ML16350A327

Transcript of Advisory Committee on Reactor Safeguards Plant License Renewal Subcommittee Meeting - November 17, 2016

ML16350A327
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Site:	South Texas
Issue date:	11/17/2016
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NRC-2739
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Official Transcript of Proceedings NUCLEAR REGULATORY COMMISSION Title: Advisory Committee on Reactor Safeguards Plant License Renewal Subcommittee Docket Number: (n/a)

Location: Rockville, Maryland Date: Thursday, November 17, 2016 Work Order No.: NRC-2739 Pages 1-188 NEAL R. GROSS AND CO., INC.

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

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

1 1

2 3

4 DISCLAIMER 5

6 7 UNITED STATES NUCLEAR REGULATORY COMMISSIONS 8 ADVISORY COMMITTEE ON REACTOR SAFEGUARDS 9

10 11 The contents of this transcript of the 12 proceeding of the United States Nuclear Regulatory 13 Commission Advisory Committee on Reactor Safeguards, 14 as reported herein, is a record of the discussions 15 recorded at the meeting.

16 17 This transcript has not been reviewed, 18 corrected, and edited, and it may contain 19 inaccuracies.

20 21 22 23 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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1 UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION

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ADVISORY COMMITTEE ON REACTOR SAFEGUARDS (ACRS)

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PLANT LICENSE RENEWAL SUBCOMMITTEE

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THURSDAY NOVEMBER 17, 2016

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ROCKVILLE, MARYLAND

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The Subcommittee met at the Nuclear Regulatory Commission, Two White Flint North, Room T2B1, 11545 Rockville Pike, at 8:30 a.m., Gordon R.

Skillman, Chairman, presiding.

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2 COMMITTEE MEMBERS:

GORDON R. SKILLMAN, Chairman PETER RICCARDELLA, Member-at-Large RONALD G. BALLINGER, Member WALTER L. KIRCHNER, Member DANA A. POWERS, Member JOHN W. STETKAR, Member MATTHEW W. SUNSERI, Member ACRS CONSULTANT:

STEPHEN SCHULTZ DESIGNATED FEDERAL OFFICIAL:

KENT HOWARD ALSO PRESENT:

ARDEN ALDRIDGE, STP NOC MIKE BERG, STP NOC RUSS CIPOLLA, Intertek PHYLLIS CLARK, NRR/DLR YOIRA DIAZ, NMSS/DSFM ROB ENGEN, STP NOC MICHAEL GARNER, STP NOC JIM GAVULA, NRR*

DAVE GERBER, SIA RON GIBBS, STP RAFAEL GONZALES, STP NOC ALLEN HISER, NRR/DLR NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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3 WILLIAM HOLSTON, NRR MATTHEW HOMIACK, NRR LOIS JAMES, NRR/DLR RAIHAN KHONDKER, STP NOC BRET LYNCH, WP JANE MARSHALL, NRR TODD MAXEY, STP JAMES MEDOFF, NRR/DLR MIKE MURRAY, STP NOC CHANCEY PENCE, STP NOC GREG PICK, Region IV DAVE RENCURREL, STP BILL ROGERS, NRR/DLR DAN SICKING, STP NOC RICK STARK, STP NOC DAVID STUHLER, STP NOC MIKE SVETLIK, STP MARK WALES, STP NOC GARY WARNER, WP DAVE WIEGAND, STP NOC JAMES WILLIAMS, STP NOC PRESTON WILLIAMS, STP NOC JAMES C. YOUNGER, STP NOC KEVIN REGIS, STP NOC

• Present via telephone NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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4 C-O-N-T-E-N-T-S Call to Order and Opening Remarks..................5 Staff Introduction.................................6 South Texas Project Nuclear Operating..............7 Company (STPNOC) - South Texas Project, Units 1 and 2 (STP)

NRC Staff Presentation SER with Open..............80 Items Overview Opportunity for Public Comment...................133 (None)

Committee Discussion.............................134 Adjourn NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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5 1 P R O C E E D I N G S 2 8:29 a.m.

3 CHAIRMAN SKILLMAN: (presiding) Ladies 4 and gentlemen, good morning. This meeting will now 5 come to order.

6 I am Gordon Skillman. I am Chairman of 7 the Plant License Renewal Subcommittee.

8 The Subcommittee will review the 9 license renewal application for South Texas Project 10 Units 1 and 2.

11 ACRS members in attendance today are 12 Dana Powers, John Stetkar, Ron Ballinger, Peter 13 Riccardella, Walt Kirchner, and Matt Sunseri. Our 14 ACRS consultant Dr. Stephen Schultz is also in 15 attendance. Kent Howard of the ACRS is the 16 Designated Federal Official for this meeting.

17 This morning we will hear presentations 18 from the Division of License Renewal, Region IV, 19 and South Texas Nuclear Operating Company, the 20 Applicant, regarding this matter. This 21 Subcommittee will gather information, analyze 22 relevant issues and facts, and formulate proposed 23 positions and actions, as appropriate, for 24 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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6 1 meeting have been announced as part of the notice 2 of this meeting published in The Federal Register.

3 We have not received written comments and requests 4 for time to make oral statements from members of 5 the public regarding today's meeting, and the 6 entire meeting will be open to public attendance.

7 There will be a phone bridge line. To 8 preclude interruption of the meeting, the phone 9 will be placed in a listen-in mode during the 10 presentations and Committee discussion.

11 A transcript of this meeting is being 12 kept and will be available, as stated in The 13 Federal Register notice. Therefore, I request that 14 participants in this meeting use the microphones 15 located throughout the meeting room when addressing 16 the Subcommittee. The participants are requested 17 to please identify themselves and speak with 18 sufficient clarity and volume, so that they can be 19 readily heard.

20 I also request that all attendees 21 please silence your personal electronic devices.

22 We will now proceed with the meeting, and I call upon 23 Jane Marshall to begin the presentation.

24 Thank you, Chairman Skillman.

25 As stated, I am Jane Marshall. I'm the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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7 1 Acting Director for the Division of License Renewal 2 in the Office of Nuclear Reactor Regulation. With 3 me here today are members of my management team and 4 several members of my staff. They will introduce 5 themselves as they answer questions today. Also 6 joining us by phone is Greg Pick, who is the Lead 7 Inspector from Region IV.

8 The staff's presentation will be given 9 by Lois James, who is the South Texas Project 10 Safety Project Manager. She will be joined at the 11 table by DLR Senior Technical Advisor Dr. Allen 12 Hiser and Senior Mechanical Engineer Bill Holston, 13 as well as Safety Project Manager Phyllis Clark.

14 At today's ACRS Subcommittee meeting, 15 the staff will present its review and resolution 16 path for the open item for the license renewal of 17 South Texas Project Units 1 and 2. The information 18 we will be presenting was documented in the Final 19 SER.

20 At this time, I would like to turn the 21 presentation over to South Texas Project Nuclear 22 Operating Company and Dave Rencurrel, Senior Vice 23 President for Operations, to introduce his team and 24 commence their presentation.

25 Thank you.

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8 1 MR. RENCURREL: Good morning.

2 Yes, as you said, my name is Dave 3 Rencurrel. I am from South Texas, Senior Vice 4 President of Operations.

5 I really would like to take this 6 opportunity to thank the ACRS Subcommittee for our 7 opportunity to present our overview of our license 8 renewal application, and we do look forward to your 9 questions.

10 But, before we get started, I would 11 also like to thank the NRC reviewers for their hard 12 and diligent work in this process and for everybody 13 on the staff, everybody from South Texas, who has 14 also worked very hard in this process.

15 There it is. All right. As you can 16 see, here is an overview of the agenda, which we 17 will be presenting today. I would like to point 18 out that we are setting aside a really special time 19 or focused time to discuss the Safety Evaluation 20 Report open item for aluminum bronze selective 21 leaching.

22 With that, I would like to move into 23 the introductions of the team that we brought 24 today. I will start and, then, we will just move 25 to the left and move down our line.

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9 1 Now my name, as I said, is David 2 Rencurrel. I'm the Senior Vice President of 3 Operations.

4 I began my career over 35 years ago, my 5 nuclear career over 35 years ago in 1981, when I 6 started in the United States Navy as a nuclear 7 officer. In 1988, I joined the South Texas Project 8 and, since then, I have had many different jobs. I 9 got hired in as a young system engineer. I have 10 went through license class, spent time in the 11 control room as a shift technical advisor. I spent 12 time as a work control supervisor, worked in 13 maintenance, system engineering manager, design 14 manager. I was ops manager for a little bit over 15 four years, VP of Engineering and Projects, Site VP 16 for over four years. Now I am in my current role 17 where I am responsible for all projects here 18 onsite.

19 I would like to hand off to Mike 20 Murray.

21 CHAIRMAN SKILLMAN: Not so fast, Dave.

22 You have a lofty position, huge influence at the 23 site and in the company. What is your vision of 24 the importance of 10 CFR 50 Appendix B?

25 MR. RENCURREL: I think that is NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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10 1 extremely important. 10 CFR 50 Appendix B is what 2 gives us that consistency and that credibility that 3 we all want. I think that is where that comes from 4 in that regard.

5 CHAIRMAN SKILLMAN: I asked the 6 question because in the course of time those of us 7 who have been in industry for a long time have 8 watched the devotees of 10 CFR 50 Appendix B fall 9 away. There is always somewhat of a move to cut a 10 corner here or cut a corner there and not recognize 11 how important the 18 points of that regulation are 12 --

13 MR. RENCURREL: Yes, sir, I understand.

14 CHAIRMAN SKILLMAN: -- to the materiel 15 condition of the unit and to the culture of the 16 unit. And so, my question is, how vigilant are you 17 of that? And what is the shadow that you cast on 18 your organization?

19 MR. RENCURREL: So, what is -- that is 20 the quality, right?

21 CHAIRMAN SKILLMAN: Yes, yes.

22 MR. RENCURREL: That's what I thought.

23 So, here's what we do in regards to independent 24 oversight of their station. Independent oversight, 25 obviously, we have the right dedication and right NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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11 1 resources assigned to that. They act independently 2 in that they report up to a company officer. All 3 right. We ensure that they have a very 4 professional relationship with the staff, that they 5 are honored by the staff and listened to by the 6 staff, that they have the capability to measure our 7 not just compliance, but also our drive towards 8 excellence.

9 We also have monthly reports, for 10 example, that come up to the executives where they 11 get to talk about oversight or the vision of 12 oversight of performance of how the station 13 performs. We have a very prescriptive program of 14 the elevation/escalation, where elevation is where 15 they bring up an issue to site leadership, plant 16 manager and such, where they can talk about 17 prolonged gaps or gaps that aren't being closed.

18 And then, it subsequently goes to escalate, if that 19 doesn't get solved, where, depending upon the 20 level, it can actually go all the way up to an 21 officer or a vice president to be accountably 22 resolved.

23 And then, you roll into the whole 24 concept of corrective actions and the idea of being 25 able to -- it is not just a corrective action NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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12 1 program; it is more of a program to ensure that you 2 have proper problem identification and real 3 resolutions that solve not just the symptom of the 4 problem, but the actual do the hard work of 5 understanding the cause of the problem. And I 6 believe that is extremely important, something we 7 measure very closely for.

8 I believe that in any organization you 9 have to have governance, proper governance, which 10 is the rules, the regulations, the traditions, the 11 meetings that we all interact with, so that you can 12 have proper oversight, so the oversight can come up 13 and measure how your governance is actually 14 operating and working. I believe in all those 15 concepts.

16 I also know that the folks I work with, 17 my boss, our Chief Executive Officer Dennis Koehl, 18 our Chief Nuclear Officer Tim Powell, also believe 19 very strongly in the Appendix B, in the 50.B 20 program. They believe very strongly in the 21 corrective action program and independent 22 oversight.

23 And having said all those words, in 24 conclusion, I would say plants/stations that 25 perform well, stations that perform with NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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13 1 excellence, stations that, quite frankly, meet the 2 business plan needs of the owners and the 3 shareholders have that healthy respect. Plants 4 that don't, they don't meet those; they don't have 5 that performance and they don't meet those business 6 goals. So, it all ties together.

7 CHAIRMAN SKILLMAN: Yes, I thank you 8 for your explanation. My real question was about 9 your office and your shadow on the QA program.

10 MR. RENCURREL: Yes, my office and my 11 shadow on the QA program is I know the QA Manager 12 personally and I actually mentor him through his 13 roles. I help him interact with folks on the 14 station. In my role right now, they don't report 15 to me. In my previous roles, they actually 16 reported to me. So, it was much more hands-on in 17 how things are working.

18 My shadow is that I believe very, very 19 strongly in the independence of QA, its 20 independence and conclusion, its independence in 21 their messaging, but we work closely with them in 22 ensuring that that message is presented in a way 23 that can be readily understood and accepted by the 24 staff.

25 I spend time; I go down and talk to the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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14 1 folks -- they actually sit down the hall from me.

2 I go down and visit with them a lot, pretty much 3 know just about everybody there. And at times I 4 have both defended them and I both chastised them.

5 So, I think I have a very good shadow.

6 CHAIRMAN SKILLMAN: Dave, thank you.

7 Please proceed.

8 MR. RENCURREL: Okay. Thank you.

9 MR. MURRAY: My name is Michael Murray.

10 I'm the Regulatory Affairs Manager at South Texas 11 Project.

12 I have been in the industry for 41 13 years, started as an I&C tech at the Brunswick 14 Plant. I have had 31 years at South Texas Project.

15 I was there for startup of both units. So, I have 16 a long history at South Texas Project.

17 Various management positions. I was 18 I&C Manager, Systems Engineering Manager; spent 19 some time working on the Units 3 and 4 licensing 20 project as I&C, the Design Manager there. And I 21 have met a few of these folks here during that 22 process. And then, currently, I'm Reg Affairs 23 Manager at South Texas Project.

24 MR. GIBBS: Good morning. I'm Ron 25 Gibbs. My current position is the Manager, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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15 1 Operations, Shift Operations. I'm the Senior 2 License at the South Texas Project now.

3 I've got over 30 years of nuclear 4 experience. Started out as a unit supervisor, STA, 5 at Comanche Peak. Came to the South Texas Project 6 in 1993. Got my Senior Reactor Operator License 7 there in 1995 and worked my way on shift. I 8 started as unit sup, STA, again, up through shift 9 manager. Came off shift in 2013 into an ops 10 manager role and took over as the Senior License 11 January of this year.

12 MR. ALDRIDGE: Good morning. My name 13 is Arden Aldridge.

14 I have been in the nuclear service for 15 about 38 years. I started in the nuclear submarine 16 service, consultation with some consulting groups, 17 and then, with two utilities.

18 For the last 22 years, I have been at 19 South Texas Project fulfilling various engineering 20 roles and functions. In the last 10, I have been 21 focused on license renewal applications, helping 22 our peer plants prepare three application from 23 preparation to approval. In the last five years, 24 it has been focused as the project lead and the 25 Implementation Coordinator for South Texas.

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16 1 CHAIRMAN SKILLMAN: Thank you.

2 MR. BERG: Good morning. I'm Michael 3 Berg. I'm the Engineering Manager of Design and 4 Programs.

5 I have got 38 years in the nuclear 6 industry, 34 years at South Texas Project. I was 7 one of the original engineering supervisors that 8 took over design control from the architect 9 engineer.

10 I have had various manager roles over 11 the past 25 years and I was the manager over the 12 STP initial license renewal application submitted.

13 CHAIRMAN SKILLMAN: Gentlemen, thank 14 you. Please proceed.

15 MR. RENCURREL: Okay. What I would 16 like to do now is give a brief station ownership, 17 overview of station ownership and operation.

18 South Texas Project Nuclear Operating 19 Company is the licensed holder for the station.

20 The station is actually owned by three different 21 companies, Energy Texas, which is an investment-22 owned utility; the City Public Services, San 23 Antonio, which is owned by the municipality San 24 Antonio, Texas, and Austin Energy, which is owned 25 by the City of Austin. So, we are owned by one NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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17 1 investor and two municipalities. To put our 2 generation in context, over 25 percent of the 3 carbon-free electric generation in the State of 4 Texas is produced at South Texas.

5 CHAIRMAN SKILLMAN: And you get no 6 credit for that whatsoever.

7 (Laughter.)

8 MR. RENCURREL: Yes, sir.

9 To go over our plant history and some 10 major investments, we received our initial license 11 in 1987 and 1988, respectively, for Unit 1 and Unit 12 2. Since that time, we have made major capital 13 investments. We have replaced our steam 14 generators, all four in each unit. We have 15 replaced our low-pressure turbines. We have 16 replaced both reactor vessel heads in both units.

17 We have also rewound our main generator stators and 18 have replaced the rotors, the main generator 19 rotors, in both units.

20 Looking forward, we have main 21 transformers done on one unit, but we are replacing 22 the main transformers in the other unit in the next 23 outage, and we are working through the replacement 24 of our feedwater heaters that show that there is an 25 ongoing investment in the major improvements of the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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18 1 plant. Also, as you can see there, the non-welded 2 stress improvement process is being put in place, 3 and that is going to go down in 2017 and 2019.

4 The way our governance works is that we 5 have a business plan. And the way that the owners 6 commit to the long-term safe operation of the 7 station is via that business plan. This business 8 plan is approved annually for the next five years' 9 spend.

10 And so, in a sense, what goes on is the 11 money is allocated or set aside for the next five 12 years' worth of capital investments. However, our 13 plant investment plan itself goes out 20 years 14 where we have levelized out and put in all the 15 capital improvements and all the capital necessary 16 to move forward.

17 If you look at our plant investment 18 plan, you will see that our owners, we have 19 identified and our owners have committed to the 20 capital monies necessary to implement the aging 21 management plan. And so, there is that commitment, 22 not just in words, but in treasure, in regards to 23 implementing the extended license and safely moving 24 into the extended period of operation.

25 With that, I would like to turn it over NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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19 1 to Ron Gibbs, our ops manager.

2 MR. GIBBS: Good. Thank you, Dave.

3 This morning I will be giving a brief 4 description of the South Texas Project site and 5 station design.

6 South Texas Project is located about 90 7 miles southwest of Houston. You see the star here 8 on the Texas map gives a representation of our 9 location. Here in the center of this aerial map 10 you can see is the South Texas Project site. It is 11 about 12,000 acres. As you can see also in this 12 aerial view, it is largely a rural area, a lot of 13 farming in our community. We are Matagorda County 14 and about 15 miles inland from the Gulf of Mexico.

15 The large body of water here in the 16 center is our main cooling reservoir. Makeup from 17 our main cooling reservoir is the Colorado River 18 you can see here -- that is the main source -- and, 19 also, rainwater.

20 Our station, here is our main cooling 21 reservoir again on the top of the picture. Our 22 essential cooling water pond here is on the bottom.

23 That is commonly called service water in the 24 industry, and this is our ultimate heat sink.

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20 1 means of makeup and rainwater.

2 Just to the right here you can see our 3 switchyard. We have nine 345-KV lines coming into 4 and out of the switchyard. And the units here are 5 in the center of the pictures. We have two 6 Westinghouse four-loop PWRs, Pressurized Water 7 Reactors. Our thermal rate of power is 3853 8 megawatts thermal with a design output of 1250 9 megawatts electric.

10 CHAIRMAN SKILLMAN: Ron, the essential 11 service water pond there fed from wells, does that 12 mean that that is freshwater --

13 MR. GIBBS: Yes.

14 CHAIRMAN SKILLMAN: -- compared with 15 brackish water?

16 MR. GIBBS: That's correct.

17 CHAIRMAN SKILLMAN: Okay. I did not 18 appreciate that when I was reading the application 19 for the safety evaluation. Thank you.

