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| docket = 05000275, 05000323
| docket = 05000275, 05000323
| license number =  
| license number =  
| contact person = Weaver K D
| contact person = Weaver K
| case reference number = NRC-698
| case reference number = NRC-698
| document type = Meeting Transcript
| document type = Meeting Transcript
| page count = 213
| page count = 213
| project =  
| project =  
| stage = Other
| stage = Acceptance Review
}}
}}


=Text=
=Text=
{{#Wiki_filter:Official Transcript of Proceedings NUCLEAR REGULATORY COMMISSION Title:  Advisory Committee on Reactor Safeguards Plant License Renewal Subcommittee
{{#Wiki_filter: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:          Wednesday, February 9, 2011 Work Order No.:        NRC-698                          Pages 1-145 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                              DISCLAIMER 4
5 6  UNITED STATES NUCLEAR REGULATORY COMMISSIONS 7        ADVISORY COMMITTEE ON REACTOR SAFEGUARDS 8
9 10          The contents of this transcript of the 11 proceeding of the United States Nuclear Regulatory 12 Commission Advisory Committee on Reactor Safeguards, 13 as reported herein, is a record of the discussions 14 recorded at the meeting.
15 16          This transcript has not been reviewed, 17 corrected, and edited, and it may contain 18 inaccuracies.
19 20 21 22 23 24 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
(202) 234-4433          WASHINGTON, D.C. 20005-3701  www.nealrgross.com
 
