ML18282A252
| ML18282A252 | |
| Person / Time | |
|---|---|
| Issue date: | 09/20/2018 |
| From: | Kent Howard Advisory Committee on Reactor Safeguards |
| To: | |
| Howard K | |
| References | |
| Download: ML18282A252 (131) | |
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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, September 20, 2018 Work Order No.: NRC-3911 Pages 1-131 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 SEPTEMBER 20, 2018
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ROCKVILLE, MARYLAND
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The Subcommittee met at the Nuclear Regulatory Commission, Two White Flint North, Room T2B1, 11545 Rockville Pike, at 1:27 p.m., Gordon R.
Skillman, Chairman, presiding.
COMMITTEE MEMBERS:
GORDON R. SKILLMAN, Chairman RONALD G. BALLINGER, Member CHARLES H. BROWN, JR. Member JOSE MARCH-LEUBA, Member HAROLD B. RAY, Member PETER C. RICCARDELLA, Member MATTHEW SUNSERI, Member NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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2 ACRS CONSULTANT:
STEPHEN SCHULTZ DESIGNATED FEDERAL OFFICIAL:
KENT HOWARD ALSO PRESENT:
PHYLLIS CLARK, NRR ALAN COX, NRR JOE DONOGHUE, DMLR BRYAN FORD, Entergy SAMUEL GRAVES, Region IV*
JAMES HENDERSON, Entergy ALLEN HISER, NRR WILLIAM HOLSTON, NRR*
PAUL HYMEL, Entergy LOIS JAMES, NRR JOHN JARRELL, Entergy BRIAN LANKA, Entergy JAMES MEDOFF, NRR ERIC OESTERLE, NRR AMRIT PATEL, NRR GORDON PICKERING, Entergy HERBERT RIDEOUT, Entergy NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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3 MOHAMMAD SADOLLAH, NRR DEAN SANDLIN, Entergy EMMANUEL SAYOC, NRR TIM SCHENK, Entergy TODD SHERMAN, Entergy ANDREA D. VEIL, Executive Director, ACRS JOHN VENTOSA, Entergy GEORGE WILSON, NRR ALBERT WONG, NRR MATTHEW YODER, NRR GARRY YOUNG, Entergy
- Present via telephone NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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4 C-O-N-T-E-N-T-S RBS License Renewal Application by Entergy Introduction by John Ventosa.................7 Presentation by Tim Schenk...................8 Presentation by James Henderson.............10 Presentation by Garry Young.................38 Discussion with Entergy Leadership Team.....42 RBS Safety Evaluation Report by NRC Introduction by Emmanuel Sayoc..............52 Presentation by Samuel Graves...............56 Presentation by Emmanuel Sayoc..............65 Meeting Adjourned.................................89 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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5 1 P R O C E E D I N G S 2 1:27 p.m.
3 CHAIRMAN SKILLMAN: Ladies and gentlemen, 4 good afternoon. This meeting will begin. We recessed 5 at approximately 1020. And so we are continuing the 6 meeting that we began at 0830 this morning.
7 This is the meeting for the River Bend Unit 8 1 License Renewal Application. This meeting is a 9 meeting of the ACRS Plant License Renewal Subcommittee.
10 I'm Gordon Skillman. I'm chairman of the 11 subcommittee. ACRS members that are in attendance are 12 the same as were here this morning.
13 I will make one change. The meeting is 14 open to the public. We have one set of written comments 15 from a member of the public for this afternoon's 16 meeting, and we may or may not deal with that later 17 if that member decides to call in or to participate.
18 As before, the meeting is being 19 transcribed. We request that all in the meeting, when 20 they come to the microphone, please speak clearly and 21 introduce themselves.
22 A telephone bridge line is established.
23 And to preclude interruption of the meeting, we ask 24 that the bridge line participants please maintain their 25 phones on mute during the presentations and the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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6 1 committee discussion. We believe that the noise that 2 we heard this morning was the consequence of an unmuted 3 line. And for those in the meeting room here, please 4 silence all of your electronic devices.
5 We're now prepared to proceed with the 6 meeting, and I call upon Joe Donoghue to please 7 introduce the second part of this meeting. Joe?
8 MR. DONOGHUE: Thanks, Chairman Skillman, 9 and again, the members of the subcommittee. And once 10 again, for those of who may not have been here, I'm 11 Joe Donoghue. I'm the Deputy Director, Division of 12 Materials and License Renewal in NRR. We, again, want 13 to express our appreciation for doing the double header 14 today to save staff resources and the licensee's 15 resources.
16 Later this afternoon, you'll hear from our 17 project manager leading the staff's evaluation -- a 18 presentation of the evaluation, Manny Sayoc. Also 19 here, as was this morning, is Dr. Allen Hiser, our senior 20 technical advisor. Eric, you already heard from.
21 He's the project's branch chief. And we have staff 22 and managers who contributed to the review from River 23 Bend in the audience to answer any questions you may 24 have. We also have Region IV staff again all lined 25 up to discuss their inspection activities related to NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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7 1 this review.
2 So again, thank you. I turn it over to 3 the Chief Operations Officer from Entergy team, John 4 Ventosa.
5 MR. VENTOSA: Good afternoon. My name is 6 John Ventosa. I'm the Chief Operating Officer for the 7 Southern Region for Entergy of which River Bend is one 8 of the sites that I have responsibility for and 9 obviously the topic of this afternoon's meeting.
10 I very much appreciate the opportunity to 11 speak to this committee this afternoon about the license 12 renewal application for River Bend. In our view, the 13 staff has conducted a very thorough but fair review 14 of our readiness for the renewed operating license.
15 For this afternoon's discussion, we have 16 with us James Henderson who's the Engineering Director 17 for River Bend, Tim Schenk who's the River Bend Reg 18 Assurance Manager, and Garry Young who's our Director 19 for License Renewal for Entergy.
20 Tim will describe our River Bend Station 21 plant status and its licensing history. James will 22 describe major equipment upgrades, completed and 23 planned, that are supporting our extended operation 24 at River Bend. And finally, Garry will discuss the 25 license renewal project itself and provide more NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 1 in-depth information on selected few topics.
2 Again, thank you for the opportunity to 3 be here today for this very important milestone for 4 River Bend. And we welcome your question and look 5 forward to the discussion. Thank you. I'll turn the 6 presentation over to Tim Schenk.
7 MR. SCHENK: And good afternoon. My name 8 is Tim Schenk. I'm the Regulatory Assurance Manager 9 at River Bend Station. River Bend Station is located 10 in West Feliciana Parish, Louisiana, approximately 24 11 miles north-northwest of Baton Rouge, Louisiana.
12 It was a General Electric designed plant.
13 Stone and Webster was the constructor. We're a 14 Boiling Water Reactor 6 model with a GE Mark III 15 containment and GE turbine -- General Electric turbine.
16 Our ultimate heat sink is independent wet cooling 17 tower. We have a closed circ water system with 18 mechanical draft cooling towers, and we're currently 19 licensed to 3,091 megawatts thermal with a staff of 20 820 individuals.
21 Currently, River Bend is operating at 100 22 percent power and is on a 24-month operating cycle.
23 We're a Column 1 plant in the reactor oversight process, 24 and we have a last refueling outage was in the spring 25 of 2017. That was Refueling Outage No. 19 and Refueling NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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9 1 Outage No. 20 is scheduled for the spring of 2019.
2 CHAIRMAN SKILLMAN: Tim, what has your 3 capacity factor been for the last several cycles?
4 MR. SCHENK: The capacity factor for 2018 5 is currently 75.1 percent and 2017 is 83.1 percent.
6 CHAIRMAN SKILLMAN: The most recent is the 7 result of a refueling cycle or refueling outage?
8 MR. SCHENK: We had a planned down power 9 in early 2018 to address fuel failures at the station, 10 and that has impacted our capacity factor for 2018.
11 CHAIRMAN SKILLMAN: Okay.
12 MR. SCHENK: Some of the history of River 13 Bend Station, we received our construction permit in 14 March of 1977. Our operating license was November of 15 1985, and we commenced commercial operation in June 16 of 1986. So we were rated at that time at 2,894 17 megawatts thermal.
18 We did our first power uprate in November 19 of 2000. That's five percent power uprate. That took 20 us to 3,031 megawatts thermal. And we did another power 21 uprate in January of 2003, and it's got us to our current 22 power capacity of 3,091 megawatts thermal. Our license 23 renewal was submitted in May of 2017, and our current 24 operating license expires in August of 2025.
25 With this, I'd like to turn it over to NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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10 1 Engineering Director James Henderson to talk a little 2 bit about major equipment upgrades.
3 MR. HENDERSON: Good afternoon. My name 4 is James Henderson. I am the Engineering Director here 5 at River Bend Station. I want to go over a couple items 6 for our major equipment upgrades. What you see is 7 reflective of a long-range plan that's been focused 8 not only on equipment reliability but also safety for 9 the station.
10 A couple of the items that we have going 11 forward that we've completed already at the station, 12 the first, we've made a major upgrade to our Digital 13 EHC. That's our electrical hydraulic control system, 14 turbine controls. We have a picture going forward in 15 the presentation that we'll show to the team so that 16 you all can see the major adjustments we did there.
17 We have eliminated several single point 18 vulnerabilities on the order of greater than 90 to help 19 with the equipment reliability and long-term operation 20 of the plant. We've also done control building 21 upgrades to our control building chillers, upgrading 22 those to digital controls, looking specifically at our 23 additional monitoring, giving our operators additional 24 redundancy, and giving them the ability to identify 25 issues prior to becoming challenges for the station.
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11 1 Also, for long-term reliability, we've 2 done recoating for underground circ water piping.
3 We've also replaced some of our obsolescence items 4 related to inverters as well as 40 Volt control circuit 5 breakers which are listed above. We've also done 6 upgrades to our normal service water cooling towers.
7 We have plate and frame heat exchangers associated 8 with our service water cooling towers. We want to make 9 sure those can support long-term operation of the plant.
10 And we've also replaced our fourth point feedwater 11 heaters associated with the station.
12 So if we go to the next slide.
13 CHAIRMAN SKILLMAN: Before you do that, 14 please. Here, you recoated your underground 15 circulating water piping. But at Waterford 3, it was 16 a one-time inspection, maybe last time when Moby Dick 17 was a minnow. So how come you're doing inspections 18 and coating here? It appears to be a very different 19 cadence than the sister plant.
20 MR. HENDERSON: Yes, for our station, 21 we've done a couple of inspections for our underground 22 piping just because we want to make sure we have that 23 long-term reliability for the station. In 2012, we 24 did a complete excavation inspection for our 25 underground piping. We also did culvert work in 2017.
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12 1 We also took that opportunity to look at the 2 underground piping.
3 So any opportunity that we have where we 4 do excavation activities or things of that nature.
5 Because of the nature of our underground piping system, 6 we want to make sure we're doing the right thing for 7 the station.
8 CHAIRMAN SKILLMAN: Replacing the fourth 9 point heaters, is it because they were not sufficient 10 for your thermal efficiency, or were they actually 11 failing?
12 MR. HENDERSON: They were not failing.
13 This was to improve our thermal efficiency.
14 CHAIRMAN SKILLMAN: Yes sir. Thank you.
15 MR. SCHULTZ: James, what's the relative 16 time frame for the completed upgrades that are listed 17 here?
18 MR. HENDERSON: These upgrades have been 19 completed.
20 MR. SCHULTZ: No, but over what time 21 period?
22 MR. HENDERSON: Oh, it's over a five-year 23 period. So as a part of our nuclear strategic plan 24 that we did for our station, through our fleets focus, 25 we laid out specific items to go after from 2018 to NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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13 1 2023. And that's where you'll see a lot of our 2 modifications or the things we're going after to improve 3 equipment reliability.
4 MR. SCHULTZ: But these are completed?
5 MR. HENDERSON: That's correct.
6 MR. SCHULTZ: So five years past, you begin 7 some of these modifications, either in engineering or 8 in physical modification?
9 MR. HENDERSON: That's correct.
10 CHAIRMAN SKILLMAN: James, which of these 11 upgrades was the result of a PRA review where the Entergy 12 team said, we've got some safety benefit by making this 13 or these changes? I'm looking particularly at the 14 inverters and wondering if that was a material or 15 equipment reliability change that was driven by PRA 16 examination.
17 MR. HENDERSON: The inverter upgrades that 18 we did specifically were driven based upon obsolescence 19 for the inverters that we had in service. I'm not 20 really sure the tie to the PRA aspect of things for 21 the inverter.
22 CHAIRMAN SKILLMAN: Thank you.
23 MEMBER SUNSERI: James, do you have any 24 underground electrical cables that are subject to being 25 covered up by water?
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14 1 MR. HENDERSON: We do have underground 2 cables that are susceptible to being covered by water.
3 We do have preventative maintenance strategies in 4 place, not only to do monitoring. But we also have 5 solar power sump pumps to keep those wells empty.
6 MEMBER SUNSERI: Thank you.
7 CHAIRMAN SKILLMAN: So how do the solar 8 power sump pumps do at night?
9 MR. HENDERSON: That's really the piece 10 of the performance, the preventative maintenance 11 activity as well. So not just relying on the solar 12 power sump pumps, but we also have our maintenance craft 13 go out, do inspections of those water holes to make 14 sure that they're getting pumped out efficiently.