20 MR. GIBBS: Okay.

21 CHAIRMAN SKILLMAN: Okay.

22 MR. GIBBS: Operators are licensed on 23 both units. So, we can operate either unit, and we 24 utilize common operating procedures.

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21 1 tensioned concrete cylinders with steel liner 2 plates, hemispherical tops, and flat bottoms.

3 Each unit has three independent safety 4 trains, including piping, valves, pumps, and diesel 5 generators, our emergency supply for emergency 6 power. And each unit has four safety-related 7 auxiliary feedwater trains, three electric pumps, 8 and one steam-driven pump.

9 And next, I will turn it over to Arden.

10 CHAIRMAN SKILLMAN: Let me ask you to 11 back up a slide, please. Your aerial, the Mad 12 Island, that is the wildlife management area?

13 MR. GIBBS: That's correct.

14 CHAIRMAN SKILLMAN: And so, most of the 15 population down there are alligators and critters?

16 Is that what you've got down there?

17 MR. GIBBS: That's correct, a lot of 18 alligators, a lot of critters.

19 CHAIRMAN SKILLMAN: That's 5-6,000 20 acres, 10,000 acres, something like that?

21 MR. GIBBS: It itself, yes.

22 CHAIRMAN SKILLMAN: Yes. Thank you.

23 Okay. Okay.

24 MR. GIBBS: Next, I will turn it over 25 to Arden to walk us through our license renewal.

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22 1 CHAIRMAN SKILLMAN: Right.

2 MR. ALDRIDGE: As I mentioned, my name 3 is Arden Aldridge. I was the license renewal 4 project lead, and I would like to just go through a 5 little chronology of where we have been in 6 preparation of this application.

7 In October of 2010, we submitted our 8 license renewal application against the 9 requirements of GALL Rev. 1. We, then, went 10 through the inspections and reviews. In 2013, we 11 received a Safety Evaluation Report with four open 12 items, and at the same time we put the safety 13 review on hold because of the uncertainty of the 14 waste confidence role on future license decisions.

15 Well, during the year that we put it on 16 hold we continued to work on the project. We 17 updated to GALL Rev. 2, the requirements of GALL 18 Rev. 2. We incorporated lessons learned from 19 License Renewal Safety Evaluation Reports and 20 performed annual updates. We also resolved three 21 of the open items going forward.

22 Here we are in 2016. We completed all 23 the reviews. The Safety Evaluation Report with 24 just one open item was issued on October of 2016, 25 and that open item is the aluminum bronze that we NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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23 1 will talk to later in the application.

2 On the next slide, just a description 3 of the programs, of how they have rolled out. We 4 had 41 aging management programs, of which 33 of 5 them were existing programs and eight new ones. On 6 that slide you will see in GALL consistency we said 7 we were 90-percent consistent with the standard 8 notes alpha through echo of GALL Rev. 1. However, 9 with the enhancements of GALL Rev. 2, that 10 consistency with GALL Rev. 2 is 95 percent against 11 the standard notes. As just a reminder, on the 12 bottom there, reinforcement, we did get reviewed 13 against standard review plan for GALL Rev. 2 and 14 those requirements.

15 On the next page, STP's program's 16 consistency with the GALL is we were consistent 17 with GALL Rev. -- the consistency table is against 18 GALL Rev. 1, but it is just an accounting 19 perspective. We had 21 aging management programs 20 that are consistent with GALL. We have 16 aging 21 management programs that are consistent with 22 exceptions, and we have four plant-specific aging 23 management programs.

24 Approximately 10 of the 16 aging 25 management programs with exceptions are due to the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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24 1 addition of the requirements of GALL Rev. 2 and the 2 lessons learned that we incorporated. The 3 remaining exceptions would be alternate methods of 4 managing the aging effects specifically for the 5 programs that we developed.

6 As far as the license renewal 7 commitments, those are being tracked and we have 46 8 of them. This slide is just to represent the 9 different categories of commitments that we have 10 established. And up to this date, you can see 11 several of them are closed. Eight of the 46 12 commitments have been closed or have been 13 completed. That leaves us with 38 remaining to 14 implement prior to the period of extended 15 operation.

16 We have an implementation plan, a 17 schedule, and the budget that Dave mentioned to 18 complete these remaining open commitments prior to 19 their scheduled due dates in preparation for 20 entering the period of extended operation in 2027 21 and 2028.

22 CHAIRMAN SKILLMAN: Before you change 23 that slide, would you give us a little tutorial on 24 your inspections? The Unit 1 refueling water 25 storage tank welds you had some leaking, outside NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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25 1 tanks?

2 MR. ALDRIDGE: Yes.

3 CHAIRMAN SKILLMAN: You repaired those.

4 MR. ALDRIDGE: Yes.

5 CHAIRMAN SKILLMAN: You brought them 6 into conformance with their codes. You are on an 7 inspection frequency, that is, an outage inspection 8 frequency. I don't know if that is 24 months or 18 9 months. But it seems as though you found yourself 10 in a predicament with a leaking RWST. And so, you 11 have amended your procedures for inspection.

12 Please tell us more about this.

13 MR. ALDRIDGE: Thank you, Mr. Chairman.

14 We did have a plant-specific condition 15 on the refueling water storage tank on Unit 1, and 16 it was identified through external leakage. And 17 so, we did an internal inspection and repair. That 18 internal inspection and repair, then, had a root 19 cause performed on that, and we identified that the 20 cause was due to external leakage from water that 21 had entered the room from seals and there was no 22 berm around the tank. So, it had attacked the 23 exterior of the tank.

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26 1 concern. When we did our aging management program, 2 we were committed to performing a confirmatory that 3 the repairs, confirmed that they were effective and 4 that there is no aging degradation going on on the 5 internal side of the tank. In addition, we, then, 6 every refueling outage, we look at the exterior of 7 the tank for external indications of cracking or 8 leakage.

9 CHAIRMAN SKILLMAN: What is your fuel 10 cycle length, please? Fuel cycle length?

11 MR. ALDRIDGE: Yes, 18 months.

12 CHAIRMAN SKILLMAN: You are on 18 13 months? Okay. Thank you.

14 MR. ALDRIDGE: Okay.

15 MEMBER SUNSERI: I have a question 16 while you are on this page as well. So, we have 17 been following an issue with degraded baffle bolts 18 in the industry. And in South Texas your core is 19 larger. So, I suspect you are unique from the rest 20 of the fleet within maybe the number of baffle 21 bolts and how they are put together.

22 So, my question for you is, are you an 23 upflow or downflow plant? What has your experience 24 with the baffle bolts been? And what are you doing 25 to track the issue from an aging management NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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27 1 perspective?

2 MR. BERG: I will go ahead and answer 3 that question. Certainly, we have been involved 4 with the EPRI Materials Reliability Project and 5 compliance with MRPG-27. We are an upflow design, 6 and our baffle bolts are 3/16 material. So, when 7 you look at the susceptibility, we are in the 8 lowest susceptibility associated with that.

9 We have done some inspections where we 10 just visually looked at the baffle bolts. We have 11 not found any degradation of the baffle bolts.

12 MEMBER SUNSERI: Do you do the UT 13 inspections or just the visual?

14 MR. BERG: Just visual inspection. We 15 will do the UT inspections, per MRPG-27, prior to 16 the period --

17 MEMBER SUNSERI: So, you have it right?

18 Yes, okay. I've got it. Thank you.

19 MEMBER KIRCHNER: Dick, may I ask a 20 question?

21 CHAIRMAN SKILLMAN: Please.

22 MEMBER KIRCHNER: From this long list, 23 what are the long poles in the tent? Not all these 24 are equal in terms of effort and commitment and 25 difficulty. Could you just highlight those that NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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28 1 are -- we know we have one more coming, but --

2 MR. ALDRIDGE: Right.

3 MEMBER KIRCHNER: -- excepting that 4 one, on this long list and the AMPs program, which 5 are taking more of your time or attention or 6 resources?

7 MR. ALDRIDGE: Yes, sir. When you 8 really look at, with the enhancements that we have 9 in place and have committed to, program 10 enhancements and program implementation both go 11 hand-in-hand. And we have been in the development 12 phase for all these years. So, those, just because 13 of the numbers, 26 of them remain open for 14 enhancements with nine implementation. The 15 implementation programs, not only are we developing 16 the base procedures and all the requirements that 17 we committed to in the aging management program, 18 but most of those require in-plant inspections, 19 whether they are one-time inspections or the 20 beginning of a periodic.

21 And then, from an analysis perspective, 22 we have already performed the screening on the 23 NUREG-6260 central locations. We just have to go 24 through and upgrade the program to continue to 25 monitor those new locations. So, that would be the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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29 1 main areas.

2 MEMBER KIRCHNER: Thank you.

3 CHAIRMAN SKILLMAN: Please proceed.

4 MR. ALDRIDGE: Thank you.

5 Okay. And so, really, in conclusion, 6 the license renewal commitments are included in our 7 SAR Supplement, in our FSAR Supplement, Appendix 8 Alpha of the license renewal application. It is 9 managed by our Appendix B Program, and it is the 10 STP condition reporting process and the license 11 commitment management and administrative processes.

12 There are two processes that control those, and 13 they are being tracked for completion under those 14 programs.

15 All right. At this time, I would like 16 to transfer to Mike Berg.

17 MR. BERG: Okay. I would like to talk 18 about our Safety Evaluation Report open item. This 19 is associated with selective leaching of our 20 aluminum bronze essential cooling water system.

21 The open item focuses on wells 22 themselves. But, prior to getting into the 23 specifics of the open item, I would just like to 24 give a brief overview of the selective leaching 25 process. So, from a high-level background for NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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30 1 selective leaching of our low-pressure essential 2 cooling water system, which is commonly referred to 3 in the industry as service water system, as Ron 4 stated earlier, the material is aluminum bronze, 5 which is a copper aluminum alloy. Selective 6 leaching is a corrosion process where the aluminum 7 in the transformed phase can selectively leach out 8 when you have aluminum that is greater than 8 9 percent and exposed to wetted surfaces. Selective 10 leaching of aluminum leaves micro-voids along the 11 grain boundaries and, when progressed through a 12 wall, leakage/seepage will become visible on the 13 outside surface of the material.

14 So now, I would like to refer to the 15 slide here. So, what we are looking at here, this 16 is a section of pipe. We have a weld and, then, we 17 have got a weld-neck flange. So, the piping itself 18 -- there we go -- the piping itself is made out of 19 wrought material. It has less than 8-percent 20 aluminum, and we have not seen, nor is it 21 vulnerable to, selective leaching.

22 I want to talk about the casting --

23 MEMBER KIRCHNER: Just for perspective 24 --

25 MR. BERG: Yes.

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31 1 MEMBER KIRCHNER: -- what is the 2 diameter of the pipe there and what is the schedule 3 and such? What are we looking at in the picture?

4 I can see nuts on the side. So, it looks like it 5 is now 4-inch or --

6 MR. BERG: I'm thinking it is 4- or 6-7 inch diameter pipe that we are looking at here.

8 So, let's talk about the casting 9 materials themselves. They are susceptible to the 10 alloying. We first saw the alloying or cast 11 materials on our small-bore piping back in 1988.

12 All of those were replaced.

13 We do programmatically do a walkdown 14 every six months. What we are looking for is 15 copper oxide on the exterior of the pipe, like you 16 see right here. So, the green pipe, and we look 17 for a buildup of residual.

18 If I sectioned this pipe, I would look 19 at the inside of the pipe and I would see some 20 aluminum hydroxide corrosion products where the 21 aluminum has selectively leached inside the pipe 22 and, then, on the outside, again, I see the copper 23 oxide deposits that have occurred.

24 Just over a period of time, on these 25 large-bore castings we were somewhere between five NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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32 1 or ten first initial startup. Over the years, we 2 currently run somewhere between zero or two of 3 these per year, is what we see.

4 CHAIRMAN SKILLMAN: Is this phenomenon 5 limited to just the cast material?

6 MR. BERG: So, we are going to talk a 7 little bit later on the welds, which is the open 8 item. But where we have seen it predominantly is 9 in the cast materials.

10 CHAIRMAN SKILLMAN: Okay.

11 MEMBER SUNSERI: And it progresses from 12 the exterior of the pipe inward or?

13 MR. BERG: No, from the interior of the 14 pipe, selective leaching, and then, it takes the 15 aluminum, so the aluminum hydroxide on the inside 16 of the pipe. Once the aluminum comes through to 17 the outside of the wall, then you will see weepage.

18 So, we don't see a lot of leakage. It is really 19 weepage. Or, even in a lot of cases, when we will 20 do the walkdown, we will see the spots and you 21 won't even see any moisture at all. Yes, it is 22 kind of a sponge.

23 CHAIRMAN SKILLMAN: Do you want to be 24 on the record?

25 MEMBER KIRCHNER: Have you cut any of NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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33 1 these castings out and done an evaluation?

2 MR. BERG: Oh, absolutely. We have 3 done a lot of evaluations.

4 MEMBER KIRCHNER: Do you have any 5 pictures with you to show the phenomenon as it 6 progresses?

7 MR. BERG: Really, we don't have 8 pictures with us. As part of our license renewal 9 application for our casting materials, we are going 10 to replace the casting materials with materials 11 that are not subject to the selective leaching 12 phenomena. So, our commitment is we are going to 13 change all of these castings out prior to the 14 period of extended operation.

15 MEMBER KIRCHNER: Well, it begs the 16 question, then, to what?

17 MR. BERG: We will go with, if we stay 18 with aluminum bronze material, then we will have 19 material probably a wrought-type material that has 20 less than 8-percent aluminum.

21 MEMBER BALLINGER: Yes, wrought 22 material, it is a two-phase thing where they get 23 something called the gamma-2 phase which is rich in 24 aluminum. It is like dezincification.

25 MR. BERG: Right.

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34 1 MEMBER BALLINGER: So, you get 2 electrochemical cell buildup and you selectively 3 leach out the aluminum. It is like 4 dezincification. And so, you end up with sort of 5 like a porous structure.

6 MR. BERG: Right.

7 MEMBER BALLINGER: But, if you whack it 8 with a hammer, you will find out that it is not 9 so -- that the porosity is a problem. And so, 10 wrought materials are usually not susceptible or if 11 you heat-treated casting, so that you get rid of 12 the solidification microstructure that goes on.

13 And the rates are anywhere from .05 to .5 mLs per 14 year sometimes, or even higher, depending on the 15 structure.

16 MEMBER KIRCHNER: With the current 17 material?

18 MEMBER BALLINGER: With the cast 19 material.

20 MEMBER KIRCHNER: With the casting?

21 MEMBER BALLINGER: With the cast 22 material.

23 MEMBER KIRCHNER: Right. And what is 24 the differential with the wrought?

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35 1 gamma phase. And so, you don't have the same kind 2 of problem at all for de-aluminization. So, 3 wrought materials are generally not susceptible to 4 the material. And if you are less than -- you said 5 8 or 9 percent --

6 MR. BERG: Yes, 8 percent.

7 MEMBER BALLINGER: I think it is on the 8 order of 8 percent, where if you look at the phase 9 diagram, you can't get that phase.

10 MEMBER KIRCHNER: Yes. Thank you.

11 MR. BERG: Okay. So, the focus on the 12 open item is associated with the welds themselves.

13 So, let's move on to that particular area.

14 So, with the welds, we have seen --

15 first off, we haven't seen any since 1994, but what 16 we see is, it actually is a cracking phenomena that 17 occurs. Okay? So, from finding the particular 18 condition when it does occur, and it hasn't been 19 since 1994, just operators doing a walkdown, so you 20 will see a light mist spray or maybe some water on 21 the floor. So, the operators would identify that 22 as part of the walkdown and would put in a 23 corrective action program and handle it through 24 that methodology.

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36 1 cracking. The cracking has some de-alloying 2 associated with that. We have had two of them that 3 occurred, two of the cracks that have occurred in 4 thermal welds. The rest of the cracks, though, 5 have occurred with welds with backing rings, which 6 is the focus of a lot of our work in addressing the 7 open item.

8 MEMBER KIRCHNER: What is the typical 9 corrective action, then, once you discover this?

10 MR. BERG: We would cut it out and 11 replace it. When we talk about the open item, 12 there are 10 issues associated with that. When I 13 go through that, I will talk about the specifics we 14 do on how do we do the inspection, acceptance 15 criteria, and then, we will talk about corrective 16 actions.

17 MEMBER RICCARDELLA: So, is a 18 significant percentage of this piping underground?

19 MR. BERG: Not percentage-wise, and I 20 don't know what the percentage of the welds because 21 most of the underground piping is of large sections 22 in nature, but we do have some of the welds 23 certainly that are underground with backing rings.

24 MEMBER SUNSERI: So, maybe you are 25 going to talk about this when you get to the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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37 1 inspections, but is there an NDE technique for this 2 or?

3 MR. BERG: This really gets into our 4 corrective action. But we have been working over 5 the last few years with an NDE technique. So, 6 obviously, if it is a cracking-type phenomena that 7 is occurring, ultrasonic NDE will detect that 8 condition.

9 MEMBER SUNSERI: And are you doing it 10 any?

11 MR. BERG: So, we would do it if we 12 found a condition where we were seeing cracks at 13 the surface type of thing. Then, we would follow 14 the code requirements and we would have to go 15 characterize that, and we would go do an NDE 16 inspection.

17 MEMBER SUNSERI: Okay. Because I 18 thought I heard you say you see the misting and all 19 that stuff. So, I mean, it is a safety-related 20 system. I guess that puts you in a tech-spec 21 action statement.

22 MR. BERG: That is correct. So, we 23 would do an operability --

24 MEMBER SUNSERI: The active mode 25 versus --

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38 1 MR. BERG: It would be an operability 2 determination associated with that, which Ron would 3 request, and we would go do the characterizations 4 in accordance with code.

5 And we are going to talk a little bit 6 later on, the proactive piece is prior to the 7 period of extended operation. I will just get to 8 it briefly now. It is that we will do an 9 inspection of -- I'm going to get this wrong -- 20 10 percent with 25 welds with backing rings and 11 without backing rings prior to the period of 12 extended operation. We will actually go in and 13 come apart and look at it.

14 We have looked at others as well. I 15 don't want to let you believe we haven't done any 16 evaluation. We have done evaluations, 17 metallurgical exams of the things where we have 18 found cracking in the past and other ones where we 19 have the castings, you know, we look at the welds 20 as well as part of that.

21 MEMBER SUNSERI: Okay.

22 CHAIRMAN SKILLMAN: Mike, let me ask 23 this: from the inspection report, the 71002 24 inspection report, the comment is, "The team noted 25 the experience regarding the loss of material NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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39 1 caused by selective leaching in aluminum bronze 2 components in the essential service water system is 3 an ongoing aging mechanism." That is from the 4 71002 inspection.

5 MR. BERG: Yes.

6 CHAIRMAN SKILLMAN: The text appears to 7 point only to the essential service water system.

8 Is th is phenomenon anywhere else in any other 9 systems?

10 MR. BERG: The answer to that is no 11 because we only use aluminum bronze in our 12 essential --

13 CHAIRMAN SKILLMAN: Let me ask you one 14 more. Your cathodic protection system is not in 15 scope. At least it isn't in the document that I 16 read. What connection have you made between this 17 phenomenon and the inoperability of your cathodic 18 protection system for what appears to be 10 to 15 19 years?

20 MR. BERG: Do you want to answer from 21 the TLA perspective?

22 MR. ALDRIDGE: Yes. Yes, sir. Let me 23 answer from the perspective of the cathodic 24 protection. The piping at South Texas is 25 cathodically protected as part of the buried piping NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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40 1 aging management program, and aluminum bronze is 2 one of the systems that is protected by the 3 cathodic protection.

