ML122770433
| ML122770433 | |
| Person / Time | |
|---|---|
| Site: | Limerick  |
| Issue date: | 10/01/2012 |
| From: | Wen P Advisory Committee on Reactor Safeguards |
| To: | Advisory Committee on Reactor Safeguards |
| References | |
| Download: ML122770433 (198) | |
Text
UNITED STATES NUCLEAR REGULATORY COMMISSION ADVISORY COMMITTEE ON REACTOR SAFEGUARDS WASHINGTON, 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
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, 2012 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 1
Certified on: September 29, 2012 Issued by: October 1, 2012 Certified by: William Shack ADVISORY COMMITTEE ON REACTOR SAFEGUARDS MINUTES OF THE ACRS LIMERICK GENERATING STATION LICENSE RENEWAL SUBCOMMITTEE MEETING SEPTEMBER 5, 2012 On September 5, 2012, the Advisory Committee on Reactor Safeguards (ACRS) Subcommittee on Plant License Renewal held a meeting regarding Limerick Generating Station, Units 1 and 2 license renewals in Room T-2B1, at 11545 Rockville Pike, Rockville, Maryland. The meeting convened at 8:30 a.m. and adjourned at 11:32 a.m. The entire meeting was open to the public.
Written comments from Dr. Lewis Cuthbert of the Alliance for a Clean Environment were received on September 3, 2012. Dr. Cuthberts comments are attached to the meeting transcript.
ATTENDEES ACRS Members/Consultants William Shack, Chairman John Sieber, Member Gordon Skillman, Member Dana Powers, Member Charles Brown, Member John Stetkar, Member John Barton, Consultant Peter Wen, ACRS staff - Designated Federal Official NRC Staff Melanie Galloway Patrick Milano Allen Hiser Abdul Sheikh Matt Homiack Michael Modes Rob Kuntz James Medoff Roger Kahkian Raj Auluck John Wise Alice Erickson Seung Min Michelle Kichline Angela Buford Duc Nguyen Brian Harris Cliff Doutt William Gardner Bryce Lehman Robert Sun Andrew Prinaris Bennett Brady Rui Li Albert Wong Dennis Morey Michael Marshall William Holston James Gavula* Naeem Iqbal*
Exelon Michael Gallagher Dan Doran Gene Kelly Mark DiRado Tom Daugherty Chris Mudrick Chris Wilson John Hufnagel Mark Miller Mary Kowalski Al Fulvio James Jordan R. H. Churomanski Bob Dickinson Mike Guthrie Michelle Karasek Brian Tracy Deb Spamer Ron Hess David Tillman Preet Soni George Buduck Greg Sprissler Shannon Rafferty-Czincila Martin Bonifanti Brandon Shultz Mike Yun Leanne Birkmin Christine Kirkead David Clohecy Ken Slough Mark Marquis, Underwater Construction Corporation Barry Gordon, Structural Integrity Associates Other Attendees Alex Polonsky, Morgan Lewis Tim Matthews, Morgan Lewis Eric Blocker, STARS Arden Aldridge, STPNOC Steve Dorts*, First Energy Corp Rigel Davis*, STARS
- Participating via telephone
SUMMARY
The purpose of the meeting was to review the license renewal application (LRA) for the Limerick Generating Station, Units 1 and 2 and the associated staff draft safety evaluation report (SER) with open items. The briefing was provided by representatives from the NRC staff and applicant, Exelon Generation Company, LLC. The meeting transcripts are attached and contains an accurate description of each matter discussed during the meeting. The presentation slides and handouts used during the meeting are attached to these transcripts.
The following table lists the significant issues that were discussed during the meeting with the corresponding pages in the transcript.
Significant Issues Discussed Reference Pages in Transcript Chairman Bill Shack opened the Limerick License Renewal 4-5 Subcommittee meeting. He acknowledged that the Subcommittee had received written comments from Dr. Lewis Cuthbert of the Alliance for a Clean Environment. Dr. Shack stated that the purpose of this subcommittee meeting was to review the LRA for the Limerick Generating Station Units 1 and 2, the draft SER and associated documents. He noted that the ACRS does not review the Environmental Impact Statement.
Melanie Galloway (Acting Director, Division of License Renewal) noted 7-8 that the Limerick LRA is the first license renewal application consistent with GALL Report Rev. 2. She commented that the recently court issued waste confidence decision will affect renewal schedule for Limerick license renewal.
Exelon presentation on the site description 10-12 Issues discussed:
Potential flooding due to Schuylkill River high water levels 11 Output voltages and interconnectivity of 220KV and 500KV 11-12 switchyards Exelon provided an overview of Limerick operating history 12-13 Exelon provided an overview of Limerick LRA 13-28 Issues discussed:
Based on flow-accelerated corrosion (FAC) operation experience 15-16 described in the LRA, Chairman Shack inquired about the applicants plan to address the FAC-related issue.
Based on Class 1 piping system environmental fatigue analysis 16-17 results, described in LRA Table 4.3.3-2, Chairman Shack inquired about what kind of stress analysis was performed for reactor water cleanup piping which shows CUF of 0.999.
Core shroud weld inspection and material type 17-18 Current status of steam dryer in both units 19 Internal inspections of buried safety-related service water piping 20, also discussed in 96-99 Potential stress corrosion cracking in the closed cooling water 22 systems The status of water chemistry operation in the closed treated 23 water system The bolting integrity program related non-torque loosing problem 24 Scoping issue related to lube oil storage enclosure 25-26 Possible modification on the hardened vent 26-27 Inspection of water control structures 27-28
Exelon discussed the open item related to suppression pool liner issue 28-94 Issues discussed:
The composition of the coating material used in Limerick 30 suppression pool liner.
The material condition of the liner and how it was inspected. 33 Could coating problems observed at older Mark I containments 37-39 occur at Limerick Mark II containments?
How the coating material satisfies both liner protection and suction 39-44 strainer clogging concern as described in Generic Letter 98-04.
Coating inspection and coating maintenance plan 46-48, also discussed in 72-74 Oversight of vendor work on underwater coating inspection 50-54 Suppression pool water environment and general corrosion issue 57-61 Re-coating material and operating experience 80-84 Clarified the applicants coating aging management program 84-87 enhancements.
Organic content of the suppression pool water chemistry 92-94 NRC Staff Presentation 94-134
- 2. Region I inspection 106-108
- 3. Open item related to suppression pool liner issue 115-129
- 4. Open item related to operating experience 129-131
- 5. Time-Limited Aging Analyses 131-133 Issues discussed:
Limerick plant material conditions 108 Inspection of diesel fuel oil storage tank 110-114 Projected lifetime of zinc coating and the need for coating 122-125 inspection Inspection of re-coated expoxy coating and zinc coating 126-128 Chairman Shack adjourned the meeting at 11:32 a.m. 136 FOLLOW-UP ITEMS Issue Reference Pages on Transcript During the Scoping and Screening Methodology audit, the staff selected 103-104 four systems (essential service water system, fuel pool cooling and cleanup system, emergency diesel generator system, and fuel transfer and air start systems) for audit. Member Skillman asked:
- a. What is the basis for selecting only those four systems? Why these 4?
- b. Are these 4 systems the same 4 that have been chosen at other plants in Region I?
- c. Why not 6 or 7 systems? Or why two different systems from these 4?
The staff will provide more detailed response later.
Based on cathodic protection system operation experience, Member 118-120 Skillman asked whether there is any correlation between operability of the cathodic protection system and the observed Limerick plant liner corrosion. Was it a design consideration?
BACKGROUND MATERIALS PROVIDED TO THE SUBCOMMITTEE
- 1. Exelon Generation Company, LLC, Limerick Generating Station, Units 1 and 2 - License Renewal Application, June 22, 2011 (ML11179A101).
- 2. NRC Safety Evaluation Report With Open Items Related to the License Renewal of Limerick Generating Station, Units 1 and 2, July 2012 (ML12213A721).
- 3. Email from Dr. Lewis Cuthbert, the Alliance for a Clean Environment to Peter Wen, ACRS, NRC, Comments for 9-5-12 Subcommittee meeting, September 3, 2012
Official Transcript of Proceedings NUCLEAR REGULATORY COMMISSION Title: Advisory Committee on Reactor Safeguards License Renewal Subcommittee Docket Number: (n/a)
Location: Rockville, Maryland Date: Wednesday, September 5, 2012 Work 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 1 UNITED STATES OF AMERICA 2 NUCLEAR REGULATORY COMMISSION 3 + + + + +
4 ADVISORY COMMITTEE ON REACTOR SAFEGUARDS 5 (ACRS) 6 + + + + +
7 LICENSE RENEWAL SUBCOMMITTEE 8 + + + + +
9 WEDNESDAY 10 SEPTEMBER 5, 2012 11 + + + + +
12 ROCKVILLE, MARYLAND 13 + + + + +
14 The Subcommittee met at the Nuclear 15 Regulatory Commission, Two White Flint North, Room 16 T2B1, 11545 Rockville Pike, at 8:30 a.m., William J.
17 Shack, Chairman, presiding.
18 COMMITTEE MEMBERS:
19 WILLIAM J. SHACK, Chairman 20 CHARLES H. BROWN, JR. Member 21 DANA A. POWERS, Member 22 HAROLD B. RAY, Member 23 JOHN D. SIEBER, Member 24 GORDON R. SKILLMAN, Member 25 JOHN W. STETKAR, Member NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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2 1 ACRS CONSULTANTS PRESENT:
2 JOHN BARTON 3 DESIGNATED FEDERAL OFFICIAL:
4 PETER WEN 5
6 7
8 9
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3 1 A-G-E-N-D-A 2 Applicant's Presentation . . . . . . . . . . . . 4 3 Staff's Presentation . . . . . . . . . . . . . . 96 4 Public Comment . . . . . . . . . . . . . . . . . 135 5
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4 1 P-R-O-C-E-E-D-I-N-G-S 2 8:28 a.m.
3 CHAIRMAN SHACK: The meeting will now come 4 to order. This is a meeting of the Plant License 5 Renewal Subcommittee. I'm Bill Shack, chairman of the 6 Limerick License Renewal Subcommittee.
7 ACRS members in attendance are Jack 8 Sieber, Dick Skillman, Harold Ray, Dana Powers, John 9 Stetkar, Charles Brown and our consultant John Barton.
10 Peter Wen of the ACRS staff is the designated federal 11 official for this meeting.
12 The purpose of this meeting is to review 13 the License Renewal Application for the Limerick 14 Generating Station Units 1 and 2, the draft Safety 15 Evaluation Report and associated documents. I would 16 note that the ACRS does not review the Environmental 17 Impact Statement.
18 We will hear presentations from the 19 representatives of the Office of Nuclear Reactor 20 Regulation and the applicant, Exelon Generation 21 Company, LLC. The subcommittee will gather 22 information, analyze relevant issues and facts, and 23 formulate proposed positions and actions as 24 appropriate for deliberation by the full committee.
25 The rules for participation in today's NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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5 1 meeting have been announced as part of the notice of 2 this meeting previously published in the Federal 3 Register. We have received written documents from Dr.
4 Lewis Cuthbert of the Alliance for a Clean Environment 5 regarding today's meeting.
6 A transcript of the meeting is being kept 7 and will be made available as stated in the Federal 8 Register notice. Therefore we request the 9 participants in this meeting use the microphones 10 located throughout the reading room when addressing 11 the subcommittee. Participants should first identify 12 themselves and speak with sufficient clarity and 13 volume so they can be readily heard.
14 We have several people on phone bridge 15 lines listening to the discussion. To preclude 16 interruption of the meeting the phone line is placed 17 on a listen-in mode.
18 We will now proceed with the meeting and 19 I call upon Ms. Melanie Galloway of the Office of 20 Nuclear Reactor Regulation to introduce the 21 presenters.
22 MS. GALLOWAY: Okay, great. Thank you, 23 Dr. Shack. My name is Melanie Galloway. I'm the 24 acting director of the Division of License Renewal at 25 NRR. And as always on behalf of the staff we are NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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6 1 pleased to be here today to interact and discuss the 2 Limerick License Renewal Application with the ACRS 3 subcommittee.
4 There are a few things I want to note 5 first. We do have representatives from the staff here 6 to support our presentation. We have next to me 7 Patrick Milano, the project manager for Limerick. He 8 has recently been assigned in the last month so we're 9 indoctrinating him early to the process of license 10 renewal in participating in this meeting.
11 I also have a number of branch chiefs here 12 to support. Dennis Morey is our Safety Projects 13 Branch chief. Michael Marshall is the branch chief 14 associated with our Electrical and Structural Branch.
15 And Raj Auluck is in the front row over there and he 16 is our branch chief for the Aging Management of Plant 17 Systems.
18 In addition, Michael Modes is here from 19 Region I to talk about the inspection process 20 associated with Limerick license renewal. And also we 21 have Jim Gavula who's a representative from our Region 22 III office actually assigned to license renewal but 23 placed in Region III.
24 I did want to note a few things about the 25 application. First of all, the Limerick application NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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7 1 is the first application that we have reviewed 2 consistent with GALL Rev 2. So that's of particular 3 note. We do believe that GALL Rev 2 was successful in 4 introducing certain efficiencies in the review and I 5 think the Limerick application supported that.
6 Also, I want to note that the Limerick 7 application was of particular high quality, and that 8 also contributed very significantly to the efficiency 9 and effectiveness of the NRC review. That was also 10 indicated by the number of RAIs we had on the 11 application. The number of first round RAIs was only 12 150 and that is sufficiently lower than other 13 applications which we have in-house now and which we 14 see.
15 And of note also is the fact that the 16 Limerick application is part of the Exelon fleet and 17 the quality of the application not only applies to 18 Limerick but it's also typical of what we see from 19 other Exelon applications. So kudos to the applicant 20 for the good job they've done in making our job 21 easier.
22 In addition, I also want to commend the 23 applicant for the background documentation that they 24 provided to us on our onsite audits. They were 25 extremely thorough and again that made our review much NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 1 more efficient and much more effective. And as a 2 result of this exchange we've had with the applicant 3 in light of the quality that they provided to us our 4 safety review has maintained the current schedule and 5 that is good news.
6 Also, as a result of the exchange we've 7 had so far you'll see that we only have two open 8 items. And again that is reflective of the low number 9 of RAIs and the quality of the application.
10 Now, I do want to mention while I know the 11 ACRS does not review the environmental aspect of the 12 reviews I do need to note that the waste confidence 13 decision which was recently issued by the court has 14 affected review schedules for license renewal. And 15 while the safety review schedule for Limerick remains 16 on schedule the effect of the waste confidence 17 decision and the determination of what the staff needs 18 to do in order to respond to the court's decision is 19 going to cause an ultimate delay associated with 20 Limerick license renewal.
21 At this point that concludes my opening 22 remarks and I'll turn it over to Mike Gallagher, 23 senior vice president for license renewal with Exelon.
24 MR. GALLAGHER: Okay. Thanks, Melanie.
25 Good morning. My name is Mike Gallagher. I'm the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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9 1 vice president of license renewal for Exelon. Slide 2 1, please?
3 Before we begin today's presentation I'd 4 like to introduce the presenters. To my right is Gene 5 Kelly. Gene is the Limerick license renewal manager 6 for Exelon. Gene has 38 years nuclear power plant 7 experience including 13 at Limerick.
8 To Gene's right is Dan Doran and Dan is 9 the Limerick engineering director. Dan has 21 years 10 nuclear power plant experience at Limerick.
11 To Dan's right is Mark DiRado. Mark is 12 our programs engineering manager. Mark has 13 years 13 of nuclear power plant experience at Limerick.
14 To Mark's right is Barry Gordon. And 15 Barry is a senior consultant and corrosion specialist 16 with Structural Integrity Associates.
17 In addition to today's presenters we also 18 have with us Chris Mudrick. And Chris is our senior 19 vice president of mid-Atlantic operations. And we 20 have Tom Daugherty and Tom is our site vice president 21 at Limerick. Slide 2.
22 Slide 2 shows our agenda for the 23 presentation. We will begin with the description of 24 the site and an overview of the operating history 25 followed by an overview of the License Renewal NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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10 1 Application. We will then continue with the 2 discussions of the open items regarding the 3 suppression pool and operating experience.
4 We've developed a comprehensive, high-5 quality License Renewal Application and a robust aging 6 management program that will ensure the continued safe 7 operation of Limerick. We appreciate this opportunity 8 to make this presentation and look forward to 9 answering any questions you might have.
10 I'll now turn the presentation over to Dan 11 Doran. Dan?
12 MR. DORAN: Thank you, Mike. Slide 3, 13 please. Good morning. My name is Dan Doran and I am 14 the engineering director at Limerick Generating 15 Station.
16 Limerick Units 1 and 2 are General 17 Electric BWR/4 designs with Mark II containments.
18 They are owned and operated by Exelon Corporation.
19 The Limerick Generating Station is located 20 on the east bank of the Schuylkill River in Limerick 21 Township of Montgomery County, Pennsylvania and it's 22 approximately 4 miles down-river from Pottstown, 35 23 miles up-river from Philadelphia.
24 On this slide you will see the Schuylkill 25 River which is one of our two non-safety related NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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11 1 makeup water sources, the Schuylkill River Pump House, 2 the independent spent fuel storage installation, the 3 Unit 1 225 kV switchyard, the Unit 2 500 kV switchyard 4 and the spray pond which is our ultimate heat sink.
5 Limerick Generating Station also has four emergency 6 diesel generators per unit.
7 Slide 4, please.
8 MR. BARTON: Let me ask you a question on 9 this slide. Schuylkill River sometimes overflows its 10 banks. I used to live in Cherry Hill so I remember 11 about the Schuylkill River. What effect has the 12 Schuylkill River high levels affected the site?
13 MR. DORAN: It has not affected the site.
14 The site ground elevation is 85 feet above the 15 Schuylkill River.
16 MR. BARTON: All right, thank you.
17 MEMBER SKILLMAN: Question, please. With 18 the two different voltages in the switchyards do the 19 two units generate at different voltages?
20 MR. DORAN: They do not generate coming 21 out of the generator at different voltages. They are 22 stepped up to 200 kV for Unit 1 and 500 kV for Unit 2.
23 The generator terminal voltages are the same.
24 MEMBER SKILLMAN: Thank you.
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12 1 interconnected?
2 MR. DORAN: Excuse me?
3 MEMBER SIEBER: Are those switchyards 4 interconnected onsite?
5 MR. DORAN: They can be interconnected 6 through a cross-tie line that we have. We can supply 7 power from both units from either of the units that 8 are cross-tied. That's correct.
9 MEMBER SIEBER: Thank you.
10 MR. DORAN: Slide 4, please. This slide 11 provides an overview of Limerick's history as well as 12 the major station improvements.
13 Limerick was initially licensed to 3,293 14 megawatts thermal in 1984 for Unit 1 and 1989 for Unit 15 2. Following a successful startup test program 16 commercial operation began in 1986 and 1990 for Unit 17 1 and Unit 2 respectively.
18 A 5 percent increase in rating of power on 19 both units was performed in the 1995-1996 time frame.
20 And on April 8th of last year a 1.65 percent 21 measurement uncertainty recapture power uprate was 22 implemented which increased the thermal rating on each 23 unit to their current rating of 3,515 megawatts 24 thermal.
25 Exelon has continued to make substantial NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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13 1 improvements to both Limerick units such as turbine 2 rotor replacements, digital feedwater control 3 modifications, independent spent fuel storage 4 installation, main transformer replacements, and most 5 recently the addition of recirc pump adjustable speed 6 drives.
7 Limerick is operated on 24-month fuel 8 cycles. The current 24-month capacity factor is 91.6 9 percent for both units.
10 The License Renewal Application was 11 submitted on June 22nd, 2011. Our current licenses 12 expire on October 26th, 2024 for Unit 1 and June 22nd, 13 2029 for Unit 2.