15 CHAIRMAN SKILLMAN: Thank you.
16 MR. HENDERSON: No problem.
17 MR. SCHULTZ: James, let me ask Member 18 Skillman's question a little differently with regard 19 to PRA. You talked about this as what really appears 20 to be about a ten-year program for plant improvement 21 and modification.
22 To what extent have you used the PRA in 23 providing the listing of those major improvements that 24 you're going to do? And how does the PRA team interact 25 with the modifications in terms of upgrade and update?
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15 1 MR. HENDERSON: So when we put together 2 our nuclear strategic plan, one of the key pieces was 3 our impact to safety, our impact to risk. For example, 4 the upgrade of the control building chillers, those 5 control building chillers feed directly into our PRA 6 model, and the loss of those control building chillers 7 not only impact safety related switch gears, but it 8 also impacts the safety reliability of the main control 9 room. So those major activities that we have built 10 into our plan do have the -- our PRA team was involved 11 in making those decisions.
12 MR. SCHULTZ: That's a good example. So 13 you could go through these one at a time determine and 14 describe how they do relate to the PRA and which ones 15 most affect reliability of the facility. Thank you.
16 MR. HENDERSON: No problem. All right.
17 The next picture that you guys see, this is the graphic 18 user interface that we have for our EHC control system.
19 The visual controls are upgraded from an analog control 20 system.
21 This provides additional reliability for 22 the equipment operators, additional temp monitoring 23 as well as testing capabilities for our EHC system.
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16 1 hydraulic control system.
2 The next slide shows our upgrades we've 3 done for our load center breakers. Again, diagnostic 4 capability increases. The availability of the 5 breakers, all things that not only help with the 6 criminal liability but also the operator-user interface 7 associated with diagnosis as well as monitoring for 8 long-term reliability.
9 Our next slide, we've done activities 10 associated with carbon steel piping replacement. Very 11 specifically looking at our reactor water cleanup 12 system, we've gone through with some of the carbon 13 piping, removed those, replaced those with chrome moly 14 or updated with new carbon steel really to help our 15 reactor water cleanup system as it serves the function 16 to improve the chemistry and quality of our RCS. So 17 we're seeing the dividends of what we've been doing 18 here for the station.
19 MEMBER RICCARDELLA: What was the issue 20 with the old carbon steel piping? Was it flow assisted 21 or --
22 MR. HENDERSON: This was all associated 23 with our fab program.
24 So the next piece we'll talk through is 25 our major equipment upgrades. The very first are NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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17 1 turbine building chiller replacements. This is more 2 for generation and reliability for the station. Our 3 turbine building chillers not only support the turbine 4 building itself but also the cooling of our main steam 5 tunnel. So those replacements are in progress and are 6 scheduled to complete by the end of 2018.
7 We do have spent fuel pool neutron absorber 8 upgrade. I'll show you a picture going forward of that 9 upgrade that we're doing. We have inserts that we're 10 installing as prototypes to help improve not only our 11 neutron absorption but also going forward to be able 12 to use that by year 2020 for that modification.
13 The next piece, our condenser upgrade.
14 In our refueling outage '21, which will occur in 2021, 15 we plan to do a major scope on our main condenser, two 16 replacements. That's going to take place in '21. We 17 have bridging strategies from now until that time frame.
18 And in our next refueling outage, we're going to be 19 doing any current testing as well as tube cleaning and 20 all that good stuff to really make sure that we have 21 a good bridging strategy going forward to '21.
22 We've got service water cooling heat 23 exchanger refurbishment that's in progress. I did 24 annotate that earlier in our discussion. Our Fancy 25 Point switchyard upgrades, that's our offsite power NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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18 1 coming to the station, really increasing the 2 reliability there to make sure that we have a viable 3 resource of offsite power to the station.
4 Our recirc pump power cable replacement, 5 that's a part of our EQ program, getting those power 6 cables replaced so that we can improve the operation 7 of our recirc pumps.
8 And then the final two. The feedwater 9 strainer, that's directly associated foreign material 10 exclusion to the vessel. We'll have a picture later 11 in the presentation that I'll show and share with the 12 team really to make sure we have FME concerns addressed 13 for our station to prevent fuel failures and really 14 going forward to make sure that we've got long-term 15 reliability for the station.
16 And the last piece, our feedwater level 17 control system. That upgrade will also remove several 18 single-point vulnerabilities associated with our 19 feedwater level control system.
20 MR. SCHULTZ: James, with regard to the 21 switchyard upgrades, can you quantify that a bit about 22 what type of advantage do you expect to obtain by making 23 these upgrades?
24 MR. HENDERSON: So from a quantification 25 purpose, I'm not sure if I can articulate it quite well.
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19 1 I'll tell you what we're doing for the upgrade. We're 2 going to have a total separate switchyard from the 3 switchyard that we have in place right now.
4 We have a 500 kV distribution that gets 5 stepped down to 13.8 kV for the station. So we're going 6 to totally upgrade not only the breakers and lines 7 associated with that from our transmission and 8 distribution side but also the feeders that come to 9 our station. So from a quantifying aspect, I'm not 10 sure if I could really articulate that very well.
11 MR. SCHULTZ: It's more of a changeover 12 to a different type of switchyard approach which would 13 provide additional reliability?
14 MR. HENDERSON: Yes, the way I would table 15 it, it's from an equipment reliability perspective.
16 MR. SCHULTZ: Thank you.
17 MEMBER SUNSERI: James, the power 18 reduction that Tim talked about due to fuel performance, 19 do you know if that was related to foreign material 20 yet or not?
21 MR. HENDERSON: It was related to foreign 22 material.
23 MEMBER SUNSERI: So has this been an 24 ongoing challenge for the station, hence the 25 modification?
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20 1 MR. HENDERSON: Yes, we've had challenges 2 to the station. The first fuel failure that we 3 experienced happened in 2016 associated with a recent 4 string of fuel failures. We have the modification in 5 question for the feedwater strainers. It's really our 6 aggressive approach to making sure that we put something 7 in place to not only just perform flushing or look at 8 FME practices but really modify the plant so that we 9 put ourselves in the best position not to introduce 10 foreign material.
11 MEMBER SUNSERI: Yes, and I presume the 12 fuel assemblies themselves have some kind of debris 13 filter or something online?
14 MR. HENDERSON: They do, they do, they do.
15 MEMBER SUNSERI: So this debris is getting 16 past that?
17 MR. HENDERSON: Yes.
18 MEMBER SUNSERI: Thanks.
19 CHAIRMAN SKILLMAN: James, would you 20 please say more about the neutron absorber upgrade?
21 That is your second bullet here.
22 MR. HENDERSON: Yes, so the next slide 23 shows the neutron absorber. We currently have 60 that 24 are installed in our spent fuel pool. Basically, what 25 we're doing right now, we have the analysis from a NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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21 1 thermal perspective as well as seismic perspective.
2 And at this time, it's really monitoring to see the 3 effectiveness of those absorbers. It's aluminum 4 material is what the inserts are made of, and we're 5 going to be using that.
6 We're not taking credit for it in any of 7 our licensing basis or anything of that nature at this 8 time. It won't be until the engineering change is 9 completed as well as the full analysis of the ability 10 for our absorbers to really work. That'll be completed 11 in 2020. So we'll have all of the inserts by the end 12 of the year. We'll be able to continue to collect data.
13 And by 2020, we'll have the modification complete and 14 we'll be able to take credit for our neutron absorption.
15 CHAIRMAN SKILLMAN: Okay. So here is your 16 spent fuel pool and here you are adding hold down by 17 adding these inserts. Is this being conducted on a 18 50.59? Is this a license amendment? What is the 19 documentation that has enabled you to make, if you will, 20 a change in process?
21 I mean, this isn't something that you can 22 walk away from. You're doing it contemporaneously with 23 the requirement for the new material to provide the 24 hold down on which you depend. So what is the vehicle 25 by which you are doing this?
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22 1 MR. FORD: This is Bryan Ford from Entergy.
2 We are going to be requesting a license amendment so 3 that we can credit the inserts for their neutron 4 absorption capability. That's an analysis change that 5 we have to get approval for. For just installing the 6 inserts, we will do that under 50.59 and we just won't 7 credit them in our neutron analysis until we get 8 approval.
9 CHAIRMAN SKILLMAN: How do you clear the 10 question on 50.59 regarding either analysis or a change 11 to the facility that might rise to the need for a license 12 amendment?
13 MR. FORD: Because we're not crediting 14 them for the analysis. So we haven't changed the 15 analysis. We're still relying upon our previous 16 analysis for it.
17 (Simultaneous speaking.)
18 CHAIRMAN SKILLMAN: Okay. I'm just 19 getting it clear. Thank you. Now I understand.
20 Thank you.
21 MR. HENDERSON: Any other questions? Our 22 next slide -- oh, go ahead. Sorry, yes.
23 MEMBER SUNSERI: Just following up on that 24 a little bit there. But these inserts must have some 25 impact other than just reactivity, right? They're NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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23 1 going to be touching the fuel assemblies. They're 2 going to change the loading of the pool. I mean, 3 seismic, material, chemistry, you're looking at of all?
4 MR. FORD: Yes, and those parts of the 5 modification are performed under 50.59. So we make 6 sure we're within the applicable margins and redo the 7 appropriate analysis to accomplish that.
8 MEMBER SUNSERI: Thank you.
9 MR. HENDERSON: The next slide for our 10 planned upgrades, this is a picture of our feedwater 11 strainer to specifically address the foreign material 12 concerns that we discussed earlier. This will be one 13 of two feedwater strainers that are installed in our 14 feedwater line directly to the vessel. It gives us 15 the last opportunity to make sure that we collect any 16 type of foreign material so that it doesn't become a 17 concern for our fuel reliability.
18 MEMBER MARCH-LEUBA: So I can understand 19 this, what are the dimensions? I mean, how big is?
20 Is it this big or this big? Is that one foot, two feet, 21 two inches in diameter?
22 MR. HENDERSON: I don't know the exact 23 diameter, but it's bigger. It's a bigger strain.
24 MEMBER MARCH-LEUBA: But the strainer 25 themselves is minuscule, right?
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24 1 MR. HENDERSON: That's correct.
2 MEMBER MARCH-LEUBA: You're trying to 3 catch microfibers?
4 MR. HENDERSON: If you can imagine, it's 5 almost a witch's hat design where you can see the 6 differences.
7 MR. SANDLIN: I'm Dean Sandlin, the design 8 manager at River Bend. These things are about six foot 9 long and they're in 20-inch pipe. So they are actually 10 larger than 20-inch, and then we have the reducers on 11 both sides. It's probably 30 inches in diameter.
12 MEMBER MARCH-LEUBA: And the inside filter 13 is six foot long and very --
14 MR. SANDLIN: It's like a witch's hat.
15 It necks down into that, and you have about a million 16 holes in it. That's the best way to describe it. It's 17 like a witch's hat with a million little bitty small 18 holes in it.
19 MEMBER MARCH-LEUBA: And you have enough 20 pumping power to go through the pressure drop?
21 MR. SANDLIN: Yes. We've already had the 22 hydraulic analysis complete.
23 MEMBER MARCH-LEUBA: Okay. Thank you.
24 MR. SANDLIN: We didn't want to go forward 25 without that.
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25 1 CHAIRMAN SKILLMAN: So the design pressure 2 of this is approximately 1,500 psi?
3 MR. SANDLIN: Yes.
4 CHAIRMAN SKILLMAN: And so what we're 5 seeing here is construction bolting. This is not final 6 fit of bolting?
7 MR. SANDLIN: No, that's just the shop 8 stuff right there.
9 CHAIRMAN SKILLMAN: Copy that. Okay.
10 Very good.
11 MR. SANDLIN: It'll be professional when 12 we get finished.
13 (Laughter.)
14 CHAIRMAN SKILLMAN: Okay. I'm saying, 15 wow, that's quite a mod. That's not even a 50.59.
16 (Laughter.)
17 CHAIRMAN SKILLMAN: I like that. So this 18 is basically a concept. And when this thing is snugged 19 up in place, it's got the 18 or 20-inch, inch and a 20 half high strength bolts?
21 MR. HENDERSON: Exactly, correct.
22 CHAIRMAN SKILLMAN: And she's cinched in 23 at 1,500 psi design.
24 MEMBER MARCH-LEUBA: And going back to 25 this, you have confidence that the fibers -- or I mean NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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26 1 the loose parts are coming from upstream of this filter?
2 MR. HENDERSON: Yes.
3 MEMBER MARCH-LEUBA: They're not inside 4 the vessel? They're not coming from the vessel?
5 MR. HENDERSON: Yes, the whole purpose of 6 this is to catch anything with the interface with the 7 feedwater system before it goes into the vessel, so 8 yes.
9 CHAIRMAN SKILLMAN: If I can ask, this is, 10 first of all, well done. You're protecting your fuel.
11 On the other hand, you've put in a barrier to feedwater 12 flow. So in the analysis for installation of this 13 filter, what consequence or what feature have you 14 recognized for plugging of this and its effect on your 15 core?
