ML18282A252

Transcript of Advisory Committee on Reactor Safeguards Plant License Renewal Subcommittee Meeting (River Bend)- September 20, 2018 (PM Session)

ML18282A252
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Issue date:	09/20/2018
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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- NEAL R. GROSS AND CO., INC.

Court Reporters and Transcribers 1323 Rhode Island Avenue, N.W.

Washington, D.C. 20005 (202) 234-4433 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

(202) 234-4433 WASHINGTON, D.C. 20005

-3701 www.nealrgross.com 1 1 2 3 DISCLAIMER 4 5 6 UNITED STATES NUCLEAR REGULATORY COMMISSION'S 7 ADVISORY COMMITTE E ON REACTOR SAFEGUARDS 8 9 10 The contents of this transcript of the 11 proceeding of the United States Nuclear Regulatory 12 Commission Advisory Committee on Reactor Safeguards, 13 as reported herein, is a record of the discussions 14 recorded at the meeting.

15 16 This t ranscript has not been reviewed, 17 corrected, and edited, and it may contain 18 inaccuracies.

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-3701 (202) 234-4433 UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION

+ + + + + ADVISORY COMMITTEE ON REACTOR SAFEGUARDS (ACRS) + + + + + PLANT LICENSE RENEWAL SUBCOMMITTEE

+ + + + + THURSDAY SEPTEMBER 20, 2018

+ + + + + ROCKVILLE, MARYLAND

+ + + + + 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. BRO WN, JR. Member JOSE MARCH

-LEUBA, Member HAROLD B. RAY, Member PETER C. RICCARDELLA, Member MATTHEW SUNSERI, Member

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-3701 (202) 234-4433 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

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-3701 (202) 234-4433 MOHAMMAD SADOLLAH, NR R 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

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-3701 (202) 234-4433 C-O-N-T-E-N-T-S RBS License Renewal Application by Entergy Introduction by John Ventosa

.................

7 Presentation by Tim Schenk

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8 Presentation by James Henderson

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10 Presentation by Garry Young

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38 Discussion with Entergy Leadership Team

.....42 RBS Safety Evaluation Report by NRC Introduction by Emmanuel Sayoc

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52 Presentation by Samuel Graves

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56 Presentation by Emmanuel Sayoc

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65 Meeting Adjourned

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-3701 (202) 234-4433 P R O C E E D I N G S 1 1:27 p.m. 2 CHAIRMAN SKILLMAN: Ladies and gentlemen, 3 good afternoon. This meeting will begin. We recessed 4 at approximately 1020. And so we are continuing the 5 meeting that we began at 0830 this morning.

6 This is the meeting for the River Bend Unit 7 1 License Renewal Application. This meeting is a 8 meeting of the ACRS Plant License Renewal Subcommittee.

9 I'm Gordon Skillman. I'm chairman of the 10 subcommittee. ACRS members that are in attendance are 11 the same as were here this morning.

12 I will make one change. The meeting is 13 open to the public. We have one set of written comments 14 from a member of the public for this afternoon's 15 meeting, and we may or may not deal with that later 16 if that member decides to call in or to participate.

17 As before, the meeting is being 18 transcribed. We request that all in the meeting, when 19 they come to the microphone, please speak clearly and 20 introduce themselves.

21 A telephone bridge line is established.

22 And to preclude interruption of the meeting, we ask 23 that the bridge line participants please maintain their 24 phones on mute during the presentations and the 25 6 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 committee discussion. We believe that the noise that 1 we heard this morning was the consequence of an unmuted 2 line. And for those in the meeting room here, please 3 silence all of your electronic devices.

4 We're now prepared to proceed with the 5 meeting, and I call upon Joe Donoghue to please 6 introduce the second part of this meeting. Joe?

7 MR. DONOGHUE: Thanks, Chairman Skillman, 8 and again, the members of the subcommittee. And once 9 again, for those of who may no t have been here, I'm 10 Joe Donoghue. I'm the Deputy Director, Division of 11 Materials and License Renewal in NRR. We, again, want 12 to express our appreciation for doing the double header 13 today to save staff resources and the licensee's 14 resources.

15 Later this afternoon, you'll hear from our 16 project manager leading the staff's evaluation

-- a 17 presentation of the evaluation, Manny Sayoc. Also 18 here, as was this morning, is Dr. Allen Hiser, our senior 19 technical advisor. Eric, you already heard from.

20 He's the project's branch chief. And we have staff 21 and managers who contributed to the review from River 22 Bend in the audience to answer any questions you may 23 have. We also have Region IV staff again all lined 24 up to discuss their i nspection activities related to 25 7 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 this review.

1 So again, thank you. I turn it over to 2 the Chief Operations Officer from Entergy team, John 3 Ventosa. 4 MR. VENTOSA: Good afternoon. My name is 5 John Ventosa. I'm the Chief Operating Officer for the 6 Southern Region for Entergy of which River Bend is one 7 of the sites that I have responsibility for and 8 obviously the topic of this afternoon's meeting.

9 I very much appreciate the opportunity to 10 speak to this committee this afternoon about the license 11 renewal application for River Bend. In our view, the 12 staff has conducted a very thorough but fair review 13 of our readiness for the renewed operating license.

14 For this afternoon's discussion, we have 15 with us James Henderson who's the Engineering Director 16 for River Bend, Tim Schenk who's the River Bend Reg 17 Assurance Manager, and Garry Young who's our Director 18 for License Renewal for Entergy.

19 Tim will describe our River Bend Station 20 plant status and its licensing history. James will 21 describe major equi pment upgrades, completed and 22 planned, that are supporting our extended operation 23 at River Bend. And finally, Garry will discuss the 24 license renewal project itself and provide more 25 8 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 in-depth information on selected few topics.

1 Again, thank you for the oppo rtunity to 2 be here today for this very important milestone for 3 River Bend. And we welcome your question and look 4 forward to the discussion. Thank you. I'll turn the 5 presentation over to Tim Schenk.

6 MR. SCHENK: And good afternoon. My name 7 is Tim Schenk. I'm the Regulatory Assurance Manager 8 at River Bend Station. River Bend Station is located 9 in West Feliciana Parish, Louisiana, approximately 24 10 miles north

-northwest of Baton Rouge, Louisiana.

11 It was a General Electric designed plant.

12 Stone and Webste r was the constructor. We're a 13 Boiling Water Reactor 6 model with a GE Mark III 14 containment and GE turbine

-- General Electric turbine.

15 Our ultimate heat sink is independent wet cooling 16 tower. We have a closed circ water system with 17 mechanical draft coo ling towers, and we're currently 18 licensed to 3,091 megawatts thermal with a staff of 19 820 individuals.

20 Currently, River Bend is operating at 100 21 percent power and is on a 24

-month operating cycle.

22 We're a Column 1 plant in the react or oversight process, 23 and we have a last refueling outage was in the spring 24 of 2017. That was Refueling Outage No. 19 and Refueling 25 9 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 Outage No. 20 is scheduled for the spring of 2019.

1 CHAIRMAN SKILLMAN: Tim, what has your 2 capacity factor been for the last several cycles?

3 MR. SCHENK: The capacity factor for 2018 4 is currently 75.1 percent and 2017 is 83.1 percent.

5 CHAIRMAN SKILLMAN: The most recent is the 6 result of a refueling cycle or refueling outage?

7 MR. SCHENK: We had a planned down power 8 in early 2018 to address fuel failures at the station, 9 and that has impacted our capacity factor for 2018.

10 CHAIRMAN SKILLMAN: Okay.

11 MR. SCHENK: Some of the history of River 12 Bend Station, we received our construction permit in 13 March of 1977. Our operating license was November of 14 1985, and we commenced commercial operation in June 15 of 1986. So we were rated at that time at 2,894 16 megawatts thermal.

17 We did our first power uprate in November 18 of 2000. That's five percent power uprate. That too k 19 us to 3,031 megawatts thermal. And we did another power 20 uprate in January of 2003, and it's got us to our current 21 power capacity of 3,091 megawatts thermal. Our license 22 renewal was submitted in May of 2017, and our current 23 operating license expires in August of 2025.

24 With this, I'd like to turn it over to 25 10 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 Engineering Director James Henderson to talk a little 1 bit about major equipment upgrades.

2 MR. HENDERSON: Good afternoon. My name 3 is James Henderson. I am the Engineering Director here 4 at River Bend Station. I want to go over a couple items 5 for our major equipment upgrades. What you see is 6 reflective of a long

-range plan that's been focused 7 not only on equipment reliability but also safety for 8 the station.

9 A couple of the items that we have going 10 fo rward that we've completed already at the station, 11 the first, we've made a major upgrade to our Digital 12 EHC. That's our electrical hydraulic control system, 13 turbine controls. We have a picture going forward in 14 the presentation that we'll show to the team so that 15 you all can see the major adjustments we did there.

16 We have eliminated several single point 17 vulnerabilities on the order of greater than 90 to help 18 with the equipment reliability and long

-term operation 19 of the plant. We've also done control building 20 upgrades to our control building chillers, upgrading 21 those to digital controls, looking specifically at our 22 additional monitoring, giving our operators additional 23 redundancy, and giving them the ability to identify 24 issues prior to becoming challenges for the station.

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-3701 (202) 234-4433 Also, for long

-term reliability, we've 1 done recoating for underground circ water piping.

2 We've also replaced some of our obsolescence items 3 related to inverters as well as 40 Volt control circuit 4 breakers which are listed above. We've also done 5 upgrades to our normal service water cooling towers.

6 We have plate and frame heat exchangers associated 7 with our service water cooling towers. We want to make 8 sure those can support long

-term operation of the plant.

9 And we've also replaced our fourth point feedwater 10 heaters associated with the station.

11 So if we go to the next slide.

12 CHAIRMAN SKILLMAN: Before you do that, 13 please. Here, you recoated your underground 14 circulating water piping. But at Waterford 3, it was 15 a on e-time inspection, maybe last time when Moby Dick 16 was a minnow. So how come you're doing inspections 17 and coating here? It appears to be a very different 18 cadence than the sister plant.

19 MR. HENDERSON: Yes, for our station, 20 we've do ne a couple of inspections for our underground 21 piping just because we want to make sure we have that 22 long-term reliability for the station. In 2012, we 23 did a complete excavation inspection for our 24 underground piping. We also did culvert work in 2017.

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-3701 (202) 234-4433 We also took that opportunity to look at the 1 underground piping.

2 So any opportunity that we have where we 3 do excavation activities or things of that nature.

4 Because of the nature of our underground piping system, 5 we want to make sure we're doing the right t hing for 6 the station.

7 CHAIRMAN SKILLMAN: Replacing the fourth 8 point heaters, is it because they were not sufficient 9 for your thermal efficiency, or were they actually 10 failing? 11 MR. HENDERSON: They were not failing.

12 This was to improve our thermal efficie ncy. 13 CHAIRMAN SKILLMAN: Yes sir. Thank you.

14 MR. SCHULTZ: James, what's the relative 15 time frame for the completed upgrades that are listed 16 here? 17 MR. HENDERSON: These upgrades have been 18 completed.

19 MR. SCHULTZ: No, but over what t ime 20 period? 21 MR. HENDERSON: Oh, it's over a five

-year 22 period. So as a part of our nuclear strategic plan 23 that we did for our station, through our fleets focus, 24 we laid out specific items to go after from 2018 to 25 13 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 2023. And that's where you'll see a lot of our 1 modifications or the things we're going after to improve 2 equipment reliability.

3 MR. SCHULTZ: But these are completed?

4 MR. HENDERSON: That's correct.

5 MR. SCHULTZ: So five years past, you begin 6 some of these modifications, either in engineering or 7 in physical modification?

8 MR. HENDERSON: That's correct.

9 CHAIRMAN SKILLMAN: James, which of these 10 upgrades was the result of a PRA review where the Entergy 11 team said, we've got some safety benefit by making this 12 or these changes? I'm looking particularly at the 13 inverters and wondering if that was a material or 14 equipment reliability change that was driven by PRA 15 examination.

16 MR. HENDERSON: The inverter upgrades that 17 we did specifically were driven based upon obsolescence 18 for the inv erters that we had in service. I'm not 19 really sure the tie to the PRA aspect of things for 20 the inverter.

21 CHAIRMAN SKILLMAN: Thank you.

22 MEMBER SUNSERI: James, do you have any 23 underground electrical cables that are subject to being 24 covered up by water?

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-3701 (202) 234-4433 MR. HENDERSON: We do have underground 1 cables that are susceptible to being covered by water.

2 We do have preventative maintenance strategies in 3 place, not only to do monitoring. But we also have 4 solar power sump pumps to keep those wells empty.