4 CHAIRMAN SKILLMAN: Would it be more 5 accurate to say is now protected by, but was not 6 for a long time period? That is a yes or no.

7 MR. ALDRIDGE: No. It is always had 8 various degrees of protection. We have enhanced 9 the degree of protection since the regional 10 inspection, and now we are meeting better 11 availability and --

12 MEMBER STETKAR: Let's get specific.

13 What has the historic availability over the life 14 of the plant of your cathodic protection system 15 been?

16 MR. ALDRIDGE: Thank you, sir. We have 17 the subject matter expert present, and he can give 18 you the numbers.

19 CHAIRMAN SKILLMAN: Okay. Let's do 20 that, please.

21 MR. KHONDKER: My name is -- can you 22 hear me?

23 CHAIRMAN SKILLMAN: Yes.

24 MR. KHONDKER: Okay. So, my name is 25 Raihan Khondker. I am the Cathodic Protection NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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41 1 System Engineer at South Texas.

2 And the question being asked, what is 3 our historical availability of the cathodic 4 protection system? Over the past since the 5 inception of the plant, we have maintained the 6 cathodic protection system in the entire protected 7 area. So, we always adhere to the 8 needs/requirements back then, which used to be --

9 now it is called SBO 0169; back then it was RP. We 10 adhered to that since the beginning and we did 11 maintain the full availability as possible.

12 But, of course, over the course of the 13 years when we saw deteriorations, rectifiers out of 14 service, in some years we did see the rectifiers' 15 ability to go down. But, based on our corrective 16 action program, we have fixed those and we have 17 made sure that availability was always at the 18 higher point more than 80 percent, as we always 19 adhere to.

20 MEMBER STETKAR: I'm not sure that I 21 got a straight answer to my question. Over the 22 life of the plant, I would like to know what the 23 historic percentage availability has been if I take 24 the time up divided by the total time the plant has 25 been operating as a percentage. You have told me NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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42 1 that you had corrective action programs and things 2 were out of service for a long time. But what is 3 the average historical availability over the life 4 of the plant?

5 MR. KHONDKER: For that, I will have to 6 go through my trending database.

7 MEMBER STETKAR: Great. Thank you.

8 MR. KHONDKER: And then, I have to find 9 it out for you.

10 MEMBER STETKAR: Thanks.

11 MR. KHONDKER: But, since I took over, 12 it has been over 80 percent.

13 MEMBER STETKAR: Okay. Thanks.

14 MEMBER RICCARDELLA: Does cathodic 15 protection have any influence on this selective 16 leaching process?

17 MR. BERG: The answer is, no, it does 18 not, but our very piping is coated and it is 19 protected from that standpoint.

20 MR. MURRAY: Yes, I was going to make 21 sure we got back to that as well, to break that 22 tie. That was, for example, the picture that you 23 saw was not an underground cathodic-protected area.

24 MEMBER BALLINGER: It is very difficult 25 to use cathodic protection for this problem, yes, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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43 1 because it is a very local system.

2 MR. BERG: Okay. Moving on, wrought 3 material is not susceptible, as we have already 4 discussed. The susceptible component population, 5 castings will be replaced. Just a feel for that, 6 400 to 450 castings in the plant. We will replace 7 those prior to the period of extended operation.

8 And again, our focus on our open item 9 is associated with welds or weld repairs with 10 susceptible weld filler material. It will be 11 managed. That includes piping butt-welds and, 12 also, weld preparers on extruded tees.

13 MEMBER STETKAR: Is that 400 to 450 per 14 unit or per the site?

15 MR. BERG: Per the site.

16 MEMBER STETKAR: Thanks.

17 MEMBER BALLINGER: But castings are 18 susceptible, but you haven't had a problem with the 19 castings, except I read in the SER you had a lot of 20 valve bodies and all kinds of things that were.

21 So, you have had that problem?

22 MR. BERG: Yes.

23 MEMBER BALLINGER: But, with the 24 welding, how are you going to get around the 25 problem with welding? Because you still have the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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44 1 solidification issue. Are you going to post-weld 2 heat-treat? What are you going to do to get rid of 3 that problem?

4 MR. BERG: Okay. So, we will talk 5 about that when we go through the open issue, but 6 it is really with the one-time inspections and with 7 the periodic inspection, particularly the welds 8 with the backing rings.

9 What we do to address that is we would 10 use a weld filler material with nickel in it.

11 MEMBER BALLINGER: Yes, okay.

12 MR. BERG: We have found that would 13 prevent having the transformed region.

14 MEMBER BALLINGER: It is like a Class 15 IV. Okay.

16 MR. BERG: Okay. So, to get into the 17 open item, our open item, the STP has responded to 18 NRC staff's questions associated with selective 19 leach in aluminum bronze. We did send a response 20 in on September 28th.

21 Just to talk a little, we do have a 22 comprehensive aging management program that 23 addresses selective leaching. That program 24 includes inspections of walkdowns, replacements 25 prior to the period of extended operation. Then, I NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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45 1 am going to talk specifically associated with the 2 welds. It includes one-time volumetric exams, 3 periodic volumetric examination, defines acceptance 4 criteria, and has additional testing elements in 5 it.

6 The specific open item is related to 7 welds, and the Safety Evaluation Report does 8 contain 10 specific issues, which I will discuss 9 further on the following three slides.

10 DR. SCHULTZ: Mike, I've got a general 11 question related to the recent history for the 12 program. Of course, the overall discussion goes 13 back many years.

14 But, in this year, you put together a 15 fully-revised, well, I will call it a fully-revised 16 program because there were many issues associated 17 with Rev. 1 of the program. And now, this Rev. 2 18 program was submitted to the staff in June of this 19 year.

20 And my question is general, in that, 21 once that was submitted, then there were many 22 questions from the staff related to the new and 23 revised program. So, my general question is, why 24 did that happen? You had a lot of experience with 25 the program moving forward. You had the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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46 1 opportunity or made the choice to put in a fully-2 developed to address a number of concerns that the 3 staff had had over the years really. And yet, 4 there were a number of issues that were not, if you 5 will, fully addressed in the new program where you 6 had the opportunity to really set yourself up for 7 full success. And yet, there has been a number of 8 issues in many different areas that the staff found 9 needed additional attention. So, my question is 10 that: why did that happen? Can you give me some 11 perspective on that or give us some perspective on 12 that?

13 MR. BERG: So, there are several phases 14 that I think we have gone through here. First, our 15 first focus was on the casting-type material. I 16 said before we have got about 400 to 450 of those.

17 I believe it is about 56 of them, of the large 18 border castings that we have found that the 19 alloying on, again, as we talked about earlier, 20 with a little bit of copper oxide on the outside 21 surface so far.

22 Our real focus was on the casting-type 23 area. We did a lot of research, testing, did bin 24 testing and strength tied to the de-alloying of our 25 casting materials. Lots of correspondence and NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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47 1 interaction took place between us and the Nuclear 2 Regulatory Commission, and we just ended up in the 3 point of all of that to go to that reasonable 4 assurance to the level that was expected for that; 5 that the easiest answer to that was just to go 6 ahead and replace the castings. And we were doing 7 selective replacements just to do testing anyway.

8 So, that was a change in the program.

9 And then, the next phase came in 10 associated with the welds themselves. Okay?

11 Again, that assurance that, from a welding 12 standpoint, that we would not expect to see any 13 cracks in the future or, even more important, that 14 we don't see anything that would impact the 15 structural integrity of our essential cooling water 16 system.

17 We think we have had that, but there 18 were a series of questions that we had to go 19 through to answer and to come up with some 20 additional research or evaluation of the welding 21 itself just to demonstrate that.

22 DR. SCHULTZ: So, as you revamped the 23 program, you really went broader in terms of those 24 specific areas that you determined you needed to 25 address? So, the scope of the program grew NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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48 1 dramatically --

2 MR. BERG: Correct.

3 DR. SCHULTZ: -- based on lessons 4 learned? And you, then, look at these additional 5 items as a reasonable level of issue that needed to 6 be resolved, given that you have revamped a major 7 part of the overall program?

8 MR. BERG: That is correct.

9 DR. SCHULTZ: Thank you.

10 MR. BERG: Okay. Let's get into the 11 specific 10 issues for our particular open item.

12 So, the first one -- and I am going to do this at a 13 high level -- we added information to bound 14 extruding piping tee repairs. We have about 17 15 tees, extruded tees. Extruded tees are not 16 susceptible to selective leaching, but they do have 17 weld repairs on them. So, part of this is that we 18 will evaluate those repairs. We are just going to 19 make a conservative assumption that that repair is 20 cracked, okay, and then, look at it from that 21 standpoint of structural integrity of that tee. If 22 we cannot demonstrate structural integrity under 23 that condition, we will replace that tee prior to 24 the period of extended operation.

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49 1 monitored to address. First is loss of material 2 due to selective leaching, which is monitored 3 through our system walkdowns and destructive 4 examinations. Cracking associated with selective 5 leaching is monitored through volumetric 6 examination of destructive evaluation. And the 7 third area is our root passes phase distribution is 8 verified to be discontinuous phase during our 9 destructive inspections.

10 Item No. 3, clarify the sample size for 11 volumetric inspections. As I said earlier, we will 12 do a one-time inspection on 20 percent with a 13 maximum of 25 welds with and also another sample 14 without backing rings prior to the period of 15 extended operation. And then, we will do periodic 16 examination every 10 years on 20 percent with a 17 maximum of 25 welds with backing rings, just to 18 validate from an aging management standpoint that 19 there is not something that we missed in there.

20 Four, clarify the thresh --

21 MEMBER RICCARDELLA: Excuse me. Is 22 that different weld, a different 25 percent for the 23 initial inspection versus the subsequent, the 24 periodic?

25 MR. BERG: An answer would be yes to NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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50 1 that because, when we do the destructive 2 examination, we will --

3 MEMBER RICCARDELLA: Oh, it is a 4 destructive?

5 MR. BERG: It is a destructive --

6 MEMBER RICCARDELLA: I'm sorry, I 7 thought it was --

8 MR. BERG: Yes. We do the volumetric, 9 but to look at the phase distribution, it is going 10 to end up being destructive.

11 MEMBER RICCARDELLA: Okay. And you 12 said there is only about 100 of these welds out 13 there?

14 MR. BERG: There is actually about 3300 15 welds in the plant.

16 MEMBER RICCARDELLA: So, you said 20 17 percent was 25 welds. I don't understand.

18 MR. BERG: Well, the criteria we use is 19 20 percent. A standard in the GALL would be 20 20 percent or 25. So, we are meeting the GALL 2 21 requirements on our sample size.

22 So, we have got about 3300 welds total.

23 About a third of those, or about 1100 of them, have 24 backing rings.

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51 1 answered?

2 MEMBER RICCARDELLA: I thought I heard 3 you say a one-time inspection of 20 percent which 4 is about 25 welds. And I don't understand how that 5 fits with 3300 welds total.

6 MEMBER STETKAR: The criteria, the GALL 7 criteria says 20 percent or a maximum of 25.

8 MEMBER RICCARDELLA: Oh, oh, oh, oh.

9 Okay. Yes.

10 MR. BERG: So, I am staying with the 11 GALL requirements, but, in reality, it is 25.

12 MEMBER RICCARDELLA: Okay. All right.

13 All right.

14 MEMBER BALLINGER: Is that a rational 15 choice?

16 (Laughter.)

17 I mean, I can understand sticking with 18 the letter of the law, okay, but you have a known 19 issue which you think you are going to have solved, 20 which you might have. And so, to just arbitrarily 21 say we're just going to do 25 and get it over with 22 and move on just doesn't seem to me -- I mean, is 23 there a way, is there some kind of rapid expansion 24 that would occur if you see an issue that is also 25 different from the GALL requirements? You know, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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52 1 this is a unique set of cases, I think.

2 MR. BERG: So, that does get into the 3 next item here. Okay? So, let me try to answer 4 your question a little bit more basic to start 5 with.

6 So, again, this condition, we have not 7 seen any crack in the welding since 1994. We have 8 done some research and testing that we believe that 9 we understand why that is the case. We do believe 10 it is a preexisting flaw that seems to be there.

11 So, you expect to see with a preexisting flaw 12 sometime early in life you can see the propagation 13 to the surface. So, we think we fully understand 14 why we haven't seen anything since 1994. We think 15 the 25 sample size is adequate to do confirmation 16 on what we have cut open. We have also cut open 17 some other samples of other removed castings and 18 looked at those as part of coming up with our 19 criteria. So, the 25 is to meet the GALL 20 requirements, but we do believe that that is 21 perfectly acceptable, that condition.

22 If we do find one that doesn't meet the 23 criteria, we would go back to the Generic Letter 24 90-05 criteria. And for every one that we would 25 find that doesn't meet our predictions, we would NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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53 1 increase that sample size by five until we had no 2 welds that had issues on them. So, we will follow 3 the Generic Letter --

4 MEMBER BALLINGER: By five or a factor 5 of five?

6 MR. BERG: By five.

7 MEMBER BALLINGER: By five.

8 MEMBER RICCARDELLA: How are the 25 9 samples selected?

10 MR. BERG: Okay. So, that is No. 5 on 11 the bottom of the page, and those will be randomly 12 selected from the total population of above-ground 13 welds, considering construction and size 14 distributions. We will use ASME Code criteria to 15 do that.

16 MEMBER BALLINGER: Okay. Randomly 17 selection, with this kind of phenomenon, can't you 18 get a little bit less random? Because when you do 19 welding and stuff like that, you can record heat 20 input and all those kinds of things. So, is there 21 another set of criteria which you can overlay on 22 this that says we'll do this random 23 characterization, but this particular weld and this 24 particular weld, in our judgment, may be a little 25 bit more susceptible? Can you modify the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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54 1 randomness a little bit?

2 MR. BERG: I don't know.

3 MEMBER BALLINGER: Modified randomness, 4 I'm not sure that is a good --

5 MR. BERG: Yes. I mean --

6 DR. SCHULTZ: But the question is, 7 should you modify the GALL process?

8 MR. BERG: Yes, I'm not sure what 9 criteria that we could actually use to be able to 10 do any more. We use the standard welding process 11 for all the pipe. Again, you are looking focused 12 mainly on those pipes with backing rings to go 13 after. But, because it is a standard process that 14 we used, I am sure that we would see anything where 15 we could say this particular welder or this 16 particular heat, you know, is any different.

17 We have gone back and looked at the 18 heats. We have looked at where we stand with 19 respect to the amount of aluminum in our weld 20 filler material. I'll tell you, it is pretty 21 standard percent aluminum that goes through that 22 whole thing.

23 So, I am really not aware of any 24 criteria that we can use to try to --

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55 1 bronze weld material is going to be better, much 2 better.

3 MR. BERG: Absolutely.

4 MEMBER BALLINGER: But right at the 5 interface between the weld and the heat-affected 6 zone there is going to be a wrought material which 7 is not going to be wrought anymore.

8 MR. BERG: Yes.

9 MEMBER BALLINGER: It is going to be at 10 the melting point and, then, it is going to be 11 requenched. And so, I am wondering whether or not 12 the welds will be fine, but right, you know, 13 adjacent to the weld where that thermal transient 14 has happened, you don't get gamma phase in the 15 piping itself and now get yourself in an issue 16 there.

17 MR. BERG: So, again, you start off 18 with less than 8 percent. So, if you look at the 19 phase diagram for the wrought material, you know, 20 being less than 8 percent, you would not expect to 21 go through a transformed region.

22 MEMBER BALLINGER: I agree.

23 MR. BERG: And --

24 MEMBER BALLINGER: But, again, you are 25 going to melt some of that material.

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56 1 MR. BERG: Right.

2 MEMBER BALLINGER: In the 3 solidification process there is a chance that you 4 will get a region during the solidification process 5 where you go where you are above 8 percent.

6 MR. BERG: Okay.

7 MEMBER BALLINGER: Okay. I am just 8 curious as to --

9 MR. BERG: For two pieces of that, I 10 have got an expert here I can call upon. But the 11 other piece is, when we look at the root pass of 12 the weld, one of the differences there, it is very 13 rapidly-cooled.

14 MEMBER BALLINGER: Yes.

15 MR. BERG: So, we have actually looked 16 at that and --

17 MEMBER BALLINGER: Okay.

18 MR. BERG: -- it looks like it is like 19 a maximum of 36 seconds to cool it down. So, there 20 is really not adequate time, even if you end up 21 with greater than 8 percent type of aluminum 22 content, to go to the transformed region. And if 23 you do get some in there, you are usually, instead 24 of at the gamma-2 phase, you are at the beta phase.

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57 1 saying usually --

2 MR. BERG: That is 25, which is less 3 acceptable and it is discontinuous in nature.

4 MEMBER BALLINGER: Okay. You know the 5 old saying: the great tragedy of science is the 6 slaying of a beautiful hypothesis by a ugly fact.

7 MR. BERG: Yes.

8 MEMBER RICCARDELLA: But as your OE 9 indicated any problems at all with the wrought 10 side, with the piping side of the weld?

11 MEMBER BALLINGER: The wrought material 12 is never a problem.

13 MEMBER RICCARDELLA: No, but it is the 14 weld. You are talking about the heat effect has on 15 the weld, but --

16 MEMBER BALLINGER: Yes, right where it 17 has been solidified.

18 MEMBER RICCARDELLA: Yes.

19 MR. BERG: The answer is no to that 20 question. And going one step further, when we have 21 seen an issue, it has been due to a weld defect 22 that was already there as part of the original 23 construction.

24 MEMBER RICCARDELLA: And it was in the 25 weld, not in the heat-affected zone?

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58 1 MR. BERG: In the weld, correct.

2 MEMBER RICCARDELLA: Okay.

3 MEMBER BALLINGER: But don't you have 4 two issues, cracking and de-aluminization?

5 MR. BERG: Yes.

6 MEMBER BALLINGER: So, I'm talking 7 about the de-aluminization part, not the cracking 8 part.

9 MR. BERG: So, the de -- I will try to 10 get there.

11 MEMBER BALLINGER: It is too many 12 syllables.

13 (Laughter.)

14 MR. BERG: Yes. So, the de-alloying 15 going on in the casting pipe region, we are taking 16 care of that. And we have seen a lot of that 17 without any, you know, preexisting --

18 MEMBER BALLINGER: Okay.

19 MR. BERG: -- flaws or anything else.

20 When we get into the welds, we do see 21 some de-alloying in the weld surfaces, but 22 everything is telling us it is due to that 23 preexisting flaw. Probably just created an 24 environment because of the type crack and the 25 aqueous condition in there, it has created an NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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59 1 environment that did allow anything in the 2 transformed region to show that de-alloying 3 occurred, maybe weakened the material a little bit, 4 and then, allowed cracking and, then, de-alloying 5 and cracking as it propagates through. We don't 6 really know that for a fact, but what we do know is 7 all of our OE tells us there had to be a 8 preexisting flaw there for this condition to occur.

9 MEMBER RICCARDELLA: Just to be clear, 10 if we go to that slide 17, the picture, you have 11 never had the type of problem that you have circled 12 there on the wrought piping side of a weld?

13 MR. BERG: That is correct.

14 MEMBER RICCARDELLA: Thank you.

15 CHAIRMAN SKILLMAN: I would like to 16 move on. I want to make it clear that in your 17 prior discussion you communicated that, when you do 18 have evidence, you file a condition report because 19 of the way your tech specs are written. You do an 20 operability determination, and that operability 21 determination directs the action of the site staff?

22 MR. BERG: That is correct.

23 CHAIRMAN SKILLMAN: And with that, I 24 believe we --

25 MEMBER STETKAR: Hold on.

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60 1 CHAIRMAN SKILLMAN: Go ahead, John.