16 MR. SANDLIN: We've had the full hydraulic 17 analysis. We have enough capability in our feedwater 18 level control valves to provide the additional pumping 19 power we need to accommodate what we assume is the worst 20 case delta P across this filter and still maintain 21 enough flow to the core to maintain water level.
22 MEMBER MARCH-LEUBA: Is there only one of 23 these or two?
24 MR. SANDLIN: There'll be two. We have 25 two lines going into the vessel.
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27 1 MEMBER MARCH-LEUBA: If you were --
2 MR. SANDLIN: So both lines will have one 3 of these.
4 MEMBER MARCH-LEUBA: If you were to have 5 a degree sufficient to plug it in and you have a thousand 6 holes in there, you will need another one.
7 MR. SANDLIN: We'll have differential 8 pressure instruments across it so we can constantly 9 monitor the filter as well as vibration probes on it 10 as well.
11 MEMBER MARCH-LEUBA: And after the scram, 12 you don't rely on fuel water --
13 MR. SANDLIN: That's correct.
14 MEMBER MARCH-LEUBA: -- for safety actions 15 anyway to have HPCS?
16 MR. VENTOSA: But the concern you're 17 raising was probably the primary concern in the design 18 that we needed to get a clear answer on prior to 19 installation this coming spring. So there was some 20 independent -- we had independent teams, independent 21 vendors go look at that to make sure because that is 22 the critical question. Yes, it's good that we're going 23 to protect the fuel but not causing some other effect 24 was really the --
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28 1 mode that you've considered?
2 MR. SANDLIN: I didn't understand your 3 question.
4 CHAIRMAN SKILLMAN: What is the failure 5 mode that you considered? What if the whole set of 6 guts carries away? You have an inside zipper failure 7 that pulls the witch's hat apart. And now, you've got 8 a forest of material entering your core.
9 MR. SANDLIN: GE did an extensive analysis 10 on the construction of the filter itself, the witch's 11 hat I'm going to call it. That's what everybody calls 12 it. And it has a structural integrity it needs to where 13 it will not fail like you're talking about, come apart 14 and then send additional FME to the core. So they've 15 got extensive analysis on that. That's another issue 16 we wanted to make sure we completely understood before 17 we went forward with this project as well.
18 CHAIRMAN SKILLMAN: And is that documented 19 in a safety evaluation or something?
20 MR. SANDLIN: The failure modes and 21 effective analysis included in our modification. GE 22 will provide that.
23 MEMBER RICCARDELLA: Is this located 24 inside containment --
25 MR. SANDLIN: No, it's in the --
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29 1 MEMBER RICCARDELLA: -- or outside 2 containment?
3 MR. SANDLIN: -- just before it goes into 4 our steam tunnel in the turbine area.
5 MEMBER SUNSERI: And this is unique to 6 River Bend?
7 MR. SANDLIN: Yes.
8 MEMBER SUNSERI: So I guess you understand 9 the root cause of the foreign material well enough to 10 know you're -- I mean, you're putting a Band-Aid on 11 versus addressing the root cause, right?
12 MR. SANDLIN: Actually, we don't consider 13 it a Band-Aid. We want to make sure we keep all FME 14 from going to the core, and this is the last point before 15 it goes to the reactor. There's really nothing else 16 FME generator past this point going to the core. We'll 17 catch it with this filter. Anything that may happen 18 in the BOP area that will get in the feedwater system, 19 this is designed to catch it. We want to protect our 20 fuel at all costs.
21 MEMBER SUNSERI: Right. But probably so 22 does every other BWR-6 too that doesn't have this thing, 23 right?
24 MR. SANDLIN: Other BWRs may.
25 MR. VENTOSA: I can speak a little. Our NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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30 1 plans are to install it at Grand Gulf which is our other 2 BWR-6. It's just a couple years out. I don't want 3 to give you the impression that this is our fix for 4 foreign material. The root cause is work practices 5 and frankly some operational issues we had, how we set 6 valves up where we had some damage to valve internal 7 parts.
8 So we've addressed all that. We just 9 looked at the design and we felt there was still too 10 much of a vulnerability for fuel failures without taking 11 this next step.
12 MEMBER SUNSERI: Okay. That's fair.
13 MR. VENTOSA: Thanks.
14 MR. SCHULTZ: What are the maintenance 15 requirements for this? Do you have to change out the 16 filtration or flush the filtration system?
17 MR. SANDLIN: At the end of the first 18 cycle, we will take this thing out and inspect it to 19 see what kind of FME we have captured. We will 20 continuously monitor dP across it to make sure that 21 the dP doesn't exceed our hydraulic limits for pumping 22 water to the reactor to maintain the right water level.
23 But at the first cycle, we'll inspect it and we'll 24 determine what the future removal rate will be based 25 on the amount we capture.
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31 1 MR. SCHULTZ: Good. Thank you.
2 CHAIRMAN SKILLMAN: What is the 3 anticipated radiation level when you've captured this 4 fine material in this machine?
5 MR. SANDLIN: I don't have an answer for 6 that one. We'll talk about it in our modification.
7 It's in a remote area where people just are not -- it's 8 not a routine traffic area. It's in a high radiation 9 area already.
10 MEMBER MARCH-LEUBA: I know the FME comes 11 from the balance of plant. There is no neutron flux 12 there for activation.
13 MR. SANDLIN: I can't understand.
14 MEMBER MARCH-LEUBA: All of the material 15 that it catches comes from the balance of plant, 16 correct?
17 MR. SANDLIN: It comes from the BOP.
18 Here's the feedwater system.
19 MEMBER MARCH-LEUBA: And those materials 20 are not subject to neutron fluxes that will activate 21 them. So they're very likely to not be very hot. If 22 you start catching hot material there, we'd like to 23 hear from you.
24 CHAIRMAN SKILLMAN: I'm sure we will. And 25 that's a big enough machine that if there's a lot of NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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32 1 hot material, you're going to need some super whamodyne 2 shielding around that thing.
3 MEMBER MARCH-LEUBA: While I have the 4 microphone on, I'm going to regress a little bit on 5 philosophy. I wanted to end with what Dick stated, 6 good job. Because you took positive steps to make the 7 reactor better instead of doing a whole bunch of 8 analysis that did not change the reactor. And the 9 penalty you get for that, you always get one, is that 10 you get a lot of questions about it. But let me tell 11 you, good job. Thank you for doing it.
12 CHAIRMAN SKILLMAN: Yes, this reminds me 13 of some sage advice from Benjamin Franklin who said 14 if you put all your eggs in one basket, watch that basket 15 very, very, very closely. I think this is probably 16 good practice, but I think you need to be very aware 17 of the potential to start building up small amounts 18 of material that may have found its way here and that 19 is irradiated.
20 For whatever the reason is that you're 21 having fuel challenges, it's going to collect here.
22 I've just spent enough time at nuclear power plants 23 to know any place where material can collect can become 24 a very serious radiation source. And I know you know 25 that. You don't need that sermon. But this is a big NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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33 1 trap. A big trap can get a lot of stuff and you can't 2 get near it when it gets hot. Thank you.
3 MR. HENDERSON: Our next slide shows the 4 upgrades to our feedwater level control system. For 5 perspective, our feedwater level control system has 6 had previous challenges. We've done specific items 7 to help bridge and alleviate some of those issues.
8 But the feedwater level control system is really the 9 elimination strategy for several of the single-point 10 vulnerabilities associated with the circuitry as well 11 as the workings of the feedwater level control itself.
12 So it not only provides the impact for 13 elimination of single-point vulnerabilities. It also 14 provides reliability, deals with some of the 15 obsolescence items that we have with our old system 16 and also provides our operators a full range of control 17 automatically for our feedwater regulating system to 18 help them as far as monitoring and control of the unit.
19 MEMBER MARCH-LEUBA: Was this done under 20 or planned to be done under 50.59? Because this is 21 the licensee, so it's a significant challenge.
22 MR. HENDERSON: Yes, so it is planned to 23 be done under 50.59.
24 MEMBER MARCH-LEUBA: And I'm sure you're 25 considering -- and you don't need to answer this because NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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34 1 it might go not only proprietary but classified --
2 cybersecurity.
3 MR. HENDERSON: Yes.
4 MEMBER MARCH-LEUBA: So let's make sure 5 that the staff has reviewed that you don't have a 6 penetration point there.
7 MR. HENDERSON: Agreed. Thank you very 8 much.
9 MEMBER MARCH-LEUBA: And it's not only 10 internet. USB drives, the CDs, the components, even 11 microchips.
12 MR. HENDERSON: Completely understand.
13 MEMBER BROWN: Let me echo that. Looking 14 at your slide, I haven't seen the Ovation system in 15 a while being used. It's a distributed control system, 16 if I read your acronyms correctly. And I guess my 17 question is, is that DCS connected in some type of a 18 plant network and what type of communications did you 19 have? It's referring to Jose's comment relative to 20 the access from remote sources through software-based 21 firewalls that are in some plant network.
22 On most of the new plant designs, and quite 23 frankly, on all of the new plant designs that we've 24 gone through, any connections into a network or a 25 distributed control system like this have been via NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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35 1 unidirectional hardware-based data diodes, no software 2 control one way and they're hardware configured so that 3 they can't be reconfigured externally via software 4 hackers.
5 We don't see what's going on here. If 6 you're doing it in the future, somebody may be asking 7 that question when you all come in. If it's under 8 50.59, at least it gets the antennas going in terms 9 of whether we should be asking questions about it.
10 We've raised that concern in multiple full committee 11 meetings and sessions over the last eight years. And 12 pretty much everybody has defaulted to hardware-based 13 communication one way only.
14 No problem with sending data out. You'd 15 like to get data out so people can monitor it and trend 16 and do all that type of stuff. It's just the ability 17 to come in and do any software changes via external 18 sources as opposed to having to go into the plant and 19 upload new software changes or revisions as well as 20 control access.
21 You've always got the administrative 22 controls for internal stuff. But this should be inside 23 what I call a Level 4 boundary. And you certainly don't 24 want to have to fight cybersecurity threats and always 25 being upgrading software and that firewall and access NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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36 1 to it get to this stuff. It'll just eat you alive.
2 You can have a whole staff planned with it. That's 3 all. I'm just bringing the point up.
4 MR. HENDERSON: No, we definitely 5 appreciate the concern. And one of the things that 6 we've done, this modification is scheduled for 2021; 7 however, there are industry OE for folks that have 8 installed this digital feedwater level control. So 9 really capturing those lessons learned so we don't end 10 up in a position where we're trying to --
11 MEMBER BROWN: Well, they probably haven't 12 thought about this yet. Based on our conversations 13 with other folks, it's been, well, we'll figure this 14 out later. And they haven't really thought about the 15 ability to limit -- I mean, the air gap is the best 16 control that you have over ensuring nobody gets into 17 the critical controls on this stuff.
18 It's not a reactor safety system, per se, 19 in that definition like your reactor trip or safeguard 20 systems are. But it is a vital system, and that should 21 be treated appropriately in the same way.
22 MR. HENDERSON: That's a very good 23 challenge, and we appreciate that.
24 MEMBER MARCH-LEUBA: Let's not forget that 25 cybersecurity is a rapidly changing field. Just five NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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37 1 years ago, you had to deal with teenagers from high 2 school trying to steal your debt. And now you're 3 dealing with state actors with the best and brightest 4 fully funded. So you have to protect -- you have to 5 inspect any around that comes in there.
6 MR. HENDERSON: I agree.
7 CHAIRMAN SKILLMAN: Please proceed.
8 MR. VENTOSA: Then we'll turn it over Garry 9 now.
10 MR. YOUNG: Okay. Thank you. I'm Garry 11 Young, Director of License Renewal for the Entergy 12 nuclear fleet. And I'd like to give you some background 13 on our license renewal process including the approach 14 for the integrative plant assessment and for preparing 15 the license renewal application.
16 We have a dedicated corporate team working 17 on license renewal for all the Entergy nuclear plants.
18 The team has almost two decades of experience with 19 all aspects of aging management and license renewal 20 and has prepared more than a dozen license renewal 21 applications over the past several years.
22 In addition to the corporate team, a plant 23 team of River Bend experts in design, systems 24 engineering, and plant programs was established for 25 this license renewal project. The plant team provided NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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38 1 needed input, review, and oversight of all of the 2 engineering and environmental reports that were 3 created.
4 We had more than 40 engineering reports 5 that were prepared to address the mechanical, 6 electrical, civil, structural, and time limited aging 7 analysis topics needed to prepare the application.
8 We used the NRC approved guidance in NEI 9 95-10 to prepare the project-specific procedures.
10 These procedures have been used on our previous license 11 renewal projects and are routinely updated based on 12 lessons-learned industry operating experience and 13 changes to the NRC guidance.
14 The site specific aging management review 15 for River Bend were compared to the GALL report, 16 NUREG-1801, Revision 2 as part of the application 17 development. The individual line items in the 18 application indicate their consistency with the GALL 19 report aging management review results. And I'll talk 20 more about the comparison of the aging management 21 program with the GALL report on a later slide.
