ML122770433

Minutes of the ACRS Plant License Renewal Subcommittee Meeting on September 5, 2012 (Open)

ML122770433
Person / Time
Site:	Limerick
Issue date:	10/01/2012
From:	Wen P Advisory Committee on Reactor Safeguards
To:	Advisory Committee on Reactor Safeguards
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Download: ML122770433 (198)

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U N I T E D S T A T E S N U C L E A R R E G U L A T O R Y C O M M I S S I O NADVISORY COMMITTEE ON REACTOR SAFEGUARDSWASHINGTON, DC 20555 - 0001 October 1, 2012 MEMORANDUM TO:

ACRS Members FROM: Peter Wen , Senior Staff Engineer /RA/ Technical Support Branch, ACRS

SUBJECT:

CERTIFIED MINUTES OF THE ACRS PLANT LICENSE RENEWAL SUBCOMMITTEE MEETING ON LIMERICK GENERATING STATION ON SEPTEMBER 5, 2012 The minutes of the subject meeting were certified on September 29, 2012, as the official record of the proceedings of that meeting. Copies of the certification letter and minutes are attached.

Attachments: As stated cc: E. Hackett H. Gonzalez 1 UNITED STATES NUCLEAR REGULATORY COMMISSION ADVISORY COMMITTEE ON REACTOR SAFEGUARDS WASHINGTON, DC 20555

- 0001 October 1, 2012 MEMORANDUM TO:

Peter Wen , Senior Staff Engineer Technical Support Branch Advisory Committee on Reactor Safeguards

FROM: William Shack, Chairman Plant License Renewal Subcommittee Advisory Committee on Reactor Safeguards

SUBJECT:

CERTIFICATION OF THE MINUTES OF THE ACRS PLANT LICENSE RENEWAL SUBCOMMITTEE MEETING ON SEPTEMBER 5, 201 2 I hereby certify, to the best of my knowledge and belief, that the minutes of the subject meeting are an accurate record of the proceedings for that meeting. ______________

___9/29/12________ William Shack

, Chairman Date Plant License Renewal Subcommittee

Significant Issues Discussed Reference Pages in Transcript

FOLLOW-UP ITEMS Issue Reference Pages on Transcript

Official Transcript of Proceedings NUCLEAR REGULATORY COMMISSION Title: Advisory Committee on Reactor Safeguards License Renewal SubcommitteeDocket Number:(n/a)Location:Rockville, Maryland

Date: Wednesday, September 5, 2012Work Order No.:NRC-1863 Pages 1-136 NEAL R. GROSS AND CO., INC.

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

Washington, D.C. 20005 (202) 234-4433 1 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 UNITED STATES OF AMERICA 1 NUCLEAR REGULATORY COMMISSION 2+ + + + +3 ADVISORY COMMITTEE ON REACTOR SAFEGUARDS 4 (ACRS)5+ + + + +6 LICENSE RENEWAL SUBCOMMITTEE 7+ + + + +8 WEDNESDAY 9 SEPTEMBER 5, 2012 10+ + + + +11 ROCKVILLE, MARYLAND 12+ + + + +13 The Subcommittee met at the Nuclear 14 Regulatory Commission, Two White Flint North, Room 15 T2B1, 11545 Rockville Pike, at 8:30 a.m., William J.

16 Shack, Chairman, presiding.

17 COMMITTEE MEMBERS:

18 WILLIAM J. SHACK, Chairman 19 CHARLES H. BROWN, JR. Member 20 DANA A. POWERS, Member 21 HAROLD B. RAY, Member 22 JOHN D. SIEBER, Member 23 GORDON R. SKILLMAN, Member 24 JOHN W. STETKAR, Member 25 2 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 ACRS CONSULTANTS PRESENT:

1 JOHN BARTON 2 DESIGNATED FEDERAL OFFICIAL:

3 PETER WEN 4 5 6

7 8

9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 3 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 A-G-E-N-D-A 1 Applicant's Presentation . . . . . . . . . . . . 4 2 Staff's Presentation . . . . . . . . . . . . . . 96 3 Public Comment . . . . . . . . . . . . . . . . . 135 4 5 6

7 8

9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 4 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 P-R-O-C-E-E-D-I-N-G-S 1 8:28 a.m.2CHAIRMAN SHACK: The meeting will now come 3to order. This is a meeting of the Plant License 4Renewal Subcommittee. I'm Bill Shack, chairman of the 5 Limerick License Renewal Subcommittee.

6 ACRS members in attendance are Jack 7 Sieber, Dick Skillman, Harold Ray, Dana Powers, John 8 Stetkar, Charles Brown and our consultant John Barton.

9 Peter Wen of the ACRS staff is the designated federal 10 official for this meeting.

11 The purpose of this meeting is to review 12 the License Renewal Application for the Limerick 13 Generating Station Units 1 and 2, the draft Safety 14 Evaluation Report and associated documents. I would 15 note that the ACRS does not review the Environmental 16 Impact Statement.

17 We will hear presentations from the 18 representatives of the Office of Nuclear Reactor 19 Regulation and the applicant, Exelon Generation 20Company, LLC. The subcommittee will gather 21 information, analyze relevant issues and facts, and 22 formulate proposed positions and actions as 23 appropriate for deliberation by the full committee.

24 The rules for participation in today's 25 5 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 meeting have been announced as part of the notice of 1 this meeting previously published in the Federal 2 Register. We have received written documents from Dr.

3 Lewis Cuthbert of the Alliance for a Clean Environment 4 regarding today's meeting.

5 A transcript of the meeting is being kept 6and will be made available as stated in the Federal 7Register notice. Therefore we request the 8 participants in this meeting use the microphones 9 located throughout the reading room when addressing 10the subcommittee. Participants should first identify 11 themselves and speak with sufficient clarity and 12 volume so they can be readily heard.

13 We have several people on phone bridge 14 lines listening to the discussion. To preclude 15 interruption of the meeting the phone line is placed 16 on a listen-in mode.

17 We will now proceed with the meeting and 18 I call upon Ms. Melanie Galloway of the Office of 19 Nuclear Reactor Regulation to introduce the 20 presenters.

21MS. GALLOWAY: Okay, great. Thank you, 22Dr. Shack. My name is Melanie Galloway. I'm the 23 acting director of the Division of License Renewal at 24 NRR. And as always on behalf of the staff we are 25 6 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 pleased to be here today to interact and discuss the 1 Limerick License Renewal Application with the ACRS 2 subcommittee.

3 There are a few things I want to note 4 first. We do have representatives from the staff here 5to support our presentation. We have next to me 6Patrick Milano, the project manager for Limerick. He 7 has recently been assigned in the last month so we're 8indoctrinating him early to the process of license 9 renewal in participating in this meeting.

10 I also have a number of branch chiefs here 11to support. Dennis Morey is our Safety Projects 12Branch chief. Michael Marshall is the branch chief 13 associated with our Electrical and Structural Branch.

14 And Raj Auluck is in the front row over there and he 15 is our branch chief for the Aging Management of Plant 16 Systems.

17 In addition, Michael Modes is here from 18 Region I to talk about the inspection process 19associated with Limerick license renewal. And also we 20 have Jim Gavula who's a representative from our Region 21 III office actually assigned to license renewal but 22 placed in Region III.

23 I did want to note a few things about the 24 application. First of all, the Limerick application 25 7 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433is the first application that we have reviewed 1 consistent with GALL Rev 2. So that's of particular 2 note. We do believe that GALL Rev 2 was successful in 3 introducing certain efficiencies in the review and I 4 think the Limerick application supported that.

5Also, I want to note that the Limerick 6 application was of particular high quality, and that 7 also contributed very significantly to the efficiency 8 and effectiveness of the NRC review. That was also 9indicated by the number of RAIs we had on the 10 application. The number of first round RAIs was only 11 150 and that is sufficiently lower than other 12 applications which we have in-house now and which we 13 see. 14 And of note also is the fact that the 15 Limerick application is part of the Exelon fleet and 16 the quality of the application not only applies to 17Limerick but it's also typical of what we see from 18other Exelon applications. So kudos to the applicant 19for the good job they've done in making our job 20 easier.21 In addition, I also want to commend the 22 applicant for the background documentation that they 23provided to us on our onsite audits. They were 24 extremely thorough and again that made our review much 25 8 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433more efficient and much more effective. And as a 1 result of this exchange we've had with the applicant 2 in light of the quality that they provided to us our 3 safety review has maintained the current schedule and 4 that is good news.

5Also, as a result of the exchange we've 6 had so far you'll see that we only have two open 7 items. And again that is reflective of the low number 8 of RAIs and the quality of the application.

9 Now, I do want to mention while I know the 10 ACRS does not review the environmental aspect of the 11 reviews I do need to note that the waste confidence 12 decision which was recently issued by the court has 13affected review schedules for license renewal. And 14 while the safety review schedule for Limerick remains 15on schedule the effect of the waste confidence 16 decision and the determination of what the staff needs 17 to do in order to respond to the court's decision is 18going to cause an ultimate delay associated with 19 Limerick license renewal.

20 At this point that concludes my opening 21 remarks and I'll turn it over to Mike Gallagher, 22 senior vice president for license renewal with Exelon.

23MR. GALLAGHER: Okay. Thanks, Melanie.

24Good morning. My name is Mike Gallagher. I'm the 25 9 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 vice president of license renewal for Exelon. Slide 1 1, please?

2 Before we begin today's presentation I'd 3like to introduce the presenters. To my right is Gene 4 Kelly. Gene is the Limerick license renewal manager 5for Exelon. Gene has 38 years nuclear power plant 6 experience including 13 at Limerick.

7 To Gene's right is Dan Doran and Dan is 8 the Limerick engineering director. Dan has 21 years 9 nuclear power plant experience at Limerick.

10To Dan's right is Mark DiRado. Mark is 11 our programs engineering manager. Mark has 13 years 12 of nuclear power plant experience at Limerick.

13To Mark's right is Barry Gordon. And 14 Barry is a senior consultant and corrosion specialist 15 with Structural Integrity Associates.

16 In addition to today's presenters we also 17 have with us Chris Mudrick. And Chris is our senior 18vice president of mid-Atlantic operations. And we 19 have Tom Daugherty and Tom is our site vice president 20 at Limerick. Slide 2.

21 Slide 2 shows our agenda for the 22 presentation. We will begin with the description of 23 the site and an overview of the operating history 24followed by an overview of the License Renewal 25 10 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 Application. We will then continue with the 1 discussions of the open items regarding the 2 suppression pool and operating experience.

3 We've developed a comprehensive, high-4 quality License Renewal Application and a robust aging 5 management program that will ensure the continued safe 6operation of Limerick. We appreciate this opportunity 7 to make this presentation and look forward to 8 answering any questions you might have.

9 I'll now turn the presentation over to Dan 10 Doran. Dan?

11MR. DORAN: Thank you, Mike. Slide 3, 12 please. Good morning. My name is Dan Doran and I am 13 the engineering director at Limerick Generating 14 Station.

15 Limerick Units 1 and 2 are General 16 Electric BWR/4 designs with Mark II containments.

17 They are owned and operated by Exelon Corporation.

18 The Limerick Generating Station is located 19 on the east bank of the Schuylkill River in Limerick 20 Township of Montgomery County, Pennsylvania and it's 21 approximately 4 miles down-river from Pottstown, 35 22 miles up-river from Philadelphia.

23 On this slide you will see the Schuylkill 24 River which is one of our two non-safety related 25 11 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 makeup water sources, the Schuylkill River Pump House, 1 the independent spent fuel storage installation, the 2 Unit 1 225 kV switchyard, the Unit 2 500 kV switchyard 3and the spray pond which is our ultimate heat sink.

4 Limerick Generating Station also has four emergency 5 diesel generators per unit.

6 Slide 4, please.

7MR. BARTON: Let me ask you a question on 8this slide. Schuylkill River sometimes overflows its 9 banks. I used to live in Cherry Hill so I remember 10about the Schuylkill River. What effect has the 11 Schuylkill River high levels affected the site?

12MR. DORAN: It has not affected the site.

13 The site ground elevation is 85 feet above the 14 Schuylkill River.

15 MR. BARTON: All right, thank you.

16MEMBER SKILLMAN: Question, please. With 17 the two different voltages in the switchyards do the 18 two units generate at different voltages?

19 MR. DORAN: They do not generate coming 20out of the generator at different voltages. They are 21 stepped up to 200 kV for Unit 1 and 500 kV for Unit 2.

22 The generator terminal voltages are the same.

23 MEMBER SKILLMAN: Thank you.

24MEMBER SIEBER: Are those switchyards 25 12 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 interconnected?

1 MR. DORAN: Excuse me?

2MEMBER SIEBER: Are those switchyards 3 interconnected onsite?

4MR. DORAN: They can be interconnected 5through a cross-tie line that we have. We can supply 6power from both units from either of the units that 7 are cross-tied. That's correct.

8 MEMBER SIEBER: Thank you.

9 MR. DORAN: Slide 4, please. This slide 10 provides an overview of Limerick's history as well as 11 the major station improvements.

12 Limerick was initially licensed to 3,293 13 megawatts thermal in 1984 for Unit 1 and 1989 for Unit 14 2. Following a successful startup test program 15 commercial operation began in 1986 and 1990 for Unit 16 1 and Unit 2 respectively.

17 A 5 percent increase in rating of power on 18 both units was performed in the 1995-1996 time frame.

19 And on April 8th of last year a 1.65 percent 20 measurement uncertainty recapture power uprate was 21 implemented which increased the thermal rating on each 22unit to their current rating of 3,515 megawatts 23 thermal.24 Exelon has continued to make substantial 25 13 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 improvements to both Limerick units such as turbine 1 rotor replacements, digital feedwater control 2 modifications, independent spent fuel storage 3 installation, main transformer replacements, and most 4 recently the addition of recirc pump adjustable speed 5 drives.6 Limerick is operated on 24-month fuel 7 cycles. The current 24-month capacity factor is 91.6 8 percent for both units.

9 The License Renewal Application was 10submitted on June 22nd, 2011. Our current licenses 11 expire on October 26th, 2024 for Unit 1 and June 22nd, 12 2029 for Unit 2.

13 I will now turn it over to Gene Kelly who 14 will present to you the highlights of the License 15 Renewal Application.

16MR. KELLY: Thank you, Dan. Slide 5, 17 please? Good afternoon. My name is Gene Kelly and 18I'm the license renewal manager. My portion of the 19 presentation covers the highlights of our License 20 Renewal Application including aging management 21 programs, commitments and an overview of the two open 22 items in the SER. Slide 6, please.

23 In preparing the application Exelon used 24 industry and NRC guidance with the goal of making our 25 14 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 application as consistent with the GALL as possible.

1 Our submittal was based on GALL Revision 2.

2 There are 45 aging management programs 3 including 34 existing programs, 11 new programs 4 developed. Twelve of the existing programs required 5no changes to align with the GALL. Twenty-one of the 6 existing programs required enhancements to align with 7the GALL. The one exception to the GALL is associated 8 with the reactor head closure stud bolting program, 9 specifically the preventive measures for measured or 10 actual yield strength.

11 There are 47 license renewal commitments.

12 These commitments are managed under an existing 13 process consistent with NEI 99-04 and tracked as part 14 of that process.

15 Forty-five of these commitments are 16associated with aging management programs. One 17 commitment institutes operating experience program 18 enhancements and another commitment will reevaluate a 19 Unit 1 recirculation nozzle safe-end flaw that was 20 mitigated by a mechanical stress improvement process 21 in 1992 prior to entering the period of extended 22 operation. Slide 7, please.

23 CHAIRMAN SHACK: Before we get into this 24I just -- since we don't seem to have an opening to 25 15 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 discuss other parts of the license renewal thing let 1 me just ask some questions about some other items.

2 One I was concerned about, I was looking 3 at the flow-assisted corrosion evidence and in 2008 4 you had 62 inspections on Unit 1 and you replaced 454 5feet of small-bore piping. In 2010 you did 102 6 inspections and replaced 442 feet of small-bore and 74 7 feet of large-bore piping.

8 On trending that doesn't look real good.

9 How much susceptible piping do you have left and do 10 you anticipate that kind of replacement going forward 11 in the future?

12 MR. DIRADO: Sure. The flow-accelerated 13 corrosion program is fleet-wide and it's based on 14known industry regulations and requirements. As part 15 of the flow-accelerated program all of the susceptible 16piping is modeled. I don't have a total number 17 available to me. We can certainly provide that.

18But what I will say is that as we make 19 enhancements and learn where our areas are we actually 20have been increasing the number of inspections. So 21what you say is possibly an increasing trend in the 22 number of inspections and replacement. I look at it 23 as good management of the program to, one, understand 24where the vulnerabilities are and ensure they get 25 16 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433monitored prior to having failures. If you look at 1 our failure rate I'm sure that would show you it had 2 favorable results for the station.

3CHAIRMAN SHACK: Okay. There's another 4 one that was kind of curious and it says, you know, no 5 preventive or mitigative measures are directly -- the 6FAC program. The program considers water treatment 7changes that may affect FAC rates. For example, water 8 treatment amines, hydrogen water chemistry, hydrogen 9 addition, or any change that might affect the pH or 10 dissolved oxygen concentration. What systems do you 11 use amines and hydrazine in?

12 MR. KELLY: I think I'd like to ask Greg 13 Sprissler of our chemistry department to address that 14 question, please.

15MR. SPRISSLER: Greg Sprissler. I'm with 16the chemistry department at Limerick Station. We are 17 currently not using any amines for treating chemicals 18 at Limerick Station.

19CHAIRMAN SHACK: Yes, that's sort of what 20 I figured. It just seemed like a curious statement.

21 Okay. 22The next question is on fatigue. And 23 you've got an environmental cumulative usage factor 24 for one system, reactor water cleanup -- I like this 25 17 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 number -- 0.9990. It's certainly less than 1.

1 You're crediting there the reduction in 2the number of cycles. Does that also include a finite 3 element analysis to get the stresses down, or is that 4 with a sort of a classic code type conservative stress 5 number?6MR. KELLY: It was a classic code type 7 approach.8 CHAIRMAN SHACK: Okay.

9 MR. KELLY: We didn't do finite elements 10 but we have additional information in the corrective 11 action process where we're going to address that with 12a more refined analysis. And that's actually underway 13 and working in the corrective action process.

14CHAIRMAN SHACK: Okay. Then just another 15 question. You had some cracking in your core shroud 16welds on both units. Just how much cracking are we 17 talking about here? Feet, inches, kilometers?

18MR. KELLY: I'll field it initially and 19then I'll ask our engineer to come up. But we've 20 examined all the horizontal and vertical welds at this 21 point and we do see cracking in most of those welds.

22 In some of them it's more than 10 percent of the 23 inspected length and so that puts you on an increased 24 inspection schedule.

25 18 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 Most of those cracks are considered quite 1 shallow and the hydrogen water chemistry appears to be 2 effective. And we'll continue to examine it per the 3BWRVIP guidelines and you know, do the appropriate 4structural integrity analyses to make sure we have 5 adequate margin for the shroud.

6 MR. BARTON: Do you have any mechanical 7 restraints on your core shrouds?

8MR. KELLY: No, none. We did not put any 9 fixes in, John. No tie rods or anything like that.

10 MR. BARTON: I got it.

11 MR. KELLY: No repairs.

12CHAIRMAN SHACK: Is that material 304-LM?

13MR. KELLY: I'd like to ask Michelle 14 Karasek, our vessel internals engineer, to address 15that question. Michelle, the question is about the 16 material type of the shroud.

17MS. KARASEK: Hello, this is Michelle 18 Karasek, Limerick site RPV internals program owner.

19 It is 304-L.

20 CHAIRMAN SHACK: 304-L.

21 MS. KARASEK: Yes.

22 CHAIRMAN SHACK: And the weld metal?

23MS. KARASEK: I don't have that 24 information.

25 19 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433CHAIRMAN SHACK: But the cracking is in 1 the base metal typically.

2MS. KARASEK: That's correct. It's in the 3 heat-affected zones.

4CHAIRMAN SHACK: In the heat-affected 5 zones.6 MS. KARASEK: That's correct.

7 CHAIRMAN SHACK: But even in the 304-L 8 welds.9 MS. KARASEK: Yes.

10 CHAIRMAN SHACK: Okay.

11MR. BARTON: Are you through with core 12 shroud? Let's jump from core shroud to steam dryers.

13 I noticed you've got some steam dryer issues that 14 you've found during inspections. What's the current 15 status of your steam dryers in both units?

16MR. KELLY: Michelle, could you please 17 address that question?