2 MEMBER STETKAR: We have got all kinds 3 of time here this morning. We don't have to rush 4 through this.

5 CHAIRMAN SKILLMAN: No, no.

6 MEMBER STETKAR: Ron, I'm not a 7 materials guy. So, you questioned first the kind 8 of random sampling notion. This is for my own 9 education.

10 In many other of these programs that we 11 have seen, not this particular one, throughout the 12 course of license renewal, where you do have a 13 large population to select from, people establish 14 what they call a risk-informed sampling program.

15 And I don't want to get into the nuances of risk, 16 but they look at places where they would be more 17 likely to find a problem, whether that is a fatigue 18 issue or whether it is cracking of small-bore 19 piping welds, or whatever, and then, sample from 20 those locations.

21 So, I'm asking you, given what we have 22 heard here, is there a more, I'll call it risk-23 informed approach that could be used, rather than 24 just randomly selecting 25 out of 3300, in your 25 opinion?

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61 1 MEMBER BALLINGER: See, I am not a risk 2 guy. So, I hesitate to use the word "risk," but I 3 will use it anyway.

4 That is what I was trying to get at.

5 Basically, modifying the random sample business, 6 knowing that under certain conditions the 7 possibility is that you will get a more susceptible 8 area, so that is exactly what I am suggesting.

9 MEMBER STETKAR: But, I mean, you know, 10 based on your own experience, is there something 11 that you could think of that would sort of narrow 12 down the field a bit?

13 MEMBER BALLINGER: I would take a look 14 at the welding procedures, and you already have, 15 and decide, depending on pipe size and heat input 16 and things like that, whether or not there is a 17 possibility that you get the second phase and, 18 then, focus your randomness, if you will, on some 19 of those areas, until you discover that, yes or no, 20 we don't have an issue. And this occurs over a 21 very long period of time, though.

22 MR. BERG: Correct.

23 MEMBER BALLINGER: So, it is not like 24 you are going to have some kind of catastrophic 25 failure all the time.

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62 1 MR. BERG: Correct.

2 MEMBER BALLINGER: But you are right, 3 that is the way to do it.

4 MEMBER STETKAR: Okay. Thanks.

5 MEMBER BALLINGER: Thanks.

6 MEMBER RICCARDELLA: I'm not familiar 7 with this type of piping, but, from what I know 8 about code class piping, 25 welds out of 3300 is a 9 minuscule sample. I mean, in code class piping we 10 do typically 25 percent of the welds, and if you 11 find anything in that 25 percent, you are in doing 12 another 25 percent, and if you find anything in 13 that second 25 percent, you do 100 percent.

14 MEMBER STETKAR: But, again, that is 15 more of a question for the staff --

16 MEMBER RICCARDELLA: Yes, yes.

17 MEMBER STETKAR: -- because they wrote 18 the guidance and they are following the guidance.

19 MEMBER RICCARDELLA: Right.

20 Understood, yes.

21 MR. BERG: So, I would like to go ahead 22 and move on to slide 21.

23 CHAIRMAN SKILLMAN: Yes, please 24 proceed, yes.

25 MR. BERG: Okay. Item No. 6, we did NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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63 1 determine that there was no impact of the external 2 coatings regarding detecting buried piping leaks at 3 the surface.

4 Seven, we have identified a method to 5 monitor our trend results.

6 I would like to focus a little bit more 7 on Item No. 8, define the acceptance criteria for 8 the weld defects. For visual exams, the acceptance 9 criteria is no detectable leakage. For volumetric 10 examination, it would be no detected twiner 11 indication that is subsurface-connected unless the 12 depth of the indication is contained within the 80 13 percent of the weld root pass. And for destructive 14 examinations, no selective leaching penetrating 80 15 percent of the root pass region, and any found 16 selective leaching is non-propagating. So, it is 17 surrounded by a non-continuous resistant phase 18 distribution.

19 And then, the microstructure of the 20 weld root region will exhibit a non-continuous 21 phase distribution, which is consistent with all of 22 our metallurgical evaluation or metallurgical 23 reports that we have done so far. So, we see a 24 non-continuous phase distribution. So, if you had 25 a little localized de-alloying, it is not going to NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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64 1 have any depth associated with that, being a non-2 continuous.

3 Item No. 9, identify the threshold for 4 increased inspections when adverse inspection 5 results are detected. We talked about that a 6 little bit earlier. That is tied back to Generic 7 Letter 90-05.

8 And the last item is to identify the 9 corrective actions to address all potential 10 inspection results. We will remove any leaking 11 welds and destructively exam to determine the 12 extent of the cracks, the extent of the selective 13 leaching, and the microstructure phase 14 distribution, perform five additional volumetric 15 exams, and perform a structural integrity 16 evaluation to confirm the load-carrying capacity.

17 Move on to the next slide. So, this 18 brings us into one remaining open issue associated 19 with the corrective actions. This remaining issue 20 concerns how to address the extended condition in 21 the unlikely condition that structural integrity 22 evaluation does not support the load-carrying 23 capability or capacity.

24 A method and acceptance criteria to 25 bound the extended condition is being defined. We NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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65 1 have had some initial communications with the NRC 2 staff, and we do feel comfortable that we can 3 address that concern, and it does support a pathway 4 forward and timely response and resolution.

5 DR. SCHULTZ: Mike --

6 MR. BERG: Yes?

7 DR. SCHULTZ: -- just before you get to 8 the conclusion, as you presented it, the addressed 9 issues, you have presented your response to the 10 staff and you feel you have agreement with the 11 staff that, in fact, your responses have been 12 accepted? And it is only Item No. 10 that has not 13 been fully resolved? You have provided a response, 14 but, then, the staff had additional questions 15 related to that?

16 MR. BERG: Yes, an additional question 17 is what we are working with the staff on to 18 address.

19 DR. SCHULTZ: Okay.

20 MR. BERG: And again, we do feel that 21 we have a pathway to timely resolution of that --

22 DR. SCHULTZ: On Item No. 10?

23 MR. BERG: -- item, yes.

24 MR. MURRAY: Yes, it could be 25 characterized as initial conversations on that --

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66 1 DR. SCHULTZ: Okay.

2 MR. MURRAY: -- with the understanding 3 of the strategy.

4 DR. SCHULTZ: Thank you.

5 MEMBER KIRCHNER: I should have asked 6 this earlier. How many linear feet of pipe 7 comprises this system with the aluminum bronze and 8 how much of it is buried underground? Just an 9 estimate. I'm not holding you to exact numbers.

10 Where I am getting at is most of your visual at 11 least inspections will be --

12 CHAIRMAN SKILLMAN: Well, buried 13 underground versus buried where else?

14 (Laughter.)

15 MEMBER KIRCHNER: Well, you know, 16 inaccessible.

17 CHAIRMAN SKILLMAN: Oh, okay. Just 18 making sure.

19 MEMBER KIRCHNER: Sure.

20 MR. BERG: I would say I am really 21 giving you kind of an estimate, just based on where 22 our essential cooling water intake structure is to 23 our Class 1E structures -- you can choose a little 24 bit further away -- so, I would say about 3,000 25 foot underground would be my estimate associated NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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67 1 with that.

2 MEMBER KIRCHNER: And that, the 3 component of piping that is underground, that is 4 primarily welded. The flanges that you have had 5 problems with are at the actual above-ground 6 equipment?

7 MR. BERG: Yes. So, I will make it 8 real clear. There are no castings or cast material 9 underground.

10 MEMBER KIRCHNER: Okay. Thank you.

11 Thank you.

12 MEMBER RICCARDELLA: But, then, above 13 ground -- there's 3,000 feet below underground --

14 then, what is the remainder of the system, 15 approximate? I'm sorry. Just ballpark, what is 16 the remainder. If you have 3300 welds, I imagine 17 it is a lot of feet.

18 MR. BERG: Yes, there's several 19 thousand feet. We have 30-inch pipe; we have 4-20 inch pipe, 10-inch pipe through the plant. I'm 21 thinking in the several thousands, 13,000-ish.

22 Kevin or Rick?

23 MR. STARK: Good afternoon. Rick 24 Stark, the Pipe Program Engineer at South Texas.

25 Buried underground piping, between the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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68 1 two units, supply and return, is just over 24,000 2 feet.

3 MEMBER RICCARDELLA: Buried? Buried?

4 MR. BERG: And that is essential 5 cooling water piping?

6 MR. STARK: That is correct. That is 7 all essential cooling water piping. There is 6-8 inch, 10-inch, and 30-inch.

9 MR. BERG: I was off by a factor of 10 eight.

11 Thanks, Rick. Thank you.

12 MEMBER SUNSERI: Hey, Mike, I hate to 13 keep picking on this, but this acceptance criteria 14 for the weld defects, I am confused on it. When 15 you go out and do your 25 inspection, you are going 16 to look at these welds and you are going to apply 17 this criteria?

18 MR. BERG: Right.

19 MEMBER SUNSERI: Is that correct? So, 20 you are going to look at it to see if it is not 21 leaking? You are going to do a volumetric 22 examination to see if there is anything inside of 23 it? And then, you are going to cut it out to do a 24 metallurgy examination?

25 MR. BERG: A metallurgy examination.

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69 1 MEMBER SUNSERI: So, essentially, you 2 are replacing 25 every inspection period then, 3 right?

4 MR. BERG: That is correct.

5 MEMBER SUNSERI: Okay. Thank you.

6 MR. BERG: Okay. So, in conclusion, 7 following the resolution of that remaining issue 8 related to corrective actions, the selective 9 leaching of Aluminum Bronze Aging Management 10 Program, effectively, we will manage the aging of 11 the essential cooling water cast components and 12 welds during the period of extended operation.

13 MEMBER BALLINGER: Can I get one thing?

14 I'm still fuzzy. You have got several miles, 15 kilometers, of buried piping. You are going to 16 take 25 welds, presumably not buried?

17 MR. BERG: That is correct.

18 MEMBER BALLINGER: Okay. And the 19 reason you don't have to take any of the welds from 20 the buried piping is because there is no cast 21 material buried?

22 MR. BERG: Not really. Because if it 23 is a cast material, we will replace the castings 24 prior to the period of extended operation.

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70 1 replace the castings?

2 MR. BERG: And when we replace that 3 weld, we will use the nickel-based material. So, 4 it won't be vulnerable to it.

5 MEMBER BALLINGER: So, of the 6 underground piping, that will fall into a category 7 where it has either been replaced, the casting has 8 been replaced, or it is wrought material and, 9 therefore, there is no selective leaching issue for 10 the underground piping? Is that what I'm hearing?

11 MR. BERG: For the underground? So, 12 the underground piping is only wrought material 13 already. That is what exists now. So, we will use 14 -- so, from a stress standpoint, the above-ground 15 welds are higher-stress conditions; they are more 16 vulnerable -- so, we will use our operating 17 experience from the above-ground welds for any 18 decisions associated with expansion of scope. And 19 this really ties back in the corrective action, 20 depending on what we see.

21 Again, we think all of our research 22 shows us that we have a boundedness condition and 23 we don't expect to see anything really for the rest 24 of the life of the plant, as we haven't since 1994.

25 Our aging management program will demonstrate that.

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71 1 MEMBER BALLINGER: Thank you.

2 MR. BERG: Okay. I would now like to 3 turn it over to Dave Rencurrel for closing remarks.

4 CHAIRMAN SKILLMAN: Before we get 5 there, one of the reasons I was trying to move 6 along is I have got a couple of comments 7 independent from aluminum bronze, and perhaps my 8 colleagues have comments as well. So, may I please 9 go after those right now? I'm good for your 10 closing comments, but I would like to have this 11 opportunity with the STP staff in front to ask some 12 questions.

13 I'm in your license renewal 14 application. I'm on page 84. "Cathodic protection 15 is not in scope." Why? It is on the record in 16 your document.

17 MR. ALDRIDGE: Arden Aldridge.

18 Cathodic protection as far as in the 19 scope, let me have Mr. Warner --

20 CHAIRMAN SKILLMAN: Please do.

21 MR. ALDRIDGE: -- who can provide some 22 clarification.

23 CHAIRMAN SKILLMAN: Okay.

24 MR. WARNER: Yes, my name is Gary 25 Warner. I'm the Senior Project Manager for License NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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72 1 Renewal.

2 Cathodic protection is not in the scope 3 of license renewal because it is not one of those 4 systems that performs an intended function for 5 license renewal. It is a support system that is 6 used to allow you to protect your buried piping.

7 But, in the absence of cathodic protection, you are 8 required to inspect a lot more buried piping than 9 you would if you have adequate cathodic protection.

10 So, based on the other plants in the 11 country plus the way the rule is written, cathodic 12 protection does not perform a license-renewal-13 intended function.

14 CHAIRMAN SKILLMAN: Thank you for that 15 explanation.

16 I want to reinforce John Stetkar's 17 question about the time availability of cathodic 18 protection because in the Inspection Report the 19 Inspection Report very clearly states that there 20 was a 10-year period that there was no cathodic 21 protection. So, I would like to get the answer to 22 John's question as soon as you can get it to us.

23 MR. ALDRIDGE: Yes, sir.

24 CHAIRMAN SKILLMAN: Another question --

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73 1 you a followup on the operating experience of the 2 cathodic protection system?

3 CHAIRMAN SKILLMAN: That's correct, as 4 a percentage of time, yes.

5 On your license renewal application, 6 page 112, the statement is -- it is actually 7 2.3-27, but it is on PDF page 112 -- "The essential 8 cooling pond is included with the evaluation of the 9 essential cooling water structures in Section 10 2.4.9." Please tell us about the actions that you 11 have taken to confirm that the pond is good for 12 your projected PEO.

13 MR. ALDRIDGE: Arden Aldridge.

14 Yes, the pond is part of our aging 15 management program, the structured monitoring 16 program, and I have a subject matter expert here 17 who can give you some additional details on the 18 inspections that we have performed.

19 CHAIRMAN SKILLMAN: Please do.

20 MR. ALDRIDGE: Okay. Mark Wales.

21 MR. WALES: My name is Mark Wales. I 22 am a civil structural engineer at STP.

23 The pond, it is an underground pond.

24 That is the first thing you need to understand.

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74 1 out of the pond. But, as far as maintenance of the 2 pond, there's not really any maintenance that is 3 required. We do periodically inspect it and use 4 biocides to prevent things from growing in it and 5 in the concrete, and we inspect it as part of the 6 structures monitoring program periodically. But, 7 other than that, there is no specific maintenance.

8 CHAIRMAN SKILLMAN: Now you stated it 9 is underground. Is it really a surface pond or an 10 underground pond?

11 MR. WALES: Below grade, that would be 12 a better word for it. The surface water is 2 feet 13 below the ground level.

14 CHAIRMAN SKILLMAN: Okay.

15 MR. ALDRIDGE: And I can add a little 16 clarification, too. It is not only with the 17 Structures Monitoring Aging Management Program, but 18 the pond is specifically managed under the Water 19 Control Structure's Aging Management Program that 20 has the different inspections that are performed 21 for silting and volume validation and conditions.

22 So, it is managed there from that perspective.

23 CHAIRMAN SKILLMAN: Okay. Thank you.

24 Let me bring your attention to page 9-25 12 in your license renewal application. This is NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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75 1 under TLAAs. The subject is your studs, nuts, 2 flanges. But, in this particular section, you are 3 silent on inserts. And the table that you show 4 shows inserts with cumulative usage factor greater 5 than one. So, do you have someone here who can 6 explain the relationship between studs, nuts, 7 flanges, and inserts? I understand the CUF for the 8 studs, nuts, and flanges, but I do not understand 9 CUF greater than one for inserts.

10 MR. LYNCH: My name is Bret Lynch. I 11 worked on the time-limiting aging analyses.

12 For standard practice, when we were 13 developing the South Texas application, we took a 14 40-year CUF, Cumulative Usage Factor, and 15 multiplied it by 1.5 to get an estimate of what the 16 CUF would be. On that criteria, we decided either 17 the current CUF was projected to the end of the 18 period of extended operation, which was one of the 19 disposition criterias. If it was over one in this 20 case, we would have to justify managing the usage 21 factor to ensure that the 40-year one would be good 22 for 60 years. So, we were keeping the same number, 23 the design transients, from 40 years for 60 years.

24 CHAIRMAN SKILLMAN: Okay. Now hold 25 that thought. That suggests in this case, and in NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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76 1 other texts in your application, your TLAA depends 2 upon your cycle-counting program.

3 MR. LYNCH: That is correct.

4 CHAIRMAN SKILLMAN: Okay. What is the 5 pedigree of that cycle-counting program and how 6 does the plant manage that program? What is the 7 pedigree and how do you manage it?

8 MR. LYNCH: Well, we did perform a 9 baseline to get the current number of transients 10 currently. And then, it is an ongoing program at 11 the plant. I do not own that program.

12 MR. BERG: So, I will just add to it.

13 Really, it is procedurally-controlled under our 10 14 CFR Appendix B Program. Okay? And Mike Garner is 15 our engineer that does that cycle counting and 16 manages that program for us.

17 CHAIRMAN SKILLMAN: Okay. Thank you.

18 Let me see if I have any more here.

19 (Pause.)

20 I'll ask my colleagues, any comments 21 for the Applicant relative to this matter?

22 MEMBER STETKAR: Yes. They make me do 23 this. It's the voices in my head, I think. But I 24 have to ask this for every license renewal 25 applicant.

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77 1 Inaccessible underground cables, I 2 understand and I read back in 2011-2012, as the 3 program was evolving, there were a lot of RAIs. I 4 understand that your program is now consistent with 5 GALL Rev. 2, is that correct?

6 MR. ALDRIDGE: That is correct.

7 MEMBER STETKAR: Okay. Thank you.

8 I noticed that, as I read through 9 things, you have manholes that have solar-powered 10 sump pumps in them. And as best I can tell, you 11 have committed to what is in GALL Rev. 2, which is 12 an annual inspection of manholes or I would 13 categorize it as an episodic inspection if you 14 have, you know, a typical -- I used to do 15 consulting work down at South Texas and they used 16 to call them South Texas frog floaters.

17 (Laughter.)

18 So, you had a particularly heavy rain.

19 As best as I can tell, it is says that, 20 if an inspection determines that a sump pump is 21 inoperable, you will put it into your corrective 22 action program and fix it. Are those sump pumps 23 alarmed? I mean, is there a better indication of 24 whether they are operating or inoperable than just 25 simply finding that there is water in the manhole NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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78 1 and the sump pump wasn't working?

2 MR. ALDRIDGE: Yes, sir. The short 3 answer is they are not alarmed.

4 MEMBER STETKAR: Okay.

5 MR. ALDRIDGE: However, we do monitor 6 those, and over the years we have improved our 7 inspections there. And the subject matter expert 8 is present.

9 MEMBER STETKAR: Okay.

10 MR. ALDRIDGE: And we are doing some 11 enhancements.

12 MEMBER STETKAR: The reason I am 13 curious is because not only episodic events, but 14 you have had a history of groundwater.

15 MR. ALDRIDGE: Correct.

16 MEMBER STETKAR: So, it is a pretty 17 low-lying area --

18 MR. ALDRIDGE: Yes.

19 MEMBER STETKAR: -- and groundwater 20 intrusion is pretty pervasive.

21 MR. ALDRIDGE: Right.

22 MEMBER STETKAR: So, I was curious.

23 So, if I could hear what you are doing about those, 24 I would appreciate it.

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79 1 Khondker. I'm the cable program owner at South 2 Texas Project.

3 The question is regarding the sump 4 pumps in our manholes at STP and what we are doing 5 about it. At present, we have solar pumps designed 6 in all the manholes where we have seen water 7 submergence issues. The solar pump design that we 8 have, we have been maintaining them through our 9 preventive maintenance program. We have, depending 10 on what kind of manhole it is and how often, we 11 have seen the trend showing how often the 12 groundwater incurs. We have frequencies from four 13 weeks all the way to annually, depending on which 14 manhole it is, and we go in and inspect the pumps 15 on them.