5 MEMBER SUNS ERI: Thank you.

6 CHAIRMAN SKILLMAN: So how do the solar 7 power sump pumps do at night?

8 MR. HENDERSON: That's really the piece 9 of the performance, the preventative maintenance 10 activity as well. So not just relying on the solar 11 power sump pumps, but we also have our maintenance craft 12 go out, do inspections of those water holes to make 13 sure that they're getting pumped out efficiently.

14 CHAIRMAN SKILLMAN: Thank you.

15 MR. HENDERSON: No problem.

16 MR. SCHULTZ: James, let me ask Member 17 Ski llman's question a little differently with regard 18 to PRA. You talked about this as what really appears 19 to be about a ten

-year program for plant improvement 20 and modification.

21 To what extent have you used the PRA in 22 providing the listing of those major impr ovements that 23 you're going to do? And how does the PRA team interact 24 with the modifications in terms of upgrade and update?

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-3701 (202) 234-4433 MR. HENDERSON: So when we put together 1 our nuclear strategic plan, one of the key pieces was 2 our impact to safety, our impact to risk. For example, 3 the upgrade of the control building chillers, those 4 control building chillers feed directly into our PRA 5 model, and the loss of those control building chillers 6 not only impact safety related switch gears, but it 7 also impacts the safety r eliability of the main control 8 room. So those major activities that we have built 9 into our plan do have the

-- our PRA team was involved 10 in making those decisions.

11 MR. SCHULTZ: That's a good example. So 12 you could go through these one at a time determine and 13 describe how they do relate to the PRA and which ones 14 most affect reliability of the facility. Thank you.

15 MR. HENDERSON: No problem. All right.

16 The next picture that you guys see, this is the graphic 17 user interface that we have for our EHC control system.

18 The visual controls are upgraded from an analog control 19 system. 20 This provides additional reliability for 21 the equipment operators, additional temp monitoring 22 as well as testing capabilities for our EHC system.

23 It has prove n valuable not only for operator performance 24 but equipment reliability associated with our electric 25 16 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 hydraulic control system.

1 The next slide shows our upgrades we've 2 done for our load center breakers. Again, diagnostic 3 capability increases. The availabil ity of the 4 breakers, all things that not only help with the 5 criminal liability but also the operator

-user interface 6 associated with diagnosis as well as monitoring for 7 long-term reliability.

8 Our next slide, we've done activities 9 associated with carbon steel piping replacement. Very 10 specifically looking at our reactor water cleanup 11 system, we've gone through with some of the carbon 12 piping, removed those, replaced those with chrome moly 13 or updated with new carbon steel really to help our 14 reactor water cleanu p system as it serves the function 15 to improve the chemistry and quality of our RCS. So 16 we're seeing the dividends of what we've been doing 17 here for the station.

18 MEMBER RICCARDELLA: What was the issue 19 with the old carbon steel piping? Was it flow assisted 20 or -- 21 MR. HENDERSON: This was all associated 22 with our fab program.

23 So the next piece we'll talk through is 24 our major equipment upgrades. The very first are 25 17 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 turbine building chiller replacements. This is more 1 for generation and reliability for the station. Our 2 turbine building chillers not only support the turbine 3 building itself but also the cooling of our main steam 4 tunnel. So those replacements are in progress and are 5 scheduled to complete by the end of 2018.

6 We do have spent fuel pool neutron absorber 7 upgrade. I'll show you a picture going forward of that 8 upgrade that we're doing. We have inserts that we're 9 installing as prototypes to help improve not only our 10 neutron absorption but also going forward to be able 11 to use tha t by year 2020 for that modification.

12 The next piece, our condenser upgrade.

13 In our refueling outage '21, which will occur in 2021, 14 we plan to do a major scope on our main condenser, two 15 replacements. That's going to take place in

'21. We 16 have bridging strategies from now until that time frame.

17 And in our next refueling outage, we're going to be 18 doing any current testing as well as tube cleaning and 19 all that good stuff to really make sure that we have 20 a good bridging strategy goi ng forward to '21.

21 We've got service water cooling heat 22 exchanger refurbishment that's in progress. I did 23 annotate that earlier in our discussion. Our Fancy 24 Point switchyard upgrades, that's our offsite power 25 18 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 coming to the station, really increasing the 1 reliability there to make sure that we have a viable 2 resource of offsite power to the station.

3 Our recirc pump power cable replacement, 4 that's a part of our EQ program, getting those power 5 cables replaced so that we can improve the operation 6 of our recirc pumps. 7 And then the final two. The feedwater 8 strainer, that's directly associated foreign material 9 exclusion to the vessel. We'll have a picture later 10 in the presentation that I'll show and share with the 11 team really to make sure we have FME concerns add ressed 12 for our station to prevent fuel failures and really 13 going forward to make sure that we've got long

-term 14 reliability for the station.

15 And the last piece, our feedwater level 16 control system. That upgrade will also remove sever al 17 single-point vulnerabilities associated with our 18 feedwater level control system.

19 MR. SCHULTZ: James, with regard to the 20 switchyard upgrades, can you quantify that a bit about 21 what type of advantage do you expect to obtain by making 22 these upgrades?

23 MR. HENDERSON: So from a quantification 24 purpose, I'm not sure if I can articulate it quite well.

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-3701 (202) 234-4433 I'll tell you what we're doing for the upgrade. We're 1 going to have a total separate switchyard from the 2 switchyard that we have in place right now.

3 We have a 500 kV distribution that gets 4 stepped down to 13.8 kV for the station. So we're going 5 to totally upgrade not only the breakers and lines 6 associated with that from our transmission and 7 distribution side but also the feeders that come to 8 our station. So from a quantifying aspect, I'm not 9 sure if I could really articulate that very well.

10 MR. SCHULTZ: It's more of a changeover 11 to a different type of switchyard approach which would 12 provide additional reliability?

13 MR. HENDERSON: Yes, the way I would table 14 it, it's from an equipment reliability perspective.

15 MR. SCHULTZ: Thank you.

16 MEMBER SUNSERI: James, the power 17 reduction that Tim talked about due to fuel performance, 18 do you know if that was related to foreign material 19 yet or not?

20 MR. HENDERSON: It was related to foreign 21 material. 22 MEMBER SUNSERI: So has this been an 23 ongoing challenge for the station, hence the 24 modification?

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-3701 (202) 234-4433 MR. HENDERSON: Yes, we've had challenges 1 to the station. The first fuel failure that we 2 experienced happened in 2016 associated with a recent 3 string of fuel failures. We have the modification in 4 question for the feedwater strainers. It's really our 5 aggressive approach to making sure that we put something 6 in place to not only just perform flushing or look at 7 FME practices but really modify the plant so that we 8 put ourselves in the best position not to introduce 9 foreign material.

10 MEMBER SUNSERI: Yes, and I presume the 11 fuel assemblies themselves have some kind of debris 12 filter or something online?

13 MR. HENDERSON: T hey do, they do, they do.

14 MEMBER SUNSERI: So this debris is getting 15 past that?

16 MR. HENDERSON: Yes.

17 MEMBER SUNSERI: Thanks.

18 CHAIRMAN SKILLMAN: James, would you 19 please say more about the neutron absorber upgrade?

20 That is your sec ond bullet here.

21 MR. HENDERSON: Yes, so the next slide 22 shows the neutron absorber. We currently have 60 that 23 are installed in our spent fuel pool. Basically, what 24 we're doing right now, we have the analysis from a 25 21 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 thermal perspective as well as seismic perspective.

1 And at this time, it's really monitoring to see the 2 effectiveness of those absorbers. It's aluminum 3 material is what the inserts are made of, and we're 4 going to be using that.

5 We're not taking credit for it in any of 6 our licensing basis or a nything of that nature at this 7 time. It won't be until the engineering change is 8 completed as well as the full analysis of the ability 9 for our absorbers to really work. That'll be completed 10 in 2020. So we'll have all of the inserts by the end 11 of the year. We'll be able to continue to collect data.

12 And by 2020, we'll have the modification complete and 13 we'll be able to take credit for our neutron absorption.

14 CHAIRMAN SKILLMAN: Okay. So here is your 15 spent fuel pool and here you are adding hold down by 16 adding these inserts. Is this being conducted on a 17 50.59? Is this a license amendment? What is the 18 documentation that has enabled you to make, if you will, 19 a change in process?

20 I mean, this isn't something that you can 21 walk away from. You're doing it contemporaneously with 22 the requirement for the new material to provide the 23 hold down on which you depend. So what is the vehicle 24 by which you are doing this?

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-3701 (202) 234-4433 MR. FORD: This is Bryan Ford from Entergy.

1 We are going to be requesting a license amendment so 2 that we can credit the inserts for their neutron 3 absorption capability. That's an analysis change that 4 we have to get approval for. For just installing the 5 inserts, we will do that under 50.59 and we just won't 6 credit them in our neutron analysis until we get 7 approval. 8 CHAIRMAN SKILLMAN: How do you clear the 9 question on 50.59 regarding either analysis or a change 10 to the facility that might rise to the need for a license 11 amendment?

12 MR. FORD: Because we're n ot crediting 13 them for the analysis. So we haven't changed the 14 analysis. We're still relying upon our previous 15 analysis for it.

16 (Simultaneous speaking.)

17 CHAIRMAN SKILLMAN: Okay. I'm just 18 getting it clear. Thank you. Now I understand.

19 Thank you.

20 MR. HENDERSON: Any other questions? Our 21 next slide

-- oh, go ahead. Sorry, yes.

22 MEMBER SUNSERI: Just following up on that 23 a little bit there. But these inserts must have some 24 impact other than just reactivity, right? They're 25 23 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 going to be touching the fuel assemblies. They're 1 going to change the loading of the pool. I mean, 2 seismic, material, chemistry, you're looking at of all?

3 MR. FORD: Yes, and those parts of the 4 modification are performed under 50.59. So we make 5 sure we're within the applicable margi ns and redo the 6 appropriate analysis to accomplish that.

7 MEMBER SUNSERI: Thank you.

8 MR. HENDERSON: The next slide for our 9 planned upgrades, this is a picture of our feedwater 10 strainer to specifically address the foreign material 11 concerns that we discussed earlier. This will be one 12 of two feedwater strainers that are installed in our 13 feedwater line directly to the vessel. It gives us 14 the last opportunity to make sure that we collect any 15 type of foreign material so that it doesn't become a 16 concern for our fuel reliability.

17 MEMBER MARCH

-LEUBA: So I can understand 18 this, what are the dimensions? I mean, how big is?

19 Is it this big or this big? Is that one foot, two feet, 20 two inches in diameter?

21 MR. HENDERSON: I don't know the exact 22 diameter, but it's bigger. It's a bigger strain.

23 MEMBER MARCH

-LEUBA: But the strainer 24 themselves is minuscule, right?

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-3701 (202) 234-4433 MR. HENDERSON: That's correct.

1 MEMBER MARCH

-LEUBA: You're trying to 2 catch microfibers?

3 MR. HENDERSON: If you can imagine, it's 4 almos t a witch's hat design where you can see the 5 differences.

6 MR. SANDLIN: I'm Dean Sandlin, the design 7 manager at River Bend. These things are about six foot 8 long and they're in 20

-inch pipe. So they are actually 9 larger than 20

-inch, and then we have the r educers on 10 both sides. It's probably 30 inches in diameter.

11 MEMBER MARCH

-LEUBA: And the inside filter 12 is six foot long and very

-- 13 MR. SANDLIN: It's like a witch's hat.

14 It necks down into that, and you have about a million 15 holes in it. That's the best way to describe it. It's 16 like a witch's hat with a million little bitty small 17 holes in it.

18 MEMBER MARCH

-LEUBA: And you have enough 19 pumping power to go through the pressure drop?

20 MR. SANDLIN: Yes. We've already had the 21 hydraulic analysis complete.

22 MEMBER MARCH

-LEUBA: Okay. Thank you.

23 MR. SANDLIN: We didn't want to go forward 24 without that.

25 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 CHAIRMAN SKILLMAN: So the design pressure 1 of this is approximately 1,500 psi?

2 MR. SANDLIN: Yes.

3 CHAIRMAN SKILLMAN: And so what we're 4 seeing here is construction bolting. This is not final 5 fit of bolting?

6 MR. SANDLIN: No, that's just the shop 7 stuff right there.

8 CHAIRMAN SKILLMAN: Copy that. Okay.

9 Very good.

10 MR. SANDLIN: It'll be professional when 11 we get finished.

12 (Laughter.)

13 CHAIRMAN SKILLMAN: Okay. I'm saying, 14 wow, that's quite a mod. That's not even a 50.59.

15 (Laughter.)