14 I will now turn it over to Gene Kelly who 15 will present to you the highlights of the License 16 Renewal Application.
17 MR. KELLY: Thank you, Dan. Slide 5, 18 please? Good afternoon. My name is Gene Kelly and 19 I'm the license renewal manager. My portion of the 20 presentation covers the highlights of our License 21 Renewal Application including aging management 22 programs, commitments and an overview of the two open 23 items in the SER. Slide 6, please.
24 In preparing the application Exelon used 25 industry and NRC guidance with the goal of making our NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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14 1 application as consistent with the GALL as possible.
2 Our submittal was based on GALL Revision 2.
3 There are 45 aging management programs 4 including 34 existing programs, 11 new programs 5 developed. Twelve of the existing programs required 6 no changes to align with the GALL. Twenty-one of the 7 existing programs required enhancements to align with 8 the GALL. The one exception to the GALL is associated 9 with the reactor head closure stud bolting program, 10 specifically the preventive measures for measured or 11 actual yield strength.
12 There are 47 license renewal commitments.
13 These commitments are managed under an existing 14 process consistent with NEI 99-04 and tracked as part 15 of that process.
16 Forty-five of these commitments are 17 associated with aging management programs. One 18 commitment institutes operating experience program 19 enhancements and another commitment will reevaluate a 20 Unit 1 recirculation nozzle safe-end flaw that was 21 mitigated by a mechanical stress improvement process 22 in 1992 prior to entering the period of extended 23 operation. Slide 7, please.
24 CHAIRMAN SHACK: Before we get into this 25 I just -- since we don't seem to have an opening to NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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15 1 discuss other parts of the license renewal thing let 2 me just ask some questions about some other items.
3 One I was concerned about, I was looking 4 at the flow-assisted corrosion evidence and in 2008 5 you had 62 inspections on Unit 1 and you replaced 454 6 feet of small-bore piping. In 2010 you did 102 7 inspections and replaced 442 feet of small-bore and 74 8 feet of large-bore piping.
9 On trending that doesn't look real good.
10 How much susceptible piping do you have left and do 11 you anticipate that kind of replacement going forward 12 in the future?
13 MR. DIRADO: Sure. The flow-accelerated 14 corrosion program is fleet-wide and it's based on 15 known industry regulations and requirements. As part 16 of the flow-accelerated program all of the susceptible 17 piping is modeled. I don't have a total number 18 available to me. We can certainly provide that.
19 But what I will say is that as we make 20 enhancements and learn where our areas are we actually 21 have been increasing the number of inspections. So 22 what you say is possibly an increasing trend in the 23 number of inspections and replacement. I look at it 24 as good management of the program to, one, understand 25 where the vulnerabilities are and ensure they get NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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16 1 monitored prior to having failures. If you look at 2 our failure rate I'm sure that would show you it had 3 favorable results for the station.
4 CHAIRMAN SHACK: Okay. There's another 5 one that was kind of curious and it says, you know, no 6 preventive or mitigative measures are directly -- the 7 FAC program. The program considers water treatment 8 changes that may affect FAC rates. For example, water 9 treatment amines, hydrogen water chemistry, hydrogen 10 addition, or any change that might affect the pH or 11 dissolved oxygen concentration. What systems do you 12 use amines and hydrazine in?
13 MR. KELLY: I think I'd like to ask Greg 14 Sprissler of our chemistry department to address that 15 question, please.
16 MR. SPRISSLER: Greg Sprissler. I'm with 17 the chemistry department at Limerick Station. We are 18 currently not using any amines for treating chemicals 19 at Limerick Station.
20 CHAIRMAN SHACK: Yes, that's sort of what 21 I figured. It just seemed like a curious statement.
22 Okay.
23 The next question is on fatigue. And 24 you've got an environmental cumulative usage factor 25 for one system, reactor water cleanup -- I like this NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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17 1 number -- 0.9990. It's certainly less than 1.
2 You're crediting there the reduction in 3 the number of cycles. Does that also include a finite 4 element analysis to get the stresses down, or is that 5 with a sort of a classic code type conservative stress 6 number?
7 MR. KELLY: It was a classic code type 8 approach.
9 CHAIRMAN SHACK: Okay.
10 MR. KELLY: We didn't do finite elements 11 but we have additional information in the corrective 12 action process where we're going to address that with 13 a more refined analysis. And that's actually underway 14 and working in the corrective action process.
15 CHAIRMAN SHACK: Okay. Then just another 16 question. You had some cracking in your core shroud 17 welds on both units. Just how much cracking are we 18 talking about here? Feet, inches, kilometers?
19 MR. KELLY: I'll field it initially and 20 then I'll ask our engineer to come up. But we've 21 examined all the horizontal and vertical welds at this 22 point and we do see cracking in most of those welds.
23 In some of them it's more than 10 percent of the 24 inspected length and so that puts you on an increased 25 inspection schedule.
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18 1 Most of those cracks are considered quite 2 shallow and the hydrogen water chemistry appears to be 3 effective. And we'll continue to examine it per the 4 BWRVIP guidelines and you know, do the appropriate 5 structural integrity analyses to make sure we have 6 adequate margin for the shroud.
7 MR. BARTON: Do you have any mechanical 8 restraints on your core shrouds?
9 MR. KELLY: No, none. We did not put any 10 fixes in, John. No tie rods or anything like that.
11 MR. BARTON: I got it.
12 MR. KELLY: No repairs.
13 CHAIRMAN SHACK: Is that material 304-LM?
14 MR. KELLY: I'd like to ask Michelle 15 Karasek, our vessel internals engineer, to address 16 that question. Michelle, the question is about the 17 material type of the shroud.
18 MS. KARASEK: Hello, this is Michelle 19 Karasek, Limerick site RPV internals program owner.
20 It is 304-L.
21 CHAIRMAN SHACK: 304-L.
22 MS. KARASEK: Yes.
23 CHAIRMAN SHACK: And the weld metal?
24 MS. KARASEK: I don't have that 25 information.
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19 1 CHAIRMAN SHACK: But the cracking is in 2 the base metal typically.
3 MS. KARASEK: That's correct. It's in the 4 heat-affected zones.
5 CHAIRMAN SHACK: In the heat-affected 6 zones.
7 MS. KARASEK: That's correct.
8 CHAIRMAN SHACK: But even in the 304-L 9 welds.
10 MS. KARASEK: Yes.
11 CHAIRMAN SHACK: Okay.
12 MR. BARTON: Are you through with core 13 shroud? Let's jump from core shroud to steam dryers.
14 I noticed you've got some steam dryer issues that 15 you've found during inspections. What's the current 16 status of your steam dryers in both units?
17 MR. KELLY: Michelle, could you please 18 address that question?
19 MS. KARASEK: This is Michelle Karasek 20 from Limerick site RPV internals program engineer. We 21 have extensively inspected the core shroud -- I'm 22 sorry, the steam dryer on both units in accordance 23 with GE SILs and the VIP-139. We completed all 24 baseline inspections.
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20 1 mostly in the support ring. There are a few hood seam 2 weld indications that are also IGSCC and one fatigue 3 flaw in a hood seam weld that has relieved itself and 4 is not showing any signs of new or changed in growth.
5 MR. BARTON: So you're nowhere near 6 talking about steam dryer replacements I take it.
7 MS. KARASEK: No, we're not talking about 8 steam dryer replacements. I know it's on as a 9 proposal if we go to EPU. That is something that is 10 being looked at and evaluated.
11 MR. BARTON: Thank you.
12 MEMBER STETKAR: Bill, are we going to try 13 to get all of the peripheral things out of the way 14 first?
15 CHAIRMAN SHACK: Yes. I assume once we 16 get into the liner that will probably.
17 MEMBER STETKAR: If so I've got a couple 18 of questions, one on buried pipe. And the RHR service 19 water and essential whatever you call it, ESW system.
20 I got confused as I was reading back and forth among 21 the LRA and RAIs and SER and all of those 22 abbreviations. Are you going to do internal 23 inspections of the buried safety-related service water 24 piping?
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21 1 inspections of that piping. We are currently in 2 progress of replacing large-bore RHR service water 3 piping in our pipe tunnel.
4 As we remove that piping it will provide 5 an opportunity which we will take advantage of to send 6 an inspection method down and inspect the internals of 7 the large-bore underground piping.
8 MEMBER STETKAR: Okay. Are you going to 9 be doing -- that's fine, but the period of extended 10 operation is a ways in the future. Are you going to 11 be doing periodic inspections, internal inspections of 12 that piping during the period of extended operation?
13 MR. DORAN: We do not have plans at this 14 time to do that. If the opportunity presents itself.
15 MR. GALLAGHER: But we added a commitment 16 to do the inspection when accessible.
17 MEMBER STETKAR: But isn't that 18 inconsistent with Rev 2 of the GALL report that says 19 if you've had indications of leakage or problems 20 you're supposed to do something like a 5-year periodic 21 inspection of 25 percent of the piping or something 22 like that?
23 MR. GALLAGHER: For external?
24 MEMBER STETKAR: Internal.
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22 1 consistent with the GALL.
2 MEMBER STETKAR: Okay. I guess we'll ask 3 the staff about that. Take that as a heads up. No, 4 I'll wait till you get up so that we can get to the 5 applicant's presentation.
6 One other question. On the closed cooling 7 water systems there's a statement made that they're 8 not susceptible to stress corrosion cracking because 9 the temperatures are below 60 degrees C. That sounds 10 fairly low. I mean some of those systems, they're 11 diesel generator cooling water systems, they are 12 recirc pump cooling water. Are the outlet 13 temperatures uniformly below 60 degrees C on all of 14 those closed cooling water lines?
15 MR. KELLY: I'd like to ask Mark Miller of 16 our license renewal project team to address that 17 question, please.
18 MEMBER STETKAR: It seemed a rather modest 19 temperature to me.
20 MR. MILLER: Mark Miller, Exelon license 21 renewal. The portions of the system that have 22 stainless steel are less than 140 degrees Fahrenheit.
23 There are portions in the system that exceed 140 24 degrees but there is no stainless steel material in 25 those portions.
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23 1 MEMBER STETKAR: Okay, thank you.
2 MR. BARTON: I've got a couple more if you 3 want to take the time now, Bill. Closed treated water 4 systems. In early 2009, January 2009 and again in 5 November you had some problems with the turbine 6 closure cooling water system. You had high 7 consumption of the chemicals from that system and 8 turned it over to a system engineer for the root cause 9 and that's where the story ends in the documents I was 10 reading.
11 In November then you had an increasing 12 trend in nitrate concentration in that same system.
13 Now, can somebody explain what was going on in that 14 system and has that problem been resolved?
15 MR. KELLY: Yes, I would like to have Greg 16 Sprissler of the chemistry department address that, 17 please.
18 MR. SPRISSLER: Greg Sprissler from the 19 Limerick chemistry department. That was a TBCW 20 system. It was identified by our chemistry analysis, 21 sampling analysis program. We were making frequent 22 adds of sodium nitrate and copper corrosion inhibitor 23 to the system. It was documented in our CAP system.
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24 1 leakage but that did not follow through because of the 2 copper corrosion inhibitor was not being -- was being 3 affected also.
4 It was determined by engineering that it 5 was a leakage. I don't have details on how the system 6 was repaired, where the leak was found, how it was 7 repaired but I can tell you that the system is very 8 stable now. We have not made sodium nitrate adds 9 since 2010 and we have not made a copper corrosion 10 inhibitor add since 2011.
11 MR. BARTON: Okay, thank you. In the 12 bolting -- this goes to one of your aging management 13 programs, your bolting integrity program. In the 14 literature I went through I noticed there was a lot of 15 examples of loose connections resulting from improper 16 tightening of mechanical connections throughout the 17 documents. And that's more than I would expect.
18 That's more than I've seen in a lot of other plants.
19 My question there is did you recognize 20 that? Did it require additional training and 21 maintenance or what? Because it was an awful lot of, 22 you know, non-torque loosening and it just seemed like 23 there was a problem there somewhere in your system.
24 Has that -- have you tackled that? Has that been 25 resolved?
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25 1 MR. KELLY: It has. I'd like to ask Ron 2 Hess of the project team to address that question. I 3 think he has the details on this.
4 MR. HESS: My name is Ron Hess. I'm with 5 the Limerick license renewal team. Those events did 6 result in enhancements to our training program. First 7 of all, specifically some of those related to the use 8 and application of hydraulic torque. So that was 9 specific training that was instituted for maintenance 10 personnel using hydraulic torque wrenches. And also 11 our continuing training includes modules for 12 maintenance personnel on bolting connections. And 13 those were enhanced as well to include the OE from 14 those events.
15 MR. BARTON: Thank you. And looking at 16 the application and scoping I was confused here.
17 Section 2.4 talked about screening of structures. The 18 auxiliary water pipe tunnel which is located under the 19 auxiliary water enclosure houses safety-related piping 20 and is in scope for license renewal.
21 And a couple of paragraphs later it says 22 the lube oil storage enclosure is located above below-23 grade piping tunnel that contains safety-related 24 piping. However, I couldn't find that this lube oil 25 storage -- that this was in scope.
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26 1 Can somebody explain that? It seems like 2 they're both over an enclosure that's got safety-3 related piping yet one's in scope and the other is 4 not. Lube oil storage enclosure is not included in 5 scope and yet the auxiliary water tunnel located under 6 the auxiliary water enclosure is in scope. So I don't 7 understand what's going on here.
8 MR. GALLAGHER: We had received an RAI on 9 that also and had some clarity so maybe we can have 10 Dave Clohecy. Can you please give us the info on 11 that?
12 MR. CLOHECY: My name is Dave Clohecy and 13 I'm a member of the Exelon license renewal team. We 14 revised the LRA in response to an RAI. We clarified 15 in that response that the non-safety related aux 16 boiler enclosure and the non-safety related aux boiler 17 pipe tunnel were both in scope because they were 18 immediately adjacent to the reactor enclosure which is 19 safety-related. We also clarified that the lube oil 20 structure is not in scope because it is not 21 immediately adjacent to the reactor enclosure.
22 MR. BARTON: Okay, thank you.
23 CHAIRMAN SHACK: Just do you currently 24 have a hardened vent for your wet well?
25 MR. GALLAGHER: No, we do not.
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27 1 CHAIRMAN SHACK: So that will be something 2 you'll be considering? I know that your most 3 beneficial SAMDA was an ATWS vent. Would you consider 4 making your hardened vent larger than the 1 percent 5 sort of decay heat level vent that most plants are 6 considering?
7 MR. GALLAGHER: I don't know what we're 8 considering, Dr. Shack, on that but we're heavily 9 involved with the industry initiatives and we'll put 10 the appropriate size hardened vent in in accordance 11 with the orders.
12 MR. BARTON: I've got one more.
13 Inspection of water control structures. Your program 14 is to monitor all water chemistry inside every 5 years 15 and your program was enhanced to do that. What's your 16 current frequency and why did you increase it to every 17 5 years? Is there something going on in your 18 groundwater that's indicating it's getting aggressive 19 or something?
20 MR. KELLY: I believe the answer is no but 21 I think I'd like to have Dave Clohecy answer that 22 question if he can.
23 MR. CLOHECY: My name is Dave Clohecy and 24 I'm a member of the Exelon license renewal team. Our 25 groundwater, a few wells have tested with chloride NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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28 1 that is a little higher than we would like. However, 2 the groundwater is below the level of the safety-3 related structures and we are monitoring the sub-4 drainage sump head as a leading indicator of the 5 concrete condition.
6 MR. GALLAGHER: So I think we went to the 7 5 years just to be consistent with GALL.
8 MR. CLOHECY: Yes, that's correct. The 9 GALL requires that 5-year monitoring so we are doing 10 that at 5 years per the GALL.
11 MR. BARTON: That's it. The only other 12 questions I've got are on the liner. We're going to 13 get to that.
14 MR. GALLAGHER: We can continue on.
15 MR. KELLY: Okay, slide 7 then. There are 16 two open items in the Limerick SER. Slide 8, please.
17 The first open item involves aging 18 management of the suppression pool liner. The NRC 19 staff is requesting more information in four main 20 areas: our prioritized approach to implementation of 21 the coating maintenance plan, the method utilized for 22 examination of the coating underwater, the expected 23 corrosion mechanism present in the suppression pools, 24 and the incorporation of acceptance criteria for 25 downcomer examinations into aging management NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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29 1 procedures.
2 We will provide background information on 3 the suppression pool and we will address the four 4 areas where the NRC staff is requesting more 5 information in our presentation. The additional 6 information to address this open item will be 7 submitted to the NRC staff for their review.
8 The second open item involves operating 9 experience for aging management programs. The staff's 10 question relates to the review of aging management 11 related operating experience in the period between the 12 issuance of the renewed licensee and the 13 implementation of our operating experience program 14 enhancements which we've committed to enhance within 15 2 years following issuance of the renewed licenses.
16 Exelon will conduct appropriate operating 17 experience reviews to close this gap. Additional 18 information will be submitted to the NRC staff for 19 their review. This completes our discussion of the 20 operating experience open item.
21 I will now turn the presentation over to 22 Mark DiRado --
23 MEMBER POWERS: Can I ask you a question 24 about your coating material. That's a sacrificial 25 zinc?
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30 1 MR. KELLY: Yes. Inorganic zinc.
2 MEMBER POWERS: What is it really?
3 MR. KELLY: I'm not sure I understand your 4 question. Can you repeat it, Dr. Powers?
5 MEMBER POWERS: Well, we know it's not 6 just zinc that you put on it. What else does it have 7 in it?
8 MR. GALLAGHER: Mark Miller, it's a 9 question about the coating system, the present coating 10 system. Do you have the details of that?
11 MR. MILLER: Mark Miller, Exelon license 12 renewal. The question is what other constituents are 13 within the zinc coating?
14 MEMBER POWERS: Yes, like zinc chromate or 15 something like that.
16 MR. MILLER: I don't have the information 17 on that.
18 MR. GALLAGHER: It was the original 19 coating system in the plant.
20 MR. MILLER: I can tell you that it's a 21 carbozinc and a Dimetcote.
22 MEMBER POWERS: In that case I know what 23 it is. Thank you.
24 MEMBER SKILLMAN: Gene, I'd like to ask 25 you a question, please. In the second open item we NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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31 1 are talking in this room today about granting an 2 extension that will become effective 20 years from 3 now. This open item is asking why operating 4 experience won't be factored in until 2 years after 5 that future 20-year period begins.
6 MR. KELLY: Actually it's 2 years after 7 issuance of the licenses, not when the PEO begins, Mr.
8 Skillman.
9 MR. GALLAGHER: Yes, the issue was that 10 the staff guidance in the ISG says to institute your 11 enhancements to get to the operating experience 12 program immediately upon receipt of the license. We 13 said that we wanted a 2-year transition because we 14 want to implement the enhancements fleet-wide.
15 The basis for that was our existing 16 program is very, very robust. I mean our whole 17 application is built on our existing program so we 18 think the existing program in itself is good.
19 But with that we are enhancing the 20 program. We're going to do it fleet-wide. And then 21 the staff had asked for what, in this transition 22 period what are you going to do. And so we're going 23 to address that also. So we're putting these 24 enhancements in fleet-wide and for Limerick at least 25 10 years before the PEO. So it's pretty much meeting.
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32 1 MEMBER SKILLMAN: Thank you, that 2 clarification helps. It surprises me that the wording 3 isn't worded that way such that what you're really 4 communicating is we will make sure that we've got the 5 operating experience well embedded many years before 6 the PEO.