16 And if we see that a float switch or a 17 pump or any of the control mechanisms are not 18 working, we replace it as a part of the PM. I will 19 say, if there is any water at the floor level, we 20 pump it out.

21 At present, also, what we are doing as 22 a corrective action is that we have redesigned all 23 our pumps. We have a new approved design change 24 package which is allowing me to go and replace all 25 the pumps we have. We are putting higher-duty NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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80 1 pumps. Like we have in the higher ones we are 2 putting 2,000 gallons per hour. In some of them we 3 are putting 1500 gallons per hour, and some of them 4 are below 1,00 gallons per hour.

5 So, these designs are going in as we 6 speak. We are coming out of the outage, and those 7 pumps will be going in as solar pump designs, so 8 that we can keep all the manholes dry.

9 MEMBER STETKAR: Good. That is 10 encouraging.

11 MR. KHONDKER: Yes. In total, we have 12 an estimate of 96 pumps that is going to be put --

13 MEMBER STETKAR: Ninety-six, wow.

14 MR. KHONDKER: Ninety-six solar pumps 15 are going in manholes because we have 155 manholes, 16 and out of them, 96 have seen historic --

17 MEMBER STETKAR: Since I have got you 18 up and on the --

19 MR. KHONDKER: Yes.

20 MEMBER STETKAR: -- carpet here, you 21 said 155 manholes. Is that 155 in scope for 22 license renewal or just 155 total?

23 MR. KHONDKER: No, they are not all in 24 scope.

25 MEMBER STETKAR: Yes.

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81 1 MR. KHONDKER: It is a combination 2 because we are looking at manholes, so we look at 3 them all as similar, yes.

4 MEMBER STETKAR: Sure, sure, sure, 5 sure.

6 MR. KHONDKER: Not just in scope, no.

7 MEMBER STETKAR: Great. Thank you.

8 MR. KHONDKER: No problem, sir.

9 MR. MURRAY: This is Mike Murray.

10 I do want to point out that you talked 11 about the frog floaters. We have also improved the 12 sealing, the external sealing of those manholes as 13 well.

14 MEMBER STETKAR: Yes, I have read some 15 of the operating experience. Thank you.

16 CHAIRMAN SKILLMAN: Colleagues, any 17 further questions, please, for the Applicant?

18 MEMBER RICCARDELLA: Yes, you indicate 19 you have your plant-specific program for nickel 20 alloys. As I recall, South Texas is somewhat 21 unique in having had a cracking of the bottom head 22 instrument nozzles. Is that part of your plant-23 specific program or is there anything special you 24 are doing on that topic?

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82 1 a specific on the nickel alloy program, on the 2 scope? Is that what it is for?

3 MR. ALDRIDGE: In regards to VMI, 4 right?

5 MEMBER RICCARDELLA: Yes, yes.

6 MR. GARNER: Are you referring to VMI?

7 MEMBER RICCARDELLA: Uh-hum.

8 CHAIRMAN SKILLMAN: Please identify 9 yourself.

10 MR. GARNER: My name is Michael Garner.

11 I'm the Site Metallurgist for STP.

12 The inspections for VMI will fall under 13 the code case, the guidelines described in the code 14 case, in 722, where we do a VE, a visual 15 examination, an enhanced visual examination, every 16 other year looking at 100 percent penetrations on 17 VMI. And then, every other year that isn't a code 18 inspection, we do a visual as well. It is not 100 19 percent, but it is looking for gross leakage.

20 MEMBER RICCARDELLA: Okay. Thank you.

21 CHAIRMAN SKILLMAN: Okay. Colleagues, 22 any further questions?

23 (No response.)

24 Dave, to you, please, sir?

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83 1 and we would like to thank the ACRS for your 2 questioning.

3 And I would also like to thank the 4 staff. I did not recognize our subject matter 5 experts who came here, too. We brought a little 6 bit under two dozen folks to come and ensure that 7 we had the right answers to your questions.

8 And one point I would like to make is 9 we started off by talking about the robust quality 10 assurance program, Appendix B. We are very 11 committed to the quality assurance program at South 12 Texas. As you heard here, leveraging that 13 independent oversight is one way we know that the 14 commitments we are making are being carried out.

15 With that, I would like to thank you 16 for your time.

17 CHAIRMAN SKILLMAN: Yes, sir. Thank 18 you very much.

19 With that, ladies and gentlemen, we 20 will take a 16-minute break and we will resume at 21 quarter after 10:00 on that clock.

22 We are in recess.

23 (Whereupon, the foregoing matter went 24 off the record at 9:57 a.m. and went back on the 25 record at 10:15 a.m.)

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84 1 CHAIRMAN SKILLMAN: Ladies and 2 gentlemen, we are back in session.

3 To those who are on the bridge line, we 4 respectfully request that you put your phones, *6, 5 on mute. We can hear your family background.

6 (Laughter.)

7 We would like you to please silence 8 your phones, so that there is no background noise 9 affecting other members of the public that are 10 listening in. Would you please do that?

11 Also, Greg Pick, are you there, please?

12 MR. PICK: Yes, I am.

13 CHAIRMAN SKILLMAN: Thank you.

14 Greg is our inspector. We want to make 15 sure that our recon team is onboard. He is.

16 With that, let's begin. Lois, to you, 17 please.

18 MS. JAMES: Thank you.

19 Good morning, Chairman Skillman and 20 Members of the License Renewal Subcommittee.

21 My name is Lois James, and I'm the 22 License Renewal Project Manager for the South Texas 23 Project, or STP, license renewal safety review.

24 We are here today to discuss the review 25 of the STP license renewal application, or LRA, as NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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85 1 documented in the Safety Evaluation Report with 2 open items which was issued in October.

3 Joining me here at the table today are 4 Dr. Allen Hiser, the DLR Senior Technical Advisor; 5 Mr. Bill Holston, Senior Mechanical Engineer, and 6 Ms. Phyllis Clark, Project Manager, who will be 7 running the slides. Mr. Greg Pick, Senior Reactor 8 Inspector in Region IV, is on the phone and will 9 discuss the 71002 inspection results. Sitting in 10 the audience and the phone are other members of the 11 technical staff who participated in the review and 12 conducted several audits and inspections.

13 Next slide, please. I will begin the 14 presentation with a general overview of the staff 15 review. Next, Mr. Pick will present the 71002 16 inspection results. I will, then, present the main 17 sections of the Safety Evaluation Report. Mr.

18 Holston will discuss the open item on the Selective 19 Leaching of Aluminum Bronze Aging Management 20 Program, or AMP.

21 Next slide, please. STP Nuclear 22 Operating Company, or Applicant, submitted an 23 application for the renewal of STP Units 1 and 2 24 operating licenses for an additional 20 years. The 25 staff conducted onsite audits, offsite audits here NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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86 1 in Maryland, and onsite inspections. As you can 2 see, the staff performed additional audits of the 3 open item for selective leaching of aluminum 4 bronze, AMP.

5 During the scoping and screening 6 methodology audit, the team reviewed the 7 Applicant's administrative controls governing the 8 scoping and screening methodology and the technical 9 basis for select scoping and screening results.

10 The scoping and screening methodology audit results 11 were documented in a report dated September 6th, 12 2011.

13 During the AMP audit, the team examined 14 the Applicant's aging management programs and 15 related documentation to verify that the 16 Applicant's programs are consistent with those 17 described in the GALL Report and with the plant 18 conditions and operating experience. The staff 19 reviewed the initial 40 AMPs and documented the 20 results in a report dated September 22nd, 2011.

21 In January of 2016, the Applicant 22 informed the staff of significant changes to the 23 Aluminum Bronze Selective Leaching AMP. These 24 changes redirected the staff's review such that the 25 topic-specific audits conducted in 2012 and 2015 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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87 1 were no longer applicable.

2 In 2016, the staff conducted an audit 3 of the Revised Aluminum Bronze Selective Leaching 4 AMP in two parts. During the week of March 21st, 5 the staff went onsite at STP and, then, a followup 6 day on June 22nd in the NEI offices in Rockville.

7 The audit focused on material 8 information, material process information, 9 microstructure information, and structural 10 integrity evaluations regarding the welds that may 11 be susceptible to selective leaching needed in 12 order for the staff to complete its review.

13 The results of the audit were 14 documented in a report dated August 30th. Region 15 IV will discuss the activities and results of the 16 71002 inspection in a few minutes.

17 Next slide, please. The staff 18 performed its review of the STP LRA and documented 19 its results in two Safety Evaluation Reports with 20 open items. In February of 2013, the staff issued 21 an SER with four open items. We did not come to an 22 ACRS meeting because the staff continued its review 23 of the selective leaching of the Aging Aluminum 24 Bronze AMP. We were uncertain about where the 25 review was going and we thought it was premature to NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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88 1 come to the ACRS at that time.

2 As stated in 2016, the Applicant 3 informed the staff of significant changes to this 4 AMP. The staff was able to make progress in its 5 review and issued an updated SER with open items in 6 October. The Final SER will include the resolution 7 of the open item regarding the aluminum bronze 8 selective leaching.

9 Next slide, please. I will now direct 10 the presentation to Mr. Pick to discuss the 11 inspection activities associated with the license 12 renewal review.

13 Mr. Pick.

14 MR. PICK: Thank you, Lois.

15 Good morning, Members of the 16 Subcommittee.

17 CHAIRMAN SKILLMAN: Good morning, Greg.

18 We can hear you loudly and clearly.

19 MR. PICK: Thank you.

20 So, in our inspection we verified that 21 STP had properly identified those structures, 22 systems, and components included in scope and made 23 appropriate determinations of non-safety-related 24 systems and components affecting safety-related 25 components.

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89 1 STP had established adequate programs 2 to manage aging of in-scope structures systems and 3 components, as specified in our regulations and 4 their Applicant's license renewal program.

5 The five inspectors on the team had 6 experience and expertise related to mechanical 7 systems and components, electrical systems and 8 components, and structures. Bill Holston also 9 accompanied us for one week of this inspection.

10 During our two-week onsite inspection, 11 our review included five of eight new aging 12 management programs and 14 of 32 existing aging 13 management programs. We walked down numerous 14 structures, systems, components to assess the 15 adequacy of the Applicant's license renewal 16 boundaries, in conformance with their application 17 and the Generic Aging License Renewal Report.

18 These walkdowns enabled us to assess 19 and evaluate whether the existing aging management 20 programs would be successful at managing aging 21 effects for in-scope structure systems and 22 components.

23 Next slide, please. The results of our 24 inspection. We determined that the plan had good 25 material condition. They revised two procedures.

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90 1 They added susceptibility considerations when using 2 the online fact manager, and they developed 3 guidance in the structures monitoring program to 4 allow for noting changes and trending. This 5 included things such as taking measurements, 6 providing more detailed descriptions, and the use 7 of photographs.

8 They changed two aging management 9 programs as a result of the inspection. They 10 removed the fuel supply line evaluation as part of 11 the Fire Protection Aging Management Program, and 12 they initiated corrective action documents where 13 they will begin trending requirements added for the 14 type of test and accessible medium-voltage cables.

15 And the type of tests, for example, would be power 16 factor, partial discharge, time to remaining 17 reflective time, reflect time, trending each of 18 those types.

19 They changed five application 20 commitments and the related aging management 21 programs. They changed their sampling criteria for 22 selecting fire water piping to flow tests. They 23 will need a flow test 20 percent of the piping up 24 to a maximum of 25 components during their flow 25 testing. They will look at 20 percent or a maximum NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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91 1 of 25.

2 They are going to clarify selecting the 3 representative samples frequency inspection 4 requirements for the structures. They changed the 5 frequency for inside containment to five years, as 6 an example.

7 They are going to clarify the purpose 8 of the benchmark and the essential cooling water 9 structure. They have already done that.

10 They clarified their water control 11 structure monitoring requirements, and they updated 12 the requirements to inspect the interior of their 13 metal enclosed bus boxes. Instead of using 14 external thermography, they are going to look at 15 the internals.

16 Next slide, please. As a result of our 17 inspection, we concluded that the Applicant 18 performed the scoping and screening in accordance 19 with the rule. The information was easily 20 retrievable, auditable, and consistent with the 21 rule requirements.

22 From our reviews, we verified that 23 existing programs effectively managed the aging 24 effects. We verified that the Applicant tracked 25 the completion of enhancements and development of NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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92 1 new programs and a database, as they have already 2 described.

3 Based on our inspection results, the 4 team had reasonable assurance that the programs in 5 place or planned, as described by their commitment 6 table, with manage the aging effects and ensure the 7 intended safety and function of systems, 8 structures, and components within the scope of the 9 rule.

10 Does anyone have any questions?

11 CHAIRMAN SKILLMAN: Greg, yes, I do. I 12 want to push back a little bit on the broadness of 13 your findings. I am referring to page 54 in the 14 PDF file of the SER. And here it is written, 15 "However, upon further review, subsequent to 16 submittal of the LRA, the Applicant determined that 17 the method used did not identify all non-safety 18 SSCs with the potential to impact the performance 19 of safety-related SSCs." This goes on to read, 20 "Following this determination, the Applicant 21 performed walkdowns of the applicable MAB and FHB 22 spaces and identified additional non-safety SSCs 23 with the potential to impact safety-related SSCs, 24 and provided this additional information to the 25 staff in response to RAI 2.1-3."

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93 1 Then, that paragraph concludes the 2 staff's concerns are resolved. What gives you 3 comfort that walking down the MAB and the FHB is 4 sufficient for thoroughness in this regard?

5 MR. PICK: When the team members walked 6 down the areas and did our reviews, what we saw 7 from using the drawings and looking at the safety-8 related components, the things that they said were 9 in scope were in scope. So, during our individual 10 samples, we did not identify anything that they had 11 not previously identified. So, that was the basis 12 of our statement on the sample we took.

13 CHAIRMAN SKILLMAN: Thank you. No 14 further question on that issue, Greg.

15 MR. PICK: Are there any other 16 questions?

17 MEMBER STETKAR: Yes, I had one. And I 18 think I understand, but I wasn't quite sure from 19 your oral presentation what they are doing 20 regarding the fire protection system. Are they 21 doing flow tests according to the -- I don't know 22 if they are NFPA requirements -- they are probably 23 NFPA requirements -- for flow testing.

24 MR. PICK: They do do the flow tests in 25 accordance with the NFPA.

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94 1 MEMBER STETKAR: Okay. Because you 2 mentioned --

3 MR. PICK: That is something we look at 4 during our triannual fire protection inspections.

5 MEMBER STETKAR: Okay. Good.

6 You did mention something about 20-7 percent sampling or 25 items. What's that? That 8 is not related to flow testing, though?

9 MR. PICK: No, no. I misspoke.

10 MEMBER STETKAR: Okay.

11 MR. PICK: In the report under fire 12 water system, they had identified they were going 13 to take 10 samples for volumetric examination to 14 see if there were any issues during their 15 enhancement for blockage. What they are really 16 going to do is take a 20-percent sample of the 17 piping or a maximum of 25 samples, because that is 18 what ends up statistically being the maximum they 19 would need to take of the fire water pipe 20 locations. And they are, again, going to base it 21 on location and pipe size.

22 MEMBER STETKAR: Okay. Thank you.

23 That helps clarify. Thank you.

24 CHAIRMAN SKILLMAN: Greg, this is Dick 25 Skillman. I have a question, a little different NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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95 1 topic.

2 I'm reading from our Status Report that 3 "The staff determined that the Applicant has a 4 quality Class QC4 that was not addressed in the 5 application." What can you tell us about QC4 and 6 its applicability to our deliberations today, 7 please?

8 MR. PICK: I have no knowledge of that 9 classification and I would have to defer that to 10 the licensee.

11 MS. JAMES: Actually, we have Billy 12 Rogers coming up to the microphone to answer your 13 question.

14 CHAIRMAN SKILLMAN: Thank you.

15 MR. PICK: Thank you, Lois.

16 MR. ROGERS: Good morning. This is 17 Bill Rogers from the staff.

18 So, we looked at that when we were 19 doing the scope-instituting methodology audit.

20 Many applicants have a variety of classifications 21 for components and systems onsite. And if there 22 are multiple quality classifications that might be 23 applicable to the determination of safety-related, 24 we will review those during the audit.

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96 1 classification, QC4, that it wasn't clear how that 2 related to the determination of safety-related as 3 it would be applied in the implementation of the 4 rule. So, we discussed that.

5 And the answer that was provided to us 6 during discussion and, then, in the followup RAI 7 was QC4 could actually refer to both non-safety-8 related and safety-related components. So, the 9 Applicant had reviewed all of the QC4 components 10 and determined those which are identified, those 11 which were safety-related, and include them within 12 the scope of license renewal for A1, identified 13 those which were non-safety-related, and they would 14 have been included only if they were in scope for 15 A2, non-safety affecting safety; otherwise, they 16 would have been excluded. And we determined that 17 as an acceptable response and it resolved the 18 question.

19 CHAIRMAN SKILLMAN: Thank you. Thank 20 you.

21 Please proceed.

22 DR. SCHULTZ: I have one general 23 question, Dick. I would like to ask the question, 24 as one reads through the Inspection Report -- and 25 this is to be expected -- but, as we look at NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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97 1 license renewal and aging management, as you did 2 the inspection, you had the opportunity or the 3 need, of course, to look at the corrective action 4 program, the program health reports, surveillances, 5 as you did your investigations.

6 As you reflect on those programs, 7 corrective action, program health, and 8 surveillance, that are maintained by the sites, did 9 you have any issues or particular concerns related 10 to any of those programs in general?

11 MR. PICK: During our inspection we did 12 not. I also do fire protection inspections and 13 cybersecurity inspections. When we do our baseline 14 inspections, we also take corrective action program 15 samples. We do look at surveillances, and during 16 those programs we have found that the licensee does 17 follow their tech specs, technical requirements 18 manual, do proper surveillances. And when they 19 find things wrong, they enter them into their 20 corrective action program and they resolve them.

21 DR. SCHULTZ: Did you find the 22 resolution and process that they used to be robust?

23 MR. PICK: We do.

24 DR. SCHULTZ: Thank you.

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98 1 turn it back over to Lois?

2 CHAIRMAN SKILLMAN: Colleagues, any 3 more for our inspector? Colleagues, any more for 4 the inspector?

5 (No response.)

6 Hearing none, Lois, please proceed.

7 Thank you, Greg.

8 MR. PICK: Thank you.

9 MS. JAMES: Thank you, Greg.

10 In the next few slides I will be 11 presenting the results as described in the SER with 12 open items. SER Section 2 described the scoping 13 and screening of structures and components subject 14 to the aging management review. The staff reviewed 15 the Applicant's scoping and screening methodology 16 procedures, quality controls applicable to the LRA 17 development, and training of its personnel.

18 The staff also reviewed the various 19 summaries of the safety-related systems, 20 structures, and components, non-safety-related 21 systems, structures, and components affecting 22 safety-related functions, and systems, structures, 23 and components relied upon to perform functions in 24 compliance with the Commission's regulations for 25 fire protection, environmental qualification, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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99 1 station blackout, pressurized thermal shock, and 2 anticipated transients without a scram.

3 Based on their review, the results of 4 the scoping and screening audit, and additional 5 information provided, the staff concludes that the 6 Applicant's scoping and screening methodology is 7 consistent with the standard review plan and the 8 requirements of 10 CFR Part 54.

