance 16 differed, the staff issued requests for additional 17 information to resolve the differences and complete 18 its review.
19 CHAIRMAN SKILLMAN: Was that done in each 20 and every case where there was a difference?
21 MR. BURTON: Yes, sir, it was.
22 CHAIRMAN SKILLMAN: Thank you, Butch.
23 MR. BURTON: Yes. For a given AMR item, 24 the staff reviewed the item to determine whether it 25 as consistent with the GALL report.
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75 1 If an AMR item was not consistent with 2 Revision 2 of the GALL report, the staff reviewed 3 NextEra's evaluation to determine whether NextEra had 4 demonstrated that the effects of aging will be 5 adequately managed so that there is reasonable 6 assurance that the intended functions will be 7 maintained consistent with the current licensing basis 8 for the period of extended operation, as required by 9 10 CFR 54.21 (a)(3).
10 The license renewal application that was 11 submitted in 2010 described a total of 42 aging 12 management programs, 13 of which were new, and 29 of 13 which were existing.
14 As a result of the staff's review, two 15 additional plant-specific aging management programs, 16 the ASR Monitoring Program and the Building Deformation 17 Program, were developed to address the management of 18 structures affected by ASR for a total of 44 aging 19 management programs.
20 All AMPs, with the exception of the 21 plant-specific AMPs, were evaluated by the staff for 22 consistency with Revision 2 of the GALL report. For 23 the plant-specific AMPs, the staff evaluated them 24 against the program elements defined in Appendix A1 25 of the SRP.
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76 1 I'll now discuss the staff's resolution 2 of the seven open items identified in the 2012 safety 3 evaluation report with the exception of the ASR open 4 item which was discussed at a previous subcommittee 5 meeting.
6 We took the open items somewhat out of 7 order. We wanted to start with operating experience 8 which actually, I think, speaks to some of Dr.
9 Schultz's comments as well as your opening question 10 to NextEra regarding Appendix B and some of those 11 things. And I think this starts to hit on it.
12 Because unlike the other open items which 13 are specific to a specific technical issue or a specific 14 aging management program, this is more generic, applies 15 across a number of aging management programs, and so 16 it was very important that we make sure that this 17 operating experience was being applied and implemented 18 in a consistent way. So we wanted to start resolution 19 of our open items with this one.
20 The first open item had to do with operating 21 experience. Specifically, the staff had found that 22 NextEra had not fully or clearly described in the 23 license renewal application how it will use operating 24 experience to ensure that the aging management programs 25 will remain effective for managing aging effects NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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77 1 throughout the period of extended operation.
2 The SRP notes that operating experience 3 consists of three attributes. Number one, that the 4 AMP should discuss how future plant-specific and 5 industry-wide operating experience will be used to 6 confirm the effectiveness of current AMPs and to 7 determine the need for new AMPs.
8 Number two, AMPs should discuss the 9 operating experience with existing AMPs, including past 10 corrective actions resulting from the program 11 enhancements or additions to show where the existing 12 programs have succeeded or failed at identifying 13 age-related degradation in a timely manner.
14 And number three, that new AMPs should use 15 other relevant plant or industry operating experience 16 to inform the relevance and effectiveness of the new 17 programs and to commit to a review of future experience 18 with the programs to confirm their effectiveness.
19 The staff was concerned that NextEra had 20 not clarified how it would implement actions to monitor 21 operating experience on an ongoing basis or how it would 22 use the information to ensure the continued 23 effectiveness of the AMPs. It was also not clear to 24 the staff whether new AMPs will be developed as needed.
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78 1 additional information requesting that NextEra 2 describe the programmatic activities that will be used 3 to identify and evaluate aging issues and, as needed, 4 enhance existing programs or develop new programs.
5 The staff also issued interim staff 6 guidance, or ISGs, in the form of License Renewal ISG 7 2011-05 regarding the review and use of operating 8 experience.
9 Subsequently, NextEra provided detailed 10 information on how it considers operating experience 11 on an ongoing basis and provided specific information 12 on how the operating experience review activities 13 address issues related to aging. NextEra addressed 14 the key issues identified in the ISG.
15 On the basis of this information, the staff 16 determined that NextEra's programmatic activities for 17 the ongoing review of operating experience were 18 consistent with the SRP and the ISG. Therefore, this 19 open item was closed.
20 DR. SCHULTZ: The open item, at least on 21 your slide, and I don't have a recollection of the dates 22 back in 2011 and '12, but on the earlier slide you 23 indicated that it was the SER in June of 2012 that 24 identified this as an open item.
25 MR. BURTON: Yes.
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79 1 DR. SCHULTZ: Okay. And they sent you 2 this letter in January of that year. So was the staff 3 still --- does that mean the staff was still evaluating 4 the information that NextEra had submitted when the 5 June 2012 SER was issued?
6 MR. BURTON: Well, what ---
7 DR. SCHULTZ: Or do you just want to 8 capture the fact that this was an open item that was 9 addressed by this?
10 MR. BURTON: Yeah, I see Jim Medoff raising 11 his hand in the back to perhaps address your question.
12 DR. SCHULTZ: Thank you. I just -- and 13 then I have a follow-up question.
14 MR. MEDOFF: This is Jim Medoff of the 15 staff. One of the things you have to understand is 16 that this was an application that got put on hold for 17 six, seven years. So the instructions to the staff 18 were that we weren't supposed to do any reviews between 19 2012 and when the review commenced in 2017. We weren't 20 allowed to charge time to it.
21 Because the ASR issue was put in the Part 22 50 space for addressing the issue and then later on 23 bringing it back into aging management when the review 24 got resumed. So anything in between the time that the 25 application got put on hold and the time we resumed NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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80 1 the review of the application, we didn't do any review.
2 So I just want to clear that up for you.
3 MR. BURTON: Well, and I do want to 4 supplement that. One of the things that we are required 5 to do is under -- the applicant is required to submit 6 annual updates to changes in their current licensing 7 bases. So the staff is required to perform those 8 reviews to see how that may have changed any of the 9 insights that they gained from their review.
10 In addition, any guidance such as ISGs that 11 are issued in that intervening timeframe, applicants 12 are also required to go back and consider those and, 13 again, how that may impact in their aging management 14 programs. And the staff looks at that. And that's 15 exactly what happened in this case with the ISG which 16 was issued in 2011.
17 So when the SER with open items was issued 18 in 2012, we were in the process of, as well as next 19 year, were in the process of evaluating against that 20 newly issued ISG. And, you know, sometimes there are 21 timing issues and things like that.
22 But until we got on the record, in-house, 23 their resolution to that ISG, we were working on that.
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81 1 concern.
2 DR. SCHULTZ: Good. And that now reflects 3 on kicking my memory that our last meeting, previous 4 meeting on this application was in the mid-spring of 5 2012.
6 MR. BURTON: Right.
7 DR. SCHULTZ: So that was just before some 8 of this happened, before and after that.
9 So the next question would be, with regard 10 to operating experience and the licensee's explanation, 11 amplification, additional information presented in 12 2011, has the staff then found -- and I presume based 13 upon closure that you have -- that they have 14 demonstrated follow through on their overall program 15 to incorporate the operating experience in their 16 submittal?
17 MR. FLOYD: So as far as ongoing 18 implementation, right now, because they're not into 19 the period of extended operation, they'll manage the 20 operating experience to the Part 50, the current 21 license. And they'll do that kind of through some of 22 the processes that I explained earlier.
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82 1 own programs and procedures, not to open up the door 2 to ASR again, but one of the areas that we saw operating 3 experience and how it applies to aging management was 4 through their testing program and onsite monitoring.