7 MR. GALLAGHER: And that's our intent.
8 MEMBER SKILLMAN: Thank you.
9 MR. GALLAGHER: Okay, Gene.
10 MR. KELLY: Okay, so Mark I'll turn it 11 over to you. And Mark will discuss the suppression 12 pool.
13 MR. GALLAGHER: Yes, so this is our main 14 part of our presentation. We're going to go into the 15 details, background and details of the suppression 16 pool. So, open-ended questions you have, that's this 17 period.
18 Mark?
19 MR. DIRADO: Thank you. Slide 9, please.
20 Good morning. My name is Mark DiRado and I'm the 21 engineering programs manager at Limerick. First I 22 will summarize some key points about our suppression 23 pool. I will then address those in detail on the 24 subsequent slides. Slide 10, please.
25 The Limerick primary containment is a NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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33 1 robust Mark II design. It incorporates a 6-foot to 8-2 foot thick reinforced concrete containment and a 250 3 mil thick metal leakage barrier. The liner is twice 4 as thick as needed to withstand design loads.
5 Excellent water chemistry in the 6 suppression pool in combination with a normally 7 inverted suppression pool airspace results in a low 8 general corrosion rate.
9 The material condition of the liner has 10 been thoroughly characterized as part of ASME code 11 inspections and the material condition is therefore 12 well understood.
13 MEMBER SKILLMAN: Mark, would you explain 14 that a little more thoroughly please? How is it 15 documented? How long has the material condition been 16 examined? What level of confidence should we have 17 that that statement is thoroughly accurate?
18 MR. DIRADO: We have a very high level of 19 confidence in the water condition, the inspections 20 being performed and the documentation of the results.
21 Each inspection that's performed is done by 22 professional divers using calibrated instruments 23 underwater. Those are documented in the results and 24 they are reviewed by the station after each subsequent 25 outage. The data is collected and reviewed by NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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34 1 engineering to validate corrosion rates, trends and 2 factor into future re-coating or repair plans.
3 MR. GALLAGHER: And Mr. Skillman, we're 4 going to go into this in a lot of detail. It's 5 actually on slide 21 where we go into the inspections.
6 And one point we wanted to make up front 7 is we have -- are transitioning from an inspection 8 program to a comprehensive aging management program.
9 And we feel we're doing this early, you know, because 10 like we said we're 12 years away from PEO. So you 11 know, as you know IWE only came in play in like the 12 year 2000 so there's only been a couple of inspections 13 in accordance with IWE.
14 We instituted the aging management program 15 for Unit 1 as we started the last outage so we say we 16 thoroughly characterized it. For Unit 1 we have done 17 a complete survey inspection of the suppression pool 18 and we're going to present to you a summary of the 19 information here in this presentation. And we'll tell 20 you how -- that we take that data and why we're very 21 confident that we can identify the areas that require 22 attention in the coating system.
23 MEMBER SKILLMAN: Thank you.
24 MR. DIRADO: Exelon is committed to an 25 aggressive aging management program. This will be NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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35 1 begun well in advance of the period of extended 2 operation. And we'll ensure that the suppression pool 3 liner's intended function is maintained throughout the 4 period of extended operation. Slide 11, please.
5 The Limerick Mark II primary containment 6 design is shown in the diagram on this slide. Primary 7 containment consists of a drywell and a suppression 8 pool. A slab separates the upper and lower sections 9 of containment. The continuous carbon steel liner 10 which is shown in the blue color on the slide 11 functions as a leakage barrier. The suppression pool 12 is situated below the drywell.
13 Downcomers provide a direct path to the 14 water in the suppression pool. That's for uncondensed 15 steam from the drywell during the design basis event.
16 Slide 12, please.
17 The suppression pool has a continuous 18 carbon steel liner. It's coated with inorganic zinc.
19 The liner is 250 mils thick and functions as a leakage 20 barrier for the reinforced concrete containment 21 structure. The strength of the containment is derived 22 from the 6-foot to 8-foot thick reinforced concrete.
23 The liner has 100 percent thickness 24 margin. In that 125 mils of general or large area 25 thickness is required for liner structural integrity.
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36 1 A minimum local area thickness of 62.5 mils is 2 required for structural integrity of the liner. This 3 means that flaws less than 2.5 inches in diameter and 4 up to 187.5 mils in depth could be tolerated. Slide 5 13, please.
6 I will now describe the original coating 7 system applied to the suppression pool liner and its 8 intended function. The continuous carbon steel liner 9 is a service level 1 inorganic zinc sacrificial 10 coating.
11 MR. BARTON: Excuse me. What's the life 12 of this coating? The useful life. I mean you're 13 using this coating maybe 20-25 years or pick a number.
14 Do you know what the useful life of this coating is?
15 What's the vendor say is the useful life of this?
16 MR. GALLAGHER: Well the vendor, they'll 17 give you a short number. Basically --
18 MR. BARTON: What's their short number?
19 MR. GALLAGHER: Well, I think we had an IR 20 that said like 15 years or something like that.
21 MR. BARTON: Yes, that's what I was 22 thinking.
23 MR. GALLAGHER: But really the life of the 24 coating is sustained by the implementation of the 25 coating maintenance plan. That's what we're proposing NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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37 1 in this aging management program. Basically you touch 2 up the coating and the coating with good chemistry, 3 water chemistry, the type of water that's in the 4 suppression pool you can maintain the coating system 5 for a long, long time. So there's really no such 6 thing as, you know, a specific service life. It's 7 maintained by the coating maintenance.
8 MR. BARTON: The only reason I'm asking 9 that is been there and done that. You probably know 10 about this, right? You were there.
11 MR. GALLAGHER: Right, right.
12 MR. BARTON: We had suppression pool with 13 -- it had some kind of, I don't know, zinc something 14 coating. Life 20-25 years. Well, before that time it 15 got so bad the coating maintenance program did not 16 work and we ended up with complete re-coating of 17 suppression pool liner. And I'm just wondering if 18 that's -- I don't mean to interrupt your presentation 19 but you know, eventually we gave up and had to 20 completely re-coat it.
21 MR. GALLAGHER: Yes, and that's always a 22 possibility. I think we, you know, like I said we 23 transitioned from an inspection program to an aging 24 management program. I think at the right point 25 definitely when you look at our data on Unit 2, Unit NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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38 1 2 is very, very, you know minor. Unit 1 we have a 2 little bit of catchup to do. But I think you'll see 3 that, you know, I think we got it at the right point.
4 We can get into a good coating maintenance plan.
5 MR. BARTON: Okay.
6 CHAIRMAN SHACK: But I mean, just coming 7 back to John's point. The material in your 8 environment is really the same as a Mark I 9 containment. I mean you know they're different 10 containment designs but the corrosion problem is 11 similar. And we sort of know the older Mark Is 12 certainly have coating problems. It's just hard for 13 me at least to understand why you're going to be any 14 different than those plants are.
15 MR. BARTON: That's where I was coming 16 from.
17 MR. GALLAGHER: And we recognize that 18 because we have plants of those vintage also. And we 19 know the -- and we'll get into the presentation, but 20 the larger implications of say replacing your coating 21 system. There's a lot of issues with that. Obviously 22 you have to offload the core, you have to -- in that 23 outage you have to reduce the ECCS inventory during 24 that outage. There's radiological issues, industrial 25 safety issues. In fact, we're going through that at NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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39 1 one of our plants that we're in process on. So we 2 think that if we can do this early we can maintain the 3 system.
4 And then, however, we'll get into showing 5 you our commitment. The commitment is clear, we have 6 to meet the criteria going into the period of extended 7 operation. So, if the only way to do it is to replace 8 the system then that's what we'd have to do.
9 CHAIRMAN SHACK: The focus here is on 10 structural function. There's also the Generic Letter 11 9804 kind of thing of preventing particulate products 12 and stuff. There are places you seem to have lost a 13 lot of coating that, you know, you may not be getting 14 a structural limit but I assume that you're generating 15 particulate at a fairly good clip.
16 Both of these have to be met and that was 17 one of the things that was confusing to me, that you 18 say you're meeting the XI S8 protective coating thing 19 which is sort of an ASME, or an ASTM kind of thing to 20 I think look at it as a 98-04 kind of a problem. And 21 then you're off here in IWE space looking at it as a 22 structural problem.
23 Are both of those consistent? Is one more 24 limiting than the other?
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40 1 where we're talking about what the intended function 2 is of the coating system, the present coating system.
3 MR. GALLAGHER: Well, you made it 4 inorganic zinc for some reason.
5 MR. GALLAGHER: Yes, and the reason, just 6 like you said Dr. Shack, is that the -- you know, you 7 balance the two issues, asset protection and not 8 clogging the suction strainers for ECCS. So this 9 coating system was actually picked because it kind of 10 dissolves. It doesn't cause problems with clogging of 11 the suction strainers.
12 CHAIRMAN SHACK: Well, but that's the 13 adhesion of the film. What I'm worried about is that 14 you're getting corrosion products.
15 MR. GALLAGHER: Yes, and part of our aging 16 management program is to de-sludge, clean up the 17 suppression pool every outage. And that's part of our 18 commitment to -- and when we do that, let's see, Ron 19 Hess, Ron, how much particulate corrosion products do 20 we remove each outage now?
21 MR. HESS: Okay, Ron Hess, Limerick 22 license renewal team. Typically on a yearly basis we 23 generate about 100 pounds of material that is then 24 removed during our de-sludging operations during 25 routine outages.
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41 1 MR. GALLAGHER: So it's not really that 2 much and the suction strainers are huge.
3 MR. BARTON: One hundred pounds?
4 CHAIRMAN SHACK: Yes, I was going to say 5 we'll have Sanjoy come in and talk to you about 100 6 pounds of particulate.
7 MEMBER STETKAR: That's 100 pounds under 8 for all practical purposes stagnant conditions. No 9 blowdown forces, no --
10 MR. KELLY: Correct.
11 MEMBER STETKAR: -- nothing deciding to 12 dislodge a lot of other material.
13 MR. GALLAGHER: Yes, it's the corrosion 14 products from -- that's in the piping system.
15 MR. KELLY: And it's a very -- Dr. Shack, 16 a very small fraction of the design loading of those 17 new strainers. They're much bigger and can 18 accommodate quite a bit more than that.
19 MR. HESS: Yes, if you want me to add some 20 information, our design requirements for the ECCS 21 suction strainers include things like 900 cubic feet 22 of insulation, 1,000 pounds of sludge, 150 pounds of 23 miscellaneous dust and dirt, another 50 pounds of 24 corrosion products.
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42 1 loading on the strainers from material that we remove 2 each de-sludging operation is far more than what the 3 strainers are designed to accommodate.
4 CHAIRMAN SHACK: Is that based on full-5 scale testing of thin bed effects?
6 MR. HESS: That's --
7 (Laughter) 8 MEMBER POWERS: Just say no.
9 MEMBER SKILLMAN: That sounds like a small 10 number and we're laughing because maybe it is but you 11 know, a 40-pound plate, steel, 1 square foot and 1-12 inch thick is 40 pounds. That's 2 and a half square 13 feet of steel -- if it's iron? Fighting its way out 14 of your system into sludge, if it's iron.
15 That's not really inconsequential. Think 16 about it. You might say well there are an awful lot 17 of square feet. Well, I'm not sure that gives me any 18 comfort. Most of the square feet are probably covered 19 with your inorganic coating. I'm concerned about all 20 the stuff you can't see that's wasting away.
21 MR. GALLAGHER: Most of the corrosion 22 products are coming from the piping systems which are 23 attached, not from the system itself. When you see 24 the -- not from the liners. When you see the coating 25 coverage right now we have about 85 percent of the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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43 1 coating still intact on Unit 1, 96 percent on Unit 2.
2 So, it's relatively, you know, a small area that's 3 affected by the --
4 (Laughter) 5 CHAIRMAN SHACK: It's square feet. That's 6 probably not so insignificant.
7 MEMBER SKILLMAN: That's what I think. I 8 mean if you really make it thin you'd say golly, that 9 could be a lot of stuff.
10 MR. GALLAGHER: What I'm saying is the 11 corrosion products are not predominantly coming from 12 the liner, they're coming from the piping system.
13 MEMBER SKILLMAN: I got it.
14 MR. GALLAGHER: Okay, so Mark, why don't 15 we start with this slide again on --
16 MR. DIRADO: Sure.
17 MR. GALLAGHER: There's some key points 18 here we wanted to make sure.
19 MR. DIRADO: Okay. As stated previously, 20 the continuous carbon steel liner has a service level 21 1 inorganic zinc sacrificial coating.
22 The coating was applied to the liner with 23 a 6 to 8 mil dry film thickness. The intended 24 function of the coating is to maintain adhesion so as 25 to not adversely affect the ECCS strainers by NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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44 1 clogging. The coating --
2 CHAIRMAN SHACK: If that was its intended 3 function you wouldn't put it on.
4 MR. GALLAGHER: It's intended function is 5 because that's the safety-related function of the 6 coating system is to prevent clogging of safety-7 related ECCS systems.
8 MR. DIRADO: Right. We --
9 MR. GALLAGHER: We have it on there --
10 CHAIRMAN SHACK: Okay, but not only by 11 maintaining adhesion but also by reducing corrosion 12 product development.
13 MR. DIRADO: It's probably a combination 14 but you know, in effect it was to make sure that you 15 don't have flaking of your coating from, you know, 16 post accident that would go onto your suction 17 strainers and clog it.
18 MR. DIRADO: We view the coating system as 19 a design feature that assists in asset protection.
20 CHAIRMAN SHACK: You mean you put this on 21 just to make sure it wouldn't flake off?
22 MEMBER POWERS: I mean that makes no sense 23 at all.
24 MR. GALLAGHER: We put it on for asset 25 protection.
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45 1 MEMBER POWERS: To make sure it didn't 2 fall off.
3 MR. GALLAGHER: The safety-related 4 function is so it doesn't affect the safety-related 5 systems.
6 MEMBER POWERS: You put it on so you don't 7 corrode your steel.
8 MR. GALLAGHER: For asset protection.
9 MEMBER POWERS: And when you do your 10 inspection the only vehicle you have to tell that it's 11 failing to meet this adhesion is to see it flaking 12 off, is that right?
13 MR. GALLAGHER: Visual, yes.
14 MEMBER POWERS: You don't have a good 15 mechanism to tell us when these things are getting old 16 and we're losing the hydroxyl bonding?
17 MR. GALLAGHER: Actually, we do dry film 18 thickness measurements and we'll talk to you about 19 that in the inspection slide. You can see how thick 20 the coating is remaining.
21 MEMBER POWERS: You get the thickness but 22 you don't know anything about the adhesion to the 23 surface other than --
24 MR. GALLAGHER: Yes, that would just be --
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46 1 bubbles when you're doing it.
2 MEMBER POWERS: Yes, I mean it's just a 3 visual thing. It's the only thing we have.
4 CHAIRMAN SHACK: Don't some of the ASTM 5 requirements have adhesion tests?
6 MR. GALLAGHER: I think when you apply the 7 coating.
8 CHAIRMAN SHACK: Apply the coating.
9 MR. GALLAGHER: But not when you're --
10 MEMBER POWERS: What we know is that as 11 these materials age you start developing a carbon 12 yield signal when you do an infrared spectrum monitor.
13 And I suspect it's the anolic hydroxide is changing 14 into a carbonyl group. But I don't know that for a 15 fact.
16 I know only the empirical observation but 17 we've just never developed an instrument that you 18 could take in and run over the coating and say oh, 19 it's getting bad here and it will start flaking off 20 five outages from now. I mean we just don't have 21 that.
22 Anecdotally, I asked the Air Force how 23 they knew when to change -- when to paint their 24 airplanes. And the guy told me we have invested 25 millions of dollars in academic research in this. But NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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47 1 in the end some sergeant goes out, looks at it and 2 decides whether to paint it or not. There are lots of 3 devices out there but nobody uses them. It's just 4 unfortunate. I mean the only thing you can do is you 5 look at it.
6 MR. GALLAGHER: We'll get into our visual 7 inspection methods in subsequent slides. We'll tell 8 you how we do that. Okay? Mark.
9 MR. DIRADO: Thank you. The service life 10 of the inorganic zinc coating is sustained by 11 implementation of our coating maintenance plan.
12 Frequent full ASME exams, spot re-coating, protective 13 large area re-coats and frequent cleaning of the 14 suppression pool and removal of sludge sustain the 15 service life of this coating system.
16 MEMBER SKILLMAN: Mark, how do you know 17 your coating maintenance plan and program are robust 18 and effective? If it's your protection how do you 19 know it's working for you?
20 MR. DIRADO: We -- for effectiveness of 21 the plan each inspection that's done in review has a 22 documented engineering evaluation that follows it to 23 validate a number of specific factors that will weigh 24 into either augmentation or moving up of the re-25 coating or additional methods to, corrective NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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48 1 maintenance to maintain the liner appropriately.
2 MEMBER SKILLMAN: How do you weave 3 operating experience into that?
4 MR. DIRADO: The operating experience is 5 gathered for each coating application. It's discussed 6 in or prior to coating work. Each outage there's a 7 set of meetings that are held that will factor that 8 in. We use industry experts that factor in operating 9 experience from the past and bring those to the 10 station. We leverage INPO and other outside sources 11 for that, plus we have a large fleet where operating 12 experience for coating maintenance is leveraged as 13 well.
14 MEMBER SKILLMAN: Thank you, Mark.
15 MR. BARTON: Who does this work? Is this 16 contracted out each outage?
17 MR. DIRADO: Yes.
18 MR. BARTON: And who does the inspection 19 of the contractor's work?
20 MR. DIRADO: The contract organization 21 currently is UCC.
22 MR. BARTON: They do their own? The plant 23 doesn't go and look, inspect the work that's done in 24 the liner in the outage?
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49 1 construction company. It's a diving outfit because 2 it's done underwater. And they will do the 3 inspections.
4 MR. BARTON: They do the work and inspect 5 their own work?
6 MR. GALLAGHER: And they would do the 7 coating. And so you know, it's all done in accordance 8 with their inspection procedures.
9 MR. BARTON: But you never go and check?
10 MR. GALLAGHER: Well, we have --
11 MR. BARTON: The guy does the work and 12 inspects it and turns in some paperwork. But do you 13 ever double-check?
14 MR. GALLAGHER: With our own diving folks?
15 No.
16 MR. BARTON: You don't.
17 MR. GALLAGHER: There's some oversight 18 that occurs by video, you know, and that type of 19 thing, but they have a QA program in accordance with 20 their quality assurance program. We verify that they 21 meet all those requirements.
22 MR. BARTON: Okay.
23 MEMBER BROWN: So they do the work and 24 then they tell you they did it right.
25 MR. BARTON: Yes, exactly.
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50 1 MR. GALLAGHER: Well, there is oversight.
2 I mean, you know, they're on video the entire time.
3 MEMBER BROWN: I heard the video part but 4 I didn't understand it. They've got a camera and 5 you've got somebody off --
6 MR. GALLAGHER: Yes.
7 MEMBER BROWN: -- sitting up there looking 8 at what they're looking at so you can see that they 9 spot a bubble or they spot an area or they take a 10 measurement or whatever they do underwater?
11 MR. GALLAGHER: There's some oversight 12 just because they're on video the entire time. But 13 you know, the company.
14 MEMBER BROWN: Watching guys float around 15 underwater, you know, just trying to get a picture of 16 how you get a feel for whether their inspection is 17 actually effective or not other than them telling you 18 that it is. That's -- I'm just following up on that.
19 MR. BARTON: Yes, well that's my concern.
20 You know, there's nobody from the plant that goes and 21 actually looks at what did this guy do and the 22 paperwork he turned in, does it really -- is it really 23 what happened.
24 MEMBER BROWN: Auditing the papers.
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51 1 you have a dishonest contractor, I'm just saying you 2 know at some point you go check his work and that's my 3 concern. You're not doing that.