22 The LRA was submitted to the NRC in May 23 of 2017. The NRC used a new review process for the 24 River Bend application that included some efficiency 25 improvements based on lessons learned from previous NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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39 1 NRC reviews. This has proven to be a successful effort 2 by the NRC staff and has resulted in a planned 18-month 3 review schedule rather than the typical 22-month review 4 schedule. Next slide.
5 The NRC review process culminated in the 6 River Bend safety evaluation report which was issued 7 in August of 2018 with no open items and no confirmatory 8 items. And we appreciate the extensive and thorough 9 work of the NRC staff in reaching this important 10 milestone in the license renewal application review 11 process. Okay, next slide.
12 Okay. This slide summarizes the aging 13 management programs that were credited for license 14 renewal. We have 43 aging management programs that 15 include 12 new programs and 30 existing programs that 16 are or will be consistent with the GALL report aging 17 management programs with a handful of exceptions as 18 shown on this slide.
19 So examples of the 12 new programs are the 20 buried and underground piping and tanks inspection 21 program, the non-EQ cables and connectors aging 22 management programs, one-time inspection programs, and 23 selective leeching program.
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40 1 based on a significant number of changes that must be 2 made or have only recently been made to make them 3 consistent with the program descriptions in the GALL 4 report.
5 For example, the River Bend buried piping 6 program was initiated in response to the 2009 NEI 7 initiative, but significant changes are necessary to 8 incorporate the latest NRC guidance which includes 9 interim staff guidance issued in 2015. For clarity 10 in describing the program, Entergy classified it as 11 a new program that would be consistent with the program 12 described in the most recent NRC guidance.
13 In addition, most of these new programs 14 have already been implemented in other Entergy nuclear 15 plants. This allows us to ensure that implementation 16 of the River Bend aging management programs reaps the 17 benefits of lessons learned from the Entergy operating 18 experience review program and the corrective action 19 program.
20 The 30 existing programs have been compared 21 to the GALL programs, and only a few exceptions have 22 been taken. These exceptions include such things as 23 revised inspection intervals based on the River Bend 24 refueling outage schedules and referencing NRC guidance 25 regulatory guides and industry standards that are later NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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41 1 revisions than those referenced in the GALL report which 2 was published in 2010.
3 And finally, we have one plant-specific 4 program which is the periodic surveillance and 5 preventative maintenance program. This program 6 includes a variety of aging activities that could not 7 readily fit within the scope of the GALL review programs 8 without taking exceptions to those provisions.
9 And at this point, we can talk about the 10 diesel crankcase vent, if it's appropriate.
11 MEMBER BALLINGER: I have --
12 MR. YOUNG: It's the last -- oh, sorry.
13 MEMBER BALLINGER: -- another question.
14 I didn't notice it in the presentation. So in going 15 through the audit and going through the SER and going 16 through this, I could not for the life of me figure 17 out what the current status was of the shroud -- the 18 core shroud. What is the current status of the shroud?
19 MR. SHERMAN: I'm Todd Sherman from 20 Entergy. I'm the vessel internal engineer. The 21 current status of the shroud is per the BWR 22 VIP-76-1-alpha. We are classified as a Category 23 Charlie or Category C shroud.
24 MEMBER BALLINGER: Yeah, you were A, then 25 you got --
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42 1 MR. SHERMAN: We were at the Bravo --
2 MEMBER BALLINGER: I got that right, yes.
3 MR. SHERMAN: -- prior to the last outage.
4 MEMBER BALLINGER: So I got that part.
5 But then there was -- how much crack do you have? And 6 what's the five cycle conductivity been trending?
7 MR. SHERMAN: We inspected the shroud 8 three times previous. Specifically the weld that is 9 in question is the H-4 --
10 MEMBER BALLINGER: H-4, yes.
11 MR. SHERMAN: -- beltline weld. It was 12 first inspected in 1997 with no identified cracking, 13 and that was performed from the outer diameter with 14 a little over 50 percent of the welding being inspected.
15 And then it was inspected again in 2008 from the inner 16 diameter with approximately 90 percent of the coverage 17 inspected. And it was found to have about nine percent 18 of the inspected length had flaws or cracks in it.
19 And we reinspected again in 2017 from the 20 outer diameter. We inspected once again a little over 21 50 percent of the length of the weld. And I don't 22 remember the exact figure but I believe it was between 23 40-50 percent of what was inspected was found to have 24 flaws or cracks in it.
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43 1 that's been applied?
2 MR. SHERMAN: Correct. We have evaluated 3 the shroud according to the flaw evaluation criteria 4 in BWR-76 and found that it still meets the maximum 5 inspection interval that there's enough structural 6 integrity maintained in the remaining uncracked 7 ligaments of the weld.
8 MEMBER BALLINGER: And that applies out 9 to the license extension length?
10 MR. SHERMAN: The next scheduled 11 inspection would be 2027 which I believe is beyond the 12 expiration of the current license.
13 MEMBER BALLINGER: Okay.
14 MR. SHERMAN: Yes?
15 MEMBER BALLINGER: And who made the 16 shroud? Who made the shroud?
17 MR. SHERMAN: I believe it's Sun 18 Shipbuilders. I'd have to look.
19 MEMBER BALLINGER: Okay. Because it 20 makes a difference.
21 MR. SHERMAN: Yes.
22 MEMBER BALLINGER: It makes a difference.
23 MR. SHERMAN: Finding the manufacturer has 24 been a big player to who gets cracked and when.
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44 1 staff. I was responsible for the review of the BWR 2 vessel internals program. If you ask the same question 3 when the staff presents, I'll explain what I did to 4 look at it and to review everything that Todd just talked 5 about here.
6 MEMBER BALLINGER: Right. Thank you.
7 CHAIRMAN SKILLMAN: If you would like to 8 talk about the crankcase vent now, that's fine.
9 MR. YOUNG: Okay.
10 CHAIRMAN SKILLMAN: But let me tell you 11 how we got to this part of the discussion.
12 MR. YOUNG: Okay.
13 CHAIRMAN SKILLMAN: In the safety 14 evaluation, page 2-50, is the statement, Entergy 15 responded to an RAI stating the subject diesel crankcase 16 vent pipes do not have a license renewal intended 17 function since venting the crankcase is not necessary 18 for the diesel to operate under emergency conditions.
19 So this marine engineer with an unlimited horsepower 20 diesel engine license says, I'm not sailing on that 21 ship.
22 (Laughter.)
23 MR. YOUNG: Right. And we agree. That 24 statement is incorrect.
25 CHAIRMAN SKILLMAN: Thank you.
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45 1 MR. YOUNG: Based on the comments that 2 you've provided and the statement in the SER, we're 3 preparing a supplement to that RAI response. And we 4 agree that venting of the subject diesel generator 5 crankcases is necessary. The original RAI response 6 should have more clearly stated that the vent line 7 intended function was to vent the crankcases outside 8 the diesel rooms.
9 And the potential failure of the vent line 10 due to aging effects would be loss of pressure boundary 11 which would not result in the loss of a vent function, 12 but it would result in a loss of venting outside the 13 diesel room. And that would not impact the safe 14 operation of the standby diesel generators.
15 CHAIRMAN SKILLMAN: It might mess up the 16 room, but it won't impact the diesel.
17 MR. YOUNG: Right. And therefore, we will 18 be submitting an RAI supplement to the NRC staff to 19 remove the statement that the crankcase venting is 20 unnecessary.
21 CHAIRMAN SKILLMAN: Thank you.
22 MR. YOUNG: Okay.
23 CHAIRMAN SKILLMAN: Please proceed.
24 MR. YOUNG: Okay. On this slide, on the 25 topic of commitment management and controlling the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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46 1 commitments that we've made for license renewal, 2 Entergy has a fleet program that covers management of 3 commitments for all our nuclear plants including 4 commitments for license renewal.
5 Entergy's program is based on the 6 commitment management guidance in NEI 99-04 that the 7 NRC staff has endorsed. We have successfully used this 8 commitment management program for our previous license 9 renewal projects including projects for plants that 10 implemented license renewal commitments and are 11 successfully operating in the period of extended 12 operation.
13 For each River Bend license renewal 14 commitment, the commitment management program 15 identifies the actions needed to implement the 16 commitments and identifies the owner responsible for 17 its implementation. Assignments will include actions 18 such as a creation of implementing procedures for new 19 aging management programs and implementation of 20 enhancements to existing aging management programs.
21 And that completes my portion of the 22 presentation, and I'll turn it over to --
23 CHAIRMAN SKILLMAN: Thank you, Garry.
24 MR. YOUNG: -- John Ventosa.
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47 1 meeting with us this afternoon. We truly do appreciate 2 the challenges and borderline, I guess, advice with 3 some of the modifications you spoke to. And we will 4 act upon each and every comment. So we do appreciate 5 that.
6 We are fully committed to continuously 7 improving our aging management programs, but we do have 8 strong ownership at the site of those programs. And 9 we fundamentally sound path successfully managing the 10 aging effects through 60 years of operations.
11 And in addition, Entergy is committed to 12 continuously investing in the plants, and I think we've 13 showed you that today in plant modifications to ensure 14 the safe, reliable operation through the period of 15 extended operations.
16 If there's no further questions, that 17 concludes our presentation. Thank you.
18 CHAIRMAN SKILLMAN: John, thank you.
19 Just to hold here, colleagues. Before we change teams, 20 might any of you have a question for the Entergy 21 leadership here?
22 MEMBER BROWN: I just wanted to amplify 23 a perspective a little bit on that earlier comment.
24 This system is an in-plant system and is largely within 25 a boundary. But if you -- even though you probably NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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48 1 don't have them defined this way, it would be called 2 a Level 4 security from an access standpoint.
3 This is really not a programmatic issue 4 as much as it is a control of access -- remote access 5 issue. And my fundamental concern I've tried to convey 6 is that while my statement is not 100 percent correct, 7 almost all cyber issues and upgrades and revisions are 8 reactive.
9 In other words, you are always responding 10 to what has already killed somebody else. And nobody 11 is out there sitting there, oh, gee, the guy could make 12 access this way or that way. You're not preventing 13 all circumstances. There are always holes. Now, that 14 is not exactly -- there are some obvious holes that 15 you can plug. But there is the non-obvious ones that 16 you can't, and that's where all the problems come about.
17 That's why I would encourage you -- I was 18 going to ask the question on your circuit breaker.
19 I presume those are digital-based circuit breaker 20 controls. Same issue as if you had those connected 21 into a distributed control system or they're via part 22 of the big network that has direct access from external 23 sources.
24 Such that if you do, if some of them --
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49 1 some of those breakers for some reason, you don't have 2 any choice. More than likely, that's where all of your 3 internal control breakers, the big ones or small ones.
4 It's best to just keep them totally isolated from the 5 outside world.
6 It wasn't problem in the old days when you 7 turned a switch and a little current went and tripped 8 a relay. And the words we used to have in the documents 9 like control of access and things like that for 10 instrumentation control were pretty fundamentally 11 based on the old analog world that we lived in. And 12 that's the whole thing has changed now relative to the 13 ability to get to a system to do things with them.
14 So I mean, it's just a little more 15 perspective. That's all I'm -- obviously, I'm not 16 trying to tell you, you can't do them. And that's not 17 the point. It's just to be very, very thoughtful about 18 how you allow that access. You can hurt yourself in 19 the long run.
20 MR. VENTOSA: No, we definitely appreciate 21 the insight.
22 MEMBER BROWN: Thank you.
23 MR. SANDLIN: This is Dan Sandlin again.
24 I want to talk to your point. The BWR level control 25 upgrade will be an extension of the existing Ovation NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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50 1 system and has already been inspected by Sam -- I can't 2 remember. He was talking on the -- we were the first 3 plant to be cybersecurity inspected, and that Ovation 4 system was already there. They looked at it in depth 5 and found no issues. We do have data diodes. You can't 6 talk into it. You can talk out, but you can't talk 7 in. It's part of our process.
8 MEMBER BROWN: Are they hardware data 9 diodes or they're --
10 MR. SANDLIN: Yes.
11 MEMBER BROWN: -- software? In other 12 words, it's a physical hardware? You might have 13 something that can give you a transmitted receive, but 14 you disconnect the receive. That's the point.
15 MR. SANDLIN: They can't get into us.
16 MEMBER BROWN: Okay. That's fine.
17 You've thought it then.
18 MR. SANDLIN: We did, yes.
19 MEMBER BROWN: Just saying somebody has 20 reviewed Ovation. I remember this has been several 21 years ago when I saw it. And it definitely had 22 bidirectional -- the ability to be communicated 23 bidirectional. And you have to physically make it --
24 you want to make it physically impossible to do so.
25 So thanks.
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51 1 MR. SANDLIN: For the digital breakers, 2 they are independent, standalone. There's no 3 connections to it.
4 MEMBER BROWN: No connections? Okay.
5 Excellent, thank you.
6 CHAIRMAN SKILLMAN: Thank you, Charlie.
7 Yes sir, thank you. Colleagues, any other comments 8 for the Entergy team? If not, let's swap teams and 9 keep on going. Joe, your team is up.
10 (Pause.)
11 CHAIRMAN SKILLMAN: Manny, whenever 12 you're ready, please.
13 MR. SAYOC: Is that on?
14 CHAIRMAN SKILLMAN: Yes sir, yes.
15 MR. SAYOC: Again, good afternoon, 16 Chairman Skillman and members of the License Renewal 17 Subcommittee. My name is Emmanuel Sayoc, and I am the 18 project manager for the River Bend Station, Unit 1 19 License Renewal Safety Review.