5 As new issues came up, that fed back into 6 their existing programs and whether or not those were 7 adequate to manage aging effects. And as a result, 8 they enhanced the programs and, in fact, created two 9 new plant-specific programs. So that's just one 10 example of them implementing the operating experience 11 process.
12 But as far as ongoing monitoring and 13 implementation operating experience, it'll be through 14 the current license. And that's something that we 15 monitor from the resident inspectors in the regional 16 office. I don't know if that answers your question.
17 DR. SCHULTZ: It does, thank you very much.
18 But the other part of that is our comments earlier 19 about some of the commitments that are made in their 20 submittal which seem to be items that are operational 21 and relatively ready, at the time identified, to be 22 implemented. And they've listed those as commitments 23 to be implemented prior to the license renewal period.
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83 1 ought to have been put in place or should be put in 2 place sooner than later?
3 MR. OESTERLE: Yeah, this is Eric Oesterle 4 from the staff. So those types of commitments, we view 5 those as from the perspective of what is necessary for 6 license renewal, and what is necessary in terms of aging 7 management to ensure that the intended safety functions 8 can be performed during the period of extended 9 operation.
10 And we don't look at it from the perspective 11 of when is it best, from maybe a business case, to 12 implement these programs. We look at it more from the 13 perspective of these programs need to be implemented 14 no later than. And we're not looking at what is the 15 most efficient time for implementing these programs.
16 That's more of an operational issue that gets handled 17 under Part 50.
18 MR. FLOYD: I can add to that. So the 19 aging management programs, for several of them there's 20 already existing plant programs in the current license.
21 So those are programs that are being implemented, in 22 many cases, under the Appendix Bravo quality assurance 23 program. And so they will be inspected and reviewed.
24 Another chance that the staff has at 25 continuing the review would be before they enter, the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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84 1 licensee enters the period of extended operation, in 2 which case we'll conduct a -- it's called a post site 3 approval inspection, the IP 71003 license renewal 4 inspection.
5 And in that case, that occurs approximately 6 one to two years prior to the refueling outage. And 7 we'll go through, and we'll look at that list of 8 commitments and see have they been satisfied or are 9 they planning to satisfy them prior to entering the 10 period of extended operation.
11 And an element to add to that is in the 12 operating experience between pretty much now and then, 13 are they managing the aging effects in accordance with 14 those commitments and those aging management programs?
15 So it's another touch we have on it between the current 16 licensing reviews and then prior to entering the period 17 of extended operation.
18 DR. SCHULTZ: Yeah, thank you. Go ahead, 19 Ron.
20 MEMBER BALLINGER: So I --
21 DR. SCHULTZ: And let me just a comment, 22 because it's directly in response. Perhaps the 23 corrective action program will take care of our concern 24 in this regard. That is, NextEra said that these items 25 were going into their corrective action program.
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85 1 I presume that the corrective action item 2 is going to have those things that are, in fact, ripe 3 for implementation now, done sooner than later.
4 Because most licensees don't like a lot of things piling 5 up in their corrective action program. They like to 6 get them done.
7 MR. FLOYD: That would be correct.
8 MEMBER BALLINGER: So maybe I'm misreading 9 this table then. If you look at Item Number 90, which 10 is the last one, easy to find, "Implement the PWR 11 internals program. The program will be implemented 12 in accordance with MRP 2278," da-da-da-da-da. It says 13 prior to the period of extended operation.
14 I would be astounded if it wasn't already 15 implemented.
16 MR. HISER: Actually, that program is 17 really a license renewal program.
18 MEMBER BALLINGER: Yeah.
19 MR. HISER: So it is not necessary that 20 it be implemented today. It really addresses aging 21 issues that are not thought to be applicable until 22 you're beyond 40 years.
23 Things like baffle bolts, things like that, 24 are addressed sort of as special issues by the industry.
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86 1 of its age, its materials, its configuration, it may 2 not be doing any inspections if they're not necessary.
3 MEMBER BALLINGER: I'm confused. But 4 that's just me.
5 MR. FLOYD: Mel Gray, the branch chief from 6 I Branch, wants to give a comment.
7 MR. GRAY: Good morning, Mel Gray out of 8 NRC, Region I. I oversee the in-service inspections 9 and engineering inspections.
10 These commitments, MR -- in vessel 11 commitments, whether it's BWRVIP, that's for boiling 12 water reactors, or MRP, materials or liability 13 programs, PWRs, those are being implemented outside 14 of license renewal. They're off the shelf programs 15 that are either taken as is or enhanced. And so we 16 get, in the region, we get a good look at those 17 implementations as part of every outage.
18 We will select risk-informed samples.
19 Some will be things like baffle bolts. Some will be 20 other internals. So we do get insight on performance 21 well before they may become regulatory requirements 22 under a renewed license. They're still activities we 23 scrutinize closely. So thanks, I just wanted to add 24 that.
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87 1 programs, while covered under aging management license 2 renewal, they are industry mandatory programs. And 3 those are directly inspected by our staff.
4 MEMBER BALLINGER: I guess my only point 5 is why do you have to say that that has to be implemented 6 prior to license -- extended operation if they're 7 already implemented?
8 MR. BURTON: Well, I guess the reason we 9 have to say that because it is a license renewal review, 10 yeah. And I guess I'm going show my age.
11 CHAIRMAN SKILLMAN: Let me get oriented 12 here just for a second. If you look at the --- if I 13 look, when I went and looked at the license renewal 14 application, 2012/2013, and you recognize that there 15 have been 20 updates since then, and the current 16 commitment list is really Appendix A to the license 17 renewal application, so if you go back six years, there 18 were 40 or 42 commitments, and now there're 91.
19 And there are some big, heavy hitters in 20 there that include ASR. But there are other ones that 21 deal with all types of technological changes. And so 22 the commitment list is really the appendix to the 23 license renewal application.
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88 1 out of that find their way into the commitment list.
2 And so they're not exactly the same thing, but they 3 run in parallel, if that's a fair description.
4 MR. BURTON: And I'll just add one thing.
5 And I hate to show my age here, but I was the safety 6 project manager for the Plant Hatch license renewal 7 which was the number three LRA that was submitted in 8 the early 2000s.
9 I was also the safety project manager for 10 the Fort Calhoun license renewal application which was 11 the first plant that actually implemented GALL. So 12 I do have what I would call anecdotal experience that, 13 as we've watched the implementation of some of the 14 commitments of prior applicants, it is very often that 15 those commitments are actually satisfied well before, 16 for the reasons that we've discussed, well before the 17 period of extended operation starts, just as a practical 18 matter.
19 MEMBER BALLINGER: You don't look that 20 old.
21 MR. BURTON: Thank you. Tell my wife 22 that, please.
23 MR. OESTERLE: Yeah, this is Eric Oesterle 24 from the staff. Another way to look at this is that 25 even if there are existing programs in place that the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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89 1 applicant has, they still have to identify, in their 2 license renewal, application those programs that they 3 --- those existing programs that they are taking credit 4 for to comply with the license renewal regulatory 5 requirements.
6 And so that's one of the reasons why we 7 need to see that in the application and why it gets 8 referred to in the commitment table so that there can 9 be an inspection on implementation of that commitment, 10 such that we can demonstrate that it satisfies the 11 license condition that gets included in the renewed 12 license.
13 MR. BURTON: And I'm glad we had this as 14 a conversation. Because, like I said, operating 15 experience is something that applies across the board.
16 And so it is vitally important that we understand that 17 it's being used effectively to identify whether these 18 aging management programs are working the way they were 19 intended, whether they need to be revised and updated, 20 or whether new AMPs need to be implemented.