18MS. KARASEK: This is Michelle Karasek 19from Limerick site RPV internals program engineer. We 20have extensively inspected the core shroud -- I'm 21 sorry, the steam dryer on both units in accordance 22with GE SILs and the VIP-139. We completed all 23 baseline inspections.

24 We do have some minor IGSCC cracking 25 20 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433mostly in the support ring. There are a few hood seam 1 weld indications that are also IGSCC and one fatigue 2 flaw in a hood seam weld that has relieved itself and 3 is not showing any signs of new or changed in growth.

4MR. BARTON: So you're nowhere near 5 talking about steam dryer replacements I take it.

6MS. KARASEK: No, we're not talking about 7steam dryer replacements. I know it's on as a 8 proposal if we go to EPU. That is something that is 9 being looked at and evaluated.

10 MR. BARTON: Thank you.

11MEMBER STETKAR: Bill, are we going to try 12 to get all of the peripheral things out of the way 13 first?14CHAIRMAN SHACK: Yes. I assume once we 15 get into the liner that will probably.

16 MEMBER STETKAR: If so I've got a couple 17of questions, one on buried pipe. And the RHR service 18 water and essential whatever you call it, ESW system.

19 I got confused as I was reading back and forth among 20the LRA and RAIs and SER and all of those 21 abbreviations. Are you going to do internal 22 inspections of the buried safety-related service water 23 piping?24MR. DORAN: We are going to perform 25 21 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433inspections of that piping. We are currently in 1 progress of replacing large-bore RHR service water 2 piping in our pipe tunnel.

3 As we remove that piping it will provide 4 an opportunity which we will take advantage of to send 5 an inspection method down and inspect the internals of 6 the large-bore underground piping.

7 MEMBER STETKAR: Okay. Are you going to 8 be doing -- that's fine, but the period of extended 9 operation is a ways in the future. Are you going to 10 be doing periodic inspections, internal inspections of 11 that piping during the period of extended operation?

12 MR. DORAN: We do not have plans at this 13time to do that. If the opportunity presents itself.

14MR. GALLAGHER: But we added a commitment 15 to do the inspection when accessible.

16MEMBER STETKAR: But isn't that 17 inconsistent with Rev 2 of the GALL report that says 18if you've had indications of leakage or problems 19 you're supposed to do something like a 5-year periodic 20 inspection of 25 percent of the piping or something 21 like that?

22 MR. GALLAGHER: For external?

23 MEMBER STETKAR: Internal.

24 MR. GALLAGHER: For internal? No, we're 25 22 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 consistent with the GALL.

1MEMBER STETKAR: Okay. I guess we'll ask 2 the staff about that. Take that as a heads up. No, 3 I'll wait till you get up so that we can get to the 4 applicant's presentation.

5One other question. On the closed cooling 6 water systems there's a statement made that they're 7 not susceptible to stress corrosion cracking because 8the temperatures are below 60 degrees C. That sounds 9 fairly low. I mean some of those systems, they're 10 diesel generator cooling water systems, they are 11 recirc pump cooling water. Are the outlet 12 temperatures uniformly below 60 degrees C on all of 13 those closed cooling water lines?

14MR. KELLY: I'd like to ask Mark Miller of 15our license renewal project team to address that 16 question, please.

17MEMBER STETKAR: It seemed a rather modest 18 temperature to me.

19 MR. MILLER: Mark Miller, Exelon license 20 renewal. The portions of the system that have 21 stainless steel are less than 140 degrees Fahrenheit.

22 There are portions in the system that exceed 140 23 degrees but there is no stainless steel material in 24 those portions.

25 23 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 MEMBER STETKAR: Okay, thank you.

1MR. BARTON: I've got a couple more if you 2want to take the time now, Bill. Closed treated water 3 systems. In early 2009, January 2009 and again in 4 November you had some problems with the turbine 5closure cooling water system. You had high 6 consumption of the chemicals from that system and 7 turned it over to a system engineer for the root cause 8 and that's where the story ends in the documents I was 9 reading.

10 In November then you had an increasing 11 trend in nitrate concentration in that same system.

12Now, can somebody explain what was going on in that 13 system and has that problem been resolved?

14MR. KELLY: Yes, I would like to have Greg 15 Sprissler of the chemistry department address that, 16 please.17MR. SPRISSLER: Greg Sprissler from the 18Limerick chemistry department. That was a TBCW 19 system. It was identified by our chemistry analysis, 20sampling analysis program. We were making frequent 21 adds of sodium nitrate and copper corrosion inhibitor 22 to the system. It was documented in our CAP system.

23 It was given to engineering for 24 evaluation. At first they thought it was air and 25 24 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 leakage but that did not follow through because of the 1 copper corrosion inhibitor was not being -- was being 2 affected also.

3 It was determined by engineering that it 4was a leakage. I don't have details on how the system 5was repaired, where the leak was found, how it was 6 repaired but I can tell you that the system is very 7stable now. We have not made sodium nitrate adds 8since 2010 and we have not made a copper corrosion 9 inhibitor add since 2011.

10MR. BARTON: Okay, thank you. In the 11 bolting -- this goes to one of your aging management 12programs, your bolting integrity program. In the 13 literature I went through I noticed there was a lot of 14 examples of loose connections resulting from improper 15 tightening of mechanical connections throughout the 16 documents. And that's more than I would expect.

17 That's more than I've seen in a lot of other plants.

18 My question there is did you recognize 19 that? Did it require additional training and 20maintenance or what? Because it was an awful lot of, 21 you know, non-torque loosening and it just seemed like 22 there was a problem there somewhere in your system.

23Has that -- have you tackled that? Has that been 24 resolved?25 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 MR. KELLY: It has. I'd like to ask Ron 1Hess of the project team to address that question. I 2 think he has the details on this.

3MR. HESS: My name is Ron Hess. I'm with 4 the Limerick license renewal team. Those events did 5result in enhancements to our training program. First 6 of all, specifically some of those related to the use 7and application of hydraulic torque. So that was 8 specific training that was instituted for maintenance 9 personnel using hydraulic torque wrenches. And also 10 our continuing training includes modules for 11maintenance personnel on bolting connections. And 12those were enhanced as well to include the OE from 13 those events.

14MR. BARTON: Thank you. And looking at 15the application and scoping I was confused here.

16Section 2.4 talked about screening of structures. The 17 auxiliary water pipe tunnel which is located under the 18 auxiliary water enclosure houses safety-related piping 19 and is in scope for license renewal.

20 And a couple of paragraphs later it says 21 the lube oil storage enclosure is located above below-22 grade piping tunnel that contains safety-related 23 piping. However, I couldn't find that this lube oil 24 storage -- that this was in scope.

25 26 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433Can somebody explain that? It seems like 1they're both over an enclosure that's got safety-2 related piping yet one's in scope and the other is 3 not. Lube oil storage enclosure is not included in 4 scope and yet the auxiliary water tunnel located under 5the auxiliary water enclosure is in scope. So I don't 6 understand what's going on here.

7MR. GALLAGHER: We had received an RAI on 8 that also and had some clarity so maybe we can have 9Dave Clohecy. Can you please give us the info on 10 that?11MR. CLOHECY: My name is Dave Clohecy and 12 I'm a member of the Exelon license renewal team. We 13 revised the LRA in response to an RAI. We clarified 14in that response that the non-safety related aux 15 boiler enclosure and the non-safety related aux boiler 16 pipe tunnel were both in scope because they were 17 immediately adjacent to the reactor enclosure which is 18 safety-related. We also clarified that the lube oil 19 structure is not in scope because it is not 20 immediately adjacent to the reactor enclosure.

21 MR. BARTON: Okay, thank you.

22CHAIRMAN SHACK: Just do you currently 23 have a hardened vent for your wet well?

24 MR. GALLAGHER: No, we do not.

25 27 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433CHAIRMAN SHACK: So that will be something 1you'll be considering? I know that your most 2beneficial SAMDA was an ATWS vent. Would you consider 3 making your hardened vent larger than the 1 percent 4sort of decay heat level vent that most plants are 5 considering?

6 MR. GALLAGHER: I don't know what we're 7considering, Dr. Shack, on that but we're heavily 8 involved with the industry initiatives and we'll put 9 the appropriate size hardened vent in in accordance 10 with the orders.

11MR. BARTON: I've got one more.

12Inspection of water control structures. Your program 13 is to monitor all water chemistry inside every 5 years 14and your program was enhanced to do that. What's your 15 current frequency and why did you increase it to every 165 years? Is there something going on in your 17 groundwater that's indicating it's getting aggressive 18 or something?

19MR. KELLY: I believe the answer is no but 20 I think I'd like to have Dave Clohecy answer that 21 question if he can.

22MR. CLOHECY: My name is Dave Clohecy and 23I'm a member of the Exelon license renewal team. Our 24groundwater, a few wells have tested with chloride 25 28 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433that is a little higher than we would like. However, 1 the groundwater is below the level of the safety-2related structures and we are monitoring the sub-3 drainage sump head as a leading indicator of the 4 concrete condition.

5MR. GALLAGHER: So I think we went to the 6 5 years just to be consistent with GALL.

7MR. CLOHECY: Yes, that's correct. The 8 GALL requires that 5-year monitoring so we are doing 9 that at 5 years per the GALL.

10MR. BARTON: That's it. The only other 11 questions I've got are on the liner. We're going to 12 get to that.

13 MR. GALLAGHER: We can continue on.

14MR. KELLY: Okay, slide 7 then. There are 15two open items in the Limerick SER. Slide 8, please.

16 The first open item involves aging 17management of the suppression pool liner. The NRC 18staff is requesting more information in four main 19 areas: our prioritized approach to implementation of 20 the coating maintenance plan, the method utilized for 21 examination of the coating underwater, the expected 22 corrosion mechanism present in the suppression pools, 23 and the incorporation of acceptance criteria for 24 downcomer examinations into aging management 25 29 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 procedures.

1 We will provide background information on 2 the suppression pool and we will address the four 3 areas where the NRC staff is requesting more 4information in our presentation. The additional 5 information to address this open item will be 6 submitted to the NRC staff for their review.

7 The second open item involves operating 8experience for aging management programs. The staff's 9 question relates to the review of aging management 10 related operating experience in the period between the 11 issuance of the renewed licensee and the 12 implementation of our operating experience program 13 enhancements which we've committed to enhance within 14 2 years following issuance of the renewed licenses.

15 Exelon will conduct appropriate operating 16 experience reviews to close this gap. Additional 17 information will be submitted to the NRC staff for 18their review. This completes our discussion of the 19 operating experience open item.

20 I will now turn the presentation over to 21 Mark DiRado --

22 MEMBER POWERS: Can I ask you a question 23about your coating material. That's a sacrificial 24 zinc?25 30 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 MR. KELLY: Yes. Inorganic zinc.

1 MEMBER POWERS: What is it really?

2MR. KELLY: I'm not sure I understand your 3 question. Can you repeat it, Dr. Powers?

4MEMBER POWERS: Well, we know it's not 5just zinc that you put on it. What else does it have 6 in it?7MR. GALLAGHER: Mark Miller, it's a 8 question about the coating system, the present coating 9 system. Do you have the details of that?

10 MR. MILLER: Mark Miller, Exelon license 11 renewal. The question is what other constituents are 12 within the zinc coating?

13MEMBER POWERS: Yes, like zinc chromate or 14 something like that.

15MR. MILLER: I don't have the information 16 on that.17MR. GALLAGHER: It was the original 18 coating system in the plant.

19 MR. MILLER: I can tell you that it's a 20 carbozinc and a Dimetcote.

21 MEMBER POWERS: In that case I know what 22 it is. Thank you.

23MEMBER SKILLMAN: Gene, I'd like to ask 24you a question, please. In the second open item we 25 31 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 are talking in this room today about granting an 1 extension that will become effective 20 years from 2 now. This open item is asking why operating 3 experience won't be factored in until 2 years after 4 that future 20-year period begins.

5MR. KELLY: Actually it's 2 years after 6 issuance of the licenses, not when the PEO begins, Mr.

7 Skillman.8MR. GALLAGHER: Yes, the issue was that 9 the staff guidance in the ISG says to institute your 10 enhancements to get to the operating experience 11 program immediately upon receipt of the license. We 12 said that we wanted a 2-year transition because we 13 want to implement the enhancements fleet-wide.

14 The basis for that was our existing 15program is very, very robust. I mean our whole 16 application is built on our existing program so we 17 think the existing program in itself is good.

18 But with that we are enhancing the 19 program. We're going to do it fleet-wide. And then 20 the staff had asked for what, in this transition 21 period what are you going to do. And so we're going 22to address that also. So we're putting these 23 enhancements in fleet-wide and for Limerick at least 2410 years before the PEO. So it's pretty much meeting.

25 32 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433MEMBER SKILLMAN: Thank you, that 1clarification helps. It surprises me that the wording 2 isn't worded that way such that what you're really 3 communicating is we will make sure that we've got the 4 operating experience well embedded many years before 5 the PEO.6 MR. GALLAGHER: And that's our intent.

7 MEMBER SKILLMAN: Thank you.

8 MR. GALLAGHER: Okay, Gene.

9MR. KELLY: Okay, so Mark I'll turn it 10over to you. And Mark will discuss the suppression 11 pool.12 MR. GALLAGHER: Yes, so this is our main 13part of our presentation. We're going to go into the 14 details, background and details of the suppression 15 pool. So, open-ended questions you have, that's this 16 period.17 Mark?18MR. DIRADO: Thank you. Slide 9, please.

19Good morning. My name is Mark DiRado and I'm the 20 engineering programs manager at Limerick. First I 21 will summarize some key points about our suppression 22 pool. I will then address those in detail on the 23 subsequent slides. Slide 10, please.

24 The Limerick primary containment is a 25 33 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433robust Mark II design. It incorporates a 6-foot to 8-1 foot thick reinforced concrete containment and a 250 2 mil thick metal leakage barrier. The liner is twice 3 as thick as needed to withstand design loads.

4 Excellent water chemistry in the 5 suppression pool in combination with a normally 6 inverted suppression pool airspace results in a low 7 general corrosion rate.

8 The material condition of the liner has 9been thoroughly characterized as part of ASME code 10 inspections and the material condition is therefore 11 well understood.

12MEMBER SKILLMAN: Mark, would you explain 13that a little more thoroughly please? How is it 14 documented? How long has the material condition been 15 examined? What level of confidence should we have 16 that that statement is thoroughly accurate?

17MR. DIRADO: We have a very high level of 18 confidence in the water condition, the inspections 19 being performed and the documentation of the results.

20 Each inspection that's performed is done by 21 professional divers using calibrated instruments 22 underwater. Those are documented in the results and 23 they are reviewed by the station after each subsequent 24 outage. The data is collected and reviewed by 25 34 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 engineering to validate corrosion rates, trends and 1 factor into future re-coating or repair plans.

2MR. GALLAGHER: And Mr. Skillman, we're 3going to go into this in a lot of detail. It's 4 actually on slide 21 where we go into the inspections.

5 And one point we wanted to make up front 6 is we have -- are transitioning from an inspection 7 program to a comprehensive aging management program.

8 And we feel we're doing this early, you know, because 9 like we said we're 12 years away from PEO. So you 10 know, as you know IWE only came in play in like the 11 year 2000 so there's only been a couple of inspections 12 in accordance with IWE.

13 We instituted the aging management program 14 for Unit 1 as we started the last outage so we say we 15thoroughly characterized it. For Unit 1 we have done 16 a complete survey inspection of the suppression pool 17 and we're going to present to you a summary of the 18information here in this presentation. And we'll tell 19 you how -- that we take that data and why we're very 20 confident that we can identify the areas that require 21 attention in the coating system.

22 MEMBER SKILLMAN: Thank you.

23MR. DIRADO: Exelon is committed to an 24aggressive aging management program. This will be 25 35 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 begun well in advance of the period of extended 1 operation. And we'll ensure that the suppression pool 2 liner's intended function is maintained throughout the 3 period of extended operation. Slide 11, please.

4 The Limerick Mark II primary containment 5design is shown in the diagram on this slide. Primary 6 containment consists of a drywell and a suppression 7 pool. A slab separates the upper and lower sections 8of containment. The continuous carbon steel liner 9which is shown in the blue color on the slide 10functions as a leakage barrier. The suppression pool 11 is situated below the drywell.

12 Downcomers provide a direct path to the 13water in the suppression pool. That's for uncondensed 14 steam from the drywell during the design basis event.

15 Slide 12, please.

16 The suppression pool has a continuous 17carbon steel liner. It's coated with inorganic zinc.

18 The liner is 250 mils thick and functions as a leakage 19 barrier for the reinforced concrete containment 20 structure. The strength of the containment is derived 21 from the 6-foot to 8-foot thick reinforced concrete.

22 The liner has 100 percent thickness 23 margin. In that 125 mils of general or large area 24 thickness is required for liner structural integrity.

25 36 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 A minimum local area thickness of 62.5 mils is 1required for structural integrity of the liner. This 2 means that flaws less than 2.5 inches in diameter and 3 up to 187.5 mils in depth could be tolerated. Slide 4 13, please.

5 I will now describe the original coating 6 system applied to the suppression pool liner and its 7intended function. The continuous carbon steel liner 8is a service level 1 inorganic zinc sacrificial 9 coating.10 MR. BARTON: Excuse me. What's the life 11of this coating? The useful life. I mean you're 12 using this coating maybe 20-25 years or pick a number.

13 Do you know what the useful life of this coating is?

14 What's the vendor say is the useful life of this?

15 MR. GALLAGHER: Well the vendor, they'll 16 give you a short number. Basically --

17 MR. BARTON: What's their short number?

18MR. GALLAGHER: Well, I think we had an IR 19 that said like 15 years or something like that.

20MR. BARTON: Yes, that's what I was 21 thinking.22MR. GALLAGHER: But really the life of the 23coating is sustained by the implementation of the 24coating maintenance plan. That's what we're proposing 25 37 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433in this aging management program. Basically you touch 1 up the coating and the coating with good chemistry, 2 water chemistry, the type of water that's in the 3 suppression pool you can maintain the coating system 4for a long, long time. So there's really no such 5thing as, you know, a specific service life. It's 6 maintained by the coating maintenance.

7MR. BARTON: The only reason I'm asking 8 that is been there and done that. You probably know 9 about this, right? You were there.

10 MR. GALLAGHER: Right, right.

11MR. BARTON: We had suppression pool with 12-- it had some kind of, I don't know, zinc something 13 coating. Life 20-25 years. Well, before that time it 14 got so bad the coating maintenance program did not 15 work and we ended up with complete re-coating of 16suppression pool liner. And I'm just wondering if 17 that's -- I don't mean to interrupt your presentation 18 but you know, eventually we gave up and had to 19 completely re-coat it.

20 MR. GALLAGHER: Yes, and that's always a 21 possibility. I think we, you know, like I said we 22 transitioned from an inspection program to an aging 23management program. I think at the right point 24 definitely when you look at our data on Unit 2, Unit 25 38 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-44332 is very, very, you know minor. Unit 1 we have a 1 little bit of catchup to do. But I think you'll see 2 that, you know, I think we got it at the right point.

3 We can get into a good coating maintenance plan.

4 MR. BARTON: Okay.

5 CHAIRMAN SHACK: But I mean, just coming 6back to John's point. The material in your 7 environment is really the same as a Mark I 8 containment. I mean you know they're different 9 containment designs but the corrosion problem is 10 similar. And we sort of know the older Mark Is 11 certainly have coating problems. It's just hard for 12 me at least to understand why you're going to be any 13 different than those plants are.

14MR. BARTON: That's where I was coming 15 from.16MR. GALLAGHER: And we recognize that 17because we have plants of those vintage also. And we 18 know the -- and we'll get into the presentation, but 19 the larger implications of say replacing your coating 20 system. There's a lot of issues with that. Obviously 21 you have to offload the core, you have to -- in that 22 outage you have to reduce the ECCS inventory during 23that outage. There's radiological issues, industrial 24 safety issues. In fact, we're going through that at 25 39 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433one of our plants that we're in process on. So we 1 think that if we can do this early we can maintain the 2 system. 3 And then, however, we'll get into showing 4you our commitment. The commitment is clear, we have 5 to meet the criteria going into the period of extended 6 operation. So, if the only way to do it is to replace 7 the system then that's what we'd have to do.

8 CHAIRMAN SHACK: The focus here is on 9structural function. There's also the Generic Letter 10 9804 kind of thing of preventing particulate products 11 and stuff. There are places you seem to have lost a 12 lot of coating that, you know, you may not be getting 13 a structural limit but I assume that you're generating 14 particulate at a fairly good clip.