9 Next slide. SER Section 3 covers the 10 staff's review of the Applicant's AMPs. For a 11 given aging management review, the staff evaluated 12 the item to determine whether it is consistent with 13 the GALL Report and meets the requirements of 10 14 CFR Part 54. Section 3.1 through 3.6 include the 15 aging management review items in each of the 16 general system areas within the scope of license 17 renewal. If an aging management review was not 18 consistent with the GALL Report, then the staff 19 reviewed the Applicant's evaluation to determine 20 whether the Applicant demonstrated that the aging 21 effects will be adequately managed, so that the 22 intended functions will be maintained consistent 23 with the current licensing basis for the period of 24 extended operation.

25 Next slide, please. The LRA identified NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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100 1 40 AMPs, and the Applicant subsequently added an 2 existing program in response to License Renewal 3 Interim Staff Guidance ISG-2013-01, aging 4 management of loss of coating or lining integrity 5 for internal coatings/linings or on in-scope 6 piping, piping components, heat exchangers, and 7 tanks issued in November of 2014.

8 The left side of the slide identifies 9 the Applicant's original disposition of the AMPs, 10 and the right side identifies the staff review of 11 the AMPs, as documented in the SER with open items.

12 All AMPs were evaluated by the staff for 13 consistency with the GALL Report.

14 Next slide, please. The staff closed 15 two open items associated with the aging management 16 review from the 2013 SER with open items under the 17 review of the aging management program.

18 The first open item. In reviewing the 19 open-cycle cooling water system AMP, the staff 20 found that the LRA did not describe the protective 21 coatings used in the essential cooling water 22 system, nor discuss site-specific operating 23 experience which would provide objective evidence 24 supporting the conclusion that the effects of aging 25 will be adequately managed during the period of NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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101 1 extended operation.

2 Between February and November of 2012, 3 the staff issued Requests for Additional 4 Information, or RAIs, on these topics and 5 documented an open item in the 2013 SER with open 6 items. Subsequently, in November of 2014, the 7 staff issued ISG-2013-01 which encompassed these 8 issues.

9 After reviewing the RAI responses and 10 changes in response to the ISG, the staff 11 determined that the open cycle cooling water system 12 AMP is consistent with the GALL Report and meets 13 the requirements of 10 CFR Part 54.

14 For the second open item, in reviewing 15 the one-time inspection AMP, the staff questioned 16 why the Applicant did not have an AMP to detect and 17 address cracking on the interior surfaces of the 18 RWST or other similar stainless steel tanks. If an 19 AMP is not necessary, the Applicant needed to state 20 the basis for why such an AMP was not necessary.

21 In response to RAIs, STP detailed its 22 activities to characterize the cracking on the Unit 23 1 RWST and its proposed methods to manage the aging 24 effects with both one-time and periodic 25 inspections. Based on the staff's review of the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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102 1 Applicant's response, the concerns regarding the 2 cracking in the Unit 1 RWST were resolved and the 3 corresponding open item is closed.

4 DR. SCHULTZ: Lois, did you have an 5 expectation that that might be extended to other 6 tanks?

7 MS. JAMES: Yes, the program extends to 8 other stainless steel tanks.

9 DR. SCHULTZ: But the focus here was 10 just for the RWST?

11 MS. JAMES: Well, the question rose 12 from operating experience regarding the RWST. So, 13 that is where the question started.

14 DR. SCHULTZ: All right. But, in terms 15 of the AMP program going forward, they are going to 16 be --

17 MS. JAMES: Considering it --

18 DR. SCHULTZ: -- applying it to all 19 tanks?

20 MS. JAMES: Yes. Yes, sir.

21 DR. SCHULTZ: Thank you.

22 CHAIRMAN SKILLMAN: Lois, thank you.

23 Before you leave this section on open 24 items closed -- thank you, John -- before you leave 25 this slide on open items closed, there is another NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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103 1 open item that has been closed. It is open item 2 4.3.2.11-1, the Effects of Thermal Aging on Cast 3 Austenitic Stainless Steel.

4 MS. JAMES: Yes, sir.

5 CHAIRMAN SKILLMAN: And written in the 6 documentation is this statement: "Use of minimum 7 material properties do not provide adequate 8 protection in light of information from the past 29 9 years." This item was then closed. Would you 10 please provide an explanation of how this 11 determination was made that this open item can be 12 closed?

13 MS. JAMES: Can I defer that to Section 14 4?

15 CHAIRMAN SKILLMAN: Sure.

16 MS. JAMES: I will actually address 17 that on slide 17.

18 CHAIRMAN SKILLMAN: Yes, that will be 19 fine. Thank you, Lois. Please proceed.

20 MS. JAMES: Okay. I will now turn the 21 presentation over to Mr. Holston, who will address 22 the open item, the aluminum bronze open item.

23 MR. HOLSTON: So, the aluminum bronze 24 open item, as you heard the Applicant discussing, 25 initially, the aluminum bronze program was focused NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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104 1 on about 450 cast components that were susceptible 2 to selective leaching. And in January of last 3 year, they came in and said, well, we are going to 4 replace all of those castings because we had 5 questions related to what is the real strength of 6 the component when you de-alloy part of it. When 7 you saw the picture that they showed on the slide 8 with that little area of external de-alloying or 9 the indication you could see, well, how do you 10 really project what is going on inside the pipe to 11 do your operability evaluations?

12 So, those are all being replaced.

13 That, however, left, as was discussed, about 3300 14 welds. Of course, that number will be lower when 15 castings are cut out and replaced, so you are still 16 talking about 2,000 welds, somewhere in that 17 ballpark, that are susceptible to selective 18 leaching.

19 As a result of our review of the 20 changes to the program, you heard we had about a 21 10-part open item, of which nine of those were 22 closed by a submittal that changed the program. It 23 came in in September of 2016. So, I am going to 24 focus that point forward on this.

25 So, one of the key aspects that the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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105 1 Applicant was looking at is they had not had any 2 leaks due to selective leaching in these welds, 3 these susceptible welds, since 1994. So, they did 4 some metallurgical testing. They did some 5 calculations on cooldown rates on welds and all 6 sorts of things, and then, came to postulate that 7 the root pass is less susceptible, and it is less 8 susceptible because the dilution, the higher rate 9 of dilution that occurs in the root pass and the 10 cooldown rate being higher than in subsequent 11 passes.

12 So, in effect, what would happen is 13 they have reduced the susceptibility of the overall 14 weld to selective leaching of this aluminum bronze 15 because the root pass acts as a barrier. I mean, 16 you can almost kind of think of it as, well, it is 17 kind of like a coating and it is isolating the more 18 susceptible passes of the weld from the 19 environment. If you isolate it from the 20 environment, you are not going to have selective 21 leaching occur.

22 And some, that is dependent upon not 23 having a construction-related or an in-service flaw 24 that penetrates through the root pass and, then, 25 unless you can get the environment in the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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106 1 subsequent passes that are most likely more 2 susceptible. That is where it is postulated they 3 had the through-wall de-alloying up to 1994, was in 4 welds that had, you know, construction-related 5 flaws.

6 So, as the staff and Lois talked about 7 audits we did on site, technical data we reviewed, 8 testing results we reviewed, the root pass as a 9 barrier seemed very plausible to us. However, 10 there wasn't enough testing done. The Applicant 11 had cross-sectioned, you know, about six welds.

12 That was leaning in that direction, that that was 13 plausible. So, we proceeded from that point.

14 So, we can go to the next slide, slide 15 No. 13. I just want to talk about a couple of the 16 conclusions we derived from not only looking at the 17 Applicant's results of their destructive 18 examinations, but also in a lot of review of the 19 technical literature that is available.

20 The de-alloying process occurs at a 21 microstructure level, and it is confined for a 22 localized front at scales with a grain size. Those 23 are some really cool words, right, and he is a 24 metallurgist, but what does it really say to you?

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107 1 of these welds or any material that is susceptible, 2 you basically have a front of de-alloying that goes 3 through. On one side of that front it is 100-4 percent de-alloyed; on the other side of the front 5 it is not de-alloyed. Now, of course, if you can 6 keep exposing the environment as you pass through 7 those grains, those are going to become de-alloyed 8 eventually. However, that is what it is.

9 So, the material on either side of that 10 front that goes through the material is either in 11 its as-received material properties or it is in 12 fully de-alloyed material properties. We concluded 13 from the data that the Applicant had constructed on 14 testing of material properties for the de-alloyed 15 material within the bulk component that there was 16 insufficient data to bound the mechanical 17 properties.

18 We are very fortunate to have a person 19 on staff, Chris Sevanick, who was involved in the 20 Navy Air Program, had actually been involved in 21 developing material properties from testing, and, 22 basically, had to go through all that data.

23 So, based on the number, the size of 24 the population of tests they had, and based upon 25 some of the scatter within those results, we NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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108 1 basically came to a conclusion that you would not 2 give any credit or there would be no strength 3 credit, in other words, no tensile value, for de-4 alloyed properties or fracture toughness credit.

5 Now the Applicant throughout, even back 6 in the eighties when they did their operability 7 evaluations and they did their calculations, never 8 credited any material properties for the de-alloyed 9 portions, right? And so, that is nothing new or 10 big, but it is important when we talk later about 11 structural integrity.

12 Next slide. So, given what we knew and 13 what the Applicant changed in the programs, I 14 wanted to highlight some of the key features of the 15 program that lead us to a conclusion that we are 16 down to just one last open item. And some of those 17 you have heard already.

18 But in the detection of aging effects 19 program element, the Applicant is going to do 20 volumetric inspections. These volumetric 21 inspections will look to see if there is weld 22 defects, weld defects that could be progressing 23 through the root pass, right? So, these are not 24 ultrasonic exams that are going to measure how much 25 de-alloying is going on. We are going to talk NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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109 1 about that maybe in a little bit, just as an 2 overview.

3 But those volumetric examinations will 4 provide information that, in fact, based upon a 5 representative sample, we aren't seeing, we haven't 6 seen from the last time they did these volumetric 7 examinations during the plant construction, that 8 there aren't weld defects that are propagating 9 through the root pass.

10 They are going to do destructive 11 examinations in addition. And in doing this, you 12 heard a lot about 25, 20 percent. Twenty percent 13 is immaterial in this case, right, because it is 14 25. So, there is going to be 25 volumetric 15 inspections for the welds with backing rings and 16 welds without. There is going to be 25 destructive 17 examinations of welds with backing rings and welds 18 without. So, in effect, we are going to see 50 19 welds cross-sectioned.

20 There will be continuing inspections 21 for leakage. How the licensee has been managing 22 this selective leaching since the days that it 23 started occurring is every six months they do a 24 walkdown of all the above-ground piping.

25 One of the pictures you saw or the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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110 1 picture they showed you is very characteristic of 2 what you see if you see selective leaching. I 3 actually did a walkdown with one of the Applicant 4 staff members, and there was a fitting, you know, a 5 much smaller fitting. It was about a 3-inch 6 fitting that showed that little fluorescent break 7 there.

8 Then, in addition, they look at yard 9 areas to detect if there is moisture that is 10 unusual that shouldn't be there. That would seem 11 odd. How do you that? Well, we explored that with 12 the Applicant. We looked at detailed calculations 13 that demonstrated that, if you have a 10-gallon 14 permatted leak, it will get to the surface within 15 30 days. And they have a huge margin there. They 16 have about a margin of 1,000 gallons, I mean that 17 they can tolerate.

18 I am not a hydrology expert. I looked 19 at the calculations. So, fortunately, the New 20 Reactors Organization, they had a hydrology expert.

21 He reviewed those calculations and felt that they 22 were well-bounded and well-founded. So, albeit, 23 you can't look for leakage on the outside surface 24 of the components that are buried, we can observe 25 for an indirect effect and be convinced that there NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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111 1 is no leakage going on that would affect the 2 intended function.

3 Of course, when they do opportunistic 4 buried pipe inspections, they will actually go in 5 and look at the coatings for those pipes. All this 6 piping is coated that is buried. Of course, that 7 isolates the susceptible weld layers, you know, the 8 crown pass from the environment.

9 So, that is basically what is going to 10 go on with detection of aging effects. Basically, 11 at the end of that, having done the volumetric 12 examinations to show that, yes, after that 13 representative sample, we don't see any defects 14 that are challenging the root pass, and we will 15 have 50 examinations that will actually not only 16 look at is there de-alloying going on, but it will 17 look at the phase, the actual phases within that 18 cross-section that will be sufficient to 19 demonstrate that the theory, which we think is 20 true, is that root pass is more resistant to de-21 alloying and protects the other layers of the weld.

22 And that is one reason why they haven't had any 23 leaks since 1994.

24 Yes, sir?

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112 1 presence of a backing bar affect this protection --

2 MR. HOLSTON: Well, the backing ring 3 does two things. It does one good thing and it 4 does one bad thing. There are two effects that 5 contribute to whether the welds are going to be 6 susceptible.

7 One is, with the dilution, with 8 diluting the welds, you have a lower concentration 9 of aluminum, which with the samples they have taken 10 they have demonstrated it. They can show a 11 difference across the passes as you go.

12 The other thing is the backing ring 13 allows you to have a greater heat sink, which cools 14 it down quicker. If you cool it down quicker, you 15 don't get the gamma-2 or the beta phase that are 16 susceptible to selective leaching aluminum bronze.

17 The downside of having a backing ring 18 is that it gives you kind of a notch. It gives you 19 a localized place where it can concentrate and 20 adverse chemistry that can cause a selective 21 leaching. So, that is why the Applicant 22 identified, you know, we have got a backing ring 23 population. We are going to do 25 of those. We 24 have got a non-backing-ring population. We are 25 going to do 25 of those.

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113 1 MEMBER RICCARDELLA: Okay.

2 MR. HOLSTON: So, any other questions 3 on detection of aging effects?

4 DR. SCHULTZ: Bill --

5 MR. HOLSTON: Yes?

6 DR. SCHULTZ: -- one more question. We 7 have kind of bounced back and forth between a 8 representative sample and 25.

9 MR. HOLSTON: Uh-hum.

10 DR. SCHULTZ: With regard to the 11 destructive examinations, what are the staff's 12 expectations if, when those are done, issues arise 13 as a result of the investigation? I mean, you 14 could hypothesize you do the destructive 15 examinations and you find issues.

16 MR. HOLSTON: Correct.

17 DR. SCHULTZ: What are the staff's 18 expectations of what will be done if in examining 19 25 and 25 that there are problems identified?

20 MR. HOLSTON: Can I defer that just to 21 the next slide?

22 DR. SCHULTZ: Sure.

23 MR. HOLSTON: Because I am going to 24 address that within corrective actions.

25 DR. SCHULTZ: Thank you.

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114 1 MR. HOLSTON: So, yes, I will go 2 through acceptance criteria and, then, get to that 3 and I will answer your question I think directly.

4 Any other questions on detection, how 5 they are going to detect these aging effects?

6 MEMBER SUNSERI: Yes. With regard to 7 the underground pipe and just looking for moisture, 8 or what have you, to reach the surface, was there 9 any consideration of using other techniques such as 10 ground-penetrating radar or something like that to 11 get on top of the leaks faster?

12 MR. HOLSTON: The simple answer to the 13 question is no, because there is a huge -- but the 14 answer to why is that there is a very large margin.

15 They can detect a 10-gallon-per-minute leak. They 16 can tolerate 1,000 gallons per minute. Now, 17 clearly, if they had a 1,000 gallons a minute, that 18 is going to be washing out soil. It could affect 19 structural integrity evaluations. But selective 20 leaching is not a rapidly-propagating phenomenon.

21 You know, you are not going to go from 10 gallons a 22 minute one day and now, suddenly, you are at 500 a 23 month later, right? It is just not going to 24 happen. So, that is why we didn't --

25 MEMBER SUNSERI: Yes. Thank you.

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115 1 MEMBER STETKAR: Bill, should I ask you 2 about the buried and underground piping program now 3 or should I ask you about it at all?

4 MR. HOLSTON: Well, you can ask me.

5 MEMBER STETKAR: Okay.

6 MR. HOLSTON: And why don't you go 7 ahead?

8 MEMBER STETKAR: Okay.

9 MR. HOLSTON: We might have Brian Allik 10 answer some of that. Brian Allik is taking some of 11 that over.

12 MEMBER STETKAR: Yes. Well, let me get 13 to where I was headed.

14 MR. HOLSTON: Sure.

15 MEMBER STETKAR: We heard earlier that 16 the license renewal application checked off a box 17 that said the cathodic protection system is not in 18 scope for license renewal. So, does that mean that 19 in their buried and underground piping inspection 20 program they are applying the -- I don't know 21 whether it is Category E or Category F of their 22 inspections. In other words, not taking credit at 23 all for cathodic protection? Or what are they 24 doing?

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116 1 that. What it means is, when we say the cathodic 2 protection system is not within the scope, it is 3 the wires; it is the panels; it is the rectifiers 4 that aren't in scope.

5 So, what we did was we built into Aging 6 Management Program 41 for buried and underground 7 piping the measurement of the cathodic protection 8 from two perspectives. And that is what drives you 9 to those additional inspections in Category E and 10 F, as you mentioned.

11 MEMBER STETKAR: Yes.

12 MR. HOLSTON: So, the Applicant has to 13 measure the amount of time the current is turned 14 on. Somebody trips a breaker open for something 15 and it has been off for two months, that is going 16 to be a problem, right? Because if you don't pull 17 the electricity, you are not going to get the 18 cathodic protection. So, there is a criteria for 19 that, and that is 85 percent of the time it has to 20 be on.

21 We also have a criteria, then, for the 22 effectiveness of it. And that is measured by the 23 annual cathodic protection surveys. You have to 24 demonstrate that you have negative 850 millivolts.

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117 1 in higher resistivity soils -- that is negative 750 2 or negative 650. We also allow for actually direct 3 measurement of corrosion rates. But, if you can't 4 demonstrate that you are meeting that level of 5 protection, then you have to go to E or F --

6 MEMBER STETKAR: Right.

7 MR. HOLSTON: -- and do the additional 8 inspections.

9 And what demarcates between E and F is, 10 if your plant-specific operating experience is good 11 and meets the criteria in the AMP, then your 12 cathodic protection is upright, up-to-speed, you do 13 E, which is three every 10 years. But, if you also 14 have bad operating experience, then you have got to 15 go to six every 10 years.

16 MEMBER STETKAR: Right. So, I think 17 what I hear you saying is that they will -- I 18 always hate to say "take credit" -- but they will 19 take credit for cathodic protection with all of 20 those caveats in determining the frequency and 21 extent of their piping inspections?

22 MR. HOLSTON: Right. Because, in 23 effect, what we are doing is, rather than going to 24 the panel and seeing if it is leaking --

25 MEMBER STETKAR: No, no.

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118 1 MR. HOLSTON: -- rather than checking 2 the wires, we performance monitor the effects of 3 the cathodic protection system with the 4 availability and the effectiveness.

5 MEMBER STETKAR: Yes. Thank you. That 6 helps.

7 MR. HOLSTON: Any other questions on 8 detection of aging effects?

9 (No response.)

10 Okay. For the acceptance criteria, 11 what they will do when they do the volumetric exams 12 is, obviously, they are looking for any plane or 13 flaw that would exceed 80 percent of the root pass 14 if it is connected -- you know, you could have a 15 plane or flaw within. So, here's your water. And 16 so, your inside diameter of your pipe, and you have 17 your pipe, you know, your outer edge of your root 18 pass. If it is up here, we are not really worried 19 about it. We are here with an environment 20 connected plane or flaw.

21 And with the destructive examinations, 22 the microstructure of the root region, we are 23 looking to see that we are reasonably certain they 24 are going to see some gamma-2 in the welds, right?

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119 1 want to see that that is surrounded by the alpha 2 phase which is not susceptible to selective 3 leaching. And if the gamma-2 or the beta phase 4 would exceed 80 percent of the depth of that root 5 pass, then we have an issue. And so, that is the 6 microstructure monitoring.