21 And it's the operating experience, both 22 plant-specific as well as industry-wide, that helps 23 us make that determination. So I know this was kind 24 of a long conversation, but I think it was a good one.
25 And I think it was necessary. Other ---
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90 1 CHAIRMAN SKILLMAN: Let's proceed.
2 MR. BURTON: Okay. Slide 13, bolting 3 integrity program. The second open item had to do with 4 the bolting integrity program. Specifically the NRC 5 staff noted that seal cap enclosures, which are used 6 to encase leaking or potentially leaking valves, can 7 contain water leakage. And therefore, the use of such 8 enclosures should be accounted for in the license 9 renewal application to ensure proper aging management.
10 For example, the environment within seal 11 cap enclosures may be submerged environment rather than 12 the air environment of the original component design.
13 Also, the seal cap enclosures may prevent direct 14 inspection of bolting and component external surfaces.
15 The staff was concerned that NextEra may 16 have used or currently uses seal cap enclosures to 17 contain water leakage and noted that the license renewal 18 application did not contain any AMR items that addressed 19 bolting and external surfaces in the potentially 20 submerged seal cap enclosure environments.
21 It was also unclear to the staff how 22 components within the seal cap enclosures will be age 23 managed since direct inspection is not possible.
24 Furthermore, it was unclear to the staff whether seal 25 cap enclosure configurations will be used during the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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91 1 period of extended operation.
2 In June 2012, NextEra provided additional 3 information to address the staff's concern, including 4 the statement that the single steel cap enclosure in 5 place at Seabrook will be removed.
6 In December 2012, NextEra confirmed that 7 the seal cap enclosure was put in place for one cycle 8 and that the valve was out and replaced at the next 9 outage. The replacement of the valve eliminated the 10 need for the enclosure.
11 On the basis of this information, the staff 12 determined that its concern was addressed, and 13 therefore this open item was closed. And we talked 14 about the earlier today.
15 The third open item had to do with the ASME 16 Code, Section 11, Subsection IWE Program.
17 Specifically, in response to the staff's concerns 18 regarding water accumulation in the containment 19 annulus, NextEra committed to keeping the annulus free 20 of water.
21 However, NRC inspectors noted that the 22 method being used was a portable pump. The staff was 23 concerned that the applicant had not implemented any 24 permanent measures for de-watering or had not revised 25 its procedures for routine inspection of this area to NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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92 1 ensure that the area remained de-watered.
2 By letter dated June 30th, 2015, NextEra 3 confirmed that the on-going de-watering activities have 4 been incorporated into Seabrook's preventive 5 maintenance program to specifically maintain the 6 containment structure in de-watered state. On the 7 basis of this information, the staff determined that 8 its concern was addressed. Therefore, this open item 9 was closed.
10 And I know, to some extent, we're kind of 11 going over old ground, because this was covered by 12 NextEra But this is the staff's perspective.
13 The fourth open item had to do with the 14 steam generator tube integrity program. Specifically, 15 in the license renewal application, operating 16 experience indicated the potential for primary water 17 stress corrosion cracking of the steam generator 18 tube-to-tubesheet welds that could impact the 19 applicant's program for adequately managing aging 20 effects during the period of extended operation. The 21 staff was concerned that the management of the 22 degradation of the welds was unclear.
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93 1 corrosion cracking at least 24 months prior to the 2 period of extended operation.
3 The plant-specific program would either, 4 one, perform a one-time inspection of the 5 tube-to-tubesheet welds or, two, perform an analytical 6 evaluation that redefined the reactor coolant pressure 7 boundary to not include the tube-to-tubesheet welds 8 and have the redefinition approved by the NRC as part 9 of a license amendment request.
10 Subsequently, NextEra requested, and the 11 NRC approved, an amendment to permanently apply steam 12 generator tube alternate repair criteria which allowed 13 the licensee to exclude the tube-to-tubesheet welds 14 from the reactor coolant pressure boundary.
15 This license amendment satisfied the 16 commitment since the tube-to-tubesheet welds were no 17 longer part of the reactor coolant pressure boundary.
18 And therefore, no plant-specific AMP was required.
19 MEMBER KIRCHNER: May I ask you a question 20 at this point? What does that, in practice, mean when 21 you redefine the reactor coolant pressure boundary?
22 Does that impact Chapter 15 analyses as an example?
23 MR. HISER: Oh boy. No, it doesn't. What 24 it basically means is that there's structural and 25 leak-tight integrity of that tube-to-tubesheet joint, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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94 1 if you will, without crediting the weld. So the rolling 2 that was done when the tubes were inserted in the 3 tubesheet, that is sufficient to maintain integrity 4 from both the structural perspective and also from the 5 leak-tightness perspective.
6 MEMBER KIRCHNER: So I get that. I just 7 find the declaration that it's not part of the pressure 8 boundary is rather odd. Let me just say it. I mean, 9 the tubesheet --
10 MR. HISER: Well, clearly they're still 11 there.
12 MEMBER KIRCHNER: It's still there. The 13 tubesheet's still there. If the tubesheet fails, you 14 have a break with our without the weld. So it's still 15 part of the pressure boundary.
16 MR. HISER: Yeah. These welds are just, 17 in effect, seal welds between the tube and the 18 tubesheet. So the fact that they're excluded means 19 that the integrity of the welds themselves are not 20 important.
21 MEMBER KIRCHNER: They're on the secondary 22 side.
23 MR. HISER: Yes.
24 MEMBER KIRCHNER: Right. So you're just 25 saying that ---
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95 1 MR. HISER: No, no, no. They're on the 2 primary side.
3 MEMBER KIRCHNER: Primary side?
4 MR. HISER: Yeah.
5 MEMBER RICCARDELLA: Westinghouse 6 conducted a big program about ten years ago. I was 7 actually part of but the consulting that I monitored.
8 They looked at coefficient friction and the 9 variability of coefficient friction ---
10 MEMBER BLEY: Did he turn on his mic?
11 MEMBER RICCARDELLA: I did, it's on. I'm 12 sorry. The question is what depth do you need this 13 H-STAR number to ensure that the tubes won't pull out 14 even if the welds aren't there. And if you meet that 15 criteria then you have -- you don't need to consider 16 the weld and consider that part of the pressure 17 boundary.
18 MEMBER BALLINGER: Again, those tubes are 19 fully expanded?
20 MEMBER RICCARDELLA: Hydraulically.
21 MEMBER BALLINGER: They're hydraulically, 22 but fully expanded, not partial depth?
23 MEMBER RICCARDELLA: I think that's part 24 of the eight star ---
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96 1 trying to --- it has be full depth?
2 MR. HISER: Well, whatever the analysis 3 criteria were, the plant had to then demonstrate that 4 it met those criteria.
5 MEMBER BALLINGER: Three or four different 6 categories.
7 MR. HISER: That's correct.
8 MEMBER RICCARDELLA: But eight star 9 doesn't necessarily have a full depth of the tubesheet.
10 It's just how much depth you need before the tube 11 collapses.
12 MR. BURTON: Okay. Continuing on, we're 13 on the same slide. Also in December 2010, the staff 14 requested that NextEra address foreign operating 15 experience in steam generators similar to the Seabrook 16 steam generators where primary water stress corrosion 17 cracking had been identified in steam generator divider 18 plate assemblies made with Alloy 600.
19 In January 2011, NextEra confirmed that 20 the Seabrook steam generator divider plate material 21 was Alloy 600 and made a commitment to perform a one-time 22 inspection of the divider plate assembly.
23 Subsequently, the staff issued interim 24 staff guidance which provided additional aging 25 management guidance on primary water stress corrosion NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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97 1 cracking of divider plate assemblies and 2 tube-to-tubesheet welds.