20 We are here today to discuss the staff's 21 review of RBS license renewal application, or LRA, as 22 documented in our safety evaluation report issued 23 August 16, 2018. Joining me here at the table are Dr.
24 Allen Hiser, the LR Senior Technical Advisor, and Mr.
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52 1 be running the slides.
2 Mr. Samuel Graves, Senior Reactor 3 Inspector from Region IV is on the phone and will discuss 4 the 71002 inspection. Sitting in the audience and on 5 the phone are members of the technical staff who 6 participated in the review of the national application 7 and conducted the various audits. Next slide, please.
8 I will begin the presentation with a 9 general overview of the staff's review. Next, Mr.
10 Graves will present the 71002 inspection results. I 11 will then present the main sections of the safety 12 evaluation report. Next slide, please.
13 On May 25, 2017, Entergy Louisiana, LLC 14 and Entergy Operations, Inc. -- collectively referred 15 to as Entergy or the applicant -- submitted an 16 application for the renewal of RBS operating license 17 for an additional 20 years. The RBS license renewal 18 review process was optimized from previous license 19 reviews including the Waterford review that you heard 20 about this morning.
21 In particular, the RBS license renewal 22 review used an 18-month schedule with expanded audits 23 and a streamlined SER that was issued in August 2018.
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53 1 applications.
2 Consistent with prior license renewal 3 reviews, the staff conducted three centered audits as 4 shown in the slide. The operating experience audit 5 was conducted at local offices that are within walking 6 distance with NRC headquarters.
7 The scoping and screening audit and the 8 regional site one and two inspection was done onsite 9 at River Bend.
10 The AMP audits were expanded to about ten 11 weeks and included document reviews via electronic 12 portal and applicant interviews conducted from the NRC 13 headquarters. There was a portion done onsite at River 14 Bend to perform system walk downs.
15 During the operating experience audit, the 16 team conducted an independent search of the plant 17 operating experience for information to determine, "A",
18 whether previously known or recurring aging effects 19 were identified, and "B", whether in light of the plant 20 operating experience, the applicant's LRA aging 21 management program can adequately manage the associated 22 aging effects. The operating experience audit results 23 were documented in a report dated January 8, 2018.
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54 1 administrative controls governing the scoping and 2 screening methodology and the technical basis for 3 selected scoping and screening results. The scoping 4 and screening methodology audit report results were 5 documented in a report dated January 8, 2018.
6 During the AMP audits, the team examined 7 applicant's aging management programs and related 8 documentation to verify the applicant's programs were 9 consistent with those described in GALL report and with 10 plant conditions and operating experience. The staff 11 reviewed the 43 AMPs outlined in the LRA and documented 12 the results in a report dated January 29, 2018.
13 Mr. Graves will discuss the activities of 14 the 71002 inspection in a few minutes. Next slide.
15 As discussed before, the RBS final SER was 16 issued on August 16, 2018 with no open items or 17 confirmatory items. During the staff's in-depth 18 technical review of the LRA, a total of 119 RAIs were 19 issued, 15 of which were follow-up RAIs. The final 20 SER will be published as a NUREG following issuance 21 of the new license.
22 I will now direct the presentation to Mr.
23 Graves who will discuss the inspection activities and 24 results associated with this LRA review. Next slide.
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55 1 afternoon, subcommittee members. My name is Sam 2 Graves. I'm a senior reactor inspector in the Region 3 IV office, and my branch is responsible for performing 4 license renewal inspections. This inspection involves 5 four experienced regional inspections with expertise 6 in electrical, civil, nuclear, and mechanical 7 engineering.
8 The team was onsite February 26th through 9 March 19th, and the inspection report was issued on 10 May 7th. The team reviewed the scoping and screening 11 of components, walk down accessible areas and reviewed 12 25 aging management programs of which 6 were new 13 programs and 19 were existing.
14 The team walked down numerous structures, 15 systems, and components to assess the adequacy of the 16 applicant's license renewal boundaries, material 17 condition, and conformance with their application and 18 the Generic Aging Lessons-Learned report. Next slide, 19 please.
20 From the walk down, the team determined 21 that the material condition of the facility was very 22 good with one exception that the applicant was 23 addressing related to some corrosion on piping located 24 in the below ground level piping tunnels.
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56 1 humid, and the pipes were relatively cold resulting 2 in a lot of condensation formation and some subsequent 3 surface corrosion. The applicant was in the process 4 of remediating the pipe to remove the existing surface 5 corrosion and applying an oxy type paint.
6 For the surface water integrity program, 7 the applicant had been performing heat exchanger 8 inspections in their service water system for many years 9 but had not considered crediting these existing 10 inspections as part of their aging management program.
11 The applicant agreed to include the inspections they 12 were already performing into their plant-specific 13 Periodic Surveillance and Preventive Maintenance aging 14 management program. Next slide, please.
15 So in summary, the team concluded that the 16 applicant performed the scoping and screening in 17 accordance with the rule. The team found that the 18 information was easily retrievable, auditable, and 19 consistent with the rule. The team verified that the 20 existing programs were effective in managing aging 21 effects, and the new programs provided reasonable 22 assurance that aging effects will be managed. The team 23 also verified that the applicant had a process to track 24 the completion of enhancements and the development of 25 the new programs.
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57 1 So based on the inspection results, the 2 team had reasonable assurance that the programs in place 3 or planned as described in their commitment table will 4 manage the aging effects and ensure the intended safety 5 functions of systems, structures, and components within 6 the scope of the rule.
7 Are there any questions for me?
8 CHAIRMAN SKILLMAN: Sam, thank you. I do 9 have several questions. This is Dick Skillman.
10 MR. GRAVES: Yes sir.
11 CHAIRMAN SKILLMAN: On page 8 of your 12 inspection report, in the middle of the page, the text 13 is as follows. This is regarding bolting integrity.
14 It is Bravo, 1, 2, and it's Roman IX, M18 is the program.
15 The sentence that I'm sentence that I'm 16 focusing on is this sentence: The second exception 17 related to the inaccessible services of the suppression 18 pull suction strainer submerged bolting. The 19 applicant requested to conducted visual inspection once 20 every ten years instead of once every refueling cycle.
21 The applicant planned to verify the bolting was hand 22 tight.
23 That doesn't make sense to me. What in 24 the world does that mean?
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58 1 is that the bolts are normally drilled and lock wired 2 in place. So if they have demonstrated any loosening, 3 the manipulation with your hands would be able to 4 determine that. And from there, that would lead to 5 remedial action.
6 If I remember correctly discussing it with 7 a team leader, they weren't really trying to communicate 8 that you wouldn't put any torque on it. You'd just 9 screw it down mechanic tight or hand tight. That, I 10 don't think, was what they intended to try to 11 communicate in that section.
12 CHAIRMAN SKILLMAN: Just hold on here.
13 Let's get a licensee person who understands hand tight 14 versus torque to 90 or 250-foot pounds and find out 15 what the answer is. Can someone from Entergy tell us 16 what hand tight means on these very important flanges?
17 MR. SANDLIN: I believe the intent -- this 18 is Dean Sandlin. I'm sorry. The intent was they were 19 torqued originally to the torqueing requirements. And 20 if they had come loose, it would be secured with the 21 tie wraps -- I mean, the lock wire that we put on anything 22 over the pool area. And if they had come loose, we'd 23 be able to detect by the diver going down and seeing 24 if the connection was loose.
25 CHAIRMAN SKILLMAN: That's fair enough.
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59 1 That's what Sam just explained too. That's all right.
2 It's just the only evidence that the ACRS members of 3 these inspections is what was provided in the SER.
4 And please know that my team members and I read this 5 stuff very carefully so that we discharge our 6 responsibilities as we should. So thank you.
7 Sam, I've got another one.
8 MR. GRAVES: Yes sir.
9 CHAIRMAN SKILLMAN: So on your inspection 10 report, pages 10 and 11, and the wording that caught 11 my attention is this wording at the top of page 11.
12 This is regarding enhancements on one of the programs.
13 And what is important is the way this text reads.
14 The text reads, at least two years prior 15 to entering the period of extended operation, the 16 applicant planned to develop a set of fatigue usage 17 calculations that consider the effects of the reactor 18 water environment for a set of the most limiting reactor 19 coolant system components, considering all stress 20 components for environmentally assisted fatigue, and 21 use the maximum temperature if the average temperature 22 is below the threshold.
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60 1 for something that just might happen if it happens at 2 all. So I'm wondering what is the firmness of this 3 commitment.
4 MR. GRAVES: Well, sir, that's a good 5 question. I cannot answer the firmness of the 6 commitment. That would certainly be something to 7 direct to the licensee. But our impression was that 8 that was their intention.
9 CHAIRMAN SKILLMAN: Fair enough. Now, 10 we're going to ask someone from the licensee to tell 11 us what it means.
12 MR. MIN: Yes, this is Seung Min with the 13 staff first. And then if I address that question that 14 there is a difference between the current license basis 15 particularly on these requirements mainly based on 16 appendix -- I'm sorry,Section III of ASME code.
17 Before the fatigue analysis, TLA. If we 18 take TLA for the period of extended operation, 19 environmental effects need to be considered. That 20 portion either dealt between the PEO fatigue analysis 21 and the CLB fatigue analysis for to fill in the gap.
22 The applicant identified the enhancement to implement 23 to identify the locations involved environmentally set 24 fatigue analysis. That's all.
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61 1 someone from Entergy confirm that this is a commitment 2 that's embedded in your commitment list?
3 MR. COX: Yes, this is Alan Cox. I'm 4 looking at the commitment list in the SER, and 5 Commitment No. 11 is on the fatigue monitoring program.
6 It says, to enhance it as described in LRA Section 7 A.1.18. And in that section, it discusses this. And 8 the due date for this commitment is enhancement to 9 develop a set of fatigue uses calculations prior to 10 August 29, 2023. And that's the two years prior to.
11 So it is a formal commitment as documented in the SER.
12 CHAIRMAN SKILLMAN: Yes sir. Alan, thank 13 you very much. Thank you.
14 Sam, that concludes my comments. Thank 15 you for a very thorough inspection, and that ends my 16 questions on the inspection report.
17 Manny, back to you.
18 MR. SCHULTZ: Just one. Sam, I think --
19 this is Steve Schultz. This may be a comment more than 20 a question, but I'd like you to respond. On your last 21 page of discussion, you've indicated that in performing 22 the audit at the site, the information was easily 23 retrievable and auditable. And then you follow that 24 with a conclusion that existing programs effectively 25 managed aging effect.
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62 1 And my impression is in reading the audit 2 reports, not only the documentation that you've been 3 able to provide and following through the track of 4 inspection that you've accomplished at the site that, 5 in fact, these summary statements are very accurate.
6 You provide a lot of good information in each of the 7 areas to support your conclusions that are presented 8 in the audit.
9 I also notice as I look through the listing 10 of items that you draw from the documentation at the 11 site that there seems to be in many of the areas that 12 you inspect, if I look at the time history of what you 13 pulled as documentation, that there seems to be an 14 improvement in plant condition, at least based on the 15 chronological reporting of events.
16 Am I drawing a proper conclusion, or did 17 I just happen to see things that looked like they 18 demonstrate that trend?
19 MR. GRAVES: I can tell you my 20 communication with the team leader, he was actually 21 very favorably impressed with the material condition 22 of River Bend Station. Greg Pick was the lead inspector 23 on this, and he's done a number of these inspections 24 throughout the region. And he said that this was the 25 most impressive material condition he had seen. So NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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63 1 I think your conclusions, not 100 percent sure how you 2 got there, but that is exactly the conclusion he came 3 to as well.
4 MR. SCHULTZ: Thank you. I'm not taking 5 that as a full confirmation. I just wanted to talk 6 with you about it and get your impressions.
7 MR. GRAVES: I know we very much appreciate 8 that. We try to make the inspection reports thorough 9 and we try to use language that will communicate the 10 issues. And as inspectors, if we say something is 11 adequate, that's typically a pretty tall compliment 12 for an NRC inspector.
13 MR. SCHULTZ: I understand that.
14 MR. GRAVES: Yes sir. So that's why some 15 of the wording is the way it is. But yes sir, thank 16 you very much.
17 MR. SCHULTZ: Well, your document says --
18 the slides we have say that the material condition is 19 good. I think you amplified that by saying it was very 20 good when you made your report today.
21 MR. GRAVES: Yes sir, I did.
22 MR. SCHULTZ: But I'm not taking that --
23 I'll take it as you've just stated it. I appreciate 24 that. Thank you very much.
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64 1 I think I'm finished. Your turn.
2 MR. SAYOC: Thank you, Sam. We're on 3 Slide 8. In the next few slides, I will present the 4 results of the staff's review of the LRA as described 5 in the SER. SER Section 2 described scoping and 6 screening of structures and components subject to aging 7 management review. The staff reviewed the applicant's 8 scoping and screening methodology, procedures, quality 9 controls applicable to the LRA development and training 10 of project personnel.