15 Both of these have to be met and that was 16 one of the things that was confusing to me, that you 17 say you're meeting the XI S8 protective coating thing 18 which is sort of an ASME, or an ASTM kind of thing to 19I think look at it as a 98-04 kind of a problem. And 20 then you're off here in IWE space looking at it as a 21 structural problem.

22Are both of those consistent? Is one more 23 limiting than the other?

24MR. GALLAGHER: Yes, and actually this is 25 40 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 where we're talking about what the intended function 1 is of the coating system, the present coating system.

2MR. GALLAGHER: Well, you made it 3 inorganic zinc for some reason.

4MR. GALLAGHER: Yes, and the reason, just 5 like you said Dr. Shack, is that the -- you know, you 6balance the two issues, asset protection and not 7clogging the suction strainers for ECCS. So this 8 coating system was actually picked because it kind of 9 dissolves. It doesn't cause problems with clogging of 10 the suction strainers.

11CHAIRMAN SHACK: Well, but that's the 12adhesion of the film. What I'm worried about is that 13 you're getting corrosion products.

14MR. GALLAGHER: Yes, and part of our aging 15 management program is to de-sludge, clean up the 16suppression pool every outage. And that's part of our 17 commitment to -- and when we do that, let's see, Ron 18 Hess, Ron, how much particulate corrosion products do 19 we remove each outage now?

20MR. HESS: Okay, Ron Hess, Limerick 21license renewal team. Typically on a yearly basis we 22 generate about 100 pounds of material that is then 23 removed during our de-sludging operations during 24 routine outages.

25 41 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433MR. GALLAGHER: So it's not really that 1 much and the suction strainers are huge.

2 MR. BARTON: One hundred pounds?

3 CHAIRMAN SHACK: Yes, I was going to say 4 we'll have Sanjoy come in and talk to you about 100 5 pounds of particulate.

6 MEMBER STETKAR: That's 100 pounds under 7 for all practical purposes stagnant conditions. No 8 blowdown forces, no --

9 MR. KELLY: Correct.

10MEMBER STETKAR: -- nothing deciding to 11 dislodge a lot of other material.

12MR. GALLAGHER: Yes, it's the corrosion 13 products from -- that's in the piping system.

14MR. KELLY: And it's a very -- Dr. Shack, 15 a very small fraction of the design loading of those 16new strainers. They're much bigger and can 17 accommodate quite a bit more than that.

18MR. HESS: Yes, if you want me to add some 19 information, our design requirements for the ECCS 20 suction strainers include things like 900 cubic feet 21 of insulation, 1,000 pounds of sludge, 150 pounds of 22miscellaneous dust and dirt, another 50 pounds of 23 corrosion products.

24 And so from a design basis standpoint the 25 42 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 loading on the strainers from material that we remove 1 each de-sludging operation is far more than what the 2 strainers are designed to accommodate.

3CHAIRMAN SHACK: Is that based on full-4 scale testing of thin bed effects?

5 MR. HESS: That's --

6 (Laughter) 7 MEMBER POWERS: Just say no.

8MEMBER SKILLMAN: That sounds like a small 9 number and we're laughing because maybe it is but you 10know, a 40-pound plate, steel, 1 square foot and 1-11 inch thick is 40 pounds. That's 2 and a half square 12 feet of steel -- if it's iron? Fighting its way out 13 of your system into sludge, if it's iron.

14That's not really inconsequential. Think 15 about it. You might say well there are an awful lot 16of square feet. Well, I'm not sure that gives me any 17 comfort. Most of the square feet are probably covered 18with your inorganic coating. I'm concerned about all 19 the stuff you can't see that's wasting away.

20MR. GALLAGHER: Most of the corrosion 21 products are coming from the piping systems which are 22 attached, not from the system itself. When you see 23the -- not from the liners. When you see the coating 24coverage right now we have about 85 percent of the 25 43 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 coating still intact on Unit 1, 96 percent on Unit 2.

1 So, it's relatively, you know, a small area that's 2 affected by the --

3 (Laughter) 4CHAIRMAN SHACK: It's square feet. That's 5 probably not so insignificant.

6MEMBER SKILLMAN: That's what I think. I 7 mean if you really make it thin you'd say golly, that 8 could be a lot of stuff.

9MR. GALLAGHER: What I'm saying is the 10 corrosion products are not predominantly coming from 11 the liner, they're coming from the piping system.

12 MEMBER SKILLMAN: I got it.

13 MR. GALLAGHER: Okay, so Mark, why don't 14 we start with this slide again on --

15 MR. DIRADO: Sure.

16MR. GALLAGHER: There's some key points 17 here we wanted to make sure.

18MR. DIRADO: Okay. As stated previously, 19 the continuous carbon steel liner has a service level 20 1 inorganic zinc sacrificial coating.

21 The coating was applied to the liner with 22a 6 to 8 mil dry film thickness. The intended 23 function of the coating is to maintain adhesion so as 24 to not adversely affect the ECCS strainers by 25 44 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 clogging. The coating --

1CHAIRMAN SHACK: If that was its intended 2 function you wouldn't put it on.

3MR. GALLAGHER: It's intended function is 4 because that's the safety-related function of the 5 coating system is to prevent clogging of safety-6 related ECCS systems.

7 MR. DIRADO: Right. We --

8 MR. GALLAGHER: We have it on there --

9 CHAIRMAN SHACK: Okay, but not only by 10 maintaining adhesion but also by reducing corrosion 11 product development.

12 MR. DIRADO: It's probably a combination 13 but you know, in effect it was to make sure that you 14 don't have flaking of your coating from, you know, 15 post accident that would go onto your suction 16 strainers and clog it.

17MR. DIRADO: We view the coating system as 18 a design feature that assists in asset protection.

19CHAIRMAN SHACK: You mean you put this on 20 just to make sure it wouldn't flake off?

21MEMBER POWERS: I mean that makes no sense 22 at all. 23MR. GALLAGHER: We put it on for asset 24 protection.

25 45 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433MEMBER POWERS: To make sure it didn't 1 fall off.2MR. GALLAGHER: The safety-related 3function is so it doesn't affect the safety-related 4 systems.5MEMBER POWERS: You put it on so you don't 6 corrode your steel.

7 MR. GALLAGHER: For asset protection.

8MEMBER POWERS: And when you do your 9 inspection the only vehicle you have to tell that it's 10 failing to meet this adhesion is to see it flaking 11 off, is that right?

12 MR. GALLAGHER: Visual, yes.

13MEMBER POWERS: You don't have a good 14 mechanism to tell us when these things are getting old 15 and we're losing the hydroxyl bonding?

16 MR. GALLAGHER: Actually, we do dry film 17thickness measurements and we'll talk to you about 18 that in the inspection slide. You can see how thick 19 the coating is remaining.

20MEMBER POWERS: You get the thickness but 21 you don't know anything about the adhesion to the 22 surface other than --

23MR. GALLAGHER: Yes, that would just be --

24MR. BARTON: Unless you see a lot of 25 46 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 bubbles when you're doing it.

1MEMBER POWERS: Yes, I mean it's just a 2 visual thing. It's the only thing we have.

3CHAIRMAN SHACK: Don't some of the ASTM 4 requirements have adhesion tests?

5MR. GALLAGHER: I think when you apply the 6 coating.7 CHAIRMAN SHACK: Apply the coating.

8 MR. GALLAGHER: But not when you're --

9MEMBER POWERS: What we know is that as 10these materials age you start developing a carbon 11 yield signal when you do an infrared spectrum monitor.

12 And I suspect it's the anolic hydroxide is changing 13into a carbonyl group. But I don't know that for a 14 fact. 15 I know only the empirical observation but 16 we've just never developed an instrument that you 17 could take in and run over the coating and say oh, 18it's getting bad here and it will start flaking off 19five outages from now. I mean we just don't have 20 that. 21 Anecdotally, I asked the Air Force how 22they knew when to change -- when to paint their 23 airplanes. And the guy told me we have invested 24millions of dollars in academic research in this. But 25 47 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 in the end some sergeant goes out, looks at it and 1decides whether to paint it or not. There are lots of 2 devices out there but nobody uses them. It's just 3 unfortunate. I mean the only thing you can do is you 4 look at it.

5MR. GALLAGHER: We'll get into our visual 6 inspection methods in subsequent slides. We'll tell 7 you how we do that. Okay? Mark.

8MR. DIRADO: Thank you. The service life 9 of the inorganic zinc coating is sustained by 10 implementation of our coating maintenance plan.

11 Frequent full ASME exams, spot re-coating, protective 12large area re-coats and frequent cleaning of the 13suppression pool and removal of sludge sustain the 14 service life of this coating system.

15MEMBER SKILLMAN: Mark, how do you know 16 your coating maintenance plan and program are robust 17and effective? If it's your protection how do you 18 know it's working for you?

19 MR. DIRADO: We -- for effectiveness of 20 the plan each inspection that's done in review has a 21 documented engineering evaluation that follows it to 22 validate a number of specific factors that will weigh 23 into either augmentation or moving up of the re-24 coating or additional methods to, corrective 25 48 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 maintenance to maintain the liner appropriately.

1MEMBER SKILLMAN: How do you weave 2 operating experience into that?

3 MR. DIRADO: The operating experience is 4gathered for each coating application. It's discussed 5in or prior to coating work. Each outage there's a 6set of meetings that are held that will factor that 7 in. We use industry experts that factor in operating 8 experience from the past and bring those to the 9 station. We leverage INPO and other outside sources 10 for that, plus we have a large fleet where operating 11 experience for coating maintenance is leveraged as 12 well.13 MEMBER SKILLMAN: Thank you, Mark.

14MR. BARTON: Who does this work? Is this 15 contracted out each outage?

16 MR. DIRADO: Yes.

17 MR. BARTON: And who does the inspection 18 of the contractor's work?

19MR. DIRADO: The contract organization 20 currently is UCC.

21MR. BARTON: They do their own? The plant 22 doesn't go and look, inspect the work that's done in 23 the liner in the outage?

24MR. GALLAGHER: We have an underwater 25 49 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433construction company. It's a diving outfit because 1it's done underwater. And they will do the 2 inspections.

3MR. BARTON: They do the work and inspect 4 their own work?

5MR. GALLAGHER: And they would do the 6 coating. And so you know, it's all done in accordance 7 with their inspection procedures.

8 MR. BARTON: But you never go and check?

9 MR. GALLAGHER: Well, we have --

10MR. BARTON: The guy does the work and 11 inspects it and turns in some paperwork. But do you 12 ever double-check?

13MR. GALLAGHER: With our own diving folks?

14 No. 15 MR. BARTON: You don't.

16MR. GALLAGHER: There's some oversight 17that occurs by video, you know, and that type of 18 thing, but they have a QA program in accordance with 19their quality assurance program. We verify that they 20 meet all those requirements.

21 MR. BARTON: Okay.

22MEMBER BROWN: So they do the work and 23 then they tell you they did it right.

24 MR. BARTON: Yes, exactly.

25 50 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433MR. GALLAGHER: Well, there is oversight.

1 I mean, you know, they're on video the entire time.

2MEMBER BROWN: I heard the video part but 3I didn't understand it. They've got a camera and 4 you've got somebody off --

5 MR. GALLAGHER: Yes.

6MEMBER BROWN: -- sitting up there looking 7 at what they're looking at so you can see that they 8spot a bubble or they spot an area or they take a 9 measurement or whatever they do underwater?

10MR. GALLAGHER: There's some oversight 11just because they're on video the entire time. But 12 you know, the company.

13MEMBER BROWN: Watching guys float around 14 underwater, you know, just trying to get a picture of 15how you get a feel for whether their inspection is 16 actually effective or not other than them telling you 17that it is. That's -- I'm just following up on that.

18MR. BARTON: Yes, well that's my concern.

19 You know, there's nobody from the plant that goes and 20 actually looks at what did this guy do and the 21 paperwork he turned in, does it really -- is it really 22 what happened.

23 MEMBER BROWN: Auditing the papers.

24MR. BARTON: You know, and I'm not saying 25 51 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 you have a dishonest contractor, I'm just saying you 1 know at some point you go check his work and that's my 2 concern. You're not doing that.

3MR. KELLY: We have him here today and 4he's going to address that in a later slide. But I 5 think I'd like to ask our program owner, George 6Buduck, to step up and maybe address this. George is 7 the ISI engineer at Limerick and George is responsible 8 to implement this program including the oversight of 9 those vendors. So George, you might want to address 10 the question of oversight.

11 MR. BUDUCK: George Buduck, the Limerick 12ISI program owner. We do not review their 13 inspections. We don't specifically have divers that 14 go in and take a look at it to verify the readings are 15 accurate. We don't do anything like that.

16CHAIRMAN SHACK: Do you get to see closeup 17 video of the surfaces?

18MR. BUDUCK: There are some videos that we 19do look at. We do have a picture that we will show 20 later on.21CHAIRMAN SHACK: Yes, I mean I saw that 22 picture. The question is really how much of that 23 inspection you're actually able to monitor with the 24 video or is it just a picture of a, you know, a 25 52 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 region. Or is it, you know, somebody really is 1 actually sort of looking at this inspection.

2MR. BARTON: You know, somebody is sitting 3 there watching this video while the guy's doing the 4 work. Is somebody from the site actually sitting 5 there watching that? Or is it a copy of his film or 6 something he gives you? I'm a little nervous about 7 your oversight of the work that's being done.

8MR. GALLAGHER: The oversight we do do is 9 there is a live video that's occurring during the 10 outage. And we have people that can look at the video 11and do. I'm not saying we're there the entire time 12 but there is some oversight. And we verify that the 13 contractor is doing his work in accordance with the 14 contract.

15 But this work is underwater and we are not 16 there with him underwater but he is -- and we have 17Mark Marquis. Where's Mark? Mark, come up to the 18microphone, please. Mark is our underwater 19construction contractor. So Mark, maybe you can give 20 us some more insight on this and our oversight.

21MR. MARQUIS: Mark Marquis, Underwater 22Construction Corporation. During any given inspection 23 we have video monitors with -- that are relaying 24 pictures right from the diver's helmet at any given 25 53 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 time. 1 We are I'll say subject to I'll call it a 2 spot audit or whatever by plant QC, et cetera.

3 Whether or not they come down is certainly to the 4utility's discretion. So, it's always being played 5back, it's always there. A live feed is always there 6 available at any given time for anybody to watch over 7 our shoulder.

8 MEMBER BROWN: How clear is the video?

9 MR. MARQUIS: The video is --

10MR. BARTON: The water's moving when these 11 guys are --

12 MR. MARQUIS: Yes, the water --

13 MR. BARTON: That creates refraction and 14 everything else.

15MR. MARQUIS: It's -- water clarity is, 16 you know, we have sufficient visibility to conduct the 17 inspection. Generally it's greater than 12 inches, 18 less than 48 for the most part in general.

19MR. GALLAGHER: And we have some pictures 20here we can show you. And they're right from the 21 video that the diver is -- from his helmet cam.

22 MEMBER BROWN: But the diver's using his 23-- Mark's eyeball. It's a clarity. In other words, 24 he's got to be right up against the wall effectively 25 54 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 to tell any condition.

1MR. GALLAGHER: And that is the 2 inspection. So he's a qualified inspector, you know, 3has a level 2 inspection criteria. Mark's a level 3.

4 And you know, they're doing it in accordance with 5 approved procedures and a QA plan.

6MR. DIRADO: And if I could just add, for 7 the inspections when we do conduct these during the 8 outages there is a dedicated site team that works with 9 the underwater coating inspectors. They're reviewed 10 on a shift basis. If there's any questions that are 11 brought up or challenges that come from engineering 12they're provided directly to the team. We've never 13had an issue with going back out and re-looking or 14 clarifying an issue that we have.

15 And as far as general oversight the divers 16 are in communication with that team during the work.

17 There is Exelon personnel provided during the coating 18inspection activities. And they're there to answer 19 any possible questions or challenges or questions that 20 may come up during the course of the coating activity.

21 If I can continue we'll go onto slide 14.

22Thank you. The suppression pool water quality is 23 excellent. It meets the BWR VIP-190 EPRI water 24 chemistry guidelines. The water is nearly a neutral 25 55 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 pH and normally below 90 degrees Fahrenheit where low 1 general corrosion rates are expected.

2 There exists only trace amounts of 3chlorides less than or equal to 2 parts per billion 4 which is 2 orders of magnitude below the recommended 5 limit. Sulfates average less than or equal to 13 6 parts per billion.

7 Primary containment is normally inerted 8with nitrogen. So a little dissolved oxygen is 9present and available to drive corrosion. The general 10 corrosion rate in the Limerick suppression pool is 11 less than 2 mils per year and this value has been 12confirmed by data taken from evaluation grids which 13 are monitored in the suppression pool on each unit.

14 One area that the NRC staff requested more 15 information is the expected corrosion mechanism in the 16suppression pool. I will now turn the presentation 17 over to Barry Gordon who will discuss this issue.

18MR. GORDON: Thank you, Mark. General 19 corrosion of carbon steel is the predominant corrosion 20 mechanism expected at the Limerick suppression pool.

21Pitting corrosion is not expected in the Limerick 22 suppression pools. When carbon steel is essentially 23 exposed to the steel border at ambient temperatures 24 carbon steel simply rusts. It does not pit.

25 56 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 This statement is supported by three main 1 mitigating factors. First, pitting corrosion occurs 2 in alloys that form thin nanometer protective passive 3films on the surface. Carbon steel does not form 4 passive films in the low-temperature high-purity water 5 that's observed in the Limerick suppression pool.

6CHAIRMAN SHACK: Again there's an 7 inspection report that says every floor and wall 8 plate, every downcomer and every suppression pool 9 column has some degree of pitting. Most of the pits 10 and floor plates are less than 50 mils deep and there 11 are hundreds of pits that are less than 30 mils deep.

12MR. GORDON: This is misinterpretation.

13 This is the most common, common thing I see relative 14to pitting. Everyone looks at -- if you look at high 15 magnification of general corrosion you're going to see 16 little indications that look like pits and it's just 17not -- it's just not pitting. It is indeed pits, but 18 it is not the pitting mechanism.

19 Second, pitting of passive alloys such as 20 stainless steel, aluminum alloys, nickel-based alloys, 21 typically occurs in the presence of aggressive anolic 22species, especially chlorides. But this primary 23 pitting agent is not present, essentially not present 24 in the Limerick suppression pools.

25 57 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 MEMBER SKILLMAN: Barry, how do you know 1 that you have identified what could be the aggressive 2 species? You identified chlorides, sulfates. I know 3one case where sulfites were more aggressive than 4either chlorides or sulfates. Could there be other 5 anions or cations in the suppression pool water that 6 would be particularly aggressive right at the water?

7MR. GORDON: If you had -- even if you had 8 aggressive species present which doesn't appear to be 9the case you still need a material that forms a 10passive film. The fact that carbon steel in this 11 environment does not form a passive film like it does 12 in case of embedded in concrete where it does form a 13passive film you still wouldn't -- you have more, a 14 higher rate of general corrosion but you wouldn't have 15 pitting corrosion.

16 MEMBER SKILLMAN: Thank you.

17MR. GORDON: Finally, the suppression pool 18 environment has limited amounts of dissolved oxygen 19 since the airspace above the water is inerted with 20nitrogen during operation. Dissolved oxygen is 21necessary to drive the corrosion process. In other 22 words, the limited amount of cathodic reactant oxygen 23 will mitigate all forms of corrosion in the Limerick 24 suppression pool.

25 58 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 I'll now turn the presentation back to 1 Mark DiRado who will discuss the results of IWE 2 examinations in the suppression pools and the material 3 condition in the liners of both units.

4MEMBER POWERS: When you say that the head 5 space is inerted with nitrogen what is the oxygen 6 partial pressure?

7MR. KELLY: I would like to ask Greg 8Sprissler of the chemistry department if he can 9address that question. Greg, did you hear the 10 question?11MR. SPRISSLER: I did. The partial 12 pressure of oxygen in the suppression pool, was that 13 the question?

14 MEMBER POWERS: And the head space above 15 the pressure.

16MR. SPRISSLER: Greg Sprissler from the 17Limerick chemistry department. I do not have that 18 information, sorry.

19MEMBER POWERS: But the inertion can take 20 that oxygen potential down below -- partial pressure 21 down below a torr in something like that, right?

22MR. GALLAGHER: The tech spec is less than 23 4 percent.

24MEMBER POWERS: Yes, the tech spec is 25 59 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 nonsense, okay, because you go way below that.

1MR. GALLAGHER: Yes, but that's what it's 2 maintained, at least below 4 percent oxygen.