2 1                    UNITED STATES OF AMERICA 2                  NUCLEAR REGULATORY COMMISSION 3                                + + + + +
4          ADVISORY COMMITTEE ON REACTOR SAFEGUARDS 5                                  (ACRS) 6                                + + + + +
7                PLANT LICENSE RENEWAL SUBCOMMITTEE 8                    DIABLO CANYON POWER PLANT 9                                + + + + +
10                                WEDNESDAY 11                          FEBRUARY 9, 2011 12                                + + + + +
13                        ROCKVILLE, MARYLAND 14                                + + + + +
15                    The  Subcommittee            met    at  the    Nuclear 16 Regulatory          Commission,          Two      White    Flint      North, 17 Room        T2-B1,    at    1:30      p.m.,        Dennis   C.      Bley, 18 Chairman, presiding.
19 20 COMMITTEE MEMBERS:
21            DENNIS C. BLEY                      Chairman 22            SAID ABDEL-KHALIK                    Member 23            J. SAM ARMIJO                    Member 24            SANJOY BANERJEE                      Member 25            MICHAEL L. CORRADINI                Member 26                                NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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3 1            HAROLD B. RAY                      Member 2            MICHAEL T. RYAN                    Member 3            WILLIAM J. SHACK                  Member 4            JOHN D. SIEBER                    Member 5            JOHN W. STETKAR                    Member at Large 6
7 ACRS CONSULTANTS PRESENT:
8            JOHN J. BARTON 9
10 NRC STAFF PRESENT:
11            NATHANIEL FERRER, NRR 12            MELANIE GALLOWAY, NRR/DLR 13            STAN GARDOCKI, NRR/DSS 14            ALLEN HISER, NRR/DLR 15            BRIAN HOLIAN, NRR/DLR 16            WILLIAM HOLSTON, NRR/DLR 17            JAMES MEDOFF, NRR/DLR 18            NEIL O'KEEFE 19            GREG PICK, Region IV 20            JEFF POEHLER, NRR/DSI 21            DAVE WRONA, NRR/DLR 22            MICHAEL BENSON, Designated Federal Official 23 24 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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4 1 ALSO PRESENT FROM PG&E 2            MICHELLE ALBRIGHT 3            CHRIS BEARD 4            JIM BECKER 5            DAVID GERBER, Structural Integrity 6                  Associates 7            DAVID GONZALEZ 8            JOE GORYANCE 9            LEE GOYETTE 10            TERRY GREBEL 11            DANIEL HARDESTY 12            MARK MAYER 13            DAVE MIKLUSH 14            CHALMER MYER 15            LOREN SHARP 16            MIRANDA TAN 17            RYAN WEST 18            DAVID WONG 19            MIKE WRIGHT 20 21 22 23 24 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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5 1                        TABLE OF CONTENTS 2                  AGENDA ITEM                                  PAGE 3 Opening Remarks, Dennis Bley, ACRS                                    6 4 Staff Introduction, Brian Holian                                      7 5 PG&E Company - Diablo Canyon Power Plant:
6    Introductions; Site & Station                                  13 7            Descriptions, Jim Becker 8    History/Major Improvements, Loren Sharp                        18 9    License Renewal Application; Open                              20 10            and Confirmatory Items, Terry Grebel 11    Flux Thimble Tube Inspection Program                            29 12            (Open Item), Mike Wright 13    Flaw Growth Evaluation for RHR (Open                            39 14            Item), Dave Gonzalez 15    Scoping and Screening (Open Items);                            55 16            Buried Piping and Tanks Inspection 17            Program (Open Item), Dave Miklush 18    TLAA Identification and Metal Fatigue                          66 19            (Open Items), Michelle Albright 20 NRC STAFF:        Nathaniel Ferrer, Greg Pick 21    SER Overview and Scoping and                                    81 22    Screening Results; Onsite Inspection Results 23    Aging Management Review; and                                  102 24    Time Limited Aging Analyses 25 Subcommittee Discussion                                          141 26                              NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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6 1                      P-R-O-C-C-E-D-I-N-G-S 2                                                      Time:    1:30 p.m.
3                  CHAIRMAN BLEY:            The meeting will now 4 come to order. This is a meeting of the Plant 5 License        Renewal      Subcommittee              of  the    Advisory 6 Committee on Reactor Safeguards.
7                  I  am    Dennis      Bley,        Chairman      of      the 8 Subcommittee.        ACRS      Members        in      attendance        today 9 are      Bill  Shack,    Mike      Ryan,      John    Stetkar,        Said 10 Abdel-Khalik,        Sam      Armijo,      Harold      Ray  and        Jack 11 Sieber.
12                  We have Tom Barton as our consultant, 13 and        Michael  Benson      is    the      Designated      Federal 14 Official for this meeting.
15                  The    Subcommittee              will    review          the 16 License Renewal Application of the Diablo Canyon 17 Power Plant, Units 1 and 2, and the associated 18 SER with open items.                We will hear presentations 19 from the NRC staff and Pacific Gas and Electric, 20 PG&E.
21                  We have received no written comments 22 or requests for time to make oral statements from 23 members of the public regarding today's meeting.
24  I    will    mention    that      the    next-door        conference 25 room is also following this meeting on the TV NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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7 1 screens.          There is an overflow audience today.
2                    The  entire        meeting        will  be    open        to 3 public attendance.                The Subcommittee will gather 4 information, analyze relevant issues and facts, 5 and formulate proposed positions and actions, as 6 appropriate,          for      deliberation            by  the        full 7 Committee.
8                    The rules for participation in today's 9 meeting have been announced as part of the Notice 10 of      this    meeting      previously          published      in      the 11 Federal Register.
12                    A transcript of the meeting is being 13 kept, and will be made available as stated in the 14 Federal Register Notice.                    Therefore, we request 15 that        participants        in    this        meeting    use        the 16 microphones located throughout the meeting room 17 when          addressing        the        Subcommittee.                    The 18 participants should first identify themselves and 19 speak with sufficient clarity and volume so that 20 they may be readily heard.
21                    We will now proceed with the meeting, 22 and I call upon Brian Holian to begin.
23                    MR. HOLIAN:          Thank you, Chairman, and 24 thank you -- Good afternoon, Subcommittee.                                    My 25 name is Brian Holian.                  I am the Director of the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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8 1 Division        of  License      Renewal,          and  we  are        here 2 today for the Diablo Canyon Subcommittee meeting.
3                    I  will      make    brief        introductions          and 4 then quickly go over the agenda and turn it over 5 to        the    licensee        for        their        part      of        the 6 presentation.
7                    To my left is Melanie Galloway, the 8 Deputy Director for Division of License Renewal.
9  Behind      us    --  I    will    just      make    a  couple          of 10 introductions, and we will repeat a few and add a 11 few for when our people come to the table, but I 12 wanted to mention that Dave Wrona is the Branch 13 Chief for Diablo Canyon sitting over there behind 14 the stanchion.
15                    The  Project        Manager,        you  will        hear 16 more from later, is Nate Ferrer, and we do have 17 two        individuals      who    escaped        Region    IV      and      a 18 quarter-inch of snow or whatever they got.                                    The 19 office        is    closed      today,        but      they    got        out 20 yesterday on a plane, and that is Mr. Greg Pick, 21 the        Senior    Inspector          from      Region    IV    --      the 22 Committee          has      seen        him        before;      he        had 23 presentations          --    and    Neil      O'Keefe,      his      Branch 24 Chief.          So I welcome them in from the cold of 25 Dallas.
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9 1                    The agenda today, as I mentioned, is 2 to look at Diablo Canyon, the third STARS plan to 3 come in for an application for a license renewal.
4  We had Wolf Creek several years ago, and then 5 Palo        Verde,    and    the      full      committee      will        be 6 hearing        from    Palo      Verde      tomorrow        morning          for 7 their final SER and the closure of their open 8 items.
9                    I      mention            that,        because,              in 10 particular, some of the items you will see both 11 in      Diablo's      presentation          and      the  staff's.            We 12 have        a  couple      of    open      items      that    are      still 13 related to scoping, and the Subcommittee might 14 wonder about that.
15                    We did see some issues on Palo Verde's 16 scoping, if you remember back on draft SER, and 17 so      I    just    highlight        that.          The  STARS    --      The 18 alliance, the STARS group, was learning from the 19 Palo Verde.          Folks are here in the audience from 20 Palo        Verde    for    tomorrow,          and    we  know        that, 21 through our license renewal quarterly meetings, 22 those lessons learned get passed on, but their 23 application was already in, and our audits were 24 already going when you see a lot of those RAIs.
25 So I think the Applicant will speak to that a NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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10 1 little bit, but I wanted to mention that.
2                    The  second        item      that    I  wanted          to 3 really mention overall for the Committee -- the 4 Committee is probably aware of it from general 5 correspondence, but I just wanted to highlight it 6 here          at  the    opening.                Diablo,      being          in 7 California, seismic issues are of concern to the 8 local population there and, of course, the staff 9 also.
10                    Last year, as the application came in 11 for      Diablo,    we  got    several        letters      in    to      the 12 staff          requesting        a      delay,          requesting          more 13 information be done first.                          Even the State of 14 California            was      interested,              besides          local 15 interested          stakeholders,          on      new    information          on 16 potential        faults      or    differences            in  the      design 17 basis.
18                    I just wanted to highlight that to the 19 Committee.          We addressed that in a July letter 20 from        the  Director      of    NRR    to      the  stakeholders, 21 saying that those issues would be best dealt with 22 under Part 50.            They are current issues.                      Right 23 now, their current licensing basis is -- although 24 there might be questions on it -- not called into 25 effect.
NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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11 1                    The    staff        even        looked  at    a      new 2 potential fault back in the '09 time frame.                              That 3 was the subject.                So I just wanted to make the 4 Committee aware that we and the Region have had 5 several          public  meetings        out      in  the  California 6 area to address that potential stakeholder item.
7  So you will see correspondence on that as you 8 look through the docket, but we consider it a 9 Part 50 issue.
10                    If    at      anytime          that  design        basis 11 changes, we would be able to either -- if it 12 happened during the license renewal, be able to 13 supplement an SER, if that was needed to be, or 14 after          the  fact    still      do      it  under    Part        50 15 processes to address their licensing basis.
16                    With that, I will turn it over to the 17 Applicant, who has the first part.                      Go ahead.
18                    MEMBER SHACK:          Can I ask you a generic 19 question.          I was looking.            You know, they came in 20 with the usual language about PWR internals, and 21 I was trying to remember.                    I saw Ginna submitted 22 an inspection plan.              Was that approved?
23                    MR. HOLIAN:          Allen Hiser, I will have 24 address that during -- or Jim Medoff, if you want 25 to wait for our staff presentation.
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12 1                    MEMBER SHACK:          Yes.
2                    MR. HOLIAN:                During      our        staff 3 presentation, we will address that.                              I know it 4 has come up recently in the GALL.
5                    MEMBER SHACK:          Yes.        The GALL actually 6 has guidance, and that was the next question, is 7 when        were    you  expecting          licensees        to    actually 8 pick up that GALL guidance and incorporate it in 9 their documents?
10                    MR. HOLIAN:          Yes.        We have been -- I 11 will          address    that        more        in      depth      in        our 12 presentation, but in general, Diablo has come in 13 here, and now there are seven to nine open items.
14  I    know    the  committees          have        seen  us    recently 15 taking our time and asking additional questions 16 to      get    plants    that      are    in-house        up    to      the 17 significant          items      of    GALL,        Rev. 2,    which          we 18 issued last December.
19                    The staff did a kind of an in depth 20 look through the significant items in there, and 21 for        the    plants    in-house,        we      thought    it      most 22 appropriate, while we have the SERs in process, 23 to ask those additional requests for information, 24 even if they submit it under GALL Rev 1.                              We just 25 thought it is the right thing to do.
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13 1                  Utilities have responded well to that.
2 So in general, we have done that, bringing all 3 the      plants  in-house      up    to      that. So    I      will 4 address it in particular on the MRP and internals 5 during our presentation.
6                  With that, I will turn it over to Mr.
7 Jim Becker, the site VP for Diablo Canyon.
8                  MR. BECKER:            Thank you, Mr. Holian.
9 So I am Jim Becker.            I am the site Vice President 10 at Diablo Canyon, and on behalf of the STARS and 11 PG&E team, it is our pleasure to be here today.
12 We look forward to a good presentation and some 13 good        questions    and    answers,          and  that    is      our 14 purpose here today.
15                  I would like to start off with some 16 introductions.          As I said, I am Jim Becker, the 17 site Vice President.
18                  MR. SHARP:          I am Loren Sharp, Senior 19 Director of Technical Services.
20                  MR. WRIGHT:            Mike Wright, Mechanical 21 Systems Engineering Manager.
22                  MR. GREBEL:            Terry      Grebel,    License 23 Renewal Project Manager.
24                  MR. BECKER:            Thank      you.      And        in 25 addition to the folks up here in front of you, we NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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14 1 have a fairly large contingent that has come out 2 to      Washington,      D.C.,      with      us,    and  those        are 3 members both of the STARS Center of Business and 4 of our own plant staff, and they have been very 5 instrumental          in      preparing            the    application, 6 responding to the requests for information, and 7 will assist us in our presentation and answering 8 questions here today.
9                  Our agenda for the day:                  We are going 10 to      start    off  with      Loren        and    I  giving          the 11 Subcommittee         an      overview          of    the    site,          our 12 history, major improvements, etcetera, that have 13 occurred at the site.
14                  Then Terry Grebel will briefly cover 15 GALL consistency and commitments, and with that 16 complete, we are then going to go into some more 17 detailed presentation about the open items, and 18 those are the items you see in front of you there 19 on the agenda.
20                  Then when we are done with that, I 21 will have some brief concluding remarks.                          So that 22 is the agenda that we have planned for you today.
23                  This slide shows a site description, 24 and        I  thought    it      would        be  good    for        the 25 Subcommittee to review with us some basic facts NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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15 1 about the site.
2                    Diablo      Canyon        is      located    on        the 3 central California coast.                      It is about halfway 4 between Los Angeles and San Francisco.                            What you 5 see here is the coastline at the site.                              Miranda 6 has      highlighted      the    Diablo        Canyon    site      itself 7 there.
8                    There are about 13,000 acres in the 9 Diablo Canyon lands that PG&E now owns, and the 10 boundary for the company owned property is shown 11 as the dark black line there.                          The closest town 12 of      any    size  is    the    town    of      Avila  Beach,        and 13 Miranda is now highlighting that.
14                    That    is    a    quick        overview    of      our 15 location on the central coast of California.
16                    DR. BARTON:          What is the population of 17 Avila Beach?
18                    MR. BECKER:          As a resident of                Avila 19 Beach, I will tell you that the population is, I 20 believe, three to four thousand people.                              It has 21 grown        a  fair  amount      in    recent        years  into        the 22 hillsides outside the direct village.
23                    Okay.          Moving          on    to  this        site 24 description slide, this is an aerial photograph, 25 and I thought it would be worthwhile to review NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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16 1 the basic layout of the site here.
2                  So    what      you      see      here    are        the 3 containment structures, Units 1 and 2.                            Unit 1 4 lies to the north.              They share a common turbine 5 building        that  you      see    laid      out  there    in      the 6 picture.
7                  We take suction at the intake, and the 8 units share a common intake structure, and they 9 also share a common discharge structure that you 10 see      in  the  picture.          Of    course,    we    have        an 11 administration building.
12                  Most of the make-up water to the plant 13 -- Actually, all the make-up water to the plant 14 flows through the raw water reservoirs, which are 15 on the hill to the east of the plant, and we 16 recently began dry cast storage operations.                                  So 17 the        ISFSI,    or      interim        spent      fuel    storage 18 installation, pad is just to the south of the raw 19 water reservoirs.              We have completed two ISFSI 20 campaigns thus far, one for each unit.
21                  Now a brief station description.                          So 22 there are two units at Diablo.                          They share a 23 common operating set of procedures and design.
24 The units are not identical, but they are highly 25 similar.        They are both 4 loop Westinghouse units NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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17 1 with a core rating of 3411 megawatts thermal.
2                    PG&E    was    the      architect/engineer              for 3 Diablo Canyon.              We were assisted in the latter 4 stages          of    the    construction              time  period          by 5 Bechtel,          and  that      got    us    to      the  point      of      an 6 actual operating license.
7                    It is a once-through cooling facility.
8  Each unit has two circ water pumps.                              At full 9 power,        we  pump    about      1.5    million      gallons        per 10 minute of ocean water through the condensers and 11 then        back    out    through        that        common  discharge 12 structure that I showed you earlier.
13                    Our containments are free standing, as 14 you see on that slide, steel-lined, reinforced 15 concrete buildings.                PG&E is the sole owner and 16 operator for Diablo Canyon.
17                    I mentioned that the plant is on the 18 central California coast.                    We are at the southern 19 end of the PG&E electric service territory.                                    We 20 do own and operate the switchyards and the high 21 voltage          transmission          system.            PG&E's    service 22 territory extends from the Oregon border down to 23 about 50 miles south of where Diablo Canyon is 24 located.
25                    So that competes my overview of the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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18 1 facility.
2                    MEMBER      RAY:        Did      you    say    anything 3 about the California ISO?
4                    MR. BECKER:            We are subject to -- Our 5 generation          is  subject        to    the      jurisdiction          and 6 regulation of the California Independent System 7 Operator, as has been the case for a bit over 10 8 years now.
9                    MR. SHARP:            Thanks, Jim.          I am Loren 10 Sharp.          I also welcome the opportunity to appear 11 in front of you to talk about license renewal 12 today.          I am the Senior Director of Technical 13 Services, and I will discuss some of the STARS 14 Center          of  Business,        plant        history      and      major 15 improvements at Diablo Canyon.
16                    Slide 9.          So the Center of Business 17 was created to form a format of consistency for 18 the seven PWR plants that are getting ready to 19 apply          or  have      applied        for        license    renewal.
20 Therefore,            we      are        providing          a    standard 21 application with additional quality stemming from 22 applying          our      operating          experience,          lessons 23 learned from the other STARS plants.
24                    Diablo          Canyon              personnel            have 25 consistently          provided        oversight,          leadership          and NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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19 1 ownership of the licensing renewal process, as 2 well        as  the    implementation                of  that      process 3 continuing into the future.
4                    Slide    10.          Unit      1    was    issued          an 5 operating power license in 1984, with Unit 2 in 6 1985.          There was a change to increase power for 7 Unit        1  to    3411,      so      that        both    units          are 8 essentially equal, and that is one of the reasons 9 why we have a common license renewal application 10 for both units.                We have -- Currently, license 11 expires in 2024 and 2025.
12                    Slide 11.
13                    DR. BARTON:          What is the status of the 14 two plants today?              Both at 100 percent power?
15                    MR. BECKER:            Yes.          Both units today 16 are at full power.
17                    MR. SHARP:          For the Slide 11, we have 18 done a number of major improvements.                            I won't go 19 through the list in total, but I would say we 20 have done significant improvements to make sure 21 we maintain our facility.                        I will discuss just 22 the steam generators and reactor heads that were 23 recently        completed        to    make      sure    we  have        the 24 quality        of  plant      that      we    need      as  we    go      into 25 license          renewal      as      well        as      the    continued NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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20 1 operation of our current license.
2                  Now I would like to turn it over to 3 Terry Grebel, our Diablo Canyon License Renewal 4 Project Manager to discuss GALL consistency and 5 some of the commitments made at Diablo Canyon.
6                  MR. GREBEL:            Thank you, Loren.                Good 7 afternoon.          My name is Terry Grebel.                    I am the 8 Diablo        Canyon  License        Renewal        Project    Manager.
9 My portion of the presentation today covers the 10 highlights        of  our      license        renewal    application, 11 including          the        aging        management        programs, 12 commitments, open items and confirmatory items.
13                  Slide 13, please.                    In preparing our 14 license        renewal    application,            we  used    the      GALL 15 Rev. 1 and NEI 95-10 Rev. 6 guidance with the 16 goal of making the application as consistent with 17 this guidance as possible.
18                  In    addition,        as      Brian    talked        about 19 earlier,        the  staff      has    recently        asked    several 20 RAIs based on recent operating experience.                                    We 21 have been responding to these RAIs as well.
22                  We have a total of 42 aging management 23 programs, 31 of which are existing.                              Nine are 24 new, and we have two plant specific programs.
25                  Our aging evaluations are greater than NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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21 1 93 percent consistent with GALL Rev 1 (standard 2 notes A through E).
3                  We      have          64        license        renewal 4 commitments,        and      these      commitments        are      being 5 tracked        through    our      Diablo        Canyon    commitment 6 tracking system, which implements the guidance of 7 NEI 99-04.
8                  Slide 14, please.
9                  MEMBER      SHACK:            There    is    only        55 10 commitments listed in the SER.                      Are these new?
11            MR. GREBEL:        These        reflect    the      latest 12 updated members' responding to the --
13                  MEMBER SHACK:          RAIs.
14                  MR. GREBEL:        -- to the open items.
15                  MEMBER SHACK:            The open items.              Okay.
16  Thank you.
17                  MR. GREBEL:          We have -- Diablo Canyon 18 SER      has  eight  open      items      and      two  confirmatory 19 items.        PG&E has submitted responses to all open 20 and confirmatory items.                    As Brian talked about 21 earlier, the staff is in the process of reviewing 22 these responses.
23                  The eight open items will be discussed 24 further by the other members of the Diablo Canyon 25 team.
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22 1                    MEMBER STETKAR:            Terry, I know you are 2 going to discuss the open items.                        I would like to 3 ask you a couple of questions about confirmatory 4 items, if I could.
5                    MR. GREBEL:          I was going to jump into 6 that next.
7                    MEMBER STETKAR:            Oh, were you?            Okay, 8 I didn't see a slide.                Go on.        I'm sorry.
9                    MR. GREBEL:          The first item dealt with 10 the        confirmatory        to    change        our  cable      testing 11 frequency        from    10    years      to    six  years.          This 12 aligns it with the GALL Rev 2.
13                    The second item dealt with our spent 14 fuel pool leak chase.                  We have a leak in Unit 2, 15 a minor leak.            We have done some inspections of 16 the      leak    chases,      and    we    have      committed      to      do 17 another inspection.
18                    The  staff      had    asked      --  We    said        we 19 would          do that    during        the      period    of    extended 20 operation.          The staff asked that, to be in the 21 one-year prior, the period of extended operation, 22 and we have since made that commitment.
23                    MEMBER      STETKAR:            Now  my  questions.
24 Start from the back first then.                        Have you made --
25 You      have    not  made      any      commitments        to    do      any NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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23 1 inspections, at least from what I have read in 2 the      SER,    of  the    Unit      1  spent      fuel  pool        leak 3 chase.
4                    Now  I    recognize          you    don't    have        any 5 identified          leakage,        but      you        don't    have        any 6 identified leakage.                  So are you confident that 7 indeed the Unit 1 spent fuel pool leak chase is 8 open?          I don't know how you measure the flow, 9 through          drains    or    whatever          --    that  they        are 10 indeed open?
11                    In other words, what I am concerned 12 about is do you have leakage that you don't know 13 about          and  haven't      confirmed          that    indeed        your 14 monitoring systems are available over on Unit 1?
15                    MR. GREBEL:            We      are  prepared          to 16 address          that.        Mike,      could      you    address        that 17 question, please?
18                    MR. WRIGHT:            Sure,      Terry.            Mike 19 Wright, Engineering.
20                    Both    units      leak      chase    systems        were 21 visually inspected in the 2006-2007 time frame 22 area,          and  both    units'        leak      chase    valves          are 23 opened weekly to verify that we measure the flow, 24 if there is any leakage past the spent fuel pool 25 liners.
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24 1                    Both    units'      leak      chase  systems        were 2 verified to be free of boron clogging.                          There was 3 no evidence of blockage on either unit at that 4 time.
5                    MEMBER      STETKAR:              I  know  that        the 6 amount of leakage on Unit 2 is pretty small, and 7 the amount of leakage, at least what I read on 8 Unit 1, is yet much smaller.                          But when you open 9 the Unit 1 valves, do you get --
10                    MR. WRIGHT:        You get nothing.
11                    MEMBER STETKAR:            -- any flow?
12                    MR. WRIGHT:            No, sir.        When we open 13 the Unit 1 valves on a weekly basis, we get zero 14 flow.
15                    MEMBER STETKAR:            You know those lines 16 are open?
17                    MR. WRIGHT:          Yes.        We inspected them 18 in 2006 time frame with boroscope.
19                    MEMBER      STETKAR:              With    boroscope?
20 Okay.          Thanks. That's what I was looking for.
21                    On the cables, I know that you have 22 committed -- With that confirmatory of the six-23 year testing, you are essentially consistent with 24 GALL Rev 2, I think, with the exception that you 25 are not doing inspections based on event driven NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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25 1 events.        If I recall correctly, just you said 2 that there was no evidence of event driven water 3 accumulation.        So I believe you took an exception 4 to that element of the inspection program.
5                I guess my question was:                  You have had 6 water accumulation in the past, years back.                                    I 7 recognize      not  in    recent      years.        What    was      the 8 source of that water, if it wasn't event driven?
9                MR. WRIGHT:            I think, in general, I 10 would like to ask my Engineering Manager, Ryan 11 West, to address that question.
12                MR. WEST:            Ryan      West,  Engineering 13 Manager, Diablo Canyon.
14                In the early Nineties, we identified 15 that our pull boxes were full of water resulting 16 in submergence of the cables.                        The causes that 17 were identified were basically that our pull box 18 drains and sump pumps were not being maintained 19 adequately, resulting in rainwater backing up in 20 the boxes.
21                MEMBER STETKAR:            So it was rainwater?
22                MR. WEST:            That is correct.              It was 23 rainwater.        We    have      not    seen      any  evidence          of 24 groundwater leaking into the pull boxes.
25                MR. WRIGHT:            Ryan, could you address NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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26 1 the inspection frequency?
2                  MR. WEST:        Yes.        Right now, we have a 3 bi-monthly inspection of the pull boxes looking 4 for evidence of water in the pull boxes.                            So it 5 is not quite event driven, but during the rainy 6 season we do look in the boxes on a bi-monthly 7 frequency.        We have the ability to defer those 8 once we get out of the rainy season and we are 9 not getting rain.
10                  MEMBER STETKAR: So in a sense, you do 11 some -- if I understand what you just said, you 12 do      inspections    more      frequently        in  the      rainy 13 season.
14                  MR. WEST:      That is correct.
15                  MEMBER STETKAR:            Okay, thanks.          I had 16 one other question on cables, which -- I have too 17 many notes here.            Oh, I just wanted to confirm.
18 Do all of your underground cable ducts, conduit 19 runs -- I don't know what the configuration is 20 there -- including whatever low voltage cables 21 that are now in scope, positively drain to low 22 points where you have sump pumps installed?
23                  What    I    am    asking        is:    Are        you 24 confident that you don't have any intermediate 25 low      points  where      water      can      collect  and      remain NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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27 1 stagnant        without      positively            draining    to      some 2 location that you can either inspect or have an 3 installed sump pump?
4                  MR. WEST:        So our operating experience 5 has identified that we have some low points in 6 our conduits.            Here on Slide 78 is a general 7 layout of our conduit arrangement where there are 8 drains that drain from pull box to pull box to a 9 low point out to a sump area which is drained out 10 to the building sumps.
11                  We have identified dips in the pull 12 boxes.        We have done -- We are in the process of 13 completing        all    of    them,        but    we  are      doing 14 inspections        of  the    accessible          portions    of      the 15 underground        loops.        We    are      also  removing        the 16 seals at the buildings, and it is promoting air 17 flow through the conduits, which is also helping 18 to keep the conduits free of water, and we are 19 going back after we have done all the inspections 20 in        the    locations        that      were      identified          as 21 containing water, we will verify that we are not 22 getting        any    in-leakage          from      damage    in        the 23 conduits.
24                  MEMBER STETKAR:            Thank you.        One last 25 question.            In      your      Generic        Letter      2007-1 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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28 1 response,          you    identified          a      number    of      cable 2 failures          due    to      water      in-leakage.              Now        I 3 understand that since then you have replaced, I 4 think it said, all of the in-scope medium voltage 5 cables.          Have    you    experienced            any  underground 6 cable failures since 2007, in other words since 7 that report was filed?
8                    MR. WEST:            We        have    experienced 9 degradation on underground medium voltage cables 10 that        had  not  been      replaced.            Of  the  replaced 11 cables, we have not seen any repeat degradation 12 or failures.
13                    MEMBER STETKAR:            Thanks.
14                    MEMBER ABDEL-KHALIK:                  The degradation 15 that you referred to was measured by, what, the 16 10 delta test?
17                    MR. WEST:        Seven of the 11 identified 18 degradations          or    failures          were      identified          by 19 ground          alarms.        We    have        a    high    resistance 20 grounding system.                So we have a single phased 21 ground        fault.      So    it    was      identified,        and      the 22 equipment          was  removed        from      service,    and        then 23 subsequently we verified through high-pots that 24 the cable was degraded.
25                    MEMBER ABDEL-KHALIK:                  Are you sure it NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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29 1 is        cable      degradation            versus        a    connection 2 degradation?
3                    MR. WEST:          Can      you    clarify    that        a 4 little bit for me?
5                    MEMBER ABDEL-KHALIK:                  The connections 6 between        cable    segments        --    Are      you  sure      that, 7 really, the problem is with the cable segments 8 themselves          or    with        the      connections        between 9 segments?
10                    MR. WEST:        So we are confident it was 11 the cables themselves.                    We don't typically have 12 splices          in    the      underground            portions    of      the 13 cables.          So we are able to isolate and validate 14 that it is the cable itself.
15                    MEMBER ABDEL-KHALIK:                Okay, thank you.
16                    MR. SHARP:            So, Mike Wright is the 17 next presenter on flux thimble tube.
18                    MR. WRIGHT:          Thank you, Loren.                Good 19 afternoon, Mr. Chairman, Committee members.                                    My 20 name          is    Mike        Wright,          Mechanical          System 21 Engineering          Manager      at    Diablo        Canyon.      I    have 22 been at the plant for 22 years and in Engineering 23 for the last 10, for 10 years.
24                    I will be presenting some background 25 information          on  a    flux    thimble        tube  leak      that NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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30 1 occurred        in  2006,      a      status        one  open        item 2 associated with flux thimbles.
3                  Slide 16, please.              Unit 2 thimble tube 4 L-13 leaked approximately four months following 5 refueling outage 2R-13 in 2006.                          The tube had 6 been        in service    for    a    little      more  than        three 7 cycles.        This  graphic        depicts        the  approximate 8 location of thimble tube L-13, and the magenta 9 boxed area would be the approximate location.
10                  Historically, L-13 was capped in 1990 11 following refueling outage 2R-3, remained out of 12 service for over 10 years until it was replaced 13 in 2001 with a tube having a 15-inch chrome band 14 designed to be centered around the highest wear 15 location, which is the bottom nozzle of the fuel 16 assembly.
17                  Slide 17, please.                More history:            In 18 2004, 2R-12, we measured approximately 47 percent 19 wear outside of the chrome band of this thimble 20 tube, approximately five feet below the bottom 21 nozzle, and the tube was pulled out five inches 22 to relocate the wear spot.
23                  Again in 2006, the subsequent outage, 24 2R-13, we measured 44 percent wear in the same 25 thimble tube in a similar location, and the tube NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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31 1 was pulled out an additional five inches, again 2 to move the wear spot.
3                    These two pulls resulted in exposing 4 the non-chrome plated portion of the thimble tube 5 to be bottom nozzle, the higher wear area of the 6 fuel          assembly.            Approximately            four      months 7 following 2R-13, L-13 leaked.                            The leakage was 8 isolated by closing a valve at the seal cable.
9                    Slide 18, please. Now I will address 10 the open item.            There are two aspects of the open 11 item, the first being that the Diablo acceptance 12 criteria does not specifically include a value 13 for      instrument      and      wear      scar uncertainty.                  We 14 were asked to verify that we have the appropriate 15 margin to account for them.
16                    Resolution:            Diablo wear methodology 17 was        compared      to      the      Westinghouse          industry 18 standard,          the  WCAP-12866          or    thimble    tube        eddy 19 current          testing      using      our      site    specific        wear 20 data.          The result of that analysis is that Diablo 21 wear        projection        methodology            was    slightly        more 22 conservative than the WCAP.
23                    The      Westinghouse              war    projection 24 methodology          acceptance          criteria        is  80  percent, 25 which        does  include      instrument          uncertainty,          and NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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32 1 currently          our    wear      projection          methodology            or 2 acceptance criteria is 68 percent, which does not 3 include uncertainty.
4                    The  difference          between      those      two      is 5 17.5          percent,      more        conservative          than          the 6 Westinghouse industry standard.                            Typical values 7 used for uncertainty are 10                      percent.      We believe 8 our        17.5    percent      margin          from    the    industry 9 standard          represents      adequate          margin    to    account 10 for instrument and wear scar uncertainties.
11                    As    a      result        of      the    L-13        cause 12 analysis,          again    from      cycle        14,    we  have      added 13 additional          nonlinear        wear      acceptance        criteria 14 that I will describe in a couple of slides.                                      In 15 total, we believe that the combination of the 68 16 percent          wear    in      addition          to    the    nonlinear 17 acceptance          criteria        is    both        conservative          and 18 comprehensive.
19                    MEMBER      STETKAR:            Mike,    let    me      just 20 make sure I understand this slide, and from what 21 I read in the SER.
22                    You  are    now      proposing        a  68    percent 23 wear acceptance criteria, and is that -- I know, 24 from what I read, you used to have that, and then 25 the WCAP was issued, and it sounded like you had NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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33 1 increased it to -- I don't know whether it was 78 2 percent or 80 percent or something like that.
3                  As a resolution of the open item, you 4 are now dropping back to the 68 percent.                          Is that 5 correct?
6                  MR. WRIGHT:          No, sir.          We have had 68 7 percent the entire time.                  We got the WCAP in the 8 Nineties,      which    said      80    percent.          We    did      not 9 adopt that number.
10                  MEMBER      STETKAR:              Oh,  I    guess          I 11 misunderstood what I read in the SER, because it 12 sounded like you had increased that limit, and 13 that is what the staff was concerned about, that 14 that        80 percent    wear      limit      did    not  adequately 15 account for the uncertainties, but you have --
16                  MR. WRIGHT:            We      have    got    the        68 17 percent number.            What we did do was remove the 18 uncertainty penalty, and that is the area that we 19 are still working with the staff to --
20                  MEMBER STETKAR:              So you are actually 21 still negotiating with the staff over this.                                  It 22 is still an open item.
23                  MR. WRIGHT:            Still working with the 24 staff to get a resolution.
25                  MEMBER      STETKAR:            Thank    you.          That NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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34 1 helps.
2                    MR. WRIGHT:            Slide 19, please.                  The 3 second          aspect  of    the      open      item    requests        the 4 additional          information            on      the      L-13        cause 5 evaluation and corrective actions.
6                    In  2R14,      L-13      was      removed    from        the 7 plant          in  2$14    following        eddy        current    testing 8 examination.          There were two high wear locations 9 that were identified greater than 90 percent on 10 the L-13 with eddy current examinations.
11                    One  was      in      the      highly    radioactive 12 region at the bottom nozzle of the fuel assembly, 13 and the other about five feet below the lower 14 core        plate    in  the    vicinity          of    the  previously 15 identified wear.
16                    When we cut the tube out to remove it 17 from the plant, we inspected both portions, the 18 highly radioactive one by video camera since it 19 was highly radioactive, the other one by touch, 20 by feel.            Due to the feel of the tube at the 21 location five feet below the lower core plate, we 22 felt that was the wear or the through-wall leak, 23 and        that    is  the    piece      that        we  sent    off        to 24 Westinghouse          to      be      examined          by    destructive 25 testing.
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35 1                  During          that            examination                by 2 Westinghouse, it was determined that the three-3 foot section we sent to them did not contain the 4 throughwall leak.            However, it did contain the 90 5 percent wear location leak as well as both the 47 6 and 44 percent wear location.
7                  The  signatures          on      the  eddy    current 8 test        of  both  the      90    percent,        the  graded          90 9 percent locations, were similar, and the cause of 10 the        wear  of  the      tube      that        we  did    send        to 11 Westinghouse was determined to be flow induced 12 wear.
13                  Based    on    this      determination          and      the 14 similarity of the two 90 percent wear locations 15 of the tube and previous Diablo tube violations 16 that we had sent back to Westinghouse -- we sent 17 tubes back to them in the early Nineties in the 18 development of the WCAP-12866 -- the cause was 19 determined        to  be      flow    induced        wear  and      plant 20 practices that allowed multiple repositioning of 21 thimble tubes.
22                  Repositioning of L-13 exposed the non-23 chrome plated portion of the tube to the bottom 24 nozzle, and then we have been doing eddy current 25 testing since 1R3, 2R3, and in all that time flow NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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36 1 induced wear is the only degradation mechanism 2 found          at  Diablo.            Cracking          has    not        been 3 identified          in      any      of      the        eddy      currents 4 examinations performed.
5                    Slide 20, please.              In resolution, this 6 is the slide that I referred to previously.                                    The 7 corrective actions to prevent reoccurrence from 8 the root cause evaluation resulted in additional 9 acceptance          criteria      to    address        the    non-linear 10 wear.          They include:          A thimble must be removed 11 from        service    or    repositioned              if  we    experience 12 greater than 25 percent wear per year, or a tube 13 has two wear scars greater than 40 percent.
14                    Additionally,          a      tube      may    only          be 15 repositioned          six    inches,        and      they    may    only        be 16 repositioned once.              I note that each of --
17                    MEMBER ABDEL-KHALIK:                If the mechanism 18 is indeed flow induced wear, do you have any idea 19 what the extent of your lower plenum anomaly is?
20                    MR. WRIGHT:            Well,        we  detect          the 21 degradation          through        100      percent        eddy    current 22 testing.          So we know the status of --
23                    MEMBER      ABDEL-KHALIK;                Lower      plenum 24 flow anomaly was in the core.
25                    MR. WRIGHT:          I'd like to get some help NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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37 1 from Mr. Mark Mayer, please.
2                    MR. MAYER:          My name is Mark Mayer.                  I 3 am at the Diablo Canyon staff.
4                    We have some information on the lower 5 plenum        anomaly,    but    we    do    not  really    see      any 6 indications of a strong lower plenum anomaly, and 7 we      can    get  you    additional          information,      if      you 8 would like that.
9                    MEMBER ABDEL-KHALIK:                And what would 10 be your indications that you are looking for?
11                    MR. MAYER:          I would have to get back 12 to you on that particular question.
13                    MR. SHARP:          The current charts we do 14 have that shows the number of them that are still 15 at that same --
16                    MR. BECKER:          Yes.      I think that would 17 give you some information about it.
18                    MR. WRIGHT:          Miranda,      if  you      could 19 move to slide Number 70.                      Slide 70 depicts the 20 current status of all 58 thimble tubes in both 21 units.          It represents that approximately half of 22 the      thimble    tubes      in    both      units  are  original, 23 non-chrome plated thimble tubes with minimal wear 24 located in various locations, and the remaining 25 half are locations where we have replaced them NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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38 1 with either 15-inch chrome plated thimble tubes 2 or a full 12-foot chrome plated thimble tube, and 3 then 11 of the tubes, total tubes, are either 4 capped or the guide tube is attached.
5                  So the flows vary in the lower portion 6 of the lower internals.                    Again, essentially we 7 used our eddy current testing to determine the 8 locations        where    we    need      to      put  the  hardened 9 outside thimble tubes.
10                  I would like to go back to Slide 20, 11 please, Miranda.              In addition, the -- Each of 12 these four acceptance criteria individually would 13 have resulted in removing thimble tube L-13 from 14 service in 2R13.
15                  Since    application          of  these    new      non-16 linear acceptance criteria, 31 tubes have been 17 removed from service in the last five refueling 18 outages.        Of these 31 tubes, 67 percent were due 19 to this exceeding the non-linear wear criteria.
20 So the message here is the additional criteria we 21 put in place has been effective in identifying 22 tubes to replace.
23                  When we do replace them, we replace 24 them        with  Westinghouse        supplied        12-foot      chrome 25 plated band to cover the entire area in the lower NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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39 1 head up through the bottom nozzle.
2                    Diablo Canyon, again, has not observed 3 any wear in a chrome plated portion of thimble 4 tubes.
5                    Slide 21, please.              In conclusion, PG&E 6 is      confident      that      the      68      percent    acceptance 7 criteria, in combination with the additional non-8 linear acceptance criteria, is both comprehensive 9 and conservative.
10                    MR. SHARP:          the      next    presenter          is 11 David          Gonzalez,      my    ISI      supervisor        at      Diablo 12 Canyon.
13                    MR. GONZALEZ:            Good      afternoon.            My 14 name        is    David    gonzalez,          and      I  am    the        ISI 15 Supervisor at Diablo Canyon.                        Today I am going to 16 discuss the open item addressing the 1997 flaw 17 analysis for Unit 1 piping weld, and the reason 18 that        this    flaw    analysis        did      not  address        the 19 stress corrosion cracking.
20                    In support of this discussion, I will 21 present          PG&E's    basis      for    concluding      that        this 22 flaw was not service related and, hence, did not 23 need        to  be    analyzed        for      a    stress  corrosion 24 cracking flaw growth.
25                    Please      note      that      we    had  previously NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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40 1 submitted          and  discussed          additional      information 2 regarding this open item.
3                    MEMBER ARMIJO:              This is a stainless 4 steel pipe?
5                    MR. GONZALEZ:          Yes, and I will discuss 6 the characteristics and the isometric drawing.
7                    MEMBER      ARMIJO:            And  what  grade          of 8 stainless steel is this?
9                    MR. GONZALEZ:              It is 304, and that 10 will        be  depicted      on    the    following      slide.            So 11 first          I  would    like      to    describe      this      piping 12 system.          Miranda, Slide 24, please.
13                    So  this      line      is      the  residual        heat 14 removal system, stainless steel pipe, 12 inches 15 diameter,          and    about        .4    inches    thick.            The 16 specific weld I am addressing is identified as 17 WIC-95, and is pipe to tee weld and as shown on 18 this isometric drawing, Miranda is highlighting 19 that location now.
20                    It    is      located          in  our    auxiliary 21 building in our 100-foot penetration room.                                This 22 RHR's line's function is to supply flow to the 23 reactor coolant system, hot legs 1 and 2, in the 24 event it is needed post-accident.
25                    This line would not normally see flow, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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41 1 as it is not a standard at-power or refueling 2 outage alignment.              I would only see check valve 3 testing        operations,      and      that        is  typically          one 4 time per outage.
5                    A    routine            ISI          --      ultrasonic 6 examination in 1997 discovered an indication in 7 this        weld.      The    indication          was    ultrasonically 8 dimensioned as approximately .4 inches long and 9 approximately            .2        inches            in    through-wall 10 dimension,          and  it    was    plotted        to  be  in      close 11 proximity to the ID of the pipe.
12                    Slide 25, please.                    This slide is a 13 graphic          representation          of      the      pipe    to        tee 14 configuration and the location of the indication 15 I am discussing.
16                    So in answer to your question, sir, 17 the tee is 403 wrought 304 stainless steel.                                      So 18 it      a    wrought  tee,      and      the      pipe    is    also,        as 19 depicted there on the righthand side.                            That is a 20 12 inch Schedule-40 stainless steel, also 304, 21 and the weld material would be our ER 308.
22                    So the indication we are discussion as 23 at approximately 90 degrees on the pipe side of 24 the tee, on the pipe side of the weld.                                This 12 25 inch          line    would      eventually              tie    into          the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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42 1 containment flow path and into the loop 1 and 2 2 hot legs.
3                  So  at    the    time      of    the  indication's 4 discovery, Diablo Canyon's UT level 3s compared 5 the recorded dimensions of this reflector to ASME 6 Section 11 Code acceptance criteria.
7                  MEMBER ARMIJO:            Now that flaw was not 8 detected during post-fabrication inspection?
9                  MR. GONZALEZ:            Actually,      there        was 10 flaws, and I will discuss that also.                          There was 11 flaws          detected      for      insufficient          penetration 12 during the initial construction radiography, and 13 there was notes that there had been repairs on 14 that weld for insufficient penetration, and that 15 factored        into  similar        confusion        regarding          the 16 nature of this flaw.
17                  So    when        the      dimensions        of        the 18 reflector were compared to the ASME Section 11 19 Code acceptance criteria, it was found not to be 20 within the standard code table acceptance limit.
21  At      this    time,      supplementary            ultrasonic          and 22 radiographic examination techniques were applied 23 to attempt to ascertain the size and the nature, 24 the character, of this reflector.
25                  Construction          period        radiographs        were NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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43 1 also reviewed.              As I had noted, there had been 2 repairs        on    this      weld      during        construction          for 3 insufficient penetration.                      However, we were not 4 able to positively match up the RT number belt 5 locations and the repairs to this reflector that 6 we had recently recorded.
7                    This      information              was    immediately 8 entered into our corrective action program, and 9 an engineering analytical evaluation, as allowed 10 by      ASME    code,    was    performed.              This  evaluation 11 considered              relevant            material          properties, 12 operating loads, and degradation mechanisms using 13 fatigue as a dominant driver.
14                    The result of this assessment was that 15 the weld was suitable for continued service.                                    As 16 part        of  the    evaluation          actions,        Engineering 17 stipulated          a  repeat      UT    examination        during        the 18 next refueling outage.
19                    In 1999, the first follow-up UT exam 20 was performed, and no flaw growth was measured.
21 This was also entered into our corrective action 22 program.        Again, in the next refueling outage in 23 the      year  2000,      another        successive        UT  exam        was 24 performed, and no flaw growth was measured.
25                    Note    that    ASME      Code      rules  for      this NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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44 1 Class        II  system      would      have      only  required          one 2 single          follow-up        examination,            but    we        have 3 performed two.
4                    MEMBER SHACK:            What is the exact UT 5 method you used?
6                    MR. GONZALEZ:            This was sheer wave --
7 At      the    time    of    its      initial        examination,            a 8 performance            demonstration            initiative        or        PDI, 9 Appendix -- Section 11, Appendix 8, requirements 10 were not in effect.                So it was standard appendix 11 3 flaw sizing rules.                    However, at that time, we 12 used        what    we    considered            state    of    the        art 13 techniques, which were the Appendix 8 techniques 14 with multiple search units and multiple mode of 15 propagation.
16                    Miranda, would you put on Slide 66, 17 please.          This is just a graphic representation of 18 some of the UT techniques we applied at that time 19 over        a    period      of      a    few      days,    trying          to 20 characterize that indication.                        So we did not rely 21 solely on the specified ASME techniques.
22                    We used what we considered state of 23 the art with qualified UT examiners.                          So you can 24 see, we used 70 sheer waves, 60 degree L-waves, 25 etcetera,            focused        dual-element            transducers, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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45 1 creeping longitudinal waves.                      We threw everything 2 we had at it, trying to characterize it.
3                  MEMBER SHACK:            And in the subsequent 4 exams?
5                  MR. GONZALEZ:              At    that    time,        PDI 6 requirements        were      in    effect.          So  we  used        PDI 7 qualified        procedures,          including        PDI  qualified 8 examination of personnel.                  Yes.
9                  MEMBER      ABDEL-KHALIK:              Is  there        any 10 vibration monitoring of this line?
11                  MR. GONZALEZ:          Not to my knowledge.                  I 12 would expect not, and I would be correct.                                  No, 13 sir.          This line, as I noted earlier, would not 14 normally see flow.              It would only be used after a 15 post-accident or to flow RHR into loop 1 and 2 16 hot leg, and that is an evolution that would not 17 occur for a number of hours after an accident.
18                  MEMBER      ARMIJO:            So    during      normal 19 operation then, is that a dead leg?                      Is there --
20                  MR.      GONZALEZ:                  During        normal 21 operation,        that    would      not      see    any  flow,        and 22 actually, that would be at ambient temperatures 23 with no elevated temperatures and no flow and no 24 pressure or minimal pressure, if any.
25                  MEMBER      ABDEL-KHALIK:                But      during NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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46 1 periodic testing of the pumps, would this line be 2 vibrating?
3                  MR. SHARP:          No.        During  non-outage 4 situations, we run the RHR pump on recirculation.
5  So it wouldn't see flow, and during outages we 6 mostly flow into the cold legs, not so much the 7 hot legs.          So typically, no flow period in those 8 -- in the RHR hot leg line.
9                  MR. GONZALEZ:                So  the    fracture 10 mechanics analysis conducted in 1997 considered 11 fatigue        as    a    degradation            mechanism.              The 12 ultrasonic        examination        had      concluded    that        this 13 flaw did not have the nature of stress corrosion 14 cracking        due  to    the    characteristics          of    the      UT 15 signal envelope and, as had we illustrated, we 16 applied        various      UT    techniques          in  trying          to 17 ascertain the reflector's attributes.
18                  So    the    multiple          UT    techniques          and 19 precisely        aligned      radiography            shots    that          we 20 employed        to  characterize            this    flaw,      and        in 21 concert with each other, they had concluded the 22 reflector        was    not    stress          corrosion    cracking.
23 This        was  a  degradation          mechanisms        that    we      had 24 reported to Engineering for their flaw analysis 25 was that it was not stress corrosion cracking.
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47 1                    The UT exams had plotted the position 2 of this flaw to be at or near the ID of the pipe.
3  The      proximity      rules      for    flaw      sizing    in      ASME 4 Section          11  Code      required        it      to  be  considered 5 surface connected at this point, regardless of 6 whether it had an actual opening to the ID of the 7 pipe or not.              So by default, this placed the 8 reject criteria in the more conservative column 9 of a surface connected flaw for Section 11.
10                    Due to the configuration of the piping 11 system, however, there was no practical method 12 for examining the ID of the weld to determine if 13 it actually was or was not open to the surface.
14                    Slide 23, please.
15                    MEMBER SIEBER:            This is a low pressure 16 line.          Right?
17                    MR. GONZALEZ:              It would see maximum 18 RHR pressure, which would be approximately --
19                    MR. SHARP:            In piggyback mode, less 20 than that, 350 pounds, yes.
21                    MR. GONZALEZ:            So normally, it would 22 not see extreme pressures, yes.
23                    MEMBER SIEBER:          Right.
24                    MR. GONZALEZ:            And normally -- excuse 25 me.        It would see a maximum pressure as 350.
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48 1                    MEMBER SIEBER:          Schedule 4, right?
2                    MR. GONZALEZ:            That      is  correct,          12 3 inch          diameter,        .4      inches          thick,    and          UT 4 measurements actually measure it slightly thicker 5 than .4 inches thick.
6                    So we are back on Slide 23.                  So a new 7 Engineer analysis has recently been performed on 8 this flaw using both stress corrosion cracking 9 and fatigue as a degradation mechanism.                                  These 10 results continue to find the flaw is currently 11 acceptable.
12                    An ISI exam scheduled for the Unit 1 13 refueling outage in 2012 will determine if this 14 indication has experienced any growth.                          If growth 15 is detected, this information will be immediately 16 entered into our corrective action program system 17 for        disposition        in    accordance          with  ASME        Code 18 requirements.
19                    MEMBER ARMIJO:            How did you conclude 20 that        the    --  if    the      stress        corrosion    cracking 21 evaluation          was  acceptable,            because    of    the      low 22 temperature of the environment or some other?
23                    MR. GONZALEZ:            The      new  engineering 24 analysis, and if we want some detail, I will ask 25 for        some    assistance        on    this.        But    the        new NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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49 1 engineering analysis used the material properties 2 and        the  time  at    temperature            that  this      would 3 typically see during a normal operating cycle, 4 and it used those inputs to determine what the 5 propagation rate would be for stress corrosion 6 cracking and when we would achieve unacceptable 7 progress.
8                  MEMBER      ARMIJO:            So    you  had        very 9 limited time at temperature.
10                  MR. GONZALEZ:          That is correct.
11                  MEMBER ARMIJO:            And you used the crack 12 growth correlation.
13                  MR. GONZALEZ:          That is correct.
14                  MEMBER SHACK:              And the crack growth 15 correlation came from what?
16                  MR. GONZALEZ:            Let      me  ask    Mr.      Lee 17 Goyette, who has been very much involved with the 18 fracture mechanics analysis to discuss that.
19                  MR. GOYETTE:          I am Lee Goyette.                I am 20 with        PG&E,  and    we    have      the      calculation        done 21 according          to      --      by      Structural        Integrity 22 Associates,        and    they      used      the      latest  criteria 23 that was available in the literature for crack 24 growth        rates  under      stress          corrosion    cracking 25 concerns.
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50 1                  So there is quite a bit of discussion 2 over the crack growth rates that were appropriate 3 in this situation, and --
4                  MEMBER SHACK:          Yes, I can imagine.
5                  MR. GOYETTE:            Yes.          And the fellows 6 that did the analysis sit on the code committees, 7 and they are aware of the latest what is the best 8 stuff to use.              So the analysis was done in a 9 conservative        way    at    the    high        temperature,          the 10 highest temperature that we determined the system 11 to be operating at for a limited time during each 12 refueling        outage,      and      we    turned      out    to      have 13 acceptable        results,      and      we      will    look    at      the 14 indication        again      during        the      next  outage          and 15 confirm.
16                  MR. GONZALEZ:          So the information that 17 we have gathered indirectly via the ultrasonics, 18 and        using  the    signal        envelope        characteristics 19 that are mentioned, that are noted in the PDI 20 approved        procedures      are      used        to  determine          the 21 nature of the flaw, and a linear rise and fall 22 rate,          nonspecular        reflection,            very      uniform 23 positioning of the ultrasonic responses, all tell 24 us that it is not stress corrosion cracking.
25                  As I had noted earlier, we have done NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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51 1 some specifically aligned radiography to look at 2 this flaw.          Aside from the construction period 3 radiography,        we    have      done        some  specifically 4 aligned radiography to see if we could see a flaw 5 there, and we saw nothing, also telling us that 6 it could be nothing but either lack of fusion or 7 lack of penetration.
8                  My      experience              in    construction 9 industry, a repair on a weld -- sometimes they do 10 get the flaw.          They do get all the insufficient 11 penetration        out    or    lack      of      fusion  out,        and 12 sometimes they will leave a little residual bit 13 of it, but the subsequent radiography will accept 14 it.        So it is not uncommon to see a reflector in 15 a previously repaired area.
16                  MEMBER      ARMIJO:            Now    you  did        have 17 instances of IGSEC in your plant early on, 1987, 18 and in your LRA you mentioned some accumulator 19 nozzles, again signature 304 conventional carbon, 20 high carbon.          So you detected that by your ISI 21 program?
22                  MR. GONZALEZ:            Yes, actually, it was 23 spotted        visually,      and    then      we    had  --    WE      have 24 implemented        a    long        term        program    where          we 25 ultrasonically            examined            these      accumulator NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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52 1 nozzles,        and  we    were      able      to  see  incipient 2 cracking in these accumulator nozzles.
3                  A    mechanism          there        was    different.
4 Metallurgy          found        there          was    considerable 5 contaminants, and we determined that it was due 6 to the original manufacturer.
7                  MEMBER      ARMIJO:            Was    that    furnace 8 sensitized          or    heat      treated          with  any        other 9 components?
10                  MR. GONZALEZ;          I believe those nozzles 11 were installed -- and I will be corrected if I am 12 wrong.        Those nozzles had been installed prior to 13 the heat treat of the accumulators, and that was 14 a contributor to their cracking.
15                  MEMBER      ARMIJO:            And    what    did        you 16 replace them with?
17                  MR. GONZALEZ:            With a partial fillet 18 weld        accumulator    nozzle.          They      were  bored        up.
19 These had been full penetration fillet welds on 20 both sides in the accumulators, and we replaced 21 them with a partial penetration fillet weld, and 22 the material is -- I am going to have to ask 23 Chris Beard, who is our Materials Engineer, also 24 of the ISI group.
25                  MR. BEARD:            Yes.        My name is Chris NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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53 1 Beard.          I work for PG&E, and we replaced them 2 with 304 L-grade stainless steel.
3                  MR. GONZALEZ:              And      our  subsequent 4 exams on those accumulator nozzles have not found 5 any repeat incidences of cracking, and it appears 6 we      are    over  the    curve      where        we saw a lot of 7 cracking early on in these accumulator nozzles, 8 but subsequent examinations have found those, and 9 we actually do those early in every outage.
10                  MEMBER ARMIJO:          Okay.        thank you.
11                  MR. GONZALEZ:            Non-replaced outage --
12 non-replaced nozzles only.
13                  MEMBER      ARMIJO:            Right.      You      still 14 monitor the non-replaced.
15                  MR. GONZALEZ:          That is correct.
16                  MEMBER ARMIJO:            But you don't have to 17 do it with the 304 L-grade?
18                  MR. GONZALEZ:          That is correct.
19                  MR. WRIGHT:            We      monitor    them        with 20 visual inspection only.                Yes, sir?
21                  MEMBER      ABDEL-KHALIK:              I  understand 22 that this pipe is essentially empty during normal 23 operation and refueling.
24                  MR. WRIGHT:        No, it would remain full.
25                  MEMBER ABDEL-KHALIK:                  I mean there is NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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54 1 no flow.          Excuse me.          So what is the state of 2 stress          on    this      pipe,        first      under      normal 3 conditions          when    there      is    no      flow,  and    in      the 4 event that flow is started?
5                    MR. GONZALEZ:            I will have to ask Mr.
6 Goyette to answer that.
7                    MR. GOYETTE:          Lee Goyette.        Well, the 8 state        of  stress    during      normal      plant  operation 9 would        be  dead  weight        and    whatever      temperature 10 effects, and in a design seismic event.                                  So a 11 very low state of stress, plus pressure.
12                    With the system in service, during an 13 accident        mode,    normal        --    emergency      and      faulty 14 conditions, it would be at temperature for long 15 term cooling.
16                    MEMBER ARMIJO:            Do you put in a weld 17 residual stress into your stress analysis when 18 you evaluate for stress corrosion cracking?
19                    MR. GOYETTE:          Weld residual stress?                  I 20 think not.
21                    MEMBER ARMIJO:            That is typically the 22 initiators of stress corrosion cracking compared 23 to      dead    weight    load,      but    these      cracks    haven't 24 grown.        You have monitored them.
25                    MR. GONZALEZ:            That is correct.                We NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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55 1 have had two subsequent examinations.                          There has 2 been no measurable change in growth -- in size, 3 excuse me.
4                    Continuing on:            So the ISI examination 5 that is scheduled for the next refueling outage 6 in 2012 will monitor this flaw for any change in 7 dimensions.              If      growth        is    detected,          this 8 information will be immediately entered into our 9 corrective          action      system        for    disposition          in 10 accordance with the current code requirements.
11                    If no growth is experienced, this weld 12 will        revert    to    the      standard        ASME  inspection 13 frequency, as specified by the ISI program which 14 will require an examination every 10 years, and 15 examination results from those future inspections 16 will        be  evaluated      against          the  existing        code 17 requirements at those times.
18                    So this concludes my presentation on 19 the WIC-95.
20                    MR. SHARP:            Next presentation is by 21 Dave Miklush of our License Renewal Project.
22                    MR. MIKLUSH:          My name is Dave Miklush, 23 and I am a member of the Diablo Canyon License 24 Renewal        Team.      I    will      be    presenting    the      open 25 items for the scoping and screening portion of NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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56 1 our submittal.
2                    Slide 27, please.                The first open item 3 deals with non-safety related fluid-filled piping 4 near safety related systems.
5                    In our first series of walkdowns, we 6 missed two things.                One was we didn't look hard 7 for        rainwater      entry      at    the      systems,      and        the 8 second        one  was    the    proximity          of  low    pressure 9 piping near a safety system, specifically in the 10 Turbine Building.
11                    So    we      instituted            another      set        of 12 walkdowns,          and    found        that      our    HVAC    ducting, 13 exhaust ducts from Unit 2's 480V switchgear room 14 had an outlet that was oriented upward that could 15 collect rainwater.                So it looked like it might be 16 a problem, but when we inspected it further, we 17 found          out    there        were      drain        holes      inside.
18 However, there was some rusting going on where 19 the water had been collecting.
20                    So we have elected to add more drain 21 holes in there.              I would point out that we have 22 never had a water problem getting into our 480V 23 switchgear rooms from the ventilation system.
24                    The second two items had to do with 25 firewater          piping        near      control        pressurization, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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57 1 pressurization          fan      controls.              On  our        first 2 walkdown,          we  saw      this      piping.          It    was        low 3 pressure, and it wasn't very close.
4                    After      the      RAI,        we    went    out        and 5 recalibrated our walkdown and said, if we could 6 see low pressure piping within line of sight, we 7 will        add  it  into    scope,      and      that  resulted          in 8 these two items that we added into scope on the 9 control pressurization fans and on the exhaust 10 opening for the 4kV switchgear rooms, which had 11 firewater and domestic water pipes within 50 or 12 60, again line of sight, of the equipment.
13                    Slide 28.        slide 28 had to do with the 14 electrical pull boxes and whether or not the pull 15 boxes had pressurized piping going through the 16 pull boxes.
17                    Now Ryan West earlier talked to you a 18 lot about the configuration of the drainage and 19 the gravity drains and the external sumps, and we 20 have        just  confirmed        here      that      there    are        no 21 pressurized sump pump piping returning into the 22 pull box, electrical pull box.                            So that was a 23 clarification on that one.
24                    Slide      29.        Slide        29,  in    another 25 walkdown we found water trapped in the instrument NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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58 1 air system that was near the exhaust ducting of 2 the fuel handling building supply fans.
3                  Although the instrument air system is 4 a very dry system and it is monitored for dew 5 point, we have elected to keep the inlet valve to 6 that water trap closed, because the valve that it 7 supplies is a heating steam valve to the flow 8 handling, and we have never used the system and 9 don't expect to ever use it in the future.                                    So 10 that is how we resolve that one.
11                  Slide 30 is a different topic.                        It is 12 the scope boundary between non-safety related and 13 safety        related  instrument          air      tubing.        Again, 14 this is a clarification that our scope boundary 15 extends beyond the safety related to non-safety 16 related isolation device to the solenoid valve or 17 check valve into the non-safety related tubing at 18 the first seismic anchor or equivalent seismic 19 anchor.
20                  That has been noted on the instrument 21 air      system    drawings      for    license      renewal        scope 22 boundary.          That      explains        to      future  engineers 23 where        the  scope    boundary        ends      for  the      safety 24 related instrument air tubing.
25                  Slide 31.          This issue had to do with NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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59 1 the      pressure  boundary        status        of  the  air      start 2 compressor unloader line, which connects the air 3 compressor        directly        to      the        instrument          air 4 receiver.      The diesels are air start.                  Motors air 5 start, air receiver.
6                  The line as non-safety related, very 7 small line, quarter inch in diameter.                              In the 8 past, it had been evaluated as acceptable as is, 9 meaning if it had failed, the air receiver could 10 still do its duty.                  However, in an effort to 11 clean up this design situation, we have rerouted 12 this unloader line upstream into the non-safety 13 related portion of the system, upstream of the 14 safety related isolation device.
15                  That      modification              work  has        been 16 completed      on  Unit      1.        All      three    diesels        are 17 complete.        One Unit 2, one diesel is complete, 18 and two more to go, and that will complete in 19 April of this year.
20                  Slide      32    is    two        items  concerning 21 buried valves and piping.                  The first one had to 22 do with copper valves in the makeup water system 23 that are in contact with soil, and the question 24 that        was asked    is    how      we    aging    manage      those 25 valves, and our answer is we will be using the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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60 1 Buried          Pipe  and      Tank      Program        to  aging      manage 2 those copper valves.
3                    The second item had to do with the 4 branch          line  off      our    raw    water      reservoir        line 5 coming into the plant.                      There is a branch line 6 that        feeds    industrial          buildings.            No      safety 7 systems on that branch, and to limit the scope of 8 our license renewal program, we have elected to 9 revise operating procedures to isolate valves to 10 the branch line in case of a branch line leak or 11 the      raw    water  reservoirs          are      aligned    for      long 12 term cooling, then we will go out and close those 13 valves to preserve the water supply in the raw 14 water reservoirs.
15                    In that way, we have taken that branch 16 line out of scope.
17                    DR. BARTON:            Do      you    have  cathodic 18 protection on your buried piping?
19                    MR. MIKLUSH:            There is some cathodic 20 protection on the aux saltwater system.                                  We do 21 not have any on the make-up water system.
22                    DR. BARTON:              And      what    is        its 23 availability?
24                    MR. MIKLUSH:          Its availability is very 25 good.          I don't have the exact --
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61 1                    DR. BARTON:            What      is  very        good?
2 Ninety, 95 percent?
3                    MR. SHARP:        Mr. Lee Goyette, could you 4 answer that?
5                    MR. GOYETTE:            Lee Goyette with PG&E.
6 The        availability        of    cathodic          protection            is 7 monitored        monthly,      and    it    is      over  90    percent, 8 according to the NACE standards.
9                    MEMBER STETKAR:            Before you leave, if 10 you        are  the    cathodic          protection        person,          the 11 staff's        inspection        report      noted      that    you      have 12 recently        --    that      is    the      term    they    used        --
13 upgraded cathodic protection system.                          If that is 14 the case, when was that upgrade performed?
15                    I understand you are now claiming it 16 is 90 percent available today, but what has it 17 been historically, and if it was indeed improved, 18 when were the improvements made?
19                    MR. GOYETTE:          That is a good question.
20                    MEMBER STETKAR:            I thought so.
21                    MR. MIKLUSH:            The cathodic protection 22 system was installed approximately 1995.
23                    MEMBER STETKAR:            Installed?
24                    MR. MIKLUSH:                The    aux    saltwater 25 system.
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62 1                  DR. BARTON:            The      original    or      the 2 upgrades?
3                  MR. MIKLUSH:          It was installed on the 4 entire        supply  system        from      the    intake    to      the 5 turbine building, including the bypass section, 6 which was new pipe at the time, and the old pipe 7 that remained in service. The old pipe was above 8 the ocean tide level.
9                  MEMBER ARMIJO:          On this chart about --
10                  MEMBER STETKAR:            Hold on a second.                I 11 don't think I got the answer to my question.                                    I 12 heard when it was installed.                      I asked had it been 13 upgraded at sometime since it was installed, and 14 when        was  that    upgrade        performed        or    was        the 15 installation        considered        an    upgrade,    going        from 16 zero to something?
17                  MR. MIKLUSH:          When the insulation went 18 in in 1995, that was the upgrade at the cathodic 19 protection system on the aux saltwater system.
20 Now the plant has had other non-safety related 21 cathodic protection systems in service since the 22 early Eighties, and we have had a surveillance 23 program        written    for    those        cathodic    protection 24 systems for the entire life of the plant.
25                  MEMBER STETKAR:            Okay, I guess I will NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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63 1 wait and ask the staff.
2                MEMBER SHACK:              We have a commitment 3 here to install cathodic protection for the ASW 4 discharge piping.
5                MR. MIKLUSH:            There is a portion of 6 the discharge pipe from the turbine building to 7 the intake that is in contact with soil that does 8 not have cathodic protection on it, and --
9                MEMBER      SHACK:          So      that  will      be      an 10 upgrade when it is installed.
11                MR. MIKLUSH:          That will be an upgrade.
12                MEMBER SHACK:            And that is going to 13 happen when?        Prior to the period of extended 14 operation?
15                MR. MIKLUSH:            Prior to the period of 16 extended operation.          That is right.
17                MEMBER ARMIJO:            Now your makeup water 18 system, you said, is not covered by your cathodic 19 protection, or is?
20                MR. MIKLUSH:          No, it is not.
21                MEMBER      ARMIJO:          It      is  not?        Now      a 22 copper valve -- I have never heard of such a 23 thing, but there may be.              But are these bronze or 24 brass or are they truly copper valves?
25                MR. MIKLUSH:            I am not sure of the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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64 1 exact alloy that they are made of.
2                    MEMBER      ARMIJO:          Maybe      some    of      your 3 people        could  say.        And      are      they  attached          to 4 carbon        steel  piping,        bolted        or    something          like 5 that?
6                    MR. MIKLUSH:            The      piping      and        the 7 firewater          makeup      water        system        is    concrete 8 asbestos piping..
9                    MEMBER ARMIJO:          Concrete?
10                    MR. MIKLUSH:                Concrete        asbestos 11 reinforced.
12                    MEMBER      ARMIJO:            With    copper        valves 13 attached to that?
14                    MR. MIKLUSH:          And where -- Well, most 15 of the valves in the system are carbon steel.
16 There's a few valves that are copper or bronze 17 material, and those were these three valves that 18 were part of the RAI.
19                    MEMBER ARMIJO:            so you wouldn't have 20 any        galvanic      corrosion,            because        these          are 21 concrete          that  they      are      attached        to,    because 22 copper and steel --
23                    MR. MIKLUSH:            There is not a piping 24 issue, but there is an issue with the metals that 25 are      in    the  ground.          So    every      valve    location, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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65 1 there is a question of long term performance.                                So 2 those will have to be managed in the inspection 3 program.
4                  MEMBER STETKAR:            Someplace in the SER 5 I    read    that  you      have    had      problems    with        some 6 leakage in gray cast iron buried piping in the 7 firewater system, and apparently the corrective 8 actions have been to replace the piping with --
9 to replace the piping.
10                  Do  you    still      have        buried  gray        cast 11 iron firewater piping on site or has all of that 12 been replaced?
13                  MR. SHARP:          Lee      Goyette,    could        you 14 answer that?
15                  MR. GOYETTE:          Yes, sir.        The majority 16 of the underground firewater piping is asbestos 17 concrete, and the risers that go to the hydrants, 18 those are gray cast --
19                  MEMBER STETKAR:            Okay.      So it is only 20 the risers --
21                  MR. GOYETTE:            -- and they are being 22 replaced with ductile iron.
23                  MEMBER      STETKAR:              They  are        being 24 replaced?
25                  MR. GOYETTE:          Yes, sir, they are.
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66 1                  MEMBER STETKAR:            But you also have PVC 2 piping in the firewater system.                        Right?
3                  MR. GOYETTE:          We do have PVC piping in 4 the firewater system.                Yes.
5                  MEMBER STETKAR:                So you said it was 6 concrete.        So it is both.
7                  MR. GOYETTE:          Both.
8                  MEMBER STETKAR:              Is one a replacement 9 for the other or you use them in different --
10                  MR. GOYETTE:            Don't know.            I cannot 11 answer that question.
12                  MR. SHARP:            I    can    say    that        the 13 majority, 95+ percent of the buried pipe in the 14 fire protection system is the asbestos concrete 15 pipe.          As Lee said, some of the risers have the 16 cast        iron  that    we    are    replacing          with    ductile 17 iron.          There  are      small      segments        of  PVC,        but 18 primarily the asbestos -- ACP pipe.
19                  MR. MIKLUSH:                That      concludes            my 20 presentation.
21                  MR. SHARP:            The        next    speaker          is 22 Michelle Albright.
23                  MS. ALBRIGHT:                Mr. Chairman          and 24 members of the Committee, good afternoon.                                  I am 25 Michelle Albright, and I am part of the Diablo NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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67 1 Canyon        License    Renewal        Team,        and  I    will        be 2 discussing the two open items that we have TLAAs.
3                    The first one that I will discuss is 4 on      TLAA    identification,          which        consists    of      two 5 RAIs.          Secondly, I will be discussing the open 6 item on metal fatigue, which is on nine RAIs.
7                    Responses to all of these RAIs have 8 been submitted to the staff.                        We believe that we 9 have provided adequate responses to address the 10 staff's          concerns,      but      they        still  are        under 11 review.
12                    Slide 34, please.                Open item 4.1-1 is 13 on two topics.              The first of these is on the 14 design        codes  for      the    reactor        coolant    pressure 15 boundary valves, and secondly is the managing of 16 the baffle and former bolts.
17                    To  address        the    first      open    item,        we 18 reverified that the design codes for our reactor 19 coolant pressure boundary valves do not require a 20 fatigue or any time dependent analyses, and we 21 clarified it in the response to the staff.
22                    Secondly,      for    the      baffle    and      former 23 bolts, we revised the license renewal application 24 to choose Option III, which is to use an aging 25 management program to manage the potential aging NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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68 1 of those baffle and former bolts, and that is the 2 Reactor Vessel Internals Program.
3                    MEMBER      SIEBER:              Do  we    have        any 4 evidence of baffle jetting?
5                    MR. SHARP:            The answer is yes.                    We 6 have        two    over    the    time      frame.        We    did      have 7 evidence          of  baffle      jetting,          and  that    has      been 8 remedied with modifications performed --                                upflow 9 modifications          performed          in        the  last    five        to 10 eight years.
11                    MEMBER SIEBER:              And that is replace 12 bolts modification?
13                    MR. SHARP:          It was to cut some holes 14 in the upper portion of the baffle.
15                    MEMBER      SIEBER:          So    you  lowered        the 16 pressure differential?
17                    MR. SHARP:        Yes, sir.
18                    MEMBER SIEBER:            Does that reverse the 19 flow?          Does that reverse the baffle flow?
20                    MR. SHARP:            It does in some cases, 21 yes.        Dan Hardesty, could you please come to the 22 microphone and answer that question.
23                    MR. HARDESTY:                My  name      is        Dan 24 Hardesty, Primary Systems Engineering.                              In 2R10 25 we performed what is called an upflow mod to the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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69 1 internals, lower internals and upper internals of 2 the reactor for Unit 2, and that corrected -- It 3 lowered the pressure in the inside of the baffles 4 so that it would jet in the opposite direction.
5                  Westinghouse          designed        and  performed 6 the modification.
7                  MEMBER      SIEBER:            Did  you  have        fuel 8 damage associated with the baffle flow?
9                  MR. HARDESTY:            Yes, sir, we did.                In 10 the Nineties we had some damage.
11                  MEMBER SIEBER:              That is why you did 12 the mod, but the mod did not change the bolting.
13  What it did was reverse the flow.
14                  MR. HARDESTY:          That is correct.
15                  MEMBER SIEBER:          Thank you.
16                  MS. ALBRIGHT:          Slide 35, please.
17                  There    are    nine      RAIs    associated        with 18 open item 4.3-1.              For the purposes of discussion 19 today,        we categorized          the    resolution      of      these 20 nine RAIs into four common areas to give you a 21 feel for the types of responses that we had to 22 these RAIs.
23                  The  first      of    these      areas  would          be 24 items that required additional information.                                For 25 example, in our license renewal application we NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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70 1 provided        the  conclusions          that      the  replacement 2 reactor        vessel    head      replacement          CRDMs    and      the 3 replacement CETNAs were good past the period of 4 extended operation.                However, we did not provide 5 the actual cumulative usage factor values in the 6 application to demonstrate that.
7                  So in response to the RAI we merely 8 provided those CUF values, which showed that we 9 had adequate margin.
10                  In    the      second          group    we    provided 11 clarifying information based on four RAIs that we 12 received.          An example here is a clarification for 13 the        metal    fatigue        program.            Basically,          we 14 clarified that we were going to be using the FSAR 15 number        of    transients          in      our    metal    fatigue 16 program.          These are lower numbers than are used 17 in      the    analyses      for    the    upper      and  lower        core 18 plate.          So they are more conservative to count 19 to.
20                  In the next group of RAIs, we will be 21 enhancing our current licensing basis.
22                  MEMBER STETKAR:              Before we go to the 23 enhancement,          have      you    completely        updated      Table 24 4.3-2 in the license renewal application, because 25 all I have is the table from the original LRA, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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71 1 and looking at the responses to some of the RAIs 2 and the numbers in that table, there are a number 3 of instances where I couldn't make numbers add 4 up.
5                  So,    for      example,            your  example          on 6 charging        cycle    estimates        for        auxiliary        spray 7 during plant cooldown, in the SER it is noted 8 that -- I have to find my notes; bear with me 9 here -- that there would be -- You are counting 10 two        of  those  events        per      cooldown,      and        that 11 resulted in an estimate of 146 occurrences for 12 Unit 1 and 102 occurrences for Unit 2.                          But if I 13 use the number of cooldown events tabulated at 14 least in the license renewal application for Unit 15 1, I count 176, because there are -- I'm sorry, 16 174 -- I can't read my own writing -- because 17 there are 87 cooldown events projected for Unit 18 1, and 63 for Unit 2, which gives me 126.
19                  So I am curious how you got 146 and 20 102.          Is it a big deal?              Are you close to the 21 margin?          I am just interested in multiplying X 22 times 2 and being able to understand how that 23 counting is done.
24                  MS. ALBRIGHT:            I understand.            i would 25 like        to  ask  Mr. Chalmer      Myer      to  address        that NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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72 1 question.
2                    MR. MYER:          This is Chalmer Myer with 3 the Star Center of Business.                            We are going to 4 need        to  take    it    offline        and      respond      later, 5 because it is going to take some review, but we 6 will get you an answer.
7                    MEMBER      STETKAR:              There  were        some 8 others.            In  the      interest          of    time,    I      would 9 encourage you and also the staff when they come 10 up to look at things like consistency.                                If you 11 are using 2 times X, make sure that X and 2 times 12 X are equivalent numbers.                    There are a number of 13 those things that I have come across.
14                    As  I  said,      in    the      grand  scheme          of 15 things, you are well below the margins, but I am 16 talking about consistency, because you are using 17 methods        to  develop      those      cycle        counts.        Thank 18 you.
19                    MS. ALBRIGHT:              Thank you.            For the 20 next        group  of    RAIs,      we    will        be  enhancing        our 21 current licensing basis and, namely, this is the 22 FSAR.          For example, the staff questioned why our 23 FSAR didn't provide the technical basis for us 24 not      counting    load-following              transients.            While 25 they agreed with the technical basis of why we NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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73 1 aren't        counting        them,      we      didn't    have        that 2 actually documented in our FSAR.                          So we will be 3 updating our FSAR, and committed to do so in our 4 response.
5                  The      last        category          here      is        on 6 environmentally-assisted                    fatigue.            For          our 7 license        renewal      application,            we    performed        the 8 environmentally-assisted                  fatigue        analyses          per 9 NUREG/CR-6260 using the locations for an older 10 vintage Westinghouse plant.
11                  The staff did question why we did not 12 consider other locations than those originally in 13 our application.            After discussions with them, we 14 did      agree    that    it    would      be      --  that  we      would 15 commit to review our existing fatigue analyses to 16 determine if the analyses that we performed for 17 environmentally-assisted fatigue are limiting for 18 the Diablo Canyon reactor cooling environment.
19                  Through      those      evaluations,        if    we      do 20 find        more  limiting        locations,          then  the        most 21 limiting          component          will        be    evaluated          for 22 environmentally-assisted                    fatigue        through          our 23 metal fatigue program, and we will be doing that 24 prior to the period of extended operation.
25                  This      concludes        the      presentation          on NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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74 1 TLAA open items.
2                    MEMBER      SIEBER:            Have  you    had        any 3 issues          with  control        rod    drive      mechanism        tube 4 split pins that hold the tubes in place within 5 the control rod drive?
6                    MR. GREBEL:          Dan Hardesty, have we had 7 a previous history with split pins?                          Dan, could 8 you answer that?
9                    MR. HARDESTY:            Sorry, I didn't catch 10 the question all the way.
11                    MEMBER SIEBER:              The question is:              In 12 your class of plants around the time this plant 13 was      built,    there      was    an    issue    of  cracking          of 14 split          pins  that      hold      the      control    rod      drive 15 mechanism tubes at the top of the core plate into 16 position so that you would not delay the dropping 17 of the control rod during a reactor SCRAM.
18                    Have you examined your split pins or 19 have you replaced them?
20                    MR. HARDESTY:            We replaced our split 21 pins.            I    believe          we    have      two    different 22 replacements at different times, but the last one 23 was in 2R10 when we did the upflow mod.                            We took 24 advantage at the time and replaced the split pins 25 with the new versions.
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75 1                    MEMBER SIEBER:            And so baffle jettings 2 issue solution is pretty recent?
3                    MR. HARDESTY:            It      was  a  convenient 4 time to do it, because we had --
5                    MEMBER SIEBER:            So you did split pins 6 --      some      split    pins      and    baffle        jetting,        flow 7 reversal at the same time, same outage?
8                    MR. HARDESTY:          Yes.
9                    CHAIRMAN BLEY:            Any      other questions?
10  Yes?        Go ahead.
11                    MEMBER STETKAR:            Thank you.          A couple 12 of      quick      ones.        You    have      apparently      had      some 13 problems out in the intake structure, because it 14 is a pretty harsh environment on the coast there, 15 and I have noted that it was placed into a higher 16 category          of    attention          with        the    plans          for 17 remediation because of deterioration, I guess, in 18 the structural concrete and things like that.
19                    According to the SER anyway, it said 20 that the Applicant had developed a repair plan to 21 return          the  intake      structure          to    A2  inspection 22 status          under  the      maintenance            program    by      2010, 23 which        implies    that      it    should        now  be    in      much 24 better shape.            Is it?
25                    MR. SHARP:            I      would      say      --      a NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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76 1 preemptive        comment,        and    then      I  will    let      David 2 Wong answer.
3                    We    have      indeed      done      repairs      on      the 4 intake        structure      to    take    it      back    to    a    better 5 condition.            We had some additional degradations 6 identified as we were making those repairs, and 7 so there has been a little bit of delay.                                      That 8 won't be completed now until this spring in 2011.
9                    MEMBER STETKAR:                Thanks.        One more.
10 Let me just make a note on that.                          This, again --
11 You apparently in Unit 2 during RO-15 identified 12 --      they    are  characterized            as      gaps  between          the 13 concrete          floor      and      the      steel      liner      in      the 14 containment,          and      apparently            you    have      made        a 15 commitment to seal the gaps.
16                    The    way      I    read      the    material,            it 17 sounded to me as if there had never been any 18 sealant in the gaps.                Is that true?
19                    MR. SHARP:          Yes.      The    Diablo        Canyon 20 design          does    not      include        a      moisture      barrier 21 component        seen    in      other      plants.          The    concrete 22 runs up to the containment liner at the base of 23 containment.
24                    MEMBER        STETKAR:                A    couple            of 25 questions.          If you have now made the decision to NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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77 1 seal the gaps, does that mean you are only going 2 to seal the places where you found the gaps or 3 are you going to actually install circumferential 4 moisture barrier?
5                  MR. WONG:          This is David Wong, Civil 6 Engineering Supervisor.                  We are intending to seal 7 only the gaps at this time.                    The concrete is very 8 hard pressed up against the liner.                            We inspect 9 them every outage.              We have a couple of programs 10 that        look  at  that      every      outage,      our  Coatings 11 Monitoring          Program,          and        also    the        Civil 12 Maintenance Rule Program.
13                  DR. BARTON:          How do you know you have 14 never had any leakage between the concrete and 15 the        liner    or    there        is    any      corrosion        down 16 underneath the floor?
17                  MR. WONG:          We    have      never  seen        any 18 leakage        or  any    signs        of    degradation        of      the 19 concrete, any kind of degradation which would re-20 collect through the liner as popping and spalling 21 the concrete or cracking it.
22                  MEMBER      STETKAR:              Thanks.          I      am 23 finished.
24                  CHAIRMAN BLEY:          Any other questions?
25                  DR. BARTON:        Yes.
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78 1                  CHAIRMAN BLEY:            Yes, John?
2                  DR. BARTON:            The      Appendix      A,      your 3 final safety analysis supplement and also Append 4 B, aging management program, when you talk about 5 your one-time inspection of code Class 1 small 6 bore        piping,    I    don't      get        what    your        final 7 commitment        is  on      volumetric          testing    of      socket 8 welds.
9                  MR. SHARP:          Chris        Beard,  could        you 10 please respond to that?
11                  MR. BEARD:            Chris Beard.            Our final 12 commitment, as responded to in our latest request 13 for additional information, is:                            Diablo Canyon 14 will        volumetrically        examine          10    percent    with        a 15 maximum of 25 welds of each weld type socket and 16 butt        welds  for    ASME      Class        1,    less  than        four 17 inches.        That is our final commitment.
18                  DR. BARTON:          Okay.        I didn't get that.
19  So I am glad to hear you committed to do that.
20                  Also,      you      have      got      an  opening          in 21 containment where you had strain gauges installed 22 for initial structure integrity tests, and those 23 openings are still there on both units.                            How do I 24 know that you don't have environment gotten into 25 there,        and    you      have      got        rebar,    concrete NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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79 1 degradation enclosed in your environment?
2                  MR. SHARP:          David        Wong,    could        you 3 respond to that?
4                  MR. WONG:        This is David Wong.                  These 5 strain gauge boxes -- Yes, they were originally 6 installed        during      construction            to  monitor          the 7 strain on the rebar.                They are thin gauge 4 x 4 8 by 4 inch in depth thin gauge carbon steel boxes 9 embedded on the exterior part of the containment 10 structure.
11                  They    were        banded        in    place        after 12 testing.          The strain gauge access boxes, which 13 were called openings, are actually covered with 14 plastic covers and sealed around with caulking.
15                  Due to the age weathering effects, we 16 have seen some damage.                    Either the covers are 17 missing        or  they      are    broken,        and    we  plan        on 18 repairing        those    thin    gauge        boxes    that    we      find 19 damaged in our next containment exterior concrete 20 inspections.
21                  DR. BARTON:            How      do  you    know        you 22 haven't had any corrosion since then, since you 23 know that you are really not sealed right now?
24                  MR. WONG:          We would see signs of the 25 concrete spalling or cracking, which we have not NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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80 1 seen.
2                CHAIRMAN BLEY:              No further questions?
3  Thank you very          much for your presentations.                          I 4 think we will take a break now, and I would ask 5 everybody to be back at 3:15.                          We will recess 6 now.
7                (Whereupon, the foregoing matter went 8 off the record at 2:57 p.m. and went back on the 9 record at 3:15 p.m.)
10                CHAIRMAN BLEY:              The meeting will come 11 back to order, please.              Brian, back to you.
12                MR. HOLIAN:            Thank        you.        Sorry.
13 Waiting for the rest of the NRC staff.                            This is 14 Brian Holian, Director of License Renewal.
15                Our staff did take good notes during 16 some of the questions there.                        I know Mr. Shack 17 had a question early on about MRP.                        Let me just -
18 - So we will be addressing those as part of our 19 staff response to the SER and the open items.
20                Once again, up at the table we have 21 Stan Gardocki.          Stan is one of our members from 22 another technical region, DSS, Division of Safety 23  Systems, and he helps out a lot of scoping.
24                You have heard from him before from 25 the      floor  on  this      particular            plant.      We      had NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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81 1 issues with the plant walkdowns, and Stan is here 2 to support our discussion of that.
3                  Bill    Holston,        a    senior    engineer          in 4 License        Renewal,      there      for      the  buried      piping 5 issues.        You have heard him on previous plants.
6                  Alan Hiser, a senior level advisor in 7 Division of License Renewal, will be talking to 8 some of the metal fatigue items there, thimble 9 tube issues.
10                  Greg    Pick,        I    mentioned,      a      senior 11 inspector from Region IV, and Nate Ferrer, our 12 Project Manager.            With that, I will turn it over 13 to Nate.
14                  MR. FERRER:            Thanks,      Brian.          Good 15 afternoon.        As Brian said, I am Nate Ferrer.                            I 16 am      the    Project    Manager        for      the  Diablo      Canyon 17 License Renewal Review, and I am pleased to have 18 the opportunity to present the staff's review, as 19 documented in our Safety Evaluation Report or SER 20 with open items.
21                  Before      I      actually        get    into        the 22 presentation,          Allen      will      address      the  question 23 that we had earlier on the vessel internals.
24                  DR. HISER:          I guess, Bill, could you 25 restate the question?
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82 1                    MEMBER SHACK:              Two things.            One, I 2 know Ginna submitted an inspection plan, and I 3 never saw whether you guys accepted it or not.
4 Since MRP 227 is all over GALL, I assume it was 5 finally accepted, but I haven't really seen that.
6                    Then    just      since        you    now  have        the 7 guidance, you have presumably got somebody who 8 had one inspected.                  When are we going to see 9 people          coming  in      with    inspection          plans      rather 10 than,          you  know,      we    are    going        to  follow        the 11 industry sort of thing that we see standard here.
12                    DR. HISER:          A number of plants have 13 come in with inspection plans, because they have 14 already entered the extended period of operation, 15 and those plans are generally due two years ahead 16 of that time.
17                    I am not sure of the status of the 18 Ginna plan, but --
19                      MEMBER      SHACK:          Okay,      but  you      have 20 accepted other plans then.
21                    DR. HISER:        I don't -- I am not sure 22 that        we    have  accepted          any.          There  were        some 23 plants          --  for    example,          Calvert        Cliffs          had 24 proposed          specific      inspections            in  their    initial 25 application, and so they do not have that type of NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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83 1 commitment and do not owe us a plan.
2                    So I will verify the status of Ginna 3 and some of the other plants.                            I am not aware, 4 though, that we have approved any MRP 227.                                    The 5 SER has not been issued yet, but that will be 6 forthcoming.
7                    MEMBER SHACK:          Well, GALL-2, as I read 8 it,        it  seems    to    imply      that        you  accept        that 9 guidance.          GALL-2        incorporates              a    lot          of 10 information          from      MRP    227,      the      recommendations 11 that are in that report, but also some additional 12 items        that  the    staff      thinks        is  necessary        for 13 applicants.          There is no a GALL section for it.
14                    DR. HISER:          Yes, that is correct, and 15 after probably the current set of plants, we will 16 expect plants to come in with a GALL consistent 17 program.          Once we finalize the SER for MRP 227, 18 we may modify the GALL program to be consistent 19 with the staff positions that come out of that 20 review.        Jeff?
21                    MR. POEHLER:          Jeff Poehler, Materials 22 Engineer          from    the      Vessel          Integrity        Branch, 23 Division of Component Integrity.
24                    We have not issued an SER or an SE on 25 any        of  the    plant        specific          reactor      vessel NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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84 1 internals inspection plans.                    We have accepted for 2 review quite a few of them.                    I can't tell you the 3 exact number.        So it is basically waiting on the 4 SE for MRP 227 Rev 0, which is the basis for all 5 these inspection plans, which is supposed to be 6 issued in the next month or so.
7                  DR. HISER:        Is that the final SER?
8                  MR. POEHLER:          Correct.
9                  MEMBER SHACK:          So soon.
10                  DR. HISER:          But there will be a point 11 at        which  the    commitment            is    no    longer          an 12 acceptable method to demonstrate aging management 13 for vessel internals.                That answers my question.
14  Thank you.
15                  MEMBER      SHACK:              That    answers          my 16 question.      Thank you.
17                  MR. FERRER:            Getting      back    to      the 18 presentation        for    today,      I    will      begin    with        an 19 overview of the Diablo Canyon review, and I will 20 keep        it brief,        since      this        information          was 21 previously discussed by the applicant.
22                  We    will        then        follow      the        basic 23 structure of the SER, covering topics of interest 24 and open items on each section.                        Greg Pick will 25 be        presenting    the      license            renewal    regional NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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85 1 inspection, as Brian mentioned, and we will try 2 not to repeat all of the information that the 3 applicant        has  presented.              We    just  intend          to 4 ensure        that  you      receive        adequate        information 5 associated with the staff's review and findings, 6 and      as  always,    feel      free      to      ask  questions          at 7 anytime.
8                  This slide just provides the general 9 details of the license renewal application.                                  The 10 applicant has previously covered all this.                                    So 11 unless there are any questions, I will move on at 12 this time.
13                  Staff    review      teams        conducted      audits 14 and      inspections      of    the    application          during        the 15 period shown on the slide.                  I will highlight that 16 issues raised and discussed during the scoping 17 and screening methodology audit led to two LRA 18 amendments          related      to    scoping          and  screening 19 submitted in the summer of 2010.
20                  They        provided            the      applicant's 21 additional scoping and screening evaluations for 22 various plant systems, structures and components.
23  San Gardocki will be covering these topics in 24 more detail during the discussion of Section 2.
25                  In  preparing          the      Safety    Evaluation NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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86 1 Report          and  in    addition        to      the  audits          and 2 inspections            already          mentioned,          the          staff 3 conducted in depth technical reviews.                            We issued 4 approximately            200        Requests            for    Additional 5 Information to which the applicant responded.
6                    The SER was issued to the applicant on 7 January 10, 2011, and contains eight open items 8 and two confirmatory items.                      The first three open 9 items relate to scoping and screening, which Stan 10 will cover in his discussion of Section 2.
11                    Two    open        items        relate    to        aging 12 management programs.                Allen Hiser will cover one, 13 and Bill Holston will be covering the other in 14 discussion of Section 3.                      The last three open 15 items relate to time limited aging analyses, and 16 Allen          Hiser  will      be      covering        those      in      our 17 discussion of Section 4.
18                    Two confirmatory items also relate to 19 aging          management      programs,          and    again    we      will 20 cover those in Section 3.
21                    CHAIRMAN BLEY:            Have you had time to 22 review the responses to these issues?
23                    MR. FERRER:          We have.
24                    CHAIRMAN BLEY:          So that is included?
25                    MR. FERRER:            Yes.          We    will          be NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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87 1 discussing those once we get into more detail on 2 each one.
3                Moving on to Section 2 of the SER.
4 This section concerns structures and components 5 subject to aging management review.                          The staff 6 has completed its review of scoping and screening 7 methodology and results, with the exception of 8 the open items mentioned earlier.
9                I  will      now    hand        it    over    to      Stan 10 Gardocki      to discuss        the      open      items  and      other 11 items of interest from this section.
12                MR. GARDOCKI:            Good afternoon.                Stan 13 Gardocki.        I  work      in    the      Balance    of      Plant 14 Section, Division of Safety Systems, as Senior 15 Reactor System Engineer.                  I have been involved 16 with the scoping of the plants, and I was on site 17 with the audit conducted in March.
18                The  staff        reviewed          the  applicant's 19 scoping        and      screening              methodology              and 20 implementation        utilizing          the      resources      in      the 21 application,        the      drawings,            and  the        staff 22 augmented that with a physical walkdown of the 23 plant systems during the scoping and screening 24 audit done in March of 2010.
25                During      the    on-site        audit,  the      staff NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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88 1 walked down selected non-safety areas where the 2 plant people identified where the applicant said 3 there          was    no      or      limited          safety      related 4 components.              The    staff      focused        mainly    on      non-5 safety related Turbine Building to verify whether 6 there          was      any        additional            safety        related 7 components in this area.
8                    The staff also walked down the safety 9 related          areas,      mainly        the        emergency        diesel 10 generator          rooms,        the      component          cooling          heat 11 exchanger room, and the auxiliary building, to 12 verify whether there were any unidentified non-13 safety          related    components          in      these  areas        that 14 could          potentially        adversely          affect    the      safety 15 related components.
16                    The staff identified several instances 17 where the applicant's scoping of these components 18 did not align with the proposed methodology.
19                    In    the        non-safety          related      Turbine 20 Building, the staff identified additional safety 21 related components that did not have an adequate 22 evaluation          or  10      CFR    54.4(a)(2)          for  potential 23 adverse effects from the failure of nearby non-24 safety related components.
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89 1 components        identified          in    the      Turbine    Building 2 included control room pressurization system and 3 exhaust        ducts    for    the    switchgear        HVAC    system.
4 Additionally,          the    staff      looked      at  the      safety 5 related cables in the Turbine Building where the 6 applicant credited its mitigation of the conduit, 7 but that was only for the low and medium line 8 breaks, but they didn't evaluate for high energy 9 line breaks.
10                  In the safety related areas, the staff 11 identified            additional            non-safety            related 12 components in the vicinity of the safety related 13 components that did not have an adequate (a)(2) 14 evaluation.          Some of these examples were inside 15 the Diesel Room and the component cooling heat 16 exchanger room.            There were overhead drain lines, 17 and there was additional service water lines in 18 the diesel room.
19                  Outside        in      the        yard    there        were 20 underground vaults and electric pull boxes, which 21 the staff identified sumps and pumps that didn't 22 have an adequate (a)(2) evaluation.
23                  In    the    auxiliary          building    there        was 24 water traps and compressed air system near safety 25 related components.                The staff also identified NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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90 1 instances        where    the    applicant          did  not    include 2 into        scope  non-safety          related        piping  that        was 3 directly        attached      to    safety        related    components 4 past the safety/non-safety related boundary up to 5 the first qualified anchor and, as the applicant 6 said, these were mostly in suppressed gas systems 7 to clean the air, and the nitrogen systems.
8                  The    staff      also      identified      instances 9 where the applicant stopped its (a)(1) scoping at 10 the code class break on safety related piping at 11 an open valve.              The failure of the downstream 12 piping        could    result      in    loss      of  the    pressure 13 boundary of the safety related system.
14                  One      instance          of      this    that          was 15 mentioned is the EDG air start system where the 16 unloader        line    transitted          back      from  the      safety 17 related        air    receiver        back      to    the  non-safety 18 related air compressor.
19                  After the site out was completed in 20 March of 2010, the staff issued about 17 RAIs to 21 the        applicant.            The    applicant's          preliminary 22 response          indicated          that        additional        systems 23 components, especially in the Turbine Building, 24 would have to be added to the scope of license 25 renewal.        As Nate said, there were two responses, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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91 1 LER and maintenance.
2                    Later,        the    applicant          submitted          the 3 changes          to    the    application            to    include        these 4 components in the scope of license renewal, and 5 after          reviewing      the      additional          material,          the 6 staff was able to resolve all the issues except 7 for three open items identified in the SER.
8                    The staff has received the applicant's 9 responses          to    these      open      items      on  January        12, 10 2011.          The applicant has already described their 11 proposed resolutions.                    In conclusion, the staff 12 has reviewed those and their responses, and has 13 now the necessary information from the applicant 14 to satisfactorily resolve these three open items 15 in the final safety evaluation.
16                    Do    you      have    any      questions      on      this 17 matter?
18                    CHAIRMAN        BLEY:          I    am  just    curious.
19 When staff does the walkdown you describe, would 20 you        consider      it    a    spot      check        or  would        you 21 consider it a thorough walkdown?
22                    MR. GARDOCKI:            We systematically look 23 at the application, look at areas of interest.
24 In this particular application, we looked at they 25 excluded          the    Turbine        Building,          and  they        said NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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92 1 there was nothing safety related in there.                              so we 2 would focus on something like that.
3                    We always walkdown general areas where 4 we      find    deficiencies          in    the      application,          EDG 5 rooms, and we identified some --
6                    CHAIRMAN BLEY:            So the areas that drew 7 your          interest,      you      did      a    pretty    thorough 8 walkdown?
9                    MR. GARDOCKI:          Oh, absolutely, and you 10 can        tell    from    the    level        of    detail    that        we 11 identified          quite        a      significant        amount            of 12 components.
13                    DR. BARTON:            What is your assessment 14 of the material condition of the parts of the 15 plant that you looked at in detail?
16                    MR. GARDOCKI:            The material condition 17 was very good.            We walked down the aux building, 18 turbine buildings, and everything had a good coat 19 of paint.          We didn't see any spalling or dirt 20 conditions.          There were some areas we tried to 21 get around in the aux building to the back of the 22 containment to look at some penetrations, and we 23 just couldn't get to it.                  So --
24                    MEMBER ARMIJO:            In the SER there was a 25 mention of a removal of cracked coating on the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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93 1 liner, and it is a small area, but apparently 2 about two square feet were not re-coated after 3 this repair.          I just wondered what the logic was 4 for that.        Are you familiar with that?
5                    MR. GARDOCKI:            I cannot address that 6 matter.
7                    MEMBER ARMIJO:              Maybe the -- I will 8 read it to you:                Defect areas were cleaned and 9 coated at the end of cycle 15, 1R15 and 2R15, 10 total of three square foot cluster; liner plate 11 coatings was found cracked and delaminated at the 12 185      foot  and    195    foot      elevations.        The      loose 13 coatings were removed without repair.                        Two square 14 feet of the three square foot area were left as 15 bare        steel  after      cleaning.            This  area        will 16 require continuous monitoring.
17                    I agree with all of that, and I know 18 it is a small area, but I don't understand the 19 logic of not repairing it.
20                    DR. HISER:          I am not sure that we can 21 address why they didn't repair it.
22                    MEMBER      ARMIJO:          Why    does  the      staff 23 think that is okay?
24                    DR.      HISER:                  Well,    from          our 25 perspective,          as    long      as    they      ensure    that        it NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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94 1 doesn't degrade, then we are -- As long as there 2 is aging management program in place to address 3 that and to monitor that, then I think we are 4 satisfied.
5                  CHAIRMAN BLEY:            I think Diablo Canyon 6 wanted to say something.
7                  MEMBER      ARMIJO:            Does    the  applicant 8 have a response?
9                  MR. WRIGHT:          I will start off.                This 10 is Mike Wright from Diablo.                      We do have an aging 11 management        program        for      containment        coatings.
12 There are -- Part of that program is to identify 13 all degraded coatings at the start of the outage, 14 and we have remedied as much as possible during 15 that        refueling    outage,        and      then  we    identify 16 coatings that would have to be subsequently re-17 coated in the following outage.
18                  So that will be a remedy.                      It just 19 wasn't fixed at --
20                  MEMBER      ARMIJO:          So    it  was    just        an 21 interim problem?
22                  MR. WRIGHT:            Yes,      sir,    that          is 23 correct.
24                  MEMBER      ARMIJO:          Oh,    okay.      I      just 25 thought it was some experiment you were running NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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95 1 or something else, and up at that elevation it 2 may not be the most convenient place to repair 3 it.            I  don't    know.          Okay,        you  answered          my 4 question.
5                    MEMBER      STETKAR:            Staff,    in    the      SER 6 there are statements like "the applicant applied 7 its        evaluation          of      non-safety          related          SCs 8 inconsistently            throughout          the        LRA."          Quite 9 honestly,          there    are    more      RAIs      issued    and      more 10 applicant          responses        to      those        RAIs  regarding 11 scoping and screening than I have seen in the 12 last        two    or  three      years        of      license    renewal 13 applications.
14                    Since your walkdowns -- As you said, 15 the areas that you walk down are pretty thorough, 16 and those resulted in rather extensive RAIs that 17 were focused on the areas you looked at.                                      But 18 since there are only selected areas, how do we 19 have        confidence      in    the      areas        that  you      didn't 20 walkdown,          that    there        aren't        similar    kind        of 21 scoping and screening issues; and when you found 22 the relatively large number of issues, at least 23 by counting RAIs and looking at the responses to 24 those          RAIs    --    for      example,          in  the    Turbine 25 Building -- did you make any conscious effort to NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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96 1 expand the scope of your samples and audits and 2 walkdowns to inspect other areas to see whether 3 or not it simply was focused out in the Turbine 4 Building and that the scoping and screening of 5 (a)(2) type issues in other parts of the plant 6 had, in fact, been done?
7                MR. GARDOCKI:            Okay, I will try it.
8 We      looked  for    --    like      if      you    got    the        aux 9 building, they say everything in the aux building 10 is in scope of license renewal.
11                MEMBER STETKAR:            Okay, that is pretty 12 easy.
13                MR. GARDOCKI:            So that was a pretty 14 easy area.        So we go in there, and we walkdown 15 something just to make sure scoping values were 16 correct.          We      were      trying          to  find          some 17 penetrations      of    the    makeup        water    system        going 18 through        there.          We      are        limited      to        the 19 radiological        areas,        and      we      couldn't        access 20 anymore than we could.
21                There was an area between -- Now the 22 areas that stand out is what we have tried to 23 focus on in this very limited time we were out 24 there, and between the aux building and Turbine 25 Building there is another building in between it.
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97 1                    So we asked them, do you classify it 2 as the aux building or do you classify it as the 3 Turbine Building?              So those are the areas we kind 4 of focus on and try to clarify that area:                            Do you 5 classify        it  as    aux    building?          Everything          in 6 scope.          For  the      Turbine      Building,      nothing          in 7 scope.
8                    Then we refocus our review when we get 9 back to the office to see if there is anything in 10 that area that has particular interest.                                So we 11 follow to the main steam piping out there.                                    We 12 asked        some  RAIs    to    clarify        the  boundaries          on 13 those.
14                    The Turbine Building, when they said 15 they excluded it initially, I mean, we focused 16 right on that area to see if there was anything 17 else        in  that  area,      and      we    found  some      safety 18 related in there.                And if you didn't scope it 19 initially, you don't have any basis to evaluate 20 to.          So  we  had      to    wait      for    that  additional 21 scoping to come in.
22                    Then    we    focused        on  the  particular 23 lines they called conduit with safety related.
24 They        said,    well,        we    use        the  conduit          for 25 mitigation, but then you didn't use it for all NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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98 1 mitigations.          So then you had to scope the entire 2 Turbine Building for high pressure piping.
3                    So there was a very substantial amount 4 of additional components put in scope after our 5 audit.          So we focused our audits mainly on areas 6 where we would think we would find some problems, 7 based on previous audits where we find problems.
8  Then those areas that stand out, like here the 9 Turbine Building or that building between the aux 10 buildings, or if they have main steam piping and 11 feedwater piping that is routed outside of the 12 aux      building    to    go    into      containment,      we      would 13 walk those particular areas down to see how they 14 are managed for aging management, or in scope.
15                    MR. HOLIAN:          This is Brian Holian.                I 16 wanted        to  add  to    the    question      maybe    and      the 17 answer.          On the question, it is a question we ask 18 during        review,    branch        chief      review  and      senior 19 management review of the SER for that purpose.
20                    Staff    --    We    are      still  pushing        the 21 staff.          But when you ask an RAI on an item, get 22 that right, but ask the Part B to the RAI, which 23 is:        We found this one or think we found this 24 one; give us some assurance that you have sampled 25 other areas or you have gone there.
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99 1                    I think we are pretty good on doing 2 that in RAIs.            Sometimes we don't also translate 3 that to the SER write-up that says that we kind 4 of      asked    that  second        part      of    the  question          or 5 during discussions, it had that.
6                    So I don't see it all the time in the 7 SER write-up that we are asking the extent of 8 condition question of them to also do that.                                Stan 9 and -- you know, even in the past week sitting in 10 here, as I have looked back this year -- kind of 11 reiterated that some of those items -- you know, 12 the very specific ones, caused other issues to be 13 found by them as part of that extended condition.
14                    So a lot of the detail items came out 15 of that type of questioning, but I agree with you 16 that        the    staff    can      be    even      more  overt          in 17 translating it into the SER.                      I have told them to 18 tell the story a bit better about what did you 19 find, and then what did the applicant have to do.
20                    MEMBER STETKAR: That helps.                      Thanks, 21 Brian, because the way I read the SER is there 22 was a large number of individually identified, as 23 you said, focused items, a large number of which 24 were        resolved    by      very    focused        responses      of      a 25 handful          or  whatever,          which        are  still        being NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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100 1 discussed,        and      then        there        is  the      overall 2 conclusion that says, with the exception of this 3 handful, everything is fine.
4                  MR. HOLIAN:              That is right, and it 5 leaves out the in between.                        Why did the staff 6 have a good feeling that we didn't need to go do 7 a    second    audit.        But    we    ask    ourselves        those 8 questions.
9                  MEMBER STETKAR:            Thank you.
10                  DR. BARTON:            Along those same lines, 11 in the SER it talks about the external surface 12 monitoring program, and the inspection team noted 13 that        the  training      program          for    the    personnel 14 performing        these      inspections            did  not    meet        the 15 commitment the applicant made for training.                                So I 16 wonder if the people that the applicant had out 17 there doing external surfaces monitoring weren't 18 probably trained.
19                  How was this ever resolved?                    Did these 20 guys get requalified?                  Did you guys go look at 21 that?
22                  MR. PICK:          As    an      inspection        team, 23 during our interviews the system engineers and 24 the people doing aging management -- they had a 25 lot of criteria for what was aging management, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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101 1 but they weren't comfortable that they had enough 2 background.            They      were    using        common  sense        and 3 their procedures, which were quite good, and they 4 all commented to the external surfaces program 5 reviewer that they would like more training.
6                    When        we      brought          that    to          the 7 applicant's attention, they went and did their 8 own survey, and I will let them respond to what 9 they found.
10                    MR. WRIGHT:            This is Mike Wright from 11 Diablo.          We agreed with the Region IV inspection 12 team.          We  have      committed          to    doing    extensive 13 training for all system engineers prior to the 14 December          of    this      year      to      close    the    gap        on 15 training,          and  for      sustainability,            include        that 16 training as part of the qualification for system 17 engineers.
18                    DR. BARTON:          Thank you.
19                    MR. GARDOCKI:            Well,      if  there's          no 20 more          further      questions,            that      concludes            my 21 presentation.
22                    MR. FERRER:          Thank you, Stan.            I would 23 like        to  highlight        just    one      item    on  open        item 24 2.3.3.14-1.            The      topic      of      this    item    actually 25 became an inspection finding, as documented in an NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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102 1 inspection report dated September 9, 2010.
2                    I just highlight that, because just to 3 show        sometimes      when      we    are      doing    the    license 4 renewal reviews, we find things that we can pass 5 on      to    regional      staff      or    residents      in    current 6 operating space.
7                    With that, I would pass it on to Greg 8 Pick from Region IV.
9                    MR. PICK:            Thanks,        Nate.            Good 10 afternoon, members of the ACRS Committee.
11                    I  led      the    inspection        team,    and        we 12 conducted an extensive review using one of our 13 most        experienced        teams.            The    six  inspectors 14 shared 170 years of inspection experience.                                      We 15 looked        at  60  percent        of    the      aging  management 16 programs,          instead        of    the      nominal    40      to      50 17 percent.
18                    We    reviewed          24      of    the    40      aging 19 management          programs      that      were      in  existence          at 20 that time, and this included six of the nine new 21 aging management programs.
22                    We    evaluated          whether        the  applicant 23 properly          scoped      non-safety          related    structures, 24 systems and components that could affect safety 25 related structures, systems and components, and NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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103 1 whether they developed aging management programs 2 consistent with the GALL report.
3                  We    focused        on    the        conditions        that 4 existed        at    the    plant      and      how    the  applicant 5 implemented        their      existing          programs      that        were 6 going to be aging management programs, and their 7 plans for implementing their new aging management 8 programs.
9                  We    also      performed          a  vertical        slice 10 evaluation of three systems to assess whether the 11 identified        aging      management          programs    could          be 12 expected        to  effectively          manage        the  effects          of 13 aging.
14                  We    also      looked        at      the  applicant's 15 treatment        of    latest      industry          aging  issues        and 16 several site specific issues.                      Next slide.
17                  During our reviews, we looked at the 18 conditions          of      the      structures,            systems          and 19 components needed to withstand a seismic event.
20 These included the supports and restraints, the 21 applicant's program for evaluating the effects of 22 non-safety        related        equipment            affecting        safety 23 related equipment and their Class 2 equipment, an 24 the        structural      inspector        also        considered          the 25 seismic design in his review of the walls -- the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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104 1 design information.
2                  We looked at the buried pipe program 3 with        a  focus  on    environmental            monitoring.              We 4 looked        at  inaccessible          medium        voltage      cables, 5 because the plant had documented aging experience 6 problems        with  those      cables,          and  we  looked          at 7 their metal enclosed bus program because they had 8 experienced        bus    part      failures        in  their        past.
9 Next slide.
10                  Related to scoping, when we arrived on 11 site        the  applicant        was    in      the    process          of 12 incorporating lessons learned related to scoping 13 from        a  previous      STARS      plant,        similar      to      the 14 scoping team.
15                  IN addition, I had talked with Stan in 16 detail prior to going to the site to see how I 17 might assist him in getting eyes on some of the 18 requests for additional information responses and 19 verify the information being provided.
20                  The      items          that        we      assisted 21 headquarters reviewers in resolving included:                                  We 22 verified the configuration of non-safety related 23 service water cooling piping that went into the 24 room; we verified that no safety related electric 25 cables were present in the oily waste sump room.
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105 1                    We verified that the water spray from 2 a      service      cooling        water      pump    in  the    Turbine 3 Building would not have affected the control room 4 pressurization            system      components.          We    verified 5 the      physical      configurations              reflected    in      their 6 Turbine Building reviews, that in fact the cables 7 were in conduits, the safety related cables for 8 the high energy line break.
9                      During our vertical slice review of 10 the compressed air system, we identified examples 11 of items that had not been considered for aging 12 management.
13                    The    unloader        valves      for  the      diesel 14 generator air compressors -- they were made of 15 two materials, stainless steel and copper, and we 16 asked          how  they    monitored          for    aging    effects.
17 Well, they did, in fact.                      They have a five-year 18 PM,        and    they    have      a    line      item  to    look        for 19 evidence of corrosion when they do that five-year 20 PM.          But  they    had    not      included      it  in      their 21 evaluation in their license renewal application.
22  So they updated that.
23                    The other one was they had flexible 24 hoses attached to their back-up nitrogen bottles.
25  That was identified as a steel line on their NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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106 1 drawings when, in fact, it was flexible hoses, 2 and they put that in a 10-year PM.
3                  In  regard        to    the      aging    management 4 programs, we already discussed that training was 5 required        for  the    system      engineers.            We      also 6 discussed the one instance related to age related 7 degradation of the silicon seal for the abandoned 8 containment        screening        stage        cover    plate,        which 9 allowed rain to enter the metal box.
10                  We identified this through review of 11 test        reports    where        they        did    a    containment 12 integrated        leak    rate      test      in    the    inspections.
13 They took photographs of the abnormal conditions 14 and had it included as part of the report.                              So we 15 asked,        what  are    you      doing        as    far  as      aging 16 management        of  this,      and    they      have    agreed          to 17 monitor        it,  seal      them,      and      then    eventually 18 perform a plant modification to seal the metal 19 boxes.
20                  For  the      inaccessible            medium    voltage 21 cables in the cable vaults, they were routed on 22 supports.          They didn't have any criteria when we 23 were        on  site    for      looking          at    the    support 24 structures        for  the    cables.            So  they    issued          a 25 corrective action document to add that to their NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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107 1 structures monitoring program anytime the vaults 2 are opened.
3                  MEMBER STETKAR:                Greg, when you did 4 the      inspection    --    I  don't      have      my  notes        here 5 complete        --  did    you    actually          look  in    some        of 6 those?
7                  MR. PICK:          We    did      not  look    in      the 8 vaults.
9                  MEMBER STETKAR: Didn't look in any of 10 them?
11                  MR. PICK:          But we gave the residents 12 criteria, and they agreed to look in the vaults.
13                  MEMBER      STETKAR:                But    you      didn't 14 actually?
15                  MR. PICK:        But we did not put eyes on 16 them, no.
17                  MEMBER ABDEL-KHALIk:                  What is the span 18 over which the cables were supported?
19                  MR. PICK:            It appeared to be about 20 four feet.        I am not sure.              But the droop based 21 on the span couldn't be anymore than 12 inches.
22 The electrical inspector determined that.
23                  The  last      one,      the      location    selected 24 for        fouling:      For    the      closed        cooling        water 25 inspection criteria, they selected two valves to NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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108 1 look for fouling, because we already had a PM 2 when they opened it.
3                    We asked the question, is that a low 4 flow        area,    because        when      you      read    all      their 5 experience, they were about closing in the low 6 flow areas.            They wrote a notification, took a 7 look, discovered it is not a low flow area.                                      So 8 they        are  looking      for    alternate          locations        as    a 9 result        of  it    being      in    their        corrective      action 10 program.
11                    We    also      found      a      couple    of      minor 12 procedure          issues.          With      their        heat  exchanger 13 program, right now Generic Letter 13 allows you 14 to      do    maintenance        and      did      not    require        heat 15 exchanger          testing,        but      their        license    renewal 16 application          said      we    will        do    heat  exchanger 17 testing.
18                    Their procedure said it was prudent.
19 Well, the fixes are going to take out the option 20 of      it    being  a    prudent      test,        and it is now a 21 required test.
22                    The second one was they do predictive 23 maintenance thermography of their metal enclosed 24 bus stops.            Well, predictive maintenance isn't 25 required.            It  is    something          that    they    do,      but NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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109 1 again        the  license      renewal        application        said        we 2 will do this as our way of monitoring aging.                                    So 3 they now have to keep them as records.                            They are 4 required, versus being an option of keeping those 5 records.
6                    DR. BARTON:          Don't most people do that 7 anyhow?
8                    MR.PICK:      They do the thermography for 9 other plants.            I can't answer whether they keep 10 them        as    quality    records.            That    is  why      it      is 11 minor.          They might keep the record, but they are 12 not required to.
13                    DR. BARTON:        I got you.
14                    MR. PICK:          Next slide.          Overall, we 15 also        found    that      the    plant        had  good    material 16 condition.          We would go in one of the diesel fuel 17 vaults.          Didn't find any issues with that.
18                    The applicant had developed procedures 19 for many programs, and it had initiated plans to 20 incorporate          aging      management            evaluations        into 21 their day to day activities.
22                    They are developing a long term plan 23 that        looks    to    be    implemented            over  the        next 24 several        years.        By    the      time      they  get    to      the 25 period of extended operations, it will just be NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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110 1 part of their routine way of doing business, and 2 the procedures were drafted when we were there.
3 So as inspectors, we had lots of information to 4 review where we could make decisions and comment 5 on      whether    we    thought        it      would    do    --      the 6 procedure would accomplish what was expected of 7 it.
8                    They already identified that they had 9 replaced            several          major          components,            and 10 essentially resets the clock on aging.                            And you 11 already        discussed      the    intake        structure.          They 12 also        replaced    some      high      voltage        insulators          on 13 their station blackout lines.                      Yes, sir?
14                    MEMBER SIEBER:              What was the reason 15 that they replaced insulators?                          Was it -- Some 16 insulators have manufacturing --
17                    MR. PICK:          I do not -- It may have 18 been cracking, but I do not recall.
19                    MEMBER SIEBER:            Another thing is that 20 plants        that  are    located        at    salt    water    collect 21 salt on the insulators.
22                    MR. PICK:          I know they do.              They do 23 spray on their insulators, but I believe they --
24                    MEMBER SIEBER:            I would sure like to 25 know what steps you go through periodically to NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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111 1 make sure the insulators are not building up salt 2 and capable of flashovers.
3                    MR. GORYANCE:                My name      is        Joe 4 Goryance, Diablo Canyon License Renewal,                            5R kV, 5 230 kV system engineer and supervisor.
6                    Our program is based on General Order 7 95, which is a California order.                      We have to, by 8 California law, inspect our insulators.                        Based on 9 our local climate, we have -- We are at a high 10 salt spray area, being close to the ocean, high 11 winds.          So  we    have    an    inspection      program        for 12 that.
13                    For our 5R kV insulators, we do a hot 14 wash every six weeks.                  Based on rainfall, we can 15 defer that if we get one inch of rain in a 24-16 hour period.          So that is our program.
17                    During the inspection part, we noticed 18 that          we  started        having          some  rust.            The 19 galvanizing on porcelain insulators was starting 20 to show signs of rust.                  So then we replaced that 21 string of insulators on the 5R kV system, and our 22 230 kVs also have been replaced.
23                    MEMBER SIEBER:          Thank you.
24                    MEMBER      ABDEL-KHALIK:            You  mentioned 25 you do hot wash on the 500 kV, and that is what I NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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112 1 read in the report.                I didn't hear anything about 2 hot washing the 230 kV.                  Do you do that?
3                    MR. GORYANCE:            Our 230 kV are polymer 4 insulators.          They are not porcelain.                  So we can't 5 wash        those.      The    polymer        types      have    a    better 6 creepage distance. So they are not required.
7                    MEMBER ABDEL-KHALIK:                Thanks.
8                    MR. PICK:        Thank you.          The scoping of 9 -- Our overall conclusions from the inspection:
10 The scoping of non-safety structures, systems and 11 components          and    the      application          of    the      aging 12 management programs to those structures, systems 13 and components were acceptable.
14                    Applicant      personnel          had  incorporated 15 actions to manage their aging effects into their 16 programs,          and  reasonable          assurance      exists        that 17 aging          effects    will      be    managed        and    intended 18 functions maintained.
19                    With that, I am going to turn this 20 back        over    to    Nate,        unless        there    are        any 21 additional questions.
22                    MEMBER STETKAR:              Yes, Greg.          Since I 23 beat up the applicant, I might as well beat you 24 up.            The  inspection          report        says    the        team 25 determined          that      the      applicant          had    recently NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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113 1 upgraded        the    cathodic        protection        system          and 2 programs.
3                  Words like recently always send a flag 4 forme,        especially      because        your      inspection          was 5 done in 2010.          What does that phrase mean, since 6 you      guys  did  the    inspection?              Was  the      recent 7 upgrade the actual 1995 installation, 15 years 8 before you did the inspection?
9                  MR. PICK:          I do not know the exact 10 time frame reflected in that phrase.
11                  MEMBER      STETKAR:              You  want    to      ask 12 Diablo.          You heard the answer that, well, they 13 installed it in 1995, and its current reliability 14 is        90    percent      or      better        or    whatever          the 15 requirements are.              But this seems to imply that 16 the inspection team discovered something that had 17 been done, quote, "recently," which implies that, 18 before recently, whenever that was, it wasn't so 19 good.
20                  DR. BARTON:          Depends what you timing 21 is.        Is 15 years recent?
22                  MEMBER      STETKAR:              Yes,  recent          in 23 geologic time perhaps.
24                  MR. HOLIAN:          Bill,        do  you    want        to 25 answer?
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114 1                    MR. HOLSTON:          Yes.        I was just waiting 2 for the discussion.                Yes, the applicant had noted 3 corrosion in their aux salt water system that was 4 down in the lower basin.                        So in that mid-late 5 Nineties,          they    bypassed        a    whole    lot    of      that 6 piping, put new piping in, upgraded the cathodic 7 protection          system      to    ensure        that    they        would 8 protect the newly installed piping.
9                    There were some other modifications, 10 too.          They  had    some      corrosion        of  diesel        fuel 11 piping.          Now instead of cathodically protecting 12 that, they replaced that diesel fuel piping and 13 ran      it    in  underground          vaults.          So  now      it      is 14 exposed to air.            So that is what they have done.
15                    Currently,        their        cathodic      protection 16 system is available greater than 90 percent of 17 the time.            They conduct annual NACE testing to 18 ensure that the system is effective by measuring 19 the pipe-to-soil potentials.
20                    MEMBER STETKAR:                Right.      I read and 21 heard,          and  I  understand          all      of    that.            The 22 question, I guess, then is still:                              Is 1995 the 23 recent          upgrade,      and      indeed        has    the    cathodic 24 protection system, if that is the recent upgrade, 25 been available 90 percent of the time or better NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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Docket Number:
115 1 since 1995 then?
  (n/a)
2                      MR.      HOLSTON:                    That      is          my 3 understanding.                Yes,      sir.          And    that    is      from 4 talking          to  the    applicant,          working      through        the 5 request        for    additional          information.            I    am      not 6 aware of any period of time where, once they put 7 the        new    cathodic      protection          system    in,      which 8 again was mid- kind of like '95-'96 or it might 9 have been '94, that they had a period where it 10 went out of effective monitoring.
11                      MEMBER STETKAR:            I am just triggering 12 on the word recently, you know.                              That, to me, 13 implies maybe in the last year or two rather than 14 15 years ago.            So, thanks.
15                      I actually know how some of the people 16 prepare for the license renewal applications, and 17 recent sometimes means six months ago.                            Thanks.
18                      MR. PICK:      Any other questions?
19                      MR. FERRER:         Thanks, Greg.          I will now 20 move        on    to  Section      3,    Aging        Management      Review 21 results.
22                      Section 3.0 covers the staff's review 23 of the applicant's aging management programs.                                      I 24 will        just    note    that    the      open      and confirmatory 25 items        in    Section      3  are    all      discussed      in      this NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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Location: Rockville, Maryland
116 1 section.
2                    Sections 3.1 through 3.6 cover aging 3 management review items, and each of the systems 4 within the scope of license renewal.                          For a given 5 aging management review, the staff reviewed the 6 items to determine whether it was consistent with 7 the        GALL    report      and,      if    an      aging    management 8 review          is    not      consistent,            then    the        staff 9 conducted a technical review to ensure adequacy.
10                    As    the    applicant          previously      stated, 11 they submitted 42 aging management programs, and 12 there were approximately 3,000 aging management 13 review          items.        Of    the      42      aging    management 14 programs, 31 were existing, nine are new, and two 15 plant specific.
16                    As I noted earlier, there are two open 17 items          related    to      aging      management        programs.
18 Allen Hiser will discuss the open item related to 19 the flux thimble tube inspection program at this 20 time.
21                    DR. HISER:           Thanks, Nate.            The flux 22 thimble          tube    inspection          program        is    a      GALL 23 program. During the staff's review, the one item 24 that really stuck out to us was the operating 25 experience at Diablo Canyon.
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Date:  Wednesday, February 9, 2011
117 1                    I don't want to rehash much of what 2 the applicant provided earlier, but a lot of the 3 RAIs        in  the  open      item      relate      back    to      that 4 finding.          The one area I guess I did want to 5 highlight was the concern that the staff has that 6 the wear rate projection methodology employed by 7 the applicant may be nonconservative.
8                    So    it      may      not        give    conservative 9 estimates of wear that would be measured after 10 the current operating cycle, and that is one area 11 that we still have the open item that we will 12 review applicant's response to, and we will reach 13 a      determination        on    the      acceptability          of      the 14 program based on that review.
15                    MEMBER      STETKAR:         Allen,    the    way        at 16 least I read the SER, the concern seemed to be 17 focused        on  the    thinning        threshold,      and      I    was 18 under the impression it was different from what 19 Diablo        said,   that      they      are      using  68    percent 20 rather than 80 percent.
21                    What is the real concern?                  Is it the 22 methodology on how they project the rate or that 23 actual          acceptance        criterion            --  the    staff's 24 concern.
25                    DR. HISER:        It really is a combination NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
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Work Order No.:
118 1 of all pieces.             The project methodology does not 2 incorporate explicit uncertainty considerations.
NRC-698 Pages 1-145 
3                    MEMBER STETKAR:             Let me ask you then 4 what          is    different          in      Diablo's        methodology 5 compared          to  other      previously          approved    license 6 renewal applications that indeed have used an 80 7 percent thinning acceptance criterion?
8                    DR. HISER:        Jim Medoff is here.
9                    MEMBER STETKAR:              Is their methodology 10 different?
11                    DR. HISER:        The main reviewer on a lot 12 of this.
13                    MR. MEDOFF:          This is Jim Medoff of the 14 staff.          I was the peer reviewer for the flux 15 thimble          tube    inspection            program      for      Diablo 16 Canyon.
17                    The  big      difference          is  some    of      the 18 other          applicants      have      adopted        the  WCAP      12866 19 methodology.            So their acceptance criteria is set 20 to      80    percent      on    that      basis,      and  then        the 21 Westinghouse methodology included uncertainty to 22 derive          that    80      percent          through-wall          wear 23 acceptance criteria.
24                    For Diablo Canyon, it is a little bit 25 different.            They have a certain procedure that NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
(202) 234-4433            WASHINGTON, D.C. 20005-3701        www.nealrgross.com