11 The staff also reviewed the various 12 summaries of safety-related systems, structures, and 13 components or SSCs, non-safety SSCs affecting functions 14 of safety-related components and SSCs relied upon to 15 perform functions applicable to River Bend in 16 compliance with the emissions, regulations for fire 17 protection, environmental qualification, station 18 blackout, and anticipated transients without scram.
19 Based on the review, the results from the 20 scoping and screening audit, and additional information 21 provided by the applicant, the staff concludes that 22 the applicant's scoping and screening methodology and 23 implementation was consistent with the standard view 24 plan and the requirements of 10 CFR Part 54. Next 25 slide, please.
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65 1 CHAIRMAN SKILLMAN: Manny, let me ask one 2 or two questions that is on SER Section 2. On SER, 3 page 2-7, at the bottom of the page, the NRC writes 4 this sentence. It is in response to non-safety-related 5 SSCs providing functional support for safety-related 6 SSC functions. And this is the sentence that I 7 challenge.
8 MR. SAYOC: Okay.
9 CHAIRMAN SKILLMAN: One safety-related 10 SSC supporting 10 CFR 50.54(a)(1) was identified, the 11 plant drains system, which supports maintaining 12 suppression pool inventory for use following a LOCA.
13 And the conclusion of that section is, based on the 14 above, the methodology for identifying non-safety SSCs 15 whose failure could prevent satisfactory 16 accomplishment of the intended functions is in 17 accordance with 50.54(a)(2).
18 It sounds as if this is the single one and 19 only SSC. Is that an accurate conclusion?
20 MR. SAYOC: If I am understanding your 21 question, you're referring to the plant drains.
22 CHAIRMAN SKILLMAN: Yes, it sounds as if 23 that is the single one and only and there isn't anything 24 else. And that doesn't make sense. So could it be 25 it's just the wording of your SE? Or is this an example?
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66 1 And failing the words, an example, one would be led 2 to believe it's just this single and only one system?
3 MR. HISER: This is Allen Hiser of the 4 staff. I'd be surprised if this is the only system 5 that falls under this category. We can go back and 6 take a look at the SER and bring back to you any 7 clarification.
8 CHAIRMAN SKILLMAN: If you would, a 9 clarification. And it is page 2-7 of the safety 10 evaluation. And it is the last and final sentence on 11 that page.
12 I've got one other comment on Section 2.
13 This is an RAI response to RAI B.1.10-2. And this 14 has to do with the internal portions of the SLICK lines.
15 And the safety evaluation says, the internal portions 16 of the SLICK lines don't matter because they've boosted 17 the boring concentration 25 percent. And that leads 18 to the impression that the SLICK lines can fall apart 19 and you can still poison the core.
20 Well, it sounds like a dandy argument for 21 reactivity, but it doesn't sound like much of an 22 argument for structural integrity inside the reactor 23 vessel. So I'm wondering what the safety evaluation 24 really evaluated.
25 MR. HISER: Which page was that again?
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67 1 CHAIRMAN SKILLMAN: That is on SER, page 2 2-21 at the bottom of that page.
3 MR. SAYOC: I think that's from the staff, 4 Jim Medoff.
5 MR. MEDOFF: So, this was a matter that 6 was looked at by the staff, Mr. Summerson of DSS and 7 myself, as part of the vessel -- I'm sorry. This is 8 Jim Medoff of the staff. This was as an aspect of the 9 application that was investigated by the both of 10 Division of Safety and Safeguards and by the Division 11 of Materials and License and Renewal. It deals with 12 the way the vessel internals program manages the standby 13 liquid control system to manage an ATWS event.
14 In the approved report, the EPRI BWR VIP 15 has concluded that the internal portions of this SLICK 16 system did not need to be age managed because even if 17 it broke, even if you had a through-all crack and the 18 component fail and you had a blob of boron water coming 19 into the reactor near in the lower plenum, what would 20 happen is eventually the reactor coolant would start 21 to heat up and then it would promote some natural 22 circulation to get the boron up towards the core where 23 you needed it.
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68 1 start to cool down and instead you would get this 2 reiterative cycle to make sure you got boron cooling 3 in the core. For that reason, Entergy did not include 4 the internal portions of volume and scope and we 5 wondered about that. We did think about it.
6 And so we basically asked them a question.
7 We wanted to assume. Let's assume that the VIP report 8 is it's questionable, I think, that it really occurred.
9 We asked the question, would you really get adequate 10 mixing if the line broke? Because it's serving a safe 11 shutdown function.
12 From that perspective, we asked a question 13 on that. And we had a teleconference, and Entergy had 14 replied that they had something in their design basis 15 that would account for inadequate mixing which was our 16 big issue on the review.
17 What we did is we went back to the FSAR 18 in the design basis. We did find a statement in their 19 ATWS evaluation and their SLICK system operational 20 statements that said they included an additional 25 21 percent of boron into the boron control tank which would 22 account for any questions of inadequate mixing which 23 alleviated our concern with the potential through all 24 flaw and warming.
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69 1 your concern?
2 MR. MEDOFF: Because the question is 3 whether the mixing argument in the approved VIP report 4 would be okay. We had a big discussion with this with 5 the folks in DSS. The conclusion was the additional 6 25 percent for Entergy should be sufficient to address 7 any questions on whether they put adequate mixing if 8 you had a through-all flaw in the line.
9 CHAIRMAN SKILLMAN: And is all of that 10 documented?
11 MR. MEDOFF: Some of it's documented in 12 the scoping section. Some of it's documented in the 13 review of the AMP and in the audit report. So there's 14 another section which would be the Section 3, a section 15 for the reactor vessel internals AMP that should discuss 16 that as well in one of the action item responses.
17 CHAIRMAN SKILLMAN: Thank you. Go ahead, 18 Manny. Thank you.
19 MR. SAYOC: SER Chapter 3 in its 20 subsections covers the staff's review of aging 21 management programs for managing aging in accordance 22 with 10 CFR 54.21(a)(3). Chapters 3.1 through 3.6 23 include the aging management review items in each of 24 the general system areas within scope of license 25 renewal.
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70 1 For a given aging management review, the 2 staff reviewed the item to determine whether it is 3 consistent with the GALL report. If an aging 4 management review is not consistent with the GALL 5 report, then the staff reviewed the applicant's 6 evaluation to determine with the applicant has 7 demonstrated assurance that the effects of aging will 8 be adequately managed so that intended functions will 9 be maintained consistent with the current licensing 10 basis for the period of extended operation. Next 11 slide.
12 The LRA describe a total of 43 aging 13 management programs: 11 new, 31 existing, and one 14 plant-specific. This slide identifies the applicant's 15 disposition of AMPs on the left column and the final 16 disposition of AMPs as a result of the staff's review 17 on the right column.
18 One plant-specific AMP was provided, all 19 with the exception of the plant-specific AMP were 20 evaluated by the staff for consistency with GALL report, 21 Rev. 2. Overall, the staff concluded that 22 AMPs were 22 consistent with the GALL report. These included 12 23 new programs and 10 existing programs.
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71 1 5 were consistent with enhancements and exceptions.
2 RBS has one plant-specific program. Later in the 3 presentation, we will discuss an existing program that 4 was replaced and thus became a new program. Next slide, 5 please.
6 Section 4 identifies time-limited aging 7 analyses, or TLAAs. Section 4.1 documents the staff's 8 evaluation of the applicant's identification of 9 applicable TLAAs. The staff evaluated the applicant's 10 basis for identifying those plant-specific or generic 11 analyses that need to be identified as TLAAs and 12 determine that the applicant has provided an accurate 13 list of TLAAs as required by 10 CFR 54.21(c)(1).
14 Sections 4.2 through 4.7 document the 15 staff's review of applicable TLAAs as shown. Based 16 on its review of the information provided by the 17 applicant, the staff concludes that either the analysis 18 remained valid for the period of extended operation, 19 the analysis has been projected to the end of period 20 of extended operation, or the effects of aging on the 21 intended functions will be adequately managed for the 22 period of extended operation as required by 10 CFR 23 54.21(c)(1)(i), (ii), and (iii) respectively. Next 24 slide, please.
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72 1 items, we wanted to highlight a few areas of interest 2 in our review. The first area is related to the reactor 3 vessel of neutron fluence TLAA. In its review, the 4 staff identified an issue with the methodology used 5 to calculate the 60-year neutron fluence values -- I'm 6 sorry, fluence levels for the reactor pressure vessel 7 RPV.
8 The LRA stated it used an NRC-approved 9 methodology to determine the neutron fluence values.
10 However, the staff noted that the staff approved 11 methodology is not applicable to RPV beltline 12 components above the active fuel region. The staff 13 therefore issued an RAI requesting justification on 14 how the methodology was expanded to incorporate the 15 qualified above core calculation model.
16 In its response, Entergy provided 17 additional core design conservatisms that justified 18 neutron fluence values for the RPV, including the 19 components above the active fuel region.
20 Specifically, the applicant stated that the 21 conservatisms in this methodology accounts for 22 potential uncertainties in the above core water 23 densities and considers the bounding power-flow state 24 point that leads to higher neutron fluence.
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73 1 demonstration that the 60-year neutron fluence values 2 in the LRA are conservative and meet the intent of 3 guidelines in Reg. Guide 1.190 which demonstrates --
4 sorry, which describes methods and assumptions 5 acceptable to the NRC for calculating a neutron fluence.
6 The staff therefore concluded that 7 associates TLAAs were demonstrated to be acceptable 8 for 10 CFR 54.21(c)(1)(ii). Next slide.
9 MR. SCHULTZ: Emmanuel, one question 10 associated with the vessel neutron fluence. And I 11 guess it really occurred to me to look at this further 12 with respect to the evaluations we discussed this 13 morning at Waterford in this area.
14 The SER talks about, just as it is on the 15 slide here, a conclusion that is based upon these 16 conservatisms. Did the staff do any audit calculations 17 or anything to demonstrate that what has been reported 18 as conservatisms are validated or is there some 19 experience that the staff has that led you to agree 20 with the conclusions that were being presented? That's 21 one question.
22 The other question I have is, was this 23 information presented by the vendor or was it performed 24 and presented by the applicant?
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74 1 question. We have Mr. Amrit Patel that I think can 2 better answer your question.
3 MR. SCHULTZ: Thank you.
4 MR. PATEL: I'm Amrit Patel from the tech 5 staff. So the staff didn't base this on anything from 6 an audit. So there were no staff performed 7 calculations to verify that. It was based solely on 8 our information submitted through RAI responses based 9 on staff questioning of the qualification and 10 validation of the method for these above core region.
11 So the majority of that response is 12 proprietary, so that's kind of why it's couched in terms 13 of conservatisms. But there are several layers of 14 conservatism in the qualification. So a lot of that 15 is focused on the above core voiding distribution which 16 has a direct influence on the flow -- direct impact 17 on the fluence. But it's purely the applicant's 18 assessment or analysis.
19 MR. SCHULTZ: You're right. I didn't 20 appreciate the proprietary nature of the calculations 21 and the results thereof. So now, I better understand.
22 Because recently, that is since this morning, I was 23 looking at the SER particularly. So now, I understand 24 why the details aren't there. I had looked at the RAI, 25 and I know what details are there, the RAI response.
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75 1 The other question I had with regard to 2 the SER presentation of information is that there was 3 an error noted and it was pretty late in the game, in 4 August, associated with the effect of pull power year 5 calculation that had been done. I didn't know which 6 direction that error was made. I presumed it was an 7 issue where you needed to demonstrate more fully the 8 ability of the conservatisms to account for the final 9 results.
10 MR. PATEL: So my understanding, I wasn't 11 directly involved in the finding. But if my memory 12 serves me right, it was related to a transposition 13 error.
14 MR. SCHULTZ: Yes.
15 MR. PATEL: Right. And I do recall it was 16 quite minor. The relative change in -- yes, if you 17 want to --
18 MR. SCHULTZ: Only if you're not 19 performing the calculation.
20 MR. PATEL: Right, but I think the way --
21 yes, if I understand, I think -- oh, can you speak to 22 it? Okay.
23 MR. SCHULTZ: I'd appreciate that. Thank 24 you.
25 MR. SHERMAN: Todd Sherman from Entergy.
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76 1 So unfortunately, the error that was found was in the 2 less conservative direction. And for the past 3 operating cycles, the vendor modeled them as-is. But 4 for the future projected cycles, they added on an 5 additional ten percent conservatism to account for 6 different core-to-core cycle variations.
7 And so the error that was found was 8 approximately .72 EEPY that were not added onto that 9 irradiation past cycle.
10 MR. SCHULTZ: A cycle is 10 to 11.
11 MR. SHERMAN: That is correct.
12 MR. SCHULTZ: Yes.
13 MR. SHERMAN: And so the ten percent margin 14 which was originally 2.866 of EEPY was reduced to 2.086.
15 So it just reduced the overall margin from the future 16 projected cycles irradiation.
17 MR. SCHULTZ: That helps a lot. Thank 18 you.
19 MR. SAYOC: Okay, thank you. The second 20 area of our review that we would like to highlight is 21 related to the use of polymeric material in high voltage 22 insulators. The staff noted high voltage insulators 23 made of polymeric material utilize in the recovery path 24 transmission lines. The applicant stated that 25 polymeric high voltage insulators were installed in NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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77 1 2008. However, the LRA only lists porcelain high 2 voltage material.