16 CHAIRMAN SKILLMAN: I like that. So this 17 is basically a concept. And when this thing is snugged 18 up in place, it's got the 18 or 20-inch, inch and a 19 half high strength bolts?

20 MR. HENDERSON: Exactly, correct.

21 CHAIRMAN SKILLMAN: And she's cinched in 22 at 1,500 psi design.

23 MEMBER MARCH

-LEUBA: And going back to 24 this, you have confidence that the fibers

-- or I mean 25 26 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 the loose parts are coming from upstream of this filter?

1 MR. HENDERSON: Yes.

2 MEMBER MARCH

-LEUBA: They're not inside 3 the vessel? They're not coming from the vessel?

4 MR. HENDERSON: Yes, the whole purpose of 5 this is to catch anything with the interface with the 6 feedwater system before it goes into the vessel, so 7 yes. 8 CHAIRMAN SKILLMAN: If I can ask, this is, 9 first of all, well done. You're protecting your fuel.

10 On the other hand, you've put in a barrier to feedwater 11 flow. So in the analysis for in stallation of this 12 filter, what consequence or what feature have you 13 recognized for plugging of this and its effect on your 14 core? 15 MR. SANDLIN: We've had the full hydraulic 16 analysis. We have enough capability in our feedwater 17 level control valves to provi de the additional pumping 18 power we need to accommodate what we assume is the worst 19 case delta P across this filter and still maintain 20 enough flow to the core to maintain water level.

21 MEMBER MARCH

-LEUBA: Is there only one of 22 these or two?

23 MR. SANDLIN: There'll be two. We have 24 two lines going into the vessel.

25 27 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 MEMBER MARCH

-LEUBA: If you were

-- 1 MR. SANDLIN: So both lines will have one 2 of these. 3 MEMBER MARCH

-LEUBA: If you were to have 4 a degree sufficient to plug it in and you have a thousand 5 holes in ther e, you will need another one.

6 MR. SANDLIN: We'll have differential 7 pressure instruments across it so we can constantly 8 monitor the filter as well as vibration probes on it 9 as well. 10 MEMBER MARCH

-LEUBA: And after the scram, 11 you don't rely on fuel water

-- 12 MR. SANDLIN: That's correct.

13 MEMBER MARCH

-LEUBA: -- for safety actions 14 anyway to have HPCS?

15 MR. VENTOSA: But the concern you're 16 raising was probably the primary concern in the design 17 that we needed to get a clear answer on pr ior to 18 installation this coming spring. So there was some 19 independent

-- we had independent teams, independent 20 vendors go look at that to make sure because that is 21 the critical question. Yes, it's good that we're going 22 to protect the fuel but not causing some other effect 23 was really the

-- 24 CHAIRMAN SKILLMAN: So what is the failure 25 28 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 mode that you've considered?

1 MR. SANDLIN: I didn't understand your 2 question. 3 CHAIRMAN SKILLMAN: What is the failure 4 mode that you considered? What if the whole set of 5 guts carries away? You have an inside zipper failure 6 that pulls the witch's hat apart. And now, you've got 7 a forest of material entering your core.

8 MR. SANDLIN: GE did an extensive analysis 9 on the construction of the filter itself, the witch's 10 hat I'm going to call it. That's what everybody calls 11 it. And it has a structural integrity it needs to where 12 it will not fail like you're talking about, come apart 13 and then send additional FME to the core. So they've 14 got extensive analysis on that. That's another issue 15 we wanted to make sure we completely understood before 16 we went forward with this project as well.

17 CHAIRMAN SKILLMAN: And is that documented 18 in a safety evaluation or something?

19 MR. SANDLIN: The failure modes and 20 effective anal ysis included in our modification. GE 21 will provide that.

22 MEMBER RICCARDELLA: Is this located 23 inside containment

-- 24 MR. SANDLIN: No, it's in the

-- 25 29 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 MEMBER RICCARDELLA:

-- or outside 1 containment?

2 MR. SANDLIN:

-- just before it goes into 3 our steam tunnel in the turbine area.

4 MEMBER SUNSERI: And this is unique to 5 River Bend?

6 MR. SANDLIN: Yes.

7 MEMBER SUNSERI: So I guess you understand 8 the root cause of the foreign material well enough to 9 know you're

-- I mean, you're putting a Ban d-Aid on 10 versus addressing the root cause, right?

11 MR. SANDLIN: Actually, we don't consider 12 it a Band-Aid. We want to make sure we keep all FME 13 from going to the core, and this is the last point before 14 it goes to the reactor. There's really nothing else 15 FME generator past this point going to the core. We'll 16 catch it with this filter. Anything that may happen 17 in the BOP area that will get in the feedwater system, 18 this is designed to catch it. We want to protect our 19 fuel at all costs.

20 MEMBER SUNSERI: Ri ght. But probably so 21 does every other BWR

-6 too that doesn't have this thing, 22 right? 23 MR. SANDLIN: Other BWRs may.

24 MR. VENTOSA: I can speak a little. Our 25 30 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

(202) 234-4433 WASHINGTON, D.C. 20005

-3701 (202) 234-4433 plans are to install it at Grand Gulf which is our other 1 BWR-6. It's just a couple years out. I d on't want 2 to give you the impression that this is our fix for 3 foreign material. The root cause is work practices 4 and frankly some operational issues we had, how we set 5 valves up where we had some damage to valve internal 6 parts. 7 So we've addressed all that. We just 8 looked at the design and we felt there was still too 9 much of a vulnerability for fuel failures without taking 10 this next step.

11 MEMBER SUNSERI: Okay. That's fair.

12 MR. VENTOSA: Thanks.

13 MR. SCHULTZ: What are the maintenance 14 requirements for this? Do you have to change out the 15 filtration or flush the filtration system?

16 MR. SANDLIN: At the end of the first 17 cycle, we will take this thing out and inspect it to 18 see what kind of FME we have captured. We will 19 continuously monitor dP across it to make sure that 20 the dP doesn't exceed our hydraulic limits for pumping 21 water to the reactor to maintain the right water level.

22 But at the first cycle, we'll inspect it and we'll 23 determine what the future removal rate will be ba sed 24 on the amount we capture.

25 31 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 MR. SCHULTZ: Good. Thank you.

1 CHAIRMAN SKILLMAN: What is the 2 anticipated radiation level when you've captured this 3 fine material in this machine?

4 MR. SANDLIN: I don't have an answer for 5 that one. We'll talk about it in our modification.

6 It's in a remote area where people just are not

-- it's 7 not a routine traffic area. It's in a high radiation 8 area already.

9 MEMBER MARCH

-LEUBA: I know the FME comes 10 from the balance of plant. There is no neutron f lux 11 there for activation.

12 MR. SANDLIN: I can't understand.

13 MEMBER MARCH

-LEUBA: All of the material 14 that it catches comes from the balance of plant, 15 correct? 16 MR. SANDLIN: It comes from the BOP.

17 Here's the feedwater system.

18 MEMBER MARCH

-LEUBA: And those materials 19 are not subject to neutron fluxes that will activate 20 them. So they're very likely to not be very hot. If 21 you start catching hot material there, we'd like to 22 hear from you.

23 CHAIRMAN SKILLMAN: I'm sure we will. And 24 that's a big enough machine that if there's a lot of 25 32 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 hot material, you're going to need some super whamodyne 1 shielding around that thing.

2 MEMBER MARCH

-LEUBA: While I have the 3 microphone on, I'm going to regress a little bit on 4 philosophy. I wanted to end wit h what Dick stated, 5 good job. Because you took positive steps to make the 6 reactor better instead of doing a whole bunch of 7 analysis that did not change the reactor. And the 8 penalty you get for that, you always get one, is that 9 you get a lot of questions about it. But let me tell 10 you, good job. Thank you for doing it.

11 CHAIRMAN SKILLMAN: Yes, this reminds me 12 of some sage advice from Benjamin Franklin who said 13 if you put all your eggs in one basket, watch that basket 14 very, very, very closely. I think thi s is probably 15 good practice, but I think you need to be very aware 16 of the potential to start building up small amounts 17 of material that may have found its way here and that 18 is irradiated.

19 For whatever the reason is that you're 20 having fuel challenges, it's going to collect here.

21 I've just spent enough time at nuclear power plants 22 to know any place where material can collect can become 23 a very serious radiation source. And I know you know 24 that. You don't need that sermon. But this is a big 25 33 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 trap. A big trap can get a lot of stuff and you can't 1 get near it when it gets hot. Thank you.

2 MR. HENDERSON: Our next slide shows the 3 upgrades to our feedwater level control system. For 4 perspective, our feedwater level control system has 5 had previous challenges. We've done specific items 6 to help bridge and alleviate some of those issues.

7 But the feedwater level control system is really the 8 elimination strategy for several of the single

-point 9 vulnerabilities associated with the circuitry as we ll 10 as the workings of the feedwater level control itself.

11 So it not only provides the impact for 12 elimination of single

-point vulnerabilities. It also 13 provides reliability, deals with some of the 14 obsolescence items that we have with our old system 15 and also provides our operators a full range of control 16 automatically for our feedwater regulating system to 17 help them as far as monitoring and control of the unit.

18 MEMBER MARCH

-LEUBA: Was this done under 19 or planned to be done under 50.59? Because this is 20 the li censee, so it's a significant challenge.

21 MR. HENDERSON: Yes, so it is planned to 22 be done under 50.59.

23 MEMBER MARCH

-LEUBA: And I'm sure you're 24 considering

-- and you don't need to answer this because 25 34 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 it might go not only proprietary but classified

-- 1 cybe rsecurity.

2 MR. HENDERSON: Yes.

3 MEMBER MARCH

-LEUBA: So let's make sure 4 that the staff has reviewed that you don't have a 5 penetration point there.

6 MR. HENDERSON: Agreed. Thank you very 7 much. 8 MEMBER MARCH

-LEUBA: And it's not only 9 internet. USB drives, the CDs, the components, even 10 microchips.

11 MR. HENDERSON: Completely understand.

12 MEMBER BROWN: Let me echo that. Looking 13 at your slide, I haven't seen the Ovation system in 14 a while being used. It's a distributed control system, 15 i f I read your acronyms correctly. And I guess my 16 question is, is that DCS connected in some type of a 17 plant network and what type of communications did you 18 have? It's referring to Jose's comment relative to 19 the access from remote sources through software

-based 20 firewalls that are in some plant network.

21 On most of the new plant designs, and quite 22 frankly, on all of the new plant designs that we've 23 gone through, any connections into a network or a 24 distributed control system like this have been via 25 35 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

(202) 234-4433 WASHINGTON, D.C. 20005

-3701 (202) 234-4433 unidirecti onal hardware

-based data diodes, no software 1 control one way and they're hardware configured so that 2 they can't be reconfigured externally via software 3 hackers. 4 We don't see what's going on here. If 5 you're doing it in the future, s omebody may be asking 6 that question when you all come in. If it's under 7 50.59, at least it gets the antennas going in terms 8 of whether we should be asking questions about it.

9 We've raised that concern in multiple full committee 10 meetings and sessions over the last eight years. And 11 pretty much everybody has defaulted to hardware

-based 12 communication one way only.

13 No problem with sending data out. You'd 14 like to get data out so people can monitor it and trend 15 and do all that type of stuff. It's just the abi lity 16 to come in and do any software changes via external 17 sources as opposed to having to go into the plant and 18 upload new software changes or revisions as well as 19 control access.

20 You've always got the administrative 21 controls for internal stuff. But this s hould be inside 22 what I call a Level 4 boundary. And you certainly don't 23 want to have to fight cybersecurity threats and always 24 being upgrading software and that firewall and access 25 36 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

(202) 234-4433 WASHINGTON, D.C. 20005

-3701 (202) 234-4433 to it get to this stuff. It'll just eat you alive.

1 You can have a whole staff planned with it. That's 2 all. I'm just bringing the point up.

3 MR. HENDERSON: No, we definitely 4 appreciate the concern. And one of the things that 5 we've done, this modification is scheduled for 2021; 6 however, there are indus try OE for folks that have 7 installed this digital feedwater level control. So 8 really capturing those lessons learned so we don't end 9 up in a position where we're trying to

-- 10 MEMBER BROWN: Well, they probably haven't 11 thought about this yet. Based on our conversations 12 with other folks, it's been, well, we'll figure this 13 out later. And they haven't really thought about the 14 ability to limit

-- I mean, the air gap is the best 15 control that you have over ensuring nobody gets into 16 the critical controls on this stuff. 17 It's not a reactor safety system, per se, 18 in that definition like your reactor trip or safeguard 19 systems are. But it is a vital system, and that should 20 be treated appropriately in the same way.