3MEMBER POWERS: But even at 1 percent 4 that's enough dissolved oxygen to drive corrosion, 5 isn't it?

6 MR. GORDON: But a lot of the -- I mean, 7 the oxygen will be consumed with corrosion of the 8 zinc, you know, film and also any exposed carbon 9 steel. Also, you know, the oxygen should be higher 10 concentration at the surface and then it will decrease 11 as you go down.

12 MEMBER POWERS: It ought to.

13 MR. GORDON: Yes.

14MEMBER POWERS: It ought to if it's being 15 consumed.16MR. GORDON: Yes. It's essentially de-17 aerated at the bottom.

18MEMBER POWERS: My contention here is they 19 can't inert it enough to totally suppress corrosion.

20 MR. GORDON: Right, but --

21 MEMBER POWERS: It's just impractical.

22MR. GORDON: Yes. But again, at 90 23degrees Fahrenheit you go from maybe 5 ppm to a 24 significant, to 1 ppm or half a ppm dissolved oxygen.

25 60 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433MEMBER POWERS: Yes, but it's -- it's 1 doing that because it's being consumed.

2MR. GORDON: But it can't be refreshed 3 during the operating period.

4 MEMBER POWERS: Sure it can.

5 MR. GORDON: Well, you have still a slow 6 amount of oxygen.

7MEMBER POWERS: Yes, but it's probably 8fast compared to the corrosion. The corrosion is only 9 2 mils per year.

10 MR. GORDON: Right.

11MEMBER POWERS: The leak into their system 12 is more oxygen than that by a lot.

13 MR. GALLAGHER: Yes, I think your point, 14 Dr. Powers, is that the corrosion, even though the 15oxygen is low there's enough in there to sustain a 16corrosion rate. And I think that we would give you 17 that but the overall environment does support about a 18 2 mil per year corrosion rate and that's basically 19 what we see.

20MEMBER POWERS: Yes, I mean you're 21 inerting it, it helps, but it's not going to suppress.

22CHAIRMAN SHACK: It's not going to 23 eliminate.

24MR. GORDON: No, it's mitigation. It's 25 61 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 not --1MR. GALLAGHER: Yes, we just want to 2 describe the overall environment which is -- supports 3 this 2 mil per year general corrosion rate and that's 4 kind of the point we're trying to make.

5MEMBER POWERS: Okay. I make that but you 6know, to appeal to inertion here. I mean inerting for 7 these guys is inerting for combustion, okay? That's 8what they're looking for. It's not inerting to 9 suppress corrosion.

10 MR. GALLAGHER: Right, exactly.

11MEMBER STETKAR: Do you run your 12 suppression pool cooling and cleanup system 13continuously, sporadically, as needed? Only during 14 outages?15MR. DORAN: We run the suppression pool 16cleanup system prior to our outages to clean up the 17 pool and on certain periodicity we run suppression 18 pool cooling when needed for temperature.

19 MEMBER STETKAR: Temperature.

20 MR. DORAN: That's correct.

21 MEMBER STETKAR: Okay, thank you.

22MR. DORAN: And, I'm sorry, and for 23 surveillance testing.

24 MEMBER STETKAR: Oh, sure.

25 62 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 MR. DORAN: Surveillance testing.

1 MEMBER STETKAR: Thank you.

2MR. DIRADO: Thank you. Slide 16, please.

3 This slide depicts the current material condition of 4the Unit 1 liner using data from the 2012 refueling 5 outage. A little bit of introduction may be necessary 6 at this point for the data so let me walk you through 7 the format of the graphic and how we portray this 8 data.9 The total submerged surface area affected 10 by corrosion is graphically shown on the y axis.

11That's from zero to 100 percent. That's as a function 12 of the metal liner wall loss which is zero to 190 13 mils. The first vertical dashed line is the 10 14 percent liner wall thickness value, or 25 mils. The 15 acceptance limit for general corrosion of 125 mils is 16 shown on the dashed vertical line.

17MEMBER BROWN: Did you say coating intact 18was assumed to be anything greater than 190 mils? For 19that first column. Did I understand that or did I get 20 that --21MR. GALLAGHER: No, just the x axis is 22zero to 190. The coating intact we're actually 23showing less than zero, meaning that there's no 24degradation and the coating is intact. So that first 25 63 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433bar, that e 4.8 percent is no corrosion and the 1 coating is intact.

2MEMBER POWERS: This gives an overall view 3 for the whole area but if we ascribe to the 4 description of corrosion that you've just given to us 5 it would be the area around the water line that would 6 be most heavily corroded because that's where the 7 oxygen concentration is the highest. So do we have 8 one that's spatially resolved so that we know if the 9 water line area is more displaced into the 25 to 50 10 than the vast majority of it?

11MR. GALLAGHER: We don't have a spatial 12depiction in our slide set. Most of the corrosion is 13 occurring on the floor and there's no real particular 14pattern to it per se if you look at it. There is some 15 corrosion of the walls and like you said it would be, 16you know, in the upper part. That does occur. But 17 most of it is on the floor.

18 MEMBER POWERS: If it's corroding on the 19 floor then it's some mechanism other than this oxygen 20that was described to us earlier. Presumably 21 corrosion under sludge that you're taking out.

22MR. GALLAGHER: Well, yes. And there's a 23whole debate on, you know, what does the sludge do.

24 Does it aid in corrosion or does it just aid in 25 64 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433depletion of the coating system. That being said 1 we're -- we want to make sure as part of our aging 2management program that we eliminate it. So we're, in 3 our commitment we're going to take the sludge out 4 every outage. And it's got to help, that's our view 5 and that's the way --

6 MEMBER POWERS: It can't hurt.

7MR. GALLAGHER: Yes, right. So, that's 8 part of our program.

9CHAIRMAN SHACK: What has your past 10 practice been about removing sludge?

11MR. GALLAGHER: It wasn't every outage and 12 early in plant life there were several outages where 13it was not removed. And you know, then the ECCS 14 suction strainer issue came up in the mid-nineties and 15 that's when more frequent cleaning would occur. But 16it was not every outage. We are going to do it every 17 outage and that's part of our aging management program 18 commitment.

19 MEMBER POWERS: I guess what concerns me 20 is that when we talked about corrosion we focused in 21on oxygen which manifest you need or you don't get 22corrosion product. But now you're telling me that 23 this oxygen may in fact be supplied by a sludge rather 24 than by the ambient air dissolving in your solution.

25 65 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 1MR. GALLAGHER: Well I don't know if we're 2 saying that but what we're, you know, we'll get into 3 the elements of our plan that's going to be on page 23 4when we get there. But basically what we're trying to 5 say is we, you know, we think that we have a 6 comprehensive -- we're addressing all the elements in 7the program. You know, keep it clean, frequent 8 inspections, low threshold for inspection for re-9 coating. Start early, you know, in the plant life, 10 transitioning from this inspection to aging 11 management. So all those elements are included in 12 this.13MEMBER POWERS: Put a fan in there to keep 14 the corrosion products suspended.

15MR. GALLAGHER: No, we haven't got to that 16 point.17MEMBER STETKAR: Well, in that sense, the 18 reason I asked earlier, does your suppression pool 19 cleanup system take -- can it take a suction from the 20 bottom of the pool? I mean dead bottom.

21MR. DORAN: That's where it does take a 22 suction from.

23 MEMBER STETKAR: Thank you. That's your 24 fan.25 66 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 (Laughter) 1MEMBER POWERS: Obviously it's not enough.

2MEMBER STETKAR: Well, they don't run it.

3MEMBER POWERS: Oh, I see. I think a 4 little impeller in there to keep it a little stirred 5 up.6 MR. GALLAGHER: Okay, Mark?

7MR. DIRADO: So at this part of the slide 8 we were discussing the vertical bars that are shown on 9the graph. The first bar that's shown in green 10 indicates that 84.8 percent of the submerged liner 11 surface has intact coating.

12 The second bar which is shown in orange 13indicates that 12.6 percent of the submerged liner 14 surface is affected by general corrosion that averages 15 in depth up to 25 mils.

16The third bar which is shown in blue 17 indicates that 2.6 percent of the liner surface is 18 affected by general corrosion that ranges in average 19 depth from 25 to 50 mils.

20 The fourth smaller bar shown in red 21 indicates that a very small portion, 0.03 percent of 22the liner surface is affected by general corrosion 23 that has an average depth between 50 and 57 mils.

24 The data that's on this slide indicates 25 67 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 that 97.4 percent of the submerged liner surface area 1 has less than or equal to 10 percent wall loss. All 2 of the data is well below the 125 mil large acceptance 3 limit.4 The next slide will address smaller local 5 areas of corrosion which are less than 2.5 inches in 6 diameter. Slide 17, please.

7 This graph is similar to the previous 8 slide. Individual localized corrosion spots have been 9 added. The graph shows that there have been a few 10 local areas of general corrosion which is greater than 1150 mils. The right-hand side y axis is the number of 12 localized corrosion locations from zero to 30 as a 13 function of metal loss in mils.

14 The corrosion locations greater than 50 15mils in depth are depicted by green diamonds. The 16 acceptance limit for local areas of general corrosion 17 which is 187.5 mils is shown as a dashed vertical 18 line. 19 The deepest single spot of 122 mils was 20 discovered and re-coated in 2006 to arrest the loss of 21 material. This location was re-inspected in 2010 and 22 again in 2012 and confirms that coating remains intact 23and the loss of material has been arrested. This 122 24 mil spot is likely the result of past mechanical 25 68 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 damage combined with general corrosion.

1 As can be seen from this graph few local 2 areas of general corrosion with greater than 50 mils 3 metal loss have been observed since underwater 4 examinations were begun. Those locations that have 5 been identified are well below the corrosion limit of 6 187.5 mils. Slide 18, please.

7 This slide depicts the current material 8 condition of the Unit 2 liner using data from the 2009 9refueling outage. The information on this slide is 10 presented in a similar fashion to that on the previous 11 slides. The colored bars on the graph depict large 12 area corrosion as a function of metal loss.

13 The first bar shown in green indicates 14 that 95.8 percent of the submerged liner surface has 15the coating intact. The second bar which is shown in 16orange indicates that 3.8 percent of the submerged 17 liner surface is affected by general corrosion that 18 ranges in depth up to 25 mils.

19The third bar which is shown in blue 20 indicates that a small portion, 0.04 percent, of the 21 submerged liner surface is affected by general 22 corrosion ranging in average depth from 25 to 50 mils.

23 None of the Unit 2 submerged liner surface is affected 24 by general area corrosion greater than 50 mils.

25 69 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 The data on this slide indicates that 99.6 1 percent of the liner surface area on Unit 2 has less 2than or equal to 10 percent wall loss. All of this 3 data is well below the 125 mil large area acceptance 4 limit. The next slide will address the smaller local 5 areas of general corrosion, those less than 2.5 inches 6 in diameter.

7MR. BARTON: Unit 2 has been in operation, 8 what, 2 years after Unit 1?

9 MR. GALLAGHER: It's about 5 years.

10 MR. BARTON: Five years?

11 MR. GALLAGHER: About 5 years, yes.

12MEMBER SKILLMAN: So is that differential 13 between Unit 1 and Unit 2 due almost solely to the age 14 during which the submergence has been occurring?

15MR. GALLAGHER: We think it's the age and 16 we institute, you know, when you identify our practice 17 is to do -- because of operating experience in Unit 1 18 or industry operating experience those good practices 19 were initiated earlier, early.

20MEMBER SKILLMAN: So it benefitted Unit 2.

21MR. GALLAGHER: It benefitted more in Unit 22 2.23MEMBER SKILLMAN: I understand. Thank 24 you.25 70 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433MR. DIRADO: Slide 19, please. As with 1the previous slide for Unit 1 localized corrosion 2 locations greater than 50 mils in depth on the Unit 2 3liner are depicted by green diamonds. The acceptance 4 limit of 187.5 mils is the same for both units.

5 Eight local areas of general corrosion 6 have been identified on the Unit 2 liner greater than 750 mils. As can be seen by this graph of submerged 8 liner exams very few local areas of general corrosion 9 with greater than 50 mils metal loss have been 10 observed since underwater examination has begun.

11Those locations that have been identified are well 12below the corrosion limit of 187.5 mils. Slide 20, 13 please.14 Now that I've described the material 15 condition of the suppression pool liners I'll address 16the design features and material condition of the 17 downcomers.

18 The Limerick Mark II containment has 87 19 downcomers, each 24 inches in diameter with a 375 mil 20wall thickness. The downcomer interiors are coated 21 with epoxy. The exteriors are coated with inorganic 22 zinc. Each downcomer is 45 feet long and the lower 11 23feet are submerged. Four of the 87 downcomers, those 24 with vacuum breakers, are capped at the bottom.

25 71 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 The Unit 1 downcomers were inspected in 1 2012, currently have less than 25 mils of wall loss.

2 The Unit 2 downcomers were inspected in 2009. Those 3 currently have less than 10 mils of wall loss.

4 The acceptance criteria for general area 5metal loss is 44 mils. This corresponds to a wall 6 thickness of 331 mils required for structural 7 integrity.

8 For smaller local areas the metal loss 9acceptance criteria is 62.5 mils. This corresponds to 10 a wall thickness of 312.5 mils which is required for 11 structural integrity.

12 The SER open item identified that these 13 acceptance criteria should be incorporated into the 14 procedures that are used for downcomer inspections.

15Exelon agrees with the NRC staff. These criteria will 16 be incorporated into aging management inspection 17 procedures.

18 Now that we have addressed the actual 19 material condition of the suppression pool liners and 20 downcomers and the extent of general corrosion we will 21 next address how the ASME IWE examinations are 22 performed.

23 Since we implement the coating maintenance 24 plan by performing underwater inspections the 25 72 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 following slide discusses details associated with that 1method of examination. There is an area -- this is an 2 area where the NRC staff has requested more 3 information on the SER open item. Slide 21, please.

4 This slide depicts how qualified divers 5 perform underwater examinations and record data 6 associated with coating depletion and metal loss.

7 First, personnel performing underwater 8 inspections are qualified and certified coating 9 inspectors. They meet the requirements of ANSI 10N45.2.6 and ASTM D4537. For the liner the underwater 11 inspectors are qualified to ASNT CP-189 and meet ASME 12 Section 11 requirements.

13 A 100 percent inspection is performed on 14 accessible wall and floor plates to qualitatively 15 assess the general condition of the coating and steel 16 liner by performing a VT-3 visual examination.

17CHAIRMAN SHACK: What does VT-3 mean in 18 this context?

19MR. DIRADO: It means that the inspectors 20 are qualified to ASME VT-3 requirements in the 21 performance.

22 CHAIRMAN SHACK: But VT-3 almost sort of 23means there's no loose parts laying around, right? I 24 mean, it's -- what are you actually looking for when 25 73 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 you say VT-3 in this context?

1MR. GALLAGHER: It's a visual inspection.

2We have Mark Marquis. Mark, why don't you tell us 3 about that.

4MR. MARQUIS: Mark Marquis, Underwater 5Construction Corporation. VT-3 for the liner 6 inspection is primarily you're looking for anything, 7 any corrosion. You're performing a coating and 8corrosion assessment on the liner itself. It's not 9 strictly for bolting or loose parts necessarily but on 10 the liner, the welds, et cetera, and all done within 11-- by our program within 4 feet.

12CHAIRMAN SHACK: Okay. And then how is 13 that going to differ then from the VT-1 examination?

14MR. DIRADO: I have some information on 15 that for this slide if you let me continue or we can 16-- let Mark address. So, for the VT-3 the qualitative 17 examinations, they identify and evaluate any coating 18 discontinuities, any imperfections and also identify 19the complete loss of coating for an area. This is 20 evident by the presence of corrosion as stated.

21 Our large surface areas then get 22 subdivided into smaller areas as necessary to 23facilitate data clinician. And then describe the 24 conditions on different regions of the plates.

25 74 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 The characterization of the degree of 1 rusting is performed consistent with methods described 2 in the ASME standard test method for evaluating the 3 degree of rusting on painted steel surfaces.

4 Indications of general corrosion are 5 entered into a data sheet by the size of area 6inspected and the percentage of the inspected area 7 affected. The affected area for a plate is then 8 calculated based on the recorded data.

9 For smaller local areas of general 10 corrosion the inspector identifies the size of the 11area containing the indications, the size of the 12 indications and the quantity of those indications 13 within the area.

14 VT-1 or a detailed visual examination is 15performed for plate areas that meet the augmented 16 requirements of ASME IWE. For the liner plate areas 17 that exceed 25 mils general area or 50 mils local area 18 are subject to augmented examinations.

19 Metal loss for such areas is 20 quantitatively assessed for these areas using 21 calibrated depth gauges and adjusted by measuring dry 22 film thickness of the coating to determine the actual 23 metal loss for each reported location.

24 The visual exams are supplemented by 25 75 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433volumetric UT in accordance with ASME IWE 3200. These 1 supplemental exams are used when degradation would 2 otherwise require additional technical evaluation such 3 as conditions which would bring into question 4 surrounding metal assumptions contained in the design 5 flaw analyses.

6 Considering all these quality measures and 7 examination techniques Exelon is confident that the 8 underwater examinations are performed rigorously in 9accordance with procedures and industry standards. We 10 are also confident that both metal loss and coating 11 depletion will be consistently and thoroughly 12 characterized both prior to and during the period of 13 extended operation. Slide 22, please.

14 This picture provides an idea of what the 15 liner corrosion looks like in the suppression pools.

16 The visible area seen is approximately 1 square foot.

17It represents a plate surface that's affected by 18 general corrosion that is occurring at a rate of less 19than 2 mils per year in the suppression pool. The 20 estimated coating depletion on this plate is 40 21 percent. The average metal loss due to general 22 corrosion is 17 mils in depth which is less than 10 23 percent wall thickness loss.

24 MR. BARTON: I'm looking at a wall? I'm 25 76 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433not looking at the floor here, I'm looking at a 1 vertical? This is not the floor?

2MR. GALLAGHER: This is a floor plate. A 3 floor plate.

4 MR. BARTON: A floor plate?

5MR. DIRADO: Sorry, I used wall thickness 6 interchangeably with metal thickness.

7 MR. BARTON: Okay. I always wonder am I 8 looking at the vertical or am I looking at the floor.

9MR. DIRADO: The areas where corrosion is 10visible have experienced coating depletion. The 11 unaffected areas shown still have inorganic zinc 12 coating present which is protecting the liner surface.

13 Slide 23, please.

14 This slide summarizes the enhancements 15made to the IWE aging management program. These 16 enhancements represent an aggressive aging management 17 plan begun well before the period of extended 18 operation that will maintain coating protection and 19 minimize liner metal loss.

20 First, the plan includes de-sludging the 21suppression pool floor each refueling outage. This 22 frequent cleaning will minimize the potential 23 corrosion sites.

24MEMBER SKILLMAN: Mark, does this de-25 77 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433sludging only vacuum or does it lase, water lase so 1 fresh surface is exposed?

2MR. DIRADO: It includes vacuuming. As 3 far as water lasing?

4MR. KELLY: We can ask Mark Marquis of UCC 5 to address that question.

6MR. MARQUIS: Mark Marquis, Underwater 7 Construction. I'm sorry, could you repeat the 8 question?9MEMBER SKILLMAN: Yes. Is the de-sludging 10a vacuuming process or is it a vacuuming plus a 11 hydrolasing process?

12MR. MARQUIS: No, the de-sludging process 13is primarily a de-sludge vacuuming process. I'm 14 sorry.15 MEMBER SKILLMAN: Thank you. Thanks.

16MR. DIRADO: Second. An ASME IWE 17examination is conducted each ISI period which is 18 three times every 10 years. This is for 100 percent 19of the submerged liner surface. This more frequent 20 exam schedule thoroughly characterizes the material 21 condition of the suppression pool liner.

22 The frequent exams also continue to 23 confirm the expected general corrosion rate expected 24 for the suppression pool water environment as well as 25 78 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 providing opportunities for re-coating.

1 Third, the area re-coats for general 2 corrosion of greater than 25 mils will be performed.

3 General corrosion occurs in the suppression pool at a 4rate of less than 2 mils per year. The acceptance 5 limit for loss of material due to large area general 6 corrosion is 125 mils metal loss.

7 Re-coating at 25 mils which equates to 10 8 percent wall thickness coupled with a frequent 9 inspection interval of less than 4 years ensures 10 minimal additional liner wall loss.

11 Fourth, spot re-coating of the local areas 12 of general corrosion greater than 50 mils in depth 13 will be performed.

14MR. BARTON: Let me ask you something.