3 GALL has addressed porcelain high voltage 4 insulators but not polymeric high voltage insulators.
5 The staff noted that polymeric high voltage insulators 6 have unique aging mechanisms that can result in aging 7 effects such as loss of insulation resistance and loss 8 of material. Animal excrements containing chemicals 9 such as phosphates, ammonia, nitrates at present can 10 contribute to and accelerate aging as well.
11 Thus, the staff issued an RAI requesting 12 inclusion of the polymeric high voltage insulators and 13 evaluation of this site-specific material-evaluation 14 combination. The applicant responded by including the 15 polymeric high voltage insulators and provided an 16 evaluation of the pertinent aging mechanisms and aging 17 effects.
18 The applicant incorporated periodic 19 preventive maintenance and inspections to be relied 20 upon to monitor potential age-related degradation.
21 The staff concluded that inclusion of the polymeric 22 high voltage insulators in the LRA and periodic 23 preventive maintenance and inspections are acceptable.
24 Next slide, please.
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78 1 to highlight pertains to Entergy's new neutron 2 absorbing material program. The staff found this new 3 program to be consistent with GALL Report AMP XI.M40 4 and will adequately manage the effects of aging.
5 This is a replacement for the Boraflex 6 monitoring program that was previously credited for 7 neutron absorbing material. Due to degradation, 8 Boraflex material currently in the spent fuel pool will 9 not be able to maintain required sub-criticality margin 10 into the period of extended operation.
11 Entergy plans to submit an LAR for SNAP-IN 12 inserts by the end of the third quarter of 2018.
13 Installation is scheduled for June through October 14 2019, and aluminum boron-carbide neutron absorbing 15 material will be installed prior to the PEO. The staff 16 finds these acceptable. Next slide, please.
17 CHAIRMAN SKILLMAN: Manny, what 18 examination has the staff given to the new SNAP-IN 19 material and its survivability in the spent fuel pool?
20 MR. SAYOC: Okay. We have the staff.
21 MR. YODER: Matt Yoder from the NRC staff.
22 We previously reviewed and approved let's say on the 23 order of ten other license amendments for this material.
24 So it's well documented and well tested.
25 CHAIRMAN SKILLMAN: Okay, thank you.
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79 1 MEMBER MARCH-LEUBA: Okay. Excuse the 2 question then. What degradation was found on the 3 Boraflex?
4 MR. YODER: So again, this is Matt Yoder 5 from the staff. Boraflex material, essentially, it's 6 a polymer and it's dissolving. It's well documented 7 there had been multiple information notices, generic 8 letters, et cetera documenting this phenomena.
9 MEMBER MARCH-LEUBA: I guess you answered 10 my next question is it's a generic issue. And you're 11 saying there was a generic letter.
12 MR. YODER: Most plants that have this 13 material have done away with it either by replacing 14 with the SNAP-INs or using a geometric approach, 15 spreading the fuel out, if you have the room to do so.
16 MEMBER MARCH-LEUBA: Thank you.
17 MEMBER BALLINGER: When they change out 18 the Boraflex, the lifetime goes from essentially very 19 small to essentially infinity with the new material.
20 So it's a huge difference.
21 CHAIRMAN SKILLMAN: But let me ask this.
22 With the dissolution of the Boraflex, is the fuel that 23 is in the pool that is reintroduced to the core injured 24 in any way?
25 MR. YODER: Matt Yoder from the staff.
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80 1 There's no impact on the fuel.
2 CHAIRMAN SKILLMAN: How do you know?
3 MR. YODER: You do have silica going into 4 the water, and you're counting on your reactor water 5 cleanup system to take that out. As far as impact on 6 the actual fuel itself, but we're not aware of any impact 7 on the fuel.
8 CHAIRMAN SKILLMAN: I was just wondering 9 if there's any relationship between dissolution of 10 Boraflex and some of the fuel problems that you're 11 having for which you put in that great big filter.
12 MR. YODER: I would say no.
13 CHAIRMAN SKILLMAN: I would say no too, 14 but I just wanted to ask the question. Thank you.
15 Thank you.
16 MR. SAYOC: Okay, next slide. The final 17 item we want to highlight pertains to the emergency 18 diesel generator crankcase vent lines. This was an 19 item that was brought to the attention to the NRC staff 20 by the ACRS to review the conclusion that the vent lines 21 are not subject to aging management review. The staff 22 appreciates ACRS for giving this feedback.
23 In RAI 2.3.3.16-1, the staff noted that 24 the Division I and II Emergency Diesel Generator vent 25 lines as delineated in the Drawing LRA-PID-08-9B were NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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81 1 not depicted as being subject to AMR. The staff 2 question how the function of the venting crankcase where 3 the Division I and II Emergency Diesel Generators and 4 the HPCS diesel generator will be maintained during 5 the period of extended plant operations.
6 Entergy responded, in part, the function 7 of venting the crankcase is not necessary for the diesel 8 to operate under emergency conditions. This is shown 9 in the USAR Section 8311.4.1 which lists two sets of 10 conditions under which the diesel will trip, one set 11 for both normal and emergency conditions and one set 12 for normal conditions only.
13 The trip for high crankcase pressure is 14 only listed with a set for normal conditions and not 15 as a required trip for emergency conditions. In fact, 16 the non-emergency trips are bypassed on receipt of 17 emergency start signal.
18 Upon revisiting this issue and preparing 19 for this ACRS subcommittee meeting, the staff 20 determined that further clarification of the technical 21 content of the applicant's RAI is warranted. To 22 facilitate this clarification, the staff relayed this 23 issue to the applicant such that they would prepare 24 for a discussion here today.
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82 1 applicant needs to either justify to the NRC why the 2 EDG vent pipes do not have either a 54.4(a)(1) or (a)(2) 3 function. Or if they serve either a 54.4(a)(1) or 4 (a)(2) function, then the applicant needs to propose 5 an aging management program and AMR line items to age 6 manage the vent pipes.
7 As you heard today, Entergy plans to 8 supplement it's RAI response regarding this issue in 9 the upcoming weeks. The staff will review the 10 applicant's supplemental information for completeness.
11 Subsequently, the staff plans to amend the River Bend 12 license renewal safety evaluation report before ACRS 13 full committee meeting on November 1. Next slide.
14 MR. SCHULTZ: Your last comment answered 15 a question I was going to ask. In going through the 16 SER, there are many instances where the staff has 17 documented an additional commitment that was made by 18 Entergy as a part of the interactions that have gone 19 back and forth, especially through the responses to 20 the RAI. So the completion of that documentation is 21 going to be accomplished just in the next few weeks?
22 MR. SAYOC: Well, certainly for the case 23 of the crankcase, we'll --
24 MR. SCHULTZ: This one? Oh, okay.
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83 1 and see if there's any other items that we need to 2 complete as far as documentation. And we'll update 3 the SER prior to November 1, our full committee.
4 MR. SCHULTZ: November 1, okay. I noted 5 the -- I mean, the example I was looking at was this 6 stainless steel underground piping and a commitment 7 to increase the frequency of the inspection above and 8 beyond what was in the original proposal. It'd be two 9 inspections in ten years instead of one. Those things 10 are already documented?
11 MR. SAYOC: Do we have --
12 MR. DONOGHUE: This is Joe Donoghue. If 13 there's a commitment that the applicant made and we 14 relied upon it in our review, my expectation is that 15 they made it in the commitment list. Garry is to the 16 mic.
17 MR. YOUNG: Yes, this is Garry Young with 18 Entergy. The commitments and the changes to the 19 commitments that result from the RAI interaction that's 20 documented in the SER have all been captured.
21 And so when we talked about our commitment 22 management system, that includes the original 23 commitments and then all of the modifications to those 24 commitments. And then when the SER is finally 25 published in the final form, we will go back and verify NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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84 1 that we have correctly captured the changes to the 2 commitments that have occurred as documented in the 3 SER in our system that we have in the plant.
4 MR. SCHULTZ: Okay. So then it's 5 iterative and well understood who's doing what then?
6 MR. YOUNG: It's iterative and we have what 7 we call a living LRA where we capture all of this 8 information at the plant. And then by the time the 9 SER is published, we believe we have a completely 10 accurate picture. But we will verify it against the 11 results that are documented in the SER.
12 MR. SCHULTZ: Excellent. Go ahead.
13 MR. HISER: This is Allen Hiser of the 14 staff. And within the SER whenever there is a 15 commitment, there should be a commitment number 16 associated with it so it ties directly. If there is 17 not a number associated with it, then we need to go 18 back and make sure that it is on the list.
19 MR. SCHULTZ: Okay, good. Thank you.
20 MR. OESTERLE: This is Eric Oesterle from 21 the staff. Just another piece of the puzzle. When 22 we get ready to issue a renewed license, what we always 23 do is include a license condition which enforces rolling 24 all those commitments that we've relied on in the SER 25 into the plant's licensing basis the day that we issue NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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85 1 the renewed license. So it gets incorporated that day 2 into the UFSAR.
3 MR. SCHULTZ: Thank you.
4 MR. SAYOC: Okay. On the base of its 5 review, the staff determines that the requirements of 6 10 CFR 54.29(a) have been met for the license renewal 7 of River Bend Station, Unit 1. This concludes my 8 presentation now. If there are any questions, the 9 staff would like to take them at this time.
10 CHAIRMAN SKILLMAN: So colleagues around 11 the table, are there any further questions for the NRC 12 staff on the matter of River Bend license renewal?
13 MEMBER RICCARDELLA: I believe somebody 14 from the staff was going to brief us on the core shroud 15 cracking and how that is going to be monitored into 16 the period of extended operation.
17 MR. MEDOFF: So this is Jim Medoff of the 18 staff. I was responsible for the vessel internals 19 program review. Entergy -- as has been explained to 20 you before, this is a new process. So we didn't put 21 quite as much information in the SER. But a lot of 22 the things we did review are included in the audit 23 report.
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86 1 reports. And we did confirm it was an unrepaired shroud 2 and we were able to confirm that they assessed the extent 3 of cracking including taking into account some 4 proximity rules if cracks were close to one another.
5 What we didn't have from Entergy at the start was 6 whether they had re-categorized the shroud.
7 What we did was we asked them an RAI on 8 that and Todd Sherman, my counterpart at the utility, 9 explained that they did re-categorize the shroud and 10 they did put it in an RAI response. So that's 11 documented in the operating experience of the AMP 12 write-up for the VIP or vessel internals program. It's 13 in Section 3.0. And also, we have a write-up in the 14 audit report.
15 MEMBER BALLINGER: So let me ask the 16 question about the re-categorization. It's usually 17 re-categorized based on dose or fluence or 18 conductivity.
19 MR. MEDOFF: From what I can tell from my 20 reading of VIP 76-8 documents, re-categorization based 21 on flaw size reinspection.
22 MEMBER BALLINGER: Okay, flaw size.
23 Okay, all right. Because it's A, B, and C.
24 CHAIRMAN SKILLMAN: Colleagues, any other 25 questions for the staff before we release them?
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87 1 Hearing none, Manny, thank you very much.
2 MR. SAYOC: Thank you, sir.
3 CHAIRMAN SKILLMAN: At this point in the 4 meeting, I would like to ask if there are any individuals 5 in the room that would like to make a comment relative 6 to the license renewal activity for River Bend nuclear 7 station. Seeing none, if the phone line is open, if 8 someone is out there, would you please simply say hello.
9 PARTICIPANT: Hello.
10 CHAIRMAN SKILLMAN: Thank you. Now, if 11 anybody on the phone line would like to make a comment, 12 I invite you to do so at this time. Please introduce 13 yourself. Hearing none, Kent, please close the line.
14 Colleagues, any final comments for either 15 the NRC staff or the Entergy staff? Hearing none, Manny 16 and to your team, thank you for a very thorough 17 examination of River Bend. And to John Ventosa and 18 his crew from Entergy, thank you for bringing your team 19 all this distance and for the presentations that you 20 have presented to us today.
21 So to the staff and to Entergy, thank you.
22 And with that, we are adjourned.
23 (Whereupon, the above-entitled matter went 24 off the record at 3:15 p.m.)