NEAL R. GROSS AND CO., INC.
119 1 refers to a different Westinghouse plant specific 2 calculation for them, and that calculation set 3 the        acceptable    wear      criterion          to  68    percent 4 through wall, including uncertainty.
Court Reporters and Transcribers 1323 Rhode Island Avenue, N.W.
5                  Then later on, the applicant had done 6 a      50.59    to  that      Westinghouse            methodology          to 7 remove the uncertainty based on a comparison to 8 the        WCAP  methodology,          even      though    it    is      not 9 really part of their licensing basis.
Washington, D.C. 20005 (202) 234-4433 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
10                  CHAIRMAN BLEY:              Compared to the new 11 WCAP methodology?
(202) 234-4433 WASHINGTON, D.C. 20005
12                  MR. MEDOFF:            Yes.        Yes. So that is 13 what we are trying to figure out, whether that is 14 an acceptable basis or not, and we are looking 15 that over.
-3701 www.nealrgross.com 1  1  2 DISCLAIMER 3  4  5 UNITED STATES NUCLEAR REGULATORY COMMISSION'S 6 ADVISORY COMMITTEE ON REACTOR SAFEGUARDS 7  8  9  The contents of this transcript of the 10 proceeding of the United States Nuclear Regulatory 11 Commission Advisory Committee on Reactor Safeguards, 12 as reported herein, is a record of the discussions 13 recorded at the m eeting. 14  15  This transcript has not been reviewed, 16 corrected, and edited, and it may contain 17 inaccuracies.
16                  The      other        matter          is    the        wear 17 projections,        including          whether        it  should        have 18 uncertainties in it, and to figure out whether 19 the way they do wear projection is conservative.
18  19  20  21  22  23 24 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
20  Their current program does wear projections on a 21 linear basis, but some of the wear history that 22 we have audited for the program may indicate that 23 they are getting some non-linear wear, and we are 24 wondering          whether          the        linear      basis            is 25 conservative at this point.
(202) 234-4433 WASHINGTON, D.C. 20005
NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
-3701 www.nealrgross.com 2  UNITED STATES OF AMERICA 1  NUCLEAR REGULATORY COMMISSION 2  + + + + + 3  ADVISORY COMMITTEE ON REACTOR SAFEGUARDS 4  (ACRS) 5  + + + + + 6  PLANT LICENSE RENEWAL SUBCOMMITTEE 7  DIABLO CANYON POWER PLANT 8  + + + + + 9  WEDNESDAY 10  FEBRUARY 9, 2011 11  + + + + + 12  ROCKVILLE, MARYLAND 13  + + + + + 14  The Subcommittee met at the Nuclear 15 Regulatory Commission, Two White Flint North, 16 Room T2-B1, at 1:30 p.m., Dennis C. Bl ey, 17 Chairman, presiding.
(202) 234-4433          WASHINGTON, D.C. 20005-3701          www.nealrgross.com
18  19 COMMITTEE MEMBERS:
 