4 MR. KELLY: We have him here today and 5 he's going to address that in a later slide. But I 6 think I'd like to ask our program owner, George 7 Buduck, to step up and maybe address this. George is 8 the ISI engineer at Limerick and George is responsible 9 to implement this program including the oversight of 10 those vendors. So George, you might want to address 11 the question of oversight.
12 MR. BUDUCK: George Buduck, the Limerick 13 ISI program owner. We do not review their 14 inspections. We don't specifically have divers that 15 go in and take a look at it to verify the readings are 16 accurate. We don't do anything like that.
17 CHAIRMAN SHACK: Do you get to see closeup 18 video of the surfaces?
19 MR. BUDUCK: There are some videos that we 20 do look at. We do have a picture that we will show 21 later on.
22 CHAIRMAN SHACK: Yes, I mean I saw that 23 picture. The question is really how much of that 24 inspection you're actually able to monitor with the 25 video or is it just a picture of a, you know, a NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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52 1 region. Or is it, you know, somebody really is 2 actually sort of looking at this inspection.
3 MR. BARTON: You know, somebody is sitting 4 there watching this video while the guy's doing the 5 work. Is somebody from the site actually sitting 6 there watching that? Or is it a copy of his film or 7 something he gives you? I'm a little nervous about 8 your oversight of the work that's being done.
9 MR. GALLAGHER: The oversight we do do is 10 there is a live video that's occurring during the 11 outage. And we have people that can look at the video 12 and do. I'm not saying we're there the entire time 13 but there is some oversight. And we verify that the 14 contractor is doing his work in accordance with the 15 contract.
16 But this work is underwater and we are not 17 there with him underwater but he is -- and we have 18 Mark Marquis. Where's Mark? Mark, come up to the 19 microphone, please. Mark is our underwater 20 construction contractor. So Mark, maybe you can give 21 us some more insight on this and our oversight.
22 MR. MARQUIS: Mark Marquis, Underwater 23 Construction Corporation. During any given inspection 24 we have video monitors with -- that are relaying 25 pictures right from the diver's helmet at any given NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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53 1 time.
2 We are I'll say subject to I'll call it a 3 spot audit or whatever by plant QC, et cetera.
4 Whether or not they come down is certainly to the 5 utility's discretion. So, it's always being played 6 back, it's always there. A live feed is always there 7 available at any given time for anybody to watch over 8 our shoulder.
9 MEMBER BROWN: How clear is the video?
10 MR. MARQUIS: The video is --
11 MR. BARTON: The water's moving when these 12 guys are --
13 MR. MARQUIS: Yes, the water --
14 MR. BARTON: That creates refraction and 15 everything else.
16 MR. MARQUIS: It's -- water clarity is, 17 you know, we have sufficient visibility to conduct the 18 inspection. Generally it's greater than 12 inches, 19 less than 48 for the most part in general.
20 MR. GALLAGHER: And we have some pictures 21 here we can show you. And they're right from the 22 video that the diver is -- from his helmet cam.
23 MEMBER BROWN: But the diver's using his 24 -- Mark's eyeball. It's a clarity. In other words, 25 he's got to be right up against the wall effectively NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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54 1 to tell any condition.
2 MR. GALLAGHER: And that is the 3 inspection. So he's a qualified inspector, you know, 4 has a level 2 inspection criteria. Mark's a level 3.
5 And you know, they're doing it in accordance with 6 approved procedures and a QA plan.
7 MR. DIRADO: And if I could just add, for 8 the inspections when we do conduct these during the 9 outages there is a dedicated site team that works with 10 the underwater coating inspectors. They're reviewed 11 on a shift basis. If there's any questions that are 12 brought up or challenges that come from engineering 13 they're provided directly to the team. We've never 14 had an issue with going back out and re-looking or 15 clarifying an issue that we have.
16 And as far as general oversight the divers 17 are in communication with that team during the work.
18 There is Exelon personnel provided during the coating 19 inspection activities. And they're there to answer 20 any possible questions or challenges or questions that 21 may come up during the course of the coating activity.
22 If I can continue we'll go onto slide 14.
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55 1 pH and normally below 90 degrees Fahrenheit where low 2 general corrosion rates are expected.
3 There exists only trace amounts of 4 chlorides less than or equal to 2 parts per billion 5 which is 2 orders of magnitude below the recommended 6 limit. Sulfates average less than or equal to 13 7 parts per billion.
8 Primary containment is normally inerted 9 with nitrogen. So a little dissolved oxygen is 10 present and available to drive corrosion. The general 11 corrosion rate in the Limerick suppression pool is 12 less than 2 mils per year and this value has been 13 confirmed by data taken from evaluation grids which 14 are monitored in the suppression pool on each unit.
15 One area that the NRC staff requested more 16 information is the expected corrosion mechanism in the 17 suppression pool. I will now turn the presentation 18 over to Barry Gordon who will discuss this issue.
19 MR. GORDON: Thank you, Mark. General 20 corrosion of carbon steel is the predominant corrosion 21 mechanism expected at the Limerick suppression pool.
22 Pitting corrosion is not expected in the Limerick 23 suppression pools. When carbon steel is essentially 24 exposed to the steel border at ambient temperatures 25 carbon steel simply rusts. It does not pit.
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56 1 This statement is supported by three main 2 mitigating factors. First, pitting corrosion occurs 3 in alloys that form thin nanometer protective passive 4 films on the surface. Carbon steel does not form 5 passive films in the low-temperature high-purity water 6 that's observed in the Limerick suppression pool.
7 CHAIRMAN SHACK: Again there's an 8 inspection report that says every floor and wall 9 plate, every downcomer and every suppression pool 10 column has some degree of pitting. Most of the pits 11 and floor plates are less than 50 mils deep and there 12 are hundreds of pits that are less than 30 mils deep.
13 MR. GORDON: This is misinterpretation.
14 This is the most common, common thing I see relative 15 to pitting. Everyone looks at -- if you look at high 16 magnification of general corrosion you're going to see 17 little indications that look like pits and it's just 18 not -- it's just not pitting. It is indeed pits, but 19 it is not the pitting mechanism.
20 Second, pitting of passive alloys such as 21 stainless steel, aluminum alloys, nickel-based alloys, 22 typically occurs in the presence of aggressive anolic 23 species, especially chlorides. But this primary 24 pitting agent is not present, essentially not present 25 in the Limerick suppression pools.
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57 1 MEMBER SKILLMAN: Barry, how do you know 2 that you have identified what could be the aggressive 3 species? You identified chlorides, sulfates. I know 4 one case where sulfites were more aggressive than 5 either chlorides or sulfates. Could there be other 6 anions or cations in the suppression pool water that 7 would be particularly aggressive right at the water?
8 MR. GORDON: If you had -- even if you had 9 aggressive species present which doesn't appear to be 10 the case you still need a material that forms a 11 passive film. The fact that carbon steel in this 12 environment does not form a passive film like it does 13 in case of embedded in concrete where it does form a 14 passive film you still wouldn't -- you have more, a 15 higher rate of general corrosion but you wouldn't have 16 pitting corrosion.
17 MEMBER SKILLMAN: Thank you.
18 MR. GORDON: Finally, the suppression pool 19 environment has limited amounts of dissolved oxygen 20 since the airspace above the water is inerted with 21 nitrogen during operation. Dissolved oxygen is 22 necessary to drive the corrosion process. In other 23 words, the limited amount of cathodic reactant oxygen 24 will mitigate all forms of corrosion in the Limerick 25 suppression pool.
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58 1 I'll now turn the presentation back to 2 Mark DiRado who will discuss the results of IWE 3 examinations in the suppression pools and the material 4 condition in the liners of both units.
5 MEMBER POWERS: When you say that the head 6 space is inerted with nitrogen what is the oxygen 7 partial pressure?
8 MR. KELLY: I would like to ask Greg 9 Sprissler of the chemistry department if he can 10 address that question. Greg, did you hear the 11 question?
12 MR. SPRISSLER: I did. The partial 13 pressure of oxygen in the suppression pool, was that 14 the question?
15 MEMBER POWERS: And the head space above 16 the pressure.
17 MR. SPRISSLER: Greg Sprissler from the 18 Limerick chemistry department. I do not have that 19 information, sorry.
20 MEMBER POWERS: But the inertion can take 21 that oxygen potential down below -- partial pressure 22 down below a torr in something like that, right?
23 MR. GALLAGHER: The tech spec is less than 24 4 percent.
25 MEMBER POWERS: Yes, the tech spec is NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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59 1 nonsense, okay, because you go way below that.
2 MR. GALLAGHER: Yes, but that's what it's 3 maintained, at least below 4 percent oxygen.
4 MEMBER POWERS: But even at 1 percent 5 that's enough dissolved oxygen to drive corrosion, 6 isn't it?
7 MR. GORDON: But a lot of the -- I mean, 8 the oxygen will be consumed with corrosion of the 9 zinc, you know, film and also any exposed carbon 10 steel. Also, you know, the oxygen should be higher 11 concentration at the surface and then it will decrease 12 as you go down.
13 MEMBER POWERS: It ought to.
14 MR. GORDON: Yes.
15 MEMBER POWERS: It ought to if it's being 16 consumed.
17 MR. GORDON: Yes. It's essentially de-18 aerated at the bottom.
19 MEMBER POWERS: My contention here is they 20 can't inert it enough to totally suppress corrosion.
21 MR. GORDON: Right, but --
22 MEMBER POWERS: It's just impractical.
23 MR. GORDON: Yes. But again, at 90 24 degrees Fahrenheit you go from maybe 5 ppm to a 25 significant, to 1 ppm or half a ppm dissolved oxygen.
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60 1 MEMBER POWERS: Yes, but it's -- it's 2 doing that because it's being consumed.
3 MR. GORDON: But it can't be refreshed 4 during the operating period.
5 MEMBER POWERS: Sure it can.
6 MR. GORDON: Well, you have still a slow 7 amount of oxygen.
8 MEMBER POWERS: Yes, but it's probably 9 fast compared to the corrosion. The corrosion is only 10 2 mils per year.
11 MR. GORDON: Right.
12 MEMBER POWERS: The leak into their system 13 is more oxygen than that by a lot.
14 MR. GALLAGHER: Yes, I think your point, 15 Dr. Powers, is that the corrosion, even though the 16 oxygen is low there's enough in there to sustain a 17 corrosion rate. And I think that we would give you 18 that but the overall environment does support about a 19 2 mil per year corrosion rate and that's basically 20 what we see.
21 MEMBER POWERS: Yes, I mean you're 22 inerting it, it helps, but it's not going to suppress.
23 CHAIRMAN SHACK: It's not going to 24 eliminate.
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61 1 not --
2 MR. GALLAGHER: Yes, we just want to 3 describe the overall environment which is -- supports 4 this 2 mil per year general corrosion rate and that's 5 kind of the point we're trying to make.
6 MEMBER POWERS: Okay. I make that but you 7 know, to appeal to inertion here. I mean inerting for 8 these guys is inerting for combustion, okay? That's 9 what they're looking for. It's not inerting to 10 suppress corrosion.
11 MR. GALLAGHER: Right, exactly.
12 MEMBER STETKAR: Do you run your 13 suppression pool cooling and cleanup system 14 continuously, sporadically, as needed? Only during 15 outages?
16 MR. DORAN: We run the suppression pool 17 cleanup system prior to our outages to clean up the 18 pool and on certain periodicity we run suppression 19 pool cooling when needed for temperature.
20 MEMBER STETKAR: Temperature.
21 MR. DORAN: That's correct.
22 MEMBER STETKAR: Okay, thank you.
23 MR. DORAN: And, I'm sorry, and for 24 surveillance testing.
25 MEMBER STETKAR: Oh, sure.
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62 1 MR. DORAN: Surveillance testing.
2 MEMBER STETKAR: Thank you.
3 MR. DIRADO: Thank you. Slide 16, please.
4 This slide depicts the current material condition of 5 the Unit 1 liner using data from the 2012 refueling 6 outage. A little bit of introduction may be necessary 7 at this point for the data so let me walk you through 8 the format of the graphic and how we portray this 9 data.
10 The total submerged surface area affected 11 by corrosion is graphically shown on the y axis.
12 That's from zero to 100 percent. That's as a function 13 of the metal liner wall loss which is zero to 190 14 mils. The first vertical dashed line is the 10 15 percent liner wall thickness value, or 25 mils. The 16 acceptance limit for general corrosion of 125 mils is 17 shown on the dashed vertical line.
18 MEMBER BROWN: Did you say coating intact 19 was assumed to be anything greater than 190 mils? For 20 that first column. Did I understand that or did I get 21 that --
22 MR. GALLAGHER: No, just the x axis is 23 zero to 190. The coating intact we're actually 24 showing less than zero, meaning that there's no 25 degradation and the coating is intact. So that first NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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63 1 bar, that e 4.8 percent is no corrosion and the 2 coating is intact.
3 MEMBER POWERS: This gives an overall view 4 for the whole area but if we ascribe to the 5 description of corrosion that you've just given to us 6 it would be the area around the water line that would 7 be most heavily corroded because that's where the 8 oxygen concentration is the highest. So do we have 9 one that's spatially resolved so that we know if the 10 water line area is more displaced into the 25 to 50 11 than the vast majority of it?
12 MR. GALLAGHER: We don't have a spatial 13 depiction in our slide set. Most of the corrosion is 14 occurring on the floor and there's no real particular 15 pattern to it per se if you look at it. There is some 16 corrosion of the walls and like you said it would be, 17 you know, in the upper part. That does occur. But 18 most of it is on the floor.
19 MEMBER POWERS: If it's corroding on the 20 floor then it's some mechanism other than this oxygen 21 that was described to us earlier. Presumably 22 corrosion under sludge that you're taking out.
23 MR. GALLAGHER: Well, yes. And there's a 24 whole debate on, you know, what does the sludge do.
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64 1 depletion of the coating system. That being said 2 we're -- we want to make sure as part of our aging 3 management program that we eliminate it. So we're, in 4 our commitment we're going to take the sludge out 5 every outage. And it's got to help, that's our view 6 and that's the way --
7 MEMBER POWERS: It can't hurt.
8 MR. GALLAGHER: Yes, right. So, that's 9 part of our program.
10 CHAIRMAN SHACK: What has your past 11 practice been about removing sludge?
12 MR. GALLAGHER: It wasn't every outage and 13 early in plant life there were several outages where 14 it was not removed. And you know, then the ECCS 15 suction strainer issue came up in the mid-nineties and 16 that's when more frequent cleaning would occur. But 17 it was not every outage. We are going to do it every 18 outage and that's part of our aging management program 19 commitment.
20 MEMBER POWERS: I guess what concerns me 21 is that when we talked about corrosion we focused in 22 on oxygen which manifest you need or you don't get 23 corrosion product. But now you're telling me that 24 this oxygen may in fact be supplied by a sludge rather 25 than by the ambient air dissolving in your solution.
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65 1
2 MR. GALLAGHER: Well I don't know if we're 3 saying that but what we're, you know, we'll get into 4 the elements of our plan that's going to be on page 23 5 when we get there. But basically what we're trying to 6 say is we, you know, we think that we have a 7 comprehensive -- we're addressing all the elements in 8 the program. You know, keep it clean, frequent 9 inspections, low threshold for inspection for re-10 coating. Start early, you know, in the plant life, 11 transitioning from this inspection to aging 12 management. So all those elements are included in 13 this.
14 MEMBER POWERS: Put a fan in there to keep 15 the corrosion products suspended.
16 MR. GALLAGHER: No, we haven't got to that 17 point.
18 MEMBER STETKAR: Well, in that sense, the 19 reason I asked earlier, does your suppression pool 20 cleanup system take -- can it take a suction from the 21 bottom of the pool? I mean dead bottom.
22 MR. DORAN: That's where it does take a 23 suction from.
24 MEMBER STETKAR: Thank you. That's your 25 fan.
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66 1 (Laughter) 2 MEMBER POWERS: Obviously it's not enough.
3 MEMBER STETKAR: Well, they don't run it.
4 MEMBER POWERS: Oh, I see. I think a 5 little impeller in there to keep it a little stirred 6 up.
7 MR. GALLAGHER: Okay, Mark?
8 MR. DIRADO: So at this part of the slide 9 we were discussing the vertical bars that are shown on 10 the graph. The first bar that's shown in green 11 indicates that 84.8 percent of the submerged liner 12 surface has intact coating.
13 The second bar which is shown in orange 14 indicates that 12.6 percent of the submerged liner 15 surface is affected by general corrosion that averages 16 in depth up to 25 mils.
17 The third bar which is shown in blue 18 indicates that 2.6 percent of the liner surface is 19 affected by general corrosion that ranges in average 20 depth from 25 to 50 mils.
21 The fourth smaller bar shown in red 22 indicates that a very small portion, 0.03 percent of 23 the liner surface is affected by general corrosion 24 that has an average depth between 50 and 57 mils.
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67 1 that 97.4 percent of the submerged liner surface area 2 has less than or equal to 10 percent wall loss. All 3 of the data is well below the 125 mil large acceptance 4 limit.
5 The next slide will address smaller local 6 areas of corrosion which are less than 2.5 inches in 7 diameter. Slide 17, please.
8 This graph is similar to the previous 9 slide. Individual localized corrosion spots have been 10 added. The graph shows that there have been a few 11 local areas of general corrosion which is greater than 12 50 mils. The right-hand side y axis is the number of 13 localized corrosion locations from zero to 30 as a 14 function of metal loss in mils.
15 The corrosion locations greater than 50 16 mils in depth are depicted by green diamonds. The 17 acceptance limit for local areas of general corrosion 18 which is 187.5 mils is shown as a dashed vertical 19 line.
20 The deepest single spot of 122 mils was 21 discovered and re-coated in 2006 to arrest the loss of 22 material. This location was re-inspected in 2010 and 23 again in 2012 and confirms that coating remains intact 24 and the loss of material has been arrested. This 122 25 mil spot is likely the result of past mechanical NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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68 1 damage combined with general corrosion.
2 As can be seen from this graph few local 3 areas of general corrosion with greater than 50 mils 4 metal loss have been observed since underwater 5 examinations were begun. Those locations that have 6 been identified are well below the corrosion limit of 7 187.5 mils. Slide 18, please.
8 This slide depicts the current material 9 condition of the Unit 2 liner using data from the 2009 10 refueling outage. The information on this slide is 11 presented in a similar fashion to that on the previous 12 slides. The colored bars on the graph depict large 13 area corrosion as a function of metal loss.
14 The first bar shown in green indicates 15 that 95.8 percent of the submerged liner surface has 16 the coating intact. The second bar which is shown in 17 orange indicates that 3.8 percent of the submerged 18 liner surface is affected by general corrosion that 19 ranges in depth up to 25 mils.
20 The third bar which is shown in blue 21 indicates that a small portion, 0.04 percent, of the 22 submerged liner surface is affected by general 23 corrosion ranging in average depth from 25 to 50 mils.
24 None of the Unit 2 submerged liner surface is affected 25 by general area corrosion greater than 50 mils.
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69 1 The data on this slide indicates that 99.6 2 percent of the liner surface area on Unit 2 has less 3 than or equal to 10 percent wall loss. All of this 4 data is well below the 125 mil large area acceptance 5 limit. The next slide will address the smaller local 6 areas of general corrosion, those less than 2.5 inches 7 in diameter.
8 MR. BARTON: Unit 2 has been in operation, 9 what, 2 years after Unit 1?
10 MR. GALLAGHER: It's about 5 years.
11 MR. BARTON: Five years?
12 MR. GALLAGHER: About 5 years, yes.
13 MEMBER SKILLMAN: So is that differential 14 between Unit 1 and Unit 2 due almost solely to the age 15 during which the submergence has been occurring?