21 MR. HENDERSON: That's a very good 22 challenge, and we appreciate that.

23 MEMBER MARCH

-LEUBA: Let's not forget that 24 cybersecurity is a rapidly changing field. Just five 25 37 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

(202) 234-4433 WASHINGTON, D.C. 20005

-3701 (202) 234-4433 years ago, you had to deal with teenagers from high 1 school trying to steal your debt. And now you're 2 dealing with state actors with the best and brightest 3 fully funded. So you have to protect

-- you have to 4 inspect any around that comes in there.

5 MR. HENDERSON: I agree.

6 CHAIRMAN SKILLMAN: Please proceed.

7 MR. VENTOSA: Then we'll turn it over Garry 8 now. 9 MR. YOUNG: Oka

y. Thank you. I'm Garry 10 Young, Director of License Renewal for the Entergy 11 nuclear fleet. And I'd like to give you some background 12 on our license renewal process including the approach 13 for the integrative plant assessment and for preparing 14 the license r enewal application.

15 We have a dedicated corporate team working 16 on license renewal for all the Entergy nuclear plants.

17 The team has almost two decades of experience with 18 all aspects of aging management and license renewal 19 and has prepared more than a dozen license renewal 20 applications over the past several years.

21 In addition to the corporate team, a plant 22 team of River Bend experts in design, systems 23 engineering, and plant programs was established for 24 this license renewal project. The plant team provided 25 38 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 needed input, review, and oversight of all of the 1 engineering and environmental reports that were 2 created. 3 We had more than 40 engineering reports 4 that were prepared to address the mechanical, 5 electrical, civil, structural, and time limited aging 6 analysis t opics needed to prepare the application.

7 We used the NRC approved guidance in NEI 8 95-10 to prepare the project

-specific procedures.

9 These procedures have been used on our previous license 10 renewal projects and are routinely updated based on 11 lessons-learned industry operating experience and 12 changes to the NRC guidance.

13 The site specific aging management review 14 for River Bend were compared to the GALL report, 15 NUREG-1801, Revision 2 as part of the application 16 development. The individua l line items in the 17 application indicate their consistency with the GALL 18 report aging management review results. And I'll talk 19 more about the comparison of the aging management 20 program with the GALL report on a later slide.

21 The LRA was submitted to the NR C in May 22 of 2017. The NRC used a new review process for the 23 River Bend application that included some efficiency 24 improvements based on lessons learned from previous 25 39 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 NRC reviews. This has proven to be a successful effort 1 by the NRC staff and has resulted in a planned 18

-month 2 review schedule rather than the typical 22

-month review 3 schedule. Next slide.

4 The NRC review process culminated in the 5 River Bend safety evaluation report which was issued 6 in August of 2018 with no open items and no confirmatory 7 items. And we appreciate the extensive and thorough 8 work of the NRC staff in reaching this important 9 milestone in the license renewal application review 10 process. Okay, next slide.

11 Okay. This slide summarizes the aging 12 management prog rams that were credited for license 13 renewal. We have 43 aging management programs that 14 include 12 new programs and 30 existing programs that 15 are or will be consistent with the GALL report aging 16 management programs with a handful of exceptions as 17 shown on this slide.

18 So examples of the 12 new programs are the 19 buried and underground piping and tanks inspection 20 program, the non

-EQ cables and connectors aging 21 management programs, one

-time inspection programs, and 22 selective leeching program.

23 Some aspects of the se new programs have 24 been implemented, but they are considered new programs 25 40 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

(202) 234-4433 WASHINGTON, D.C. 20005

-3701 (202) 234-4433 based on a significant number of changes that must be 1 made or have only recently been made to make them 2 consistent with the program descriptions in the GALL 3 report. 4 For example, the River Bend buried piping 5 program was initiated in response to the 2009 NEI 6 initiative, but significant changes are necessary to 7 incorporate the latest NRC guidance which includes 8 interim staff guidance issued in 20

15. For clarity 9 in describing the program, Entergy classified it as 10 a new program that would be consistent with the program 11 described in the most recent NRC guidance.

12 In addition, most of these new programs 13 have already been implemented in other Entergy n uclear 14 plants. This allows us to ensure that implementation 15 of the River Bend aging management programs reaps the 16 benefits of lessons learned from the Entergy operating 17 experience review program and the corrective action 18 program. 19 The 30 existing programs have been compared 20 to the GALL programs, and only a few exceptions have 21 been taken. These exceptions include such things as 22 revised inspection intervals based on the River Bend 23 refueling outage schedules and referencing NRC guidance 24 regulatory guides and industry standards that are later 25 41 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 revisions than those referenced in the GALL report which 1 was published in 2010.

2 And finally, we have one plant

-specific 3 program which is the periodic surveillance and 4 preventative maintenance progra

m. This program 5 includes a variety of aging activities that could not 6 readily fit within the scope of the GALL review programs 7 without taking exceptions to those provisions.

8 And at this point, we can talk about the 9 diesel crankcase vent, if it's appropria te. 10 MEMBER BALLINGER: I have

-- 11 MR. YOUNG: It's the last

-- oh, sorry.

12 MEMBER BALLINGER:

-- another question.

13 I didn't notice it in the presentation. So in going 14 through the audit and going through the SER and going 15 through this, I could not for the l ife of me figure 16 out what the current status was of the shroud

-- the 17 core shroud. What is the current status of the shroud?

18 MR. SHERMAN: I'm Todd Sherman from 19 Entergy. I'm the vessel internal engineer. The 20 current status of the shroud is per the BWR 21 V IP-76-1-alpha. We are classified as a Category 22 Charlie or Category C shroud.

23 MEMBER BALLINGER: Yeah, you were A, then 24 you got -- 25 42 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 MR. SHERMAN: We were at the Bravo

-- 1 MEMBER BALLINGER: I got that right, yes.

2 MR. SHERMAN:

-- prior to the last outage.

3 MEMBER BALLINGER: So I got that part.

4 But then there was

-- how much crack do you have? And 5 what's the five cycle conductivity been trending?

6 MR. SHERMAN: We inspected the shroud 7 three times previous. Specifically the weld tha t is 8 in question is the H - 9 MEMBER BALLINGER: H

-4, yes. 10 MR. SHERMAN:

-- beltline weld. It was 11 first inspected in 1997 with no identified cracking, 12 and that was performed from the outer diameter with 13 a little over 50 percent of the welding being inspe cted. 14 And then it was inspected again in 2008 from the inner 15 diameter with approximately 90 percent of the coverage 16 inspected. And it was found to have about nine percent 17 of the inspected length had flaws or cracks in it.

18 And we reinspected again in 2017 from the 19 outer diameter. We inspected once again a little over 20 50 percent of the length of the weld. And I don't 21 remember the exact figure but I believe it was between 22 40-50 percent of what was inspected was found to have 23 flaws or cracks in it.

24 MEMBER B ALLINGER: So there's no fix 25 43 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 that's been applied?

1 MR. SHERMAN: Correct. We have evaluated 2 the shroud according to the flaw evaluation criteria 3 in BWR-76 and found that it still meets the maximum 4 inspection interval that there's enough structural 5 integrity maintained in the remaining uncracked 6 ligaments of the weld.

7 MEMBER BALLINGER: And that applies out 8 to the license extension length?

9 MR. SHERMAN: The next scheduled 10 inspection would be 2027 which I believe is beyond the 11 expira tion of the current license.

12 MEMBER BALLINGER: Okay.

13 MR. SHERMAN: Yes?

14 MEMBER BALLINGER: And who made the 15 shroud? Who made the shroud?

16 MR. SHERMAN: I believe it's Sun 17 Shipbuilders. I'd have to look.

18 MEMBER BALLINGER: Okay. Because it 19 makes a differ ence. 20 MR. SHERMAN: Yes.

21 MEMBER BALLINGER: It makes a difference.

22 MR. SHERMAN: Finding the manufacturer has 23 been a big player to who gets cracked and when.

24 MR. MEDOFF: This is Jim Medoff from the 25 44 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

(202) 234-4433 WASHINGTON, D.C. 20005

-3701 (202) 234-4433 staff. I was responsible for the review of the BWR 1 vessel internals program. If you ask the same question 2 when the staff presents, I'll explain what I did to 3 look at it and to review everything that Todd just talked 4 about here.

5 MEMBER BALLINGER: Right. Thank you.

6 CHAIRMAN SKILLMAN: I f you would like to 7 talk about the crankcase vent now, that's fine.

8 MR. YOUNG: Okay.

9 CHAIRMAN SKILLMAN: But let me tell you 10 how we got to this part of the discussion.

11 MR. YOUNG: Okay.

12 CHAIRMAN SKILLMAN: In the safety 13 evaluation, page 2

-50, is the state ment, Entergy 14 responded to an RAI stating the subject diesel crankcase 15 vent pipes do not have a license renewal intended 16 function since venting the crankcase is not necessary 17 for the diesel to operate under emergency conditions.

18 So this marine engineer wi th an unlimited horsepower 19 diesel engine license says, I'm not sailing on that 20 ship. 21 (Laughter.)

22 MR. YOUNG: Right. And we agree. That 23 statement is incorrect.

24 CHAIRMAN SKILLMAN: Thank you.

25 45 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 MR. YOUNG: Based on the comments that 1 you've provided and the statement in the SER, we're 2 preparing a supplement to that RAI response. And we 3 agree that venting of the subject diesel generator 4 crankcases is necessary. The original RAI response 5 should have more clearly stated that the vent lin e 6 intended function was to vent the crankcases outside 7 the diesel rooms.

8 And the potential failure of the vent line 9 due to aging effects would be loss of pressure boundary 10 which would not result in the loss of a vent function, 11 but it would result in a loss of venting outside the 12 diesel room. And that would not impact the safe 13 operation of the standby diesel generators.

14 CHAIRMAN SKILLMAN: It might mess up the 15 room, but it won't impact the diesel.

16 MR. YOUNG: Right. And therefore, we will 17 be submitting an RAI supplement to the NRC staff to 18 remove the statement that the crankcase venting is 19 unnecessary.

20 CHAIRMAN SKILLMAN: Thank you.

21 MR. YOUNG: Okay.

22 CHAIRMAN SKILLMAN: Please proceed.

23 MR. YOUNG: Okay. On this slide, on the 24 topic o f commitment management and controlling the 25 46 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

(202) 234-4433 WASHINGTON, D.C. 20005

-3701 (202) 234-4433 commitments that we've made for license renewal, 1 Entergy has a fleet program that covers management of 2 commitments for all our nuclear plants including 3 commitments for license renewal.

4 Entergy's program is based on the 5 commitment management guidance in NEI 99

-04 that the 6 NRC staff has endorsed. We have successfully used this 7 commitment management program for our previous license 8 renewal projects including projects for plants that 9 implemented license renewal commi tments and are 10 successfully operating in the period of extended 11 operation.

12 For each River Bend license renewal 13 commitment, the commitment management program 14 identifies the actions needed to implement the 15 commitments and identifies the owner responsible for 16 its implementation. Assignments will include actions 17 such as a creation of implementing procedures for new 18 aging management programs and implementation of 19 enhancements to existing aging management programs.

20 And that completes my portion of the 21 presentati on, and I'll turn it over to

-- 22 CHAIRMAN SKILLMAN: Thank you, Garry.

23 MR. YOUNG:

-- John Ventosa.

24 MR. VENTOSA: So again, thank you for 25 47 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 meeting with us this afternoon. We truly do appreciate 1 the challenges and borderline, I guess, advice with 2 some of the modifications you spoke to. And we will 3 act upon each and every comment. So we do appreciate 4 that. 5 We are fully committed to continuously 6 improving our aging management programs, but we do have 7 strong ownership at the site of tho se programs. And 8 we fundamentally sound path successfully managing the 9 aging effects through 60 years of operations.

10 And in addition, Entergy is committed to 11 continuously investing in the plants, and I think we've 12 showed you that today in plant modificati ons to ensure 13 the safe, reliable operation through the period of 14 extended operations.

15 If there's no further questions, that 16 concludes our presentation. Thank you.

17 CHAIRMAN SKILLMAN: John, thank you.

18 Just to hold here, colleagues. Before we change teams , 19 might any of you have a question for the Entergy 20 leadership here?

21 MEMBER BROWN: I just wanted to amplify 22 a perspective a little bit on that earlier comment.

23 This system is an in

-plant system and is largely within 24 a boundary. But if you

-- even though you probably 25 48 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 don't have them defined this way, it would be called 1 a Level 4 security from an access standpoint.