15 How do you re-coat this stuff?

16MR. DIRADO: The specific spot re-coatings 17 are performed with a direct application by the divers.

18 The larger area re-coats have a specific methodology 19 and they're usually applied by a roller technique.

20 MR. BARTON: While it's underwater?

21 MR. DIRADO: Yes. Underwater.

22 MR. BARTON: And it adheres?

23MR. DIRADO: That's correct. And it 24 results in a service level 1 qualified coating.

25 79 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 So fourth on this slide, spot re-coating 1 for local areas of general corrosion greater than 50 2mils in depth will be performed. Pitting corrosion is 3 not expected to occur in the suppression pool water 4 environment.

5 However, even if the localized metal loss 6 rate were hypothetically eight times larger than 7 expected, for example, 16 mils a year, then a 50 mil 8 spot would progress to 114 mils in depth over 4 years, 9 and that is still well below the acceptance limit for 10 general corrosion of 187.5 mils.

11 Fifth, in addition to the action levels 12 for metal loss the plan has provisions to proactively 13 re-coat large areas before significant corrosion 14 occurs. For plates greater than 25 percent coating 15 depletion the affected area will be re-coated.

16 Last, item 6 on the slide --

17CHAIRMAN SHACK: So we would re-coat that 18 plate we saw in the picture?

19 MR. GALLAGHER: Yes. So, and that's our 20 plan. We think we've hit all the elements to have a 21 good aging management plan and this is the key feature 22of being proactive. So when we have coating depletion 23 greater than 25 percent in an area we'll -- even 24 though the corrosion would be less than 10 percent, 25 80 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 you know, it could be hardly anything we're going to 1re-coat that area. And that way we'll get ahead of 2 this. And to Mr. Barton's point on, you know --

3MR. BARTON: I'm still trying to 4 understand this. I've got a corroded spot there. I 5 can dab some zinc on it underwater?

6MR. GALLAGHER: No, no. It's epoxy. It's 7 an epoxy coating.

8 MR. BARTON: Oh, okay.

9MR. GALLAGHER: And it's intended for 10 underwater application.

11MR. BARTON: And I don't have to clean 12 this corrosion at all.

13MR. GALLAGHER: Well, you have to do some 14surface prep. You do surface prep and then there's a 15 coating.16MR. BARTON: On the epoxy. Okay. All 17 right. Thank you.

18MR. GALLAGHER: But that -- our intent in 19 this part was to be proactive in getting ahead and not 20 having significant material loss in the lining.

21 MR. DIRADO: Finally, for item 6 on this 22 slide the enhancements were begun in 2012 for Unit 1 23and will be initiated in 2013 for Unit 2. Early 24 institution of the plan allows seven cycles of coating 25 81 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 maintenance for Unit 1 and nine cycles of coating 1 maintenance for Unit 2 prior to reaching their period 2 of extended operation.

3 MEMBER SKILLMAN: Mark, where is the re-4 coat material successfully used?

5MR. DIRADO: The re-coat material has been 6successfully used at other stations. I'd like to ask 7 George Buduck to provide the specific data.

8MR. BUDUCK: George Buduck, the ISI 9program owner. Mark Marquis would probably be better 10 to answer that question.

11 MR. DIRADO: Sorry, Mark Marquis.

12MR. MARQUIS: Mark Marquis, Underwater 13 Construction. The coating material for spot 14 applications has been used at Limerick, Peach Bottom 15 and throughout most of the other Exelon utilities.

16MEMBER SKILLMAN: Is this a product that's 17 widely used in maritime by the Navy or by the Merchant 18 Marines?19 MR. MARQUIS: I believe that it is, yes.

20 For use in -- the coating product has been tested and 21 qualified for surface level 1 use as well for 22 underwater application.

23MR. GALLAGHER: And right now, Mr.

24 Skillman, since we've just started this plan most of 25 82 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 the coating repairs that are done have been spot 1 coating. We have done qualification testing, mockup 2 testing of vertical and horizontal surfaces you know 3in a mockup, not in the pool itself. Because what we 4 need to do is we need to get that process down 5efficiently so wider areas can be done underwater.

6 And that's what our program is doing.

7 That being said, you know, we want to make 8clear that our commitment is very clear. Prior to the 9 period of extended operation we need to meet all this 10 criteria. You know, the areas of greater than 25 mils 11 re-coated, the spots greater than 50 mils re-coated, 12 any areas greater than 25 percent depleted re-coated.

13 So if we can't successfully get it efficiently done 14 underwater we would have to do it in another way, 15 i.e., drain it and do it.

16 And this goes back to Mr. Barton's thing.

17 We're -- at other plants you try this, you do this and 18at some point you may have to do something else.

19 That's based all on the economics, the outage timing 20and that type of thing. But our commitment is very 21 clear.22MEMBER SKILLMAN: Thank you, Mike. Thank 23 you.24MEMBER SIEBER: Has the prototype testing 25 83 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433been performed to the extent that you were able to 1 establish that when you apply the coating you don't 2 trap water between the coating and the surface of the 3 liner?4 MR. GALLAGHER: Yes. We actually --

5 MEMBER SIEBER: How did they do that?

6MR. GALLAGHER: -- just for -- maybe we 7 can just show you a picture we did for the mockup.

8 Let's go to slide number 43.

9 MEMBER SKILLMAN: I think it's a backup.

10 We don't have that.

11 MR. GALLAGHER: Yes, it's a backup. And 12we'll show you this. This is 43, a vertical plate 13that was done in a mockup and then look at 44. Can we 14go to 44, Chris? Did a configuration of floor with 15various configurations. And you know, so the process 16 is set up to be performed underwater, cleaning the 17 application. You know, it's a multi-coat system 18 that's applied.

19 MEMBER BROWN: Is it sprayed on?

20MR. GALLAGHER: No, I believe it's rolled 21 on. Mark?

22MR. MARQUIS: Yes, it's not -- we got away 23from the roller. It's actually a pad type applicator 24but it's a power-fit pad applicator. That's correct.

25 84 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433MEMBER STETKAR: Mark, before you sit down 1 is there any experience -- I mean, you know, these 2 photographs show that you have some confidence that 3you can apply it fairly well. Is there any operating 4experience either from the nuclear fleet and the 5 answer there is probably not yet, but from perhaps 6 maritime applications if it's indeed used in maritime 7 applications to give you confidence that indeed the 8 coating remains intact and is effective for periods 9 like 10 to 15 to 20 years? Is there any evidence to 10 support that?

11 MR. MARQUIS: We've used this particular 12 product in concrete, spent fuel concrete fuel basins 13at various utilities overseas. And we don't have a 14 15-year period to go by but the last -- we've been 15 back over the last few years, but it's been in service 16 probably 3 or 4 years now with no detrimental effects 17 noted. Still intact.

18 MEMBER STETKAR: Thank you.

19CHAIRMAN SHACK: But let me understand the 20 commitment. Since you actually haven't demonstrated 21you can re-coat the plates yet with this process. If 22 it turns out you're unsuccessful your commitment is 23 basically sometime before the PEO to re-coat? Or?

24 MR. GALLAGHER: Yes. If you look at our 25 85 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433commitment it's based on this criteria. We need to 1 meet these criteria, the 25 mils for any areas greater 2 than 25 mils, any spots greater than 50 and any plates 3 with greater than 25 percent loss.

4 If you go to our next slide on the 5 prioritization. Is that the next slide? Yes. So, 6 one of the questions the staff had was about how we 7would prioritize this. And so this is what we have 8 and we'll go over that with you.

9 But essentially what I was trying to say 10 with the commitment is this would be how we would do 11 this. And as I said we want to do it in scheduled 12 outages because you don't have all the other competing 13 safety issues of draining the suppression pool, 14 offloading the core, that type of thing.

15 But our commitment is clear, we need to 16 meet these areas prior to the period of extended 17 operation and maintain that in the period of extended 18 operation. This is how we will maintain it in the 19 period of extended operation.

20 It basically is we will re-coat these as 21 we go and the proactive plate approach we give 22 ourselves one inspection schedule just for some 23 planning and scheduling. But prior to PEO all those 24areas need to be re-coated. And so if we can't do it 25 86 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 underwater the way we want to with this, the way we 1 think we can then we would have to take other action, 2 i.e., drain it or you could do it in multiple outages.

3 You could drain it through the walls, you know, drain 4 it through the floor, drain it through the whole 5 thing, whatever.

6 CHAIRMAN SHACK: But that plate we saw 7 then could sort of sit that way until PEO if you 8 couldn't successfully do it underwater.

9MR. GALLAGHER: That's not our intent.

10Our intent is if you go back to the data slide on 11slide 16. So the real areas of concern, the spot re-12 coats are easy and those greater than 50 mils, we're 13 going to do those and that's not a problem.

14 So, the issue is the greater than 25 mils, 15greater than 10 percent. And there's only 2.6 percent 16of the area. So we think we can get there definitely 17in this area. And if you go to the Unit 2 it was only 18-- go to page 19, or 18. It was only 0.4 percent. So 19 we have those areas identified, we have -- there are 20 just a few plates that are involved and we can go out 21 and get those.

22So the only areas that we'd be talking 23 about would be the ones for the more proactive 24 approach. There are a number of those areas. In Unit 25 87 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-44331, Unit 2 there's not so much. And we think with a 1 stepwise fashion we can get there.

2 And the justification is that there really 3 is no significant degradation on those plates at this 4 point. And but you know, again, we have to meet the 5 criteria going into the period of extended operation.

6MEMBER STETKAR: Mike, anywhere in your 7backup slides do you have a graphic that shows the 8 spatial distribution of the areas where you do have 9 greater than 25 mils loss?

10 MR. GALLAGHER: No.

11MEMBER STETKAR: You know, a picture of 12 vertical, horizontal surfaces that show what they are.

13MR. GALLAGHER: No, Mr. Stetkar. The only 14 thing I can show you, if we go to page 30, slide 30.

15 This is an overview of the floor plan.

16MEMBER STETKAR: Yes, that doesn't help 17 much.18MR. GALLAGHER: Yes. So this has the 19plates, you can see the plates there. When we talk 20 plates, those individual rectangles are plates. The 21-- you can see some of the equipment.

22 The only thing I can tell you is there 23 really isn't much of a pattern but there's two --

24MEMBER STETKAR: I was trying to get, you 25 88 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 know, you have small percentages but I was trying to 1 get a feel for area and location.

2MR. GALLAGHER: Yes. So, there's three --

3 okay, so actually on Unit 1 for the areas greater than 4 25 mils there's actually two wall plates and there's 5two floor plates. The two floor plates are 4A and 6C.

6So if we can point to those, Chris. 4A is in the 7 north -- no.

8MEMBER STETKAR: Northeast corner there 9 someplace.

10MR. GALLAGHER: No, get back on the --

11 okay.12 MEMBER STETKAR: I see that one.

13MR. GALLAGHER: Four alpha and then the 14 other was 6C. Six charlie --

15MEMBER STETKAR: -- charlie is the 16 southwest corner.

17 MR. GALLAGHER: Southwest corner. Okay.

18 So, there's really no specific pattern or anything but 19there are the two areas on the floor. And on the wall 20there's 7B and 6B. They're two areas we would have to 21 address.22 MR. KELLY: But, and it would not be the 23 entire plate, Mr. Stetkar.

24MEMBER STETKAR: Yes, that's what I was 25 89 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433trying to get a feel for. Do you have, you know, 200 1 places where you have about 6 square inches that you 2 need to coat or do you have a fairly large area.

3MR. GALLAGHER: No, for these greater than 425 mil there's only these four plates on Unit 1. And 5 then Unit 2 --

6 MEMBER STETKAR: Is less.

7MR. GALLAGHER: Yes, Unit 2 is -- there's 8 a couple. There's actually four plates also but two 9 of them are very, very small areas.

10CHAIRMAN SHACK: Okay, we're going to have 11 to finish up here.

12MR. GALLAGHER: Yes. Okay. If we can go 13to wrap up here, Mark. So, if we go to page 24 I 14think we covered this. Dr. Shack, in the interest of 15 time do you want us to move forward quickly?

16 CHAIRMAN SHACK: Move forward.

17MR. GALLAGHER: Okay. So, if you look on 18 page 24 here this is new information we're going to be 19 supplying the staff on how we'll be implementing the 20 program. And the feature is basically we're -- we 21 have to get some catchup to do on -- particularly on 22 Unit 1 and so we have that prioritized as we have 23 prior to PEO.

24 And then in PEO what we're proposing is 25 90 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 that we would re-coat these areas of degradation as 1 they occur when they're discovered in the outage and 2 then the proactive coating for the plates would be 3 done within one scheduled period.

4MEMBER SKILLMAN: Mike, in the context of 5 the slide you identify areas, local corrosion areas, 6and plates. Should we interpret plate to be the 7 geometric square?

8MR. GALLAGHER: Yes, the plates where 9 there's rectangles. And we're just saying that --

10 MEMBER SKILLMAN: So each of those is an 11identified quantity in the map of the suppression 12 pool.13MR. GALLAGHER: Right. When we map out 14 the suppression pool we do it by plate so we can say 15 okay, that plate is, you know, X percent depleted of 16 coating.17MEMBER STETKAR: So bullet 3 is 18 communicating that if 6A plate has that or greater 19 depletion you're going to fix the whole plate.

20MR. GALLAGHER: The plate could be 21entirely re-coated if it was spread out. If it was in 22 a specific area you could just do the specific area.

23But what we're saying is that plate would have been 24 identified for treatment because it had at least 25 25 91 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 percent depletion.

1 MEMBER STETKAR: Thank you.

2 MR. GALLAGHER: And again, that depleted 3 area is well less than -- it's less than 10 percent 4 material loss.

5 So we'll just, if we can just step through 6 to the next slide. We just wanted to summarize what 7the open item resolution was. We had four areas. We 8think we've covered those in the presentation, a 9 prioritized approach, methods, the exam, our expected 10 corrosion mechanism and our downcomer acceptance 11 criteria.

12 And all this will be -- we have a written 13 open item response which will be sent into the staff 14 next week. Go to the next slide.

15Mark, if you could just give us our 16 overall summary.

17MR. DIRADO: Sure. In summary the 18 enhancements to the Limerick IWE aging management 19 program provide reasonable assurance that the aging of 20 the suppression pool liner will be managed 21 appropriately. Limerick has a robust containment 22 design with a metal liner that has 100 percent 23 thickness margin.

24 The environment in the suppression pool is 25 92 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 not conducive to pitting corrosion and water chemistry 1 quality is excellent with respect to minimizing 2 general corrosion.

3 MEMBER POWERS: Your discussion of water 4 chemistry, you focused on inorganic species, chloride 5and sulfate particularly. Do you characterize the 6 organic content of that water?

7MR. GALLAGHER: Organic content? Greg, 8 Dr. Powers has a question about organic content of the 9 suppression pool.

10MR. SPRISSLER: Greg Sprissler from 11 Limerick chemistry. Our analysis was limited to 12chloride sulfate pH connectivity and TOC analysis. So 13 with TOC we have a general characterization of organic 14 compounds but nothing specific.

15MEMBER POWERS: And what does your TOC 16 come in at?

17MR. SPRISSLER: I'm sorry, I can't hear 18 you.19 MEMBER POWERS: What level of TOC do you 20 have?21MR. SPRISSLER: Typically we have less 22 than 50 ppb.

23 MEMBER POWERS: Fifty ppb.

24 MR. SPRISSLER: Parts per billion.

25 93 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 MEMBER POWERS: Right. By mass.

1 MR. SPRISSLER: Yes.

2MEMBER POWERS: And you just don't know 3 what that is.

4 MR. SPRISSLER: That is correct.

5 MEMBER POWERS: Okay.

6 MR. DIRADO: Our low corrosion rate has 7been confirmed. Exelon is committed to an aggressive 8 aging management program begun well in advance of the 9 period of extended operation which will ensure that 10 the intended function of the suppression pool liners 11 are maintained throughout the period of extended 12 operation.

13 I'll now turn the presentation over to 14 Mike Gallagher for closing remarks.

15MR. GALLAGHER: Okay, thanks Mark. So in 16 conclusion we've developed a comprehensive, high-17 quality License Renewal Application and a robust aging 18 management program that will ensure the continued safe 19 operation of Limerick. Pending any questions that 20 ends our presentation.

21CHAIRMAN SHACK: Any further questions 22 from the subcommittee?

23MEMBER POWERS: Just a reminder, the water 24 volume in your suppression pool?

25 94 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433MR. GALLAGHER: Water volume, I think it's 1 about 1 million gallons.

2 MEMBER POWERS: 1.2 million?

3 MR. GALLAGHER: Dave Clohecy?

4MR. CLOHECY: My name is Dave Clohecy and 5I'm a member of the Exelon license renewal team. The 6 water volume in the suppression pool is approximately 7 1 million gallons.

8 CHAIRMAN SHACK: Thank you very much for 9an excellent presentation. We'll take a break now 10 until 10:35. Then we'll hear from the staff.

11 (Whereupon, the foregoing matter went off 12 the record at 10:19 a.m. and went back on the record 13 at 10:35 a.m.)

14CHAIRMAN SHACK: If we can come back into 15 session Melanie Galloway will start us off again.

16MS. GALLOWAY: Okay. Thank you, Dr.

17 Shack. I've already introduced Patrick Milano. He's 18the Limerick project manager for the last month.

19 Previous to his assignment as the project manager Rob 20 Kuntz who is sitting here at the computer was the 21 project manager who led and coordinated the project 22through the initial application. So he's here to 23 assist as well.

24Pat is going to be giving the whole 25 95 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433presentation today since there are only two open 1 items, but there are support staff at the front table 2 that I'd like to go ahead and introduce. To the far 3 end of the panel there without a name tag is Dr. Allen 4 Hiser who's our senior-level advisor on materials and 5degradation in the division. Abdul Sheikh is a senior 6 structural engineer with responsibility for the open 7item on the suppression pool liner. Michael Modes is 8 from Region I and had the lead for the inspection, and 9we'll talk about that in the presentation today. And 10 Matt Homiack is our mechanical engineer with 11 responsibility for our operating experience program 12 and the open item at Limerick.

13 We have attempted to streamline our 14 program today, taking account for the background 15 information that was already included in the 16 applicant's presentation, so hopefully that will 17facilitate efficient review. We're going to focus on 18 the areas that are unique to our review of the 19 application and provide our characterization of the 20 open items.

21 We are expecting written responses from 22 the applicant on the open item so we are in the middle 23of the review. We are not in a position at this point 24 in time because of that status of review to indicate 25 96 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433a clear path forward on the open items. And you will 1 get a sense of that from our presentation.

2 Before we get into our formal presentation 3I'd like to ask Bill Holston who is a senior 4 mechanical engineer in the division to respond to Mr.

5 Stetkar's question earlier about the internal 6 inspection program of large-bore piping and 7 consistency with the GALL. Bill?

8MR. HOLSTON: Good afternoon. My response 9 to that, or I understand the question to be how the 10 applicant will be age-managing the internal surfaces 11of the surface water piping that is buried. And we 12 worked with the applicant throughout the application 13 and what they have committed to do is to take 10 14 locations every 2 years in aboveground service water 15 piping and conduct ultrasonic examinations of that 16 piping to detect any corrosion.

17 And that piping select -- the selection of 18 those locations will be based upon similar flow rates 19as buried piping. And given that they have similar 20 environments, internal environments between the 21 service water piping that's buried and the aboveground 22 service water piping, we believe that sufficiently 23 examines the internals for both.

24MEMBER STETKAR: Those are going to be you 25 97 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 said volumetric examinations?

1MR. HOLSTON: Yes sir, volumetric 2 examinations.

3MEMBER STETKAR: Okay. From the ID or the 4 OD?5 MR. HOLSTON: From the outside diameter.

6MEMBER STETKAR: Okay. At least I know 7what they're going to do. And you feel that's 8 consistent with the intent of GALL?

9MR. HOLSTON: Yes, sir. The internal 10 surfaces would be managed by -- you would manage them 11 by AMP 11 M38 which is the internal inspection program 12which is an opportunistic program. So in this case 13 rather than just simply going with opportunistic 14 inspections the licensee committed to do, you know, 15 guaranteed periodic inspections and 10 every 2 years 16will very fairly represent what we expect to see as 17 age-managing in those internal surfaces of that 18 piping.19MEMBER STETKAR: I guess I was looking at 20M41 under buried piping which seems to give you an 21 indication that if you've had experience with leaks it 22 says opportunistic examinations of non-leaking piping 23 may be credited.