16 MR. GALLAGHER: We think it's the age and 17 we institute, you know, when you identify our practice 18 is to do -- because of operating experience in Unit 1 19 or industry operating experience those good practices 20 were initiated earlier, early.
21 MEMBER SKILLMAN: So it benefitted Unit 2.
22 MR. GALLAGHER: It benefitted more in Unit 23 2.
24 MEMBER SKILLMAN: I understand. Thank 25 you.
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70 1 MR. DIRADO: Slide 19, please. As with 2 the previous slide for Unit 1 localized corrosion 3 locations greater than 50 mils in depth on the Unit 2 4 liner are depicted by green diamonds. The acceptance 5 limit of 187.5 mils is the same for both units.
6 Eight local areas of general corrosion 7 have been identified on the Unit 2 liner greater than 8 50 mils. As can be seen by this graph of submerged 9 liner exams very few local areas of general corrosion 10 with greater than 50 mils metal loss have been 11 observed since underwater examination has begun.
12 Those locations that have been identified are well 13 below the corrosion limit of 187.5 mils. Slide 20, 14 please.
15 Now that I've described the material 16 condition of the suppression pool liners I'll address 17 the design features and material condition of the 18 downcomers.
19 The Limerick Mark II containment has 87 20 downcomers, each 24 inches in diameter with a 375 mil 21 wall thickness. The downcomer interiors are coated 22 with epoxy. The exteriors are coated with inorganic 23 zinc. Each downcomer is 45 feet long and the lower 11 24 feet are submerged. Four of the 87 downcomers, those 25 with vacuum breakers, are capped at the bottom.
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71 1 The Unit 1 downcomers were inspected in 2 2012, currently have less than 25 mils of wall loss.
3 The Unit 2 downcomers were inspected in 2009. Those 4 currently have less than 10 mils of wall loss.
5 The acceptance criteria for general area 6 metal loss is 44 mils. This corresponds to a wall 7 thickness of 331 mils required for structural 8 integrity.
9 For smaller local areas the metal loss 10 acceptance criteria is 62.5 mils. This corresponds to 11 a wall thickness of 312.5 mils which is required for 12 structural integrity.
13 The SER open item identified that these 14 acceptance criteria should be incorporated into the 15 procedures that are used for downcomer inspections.
16 Exelon agrees with the NRC staff. These criteria will 17 be incorporated into aging management inspection 18 procedures.
19 Now that we have addressed the actual 20 material condition of the suppression pool liners and 21 downcomers and the extent of general corrosion we will 22 next address how the ASME IWE examinations are 23 performed.
24 Since we implement the coating maintenance 25 plan by performing underwater inspections the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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72 1 following slide discusses details associated with that 2 method of examination. There is an area -- this is an 3 area where the NRC staff has requested more 4 information on the SER open item. Slide 21, please.
5 This slide depicts how qualified divers 6 perform underwater examinations and record data 7 associated with coating depletion and metal loss.
8 First, personnel performing underwater 9 inspections are qualified and certified coating 10 inspectors. They meet the requirements of ANSI 11 N45.2.6 and ASTM D4537. For the liner the underwater 12 inspectors are qualified to ASNT CP-189 and meet ASME 13 Section 11 requirements.
14 A 100 percent inspection is performed on 15 accessible wall and floor plates to qualitatively 16 assess the general condition of the coating and steel 17 liner by performing a VT-3 visual examination.
18 CHAIRMAN SHACK: What does VT-3 mean in 19 this context?
20 MR. DIRADO: It means that the inspectors 21 are qualified to ASME VT-3 requirements in the 22 performance.
23 CHAIRMAN SHACK: But VT-3 almost sort of 24 means there's no loose parts laying around, right? I 25 mean, it's -- what are you actually looking for when NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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73 1 you say VT-3 in this context?
2 MR. GALLAGHER: It's a visual inspection.
3 We have Mark Marquis. Mark, why don't you tell us 4 about that.
5 MR. MARQUIS: Mark Marquis, Underwater 6 Construction Corporation. VT-3 for the liner 7 inspection is primarily you're looking for anything, 8 any corrosion. You're performing a coating and 9 corrosion assessment on the liner itself. It's not 10 strictly for bolting or loose parts necessarily but on 11 the liner, the welds, et cetera, and all done within 12 -- by our program within 4 feet.
13 CHAIRMAN SHACK: Okay. And then how is 14 that going to differ then from the VT-1 examination?
15 MR. DIRADO: I have some information on 16 that for this slide if you let me continue or we can 17 -- let Mark address. So, for the VT-3 the qualitative 18 examinations, they identify and evaluate any coating 19 discontinuities, any imperfections and also identify 20 the complete loss of coating for an area. This is 21 evident by the presence of corrosion as stated.
22 Our large surface areas then get 23 subdivided into smaller areas as necessary to 24 facilitate data clinician. And then describe the 25 conditions on different regions of the plates.
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74 1 The characterization of the degree of 2 rusting is performed consistent with methods described 3 in the ASME standard test method for evaluating the 4 degree of rusting on painted steel surfaces.
5 Indications of general corrosion are 6 entered into a data sheet by the size of area 7 inspected and the percentage of the inspected area 8 affected. The affected area for a plate is then 9 calculated based on the recorded data.
10 For smaller local areas of general 11 corrosion the inspector identifies the size of the 12 area containing the indications, the size of the 13 indications and the quantity of those indications 14 within the area.
15 VT-1 or a detailed visual examination is 16 performed for plate areas that meet the augmented 17 requirements of ASME IWE. For the liner plate areas 18 that exceed 25 mils general area or 50 mils local area 19 are subject to augmented examinations.
20 Metal loss for such areas is 21 quantitatively assessed for these areas using 22 calibrated depth gauges and adjusted by measuring dry 23 film thickness of the coating to determine the actual 24 metal loss for each reported location.
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75 1 volumetric UT in accordance with ASME IWE 3200. These 2 supplemental exams are used when degradation would 3 otherwise require additional technical evaluation such 4 as conditions which would bring into question 5 surrounding metal assumptions contained in the design 6 flaw analyses.
7 Considering all these quality measures and 8 examination techniques Exelon is confident that the 9 underwater examinations are performed rigorously in 10 accordance with procedures and industry standards. We 11 are also confident that both metal loss and coating 12 depletion will be consistently and thoroughly 13 characterized both prior to and during the period of 14 extended operation. Slide 22, please.
15 This picture provides an idea of what the 16 liner corrosion looks like in the suppression pools.
17 The visible area seen is approximately 1 square foot.
18 It represents a plate surface that's affected by 19 general corrosion that is occurring at a rate of less 20 than 2 mils per year in the suppression pool. The 21 estimated coating depletion on this plate is 40 22 percent. The average metal loss due to general 23 corrosion is 17 mils in depth which is less than 10 24 percent wall thickness loss.
25 MR. BARTON: I'm looking at a wall? I'm NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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76 1 not looking at the floor here, I'm looking at a 2 vertical? This is not the floor?
3 MR. GALLAGHER: This is a floor plate. A 4 floor plate.
5 MR. BARTON: A floor plate?
6 MR. DIRADO: Sorry, I used wall thickness 7 interchangeably with metal thickness.
8 MR. BARTON: Okay. I always wonder am I 9 looking at the vertical or am I looking at the floor.
10 MR. DIRADO: The areas where corrosion is 11 visible have experienced coating depletion. The 12 unaffected areas shown still have inorganic zinc 13 coating present which is protecting the liner surface.
14 Slide 23, please.
15 This slide summarizes the enhancements 16 made to the IWE aging management program. These 17 enhancements represent an aggressive aging management 18 plan begun well before the period of extended 19 operation that will maintain coating protection and 20 minimize liner metal loss.
21 First, the plan includes de-sludging the 22 suppression pool floor each refueling outage. This 23 frequent cleaning will minimize the potential 24 corrosion sites.
25 MEMBER SKILLMAN: Mark, does this de-NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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77 1 sludging only vacuum or does it lase, water lase so 2 fresh surface is exposed?
3 MR. DIRADO: It includes vacuuming. As 4 far as water lasing?
5 MR. KELLY: We can ask Mark Marquis of UCC 6 to address that question.
7 MR. MARQUIS: Mark Marquis, Underwater 8 Construction. I'm sorry, could you repeat the 9 question?
10 MEMBER SKILLMAN: Yes. Is the de-sludging 11 a vacuuming process or is it a vacuuming plus a 12 hydrolasing process?
13 MR. MARQUIS: No, the de-sludging process 14 is primarily a de-sludge vacuuming process. I'm 15 sorry.
16 MEMBER SKILLMAN: Thank you. Thanks.
17 MR. DIRADO: Second. An ASME IWE 18 examination is conducted each ISI period which is 19 three times every 10 years. This is for 100 percent 20 of the submerged liner surface. This more frequent 21 exam schedule thoroughly characterizes the material 22 condition of the suppression pool liner.
23 The frequent exams also continue to 24 confirm the expected general corrosion rate expected 25 for the suppression pool water environment as well as NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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78 1 providing opportunities for re-coating.
2 Third, the area re-coats for general 3 corrosion of greater than 25 mils will be performed.
4 General corrosion occurs in the suppression pool at a 5 rate of less than 2 mils per year. The acceptance 6 limit for loss of material due to large area general 7 corrosion is 125 mils metal loss.
8 Re-coating at 25 mils which equates to 10 9 percent wall thickness coupled with a frequent 10 inspection interval of less than 4 years ensures 11 minimal additional liner wall loss.
12 Fourth, spot re-coating of the local areas 13 of general corrosion greater than 50 mils in depth 14 will be performed.
15 MR. BARTON: Let me ask you something.
16 How do you re-coat this stuff?
17 MR. DIRADO: The specific spot re-coatings 18 are performed with a direct application by the divers.
19 The larger area re-coats have a specific methodology 20 and they're usually applied by a roller technique.
21 MR. BARTON: While it's underwater?
22 MR. DIRADO: Yes. Underwater.
23 MR. BARTON: And it adheres?
24 MR. DIRADO: That's correct. And it 25 results in a service level 1 qualified coating.
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79 1 So fourth on this slide, spot re-coating 2 for local areas of general corrosion greater than 50 3 mils in depth will be performed. Pitting corrosion is 4 not expected to occur in the suppression pool water 5 environment.
6 However, even if the localized metal loss 7 rate were hypothetically eight times larger than 8 expected, for example, 16 mils a year, then a 50 mil 9 spot would progress to 114 mils in depth over 4 years, 10 and that is still well below the acceptance limit for 11 general corrosion of 187.5 mils.
12 Fifth, in addition to the action levels 13 for metal loss the plan has provisions to proactively 14 re-coat large areas before significant corrosion 15 occurs. For plates greater than 25 percent coating 16 depletion the affected area will be re-coated.
17 Last, item 6 on the slide --
18 CHAIRMAN SHACK: So we would re-coat that 19 plate we saw in the picture?
20 MR. GALLAGHER: Yes. So, and that's our 21 plan. We think we've hit all the elements to have a 22 good aging management plan and this is the key feature 23 of being proactive. So when we have coating depletion 24 greater than 25 percent in an area we'll -- even 25 though the corrosion would be less than 10 percent, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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80 1 you know, it could be hardly anything we're going to 2 re-coat that area. And that way we'll get ahead of 3 this. And to Mr. Barton's point on, you know --
4 MR. BARTON: I'm still trying to 5 understand this. I've got a corroded spot there. I 6 can dab some zinc on it underwater?
7 MR. GALLAGHER: No, no. It's epoxy. It's 8 an epoxy coating.
9 MR. BARTON: Oh, okay.
10 MR. GALLAGHER: And it's intended for 11 underwater application.
12 MR. BARTON: And I don't have to clean 13 this corrosion at all.
14 MR. GALLAGHER: Well, you have to do some 15 surface prep. You do surface prep and then there's a 16 coating.
17 MR. BARTON: On the epoxy. Okay. All 18 right. Thank you.
19 MR. GALLAGHER: But that -- our intent in 20 this part was to be proactive in getting ahead and not 21 having significant material loss in the lining.
22 MR. DIRADO: Finally, for item 6 on this 23 slide the enhancements were begun in 2012 for Unit 1 24 and will be initiated in 2013 for Unit 2. Early 25 institution of the plan allows seven cycles of coating NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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81 1 maintenance for Unit 1 and nine cycles of coating 2 maintenance for Unit 2 prior to reaching their period 3 of extended operation.
4 MEMBER SKILLMAN: Mark, where is the re-5 coat material successfully used?
6 MR. DIRADO: The re-coat material has been 7 successfully used at other stations. I'd like to ask 8 George Buduck to provide the specific data.
9 MR. BUDUCK: George Buduck, the ISI 10 program owner. Mark Marquis would probably be better 11 to answer that question.
12 MR. DIRADO: Sorry, Mark Marquis.
13 MR. MARQUIS: Mark Marquis, Underwater 14 Construction. The coating material for spot 15 applications has been used at Limerick, Peach Bottom 16 and throughout most of the other Exelon utilities.
17 MEMBER SKILLMAN: Is this a product that's 18 widely used in maritime by the Navy or by the Merchant 19 Marines?
20 MR. MARQUIS: I believe that it is, yes.
21 For use in -- the coating product has been tested and 22 qualified for surface level 1 use as well for 23 underwater application.
24 MR. GALLAGHER: And right now, Mr.
25 Skillman, since we've just started this plan most of NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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82 1 the coating repairs that are done have been spot 2 coating. We have done qualification testing, mockup 3 testing of vertical and horizontal surfaces you know 4 in a mockup, not in the pool itself. Because what we 5 need to do is we need to get that process down 6 efficiently so wider areas can be done underwater.
7 And that's what our program is doing.
8 That being said, you know, we want to make 9 clear that our commitment is very clear. Prior to the 10 period of extended operation we need to meet all this 11 criteria. You know, the areas of greater than 25 mils 12 re-coated, the spots greater than 50 mils re-coated, 13 any areas greater than 25 percent depleted re-coated.
14 So if we can't successfully get it efficiently done 15 underwater we would have to do it in another way, 16 i.e., drain it and do it.
17 And this goes back to Mr. Barton's thing.
18 We're -- at other plants you try this, you do this and 19 at some point you may have to do something else.
20 That's based all on the economics, the outage timing 21 and that type of thing. But our commitment is very 22 clear.
23 MEMBER SKILLMAN: Thank you, Mike. Thank 24 you.
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83 1 been performed to the extent that you were able to 2 establish that when you apply the coating you don't 3 trap water between the coating and the surface of the 4 liner?
5 MR. GALLAGHER: Yes. We actually --
6 MEMBER SIEBER: How did they do that?
7 MR. GALLAGHER: -- just for -- maybe we 8 can just show you a picture we did for the mockup.
9 Let's go to slide number 43.
10 MEMBER SKILLMAN: I think it's a backup.
11 We don't have that.
12 MR. GALLAGHER: Yes, it's a backup. And 13 we'll show you this. This is 43, a vertical plate 14 that was done in a mockup and then look at 44. Can we 15 go to 44, Chris? Did a configuration of floor with 16 various configurations. And you know, so the process 17 is set up to be performed underwater, cleaning the 18 application. You know, it's a multi-coat system 19 that's applied.
20 MEMBER BROWN: Is it sprayed on?
21 MR. GALLAGHER: No, I believe it's rolled 22 on. Mark?
23 MR. MARQUIS: Yes, it's not -- we got away 24 from the roller. It's actually a pad type applicator 25 but it's a power-fit pad applicator. That's correct.
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84 1 MEMBER STETKAR: Mark, before you sit down 2 is there any experience -- I mean, you know, these 3 photographs show that you have some confidence that 4 you can apply it fairly well. Is there any operating 5 experience either from the nuclear fleet and the 6 answer there is probably not yet, but from perhaps 7 maritime applications if it's indeed used in maritime 8 applications to give you confidence that indeed the 9 coating remains intact and is effective for periods 10 like 10 to 15 to 20 years? Is there any evidence to 11 support that?
12 MR. MARQUIS: We've used this particular 13 product in concrete, spent fuel concrete fuel basins 14 at various utilities overseas. And we don't have a 15 15-year period to go by but the last -- we've been 16 back over the last few years, but it's been in service 17 probably 3 or 4 years now with no detrimental effects 18 noted. Still intact.
19 MEMBER STETKAR: Thank you.
20 CHAIRMAN SHACK: But let me understand the 21 commitment. Since you actually haven't demonstrated 22 you can re-coat the plates yet with this process. If 23 it turns out you're unsuccessful your commitment is 24 basically sometime before the PEO to re-coat? Or?
25 MR. GALLAGHER: Yes. If you look at our NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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85 1 commitment it's based on this criteria. We need to 2 meet these criteria, the 25 mils for any areas greater 3 than 25 mils, any spots greater than 50 and any plates 4 with greater than 25 percent loss.
5 If you go to our next slide on the 6 prioritization. Is that the next slide? Yes. So, 7 one of the questions the staff had was about how we 8 would prioritize this. And so this is what we have 9 and we'll go over that with you.
10 But essentially what I was trying to say 11 with the commitment is this would be how we would do 12 this. And as I said we want to do it in scheduled 13 outages because you don't have all the other competing 14 safety issues of draining the suppression pool, 15 offloading the core, that type of thing.
16 But our commitment is clear, we need to 17 meet these areas prior to the period of extended 18 operation and maintain that in the period of extended 19 operation. This is how we will maintain it in the 20 period of extended operation.
21 It basically is we will re-coat these as 22 we go and the proactive plate approach we give 23 ourselves one inspection schedule just for some 24 planning and scheduling. But prior to PEO all those 25 areas need to be re-coated. And so if we can't do it NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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86 1 underwater the way we want to with this, the way we 2 think we can then we would have to take other action, 3 i.e., drain it or you could do it in multiple outages.
4 You could drain it through the walls, you know, drain 5 it through the floor, drain it through the whole 6 thing, whatever.
7 CHAIRMAN SHACK: But that plate we saw 8 then could sort of sit that way until PEO if you 9 couldn't successfully do it underwater.
10 MR. GALLAGHER: That's not our intent.
11 Our intent is if you go back to the data slide on 12 slide 16. So the real areas of concern, the spot re-13 coats are easy and those greater than 50 mils, we're 14 going to do those and that's not a problem.
15 So, the issue is the greater than 25 mils, 16 greater than 10 percent. And there's only 2.6 percent 17 of the area. So we think we can get there definitely 18 in this area. And if you go to the Unit 2 it was only 19 -- go to page 19, or 18. It was only 0.4 percent. So 20 we have those areas identified, we have -- there are 21 just a few plates that are involved and we can go out 22 and get those.
23 So the only areas that we'd be talking 24 about would be the ones for the more proactive 25 approach. There are a number of those areas. In Unit NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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87 1 1, Unit 2 there's not so much. And we think with a 2 stepwise fashion we can get there.
3 And the justification is that there really 4 is no significant degradation on those plates at this 5 point. And but you know, again, we have to meet the 6 criteria going into the period of extended operation.
7 MEMBER STETKAR: Mike, anywhere in your 8 backup slides do you have a graphic that shows the 9 spatial distribution of the areas where you do have 10 greater than 25 mils loss?
11 MR. GALLAGHER: No.
12 MEMBER STETKAR: You know, a picture of 13 vertical, horizontal surfaces that show what they are.
14 MR. GALLAGHER: No, Mr. Stetkar. The only 15 thing I can show you, if we go to page 30, slide 30.
16 This is an overview of the floor plan.
17 MEMBER STETKAR: Yes, that doesn't help 18 much.
19 MR. GALLAGHER: Yes. So this has the 20 plates, you can see the plates there. When we talk 21 plates, those individual rectangles are plates. The 22 -- you can see some of the equipment.