20  DENNIS C. BLEY          Chairman 21  SAID ABDEL
120 1                    They have given us access to some non-2 docketed information that we are doing sort of an 3 informal          audit  of    now
-KHALIK      Member 22  J. SAM ARMIJO Member 23  SANJOY BANERJEE        Member 24  MICHAEL L. CORRADINI    Member 25 26 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
(202) 234-4433 WASHINGTON, D.C. 20005
-3701 www.nealrgross.com 3  HAROLD B. RAY          Member 1  MICHAEL T. RYAN Member 2  WILLIAM J. SHACK        Member 3  JOHN D. SIEBER          Member 4  JOHN W. STETKAR        Member at Large 5  6 ACRS CONSULTANTS PRESENT:
7  JOHN J. BARTON 8  9 NRC STAFF PRESENT:
10  NATHANIEL FERRER, NRR 11  MELANIE GALLOWAY, NRR/DLR 12  STAN GARDOCKI, NRR/DSS 13  ALLEN HISER, NRR/DLR 14  BRIAN HOLIAN, NRR/DLR 15  WILLIAM HOLSTON, NRR/DLR 16  JAMES MEDOFF, NRR/DLR 17  NEIL O'KEEFE 18  GREG PICK, Region IV 19  JEFF POEHLER, NRR/DSI 20  DAVE WRONA, NRR/DLR 21  MICHAEL BENSON, Designated Federal Official 22  23  24 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
(202) 234-4433 WASHINGTON, D.C. 20005
-3701 www.nealrgross.com 4 ALSO PRESENT FROM PG&E 1  MICHELLE ALBRIGHT 2  CHRIS BEARD 3  JIM BECKER 4  DAVID GERBER, Structural Integrity 5  Associates 6  DAVID GONZALEZ 7  JOE GORYANCE 8  LEE GOYETTE 9  TERRY GREBEL 10  DANIEL HARDESTY 11  MARK MAYER 12  DAVE MIKLUSH 13  CHALMER MYER 14  LOREN SHARP 15  MIRANDA TAN 16  RYAN WEST 17  DAVID WONG 18  MIKE WRIGH T 19  20  21  22  23  24 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
(202) 234-4433 WASHINGTON, D.C. 20005
-3701 www.nealrgross.com 5  TABLE OF CONTENTS 1            AGENDA ITEM PAGE 2 Opening Remarks, Dennis Bley, ACRS 6 3 Staff Introduction, Brian Holian 7 4 PG&E Company
- Diablo Canyon Power Plant:
5  Introductions; Site & Station 13 6    Descriptions, Jim Becker 7  History/Major Improvements, Loren Sharp 18 8  License Renewal Application; Open 20 9  and Confirmatory Items, Terry Grebel 10  Flux Thimble Tube Inspection Program 29 11  (Open Item), Mike Wright 12  Flaw Growth Evaluation for RHR (Open 39 13  Item), Dave Gonzalez 14  Scoping and Scree ning (Open Items);
55 15  Buried Piping and Tanks Inspection 16  Program (Open Item), Dave Miklush 17  TLAA Identification and Metal Fatigue 66 18  (Open Items), Michelle Albright 19 NRC STAFF:  Nathaniel Ferrer, Greg Pick 20  SER Overview and Scoping and 81 21  Screening Results; Onsite Inspection Results 22  Aging Management Review; and 102 23  Time Limited Aging Analyses 24 Subcommittee Discussion 141 25 26 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
(202) 234-4433 WASHINGTON, D.C. 20005
-3701 www.nealrgross.com 6  P-R-O-C-C-E-D-I-N-G-S 1  Time:  1:30 p.m.
2  CHAIRMAN BLEY:  The meeting will now 3 come to order. This is a meeting of the Plant 4 License Renewal Subcommittee of the Advisory 5 Committee on Reactor Safeguards.
6  I am Dennis Bley, Chairman of the 7 Subcommittee. ACRS Members in attendance today 8 are Bill Shack, Mike Ryan, John Stetkar, Said 9 Abdel-Khalik, Sam Armijo, Harold Ray and Jack 10 Sieb er. 11  We have Tom Barton as our consultant, 12 and Michael Benson is the Designated Federal 13 Official for this meeting.
14  The Subcommittee will review the 15 License Renewal Application of the Diablo Canyon 16 Power Plant, Units 1 and 2, and the associated 17 SER with open items. We will hear presentations 18 from the NRC staff and Pacific Gas and Electric, 19 PG&E. 20  We have received no written comments 21 or requests for time to make oral statements from 22 members of the public regarding today's meeting.
23  I will mention that th e next-door conference 24 room is also following this meeting on the TV 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.
(202) 234-4433 WASHINGTON, D.


==Background:==
==Background:==


-Evaluated the characteristics of the flaw as non
    - Evaluated the characteristics of the flaw as non-service induced
-service induced  
    - Fatigue crack growth evaluated with acceptable results
-Fatigue crack growth evaluated with acceptable results
    - Subsequent 2000 UT inspection result consistent with non-service induced (no growth)
-Subsequent 2000 UT inspection result consistent with non
Resolution:
-service induced (no growth)Resolution:  
    - SCC evaluation performed with acceptable results
-SCC evaluation performed with acceptable results
    - Confirmatory UT inspection of WIC-95 during the 2012 outage 23
-Confirmatory UT inspection of WIC
 
-95 during the 2012 outage 24Flaw Growth Evaluation for RHR Piping Weld WIC
Flaw Growth Evaluation for RHR Piping Weld WIC-95 24
-95 25Flaw Growth Evaluation for RHR Piping Weld WIC
 
-95 26Dave MiklushDiablo Canyon License Renewal Project 27SCOPING AND SCREENINGOI 2.1-1 -SER 2.1.4.1.2Issue: -NSR fluid-filled components in the vicinity of SR components(1) Rainwater entering HVAC ducting to vital 480V switchgear room(2) Firewater piping in the vicinity of the Control Room Pressurization System I&C(3) Firewater piping and domestic water piping in the vicinity of HVAC exhaust openings to 4kV switchgear roomResolution: (1) Enhanced water drainage provisions in Unit 2 HVAC exhaust ducting (2) Include in scope firewater piping under 10 CFR 54.4(a)(2)
Flaw Growth Evaluation for RHR Piping Weld WIC-95 25
(3) Include in scope firewater and domestic water piping under 10 CFR 54.4(a)(2) 28SCOPING AND SCREENING OI 2.1-1 -SER 2.3Issue: -NSR fluid-filled components leaking or spraying onto SR cables in electrical pull boxesResolution:
 
-Pull boxes drain to building sumps or in
Dave Miklush Diablo Canyon License Renewal Project 26
-ground sumps
 
-In-scope pull boxes are physically separated from the sumps and from the pumps and discharge piping 29SCOPING AND SCREENINGOI 2.1-1 -SER 2.3.3.7.2Issue: -NSR fluid-filled water traps spraying onto SR componentsResolution:
SCOPING AND SCREENING OI 2.1 SER 2.1.4.1.2 Issue:
-This portion of system is not used
    - NSR fluid-filled components in the vicinity of SR components (1) Rainwater entering HVAC ducting to vital 480V switchgear room (2) Firewater piping in the vicinity of the Control Room Pressurization System I&C (3) Firewater piping and domestic water piping in the vicinity of HVAC exhaust openings to 4kV switchgear room Resolution:
-Commitment to close the upstream isolation valves and drain any contained water from the traps 30SCOPING AND SCREENINGOI 2.3-1 -SER 2.3Issue: -NSR tubing directly attached to SR solenoid valves in the compressed air systemResolution:  
(1) Enhanced water drainage provisions in Unit 2 HVAC exhaust ducting (2) Include in scope firewater piping under 10 CFR 54.4(a)(2)
-All NSR tubing directly attached to SR solenoid valves in the compressed air system is included in scope up to the first seismic or equivalent anchor on the NSR side of the code break 31SCOPING AND SCREENINGOI 2.3.3.14 SER 2.3.3.14.2Issue: -Scoping methodology of Diesel Generator compressor unloader line endpoint for pressure boundary functionResolution:  
(3) Include in scope firewater and domestic water piping under 10 CFR 54.4(a)(2) 27
-Design change relocates unloader tubing to the compressor discharge piping upstream of the pressure boundary isolation check valve
 
-After design change unloader line is no longer in
SCOPING AND SCREENING OI 2.1 SER 2.3 Issue:
-scope-Completed on Unit 1; Unit 2 scheduled for April 2011 32BURIED PIPING AND TANKS INSPECTION PROGRAM OI 3.0.3.2.8 SER 3.0.3.2.8Issue:-Management of aging effect for buried copper valves in the Makeup Water System
    - NSR fluid-filled components leaking or spraying onto SR cables in electrical pull boxes Resolution:
-Clarification of in
    - Pull boxes drain to building sumps or in-ground sumps
-scope steel pipe in the Makeup Water SystemResolution:  
    - In-scope pull boxes are physically separated from the sumps and from the pumps and discharge piping 28
-Buried copper valves will be managed by the Buried Piping and Tanks Inspection Program
 
-Commitment to enhance operating procedure to close Makeup Water System isolation valve in event of a pressure boundary failure and removed steel piping and components from scope 33Michelle AlbrightDiablo Canyon License Renewal Project 34TIME-LIMITED AGING ANALYSES IDENTIFICATION OI 4.1-1RAIs:-Reactor coolant pressure boundary valves
SCOPING AND SCREENING OI 2.1 SER 2.3.3.7.2 Issue:
-Baffle and former boltsResolution:
    - NSR fluid-filled water traps spraying onto SR components Resolution:
-Confirmed DCPP design codes for the reactor coolant pressure boundary valves do not require a fatigue analysis
    - This portion of system is not used
-Fatigue of the baffle and former bolts is managed by the Reactor Vessel Internals AMP 35METAL FATIGUEOI 4.3-1Additional information
    - Commitment to close the upstream isolation valves and drain any contained water from the traps 29
-Replacement reactor head CUF values
 
-AMR revisions for piping system cumulative fatigue damage Clarification
SCOPING AND SCREENING OI 2.3 SER 2.3 Issue:
-Cycle counting for upper and lower core plates
    - NSR tubing directly attached to SR solenoid valves in the compressed air system Resolution:
-Cycle estimates for the "Auxiliary Spray during Plant Cooldown" transient  
    - All NSR tubing directly attached to SR solenoid valves in the compressed air system is included in scope up to the first seismic or equivalent anchor on the NSR side of the code break 30
-Charging system cycle estimate methodology during unmonitored periods  
 
-Electrical raceway seismic evaluation requirementsFSAR/CLB enhancement
SCOPING AND SCREENING OI 2.3.3.14 SER 2.3.3.14.2 Issue:
-Load-following transients used in design analyses and the FSAR  
    - Scoping methodology of Diesel Generator compressor unloader line endpoint for pressure boundary function Resolution:
-Monitoring transients in non
    - Design change relocates unloader tubing to the compressor discharge piping upstream of the pressure boundary isolation check valve
-CUF type analysesEvaluate DCPP Environmentally
    - After design change unloader line is no longer in-scope
-Assisted Fatigue analyses 36Concluding RemarksJim BeckerSite Vice President 66 Flaw Growth Evaluation for RHR Piping Weld WIC-95 70 FLUX THIMBLE TUBE 44 Needed for Tech Spec Flux Map 50 54 UseableThimble Tube RemovedN/A 1 (L-13)Guide Tube CappedScheduled for Replacement in 2R16, May 2011 None Observed 7 4 Capped Minimal (Outside Chrome Band)10 21Chrome: 12 Feet No Wear on Chrome Band Minimal (Outside Chrome Band)7 9Chrome: 15 Inches Minimal 33 24 Original (No Chrome)NotesWear Potential Unit 2 Unit 1 78 CONDUIT LAYOUT (SECTION VIEW) 1Safety Evaluation Reportwith Open ItemsFebruary 9, 2011Nate Ferrer, Project ManagerOffice of Nuclear Reactor RegulationAdvisory Committee on Reactor SafeguardsLicense Renewal Subcommittee Diablo Canyon Nuclear Power Plant, Units 1 and 2
    - Completed on Unit 1; Unit 2 scheduled for April 2011 31
Presentation OutlineOverview of DCPPLicense Renewal ReviewSER Section 2, Scoping and Screening reviewRegion IV License Renewal InspectionsSER Section 3, Aging Management Programs and Aging Management Review ResultsSER Section 4, Time
 
-Limited Aging Analyses 2
BURIED PIPING AND TANKS INSPECTION PROGRAM OI 3.0.3.2.8 SER 3.0.3.2.8 Issue:
Overview of LRALicense Renewal Application submitted November 23, 2009
    - Management of aging effect for buried copper valves in the Makeup Water System
-Applicant: Pacific Gas and Electric Company
    - Clarification of in-scope steel pipe in the Makeup Water System Resolution:
-Facility Operating Licenses DPR
    - Buried copper valves will be managed by the Buried Piping and Tanks Inspection Program
-80 and DPR
    - Commitment to enhance operating procedure to close Makeup Water System isolation valve in event of a pressure boundary failure and removed steel piping and components from scope 32
-82 expire November 2, 2024, and August 26, 2025, respectivelyApproximately 12 miles west southwest of San Luis Obispo, CA in Avila Beach, CADCPPunits are Westinghouse four loop PWRs 3 Audits and InspectionsScoping and Screening Methodology Audit
 
-March 15-18, 2010-Led to submittal of 2 LRAamendments related to scoping and screeningAging Management Program Audits
Michelle Albright Diablo Canyon License Renewal Project 33
-April 12-15, 2010-April 26-29, 2010-Over 20 technical reviewers, including contractors from ANL and ORNLRegion IV Inspection
 
-August/September 2010 4
TIME-LIMITED AGING ANALYSES IDENTIFICATION OI 4.1-1 RAIs:
Overview of SERSafety Evaluation Report with Open Items issued January 10, 2011 SER contains 8 Open Items:
    - Reactor coolant pressure boundary valves
1.10 CFR54.4(a)(2) evaluations for nonsafety-related, fluid
    - Baffle and former bolts Resolution:
-filled structures and components (SCs) in the vicinity of safety
    - Confirmed DCPP design codes for the reactor coolant pressure boundary valves do not require a fatigue analysis
-related SCs(Open Item 2.1-1)2.10 CFR54.4(a)(2) evaluations for nonsafety-related piping directly attached to safety
    - Fatigue of the baffle and former bolts is managed by the Reactor Vessel Internals AMP 34
-related components (Open Item 2.3
 
-1)3.Endpoint for the diesel air start unloaderline (Open Item 2.3.3.14
METAL FATIGUE OI 4.3-1 Additional information
-1)5 Overview of SER (cont.)SER contains 8 Open Items (cont.)
    - Replacement reactor head CUF values
4.Buried Piping and Tanks Inspection Program (Open Item 3.0.3.2.8
    - AMR revisions for piping system cumulative fatigue damage Clarification
-1)5.Flux Thimble Tube Inspection Program (Open Item 3.0.3.2.12
    - Cycle counting for upper and lower core plates
-1)6.TLAAIdentification (Open Item 4.1
    - Cycle estimates for the Auxiliary Spray during Plant Cooldown transient
-1)7.Metal Fatigue (Open Item 4.3
    - Charging system cycle estimate methodology during unmonitored periods
-1)8.Flaw Growth Evaluation for RHRpiping Weld (Open Item 4.7.5
    - Electrical raceway seismic evaluation requirements FSAR/CLB enhancement
-1)6 Overview of SER (cont.)SER contains 2 Confirmatory Items 1.Inaccessible Medium
    - Load-following transients used in design analyses and the FSAR
-Voltage Cables Not Subject to 10 CFR50.49 Environmental Qualification Requirements Program (Confirmatory               Item 3.0.3.2.14
    - Monitoring transients in non-CUF type analyses Evaluate DCPP Environmentally-Assisted Fatigue analyses 35
-1).2.Structures Monitoring Program (Confirmatory Item 3.0.3.2.18
 
-1)7 SER Section 2 SummaryStructures and Components Subject to Aging Management Review
Concluding Remarks Jim Becker Site Vice President 36
-Section 2.1, Scoping and Screening Methodology   (open item)
 
-Section 2.2, Plant
Flaw Growth Evaluation for RHR Piping Weld WIC-95 66
-Level Scoping Results
 
-Section 2.3, Scoping and Screening Results  
FLUX THIMBLE TUBE Unit 1 Unit 2      Wear Potential            Notes Original (No 24      33            Minimal Chrome)
-
Minimal (Outside Chrome No Wear on Chrome Chrome: 15 Inches  9        7 Band)                Band Minimal (Outside Chrome Chrome: 12 Feet  21      10 Band)
Scheduled for Capped        4        7       None Observed          Replacement in 2R16, May 2011 Thimble Tube Guide Tube Capped        1 (L-13)           N/A Removed 44 Needed for Tech Useable      54      50 Spec Flux Map 70
 
CONDUIT LAYOUT (SECTION VIEW) 78
 
Advisory Committee on Reactor Safeguards License Renewal Subcommittee Diablo Canyon Nuclear Power Plant, Units 1 and 2 Safety Evaluation Report with Open Items February 9, 2011 Nate Ferrer, Project Manager Office of Nuclear Reactor Regulation 1
 
Presentation Outline
* Overview of DCPP License Renewal Review
* SER Section 2, Scoping and Screening review
* Region IV License Renewal Inspections
* SER Section 3, Aging Management Programs and Aging Management Review Results
* SER Section 4, Time-Limited Aging Analyses 2
 
Overview of LRA
* License Renewal Application submitted November 23, 2009
  - Applicant: Pacific Gas and Electric Company
  - Facility Operating Licenses DPR-80 and DPR-82 expire November 2, 2024, and August 26, 2025, respectively
* Approximately 12 miles west southwest of San Luis Obispo, CA in Avila Beach, CA
* DCPP units are Westinghouse four loop PWRs 3
 
Audits and Inspections
* Scoping and Screening Methodology Audit
  - March 15-18, 2010
  - Led to submittal of 2 LRA amendments related to scoping and screening
* Aging Management Program Audits
  - April 12-15, 2010
  - April 26-29, 2010
  - Over 20 technical reviewers, including contractors from ANL and ORNL
* Region IV Inspection
  - August/September 2010 4
 
Overview of SER
* Safety Evaluation Report with Open Items issued January 10, 2011
* SER contains 8 Open Items:
: 1. 10 CFR 54.4(a)(2) evaluations for nonsafety-related, fluid-filled structures and components (SCs) in the vicinity of safety-related SCs (Open Item 2.1-1)
: 2. 10 CFR 54.4(a)(2) evaluations for nonsafety-related piping directly attached to safety-related components (Open Item 2.3-1)
: 3. Endpoint for the diesel air start unloader line (Open Item 2.3.3.14-1) 5
 
Overview of SER (cont.)
* SER contains 8 Open Items (cont.)
: 4. Buried Piping and Tanks Inspection Program (Open Item 3.0.3.2.8-1)
: 5. Flux Thimble Tube Inspection Program (Open Item 3.0.3.2.12-1)
: 6. TLAA Identification (Open Item 4.1-1)
: 7. Metal Fatigue (Open Item 4.3-1)
: 8. Flaw Growth Evaluation for RHR piping Weld (Open Item 4.7.5-1) 6
 
Overview of SER (cont.)
* SER contains 2 Confirmatory Items
: 1. Inaccessible Medium-Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program (Confirmatory Item 3.0.3.2.14-1).
: 2. Structures Monitoring Program (Confirmatory Item 3.0.3.2.18-1) 7
 
SER Section 2 Summary
* Structures and Components Subject to Aging Management Review
  - Section 2.1, Scoping and Screening Methodology (open item)
  - Section 2.2, Plant-Level Scoping Results
   - Section 2.3, Scoping and Screening Results -
Mechanical (open items)
Mechanical (open items)
-Section 2.4, Scoping and Screening Results  
  - Section 2.4, Scoping and Screening Results -
-
Structures
Structures  
  - Section 2.5, Scoping and Screening Results -
-Section 2.5, Scoping and Screening Results  
-
Electrical 8
Electrical 8
SER Section 2 Open Items10 CFR54.4(a)(2) evaluations for nonsafety-related, fluid
 
-filled components in the vicinity of safety
SER Section 2 Open Items
-related components, Open Item 2.1 control room pressurization system/HVAC exhaust ducts
* 10 CFR 54.4(a)(2) evaluations for nonsafety-related, fluid-filled components in the vicinity of safety-related components, Open Item 2.1-1
-electrical pull boxes
    - control room pressurization system/HVAC exhaust ducts
-compressed air system water traps10 CFR54.4(a)(2) evaluations for nonsafety-related piping directly attached to safety
    - electrical pull boxes
-related components, Open Item 2.3-1-compressed gas systems10 CFR54.4(a)(1) evaluations for scoping boundary of safety-related piping, Open Item 2.3.3.14 EDGair start system  
    - compressed air system water traps
-unisolatedunloaderline from air receiver back to the air compressorApplicant has submitted additional informationStaff is finalizing its review of the response 9
* 10 CFR 54.4(a)(2) evaluations for nonsafety-related piping directly attached to safety-related components, Open Item 2.3-1
Regional Inspection  
    - compressed gas systems
-License Renewal Inspections Program ImplementationGreg PickRegion IV Inspection Team Leader10 Regional Inspection OverviewSix inspectors for 2 weeksScoping & screening inspectionAging management programs inspectionSeveral focus areas 11 Regional Inspection       Focus AreasSSCs needed to withstand a design basis seismic eventSSCs and programs that prevent leaks to the environmentTreatment of the latest industry aging concernsPrior site
* 10 CFR 54.4(a)(1) evaluations for scoping boundary of safety-related piping, Open Item 2.3.3.14-1
-specific aging issues12 Regional Inspection ResultsScoping of nonsafety-related systems
    - EDG air start system - unisolated unloader line from air receiver back to the air compressor
-Spatial interaction issues
* Applicant has submitted additional information
-Some material types incorrect or omitted Aging management programs
* Staff is finalizing its review of the response 9
-Training required
 
-Degraded silicon seal
Regional Inspection -
-Reviewed electrical vaults
License Renewal Inspections Program Implementation Greg Pick Region IV Inspection Team Leader 10
-Location selected for fouling
 
-Procedures developed but some errors13 Regional Inspection ObservationsOverall, good material conditionProcedures developed for the programs reviewedMajor component replacements
Regional Inspection Overview
-230 kV & 500 kV insulators
* Six inspectors for 2 weeks
-Intake structure14 Regional Inspection ConclusionsScoping of non
* Scoping & screening inspection
-safety SSCs and application of the AMPs to those SSCs were acceptableApplicant personnel had incorporated actions to manage aging effects into their programsReasonable assurance exists that aging effects will be managed and intended functions maintained15 Section 3: Aging Management ReviewSection 3.0  
* Aging management programs inspection
-Aging Management Programs (2 open items & 2 confirmatory items)Section 3.1  
* Several focus areas 11
-Reactor Vessel & InternalsSection 3.2  
 
-Engineered Safety FeaturesSection 3.3  
Regional Inspection Focus Areas
-Auxiliary SystemsSection 3.4  
* SSCs needed to withstand a design basis seismic event
-Steam and Power Conversion SystemSection 3.5  
* SSCs and programs that prevent leaks to the environment
-Containments, Structures and Component SupportsSection 3.6  
* Treatment of the latest industry aging concerns
-Electrical and Instrumentation and Controls System16 SER Section 33.0.3 -Aging Management Programs42 aging management programs (AMPs) presented by applicant and evaluated in the SER17Consistent with GALLConsistentwith exceptionConsistentwith enhancementConsistent with exception & enhancement Existing(31)16 5 5 5New (9)5 4N/AN/APlant-specific(2)N/AN/AN/AN/A SER Section 3 Open ItemsFlux Thimble Tube Inspection Program, Open Item 3.0.3.2.12 Justification for not including measurement and wear scar geometry uncertainties
* Prior site-specific aging issues 12
-Wear rate projection methodology and the capability of program to detect degradation in a flux thimble before the occurrence of a through
 
-wall failure
Regional Inspection Results
-Applicant has submitted additional information
* Scoping of nonsafety-related systems
-Staff is reviewing the response18 SER Section 3 Open ItemsBuried Piping and Tanks Inspection Program, Open Item 3.0.3.2.8 Staff requested additional information on how the program would account for recent operating experienceBackfill is acceptableCathodicprotection providedCoatings utilizedIncreased inpsections
  - Spatial interaction issues
-Applicant's initial response did not provide details for:Management of buried copper and steel valves and piping in the makeup water systemAlternate methods used for inspections
  - Some material types incorrect or omitted
-Applicant has submitted additional information
* Aging management programs
-Staff is finalizing its review of the response19 SER Section 3 Confirmatory ItemInaccessible Medium
  - Training required
-Voltage Cables Not Subject to 10 CFR50.49 Environmental Qualification Requirements Program, Confirmatory               Item 3.0.3.2.14 Staff requested additional information on how the program would account for recent operating experience
  - Degraded silicon seal
-Applicant's initial response did not provide sufficient details for absence of event
  - Reviewed electrical vaults
-driven inspections or use of a 10-year testing frequency
  - Location selected for fouling
-Applicant has submitted additional information
  - Procedures developed but some errors 13
-Staff is finalizing its review of the response 20 SER Section 3 Confirmatory ItemStructures Monitoring Program, Confirmatory Item 3.0.3.2.18 Applicant initially committed to perform video inspection of the Unit 2 spent fuel pool leak chase during the period of extended operation but did not specify the timing of the inspection
 
-Applicant revised its commitment to perform the inspection within 1 year prior to the period of extended operation
Regional Inspection Observations
-Staff is finalizing its review of the response 21 SER Section 4:
* Overall, good material condition
Time-Limited Aging AnalysesSection 4.1  
* Procedures developed for the programs reviewed
-Identification of Time
* Major component replacements
-Limited Aging Analyses (1 open item)Section 4.2  
  - 230 kV & 500 kV insulators
-Reactor Vessel Neutron EmbrittlementSection 4.3  
  - Intake structure 14
-Metal Fatigue (1 open item)Section 4.4  
 
-Environmental Qualification of Electrical EquipmentSection 4.5  
Regional Inspection Conclusions
-Concrete Containment Tendon PrestressSection 4.6  
* Scoping of non-safety SSCs and application of the AMPs to those SSCs were acceptable
-Containment Liner Plate, Metal Containments, and Penetrations Fatigue AnalysisSection 4.7  
* Applicant personnel had incorporated actions to manage aging effects into their programs
-Other Plant
* Reasonable assurance exists that aging effects will be managed and intended functions maintained 15
-Specific Time
 
-Limited Aging Analyses (1 open item)22 SER Section 4SER Section 4.2.2: Pressurized Thermal Shock Limiting Beltline Material  
Section 3: Aging Management Review
-Unit 1 lower shell longitudinal (axial) weld 3
* Section 3.0 - Aging Management Programs (2 open items & 2 confirmatory items)
-442C23%CU%NiEOLEFluence(E>1 MeV)1019 (n/cm 2)Initial Charpy RT NDT 0 F RT PTS 0 FAcceptance Criterion per 10 CFR 50.61 0 F0.2031.0182.04-56280.4<270 o FThe applicant stated in that it will implement 10 CFR 50.61a at least three years prior to exceeding the PTS screening criteria of 10 CFR 50.61. In the event that the provisions of 10 CFR 50.61a cannot be met, PG&E will implement alternate options, such as flux reduction, as provided in 10 CFR 50.61.
* Section 3.1 - Reactor Vessel & Internals
SER Section 4 Open Items TLAAIdentification, Open Item 4.1 Justification for absence of TLAAsfor:Reactor coolant pressure boundary valvesBaffle and former bolts
* Section 3.2 - Engineered Safety Features
-Applicant has submitted additional information
* Section 3.3 - Auxiliary Systems
-Staff is reviewing the response24 SER Section 4 Open ItemsMetal Fatigue, Open Item 4.3 Issues related to Metal Fatigue TLAAsCycle countingEnvironmentally
* Section 3.4 - Steam and Power Conversion System
-assisted fatigueCumulative usage factors
* Section 3.5 - Containments, Structures and Component Supports
-Applicant has submitted additional information
* Section 3.6 - Electrical and Instrumentation and Controls System 16
-Staff is reviewing the response25 SER Section 4 Open Items Residual Heat Removal Piping Weld WIC
 
-95 Flaw Evaluation TLAA, Open Item 4.7.5 Applicant did not consider the potential of stress corrosion cracking for a flaw that may be connected to pipe inside surface
SER Section 3 3.0.3 - Aging Management Programs
-Applicant has submitted additional information
* 42 aging management programs (AMPs) presented by applicant and evaluated in the SER Consistent  Consistent    Consistent Consistent with with GALL  with exception    with      exception &
-Staff is reviewing the response26 ConclusionThe staff is continuing review to resolve the open and confirmatory items regarding the LRAfor DCPP. Pending resolution of the open and confirmatory items, the staff is working towards issuing the SER.27}}
enhancement  enhancement Existing 16           5            5           5 (31)
New 5           4          N/A          N/A (9)
Plant-specific     N/A          N/A          N/A          N/A (2) 17
 
SER Section 3 Open Items
* Flux Thimble Tube Inspection Program, Open Item 3.0.3.2.12-1
  - Justification for not including measurement and wear scar geometry uncertainties
  - Wear rate projection methodology and the capability of program to detect degradation in a flux thimble before the occurrence of a through-wall failure
  - Applicant has submitted additional information
  - Staff is reviewing the response 18
 
SER Section 3 Open Items
* Buried Piping and Tanks Inspection Program, Open Item 3.0.3.2.8-1
  - Staff requested additional information on how the program would account for recent operating experience
* Backfill is acceptable
* Cathodic protection provided
* Coatings utilized
* Increased inpsections
  - Applicants initial response did not provide details for:
* Management of buried copper and steel valves and piping in the makeup water system
* Alternate methods used for inspections
  - Applicant has submitted additional information
  - Staff is finalizing its review of the response 19
 
SER Section 3 Confirmatory Item
* Inaccessible Medium-Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program, Confirmatory Item 3.0.3.2.14-1
  - Staff requested additional information on how the program would account for recent operating experience
  - Applicants initial response did not provide sufficient details for absence of event-driven inspections or use of a 10-year testing frequency
  - Applicant has submitted additional information
  - Staff is finalizing its review of the response 20
 
SER Section 3 Confirmatory Item
* Structures Monitoring Program, Confirmatory Item 3.0.3.2.18-1
  - Applicant initially committed to perform video inspection of the Unit 2 spent fuel pool leak chase during the period of extended operation but did not specify the timing of the inspection
  - Applicant revised its commitment to perform the inspection within 1 year prior to the period of extended operation
  - Staff is finalizing its review of the response 21
 
SER Section 4:
Time-Limited Aging Analyses
* Section 4.1 - Identification of Time-Limited Aging Analyses (1 open item)
* Section 4.2 - Reactor Vessel Neutron Embrittlement
* Section 4.3 - Metal Fatigue (1 open item)
* Section 4.4 - Environmental Qualification of Electrical Equipment
* Section 4.5 - Concrete Containment Tendon Prestress
* Section 4.6 - Containment Liner Plate, Metal Containments, and Penetrations Fatigue Analysis
* Section 4.7 - Other Plant-Specific Time-Limited Aging Analyses (1 open item) 22
 
SER Section 4 SER Section 4.2.2: Pressurized Thermal Shock Limiting Beltline Material - Unit 1 lower shell longitudinal (axial) weld 3-442C
%CU         EOLE Fluence            Initial Charpy      RTPTS        Acceptance
%Ni          (E>1 MeV)                 RTNDT            0F        Criterion per 1019 (n/cm2)                 0F                        10 CFR 50.61 0F 0.203            2.04                     -56            280.4         <270oF 1.018 The applicant stated in that it will implement 10 CFR 50.61a at least three years prior to exceeding the PTS screening criteria of 10 CFR 50.61. In the event that the provisions of 10 CFR 50.61a cannot be met, PG&E will implement alternate options, such as flux reduction, as provided in 10 CFR 50.61.
23
 
SER Section 4 Open Items
* TLAA Identification, Open Item 4.1-1
  - Justification for absence of TLAAs for:
* Reactor coolant pressure boundary valves
* Baffle and former bolts
  - Applicant has submitted additional information
  - Staff is reviewing the response 24
 
SER Section 4 Open Items
* Metal Fatigue, Open Item 4.3-1
  - Issues related to Metal Fatigue TLAAs
* Cycle counting
* Environmentally-assisted fatigue
* Cumulative usage factors
  - Applicant has submitted additional information
  - Staff is reviewing the response 25
 
SER Section 4 Open Items
* Residual Heat Removal Piping Weld WIC-95 Flaw Evaluation TLAA, Open Item 4.7.5-1
  - Applicant did not consider the potential of stress corrosion cracking for a flaw that may be connected to pipe inside surface
  - Applicant has submitted additional information
  - Staff is reviewing the response 26
 
Conclusion
* The staff is continuing review to resolve the open and confirmatory items regarding the LRA for DCPP. Pending resolution of the open and confirmatory items, the staff is working towards issuing the SER.
27}}

Latest revision as of 03:15, 13 November 2019

Transcript of the Advisory Committee on Reactor Safeguards Plant License Renewal Subcommittee - Diablo Canyon - February 9, 2011 (Open). Pages 1-145
ML110530294
Person / Time
Site: Diablo Canyon  Pacific Gas & Electric icon.png
Issue date: 02/09/2011
From:
Advisory Committee on Reactor Safeguards
To:
Weaver K
References
NRC-698
Download: ML110530294 (213)
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Text

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: Wednesday, February 9, 2011 Work Order No.: NRC-698 Pages 1-145 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 DISCLAIMER 4

5 6 UNITED STATES NUCLEAR REGULATORY COMMISSIONS 7 ADVISORY COMMITTEE ON REACTOR SAFEGUARDS 8

9 10 The contents of this transcript of the 11 proceeding of the United States Nuclear Regulatory 12 Commission Advisory Committee on Reactor Safeguards, 13 as reported herein, is a record of the discussions 14 recorded at the meeting.