2 This is really not a programmatic issue 3 as much as it is a control of access

-- remote access 4 issue. And my fundamental concern I've tried to convey 5 is that while my statement is not 100 percent correct, 6 almost all cyber issues and upgrades and revisions are 7 reactive. 8 In other words, you are always responding 9 to what has already killed somebody else. And nobody 10 is out the re sitting there, oh, gee, the guy could make 11 access this way or that way. You're not preventing 12 all circumstances. There are always holes. Now, that 13 is not exactly

-- there are some obvious holes that 14 you can plug. But there is the non

-obvious ones th at 15 you can't, and that's where all the problems come about.

16 That's why I would encourage you

-- I was 17 going to ask the question on your circuit breaker.

18 I presume those are digital

-based circuit breaker 19 controls. Same issue as if you had those connected 20 into a distributed control system or they're via part 21 of the big network that has direct access from external 22 sources. 23 Such that if you do, if some of them

-- 24 I guess if you got a transmission guy that has to operate 25 49 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 some of those b reakers for some reason, you don't have 1 any choice. More than likely, that's where all of your 2 internal control breakers, the big ones or small ones.

3 It's best to just keep them totally isolated from the 4 outside world.

5 It wasn't problem in the old days w hen you 6 turned a switch and a little current went and tripped 7 a relay. And the words we used to have in the documents 8 like control of access and things like that for 9 instrumentation control were pretty fundamentally 10 based on the old analog world that we l ived in. And 11 that's the whole thing has changed now relative to the 12 ability to get to a system to do things with them.

13 So I mean, it's just a little more 14 perspective. That's all I'm

-- obviously, I'm not 15 trying to tell you, you can't do them. And that's not 16 the point. It's just to be very, very thoughtful about 17 how you allow that access. You can hurt yourself in 18 the long run.

19 MR. VENTOSA: No, we definitely appreciate 20 the insight.

21 MEMBER BROWN: Thank you.

22 MR. SANDLIN: This is Dan Sandlin again.

23 I want to talk to your point. The BWR level control 24 upgrade will be an extension of the existing Ovation 25 50 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 system and has already been inspected by Sam

-- I can't 1 remember. He was talking on the

-- we were the first 2 plant to be cybersecurity inspected, and that Ovation 3 system was already there. They looked at it in depth 4 and found no issues. We do have data diodes. You can't 5 talk into it. You can talk out, but you can't talk 6 in. It's part of our process.

7 MEMBER BROWN: Are they hard ware data 8 diodes or they're

-- 9 MR. SANDLIN: Yes.

10 MEMBER BROWN:

-- software? In other 11 words, it's a physical hardware? You might have 12 something that can give you a transmitted receive, but 13 you disconnect the receive. That's the point.

14 MR. SANDLIN: The y can't get into us.

15 MEMBER BROWN: Okay. That's fine.

16 You've thought it then.

17 MR. SANDLIN: We did, yes.

18 MEMBER BROWN: Just saying somebody has 19 reviewed Ovation. I remember this has been several 20 years ago when I saw it. And it definitely had 21 bidirect ional -- the ability to be communicated 22 bidirectional. And you have to physically make it

-- 23 you want to make it physically impossible to do so.

24 So thanks.

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-3701 (202) 234-4433 MR. SANDLIN: For the digital breakers, 1 they are independent, standalone.

There's no 2 connections to it.

3 MEMBER BROWN: No connections? Okay.

4 Excellent, thank you.

5 CHAIRMAN SKILLMAN: Thank you, Charlie.

6 Yes sir, thank you. Colleagues, any other comments 7 for the Entergy team? If not, let's swap teams and 8 keep on going. Joe , your team is up.

9 (Pause.) 10 CHAIRMAN SKILLMAN: Manny, whenever 11 you're ready, please.

12 MR. SAYOC: Is that on?

13 CHAIRMAN SKILLMAN: Yes sir, yes.

14 MR. SAYOC: Again, good afternoon, 15 Chairman Skillman and members of the License Renewal 16 Subcommittee. My name i s Emmanuel Sayoc, and I am the 17 project manager for the River Bend Station, Unit 1 18 License Renewal Safety Review.

19 We are here today to discuss the staff's 20 review of RBS license renewal application, or LRA, as 21 documented in our safety evaluation report issue d 22 August 16, 2018. Joining me here at the table are Dr.

23 Allen Hiser, the LR Senior Technical Advisor, and Mr.

24 Albert Wong, Senior Project Manager for the LR who will 25 52 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 be running the slides.

1 Mr. Samuel Graves, Senior Reactor 2 Inspecto r from Region IV is on the phone and will discuss 3 the 71002 inspection. Sitting in the audience and on 4 the phone are members of the technical staff who 5 participated in the review of the national application 6 and conducted the various audits. Next slide, p lease. 7 I will begin the presentation with a 8 general overview of the staff's review. Next, Mr.

9 Graves will present the 71002 inspection results. I 10 will then present the main sections of the safety 11 evaluation report. Next slide, please.

12 On May 25, 2017, E ntergy Louisiana, LLC 13 and Entergy Operations, Inc.

-- collectively referred 14 to as Entergy or the applicant

-- submitted an 15 application for the renewal of RBS operating license 16 for an additional 20 years. The RBS license renewal 17 review process was optimize d from previous license 18 reviews including the Waterford review that you heard 19 about this morning.

20 In particular, the RBS license renewal 21 review used an 18

-month schedule with expanded audits 22 and a streamlined SER that was issued in August 2018.

23 This proce ss also served as a pilot program for the 24 staff review of subsequent license renewal 25 53 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 applications.

1 Consistent with prior license renewal 2 reviews, the staff conducted three centered audits as 3 shown in the slide. The operating experi ence audit 4 was conducted at local offices that are within walking 5 distance with NRC headquarters.

6 The scoping and screening audit and the 7 regional site one and two inspection was done onsite 8 at River Bend.

9 The AMP audits were expanded to about ten 10 weeks and included document reviews via electronic 11 portal and applicant interviews conducted from the NRC 12 headquarters. There was a portion done onsite at River 13 Bend to perform system walk downs.

14 During the operating experience audit, the 15 team conducted an independent search of the plant 16 operating experience for information to determine, "A", 17 whether previously known or recurring aging effects 18 were identified, and "B", whether in light of the plant 19 operating experience, the applicant's LRA aging 20 management progr am can adequately manage the associated 21 aging effects. The operating experience audit results 22 were documented in a report dated January 8, 2018.

23 During the scoping and screening 24 methodology audit, the team reviewed the applicant's 25 54 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 administrative controls governing the scoping and 1 screening methodology and the technical basis for 2 selected scoping and screening results. The scoping 3 and screening methodology audit report results were 4 documented in a report dated January 8, 2018.

5 Durin g the AMP audits, the team examined 6 applicant's aging management programs and related 7 documentation to verify the applicant's programs were 8 consistent with those described in GALL report and with 9 plant conditions and operating experience. The staff 10 review ed the 43 AMPs outlined in the LRA and documented 11 the results in a report dated January 29, 2018.

12 Mr. Graves will discuss the activities of 13 the 71002 inspection in a few minutes. Next slide.

14 As discussed before, the RBS final SER was 15 issued on August 16, 2018 with no open items or 16 confirmatory items. During the staff's in

-depth 17 technical review of the LRA, a total of 119 RAIs were 18 issued, 15 of which were follow

-up RAIs. The final 19 SER will be published as a NUREG following issuance 20 of the new license.

21 I will now direct the presentation to Mr.

22 Graves who will discuss the inspection activities and 23 results associated with this LRA review. Next slide.

24 MR. GRAVES: Thanks, Manny. Good 25 55 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 afternoon, subcommittee members. My name is Sam 1 Graves. I'm a senior reactor inspector in the Region 2 IV office, and my branch is responsible for performing 3 license renewal inspections. This inspection involves 4 four experienced regional inspections with expertise 5 in electrical, civil, nuclear, and mecha nical 6 engineering.

7 The team was onsite February 26th through 8 March 19th, and the inspection report was issued on 9 May 7th. The team reviewed the scoping and screening 10 of components, walk down accessible areas and reviewed 11 25 aging management programs of wh ich 6 were new 12 programs and 19 were existing.

13 The team walked down numerous structures, 14 systems, and components to assess the adequacy of the 15 applicant's license renewal boundaries, material 16 condition, and conformance with their application and 17 the Generic Aging Lessons

-Learned report. Next slide, 18 please. 19 From the walk down, the team determined 20 that the material condition of the facility was very 21 good with one exception that the applicant was 22 addressing related to some corrosion on piping located 23 in the be low ground level piping tunnels.

24 The environment in the pipe tunnels is very 25 56 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 humid, and the pipes were relatively cold resulting 1 in a lot of condensation formation and some subsequent 2 surface corrosion. The applicant was in the pro cess 3 of remediating the pipe to remove the existing surface 4 corrosion and applying an oxy type paint.

5 For the surface water integrity program, 6 the applicant had been performing heat exchanger 7 inspections in their service water system for many years 8 but had not considered crediting these existing 9 inspections as part of their aging management program.

10 The applicant agreed to include the inspections they 11 were already performing into their plant

-specific 12 Periodic Surveillance and Preventive Maintenance aging 13 m anagement program. Next slide, please.

14 So in summary, the team concluded that the 15 applicant performed the scoping and screening in 16 accordance with the rule. The team found that the 17 information was easily retrievable, auditable, an d 18 consistent with the rule. The team verified that the 19 existing programs were effective in managing aging 20 effects, and the new programs provided reasonable 21 assurance that aging effects will be managed. The team 22 also verified that the applicant had a proc ess to track 23 the completion of enhancements and the development of 24 the new programs.

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-3701 (202) 234-4433 So based on the inspection results, the 1 team had reasonable assurance that the programs in place 2 or planned as described in their commitment table will 3 manage the aging effects and ensure the intended safety 4 functions of systems, structures, and components within 5 the scope of the rule.

6 Are there any questions for me?

7 CHAIRMAN SKILLMAN: Sam, thank you. I do 8 have several questions. This is Dick Skillman.

9 MR. GRAVES: Yes s ir. 10 CHAIRMAN SKILLMAN: On page 8 of your 11 inspection report, in the middle of the page, the text 12 is as follows. This is regarding bolting integrity.

13 It is Bravo, 1, 2, and it's Roman IX, M18 is the program.

14 The sentence that I'm sentence that I'm 15 focusing on is this sentence: The second exception 16 related to the inaccessible services of the suppression 17 pull suction strainer submerged bolting. The 18 applicant requested to conducted visual inspection once 19 every ten years instead of once every refueling cycle.

20 The applicant planned to verify the bolting was hand 21 tight. 22 That doesn't make sense to me. What in 23 the world does that mean?

24 MR. GRAVES: Well, sir, my understanding 25 58 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 is that the bolts are normally drilled and lock wired 1 in place. So if they have demonstrated any loosening, 2 the manipulation with your hands would be able to 3 determine that. And from there, that would lead to 4 remedial action.

5 If I remember correctly discussing it with 6 a team leader, they weren't really trying to com municate 7 that you wouldn't put any torque on it. You'd just 8 screw it down mechanic tight or hand tight. That, I 9 don't think, was what they intended to try to 10 communicate in that section.

11 CHAIRMAN SKILLMAN: Just hold on here.

12 Let's get a licensee person who understands hand tight 13 versus torque to 90 or 250

-foot pounds and find out 14 what the answer is. Can someone from Entergy tell us 15 what hand tight means on these very important flanges?

16 MR. SANDLIN: I believe the intent

-- this 17 is Dean Sandlin. I'm sorry. The intent was they were 18 torqued originally to the torqueing requirements. And 19 if they had come loose, it would be secured with the 20 tie wraps

-- I mean, the lock wire that we put on anything 21 over the pool area. And if they h ad come loose, we'd 22 be able to detect by the diver going down and seeing 23 if the connection was loose.

24 CHAIRMAN SKILLMAN: That's fair enough.

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-3701 (202) 234-4433 That's what Sam just explained too. That's all right.

1 It's just the only evidence that the ACRS members of 2 these inspections is what was provided in the SER.

3 And please know that my team members and I read this 4 stuff very carefully so that we discharge our 5 responsibilities as we should. So thank you.

6 Sam, I've got another one.

7 MR. GRAVES: Yes sir.

8 CHAIRMAN SKILLMAN: So on your inspection 9 report, pages 10 and 11, and the wording that caught 10 my attention is this wording at the top of page 11.

11 This is regarding enhancements on one of the programs.

12 And what is important is the way this text reads.

13 The text reads, at least two years prior 14 to entering the period of extended operation, the 15 applicant planned to develop a set of fatigue usage 16 calculations that consider the effects of the reactor 17 water environment for a set of the most limiting reactor 18 coolant system com ponents, considering all stress 19 components for environmentally assisted fatigue, and 20 use the maximum temperature if the average temperature 21 is below the threshold.