7 And I did have a typo -- I apologize 8 for that -- in the third acceptance criteria, which 9 is the walkdowns every six months. They will go to 10 monthlies if they have some other problems, but 11 those are just they are looking for leakage, is 12 what the acceptance criteria is for that.

13 CHAIRMAN SKILLMAN: Bill, has the 14 Applicant ever discovered a geyser? Have they ever 15 seen a leak great enough to really push water out 16 of the soil?

17 MR. HOLSTON: I looked at their 18 operating experience when I did the buried pipe 19 audit and saw none, no, sir.

20 CHAIRMAN SKILLMAN: Okay. Thank you.

21 MR. HOLSTON: Any questions on 22 acceptance criteria?

23 (No response.)

24 Okay. Next slide, and this gets to the 25 corrective actions I was talking about before that NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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120 1 Mr. Schultz was asking about.

2 So, if they find a problem within the 3 volumetrics for weld defects that are penetrating 4 the root pass, they have to do five additional 5 volumetric examinations until they see none. And 6 for the destructive examinations, the criteria is 7 the same. It is, if you see that phased 8 distribution not what we would expect, not 9 supportive of what the theory is, then you have to 10 keep doing five more until you don't see that 11 anymore. The five comes from Generic Letter 12 90-05, which the Applicant commented upon. It is 13 the NRC staff basic position when you find 14 something that is adverse that you look more until 15 you find the issue.

16 Does that answer your question?

17 DR. SCHULTZ: Yes. Thank you.

18 MR. HOLSTON: Okay. Now another 19 aspect, though, which is structural integrity 20 calculations conducted with the as-found 21 conditions, so, then, the question is, well, what 22 is a corrective action if you find an issue with 23 structural integrity?

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121 1 integrity, you have an issue with the intended 2 function of the system. And so, that is where we 3 are right now with the Request for Additional 4 Information.

5 The licensee has worked with EPRI and 6 done some testing of a UT volumetric method that 7 should be able to actually take the weld and 8 measure the amount of de-alloying that is going 9 inside, from the inside, from the ID to the OD.

10 So, what you could picture, if you are 11 looking at a ring, is here it is penetrating 60 12 percent. That would be bad, right, because it is 13 through the root pass? But, over here, it is just 14 penetrating 10 percent, and there is none down 15 here. And it just is based upon reasonable theory.

16 We were aware of Vermont Yankee doing 17 the cast iron piping. We just hadn't been aware of 18 anybody doing it for aluminum bronze welding or 19 fittings.

20 And so, our RAI talks about, well, tell 21 us how you are going to demonstrate the method, how 22 you are going to quality people, what the 23 resolution of that process is, and several other 24 questions on sampling size and all of that. So, 25 that is the remaining open item, is, what are you NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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122 1 going to do for corrective actions if the 2 structural integrity evaluation isn't acceptable?

3 CHAIRMAN SKILLMAN: Bill, as a matter 4 of admin as we look into the new year, is it these 5 RAIs that will not be presented until after March?

6 MR. HOLSTON: I don't -- well --

7 MS. JAMES: We have not issued the RAI 8 yet. So, we have to issue it. They have to have 9 their 30 days to respond and, then, we need at 10 least 30 days to look at what their response is.

11 And in this instance, we have to get 12 another division involved. So, we wanted to give 13 ourselves a little extra time to review what comes 14 in, which is why we are discussing delaying the 15 full Committee from February.

16 CHAIRMAN SKILLMAN: Thank you. I 17 understand.

18 MR. HOLSTON: The RAI has been peer-19 reviewed.

20 CHAIRMAN SKILLMAN: Okay.

21 MR. HOLSTON: It has been approved by 22 management, but we have to get it out.

23 CHAIRMAN SKILLMAN: Thank you for the 24 explanation. We were trying to get clear on timing 25 and the workload for the Committee. And this gives NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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123 1 us an explanation of what is happening. Thank you.

2 Please proceed.

3 Go ahead, John.

4 MEMBER STETKAR: I was going to say, do 5 you have more on this?

6 MR. HOLSTON: No, no, that is the end 7 of my presentation. If you have any questions --

8 MEMBER STETKAR: Let me go back to the, 9 for lack of a better term, risk-informed sampling 10 process. Is the staff good with taking a random 11 sample, you know, throwing a random number 12 generator in and taking a random sample of any 25 13 of the 3300, I think I wrote down here?

14 MR. HOLSTON: Yes, we are thinking 15 there is about 2,000. Once you cut out the 400-16 some-odd fittings --

17 MEMBER STETKAR: All right. I don't 18 want to get down too much.

19 (Laughter.)

20 MR. HOLSTON: It is a little bit less.

21 MEMBER STETKAR: But 25 out of a large 22 number --

23 MR. HOLSTON: Right.

24 MEMBER STETKAR: -- randomly 25 selected --

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124 1 MR. HOLSTON: What we did was Matt 2 Homiack, who is back here in the room, he is in 3 Research now, did some calculations, finite element 4 heat transfer calculations to determine how 5 sensitive that is. And he is coming up to the 6 microphone, and I would like to give him credit for 7 the great work he did in that regard. I think he 8 is going to have some positive answers for you.

9 MR. HOMIACK: Thank you, Bill.

10 So, the Office of Nuclear Regulatory 11 Research has been supporting NRR --

12 CHAIRMAN SKILLMAN: Excuse me, sir.

13 Identify yourself, please.

14 MR. HOMIACK: Matthew Homiack from the 15 Office of Research.

16 CHAIRMAN SKILLMAN: And, Matt, make 17 sure you speak up in the microphone, so we can 18 hear.

19 MR. HOMIACK: Will do. Thank you. Is 20 this okay?

21 CHAIRMAN SKILLMAN: Yes.

22 MR. HOMIACK: So, there is actually two 23 -- it is a smart sample. There is two sample 24 populations, first of all. One, welds with backing 25 rings and one of welds without. And I believe, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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125 1 Bill, each will get 25 destructive examinations.

2 And so, the reason for looking at those 3 differently is the welds with the backing rings 4 have the operating experience, and the welds 5 without the backing rings are more susceptible root 6 pass to de-alloying because they have a quicker 7 cooldown rate.

8 The Applicant has done some cooling 9 rate analyses, which the staff has done some 10 independent confirmatory calculations as well, and 11 we think their cooldown rates are conservative.

12 MR. HOLSTON: And Matt, in his 13 calculations, varied heat inputs, the exact 14 question you were asking. Because one of the 15 concerns we had was not so much some variation from 16 welder to welder, but if you are hanging upside-17 down and trying to make that weld versus doing a 18 flat weld, doing a vertical weld, you know, as 19 well-controlled as weld procedures are, it is a 20 little tougher to make some of those welds. And 21 would they have a higher heat input or something?

22 But the calculation, it is not really 23 -- the cooldown rate is not very sensitive to a 24 reasonable range of expectations of heat input from 25 the weld. So, the random sample is reasonable.

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126 1 Now the AMP does say, the aging management say that 2 they will take into effect construction-related 3 factors.

4 MEMBER POWERS: If I just assume that 5 they have a random population --

6 MR. HOLSTON: I'm sorry, I couldn't 7 hear you. What?

8 MEMBER POWERS: If I assume that I have 9 a random population, in other words, defects are a 10 random sort of thing, which may not be true, but 11 close enough for argument's sake, and I look after 12 three refueling inspections. So, I have a sample 13 of 75. I would probably have a 95-percent chance 14 that I have covered 90 percent of the range of 15 things.

16 So, while the number looks small, it is 17 pretty powerful if you don't have systematic 18 effects. And that, coupled with your walkdown to 19 identify systematic vulnerabilities, it appears to 20 me, though, it is 25 of a large number, the fact is 21 random sampling is a pretty powerful technique for 22 identifying outliers in that range.

23 MEMBER STETKAR: Well, except for how 24 frequently do they do this destructive examination 25 sampling.

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127 1 MR. HOLSTON: Well, if they are going 2 to do the destructive examinations, it is a one-3 time destructive examination. Because you want to 4 demonstrate with adequate data that that root pass 5 is less susceptible.

6 MEMBER STETKAR: So, the sample is not 7 after three refuelings. It is a one-time. It is 8 25. So, you have a little lower confidence.

9 MEMBER POWERS: Yes, it is a fairly 10 sharp function --

11 MEMBER STETKAR: Yes.

12 MEMBER POWERS: -- that moves up 13 rapidly.

14 MR. HOLSTON: The actual numbers are 15 that the 25 is a 90/90 certainty. That is the 16 number. So, where we have adopted that throughout 17 the GALL Report and several aging management 18 programs is, where you are demonstrating that an 19 aging effect is not likely to cause a loss of 20 intended function, we use 90/90.

21 Now, for example, when talking about 22 structural integrity, there is a challenge to 23 structural integrity, the certainty needs to be 24 higher. So, for these welds that we are doing 25 where we have seen some cross-sections, right, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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128 1 about six welds that they cross-sectioned that 2 support the theory, we want to have enough to say 3 that that is reasonable, that they are not going to 4 de-alloy through the root pass, go into the higher 5 susceptible weld passes, and then, de-alloy 6 through-wall. And so, that is why we are very 7 comfortable with the 25 and the random at this 8 point. But the RAI addresses what happens if you 9 see more consequential results --

10 MEMBER STETKAR: Yes, I didn't read the 11 RAI.

12 MR. HOLSTON: Yes. Yes, we haven't 13 given that to you yet. It is not published yet.

14 MS. JAMES: It is not publicly-15 available yet. So, it will be public and it will 16 issue in the next week or so.

17 MEMBER BALLINGER: So I have it clear 18 in my head, the weld heat input and all of that 19 stuff for the various sizes of welds, it is not 20 that much different welds. So that there is not 21 likely that there will be a distinction, there 22 would be a distinction between small diameter or 23 large diameter. That is not going to be an issue 24 that unrandomizes things, if you will?

25 MR. HOLSTON: That is correct, yes.

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129 1 MEMBER BALLINGER: Okay.

2 MR. HOLSTON: And again, we didn't just 3 -- because, well, suppose in the audience that his 4 company did some of the finite element calculations 5 for the cooldown, and we didn't just take that at 6 face value. Matt Homiack did his own independent 7 evaluations to that effect.

8 MEMBER BALLINGER: Okay. Some of us 9 remember, well, it only happens to small diameter 10 pipes. And then, well, it only happens to slightly 11 larger diameter pipes. And then, yes --

12 MEMBER RICCARDELLA: Bill, as you know, 13 the other side of risk-informing this type of a 14 selection is to look at consequences. Is there any 15 ability to distinguish from different piping 16 locations based on the consequences of failure?

17 And what are we looking at? I mean, are we looking 18 at an actual rupture that we are concerned about or 19 just a leak?

20 MR. HISER: Okay, so two parts to that.

21 We are sampling to try to demonstrate that all of 22 the 2,000 welds are okay. Are there welds that 23 would have a higher consequent? Absolutely.

24 Right, because there are welds in the main header.

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130 1 for diesel, and those would be more. There are 2 welds that are downstream of the coolers. It has 3 already done its function as long as it doesn't 4 flood the room. All it is doing is going to the 5 bay, or not the bay, to the pond, right?

6 So, we didn't factor in in any 7 selection the consequential because we are 8 confident, based upon what we have seen with the 9 testing results, also with what Matt has done with 10 the backup analyses, that what you see in a weld 11 here that is a very critical weld would be the same 12 thing because the environment is the same here; the 13 weld processes are the same, and the sensitivity to 14 the amount of heat put in with the weld is 15 virtually, you know, it doesn't really affect the 16 potential for additional beta or gamma-2. So, we 17 didn't say, make sure you do all your sampling of 18 your welds upstream or in the main header, or 19 anything like that.

20 MR. HOLSTON: Well, the consequence, 21 yes. Yes, as Allen is saying, the consequence 22 issue gets into whether what you see affects 23 structural integrity. And so, that is where we 24 have a four-page RAI to address what -- you know, 25 that is why the corrective actions for structural NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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131 1 integrity is still an open item. You know, we are 2 hopeful that this volumetric technique will be 3 something that we can accept it. Of course, with 4 the volumetric technique of that nature, they could 5 look at a lot of welds. They could zero into the 6 more consequential welds in that case. Because, to 7 date, of all the casting failures, castings are a 8 lot more susceptible than the welds are, and on the 9 weld failure side, they have not had one that 10 failed structural integrity criteria.

11 MEMBER RICCARDELLA: Question. You 12 know, when you say "structural integrity criteria,"

13 you say, well, the stresses are higher than the 14 allowable stress, or something like that. But is 15 there any concern at all about a rupture of one of 16 these or are we mainly just concerned about a leak?

17 MR. HOLSTON: Because of the very low 18 operating pressure at very low operating 19 temperatures, we are not too concerned. And they 20 have very low seismic loads, too. We looked at 21 their seismic analyses. There is nothing huge 22 there.

23 We would be more concerned with a leak 24 than we would be -- but they have done a lot of 25 analyses on the leak rates, the allowable leak NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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132 1 rates versus detectability of those leaks. And we 2 have reviewed all of that, and that is all 3 documented, that we feel they have the 4 detectability to see it before it could approach to 5 a leak that would starve the heat exchanger, or 6 whatever.

7 MEMBER RICCARDELLA: Thank you.

8 CHAIRMAN SKILLMAN: Let's proceed, 9 please.

10 Bill, thank you.

11 MR. HOLSTON: Yes, sir.

12 MS. JAMES: Okay. We are now on slide 13 16. SER Section 4 identifies the time-limited 14 aging analysis, or TLAAs. Section 4.1 documents 15 the staff's evaluation of the Applicant's basis for 16 identifying plant-specific or generic analysis that 17 need to be identified as TLAAs and determine that 18 the Applicant has provided an accurate list, as 19 required by 10 CFR 54.21(c)(1).

20 Sections 4.2 through 4.7 document the 21 staff's review of the applicable STP TLAAs as 22 shown. Based on its review and the information 23 provided by the Applicant, the staff concludes that 24 the TLAAs will remain valid for the period of 25 extended operation. The TLAAs have been projected NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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133 1 to the end of the period of extended operation or 2 the effects of aging on those intended functions 3 will be adequately managed for the period of 4 extended operations, as required by 10 CFR 5 54.21(c)(1).

6 Next slide, please. There is one TLAA 7 open item from the 2013 SER with open items that we 8 closed in this 2013 SER -- or 2016 SER. In 9 reviewing the effects of thermal aging on CASS, the 10 staff was concerned that the Applicant's thermal 11 embrittlement evaluation of CASS material in the 12 leak-before-break piping relied upon an evaluation 13 and data from 1983. The staff issued RAIs between 14 April 2011 and November 2013 and documented its 15 concerns as an open item in the 2013 SER with open 16 items.

17 In response, the Applicant stated that 18 the referenced material, fractured toughness 19 properties, for their evaluations are shown to be 20 bounding. In addition, the Applicant revised its 21 LRA to identify the fracture mechanics evaluation 22 as a TLAA and dispositioned it in accordance with 23 10 CFR 51.21(c)(1) as an analysis that remains 24 valid for the period of extended operation.

25 The staff confirmed that the Applicant NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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134 1 used a bounding fractured toughness value for its 2 leak-before-break analysis, and that the fractured 3 toughness used is applicable to 60 years.

4 Therefore, the staff concluded that the revisions 5 to the LRA are acceptable, and the open item is 6 closed.

7 Mr. Skillman, do you have more 8 questions? We have our technical reviewer in the 9 audience.

10 CHAIRMAN SKILLMAN: No. You have 11 addressed the question that I raised earlier.

12 MS. JAMES: Okay.

13 CHAIRMAN SKILLMAN: I'm good. Thank 14 you.

15 MS. JAMES: The next slide, please.

16 Pending the satisfactory resolution of the open 17 item, the staff will determine whether the 18 requirements of 10 CFR 29(a) have been met for the 19 license renewal for South Texas Project Units 1 and 20 2.

21 This concludes our staff presentation, 22 and we will now be available for any further 23 questions from the Subcommittee.

24 Thank you.

25 CHAIRMAN SKILLMAN: Lois, thank you.

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135 1 Colleagues, I invite any questions you 2 might have for the staff at this time.

3 (No response.)

4 Hearing none, I have one. There is a 5 very interesting discussion in the Safety 6 Evaluation about whether or not there are vent 7 valves on the aux feedwater pumps. And when you 8 read the text, the text is convoluted. First of 9 all, it says there are some, then there aren't 10 some. Then, some are in and some are out. And I 11 am wondering if anybody can speak to this.

12 MS. JAMES: Okay. Your question is, do 13 the feedwater pumps have vent valves?

14 CHAIRMAN SKILLMAN: Aux feedwater 15 pumps.

16 MS. JAMES: Aux feedwater pumps have 17 vent valves and are they or are they not within the 18 scope of license renewal?

19 CHAIRMAN SKILLMAN: Yes, and it is page 20 127 in the PDR file of the SER. I don't need to 21 read the text. It just seems as though there was 22 an awful lot of traffic on this subject, and I 23 found it extremely confusing. And I said, oh, wait 24 a minute, most of these pumps do have some kind of 25 a vent valve. Most of them have some valves on NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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136 1 piping that is connected to the casing. So, it is 2 not a substance of issue, but I found the text in 3 the SER very --

4 MS. JAMES: Confusing?

5 CHAIRMAN SKILLMAN: -- confusing.

6 MS. JAMES: Okay. Well, first, I will 7 take an action item to try to make sure we do 8 something with that in the Final SER.

9 CHAIRMAN SKILLMAN: It is 127 in the 10 PDR file.

11 MS. JAMES: Is that Section 2 of the 12 SER?

13 CHAIRMAN SKILLMAN: This is.

14 MS. JAMES: It has got to be.

15 CHAIRMAN SKILLMAN: It's -87.

16 MS. JAMES: 2-, yes.

17 CHAIRMAN SKILLMAN: 2-87 is the text 18 page.

19 MS. JAMES: Okay. I guess at this 20 point I'm going to have to take that as a takeaway.

21 CHAIRMAN SKILLMAN: If you would.

22 MS. JAMES: Yes.

23 MEMBER STETKAR: Maybe South Texas can 24 tell us whether or not, indeed, the aux feedwater 25 pumps have vents.

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137 1 CHAIRMAN SKILLMAN: Yes.

2 MR. GIBBS: We have vent valves.

3 MEMBER STETKAR: You actually have to 4 tell us on the record.

5 (Laughter.)

6 MS. JAMES: Yes. And identify 7 yourself, too. Thank you.

8 CHAIRMAN SKILLMAN: For those of us who 9 were plant operators, you would think there is 10 probably a vent valve out there, maybe two.

11 MR. GIBBS: Yes. Ron Gibbs, South 12 Texas operations.

13 Yes, we have vent valves on the aux 14 feedwater pumps. I don't want to lead anybody 15 anywhere, but we installed extra connections for 16 our flex. And maybe that is some of the confusion, 17 how the drawings got updated during this time 18 period. So, we will follow up with Lois to make 19 sure we get the right answer.

20 CHAIRMAN SKILLMAN: This is not a 21 substantive item, but I was being thorough, and I 22 would certainly like to understand what you are 23 communicating on page 2-87, please.

24 MS. JAMES: Okay.

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

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138 1 thank you.

2 MS. JAMES: And we will respond to you, 3 but we will also update the SER. If you had the 4 question, I am sure someone else had the question.

5 CHAIRMAN SKILLMAN: Okay. Thank you.

6 MS. DIAZ: For the purposes of the 7 staff, could you restate the question?

8 MS. JAMES: Restate the question?

9 MS. DIAZ: Yes.

10 MS. JAMES: Okay. I was asked to 11 restate the question. The question is, based on 12 the writeup on page 2-87 of the SER, it was 13 confusing as to whether or not there were vent 14 valves on the aux feedwater pumps and were those 15 vent valves within scope of license renewal?