23 The only thing I can tell you is there 24 really isn't much of a pattern but there's two --
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88 1 know, you have small percentages but I was trying to 2 get a feel for area and location.
3 MR. GALLAGHER: Yes. So, there's three --
4 okay, so actually on Unit 1 for the areas greater than 5 25 mils there's actually two wall plates and there's 6 two floor plates. The two floor plates are 4A and 6C.
7 So if we can point to those, Chris. 4A is in the 8 north -- no.
9 MEMBER STETKAR: Northeast corner there 10 someplace.
11 MR. GALLAGHER: No, get back on the --
12 okay.
13 MEMBER STETKAR: I see that one.
14 MR. GALLAGHER: Four alpha and then the 15 other was 6C. Six charlie --
16 MEMBER STETKAR: -- charlie is the 17 southwest corner.
18 MR. GALLAGHER: Southwest corner. Okay.
19 So, there's really no specific pattern or anything but 20 there are the two areas on the floor. And on the wall 21 there's 7B and 6B. They're two areas we would have to 22 address.
23 MR. KELLY: But, and it would not be the 24 entire plate, Mr. Stetkar.
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89 1 trying to get a feel for. Do you have, you know, 200 2 places where you have about 6 square inches that you 3 need to coat or do you have a fairly large area.
4 MR. GALLAGHER: No, for these greater than 5 25 mil there's only these four plates on Unit 1. And 6 then Unit 2 --
7 MEMBER STETKAR: Is less.
8 MR. GALLAGHER: Yes, Unit 2 is -- there's 9 a couple. There's actually four plates also but two 10 of them are very, very small areas.
11 CHAIRMAN SHACK: Okay, we're going to have 12 to finish up here.
13 MR. GALLAGHER: Yes. Okay. If we can go 14 to wrap up here, Mark. So, if we go to page 24 I 15 think we covered this. Dr. Shack, in the interest of 16 time do you want us to move forward quickly?
17 CHAIRMAN SHACK: Move forward.
18 MR. GALLAGHER: Okay. So, if you look on 19 page 24 here this is new information we're going to be 20 supplying the staff on how we'll be implementing the 21 program. And the feature is basically we're -- we 22 have to get some catchup to do on -- particularly on 23 Unit 1 and so we have that prioritized as we have 24 prior to PEO.
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90 1 that we would re-coat these areas of degradation as 2 they occur when they're discovered in the outage and 3 then the proactive coating for the plates would be 4 done within one scheduled period.
5 MEMBER SKILLMAN: Mike, in the context of 6 the slide you identify areas, local corrosion areas, 7 and plates. Should we interpret plate to be the 8 geometric square?
9 MR. GALLAGHER: Yes, the plates where 10 there's rectangles. And we're just saying that --
11 MEMBER SKILLMAN: So each of those is an 12 identified quantity in the map of the suppression 13 pool.
14 MR. GALLAGHER: Right. When we map out 15 the suppression pool we do it by plate so we can say 16 okay, that plate is, you know, X percent depleted of 17 coating.
18 MEMBER STETKAR: So bullet 3 is 19 communicating that if 6A plate has that or greater 20 depletion you're going to fix the whole plate.
21 MR. GALLAGHER: The plate could be 22 entirely re-coated if it was spread out. If it was in 23 a specific area you could just do the specific area.
24 But what we're saying is that plate would have been 25 identified for treatment because it had at least 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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91 1 percent depletion.
2 MEMBER STETKAR: Thank you.
3 MR. GALLAGHER: And again, that depleted 4 area is well less than -- it's less than 10 percent 5 material loss.
6 So we'll just, if we can just step through 7 to the next slide. We just wanted to summarize what 8 the open item resolution was. We had four areas. We 9 think we've covered those in the presentation, a 10 prioritized approach, methods, the exam, our expected 11 corrosion mechanism and our downcomer acceptance 12 criteria.
13 And all this will be -- we have a written 14 open item response which will be sent into the staff 15 next week. Go to the next slide.
16 Mark, if you could just give us our 17 overall summary.
18 MR. DIRADO: Sure. In summary the 19 enhancements to the Limerick IWE aging management 20 program provide reasonable assurance that the aging of 21 the suppression pool liner will be managed 22 appropriately. Limerick has a robust containment 23 design with a metal liner that has 100 percent 24 thickness margin.
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92 1 not conducive to pitting corrosion and water chemistry 2 quality is excellent with respect to minimizing 3 general corrosion.
4 MEMBER POWERS: Your discussion of water 5 chemistry, you focused on inorganic species, chloride 6 and sulfate particularly. Do you characterize the 7 organic content of that water?
8 MR. GALLAGHER: Organic content? Greg, 9 Dr. Powers has a question about organic content of the 10 suppression pool.
11 MR. SPRISSLER: Greg Sprissler from 12 Limerick chemistry. Our analysis was limited to 13 chloride sulfate pH connectivity and TOC analysis. So 14 with TOC we have a general characterization of organic 15 compounds but nothing specific.
16 MEMBER POWERS: And what does your TOC 17 come in at?
18 MR. SPRISSLER: I'm sorry, I can't hear 19 you.
20 MEMBER POWERS: What level of TOC do you 21 have?
22 MR. SPRISSLER: Typically we have less 23 than 50 ppb.
24 MEMBER POWERS: Fifty ppb.
25 MR. SPRISSLER: Parts per billion.
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93 1 MEMBER POWERS: Right. By mass.
2 MR. SPRISSLER: Yes.
3 MEMBER POWERS: And you just don't know 4 what that is.
5 MR. SPRISSLER: That is correct.
6 MEMBER POWERS: Okay.
7 MR. DIRADO: Our low corrosion rate has 8 been confirmed. Exelon is committed to an aggressive 9 aging management program begun well in advance of the 10 period of extended operation which will ensure that 11 the intended function of the suppression pool liners 12 are maintained throughout the period of extended 13 operation.
14 I'll now turn the presentation over to 15 Mike Gallagher for closing remarks.
16 MR. GALLAGHER: Okay, thanks Mark. So in 17 conclusion we've developed a comprehensive, high-18 quality License Renewal Application and a robust aging 19 management program that will ensure the continued safe 20 operation of Limerick. Pending any questions that 21 ends our presentation.
22 CHAIRMAN SHACK: Any further questions 23 from the subcommittee?
24 MEMBER POWERS: Just a reminder, the water 25 volume in your suppression pool?
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94 1 MR. GALLAGHER: Water volume, I think it's 2 about 1 million gallons.
3 MEMBER POWERS: 1.2 million?
4 MR. GALLAGHER: Dave Clohecy?
5 MR. CLOHECY: My name is Dave Clohecy and 6 I'm a member of the Exelon license renewal team. The 7 water volume in the suppression pool is approximately 8 1 million gallons.
9 CHAIRMAN SHACK: Thank you very much for 10 an excellent presentation. We'll take a break now 11 until 10:35. Then we'll hear from the staff.
12 (Whereupon, the foregoing matter went off 13 the record at 10:19 a.m. and went back on the record 14 at 10:35 a.m.)
15 CHAIRMAN SHACK: If we can come back into 16 session Melanie Galloway will start us off again.
17 MS. GALLOWAY: Okay. Thank you, Dr.
18 Shack. I've already introduced Patrick Milano. He's 19 the Limerick project manager for the last month.
20 Previous to his assignment as the project manager Rob 21 Kuntz who is sitting here at the computer was the 22 project manager who led and coordinated the project 23 through the initial application. So he's here to 24 assist as well.
25 Pat is going to be giving the whole NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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95 1 presentation today since there are only two open 2 items, but there are support staff at the front table 3 that I'd like to go ahead and introduce. To the far 4 end of the panel there without a name tag is Dr. Allen 5 Hiser who's our senior-level advisor on materials and 6 degradation in the division. Abdul Sheikh is a senior 7 structural engineer with responsibility for the open 8 item on the suppression pool liner. Michael Modes is 9 from Region I and had the lead for the inspection, and 10 we'll talk about that in the presentation today. And 11 Matt Homiack is our mechanical engineer with 12 responsibility for our operating experience program 13 and the open item at Limerick.
14 We have attempted to streamline our 15 program today, taking account for the background 16 information that was already included in the 17 applicant's presentation, so hopefully that will 18 facilitate efficient review. We're going to focus on 19 the areas that are unique to our review of the 20 application and provide our characterization of the 21 open items.
22 We are expecting written responses from 23 the applicant on the open item so we are in the middle 24 of the review. We are not in a position at this point 25 in time because of that status of review to indicate NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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96 1 a clear path forward on the open items. And you will 2 get a sense of that from our presentation.
3 Before we get into our formal presentation 4 I'd like to ask Bill Holston who is a senior 5 mechanical engineer in the division to respond to Mr.
6 Stetkar's question earlier about the internal 7 inspection program of large-bore piping and 8 consistency with the GALL. Bill?
9 MR. HOLSTON: Good afternoon. My response 10 to that, or I understand the question to be how the 11 applicant will be age-managing the internal surfaces 12 of the surface water piping that is buried. And we 13 worked with the applicant throughout the application 14 and what they have committed to do is to take 10 15 locations every 2 years in aboveground service water 16 piping and conduct ultrasonic examinations of that 17 piping to detect any corrosion.
18 And that piping select -- the selection of 19 those locations will be based upon similar flow rates 20 as buried piping. And given that they have similar 21 environments, internal environments between the 22 service water piping that's buried and the aboveground 23 service water piping, we believe that sufficiently 24 examines the internals for both.
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97 1 said volumetric examinations?
2 MR. HOLSTON: Yes sir, volumetric 3 examinations.
4 MEMBER STETKAR: Okay. From the ID or the 5 OD?
6 MR. HOLSTON: From the outside diameter.
7 MEMBER STETKAR: Okay. At least I know 8 what they're going to do. And you feel that's 9 consistent with the intent of GALL?
10 MR. HOLSTON: Yes, sir. The internal 11 surfaces would be managed by -- you would manage them 12 by AMP 11 M38 which is the internal inspection program 13 which is an opportunistic program. So in this case 14 rather than just simply going with opportunistic 15 inspections the licensee committed to do, you know, 16 guaranteed periodic inspections and 10 every 2 years 17 will very fairly represent what we expect to see as 18 age-managing in those internal surfaces of that 19 piping.
20 MEMBER STETKAR: I guess I was looking at 21 M41 under buried piping which seems to give you an 22 indication that if you've had experience with leaks it 23 says opportunistic examinations of non-leaking piping 24 may be credited.
25 MR. HOLSTON: Well -- oh, I'm sorry.
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98 1 MEMBER STETKAR: I don't know what you 2 define as a leak. I mean, you know, they've had 3 evidence of problems with their service water piping.
4 MR. BARTON: But that has to do with 5 buried piping when you go down and actually look at 6 it, right? And they're talking about a surface 7 program.
8 MEMBER STETKAR: Well, this is for 9 internals.
10 MR. BARTON: Right, right. Oh, okay.
11 MEMBER STETKAR: The internal examinations 12 of buried piping.
13 MR. HOLSTON: M41 deals with external 14 examination of piping only. There is no internal 15 surface examinations in M41. The internal surface 16 examinations for this piping would be under 11 M38.
17 MEMBER STETKAR: Section -- footnote 10 18 capital letter B. At least 25 percent of the code 19 class safety-related or haz mat piping are both 20 constructed from the material under construction is 21 internally inspected by a method capable of precisely 22 determining pipe wall thickness. That's in M41 under 23 buried piping.
24 MR. HOLSTON: That's an alternative to if 25 you do not want to do direct, you know, excavated NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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99 1 direct visual examinations of the external surfaces 2 you can substitute looking at 25 percent of the length 3 with the volumetric method. That's the intent of AMP 4 M41.
5 MEMBER STETKAR: Okay. I'll have to think 6 about that because -- okay. I don't want to take up 7 too much time because we have a lot of discussion on 8 the suppression pools. Thank you.
9 MS. GALLOWAY: Thank you. Patrick?
10 MR. MILANO: Okay. Good morning, Dr.
11 Shack and members of the subcommittee. I and the 12 members of the NRR and Region I staffs are here to 13 discuss the Limerick License Renewal Application as 14 indicated here documented in the Safety Evaluation 15 Report with open items that we issued in July of 2012.
16 In addition to the members up here at the 17 table we also have staff who also participated in 18 technical review and in the audits that were conducted 19 at the plant that are here in case questions arise.
20 Next slide, please.
21 This slide just predicts the general 22 outline of the areas that were going to be covered in 23 today's presentation and coincides with the --
24 specifically with the SER itself. Next slide.
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100 1 information. Everything on it was -- all the points 2 that are being made on this slide were covered in the 3 licensee's presentation. Next slide.
4 The staff conducted audits and inspections 5 of the application during periods as shown on this 6 slide. The purpose of the scoping and screening 7 methodology audit was to review the applicant's 8 administrative controls governing implementation of 9 the scoping and screening methodology and the 10 technical basis for selected scoping and screening 11 results for various plant systems, structures and 12 components, SSCs.
13 The audit also reviewed selected examples 14 of component material and environmental combinations.
15 Information contained in the applicant's corrective 16 action database relevant to plant-specific age-related 17 degradation. Quality practices applied during the 18 development of the application and the training of 19 personnel who participated in the -- also in the 20 development of the application.
21 The purpose of this aging management 22 program (AMP) audit was to examine Exelon's aging 23 management programs and related documentation to 24 verify that the applicant's claim of consistency with 25 the corresponding AMPs in the Generic Aging Lessons NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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101 1 Learned (GALL) report were indeed correct.
2 As described in the GALL report the staff 3 based its evaluation on the adequacy of each AMP on 4 its review of 7 of the 10 AMP program elements. The 5 other three program elements were audited during the 6 scoping and screening methodology audit.
7 As Exelon indicated the staff reviewed 45 8 AMPs and documented the results in a report on 9 February 28th of this year. If the applicant took 10 credit for the program in the GALL report the staff 11 verified that the plant program contained all the 12 elements of the referenced GALL report program. In 13 addition, the staff verified the conditions at the 14 plant were bounded by the conditions -- excuse me, by 15 the conditions for which the GALL report program was 16 evaluated.
17 Of note, the applicant initially indicated 18 that all of its programs were consistent with the GALL 19 report. However, during the staff's AMP audit the 20 staff found AMPs where the applicant was taking an 21 exception and which should have been so stated in the 22 application. In response to questions from the staff 23 the applicant modified its description, thus resolving 24 the noted gap.
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102 1 situation that I'm referring to here. The monitoring 2 and trending program element in GALL report AMP II M24 3 recommends that daily readings of system dew point be 4 recorded and trended. However, during its audit the 5 staff found that the applicant's program basis 6 document for the compressed air monitoring program 7 states that the instrument air system dew point is 8 continuously monitored and alarmed, inspected weekly 9 and recorded quarterly. So it's just a, it was a 10 matter of a difference in the way it was presented 11 vice the way it was indicated actually in the field.
12 And however we found this to be acceptable.
13 In addition, Region I conducted a regional 14 inspection during the period from June 4th through the 15 21st of this year. Those inspection results will be 16 presented shortly.
17 And lastly, the staff conducted an 18 environmental review audit in support of the 19 preparation of the Environmental Impact Statement 20 which we are not going to be discussing anything 21 environmental today.
22 MEMBER SKILLMAN: Pat, before you proceed 23 onto slide 6.
24 MR. MILANO: Yes.
25 MEMBER SKILLMAN: Your first bullet, that NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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103 1 scoping and screening methodology audit.
2 MR. MILANO: Yes.
3 MEMBER SKILLMAN: I think perhaps my 4 question is more appropriately directed at Bob Kuntz.
5 Four systems were chosen: essential service water, 6 fuel pool cooling and cleanup, emergency diesel 7 generator system and fuel transfer and air start 8 subsystems. What is the basis for selecting only 9 those four?
10 MR. MILANO: The basis for it is they were 11 representative of it and also based on previous 12 experience that the staff has with conducting other 13 audits, especially in Region I wherein this is the 14 last plant that is being inspected for license 15 renewal, for initial license renewal. And it's just 16 plant experience and these seem to be reasonable to --
17 reasonable samples in relationship to the total 18 population. I don't know if, Rob, can you answer?
19 MEMBER SKILLMAN: Are these the same four 20 that have been chosen at other plants in Region I that 21 are applying for license extensions?
22 MS. GALLOWAY: We don't have the answer to 23 that. Our scoping lead is on vacation this week so we 24 can get back to you on that question, Mr. Skillman.
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104 1 these four. Why not six or seven? Or why two 2 different from these? What is the basis for these 3 four, please?
4 MS. GALLOWAY: Sure. We'll get back to 5 you. Thank you.
6 MEMBER SKILLMAN: Thank you.
7 MR. MILANO: Slide 6, please. In addition 8 to the audits and inspections that I've already 9 mentioned the staff conducted in-depth technical 10 reviews and issued 150 questions initially and about 11 200 questions overall as requests for additional 12 information while preparing the overall Safety 13 Evaluation Report. Slide 7.
14 Section 2 of the SER describes structures 15 and components subject to aging management review. As 16 you're well aware Section 54.21 of Part 54 requires 17 the applicant to identify SSCs within the scope of 18 license renewal and additionally to prepare an 19 integrated plan assessment which identifies and lists 20 those structures and components which are identified 21 to be within the scope of license renewal that are 22 subject to an aging management review.
23 Based on the staff's review of the 24 applicant's detailed scoping and screening 25 implementing procedures, discussions with the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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105 1 applicant's license renewal personnel, review of 2 quality controls applied to the development of the 3 application and the training of personnel 4 participating in that development, and the results of 5 the scoping and screening methodology audit, and 6 additional information from the RAIs the staff 7 concluded that the applicant's scoping and screening 8 program was consistent with the staff's Standard 9 Review Plan for license renewal and the requirements 10 of Part 54 of the regulations.
11 The staff then reviewed the summary of the 12 identified safety-related SSCs which are those relied 13 upon to remain functional during and following a 14 design basis event as well as all non-safety related 15 SSCs whose failure could prevent satisfactory 16 accomplishment of any of the design basis functions.
17 Also, all SSCs relied on in safety 18 analysis to perform a function that demonstrates 19 compliance with the Commission's regulations for fire 20 protection, environmental qualification, anticipated 21 transit without scram (ATWS) and station blackout were 22 identified. The staff found that the applicant's 23 implementation in this area was consistent with both 24 the SRP and applicable regulations.
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106 1 slide I'll now turn over the presentation to Mr.
2 Michael Modes, the Region I lead inspector who will 3 discuss the license renewal inspection itself.
4 MR. MODES: Thank you gentlemen, it's 5 always a pleasure to be here. As an overview this 6 particular inspection took six inspectors over 3 7 weeks. You would probably note that's a pretty high 8 level of inspectors spread out over a longer period of 9 time. The only reason that occurred was we had a lot 10 of exigent serious issues that the region was dealing 11 with at the time at other plants and so Limerick staff 12 and Exelon were very kind in allowing us to spread out 13 the number of inspectors over a longer period. They 14 kept support staff available to get the job done so 15 that these inspectors could go on to these other 16 facilities.
17 As usual we did the A2 inspection looking 18 for those three-dimensional relationships. And we did 19 32 of 45 aging management programs were reviewed in 20 total over that period of time. Next slide.
21 Because of the number of inspectors that 22 went through over a longer period of time we did a lot 23 of walkdowns even though it was beastly hot at the 24 time. And this is just a partial list of the systems 25 that were walked down. An extensive amount of NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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107 1 walkdown and I took a pretty long tour of the facility 2 in order to answer the material question -- pretty 3 good.