22 And they're going to do all of that two 23 years before the PEO and the y plan to develop a set 24 of calculations. That almost sounds like a commitment 25 60 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 for something that just might happen if it happens at 1 all. So I'm wondering what is the firmness of this 2 commitment.

3 MR. GRAVES: Well, sir, that's a good 4 question. I cannot a nswer the firmness of the 5 commitment. That would certainly be something to 6 direct to the licensee. But our impression was that 7 that was their intention.

8 CHAIRMAN SKILLMAN: Fair enough. Now, 9 we're going to ask someone from the licensee to tell 10 us what i t means. 11 MR. MIN: Yes, this is Seung Min with the 12 staff first. And then if I address that question that 13 there is a difference between the current license basis 14 particularly on these requirements mainly based on 15 appendix -- I'm sorry,Section III of ASME code. 16 Before the fatigue analysis, TLA. If we 17 take TLA for the period of extended operation, 18 environmental effects need to be considered. That 19 portion either dealt between the PEO fatigue analysis 20 and the CLB fatigue analysis for to fill in the gap.

21 The applicant identified the enhancement to implement 22 to identify the locations involved environmentally set 23 fatigue analysis. That's all.

24 CHAIRMAN SKILLMAN: Thank you. Can 25 61 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 someone from Entergy confirm that this is a commitment 1 that's embedded in your commitment list?

2 MR. COX: Yes, this is Alan Cox. I'm 3 looking at the commitment list in the SER, and 4 Commitment No. 11 is on the fatigue monitoring program.

5 It says, to enhance it as described in LRA Section 6 A.1.18. And in that section, it discusses this. And 7 the due date for this commitment is enhancement to 8 develop a set of fatigue uses calculations prior to 9 August 29, 2023. And that's the two years prior to.

10 So it is a formal commitment as documented in the SER.

11 CHAIRMAN SKILLMAN: Yes sir. Alan, thank 12 you very much. Thank you.

13 Sam, that concludes my comments. Thank 14 you for a very thorough inspection, and that ends my 15 questions on the inspection report.

16 Manny, back to you.

17 MR. SCHULTZ: Just one. Sam, I think -- 18 this is Steve Schultz. This may be a comment more than 19 a question, but I'd like you to respond. On your last 20 page of discussion, you've indicated that in performing 21 the audit at the site, the information was easily 22 retrievable and auditable.

And then you follow that 23 with a conclusion that existing programs effectively 24 managed aging effect.

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-3701 (202) 234-4433 And my impression is in reading the audit 1 reports, not only the documentation that you've been 2 able to provide and following through the track of 3 inspection that you've accomplished at the site that, 4 in fact, these summary statements are very accurate.

5 You provide a lot of good information in each of the 6 areas to support your conclusions that are presented 7 in the audit.

8 I also notice as I look through the li sting 9 of items that you draw from the documentation at the 10 site that there seems to be in many of the areas that 11 you inspect, if I look at the time history of what you 12 pulled as documentation, that there seems to be an 13 improvement in plant condition, at le ast based on the 14 chronological reporting of events.

15 Am I drawing a proper conclusion, or did 16 I just happen to see things that looked like they 17 demonstrate that trend?

18 MR. GRAVES: I can tell you my 19 communication with the team leader, he was actually 20 very favorably impressed with the material condition 21 of River Bend Station. Greg Pick was the lead inspector 22 on this, and he's done a number of these inspections 23 throughout the region. And he said that this was the 24 most impressive material condition he had seen. So 25 63 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 I think your conclusions, not 100 percent sure how you 1 got there, but that is exactly the conclusion he came 2 to as well.

3 MR. SCHULTZ: Thank you. I'm not taking 4 that as a full confirmation. I just wanted to talk 5 with you about it and get your impressions.

6 MR. GRAVES: I know we very much appreciate 7 that. We try to make the inspection reports thorough 8 and we try to use language that will communicate the 9 issues. And as inspectors, if we say something is 10 adequate, that' s typically a pretty tall compliment 11 for an NRC inspector.

12 MR. SCHULTZ: I understand that.

13 MR. GRAVES: Yes sir. So that's why some 14 of the wording is the way it is. But yes sir, thank 15 you very much.

16 MR. SCHULTZ: Well, your document says

-- 17 the slides we have say that the material condition is 18 good. I think you amplified that by saying it was very 19 good when you made your report today.

20 MR. GRAVES: Yes sir, I did.

21 MR. SCHULTZ: But I'm not taking that

-- 22 I'll take it as you've jus t stated it. I appreciate 23 that. Thank you very much.

24 MR. GRAVES: Yes sir, thank you. Manny, 25 64 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 I think I'm finished. Your turn.

1 MR. SAYOC: Thank you, Sam. We're on 2 Slide 8. In the next few slides, I will present the 3 results of the staff's review of th e LRA as described 4 in the SER. SER Section 2 described scoping and 5 screening of structures and components subject to aging 6 management review. The staff reviewed the applicant's 7 scoping and screening methodology, procedures, quality 8 controls applicable to the LRA development and training 9 of project personnel.

10 The staff also reviewed the various 11 summaries of safety

-related systems, structures, and 12 components or SSCs, non

-safety SSCs affecting functions 13 of safety-related components and SSCs relied upon to 14 pe rform functions applicable to River Bend in 15 compliance with the emissions, regulations for fire 16 protection, environmental qualification, station 17 blackout, and anticipated transients without scram.

18 Based on the review, the results fr om the 19 scoping and screening audit, and additional information 20 provided by the applicant, the staff concludes that 21 the applicant's scoping and screening methodology and 22 implementation was consistent with the standard view 23 plan and the requirements of 10 CF R Part 54. Next 24 slide, please.

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-3701 (202) 234-4433 CHAIRMAN SKILLMAN: Manny, let me ask one 1 or two questions that is on SER Section 2. On SER, 2 page 2-7, at the bottom of the page, the NRC writes 3 this sentence. It is in response to non

-safety-related 4 SSCs providing functio nal support for safety

-related 5 SSC functions. And this is the sentence that I 6 challenge.

7 MR. SAYOC: Okay.

8 CHAIRMAN SKILLMAN: One safety

-related 9 SSC supporting 10 CFR 50.54(a)(1) was identified, the 10 plant drains system, which supports maintaining 11 suppres sion pool inventory for use following a LOCA.

12 And the conclusion of that section is, based on the 13 above, the methodology for identifying non

-safety SSCs 14 whose failure could prevent satisfactory 15 accomplishment of the intended functions is in 16 accordance wit h 50.54(a)(2).

17 It sounds as if this is the single one and 18 only SSC. Is that an accurate conclusion?

19 MR. SAYOC: If I am understanding your 20 question, you're referring to the plant drains.

21 CHAIRMAN SKILLMAN: Yes, it sounds as if 22 tha t is the single one and only and there isn't anything 23 else. And that doesn't make sense. So could it be 24 it's just the wording of your SE? Or is this an example?

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-3701 (202) 234-4433 And failing the words, an example, one would be led 1 to believe it's just this single and on ly one system?

2 MR. HISER: This is Allen Hiser of the 3 staff. I'd be surprised if this is the only system 4 that falls under this category. We can go back and 5 take a look at the SER and bring back to you any 6 clarification.

7 CHAIRMAN SKILLMAN: If you would, a 8 clarification. And it is page 2

-7 of the safety 9 evaluation. And it is the last and final sentence on 10 that page.

11 I've got one other comment on Section 2.

12 This is an RAI response to RAI B.1.10

-2. And this 13 has to do with the internal portions of the SLI CK lines.

14 And the safety evaluation says, the internal portions 15 of the SLICK lines don't matter because they've boosted 16 the boring concentration 25 percent. And that leads 17 to the impression that the SLICK lines can fall apart 18 and you can still poison the core. 19 Well, it sounds like a dandy argument for 20 reactivity, but it doesn't sound like much of an 21 argument for structural integrity inside the reactor 22 vessel. So I'm wondering what the safety evaluation 23 really evaluated.

24 MR. HISER:

Which page was that again?

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-3701 (202) 234-4433 CHAIRMAN SKILLMAN: That is on SER, page 1 2-21 at the bottom of that page.

2 MR. SAYOC: I think that's from the staff, 3 Jim Medoff.

4 MR. MEDOFF: So, this was a matter that 5 was looked at by the staff, Mr. Summerson of DSS and 6 mysel f, as part of the vessel

-- I'm sorry. This is 7 Jim Medoff of the staff. This was as an aspect of the 8 application that was investigated by the both of 9 Division of Safety and Safeguards and by the Division 10 of Materials and License and Renewal. It deals wi th 11 the way the vessel internals program manages the standby 12 liquid control system to manage an ATWS event.

13 In the approved report, the EPRI BWR VIP 14 has concluded that the internal portions of this SLICK 15 system did not need to be age managed because even if 16 it broke, even if you had a through

-all crack and the 17 component fail and you had a blob of boron water coming 18 into the reactor near in the lower plenum, what would 19 happen is eventually the reactor coolant would start 20 to heat up and then it would promote some natural 21 circulation to get the boron up towards the core where 22 you needed it.

23 And then that would start to shut down the 24 reactor with the boron inventory. And then it would 25 68 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 start to cool down and instead you would get this 1 reit erative cycle to make sure you got boron cooling 2 in the core. For that reason, Entergy did not include 3 the internal portions of volume and scope and we 4 wondered about that. We did think about it.

5 And so we basically asked them a question.

6 We wanted to assume. Let's assume that the VIP report 7 is it's questionable, I think, that it really occurred.

8 We asked the question, would you really get adequate 9 mixing if the line broke? Because it's serving a safe 10 shutdown function.

11 From that perspective, we asked a question 12 on that. And we had a teleconference, and Entergy had 13 replied that they had something in their design basis 14 that would account for inadequate mixing which was our 15 big issue on the review.

16 What we did is we went back to the FSAR 17 in the design basis. We did find a statement in their 18 ATWS evaluation and their SLICK system operational 19 statements that said they included an additional 25 20 percent of boron into the boron control tank which would 21 account for any questions of ina dequate mixing which 22 alleviated our concern with the potential through all 23 flaw and warming.

24 CHAIRMAN SKILLMAN: How did that alleviate 25 69 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 your concern?

1 MR. MEDOFF: Because the question is 2 whether the mixing argument in the approved VIP report 3 would be okay.

We had a big discussion with this with 4 the folks in DSS. The conclusion was the additional 5 25 percent for Entergy should be sufficient to address 6 any questions on whether they put adequate mixing if 7 you had a through

-all flaw in the line.

8 CHAIRMAN SKILL MAN: And is all of that 9 documented?

10 MR. MEDOFF: Some of it's documented in 11 the scoping section. Some of it's documented in the 12 review of the AMP and in the audit report. So there's 13 another section which would be the Section 3, a section 14 for the reactor vessel internals AMP that should discuss 15 that as well in one of the action item responses.

16 CHAIRMAN SKILLMAN: Thank you. Go ahead, 17 Manny. Thank you.

18 MR. SAYOC: SER Chapter 3 in its 19 subsections covers the staff's review of aging 20 management programs for managing aging in accordance 21 with 10 CFR 54.21(a)(3). Chapters 3.1 through 3.6 22 include the aging management review items in each of 23 the general system areas within scope of license 24 renewal. 25 70 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 For a given aging management review, the 1 staff reviewed the item to determine whether it is 2 consistent with the GALL report. If an aging 3 management review is not consistent with the GALL 4 report, then the staff reviewed the applicant's 5 evaluation to determine with the applicant has 6 demonstrated assurance that the effects of aging will 7 be adequately managed so that intended functions will 8 be maintained consistent with the current licensing 9 basis for the period of extended operation. Next 10 slide. 11 The LRA describe a total of 43 aging 12 management programs: 11 new, 31 existing, and one 13 plant-specific. This slide identifies the applicant's 14 disposition of AMPs on the left column and the final 15 disposition of AMPs as a result of the staff's review 16 on the right column.

17 One plant-spe cific AMP was provided, all 18 with the exception of the plant

-specific AMP were 19 evaluated by the staff for consistency with GALL report, 20 Rev. 2. Overall, the staff concluded that 22 AMPs were 21 consistent with the GALL report. These included 12 22 new programs and 10 existing programs.

23 In addition, 13 programs were consistent 24 with enhancements, 2 consistent with exceptions, and 25 71 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 5 were consistent with enhancements and exceptions.