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

19 20 21 22 23 24 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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2 1 UNITED STATES OF AMERICA 2 NUCLEAR REGULATORY COMMISSION 3 + + + + +

4 ADVISORY COMMITTEE ON REACTOR SAFEGUARDS 5 (ACRS) 6 + + + + +

7 PLANT LICENSE RENEWAL SUBCOMMITTEE 8 DIABLO CANYON POWER PLANT 9 + + + + +

10 WEDNESDAY 11 FEBRUARY 9, 2011 12 + + + + +

13 ROCKVILLE, MARYLAND 14 + + + + +

15 The Subcommittee met at the Nuclear 16 Regulatory Commission, Two White Flint North, 17 Room T2-B1, at 1:30 p.m., Dennis C. Bley, 18 Chairman, presiding.

19 20 COMMITTEE MEMBERS:

21 DENNIS C. BLEY Chairman 22 SAID ABDEL-KHALIK Member 23 J. SAM ARMIJO Member 24 SANJOY BANERJEE Member 25 MICHAEL L. CORRADINI Member 26 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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3 1 HAROLD B. RAY Member 2 MICHAEL T. RYAN Member 3 WILLIAM J. SHACK Member 4 JOHN D. SIEBER Member 5 JOHN W. STETKAR Member at Large 6

7 ACRS CONSULTANTS PRESENT:

8 JOHN J. BARTON 9

10 NRC STAFF PRESENT:

11 NATHANIEL FERRER, NRR 12 MELANIE GALLOWAY, NRR/DLR 13 STAN GARDOCKI, NRR/DSS 14 ALLEN HISER, NRR/DLR 15 BRIAN HOLIAN, NRR/DLR 16 WILLIAM HOLSTON, NRR/DLR 17 JAMES MEDOFF, NRR/DLR 18 NEIL O'KEEFE 19 GREG PICK, Region IV 20 JEFF POEHLER, NRR/DSI 21 DAVE WRONA, NRR/DLR 22 MICHAEL BENSON, Designated Federal Official 23 24 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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4 1 ALSO PRESENT FROM PG&E 2 MICHELLE ALBRIGHT 3 CHRIS BEARD 4 JIM BECKER 5 DAVID GERBER, Structural Integrity 6 Associates 7 DAVID GONZALEZ 8 JOE GORYANCE 9 LEE GOYETTE 10 TERRY GREBEL 11 DANIEL HARDESTY 12 MARK MAYER 13 DAVE MIKLUSH 14 CHALMER MYER 15 LOREN SHARP 16 MIRANDA TAN 17 RYAN WEST 18 DAVID WONG 19 MIKE WRIGHT 20 21 22 23 24 25 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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5 1 TABLE OF CONTENTS 2 AGENDA ITEM PAGE 3 Opening Remarks, Dennis Bley, ACRS 6 4 Staff Introduction, Brian Holian 7 5 PG&E Company - Diablo Canyon Power Plant:

6 Introductions; Site & Station 13 7 Descriptions, Jim Becker 8 History/Major Improvements, Loren Sharp 18 9 License Renewal Application; Open 20 10 and Confirmatory Items, Terry Grebel 11 Flux Thimble Tube Inspection Program 29 12 (Open Item), Mike Wright 13 Flaw Growth Evaluation for RHR (Open 39 14 Item), Dave Gonzalez 15 Scoping and Screening (Open Items); 55 16 Buried Piping and Tanks Inspection 17 Program (Open Item), Dave Miklush 18 TLAA Identification and Metal Fatigue 66 19 (Open Items), Michelle Albright 20 NRC STAFF: Nathaniel Ferrer, Greg Pick 21 SER Overview and Scoping and 81 22 Screening Results; Onsite Inspection Results 23 Aging Management Review; and 102 24 Time Limited Aging Analyses 25 Subcommittee Discussion 141 26 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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6 1 P-R-O-C-C-E-D-I-N-G-S 2 Time: 1:30 p.m.

3 CHAIRMAN BLEY: The meeting will now 4 come to order. This is a meeting of the Plant 5 License Renewal Subcommittee of the Advisory 6 Committee on Reactor Safeguards.

7 I am Dennis Bley, Chairman of the 8 Subcommittee. ACRS Members in attendance today 9 are Bill Shack, Mike Ryan, John Stetkar, Said 10 Abdel-Khalik, Sam Armijo, Harold Ray and Jack 11 Sieber.

12 We have Tom Barton as our consultant, 13 and Michael Benson is the Designated Federal 14 Official for this meeting.

15 The Subcommittee will review the 16 License Renewal Application of the Diablo Canyon 17 Power Plant, Units 1 and 2, and the associated 18 SER with open items. We will hear presentations 19 from the NRC staff and Pacific Gas and Electric, 20 PG&E.

21 We have received no written comments 22 or requests for time to make oral statements from 23 members of the public regarding today's meeting.

24 I will mention that the next-door conference 25 room is also following this meeting on the TV NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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7 1 screens. There is an overflow audience today.

2 The entire meeting will be open to 3 public attendance. The Subcommittee will gather 4 information, analyze relevant issues and facts, 5 and formulate proposed positions and actions, as 6 appropriate, for deliberation by the full 7 Committee.

8 The rules for participation in today's 9 meeting have been announced as part of the Notice 10 of this meeting previously published in the 11 Federal Register.

12 A transcript of the meeting is being 13 kept, and will be made available as stated in the 14 Federal Register Notice. Therefore, we request 15 that participants in this meeting use the 16 microphones located throughout the meeting room 17 when addressing the Subcommittee. The 18 participants should first identify themselves and 19 speak with sufficient clarity and volume so that 20 they may be readily heard.

21 We will now proceed with the meeting, 22 and I call upon Brian Holian to begin.

23 MR. HOLIAN: Thank you, Chairman, and 24 thank you -- Good afternoon, Subcommittee. My 25 name is Brian Holian. I am the Director of the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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8 1 Division of License Renewal, and we are here 2 today for the Diablo Canyon Subcommittee meeting.

3 I will make brief introductions and 4 then quickly go over the agenda and turn it over 5 to the licensee for their part of the 6 presentation.

7 To my left is Melanie Galloway, the 8 Deputy Director for Division of License Renewal.

9 Behind us -- I will just make a couple of 10 introductions, and we will repeat a few and add a 11 few for when our people come to the table, but I 12 wanted to mention that Dave Wrona is the Branch 13 Chief for Diablo Canyon sitting over there behind 14 the stanchion.

15 The Project Manager, you will hear 16 more from later, is Nate Ferrer, and we do have 17 two individuals who escaped Region IV and a 18 quarter-inch of snow or whatever they got. The 19 office is closed today, but they got out 20 yesterday on a plane, and that is Mr. Greg Pick, 21 the Senior Inspector from Region IV -- the 22 Committee has seen him before; he had 23 presentations -- and Neil O'Keefe, his Branch 24 Chief. So I welcome them in from the cold of 25 Dallas.

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9 1 The agenda today, as I mentioned, is 2 to look at Diablo Canyon, the third STARS plan to 3 come in for an application for a license renewal.

4 We had Wolf Creek several years ago, and then 5 Palo Verde, and the full committee will be 6 hearing from Palo Verde tomorrow morning for 7 their final SER and the closure of their open 8 items.

9 I mention that, because, in 10 particular, some of the items you will see both 11 in Diablo's presentation and the staff's. We 12 have a couple of open items that are still 13 related to scoping, and the Subcommittee might 14 wonder about that.

15 We did see some issues on Palo Verde's 16 scoping, if you remember back on draft SER, and 17 so I just highlight that. The STARS -- The 18 alliance, the STARS group, was learning from the 19 Palo Verde. Folks are here in the audience from 20 Palo Verde for tomorrow, and we know that, 21 through our license renewal quarterly meetings, 22 those lessons learned get passed on, but their 23 application was already in, and our audits were 24 already going when you see a lot of those RAIs.

25 So I think the Applicant will speak to that a NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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10 1 little bit, but I wanted to mention that.

2 The second item that I wanted to 3 really mention overall for the Committee -- the 4 Committee is probably aware of it from general 5 correspondence, but I just wanted to highlight it 6 here at the opening. Diablo, being in 7 California, seismic issues are of concern to the 8 local population there and, of course, the staff 9 also.

10 Last year, as the application came in 11 for Diablo, we got several letters in to the 12 staff requesting a delay, requesting more 13 information be done first. Even the State of 14 California was interested, besides local 15 interested stakeholders, on new information on 16 potential faults or differences in the design 17 basis.

18 I just wanted to highlight that to the 19 Committee. We addressed that in a July letter 20 from the Director of NRR to the stakeholders, 21 saying that those issues would be best dealt with 22 under Part 50. They are current issues. Right 23 now, their current licensing basis is -- although 24 there might be questions on it -- not called into 25 effect.

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11 1 The staff even looked at a new 2 potential fault back in the '09 time frame. That 3 was the subject. So I just wanted to make the 4 Committee aware that we and the Region have had 5 several public meetings out in the California 6 area to address that potential stakeholder item.

7 So you will see correspondence on that as you 8 look through the docket, but we consider it a 9 Part 50 issue.

10 If at anytime that design basis 11 changes, we would be able to either -- if it 12 happened during the license renewal, be able to 13 supplement an SER, if that was needed to be, or 14 after the fact still do it under Part 50 15 processes to address their licensing basis.

16 With that, I will turn it over to the 17 Applicant, who has the first part. Go ahead.

18 MEMBER SHACK: Can I ask you a generic 19 question. I was looking. You know, they came in 20 with the usual language about PWR internals, and 21 I was trying to remember. I saw Ginna submitted 22 an inspection plan. Was that approved?

23 MR. HOLIAN: Allen Hiser, I will have 24 address that during -- or Jim Medoff, if you want 25 to wait for our staff presentation.

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12 1 MEMBER SHACK: Yes.

2 MR. HOLIAN: During our staff 3 presentation, we will address that. I know it 4 has come up recently in the GALL.

5 MEMBER SHACK: Yes. The GALL actually 6 has guidance, and that was the next question, is 7 when were you expecting licensees to actually 8 pick up that GALL guidance and incorporate it in 9 their documents?

10 MR. HOLIAN: Yes. We have been -- I 11 will address that more in depth in our 12 presentation, but in general, Diablo has come in 13 here, and now there are seven to nine open items.

14 I know the committees have seen us recently 15 taking our time and asking additional questions 16 to get plants that are in-house up to the 17 significant items of GALL, Rev. 2, which we 18 issued last December.

19 The staff did a kind of an in depth 20 look through the significant items in there, and 21 for the plants in-house, we thought it most 22 appropriate, while we have the SERs in process, 23 to ask those additional requests for information, 24 even if they submit it under GALL Rev 1. We just 25 thought it is the right thing to do.

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13 1 Utilities have responded well to that.

2 So in general, we have done that, bringing all 3 the plants in-house up to that. So I will 4 address it in particular on the MRP and internals 5 during our presentation.

6 With that, I will turn it over to Mr.

7 Jim Becker, the site VP for Diablo Canyon.

8 MR. BECKER: Thank you, Mr. Holian.

9 So I am Jim Becker. I am the site Vice President 10 at Diablo Canyon, and on behalf of the STARS and 11 PG&E team, it is our pleasure to be here today.

12 We look forward to a good presentation and some 13 good questions and answers, and that is our 14 purpose here today.

15 I would like to start off with some 16 introductions. As I said, I am Jim Becker, the 17 site Vice President.

18 MR. SHARP: I am Loren Sharp, Senior 19 Director of Technical Services.

20 MR. WRIGHT: Mike Wright, Mechanical 21 Systems Engineering Manager.

22 MR. GREBEL: Terry Grebel, License 23 Renewal Project Manager.

24 MR. BECKER: Thank you. And in 25 addition to the folks up here in front of you, we NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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14 1 have a fairly large contingent that has come out 2 to Washington, D.C., with us, and those are 3 members both of the STARS Center of Business and 4 of our own plant staff, and they have been very 5 instrumental in preparing the application, 6 responding to the requests for information, and 7 will assist us in our presentation and answering 8 questions here today.

9 Our agenda for the day: We are going 10 to start off with Loren and I giving the 11 Subcommittee an overview of the site, our 12 history, major improvements, etcetera, that have 13 occurred at the site.

14 Then Terry Grebel will briefly cover 15 GALL consistency and commitments, and with that 16 complete, we are then going to go into some more 17 detailed presentation about the open items, and 18 those are the items you see in front of you there 19 on the agenda.

20 Then when we are done with that, I 21 will have some brief concluding remarks. So that 22 is the agenda that we have planned for you today.

23 This slide shows a site description, 24 and I thought it would be good for the 25 Subcommittee to review with us some basic facts NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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15 1 about the site.

2 Diablo Canyon is located on the 3 central California coast. It is about halfway 4 between Los Angeles and San Francisco. What you 5 see here is the coastline at the site. Miranda 6 has highlighted the Diablo Canyon site itself 7 there.

8 There are about 13,000 acres in the 9 Diablo Canyon lands that PG&E now owns, and the 10 boundary for the company owned property is shown 11 as the dark black line there. The closest town 12 of any size is the town of Avila Beach, and 13 Miranda is now highlighting that.

14 That is a quick overview of our 15 location on the central coast of California.

16 DR. BARTON: What is the population of 17 Avila Beach?

18 MR. BECKER: As a resident of Avila 19 Beach, I will tell you that the population is, I 20 believe, three to four thousand people. It has 21 grown a fair amount in recent years into the 22 hillsides outside the direct village.

23 Okay. Moving on to this site 24 description slide, this is an aerial photograph, 25 and I thought it would be worthwhile to review NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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16 1 the basic layout of the site here.

2 So what you see here are the 3 containment structures, Units 1 and 2. Unit 1 4 lies to the north. They share a common turbine 5 building that you see laid out there in the 6 picture.

7 We take suction at the intake, and the 8 units share a common intake structure, and they 9 also share a common discharge structure that you 10 see in the picture. Of course, we have an 11 administration building.

12 Most of the make-up water to the plant 13 -- Actually, all the make-up water to the plant 14 flows through the raw water reservoirs, which are 15 on the hill to the east of the plant, and we 16 recently began dry cast storage operations. So 17 the ISFSI, or interim spent fuel storage 18 installation, pad is just to the south of the raw 19 water reservoirs. We have completed two ISFSI 20 campaigns thus far, one for each unit.

21 Now a brief station description. So 22 there are two units at Diablo. They share a 23 common operating set of procedures and design.

24 The units are not identical, but they are highly 25 similar. They are both 4 loop Westinghouse units NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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17 1 with a core rating of 3411 megawatts thermal.

2 PG&E was the architect/engineer for 3 Diablo Canyon. We were assisted in the latter 4 stages of the construction time period by 5 Bechtel, and that got us to the point of an 6 actual operating license.

7 It is a once-through cooling facility.

8 Each unit has two circ water pumps. At full 9 power, we pump about 1.5 million gallons per 10 minute of ocean water through the condensers and 11 then back out through that common discharge 12 structure that I showed you earlier.

13 Our containments are free standing, as 14 you see on that slide, steel-lined, reinforced 15 concrete buildings. PG&E is the sole owner and 16 operator for Diablo Canyon.

17 I mentioned that the plant is on the 18 central California coast. We are at the southern 19 end of the PG&E electric service territory. We 20 do own and operate the switchyards and the high 21 voltage transmission system. PG&E's service 22 territory extends from the Oregon border down to 23 about 50 miles south of where Diablo Canyon is 24 located.

25 So that competes my overview of the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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18 1 facility.

2 MEMBER RAY: Did you say anything 3 about the California ISO?

4 MR. BECKER: We are subject to -- Our 5 generation is subject to the jurisdiction and 6 regulation of the California Independent System 7 Operator, as has been the case for a bit over 10 8 years now.

9 MR. SHARP: Thanks, Jim. I am Loren 10 Sharp. I also welcome the opportunity to appear 11 in front of you to talk about license renewal 12 today. I am the Senior Director of Technical 13 Services, and I will discuss some of the STARS 14 Center of Business, plant history and major 15 improvements at Diablo Canyon.

16 Slide 9. So the Center of Business 17 was created to form a format of consistency for 18 the seven PWR plants that are getting ready to 19 apply or have applied for license renewal.

20 Therefore, we are providing a standard 21 application with additional quality stemming from 22 applying our operating experience, lessons 23 learned from the other STARS plants.

24 Diablo Canyon personnel have 25 consistently provided oversight, leadership and NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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19 1 ownership of the licensing renewal process, as 2 well as the implementation of that process 3 continuing into the future.

4 Slide 10. Unit 1 was issued an 5 operating power license in 1984, with Unit 2 in 6 1985. There was a change to increase power for 7 Unit 1 to 3411, so that both units are 8 essentially equal, and that is one of the reasons 9 why we have a common license renewal application 10 for both units. We have -- Currently, license 11 expires in 2024 and 2025.

12 Slide 11.

13 DR. BARTON: What is the status of the 14 two plants today? Both at 100 percent power?

15 MR. BECKER: Yes. Both units today 16 are at full power.

17 MR. SHARP: For the Slide 11, we have 18 done a number of major improvements. I won't go 19 through the list in total, but I would say we 20 have done significant improvements to make sure 21 we maintain our facility. I will discuss just 22 the steam generators and reactor heads that were 23 recently completed to make sure we have the 24 quality of plant that we need as we go into 25 license renewal as well as the continued NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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20 1 operation of our current license.

2 Now I would like to turn it over to 3 Terry Grebel, our Diablo Canyon License Renewal 4 Project Manager to discuss GALL consistency and 5 some of the commitments made at Diablo Canyon.

6 MR. GREBEL: Thank you, Loren. Good 7 afternoon. My name is Terry Grebel. I am the 8 Diablo Canyon License Renewal Project Manager.

9 My portion of the presentation today covers the 10 highlights of our license renewal application, 11 including the aging management programs, 12 commitments, open items and confirmatory items.

13 Slide 13, please. In preparing our 14 license renewal application, we used the GALL 15 Rev. 1 and NEI 95-10 Rev. 6 guidance with the 16 goal of making the application as consistent with 17 this guidance as possible.

18 In addition, as Brian talked about 19 earlier, the staff has recently asked several 20 RAIs based on recent operating experience. We 21 have been responding to these RAIs as well.

22 We have a total of 42 aging management 23 programs, 31 of which are existing. Nine are 24 new, and we have two plant specific programs.

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21 1 93 percent consistent with GALL Rev 1 (standard 2 notes A through E).

3 We have 64 license renewal 4 commitments, and these commitments are being 5 tracked through our Diablo Canyon commitment 6 tracking system, which implements the guidance of 7 NEI 99-04.

8 Slide 14, please.

9 MEMBER SHACK: There is only 55 10 commitments listed in the SER. Are these new?

11 MR. GREBEL: These reflect the latest 12 updated members' responding to the --

13 MEMBER SHACK: RAIs.

14 MR. GREBEL: -- to the open items.

15 MEMBER SHACK: The open items. Okay.

16 Thank you.

17 MR. GREBEL: We have -- Diablo Canyon 18 SER has eight open items and two confirmatory 19 items. PG&E has submitted responses to all open 20 and confirmatory items. As Brian talked about 21 earlier, the staff is in the process of reviewing 22 these responses.

23 The eight open items will be discussed 24 further by the other members of the Diablo Canyon 25 team.

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22 1 MEMBER STETKAR: Terry, I know you are 2 going to discuss the open items. I would like to 3 ask you a couple of questions about confirmatory 4 items, if I could.

5 MR. GREBEL: I was going to jump into 6 that next.

7 MEMBER STETKAR: Oh, were you? Okay, 8 I didn't see a slide. Go on. I'm sorry.

9 MR. GREBEL: The first item dealt with 10 the confirmatory to change our cable testing 11 frequency from 10 years to six years. This 12 aligns it with the GALL Rev 2.

13 The second item dealt with our spent 14 fuel pool leak chase. We have a leak in Unit 2, 15 a minor leak. We have done some inspections of 16 the leak chases, and we have committed to do 17 another inspection.

18 The staff had asked -- We said we 19 would do that during the period of extended 20 operation. The staff asked that, to be in the 21 one-year prior, the period of extended operation, 22 and we have since made that commitment.

23 MEMBER STETKAR: Now my questions.

24 Start from the back first then. Have you made --

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23 1 inspections, at least from what I have read in 2 the SER, of the Unit 1 spent fuel pool leak 3 chase.

4 Now I recognize you don't have any 5 identified leakage, but you don't have any 6 identified leakage. So are you confident that 7 indeed the Unit 1 spent fuel pool leak chase is 8 open? I don't know how you measure the flow, 9 through drains or whatever -- that they are 10 indeed open?

11 In other words, what I am concerned 12 about is do you have leakage that you don't know 13 about and haven't confirmed that indeed your 14 monitoring systems are available over on Unit 1?

15 MR. GREBEL: We are prepared to 16 address that. Mike, could you address that 17 question, please?

18 MR. WRIGHT: Sure, Terry. Mike 19 Wright, Engineering.

20 Both units leak chase systems were 21 visually inspected in the 2006-2007 time frame 22 area, and both units' leak chase valves are 23 opened weekly to verify that we measure the flow, 24 if there is any leakage past the spent fuel pool 25 liners.

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24 1 Both units' leak chase systems were 2 verified to be free of boron clogging. There was 3 no evidence of blockage on either unit at that 4 time.

5 MEMBER STETKAR: I know that the 6 amount of leakage on Unit 2 is pretty small, and 7 the amount of leakage, at least what I read on 8 Unit 1, is yet much smaller. But when you open 9 the Unit 1 valves, do you get --

10 MR. WRIGHT: You get nothing.

11 MEMBER STETKAR: -- any flow?

12 MR. WRIGHT: No, sir. When we open 13 the Unit 1 valves on a weekly basis, we get zero 14 flow.

15 MEMBER STETKAR: You know those lines 16 are open?

17 MR. WRIGHT: Yes. We inspected them 18 in 2006 time frame with boroscope.

19 MEMBER STETKAR: With boroscope?

20 Okay. Thanks. That's what I was looking for.

21 On the cables, I know that you have 22 committed -- With that confirmatory of the six-23 year testing, you are essentially consistent with 24 GALL Rev 2, I think, with the exception that you 25 are not doing inspections based on event driven NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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25 1 events. If I recall correctly, just you said 2 that there was no evidence of event driven water 3 accumulation. So I believe you took an exception 4 to that element of the inspection program.

5 I guess my question was: You have had 6 water accumulation in the past, years back. I 7 recognize not in recent years. What was the 8 source of that water, if it wasn't event driven?

9 MR. WRIGHT: I think, in general, I 10 would like to ask my Engineering Manager, Ryan 11 West, to address that question.

12 MR. WEST: Ryan West, Engineering 13 Manager, Diablo Canyon.

14 In the early Nineties, we identified 15 that our pull boxes were full of water resulting 16 in submergence of the cables. The causes that 17 were identified were basically that our pull box 18 drains and sump pumps were not being maintained 19 adequately, resulting in rainwater backing up in 20 the boxes.

21 MEMBER STETKAR: So it was rainwater?

22 MR. WEST: That is correct. It was 23 rainwater. We have not seen any evidence of 24 groundwater leaking into the pull boxes.

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26 1 the inspection frequency?

2 MR. WEST: Yes. Right now, we have a 3 bi-monthly inspection of the pull boxes looking 4 for evidence of water in the pull boxes. So it 5 is not quite event driven, but during the rainy 6 season we do look in the boxes on a bi-monthly 7 frequency. We have the ability to defer those 8 once we get out of the rainy season and we are 9 not getting rain.

10 MEMBER STETKAR: So in a sense, you do 11 some -- if I understand what you just said, you 12 do inspections more frequently in the rainy 13 season.

14 MR. WEST: That is correct.

15 MEMBER STETKAR: Okay, thanks. I had 16 one other question on cables, which -- I have too 17 many notes here. Oh, I just wanted to confirm.

18 Do all of your underground cable ducts, conduit 19 runs -- I don't know what the configuration is 20 there -- including whatever low voltage cables 21 that are now in scope, positively drain to low 22 points where you have sump pumps installed?

23 What I am asking is: Are you 24 confident that you don't have any intermediate 25 low points where water can collect and remain NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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27 1 stagnant without positively draining to some 2 location that you can either inspect or have an 3 installed sump pump?

4 MR. WEST: So our operating experience 5 has identified that we have some low points in 6 our conduits. Here on Slide 78 is a general 7 layout of our conduit arrangement where there are 8 drains that drain from pull box to pull box to a 9 low point out to a sump area which is drained out 10 to the building sumps.

11 We have identified dips in the pull 12 boxes. We have done -- We are in the process of 13 completing all of them, but we are doing 14 inspections of the accessible portions of the 15 underground loops. We are also removing the 16 seals at the buildings, and it is promoting air 17 flow through the conduits, which is also helping 18 to keep the conduits free of water, and we are 19 going back after we have done all the inspections 20 in the locations that were identified as 21 containing water, we will verify that we are not 22 getting any in-leakage from damage in the 23 conduits.

24 MEMBER STETKAR: Thank you. One last 25 question. In your Generic Letter 2007-1 NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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28 1 response, you identified a number of cable 2 failures due to water in-leakage. Now I 3 understand that since then you have replaced, I 4 think it said, all of the in-scope medium voltage 5 cables. Have you experienced any underground 6 cable failures since 2007, in other words since 7 that report was filed?

8 MR. WEST: We have experienced 9 degradation on underground medium voltage cables 10 that had not been replaced. Of the replaced 11 cables, we have not seen any repeat degradation 12 or failures.

13 MEMBER STETKAR: Thanks.

14 MEMBER ABDEL-KHALIK: The degradation 15 that you referred to was measured by, what, the 16 10 delta test?

17 MR. WEST: Seven of the 11 identified 18 degradations or failures were identified by 19 ground alarms. We have a high resistance 20 grounding system. So we have a single phased 21 ground fault. So it was identified, and the 22 equipment was removed from service, and then 23 subsequently we verified through high-pots that 24 the cable was degraded.

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29 1 is cable degradation versus a connection 2 degradation?

3 MR. WEST: Can you clarify that a 4 little bit for me?

5 MEMBER ABDEL-KHALIK: The connections 6 between cable segments -- Are you sure that, 7 really, the problem is with the cable segments 8 themselves or with the connections between 9 segments?

10 MR. WEST: So we are confident it was 11 the cables themselves. We don't typically have 12 splices in the underground portions of the 13 cables. So we are able to isolate and validate 14 that it is the cable itself.

15 MEMBER ABDEL-KHALIK: Okay, thank you.

16 MR. SHARP: So, Mike Wright is the 17 next presenter on flux thimble tube.

18 MR. WRIGHT: Thank you, Loren. Good 19 afternoon, Mr. Chairman, Committee members. My 20 name is Mike Wright, Mechanical System 21 Engineering Manager at Diablo Canyon. I have 22 been at the plant for 22 years and in Engineering 23 for the last 10, for 10 years.

24 I will be presenting some background 25 information on a flux thimble tube leak that NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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30 1 occurred in 2006, a status one open item 2 associated with flux thimbles.

3 Slide 16, please. Unit 2 thimble tube 4 L-13 leaked approximately four months following 5 refueling outage 2R-13 in 2006. The tube had 6 been in service for a little more than three 7 cycles. This graphic depicts the approximate 8 location of thimble tube L-13, and the magenta 9 boxed area would be the approximate location.

10 Historically, L-13 was capped in 1990 11 following refueling outage 2R-3, remained out of 12 service for over 10 years until it was replaced 13 in 2001 with a tube having a 15-inch chrome band 14 designed to be centered around the highest wear 15 location, which is the bottom nozzle of the fuel 16 assembly.

17 Slide 17, please. More history: In 18 2004, 2R-12, we measured approximately 47 percent 19 wear outside of the chrome band of this thimble 20 tube, approximately five feet below the bottom 21 nozzle, and the tube was pulled out five inches 22 to relocate the wear spot.

23 Again in 2006, the subsequent outage, 24 2R-13, we measured 44 percent wear in the same 25 thimble tube in a similar location, and the tube NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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31 1 was pulled out an additional five inches, again 2 to move the wear spot.

3 These two pulls resulted in exposing 4 the non-chrome plated portion of the thimble tube 5 to be bottom nozzle, the higher wear area of the 6 fuel assembly. Approximately four months 7 following 2R-13, L-13 leaked. The leakage was 8 isolated by closing a valve at the seal cable.

9 Slide 18, please. Now I will address 10 the open item. There are two aspects of the open 11 item, the first being that the Diablo acceptance 12 criteria does not specifically include a value 13 for instrument and wear scar uncertainty. We 14 were asked to verify that we have the appropriate 15 margin to account for them.

16 Resolution: Diablo wear methodology 17 was compared to the Westinghouse industry 18 standard, the WCAP-12866 or thimble tube eddy 19 current testing using our site specific wear 20 data. The result of that analysis is that Diablo 21 wear projection methodology was slightly more 22 conservative than the WCAP.

23 The Westinghouse war projection 24 methodology acceptance criteria is 80 percent, 25 which does include instrument uncertainty, and NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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32 1 currently our wear projection methodology or 2 acceptance criteria is 68 percent, which does not 3 include uncertainty.

4 The difference between those two is 5 17.5 percent, more conservative than the 6 Westinghouse industry standard. Typical values 7 used for uncertainty are 10 percent. We believe 8 our 17.5 percent margin from the industry 9 standard represents adequate margin to account 10 for instrument and wear scar uncertainties.

11 As a result of the L-13 cause 12 analysis, again from cycle 14, we have added 13 additional nonlinear wear acceptance criteria 14 that I will describe in a couple of slides. In 15 total, we believe that the combination of the 68 16 percent wear in addition to the nonlinear 17 acceptance criteria is both conservative and 18 comprehensive.

19 MEMBER STETKAR: Mike, let me just 20 make sure I understand this slide, and from what 21 I read in the SER.

22 You are now proposing a 68 percent 23 wear acceptance criteria, and is that -- I know, 24 from what I read, you used to have that, and then 25 the WCAP was issued, and it sounded like you had NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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33 1 increased it to -- I don't know whether it was 78 2 percent or 80 percent or something like that.

3 As a resolution of the open item, you 4 are now dropping back to the 68 percent. Is that 5 correct?

6 MR. WRIGHT: No, sir. We have had 68 7 percent the entire time. We got the WCAP in the 8 Nineties, which said 80 percent. We did not 9 adopt that number.

10 MEMBER STETKAR: Oh, I guess I 11 misunderstood what I read in the SER, because it 12 sounded like you had increased that limit, and 13 that is what the staff was concerned about, that 14 that 80 percent wear limit did not adequately 15 account for the uncertainties, but you have --

16 MR. WRIGHT: We have got the 68 17 percent number. What we did do was remove the 18 uncertainty penalty, and that is the area that we 19 are still working with the staff to --

20 MEMBER STETKAR: So you are actually 21 still negotiating with the staff over this. It 22 is still an open item.

23 MR. WRIGHT: Still working with the 24 staff to get a resolution.

25 MEMBER STETKAR: Thank you. That NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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34 1 helps.

2 MR. WRIGHT: Slide 19, please. The 3 second aspect of the open item requests the 4 additional information on the L-13 cause 5 evaluation and corrective actions.

6 In 2R14, L-13 was removed from the 7 plant in 2$14 following eddy current testing 8 examination. There were two high wear locations 9 that were identified greater than 90 percent on 10 the L-13 with eddy current examinations.

11 One was in the highly radioactive 12 region at the bottom nozzle of the fuel assembly, 13 and the other about five feet below the lower 14 core plate in the vicinity of the previously 15 identified wear.

16 When we cut the tube out to remove it 17 from the plant, we inspected both portions, the 18 highly radioactive one by video camera since it 19 was highly radioactive, the other one by touch, 20 by feel. Due to the feel of the tube at the 21 location five feet below the lower core plate, we 22 felt that was the wear or the through-wall leak, 23 and that is the piece that we sent off to 24 Westinghouse to be examined by destructive 25 testing.

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35 1 During that examination by 2 Westinghouse, it was determined that the three-3 foot section we sent to them did not contain the 4 throughwall leak. However, it did contain the 90 5 percent wear location leak as well as both the 47 6 and 44 percent wear location.

7 The signatures on the eddy current 8 test of both the 90 percent, the graded 90 9 percent locations, were similar, and the cause of 10 the wear of the tube that we did send to 11 Westinghouse was determined to be flow induced 12 wear.

13 Based on this determination and the 14 similarity of the two 90 percent wear locations 15 of the tube and previous Diablo tube violations 16 that we had sent back to Westinghouse -- we sent 17 tubes back to them in the early Nineties in the 18 development of the WCAP-12866 -- the cause was 19 determined to be flow induced wear and plant 20 practices that allowed multiple repositioning of 21 thimble tubes.

22 Repositioning of L-13 exposed the non-23 chrome plated portion of the tube to the bottom 24 nozzle, and then we have been doing eddy current 25 testing since 1R3, 2R3, and in all that time flow NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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36 1 induced wear is the only degradation mechanism 2 found at Diablo. Cracking has not been 3 identified in any of the eddy currents 4 examinations performed.

5 Slide 20, please. In resolution, this 6 is the slide that I referred to previously. The 7 corrective actions to prevent reoccurrence from 8 the root cause evaluation resulted in additional 9 acceptance criteria to address the non-linear 10 wear. They include: A thimble must be removed 11 from service or repositioned if we experience 12 greater than 25 percent wear per year, or a tube 13 has two wear scars greater than 40 percent.

14 Additionally, a tube may only be 15 repositioned six inches, and they may only be 16 repositioned once. I note that each of --

17 MEMBER ABDEL-KHALIK: If the mechanism 18 is indeed flow induced wear, do you have any idea 19 what the extent of your lower plenum anomaly is?

20 MR. WRIGHT: Well, we detect the 21 degradation through 100 percent eddy current 22 testing. So we know the status of --

23 MEMBER ABDEL-KHALIK; Lower plenum 24 flow anomaly was in the core.

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37 1 from Mr. Mark Mayer, please.

2 MR. MAYER: My name is Mark Mayer. I 3 am at the Diablo Canyon staff.

4 We have some information on the lower 5 plenum anomaly, but we do not really see any 6 indications of a strong lower plenum anomaly, and 7 we can get you additional information, if you 8 would like that.

9 MEMBER ABDEL-KHALIK: And what would 10 be your indications that you are looking for?

11 MR. MAYER: I would have to get back 12 to you on that particular question.

13 MR. SHARP: The current charts we do 14 have that shows the number of them that are still 15 at that same --

16 MR. BECKER: Yes. I think that would 17 give you some information about it.

18 MR. WRIGHT: Miranda, if you could 19 move to slide Number 70. Slide 70 depicts the 20 current status of all 58 thimble tubes in both 21 units. It represents that approximately half of 22 the thimble tubes in both units are original, 23 non-chrome plated thimble tubes with minimal wear 24 located in various locations, and the remaining 25 half are locations where we have replaced them NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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38 1 with either 15-inch chrome plated thimble tubes 2 or a full 12-foot chrome plated thimble tube, and 3 then 11 of the tubes, total tubes, are either 4 capped or the guide tube is attached.

5 So the flows vary in the lower portion 6 of the lower internals. Again, essentially we 7 used our eddy current testing to determine the 8 locations where we need to put the hardened 9 outside thimble tubes.

10 I would like to go back to Slide 20, 11 please, Miranda. In addition, the -- Each of 12 these four acceptance criteria individually would 13 have resulted in removing thimble tube L-13 from 14 service in 2R13.

15 Since application of these new non-16 linear acceptance criteria, 31 tubes have been 17 removed from service in the last five refueling 18 outages. Of these 31 tubes, 67 percent were due 19 to this exceeding the non-linear wear criteria.

20 So the message here is the additional criteria we 21 put in place has been effective in identifying 22 tubes to replace.

23 When we do replace them, we replace 24 them with Westinghouse supplied 12-foot chrome 25 plated band to cover the entire area in the lower NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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39 1 head up through the bottom nozzle.

2 Diablo Canyon, again, has not observed 3 any wear in a chrome plated portion of thimble 4 tubes.

5 Slide 21, please. In conclusion, PG&E 6 is confident that the 68 percent acceptance 7 criteria, in combination with the additional non-8 linear acceptance criteria, is both comprehensive 9 and conservative.

10 MR. SHARP: the next presenter is 11 David Gonzalez, my ISI supervisor at Diablo 12 Canyon.

13 MR. GONZALEZ: Good afternoon. My 14 name is David gonzalez, and I am the ISI 15 Supervisor at Diablo Canyon. Today I am going to 16 discuss the open item addressing the 1997 flaw 17 analysis for Unit 1 piping weld, and the reason 18 that this flaw analysis did not address the 19 stress corrosion cracking.