4 MR. BARTON: Thank you, I didn't have to 5 ask that this time.
6 MR. MODES: Yes, well, after 13 years --
7 MR. BARTON: You guys are getting ready, 8 all right.
9 MR. MODES: Right, I give up. Thirteen 10 years. Besides, this is the last time through, so.
11 (Laughter) 12 MR. MODES: Next slide. And what we 13 concluded was that the scoping of non-safety SSCs and 14 the application of the AMPs to those were acceptable.
15 And the inspection results support a conclusion that 16 reasonable assurance exists, that aging effects will 17 be managed and intended functions maintained. Last 18 slide.
19 Just wanted to note how long it has taken 20 us in Region I to get through all of them. I've had 21 the pleasure of inspecting every single one of these 22 since June of `98. And it is the last slide, 23 gentlemen, I will ever present to you.
24 (Laughter) 25 MEMBER SKILLMAN: So Michael, when you say NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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108 1 material condition -- pretty good it's against that 2 lens right there?
3 MR. MODES: Yes. Well, actually no.
4 Prior to this endeavor I used to run the NDE mobile 5 laboratory and I have had the pleasure of visiting 64 6 facilities. Prior to that I used to do NDE in general 7 so it's a benchmark of probably the entire fleet.
8 MEMBER SKILLMAN: Thank you.
9 MR. MILANO: Okay, thanks Mike. Now 10 moving onto Section 3 of the SER. Section 3 covers 11 the staff's review of the applicant's aging management 12 programs and the aging management review line items in 13 each of the systems within scope and reviewed against 14 the SRP and recommendations in the GALL report.
15 In its Table 2 of the application the 16 applicant provided information concerning whether or 17 not the AMRs, the aging management reviews, identified 18 by the applicant aligned with the GALL report AMRs.
19 For a given AMR in Table 2 the staff reviewed the 20 intended function, the material, environment, aging 21 management -- aging effect requiring management and 22 the AMP combination for the particular system 23 component type.
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109 1 appropriate correlation in the GALL report. The staff 2 also conducted a technical review of combinations not 3 consistent with the GALL report.
4 For component groups evaluated in GALL for 5 which the applicant claimed consistency and for which 6 it does not recommend further evaluation the staff's 7 review determined whether the plant-specific 8 components were indeed bounded by the GALL report 9 evaluation. If an AMR did not align with the GALL 10 report the staff conducted a technical review to 11 ensure adequacy and issued a request for additional 12 information as necessary.
13 Based on its review of the application, 14 the implementing procedures and a sampling of 15 screening results the staff concluded that the 16 applicant's screening methodology was indeed 17 consistent with the Standard Review Plan guidance.
18 Next slide.
19 As both Mike and I and others have 20 indicated there were 45 aging management programs 21 presented in the application. I do want to make one 22 special note of the fact that there were no plant-23 specific aging management programs. Next slide.
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110 1 storage tanks. And I may have just missed this so 2 perhaps it's quick. There was an issue about their 3 large diesel fuel oil storage tanks and the fact that 4 they take samples from that tank 11 inches off the 5 bottom. And you basically accepted that.
6 Are they going to do a volumetric 7 examination of the bottom of that tank at any time?
8 I see commitments to do volumetric examinations of 9 little bay tanks here and there, but that's not the 10 big storage tank. I'm concerned about 10 and a half 11 inches of stuff laying on the bottom of that tank that 12 nobody knows about.
13 MR. MILANO: There was some discussion in 14 both the application and in the SER in that area. I 15 think best if I turn it over to Mr. Gallagher and he 16 can -- he and his staff.
17 MEMBER STETKAR: Okay. I didn't ask them 18 in the sense of time but.
19 MR. GALLAGHER: Yes, we can answer that 20 question. I'm going to have Mark Miller of our 21 project team answer that question.
22 MR. MILLER: Mark Miller, Exelon license 23 renewal. The main diesel oil fuel oil storage tanks 24 are drained clean and inspected every 10 years. And 25 should there be evidence of corrosion visually then we NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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111 1 would be performing a UT.
2 MEMBER STETKAR: Okay, thank you. I 3 missed that.
4 MEMBER SIEBER: Well, the other issue is 5 sludge and water. Water settles to the bottom and 6 that's why the line does not go all the way to the 7 bottom, plus all the sludge lays there. And usually 8 there are samples taken periodically at the level 9 below the level of the section line to determine how 10 much sludge and how much water is there. Is that 11 periodically done?
12 MR. MILLER: Mark Miller, Exelon license 13 renewal. The only sampling that we do on that tank is 14 11 inches off of the bottom of the tank. There's no 15 physical connection. However, we do test for water by 16 dropping down -- and I forget exactly what the term 17 is, but it's material of some sort that detects the 18 presence of water and that is dropped down to 19 determine whether there is water sitting on the 20 bottom.
21 MR. GALLAGHER: And I think Greg Sprissler 22 of our chemistry department has something to add too.
23 MR. SPRISSLER: Greg Sprissler from the 24 chemistry department. The tanks are pitched and at 25 the bottom of the pitch is a low level sump.
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112 1 Periodically the tanks are dewatered. So at that 2 point there would be visual indication of any 3 indication of sludge.
4 MEMBER STETKAR: There is a low point 5 drain?
6 MR. SPRISSLER: Not a drain, a sump.
7 MEMBER STETKAR: Inside the tank itself?
8 MR. SPRISSLER: Yes. Operations 9 periodically does checks for water content in the fuel 10 and they pump out from the low-level sump.
11 MEMBER STETKAR: But -- so they can 12 actually, someone can actually take a suction from 13 that low point.
14 MR. SPRISSLER: They have a device that 15 they use to do that.
16 MR. GALLAGHER: Basically suck the, you 17 know, vacuum out that little volume.
18 MEMBER STETKAR: Okay. Well, why can't 19 you then take credit for that for accumulation of, you 20 know, corrosion sediment and everything else that 21 might collect in that tank?
22 MR. GALLAGHER: I guess our periodicity 23 wasn't in agreement with the GALL so we came up with 24 what would be in agreement with the GALL and then this 25 is extra that we do.
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113 1 MEMBER STETKAR: Well, the GALL seems to 2 say that you're supposed to take a sample from the 3 lowest point in the tank if I read the GALL --
4 MR. GALLAGHER: Right.
5 MEMBER STETKAR: -- which this would do.
6 MR. HISER: This is Allen Hiser of the 7 staff. This is one of the areas that I looked at 8 during the audit and we verified through drawings that 9 they do have an area where the sludge and things would 10 collect.
11 MEMBER STETKAR: But they're not -- and 12 you're okay with them not taking periodic samples from 13 that area as a commitment?
14 MR. HISER: Yes. That was something that 15 we found to be acceptable because they would be able 16 to remove materials down there that, you know, water 17 and things.
18 MEMBER STETKAR: I'm sorry but they're not 19 committing to do that. They are not committing to do 20 that. I would think it would be acceptable, for 21 example, to take a suction, a sample from down there 22 but they're not -- in particular they're not 23 committing to do that.
24 MR. HISER: They -- I don't remember 25 specifically whether there is a commitment but in NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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114 1 terms of their draining, cleaning and inspecting the 2 tank that was the main focus of the program.
3 MEMBER STETKAR: Okay. I don't -- Bill, 4 I don't want to take up too much more time because we 5 have a time constraint here.
6 MEMBER SIEBER: Well, I would like to ask 7 you say that you take a sample out of the sump area 8 periodically. What's periodically? What frequency?
9 MR. SPRISSLER: Once again Greg Sprissler 10 from Limerick chemistry. I am actually not sure of 11 the periodicity. My best estimate would be quarterly.
12 That is an estimate.
13 MR. GALLAGHER: Yes, and I guess, you 14 know, the reason we didn't -- that that wasn't the 15 fulfilling our commitment consistent with the GALL is 16 that that particular thing is fairly intrusive. You 17 have to go down into the vault, remove the lid on the 18 tank and that type of thing.
19 So the sampling we thought was sufficient 20 to, you know, because we do the pre-loading of the 21 fuel sampling, we do the frequent sampling. And we 22 thought that that was more consistent with the GALL.
23 And this other activity we do is a good practice that 24 we have.
25 MEMBER SIEBER: Thank you.
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115 1 MR. MILANO: Go on now to slide 14. The 2 NRC characterized the issues regarding this, the open 3 item that's presented on this page into three parts as 4 noted on the slide. Because the applicant has covered 5 the specific technical information on the slide I'm 6 not going to repeat this.
7 Also, the applicant proposed this AMP to 8 manage the aging of the suppression pool liner and 9 downcomers for a loss of material from corrosion and 10 to preserve the leak tightness barrier.
11 The applicant in part stated that the AMP 12 addresses the inspection of primary containment 13 components exposed to an uncontrolled indoor air and 14 treated water environments. In addition, the program 15 basis document states that the Section 11 IWE program 16 is an existing AMP that will be enhanced to manage the 17 suppression pool liner and coating system as you heard 18 from the licensee previously. Next slide, please.
19 As just stated the applicant proposed an 20 enhancement of its existing IWE program to manage the 21 aging effects in the suppression pool liner and 22 coating system. In an enhancement to the detection of 23 aging effects program element the applicant stated 24 that prior to the period of extended operation the AMP 25 will include more frequent inspections and selected NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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116 1 and phased re-coating of the corroded areas of the 2 suppression pool.
3 The applicant has described the specific 4 attributes in this enhancement as noted on this slide.
5 I provide them now, however, just as a reference in 6 case we need to go back to them. Next slide, please.
7 In the SER the overall open item was, like 8 I said, it was expressed in three parts. The staff 9 will only address the first two parts as indicated in 10 this slide because the third part dealing with the 11 downcomer corrosion appears to be on a path to 12 resolution.
13 Regarding the remaining two parts the 14 staff seeks additional information from the applicant 15 about the corrosion mechanisms affecting the 16 suppression pool liner and the criteria and supporting 17 basis in the program for coating degradation. As you 18 heard earlier the applicant has been managing the 19 degradation of the liner rather than maintaining the 20 coating system.
21 The staff is aware that the Limerick 22 suppression pool liners have been subjected to both 23 general and pitting corrosion or localized corrosion 24 as the applicant indicated. The staff has come to 25 this conclusion from the results of inspections NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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117 1 discussed in the applicant's assessment report of the 2 liner degradation. Thus the staff lacks sufficient 3 information from the applicant to conclude that 4 pitting corrosion is not a degradation in the liner.
5 Because of the operating history of 6 pitting corrosion in the Limerick liners the enhanced 7 AMP should fully account for pitting corrosion. This 8 is important because operating experience has shown 9 that pitting corrosion rates are higher, usually 2 to 10 10 times higher than general corrosion rates, are not 11 as predictable and could result in a leak in the liner 12 over time.
13 The staff is also concerned that the 14 applicant's methods and technique for measuring the 15 amount of liner material lost to corrosion may not be 16 an effective means to determine the remaining 17 thickness of the liner. The applicant uses depth 18 gauges to measure loss of material due to general and 19 pitting corrosion.
20 This may not be appropriate in all areas 21 experiencing general corrosion some of which has 22 exhibited up to 35 mils of general corrosion adjacent 23 to the pits. It's unclear to the staff how the 24 reference datum of the original thickness of the liner 25 will be considered in monitoring the total material NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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118 1 loss in the inspected areas.
2 Moving onto the --
3 MEMBER SKILLMAN: Before you change 4 slides, this is a pure curiosity question. Is there 5 any correlation between the operability of the 6 cathodic protection system on this plant, both units, 7 and the pitting and degradation of the liner? Has 8 anyone pulled that thread?
9 MR. SHEIKH: I'm not aware of this issue.
10 MEMBER SKILLMAN: Does anybody know what 11 the operating history is of the cathodic protection 12 system for Limerick?
13 MR. SHEIKH: Bill Holston might.
14 MR. HOLSTON: My name's Bill Holston, 15 staff with the Division of License Renewal. They have 16 an operational cathodic protection system. It 17 protects the buried piping but I am not aware that it 18 protects the surfaces you're discussing there.
19 MEMBER SKILLMAN: I'd be curious whether 20 that's a design consideration. In my consulting 21 independent from this I've been on plants where the 22 cathodic protection system was not functional, was 23 hooked up backwards, was connected to some components 24 and not others, was not grounded properly and it 25 turned out the cathodic protection system was part of NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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119 1 the problem rather than part of the resolution of the 2 problem. So I'm just wondering if when you ask 3 questions about not knowing why the rates are what 4 they are if perhaps there is another mechanism that's 5 fairly simply discovered that hasn't been touched upon 6 yet.
7 MR. SHEIKH: I can only add to this that 8 this kind of pitting has been observed at other BWR 9 plants, suppression pools. And the pitting is in the 10 same kind of ranges. We are aware, at least I am 11 aware of Cooper Plant and Duane Arnold Plant where the 12 pitting was in that kind of range.
13 MS. GALLOWAY: Abdul, when you speak could 14 you be closer to the microphone so we can all hear 15 you? Thank you.
16 MR. SHEIKH: I repeat that the pitting 17 which has been observed here in Limerick is similar to 18 other plants which, you know, like Cooper and Duane 19 Arnold where they were pitting in the suppression pool 20 of similar magnitude.
21 MEMBER SKILLMAN: I understand your 22 answer. I would like to put on the record the 23 question and ask for a response is there a correlation 24 between operability of cathodic protection and what 25 you're seeing on the corrosion of the liner.
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120 1 MR. HISER: Are you speaking specifically 2 of the buried pipe cathodic protection program? Or 3 are you speaking of any stray occurrence that could?
4 MEMBER SKILLMAN: Well, generally the 5 cathodic protection system covers more than just the 6 buried pipe. It's condenser, buried piping, however 7 the plant is grounded. And unless it's connected 8 properly you can have portions of the plant that have 9 electrical potentials that are driving degradation.
10 So that is the general basis of my question, is there 11 a correlation here. Thank you.
12 MR. MILANO: We'll take that down and 13 we'll provide an answer back to you.
14 MEMBER SKILLMAN: Thank you.
15 MR. MILANO: Okay, continuing on with this 16 slide onto the second part. On coating degradation 17 the staff notes that the application has three 18 criteria as you've heard before the results of which 19 will be used to initiate implementation of the coating 20 maintenance plan. The staff is unclear as to the 21 technical basis for using the 25 percent loss of 22 coated area as a criterion in the enhancement.
23 Second, it's unclear to the staff how the 24 liner plates that have experienced a coating loss to 25 date some of which is exceeding 25 percent and up to NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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121 1 72 percent of a specific plate surface area will be 2 prioritized and corrected in a phased approach as the 3 applicant has indicated prior to the start of the 4 period of extended operation.
5 This cold mean that areas with up to 24 6 percent of the coated area degraded could possibly not 7 be re-coated even at the start of the period of 8 extended operation in 2024 for Unit 1.
9 You know, today we heard some additional 10 information for the first time being presented in this 11 area to help clarify what Exelon meant by its phased 12 approach. And the staff will be looking forward to 13 Exelon's submission of its response to the open items 14 as they indicated next week.
15 I would state of note that the applicant 16 has classified the suppression pool liner coating as 17 service level 1 because of the potential for coating 18 failure to adversely affect the post-accident fluid 19 systems.
20 And also the suppression pools were 21 initially filled in the nineteen eighties and in the 22 nineteen nineties the applicant determined that the 23 coating was beyond its projected service life. And as 24 Mr. Barton indicated my recollection is reading that 25 the projected service life was determined to be 12 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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122 1 years.
2 The staff also wishes to note that in its 3 SER it indicated that recent industry operating 4 experience as described in the NRC's Information 5 Notice 2011-15 titled "Steel Containment Degradation 6 and Associated License Renewal Aging Management 7 Issues."
8 This information notice provides 9 information of the type of situations such as showing 10 that zinc coatings have a limited lifetime and may not 11 be effective during the period of extended operation 12 if not reapplied.
13 MEMBER POWERS: When they make these 14 lifetime projections what's changing? What's being 15 lost from the coating that means it won't perform its 16 function?
17 MR. MILANO: Well, it is a sacrificial 18 coating and that's what the -- that's in terms of 19 setting up its, you know, the galvanic relationships 20 and stuff the zinc is expected to oxidize first and 21 sacrifice itself to save the base metal. I don't know 22 if Mr. Hiser wants to say anything more?
23 MR. HISER: No, that's exactly right.
24 MEMBER POWERS: So you would -- when they 25 make the projection they're saying okay, we've NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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123 1 depleted all the zinc here, it's all been turned into 2 zinc oxide or zinc carbonate.
3 MR. HISER: I would assume that's the kind 4 of calculation. I don't think we've reviewed the 5 calcs and I wouldn't want to speak to what the vendor 6 has done.
7 MEMBER POWERS: So if somebody comes in 8 and says well, yes, my zinc's still here he's okay 9 then?
10 MR. HISER: Well, I think the qualified 11 life like that depend on certain conditions, and if 12 the conditions in the field are different, maybe less 13 severe, then presumably the lifetime could be 14 extended.
15 MEMBER POWERS: Yes, I mean if I'm 16 marketing the zinc I'm going to say okay, what's the 17 most severe thing they're going to have here and 18 that's how I'm going to do my calculations. In 19 reality it's something more mild like that's the guy 20 who comes in and says well, you know, my zinc is still 21 here. I mean, that's pretty easy to check. If it was 22 the hydroxyl bonding to the steel and de-adhesion 23 that's a much harder thing to check.
24 MR. HISER: Yes, I think in this case the 25 discussion that we've had of the qualified life is NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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124 1 really not to say anything bad about what the plant 2 condition is but just the fact that for a 40-year 3 initial lifetime there's no surprise that the coating 4 is no longer intact in many places because it really 5 wasn't designed to be there still.
6 MEMBER POWERS: Well, I think what I'm 7 driving at is that when we have these limited lifetime 8 components there's some projection of how long it's 9 going to last. Here's one where even if that 10 projection is a very accurate one it is, as you 11 accurately pointed out, based on some estimate of what 12 conditions, what the service conditions are. Those 13 are not the real service conditions. So the fact that 14 its lifetime, projected lifetime has been exceeded 15 doesn't mean anything if it's still functional.
16 Because we know what makes it non-functional.
17 MR. HISER: And in the case of the coating 18 like this it makes evident.
19 MEMBER POWERS: Yes, I mean --
20 MR. HISER: It's evident whether it's 21 there --
22 MEMBER POWERS: It's fairly evident.
23 MR. HISER: -- and functional or not.
24 MEMBER POWERS: And it's not catastrophic.
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125 1 corrode all the way through the liner? I don't think 2 so.
3 MR. HISER: I don't think so either but I 4 think that's one of the concerns that we have, 5 comparing the general corrosion with the -- whether 6 you want to call it pitting corrosion or corrosion 7 that results in pits in the liner I think the concern 8 we have is there's some very deep pits. And whether 9 that behavior could be replicated in other portions of 10 the liner is really the concern that we have on the 11 re-coating side effects.
12 MR. MILANO: Okay. Barring any further 13 questions I'll go to the next slide which is the 14 second open item that the staff has.
15 MEMBER BROWN: Can you back up?
16 MR. MILANO: Yes.
17 MEMBER BROWN: Just something I didn't 18 understand from what they said during the re-coating, 19 applying the re-coating. The zinc is part of the 20 coating, right?
21 MR. MILANO: The original coating.
22 MEMBER BROWN: The original coating.
23 MR. MILANO: Yes.
24 MEMBER BROWN: When they said they re-25 coated they re-coated with an epoxy. Has that also NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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126 1 got new zinc? I mean, is that zinc compound or 2 whatever it is?