1 RBS has one plant

-specific program. Later in the 2 presentation, we will discuss an existing program that 3 was replaced and thus became a new program. Next slide, 4 please. 5 Section 4 identifies time

-limited aging 6 analyses, or TLAAs. Section 4.1 documents the staff's 7 evaluation of the applicant's identification of 8 applicable TLAAs. The sta ff evaluated the applicant's 9 basis for identifying those plant

-specific or generic 10 analyses that need to be identified as TLAAs and 11 determine that the applicant has provided an accurate 12 list of TLAAs as required by 10 CFR 54.21(c)(1).

13 Sections 4.2 through 4.7 document the 14 staff's review of applicable TLAAs as shown. Based 15 on its review of the information provided by the 16 applicant, the staff concludes that either the analysis 17 remained valid for the period of ext ended operation, 18 the analysis has been projected to the end of period 19 of extended operation, or the effects of aging on the 20 intended functions will be adequately managed for the 21 period of extended operation as required by 10 CFR 22 54.21(c)(1)(i), (ii), and (iii) respectively. Next 23 slide, please.

24 Since we have no open or confirmatory 25 72 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 items, we wanted to highlight a few areas of interest 1 in our review. The first area is related to the reactor 2 vessel of neutron fluence TLAA. In its review, the 3 staff identified an issue with the methodology used 4 to calculate the 60

-year neutron fluence values

-- I'm 5 sorry, fluence levels for the reactor pressure vessel 6 RPV. 7 The LRA stated it used an NRC

-approved 8 methodology to determine the neutron fluence values.

9 However, the staff noted that the staff approved 10 methodology is not applicable to RPV beltline 11 components above the active fuel region. The staff 12 therefore issued an RAI requesting justification on 13 how the methodology was expanded to incorporate the 14 qualified above c ore calculation model.

15 In its response, Entergy provided 16 additional core design conservatisms that justified 17 neutron fluence values for the RPV, including the 18 components above the active fuel region.

19 Specifically, the applicant sta ted that the 20 conservatisms in this methodology accounts for 21 potential uncertainties in the above core water 22 densities and considers the bounding power

-flow state 23 point that leads to higher neutron fluence.

24 These conservatisms provide sufficient 25 73 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 demonstrati on that the 60

-year neutron fluence values 1 in the LRA are conservative and meet the intent of 2 guidelines in Reg. Guide 1.190 which demonstrates

-- 3 sorry, which describes methods and assumptions 4 acceptable to the NRC for calculating a neutron fluence.

5 The s taff therefore concluded that 6 associates TLAAs were demonstrated to be acceptable 7 for 10 CFR 54.21(c)(1)(ii). Next slide.

8 MR. SCHULTZ: Emmanuel, one question 9 associated with the vessel neutron fluence. And I 10 guess it really occurred to me to look at thi s further 11 with respect to the evaluations we discussed this 12 morning at Waterford in this area.

13 The SER talks about, just as it is on the 14 slide here, a conclusion that is based upon these 15 conservatisms. Did the staff do any audit ca lculations 16 or anything to demonstrate that what has been reported 17 as conservatisms are validated or is there some 18 experience that the staff has that led you to agree 19 with the conclusions that were being presented? That's 20 one question.

21 The other question I have is, was this 22 information presented by the vendor or was it performed 23 and presented by the applicant?

24 MR. SAYOC: Yes sir. I appreciate the 25 74 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 question. We have Mr. Amrit Patel that I think can 1 better answer your question.

2 MR. SCHULTZ: Thank you.

3 MR. PATEL: I'm Amrit Patel from the tech 4 staff. So the staff didn't base this on anything from 5 an audit. So there were no staff performed 6 calculations to verify that. It was based solely on 7 our information submitted through RAI responses based 8 on staff que stioning of the qualification and 9 validation of the method for these above core region.

10 So the majority of that response is 11 proprietary, so that's kind of why it's couched in terms 12 of conservatisms. But there are several layers of 13 conservatism in the qual ification. So a lot of that 14 is focused on the above core voiding distribution which 15 has a direct influence on the flow

-- direct impact 16 on the fluence. But it's purely the applicant's 17 assessment or analysis.

18 MR. SCHULTZ: You're right. I didn't 19 appreciate the proprietary nature of the calculations 20 and the results thereof. So now, I better understand.

21 Because recently, that is since this morning, I was 22 looking at the SER particularly. So now, I understand 23 why the details aren't there. I had looked at the RAI, 24 and I know what details are there, the RAI response.

25 75 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 The other question I had with regard to 1 the SER presentation of information is that there was 2 an error noted and it was pretty late in the game, in 3 August, associated with the effect of pull power year 4 calculation that had been done. I didn't know which 5 direction that error was made. I presumed it was an 6 issue where you needed to demonstrate more fully the 7 ability of the conservatisms to account for the final 8 results. 9 MR. PATEL: So my understanding, I wasn't 10 directly involved in the finding. But if my memory 11 serves me right, it was related to a transposition 12 error. 13 MR. SCHULTZ: Yes.

14 MR. PATEL: Right. And I do recall it was 15 quite minor. The relative change in

-- yes, if you 16 want to -- 17 MR. SCHULTZ: Only if you're not 18 performing the calculation.

19 MR. PATEL: Right, but I think the way

-- 20 yes, if I understand, I think

-- oh, can you speak to 21 it? Okay.

22 MR. SCHULTZ: I'd appreciate that. Thank 23 you. 24 MR. SHERMAN: Todd Sherman from Entergy.

25 76 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 So unfortunately, the error that was found was in the 1 less conservative direction. And for the past 2 operating cycles, the vendor modeled them as

-is. But 3 for the future projected cycles, they added on an 4 additio nal ten percent conservatism to account for 5 different core

-to-core cycle variations.

6 And so the error that was found was 7 approximately .72 EEPY that were not added onto that 8 irradiation past cycle.

9 MR. SCHULTZ: A cycle is 10 to 11.

10 MR. SHERMAN: That is c orrect. 11 MR. SCHULTZ: Yes.

12 MR. SHERMAN: And so the ten percent margin 13 which was originally 2.866 of EEPY was reduced to 2.086.

14 So it just reduced the overall margin from the future 15 projected cycles irradiation.

16 MR. SCHULTZ: That helps a lot. Thank 17 you. 18 MR. SAYOC: Okay, thank you. The second 19 area of our review that we would like to highlight is 20 related to the use of polymeric material in high voltage 21 insulators. The staff noted high voltage insulators 22 made of polymeric material utilize in the recovery path 23 transmission lines. The applicant stated that 24 polymeric high voltage insulators were installed in 25 77 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 2008. However, the LRA only lists porcelain high 1 voltage material.

2 GALL has addressed porcelain high voltage 3 insulators but no t polymeric high voltage insulators.

4 The staff noted that polymeric high voltage insulators 5 have unique aging mechanisms that can result in aging 6 effects such as loss of insulation resistance and loss 7 of material. Animal excrements containing chemicals 8 s uch as phosphates, ammonia, nitrates at present can 9 contribute to and accelerate aging as well.

10 Thus, the staff issued an RAI requesting 11 inclusion of the polymeric high voltage insulators and 12 evaluation of this site

-specific material

-evaluation 13 combination. The applicant responded by including the 14 polymeric high voltage insulators and provided an 15 evaluation of the pertinent aging mechanisms and aging 16 effects. 17 The applicant incorporated periodic 18 preventive maintenance and inspections to be relied 19 upon to monitor potential age

-related degradation.

20 The staff concluded that inclusion of the polymeric 21 high voltage insulators in the LRA and periodic 22 preventive maintenance and inspections are acceptable.

23 Next slide, please.

24 Another area of review that we would like 25 78 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 to highlight pertains to Entergy's new neutron 1 absorbing material program. The staff found this new 2 program to be consistent with GALL Report AMP XI.M40 3 and will adequately manage the effects of aging.

4 This is a replacement for the Boraflex 5 monitoring program that was previously credited for 6 neutron absorbing material. Due to degradation, 7 Boraflex material currently in the spent fuel pool will 8 not be able to maintain required sub

-criticality margin 9 into the period of extended o peration. 10 Entergy plans to submit an LAR for SNAP

-IN 11 inserts by the end of the third quarter of 2018.

12 Installation is scheduled for June through October 13 2019, and aluminum boron

-carbide neutron absorbing 14 material will be installed prior to the PEO. The s taff 15 finds these acceptable. Next slide, please.

16 CHAIRMAN SKILLMAN: Manny, what 17 examination has the staff given to the new SNAP

-IN 18 material and its survivability in the spent fuel pool?

19 MR. SAYOC: Okay. We have the staff.

20 MR. YODER: Matt Yoder from the NRC staff.

21 We previously reviewed and approved let's say on the 22 order of ten other license amendments for this material.

23 So it's well documented and well tested.

24 CHAIRMAN SKILLMAN: Okay, thank you.

25 79 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 MEMBER MARCH

-LEUBA: Okay. E xcuse the 1 question then. What degradation was found on the 2 Boraflex? 3 MR. YODER: So again, this is Matt Yoder 4 from the staff. Boraflex material, essentially, it's 5 a polymer and it's dissolving. It's well documented 6 there had been multiple information no tices, generic 7 letters, et cetera documenting this phenomena.

8 MEMBER MARCH

-LEUBA: I guess you answered 9 my next question is it's a generic issue. And you're 10 saying there was a generic letter.

11 MR. YODER: Most plants that have this 12 material have done away with it either by replacing 13 with the SNAP

-INs or using a geometric approach, 14 spreading the fuel out, if you have the room to do so.

15 MEMBER MARCH

-LEUBA: Thank you.

16 MEMBER BALLINGER: When they change out 17 the Boraflex, the lifetime g oes from essentially very 18 small to essentially infinity with the new material.

19 So it's a huge difference.

20 CHAIRMAN SKILLMAN: But let me ask this.

21 With the dissolution of the Boraflex, is the fuel that 22 is in the pool that is reintroduced to the core inju red 23 in any way?

24 MR. YODER: Matt Yoder from the staff.

25 80 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 There's no impact on the fuel.

1 CHAIRMAN SKILLMAN: How do you know?

2 MR. YODER: You do have silica going into 3 the water, and you're counting on your reactor water 4 cleanup system to take that out. As far as impact on 5 the actual fuel itself, but we're not aware of any impact 6 on the fuel.

7 CHAIRMAN SKILLMAN: I was just wondering 8 if there's any relationship between dissolution of 9 Boraflex and some of the fuel problems that you're 10 having for which you put in that great big filter.

11 MR. YODER: I would say no.

12 CHAIRMAN SKILLMAN: I would say no too, 13 but I just wanted to ask the question. Thank you.

14 Thank you.

15 MR. SAYOC: Okay, next slide. The final 16 item we want to highlight pertains to the emergency 17 diesel generator crankcase vent lines. This was an 18 item that was brought to the attention to the NRC staff 19 by the ACRS to review the conclusion that the vent lines 20 are not subject to aging management review. The staff 21 appreciates ACRS f or giving this feedback.

22 In RAI 2.3.3.16

-1, the staff noted that 23 the Division I and II Emergency Diesel Generator vent 24 lines as delineated in the Drawing LRA

-PID-08-9B were 25 81 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 not depicted as being subject to AMR. The staff 1 question how the function of the v enting crankcase where 2 the Division I and II Emergency Diesel Generators and 3 the HPCS diesel generator will be maintained during 4 the period of extended plant operations.

5 Entergy responded, in part, the function 6 of venting the crankcase is not necessary for the diesel 7 to operate under emergency conditions. This is shown 8 in the USAR Section 8311.4.1 which lists two sets of 9 conditions under which the diesel will trip, one set 10 for both normal and emergency conditions and one set 11 for normal conditions only.

12 The trip for high crankcase pressure is 13 only listed with a set for normal conditions and not 14 as a required trip for emergency conditions. In fact, 15 the non-emergency trips are bypassed on receipt of 16 emergency start signal.

17 Upon rev isiting this issue and preparing 18 for this ACRS subcommittee meeting, the staff 19 determined that further clarification of the technical 20 content of the applicant's RAI is warranted. To 21 facilitate this clarification, the staff relayed this 22 issue to the applicant such that they would prepare 23 for a discussion here today.

24 Specifically, the staff finds that the 25 82 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 applicant needs to either justify to the NRC why the 1 EDG vent pipes do not have either a 54.4(a)(1) or (a)(2) 2 function. Or if they serve either a 54.4(a)(1) or 3 (a)(2) function, then the applicant needs to propose 4 an aging management program and AMR line items to age 5 manage the vent pipes.

6 As you heard today, Entergy plans to 7 supplement it's RAI response regarding this issue in 8 the upcoming weeks. The staff will review the 9 applicant's supplemental information for completeness.