20 In support of this discussion, I will 21 present PG&E's basis for concluding that this 22 flaw was not service related and, hence, did not 23 need to be analyzed for a stress corrosion 24 cracking flaw growth.

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40 1 submitted and discussed additional information 2 regarding this open item.

3 MEMBER ARMIJO: This is a stainless 4 steel pipe?

5 MR. GONZALEZ: Yes, and I will discuss 6 the characteristics and the isometric drawing.

7 MEMBER ARMIJO: And what grade of 8 stainless steel is this?

9 MR. GONZALEZ: It is 304, and that 10 will be depicted on the following slide. So 11 first I would like to describe this piping 12 system. Miranda, Slide 24, please.

13 So this line is the residual heat 14 removal system, stainless steel pipe, 12 inches 15 diameter, and about .4 inches thick. The 16 specific weld I am addressing is identified as 17 WIC-95, and is pipe to tee weld and as shown on 18 this isometric drawing, Miranda is highlighting 19 that location now.

20 It is located in our auxiliary 21 building in our 100-foot penetration room. This 22 RHR's line's function is to supply flow to the 23 reactor coolant system, hot legs 1 and 2, in the 24 event it is needed post-accident.

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41 1 as it is not a standard at-power or refueling 2 outage alignment. I would only see check valve 3 testing operations, and that is typically one 4 time per outage.

5 A routine ISI -- ultrasonic 6 examination in 1997 discovered an indication in 7 this weld. The indication was ultrasonically 8 dimensioned as approximately .4 inches long and 9 approximately .2 inches in through-wall 10 dimension, and it was plotted to be in close 11 proximity to the ID of the pipe.

12 Slide 25, please. This slide is a 13 graphic representation of the pipe to tee 14 configuration and the location of the indication 15 I am discussing.

16 So in answer to your question, sir, 17 the tee is 403 wrought 304 stainless steel. So 18 it a wrought tee, and the pipe is also, as 19 depicted there on the righthand side. That is a 20 12 inch Schedule-40 stainless steel, also 304, 21 and the weld material would be our ER 308.

22 So the indication we are discussion as 23 at approximately 90 degrees on the pipe side of 24 the tee, on the pipe side of the weld. This 12 25 inch line would eventually tie into the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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42 1 containment flow path and into the loop 1 and 2 2 hot legs.

3 So at the time of the indication's 4 discovery, Diablo Canyon's UT level 3s compared 5 the recorded dimensions of this reflector to ASME 6 Section 11 Code acceptance criteria.

7 MEMBER ARMIJO: Now that flaw was not 8 detected during post-fabrication inspection?

9 MR. GONZALEZ: Actually, there was 10 flaws, and I will discuss that also. There was 11 flaws detected for insufficient penetration 12 during the initial construction radiography, and 13 there was notes that there had been repairs on 14 that weld for insufficient penetration, and that 15 factored into similar confusion regarding the 16 nature of this flaw.

17 So when the dimensions of the 18 reflector were compared to the ASME Section 11 19 Code acceptance criteria, it was found not to be 20 within the standard code table acceptance limit.

21 At this time, supplementary ultrasonic and 22 radiographic examination techniques were applied 23 to attempt to ascertain the size and the nature, 24 the character, of this reflector.

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43 1 also reviewed. As I had noted, there had been 2 repairs on this weld during construction for 3 insufficient penetration. However, we were not 4 able to positively match up the RT number belt 5 locations and the repairs to this reflector that 6 we had recently recorded.

7 This information was immediately 8 entered into our corrective action program, and 9 an engineering analytical evaluation, as allowed 10 by ASME code, was performed. This evaluation 11 considered relevant material properties, 12 operating loads, and degradation mechanisms using 13 fatigue as a dominant driver.

14 The result of this assessment was that 15 the weld was suitable for continued service. As 16 part of the evaluation actions, Engineering 17 stipulated a repeat UT examination during the 18 next refueling outage.

19 In 1999, the first follow-up UT exam 20 was performed, and no flaw growth was measured.

21 This was also entered into our corrective action 22 program. Again, in the next refueling outage in 23 the year 2000, another successive UT exam was 24 performed, and no flaw growth was measured.

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44 1 Class II system would have only required one 2 single follow-up examination, but we have 3 performed two.

4 MEMBER SHACK: What is the exact UT 5 method you used?

6 MR. GONZALEZ: This was sheer wave --

7 At the time of its initial examination, a 8 performance demonstration initiative or PDI, 9 Appendix -- Section 11, Appendix 8, requirements 10 were not in effect. So it was standard appendix 11 3 flaw sizing rules. However, at that time, we 12 used what we considered state of the art 13 techniques, which were the Appendix 8 techniques 14 with multiple search units and multiple mode of 15 propagation.

16 Miranda, would you put on Slide 66, 17 please. This is just a graphic representation of 18 some of the UT techniques we applied at that time 19 over a period of a few days, trying to 20 characterize that indication. So we did not rely 21 solely on the specified ASME techniques.

22 We used what we considered state of 23 the art with qualified UT examiners. So you can 24 see, we used 70 sheer waves, 60 degree L-waves, 25 etcetera, focused dual-element transducers, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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45 1 creeping longitudinal waves. We threw everything 2 we had at it, trying to characterize it.

3 MEMBER SHACK: And in the subsequent 4 exams?

5 MR. GONZALEZ: At that time, PDI 6 requirements were in effect. So we used PDI 7 qualified procedures, including PDI qualified 8 examination of personnel. Yes.

9 MEMBER ABDEL-KHALIK: Is there any 10 vibration monitoring of this line?

11 MR. GONZALEZ: Not to my knowledge. I 12 would expect not, and I would be correct. No, 13 sir. This line, as I noted earlier, would not 14 normally see flow. It would only be used after a 15 post-accident or to flow RHR into loop 1 and 2 16 hot leg, and that is an evolution that would not 17 occur for a number of hours after an accident.

18 MEMBER ARMIJO: So during normal 19 operation then, is that a dead leg? Is there --

20 MR. GONZALEZ: During normal 21 operation, that would not see any flow, and 22 actually, that would be at ambient temperatures 23 with no elevated temperatures and no flow and no 24 pressure or minimal pressure, if any.

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46 1 periodic testing of the pumps, would this line be 2 vibrating?

3 MR. SHARP: No. During non-outage 4 situations, we run the RHR pump on recirculation.

5 So it wouldn't see flow, and during outages we 6 mostly flow into the cold legs, not so much the 7 hot legs. So typically, no flow period in those 8 -- in the RHR hot leg line.

9 MR. GONZALEZ: So the fracture 10 mechanics analysis conducted in 1997 considered 11 fatigue as a degradation mechanism. The 12 ultrasonic examination had concluded that this 13 flaw did not have the nature of stress corrosion 14 cracking due to the characteristics of the UT 15 signal envelope and, as had we illustrated, we 16 applied various UT techniques in trying to 17 ascertain the reflector's attributes.

18 So the multiple UT techniques and 19 precisely aligned radiography shots that we 20 employed to characterize this flaw, and in 21 concert with each other, they had concluded the 22 reflector was not stress corrosion cracking.

23 This was a degradation mechanisms that we had 24 reported to Engineering for their flaw analysis 25 was that it was not stress corrosion cracking.

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47 1 The UT exams had plotted the position 2 of this flaw to be at or near the ID of the pipe.

3 The proximity rules for flaw sizing in ASME 4 Section 11 Code required it to be considered 5 surface connected at this point, regardless of 6 whether it had an actual opening to the ID of the 7 pipe or not. So by default, this placed the 8 reject criteria in the more conservative column 9 of a surface connected flaw for Section 11.

10 Due to the configuration of the piping 11 system, however, there was no practical method 12 for examining the ID of the weld to determine if 13 it actually was or was not open to the surface.

14 Slide 23, please.

15 MEMBER SIEBER: This is a low pressure 16 line. Right?

17 MR. GONZALEZ: It would see maximum 18 RHR pressure, which would be approximately --

19 MR. SHARP: In piggyback mode, less 20 than that, 350 pounds, yes.

21 MR. GONZALEZ: So normally, it would 22 not see extreme pressures, yes.

23 MEMBER SIEBER: Right.

24 MR. GONZALEZ: And normally -- excuse 25 me. It would see a maximum pressure as 350.

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48 1 MEMBER SIEBER: Schedule 4, right?

2 MR. GONZALEZ: That is correct, 12 3 inch diameter, .4 inches thick, and UT 4 measurements actually measure it slightly thicker 5 than .4 inches thick.

6 So we are back on Slide 23. So a new 7 Engineer analysis has recently been performed on 8 this flaw using both stress corrosion cracking 9 and fatigue as a degradation mechanism. These 10 results continue to find the flaw is currently 11 acceptable.

12 An ISI exam scheduled for the Unit 1 13 refueling outage in 2012 will determine if this 14 indication has experienced any growth. If growth 15 is detected, this information will be immediately 16 entered into our corrective action program system 17 for disposition in accordance with ASME Code 18 requirements.

19 MEMBER ARMIJO: How did you conclude 20 that the -- if the stress corrosion cracking 21 evaluation was acceptable, because of the low 22 temperature of the environment or some other?

23 MR. GONZALEZ: The new engineering 24 analysis, and if we want some detail, I will ask 25 for some assistance on this. But the new NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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49 1 engineering analysis used the material properties 2 and the time at temperature that this would 3 typically see during a normal operating cycle, 4 and it used those inputs to determine what the 5 propagation rate would be for stress corrosion 6 cracking and when we would achieve unacceptable 7 progress.

8 MEMBER ARMIJO: So you had very 9 limited time at temperature.

10 MR. GONZALEZ: That is correct.

11 MEMBER ARMIJO: And you used the crack 12 growth correlation.

13 MR. GONZALEZ: That is correct.

14 MEMBER SHACK: And the crack growth 15 correlation came from what?

16 MR. GONZALEZ: Let me ask Mr. Lee 17 Goyette, who has been very much involved with the 18 fracture mechanics analysis to discuss that.

19 MR. GOYETTE: I am Lee Goyette. I am 20 with PG&E, and we have the calculation done 21 according to -- by Structural Integrity 22 Associates, and they used the latest criteria 23 that was available in the literature for crack 24 growth rates under stress corrosion cracking 25 concerns.

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50 1 So there is quite a bit of discussion 2 over the crack growth rates that were appropriate 3 in this situation, and --

4 MEMBER SHACK: Yes, I can imagine.

5 MR. GOYETTE: Yes. And the fellows 6 that did the analysis sit on the code committees, 7 and they are aware of the latest what is the best 8 stuff to use. So the analysis was done in a 9 conservative way at the high temperature, the 10 highest temperature that we determined the system 11 to be operating at for a limited time during each 12 refueling outage, and we turned out to have 13 acceptable results, and we will look at the 14 indication again during the next outage and 15 confirm.

16 MR. GONZALEZ: So the information that 17 we have gathered indirectly via the ultrasonics, 18 and using the signal envelope characteristics 19 that are mentioned, that are noted in the PDI 20 approved procedures are used to determine the 21 nature of the flaw, and a linear rise and fall 22 rate, nonspecular reflection, very uniform 23 positioning of the ultrasonic responses, all tell 24 us that it is not stress corrosion cracking.

25 As I had noted earlier, we have done NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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51 1 some specifically aligned radiography to look at 2 this flaw. Aside from the construction period 3 radiography, we have done some specifically 4 aligned radiography to see if we could see a flaw 5 there, and we saw nothing, also telling us that 6 it could be nothing but either lack of fusion or 7 lack of penetration.

8 My experience in construction 9 industry, a repair on a weld -- sometimes they do 10 get the flaw. They do get all the insufficient 11 penetration out or lack of fusion out, and 12 sometimes they will leave a little residual bit 13 of it, but the subsequent radiography will accept 14 it. So it is not uncommon to see a reflector in 15 a previously repaired area.

16 MEMBER ARMIJO: Now you did have 17 instances of IGSEC in your plant early on, 1987, 18 and in your LRA you mentioned some accumulator 19 nozzles, again signature 304 conventional carbon, 20 high carbon. So you detected that by your ISI 21 program?

22 MR. GONZALEZ: Yes, actually, it was 23 spotted visually, and then we had -- WE have 24 implemented a long term program where we 25 ultrasonically examined these accumulator NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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52 1 nozzles, and we were able to see incipient 2 cracking in these accumulator nozzles.

3 A mechanism there was different.

4 Metallurgy found there was considerable 5 contaminants, and we determined that it was due 6 to the original manufacturer.

7 MEMBER ARMIJO: Was that furnace 8 sensitized or heat treated with any other 9 components?

10 MR. GONZALEZ; I believe those nozzles 11 were installed -- and I will be corrected if I am 12 wrong. Those nozzles had been installed prior to 13 the heat treat of the accumulators, and that was 14 a contributor to their cracking.

15 MEMBER ARMIJO: And what did you 16 replace them with?

17 MR. GONZALEZ: With a partial fillet 18 weld accumulator nozzle. They were bored up.

19 These had been full penetration fillet welds on 20 both sides in the accumulators, and we replaced 21 them with a partial penetration fillet weld, and 22 the material is -- I am going to have to ask 23 Chris Beard, who is our Materials Engineer, also 24 of the ISI group.

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53 1 Beard. I work for PG&E, and we replaced them 2 with 304 L-grade stainless steel.

3 MR. GONZALEZ: And our subsequent 4 exams on those accumulator nozzles have not found 5 any repeat incidences of cracking, and it appears 6 we are over the curve where we saw a lot of 7 cracking early on in these accumulator nozzles, 8 but subsequent examinations have found those, and 9 we actually do those early in every outage.

10 MEMBER ARMIJO: Okay. thank you.

11 MR. GONZALEZ: Non-replaced outage --

12 non-replaced nozzles only.

13 MEMBER ARMIJO: Right. You still 14 monitor the non-replaced.

15 MR. GONZALEZ: That is correct.

16 MEMBER ARMIJO: But you don't have to 17 do it with the 304 L-grade?

18 MR. GONZALEZ: That is correct.

19 MR. WRIGHT: We monitor them with 20 visual inspection only. Yes, sir?

21 MEMBER ABDEL-KHALIK: I understand 22 that this pipe is essentially empty during normal 23 operation and refueling.

24 MR. WRIGHT: No, it would remain full.

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54 1 no flow. Excuse me. So what is the state of 2 stress on this pipe, first under normal 3 conditions when there is no flow, and in the 4 event that flow is started?

5 MR. GONZALEZ: I will have to ask Mr.

6 Goyette to answer that.

7 MR. GOYETTE: Lee Goyette. Well, the 8 state of stress during normal plant operation 9 would be dead weight and whatever temperature 10 effects, and in a design seismic event. So a 11 very low state of stress, plus pressure.

12 With the system in service, during an 13 accident mode, normal -- emergency and faulty 14 conditions, it would be at temperature for long 15 term cooling.

16 MEMBER ARMIJO: Do you put in a weld 17 residual stress into your stress analysis when 18 you evaluate for stress corrosion cracking?

19 MR. GOYETTE: Weld residual stress? I 20 think not.

21 MEMBER ARMIJO: That is typically the 22 initiators of stress corrosion cracking compared 23 to dead weight load, but these cracks haven't 24 grown. You have monitored them.

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55 1 have had two subsequent examinations. There has 2 been no measurable change in growth -- in size, 3 excuse me.

4 Continuing on: So the ISI examination 5 that is scheduled for the next refueling outage 6 in 2012 will monitor this flaw for any change in 7 dimensions. If growth is detected, this 8 information will be immediately entered into our 9 corrective action system for disposition in 10 accordance with the current code requirements.

11 If no growth is experienced, this weld 12 will revert to the standard ASME inspection 13 frequency, as specified by the ISI program which 14 will require an examination every 10 years, and 15 examination results from those future inspections 16 will be evaluated against the existing code 17 requirements at those times.

18 So this concludes my presentation on 19 the WIC-95.

20 MR. SHARP: Next presentation is by 21 Dave Miklush of our License Renewal Project.

22 MR. MIKLUSH: My name is Dave Miklush, 23 and I am a member of the Diablo Canyon License 24 Renewal Team. I will be presenting the open 25 items for the scoping and screening portion of NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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56 1 our submittal.

2 Slide 27, please. The first open item 3 deals with non-safety related fluid-filled piping 4 near safety related systems.

5 In our first series of walkdowns, we 6 missed two things. One was we didn't look hard 7 for rainwater entry at the systems, and the 8 second one was the proximity of low pressure 9 piping near a safety system, specifically in the 10 Turbine Building.

11 So we instituted another set of 12 walkdowns, and found that our HVAC ducting, 13 exhaust ducts from Unit 2's 480V switchgear room 14 had an outlet that was oriented upward that could 15 collect rainwater. So it looked like it might be 16 a problem, but when we inspected it further, we 17 found out there were drain holes inside.

18 However, there was some rusting going on where 19 the water had been collecting.

20 So we have elected to add more drain 21 holes in there. I would point out that we have 22 never had a water problem getting into our 480V 23 switchgear rooms from the ventilation system.

24 The second two items had to do with 25 firewater piping near control pressurization, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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57 1 pressurization fan controls. On our first 2 walkdown, we saw this piping. It was low 3 pressure, and it wasn't very close.

4 After the RAI, we went out and 5 recalibrated our walkdown and said, if we could 6 see low pressure piping within line of sight, we 7 will add it into scope, and that resulted in 8 these two items that we added into scope on the 9 control pressurization fans and on the exhaust 10 opening for the 4kV switchgear rooms, which had 11 firewater and domestic water pipes within 50 or 12 60, again line of sight, of the equipment.

13 Slide 28. slide 28 had to do with the 14 electrical pull boxes and whether or not the pull 15 boxes had pressurized piping going through the 16 pull boxes.

17 Now Ryan West earlier talked to you a 18 lot about the configuration of the drainage and 19 the gravity drains and the external sumps, and we 20 have just confirmed here that there are no 21 pressurized sump pump piping returning into the 22 pull box, electrical pull box. So that was a 23 clarification on that one.

24 Slide 29. Slide 29, in another 25 walkdown we found water trapped in the instrument NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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58 1 air system that was near the exhaust ducting of 2 the fuel handling building supply fans.

3 Although the instrument air system is 4 a very dry system and it is monitored for dew 5 point, we have elected to keep the inlet valve to 6 that water trap closed, because the valve that it 7 supplies is a heating steam valve to the flow 8 handling, and we have never used the system and 9 don't expect to ever use it in the future. So 10 that is how we resolve that one.

11 Slide 30 is a different topic. It is 12 the scope boundary between non-safety related and 13 safety related instrument air tubing. Again, 14 this is a clarification that our scope boundary 15 extends beyond the safety related to non-safety 16 related isolation device to the solenoid valve or 17 check valve into the non-safety related tubing at 18 the first seismic anchor or equivalent seismic 19 anchor.

20 That has been noted on the instrument 21 air system drawings for license renewal scope 22 boundary. That explains to future engineers 23 where the scope boundary ends for the safety 24 related instrument air tubing.

25 Slide 31. This issue had to do with NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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59 1 the pressure boundary status of the air start 2 compressor unloader line, which connects the air 3 compressor directly to the instrument air 4 receiver. The diesels are air start. Motors air 5 start, air receiver.

6 The line as non-safety related, very 7 small line, quarter inch in diameter. In the 8 past, it had been evaluated as acceptable as is, 9 meaning if it had failed, the air receiver could 10 still do its duty. However, in an effort to 11 clean up this design situation, we have rerouted 12 this unloader line upstream into the non-safety 13 related portion of the system, upstream of the 14 safety related isolation device.

15 That modification work has been 16 completed on Unit 1. All three diesels are 17 complete. One Unit 2, one diesel is complete, 18 and two more to go, and that will complete in 19 April of this year.

20 Slide 32 is two items concerning 21 buried valves and piping. The first one had to 22 do with copper valves in the makeup water system 23 that are in contact with soil, and the question 24 that was asked is how we aging manage those 25 valves, and our answer is we will be using the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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60 1 Buried Pipe and Tank Program to aging manage 2 those copper valves.

3 The second item had to do with the 4 branch line off our raw water reservoir line 5 coming into the plant. There is a branch line 6 that feeds industrial buildings. No safety 7 systems on that branch, and to limit the scope of 8 our license renewal program, we have elected to 9 revise operating procedures to isolate valves to 10 the branch line in case of a branch line leak or 11 the raw water reservoirs are aligned for long 12 term cooling, then we will go out and close those 13 valves to preserve the water supply in the raw 14 water reservoirs.

15 In that way, we have taken that branch 16 line out of scope.

17 DR. BARTON: Do you have cathodic 18 protection on your buried piping?

19 MR. MIKLUSH: There is some cathodic 20 protection on the aux saltwater system. We do 21 not have any on the make-up water system.

22 DR. BARTON: And what is its 23 availability?

24 MR. MIKLUSH: Its availability is very 25 good. I don't have the exact --

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61 1 DR. BARTON: What is very good?

2 Ninety, 95 percent?

3 MR. SHARP: Mr. Lee Goyette, could you 4 answer that?

5 MR. GOYETTE: Lee Goyette with PG&E.

6 The availability of cathodic protection is 7 monitored monthly, and it is over 90 percent, 8 according to the NACE standards.

9 MEMBER STETKAR: Before you leave, if 10 you are the cathodic protection person, the 11 staff's inspection report noted that you have 12 recently -- that is the term they used --

13 upgraded cathodic protection system. If that is 14 the case, when was that upgrade performed?

15 I understand you are now claiming it 16 is 90 percent available today, but what has it 17 been historically, and if it was indeed improved, 18 when were the improvements made?

19 MR. GOYETTE: That is a good question.

20 MEMBER STETKAR: I thought so.

21 MR. MIKLUSH: The cathodic protection 22 system was installed approximately 1995.

23 MEMBER STETKAR: Installed?

24 MR. MIKLUSH: The aux saltwater 25 system.

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62 1 DR. BARTON: The original or the 2 upgrades?

3 MR. MIKLUSH: It was installed on the 4 entire supply system from the intake to the 5 turbine building, including the bypass section, 6 which was new pipe at the time, and the old pipe 7 that remained in service. The old pipe was above 8 the ocean tide level.

9 MEMBER ARMIJO: On this chart about --

10 MEMBER STETKAR: Hold on a second. I 11 don't think I got the answer to my question. I 12 heard when it was installed. I asked had it been 13 upgraded at sometime since it was installed, and 14 when was that upgrade performed or was the 15 installation considered an upgrade, going from 16 zero to something?

17 MR. MIKLUSH: When the insulation went 18 in in 1995, that was the upgrade at the cathodic 19 protection system on the aux saltwater system.

20 Now the plant has had other non-safety related 21 cathodic protection systems in service since the 22 early Eighties, and we have had a surveillance 23 program written for those cathodic protection 24 systems for the entire life of the plant.

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63 1 wait and ask the staff.

2 MEMBER SHACK: We have a commitment 3 here to install cathodic protection for the ASW 4 discharge piping.

5 MR. MIKLUSH: There is a portion of 6 the discharge pipe from the turbine building to 7 the intake that is in contact with soil that does 8 not have cathodic protection on it, and --

9 MEMBER SHACK: So that will be an 10 upgrade when it is installed.

11 MR. MIKLUSH: That will be an upgrade.

12 MEMBER SHACK: And that is going to 13 happen when? Prior to the period of extended 14 operation?

15 MR. MIKLUSH: Prior to the period of 16 extended operation. That is right.

17 MEMBER ARMIJO: Now your makeup water 18 system, you said, is not covered by your cathodic 19 protection, or is?

20 MR. MIKLUSH: No, it is not.

21 MEMBER ARMIJO: It is not? Now a 22 copper valve -- I have never heard of such a 23 thing, but there may be. But are these bronze or 24 brass or are they truly copper valves?

25 MR. MIKLUSH: I am not sure of the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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64 1 exact alloy that they are made of.

2 MEMBER ARMIJO: Maybe some of your 3 people could say. And are they attached to 4 carbon steel piping, bolted or something like 5 that?

6 MR. MIKLUSH: The piping and the 7 firewater makeup water system is concrete 8 asbestos piping..

9 MEMBER ARMIJO: Concrete?

10 MR. MIKLUSH: Concrete asbestos 11 reinforced.

12 MEMBER ARMIJO: With copper valves 13 attached to that?

14 MR. MIKLUSH: And where -- Well, most 15 of the valves in the system are carbon steel.

16 There's a few valves that are copper or bronze 17 material, and those were these three valves that 18 were part of the RAI.

19 MEMBER ARMIJO: so you wouldn't have 20 any galvanic corrosion, because these are 21 concrete that they are attached to, because 22 copper and steel --

23 MR. MIKLUSH: There is not a piping 24 issue, but there is an issue with the metals that 25 are in the ground. So every valve location, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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65 1 there is a question of long term performance. So 2 those will have to be managed in the inspection 3 program.

4 MEMBER STETKAR: Someplace in the SER 5 I read that you have had problems with some 6 leakage in gray cast iron buried piping in the 7 firewater system, and apparently the corrective 8 actions have been to replace the piping with --

9 to replace the piping.

10 Do you still have buried gray cast 11 iron firewater piping on site or has all of that 12 been replaced?

13 MR. SHARP: Lee Goyette, could you 14 answer that?

15 MR. GOYETTE: Yes, sir. The majority 16 of the underground firewater piping is asbestos 17 concrete, and the risers that go to the hydrants, 18 those are gray cast --

19 MEMBER STETKAR: Okay. So it is only 20 the risers --

21 MR. GOYETTE: -- and they are being 22 replaced with ductile iron.

23 MEMBER STETKAR: They are being 24 replaced?

25 MR. GOYETTE: Yes, sir, they are.

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66 1 MEMBER STETKAR: But you also have PVC 2 piping in the firewater system. Right?

3 MR. GOYETTE: We do have PVC piping in 4 the firewater system. Yes.

5 MEMBER STETKAR: So you said it was 6 concrete. So it is both.

7 MR. GOYETTE: Both.

8 MEMBER STETKAR: Is one a replacement 9 for the other or you use them in different --

10 MR. GOYETTE: Don't know. I cannot 11 answer that question.

12 MR. SHARP: I can say that the 13 majority, 95+ percent of the buried pipe in the 14 fire protection system is the asbestos concrete 15 pipe. As Lee said, some of the risers have the 16 cast iron that we are replacing with ductile 17 iron. There are small segments of PVC, but 18 primarily the asbestos -- ACP pipe.

19 MR. MIKLUSH: That concludes my 20 presentation.

21 MR. SHARP: The next speaker is 22 Michelle Albright.

23 MS. ALBRIGHT: Mr. Chairman and 24 members of the Committee, good afternoon. I am 25 Michelle Albright, and I am part of the Diablo NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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67 1 Canyon License Renewal Team, and I will be 2 discussing the two open items that we have TLAAs.

3 The first one that I will discuss is 4 on TLAA identification, which consists of two 5 RAIs. Secondly, I will be discussing the open 6 item on metal fatigue, which is on nine RAIs.

7 Responses to all of these RAIs have 8 been submitted to the staff. We believe that we 9 have provided adequate responses to address the 10 staff's concerns, but they still are under 11 review.

12 Slide 34, please. Open item 4.1-1 is 13 on two topics. The first of these is on the 14 design codes for the reactor coolant pressure 15 boundary valves, and secondly is the managing of 16 the baffle and former bolts.

17 To address the first open item, we 18 reverified that the design codes for our reactor 19 coolant pressure boundary valves do not require a 20 fatigue or any time dependent analyses, and we 21 clarified it in the response to the staff.

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68 1 of those baffle and former bolts, and that is the 2 Reactor Vessel Internals Program.

3 MEMBER SIEBER: Do we have any 4 evidence of baffle jetting?

5 MR. SHARP: The answer is yes. We 6 have two over the time frame. We did have 7 evidence of baffle jetting, and that has been 8 remedied with modifications performed -- upflow 9 modifications performed in the last five to 10 eight years.

11 MEMBER SIEBER: And that is replace 12 bolts modification?

13 MR. SHARP: It was to cut some holes 14 in the upper portion of the baffle.

15 MEMBER SIEBER: So you lowered the 16 pressure differential?

17 MR. SHARP: Yes, sir.

18 MEMBER SIEBER: Does that reverse the 19 flow? Does that reverse the baffle flow?

20 MR. SHARP: It does in some cases, 21 yes. Dan Hardesty, could you please come to the 22 microphone and answer that question.

23 MR. HARDESTY: My name is Dan 24 Hardesty, Primary Systems Engineering. In 2R10 25 we performed what is called an upflow mod to the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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69 1 internals, lower internals and upper internals of 2 the reactor for Unit 2, and that corrected -- It 3 lowered the pressure in the inside of the baffles 4 so that it would jet in the opposite direction.

5 Westinghouse designed and performed 6 the modification.

7 MEMBER SIEBER: Did you have fuel 8 damage associated with the baffle flow?

9 MR. HARDESTY: Yes, sir, we did. In 10 the Nineties we had some damage.

11 MEMBER SIEBER: That is why you did 12 the mod, but the mod did not change the bolting.

13 What it did was reverse the flow.

14 MR. HARDESTY: That is correct.

15 MEMBER SIEBER: Thank you.

16 MS. ALBRIGHT: Slide 35, please.

17 There are nine RAIs associated with 18 open item 4.3-1. For the purposes of discussion 19 today, we categorized the resolution of these 20 nine RAIs into four common areas to give you a 21 feel for the types of responses that we had to 22 these RAIs.

23 The first of these areas would be 24 items that required additional information. For 25 example, in our license renewal application we NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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70 1 provided the conclusions that the replacement 2 reactor vessel head replacement CRDMs and the 3 replacement CETNAs were good past the period of 4 extended operation. However, we did not provide 5 the actual cumulative usage factor values in the 6 application to demonstrate that.

7 So in response to the RAI we merely 8 provided those CUF values, which showed that we 9 had adequate margin.

10 In the second group we provided 11 clarifying information based on four RAIs that we 12 received. An example here is a clarification for 13 the metal fatigue program. Basically, we 14 clarified that we were going to be using the FSAR 15 number of transients in our metal fatigue 16 program. These are lower numbers than are used 17 in the analyses for the upper and lower core 18 plate. So they are more conservative to count 19 to.

20 In the next group of RAIs, we will be 21 enhancing our current licensing basis.

22 MEMBER STETKAR: Before we go to the 23 enhancement, have you completely updated Table 24 4.3-2 in the license renewal application, because 25 all I have is the table from the original LRA, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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71 1 and looking at the responses to some of the RAIs 2 and the numbers in that table, there are a number 3 of instances where I couldn't make numbers add 4 up.

5 So, for example, your example on 6 charging cycle estimates for auxiliary spray 7 during plant cooldown, in the SER it is noted 8 that -- I have to find my notes; bear with me 9 here -- that there would be -- You are counting 10 two of those events per cooldown, and that 11 resulted in an estimate of 146 occurrences for 12 Unit 1 and 102 occurrences for Unit 2. But if I 13 use the number of cooldown events tabulated at 14 least in the license renewal application for Unit 15 1, I count 176, because there are -- I'm sorry, 16 174 -- I can't read my own writing -- because 17 there are 87 cooldown events projected for Unit 18 1, and 63 for Unit 2, which gives me 126.

19 So I am curious how you got 146 and 20 102. Is it a big deal? Are you close to the 21 margin? I am just interested in multiplying X 22 times 2 and being able to understand how that 23 counting is done.

24 MS. ALBRIGHT: I understand. i would 25 like to ask Mr. Chalmer Myer to address that NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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72 1 question.

2 MR. MYER: This is Chalmer Myer with 3 the Star Center of Business. We are going to 4 need to take it offline and respond later, 5 because it is going to take some review, but we 6 will get you an answer.

7 MEMBER STETKAR: There were some 8 others. In the interest of time, I would 9 encourage you and also the staff when they come 10 up to look at things like consistency. If you 11 are using 2 times X, make sure that X and 2 times 12 X are equivalent numbers. There are a number of 13 those things that I have come across.

14 As I said, in the grand scheme of 15 things, you are well below the margins, but I am 16 talking about consistency, because you are using 17 methods to develop those cycle counts. Thank 18 you.

19 MS. ALBRIGHT: Thank you. For the 20 next group of RAIs, we will be enhancing our 21 current licensing basis and, namely, this is the 22 FSAR. For example, the staff questioned why our 23 FSAR didn't provide the technical basis for us 24 not counting load-following transients. While 25 they agreed with the technical basis of why we NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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73 1 aren't counting them, we didn't have that 2 actually documented in our FSAR. So we will be 3 updating our FSAR, and committed to do so in our 4 response.

5 The last category here is on 6 environmentally-assisted fatigue. For our 7 license renewal application, we performed the 8 environmentally-assisted fatigue analyses per 9 NUREG/CR-6260 using the locations for an older 10 vintage Westinghouse plant.

11 The staff did question why we did not 12 consider other locations than those originally in 13 our application. After discussions with them, we 14 did agree that it would be -- that we would 15 commit to review our existing fatigue analyses to 16 determine if the analyses that we performed for 17 environmentally-assisted fatigue are limiting for 18 the Diablo Canyon reactor cooling environment.

19 Through those evaluations, if we do 20 find more limiting locations, then the most 21 limiting component will be evaluated for 22 environmentally-assisted fatigue through our 23 metal fatigue program, and we will be doing that 24 prior to the period of extended operation.

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74 1 TLAA open items.

2 MEMBER SIEBER: Have you had any 3 issues with control rod drive mechanism tube 4 split pins that hold the tubes in place within 5 the control rod drive?

6 MR. GREBEL: Dan Hardesty, have we had 7 a previous history with split pins? Dan, could 8 you answer that?

9 MR. HARDESTY: Sorry, I didn't catch 10 the question all the way.

11 MEMBER SIEBER: The question is: In 12 your class of plants around the time this plant 13 was built, there was an issue of cracking of 14 split pins that hold the control rod drive 15 mechanism tubes at the top of the core plate into 16 position so that you would not delay the dropping 17 of the control rod during a reactor SCRAM.

18 Have you examined your split pins or 19 have you replaced them?

20 MR. HARDESTY: We replaced our split 21 pins. I believe we have two different 22 replacements at different times, but the last one 23 was in 2R10 when we did the upflow mod. We took 24 advantage at the time and replaced the split pins 25 with the new versions.

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75 1 MEMBER SIEBER: And so baffle jettings 2 issue solution is pretty recent?

3 MR. HARDESTY: It was a convenient 4 time to do it, because we had --

5 MEMBER SIEBER: So you did split pins 6 -- some split pins and baffle jetting, flow 7 reversal at the same time, same outage?

8 MR. HARDESTY: Yes.

9 CHAIRMAN BLEY: Any other questions?

10 Yes? Go ahead.

11 MEMBER STETKAR: Thank you. A couple 12 of quick ones. You have apparently had some 13 problems out in the intake structure, because it 14 is a pretty harsh environment on the coast there, 15 and I have noted that it was placed into a higher 16 category of attention with the plans for 17 remediation because of deterioration, I guess, in 18 the structural concrete and things like that.

19 According to the SER anyway, it said 20 that the Applicant had developed a repair plan to 21 return the intake structure to A2 inspection 22 status under the maintenance program by 2010, 23 which implies that it should now be in much 24 better shape. Is it?

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76 1 preemptive comment, and then I will let David 2 Wong answer.

3 We have indeed done repairs on the 4 intake structure to take it back to a better 5 condition. We had some additional degradations 6 identified as we were making those repairs, and 7 so there has been a little bit of delay. That 8 won't be completed now until this spring in 2011.

9 MEMBER STETKAR: Thanks. One more.

10 Let me just make a note on that. This, again --

11 You apparently in Unit 2 during RO-15 identified 12 -- they are characterized as gaps between the 13 concrete floor and the steel liner in the 14 containment, and apparently you have made a 15 commitment to seal the gaps.

16 The way I read the material, it 17 sounded to me as if there had never been any 18 sealant in the gaps. Is that true?

19 MR. SHARP: Yes. The Diablo Canyon 20 design does not include a moisture barrier 21 component seen in other plants. The concrete 22 runs up to the containment liner at the base of 23 containment.

24 MEMBER STETKAR: A couple of 25 questions. If you have now made the decision to NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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77 1 seal the gaps, does that mean you are only going 2 to seal the places where you found the gaps or 3 are you going to actually install circumferential 4 moisture barrier?

5 MR. WONG: This is David Wong, Civil 6 Engineering Supervisor. We are intending to seal 7 only the gaps at this time. The concrete is very 8 hard pressed up against the liner. We inspect 9 them every outage. We have a couple of programs 10 that look at that every outage, our Coatings 11 Monitoring Program, and also the Civil 12 Maintenance Rule Program.

13 DR. BARTON: How do you know you have 14 never had any leakage between the concrete and 15 the liner or there is any corrosion down 16 underneath the floor?

17 MR. WONG: We have never seen any 18 leakage or any signs of degradation of the 19 concrete, any kind of degradation which would re-20 collect through the liner as popping and spalling 21 the concrete or cracking it.

22 MEMBER STETKAR: Thanks. I am 23 finished.

24 CHAIRMAN BLEY: Any other questions?

25 DR. BARTON: Yes.

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78 1 CHAIRMAN BLEY: Yes, John?

2 DR. BARTON: The Appendix A, your 3 final safety analysis supplement and also Append 4 B, aging management program, when you talk about 5 your one-time inspection of code Class 1 small 6 bore piping, I don't get what your final 7 commitment is on volumetric testing of socket 8 welds.

9 MR. SHARP: Chris Beard, could you 10 please respond to that?

11 MR. BEARD: Chris Beard. Our final 12 commitment, as responded to in our latest request 13 for additional information, is: Diablo Canyon 14 will volumetrically examine 10 percent with a 15 maximum of 25 welds of each weld type socket and 16 butt welds for ASME Class 1, less than four 17 inches. That is our final commitment.

18 DR. BARTON: Okay. I didn't get that.

19 So I am glad to hear you committed to do that.

20 Also, you have got an opening in 21 containment where you had strain gauges installed 22 for initial structure integrity tests, and those 23 openings are still there on both units. How do I 24 know that you don't have environment gotten into 25 there, and you have got rebar, concrete NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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79 1 degradation enclosed in your environment?

2 MR. SHARP: David Wong, could you 3 respond to that?

4 MR. WONG: This is David Wong. These 5 strain gauge boxes -- Yes, they were originally 6 installed during construction to monitor the 7 strain on the rebar. They are thin gauge 4 x 4 8 by 4 inch in depth thin gauge carbon steel boxes 9 embedded on the exterior part of the containment 10 structure.

11 They were banded in place after 12 testing. The strain gauge access boxes, which 13 were called openings, are actually covered with 14 plastic covers and sealed around with caulking.

15 Due to the age weathering effects, we 16 have seen some damage. Either the covers are 17 missing or they are broken, and we plan on 18 repairing those thin gauge boxes that we find 19 damaged in our next containment exterior concrete 20 inspections.

21 DR. BARTON: How do you know you 22 haven't had any corrosion since then, since you 23 know that you are really not sealed right now?

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80 1 seen.

2 CHAIRMAN BLEY: No further questions?

3 Thank you very much for your presentations. I 4 think we will take a break now, and I would ask 5 everybody to be back at 3:15. We will recess 6 now.

7 (Whereupon, the foregoing matter went 8 off the record at 2:57 p.m. and went back on the 9 record at 3:15 p.m.)

10 CHAIRMAN BLEY: The meeting will come 11 back to order, please. Brian, back to you.

12 MR. HOLIAN: Thank you. Sorry.

13 Waiting for the rest of the NRC staff. This is 14 Brian Holian, Director of License Renewal.

15 Our staff did take good notes during 16 some of the questions there. I know Mr. Shack 17 had a question early on about MRP. Let me just -

18 - So we will be addressing those as part of our 19 staff response to the SER and the open items.

20 Once again, up at the table we have 21 Stan Gardocki. Stan is one of our members from 22 another technical region, DSS, Division of Safety 23 Systems, and he helps out a lot of scoping.

24 You have heard from him before from 25 the floor on this particular plant. We had NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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81 1 issues with the plant walkdowns, and Stan is here 2 to support our discussion of that.

3 Bill Holston, a senior engineer in 4 License Renewal, there for the buried piping 5 issues. You have heard him on previous plants.

6 Alan Hiser, a senior level advisor in 7 Division of License Renewal, will be talking to 8 some of the metal fatigue items there, thimble 9 tube issues.