3 MR. MILANO: No.
4 MEMBER BROWN: So there is no renewal then 5 of whatever zinc was lost in that coating area.
6 MR. HISER: No, it's a different approach, 7 it's a barrier approach as opposed to --
8 MEMBER BROWN: A sacrificial approach.
9 Okay, thank you.
10 MR. HISER: But then that coating as well 11 will have a certain qualified life to it.
12 MEMBER BROWN: I understand. I didn't 13 hear anything on that, on the new re-coating. When 14 they go back and re-inspect subsequently in other 15 outages or whatever they do on their spot inspections 16 do you re-inspect the epoxy-coated parts different 17 than you do --
18 MR. HISER: Well, my understanding is --
19 MEMBER BROWN: -- different criteria or 20 what do they do?
21 MR. BARTON: You look for blisters and 22 stuff in the epoxy.
23 MR. HISER: If they have a service level 24 1 coating that would be something that they would 25 maintain. So they would have an inspection program I NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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127 1 believe as a part of their IWE program.
2 MEMBER BROWN: Sort of slow -- I'm an 3 electrical guy so you've gone way over my head.
4 MR. HISER: But the coating --
5 MEMBER BROWN: What does that mean, a 6 service level 1? You mean it's supposed to last 7 forever or?
8 MR. HISER: No, it has certain 9 requirements associated with it in terms of 10 inspection.
11 MEMBER BROWN: But I'm looking for the 12 difference between the epoxy re-inspections. If 13 you've mapped those is there something different you 14 do when you re-inspect periodically relative to those 15 areas you've already re-coated relative to the ones 16 you do for zinc? Is there some different process?
17 MR. BARTON: You'd look for different 18 things with an epoxy coating than you would for the 19 zinc.
20 MR. HISER: The epoxy coating would have 21 its own specific criteria from acceptance by 22 inspection. So areas that have been re-coated would 23 require certain inspections, techniques, frequency, 24 acceptance criteria, et cetera. They would be 25 different from the zinc coating because they have NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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128 1 different functions and therefore different 2 requirements.
3 MEMBER BROWN: I understand they're 4 different. Okay.
5 MR. MILANO: Well indeed, in the 6 application itself they have, the applicant did 7 indicate that any areas where they observed flaws and 8 they've re-coated either for that or because the re-9 coating was done because they've exceeded, you know, 10 let's say one of those 25 percent area issues and 11 they've re-coated the whole plate that they have 12 committed to do a follow-on inspection during the next 13 refueling outage of that plate surface area.
14 MEMBER BROWN: So areas that were re-15 coated with the epoxy have a -- okay. So roughly 2 16 years later then you're saying that they would re-look 17 at that during their next outage.
18 MR. MILANO: That's correct.
19 MEMBER BROWN: And they've committed to 20 that.
21 MR. MILANO: Yes, they have.
22 MR. HISER: I don't know that it's 2 23 years. I mean again --
24 MEMBER BROWN: Well, they said refueling 25 outage. I thought they said 2 years during the break.
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129 1 MR. GALLAGHER: Just as a clarification.
2 So, we inspect three times every 10 years. And so 3 that's done, that's the interval. And so when you do 4 the inspection you inspect the entire submerged area.
5 So whether there's zinc coating or epoxy coating it's 6 all included in the inspection.
7 And three times per 10 years is just, 8 that's an ISI interval -- excuse me, period. The 9 interval is 10 years. A period is three of them in an 10 interval and that's how that's determined.
11 MEMBER BROWN: But those don't necessarily 12 correspond to outages.
13 MR. GALLAGHER: Correct. So sometimes you 14 do it like, you know, if you can imagine there's three 15 periods in a 10-year. So, it could be like two 16 outages, one outage, two outage, you know. That's 17 kind of how you would do it.
18 MR. MILANO: Yes, Mr. Gallagher is 19 correct. It was the next refueling outage wherein 20 there was going to be an inspection.
21 MEMBER BROWN: Okay. All right. Thank 22 you.
23 MR. MILANO: With that I'll go onto the 24 second open item. This open item describes the 25 staff's concern related to the consideration of NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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130 1 operating experience during the term of the renewed 2 license. This issue has been discussed with the ACRS 3 in previous meetings.
4 In March of this year the staff issued 5 final license renewal interim staff guidance ISG 2011-6 5 entitled "Ongoing Review of Operating Experience."
7 This guidance emphasizes that operating experience is 8 a key feedback mechanism used to ensure the continued 9 effectiveness of the aging management programs and 10 activities.
11 In response to the staff's RAIs the 12 applicant has described the process that will be used 13 to review operating experience and the staff has 14 reviewed the description of these processes against 15 the framework set forth in the ISG.
16 And I'll repeat this even though Exelon 17 has described the issue itself well and as indicated 18 today they -- it appears they're on a path towards 19 resolution.
20 The staff's position is that any 21 enhancements to the existing operating experience 22 review activities that are necessary for license 23 renewal should be put in place no later than the date 24 when the renewed operating licenses are issued.
25 The applicant identified a number of NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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131 1 enhancements in its existing operating experience 2 program. However, these enhancements will not be 3 implemented until about 2 years after issuance of the 4 renewed license.
5 The issue that the staff has as Exelon has 6 indicated that they're responding to is -- it relates 7 to that period between the issuance of the renewed 8 license and that date, the 2-year following date 9 wherein they were going to implement this enhancement.
10 And, well this issue is open pending 11 receipt of the applicant's additional information and 12 the staff's review of it. Next slide.
13 As you know, time-limited aging analyses 14 are those licensing calculation analyses that in part 15 consider aging effects, involve time-limited 16 assumptions defined by the current operating term, are 17 relevant in making a safety determination and involve 18 conclusions or the basis for conclusions related to 19 the capability of SSCs to perform their intended 20 functions.
21 For each evaluation, analyses or 22 calculation the applicant has to determine that: one, 23 the analyses remain valid for the period of extended 24 operation; two, that the analyses have been projected 25 to the end of the period of extended operation; or NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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132 1 three, the effects of aging or the intended functions 2 will be adequately managed during the period of 3 extended operation.
4 The staff evaluated the applicant's basis 5 for identifying those plant-specific or generic 6 analyses that need to be identified as TLAAs. The 7 applicant two exemptions based on a TLAA but neither 8 of these exemptions is required for the period of 9 extended operation.
10 The exemptions were associated with the 11 pressure temperature, the PT limits developed using 12 exemptions from Appendix G of Part 50 to permit use of 13 ASME code cases and 588 and 640.
14 Since the current PT limits are only valid 15 for 32 effective full power years the exemptions must 16 be superceded before the period of extended operation.
17 Therefore, the current exemptions will not be required 18 during the period of extended operation.
19 Based on its review and the information 20 provided by the applicant the staff concludes that the 21 applicant has provided a list of plant-specific 22 exemptions granted in effect that are based on TLAAs 23 and the applicant has provided an evaluation that 24 justifies the continuation of any exemptions for the 25 period of extended operation. Thus in summary the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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133 1 staff has no open issues in the area of TLAAs section 2 for the SER.
3 And lastly, just in conclusion, and you've 4 seen this conclusion before, the staff's conclusion 5 will be provided in the final SER on the basis of its 6 review. And pending the satisfactory review and 7 resolution of the open items the staff will be able to 8 determine that the requirements of 10 C.F.R. 54.29(a) 9 have been met for the renewal of the Limerick 10 Generating Station operating license. And subject to 11 any further questions this concludes the staff's 12 presentation.
13 MEMBER SKILLMAN: Back to slide 17, 14 please, second bullet. A cynical interpretation of 15 that bullet would be you give us the renewed operating 16 license and then we'll do some more work. Is that 17 what that bullet means?
18 MR. MILANO: The second bullet, you're 19 talking about we'll the enhancements within 2 years 20 following receipt of the renewed licenses. In 21 reality, in reality these enhancements, you know, are 22 generally put into place only at the time that the 23 renewed operating license has been granted and stuff.
24 In this case here you're indeed correct as they --
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134 1 answer the question.
2 MR. MILANO: Okay.
3 MR. HOMIACK: Pat, I can field this.
4 MR. MILANO: Thank you.
5 MR. HOMIACK: Essentially the enhancements 6 the applicant has described are consistent with the 7 framework set forth in the staff's interim staff 8 guidance document. However, the only inconsistency is 9 in the implementation schedule, the ISG. And the 10 staff's position is that they had -- to be put in 11 place when the renewed licenses are issued. In this 12 case the applicant has indicated that it would like to 13 put them in place 2 years after issuance of the 14 renewed licenses. And I believe that's mainly based 15 on them, the applicant implementing them across its 16 fleet.
17 MEMBER SKILLMAN: Okay, thank you.
18 MR. MILANO: Any other questions? Thank 19 you.
20 CHAIRMAN SHACK: I'm going to open it up 21 for comments. Are there any comments from anybody in 22 the audience? Do you want to check and see if their 23 line is open and if there are any comments from 24 anybody who's been listening in?
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135 1 presentation. As I understand it we have no real 2 schedule to bring this to the full committee because 3 again we're still working on the resolution of the 4 open items. So that's indefinite at the moment unless 5 you have some?
6 MR. MILANO: At this point here the staff 7 does have a projected schedule for the safety review 8 portion as compared to the environmental review. And 9 based on the two open items and the fact that from 10 what we've heard today and what we knew coming into 11 here we believe that the staff should be able to issue 12 a final SER in January of 2013.
13 And with that there's a -- currently have 14 a full committee presentation scheduled for February 15 of next year. Again, it's subject to being able to 16 complete the open items but it looks right now like 17 that should be, that could be met.
18 CHAIRMAN SHACK: Okay. Is there anybody 19 on the line that would like to make a comment? No.
20 Hearing none we'll assume there are none. I'd like to 21 thank you.
22 Again, any final questions from the 23 committee? Anybody have any observations they'd like 24 to make?
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136 1 presentation and I think we heard a good presentation 2 from both the applicant and the NRC. I struggled to 3 find issues in this application when I was doing the 4 review. So I think it was a good quality application.
5 MEMBER SKILLMAN: I would echo that. I 6 think this has been a very high-quality presentation 7 with a lot of very good material.
8 I would make two observations. As complex 9 as scheduling would be to do a complete coating of the 10 suppression pool wall and floor it's my thought is 11 that it may be beneficial for the long run to do the 12 entire suppression pool at one time so it is treated 13 uniformly and thoroughly as opposed to breaking that 14 if you will repair up into a number of outages where 15 each prior application is in the throes of its own 16 degradation different from the next application. It 17 seems to me that that raises variability in 18 understanding what the health of that liner coating 19 would be. That would be my one comment. Thank you.
20 CHAIRMAN SHACK: Any other comments? If 21 there are no further comments we'll adjourn. Thank 22 you.
23 (Whereupon, the foregoing matter went off 24 the record at 11:32 a.m.)
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Limerick Generating Station License Renewal Application ACRS Subcommittee Presentation September 05, 2012
Introductions
- Mike Gallagher VP, Exelon License Renewal
- Gene Kelly License Renewal Manager
- Dan Doran Limerick Engineering Director
- Mark DiRado Limerick Engineering Programs Manager
1 Limerick Generating Station, Units 1 and 2
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 2 Limerick Generating Station, Units 1 and 2
Limerick Generating Station Spray Pond (Ultimate Heat Sink) 220 kV Switchyard Independent Spent Fuel Storage Installation (ISFSI)
Schuylkill River Schuylkill River Pump House 3 Limerick Generating Station, Units 1 and 2
Limerick Overview 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 2007 2007 Installation (ISFSI) 1.65% Measurement Uncertainty 4/8/11 4/8/11 Recapture (MUR) 3515 MWth Main Transformer replacements 2014 2011 Recirculation Pump Adjustable 2012 2013 Speed Drive Units (ASD)
Next scheduled Refueling Outage March 2014 March 2013 Current License Expiration 10/26/24 6/22/29 4 Limerick Generating Station, Units 1 and 2
GALL Revision 2 Consistency and License Renewal Commitments 5 Limerick Generating Station, Units 1 and 2
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 for Managing NRC Commitment Changes Total of 47 Commitments o 45 associated with aging management programs o Operating Experience program enhancement o Unit 1 Recirculation Nozzle flaw re-evaluation 6 Limerick Generating Station, Units 1 and 2
SER with Open Items 7 Limerick Generating Station, Units 1 and 2
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
Suppression Pool 9 Limerick Generating Station, Units 1 and 2
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 10 Limerick Generating Station, Units 1 and 2
MARK II Containment Liner Drywell Slab Downcomer Suppression Pool Liner 11 Limerick Generating Station, Units 1 and 2
MARK II Containment - Suppression Pool
- 250-mil continuous carbon steel liner
- 6-2 (minimum) reinforced concrete wall
- Liner serves as a leakage barrier
- Liner structural integrity limits
- 125 mils minimum general area thickness
- 62.5 mils minimum local area thickness 12 Limerick Generating Station, Units 1 and 2
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 13 Limerick Generating Station, Units 1 and 2
Suppression Pool Water Environment
- Suppression pool water quality meets BWRVIP-190, BWR Water Chemistry Guidelines, EPRI Report 1016579 Nearly neutral pH (range of 6.4 to 6.8)
Temperatures at which low corrosion rates are expected Chlorides average 2 ppb (recommended 200 ppb)
Sulfates average 13 ppb (recommended 200 ppb)
- Primary Containment inerted with nitrogen
- General corrosion rate predicted < 2 mils per year
- Corrosion data from evaluation grids confirms rate 14 Limerick Generating Station, Units 1 and 2
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 15 Limerick Generating Station, Units 1 and 2
Unit 1 Liner Condition Unit 1 - 2012 Data 100 90 Number of Localized Corrosion Locations 84.8 125-mil large area corrosion limit 80
% Submerged Liner Area 70 60 10 % Wall Loss 50 40 30 20 12.6 10 2.6 .03 0 Coating 25 50 75 100 125 150 175 190 Intact >0 Liner Metal Loss (mils) 16 Limerick Generating Station, Units 1 and 2
Unit 1 Liner Condition Unit 1 - 2012 Data - Individual localized corrosion location > 50 mils 100 30 90 84.8 Number of Localized Corrosion Locations 25 80
% Submerged Liner Area 187.5-mil local corrosion limit 70 20 60 10 % Wall Loss 50 15 40 10 30 20 12.6 5 10 2.6 .03 0 0 Coating 25 50 75 100 125 150 175 190 Intact >0 Liner Metal Loss (mils) 17 Limerick Generating Station, Units 1 and 2
Unit 2 Liner Condition 95.8 Unit 2 - 2009 Data 100 90 125-mil large area corrosion limit 80
% Submerged Liner Area 70 60 10 % Wall Loss 50 40 30 20 10 3.8 0.4 0
Coating 25 50 75 100 125 150 175 190 Intact >0 Liner Metal Loss (mils) 18 Limerick Generating Station, Units 1 and 2
Unit 2 Liner Condition
-Individual localized 95.8 Unit 2 - 2009 Data corrosion location > 50 mils 100 30 Number of Localized Corrosion Locations 90 25 187.5-mil local corrosion limit 80
% Submerged Liner area 70 20 60 10 % Wall Loss 50 15 40 10 30 20 5
10 3.8 0.4 0 0 Coating 25 50 75 100 125 150 175 190 Intact >0 Liner Metal Loss (mils) 19 Limerick Generating Station, Units 1 and 2
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 20 Limerick Generating Station, Units 1 and 2
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),
Standard Test Method for Evaluating Degree of Rusting on Painted Steel Surfaces
- 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 21 Limerick Generating Station, Units 1 and 2
Suppression Pool Plate
- Examination from 2010 Spot General refueling outage Corrosion
- Visible area approximately 1 ft2 Intact Coating General Corrosion 22 Limerick Generating Station, Units 1 and 2
Aging Management Program Enhancements Enhancement Basis 1 De-sludge each Refueling Outage (2 yrs) Frequent cleaning minimizes corrosion sites.
2 Full ASME IWE examination each ISI 100% inspection will occur frequently to confirm period (3 times in 10-year ISI interval) for expected low corrosion rate for this environment 100% of the submerged surface 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 Allows 7 cycles for Unit 1 and 9 cycles for Unit 2 and 2013 for Unit 2 prior to the PEO to recoat.
23 Limerick Generating Station, Units 1 and 2
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 24 Limerick Generating Station, Units 1 and 2
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 25 Limerick Generating Station, Units 1 and 2
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 26 Limerick Generating Station, Units 1 and 2
Closing Comments Questions?
27 Limerick Generating Station, Units 1 and 2
Back-up Slides Back-up Slides 28 Limerick Generating Station, Units 1 and 2
Suppression Pool Floor Plan Approximately 5,700 ft2 29 Limerick Generating Station, Units 1 and 2
Mockup - Wall Panel 30 Limerick Generating Station, Units 1 and 2
Mockup - Floor Panel 31 Limerick Generating Station, Units 1 and 2
Advisory Committee on Reactor Safeguards License Renewal Subcommittee Safety Evaluation Report (SER) with Open Items Limerick Generating Station, Units 1 and 2 Issued: July 31, 2012 1
Safety Evaluation Report (SER) with Open Items Limerick Generating Station, Units 1 and 2 September 5, 2012 Patrick Milano, Sr. Project Manager Office of Nuclear Reactor Regulation 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
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
- 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
Regional Inspections Overview
- Six inspectors over three weeks
- 10 CFR 54.4(a)(2) inspection
- 32 of 45 Aging Management Programs Reviewed 8
Regional Inspections Walk-downs
- 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 9
Regional Inspections Inspection Conclusions
- Inspection results support a conclusion that reasonable assurance exists that aging effects will be managed and intended functions maintained 10
Regional Inspections All Region I Plants Inspected for Renewal
- 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 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
SER Section 3 Open Items
- 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 14
Open Item 3.0.3.2.13-1 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 15
Open Item 3.0.3.2.13-1 Concerns Expressed by the Staff
- 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 16
Open Item 3.0.5-1 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 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 18
Conclusion 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 19
Wen, Peter From: aceactivists@comcast.net Sent: Monday, September 03, 2012 9:07 AM To: Wen, Peter
Subject:
Comments for 9-5-12 Subcommittee Meeting September 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 Exelons 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 isnt 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 Limericks 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 LBS. USED EVERY DAY (From Exelons NPDES Permit Application)
This doesnt disappear. It ends up in the air and water.
1
Exelon told NRC that the chlorine plume from Limericks 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 Limericks 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 Limerick reported corroded cars and lawn furniture.
- Since 2006, ACE repeated requested year-long air monitoring for all the corrosive chemicals added to Limericks 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 doesnt disappear. What vital equipment is being damaged?
Another issue that must be considered 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 Plants Total Dissolved Solids (TDS) discharges in over 14 BILLION GALLONS PER YEAR, include corrosive cooling tower chemicals and the broad range of radionuclides from Limericks operations.
- Both Exelon and PA DEP admitted that Limerick cannot meet Safe Drinking Water standards (500 mg/L) for TDS under the Clean Water Act, or even DRBCs far higher standards (1,000 mg/L).
Instead of requiring reverse osmosis to filter Limericks TDS (including cooling tower toxics and radionuclides),
PA DEP has planned to issue Limericks 5-Year NPDES permit, without limits and with an exemption of this pollution. Exemptions dont remove threats to water and health.
PLEASE RESPOND:
How Can NRC Justify Allowing Limerick to be Relicensed, When Limerick Cant Meet Clean Water Laws for Discharges That Include Radionuclides, Into A Vital Drinking Water Source For Almost Two Million People?
- Circumventing the law does not remove the threats to water and public health.
2
- 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 Limericks most dangerous discharge pipe, Outfall 001.
- Evidence at Limerick and elsewhere shows why monitoring, calculating, testing, and reporting controlled by Exelon cant be trusted.
Please consider our comments and respond so that we can report your response to our community.
Thank you, Dr. Lewis Cuthbert ACE President 3