3 In 2017, NextEra submitted a supplement 4 to the license renewal application which incorporated 5 recurring inspections of the divider plate assembly 6 into the steam generator AMP, in accordance with the 7 guidance in the ISG, and removed the commitment, since 8 following the guidance in the ISG made the commitment 9 unnecessary.
10 On the basis of this information, the staff 11 determined that its concerns were addressed, and 12 therefore this open item was closed.
13 MEMBER KIRCHNER: Let me ask a process kind 14 of question. As a result of --- this is similar to 15 the operating experience questions earlier. So there 16 is staff guidance that is out there. If there's another 17 license renewal application, are you confident that 18 the staff guidance for this issue is clear enough that 19 a subsequent applicant can successfully navigate it 20 and not wind up with an open item on this particular 21 issue?
22 MR. HISER: Absolutely. The GALL 23 report, Revision 2, isn't just the book that's bound 24 in blue covers. It includes all the ISG. So there're 25 sort of mini revisions, if you will, of the GALL report.
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98 1 MR. BURTON: Yeah. And I will add, as a 2 process question, generally there is a certain 3 revision of the SRP in GALL that's out on the street.
4 After that, we may issue ISGs, other guidance. But 5 the intent is that at the next revision of the GALL 6 in SRP those will be incorporated.
7 Now, if between now and then an applicant 8 submits a license renewal application, process-wise, 9 one of the things that we do is we have extensive 10 pre-submittal interactions with an applicant. And 11 part of those discussions is to make crystal clear what 12 is it that's going to apply to them in their application, 13 so to include everything in the current revision of 14 the GALL in the SRP plus any additional guidance that's 15 been issued.
16 MR. OESTERLE: Yeah, this is Eric 17 Oesterle. And I will add to that, that when the staff 18 issued guidance for subsequent license renewal 19 applications, that guidance incorporated all of the 20 ISGs that were issued subsequent to issuing Sub Rev 21 2 of the GALL report.
22 And the language in the SRP -- SLR guidance 23 in the GALL SLR report indicates that even applicants 24 for initial license renewal can follow that guidance.
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99 1 new issues that were identified and addressed by the 2 staff in terms of staff guidance documents.
3 MR. BURTON: Okay. Slide 16, the fifth 4 open item had to do with treated borated water.
5 Specifically, one-time inspections of stainless steel 6 components exposed to treated borated water were not 7 required by the NextEra one-time inspection program.
8 This was consistent with both Revisions 9 1 and 2 of the GALL report which did not recommend 10 one-time inspections to detect potential degradation 11 in stainless steel components exposed to treated 12 borated water. Because it was believed at the time 13 that the boron would mitigate potential aging effects 14 for stainless steel components.
15 However, the staff could not identify an 16 adequate basis for this position and determined that 17 the presence of boron, in and of itself, would not 18 prevent degradation. And, as such, a one-time 19 inspection was warranted.
20 The staff issued this determination in an 21 ISG and identified this concern as an open item for 22 Seabrook. In response, NextEra revised its associated 23 AMR items to include a one-time inspection to detect 24 potential loss of material, cracking, or reduction of 25 heat transfer for stainless steel components exposed NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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100 1 to treated borated water.
2 The staff concluded that the addition of 3 the one-time inspections to the NextEra program to 4 detect potential degradation of stainless steel 5 components exposed to treated borated water was 6 consistent with Revision 2 of the GALL report as 7 modified by the ISG. And therefore, the open item was 8 closed.
9 Section 4 of the Safety Evaluation Report 10 identifies Time Limited Aging Analyses, or TLAAs.
11 Section 4.1 documents the staff's evaluation of the 12 applicant's identification of applicable TLAAs.
13 The staff evaluated the applicant's basis 14 for identifying those plant-specific or generic 15 analyses that need to be identified as TLAAs and 16 determined that the applicant had provided an accurate 17 list of TLAAs as required by 10 CFR 5421(c)(1).
18 Sections 4.2 through 4.7 document the staff's review 19 of the applicable TLAAs as shown.
20 Based on its review and the information 21 provided by the applicant, the staff now concludes that 22 either, one, the analyses remained valid for the period 23 of extended operation. Or, two, the analyses had been 24 projected to the end of the period of extended 25 operation. Or, three, the effects of aging on the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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101 1 intended functions will be adequately managed for the 2 period of extended operations, as required by 10 CFR 3 5421(c)(1), sub-paragraphs 1, 2, or 3, respectively.
4 The sixth open item had to do with pressure 5 temperature limits. Specifically, Appendix G of 10 6 CFR Part 50 requires that pressure temperature limits 7 consider all ferritic beltline and non-beltline 8 materials in the reactor vessel.
9 The staff was concerned, however, that the 10 methodology used to calculate the PT limits for 20 11 effective full-power years, or EFPY, in the license 12 renewal application may not have appropriately 13 considered non-beltline materials.
14 In a separate Part 50 licensing action, 15 the applicant requested approval of PT limits that would 16 extend the operating time of the curves from 20 to 23.7 17 EFPY.
18 The applicant addressed the non-beltline 19 materials as part of its license amendment request.
20 The applicant demonstrated that the limiting beltline 21 materials bound the non-beltline materials, and the 22 staff approved the license amendment request to amend 23 the PT limit curves.
24 The approval of the license amendment 25 request addressed the staff's concern and, therefore, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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102 1 this open item was closed.
2 Subsequently, in November 2015, the staff 3 approved a license amendment request to revise the PT 4 limits up to 55 EFPY which NextEra mentioned in its 5 presentation.
6 The staff has reviewed NextEra's responses 7 to the open items identified in the Safety Evaluation 8 Report with open items issued in June 2012 and finds 9 that all of the open items have been satisfactorily 10 resolved and closed.
11 With the closure of the open items, the 12 staff finds that NextEra has met the requirements of 13 10 CFR 5429(a) for the license renewal of Seabrook 14 Station, Unit 1.
15 More specifically, the staff finds that 16 actions have been identified and have been or will be 17 taken at Seabrook Station, Unit 1, such that there is 18 reasonable assurance that the activities authorized 19 by the renewed license will continue to be conducted 20 in accordance with the current licensing basis and that 21 any changes made to the plant's current licensing basis 22 are in accord with the Atomic Energy Act and the 23 Commission's regulations.
24 This concludes the staff's presentation.
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103 1 you may have.
2 CHAIRMAN SKILLMAN: Butch, thank you.
3 Colleagues, any questions for the NRC staff? I do have 4 one, but let me ask my colleagues to go first if they 5 choose to. Anybody? Steve, go ahead.
6 DR. SCHULTZ: Butch, I have a follow-on 7 question. And I just really would like to get something 8 on the record. Because if you read over the commitment 9 list, there is now --- and you mentioned a few ---
10 there's a number of items that are identified as before 11 the period of extended operation, there will be a 12 one-time inspection.
13 Is it just presumed that a one-time 14 inspection has coupled with it an action plan associated 15 with what might be found in that one-time inspection 16 to move forward with a program that would allow 17 operation, if there're some elements identified that 18 need attention?
19 MR. BURTON: Yeah. That's a good 20 question. There's a philosophy behind one-time 21 inspections. When it's generally determined that a 22 one-time inspection would be satisfactory, it's 23 generally because a determination was made, or that 24 was a belief that aging effects would either not occur 25 at all during the period of extended operation or that NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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104 1 they would occur so slowly that they would not impact 2 any safety function. That's the philosophy behind it.