10 Subsequently, the staff plans to amend the River Bend 11 license renewal safety evaluation report before ACRS 12 full committee meeting on November 1. Next slide.

13 M R. SCHULTZ: Your last comment answered 14 a question I was going to ask. In going through the 15 SER, there are many instances where the staff has 16 documented an additional commitment that was made by 17 Entergy as a part of the interactions that have gone 18 back and forth, especially through the responses to 19 the RAI. So the completion of that documentation is 20 going to be accomplished just in the next few weeks?

21 MR. SAYOC: Well, certainly for the case 22 of the crankcase, we'll

-- 23 MR. SCHULTZ: This one? Oh, okay.

24 MR. SAYOC: We will look through the SER 25 83 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 and see if there's any other items that we need to 1 complete as far as documentation. And we'll update 2 the SER prior to November 1, our full committee.

3 MR. SCHULTZ: November 1, okay. I noted 4 the -- I mean, the examp le I was looking at was this 5 stainless steel underground piping and a commitment 6 to increase the frequency of the inspection above and 7 beyond what was in the original proposal. It'd be two 8 inspections in ten years instead of one. Those things 9 are already documented?

10 MR. SAYOC: Do we have

-- 11 MR. DONOGHUE: This is Joe Donoghue. If 12 there's a commitment that the applicant made and we 13 relied upon it in our review, my expectation is that 14 they made it in the commitment list. Garry is to the 15 mic. 16 MR. YOUNG: Yes, this is Garry Young with 17 Entergy. The commitments and the changes to the 18 commitments that result from the RAI interaction that's 19 documented in the SER have all been captured.

20 And so when we talked about our commit ment 21 management system, that includes the original 22 commitments and then all of the modifications to those 23 commitments. And then when the SER is finally 24 published in the final form, we will go back and verify 25 84 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 that we have correctly captured the changes to the 1 commitments that have occurred as documented in the 2 SER in our system that we have in the plant.

3 MR. SCHULTZ: Okay. So then it's 4 iterative and well understood who's doing what then?

5 MR. YOUNG: It's iterative and we have what 6 we call a living LRA whe re we capture all of this 7 information at the plant. And then by the time the 8 SER is published, we believe we have a completely 9 accurate picture. But we will verify it against the 10 results that are documented in the SER.

11 MR. SCHULTZ: Excellent. Go ahead.

12 MR. HISER: This is Allen Hiser of the 13 staff. And within the SER whenever there is a 14 commitment, there should be a commitment number 15 associated with it so it ties directly. If there is 16 not a number associated with it, then we need to go 17 back and make sure that it is on the list.

18 MR. SCHULTZ: Okay, good. Thank you.

19 MR. OESTERLE: This is Eric Oesterle from 20 the staff. Just another piece of the puzzle. When 21 we get ready to issue a renewed license, what we always 22 do is include a license condition which enforces rolling 23 all those commitments that we've relied on in the SER 24 into the plant's licensing basis the day that we issue 25 85 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 the renewed license. So it gets incorporated that day 1 into the UFSAR.

2 MR. SCHULTZ: Thank you.

3 MR. SAYO C: Okay. On the base of its 4 review, the staff determines that the requirements of 5 10 CFR 54.29(a) have been met for the license renewal 6 of River Bend Station, Unit 1. This concludes my 7 presentation now. If there are any questions, the 8 staff would like to take them at this time.

9 CHAIRMAN SKILLMAN: So colleagues around 10 the table, are there any further questions for the NRC 11 staff on the matter of River Bend license renewal?

12 MEMBER RICCARDELLA: I believe somebody 13 from the staff was going to brief us on the core shroud 14 cracking and how that is going to be monitored into 15 the period of extended operation.

16 MR. MEDOFF: So this is Jim Medoff of the 17 staff. I was responsible for the vessel internals 18 program review. Entergy

-- as has been explained to 19 you before, this is a new process. So we didn't put 20 quite as much information in the SER. But a lot of 21 the things we did review are included in the audit 22 report. 23 We did look at the operating experience 24 for the core shroud as explained in sev eral condition 25 86 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 reports. And we did confirm it was an unrepaired shroud 1 and we were able to confirm that they assessed the extent 2 of cracking including taking into account some 3 proximity rules if cracks were close to one another.

4 What we didn't have from Entergy at the start was 5 whether they had re

-categorized the shroud.

6 What we did was we asked them an RAI on 7 that and Todd Sherman, my counterpart at the utility, 8 explained that they did re

-categorize the shroud and 9 they did put it in an RAI response. So that's 10 documented in the operating experience of the AMP 11 write-up for the VIP or vessel internals program. It's 12 in Section 3.0. And also, we have a write

-up in the 13 audit report.

14 MEMBER BALLINGER: So let me ask the 15 question about the re-categorization. It's usually 16 re-categorized based on dose or fluence or 17 conductivity.

18 MR. MEDOFF: From what I can tell from my 19 reading of VIP 76

-8 documents, re

-categorization based 20 on flaw size reinspection.

21 MEMBER BALLINGER: Okay, flaw size.

22 Ok ay, all right. Because it's A, B, and C.

23 CHAIRMAN SKILLMAN: Colleagues, any other 24 questions for the staff before we release them?

25 87 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 Hearing none, Manny, thank you very much.

1 MR. SAYOC: Thank you, sir.

2 CHAIRMAN SKILLMAN: At this point in the 3 meeting, I w ould like to ask if there are any individuals 4 in the room that would like to make a comment relative 5 to the license renewal activity for River Bend nuclear 6 station. Seeing none, if the phone line is open, if 7 someone is out there, would you please simply s ay hello. 8 PARTICIPANT: Hello.

9 CHAIRMAN SKILLMAN: Thank you. Now, if 10 anybody on the phone line would like to make a comment, 11 I invite you to do so at this time. Please introduce 12 yourself. Hearing none, Kent, please close the line.

13 Colleagues, any final comments for either 14 the NRC staff or the Entergy staff? Hearing none, Manny 15 and to your team, thank you for a very thorough 16 examination of River Bend. And to John Ventosa and 17 his crew from Entergy, thank you for bringing your team 18 all this distance and for the presentations that you 19 have presented to us today.

20 So to the staff and to Entergy, thank you.

21 And with that, we are adjourned.

22 (Whereupon, the above

-entitled matter went 23 off the record at 3:15 p.m.)

24 25 88 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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-3701 (202) 234-4433 1 2 3 4 5 6 7 8 9 10 11 12 13 14 River Bend StationLicense Renewal 1Entergy PresentersNameTitleJohn VentosaChief Operating Officer

-SouthJames HendersonDirector, EngineeringTim SchenkManager, Regulatory AssuranceGarry YoungDirector, Fleet License Renewal 2Agenda *Background

-Site Description

-Plant Status-Licensing History-Major Equipment Upgrades

• License Renewal Project-License Renewal Application (LRA)

-Aging Management Programs and Commitments

• Conclusion 3RBS 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 4RBS 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 5RBS 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)

Construction PermitMarch 25, 1977Operating LicenseNovember 20, 1985Commercial OperationJune 16, 19865% PowerUprateNovember 2000Power UprateLicense Amendment (1.7% Thermal Power Optimization)January 31, 2003LRA SubmittedMay 25, 2017Operating License ExpirationAugust 29, 2025 6RBS Licensing History 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 feedwaterheaters*Upgraded 480 V load center breakers 7Major Equipment Upgrades 8Photos -Digital EHC Human Machine Interface for EHC on the H13-P680 Panel 9Photos -480 V LoadcenterBreakers 10Photos -Carbon Steel Piping ReplacementCarbon Steel Piping Replacement in RF

-18 and RF-19Old Carbon Steel removedNew Carbon Steel PipingNew Carbon Steel Piping 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

• Feedwaterstrainer *Feedwaterlevel control 11Major Equipment Upgrades 12Photos -Neutron Absorber Prototype InsertsStart of absorber insertionFull insertion. Ready to retract tool 13Photos -FeedwaterStrainer 14Photos -FeedwaterLevel Controls 15Major Equipment UpgradesRBS License Renewal Project

• 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 16Safety Evaluation Report

• SER issued August 2018

-No open items

-No confirmatory items 17Major Equipment Upgrades

• 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 enhancementsAging Management Programs and Regulatory Commitments 18Program 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

• Similar new AMPs and AMP enhancements have been successfully implemented at other Entergy plants 19Conclusion

• 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.

• RAI response 2.3.3.16

-1 & SER page 2

-50*ACRS raised question on wording of RAI response

• Agree wording is misleading

-RAI supplement planned to clarify

• Aging effects would not prevent venting 20Standby Diesel Crankcase Vent Advisory Committee on Reactor Safeguards License Renewal Subcommittee River Bend Nuclear Generating StationSafety Evaluation Report (SER

)September 20, 2018Emmanuel Sayoc, Project ManagerOffice 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 3Audit / InspectionDatesLocationOperatingExperience AuditOctober 2

-13, 2017RockvilleScoping &Screening Methodology AuditOctober 24

-26, 2017OnsiteAging Management Program (AMP) AuditsOctober 16

-November 8, 2017November 6

-10, 2017NRC HQOnsiteRegionIV 71002 Inspection: Scoping, Screening, and AMPsFebruary 26

-March 2, 2018March 19 -23, 2018Onsite SEROverview*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 8*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 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 3Applicant's Disposition of AMPs

• 11 new programsAll consistent

• 31 existing programs12 consistent13 consistent with enhancements2consistent with exceptions4consistent with enhancements and exceptions

• 1 plant-specific existing programFinal Disposition of AMPs in SER

• 12 new programsAll consistent

• 30 existing programs10 consistent13 consistent with enhancements2 consistent with exceptions5 consistent with enhancements and exceptions

• 1 plant-specific existing program10Section 3.0.3

-Aging Management Programs

• 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 ElectricEquipment-4.5: Concrete Containment Tendon Prestress Analyses

-4.6: Containment Liner Plate, Metal Containment, and Penetrations Fatigue Analyses

-4.7: Other Plant

-Specific TLAAs SER Section 4 11 Reactor Vessel Neutron Fluence

• Issue:-No basis for the adequacy of the neutron fluencemethodology for RPV beltline components above the active fuel region

• Resolution:

-Fluencemethodology includes sufficient conservatisms:

• Accounting for potential uncertainties in the above

-core water densities*Considering the bounding power/flow statepointthat leads to higher fluence-60-year fluencecalculations 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 Material13*Issue:HV insulators made of polymeric material identified during on

-site audit, while LRA only cited porcelain insulatorsGALL has not evaluated polymeric HV insulators

• RAI requested: Justification for not listing polymeric material in LRADiscussion of site

-specific aging mechanisms, aging effects, and chemical contaminants from animal excrement associated with polymeric HV insulators

• Applicant's RAI Responses:Revised LRA to include polymeric HV insulatorsAddressed pertinent aging effects and mechanismsProposed periodic preventive maintenance and inspections

• Staff's

Conclusion:

Changes in LRA to include polymeric HV insulators, periodic preventive maintenance and inspections are acceptable Neutron Absorbing Material Monitoring Program14*New program consistent with GALL Report AMP XI.M40

• Will adequately manage the effects of aging

• Replacement for Boraflex monitoring program that was previously credited for neutron absorbing materialDue 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

-INinserts end of 3 rdquarter 2018Installation scheduled for June

-October 2019Aluminum boron

-carbide neutron absorbing material will be installed prior to PEO 15RAI 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.

16On the basis of its review, the staff determines that the requirements of 10CFR54.29(a) have been met for the license renewal of River Bend Station, Unit 1

.Conclusion 17Backup Slides HV Insulators: Loss of Material Due to Mechanical Wear18*Issue:EPRI 1003057 states that mechanical wear in porcelain HV insulators is an aging effectGALL report recommends plant

-specific AMP for loss of material due to mechanical wear & reduced insulation resistancePolymeric 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

• Applicant's Response:Metallic components of polymeric HV insulators are similar to porcelain type previously evaluated in the LRALoss of material due to mechanical wear is not an applicable aging effect (same as porcelain insulators)No plant-specific AMP is required

• Staff's

Conclusion:

Applicant's evaluation is consistent with license renewal Standard Review Plan and acceptable 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 Bend's operating license:

According to River Bend's 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 plant's automatic reactor protection systems, or from its operators, could easily end the plant's operating lifetime (e.g., consider the consequences of the unmitigated infrequent incident that occurred at Three Mile Island, in 1979).

If River Bend's 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 Commission's 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 Bend's aging management program should account for the potential increase in infrequent incidents that would accompany the extension in operating lifetime. That is, increasing the plant's 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".