24 MR. HOLSTON: Well -- oh, I'm sorry.

25 98 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433MEMBER STETKAR: I don't know what you 1define as a leak. I mean, you know, they've had 2 evidence of problems with their service water piping.

3MR. BARTON: But that has to do with 4buried piping when you go down and actually look at 5it, right? And they're talking about a surface 6 program.7MEMBER STETKAR: Well, this is for 8 internals.

9 MR. BARTON: Right, right. Oh, okay.

10MEMBER STETKAR: The internal examinations 11 of buried piping.

12MR. HOLSTON: M41 deals with external 13examination of piping only. There is no internal 14surface examinations in M41. The internal surface 15 examinations for this piping would be under 11 M38.

16MEMBER STETKAR: Section -- footnote 10 17capital letter B. At least 25 percent of the code 18class safety-related or haz mat piping are both 19 constructed from the material under construction is 20 internally inspected by a method capable of precisely 21determining pipe wall thickness. That's in M41 under 22 buried piping.

23MR. HOLSTON: That's an alternative to if 24 you do not want to do direct, you know, excavated 25 99 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 direct visual examinations of the external surfaces 1 you can substitute looking at 25 percent of the length 2with the volumetric method. That's the intent of AMP 3 M41.4MEMBER STETKAR: Okay. I'll have to think 5 about that because -- okay. I don't want to take up 6 too much time because we have a lot of discussion on 7 the suppression pools. Thank you.

8 MS. GALLOWAY: Thank you. Patrick?

9MR. MILANO: Okay. Good morning, Dr.

10Shack and members of the subcommittee. I and the 11 members of the NRR and Region I staffs are here to 12 discuss the Limerick License Renewal Application as 13 indicated here documented in the Safety Evaluation 14 Report with open items that we issued in July of 2012.

15 In addition to the members up here at the 16 table we also have staff who also participated in 17 technical review and in the audits that were conducted 18at the plant that are here in case questions arise.

19 Next slide, please.

20 This slide just predicts the general 21 outline of the areas that were going to be covered in 22 today's presentation and coincides with the --

23 specifically with the SER itself. Next slide.

24 I provided this slide only for 25 100 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 information. Everything on it was -- all the points 1 that are being made on this slide were covered in the 2 licensee's presentation. Next slide.

3 The staff conducted audits and inspections 4 of the application during periods as shown on this 5 slide. The purpose of the scoping and screening 6 methodology audit was to review the applicant's 7 administrative controls governing implementation of 8 the scoping and screening methodology and the 9 technical basis for selected scoping and screening 10 results for various plant systems, structures and 11 components, SSCs.

12 The audit also reviewed selected examples 13 of component material and environmental combinations.

14 Information contained in the applicant's corrective 15 action database relevant to plant-specific age-related 16 degradation. Quality practices applied during the 17development of the application and the training of 18 personnel who participated in the -- also in the 19 development of the application.

20 The purpose of this aging management 21program (AMP) audit was to examine Exelon's aging 22 management programs and related documentation to 23 verify that the applicant's claim of consistency with 24 the corresponding AMPs in the Generic Aging Lessons 25 101 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 Learned (GALL) report were indeed correct.

1 As described in the GALL report the staff 2based its evaluation on the adequacy of each AMP on 3 its review of 7 of the 10 AMP program elements. The 4 other three program elements were audited during the 5 scoping and screening methodology audit.

6 As Exelon indicated the staff reviewed 45 7 AMPs and documented the results in a report on 8February 28th of this year. If the applicant took 9 credit for the program in the GALL report the staff 10verified that the plant program contained all the 11elements of the referenced GALL report program. In 12addition, the staff verified the conditions at the 13 plant were bounded by the conditions -- excuse me, by 14 the conditions for which the GALL report program was 15 evaluated.

16 Of note, the applicant initially indicated 17 that all of its programs were consistent with the GALL 18 report. However, during the staff's AMP audit the 19 staff found AMPs where the applicant was taking an 20 exception and which should have been so stated in the 21 application. In response to questions from the staff 22 the applicant modified its description, thus resolving 23 the noted gap.

24 And I'd like to present one example of a 25 102 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433situation that I'm referring to here. The monitoring 1 and trending program element in GALL report AMP II M24 2 recommends that daily readings of system dew point be 3 recorded and trended. However, during its audit the 4 staff found that the applicant's program basis 5 document for the compressed air monitoring program 6 states that the instrument air system dew point is 7 continuously monitored and alarmed, inspected weekly 8and recorded quarterly. So it's just a, it was a 9 matter of a difference in the way it was presented 10 vice the way it was indicated actually in the field.

11 And however we found this to be acceptable.

12 In addition, Region I conducted a regional 13 inspection during the period from June 4th through the 14 21st of this year. Those inspection results will be 15 presented shortly.

16 And lastly, the staff conducted an 17 environmental review audit in support of the 18 preparation of the Environmental Impact Statement 19 which we are not going to be discussing anything 20 environmental today.

21MEMBER SKILLMAN: Pat, before you proceed 22 onto slide 6.

23 MR. MILANO: Yes.

24MEMBER SKILLMAN: Your first bullet, that 25 103 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 scoping and screening methodology audit.

1 MR. MILANO: Yes.

2MEMBER SKILLMAN: I think perhaps my 3 question is more appropriately directed at Bob Kuntz.

4 Four systems were chosen: essential service water, 5 fuel pool cooling and cleanup, emergency diesel 6generator system and fuel transfer and air start 7 subsystems. What is the basis for selecting only 8 those four?

9MR. MILANO: The basis for it is they were 10 representative of it and also based on previous 11 experience that the staff has with conducting other 12 audits, especially in Region I wherein this is the 13last plant that is being inspected for license 14 renewal, for initial license renewal. And it's just 15 plant experience and these seem to be reasonable to --

16 reasonable samples in relationship to the total 17 population. I don't know if, Rob, can you answer?

18MEMBER SKILLMAN: Are these the same four 19 that have been chosen at other plants in Region I that 20 are applying for license extensions?

21MS. GALLOWAY: We don't have the answer to 22 that. Our scoping lead is on vacation this week so we 23 can get back to you on that question, Mr. Skillman.

24MEMBER SKILLMAN: My curiosity is why 25 104 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433these four. Why not six or seven? Or why two 1 different from these? What is the basis for these 2 four, please?

3MS. GALLOWAY: Sure. We'll get back to 4 you. Thank you.

5 MEMBER SKILLMAN: Thank you.

6MR. MILANO: Slide 6, please. In addition 7 to the audits and inspections that I've already 8 mentioned the staff conducted in-depth technical 9 reviews and issued 150 questions initially and about 10 200 questions overall as requests for additional 11 information while preparing the overall Safety 12 Evaluation Report. Slide 7.

13 Section 2 of the SER describes structures 14and components subject to aging management review. As 15 you're well aware Section 54.21 of Part 54 requires 16 the applicant to identify SSCs within the scope of 17 license renewal and additionally to prepare an 18 integrated plan assessment which identifies and lists 19 those structures and components which are identified 20to be within the scope of license renewal that are 21 subject to an aging management review.

22 Based on the staff's review of the 23 applicant's detailed scoping and screening 24 implementing procedures, discussions with the 25 105 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 applicant's license renewal personnel, review of 1quality controls applied to the development of the 2 application and the training of personnel 3 participating in that development, and the results of 4 the scoping and screening methodology audit, and 5 additional information from the RAIs the staff 6 concluded that the applicant's scoping and screening 7 program was consistent with the staff's Standard 8 Review Plan for license renewal and the requirements 9 of Part 54 of the regulations.

10 The staff then reviewed the summary of the 11 identified safety-related SSCs which are those relied 12upon to remain functional during and following a 13 design basis event as well as all non-safety related 14 SSCs whose failure could prevent satisfactory 15 accomplishment of any of the design basis functions.

16 Also, all SSCs relied on in safety 17 analysis to perform a function that demonstrates 18 compliance with the Commission's regulations for fire 19 protection, environmental qualification, anticipated 20 transit without scram (ATWS) and station blackout were 21 identified. The staff found that the applicant's 22 implementation in this area was consistent with both 23 the SRP and applicable regulations.

24If there are no other questions on this 25 106 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 slide I'll now turn over the presentation to Mr.

1 Michael Modes, the Region I lead inspector who will 2 discuss the license renewal inspection itself.

3MR. MODES: Thank you gentlemen, it's 4always a pleasure to be here. As an overview this 5 particular inspection took six inspectors over 3 6 weeks. You would probably note that's a pretty high 7 level of inspectors spread out over a longer period of 8 time. The only reason that occurred was we had a lot 9 of exigent serious issues that the region was dealing 10 with at the time at other plants and so Limerick staff 11 and Exelon were very kind in allowing us to spread out 12 the number of inspectors over a longer period. They 13kept support staff available to get the job done so 14 that these inspectors could go on to these other 15 facilities.

16 As usual we did the A2 inspection looking 17for those three-dimensional relationships. And we did 18 32 of 45 aging management programs were reviewed in 19 total over that period of time. Next slide.

20 Because of the number of inspectors that 21 went through over a longer period of time we did a lot 22of walkdowns even though it was beastly hot at the 23 time. And this is just a partial list of the systems 24that were walked down. An extensive amount of 25 107 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 walkdown and I took a pretty long tour of the facility 1 in order to answer the material question -- pretty 2 good.3 MR. BARTON: Thank you, I didn't have to 4 ask that this time.

5 MR. MODES: Yes, well, after 13 years --

6 MR. BARTON: You guys are getting ready, 7 all right.

8MR. MODES: Right, I give up. Thirteen 9 years. Besides, this is the last time through, so.

10 (Laughter) 11MR. MODES: Next slide. And what we 12 concluded was that the scoping of non-safety SSCs and 13 the application of the AMPs to those were acceptable.

14 And the inspection results support a conclusion that 15 reasonable assurance exists, that aging effects will 16be managed and intended functions maintained. Last 17 slide.18 Just wanted to note how long it has taken 19 us in Region I to get through all of them. I've had 20 the pleasure of inspecting every single one of these 21since June of `98. And it is the last slide, 22 gentlemen, I will ever present to you.

23 (Laughter) 24MEMBER SKILLMAN: So Michael, when you say 25 108 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 material condition -- pretty good it's against that 1 lens right there?

2MR. MODES: Yes. Well, actually no.

3 Prior to this endeavor I used to run the NDE mobile 4 laboratory and I have had the pleasure of visiting 64 5 facilities. Prior to that I used to do NDE in general 6 so it's a benchmark of probably the entire fleet.

7 MEMBER SKILLMAN: Thank you.

8MR. MILANO: Okay, thanks Mike. Now 9moving onto Section 3 of the SER. Section 3 covers 10 the staff's review of the applicant's aging management 11 programs and the aging management review line items in 12 each of the systems within scope and reviewed against 13 the SRP and recommendations in the GALL report.

14In its Table 2 of the application the 15 applicant provided information concerning whether or 16 not the AMRs, the aging management reviews, identified 17 by the applicant aligned with the GALL report AMRs.

18 For a given AMR in Table 2 the staff reviewed the 19 intended function, the material, environment, aging 20 management -- aging effect requiring management and 21 the AMP combination for the particular system 22 component type.

23 In the application the applicant also 24 indicated where it was unable to identify an 25 109 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433appropriate correlation in the GALL report. The staff 1 also conducted a technical review of combinations not 2 consistent with the GALL report.

3 For component groups evaluated in GALL for 4 which the applicant claimed consistency and for which 5 it does not recommend further evaluation the staff's 6 review determined whether the plant-specific 7components were indeed bounded by the GALL report 8 evaluation. If an AMR did not align with the GALL 9 report the staff conducted a technical review to 10 ensure adequacy and issued a request for additional 11 information as necessary.

12 Based on its review of the application, 13 the implementing procedures and a sampling of 14 screening results the staff concluded that the 15 applicant's screening methodology was indeed 16 consistent with the Standard Review Plan guidance.

17 Next slide.

18As both Mike and I and others have 19 indicated there were 45 aging management programs 20 presented in the application. I do want to make one 21special note of the fact that there were no plant-22 specific aging management programs. Next slide.

23MEMBER STETKAR: Before we get into the 24open item -- give me 2 minutes here. Diesel fuel oil 25 110 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433storage tanks. And I may have just missed this so 1perhaps it's quick. There was an issue about their 2 large diesel fuel oil storage tanks and the fact that 3they take samples from that tank 11 inches off the 4 bottom. And you basically accepted that.

5 Are they going to do a volumetric 6 examination of the bottom of that tank at any time?

7I see commitments to do volumetric examinations of 8 little bay tanks here and there, but that's not the 9 big storage tank. I'm concerned about 10 and a half 10 inches of stuff laying on the bottom of that tank that 11 nobody knows about.

12MR. MILANO: There was some discussion in 13 both the application and in the SER in that area. I 14 think best if I turn it over to Mr. Gallagher and he 15 can -- he and his staff.

16MEMBER STETKAR: Okay. I didn't ask them 17 in the sense of time but.

18MR. GALLAGHER: Yes, we can answer that 19 question. I'm going to have Mark Miller of our 20 project team answer that question.

21 MR. MILLER: Mark Miller, Exelon license 22 renewal. The main diesel oil fuel oil storage tanks 23 are drained clean and inspected every 10 years. And 24 should there be evidence of corrosion visually then we 25 111 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 would be performing a UT.

1MEMBER STETKAR: Okay, thank you. I 2 missed that.

3 MEMBER SIEBER: Well, the other issue is 4sludge and water. Water settles to the bottom and 5that's why the line does not go all the way to the 6 bottom, plus all the sludge lays there. And usually 7there are samples taken periodically at the level 8 below the level of the section line to determine how 9much sludge and how much water is there. Is that 10 periodically done?

11 MR. MILLER: Mark Miller, Exelon license 12 renewal. The only sampling that we do on that tank is 13 11 inches off of the bottom of the tank. There's no 14physical connection. However, we do test for water by 15dropping down -- and I forget exactly what the term 16is, but it's material of some sort that detects the 17 presence of water and that is dropped down to 18determine whether there is water sitting on the 19 bottom.20MR. GALLAGHER: And I think Greg Sprissler 21 of our chemistry department has something to add too.

22MR. SPRISSLER: Greg Sprissler from the 23chemistry department. The tanks are pitched and at 24the bottom of the pitch is a low level sump.

25 112 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433Periodically the tanks are dewatered. So at that 1 point there would be visual indication of any 2 indication of sludge.

3MEMBER STETKAR: There is a low point 4 drain?5 MR. SPRISSLER: Not a drain, a sump.

6 MEMBER STETKAR: Inside the tank itself?

7MR. SPRISSLER: Yes. Operations 8 periodically does checks for water content in the fuel 9 and they pump out from the low-level sump.

10 MEMBER STETKAR: But -- so they can 11 actually, someone can actually take a suction from 12 that low point.

13MR. SPRISSLER: They have a device that 14 they use to do that.

15MR. GALLAGHER: Basically suck the, you 16 know, vacuum out that little volume.

17MEMBER STETKAR: Okay. Well, why can't 18 you then take credit for that for accumulation of, you 19 know, corrosion sediment and everything else that 20 might collect in that tank?

21MR. GALLAGHER: I guess our periodicity 22 wasn't in agreement with the GALL so we came up with 23 what would be in agreement with the GALL and then this 24 is extra that we do.

25 113 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 MEMBER STETKAR: Well, the GALL seems to 1 say that you're supposed to take a sample from the 2 lowest point in the tank if I read the GALL --

3 MR. GALLAGHER: Right.

4 MEMBER STETKAR: -- which this would do.

5MR. HISER: This is Allen Hiser of the 6 staff. This is one of the areas that I looked at 7 during the audit and we verified through drawings that 8 they do have an area where the sludge and things would 9 collect.10MEMBER STETKAR: But they're not -- and 11 you're okay with them not taking periodic samples from 12 that area as a commitment?

13MR. HISER: Yes. That was something that 14 we found to be acceptable because they would be able 15 to remove materials down there that, you know, water 16 and things.

17MEMBER STETKAR: I'm sorry but they're not 18committing to do that. They are not committing to do 19 that. I would think it would be acceptable, for 20 example, to take a suction, a sample from down there 21but they're not -- in particular they're not 22 committing to do that.

23MR. HISER: They -- I don't remember 24specifically whether there is a commitment but in 25 114 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 terms of their draining, cleaning and inspecting the 1 tank that was the main focus of the program.

2 MEMBER STETKAR: Okay. I don't -- Bill, 3 I don't want to take up too much more time because we 4 have a time constraint here.

5MEMBER SIEBER: Well, I would like to ask 6you say that you take a sample out of the sump area 7 periodically. What's periodically? What frequency?

8MR. SPRISSLER: Once again Greg Sprissler 9 from Limerick chemistry. I am actually not sure of 10the periodicity. My best estimate would be quarterly.

11 That is an estimate.

12MR. GALLAGHER: Yes, and I guess, you 13know, the reason we didn't -- that that wasn't the 14 fulfilling our commitment consistent with the GALL is 15 that that particular thing is fairly intrusive. You 16 have to go down into the vault, remove the lid on the 17 tank and that type of thing.

18 So the sampling we thought was sufficient 19to, you know, because we do the pre-loading of the 20fuel sampling, we do the frequent sampling. And we 21 thought that that was more consistent with the GALL.

22 And this other activity we do is a good practice that 23 we have.24 MEMBER SIEBER: Thank you.

25 115 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 MR. MILANO: Go on now to slide 14. The 1 NRC characterized the issues regarding this, the open 2 item that's presented on this page into three parts as 3noted on the slide. Because the applicant has covered 4the specific technical information on the slide I'm 5 not going to repeat this.

6 Also, the applicant proposed this AMP to 7 manage the aging of the suppression pool liner and 8 downcomers for a loss of material from corrosion and 9 to preserve the leak tightness barrier.

10 The applicant in part stated that the AMP 11 addresses the inspection of primary containment 12 components exposed to an uncontrolled indoor air and 13treated water environments. In addition, the program 14 basis document states that the Section 11 IWE program 15 is an existing AMP that will be enhanced to manage the 16 suppression pool liner and coating system as you heard 17 from the licensee previously. Next slide, please.

18 As just stated the applicant proposed an 19 enhancement of its existing IWE program to manage the 20aging effects in the suppression pool liner and 21coating system. In an enhancement to the detection of 22 aging effects program element the applicant stated 23 that prior to the period of extended operation the AMP 24 will include more frequent inspections and selected 25 116 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 and phased re-coating of the corroded areas of the 1 suppression pool.

2 The applicant has described the specific 3 attributes in this enhancement as noted on this slide.

4I provide them now, however, just as a reference in 5case we need to go back to them. Next slide, please.

6 In the SER the overall open item was, like 7I said, it was expressed in three parts. The staff 8 will only address the first two parts as indicated in 9 this slide because the third part dealing with the 10 downcomer corrosion appears to be on a path to 11 resolution.

12 Regarding the remaining two parts the 13 staff seeks additional information from the applicant 14 about the corrosion mechanisms affecting the 15 suppression pool liner and the criteria and supporting 16basis in the program for coating degradation. As you 17heard earlier the applicant has been managing the 18 degradation of the liner rather than maintaining the 19 coating system.

20 The staff is aware that the Limerick 21 suppression pool liners have been subjected to both 22 general and pitting corrosion or localized corrosion 23as the applicant indicated. The staff has come to 24 this conclusion from the results of inspections 25 117 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 discussed in the applicant's assessment report of the 1liner degradation. Thus the staff lacks sufficient 2 information from the applicant to conclude that 3 pitting corrosion is not a degradation in the liner.

4 Because of the operating history of 5 pitting corrosion in the Limerick liners the enhanced 6AMP should fully account for pitting corrosion. This 7 is important because operating experience has shown 8 that pitting corrosion rates are higher, usually 2 to 9 10 times higher than general corrosion rates, are not 10 as predictable and could result in a leak in the liner 11 over time.

12 The staff is also concerned that the 13 applicant's methods and technique for measuring the 14 amount of liner material lost to corrosion may not be 15 an effective means to determine the remaining 16thickness of the liner. The applicant uses depth 17 gauges to measure loss of material due to general and 18 pitting corrosion.

19 This may not be appropriate in all areas 20 experiencing general corrosion some of which has 21 exhibited up to 35 mils of general corrosion adjacent 22to the pits. It's unclear to the staff how the 23 reference datum of the original thickness of the liner 24 will be considered in monitoring the total material 25 118 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 loss in the inspected areas.

1 Moving onto the --

2MEMBER SKILLMAN: Before you change 3 slides, this is a pure curiosity question. Is there 4 any correlation between the operability of the 5 cathodic protection system on this plant, both units, 6and the pitting and degradation of the liner? Has 7 anyone pulled that thread?