3 But to be sure, there is an opportunity 4 to perform a one-time inspection. Usually it can be 5 implemented by a date certain, or oftentimes these are 6 done at opportune times. Like, if there's some piping 7 being dug up, things like that, they take that 8 opportunity. But that's the philosophy behind it.
9 But there is an understanding that, when 10 you perform that one-time inspection, if the results 11 don't conform with your assumptions that, again, either 12 there is no aging management, or aging effects, or the 13 aging effects are occurring faster than you had 14 anticipated, then part of that is to go back and say, 15 well, perhaps we need to have an ongoing aging 16 management program to address what we're seeing as 17 opposed to a one-time inspection to confirm what we 18 thought was occurring. So that's kind of the 19 philosophy.
20 MR. HISER: And that would be part of the 21 corrective action program.
22 MR. BURTON: Right.
23 MR. HISER: And just to be clear, if they 24 were to find a problem that indicates a potential safety 25 issue was in existence or imminent, then they would NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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105 1 require corrections of that issue immediately.
2 But the prognosis for the potential to 3 implement a new program would be one of the potential 4 consequences coming out of that finding and the 5 corrective action program review.
6 DR. SCHULTZ: Thank you both for your 7 explanations. That helps a lot. Thank you.
8 MR. HISER: Sure.
9 CHAIRMAN SKILLMAN: Let me ask this 10 question. My question focuses on the Nickel Alloy 11 Nozzle and Penetrations Program. So it's a specific 12 question, and it really has to do with text in the safety 13 evaluation. And the text is on Page 3-206, just as 14 a reference.
15 This is the conclusion that the staff wrote 16 relative to the Nickel Alloy Nozzles and Penetrations 17 Program. "On the basis of its technical review, the 18 staff concludes that the applicant demonstrated that, 19 through the use of this AMP, the effects of aging of 20 nickel alloys may be adequately managed so that the 21 indebted functions under consideration will be 22 maintained consistent with the CLB."
23 This is the single and only instance in 24 the whole document where you use the word "may." If 25 you search "may," you'll find maybe and some other words NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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106 1 that contain M-A-Y. But this is the only place where 2 the conclusion uses the word "may" versus the word will.
3 MR. BURTON: Hum, okay.
4 CHAIRMAN SKILLMAN: So I bring that to your 5 attention so that you'll know at least one member of 6 the ACRS used a very thick magnifying glass. And 7 I'm wondering if you may want to consider, at some future 8 revision, changing that word "may" to "will."
9 MR. BURTON: Okay. Yeah, that's noted.
10 I'll go back, and we'll check with the reviewer for 11 that portion if they actually ---
12 CHAIRMAN SKILLMAN: It's odd that the word 13 "may" was used.
14 MR. BURTON: Yeah.
15 CHAIRMAN SKILLMAN: Because it isn't used 16 in this context anywhere else through this very thorough 17 document.
18 MR. BURTON: Yeah.
19 CHAIRMAN SKILLMAN: So it kind of --- at 20 least it popped out at me.
21 MR. BURTON: Yeah. My guess is that we 22 just want to be inconsistent. But I'll follow-up on 23 that and just make sure. And if there is an issue of 24 some kind, you know, we'll ---
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107 1 of all, it's a nit, I acknowledge that. Second of all, 2 why the change in tone? Because the tone has been so 3 consistent through the whole document.
4 MR. BURTON: Yeah.
5 CHAIRMAN SKILLMAN: Will, will, will.
6 And here comes this "may" on a very important AMP.
7 MR. BURTON: Okay. Got it on my to do 8 list.
9 CHAIRMAN SKILLMAN: One more time, 10 colleagues, any other questions for the NRC staff?
11 Before we go to anyone in the room or the 12 public, I would like to ask NextEra one question. And 13 it comes from the discussion that we just had about 14 the steam generator tubes, the reactor coolant system 15 pressure boundary, and the exclusion of the boundary 16 based on the expanding of the tubes of the mandrel.
17 How many tubes are plugged at this plant?
18 Is there someone from NextEra can give us an idea, 19 please? If so, please come to the mic and just tell 20 us what you know, please.
21 MR. GIL: This is Rudy Gil, fleet programs 22 manager for NextEra Energy. Currently, our total 23 number of tubes is 195 tubes. This is less than one 24 percent of the total tubes in our steam generators.
25 CHAIRMAN SKILLMAN: So each generator is NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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108 1 6,000 to 7,000 tubes, a number in that neighborhood, 2 approximately, just to get it in perspective?
3 MR. GIL: Each steam generator has 4 approximately 5,600 tubes.
5 CHAIRMAN SKILLMAN: Approximately 5,600.
6 MEMBER RICCARDELLA: What is the tube 7 material?
8 MR. GIL: It is Alloy 600, thermally 9 treated. Thermally treated Alloy 600.
10 CHAIRMAN SKILLMAN: So out of 11 approximately 12,000 tubes, 11,200 tubes.
12 MR. GIL: We have four steam generators.
13 CHAIRMAN SKILLMAN: Oh.
14 MEMBER BALLINGER: I should add that of 15 those tubes that are plugged most of them were a result 16 of an anomaly in the manufacture of the tubes. So those 17 tubes were not plugged because of an ongoing degradation 18 mechanism that you would expect to have in thermally 19 treated, properly thermally treated Alloy 600 tubing.
20 CHAIRMAN SKILLMAN: Ron, thanks. Rudy, 21 thank you.
22 MEMBER REMPE: Well just, while you're 23 there, Ron sort of answered it, but it sounds like there 24 was a big increase at one point. But now are you seeing 25 an increase during inspections, or is it decreasing NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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109 1 on what you were finding with respect to the tube 2 thickness during the inspections?
3 MR. GIL: Yeah. So, as you said, part of 4 the question was already answered.
5 MEMBER REMPE: Yes.
6 MR. GIL: Probably the, for clarification, 7 the majority of the tubes are plugged because of wear 8 at the two support plates. That again occurred early 9 in the process.
10 We have very little wear that we're dealing 11 with at this point in time which is really what you 12 would expect in the industry with time in these steam 13 generators. So we're really not seeing anything 14 significant. We're plugging very few tubes. Most of 15 them we do preventively, just to make sure that we don't 16 have an issue in the future.
17 MEMBER REMPE: Okay, thank you.
18 CHAIRMAN SKILLMAN: Rudy, thank you. Dr.
19 Bley, Dennis, you're on the line. I don't know how 20 much you've heard, but if you have any questions or 21 comments, I'd sure appreciate it if you would 22 communicate.
23 Hearing none, Theron, would you make sure 24 that the public line is open? It's open.
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110 1 individual in the room that would care to come to the 2 microphone and make a comment, please? If so, you are 3 welcome to do so.
4 Seeing none, thank you. To those who may 5 be listening in and who would like to make a comment, 6 we invite you to simply say hello at this point so that 7 we know you're out there.
8 MS. GILMORE: Hello.
9 CHAIRMAN SKILLMAN: Thank you.
10 MR. HOFFMAN: Hello.
11 MR. BOSSING: Hello.
12 CHAIRMAN SKILLMAN: Well, good morning.
13 And to any of you that answered, or others, if you wish 14 to make a comment, please introduce yourself, and then 15 please make your comment.
16 MS. GILMORE: This is Donna Gilmore. I 17 have a question. These plants were engineered for 40 18 years. And I know there are parts of it that are not 19 inspectable. How do you determine or how do you have 20 confidence that the parts you cannot inspect are going 21 to be acceptable for the re-license period?
22 CHAIRMAN SKILLMAN: We thank you for your 23 comment. Your comment is noted.
24 Would anybody else care to make a comment, 25 please?
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111 1 MR. HOFFMAN: This is Ace Hoffman. And 2 I did not hear anything about what you're going to do 3 about the spent fuel once you've created another couple 4 of million pounds of it over the next 20 years.