10 Greg Pick, I mentioned, a senior 11 inspector from Region IV, and Nate Ferrer, our 12 Project Manager. With that, I will turn it over 13 to Nate.

14 MR. FERRER: Thanks, Brian. Good 15 afternoon. As Brian said, I am Nate Ferrer. I 16 am the Project Manager for the Diablo Canyon 17 License Renewal Review, and I am pleased to have 18 the opportunity to present the staff's review, as 19 documented in our Safety Evaluation Report or SER 20 with open items.

21 Before I actually get into the 22 presentation, Allen will address the question 23 that we had earlier on the vessel internals.

24 DR. HISER: I guess, Bill, could you 25 restate the question?

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82 1 MEMBER SHACK: Two things. One, I 2 know Ginna submitted an inspection plan, and I 3 never saw whether you guys accepted it or not.

4 Since MRP 227 is all over GALL, I assume it was 5 finally accepted, but I haven't really seen that.

6 Then just since you now have the 7 guidance, you have presumably got somebody who 8 had one inspected. When are we going to see 9 people coming in with inspection plans rather 10 than, you know, we are going to follow the 11 industry sort of thing that we see standard here.

12 DR. HISER: A number of plants have 13 come in with inspection plans, because they have 14 already entered the extended period of operation, 15 and those plans are generally due two years ahead 16 of that time.

17 I am not sure of the status of the 18 Ginna plan, but --

19 MEMBER SHACK: Okay, but you have 20 accepted other plans then.

21 DR. HISER: I don't -- I am not sure 22 that we have accepted any. There were some 23 plants -- for example, Calvert Cliffs had 24 proposed specific inspections in their initial 25 application, and so they do not have that type of NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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83 1 commitment and do not owe us a plan.

2 So I will verify the status of Ginna 3 and some of the other plants. I am not aware, 4 though, that we have approved any MRP 227. The 5 SER has not been issued yet, but that will be 6 forthcoming.

7 MEMBER SHACK: Well, GALL-2, as I read 8 it, it seems to imply that you accept that 9 guidance. GALL-2 incorporates a lot of 10 information from MRP 227, the recommendations 11 that are in that report, but also some additional 12 items that the staff thinks is necessary for 13 applicants. There is no a GALL section for it.

14 DR. HISER: Yes, that is correct, and 15 after probably the current set of plants, we will 16 expect plants to come in with a GALL consistent 17 program. Once we finalize the SER for MRP 227, 18 we may modify the GALL program to be consistent 19 with the staff positions that come out of that 20 review. Jeff?

21 MR. POEHLER: Jeff Poehler, Materials 22 Engineer from the Vessel Integrity Branch, 23 Division of Component Integrity.

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84 1 internals inspection plans. We have accepted for 2 review quite a few of them. I can't tell you the 3 exact number. So it is basically waiting on the 4 SE for MRP 227 Rev 0, which is the basis for all 5 these inspection plans, which is supposed to be 6 issued in the next month or so.

7 DR. HISER: Is that the final SER?

8 MR. POEHLER: Correct.

9 MEMBER SHACK: So soon.

10 DR. HISER: But there will be a point 11 at which the commitment is no longer an 12 acceptable method to demonstrate aging management 13 for vessel internals. That answers my question.

14 Thank you.

15 MEMBER SHACK: That answers my 16 question. Thank you.

17 MR. FERRER: Getting back to the 18 presentation for today, I will begin with an 19 overview of the Diablo Canyon review, and I will 20 keep it brief, since this information was 21 previously discussed by the applicant.

22 We will then follow the basic 23 structure of the SER, covering topics of interest 24 and open items on each section. Greg Pick will 25 be presenting the license renewal regional NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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85 1 inspection, as Brian mentioned, and we will try 2 not to repeat all of the information that the 3 applicant has presented. We just intend to 4 ensure that you receive adequate information 5 associated with the staff's review and findings, 6 and as always, feel free to ask questions at 7 anytime.

8 This slide just provides the general 9 details of the license renewal application. The 10 applicant has previously covered all this. So 11 unless there are any questions, I will move on at 12 this time.

13 Staff review teams conducted audits 14 and inspections of the application during the 15 period shown on the slide. I will highlight that 16 issues raised and discussed during the scoping 17 and screening methodology audit led to two LRA 18 amendments related to scoping and screening 19 submitted in the summer of 2010.

20 They provided the applicant's 21 additional scoping and screening evaluations for 22 various plant systems, structures and components.

23 San Gardocki will be covering these topics in 24 more detail during the discussion of Section 2.

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86 1 Report and in addition to the audits and 2 inspections already mentioned, the staff 3 conducted in depth technical reviews. We issued 4 approximately 200 Requests for Additional 5 Information to which the applicant responded.

6 The SER was issued to the applicant on 7 January 10, 2011, and contains eight open items 8 and two confirmatory items. The first three open 9 items relate to scoping and screening, which Stan 10 will cover in his discussion of Section 2.

11 Two open items relate to aging 12 management programs. Allen Hiser will cover one, 13 and Bill Holston will be covering the other in 14 discussion of Section 3. The last three open 15 items relate to time limited aging analyses, and 16 Allen Hiser will be covering those in our 17 discussion of Section 4.

18 Two confirmatory items also relate to 19 aging management programs, and again we will 20 cover those in Section 3.

21 CHAIRMAN BLEY: Have you had time to 22 review the responses to these issues?

23 MR. FERRER: We have.

24 CHAIRMAN BLEY: So that is included?

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87 1 discussing those once we get into more detail on 2 each one.

3 Moving on to Section 2 of the SER.

4 This section concerns structures and components 5 subject to aging management review. The staff 6 has completed its review of scoping and screening 7 methodology and results, with the exception of 8 the open items mentioned earlier.

9 I will now hand it over to Stan 10 Gardocki to discuss the open items and other 11 items of interest from this section.

12 MR. GARDOCKI: Good afternoon. Stan 13 Gardocki. I work in the Balance of Plant 14 Section, Division of Safety Systems, as Senior 15 Reactor System Engineer. I have been involved 16 with the scoping of the plants, and I was on site 17 with the audit conducted in March.

18 The staff reviewed the applicant's 19 scoping and screening methodology and 20 implementation utilizing the resources in the 21 application, the drawings, and the staff 22 augmented that with a physical walkdown of the 23 plant systems during the scoping and screening 24 audit done in March of 2010.

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88 1 walked down selected non-safety areas where the 2 plant people identified where the applicant said 3 there was no or limited safety related 4 components. The staff focused mainly on non-5 safety related Turbine Building to verify whether 6 there was any additional safety related 7 components in this area.

8 The staff also walked down the safety 9 related areas, mainly the emergency diesel 10 generator rooms, the component cooling heat 11 exchanger room, and the auxiliary building, to 12 verify whether there were any unidentified non-13 safety related components in these areas that 14 could potentially adversely affect the safety 15 related components.

16 The staff identified several instances 17 where the applicant's scoping of these components 18 did not align with the proposed methodology.

19 In the non-safety related Turbine 20 Building, the staff identified additional safety 21 related components that did not have an adequate 22 evaluation or 10 CFR 54.4(a)(2) for potential 23 adverse effects from the failure of nearby non-24 safety related components.

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89 1 components identified in the Turbine Building 2 included control room pressurization system and 3 exhaust ducts for the switchgear HVAC system.

4 Additionally, the staff looked at the safety 5 related cables in the Turbine Building where the 6 applicant credited its mitigation of the conduit, 7 but that was only for the low and medium line 8 breaks, but they didn't evaluate for high energy 9 line breaks.

10 In the safety related areas, the staff 11 identified additional non-safety related 12 components in the vicinity of the safety related 13 components that did not have an adequate (a)(2) 14 evaluation. Some of these examples were inside 15 the Diesel Room and the component cooling heat 16 exchanger room. There were overhead drain lines, 17 and there was additional service water lines in 18 the diesel room.

19 Outside in the yard there were 20 underground vaults and electric pull boxes, which 21 the staff identified sumps and pumps that didn't 22 have an adequate (a)(2) evaluation.

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90 1 instances where the applicant did not include 2 into scope non-safety related piping that was 3 directly attached to safety related components 4 past the safety/non-safety related boundary up to 5 the first qualified anchor and, as the applicant 6 said, these were mostly in suppressed gas systems 7 to clean the air, and the nitrogen systems.

8 The staff also identified instances 9 where the applicant stopped its (a)(1) scoping at 10 the code class break on safety related piping at 11 an open valve. The failure of the downstream 12 piping could result in loss of the pressure 13 boundary of the safety related system.

14 One instance of this that was 15 mentioned is the EDG air start system where the 16 unloader line transitted back from the safety 17 related air receiver back to the non-safety 18 related air compressor.

19 After the site out was completed in 20 March of 2010, the staff issued about 17 RAIs to 21 the applicant. The applicant's preliminary 22 response indicated that additional systems 23 components, especially in the Turbine Building, 24 would have to be added to the scope of license 25 renewal. As Nate said, there were two responses, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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91 1 LER and maintenance.

2 Later, the applicant submitted the 3 changes to the application to include these 4 components in the scope of license renewal, and 5 after reviewing the additional material, the 6 staff was able to resolve all the issues except 7 for three open items identified in the SER.

8 The staff has received the applicant's 9 responses to these open items on January 12, 10 2011. The applicant has already described their 11 proposed resolutions. In conclusion, the staff 12 has reviewed those and their responses, and has 13 now the necessary information from the applicant 14 to satisfactorily resolve these three open items 15 in the final safety evaluation.

16 Do you have any questions on this 17 matter?

18 CHAIRMAN BLEY: I am just curious.

19 When staff does the walkdown you describe, would 20 you consider it a spot check or would you 21 consider it a thorough walkdown?

22 MR. GARDOCKI: We systematically look 23 at the application, look at areas of interest.

24 In this particular application, we looked at they 25 excluded the Turbine Building, and they said NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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92 1 there was nothing safety related in there. so we 2 would focus on something like that.

3 We always walkdown general areas where 4 we find deficiencies in the application, EDG 5 rooms, and we identified some --

6 CHAIRMAN BLEY: So the areas that drew 7 your interest, you did a pretty thorough 8 walkdown?

9 MR. GARDOCKI: Oh, absolutely, and you 10 can tell from the level of detail that we 11 identified quite a significant amount of 12 components.

13 DR. BARTON: What is your assessment 14 of the material condition of the parts of the 15 plant that you looked at in detail?

16 MR. GARDOCKI: The material condition 17 was very good. We walked down the aux building, 18 turbine buildings, and everything had a good coat 19 of paint. We didn't see any spalling or dirt 20 conditions. There were some areas we tried to 21 get around in the aux building to the back of the 22 containment to look at some penetrations, and we 23 just couldn't get to it. So --

24 MEMBER ARMIJO: In the SER there was a 25 mention of a removal of cracked coating on the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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93 1 liner, and it is a small area, but apparently 2 about two square feet were not re-coated after 3 this repair. I just wondered what the logic was 4 for that. Are you familiar with that?

5 MR. GARDOCKI: I cannot address that 6 matter.

7 MEMBER ARMIJO: Maybe the -- I will 8 read it to you: Defect areas were cleaned and 9 coated at the end of cycle 15, 1R15 and 2R15, 10 total of three square foot cluster; liner plate 11 coatings was found cracked and delaminated at the 12 185 foot and 195 foot elevations. The loose 13 coatings were removed without repair. Two square 14 feet of the three square foot area were left as 15 bare steel after cleaning. This area will 16 require continuous monitoring.

17 I agree with all of that, and I know 18 it is a small area, but I don't understand the 19 logic of not repairing it.

20 DR. HISER: I am not sure that we can 21 address why they didn't repair it.

22 MEMBER ARMIJO: Why does the staff 23 think that is okay?

24 DR. HISER: Well, from our 25 perspective, as long as they ensure that it NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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94 1 doesn't degrade, then we are -- As long as there 2 is aging management program in place to address 3 that and to monitor that, then I think we are 4 satisfied.

5 CHAIRMAN BLEY: I think Diablo Canyon 6 wanted to say something.

7 MEMBER ARMIJO: Does the applicant 8 have a response?

9 MR. WRIGHT: I will start off. This 10 is Mike Wright from Diablo. We do have an aging 11 management program for containment coatings.

12 There are -- Part of that program is to identify 13 all degraded coatings at the start of the outage, 14 and we have remedied as much as possible during 15 that refueling outage, and then we identify 16 coatings that would have to be subsequently re-17 coated in the following outage.

18 So that will be a remedy. It just 19 wasn't fixed at --

20 MEMBER ARMIJO: So it was just an 21 interim problem?

22 MR. WRIGHT: Yes, sir, that is 23 correct.

24 MEMBER ARMIJO: Oh, okay. I just 25 thought it was some experiment you were running NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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95 1 or something else, and up at that elevation it 2 may not be the most convenient place to repair 3 it. I don't know. Okay, you answered my 4 question.

5 MEMBER STETKAR: Staff, in the SER 6 there are statements like "the applicant applied 7 its evaluation of non-safety related SCs 8 inconsistently throughout the LRA." Quite 9 honestly, there are more RAIs issued and more 10 applicant responses to those RAIs regarding 11 scoping and screening than I have seen in the 12 last two or three years of license renewal 13 applications.

14 Since your walkdowns -- As you said, 15 the areas that you walk down are pretty thorough, 16 and those resulted in rather extensive RAIs that 17 were focused on the areas you looked at. But 18 since there are only selected areas, how do we 19 have confidence in the areas that you didn't 20 walkdown, that there aren't similar kind of 21 scoping and screening issues; and when you found 22 the relatively large number of issues, at least 23 by counting RAIs and looking at the responses to 24 those RAIs -- for example, in the Turbine 25 Building -- did you make any conscious effort to NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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96 1 expand the scope of your samples and audits and 2 walkdowns to inspect other areas to see whether 3 or not it simply was focused out in the Turbine 4 Building and that the scoping and screening of 5 (a)(2) type issues in other parts of the plant 6 had, in fact, been done?

7 MR. GARDOCKI: Okay, I will try it.

8 We looked for -- like if you got the aux 9 building, they say everything in the aux building 10 is in scope of license renewal.

11 MEMBER STETKAR: Okay, that is pretty 12 easy.

13 MR. GARDOCKI: So that was a pretty 14 easy area. So we go in there, and we walkdown 15 something just to make sure scoping values were 16 correct. We were trying to find some 17 penetrations of the makeup water system going 18 through there. We are limited to the 19 radiological areas, and we couldn't access 20 anymore than we could.

21 There was an area between -- Now the 22 areas that stand out is what we have tried to 23 focus on in this very limited time we were out 24 there, and between the aux building and Turbine 25 Building there is another building in between it.

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97 1 So we asked them, do you classify it 2 as the aux building or do you classify it as the 3 Turbine Building? So those are the areas we kind 4 of focus on and try to clarify that area: Do you 5 classify it as aux building? Everything in 6 scope. For the Turbine Building, nothing in 7 scope.

8 Then we refocus our review when we get 9 back to the office to see if there is anything in 10 that area that has particular interest. So we 11 follow to the main steam piping out there. We 12 asked some RAIs to clarify the boundaries on 13 those.

14 The Turbine Building, when they said 15 they excluded it initially, I mean, we focused 16 right on that area to see if there was anything 17 else in that area, and we found some safety 18 related in there. And if you didn't scope it 19 initially, you don't have any basis to evaluate 20 to. So we had to wait for that additional 21 scoping to come in.

22 Then we focused on the particular 23 lines they called conduit with safety related.

24 They said, well, we use the conduit for 25 mitigation, but then you didn't use it for all NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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98 1 mitigations. So then you had to scope the entire 2 Turbine Building for high pressure piping.

3 So there was a very substantial amount 4 of additional components put in scope after our 5 audit. So we focused our audits mainly on areas 6 where we would think we would find some problems, 7 based on previous audits where we find problems.

8 Then those areas that stand out, like here the 9 Turbine Building or that building between the aux 10 buildings, or if they have main steam piping and 11 feedwater piping that is routed outside of the 12 aux building to go into containment, we would 13 walk those particular areas down to see how they 14 are managed for aging management, or in scope.

15 MR. HOLIAN: This is Brian Holian. I 16 wanted to add to the question maybe and the 17 answer. On the question, it is a question we ask 18 during review, branch chief review and senior 19 management review of the SER for that purpose.

20 Staff -- We are still pushing the 21 staff. But when you ask an RAI on an item, get 22 that right, but ask the Part B to the RAI, which 23 is: We found this one or think we found this 24 one; give us some assurance that you have sampled 25 other areas or you have gone there.

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99 1 I think we are pretty good on doing 2 that in RAIs. Sometimes we don't also translate 3 that to the SER write-up that says that we kind 4 of asked that second part of the question or 5 during discussions, it had that.

6 So I don't see it all the time in the 7 SER write-up that we are asking the extent of 8 condition question of them to also do that. Stan 9 and -- you know, even in the past week sitting in 10 here, as I have looked back this year -- kind of 11 reiterated that some of those items -- you know, 12 the very specific ones, caused other issues to be 13 found by them as part of that extended condition.

14 So a lot of the detail items came out 15 of that type of questioning, but I agree with you 16 that the staff can be even more overt in 17 translating it into the SER. I have told them to 18 tell the story a bit better about what did you 19 find, and then what did the applicant have to do.

20 MEMBER STETKAR: That helps. Thanks, 21 Brian, because the way I read the SER is there 22 was a large number of individually identified, as 23 you said, focused items, a large number of which 24 were resolved by very focused responses of a 25 handful or whatever, which are still being NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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100 1 discussed, and then there is the overall 2 conclusion that says, with the exception of this 3 handful, everything is fine.

4 MR. HOLIAN: That is right, and it 5 leaves out the in between. Why did the staff 6 have a good feeling that we didn't need to go do 7 a second audit. But we ask ourselves those 8 questions.

9 MEMBER STETKAR: Thank you.

10 DR. BARTON: Along those same lines, 11 in the SER it talks about the external surface 12 monitoring program, and the inspection team noted 13 that the training program for the personnel 14 performing these inspections did not meet the 15 commitment the applicant made for training. So I 16 wonder if the people that the applicant had out 17 there doing external surfaces monitoring weren't 18 probably trained.

19 How was this ever resolved? Did these 20 guys get requalified? Did you guys go look at 21 that?

22 MR. PICK: As an inspection team, 23 during our interviews the system engineers and 24 the people doing aging management -- they had a 25 lot of criteria for what was aging management, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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101 1 but they weren't comfortable that they had enough 2 background. They were using common sense and 3 their procedures, which were quite good, and they 4 all commented to the external surfaces program 5 reviewer that they would like more training.

6 When we brought that to the 7 applicant's attention, they went and did their 8 own survey, and I will let them respond to what 9 they found.

10 MR. WRIGHT: This is Mike Wright from 11 Diablo. We agreed with the Region IV inspection 12 team. We have committed to doing extensive 13 training for all system engineers prior to the 14 December of this year to close the gap on 15 training, and for sustainability, include that 16 training as part of the qualification for system 17 engineers.

18 DR. BARTON: Thank you.

19 MR. GARDOCKI: Well, if there's no 20 more further questions, that concludes my 21 presentation.

22 MR. FERRER: Thank you, Stan. I would 23 like to highlight just one item on open item 24 2.3.3.14-1. The topic of this item actually 25 became an inspection finding, as documented in an NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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102 1 inspection report dated September 9, 2010.

2 I just highlight that, because just to 3 show sometimes when we are doing the license 4 renewal reviews, we find things that we can pass 5 on to regional staff or residents in current 6 operating space.

7 With that, I would pass it on to Greg 8 Pick from Region IV.

9 MR. PICK: Thanks, Nate. Good 10 afternoon, members of the ACRS Committee.

11 I led the inspection team, and we 12 conducted an extensive review using one of our 13 most experienced teams. The six inspectors 14 shared 170 years of inspection experience. We 15 looked at 60 percent of the aging management 16 programs, instead of the nominal 40 to 50 17 percent.

18 We reviewed 24 of the 40 aging 19 management programs that were in existence at 20 that time, and this included six of the nine new 21 aging management programs.

22 We evaluated whether the applicant 23 properly scoped non-safety related structures, 24 systems and components that could affect safety 25 related structures, systems and components, and NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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103 1 whether they developed aging management programs 2 consistent with the GALL report.

3 We focused on the conditions that 4 existed at the plant and how the applicant 5 implemented their existing programs that were 6 going to be aging management programs, and their 7 plans for implementing their new aging management 8 programs.

9 We also performed a vertical slice 10 evaluation of three systems to assess whether the 11 identified aging management programs could be 12 expected to effectively manage the effects of 13 aging.

14 We also looked at the applicant's 15 treatment of latest industry aging issues and 16 several site specific issues. Next slide.

17 During our reviews, we looked at the 18 conditions of the structures, systems and 19 components needed to withstand a seismic event.

20 These included the supports and restraints, the 21 applicant's program for evaluating the effects of 22 non-safety related equipment affecting safety 23 related equipment and their Class 2 equipment, an 24 the structural inspector also considered the 25 seismic design in his review of the walls -- the NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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104 1 design information.

2 We looked at the buried pipe program 3 with a focus on environmental monitoring. We 4 looked at inaccessible medium voltage cables, 5 because the plant had documented aging experience 6 problems with those cables, and we looked at 7 their metal enclosed bus program because they had 8 experienced bus part failures in their past.

9 Next slide.

10 Related to scoping, when we arrived on 11 site the applicant was in the process of 12 incorporating lessons learned related to scoping 13 from a previous STARS plant, similar to the 14 scoping team.

15 IN addition, I had talked with Stan in 16 detail prior to going to the site to see how I 17 might assist him in getting eyes on some of the 18 requests for additional information responses and 19 verify the information being provided.

20 The items that we assisted 21 headquarters reviewers in resolving included: We 22 verified the configuration of non-safety related 23 service water cooling piping that went into the 24 room; we verified that no safety related electric 25 cables were present in the oily waste sump room.

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105 1 We verified that the water spray from 2 a service cooling water pump in the Turbine 3 Building would not have affected the control room 4 pressurization system components. We verified 5 the physical configurations reflected in their 6 Turbine Building reviews, that in fact the cables 7 were in conduits, the safety related cables for 8 the high energy line break.

9 During our vertical slice review of 10 the compressed air system, we identified examples 11 of items that had not been considered for aging 12 management.

13 The unloader valves for the diesel 14 generator air compressors -- they were made of 15 two materials, stainless steel and copper, and we 16 asked how they monitored for aging effects.

17 Well, they did, in fact. They have a five-year 18 PM, and they have a line item to look for 19 evidence of corrosion when they do that five-year 20 PM. But they had not included it in their 21 evaluation in their license renewal application.

22 So they updated that.

23 The other one was they had flexible 24 hoses attached to their back-up nitrogen bottles.

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106 1 drawings when, in fact, it was flexible hoses, 2 and they put that in a 10-year PM.

3 In regard to the aging management 4 programs, we already discussed that training was 5 required for the system engineers. We also 6 discussed the one instance related to age related 7 degradation of the silicon seal for the abandoned 8 containment screening stage cover plate, which 9 allowed rain to enter the metal box.

10 We identified this through review of 11 test reports where they did a containment 12 integrated leak rate test in the inspections.

13 They took photographs of the abnormal conditions 14 and had it included as part of the report. So we 15 asked, what are you doing as far as aging 16 management of this, and they have agreed to 17 monitor it, seal them, and then eventually 18 perform a plant modification to seal the metal 19 boxes.

20 For the inaccessible medium voltage 21 cables in the cable vaults, they were routed on 22 supports. They didn't have any criteria when we 23 were on site for looking at the support 24 structures for the cables. So they issued a 25 corrective action document to add that to their NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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107 1 structures monitoring program anytime the vaults 2 are opened.

3 MEMBER STETKAR: Greg, when you did 4 the inspection -- I don't have my notes here 5 complete -- did you actually look in some of 6 those?

7 MR. PICK: We did not look in the 8 vaults.

9 MEMBER STETKAR: Didn't look in any of 10 them?

11 MR. PICK: But we gave the residents 12 criteria, and they agreed to look in the vaults.

13 MEMBER STETKAR: But you didn't 14 actually?

15 MR. PICK: But we did not put eyes on 16 them, no.

17 MEMBER ABDEL-KHALIk: What is the span 18 over which the cables were supported?

19 MR. PICK: It appeared to be about 20 four feet. I am not sure. But the droop based 21 on the span couldn't be anymore than 12 inches.

22 The electrical inspector determined that.

23 The last one, the location selected 24 for fouling: For the closed cooling water 25 inspection criteria, they selected two valves to NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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108 1 look for fouling, because we already had a PM 2 when they opened it.

3 We asked the question, is that a low 4 flow area, because when you read all their 5 experience, they were about closing in the low 6 flow areas. They wrote a notification, took a 7 look, discovered it is not a low flow area. So 8 they are looking for alternate locations as a 9 result of it being in their corrective action 10 program.

11 We also found a couple of minor 12 procedure issues. With their heat exchanger 13 program, right now Generic Letter 13 allows you 14 to do maintenance and did not require heat 15 exchanger testing, but their license renewal 16 application said we will do heat exchanger 17 testing.

18 Their procedure said it was prudent.

19 Well, the fixes are going to take out the option 20 of it being a prudent test, and it is now a 21 required test.

22 The second one was they do predictive 23 maintenance thermography of their metal enclosed 24 bus stops. Well, predictive maintenance isn't 25 required. It is something that they do, but NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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109 1 again the license renewal application said we 2 will do this as our way of monitoring aging. So 3 they now have to keep them as records. They are 4 required, versus being an option of keeping those 5 records.

6 DR. BARTON: Don't most people do that 7 anyhow?

8 MR.PICK: They do the thermography for 9 other plants. I can't answer whether they keep 10 them as quality records. That is why it is 11 minor. They might keep the record, but they are 12 not required to.

13 DR. BARTON: I got you.

14 MR. PICK: Next slide. Overall, we 15 also found that the plant had good material 16 condition. We would go in one of the diesel fuel 17 vaults. Didn't find any issues with that.

18 The applicant had developed procedures 19 for many programs, and it had initiated plans to 20 incorporate aging management evaluations into 21 their day to day activities.

22 They are developing a long term plan 23 that looks to be implemented over the next 24 several years. By the time they get to the 25 period of extended operations, it will just be NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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110 1 part of their routine way of doing business, and 2 the procedures were drafted when we were there.

3 So as inspectors, we had lots of information to 4 review where we could make decisions and comment 5 on whether we thought it would do -- the 6 procedure would accomplish what was expected of 7 it.

8 They already identified that they had 9 replaced several major components, and 10 essentially resets the clock on aging. And you 11 already discussed the intake structure. They 12 also replaced some high voltage insulators on 13 their station blackout lines. Yes, sir?

14 MEMBER SIEBER: What was the reason 15 that they replaced insulators? Was it -- Some 16 insulators have manufacturing --

17 MR. PICK: I do not -- It may have 18 been cracking, but I do not recall.

19 MEMBER SIEBER: Another thing is that 20 plants that are located at salt water collect 21 salt on the insulators.

22 MR. PICK: I know they do. They do 23 spray on their insulators, but I believe they --

24 MEMBER SIEBER: I would sure like to 25 know what steps you go through periodically to NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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111 1 make sure the insulators are not building up salt 2 and capable of flashovers.

3 MR. GORYANCE: My name is Joe 4 Goryance, Diablo Canyon License Renewal, 5R kV, 5 230 kV system engineer and supervisor.

6 Our program is based on General Order 7 95, which is a California order. We have to, by 8 California law, inspect our insulators. Based on 9 our local climate, we have -- We are at a high 10 salt spray area, being close to the ocean, high 11 winds. So we have an inspection program for 12 that.

13 For our 5R kV insulators, we do a hot 14 wash every six weeks. Based on rainfall, we can 15 defer that if we get one inch of rain in a 24-16 hour period. So that is our program.

17 During the inspection part, we noticed 18 that we started having some rust. The 19 galvanizing on porcelain insulators was starting 20 to show signs of rust. So then we replaced that 21 string of insulators on the 5R kV system, and our 22 230 kVs also have been replaced.

23 MEMBER SIEBER: Thank you.

24 MEMBER ABDEL-KHALIK: You mentioned 25 you do hot wash on the 500 kV, and that is what I NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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112 1 read in the report. I didn't hear anything about 2 hot washing the 230 kV. Do you do that?

3 MR. GORYANCE: Our 230 kV are polymer 4 insulators. They are not porcelain. So we can't 5 wash those. The polymer types have a better 6 creepage distance. So they are not required.

7 MEMBER ABDEL-KHALIK: Thanks.

8 MR. PICK: Thank you. The scoping of 9 -- Our overall conclusions from the inspection:

10 The scoping of non-safety structures, systems and 11 components and the application of the aging 12 management programs to those structures, systems 13 and components were acceptable.

14 Applicant personnel had incorporated 15 actions to manage their aging effects into their 16 programs, and reasonable assurance exists that 17 aging effects will be managed and intended 18 functions maintained.

19 With that, I am going to turn this 20 back over to Nate, unless there are any 21 additional questions.

22 MEMBER STETKAR: Yes, Greg. Since I 23 beat up the applicant, I might as well beat you 24 up. The inspection report says the team 25 determined that the applicant had recently NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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113 1 upgraded the cathodic protection system and 2 programs.

3 Words like recently always send a flag 4 forme, especially because your inspection was 5 done in 2010. What does that phrase mean, since 6 you guys did the inspection? Was the recent 7 upgrade the actual 1995 installation, 15 years 8 before you did the inspection?

9 MR. PICK: I do not know the exact 10 time frame reflected in that phrase.

11 MEMBER STETKAR: You want to ask 12 Diablo. You heard the answer that, well, they 13 installed it in 1995, and its current reliability 14 is 90 percent or better or whatever the 15 requirements are. But this seems to imply that 16 the inspection team discovered something that had 17 been done, quote, "recently," which implies that, 18 before recently, whenever that was, it wasn't so 19 good.

20 DR. BARTON: Depends what you timing 21 is. Is 15 years recent?

22 MEMBER STETKAR: Yes, recent in 23 geologic time perhaps.

24 MR. HOLIAN: Bill, do you want to 25 answer?

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114 1 MR. HOLSTON: Yes. I was just waiting 2 for the discussion. Yes, the applicant had noted 3 corrosion in their aux salt water system that was 4 down in the lower basin. So in that mid-late 5 Nineties, they bypassed a whole lot of that 6 piping, put new piping in, upgraded the cathodic 7 protection system to ensure that they would 8 protect the newly installed piping.

9 There were some other modifications, 10 too. They had some corrosion of diesel fuel 11 piping. Now instead of cathodically protecting 12 that, they replaced that diesel fuel piping and 13 ran it in underground vaults. So now it is 14 exposed to air. So that is what they have done.

15 Currently, their cathodic protection 16 system is available greater than 90 percent of 17 the time. They conduct annual NACE testing to 18 ensure that the system is effective by measuring 19 the pipe-to-soil potentials.

20 MEMBER STETKAR: Right. I read and 21 heard, and I understand all of that. The 22 question, I guess, then is still: Is 1995 the 23 recent upgrade, and indeed has the cathodic 24 protection system, if that is the recent upgrade, 25 been available 90 percent of the time or better NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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115 1 since 1995 then?

2 MR. HOLSTON: That is my 3 understanding. Yes, sir. And that is from 4 talking to the applicant, working through the 5 request for additional information. I am not 6 aware of any period of time where, once they put 7 the new cathodic protection system in, which 8 again was mid- kind of like '95-'96 or it might 9 have been '94, that they had a period where it 10 went out of effective monitoring.

11 MEMBER STETKAR: I am just triggering 12 on the word recently, you know. That, to me, 13 implies maybe in the last year or two rather than 14 15 years ago. So, thanks.

15 I actually know how some of the people 16 prepare for the license renewal applications, and 17 recent sometimes means six months ago. Thanks.

18 MR. PICK: Any other questions?

19 MR. FERRER: Thanks, Greg. I will now 20 move on to Section 3, Aging Management Review 21 results.

22 Section 3.0 covers the staff's review 23 of the applicant's aging management programs. I 24 will just note that the open and confirmatory 25 items in Section 3 are all discussed in this NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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116 1 section.

2 Sections 3.1 through 3.6 cover aging 3 management review items, and each of the systems 4 within the scope of license renewal. For a given 5 aging management review, the staff reviewed the 6 items to determine whether it was consistent with 7 the GALL report and, if an aging management 8 review is not consistent, then the staff 9 conducted a technical review to ensure adequacy.

10 As the applicant previously stated, 11 they submitted 42 aging management programs, and 12 there were approximately 3,000 aging management 13 review items. Of the 42 aging management 14 programs, 31 were existing, nine are new, and two 15 plant specific.

16 As I noted earlier, there are two open 17 items related to aging management programs.

18 Allen Hiser will discuss the open item related to 19 the flux thimble tube inspection program at this 20 time.

21 DR. HISER: Thanks, Nate. The flux 22 thimble tube inspection program is a GALL 23 program. During the staff's review, the one item 24 that really stuck out to us was the operating 25 experience at Diablo Canyon.

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117 1 I don't want to rehash much of what 2 the applicant provided earlier, but a lot of the 3 RAIs in the open item relate back to that 4 finding. The one area I guess I did want to 5 highlight was the concern that the staff has that 6 the wear rate projection methodology employed by 7 the applicant may be nonconservative.

8 So it may not give conservative 9 estimates of wear that would be measured after 10 the current operating cycle, and that is one area 11 that we still have the open item that we will 12 review applicant's response to, and we will reach 13 a determination on the acceptability of the 14 program based on that review.

15 MEMBER STETKAR: Allen, the way at 16 least I read the SER, the concern seemed to be 17 focused on the thinning threshold, and I was 18 under the impression it was different from what 19 Diablo said, that they are using 68 percent 20 rather than 80 percent.

21 What is the real concern? Is it the 22 methodology on how they project the rate or that 23 actual acceptance criterion -- the staff's 24 concern.

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118 1 of all pieces. The project methodology does not 2 incorporate explicit uncertainty considerations.

3 MEMBER STETKAR: Let me ask you then 4 what is different in Diablo's methodology 5 compared to other previously approved license 6 renewal applications that indeed have used an 80 7 percent thinning acceptance criterion?

8 DR. HISER: Jim Medoff is here.

9 MEMBER STETKAR: Is their methodology 10 different?

11 DR. HISER: The main reviewer on a lot 12 of this.

13 MR. MEDOFF: This is Jim Medoff of the 14 staff. I was the peer reviewer for the flux 15 thimble tube inspection program for Diablo 16 Canyon.

17 The big difference is some of the 18 other applicants have adopted the WCAP 12866 19 methodology. So their acceptance criteria is set 20 to 80 percent on that basis, and then the 21 Westinghouse methodology included uncertainty to 22 derive that 80 percent through-wall wear 23 acceptance criteria.

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119 1 refers to a different Westinghouse plant specific 2 calculation for them, and that calculation set 3 the acceptable wear criterion to 68 percent 4 through wall, including uncertainty.

5 Then later on, the applicant had done 6 a 50.59 to that Westinghouse methodology to 7 remove the uncertainty based on a comparison to 8 the WCAP methodology, even though it is not 9 really part of their licensing basis.

10 CHAIRMAN BLEY: Compared to the new 11 WCAP methodology?

12 MR. MEDOFF: Yes. Yes. So that is 13 what we are trying to figure out, whether that is 14 an acceptable basis or not, and we are looking 15 that over.

16 The other matter is the wear 17 projections, including whether it should have 18 uncertainties in it, and to figure out whether 19 the way they do wear projection is conservative.

20 Their current program does wear projections on a 21 linear basis, but some of the wear history that 22 we have audited for the program may indicate that 23 they are getting some non-linear wear, and we are 24 wondering whether the linear basis is 25 conservative at this point.

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120 1 They have given us access to some non-2 docketed information that we are doing sort of an 3 informal audit of now to see whether we can 4 accept their projected basis. So it is under 5 review right now.

6 MEMBER STETKAR: Is that non-linear 7 wear history specifically focused on that L-3 8 flux thimble tube?

9 MR. MEDOFF: I think there are two 10 others that may have non-linear basis, and that 11 is why we are checking the data right now.

12 MEMBER STETKAR: I will tell you, I 13 plotted out the actual wear history on that tube 14 and, although it is not a perfectly straight 15 line, it is pretty doggone close to a straight 16 line. So a linear projection didn't look too bad 17 to me at least -- well, and the four years of 18 data they had.

19 DR. HISER: But those are three 20 different areas that have worn. It is not the 21 same area.

22 MR. MEDOFF: And the other thing is 23 that the one outage that they had some wear, they 24 have not stated in their slide projection. They 25 had replaced that tube in outage 10, and they had NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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121 1 a certain amount of wear in outage 11. They 2 didn't do any corrective action, because it was 3 so low, and then the subsequent outage, they 4 found even more wear. So it went from like 16 5 percent up to somewhere in the thirties or 6 forties. Then they repositioned the first time.

7 DR. HISER: And then it went up to 8 about 46 percent in the third year, which is 9 another 16 percent.

10 MR. MEDOFF: So this tube was a real 11 anomaly, I think, for the facility. We are 12 looking at some of the other tube data to see if 13 this is happening in other tubs.

14 MEMBER STETKAR: My only concern in 15 terms of consistency in these reviews is that I 16 recognize they had a failure which was an 17 anomaly. You wouldn't have expected a failure 18 after that short a period of time.

19 I hope the staff is not overreacting 20 to that singular event and applying consistent 21 criteria for these programs across the entire 22 fleet, because the small sample that I took 23 seemed to be -- Now I am not familiar with the 24 actual detailed methods. There may be some 25 subtleties in the methods that they are using NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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122 1 that is the concern, because the way I read the 2 SER, it was strictly on the acceptance criterion, 3 whether or not you have applied uncertainties on 4 it. To me, a 68 percent wear without uncertainty 5 probably adequately applies -- you know, covers 6 uncertainty up to an 80 percent that probably 7 does include uncertainties.

8 DR. HISER: Yes. I guess the one 9 concern was the inconsistency within their 10 procedures. The procedure referred to a 11 calculation that said 68 percent, and included 10 12 percent uncertainty. They were not including the 13 10 percent uncertainty, and that basis was what 14 we were seeking.

15 MEMBER STETKAR: So you would have 16 expected them to use 58 percent?

17 DR. HISER: Well, that is what their 18 calculation would have indicated, that that is 19 what they should have used.

20 MEMBER STETKAR: Well, had you earlier 21 looked at the 59.59 that, I think, I heard 22 changed that?

23 DR. HISER: No.

24 MR. MEDOFF: No, and we may -- It is 25 still an open item. We may accept their basis, NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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123 1 but it is under review, at least on the 2 uncertainty. The projection -- The wear 3 projection methodology is something we are going 4 to have to look in a little bit deeper, based on 5 the inspection data that they have given us 6 access to.

7 DR. HISER: I didn't mean to indicate 8 that we overreacted to the one tube that leaked, 9 but we do want to understand from their 10 comprehensive data whether their wear projection 11 methodology is conservative of nonconservative, 12 and just to ensure that they do get conservative 13 projections.

14 MEMBER ABDEL-KHALIK: Now you stated 15 that this is unusual OE. If that is the case, 16 and if the cause is flow induced wear, has the 17 staff asked what would be the possible 18 implication beyond just the impact on wear of the 19 flux thimble tubes?

20 The example would be does that mean 21 that the lower plenum anomaly in this particular 22 plant may be much more severe than what is 23 predicted by the scaled experiments performed by 24 Westinghouse, so that there may be an impact on 25 core design calculations?

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124 1 MR. MEDOFF: May I address that, 2 Allen? One of the reasons the GALL program is 3 written the way it is, is back for a previous 4 application they did apply the Westinghouse --

5 they were applying the Westinghouse methodology, 6 and I reminded the applicant that the bulletin 7 has directed that you are supposed to use your 8 own plant specific data in coming up with your 9 wear projections and setting your acceptance 10 criteria.

11 MEMBER ABDEL-KHALIK: I think that you 12 and I are talking about different Westinghouse 13 data.

14 DR. HISER: Let me take a crack at 15 that. The excessive accelerated wear in this 16 thimble tube, the applicant has indicated through 17 their failure analysis was due to the tube being 18 repositioned outside of the chrome band, and I 19 think that is the cause of the failure.

20 I am not aware that any lower plenum 21 anomaly would have impacted that. Since that 22 tube was capped, as far as we know, there has not 23 been any other excessive wear locations 24 identified.