8MR. SHEIKH: I'm not aware of this issue.

9 MEMBER SKILLMAN: Does anybody know what 10 the operating history is of the cathodic protection 11 system for Limerick?

12 MR. SHEIKH: Bill Holston might.

13MR. HOLSTON: My name's Bill Holston, 14staff with the Division of License Renewal. They have 15an operational cathodic protection system. It 16 protects the buried piping but I am not aware that it 17 protects the surfaces you're discussing there.

18 MEMBER SKILLMAN: I'd be curious whether 19 that's a design consideration. In my consulting 20 independent from this I've been on plants where the 21 cathodic protection system was not functional, was 22 hooked up backwards, was connected to some components 23 and not others, was not grounded properly and it 24 turned out the cathodic protection system was part of 25 119 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 the problem rather than part of the resolution of the 1 problem. So I'm just wondering if when you ask 2 questions about not knowing why the rates are what 3 they are if perhaps there is another mechanism that's 4 fairly simply discovered that hasn't been touched upon 5 yet.6 MR. SHEIKH: I can only add to this that 7 this kind of pitting has been observed at other BWR 8plants, suppression pools. And the pitting is in the 9 same kind of ranges. We are aware, at least I am 10 aware of Cooper Plant and Duane Arnold Plant where the 11 pitting was in that kind of range.

12MS. GALLOWAY: Abdul, when you speak could 13 you be closer to the microphone so we can all hear 14 you? Thank you.

15MR. SHEIKH: I repeat that the pitting 16 which has been observed here in Limerick is similar to 17 other plants which, you know, like Cooper and Duane 18 Arnold where they were pitting in the suppression pool 19 of similar magnitude.

20MEMBER SKILLMAN: I understand your 21 answer. I would like to put on the record the 22 question and ask for a response is there a correlation 23 between operability of cathodic protection and what 24 you're seeing on the corrosion of the liner.

25 120 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433MR. HISER: Are you speaking specifically 1of the buried pipe cathodic protection program? Or 2 are you speaking of any stray occurrence that could?

3MEMBER SKILLMAN: Well, generally the 4 cathodic protection system covers more than just the 5 buried pipe. It's condenser, buried piping, however 6the plant is grounded. And unless it's connected 7 properly you can have portions of the plant that have 8 electrical potentials that are driving degradation.

9 So that is the general basis of my question, is there 10 a correlation here. Thank you.

11MR. MILANO: We'll take that down and 12 we'll provide an answer back to you.

13 MEMBER SKILLMAN: Thank you.

14MR. MILANO: Okay, continuing on with this 15slide onto the second part. On coating degradation 16the staff notes that the application has three 17 criteria as you've heard before the results of which 18 will be used to initiate implementation of the coating 19maintenance plan. The staff is unclear as to the 20 technical basis for using the 25 percent loss of 21 coated area as a criterion in the enhancement.

22 Second, it's unclear to the staff how the 23 liner plates that have experienced a coating loss to 24 date some of which is exceeding 25 percent and up to 25 121 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-443372 percent of a specific plate surface area will be 1 prioritized and corrected in a phased approach as the 2 applicant has indicated prior to the start of the 3 period of extended operation.

4 This cold mean that areas with up to 24 5 percent of the coated area degraded could possibly not 6be re-coated even at the start of the period of 7 extended operation in 2024 for Unit 1.

8 You know, today we heard some additional 9 information for the first time being presented in this 10 area to help clarify what Exelon meant by its phased 11 approach. And the staff will be looking forward to 12 Exelon's submission of its response to the open items 13 as they indicated next week.

14 I would state of note that the applicant 15 has classified the suppression pool liner coating as 16 service level 1 because of the potential for coating 17 failure to adversely affect the post-accident fluid 18 systems.

19 And also the suppression pools were 20 initially filled in the nineteen eighties and in the 21 nineteen nineties the applicant determined that the 22coating was beyond its projected service life. And as 23 Mr. Barton indicated my recollection is reading that 24 the projected service life was determined to be 12 25 122 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 years.1 The staff also wishes to note that in its 2 SER it indicated that recent industry operating 3 experience as described in the NRC's Information 4 Notice 2011-15 titled "Steel Containment Degradation 5 and Associated License Renewal Aging Management 6 Issues." 7 This information notice provides 8 information of the type of situations such as showing 9 that zinc coatings have a limited lifetime and may not 10 be effective during the period of extended operation 11 if not reapplied.

12MEMBER POWERS: When they make these 13lifetime projections what's changing? What's being 14 lost from the coating that means it won't perform its 15 function?16MR. MILANO: Well, it is a sacrificial 17 coating and that's what the -- that's in terms of 18 setting up its, you know, the galvanic relationships 19and stuff the zinc is expected to oxidize first and 20sacrifice itself to save the base metal. I don't know 21 if Mr. Hiser wants to say anything more?

22 MR. HISER: No, that's exactly right.

23MEMBER POWERS: So you would -- when they 24 make the projection they're saying okay, we've 25 123 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 depleted all the zinc here, it's all been turned into 1 zinc oxide or zinc carbonate.

2MR. HISER: I would assume that's the kind 3of calculation. I don't think we've reviewed the 4 calcs and I wouldn't want to speak to what the vendor 5 has done.6MEMBER POWERS: So if somebody comes in 7and says well, yes, my zinc's still here he's okay 8 then?9MR. HISER: Well, I think the qualified 10 life like that depend on certain conditions, and if 11 the conditions in the field are different, maybe less 12 severe, then presumably the lifetime could be 13 extended.14MEMBER POWERS: Yes, I mean if I'm 15 marketing the zinc I'm going to say okay, what's the 16 most severe thing they're going to have here and 17 that's how I'm going to do my calculations. In 18 reality it's something more mild like that's the guy 19 who comes in and says well, you know, my zinc is still 20 here. I mean, that's pretty easy to check. If it was 21the hydroxyl bonding to the steel and de-adhesion 22 that's a much harder thing to check.

23MR. HISER: Yes, I think in this case the 24 discussion that we've had of the qualified life is 25 124 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433really not to say anything bad about what the plant 1 condition is but just the fact that for a 40-year 2 initial lifetime there's no surprise that the coating 3 is no longer intact in many places because it really 4 wasn't designed to be there still.

5MEMBER POWERS: Well, I think what I'm 6 driving at is that when we have these limited lifetime 7 components there's some projection of how long it's 8going to last. Here's one where even if that 9projection is a very accurate one it is, as you 10 accurately pointed out, based on some estimate of what 11conditions, what the service conditions are. Those 12are not the real service conditions. So the fact that 13 its lifetime, projected lifetime has been exceeded 14 doesn't mean anything if it's still functional.

15 Because we know what makes it non-functional.

16MR. HISER: And in the case of the coating 17 like this it makes evident.

18 MEMBER POWERS: Yes, I mean --

19MR. HISER: It's evident whether it's 20 there --21 MEMBER POWERS: It's fairly evident.

22 MR. HISER: -- and functional or not.

23MEMBER POWERS: And it's not catastrophic.

24 I mean, if your coating goes away for a cycle can you 25 125 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433corrode all the way through the liner? I don't think 1 so.2MR. HISER: I don't think so either but I 3 think that's one of the concerns that we have, 4 comparing the general corrosion with the -- whether 5 you want to call it pitting corrosion or corrosion 6 that results in pits in the liner I think the concern 7 we have is there's some very deep pits. And whether 8 that behavior could be replicated in other portions of 9 the liner is really the concern that we have on the 10 re-coating side effects.

11MR. MILANO: Okay. Barring any further 12questions I'll go to the next slide which is the 13 second open item that the staff has.

14 MEMBER BROWN: Can you back up?

15 MR. MILANO: Yes.

16MEMBER BROWN: Just something I didn't 17 understand from what they said during the re-coating, 18applying the re-coating. The zinc is part of the 19 coating, right?

20 MR. MILANO: The original coating.

21 MEMBER BROWN: The original coating.

22 MR. MILANO: Yes.

23MEMBER BROWN: When they said they re-24 coated they re-coated with an epoxy. Has that also 25 126 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433got new zinc? I mean, is that zinc compound or 1 whatever it is?

2 MR. MILANO: No.

3MEMBER BROWN: So there is no renewal then 4 of whatever zinc was lost in that coating area.

5MR. HISER: No, it's a different approach, 6 it's a barrier approach as opposed to --

7MEMBER BROWN: A sacrificial approach.

8 Okay, thank you.

9MR. HISER: But then that coating as well 10 will have a certain qualified life to it.

11MEMBER BROWN: I understand. I didn't 12hear anything on that, on the new re-coating. When 13they go back and re-inspect subsequently in other 14 outages or whatever they do on their spot inspections 15 do you re-inspect the epoxy-coated parts different 16 than you do --

17 MR. HISER: Well, my understanding is --

18MEMBER BROWN: -- different criteria or 19 what do they do?

20MR. BARTON: You look for blisters and 21 stuff in the epoxy.

22 MR. HISER: If they have a service level 23 1 coating that would be something that they would 24 maintain. So they would have an inspection program I 25 127 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 believe as a part of their IWE program.

1MEMBER BROWN: Sort of slow -- I'm an 2 electrical guy so you've gone way over my head.

3 MR. HISER: But the coating --

4 MEMBER BROWN: What does that mean, a 5 service level 1? You mean it's supposed to last 6 forever or?

7MR. HISER: No, it has certain 8 requirements associated with it in terms of 9 inspection.

10MEMBER BROWN: But I'm looking for the 11difference between the epoxy re-inspections. If 12 you've mapped those is there something different you 13 do when you re-inspect periodically relative to those 14 areas you've already re-coated relative to the ones 15 you do for zinc? Is there some different process?

16MR. BARTON: You'd look for different 17things with an epoxy coating than you would for the 18 zinc.19 MR. HISER: The epoxy coating would have 20 its own specific criteria from acceptance by 21 inspection. So areas that have been re-coated would 22 require certain inspections, techniques, frequency, 23acceptance criteria, et cetera. They would be 24different from the zinc coating because they have 25 128 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 different functions and therefore different 1 requirements.

2MEMBER BROWN: I understand they're 3 different. Okay.

4MR. MILANO: Well indeed, in the 5 application itself they have, the applicant did 6 indicate that any areas where they observed flaws and 7 they've re-coated either for that or because the re-8 coating was done because they've exceeded, you know, 9 let's say one of those 25 percent area issues and 10they've re-coated the whole plate that they have 11 committed to do a follow-on inspection during the next 12 refueling outage of that plate surface area.

13MEMBER BROWN: So areas that were re-14coated with the epoxy have a -- okay. So roughly 2 15 years later then you're saying that they would re-look 16 at that during their next outage.

17 MR. MILANO: That's correct.

18MEMBER BROWN: And they've committed to 19 that.20 MR. MILANO: Yes, they have.

21MR. HISER: I don't know that it's 2 22 years. I mean again --

23 MEMBER BROWN: Well, they said refueling 24 outage. I thought they said 2 years during the break.

25 129 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 MR. GALLAGHER: Just as a clarification.

1So, we inspect three times every 10 years. And so 2that's done, that's the interval. And so when you do 3 the inspection you inspect the entire submerged area.

4 So whether there's zinc coating or epoxy coating it's 5 all included in the inspection.

6And three times per 10 years is just, 7that's an ISI interval -- excuse me, period. The 8interval is 10 years. A period is three of them in an 9 interval and that's how that's determined.

10MEMBER BROWN: But those don't necessarily 11 correspond to outages.

12MR. GALLAGHER: Correct. So sometimes you 13 do it like, you know, if you can imagine there's three 14periods in a 10-year. So, it could be like two 15outages, one outage, two outage, you know. That's 16 kind of how you would do it.

17MR. MILANO: Yes, Mr. Gallagher is 18 correct. It was the next refueling outage wherein 19 there was going to be an inspection.

20MEMBER BROWN: Okay. All right. Thank 21 you.22MR. MILANO: With that I'll go onto the 23second open item. This open item describes the 24 staff's concern related to the consideration of 25 130 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 operating experience during the term of the renewed 1 license. This issue has been discussed with the ACRS 2 in previous meetings.

3In March of this year the staff issued 4 final license renewal interim staff guidance ISG 2011-5 5 entitled "Ongoing Review of Operating Experience." 6 This guidance emphasizes that operating experience is 7 a key feedback mechanism used to ensure the continued 8 effectiveness of the aging management programs and 9 activities.

10 In response to the staff's RAIs the 11 applicant has described the process that will be used 12to review operating experience and the staff has 13 reviewed the description of these processes against 14 the framework set forth in the ISG.

15 And I'll repeat this even though Exelon 16 has described the issue itself well and as indicated 17today they -- it appears they're on a path towards 18 resolution.

19 The staff's position is that any 20 enhancements to the existing operating experience 21 review activities that are necessary for license 22 renewal should be put in place no later than the date 23 when the renewed operating licenses are issued.

24 The applicant identified a number of 25 131 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 enhancements in its existing operating experience 1 program. However, these enhancements will not be 2 implemented until about 2 years after issuance of the 3 renewed license.

4 The issue that the staff has as Exelon has 5 indicated that they're responding to is -- it relates 6 to that period between the issuance of the renewed 7 license and that date, the 2-year following date 8 wherein they were going to implement this enhancement.

9 And, well this issue is open pending 10 receipt of the applicant's additional information and 11 the staff's review of it. Next slide.

12 As you know, time-limited aging analyses 13 are those licensing calculation analyses that in part 14 consider aging effects, involve time-limited 15 assumptions defined by the current operating term, are 16 relevant in making a safety determination and involve 17conclusions or the basis for conclusions related to 18the capability of SSCs to perform their intended 19 functions.

20 For each evaluation, analyses or 21 calculation the applicant has to determine that: one, 22 the analyses remain valid for the period of extended 23 operation; two, that the analyses have been projected 24to the end of the period of extended operation; or 25 132 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 three, the effects of aging or the intended functions 1will be adequately managed during the period of 2 extended operation.

3 The staff evaluated the applicant's basis 4 for identifying those plant-specific or generic 5analyses that need to be identified as TLAAs. The 6 applicant two exemptions based on a TLAA but neither 7 of these exemptions is required for the period of 8 extended operation.

9 The exemptions were associated with the 10 pressure temperature, the PT limits developed using 11 exemptions from Appendix G of Part 50 to permit use of 12 ASME code cases and 588 and 640.

13 Since the current PT limits are only valid 14 for 32 effective full power years the exemptions must 15 be superceded before the period of extended operation.

16 Therefore, the current exemptions will not be required 17 during the period of extended operation.

18 Based on its review and the information 19 provided by the applicant the staff concludes that the 20 applicant has provided a list of plant-specific 21 exemptions granted in effect that are based on TLAAs 22 and the applicant has provided an evaluation that 23 justifies the continuation of any exemptions for the 24period of extended operation. Thus in summary the 25 133 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 staff has no open issues in the area of TLAAs section 1 for the SER.

2 And lastly, just in conclusion, and you've 3 seen this conclusion before, the staff's conclusion 4 will be provided in the final SER on the basis of its 5 review. And pending the satisfactory review and 6 resolution of the open items the staff will be able to 7 determine that the requirements of 10 C.F.R. 54.29(a) 8 have been met for the renewal of the Limerick 9Generating Station operating license. And subject to 10 any further questions this concludes the staff's 11 presentation.

12MEMBER SKILLMAN: Back to slide 17, 13please, second bullet. A cynical interpretation of 14 that bullet would be you give us the renewed operating 15license and then we'll do some more work. Is that 16 what that bullet means?

17MR. MILANO: The second bullet, you're 18talking about we'll the enhancements within 2 years 19 following receipt of the renewed licenses. In 20 reality, in reality these enhancements, you know, are 21generally put into place only at the time that the 22 renewed operating license has been granted and stuff.

23 In this case here you're indeed correct as they --

24MS. GALLOWAY: Perhaps Matt Homiack can 25 134 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 answer the question.

1 MR. MILANO: Okay.

2 MR. HOMIACK: Pat, I can field this.

3 MR. MILANO: Thank you.

4MR. HOMIACK: Essentially the enhancements 5 the applicant has described are consistent with the 6framework set forth in the staff's interim staff 7guidance document. However, the only inconsistency is 8in the implementation schedule, the ISG. And the 9 staff's position is that they had -- to be put in 10 place when the renewed licenses are issued. In this 11 case the applicant has indicated that it would like to 12put them in place 2 years after issuance of the 13 renewed licenses. And I believe that's mainly based 14on them, the applicant implementing them across its 15 fleet.16 MEMBER SKILLMAN: Okay, thank you.

17 MR. MILANO: Any other questions? Thank 18 you. 19 CHAIRMAN SHACK: I'm going to open it up 20for comments. Are there any comments from anybody in 21 the audience? Do you want to check and see if their 22line is open and if there are any comments from 23 anybody who's been listening in?

24I'd like to thank the staff for their 25 135 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 presentation. As I understand it we have no real 1 schedule to bring this to the full committee because 2 again we're still working on the resolution of the 3open items. So that's indefinite at the moment unless 4 you have some?

5MR. MILANO: At this point here the staff 6 does have a projected schedule for the safety review 7portion as compared to the environmental review. And 8 based on the two open items and the fact that from 9 what we've heard today and what we knew coming into 10 here we believe that the staff should be able to issue 11 a final SER in January of 2013.

12 And with that there's a -- currently have 13 a full committee presentation scheduled for February 14of next year. Again, it's subject to being able to 15complete the open items but it looks right now like 16 that should be, that could be met.

17 CHAIRMAN SHACK: Okay. Is there anybody 18on the line that would like to make a comment? No.

19Hearing none we'll assume there are none. I'd like to 20 thank you.

21 Again, any final questions from the 22 committee? Anybody have any observations they'd like 23 to make?24MR. BARTON: I think it was a quality 25 136 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.(202) 234-4433WASHINGTON, D.C. 20005-3701(202) 234-4433 presentation and I think we heard a good presentation 1 from both the applicant and the NRC. I struggled to 2 find issues in this application when I was doing the 3 review. So I think it was a good quality application.

4MEMBER SKILLMAN: I would echo that. I 5 think this has been a very high-quality presentation 6 with a lot of very good material.

7I would make two observations. As complex 8 as scheduling would be to do a complete coating of the 9 suppression pool wall and floor it's my thought is 10 that it may be beneficial for the long run to do the 11 entire suppression pool at one time so it is treated 12 uniformly and thoroughly as opposed to breaking that 13 if you will repair up into a number of outages where 14each prior application is in the throes of its own 15 degradation different from the next application. It 16seems to me that that raises variability in 17 understanding what the health of that liner coating 18 would be. That would be my one comment. Thank you.

19 CHAIRMAN SHACK: Any other comments? If 20there are no further comments we'll adjourn. Thank 21 you. 22 (Whereupon, the foregoing matter went off 23 the record at 11:32 a.m.)

24 25 ACRS Subcommittee Presentation September 05, 2012 Limerick Generating Station License Renewal Application

Introductions

Mike Gallagher VP, Exelon License Renewal Gene Kelly License Renewal Manager Dan Doran Limerick Engineering Director Mark DiRado Limerick Engineering Programs Manager Barry Gordon MSc, PE, Senior Consultant, SIA, Inc.