5 The interim storage site that's planned 6 for New Mexico, which probably won't ever be built, 7 but at any rate its capacity is already filled up with 8 what already exists. So shouldn't what you're going 9 to do with the waste be part of the aging management 10 plan? Thank you.
11 CHAIRMAN SKILLMAN: Sir, thank you for 12 your comment?
13 Does anybody else wish to make a comment, 14 please?
15 MR. BOSSING: Yes, hello. Thank you, 16 Chairman Skillman. My name is Mike BOSSING. Thanks 17 for the opportunity to address the Committee. I want 18 to express my appreciation for the diligent review by 19 the ACRS Subcommittee.
20 I also want to acknowledge the NRC staff's 21 efforts during this eight-year review period for the 22 license review application and subsequent SER. In my 23 opinion, the review has been thorough, and detailed, 24 and demonstrates NextEra has followed the license 25 renewal process. Thank you, Chairman.
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112 1 CHAIRMAN SKILLMAN: Thank you, sir.
2 Anybody else out there that would like to 3 make a comment, please?
4 MR. MIRANDA: Yes. My name is Sam 5 Miranda. Hello?
6 CHAIRMAN SKILLMAN: Go ahead, Sam.
7 MR. MIRANDA: I had submitted some 8 comments in writing. And I'd like to have an answer 9 to one question I had regarding Condition 3 events.
10 And Condition 3 events are defined as accidents that 11 could occur as often as once in the lifetime of a plant.
12 And when that was written, the lifetime 13 of a plant was 40 years. So now it's going to be 60 14 years, maybe 80 years. What provision has been made 15 for the potential increase in Condition 3 events? This 16 is just an average. I'm not saying it's going to 17 happen, but it could possibly happen.
18 And so the incident at Three Mile Island 19 in 1979 was a Condition 3 event, a stuck open pressurize 20 relief valve. So I'd like to see that looked into.
21 CHAIRMAN SKILLMAN: Sam, thank you for 22 your comment. We do have your comment in writing, and 23 we will put it on the record.
24 Is there anybody else that would like to 25 make a comment, please? Please do so at this time.
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113 1 Hearing none, Throne, you can close the 2 line.
3 At this point, I'm going to ask my 4 colleagues for any final comments that they may have 5 about today's proceeding. And I'll start with Dr.
6 Ballinger, please. Ron?
7 MEMBER BALLINGER: Nothing from me, 8 thanks.
9 CHAIRMAN SKILLMAN: Charlie Brown?
10 MEMBER BROWN: Nothing else for me either, 11 thank you.
12 CHAIRMAN SKILLMAN: Mike?
13 MEMBER CORRADINI: I appreciate the 14 presentation from both the applicant and the staff.
15 No other comments.
16 MEMBER RICCARDELLA: No further comments.
17 I made my comments after Seabrook's presentation.
18 Thank you.
19 CHAIRMAN SKILLMAN: Dr. Rempe?
20 MEMBER REMPE: I don't have any additional 21 comments except, again, thanking the staff and the folks 22 from NextEra for their presentations and everyone's 23 work on this effort.
24 CHAIRMAN SKILLMAN: Thank you. Dr.
25 Kirchner?
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114 1 MEMBER KIRCHNER: No further comments.
2 Thank you. Thank you all.
3 CHAIRMAN SKILLMAN: Dr. Schultz?
4 DR. SCHULTZ: I also would like to thank 5 the staff and NextEra for the presentations this morning 6 and also for the detailed responses to our questions 7 and to the discussions that we've had on the record 8 which have been very helpful in clarifying both the 9 application and the review. Thank you.
10 MR. HISER: Chairman Skillman, can I add 11 just one little bit.
12 CHAIRMAN SKILLMAN: Dr. Hiser?
13 MR. HISER: I just had a message from one 14 of our staff that Seabrook has full depth hydraulic 15 expansion in the tubesheet. So the tubes are fully 16 expanded within the tubesheet.
17 MEMBER BALLINGER: And they were full 18 depth from the start.
19 MR. HISER: Yes.
20 MEMBER BALLINGER: Yeah.
21 CHAIRMAN SKILLMAN: Thank you, thank you.
22 I would like to make just one or two comments. First 23 of all, the depth of the application is extraordinary.
24 The three volumes of the license renewal application, 25 the multiple RAIs, the 60-some updates, and the 91 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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115 1 commitments to date present a thorough defense for 2 license renewal.
3 We expended a full day on October 31, 4 approximately 60 to 70 people, on alkalized silica 5 reaction. We will write a separate letter on that 6 technical topic independent from the letter on license 7 renewal.
8 I want to compliment the staff for a very 9 thorough safety evaluation report. And I would just 10 note that one had to be particularly careful going 11 through the SER, because there were portions of it that 12 were dated 2011 and 2012 and then updates into 2015 13 and into 2018. So in a way, it was a work in progress.
14 But all the action items from 2012 have 15 been addressed. And it appears to me that all of the 16 critical items that need attention have been codified 17 into the commitment list in NextEra's license renewal 18 application.
19 In other words, there is correspondence 20 between the NRC staff action and the NextEra action 21 to make sure that the items that needed attention and 22 need committed to have been addressed or will be 23 addressed before the PEO. So thank you.
24 And thank you to those of you who traveled.
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116 1 adjourned.
2 (Whereupon, the above-entitled matter went 3 off the record at 11:04 a.m.)
4 5
6 7
8 9
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Seabrook Station ACRS License Renewal Subcommittee November 15, 2018
The foundation for everything we do are the Values and Core Principles of our Nuclear Excellence Model 2
Personnel in Attendance
- Eric McCartney Regional Vice President -
Northern Region
- Michael Collins Engineering Director
- Ken Browne Licensing Manager
- Edward Carley License Renewal Supervisor
- Rudy Gil Programs Engineering Manager 3
Agenda
Background
- Plant
- Status
- Licensing License Renewal Project Overview
- Scoping
- Time Limited Aging Analysis
- Application of GALL
- Commitment Process Closure of Previous SER Open Items Concluding Remarks NextEra Energy Seabrook has met the requirements of 10 CFR 54 for issuance of a renewed licensed for Seabrook Station Unit 1 4
Seabrook Background
- Seabrook Station is a single unit Westinghouse 4-loop pressurized water reactor with a General Electric turbine generator
- Located in the Town of Seabrook, New Hampshire
- Two miles west of the Atlantic Ocean
- Approximately two miles north of the Massachusetts state line
- Approximately 15 miles south of the Maine state line
- Reactor housed in a steel lined reinforced concrete containment structure which is enclosed by a reinforced concrete containment enclosure structure
- 3648 MWt Thermal Power; ~ 1,250 net megawatts electric
- Atlantic Ocean is the ultimate heat sink.
- A Seismic Cat I mechanical draft cooling tower provides additional safe shutdown capability.