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125 1 localized phenomenon.

2 DR. HISER: Yes.

3 MEMBER ABDEL-KHALIK: So if that is 4 the case, could be some sub-assemblies that would 5 be relatively starred for flow at the inlet to 6 the core?

7 DR. HISER: I am not that familiar 8 with the thermal hydraulics.

9 ME. MEDOFF: Yes. To get into that, 10 we would have to go back to some of the guys at 11 Division of Systems here at DSS and talk to them 12 about that.

13 MEMBER ABDEL-KHALIK: You promised to 14 give us some information later on. so we will 15 wait for you information then.

16 MR. MEDOFF: He has that information 17 now.

18 MEMBER ABDEL-KHALIK: You do? Well, 19 thank you. Please.

20 CHAIRMAN BLEY: We will let Diablo 21 Canyon tell it.

22 MR. MAYER: My name is Mark Mayer. We 23 checked back with our people back at the plant, 24 and we have had an evaluation performed by 25 Westinghouse, and the conclusion was that our NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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126 1 internals are not susceptible to the phenomenon 2 known in the industry as lower plenum anomaly.

3 What we do have is a fair amount of 4 cross-flow like at the entrance of the core, 5 which does result in some excitation of the flux 6 thimble tubes.

7 MEMBER ABDEL-KHALIK: And that would 8 be the cause of the wear?

9 MR. MAYER: That is correct. Going 10 back to your other half of your question, the 11 indications that we would see for lower plenum 12 anomaly would be a combination of sudden changes 13 in core exit thermocouple indications in 14 conjunction with step changes in the indicated 15 RCS flow.

16 MEMBER ABDEL-KHALIK: You could 17 resolve lower plenum anomaly with core exit 18 thermocouples?

19 MR. MAYER: They correlate.

20 MEMBER ABDEL-KHALIK: Thank you.

21 CHAIRMAN BLEY: Said, you accept that, 22 do you?

23 MEMBER ABDEL-KHALIK: No, I don't, but 24 it is not important to this.

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127 1 questions, we will move on. Bill Holston will be 2 discussing the buried piping and tanks inspection 3 program open item.

4 MR. HOLSTON: So we discussed some of 5 this in standard pieces throughout the 6 presentation, but to summarize it all, without 7 going through how the applicant adjusted their 8 program based on recent operating experience, 9 they have confirmed that their backfill won't 10 damage coatings or the piping.

11 Steel piping is coated. The soil 12 conditions are acceptable for no coatings on 13 their stainless, their copper, and their asbestos 14 concrete pipe.

15 We have already discussed that they 16 have cathodically protected the steel piping, 17 with the exception of 40 feet of the salt water 18 piping. That is going to be cathodically 19 protected by the period of extended operation 20 and, given that it is not currently cathodically 21 protected, they are augmenting their number of 22 inspections from one to four for that system 23 until it is cathodically protected.

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128 1 two over the 30-year period, to 12 inspections.

2 The two items that were still open at 3 the time of the SER, we have talked about, and 4 that was the resolution of where the copper 5 valves in scope are not copper alloy, the bronze 6 valves, and the steel piping that was in the 7 makeup system that was buried, and the applicant 8 talked about how they changed their isolation 9 point and less their boundary of the license 10 renewal such that the steel piping was no longer 11 in scope. They appropriately modified their 12 operating procedures to use that as a boundary 13 valve. Are there any other questions?

14 MEMBER STETKAR: Yes. Simple. I 15 couldn't follow all the bits and pieces. So let 16 me just ask you: Rev 2 of the GALL report has 17 fairly detailed tabulations of the number of 18 inspections and the types of inspections as a 19 function of all of the different parameters you 20 have mentioned, backfill, cathodic protection 21 type of pipe, etcetera, etcetera.

22 With the exception of the current 23 issues that are under discussion, is Diablo's 24 proposed inspection program consistent with those 25 recommendations?

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129 1 MR. HOLSTON: Yes, sir, it is. And 2 including the 40 feet of piping that is not 3 cathodically protected.

4 MEMBER STETKAR: I just couldn't -- I 5 didn't know the piping lengths. Fine. That is 6 all. Yes is a good answer. Thank you.

7 MR. FERRER: Thanks, Bill. I will now 8 cover the two confirmatory items. Confirmatory 9 item 3.0.3.2.14-1 relates to the inaccessible 10 medium-voltage cables not subject to 10 CFR 11 50.49, Environmental Qualification Requirements 12 Program.

13 The staff requested additional 14 information on how the program would account for 15 recent operating experience. In is response, as 16 the applicant stated previously, they increased 17 the scope of the program, removed the significant 18 voltage screening criteria, and increased their 19 manhole inspections to one year.

20 The staff had identified that we 21 needed clarification on the applicant's 22 justification for not performing the event-driven 23 inspections as well as the use of the 10-year 24 testing frequency, and since then the applicant 25 has, as they stated, submitted a response by NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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130 1 letter dated January 7th. They have provided the 2 additional details, and the staff believes we 3 will be able to close it.

4 Are there any additional questions on 5 this?

6 The structures monitoring program 7 confirmatory item: Again, to recap a little bit, 8 the staff noted that the Unit 2 spent fuel pool 9 has the persistent but minor leakage. As part of 10 the response, the applicant clarified that the 11 leakage is contained within the leak chase 12 system, and that they were inspected in March 13 2010 and were not blocked.

14 Then they initially committed to 15 perform that follow-up inspection, and our 16 concern was about the timing. They have since 17 then submitted their commitment to perform the 18 inspection one year to prior to entering the 19 period of extended operation. So the staff 20 believes it will be able to close this item as 21 well.

22 Are there any questions on that?

23 DR. BARTON: The structures 24 monitoring: Is there any example of exterior 25 containment cracking at the site?

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131 1 MR. FERRER: Abdul Sheikh can speak to 2 that.

3 MR. SHEIKH: This is Abdul Sheikh on 4 the NRC staff. When we did the audit, we looked 5 at this closely, and the first thing we noticed 6 was the applicant's program for inspection, and 7 we found that they were inspecting the concrete 8 every 10 years instead of the requirement of five 9 years. So we discussed this with the applicant, 10 and the applicant has changed their procedures, 11 and they are inspecting every five years.

12 Then we looked at their criteria for 13 inspection on how they record the degradation of 14 concrete, and we found that it was not consistent 15 with the industry criteria, which is ACI-349. So 16 we asked the applicant about it, and applicant 17 has agreed to change their procedures to inspect 18 it according to the industry criteria.

19 Then we asked them to look at all the 20 discrepancies they have for spalling and 21 degradation in concrete which they have recorded 22 based on the new criteria, and their engineers 23 have looked at it and found all of them are 24 accepted within the criteria.

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132 1 bring that is, in the SER Structures Monitoring 2 Program, the operating experience section of that 3 describes instance of concrete delamination, 4 spalling exterior containment, corrosion of 5 containment and liner, cracking at Turbine 6 Building concrete piers to the turbine pedestal, 7 and conditions of the concrete intake structure.

8 I guess my overall question is: Does 9 the staff feel that the applicant has got all 10 this under control or is the plant crumbling 11 around it?

12 MR. PICK: During our on-site 13 inspection, looking at that same inspection 14 report where we noticed the strain gauge boxes, 15 there were also photographs of cracks on the 16 exterior of the containment, but they were --

17 Many of them did not have a gauge to figure out 18 how wide they were, but a couple of them showed a 19 pop-out the size of an eighth of an inch.

20 So there is some small cracking on the 21 exterior of the containment. But the answer of 22 the concern of whether it is falling down around 23 us, the staff felt that the material condition of 24 the areas that we reviewed looked good.

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133 1 describes a lot of misery in inspector concrete 2 cracks and stuff like that, not just in the 3 containment but turbine piers at a pedestal and 4 stuff like that. So just wonder whether you guys 5 looked at all that and you've got some concern 6 about those areas, or not. That is all I am 7 asking.

8 MR. PICK: Our structural inspector 9 also looked at the base of many of the tanks, 10 even up to the raw water ponds. Basically, 11 everywhere that he could physically walk and 12 access, he did, and he reported back that he did 13 not have any concerns with the concrete.

14 MR. FERRER: Any other questions? We 15 will now move on to SER Section 4, which contains 16 the staff's review of time-limited aging 17 analyses. In this section, we will focus mainly 18 on the three open items and any additional items 19 of interest.

20 Section 4.2 of the SER documents the 21 staff's review of the reactor vessel neutron 22 embrittlement time limited aging analyses. With 23 regard to the pressurized thermal shock, Diablo 24 Canyon has one insensible weld not meeting the 10 25 CFR 50.61 pressurized thermal shock screening NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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134 1 criteria, and this slide provides the information 2 on the Unit 1 lower shell longitudinal weld noted 3 up there.

4 The applicant stated that it would 5 either implement 10 CFR 50.61(a) at least three 6 years prior to exceeding the PTS screening 7 criteria or, if it cannot meet that, it would 8 implement alternate options, such as flux 9 reduction.

10 So unless there are any questions, 11 Allen Hiser will now discuss the three open 12 items.

13 MEMBER SHACK: Is this the first time 14 that they have asked for 50.61(a)?

15 DR. HISER: I believe it is the first 16 time any applicant has asked for it.

17 MEMBER SHACK: Has Beaver Valley come 18 back? I mean, they had sort of committed to 19 something like flux reduction. Right?

20 DR. HISER: I am not sure what their 21 measures are. Within the 54.21(c)(iii) EV 22 management, they have a variety of options that 23 they could implement.

24 MEMBER SHACK: But they haven't come 25 back for them?

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135 1 DR. HISER: No, I don't believe so at 2 this point. And, generally, they would have 3 flexibility within the PTS rule, for example, to 4 wait until three years before they would exceed 5 the PTS screening criteria before they would have 6 to identify to the staff additional actions that 7 they were going to take.

8 During the staff's review of Section 4 9 on time-limited aging analyses, the staff 10 identified two TLAAs that the applicant had 11 indicated that there was no TLAA, the first area 12 on reactor coolant pressure boundary valves.

13 The staff routinely reviews the 14 application and the design codes that are cited 15 in the application to ensure that there are no 16 TLAAs that relate to those analyses. In the case 17 of this application, there was insufficient 18 information for the staff to do that review, and 19 at this point that is still an open item.

20 We have received a response, but we 21 have not completed our review of that response.

22 On the baffle and former bolts, there 23 is an existing ASME Section 3 cumulative usage 24 factor calculation on fatigue. The applicant 25 indicated that that was not a TLAA, because they NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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136 1 would be providing aging management using MRP-227 2 inspection criteria.

3 Although that is technically one way 4 to manage fatigue, it is not consistent with the 5 Section 3 requirements that you maintain your 6 design basis and maintain a cumulative usage 7 factor. The applicant has provided a response, 8 and again we are evaluating the acceptability of 9 that response.

10 If we move to the next slide, metal 11 fatigue is another area where the staff 12 identified the need for additional information.

13 Even after reviewing that additional information, 14 we ended up with an open item, 4.3-1. It had 15 several parts to it.

16 We have binned those, as indicated 17 here, under cycle counting, environmentally 18 assisted fatigue, and cumulative usage factors.

19 I believe the applicant did a fairly thorough 20 review of the various pieces of this open item.

21 So I don't want to go into anymore detail than 22 that.

23 We have received the open item RAI 24 response, and we are still reviewing that.

25 If there are no other questions?

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137 1 MEMBER STETKAR: Yes. Let me ask you 2 about cycle counting, because I got a chance to 3 ask Diablo. In the SER, Diablo used some sort of 4 methodology to infer the number of feedwater 5 cycle events, I guess, going to hot shutdown or 6 at hot shutdown transients based on the number of 7 pressurizer heat-up events. So there was some 8 sort of inferred correlation there.

9 I didn't quite understand how they did 10 that, because when I -- this again is a 11 consistency issue, because when I project the 12 number of pressurizer heat-ups using the 13 correlation that I thought they did, I come up 14 with a different number of projected feedwater 15 transients. So I am not quite sure what they 16 did. Do I care? Yeah, I do, for consistency.

17 They are well in the margin, but I 18 like consistent numbers. However, I noted in the 19 SER it says the staff also independently 20 confirmed that the applicant's basis yields a 21 projected feedwater cycling event value of 685 22 events for Unit 1 -- yada, yada, yada.

23 In a separate paragraph, the staff has 24 independently calculated the number of feedwater 25 initiating events to be 685 initiations. Well, I NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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138 1 could independently calculate those, because I 2 can multiple 14 times X and get those numbers.

3 Is that the independent calculation that you did 4 to confirm that 14 times X is --

5 MR. MEDOFF: We take the data they 6 give us, because they are doing --

7 MEMBER STETKAR: It is not an 8 independent calculation, is it? It is a sort of 9 can I multiply check. I am led to infer that you 10 had some other data and did some different type 11 of analysis on that.

12 MR. MEDOFF: We use the cycle counting 13 data they provide for us.

14 MEMBER STETKAR: So you check whether 15 their calculator could multiply. Thanks. I get 16 concerned about independently verified or 17 independently calculated numbers versus audited 18 their calculation and indeed confirmed that they 19 multiplied correctly.

20 MR. MEDOFF: But this is similar to 21 what we do for the PTS assessment that we gather 22 data.

23 MEMBER STETKAR: Well, but in some 24 cases, for example, in other parts of the reviews 25 and audits that the NRC staff does, they actually NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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139 1 run separate, independent analyses; for example, 2 thermal hydraulic analyses or things like that, 3 that are actually independent calculations to 4 confirm an applicant's projections or analysis.

5 MR. MEDOFF: This is more of an 6 independent verification.

7 MEMBER STETKAR: Okay, thanks. I just 8 wanted to make sure I wasn't missing something.

9 DR. HISER: Okay, we are ready for the 10 next slide. Open item 4.7.5-1 covers the RHR 11 piping weld that the applicant described earlier.

12 During the staff's review, the staff 13 noted that the applicant did follow ASME code 14 requirements and that the location of the flaw 15 that they identified met the proximity rule 16 requirements of IWA 3300 of the ASME code and, 17 therefore, in their fracture stability 18 calculation they assumed that it was a 19 throughwall flaw.

20 The staff felt that it was 21 inconsistent then for the applicant to not use --

22 or not assume a stress corrosion cracking or a 23 water environment for that flaw, and asked the 24 applicant to justify its position. As indicated 25 by the applicant, they have gone ahead and done NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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140 1 the stress corrosion cracking calculation and had 2 submitted that to the staff. We have not 3 completed our review of that, but will do so and 4 we will document that in the final SER.

5 So that is the open item related to 6 the RHR weld.

7 MR. FERRER: In closing, the staff is 8 working to resolve the open items and, pending 9 resolution of these items, the staff is working 10 to issue the SER. Again, thank you for the 11 opportunity to discuss the staff's review of the 12 Diablo Canyon license renewal application.

13 CHAIRMAN BLEY: Anymore questions from 14 the Committee? Thank you very much for the 15 presentations.

16 At this point, Diablo Canyon has some 17 answers to questions we had asked earlier.

18 MR. SHARP: Loren Sharp from Diablo 19 Canyon. If I could have David Gerber answer the 20 question on cycles.

21 MR. GERBER: My name is Dave Gerber.

22 I am with Structural Integrity Associates, and I 23 am on the Diablo Canyon License Renewal Team.

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141 1 during plant cooldown events not two times the 2 number of plant cooldown events?

3 MEMBER STETKAR: Yes.

4 MR. GERBER: The answer is that we 5 took two different periods of time to make this 6 evaluation. The first period of time there was 7 no -- The plant data available to do counting was 8 not available. The second period of time, the 9 plant's data was available.

10 For the first period, we applied the 11 two times rule, aux spray during plant cooldown 12 equals two times plant cooldown. For the second 13 period we actually counted both plant cooldowns 14 and aux spray during plant cooldowns. Thus, the 15 projection could and did divert.

16 MEMBER STETKAR: Thanks. Thank you.

17 MR. SHARP: Thank you. I believe that 18 answers all, but we still owe you one, I believe.

19 CHAIRMAN BLEY: At this time, I would 20 ask if there are any comments from the public 21 attending the meeting.

22 I would like to go around and have 23 members of the Committee provide any comments on 24 what we have heard today, and then we get our 25 consultant after that. So if we can start with NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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142 1 Jack Sieber.

2 MEMBER SIEBER: I think that the level 3 of review and the quality application is 4 consistent with most of the plants that we have 5 reviewed. I think there are unanswered questions 6 and, obviously, there are open items, RAIs that 7 we will have to look at before we get to the 8 final meeting, but I think the actions taken for 9 the issues that I am concerned about are 10 consistent with the ways that industry has 11 basically solved the problems at hand, and I 12 think that the applicant is basically aware of 13 the issues that exist with this type of plant and 14 this environment.

15 So I am reasonably satisfied that 16 progress is being made.

17 CHAIRMAN BLEY: Thank you. Harold?

18 MEMBER RAY: I don't have anything to 19 add.

20 CHAIRMAN BLEY: Sam?

21 MEMBER ARMIJO: Yes. I thought it was 22 a very good presentation. I think the plant, 23 based on the inspection results and all the 24 information provided, is in good shape. The 25 arguments about the weld flaw and what it means NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

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143 1 and whether it is going to grow are very 2 persuasive to me, particularly when the 3 temperatures are as low as they are, but the UT 4 examination technique, I thought, was very good.

5 So I don't think that is a big concern.

6 Although it wasn't presented, I did 7 review the material on the water chemistry and 8 the material degradation in the plant over the 9 lifetime. I think, based on that information, it 10 has been excellent, and I think the very few 11 stress corrosion cracking events attest to that 12 very good control of the operating environment, 13 and I think that will continue during the period 14 of extended operation.

15 So overall, I think it is in very good 16 shape.

17 CHAIRMAN BLEY: Thank you.

18 MEMBER ABDEL-KHALIK: I have no 19 additional remarks.

20 CHAIRMAN BLEY: John?

21 MEMBER STETKAR: Nothing. Nothing at 22 all. I think the staff did a really good review.

23 So I congratulate them on another good job well 24 done.

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144 1 said before, and I also appreciate the applicant 2 bringing, I think, promising weather from the 3 plant here today.

4 CHAIRMAN BLEY: There is nothing in 5 the store, Mike. Come on.

6 MEMBER RYAN: I appreciate the fact 7 that you brought everybody here to answer any 8 question we might have. Thank you.

9 CHAIRMAN BLEY: Bill?

10 MEMBER SHACK: Nothing additional.

11 CHAIRMAN BLEY: Mike?

12 MEMBER CORRADINI: Nothing additional.

13 CHAIRMAN BLEY: Nothing more from me, 14 although just to check my counting on the 15 questions that Jack raised, did I count right?

16 Are there only two open items left that still 17 need resolution, the flux thimbles and the stress 18 corrosion cracking?

19 MR. FERRER: Also, the TLAA 20 identification of metal fatigue, we are still 21 reviewing those as well.

22 DR. HISER: We just have not completed 23 our reviews of those items, the TLAA.

24 CHAIRMAN BLEY: Did we have a phone 25 line open? I don't think so.

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

(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com

145 1 MR. BENSON: Yes, we did have some 2 people call in.

3 CHAIRMAN BLEY: Want to open it up and 4 see if we have public comments from them? Can we 5 do that?

6 CHAIRMAN BLEY: Oh, I am sorry. John 7 Barton. I forgot. I just slid right by.

8 Please. You should have yelled at me.

9 DR. BARTON: I usually don't give out 10 kudos, but I got to give that to the staff. I 11 mean, after seeing the number of RAIs, follow-up 12 RAIs, conference calls -- I mean, it had to get 13 pretty tough.

14 You know, we are doing -- this is 62, 15 63, somewhere in there, in license --

16 CHAIRMAN BLEY: Sixty-three.

17 DR. BARTON: And I guess I have looked 18 at about 42 of them. This application looked 19 like it was the initial plants when GALL was out, 20 before NEI came on board, and I just thought it 21 was not very good quality.

22 I feel a lot better today after 23 hearing the applicant's presentation and the 24 staff's work that they have done in reviewing 25 this thing. But I just expected at this stage of NEAL R. GROSS COURT REPORTERS AND TRANSCRIBERS 1323 RHODE ISLAND AVE., N.W.

(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com

146 1 the process a lot better application than what 2 you people received, and I think those are -- I 3 don't see any major issue that says that this 4 plant doesn't deserve license extension after all 5 the issues are resolved. It just didn't look 6 good from the get-go. That is all I am going to 7 say.

8 CHAIRMAN BLEY: Thank you, John.

9 I think the phone line is open now.

10 If anybody is on the phone, please just say a 11 word so we know you are there, hello or 12 something. Oh, there is somebody there. So if 13 anyone listening in on the phone line cares to 14 make a comment, we would be glad to entertain 15 that at this point in time. Identify yourself 16 and make your comments, please. I take nobody 17 wants to.

18 I want to thank the applicant and the 19 staff for very good presentations and 20 discussions. We appreciate it a lot, and this 21 meeting is adjourned.

22 (Whereupon, the foregoing matter went 23 off the record at 4:31 p.m.)

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

(202) 234-4433 WASHINGTON, D.C. 20005-3701 www.nealrgross.com

DIABLO CANYON POWER PLANT LICENSE RENEWAL

Jim Becker Site Vice President 2

DIABLO CANYON POWER PLANT PERSONNEL IN ATTENDANCE Jim Becker, Site Vice President Loren Sharp, Senior Director Technical Services Mike Wright, Engineering Manager Terry Grebel, License Renewal Project Manager STARS Center of Business and Plant Staff 3

AGENDA

Introductions

Site and Station Description Plant History Major Improvements GALL Consistency and Commitments Safety Evaluation Report Open and Confirmatory Items

- Flux Thimble Tube Inspection Program

- Flaw Growth Evaluation for RHR

- Scoping and Screening

- Buried Piping and Tanks Inspection Program

- TLAA Identification

- Metal Fatigue Concluding Remarks 4

SITE DESCRIPTION 5

SITE DESCRIPTION Discharge Unit 1 Raw Water ISFSI Reservoirs Unit 2 Turbine Admin Building Building Intake 6

STATION DESCRIPTION Two Units

- Common operating procedures/design 4 loop Westinghouse NSSS 3411 MWt PG&E was architect/engineer with Bechtel support Once-through cooling Containment - free standing, steel-lined, reinforced concrete building PG&E owner and operator PG&E owns and operates the switchyards and the high voltage transmission system 7

Loren Sharp Senior Director, Technical Services 8

STARS CENTER OF BUSINESS Strategic Teaming and Resource Sharing (STARS) Alliance Center of Business

- Seven large PWR stations in Region IV

- Center of Business created to prepare license renewal applications for the member utilities Leadership, oversight and ownership by Diablo Canyon personnel through the License Renewal development and review phases, continuing through implementation 9

PLANT HISTORY Unit 1 full power operating license issued November 2, 1984 Unit 2 full power operating license issued August 26, 1985 October 2000, Unit 1 increased licensed power to 3411 MWt Unit 1 operating license expires November 2, 2024 Unit 2 operating license expires August 26, 2025 10

MAJOR IMPROVEMENTS Steam Generators replaced Reactor Heads replaced Auxiliary Saltwater System piping bypass Diesel Fuel Oil tanks replaced Low Pressure Turbine rotors replaced 4 kV cables replaced 6th Emergency Diesel Generator added Main Generator Rotors replaced Feedwater heaters/MSR copper tubes replaced with stainless steel Main Bank and Start-up Transformers replaced Analog to Digital Control Systems upgraded Extensive FAC piping replacements 11

Terry Grebel License Renewal Project Manager 12

GALL CONSISTENCY AND COMMITMENTS Total Aging Management Programs - 42

- Existing Programs - 31

- New Programs - 9

- Plant Specific - 2 Aging evaluations are greater than 93% consistent with GALL Rev 1 (standard notes A through E)

License Renewal commitments - 64 License Renewal commitments managed through the DCPP commitment tracking system which implements the guidance of NEI 99-04, Revision 0, Guidelines for Managing NRC Commitment Changes 13

SAFETY EVALUATION REPORT OPEN ITEMS - 8

- Flux Thimble Tube Inspection Program

- Flaw Growth Evaluation for RHR

- Scoping and Screening (3 Open Items)

- Buried Piping and Tanks Inspection Program

- TLAA Identification

- Metal Fatigue CONFIRMATORY ITEMS - 2

- Cable Testing 6 Years Frequency

- Spent Fuel Pool Leak Chase Inspection Schedule 14

Flux Thimble Tube Inspection Program Mike Wright Engineering Manager 15

DCPP THIMBLE TUBE BACKGROUND 16

DCPP THIMBLE TUBE L-13 HISTORY 17

FLUX THIMBLE TUBE INSPECTION PROGRAM OI 3.0.3.2.12 RAI B2.1.21-1 Issue:

- Based on Unit 2 thimble tube L-13 operating experience, justify an appropriate margin to account for NDE measurement and wear scar uncertainties Resolution:

- DCPP wear projection methodology was compared to Westinghouse WCAP-12866 using site-specific wear data

- WCAP methodology acceptance criteria is 80% wear (including uncertainties)

- DCPP acceptance criteria is 68% wear (17.5% margin from WCAP)

- DCPP acceptance criteria is conservative and comprehensive 18

FLUX THIMBLE TUBE INSPECTION PROGRAM OI 3.0.3.2.12 RAI B2.1.21-2 Issue:

- Additional information regarding L-13 FTT failure causes and corrective actions 2R14 (2008) L-13 actions & cause determination Cause of Failure:

- L-13 thimble tube failure caused by flow-induced wear and plant practices that allowed multiple repositioning of thimble tubes

- Repositioning practices exposed non-chrome plated portion of the thimble tube to the bottom nozzle

- No cracking has been identified in any thimble tube eddy current examinations 19

FLUX THIMBLE TUBE INSPECTION PROGRAM OI 3.0.3.2.12 RAI B2.1.21-2 Resolution: Non-Linear Wear

- Procedure acceptance criteria revised to require capping or replacing tubes:

  • > 25% wear per year, or
  • Any tube with multiple wear scars, any two of which measured > 40% wear

- In addition:

  • Tube may only be repositioned 6 inches, and
  • Tube may only be repositioned once

- Replacement thimble tubes are supplied by Westinghouse with a 12 foot chrome plated band 20

FLUX THIMBLE TUBE INSPECTION PROGRAM CONCLUSION PG&E is confident that the 68% acceptance criteria in combination with the additional procedural acceptance criteria is comprehensive and conservative 21

Flaw Growth Evaluation for RHR Piping Weld David Gonzalez ISI Supervisor 22

Flaw Growth Evaluation for RHR Piping Weld WIC-95 OI 4.7.5 SER 4.7.5 Issue:

- PG&E's basis for concluding that the flaw in Unit 1 RHR piping weld WIC-95 is not service-related

- PG&E's flaw analysis for this weld did not address stress corrosion cracking (SCC)

Background:

- Evaluated the characteristics of the flaw as non-service induced

- Fatigue crack growth evaluated with acceptable results

- Subsequent 2000 UT inspection result consistent with non-service induced (no growth)

Resolution:

- SCC evaluation performed with acceptable results

- Confirmatory UT inspection of WIC-95 during the 2012 outage 23

Flaw Growth Evaluation for RHR Piping Weld WIC-95 24

Flaw Growth Evaluation for RHR Piping Weld WIC-95 25

Dave Miklush Diablo Canyon License Renewal Project 26

SCOPING AND SCREENING OI 2.1 SER 2.1.4.1.2 Issue:

- NSR fluid-filled components in the vicinity of SR components (1) Rainwater entering HVAC ducting to vital 480V switchgear room (2) Firewater piping in the vicinity of the Control Room Pressurization System I&C (3) Firewater piping and domestic water piping in the vicinity of HVAC exhaust openings to 4kV switchgear room Resolution:

(1) Enhanced water drainage provisions in Unit 2 HVAC exhaust ducting (2) Include in scope firewater piping under 10 CFR 54.4(a)(2)

(3) Include in scope firewater and domestic water piping under 10 CFR 54.4(a)(2) 27

SCOPING AND SCREENING OI 2.1 SER 2.3 Issue:

- NSR fluid-filled components leaking or spraying onto SR cables in electrical pull boxes Resolution:

- Pull boxes drain to building sumps or in-ground sumps

- In-scope pull boxes are physically separated from the sumps and from the pumps and discharge piping 28

SCOPING AND SCREENING OI 2.1 SER 2.3.3.7.2 Issue:

- NSR fluid-filled water traps spraying onto SR components Resolution:

- This portion of system is not used

- Commitment to close the upstream isolation valves and drain any contained water from the traps 29

SCOPING AND SCREENING OI 2.3 SER 2.3 Issue:

- NSR tubing directly attached to SR solenoid valves in the compressed air system Resolution:

- All NSR tubing directly attached to SR solenoid valves in the compressed air system is included in scope up to the first seismic or equivalent anchor on the NSR side of the code break 30

SCOPING AND SCREENING OI 2.3.3.14 SER 2.3.3.14.2 Issue:

- Scoping methodology of Diesel Generator compressor unloader line endpoint for pressure boundary function Resolution:

- Design change relocates unloader tubing to the compressor discharge piping upstream of the pressure boundary isolation check valve

- After design change unloader line is no longer in-scope

- Completed on Unit 1; Unit 2 scheduled for April 2011 31

BURIED PIPING AND TANKS INSPECTION PROGRAM OI 3.0.3.2.8 SER 3.0.3.2.8 Issue:

- Management of aging effect for buried copper valves in the Makeup Water System

- Clarification of in-scope steel pipe in the Makeup Water System Resolution:

- Buried copper valves will be managed by the Buried Piping and Tanks Inspection Program

- Commitment to enhance operating procedure to close Makeup Water System isolation valve in event of a pressure boundary failure and removed steel piping and components from scope 32

Michelle Albright Diablo Canyon License Renewal Project 33

TIME-LIMITED AGING ANALYSES IDENTIFICATION OI 4.1-1 RAIs:

- Reactor coolant pressure boundary valves

- Baffle and former bolts Resolution:

- Confirmed DCPP design codes for the reactor coolant pressure boundary valves do not require a fatigue analysis

- Fatigue of the baffle and former bolts is managed by the Reactor Vessel Internals AMP 34

METAL FATIGUE OI 4.3-1 Additional information

- Replacement reactor head CUF values

- AMR revisions for piping system cumulative fatigue damage Clarification

- Cycle counting for upper and lower core plates

- Cycle estimates for the Auxiliary Spray during Plant Cooldown transient

- Charging system cycle estimate methodology during unmonitored periods

- Electrical raceway seismic evaluation requirements FSAR/CLB enhancement

- Load-following transients used in design analyses and the FSAR

- Monitoring transients in non-CUF type analyses Evaluate DCPP Environmentally-Assisted Fatigue analyses 35

Concluding Remarks Jim Becker Site Vice President 36

Flaw Growth Evaluation for RHR Piping Weld WIC-95 66

FLUX THIMBLE TUBE Unit 1 Unit 2 Wear Potential Notes Original (No 24 33 Minimal Chrome)

Minimal (Outside Chrome No Wear on Chrome Chrome: 15 Inches 9 7 Band) Band Minimal (Outside Chrome Chrome: 12 Feet 21 10 Band)

Scheduled for Capped 4 7 None Observed Replacement in 2R16, May 2011 Thimble Tube Guide Tube Capped 1 (L-13) N/A Removed 44 Needed for Tech Useable 54 50 Spec Flux Map 70

CONDUIT LAYOUT (SECTION VIEW) 78

Advisory Committee on Reactor Safeguards License Renewal Subcommittee Diablo Canyon Nuclear Power Plant, Units 1 and 2 Safety Evaluation Report with Open Items February 9, 2011 Nate Ferrer, Project Manager Office of Nuclear Reactor Regulation 1

Presentation Outline

  • SER Section 2, Scoping and Screening review
  • SER Section 4, Time-Limited Aging Analyses 2

Overview of LRA

- Applicant: Pacific Gas and Electric Company

- Facility Operating Licenses DPR-80 and DPR-82 expire November 2, 2024, and August 26, 2025, respectively

  • Approximately 12 miles west southwest of San Luis Obispo, CA in Avila Beach, CA
  • DCPP units are Westinghouse four loop PWRs 3

Audits and Inspections

  • Scoping and Screening Methodology Audit

- March 15-18, 2010

- Led to submittal of 2 LRA amendments related to scoping and screening

- April 12-15, 2010

- April 26-29, 2010

- Over 20 technical reviewers, including contractors from ANL and ORNL

  • Region IV Inspection

- August/September 2010 4

Overview of SER

  • Safety Evaluation Report with Open Items issued January 10, 2011
  • SER contains 8 Open Items:
1. 10 CFR 54.4(a)(2) evaluations for nonsafety-related, fluid-filled structures and components (SCs) in the vicinity of safety-related SCs (Open Item 2.1-1)
2. 10 CFR 54.4(a)(2) evaluations for nonsafety-related piping directly attached to safety-related components (Open Item 2.3-1)
3. Endpoint for the diesel air start unloader line (Open Item 2.3.3.14-1) 5

Overview of SER (cont.)

  • SER contains 8 Open Items (cont.)
4. Buried Piping and Tanks Inspection Program (Open Item 3.0.3.2.8-1)
5. Flux Thimble Tube Inspection Program (Open Item 3.0.3.2.12-1)
6. TLAA Identification (Open Item 4.1-1)
7. Metal Fatigue (Open Item 4.3-1)
8. Flaw Growth Evaluation for RHR piping Weld (Open Item 4.7.5-1) 6

Overview of SER (cont.)

  • SER contains 2 Confirmatory Items
1. Inaccessible Medium-Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program (Confirmatory Item 3.0.3.2.14-1).
2. Structures Monitoring Program (Confirmatory Item 3.0.3.2.18-1) 7

SER Section 2 Summary

- Section 2.1, Scoping and Screening Methodology (open item)

- Section 2.2, Plant-Level Scoping Results

- Section 2.3, Scoping and Screening Results -

Mechanical (open items)

- Section 2.4, Scoping and Screening Results -

Structures

- Section 2.5, Scoping and Screening Results -

Electrical 8

SER Section 2 Open Items

  • 10 CFR 54.4(a)(2) evaluations for nonsafety-related, fluid-filled components in the vicinity of safety-related components, Open Item 2.1-1

- control room pressurization system/HVAC exhaust ducts

- electrical pull boxes

- compressed air system water traps

  • 10 CFR 54.4(a)(2) evaluations for nonsafety-related piping directly attached to safety-related components, Open Item 2.3-1

- compressed gas systems

  • 10 CFR 54.4(a)(1) evaluations for scoping boundary of safety-related piping, Open Item 2.3.3.14-1

- EDG air start system - unisolated unloader line from air receiver back to the air compressor

  • Applicant has submitted additional information
  • Staff is finalizing its review of the response 9

Regional Inspection -

License Renewal Inspections Program Implementation Greg Pick Region IV Inspection Team Leader 10

Regional Inspection Overview

  • Six inspectors for 2 weeks
  • Scoping & screening inspection
  • Several focus areas 11

Regional Inspection Focus Areas

  • SSCs needed to withstand a design basis seismic event
  • SSCs and programs that prevent leaks to the environment
  • Treatment of the latest industry aging concerns
  • Prior site-specific aging issues 12

Regional Inspection Results

  • Scoping of nonsafety-related systems

- Spatial interaction issues

- Some material types incorrect or omitted

- Training required

- Degraded silicon seal

- Reviewed electrical vaults

- Location selected for fouling

- Procedures developed but some errors 13

Regional Inspection Observations

  • Overall, good material condition
  • Procedures developed for the programs reviewed
  • Major component replacements

- 230 kV & 500 kV insulators

- Intake structure 14

Regional Inspection Conclusions

  • Scoping of non-safety SSCs and application of the AMPs to those SSCs were acceptable
  • Applicant personnel had incorporated actions to manage aging effects into their programs
  • Reasonable assurance exists that aging effects will be managed and intended functions maintained 15

Section 3: Aging Management Review

  • Section 3.1 - Reactor Vessel & Internals
  • Section 3.2 - Engineered Safety Features
  • Section 3.3 - Auxiliary Systems
  • Section 3.4 - Steam and Power Conversion System
  • Section 3.5 - Containments, Structures and Component Supports
  • Section 3.6 - Electrical and Instrumentation and Controls System 16

SER Section 3 3.0.3 - Aging Management Programs

  • 42 aging management programs (AMPs) presented by applicant and evaluated in the SER Consistent Consistent Consistent Consistent with with GALL with exception with exception &

enhancement enhancement Existing 16 5 5 5 (31)

New 5 4 N/A N/A (9)

Plant-specific N/A N/A N/A N/A (2) 17

SER Section 3 Open Items

  • Flux Thimble Tube Inspection Program, Open Item 3.0.3.2.12-1

- Justification for not including measurement and wear scar geometry uncertainties

- Wear rate projection methodology and the capability of program to detect degradation in a flux thimble before the occurrence of a through-wall failure

- Applicant has submitted additional information

- Staff is reviewing the response 18

SER Section 3 Open Items

  • Buried Piping and Tanks Inspection Program, Open Item 3.0.3.2.8-1

- Staff requested additional information on how the program would account for recent operating experience

  • Backfill is acceptable
  • Increased inpsections

- Applicants initial response did not provide details for:

  • Management of buried copper and steel valves and piping in the makeup water system
  • Alternate methods used for inspections

- Applicant has submitted additional information

- Staff is finalizing its review of the response 19

SER Section 3 Confirmatory Item

  • Inaccessible Medium-Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program, Confirmatory Item 3.0.3.2.14-1

- Staff requested additional information on how the program would account for recent operating experience

- Applicants initial response did not provide sufficient details for absence of event-driven inspections or use of a 10-year testing frequency

- Applicant has submitted additional information

- Staff is finalizing its review of the response 20

SER Section 3 Confirmatory Item

  • Structures Monitoring Program, Confirmatory Item 3.0.3.2.18-1

- Applicant initially committed to perform video inspection of the Unit 2 spent fuel pool leak chase during the period of extended operation but did not specify the timing of the inspection

- Applicant revised its commitment to perform the inspection within 1 year prior to the period of extended operation

- Staff is finalizing its review of the response 21

SER Section 4:

Time-Limited Aging Analyses

  • Section 4.1 - Identification of Time-Limited Aging Analyses (1 open item)
  • Section 4.2 - Reactor Vessel Neutron Embrittlement
  • Section 4.3 - Metal Fatigue (1 open item)
  • Section 4.4 - Environmental Qualification of Electrical Equipment
  • Section 4.5 - Concrete Containment Tendon Prestress
  • Section 4.6 - Containment Liner Plate, Metal Containments, and Penetrations Fatigue Analysis
  • Section 4.7 - Other Plant-Specific Time-Limited Aging Analyses (1 open item) 22

SER Section 4 SER Section 4.2.2: Pressurized Thermal Shock Limiting Beltline Material - Unit 1 lower shell longitudinal (axial) weld 3-442C

%CU EOLE Fluence Initial Charpy RTPTS Acceptance

%Ni (E>1 MeV) RTNDT 0F Criterion per 1019 (n/cm2) 0F 10 CFR 50.61 0F 0.203 2.04 -56 280.4 <270oF 1.018 The applicant stated in that it will implement 10 CFR 50.61a at least three years prior to exceeding the PTS screening criteria of 10 CFR 50.61. In the event that the provisions of 10 CFR 50.61a cannot be met, PG&E will implement alternate options, such as flux reduction, as provided in 10 CFR 50.61.

23

SER Section 4 Open Items

  • TLAA Identification, Open Item 4.1-1

- Justification for absence of TLAAs for:

  • Baffle and former bolts

- Applicant has submitted additional information

- Staff is reviewing the response 24

SER Section 4 Open Items

  • Metal Fatigue, Open Item 4.3-1

- Issues related to Metal Fatigue TLAAs

  • Cycle counting
  • Environmentally-assisted fatigue
  • Cumulative usage factors

- Applicant has submitted additional information

- Staff is reviewing the response 25

SER Section 4 Open Items

- Applicant did not consider the potential of stress corrosion cracking for a flaw that may be connected to pipe inside surface

- Applicant has submitted additional information

- Staff is reviewing the response 26

Conclusion

  • The staff is continuing review to resolve the open and confirmatory items regarding the LRA for DCPP. Pending resolution of the open and confirmatory items, the staff is working towards issuing the SER.

27

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