Limerick Generating Station, Units 1 and 2 1 Agenda Introductions Mike Gallagher Site Description Dan Doran Limerick Overview Dan Doran GALL Consistency & Commitments Gene Kelly SER Open Items Gene Kelly Suppression Pool Liner Mark DiRado / Barry Gordon Operating Experience Gene Kelly Questions and Close Mike Gallagher Limerick Generating Station, Units 1 and 2 2 Limerick Generating Station, Units 1 and 2 3 Spray Pond (Ultimate Heat Sink) Schuylkill River Pump House Schuylkill River Independent Spent Fuel Storage Installation (ISFSI) 220 kV Switchyard Limerick Generating Station

Limerick Overview Limerick Generating Station, Units 1 and 2 4 Unit 1 Unit 2 Initially Licensed to 3293 MWt 10/26/84 6/22/89 5% Power Uprate to 3458 MWt 1/24/96 2/16/95 Turbine Rotor Replacements 1998 1999 Digital Feedwater Control 2004 2005 Independent Spent Fuel Storage Installation (ISFSI) 2007 2007 1.65% Measurement Uncertainty Recapture (MUR) 3515 MWth 4/8/11 4/8/11 Main Transformer replacements 2014 2011 Recirculation Pump Adjustable Speed Drive Units (ASD) 2012 2013 Next scheduled Refueling Outage March 2014 March 2013 Current License Expiration 10/26/24 6/22/29

GALL Revision 2 Consistency and License Renewal Commitments Limerick Generating Station, Units 1 and 2 5 GALL Consistency and Commitments Submittal based on GALL Revision 2 Aging Management Programs 45 Consistent with GALL 44 Exception to GALL 1 License Renewal Commitments UFSAR Supplement (Appendix A of the LRA) Managed by Exelon Commitment Tracking program based on Nuclear Energy Institute 99-04, "Guidelines Total of 47 Commitments o45 associated with aging management programs oOperating Experience program enhancement oUnit 1 Recirculation Nozzle flaw re-evaluation Limerick Generating Station, Units 1 and 2 6

SER with Open Items Limerick Generating Station, Units 1 and 2 7 SER With Open Items Open Item 3.0.3.2.13-1 ASME Section XI, Subsection IWE Suppression Pool The Staff needs additional information regarding aging management of suppression pool liners and downcomers in the following areas: Prioritized approach to implementation of coating plan Methods for examination of coating underwater Expected corrosion mechanism Downcomer acceptance criteria Open Item 3.0.5-1 Operating Experience for Aging Management Programs The staff needs additional information to determine whether operating experience will be considered in the period between issuance of the renewed licenses and implementation of the program enhancements Exelon will provide the information to the staff to address this issue 8 Limerick Generating Station, Units 1 and 2 Limerick Generating Station, Units 1 and 2 9 Suppression Pool Key Points Robust MARK II reinforced containment design 100% liner thickness margin Environment minimizes corrosion Inerted atmosphere Excellent water chemistry Low corrosion rate Material condition well understood Enhancements to Aging Management Program initiated in 2012 well before PEO in 2024 Suppression pool liner intended function will be maintained through PEO Limerick Generating Station, Units 1 and 2 10 MARK II Containment Limerick Generating Station, Units 1 and 2 11 Drywell Slab Liner Liner Suppression Pool Downcomer MARK II Containment - Suppression Pool 250-mil continuous carbon steel liner - Liner serves as a leakage barrier Liner structural integrity limits 125 mils minimum general area thickness 62.5 mils minimum local area thickness Limerick Generating Station, Units 1 and 2 12 Suppression Pool Coating System Service Level I inorganic zinc sacrificial coating 6-8 mils initial dry film thickness License renewal intended function is to "maintain adhesion" so as to not impact ECCS suction strainers Coating is a design feature to assist in asset protection Service life sustained by Coating Maintenance Plan -Frequent full ASME exams -Spot recoat and proactive large area recoat

-Regular cleaning and sludge removal Limerick Generating Station, Units 1 and 2 13 Suppression Pool Water Environment Suppression pool water quality meets BWRVIP- Nearly neutral pH (range of 6.4 to 6.8) Temperatures at which low corrosion rates are expected Primary Containment inerted with nitrogen General corrosion rate predicted < 2 mils per year Corrosion data from evaluation grids confirms rate Limerick Generating Station, Units 1 and 2 14 Corrosion Environment General corrosion is the predominant mechanism in the Limerick suppression pools Pitting corrosion is not expected in suppression pools Carbon steel does not form passive films in the low temperature suppression pool water Aggressive anionic species such as chlorides are absent (< 2 ppb) in the suppression pools The suppression pool environment has limited amounts of dissolved oxygen since the airspace above the water is inerted with nitrogen during normal operation Limerick Generating Station, Units 1 and 2 15 Unit 1 Liner Condition Limerick Generating Station, Units 1 and 2 16 84.8 12.6 2.6 0 10 20 30 40 50 60 70 80 90100Number of Localized Corrosion Locations

% Submerged Liner Area Liner Metal Loss (mils)

Unit 1 - 2012 Data Coating Intact >0 25 50 75 100 125 150 175 190 .03 10 % Wall Loss 125-mil large area corrosion limit

Unit 1 Liner Condition Limerick Generating Station, Units 1 and 2 17 84.8 12.6 2.6 0 5 10 15 20 25 30 0 10 20 30 40 50 60 70 80 90100Number of Localized Corrosion Locations

% Submerged Liner Area Liner Metal Loss (mils)

Unit 1 - 2012 Data 25 50 75 100 125 150 175 190 .03 10 % Wall Loss 187.5-mil local corrosion limit

- Individual localized corrosion location > 50 mils Coating Intact >0 Unit 2 Liner Condition Limerick Generating Station, Units 1 and 2 18 95.8 3.8 0.4 0 10 20 30 40 50 60 70 80 90100% Submerged Liner Area Liner Metal Loss (mils)

Unit 2 - 2009 Data Coating Intact >0 25 50 75 100 125 150 175 190 10 % Wall Loss 125-mil large area corrosion limit

Unit 2 Liner Condition Limerick Generating Station, Units 1 and 2 19 95.8 3.8 0.4 0 5 10 15 20 25 30 0 10 20 30 40 50 60 70 80 90100Number of Localized Corrosion Locations

% Submerged Liner area Liner Metal Loss (mils)

Unit 2 - 2009 Data Coating Intact >0 25 50 75 100 125 150 175 190 10 % Wall Loss

-Individual localized corrosion location > 50 mils 187.5-mil local corrosion limit Downcomers 24-inch diameter, 375 mils wall thickness Interior coated with epoxy; exterior with inorganic zinc 45 feet long, lower 11 feet submerged Four downcomers (with vacuum breakers) capped at bottom Unit 1 downcomers inspected in 2012 (< 25 mils wall loss) Unit 2 downcomers inspected in 2009 (< 10 mils wall loss) Metal loss acceptance criteria established: - 44 mils general area metal loss/ 331 mils thickness limit - 62.5 mils local area metal loss/ 312.5 mils thickness limit Criteria will be incorporated into inspection procedure Limerick Generating Station, Units 1 and 2 20 Methods of Examination Underwater Qualified personnel - ANSI N45.2.6 and ASTM D4537 for coating - ASNT CP-189 and ASME XI for liner 100% VT-3 visual exam performed Areas characterized using ASTM D610 (SSPC-VIS-2),

VT-1 examination of augmented areas 25 mils general area or 50 mils local area thickness loss Dial-depth gage for metal loss Dry film thickness gage for coating Visual exams supplemented by volumetric (UT) examination in accordance with IWE-3200 Limerick Generating Station, Units 1 and 2 21 Suppression Pool Plate Limerick Generating Station, Units 1 and 2 22 Examination from 2010 refueling outage Visible area approximately 1 ft 2 Spot General Corrosion Intact Coating General Corrosion

Aging Management Program Enhancements Limerick Generating Station, Units 1 and 2 23 Enhancement Basis 1 De-sludge each Refueling Outage (2 yrs) Frequent cleaning minimizes corrosion sites.

2 Full ASME IWE examination each ISI period (3 times in 10-year ISI interval) for 100% of the submerged surface 100% inspection will occur frequently to confirm expected low corrosion rate for this environment and provide opportunities for recoating.

3 Area recoat for general corrosion > 25 mils General corrosion is 2 mils per year. Acceptance limit is 125 mils metal loss.

Recoating at 25 mils (10% wall loss) and frequent inspection interval ensures minimal additional wall loss.

4 Spot recoat local corrosion > 50 mils Pitting corrosion is not expected due to environment. If localized metal loss rate were hypothetically 16 mils per year, then a 50-mil spot would progress to 114 mils depth over 4 years. The acceptance limit for local corrosion is 187.5 mils metal loss. 5 Recoat plates with > 25% loss of coating Proactively recoat large general areas before significant corrosion occurs.

6 Initiate enhancements in 2012 for Unit 1 and 2013 for Unit 2 Allows 7 cycles for Unit 1 and 9 cycles for Unit 2 prior to the PEO to recoat.

Prioritized Approach to Implementation Prior to PEO Local corrosion > 50 mils recoated in outage of discovery Areas with general corrosion > 25 mils recoated based on ranking of affected surface area (high to low) prior to PEO Plates with > 25% coating surface depletion recoated based on ranking of area depleted and thickness loss prior to PEO During PEO Local corrosion > 50 mils recoated in outage of discovery Areas with general corrosion > 25 mils will be recoated in outage of discovery Plates with > 25% coating surface depletion will be recoated no later than the next scheduled inspection Limerick Generating Station, Units 1 and 2 24 Open Item 3.0.3.2.13 -1 Resolution Prioritized approach to implementation of coating plan Methods for examination of coating underwater Expected corrosion mechanism Downcomer acceptance criteria Limerick Generating Station, Units 1 and 2 25 Summary and Conclusions Robust MARK II containment design 100% liner thickness margin Environment minimizes corrosion Inerted atmosphere Excellent water chemistry Low corrosion rate Material condition well understood Enhancements to Aging Management Program Initiated in 2012 well before PEO in 2024 Suppression pool liner intended function will be maintained through PEO Limerick Generating Station, Units 1 and 2 26 Closing Comments Limerick Generating Station, Units 1 and 2 27 Questions?

Back-up Slides Limerick Generating Station, Units 1 and 2 28 Back-up Slides Suppression Pool Floor Plan Limerick Generating Station, Units 1 and 2 29 Approximately 5,700 ft2 Mockup Wall Panel Limerick Generating Station, Units 1 and 2 30 Mockup Floor Panel Limerick Generating Station, Units 1 and 2 31 Safety Evaluation Report (SER) with Open Items Limerick Generating Station, Units 1 and 2 Issued: July 31, 2012 Advisory Committee on Reactor Safeguards License Renewal Subcommittee 1

September 5, 2012 Patrick Milano, Sr. Project Manager Office of Nuclear Reactor Regulation Safety Evaluation Report (SER) with Open Items Limerick Generating Station, Units 1 and 2 2

Presentation Outline Overview of Limerick license renewal review SER Section 2, Scoping and Screening review Region I License Renewal Onsite Inspection SER Section 3, Aging Management Programs and Aging Management Review Results SER Section 4, Time

-Limited Aging Analyses 3

Facility Facts License Renewal Application (LRA) submitted June 22, 2011 Applicant: Exelon Generation Company, LLC (Exelon)

Facility Operating License Nos. NPF

-39 and NPF

-85 Docket Nos. 50

-352 and 50

-353 Current License Expiration Dates: October 26, 2024, and June 22, 2029 Requested renewal period of 20 years beyond the current license dates Approximately 21 miles northwest of Philadelphia, PA BWRs (GE 4) with Mark II containment design 4

Audits and Inspections Scoping and Screening Methodology Audit

-September 19

-23, 2011(report December 9, 2011)

Aging Management Program (AMP) Audit

-October 3-14, 2011 (report February 28, 2012)

Region I Inspection (Scoping and Screening & AMPs)

-June 4-21, 2012 (report July 30, 2012)

Environmental Review Audit

-November 7

-10, 2011 5 Overview (SER)

Safety Evaluation Report (SER) with Open Items issued July 31, 2012 SER contains 2 Open Items (OIs):

-Suppression Pool Liner and Downcomer Corrosion -Operating Experience Final SER is tentatively expected to be completed in January 2013 6

SER Section 2 Summary Structures and Components Subject to Aging Management Review Section 2.1, Scoping and Screening Methodology Section 2.2, Plant

-Level Scoping Results Sections 2.3, 2.4, 2.5 Scoping and Screening Results 7

Six inspectors over three weeks 10 CFR 54.4(a)(2) inspection 32 of 45 Aging Management Programs Reviewed Overview Regional Inspections 8

Systems in the Units 1 and 2 Reactor Enclosures Systems in the Units 1 and 2 Turbine Enclosures Essential Service Water pipe tunnel 2A Emergency Diesel Generator Room Battery Rooms Refueling Floor Control Room Unit 1 and 2 Spray Pond Structure Compressed Air System Turbine Building, Containment Building, Diesel Generator Building, and Intake Structures Metal Enclosed Buses Walk-downs Regional Inspections 9

Scoping of non

-safety SSCs and application of the AMPs to those SSCs were acceptable.

Inspection results support a conclusion that reasonable assurance exists that aging effects will be managed and intended functions maintained Inspection Conclusions Regional Inspections 10 Calvert Cliffs June 1998 Peach Bottom May 2002 Ginna June 2003 Millstone July 2004 Nine Mile February 2005 Oyster Creek March 2006 Pilgrim September 2006 Vermont Yankee February 2007 Fitzpatrick April 2007 Indian Point January 2008 Beaver Valley June 2008 Susquehanna August 2008 Three Mile Island December 2008 Salem Hope Creek June 2010 Seabrook April 2011 Limerick June 2012 All Region I Plants Inspected for Renewal Regional Inspections 11 Section 3: Aging Management Review Section 3.0 - Use of the GALL Report Section 3.1 - Reactor Vessel & Internals Section 3.2 - Engineered Safety Features Section 3.3 - Auxiliary Systems Section 3.4 - Steam and Power Conversion System Section 3.5 - Containments, Structures and Component Supports Section 3.6 - Electrical and Instrumentation and Controls System 12 SER Section 3 3.0.3 - Aging Management Programs

-45 Aging Management Programs (AMPs) presented by applicant and evaluated in the

SER -No plant-specific AMPs 13 Open Item 3.0.3.2.13

-1 ASME Section XI, Subsection IWE Corrosion in suppression pool carbon steel liner

-General corrosion of liner up to 35 mils in depth, and affecting up to 72% of surface area in some liner panels

-Pitting up to 122 mils deep

-Method for augmented inspection to measure loss of liner material Degradation of liner coating

-Existing coating is inorganic zinc material, 6

-8 mils thick

-Adequacy of criteria for selecting locations for recoating

-Effective identification of degradation in liner plates underwater Identification of acceptance criterion for downcomer corrosion SER Section 3 Open Items 14 Proposed Enhancement to IWE AMP Concerning Suppression Pool Liner Plate Degradation Remove any accumulated sludge in suppression pool every refueling outage Examine submerged portion of suppression pool every ISI period Use results of examination to implement coating maintenance plan

-Perform local recoating of areas with general corrosion that exhibit greater than 25 mils loss in plate thickness

-Perform spot recoating of pitting greater than 50 mils deep

-Recoat plates with greater than 25 percent coating depletion Coating Maintenance Plan will be implemented for the selected areas in a phased approach starting in 2012 Open Item 3.0.3.2.13

-1 15 Corrosion of liner

-Account for pitting corrosion in the enhanced AMP

-Justify technique to measure remaining thickness of liner plates Coating Degradation

-Justify basis for using 25% loss of coated area to classify affected area requiring augmented inspection

-Define and justify phased approach of selective recoating to manage aging due to corrosion and pitting Open Item 3.0.3.2.13

-1 16 Concerns Expressed by the Staff

SER Section 3.0.5 - Operating Experience for Aging Management Programs (OI 3.0.5

-1) Applicant identified several areas where enhancements to operating experience review activities are necessary Applicant plans to implement these enhancements within two years of receipt of the renewed operating licenses Given this schedule, it is not clear whether operating experience related to aging management and age

-related degradation will be adequately considered in the period between issuance of the renewed licenses and implementation of the enhancements Open Item 3.0.5

-1 17 4.1 Identification of TLAAs 4.2 Reactor Vessel Neutron Embrittlement 4.3 Metal Fatigue 4.4 Environmental Qualification of Electrical Equipment 4.5 Containment Liner Plate and Penetration Fatigue Analyses 4.6 Other Plant

-Specific TLAAs SER Section 4: TLAA 18 On the basis of its review and pending satisfactory resolution of the open items, the staff will be able to determine that the requirements of 10 CFR 54.29(a) have been met for the license renewal of Limerick Generating Station Conclusion 19 1 Wen, Peter From: aceactivists@comcast.net Sent: Monday, September 03, 2012 9:07 AM To: Wen, Peter

Subject:

Comments for 9-5-12 Subcommittee MeetingSeptember 3, 2012 Peter Wen Designated Federal Official ACRS Contact For ACRS Subcommittee Meeting Re: Limerick Nuclear Plant License Renewal

Dear Mr. Wen,

The Alliance For A Clean Environment (ACE) just learned about this meeting. ACE is a grassroots group extremely concerned about the safety of millions of people surrounding Limerick Nuclear Plant. NRC failed to notify us about this open to the public meeting, even though we received all the letters NRC sent to Exelon. It is not possible for us to attend, but we would like this committee to consider our comments.

First, we applaud important questions and concerns raised by NRC staff on serious issues concerning corrosion and thinning, in letters to Exelon. We urge this committee to avoid accepting Exelon's illogical explanations and excuses, as has been done in the past. The nuclear industry has admitted some impacted equipment is too big and expensive to replace, putting communities like ours at high risk. We remind NRC there have already been problems at Limerick and the current license isn't up until 2029. The lives of many people depend on NRC standing firm against relicensing on these vital issues.

While we will wait until EIS public hearing comments to address most of the corrosion issues we find alarming, there is one that we feel compelled to bring to your attention at this time. Since 2006, we have been very concerned with and asked questions about corrosion from the cooling tower air emissions. We received MSDS sheets from Exelon on the products they use as additives in the cooling towers and discovered most are extremely corrosive. These do not disappear. They end up in the air or discharges into the river.

NRC also expressed concern about corrosive impacts from Limerick's cooling towers, specifically chlorine, as sodium hypochlorite. NRC pointed to impacts at other nuclear plants.

Are you aware?

Limerick uses massive amounts of Chlorine (Sodium Hypochlorite) - 16, 000 to 58,000 LB S. USED EVERY DAY (From Exelon's NPDES Permit Application)

This doesn't disappear. It ends up in the air and water.

2Exelon told NRC that the chlorine plume from Limerick's cooling towers is of little concern for corrosion of Limerick equipment because it blows offsite. Clearly, not all blows off-site as suggested by Exelon, according to problems NRC cited elsewhere. However, while evidence shows equipment has been corroded elsewhere, we are also worried about the harmful health impacts to our residents from what Exelon admits is blowing off-site.

• When it can corrode steel, what is the chlorine doing to residents around Limerick who breathe in the chlorine from Limerick's drift?

• The World Health Organization has a strict limit on chlorine in air due to its harmful health impacts. Lung cancer and other lung problems are ramped in communities near Limerick, a fact acknowledged by respiratory therapists and physicians. Many residents around Limer ick reported corroded cars and lawn furniture.

• Since 2006, ACE repeated requested year-long air monitoring for all the corrosive chemicals added to Limerick's cooling towers. No agency has complied with our request. The astronomical use of chlorine and other harmful corrosives clearly jeopardizes vital equipment and public health. This is an important reason to reject Limerick Nuclear Plant relicensing.

Massive amounts of corrosive chemicals used at Limerick Nuclear Plant also jeopardize all the miles of underground pipes. Many corrosive chemicals are used. One example: Are You Aware? Sulfuric Acid - 40,000 to 60, 000 LBS. used at Limerick EVERY DAY This doesn't disappear. What vital equipment is being damaged?

Another issue that must be cons idered by NRC:

Are You Aware? Limerick Nuclear Plant cannot meet Clean Water Act standards for its massive dangerous discharges into the Schuylkill River, a vital drinking water source for almost 2 million people.

• Limerick Nuclear Plant's Total Dissolved Solids (TDS) discharges in over 14 BILLION GALLONS PER YEAR, includ e corrosive cooling tower chemicals and the broad range of radionuclides from Limerick's operations.

• Both Exelon and PA DEP admitted that Limerick cannot meet Safe Drinking Water standards (500 mg/L) for TDS under the Clean Wate r Act, or even DRBC's far higher standards (1,000 mg/L).

Instead of requiring reverse osmosis to filter Limerick's TDS (including cooling tower toxics and radionuclides), PA DEP has planned to issue Limerick's 5-Year NPDES per mit, without limits and with an exemption of this pollution. Exemptions don't remove threats to water and health.

PLEASE RESPOND:

How Can NRC Justify Allowing Limerick to be Relicens ed, When Limerick Can't Meet Clean Water Laws for Discharges That Include R adionuclides, Into A Vital Drinking Water Source For Almost Two Million People?

• Circumventing the law does not remove the threats to water and public health.

3* Exelon can reduce the risk with filtration of Outfall 001. To issue relicensing without requiring reverse osmosis for these dangerous discharges would be both irresponsible and negligent.

• NRC has never done testing (much less a year of continuous independent monitoring) for all radionuclides discharged from Limerick's most dangerous discharge pipe, Outfall 001.

• Evidence at Limerick and elsewhere shows why monitoring, calculating, testing, and reporting controlled by Exelon can't be trus ted. Please consider our comments and respond so that we can report y our response to our community.

Thank you,

Dr. Lewis Cuthbert ACE President