5
Plant Site
- Switchyard
- Turbine Building
- Control/Diesel Building
- Containment Enclosure Building
- Fuel Storage Building
- Primary Auxiliary Building
- Unit #2 Area
- Waste Process Building 6
Licensing Construction Permit (CPPR-135) July 1976 Zero Power Operating License (NPF-56) October 1986 Low Power Operating License (NPF-67) May 1989 Full Power Operating License (NPF-86) March 15, 1990 Commercial Operation August 1990 Operating License Transfer to FPL Energy (NextEra) November 2002 Stretch Power Uprate (3587 MW) February 2005 Zero Power Recapture (3.4 years) December 2005 Measurement Uncertainty Uprate (3648MW) May 2006 LR Application Submitted May 25, 2010 Operating License Expires March 15, 2030 7
Plant Status Current Plant Status
- Completed latest refuel outage (OR19) 10/29/18
- Capacity Factor 15/19 cycles > 94%
- Lifetime 87%
- Lifetime excluding refueling outages 95.2%
- Cycle 19: 99.86%
- Cycle 18: 98.34%
- Cycle 17: 99.27%
- Cycle 16: 99.71%
- Next Refuel Outage - Spring 2020 (End of Cycle 20)
Capacity factor performance is representative of solid equipment reliability and material condition 8
Recent Station Improvements
- Vital Batteries
- Vital Inverters
- Generator Step-Up Transformers
- Mechanical Stress Improvement Process completed for all Reactor Vessel Nozzles
- Service Water Piping (AL6XN)
- Incore Detectors
- Process Control Single Point Vulnerability Circuit Cards
- Solid State Protection System Circuit Cards
- Rod Control Motor/Generator Sets
- Shutdown Reactor Coolant Pump Seals NextEra Energy Seabrook is committed to continuous improvement 9
Project Overview - Scoping
- Experienced, multi-discipline Site Team developed the License Renewal Application (LRA)
- Contractors experienced in License Renewal Application development
- Personnel familiar with Seabrook Station design and operation
- Incorporated lessons learned from previous applications
- Guidance of NEI 95-10 and NUREG 1800
- NUREG-1801 (GALL) Rev1
- GALL Revision 2 review was performed and changes were made to the LRA
- LR-ISG Topics Incorporated into Seabrook LRA 10
Project Overview - Scoping
- Utilized site component database, controlled drawings, design and licensing documents
- SSCs Evaluated to Scoping Criteria 10CFR54.4 (a)(1), (a)(2) and (a)(3)
- Identified SSCs that perform or support an intended function
- Non-Safety Affecting Safety (a)(2)
- Reviewed safety related equipment locations
- Conservative spaces approach
- Performed walk-downs for verification
- Use of commodity groups when evaluations were best performed by component type rather than SSC 11
Project Overview - TLAA Design and Licensing Basis reviewed for potential TLAAs
- Keyword Search (UFSAR, NUREG-0896, Calcs, Specs)
- Review of previous LRA applications Neutron Fluence
- Determined fluence for operation to 60 years
- Materials in the extended beltline identified and evaluated
- Upper Shelf Energy values exceed the minimum acceptance limit of 50 ft-lbs
- PTS limits are below the maximum allowable screening criteria Metal Fatigue
- Cumulative Usage Factor evaluated for 60 years
- Evaluated Environmentally Assisted Fatigue for NUREG/CR-6260 locations.
12
Project Overview - GALL Application 44 Aging Management Programs GALL Consistency
- 29 Existing Programs Consistent 8 Consistent with Enhancements 12 Consistent with Exceptions 2 Consistent with Enhancements and Exceptions 5 Plant Specific 2
- Nickel Alloy Nozzles and Penetrations
- Boral Monitoring
- 15 New Programs Consistent 7 Consistent with Enhancements 1 Consistent with Exceptions 2 Consistent with Enhancements and Exceptions 1 Plant Specific 4
- Buried Piping and Tanks Inspection
- 345kV SF6 Bus
- Building Deformation Management Program
- Alkali-Silica Reaction Management Program 13
License Renewal Implementation
- Implementation Project Plan Developed
- Process and Procedures established for:
- Aging Management Plan (AMP) Implementation
- Problem / Deficiency Identification
- Internal and External Operating Experience
- Program Documentation and Records
- Completion of License Renewal Commitments
- 10 CFR 54.37(b) Process 14
Safety Evaluation Report SER Issued September 28, 2018
- No open items
- No confirmatory items Closure of Open Items from previous SER (2012)
- OI 3.0.3.2.2-1 Steam Generator Tube Integrity
- OI 4.2.4-1 Pressure-Temperature Limit
- OI 3.2.2.1-1 Treated Borated Water
- OI 3.0.3.1.7-1 Bolting Integrity Program
- OI B.1.4-2 Operating Experience
- OI 3.0.3.1.9-1 ASME Section XI, IWE Program
- OI 3.0.3.2.18-1 Structures Monitoring Program 15
Steam Generator Tube Integrity Program OI 3.0.3.2.2-1
- a. Cracking of tube-to-tubesheet welds due to primary water stress corrosion cracking (PWSCC) on the primary coolant side of the steam generator.
- b. Potential degradation (PWSCC) of steam generator (SG) divider plate assemblies based on industry experience (foreign).
Resolution a) Amendment No. 131 to Facility Operating License provided for the permanent application of SG tube alternate repair criteria.
Tube-to-tubesheet welds are permanently excluded from the reactor coolant pressure boundary.
b) Per Supplement 53 to the LR application, Seabrook will follow the guidance in LR-ISG-2016-01.
Evaluation completed to demonstrate that results of the industry (EPRI) analyses for PWSCC of the divider plate assemblies are bounding for the Seabrook SG divider plate assemblies.
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Pressure-Temperature Limit OI 4.2.4-1
- Consistency of methods used to develop the P-T limits with 10CFR50 Appendix G Resolution
- Amendment No. 151 issued to Seabrook Station Facility Operating License, approved P-T Limits for 55 EFPY consistent with 10CFR50 Appendix G.
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Treated Borated Water OI 3.2.2.1-1
- LR-ISG-2011-01 issued with guidance for managing the aging effects of stainless steel structures and components exposed to treated borated water.
Resolution
- License Renewal Application updated to add affected components to the One Time Inspection Program population consistent with LR-ISG-2011-01.
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Bolting Integrity Program OI 3.0.3.1.7-1
- Once a seal cap enclosure is installed, the bolting and component external surfaces within the enclosure are no longer visible for direct inspection.
Resolution
- NextEra removed the seal cap enclosure (OR15, 2012).
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Operating Experience OI B.1.4-2
- Describe the programmatic details used to continually identify, evaluate and use Operating Experience.
Resolution
- LRA has been updated to document programmatic aspects of evaluating aging related OE consistent with LR-ISG 2011-05.
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ASME Code Section XI Subsection IWE Program OI 3.0.3.1.9-1 Accumulation of water in the Containment Enclosure Building annular space can potentially degrade the containment liner plate.
Resolution LRA updated to: Perform confirmatory UT testing of the containment liner plate in the vicinity of the moisture barrier every 5 cycles.
Implemented measures to maintain the exterior surface of the Containment Structure, from elevation -30 feet to +20 feet, in a dewatered state.
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Structures Monitoring Program OI 3.0.3.2.18-1
- Aging management of concrete structures affected by Alkali-Silica Reaction (ASR).
Resolution
- LRA updated to augment existing Structures Monitoring Program by addition of plant specific Alkali-Silica Reaction (ASR) and Building Deformation (BM) Aging Management Programs as discussed in 10/31/2018 ACRS sub-committee meeting.
- Aging management of ASR has been integrated into the Section XI IWL Program. Inspection, tracking and evaluation are in accordance with guidance of ACI 349.3R.