16 CHAIRMAN SKILLMAN: That is the 17 question. Thank you.

18 MS. JAMES: And we will have to get 19 back to you on that.

20 CHAIRMAN SKILLMAN: Thank you.

21 Colleagues, at this point the staff has 22 completed their presentation. Do any of you have 23 comments for the staff, please?

24 MEMBER KIRCHNER: Dick, I have just a 25 question. I can't find it in the SER now. I NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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139 1 believe that tests were done on the baffle region 2 for vibration of reactor internals. Can you or the 3 Applicant report back on that? It is relevant to 4 Matt's earlier question about baffle bolts and what 5 you may have found as a result of that testing. I 6 think you did a scale model test of the conforming 7 region, the baffle conforming region. I just can't 8 find it. I know it is here in the SER and I can't 9 find it.

10 MS. JAMES: Okay. Jim Medoff is coming 11 to the microphone for the staff.

12 MR. MEDOFF: This is Jim Medoff of the 13 staff. I was the lead for the reactor internals 14 and I had some assistance with Mark Hughes of the 15 staff.

16 One of the things we check as part of 17 the identification of TLAAs in Chapter 4.1 is 18 whether the preopt testing for initial plant 19 operations, whether any analyses associated with 20 preopt testing are TLAAs. So, we did look at that 21 for the application. We usually would -- in most 22 applications the vibrational analyses are below the 23 endurance limit for the components. So, vibrations 24 didn't come in as a TLAA for the internals.

25 That being said, we do rely on the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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140 1 MRP-227 report and AMP XIM-16(a) for the internal.

2 Originally, this plant was one that did it under 3 commitment, but due to the delays in the aluminum 4 rods, we did make them update the LRA, update their 5 AMRs and AMPs. So now, we have reviewed the entire 6 AMP, their inspection plan, to make sure it is 7 consistent with MRP-227-A. That would include any 8 inspections of the baffle former region, including 9 the baffle formal bolts.

10 MEMBER KIRCHNER: Thank you.

11 MR. MEDOFF: Any more questions on 12 that?

13 CHAIRMAN SKILLMAN: No, sir. Thank 14 you.

15 Walt, thank you.

16 Colleagues, any other questions at this 17 point for the staff?

18 (No response.)

19 Hearing none, I would ask everybody to 20 remain in place. What we are going to do is to 21 open the phone line.

22 MR. HOWARD: The bridge is open.

23 CHAIRMAN SKILLMAN: The bridge is open.

24 Before we go to those who may be on the phone line, 25 I would like to ask if there are any individuals in NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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141 1 the audience that would like to make a statement, 2 please.

3 (No response.)

4 Seeing none, ladies and gentlemen, the 5 bridge line is open. If any individual is out 6 there, would you just please communicate that you 7 are there?

8 MR. GAVULA: This is Jim Gavula.

9 CHAIRMAN SKILLMAN: Good morning, sir.

10 Thank you.

11 Anybody else out there?

12 (No response.)

13 No?

14 For anyone that is on the line, would 15 you care to make a comment, please?

16 (No response.)

17 Hearing none, please close the bridge 18 line.

19 I would like to go around the room with 20 my colleagues to determine if there are any more 21 comments that my colleagues may have.

22 Ron, may I start with you?

23 MEMBER BALLINGER: No further comments.

24 I think I have badgered them enough.

25 CHAIRMAN SKILLMAN: Thank you, Ron.

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142 1 Pete?

2 MEMBER RICCARDELLA: Likewise.

3 CHAIRMAN SKILLMAN: Thank you.

4 Steve?

5 DR. SCHULTZ: I have no further 6 comments. I would like to thank the staff and the 7 Applicant for the discussions. Thank you.

8 CHAIRMAN SKILLMAN: Okay. Dana, 9 anything?

10 MEMBER POWERS: No.

11 CHAIRMAN SKILLMAN: Matt?

12 MEMBER SUNSERI: I appreciate the staff 13 and the Applicant's participation today, and it was 14 helpful to understand what is going on. Thank you.

15 CHAIRMAN SKILLMAN: Thank you.

16 John?

17 MEMBER STETKAR: Nothing more. Thank 18 you.

19 CHAIRMAN SKILLMAN: Walt?

20 MEMBER KIRCHNER: Thank you to the 21 presenters.

22 CHAIRMAN SKILLMAN: Okay. Our 23 Designated Federal Official, Ken Howard, any 24 questions or comments at this point?

25 MR. HOWARD: None.

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143 1 CHAIRMAN SKILLMAN: Okay. To all who 2 have participated and traveled, thank you very 3 much. I wish you a safe journey home.

4 And with that, this meeting is 5 concluded.

6 (Whereupon, at 11:20 a.m., the meeting 7 was adjourned.)

8 9

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SOUTH TEXAS PROJECT Advisory Committee on Reactor Safeguards License Renewal Subcommittee Meeting November 17, 2016

Dave Rencurrel Senior Vice President Operations 2

Agenda

• Introductions

• Station Ownership and Operation

• Site and Station Description

• License Renewal, GALL Consistency and Commitments

• Safety Evaluation Report Open Item o Aluminum Bronze Selective Leaching

• Concluding Remarks SOUTH TEXAS PROJECT ACRS SUBCOMMITTEE November 17, 2016 3

Introduction PERSONNEL IN ATTENDANCE Dave Rencurrel Senior Vice President Operations Michael Murray Manager Regulatory Affairs Mike Berg Manager Engineering Ron Gibbs Manager Operations Arden Aldridge License Renewal Project Lead Plant Staff AMP Subject Matter Experts, Licensing, Chemistry, Systems Engineering, Design Engineering, and Programs Engineering Specialty Consultants SOUTH TEXAS PROJECT ACRS SUBCOMMITTEE November 17, 2016 4

Station Ownership and Operation Operated by STP Nuclear Operating Company (STPNOC)

STP Units 1 and 2 are owned by:

• NRG South Texas LP

• The City Public Service Board of San Antonio (CPS Energy)

• The City of Austin, Texas (COA)

SOUTH TEXAS PROJECT ACRS SUBCOMMITTEE November 17, 2016 5

Plant History & Major Investments South Texas Unit 1 Unit 2 Initial License August 21, 1987 Dec 16, 1988 Steam Generator Replacement 2000 2002 Low Pressure Turbine upgrade 2006 2004 Replaced RX heads 2009 2010 Main Generator Stator rewind 2014 2012 Non-welded Stress Improvement 2017 2019 Process (RPV)

Expiration of current License August 20, 2027 Dec 15, 2028 SOUTH TEXAS PROJECT ACRS SUBCOMMITTEE November 17, 2016 6

Site and Station Description Ron Gibbs Manager Operations 7

SITE DESCRIPTION SOUTH TEXAS PROJECT ACRS SUBCOMMITTEE November 17, 2016 8

STATION DESCRIPTION SOUTH TEXAS PROJECT ACRS SUBCOMMITTEE November 17, 2016 9

License Renewal Application Arden Aldridge License Renewal Project Lead 10

License Renewal Application License Renewal Application (LRA) submitted to NUREG 1801 rev 1 10/2010 NUREG 1800 and 1801 Revision 2 issued 12/2010 Scoping & Screening, AMP Audits completed 06/2011 Scoping & Screening, AMP Inspection completed 08/2011 Annual Updates 2011, 2012, 2013 2011-2013 Issued initial safety evaluation report (SER) with open item(s) 02/2013 Safety review paused 2/2013-12/2013 RAIs, LR-ISG incorporation into LRA 1/2014-Present Annual Updates 2014, 2015, 2016 2014-2016 Issued safety evaluation report (SER) with open item 10/2016 SOUTH TEXAS PROJECT ACRS SUBCOMMITTEE November 17, 2016 11

Aging Management Programs and GALL

• Total Aging Management Programs - 41

• Existing Programs - 33 (3) plant specific

• New Programs - 8 (1) plant specific

• Plant Specific

- Nickel-Alloy

- PWR Reactor Internals

- Protective Coating Monitoring and Maintenance

- Selective Leaching of Aluminum Bronze

• Aging evaluations are greater than 90% consistent with GALL Rev 1 and greater than 95% consistent with GALL Rev 2 (standard notes A through E)

• GALL Revision 2 lessons learned incorporated through license renewal application supplement and reviewed by the NRC using Standard Review Plan Rev 2.

SOUTH TEXAS PROJECT ACRS SUBCOMMITTEE November 17, 2016 12

GALL Consistency Consistency Table AMPS AMPS AMPS Consistent Consistent with AMPS with Plant AMPS Consistent with Exception & Exceptions Specific Enhancements Enhancements New (8) 3 4 1 Existing (33) 5 13 11 1 3 Total AMPS (41)

SOUTH TEXAS PROJECT ACRS SUBCOMMITTEE November 17, 2016 13

License Renewal Commitments License Renewal commitments - 46 total

- Program Enhancements (4 complete, 26 open)

- Program Implementation (1 implemented , 9 open)

- Replace 6 Standby Emergency Diesel Generator bellows (open)

- Remove Safety Related Check Valve Seal Caps (complete)

- Review NUREG/CR-6260 (Enhanced Fatigue Monitoring locations (open)

- Take ground water samples for 24 consecutive months to assure non aggressive (complete)

- Calculate Essential Cooling Water leakage rates to validate maximum flaw size (complete)

- One time internal inspection of Unit 1 Refueling Water Storage Tank (RWST) bottom and side welds. (open)

SOUTH TEXAS PROJECT ACRS SUBCOMMITTEE November 17, 2016 14

License Renewal Commitments and Implementation License Renewal commitments are included in UFSAR Supplement (Appendix A to the LRA) and managed through the STP Condition Reporting and Licensing Commitment Management and Administration processes.

SOUTH TEXAS PROJECT ACRS SUBCOMMITTEE November 17, 2016 15

Safety Evaluation Report Open Item Mike Berg Engineering Manager 16

OI 3.0.3.3.3-2 Aluminum Bronze Selective Leaching SOUTH TEXAS PROJECT ACRS SUBCOMMITTEE November 17, 2016 17

Selective Leaching of Aluminum Bronze Background Wrought Material is non-Susceptible Susceptible Component Population - Will be replaced with non-susceptible material prior to period of extended operation Welds or weld-repairs with susceptible weld filler material will be managed

• piping butt-welds

• weld repairs on extruded tees SOUTH TEXAS PROJECT ACRS SUBCOMMITTEE November 17, 2016 18

Selective Leaching of Aluminum Bronze Aging Management Program (AMP)

STP responded to the NRCs open items related to Selective Leaching of Aluminum Bronze AMP by letter dated September 28, 2016, NOC-AE-16003403.

OI 3.0.3.3.3-2 Identified ten open issues requiring closure.

Nine of the ten open issues have been addressed. The final issue is still open but a pathway forward has been identified to assure timely resolution.

SOUTH TEXAS PROJECT ACRS SUBCOMMITTEE November 17, 2016 19

Selective Leaching of Aluminum Bronze Aging Management Program (AMP)

Addressed Issues:

1. Added information to bound extruded piping tee repairs

2. Clarified the parameters monitored to address loss of material, cracking, and phase distribution.

3. Clarified the sample size for volumetric inspections One-time examination of welds Periodic examination of welds

4. Clarified the threshold for the number of defective welds resulting in further inspections

5. Identified selection criteria for weld inspections SOUTH TEXAS PROJECT ACRS SUBCOMMITTEE November 17, 2016 20

Selective Leaching of Aluminum Bronze Aging Management Program (AMP)

Addressed Issues:

6. Determined there was no impact of the external coatings regarding detecting buried piping leaks at the surface.

7. Identified a method to monitor or trend results

8. Defined the acceptance criteria for weld defects Visual inspection Volumetric examination Destructive examination

9. Identified the threshold for increased inspections when adverse inspection results are detected

10. Identified the corrective actions to address all potential inspection results.

SOUTH TEXAS PROJECT ACRS SUBCOMMITTEE November 17, 2016 21

Selective Leaching of Aluminum Bronze Aging Management Program (AMP)

Remaining Open Issue:

10. Corrective actions do not address all potential inspection results.

Followup question is being developed by the NRC. Initial communication of the concern supports a pathway forward and timely response and resolution.

SOUTH TEXAS PROJECT ACRS SUBCOMMITTEE November 17, 2016 22

Selective Leaching of Aluminum Bronze Aging Management Program (AMP)

Conclusion:

Following the resolution of the remaining issue related to corrective actions, the Selective Leaching of Aluminum Bronze Aging Management program will effectively manage aging of the Essential Cooling Water cast components and welds during the extended period of operation.

SOUTH TEXAS PROJECT ACRS SUBCOMMITTEE November 17, 2016 23

Concluding Remarks Dave Rencurrel Senior Vice President Operations 24

END 25

Advisory Committee on Reactor Safeguards License Renewal Subcommittee South Texas Project Safety Evaluation Report (SER) with Open Items November 17, 2016 Lois M. James, Senior Project Manager Office of Nuclear Reactor Regulation

Presentation Outline

• Overview of South Texas Project (STP) license renewal review

• Region IV 71002 Inspection, License Renewal Inspection

• SER Section 2, Scoping and Screening Review

• SER Section 3, Aging Management Review

• SER Section 4, Time-Limited Aging Analyses

• Conclusion 2

License Renewal Review (Audits and Inspections)

• Scoping and Screening Methodology Audit

- May 15 - 19, 2011 (Onsite)

• Aging Management Program (AMP) Audit

- June 13 - 24, 2011 (Onsite)

• Aluminum Bronze Selective Leaching AMP Audits

- February 29, 2012 (Rockville)

- March 9 - 13, 2015 (Onsite)

- March 21 - 23 (Onsite) and June 22, 2016 (Rockville)

• Region IV 71002 Inspection (Scoping and Screening & AMPs)

- August 8 - 25, 2011 (Onsite) 3

SER Overview

• SER with Open Item (OIs) issued in 2013

• SER with OIs issued in 2016

- Closed the OIs from 2013

- Opened OI 3.0.3.3.3 Insufficient details provided regarding applicants Selective Leaching of Aluminum Bronze AMP 4

71002 Inspection

• Scope

• Non-Safety Systems affecting Safety Systems

• Aging Management Programs

• Inspection

• August 8 - August 25, 2011

• Team Inspection on-site for 2 weeks 5

71002 Inspection

• Results

- Good material condition of structures, systems and components

- Two implementing procedures changed

- Two Aging Management Programs Changed

- Revised Commitments and Corresponding Changes for five Aging Management Programs 6

71002 Inspection

• Conclusions

- Scoping and screening performed in accordance with 10 CFR 54

- Information easily retrievable and auditable

- Existing programs effectively managed aging effects

- Corrective and other actions being tracked for completion

- Reasonable assurance that aging effects will be managed and intended functions maintained 7

SER Section 2

• Structures and Components Subject to Aging Management Review

- Section 2.1, Scoping and Screening Methodology

- Section 2.2, Plant-Level Scoping Results

- Sections 2.3, 2.4, 2.5 Scoping and Screening Results 8

SER Section 3

• Aging Management Review Results

- Section 3.1, Aging Management of Reactor Vessel, Internals, and Reactor Coolant System

- Section 3.2, Aging Management of Engineered Safety Features

- Section 3.3, Aging Management of Auxiliary Systems

- Section 3.4, Aging Management of Steam and Power Conversion Systems

- Section 3.5, Aging Management of Containments, Structures and Component Supports

- Section 3.6, Aging Management of Electrical Commodity Group 9

SER Section 3 3.0.3 - Aging Management Programs Applicants Disposition of AMPs Final Disposition of AMPs in SER with OIs

• 8 new programs

• 8 new programs 3 consistent 3 consistent 4 consistent with exceptions 4 consistent with exceptions 1 plant specific 1 plant specific

• 32 existing programs

• 33 existing programs 6 consistent 5 consistent 13 consistent with enhancements 14 consistent with enhancements 3 consistent with exception 1 consistent with exceptions 8 consistent with enhancements 10 consistent with enhancements and exceptions and exceptions 2 plant specific 3 plant specific

• 1 existing program added Note: The staff received and is reviewing the 2016 annual 1 plant specific update. The final SER will be updated based on the staffs review.

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SER Section 3 Open Items Closed OI 3.0.3.2.6-2: Management of fouling of downstream components due to coating degradations upstream

• Concern: AMP may be inadequate

• Resolution: AMP was revised in accordance with staffs guidance in ISG-2013-01, Aging Management of Loss of Coating or Lining Integrity for Internal Coatings/Linings on In-Scope Piping, Piping Components, Heat Exchangers, and Tanks.

OI 3.0.3.1.4-1: Cracking in Unit 1 Reactor Water Storage Tank (RWST)

• Concern: No AMP

• Resolution: Revised the One-Time Inspection AMP to include the internal surfaces of the Unit 1 RWST; and revised External Surfaces AMP to include visual inspections of the Unit 1 RWST every refueling cycle.

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Aluminum Bronze Overview

• Applicant revised AMP in September 2016.

• Replacing all susceptible piping components that have exhibited leakage except for susceptible weld material joining nonsusceptible piping components.

• Applicant proposed a basis for why butt welds have not experienced leakage since 1994.

- Root pass less susceptible: dilution and cool down rate

- Root pass acts as a barrier

- No construction related or service induced flaws in root pass, barrier remains intact

• Root pass as a barrier seemed plausible; however, basis lacked sufficient data to substantiate 12

Staff Conclusions Based on review of tests and examinations conducted by the applicant, and the review of technical literature by the staff:

• Microstructure level dealloying process is confined to a localized front that scales with the grain size.

• Material on either side of the dealloying front is either in the as-received or fully dealloyed condition.

• Insufficient data to establish lower bound mechanical properties for dealloyed aluminum bronze.

• No strength or fracture toughness credit should be given to dealloyed material.

13

Program Element Overview September 2016, AMP revised to address most of the OI

• Detection of aging effects:

- Volumetric inspections and destructive examinations

- Visual inspections for leakage

- Opportunistic buried pipe coating inspections

• Acceptance criteria:

- Planar defect and dealloying

- Microstructure of the weld root region

- Monthly walkdowns 14

Program Element Overview, cont.

Corrective Actions:

• Additional volumetric and destructive examinations

• Structural integrity calculations conducted with as-found conditions

• Structural integrity analysis fails - additional inspections by ultrasonic testing (UT) technique capable of detecting loss of material due to selective leaching - Associated Request for Additional Information (RAI) for further information 15

SER Section 4

• Time-Limited Aging Analyses

- 4.1, Identification of Time-Limited Aging Analyses (TLAA)

- 4.2, Reactor Vessel Neutron Embrittlement Analysis

- 4.3, Metal Fatigue Analysis

- 4.4, Environmental Qualification of Electric Equipment

- 4.5, Concrete Containment Tendon Prestress Analyses

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

- 4.7, Other Plant-Specific TLAAs 16

SER Section 4 Open Item Closed OI 4.3.2.11-1: Effects of thermal aging on cast austenitic stainless steel (CASS):

• Concern: Leak-Before-Break (LBB) TLAA may not be dispositioned correctly

• Resolution: Revised LRA Section 4.3.2.11 to identify the fracture mechanics evaluation as a TLAA and disposition it in accordance with 10 CFR 54.21(c)(1)(i); and the material fracture toughness properties selected for use in the LBB analysis are sufficiently embrittled that they bound the amount of thermal embrittlement that will occur in 60 years.

17

Conclusion Pending satisfactory resolution of the Open Item, the staff will determine whether the requirements of 10 CFR 54.29(a) have been met for the license renewal of STP.

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