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River Bend Station License Renewal
Entergy Presenters Name Title John Ventosa Chief Operating Officer-South James Henderson Director, Engineering Tim Schenk Manager, Regulatory Assurance Garry Young Director, Fleet License Renewal 1
Agenda
- Background
- Site Description
- Plant Status
- Licensing History
- Major Equipment Upgrades
- License Renewal Project
- License Renewal Application (LRA)
- Aging Management Programs and Commitments
- Conclusion 2
RBS Site Description
- Located in West Feliciana Parish, Louisiana, approximately 24 miles north-northwest of Baton Rouge, Louisiana
- General Electric NSSS - Stone & Webster (constructor)
- BWR-6, GE Mark III containment
- GE turbine generator 3
RBS Site Description
- Ultimate heat sink is independent wet cooling tower
- Closed circulating water system with mechanical draft cooling towers
- Licensed thermal power - 3091 MWt
- Staff complement - approximately 820 4
RBS Plant Status
- Plant Status
- 100% power month cycle
- ROP action matrix Column 1
- Last Refueling Outage
- RF19 (Spring 2017)
- Next Refueling Outage
- RF20 (Spring 2019) 5
RBS Licensing History Construction Permit March 25, 1977 Operating License November 20, 1985 Commercial Operation June 16, 1986 5% Power Uprate November 2000 Power Uprate License January 31, 2003 Amendment (1.7% Thermal Power Optimization)
LRA Submitted May 25, 2017 Operating License Expiration August 29, 2025 6
Major Equipment Upgrades Completed
- Upgraded digital EHC turbine controls
- Upgraded control building chiller controls
- Recoated underground circulating water piping
- Replaced inverters
- Replaced carbon steel piping
- Upgraded normal service water cooling tower
- Replaced 4th point feedwater heaters
- Upgraded 480 V load center breakers 7
Photos - Digital EHC Human Machine Interface for EHC on the H13-P680 Panel 8
Photos - 480 V Loadcenter Breakers 9
Photos - Carbon Steel Piping Replacement Carbon Steel Piping Replacement in RF-18 and RF-19 Old Carbon Steel removed New Carbon Steel Piping New Carbon Steel Piping 10
Major Equipment Upgrades Planned
- Turbine building chiller replacements
- Spent fuel pool neutron absorber upgrade
- Condenser upgrades
- Service water cooling heat exchanger refurbishment
- Fancy Point switchyard upgrades
- Recirculation pump power cable replacement
- Feedwater strainer
- Feedwater level control 11
Photos - Neutron Absorber Prototype Inserts Start of absorber insertion Full insertion. Ready to retract tool 12
Photos - Feedwater Strainer 13
Photos - Feedwater Level Controls 14
RBS MajorLicense Renewal Equipment Project Upgrades
- Experienced, multi-discipline Entergy team (corporate and site personnel) prepared the license renewal application (LRA)
- Incorporated lessons learned from previous applications
- Used NEI 95-10 guidance
- Scoping and screening process
- Aging management review
- LRA format and content
- Used Revision 2 of NUREG-1801
- 18-month NRC review schedule 15
Safety Evaluation Report
- SER issued August 2018
- No open items
- No confirmatory items 16
Major Aging Equipment Management Upgrades Programs and Regulatory Commitments
- 43 Aging Management Programs
- 12 new programs
- 12 consistent without exception
- 30 existing programs
- 10 consistent without exception
- 13 consistent with enhancements
- 2 consistent with exceptions
- 5 consistent with exceptions and enhancements
- 1 existing plant-specific program with enhancements 17
Program Commitment Implementation
- Regulatory commitments in the commitment management system track enhancements to existing programs and implementation of new programs
- Entergy has significant experience with license renewal commitment implementation
Conclusion
- Entergy is committed to the long-term operation and continuous improvement of our facilities.
- Entergy will manage the effects of aging in accordance with 10 CFR 54.21(a)(1)
- Entergy has evaluated time-limited aging analyses that require evaluation under 10 CFR 54.21(c)
- Entergy has met provisions of 10 CFR 54 for issuance of a renewed license.
19
Standby Diesel Crankcase Vent
- Agree wording is misleading - RAI supplement planned to clarify
- Aging effects would not prevent venting 20
Advisory Committee on Reactor Safeguards License Renewal Subcommittee River Bend Nuclear Generating Station Safety Evaluation Report (SER)
September 20, 2018 Emmanuel Sayoc, Project Manager Office of Nuclear Reactor Regulation
Presentation Outline
- Overview of River Bend Station (RBS) License Renewal Review
- Region IV 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 Audit / Inspection Dates Location Operating Experience October 2 - 13, 2017 Rockville Audit Scoping & Screening October 24 - 26, 2017 Onsite Methodology Audit Aging Management October 16 - November 8, 2017 NRC HQ Program (AMP) Audits November 6 - 10, 2017 Onsite Region IV 71002 February 26 - March 2, 2018 Onsite Inspection: Scoping, March 19 - 23, 2018 Screening, and AMPs 3
SER Overview
- Final SER issued August 16, 2018
- No open items or confirmatory items
- Total of 119 RAIs issued
- 15 follow-up RAIs 4
71002 Inspection: Scope
- Scope:
- Scoping and screening of components
- Walk down of accessible areas
- Review of 25 AMPs (6 new & 19 existing)
- Team of 4 conducted on-site inspection for 2 weeks:
- Weeks of February 26 and March 19, 2018
- Inspection Report issued May 7, 2018 (ML18127B169) 5
71002 Inspection: Results
- Facility was in good material condition
- Applicant agreed to include existing periodic heat exchanger inspections for their service water systems into their plant-specific Periodic Surveillance and Preventive Maintenance aging management program 6
71002 Inspection: Conclusions
- Scoping and screening performed in accordance with 10 CFR 54
- Information easily retrievable and auditable
- Existing programs effectively managed aging effects
- Reasonable assurance that aging effects will be managed and intended functions maintained 7
SER Section 2
- Structures and Components Subject to Aging Management Review
- Section 2.1: Scoping and Screening Methodology
- Section 2.2: Plant-Level Scoping Results
- Sections 2.3, 2.4, 2.5: Scoping and Screening Results 8
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 9
SER Section 3 Section 3.0.3 - Aging Management Programs Applicants Disposition of AMPs Final Disposition of AMPs in SER
- 11 new programs
- 12 new programs All consistent All consistent
- 31 existing programs
- 30 existing programs 12 consistent 10 consistent 13 consistent with enhancements 13 consistent with enhancements 2 consistent with exceptions 2 consistent with exceptions 4 consistent with enhancements 5 consistent with enhancements and exceptions and exceptions
- 1 plant-specific existing program
- 1 plant-specific existing program 10
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 11
Reactor Vessel Neutron Fluence
- Issue:
- No basis for the adequacy of the neutron fluence methodology for RPV beltline components above the active fuel region
- Resolution:
- Fluence methodology includes sufficient conservatisms:
- Accounting for potential uncertainties in the above-core water densities
- Considering the bounding power/flow statepoint that leads to higher fluence year fluence calculations are conservative and meet RG 1.190
- TLAA demonstrated to be acceptable per 10 CFR 54.21(c)(1)(ii) 12
High Voltage (HV) Insulators:
Use of Polymeric Material
- Issue:
HV insulators made of polymeric material identified during on-site audit, while LRA only cited porcelain insulators GALL has not evaluated polymeric HV insulators
- RAI requested:
Justification for not listing polymeric material in LRA Discussion of site-specific aging mechanisms, aging effects, and chemical contaminants from animal excrement associated with polymeric HV insulators
- Applicants RAI Responses:
Revised LRA to include polymeric HV insulators Addressed pertinent aging effects and mechanisms Proposed periodic preventive maintenance and inspections
- Staffs
Conclusion:
Changes in LRA to include polymeric HV insulators, periodic preventive maintenance and inspections are acceptable 13
Neutron Absorbing Material Monitoring Program
- Will adequately manage the effects of aging
- Replacement for Boraflex monitoring program that was previously credited for neutron absorbing material Due to degradation, Boraflex material currently in the spent fuel pool will not be able to maintain required sub-criticality margin into period of extended operation (PEO)
Plans to submit LAR for SNAP-IN inserts end of 3rd quarter 2018 Installation scheduled for June - October 2019 Aluminum boron-carbide neutron absorbing material will be installed prior to PEO 14
RAI 2.3.3.16-1: EDG Crankcase Vent Lines Not Subject to AMR
- Issue:
- ACRS identified concern re: RAI response regarding the Division I & II Emergency Diesel Generator vent lines being not necessary for the diesels to operated under emergency conditions.
- Information provided does not clearly provide technical justification as to why the vent lines do not have either 54.4(a)(1) or (a)(2) function.
- Resolution:
- Staff contacted RBS to make them aware of the ACRS concern.
- RBS plans to supplement this information by October 15, 2018.
- Staff will review the supplemented information and revise the SER accordingly.
15
Conclusion On the basis of its review, the staff determines that the requirements of 10 CFR 54.29(a) have been met for the license renewal of River Bend Station, Unit 1.
16
Backup Slides 17
HV Insulators: Loss of Material Due to Mechanical Wear
- Issue:
EPRI 1003057 states that mechanical wear in porcelain HV insulators is an aging effect GALL report recommends plant-specific AMP for loss of material due to mechanical wear & reduced insulation resistance Polymeric HV insulators have not been addressed in the LRA
- RAI requested:
Include evaluation of metallic material used and applicable loss of material in polymeric HV insulators
- Applicants Response:
Metallic components of polymeric HV insulators are similar to porcelain type previously evaluated in the LRA Loss of material due to mechanical wear is not an applicable aging effect (same as porcelain insulators)
No plant-specific AMP is required
- Staffs
Conclusion:
Applicants evaluation is consistent with license renewal Standard Review Plan and acceptable 18
Here are my comments regarding the River Bend Nuclear Generating Station, Unit 1 License Renewal Application.
The ACRS Subcommittee on Plant License Renewal is asked consider the following comment with respect to the aging management program for systems, structures, and components that are credited for the renewal of River Bends operating license:
According to River Bends FSAR (Chapter 15.0.3, ADAMS No. ML17226A118), infrequent incidents are described as incidents that, may occur during the life of the particular plant (spanning once in 20 yr to once in 100 yr). These events are also known as "abnormal (unexpected) operational transients."
Therefore, the River Bend nuclear generating plant must be designed to deal with as many as two infrequent incidents during its design lifetime of 40 years, without endangering the public health and safety.
Infrequent incidents are not like anticipated operational occurrences, which might occur one or more times during a calendar year of operation, and which are remedied simply by a reactor shutdown. A single infrequent incident that does not receive the correct response, from the plants automatic reactor protection systems, or from its operators, could easily end the plants operating lifetime (e.g., consider the consequences of the unmitigated infrequent incident that occurred at Three Mile Island, in 1979).
If River Bends operating license is renewed, then the plant must be designed to deal with as many as three infrequent incidents during its new design lifetime of 60 years, without endangering the public health and safety.
Probabilistic risk assessment (PRA) arguments could well dismiss the occurrence of three infrequent incidents, as highly unlikely; but the use of PRA would be inappropriate in this application. This is because 10 CFR §54 requires that plants maintain their current, deterministic licensing bases during the extended terms of operation that are authorized by their renewed licenses. Consider that an even less likely class of events, anticipated transients without scram (ATWS) is specifically listed in the scope of 10 CFR §54. The definition of scope, as defined in 10 CFR §54.4, includes, (a) Plant systems, structures, and components within the scope of this part are (3) All systems, structures, and components relied on in safety analyses or plant evaluations to perform a function that demonstrates compliance with the Commissions regulations for . Anticipated transients without scram (10 CFR 50.62). ATWS events are not likely to occur, and not included in plant design bases.
This is supported by the Statement of Consideration, The Commission reaffirms its previous conclusion (see 56 FR 64943 - 64956) that PRA techniques are most valuable when they focus the traditional, deterministic-based regulations and support the defense-in depth philosophy. In this regard, PRA methods and techniques would focus regulations and programs on those items most important to safety
by eliminating unnecessary conservatism or by supporting additional regulatory requirements. PRA insights would be used to more clearly define a proper safety focus, which may be narrower or may be broader. In any case, PRA will not be used to justify poor performance in aging management or to reduce regulatory or programmatic requirements to the extent that the implementation of the regulation or program is no longer adequate to credit for monitoring or identifying the effects of aging. --- FR 22468, Vol. 60, No. 88 (May 8, 1995)
River Bends aging management program should account for the potential increase in infrequent incidents that would accompany the extension in operating lifetime. That is, increasing the plants operating lifetime by 50% will consequently increase the number of potential infrequent incidents by 50%. (This issue also applies to other BWRs, and to PWRs, as well.) Since increasing the authorized operating lifetime of a plant could increase the maximum number of infrequent incidents, from 2 to 3, then it seems that some sort of modification (e.g., in plant design or operation) would be required in order to maintain the number of infrequent incidents, in the CLB, at not more than 2 incidents over a period of 60 years of operation.
10 CFR §54, Requirements for Renewal of Operating Licenses for Nuclear Power Plants, governs the issuance of renewed operating licenses for nuclear power plants. So, is the renewal of an operating license the same as the issuance of a renewed operating license? If yes, then why is 10 CFR §54 required? Would it not be simpler, and less confusing, to issue a license amendment, under 10 CFR §50, which would extend the license expiration date, and record a license commitment (or condition) to establish and implement an acceptable aging management program? Then the new expiration date would be specified in a license amendment that converts a 40-year license into a 60-year license.
Approval of the license renewal, as an amendment, would also be subject to the requirements of 10 CFR
§50.92, Issuance of amendment, which addresses, among other things, the question of whether the operation of the facility, in accordance with the proposed amendment, would cause a significant increase (e.g., 50%) in the probability of an accident (e.g., an infrequent incident) previously evaluated.
In this way, (1) the CLB is maintained, (2) there is no doubt as to whether all amendments and commitments that were made for a 40-year license also apply to a 60-year license, and (3) the license renewal is accomplished by amendment to an existing license, consistent with all other major changes (e.g. power upratings); not by issuing a renewed license.