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Concluding Remarks
- Seabrook is committed to the continuous improvement and long-term operation of Seabrook Station
- Seabrook will manage the effects of aging in accordance with 10 CFR 54.21(a)(1)
- Seabrook has evaluated time-limited aging analyses that require evaluation under 10 CFR 54.21(c)
- Seabrook has met the provisions of 10 CFR 54 for issuance of a renewed license NextEra Energy Seabrook has demonstrated compliance with the requirements of 10 CFR 54 for issuance of a renewed licensed for Seabrook Station Unit 1 23
Advisory Committee on Reactor Safeguards License Renewal Subcommittee Seabrook Station, Unit 1 Safety Evaluation Report (SER)
November 15, 2018 Division of Materials and License Renewal Office of Nuclear Reactor Regulation
Presentation Outline
- Overview of Seabrook License Renewal Review
- Region I 71002 Inspection: License Renewal Inspection
- SER Section 2: Scoping and Screening Review
- SER Section 3: Aging Management Review
- SER Section 4: Time-Limited Aging Analyses
- Conclusion 2
License Renewal Review:
Audits and Inspections Onsite Audit / Inspection Dates Scoping & Screening Methodology September 20 - 23, 2010 Audit (ML110270026)
Aging Management Program (AMP) October 12 - 15, 2010 Audits (ML110280424) October 18 - 22, 2010 Region I 71002 Inspection: Scoping, March 7 - 11, 2011 Screening, and AMPs March 21 - 25, 2011 (ML111360432) April 4 - 8, 2011 Region I 71002 Inspection: AMPs for April 30 - May 3, 2018 Alkali-Silica Reaction (ASR)
(ML18222A292) 3
SER Overview
- SER with 7 Open Items issued June 2012
- 1. Bolting Integrity Program
- 3. Steam Generator Tube Integrity Program
- 4. Operating Experience
- 5. Treated Borated Water
- 6. Pressure-Temperature Limit
- 7. Structures Monitoring Program/ASR
- Open items closed on September 28, 2018 4
71002 Inspection in 2011
- Scope:
- Scoping and screening of components per 10 CFR 54.4(a)(2)
- Walk down of accessible areas
- Review of a sample of AMPs
- Team of 4 conducted on-site inspection for 3 weeks:
- Weeks of March 7, March 21, and April 4, 2011
- Inspection Report issued May 23, 2011 (ML111360432) 5
71002 Inspection: Observations
- Buried Piping and Tanks Inspection
- Lubricating Oil Analysis
- Fire Water System
- ASME Section XI, Subsection IWL
- Structures Monitoring Program
- Water intrusion was noted during walk-down of residual heat removal vaults
- Deposits
- Brown Stains (Membrane Failure)
- Applicants review of the effects of ASR on structures was incomplete at the time of the inspection 6
71002 Inspection: Conclusions
- Except for the ASR issue, inspection results provided reasonable assurance that aging effects will be managed and intended functions maintained during the period of extended operation
- Documentation supporting the application was auditable and retrievable 7
71002 Inspection in 2018
- Scope:
- Focused review of AMPs for ASR
- Walk down of a sample of structures
- Review of the structures monitoring program database
- Team of 2 conducted on-site inspection for 1 week:
- Week of April 30, 2018
- Inspection Report issued August 10, 2018 (ML18222A292) 8
SER Section 2
- Structures and Components Subject to Aging Management Review (AMR)
- Section 2.1: Scoping and Screening Methodology
- Section 2.2: Plant-Level Scoping Results
- Sections 2.3, 2.4, 2.5: Scoping and Screening Results 9
SER Section 3
- Aging Management Review Results
- Section 3.1: Aging Management of Reactor Vessel, Internals, and Reactor Coolant System
- Section 3.2: Aging Management of Engineered Safety Features
- Section 3.3: Aging Management of Auxiliary Systems
- Section 3.4: Aging Management of Steam and Power Conversion Systems
- Section 3.5: Aging Management of Containments, Structures, and Component Supports
- Section 3.6: Aging Management of Electrical Commodity Group 10
SER Section 3 Section 3.0.3 - Aging Management Programs (AMPs)
Applicants Disposition of AMPs Final Disposition of AMPs in SER
- 13 new programs
- 15 new programs 6 consistent 7 consistent 1 consistent with enhancements 1 consistent with enhancement 3 consistent with exceptions 2 consistent with exceptions 3 consistent with enhancements 1 consistent with enhancements and exceptions and exceptions 4 plant specific
- 29 existing programs 10 consistent
- 29 existing programs 10 consistent with enhancements 8 consistent 3 consistent with exceptions 12 consistent with enhancements 4 consistent with enhancements 2 consistent with exceptions and exceptions 5 consistent with enhancements 2 plant specific and exceptions 2 plant specific 11
Operating Experience (OpE)
- Open Item B.1.4-2
- NextEra did not fully describe how it will use future OpE to ensure AMPs will remain effective for managing the aging effects during the period of extended operation
- Resolution:
- In a letter dated January 20, 2012, NextEra provided detailed information on how it considers OpE on an ongoing basis and how the OpE review activities address issues related to aging 12
Bolting Integrity Program
- Open Item 3.0.3.1.7-1
- A seal cap enclosure was installed on a valve
- The recommended inspections for the Bolting Integrity Program, external visual examinations to detect leakage, would not be effective at detecting potential degradation of the closure bolting
- Resolution:
- Seal cap enclosure was removed
- There are no plans to install new seal cap enclosures 13
ASME Code Section XI, Subsection IWE Program
- Open Item 3.0.3.1.9-1
- NextEra had not implemented procedures and inspection requirements to keep the annular space between the containment and containment enclosure buildings in a dewatered state. Water accumulation in the annular space can potentially degrade the containment liner plate.
- Resolution:
- NextEra revised its program to include specific provisions in preventive monitoring and maintenance program to maintain the containment annulus in a dewatered state.
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Steam Generator (SG) Tube Integrity Program
- Open Item 3.0.3.2.2-1
- Management of cracking on the primary coolant side of steam generator tube-to-tubesheet welds due to primary water stress corrosion cracking
- Provide information on the one-time inspection of the SG divider plate assembly
- Resolution:
- Amendment No. 131 approved the permanent application of SG tube alternate repair criteria, which allowed the licensee to exclude the tube-to-tubesheet welds from the reactor coolant pressure boundary
- An LRA supplement implemented LR-ISG-2016-01, which incorporated recurring inspection of the SG divider plate assembly into the SG Tube Integrity AMP 15
Treated Borated Water
- Open Item 3.2.2.1-1
- LR-ISG-2011-01 revised GALL Report Revision 2 to include a one-time inspection in addition to managing aging effects with the Water Chemistry Program for stainless steel components exposed to treated borated water
- Resolution
- NextEra revised its associated AMR items to include a one-time inspection to detect potential loss of material, cracking, or reduction of heat transfer for stainless steel components exposed to treated borated water 16
SER Section 4
- Time-Limited Aging Analyses (TLAAs)
- 4.1: Identification of TLAAs
- 4.2: Reactor Vessel Neutron Embrittlement Analyses
- 4.3: Metal Fatigue Analyses
- 4.4: Environmental Qualification of Electric Equipment
- 4.5: Concrete Containment Tendon Prestress Analyses
- 4.6: Containment Liner Plate, Metal Containment, and Penetrations Fatigue Analyses
- 4.7: Other Plant-Specific TLAAs 17
Pressure-Temperature Limits
- Open Item 4.2.4-1
- Methodology used to calculate P-T limits must consider beltline and non-beltline ferritic materials, per 10 CFR Part 50 Appendix G.
- The NRC determined that the applicants operating P-T limit curves may not appropriately consider non-beltline ferritic materials.
- Resolution:
- License amendment request to extend the P-T limit curves to 23.7 EFPY included consideration of non-beltline ferritic materials.
- NRC staff approved the amendment
- Approval of amendment closed Open Item 4.2.4-1.
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Conclusion On the basis of its review, the staff finds that the requirements of 10 CFR 54.29(a) have been met for the license renewal of Seabrook Station, Unit 1.
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